Perspective | Is the design of the electricity market costing consumers money?

This article is from our Energy Spectrum publication which was published on 4 March 2022.

It has become increasingly clear the existing market design is unfit for either a future net zero world or a period of fossil fuel price crisis, but what market design might be best for our immediate and long-term future?

If we accelerate the deployment of renewable resources to reduce the use of gas, would the price of power actually fall? Even though the UK generated 41.9% (wind and solar combined) in February 2022 from renewables resources, the price of electricity has increased in line with the gas price.

This is because the price is related to the cost of the marginal generator on the system, which is usually a gas fired power station, and therefore the price of power is intimately tied to the price of gas.

Of course, any reduction in gas use should help reduce the overall cost of gas, as the marginal price effect also exists in the gas market, and by using less gas we no longer need to import or produce the most expensive molecules. But while gas markets are as tight as they are, and likely to stay that way, can the cost to consumers be cushioned by a different market design which does away with marginal pricing?

What is marginal pricing?

Marginal pricing is related to the idea of the merit order. This is the order in which different generators or resources are turned on or connected to the system to provide power, from cheapest to most expensive, where the final generator running to keep load supplied is the marginal generator. It is the expectation of the generators in the market that the price needed to keep this marginal generator on the system is the price needed to keep the lights on, and that they should be rewarded for providing power at this rate.

This means, for example, in the day-ahead auction every generator is paid at the clearing price of the market, the price paid to the most expensive generator to keep the lights on. In the bilateral markets, where parties contract with one another and there is no centralised price mechanism, parties seek to be paid or pay close to the marginal cost of the generator they think will be needed to meet demand.

So, the implication here is that any generator which is likely to be lower in price than the marginal unit, will make a profit equal to the difference between their marginal cost and the cost of the marginal plant. This is especially useful for renewables generators as they have a very low (almost nothing) marginal cost and can therefore capture a large profit from running to pay back their high upfront capital costs.

What are the alternatives?

In a world of rising gas prices, the marginal cost of generating power from gas keeps going up, and as the marginal unit is generally a gas-fired unit all generators are earning a revenue that reflects the gas price even if they have not burned any gas. Given renewables do not burn any fuels, why are they being remunerated as if they have? If the objective is to lower costs to consumers should not the renewables generators be paid a price that reflects their costs?

One proposal from the Aldersgate Group and UCL is to create a Green Power Pool – a separate market where only renewables participate. Generators bidding into this pool would get a priority dispatch in a linked wholesale market which allowed other generators to participate.

In this market, there is a separate clearing price for renewable power and a guaranteed offtake for the generators. This would allow consumers to access low-cost bulk power themselves, or through the government, at the Long Run Marginal Cost of the renewable generators. The proposers also expect it to encourage the development of long-term storage as it would allow these assets to procure lower-cost renewables at guaranteed prices rather than taking a merchant position in short-term markets.

A similar thing was proposed by France and Spain in October 2021 to decouple electricity markets from the gas market, but they were rejected as outside the principles of the internal energy market – they were calling for European Banks to support long-term Power Purchase Agreements (PPAs) between customers and generators. This would likely require a government intervention to set up a centralised pool where buyers could access credit from the government to make long-term purchases from the pool of generators seeking revenues and where the government could access long-term offtake agreements directly.

Should we or shouldn’t we?

Renewables are, in any likely future scenario, going to make up the bulk of power supplied to customers in GB, so purchasing that power at fixed prices without any exposure to volatile gas prices could result in lower overall cost to consumers, especially in a world where investment in gas is declining because of fear of stranded assets.

Given the overwhelming imperative to construct significant volumes of new renewables capacity to meet our targets, one of the most important levers we can manipulate to lower costs to consumers is the cost to finance these assets. Granting investor certainty through long-term fixed prices will help in that regard.

Although ultimately, we do not see these arrangements differing in great regards to the Contract for Difference (CfD). Here there is a guaranteed price that insulates generators from the spot wholesale market. This might be viewed more favourably by investors by providing a guaranteed market for power for the lifetime of the asset rather than just the 15 years under the CfD. What would the role be for suppliers in such a market, where most of the power is bought by a central pool, with little customer involvement? Perhaps the reduction of costs under a majority renewable system can be achieved more easily by increasing settlement frequency and allowing the LCCC to charge negative CfD rates to suppliers, rather than returning money piecemeal later by offsetting the reserve amount.

But moving the market arrangements in such a way will create significant implementation challenges, not least of which is the migration costs of moving wholesale market arrangements for Renewable Obligation Certificate (ROC) and CfD schemes. This might be relatively simple in the CfD, where the reference price can be changed to the Green Power Pool price, but ROC generators are unlikely to be keen to move away from potentially high gas-related prices to prices set by new lower levelised cost renewable projects.

The Green Power Pool likely also comes with the same disadvantages as the CfD. By insulating generators from the effects of wholesale power prices on the dispatch of renewables, balancing costs associated with temporal and spatial issues will drive BSUoS charges upwards, as identified by NGESO in its Market Design for net zero work. The design could be adapted to work with locational marginal pricing, and create nodal prices for consumers and generators, backed up by Firm Transmission Rights purchased by the GPP, but that still leaves the question of cost-effectiveness of any LMP system coupled with a revenue stabilisation system hanging.

Very high gas prices also act as an incentive for merchant projects to deploy, or for subsidised projects to deliver early and earn merchant revenues before their subsidy starts, therefore separating all renewables into a separate Green Power Pool would deter this behaviour which might be useful during crisis-driven price spikes. Given the significant cost and time to implement split market arrangements, this is not going to be a solution to the immediate price crisis, but the real test will be if it delivers the new investment needed to meet net zero targets and insulate GB consumers from international fuel prices. I am not necessarily convinced it delivers a better solution than the current or reformed CfD, with significant implementation costs. And it’s not clear it delivers on the dispatch challenges National Grid ESO considers to be of critical importance.

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