*1.1. The Role of Natural Gas (NG) in Future Energy Systems*

Natural gas is an important energy carrier used to generate heat or electricity. In 2019, 10.2% of the total electricity consumption in Germany was covered by natural gas-based generation [5]. In 2020, natural gas storage in Germany amounted to around 23.9 billion cubic meters, which corresponds to roughly 250 TWh of energy [6]. Due to the increasing share of renewable power generation, long-term storage with power-to-gas (PtG) will most likely become necessary and cost-efficient [7]. The gas sector therefore has great potential to provide enormous storage capacity for the power network. Moreover, PtG technologies can provide flexibility to the electrical network [8]. The conversion of electrical energy into chemical energy is an essential part of every PtG technology and is achieved using water electrolysis [9]. In addition to the impacts on the power sector, hydrogen generated from

**Citation:** Lu, Y.; Pesch, T.; Benigni, A. Simulation of Coupled Power and Gas Systems with Hydrogen-Enriched Natural Gas. *Energies* **2021**, *14*, 7680. https://doi.org/10.3390/ en14227680

Academic Editor: Bahman Shabani

Received: 10 October 2021 Accepted: 13 November 2021 Published: 16 November 2021

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**Copyright:** © 2021 by the authors. Licensee MDPI, Basel, Switzerland. This article is an open access article distributed under the terms and conditions of the Creative Commons Attribution (CC BY) license (https:// creativecommons.org/licenses/by/ 4.0/).

electrolysis can be a key factor in the decarbonization of heavy industries such as steel or chemistry [10].

#### *1.2. Blending Hydrogen into Existing NG Infrastructure*

Hydrogen generated using electrolysis can either be directly stored or be transported using pipeline network systems. It can also be further converted into methane using methanation reactions. In order to predominantly utilize the existing gas transmission infrastructure, the feasibility of blending hydrogen into the natural gas network is being intensively investigated [11]. Due to different infrastructure states and regulations, the maximum permitted levels of hydrogen concentration in the natural gas transmission system vary from country to country [12]. German regulations currently allow for up to 10% hydrogen concentration in the natural gas network. In the future, up to 20% is planned, and the German Technical and Scientific Association for Gas and Water (DVGW) estimates that up to 50% hydrogen concentration is feasible [13]. In a recent study, the impact of higher and fluctuating hydrogen concentrations of up to 50% on a variety of industrial combustion systems was investigated [14]. Therefore, in order to simulate future gas networks with uncertain hydrogen concentrations, it is important to take gas mixture properties into consideration.

#### *1.3. Simulation of Hydrogen-Enriched NG Network*

Natural gas is typically a mixture of gases, in which the major component is methane. Depending on sources and locations, the compositions of natural gas can vary significantly. In the study [15], it is stated that only around 23% of industrial plants have a real-time natural gas mixture quality measurement, while more than 50% of them only have weekly or monthly data available. In addition, more than 70% of the customers suffer from poor natural gas supply quality about once a month [15]. Natural gas composition must therefore be considered as a factor that has a significant impact on network operation safety. However, in many publications such as [16,17], the properties of natural gas are not listed, which makes it difficult to reproduce their results. When considering the injection of hydrogen into the natural gas network, the impact of gas composition is even greater.

Several research studies were carried out with respect to the steady-state simulation methods for hydrogen-enriched natural gas networks. For example, Abdolahi et al. used several equations of state (EOS) to model the natural gas mixture, whereas the heating values were not considered [18]. In the work by Giulio et al., an analysis was performed to evaluate the gas heating values with respect to the hydrogen injection into the natural gas pipelines, while the impact of the gas mixture properties on the gas flow calculation was not the main focus [19]. Pellegrino et al. established a simulation framework for the hydrogen-enriched natural gas network using the virial EOS (cf. [20]), but the height difference between the pipeline inlet and outlet was not considered [21].

In addition, there are a number of tools available that can be used to analyze the hydrogen-enriched natural gas network. PSS®SINCAL (cf. [22]), SAInt (cf. [23]), and MYNTS (cf. [24]), for example, are well established tools that are capable to run complex simulations for gas pipeline networks. Nevertheless, they are closed-source software and therefore hard to extend with functionalities for the specific requirements of analysis. TransiEnt is a Modelica library that is capable of steady-state and dynamic simulations of coupled-power, gas, and heat networks [25]. However, it is currently only supported in Dymola, which is a commercial software development environment for Modelica. There is a relatively new Python package—so-called pandapipes—that can handle different gas mixture properties for gas network simulation. The nodal difference of gas mixture compositions, however, has not yet been considered [26].

#### **2. Modeling of Gas Pipeline Systems**

#### *2.1. Modeling of Gas Pipelines*

A gas network typically consists of pipelines, compressor stations, valves, and regulator stations. For simulation purposes, a number of additional virtual components are necessary, for example, short pipes and fictitious resistances. However, the working principle of these components is similar to that of normal pipelines. As the pipeline is the dominant component in a gas network, the modeling of pipelines is explained in detail in this section.

Steady-state gas flows can be calculated using pipeline equations. There are several pipeline equations that can be used to calculate volumetric gas flow rates, although they are mostly derived from the isothermal Euler equation (Equation (1), cf. [27,28]).

$$\frac{\mathrm{d}p}{\mathrm{d}x} - \frac{f}{2D}\rho v|v| - \rho \mathrm{g} \sin \theta = 0 \tag{1}$$

After calculating the integral and substituting the constant parameters with real values, the steady-state volumetric flow rate in a pipeline can be calculated as in Equation (2) (cf. [16,29]). Unless stated otherwise, the gas volumetric flow rates will be converted to the ones under standard reference conditions of 15 °C (288.15 K) and 1 bar (101,325 Pa), which correspond to *Tst* and *Pst* in the pipeline equation [30]. The unit of the standardized volumetric flow rate is sm3/s.

$$Q = C \frac{T\_{st}}{P\_{st}} D^{2.5} \eta \left( \frac{|P\_i^2 - P\_j^2 - E|}{LGT\_a Zf} \right)^{0.5} \tag{2}$$

where *C* = *π* q *<sup>R</sup>* 16*Mair* is a constant, which is around 13.29, *D* is the pipe diameter, *η* is the pipe efficiency, *f* is the friction factor, *G* is the gas specific gravity, *L* is the pipe length, *Pst* is the reference pressure, *P<sup>i</sup>* is the inlet pressure, *P<sup>j</sup>* is the outlet pressure, *Q* is the volumetric flow rate, *T<sup>a</sup>* is the average temperature, *Tst* is the reference temperature, and *Z* is the compressibility factor. In Equation (2), *E* represents the potential

$$E = 0.06843G(H\_j - H\_i)\frac{P\_a^2}{T\_a Z} \tag{3}$$

where *H<sup>i</sup>* and *H<sup>j</sup>* are the inlet and outlet height, respectively. The average pressure *P<sup>a</sup>* and average temperature *T<sup>a</sup>* can be calculated using the following formulas (cf. [16]):

$$P\_a = \frac{2}{3} \left( P\_i + P\_j - \frac{P\_l P\_j}{P\_i + P\_j} \right) \tag{4}$$

$$T\_a = T\_s + \frac{T\_i - T\_j}{\ln\left(\frac{T\_i - T\_s}{T\_j - T\_s}\right)}\tag{5}$$

The friction factor is a very important variable for calculating gas flow rates. There are various ways to calculate the pipeline friction factor that involve different levels of computational complexity and accuracy. However, the friction factor does not change significantly in the fully turbulent zone [31], which is also the case in this paper. Because the actual friction factor needs to be calculated or calibrated using pipeline efficiency, this paper uses the simplest method for pipeline friction, which is only related to the pipeline diameter *D* (cf. [16,29]).

$$f = 0.093902D^{-\frac{1}{3}}\tag{6}$$

*η* is the efficiency of the pipe to convert the theoretical friction factor into an actual one, taking other sources of friction into account, for example, valves and tees. The aging of the pipeline and corrosion or rust inside also contribute additional friction to the gas transmission system. Therefore, the real gas flow rate in a pipe is generally lower than the one calculated by flow equations where *η* = 1. To account for such extra flow reductions, the efficiency factor *η* is usually chosen between 0.75 and 0.95, while experience shows that for an old pipeline it can be reduced to lower than 0.7 [32]. However, Mohitpour et al. suggested *η* values between 0.92 and 0.97, which are much higher than the ones mentioned above (cf. [33]). In principle, *η* should be chosen according to actual gas network pipelines. In the remaining part of this paper, all pipeline friction factors are set to 0.85, which is a good assumption for a common pipeline operating status.

By reviewing Equation (2), it can be seen that most constants are preset pipeline parameters. It therefore can be simplified further using algebraic transformations, as shown below in Equation (7):

$$Q = \mathcal{C}\_{pipe} \left( \frac{|P\_i^2 - P\_j^2 - E|}{GZ} \right)^{0.5} \tag{7}$$

where *Cpipe* reflects constants and pipeline parameters

$$\mathcal{C}\_{pipe} = \mathcal{C} \frac{T\_b}{P\_b} D^{2.5} \eta \left(\frac{1}{L T\_d f}\right)^{0.5} \tag{8}$$

Typically, as shown in Equation (2), pipeline network simulations are based on volumetric flow rate conservation, which means the sum of all gas volumetric flows injected into or flowing out of one node equals zero. However, considering variant gas compositions in pipelines makes this assumption invalid. To deal with this issue, mass flow conservation is adopted in this work.

#### *2.2. Thermal Formulation*

Temperature is another important state variable in a gas network simulation. To calculate the temperature profile alongside a gas pipeline, an extra equation based on the first law of thermodynamics is needed (Equation (9), cf. [27,28]):

$$Q\_m \frac{\mathbf{d}\left(h + \frac{v^2}{2}\right)}{\mathbf{d}x} + \mathcal{U}\_l(T - T\_s)\pi D + Q\_m g \sin\theta = 0\tag{9}$$

where *Q<sup>m</sup>* is the gas mass flow rate, *h* is its specific enthalpy, *v* is the velocity of gas flow, *Ul* is the heat transfer coefficient of the pipeline, *g* is the gravitational acceleration, and sin *θ* = *Hj*−*H<sup>i</sup> L* .

When considering a steady-state simulation, the change of velocity can be ignored ( d*v* <sup>d</sup>*<sup>x</sup>* = 0). By further assuming the gas enthalpy as a function of pressure and temperature, the change of enthalpy d*h* can be rewritten as Equation (10) [27]:

$$\mathbf{d}h = \left(\frac{\partial h}{\partial T}\right)\_p \mathbf{d}T + \left(\frac{\partial h}{\partial p}\right)\_T \mathbf{d}p \tag{10}$$

with *∂h ∂p T* = *∂T ∂p h ∂h ∂T p* , Equation (9) can be rewritten as Equation (11).

$$\frac{\mathbf{d}T}{\mathbf{d}\mathbf{x}} + \mu\_{JT} \frac{\mathbf{d}p}{\mathbf{d}\mathbf{x}} + \frac{\mathbf{U}\_l}{Q\_m c\_p} (T - T\_s) \pi D + \frac{g \sin \theta}{c\_p} = 0 \tag{11}$$

To simplify the calculation, here the potential energy term is ignored. By substituting d*p* <sup>d</sup>*<sup>x</sup>* with the help of Equations (1) and (2), Equation (11) can be written in the form of Equation (12) (cf. [16,21]):

$$\frac{\text{dT}}{\text{d}\text{x}} = \mu\_{\text{JT}} \left( \frac{f Z\_s R Q\_m |Q\_m|}{2 D P A^2} T + \frac{g \sin \alpha}{\rho} \right) - \frac{\text{U}\_l \pi D}{Q\_m c\_p} (T - T\_s) \tag{12}$$

After calculating the integral and simplification, the gas pipeline outlet temperature can then be calculated using the following equation:

$$T\_j = \frac{\alpha}{\alpha + \beta} \left[ T\_s - T\_s e^{-(\alpha + \beta)L} \right] + T\_l e^{-(\alpha + \beta)L} \tag{13}$$

where *α* = *U<sup>L</sup> Qmcp* and *β* = *µJT ZR f Qm*|*Qm*| 2*PaDA*<sup>2</sup> .

#### *2.3. Calculation of Gas Mixture Properties*

As we can see in Equation (7), there are two properties that are directly related to the gas composition: the gas specific gravity *G* and the compressibility factor *Z*. For the purpose of simulating the gas network, these values are typically obtained using empirical models. In the case of the compressibility factor, for example, Papay's equation [17,21] (Equation (14)) or AGA [34] (Equation (15)) are used, where *p<sup>r</sup>* = *p*/*p<sup>c</sup>* and *T<sup>r</sup>* = *T*/*Tc*. These approaches are suitable when calculating the compressibility factor of typical natural gas. However, the critical point conditions (*p<sup>c</sup>* and *Tc*) used in the formula are constants, assuming that the gas mixture properties do not change during network operation. However, this assumption is no longer valid when considering hydrogen blended into the natural gas network. Therefore, an automated calculation with variant gas composition is not possible using these empirical models.

$$z(p,T) = 1 - 3.52p\_r e^{-2.26T\_r} + 0.247p\_r^2 e^{-1.878T\_r} \tag{14}$$

$$z(p\_\prime T) = 1 + 0.257p\_r - 0.533\frac{p\_r}{T\_r} \tag{15}$$

Now consider the gas specific gravity and heating value of the gas mixture. According to the DVGW technical regulation [35], natural gas is defined as H-gas and L-gas with respect to its composition. The properties of these two types of gases are shown in Table 1. It can be seen that heating values and specific gravity vary considerably, which makes an accurate calculation more difficult. Therefore, a comprehensive gas mixture property calculation is used in this paper.

**Table 1.** Properties of natural gas in Germany [30].


To calculate the gas mixture properties, the "thermo" python package is used [36]. The gas mixture properties are calculated using the Peng–Robinson EOS (PREOS) for a mixture of any number of compounds. The mathematical formulations can be found in the package repository or in the referenced literature [37,38].

The gas mixture heating values are calculated using another package named "Cantera" [39], based on the combustion data GRI-Mech 3.0 [40]. Limited to the available gas species data in this source, hydrocarbon species with over 3 carbon atoms (e.g., butane, pentane) are considered as methane in the heating value calculation.

$$HV = \sum\_{i \in \mathcal{R}} H\_i \mathbf{x}\_i - \sum\_{j \in \mathcal{P}} H\_j \mathbf{x}\_j \tag{16}$$

It is first used to balance all the chemical reaction equations of complete combustion based on the composition of the gas mixture. The corresponding heating value (HV) can be subsequently calculated using Equation (16) (cf. [41]), where R is the set of all reactants (all gas species in the gas mixture and O2) and P represents all products. *H* stands for the enthalpy, and *x* is the mole fraction of a single gas species in R or P. In this paper, the higher heating value (HHV) of the gas mixture is used, which assumes all water content in the end product is in a liquid state.

The natural gas composition used in this work is listed in Table A1 [42].

#### *2.4. Solution Flow*

In this tool, a gas network is modeled as a set of nodes and pipelines. The network nodes are classified into three types: reference nodes, supply nodes, and demand nodes. For the reference nodes, pressures are known and gas flows need to be calculated to balance network demand. For supply nodes and demand nodes, the gas flows are known and pressures need to be calculated. The passive sign convention system is used in this tool, with negative flows representing supply and positive ones representing consumption.

The simulation method presented in this paper combines conventional pipeline equations with comprehensive modeling of gas mixture and utilizes the Newton–Raphson (NR) method to solve steady-state gas flow calculation problems iteratively. As can be seen in Figure 1, the first step of the NR method is the initialization of network variables, which in this case are the initial estimates of unknown nodal pressures. In an electrical power flow simulation, a "flat-start" initialization is typically applied. In contrast, the pressures at both ends of a pipeline must not be the same; otherwise, this will result in zero flow in the pipeline and thus a poorly conditioned Jacobian matrix. From experience, pressures at pipeline outlets are initialized as 0.98 of those at inlets. To avoid the duplicated assignment of initial estimates, the initialization algorithm assigns pipeline outlet pressures starting from reference nodes until each node has a pressure value. Based on the initial estimates, the physical properties of the gas mixture inside pipelines can be calculated. For each iteration step, the Jacobian matrix is updated, which is later used to calculate the state variables. Afterward, the new gas mixture composition and its properties are calculated. Since the approach presented here is aimed at solving the static flow problem, flows entering a node with different compositions are assumed to be completely mixed at the node. Therefore, the gas mixture composition in a pipeline is always considered to be the same as the one at its inlet. As long as the error after one iteration step is bigger than the set tolerance, the program iterates over to set pressures to the nodes and simultaneously updates the gas mixture properties to be used for the pipelines. If the error remains within the tolerance, the simulation has converged and results are saved.

**Figure 1.** Flow chart of the solving process.

#### **3. Simulation and Results**

#### *3.1. Study Case 1: Impacts of Different Calculation Methods on a Single Pipeline with Variable Gas Mixture Composition*

Since the pipeline is the dominant component in a gas network, in the first study case the simplest case is considered, which is the analysis of different gas compositions in one single pipeline. The main purpose of this study case is to stress the importance of taking the gas composition into account when performing a pipeline flow calculation with respect to hydrogen blended into natural gas. To achieve this, PREOS is used in this study to calculate the gas mixture properties, which is proved to be one of the most accurate methods to model the natural gas mixture [43]. Since the assumption made for Equation (6) is only valid for systems with higher pressures, only high-pressure gas pipelines are considered in this section. In Germany, the pressure level of high-pressure gas networks is defined as an operational range between 1 and 100 bar [44]. Therefore, in this paper, the analyzed pressure range is also set between 1 and 100 bar. As described in previous sections, multiple pipeline flow equations are available. A comparison of the most popular methods is shown in Figure 2a to give an overview of these different methods. It can be noted that at lower pressures (from 1 to 10 bar), the calculation results of different methods do not differ significantly. Within a higher pressure range (from 10 to 100 bar), the Panhandle B method tends to overestimate the flow rates, while the Weymouth method underestimates them. The flow rates calculated with the method used in this tool lie in the middle range of all analyzed methods, both in the lower pressure range and in the higher pressure range.

Typically, simulations of gas pipeline networks are based on constant gas properties, which is no longer accurate when the properties change significantly, for example, when the operation conditions deviate strongly from the nominal value or when complex systems with different gas mixtures are simulated. As shown in Figure 2b, a comparison between the Papay's equation and the PREOS is made. The calculation results from these two alternatives

appear to be quite similar. However, at a higher pressure, the calculated flow rates with Papay's equation, which is based on constant critical conditions, are around 2% lower than those using PREOS which is a more accurate method for calculating gas properties.

**Figure 2.** (**a**) Comparison between different pipeline flow rate calculation methods. (**b**) Comparison of flow rate calculation with constant gas properties and those calculated using PREOS.

The pipeline transmission is generally restricted by the minimum and maximum permitted volumetric flow rates and the maximum permitted pressure. Therefore, it is important to investigate how the flow rate and pressure change when different gas compositions are applied to the pipeline. Now consider a binary gas mixture of CH<sup>4</sup> and H2. The simplified pipeline equation (Equation (7)) shows that the gas flow rate is dependent on the compressibility factor *Z* and the specific gravity *G* of the gas mixture. As shown in Figure 3a, the gas compressibility factor increases in a non-linear fashion with increasing hydrogen concentration. If we consider a 20% hydrogen concentration in the gas mixture, the corresponding compressibility factor is around 2% greater than the one calculated with the linear mole fraction model. When using Papay's equation, it is difficult to calculate the *T<sup>c</sup>* and *P<sup>c</sup>* of the gas mixture; thus, a simple linear mole fraction method is used. As shown in Figure 3a, at low hydrogen concentrations, this method works well, but when the hydrogen concentration is increased further, the error also becomes bigger. Obuba et al. showed that Papay's method tends to underestimate the *Z*-factor [45], an observation that also corresponds to the results shown in this figure.

Turning now to the gas specific gravity *G*. As shown in Figure 3b, the gas-specific gravity is linearly related to the hydrogen concentration, and the calculation results obtained from using PREOS and the linear mole fraction model are nearly identical.

**Figure 3.** (**a**) Gas mixture compressibility in the relation to the injection of hydrogen. (**b**) Gas mixture specific gravity in relation to the injection of hydrogen.

After analyzing the gas properties of gas mixtures with different hydrogen concentrations, the pipeline flow calculation results are shown here. In the practical gas network operation, the energy requirement of the demand side has to be met. Therefore, the actual gas flow rate may vary due to variations in the heating values of the gas mixture. In this study case, a constant energy demand at the pipeline outlet is assumed in order to analyze the pressure drops throughout the pipeline with respect to different hydrogen concentrations.

As shown in Figure 4, when considering a certain amount of energy demand, the pressure drop in the pipeline increases with increasing hydrogen concentration. At around 90% hydrogen concentration, however, there is a turning point in the pressure drop curve. Looking back to Equation (7) and Figure 3a, the reason for this turning point is that the increase of the compressibility factor *Z* slows down when the hydrogen concentration increases.

**Figure 4.** Pressure drop throughout a pipeline in relation to different hydrogen concentrations.

Besides the nodal pressure and the flow rate inside pipelines, the temperature of the transmitted gas mixture is also an important variable for gas network simulation. In Figure 5a, simulations are run to illustrate the temperature profile inside a pipeline with respect to the different inlet temperatures. It can be noted that the gas mixture temperature tends to be the same as its ambient temperature after a long-distance transmission. In Figure 5b, several simulations are run assuming different hydrogen concentration rates inside the pipeline. In the case of natural gas, the gas mixture temperature is assumed to be the same as the ambient temperature if the pipeline is longer than 25 km. However, with the increase of hydrogen concentration inside the pipe, the descent rate of the temperature becomes lower and the temperature difference between the pipe inlet and outlet has to be taken into consideration in certain cases.

Gas transmission in the pipeline network is based on pressure control. The results presented in this section show that in order to keep the same energy flow in one pipeline, gas flow rates and pressure drops also change when the hydrogen concentration changes in the pipeline.

Since the volumetric flow rate is the most important variable to be analyzed, only the volumetric flow will be analyzed and shown in the rest of the paper.

**Figure 5.** (**a**) Temperature profile throughout a gas pipe with different pipeline inlet temperatures. (**b**) Temperature profile throughout a gas pipe with different hydrogen concentrations.

#### *3.2. Study Case 2: A Simple Gas Network with Hydrogen Injection*

In the previous study case, simulations are performed on a simple pipeline model to illustrate the importance and necessity of taking gas mixture properties into account as part of a hydrogen-enriched natural gas network simulation. Considering the possibility of blending hydrogen into the natural gas network, if the hydrogen injection occurs at the demand side, the hydrogen concentration could be gradually increased and therefore cause risky conditions on a local level. In this section, a number of simulations are performed on a hydrogen-enriched natural gas network, to analyze the impacts caused by different hydrogen concentrations in the network or nodal hydrogen injections into the network.

To reproduce the network behavior with the utmost accuracy, a compatible network size for both gas and power grids should be considered. In this work, the gas grid is synthetically generated based on the CIGRE high-voltage transmission benchmark grid [46], ignoring some buses and connections.

The synthetically generated simple gas network model consists of 8 nodes and 8 branches as shown in Figure 6. Node 1 and node 2 are set as reference nodes, where the nodal pressure values are known. At these nodes, the pressures remain constant, while the flow rates are variable to be able to balance the network demands. The other nodes are defined as demand nodes, where the flow rates are predefined. The demand can be also converted into energy demand using the gas mixture heating values.

**Figure 6.** Artificial gas grid.

As shown in Figure 7, when nodal energy demands stay the same, the overall pressure at all demand nodes will be lower when the hydrogen concentration is higher. However, from 80% to 100% hydrogen concentration, the nodal pressures increase slightly, which corresponds to the results shown in Figure 4.

Water electrolysis is one of the most promising electrical flexibility options so far as it can generate hydrogen by electrolyzing water. To analyze the impacts of electrolyzer operation on the natural gas network, it is assumed that a known amount of hydrogen is fed into the natural gas network at the network nodes. In this study case, the distribution of injected hydrogen in the network is analyzed to see if the maximum permitted hydrogen concentration in the pipeline is exceeded.

**Figure 7.** Pressure at demand nodes with respect to different hydrogen concentrations in the network.

Now assume there are three electrolyzers, which are accordingly located at nodes 3, 4, and 5. The energy flow rates of hydrogen blending into the natural gas grid are assumed as 35 MW, which corresponds to around 2.9 sm3/s. In this case, different gas injections are considered to be fully mixed at conjunction nodes. The corresponding simulation results are shown in Figure 8. As shown in the figure, a relatively high hydrogen concentration of around 29.6% occurs in pipeline 3. In pipelines 2, 4, and 6, the hydrogen concentration also reaches around 13%, which is already critical with respect to current technical regulations. It should be noted, however, that although the assumed hydrogen injection rate is relatively high given the current status of real-world implementation, the total energy delivered with hydrogen covers only around 1.88% of the total energy demand in this system. Therefore, when the total hydrogen share in the gas transmission system is increased, it is important to monitor the hydrogen concentration in pipelines in order to ensure a secure operation.

## *3.3. Study Case 3: A Simple Example of a Simulation of Coupled Power and Gas Networks*

A number of studies analyzed the technical and economical performances of water electrolyzers considering different PV and wind penetration levels [47,48]. However, these studies focused mainly on the electrolyzer and its power consumption rather than on the grid perspective. In this part, a simple analysis is performed by coupling the power grid (Figure 9) and gas grid (Figure 6). To this end, a quasi-dynamic simulation is performed based on a time-series simulation. The energy demands in both networks are calculated using standard demand profiles, which are taken from [49,50] and assume an annual demand of 400 MWh and 600 MWh, based on the scenario defined in the original power system model [46]. To include the generation of renewable energy, weather data from 2015 are used [51]. The wind and PV generation profiles are calculated using the abovementioned weather data and formulas taken from [52,53]. The total installed generation capacity of wind and PV generation units is set at 500 MW with a wind and PV ratio of 50–50%. Furthermore, renewable energy generation is considered to be equally distributed at each node. In Figure 10, the PV and wind generation are plotted as box plots [54] to

show their seasonal behavior. The orange lines in the middle represent the median value of the power generation of each month. The lower and upper bounds of the boxes represent the lower and upper quartiles of monthly generation. The whiskers extend from the box and cover the major range of the data. The outliers refer to the data past the end of the whiskers, which are the peaks and valleys of power generation. It can be seen that although PV has a peak generation in the summer and the maximum total generation of renewable energy usually occurs in warmer seasons, the relatively high continuous generation of renewable energy occurs during winter. Therefore, two scenarios are assumed based on the above-mentioned renewable generation, which correspond to June and December, meaning that the PV-rich and wind-rich seasons can be considered.

To investigate the impact of coupling both networks, the combination of three water electrolyzers and one gas-fired power plant is analyzed (see Figures 6 and 9). The water electrolyzers are considered to be installed at nodes 3, 4, and 5, each with a maximum power consumption rate of 20 MW and an efficiency of 80%. A simple scheduling method is applied to ensure that the electrolyzers are only operated at times when the generation of renewable energies exceeds its nodal power demand. The gas-fired power plant is assumed at node 8, which consumes gas and produces electrical power with an efficiency of 60%. Here, instead of changing settings on the power grid side, a constant volumetric flow rate of gas consumption is assumed so that the impact of the time-variant hydrogen concentration in the natural gas grid can be illustrated.

**Figure 9.** CIGRE high-voltage transmission grid (cf. [46]).

**Figure 10.** (**a**) Relative PV power generation in relation to installed generation capacity. (**b**) Relative wind power generation in relation to installed generation capacity.

Two simulations are run separately for June and December 2015 with a sampling time of one hour. The results are shown in Figures 11 and 12. By comparing the results from Figure 11a,b, it is clear that the hydrogen concentrations in June are much higher than those in December. This result can be explained by the fact that the gas demand is usually rather low in summer while generation spikes of renewable energies are rather common. Because natural gas is mostly used for space heating purposes, the gas demand increases during colder days. Although more hydrogen is produced in the winter, the energy supplied with hydrogen does not play a major role.

In Figure 12, the power generation of the gas-fired power plant at node 8 is analyzed. It should be noted that the power generation in June is not stable, which can vary up to 20%. This is caused by the high concentration of hydrogen that occurs in pipeline 7, which directly supplies node 8. This further indicates that directly blending hydrogen into the natural gas network is theoretically impractical during summer. Although the power generation in December is relatively more stable, a difference of over 5% is still possible. Therefore, to ensure a secure operation of the power grid coupled with the hydrogen-enriched natural gas network, the heating values of the gas mixture should be taken into consideration.

**Figure 11.** (**a**) Hydrogen concentration in pipelines in June. (**b**) Hydrogen concentration in pipelines in December.

**Figure 12.** Gas-fired power plant generation with constant volumetric flow consumption.

#### **4. Conclusions**

The gas sector can provide seasonal storage capacity and additional flexibility to the power sector in an integrated power and gas system. To accurately analyze the impacts caused by coupling power and gas networks, appropriate modeling and simulation approaches are needed. In this paper, a simulation method and a corresponding tool are presented that are capable to simulate hydrogen-enriched natural gas networks. To achieve this, the Peng–Robinson equation of states is applied to calculate the gas mixture properties.

In the previous section, several study cases were developed and simulated to demonstrate the importance and necessity of modeling variant gas compositions. First, different modeling approaches were analyzed by applying them to a single pipeline. By analyzing the results, it can be concluded that hydrogen injection can pose challenges to the gas pipeline network. The gas mixture composition has a significant impact on the static gas flow calculation, which can represent the long-term gas network operation. With a potentially high penetration of hydrogen in the natural gas network, the gas volumetric flow rate and nodal pressure might

vary due to the different hydrogen concentrations in gas pipelines. In addition, when the hydrogen concentration in the natural gas network system increases, the heating value of the transported gas mixture decreases. Therefore, in order to maintain a sufficient energy supply, the volumetric flow rates have to be increased, which in turn leads to increasing pressure drops throughout the pipelines Therefore, local pipeline congestion may occur in the future, which should be analyzed in advance during network planning.

The method is then applied to a simple network, where nodal hydrogen injections take place. The simulation results further confirm the findings from the previous study case. Moreover, the presented method and tool can also be used to calculate hydrogen concentration in pipelines, which is an important state variable in the analysis of hydrogen-enriched natural gas networks. Furthermore, the simulation results also provide information about the heating value of the gas mixture, which is very helpful for real-world applications, where very little real-time measurement data are currently available.

Finally, a coupled power and gas network is simulated and analyzed. This study case shows that the power and gas demand varies greatly on a seasonal level. The feasibility of blending hydrogen directly into the natural gas grid is therefore investigated using the developed simulation tool. Due to the relatively lower gas demand in summer, the permitted amount of synthetic hydrogen in the gas grid is rather limited. Therefore, a more reasonable option is to store the synthetically generated hydrogen separately or together with natural gas in warmer seasons. In winter, the gas demand is higher due to the greater heating demand. Blending hydrogen into the gas grid is therefore more feasible.

**Author Contributions:** Conceptualization, Y.L., T.P. and A.B.; methodology, Y.L., T.P. and A.B.; software, Y.L.; validation, Y.L.; formal analysis, Y.L.; investigation, Y.L.; resources, Y.L.; data curation, Y.L.; writing—original draft preparation, Y.L.; writing—review and editing, Y.L., T.P. and A.B.; visualization, Y.L.; supervision, T.P. and A.B.; project administration, T.P. and A.B.; funding acquisition, T.P. and A.B. All authors have read and agreed to the published version of the manuscript.

**Funding:** This research was funded by Operational Program for the promotion of investments in growth and employment for North Rhine-Westphalia from the European fund for regional development (OP EFRE NRW) grant number EFRE-0400111.

**Acknowledgments:** T.P. gratefully acknowledges funding by the center of excellence "Virtual Institute-Power to Gas and Heat" (EFRE-0400111) by the "Operational Program for the promotion of investments in growth and employment for North Rhine-Westphalia from the European fund for regional development" (OP EFRE NRW) through the Ministry of Economic Affairs, Innovation, Digitalization and Energy of the State of North Rhine-Westphalia.

**Conflicts of Interest:** The authors declare no conflict of interest.

#### **Abbreviations**

The following abbreviations are used in this manuscript:



## **Nomenclature**



#### **Appendix A**

**Table A1.** Typical natural gas composition [42].


#### **References**


**Lena Maria Ringsgwandl 1,\*, Johannes Schaffert 2,\*, Nils Brücken 2,\*, Rolf Albus <sup>2</sup> and Klaus Görner <sup>2</sup>**

<sup>1</sup> ALBA Group, 10719 Berlin, Germany


**Abstract:** (1) The German energy system transformation towards an entirely renewable supply is expected to incorporate the extensive use of green hydrogen. This carbon-free fuel allows the decarbonization of end-use sectors such as industrial high-temperature processes or heavy-duty transport that remain challenging to be covered by green electricity only. However, it remains unclear whether the current legislative framework supports green hydrogen production or is an obstacle to its rollout. (2) This work analyzes the relevant laws and ordinances regarding their implications on potential hydrogen production plant operators. (3) Due to unbundling-related constraints, potential operators from the group of electricity transport system and distribution system operators face lacking permission to operate production plants. Moreover, ownership remains forbidden for them. The same applies to natural gas transport system operators. The case is less clear for natural gas distribution system operators, where explicit regulation is missing. (4) It is finally analyzed if the production of green hydrogen is currently supported in competition with fossil hydrogen production, not only by the legal framework but also by the National Hydrogen Strategy and the Amendment of the Renewable Energies Act. It can be concluded that in recent amendments of German energy legislation, regulatory support for green hydrogen in Germany was found. The latest legislation has clarified crucial points concerning the ownership and operation of electrolyzers and the treatment of green hydrogen as a renewable energy carrier.

**Keywords:** hydrogen; power-to-hydrogen; power-to-gas; energy law; energy regulation; renewable energy; legal framework; energy; energy transition; electrolysis

#### **1. Introduction**

Hydrogen as an energy carrier can be used as a fuel that reacts without causing harmful emissions. When hydrogen is reacted with pure oxygen, the reaction product is water only, making hydrogen a unique fuel. The broad use of pure hydrogen is a promising future scenario for various end-use sectors, especially those that cannot easily cover their energy demands by renewable electricity. Prominent examples are in heavy-duty transportation, such as trucks, ships, or trains, and industrial high-temperature processes. Finally, the admixture of hydrogen into natural gas is also discussed as an option [1] to partly decarbonize all end-use sectors, including all gas-fired domestic and commercial technologies, before a mass rollout of dedicated pure hydrogen technologies can be realized.

Besides its unique characteristics as a fuel, hydrogen's second essential advantage is that it can be produced using only renewable electricity and water. The process is often referred to as "power-to-hydrogen", or more generally "power-to-gas" (PtG). The resulting renewable hydrogen—in the following referred to as green hydrogen—can be transported and stored in analogy to the proven natural gas technologies [2] and, thus, serve as a large-scale option to convert and store renewable electricity to cover renewable energy demands all around the year.

**Citation:** Ringsgwandl, L.M.; Schaffert, J.; Brücken, N.; Albus, R.; Görner, K. Current Legislative Framework for Green Hydrogen Production by Electrolysis Plants in Germany. *Energies* **2022**, *15*, 1786. https://doi.org/10.3390/en15051786

Academic Editor: Attilio Converti

Received: 31 January 2022 Accepted: 20 February 2022 Published: 28 February 2022

**Publisher's Note:** MDPI stays neutral with regard to jurisdictional claims in published maps and institutional affiliations.

**Copyright:** © 2022 by the authors. Licensee MDPI, Basel, Switzerland. This article is an open access article distributed under the terms and conditions of the Creative Commons Attribution (CC BY) license (https:// creativecommons.org/licenses/by/ 4.0/).

Academia, industry, and governments are constantly developing strategies to roll out hydrogen technologies, some of which have reached high technology readiness and are all set for mass production. However, in the existing energy systems, with all the interdependent entanglements of existing laws, regulations, infrastructures, and end-use applications, the market for hydrogen technologies is not developing swiftly. Until recently, decision-makers in Germany faced a lack of planning reliability due to missing legal and regulatory frameworks in combination with high technology cost. In addition, unclear future prospects, e.g., concerning prices, fees, and tariffs levied for the electricity needed for green hydrogen production, acted as barriers to investment decisions. The regulatory framework in Germany has been improved in 2021, providing more reliability. However, business models are still missing, and some aspects that appear crucial from the societal perspective, such as the long-term storage option of renewable energy in gaseous form, are not met by today's regulatory framework in Germany.

The situation is even more complex since different qualities of hydrogen could potentially be available from domestic production or imports, which could diverge dramatically in terms of environmental footprints. Depending on the environmental footprints and prices of available hydrogen on the market, different consumer groups are expected to show varying levels of acceptance.

This work reviews, analyses, and discusses the current situation for the case of Germany in 2021 with a focus on the two following research questions: Do German laws and regulations support hydrogen produced from renewable electricity (green hydrogen) in its competition with grey, blue, turquoise, or pink hydrogen? Do German laws and regulations support green hydrogen in its potential role as a long-term renewable energy storage option?

#### **2. Materials and Methods**

This work reviews and assesses the current legal framework for hydrogen in Germany. The corresponding central laws and acts as well as the national hydrogen strategy are discussed:


### **3. Results**

#### *3.1. Hydrogen—Technology Options for Its Production and the Resulting "Color Scale"*

In this section, the different possibilities to produce hydrogen are presented. Figure 1 shows the processes, educts, by-products, and "color" of the product hydrogen. The color theory is intended to reflect the degree of sustainability of the hydrogen produced. While hydrogen from fossil natural gas is turquoise, blue, or grey, hydrogen produced from biomass and biogas is green. Hydrogen from the electrolysis process, which is the focus of this paper, is also considered green hydrogen when renewable electricity sources are used, yellow when the electricity mix is used, and pink when nuclear electricity is used. The different production processes and the respective technology readiness levels (TRLs) are described in more detail below.

scale.

**Figure 1.** Overview of possible hydrogen production pathways using various technology options and electricity sources. Dashed boxes indicate technologies that are not yet available on an industrial **Figure 1.** Overview of possible hydrogen production pathways using various technology options and electricity sources. Dashed boxes indicate technologies that are not yet available on an industrial scale.

In the electrolysis process, water is split into its components hydrogen and oxygen by the addition of electrical energy. Alkaline electrolysis (AEL) (TRL 8-9) [7], proton exchange membrane electrolysis (PEMEL) (TRL 8-9) [7], and high-temperature electrolysis (HTE) (TRL 5) [8] are known as common electrolysis technologies. While AEL and PEMEL have already been in operation for many years, HTE plants are still in the development stage, and HTE is characterized in particular by a high operating temperature of 700–1000 °C [8]. The main difference between AEL and HTE is the high temperature of the electrolyte. Essentially, AEL differs from the solid electrolyte of PEMEL by its additional caustic circuit, which transports the liquid electrolyte. While AEL has been used on a large scale for many decades, PEMEL has only been installed in the MW range for a few years. One advantage of AEL is the comparatively low specific plant costs. PEMEL is characterized by a more compact design and better dynamics, which means more flexible operating point changes, especially when renewable electricity is purchased. In addition to hydrogen, there is the possibility of removing the process heat and oxygen as by-products. As can be seen in Figure 1, the color of the hydrogen depends on the electricity used. Thus, pink hydrogen can be produced by using nuclear energy, yellow hydrogen by using the In the electrolysis process, water is split into its components hydrogen and oxygen by the addition of electrical energy. Alkaline electrolysis (AEL) (TRL 8-9) [7], proton exchange membrane electrolysis (PEMEL) (TRL 8-9) [7], and high-temperature electrolysis (HTE) (TRL 5) [8] are known as common electrolysis technologies. While AEL and PEMEL have already been in operation for many years, HTE plants are still in the development stage, and HTE is characterized in particular by a high operating temperature of 700–1000 ◦C [8]. The main difference between AEL and HTE is the high temperature of the electrolyte. Essentially, AEL differs from the solid electrolyte of PEMEL by its additional caustic circuit, which transports the liquid electrolyte. While AEL has been used on a large scale for many decades, PEMEL has only been installed in the MW range for a few years. One advantage of AEL is the comparatively low specific plant costs. PEMEL is characterized by a more compact design and better dynamics, which means more flexible operating point changes, especially when renewable electricity is purchased. In addition to hydrogen, there is the possibility of removing the process heat and oxygen as by-products. As can be seen in Figure 1, the color of the hydrogen depends on the electricity used. Thus, pink hydrogen can be produced by using nuclear energy, yellow hydrogen by using the public electricity mix, and green hydrogen by using renewable electricity.

public electricity mix, and green hydrogen by using renewable electricity. Thermolysis describes the process at temperatures above 1500 °C [9] with which the thermal decomposition of water into its components hydrogen and oxygen begins. Thus, it is theoretically possible to obtain hydrogen directly from water vapor at a very high temperature level. Challenges include technically controlling the working temperature, separating hydrogen, and avoiding direct recombination with oxygen back to water. Lowering the temperature of thermal water splitting can be achieved through coupled chem-Thermolysis describes the process at temperatures above 1500 ◦C [9] with which the thermal decomposition of water into its components hydrogen and oxygen begins. Thus, it is theoretically possible to obtain hydrogen directly from water vapor at a very high temperature level. Challenges include technically controlling the working temperature, separating hydrogen, and avoiding direct recombination with oxygen back to water. Lowering the temperature of thermal water splitting can be achieved through coupled chemical reactions based on so-called metal oxide redox systems. The TRL for thermolysis is currently about 2 to 5 [8–10].

ical reactions based on so-called metal oxide redox systems. The TRL for thermolysis is currently about 2 to 5 [8–10]. In photolysis, sunlight is used with the aid of a catalyst to effect direct water splitting. In 1972, Japanese scientists Fujishima and Honda discovered that titanium dioxide was suitable as such a catalyst [11]. Although worldwide efforts have been made since then to better understand the process flow as well as how the catalyst works, there is still a lack In photolysis, sunlight is used with the aid of a catalyst to effect direct water splitting. In 1972, Japanese scientists Fujishima and Honda discovered that titanium dioxide was suitable as such a catalyst [11]. Although worldwide efforts have been made since then to better understand the process flow as well as how the catalyst works, there is still a lack of understanding to achieve major efficiency improvements. Photolysis, like thermolysis, is at a low TRL (about 3) [10].

Biomass gasification describes a process in which biomass is supplied with heat, steam, and oxygen in a controlled manner and converted into hydrogen as well as other products. The biomass gasification process runs at temperatures of >700 ◦C without combustion. Organic or fossil carbonaceous materials are converted into carbon monoxide, hydrogen, and carbon dioxide with controlled amounts of oxygen and steam. One of the major challenges in hydrogen production using biomass gasification is the reduction in investment costs for the plant as well as for the biomass feedstock. The dual fluidized bed gasification (DFB) concept from the Vienna University of Technology is a promising approach to biomass gasification. The TRL for the DFB is currently 5 [12].

Steam methane reforming (TRL 9) [13] is today's standard in large-scale hydrogen production, usually found in industrial contexts, such as the chemical industry. Steam reforming uses methane (natural gas) which is thermally decomposed into CO and H<sup>2</sup> by hot, pressurized water steam in presence of a suitable catalyst. The water–gas shift reaction then leads to more H<sup>2</sup> output and CO<sup>2</sup> formation before, in a final step, the two are separated, e.g., by a pressure swing adsorption. The resulting hydrogen from today's largescale plants is "grey hydrogen". However, renewable methane from biogenic sources that are connected to a large-scale gas processing plant by collection lines could be a technology option to produce "green hydrogen" via steam reforming as well. Steam reforming is therefore represented twice in Figure 1. The carbon dioxide emissions resulting from steam reforming plants could be reduced by integrating carbon capture technologies, which are not yet state-of-the-art (TRLs 7-8) [13,14].

Finally, one more alternative approach for hydrogen production is the technology class of pyrolysis. Here, hydrogen is provided by separating the carbon components from the methane molecules. Since the process is endothermic, heat must be added, for example in processes that use hot liquid metal baths to crack the molecules [15,16] at technology readiness levels in the range of 3-5 [13]. Other processes work, for example, with electron beam plasmas to split the methane molecules but are at a very early stage of development (TRLs 2-3) [14]. Pyrolysis technologies could be options for very large scale hydrogen production plants in the hundreds of megawatts order of magnitude. Due to their suitability for large-scale application, pyrolysis is combined with natural gas conversion in Figure 1, producing the so-called "turquoise hydrogen". This fossil-based hydrogen variant is to be distinguished from the "grey hydrogen" since its by-product carbon accumulates in solid form. Unlike gaseous CO2, for example, the chemically inert solid carbon is prevented from reaching the atmosphere and acting as a greenhouse gas. In contrast, solid carbon products such as carbon black can be sold as dyes for specific industries.

#### *3.2. Current Techno-Economic Situation of Green Hydrogen Production*

The production of green hydrogen—for energy storage or other uses—is not yet economically viable or competitive in the market. The economic competitiveness of green hydrogen production mainly depends on the cost of electrolyzers, the cost of renewable electricity used in the process, the load factor (operating hours per year), and the plant scale [17–20]. With regard to the German legal situation, the price of electricity from renewable energy sources (RESs) is most interesting. The cost of RES power has generally decreased in recent years [21], meaning the production costs of green hydrogen could also drop. Currently, however, Germany has one of the highest electricity prices worldwide [22], which is a hindrance to the economic feasibility of green hydrogen production. Taxes and levies are a large part of the electricity price in Germany (accounting for approximately 50% of the electricity price for household consumers) [23]. Thus, any exceptions to any of the imposed levies are a major concern for PtG plant operators.

#### *3.3. Introduction: German Energy Industry Act (EnWG) and Renewable Energies Act (EEG)*

To a large extent, German energy law is formed by European (i.e., European Union) law. While we will not examine European energy law in itself, it plays an important role in German legislation and the interpretation of German energy law. While the European

treaties were important in setting ground rules for a common European energy market, the EU's directives and regulations are most important in providing common regulation for the EU's member states. Both kinds of regulation are binding for the member states; directives, however, are not binding for European citizens until the member state has transposed them into national law (which they are obligated to do). Regulations, on the other hand, are directly binding for member states and citizens, much like national laws.

The two central laws for the development of green hydrogen in German energy legislation are the Renewable Energy Sources Act (EEG 2021) and the Energy Industry Act (EnWG).

The EEG 2021 (with predecessing laws going back to the 1990s [24]) governs the promotion of renewable energy sources for electricity production. It is meant to extend electricity production from renewable sources and to keep the overall cost of energy at a low level (§ 1 (1) EEG 2021). To this end, it provides two main instruments:


Both instruments are designed to offer renewable energy producers a reliable legal and financial basis for their investments.

The market premiums or feed-in tariffs are financed via the "EEG surcharge". It is charged as part of the electricity price and is thus paid for by the electricity consumers.

The EnWG, on the other hand, is not limited to energy from renewable sources. It provides an overall framework for a functioning, competitive energy market (§ 1 EnWG). Among other things, it regulates the operation of energy networks (electricity and gas) and the tasks of TSOs and distribution system operators (DSOs). It further includes rules on the unbundling of network operators, storage facility operators, and suppliers, as well as rules for grid connection and the powers of the regulatory authority.

The EnWG also is the basis for a number of ordinances regarding grid access charges. We will also discuss the unbundling regulations as they pertain to the question of which players in the market are allowed to run an electrolyzer/PtG plant under German law.

#### *3.4. Applicability of the EnWG to Hydrogen*

German legislation has recently moved forward with regard to hydrogen production. Its objective in § 1 EnWG now mentions the supply of hydrogen. Hydrogen is also mentioned as one type of energy (see definition in § 3 No. 14), albeit only as far as it is used in "grid-bound" energy supply.

Hydrogen falls under the EnWG's definition of gas according to § 3 No. 19a EnWG; however, the definition only applies to hydrogen if it is made from water electrolysis and injected into the gas grid. § 3 No. 19a makes no mention of the electricity source used for the electrolysis process, meaning that not only green hydrogen is encompassed. However, neither grey nor blue hydrogen is included.

Hydrogen also falls under the EnWG's definition of biogas (§ 3 No. 10c EnWG), provided it is produced via water electrolysis using electricity predominantly from renewable energy sources [25–27].

As for energy storage via green hydrogen, the amended EnWG now defines "hydrogen storage plants" in § 3 No. 39b. They are defined as plants for the storage of hydrogen in ownership of or in operation by an energy supply undertaking. Hydrogen storage plants of hydrogen grid operators for their tasks are not encompassed by this definition and are not hydrogen storage plants according to § 3 No. 39b EnWG.

#### 3.4.1. Ownership and Operation of Power-to-Hydrogen Plants: Unbundling Regulations

The energy market is highly regulated in Germany. There are strict rules on which players can or cannot—for example—operate electricity generation facilities, operate energy networks, or sell/supply energy. How these regulations apply to hydrogen production/PtG facilities is important to potential operators, investors, and network operators alike.

Unbundling regulations are to be found in §§ 6–10 EnWG. They transpose binding European unbundling legislation into German national law [28]. Unbundling generally is the idea that the operation of gas/electricity networks (distribution and transmission networks) has to be separated from electricity/natural gas generation and supply. The reason behind this is that network operation is a natural monopoly while generation and supply are competitive activities. Therefore, DSOs and TSOs must not be in a position to exploit their position as monopolists and unfairly influence the generation/supply market [29].

According to § 6 (1) EnWG, any network operator (NO), i.e., TSO or DSO, has to be independent from any kind of electricity/gas generation or supply. The EnWG does not allow the operation for NOs. Instead, it prescribes ownership unbundling for these activities [30].

The latest amendment to the EnWG now includes a definition of energy storage facilities (§ 3 No. 15d), which was missing from the EnWG before. Are PtG plants energy storage facilities and, if so, is this of any consequence for hydrogen energy storage? § 3 No. 15d EnWG now defines energy storage facilities. They are "facilities consuming electrical energy for electrical, chemical, mechanical or physical intermittent storage and reproduce it as electrical energy or in another form of energy". This wording includes PtG plants producing green hydrogen for energy storage. The official justification for the new amendment (BR-Drs. 165/21 v. 12.02.2021) [31] explicitly mentions PtX (power-to- . . . technologies, including PtG).

There has been some discussion about whether or not NOs should be allowed to own or operate electrolyzers [16,25,27,29]. The latest amendment of the EnWG, however, has largely rendered this question moot as far as TSOs and electricity DSOs are generally concerned.

According to § 7 (1) EnWG, electricity DSOs are not allowed to own an energy storage facility or to build, manage, or operate one. According to § 8 (2) EnWG, electricity TSOs are not allowed to own an energy storage facility or to build, manage, or operate one. § 10b (3) EnWG holds a similar regulation for TSOs within a VIU. Notice it is not gas NOs that are forbidden from engaging in energy storage facilities. The official justification merely states that the rules for gas NOs in this regard are "the general regulations" [31]. Natural gas network operators also have to abide by the unbundling regulations according to §§ 6 ff. EnWG; hence, the reasonable legal assessment is that they are also not allowed to engage in the ownership or operation of an electrolyzer [19,30].

There is an exception to the prohibition for electricity network operators: § 11a (1) EnWG says that electricity NOs are allowed to build, manage and operate energy storage facilities under certain circumstances. The energy storage facility has to be owned by a third party. The construction, management, and operation have to be tendered in an open and fair procedure. All of this only applies if the energy storage facilities are necessary for the NO to fulfil its duties according to § 11 (1) EnWG. These are to run a secure, reliable, and effective network in a non-discriminatory way and to maintain it, optimize it according to demand, and augment and expand it, as far as is economically reasonable.

§ 11b EnWG states that in certain cases, an electricity NO may own energy storage facilities or operate, build or manage them, if the regulatory authority gave permission to do so or if the regulatory authority allowed it for several or all NOs according to § 29 EnWG. This applies only to energy storage facilities that are fully integrated network components. Both § 11a and § 11b EnWG only apply to energy storage facilities that can produce electric energy. NOs could only make use of electrolyzer exceptions if they also re-electrify the hydrogen.

An example that the (green hydrogen) market has already tried these regulations is the decision made by the Federal Network Agency regarding the project "ELEMENT EINS" [32]. The planned project was to build a large-scale electrolyzer for the production of green hydrogen. The project partners were three network operators (one electricity TSO, two natural gas TSOs). The two natural gas TSOs were to build and operate the electrolyzer, and all three applicants would offer network access to their respective networks. The

application pertained to the investments necessary for the project and their financing via network fees. After long consideration, the Federal Network Agency denied the application for the project because the operation of such a plant was not within the original tasks of network operators. The agency found among other considerations that the construction of the electrolyzer was not necessary for the expansion of the supply network according to § 11 EnWG. § 11 (1) EnWG obliges NOs to run and also optimize or expand their networks as needed. The Federal Network Agency did not see the construction of the electrolyzer as part of the applicants' duties. Furthermore, the agency saw the possibility that the operation of the electrolyzer by an NO might be a risk to the network operation itself. Since the successful operation of the electrolyzer depends on congestions in the network, the NO might therefore have less of an incentive to secure an efficient and safe network in the first place. It should be kept in mind that the application was aimed at the financing of the electrolyzer investment costs via network fees. According to the Agency, this could discriminate against other potential electrolyzer operators, which do not have the possibility of offsetting their costs via network charges.

Since the time the Federal Network Agency issued the decision, the unbundling legislation in the EnWG was amended, as seen above for §§ 11 a, b EnWG. This begs the following question: would the Federal Network Agency issue a different decision today? In its decision, the Federal Network Agency stressed specifically that the legislator had not assigned the operation of an electrolyzer to an NO. This has changed to some degree as the legislator has now specifically prohibited the ownership and operation of energy storage facilities for electricity NOs (§ 7 EnWG). If the exemptions of §§ 11 a and b EnWG do not apply, there is still no way for an electricity NO to operate an electrolyzer. For natural gas NOs, there has been no change in legislation, and the decision would probably be issued in the same way now.

An overview of the current regulatory status of potential electrolyzer owners and operators in Germany is given in Table 1.


**Table 1.** Regulation of ownership and operation of electrolyzers in Germany for potential stakeholders.

#### 3.4.2. Grid Tariffs

Energy storage facilities are generally considered "final customers" in terms of electricity consumption [28]. The EnWG defines final consumers as "natural or legal persons purchasing energy for their own use" [28]. In this sense, PtG plant operators are final consumers since they purchase energy (electricity) for their own use. However, subjecting them to all the regular levies also means that the costs for running a PtG plant for storage might be high. There is also a definition of wholesale customers (§ 3 No. 21 EnWG) defining wholesale customers as "a natural or legal person purchasing electricity for the purpose of resale inside or outside the system where it is established" [28]. This definition seems to be

a little closer to the business model of an energy storage plant than the definition of a final consumer [28]; however, the wording does not fit—electrolyzer operators might not buy electricity primarily to resell it but actually to store it. The prevailing legal opinion is that energy storage plant operators are to be classified as final consumers [28].

There is a general obligation to pay network fees according to § 21 (1) EnWG. Usage of the grid occurs when taking power from the grid as well as feeding it into the grid. There is, however, an exception to this rule which applies to electrolyzer plants. § 118 (6) EnWG provides that plants constructed after 2008 and beginning operation on or after 4 August 2011 are exempted from network access fees regarding the electricity taken for storage. This expressly includes PtG plants [33]. § 118 (6) EnWG does not include an exception from feed-in fees for feeding electricity into the grid (from a PtG plant); this, however, is covered by § 15 (1) StromNEV (electricity network fee regulation ordinance): there are no charges for the injection of electricity. It should be noted that § 15 StromNEV applies to electricity of any source, not just renewable sources. Therefore, § 15 StromNEV does not constitute a privilege.

### *3.5. Green Hydrogen Production under the EEG 2021*

In the 2021 amendment of the Renewable Energies Act, hydrogen is taken into account to a larger degree. Before, the electricity supply for green hydrogen production was not exempted from surcharges. The amendments will be described in detail in the following subsections.

#### 3.5.1. Applicability of the EEG 2021 to Hydrogen

The EEG 2021 governs the promotion of energy from renewable sources. One of its objectives is the system integration of electricity from renewable sources (RES) (§§ 1, 2 EEG 2021). The EEG contains support schemes for RES, which directly affect the cost of electricity consumed for green hydrogen production and will be assessed in the following.

Does green hydrogen qualify as renewable energy according to § 3 No. 21 EEG 2017? "Renewable energy" according to this provision is, among others, "energy from biomass including biogas, bio methane ( . . . )" (see § 3 No. 21 in [34]). Hydrogen of any kind is not named in the provision. It does not fit under this regulation because it is not derived from biomass, but also not biogas. § 3 No. 11 EEG 2021 defines biogas as "any gas obtained from anaerobic fermentation of biomass". Biomass is not actually defined in the EEG 2021 [35]. However, the official justification of the EEG 2009 gives an indication: Biomass encompasses "biogenic energy carriers in solid, liquid or gaseous form" [36], which have to be biodegradable and generally derived from plant or animal origin [36]. Hydrogen is none of these things and therefore does not fall under this definition of "renewable energy". It has been argued that one could draw an analogy and thus subsume hydrogen under the term "biogas", with the reasoning being as follows: the EEG's objective is to promote climate and environmental protection, and, to that end, to promote the use of renewable electricity and the development of suitable technologies (see § 1 (1) in [33,34]); because of this, green hydrogen should also be subsumed under biogas since it has all the attributes and functions of biogas [33]. While this argumentation may appear preferable for the development of green hydrogen production in Germany, the reasoning lacks justification. In German law, an analogy requires an accidental gap in regulation, in other words, that the legislator would have included hydrogen if he had only remembered to do so. This might have been the case for the EEG 2017; however, the legislator for the EEG 2021 clearly made an amendment to include green hydrogen in other regulations (see § 69b EEG 2021). Therefore, hydrogen does not qualify as biogas in the sense of the EEG 2021.

It is important to underline the difference between the two relevant laws since in contrast to the EEG 2021, the EnWG does qualify hydrogen as biogas. This is due to different definitions of the term "biogas". Hence, it is important to apply this term only with clear reference to one law and not to assume that the EnWG and the EEG 2021 employ the same definitions.

#### 3.5.2. The EEG Surcharge

Since the operating expenditures are a crucial and potentially hindering factor in the economic viability of hydrogen production, we should take a closer look at the charges and levies that apply for green electricity supply.

The EEG surcharge serves the purpose of promoting renewable energies in Germany. It is part of the electricity price and as such has to be paid by the electricity consumers. The revenues created from the EEG surcharge are used to pay certain remunerations for operators of renewable energy, i.e., to electricity generators. The plant operators feed electricity into the power grid and receive fixed remunerations from the TSO. The TSO in turn is reimbursed via the revenues from the EEG surcharge [37].

Since electrolyzers draw power from the grid, they are considered "final consumers" (see § 3 No. 33 EEG 2021). Consequently, they fall under the scope of § 61 (I) EEG 2021 and thus have to pay the EEG surcharge as part of the electricity price. This does not seem reasonable for plant operators, since they argue their purpose is the storage of electricity, not consumption. The last amendment of the EEG has improved this situation, however. § 61 (II) EEG 2021 stipulates that under certain circumstances, the EEG surcharge can be reduced or be omitted completely. For electrolyzers, it refers to § 69b EEG 2021 (titled "production of green hydrogen"). This exemption will be explored in the following section.

#### 3.5.3. Exemption from the EEG Surcharge

§ 69b EEG 2021: Green hydrogen production

§ 69b EEG 2021 exempts PtG plants from the duty of paying the EEG surcharge. There are several requirements to be met in order to qualify for the exemption. First, it only applies to the electricity used for the production of green hydrogen. This begs the following question: what exactly qualifies as green hydrogen? The EEG 2021 itself does not define green hydrogen. § 69b stipulates that the exemption is only applicable when an ordinance has given detailed requirements for the qualification of green hydrogen. As of July 2021, an (amended) ordinance is in force: the "Ordinance for the implementation of the renewable energies act and the wind power at sea act" (also renewable energies ordinance, EEV, [5]). §§ 12h-12l EEV apply to green hydrogen. The objective of the new regulations is to exempt certain hydrogen production plants from the EEG surcharge, thus making electricity cheaper to them and eventually rendering the electrochemical production of green hydrogen more economically feasible and competitive [5].

Green hydrogen according to § 69b EEG 2021 is hydrogen made within the first 5000 full-load hours of the year (calendar year) in a green hydrogen production facility. According to § 12i EEV, it is required that the production uses exclusively electricity that:


§ 12i (2) EEV gives further definition regarding electricity stemming from renewable energy plants. Renewable energies according to § 3 No. 21 EEG 2021 are, among others, hydropower, solar power, energy from biomass, and geothermal energy. § 12i (3) EEV gives instructions for the calculation of full-load hours. It is irrelevant for which purpose the hydrogen is produced. Furthermore, § 69b EEG 2021 only applies to facilities taken into operation before 1 January 2030. According to § 12 h EEV, exemptions apply to electricity used from 1 January 2022 on [5].

§ 64a EEG 2021: Limitation for undertakings with intensive electricity costs

There is another option to reduce the EEG surcharge for green hydrogen production. §§ 63 No. 1 a, 64a EEG 2021 offers a limitation of the EEG surcharge to be paid by PtG plant operators. It applies to hydrogen production plants qualifying as undertakings with intensive electricity costs.

A short digression in order to explain the notion of "undertakings with intensive electricity costs" is as follows: The limitation of the EEG surcharge is an established instrument within the EEG's regime. Companies in certain industries (e.g., railroad, production of goods, mining, see annex 4 to EEG 2021) can apply for the limitation, provided they meet certain requirements. The objective is to keep these companies competitive in the market and to prevent them from moving their operation abroad.

According to §§ 63 No. 1a, 64a EEG 2021, companies producing hydrogen electrochemically are also eligible for this kind of EEG surcharge limitation. The limitation applies to hydrogen production for energy storage since § 64a (1) EEG 2021 states that the regulation applies regardless of the intended usage of the hydrogen. It is interesting that § 64a EEG 2021 does not make any demands regarding the source of the electricity used. As long as the hydrogen is produced electrochemically, the electricity could also stem from nuclear, coal, or other nonrenewable power sources.

Not any company involved in hydrogen production is eligible for the limitation. § 64a EEG 2021 only applies to companies active in the sector "production of industry gases" (§ 64a EEG 2021, annex 4, No. 78). Additionally, the production has to constitute the largest portion of the total added value of the company.

In case an undertaking is eligible for limitation or exemption according to both § 64a and § 69b EEG 2021, they have to decide for which one to apply. Both regulations are mutually exclusive (§ 12i (1) EEV). Only one of the regulations can be applied throughout the year. It is albeit possible to switch to the other one in the following year, and back the year after that.

§§ 61a ff. EEG 2021: Exemptions for self-provision

Another Possibility for an Exemption from the EEG Surcharge Is Offered by §§ 61a ff. EEG 2021.The exemptions apply to entities operating their own power generating facilities, without the electricity passing through the power grid (§ 3 No. 19 EEG 2021). In terms of green hydrogen production, these exemptions would benefit hydrogen projects if they produce their own electricity with renewable sources. The requirement that the electricity has to be self-produced and may not have been passed through the power grid means that the exemptions of §§ 61a ff. EEG 2021 cannot be met by many companies [39]. In case an electrolyzer is operated by an industrial hydrogen consumer, partial savings on electricity cost may be achieved by using renewable energy from their own renewable energy source production plants.

#### *3.6. Political Developments in Germany: The National Hydrogen Strategy*

The growing attention for hydrogen as an energy carrier is reflected by the fact that the German Federal Government has released its own hydrogen strategy, the National Hydrogen Strategy [6]. While it is a communication that is not legally binding, it does reflect the governments' goals which can be indicative of coming legislation. The National Hydrogen Strategy was issued in June 2020. It outlines its goals within the context of the energy transition and the German 2030 Climate Action Plan as well as the fact that Germany is committed to achieving greenhouse gas (GHG) neutrality [6]. The goal for GHG neutrality has recently been set higher (from 2050 to 2045) through § 3 (2) of the Federal Climate Protection Act [40] and is not reflected in the current version of the NHS, which as of now cites the 2030 Climate Action Plan with GHG neutrality for 2050 [41]. The Strategy further states that fossil fuels have to be replaced by alternative energy sources and that hydrogen will play a key role in this endeavor [6]. The Strategy in this respect names uses of hydrogen as an energy carrier (e.g., for fuel-cell-powered vehicles); as an instrument in sector coupling, especially in energy applications that cannot be electrified; and as an energy storage medium. The strategy also states the goal of replacing grey hydrogen with green hydrogen in industrial processes that use grey hydrogen today [6]. The last part relates to an important factor of the German hydrogen strategy: It focuses exclusively on green hydrogen [6]. It can be said that it regards only green hydrogen to be "*sustainable in the long term*" [6], although turquoise hydrogen is also mentioned [6]. Within

these conditions, the strategy aims to make hydrogen a "competitive option", to develop a "domestic market for hydrogen technology" in Germany, "establishing hydrogen as an alternative for other energy sources" and making it "a sustainable base for the industrial sector" [6]. Via the strategy, the federal government also announces wide-ranging financial support for the promotion and deployment of green hydrogen technology [6].

#### **4. Discussion**

In the following, we discuss the role of green hydrogen in the German energy system. Is green hydrogen supported by the current legal framework (Section 4.1), i.e., the Energy Industry Act and the Renewable Energies Act including its amendments? Which future developments can be drawn from the political National Hydrogen Strategy (Section 4.2)?

#### *4.1. Hydrogen in the Current Legal Framework*

The current legal framework for (green) hydrogen is the result of some recently adopted changes in legislation: The EEG 2021 was adopted (and in its wake, the EEV was amended) and the EnWG was amended as well in 2021. These laws now explicitly mention hydrogen. This is remarkable as, until 2021, there were no regulations directly addressing hydrogen or electrolyzers. Lawyers mostly had to interpret existing regulations, for the qualification of hydrogen; e.g., "Does hydrogen qualify as natural gas/biogas?", "Under which conditions is hydrogen a renewable energy carrier?". The characteristics of hydrogen as an energy carrier and a means of storing and converting electricity did not fit into some regulations. This was especially discussed when it came to questions of unbundling: Since green hydrogen is a gas that is produced from electricity, it is technically associated somewhere between the natural gas sector and the electricity sector, and it was for a long time ambiguous which sector it "belonged" to. The recent legislation is a step forward as it addresses hydrogen and hydrogen production directly. This provides legal certainty for network operators, investors, and regulatory authorities alike. This certainty is especially important for investors and potential operators or electrolyzers.

The legal framework does not, however, provide a coherent, overall regulation for hydrogen production [42]. As shown above, any definition of "green hydrogen", or hydrogen as biogas, is only relevant within the scope of the respective act. For example, the definition of green hydrogen as given in the EEV is only relevant for the exemption from the EEG surcharge according to § 69b EEG 2021. So far, there is no single and overall valid legal definition of what green hydrogen exactly is and what it qualifies for.

The aforementioned exemptions from grid access charges (§ 118 EnWG) and from the EEG surcharge (§ 64a and § 69b EEG 2021) provide support for the production of green hydrogen in Germany. Another factor for the competitiveness of green hydrogen production is carbon pricing [42]. While the price of carbon does not directly affect the hydrogen production process, an increase in the carbon price could level the playing field between grey and green hydrogen and would make green hydrogen financially more interesting for industrial companies. The German legislator will have to examine whether the current way of carbon pricing is efficient or whether it has to be adjusted in scope and price, as some have suggested that the carbon price in Germany is not high enough [42,43]. This can also be addressed in the European Union's emissions trading system at the same time.

The legislation passed in 2020 and 2021 shows that the German legislator regards hydrogen, especially green hydrogen, as a relevant factor for the German energy industry. As a result, the current legislation is overall more supportive of green hydrogen than in recent years.

#### 4.1.1. Hydrogen in the Energy Industry Act

The EnWG has had several amendments adopted in 2021. It now addresses hydrogen and regulates its use in the German energy system. This in itself is an important step forward. The new definition of energy storage facilities (§ 3 No. 15d) encompasses

electrolyzers. This definition as well as the new definition of (natural) gas, energy, and biogas (§ 3 No. 10f, 14 and 19a EnWG) now addressing hydrogen open the door for regulation of (green) hydrogen and its production. The EnWG thus regulates not only green hydrogen, but also other kinds of hydrogen. The regulations differ, however, since the general regulations regarding hydrogen apply to any "color" of hydrogen. Only hydrogen produced through electrolysis using electricity from renewable sources qualifies as biogas. Consequently, any regulation within the EnWG regarding biogas applies to green hydrogen. Whether or not the regulations are in themselves beneficial, the EnWG now provides a clearer legal framework for any entity planning to produce hydrogen. With the technique of encompassing hydrogen into already existing terms (natural gas, biogas), the legislator also was able to employ the already existing regulation as opposed to creating an overall new framework.

One criticism pertaining to the new definitions of natural gas and energy could be that they only apply to hydrogen as far as it is fed into the grid or used for grid-bound energy supply (§ 3 No. 14, 19a EnWG). This is consistent within the framework of the EnWG because this prerequisite also applies to natural gas and other energy carriers [15]; however, one interesting feature of hydrogen is that it is not dependent on the gas grid, but can be transported in other ways.

The EnWG now holds several important regulations with regard to unbundling (see above), giving potential operators of electrolyzers the much-needed legal certainty for their business. Generally, the fact that network operators are not allowed to own or operate electrolyzers is probably going to be supportive of a market launch for hydrogen production. There has been some criticism of the exceptions to those rules. Any employment of electrolyzers can potentially interfere with the energy market.

Generally, while there are good arguments for allowing NOs to operate PtG plants regarding grid safety, it would be inconsistent with the current legal framework. Since the delineation between competitive and system-based measures would be blurred, there would be a certain risk of market distortion. The benefits of PtG for grid operation could probably also be reaped if the plants were operated not by NOs, but by competitive undertakings.

#### 4.1.2. Hydrogen in the Renewable Energies Act and Its Amendment

The amendments of the EEG 2021/Renewable Energies Act could well make the production of green hydrogen economically more viable. As stated above, a major concern was (or is) the high cost of electricity in Germany, mainly due to a number of publicly imposed charges. This problem is partially solved by the regulations in § 69b and also § 64a EEG 2021 as they give a possibility to limit or be exempted from the EEG surcharge. Both state no conditions for the usage of the hydrogen produced and thus also apply to hydrogen produced for electricity/energy storage. Both regulations are relatively new and a necessary step towards promoting hydrogen as a means for energy storage.

It is worth analyzing the regulation in the EEV. Many of the detailed requirements regarding § 69b EEG 2021 are left to the EEV. The overall possibility of an exemption from the EEG surcharge is beneficial. The detailed instructions and the definition as to what green hydrogen is within the scope of the EEG 2021 are also positive: they provide legal certainty for PtG plant operators, investors, and government agencies. This being said, the requirements are quite restrictive since only the first 5000 full-load hours per year are exempted. Any electricity used after/beyond the first 5000 full-load hours is charged with the full EEG surcharge.

#### *4.2. The National Hydrogen Strategy*

Since the National Hydrogen Strategy (NHS) is a political strategy, it is not legally binding and does in itself not yield any consequences for entities dealing with hydrogen. As mentioned above, the strategy focuses on green hydrogen, as the German Federal Government only sees green hydrogen as sustainable [29]. It is coherent that the strategy then focuses on green hydrogen since it sees hydrogen as one possibility of decarbonization

and of reducing Germany's greenhouse gas emissions [29]. The NHS addresses some regulatory barriers in the promotion of green hydrogen production. By the time this paper was written, some of the regulation which was in place when the NHS was issued had already been amended.

The NHS acknowledges the problem of the current high cost of hydrogen production. The high cost of electricity—especially the price components induced by regulation—is addressed. The NHS names as one of several measures "a fair design of price components induced by the state" [29]. The NHS promises an analysis as to how the production of green hydrogen can be exempted from taxes, levies, or charges. The exemption from the EEG surcharge is specifically mentioned as one goal. Here, the strategy addresses one central regulatory problem regarding hydrogen production and has specific measures to solve it.

Another measure is the exploration of model projects of cooperations between operators of electrolyzers and network operators [29]. Since these have to be in line with the unbundling regulations, the NHS states that the government will explore the need for possibly amending the regulatory framework. The aim here is to "*ease the burden*" on the grid. A general clarification of the status of electrolyzers in the unbundling regulations is not the goal here; this could also be a sign that the government sees no need for clarification. This proposal is on the one side supportive of green hydrogen since it aims to enable the production of hydrogen. On the other hand, the operation of electrolyzers by network operators always involves the danger of market distortion. Therefore, this measure could not be supportive for the market launch of green hydrogen in the long run. This measure is also one of the few instances where the NHS indirectly mentions green hydrogen as an energy storage medium. Remarkably, the strategy almost does not mention the possibility of green hydrogen as an energy storage medium. This is on the one hand surprising because energy storage is a crucial challenge in the promotion of renewable energy sources. Green hydrogen could be an important storage medium here. On the other hand, the technology and the financial side of hydrogen as an energy storage medium are not yet on a level where it could be widely employed for storage.

The Strategy promises several measures to foster the development of a hydrogen market, some of which could be beneficial for green hydrogen production (e.g., introducing carbon dioxide pricing for fossil fuels and possible exemption from taxes, levies, and surcharges for green hydrogen production) [6]. Measures such as the support of electrolyzers for industrial procedures could indirectly also be beneficial for the economic viability of hydrogen energy storage since they might bring down prices for electrolyzers by promoting their production on a mass scale. Overall, the NHS addresses regulatory barriers for green hydrogen and suggests concrete and probably promising measures.

#### **5. Conclusions and Outlook**

German legislation has made significant progress in the last two years in terms of the regulation of green hydrogen as an energy carrier. Two central acts in German energy law —the EnWG and the EEG 2021—now explicitly address and categorize hydrogen, providing legal certainty for plant operators and network operators. One hindrance in the production of green hydrogen is the high electricity price. This has been addressed through exemptions from grid tariffs and the EEG. The regulatory framework is confined to the scope of the respective acts, meaning there is no comprehensive regulation of green hydrogen production in German law yet.

The newly formed German federal government includes green hydrogen in its coalition agreement [44]. In line with the current NHS, the focus remains on green hydrogen. Among other goals, the new government aims to make Germany a lead market for hydrogen technologies and promote the production of green hydrogen. The coalition agreement does not make any direct announcements regarding new regulation, apart from promising purchasing quotas for public agencies [44]. The coalition agreement also promises to achieve competitive electricity prices for German companies; this would have to involve

some legislation as the electricity prices in Germany are in a large part regulation-driven by charges, levies, and taxes [17].

The European Hydrogen Strategy (EHS) [45] will also further play a role as it shapes European legislation which, in turn, informs German national legislation. It is worth pointing out one difference in their terminology: The NHS focuses on green hydrogen and uses the terminology described in Section 3.1. The EHS however uses the following two terms: (a) "renewable" or "clean" hydrogen that is produced via water electrolysis using electricity from renewable sources and (b) "low-carbon" hydrogen which is fossil-based hydrogen with carbon capture or electricity-based hydrogen regardless of the electricity source [45]. Why the Commission chose this terminology is not entirely clear. It could be suggested that the aim is to shift policies in a new direction—possibly to "blur the line between 'green' and 'blue' hydrogen, essentially defining both as 'clean'" [46]. In this case, the German and the European strategies differ in a key point, and it remains open how this will shape the future German legislation regarding hydrogen.

New legislation is also to be expected from the European Union—and subsequently on the German level where it will have to be transposed. The European Commission has issued a draft to amend the current Renewable Energy Directive (RED II) [47]. The proposed amendment for the so-called RED III [48] was issued by the Commission in July 2021; it includes a quota for the member states for hydrogen used in industry: by 2030, 50% of the hydrogen used for industry purposes has to be contributed by renewable fuels of nonbiological origin [48]. If and when this proposal is passed, this quota will inform the German legislation on hydrogen and possibly be a promotor of green hydrogen in the future.

**Author Contributions:** Conceptualization and methodology, L.M.R., J.S., N.B.; formal analysis, L.M.R.; investigation, resources, visualization, L.M.R., J.S., N.B.; writing—original draft preparation, L.M.R.; writing—review and editing, J.S., N.B.; supervision, R.A., K.G. All authors have read and agreed to the published version of the manuscript.

**Funding:** This research received no external funding.

**Institutional Review Board Statement:** Not applicable.

**Acknowledgments:** The authors would like to thank Eadbhard Pernot, Christian Hampel, Elina Martens, Manfred Lange, and Frank Burmeister.

**Conflicts of Interest:** The authors declare no conflict of interest.

### **References**


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