How green is green hydrogen?
The publication of the Delegated Act (DA) on the definition of green hydrogen by the EU Commission [1] gives planning certainty to future electrolyzer operators: As soon as the Council and Parliament have given their approval by June 2023, it will be clear which conditions electricity must fulfill so that hydrogen produced with it is also legally considered green. In addition to the requirement that the electricity used must come from renewable energy sources, the criteria of temporal correlation of generation and consumption and additionality of the electricity generation plant play a particularly important role.
There are some exceptions and transition periods in the DA regulations. Together with the complexity of the electricity market, this allows for “green” power purchase strategies for electrolyser operators that may partially circumvent the above criteria or have negative impacts on the transformation of the power system. As a basis for disucussion, we have identified such strategies and describe them in this article.
Case 1: Geographical proximity to hydrogen consumers
Currently, all of Germany lies in one electricity bidding zone, so the DA allows an electrolyzer to operate in the industry-rich south of Germany while purchasing electricity via a power purchsing agreement (PPA) from a wind power plant in the wind-rich north of the country. There, electricity from wind turbines can often be produced more cheaply than in the south.
However, this increases the long-term load on the already heavily stressed north-south connection of the power grid. In 2021, the total cost of grid and system security measures under §13 of the EnWG was around €2.3 billion [2]. The commissioning of large-scale electrolyser capacities for the production of green hydrogen in southern Germany could drive these costs further. The Agency for the Cooperation of Energy Regulators (ACER) has published proposals at EU level for dividing Germany into several bidding zones [3], [4]. The division of the bidding zone is currently also being discussed in Germany [5] . This measure represents an adjustment of the electricity market to the physical limits of the grids and could reduce grid congestion. Since a higher price for electricity from renewable energies would be expected in a southern German bidding zone than in northern Germany, the operation of electrolysers for the production of green hydrogen would then be more economically attractive in the north.
Case 2: “Preventing” redispatch measures
In the course of redispatch measures, wind turbines in northern Germany are frequently shut down because the grid at their current capacity cannot absorb the green electricity generated in certain weather conditions. An electrolyzer in northern Germany would therefore have the opportunity to benefit from grid congestion and produce green hydrogen by taking off electricity volumes from wind installations that would otherwise be shut down. In 2021, the total outage work of EEG-compensated plants affected by curtailment under redispatch measures amounted to 5,818 GWh [2]. Purchasing electricity only from redispatch measures provides little planning certainty for an electrolyzer operator. Combining this strategy with a PPA could increase the economic viability of green hydrogen production.
If, on the other hand, an operator owns an electrolyzer on the load side of a grid bottleneck (in Germany, for example, in the south), it would not be possible to obtain electricity via the case of prevented negative redispatch. However, the additional load of the electrolyzer in the south would make the dispatch of a fossil power plant necessary, while on the market side the purchased power comes from a green PPA.
Article 27(3) of EU Directive 2018/2001 prohibits double counting of green power in principle. In Germany, when an electricity generation plant from renewable energies (RE plant) is curtailed in the course of redispatch measures, no guarantees of origin are currently issued for the curtailed electricity quantity. The plant operator is compensated for this [6]. During such a measure, an electrolyzer that has concluded a PPA with a plant that has been subject to redispatch only receives gray electricity. In this case, this ensures that the same amount of electricity is not marketed twice for the production of green hydrogen.
Case 3: Monthly correlation for constant electrolyser operation
Electricity from renewable sources must be used for the production of green hydrogen. Article 19 of the EU Directive 2018/2001 [7] specifies that certificates of origin must be invalidated for the verification of energy from renewable sources. In Germany, electricity labeling is regulated by the Energy Industry Act (EnWG) and the Ordinance on Guarantees of Origin and Regional Guarantees of Origin (HkRNDV). The generation date of Guarantees of Origin (HKN) in Germany is given in monthly resolution. They can be used for electricity labeling throughout the calendar year of the point of generation.
For the production of green hydrogen with electricity from renewable sources, there are higher requirements for the temporal resolution of electricity labeling than currently prescribed in Germany. This relates in particular to the temporal correlation of generation and consumption. In this context, the German Federal Environment Agency (UBA) 2021 proposed a reform of the “optional coupling” [8], which links the issuance, transaction and invalidation of HKNs to electricity deliveries. Although the proposal has since been implemented on the part of the legislature, the application of the coupling feature for green hydrogen, formerly required under §12 i EEV (a.F.), is currently not mandatory in Germany.
Thus, under the current regulation, “simultaneity” of generation and consumption of the electricity transferred under a PPA already applies for green hydrogen production in Germany if, as described in the DA, the electricity quantities balance within one month (until 2029) or one hour (from 2030). This allows an operator through the end of 2029 to freely shift the “green attribute” of a renewable facility’s electricity throughout the month, as long as the total amount of green electricity produced is equal to or greater than the electricity claimed as green for hydrogen production.
An electrolyzer that purchases electricity through a PPA with a RE plant could thus follow the following strategy: The electrolyzer runs continuously at rated power. When electricity is available from the RE plant, it is used to run the electrolyzer and excess RE electricity is sold on the market as gray electricity. The certificates of origin for the sold electricity are retained. If the RE plant produces less power than the rated power of the electrolyzer, the necessary difference is purchased in the electricity market and labeled as green power with the retained certificates of origin. As long as less electricity is purchased on the market over a month than surplus electricity is sold from the RE plant, all hydrogen produced may be labeled renewable, otherwise it is considered renewable on a pro-rata basis. A stylized illustration can be found in Figure 1.
For the operator, this operating strategy allows for predictable hydrogen production. However, he must buy electricity at times of low renewable availability (i.e., high electricity prices), and sell electricity at times of high renewable availability (i.e., low electricity prices). Thus, pursuing the strategy described here will not generate the highest revenues.
Operating at largely constant power would also have the effect of increasing the base load in the overall system, since the simultaneity of generation and consumption is not only in monthly resolution. In the course of the energy transition, base-load capable fossil-fired power plants will be decommissioned, which is expected to further drive up the price of electricity during periods of low RE availability and necessitate extensive flexibilization of controllable loads such as electrolysers.
Case 4: Hedging against high electricity prices with forwards or futures
As explained above, case 3 presents the operator with the difficulty that surplus or shortfall electricity volumes must be traded “against the market”. A partial hedge against this can be achieved on the purchasing side via a forward or future contract.
Here, the electrolyzer operator enters into a long-term electricity purchase contract in addition to its electricity PPA witha RE plant to ensure constant electricity supply that covers the consumption of the electrolyzer of rated power. The electricity supplied via the forward contract does not necessarily have to come from renewable energy sources.
The energy from the RE plant is sold entirely as gray electricity on the market. In this process, the operator of the electrolyzer retains the certificates of origin for the quantities of electricity sold. According to the DA, production and consumption of the green power can be accounted for over one month until the end of 2029. Thus, to meet the DA’s criteria for green hydrogen production, an operator must do little differently than without the DA. The only additional need is to purchase green power certificates from the same bidding zone through a PPA, and then invalidate them in the same month.
As in Case 3, the strategy described here increases the baseload on the power system by partially bypassing the simultaneity of generation and consumption using PPAs. However, by hedging with a forward contract, this case offers a higher potential for economic operation.
Case 5: Market price-oriented operation with monthly accounting of green electricity
Electrolysers can be operated flexibly at lower outputs than the nominal output and thus respond to electricity price fluctuations, for example. A higher production output in times of low electricity prices would compensate for a (partial) shutdown when electricity prices are high. For the same amount of hydrogen produced, a larger electrolyzer is required compared to continuous operation. Up to a point, the required higher investment costs are overcompensated by the lower electricity costs.
In times of high electricity prices, the electrolyzer can be shut down. The electricity purchased through a PPA can then be profitably sold as gray electricity. As in cases 3 and 4, the guarantees of origin are retained in the process. This allows purchased gray electricity to be “greened” at times when electricity prices are low.
On the other hand, if electricity prices are low, the electrolyzer would run at full capacity. If the RE plant is running, the self-produced electricity can be used; otherwise, cheap electricity is purchased from the electricity market and the green power certificates accumulated in that month are devalued in return.
From an electricity system perspective, this strategy shifts demand to times of low electricity prices. The price of electricity correlates with the CO2 emissions from electricity production. Therefore, market-priced electrolysis operations can support the reduction of GHG emissions in the power system. At the same time, it results in an incentive for the addition of more RE plants, which generate a large portion of their energy output during these periods of low electricity prices. During high electricity prices, on the other hand, this case produces no additional demand and may even lead to feed-in of electricity.
Conclusion
The Delegated Act of the EU Commission defines criteria for green hydrogen that are fundamentally suitable for accelerating the energy transition. However they also leave some leeway that allows production strategies with negative impacts on the German electricity system.
Here, production strategies were identified that increase the load on the German power grids and can cause additional costs for the overall system via measures such as redispatch. Second, strategies were identified that take advantage of the balancing of electricity generation and consumption allowed in the DA over a one-month period (through 2029). This can lead to an increase in the base load in the overall system. In Germany, this is currently covered by electricity generation from fossil fuels.
DA-compliant operation of electrolyzers in southern Germany would support the energy transition by aiding the construction of additional RE plants (Case 1). However, it would also further increase the load on the German power grids. This would especially be the case if the German bidding zone is maintained in its current form.
By operating electrolysers on both sides of a grid bottleneck (case 2), a hydrogen producer could increase its planning security by taking off electricity production that is otherwise shut down by curtailment through redispatch measures. However, as in case 1, this strategy could increase the load on the German power grids. A strategy based purely on preventing redispatch measures through hydrogen production is likely to provide insufficient planning security for electricity purchases.
There is no economic incentive to operate an electrolyzer at constant output (Case 3) with electricity from a PPA. However, if additional gray electricity is purchased via a long-term contract and colored green by means of retained guarantees of origin from sold PPA electricity (case 4), this can increase economic viability. In particular, when the cost of building electrolysers is high, consistently high utilization of an electrolyzer makes economic sense. If this strategy is not prevented by regulation, the base load in the overall system may increase.
In the case of market price-driven operation (Case 5) of an electrolyzer, generation and consumption of electricity from renewable energies do not occur simultaneously until the end of 2029, but this strategy may nevertheless ensure low-CO2 hydrogen and thus supports the energy transition.
Literature
[1] Commission delegated regulation (EU) …/… of 10.2.2023 supplementing Directive (EU) 2018/2001 of the European Parliament and of the Council by establishing a Union methodology setting out detailed rules for the production of renewable liquid and gaseous transport fuels of non-biological origin. Ausgefertigt am 2023-2-10; Brüssel: Europäische Kommission, 2023.
[2] Bericht Netzengpassmanagement Gesamtes Jahr 2021. Bonn: Bundesnetzagentur für Elektrizität, Gas, Telekommunikation, Post und Eisenbahnen, 2022.
[3] Decision No 11/2022 of the European Union agengy for the cooperation of energy regulators. Brussels: European Union Agency for the Cooperation of Energy Regulators (ACER), 2022.
[4] Annex 1 to the decision on the alternative bidding zone configurations to be considered in the bidding zone review process – List of alternative bidding zone configurations to be considered for the bidding zone review. Brussels: European Union Agency for the Cooperation of Energy Regulators (ACER), 2922.
[5] Storch, Lorenz: Neue Preiszonen: Muss Bayern bald mehr für Strom bezahlen? In https://www.br.de/nachrichten/bayern/neue-preiszonen-muss-bayern-bald-mehr-fuer-strom-bezahlen,TTJI1C6. (Abruf am 2023-3-28); München: BR24, 2023.
[6] BDEW-Leitfaden zur Berechnung der Ausfallarbeit Redispatch 2.0. Berlin: Bundesverband der Energie- und Wasserwirtschaft e.V., 2020.
[7] Directive (EU) 2018/2001 of the European Parliament and of the Council of 11 December 2018 on the promotion of the use of energy from renewable sources (Text with EEA relevance.) (RED). Ausgefertigt am 11-12-20; Brussels, Belgium: The European Parliament and the Council, 11.
[8] Umweltbundesamt: Vorschlag zur Weiterentwicklung der Kopplung von Herkunftsnachweisen an den zugrundeliegenden Strom – Bericht des Umweltbundesamtes nach § 12l Absatz 2 der Erneuerbare- Energien-Verordnung. Berlin: Umweltbundesamt, 2021.
