Metering
How electricity meters are identified and classified in the UK energy market.
MPAN (Meter Point Administration Number)
Definition: A unique 21 or 22-digit reference number that identifies every electricity meter in Great Britain, similar to how a postcode identifies a specific address.
Every electricity supply point in Great Britain has its own MPAN - think of it as your meter's unique fingerprint. You'll find this number on your electricity bill, usually in a distinctive grid format.
The MPAN isn't just a random string of numbers. Each section contains specific information: which regional network operator supplies you, what type of customer you are (domestic or business), and crucially, which tariff category applies to your supply. The last digit is a "check digit" that helps catch any typing errors.
**MPAN Structure:**
- **Profile Class** (2 digits): Your customer type (01-02 domestic, 03-08 non-domestic, 00 for MHHS migrated)
- **MTC/SSC** (3-4 digits): Meter Timeswitch Code or Standard Settlement Configuration
- **LLFC** (3 characters): Line Loss Factor Class - the key link to your tariff
- **Distributor ID** (2 digits): Which of the 14 regional DNOs supplies you
- **Unique ID** (8 digits): Your meter's unique reference number
- **Check Digit** (1 digit): Validates the MPAN is entered correctly
For businesses checking their bills, the most important part is the LLFC code embedded within the MPAN - this three-character code determines exactly which tariff rates you should be charged. If this code is wrong, you could be paying the wrong rates entirely.
Example: 03 801 100 10 12345678 901
Related Terms: DNO, LLFC, Profile Class, Check Digit, Distributor ID
Site
Definition: A single physical location, such as a factory, office, or substation, that can hold one or more MPANs: an import MPAN, an export MPAN, or both.
A site is the physical place where power is taken from, or fed back into, the network. It is not the same thing as an MPAN: the MPAN identifies a specific supply point, and one site can hold several MPANs.
Most sites have a single import MPAN, covering the power they draw from the grid. A site with its own generation, such as solar panels or a battery, can also hold an export MPAN for the power it feeds back. Larger EHV (Extra High Voltage) sites often have both, and each is charged on its own terms: import charges on the import MPAN, and a mix of charges and credits on the export MPAN.
This is why the EHV Site Tariffs tool is organised by site rather than by MPAN. A single EHV connection can carry both an import and an export leg, so we surface the rates for each.
Example: An EHV factory with rooftop solar holds an import MPAN for what it consumes and an export MPAN for what it generates, both at the one site.
Related Terms: MPAN, EDCM
Profile Class
Definition: A two-digit code on your MPAN that tells suppliers what type of customer you are and how your electricity usage is estimated.
Profile Classes range from 00 to 08 and help energy companies understand your typical usage patterns. Domestic customers are usually Profile Class 01 (standard) or 02 (with electric heating like storage heaters). Small businesses typically fall into 03 or 04, while larger commercial premises with more complex usage patterns use 05 through 08.
This matters because, historically, most meters only recorded total usage - not when you used electricity. Profile Classes allowed suppliers to estimate your half-hourly consumption based on typical patterns for your customer type. A shop (Profile Class 03) has very different usage patterns to a factory running night shifts (Profile Class 05-08).
**Profile Classes:**
| Class | Type | Description |
|-------|------|-------------|
| 00 | Half-Hourly Metered | MHHS migrated meters with actual HH data |
| 01 | Domestic Unrestricted | Standard single-rate residential supply |
| 02 | Domestic Economy 7 | Multi-rate residential (day/night tariffs) |
| 03 | Non-Domestic Unrestricted | Single-rate business supply |
| 04 | Non-Domestic Economy 7 | Multi-rate business supply |
| 05 | Non-Domestic MD (<20% LF) | Low load factor commercial |
| 06 | Non-Domestic MD (20-30% LF) | Medium-low load factor |
| 07 | Non-Domestic MD (30-40% LF) | Medium load factor |
| 08 | Non-Domestic MD (>40% LF) | High load factor (factories, data centres) |
Profile Class 00 is special - it indicates your meter has been migrated to the new Market-wide Half-Hourly Settlement system, where actual readings replace these estimates.
Example: Profile Class 03 = Non-domestic unrestricted (typical office or retail)
Related Terms: MPAN, MHHS, Time Bands
Check Digit
Definition: The final digit of an MPAN that acts as an error-detection tool - if you type the number incorrectly, the check digit won't match, alerting you to the mistake.
The check digit is a clever mathematical safeguard built into every MPAN. It's calculated using a specific formula applied to the preceding digits. When you enter an MPAN into a system, it recalculates this digit - if it doesn't match, you've made a typo somewhere.
This might seem like a small detail, but in an industry where incorrect meter numbers can lead to bills going to the wrong customer or consumption being misallocated, it's an important line of defence. The calculation uses a series of prime numbers as multipliers, making it highly effective at catching common errors like transposed digits.
**How it works:**
The check digit validates the "MPAN Core" - the last 13 digits of the full MPAN. Each of the first 12 digits is multiplied by a prime number weight: [3, 5, 7, 13, 17, 19, 23, 29, 31, 37, 41, 43]. The products are summed, and the formula (sum % 11) % 10 produces the check digit.
For most users, you don't need to understand the maths - just know that if a system rejects your MPAN, double-check you've entered all the digits correctly.
Example: MPAN Core 1012345678809: The check digit 9 is calculated from the preceding 12 digits using prime weights
Related Terms: MPAN, Distributor ID
Meter Timeswitch Code (MTC)
Definition: A three-digit code in legacy MPANs that identifies your meter's time-switching capability and configuration - whether it can record usage at different rates for different times of day.
The Meter Timeswitch Code (MTC) is a three-digit field found in positions 3-5 of legacy 21-digit MPANs. It describes the metering equipment's ability to switch between different registers based on time of day, enabling multi-rate tariffs like Economy 7.
**Key facts about MTC:**
**Position in MPAN:**
- Legacy MPANs (21 digits): Positions 3-5 (after Profile Class)
- MHHS MPANs (22 digits): Replaced by SSC (Standard Settlement Configuration)
**What MTC tells you:**
- Whether the meter has time-switching capability
- Number of registers (single-rate vs multi-rate)
- Settlement timing information
- Compatibility with time-of-use tariffs
**Common MTC values:**
- **000** - No time-switching capability
- **100** - Standard unrestricted meter
- **845** - Common for Profile Class 03 (non-domestic unrestricted)
- **070** - Economy 7 variant for domestic customers
**Important limitation:**
MTC codes are DNO-specific - the same MTC can mean different things in different regions. This is one reason why MHHS replaces MTC with the standardised SSC code.
Example: MTC 845 in MPAN 03 845 100 10 12345678 901 indicates a non-domestic meter configuration
Related Terms: MPAN, Profile Class, LLFC, SSC, Half-Hourly Metered
Standard Settlement Configuration (SSC)
Definition: A four-digit code in MHHS-format MPANs that replaces the legacy Meter Timeswitch Code, providing a standardised way to identify how consumption data is processed for settlement.
The Standard Settlement Configuration (SSC) is a four-digit field found in positions 3-6 of the newer 22-digit MHHS-format MPANs. It replaces the legacy three-digit MTC (Meter Timeswitch Code) and provides a nationally standardised settlement configuration.
**Key facts about SSC:**
**Position in MPAN:**
- MHHS MPANs (22 digits): Positions 3-6 (four digits, after Profile Class)
- Legacy MPANs (21 digits): Not present (use MTC instead)
**Why SSC was introduced:**
- Legacy MTCs were DNO-specific and inconsistent
- SSC provides industry-wide standardisation
- Supports the Market-wide Half-Hourly Settlement (MHHS) reforms
- Removes regional ambiguity in settlement processing
**SSC values:**
- **0000** - Default/not applicable (common during transition)
- Other four-digit codes map to specific settlement rules defined by Elexon
**Relationship to MPAN length:**
The extra digit in SSC (4 vs MTC's 3) is why MHHS MPANs are 22 digits instead of 21.
**Impact on EnergyCode:**
SSC is captured when parsing MHHS-format MPANs but doesn't directly affect DUoS tariff determination - that's still handled by the LLFC.
Example: SSC 0393 in MPAN 00 0393 100 10 12345678 901 indicates a 7-hour Economy 7 meter configuration with two registers
Related Terms: MPAN, MTC, MHHS, Profile Class, Half-Hourly Metered, TPR
Time Pattern Regime (TPR)
Definition: A five-digit code that defines exactly which half-hourly settlement periods a meter register records - the granular timing rules behind multi-rate tariffs like Economy 7.
Time Pattern Regimes (TPRs) are the detailed timing rules that specify which half-hours of the day each meter register captures. Every SSC (Standard Settlement Configuration) links to one or more TPRs, which together define how a meter's consumption is split across different time periods for billing.
**Why TPRs matter:**
For multi-rate tariffs like Economy 7, TPRs define exactly when "night" and "day" rates apply. While you might think "night rate = midnight to 7am", the actual switching times vary and are precisely defined by the TPR code.
**How TPRs work:**
Each day has 48 settlement periods (00:00-00:30 is period 1, 00:30-01:00 is period 2, etc.). A TPR specifies which periods belong to each register:
| Example TPR | Description | Settlement Periods |
|-------------|-------------|-------------------|
| TPR 00210 | Day register | Periods 15-46 (07:00-23:00) |
| TPR 00211 | Night register | Periods 1-14, 47-48 (23:00-07:00) |
**Clock vs Switch TPRs:**
- **Clock TPRs (Type C)**: Fixed times that don't change seasonally
- **Teleswitch TPRs (Type S)**: Radio-controlled switching that can vary
**Relationship to SSC:**
Each SSC links to 1-6 TPRs. For example:
- SSC 0393 (7-hour E7): Links to 2 TPRs (day and night)
- SSC 0144 (6-rate SToD): Links to 6 TPRs (seasonal time-of-day rates)
**Finding TPR data:**
TPR definitions are maintained in Elexon's Market Domain Data (MDD). EnergyCode provides TPR reference data through the MHHS Reference feature and Enterprise API.
Example: SSC 0393 links to TPR 00210 (day: 07:00-23:00) and TPR 00211 (night: 23:00-07:00)
Related Terms: SSC, MHHS, Half-Hourly Metered, MTC, Settlement Period
MPAN Core
Definition: The last 13 digits of any MPAN that uniquely identify a meter point - this is the part validated by the check digit and used in most industry systems.
The MPAN Core is the final 13 digits of any full MPAN, regardless of whether it's a 21-digit legacy format or 22-digit MHHS format. It's the critical identifier used in settlement systems and data flows across the energy industry.
**Structure of the MPAN Core (13 digits):**
| Component | Digits | Description |
|-----------|--------|-------------|
| Distributor ID | 2 | DNO (10-23) or IDNO (24+) identifier |
| Unique Identifier | 8 | Meter point's unique reference within the network |
| Extended Identifier | 2 | Additional identification digits |
| Check Digit | 1 | Validation digit (prime weights calculation) |
**Why the MPAN Core matters:**
**Industry data flows:**
Most industry systems (supplier switching, settlement, meter registration) use only the 13-digit MPAN Core, not the full 21/22-digit MPAN with supplementary data.
**Check digit validation:**
The single check digit at the end validates only the MPAN Core. It's calculated using the first 12 digits with prime weights [3, 5, 7, 13, 17, 19, 23, 29, 31, 37, 41, 43] and the formula (sum % 11) % 10.
**Consistent across formats:**
Whether you have a legacy 21-digit or MHHS 22-digit MPAN, the last 13 digits are always the MPAN Core.
**Common misconception:**
Many people think the "last 3 digits" are all check digits - in fact, only the FINAL digit is a check digit. The previous 2 digits are part of the extended identifier.
Example: Full MPAN: 03 801 100 10 12345678 901 | MPAN Core: 1012345678901 (last 13 digits)
Related Terms: MPAN, Check Digit, Distributor ID, MHHS
Distributor ID
Definition: A two-digit code (10-23) within your MPAN that identifies which of the 14 regional electricity network operators manages your supply.
Great Britain's electricity distribution network is divided into 14 geographic regions, each operated by a Distribution Network Operator (DNO). The Distributor ID tells you which region your supply falls within - this matters because each DNO sets its own distribution charges.
**The 14 DNO regions:**
| ID | DNO Name | Operator | Area Covered |
|----|----------|----------|--------------|
| 10 | Eastern Power Networks | UKPN | East Anglia, Essex |
| 11 | East Midlands | NGED | Lincolnshire, Nottinghamshire |
| 12 | London Power Networks | UKPN | Greater London |
| 13 | SP Manweb | SPEN | Merseyside, North Wales |
| 14 | West Midlands | NGED | Birmingham, Staffordshire |
| 15 | Northern Powergrid (NE) | NPg | Northumberland, Durham |
| 16 | Electricity North West | ENWL | Greater Manchester, Lancashire |
| 17 | Scottish Hydro (SHEPD) | SSEN | Scottish Highlands, Islands |
| 18 | SP Distribution | SPEN | Central Scotland |
| 19 | South Eastern Power Networks | UKPN | Kent, Sussex, Surrey |
| 20 | Southern Electric (SEPD) | SSEN | Hampshire, Berkshire |
| 21 | South Wales | NGED | South Wales |
| 22 | South West | NGED | Cornwall, Devon, Somerset |
| 23 | Northern Powergrid (Yorkshire) | NPg | Yorkshire, Humberside |
**Operator Groups:** UKPN (10, 12, 19), NGED (11, 14, 21, 22), SPEN (13, 18), NPg (15, 23), ENWL (16), SSEN (17, 20)
If you see a Distributor ID of 24 or higher, your supply is on a private network managed by an Independent Distribution Network Operator (IDNO) - typically found on newer housing developments or business parks.
Example: Distributor ID 12 = London Power Networks (UKPN)
Related Terms: DNO, IDNO, MPAN, DUoS
22-Digit MPAN
Definition: The MHHS-era electricity supply number format, where the legacy 3-digit Meter Timeswitch Code becomes the 4-digit Standard Settlement Configuration, taking the full MPAN from 21 to 22 digits.
Under Market-wide Half-Hourly Settlement, the electricity supply number (MPAN) moves from 21 digits to 22 digits. The change was introduced at MHHS go-live on 22 September 2025 under REC Change Proposal R0083.
**What actually changed:**
The extra digit comes from one field. The legacy 3-digit Meter Timeswitch Code (MTC) is replaced by the 4-digit Standard Settlement Configuration (SSC). The other fields keep their position and length; the 3-character LLFC keeps its value but is renamed the DUoS Tariff ID.
| Field | Legacy (21-digit) | MHHS (22-digit) |
|-------|-------------------|-----------------|
| Configuration | MTC (3 digits) | SSC (4 digits) |
| Profile Class | 2 digits | 2 digits |
| LLFC | 3 characters | 3 characters (now also called DUoS Tariff ID) |
| Distributor ID | 2 digits | 2 digits |
| MPAN Core | last 13 digits | last 13 digits (unchanged) |
**Important:** the MPAN Core (the last 13 digits used across most industry systems) and its check digit are not affected. Only the top-line configuration field grows.
**Why it matters for systems:**
During the transition, both formats are live at the same time. Any system that validates or parses MPANs needs to accept 21 and 22-digit supply numbers, and recognise that a migrated meter shows Profile Class 00 with a 4-digit SSC.
Example: Legacy: 03 845 100 10 12345678 901 (21 digits) becomes MHHS: 00 0393 100 10 12345678 901 (22 digits)
Related Terms: MPAN, SSC, MTC, MHHS, MPAN Core
SSC vs MTC
Definition: A side-by-side of the legacy Meter Timeswitch Code and the MHHS Standard Settlement Configuration: both describe a meter's register and time-switching setup, but the SSC is nationally standardised and four digits.
Both the Meter Timeswitch Code (MTC) and the Standard Settlement Configuration (SSC) describe how a meter is configured: how many registers it has and which time periods each register records. The MTC is the legacy field; the SSC is its MHHS replacement.
**The key differences:**
| | MTC (legacy) | SSC (MHHS) |
|--|--------------|------------|
| Length | 3 digits | 4 digits |
| Position in MPAN | 3 to 5 of 21 | 3 to 6 of 22 |
| Scope | DNO-specific (same code can differ by region) | Nationally standardised |
| Source | Frozen in MDD | REC Portal (enduring) |
| Linked timing rules | TPRs | TPRs |
**Why the move was made:**
The biggest weakness of the MTC was that it was DNO-specific: the same code could mean different things in different regions, which made validation and migration harder. The SSC removes that ambiguity with a single national set of configurations. Both still link to one or more Time Pattern Regimes (TPRs), which define the exact half-hours each register captures.
**During the transition:**
Legacy meters keep MTC-based configuration until they migrate. Migrated smart meters typically take SSC 0000. There is no single published crosswalk mapping every MTC to its SSC, so systems running both formats must hold each set of reference data.
Example: MTC 845 (3-digit, DNO-specific) maps conceptually to an SSC such as 0393 (4-digit, national) for an equivalent configuration
Related Terms: MTC, SSC, TPR, MPAN, 22-Digit MPAN
Measurement Class
Definition: A single-letter code (A to G) that classifies how a meter is measured and settled, sitting alongside the Profile Class. Under MHHS, meters are also organised into three settlement segments: Smart, Advanced, and Unmetered.
Measurement Class is a letter (A to G) that tells the industry how a supply is metered and settled. It sits alongside the Profile Class in settlement data.
**The classes (A to G):**
| Class | Meaning |
|-------|---------|
| A | Non-half-hourly metered |
| B | Non-half-hourly unmetered supplies |
| C | Half-hourly metered, 100 kW and above |
| D | Half-hourly unmetered supplies |
| E | Half-hourly, under 100 kW, CT metered |
| F | Half-hourly, under 100 kW, domestic (smart / MHHS) |
| G | Half-hourly, under 100 kW, non-domestic whole-current (smart / MHHS) |
**What MHHS changes:**
MHHS does not abolish the Measurement Class field, but it organises meters into three settlement segments for data services, cutting across the old half-hourly versus non-half-hourly split:
| MHHS segment | Covers |
|--------------|--------|
| Smart | Smart and traditional meters at consumer and small-business level |
| Advanced | AMR and CT-metered supplies, typically larger or more complex sites |
| Unmetered | Street lighting, traffic signals and similar |
**A note on terminology:**
These MHHS settlement segments are different from the import or export market segment (Domestic, Non-Domestic, Generation, Unmetered) that the LLFC encodes for charging. One describes how a meter is settled; the other describes what kind of supply it is for charging purposes.
Related Terms: MHHS, Half-Hourly Metered, Market Segment, Profile Class
Network Charges
The various charges applied for using electricity distribution and transmission networks.
DUoS (Distribution Use of System)
Definition: The charges you pay for using your local electricity distribution network - typically 15-20% of your total electricity bill.
DUoS charges pay for the maintenance, operation, and development of the local electricity cables, substations, and equipment that deliver power to your premises. These are the networks run by the 14 regional DNOs, and each region has different rates based on their specific costs.
Your DUoS bill has several components:
- **Unit rates** vary by time of day - Red (peak, most expensive), Amber (daytime), and Green (nights and weekends, cheapest)
- **Fixed charges** - a daily standing charge per meter
- **Capacity charges** - for larger supplies, based on your agreed maximum demand in kVA
- **Reactive power charges** - if your electrical equipment isn't operating efficiently
These charges are passed through by your energy supplier and appear on your bill, though they may be bundled into your overall unit rate rather than shown separately. Understanding DUoS is key to identifying billing errors, as the wrong tariff category can significantly affect what you pay.
**Common billing errors:**
- Wrong LLFC-to-tariff mapping (most common)
- Incorrect time band allocation (kWh in wrong Red/Amber/Green bucket)
- Outdated rates after April tariff changes
- Incorrect capacity band applied
Example: Red Rate: 15.50 p/kWh, Amber Rate: 2.80 p/kWh, Green Rate: 0.35 p/kWh
Related Terms: DNO, TNUoS, Time Bands, LLFC, Capacity Charges
TNUoS (Transmission Network Use of System)
Definition: Charges for using the national high-voltage transmission network that carries electricity across the country before it reaches local distribution networks.
While DUoS covers your local network, TNUoS pays for the national transmission system - the network of high-voltage pylons and cables that transport electricity across Great Britain from power stations to regional networks. This is operated by the National Energy System Operator (NESO, formerly National Grid ESO).
TNUoS underwent major reform in April 2023 through the Targeted Charging Review (TCR). Previously, large businesses could reduce these charges through "Triad avoidance" - cutting usage during the three highest-demand half-hours each winter. Now, most businesses pay fixed charges based on capacity bands, removing the incentive (and complexity) of Triad management.
The charges vary by location across 14 zones - businesses in areas far from power generation typically pay more because electricity has to travel further, incurring more losses. These locational signals are designed to encourage new demand to locate nearer to power sources.
**Key points:**
- Set annually by National Grid ESO
- 14 demand zones (aligned with DNO regions)
- Post-TCR: ~88-100% recovered through fixed TDR bands
- Higher in areas far from generation (e.g., southern zones)
- Typically 5-10% of a business electricity bill
Example: TDR Band 1 (0-20 kVA): Fixed daily charge regardless of consumption
Related Terms: DUoS, BSUoS, GSP, TCR, National Grid ESO
BSUoS (Balancing Services Use of System)
Definition: Charges that cover the cost of keeping the electricity grid stable and balanced in real-time - ensuring supply always matches demand.
Electricity grids must be balanced second-by-second - the amount being generated must exactly match what's being consumed, or the system frequency deviates from 50Hz and problems occur. BSUoS charges fund the services needed to maintain this balance, including backup power plants, demand reduction schemes, and frequency response services.
These charges were reformed in April 2023 through a change called CMP361. Previously, BSUoS varied every half-hour based on actual balancing costs, creating unpredictability. Now, rates are fixed every six months in advance, making costs much easier to forecast. Additionally, all BSUoS costs are now recovered from electricity consumers (demand) rather than being shared with generators.
**Key changes from CMP361:**
- **Fixed rates**: BSUoS is now a fixed p/kWh rate for each six-month period (April-September and October-March)
- **Demand-only recovery**: 100% recovered from demand customers (approximately doubled the rate)
- **Predictable costs**: Rates announced well in advance for budgeting
For most businesses, BSUoS is a relatively small part of the bill, but the reforms have made this cost much more predictable for budgeting purposes.
Example: October 2025 - March 2026 rate: 1.569 p/kWh (applies to all consumption)
Related Terms: TNUoS, DUoS, CMP361, National Grid ESO
Capacity Market Levy (CM)
Definition: A charge that funds payments to power stations and other providers who commit to being available during potential electricity shortages - essentially insurance against blackouts.
The Capacity Market is the government's mechanism for ensuring there's always enough electricity generation available to meet peak demand, even during unexpected events like cold snaps or power station failures. Providers (generators, storage facilities, and demand response services) bid in annual auctions to be available during "stress events" when the system is under pressure.
The levy on electricity bills funds these capacity payments. When you pay the Capacity Market charge, you're contributing to a national insurance policy against power shortages. The rate varies based on auction results and how much capacity has been secured.
**Key facts:**
- Auctions held 4 years and 1 year ahead of each "delivery year" (October to September)
- Delivery year runs October to September (not April to March)
- Primarily applies to half-hourly metered customers (Profile Classes 00, 05-08)
- Clearing prices have risen from ~£6-8/kW (2017-18) to over £60/kW recently
- Includes main obligation plus small Settlement Costs Levy for administration
This charge primarily applies to half-hourly metered customers (typically larger businesses). The levy is usually shown separately on business electricity bills or included in third-party charges.
Related Terms: CfD Levy, DUoS, Half-Hourly Metered
CfD Levy (Contracts for Difference)
Definition: A charge that supports renewable energy by guaranteeing generators a stable price - you pay more when wholesale prices are low, but can pay nothing when market prices are high.
Contracts for Difference are the government's main mechanism for supporting new renewable energy projects like offshore wind farms. Generators are guaranteed a "strike price" for their electricity - if wholesale market prices fall below this, the CfD scheme pays them the difference. If market prices exceed the strike price, generators pay money back.
The quarterly levy, administered by the Low Carbon Contracts Company (LCCC), funds these support payments. Interestingly, during periods of very high wholesale prices (like those seen in 2022), the levy can drop to zero or even result in credits, as generators pay back their excess earnings.
**Key facts:**
- Quarterly rates from LCCC (changes 1 Jan, 1 Apr, 1 Jul, 1 Oct)
- Called the Interim Levy Rate (ILR)
- Can be zero when market prices exceed strike prices (as in 2021-2022)
- Operational Costs Levy for LCCC administration, set per April–March obligation year (£0.1089/MWh FY2025/26, £0.1463/MWh FY2026/27)
- Applies to ALL electricity consumption with no exemptions
This charge applies to all electricity customers and reflects the national commitment to decarbonising the power system.
Example: Q4 2024 rate: ~10-12 £/MWh (varies based on wholesale price forecasts)
Related Terms: Capacity Market, Wholesale Price, LCCC
Fixed Charge (Standing Charge)
Definition: A daily charge applied to every electricity supply point regardless of how much electricity you use - think of it as a "line rental" for your connection to the network.
The fixed charge is a standing daily fee that covers the basic costs of maintaining your connection to the electricity network. You pay this charge every day, whether you use 1 kWh or 10,000 kWh of electricity.
**How fixed charges are calculated:**
- Charged in pence per MPAN per day (p/MPAN/day)
- Applied to every billing day in your period
- Varies by DNO region and tariff category
- Typically ranges from 1-10 p/day for domestic to 50+ p/day for larger supplies
**Fixed charge bands under CDCM:**
| Band | Agreed Capacity | Description |
|------|-----------------|-------------|
| NR | No Residual | Minimal fixed charge |
| B1 | 0-20 kVA | Small business |
| B2 | 21-99 kVA | Medium business |
| B3 | 100-499 kVA | Large business |
| B4 | 500+ kVA | Very large business |
**Common billing errors:**
Fixed charges are straightforward to validate - simply multiply the daily rate by the number of days in your billing period. Errors typically occur when the wrong tariff category is applied (via incorrect LLFC), leading to the wrong fixed rate being charged.
Example: Fixed Charge: 8.50 p/MPAN/day x 31 days = £2.64
Related Terms: DUoS, LLFC, CDCM, Capacity Charges
Exceeded Capacity Charge
Definition: A penalty charge applied when your electricity demand exceeds the agreed maximum capacity for your supply - typically charged at 2-3 times the standard capacity rate.
When you connect a larger electricity supply, you agree a Maximum Import Capacity (MIC) with your DNO - the highest demand (in kVA) you'll draw at any moment. If your actual demand exceeds this agreed level, you pay exceeded capacity charges at penalty rates.
**How exceeded capacity charges work:**
- Only applies to half-hourly metered supplies (Profile Classes 00, 05-08)
- Measured against your agreed capacity (MIC) in kVA
- Charged in pence per kVA per day (p/kVA/day)
- Penalty rates typically 2-3 times higher than standard capacity rates
- Based on the highest recorded demand in the billing period
**Why DNOs charge this:**
Network infrastructure is designed based on agreed capacity levels. When customers exceed their agreed capacity, they're using more network capacity than was planned for, potentially causing stress on local equipment.
**Avoiding exceeded capacity charges:**
- Monitor maximum demand regularly
- Set up demand management alerts
- Request a capacity increase if consistently exceeding
- Review operational patterns that cause demand spikes
**Bill validation tip:**
Check your maximum demand readings against your agreed capacity. If you're being charged exceeded capacity but your readings show you stayed within limits, this is a billing error.
Example: Exceeded Capacity: 25 kVA over x 4.50 p/kVA/day x 31 days = £34.88
Related Terms: MIC / Agreed Capacity, Capacity Charges, DUoS, Half-Hourly Metered, DNO
CCL (Climate Change Levy)
Definition: A government environmental tax on business energy use designed to incentivise energy efficiency - domestic customers are exempt, and some businesses qualify for significant discounts.
The Climate Change Levy is an environmental tax charged by HM Revenue & Customs on electricity (and gas) used by businesses. It's designed to encourage energy efficiency and reduce carbon emissions.
**Key CCL facts:**
- Charged in pence per kilowatt-hour (p/kWh)
- Set annually by HMRC in the Budget
- Domestic customers are exempt (Profile Classes 01-02)
- Standard rate approximately 0.775 p/kWh (2024-25)
- Applies to all business electricity consumption
**CCL Exemptions and discounts:**
- **Domestic exempt** - Profile Classes 01-02 pay no CCL
- **CCA discount (92%)** - Businesses with Climate Change Agreements with HMRC
- **Renewable exemptions** - Some renewable electricity may be exempt with Levy Exemption Certificates (LECs)
**Why EnergyCode doesn't validate CCL:**
While CCL has published rates, exemptions depend on customer-specific agreements (Climate Change Agreements with HMRC, renewable contracts). We can verify the standard rate is applied correctly, but exemption eligibility requires information beyond the MPAN.
**Historical rates:**
The CCL rate has been relatively stable in recent years at around 0.775 p/kWh, though it adjusts periodically based on government policy.
Example: CCL: 50,000 kWh x 0.775 p/kWh = £387.50
Related Terms: DUoS, Profile Class, Half-Hourly Metered
MIC / Agreed Capacity (Maximum Import Capacity)
Definition: The maximum electrical demand (in kVA) your connection is designed to handle, set in your connection agreement with the DNO - this value directly determines your DUoS capacity charges and TNUoS TDR band.
Maximum Import Capacity (MIC) is the maximum power (in kVA) that your electricity connection is designed to supply at any moment. It's agreed between you and the DNO when the connection is established and recorded in your connection agreement.
**Why MIC matters:**
MIC directly affects two charges on your bill:
- **DUoS Capacity Charge** - For Site Specific tariffs: MIC × p/kVA/day × days
- **TNUoS TDR Band** - Since April 2023, your MIC determines which fixed band you fall into
**Example calculation:**
- MIC: 200 kVA
- Capacity Rate: 1.50 p/kVA/day
- 30-day month
- **Charge: 200 × 1.50 × 30 = 9,000 pence = £90.00**
**TNUoS TDR Bands (determined by MIC):**
| Band | LV Capacity | HV Capacity |
|------|-------------|-------------|
| Band 1 | 0-69 kVA | 0-999 kVA |
| Band 2 | 70-499 kVA | 1,000-1,999 kVA |
| Band 3 | 500-999 kVA | 2,000-9,999 kVA |
| Band 4 | 1,000+ kVA | 10,000+ kVA |
**The MIC data access problem:**
A common industry challenge is obtaining accurate MIC data before receiving the first DUoS bill. Unlike meter readings that flow through standard industry data channels, MIC is **connection data** stored by DNOs but not routinely shared via systems like ElectraLink/ECOES.
**Options for obtaining MIC data:**
| Source | Reliability | Speed | Notes |
|--------|-------------|-------|-------|
| Customer's connection agreement | High | Varies | Customer may not have it |
| Previous supplier's DUoS invoice | High | Varies | Shows capacity charged |
| Direct DNO request | High | 5-10 days | May need customer authorisation |
| ElectraLink/ECOES | Partial (~60%) | Immediate | Often outdated |
| First DNO bill | 100% | After billing cycle | Most common "true-up" approach |
**Why ElectraLink data is often incomplete:**
MIC isn't a mandatory field in standard industry data flows (DTS). The switching and settlement systems were built around meter readings, not connection agreements. Many historical connections pre-date digital systems and were never properly captured.
**Changing your MIC:**
If your requirements change, you can request a capacity increase or decrease from your DNO. This may involve:
- Application fee
- Possible network reinforcement costs (if increasing)
- New connection agreement
- Updated capacity charges from the effective date
**Bill validation tip:**
If the capacity charged on your DUoS invoice doesn't match your connection agreement, this is a billing error. Also check that your TNUoS TDR band is consistent with your MIC - wrong band = wrong charges.
Example: Connection Agreement: Maximum Import Capacity = 150 kVA
Related Terms: DUoS, Capacity Charges, Exceeded Capacity Charge, TNUoS, TDR, DNO
Network Operators
Organizations responsible for operating and maintaining electricity networks.
DNO (Distribution Network Operator)
Definition: The regional monopoly company responsible for maintaining and operating the local electricity cables, substations, and equipment that deliver power to your premises.
Great Britain has 14 DNO regions, each operated by a licensed company responsible for everything from the high-voltage cables leaving substations to the service cable entering your building. Unlike energy suppliers (who you can choose and switch), your DNO is determined by your location - you cannot change them.
**The 14 DNOs by parent company:**
| Operator | DNOs | Coverage |
|----------|------|----------|
| UKPN | Eastern (10), London (12), South Eastern (19) | London and South East |
| NGED | East Midlands (11), West Midlands (14), South Wales (21), South West (22) | Midlands and South West |
| NPg | Northern Powergrid NE (15), Yorkshire (23) | North East England |
| ENWL | Electricity North West (16) | Greater Manchester, Lancashire |
| SSEN | Scottish Hydro (17), Southern Electric (20) | Scottish Highlands, Southern England |
| SPEN | SP Manweb (13), SP Distribution (18) | Merseyside, North Wales, Central Scotland |
Your DNO is responsible for maintaining power quality, responding to outages (call 105 for power cuts), and connecting new supplies.
Related Terms: MPAN, DUoS, IDNO, GSP, Distributor ID
IDNO (Independent Distribution Network Operator)
Definition: A private electricity network operator, typically on new housing estates or business parks, that owns and maintains the local cables but must charge the same distribution rates as the regional DNO.
When new developments are built, the developer can choose to have the electricity network installed by either the regional DNO or an Independent Distribution Network Operator (IDNO). IDNOs are private companies that build, own, and operate these local networks, connecting them to the wider distribution system.
For customers on IDNO networks, the practical experience is largely the same as being on a DNO network. Crucially, IDNOs are subject to "Relative Price Control" - they must charge the same distribution rates as the host DNO, so you won't pay more (or less) just because you're on a private network.
**Key IDNO facts:**
- Distributor IDs 24 and above (versus DNOs at 10-23)
- 19+ licensed IDNOs in Great Britain
- Common on new housing developments, business parks, EV charging infrastructure
- Must mirror host DNO rates (Ofgem's Relative Price Control)
- Major IDNOs include: GTC/BUUK (IDs 24, 27), ESP/LENG (ID 25), Indigo Power (ID 38)
You can identify an IDNO connection by the Distributor ID in your MPAN - codes 24 and above indicate an IDNO rather than one of the 14 DNOs.
Example: Distributor ID 25 = ESP Electricity (LENG) - common on new developments
Related Terms: DNO, MPAN, Distributor ID, DUoS
National Grid ESO (NESO (National Energy System Operator))
Definition: The organisation that operates Britain's high-voltage transmission network and balances electricity supply with demand in real-time.
While DNOs manage local distribution, the National Energy System Operator (formerly National Grid ESO) manages the national transmission system - the backbone of high-voltage lines that carry electricity across the country. They're responsible for ensuring the lights stay on, balancing generation with demand second-by-second.
NESO publishes the TNUoS (transmission) and BSUoS (balancing) charges that appear on business electricity bills. They run the control room that dispatches power stations, manages interconnectors with Europe, and coordinates responses to system emergencies. They also administer the Capacity Market auctions.
**Key responsibilities:**
- Operating the 132kV+ transmission network 24/7
- Second-by-second balancing of supply and demand
- Procuring and dispatching balancing services
- Publishing TNUoS and BSUoS tariffs
- Administering Capacity Market auctions as Delivery Body
- Planning network development
In 2024, the Electricity System Operator was separated from National Grid's ownership and brought into public ownership as NESO. For most businesses, the practical impact is minimal - the same charges apply, just administered by the newly independent organisation.
Related Terms: TNUoS, BSUoS, GSP, Capacity Market
GSP (Grid Supply Point)
Definition: A point where the national transmission network connects to a regional distribution network.
Grid Supply Points are the interfaces between the high-voltage transmission network (operated by National Grid ESO) and the lower-voltage distribution networks (operated by DNOs). Think of them as the "junction boxes" where national electricity highways meet regional roads.
**Key facts:**
- Approximately 340 GSPs across Great Britain
- Each GSP serves a specific geographic area
- Electricity flows from transmission (132kV+) to distribution at GSPs
- Used for settlement and pricing purposes
- TNUoS charges vary by GSP group (14 zones)
Your GSP group affects your TNUoS charges, with different zones having different locational charges. Northern Scotland typically has the highest transmission charges because electricity must travel furthest from southern generation sources.
The GSP Group ID is a letter (A to P, excluding I and O) that identifies which transmission demand zone your supply falls into.
Related Terms: TNUoS, DNO, National Grid ESO, Distributor ID
LCCC (Low Carbon Contracts Company)
Definition: The government-owned company that administers the Contracts for Difference scheme and Capacity Market - they calculate and collect the levies that support renewable energy and security of supply.
LCCC is a government-owned company that manages two key schemes supporting the UK's electricity system: Contracts for Difference (supporting renewable energy) and the Capacity Market (ensuring enough generation capacity exists).
**LCCC responsibilities:**
- Administering CfD contracts with renewable generators
- Calculating quarterly Interim Levy Rates (ILR) for CfD
- Managing Capacity Market payments to providers
- Calculating Capacity Market supplier obligations
- Publishing levy rates and methodologies
**CfD administration:**
When renewable generators produce electricity, LCCC pays them the difference between the "strike price" (the guaranteed price) and the market reference price. When market prices exceed strike prices, generators pay money back. LCCC calculates the net cost and passes this to suppliers via the quarterly levy.
**Capacity Market administration:**
LCCC also acts as the counterparty for Capacity Market agreements, making payments to providers who commit to being available during system stress events.
**Why LCCC matters for bill validation:**
EnergyCode uses LCCC's published levy rates to validate CfD charges on your bill. If your supplier is charging a different rate than the published LCCC Interim Levy Rate for that quarter, that's an error.
Related Terms: CfD Levy, Capacity Market, National Grid ESO, Ofgem
Elexon (Electricity Market Administrator)
Definition: The company that administers electricity settlement in Great Britain - they ensure generators are paid for what they produce and suppliers pay for what their customers use.
Elexon is the central administrator for electricity settlement in Great Britain, operating under the Balancing and Settlement Code (BSC). They're responsible for comparing what generators produced with what was consumed, and settling the financial differences.
**Elexon responsibilities:**
- Managing the Balancing and Settlement Code (BSC)
- Operating the settlement system that matches supply and demand financially
- Administering the Market-wide Half-Hourly Settlement (MHHS) programme
- Managing meter registration and data flows
- Publishing market data and reports
**Settlement explained:**
Every day, Elexon calculates how much electricity each supplier's customers used and compares this to what was contracted in the wholesale market. Differences are settled at the System Sell Price or System Buy Price.
**MHHS programme:**
Elexon is leading the industry transition to Market-wide Half-Hourly Settlement, the major reform that will see all electricity meters settled on actual half-hourly data rather than estimated profiles. This is rolling out September 2025 to May 2027.
**Why Elexon matters:**
While Elexon doesn't directly set network charges, they manage the settlement data that underlies accurate billing. The D0018 data flows (profile coefficients) that help estimate when non-half-hourly customers use electricity come through Elexon's systems.
Related Terms: MHHS, BSUoS, Half-Hourly Metered, Profile Class
TPI (Third-Party Intermediary)
Definition: Energy brokers and consultants who help businesses manage their electricity contracts and costs - ranging from large consultancies to independent advisors.
TPIs are the energy industry's equivalent of insurance brokers or mortgage advisors - they help businesses navigate the complex energy market, negotiate contracts, and manage costs. The term covers a wide range of services from simple procurement to comprehensive energy management.
**Types of TPI services:**
- **Energy procurement** - Tendering and negotiating supply contracts
- **Bill validation** - Checking invoices for errors
- **Cost analysis** - Breaking down what you pay and why
- **Budget forecasting** - Predicting future costs
- **Consumption monitoring** - Tracking and optimising usage
- **Network charge auditing** - Verifying DUoS, TNUoS, etc.
**The market landscape:**
- Large TPIs serve major corporations with dedicated account teams
- Smaller TPIs and independents serve SMEs
- Some specialise in specific sectors (retail, manufacturing, healthcare)
- Fees range from commission on contracts to fixed consultancy fees
**Why EnergyCode serves TPIs:**
Bill validation - checking that network charges are correct - has traditionally been a service that only large TPIs could offer, as it requires expensive proprietary tools and deep industry expertise. EnergyCode democratises this capability, allowing smaller TPIs and independent consultants to offer the same level of validation.
**Bill validation opportunity:**
Industry estimates suggest 3-4% of electricity bills contain errors. TPIs who can identify and recover these overcharges provide significant value to their clients.
Related Terms: DUoS, LLFC, Supercustomer, DNO
Tariff Structure
How electricity charges are calculated and structured.
LLFC (Line Loss Factor Class)
Definition: A three-character code that determines which tariff category applies to your electricity supply - getting this wrong means paying incorrect rates.
The LLFC is arguably the most important code on your MPAN for billing purposes. This three-character code (which can include letters and numbers) acts as the bridge between your meter and the tariff rates you pay. Every LLFC maps to a specific tariff category, which determines your unit rates, standing charges, and capacity charges.
Different LLFCs exist because electricity loses some energy as it travels through the network - supplies connected at higher voltages (like factories with their own substations) lose less energy than domestic supplies at standard voltage. The LLFC captures this difference along with other characteristics like your metering type.
**Key facts about LLFCs:**
- **Alphanumeric since 2016**: Following BSC Change Proposal CP1434 (30 June 2016), LLFCs can contain letters A-Z (excluding I and O to avoid confusion with 1 and 0)
- **Examples**: 001, N01, P80, LST, HST
- **Market segments**: Domestic, Non-Domestic, Generation (export), Unmetered (street lighting)
- **Voltage levels**: LV (Low Voltage), LV Sub, HV (High Voltage), EHV (Extra High Voltage)
Billing errors often stem from an incorrect LLFC being applied. If your supply has been upgraded, moved, or changed, the LLFC might not have been updated correctly. This is one of the first things to check if you suspect you're being overcharged.
**How LLFC-to-Tariff Mapping Works**
Each DNO publishes an LLFC schedule (typically in Annex 3 of their charging statement) that maps every LLFC to a tariff category. Multiple LLFCs can map to the same tariff because they represent different physical configurations that have the same charging treatment.
**Why New LLFCs Appear Mid-Year**
DNOs occasionally publish revised charging statements (v1.0 → v1.1) during a charging year:
- **What changes:** New LLFC codes for new meter configurations or IDNO networks
- **What stays the same:** All tariff rates remain unchanged
For bill validation, always use the latest version of the charging statement.
Example: LLFC 100 = ND_AGG_B1 (Non-Domestic Aggregated Band 1) in UKPN Eastern
Related Terms: MPAN, Tariff Category, Line Loss Factor, CDCM
Time Bands (Red/Amber/Green)
Definition: The three pricing periods used for distribution charges - Red is the most expensive (peak hours), Green is the cheapest (nights and weekends), and Amber falls in between.
Distribution charges vary by time of day to reflect when the network is under most stress. Red periods cover the expensive peak hours - typically 4pm to 7pm on weekdays when household demand combines with commercial usage. Green periods cover the cheapest times - overnight hours and weekends when demand is lowest. Amber periods cover the remaining daytime hours.
**Typical time band definitions:**
- **Red (Peak)**: Weekday late afternoon/evening (commonly 16:00-19:00)
- **Amber (Shoulder)**: Weekday daytime outside peak
- **Green (Off-peak)**: Nights (typically after 23:00), weekends, bank holidays
The exact timing of these bands varies slightly between DNO regions, reflecting local demand patterns. Some regions also have different bands for different tariff types or seasons (winter vs summer).
**Why it matters:**
The difference between Red and Green rates can be substantial - Red rates can be 3-4 times higher than Green. For businesses with flexibility - such as the ability to schedule energy-intensive processes overnight - even small shifts in usage patterns can generate meaningful savings over a year.
Each DNO publishes their time band definitions in their annual Charging Statement.
Example: Red: 16:00-19:00 weekdays, Amber: 07:00-16:00 weekdays, Green: all other times
Related Terms: DUoS, CDCM, Profile Class
Capacity Charges (Agreed Capacity)
Definition: Daily charges based on your site's agreed maximum power demand (measured in kVA) - exceed this limit and you pay penalty rates for the extra capacity used.
When larger electricity supplies are connected, customers agree a maximum import capacity (MIC) with their network operator - the maximum power in kilovolt-amperes (kVA) they'll draw at any point. The capacity charge is a daily fee based on this agreed level, regardless of whether you actually use that much power.
**How capacity charges work:**
- Measured in kVA (kilovolt-amperes)
- Charged daily: pence per kVA per day
- Must be formally agreed with the DNO
- Determines which capacity band you fall into (B1-B4 under CDCM)
**Exceeded capacity:**
If your actual demand exceeds your agreed capacity, you'll pay exceeded capacity charges at penalty rates - typically much higher than the standard capacity rate. This incentivises customers to either request appropriate capacity upfront or manage their usage to stay within limits.
**Cost optimisation:**
For many businesses, reviewing agreed capacity is worthwhile. If your operations have changed and you consistently use far less than your agreed capacity, you might be able to reduce it and save money. Conversely, if you regularly exceed your limit, it may be cheaper to formally increase your agreed capacity than continue paying penalty rates.
Example: Agreed Capacity: 150 kVA at 1.80 p/kVA/day = £2.70/day = ~£985/year
Related Terms: DUoS, DNO, CDCM, LLFC
Reactive Power Charges (Power Factor)
Definition: Penalty charges for electrical inefficiency - if your equipment draws power inefficiently (poor power factor), you pay extra for the wasted network capacity.
Electrical equipment doesn't just use "real" power that does useful work - it also draws "reactive" power that oscillates back and forth without producing useful output. This reactive power still uses network capacity, so customers with significant reactive power consumption pay additional charges.
**Understanding power factor:**
The efficiency of power usage is measured as "power factor" - a perfect score is 1.0, meaning all power drawn is used productively. Distribution networks typically expect a power factor of at least 0.95. If your factor falls below this threshold, you'll pay reactive power charges based on the kVArh (kilovolt-ampere reactive hours) recorded.
**Who pays reactive power charges:**
- Only half-hourly metered customers (Profile Classes 00, 05-08)
- Only when power factor drops below the threshold (typically 0.95)
- Charged in pence per kVArh
**Common causes of poor power factor:**
- Electric motors (especially older or under-loaded ones)
- Fluorescent lighting with magnetic ballasts
- Air conditioning compressors
- Welding equipment
**Solutions:**
If you face these charges, power factor correction equipment (capacitor banks) can often reduce or eliminate them, with installation costs typically recovered through bill savings within 1-2 years.
Example: Reactive Power Rate: 0.45 p/kVArh when power factor < 0.95
Related Terms: DUoS, Half-Hourly Metered, Capacity Charges
Line Loss Factor (LLF)
Definition: A multiplier that accounts for electricity lost as heat during transmission through the network - higher voltage connections have lower losses.
Line Loss Factors (LLFs) adjust metered consumption to account for technical losses in the distribution network - electricity converted to heat as it flows through cables and transformers. This is the physics of electricity transmission that the LLFC (Line Loss Factor Class) code captures.
**How LLFs work:**
- Expressed as a percentage above metered units
- Higher for lower voltage connections (more transformation losses)
- Varies by time of year (seasonal factors)
- Different for import vs export
- Set by DNOs based on network modelling
- Published by Elexon (the BSC agent) as Industry Standing Data (ISD)
- Elexon-published values are the authoritative source used in settlement
**Example:**
An LLF of 1.08 means for every 100 kWh metered at your premises, 108 kWh is deemed to have been consumed at the GSP (Grid Supply Point). The extra 8% accounts for energy lost in the cables and transformers between the GSP and your meter.
**Why voltage matters:**
- High Voltage (HV) connections: Lower losses (~2-4%)
- LV Sub connections: Medium losses (~5-7%)
- Low Voltage (LV) connections: Higher losses (~7-10%)
This is why large industrial sites often have their own substations with HV connections - the savings on line losses can be substantial.
Example: Metered: 10,000 kWh x LLF 1.08 = 10,800 kWh for settlement
Related Terms: LLFC, GSP, Settlement, DNO
Voltage Levels (LV/HV/EHV)
Definition: The different levels of electrical voltage at which supplies are connected - higher voltage connections have lower network losses and typically lower distribution charges.
Electricity is distributed at different voltage levels depending on the size and type of supply. Larger sites that need more power often connect at higher voltages, which means less energy is lost in the network and lower charges apply.
**The voltage hierarchy:**
| Level | Voltage | Typical Line Losses | Typical Customers |
|-------|---------|---------------------|-------------------|
| EHV | 132kV/33kV | ~1-2% | Large industrial sites, data centres |
| HV | 11kV/6.6kV | ~2-4% | Factories, large commercial premises |
| LV Sub | 400V (substation) | ~5-7% | Medium business supplies |
| LV | 230V/400V | ~7-10% | Domestic and small business supplies |
**Why voltage matters for charges:**
Each transformation step (stepping voltage down through a transformer) loses some energy as heat. A supply connected directly at HV avoids the losses from the final LV transformer. This is reflected in both:
- **Line Loss Factors** - Lower losses at higher voltages
- **Tariff categories** - HV_SS tariffs vs LV_SS tariffs
**How EnergyCode uses voltage levels:**
Your LLFC code encodes your voltage level, which maps to the appropriate tariff category. For example:
- LLFC codes for LV Site Specific
- LLFC codes for LV Sub Site Specific
- LLFC codes for HV Site Specific
**Site Specific vs Aggregated:**
Higher voltage connections are typically "site specific" (bespoke tariff for your connection) rather than "aggregated" (standard tariff shared with similar customers).
Example: HV supply at 11kV has ~3% line losses vs LV supply at 230V with ~8% losses
Related Terms: LLFC, Line Loss Factor, DUoS, CDCM
Market Segment
Definition: One of four categories that classify electricity supplies: Domestic, Non-Domestic, Generation (export), and Unmetered - determining which tariff structures apply.
Every electricity supply in Great Britain falls into one of four market segments, which determines the overall framework of charges that apply. The market segment is encoded in the LLFC and drives which tariff categories are available.
**The four market segments:**
| Segment | Profile Classes | CCL | Tariff Examples |
|---------|-----------------|-----|-----------------|
| Domestic | 01-02 | Exempt | DOM_AGG, DOM_AGG_REL |
| Non-Domestic | 03-08, 00 | Subject to | ND_AGG, LV_SS, LVS_SS, HV_SS |
| Generation | N/A (export) | N/A | LV_GEN_AGG, LVS_GEN_SS, HV_GEN_SS |
| Unmetered | N/A | Subject to | UMS |
**Segment details:**
- **Domestic** - Residential customers only
- **Non-Domestic** - All commercial and industrial premises
- **Generation** - Embedded generation that exports to the network (negative charges possible)
- **Unmetered** - Street lighting, traffic signals, phone boxes (consumption estimated from inventory)
**Why market segment matters:**
If your LLFC maps to the wrong market segment, your entire tariff framework could be wrong. For example, a small business incorrectly coded as domestic might avoid CCL but face different DUoS rates. EnergyCode validates that your LLFC's market segment matches your actual supply type.
Example: LLFC 100 maps to NON_DOMESTIC segment, tariff ND_AGG_B1
Related Terms: LLFC, Profile Class, CDCM, DUoS
Tariff Category (CDCM Category)
Definition: One of 32 standardised tariff types used by all DNOs since April 2022 - your LLFC code maps to exactly one tariff category, which determines all your DUoS rates.
Since the Common Distribution Charging Methodology (CDCM) came into effect in April 2022, all 14 DNOs use the same 32 standardised tariff categories. Your LLFC code maps to exactly one of these categories, and that determines all your DUoS rate components.
**The 32 CDCM tariff categories:**
**Domestic (2):**
- DOM_AGG - Domestic Aggregated (standard domestic)
- DOM_AGG_REL - Domestic Related MPAN (secondary meters like storage heaters)
**Non-Domestic Aggregated (6):**
- ND_AGG_NR - No Residual
- ND_AGG_B1 through ND_AGG_B4 - Bands 1-4
- ND_AGG_REL - Related MPAN
**Site Specific (15):**
- LV_SS_NR, LV_SS_B1-B4 (Low Voltage)
- LVS_SS_NR, LVS_SS_B1-B4 (LV Sub)
- HV_SS_NR, HV_SS_B1-B4 (High Voltage)
**Generation (8):**
- LV_GEN_AGG, LVS_GEN_AGG (Aggregated)
- LV_GEN_SS, LVS_GEN_SS, HV_GEN_SS (Site Specific)
- LV_GEN_SS_NRP, LVS_GEN_SS_NRP, HV_GEN_SS_NRP (No RP Charge)
**Unmetered (1):**
- UMS - Unmetered Supplies
**Why this matters for validation:**
EnergyCode maintains a complete mapping of 4,278 LLFCs to their correct tariff categories across all 14 DNOs and 22 IDNOs. If your bill shows rates that don't match the published rates for your tariff category, we'll flag the discrepancy.
Example: LLFC 210 in UKPN Eastern maps to ND_AGG_B2 tariff category
Related Terms: LLFC, CDCM, DUoS, Market Segment
EDCM (EHV Distribution Charging Methodology)
Definition: Site-specific pricing methodology for Extra High Voltage (22kV+) connections - unlike CDCM's 32 standard tariffs, each EHV site gets individually calculated charges based on network modelling.
EDCM is the charging methodology used for large electricity connections at Extra High Voltage (22kV and above). Unlike CDCM which uses standardised tariff categories, EDCM calculates bespoke charges for each site based on detailed network modelling.
**Key differences from CDCM:**
| Aspect | CDCM | EDCM |
|--------|------|------|
| Voltage | LV, LV Sub, HV | EHV (22kV+) |
| Tariffs | 32 standard categories | Site-specific |
| Published in | Annexe 1 | Annexe 2 |
| Calculation | LLFC lookup | DNO network model |
| Time bands | Red/Amber/Green | Super Red + other |
**Two EDCM variants:**
- **FCP (Forward Cost Pricing)** - DCUSA Schedule 17, based on projected network load growth
- **LRIC (Long Run Incremental Cost)** - DCUSA Schedule 18, based on nodal incremental costs
**What EDCM charges include:**
- Import and export capacity charges
- Exceeded capacity penalties
- Super Red unit charges (Nov-Feb, Mon-Fri 4pm-7pm)
- Fixed charges
- Reactive power charges
**Why EDCM sites exist:**
These are typically large industrial sites, data centres, or sites with their own primary substations that connect directly to the 22kV, 33kV, 66kV, or 132kV network. The site-specific approach reflects that their network impact varies significantly based on location.
**Important:** EnergyCode provides EDCM tariff data for reference and validation purposes, but cannot calculate EDCM charges as this requires DNO network models we do not have access to. We also surface site identity for EHV connections (operator, connection type, voltage, indicative capacity and address) drawn from public registers and Companies House, alongside the reference tariff data.
Related Terms: CDCM, Super Red, Annexe 2, FCP, LRIC, DUoS
Super Red
Definition: The single peak time period used in EDCM charging - November to February, Monday to Friday, 4pm to 7pm - contrasting with CDCM's Red/Amber/Green bands.
Super Red is the peak charging period used in EDCM (Extra High Voltage Distribution Charging Methodology). Unlike CDCM which has three time bands (Red, Amber, Green), EDCM uses a single "Super Red" period to identify peak demand times.
**Super Red definition:**
- **Months:** November, December, January, February (winter only)
- **Days:** Monday to Friday (excludes weekends)
- **Hours:** 4pm to 7pm (16:00-19:00)
- **Excludes:** Bank holidays and public holidays
**Why "Super Red":**
The name distinguishes this from CDCM's standard "Red" band. While CDCM Red periods can span several hours across autumn/winter/spring, Super Red is a much narrower, more intense peak period focused on the winter evening peak when national electricity demand is highest.
**Usage in EDCM:**
Super Red unit rates are charged on kWh consumption during these peak periods. These rates are typically the highest unit charges on an EHV site's bill, reflecting the network stress during winter evening peaks.
**Relationship to Triads:**
The Super Red period aligns closely with when Triads historically occurred (the three highest national demand half-hours, always in winter 4-7pm). Although Triads no longer drive TNUoS charges post-TCR, the Super Red period reflects the same underlying network stress pattern.
Example: Super Red rate: 15.50 p/kWh for consumption Mon-Fri 4-7pm, November-February
Related Terms: EDCM, Time Bands, Triad, DUoS
FCP (Forward Cost Pricing)
Definition: One of two EDCM calculation variants (DCUSA Schedule 17) - calculates site-specific charges based on projected network load growth and reinforcement costs.
Forward Cost Pricing (FCP) is one of two methodologies used to calculate site-specific EDCM tariffs for Extra High Voltage connections. It's defined in DCUSA Schedule 17 and focuses on the forward-looking costs of accommodating demand at each network location.
**How FCP works:**
FCP calculates charges based on:
- Projected network load growth in the area
- Expected reinforcement costs
- The site's contribution to network investment needs
- Location-specific factors from the DNO's network model
**FCP vs LRIC:**
| Aspect | FCP | LRIC |
|--------|-----|------|
| DCUSA Schedule | 17 | 18 |
| Focus | Forward costs | Incremental costs |
| Based on | Projected growth | Nodal analysis |
| Time horizon | Future investment | Long-run impact |
**Which DNOs use which:**
Different DNOs may use FCP, LRIC, or a combination. The choice affects how charges are calculated but both aim to produce cost-reflective, location-specific tariffs.
**Why it matters:**
Understanding whether your DNO uses FCP or LRIC can help explain why your EDCM charges differ from similar sites in other regions. The methodology affects how network costs are attributed to individual sites.
Related Terms: EDCM, LRIC, DCUSA, DUoS
LRIC (Long Run Incremental Cost)
Definition: One of two EDCM calculation variants (DCUSA Schedule 18) - calculates site-specific charges based on the long-run incremental cost of each kW of demand at each network node.
Long Run Incremental Cost (LRIC) is one of two methodologies used to calculate site-specific EDCM tariffs for Extra High Voltage connections. It's defined in DCUSA Schedule 18 and focuses on the incremental cost impact of demand at each specific network location.
**How LRIC works:**
LRIC calculates charges based on:
- The incremental cost of an additional kW at each network node
- Long-run network development costs
- Location-specific utilisation and capacity headroom
- The site's marginal impact on network investment timing
**Key concept - nodal pricing:**
LRIC uses detailed network modelling to determine how adding demand at each specific location affects network costs. A site in an area with spare capacity will have lower LRIC charges than one in a constrained area requiring reinforcement.
**LRIC vs FCP:**
| Aspect | LRIC | FCP |
|--------|------|-----|
| DCUSA Schedule | 18 | 17 |
| Focus | Incremental impact | Forward costs |
| Based on | Nodal analysis | Projected growth |
| Signals | Capacity constraints | Investment needs |
**Location signals:**
LRIC provides strong locational signals - sites in network-constrained areas face higher charges, potentially encouraging them to reduce demand or locate elsewhere. This is more granular than CDCM's regional approach.
Related Terms: EDCM, FCP, DCUSA, DUoS
Why DUoS Rates Vary By Region
Definition: DUoS charges reflect each DNO's actual network costs - geography, customer density, and infrastructure age all affect what you pay.
The 14 DNO regions in Great Britain have significantly different DUoS rates because charges are cost-reflective, not standardised nationally.
**Factors that drive regional variation:**
| Factor | Higher Costs | Lower Costs |
|--------|--------------|-------------|
| Geography | Rural, mountainous | Urban, flat |
| Customer density | Sparse population | Dense urban areas |
| Network age | Older infrastructure | Recently upgraded |
| Cable type | Underground cables | Overhead lines |
| Weather | Coastal, extreme weather | Sheltered inland |
**Practical example:**
Scottish Hydro (SSEH) serves the Highlands with long cable runs between small communities. UKPN London serves dense urban areas with short connections. SSEH's costs per customer are naturally higher.
This explains why the same business type can pay 30-50% more for DUoS in Scotland than in London for identical consumption.
**DNO ownership groups:**
- **SSEN** (SSE): SSEH (North Scotland), SSES (Central Southern)
- **UKPN** (UK Power Networks): Eastern, London, South Eastern
- **WPD** (National Grid): East/West Midlands, South Wales, South West
- **NPG** (Northern Powergrid): North East, Yorkshire
- **ENWL** (Electricity North West): North West
- **SPEN** (SP Energy Networks): SP Distribution (Central/Southern Scotland), SP Manweb (Merseyside/North Wales)
Related Terms: DUoS, DNO, CDCM, LLFC
Why There Are 32 Tariff Categories
Definition: The CDCM standardises DUoS pricing into 32 categories that balance simplicity with cost-reflectivity across all customer types.
Before the Common Distribution Charging Methodology (CDCM) was introduced, each DNO had its own tariff structure with different names, bands, and categories. This made it nearly impossible to compare charges across regions.
**The 32 categories cover:**
| Dimension | Options |
|-----------|---------|
| Market segment | Domestic, Non-Domestic, Unmetered |
| Size band | Small, Medium, Large |
| Metering | Aggregated, Half-Hourly |
| Voltage | LV, LV Sub, HV |
| Time configuration | Unrestricted, Two Rate, Three Rate |
**Why standardisation matters:**
- **Comparison:** You can now compare equivalent tariffs across DNOs
- **Billing validation:** Systems can validate charges against published rates
- **Portability:** Switching supplier doesn't affect your tariff category
The LLFC code on your MPAN determines which of the 32 categories applies. Each DNO publishes a mapping table showing which LLFCs map to which tariff categories.
**Note:** EDCM (EHV) customers are NOT covered by these 32 categories - they have individually-calculated site-specific tariffs.
Related Terms: CDCM, Tariff Category, LLFC, DUoS
Why Charging Statements Get Revised Mid-Year
Definition: DNOs publish revised versions (v1.1, v1.2) during a charging year to add new LLFC codes - tariff rates stay the same.
DNOs publish their charging statements before each charging year (1 April to 31 March). However, you'll often see revised versions appear during the year - v1.0 becomes v1.1, then v1.2.
**What changes in revisions:**
- New LLFC codes added (Annex 3)
- New IDNO embedded network mappings
- Corrections to typos or formatting
**What never changes:**
- Tariff rates (Annex 1)
- Tariff category definitions
- Charge component structures
**Why this happens:**
- New smart meter configurations are deployed
- IDNOs register new embedded networks
- Aggregated billing arrangements are modified
- Minor corrections needed
**For bill validation:**
Always use the **latest version** of the charging statement for the relevant charging year. If you're validating a bill from October 2025 and v1.2 was published in August 2025, use v1.2.
EnergyCode automatically tracks charging statement versions and uses the latest available data for each DNO region.
Related Terms: LLFC, CDCM, DNO, IDNO, Tariff Category
Pricing Engine (The cost stack of a UK energy tariff)
Definition: A deterministic, bottom-up builder for UK energy tariffs — every cost row traced to an official published source, across all 14 GB DNO regions, for domestic and SME (PC03, PC04) profiles.
Pricing Engine is EnergyCode's flagship product. It builds the full deterministic cost stack of a UK energy tariff: wholesale energy, network charges (DUoS, TNUoS, BSUoS), policy levies (Capacity Market, CfD, CCL, Nuclear RAB, AAHEDC), metering, operating costs, margin and VAT — assembled bottom-up rather than estimated top-down.
**What "bottom-up" means**
Every cost row in Pricing Engine traces back to an official published source. Wholesale comes from primary market data; network charges from the DNO charging statements; levies from the regulators and operators that publish them. No aggregator estimates, no opaque magic numbers.
**Four views, one workspace**
- **Overview** — all 14 DNO regions side by side, annual £ per region
- **Breakdown** — the full cost cascade per region (wholesale → network → policy → metering → ops → margin → VAT)
- **Profile Class** — comparison across domestic (PC01, PC02 Economy 7, PC02 Economy 10) and SME (PC03, PC04) profiles, with the remaining SME classes (PC05–08) next
- **Unit rate** — the full tariff sheet output (p/kWh, p/day, annual £)
**Six levers**
Contract length, VAT toggle, Annual vs Contract view, Custom kWh override, an Other Costs drawer for bespoke rows, and an Assumptions drawer where the commercial layer lives (margin, hedging, shape risk uplift, imbalance) — every lever is editable and the impact is live.
**Who uses it**
Energy consultancies modelling for clients, suppliers (and aspiring suppliers) building the pricing layer of their stack, TPIs validating quotes at scale, and analysts who need to see what is actually in a UK energy tariff across all 14 DNO regions.
Example: Pricing Engine lets a consultancy build a PC01 domestic or PC04 SME tariff for the Eastern region in seconds — wholesale through to VAT, every row sourced.
Related Terms: Cost Stack, DUoS, TNUoS, CDCM, Profile Class
Cost Stack (The layered build-up of a tariff price)
Definition: The vertical build-up of every cost component that goes into a UK energy tariff — wholesale at the bottom, through network, policy, metering, ops, margin, and VAT at the top.
The cost stack is the order in which costs accumulate to form a final tariff. Each layer sits on top of the one below, and each is calculated independently before the totals are summed.
**The deterministic layers (the bottom ~90%)**
- **Wholesale energy** — the commodity cost (Elec or Gas) for the contract period
- **Network charges** — DUoS for distribution, TNUoS for transmission, BSUoS for balancing
- **Policy levies** — Capacity Market, CfD, CCL, Nuclear RAB, AAHEDC (and gas-equivalent for gas supplies)
- **Metering** — meter operator costs and data services
- **Operating costs** — supplier admin, billing, customer service
These are deterministic because the rates are published and the methodology is defined. Given a meter, a region, and a consumption profile, every supplier should arrive at very similar numbers.
**The commercial layers (the top ~10%)**
- **Margin** — the supplier's profit
- **Hedging strategy** — how much of the wholesale exposure is locked in vs floating
- **Shape risk uplift** — premium to cover the difference between a customer's load shape and a baseload hedge
- **Imbalance risk** — premium to cover settlement period imbalance
- **VAT** — 5% for domestic, 20% for non-domestic
These are commercial choices, not sourced facts. Pricing Engine surfaces them in the Assumptions drawer rather than baking them in.
Example: For a domestic PC01 tariff, the cost stack runs: wholesale (~58%) → network (~18%) → policy levies (~11%) → metering and ops (~5%) → margin (~5%) → VAT (~3%).
Related Terms: Pricing Engine, DUoS, TNUoS, BSUoS, Wholesale Energy
DUoS Tariff ID
Definition: The MHHS field that determines which distribution charging tariff applies to a meter, the charging half of the legacy LLFC, which under MHHS splits into a DUoS Tariff ID and a separate LLF ID.
Under MHHS, the single legacy LLFC concept separates into two distinct identifiers:
- **DUoS Tariff ID** - determines which distribution (DUoS) tariff category applies, that is, your charges
- **LLF ID** - determines which line loss factors apply for settlement, that is, your losses
Historically both jobs were bundled into one 3-character LLFC. MHHS pulls them apart so charging and loss-adjustment can be referenced independently.
**The crucial continuity point:**
At MHHS go-live the DUoS Tariff ID is identical to the existing LLFC (the same data item, J0147, simply renamed over time). It is a 3-character code in the same format and it maps to the same 32 CDCM tariff categories. So existing charge lookups keyed on the LLFC continue to work unchanged; only the name of the field evolves.
**Where each one lives:**
The split is in the settlement data model, not on the supply number itself. The 22-digit MPAN top line carries the DUoS Tariff ID; the LLF ID is held in settlement data, not displayed on the MPAN.
**Why split it at all:**
Separating charging from losses gives a cleaner data model for a half-hourly-settled market, where loss factors are applied per settlement period. The LLF ID can be maintained and updated independently of the charging tariff.
**The practical read:**
If you maintain systems, treat the DUoS Tariff ID as the new name for the charging role of the LLFC, and expect a companion LLF ID for losses. No tariff rate or category changes as a result of the rename.
Related Terms: LLFC, Line Loss Factor, Tariff Category, MHHS, DUoS
Profile Coefficients (D0018)
Definition: Statistical half-hourly usage shapes (published in the D0018 data flow) once used to estimate when non-half-hourly meters consumed electricity, now being retired under MHHS in favour of actual half-hourly data.
Profile coefficients are statistical shapes that estimate how a non-half-hourly meter's total consumption was spread across the 48 half-hours of each day. They were published in the D0018 data flow and combined with a meter's Profile Class to settle usage before actual half-hourly data was available for everyone.
**How they worked:**
Each Profile Class (for example a standard domestic supply, or a particular business type) had an associated set of coefficients describing a typical daily and seasonal shape. Settlement applied that shape to estimate half-hourly consumption, because the meter itself only recorded a cumulative total.
**Why they are being retired:**
- MHHS settles meters on actual half-hourly readings, removing the need to estimate
- Elexon's Profile Administration Service, which produced the coefficients, is being decommissioned through MHHS (supplier sampling submissions ceased late 2024)
- The Load Shaping Service now derives load shapes from real data
**They are not gone yet:**
Profile coefficients remain needed to settle and reconcile any meter that has not migrated, and to reconcile historic pre-migration periods. That reconciliation tail runs to around 2028, after which the data can be archived rather than maintained.
Related Terms: Profile Class, Load Shaping Service, MHHS, Half-Hourly Metered
Industry Bodies
Regulatory organizations and governance frameworks in the energy sector.
DCUSA (Distribution Connection and Use of System Agreement)
Definition: The master contract that governs how electricity distribution networks operate in Great Britain, setting the rules for connections, charging, and the relationships between network operators and suppliers.
DCUSA is the multi-party legal agreement that underpins the entire electricity distribution market in Great Britain. It's signed by all DNOs, IDNOs, and licensed electricity suppliers, establishing the framework for how distribution networks are accessed and paid for.
**What DCUSA covers:**
- How new connections are made
- Methodology for calculating charges (CDCM)
- Data exchange requirements between parties
- Rights and obligations of all signatories
- Dispute resolution processes
**Change process:**
When industry changes are needed, they go through a formal DCUSA Change Proposal (DCP) process, with working groups, consultations, and ultimately Ofgem approval.
**Why it matters for bill validation:**
DCUSA-mandated transparency means you have the right to verify your DUoS charges against published tariffs. Every DNO must publish their complete Charging Statement including all tariff rates, LLFC mappings, and time band definitions. If your supplier cannot explain a charge by reference to published DCUSA-compliant methodology, that's a red flag.
Related Terms: DNO, DUoS, Ofgem, CDCM
CDCM (Common Distribution Charging Methodology)
Definition: The standardised charging system used by all 14 DNOs since April 2022, ensuring consistent tariff categories and calculation methods across the country.
Before CDCM, each DNO had slightly different approaches to naming and structuring their tariffs, making comparison difficult. Since April 2022, all DNOs use the same 32 standardised tariff categories with consistent naming conventions.
**The 32 CDCM tariff categories:**
**Domestic (2):**
- DOM_AGG - Domestic Aggregated
- DOM_AGG_REL - Domestic Related MPAN
**Non-Domestic Aggregated (6):**
- ND_AGG_NR - No Residual
- ND_AGG_B1 through ND_AGG_B4 - Bands 1-4
- ND_AGG_REL - Related MPAN
**LV Site Specific (5):**
- LV_SS_NR, LV_SS_B1 through LV_SS_B4
**LV Sub Site Specific (5):**
- LVS_SS_NR, LVS_SS_B1 through LVS_SS_B4
**HV Site Specific (5):**
- HV_SS_NR, HV_SS_B1 through HV_SS_B4
**Generation (8):**
- LV_GEN_AGG, LVS_GEN_AGG, LV_GEN_SS, LVS_GEN_SS, HV_GEN_SS
- Plus NRP (No RP Charge) variants
**Unmetered (1):**
- UMS - Unmetered Supplies
This standardisation makes it much easier to understand and compare distribution charges across regions. The same tariff category means the same thing whether you're in London (DNO 12) or the Scottish Highlands (DNO 17) - only the actual rates differ.
Example: ND_AGG_B2 = Non-Domestic Aggregated Band 2 (100-499 kVA agreed capacity)
Related Terms: DCUSA, DUoS, LLFC, Tariff Category
Ofgem (Office of Gas and Electricity Markets)
Definition: The independent regulator for gas and electricity markets in Great Britain, responsible for protecting consumers and ensuring energy networks operate fairly and efficiently.
Ofgem oversees the energy industry, from setting price controls that determine how much network companies can charge, to licensing suppliers and network operators, to investigating complaints and enforcing rules.
**Key regulatory activities:**
- Setting RIIO (Revenue = Incentives + Innovation + Outputs) price controls for DNOs
- Approving charging methodologies (CDCM, TNUoS, BSUoS)
- Licensing suppliers and network operators
- Investigating supplier compliance
- Managing supplier of last resort when companies fail
- Administering exemption schemes (e.g., Climate Change Agreements for CCL relief)
**Major Ofgem-driven reforms:**
- Targeted Charging Review (TCR) - restructured TNUoS charges
- MHHS oversight - Market-wide Half-Hourly Settlement
- Access and Forward-Looking Charges - future distribution charging
**For consumers:**
If you have a serious complaint about your energy supplier or network operator that can't be resolved directly, Ofgem is ultimately responsible for ensuring companies meet their licence obligations. However, for most billing disputes, you'd first go through your supplier and then the Energy Ombudsman before Ofgem involvement.
Related Terms: DCUSA, DNO, CDCM, TCR
CUSC (Connection and Use of System Code)
Definition: The industry code that governs access to and charging for the national transmission network - it defines how TNUoS charges are calculated and the rules for connecting large generators and supplies.
While DCUSA governs the distribution network, CUSC governs the transmission network - the high-voltage backbone that carries electricity across Great Britain. It's the rulebook for how generators and large customers connect to and pay for using the transmission system.
**What CUSC covers:**
- Connection arrangements for large generators and demand
- Transmission Network Use of System (TNUoS) charging methodology
- Balancing Services Use of System (BSUoS) methodology
- Rights and obligations of transmission users
- Change process for transmission-related modifications
**CUSC Modifications Process:**
When changes to transmission charging are needed, they go through a formal CUSC Modification Proposal (CMP) process. Major recent modifications include:
- **CMP361** - Fixed BSUoS tariffs from April 2023
- **CMP343** - Changes supporting the Targeted Charging Review
**Why CUSC matters:**
The TNUoS and BSUoS charges on your bill are calculated according to methodologies defined in CUSC. Understanding the code helps explain why charges work the way they do - for example, why TNUoS varies by location (14 zones) or why BSUoS is now a fixed rate.
**Governance:**
CUSC is governed by a panel with representatives from generators, suppliers, network operators, and consumers. Ofgem has ultimate authority to approve or reject modifications.
Related Terms: TNUoS, BSUoS, National Grid ESO, CMP361
BSC (Balancing and Settlement Code)
Definition: The industry code that governs how electricity supply and demand is balanced and settled financially - administered by Elexon, it defines how meters are registered and consumption is allocated.
The Balancing and Settlement Code (BSC) is the central rulebook for electricity trading and settlement in Great Britain. It defines how the electricity market operates minute-by-minute and how financial settlement occurs between generators, suppliers, and the system operator.
**What BSC covers:**
- Electricity trading arrangements
- Imbalance settlement (when actual differs from contracted)
- Meter registration and data collection
- Profile class definitions and coefficients
- Data flows between market participants (D0018, D0019, etc.)
**Key BSC concepts:**
- **Imbalance** - Difference between contracted and actual volumes
- **System prices** - The price for settling imbalances
- **Profile coefficients** - How NHH consumption is estimated by half-hour
- **Settlement periods** - The 48 half-hours in each day
**BSC Change Proposals:**
Changes to the BSC go through a formal Change Proposal (CP) process. Important recent changes include:
- **CP1434** - Introduced alphanumeric LLFC codes (June 2016)
- **P432** - Market-wide Half-Hourly Settlement (MHHS)
**Why BSC matters for bill validation:**
The D0018 data flows (profile coefficients) that EnergyCode uses to estimate when non-half-hourly customers use electricity are defined and managed under BSC.
Related Terms: Elexon, MHHS, Half-Hourly Metered, Profile Class
RIIO (Revenue = Incentives + Innovation + Outputs)
Definition: Ofgem's price control framework that determines how much network operators can charge - it sets revenue allowances and incentivises efficiency, innovation, and customer service over 5-year periods.
RIIO is the regulatory framework Ofgem uses to control the revenues of electricity and gas network companies. It replaced the previous RPI-X framework and runs in multi-year periods, currently RIIO-ED2 (2023-2028) for electricity distribution.
**How RIIO works:**
- **Revenue allowance** - Ofgem sets the total revenue each network can recover
- **Incentive mechanisms** - Networks can earn more (or less) based on performance
- **Innovation funding** - Dedicated allowances for network innovation projects
- **Output targets** - Service quality, reliability, and customer satisfaction metrics
**Current price control periods:**
- RIIO-ED1 (2015-2023) - Electricity Distribution (completed)
- RIIO-ED2 (2023-2028) - Electricity Distribution (current)
- RIIO-T2 (2021-2026) - Transmission
**Why RIIO matters for your bills:**
The RIIO framework ultimately determines the total pot of money that DNOs can recover through DUoS charges. When you see year-on-year changes in distribution charges, these largely reflect Ofgem's RIIO determinations about what network investment is needed and what return companies should earn.
**ED2 priorities:**
The current RIIO-ED2 period focuses heavily on preparing networks for net zero, including EV charging infrastructure, heat pump connections, and accommodating more distributed generation.
Related Terms: Ofgem, DNO, DUoS, DCUSA
Billing Concepts
Terminology specific to energy billing and settlement processes.
Supercustomer
Definition: A billing arrangement where a large energy supplier receives aggregated bills from DNOs for all their customers, then passes these charges through to end customers.
Under the Supercustomer arrangement, DNOs bill energy suppliers for all their customers' DUoS charges in aggregate, rather than billing each end customer directly. This is the standard arrangement for most business electricity customers.
**How it works:**
1. DNO calculates DUoS charges for all meters supplied by each supplier
2. DNO sends aggregated bill to supplier monthly
3. Supplier pays DNO
4. Supplier recovers DUoS from end customers (often bundled into unit rates)
**Advantages:**
- Simplifies administration for large portfolios
- Single relationship for customers (with supplier, not DNO)
- Suppliers can offer bundled pricing
**Why it matters:**
This is why DUoS appears as a line item on your supplier bill rather than coming directly from the DNO. It also means your supplier is responsible for applying the correct tariff - and where billing errors can occur.
Related Terms: DNO, DUoS, Settlement
Half-Hourly Metered (HH)
Definition: Electricity meters that record consumption every 30 minutes, providing actual usage data rather than estimated profiles.
Half-hourly (HH) metered supplies record exactly how much electricity is consumed in each 30-minute period. This is in contrast to non-half-hourly (NHH) meters which only record total consumption and rely on profile estimation.
**Who has HH metering:**
- All supplies over 100kW (mandatory)
- Profile Classes 05-08 and 00
- CT (Current Transformer) metered supplies
- Any supply with an advanced/smart meter collecting HH data
**Why HH metering matters:**
- Actual time-of-use data for Red/Amber/Green billing
- Subject to Capacity Market charges
- May face reactive power charges
- More accurate bills (no profile estimation)
- Required for certain industry charges
**Post-MHHS:**
After Market-wide Half-Hourly Settlement, all smart meters will be settled on actual HH data, even if they're currently treated as NHH. This will make HH settlement the norm rather than the exception.
Related Terms: Profile Class, MHHS, Time Bands, Smart Meter
Pass-Through Charges
Definition: Network and third-party charges that your supplier collects on behalf of other organisations and passes directly to you without markup - these include DUoS, TNUoS, BSUoS, and levies.
Pass-through charges are costs that your energy supplier doesn't control - they simply collect them from you and pass them on to the relevant network operators or levy administrators. Understanding these charges is key to identifying billing errors.
**Common pass-through charges:**
- **DUoS** - Passed to your regional DNO
- **TNUoS** - Passed to National Grid ESO
- **BSUoS** - Passed to National Grid ESO
- **Capacity Market** - Passed to LCCC
- **CfD Levy** - Passed to LCCC
- **CCL** - Passed to HMRC
**How pass-through appears on bills:**
On "pass-through" or "cost-plus" contracts, these charges appear as separate line items. On "fixed price" contracts, they're bundled into your unit rate and you may not see them itemised.
**Why pass-through contracts matter:**
- **Transparency** - You can see exactly what you're paying for each charge
- **Risk transfer** - You bear the risk of rate changes, not the supplier
- **Validation opportunity** - Separate line items can be checked against published rates
**Validation with EnergyCode:**
This is exactly where EnergyCode adds value. Each pass-through charge has published rates and methodologies - we calculate what you should pay and compare it to what's on your bill.
Example: Invoice shows: DUoS £1,250, TNUoS £380, BSUoS £156, CCL £387 (all pass-through)
Related Terms: DUoS, TNUoS, BSUoS, Supercustomer
Billing Period
Definition: The date range covered by an electricity invoice - typically monthly, but can span different periods. Accurately counting days is essential for validating fixed and capacity charges.
The billing period defines the start and end dates covered by your invoice. While this seems simple, it's crucial for accurate bill validation - fixed charges and capacity charges are calculated per day, so the number of days directly affects the amount.
**Why billing periods matter:**
- **Fixed charges** = Rate x Days in period
- **Capacity charges** = Rate x kVA x Days in period
- **Cross-year billing** - Periods spanning rate changes need pro-rata calculation
**Common billing period issues:**
- **Day count errors** - Invoice calculates 30 days but period covers 31
- **Rate change handling** - April rate changes not applied correctly mid-period
- **Overlap/gaps** - Consecutive invoices that double-count or miss days
**How EnergyCode handles billing periods:**
When you enter a billing period, EnergyCode:
1. Counts the correct number of days (inclusive vs exclusive dates)
2. Identifies if the period spans a rate change (typically 1 April)
3. Applies pro-rata calculation if rates changed mid-period
4. Flags any discrepancies with your invoice
**Cross-year example:**
A billing period of 15 March to 14 April spans the 1 April rate change. EnergyCode calculates:
- 17 days at 2024-25 rates
- 14 days at 2025-26 rates
- Weighted average for comparison
Example: Billing period: 1 March 2025 - 31 March 2025 = 31 days
Related Terms: Fixed Charge, Capacity Charges, DUoS
CT Metered (Current Transformer Metered)
Definition: Larger electricity supplies measured using current transformers - these meters can handle higher loads and provide half-hourly readings required for accurate billing of larger sites.
Current Transformer (CT) metering is used for larger electricity supplies where the current is too high for a standard meter. CTs step down the current to a measurable level while maintaining accurate proportional readings. This type of metering is standard for supplies above 70kW.
**What makes CT metering different:**
- Can measure very high currents (hundreds or thousands of amps)
- Provides half-hourly (HH) consumption data
- Required for Profile Classes 05-08 and mandatory above 100kW
- Typically has both import and (potentially) export capability
- Records kWh, kVA, and kVArh for complete consumption picture
**CT metering and charges:**
Supplies with CT metering typically face:
- Site Specific tariffs (LV_SS, LVS_SS, HV_SS) rather than Aggregated
- Capacity charges based on agreed kVA
- Potential reactive power charges if power factor is poor
- Capacity Market obligations
- More complex DUoS calculations
**Why CT metering matters for validation:**
CT metered supplies have actual half-hourly data, meaning:
- Exact Red/Amber/Green consumption split is known
- No profile estimation needed
- More precise validation possible
- But also more ways for billing errors to occur
**CT ratio:**
The CT ratio (e.g., 200:5) indicates how the measured current relates to actual current. Bills should reflect actual consumption, not CT secondary values.
Example: CT Metered supply with 200:5 ratio measuring 400A peak = 16kVA at that moment
Related Terms: Half-Hourly Metered, Capacity Charges, Reactive Power, Profile Class
Annexe 2
Definition: The DNO publication containing site-specific EDCM tariffs for Extra High Voltage connections - each EHV site has its own entry with individually calculated charges.
Annexe 2 is part of each DNO's annual Charging Statement that contains the site-specific tariffs for EDCM (Extra High Voltage) connections. While Annexe 1 contains standard CDCM tariffs that apply to categories of customers, Annexe 2 lists individual tariffs for each EHV site.
**What Annexe 2 contains:**
- Import capacity charges (p/kVA/day)
- Export capacity charges (p/kVA/day)
- Exceeded capacity rates
- Super Red unit rates (p/kWh)
- Fixed charges (p/MPAN/day)
- Reactive power charges (p/kVArh)
**Site identification:**
Each site is listed by MPAN or site reference, with its own unique set of charges calculated using the DNO's network model. This means two EHV sites in the same DNO region can have completely different tariffs based on their location and network impact.
**Publication cycle:**
Like all DUoS tariffs, Annexe 2 is updated annually with new rates effective from 1 April each charging year. DNOs publish draft rates in autumn for consultation before finalising.
**Why site-specific:**
Unlike lower voltage connections where costs can be averaged across similar customers, EHV sites have such individual network characteristics that bespoke pricing is more cost-reflective.
Related Terms: EDCM, Annexe 3, Charging Statement, DUoS
Annexe 3
Definition: The DNO publication containing preserved CDCM tariffs for closed LLFCs - legacy tariff categories that no longer accept new connections but still apply to existing supplies.
Annexe 3 contains tariffs for "closed" LLFC codes - legacy tariff categories that are no longer assigned to new connections but still apply to existing meter points. These preserved tariffs ensure existing customers continue to be billed correctly even though their LLFC code is no longer in active use.
**Why Annexe 3 exists:**
Over time, DNOs rationalise their LLFC codes, closing old codes and directing new connections to standardised alternatives. However, existing supplies retain their original LLFC, so the tariffs must continue to be published.
**What Annexe 3 contains:**
The same rate components as standard CDCM tariffs:
- Red, Amber, Green unit rates (p/kWh)
- Fixed charges (p/MPAN/day)
- Capacity charges (p/kVA/day)
- Reactive power charges (p/kVArh)
**Closed vs Open LLFCs:**
- **Open LLFCs** (in Annexe 1): Currently assignable to new connections
- **Closed LLFCs** (in Annexe 3): No longer issued but still valid for existing supplies
**Important for bill validation:**
If your MPAN has a closed LLFC, your tariff rates are in Annexe 3, not Annexe 1. Using rates from the wrong annexe would result in incorrect validation.
Related Terms: LLFC, Annexe 2, CDCM, Tariff Category
Annex 1
Definition: The section of DNO charging statements containing CDCM tariff rates - 32 tariff categories with 7 charge components each (Red/Amber/Green rates, fixed charge, capacity charge, exceeded capacity, reactive power).
Annex 1 is the primary source of CDCM (Common Distribution Charging Methodology) tariff data within each DNO's annual charging statement. It contains the 32 standardised tariff categories used across all 14 GB DNOs since April 2022.
**What Annex 1 contains:**
For each of the 32 CDCM tariff categories, Annex 1 publishes 7 charge components:
- **Red Rate** (p/kWh) - Peak period unit charge
- **Amber Rate** (p/kWh) - Shoulder period unit charge
- **Green Rate** (p/kWh) - Off-peak unit charge
- **Fixed Charge** (p/MPAN/day) - Daily standing charge
- **Capacity Charge** (p/kVA/day) - Based on agreed capacity
- **Exceeded Capacity** (p/kVA/day) - Penalty for exceeding agreed capacity
- **Reactive Power** (p/kVArh) - Charge for poor power factor
**Annex 1 vs Annex 3:**
- **Annex 1** contains active/open tariffs that can be assigned to new connections
- **Annex 3** contains preserved/legacy tariffs for closed LLFC codes
**Publication cycle:**
Annex 1 tariffs are updated annually, typically effective from 1 April of each charging year. DNOs publish draft rates in autumn for consultation before finalising.
**Why Annex 1 matters:**
This is the authoritative source for validating DUoS charges on business electricity bills. If your bill shows different rates than those published in your DNO's Annex 1 for your tariff category, that's a billing error.
Related Terms: CDCM, Annexe 3, Charging Statement, DUoS, Tariff Category
Annex 6
Definition: Quarterly addenda to DNO charging statements containing new or amended EHV site tariffs - if a site appears in both Annex 2 and Annex 6, the Annex 6 rates take precedence.
Annex 6 contains quarterly updates to EDCM (EHV) tariffs published between annual charging statement releases. While Annex 2 is published once a year (effective 1 April), Annex 6 addenda are published throughout the year to reflect changes.
**Why Annex 6 exists:**
The electricity network constantly evolves - new EHV sites connect, existing sites modify their capacity, and tariff corrections may be needed. Rather than wait for the next annual charging statement, DNOs publish Annex 6 addenda to keep tariffs current.
**What Annex 6 contains:**
- **New site tariffs** - Sites that connected after the annual Annex 2 was published
- **Amended tariffs** - Corrections to existing site tariffs
- **Capacity changes** - Updated tariffs when sites change their agreed capacity
- All the same charge components as Annex 2 (Super Red rates, fixed adders, capacity charges, etc.)
**Precedence rules:**
When a site appears in both Annex 2 and Annex 6, the Annex 6 rates take precedence. This is critical for bill validation - using the older Annex 2 rates when an Annex 6 update exists would result in incorrect calculations.
**Publication cycle:**
DNOs publish Annex 6 addenda quarterly, though the exact timing varies by DNO. EnergyCode monitors all 14 DNOs weekly for new Annex 6 publications.
**Why Annex 6 matters:**
For accurate EHV bill validation, you must check both Annex 2 and any subsequent Annex 6 addenda. Missing an Annex 6 update could mean validating against outdated rates.
Related Terms: EDCM, Annexe 2, Charging Statement, DUoS
Industry Reforms
Major regulatory and market changes shaping the future of electricity billing.
MHHS (Market-wide Half-Hourly Settlement)
Definition: A major industry reform that moves all electricity meters to actual half-hourly readings instead of estimated usage profiles, rolling out from September 2025 to May 2027.
Historically, only large business meters recorded exactly when electricity was used in 30-minute intervals. Everyone else had their usage estimated from typical patterns for their customer type. MHHS changes this: in time, all meters (including domestic smart meters) settle on actual half-hourly data.
**Timeline:**
- **22 September 2025** - Go-live. Industry code changes take effect and the supply number format moves to 22 digits.
- **22 October 2025** - First meter migrations begin.
- **28 October 2026** - Target for all suppliers to be qualified to operate under MHHS.
- **7 May 2027** - Target for all meters migrated to half-hourly settlement.
**What's changing:**
- Settlement uses actual half-hourly consumption instead of estimated profiles
- The profile-estimation system (D0018 coefficients) is replaced by the Load Shaping Service
- Migrated meters move to Profile Class 00
- The supply number gains a digit as the 3-digit MTC becomes the 4-digit SSC
- The LLFC field on the supply number becomes the DUoS Tariff ID (charging), with a separate LLF ID used for losses in settlement
**What's NOT changing:**
- The Distributor ID still identifies your DNO region
- DUoS tariff categories, time bands and rate structures stay the same
- At go-live the DUoS Tariff ID is identical to the existing LLFC, so charge lookups are unaffected
The practical effect for organisations is that settlement, and increasingly the time-of-use signals in your charges, reflect when electricity is actually used, not just how much.
Related Terms: Profile Class, Half-Hourly Metered, SSC, DUoS Tariff ID, Load Shaping Service, MHHS Timeline
TCR (Targeted Charging Review)
Definition: A major reform from April 2023 that changed how network costs are recovered - replacing the old "Triad" system (which rewarded usage reduction during peak winter periods) with fixed capacity bands.
Before the Targeted Charging Review, large businesses could significantly reduce their TNUoS transmission charges through "Triad avoidance" - cutting electricity usage during the three highest-demand half-hours each winter. This created a cottage industry of Triad warning services and demand management, but Ofgem concluded it was unfair, as avoided costs were simply shifted to other customers.
**What TCR changed:**
**Before TCR (pre-April 2023):**
- Triad-based charging for TNUoS
- Businesses could dramatically reduce costs through Triad avoidance
- Unpredictable costs dependent on winter demand peaks
- Industry of Triad warning services
**After TCR (April 2023 onwards):**
- Fixed Transmission Demand Residual (TDR) bands
- ~88-100% of TNUoS recovered through fixed charges
- Only small locational element remains variable
- Predictable, unavoidable costs based on capacity band
**Impact:**
For businesses that previously benefited from Triad management, TCR increased their costs. For those who didn't engage in avoidance, it often reduced costs slightly. The reform made costs more predictable and removed the operational complexity of responding to Triad warnings.
Related Terms: TNUoS, Triad, National Grid ESO, Ofgem
CMP361 (Connection and Modification Proposal 361)
Definition: A reform from April 2023 that made grid balancing costs (BSUoS) predictable by fixing rates six months in advance and recovering 100% from electricity consumers rather than splitting costs with generators.
CMP361 was an industry modification that reformed how Balancing Services Use of System (BSUoS) charges work. Before this change, BSUoS rates varied every half-hour based on the actual costs of balancing the grid that day - making them unpredictable and adding complexity to energy pricing.
**Three major changes from CMP361:**
**1. Fixed rates:**
- BSUoS now fixed for six-month periods (April-September, October-March)
- Rates published well in advance for budgeting
- No more half-hourly volatility
**2. Demand-only recovery:**
- Previously 50/50 split between generators and demand
- Now 100% recovered from demand customers
- Approximately doubled the per-kWh rate
**3. Predictable costs:**
- Suppliers and customers can budget with confidence
- Removed uncertainty and risk premiums from contracts
- Simpler billing calculations
**Impact:**
The actual cost level depends on system conditions, but knowing the rate in advance makes budgeting more straightforward. While rates approximately doubled due to the 100% demand recovery shift, this was partially offset by reduced risk premiums in wholesale contracts.
Example: CMP361 fixed BSUoS: October 2025 - March 2026 = 1.569 p/kWh
Related Terms: BSUoS, National Grid ESO, TCR
Triad (Three Peak Periods)
Definition: The historic system (pre-April 2023) where TNUoS charges were based on demand during the three highest half-hours each winter - now largely replaced by fixed TDR bands following the Targeted Charging Review.
Triads were the three half-hour periods of highest national electricity demand each winter, used to calculate TNUoS transmission charges for half-hourly metered customers. This system was replaced by fixed TDR bands in April 2023 following the Targeted Charging Review.
**How Triads worked:**
- Three highest demand half-hours between November and February
- Each Triad had to be at least 10 days apart
- Your TNUoS charge was based on your demand during these three periods
- Final Triads only known after winter ended
**The Triad avoidance industry:**
Because charges were based on just three half-hours, businesses could dramatically reduce costs by:
- Subscribing to Triad warning services
- Reducing demand when warned of potential Triad periods
- Installing on-site generation or storage
- Demand response agreements
**Why Triads were replaced:**
Ofgem concluded the system was:
- Unfair - avoided costs shifted to other customers
- Inefficient - created artificial demand patterns
- Unpredictable - costs only known after the fact
**Post-TCR (April 2023):**
- Fixed Transmission Demand Residual (TDR) bands replaced Triad-based charging
- Charges based on agreed capacity, not peak demand
- ~88-100% of TNUoS now recovered through fixed charges
**Legacy relevance:**
While Triads no longer drive charges for most customers, understanding them helps explain historical bills and why TCR was implemented.
Example: Pre-2023: Your Triad demand of 500kW x £50/kW zone rate = £25,000 TNUoS/year
Related Terms: TCR, TNUoS, National Grid ESO, Half-Hourly Metered
TDR (Transmission Demand Residual)
Definition: Fixed daily charges for TNUoS introduced in April 2023, replacing the variable Triad-based system - your band (1-4) is determined by your Maximum Import Capacity (MIC) and voltage level.
The Transmission Demand Residual (TDR) is the main component of TNUoS charges since the Targeted Charging Review (April 2023). It replaced the old Triad-based system with fixed daily charges based on capacity bands.
**How TDR Actually Works:**
TDR uses **4 bands per voltage level**, with band determined by your Maximum Import Capacity (MIC) agreed with your DNO. Band thresholds are set by NESO using percentiles (40th, 70th, 85th) of GB-wide capacity data.
**Current RIIO-2 Thresholds (April 2023 - March 2026):**
| Voltage | Band 1 | Band 2 | Band 3 | Band 4 |
|---------|--------|--------|--------|--------|
| LV | ≤80 kVA | 81-150 | 151-231 | >231 |
| HV | ≤422 kVA | 423-1,000 | 1,001-1,800 | >1,800 |
| EHV | ≤5,000 kVA | 5,001-12,000 | 12,001-21,500 | >21,500 |
*LV No MIC sites are banded by annual consumption (kWh) instead.*
**RIIO-3 Changes (April 2026 - March 2031):**
Rates nearly double AND thresholds shift:
| Voltage | Band 1 | Band 2 | Band 3 | Band 4 |
|---------|--------|--------|--------|--------|
| LV | ≤90 kVA | 91-150 | 151-250 | >250 |
| HV | ≤500 kVA | 501-1,100 | 1,101-2,000 | >2,000 |
| EHV | ≤3,500 kVA | 3,501-11,000 | 11,001-20,000 | >20,000 |
**Critical Warning:** EHV thresholds **decrease** in RIIO-3. An EHV site with 4,000 kVA capacity will automatically move from Band 1 to Band 2, potentially increasing TNUoS costs by 767%.
**The MIC Optimization Opportunity:**
Many businesses historically over-specified their MIC for headroom. Under TDR, this means paying more than necessary. If your actual maximum demand is well below your MIC, you may be able to review your demand data, request an MIC reduction from your DNO, and move to a lower TDR band.
**Why April 2026 Matters:** RIIO-3 rate increases are substantial. EHV sites between 3,500-5,000 kVA will automatically move up a band. Businesses should review their MIC now to plan reductions before the new period.
Example: HV site with 600 kVA MIC = HV Band 2 (RIIO-2). Daily TDR charge approximately 450p/day = approximately 1,640/year
Related Terms: TCR, TNUoS, Capacity Charges, Triad, RIIO, MIC
Access Reform (Access SCR)
Definition: Ofgem's ongoing review of how network access is defined and charged - aims to make charges more cost-reflective and facilitate the transition to net zero.
The Access and Forward-Looking Charges Significant Code Review is Ofgem's programme to reform how network access is defined, allocated, and priced. It's still in development and will significantly change distribution charging when implemented.
**What Access Reform addresses:**
- How connection capacity is defined and allocated
- Whether charges should better signal network costs
- How to facilitate flexible connections and storage
- Fair charging for distributed generation
- Network investment signals for net zero
**Key concepts being explored:**
**1. Access rights:**
- Moving from "firm" connections (guaranteed access) to more flexible arrangements
- Time-of-use access that varies by network conditions
- Interruptible connections at lower cost
**2. Forward-looking charges:**
- Charges that signal future network investment needs
- Location-specific signals to encourage development where capacity exists
- Time-varying charges reflecting network congestion
**3. Residual charges:**
- Following TCR principles from transmission to distribution
- Fixed charges based on capacity bands
- Reducing ability to avoid fair share of network costs
**Timeline:**
- Ongoing consultation and code drafting
- Expected implementation in RIIO-ED2 period (2023-2028)
- Significant industry engagement required
**Why this matters:**
Access Reform will likely change how DUoS charges are structured and calculated. EnergyCode will need to adapt when these changes are implemented, but currently all validation uses the existing CDCM methodology.
Related Terms: CDCM, Ofgem, TCR, RIIO
MHHS Timeline
Definition: The phased schedule for Market-wide Half-Hourly Settlement, running from go-live on 22 September 2025 to all meters migrated by 7 May 2027.
Market-wide Half-Hourly Settlement is not a single switch-on. It is a multi-year migration managed by Elexon as programme manager, with industry-wide milestones. Knowing where the programme sits helps explain why some meters already settle half-hourly while others still use estimated profiles.
**Key milestones:**
| Milestone | Date | What happens |
|-----------|------|--------------|
| Go-live | 22 Sep 2025 | Industry code changes take effect; supply number format moves to 22 digits |
| First migrations | 22 Oct 2025 | Suppliers begin moving meters to half-hourly settlement |
| Load Shaping Service live | Oct 2025 | Replaces D0018 profile coefficients for load shapes |
| All suppliers qualified | 28 Oct 2026 | Target for every supplier qualified to operate under MHHS |
| All meters migrated | 7 May 2027 | Target for the full meter population on half-hourly settlement |
| Shortened settlement | 2 Jul 2027 | The reconciliation timetable shortens |
**Why it runs in phases:**
Around 30 million meters must move without disrupting settlement. Suppliers qualify, then migrate portfolios in tranches. During the transition, legacy and MHHS reference data coexist, which is why systems must handle both 21 and 22-digit supply numbers.
**The practical read:**
Until a meter migrates, it still settles on estimated profiles and keeps its legacy Profile Class. After migration it moves to Profile Class 00 and settles on actual half-hourly data. Reconciliation of pre-migration periods continues for months after, so legacy reference data stays relevant into 2028.
Related Terms: MHHS, Load Shaping Service, Profile Class, SSC, 22-Digit MPAN
Load Shaping Service
Definition: The Elexon service that derives half-hourly load shapes from actual metered data under MHHS, replacing the old D0018 statistical profile coefficients.
Before MHHS, the half-hourly shape of a non-half-hourly meter's consumption was estimated using statistical profiles published as D0018 profile coefficients. The Load Shaping Service is the MHHS replacement. It went live in October 2025.
**What it does:**
Rather than applying a fixed statistical profile for a customer type, the Load Shaping Service builds load shapes from real settlement data. As more meters settle on actual half-hourly readings, the shapes used for any remaining estimation reflect observed behaviour, not historic assumptions.
**Why it replaced D0018:**
- D0018 coefficients were produced by Elexon's Profile Administration Service, which is being decommissioned through MHHS (supplier sampling submissions ceased late 2024)
- Statistical profiles averaged individual behaviour into broad customer-type shapes
- Actual half-hourly data is far more accurate for settlement
**What it means in practice:**
The Load Shaping Service is settlement infrastructure, not something that appears on a charge breakdown. Its significance is that the long-standing D0018 profiling approach is being retired. D0018 data remains needed for reconciling pre-migration periods through to around 2028, after which it can be archived.
Related Terms: MHHS, Profile Coefficients, Profile Class, Half-Hourly Metered
ISD (Industry Standing Data)
Definition: Industry Standing Data is the MHHS-era reference dataset that replaces Market Domain Data (MDD), holding the valid codes and configurations systems use to validate MPANs and process settlement.
Industry Standing Data (ISD) is the reference data backbone for the MHHS world. It replaces Market Domain Data (MDD), the long-standing dataset of valid market codes and combinations that systems relied on for validation and settlement.
**ISD vs MDD:**
| | MDD (legacy) | ISD (MHHS) |
|--|--------------|------------|
| Role | Valid combinations, reference codes | Same role, MHHS-era model |
| Status | Frozen, retained around 5 years (to ~Sep 2030) | Live, versioned catalogues |
| Cadence | Periodic releases | More frequent releases during transition |
| Source | Elexon | Elexon ISD Data Store |
**Why both exist at once:**
During the migration, some meters are settled the legacy way and some under MHHS. Systems therefore need legacy MDD codes and new ISD entities at the same time. MDD is frozen rather than deleted so historic reconciliation still works.
**What ISD contains:**
Distributor configurations, valid DUoS Tariff ID and loss-factor combinations per distributor, settlement segment definitions, and participant reference data. Early ISD releases had documented quality issues, which is why clean, structured reference data is in demand across the industry.
**Note on SSC and TPR:**
SSC-to-TPR mappings do not sit in ISD. They are maintained on the REC Portal as the enduring source for MHHS supply numbers.
Related Terms: MHHS, DUoS Tariff ID, SSC, Elexon
REMA (Review of Electricity Market Arrangements)
Definition: The UK Government's wholesale review of how the GB electricity market is designed, whose outcome will shape future network charging reform including DUoS.
The Review of Electricity Market Arrangements (REMA) is a Government-led programme, run by DESNZ, examining how the GB electricity market should work as the system decarbonises. It is broader than any single charge: it looks at wholesale market design, locational signals, and how costs are allocated.
**Why it matters for network charges:**
Ofgem has stated it will not prioritise reform of distribution charging (DUoS) until the direction of REMA is clearer. Several charging reforms are effectively waiting on REMA's outcome:
- Distribution charging (DUoS) reform is on hold pending REMA direction
- Transmission charging (TNUoS) reform is being designed, with delivery targeted around 2029
- Ofgem's wider Energy Cost Allocation and Recovery review feeds into the same picture
**Where it stands:**
REMA is still in development, with periodic Government updates rather than a single decision. No charging methodology has changed because of REMA yet. The current CDCM distribution charging methodology and the post-TCR transmission arrangements remain in force.
**The practical read:**
REMA is a leading indicator, not a live change. It signals that the structure of network charges could shift later this decade, but today's charges are still calculated under the existing methodologies.
Related Terms: Access Reform, TCR, CDCM, Ofgem, TDR
Gas Networks
Terminology for GB gas distribution networks, metering, and transportation charges.
GDN (Gas Distribution Network)
Definition: One of the four regional companies that own and operate the gas pipes delivering gas from the National Transmission System to homes and businesses.
Great Britain has 4 Gas Distribution Networks (GDNs), which are the gas equivalent of electricity DNOs. Each GDN operates one or more Local Distribution Zones (LDZs) and is responsible for maintaining the gas pipes, responding to gas leaks (call 0800 111 999), and connecting new supplies.
**The 4 GDNs:**
| GDN | LDZs Operated | Coverage |
|-----|--------------|----------|
| Cadent | EA, EM, NT, NW, WM | East Anglia, East Midlands, North Thames, North West, West Midlands |
| Northern Gas Networks (NGN) | NE, NO | Northern England, Yorkshire |
| SGN | SC, SE, SO | Scotland, South East, Southern |
| Wales & West Utilities (WWU) | SW, WN, WS | South West, Wales North, Wales South |
Unlike electricity (where you cannot choose your DNO), your GDN is determined by your location. The GDN charges gas transportation charges that appear on your gas bill, similar to how DNOs charge DUoS for electricity.
**Key difference from electricity:**
The MPRN (gas meter number) does not encode the region like an MPAN does for electricity. To determine which GDN serves a gas meter, you need to look up the postcode.
Related Terms: LDZ, MPRN, DNO, Xoserve
LDZ (Local Distribution Zone)
Definition: One of 13 geographic regions within the gas distribution network, each with its own transportation charge rates.
Local Distribution Zones (LDZs) are the gas equivalent of DNO regions for electricity. Great Britain is divided into 13 LDZs, each operated by one of the 4 GDNs. Gas transportation charges vary by LDZ, similar to how DUoS rates vary by DNO region.
**The 13 LDZs:**
| LDZ Code | Name | Operator |
|----------|------|----------|
| EA | East Anglia | Cadent |
| EM | East Midlands | Cadent |
| NE | North East | NGN |
| NO | Northern | NGN |
| NT | North Thames | Cadent |
| NW | North West | Cadent |
| SC | Scotland | SGN |
| SE | South East | SGN |
| SO | Southern | SGN |
| SW | South West | WWU |
| WM | West Midlands | Cadent |
| WN | Wales North | WWU |
| WS | Wales South | WWU |
**Important difference from electricity:**
Unlike electricity MPANs which encode the DNO region in the Distributor ID, gas MPRNs do not encode the LDZ. To determine which LDZ a gas meter belongs to, you must look up the postcode. This is why gas validation often requires the meter's postcode.
Example: A gas meter in Manchester would be in the NW (North West) LDZ, operated by Cadent.
Related Terms: GDN, MPRN, DNO
MPRN (Meter Point Reference Number)
Definition: A unique 6 to 11 digit number identifying a gas meter point in Great Britain.
The MPRN (Meter Point Reference Number) is the gas equivalent of an MPAN for electricity. Every gas supply point in Great Britain has a unique MPRN that identifies it in industry systems.
**Key facts about MPRNs:**
- 6 to 11 digits long (most commonly 10 digits)
- Unique to each gas supply point
- Does NOT encode region information (unlike electricity MPANs)
- IGT (Independent Gas Transporter) MPRNs start with 74, 75, 76, or 77
- Found on gas bills and meter documentation
**Structure differences from MPAN:**
While an electricity MPAN contains encoded information (DNO region, LLFC, Profile Class, etc.), an MPRN is simply a unique identifier. To determine the GDN region, LDZ, or any other information about a gas supply point, you need to look up the MPRN in industry databases or use the postcode.
**Where to find your MPRN:**
- Gas bills (usually near the meter serial number)
- Welcome pack from your gas supplier
- The gas meter itself (sometimes)
- By calling your gas supplier
**Validation:**
MPRNs can be validated by checking:
- Length (6-11 digits)
- All numeric characters
- Exists in Xoserve's central database
Example: MPRN 1234567890 identifies a specific gas supply point.
Related Terms: MPAN, GDN, LDZ, Xoserve
AQ (Annual Quantity)
Definition: The estimated annual gas consumption for a supply point, used to determine which transportation charge bands apply.
Annual Quantity (AQ) is a gas-specific concept that represents the estimated annual consumption for a gas supply point, measured in kilowatt-hours (kWh). The AQ is used to determine which gas transportation charge rates apply.
**AQ band thresholds:**
| Band | AQ Range | Typical Use |
|------|----------|-------------|
| Small | < 73,200 kWh | Domestic, small commercial |
| Medium | 73,200 - 732,000 kWh | Medium commercial/industrial |
| Large | > 732,000 kWh | Large industrial |
**How AQ affects charges:**
- Sites below 73,200 kWh pay flat transportation rates
- Sites between 73,200 and 732,000 kWh have different charge structures including Customer Fixed charges
- Sites above 732,000 kWh use power function calculations based on SOQ
**AQ calculation:**
The AQ is calculated by the shipper (gas supplier) based on historical consumption, weather correction, and other factors. It's updated periodically and stored in Xoserve's central systems.
**Weather correction:**
Gas consumption varies significantly with temperature. The AQ is "weather corrected" to represent what consumption would be in a typical year, removing the effect of unusually warm or cold weather.
Example: A site with AQ of 500,000 kWh falls into the medium band and pays different rates than a small domestic site.
Related Terms: SOQ, GDN, LDZ, MPRN
SOQ (Supply Offtake Quantity)
Definition: The maximum daily gas consumption registered for a supply point, used to calculate capacity charges for larger sites.
Supply Offtake Quantity (SOQ) represents the maximum daily gas consumption that a supply point is registered to take from the network, measured in kilowatt-hours per day (kWh/day). For larger sites, transportation charges are calculated using the SOQ rather than flat rates.
**SOQ vs AQ:**
- **AQ** = Annual Quantity (total yearly consumption estimate)
- **SOQ** = Supply Offtake Quantity (maximum daily demand)
For larger sites (AQ > 732,000 kWh), some charges are calculated using a power function formula: rate = A x SOQ^B, where A and B are constants published by each GDN.
**When SOQ matters:**
- Large industrial sites with AQ > 732,000 kWh
- Sites needing to reserve significant network capacity
- Capacity charge calculations
**SOQ review:**
Sites can request an SOQ review if their actual peak demand has changed. Reducing SOQ can lower capacity charges, but the SOQ must still cover actual peak requirements to avoid interruption risk.
Example: A large industrial site with SOQ of 10,000 kWh/day uses the power function formula to calculate their capacity charges.
Related Terms: AQ, GDN, MPRN
Xoserve (Central Data Service Provider)
Definition: The organisation that manages central gas industry data systems, including meter registration, consumption data, and industry communications.
Xoserve is the Central Data Service Provider (CDSP) for the GB gas industry, performing a similar role to what Elexon does for electricity settlement. They operate the central systems that enable the gas market to function.
**Xoserve responsibilities:**
- Managing the UK Link system (central gas industry database)
- Processing meter readings and consumption data
- Managing gas supply point registration and switching
- Operating industry data flows between parties
- Maintaining MPRN registration
- Publishing market data and reports
**Key systems:**
- **UK Link** - The central gas industry system for registration, settlement, and communication
- **Gas Enquiry Service** - Lookup tool for MPRN and supply point information
- **Gemini** - System for daily energy balancing
**Who funds Xoserve:**
Xoserve is funded by the gas transporters (GDNs) and operates as a shared service for the whole industry. Their costs are ultimately recovered through transportation charges.
**Why Xoserve matters:**
To determine information about a gas supply point (LDZ, shipper, AQ, etc.), the authoritative source is Xoserve's UK Link system. Energy suppliers and industry parties query this system to validate supply points and process switches.
Related Terms: GDN, MPRN, Elexon, AQ
