UK companies face higher energy costs than many of their international competitors. Stubbornly elevated power prices have contributed to renewed calls to slow or abandon our net-zero goals, and to the usual misguided demands to frack Lancashire or reinvigorate North Sea oil production.
There are strong counterarguments. High UK power prices are largely a function of our continued dependence on natural gas, not the cost of renewables. Other countries, such as Germany, are as committed to the net-zero transition, but impose less of the cost on industrial users. In stark contrast to the United States, the UK’s days of abundant fossil fuel production are over, and there is little public support for domestic fracking. A failure to tackle climate change will, over time, impose much greater economic costs than the clean energy transition.
However, it is important to acknowledge that the transition is imposing near-term costs on energy consumers. The transition itself will lead to these costs failing: this suggests that policymakers need to hold their nerve, and that advocates should continue to make the energy security and improved health arguments that also support clean energy.
For commercial and industrial power consumers, it is important to understand the new dynamics of an electricity market in transition. A system increasingly dominated by intermittent renewables is leading to a wider range of prices, including a growing number of extreme pricing events – providing opportunities to shift patterns of consumption (or even become a supplier) to significantly reduce power bills.
But first, let’s examine how the energy transition is affecting power markets.
Paying down the costs of transition
It is undeniable that the energy transition is imposing upfront costs on consumers. Although the levelised cost of energy from onshore wind and solar is much lower than that of gas, investments are needed to adapt the grid to a more decentralised system and to ensure there is a sufficient despatchable generation (thermal power plants, biomass, hydro, battery storage etc.) to meet demand in periods of lower renewable power supply.
There are also costs from directly supporting renewables. The current Contracts for Difference model has added 2.9% to household bills over 2019-24, the House of Commons Library has calculated. Its predecessor, the Renewables Obligation (RO), currently adds around 15% to bills.
The good news is that these so-called ‘non-commodity’ costs are forecast to fall as the transition progresses. For example, RO payments account for around a third of these costs. Many RO payments – which typically run for 15 years from the commissioning of qualifying renewables capacity – are coming to an end. For example, 2.7GW of RO capacity came online in 2012, which was a bumper year for renewables. From 2028, these plants will be operating without subsidy, contributing to a 25% fall in RO payment levels between 2026-27 and 2027-28.
It's the same story with the Capacity Mechanism, which is designed to keep despatchable capacity available to meet demand at rare periods of inadequate supply. It is projected to rise from 5% to 15% of non-commodity costs, before declining by a third from 2027-28 to 2028-29, as more battery storage comes online.
Pricing to the extremes
In the meantime, the shift to a system dominated by renewables is increasing power price volatility. As we have discussed in earlier blogs, the market operates on marginal pricing, meaning that the price bid by the most expensive plant needed to meet anticipated demand for each 30-minute slot sets the price paid to all generators. In the UK system, gas-fired capacity typically set the power price 98% of the time in 2021 – meaning UK consumers were especially exposed to natural gas prices. This was a marked change from the years 2015-2019, when gas set the price 80-90% of the time.
But the growth of low-cost renewables paired with high-priced gas means that prices also vary significantly during the day (see charts below showing price spread for specific days in each month in 2024). In periods of strong winds, high solar radiation, and low demand, prices can be significantly lower than peak periods, especially during the winter and when wind supply is low.
These high charges are exacerbated by non-commodity charges, which are often higher in periods of high demand.
For example, companies are required to pay variable Distribution Use of System (DUoS) charges to cover the costs of maintaining and operating electricity distribution systems. These are set considerably higher during periods of high demand, such as the early evening peak. Similarly, payments for the Capacity Mechanism are only made during peak winter periods and are expected to rise significantly over the coming years:
2024–25 Delivery Year
Implied CM charge (peak periods): ~£116/MWh, i.e. ~11.6 p/kWh during 16:00–19:00.
2025–26 Delivery Year
Implied CM charge (peak periods): ~£130–135/MWh (≈13 p/kWh).
2026–27 Delivery Year
Implied CM charge (peak periods): ~£240/MWh (approximate; ~24 p/kWh)
2027–28 Delivery Year
Implied CM charge (peak periods): ~£250–260/MWh (≈25–26 p/kWh)
Playing off the extremes
For I&C consumers with the ability to flex their demand, these new market realities provide opportunities to reduce their energy costs. For example, refrigeration units could be ramped up during periods of low or negative prices and temporarily turned off when prices are high. Electric vehicle charging could be timed to avoid peak periods, or building air conditioning systems could be turned down in response to price spikes.
Similarly, these variable prices also help to reinforce the economics of behind the meter battery storage systems. Such systems can allow users to arbitrage between low and high prices, as well as providing back-up power as required.
Longer-term, there is potential for new energy-intensive production models to emerge that build in the ability to flex production, and hence power demand, in response to power prices. Currently, most industrial processes are designed to operate 24 hours a day. While reducing that to 18 hours would increase the time needed to recover the capital investment, the flexibility provided to take advantage of power price volatility could more than offset increased financing costs.
A more dynamic world
These are complex decisions to take, with significant implications for companies that seek to pursue a more dynamic approach to their power consumption. But they demonstrate that consumers do not need to be passive actors in the face of the higher power prices that, at least in the medium term, are needed to finance the energy transition.