Meeting report
Energy Modelling Across Scales – Workshop Summary
Nov 2023
As part of the price control review process known as RIIO, the revenues that the six electricity distribution network operators (DNOs) can collect from their customers through network charges are decided by Ofgem, the energy regulator. In the past, the DNOs were given a large degree of autonomy over the price control period – lasting five or eight years – to spend this money on the various business activities and investments required to deliver on their required outputs and objectives. However, due to the fundamental uncertainties around the roll out of low carbon technologies over the next five years, particularly heat pumps and EVs, Ofgem has decided to separate each DNO’s revenue into ‘variant’ and ‘non-variant’ allowances, with the costs of integrating low carbon technologies – load related expenditure (LRE) – funded through variant allowances.
Non-variant allowances are fixed at the start of the price control and cover the majority of a DNO’s individual cost categories – 51 in total – whereas variant allowances are contingent, meaning that adjustments can be made during the price control period’. This separation of DNOs’ revenue into variant and non-variant was done to protect consumers from having to fund investments in the networks which may not be required, in the event that the roll out of low carbon technologies happens at a slow pace.
As a result, any LRE arising from the integration of HPs and EVs will only be covered by consumers if the uptake of these technologies exceeds a minimum baseline and triggers the additional revenue allowance, as set out in Ofgem’s ‘Uncertainty Mechanism’ framework. The baseline for heat pump and EV uptake was decided by Ofgem at the start of the price control period and aligned closely with the System Transformation net zero scenario – the most conservative 2050 Future Energy Scenario (FES) in terms of the electrification of heating and transport demands.
There was a significant difference however between this modelled LRE calculated by Ofgem and the LRE costs submitted by the DNOs in their business plans. Although differing across the DNOs, these, in general, aligned more closely with the Consumer Transformation scenario, forecasting a greater level of low carbon technology roll-out over the next five years. This is illustrated in the figure below which shows submitted and modelled costs for secondary reinforcement, the most significant of the five LRE cost categories[1] and the one which is most affected by low carbon technology integration (see Figure 2). The differences across the three FESs which meet net zero – Falling Short misses the 2050 target – are most pronounced for the level of electrification of heating demands (Figure 3 illustrates this for the most recent FESs).
Figure 1: Differences between submitted and modelled costs for Secondary Reinforcement (£m, 2020/21 prices).
Figure 2: Load Related Expenditure across the DNOs (£m, 2020/21 prices). The total expenditure for RIIO-ED2 is £22.2bn.
Figure 3: Annual heat pump installations in the residential sector in the 2023 FES
These differences in LRE forecasts are important because variant allowances are non-fungible, meaning that a company cannot transfer its unused LRE allowance into non-variant cost categories. So, for example, if a DNO’s variant allowance to cover LRE aligned with its own ambitious submitted costs, the company would not receive its total revenue allowance – according to Ofgem’s prior estimation of efficient costs – and would be at risk of underfunding. On the other hand, if the regulator’s modelled costs were used as a basis to make the allocation, a higher proportion of the initial revenue allowance would be designated as non-variant which, in the regulator’s view, would over-compensate the company and be against its core duty to protect the interests of consumers. So, given the limitations of both these approaches to cost allocation, Ofgem decided to split the difference and take a ‘blended approach’: 50 per cent of the allocation is based on the DNOs’ submitted costs and 50 percent from the regulator’s modelled costs.
Northern Powergrid, the DNO covering Northern Lincolnshire, Yorkshire and the North East of England, however, disagreed with this approach and in early 2023 lodged an appeal to the price control determination with the Competition and Markets Authority (CMA). The main subject of their appeal was that the resulting allocation meant they could be underfunded across the price control period, to the tune of £157m – the difference in their non-variant allowance using the blended approach and Ofgem’s original modelled costs.[2]
The issue with Ofgem’s ‘blended approach’, from the company’s perspective, was that, because the company’s ambitious scenario was factored into the allocation decision, too great a proportion of its revenues were allocated to variant categories and, as a result, its non-variant costs may not be covered. It could lead to a situation where a company operating efficiently, but with an ambitious decarbonisation scenario, could be left underfunded. Northern Powergrid argued, under the 1989 Electricity Act, that the allocation decision was ‘based on an error of fact’ and the regulator did not fulfil its duty to ensure the financeability of the company. Given the significant discrepancy between their submitted and Ofgem’s modelled costs, they argued, the information relating to LRE from business plans should not have been factored in.
In its response, Ofgem argued that its use of the System Transformation scenario in calculating the total revenue allowance did not imply that the company business plans were irrelevant to the price control; that the forecasts for LCTs were adjusted downwards in the interests of protecting consumers from allocating too much revenue to LRE, but that the DNO business plans remained relevant in deciding how the companies would operate over the period and their needs across the different cost categories. As there was no prior agreed methodology for allocating revenues across variant and non-variant categories, it was reasonable, in Ofgem’s view, that they use their expert judgement as a regulator in making these allocation decisions.
In September this year the CMA published its final determination and, on the question of how to allocate revenues across the variant and non-variant categories, it upheld Northern Powergrid’s appeal of the price control. The main basis for this decision was that, as Ofgem had earlier criticised the company’s submitted LRE as overambitious and inefficient, it should not then have used these estimates as a key input for the allocation methodology. The differences between the DNO’s submitted and the regulator’s modelled LRE were of such an extent[3] that the regulator should have decided on an alternative methodology. As the two parties could not agree on a resolution, the issue is now back with Ofgem and they will need to consult on an alternative methodology for allocating Northern Powergrid’s revenues across cost categories.
While this case may seem marginal in relation to the significant challenges faced in transforming the electricity system, the question of how long-term scenarios are used in the regulatory decision-making process is an important one. In order to strategically plan the networks and align investments with net zero goals, it is likely that greater coordination across generation, networks and the demand-side of the system will be required, and risks will likely need to be taken by investing ahead of need. Having a coherent and legitimate framework for the use of scenarios in regulatory decision making will be crucial for this. The outcome of the recent CMA case will therefore have particular relevance for the new Future System Operator, an organisation that will likely play an important role in regional system planning. The case will also be relevant to the forthcoming gas distribution price control, which will commence in 2026.
[1] These are: Connections, Primary Reinforcement, Secondary Reinforcement, Fault level Reinforcement (to maintain stability), Transmission Capacity Charges (costs imposed on transmission companies associated with increasing capacity at transmission-distribution connection points).
[2] There were two grounds of appeal. Only Ground 1, on the use of submitted LCT forecasts in Ofgem’s allocation decision, is discussed here. The other (Ground 2) referred to whether NPg should be awarded under Stage 4 of the Business Plan Incentive. This was less significant and the CMA did not uphold this part of the appeal.
[3] The percentage of costs accounted for by LRE were 16.8% (submitted) and 7.6% (disaggregated modelling) for the North East region and 22% versus 8.5% for the Yorkshire region (CMA, 2023).