As non-commodity charges climb and grid costs become harder to predict, Alexander Goodall, Founder and CEO at Xela Energy, explores how private wire renewable projects can give large power users long-term price visibility and resilience, as he explains.
From 2021 to 2024, UK energy prices for non-domestic users have at times more than doubled, and as of late 2024 remain around 75% higher than at the start of 2021. The UK also has some of the highest industrial electricity prices among IEA (International Energy Agency) countries. While many are aware of wholesale price volatility, the non-energy components of electricity bills – driven by an ageing grid, green policy costs, and various market charges – are less well understood.
This article addresses non-commodity costs (NCCs): what they are, how they affect energy bills, and how behind-the-meter private wire renewables can help mitigate rising costs.
What makes up an average energy bill?
There are two key components to a business’ energy bill: commodity and non-commodity costs.
Commodity costs
Power and gas are among the largest commodities traded globally. Electricity has the specific challenge that it cannot be stored economically at large scale (at least not yet in most systems), so supply and demand must be balanced in real time.
Large energy users can select fixed or variable supply contracts, depending on risk appetite and their view of future market movements. These contracts determine the commodity price they pay for the electricity itself.
Non-commodity costs (NCCs)
Non-commodity charges were established in the early 1990s, but started increasing significantly around the year 2000 as competition and the complexity of the system required new charging mechanisms. They have continued to increase and now account for a substantial share of electricity costs for businesses across the country.
The UK, like every other country, faces the ‘energy trilemma’. The optimal energy system aims to be:
- Clean and green
- Affordable and available
- Secure and reliable
To move towards this, governments use policy tools and charges to reshape the energy mix and fund necessary infrastructure.
Over time, various ‘carrots and sticks’ have led to headlines such as ‘First coal-free day in Britain’, ‘Greenest day in UK energy’, and ‘New record for wind-powered electricity in Britain’. These signal progress towards the goal of a fully decarbonised power system.
Governments are aiming for long-term results, expecting that as renewables infrastructure matures and low-carbon technologies scale, bills may come down. Political commitments include targets for clean power by 2030 and associated claims about reducing typical household bills. However, in the near term, pushing for a green transition and a more resilient system generally requires additional charges and investment.
The timeline for any sustained reduction in overall bills is uncertain. In the meantime, businesses need to understand the structure of NCCs and how they might manage or mitigate these costs.
Understanding NCCs
Broadly, NCCs can be grouped into three categories:
- Network costs: charges for using and maintaining the grid infrastructure.
- Green levies: policy costs to support investment in a cleaner, more secure energy system.
- Market fees and supplier costs: charges and margins that enable suppliers and market operators to function.
For illustration, a large electricity user’s non-commodity cost stack might break down roughly as:
- Network costs – around 15% of NCCs
- Green levies – around 60% of NCCs
- Market fees and supplier costs – around 25% of NCCs
Actual shares vary by site, region, tariff structure, and year, but this gives a sense of where the money goes.
Network costs – illustrative share c. 15% of NCCs
- DUoS (Distribution Use of System)
Recovers costs associated with installing, operating, and maintaining regional electricity distribution networks across Great Britain and related offshore connections. - TNUoS (Transmission Network Use of System)
Regionally set charges that recover the cost of building and maintaining the high-voltage transmission network across Great Britain. - BSUoS (Balancing Services Use of System)
Recovers the cost of balancing the electricity transmission system on a day-to-day basis. Since April 2023, BSUoS has been charged on a fixed-tariff basis for six-month periods, providing more predictability compared with the historical half-hourly variable approach.
Green levies – illustrative share c. 60% of NCCs
- AAHEDC (Assistance for Areas with High Electricity Distribution Costs)
Subsidises electricity distribution for customers in high-cost areas, primarily in Northern Scotland (including the Shetland region). - CCL (Climate Change Levy)
A tax on energy supplied to businesses and the public sector, designed to incentivise energy efficiency and lower-carbon operations. Partial or full relief can apply for certain sectors and agreements. - CfD (Contracts for Difference)
The UK’s primary funding mechanism for supporting low-carbon electricity generation. CfDs stabilise revenues by compensating generators when wholesale prices fall below a set ‘strike price’ and reclaiming funds when prices exceed it. - CM (Capacity Market)
Provides payments to generators, demand-side response providers, and certain storage assets that commit to being available during periods of peak demand, helping to ensure security of supply. - FIT (Feed-in Tariff)
A legacy scheme that supported small-scale renewable generation (such as rooftop solar) by providing fixed payments for generation and export to the grid. Closed to new applicants but still active for existing installations. - REGO (Renewable Energy Guarantees of Origin)
Certifies that a given amount of electricity has been generated from renewable sources. REGOs underpin some ‘green tariffs’ offered by suppliers. - RO (Renewables Obligation)
Requires suppliers to present a certain number of Renewables Obligation Certificates (ROCs) per MWh of electricity supplied each year, or make buyout payments. The scheme is closed to new generation but costs from existing projects continue to flow through bills.
Market fees and supplier costs – illustrative share c. 25% of NCCs
- Management Fee
Charged by suppliers to cover operational costs, risk management, and margin. - Other charges
Various fees related to metering, data services, industry governance, settlement, and other administrative functions.
Why NCCs are likely to rise
Several non-commodity cost elements are expected to increase in the coming years:
- The UK intends to procure many more gigawatts of renewables through future CfD allocation rounds.
- Long-duration electricity storage is being supported via mechanisms such as cap-and-floor regimes designed to encourage investment in flexibility.
- Support frameworks for Carbon Capture, Usage and Storage (CCUS) and low-carbon hydrogen are being introduced to decarbonise hard-to-abate sectors.
- As more intermittent generation (wind, solar) connects to the system, the cost and complexity of balancing the grid can increase.
Even if wholesale (commodity) prices fall, overall electricity bills may still rise over the medium term because of growing network and policy costs. Some projections indicate that bills for large power users could increase by around 20% over the next few years largely due to higher NCCs, though the exact impact will, of course, vary by user and tariff.
Because many of these costs are set by regulation, policy, and regulated network charges, they are largely outside individual businesses’ direct control. As a result, organisations are increasingly looking at how they can:
- Improve energy efficiency and reduce consumption.
- Participate in demand-side response or flexibility services.
- Invest in on-site generation (e.g. rooftop solar, CHP).
- Secure dedicated off-site generation, including private wire renewables.
One of the more structural approaches is the use of private wire arrangements to connect directly to dedicated renewable generation assets.
Avoiding NCCs behind the meter – the role of private wire
Private wire arrangements are one way to reduce exposure to some of the increase that’s expected to come from NCCs.
What is private wire?
Private wire connects a renewable generation site (for example, a solar or wind farm) directly to the user via a dedicated circuit, rather than routing the power solely through the public distribution or transmission network in the standard way. The site often retains a grid connection for backup and export, but a large proportion of consumption can be served “behind the meter”.
Because part of the electricity supply is no longer imported via standard grid tariffs, some non-commodity charges associated with grid usage can be reduced or avoided. The exact pattern of savings depends on how the project is structured, how much power is delivered via private wire, and what charges still apply to the residual grid-imported energy.
Potential cost savings
Industry estimates suggest that offsite renewables connected by private wire can, in suitable cases, be in the region of 20–30% cheaper than grid-imported electricity, primarily by reducing exposure to certain NCCs and by locking in long-term pricing. In some favourable circumstances and project structures, discounts in the 30–50% range compared with prevailing grid prices have been reported.
These figures are not guaranteed. Actual savings depend on:
- Technology and project costs (CAPEX, OPEX, financing).
- Load profile and how well generation matches demand.
- Contract length and risk allocation between parties.
- Future evolution of wholesale prices and NCCs.
Nonetheless, private wire is increasingly being used by large power users to seek more predictable and potentially lower long-term energy costs.
Long-term PPAs and cost visibility
Traditional supply contracts from the grid are typically short term – often one to three years. Off-site renewable projects via private wire generally involve longer-term commitments.
Long-term private wire Power Purchase Agreements (PPAs), sometimes called Renewable Energy Service Agreements (RESAs), can run for 10–20 years or more. They allow organisations (for example, data centres or large industrial sites) to:
- Fix or index energy pricing over long periods.
- Reduce exposure to short-term wholesale market volatility.
- Gain better visibility over their future energy cost base.
Long-term PPAs can be more cost-effective than relying purely on grid-imported electricity, and they provide clear traceability of the underlying energy mix, which can simplify and strengthen decarbonisation reporting compared with generic ‘green tariffs’.
System benefits and constraints
Private wire renewables can also lessen reliance on an already stressed power grid. Large users can meet a significant share of their demand from dedicated assets, and in some configurations surplus energy may be used for local heat networks or exported to the grid under agreed commercial and technical arrangements.
However, these projects are not without challenges. They typically require:
- Suitable land or roof space (for on-site or near-site generation).
- Appropriate planning and environmental consents.
- Grid connection arrangements for backup and export.
- Bankable counterparties and robust contractual frameworks.
Private wire tends to suit organisations with relatively stable, long-term loads and a willingness to commit to multi-year agreements.
When rooftop solar is not enough
For many facilities with high power demands, such as large manufacturing sites, logistics hubs, or data centres, rooftop solar alone cannot cover a meaningful proportion of annual consumption. Roof area can be a limiting factor, and load often exceeds what can be generated on-site.
Connecting one or more dedicated generation assets via private wire can provide a scalable solution:
- On-site or near-site solar can be sized beyond rooftop constraints using adjacent land.
- Wind, battery storage, or hybrid systems can be integrated where feasible.
- The combination of dedicated assets and long-term agreements can deliver both cost and carbon benefits.
Specialist private wire and renewable project developers can structure fully funded, turnkey solutions for large users. In such models, the developer finances, builds, owns, and operates the generation asset, while the customer commits to purchasing power over a long-term contract. For the customer, the business case is often driven by improved cost certainty and potential long-term savings versus remaining fully exposed to grid prices and rising NCCs.
It should also be recognised that private wire is not always the cheapest option in every case. For smaller loads, complex sites, or where planning or land are constrained, other strategies, such as efficiency, standard PPAs via the grid, or more conventional on-site generation, may be more appropriate.
Two paths forward
Whatever the next decade holds for the UK’s energy landscape, it is clear that significant investment will continue to be required in generation, networks, and flexibility. Until major, long-term upgrades are completed and the system fully adapts to a more electrified economy, it is difficult to be confident that energy bills will fall materially in the short term.
Broadly, large power users face two strategic directions:
Remain largely grid-exposed
Continue to rely predominantly on grid-based supply, managing costs mainly through procurement strategy, contract timing, and efficiency measures, while accepting ongoing exposure to the evolution of wholesale markets and NCCs.
Invest in structural alternatives
Combine energy efficiency, demand flexibility, on-site generation, and private-wire renewables to reduce reliance on standard grid-imported electricity and to improve long-term cost visibility.
Private wire renewables are not a universal solution, but they are an increasingly important option for organisations with large, stable demands and a long-term view. As part of a broader energy and decarbonisation strategy, they can offer a route to greater cost control, reduced exposure to rising non-commodity costs, and more transparent carbon reporting over the years ahead.
