Grid-connected hydrogen production via large-scale water electrolysis

Energy Conversion and Management 200 (2019) 112108

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Grid-connected hydrogen production via large-scale water electrolysis ⁎

T

T. Nguyen, Z. Abdin, T. Holm, W. Mérida

Clean Energy Research Centre, The University of British Columbia, Vancouver, British Columbia V6T 1Z4, Canada

A R T I C LE I N FO

A B S T R A C T

Keywords: Water electrolysis Operation strategy Capacity factor Grid integration Flat rate pricing scheme Real-time pricing scheme

A techno-economic analysis was performed for large-scale hydrogen production plants (4000–40,000 kgH2/day or approximately 10–100 MW). Two electricity pricing schemes in 8 different geographical locations were considered. The analysis included five Canadian provinces with flat rates and real-time pricing for the wholesale markets in Germany, California, and Ontario. Under flat-rate pricing, the levelized cost of hydrogen produced via water electrolysis ranged from, for example, $4.21 to $4.71/kgH2 in Québec. For wholesale electricity markets, an operational strategy was developed that aims to identify if a posted price is high or low based on historical electricity spot prices. The electricity cost can be reduced by 4%–9% in Germany and by 15%–31% in Ontario and California at a capacity factor of 0.9 by implementing such operational strategy. Electrolytic hydrogen production in Ontario combined with underground storage was found to be the cheapest in the three wholesale electricity markets, resulting in a levelized cost of hydrogen of $2.93–$3.22/kgH2 for alkaline electrolysis and $2.66–$3.54/kgH2 for proton exchange membrane electrolysis. Compared to steam methane reforming at $2.5–$2.8/kgH2 (without carbon capture), the electrolytic hydrogen cost is 6%–27% higher. However, this cost becomes comparable to that from steam methane reforming once carbon capture and storage are included in the analysis. Our results suggest that maximizing the use of the electrolytic systems via high capacity factors can be favorable, especially under integration with wholesale electricity markets.

1. Introduction Hydrogen can play a vital role in a net-zero-emission future because it can be used as fuel in many applications in addition to being a suitable large-scale energy-storage medium. Currently, around 96% of hydrogen is produced from fossil fuels [1]. There are different approaches in use to produce hydrogen, including hydrocarbon reforming, biomass thermochemical, biological, electrolysis, photolysis, and thermolysis process. Among them, hydrocarbon reforming processes including steam methane reforming (SMR) and coal gasification are widely used, but these processes produce significant CO2 emissions owing to their carbon-containing feedstock. Hydrogen production from fossil fuels can provide a short-term solution in a net-zero emission economy for hydrogen production if it is coupled with a carbon sequestration process [2]. However, in the long-term, carbon–neutral sources must be considered. Biomass thermochemical and biological processes such as anaerobic fermentation represent alternative pathways for carbon–neutral hydrogen production [1,3–5]. Due to their low production rate, these technologies may be used for local hydrogen production or a centralized waste recycling and treatment [1,5]. For long-term development, photoelectrolysis and thermolysis are

⁎

alternative solutions, but these technologies are in the development state and facing challenges of low efficiency and stabilization [1,6]. Thermochemical cycles have major concerns due to the toxicity of the elements involved, as well as the separation of the hydrogen produced [1]. Meanwhile, water electrolysis - a mature technology - can produce hydrogen from renewable electricity. The electrolytic hydrogen system can be integrated in many applications, including power-to-power (hydrogen to electricity), power-to-gas (hydrogen to methane), powerto-liquid (hydrogen to gasoline or diesel), and power-to-industrial (hydrogen as feedstock for the industry) [7,8]. Water electrolysis is a commercially available technology, and the hydrogen obtained with this technology has a high purity once the hydrogen has been dried and oxygen impurities have been removed. The purity of hydrogen feedstock is a critical characteristic in several applications such as those using low-temperature fuel cells. In this regard, electrolytic hydrogen has an advantage over hydrogen produced from fossil fuels and biomass, as it does not need to go through a subsequent cleaning step to remove carbon-containing impurities, mainly CO. More importantly, the integration of renewable energy resources by a combination of water electrolysis and hydrocarbon fuel generation (synfuel) into the power grid constitutes a process that can

Corresponding author. E-mail address: [email protected] (W. Mérida).

https://doi.org/10.1016/j.enconman.2019.112108 Received 26 June 2019; Received in revised form 24 September 2019; Accepted 25 September 2019 0196-8904/ © 2019 Elsevier Ltd. All rights reserved.

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out Nṫ OPEXfixed OPEXvar Ptelec

Nomenclature Abbreviations AEL CAPEX CCS CF OPEX PEMEL SMR SOEL

Alkaline electrolysis Capital expenditure Carbon capture and storage Capacity factor Operational expenditure Proton exchange membrane electrolysis Steam methane reforming Solid oxide electrolysis

Output hydrogen at time step t (kgH2/hour) Annual fixed cost ($/year) Annual variable cost ($/year) Electrolyzer rated power at time step t (kW)

Parameters

Dtotal storage H2,max storage H2,min K elec Pmax elec Pmin T W i n

Variables

CAPEX Total capital investment ($) CF Capacity factor Dtinventory Maximum allowable amount of hydrogen inside the tank at time step t (kgH2) EjH,sorted Sorted historical electricity prices at index j (cents/kWh) Etcut − off Cut-off electricity spot price at time step t (cents/kWh) H2, t Hydrogen level in the storage tank at time step t (kgH2) LCofH2 Levelized cost of hydrogen ($/kgH2)

Yearly hydrogen delivered output (kgH2/year) Maximum capacity of the hydrogen storage tank (kgH2) Minimum capacity of the hydrogen storage tank (kgH2) Energy consumption of the electrolyzer (kWh/kgH2) Maximum electrolyzer rated power (kW) Minimum electrolyzer rated power (kW) Number of hours within a year (hours) Observed window of assessed historical prices (hours) Rate of return (%) Project lifetime (years)

Index Cut-off period index Time step

j t

manufacturers. In particular, 14 manufacturers offer megawatt AEL single stacks and 3 manufacturers have announced megawatt PEMEL single stacks [10]. The integration of multiple stacks in a centralized production plant was proposed with a scale from 20 MW up to 578 MW [15,16]. A pilot hydrogen plant of 6 MW PEMEL was deployed in the Energiepark Mainz electrolysis project to evaluate the P2G process and grid balancing applications [17]. Recently, an investment for a 20 MW PEMEL plant in Quebec was announced, with plans for operation by 2020 [18]. Thomas [5] presented a review of 12 renewable hydrogen technology demonstration projects with capacity from 150 kW to 2 MW. Even though the technical feasibility has been demonstrated, the energy system integration and business operation are significant challenges for the deployment of this technology on a large scale [11]. From the available techno-economic analysis, it has been found that the cost of electricity constitutes up to 40%–57% of the levelized cost of hydrogen [19,20]. However, this cost could be reduced by considering different geographical locations and smart operation strategies. Also, the carbon footprint of the electricity source must be considered to ensure that the hydrogen produced has a minimal emission of CO2. Earlier research on large-scale water electrolysis assessed technology performance and economic benefits of integrating electrolyzer into grids as hydrogen production units along with energy storage applications. Overall, several system sizes, different options for electricity markets, and operation strategies were considered. Parra et al. [21] compared the techno-economic performance of water electrolysis plants sized from 25 kW to 1000 MW participating in the Swiss wholesale electricity market [21]. The results from this study indicated that the levelized cost of hydrogen production decreased with the electrolyzer’s installed capacity because of the lower specific capital expenditure (CAPEX) and higher efficiency of the electrolysis system. The lowest hydrogen production cost was found at 1000 MW alkaline hydrogen plants, which had a unit cost of $2.76/kgH2 (CHF 83/MWh*). Parra et al. also investigated the relationship between the capacity factor and the hydrogen production cost and found that the optimum capacity factor for AEL systems was 0.54 and for PEMEL systems was 0.6. As mentioned previously, the technical performance of the current largest pilot plant built from 6 MW PEMEL in the Energiepark Mainz

decarbonize the energy supply chain [9]. The integration of large-scale water electrolysis into the power grid can mitigate the fluctuations of renewable energy sources by converting electricity into hydrogen [9,10]. For the case of synfuel production on a large scale, the installed capacity of the water electrolysis plant is expected to range from several MW to 100 MW, or even GW [9]. Currently, three water electrolysis technologies are commercially available or under development: alkaline electrolysis (AEL), proton exchange membrane electrolysis (PEMEL), and solid oxide electrolysis (SOEL) [10]. With more than 100 years of experience in alkaline electrolysis systems and thousands of installed plants around the world, AEL is the more technologically mature among the three. The improvement of AEL, which is already available at large scale (e.g., 6 MW) [10], is focused on increasing the stack’s capacity and efficiency. PEMEL is currently available at the commercial stage (e.g., a 1 MW stack in a compact design of less than 1 m2 stack footprint) [11]. Compared to AEL systems, PEMEL enables flexible operation, requires less than 1 min for start-up and seconds to ramp up from an idle state to the maximum rated power [8]. Fast response to dynamic power supplies allows PEMEL to provide services in the control reserves market and to take advantage of dynamic electricity prices. However, at the current state, PEMEL membrane lifetime is less than half of AEL membrane lifetime (40,000 h vs. 80,000 h [12]), and the design requirements of the porous electrodes represent significant disadvantages that hinder the large-scale application of PEMEL technology [13]. Based on the low heating value (LHV) of hydrogen, the nominal stack efficiency of AEL and PEMEL is 63%–71% and 60%–68%, respectively [10]. SOEL technology can reach to 100% (LHV) efficiency when the cell operates at the thermoneutral potential at a temperature range between 700 and 900 °C [10,14]. This corresponds to the specific energy consumption of approximate 3.1 kWh/Nm3H2 [10]. Because of low energy consumptions, SOEL can offer an efficient pathway for large-scale hydrogen production. However, SOEL technology is currently at the development stage [10,14]. Large-scale AEL plants, up to 100–200 MW, were constructed for the fertilizer industry in the 1950s [10]. However, implementation at this scale was abandoned because it was more expensive than SMR. Recently, driven by renewable hydrogen demand for power to gas (P2G) and power to liquid (P2L) applications, scaling up of water electrolysis plant sizes has gained attention from many leading electrolysis

*

2

At the exchange rate for January 2019.

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The selection of this system configuration was mainly based on the input requirements of feedstock hydrogen in the subsequent chemical processes related to hydrocarbon fuel generation, industrial application, or fuel supplied in electricity generation. Centralized electrolytic hydrogen production is also applicable to the transportation sector, but it requires a developed hydrogen value chain, which is not included in this study. In the following sub-sections, the technical performance and capital cost estimation for each system component is explained.

project was reported by Kopp et al. [17]. Three options for grid integration, including electricity purchase at European Power Exchange (EPEX), surplus electricity from the connected wind farm, and participation in a control reserve market, were evaluated from actual operating data from 2015 to 2016. Due to the high revenue gained from providing the ancillary services for the power grid in the control reserve market, the final electricity cost per kilogram of hydrogen was reported to be $0.96/kgH2 (€0.85/kgH2†). The specific electricity cost was approximately $1.13/kgH2 (€1/kgH2) in the EPEX market without taking into account surcharges from the German electricity market. However, a low utilization factor was reported, and the capital cost investment was not considered in this techno-economic analysis. At the country power grid scale, Gutiérrez-Martín et al. [22] proposed a hydrogen production scheme using a fleet of electrolysis plants powered by surplus energy available in the Spanish electricity grid. It was found that to be economically feasible, 300 hydrogen plants (50 MW) were required to curtail 58 TWh electricity at $0.028/kWh (€0.025/kWh) rate. While providing a qualitative assessment of the cost and revenue of water electrolysis plants for given scenarios, previous studies had a limitation in evaluating the requirements and options of power grid integration. These studies did not consider the different electricity pricing schemes and plant operating strategies. For example, the Energiepark Mainz project [17] used GAMS optimization based on dayahead electricity prices that were not able to capture the seasonal trend of electricity spot prices. Parra et al. [21] used yearly historical data to define an optimum electricity price signal—a threshold value that causes the production plant to switch to an idle state when electricity prices are higher—for the whole assessment period. However, in the wholesale electricity market, electricity spot prices are not available one year in advance, so that the previous approach is not applicable. Also, the selection of hydrogen storage technology and storage capacity was not considered. Due to these limitations, the optimum cost of electricity and the optimal system configuration were not considered fully for large-scale water electrolysis plants. In this study, the grid integration of large-scale hydrogen production with two different electrolysis technologies were analyzed with a focus on practical business operations. Furthermore, the levelized cost of hydrogen was calculated and compared to SMR production. This study included the electricity flat-rate pricing scheme in five Canadian provinces and real-time pricing scheme in the wholesale electricity markets in Ontario, Germany, and California. We considered only regions with high penetration of renewable energy sources. An operational strategy for wholesale electricity markets was proposed that aims to reduce the electricity cost of the water electrolysis plants subject to the disparity of spot electricity prices, forecasted hydrogen demand, and system constraints. The calculated, lowest levelized cost range for a large-scale PEMEL plant was found for the case of the Ontario wholesale electricity market at $2.66–$3.54/kgH2.

2.1. Electrolyzer specification and cost estimation Due to their technology readiness level, two commercial water electrolysis technologies, AEL and PEMEL [8,10], were considered in this study. Multiple reference sources including academic estimation and manufacturing announcements were included in the CAPEX evaluation of the two technologies [10,12,15,23–26]. Fig. 2 shows the specific CAPEX for both PEMEL and AEL with varying installed capacity scales [10,12,15,23–26]. Because AEL is a well-established technology while PEMEL has been commercialized recently, the CAPEX of AEL is more stable, leading to lower deviation in the estimate of the CAPEX in Fig. 2 compared to PEMEL. To reduce bias, the CAPEX inputs for both AEL and PEMEL were changed within the estimated ranges in the sensitivity analyses and the levelized cost of hydrogen was determined accordingly. Based on the literature survey, it is expected that the installed capacity of 10 MW to 100 MW for both technologies will be commonly used within the next decade [10,23]. Many key electrolyzer manufacturers have already considered a centralized production plant with multiple megawatt stacks design for both PEMEL and AEL, which may enable CAPEX reduction [11,15]. The cost for a centralized PEMEL plant at 100 MW scale is predicted to be less than $450/kW in 2030 as soon as the essential advanced technologies are available [10,23]. The efficiency of electrolyzer systems is an important parameter that strongly affects the accuracy of the techno-economic analysis. This study considered the average efficiency of actual water electrolysis plants that have operated over a long period. Specifically, based on two years of operational data for a 6 MW PEMEL plant in the Energiepark Mainz project, the energy consumption was reported to be between 5.1 and 5.2 kWh/Nm3H2, which is equivalent to 64% higher heating value (HHV) efficiency [17]. A large-scale AEL system with a stack capacity higher than 1 MW had an average efficiency of 62%, as reported by Parra et al. [21]. For a large system that is composed of multiple stacks, the efficiency was assumed to be the same as single-stack systems because the balance of the plant was already achieved within the stack module. Stack replacement was included in the economic model that took into account the annual replacement fee related to stack degradation (Table 1). 2.2. Hydrogen storage and compressors

2. Hydrogen production using water electrolysis

Due to the limited availability of low-cost electricity, a hydrogen storage unit was added to the electrolytic plant as a buffer to mitigate the variations in the hydrogen production schedule caused by electricity prices. Hydrogen storage technologies can be classified according to the physical state of the hydrogen: compressed gas hydrogen, liquid hydrogen, and solid-state hydrogen. The compressed gas storage method is chosen to store hydrogen in large-scale P2G projects because

A large-scale hydrogen production system by water electrolysis consists of several electrolyzer stacks, compressors, and gaseous hydrogen storage units (as illustrated in Fig. 1). We consider hydrogen production from electricity grids with high penetration of renewable energy and used in a wide range of applications across multiple sectors.

Fig. 1. The hydrogen production system by water electrolysis.

3

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0.4

Installed capacity (tonnes H2/day)** 2 4

40

(b)

0.4

2400

2400

2000

2000

Capital cost ($/kW)

Capital cost ($/kW)

(a)

1600 1200 800 400 0

Installed capacity (tonnes H2/day)** 2 4

40

1600 1200 800 400

1

5 10 Installed capacity (MW) Capital cost NEL Hydrogen 2015

100 E4tech 2014 Proost 2018

0

1

5 10 Installed capacity (MW) Buttler et al. 2018 FCH JU 2017 Schmidt 2017 Smolinka 2015

Fig. 2. Estimates of the specific capital cost of water electrolysis system* by installed capacity: (a): Alkaline electrolysis; (b): Proton exchange membrane electrolysis. (based on [10,12,15,23–26]). * Including power supply, system control, and gas purity. Excluding grid connection, external compression, and hydrogen storage. ** Conversion based on higher heating value efficiency: 62% for Alkaline electrolysis [17] and 64% for Proton exchange membrane electrolysis [21].

100

installation cost of the compressor was taken from Lord et al.’s economic analysis of the underground storage system [31].

Table 1 Technical specifications of water electrolysis stacks. Parameter

AEL

PEMEL

Ref

HHV efficiency Lifetime stack Stack replacement cost Electrolyzer lifetime Start-up time Ramp up Ramp down Minimum part load

62% 80,000 h $340/kW 20 years 20 min 7%–17%/s 10%–25%/s 3%–8%

64% 40,000 h $420/kW 20 years 5 min 40%/s 40%/s 0%–5%

[17,21] [12] [12,26] [12] [12] [12] [12] [12]

3. Water electrolysis system integration into the power grid Depending on the location of installation, water electrolysis plants will be charged following the existing electricity pricing scheme in that location. For most of the Canadian provinces and territories, the electricity price is set at fixed charge rates. In this pricing scheme, different charge rates are applied to different types of customers that can be classified into residential, commercial, and industrial rates depending on their consumption level. On the other hand, Alberta and Ontario have developed wholesale electricity markets over the last decade. Following a bidding process in wholesale electricity markets, the spot prices are set at the marginal production cost of the most expensive dispatched generator. The electricity spot prices or real-time prices vary hour-tohour reflecting the change in the electricity demand and supply. Participating in the wholesale electricity market gives advantages for the water electrolysis plant to reduce its operating cost by extending production capacity during periods of cheap electricity. This behavior also benefits the energy providers by reducing the peak load and enhancing grid reliability [34]. The wholesale electricity markets also exist in many regions around the world, including California and Germany. Further details of the electricity charge rates in each pricing scheme are provided in the following subsections. Energy providers also charge for the service extension to the new customers. The fee applied for extension services, especially for large electricity consumers, is typically given by energy providers. For simplification, the electrical connection charged to the hydrogen plants at

of technology readiness and energy efficiency [27–30]. Compared to gaseous storage, hydrogen liquefaction provides high storage density, which is also suitable for large-scale hydrogen storage. However, this technology requires a large amount of energy (approximately 30%–40% of the energy content of the hydrogen) for the liquefaction process and maintaining low temperature [28,29]. Gaseous hydrogen storage is a favorable storage method because of the requirement for pressurized input hydrogen in gaseous form for the subsequent hydrocarbon fuel generation processes such as Fischer-Tropsch synthesis or methanol synthesis. On a small scale, hydrogen can be stored in pressurized tanks that offer flexibility for transport. When geological conditions create suitable underground caverns, they can be used to store hydrogen on a large scale. Underground storage of hydrogen is similar to underground natural gas storage and is classified based on the geological formation, which includes salt cavern, aquifer, a depleted gas reservoir, and hard rock. Within these options, a salt cavern (an artificially constructed cavity in a deep-lying salt formation) is the best option for hydrogen storage because it maintains the purity of hydrogen since the rock salt is inert to hydrogen [27]. The underground cavern is usually located at least 1000 m underground, depending on the maximum pressure requirement and the geological conditions. The detailed specifications for a metal tank and salt cavern are given in Table 2. Financial analysis of existing underground salt caverns showed the relatively much lower capital cost $18.70/kgH2 [31] compared to the metal tank capital cost $720/kgH2 [32] for hydrogen storage. In a gaseous hydrogen storage system, 2-state diaphragm compressors that are suitable at high working pressures (40 bar upward) are recommended by expert panels [32,33]. Other types of compressors, including rotary compressor and centrifugal compressors, are limited to hydrogen applications, especially at high pressure, due to the tight tolerances needed to prevent leakage. The specific energy consumed by the compressors is dependent on the hydrogen output pressure. Regarding the storage pressure inside the metal tank (200 bar) and underground cavern (180 bar), the energy consumption of the hydrogen compressor is approximately 2.2 kWh/kgH2 [31,32]. Estimation of the

Table 2 Technical information on gaseous hydrogen storage. Metal tank

4

Ref

Maximum operating pressure (bar) Installation cost ($/kgH2)

200 bar (type I) $720/kgH2

[28] [32]

Hydrogen salt cavern General geometrical volume (m3) Average depth (m) Minimum operating pressure (bar) Maximum operating pressure (bar) Cushion gas amount (1000 kgH2) Maximum working gas amount (1000 kgH2) Max injection and withdrawal mass rates (kgH2/h) Site preparation and development cost ($/kgH2)

500,000 1200 60 180 2500 2000–4000 14,135 $18.70/kgH2

[31] [31] [31] [31] [31] [31] [31] [31]

Compressor Cost per compressor ($/kW) Compressor efficiency (kWh/kgH2)

2481 2.2

[31] [31,32]

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this scale was given the value of $200/kW, which is taken from the BC Hydro extension fee for general service [35].

from the average cost of the last 5 years based on historical electricity prices.

3.1. Flat-rate electricity pricing schemes for water electrolysis plants in Canada

3.3. Operation strategy for electrolysis systems in wholesale electricity markets

When installing on a scale at several megawatts, the water electrolysis plant is considered as a large-scale industrial customer in the flat rate pricing scheme and charged at a lower rate compared to regular consumers. Electricity rates applied to large industrial customers from five Canadian provinces are summarized in Table 3. These provinces are considered because more than 90% of their electricity is hydroelectric, and their energy charge rates are relatively low compared to other provinces. Under similar base loads, these provinces share a standard rate structure, including: an energy charge on the total energy consumption, and a demand charge on the maximum power rate during the billing period. The purpose of the demand charge is to encourage an even distribution of customers’ load to reduce the total load during the peak demand period. Among the five provinces, the lowest energy charge rates are found in Quebec, Manitoba, and Newfoundland and Labrador, where energy costs less than 3 cents/kWh. Also, some adjustable charge rates can be offered to electricity consumers under specific terms and conditions. Because of the flexibility in the operation schedule and high power consumption, a special rate can be considered for water electrolysis plants that are determined in an agreement between the plants and energy providers.

In the wholesale market, electricity prices are available 24 h ahead (“day ahead prices”) or 1 h ahead (“real-time prices”). Electricity prices also exhibit long-term trends such as seasonal fluctuation due to changing climate conditions or variation of fuel prices. Hence, in the following subsections, an operation strategy has been demonstrated to find the operation schedule in order to minimize the electricity cost of the hydrogen plants. The operation strategy was developed and simulated in Matlab using historical electricity prices of the three wholesale electricity markets. However, the operation strategy can be simulated using any computing platform. 3.3.1. Determining the cut-off electricity price Generally, a hydrogen production plant with intermediate storage can take advantage of dynamic electricity prices by increasing the production output when the electricity prices are low and reducing the output rate when prices are high. Following this practice, a threshold electricity price based on historical data is required to evaluate whether the current electricity spot price qualifies as low or high. In the implementation of the operation strategy, it is assumed that the historic electricity spot prices for one year are available and sorted in ascending order (as shown in Fig. 3) [44]. The hydrogen plant operates continuously at its rated power until it meets the total yearly demand within the sorted electricity price profile to have the minimum production cost. It is then turned off or switched to idle mode until the next production cycle starts. The value of the electricity price at the time-step when the plant switches off—after meeting the yearly forecast demand—is called cut-off value (E cut − off ). This value is used as a threshold to estimate the current electricity prices, so that the decision for the operation schedule can be made. For example, without any system constraints, when the given electricity prices are lower than the cut-off value, the hydrogen plant is set to rated power and vice versa to minimum power in the opposite scenario. If the only states of the hydrogen plants are off-state or rated power elec (Pmax ) , the capacity factor of the hydrogen plants—the ratio of the total hydrogen delivered to the maximum amount that can be produced within the production period—provides the approximate number of hours of on-state within a year. Practically, the yearly demand is forecasted for each year and assumed to be equal to the actual delivered volume (Dtotal ) . The capacity factor, CF, is defined as follows [48]:

3.2. Selection of participating in wholesale electricity markets for water electrolysis In this study, we examine the integration of water electrolysis plant into the wholesale electricity markets in Germany, Ontario, and California. Besides the availability of wholesale electricity markets, these regions have high penetration and high rate of growth of lowcarbon electricity in the total energy mix. In particular, the Ontario wholesale electricity market is considered because more than 93% of its electricity is generated from nuclear power and renewable sources. On the other hand, Alberta has a wholesale electricity market but relies heavily on fossil fuels for its electricity generation (approximately 89% of electricity is produced from fossil fuels [41]); thus it is not included in this study. Even though California and Germany have more than onethird of their electricity produced from non-renewable energy, they show growing penetration of solar energy, and therefore, they are included in this study. Also, Canada, the USA, and Germany are among the leading countries in implementing water electrolysis technology. Historical data of electricity spot prices in these markets were used to evaluate the economic performance of water electrolysis in the wholesale electricity markets. These data were obtained from CAISO [42], IESO [43], and the Energy Data Service [44] for the five years from January 2014 to December 2018. The electricity production mix and projected surge in electricity price were referred to an outlook report for Ontario and the historical data for California and Germany (as shown in Table 4). The first year’s electricity cost was determined

CF =

Dtotal elec Pmax K

×T

(1)

where T is the number of hours within a year, and K is the energy consumption by the electrolyzer. Based on this practice, the cut-off value of the electricity prices can be obtained from historical prices and the forecasted demand. For each time step t, the historical prices of the last observed window with W

Table 3 Large industrial electricity rates in five Canadian provinces. Province

Quebec British Columbia Newfoundland and Labrador Manitoba Yukon

Total electricity produced (TWh)

207.2 74.5 41.8 36.6 0.4

Electricity generation mix

95% 90% 95% 97% 95%

hydro, hydro, hydro, hydro, hydro,

*Prices are converted to USD; the exchange rate is in Jan 2019. 5

4% 9% 3% 2% 5%

wind renewable renewable, 2% petrol wind natural gas

Electricity prices*

Ref.

Demand charge

Energy charge

$9.57/kW $8.59/kW $7.40/kW $6.64/kW $11.47/kW

$0.0243/kWh $0.0422/kWh $0.0295/kWh $0.0287/kWh $0.0580/kWh

[36] [37] [38] [39] [40]

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Table 4 The electricity production mix and increasing rate of average electricity spot prices. Location

Electricity production mix (2018)

Estimated increasing rate

Ref.

California Germany Ontario

43% natural gas, 21% hydro, 17% wind and solar, 9% nuclear energy, 6% geothermal, 3% biomass, 1% other 37% coal, 28% wind and solar, 13% nuclear energy, 8% biomass, 8% natural gas, 3% hydro, 1% other 61% nuclear energy, 25% hydro, 7% wind and solar, 6% natural gas, 1% other

3.6% per year 3.6% per year 2.7% per year

[45] [46] [47]

20

demand of the production period. This constraint ensures that the hydrogen plants do not produce any amount of hydrogen that may not be in demand. Combining this with the limitation of the storage tank (Eq. (5)), the maximum allowable amount of hydrogen inside the tank at time step t (Dtinventory ) is expressed below:

Electricity Prices (cents/kWh)

CF = 0.9 15 10

Cut-off

T

5

Dtinventory = min (

∑ T−t+1

0

elec ⎛⎜Ṅ out − Pmin ⎞⎟, H storage ) t 2,max K ⎠ ⎝

(5)

out Nṫ

elec is the hydrogen output at time step t , Pmin is the minimum with rated power of the electrolyzer. Thus, the constraint of the hydrogen level at time step t is expressed as:

-5 -10

storage H2,min ≤ H2, t ≤ Dtinventory

0

(6)

1000 2000 3000 4000 5000 6000 7000 8000 9000

Hours

3.3.3. Determining the operation strategy of the hydrogen plant The detail of the subsequent steps in determining the operation strategy of the water electrolysis plants is illustrated in Fig. 4. The targeted hydrogen volume needs to be forecasted at the beginning of the production period. The following steps determine the cut-off

Fig. 3. Accessing sorted electricity spot prices: demonstrating the cut-off value at capacity factor CF = 0.9 (data from 2018 Germany spot prices [44]).

data points are sorted in ascending order. In the following step, the cutoff value is determined from the sorted historical data (EjH,sorted ) where the value is taken at the index, j , is equal to the round off value of j = CF × W .

Etcut − off = EjH,sorted

(2)

The procedure is repeated for the next time step, and the observed window moves one time-step forward, which includes the previous electricity price value. This procedure ensures a frequent update of the data and can capture the long-term trend of the electricity prices. Variations of the observed window length are examined to verify the sensitivity of this procedure to trends in electricity prices. The window length selected in this study is W = 8760 hours (=1 year). 3.3.2. System constraints To define the system constraints, it is assumed that the hydrogen plant does not produce more than the forecasted demand in the production period (one year) and that no extra hydrogen volume is carried forward to the next production period. Also, the hydrogen production rate is adjustable and varies within the minimum and maximum capacity. The operating power of the hydrogen plants is constant within the smallest time step, one hour. To address the production capability related to the system limitation and the yearly demand, the following relationships confine the constraints of the hydrogen output for each time step. First, constraints due to the production limit and storage capacity are represented in Eqs. (3) and (4) as follows: elec elec Pmin ≤Ptelec ≤ Pmax

elec Pmin ,

(3)

elec Pmax

where are the minimum and maximum rated power, and Ptelec is the rated power at time step t . storage storage H2,min ≤ H2, t ≤ H2,max

storage H2,min ,

(4)

storage H2,max

are the minimum and maximum limit of the where storage tank, and H2, t is the current hydrogen volume in the storage tank. Considering the forecasted demand, the amount of hydrogen in the storage tank at time step t should not exceed the remaining hydrogen

Fig. 4. Flowchart for determining an operation strategy of water electrolysis plants in the real-time electricity pricing scheme. 6

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storage (40,000 kgH2). A range of capacity factors from 0.4 to 1.0 is considered. This system configuration takes advantage of the flexibility of locations where large-scale geological hydrogen storage is not viable. Scenario 3 explores the effect on a levelized cost of hydrogen at wholesale electricity markets with large-scale underground hydrogen storage. By considering a 7-day storage capacity, the production plants expect to take further advantage of cost savings during off-peak periods. Similarly to scenario 2, the capacity factor is evaluated from 0.4 to 1.0. A techno-economic model is developed (as shown in Fig. 6) for each scenario to quantify the levelized cost of hydrogen. In this study, we assume that the required rate of return of capital is 10%, which is also used by National Renewable Energy Laboratory (NREL) and other clean energy consulting firms for a centralized hydrogen production technoeconomic model [32,49,50]. The rate of return is established by the potential investors could be different according to the investment criteria and risk assessment. The effects of varying interest rates are included in the sensitivity analysis section. This techno-economic model also includes other annual charges related to capital investments such as taxes and insurance. The lifetime of the plant is considered to be 20 years, based on Ref. [12]. Specific economics factors are presented in Tables 5 and 6, where Table 5 presents the other fixed costs associated with capital investment, and Table 6 lists the maintenance cost factors. Land rental and other administration and development costs, which vary across regions, are not included in this study. Stack replacement cost for the electrolyzer is not included in the component maintenance cost, but instead is part of the annual operation and maintenance (O& M) cost. Other costs related to annual expenses are labor, insurance, licensing, permitting, property tax, and land rental, also referred to the reported values from the H2A model [32]. Finally, the levelized cost of hydrogen is calculated as follows [48]:

electricity prices and the allowable range of hydrogen inventory as described in the previous sections. By comparing the current electricity price (Et ) to the cut-off price, the operation state of the electrolyzer is determined from two possible scenarios. If Et ≤ Etcut − off , the electrolyzer is set at the possible maximum rated power to meet the remaining forecasted demand (Dtinventory ) . In the second scenario (Et > Etcut − off ), hydrogen production returns to the minimum power rate that is required to maintain the minimum storage limit in the storage tank. Selection of electrolyzer rated power is presented in Eq. (7). out

inventory − H2, t − 1 + Nṫ ) × K with Et ≤ Etcut − off ⎡ (Dt Ptelec = ⎢ out (H storage − H2, t − 1 + Nṫ ) × K with Et > Etcut − off ⎣ 2,min

(7)

Ptelec

is the rated power at time step t . where The rated power at time step t (Ptelec ) determined from Eq. (7) is validated and adjusted to satisfy the constraint by the physical limit of the electrolyzer capacity (Eq. (3)). Then, the hydrogen level inside the tank is updated according to the determined rated power of the electrolyzer following this relationship:

H2, t = H2, t − 1 +

Ptelec out − Nṫ K

(8)

The procedure is applied for every time step within the production period (t ∈ (1, T ) ), and the operation power of the electrolyzer is determined accordingly. 4. Techno-economic model Three scenarios are considered (as shown in Fig. 5) to develop the techno-economic model for a grid-connected large-scale hydrogen production plant. This model also considers the variation of electricity pricing schemes, hydrogen production and storage technologies, and size of the plant components. Scenario 1 explores the effect on a levelized cost of hydrogen under the flat-rate pricing scheme where electricity prices are defined as fixed charge rates. Hydrogen storage is not included here because the operation schedule follows the output demand. The average outputs are selected at 4000 kgH2/day for medium-scale deployment and 40,000 kgH2/day for large-scale deployment. Scenario 2 explores the effect on a levelized cost of hydrogen at wholesale electricity markets with 1-day storage capacity using the metal tank at 200 bar. The storage capacity is considered to be 1-day

CAPEX × LCofH2 =

i × (1 + i)n (1 + i)n − 1 elec Pmax K

+ OPEXfixed + OPEXvar × CF × T

(9)

where i = 10% is the rate of return, n is the project lifetime, CAPEXtotal is the total initial investment, OPEXfixed is the annual fixed cost, and OPEXvar is the annual variable cost that varies depending on total hydrogen production volume.

Fig. 5. Deployment scenarios for water electrolysis. (BC = British Columbia; MB = Manitoba; NL = Newfoundland and Labrador; ON = Ontario; QC = Quebec; YT = Yukon; CA = California; GE = Germany). 7

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Fig. 6. The scope of the techno-economic model.

deployment of large-scale water electrolysis plants are Quebec, Manitoba, and Newfoundland and Labrador, which all have a relatively low energy charge rate for electricity, 2–3 cents/kWh. Hydrogen production cost can be achieved at $4.21–$4.71/kgH2 when water electrolysis plants are installed in Quebec. The levelized cost of hydrogen increases by around 7%–9% if the plant is installed in Manitoba or Newfoundland and Labrador. The levelized cost of hydrogen in British Columbia and Yukon is $5.36–$5.86/kgH2 and $6.38–$6.87/kgH2, respectively. It is also found that the demand charge in flat rate pricing schemes, which typically ranges between $6–$12/kW, contributes a significant portion to the levelized cost of hydrogen. For example, in a 10 MW AEL system, a demand charge of $1/kW increases the levelized cost of hydrogen by $0.09/kgH2. When scaling up the production rate from 10 MW to 100 MW for AEL, the levelized cost of hydrogen drops slightly by $0.076/kgH2. This moderate reduction in price arises because the AEL technology has reached a mature state, with more than 100 years of development, and large-scale units are only expected to decrease the price per installed kWh moderately (see Fig. 2). On the other hand, scaling up the installed capacity of PEMEL technology results in a higher cost reduction, estimated at $0.50/kgH2. This calculation is based on theoretical estimations but is supported by the recent commercial availability of MW scale PEMEL stacks [11]. Experts believe that developing compact stack designs and integrating PEMEL into renewable electricity grids helps to reduce the CAPEX of PEMEL [24]. In this study, we also found that the

Table 5 Install factor and other indirect costs. Indirect costs

Value (% of total capital investment)

Ref.

Site preparation Engineering design Project contingency One-time licensing fee Up-front permitting cost Install factor

5% 10% 5% 0.1% 3% 1.2–1.3

[32] [32] [32] [32] [32] [32]

Table 6 Estimation of operations and maintenance cost factor of the hydrogen production system. Operations and maintenance cost

Value (% of total capital investment)

Ref.

Labor cost Electrolyzer maintenance cost Compressor maintenance cost Storage maintenance cost Electrical maintenance cost Insurance Property tax Licensing and permits

5% 1% 4% 1% 1% 1% 1% 0.1%

[51] [32] [32] [32] [32] [32] [32] [32]

5. Results and discussion Results are presented for the three scenarios above, taking the middle values from Fig. 2 as the cost of the electrolyzers. The uncertainty of capital cost estimation, which affects the calculation of the levelized cost of hydrogen, is also included in this analysis. In the wholesale market, the electricity price is very stochastic, and in order to determine the operation cost in the wholesale market, the operation strategy (described in Section 3.3) is simulated in Matlab. Finally, the techno-economic feasibility of water electrolysis in a specific region is assessed by comparing the levelized cost of hydrogen to SMR plants (equivalent capacity).

QC NL

Levelized cost of hydrogen ($/kgH2)

For scenario 1, the levelized cost of hydrogen is estimated by varying the energy charge rate between 0 cents/kWh and 8 cents/kWh. The demand charge rate in the flat rate pricing scheme is taken to be $8.5/kW—the average value of the five provinces across Canada (shown in Table 3). Without considering the variation of demand charge, the levelized cost of hydrogen increases linearly with the energy charge rate (as shown in Fig. 7). Particularly, the levelized cost of hydrogen increases approximately $0.64–$0.67/kgH2 when the energy charge rate increases 1 cent/kWh. This study suggests that the economically feasible locations for

YT

MB

8

5.1. Hydrogen production cost in a flat-rate pricing scheme

BC

7 6 5 4

SMR+CCS

3

SMR

2

PEMEL >100 MW PEMEL 10 MW AEL >100 MW AEL 10 MW

1 0 0

1

2

3

4

5

6

7

8

Energy charged rate (cents/kWh) Fig. 7. Levelized cost of hydrogen in an electricity flat-rate pricing scheme. (BC = British Columbia; MB = Manitoba; NL = Newfoundland and Labrador; QC = Quebec; YT = Yukon). 8

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used for the observed window data set. The operation strategy was applied to the system configuration described in scenario 3. Applying the proposed operation strategy reduced the electricity costs of the hydrogen plants by 15%–27% in California, 4%–9% in Germany, and 17%–31% in Ontario. The most significant cost reduction was in the plants in Ontario, where the total cost was reduced by up to one third in the years 2016 and 2017. A possible explanation for highcost reductions in California and Ontario is the significant spike in electricity prices in peak periods compared to the low prices of the base regime. In the last five years of actual prices in Ontario, the peak prices reached 136.72 cents/kWh, while 90% of the prices were less than 3.17 cents/kWh [43]. Thus, a substantial reduction in electricity cost was achieved by avoiding operation during peak periods when the electricity prices were significantly higher. In contrast, the ratio between peak prices and the base regime in Germany was smaller than the two previous locations. The highest electricity price in the last five years in Germany was 23.73 cents/kWh, which was less than 4 times the cut-off value at CF = 0.9 (6.34 cents/kWh) [44]. Based on this finding, understanding the nature of the electricity prices is imperative to finding the cost-effectiveness of hydrogen plants in wholesale electricity markets. Furthermore, implementing the proposed operating strategy in three wholesale electricity markets enabled the definition of a cheaper electricity cost schedule based on historical electricity prices and longterm demand forecast.

investment cost of a 10 MW AEL system is approximately $14 M–$16 M, and the investment cost of the 100 MW AEL system is approximately $136 M–$159 M. For PEMEL systems, the investment cost is within $17 M–$20 M and $114 M–$183 M for 10 MW and 100 MW, respectively. To illustrate the share of the investment costs and operation costs, the detailed cost breakdown for a 100 MW PEMEL hydrogen production plant in Quebec is presented in Fig. 8. The CAPEX, including equipment cost and other indirect costs, contributes 28.4% of the levelized cost of hydrogen. In particular, the CAPEX of the electrolysis plant is dominated by the electrolyzer cost, which can represent 15.6% of the hydrogen cost and as much as 55% of the total investment costs. The largest share of the hydrogen cost corresponds to electricity costs, comprising 36.5% energy charge and 17.5% demand charge. The cost share from electricity costs can be even higher if the hydrogen plant is implemented in provinces that have higher energy charge rates. Labor cost and fixed O&M account for 7.8% and 5.1%, respectively. The remaining 4.7% of the hydrogen cost comes from the maintenance cost, annual replacement cost related to stack degradation, and water cost. The levelized cost of hydrogen in a flat rate pricing scheme of the five Canadian provinces with the lowest electricity charge rates remains higher compared to SMR. The levelized cost of hydrogen of SMR plants of equivalent scale (without carbon capture) is $2.5–$2.8/kgH2 [12]. When the carbon capture and storage (CCS) technology is considered, the levelized cost of hydrogen was reported increasing 18%–45% [1,52–54]. Noted that, the reported values were from the studies on the centralized SMR-CCS plants with scale 5–15 times larger than the current assessment scale (40,000 kg H2/day). Using this increasing rate to the levelized cost of hydrogen in the SMR plant of equivalent scale reported in this study, the cost of hydrogen by SMR-CCS is estimated within $2.95–$4.06/kgH2. Based on this estimation, the levelized cost of electrolytic hydrogen in a flat rate pricing scheme still presents less economic favorable than SMR-CCS (Fig. 7). Moreover, because of the flexibility in the operation schedule and high power consumption, it is possible for water electrolysis plants to provide ancillary services to the integrated girds, such as grid balancing and curtailment of renewable energy, thus justifying a lower electricity charge rate. In Quebec, electricity providers offer an “interruptible electricity option” in which the subscribed industrial customers get discount credits by committing to reducing their consumption during specific periods [55]. Compared to other industries, hydrogen plants have the advantages of a singleproduct output (hydrogen), a less complicated process (mostly automated), and the ability to follow intermittent schedules within short notice. To compete with SMR-CCS, reductions in both the electricity price and the demand charge for water electrolysis plants are needed. When considering the flexibility of operation schedules, storage units need to be incorporated. Storage units are also necessary to balance the variation of the hydrogen load demand in real operation.

5.3. Hydrogen production cost in the wholesale electricity market From the previous results, the operation cost of water electrolysis plants can be reduced by avoiding operation during the peak electricity prices period. However, lower use of capital investment would increase the levelized cost of hydrogen. Thus, the trade-off between the reduction of operational expenditure (OPEX) versus the increase of CAPEX needs to be optimized by the sizing of the system components. The levelized cost of hydrogen from production plants with a capacity greater than 100 MW was evaluated with capacity factors ranging from 0.4 to 1.0 to find the optimal system size in the wholesale electricity market. Operation of the plant maintains an average daily output of 40,000 kgH2/day. This assessment was carried for a system configuration in scenario 3 with two types of water electrolysis technologies, AEL and PEMEL, respectively, integrated into the California, Germany, and Ontario wholesale electricity markets. As illustrated in Fig. 10, the levelized cost of hydrogen production is strongly affected by the capacity factor. The lowest production cost of hydrogen is found at a capacity factor of 0.97 in Germany and 0.95 in both Ontario and California. When the capacity factor decreases below Annual demand charge $0.74 (17.5%) Annual energy charge $1.55 (36.5%)

5.2. Estimation of electricity cost reduction in wholesale electricity markets

Labor cost $0.33 (7.8%)

To evaluate the effectiveness of the operation strategy in the wholesale electricity markets, the electricity cost obtained from the proposed operation strategy with CF < 1.0 was compared to the total electricity cost of a similar output production plant with CF = 1.0. At capacity factor 1.0, there is no flexibility in the operating schedule; the hydrogen plant operates continuously even at the highest electricity prices during the peak hours. At lower capacity factors, applying the proposed operating strategy can reduce the electricity cost of hydrogen plants in the wholesale electricity market. The annual electricity costs were normalized in the same market for two cases (CF < 1.0 and CF = 1.0) and presented in the percentage value to have a relative comparison among various electricity markets. Fig. 9 represents the normalized results at CF = 0.9 in three wholesale electricity markets: California, Germany, and Ontario. The results were obtained from the last five years of data on electricity prices, while the first-year data are

Total fixed O&M $0.22 (5.1%) Water cost $0.01 (0.3%)

Other indirect costs $0.19 (4.4%) Electrical connection $0.22 (5.2%) Compressor $0.13 (3.2%)

Annual maintenance $0.09 (2.2%) Annual replacement cost $0.09 (2.2%) Electrolyzer $0.66 (15.6%)

Fig. 8. Cost breakdown of a 100 MW PEMEL hydrogen production plant in Quebec. 9

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100%

It is apparent from this result that, within capacity factor ranges of 0.85–0.95, the levelized costs of hydrogen in Ontario and California are slightly different, with a variation of less than 2%. Therefore, it is possible to reduce the capacity factor of the hydrogen plants to increase the flexibility of the operation schedule. This option should be considered when hydrogen plants can gain revenues from providing ancillary services such as improving the grid balance. The lower capacity factor can also be considered when integrating to renewable energy offgrid so that the hydrogen production plants can be applied to make use of the excess electricity. Note that a capacity factor of 0.4–0.6 is the availability range of combined solar and wind energies in Europe [25]. However, at this capacity factor, the production plant’s capacity is approximately two times as high as the demand forecast. Thus, the levelized cost of hydrogen is mainly dominated by CAPEX that would need further capital cost reduction to be economically feasible. Fig. 11a represents the techno-economic assessment of two system configurations, metal tank storage, and underground storage (scenario 2 and scenario 3), where the levelized cost of hydrogen is reported at the optimal capacity factor. Variation of the levelized cost of hydrogen, represented by the error bar, is induced by the uncertainty in the estimation of the capital cost (Fig. 2). Among the three assessed regions, using metal tank storage in scenario 2, the minimum cost of hydrogen production is found in Ontario, with values equal to $3.38–$3.67/kgH2 for AEL and $3.12–$3.99/kgH2 for PEMEL. This hydrogen production cost in Ontario is achieved at the optimal capacity factor of 0.97. For California, a slightly higher production cost is observed, ranging from $4.48–$4.76/kgH2 (AEL) or $4.15–$5.03/kgH2 (PEMEL) at a capacity factor of 0.96. Germany was the more expensive option among these locations, with the levelized cost of hydrogen up to $5.74–$6.02/kgH2 (AEL) and $5.38–$6.23/kgH2 (PEMEL). Note that the optimal capacity factor in Germany was found to be 0.99. When geological conditions make underground storage feasible, the levelized cost of hydrogen decreases by 8%–13% compared to metal tank storage. Mainly, the levelized cost of hydrogen in Ontario is $2.93–$3.22/kgH2 (AEL) and $2.66–$3.54/kgH2 (PEMEL), which is among the lowest production costs of the three assessed scenarios. Consistent with the literature, the lowest cost found in this research is close to what was found for 1000 MW alkaline hydrogen plants with a unit cost of $2.76/kgH2 (CHF 83/MWh) presented by Parra et al. [21]. Note that the cost of storage, which was not included in the work of Parra et al. [21], is evaluated in this work to be $0.07/kgH2 and $0.37/kgH2 for underground storage and metal tank storage, respectively. Fig. 11b provides a detailed breakdown of hydrogen production costs in three wholesale electricity markets. The CAPEX accounts for 28%–47% across the three studied regions. In terms of the breakdown of the CAPEX, electrolyzers represent the highest share of production costs, ranging from 14% to 25%. Referring to the OPEX, electricity cost

Normalized electricity cost (%)

95% 90% 85% 80% 75%

CA GE ON

70% 65% 2015

2016

Year

2017

2018

Fig. 9. Comparison of electricity cost when implementing the operation strategy in the wholesale electricity markets at CF = 0.9 (CA = California; GE = Germany; ON = Ontario).

the optimal value, the levelized cost of hydrogen increases steeply due to low use of the CAPEX. For example, the levelized cost of hydrogen rises nearly 30% when the capacity factor is reduced from 0.95 to 0.6 (Ontario-PEMEL, Fig. 10). In the opposite scenario, when the capacity factor equals 1.0, the hydrogen production cost increases 1% in Germany, 3% in Ontario, and up to 9% in California compared to a capacity factor of 0.9 because the hydrogen plants operate continuously even during the peak period. Compared to the electricity cost saving in Fig. 9, the reduction of levelized cost of hydrogen at the optimal capacity factor compared to the capacity factor of 1.0 is less significant because of those additional costs related to CAPEX. Variation in the optimal value of the capacity factor was observed among the three assessed locations because of the volatile characteristics of the electricity market. The optimal capacity factor of the plant in Germany market is close to 1 (CF = 0.97), and optimizing the capacity factor only reduces the production cost by less than 1% compared to operating with CF = 1.0. This result in Germany can be interpreted with the previous result that electricity cost was not largely reduced (4%–9%) when applying the proposed operation strategy, even at a much lower capacity factor (CF = 0.9). Hence, a high use factor is favorable in the German market to achieve cost-effectiveness. On the other hand, the levelized cost of hydrogen is much improved in California at CF = 0.95 compared to CF = 1.0 (as shown in Fig. 10).

(b)

8

Levelized cost of hydrogen($/kgH2)

Levelized cost of hydrogen ($/kgH2)

(a)

7 6 5 4 3 SMR+CCS 2

SMR CA GE ON

1 0

0.4

0.5

0.6

0.7

0.8

0.9

1.0

Capacity factor

8 7 6 5 4 3 SMR+CCS 2

SMR CA GE ON

1 0

0.4

0.5

0.6

0.7

0.8

0.9

1.0

Capacity factor

Fig. 10. Levelized cost of hydrogen in three wholesale electricity markets as a function of capacity factor: (a) AEL underground storage, (b) PEMEL underground storage (CA = California; GE = Germany; ON = Ontario). 10

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(a)

7

100%

(b)

2%

2% 0%

OPEX Annual replacement cost Annual maintenance 5% 6% 7% 7% 6% 6% 6% Water cost 8% 9% 7% 7% 8% 9% 7% 7% Total fixed O&M 8% 9% 8% 9% Labor cost 11% 11% Annual cost electricity 11% 11%

1%

2%

5%

6

Levelized cost of hydrogen ($/kgH2)

80% 5.88

5

5.81

5.43 5.36

4

4.62

4.59

4.15

3

3.53

60% SMR+ CCS

4.13

40% SMR

3.56 3.07

26% 25%

3.10

2

43% 41% 5% 5% 6%

20%

7%

6% 7%

30% 28% CAPEX

6%

6%

8%

7% 47% 45%

53% 51% 5%

5%

6%

6%

10% 10% 7%

58% 56%

6%

6%

9%

8%

6% 5%

Other indirect costs Electrical connection Storage Compressor Electrolyzer

5%

1 0

AEL PEM AEL PEM AEL PEM AEL PEM AEL PEM AEL PEM

CA

GE

ON

CA

GE

0%

17% 17% 14% 14% 21% 22% 19% 19% 15% 15% 25% 25% AEL PEM AEL PEM AEL PEM AEL PEM AEL PEM AEL PEM

ON

Metal tank storage Underground storage

CA

GE

ON

Metal tank storage

CA

GE

ON

Underground storage

Fig. 11. (a) Optimal hydrogen production cost assessment in wholesale electricity markets using AEL and PEMEL technologies; (b) hydrogen production cost breakdown in wholesale electricity markets, (labels of the values equal or less than 5% are not displayed). (CA = California; GE = Germany; ON = Ontario).

The model presented in this study provided a systematic assessment for the implementation of hydrogen plants in the wholesale electricity market. We analyzed the disparity of historical electricity prices in the targeted wholesale markets to evaluate economic viability and quantify the levelized cost of hydrogen. Our results indicate that avoiding operation during peak periods can reduce the electricity cost up to 30% in the Ontario and California wholesale markets. The lowest levelized cost of hydrogen was found for plant deployment within the Ontario wholesale market. After capital cost reduction via scaling-up production and optimizing the operation cost by following the proposed operation strategy in Ontario, the levelized cost of electrolytic hydrogen was found to be approximately 6%–27% higher than that produced via SMR. When compared to other low-carbon hydrogen production pathways, the levelized cost of hydrogen by water electrolysis in the Ontario wholesale market is comparable to SMR with CCS. On the other hand, the integration of water electrolysis under the current flat rate pricing scheme in five Canadian provinces remains expensive and requires reduction of both energy and demand charge rates to be economically viable. Compared to hydrogen from fossil fuels, electrolytic hydrogen can provide a pathway for a net-zero-emission energy system that can channel renewable power across the transport, heat, industry, and

accounts for a significant share of costs, with a maximum of 58% in Germany and a minimum of 25% in Ontario. Furthermore, labor cost and annual fixed O&M have an approximate equivalent share, in which the former makes up 7%–11% and the latter contributes about 5%–9%. This assessment illustrated the economic viability when integrating a large-scale hydrogen production plant into the wholesale electricity market. For comparison, when applying flat industrial rate electricity in Quebec (2.43 cents/kWh)—which is the cheapest rate among the flat rate pricing schemes in Canadian provinces—into the techno-economic model, the hydrogen production cost is $4.21–$4.71/kgH2. Production cost in a flat rate pricing scheme can be higher than the reported value when considering an additional investment of the hydrogen storage units if required. Moreover, the electrolytic hydrogen production cost in Ontario is comparable to the hydrogen production cost by SMR plant (with CCS) at equivalent capacity. This result showed a feasible pathway to produce low-carbon hydrogen in large scale by water electrolysis when access to low cost electricity and underground storage are available. 5.4. Sensitivity analysis The sensitives of key parameters on the hydrogen production cost are illustrated in Fig. 12. The sensitivity analysis is based on a PEMEL plant with underground storage presented in scenario 3 and selectively applied on Ontario location. The electrolyzer efficiency and the specific capital cost have largest impact magnitudes on the hydrogen production cost among the assessment parameters. Thus, the future strategy to reduce electrolytic hydrogen cost should consider the efficiency improvement and capital cost reduction. The internal rate of return considerably influences the hydrogen cost estimates but less significant relative to the electrolyzer efficiency. On the other hand, the electrical connection cost and the estimated increasing rate of electricity cost have a small impact compared to other parameters.

Levelized cost of hydrogen ($/kgH2)

4.0

6. Conclusion A techno-economic analysis was performed for a large-scale, gridconnected electrolytic hydrogen production plants under flat rate pricing schemes and wholesale electricity markets across Canada and two other locations—California and Germany. The locations were chosen based on the penetration of renewable energy in the electricity production mix, and the ability to provide low-cost electricity either at a fixed charge rate or via spot prices.

Specific capital cost Electrolyzer efficiency Rate of return Electricity cost increasing rate Electrical connection cost

3.8 3.6 3.4 3.2 3.0 2.8 2.6 -30%

-20%

-10% 0% 10% Variable percentage change (%)

20%

30%

Fig. 12. Hydrogen production cost sensitivities: selective analysis for scenario 3 in Ontario. 11

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electricity sectors. In addition, electrolyzers can provide grid balancing services by operating as controllable loads, thereby enabling high penetration of non-dispatchable renewable energy.

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