Consultation outcome

Government response to the proposed refinements for Allocation Round 8 and future allocation rounds (accessible webpage)

Updated 1 June 2026

Context

Delivering clean power by 2030 is at the heart of the Government’s mission to transform the UK into a clean energy superpower. Contracts for Difference (CfD) is the Government’s flagship policy for incentivising new low carbon electricity generating projects in Great Britain and is therefore central to the Clean Power mission. 

Including Allocation Round 7 (AR7) results, the CfD and its predecessor investment contracts have already delivered 10GW of renewable capacity, with a further 36GW contracted to become operational. Since we published the AR8 consultation in December 2025, the country has taken another significant step towards moving away from volatile fossil fuel prices, as a result of the record-breaking capacity secured through AR7.

On 14 January this year, the Government announced^{[footnote 1]} that a record 8.4GW of new offshore wind had been secured in the UK and Europe’s biggest ever offshore wind auction. This was followed on 10 February by the announcement^{[footnote 2]} that Government had secured an additional 6.2GW of new onshore wind, solar and tidal stream projects. In total AR7 secured 14.7GW of clean, homegrown generating capacity, across 201 new projects, enough to power the equivalent of 16 million homes. These new developments will unlock some £27 billion in private sector investment and support several thousands of new good jobs.

Chapter 5 of the December 2025 consultation sought views on several amendments to CfD regulations to improve the operational efficiency of the scheme during the assessment of applications from developers wishing to participate in a CfD allocation round. A summary of the consultation responses and the Government’s final policy decisions was published in a separate government response on 20 March 2026^{[footnote 3]}.

Overview of consultation proposals

The proposals in the December consultation covered a range of areas, including:

• policy on surrendered CfD capacity – making permanent the restriction on bidding previously surrendered capacity into future rounds to protect auction integrity and deployment timelines
• hybrid metering for single technology/multiple commercial arrangements – enabling CfD and merchant assets of the same technology to share metering infrastructure, reducing costs
• contractual changes for floating offshore wind (FLOW) – extending the Longstop Period and reducing the Required Installed Capacity threshold to reflect the scale and complexity of future projects
• introducing a new technology category for Other Deepwater Offshore Wind (ODOW) – enabling innovative foundation designs for deepwater sites to compete for CfD support
• strengthening Unilateral Commercial Operations Notice (UCON) provisions – improving metering access for LCCC and enforcement of these provisions for distribution-connected generators
• excluding applications with Gate 1 connection offers – aligning CfD eligibility with grid connection reforms to prioritise projects with firm connection dates
• visibility of sealed bids – changing our approach to the ability of the Secretary of State to see bids for AR8
• minor and technical changes to the CfD contract terms – updating the CPI inflation factor in the CfD Standard Terms and Conditions and amending the definition of Inside Information

Responses to the consultation

Responses to the consultation were submitted through an online response tool (Citizen Space) or by email. The consultation received 79 responses from stakeholders. The majority of responses were from developers, with several responses from other stakeholders, including trade associations, investors, supply chain companies, public bodies, individual members of the public and others interested in the renewables sector. The number of respondents to each question is indicated in accordance with the terms described below. The government is grateful to stakeholders for taking the time to engage with the consultation.

In reporting the overall response to each question, the ‘majority’ indicates the clear view of more than 50% of respondents in response to that question, and ‘minority’ indicates fewer than 50%. The following terms have been used in summarising additional points raised in the responses: ‘most respondents’ indicates more than 70% of those answering the particular question; ‘a few respondents’ means fewer than 30%; and ‘many/some’ refers to the range in between 30% and 70%.

Summary of decisions

Following the consultation earlier this year, the government has decided to implement these changes to the CfD ahead of AR8 opening in July:

• surrendered CfD capacity will be permanently restricted from bidding into future rounds to protect auction integrity and deployment timelines
• hybrid metering for single technology/multiple commercial arrangements will be enabled, allowing CfD and merchant assets of the same technology to share metering infrastructure
• for FLOW, the Longstop Period will be extended and the Required Installed Capacity threshold will be reduced to align with fixed-bottom offshore wind
• a new technology category for ODOW will be introduced
• the UCON provisions will be strengthened
• applications with Gate 1 connection offers will be excluded from participating in AR8
• visibility of sealed bids will be extended to solar and onshore wind (including remote island wind), alongside fixed-bottom offshore wind
• minor and technical changes to the CfD contract terms will be implemented

Note: Assessment of impacts have been included for sections which potentially have material impacts on developers or consumers. These are not included for more technical/process changes due to these likely having minimal impacts.

Explanation of changes to the CfD Standard Terms for Allocation Round 8

Regulation 4(1) of the Contracts for Difference (Standard Terms) Regulations 2014 (as amended) requires that where the Secretary of State publishes revised standard terms in compliance with section 11(5) of the Energy Act 2013, the Secretary of State must also publish an explanation as to why the revisions have been made.

This Government response and the response on Contract amendments to implement Clean Industry Bonus reforms published^{[footnote 4]} on 11 May 2026 explain why revisions to the standard terms have been made for AR8.

In this respect, ‘standard terms’ includes Version 8 of the CfD Standard Terms and Conditions, the CfD Agreement and the corresponding versions of the Phased (Apportioned Metering) Terms, Phased (Single Metering) Terms, Private Network Terms and Unincorporated Joint Ventures Terms, which will be published alongside this response.

Policy on surrendered CfD capacity

Proposal

The Permitted Reduction and Final Installed Capacity contractual flexibilities were not intended to be used in a way which allows developers to bid back into a subsequent CfD allocation round with the surrendered capacity. The government therefore proposed to retain the restriction introduced for AR7 on generators being able to apply into AR8 and subsequent allocation rounds with surrendered capacity.

To facilitate this, we proposed to keep the current Rule 5 (‘Excluded Applications’) restriction and Schedule 5 eligibility checks within the Contract Allocation Framework. The exclusion would apply to all projects which were previously awarded a CfD agreement in a prior allocation round. For example, for AR8, this exclusion would apply to all projects from allocation rounds 1 to 7.

For the avoidance of doubt, our proposal does not interfere with the ability of CfD generators to exercise their right to reduce their project capacity as permitted by the contract to accommodate changing circumstances around the construction of their projects.

Summary of consultation responses

There were 58 responses to Questions 1 and 2, though not every respondent answered every question. The majority of responses were from trade associations and developers.

Question 1 sought views on maintaining the exclusion. The majority of respondents agreed with excluding generators from applying into AR8 and subsequent allocation rounds with surrendered capacity. Some respondents did not agree with the proposal, outlining that the exclusion follow the Non-Delivery Disincentive exclusion of two allocation rounds for terminated projects.

Question 2 sought views on the assessment of impacts of maintaining this policy. The majority of respondents agreed with the assessment of impacts outlined in the proposal.

Assessment of impacts

Based on the responses to question 2, we believe that the assessment of impacts provided at the consultation stage remains suitable and that the proposed exclusion could have the following effects:

• potential savings to electricity consumer costs by preventing surrendered capacity from rebidding into a subsequent allocation round and achieving a higher strike price for commercial gain
• ensures a strong incentive is maintained for project developers to bid sustainably, wherever possible pricing an appropriate level of risk into their bids, and locking in prices early through supply chain contracts
• greater certainty for the supply chain that capacity secured is more likely to build out according to the original bid timelines
• ensures positive public perception of the CfD scheme as a means of delivering new build renewable electricity generation at a low cost
• a potential risk of the change is that it could prevent or slow renewable electricity deployment if developers would have sought to use this flexibility in order to respond to changes in project economics that would otherwise make their projects commercially unviable

Overall, allowing surrendered capacity to bid could lead to impacts on value for money. The introduction of 20-year CfD contracts for solar, onshore wind and offshore wind technologies may incentivise some generators to surrender capacity to secure a lengthier contract for a portion of their facility. Generators seeking to improve their contract terms may then lead to situations where previously awarded capacity is being recycled at the expense of newer developments, leading to ineffective budget utilisation. At the same time, generators choosing to exercise the flexibilities in this manner would essentially be moving a portion of their facilities to a later delivery year, thus potentially delaying deployment. Continuing to allow surrendered capacity to bid back in could promote sustainably priced bids and give an opportunity to ensure as much capacity is built as possible. However, there is also an additional risk where generators aiming to bid back in may be unsuccessful in the subsequent auction leading to the surrendered capacity not being built at all. This would be detrimental to the Government’s deployment ambitions.

Policy Response

We will maintain the exclusion on surrendered capacity applying into AR8 and subsequent allocation rounds. The Draft Contract Allocation Framework outlines how this exclusion is applied.

Hybrid metering for single technology/multiple commercial arrangements

Proposal

Reliable and robust metering is fundamental to the integrity of the CfD scheme, protecting consumers and ensuring good value for money. Under the Standard Terms and Conditions of the CfD contract, each CfD Facility must be registered and metered as a separate Balancing Mechanism Unit (BMU), a requirement introduced to ensure CfD payments are recorded and settled accurately. Technological advancements mean it is now more practical to meter CfD facilities at the point of generation, reducing the need for separate BMUs. The Government therefore consulted on relaxing this requirement by introducing a limited form of ‘hybrid metering’.

We proposed allowing multiple CfD facilities, and CfD and merchant facilities, of the same technology type to share a BMU - hybrid metering for single technology/multiple commercial arrangements or Type 1 Hybrid BMU (HBMU), as described in NESO’s review of hybrid metering arrangements^{[footnote 5]}. In these arrangements, sub-metering is used to distinguish separate commercial arrangements within the same BMU.

We separately consulted on the contract changes required to enable this change. 

Summary of consultation responses

There were 56 responses to questions 3-6, although not every respondent answered every question. Most responses were from developers and industry trade bodies.

Question 3 asked if respondents agreed with the proposal. There was broad support, with most respondents seeing it as a positive and necessary modernisation.  Respondents wanted to ensure that monitoring was proportionate and stressed the importance of clear technical guidance on hybrid metering. A few respondents argued that preventing CfD facilities from sharing a BMU with any asset subsidised under another Government scheme was overly restrictive. A few respondents also felt that the proposal would have a limited impact on projects supplying electricity to oil and gas facilities, as CfD generators are prohibited from supplying such facilities directly.  

Question 4 sought views on the proposal to restrict multiple CfD facilities from the same allocation round sharing an HBMU, with exemptions for tidal and phased offshore wind projects. The majority of respondents agreed with this proposal, with a few emphasising the importance of reducing gaming risks and protecting consumers. However, most respondents requested additional exemptions, arguing that without these, the benefits of the proposal could be limited.

The most common exemption requested was for projects with staged grid connection agreements. Respondents said that it was increasingly common for onshore wind, solar and repowering projects to receive such agreements, often spanning multiple years. Respondents asked to use hybrid metering when splitting up projects and submitting multiple CfD applications into the same allocation round across separate delivery years.

A few respondents requested exemptions for mixed-technology projects, for example combining fixed-bottom offshore wind, floating offshore wind, other deepwater offshore wind and wave energy.

Question 5 sought views on the use cases and assessment of impacts outlined in the proposal, and asked respondents to provide any supporting evidence. The majority of respondents who provided further detail believed that hybrid metering could deliver cost savings through shared metering and electrical infrastructure, reducing duplication and simplifying site designs. They referenced the benefits of incorporating merchant capacity more flexibly into site designs, derisking projects by diversifying revenue streams, and the ability to adapt sites to future conditions. Some respondents agreed that hybrid metering could support the deployment of small amounts of additional capacity and enable more efficient use of existing grid connections. A few respondents believed that the costs to the LCCC and generators would be small compared to the benefits. We received no quantitative evidence on potential cost savings or capacity estimates.

Question 6 sought views on whether there were any other use cases, benefits or risks arising from the proposal. A few respondents suggested that hybrid metering could be useful in the context of repowering. The majority of respondents were keen for progress to be made on allowing hybrid metering for multi-technology generation, storage and demand technologies, with respondents arguing that this would support more complex co-location configurations. Some stakeholders called for hybrid metering that would allow CfD facilities to share an HBMU with battery storage, arguing this would allow electricity generated during negative pricing periods to be stored and released later.

Assessment of impacts

Based on the responses to questions 5 and 6, we believe that the assessment of impacts provided at the consultation stage remains appropriate and that the changes we have proposed could have the following effects:

• Cost savings - allowing CfD facilities to share a BMU with other CfD facilities and merchant facilities of the same technology could lower development costs. While the meters are inexpensive, a full separate electrical circuit is required for each BMU, with associated costs for additional cabling, switchgear, electrical equipment and installation.
• Additional capacity - this proposal could help generators to bring forward more renewable capacity by allowing them to add a small amount of merchant capacity when finalising their project design or choosing their equipment manufacturers, rather than having to reduce their initial CfD capacity (via Permitted Reduction or Final Installed Capacity). Allowing this change retrospectively would allow generators to increase their merchant capacity post-CfD start date. Bringing forward additional renewable capacity could benefit consumers by reducing wholesale prices as well as supporting Clean Power 2030 ambitions.
• Wider efficiency benefits – it is likely that there are some wider efficiency benefits of shared infrastructure (BMUs) including quicker deployment of renewable energy and positive environmental impacts.
• Administrative costs – enhanced monitoring by the LCCC, site audits, and on-going compliance in the form of external auditors and annual metering audits may add administrative costs to the LCCC and generators.

Policy Response

We intend to implement our proposal to introduce hybrid metering for single technology/multiple commercial arrangements in the CfD from AR8.

Hybrid metering will be optional. Generators can give notice to the LCCC to request approval for the CfD Facility to become part of an HBMU after contract signing, at any time during the term. Requests must meet approval conditions set out in the contract. The LCCC will publish guidance ahead of AR8 opening to provide clarity on requirements.

Generators who already hold a CfD agreement (AR7 and earlier) can make requests for hybrid metering to the LCCC. It will be at the LCCC’s sole discretion to approve such requests for hybrid metering and make the necessary technical amendments to existing contracts.

NESO’s review found Type 1 HBMU with CfD and merchant assets low-risk and acceptable from an operational standpoint. However, NESO identified additional complexity for Type 1 HBMUs involving other combinations of commercial arrangements, beyond CfD and merchant assets. As such, CfD facilities will not be permitted to share an HBMU with facilities subsidised under other Government support schemes. We will keep this under review.

CfD facilities can share an HBMU with merchant assets, including those with a Power Purchase Agreement (PPA). A CfD Facility will only be permitted to share an HBMU with merchant assets that supply an industrial or corporate offtaker if the offtaker is separately registered and metered with a separate BMU. The LCCC’s guidance will set out further detail on permitted arrangements. 

Multiple CfD facilities from the same allocation round will not be permitted to use hybrid metering, with exemptions for tidal and phased offshore wind projects. We recognise the case for widening exemptions to include projects with staged grid connections, which are becoming more common. There are several reasons why a generator might hold such an agreement, and they can take different forms. Given this complexity, we have been unable to address this issue in time for AR8 but we will consider this issue over the longer term. We believe the current options available to applicants with such agreements are adequate for the time being. We also acknowledge stakeholders’ requests for other exemptions, and we will keep this under review. 

Generators holding Private Network Agreements are not eligible for hybrid metering as this falls outside the scope of Type 1 HBMU.

We note some stakeholder interest in hybrid metering arrangements that would allow CfD facilities to share a BMU with battery storage, with the intention of enabling ‘load shifting’ during periods of negative pricing. Such arrangements fall outside the scope of Type 1 HBMU and are not presently feasible under wider market rules.

We acknowledge the interest from respondents in going further on hybrid metering in the CfD. NESO’s review also assessed Type 2 HBMU (multiple generation and/or storage technologies) and Type 3 HBMU (mix of generation and demand technologies) which our consultation proposal did not cover.

Locating assets of different technologies within the same BMU is not currently permitted by wider market rules, such as the Balancing and Settlement Code. NESO’s review concluded that Types 2 and 3 HBMU would give rise to substantial settlement, visibility, operational and system security challenges, requiring extensive market‑wide reform. 

NESO’s review also noted that many configurations sought by developers are already achievable under existing co-location guidance. In light of the introduction of hybrid metering in the CfD, the LCCC will update its co‑location guidance and keep this under review to reflect future developments. 

We encourage stakeholders to continue engaging with NESO on the findings of its review, including contributing evidence to inform any future consideration of hybrid metering and co-location arrangements, via box.hybridmetering@neso.energy.

We will consider any future amendments in light of wider market reforms or further innovation in this area. 

Contract amendments

We consulted separately from 4 March to 1 April 2026^{[footnote 6]} on the contract changes required to enable this policy reform.

Summary of contract responses

We received 3 responses to the contract consultation, all of which were from developers. The question numbers quoted below are those in the 4 March consultation.

Question 8 sought views on the proposed criteria for approving a Hybrid Metering Notice (Condition 89.4). The majority of responses broadly agreed with the proposed criteria. One respondent asked for clearer definition of what constitutes an “adverse impact” and which “costs” are relevant, including whether reasonable CfD counterparty costs should be explicitly referenced. Concerns were raised regarding the restriction on multiple CfD facilities from the same allocation round, in line with the responses we received in the policy consultation.

Question 9 sought views on the proposed Hybrid Metering Operational Conditions Precedent and associated timelines. All responses agreed with the introduction of Operational Conditions Precedent and timelines. One respondent questioned whether the six‑month Physical Transition Period would be practical in all cases, particularly for early projects, given the time required for commissioning, testing, and counterparty assessment. Another respondent identified a possible internal drafting inconsistency within Annex 9, where one provision requires the Hybrid Metering Physical Transition Date to occur within 6 months of approval to avoid revocation, while another provision states that the transition date cannot occur earlier than six months after approval. In addition, while respondents accepted the principle of withholding CfD payments during the transition period, one respondent considered that generators should be compensated for the opportunity cost of payments withheld for up to six months, including through the accrual of interest.

Question 10 sought views on the proposed suspension of payments and termination for non‑compliance with hybrid metering obligations. All respondents to this question agreed with the proposed approach, including suspending payments where information and monitoring obligations are breached and allowing termination where breaches are not remedied, citing that the proposals appear to mirror the approach for existing CfD arrangements. One respondent requested clearer guidance on what would constitute a breach and what remedial steps would be expected of generators.

Question 11 sought views on the proposed amendments to ensure separation of the CfD Facility and any Related Facility. All respondents to this question agreed with the principle of separating the CfD Facility and Related Facility, so that compensation and excluded losses apply only to the CfD Facility. One respondent raised that force majeure events may affect an entire site, and that in such circumstances it may not be practical or realistic to separate impacts attributable solely to the CfD Facility.

Question 12 sought views on the proposed approach to facilitate hybrid metering for phased projects. All respondents agreed with the proposed approach and supported enabling hybrid metering for phased projects. One respondent, however, suggested that simplified or separate arrangements could be considered for phased projects that do not involve related facilities.

Contract response

The government will proceed with the proposed contract amendments with minor amendments to Condition 89.4 and to the revocation of approval provisions relating to the Hybrid Metering Transition Date.

Hybrid Metering Notice: condition 89.4

The intention of the hybrid metering policy is to offer generators more flexibility and thereby encourage the development of more capacity. LCCC will assess hybrid metering requests in line with this policy objective. Condition 89.4 will remain as consulted upon to ensure that LCCC has sufficient flexibility to assess the wide range of potential impacts that may arise from different hybrid metering configurations. To provide generators with further confidence, Condition 89.4 will be amended to include reference to ‘acting reasonably’. Further detail on the practical application of the criteria will instead be reflected through LCCC issued guidance.

Hybrid Metering Transition

To allow sufficient flexibility for generators to complete their hybrid metering transition, the government has decided to amend Para 8 of Annex 9 (Revocation of approval) to allow for the Hybrid Metering Physical Transition Date to occur within 9 months (as opposed to the previously stated 6 months) of approval, providing a 3-month buffer while maintaining appropriate controls against undue delays. In response to the suggestion that generators should be compensated for payments withheld for the hybrid metering transition period, the government notes that CfD payments are due only when relevant contractual conditions have been satisfied, and amounts withheld during the transition period are not payments that are due but delayed. Generators are expected to complete the conditions as promptly as possible. The government therefore considers this approach appropriate and will maintain the provisions as consulted upon.

Suspension and termination for failure to comply with metering obligations

We note agreement with the suspension and termination proposals and therefore the suspension and termination provisions will remain as consulted on. LCCC issued guidance will include information to provide clarity on the circumstances in which a breach may be considered to have occurred and the steps expected to remedy it.

Application of Force Majeure to the Separation of the CfD Facility and Related Facility

We note a respondent’s concern that the definition of “Force Majeure” excludes Force Majeure events which impacts both the Facility (subject to the CfD) and the Related Facility (not subject to the CfD). This is not the case. Under the existing drafting, Force Majeure relief will be granted on the basis of whether a Force Majeure event has an impact on the Facility, irrespective of whether the same event also has an impact on other parts of the site. We will there maintain the provisions as consulted upon.

Approach to Phased Projects and Hybrid Metering

We note a respondent’s suggestion of having separate or simplified contractual arrangements for phased projects. Our position is that maintaining a single, consistent contractual framework for hybrid metering and phased projects provides greater clarity and predictability for generators and the LCCC, while continuing to support phased delivery. We will proceed with the approach consulted upon and do not propose further contractual changes in response to this question.

Floating offshore wind: proposed contract changes

Proposal

Taking into account the anticipated increase in FLOW project capacity to gigawatt scale, alongside other factors which may result in higher risk to FLOW projects’ construction timelines including weather sensitivity, and port and supply chain constraints, the Government consulted on whether to extend the Longstop Period for new FLOW projects to 24 months and reduce Required Installed Capacity (RIC) to 85%, in line with fixed-bottom offshore wind.

We proposed the necessary changes to the CfD Agreement and Standard Terms and Conditions to implement the proposed amendments.

Summary of consultation responses

There were 38 responses to the consultation. The majority of responses were from developers. We also received responses from individuals, investors, public bodies, suppliers, and trade associations.

Question 7 asked if respondents agreed that for new FLOW projects from AR8 onwards the Longstop Period should be extended to 24 months and the RIC reduced to 85%.

Responses to this question were overwhelmingly in agreement with the proposal. The majority welcomed the proposed change ahead of upcoming allocation rounds, noting that larger FLOW projects are expected to become eligible to bid into the scheme.

Several respondents indicated that they would also welcome additional changes to allow for greater flexibility in construction, such as increasing the number of delivery years available to FLOW projects to align with fixed-bottom offshore wind, a further extension of the Longstop Period to 36 months, and an extension of the current Milestone Delivery Date from 18 months to 24 months post-CfD award to better reflect the delivery complexity and offshore logistical challenges specific to FLOW projects.

A few respondents took the opportunity to suggest that similar flexibility would be helpful for other marine technologies, such as tidal stream.

Question 8 asked if the respondents agreed with the proposed drafting amendments to the CfD contract to implement these changes.

All responses to this question agreed with the proposal, although a few respondents did include caveats in their answers.

One respondent noted that they agreed, as long as these arrangements also apply to ODOW.

Question 9 asked if the respondents agreed with the assessment of impacts outlined in our proposal, including value for money, deployment timelines or wider risk implications.

All responses were positive except one, which was neutral.

One respondent, whilst agreeing with the potential impacts, noted that longer build windows increase exposure to construction cost inflation, supply chain volatility, and engineering, procurement and construction (EPC) counterparty risk.

Assessment of impacts

We invited views on the proposed contract changes to FLOW alongside views on the assessment of impacts set out in the consultation. The majority of respondents agreed with our assessment of impacts, with one noting that a longer build window could increase exposure to construction cost inflation, supply chain volatility and EPC counterparty risk.  Overall, we consider that the proposed contract changes to FLOW would help de-risk construction and support deployment at scale. This should be beneficial to consumers, as lower risk is expected to support delivery at lower cost.

Policy response

We therefore intend to amend the CfD Standard Terms and Conditions to extend the Longstop Period for new FLOW projects to 24 months and reduce the RIC to 85%. The Government also notes the specific suggestions in consultation responses, such as to further increase construction flexibility, which it will keep under consideration for future rounds. We keep CfD policy under regular review to ensure it remains appropriate, taking into account factors such as eligible project sizes and the maturity of the respective technologies. This includes whether to extend flexibilities in the construction phase to other renewable energy generation technologies, such as tidal stream, should it become appropriate to do so in future.

Offshore wind with innovative ‘Other Deepwater’ foundations: proposals for a new technology category

Proposal

For a CfD unit to be considered ‘floating offshore wind’, any foundation designs used must float. However, the Government is aware of novel ‘hybrid’ foundation designs which may be suitable for deepwater deployment and are distinct from established fixed bottom offshore wind foundation technologies, but do not technically float, and would therefore not be considered eligible as ‘floating foundations’ under the existing legal definition of ‘floating offshore wind’. We refer to this group of technologies as ‘ODOW’.

The government recognises that there has not yet been the scale of deepwater offshore wind deployment necessary for the sector to determine the most cost-effective technological solutions. The government therefore believes that the technology definitions applied under the CfD scheme should not represent a barrier to the deployment of new or innovative substructure technologies with the potential to unlock cost-effective commercial deployment of offshore wind in deeper waters.

To ensure that ODOW projects are appropriately recognised and treated under the CfD scheme, the government proposed a series of amendments to the Contract Allocation Framework and the CfD contract to create an ODOW technology classification, providing optionality to support ODOW projects in future allocation rounds.

Summary of consultation responses

We received approximately 50 responses across these questions. The majority of responses were from developers. We also received responses from individuals, investors, public bodies, suppliers, and trade associations.

Question 10 sought views from stakeholders on support for creating an ODOW technology class. A majority of responses were from developers. We also received responses from consultancies, individuals, investors, public bodies, suppliers, and trade associations.

A majority of respondents supported the adoption of an additional ‘Other Deepwater’ offshore wind technology category as defined. A few respondents raised concerns around the eligibility of specific foundation technologies for the ODOW technology class, or disfavoured the general approach of using geometric characteristics of the foundation substructure to determine eligibility for the ODOW technology class. A few developers also mentioned limited installation vessel availability, and the relatively low technology readiness of ODOW. A few respondents suggested specific adjustments or relaxations to the geometric constraints. A few respondents suggested alternative approaches based on water depth or functional substructure definitions. More than one respondent also suggested that the proposed definition be treated as transitional for AR8 and kept under review.

Question 11 sought views related to the Clean Industry Bonus (CIB). A few respondents identified that meeting CIB minimum standards could be relatively difficult for ODOW projects (for example, procurement options may be limited) or raised concerns around the close timing of the AR8 CIB application window, and publishing of AR8 Allocation Framework.

Question 12 sought agreement on the proposed contract and policy amendments to implement ODOW. A majority of responses were from developers. We also received responses from individuals, investors, public bodies,  suppliers, and trade associations.

A majority of respondents and developers agreed with the proposed contract and policy amendments to enable the new ODOW technology to participate in the CfD scheme. A few respondents stated that ODOW is already eligible to compete with established fixed-bottom technologies as Offshore Wind (in Pot 3 as defined for AR7) or raised concerns that the proposed changes would not achieve the desired policy outcomes.

Question 13 sought agreement with the assessment of impacts outlined in the consultation. A majority of responses were from developers. We also received responses from individuals, investors, public bodies, suppliers, and trade associations.

A majority of respondents agreed with the assessment of impacts, but some with caveats. Supporters pointed to ODOW’s potential to unlock deepwater capacity, stimulate innovation, and eventually lower costs through competition and learning; however, a few asked for quantification of the capacity unlocked and clearer consumer cost protections.

Assessment of Impacts

Based on the responses to question 13, we believe that the assessment of impacts provided at the consultation stage remains suitable and that the proposed contract changes to create an ODOW technology classification could have the following effect:

• Introducing the ODOW technology classification could have the potential to deliver a positive impact on overall Value for Money. The inclusion of nascent deepwater technologies in the CfD could help support the development of the sector as well as support the achievement of our carbon targets, while continuing to prioritise delivery of a low-cost power sector through a competitive process.

Policy response

With the proposals for an ‘Other Deepwater’ offshore wind technology classification receiving majority support, we will implement the changes for AR8. The Draft Contract Allocation Framework sets out how we will define ‘Other Deepwater’ offshore wind. The contract changes outlined in the December consultation have been implemented and can be viewed in the AR8 Standard Terms and Conditions published alongside this response.

While we acknowledge the concerns raised by a few respondents around the use of geometric thresholds to define eligible foundation technologies, and the low technology readiness and unproven nature of ODOW deployment, we consider that the proposed definition is sufficient to remove the barrier to CfD support for novel solutions to the deployment of offshore wind in deep water, while minimising the risk of adverse outcomes.

We will continue to keep the range of technical solutions that could enable cost effective deployment of offshore wind in deeper waters, and the definition of ODOW under review. The nature and level of support for ODOW deployment from AR8 onwards is dependent on auction parameters and budget decisions which are not set out in this document.

In the Clean Industry Bonus, projects using ODOW foundations will be required to meet the FLOW minimum standards, and ODOW foundations will count as ‘floating foundations’ in the CIB component list, meaning they will be eligible for the FLOW sub-budget. We will keep this under review so we can adapt the scheme as needed as a clearer picture on the cost of this technology emerges.

Removal of default bids

Proposal

To encourage bidders to bid their true value within the sealed bid window and to ensure better competition that supports value for money for consumers, we proposed to remove the rule and facility to assign default bids at the Administrative Strike Price (ASP) to qualifying applications who do not submit a sealed bid during the sealed bid window. Following this proposed change, an application for which a sealed bid is not submitted in the sealed bid window would be treated as if it had been withdrawn.

Before making a change, we wanted to understand the reasons why applicants might not submit a sealed bid within the appropriate window, and any impacts of removing the facility for assigning default bids or of the proposed approach.

Summary of consultation responses

There were 46 responses across Questions 22 and 23, though not every respondent answered every question. Most responses were from developers and generators. Responses were also received from industry trade bodies, investors, public bodies and individuals.

Question 22 sought views on why an applicant would not submit a bid within the sealed bid window. The majority of respondents provided reasons why an applicant may not submit a sealed bid within the bid window. Of respondents providing a reason, most cited changing project circumstances or uncertain economics making it hard to submit a competitive and deliverable bid. Many of these respondents suggested this may be due to unexpected changes or uncertainty around costs, supply chains or market conditions. Equally, a few respondents indicated that it may be due to financing uncertainties or considering alternative routes to market. Respondents suggested that, in these circumstances, it may be that an applicant is holding off on bidding until clarity emerges or that they do not bid because the project is no longer viable. In addition, a large number of respondents also cited administrative or technical barriers and errors that would prevent timely submission, with this being especially impactful for smaller developers with limited resources. Many other respondents considered that there was no good reason for not submitting a bid within the sealed bid window.

Question 23 asked whether respondents agreed with removing default bids. The majority of respondents supported the removal of default bids (96% agreed). Of those who gave a reason why, most referred to improving the integrity of the auction by promoting truer bidding behaviour, reducing complex auction processes and improving administrative outcomes. Respondents suggested that the proposed removal of default bids would help support auction price competition, effective price discovery and, importantly, consumer value for money. A few responses suggested that the proposal would deter speculative bids and only encourage viable, committed projects to bid. This would also reduce the risk of projects that fail to withdraw from the allocation round in time being awarded a CfD at the ASP and those CfDs ultimately needing to be terminated.

Policy response

We intend to implement the suggested changes proposed in the consultation and to amend Rule 13.6 and Rule 16 of the Contract Allocation Framework. This policy will also apply to any Pending Applicant - see the Pending Application section of the Draft Contract Allocation Framework. If an applicant is still classed as a ‘Pending Applicant’ during the sealed bid window, then they will be able submit a ‘Pending Bid.’ If any Applicant, including any Pending Applicant, does not submit a bid during the sealed bid window, then that Applicant’s application will be treated as withdrawn by the Delivery Body.

Preventing delayed CfD start dates: enhanced requirements for distribution-connected CfD generators

Proposal

We invited views on changes to the CfD contract terms to strengthen the Unilateral Commercial Operations Notice (UCON) provisions by introducing measures that enable LCCC to obtain near real-time metering information for distribution-connected generators.

Summary of consultation responses

There were 27 responses to Questions 24 to 26, though not every respondent answered every question. The majority of responses were from trade associations and developers.

Question 24 sought views on the proposal to introduce contractual measures to enable LCCC to obtain near real‑time metering information for distribution‑connected generators. The majority of respondents agreed with the proposal, recognising its role in strengthening UCON provisions and ensuring consistency with transmission‑connected projects. A few respondents suggested that metering data alone cannot determine commercial operation, as commissioning and testing activities may result in periods of full output without a project being operational. Others questioned whether the proposal was proportionate given existing CfD protections, particularly for smaller projects, and suggested requirements should be tailored or scaled accordingly.

A few respondents suggested that the timing of the new obligations should apply from the start of the Target Commissioning Window (TCW), rather than apply from meter installation, due to its potential impact on commissioning activities. Some respondents highlighted practical delivery constraints, including connectivity challenges at remote sites, short response timescales, and the need for flexibility where compliance is outside a generator’s control. Others therefore called for clearer guidance on the proposals, including whether the measures would apply to generators awarded contracts in earlier allocation rounds.

Question 25 sought views on whether Default Interest should apply under Conditions 10.4(C) and 18.6(C) where generators fail to provide required metering information or access. The majority of respondents agreed with the proposal, recognising Default Interest as a proportionate enforcement mechanism to incentivise compliance and support the integrity of the CfD scheme. However, several respondents stressed that Default Interest should apply only where a generator could reasonably have complied and called for relief where non‑compliance arises from circumstances beyond the generator’s control, such as technical or commissioning constraints. A few respondents disagreed with the proposal, arguing that financial penalties should be a measure of last resort and reserved for instances of deliberate or unjustified non‑compliance. Some respondents also called for clearer definition of how Default Interest would be calculated and applied, to provide greater transparency and certainty for developers.

Question 26 sought views on the assessment of impacts set out in the proposal. The majority of respondents agreed, noting that the measures could reduce the risk of delayed CfD start dates, protect value for money, and would not materially affect deployment timelines. Some respondents emphasised the need for proportionate implementation to avoid unintended costs or impacts on compliant projects, while one respondent called for clearer quantification of benefits, particularly regarding consumer savings from reduced strategic delays.

Assessment of Impacts

Based on the responses to question 26, we believe that the assessment of impacts provided at the consultation stage remain suitable and that the proposed provisions could have the following effects:

• Administrative costs – the government recognise that these proposed changes may introduce some minor administrative costs for distribution-connected generators, primarily related to enabling near real-time metering access.
• Consumer impacts - by ensuring timely and accurate operational data, these measures will help protect consumer interests by reducing the risk of generators strategically delaying CfD commencement to operate on a merchant basis at elevated wholesale prices – retaining revenues that would otherwise have been returned to consumers under the CfD payback mechanism.

Policy response

The government will proceed with the proposed measures to strengthen the operation of the UCON provisions in order to ensure effective scheme administration and protect consumers. These measures will apply to CfD contracts awarded from AR8 onwards.

Ensuring Metering Data is Viable for Determining Commercial Operations

Near real-time metering is intended to support scheme oversight and targeted engagement, not to treat metering, in isolation, as commercial operations. The UCON framework already includes objective thresholds that act as a trigger for the LCCC to consider whether further assessment is needed, and, as per Condition 3.26(A), provides the LCCC with a right, not an obligation, to issue a UCON if it considers commercial operations to have commenced. The thresholds set out in the Standard Terms & Conditions for intermittent and baseload technologies provide the basis for identifying sustained generation patterns that may indicate commercial operation but does not automatically result in enforcement.

We note that the LCCC would use metering information as part of a wider assessment and engagement process, informed by wider contextual information available (for example, known project status and relevant milestones such as connection dates), rather than as an automatic trigger. The LCCC would actively engage with generators prior to enforcement and consider mitigating circumstances as part of administering the provisions. Furthermore, as confirmed in AR5, generators may challenge the issue or content of a UCON using the existing dispute resolution framework. We also emphasise that the CfD contract includes existing safeguards linked to commissioning requirements.

Timing of Obligations

Enabling access to metering information from the point of meter installation supports a risk‑based monitoring and engagement approach, allowing the LCCC to build an evidential picture of generation patterns over time. This is intended to provide visibility rather than enforcement and does not alter the point at which a UCON may be issued. Under the Standard Terms and Conditions, a UCON cannot be enforced before the TCW begins, and early access to data therefore does not enable pre‑TCW enforcement. This approach is consistent with the original policy intent established at AR5^{[footnote 7]}. Early visibility therefore allows the LCCC to engage with generators in advance of any potential enforcement, reducing the likelihood of abrupt intervention and supporting proportionate administration. We will therefore proceed with the proposal of commencing metering obligations from meter installation, rather than the TCW, as set out in Condition 31.13.

Proportionality of Requirements

In response to emphasis on the proportionality of the UCON provisions, we note that these changes do not introduce a fundamentally new set of obligations, but will enable the LCCC to enforce existing UCON expectations effectively for all types of generators, including distribution-connected generators. The LCCC will ensure communications and guidance on how the process operates in practice is provided to all scheme participants, including those who may be less familiar with the operation of the scheme, to provide confidence on the intended administration of the provisions.

Application of Default Interest

We note that Default Interest under Conditions 10.4(C) and 18.6(C) would apply only where a reconciliation identifies an amount owed to the LCCC as a direct result of the Generator’s failure to provide required metering information or access during any period before OCP 2.1(C) has been waived or fulfilled. In such cases, once actual metering data becomes available, any Reconciliation Amount determined to be payable to the LCCC may attract Default Interest if the Generator could reasonably have complied with its metering obligations and the reconciliation relates to a period prior to the fulfilment or waiver of OCP 2.1(C). In such circumstances, once actual metering data becomes available and a Reconciliation Amount payable to the LCCC is identified, Default Interest, as defined in Condition 1 (Definitions and Interpretation), and applied in accordance with Condition 24 (Default Interest), would accrue on that amount. Default Interest is designed to address situations where a generator’s failure to provide information or access undermines the effective operation of the scheme, including circumstances where the LCCC must rely on estimated data in the absence of cooperation.

In response to respondents who argued that financial penalties should be a measure of last resort, we consider that Default Interest represents a proportionate lever within the existing contractual framework, providing a clear incentive for compliance while avoiding the need for a bespoke enforcement mechanism. Without such a mechanism, there would be a risk that generators could withhold or delay cooperation without consequence, potentially retaining funds or benefiting from delayed repayment at the expense of consumers.

Proposed exclusion of applications with Gate 1 connection agreements

Proposal

A key CfD principle and requirement, for generators connecting either to the transmission or distribution system, is to demonstrate a valid connection agreement which evidences that they can commission their CfD facility within the applicable delivery years. The expectation is, and has been, for developers to obtain such connection evidence prior to CfD application.

The NNESO has led the Connections Reform process aiming to positively transform the connections queue by prioritising projects which are both progressing and strategically aligned with the Government’s 2030 Clean Power ambitions and net zero. During the Code Modification Proposal (CMP) 435 Gate 2 to Whole Queue (G2tWQ) process, projects in the existing queue were assessed for strategic alignment and readiness. Following the assessments, projects were then issued ‘G2tWQ Notifications’ in December 2025 to determine whether they will be assigned either a Gate 1 or Gate 2 status which will determine the revised connection offer they will receive. The Gate 2 status is further categorised into either:

• Phase 1 (projects that align with the permitted capacity for 2030 as per Government’s Clean Power 2030 Action Plan and that are prioritised for connection by 2030) or
• Phase 2 (projects that align with the permitted capacity for 2035 as per Governments CP30 Plan, and that are prioritised for connection by 2035).

We consulted and proposed to set a requirement for all applicants to hold a Gate 2 connection agreement in order to be eligible in applying for the CfD, and to exclude projects from being eligible where they hold a Gate 1 connection agreement which would be administered through the Contract Allocation Framework (CAF).

Summary of consultation responses

In total, there were approximately 60 responses across questions 27 to 29, although not every respondent answered all of the questions. The majority of responses were from developers and industry trade bodies. We also received responses from individuals, investors, public bodies and Devolved Administrations.

Question 27 asked respondents if they agreed with the proposal. The majority of respondents agreed with the proposal in principle. Respondents outlined that Gate 1 connection agreements do not provide sufficient certainty on connection date, location and cost, thus do not have the same delivery certainty as Gate 2 connection agreements which can impact auction integrity and if included, could lead to Gate 2 projects losing out. Few further mentioned that the inclusion of Gate 1 projects would undermine CP30 and the connections reform regime, as Gate 2 projects are strategically aligned (including with wider strategic programmes) and are ready to deliver in comparison to Gate 1 projects who could push out Gate 2 projects. A few also mentioned that the proposal is aligned and consistent with the CfD’s design.

However, while agreeing, some respondents also outlined administrative, operational and project eligibility concerns arising from the timeline misalignment between the two processes. Respondents suggested a Gate 2 Notification, confirming a Gate 2 offer, should be sufficient and requested LCCC assurance/communication on grid delays with a few even suggesting the proposal should not be implemented for AR8 and the process should be reviewed to ensure further alignment. A few gave conditional support due to the administrative and operational concerns outlined above. A few respondents also requested further flexibility for Gate 1 projects, particularly those which have secured planning consent and those which are expected to receive protection clause 3a^{[footnote 8]} in the next connections application window (under CMP434), as these projects are guaranteed to receive a Gate 2 offer in the next window. A few respondents suggested both Phase 1 and Phase 2 projects should be eligible, while others made comments around the connections reform process more generally, including further transparency on gated connection window timelines, concerns around the impact on existing CfD projects and the need to align CfD and connection reform timelines in the future.

A minority of respondents disagreed with the policy proposal, outlining concerns that a complete restriction on all Gate 1 projects could impact deployment and competition which will in turn impact consumers. They suggested Gate 1 projects which may be eligible for advancement from Gate 1 to Gate 2 and/or are expected to receive protection clause 3a in CMP434 should be eligible as these projects are guaranteed a Gate 2 offer, have obtained planning consent and are viable projects. A few respondents further argued that a Gate 2 status does not evidence better delivery compared to projects with a Gate 1 offer, planning consent and protection clause 3a. A few respondents also disagreed as they outlined timeline concerns suggesting many projects may not receive their revised Gate 2 offers in time, which could lead to unintended consequences, or projects being rejected inadvertently, impacting deployment and competition, thus suggested DESNZ should consider Gate 2 Notifications as having satisfied the Gate 2 status instead of a Gate 2 connection agreement. Concerns around nascent technologies were also covered, and others suggesting Gate 1 projects that can demonstrate AR8 delivery, via confirmation from the network company, could also be considered. Concerns about exclusivity agreements not satisfying CfD eligibility criteria were raised and separately, concerns regarding the exclusion of Gate 1 Connection Point and Capacity Reservation (CPCR) were also raised.

Question 28 sought views on issues/concerns regarding the Connections Reform process and interaction with the CfD and proposed potential mitigations.

Respondents raised operational and administrative concerns about the misalignment between the two timelines suggesting many projects may not receive their revised Gate 2 offers in time, concerns that some projects may experience connection date delays and could be pushed out of AR8 delivery years, concerns regarding connection offer signings, connection uncertainty impacting project timelines and FID, possible attrition, reduced competition and auction liquidity, increased strike prices, concerns regarding grid liabilities, concerns about eligibility criteria not being clear and the need for clarification ahead of the round, concerns about not having final connection dates when navigating the Sealed Bid Window and suggestions that Phase 2 projects may still be able to deliver for CP30.

Respondents suggested a range of mitigations including:

• further flexibility for some Gate 1 projects such as those which have planning consent secured, or which may qualify for protection clause 3a in CMP434
• to allow Gate 1 with confirmation from NESO that the project is deliverable by the Target Commissioning Date
• a third delivery year
• Gate 2 Notification to assess eligibility instead of connection agreements;
• the Low Carbon Contracts Company (LCCC) to confirm grid delay provisions to provide assurances on connection delays
• to allow qualification based on pre-existing connection agreements;
• flexibility to allow eligibility based on advancement dates, at least until the dates are confirmed
• to allow all Gate 2 projects regardless of their Phase status, subject to the final date meeting connection agreement date requirements
• Target Commissioning Date/Window and Milestone Delivery Date flexibilities
• changes to the connections reform process
• aligning Delivery Year end-date with Connection Reform Phase 1 end-date
• obtaining evidence from NESO to confirm earlier grid entry dates
• DESNZ to publish an indicative calendar aligning CfD milestones to NESO Gate 2 Windows for investor certainty
• DESNZ to consider proposal once industry has more confidence in the Gated connection approach
• clarity on Gate review processes, certainty on timelines for Gate 1 to Gate 2 progression and monitoring the process for unintended risks
• conditional CfD awards for projects which can progress from Gate 1 to Gate 2 prior CfD contract signature
• to monitor the interaction between connections reform and the CfD and establishing an industry working group
• to only apply this proposal if the connection reform process and issuing of Gate 2 offers has occurred within 12-months prior to the CfD
• clarifying CfD eligibility criteria for AR8 – potential for a readiness-based approach for eligibility

Question 29 asked respondents whether they agreed with our draft assessment of impacts. The majority of respondents agreed with the assessment. Respondents outlined that a Gate 2 requirement improves delivery and deployment and delivers good value for money through credible bids.

Some respondents disagreed with the assessment of impacts. Respondents outlined concerns about competition, higher strike prices and impacts on consumers suggesting flexibility for some Gate 1 projects such as those which are expected to receive protection clause 3a in CMP434.

Assessment of impacts

Based on the responses to question 29, we believe that the assessment of impacts provided at the consultation stage remain suitable and that the proposal could have the following effects:

• Deployment – as Gate 1 connection agreements will not have a confirmed point of connection or connection date, there is significant uncertainty as to when these projects will be able to connect to the grid.
• Value for money – the inclusion of Gate 1 projects may increase auction competition as it may lead to more projects applying for the CfD. However, we believe that this could reduce the quality of viable applicants as these applications will be more speculative in nature due to lack of certain grid connection, budget could also potentially be spent on procuring Gate 1 projects which may be significantly delayed in connecting to the grid and generating low-carbon electricity.

We acknowledge that some respondents have raised concerns over the impact on competition and strike prices due to excluding Gate 1 projects. However, we believe there is likely to be enough Gate 2 projects to ensure competitive tension; we recognise for some technologies that this may be lower than for others.

Policy response

We are cognisant of the strong interactions between the Connections Reform timeline and AR8. Following the publication of our contract consultation on 16th December, NESO, Transmission Owners (TOs), Distribution Network Operators (DNOs) and wider delivery partners jointly updated the delivery timeline for Connections Reform on 13th February 2026, confirming additional necessary time was added to the process to deliver good outcomes^{[footnote 9]}.

We recognise that the policy proposal as framed in the consultation, could lead to many projects being ineligible due to Gate 2 offers potentially not being issued or signed and countersigned by close of the AR8 application window, which will open in July 2026. We have developed a set of mitigations to address the specific AR8 situation, which are discussed later in the response.  

We intend to proceed and deliver the key principles of the consultation policy proposal which is to exclude Gate 1 projects as these projects do not have a confirmed connection date or point of connection, thus have reduced delivery certainty. We will therefore exclude all projects which have either been issued, or are expected to receive, a Gate 1 connection offer in relation to the capacity and connection date on which their CfD application is based, with the exception of Gate 1 CPCR projects.

We understand that there are a number of Gate 1 projects which have obtained planning consent and are expecting to receive protection clause 3a during the first CMP434 window, expected to take place later this year^{[footnote 10]}, thus are subsequently guaranteed to receive a Gate 2 offer. However, as these projects did not satisfy the Gate 2 criteria during the initial G2tWQ process, these projects have not yet been assigned a queue position and are likely to join the end of the queue when they do receive a Gate 2 offer. Thus, these Gate 1 projects have no certainty on when they will be able to connect to the grid and will likely not be able to deliver within AR8 applicable delivery years. As such, the inclusion of these projects increases delivery risk, does not provide good value for money for consumers, may impact auction integrity and is not aligned to CfD principles and design. We maintain our expectation that projects must be able to demonstrate clear evidence and ability to commission their proposed CfD facilities with respect to the applicable delivery years, at the point of CfD application.

In comparison, projects are allocated a Gate 1 CPCR status, as outlined in the Connections Network Design Methodology (CNDM)^{[footnote 11]} and as approved by Ofgem^{[footnote 12]}, where there is a specific technical or commercial need to do so. Similar to Gate 2 projects, these projects have been assigned a queue position, alongside other Gate 2 projects during the G2tWQ process. As such, and unlike non-CPCR Gate 1 projects, projects with Gate 1 CPCR status will receive a connection date and/or point of connection in their Gate 1 CPCR offer which will remain the same once they are able to raise a Modification Application to convert their offer into a Gate 2. Thus, these projects have a clear, direct, and flexible route to a Gate 2 connection offer unlike other Gate 1 projects. The delivery case and risks pertaining to the inclusion of Gate 1 CPCR is therefore materially lower than a non-CPCR Gate 1 project and is more akin to a Gate 2. Thus, we believe the inclusion of Gate 1 CPCR projects is justified, aligned to wider-system reforms and may deliver positive system outcomes^{[footnote 13]}.

To implement the policy, and as a one-off exception for AR8 due to the ongoing connections reform process, applicants will be required to provide the ‘CMP435: G2tWQ Notification’ in its entirety to evidence and demonstrate a Gate 1 CPCR or Gate 2 status, or where they are in receipt of a Gate 1 CPCR or Gate 2 connection agreement, they will have to provide the full connection agreement^{[footnote 14]}. Where applicants are not in receipt of a revised G2tWQ connection agreement, applicants will have to rely on their existing pre-reform connection agreement which will be assessed in accordance with the connection’s agreement criteria outlined in Schedule 5 of the CAF.

For the avoidance of doubt and for AR8 only – where an applicant has relied on their pre-G2tWQ connection agreement to satisfy eligibility criteria, there is no requirement on the applicant to provide the new G2tWQ connection offer/agreement to the Delivery Body at a later stage within the Contract Allocation Process. However, successful applicants may need to provide their new G2tWQ connection offer/agreement to the LCCC after CfD contract signature for other contractual reasons.

As an enduring policy position, projects for AR9 and beyond, will be required to have obtained and evidence a Gate 1 CPCR or a Gate 2 connection agreement at the point of CfD application. To support this enduring policy position, DESNZ will continue to monitor the implementation of the Connections Reform process, working closely with NESO.

Additional safeguards for AR8

Furthermore, as a one-time exception for AR8, we are implementing further mitigations and safeguards to help projects navigate the Connections Reform transition.

Decelerated projects

We are aware that some projects waiting for their revised Gate 2 offers may have been notified of an indicative ‘deceleration’. This situation only impacts projects which currently hold a connection date in their existing connection agreement which is aligned to Phase 1 (2026 – 2030), but the G2tWQ process has now notified these projects of a Phase 2 status (being prioritised for 2031 – 2035). We understand the ‘Phase’ status is only indicative in terms of future Gate 2 connection date, and projects could still, in theory, receive a date which is aligned to Phase 1 or a Phase 2 date which is still eligible^{[footnote 15]}. Thus, we will not be excluding these projects on this basis^{[footnote 16]}.

Where the new Gate 1 CPCR/Gate 2 connection offer has been issued, but not signed and countersigned, eligibility will be assessed on the current connection agreement the applicant holds at the point of CfD application and the G2tWQ Notification.

This approach is consistent with our rationale for including Gate 1 CPCR projects: decelerated projects were still assigned a queue position during the G2tWQ process, thus even where decelerations have occurred, they are not likely to be towards the back of the Gate 2 Phase 2 queue and therefore have materially better delivery certainty than non-CPCR Gate 1 projects.

Advanced projects

To maintain consistency and fairness with the ‘deceleration policy provisions’ above, we are also introducing flexibility for projects which have applied into the G2tWQ process on an ‘advancement’ basis, where they have requested an earlier connection date than they currently hold, and have been notified of a possible ‘acceleration’. For example, a project may currently hold a connection date in their existing connection agreement, which is within Phase 2, however, the G2tWQ Notification associated with the proposed CfD project outlines a Gate 2 Phase 1 status, meaning this project is being prioritised to connect to the grid with an earlier date. Thus, these projects will be able to use their ‘requested advancement date’, as set out in their G2tWQ application, which must be evidenced at the point of CfD application alongside an existing connection agreement and G2tWQ G1 CPCR or Gate 2 Notification status where both the Gate and Phase status will be assessed^{[footnote 17][footnote 18]}. 

For the avoidance of doubt, the advancement between Phases route for entry is optional.

We are also aware that some projects may have requested advancement within a Phase, i.e. they have an existing connection date within Phase 1 or 2 and are also requesting an earlier date within the same Phase. However, whether or not a project will be accelerated ahead of its existing connection date will not be formally confirmed until the Gate 1 CPCR or Gate 2 offers are issued and projects which are requesting advancement within a Phase will not be able to demonstrate the same evidence for advancement as their Phase Notification will not have changed. Thus, projects that have requested advancement within a Phase will not be able to apply using their requested advancement dates and must rely on their existing connection agreement.

Disallowing projects to apply on advancement basis within a Phase is consistent with ensuring that as many projects as possible which are likely to be deliverable can participate in the round. Projects which have requested advancement within a Phase are expected to hold a connection date which is currently not eligible and will also not be able to formally, on the basis of their G2tWQ Notification, demonstrate that their requested advancement date is being considered. In comparison, decelerated projects likely have better delivery assurance as they are still expected to hold a connection date which is eligible, at the point of CfD application, and referring back to our rationale for allowing decelerated projects: even where decelerations have occurred, they are not likely to be towards the back of the Gate 2 Phase 2 queue.

Grid delay provisions

The government understands the statement titled ‘NESO’s Grid Connection Reform – Impact on CfD’ issued by the LCCC on July 24 2025^{[footnote 19]} remains valid for projects with existing CfD contracts and those looking to enter AR8. To further reassure applicants, the Government understands that the LCCC will be issuing a revised statement which will be issued alongside, or soon after, the publication of this Government Response.

Therefore, and in summary, our final policy position will:

• For AR9 and beyond – exclude all Gate 1 projects with the exception of Gate 1 CPCR. This means applicants will be required to be in receipt of either a Gate 1 CPCR or Gate 2 connection agreement at the point of CfD application to be eligible.
• For AR8 only – exclude all Gate 1 projects with the exception of Gate 1 CPCR. Gate 1 CPCR and Gate 2 status will be assessed using G2tWQ Notifications which applicants must provide alongside an existing connection agreement, if they are not in receipt of their new connection agreement.
• For AR8 only – enable ‘decelerated’ applicants. Applicants indicatively notified of a deceleration will not be excluded, provided their existing connection agreement meets the criteria as set out in the CAF.
• For AR8 only – enable applicants which have been indicatively ‘accelerated’ between Phases. Applicants have an option to apply using their ‘requested advancement date’ as set out in their G2tWQ application, which they must evidence alongside a Gate 1 CPCR or Gate 2 status and an existing connection agreement.
• For AR8 – further details on eligibility will be outlined in the CAF and the Delivery Body’s ‘Contract Allocation Process Guidance’.

Visibility of Sealed Bids and Sealed Bid changes for technology types with Sealed Bid visibility

Proposal

We invited views on maintaining visibility of anonymised sealed bids for fixed-bottom offshore wind, and on extending this policy to other technologies. Where visibility was extended to other technologies, we invited views on limiting the number of sealed bids an applicant may submit to just one bid, mirroring the approach taken to fixed-bottom offshore wind in AR7.

Summary of consultation responses

There was a range of 34 to 42 responses to the questions listed below. Most responses were from renewables developers. We also received responses from trade associations and public bodies. Other respondent categories included: energy supplier, investor, individual, consultancy and other government department.

Question 30(a) sought views on maintaining bid stack visibility for fixed-bottom offshore wind in AR8. Most respondents supported this position, highlighting its efficacy in AR7.

Question 30(b) sought views on whether to extend bid stack visibility to other technologies. Respondents were split on extending bid stack visibility to other technologies, with many respondents supporting and opposing the proposal.

Supporters of extending visibility said it could allow for significant capacity gains at potential low cost, supporting Clean Power 2030 and value for money. They also said visibility allowed for better-informed budget decisions and greater budget efficiency.

Opponents said visibility of sealed bids is only justified to correct budget inefficiency and is unnecessary in liquid pots, such as pot 1 (solar, onshore wind). However, they suggested that more ‘mechanistic’ approaches to manage the risk of budget underspends, such as the use of capacity targets, would be preferable to visibility because the latter entailed a risk of ‘political interference’. They also raised concerns about anonymity and warned that visibility increases uncertainty, pushing up clearing prices in the long term.

Question 31 sought views on limiting the number of sealed bids. The majority of respondents supported limiting applicants to only one sealed bid for any technology type where the government had visibility of bids. A few respondents suggested that, where the government had visibility of bids from emerging technologies, allowing the submission of two sealed bids could aid price discovery.

Question 32 sought views on maintaining anonymity of sealed bids. Most respondents supported retaining anonymity of sealed bids for any technology type where the government had visibility of bids.

Question 33 sought views on the assessment of impacts on bid stack visibility. The majority of respondents agreed with the assessment of impacts outlined in our proposal. Where a few respondents disagreed, they reiterated reasons for opposing the extension of visibility as summarised above at question 30(b).

Assessment of impacts

Based on the responses to question 33, we believe that the assessment of impacts provided at the consultation stage remains suitable and that the proposal could:

• provide us with greater certainty over how much capacity is successful, by enabling greater visibility of auction information in budget-setting, increasing the likelihood of buying the right volume at a good price for consumers
• allow us to consider the budget choices for multiple technologies together, enabling the most cost-effective decisions to enable decarbonisation through the CfD

We have noted concerns over anonymisation of small-pipeline projects for more nascent technologies.

Policy response

We will continue to maintain visibility of anonymised sealed bids for fixed-bottom offshore wind in AR8, including limiting fixed-bottom offshore wind applicants to one sealed bid.

We will extend visibility of anonymised sealed bids to solar and onshore wind (including remote island wind) in AR8. This will allow us to make better-informed, more cost-effective budget decisions for technologies that are critical to delivering Clean Power 2030.

This facility could also help reduce the risk of budget underspends from the increasing participation of significantly larger solar projects in CfD auctions and/or reduce the risk of just missing out on good-value solar and onshore wind projects that could deliver for 2030.

Visibility will be extended to solar and onshore wind (including remote island wind) on the same terms as offshore wind. This means that we will only view anonymised bids that are above the relevant budget, and applications from these technologies will be limited to one sealed bid each.

We do not consider that there is a case to apply visibility to other technologies expected to participate in AR8 (for example, technologies other than solar, onshore/remote island wind and offshore wind).

As noted above, a key reason to extend visibility to solar and onshore/remote island wind is that these technologies, along with offshore wind, are critical to delivering Clean Power 2030. However, other technologies expected to participate in AR8 are not critical to delivering the 2030 ambition; therefore, there is less cause to extend visibility to these technologies.

Additionally, where the government views bids, it is important that the relevant technologies have liquid pipelines, because this creates competitive tension, which encourages bidders to submit their lowest viable price. Other technologies expected to participate in AR8 have less-liquid pipelines, which reduces competition. As a consequence, extending visibility to these technologies could risk bid inflation. The far fewer number of bidders could also pose challenges to maintaining anonymity. These challenges would remain regardless of pot structure.

Minor and Technical changes to the CfD contract terms

Updating the CPI inflation factor in the CfD Standard Terms and Conditions

Proposal

We proposed to amend the definition of “Base Year CPI” in the CfD Standard Terms and Conditions to mean the full-year 2024 CPI. This is intended to ensure closer alignment between the methodologies used for Administrative Strike Prices, reference prices and strike price bids with those used by the LCCC to calculate the annual strike price adjustment.

Summary of consultation responses

There were 37 substantive responses to question 34. An overwhelming majority of respondents supported this change. Many agreed that aligning the Base Year CPI with the other auction parameters would be beneficial and felt that the resulting consistency would enhance investor confidence.

A few respondents did not agree with the change and advocated retaining October 2023 as the base year. They highlighted the benefits of maintaining consistency across allocation rounds and the ability to compare strike prices directly over time. It was also suggested that changing the base year to a full-year figure would require changes to forecasting models and add some complexity to calculations, with some risk of errors.

Policy response

We note the very strong stakeholder support for this change and intend to amend the Standard Terms and Conditions to apply the full-year 2024 CPI to the annual strike price adjustment from AR8 onwards. We also acknowledge the concerns expressed and that the change may have some practical implications for systems. However, we believe that the change will improve clarity for stakeholders and ensure consistency with other DESNZ auction publications, including relevant statutory notices.

The Base Year CPI will be redefined to be the simple arithmetic mean of all monthly values of CPI for 2024. For the consumer price inflation time series published by the Office for National Statistics on 20 May 2026^{[footnote 20]} (the most recent series at the time of the publication of this Government response) the value for 2024 is 133.9.

Proposed amendments to the definition of ‘Inside Information’

Proposal

We proposed amending the definition of ‘Inside Information’ in the Standard Terms and Conditions and adjusting Condition 72.6 to ensure that the CfD contract reflects current UK law on insider dealing and market abuse. These changes are necessary because the Financial Services and Markets Act 2000, on which the current definition of ‘Inside Information’ is based, has been replaced by the UK Market Abuse Regulation^{[footnote 21]} (commonly known as UK MAR).

Summary of consultation responses

There were 27 substantive responses to question 35, all of which supported the proposed changes to the definition. Many respondents agreed that bringing the contract into line with current UK law was sensible and would provide generators with legal clarity.

Most respondents supported the proposed changes to Condition 72.6. However, there was a minority view that questioned the need to extend the requirements of Condition 72.6 to “the Generator’s Group” on the basis that this might create issues for group companies which can be listed entities.

Policy response

We will amend the definition of ‘Inside Information’ and Condition 72.6 as set out in the consultation.

On the matter of extending the requirements of Condition 72.6 to “the Generator’s Group”, UK MAR applies to inside information which relates, directly or indirectly, to one or more issuers of financial instruments admitted to trading (on an applicable regulated market, multilateral trading facility or organised trading facility^{[footnote 22]} or to the relevant financial instruments (or related derivative instruments) themselves.

In a group structure, it is common for listed financial instruments (whether equity or debt) to be issued at parent or financing entity level, while operating or asset-holding subsidiaries (such as a CfD Generator) do not themselves issue listed instruments. In those circumstances, the subsidiary will not itself be an “issuer” for the purposes of UK MAR. However, information relating to that subsidiary may nevertheless constitute inside information in respect of another member of the Group (for example, a listed parent or a financing special purpose vehicle with listed debt), where that information would be likely to have a significant effect on the price of the relevant issuer’s financial instruments.

Accordingly, where the Generator forms part of a wider group, Generator Confidential Information as it applies in the CfD contract may, depending on the circumstances, constitute inside information not only in relation to the Generator itself, but also in relation to other members of its Group or their listed financial instruments.

Extending the scope of Condition 72.6 to the Generator’s Group therefore reflects the way in which UK MAR operates in practice and ensures that the provision captures all potentially relevant inside information scenarios. Condition 72.6 provides a framework for the Generator and the CfD Counterparty to engage in good faith in relation to whether information held by the CfD Counterparty constitutes inside information for the purposes of UK MAR.

Additional scheme changes not subject to consultation

Specific separate clearing prices

Note: These changes do not require consultation but are referenced here to provide notice to stakeholders.

The CfD auction typically functions as a pay-as-clear auction. This means that all successful technologies in an auction pot receive the same clearing price, as set by the most expensive successful bid in the pot. However, where there are material differences to cost profiles, both between and within technologies in an auction pot, we may separate clearing prices for certain categories of projects^{[footnote 23]}. In this scenario, projects still compete against one another in an auction pot, with the lowest-priced bids being successful, but one category of project cannot have its clearing price dragged up by another (and vice versa). This reduces the risk that large cost differences lead to some projects receiving a clearing price that is a significant premium on their actual costs. Separate clearing prices should therefore be understood as a measure to protect against overcompensation while still enabling effective competition.

When identifying a need to use this facility in previous allocation rounds, we have generally separated the clearing prices of distinct technologies within the same pot. For example, solar projects had a separate clearing price to other Pot 1 technologies in the last two allocation rounds. However, in recent rounds, we have also separated the clearing prices of subcategories of the same technology. For example, in AR7, Scottish offshore wind projects had a separate clearing price to other offshore wind projects in Great Britain.

To achieve separate clearing prices in allocation rounds to date, ‘maxima’ have been set. Maxima are a budgetary limit, either in monetary or capacity terms. Maxima cap the monetary or capacity budget available for a grouping of technologies and also prevent the capped technology’s clearing price being set by the wider pot. However, using maxima in this way creates complications in maintaining the merit order, i.e. in ensuring bids are always ranked from cheapest to most expensive. For example, in AR7, maxima applying to OFW had to be set at an artificially high level to ensure preservation of the merit order, which risked confusing prospective applicants.

We recognise the potential for increased cost divergence, both between and within technologies, in upcoming allocation rounds due to factors such as location, project size and repowering. This could create an increased risk of overcompensation for some projects in the auction, in turn requiring an expanded use of separate clearing prices as mitigation.

We have therefore added new rules to the Draft Contract Allocation Framework^{[footnote 24]} to allow us to apply separate clearing prices to technologies in CfD auctions based on the following categories, without the use of maxima:

• technology specific clearing rules
• locational specific clearing rules
• repowering specific clearing rules
• project size specific clearing rules

Locational specific clearing rules, if they apply, will only apply to Offshore Wind. The position on locational clearing prices will be confirmed in the Price and Pot Notice, which will be published ahead of the round opening. All other clearing rules will be confirmed in the Contract Budget Notice.

To enable the application of locational specific clearing rules, should this be confirmed in the Pot and Price Notice, Rule 4.1(i) of the Draft Contract Allocation Framework requires Offshore Wind applicants to specify whether their project will connect to the transmission system or a distribution system in one of two groups of tariff zones/licence areas.

Next steps

Alongside this response, we have also published the Draft Contract Allocation Framework (CAF). We ask stakeholders to review the Draft CAF and send any queries to: ContractsForDifference@energysecurity.gov.uk

As announced by the Secretary of State in March 2026, Allocation Round 8 of the Contracts for Difference scheme will open in July 2026. The indicative time for AR8 can be found here.

1. https://www.gov.uk/government/news/record-breaking-auction-for-offshore-wind-secured-to-take-back-control-of-britains-energy ↩

2. https://www.gov.uk/government/news/new-auction-delivers-unprecedented-clean-homegrown-power ↩

3. Government response to the legislative proposals in the consultation on proposed refinements for Allocation Round 8 and future rounds (20 March 2026) ↩

4. Contracts for Difference: Contract amendments to implement Clean Industry Bonus reforms ↩

5. NESO, Hybrid Balancing Mechanism Unit (HBMU) Final Report (December 2025) www.neso.energy/what-we-do/strategic-planning/zero-carbon-operation ↩

6. Contracts for Difference: Contract amendments to implement Clean Industry Bonus reforms ↩

7. Contracts for Difference Allocation Round 5 ↩

8. https://www.neso.energy/document/375026/download ↩

9. Connections reform timeline - NESO ↩

10. Paragraph 10.3 of NESO’s Connections Reform Connections Methodologies Annual Consultation (March 2026) https://www.neso.energy/document/378746/download ↩

11. https://www.neso.energy/document/375026/download ↩

12. Decision: Connections Network Design Methodology ↩

13. Gate 1 CPCR projects will still be subject to the Connections Agreement eligibility criteria as set out in Schedule 5 of the Contract Allocation Framework. ↩

14. Regulation 25 of The Contracts for Difference (Allocation) Regulations 2014 requires applicants to have a ”connection offer“ which is defined as an agreement entered into by the operator of the relevant system, including a “countersigned offer“. Where projects are in receipt of a Gate 1 CPCR or Gate 2 connection offer, which has not been signed and countersigned, they will not be able to rely on this as having satisfied Regulation 25. ↩

15. This is subject to final Delivery Years for AR8 ↩

16. Further details on eligibility will be outlined in the CAF and the Delivery Body’s ‘Contract Allocation Process Guidance’. ↩

17. Further details on eligibility will be outlined in the CAF and the Delivery Body’s ‘Contract Allocation Process Guidance’ ↩

18. Projects applying on advancement basis between Phases are still subject to the requirements set out in the connection’s agreement criteria in Schedule 5. ↩

19. NESO’s Grid Connection Reform - Impact on CfD ↩

20. CPI INDEX 00: ALL ITEMS 2015=100 - Office for National Statistics ↩

21. Market Abuse Regulation - FCA ↩

22. Each as defined in Article 2(1) of the Markets in Financial Instruments Regulation as it has effect as domestic UK law ↩

23. The government can also adjust pot structure and/or set separate Administrative Strike Prices to manage large cost differences between projects. However, these alternative measures can be more distortive and challenging to implement compared to separate clearing prices, particularly where the cost differences occur within the same technology category. ↩

24. See rules 18 to 20, and 23. ↩