The sharp increase in gas prices due to the restriction of supply volumes from Russia, as well as a number of other factors have triggered a sharp increase in electricity prices since the end of last year. In the context of this development, the pricing mechanism of European electricity markets, the merit order, is now being intensively discussed due to the major influence the gas price currently takes on the electricity price. The merit order has changed significantly due to the substantial rise in fuel prices, resulting in high market prices and high profits for plants with low electricity generation costs.
The following article describes the background of the price increase and shows the current merit order of the power plant park installed in Germany. In addition, sensitivities of the merit order with respect to differences in gas prices as well as the effect of the activation of the grid reserve are shown and the currently discussed market interventions of politics are outlined.
Formation of prices based on the merit order
“Merit order” is the term for the upward-sorted marginal cost curve of electricity generation of thermal generators. Since the liberalization of the energy markets, it has formed the basis for pricing on the day-ahead market. Suppliers place bids on the market that generally correspond to their marginal costs, i.e., the costs incurred per MWh of electricity generated. This includes only the costs incurred directly by electricity production; fixed costs are not taken into account. Then, the most expensive offer that is still required to meet demand determines a uniform price (or marginal price) that is paid to all generators. Since the price is usually higher than their own bid, suppliers have an incentive to bid as close as possible to their marginal costs in order to be awarded a contract with certainty. This ensures that electricity is generated by the lowest cost generating units.
As an example of the typical composition of the merit order before the energy crisis, Figure 1 shows the merit order of conventional power plants in Germany in 2018. For this purpose, the marginal costs of the power plants were determined by, among others, the fuel type, the efficiency, the net capacity, as well as fuel and CO2 prices of all relevant power plants based on the power plant list of the Federal Network Agency (BNetzA) [10,11]. A more detailed description of the procedure can be found in our article on the merit order of thermal power plants in Germany (2018). It should be noted that small power plants with a capacity of less than 10 MW are hardly included in the BNetzA power plant list. An evaluation of the platts power plant list  showed an installed capacity of power plants smaller than 10 MW for Germany of about 4 GW in total.
As the thermal generation technology with the lowest marginal costs, power generation from waste incineration is on the left, followed by nuclear power and then lignite and hard coal-fired power plants. This is followed by gas-fired power plants, with combined-cycle gas turbines having lower marginal costs than gas turbines due to their higher efficiency. As the generation technology with the highest marginal costs, electricity production from mineral oil is on the right side of the merit order. The cost differences in the use of the same energy source are due to different efficiencies of the respective power plants. In addition, power plants with cogeneration have lower marginal costs because they can cover part of their costs by producing heat. The marginal costs of industrial power plants, which are difficult to quantify, are not presented separately here. The electricity price is now determined by the residual load, i.e. the current load minus the feed-in of renewable energy sources, which have marginal costs close to zero. For example, with the average residual load for the months of June to August of 2018 of close to 47,000 MW, the electricity price in the merit order shown in Figure 1 is about 35 €/MWh . For the actual determination of the price, however, the export balance would also have to be taken into account.
Merit Order of the thermal power plants in Germany for 2022
Price increase in the supply
The sharp rise in gas prices has multiplied the generation costs of gas-fired power plants. This effect is amplified by the fact that, depending on the efficiency of the gas-fired power plants, their fuel costs per electric MWh generated are about 2-3 times higher than the gas price itself due to the efficiency of the power plant. Figure 2 shows the updated merit order under the average fuel prices of 2022 (up to and including 09/02/2022) and CO2 prices . Compared to the 2018 merit order, it shows a significant increase in price levels for all generation technologies except nuclear and waste incineration. Especially the marginal costs of gas-fired power plants, which were still between 40 €/MWh and 80 €/MWh in 2018, increase significantly to between 200 €/MWh and 450 €/MWh. The marginal costs for electricity production from coal are also significantly higher, with lignite rising more sharply with higher emission factors compared to hard coal due to the increase in CO2 prices. Marginal costs for electricity production from petroleum are also significantly higher than 2018 costs but increase less than marginal costs for gas-fired power plants. The large differences in marginal costs within a technology also show the increased importance that power plant efficiency takes in the face of rising fuel prices. In addition to the increased prices, the merit order also shows a steeper curve because it is significantly shorter than the 2018 merit order, meaning that less installed capacity is available on the market. While just under 90,000 MW of installed capacity was available on the market in 2018, only actors with a capacity of about 65,000 MW are still able to actively participate in the market this year due to the decommissioning and transfer to the grid reserve of several power plants as part of the nuclear and coal phase-out. Assuming the average residual load for June to August of 2018, the current merit order results in an electricity price of about 350 €/MWh, ten times higher than in 2018.
While the merit order shown in Figure 2 calculates marginal costs on the basis of average fuel prices and CO2 prices, gas prices were still significantly above these average values in the meantime. At a price peak on 08/26/2022, the gas price reached 312 €/MWh. Gas-fired power plants that had to procure gas at this time were therefore still subject to significantly higher marginal costs. Taking into account these higher prices, the merit order, shown in Figure 3, is even steeper, with marginal costs for gas-fired power plants with low efficiencies sometimes exceeding 1,000 €/MWh. This results in a price of 810 €/MWh for the residual load demand of the summer months of 2018 already considered before. The spot market prices that actually occurred on 08/26/2022 range between 550 €/MWh and 800 €/MWh, depending on the hour, which can be attributed to the lower residual load compared to the average value of 2018.
Currently, a temporary activation of the grid reserve is being debated due to the gas crisis. However, the positive effect on electricity prices is offset by the negative effect of higher CO2 emissions. A potential integration of the grid reserve and temporarily decommissioned power plants into the merit order would add around 13,400 MW of capacity, mainly from coal and gas. This would result in a flatter and longer merit order and the price for the exemplary residual load of 47,000 MW would decrease to 270 €/MWh (compared to 350 €/MWh with average gas prices for 2022).
Changes in residual load and exports
Although the gas price generally has the strongest influence on the currently very high electricity prices, there are also several other influencing factors under discussion. In the summer months in particular, prices are typically lower than during the winter due to lower consumption and a high feed-in of renewable energies. In addition, this year the residual load in the June-August period has had an average of 35,600 MW, lower than the residual load for the same months in 2021 (37,750 MW) and well below the 2018 level (47,000 MW). 
However, significantly more electricity was exported in the summer months of this year than in previous years. Whereas Germany has mostly been a net importer in the summer months over the past three years, importing 2,900 GWh between June and August 2021, for example, it exported around 700 GWh in the period this year. In July 2022, exports were especially high in this regard. In particular, the reduction in production and suspension of operation of more than half of France’s nuclear power plants due to corrosion problems and outdated equipment is being discussed as the cause. Because of the European electricity market coupling, these production losses in France are covered by the lowest-cost power plants available, using cross-border trading capacities. In Germany, this has resulted in higher volumes being generated, which means that plants with higher marginal costs are subsidized and therefore set prices. Thus, the required generation from thermal power plants in Germany decreases by an average of 330 MW in 2021 due to imports in the summer months, while generation in Germany increases by about 80 MW in 2022 due to exports. [1, 3]
In response to the sharp rise in electricity prices, the European Union (EU) published a proposal for a temporary inframarginal price cap on the European power exchange on 09/02/2022, i.e. a cap that only applies to generators whose marginal costs are below the marginal price. At the same time, it also addresses the current price cap for gas on the Iberian Peninsula and explicitly excludes a potential Europe-wide implementation of the mechanism, as well as a number of other electricity market interventions discussed currently.
The mechanism on the Iberian electricity market (MIBEL) was introduced on 06/15/2022, after the European Commission had agreed to a temporary introduction after extensive negotiations. The reason for the approval was in particular the limited transmission capacities to the Iberian peninsula, which on the one hand makes it more difficult to compensate for shortages within the market so that prices had risen even more sharply than in other European countries. In addition, according to the EU, due to the relatively isolated market, a self-sufficient implementation can take place without distortions of the European electricity markets. The mechanism includes a fixed subsidy to gas and coal-fired power plants, financed by a tax on electricity. Thus, electricity generation is to be decoupled from the effects of increased fuel prices. A fixed price cap of 40 €/MWh at the beginning for gas used in electricity production was introduced, which increases by 5 €/MWh every month. According to the Portuguese government, the intervention resulted in a 16.5 % reduction in electricity prices. [5, 6]
The EU has excluded an extension of the mechanism. The main reason given is the suspension of the steering effect of high prices on demand. The EU expects this to result in an annual increase in electricity demand of 25 TWh and thus an increase in gas demand of 10 % if the mechanism is implemented throughout Europe (assuming the same upper limit as in the Iberian of 40 €/MWh). In addition, the associated costs of subsidy payments are argued against the mechanism, as well as the contradiction of subsidies on fossil fuels to decarbonization goals. 
Further measures excluded by the EU
As part of the proposal for inframarginal price caps, the European Union also explicitly excluded a number of other measures that had previously been under discussion. In addition to an EU-wide extension of the Iberian model, this also included the Greek Commission’s proposal to establish a technology-specific cost-based remuneration including a regulated profit margin. The revenues generated by the state from the difference between the market price and the regulated remuneration would be used to reduce the burden on consumers. The EU justifies its rejection of the proposal by arguing that regulated remuneration would lead to the elimination of competition and promote inefficient technologies and cost structures. It is also concerned that it would disincentivize investment in renewables. Other excluded measures include the temporary elimination of EU emissions trading, the fixed regulation of the household electricity price, and absolute price caps. These measures are excluded in particular due to high costs on the one hand, and the lack of incentives for electricity savings under regulated prices on the other. 
Inframarginal price cap
Instead of the measures described, the EU proposed an inframarginal price cap for generation technologies with lower marginal costs than those of gas-fired power plants, in addition to a controlled reduction in electricity consumption. In particular, renewable energies (with the exception of certain hydropower plants, biomass or biogas), nuclear power plants and lignite-fired power plants are specified. Thus, the revenues of these power plants are to be decoupled from the current marginal electricity price. The price cap is to be implemented ex-post, i.e. via a downstream levy. According to the EU proposal, the revenues generated by the state from the difference between the electricity price and the price cap will be used to finance consumer support measures. Ideally, these support measures would be designed to incentivize a reduction in electricity consumption. 
As an advantage of this approach, the EU names the preservation of market mechanisms, since neither certain technologies are subsidized nor fixed payments are made to producers. Moreover, with a sufficiently high price cap, renewable energies could still generate sufficient profits so that investments remain attractive. In addition, the steering effect of high and time-variable electricity prices would be maintained, so that there would be incentives to reduce consumption, especially at times of low feed-in of renewable energy sources. However, a number of uncertainties remain, including which purchase and sales prices should apply to storage facilities, whether a uniform or separate price should apply depending on the energy source, and the question of pricing for forward market products (futures). In addition, a shift to bilateral trading (OTC trading) could weaken the effectiveness of the mechanism. [6, 7]
At the beginning of August, the German government had already decided on a gas levy as of 10/01/2022 in order to relieve importers of the high costs of replacement procurement, which will be necessary due to the missing gas supplies from Russia. Initially, this will involve the payment of 2.419 ct/kWh, which can be adjusted after three months. These costs will be passed on to all gas consumers (i.e. including gas-fired power plants). With a 2.419 ct/kWh levy, this will increase the marginal costs of gas-fired power plants for electricity generation by 40 €/MWh to 70 €/MWh, depending on the plant efficiency. In order to relieve consumers for the resulting increase in costs, the value-added tax on gas will also be reduced from 19 to 7 percent starting in October. In addition, in the course of this gas levy, the third support package, which the coalition had agreed on at the beginning of September, had already been announced. [8, 9]
In addition to various support measures, in line with the EU proposal this package also includes an inframarginal price cap, which is referred to as the collection of windfall profits. The resulting additional government revenue is to be used to relieve the burden on private households and small and medium-sized enterprises. Among other things, the introduction of an electricity price ceiling for a certain basic consumption level is planned, as well as a reduction of the increase in grid fees caused by the high redispatch costs of the transmission system operators. In addition, the planned increase in the CO2 price for 2023 is to be postponed by one year. The relief package still has to pass the Federal Parliament (Bundestag) and the Federal Council (Bundesrat) before it goes into effect. 
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 Kraftwerksliste Bundesnetzagentur: https://www.bundesnetzagentur.de/DE/Sachgebiete/ElektrizitaetundGas/Unternehmen_Institutionen/Versorgungssicherheit/Erzeugungskapazitaeten/Kraftwerksliste/kraftwerksliste-node.html; Bonn: Bundesnetzagentur, 2018.
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