2015_2 Electricity market reform policy options master

Electricity market reform policy options and impact on investments case example Germany

The expansion of renewable energy sources affects the operation of thermal power plants and pushes down the profitability of these plants to the point where owners consider de-commissioning capacity. However, thermal generation is required to provide electricity when the sun is not shining or the wind not blowing. Additionally, more flexibility is required to balance the volatile production from wind and solar. Under such challenging conditions, which electricity market design options are considered by policy makers to ensure investments in much needed flexible generation? This article provides insight into the effects of two ‘main’ policy options on the security of supply, power system costs, and incentives for investment. This article is based on the award winning paper: “Market reform policy options – case example Germany” presented at the PowerGen Europe 2015 conference.


The increasing expansion of renewable energy sources, such as wind and photovoltaic, in the electricity generation mix is affecting thermal power plants in three different ways. These plants see (1) fewer operating hours with (2) lower wholesale prices and (3) an ever-increasing, volatile operating regime driven by the need to balance the fluctuating electricity production by renewables. Consequently, profitability of thermal power plants is dropping to levels where owners of these plants are considering closing or mothballing these units (or already have).

This situation can jeopardize the security of the supply in power systems. Thermal power plants are needed to provide electricity when the sun is not shining or the wind not blowing. Additionally, more flexibility is needed to balance the volatility introduced by increasing amounts of renewable energy. Alarmed by this, several EU member state governments, as well as the European Commission, are considering what changes are required to attract new investments in needed flexible generation capacity.

The German Federal Ministry for Economic Affairs and Energy (BMWi) published in October 2014 the discussion paper “An Electricity Market for Germany’s Energy Transition,” also known as “the Green Paper .” The Green Paperi is intended to provide the basis for the market design decisions to be taken in 2015. Due to its central location and size within Europe, and its high amount of renewable capacity, the German electricity market design is expected to strongly influence the rest of Europe and is, therefore, an important case to examine.

This article describes the two market design policy options presented in the Green Paper: trust in an optimised electricity market (energy only market [EOM 2.0]) or the introduction of a second market (the “capacity market” [CM]). To provide insight into the effects of these two policy options on the security of supply, system costs, and incentives for investment, Wärtsilä has commissioned Baringa (a consulting company with a focus on energy, commodities and financial services) to analyse whether an EOM 2.0 can incentivise investment in the German market, and, if so, what types of technologies are most incentivised under this market structure compared to an energy market featuring a CM. The full analysis was provided by Wärtsilä as a response to BMWi’s Green Paper consultation and can be found on their website.ii

Baringa used its in-house model of the North West European electricity markets and PLEXOS for power systems (a third party market dispatch engine) to model two scenarios for the evolution of the German electricity market across the period 2020-2035:

  • an EOM 2.0 scenario, where wholesale prices are allowed to rise above generators’ Short Run Marginal Costs (SRMC), and
  • a CM scenario, reflecting a market-wide capacity mechanism, where all generating capacity is able to receive a capacity payment based upon the ‘missing money’1 that an Open Cycle Gas Turbine (OCGT)2 requires to enter the market, but where the energy market is restricted to SRMC bidding only (i.e. ‘no mark-up’ rules). 

Notably, Baringa assumed that the EOM 2.0 scenario would also feature a strategic reserve for the transition to the new energy market arrangements, allowing for 4.5 GW of capacity to be retained by Transmission System Operators (TSOs) for emergency purposes (in line with the Green Paper proposals from BMWi).

This strategic reserve is assumed to be for dispatch as a ‘last resort’ (e.g., at the Value of Lost Load (VoLL)), and, therefore, does not affect Baringa’s modeled market dispatch results. The strategic reserve is made transitional by allowing a procured plant to close without being replaced, meaning that the reserve will largely disappear on its own by approximately 2029.

Technology decisions for new generation capacity additions are made on the basis of the most profitable generating technology, calculated based on Baringa’s profitability analysis.

Baringa calculated the total system costs for both scenarios using the energy market volume and price modeling results, the cost of procuring the strategic reserve (for the EOM 2.0 scenario), and the cost of market-wide capacity payments (for the CM scenario).3

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Fig. 1 - Profitability of a new-build CCGT.
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Fig. 2 -Profitability of a new-build OCGT.

Profitability analysis: the EOM 2.0 provides stronger incentives for flexibility

The profitability analysis shows that low capital expenditure, flexible forms of capacity, such as gas engines and OCGT, are exposed to stronger incentives to invest under the EOM 2.0 scenario. This is driven by their ability to collect uplift in the wholesale market and superior operational capabilities, allowing them to collect additional revenues from operating flexibly in the intraday and ancillary services markets.

For example, the profitability for a new-build Combined Cycle Gas Turbine (CCGT) in the EOM 2.0 scenario is shown in Figure 1. This chart demonstrates the difference that uplift can make to CCGT revenues. While the CCGT is still loss-making in the EOM 2.0 scenario, losses are higher still where no uplift is applied. (Figure 1)

 The profitability of a more flexible new-build OCGT is illustrated in Figure 2. As CM payments are assumed to be based on the value of missing money for an OCGT, the profitability under the CM is assumed to be EUR 0/kW across the modeling timeframe.

The EOM without uplift does not provide new build OCGT with the necessary revenues to recover its fixed costs. However, the EOM 2.0 scenario with uplift enables the technology to just achieve profitability; after discounting at 6%, Baringa estimates a net present value of profits over the period of just over EUR 3/kW in the EOM 2.0 scenario. (Figure 2)

 The profitability of even more flexible gas engines in the EOM 2.0 scenario is observed to be higher than OCGT, earning EUR 146/kW in net present value terms across the modeling period (see Figure 3). Gas engines deliver higher profitability than an OCGT because they are more efficient. Therefore, gas engines have a lower SRMC (allowing them to recover higher infra-marginal rents), are more flexible in operation with a lower minimum stable operating limit, and have a shorter start up time.

However, under the CM, gas engines are observed to be loss-making, primarily because they have higher annuitised capital costs than OCGTs (meaning that the capacity payment based on OCGT “missing money” does not recover these fully). While gas engines are still able to earn some infra-marginal rent, even in the energy market with no “mark-up” rule, these earnings are not sufficient to generate a profit. (Figure 3)

These results highlight that the market design choice can have a significant impact on the technology choice for investors. The Baringa analysis suggests that the EOM 2.0 is more likely to deliver more flexible and lower capital expenditure-intensive capacity, which is more in line with the future needs of the German system. Indeed, the need for market characteristics that encourage investment in flexibility to manage intermittency is a key focus of the Green Paper.

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Fig. 3 - Profitability of a new-build gas engine.
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Fig. 4 - Total cost of EOM 2.0 scenario and CM scenario.

Cost analysis: the EOM 2.0 delivers at lower overall cost per annum than the CM

Baringa’s modeling results also indicate that the EOM 2.0 can deliver at a lower overall cost than the CM, even after accounting for the additional cost of a strategic reserve.

The strategic reserve is assumed to be procured from the 12 GW of plant closures by 2023 in the EOM 2.0 scenario. The choice of plant is determined based on keeping open those that require the lowest payments in terms of missing money to cover fixed costs; i.e., the least profitable plants are still assumed to be decommissioned. On this assumption, the plants that are procured are mostly coal plants that were commissioned in the 1980s, which have fixed costs of approximately EUR 250m per annum in total. A large portion of this capacity reaches the end of its life expectancy between 2025 and 2029, and then it will be decommissioned, which brings down the cost of the strategic reserve.

To calculate total costs in the EOM 2.0 scenario, wholesale market prices incorporating uplift, as well as the costs of the strategic reserve, were taken into account.

For the CM scenario, the capacity payment, based upon the level of missing money calculated for an OCGT, was applied across all plants deemed to be eligible (i.e. conventional capacity). Baringa also compared the capacity payment, based upon the missing money calculated for a CCGT, to demonstrate the impact that setting a capacity payment at this level would have on overall costs.

The results from these total cost calculations are presented in Figure 4.

As Figure 4 illustrates, the costs under the EOM 2.0 scenario are generally close to those of the CM scenario in most years. On average, Baringa observed that the EOM 2.0 is approximately EUR 150m per annum lower cost than a CM based on OCGT missing money. Over the modeled period 2020-2035, this delivers a saving of EUR 2.5 bn net present value4.

In comparison, using a CM based on the missing money of a CCGT increases costs significantly, by around EUR 3 bn a year on average, compared to EOM 2.0. Over the modeled period, this costs German consumers an extra EUR 34 bn in net present value.

Conclusions and recommendations

Wärtsilä considers that the analysis described out above provides a number of key insights into the debate on whether electricity markets should follow an EOM 2.0 or CM design. These include:

  • It is likely that any new conventional baseload capacity, such as Combined Cycle Gas Turbines (CCGT), will continue to be loss-making in both market designs because they are unlikely to generate for the hours required to earn sufficient revenues. This is caused both by the over-supply situation in Germany, and also the long-term reduction in running hours caused by the significant penetration of renewables in the German market. Even if CCGTs are paid capacity payments in the range of EUR 36-48/kW per annum, (the missing money of a ‘best new entrant’ in capex terms) Baringa still does not find them to be profitable in both market designs.
  • The EOM 2.0 creates stronger incentives for flexibility than the CM, as it targets financial incentives on flexible operation itself, instead of remunerating all types of capacity with the same level of payment. Although the analysis is conservatively based on historic intra-day and ancillary service prices, Baringa observes an increase in the profitability of flexible resources (relative to inflexible resources) in the EOM 2.0 scenario.
  • Lastly, the results showed that between 2020 and 2035, the EOM 2.0 serves the system at a cost that is approximately EUR 2.5 bn lower in net present value terms than the estimated costs under the CM scenario (with missing money based on the cost for a best new entrant). If Baringa instead bases the capacity payment on the missing money of a CCGT, the estimated costs under the CM scenario are EUR 34 bn higher (in NPV terms) than under the EOM 2.0 scenario.

Our recommendations for the market design policy debate are the following:

1. Based on the results of the Baringa analysis, governments should consider the advantages that EOM 2.0 will have in expediting the transition of an electricity market to one that is predominantly supplied by intermittent renewables balanced with flexible generation, such as gas engines.

2. Given these advantages, and the compelling results of the Baringa analysis, we believe that a market design based on the EOM 2.0 provides a better alternative for providing a secure supply to a power system transiting to one that is dominated by renewables. This is because:

a. An EOM 2.0 market design provides efficient entry and exit signals while creating stronger incentives for the right type of capacity for the market.

b. It reduces the need for political involvement and the administrative burden associated with designing, implementing and running a CM (with recent experience in the UK providing a case in point).

c. The overall costs of the EOM 2.0 are lower compared to a CM

As Germany is one of the front runners in transforming its power system, the EOM 2.0 market design should be considered as a ‘blueprint’ for other EU member states. When other member states follow the same market design, a truly integrated, European, market-based energy system, which integrates renewables in a cost efficient and secure manner, can emerge.

In June 2015, the German government published the intention to reform the German energy market in line with the EOM 2.0 model presented in the Green Paper.


i October 2014, Federal Ministry for Economic Affairs and Energy (BMWi),http://www.bmwi.de/DE/Themen/energie,did=693402.html

ii http://www.bmwi.de/DE/Mediathek/publikationen,did=666660.html http://www.bmwi.de/DE/Themen/Energie/Strommarkt-der-Zukunft/strommarkt-2-0.html

1 Missing money refers to the level of revenues missing from the market that are required for a generator to recover its fixed operations and maintenance costs and any capital costs.

2 Assumed to be a “best new entrant” - a capacity provider that is able to deliver generating capacity at the lowest capital cost.

3 Our estimate of total system costs does not include the cost of ancillary services.

4 Discounted at 3.5%


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