Capacity Upgrades & New Connections 2026 – A Guide for Financial Controllers

Electricity, gas and water networks underpin every modern business. Rapid electrification (electric vehicles, heat pumps, data centres etc.) and the drive toward net‑zero emissions mean that network operators need to build new lines, replace old equipment and upgrade capacity. Ofgem’s 2025 RIIO‑3 draft determinations allow £24.2 billion for transmission companies during 2026‑2031. The regulator notes that high costs are driven by major transmission reinforcements, capacity upgrades to support electrification, and the need to connect new renewable generation. Distribution networks face similar pressures – the connections queue has grown to over 700 GW, far more than the capacity needed for net‑zero. The UK government is working with Ofgem and the National Energy System Operator (NESO) to reform the connections process, prioritising projects that align with the Clean Power 2030 plan.

For financial controllers, capacity upgrades and new connections are not merely engineering issues – they directly affect budgets through standing charges, capacity charges and connection fees. Non‑commodity charges (for transmission and distribution network use) are forecast to rise sharply. NESO warns that Transmission Network Use‑of‑System (TNUoS) charges will almost double from April 2026, and the new Regulated Asset Base (RAB) charge for funding nuclear generation adds approximately 0.346 p/kWh. However, there are strategies to mitigate these increases and even generate revenue.

This playbook provides a comprehensive guide to:

• understand capacity charges and new connection processes,

• reduce costs through right‑sizing capacity and energy efficiency,

• participate in flexibility markets to earn revenue by shifting or reducing demand, and

• leverage on‑site generation, storage and procurement strategies.

1.1 RIIO‑3 and RIIO‑ED3 price controls

Ofgem uses the RIIO (Revenue = Incentives + Innovation + Outputs) model to set price controls for transmission and distribution network operators. The current RIIO‑2 period ends on 31 March 2026, and RIIO‑3 (for transmission and gas) and RIIO‑ED3 (distribution) will run from April 2026 onwards. The regulator has proposed a £24.2 billion revenue cap for transmission companies, up from ~£13 billion in RIIO‑2, largely due to:

• Transmission network reinforcement – building new lines and subsea cables for offshore wind.

• Capacity upgrades to support electrification – businesses and local authorities electrify operations, so networks must expand.

• Connecting new renewable generation – the grid must integrate numerous new wind and solar projects.

These investments are recovered through higher network charges. Controllers should anticipate increases in fixed standing charges and TNUoS tariffs. For example, projections show that TNUoS charges could almost double from April 2026. The RAB charge, introduced to fund the Sizewell C nuclear plant, adds 0.346 p/kWh.

1.2 Connections reform

Historically, grid connections were queued on a first‑come‑first‑served basis. This created a pipeline of stalled projects, with the transmission and distribution queue exceeding 700 GW. In 2025 the government and Ofgem launched an End‑to‑End Review of network connection processes. Key elements include:

• Deprioritising stalled/speculative projects – NESO will remove ~500 GW of inactive projects from the queue.

• Prioritising strategic and ready‑to‑build projects aligned with Clean Power 2030.

• Minimum standards for distribution network operators (DNOs) – agreed guidance on connection timescales and indicative pricing, common digital documentation and allowing customers to apply for multiple low‑carbon technologies in a single application.

• Incentives for DNOs – Ofgem plans to incentivise pre‑application engagement, timely connection offers and delivery, with rewards for high performance and penalties for poor performance.

• Non‑firm connection offers – DNOs can offer non‑firm connections that allow customers to connect more quickly at lower cost but accept curtailment during network constraints. By March 2025 over 218 generation and storage projects (8 GW) had accepted non‑firm offers, enabling them to connect an average of 7 years earlier.

Financial controllers should monitor the RIIO‑ED3 methodology (expected in 2025) for details on distribution network charges and incentives.

2.1 Maximum Import Capacity and capacity charges

Businesses with half‑hourly electricity meters must agree a Maximum Import Capacity (MIC), measured in kVA, with their DNO. The MIC represents the highest power demand the network will guarantee. Capacity charges (part of DUoS charges) are levied monthly based on the MIC. A guide from Business Energy Deals explains:

• The MIC can be decreased without a fee, releasing capacity for other customers and reducing monthly capacity charges. However, released capacity may not be available later, so future demand should be considered.

• Increasing the MIC requires an application and may involve network reinforcement costs if local capacity is limited.

• Capacity charges typically range from £1.20 to £3.30 per kVA per month, depending on region, and are calculated by multiplying the MIC (kVA) by the unit charge and number of days.

• Exceeding the MIC incurs excess capacity charges: the extra kVA demand is charged for the full month. To avoid these charges businesses can: increase the MIC, reduce maximum demand through efficiency and load management, or use an energy management system with battery storage.

2.2 Choosing the right MIC

Selecting an appropriate MIC requires analysing half‑hourly consumption data over at least a year. Controllers should:

1. Assess current maximum demand – review the highest 30‑minute kVA readings and ensure the MIC comfortably exceeds them.

2. Forecast future demand – account for planned growth, electrification of heat/transport, and installation of on‑site generation or storage.

3. Avoid over‑committing – an excessively high MIC leads to unnecessary capacity charges; an overly low MIC risks excess charges.

4. Update annually – the MIC can only be changed once per year. Plan ahead for expansions to avoid costly delays.

2.3 New Connection Costs

Costs for new grid connections depend on capacity, voltage level and distance to existing infrastructure. Indicative figures from UKPN and other DNOs show that small commercial connections (up to ~100 kVA) can cost £4,000–£8,000, while medium‑sized industrial connections often exceed £30,000 and may require reinforcement works. To manage costs:

• Engage early with the DNO – use digital tools like ENA ConnectDirect, UKPN Smart Connect or G99 fast‑track platforms to assess available capacity and obtain indicative prices.

• Bundle low‑carbon technologies – under new guidelines, customers can apply for multiple technologies (e.g., solar PV, EV chargers and heat pumps) through a single application, simplifying the process and reducing fees.

• Consider non‑firm connections – where available, non‑firm offers allow earlier connection at lower cost but with potential curtailment.

• Plan infrastructure upgrades – if capacity is insufficient, budget for reinforcement works (new cables/transformers) which can take 6–18 months. Align these projects with other capital plans.

3.1 Reduce maximum demand

Lowering peak demand can reduce both capacity charges and commodity costs. Strategies include:

• Operational efficiency – upgrade motors, pumps and HVAC systems; schedule energy‑intensive processes outside peak periods; implement variable speed drives. Reducing maximum demand reduces the need to increase MIC and lowers capacity charges.

• Load management – use automated control systems to shift processes to off‑peak hours (e.g., pre‑cool refrigerated warehouses at night). Half‑hourly settlement makes savings more measurable.

• Energy management systems (EMS) – monitor real‑time consumption and automate response. An EMS combined with battery storage can charge when prices are low and discharge during peak periods, lowering demand and avoiding excess charges.

3.2 Decrease excess capacity

If the business consistently uses less than the agreed MIC, apply to reduce it. Decreasing the MIC is usually free and immediately reduces monthly capacity charges. However, confirm that future expansion plans (e.g., EV charging) will not require additional capacity; once released, capacity may not be available later.

3.3 Energy efficiency and demand reduction incentives

Funding and incentives exist to support energy‑saving measures, such as the Energy Savings Opportunity Scheme (ESOS) for large enterprises and tax relief for capital equipment. Reducing consumption not only cuts commodity costs but also limits the MIC needed, reducing network charges.

Audit current capacity and demand: Retrieve half‑hourly consumption data; compare maximum demand with the agreed MIC; identify under‑utilised capacity to release or capacity shortfalls requiring upgrades.

Engage with the DNO: Use digital tools to check local network capacity; plan applications for capacity changes or new connections well in advance. Where possible, bundle multiple low‑carbon technologies in a single application.

Optimise energy usage: Implement energy efficiency projects and load management to reduce peak demand; install an EMS and consider battery storage to smooth peaks and enable flexibility participation.

Evaluate non‑firm connection offers: For new projects, non‑firm connections can accelerate connection by years. Assess whether occasional curtailment is acceptable given potential savings.

Participate in flexibility markets: Identify assets that can be temporarily turned down or rescheduled (refrigeration, pumps, manufacturing equipment). Register for the Demand Flexibility Service via your supplier or an aggregator and explore other markets (frequency response, local DNO services). Expected payments of around £3/kWh in early phases and potential revenues of tens of thousands of pounds per MW per year make this attractive.

Invest in on‑site generation and storage: Conduct feasibility studies for solar PV, wind or CHP; explore the Smart Export Guarantee or PPAs for revenue; consider battery storage to maximise self‑consumption and peak shaving.

Review procurement strategy: With non‑commodity charges rising, secure competitive energy contracts; evaluate fixed vs flexible purchasing; time contract renewals to exploit low wholesale prices.

Plan for EV and electrification: Anticipate load from electric vehicle charging and heat pumps; include V2G capability where feasible to provide additional flexibility revenue.

Stay informed on policy: Monitor Ofgem’s RIIO‑ED3 methodology (expected summer 2025) and government consultations on connections reform. Regulatory changes may affect charges and incentives.