By 2026 the UK energy system will operate under new price controls, a national planning body, half-hourly settlement, updated market rules and a revised levy mix that includes a nuclear RAB charge. Headline prices look relatively stable, but the underlying structure of non-commodity costs and locational signals will change.

Businesses that understand these shifts, act early on site strategy and contracts, and make use of flexibility will be in a stronger position to control costs and capture new value as the next phase of the UK power system rolls out.

Price signals for 2026: what they mean for business

Ofgem’s default tariff cap for January to March 2026 will rise only slightly compared with the previous quarter. Large users do not buy this product, but the cap is a simple proxy for how the cost stack is moving.

The latest breakdown shows:

• Wholesale costs easing versus last year

• Policy and supplier business costs increasing

• Network charges broadly flat in early 2026

For industrial and commercial customers the important story is not the small movement in the cap. It is the slow build in non-commodity pressure that will appear through RIIO-3, network charging reform and the nuclear RAB levy from 2026 onwards.

Wholesale market conditions for 2026

Forward markets suggest that 2026 will sit in a middle ground. Prices are well below the crisis peaks of 2022 but still above pre-2021 norms.

Current indicators show:

Cal products have been held in check by steady LNG supply and mild weather. Day-ahead power prices remain volatile, especially when wind output drops. This pattern will continue. Wholesale price risk for 2026 is driven by:

• Global gas markets and LNG availability

• Weather and renewable output

• Interconnector flows and nuclear availability

For larger users this supports a strategy that blends medium-term hedges with flexibility, rather than relying purely on static annual volumes.

REMA, reformed national pricing and NESO

The government’s Review of Electricity Market Arrangements (REMA) has confirmed that Great Britain will retain a single national wholesale electricity price. Proposals for zonal or nodal pricing have been rejected.

Instead ministers are pursuing a Reformed National Pricing model built around three pillars:

• Stronger locational signals delivered through transmission charging and connection rules

• A Strategic Spatial Energy Plan (SSEP) that maps the best locations, technologies and quantities for electricity and hydrogen infrastructure

• Closer alignment between the SSEP, planning decisions, network build and future charging reform

The new National Energy System Operator (NESO) will sit at the centre of this framework. NESO brings electricity and gas planning into one independent body. It will:

• Produce the first SSEP in 2026

• Advise on how to deliver clean power by 2030

• Coordinate network investment across vectors

• Provide impartial analysis on system needs

For investors and developers this means that location choice will increasingly be judged against the SSEP. Projects that align with NESO’s preferred zones are more likely to secure timely connections and predictable charging outcomes.

Network price controls, TNUoS and the nuclear RAB levy

RIIO-3 price controls

From 1 April 2026 to 31 March 2031 gas and electricity transmission and gas distribution networks will move into the RIIO-3 price control. Draft determinations propose allowed revenue for electricity transmission of around £24.2 billion over the period, an increase of roughly 86 percent in nominal terms versus RIIO-2.

Key drivers are:

• Reinforcement to connect offshore wind and new subsea links

• Capacity upgrades for electrified transport and heating

• Replacement of aging assets

• Connections for new renewable and flexibility projects

These additional revenues will flow through to non-commodity costs, most visibly in Transmission Network Use of System charges. Final non locational demand tariffs and half hourly bands for 2026 to 2031 will not be confirmed until early 2026, but a significant uplift is expected, particularly for high voltage sites.

Reformed network charging

Ofgem’s work on network charging is pushing TNUoS and connection charges towards a more spatial approach. Expected developments include:

• Charges that reflect forecast spare capacity and reinforcement needs in each area
• Tighter links between connection offers and the Centralised Strategic Network Plan

• Greater use of locational factors in Contracts for Difference and Capacity Market auctions

In practice, new generation and storage will be steered towards zones where the SSEP and CSNP anticipate available capacity. Large load users will see clearer cost signals based on how their demand relates to those zones.

TNUoS 2026 / 27: NESO forecasts a 38 percent rise

NESO’s latest Five Year View of TNUoS shows a sharp step up in 2026 / 27. For a typical consumer, total TNUoS costs are forecast to rise by about 38 percent in that year, with demand residual revenues carrying most of the increase.

Illustrative figures show:

Half hourly demand tariffs rising from about £3.00/kW in 2025/26 to £3.18/kW in 2026/27

Non half hourly demand tariffs rising from about 0.38 p/kWh to 0.43 p/kWh

Embedded export tariffs rising from about £3.00/kW to £3.45/kW

Demand residual revenue increasing from roughly £3.84 billion to £7.52 billion

NESO highlights three main factors:

• Higher allowed revenues for transmission owners
• Increased investment in grid capacity and subsea links
• Slower progress on near term reforms under REMA, so the current framework must carry the uplift

Because TNUoS is zonal, the impact varies by region. Indicative changes suggest around a 40 percent rise in total TNUoS in the South West and about 35 percent in London, with other zones between these bounds. Actual site level outcomes depend on zone, connection voltage, metering class, agreed capacity and coincidence with system peaks.

For commercial and industrial portfolios this is a structural step change, not a small adjustment. Multi site portfolios will see very different outcomes across zones, which creates both risk and optimisation opportunities.

Hydrogen and the future of the gas network

Gas networks are starting to prepare for a mixed natural gas and hydrogen future.

Ofgem’s price control consultations include funding applications for Front-End Engineering Design (FEED) studies on hydrogen network projects in north-west England and along the St Fergus to Teesside corridor. These schemes show how existing assets could be repurposed to move low-carbon hydrogen.

Government decisions expected in 2026 will determine:

• Whether hydrogen blending is permitted in gas distribution grids
• Whether hydrogen heating trials progress into long-term markets

Capacity Market reforms

Consultations in late 2025 propose several changes to the Capacity Market ahead of the 2026 auctions. Key ideas include:

• A multiple price cap design that allows higher clearing prices for long-duration, dispatchable capacity that can support the system during tight conditions
• Tighter control of information during auctions to reduce strategic bidding and improve value for money
• Stronger recognition of demand-side response and flexibility, so consumer-side solutions can compete fairly with generation
• Rules that allow battery projects to nominate a lower connection capacity for performance tests, reflecting realistic operating profiles

• Sustainability criteria that open low-carbon Capacity Market routes to suitable non-fossil plant such as sustainable biomass

Energy broker and TPI regulation

From 2026 Ofgem will begin regulating energy brokers and third-party intermediaries. The regime is expected to include:

• A mandatory register of brokers and TPIs
• Transparent disclosure of commission and fee structures
• An authorisation framework that makes it illegal to operate without Ofgem approval

This directly addresses historic issues around hidden commissions and aggressive sales tactics in the business market. Large users will need to verify that their advisors are authorised and compliant.

Market-wide Half-Hourly Settlement (MHHS)

MHHS will move all electricity settlement onto half-hourly consumption data by October 2026, with full go-live by 2027. Migration of smart meters started in September 2025.

Expected benefits are:

• More accurate allocation of wholesale and network costs
• Wider roll-out of time-of-use and dynamic tariffs
• Commercial models for vehicle-to-grid, smart charging and load shifting

For businesses, MHHS will make flexibility more valuable. Loads that can move away from peak periods or respond to signals will unlock new savings and revenue streams.

Heat network regulation and carbon pricing

Ofgem is also taking on regulation of heat networks from 2025 or 2026 under the Heat Networks (Market Framework) legislation. Operators will need to meet new licensing, pricing and consumer protection requirements.

The UK Emissions Trading Scheme will continue to shape carbon costs. Government plans to broaden sector coverage and tighten the cap through the late 2020s. Exposed sites and energy-intensive users need to monitor these reforms and build carbon price scenarios into their planning.

The Electricity Generator Levy on certain low-carbon generators is currently scheduled to remain in force until March 2028. This will continue to influence PPA pricing and project economics for affected plant.

What businesses should expect

Taken together, these measures point to a clear set of outcomes for larger users and infrastructure investors.

You should plan for:

Higher non-commodity costs
RIIO-3 revenue increases, network charging reform and the nuclear RAB levy will lift the non-commodity share of electricity bills from 2026 onwards, particularly at high-voltage sites.

More granular, location-driven tariffs
The SSEP, CSNP and charging reforms will sharpen locational signals. Site selection and connection strategy will have a greater impact on lifetime energy costs.

Continued wholesale volatility
Price cap movements look modest, but wholesale prices will remain sensitive to gas markets, weather and renewable output. Long-term strategies should consider a range of scenarios.

More value from flexibility and storage
MHHS, Capacity Market reforms and DSR products will create new revenue opportunities for flexible loads, on-site generation and batteries.

Tighter regulation of intermediaries and new asset classes
Broker regulation, heat network licensing and hydrogen governance will raise compliance expectations along the value chain.

Conclusion

By 2026 the UK energy system will operate under new price controls, a national planning body, half-hourly settlement, updated market rules and a revised levy mix that includes a nuclear RAB charge. Headline domestic prices look relatively stable, but the underlying structure of non-commodity costs and locational signals will change.

Businesses that understand these shifts, act early on site strategy and contracts, and make use of flexibility will be in a stronger position to control costs and capture new value as the next phase of the UK power system rolls out.