GB Energy Network: Methodology and Costings

This appendix sets out the basis for the programme’s allocation of £2.5 billion per annum (from Year 2) to replace the transmission system charges currently recovered from industrial and commercial electricity supplies. The payment funds the transmission owners’ Ofgem-determined allowed revenue through the charge recovery mechanism that the National Energy System Operator (NESO) administers. All figures are expressed in 2025 prices unless otherwise stated.

This policy supports the decoupling of electricity prices from the marginal cost of fossil-fuelled generation, so that what businesses pay for power increasingly reflects what it costs to generate and deliver.

Policy objective

Why relocation precedes reassignment

The costs that make British electricity expensive are real and, for the existing generating fleet, largely fixed. They are recovered today through a fragmented set of channels, network charges, legacy renewables contracts, capacity payments and policy levies, spread thinly across every bill. In that form the cost is hidden, unowned, and contractually protected. No single party is responsible for it and no single party is motivated to reduce it. The generators whose intermittency drives much of the system cost are insulated by fixed contracts and are paid irrespective of whether their output is of use to the system at the moment it is produced.

A cost in that condition cannot be assigned to its cause, because it has first to be isolated, quantified and brought under unified control. Moving the system-cost portion onto the public account does exactly this. It converts a diffuse and protected pass-through into a single, measured, government-owned line. That is not the end of the reform. It is the precondition for the rest of it.

The transition: legacy run-off, new capacity on a causer-pays basis

The fixed contracts attached to the existing fleet are the hard constraint. They cannot be re-priced at will, and attempts to do so invite years of litigation. The realistic path is therefore a transition rather than a switch. The legacy system cost is carried on the public account and runs off as those contracts expire, while all new capacity is procured on a basis that confronts each technology with the costs it imposes on the system, including the cost of the firm, secure power that an intermittent fleet requires standing behind it. Over time the share of system cost that is socialised falls, and the share that is borne by those who create it rises. This is the difference between a programme that relocates cost and a programme that reforms it.

The institutional engine

Two features of the reform supply the motive force for this transition. The first is the operator's statutory mandate: a standing duty to deliver secure power at least whole-system cost, and to assign the costs of intermittency and security to those who cause them. That duty operates continuously, on a multi-year determination cadence comparable to an infrastructure price control, not through year-by-year intervention. The second is visibility. Because the system cost is now a single, measured, published figure rather than a charge buried across millions of bills, Parliament and the public can see whether it is falling as intended or quietly growing, which is standing democratic pressure that requires no one to hold discretion over the funding. The Treasury's interest is genuine, but it is structural and medium-term: the Exchequer gains as its residual liability shrinks under the transition, which gives it reason to back the reform and to hold the operator to a declining trajectory rather than to raid the line. Reconstituting the system operator as a body accountable to Parliament, rather than one regulated at arm's length and exposed to capture by the interests it oversees, is what makes it both the guardian of that declining trajectory and the vehicle through which the costs of intermittency and security are assigned to their causes.

The risk this guardrail addresses

Costs moved onto the public purse have a strong tendency to become permanent. Measures introduced as temporary relief are routinely endogenised; the visible pain that would have forced the harder reform is removed, and with it, the pressure to complete it. Applied to energy, the danger is precise. Once household and industrial bills are relieved and the system-cost line sits comfortably within the public accounts, the political impetus to confront the underlying costs, and to charge them to those who cause them, can quietly dissipate. The cost-causers retain their insulation. The taxpayer absorbs a line that grows rather than declines. The relocation that was meant to be the first step becomes the destination, and the result is a more complete version of the very evasion the reform set out to correct.

The mechanism is identical whether the outcome is reform or evasion. What distinguishes them is whether the commitment to assign costs to their causes is built in from the outset, stated as the purpose of the relocation, and given an accountable body and a fiscal interest to deliver it. That commitment is the guardrail. It is not an addition to the programme's objective. It is the part of the objective that makes the rest of it hold.

UK industrial competitiveness

The GB Energy Network intervention targets a specific structural disadvantage in UK industrial competitiveness: the embedding of transmission system costs — Transmission Network Use of System (TNUoS) charges — in industrial and commercial electricity prices. These charges recover the costs of building, maintaining, and operating the high-voltage transmission network and are levied by NESO on electricity suppliers and directly connected demand users, who pass them through to end customers.

The intervention does not extend to Distribution Use of System (DUoS) charges, which recover the costs of regional lower-voltage networks operated by Distribution Network Operators (DNOs) under separate RIIO-ED price controls. Nor does it cover Balancing Services Use of System (BSUoS) charges or policy levies such as the Renewables Obligation, Contracts for Difference levy, or Capacity Market charges. These remain on commercial and industrial bills or are addressed through other programme measures (the Universal Energy Service covers domestic standing charges, which include distribution and policy cost components).

The practical effect is that industrial and commercial electricity consumers would pay only the wholesale generation cost of electricity — the marginal cost of production — plus distribution network charges, policy levies, and supplier margin. Transmission system costs would be socialised through general taxation via the GB Energy Network payment, which funds the transmission owners’ allowed revenue through the TNUoS recovery mechanism that NESO administers.

Derivation of the £2.5 billion estimate

Top-down approach: total TNUoS revenue and the non-domestic share

In the 2025/26 charging year, total TNUoS allowed revenue was approximately £5.3 billion, of which roughly 75% (£3.96 billion) was recovered from demand-side users and 25% (£1.13 billion) from generators (NESO, TNUoS Tariff Publications 2025/26; Chambers and Partners, Power Generation, Transmission & Distribution 2025).

Non-domestic electricity consumption accounts for approximately 55–60% of total GB electricity demand. However, the non-domestic share of TNUoS demand charges is somewhat lower than its volumetric share, because TNUoS demand tariffs for non-half-hourly (NHH) meters, which cover smaller commercial premises, are calculated on a different basis from the charges applied to half-hourly (HH) metered industrial and large commercial sites. Since the Targeted Charging Review (April 2023), the bulk of the HH demand charge, the Transmission Demand Residual, is recovered as a fixed daily charge banded by site capacity (Authorised Supply Capacity), with only the smaller forward-looking locational element still recovered on the Triad basis. The non-domestic share of TNUoS demand revenue in 2025/26 is estimated at approximately £2.0–2.5 billion.

Bottom-up approach: industrial energy costs and network cost share

UK industrial electricity prices stood at approximately 29.6 p/kWh including taxes and levies in the first half of 2024, the highest in the EU14+UK grouping (DESNZ, Quarterly Energy Prices, December 2024). Manufacturing-sector prices excluding the Climate Change Levy averaged approximately 17.0 p/kWh in Q3 2024. TNUoS charges typically constitute 7–10% of total non-domestic electricity costs (ElectricityCosts.org.uk; NESO tariff data). Applying this range to total non-domestic electricity expenditure of approximately £20–25 billion (estimated from DESNZ price and volume data across consumption bands) yields a TNUoS component of £1.4–2.5 billion.

Cross-check: National Grid UK transmission revenues

National Grid’s UK electricity transmission business generated revenues of approximately £3–4 billion annually prior to the transfer of system operator functions to NESO on 1 October 2024. A £2.5 billion intervention targeting the non-domestic demand share of those revenues represents approximately 60–70% of total transmission system income — consistent with the industrial and commercial sector’s share of transmission network utilisation.

Settled estimate

The three approaches converge on a range of £1.5–2.5 billion for the non-domestic demand share of TNUoS charges at 2025/26 levels. The programme adopts the upper bound of £2.5 billion as the budget allocation, providing headroom against:

• annual TNUoS tariff adjustments within the current RIIO-ET2 price control;
• modest real-terms growth in transmission allowed revenues beyond general inflation; and
• the inclusion of Energy Intensive Industry (EII) exemption costs, which are currently funded through a separate levy on other electricity consumers and which this intervention would absorb.

Relationship to the Universal Energy Service

The programme’s Universal Energy Service allocates £9.0 billion per annum to absorb household energy standing charges (£8.3 billion) and provide fuel vouchers for off-grid heating households (£0.7 billion). The standing charge component covers gas and electricity standing charges, which include domestic distribution network costs (DUoS), transmission network costs (TNUoS), supplier fixed costs, metering charges, policy levies recovered through standing charges, and Supplier of Last Resort (SOLR) costs. The electricity transmission component embedded in domestic standing charges is a subset of the £8.3 billion standing charge allocation — estimated at approximately £1.5–2.0 billion, representing the domestic (household) share of TNUoS demand charges.

The combined GB Energy Network (£2.5 billion) and Universal Energy Service (£9.0 billion) therefore provide approximately £11.5 billion in total central government funding directed at the electricity and gas network system. Of this, the electricity transmission-specific component is approximately £4.0–4.5 billion (£2.5 billion non-domestic + £1.5–2.0 billion domestic via the UES), which approximates the total TNUoS demand-side revenue of £3.96 billion in 2025/26 with modest headroom for tariff growth within the current price control period.

Trajectory risk and the RIIO-ET3 price control

TNUoS charges are projected to increase substantially from April 2026 under the RIIO-ET3 price control (2026–2031). NESO’s Five-Year View forecasts total TNUoS allowed revenue rising from approximately £5.3 billion in 2025/26 to £8.9 billion in 2026/27 and £13.6 billion by 2030/31 (NESO, TNUoS Five-Year View, January 2026; Businesswise Solutions analysis). This increase is driven primarily by the transmission reinforcement programme required to deliver the government’s Clean Power 2030 ambition, including offshore wind connections, onshore reinforcements such as Eastern Green Link 1 and 2, and the Yorkshire Green project.

In nominal terms, the non-domestic share of TNUoS demand charges could rise to £4–6 billion by 2030/31 under the current RIIO-ET3 trajectory — well above the £2.5 billion allocation at 2025 prices.

Three considerations mitigate this exposure:

First, this programme’s fiscal architecture is calibrated in 2025 prices for distributional analysis purposes. The £2.5 billion reflects the real resource cost of the intervention at the point of programme design. Under the governance framework set out below, the Exchequer’s payment obligation is linked to Ofgem’s RIIO price control determinations for the relevant network operators. The nominal amount will escalate as Ofgem’s 5-year allowed revenue settlements change — particularly under RIIO-ET3, where transmission investment for Clean Power 2030 is expected to approximately double allowed revenues. The programme’s fiscal architecture accommodates this through the statutory payment obligation: the Exchequer pays whatever Ofgem independently determines, ensuring network investment is not constrained by short-term fiscal pressures.

Second, the RIIO-ET3 revenue trajectory is contingent on the pace of transmission investment delivery. The allowed revenue figures assume full delivery of the Clean Power 2030 investment programme on schedule. Historically, major transmission reinforcement projects have experienced significant delays. If the investment programme slips — or if the Clean Power 2030 target is relaxed or abandoned — allowed revenues will be lower than the Five-Year View projects, and the £2.5 billion allocation in 2025 prices will retain greater headroom.

Third, the programme’s own energy transition investments reduce long-term transmission costs. Distributed generation, demand-side flexibility, and local energy networks — all supported by other programme measures — reduce the need for long-distance bulk power transmission. To the extent that the programme accelerates distributed energy deployment, it partially offsets the transmission investment requirement and the associated TNUoS cost growth.

The programme acknowledges that under a scenario of rapid and on-schedule Clean Power 2030 delivery, the £2.5 billion allocation would cover a declining share of non-domestic TNUoS charges through the late 2020s. This is a known fiscal risk, quantifiable within a range, and subject to the same nominal adjustment mechanisms applied to other programme cost lines indexed to regulatory price controls.

NESO governance reform and payment channel safeguards

Moving energy network funding from consumer bills to the Exchequer creates a governance question: how is the funding protected from ministerial interference? Under the current system, network revenues flow automatically through Ofgem-regulated price controls — a minister cannot casually redirect them. The programme must preserve this protection while correcting the institutional design error that Helm identifies in NESO’s corporate structure.

The solution separates three functions — governance of the system operator, revenue determination for network operators, and the payment obligation — and assigns each to the appropriate institution.

NESO governance reform

NESO was established as a company outside the Civil Service, a corporate structure chosen to escape Civil Service salary restrictions. The unintended consequence, as Helm observes, was “the ridiculous consequence” of a public system operator being regulated by Ofgem — a regulator designed to oversee commercial network monopolies. NESO does not deploy capital; it plans, coordinates, and procures. Regulating it through Ofgem’s RIIO price control process — a mechanism built around incentivising efficient private-sector capital deployment — is a category mismatch.

The GB Energy Network Act reconstitutes NESO as a statutory public body with duties set directly in legislation, consistent with the institutional design adopted for Catchment Water System Operators (CWSOs) under the companion Water Act. The key provisions are:

Statutory duties. NESO's functions are established as statutory duties in the Act, replacing the current licence-based framework administered by Ofgem. Its primary duty is to secure a reliable supply of firm power at the lowest whole-system cost, pursued independently within the decarbonisation and security constraints set by the Secretary of State. Subordinate to that objective, the duties include system balancing, network development planning, demand-side coordination, competitive procurement of capacity and flexibility, and administration of the GB Energy Network and Universal Energy Service funding flows. In designing procurement and charging, NESO has a duty, so far as practicable, to recover the costs of intermittency, balancing, and capacity from the parties whose generation or demand choices give rise to them, rather than spreading them uniformly across users.

Direct accountability. NESO reports to the Secretary of State for Energy Security and Net Zero, with an annual report laid before Parliament. NESO’s own operational budget (staff, planning, systems — approximately £200–300 million) is set through the Spending Review process. The National Audit Office has full audit rights.

Salary and staffing flexibility. The statutory body retains the ability to set its own pay scales outside Civil Service bands — the original rationale for the corporate structure. The Act specifies that NESO’s remuneration framework is set by its board, subject to HM Treasury approval for senior posts, following the model established for the Bank of England and the Financial Conduct Authority. This preserves NESO’s ability to recruit from the energy industry at market rates without the governance distortion that Helm identifies.

Board appointment. The Secretary of State appoints the chair and non-executive directors. The chief executive is appointed by the board with the Secretary of State’s approval.

The principle underlying this reform is the same one that Helm articulates for water: a public system operator can plan, coordinate, and procure from multiple private and public providers without itself being structured as a commercial entity. The NESO model has been proven in energy. What has not worked is the corporate form chosen to deliver it.

Ofgem’s role: unchanged for network operators

The governance reform applies to NESO only. The private network operators — the six DNO groups, the transmission owners (National Grid Electricity Transmission, SSEN Transmission, SP Transmission), and the gas transmission and distribution companies (National Gas Transmission, Cadent, SGN, Northern Gas Networks) — remain Ofgem-regulated monopolies with 5-year RIIO price controls that determine their allowed revenues. This is unchanged from the current system.

Ofgem’s independent determination of network operator revenues is the mechanism that protects the programme from ministerial interference. The allowed revenue for each network operator is set through a quasi-judicial regulatory process, locked in for a 5-year price control period, and is legally binding once agreed. A minister cannot alter the revenue determination without overriding Ofgem, which would require primary legislation. This is precisely the same protection that exists today; the programme preserves it in full.

Statutory payment obligation

The GB Energy Network Act creates a statutory obligation on the Secretary of State to pay network operators their full Ofgem-determined allowed revenues on the schedule Ofgem sets. The minister has no discretion over the amount, the timing, or the allocation between network operators. These are determined by the independent regulator through exactly the same RIIO price control process that operates today. The only change is the source of the payment — from consumer bills to the Consolidated Fund.

This obligation operates identically for both the GB Energy Network (£2.5 billion, C&I transmission charges) and the Universal Energy Service (£7.7 billion, domestic standing charge network costs). The combined flow of approximately £10.2 billion per year from the Exchequer to network operators is a single statutory payment channel, differentiated only by accounting classification:

The legal model is analogous to debt service on gilts: the government does not choose whether to pay, or how much, or when. The obligation is created by statute and enforceable by the network operators through judicial review if the Secretary of State fails to pay. A minister who attempted to withhold, delay, or redirect the payment would be acting unlawfully.

What the minister controls — and does not control

The programme gives the minister less influence over network funding than they currently exercise over comparable public spending (NHS, defence, education), because the quantum is set by an independent regulator through a legally binding price control, not by a Spending Review negotiation. The minister’s proper role — setting the energy policy framework within which NESO and the network operators operate — is preserved. Their improper role — determining how much money flows to the network, or when, or to whom — is excluded by design.

This is the Bank of England model applied to energy infrastructure: the Chancellor sets the inflation target and appoints the Governor, but cannot set interest rates. The Secretary of State sets the decarbonisation and security constraints and appoints the chair, but cannot direct how NESO meets them, nor relax its duty to meet them at least whole-system cost.

Caveats and limitations

Scope limitation. The £2.5 billion covers transmission (TNUoS) charges only. Non-domestic consumers will continue to pay DUoS (distribution), BSUoS (balancing), and policy levies. The intervention therefore does not reduce industrial electricity prices to the pure marginal cost of generation; it removes the single largest non-wholesale, non-distribution charge component. A full reduction to marginal generation cost would require an additional £1.0–1.5 billion (at 2025 levels) to cover non-domestic DUoS fixed charges, which is not included in this programme.

Generator TNUoS charges. The intervention targets demand-side TNUoS only. Generator TNUoS charges (approximately £1.1 billion in 2025/26) are not covered. These charges are in principle passed through to consumers via wholesale electricity prices; absorbing them would require a separate mechanism and is not proposed here.

Behavioural response. Any peak-avoidance signal in the transmission demand charge is already much diminished. Ofgem's Targeted Charging Review moved the bulk of the demand charge, the Transmission Demand Residual, onto a fixed daily charge banded by site capacity from April 2023, so large consumers can no longer materially reduce it by cutting demand during winter peaks; only the smaller forward-looking locational element still rewards reduction during the three Triad half-hours. Removing the residual transmission demand charges therefore removes a largely fixed charge rather than a strong live incentive. The programme reconstitutes the demand-side signal through NESO's duty to price balancing and capacity to those who cause them, and through the appliance-level demand response infrastructure funded by Energy for the Future.

Data vintage. TNUoS revenue figures are based on NESO’s published tariff data for 2025/26 and the Five-Year View published in January 2026. DUoS and BSUoS estimates draw on Ofgem RIIO-ED2 annual reports and industry analysis. Non-domestic consumption shares are estimated from DESNZ Quarterly Energy Prices volume data and DUKES (Digest of UK Energy Statistics) sectoral consumption tables. All figures are subject to revision as regulatory determinations are finalised and outturn data become available.

Sources

• NESO, Transmission Network Use of System (TNUoS) Charges: 2025/26 Tariff Publications (2025).
• NESO, TNUoS Five-Year View (January 2026).
• Chambers and Partners, Power Generation, Transmission & Distribution 2025: UK — Trends and Developments (July 2025).
• Ofgem, RIIO-2 Electricity Distribution: Annual Report 2024 to 2025 (January 2026).
• Ofgem, RIIO-2 Electricity Transmission: Annual Report 2024 to 2025 (January 2026).
• Ofgem, RIIO-2 Regulatory Performance Data: 2024 (2024).
• DESNZ, Quarterly Energy Prices: December 2024 (December 2024).
• DESNZ, Quarterly Energy Prices: June 2025 (June 2025).
• DESNZ, Digest of UK Energy Statistics (DUKES) (2024 edition).
• House of Commons Library, Gas and electricity prices during the ‘energy crisis’ and beyond, Research Briefing CBP-9714 (updated April 2026).
• House of Commons Library, Energy standing charges, Research Briefing CBP-10339 (updated April 2026).
• ElectricityCosts.org.uk, Electricity Bill Charges: Breakdown of Bill Components (2024).
• Businesswise Solutions, TNUoS Residual Charges: Five-Year Forecast Analysis (February 2026).
• npower Business Solutions, The TNUoS Shake-up: Electricity Costs Set for Record Increases from April (February 2026).

All figures in 2025 prices unless otherwise stated. TNUoS revenue projections from NESO’s Five-Year View are in nominal terms and are noted as such where cited.