An Analysis of Current Power Station Bidding Strategies in Europe

Author: ABB European Advisors

The following post was written in May 2014 by the European Advisors team.

Wholesale power market prices are based on market fundamentals – principally the supply/demand balance, reflected through the incremental cost of generation – but also on power station behaviour as they “bid” their available volumes and prices into the market attempting to recover all their operating and financing costs.

In order to examine the impact of bidding strategies on wholesale market prices in Europe, ABB has developed three scenarios:

      • Scenario A: units bid at their short-run, incremental cost of generation
      • Scenario B: units bid at their short-run, average cost of generation and cycling units also bid-up to recover their start costs.
      • Scenario C: as scenario B, but units also try to recover their fixed operating (but not financing) costs at times of higher residual demand. The ability to recover these additional costs is phased in from 2018 to 2021 as reserve margins tighten across NW Europe.

In reality, no market is perfectly competitive, as in Scenario A. Prices and bidding today in power markets in northwest Europe look most like Scenario B, where plants are recovering their short run variable costs, but not all of their fixed costs. If the market continues to out-turn at Scenario B levels, prices will remain at around €5/MWh on average above incremental cost levels, and €5/MWh-€10/MWh above cost at peak times. If the outcomes of Scenarios B and C are compared to Scenario A, pure incremental cost, then plant do start to recover some of their fixed costs, and prices increase by as much as €15/MWh in Scenario C in France (see below graph).

France – change in market prices (€/MWh) compared to pure incremental cost bidding (Scenario A)


Is this enough to keep the market whole going forward? It may provide a reasonable contribution to old, incumbent plant with much of their fixed costs already written off, especially if they are flexible enough to “cherry pick” the highest priced hours. However, to achieve full cost recovery of all fixed and financing costs for a new entrant mid-merit (i.e. running around half the time) CCGT plant requires more than double this amount. A German CCGT with a 45% load factor, entering the market in the early 2020s, would need an average premium of €29/MWh above incremental cost to cover all of its costs from the energy market only – substantially above Scenario C levels.

How can you achieve prices closer to Scenario C levels? It may be hoped that as reserve margins tighten, generators will be able to move their bidding behaviour closer to Scenario C without losing too much market share as a result. This may be tough to achieve in practice, as it would require all plant to “bid up” together.