Ofgem has suggested that locational transmission charges should reflect the network as it is expected to be in the future, rather than its current configuration.
The regulator presented this as its initial view in an open letter updating the industry on its thinking for strategic reforms of Transmission Network Use of System (TNUoS) charges.
Ofgem also reaffirmed its earlier position that transmission charges should not be used to send short-term operational price signals to influence how the network is used in real-time, and should only be used to send longer-term price signals to influence investment decisions.
TNUoS charges are divided between forward-looking charges that are intended to reflect the impact of users on future network investment depending on where they are located, and residual charges that are designed to recover the already sunk costs of the existing network.
For generators, the former group includes wider locational TNUoS charges across 27 zones in Great Britain. These charges are based on their proximity to centres of demand. Generators located close to demand have lower charges and can even receive a credit in zones where there is significantly more demand than generation.
These charges have faced criticism for being volatile and unpredictable and deterring investment in renewables, which are often located far away from demand centres.
Following a call for evidence in 2021, Ofgem instructed the Electricity System Operator (ESO) to create a task force to look at short-term TNUoS reforms, while it considered the longer-term purpose and structure of the charges. The task force is expected to implement its proposals between 2025 and 2026.
Ofgem has now published an open letter setting its initial thinking on strategic TNUoS reforms. In line with its position from its significant code review of network access arrangements, the regulator said it continues to believe that transmission charges should not be used to send short-term operational prices signals based on system conditions at the time.
The regulator said such charges would need to be derived from a “robust whole system model that is synchronised with, or able to accurately simulate, wholesale, balancing and flexibility markets”. It adds: “This would represent a step change in the complexity of charging arrangements which would require a major transformation of the technical systems that underpin system operation and wholesale and balancing markets in GB.”
Without this transformation, the charges would likely come into conflict with price signals from other markets, leading to “unexpected or inefficient” behaviour that would make system operation more difficult.
Ofgem said there are more efficient ways to send operational price signals, which are being considered as part of the government’s Review of Electricity Market Arrangements.
Although forward-looking charges are intended to reflect users’ impact on future investment, at the moment they are based on the current configuration of the network. Ofgem said an alternative approach would be to determine the charges based on the forecasted future network.
This would reduce uncertainty and align investment signals with the Centralised Strategic Network Plan being developed by the ESO but would require a high level of confidence that forecasts are followed, “otherwise there runs a risk of inaccurate signals being sent to parties”.
The regulator said its initial view is that this would be better than the current arrangements.
Ofgem said another possibility is recovering a greater proportion of network costs through connection charges.
This would provide a strong investment signal that is more reflective of network users’ impacts on costs, although Ofgem said there is also a risk that this could deter investment and result in freeriding – issues that prompted the regulator to move in the opposition direction on distribution connection charges.
Ofgem said TNUoS charges could also be altered to reflect the impact of different costs drivers. The regulator identified three potential types of charges: expansion-based charges, reflecting the long-term costs of building and maintaining the network; losses-based charges, reflecting the cost of transmission losses depending on how close generation is located to demand; and spare capacity-based charges, reflecting the costs of network constraints in different areas.
The regulator said these charges could be used in combination.
Ofgem said another consideration is the granularity of charges. It said locational granularity could be increased by moving from 27 zones to a nodal approach with different charges for each grid supply point. This would increase variation between locations and send a stronger, more targeted signal for investment.
Meanwhile, temporal granularity could be introduced by varying charges based on the time of the day or year, for example, with peak/off-peak charges or seasonal charges. In contrast to operational price signals, these would influence general patterns of usage to reduce costs in the long-term.
Ofgem said there is also the question of the frequency of resets for charges. The regulator said these could range from real-time changes to multi-year charging periods, although given its position on operational charges it ruled out the former. It said one possibility is that charges could be set annually but form part of longer-term contracts so they are stable for a period of time after connection.
Furthermore, Ofgem said it is considering whether charges should be based on capacity (£/kW) or energy consumption (£/KWh) and whether different types of users should be charged differently according to characteristics such as voltage, size, load factors and generation and demand profiles.
As well as feedback on these issues, Ofgem also sought views on how storage should be treated given its unique characteristics; to what extent demand users should be exposed to price signals, especially in the case of households, which are unable to locational signals; whether generators should continue to receive credits in some parts of the country; and how charges should vary between voltage-levels given the changing nature of network flows.
Finally, Ofgem highlighted the interactions with other market and policy in reforms, in particular REMA, which is considering the introduction of zonal and nodal wholesale pricing.
The regulator said it will continue assessing the case for change over the remainder of this year before developing a framework for identifying and assessing options. The deadline for responses to the letter is 15 November.