Baseload price and the support to renewables

A brief introduction to the impact of baseload price on the support to renewables with the German case

The energy crisis in Europe is showing signs of improvement, evidenced by the decreasing prices of natural gas, electricity, and other commodities. This positive trend is a welcome relief for European consumers.

However, the flip side of this development is the potential impact on the revenues of energy producers, including those involved in renewable energy. The decreasing prices may be eroding the previously (too?) robust incomes of renewable energy operators. Typically, these operators receive remuneration through fixed prices rather than directly participating in the day-ahead market. The inherent risk in this model, namely the difference between the fixed price and the market price, is often transferred to a third party. This third party can be a private entity in the case of a commercial Power Purchase Agreement (PPA) or, more commonly, a public entity.

Germany, with its sizable economy and successful expansion of renewable energy, is notably affected by the price risk associated with renewables. In this discussion, we will delve into the impact of declining electricity market prices on the financing requirements for renewable energy projects in Germany. Let's jump into it.

In this post, we do not strive to be completely precise. The aim is to present some back-to-the-enveloppe calculations. Please let us know if there are some fundamental mistakes

The three pillars: volume, baseload price, and capture rate

The aggregate market value of electricity generation within a specific timeframe can be delineated as a function of three crucial components: total production (measured in MWh), baseload value (in €/MWh), and the capture rate (expressed as a percentage). The baseload value is a tradable commodity on future markets such as EEX, while the capture rate signifies the percentage of value achieved by generators in comparison to the baseload¹.

Typically, operators in the renewable energy sector secure their revenues by fixing a price for every MWh they produce. The pivotal metric in this context is the price risk, which is the difference between the fixed price and the capture value. The capture value is determined by multiplying the baseload value by the capture rate.

The backing extended to renewables can be quantified as the disparity between the market value of the electricity generated and the financial inflows associated with renewable production

Support for renewables no longer borne by consumers

A pivotal driver behind the expansion of renewables in Germany was the implementation of the Erneuerbare-Energien-Gesetz, or EEG, which outlined crucial support mechanisms such as feed-in tariffs and market premiums. The financing of the EEG was historically borne by electricity consumers through a levy. However, in a noteworthy development in 2023, the EEG levy was eliminated, relieving consumers of this financial burden. Instead, the federal budget has taken on the responsibility of financing the EEG, marking a significant shift in the funding structure.

The graph below delineates the components constituting the electricity price for households in Germany over the past decade. Up until 2021, there were four primary components: energy cost (depicted in orange), network cost (in blue), VAT (represented by dark red), and the EEG levy (illustrated in green). Notably, for the current year, 2023, the electricity price no longer incorporates the EEG levy, reflecting the recent change in the financing model.

For 2023, it was estimated that EEG will bring 3.6 B€ to the federal budget, and for 2024, it will cost 10.6 B€. A major explanation for the large difference between one year to another is the assumption concerning the baseload electricity price. The estimation of the baseload price for the next year is based on the average value between 16 June to 15 September of the future German electricity price. For 2023, as we were right in the worst of the energy crisis, the baseload price was estimated at 425.61 €/MWh and with such an elevated price, the EEG would turn out to be a revenue for the federal budget². Nevertheless, as the market price decreased over the year, the EEG turned out to be a payment to renewables and not a revenue. In the graph below, we have the monthly balance for 2023. The cumulative value up to November 2023 is 13.08 B€³.

For the year 2024, the assumption of 137.73 €/MWh for 2024 baseload price has been taken. As we write, the current baseload price is 92.2 €/MWh, or 45.53 €/MWh less than the assumption.

The decrease is not as exceptional as between the estimations for 2023 and 2024 (from 425 to 137 €/MWh), but still, the impact is not negligible.

FIT and market premium

Within the framework of the EEG, seven technologies receive support, yet the lion's share is commanded by four predominant ones: onshore wind, offshore wind, biomass, and solar. Among these, two primary support schemes prevail:

• Feed-in-tariffs (FIT). This is a fixed price paid to the provider per MWh produced. FIT results in a comparable support scheme to the contract-for-differences⁴.

• Market premium. This mechanism entails the producer receiving a premium when the market price falls below a specified threshold. Conversely, if the market price surpasses this threshold, the producer retains the surplus.

As a general practice in Germany, prices are set at a fixed rate for 20 years. Below is a table outlining the various Feed-In Tariffs (FIT) and market premium prices. Notably, solar and offshore wind projects continue to be relatively costly on average, despite the decreasing costs associated with the recent installed capacity. New onshore wind projects fall within a comparable cost range to before, whereas biomass projects remain expensive.

The main prices of renewable supports in Germany. In yellow, it is the price for the most important support schemes per technology.

Concerning the FIT, the necessity for financing arises from the gap between the price disbursed and the market value of production. Should the market value exceed the price paid, the EEG transforms from a financial obligation into revenue, as it was initially projected for the year 2023.

In the context of the market premium, the financing dynamics are analogous, with the crucial distinction being that in instances of an elevated market value (as observed during the energy crisis, for example), the support does not transition into revenue but instead reverts to zero.

A quick assessment of the impact of baseload

Again, the goal is not to be precise but to present an order of magnitude.

We will only consider the four main technologies and only the main cost drivers. The assessment is therefore probably a lower bound value. The main assumption is that the average baseload price for 2024 is now 95€/MWh, and not 137.73€. All values are taken from here.

For biomass, the vast majority has a market premium with an average price of 199 €/MWh. Since 199 € is already much higher than the considered price of 137 €, we can safely consider that all the plants would probably be impacted. The production planned under market premium from biomass is 34.9 TWh for 2024. The lower value for baseload requires therefore an increase in financing need of 1.49 B€.

For onshore wind, the majority has a market premium with an average price is 85.5 €/MWh. By considering a baseload price of 95 €/MWh and with a capture rate of 89.3%⁵, the market value of onshore wind is considered to be around 85 €/MWh, or close to the average market premium. Certainly, some payments would have to be made for the ones with a price higher than 85 €/MWh, but, in general, the additional financial need would be rather limited.

In the case of offshore wind, a parallel scenario unfolds when compared to biomass. Given the consistently high average price of the market premium, it is reasonable to infer that a significant portion of production is likely to be affected, excluding the new installations. Consequently, our consideration is narrowed to 8.45 GW out of the total projected 9.56 GW set to be installed by the close of 2024. The anticipated production from offshore wind is expected to reach 28 TWh, translating to an augmented financing requirement of 1.06 B€.

Finally, for solar, we will only consider the FIT, even though the market premium is not negligible⁶. FIT has an average price of 242 €/MWh and a planned production of 37.3 TWh to be remunerated through this support scheme. Therefore, by considering all FIT production, the additional financing needed is 1.59 B€.

In total, we calculated an increase of 4.14 B€, which is most probably a lower bound. In 2023, the electricity consumption has been 459 TWh⁷. Therefore, the total financing need for 2024 (10.6 B initially calculated plus the 4.14 B€) is the equivalent of 32.1 € for every MWh consumed, or around a third of the current traded baseload price for 2024.

What if the baseload price is 0?

Extending the analysis to an extreme scenario—where the baseload price is reduced to 0 €/MWh—equates to the Feed-In Tariff (FIT) and the market premium, simplifying the support calculation. In this circumstance, the support is determined by projecting the production and multiplying it by the average price for each respective technology. The resulting table for the primary four supported mechanisms is as follows. The cumulative financing requirements under these conditions amount to 31.865 b€, equivalent to approximately 69 € for every MWh consumed in Germany.

What about capture rates?

The total support is not solely contingent on baseload prices; capture rates also exert a significant influence⁸. For the 2024 estimation, capture rates were projected at 89%, 92%, and 83% for onshore wind, offshore wind, and solar, respectively. However, based on publicly available data up to December 11, 2023, the actual capture rates for the same period stand at 86%, 93%, and 74% for onshore wind, offshore wind, and solar.

While it appears that wind capture rates align with projections, solar capture rates notably deviate. As discussed in previous posts, there is a likelihood that solar capture rates will experience a rapid decline, particularly given the current pace of installation⁹.

In conclusion

Baseload prices, influenced by exogenous variables like natural gas prices, exert a significant impact on the overall support requirements for renewables. While a return to a more "normal" range of baseload prices is globally favorable, it's crucial to acknowledge that this shift has led to increased financial transfers to support renewables. This is particularly notable because a substantial portion of renewables operates under long-term support schemes, some of them being expensive¹⁰.

Previously, consumers bore the direct impact of these financial transfers as it was facilitated through a levy on consumers. However, as of 2023, this burden has shifted to the federal budget, which is, interestingly, in intense negotiations for next year.

1. We explained this concept here.

2. Finally, energy prices decreased drastically from these high levels, and the EEG turned out to be a cost and not a revenue for the federal budget.

3. Interestingly, this value is not far from our assessment for 2024 with a baseload price of 95€/MWh. The current baseload price for 2023 up to 11 December is 98 €/MWh.

4. See previous posts on CfD.

5. Called Marktwertfaktor in German.

6. New installations with market premiums have shown much lower prices recently. A more refined analysis should be done with a precise distribution of the market premium prices.

7. We consider December 2022 for the current month of December 2023.

8. A lower capture rate results in higher payments to renewables.

9. Germany aims at 215 GW by 2030, which is more than double the current installed capacity.

10. With time, the most expensive ones will be removed and the average support price will decrease.