Soaring wholesale power prices across Europe that are on average three times higher than this time last year are making headlines across the continent.
The reality is, though, that very few customers are paying these high prices as most power is bought and sold through so-called bilateral agreements, which were signed when prices were much lower.
But the concern is what will happen in 2022 and thereafter. If wholesale prices stay at current levels, energy prices across Europe will rise, and for all types of customers, from industrial to retail. Any such prices rises will be bad for the fight against climate change, given that electrification is the quickest and easiest way for society to decarbonise.
The ‘energy crisis’ has the EU, governments and regulators calling for change. The good news is that the solution is at hand — power market reform — and it will be beneficial for the consumer, industry and the environment.
The European electricity wholesale market follows a system of so-called marginal pricing, meaning that everyone receives the same price for the electricity they are producing at any given moment.
The actual price is determined via auctions where marginal plants, which are the most expensive plants allowed to generate in a particular time period, establish the price for everyone for that period. In practice, what this means is that gas and, to a lesser extent, coal plants set the prices three quarters of the time, despite producing less than a fifth of European electricity production.
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If we go forward to 2030 and assume that the 700GW of renewables — which is needed to hit the EU’s 2030 targets — is built, then we will have the power price being determined by a generation technology that provides maybe 5% of total generation. Does that really make sense?
The current power market structure was designed for a world of fossil fuels, to ensure there was fair competition between generators and to ensure that varying fuel costs could be passed onto the consumer. This worked well, but to decarbonise going forward we need lots of zero-carbon electricity in the form of nuclear, hydro, solar and wind — all of which have zero or close to zero fuel costs.
These technologies all have high upfront costs, which means that bringing in low-cost finance (ie, capital that is willing to accept a low return) is critical to ensuring reasonable costs for the consumer. This is why most renewables have been financed using long-term power-purchase agreements (PPAs) that give the investor a lot of visibility around long-term future cash flows. Some of these PPAs have been made with businesses but the vast majority are some form of government backed PPA in the form of a feed-in-tariff or contract-for-difference.
If we continue building renewables in a similar fashion, it will mean that by 2030 the vast majority of electricity produced in Europe will be produced under some form of long-term PPA, adding to the question of whether the marginal cost model should remain.
The governments of Spain, France, the Czech Republic, Greece and Romania are already thinking along these lines, and recently released a joint statement calling for the wholesale electricity market to be reformed.
“The electricity market has many advantages: it secures energy supplies at all times, for all European countries. But it needs to be improved to better establish a link between the price paid by the consumers, and the average production cost of electricity in national production mixes. This is all the more important as decarbonisation will increase the use of electricity in our economy,” they wrote.
This leads to the question of what a reformed power market could look like.
For hydro, wind, solar, and maybe nuclear, it could be similar to what happens today, with producers receiving an agreed power price for a period of time for any power produced. The pricing would be decided using auctions, with the only difference to the current system being that the power purchase agreement should be over the useful life of the asset (meaning for solar 30 years, as opposed to the current norm which is 20 or below).
Alongside these state-backed contracts will be commercial PPAs whereby industrial and commercial customers purchase power under long-term agreements from clean energy producers. These corporate PPAs have a role going forward but there are very few customers who can sign bilateral agreements agreements greater than ten years and that have the quality of business, balance sheet and credit rating to ensure that low cost of capital flows into renewables.
However, if we are going to accelerate decarbonisation, we will need to put in government-backed incentive structures to ensure a cost effective and speedy transition.
For back-up fossil fuel technologies, such as reciprocal gas engines, which may be needed on those dark winter days when there is no sun and wind, asset owners would be given a fair return for building and maintaining their assets, and to make sure that they are available if and when needed. This back-up market would only be called upon occasionally and could operate similar to the marginal pricing market today, with players competing based on price for the ability to produce power.
The next piece of the puzzle, and perhaps the most important, is flexibility. Traditionally, generation has followed demand, ready to supply any quantity at any point in time.
As the system accrues a higher proportion of variable renewables, there will be times when there is a surplus of power in the system and times when there is too little.
Generators need to be incentivised to store that surplus electricity for future use. On the other side, consumers need to be incentivised to delay non-critical consumption and to use whatever other flexibility that is available in the home or business such as hot water storage or EV batteries to benefit the whole system. For this to happen we need to remove bureaucratic and regulatory hurdles to allow the digitalisation of the power system and to put in place the right market mechanisms and incentives.
Finally, we have to expect and deal with resistance from incumbent players, many of whom are benefitting significantly from the marginal cost market system, especially when prices go up.
So for instance, a hydro producer who was last year receiving €50/MWh with production costs of say €40/MWh could, if they have not sold that power in advance, be receiving a windfall profit of €100/MWh because wholesale prices, due to higher gas prices, are at €150/MWh.
The way around this is to offer these producers either a long-term PPA from the government that allows them to make a fair return. Or to sell that power through long-term PPAs to their industrial, commercial and retail customer base.
Going forward, change will be complex and will meet much resistance, but if we are going to decarbonise quickly and cost-effectively, we have no choice but to abandon old ways of thinking and embrace new ones.
This post appeared first on Recharge News.