What do I need to know about the upcoming TNUoS changes?
For developers and investors working at transmission level, Transmission Network Use of System (TNUoS) charges are often among the most opaque and underestimated elements of a project’s financial case. With a series of changes now approved or under development, the assumptions underpinning long-term cost exposure may no longer hold.
This blog outlines the upcoming TNUoS changes, including CMP316, CMP432, and CMP444, and explains why early understanding of their impact is essential. Whether you are developing co-located generation, planning a 400kV-connected data centre, or operating a portfolio of large-scale projects, these changes could affect your long-term viability, revenue forecasts, and location decisions.
Who pays TNUoS?
TNUoS charges apply to:
- All generator connections under BCA
- Generator connections under BEGA where export capacity exceeds 100 MW
- Final demand connected directly to the transmission system
BELLA connections and storage do not pay demand TNUoS, but storage does still pay generator TNUoS.
As transmission-connected demand becomes more common, particularly with the rise of hyperscale data centres, a growing number of developers and investors will find themselves exposed to TNUoS, often for the first time. Read on to find out more.
TNUoS is not fixed, and it is changing fast
TNUoS charges are highly locational and reflect assumptions about how power flows across the GB transmission system under different background scenarios. As system needs and user behaviours evolve, the underlying methodology is constantly being updated through the industry code modification process.
The following sections summarise the changes as a result of the CMP316, CMP432, and CMP444 Proposals and explain the effects these could have on your projects.
CMP316 – Cost-reflective charging for co-located generation
Status: Delayed – final decision pending resubmission following Ofgem send-back
Many generation sites now include multiple technology types on a single connection. Examples include solar with battery and wind with hydrogen-ready gas. Until now, these types of co-located projects have been treated using a “predominant technology” approach, where the entire site’s TNUoS charge is based on whichever technology dominates (in terms of their respective TECs).
CMP316 proposes a new approach that:
- Breaks the site’s Transmission Entry Capacity (TEC) into shares for each technology
- Applies a separate Annual Load Factor (ALF) to each technology component
- Calculates each component’s TNUoS charge separately, and sums them to obtain total TNUoS charge for the site
During the Workgroup Consultation, an alternate Workgroup Alternative CUSC Modifications (WACM) was proposed that suggested utilising pro-rated tariff components (peak liability and not-shared year round tariff) and the pro-rated Annual Load factor for each technology type.
These changes offer a method which can be more cost-effective for the project, particularly where technologies fall into different charging categories (such as intermittent vs. conventional carbon). However, they also introduce complexity because the updated charge outcomes depend on location, technology mix, and metering setup. Where separate Building Maintenance Units (BMUs) and metering exist, the site will be charged under the new approach. If not, the current “predominant technology charge” method will apply.
The CMP316 model shows that charges for co-located sites in some Scottish and South-West England zones could fall significantly when storage is added. Elsewhere, sites may see higher charges due to higher ALFs for certain technologies.
CMP432 – Adjusting the transport model to flatten locational volatility
Status: Workgroup stage
TNUoS charges include a locational signal based on the cost of reinforcing different parts of the network (Locational Onshore Security Factor). Currently, this is based on a security-constrained transport model that, in some zones, produces very steep locational differences, particularly for demand. The current model overcharges for security of the Main Interconnected Transmission System (MITS) network.
CMP432 proposes to remove the Locational Onshore Security Factor which changes to the way security requirements are modelled in the transport calculation. It softens the locational signal by removing the additional scaling for security in demand forecasts. The result is flatter gradient for locational charges between zones. This has the following implications:
- For transmission-connected demand (such as data centres), the zones with the highest TNUoS charges historically (often in southern England) could see meaningful reductions.
- For generation developers, particularly those planning co-located load to reduce net TEC exposure, the relative value of that approach could shift. Additionally, there will be a decrease in the absolute value of the adjustment tariffs for generators.
Developers basing location or TEC-sharing decisions on current tariffs should be cautious. This change, if approved, will directly alter any cost assumptions based on the current processes.
CMP444 – Temporary caps and floors for generator wider charges
Status: Awaiting Ofgem approval
This proposal is intended as a transitional measure to reduce volatility and support investment confidence. The modification was driven by stakeholder concern over rapid swings in TNUoS charges across recent years. Although CMP444 applies to generator charges only, it is still pertinent for developers with large BEGA-connected generation above 100 MW.
CMP444 will:
- Apply only to generation and not demand
- Introduce a £/kW cap and floor mechanism to the wider generation component in the TNUoS Charges.
- The cap and floor is applied across every GB Zone to each of the three components of the wider generation TNUoS charge. The £/kW cap and floor values for each of these three components is equal to the 97.5th and 2.5th percentile of the respective 5-year forecasts from NESO’s latest Tariff publication.
Through the proposed CMP444 process, seven alternative proposals were also considered by the working group. These WACMs attempted to alter the methodology behind calculating the Cap and Floor Values applied to the calculation of all of the wider tariff components for each of the GB Zones. A summary of the different WACMs is provided below:
- WACM 1: Has more stringent cap and floor values by utilising the 90th and 10th percentile respectively to set the values.
- WACM 2: Has a similar percentile system to the original proposal (2.5th and 97.5th), but this WACM excludes data from 2029/2030 when significant network investments are modelled and therefore uses the 4-year NESO forecast from 2024/25 to 2028/29.
- WACM 3: Sets the cap and floor values for each of the wider tariff’s components at the maximum and minimum of the respective component’s 2025/26 level.
- WACM 4: Includes two-tier zonal grouping and the cap/floor values are calculated using 1 standard deviation from the mean within each of the 2 zonal groups. The tiers consist of Zones 1-7 and Zones 8-27.
- WACM 5: A maximum range is set between the highest and lowest TNUoS zones, along with an absolute cap for each wider tariff component. If tariffs exceed the range, a scaling factor is applied to each zone to reduce the component to fit within the range limit. If the highest tariff still exceeds the absolute cap, a uniform £/kW adjustment is made across all zones to bring it down while preserving the relative differences.
- WACM 6: Has the same percentile system as the original proposal, but this WACM combines data from 2 final-year tariffs (2023/24 to 2024/25) with NESO’s 3-year forecast (2025/26 – 2028/29) to obtain the cap and floor values.
- WACM 7: Sets the cap and floor values using the 2029/30 forecasts only.
The WACMs mainly differ in their proposed sources for calculating the cap and floor values in terms of the underlying forecasts or the percentile values. A couple of the WACMs, however, propose more nuanced methodologies for deriving the cap and floor values. Out of all of these proposed alternatives, the Workgroup favoured four WACMs (WACM 1, WACM 2, WACM 3 and WACM 6) along with the original proposal. However, Ofgem is yet to ratify the exact methodology that will be implemented through CMP444.
For developers looking at sites with previously high or negative TNUoS charges, this creates a new uncertainty about how long the predicted values will be relevant.
CMP442 – Predictable Generator Charges through Reference Price Freeze
Status: Under Workgroup Consultation
CMP442 proposes to provide generators with the option to freeze the wider generation tariff components for a defined period. This would mean that transmission-connected projects will pay fixed prices for a set period of time, and this procedure is intended is to limit volatility in yearly TNUoS outcomes due to fluctuations in wholesale prices or network investment updates.
Key aspects include:
- Locking the wider tariff components in line with the NESO tariff forecasts for a multi-year window.
- Providing generators with the option to opt-in to the fixed prices, or choose the variable TNUoS tariff alternative (same as the current TNUoS charging methodology).
- Improving investor confidence by limiting abrupt charge swings.
This change could give developers greater predictability in project modelling, especially for long-lead projects dependent on stable cost assumptions. However, the method for determining the freeze period and freeze values is still under Workgroup discussion.
Why does this matter now?
Each of these changes brings increased granularity, dependency on configuration, and year-on-year variability into TNUoS charges. If your project is Transmission-connected, (generation or demand) you are likely to face:
- Higher variation in cost depending on the project technology mix
- Changes to your zone’s relative cost attractiveness
- Complexities in planning and forecasting multi-year operational costs
For developers, TNUoS charges should no longer be an afterthought. A site that appears bankable today could see £1M+ annual shifts in cost under these changes. This variability could make or break a marginal project.
A fairer balance in TNUoS charging
The CMPs discussed above are not isolated changes; they are part of a wider push to correct long-standing imbalances in the TNUoS framework. The current methodology has, for some time, placed a disproportionately high burden of wider generation charges on generators located in Scotland, while projects in the south have received net payments.
This disparity is seen as not aligning with decarbonisation goals. Ofgem’s recent open letter on the prioritisation of charging modifications explicitly references the need to improve predictability and stability in the regime, while maintaining appropriate locational signals. Their ongoing coordination with NESO and the CUSC Panel indicates a more strategic sequencing of changes, especially where interactions between CMPs are likely to work together.
The upcoming decision on CMP432, for example, is being deliberately timed to inform the impact of the cap and floor mechanism under CMP444. Meanwhile, other proposals like CMP315 and CMP375, which could materially reduce locational signals, are under pause until the Government’s Review of Electricity Market Arrangements (REMA) concludes.
These moves suggest a more measured direction of travel; TNUoS is likely to remain cost-reflective, but with fewer extreme distortions. The outcome should be a system that is better aligned with wider policy aims and more supportive of net zero delivery.
How can Blake Clough’s analysis help with the upcoming TNUoS changes?
Understanding your portfolio’s exposure is no longer optional. Developers and investors need to:
- Forecast future TNUoS charges under different modification scenarios
- Identify locations where upcoming changes can create benefits
- Spot projects at risk of reduced viability due to higher TNUoS charges under CMP316 or locational rebalancing
- Evaluate whether metering and BMU setup decisions will projects into unfavourable charging categories
We have developed internal tools to run site-specific and portfolio-level TNUoS charge impact assessments. These models incorporate CMP316 structures, compare pre- and post-modification costs, and identify where changes will benefit or penalise your sites. We also have experience with projecting annual TNUoS charges for projects against each of the associated WACM methodologies under CMP444.
We have previously helped developers navigate not only the financial impact of these reforms, but also the qualitative advantages and risks of the upcoming market changes for their project portfolios.
There is no one-size-fits-all impact. For some sites, CMP316 and CMP444 will unlock savings but for others, it may push costs up. CMP432 could be a lifeline for some demand users but reduce benefits elsewhere. Depending on your requirements, we can support you in understanding the impact of each or all of these modifications on your project’s finances.
Whether you are working on a single transmission-connected site or managing a growing national portfolio, now is the time to take a detailed look at your TNUoS position.
Speak to us about how TNUoS may impact your portfolio and how we can support you