Rising TNUoS Cost BurdensFive-Year View of Transmission Network Use of System (TNUoS) tariffs

NESO has released its Five-Year View of Transmission Network Use of System (TNUoS) tariffs covering 2026-27 through 2030-31, anchored on Ofgem’s draft determinations for the upcoming RIIO-ET3 period. This report highlights the ongoing challenges posed by the Rising TNUoS Cost Burdens.

The issue of Rising TNUoS Cost Burdens is gaining significant attention in the energy sector.

These forecasts foreshadow a profound reshaping of the cost structure for electricity users, placing increased pressure on demand side actors.

As a result, the Rising TNUoS Cost Burdens will shape the future landscape of energy.

Ofgem’s Draft Determinations & NESO Inputs

Under the RIIO-ET3 draft determinations, Ofgem has proposed that Transmission Operators be permitted to recover £8.92 billion in 2026-27, escalating to £13.63 billion by 2030-31 (compared to roughly £5.09 billion in 2025-26).

NESO uses these figures as principal inputs when constructing the TNUoS forecasts, although it notes that the TOs (and other industry stakeholders) may not agree with all of the cost assumptions underpinning them.

In particular, NESO flags that while it accepts the draft revenue allowances as a modelling basis, it reserves judgment on whether the ultimate expenditure levels will be accepted by Ofgem as final. This caveat matters, since final determinations often diverge from draft assumptions.

Steep Rise in Demand Cost Recovery

Because generation charges are capped under the charging regime, the bulk of these additional costs will be allocated to demand.

NESO’s forecasts show the demand share of TNUoS cost recovery rising from 78.62% in 2025-26 to 87.87% by 2030-31. As a result, Transmission Demand Residual (TDR) – the non-locational, residual demand charge, is expected to rise from £7.52 billion in 2026-27 to £11.76 billion in 2030-31.

Understanding the implications of Rising TNUoS Cost Burdens is crucial for stakeholders.

Crucially, for 2026-27, the forecast TDR is approximately 94% higher than in 2025-26.

To put this into perspective: under the new projections, the average Half-Hourly (HH) demand tariff is expected to climb toward £3.18/kW, and the average Non-Half-Hourly (NHH) demand tariff to around 0.43 p/kWh.

Rising TNUoS Cost Burdens impact both residential and commercial electricity users.

In addition, NESO anticipates that the Embedded Export Tariff (EET), the credit paid to embedded generators and exporters, will also rise: from ~£3.00/kW to ~£3.45/kW.

The Rising TNUoS Cost Burdens may push businesses to reconsider their energy strategies.

Locational Charges & Volatility: Less of a Driver, but Still Uncertain

While the lion’s share of the cost uplift sits in the residual demand charge, locational (zonal) tariffs still play a role, particularly in determining relative burdens across regions.

NESO’s modelling embeds assumptions about grid flows, generation and demand projections, and the application of network models that reflect incremental costs via its Tariff & Transport model.

That said, the forecasts show that locational changes will be volatile and varied. For instance:

> Forecasts for Midlands show very large increases in locational HH tariffs (c. +214%).

> South Wales is projected to see locational tariff growth of ~298%.

> In contrast, Eastern regions’ locational component may decline in some years –73% in one scenario.

These wide swings highlight that locational signals are sensitive to assumptions about grid development, generation sits, and network flows.

Underlying Drivers & Key Variables

Several core dynamics fuel the steep increases in the NESO projections:

Ultimately, Rising TNUoS Cost Burdens will require adaptive strategies from consumers.

> Network reinforcements and grid expansion – As the UK transitions toward net zero, large volumes of renewables are being sited in remote locations (particularly offshore). The cost of reinforcing transmission corridors, upgrading lines, and expanding capacity to carry power from north to south is driving capital expenditure estimates.

> Resetting of model parameters for RIIO-3 – Key parameters in the TNUoS methodology are being reset ahead of the 2026 start: local onshore security factors, local substation tariffs, avoided GSP credits, generation zoning, expansion constants, and other CUSC modifications. These parameter resets influence how much cost is attributed to locational vs residual elements.

> Forecast uncertainty & sensitivity – Given the long forecasting horizon, NESO runs sensitivity analyses to show how variations in demand, permitted revenue, or network costs can shift tariffs. For example, a ±£500 million change in allowed revenue can adjust the average TDR per site by ~£15 annually in some scenarios.

Future trends will be influenced by Rising TNUoS Cost Burdens on energy users.

> Methodology constraints and caps – The charging framework is constrained by existing rules: for instance, generation tariffs are capped, which funnels additional burden to demand. NESO also faces methodological constraints (such as how residuals are allocated, how locational signals are smoothed) imposed by the CUSC framework.

> Regulatory risk and divergence – Because Ofgem’s final determinations may differ from the draft, there remains a margin of error in NESO’s projections. Final allowed expenditures, capital treatment, and allocation decisions could temper or amplify the forecast impacts.

What These Shifts Mean for Businesses, Generators & Consumers

The increased burden on demand means that virtually all electricity users, business and large consumers in particular, will face significantly higher TNUoS charges, unless mitigated by changes in usage, location, or tariff design.

Addressing Rising TNUoS Cost Burdens will require comprehensive policy responses.

> Large industrial and commercial (I&C) users will see material impacts on their bills, especially via the standing cost or fixed daily charges, since TDR is largely recovered via fixed demand charges.

In conclusion, Rising TNUoS Cost Burdens will significantly alter the market dynamics.

> Embedded generators will also face higher opportunity costs (via reduced EET credits), making small-scale generation less financially attractive.

> Smaller consumers may feel indirect effects, as increased network charges factor into supplier pricing models.

> Regional competitiveness: Areas with high locational cost increases may become less attractive for new load growth unless mitigated through network upgrades or local flexibility solutions.

Risks, Caveats & What to Watch

> The projections are model-based and preliminary, actual outcomes may differ depending on decisions by Ofgem in the final determination, adjustments in network investment plans, or evolving demand and generation trends.

In summary, awareness of Rising TNUoS Cost Burdens is essential for effective planning.

> Upcoming quarterly updates and revised Five-Year Views (e.g. slated for August 2025) may alter key assumptions.

> The sensitivity of locational tariffs means that marginal changes in generation siting, demand forecasts or transmission flows could shift burden patterns substantially.

> Broader market reforms (e.g. changes in the Electricity Market Arrangements or TNUoS structural reform after 2030) may introduce further uncertainty beyond this window.

Conclusion & Strategic Implications

NESO’s new Five-Year View, underpinned by Ofgem’s draft determinations, paints a stark picture: electricity users are poised to face a leap in transmission charges, primarily borne through demand allocations.

All energy users must be aware of Rising TNUoS Cost Burdens as they affect future costs.

While much of the trajectory is driven by capital-intensive grid reinforcements to enable clean power delivery, the burden distribution via the TDR component means that demand users will shoulder the greatest share of increases.

Awareness of Rising TNUoS Cost Burdens is essential for effective decision making.

The Rising TNUoS Cost Burdens are a critical factor in the energy industry’s evolution.

For businesses, generators, and policy watchers, the message is clear.  Engage aggressively in upcoming consultations and responses to Ofgem’s final determinations. Then reassess exposure to TNUoS, particularly through demand forecasts and contractual power load profiles.

Understanding Rising TNUoS Cost Burdens can help businesses navigate future challenges.

Explore demand flexibility and distributed energy strategies that might mitigate peak demand charges or shift consumption patterns.

Strategies to cope with Rising TNUoS Cost Burdens will be key for many organisations.

And monitor quarterly tariff updates and sensitivity disclosures from NESO as the picture crystallises.

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Engagement with the Rising TNUoS Cost Burdens topic is vital for all stakeholders.

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