Regulation & Market Terms
Key terms used across UK energy regulation, industry codes, and market mechanisms. A reference for Policy Compass users and energy professionals.
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The Office of Gas and Electricity Markets (ofgem.gov.uk). Great Britain's independent energy regulator, responsible for protecting consumers, setting price controls for network companies, enforcing licence conditions, and overseeing wholesale and retail energy markets. Governed by the Gas and Electricity Markets Authority (GEMA).
The UK government department responsible for energy policy, net zero strategy, and energy security (gov.uk). DESNZ sets the policy framework within which Ofgem regulates - including capacity market design, renewable support schemes, and net zero targets. Formerly part of BEIS, split out in February 2023.
The regulatory obligations attached to each type of energy licence (supply, generation, distribution, transmission). Licence conditions are set and enforced by Ofgem and cover areas including customer protection, market participation, data obligations, and regulatory reporting. Changes to licence conditions typically require consultation. Each licence type has its own numbered set of conditions.
A formal process by which Ofgem seeks stakeholder views before making regulatory decisions. Consultations set out proposals, evidence, and questions, with a defined response window (typically 6-12 weeks). Stakeholders submit written responses that Ofgem must consider before publishing a decision. Consultations cover licence changes, code modifications, price control decisions, and policy development.
A formal proposal to change the rules within an industry code (BSC, REC, DCUSA, CUSC, Grid Code, etc.). Modifications follow a defined governance process - raised by industry parties, assessed by workgroups, consulted on, and decided by the relevant code panel or Ofgem. Each code has its own modification process and naming convention.
The price at which energy is traded on wholesale markets before reaching end consumers. Influenced by global gas prices, renewable output, interconnector flows, and demand. Wholesale costs typically represent 30-40% of a retail electricity bill, though this varies significantly with market conditions.
A classification for larger business energy consumers, as distinct from domestic or microbusiness customers. I&C customers typically have half-hourly metering, higher consumption, and more complex contract structures. No formal regulatory definition exists - the threshold varies by supplier.
A regulatory classification defined by Ofgem. An energy customer is a microbusiness if they consume fewer than 100,000 kWh of electricity or 293,000 kWh of gas per year, OR employ fewer than 10 people and have annual turnover or balance sheet total under EUR 2 million. Microbusinesses receive additional regulatory protections similar to domestic customers.
A tax on energy supplied to non-domestic consumers, designed to incentivise energy efficiency and reduce carbon emissions. Charged per kWh on electricity and gas supplies. Exemptions and reduced rates are available through Climate Change Agreements (CCAs) for energy-intensive industries.
A certificate issued for each MWh of renewable electricity generated, used to evidence renewable sourcing. REGOs can be traded separately from the physical electricity, allowing suppliers to match their supply with renewable generation.
A tariff structure where the unit rate varies by time of day, day of week, or season - reflecting the actual cost of energy at different times. Requires half-hourly metering. Expected to become more widespread as MHHS rolls out, enabling suppliers to offer more granular price signals.
Ofgem's framework for setting price controls on network companies (DNOs, GDNs, and transmission operators). RIIO determines the allowed revenue each network company can earn over a price control period (typically 5 years), based on their expenditure plans, efficiency commitments, and output delivery. The current periods are RIIO-ED2 (electricity distribution, 2023-2028) and RIIO-3 (transmission and gas distribution, under development).
The fixed timeframe over which a network company's allowed revenue and performance targets are set under RIIO. Typically 5 years. Each period involves extensive consultation, business plan assessment, and determination by Ofgem. Network companies submit detailed business plans justifying their expenditure and output commitments.
The current electricity distribution price control period, running from April 2023 to March 2028. Sets allowed revenue, output targets, and incentive mechanisms for the 14 DNO licence areas. The next period, ED3, is under development with Ofgem currently consulting on the framework and methodology.
The upcoming price control period for electricity transmission and gas distribution, currently under development by Ofgem. RIIO-3 will set allowed revenue and output targets for transmission operators and gas distribution networks. Ofgem is consulting on the framework, methodology, and sector-specific considerations.
The combined capital expenditure (capex) and operational expenditure (opex) of a network company within a price control period. RIIO uses a totex-based approach to incentivise efficiency, removing the traditional bias towards capital spending by treating all expenditure equally. Underspend against totex allowances is shared between the company and consumers.
The value of a network company's regulated asset base, used to calculate its allowed return on capital. RAV is built up over time through capital investment (adjusted for depreciation) and forms the basis for the return component of allowed revenue. A higher RAV means higher allowed revenue.
A performance measure within RIIO that rewards or penalises network companies based on their delivery against specified outputs. ODIs cover areas like customer service, reliability, environmental impact, and connections. Financial ODIs adjust allowed revenue based on performance; reputational ODIs require public reporting.
The largest financial Output Delivery Incentive for electricity distribution network operators under RIIO. IIS rewards or penalises DNOs based on the number and duration of supply interruptions (CI - Customer Interruptions and CML - Customer Minutes Lost) against target levels. Targets are set based on historical performance and benchmarking.
A provision within RIIO price controls that allows allowed revenue to be adjusted during the price control period in response to specific uncertainties. Examples include volume drivers (adjusting for actual connection volumes), re-openers (for material changes in costs), and indexation (for input price changes). Designed to balance cost certainty for consumers with manageable risk for network companies.
The code manager and delivery body for the Balancing and Settlement Code (BSC). Elexon administers electricity settlement, manages the BSC modification process, and operates the settlement systems. Also responsible for delivering the MHHS programme.
The National Energy System Operator (neso.energy), established in October 2024 as the UK's independent system operator for electricity and (in future) gas. NESO took over system operation responsibilities from National Grid ESO. Responsible for real-time balancing of the electricity system, managing system services, and long-term network planning.
The industry code governing electricity balancing and settlement in Great Britain (full code). Defines the rules for how electricity is traded, imbalances are priced, and settlement is conducted. Administered by Elexon. BSC modifications (e.g. P462, P483) are proposed by industry parties and decided by Ofgem or the BSC Panel.
Example:
BSC P462 proposes removing subsidies from Balancing Mechanism bid prices to improve market efficiency.
The industry code governing retail energy market processes in Great Britain (retailenergycode.co.uk), including metering, data, switching, and change of supplier. Created in September 2021 by consolidating the Master Registration Agreement (MRA) and Supply Point Administration Agreement (SPAA). Managed by RECCo.
The multi-party contract between DNOs, IDNOs, suppliers, and generators governing connection to and use of electricity distribution networks (dcusa.co.uk). Covers distribution charging methodology, connection processes, and data exchange. DCUSA modifications (DCPs) are progressed through a formal governance process.
The industry code governing connection to and use of the electricity transmission system (NESO codes). Covers transmission charging methodology (TNUoS), connection agreements, and access arrangements. Administered by NESO. CUSC modifications (CMP proposals) are decided by Ofgem or the CUSC Panel.
The technical code specifying the requirements for connection to and operation of the electricity transmission system (NESO codes). Covers technical standards for generators, demand facilities, and distribution networks connecting to the grid. Grid Code modifications (GC proposals) are managed by NESO and decided by Ofgem.
The industry code governing the smart metering system, including the DCC's operations, data access, security, and technical standards. All parties accessing smart meter data or services through the DCC must be SEC parties. Administered by SECAS (Smart Energy Code Administrator and Secretariat).
The code governing the relationship between the system operator (NESO) and transmission owners (National Grid Electricity Transmission, SP Transmission, SSEN Transmission). Covers planning, operational coordination, and data exchange.
The licensed company responsible for operating and maintaining the local electricity distribution network in a specific geographic area. There are 14 DNO licence areas across Great Britain, owned by six corporate groups. DNOs are regulated by Ofgem under RIIO price controls.
A licensed operator of the regional gas distribution network that delivers gas from the National Transmission System to end consumers. There are 8 GDN licence areas across Great Britain, currently owned by four corporate groups (Cadent, SGN, NGN, Wales & West Utilities). Regulated by Ofgem under RIIO price controls.
A licensed operator of smaller, independent electricity distribution networks - typically serving new housing developments, business parks, or industrial estates. IDNOs are embedded within DNO networks and are regulated under the same framework, though at a different scale.
A licensed entity owning and maintaining the high-voltage electricity transmission network. In Great Britain, there are three onshore transmission owners: National Grid Electricity Transmission (England and Wales), SP Transmission (southern Scotland), and SSEN Transmission (northern Scotland). Regulated by Ofgem under RIIO price controls.
The licensed entity responsible for operating the smart metering communication infrastructure in Great Britain (smartdcc.co.uk). DCC provides the secure data network connecting smart meters to energy suppliers, network operators, and authorised third parties.
The process by which energy consumption is measured, allocated, and financially reconciled between market participants. Managed by Elexon under the Balancing and Settlement Code (BSC). Settlement determines how much each supplier owes for the energy their customers consumed in each half-hour period.
A major industry programme reforming how electricity consumption is settled. Under MHHS, all electricity meters - including domestic and small business - will be settled on a half-hourly basis using actual consumption data rather than estimated profiles. Managed by Elexon, with implementation progressing through a series of milestones. Aims to improve settlement accuracy, enable time-of-use tariffs, and support flexibility.
Metering that records energy consumption in 30-minute intervals, enabling precise settlement and time-of-use pricing. Mandatory for supply points with maximum demand above 100kW. Being extended to all meters under MHHS.
A classification (1-8) used to estimate the consumption pattern of non-half-hourly metered supply points. Profile Class 1 is domestic unrestricted; Classes 3-4 are non-domestic; Classes 5-8 are larger non-domestic with maximum demand metering. Being superseded by actual half-hourly data under MHHS.
A unique 13-digit reference number that identifies each electricity supply point in Great Britain. Found on electricity bills and used for switching, settlement, and data exchange. The MPAN structure encodes the distributor, line loss factor, meter timeswitch code, and profile class.
The gas equivalent of an MPAN. A unique reference number (typically 6-10 digits) identifying each gas supply point. Used for billing, supplier transfers, and gas transportation arrangements.
A code assigned to each electricity supply point that determines the estimated energy lost during distribution from the grid entry point to the meter. Higher-voltage connections have lower losses. LLFCs are used in settlement to adjust metered consumption and are assigned by the DNO.
A three-digit code identifying the type of time-switching capability of an electricity meter. Determines how consumption is split across time periods (e.g. day/night). Important for settlement and tariff application.
A four-digit code defining how a meter's registers map to settlement time periods. Used alongside MTC to determine how energy consumption is allocated across time-of-use periods for settlement and billing purposes.
The estimated total electricity consumption for a supply point over a year, measured in kWh. Used for non-half-hourly settled meters to allocate consumption for settlement and forecasting. Calculated from historical meter readings and adjusted periodically.
The gas equivalent of EAC. The estimated annual gas consumption for a supply point, measured in kWh. Used by gas transporters and shippers for capacity booking, demand forecasting, and settlement. Calculated from historical consumption and weather-corrected.
The price at which the system operator sells surplus energy to resolve imbalances in the electricity market. Part of the cash-out mechanism used in settlement. When the system is long (excess generation), the SSP applies to parties in imbalance.
The pattern of energy consumption over time for a supply point or portfolio. Load shapes are used for forecasting, settlement, and procurement. Half-hourly metering provides actual load shapes; non-half-hourly meters use estimated profiles.
A metering arrangement used for higher-demand supply points where direct measurement is impractical. Current transformers step down the current to measurable levels. Typically required for supplies above 70kVA. CT-metered sites are usually half-hourly settled.
A meter that automatically transmits readings at regular intervals (usually daily or monthly) via radio or mobile network. Common in I&C settings. Provides better data than manual reads but less granular than smart meters.
Smart Metering Equipment Technical Specifications. SMETS1 was the first-generation standard with limited interoperability between suppliers. SMETS2 is the current standard, communicating via the DCC network, fully interoperable across suppliers. SMETS1 meters are being enrolled into the DCC network to resolve legacy interoperability issues.
The party responsible for installing, maintaining, and operating electricity metering equipment. The MOP owns and maintains the physical meter; the MOA is the contractual agent appointed to manage meter operations. Appointed by the supplier or customer depending on the meter type.
Data Collectors retrieve consumption data from meters and validate it. Data Aggregators compile individual meter data into aggregated settlement runs for submission to Elexon. These roles are being reformed under MHHS as the settlement architecture changes.
Charges levied by DNOs for the use of the local distribution network. Structured as fixed charges (per MPAN), capacity charges (per kVA), and unit charges (per kWh, varying by time band). DUoS charging methodology is governed by DCUSA and regulated by Ofgem.
Charges for the use of the high-voltage transmission network, managed by NESO and the transmission owners. Charged to generators and demand customers. For half-hourly metered customers, demand TNUoS is based on consumption during Triad periods. The charging methodology is governed by CUSC.
Charges levied by NESO to recover the costs of balancing electricity supply and demand in real time. Includes the cost of activating the Balancing Mechanism, constraint management, and frequency response services. From April 2023, BSUoS is charged only to demand (not generation), following Ofgem's reform.
The three half-hour periods of highest system demand between November and February each year, separated by at least 10 days. Used to calculate TNUoS demand charges for half-hourly metered customers. Triad avoidance - reducing consumption during likely Triad periods - is a significant cost management strategy for large consumers.
Elements of an energy bill that the supplier passes directly from network operators, system costs, and policy levies without margin. Includes DUoS, TNUoS, BSUoS, capacity market charges, and environmental levies. Pass-through charges are not typically negotiable and represent a significant proportion of total energy costs.
All costs in an energy bill beyond the wholesale commodity price. Includes network charges (DUoS, TNUoS, BSUoS), environmental and social obligation levies (CCL, RO, FiT), capacity market charges, and supplier operational costs. Non-commodity costs represent over 60% of total electricity costs for many commercial consumers.
The high-pressure gas transmission network operated by National Gas Transmission (formerly part of National Grid). Transports gas from terminals, storage, and interconnectors to the Local Distribution Zones (LDZs) that serve end consumers.
A geographic area within the gas distribution network, each operated by a Gas Distribution Network (GDN). There are 13 LDZs across Great Britain. Gas transportation charges and capacity allocations are set at the LDZ level.
The maximum power (in kVA) that a supply point is authorised to import from the distribution network. Capacity charges are billed based on the MIC, regardless of actual usage. Exceeding MIC may trigger excess capacity charges. Changes to MIC require application to the DNO.
A charge based on the maximum capacity made available to a supply point, as distinct from the capacity actually used. Common in gas transportation and some electricity network charging structures. Reflects the network capacity reserved for the customer.
An Ofgem review examining how network costs are allocated and recovered from different customer groups. CARR considers the distribution of network charges between domestic and non-domestic customers, and between different voltage levels and demand profiles.
The process by which NESO balances electricity supply and demand in real time. Generators and demand-side participants submit bids (to reduce output or increase demand) and offers (to increase output or reduce demand). Operated under the Balancing and Settlement Code (BSC).
A mechanism run by DESNZ and delivered by NESO to ensure sufficient electricity generation and demand-side capacity is available to meet peak demand (gov.uk). Capacity providers bid in annual auctions (T-4 and T-1) and receive capacity payments in exchange for committing to deliver energy when called upon during system stress events.
A percentage applied to an asset's capacity to reflect its expected availability during system stress events. Used in capacity market auctions to determine the capacity credit each technology type receives. Battery storage de-rating factors are based on duration - a 1-hour battery receives a lower de-rating factor than a 4-hour battery.
The process by which capacity providers demonstrate their eligibility to participate in capacity market auctions. Includes technical assessment, metering requirements, and confirmation of deliverable capacity. Prequalification windows open annually ahead of T-4 and T-1 auctions.
The adjustment of electricity consumption in response to price signals, system needs, or contractual obligations. Includes load shifting (moving consumption to different times), load shedding (reducing consumption temporarily), and on-site generation. A key component of system flexibility.
A NESO service paying consumers and businesses to reduce electricity consumption during periods of tight supply. Participants are paid for verified demand reduction below a baseline. Introduced in winter 2022-23 as a tool for managing system stress without resorting to emergency measures.
An entity that combines the flexible capacity of multiple smaller assets (batteries, EVs, heat pumps, industrial loads) into a single portfolio that can participate in wholesale and balancing markets. Aggregators enable smaller assets to access revenue streams that would otherwise require minimum volume thresholds.
A network of distributed energy resources - batteries, solar, wind, flexible demand - coordinated by software to operate as a single power plant. VPPs can participate in wholesale markets, provide balancing services, and respond to grid constraints as a unified portfolio.
A fast-acting frequency response service procured by NESO. Providers must deliver full response within 1 second of a frequency deviation and sustain it for at least 15 minutes. Procured through daily auctions. One of the post-reform frequency response products that replaced the older Firm Frequency Response (FFR) service.
A NESO frequency response service operating in the moderate frequency deviation range. Slower-acting than Dynamic Containment, with a 1-second response requirement. Designed to manage frequency deviations that are significant but not at the extreme end of the spectrum.
A NESO frequency response service for continuous, small frequency corrections during normal system operation. Providers deliver proportional response to ongoing frequency deviations, helping maintain system frequency close to 50Hz during normal conditions.
The practice of generating income from a single flexible asset across multiple market opportunities - for example, combining capacity market payments, balancing mechanism participation, and distribution flexibility services. Revenue stacking is key to the commercial viability of battery storage and other flexible assets.
Technology enabling electric vehicles to export stored energy back to the grid, effectively using the vehicle battery as a distributed energy storage asset. V2G can provide flexibility services, reduce peak demand, and generate revenue for vehicle owners through balancing and frequency response markets.
An entity that offers flexibility services to system operators (NESO or DNOs) - either from its own assets or by aggregating third-party assets. FSPs may participate in balancing services, local constraint management, capacity market, or distribution-level flexibility procurement.
A new licence type introduced under the Energy Act 2023, required for organisations that remotely control domestic smart appliances for demand-side response. Designed to protect consumers while enabling automated flexibility services. Licensees must meet obligations around cybersecurity, data protection, and consumer consent.
A BSI Publicly Available Specification defining the energy smart appliance requirements for demand-side response. Sets out the technical standards that appliances must meet to participate in automated DSR, including communication protocols, cybersecurity, and interoperability requirements.
A BSC modification to align the Balancing and Settlement Code with the Energy Smart Appliance (ESA) regulatory framework. P483 creates the code framework for the Load Control Licence regime, enabling automated DSR at scale while maintaining settlement accuracy and consumer protection.
A framework developed by the National Cyber Security Centre (NCSC) and applied to operators of essential services. Under the ESA framework, Load Control Licence holders must comply with CAF requirements to ensure that remote control of smart appliances does not create systemic cybersecurity risks.
The foundational configuration in Policy Compass that captures your organisation's regulatory context. The information collected varies by profile type - a supplier profile captures licence type, customer segments, and code obligations, while a consultancy profile maps client portfolios, and a flexibility provider profile covers market participation and service types. Every answer, alert, and deadline in Policy Compass is contextualised through your business profile. Set up during onboarding and adjustable as your business evolves.
Policy Compass's proactive monitoring feature. Radar continuously watches regulatory bodies and industry code panels for new publications, consultations, and code modifications relevant to your business profile. When something lands that affects your business, Radar flags it - with deadlines automatically extracted to your calendar.
The set of regulatory bodies, industry codes, and publication sources mapped to your business profile in Policy Compass. Your landscape is automatically configured based on your business type and can be adjusted manually. It determines which sources Policy Radar monitors and which authorities Policy Compass draws from when researching answers.
Adaptive research methodologies within Policy Compass that automatically adjust based on the type of question asked. A deadline question triggers different research steps than a consultation analysis or a cross-code comparison. Specialist workflows ensure the right sources are consulted in the right order for each question type.
The complete citation chain attached to every Policy Compass answer. Each claim references its authoritative source - Ofgem decisions, code panel publications, DESNZ consultations - with direct links. Evidence trails are preserved in PDF exports, providing audit-ready documentation for board papers, consultation responses, and regulatory submissions.
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