Non-Commodity

Power

A regional adjustment scheme that reduces electricity distribution charges for consumers in the north of Scotland. Funded by a levy on all GB electricity users, AAHEDC spreads the cost of maintaining the network in sparsely populated areas across all distribution regions.
Funds the cost for National Grid ESO to balance electricity supply and demand in real time, including constraint management and frequency control. Tariffs are fixed seasonally in advance but influenced by past under- or over-recovery, making BSUoS a volatile and rising cost driven by wind intermittency and system congestion.
Funds the administrative and operational costs of running the Capacity Market scheme, which secures reliable electricity supply during peak winter demand. It is separate from the supplier obligation levy that funds capacity provider payments.
Pays for the actual capacity payments to generators and demand-side providers that secure delivery under Capacity Market contracts. Charged on supplier consumption during winter weekday peaks (Nov–Feb, 4–7pm), it fluctuates with auction results and market clearing prices.
Funds payments to generators and demand-side providers that commit to being available during winter peak periods (Nov–Feb, 4–7pm). The charge varies year to year depending on auction outcomes and clearing prices, and can be mitigated by reducing or shifting consumption outside of chargeable periods.
A government-imposed tax on electricity and gas supplied to business users, aimed at incentivising energy efficiency and emissions reduction. The rate is set annually by HM Treasury and applies unless an exemption (e.g. Climate Change Agreement) is in place.
Suppliers fund top-up payments to low-carbon generators (e.g. offshore wind) whose guaranteed strike price exceeds the wholesale market price. Costs are calculated daily and billed retrospectively based on actual output, making this a growing and sometimes volatile cost as more projects begin operation.
Funds the administrative costs of the Low Carbon Contracts Company (LCCC), which operates the CfD scheme. This is a smaller, fixed-rate levy that supports scheme infrastructure rather than generator payments.
Recovers the cost of top-up payments made to low-carbon generators under CfD contracts. If wholesale prices fall below the generator’s strike price, suppliers pay the difference. This is a material and growing non-commodity cost.
Covers the cost of collecting and processing half-hourly and non-half-hourly consumption data from customer meters. This function supports accurate settlement and is typically charged per MPAN.
An uplift added to metered volumes to account for electricity lost as heat in local networks. Varies by time of day, season, voltage level, and location. Influences commodity, DUoS, and policy cost calculations.
Item Covers the cost of delivering electricity from the transmission system to homes and businesses via regional distribution networks. Charges vary by location, voltage level, and customer type, and are set by Distribution Network Operators under Ofgem regulation. DUoS is typically the largest non-energy cost on a business electricity bill.
A suite of charges levied by Distribution Network Operators to recover costs for operating the local distribution networks.
• Capacity charges are based on agreed maximum demand (kVA).
• Excess Capacity applies when usage exceeds agreed limits.
• Fixed charges apply per MPAN.
• Timeband charges (Green, Amber, Red, Super Red) vary by time of day and region.
• Reactive Power charges apply if the site’s power factor is poor (below 0.95).
Impact: DUoS is typically the largest non-energy cost and varies heavily by region and profile.
A new supplier charge introduced to reimburse Energy Intensive Industries for 60% of their network charges (DUoS, TNUoS, BSUoS). The levy is based on actual network costs and will grow as these underlying charges increase, passing more cost onto non-exempt customers.
Recover the cost of operating the Balancing and Settlement Code (BSC), managed by Elexon.
• Fixed Charge: Set per meter or account.
• Variable Charge: Proportional to consumption.
These charges support the smooth functioning of energy market settlement processes.
Credited to distributed generators for exporting to the grid during TRIAD periods (winter peak demand). This payment helps offset grid constraint costs and incentivises local generation.
A historic subsidy scheme that funded small-scale renewable generators such as rooftop solar. While closed to new entrants since 2019, ongoing payments to existing installations are recouped from suppliers based on market share. Although relatively small, the cost is still present and indexed to inflation.
Charged to suppliers when their contracted energy volumes differ from actual demand. Reflects the cost of balancing incurred by ESO to match supply and demand. Calculated after the delivery period and reconciled through settlement.
Introduced in April 2023 to simplify transmission charging. Applies a fixed charge based on voltage level and agreed import capacity (kVA), replacing TRIAD for most users. Easier to forecast and manage but may change bill profiles.
An upcoming levy designed to fund construction and operation of the Sizewell C nuclear plant through fixed payments from suppliers. Unlike CfDs, costs begin before the plant is generating electricity, making this a significant future addition to non-commodity costs once the project reaches financial close.
A settlement adjustment within the electricity imbalance regime that redistributes over- or under-recovered imbalance cashflows across market participants. Can result in a credit or debit to suppliers.
A legacy scheme that requires suppliers to support large-scale renewable generators by either presenting ROCs (Renewables Obligation Certificates) or paying a buy-out fee. The cost is set annually based on policy targets and inflation, and remains one of the largest non-energy costs on electricity bills until the scheme winds down in the 2030s.
Pays for the use, maintenance, and expansion of the national electricity transmission system. Costs are largely recovered via a fixed daily charge based on customer size and location, with some regional variation. TNUoS is expected to increase significantly from 2026 due to rising infrastructure investment under the RIIO-T3 price control.
Legacy charges based on average demand during the three highest winter peak periods.
• HH (Half-Hourly): Applies to large users with smart metering.
• NHH (Non-Half-Hourly): Applies to smaller users.
These charges are gradually being replaced by banded TNUoS mechanisms.
An uplift to account for energy lost in transmission lines between generators and distribution entry points. These losses are averaged nationally and applied to metered volumes for certain charge calculations and energy trading.

Gas

A tax on business gas usage aimed at driving down emissions and encouraging energy efficiency.
Funds the UK Government’s Green Gas Support Scheme, encouraging biomethane injection into the grid. Charged either per meter or per unit of consumption, this is a growing environmental levy on suppliers.
Recovers the cost of transporting gas within the Local Distribution Zone (LDZ), based on a site’s peak daily consumption (SOQ). The larger the capacity, the higher the fixed cost.
An adjustment applied to large sites (over 732,000 kWh/year), scaling capacity charges according to demand. Helps reflect the disproportionate system impact of large users.
A modifier for large users, adjusting commodity charges to better align with actual system use and infrastructure costs.
A non-linear scaling factor applied to the capacity calculation for large sites. Encourages efficient use of capacity by increasing marginal cost with higher demand.
A volume-based charge applied to each kWh of gas consumed within the LDZ. Recovers operational costs of maintaining local gas networks and is influenced by regional factors.
Ensures a minimum contribution to system costs from large sites, regardless of calculated usage. Prevents disproportionately low charges from highly efficient or low-usage large meters.
A flat-rate charge levied by National Grid to recover a share of system costs not captured by capacity or commodity elements. Applied per supply point.
A reconciliatory charge ensuring National Grid recovers the total allowed revenue under its transmission licence. Applied if other charges (commodity and capacity) fall short, often fluctuates year-on-year.
A per-meter charge to recover admin and metering infrastructure costs. Differentiated by read frequency — monthly reads typically apply to larger, daily-metered sites.
Covers the cost of transferring customers from failed gas suppliers. These costs are socialised across suppliers and split between domestic and industrial/commercial users.
Similar to the standard LDZ capacity charge but recovered under a customer-specific framework (CCA). Based on a site’s SOQ, it recovers cost from very large consumers directly.
Applies a scaling adjustment to the above charge for sites with demand exceeding 732,000 kWh/year.
Used to add a non-linear component to large-site customer capacity charges. Supports fair and efficient network cost allocation.
A non-linear element applied to the commodity charge formula for high-usage sites. It increases proportionality and helps maintain fair cost distribution.
Sets a floor for commodity cost recovery from large sites, ensuring they contribute a minimum amount even if usage patterns are highly efficient.
A regional capacity-based charge reflecting the cost of transporting gas from the NTS exit point into the LDZ. Based on SOQ and similar in design to NGT Exit Capacity but applied at LDZ level.
A fixed charge covering the provision and maintenance of the physical gas meter and associated infrastructure. Often included in supplier contracts but occasionally itemised.
A usage-based charge applied per kWh of gas consumed. It recovers the operational cost of transporting gas across the National Transmission System (NTS). Charged on all throughput, regardless of location.
Paid by shippers injecting gas into the transmission system, this capacity charge funds the infrastructure that enables gas to enter the NTS at terminals. While not paid by consumers directly, it influences wholesale gas pricing.
A capacity-based charge that recovers the cost of transporting gas to end-users via the NTS. Based on a site’s peak demand (SOQ), this fixed annual cost secures the right to draw gas from the transmission network each day.
A penalty charge applied when a daily metered site exceeds its pre-agreed SOQ, reflecting additional system strain and risk. Encourages accurate forecasting and load management.
A charge applied for the manual or automated reading of gas meters. Higher frequency reads may attract higher costs but improve billing accuracy.
Recovers the cost of gas lost or unaccounted for within the distribution network (known as AUG). Managed by Xoserve and allocated to suppliers based on deemed responsibility.