From “what if?” to “what now?”

As the UK begins its third week of lockdown, the nation’s energy sector continues to wait to see whether there will be any economic or financial support targeted specifically at end users, suppliers, network operators and fellow participants alike.

Immediate issues for end users include their ability to pay their bills, whether in full or in part. As presented in Energy Spectrum 708, there have already been measures put forward by BEIS and Ofgem – among others – but there remains immediate questions for the retail sector.

End users looking for a new contract

The typical tendering process for a supply contract – whether undertaken directly or through a third party intermediary (TPI) – is reliant upon a forecast of consumption volume and an associated profile. Normally, this would be based upon historic metering data combined with a forecast of anticipated requirements.

However, in the current climate, the phrase, “Past performance is not a guide to future results,” could not be truer amid question marks over the extent and duration of the current lockdown, with businesses unsure of how much energy they will need and when.

This business-level uncertainty may be compounded by sectoral issues if a business that has been atypically affected by the lockdown. For example, customers in areas such as hospitality, non-food retail, vehicle manufacture, construction and civil engineering, which would otherwise have had no problems in contracting may now find themselves seen as a greater credit risk. As a result, suppliers may look to reduce their exposure to such sectors and may in turn be less willing to contract with them – making it harder for end users to find the contract they want.

Similarly, those end users that wish to secure a flexible contract may find that their ability to hedge energy over the duration of their agreement may find this curtailed. For example, customers signing up to a three-year flexible contract may only be able to hedge the first six months or first year.

In the event that customers are able to secure a contract, uncertainty regarding volume and profile considerations may be reflected in higher risk and shape fees, and therefore higher bills that would otherwise be the case under COVID-19.

Considerations for existing supply contracts

The current situation is clearly unprecedented, but energy supply contracts typically incorporate provisions for changes in volume and profile. The ability to reforecast consumption needs will be crucial for end users, while those with flexible supply contracts should be able to sell back any previously hedged volume to their supplier – albeit with a marked-to-market loss. 

In conjunction with reforecasting, the ability to call upon volume tolerance provisions within supply contracts will be important. Here, those customers with an annual volume tolerance capability may be better placed than those with a monthly volume tolerance to manage the current situation – depending of course on how long the lockdown and its effects continue.

As with new contracts, matters relating to risk and shape fees may also be subject to review given that both would have been based upon an assumed level of consumption and shape. The type of changes associated with the lockdown could serve as the basis for suppliers reviewing and potentially re-opening the existing terms.

A similar matter relates to the treatment of third party charges under a supply contract. Suppliers may have used forecast rates for charges such as Balancing Settlement Use of System (BSUoS), Feed-In Tariff (FiT) and Contracts for Differences (CfD) for inclusion in their tariffs – particularly fixed rate tariffs rather than those that operate on a passthrough basis for such charges.

However, as detailed below, in light of the extent of the demand reduction, it is possible that these costs may have changed by such a degree that suppliers may seek to utilise contract re-opener clauses to pass through further increases.

Economic implications of demand hibernation

In the first week of the lockdown, Elexon data indicates that total electricity demand has fallen by approximately 13% compared to the March 2019 average (on a non-weather corrected basis). The decline has been more apparent in the morning peak rather than the evening peak given the absence of demand from the industrial and service sectors.

Some industrial sectors were already under pressure prior to COVID-19 – whether due to international trade considerations, or uncertainties surrounding Brexit or the 2019 General Election. The broader macroeconomic implications associated with COVID-19, both at the domestic and at the international level, risk weighing heavily on the industrial sector both during the lockdown and beyond. This is because the prospect of differing public health and economic recovery rates around the world may compromise global supply chains of components and personnel alike.

While BEIS and the Office for National Statistics (ONS) utilise different definitions of what constitutes the UK’s Services sector, the former explicitly includes areas that have been acutely affected by the lockdown – offices, retail, education and hospitality. Based upon BEIS data for 2018, these four areas alone comprised over two-thirds of the nation’s electricity demand.

Although smaller contributor to UK’s electricity demand than the Industrial sector, services represents a much larger contributor to the nation’s economy. Indeed, using the ONS definition of the sector, services accounts for around 80% of UK economic output and approximately 84% of UK jobs.

From the perspective of the UK economy, the ability of the services sector to recover is more important than the industrial sector, although it is more important for electricity demand that the latter recover. Furthermore, as services are relatively more reliant on indigenous factors than industry, the service sector may be better placed than the industrial sector to recover once social distancing measures ameliorate – in turn benefitting the wider economy, including industrial consumers.

However, demand hibernation also means a smaller market, and in turn a smaller base for non-energy charges – which will have implications for both customers and suppliers.

Hibernation and third party charges

The majority of the electricity sector’s third party charges are structured in such a manner that they recover fixed or variable cost across the entire demand charging base – therefore, a smaller demand base implies higher per unit charges.

These costs are based upon (not exclusively):

  • Agreed allowed revenues with Ofgem
  • The costs of balancing the system, managing network constraints etc.
  • Generation output from renewable assets, which in turn depends on factors such as sunshine hours and windspeeds
  • The cost and capacity procured in Capacity Market (CM) auctions
  • Wholesale prices, in the case of the CfD

Suppliers will do their very best to forecast these costs and – as stated above – factor them in to fixed tariffs that they offer customers.

It should also be noted that, in the majority of industry charges, there is no specific allocation to business or domestic consumption – these are simply smeared over the total electricity demand base. However, in the case of lower demand from businesses, business suppliers are jointly impacted by higher per unit costs and lower revenues coming in the door from customers.

There are further interactions to consider for some charges, such as BSUoS. Managing a lower demand system has additional challenges for National Grid ESO, given that a low demand means that less generation is running and providing services such as inertia and reactive power response.

The changing nature of demand, and the generation mix called upon to meet it, means that National Grid ESO will need to reposition the market to ensure stability.

This could involve curtailing wind generation and interconnector imports and using pumped and battery storage to increase demand. Although National Grid ESO has experience of dealing with low demand over summer nights (as low as 17GW) managing low demand over a longer period – such as the ongoing lockdown – may result in higher costs associated with BSUoS in conjunction with a lower demand denominator over which such costs will be spread.

In the presence of demand hibernation, the structures associated with electricity third party charges are such that the effects resulting from this shift will be experienced by industry participants now and into the future.

While charges such as BSUoS will already be experiencing impacts, those associated with networks may not be seen until April 2022. This is illustrated across the suite of third party charges in Figure 1.

Further clarity is needed

However, there remain specific elements associated with certain charges that cannot be immediately quantified – such as the demand impacts on those industries which have an exemption for Energy Intensive Industries (EIIs).

It is apparent that – as with the wider societal and economic consequences of COVID-19 – further clarity will be needed to ensure that the energy sector emerges from lockdown armed with the tools to resume its journey on the road to net zero.

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