22 August 2023
The decline in wholesale prices has been reflected on business energy rates available to those looking for a new contract or to renew with their existing supplier.
Business energy retail prices move regularly, weekly or even daily for certain types of customers. They track the live market and therefore are much more volatile than those for households.
To offer fixed price contracts, energy suppliers buy gas or electricity in advance when selling it to their customers. As a result, the prices at which they have bought energy to sell today might be different from the current rates.
If their customers consume more energy than predicted, suppliers need to buy more at current market prices to cover for the shortfall.
Conversely, if their customers consume less than anticipated, then suppliers need to sell the excess energy back to the grid. If the current price for selling the excess energy on the spot or day-ahead market is lower than the original price paid for it, then suppliers will lose money.
To manage some of the risk associated with the way energy is bought and sold, suppliers often include risk premiums in their price calculations, in much the same way as banks factor risk into the rates they charge for loans and credit.
The volatility we have seen in wholesale markets over the last 18 months has increased the risk for suppliers.
According to Mark Freshney, an energy analyst at Credit Suisse, “non-domestic supply has been very tough for utilities“. Suppliers "have made returns below their cost of capital"(1).
When looking at the cost stacks for gas and electricity, the latter is comparatively more expensive than the former. There are three main reasons why electricity is more expensive than gas – excluding taxes:
Power generators are required to bid in the price they will accept to generate electricity. These bids are based on their operating costs including the costs of starting up or shutting down generation. A “merit order” is formed whereby generators are ranked from cheapest to most expensive. Wind and solar farms tend to have the lowest operating costs, followed by nuclear power plants, whist gas-fired plants usually have the highest operating costs. The electricity system operator will then contract with enough generators to ensure that there is sufficient supply to balance expected demand. The price bid by the marginal generator – the most expensive plant needed to supply electricity to balance the market – becomes the clearing price, which all participants are paid.
The government via the energy regulator Ofgem has placed various levies to support clean energy solely on electricity bills , rather than on gas bills. With electricity supply becoming less carbon-intensive than gas – due to the rapid increase in renewables to the grid – this structure has meant that higher-emissions gas supply paid a lower effective carbon tax. This set up is increasingly hard to justify.
Costs associated with maintaining and balancing the electricity system are higher than the gas transmission network. There are two key differences between the systems that can explain the cost differential . Firstly, gas moves slowly through the system, unlike electricity. This means that the network operator has more time to react to when to compress or expand gas within the pipeline system. Secondly, unlike the electricity system where the network operator deals with power producers directly, in the gas system there are gas shippers that buy gas from producers and sell it onto suppliers. They play a critical role in balancing the gas system (2).
Energy bills are made up of two main parts: commodity costs (the cost of gas or electricity in wholesale markets) and non-commodity (non-energy or third party charges) costs.
The fall in wholesale prices seen in the last few months is changing the dynamics between commodity and non-commodity costs (NCC).
Looking at a representative business gas cost stack in Q2’23, the split between commodity and NCC (which includes Network Charges plus Metering) was 81% and 19% respectively (3). The decline in the share of commodity costs was driven by a decrease of 7% in commodity costs QoQ and an increase of 10% in Network Charges over the same period.
Gas Network Charges’ share of the cost stack increased from 14% in Q1’23 to 16% in Q2’23.
In turn, the commodity element of a representative business electricity cost stack decreased from 64% in the first three months of 2023 to 58% in Q2. This was driven by a decline of 13% in wholesale electricity costs QoQ.
In contrast, NCC (which includes Environmental, Network and Metering charges) accounted for 42% of the cost stack, up from 37% in the previous quarter.
Environmental Charges rose by 19% QoQ and its share of the cost stack increased by 5ppt to 25%.
Meanwhile, Network Costs decline slightly by 2% over the same period but its share of the cost stack remained unchanged at 16%.
Non-commodity costs update
In this section we review some of the most significant developments in NCC and what is coming down the line.
Renewables obligation (RO)
This scheme was introduced in 2002 to incentivise suppliers to source power from renewables sources. Energy suppliers are required to submit renewable obligation certificates (ROCs) to the regulator every year as proof of the amount of electricity supplied from renewable sources.
RO charges have increased in recent months driven by inflation (these costs are linked to the rate of inflation) and lower electricity demand.
Furthermore, additional costs incurred during mutualisation are typically passed on to electricity customers. When suppliers don’t have sufficient ROCs, they must pay into a buy-out fund. A shortfall may occur in the buy-out fund if a supplier is unable to meet its RO obligation.
If the shortfall exceeds a minimum threshold, it will trigger a mutualisation process whereby other suppliers will have to cover it.
Mutualisation was triggered for the 2021/22 reporting period but it’s being billed in 2023.
In April, Ofgem set the buy-out price for the 2023/24 obligation period at £59.01 per ROC (4).
In July, a new requirement was introduced that mandates suppliers to ring-fence their ROCs by holding or preserving funds equivalent to the buy-out price of their obligation (5).
Balancing Services Use of System (BSUoS)
According to National Grid ESO (NGESO), the costs of balancing the system are volatile and the hardest to forecast (6).
These costs have increased significantly over the last three years. Several factors have contributed to the rising costs including the increased contribution of renewable generation, the suppression of demand due to COVID-19 restrictions, the corresponding reduction in system inertia, and more recently the increase in wholesale electricity prices.
From April 2023, BSUoS costs are being recovered directly from customers as transmission-connected generators are now exempt from this levy. The methodology for recovering these costs has also changed and NGESO now fixes the rates for six months with nine months notice.
In July, NGESO published the fixed tariffs for 2024/25 for BSUoS, which sees a drop in rate from c.£14/MWh in 2023/24 to c.£7.60/MWh for 2024/25.
This is driven by lower power price forecasts and the offsetting of forecasted over-recovered costs from 2023/24 into the 2024/25 rate.
Distribution Use of Systems (DUoS)
This charge recovers the cost of maintaining and upgrading the regional distributions networks. It’s paid to one of the eight Distribution Network Operators (DNOs) in the area of the country in which a meter is located.
These costs have also been rising driven by inflation and lower demand.
Going forwards, these charges are likely to continue rising as network companies adapt to new ways in which customers consume electricity and new technologies enter the system e.g. batteries and EVs.
Capacity Market (CM)
The CM is a scheme introduced by the government to manage security of electricity supply and to safeguard against the possibility of blackouts.
It offers payments to generators for being available to produce electricity at certain times, and to demand response providers for being able to reduce electricity demand.
Suppliers pay for the scheme in line with their market share through the winter months when electricity demand is at its highest.
The market takes the form of two auctions each year:
The T-4 auction took place in February 2023 (7) and this is a summary of the results:
As a result, CM charges increased by 60% QoQ.
Feed-in Tarif (FiT)
This is a levy paid by suppliers to subsidise small scale renewable generation such as solar panels on commercial or domestic roofs. It is closed to new applications but continues to support existing generators.
These charges are also linked to the rate of inflation and consequently have been rising gradually through to Q2’23.
Contracts for Difference (CfD)
A charge to promote new investment in zero carbon generation by providing investors a guaranteed income for the electricity they generate.
CfD costs are inversely proportional to wholesale power prices, as a result these charges declined significantly in 2022 and became a benefit to customers. However, this year, CfD charges have returned to be a cost.
Generally, it’s expected that CfD costs are likely to increase in the coming years now that the RO an FiT schemes are closed to new capacity
Transmission Network Use of System (TNUoS)
These charges are designed to recover the cost of installing and maintaining the transmission system. It’s paid by generators and suppliers.
Costs can be separated into residual charges for maintaining the existing network and forward-looking charges for future investment.
From April 2023, the residual element of TNUoS (which make up the vast majority of TNUoS cost) has been replaced with a fixed change depending on a consumer’s voltage or agreed capacity as part of Ofgem’s Targeted Charing Review (TCR).
Depending on the type of product, it’s expected that the new TNUoS TCR cost will be included in the Standing Charge for fixed price contracts or as a separate fixed daily charge on pass-through contracts (8).
Other changes coming in 2024 and beyond
These changes are intended to reduce costs for qualifying EII so they can compete with EU counterparts who pay less for business electricity.
Sources & Notes:
1) UK businesses need a solution to exorbitant energy costs, Financial Times, 30 May 2023 https://www.ft.com/content/231fd967-f3b2-4bc9-b856-4670fa6a4380
2) End-to-end balancing guide, National Gas, 2023 https://www.nationalgas.com/balancing/end-end-balancing-services
3) Gas and electricity indicative cost stacks are based on portfolio averages for SMEs over a 60-month period. Excludes taxes, operating expenses, margins and broker fees.
4) Ofgem unveils buy-out price and mutualisation ceilings for 2023-24 ROC, Energy Live News, 13 April 2023 https://www.energylivenews.com/2023/04/13/ofgem-unveils-buy-out-price-and-mutualisation-ceilings-for-2023-24-roc/
5) New RO ringfencing requirement for UK electricity suppliers. Future Net Zero, 20 July 2023 https://www.futurenetzero.com/2023/07/20/new-ro-ringfencing-requirement-for-uk-electricity-suppliers/
6) BSUoS fixed tariff Apr 2024 – Sep 2024, National Grid ESO, 30 June 2023 https://www.nationalgrideso.com/document/282691/download
7) T-4 Capacity Auction Provisional Results for Delivery Year 2026-27, Low Carbon Contracts Company, February 2023 https://www.lowcarboncontracts.uk/news/announcement/t-4-capacity-auction-provisional-results-for-delivery-year-2026-27
8) What’s New for Ofgem’s Targeted Charging Review in 2023?, British Gas Business, 26 May 2023 https://www.britishgas.co.uk/business/blog/whats-new-for-ofgems-targeted-charging-review-in-2023?cid=CBSESMTCRS01
9) Emissions and our tax forecasts, Office for Budget Responsibility, May 2023 https://obr.uk/docs/dlm_uploads/Emissions-working-paper.pdf
10) Network charging compensation scheme for energy intensive industries, Department for Energy Security & Net Zero, 6 June 2023 https://www.gov.uk/government/publications/energy-security-bill-factsheets/energy-security-bill-factsheet-network-charging-compensation-scheme-for-energy-intensive-industries
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