CMP445 Code Adminstrator Consultation v2.0

Public 1 Code Administrator Consultation CMP445: Pro-rating first year TNUoS for Generators Overview: The Connection and Use of System Code (CUSC) should be amended to ensure that Generators only pay Transmission Network Use of System (TNUoS) charges on a pro-rated basis from their Charging Date, during the first year of connection. Modification process & timetable Have 5 minutes? Read our Executive summary Have 80 minutes? Read the full Code Administrator Consultation Have 160 minutes? Read the full Code Administrator Consultation and Annexes. Status summary: The Workgroup have finalised the Proposer’s solution as well as two Alternative solutions. We are now consulting on this proposed change. This modification is expected to have a: high impact on affected Generators, a low impact on NESO, and no material impact on Transmission Owners (TOs) Governance route Standard Governance modification with Workgroups Who can I talk to about the change? Proposer: Angus Armstrong, Ocean Winds angus.armstrong@oceanwinds.com Code Administrator Chair: Prisca Evans, NESO Prisca.Evans@neso.energy How do I respond? Send your response proforma to cusc.team@neso.energy by 5pm on 29 April 2026 Proposal Form 14 November 2024 Workgroup Consultation 25 July 2025 - 22 August 2025 Workgroup Report 19 March 2026 Code Administrator Consultation 08 April 2026 - 29 April 2026 Draft Final Modification Report 14 May 2026 Final Modification Report 04 June 2026 Implementation 01 April 2027 1 2 3 4 5 6 7 Public 2 Contents Executive Summary ....................................................................................................................... 2 What is the issue? .......................................................................................................................... 4 What is the defect the Proposer believes this modification will address? ............................. 4 Why change? ................................................................................................................................. 5 What is the solution? ..................................................................................................................... 6 Proposer’s Original solution .......................................................................................................... 6 Workgroup Alternative 1 solution ................................................................................................. 6 Workgroup Alternative 2 solution ................................................................................................ 7 Legal text......................................................................................................................................... 7 Workgroup considerations ........................................................................................................... 9 Workgroup Consultation Summary .......................................................................................... 14 Post Workgroup Consultation Discussion ................................................................................ 16 Alternative Requests ................................................................................................................... 22 Terms of Reference Overview .................................................................................................... 27 What is the impact of this change? .......................................................................................... 28 Original and Workgroup Alternative Proposer’s assessment against Code Objectives .... 28 Workgroup Vote ........................................................................................................................... 36 When will this change take place? ............................................................................................ 37 Interactions .................................................................................................................................. 37 Acronyms, key terms and reference material ......................................................................... 38 Annexes ........................................................................................................................................ 39 Executive Summary This modification proposes to amend the Connection and Use of System Code (CUSC) to ensure that Transmission Network Use of System (TNUoS) charges are pro-rated during a Public 3 Generator's first year of connection, rather than being charged for the entire year regardless of the connection date. What is the issue? Generators are required to pay TNUoS charges for the entire year, regardless of when they connect within that charging year. This means Generators pay the same TNUoS for the first year, whether they connect at the beginning or end of the charging year. This is particularly apparent when connection delays are caused by factors outside of the Generator's control. It is proposed that the CUSC is amended to ensure that Generators are fairly charged on a pro-rated basis during their first year of connection. What is the solution and when will it come into effect? Proposer’s solution: The modification proposes amending the CUSC to ensure that TNUoS charges are only paid from the Charging Date, on a pro-rated basis, during the year in which a Charging Date occurs. This means that if a Generator connects for only part of the charging year, they will only pay TNUoS charges for the period they are connected. TNUoS charges will be apportioned based on the number of days connected from the Charging Date to the end of the financial year. Implementation date: 01 April 2027 Summary of Alternative solutions and implementation dates: Alternative Request 1 (voted in by the Workgroup as Workgroup Alternative CUSC Modification (WACM)1) proposes pro-rating not only the charges for the year in which a Charging Date occurs but also the year in which a generating asset permanently reduces capacity or is decommissioned. WACM1 is intended to cover the permanent increase or reduction of capacity (such as a staged commissioning or decommissioning) or complete closure of a whole or phase of a plant, and associated release of allocated Transmission Entry Capacity (TEC) back to the network, not to be used as a means of reducing network charges during temporary operational reductions during seasonal variations or maintenance periods. Implementation date: 01 April 2027. Public 4 Alternative Request 2 (voted in by the Workgroup as WACM2) proposes the same solution as WACM1 and includes retroactive charging back to 01 April 2024. Implementation date: 01 April 2027. What is the impact if this change is made? This modification is expected to have a high impact on affected Generators, a low impact on National Energy System Operator (NESO), and no material impact on Transmission Owners (TOs). It will ensure that Generators only pay TNUoS charges for the period they are connected, which will facilitate effective competition, reflect the actual costs incurred by Transmission licensees, and promote efficiency in the implementation and administration of the system charging methodology. Workgroup conclusions: The Workgroup concluded unanimously that the original, WACM1 and WACM2 better facilitated the Applicable Objectives than the baseline. Interactions A consequential modification has been initiated to adapt Section 6 of the CUSC for the WACM1 and WACM2 solutions. What is the issue? What is the defect the Proposer believes this modification will address? The CUSC is not explicit on the payment date of TNUoS during the Generator’s first year of connection (i.e. the charging year in which a Charging Date occurs under the Bilateral Connection Agreement (BCA)). In the absence of clarity around treatment of TNUoS during this charging year, the current working industry practice is that TNUoS is paid for the whole year, irrespective of when in the year the Charging Date occurs. This means that a Generator will pay the same TNUoS during the year in which the Charing Date occurs, regardless of whether it is connected at the beginning of the charging year or the end of the charging year. Public 5 Generators should not be subject to TNUoS charges during times when they are not connected to the grid. Additionally, in scenarios where a Generator’s assumed Charging Date is delayed for factors outside of its control, such as a TO delivery delay, the resulting impacts are seen to be particularly unjust and illogical as TNUoS charges are still levied during the delay period. The CUSC should be amended to clarify how TNUoS charges are applied during the first year of connection to ensure Generators are fairly and logically charged for their use of the grid on a pro-rated basis. Why change? There are several reasons to introduce the pro-rating of TNUoS charges with reference to Generator Charging Dates, from a commercial and policy standpoint. The commercial impact of being liable for TNUoS charges for periods prior to grid connection can be very severe, particularly on larger Generators and those in areas of high TNUoS tariffs. By contrast, this practice provides an uplift to those Generators in negative TNUoS zones who will receive a payment reflecting periods prior to their Charging Date. The current position incentivises Generators to request connection dates near the start of the charging year. This places undue pressure on the TOs and makes it increasingly difficult to deliver on-time connections. This means that connections are being delivered inefficiently and unreliably for system needs due to disproportionate TNUoS charges altering Generator behaviour. The current practice also risks Generators in positive TNUoS zones pricing additional TNUoS costs into their business cases when it should not be required. This could ultimately result in competition distortion and inflated Contract for Difference (CfD) bids in future Allocation Rounds. Significant transformation of the energy system is required between now and 2030, and the delivery of connections and generation must be done strategically and at-pace to achieve clean power by the turn of the decade. This instance of ambiguity in the CUSC poses a material and logistical problem that will result in connections-related bottlenecks and CfD distortions that will only increase if left unaddressed expeditiously. Public 6 This proposal will support a more strategic and timely delivery of renewable energy connections by ensuring the framework better reflects the respective roles of Transmission Owners in delivering the physical works required, and NESO in progressing connection activities within its remit. While NESO’s connections teams are highly motivated to facilitate connections, they do not control the delivery of TO infrastructure. The proposal therefore aims to create clearer, more aligned incentives across parties so that TOs can deliver the necessary works on schedule and recover TNUoS in line with their forecasts and business plans. The original proposal form can be found in Annex 01. What is the solution? Proposer’s Original solution The CUSC is not explicit on the treatment of TNUoS charges during the year in which a Generator’s Charging Date occurs. The CUSC must therefore be amended to both provide certainty and reflect the principle that TNUoS should only be paid in respect of the part of the year that the Generator has access to the Transmission System i.e. the annual value should be pro-rated from a relevant Charging Date to the end of the relevant charging year. Clause 5 of the standard BCA states that Use of System Charges shall be payable by the User from the Charging Date. As a principle, TNUoS should only be payable from the Charging Date, not for the full charging year during which a Generator’s Charging Date occurs. For example, if a Generator is able to connect for only 6 months of the charging year, the Generator should only be responsible to pay half of the TNUoS tariff for that charging year. This solution ensures that Generators do not pay TNUoS charges for periods prior to their Charging Date or (in the case of those in negative TNUoS zones) receive TNUoS payments prior to their Charging Date. WACM1 solution WACM1 builds on the baseline by including both increases and decreases in TEC when charging on a daily pro-rated basis. WACM1 also enhances fairness and cost-reflectivity by ensuring that Generators are not overcharged during periods when they are not connected or have ceased operations. It aligns with the principles of efficient network charging and supports new and retiring Generators by reducing financial barriers. This Public 7 approach also mitigates over-recovery risks in negative charging zones and improves alignment with actual system usage. In order to minimise the risk of gaming, and Parties changing TEC frequently for the purpose of reducing TEC charges, this Alternative proposes that any reverse in TEC that a party has benefited from in the previous 24 consecutive calendar months would result in that party re-paying the benefit gained, in its entirety, in the charging year in which the TEC position is reversed. This repayment would be spread evenly over the remaining months in the charging year in which the reversal happens, or, over the following charging year, in the event the reversal occurs at the end of a charging year. WACM 2 solution WACM2 builds directly on the WACM1 solution and the Original Solution. It adopts the same daily-charging approach where TEC changes during a charging year, but additionally proposes that this approach is applied retrospectively from 1 April 2024. Other than this retroactive application, WACM2 does not differ from the WACM1 solution. Legal text The legal text for these changes can be found in Annex 03, Annex 6, and Annex 7. The table below illustrates the difference between each of the proposed solutions: CUSC Section 14 Original Pro-rates first year TNUoS for Generators WACM1 Includes, in addition to the Original, prorating on a daily basis, based on date of permanent TEC increase or reduction. Short term changes and profiling are excluded. WACM2 The same solution as WACM1 and includes retroactivity from 01 April 2024. The following considerations were taken into account when creating the legal text: Original: • The Original legal text seeks to prorate the payment of TEC in the year that a project’s Charging Date occurs. Public 8 • It is intended to be a simple amendment to Section 14.18.19 of the CUSC to capture the principle that TNUoS payments in the relevant year are pro-rated with reference to the number of days between the Charging Date and the end of the Financial Year in which it occurs. WACM1: • The WACM1 legal text aims to extend the original provided by Ocean Winds to include permanent reduction in TEC. • As with the Original, WACM1 is limited to the period that charges apply in the first and last charging periods, the proposal does not attempt to amend the actual charging methodologies. • The legal text applies charges on a daily prorated basis and considers negative charges and interests on reconciliation amounts where appropriate. • It is intended be an extension of the Original proposal and not seeking to change the principles or intent of the Original solution. • Concerns about gaming were addressed in the legal text by ensuring that parties that reversed their TEC change within a period of 24 consecutive calendar months would have to pay back the monetary benefit arising from these proposals, plus interest. This would prevent parties from benefitting from seasonal changes to TEC, which is not the purpose of this modification. • The Workgroup decided to remove references to "bilateral agreement" from the legal text where it was not strictly necessary, keeping them only where contractually relevant. The Workgroup agreed that charges should be based on the actual availability of TEC rather than what is stated in a contract (Specifically supporting situations where only part of the requested and agreed capacity was made available to the generator by the TO for all or part of a charging year). WACM2: • It was clarified that WACM2 was in all ways the same as WACM1, except for the addition of retroactivity, which has been added to the proposed WACM2 legal text. • The Proposer of WACM2 provided reasoning for the inclusion of retroactivity. This reasoning and the Workgroup discussion on it is in the Retroactivity debate for the WACM2 proposal section of this report. Public 9 Workgroup considerations The Workgroup convened 9 times to discuss the issue as identified by the Proposer within the scope of the defect, develop potential solutions, and evaluate the proposal in relation to the Applicable Code Objectives. Workgroup Discussion ahead of the Workgroup Consultation The Original Proposer introduced the solution to the Workgroup and discussions were held on several aspects of the proposal. Clarification on the Cash Flow and Revenue Recovery Process NESO Representatives provided a high-level overview diagram of the cash flow and revenue recovery process, explaining how money flows between different parties within the industry. This included TOs, Transmission System Operators, and industry participants. This diagram has been included in Annex 08. The following process steps were noted by the Workgroup: Revenue Forecasting: Transmission network Owners (TOs) create cash and revenue forecasts based on the costs of operating, maintaining and developing the network. These forecasts are submitted to Ofgem, leading to their final allowed revenue for each price control period. Annually, TOs provide expenditure forecasts to the System Operator (NESO) to prepare annual transmission charging tariffs. Engagement with Industry Participants: Industry participants, including new Generators, engage with TOs and the System Operator. Once connected, the System Operator is notified, and tariffs are calculated based on the connection date. Tariff Calculation (process step affected by CMP445): Currently, tariffs are levied for the entire financial year (running from April), but this proposal suggests pro-rating the charges based on the actual connection period. This would mean calculating charges for the number of days from the actual date of connection to the end of the financial charging year. Payment and Reconciliation: Generators pay the System Operator, who then passes on payment to the TO. At the end of the year, a reconciliation process occurs to adjust charges based on actual usage Public 10 during peak periods. This ensures that the charges reflect the actual usage rather than the forecasted usage. Impact of this Modification on the Cash Flow and Revenue Recovery Process The Workgroup noted that this modification aims to pro-rate TNUoS charges based on the actual period of connection within the year that the Generator connects. Workgroup members discussed the impact of unexpected delays in connections, noting that forecasting smaller amounts for partial years could reduce the impact of such delays on revenue forecasts. This modification is expected to reduce the impact of unexpected connection delays and provide a more accurate reflection of the Generator's usage of the Transmission System. Workgroup members noted that this modification will not materially impact the overall process. Applicability to Negative Charging Zones: Workgroup members noted that current process is that in negative charging zones, Generators receive credits based not on their TEC but on their actual output during the months of November to February. This is designed to reflect their contribution to reducing peak demand during these critical months. Workgroup members highlighted a potential issue where a Generator connecting later in the year (e.g. January) might not have sufficient time to generate the required output to earn the full credits. This could potentially result in an unfair disadvantage for the Generator. Another view was that by connecting later in the financial year where the Generator is not contributing to the relevant months, that a lower credit contribution is proportionate. Workgroup members noted that in line with the defect identified, it would be inappropriate to pay out a full year's worth of credits to a Generator for contribution to reducing annual network load, if that generator was only operational for a short period within the charging year, in a similar way to charging Generators for periods they are not receiving the benefit of TEC and increasing the network load. Workgroup members discussed the possibility of pro-rating the credits based on the actual connection period within the November to February window. This would ensure that Generators are fairly compensated for their contribution to reducing peak demand, without overcompensating those who are only operational for a short period. Workgroup members sought clarification on how the testing period for output works for Generators connecting mid-year. A NESO Representative explained that the Generator's Public 11 output is assessed at the end of the year based on their maximum output during the November to February period, and any necessary adjustments are made during the reconciliation process. After further discussion, it was clarified that two different calculations are in effect. The Chargeable Capacity is different in negative charging zones, and may be less than the full TEC amount, as recalculated each year. The effective chargeable time period would be different in the first year of connection if this modification were to be approved, scaling any TNUoS charge or credit by the proportion of the whole financial year for which the connection is made. One Workgroup member explained their view that the calculation of Chargeable Capacity in relation to winter months was precisely to determine the appropriate capacity for the TNUoS calculation, and that the applicable time period for that year’s TNUoS is validly a separate consideration, dealt with appropriately by this modification, to which the Workgroup were largely supportive. Another Workgroup member agreed and added that also on grounds of simplicity this proposal did not warrant differential treatment for negative charging zones. Applying the Solution to Users Who Reduce or Increase TEC Within a Year The Workgroup discussed whether the same principle should apply to Users who voluntarily reduce or increase their TEC within the year. This includes scenarios where a Generator might close or reduce its capacity, or conversely, increase its capacity mid- year. Workgroup members raised concerns about the complexity of applying the solution to TEC changes within the year, pointing out that this could lead to significant changes in the operational aspects of charging, potentially requiring frequent adjustments and creating administrative challenges. Workgroup members emphasised the need to differentiate between permanent changes in TEC, such as commissioning, phased connections, or decommissioning, and temporary operational adjustments. Workgroup members suggested that the latter could lead to gaming the system, where Users might adjust their TEC strategically to minimise charges. The Workgroup generally agreed that applying the solution to temporary TEC changes within the year would introduce complexities that are outside the scope of the current modification. The Workgroup felt that the Original proposal should remain focused on the year in which a Charging Date occurs. Public 12 It was suggested that a separate modification would be needed to address the specific defect related to TEC profiling and operational changes. This would allow for a more thorough examination of the implications and potential solutions. A NESO Representative raised an Alternative Request, which includes prorating charges for both the start and end of the generation cycle. This approach would ensure that charges are pro-rated for both the initial connection and permanent reduction in TEC, addressing the same defect but from both ends of the generation lifecycle. This proposal was seen as a logical Alternative solution to the Original modification. The Alternative Request was raised and voted in by the Workgroup as WACM1. Further details of the Alternative Request are located within Annex 04 of this report. Recovery of Over/Under Recovery: Workgroup members noted that the current reconciliation process involves forecasting the costs and revenues for the year based on expected connections and usage. Any over or under recovery is typically managed through adjustments to the Remand Residual Tariff, which is applied in the following year (t + 1). The Workgroup discussed whether the over or under recovery should be treated differently under the proposed modification. This includes considering whether adjustments should be made immediately within the charging year or deferred to the next year (t + 1 or t + 2). Workgroup members expressed concerns about the practicality of making mid-year tariff changes. Workgroup members noted that the amounts involved in over or under recovery from individual Generators are unlikely to be significant enough to warrant such changes, given the overall scale of revenue collection. A NESO Representative highlighted that the proposed modification does not fundamentally change the current process. Generators' connection dates are already forecasted, and any deviations are managed through the existing reconciliation process. The consensus of Workgroup members was that the proposed modification does not necessitate changes to the current process of managing over or under recovery. The existing reconciliation process is seen as sufficient to handle any deviations in forecasted connections and usage. Following these discussions, Workgroup members unanimously agreed that the topic of potential midterm tariff adjustments was outside the scope of the modification. The Public 13 potential for the modification proposal to trigger such an event did not pose a significant risk and should therefore be considered out of scope. Class of Users for Recovery Workgroup members noted that the current process indirectly contributes to managing over or under recovery through adjustments to the demand residual tariff, which ultimately impacts Demand Users. The Workgroup discussed whether the recovery should be made from Generators only, Demand Users only, or both Generators and Demand Users. A NESO Representative highlighted that the proposed modification does not fundamentally change the current process. The existing reconciliation process already manages deviations in forecasted connections and usage, and any under recovery typically flows through to the demand residual tariff. The Workgroup consensus was that the existing reconciliation process is sufficient and does not need to be amended. Daily vs Monthly Pro-rated Charging The Workgroup discussed the complexity of prorating charges on a daily versus monthly basis. The Proposer noted that the originally proposed draft legal text includes a two-step approach, prorating charges for each complete calendar month and then for each part of a calendar month based on the number of days connected. This was in keeping with the wording in the CUSC, which is applicable to Connection Charges. The NESO Representative suggested simplifying the wording to make it clearer. They proposed checking with the Revenue Team to determine if charging down to the day would be feasible and preferred. The NESO Revenue Team have subsequently stated that charging down to the day is the simplest and preferred method, calculating the charge with each day of applicable charging being 1/365th of the annual charge. Workgroup members raised a concern about defining what constitutes a day, especially if a connection occurs partway through a day. It was suggested that a clear definition is needed to avoid complications. It was clarified by the NESO Revenue Team that when prorating a charge down to a day, if a Generator connects at any point on the initial day, a part day would be considered as a chargeable day when calculating the tariff liability Public 14 for the initial period. For charging purposes a day is a calendar day running from 00:00 to 23:59. Workgroup members emphasised the importance of fairness and consistency in the charging methodology, whether it is daily or monthly. The Workgroup agreed that the decision should be based on what is the most practical and clear for Users. Workgroup members unanimously agreed that charging should be calculated based on each chargeable day being 1/365th (1/366 on a leap year) of the annual charge. This approach was considered simpler and more consistent than the previously proposed method, which involved monthly and daily calculations. The view of the Workgroup evolved post-Workgroup Consultation, and it was determined that the annual charge should be divided by the number of days in the charging year (accounting for leap years) and then pro-rated based on the number of days connected. This discussion is captured in the Calculation of Daily Charges section of this report. Workgroup Consultation Summary The Workgroup held their Workgroup Consultation between 25 July 2025 and 22 August 2025 and received 8 non-confidential responses. The full responses and a summary of the responses can be found in Annexes 09 and 10. Support for the modification: The majority of consultation responses were positive, with strong support for the implementation approach and the legal text of the Original Proposal. Most respondents agreed that the legal text satisfied the intent of the modification and supported extending prorating to permanent reducing of capacity scenarios. Clarity and Legal Text Drafting: Several respondents requested greater clarity for WACM1, especially regarding how prorating would apply to incremental TEC changes within the charging year. Workgroup feedback: The Workgroup agreed to address discuss these points ensure they were reflected in the next legal text draft. Negative charging zones: While six respondents supported prorating being applied equally in both positive and negative charging zones, two raised concerns that in negative zones, prorating could result in a double penalty (reduced credits and lost generation opportunity). Public 15 Workgroup feedback: Workgroup members discussed the concern that in negative charging zones, pro-rating could potentially result in a double penalty for Generators, especially when cancellation charges are calculated based on a three-month period. The Workgroup agreed that pro-rating should apply to both positive and negative zones, but for negative zones, the calculation should use the Generator’s maximum output and be prorated according to the days connected. The NESO SME (Subject Matter Expert) clarified that proportionality should be applied consistently, and any damages or compensation issues are outside the scope of this modification. Calculation Method: Respondents generally favoured daily over monthly prorating for its simplicity and accuracy. There was a minor correction suggested regarding leap year calculations, which the Workgroup agreed to address in the legal text by specifying the number of days in the charging year. Unintended Consequences: Feedback on WACM1 highlighted potential unintended consequences, such as incentivising early closure of generation or issues with seasonal disconnects. Workgroup feedback: A Workgroup member noted that pro‑rating credits across the full charging year may incentivise Generators to keep plant online longer than economically sensible purely to secure the remaining pro‑rated portion of their revenue. They noted that under the proposal, if a Generator shuts down mid‑year, they may lose a portion of their revenue, even if they have delivered their Triads earlier in winter. The Workgroup member warned this could create a behavioural distortion: staying connected longer just to capture credits, even where output is no longer meaningful. The NESO representative noted that the issue already exists under the current methodology and is not being introduced by CMP445. They noted that CMP445 does not fix the irregularity, but neither does it worsen it. The NESO SME clarified that historic periods are not used for assessment; if a Generator produces zero in November – February, their assessed maximum remains zero, so the incentives are consistent with the existing rules. The WACM2 Proposer questioned whether this was really a defect at all, suggesting it may simply reflect differences between positive and negative charging zones rather than a flaw in CMP445. Public 16 A Workgroup member highlighted scenarios where a Generator connects late in the year due to TO delays, missing part of the charging period. Under pro‑rating, such a Generator may only get partial credit, even if they deliver full output during the winter peak. The Workgroup member thought that this was a potential fairness issue and an unintended penalty introduced specifically by CMP445. They contrasted this with current arrangements, in which credits depend only on winter output, not on connection date. The Proposer noted that pro‑rating by time connected is more appropriate, because the consumer-funded payments should reflect actual time contributing to the system, not just winter performance. They considered pro‑rating to be an improvement, not a defect, even if that means projects delayed by TOs receive reduced payments. The NESO SME agreed that CMP445 models the system more accurately and that this “penalty” is actually a fair correction, not an unintended consequence. The WACM2 Proposer suggested the discrepancy arises because positive vs. negative zones operate differently, and CMP445 isn’t meant to resolve structural fairness between zones. The Workgroup agreed that these unintended consequence discussions should be documented in the Workgroup Report, and could be used to support a future modification, but should not be included within the scope of CMP445. Post Workgroup Consultation Discussion Further discussion and clarification on the WACM1 solution As consultation responses indicated that further clarity is required for WACM1, the WACM1 Proposer explained that it is designed to allow daily prorating of TNUoS charges for both new and existing assets, including incremental increases or decreases in TEC during the year. The only restriction is to prevent frequent or seasonal increases and decreases in TEC (profiling), which the Workgroup agreed should not be supported. The proposal targets permanent changes and aims to cover the full asset lifecycle, not just initial connection, allowing charges to be reduced when capacity is permanently reduced. Public 17 A two-year period between changes was suggested to prevent gaming, with the intent that only permanent changes would benefit from pro-rated charges. This was further discussed by the Workgroup in the Ensuring that only genuine, permanent changes are prorated section of this report. Calculation of Daily Charges Following the ambiguity noted in the Workgroup Concultation, Workgroup members discussed the best way to calculate daily charges, agreeing that the annual charge should be divided by the number of days in the charging year (accounting for leap years) and then pro-rated based on the number of days connected. This approach was favored for its simplicity and accuracy over monthly or 1/12th calculations. Retroactivity debate for the WACM2 proposal The WAMC2 Proposer provided their rationale for including retroactivity within the modification: • Imbalance in the market between consequences to market participants (in this case Generators) and monopolies (in this case TOs) of late delivery of networks. It was argued that this imbalance led to a situation of undue market power with all the negative consequences falling to the competitive market participant. This fundamental unfairness could easily be rectified in this instance by including retroactivity. • While it could be argued that this has always been an imbalance in incentives between the monopolies and the competitive market participants, the WACM2 Proposer suggested that this issue has been worsened in the last few years with the increased pace of wind projects in Scotland. The WACM2 Proposer considers that this is widely recognised by the Department for Energy Security and Net Zero (DESNZ) Connections action plan and Ofgem’s Connections Delivery Board to name just a few policy initiatives aiming to address this issue. There was discussion around how many projects might be affected by retroactivity and whether this would be a burden to consumers (cost-wise) or NESO (administratively). The NESO SME provided an update that 152 projects with a total of 2,250 MW have connection dates between April 2025 and March 2027 and could potentially be affected by the retroactive application of WACM2. The NESO SME noted that this was a very small amount compared to overall generation and that not all of these plants would have had late connections. It was implied that the overall cost of retroactivity would be minor within the context of the demand residual, which would end up paying for the previous years’ reconciliations that are a normal part of the TNUoS charging methodology. The NESO Public 18 representative also suggested that retroactivity would not require significant resource to implement. The Workgroup acknowledged that while the number of sites seems significant, the overall financial impact on the demand residual is expected to be minor. Only one project in the list was identified as a step-up, the rest were new or standard connections. A Workgroup member expressed concern that the WACM2 solution could set a precedent for Parties to propose retroactive changes for any TNUoS modification. The Workgroup member noted that, while it may make sense to consider changes going forward, applying them retroactively introduces risks and potential financial impacts for affected Generators who could not have reasonably foreseen such a change and therefore had no opportunity to mitigate or manage it. The WACM2 Proposer emphasised that the current interpretation of the CUSC was unclear and that the material financial impact on affected Generators justified retroactive correction. The Original Proposer cited Ofgem’s guidance on retroactivity, asserting that all three criteria for retroactivity were met: a fault or error in central arrangements, unforeseeable circumstances, and the issue being flagged early enough. The NESO Representative recognised the WACM2 Proposers concerns and supported proportional charging but did not feel qualified to declare the situation “exceptional” without more data. They were not comfortable stating that all Ofgem’s retroactivity criteria were met, especially regarding the uniqueness of the circumstances. The WACM2 Proposer highlighted that: • A fault or error in central arrangements with resulting material losses, has been met, given the material losses suffered by some Generators for late connections and the ambiguity in the CUSC regarding the application of charges as noted by Ofgem in their urgency decision, where they refer to the current means of charging TNUoS as a “practice”; • Unforeseeable circumstances. The WACM2 Proposer pointed out to the workgroup that In addition to the general point that the “interpretation” applied by NESO was not “eminently predictable” for all parties, the period from the defect being identified was, in any event, an exceptional period for the connections market, with significant grid infrastructure upgrades needed to counteract the ageing electricity network playing their part in an exceptional level of delays to the connection dates Public 19 of nationally significant infrastructure projects. advising that this was not foreseeable, as noted by Ofgem in their Summary Decision Document: TMO4+ Connection Reform Proposals – Code Modifications, Methodologies & Impact Assessment where they state “waiting times in the electricity connections queue are too long, the connection rate is too slow, leading to inefficient network planning and risking the confidence of existing investors”. The WACM2 Proposer highlighted that delays experienced by customers when seeking network connections are growing, the implementation date of April 2027 could lead to material (non-cost reflective) loss by parties that connect during the 2.5 years since the mod was raised. A Workgroup member disagreed that all Ofgem’s retroactivity criteria were met, especially the requirement that the possibility of retroactive action be clearly flagged in advance. They expressed concern that the Workgroup had not previously discussed these criteria in detail and that the debate was new to many Workgroup members. The WACM2 Proposer considered that, with retroactivity to Charging Year 2024/25, delivers the greatest benefit against all relevant Applicable CUSC Objectives, correcting material harm suffered due to delayed connections and unclear central arrangements. The WACM2 Proposer emphasised that retroactivity is essential for fairness and market confidence, noting that without it, parties would have no incentive to raise defects that only benefit future participants. An outcome they advised would undermine competition, efficiency, cost reflectivity, and methodological clarity. The WACM2 Proposer also highlighted that retroactivity would have an impact on TOs, and NESO had confirmed that implementation would involve a one-off manual workaround with no material cost, while delivering substantial benefit to the affected Generators. Workgroup members acknowledged these points but raised concerns about precedent, noting that Ofgem is generally reluctant to approve retrospective modifications and that such changes may risk undermining wider market confidence unless exceptional circumstances are clearly demonstrated. The Workgroup ultimately agreed that all views should be transparently captured rather than resolved, with the Proposer’s justification included in the report. The full justification on retroactivity has been provided by the original Proposer and WACM2 Proposer and has been included in Annex 14. Public 20 Non-Firm and Phased Connections The Workgroup clarified that non-firm connections (where capacity is available but can be curtailed without compensation) are within scope of this modification, as long as the capacity is reflected in the connection agreement. It was agreed that short-duration or limited-duration arrangements (e.g. Limited Duration Transmission Entry Capacity (LDTEC)) are specifically excluded, as these are considered separate contractual arrangements. Ensuring that only genuine, permanent changes are pro-rated The Workgroup discussed the importance of preventing instances where Users might alternate increases and decreases in capacity within a short period to manipulate their charges. To address this, the legal text for both WACM1 and WACM2 was aligned to specify that only permanent increases or decreases in capacity in the same direction within a defined period would be eligible for pro-rating, and that reversals (i.e. increasing then decreasing, or vice versa) within 24 consecutive calendar months would not be allowed. This was to ensure that only genuine, permanent changes are pro-rated, not temporary or strategic adjustments. The Workgroup clarified that if a User reverses the direction of their capacity change within 24 consecutive calendar months, it would be considered profiling and thus excluded from pro-rating. This was explicitly added to the proposed legal text. The rationale was to maintain fairness and cost-reflectivity in the charging methodology, ensuring that the modification does not inadvertently incentivise Users to exploit the system. The use of “decommissioning" vs. "reducing capacity” The Workgroup discussed the use of phrases “decommissioning" vs. "reducing capacity”, specifically when clarifying the language used to describe the types of changes to TEC that the WACM1 and WACM2 solutions would cover. The WACM1 Proposer suggested changing the terminology in the report, aiming to clarify that the modification should not be limited to full site closures but also include partial reductions in capacity. Public 21 The WACM2 Proposer suggested the phrase "reducing capacity or decommissioned" to ensure the language covers both partial and full, permanent changes. The WACM2 Proposer emphasised that decommissioning could be interpreted too narrowly and might exclude relevant cases. The WACM1 Proposer agreed that the focus should be on permanent changes, whether partial or full, and that the language should not suggest profiling or temporary reductions. Workgroup members supported the inclusion of "permanently" to reinforce this point. The Workgroup agreed to use language such as "permanently reducing capacity" in the report, ensuring clarity that the modification applies to any permanent reduction, not just full decommissioning. This consensus was reached to accurately reflect the scope and intent of the modification and to avoid ambiguity for future readers or implementers. Clarifications on processes for negative charging zones The Workgroup discussed how the modification would interact with negative charging zones, where charges are based on actual output during the November to February measurement window. It was confirmed that the modification would not alter the existing process for negative charging zones. The NESO SME explained that if there is no measured output available in the November to February window (e.g. due to disconnection before the window), the reconciliation of negative charges would default to zero, following current procedures. This ensures consistency and avoids unintended financial impacts. The NESO Representative emphasised that both positive and negative charging zones should be treated equally under the modification, with pro-rating applied as appropriate and existing measurement processes maintained unless specifically impacted. The Workgroup agreed that the charging basis for negative zones would remain unchanged, and any exceptions or clarifications would be documented in the report. The NESO SME took an action to provide a concise written explanation of how the process would work in cases where output data is missing: As the basis for negative charging zones remains unchanged by this modification, the capacity of the Generator will still be assessed as the average of its 3 periods of maximum output between November and February separated by at least 10 clear days, Public 22 where the Generator has disconnected before the November to February assessment period its maximum output would be zero and so TNUoS liability would be zero. Sites with shared TEC A Workgroup member raised the issue of how the proposed modification would apply to sites with shared TEC, noting that while historically uncommon, such arrangements could become more prevalent in future projects. They highlighted that some projects may have shared TEC not covered under a single connection agreement, making the application of the modification unclear. The Proposer noted that, in their experience, shared TEC has typically been managed through commercial agreements with only one grid connection agreement and questioned whether this scenario would complicate the modification’s application. It was suggested that if shared TEC under multiple agreements becomes more common, it might warrant a separate modification in the future rather than delaying the current one. A Workgroup member clarified that their intent was not to delay the current modification but to ensure clarity for future implementation and to provide affected sites with guidance on how the change would apply. The NESO Representative noted that this topic does not fall within the scope of this modification. The modification is addressing the period within a year that charges apply, not the methodology for calculating charges. Alternative Requests WACM1 was submitted by the NESO Representative ahead of the Workgroup Consultation (Annex 04). Following the Workgroup Consultation, two Alternative Requests were submitted by Workgroup members (Annex 05 and Annex 15). Alternative Request 2 was voted in by the Workgroup and become WACM2 and Alternative Request 3 was rejected by the Workgroup. Public 23 These Requests set out the case as to why the Workgroup member who submitted them wished to amend parts of the original proposal. The Workgroup reviewed all the requests, and the table below provides an overview of each request (and who raised it) along with its status. WACM1 - Prorating permanent changes in TNUoS TEC values for Network Connected Generators Overview: This Workgroup Alternative CUSC Modification (WACM) proposes that TNUoS charges for Generators be pro-rated, not only from the date of connection (as in the original CMP445 proposal), but also up to the date of disconnection or TEC reduction. This ensures that Generators are charged only for the period during which they are physically connected and using the Transmission System in their first year and final year of operation. The rationale behind this proposal would be to ensure fairness and proportionality in charging. Just as it could be seen as unfair to charge for a full year when a Generator is only connected for part of the year, it could also be seen as unfair to charge for a full year when a Generator disconnects partway through the year. Recognising the principle of charges that are appropriate and proportional to costs and benefits to the network, this Alternative would involve prorating charges based on the actual period of connection within the year, both at the start and at the end of the generation lifecycle. If the baseline proposal was progressed and members of industry were to raise a subsequent change to address a similar defect for prorating of TNUoS Solution and Outcome of Alternative Vote Party Characteristic Mechanism of Workgroup Vote Alternative Request 1 (WACM1) NESO Prorating first and final year of charging Voted in by Workgroup on 15 July 2025 (Workgroup 4) Alternative Request 2 (WACM2) Brockwell Energy The same as WACM1, but requests retroactivity Voted in by Workgroup on 09 October (Workgroup 6) Alternative Request 3 SSE The same as the original but requests a retroactive mid-year reconciliation. The Workgroup rejected Alternative Request 3 on 09 March 2026 (Workgroup 10) Public 24 when permanently reducing capacity in a proportionate way, in addition to duplicating the effort of all concerned to raise a modification and run Workgroups, as the changes will require adjustments to the billing system to accommodate these changes, NESO Revenue Team would need to amend the billing systems again. All of which would seem of little value when industry time is at a premium. Applying the same principles in one go to both the start and the end of the Generator’s operation standardises the approach and avoids the complexity of two different charging models. Workgroup discussion: The Workgroup agreed that this Alternative solution addresses the same defect as the original proposal but from both ends of the generation lifecycle. They felt that it would ensure a more comprehensive and fair approach to charging. A Workgroup member raised the issue of distinguishing between permanent and temporary TEC reductions and suggested that there should be a time limitation to prevent Users from temporarily reducing their TEC to avoid charges and then increasing it again shortly after. This would ensure that the system is not gamed and that TEC reductions are genuinely permanent. The Workgroup discussed the possibility of implementing a time limitation, such as requiring a clear financial year in between TEC reductions and increases, to ensure that reductions are permanent. It was suggested that this is aligned with existing timelines in CUSC Section 15, which deals with investment cancellation charges. The NESO Representative took an action to speak with the NESO Revenue Team to clarify how charges would be reconciled, especially in cases where peak output figures are not available. It was confirmed that reconciliation of charges in negative zones where there is no maximum output available in the November to February measurement window would be handled as per the existing processes, e.g. where there is no measured output the negative charge would be reconciled to zero. Note, WACM1 will require a consequential modification to Section 6 of the CUSC to facilitate reflective pro-rate charges for permanently reducing TEC or a full decommissioning of a connection. WACM2 – Prorating first year TNUoS and prorating TNUoS based on available TEC Overview: This Alternative proposes the same solutions as WACM1. The solution is proposed to be effective from 1 April 2027 and applied retrospectively from the 2024/25 Charging Year. Public 25 Workgroup discussion: The WACM2 Proposer noted that main distinction from WACM1 is the request for retroactive application, to address significant commercial impacts for affected Generators. It was suggested that Ofgem ultimately decides the implementation date, and this should be reflected in the report. The Authority Representative clarified that Ofgem is generally reluctant to approve retrospective modifications unless justified by exceptional circumstances, and that the bar for such changes is very high. The CUSC Panel Representative confirmed the CUSC Panel’s view that WACM2 should be included as an Alternative for the Authority to consider. Workgroup Members raised concerns about investing time in developing a solution that may not be accepted due to the Authority’s stance on retroactivity. They suggested seeking an informal view from Ofgem before progressing further. The WACM2 Proposer argued that the effort to apply retroactivity would be minimal, as few plants would be affected, and suggested that NESO could provide numbers to support this. The NESO Representative agreed to take an action to gather relevant data. Note: As with WACM1 selection of this Alternative will involve the progression of a consequential modification in conjunction with the proposal. Alternative Request 3 - Prorating first year TNUoS Overview: This Alternative Request proposes that the original proposal is retained and extended to provide certainty for Generators connecting part-way through a charging year from 1 April 2026, by ensuring that TNUoS charges are pro-rated irrespective of whether the Generator has connected before the Authority’s decision on this modification. The rationale presented by the Proposer in Workgroup 9 was that applying CMP445 from 1 April 2026 would give Ofgem a more realistic and potentially approvable retrospective option, recognising that many projects due to connect in 2026/27 now face uncertainty and may be pushed back through no fault of their own. The Proposer explained that using a later date than WACM2’s 2024/25 approach could reduce the risk of creating Public 26 “winners and losers” between projects connecting days apart, while still addressing near-term charging distortions. The Proposer also noted that Ofgem has historically been reluctant to approve retrospectivity, and therefore a 2026 start date may stand a better chance of being accepted. Emphasising that this approach would not materially change the mechanics of CMP445 and would not adversely affect NESO’s revenue collection or under-recovery position, as it simply applies the already developed structure of the original/WACM2 to an earlier period. Workgroup discussion: The Alternative Request 3 Proposer presented Alternative Request 3 noting the intention was to apply the CMP445 solution to connections from April 2026, aiming to provide Ofgem with more options and address uncertainty due to connection reform and transmission build delays. Some Workgroup members struggled to see the need for the new option and felt the date was not tied to the defect or any clear principle. Noting that the WACM2’s 2024/25 date is grounded in when the defect was raised, while the proposed 2026 date lacked a compelling rationale. One Workgroup member emphasised that introducing a fourth option risked extending timescales. The Alternative Request 3 Proposer advised Ofgem may be more willing to approve an April 2026 date than the earlier WACM2 date and noted that 2026 could provide a “better chance” of acceptance. However, several Workgroup members disagreed with this reasoning. The Workgroup discussed the distinction between ad-hoc reconciliation and mid-year tariff changes, with the Alternative Request 3 Proposer explaining that a mid-year tariff change would require re-opening tariffs for the whole industry, whereas an ad-hoc reconciliation would only adjust payments for the affected subset of Generators, with impacts flowing through to 27/28 tariffs rather than altering everyone’s charges. The NESO Representative noted that negative tariffs are reconciled annually in any case, and an Observer sought clarity on whether the proposed reconciliation effectively amounts to a mid-year adjustment for those impacted, expressing concern that it still introduces uncertainty for those Generators, including potential credit repayments in certain zones. The Alternative Request 3 Proposer acknowledged this but emphasised that similar uncertainty already exists under the CMP445 baseline, and that Alternative Request 3 simply applies the same principle to 26/27. Public 27 The Workgroup generally agreed that the original, WACM1, and WACM2 already form a complete and sensible set of options, and the additional proposal did not introduce a materially new concept beyond date-shifting. The Workgroup voted on the Alternative Request 3 and by majority it was rejected. Consideration of other options The Workgroup discussed the potential for the increase and decrease of TEC within any chargng period, and agreed that the frequent changing of the required TEC to accommodate seasonal changes or extended maintenance periods, was not within the scope of the defect. Profiling of TEC did not align with the objectives of the proposal to reflect costs associted with permenant changes to TEC and so it was agreed to specifically exclude changes with reversals occuring within an agreed period, (proposed at 24 consecutive months). Terms of Reference Overview a) Consider EBR implications Workgroup members agree there is no impact on EBR. b) Consider applicability to negative charging zones given the different charging basis for those Users – i.e. based on actual output in months November to February. Positive and negative charging zones are to be treated equally within this modification. The charging basis is to remain unchanged within the solution. c) Consider whether the solution should also be applied to Users who reduce or increase TEC within year, such as when closing a generating station The principle of the WACM1 and WACM2 is that increases and decreases separated by 24 consecutive calendar months are allowed provided they are not reversing the capacity which would amount to profiling, which is specifically excluded. Public 28 d) Consider the timing of the recovery of any over or under-recovery in charging year t[0] – is it to be recovered in charging year t[0] (via a ‘mid-year tariff change?) or t[+1] or t[+2]? Covered by the existing revenue recovery processes. No changes are to be made as a result of this modification. e) Consider from which class or classes of User the recovery should be made by: (i) generators only, (ii) demand only or (iii) both generation and demand Covered by the existing revenue recovery processes. No changes are to be made as a result of this modification. The Terms of Reference can be found in Annex 02 What is the impact of this change? This change will positively impact Generators by reducing their commercial burden, incentivise TSOs and TOs to deliver connections on time, and support offshore wind targets and net zero goals. Original and Workgroup Alternative Proposer’s assessment against Code Objectives Original Proposer’s assessment against CUSC Charging Objectives Relevant Applicable Objective Identified impact (d) That compliance with the use of system charging methodology facilitates effective competition in the generation and supply of electricity and (so far as is consistent therewith) facilitates competition in the sale, distribution and purchase of electricity; Positive Ensures that Generators only pay use of system charges in the first year of connection, for the period that they enjoy the use of system. This will ensure that: (i) Generator bids in competitive CfD auctions are not distorted by (a) those in positive TNUoS zones including unnecessary provision for extra periods of TNUoS that cannot be recovered through generation and/or (b) those in negative TNUoS zones receiving an unjustified benefit during such periods, which in turn should drive down competitive pricing; and (ii) Generators competing for grid connections request the most appropriate dates of connection, not dates Public 29 driven by the TNUoS charging year (which distorts the market). Competition is better facilitated in the generation, supply, sale, distribution and purchase of electricity because Generators will have more realistic TNUoS profiles which are based on actual connection dates, removing the potential distortion to competition outlined above. (e) That compliance with the use of system charging methodology results in charges which reflect, as far as is reasonably practicable, the costs (excluding any payments between transmission licensees which are made under and accordance with the STC) incurred by transmission licensees in their transmission businesses and which are compatible with standard licence condition C26 requirements of a connect and manage connection); Positive Ensures that transmission licensees only receive use of system charges once the Generator receives use of system, thereby not unnecessarily increasing the value recovered from TNUoS in the first year of connection. (f) That, so far as is consistent with sub-paragraphs (a) and (b), the use of system charging methodology, as far as is reasonably practicable, properly takes account of the developments in transmission licensees’ transmission businesses; Positive This proposal takes account of developments in transmission licensees’ transmission businesses in the following ways. Accurate forecasting of connection dates by NESO will ensure that TOs recover all necessary charges. The implementation of this change will remove the issue referred to above (i.e. Generators seeking connection dates to align with the charging year). Public 30 Generators will (if this change is implemented) seek, and NESO/TOs will offer, connection dates more appropriately aligned with Generators’ programmes and the optimum timing for the system. This will mean that NESO and the TOs will be better resourced and prepared for delivering connections, as they will not all be condensed into April (which inevitably leads to issues with deliverability and resource). This is particularly important given the number of very large developers seeking connections in Northern Scotland following the ScotWind process where we understand the most optimum connection timing for the TO’s is following the summer outrage programme – not April. Furthermore, it is recognised that TOs will be submitting RIIO-3 Business Plans imminently and so it is important that a decision is reached on this proposal as soon as possible. (g) Compliance with the Electricity Regulation and any relevant legally binding decision of the European Commission and/or the Agency *; and Neutral (h) Promoting efficiency in the implementation and administration of the system charging methodology. Positive Encourages the most efficient connection dates for generation, ensuring that: (i) generation licensees are able to deliver power for the most efficient price (without the need for consideration of additional charges for periods where they are unable to generate and recover those costs); and (ii) provides transmission licensees with a more realistic (less condensed) connection profile across each charging year, whilst also encouraging transmission licensees Public 31 to deliver on time in order to recover TNUoS in line with forecast. Furthermore, this proposal would provide much needed clarity in the administration of the CUSC. Ambiguity is damaging to investor certainty. Certainty on this point, and a change to ensure that Generators do not pay more TNUoS than is necessary or fair will lead to greater efficiency. With less room for disagreement and dispute, the implementation and administration of CUSC arrangements will be more efficient. Certainty on this topic will, in turn, serve to increase investor certainty in the area of TNUoS charging. Relevant Applicable Objective WACM1 Proposer’s assessment WACM2 Proposer’s assessment (d) That compliance with the use of system charging methodology facilitates effective competition in the generation and supply of electricity and (so far as is consistent therewith) facilitates competition in the sale, distribution and purchase of electricity; Positive Our view is that the proposal better facilitates charging and competition by aligning charges with the benefit Generators receive from their connection to the network both in terms of charges or payments. Positive As per the original proposal this Alternative proposal ensures that Generators only pay use of system charges for the period that they enjoy the use of system. This will ensure that: (i) Generator bids in competitive CfD auctions are not distorted by (a) those in positive TNUoS zones including unnecessary provision for extra periods of TNUoS that cannot be recovered through generation and/or Public 32 (b) those in negative TNUoS zones receiving an unjustified benefit during such periods, which in turn should drive down competitive pricing; and (ii) Generators competing for grid connections request the most appropriate dates of connection, (or increase or decrease in TEC), instead of the beginning or end of a TNUoS charging year, which distorts the market. This Alternative Proposal would result in cost reflective TNUoS charges against the TEC that Generators can use, instead of against TEC they cannot, or do not want to, use. Having charges that are cost-reflective means that Generators will be able to bid lower prices into various markets in which they participate. Generators would be encouraged to change their TEC as soon as practicable rather than waiting for the start of a charging year. Competition is therefore enhanced as generation comes on earlier, or TEC becomes Public 33 available earlier than in the baseline. Competition is better facilitated in the generation, supply, sale, distribution and purchase of electricity because Generators will have more realistic TNUoS profiles which are based on actual TEC availability,