Day: October 3, 2024

This is the second in a series of posts about one of the key issues in current GB energy and climate policy: the problems associated with connecting to the electricity grid. The first post, setting out the background to the crisis, is here.

Connections reform took centre stage in a string of government announcements about energy and infrastructure topics in the Chancellor’s Autumn Statement of 22 November 2023. We will cover the connections-related announcements made by the government and Ofgem alongside the Autumn Statement (see further here, here and here) later in this series. In this post, we focus on some key steps that National Grid ESO (NG ESO) took during 2023 to remedy the connections crisis.

Ofgem’s open letter

No single entity can solve the problem of grid connections, but Ofgem has a key role to play. It regulates NG ESO, the owners of the transmission networks, and the distribution network operators (DNOs); it controls in large measure what they can invest through its regulation of network charges; and in most cases it determines whether proposed modifications to industry codes are made. The crisis in connections has featured prominently in recent speeches by Ofgem’s CEO, Jonathan Brearley (such as here).

On 16 May 2023, Ofgem published an open letter on future reform to the electricity connections process. It provides a good starting point for considering the ways in which the systemic problem of grid connection is being addressed. Figure 2 of that letter, reproduced below, gives a useful overview.

Ofgem emphasises that any move towards the more radical approaches of Stages 3 and 4 will “depend on the effectiveness of the earlier stages in meeting the outcomes”. It also sets out and elaborates some key principles that will guide its approach.

Reforms must deliver benefits to current and future consumers, as well as accelerating progress towards net zero. They must begin to deliver results as soon as possible, with impacts seen by 2025. They must support improved coordination across onshore/offshore and transmission/distribution networks. They must also be resilient to the impacts of the various wider-ranging energy market and system planning reforms playing out over the remainder of this decade (including the Review of Electricity Market Arrangements (REMA) and introduction of a Future System Operator (FSO), which, as Electricity System Operator, will take over the current roles of NG ESO).

The open letter is a useful recapitulation of action already being taken by Ofgem, such as the “c.£20 billion” Accelerated Strategic Transmission Investment or ASTI framework (see further here), and of possible agenda items for the future (such as “options which could deprioritise projects which are not making progress to allow well-developed projects to proceed“). In this document, at least, the regulator only seems to be systematically promoting “anticipatory investment” (i.e. building ahead of need) in the context of offshore generation projects (see further here).

NG ESO’s short-term actions: the Five-Point Plan

Some of the Stage 1 steps in Ofgem’s graphic feature in NG ESO’s February 2023 Five-Point Plan.

Modelling: how big is the queue (really)?

“Background modelling assumptions” may not sound terribly exciting, but they play a crucial role in the connection process. In order to be robustly connected to the network, each generating project may require “wider works”, not just the construction of infrastructure in their immediate vicinity. The current list of transmission reinforcement schemes required to facilitate network connections runs to well over 4,000 projects, most with delivery dates in the late 2020s or early 2030s.

The need for and phasing of wider works can have a significant impact on a project’s connection date. Both inevitably depend in part on what work is required to accommodate other projects that are seeking to connect. Elsewhere, NG ESO has pointed out that 42% of new applications for connection made between 2018 and 2021 had “fallen out of the process” by December 2022, and it has been estimated that as much as 30-40% of capacity in the current transmission queue may not be ready to connect on its scheduled connection date (if it is built at all).

Clearly, if an appropriate way can be found of taking account of the level of “attrition” in the connections queue, it may be possible to accelerate the connection of some projects.

NG ESO is therefore “working with GB’s Transmission Owners to review and update existing contracts with…new Construction Planning Assumptions“. It should be possible to manage these changes through existing System Operator-Transmission Owner Code and Connection and Use of System Code (CUSC) procedures. NG ESO states that implementation will require a “complete system review of the GB Transmission Reinforcement Works…for all contracted offers with a connection date post 1 January 2026“, at the end of which “some contracted parties within the GB transmission system queue…could have their connection date moved forward“.

The current estimate is that 46GW of projects could accelerate their connection dates as a result.

These modelling changes (and those specifically relating to storage – see below) are feeding into a “complete system review” of Transmission Reinforcement Works (TRW) for all projects with a connection date after 1 January 2026. This will “rationalise the TRW required” and identify options for battery projects to connect earlier with interim restrictions (see below).

Storage

Separately, NG ESO has also changed its approach to determining the impact of new storage (in particular, battery) projects on the system – recognising that the inherently two-way relationship between a storage project and the grid can mean that its presence reduces, rather than increases, the need for network reinforcement upstream of the point at which it is connected to the grid.

The Five-Point Plan is also looking at the terms on which storage projects are connected, as outlined in a policy paper published in June 2023. It is a bit like a storage-specific version of “Connect and Manage” (see the previous post in this series), but with at least one significant difference.

NG ESO recognises that accelerating the connection of storage capacity can have system benefits as well as bringing “a potential risk that under certain conditions, the real-time behaviour of such projects increases operational costs“. So, on the one hand, storage projects will be able to connect before certain “non-[safety-]critical enabling works have been carried out” but, on the other hand,”there will be certain operational scenarios such as when it is windy and storage is contributing to the local constraints where we may pull them back even if the network is intact“. There will also be no compensation for the storage projects that are subject to such curtailment.

The new offer is to be embodied in new contractual drafting and available to those connecting either to a transmission or a distribution network. An initial tranche of transmission connected battery storage customers (with a combined capacity of some 10GW) will connect on an interim non-firm basis an average of four years ahead of their firm connection dates.

Two-step offer process

However, it is not only storage projects that will see changes to their connection offers. For at least a year from 1 March 2023, NG ESO is splitting the connection offer process into two stages. An initial offer containing no detail of the works involved or any “securities” (i.e. amounts payable by the generator), but guaranteeing the project a “place in the queue” once accepted, will be followed (within nine months of acceptance) by a follow-up offer with all the details normally found in transmission connection offers that were “missing” from the initial offer.

The intention seems to be, at least in part, to buy time for NG ESO to apply the new modelling assumptions discussed above. The process will work in a slightly different way in Scotland. The detailed FAQs document suggests that the industry has had a number of questions about all this.

Jumping out of the queue…

In June 2023, NG ESO stated that, of some 40GW of projects that were due to connect to the transmission network before 2026 (numbering 220 in total), only half had planning consent and some had moved their connection dates back by more than 14 years. This is unfortunate, but not surprising.

Projects often apply to connect to the network (in particular, the transmission network) as one of the first steps that they take, years before they have obtained planning consent. Subsequently, difficulties in obtaining planning consent are one of a number of reasons why they may then not be able to build out in time to be connected at the date anticipated in their connection offer.

However, transmission-connected projects in particular tend to be slow to give up their connection rights rather than merely adjusting their target commissioning dates. A developer that terminates its connection agreement may need to go to the back of a very long queue if it later wants to re-establish its project. There are also adverse financial consequences to terminating, or reducing a project’s transmission entry capacity (TEC) under the standard form agreements that developers enter into with NG ESO, incorporating as they do the cancellation charges regime in Section 15 of the CUSC.

NG ESO’s Five-Point Plan addresses this by means of a “TEC Amnesty” (launched in September 2022). However, the amount of capacity released by this process, though useful, is not game-changing (8.1GW of projects initially expressed interest in the Amnesty; some have since withdrawn, and it looks as if, ultimately, about 4GW of capacity will be removed from the TEC register).

…or being pushed

In 2021, NG ESO proposed a CUSC modification which would allow it to manage its connections queue more actively, by terminating contracted projects not progressing against agreed milestones to free up space for those which are. Although not formally part of the Five-Point Plan, it is closely related to it, aiming to curb use of the Modification Application process to keep connection agreements artificially alive by delaying their completion dates. The proposed modification was approved by Ofgem on 13 November 2023, with an implementation date of 27 November 2023.

In future, projects will be held to a series of eight milestones. Failure to meet some of them will result in automatic termination (subject to exceptions for force majeure etc) and failure to meet others will give NG ESO discretion to terminate. The new regime will apply to new agreements and to projects whose contracted completion date is two years or more from 27 November 2023; or less than two years from that date but which NG ESO consider are not progressing satisfactorily.

From 27 November 2023, NG ESO will issue “all customers who hold live construction agreements with a completion date post-November 2025, with a notice with two options; either to have queue management milestones applied to their current completion date or submit a modified application for a new completion date where queue management milestones will be applied“.

Queue management is expected to have a much bigger impact, perhaps ultimately removing about 80GW of projects currently on the TEC register.

NG ESO’s longer-term plans for connections reform

The Five-Point Plan is just a start. In 2022, NG ESO began an extensive programme of engagement with the industry about ways of overhauling the connections application process in the longer term.

In June 2023, NG ESO published its proposals (full suite of associated documents available here). In the best traditions of significant changes in the sector, they have at their heart a new acronym – in this case, TMO4. In December 2023, NG ESO published its “final recommendations” following the consultation (full report here, summary here, webinar recording here and slide deck here

We have combined below two versions of NG ESO’s diagram summarising TMO4.

One of a series of options considered by NG ESO and stakeholders, TMO4 moves us towards Stage 3 in Ofgem’s overview table above, but stops decisively short of Stage 4. NG ESO sees the potential benefits of moving away from an essentially generator-led approach. However, it sees a shift to an entirely “centrally-planned” approach (in which generators would be expected to bring forward projects to fit around the development of the transmission network rather than the other way around) as something that would need to be mandated by “government, Ofgem and other key decision-makers”, taking account of relevant wider changes such as the ongoing REMA process.

The central idea is a (probably annual) cycle of “batched assessment” of connection applications by NG ESO (or, as it will be then, FSO – hereafter ESO). The idea is that by considering a batch of new applications together, the network design for them can be developed in one piece. A secondary application process at Gate 2 would then allow projects that can build out earlier to seek accelerated connection. The period to the left of the first vertical dashed line is estimated as lasting three months and the period between the two vertical dashed lines is estimated as lasting six months.

A further diagram offers another picture showing how the phenomenon of “attrition” (noted above), and ESO’s modelling of it, might play out against the new process (with illustrative numbers).

Broadly speaking, although the consultation elicited a number of responses that differed substantially from NG ESO’s preferred options either in terms of overall approach or on points of detail, the approach NG ESO proposes in the near term is closely aligned with that set out in the consultation.

At the same time, the consultation process has to some extent been slightly overtaken by government and Ofgem policy publications issued during November 2023 (see here, here and here). Partly for this reason, and partly because of stakeholder feedback and the evolution of NG ESO’s own thinking, it would appear that, in some respects, NG ESO’s approach may evolve on some points, so that the immediate outputs from the consultation process may be more of a staging post on a longer journey than a final destination. An example is whether the queue is formed at Gate 1 or Gate 2. NG ESO is sticking with Gate 2 for now, but clearly has not closed its mind to the alternative.

Other areas that will be subject to further consideration, starting during the “Phase 3” period of implementation (starting in January 2024), but a final position on which is not necessarily expected to form part of TMO4 when it first goes live, include the following.

• A possible move towards shorter or more frequent application windows.

• Quite a number of issues relating to the transmission/distribution interface, where DNOs are invited to identify Reserved Developer Capacity (RDC) in respect of embedded generation projects of between 1MW and 100MW capacity in England and Wales but only up to 30MW in the South and up to 10MW in the North of Scotland (although the possibility of raising the Scottish limits will continue to be explored in Phase 3). See in particular pages 23-25 of the final recommendations report. Meanwhile, RDC is to be renamed Distribution Forecasted Transmission Capacity (DFTC), which is considered a more accurate description.

• Interactions with other processes in which holding a connection agreement is important. These include the Capacity Market regime and the Network Services Procurement (Pathfinders) – which also raises the more general question of how the reformed connections process may interact with the competitive appointment of transmission owners (either OFTOs or transmission owners for onshore projects appointed under the changes made by the Energy Act 2023).

• The criteria to be used by NG ESO in rejecting applications for a new connection offer or to modify an existing agreement – which may include that they conflict with government or regulatory policy, including as embodied in a future Strategic Spatial Energy Plan (SSEP).

• The introduction of “use it or lose it” arrangements to ensure that projects fully utilise their contracted capacity once connected.

There is a fair amount of work still to be done to implement the final recommendations, not least the proposal, processing and approval by Ofgem of modifications to the CUSC and other industry codes (which, subject to Ofgem approval, would be processed on an “urgent” basis). The aim is that all of this – or, at least, enough of it to deliver a minimum viable product (MVP) version of the new process – will be accomplished during 2024, so that it can be launched at the start of 2025.

Implementation has already begun, with the proposal in December 2023 of a CUSC modification to require that new onshore transmission connection applications must be accompanied by a “letter of authority” (LoA) confirming “that the project developer has…formally engaged in discussions with the landowner(s) in respect of the rights needed to enable the construction of the developer’s project on their land” or demonstrating “that the project developer is the landowner(s)“. Pending the outcome of the modification process, customers will be “encouraged” to provide an LoA on a voluntary basis.

The LoA proposals are one of a number of elements set out in the consultation as “Target Model Add-Ons” (TMAs). Chapter 3 of the final recommendations report indicates which of these NG ESO is minded to pursue, and whether they are to form part of the MVP (as in the case of the LoA) or not (as in the case of proposals TMA D5 and D6, relating to standardisation of connection offer terms).

One area said to fall within the MVP is likely to be the subject of continuing debate: TMA F sets out the criteria that could be used to accelerate projects that fulfil specified criteria. NG ESO reports “majority stakeholder support” for fast-tracking projects with official government designation (TMA F1); otherwise demonstrating “significant additional consumer, net zero and/or wider economic and societal benefits” (TMA F2); or that are “ready(ier) to connect” (TMA F3), but this is subject to the obvious caveat that the basis for identifying them must be “clearly defined, consistent and transparent” (including as regards relative priority between projects in these three groups).

The report promises “further clarity” on TMA F1 to F3 and recommends that a mechanism which would allow some projects simply to pay to be accelerated (TMA F4) “should not be progressed at this time”. It also indicates that such acceleration will depend on capacity first being freed up as a result of contract terminations or other outputs of the new queue management process.

Developers will no doubt welcome being given access, “by end-March 2024”, to a range of tools to facilitate their planning, including an enhanced TEC register and Transmission Works Register, and an interactive map providing capacity and application data to a substation level of granularity.

One of the reasons for choosing TMO4 is its alignment with the connection process for offshore projects. NG ESO recommends that it should in future apply to them, with some modifications to reflect the different processes that apply to the granting of “land rights” offshore.

External governance of the detailed design and implementation of the final recommendations will be provided by a Connections Process Advisory Group (CPAG). CPAG will replace the existing Connections Reform Steering Group and will have “an independent chair and broad representation from across industry“. NG ESO has published draft terms of reference for CPAG.

Looking beyond TMO4, NG ESO notes that, while existing initiatives are addressing four out of five of the areas that are key to delivering the overall objective of quicker connection to and use of the transmission system in a more coordinated and efficient way, “in some cases, the level of impact of these initiatives is lower than we might hope, or the time to deliver impact is longer…because either the initiative only benefits new applicants, or because [its] impact…dampened or deferred…by the significant numbers of new projects…joining the connections queue“. Moreover, “none of the current initiatives are actively targeted at supporting an efficient transition to the new…connections process“.

To address this, the final recommendations report puts forward five “indicative packages” of further measures and some potential additional actions to support efficient transition. These are as follows.

• Package 1 comprises “low regret options/enablers” relating to guidance for projects on connecting to the transmission or distribution network; potential changes to charging for smaller embedded generation at local grid supply points; better sharing of transmission and distribution queue data; introduction of contestability into the design and delivery of transmission connections; and reallocation of bays (including existing bays) at substations.

• The measures in Package 2 would require a further Transmission Works Review, “which will take time” and focus on changing network modelling tools and assumptions to reduce the amount of network reinforcement required, enabling more projects to connect quickly. They range from extension of elements in existing initiatives to more significant changes, such as “introducing a new definition of enabling works [into the Connect and Manage regime], perhaps accompanied by changes to access arrangements for project developers, such as potentially moving away from the concept of a guaranteed firm connection“.

• In Package 3, NG ESO considers ways to “re-order/re-size the current connections queue in 2024, as a stepping stone to potential future arrangements under the SSEP from 2025 onwards“. The idea would be to find a way to set a threshold for contracted projects, either by technology type, or by auction across all technology types, so that those “below” the threshold retain their current (or an accelerated) connection date (or, where the threshold has yet to be met, are allocated a date in the normal way) and those above it are placed in a “‘stack’ or ‘waiting room’ outside of the queue“. Projects would only “exit the stack” if additional capacity below the threshold opened up (e.g. because projects still in the queue are terminated or the threshold is reset) and they could demonstrate that they are viable and ready to progress. This is difficult territory, but Package 3 could obviously make a significant impact.

• Package 4 is also about re-ordering/reducing the queue. Packages 3, 4 and 5 are seen as mutually exclusive (but individually compatible with Packages 1 and/or 2). It overlaps with ideas put forward in the Connections Action Plan. Options include a one-off window in which projects could “trade queue positions and/or capacity with each other” much more freely than is currently possible; ramping up application fees, user commitment fees, or capacity holding charges as a way of weeding out “speculative” or otherwise less viable projects; and a more “proactive” approach to queue management than is currently proposed.

• Package 5 would combine elements of Packages 3 and 4 by “shar[ing] additional information with the market with a view to providing clear signals to project developers…and then facilitating ‘queue swaps’ under a centrally administered process“. Any project that benefited from a swap would also be expected to take on any associated burdens (“queue management milestones and user commitment/liabilities of the project it has swapped with“).

• The potential additional actions proposed are reducing the amount of engineering work done in relation to connection offers before TMO4 goes live (essentially, not including all the wider enabling works), and closing the connections process to new applications for a period of, say, three months before the go-live date.

NG ESO proposes to move ahead with Package 1 in any event (while noting that parts of it are contingent on regulatory decisions). It sees any implementation of Packages 3 to 5 as requiring decisions to be made by Ofgem or government, and any decision on Package 2 as needing to be taken in the context of any decision on Packages 3 to 5.

In short, the publication of the final recommendations of NG ESO’s connection reform consultation marks a significant step in addressing the GB connections crisis but, at the same time, implementing its recommendations will be a major task over the next year or so, and will not be the end of the story.

1. Background to the RFNBO “GHG savings” requirements

In our previous article, When is H2 = RFNBO, we examined the criteria to be met for e-fuels (in particular, green hydrogen and its derivatives) to be classified as a renewable fuel of non-biological origin (RFNBO) under the European Union’s (EU) directive on renewable energy (RED II¹) and the Delegated Acts². The importance of the RFNBO designation is that the fuel would then count towards the minimum targets for renewable fuels in the EU in order to meet the EU’s mandatory carbon reduction targets.

The targets for RFNBOs in the transport sector were increased through the Revised Renewable Energy Directive (RED III, also known as the “Fit for 55” package)³ which also created targets for usage of RFNBOs in other sectors (including the iron, steel, aluminium, chemicals, fertiliser, cement and construction industries). Part of the criteria for RFNBOs under RED II requires “the greenhouse gas emissions savings from the use of [RFNBOs to be] at least 70%“⁴ compared to the fuels being replaced.

The Second Delegated Act established the methodology to be used by e-fuel producers to calculate the greenhouse gas (GHG) emissions used in the entire production process, in order to ascertain if the abovementioned GHG savings are achieved.

2. The impact of incorporated CO₂ on the GHG savings of an RFNBO

E-fuels such as e-methanol, e-methane and e-kerosene (for use in the production of SAF) are synthetic fossil fuels which blend clean hydrogen with captured CO₂ emissions. These e-fuels will be important in decarbonising the transportation sector. Although combustion of e-fuels in their end-user applications will emit carbon at much the same rate as conventional fossil fuels, those emissions can be seen as not adding anything further to the CO₂ that would have been emitted into, or existed in, the atmosphere if it had not been captured to make the e-fuel. For example, to the extent that the “same” CO₂ is captured from an industrial process and then incorporated into an e-fuel, the capturing process can be regarded as one in which emissions have been “avoided”, thereby reducing the overall amount of GHG emissions arising from that industrial process plus the end-use to which the e-fuel (that would otherwise have used fossil fuel) is put.

The Second Delegated Act imposes limitations on the permitted sources of CO₂ to be incorporated into an e-fuel to attain such a CO₂-neutral classification (such permitted deducted emissions being the Avoided CO₂ Emissions).

For e-fuel producers seeking to obtain RFNBO status, it is therefore of critical importance that the CO₂ being used in the production of the e-fuel can qualify as an Avoided CO₂ Emission in order to obtain the required 70% GHG emission saving.

3. What are Avoided CO₂ Emissions?

As set out above, the basic principle is simple enough, but in turning it into regulation – which, if complied with, will enable producers to attract subsidies or charge a green premium – legislators have to tread carefully to try to avoid creating perverse incentives for what might be environmentally unhelpful behaviour.

Accordingly, the Second Delegated Act begins straightforwardly enough by defining the following as being sources of Avoided CO₂ Emissions⁵: Emissions from “existing use or fate” that are avoided when the input is used for fuel production. However, after that, it gets more complicated.

These emissions would have been released as CO₂ into the atmosphere in any event prior to their capture and incorporation into the e-fuel⁶, and are eligible provided that the CO₂ is sourced from one of the following pathways:

a. CO₂ which has been:

(i) captured from specified industrial activities listed under Annex I to the EU ETS⁷ (e.g. oil refining, steel, cement, certain combustion installations) (Specified Industrial Source);

(ii) accounted for under an effective carbon pricing system (e.g. by paying a carbon tax or surrendering an emissions allowance); and

(iii) incorporated in the e-fuel prior to 1 January 2041 (or 1 January 2036 for CO₂ from fuel combustion for electricity generation);

b. CO₂ which has been captured from the air (e.g. through direct air capture technology);

c. CO₂ which has been captured from the production or the combustion of biofuels, bioliquids or biomass fuels:

(i) complying with the sustainability and GHG saving criteria under RED II; and

(ii) where the CO₂ captured did not receive credits for emissions savings from CO₂ capture and replacement under RED II;

d. CO₂ which has been captured from the combustion of RFNBOs or e-fuels complying with their own GHG savings criteria (i.e. recycling the same RFNBO-eligible CO₂); or

e. CO₂ which has been captured from a geological source of CO₂ where the CO₂ was previously released naturally (e.g. volcanic emissions or geothermal fields).

In addition:

a. the CO₂ must not be derived from combustion of a fuel deliberately for production of CO₂; and

b. the captured CO₂ must not have received any emissions credit under “other provisions of the law” (to avoid double-counting).

4. Considerations

a. CO₂ captured from industrial sources

Any CO₂ that is captured from a Specified Industrial Source must have been taken into account through an effective carbon pricing system, which would either be under the EU ETS (for EU domiciled industries), CBAM (for non-EU industries) or other state or national carbon pricing systems considered “effective”.

(i) EU ETS: The European Union Emissions Trading System (ETS) generally requires certain affected industries located in the EU to purchase and/or trade emissions allowances in order to cover their CO₂ emissions in the applicable year.

Whilst the EU ETS does not require emissions allowances to be surrendered for CO₂ that is captured for permanent storage, or for utilisation in such a way that it becomes permanently chemically bound (or mineralised), this exemption would not apply to CO₂ being sold for e-fuel production given that the incorporated CO₂ will be released on combustion of the e-fuel as noted above. An industrial producer would therefore still have to surrender emissions allowances or purchase allowances in respect of captured CO₂ that is intended for onward sales.

Therefore, the cost of the CO₂ being supplied will likely pass through the cost of the ETS allowances that will need to be surrendered/purchased in order to cover the captured CO₂.

CO₂ from Specified Industrial Sources may therefore be more expensive than CO₂ captured from other permitted sources. The time limitations on CO₂ from Specified Industrial Sources being an eligible Avoided CO₂ Emission⁸ will also impact its long-term viability as a source of CO₂ for e-fuel production.

(ii) CBAM: The European Union Carbon Border Adjustment Mechanism (CBAM), commencing in 2026, requires importers into the EU of certain carbon intensive goods (e.g. cement, aluminium, steel) produced outside the EU to pay for the carbon emissions associated with the production of such goods (to the extent not already paid for). The price to be paid is generally determined as the price of the emissions allowances that would have been required under the EU ETS had such goods been produced in the EU.

In theory, CO₂ from Specified Industrial Sources could be imported into the EU for the production of e-fuels. However, CBAM does not currently apply to pure CO₂, meaning that any imported CO₂ from industry could not satisfy the requirement for such CO₂ to have been accounted for unless (a) the jurisdiction of production has equivalent carbon pricing rules pursuant to which the imported CO₂ would have been accounted for in its country of origin or (b) the output of the industrial process which emitted the CO₂ (e.g. the aluminium or steel) was itself accounted for under CBAM on importation to the EU.

b. CO₂ captured from biogenic sources

CO₂ captured from the production or combustion of biofuels, bioliquids or biomass fuels (Biogenic Products) will qualify as an Avoided CO₂ Emission if the Biogenic Product produced or combusted:

(i) complies with the relevant sustainability and GHG emission savings criteria for such renewable fuels under RED II; and

(ii) did not receive any previous emissions credits.

The use of CO₂ from biogenic sources is proving to be the most popular pathway, which may be driven by the fact that the majority of biogenic sources of CO₂ are not subject to the temporal restrictions and carbon pricing considerations applicable to Specified Industrial Source CO₂.

There are, however, many biogenic production pathways for CO₂ and each pathway would need to be carefully considered on a case-by-case basis to ascertain if the resulting CO₂ could qualify as an Avoided CO₂ Emission, which would include analysis on the source of the biogenic material being used as a feedstock, how it is processed and for what the end product is to be used.

A few example biogenic pathways, and the regulatory considerations that would apply, are set out in the Annex to this article.

c. CO₂ from direct air capture

Capturing CO₂ from the atmosphere using direct air capture (DAC) technology certainly appears to be the most straightforward pathway to Avoided CO₂ Emissions from a regulatory perspective. However, due to the current costs of this technology coupled with the lack of policy incentives to use it, developers may be less likely to pursue this pathway. DAC technology is also more power-intensive for each unit of CO₂ captured, which may need to be considered in the overall GHG savings calculation and may limit such technology to locations with availability of hydro or geothermal power.

5. Final remarks

It is critical for e-fuel producers to ensure that CO₂ incorporated into the e-fuel is an Avoided CO₂ Emission.

As indicated above, there are many production pathways, but each one may have financial, technical, environmental or other constraints which will need to be analysed to ascertain which pathway will be optimal for each individual project.

This will involve careful consideration of the technical, commercial and legal landscape applicable to the relevant CO₂ supply chain and the robustness of the GHG emissions modelling of the full production and transportation chain which will be required to ensure that all relevant GHG emission reduction targets are capable of being met.

The complexities involved here, whilst not a roadblock to e-fuel production, may make it more difficult for the RED III targets to be achieved given the need for developers to expend time and cost to navigate these regulatory requirements.

ANNEX

Sample Biogenic CO₂ Pathways

No.	CO2 Production Pathway	Description	Avoided CO2 Emission Requirements	Notes
1	Biomethane Production	Biomethane is typically used as a renewable replacement for natural gas (which can be injected into natural gas grids) or, alternatively, it can be used for transport fuel. The production of biomethane involves the anaerobic digestion of biomass to produce biogas which is then separated into biomethane and biogenic CO2. The CO2 can therefore be captured and sold/used for e-fuel production.	Captured CO2 from this process could constitute Avoided CO2 Emissions under section 3(c) of this Article; CO2 captured from the production of a biomass fuel provided that: (a) the biomethane produced complies with the applicable RED II sustainability and GHG saving criteria; and   (b) in calculating whether the produced biomethane meets the GHG saving criteria, the captured CO2 emissions are accounted for.	The RED II sustainability criteria to be complied with will depend on: (a) whether any sustainability criteria apply. Note that only certain biomass fuels are required to fulfil the sustainability and GHG saving criteria under RED II. An example is if the installation producing the fuel has a specified average biomethane flow rate; (b) If the criteria are to be complied with then the specific criteria will depend on the type of biomass that is being used in the anaerobic digestion process (i.e. the feedstock). RED II contains different sustainability requirements depending on whether the biomass being used is agricultural biomass (including aquaculture and fisheries) or forestry biomass. If the biomass feedstock does not fall into either of these categories than only the GHG savings criteria need to be complied with. The GHG saving criteria to be obtained from the use of the biomethane will depend on how it is to be used (the overall GHG saving must be at least 65% if consumed in transport and between 70% and 80% if used for electricity, heating or cooling (depending on the total thermal rated input of the facility and the year in which such facility commenced operations)).(
2	Ethanol Production	Bio-ethanol is produced through the fermentation of starch rich crops (e.g. corn, sugarcane, wheat). Bio-ethanol can be used as a biofuel (i.e. a liquid fuel for transport produced from biomass). It is commonly used to replace petrol. As the fermentation process releases large amounts of CO2, this CO2 can be captured and sold/used for e-fuel production.	Captured CO2 from this process could constitute Avoided CO2 Emissions under section 3(c) of this Article; CO2 captured from the production of a biofuel provided that: (a) the ethanol produced complies with the applicable RED II sustainability and GHG saving criteria; and   (b) in calculating whether the produced ethanol meets the GHG saving criteria, the captured CO2 emissions are accounted for.	(a) The sustainability criteria under RED II that apply to food and feed crops will apply here. Notably, RED II places limitations on the amount of biofuels, bioliquids and biomass fuels produced from food/feed crops that can be counted towards the EU’s decarbonisation targets. This is because production of these fuels present a risk of land use change (from food production to biofuel production). By 2030, biomass fuels produced from food or feed crop with high indirect land use change risk cannot contribute to the EU’s renewable energy targets. As such, in order for biofuels made from food or feed crop to contribute to the EU’s renewable energy target (subject to the mandated cap), they must be certified as “low indirect land use change risk”. Obtaining this certification requires the feedstock to have, amongst other things, been produced in a sustainable manner which avoids the displacement effect of food and feed crop based fuels. (b) The required GHG saving from the use of biofuels in the transport sector is 65%.
3	Combustion of municipal waste to produce electricity in facilities with a total thermal rated input exceeding 20 MW	Waste to energy plants can burn municipal solid waste, including the biomass portion of such waste. Burning the waste releases heat, which converts water to steam. The steam is then used in a turbine generator to produce electricity.	Under regulatory consideration.	Waste to energy facilities of this size are currently covered by the EU ETS for monitoring and reporting purposes only (meaning that, whilst such CO2 emissions have to be reported, they do not currently need to be covered by ETS allowances). The legislative rationale for this approach, as set out in the EU ETS, is to enable the Commission to consider the reported data by 31 July 2026 to ascertain whether the scope of the EU ETS should be expanded to cover incineration of municipal waste from 1 January 2028 and whether member states should be able to “opt out” until 31 December 2030. There is therefore currently regulatory uncertainty as to whether CO2 captured from the combustion of municipal waste will need to fulfil the criteria applicable to the Specified Industrial Source pathway (which will be the case if the scope of the EU ETS is expanded to include municipal waste incineration). In the event that the EU ETS is so expanded, and without contemplating any other changes to the EU ETS or RED III as a result, all CO2 emissions from the combustion of municipal solid waste in the EU in facilities of this size would be “accounted for” under the EU ETS regime (either through ETS allowances being required to cover emissions from the non-biomass portion of the waste or through the reporting of emissions stemming from the biomass portion of the waste (noting that such emissions are zero-rated and do not therefore require ETS allowances)). However, the CO2 captured from this source would need to be incorporated into the e-fuel prior to 1 January 2036 (notwithstanding that some of the CO2 will come from the biomass portion of municipal waste and will therefore be “biogenic”).
4	Combustion of municipal waste to produce electricity in facilities with a total thermal rated input below 20 MW	As above	Assuming that CO2 emissions from the combustion of any biomass portion of municipal waste in facilities below the 20MW thermal rating would not fall under the scope of the EU ETS, such emissions can qualify as an Avoided CO2 Emission under section 3(c) of this Article; CO2 captured from the combustion of biomass fuel, provided that: (a) the waste complies with the applicable RED II sustainability and GHG saving criteria; and   (b) in calculating whether the GHG saving criteria have been met, the captured CO2 emissions are accounted for.	(a) In transposing RED II, member states are obliged to take into account the waste hierarchy set out in the Waste Framework Directive 2008/98 which places energy recovery towards the bottom, and prioritises prevention, re-use and recycling.   The laws of each member state transposing RED II would therefore need to be considered to ascertain if any national sustainability requirements apply with respect to the combustion of municipal waste, in light of the above.   (b) RED II specifies that electricity, heating and cooling produced from municipal solid waste shall not be subject to the GHG saving criteria. It is worth noting that, under RED II, member states are not permitted to grant direct financial support for the production of renewable energy from the incineration of waste, unless the waste collection obligations set out under the Waste Framework Directive have been complied with (which requires, for example, that bio-waste is separated and collected separately). It is therefore evident that biomass waste to energy is not the EU’s preferred source of renewable energy.

Chinese solar panel manufacturers, who collectively command approximately 95% of the global production capacity, have expanded their supply chains in recent years. At the same time, China’s industrial strategy has resulted in a slower domestic deployment of solar infrastructure. This trend has persisted over an extended period, resulting in an influx of cut-price solar panels within the European market, with pricing that challenges the viability of European manufacturers. The result of this market dynamic are twofold: some European manufacturers are compelled to explore alternative markets such as the U.S, while others have faced insolvency. The remaining European manufacturers are also grappling with the challenge of surplus inventory that is proving difficult to sell.

Historically, Europe boasted a robust solar manufacturing sector. However, the entry of lower-cost Chinese products precipitated a downturn in the European market. In response, Europe implemented anti-dumping tariffs in 2013 to safeguard its interests, albeit with limited impact. Recent years have witnessed a modest revival in European photovoltaic polysilicon and module production, yet Europe’s contribution to global output lingers at a modest 3-4%. Energy security has climbed to the top of the political agenda, in large part due to supply chain disruptions from the COVID-19 pandemic, the Russian gas crisis, and logistical complications in the Suez Canal. Europe now faces the challenge of Chinese overproduction and aggressive pricing strategies. 

What are EU solar manufacturers calling for?

One suggestion has been a buyout of European manufacturers’ inventory. A buyout would be a short-term solution which could alleviate the immediate solvency concerns of European manufacturers however it will not change the dynamics of the current market.

A Solar Energy Charter has gained traction in the industry as a possible response to demand side challenges. Drawing parallels with the Wind Energy Charter, where member states pledged to adopt measures such as non-financial prequalification criteria in procurement processes, the aim is to guarantee a portion of the supply chain remains distinctly European.

There are a lot of factors to be addressed to not just secure the immediate future of European solar manufacturing but to ensure it can flourish in the future. Europe needs to alleviate the immediate solvency concerns, increase the supply of modules manufactured in Europe, increase the demand for those modules, and make European manufactured modules more competitively priced which can only be done with scale.

To scale up manufacturing, address supply concerns and enable better price competition further subsidies will be needed. One solution is a subsidy for operational expenditure (noting that energy and labour prices are much higher in Europe than China), or counter-guarantees for manufacturers to secure the finance required to scale up manufacturing capacity.  

The way in for European manufacturers to re-emerge may be via new technologies or processes, for example, resulting in the reduction of water usage and waste in the  production of polysilicon and wafers.  It remains to be seen if this will be the case, although there are some green shoots in Europe which demonstrate this.

What else has been suggested as a possible solution?

The Net-Zero Industry Act (NZIA) has been touted as a possible solution and whilst it brings a simplified regulatory framework, Europe needs to consider whether its market design is fit for purpose to enable the growth of solar manufacturing capability. Comparing against the IRA where there is a ‘per watt’ subsidisation of manufacturing, whilst the NZIA is a positive reaction to the IRA, greater regulatory intervention is likely to be needed to support the industry.

Other methods are an exclusion of Chinese panels or high tariffs. A near-complete exclusion of cheap Chinese panels would further undermine Europe’s Green Deal targets as it would reduce the supply of Chinese panels and the development of solar projects, in favour of local manufacturing.

In terms of higher tariffs, Europe has recent history to look back on. In 2013 the European Commission imposed substantial tariffs on Chinese manufactured solar panels (at a time where Europe was particularly strong in the solar PV market). It contributed to a substantial decline of solar deployment in Europe and it did not provide any help to solar manufacturers in Europe. Given that Chinese-made panels can be produced for half of the cost of those manufactured in Europe, it is unlikely to give the European market the competitiveness it needs.

Increasing the cost of Chinese imports to align with Europe will not be the same as bringing European costs down because of the current economic environment and due to the sensitive project economics for European solar project developers. Many solar developers are reluctant to incur higher costs for European solar products when more economical international options are available however for some sentiment has shifted recently with some willing to pay a ‘green premium’ when dealing with suppliers with strong ESG credentials. We are also seeing solar module prices (from China) come down on the projects we are working on to the extent that clients have delayed executing their module supply agreement or purchase orders to obtain better prices from Chinese manufacturers.

Is the U.S also a concern for Europe in light of the IRA tax credits?

Some European manufacturers such as Meyer Burger have decided to close plants in Europe and focus on the U.S market, likely in light of favourable regulatory conditions under the IRA. Whilst direct support for renewable energy manufacturing is a small fraction of the total funding in the IRA, the manufacturing costs that are covered are substantial. It is possible that this may spark a trend but for broader reasons than IRA tax credits. A large proportion of the tax credits are applied towards the adoption of net zero technologies which has greatly increased the development of solar projects and demand for manufacturing capability. The U.S is likely to become (outside China) much more dominant in polysilicon and module production providing further competition to Europe.

Where does this leave policymakers?

To enhance energy supply chain security, will need to confront the inherent structural disadvantages of the European market, which includes higher costs for utilities (even before recent power price volatility), given the energy intensive nature of manufacturing, as well as raw material and personnel costs.

Another key question for policymakers will be how to support the scale-up. European companies will only be competitive against Chinese imports where they are able to achieve economies of scale with multi-gigawatt production capacity per site, across multiple sites. European manufacturers will also need to be adaptable to new technologies including higher levels of automation to realise efficiencies.

Whilst it is unlikely to close the gap in the timescales required to keep European solar manufacturers in the market, Europe could adopt new technologies to become more competitive. Higher cell efficiency which in turn brings greater power per module would bring down the per watt cost. To achieve this, European governments could consider R&D grants for manufacturers.

Regulatory developments in Europe have shown promise, including the revision of EU State Aid rules under the Temporary Crisis and Transition Framework. This allows the construction of solar factories to be subsidised by EU member states. While this is a positive step, it does not fully address the competitive disparity. With operational costs in Europe significantly outpacing those in the U.S. or China, manufacturers may be able to construct factories but find the operational expenses prohibitive, impeding their ability to scale. A potential remedy could involve state assistance for operational costs, not solely for capital investments.

If you would like to discuss module procurement strategies, contracting, or how to ensure that your supply chain meets today’s ESG standards please get in touch.

A decade of delivery…

On 18 July 2024, Energy Secretary Ed Miliband made a statement to Parliament on the new government’s “clean energy superpower mission”, which includes “zero carbon electricity by 2030”. Early on, he referred to the UK’s Climate Change Committee’s annual “progress report”, which was published the same day.

The stand-out graphic from the report (below) emphasises the CCC’s concerns about the credibility of the previous government’s policies and plans to deliver the next two five-yearly carbon budgets.

The targets underlying the CCC’s assessments are the less ambitious ones set by the previous government (e.g. aiming to decarbonise power supply in 2035). The CCC’s findings that the UK was “slightly” or “significantly” off track in half of the areas where progress is required are all the more urgent from the perspective of the new government’s desire to decarbonise faster and further.

It is little comfort that, in decarbonising too slowly, the UK is to a large extent reflecting global trends  (as analysed, for example, in the 2024 edition of BP’s Energy Outlook a few days earlier).

The CCC’s “top ten” policy recommendations to get back on track are generally unsurprising.

• Most call for regulatory actions (e.g. reinstating the date for phasing out fossil-fuel vehicles, getting the design of CfDs right for the next allocation rounds).

• At least one (“introduce a comprehensive programme of decarbonisation for public sector buildings”) poses an interesting challenge for a new government keen to demonstrate the power (and value for money) of public-private partnership.

• Two (on “engineered removals”, and on trees and peatlands) emphasise the importance of removing CO₂ from the atmosphere, as well as avoiding CO₂ emissions in the first place.

The CCC’s full report and accompanying documents are here; for an excellent summary see here.

Flying start

New Ministers have not been short of advice on energy and climate change priorities. A few days before the CCC report was published, another to-do list arrived in the form of Aviva Investors’ thorough and detailed “policy roadmap” on Boosting Low Carbon Investment in the UK.

The new government took a step recommended by both Aviva and the CCC on 8 July 2024 by removing the effective block on onshore wind farms in England getting planning permission.

A day later, the government announced the appointment of former CCC chief executive Chris Stark to head the “control centre” to co-ordinate the mission to decarbonise the grid by 2030. AFRY, in a report for OEUK, have since outlined what it is likely to take, in infrastructure terms, to achieve that goal.

On 17 July, the King’s Speech, announcing an extensive programme of government Bills in the first session of the new Parliament, highlighted several items relevant to the energy sector (see here).

• A Great British Energy Bill will begin the process of establishing Great British Energy. With an initial capitalisation of £8.3 billion, this publicly owned developer, owner and operator of energy sector assets will facilitate, encourage and participate in clean energy projects, the reduction of energy sector GHGs and improvements in energy efficiency. It is also intended to “oversee the biggest expansion of community energy in British history”. (See further the subsequently published “founding statement” for GBE and other documents here.)
• A Crown Estate Bill will enable the Crown Estate, which already has a central role in the UK offshore wind sector as the landlord of the seabed, to borrow and to invest in a wider range of companies and projects that will support the development of that sector.
• A Sustainable Aviation Fuel (Revenue Support Mechanism) Bill will aim to accelerate the commercialisation of SAF by providing a revenue certainty mechanism for those seeking to produce it in the UK and meet the demand for SAF stimulated by an obligation on aviation fuel suppliers to have at least 10% SAF in the fuel they supply to airlines.
• A National Wealth Fund will be established, with an initial budget of £7.3 billion, building on the work of the UK Infrastructure Bank, to invest directly in priority sectors as part of the government’s “industrial strategy and growth” and “clean energy superpower” missions.
• Speeding up consents for electricity networks and other energy infrastructure will be a key focus of the Planning and Infrastructure Bill, as it attempts to shorten the seemingly ever-lengthening timescales for determining applications in respect of major infrastructure projects.
• The development and maintenance of energy networks and other infrastructure will also be facilitated by the National Underground Asset Register, which is to be put on a statutory footing by a Digital Information and Smart Data Bill.
• The safety, accuracy and efficiency of products placed on the UK market that use or measure energy is regulated by what were originally EU rules. The Product Safety and Metrology Bill, aiming to support growth, provide regulatory stability and protect consumers, will allow the government to “mirror or diverge from updated EU rules” without primary legislation.
• The current cyber security regulations, on the other hand, which are also of EU origin and relate to energy and other sectors, are to be updated by a Cyber Security and Resilience Bill. 
• Like other sectors where growth may be constrained by a shortage of skilled labour, the energy sector should benefit from the new institutional framework of the Skills England Bill.
• No doubt there is an expectation that the Pension Schemes Bill will benefit energy projects as it “enables pension schemes to invest in a wider range of assets, driving growth”.

UK energy policy could not be more prominently placed. The aims are clear. With energy security, climate change and the growth agenda all in the frame, the stakes could scarcely be higher.

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