Business Energy Costs: a guide to third party non-commodity costs

Energy invoices are made up of a combination of the commodity cost (the fuel you consume) and non-commodity costs. Included in the non-commodity costs are government-originated charges and third party charges. Some of these charges are levied on suppliers who pass them onto the customer. In this blog, we’ll explore what you can expect from these costs for 2023-2024.

The substantial increase in wholesale prices means the TPCs portion of a typical energy bill has gone down from 60% to around 40%. However, with the underlying charges for TPCs at their highest point ever, even the slightest changes to them can significantly impact your energy costs.

Here’s an overview of our insights on the key TPCs:

  • Distribution Use of Systems (DUoS): Rising due to lower national demand, higher inflation and expected impact of electricity network charging reforms. The Significant Code Review is delayed.
  • Transmission Network Use of Systems (TNUoS): Increases fuelled by inflation expectations, the generation revenue cap and changes in Transmission Demand Residual (TDR) charges.
  • Balancing Services Use of Systems (BSUoS): Significant rises due to increased volatility, CMP308 and the likely impact of CMP361.
  • Capacity Market (CM): T-1 2022/23 has already delivered. Going up, as T-1 2023/24 and T-4 2026/27 auction prices continued to outturn high.
  • Renewables Obligation (RO): Charge is increasing again due to high inflation and low national demand. Mutualisation has been triggered for 2021/22 (and will billed in 2023).
  • Contracts for Difference (CfD): Levy volatility is set to continue, given current wholesale energy prices.

An Introduction

This blog brings you up to speed with recent regulatory changes, market developments and other factors that could impact the Third Party Costs (TPCs) element of your energy bills. Over the last year, a series of unprecedented events have led to supply security and energy prices becoming headline news. In the following pages, we aim to explain what’s happened and why, and to determine how it might affect your organisation. We hope you find our guide useful.

Russia’s invasion of Ukraine in February 2022 brought energy firmly into the spotlight. There were concerns over gas supplies into Europe which led to massive increases in both gas and power prices and lower demand (which we refer to as ‘demand destruction’) as consumers tried to reduce their consumption. These factors together with high inflation have also led to TPCs increasing significantly.

The substantial increase in wholesale prices has reduced the proportion of a typical bill that TPCs make up, from 60% to 43%. And this figure even fell below 40% during winter 2022. Even so, the underlying charges for TPCs are at their highest point ever – meaning that any changes to TPCs can make a significant difference to energy costs overall. 

Some TPCs cover policy costs that help cover the investment needed to decarbonise the electricity sector. Others are network costs that help pay to construct, maintain and balance our electricity networks. In short, TPCs help to ensure that power gets from where it’s produced to where it’s needed. 

A more welcome development has been the Government’s response to rising wholesale prices and TPCs, and to the more general cost of living crisis. Its announcement of support for energy customers – initially for winter 2022, in the form of the Energy Bill Relief Scheme (EBRS) – was certainly received positively. And it was as unprecedented as the events causing it.

Commodity Markets

Wholesale energy prices were extremely volatile in 2022 and reached new price highs, with the baseload winter 22 season power contract peaking at over £820/MWh (on 26 August). This was over four times the trading level at the beginning of the year and came just over a month before the start of delivery for the winter 22 contract.

Since then, it appears that two factors have helped to ease prices. The first was the relatively mild start to winter across the UK and Europe; the second was that users have taken energy-saving demand reduction measures. This combination has also helped to reduce power prices in both Q4 2022 and the start of 2023.

Power prices started 2022 on a bullish trajectory following a supply squeeze in the gas market. This resulted from the demand increase caused by the restart of the global economy following the period of Covid-related lockdowns over the previous 12 months.

The supply issues in the gas market were then further compounded with Russia’s invasion of Ukraine in late February 2022. This led to economic sanctions against Russia from the West and, in response, a reduction in Russian gas flows back into Europe.

Europe’s heavy reliance upon usually reliable gas flows from Russia resulted in prices for the summer 22 National Balancing Point (NBP) gas contract jumping as high as 510 pence per therm (ppt) on 3 March. This was an increase of over 250% versus the price at the start of the year, as demand for gas across Europe began to far outweigh the available supply.

The summer of 2022 also saw numerous factors further compounding the market’s supply fears. One factor was an increased requirement for EU countries to refill their natural gas storage sites, having closed the winter around only 25% full (well below the five-year averages). This led to significantly increased re-stocking in the warmer months when gas demand is usually suppressed.

In both August and September 2022, there were record-high levels of volatility in both power and gas markets. The largest day-on-day increase for the front season, winter 22 contract, was recorded on 24 August, with a rise of over £70/MWh compared to 23 August. This followed an announcement from Russia’s state-owned Gazprom regarding the complete and indefinite closure of the Nord Stream 1 gas pipeline into Europe. This news sent severe shockwaves through the market and raised serious concerns about the security of supply over the upcoming winter. In turn, this pushed power prices to record new highs before the start of the winter 22 delivery.

The outlook for wholesale prices for 2023 will depend upon various factors – including the weather over the remaining winter period – and their combined impact on supply and demand. Periods of above-seasonal normal temperatures have resulted in ample gas storage availability. In fact, storage levels are currently above their 5-year averages. This will temper the usual restocking demand traditionally seen across the summer months and could contribute to suppressing prices.

In addition, the availability of LNG supply into both the UK and Europe is likely to play a key role in determining the direction of both power and gas markets. This is set to continue as the region strives to reduce the impact of the Russia-Ukraine conflict.

Reduced Demand & Inflation

National demand reduced significantly during COVID lockdowns and this has had a compound effect with rising energy costs as businesses and home owners look to reduce consumption to tackle rising energy costs. Inflation and economic factors also contribute to rising third party costs:

  • The impact of the wider cost of living crisis – the Consumer Prices Index (CPI) and Retail Prices Index (RPI) rose by 10.1% and 13.4% respectively in the 12 months to January 2023
  • High prices, only somewhat mitigated by the Government’s energy price cap
  • A downgraded and increasingly worsening UK economic outlook since the start of the year
  • Continued increasing levels of energy efficiency

A lot of uncertainty remains: the impact of government support reducing from April and more generally, the UK economic outlook. Therefore, this guide includes a high case scenario that assumes a further year-on-year reduction in national demand from 2022/23 plus high inflation continuing for the foreseeable future. These factors will further increase the £/MWh charge of TPCs

business energy contracts - cheap business energy
business energy contracts - cheap business energy

What are the main third party costs?

Distribution Use of System (DUoS)

DUoS is the charge for distributing electricity across the distribution network to the customer supply point.

The key drivers for the higher 2024/25 final tariff reflect increased inflation assumptions for this year compounded by a truing up of inflation and under recovery of costs from previous years. This is due to the lead time Distribution Network Operators (DNOs) face when setting final tariffs, using forecasted inflation at first and then adjusting to actual when the following year’s tariffs are published. The lower than anticipated demand that we’ve seen in the last few years is also likely to have resulted in an overall under-recovery of costs by the DNOs. These costs then need to be recovered in future years.

Transmission Network Use of System (TNUoS)

TNUoS is the charge for using and maintaining the transmission network.

The system operator National Grid ESO (NGESO) recently published its 2023/24 actuals, showing revenue to be collected at £4,416m – £822m (23%) higher than 2022/23. 

The final revenue is up £433m from the Draft Tariffs that NGESO published in November 2022. A large part of this increase is due to increased inflation assumptions for 2023/24 and previous years under recovery. The €2.50/MWh cap on revenue to be collected from generation means most of the increase has been levied on consumers, resulting in a 13.7% increase in tariffs from NEGSO’s Draft Tariff. 

The largest component of TNUoS charges is called the Transmission Demand Residual (TDR). Following agreement of the Targeted Charging Review (TCR), how it’s charged is changing from April 2023. Instead of being recovered via the traditional Triad methodology, it will be a fixed £/Site/Day amount, varying by meter type and band. 

However the forward looking locational element of TNUoS will continue to be recovered via the Triad methodology. This locational element is much smaller than the TDR and accounts for only around 3% of total costs. The locational element is also being floored at zero from April 2023 onwards, following the approval of CMP343. This means that not all Grid Supply Point (GSP) areas will have a locational rate (our forecast table on page 10 shows the GSP areas affected).

Balancing Services Use of System (BSUoS)

This is the charge for keeping the network in balance, maintained by National Grid.

The cost of balancing the system increased significantly in 2022. In January 2023, NGESO is forecasting total costs of £4.7bn for 2022/23 compared to an outturn of £3.5bn in 2021/22. Increased market prices and tight system margins have played a large part in the increased cost of NGESO’s balancing actions. It’s paid prices of £3,000/ MWh and above for some HH periods. We’re forecasting 2022/23 to outturn at £9.75/MWh (compared to £7.01/MWh in 2021/22).

Capacity Market (CM)

CM is an Electricity Market Reform (EMR) mechanism to help the UK meet its carbon reduction targets and ensure security of electricity supply. It is designed to make sure there is sufficient power available to meet future needs. It operates as an annual auction, which started in December 2014, to procure the majority of the UK’s required energy capacity four years in advance. There is a top-up auction one year ahead of delivery to enable Demand Side Response (DSR) to participate. The cost of running the CM is passed through to consumers.

In February 2023, both CM auctions took place. The T-1 procured 5.8GW of capacity for delivery in winter 2023 at £60/kW – the second highest T-1 auction outcome after last year’s cleared at £75/kW. 

The T-4 for delivery in winter 2026 cleared at £63/kW. This is very high in comparison to previous outcomes (and more than double the previous T-4 clearing price of £30.59/kW). The large amount of new build capacity required drove a high clearing price. The auction’s winning contracts will deliver 43GW of capacity.

Renewables Obligation (RO)

This charge is levied on suppliers to fund the RO scheme by Ofgem, which is then passed on to consumers.

At the end of September 2022, BEIS* set the 2023/24 RO at 46.9%, a reduction from the current (2022/23) obligation of 49.1%. The reduction was driven by lower forecast Renewable Obligation Certificates (ROCs) and higher national demand. The buy-out price for the 2023/24 obligation period has been set at £59.01/ROC – an increase of 11.60% from 2022/23. This sets the RO charge for 2023/24 at £27.68/MWh (an increase of 6.6% from 2022/23).

*Energy sector responsibilities formerly under BEIS were transferred to the Department for Energy Security and Net Zero (DESNZ) under a governmental restructure.

Contracts for Difference (CfD)

CFD is an Electricity Market Reform (EMR) mechanism to help the UK meet its carbon reduction targets and ensure security of electricity supply.

The CfD charge is designed to support investment in new low-carbon generation, with a technology-dependent fixed price known as the ‘strike price’ (wholesale price + top-up subsidy). CfD costs will vary annually due to wholesale price fluctuations and amount of CfD generation produced in each year. Costs are met by a levy applied to energy suppliers, which are then passed on to consumers. This charge is levied by HMRC.

In recent months, the CfD Levy has been extremely volatile and swung from being a significant benefit to consumers to being a cost. This is because of a sharp reduction in wholesale energy costs and lower than expected baseload generation volumes. For example, January 2023 out turned at £3.05/MWh cost. Only a few months before, we were forecasting a significant benefit. 

The Low Carbon Contracts Company (LCCC) had set the Q1 and Q2 2023 Interim Levy Rates (ILR) to zero. However, given the recent drop in wholesale prices, it announced an increase to the Q1 ILR (taking it to £8.12/MWh) from 9 March until 31 March 2023 and Q2 ILR (taking it to £3.819/MWh) from 27 April to 30 June 2023. 

Going forward, wholesale energy prices and generation output will continue to drive volatility. The scheme is highly dependent upon day-ahead wholesale market prices and, given that most of the generation is from wind, forecasting is extremely difficult. This is especially true with the recent volatility in wholesale energy prices. Should wholesale prices continue to fall, scheme costs will increase and the opposite holds true if wholesale prices increase.

Feed-in Tariff (FiT)

The FiT charge is levied on suppliers to fund the a scheme designed to incentivise new renewable generation by Ofgem.

There was a significant increase in 2022/23 FiT costs, due to increased sunshine hours (particularly in the summer and milder than normal weather in October and November) and lower national demand. 2022/23 is expected to outturn at least £1/MWh higher than 2021/22. 

Total costs will rise further in 2023/24, as the FiT increases by December 2022’s Retail Price Index (RPI) inflation figure of 13.4%.

The substantial increase in wholesale prices means the TPCs portion of a typical energy bill has gone down from 60% to around 40%. However, with the underlying charges for TPCs at their highest point ever, even the slightest changes to them can significantly impact your energy costs.

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