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Time for a change to the wholesale pricing model?


6 min read

Series of wind turbines in Scottish hills, set against blue sky Photo: EDF
Rural onshore wind farm, Burnfoot East, Scotland

Photo: EDF

From Cornwall to Thurso, UK household consumers pay the same unit price for their electricity, despite the cost of getting it there. Yet this may have to change as more locally-based renewable generation is connected to the power grid. Nick Cottam reports.

Providing remote, sparsely populated parts of Britain with an electricity supply can be an expensive business. The cost of getting power to and from the north of Scotland, for example, is a world away from profitable distribution made by generators to customers in the south-east, yet household tariffs for each region are just about the same.


To offset this imbalance in supply costs, the UK’s transmission system, namely the National Grid, intervenes financially to ensure energy is made safely and gets to those who need it, wherever they live.


However, the current arrangements may need to change, admits the government, if Britain is to transition to cleaner, more cost effective, more responsive and, ideally, more localised electricity supplies. If those living in the Highlands of Scotland end up paying more for their electricity because supply is limited, generators may well be incentivised to increase supplies to the region. The alternative for consumers is to reduce demand or become more self-sufficient, for example via onsite renewable energy such as solar.


While increasing supplies of renewable energy is the net zero nirvana, the thorny issue of supply and demand in the energy market has also been brought into sharper focus by rising costs and the pressing need for higher levels of energy security.


Location, location
One option currently being considered is the introduction of a system of locational pricing, similar to those operating in several other European countries and in the US. The idea is to make the energy market more price sensitive, more reactive to changes in supply and demand.


‘At present’, notes a recent Drax Insights report: ‘There is a single price for electricity across the country in each half-hour trading period, regardless of where it comes from or where it is consumed. Changing this could make the system more efficient, but it would create winners and losers.’


With a system of locational marginal prices (LMPs), the price of supplying electricity at different points of the network would be monitored on a regular basis throughout a trading period.


If there is a surplus of power supply to one part of the country, prices to the consumer fall and the generator has an incentive to cut supplies. On the other hand, if there is a shortage of power in a region, prices rise and generators may want to increase supplies. This should produce a more responsive, more cost-effective energy market.


A key driver for change, notes the government in its latest Review of Electricity Market Arrangements (REMA), is the race to net zero and the ambitious target to deliver a fully decarbonised power sector by 2035. Meeting this commitment, the report optimistically notes, requires an even faster scale-up of technologies. Better load targeting and smarter wholesale pricing are all part of the equation.


While increasing supplies of renewable energy is the net zero nirvana, the thorny issue of supply and demand in the energy market has also been brought into sharper focus by rising costs and the pressing need for higher levels of energy security.


Climate change to blame
The Drax Electric Insights report draws a stark contrast between financial arrangements for the supply of electricity currently operating in the UK and those in the US, where the electricity market relies on a tried and tested system of LMPs. Up until now, this UK/US divide is unsurprising, given the smaller size of the former and more dramatic regional variations in climate and weather in the latter. More extreme weather in both countries, arguably caused by climate change, helps make the case for locational pricing.


In the US, the LMP system currently works by calculating hourly prices for thousands of nodes on the network based on distribution traffic and demand.


As the Drax report notes, this ‘gives generators incentives to operate in ways that do not overload the transmission system’. It adds that: ‘If more local generation is needed to overcome a constraint on how much power can flow into an area, prices can rise in that area to encourage more generators online. Similarly, areas with surplus generation would see lower prices, encouraging some stations to turn down their output.’


The result is a price sensitive electricity market designed to accurately reflect and incentivise supply and demand.


On this side of the pond things have traditionally been done a bit differently. The Drax report describes a nationwide system of wholesale prices which require National Grid, rather than the market, to take a central role in influencing generator behaviour. UK generators don’t have the same incentives to change their behaviour as their US counterparts and, as the report notes: ‘National Grid must pay them separately to keep the transmission system operating within safe limits.’


This, it is estimated, adds in excess of £2bn/y to the wholesale cost of UK electricity. Generators must pay to use the transmission system but, by the same token, National Grid must reimburse them to keep electricity supplies safely going to more remote regions. In the context of developing a more flexible, more renewables-focused energy market it is a model that’s beginning to look rather dated.


In 2022, for example, renewable energy accounted for more than 50% of Britain’s electricity. As capacity increases this should bring about a significant reduction in LMPs, which is why developers of new and expensive renewable energy capacity – think offshore wind and nuclear – receive a guaranteed price for the electricity they produce over a given contract period.


Price guarantee
The UK government’s Contract for Difference (CfD) scheme has been successful in underwriting the development of wind energy, significantly reducing both capital and operating costs and bringing about a huge increase in capacity. In 2022 electricity from wind made up 27% of the Britain’s supply.


The CfD scheme guarantees a fixed price to the developer over the period of the contract, while consumers are protected from paying increased support costs when electricity prices are high. Ørsted’s Hornsea 2 wind farm, for example, which became fully operational last year, is the world’s largest wind farm with 165 turbines, helping to power 1.4 million homes. The wind farm’s long-term revenue will be underpinned and capped by a CfD which Ørsted plans to activate this year.


Economies of scale, claims the company, will produce the UK’s lowest ever electricity price for offshore wind with a strike price of just £57.50/MWh over a 15-year period. This looks cheap against the £92.50/MWh agreed for the nuclear station Hinkley Point, albeit over a 35-year life cycle period.


The growing importance of energy security means that these different sources of renewable energy need to be included in the mix. In recent years Britain has been importing far more electricity than it exported, but last year the country spectacularly reversed this trend, exporting four times as much electricity as in the previous year – a total of 1.9 TWh, worth an estimated £3.1bn to the economy.


This was largely due to net exports to France as the French nuclear fleet went offline for maintenance over the summer. It was bolstered by robust (and robustly financed) UK wind energy.


‘The lesson from 2022,’ says Iain Staffell of Imperial College London, ‘is that we need to break our addiction to fossil fuels once and for all if we want lower-cost and more secure energy supplies.’ Will Gardiner, Chief Executive of Drax agrees, calling for an increase in homegrown renewables ‘and innovative green technologies such as bioenergy with carbon capture and storage and pumped storage hydro’.


Going with the flow
Whatever the source of electricity, its use of the distribution system has to be paid for by the generators who provide it and by the consumers who use it. While consumers’ prices are fairly even throughout the country at just over 30 pence/kWh, there is a significant regional variation in the tariff paid by generators. Electricity tends to flow from north to south, so generators pay more to use the system in the north than in the south where less distribution is needed.


As the Drax report notes: ‘The Torness nuclear station near Edinburgh pays about £20 per kW per year to use the system, while Sizewell B in Suffolk pays only about £2 per kW. On the current tariff, Hinkley Point C in Somerset would be paid about £5 per kW…’


The reality – financial and otherwise – warns Ofgem Chief Executive Jonathan Brierley, is that ‘volatility in the energy market is not over’. Ofgem, he says, must support the UK government ‘and take action over the next decade to build an energy market that will support the longer-term transition to net zero at least cost to consumers’.


Finding a wholesale electricity pricing structure which delivers timely, cost-effective electricity to exactly where it is needed, is all part of the challenge.