1. Introduction

2. Literature research and overview of simulation software

Table 1. Comparison of the levelized cost of hydrogen (LCOH) with selected studies.

3. Methodology

3.2. Detail of system components

In this study, hydrogen and oxygen are produced on-site at a WWTP in Thuriniga, Germany by electrolysis using grid electricity (Scenario 1) or PV electricity generated in-house and supplemented by grid electricity (Scenario 2). In this way, climate-neutral hydrogen for fuel cell electric vehicles (FCEV) can be produced directly at the HRS (here: publicly accessible, for public use). Oxygen can also be used directly in the biological purification stage of the WWTP after intermediate storage, see here Figure 1. On-site electrolysers offer the great advantage that the refuelling station as well as the aeration basin is independent of hydrogen or oxygen supplies, transport costs are eliminated and the investment costs remain low. Before the hydrogen can be delivered to a vehicle, it must be compressed to the required pressure. The aerator for pure oxygen only works at an operating pressure of approx. 2.5 bar [28]. Therefore, the gas can be depressurized from 90 bar before it is introduced into the aeration tank of the WWTP. The hydrogen and oxygen storage tanks are bundle battery plants in a modular system. This makes it possible to expand existing plants without any problems. The hydrogen refuelling station consists of a high-pressure compressor, a dispenser's pre-cooling unit, a remote monitoring system, a regulation and control system and H₂-dispensers. [47]

Figure 1. Model of the power-to-gas (PtG) plant with on-site HRS and oxygen utilization in the aeration tank of a wastewater treatment plant (WWTP) at Thuringia, Germany.

Figure 1. Model of the power-to-gas (PtG) plant with on-site HRS and oxygen utilization in the aeration tank of a wastewater treatment plant (WWTP) at Thuringia, Germany.

The system components to design this model are illustrated below:

a. Electrolyser

The simulation was based on an alkaline high-pressure electrolyser (AEL), which provides the product gases hydrogen and oxygen at a pressure of 90 bar [10,11]. In alkaline electrolysis, the water is usually added at the cathode side (HER – Hydrogen Evolution Reaction), where the hydrogen and the OH^- ions, the charge carriers, are formed. The latter cross the microporous or anion-conducting membrane and are converted to oxygen and water on the anode side (OER – Oxygen Evolution Reaction). The half-cell reaction of alkaline electrolysis looks as follows [48]:

$$\mathrm{C}\mathrm{a}\mathrm{t}\mathrm{h}\mathrm{o}\mathrm{d}\mathrm{e} \mathrm{r}\mathrm{e}\mathrm{a}\mathrm{c}\mathrm{t}\mathrm{i}\mathrm{o}\mathrm{n}\left(\mathrm{H}\mathrm{E}\mathrm{R}\right): 2H_{2}O+2e^{-}\to H_2+2O{H}^{-}$$

$$\mathrm{A}\mathrm{n}\mathrm{o}\mathrm{d}\mathrm{e} \mathrm{r}\mathrm{e}\mathrm{a}\mathrm{c}\mathrm{t}\mathrm{i}\mathrm{o}\mathrm{n} (\mathrm{O}\mathrm{E}\mathrm{R}): 2O{H}^{-}\to \frac{1}{2}{O}_2+H_{2}O+2e^{-}$$

The electrolyser can be scaled as required due to its modular design. The power of the electrolyser for the scenario is 1.125 MW with a hydrogen production of 148,457.43 kg and an oxygen production of 978,768.00 kg. The power-independent losses of hydrogen and oxygen due to, for example, gas measurement or backwashing for gas conditioning and the power-dependent losses of oxygen for water dosing are already deducted here and are taken into account from the outset in the simulation. These can be individually defined by the user of the software. Both gases are initially stored temporarily at 90 bar. In this case study, the hydrogen is then compressed to 875 bar.

b. Photovoltaic system

With the help of a dynamic simulation programme, PV*SOL premium [49], a south-facing ground-mounted PV system was simulated in Sonneberg-Heubisch (Thuringia), the location of the LocalHy project [10,11]. The energy yield of the PV plant generated by the csv-file with hourly resolution is temporarily stored in a separate file by GHOST as an output value and can be linearly scaled in size as required during the system simulation.

According to the ordinance on tendering of Financial Support for ground-mounted systems, there is an upper limit for the size of the offer for a PV ground-mounted system: The offers must each have a size of an installed capacity of at least 100 kWp and at most 10 MWp [50]. For this reason, the maximum size of 10 MWp was fixed as a simulation value. If the average, volume-weighted surcharge value (ct/kWh) is considered over the last few years, the result is an average value of 5,221 ct/kWh. [51]. This was given as the revenue for feeding the remaining PV electricity into the grid in Scenario 2.

c. Oxygen utilization in WWTP

The electricity demand in WWTP could be saved by using pure oxygen from electrolysis. With an average share of 20 %, WWTP are usually the largest consumers of electricity in the municipal sector and consume more electricity than schools, hospitals, administrative buildings or other municipal facilities. The high electricity consumption is due to the aeration of the aeration tank of a WWTP, which usually requires by far the most energy of all the process steps of a municipal WWTP. This is around 50 to 80 % of the total electricity demand of the WWTP. [52] In Table 2 the average specific electricity consumption of WWTPs is listed according to the size class. The population equivalent (PE) is defined as the average load of biodegradable substances in the wastewater of a resident. The inhabitant-specific, annual electricity consumption kWh/(PE*a) is used to evaluate and compare the energy parameters. The investigated WWTP is assigned to size class 4. The share of the total electricity demand is 60 % in the study example. The main goal in system optimization of WWTPs is thus to reduce electricity consumption using the oxygen from water electrolysis.

Table 2. Average specific electricity consumption of WWTP by size class according to the Federal Environment Agency. [52].

Table 2. Average specific electricity consumption of WWTP by size class according to the Federal Environment Agency. [52].

WWTP size	Number of inhabitants	Specific power consumption [kWh/PE*a]
Size class 1	< 1,000	75
Size class 2	1,001 - 5,000	55
Size class 3	5,001 - 10,000	44
Size class 4	10,001 - 100,000	35
Size class 5	> 100,000	32

In drainage engineering, a difference is made between the combined system and the separate system. The construction of new sewer networks in the mixed system has largely been completed. All new systems will be separate systems in order not to mix rainwater with wastewater and to divert it separately. In Thuringia there are still predominantly combined sewer systems. [53] Due to fluctuating amounts of precipitation, there is an irregular supply of electrolytically produced oxygen. The wastewater changes over time. Thus, higher precipitation amounts are associated with lower substance concentrations and thus also lower oxygen demand. In the course of time, there are always outliers that require a significantly higher amount of oxygen per hour. This is due to the fact that sudden heavy rainfall events are often accompanied by a so-called flushing surge, which is associated with a high volume of wastewater and high concentrations of substances. This also causes a disproportionately high oxygen demand [54].

Economically, it would be unfavourable to design the entire PtG system according to these outliers, as otherwise the entire system would be oversized and thus could no longer be transferred to economic viability. For this reason, redundancies in the form of oxygen bundles are provided for these cases, which are also considered as additional expenditure for oxygen utilization. Here, the calculation is based on the energy requirement for oxygen from air separation plants, which is offset against the missing quantity of oxygen.

d. Hydrogen refuelling station

SAE J2601 is a refuelling protocol that specifies the requirements of HRS in terms of performance, refuelling process and other operating parameters. The compression process and the refuelling time are also determined here. The latter depends on several parameters, such as delivery pressure (700 or 350 bar), ambient temperature, initial pressure in the vehicle, size of the tank and the degree of refuelling to be achieved. SAE J2601 defines the following parameters as "reference" refuelling values to determine a target for the refuelling time:

-

Delivery parameter: 70 MPa @ -40 °C (H70-T40)

-

Ambient temperature: 20 °C

-

Initial pressure in the vehicle tank: 10 MPa

-

Refuelling level to be achieved: 95 %

Under these reference conditions, the maximum refuelling time is set at three minutes. [55] In addition, there is a waiting time until the pump is ready for the next customer (see also Table 3).

Different constellations are possible for both off-site (central hydrogen production) and on-site refuelling stations (on-site production). Fraunhofer ISE together with e-mobil BW GmbH (2013) have prepared an overview of various possible HRS concepts. Since off-site refuelling stations are not the focus of this publication, they are not discussed further. [56]. For refuelling stations with decentralized hydrogen production, there are two options for storage and delivery: In cascade refuelling, the gaseous energy carrier flows from the storage tank into the vehicle due to the pressure difference. [57]. In cascading, hydrogen is compressed from the low-pressure to the high-pressure storage tank, if necessary. As soon as a refuelling process starts, the vehicle is filled from the high-pressure storage tank until the pressure is equalized. Hydrogen is then filled from a pressure tank at the next higher pressure. As soon as pressure equalization occurs, a pressure tank with a higher pressure is used. Cascading with as many stages as possible can thus reduce energy losses and is the most sensible solution in terms of energy. However, higher investment and operating costs for the pressure tanks are detrimental to economic efficiency. For this reason, the general conditions are often analysed in cascading in order to determine the refuelling station configuration [58].

In order to achieve a certain refuelling level in the cascade configuration, an overpressure is required. For this reason, hydrogen is usually stored at between 800 and 900 bar in the high-pressure tank. [58,59,60]. In the case that the refuelling process starts with more than 875 bar (900 bar tank), there is usually a pressure reducer that prevents the pressure from exceeding 875 bar. Therefore, 875 bar was specified as the maximum pressure in the simulation.

In addition, refuelling with a so-called booster compressor is possible. Here, hydrogen is compressed from a low-pressure container directly into the vehicle tank. This publication focuses on cascading.

H2 MOBILITY divides HRS into four broad categories. In Table 3 the most important parameters that characterize the different sizes are listed. The simulated HRS is a refuelling station of size M - Medium with two dispensers.

Table 3. Parameters of hydrogen refuelling station (HRS) sizes (excerpt) according to the H2 Mobility initiative. [56,61].

Table 3. Parameters of hydrogen refuelling station (HRS) sizes (excerpt) according to the H2 Mobility initiative. [56,61].

	Very small	Small	Medium	Large
Numbers of dispensers	1	1	2	4
Allowed waiting time between two refuelling events in min	20	5	5	0
Max. number of refuelling events per dispenser and hour	2.5	6	6	10
Number of refuelling events per day (average/max)	10/20	30/38	60/75	125/180
Max. dispensed H2 in kg/h	18	33.6	67.5	224
Dispensed H2 in kg/d (average/max)	56/80	168/212	336/420	700/1000

The hydrogen consumption at the HRS was determined for the simulation with 110,000 kg hydrogen, which is sold for 9.50 €/kg at the refuelling station1. This corresponds to about 550 FCEV at an annual average mileage of 20,000 km per vehicle [62]. The hydrogen storage (90 bar) is equipped with 60x50 litre cylinder bundles. This corresponds to a total volume of 3,000 litres (total H₂ stored @ 90 bar: 19.26 kg). The total volume of the hydrogen storage at 875 bar is 24,000 litres (total H₂ stored @ 875 bar: 1,048.30 kg). The present compressor is a hydraulically driven piston compressor that compresses the hydrogen from the 90 bar storage into the 875 bar storage. According to a study by Fasihi et al. [33], hydrogen could be produced on all continents in 2050 at a price of 1.58 €/kg hydrogen. This assumes a reduction in the electricity production costs of renewable energies and an increase in the CO₂ emission licence prices. Furthermore, according to this study, cost degressions of PV plants, wind energy plants, hydrogen compressors and water electrolysers are to be expected up to 2050. Government subsidies, lower investment risks and a lower WACC can also improve local competitiveness [33]. Cost reduction potentials arise primarily from the continuous increase in annual production quantities and the transition to series production.

An increase in utilization cannot be guaranteed by the constellation of electrolyser and storage. Outages may occur, which will not to be considered in this scenario. An increase in the size of the storage facility would also not have had the desired effect. It would have had to be significantly enlarged, which would not have been economical. The focus of this paper is on investigating the influence of the additional use of the by-product oxygen from electrolysis. For this reason, the simulation was set for a 100 % security of supply of around 550 FCEVs with an assumed driven distance of 20,000 km/year. The remaining approximately 38,500 kg of hydrogen in the storage at the end of the year was sold to the surrounding industry for 4.50 € in the present scenario, but could also serve as a buffer in the storage for the new year.

4. Results and discussion

Table 4. Simulation results of the energy system for a scenario without photovoltaic (PV) and a scenario with PV power plant .

4.1. Simulation with grid power only (Scenario 1)

In two different scenarios, important factors influencing economic efficiency will be examined in more detail. In Scenario 1, the electrolyser is only operated with grid electricity. A fixed tariff is set here.

4.1.1. Electricity price variation

It was found that electricity costs play a major role on the economic efficiency of the overall system. Therefore, this subsection will show how a change in the electricity price helps to bring the PtG system into economic viability, on the one hand for a pure hydrogen use and on the other hand for the use of both products from water electrolysis. The results also show the marginal electricity price at which the project becomes profitable. The electricity price on the x-axis plotted in the following figures always refers to the price for the electricity mix from the grid.

4.1.1.1. Without oxygen use

The initial capital value for the given parameters (electrolysis CAPEX: 700 €/kW and electricity price: 23 ct/kWh) in this example is -25,070.67 k€ for pure hydrogen utilization. The LCOH is 19.64 €/kg H₂. To illustrate the influence of the electricity costs, these were varied from 2 ct/kWh to 23 ct/kWh. At an electricity price of 8 ct/kWh, the NPV achieved a positive result. From here on, the investment in the project is worthwhile. The LCOH reaches a value of 7.91 €/kg H₂. The payback period is 10 years. In Figure 2, the NPV and the LCOH are plotted against the electricity price.

Figure 2. Variation in electricity price for a project lifetime of 30 years (a) Change in net present value (NPV); (b) Change in LCOH values.

Figure 2. Variation in electricity price for a project lifetime of 30 years (a) Change in net present value (NPV); (b) Change in LCOH values.

4.1.1.2. With oxygen use

If the same settings are used, but oxygen is additionally used for the biological purification stage, there is a slight improvement in the NPV, but it still remains negative: -21,902.37 k€. But for an electricity price of 9 ct/kWh the NPV becomes positive. The LCOH here is 8.16 €/kg and the payback period are 15 years. In order to establish comparability with the simulation in section 4.1.1.1., the electricity price was also set at 8 ct/kWh. Now the LCOH is 7.44 €/kg H₂ and the investment is amortized after only 8 years. Figure 3 shows the increase in NPV and the reduction in LCOH through the additional use of the by-product oxygen from water electrolysis.

The difference in the LCOH values lies between 0.06 € at an electricity price of 2 ct/kWh and 1.50 € at an electricity price of 23 ct/kWh. The more expensive the electricity is for operating the water electrolysis, the more it is worthwhile to use the oxygen in addition. If it is assumed that the electricity price for accounting for the savings in the aeration tank does not change and is assumed to be constant at 23 ct/kWh, the difference between the LCOH values with and without O₂-benefit is constant at its maximum value of 1.50 €.

Figure 3. Variation in electricity price for the energy system with oxygen use for a project lifetime of 30 years, (a) Change in NPV; (b) Change in LCOH values.

Figure 3. Variation in electricity price for the energy system with oxygen use for a project lifetime of 30 years, (a) Change in NPV; (b) Change in LCOH values.

In addition to the NPV and the LCOH, the payback period is another interesting parameter to consider. In Figure 4, the payback time of the two cases, with and without oxygen consideration, is listed depending on the electricity price. At an electricity price of 23 ct/kWh, the project duration of 30 years is not sufficient to amortize the project investment. The value here is well over 32 years. In the case with oxygen, the payback period is 15 years at an electricity price of 9 ct/kWh, see above. In order to amortize the investment even in the case without oxygen use, an electricity price of 8 ct/kWh is required. The payback period is 10 years. The strong dependence on the electricity price becomes clear here. The lower the electricity price, the less the two cases differ. This is also confirmed by the NPV and LCOH curves of the two cases, with and without oxygen utilization.

Figure 4. Influence of additional oxygen use on the payback period.

Figure 4. Influence of additional oxygen use on the payback period.

4.1.2. Variation of the CAPEX of electrolyser

In order to additionally investigate the influence of the electrolyser CAPEX (EL) on the NPV, the simulation with oxygen use was selected as the initial scenario. If the NPV is plotted against the electricity costs (see Figure 5), there is hardly any difference between the simulations with initial costs of the electrolyser of 200 €/kW to 1,000 €/kW. With CAPEX of 1,000 €/kW, the investment in the project is worthwhile from an electricity price of 8 ct/kWh and lower. For the simulation with electrolyser CAPEX of 200 €/kW to 700 €/kW, the marginal electricity price is 9 ct/kWh. A special case exists for EL = 1,000 €/kW: Here the NPV reaches a positive value in the 19th and 20th year and then becomes negative again. This is due to the fact that several expenses are due in the 21st project year, such as the stack exchange, new contract for the long-term rental of the hydrogen and oxygen storage tanks and also the inspection of the HRS.

In summary, the change in electrolyser CAPEX has a smaller impact on NPV than electricity costs.

Figure 5. Effects of varying the electrolysis CAPEX on the NPV (a) depending on the electricity price for a project time of 30 years and (b) depending on the project time with an electricity price of 9 ct/kWh.

Figure 5. Effects of varying the electrolysis CAPEX on the NPV (a) depending on the electricity price for a project time of 30 years and (b) depending on the project time with an electricity price of 9 ct/kWh.

4.2. Simulation with grid and PV power (Scenario 2) with oxygen use

The positive influence of oxygen use has already been shown in Scenario 1. Therefore, in Scenario 2, the effects of an own PV system in addition to the purchase of grid electricity (PV+grid) along with the use of the oxygen are considered in particular. If the electrolyser were to be powered only by solar energy, this would not be possible without intermediate storage of the solar energy in a battery. The compressor for the HRS has a system base load, i.e. the compressor must be continuously supplied with electricity even when it is not in operation. A battery could remedy this by providing sufficient power during the night and at times no renewable energy is available. In this scenario, grid electricity was used instead of a battery.

Minutillo et al. [30] found that an optimal configuration is achieved when the annual share of electricity supply from the grid is 50 %. As described in section 3.2. (b), the PV system had to be limited to 10 MWp due to the maximum size for PV systems. For the present constellation of the PtG plant, an annual share of electricity supply by the PV plant of only 35 % is achieved here. However, it can be seen that purchasing electricity from one's own PV system improves the NPV as long as the electricity costs from the grid are higher than 4 ct/kWh (see Figure 6). From an electricity price for grid electricity of 12 ct/kWh, the investment in the project is worthwhile. The payback period here is 25 years.

The payback period for the scenario with 100 % grid electricity is 9 ct/kWh over 15 years. If this is compared with the simulation with PV+grid and 9 ct/kWh is also set here, the payback time is 14 years. This is shown in Figure 7.

Figure 7. Positive influence of an own PV system on the payback period.

Figure 7. Positive influence of an own PV system on the payback period.

For the project to pay for itself, PV+grid, for example, only requires a reduction in electricity costs to 12 ct/kWh, but if 100 % grid electricity is purchased, an electricity price of 9 ct/kWh is needed for the same result. This shows that PV+grid scenario is more profitable than a complete grid scenario for a 30-year project lifetime even considering additional investment costs of the PV plant.

4.2.1. Variation of CAPEX of the PV system

Currently, the investment costs of the PV module are around 530 €/kWp. A decline in investment costs can make this project financially more profitable. Hence, module prices until 2050 have been considered to investigate and evaluate their effect on the NPV of the project. Fraunhofer ISE conducted a study on behalf of Agora Energiewende and examined the future module prices in different scenarios based on the historical learning curve until 2050. This approach results in module costs decreasing from about 530 €/kWp to 140-210 €/kWp by 2050 in the breakthrough scenario. Other scenarios foresee module prices between 180-260 €/kWp and in the most pessimistic scenario 270-360 €/kWp. [67]

In the best scenario, here 140 €/kWp, an electricity price of at least 17 ct/kWh is needed for the NPV to be more than zero. In the case with 360 €/kWp, the electricity price must be reduced to 14 ct/kWh in order to make the project economically viable (see Figure 8). Compared to the studied example with 12 ct/kWh for grid electricity, the future scenario is better.

Figure 8. Change in NPV due to variation of PV CAPEX depending on the electricity price for grid electricity.

Figure 8. Change in NPV due to variation of PV CAPEX depending on the electricity price for grid electricity.

4.2.2. Direct sale of oxygen

In the first considerations, oxygen was used in the biological treatment stage to aerate the aeration tank in order to replace the very electricity-intensive blower there. Here, the saved electricity costs were calculated and represented as the financial contribution of oxygen usage. In a further consideration, the oxygen is now to be sold to industry at different prices instead of being reused at the treatment plant. The storage size and costs remain the same to ensure comparability.

If the produced oxygen is sold directly, the project is more profitable for the same electricity price of 23 ct/kWh. All scenarios show profitability in the project as shown in the Figure 9, even the scenario O₂ price = 1 €/kg O₂ becomes cost-effective in the 22nd project year. An oxygen selling price of at least 1.50 €/kg O₂ is recommended for this scenario to further increase the NPV. The LCOH decrease significantly, reaching a value of 7.90 €/kg H₂ at 1 €/kg O₂, 4.60 €/kg H₂ at 1.50 €/kg O₂ and 1.31 €/kg H₂ at 2 €/kg O₂. With a different technical composition of the components with different economic parameters, this effect cannot be as pronounced. However, it clearly shows the positive influence of the additional use of oxygen, which is also obtained electrolytically.

Figure 9. Improvement of the NPV through the additional sale of the electrolytically produced oxygen depending on the project time.

Figure 9. Improvement of the NPV through the additional sale of the electrolytically produced oxygen depending on the project time.

At higher electricity prices for the operation of the water electrolysis, the additional use of the oxygen, which is also produced electrolytically, leads to a greater reduction in the LCOH compared to pure hydrogen use.

4.2.3. Variation of the Weighted Average Cost of Capital (WACC)

Finally, the influence of the WACC (equal to the discount rate) as an important financial indicator and the project time are discussed. The WACC is one of the profitability indicators that have a direct influence on the NPV. It is a valuable tool for business and risk assessment. The lower the WACC, the more positive the influence on the NPV. A longer lifetime also has the effect of improving the NPV (see Figure 10). According to the Cost of Capital Study 2020 by KMPG, the WACC for the Energy & Natural Resources sector was 5.3 % in 2020, which was used as the basis for the simulations. [68]

Figure 10. Influence of the Weighted Average Cost of Capital (WACC) on the NPV depending on the project time.

Figure 10. Influence of the Weighted Average Cost of Capital (WACC) on the NPV depending on the project time.

5. Conclusion

References

1. Bundesverband WindEnergie. Wasserstoff ist der Champagner der Energiewende; 2021 2021 Sep 30. Available from: URL: https://www.windindustrie-in-deutschland.de/expertenwissen/politik/wasserstoff-ist-der-champagner-der-energiewende [cited 2023 Apr 12].
2. BMWi. Nationales Reformprogramm 2020: Die Nationale Wasserstoffstrategie.
3. Maggio G, Nicita A, Squadrito G. How the hydrogen production from RES could change energy and fuel markets: A review of recent literature. International Journal of Hydrogen Energy 2019; 44(23): 11371–11384. [CrossRef]
4. DVGW. Wo aus Wind und Sonne grünes Gas wird…: Eine Übersicht der Power-to-Gas-Projekte in Deutschland; 2020. Available from: URL: https://www.dvgw.de/themen/energiewende/power-to-gas [cited 2023 Apr 23].
5. Nicita A, Maggio G, Andaloro APF, Squadrito G. Green hydrogen as feedstock: Financial analysis of a photovoltaic-powered electrolysis plant. International Journal of Hydrogen Energy 2020; 45(20): 11395–11408. [CrossRef]
6. SPD; BÜNDNIS 90/DIE GRÜNEN; FDP. Koalitionsvertrag 2021 - 2025: Mehr Fortschritt wagen: Bündnis für Freiheit, Gerechtigkeit und Nachhaltigkeit; 2021.
7. Smolinka T, Wiebe N, Sterchele P, Palzer A. Studie IndWEDe – Industrialisierung der Wasserelektrolyse in Deutschland: Chancen und Herausforderungen für nachhaltigen Wasserstoff für Verkehr, Strom und Wärme; 2018.
8. Kato T, Kubota M, Kobayashi N, Suzuoki Y. Effective utilization of by-product oxygen from electrolysis hydrogen production. Energy 2005; 30(14): 2580–2595. [CrossRef]
9. Deutsche Energie-Agentur GmbH (dena). Baustein einer Integrierten Energiewende: Roadmap Power to Gas; 2017.
10. donner+friends UG (haftungsbeschränkt) & Co. KG. LocalHy - the real energy transition. Available from: URL: https://donnerandfriends.de/projekte/localhy.html [cited 2023 May 12].
11. Hydrogen Power Storage & Solutions East Germany e.V. (HYPOS). LocalHy: Dezentrale Wasserelektrolyse mit kombinierter Wasserstoff- und Sauerstoffnutzung aus Erneuerbarer Energie; 2015-2020. Available from: URL: https://www.hypos-eastgermany.de/wasserstoffprojekte/zwanzig20/chemische-umwandlung/localhy/ [cited 2023 Apr 12].
12. Rao P, Muller M. Industrial oxygen: its generation and use. ACEEE Summer Study on Energy Efficiency in Industry 2007; Ind. 6: 124–135.
13. Hurskainen M. Industrial oxygen demand in Finland. Research Report VTT-R-06563-17 2017.
14. Rivarolo M, Magistri L, Massardo AF. Hydrogen and methane generation from large hydraulic plant: Thermo-economic multi-level time-dependent optimization. Applied Energy 2014; 113(6): 1737–1745. [CrossRef]
15. Alsultannty YA, Al-Shammari NN. Oxygen Specific Power Consumption Comparison for Air Separation Units. EJ 2014; 18: 67–80. [CrossRef]
16. Büttner S. Interview. Oxygen purity; 2021 May 18. Personal communication.
17. Saleem MS, Abas N, Kalair AR, et al. Design and optimization of hybrid solar-hydrogen generation system using TRNSYS. International Journal of Hydrogen Energy 2020; 45: 15814–15830. [CrossRef]
18. Riedl SM. Development of a Hydrogen Refueling Station Design Tool. International Journal of Hydrogen Energy 2020; 45: 1–9. [CrossRef]
19. Colbertaldo P, Gómez Aláez SL, Campanari S. Zero-dimensional dynamic modeling of PEM electrolyzers. Energy Procedia 2017; 142: 1468–1473. [CrossRef]
20. Sánchez M, Amores E, Abad D, Rodríguez L, Clemente-Jul C. Aspen Plus model of an alkaline electrolysis system for hydrogen production. International Journal of Hydrogen Energy 2020; 45: 3916–3929. [CrossRef]
21. INSEL: Integrated Simulation Environment Language. Quebec Canada, Stuttgart: doppelintegral GmbH. Available from: URL:https://insel.eu/de/.
22. EDGAR. Freiberg. Available from: URL:https://www.freiberg-institut.de/leistungen/simulation-und-optimierung/.
23. Lund H, Thellufsen JZ, Østergaard PA, Sorknæs P, Skov IR, Mathiesen BV. EnergyPLAN – Advanced analysis of smart energy systems. Smart Energy 2021; 1: 100007. [CrossRef]
24. Hönig F, Ebert M, Blum U. Kläranlagen in Kombination mit der Wasserelektrolyse als neue Anbieter von Regelenergieprodukten. In: Neue Energie für unser bewegtes Europa: 15. Symposium Energieinnovation : 14.-16. Februar 2018, TU Graz, Österreich. Graz: Verlag der Technischen Universität Graz; 2018. Available from: URL:https://www.tugraz.at/fileadmin/user_upload/Events/Eninnov2018/files/lf/Session_F6/766_LF_Hoenig.pdf. DOI 10.3217/978-3-85125-586-7.
25. Hönig F, Duque-Gonzalez D, Schneider J, Ebert M, Blum U. Auslegung von dezentralen Wasserelektrolyseanlagen gekoppelt mit Erneuerbaren Energien. In: Luschtinetz T, Lehmann J, editors. Nutzung Regenerativer Energiequellen und Wasserstofftechnik 2019. Stralsund: HOST - Hochschule Stralsund; 2019. p. 110–120 Available from: URL:https://www.hochschule-stralsund.de/regwa/.
26. Hönig F, Duque-Gonzalez D, Hafemann M, Schneider J, Ebert M, Blum U. Ermittlung der CO2-Emissionen von Power-to-Gas-Projekten mittels GHOST und Validierung mit EnergyPLAN. In: Energy for future - Wege zur Klimaneutralität: 16. Symposium Energieinnovation : 12.-14. Februar 2020, TU Graz, Österreich. Graz: Verlag der Technischen Universität Graz; 2020. Available from: URL:https://www.tugraz.at/fileadmin/user_upload/tugrazExternal/4778f047-2e50-4e9e-b72d-e5af373f95a4/files/lf/Session_F1/614_LF_Hoenig.pdf. DOI 10.3217/978-3-85125-734-2.
27. Büttner S. Warum kommunale Kläranlagen Wasserstoff mittels Elektrolyse produzieren sollten. gwf-Wasser 2020; 12: 14–17.
28. Büttner S, Jentsch MF, Hörnlein S, Hubner B. Sektorenkopplung im Rahmen der Energiewende - Einsatz von Elektrolyseursauerstoff auf kommunalen Kläranlagen. In: Luschtinetz T, Lehmann J, editors. Nutzung Regenerativer Energiequellen und Wasserstofftechnik 2018. Stralsund: HOST - Hochschule Stralsund; 2018. p. 22–41 Available from: URL:https://www.hochschule-stralsund.de/regwa/.
29. Jentsch MF, Büttner S. Dezentrale Umsetzung der Energie- und Verkehrswende mit Wasserstoffsystemen auf Kläranlagen. gwf Gas + Energie 2019; 160: 28–39.
30. Minutillo M, Perna A, Forcina A, Di Micco S, Jannelli E. Analyzing the levelized cost of hydrogen in refueling stations with on-site hydrogen production via water electrolysis in the Italian scenario. International Journal of Hydrogen Energy 2020. [CrossRef]
31. Viktorsson L, Heinonen J, Skulason J, Unnthorsson R. A Step towards the Hydrogen Economy: A Life Cycle Cost Analysis of A Hydrogen Refueling Station. Energies 2017; 10(6): 763. [CrossRef]
32. Squadrito G, Nicita A, Maggio G. A size-dependent financial evaluation of green hydrogen-oxygen co-production. Renewable Energy 2021; 163(2): 2165–2177. [CrossRef]
33. Fasihi M, Breyer C. Baseload electricity and hydrogen supply based on hybrid PV-wind power plants. Journal of Cleaner Production 2020; 243(306): 118466. [CrossRef]
34. Salzgitter AG. WindH2: Windwasserstoff Salzgitter. Available from: URL:https://salcos.salzgitter-ag.com/de/windh2.html [cited 2023 Apr 28].
35. Salzgitter Mannesmann Forschung GmbH. GrInHy2.0: Green Industrial Hydrogen. Available from: URL:https://www.green-industrial-hydrogen.com/ [cited 2023 Apr 28].
36. Fraunhofer-Institut für Mikrostruktur von Werkstoffen und Systemen IMWS. Großelektrolyseur Leuna Gewinner im Ideenwettbewerb Reallabore der Energiewende: GreenHydroChem Mitteldeutschland wird gefördert; 2019 Jul 18. Available from: URL: https://www.imws.fraunhofer.de/de/presse/pressemitteilungen/reallabor-leuna-elektrolyse-wasserstoff.html [cited 2023 Apr 28].
37. Raffinerie Heide GmbH. Westküste 100: Sektorenkopplung komplett: Grüner Wasserstoff und Dekarbonisierung im industriellen Maßstab. Available from: URL: https://www.westkueste100.de/ [cited 2023 Apr 28].
38. ARGE Wasserstoff-Initiative-Vorpommern. Solarer Wasserstoff in Mecklenburg-Vorpommern: Utopie oder Zukunftstechnologie; 2002.
39. Forschungsinstitut für Wasser- und Abfallwirtschaft an der RWTH Aachen (FiW) e.V. WaStraK NRW "Einsatz der Wasserstofftechnologie in der Abwasserbeseitigung" - Phase I: Abschlussbericht: 1–178.
40. Schäfer M, Gretzschel O, Steinmetz H. The Possible Roles of Wastewater Treatment Plants in Sector Coupling. Energies 2022; 13(8): 2088. [CrossRef]
41. Artuso P, Zuccari F, Dell’Era A, Orecchini F. PV-Electrolyzer Plant: Models and Optimization Procedure. Journal of Solar Energy Engineering 2010; 132(3): 1951. [CrossRef]
42. Parra D, Patel MK. Techno-economic implications of the electrolyser technology and size for power-to-gas systems. International Journal of Hydrogen Energy 2016; 41(6): 3748–3761. [CrossRef]
43. Ferrero D, Gamba M, Lanzini A, Santarelli M. Power-to-Gas Hydrogen: Techno-economic Assessment of Processes towards a Multi-purpose Energy Carrier. Energy Procedia 2016; 101: 50–57. [CrossRef]
44. Yates J, Daiyan R, Patterson R, et al. Techno-economic Analysis of Hydrogen Electrolysis from Off-Grid Stand-Alone Photovoltaics Incorporating Uncertainty Analysis. Cell Reports Physical Science 2020; 1(10): 100209. [CrossRef]
45. Grimm A, Jong WA de, Kramer GJ. Renewable hydrogen production: A techno-economic comparison of photoelectrochemical cells and photovoltaic-electrolysis. International Journal of Hydrogen Energy 2020; 45(43): 22545–22555. [CrossRef]
46. Gutiérrez-Martín F, Amodio L, Pagano M. Hydrogen production by water electrolysis and off-grid solar PV. International Journal of Hydrogen Energy 2020; 44: 11371. [CrossRef]
47. H₂ POWERCELL GmbH. Interview. Components of a hydrogen refueling station. Wettringen; 2021 Sep 22. Personal communication.
48. Smolinka T, Günther M, Garche J. NOW-Studie: "Stand und Entwicklungspotenzial der Wasserelektrolyse zur Herstellung von Wasserstoff aus regenerativen Energien": Kurzfassung des Abschlussberichts; 2011. Available from: URL:https://www.now-gmbh.de/projektfinder/studie-wasserelektrolyse/.
49. PV*SOL premium: Die Planungs- und Simulationssoftware für Photovoltaik-Systeme. Berlin. Available from: URL:https://valentin-software.com/produkte/pvsol-premium/.
50. BMWi. Verordnung zur Einführung von Ausschreibungen der finanziellen Förderung für Freiflächenanlagen sowie zur Änderung weiterer Verordnungen zur Förderung der erneuerbaren Energien: Freiflächenausschreibungsverordnung - FFAV; 2015: 1–105.
51. Bundesnetzagentur. Solar Freifläche: Beendete Ausschreibungen / Statistiken. Available from: URL: https://www.bundesnetzagentur.de/DE/Sachgebiete/ElektrizitaetundGas/Unternehmen_Institutionen/Ausschreibungen/Solaranlagen1/BeendeteAusschreibungen/BeendeteAusschreibungen_node.html [cited 2023 Apr 25].
52. Fricke K, Umweltbundesamt (Hg.). Energieeffizienz kommunaler Kläranlagen; 2009.
53. Dettmar J, Brombach H. Im Spiegel der Statistik: Abwasserkanalisation und Regenwasserbehandlung in Deutschland. Korrespondenz Abwasser 2019; 66(5).
54. Büttner S. Interview. Disproportionately high oxygen demand; 2021 Apr 27. Personal communication.
55. SAE International. SAE J2601 Fueling Protocols for Light Duty Gaseous Hydrogen Surface Vehicles: J2601_202005. 2020th ed.
56. Landesagentur für Elektromobilität und Brennstoffzellentechnologie Baden-Württemberg GmbH (e-mobil BW) in Kooperation mit dem Fraunhofer-Institut für Solare Energiesysteme ISE. Wasserstoff-Infrastruktur für eine nachhaltige Mobilität: Entwicklungsstand und Forschungsbedarf 2013.
57. NOW GmbH. Einführung von Wasserstoffbussen im ÖPNV: Fahrzeuge, Infrastruktur und betriebliche Aspekte; 2018.
58. Bauer A, Mayer T, Semmel M, Guerrero Morales MA, Wind J. Energetic evaluation of hydrogen refueling stations with liquid or gaseous stored hydrogen. International Journal of Hydrogen Energy 2019; 44(13): 6795–6812. [CrossRef]
59. Reddi K, Elgowainy A, Sutherland E. Hydrogen refueling station compression and storage optimization with tube-trailer deliveries. International Journal of Hydrogen Energy 2014; 39(33): 19169–19181. [CrossRef]
60. Ozsaban M, Midilli A, Dincer I. Exergy analysis of a high pressure multistage hydrogen gas storage system. International Journal of Hydrogen Energy 2011; 36(17): 11440–11450. [CrossRef]
61. H2 MOBILITY. 70MPa Hydrogen Refuelling Station Standardization: Functional Description of Station Modules; 2010. Available from: URL: https://www.now-gmbh.de/wissensfinder [cited 2023 Apr 25].
62. Filling up with H2: Hydrogen mobility starts now; 2023. Available from: URL: https://h2.live/ [cited 2023 Apr 25].
63. Kuckshinrichs W, Ketalaer T, Koj JC. Economic analysis of improved Alkaline Water Electrolysis. Frontiers in Energy Research 2017; 5:1. [CrossRef]
64. Blohm H, Lüder K, Schaefer C, editors. Investition: Schwachstellenanalyse des Investitionsbereichs und Investitionsrechnung. 9th ed. München: Vahlen 2006.
65. Wöhe G, Döring U, editors. Einführung in die Allgemeine Betriebswirtschaftslehre. 24th ed.: Vahlen 2010.
66. Kruschwitz L, editor. Investitionsrechnung. 12th ed. München: Oldenbourg Wissenschaftsverlag 2009.
67. Fraunhofer ISE. Current and Future Cost of Photovoltaics: Long-term Scenarios for Market Development, System Prices and LCOE of Utility-Scale PV Systems; 2015.
68. KPMG. Cost of Capital Study 2020: Global economy - search for orientation? 2020.
69. United Nations. Transforming our world: the 2030 Agenda for Sustainable Development 2015.
70. Die Bundesregierung. Deutsche Nachhaltigkeitsstrategie: Weiterentwicklung 2021.
71. Stratmann K. Energieintensive Industrie fordert radikalen Schnitt beim Strompreis: Große Energieverbraucher kämpfen dafür, dass die Strompreise auf ein wettbewerbsfähiges Niveau gesenkt werden. Sie wissen den Bundeskanzler auf ihrer Seite.; 2022. Available from: URL: https://www.handelsblatt.com/politik/ [cited 2023 Apr 25].
72. Koj J, Wulf C, Schreiber A, Zapp P. Site-Dependent Environmental Impacts of Industrial Hydrogen Production by Alkaline Water Electrolysis. Energies 2017; 10(7): 860. [CrossRef]
73. Fraunhofer Institute for Solar Energy Systems ISE. Levelized Cost of Electricity: Renewable Energy Technologies 2021.
74. Statista. Strompreise für Gewerbe- und Industriekunden in Deutschland in den Jahren 2011 bis 2021; 2021. Available form: URL: https://de.statista.com/statistik/daten/studie/154902/umfrage/strompreise-fuer-industrie-und-gewerbe-seit-2006/ [cited 2023 May 10].
75. statista. Forecast hydrogen selling price of selected giga-scale projects worldwide by 2021 wind and solar costs; 2021. Available from: URL:https://www.statista.com/statistics/1260117/projected-selling-prices-of-large-scale-hydrogen-green-projects/ [cited 2023 May 05].
76. IRENA. Hydrogen: A renewable energy perspective, Report prepared for the 2^nd Hydrogen Energy Ministerial Meeting; 2019.