Britain has chosen to secure electricity supplies through a scheme which pays power plants to be available several years in advance, but falling prices suggest this capacity market is overkill and poor value for money, with ample alternative approaches, writes energy finance consultant Gerard Wynn. Courtesy Energy and Carbon blog.
The Institute for Energy Economics and Financial Analysis (IEEFA) recently published a review of how nine countries and regions with exceptionally high levels of wind and solar power have coped with the variability of these power sources.
A costly solution
Britain has opted for a capacity market, in combination with other approaches, to cope with an expected increase in variability in electricity supply, as the country switches to the wind and sun.
The UK’s adoption of a capacity market may be overkill, putting vast sums of public money at risk
But it turns out that countries with far higher levels of so-called variable renewables are doing without capacity markets at all, finding that other measures are sufficient, such as investing in transmission capacity, reforming power markets and requiring renewable energy technologies themselves to play a bigger role in meeting power demand.
The UK’s adoption of a capacity market may be overkill, putting vast sums of public money at risk.
The capacity market approach pays utilities and other operators billions of pounds to commit to keep their coal, gas, nuclear and hydro power plants open, for up to four years ahead, regardless of whether they were planning to do this anyway, and regardless of whether they generate any electricity.
The capacity market – whose auctions have now been running for several years – has still not motivated a single large new power plant
The same utilities that are benefiting were big fans of the scheme when it was mooted in 2013. For example, SSE in 2013 warned that the UK was entering a “critical period”, including the risk of blackouts. Centrica also warned in 2013 of blackouts, in 2017/18, and said that it would not build another gas power plant without a capacity market in place.
As it happens, the capacity market – whose auctions have now been running for several years – has still not motivated a single large new power plant, but has allocated some £3.8 billion to power plant operators, including the same utilities, under auctions that are held 1 year and 4 years ahead of delivery, called T-1 and T-4 respectively.
Prices in the two most recent T-1 and T-4 auctions in early 2018 both saw price reductions, suggesting that the UK electricity system is coping well to date – see chart below. One would expect rising prices if the electricity system was short of capacity and needed a rollout of new generation.
Chart – Falling capacity payments under UK capacity market (nominal prices)
Source: the author’s and IEEFA’s interpretation of capacity market results data from the UK’s “EMR Delivery Body”
Falling prices
There are various possible explanations for these falling capacity market prices, including support in the early years of the scheme which motivated the construction of a new wave of very small generators; the prospective buildout of sub-sea interconnection into Europe; rising running times of gas power plants as coal power shuts down; and reforms to so-called cash-out markets to reward power plants that can respond quickly to supply shortfalls.
To its credit, Britain’s energy ministry did foresee the latter, saying before it introduced its capacity market: “In theory, as cash-out is fully reformed and the market has confidence to invest on the basis of scarcity rents the capacity price should tend towards zero under a capacity market.”
Such cash-out reform is a no-brainer, as an efficient market approach to incentivising flexible generation.
It isn’t too late to dial back the scheme, to focus on supporting emerging, enabling technologies such as battery storage
Given that the UK is both building out interconnection and reforming cash-out (which involves lifting caps on penalties and rewards for balancing real-time demand and supply), it may be that its capacity market is redundant.
Given the vast sums already spent, this is an important issue. It isn’t too late to dial back the scheme, to focus on supporting emerging, enabling technologies such as battery storage, and dropping support for existing gas, coal and nuclear, as IEEFA recommended last year.
Or it could even be phased out altogether.
More alternatives
IEEFA’s report reviewed nine case study power markets worldwide with very high levels of wind and solar power, at 14% to 53% of total generation. Only one of these, Spain, had a long-standing, comprehensive capacity market.
The report noted nine alternative actions that local and national grid operators and policymakers in these countries had taken to ease the transition to renewable power.
Those nine measures were: investment in the transmission grid; investment in cross-border interconnection; prioritisation of domestic flexible generation; market reform to boost flexible resources; support for demand-side flexibility; better wind and solar power forecasting; a more responsive distribution grid; making renewables more responsible for meeting demand; and national leadership in enabling renewables.
Editor’s Note
Gerard Wynn is independent energy finance consultant. This article first appeared on his blog Energy and Carbon and is republished here with permission.
Energy Post published an article about IEEFA’s report earlier this month.
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Peter Farley says
As renewables in the system increase, five things will happen.
1. Greater diversity both geographically and by type will shorten low generation periods and thus the amount of storage needed.
2. Technological advances such as low wind turbines, tracking solar and even coatings on solar panels to improve off-axis performance extend the output reducing both the non generation time and the minimum renewable power level
3. The risk of curtailment or negative prices will provide a strong business case for direct contracts for controllable demand eg power to heat or power to ice or even customer side batteries between generators and end users.
4 as volumes increase further and instances of oversupply become common, the swing between zero(curtailment) or negative prices and high peak prices makes a strong case for generator based storage. Not necessarily very much but 25% of capacity for 1-2 hours makes a huge difference to the annual revenue of a windfarm
5. Investors work out a balance between wind, solar biomass, hydro etc which optimises market performance by investing in niche projects which generate at different times from the normal summer solar peak or winter wind max.
if there really are periods with no wind and no sun someone will put in more biomass or storage or hydro because it will be very valuable power
Peter Farley says
one more thing based on the cost of the Hornsdale power reserve For about Pds 80 m you could have put in a 100 MW/250 MWh system. Pds 80 m would probably even provide a 100 MW 8 hour pumped hydro system. Therefore Pds 3.80 b will provide a mix of the two technologies would have given you 5 GW/20-25 GWh of storage or 12% of peak demand. As there is 8 GW of nuclear, 30 GW of gas and 4 GW of hydro/pumped hydro and about 5 GW of bio-energy and still 12 GW of coal and 4 GW on interconnects . i.e. a notional capacity of 68 GW. There should be more than enough capacity to meet peak demand of 51 GW
Mike Parr says
“Or it could even be phased out altogether.” That would involve the Tories admitting that is was wrong from the off. Tories don’t admit they are wrong – ever- so my guess is that cap’ markets will gradually wither – another daft idea from a “government” this is, basically, a rabble.