Show me the money: settlement and markets

Settlement starts before the electricity is even generated. Every large generator connected to the transmission network must submit Physical Notifications (PNs) to the National Energy System Operator (NESO) before each half-hourly settlement period. A PN states how much power the generator expects to produce, typically based on their forward contract position and plant availability.

Final Physical Notifications

PNs are refined as the settlement period approaches. The Final Physical Notification (FPN) is the generator's last declaration of expected output, submitted at gate closure (one hour before the settlement period). The FPN is the baseline against which any balancing actions are measured. If a generator produces exactly its FPN, it has no balancing exposure. If it produces more or less, the difference is settled through the imbalance mechanism.

Bid-Offer pairs

Alongside their FPN, generators submit Bid-Offer pairs to the Balancing Mechanism(BM). An Offer is a price at which the generator is willing to increase output above its FPN. A Bid is a price at which the generator is willing to decrease output below its FPN. NESO uses these Bids and Offers to balance supply and demand in real time.

When demand exceeds supply, NESO accepts Offers (instructing generators to increase output) and pays the Offer price. When supply exceeds demand, NESO accepts Bids (instructing generators to decrease output) and receives the Bid price. The Bid-Offer mechanism operates continuously, with NESO issuing instructions every few seconds during periods of system stress.

The Balancing Mechanism in practice

The BM is not a market in the traditional sense - it is an administrative mechanism where NESO is the sole buyer and seller. Generators and large demand customers submit Bids and Offers, but they cannot choose their counterparty. NESO selects the most economically efficient combination of Bids and Offers to balance the system, subject to technical constraints (ramp rates, minimum stable generation, transmission congestion).

The data generated by the BM is enormous. Every Bid-Offer submission, every acceptance, every instruction to a generator, and every metered output is recorded and published by Elexon. This data is publicly available and forms the basis for real-time market analysis, academic research, and regulatory oversight. The BM also generates the System Buy Price and System Sell Price that drive imbalance settlement.

After the half-hour is over, three BSC agents process the data to determine who owes what. Each agent performs a distinct function, and the output of each feeds into the next.

Supplier Volume Allocation Agent (SVAA)

The SVAA operates at each of the approximately 350 Grid Supply Points (GSPs) across England, Wales, and Scotland. A GSP is the point where the transmission network connects to the distribution network. The SVAA takes all the metered consumption data for each supplier's customers within a GSP and allocates the total consumption to that supplier.

This allocation is crucial because wholesale electricity prices vary by GSP. The GSP Group Correction Factor accounts for distribution losses and unmetered supplies. Under the current profile-based settlement, the SVAA uses load profiles to estimate half-hourly consumption for non-half-hourly settled meters. Under MHHS, actual half-hourly data replaces profiles, dramatically improving allocation accuracy.

Settlement Administration Agent (SAA)

The SAA takes the SVAA's allocations and calculates each supplier's imbalance. For each half-hour at each GSP, the SAA compares the supplier's metered volume (from SVAA) against its contracted volume (from Forward Contract Notifications and accepted Bid-Offer volumes). The difference is the supplier's imbalance volume.

If the supplier consumed more than it contracted (it is “short”), it buys the shortfall at the System Buy Price (SBP). If it consumed less than it contracted (it is “long”), it sells the surplus at the System Sell Price (SSP). Elexon still names two prices because the cashflow direction differs, but current GB imbalance pricing uses a single price calculation, so SBP equals SSP in each Settlement Period. The price signal comes from the imbalance price itself, which reflects balancing actions and reserve scarcity, not from a fixed spread between the two named prices.

Funds Administration Agent (FAA)

The FAA takes the SAA's imbalance calculations and arranges the actual cash flows between BSC Trading Parties. The FAA calculates the net position of each party, issues payment instructions, and settles the cash. Settlement payments flow through a central clearing account, with the FAA ensuring that total credits equal total debits across the market.

The FAA also manages credit cover requirements. Each BSC Trading Party must maintain credit cover (a letter of credit or cash deposit) sufficient to cover its expected settlement exposure. Credit cover protects the market against default: if a supplier goes bust, the credit cover ensures that its settlement debts are paid. The calculation of required credit cover depends directly on settlement data accuracy - better data means more accurate exposure estimates, which means lower credit cover requirements.

The settlement timetable

Settlement does not produce a single final answer. Instead, it runs multiple times as more actual data becomes available:

SF (Initial Settlement), the first financial settlement run, currently at 16 Working Days after the settlement day. It uses the metered data available at that point and estimation where data is missing. The letters SF are a run code, not an abbreviation of “settlement final”: the final answer comes much later, at RF. Note also that the SF volume allocation run sits a day earlier, at 15 Working Days, which is where the widely repeated “settlement is 15 days” figure comes from.

Reconciliation runs, which update the original position as more actual data, corrections and dispute outcomes become available.

RF (Final Reconciliation), the run that currently completes the settlement process over 14 months. This is the baseline Elexon uses when describing the MHHS timetable reduction.

Under MHHS, this timeline compresses materially at the M16 settlement timetable cutover, due early in July 2027 once meter point migration is essentially complete. Elexon states that M16 introduces a new timetable that reduces RF from 14 months to seven months and then to about four months. It also changes the first financial settlement run from 16 Working Days to about seven Working Days. The financial impact is reduced cash-flow risk because parties carry uncertainty for less time.

Four layers of wholesale trading

Before electricity reaches the Balancing Mechanism, it is traded through multiple market layers. Understanding these layers explains why wholesale costs represent approximately 45% of the average consumer bill.

1. Forward markets: operate months or years ahead. Generators and suppliers trade standardised contracts (baseload and peakload blocks) to hedge their future exposure. By the time a settlement period arrives, 90-95% of expected demand has already been contracted. Prices are published by exchanges (ICE Endex, EEX).
2. Day-ahead markets: operate the day before delivery via an auction (N2EX, operated by Nord Pool) that clears at a single marginal price per hour. Day-ahead prices are used in retail tariff calculations and CfD settlements.
3. Intraday markets: operate continuously from midnight until gate closure (one hour before the settlement period). Used to adjust positions as demand forecasts change or wind output varies. Volumes have grown with renewable penetration.
4. Balancing Mechanism: the final layer, from gate closure until real time. NESO uses Bids and Offers to balance the system, and the resulting costs are socialised through imbalance settlement.

Consumer bill composition

The average GB consumer electricity bill can be broken down into five components. These proportions vary with wholesale prices and regulatory changes, but the approximate split (as of early 2026) is:

Wholesale energy (~45%), the cost of generating and purchasing the electricity. This includes forward contracts, day-ahead purchases, intraday adjustments, and imbalance costs. The wholesale component is the most volatile, driven by gas prices (which set the marginal price in most settlement periods), renewable output, and demand levels.

Network charges (~27%), the cost of transmitting and distributing the electricity. This includes Transmission Network Use of System (TNUoS) charges and Distribution Use of System (DUoS) charges. Network charges are regulated through RIIO price controls and are relatively stable year-to-year.

Policy costs (~13%), the cost of government environmental and social policies. This includes Contracts for Difference (CfD) payments to renewable generators, the Warm Home Discount scheme, and the Energy Company Obligation (ECO). Policy costs have grown significantly as renewable capacity has expanded, though CfD costs are increasingly offset by periods when wholesale prices exceed the CfD strike price (resulting in payments flowing from generators back to consumers).

Operating costs (~10%), the supplier's costs of running the business. This includes billing systems, customer service, metering (including DCC charges for smart meter infrastructure), regulatory compliance, and profit margin. Ofgem's price cap methodology sets an allowance for these costs based on an efficient benchmark.

VAT (5%), domestic energy supply is subject to a reduced VAT rate of 5%, applied to the total of all other components.

Supplier failure and SoLR

The 2021 energy crisis exposed the fragility of the supplier market when wholesale prices spiked. Ofgem used the Supplier of Last Resort (SoLR) mechanism to transfer customers from failed suppliers to surviving suppliers. Ofgem's 2025 financial resilience report states that the billpayer cost of these protections peaked at £64 per year in 2022 to 2023 and fell to £0 in 2025 to 2026.

The crisis demonstrated the direct link between wholesale market data, settlement accuracy, and consumer protection. Suppliers that failed had typically hedged poorly (buying too little forward, leaving excessive exposure to spot prices) or had insufficient credit cover to meet their settlement obligations. Better settlement data, faster reconciliation, and more accurate exposure calculations reduce the time during which financial stress can remain hidden.

MHHS cash-flow-risk improvement

One of the most tangible benefits of MHHS is the shorter period of settlement uncertainty. Under Elexon's current framing, settlement completion moves from 14 months to four months once half-hourly settlement is fully implemented.

This matters because each reconciliation run updates cashflows, accruals and exposure estimates. Faster access to actual half-hourly data reduces reliance on long-lived estimates, makes financial positions clearer earlier and reduces the cash-flow risk that Elexon identifies in its MHHS material.

REMIT and market transparency

The Regulation on Energy Market Integrity and Transparency (REMIT) requires that wholesale energy market data is published to support market integrity. Generators must publish generation availability, interconnector flows, and inside information that could affect prices. Ofgem monitors compliance and can impose penalties for market manipulation or insider trading. The data published under REMIT is one of the richest publicly available energy datasets in Europe, providing transparency that supports research, analysis, and informed trading.

The network charges that make up roughly 27% of the bill are not a single number that someone types in. Each charge is a public data product, published to a fixed timetable and worked out from the same metered volumes that settlement produces. Charging is the largest downstream consumer of settlement data: every transmission, distribution and balancing charge is billed against settled volumes, so an error in a settlement run flows straight through into a network bill.

TNUoS: the transmission tariff tables

Transmission charges are set out in tariff tables that NESO publishes to a fixed cycle. NESO confirms the TNUoS tariffs by 31 January and they take effect on 1 April, the start of the charging year. The tables are open, so anyone can download them, read the demand and generation tariff for a charging zone, and multiply it by the metered volumes settlement has allocated to a party to reconstruct the charge. Learning to locate and read one of these tables turns the headline “network is about 27%” into a figure you can derive for yourself.

DUoS: the DNO charging statements

Distribution charges work the same way, one level down. Every DNO must publish a charging statement under the Distribution Connection and Use of System Agreement (DCUSA), the industry code that governs distribution charging. The statement sets out the DUoS tariffs for each tariff class, and the detailed charging bands sit in Schedule 32 of DCUSA. The statement is a public document: you can open a DNO's current version, find the tariff for a given profile class or metering arrangement, and read exactly what a supplier pays to use that network.

BSUoS: paying for the balancing actions

The Bids and Offers that NESO accepts in the Balancing Mechanism are not free. Their cost is recovered through BSUoS (Balancing Services Use of System), a charge recovered from suppliers in proportion to their metered demand. BSUoS closes the loop that section 10.1 opened: the balancing actions taken to keep the system in step are settled between NESO and generators, and their net cost is then spread back across demand through this charge. Because it is billed on metered volumes, it draws on the same settlement outputs as the rest of the settlement chain.

Read together, the three statements show why settlement quality matters beyond the wholesale market. The metered volumes and GSP allocations that the SVAA and SAA produce are the inputs to every network charge, which makes the charging statements the largest and most visible downstream product of settlement data.