Electricity market reform and the gathering CfD storm

The current marginal pricing system for electricity no longer works when moving from mostly fossil generation to mostly renewable generation and is likely to cause price crashes, writes Mike Parr. Unfortunately, the expected conversion to Contracts for Difference (CfDs) will only make things worse, he argues.

Mike Parr is director of PWR, a UK-based company providing market research and technical support in the field of renewables and energy efficiency.

The current trajectory for EU electricity market reform (EMR) is to retain the marginal pricing system by which wholesale electricity prices are defined whilst mandating a mixture of contract for difference (CFD) and power purchase agreements (PPAs) for all new renewable projects.

However, concerns have been raised on the medium and longer-term consequences of taking this route. Furthermore, member states such as France, unhappy with the slow progress of EMR, are threatening to go it alone on market reform.

Member states and CfDs

Some EU member states see CfDs as a source of revenue. Their assumption is that CfD prices will be mostly lower than wholesale electricity prices, allowing them to pocket the difference between the wholesale price and the CfD price paid to renewable projects.

The rating agency Standard and Poor (S&P) and the European Commission are somewhat sceptical that CfDs will deliver revenues to EU member states. In short, as renewables funded by CfDs grow, this, in turn, will cause an increase in wholesale price crashes.

The Commission knows that more renewables will cause more market price crashes. In its view, far from member states enjoying revenue from CfDs, electricity consumers will pay more for such price crashes. Consumers will, therefore, pay twice – first for the kilowatt hours they use (usually fixed in price), and then a second time to cover the difference between the zero or negative wholesale market price and the CfD price promised to a given renewable project.

An alternative to this situation is for electricity retailers to use “smart metres” to deliver real-time pricing to customers, reflecting the wholesale price at which retailers buy electricity.

However, there seems to be little prospect of this happening in the next 5 to 10 years.

Marginal pricing: Past its “sell by” date

The core problem is retaining a marginal pricing system as electricity generation moves from mostly fossil to mostly renewable.

Marginal pricing works well for fossil systems that have a fuel cost input that is linked directly to the price of the electricity generated. By contrast, renewables have no direct cost inputs, the wind or sun does not send a bill.

Instead, renewables have up-front capital costs, which define the fixed cost of a megawatt hour from a given renewable project for the next 15 or 20 years. Marginal pricing does not and cannot work with renewables. The price turbulence in wholesale markets, directly caused by renewables, proves this point.

Paris vs. Berlin: Bald men arguing over a comb?

The argument between France and Germany on electricity market reform has grabbed most of the public attention so far. While Paris wants to use CfDs to finance the lifetime extension of its existing nuclear plants, Berlin rejects this, saying this would amount to an unfair subsidy.

Without a deal, France is threatening to go it alone. But the reality is that, in terms of how France sets its wholesale electricity price, it already does “go it alone”.

European electricity markets are heterogeneous in how wholesale electricity prices are formed in each member state. In France, wholesale electricity markets are dominated by nuclear generation. Most of this is sold ahead on futures markets. The French regulator estimates that the day-ahead market (which uses marginal pricing) only accounts for perhaps 4% of market volume and thus has a modest influence on real wholesale prices.

Next door in Spain, the day-ahead market, by volume, accounts for 75% of electricity sold and thus, Spanish day-ahead prices provide a very good view of real wholesale prices.

Germany, meanwhile, sits somewhere between France and Spain.

PPAs, power supply contracts between a generator of electricity and end users, promise to provide electricity at a fixed price over a pre-determined period of time, typically several years.

France, according to the Euractiv article, might decide to massively expand PPAs. However, French regulator reports on French power markets show that the dominant way electricity is bought on French wholesale markets is via futures contracts, which extend from months to years.

Thus, France already seems to use a sort of PPA. This begs the question, given that France already uses a PPA-like instrument for most wholesale market contracts, what does “massively expand” mean in this context?

The argument between France and Germany may be to do more with two fundamentally different (and perhaps irreconcilable) approaches to how to price wholesale electricity.

Where does this leave us?

The marginal pricing system worked well until renewables started to arrive in market-disrupting quantities post-2015. Adhering to a marginal pricing system that causes massive price crashes and price rises works very well for electricity traders, who make money on volatility.

However, this is not in the interests of renewable project developers, EU member states or EU citizens.

The question to be answered regarding market reform is, will this be done promptly to support an EU renewable future and supply electricity to EU citizens that is truly reflective of generation costs? Or does the EU stick with a marginal pricing system that mostly benefits market traders and hinders renewable developments, causing headaches and disappointments for member states?