28.11.2022  |  News

Between theory and practice: Analysing the framework conditions for green hydrogen in the real-world laboratory

The Bad Lauchstädt Energy Park real-world laboratory is the first time that the entire green hydrogen value chain, from production, transport and storage to application in the nearby chemical park, has been implemented in a regional cluster. Meanwhile, the rules for the new market are being negotiated at German and European level. The analysis of the status of the regulatory framework shows that pioneering projects need more room for manoeuvre combined with legal certainty.

The transformation of the gas sector towards renewable and decarbonised gases is of central importance for the implementation of the energy transition. In connection with this, the Bad Lauchstädt Energy Park (EBL for short), funded by the Federal Ministry for Economic Affairs, is a nucleus for green hydrogen and the ramp-up of the hydrogen market. The aim of the project is to realise the entire value chain of green hydrogen. To this end, the electricity generated in a newly constructed wind farm (50 MW) is utilised in an electrolyser (30 MW) to produce green hydrogen. This is transported via a converted gas pipeline to the Leuna Chemical Park, around 25 kilometres away, where it is used by the local chemical industry.

The investment decisions to be made in the project are currently being prepared. Regulatory requirements apply to construction and operation, which either already exist, are being revised or are about to be formulated for the first time. All these regulations have a major influence on economic efficiency and therefore on the investment decision to be made. However, there are regulatory uncertainties in this respect, which are analysed in connection with the EBL project and explained in more detail below.

Framework conditions for electrolysis operation determine hydrogen price

The economic viability of the entire green hydrogen value chain depends to a large extent on the production costs. The main drivers are the costs of producing the hydrogen in the electrolyser, which are determined by the capital costs of the plant and the operating parameters, in particular electricity procurement costs and full utilisation hours (see figure)

 The direct connection between the wind farm and electrolysis forms the basis for the production of green hydrogen, but this also poses challenges for efficient utilisation. If no electricity is drawn from the public grid, the operation of the electrolysis plant is subject to a mode of operation that is dependent on the availability of wind. In the event of a lull, electrolysis would not be able to produce hydrogen. Changing operating modes lead to a loss of efficiency over time, i.e. the amount of hydrogen produced decreases while electricity consumption remains constant and parts of the electrolyser have to be replaced sooner. On the other hand, a supplementary electricity supply via the grid enables optimisation of the operating mode, an increase in the full utilisation hours and thus more economical operation of the electrolyser.

 It should also be noted that the capital costs for the first electrolysers are still very high, so that a cost degression through series production can only be expected in the course of market development. It is therefore all the more important that lawmakers allow as much flexibility as possible in the design of the framework for the operation of the first hydrogen projects.

Criteria for the production of green hydrogen at European level currently still under development

Whether the hydrogen produced can be counted as fully renewable in the meaning of the Renewable Energy Directive (EU) 2018/2001 (REDII) is of decisive importance both for the electricity procurement costs and for the subsequent sales and utilisation possibilities of the hydrogen produced. The conditions under which this should be the case are currently being defined at European level. In addition, in accordance with Art. 27 (3) RED II, a delegated act (hereinafter: DA 27) originally to be adopted by the EU Commission by the end of last year, a draft has been available since May 2022 [1]. The European provisions relate to what are called renewable fuels of non-biogenic origin (RFNBOs), which include green hydrogen in particular, and so far only to the transport sector.

However, as part of the revision of the Renewable Energy Directive (RED III), these criteria are to be extended to other sectors. A corresponding proposal was presented in summer 2021 as part of the “Fit for 55” package [2]. With reference to the current draft of DA 27, some selected individual aspects that are of particular importance for the EBL and are not yet adequately addressed in the draft will be considered below. In the present case, this relates exclusively to the crediting options for electricity from directly connected renewable energy plants.

Art. 3 DA 27 sets out the requirements for the purchase of electricity in the case of a direct connection between the RE plant and the electrolysis plant by means of a direct line. For the definition of direct line, Art. 2(2) DA 27 refers to the Internal Electricity Market Directive 2019/944. However, the description contained in Art. 2(10) is inadequate and regularly leads to legal uncertainty in practice because it does not do justice to the diversity of technical design options. In the EBL, for example, the RE plant and the electrolyser are connected via a shared transformer station, whereby the electricity is simply “fed through” without transformation. In order to avoid possible application problems, it is advisable to include all systems located downstream of the same grid connection point in the scope of the standard.

There is a need for further clarification regarding the crediting of locally generated electricity quantities, particularly with regard to the admissibility of support for surplus feed-in quantities and supplementary grid electricity purchases: For example, Art. 3 DA 27 does not exclude the possibility of subsidising surplus green electricity generation, e.g. in the form of a market premium under the EEG (German Renewable Energies Act). On the other hand, renewable energy installations within the scope of Art. 4 DA 27, which regulates the requirements for grid procurement, may not receive any support. There are no apparent reasons for the different treatment in Art. 3 and Art. 4, so that in the interests of legal certainty it is necessary to clarify that the utilisation of a grant in cases of Art. 3 is not detrimental. The same applies to the permissibility of a flexible combination of locally generated and grid-supplied green electricity. The wording of Art. 3 lit. c DA 27 is unclear in this respect and reads as if any purchase of grid electricity is excluded in the case of offsetting locally generated electricity quantities. What is probably meant is that no grey electricity should be used to produce the hydrogen.

In addition, Art. 4 of DA 27 regulates electricity purchase criteria for the production of renewable hydrogen when electricity is purchased via the public grid and includes in particular requirements for additionality, geographical location and simultaneity of RE production, which are intended to ensure the sustainability of hydrogen production and also influence the economic efficiency of the value chain.

EEG levy no longer a cost driver for green hydrogen

Until now, a significant component of electricity procurement costs has been the EEG surcharge, which was generally incurred for every final consumption of electricity, irrespective of grid utilisation. Under the EEG 2017, there were only two options for hydrogen projects to obtain an exemption: Either one of the criteria for special forms of self-supply (§§ 61a et seq. EEG 2017) or the requirements of the special equalisation scheme (§§ 63 et seq. EEG 2017) had to be met.

Both paths proved difficult. While self-supply required, among other things, a personal identity between the electricity producer and the operator of the electrolysis as well as a direct spatial connection, it was disputed with regard to the special equalisation scheme whether the production of hydrogen was to be assigned to an activity in accordance with Annex 4 to the EEG 2017. While many projects obviously considered it to be “production of industrial gases” (WZ 2008 - 20.11.), the Federal Office of Economics (BAFA) argued - depending on the use of the hydrogen produced - that it could also be "gas production" (WZ 2008 - 35.21). In particular, transmission through a pipeline system was seen as a clear criterion in favour of the latter.

Finally, the EEG 2021 created an exemption for the production of green hydrogen, which was expressly intended to apply "regardless of its intended use" (see § 69b (1) 1 EEG 2021). Irrespective of the parallel European discussion, a definition was created specifically to limit the annual full utilisation hours of the electrolysers used (see Section 12i (1) EEV). This should ensure a system-friendly and flexible operating style [3].

After the EEG 2023 fundamentally reorganises the financing of the expansion of renewable energies and completely abolishes the EEG levy, the exemption clause for the levy exemption for the production of green hydrogen will in future only apply to the CHP and offshore grid levy (cf. § 25 EnFG (Act to Finance Energy Transition)). It can be assumed that the national provisions will be adapted to the European requirements as soon as they are available.

The EEG 2021 also created the possibility of financial participation for municipalities affected by the expansion of wind turbines for the first time. However, this financial participation is only permitted in the case of subsidised systems (§ 6 EEG para. 2 (1) 2021). As wind turbines that are erected and operated for the production of green hydrogen do not receive any financial support under the EEG, the municipalities, as an important interest group, are faced with direct competition between marketing options for the production of green hydrogen and support for the plant under the EEG.

Utilising the potential of gas networks for hydrogen transport

The amendment to the Energy Economy Act (EnWG) from 2021 aims to separate the regulation of natural gas and hydrogen networks. A hydrogen network operator voluntarily has the irrevocable option to submit to regulation as a hydrogen network operator (called “opt-in”). According to the law, there can therefore be regulated and non-regulated hydrogen network operators. For the conversion of the natural gas pipeline to the transport of hydrogen in the EBL, the extensive facilitations under authorisation law for the conversion of pipelines and systems from natural gas to hydrogen (§ 43l EnWG), the transfer of rights of way from natural gas to hydrogen pipelines (§ 113a EnWG) and the applicability of the technical regulations of the DVGW and the High-Pressure Gas Pipeline Ordinance to hydrogen (§ 49 EnWG) are of great importance.

While legal uncertainties have been largely eliminated in the course of the most recent amendments to the EnWG, the European legal framework is still in the process of development. In December 2021, the European Commission presented the gas and hydrogen package, which provides for comprehensive changes to the Gas Directive (2009/73/EC) and the Gas Access Regulation (EC/715/2009). The laws are currently in the ordinary legislative process between the European Parliament and the Council of the European Union and are expected to be finalised in the second half of 2023. The aim of the legislation is to integrate renewable and low-CO2 gases into the regulatory framework. For EBL, clarifications in dealing with existing authorisations and rights of way are of great relevance here.

However, the requirements for horizontal unbundling and the tightening of vertical unbundling in the hydrogen sector are problematic. For example, the requirements of horizontal unbundling demand that H2 transport must be separated from the natural gas network operator under company law (Art. 63 Directive). This requirement, coupled with the prohibition on the exchange of commercially sensitive information (cf. Art. 50 and Art. 36) and the use of shared services, prevents the realisation of the enormous synergy potential that exists in the joint operation of natural gas and hydrogen networks. The added value of the unbundling proposal is not given in terms of achieving the transparency objectives and compared to the alternative of accounting unbundling.

The stricter requirements for vertical unbundling also stipulate that the independent transmission system operator (ITO) model, which has been very successfully established in the electricity and gas sector, will no longer apply to hydrogen after 2030. This would mean that ONTRAS, like the majority of all existing European transmission system operators, would be effectively excluded from the hydrogen transport business, as the respective shareholders would not give up their activities in energy production at the expense of a hydrogen transport market that is still in the development stage. The European Commission’s proposal therefore harbours the risk of substantially slowing down the development of a European hydrogen network and making the European connection of the EBL project more difficult.

GHG quotas as drivers of demand for green hydrogen

The first applications for green hydrogen are in the industrial and transport sectors. Regulatory targets for the reduction of greenhouse gases (GHG) provide major incentives for the substitution of fossil fuels. The EBL is located in the middle of the Central German chemical triangle region, where hydrogen is already needed today. One promising application is the use in refineries. National legislators have recognised the GHG reduction potential of using green hydrogen as a fuel and in refinery processes and have enshrined this in principle in the Federal Immission Control Act (BImSchG). However, there is still a lack of concrete guidelines on the conditions for recognition, for example in the 37th BImSchV, without which it is not possible to develop business models due to the legal uncertainty as to whether a GHG reduction quota can be generated at all and the associated considerable investment uncertainty.

Politicians must set the course now

The analyses at EBL have shown that the hydrogen ramp-up requires a broad interpretation of electricity procurement criteria and no additional hurdles. The balance with the sustainability goals must remain in focus, but must not prevent the first projects, rather, must support them with broad transitional rules. Closing regulatory gaps is essential in order to utilise hydrogen, in particular the use of hydrogen in other sectors, as envisaged in RED III, and the revision of the 37th BImschV are urgent. It has also been shown that DA 27 is very complex and contains strict requirements for the purchase of electricity. For future designs, the question arises as to whether simpler approaches are required for faster implementation.



Draft of the Delegated Act on Art. 27 (3) of RED II, https://ec.europa.eu/info/law/better-regulation/have-your-say/initiatives/7046068-Production-of-renewable-transport-fuels-share-of-renewable-electricity-requirements-en

[2] Fit-for-55 package, https://www.consilium.europa.eu/en/policies/green-deal/fit-for-55-theeu-plan-for-a-green-transition/

[3] Explanatory memorandum to the ordinance implementing the EEG 2021 and amending other energy law provisions, p. 20; https://www.bmwk.de/Redaktion/DE/Downloads/V/verordnung-zur-umsetzung-des-eeg-2021-undzur-aenderung-weiterer-energierechtlichervorschriften.pdf


P. Hauser, D. Leithold, C. Müller-Pagel, Dr. K. Schulze, VNG AG, Leipzig; M. Ortmann, Uniper SE, Düsseldorf; J. Stolle, E. Tamaske, ONTRAS Gastransport GmbH, Leipzig; R. Teichgräber, Terrawatt Planungsgesellschaft mbH, Leipzig; M. Jaeger, DBI Gas- und Umwelttechnik GmbH, Leipzig

Contact person: philipp.hauser_at_vng.de