By 2035 there will be periods when lack of wind and solar generation is low and electricity supply falls dramatically short of demand. But those times are far outweighed by periods when the GB system has a large excess of generation – expected to be 50% of hours by 2030 and more than 90% of hours by 2050, according to modelling newly published by the system operator.
The current design of the GB market does not bring forward flexibility that would allow the problem to be managed. The swing, and the problem of incentivising storage, is illustrated by modelling of a winter in 2035 that shows supply falling short of demand by over 21GW for a week in January – but oversupply at other times, including a week in December with almost continuous excess generation of over 38GW.
The need for new flexible technologies and storage to manage sometimes-dramatic imbalances between supply and demand is one of three areas where the electricity market must be redesigned, the electricity system operator (NGESO) says. For example, the system operator says electrolysis to produce hydrogen is an important technology that will allow excess renewables to be used instead of ‘spilled’, along with other demand side technologies.
The modelling comes in NGESO’s new publication Net Zero Market Reform: The Case for Change in GB Electricity Markets, an update on work throughout the year assessing how the market must change.
It sets out three interlocking challenges. Alongside flexibility the two other interlocking challenges are ensuring the necessary investment is made in generation assets, despite the fact that the change to renewables means that the electricity price will at times be zero or negative, and ensuring generation assets are located in the best place for managing the system at least cost.
The need to reduce the risk of investing in new capacity requires mechanisms such as Contracts for Difference, which provide a predictable return – but such fixed prices mean the benefit to consumers of periods of low prices is lost, while at the same time weakening market incentives to invest in flexible technologies such as storage that use price arbitrage. Low prices will undermine the financial viability of merchant-only and non-supported generation assets, NGESO says – and may also mean plants close prematurely when the support period ends and they rely on merchant revenues.
Finally the locational challenge is already growing, as the ‘single price’ across the GB system provides no incentive to use local generation, so that ‘constraint’ costs (which arise when power generated cannot be transmitted to where it is needed) are rising. More investment in transmission in constrained areas such as the Scotland/England border will partially relieve those costs over time. However ‘use of system’ charges under the current framework are likely to remain “both volatile and unpredictable”, NGESO says. That uncertainty also raises the cost of investing in new capacity.
The response to these challenges requires substantial transformation of GB’s electricity market, NGESO says. In the first stage of assessing options for a redesign it has ruled out two ‘markets-only’ options – relying on wholesale market signals to ensure there is adequate capacity and on short term markets to being forward the necessary flexibility. It is now investigating a variety of market designs that combine mixtures of locational signals, long term flexibility contracts, low-carbon competitions, national and local markets and new types of procurement.
NGESO expects to conclude the phase of work by April 2022, at which time it will present a set of recommendations on market design and a roadmap for implementation.

Read the full report NGESO_The Net Zero Market Reform_Report_PRINT