Low prices, spreads and diminishing renewable subsidies…is anyone a winner in the European power market?

Author: ABB European Advisors

On the face of it, the European electricity market is a challenging place to be. Market prices and spreads are low and fossil plants are at the margin with dwindling opportunities for profitable running as cheap must-run renewable generation floods the market. Capacity markets still seem some way off in pivotal markets such as Germany, France and Britain, with little consensus about design or payment levels. Feed-in tariffs for renewable generation are under threat, leaving renewable generators faced with the potential prospect of becoming exposed to market volatility and significantly lower market prices. Residual load is shrinking – or at best staying flat – as subsidised must run generation continues to come on line, so the prospects for significant new entry (other than replacement) are bleak. Retail customers are seeing little benefit from the market turmoil as the costs of subsidies and creaking transmission grids are loaded into tariffs, and in most countries previous years of under-recovery and sectorial cross-subsidies are being unwound.

Is anyone winning in any European power market – or, more to the point, should anyone be winning? The answer is a qualified yes: those players who are flexible and have the right market intelligence, analytical support and cost structure to be able to make fast, informed decisions – and be the cheapest unit around at the right time. The areas for opportunity are not lying in large-scale investment in old, conventional technologies, but in demand-side management, re-financing and re-contracting fuel supplies of existing generating units to ensure they are as flexible and competitive as possible, and in ensuring that traders have the best information at their fingertips to be able to “pick” the best hours to generate.

Power markets are becoming simultaneously increasingly international and localised. More and more sophisticated interconnector trading (another opportunity for “winning” here – see the example below) forces power stations to not just compete to meet residual demand in their own country, but to compete against foreign, often cheaper, generating units potentially on the other side of Europe. Cheap, flexible, coal units in central and eastern Europe could be real winners here (and even existing nuclear generators, if they can flex their units sufficiently to avoid negative prices), at the expense of more expensive fossil (especially gas) plant across North Western Europe. However, they are also competing against effectively free renewable generation, so will be the “first call back-up generation”. Not really a winner’s badge, but arguably better than mothballing or a slow decline.

At the same time, increased congestion and lack of central control of growing volumes of intermittent resources, often embedded deep in the distribution grid, gives opportunities for generators to take advantage of hyper-localised transmission constraints, reserve requirements and balancing markets. In the volatile reality of near-to-real time and real-time plant operation, well-placed, flexible, available units can make money regardless of their underlying economics – just a few hours of operation in the balancing market can prove highly profitable.

In markets like these, detailed analysis is everything, as answers are not always intuitive. Take the example of interconnection. If you increase interconnection capacity between two countries, then that ought to increase the arbitrage opportunities between the two countries and prices should decrease. Shouldn’t they? Well, in fact not in all cases, as the following example indicates where interconnector capacity is increased between France and Great Britain by first 1 GW, and then 2 GW. Market Prices (MCPs, based on the marginal cost of production), actually rise in both countries. Why? France, the home of relatively cheap nuclear generation, is able to export more to Britain than it used to, and more expensive generation is now able to come on line in France (which is still cheaper than British fossil plant). That should make the prices go down in Britain as they enjoy more, cheaper, imported generation; and indeed during these particular periods it will. But in later years, British prices actually go up. Why? The increased interconnection permits “trapped” excess wind and other relatively cheap renewable generation to be exported from the UK into France.

Annual Market prices (MCP) in Great Britain and France from ABB Reference Case, plus two interconnector scenarios
Source: ABB

Without the additional interconnection, a significant amount of British wind generation is surplus to requirements – there is not enough demand to match all this cheap, “must run” generation. The result is price collapse – generally to zero, or below, and wind generation has to be curtailed (pulled back) to avoid grid instability. With increased interconnection, this wind generation can flow into Continental Europe and displace more expensive fossil generation (assuming it is not windy and sunny across the whole of Europe). Indeed the ABB model – with its assumptions on wind generation profiles across interconnected Europe – shows that this happens often enough for prices to go up in Britain as a result, quite significantly by the end of the study and, as the below graph shows, wind curtailment caused by border constraints to be decreased by up to a third. The increased price volatility and interconnector trading also yields potential for astute portfolio players and traders with flexible options for trade.

Forecast Wind Curtailment for British Market due to interconnector constraints, ABB Reference Case plus two interconnector scenarios
Source: ABB

Gas versus coal is another competition being played out right now in the energy markets. Carbon trading should have made gas a clear winner, but a glance at the relative prospects of the two fossil fuels in Germany, as an example, shows the reverse is true. Individual coal generation load factors are holding firm as coal generation proves to be consistently cheaper than gas, and coal plant are able to flex sufficiently to cover higher priced hours (when there is a scarcity of cheaper renewable generation).

German Load Factors (% running hours)
Source: ABB

In the British market, the race to the bottom is being “won” by the coal generators – assisted by the carbon support tax imposed by the UK government to try to bolster the failing European carbon tax mechanism. You couldn’t really call gas plant winners, though, as even the most efficient H-tech gas plant reach a cliff-edge after 2020 as residual demand collapses and domestic fossil plant is largely relegated to providing load-following and peaking service, kept in reserve to cover cloudy, still periods of low renewable generation.

Source: ABB

A graph of forecast net operating revenues for key fossil plant across Northwest Europe perhaps summarises the challenges being faced by incumbent players. The gas plant are clearly suffering most, earning way below the target earnings required to achieve sufficient revenue to cover all fixed and financing costs.

Source: ABB

Is anyone really winning? Yes, the bankers specialising in re-financing, who ought to be enjoying full mailbags from incumbent players, both fossil and renewable, as their expectations of load factors, generated pre-recession (and even pre-renewables boom) when residual demand was relatively healthy, far exceed what is actually being achieved – and what will be achieved in the future.