A Techno-Economic Study for Off-Grid Green Hydrogen Production Plants: The Case of Chile

Abstract

In this study, we present a pre-feasibility analysis that examines the viability of implementing autonomous green hydrogen production plants in two strategic regions of Chile. With abundant renewable energy resources and growing interest in decarbonization in Chile, this study aims to provide a comprehensive financial analysis from the perspective of project initiators. The assessment includes determining the optimal sizing of an alkaline electrolyzer stack, seawater desalination system, and solar and wind renewable energy farms and the focus is on conducting a comprehensive financial analysis from the perspective of project initiators to assess project profitability using key economic indicators such as net present value (NPV). The analyses involve determining appropriate sizing of an alkaline electrolyzer stack, a seawater desalination system, and solar and wind renewable energy farms. Assuming a base case production of 1 kiloton per year of hydrogen, the capital expenditures (CAPEX) and operating expenses (OPEX) are determined. Then, the manufacturing and production costs per kilogram of green hydrogen are calculated, resulting in values of USD 3.53 kg⁻¹ (utilizing wind energy) and USD 5.29 kg⁻¹ (utilizing photovoltaic solar energy). Cash flows are established by adjusting the sale price of hydrogen to achieve a minimum expected return on investment of 4% per year, yielding minimum prices of USD 7.84 kg⁻¹ (with wind energy) and USD 11.10 kg⁻¹ (with photovoltaic solar energy). Additionally, a sensitivity analysis is conducted to assess the impact of variations in investment and operational costs. This research provides valuable insights into the financial feasibility of green hydrogen production in Chile, contributing to understanding renewable energy-based hydrogen projects and their potential economic benefits. These results can provide a reference for future investment decisions and the global development of green hydrogen production plants.

1. Introduction

Globally, substantial quantities of anthropogenic greenhouse gases (GHGs) continue to be emitted, exacerbating global warming and causing severe environmental impacts [1]. By 2020, CO₂ emissions from the energy sector had reached 31.5 billion tons worldwide, resulting in an atmospheric concentration of 412.5 ppm CO₂, which was approximately 50% higher than the estimated concentration in the pre-industrial era [2]. Consequently, there has been a renewed focus on exploring alternatives to mitigate carbon dioxide emissions, with particular attention given to the production of green hydrogen. Green hydrogen refers to hydrogen generated through the process of water electrolysis using renewable electricity. This approach holds promise for substantial emissions reductions in the future and has the potential to contribute to achieving a carbon-neutral balance [3].

The production of green hydrogen, a promising clean energy carrier, has garnered significant attention worldwide due to its potential to address climate change and to facilitate the transition to a low-carbon economy [4]. Numerous studies have explored various aspects of green hydrogen production, including technology advancements, cost analyses, and environmental impacts. This literature review aims to provide a comprehensive overview of the existing research on green hydrogen production while highlighting the unique contributions of this study [5].

Several studies have focused on developing and optimizing electrolysis technologies for efficient hydrogen generation from renewable energy sources. For instance, Gado et al. [6] investigated the performance of proton exchange membrane (PEM) electrolyzers and highlighted their high efficiency and scalability. Similarly, Zappia et al. [7] explored the potential of alkaline electrolyzers and emphasized their cost-effectiveness and suitability for large-scale applications. These studies underscored the importance of electrolyzer technology advancements in achieving cost-competitive green hydrogen production.

Moreover, a cost analysis is a crucial aspect of assessing the economic viability of a green hydrogen project. Liu et al. [8] conducted a comprehensive techno-economic analysis of green hydrogen production by considering capital expenditures, operational costs, and hydrogen selling prices. Their study demonstrated that these cost components influence overall project profitability. Additionally, Hjeij et al. [9] conducted a comparative cost analysis of different renewable energy sources for hydrogen production and provided insights into the cost competitiveness of wind, solar, and other renewable technologies.

Chile has implemented various recent initiatives in the field of green hydrogen production. One notable example is the Haru Oni project developed by the Highly Innovative Fuels (HIF) company. This project currently operates a pilot plant for e-fuel production and has plans for an industrial-scale expansion. By implementing a green hydrogen generation process and an atmospheric CO₂ capture system in the southern region of the country, the project aims to produce 550 million liters of e-fuels by 2026 [10].

The Chilean government has also taken significant steps in promoting green hydrogen through initiatives such as the National Green Hydrogen Strategy. Unveiled at the end of 2020, this strategy sets ambitious targets, including producing 200 kton∙year⁻¹ of hydrogen and establishing at least two production hubs with an electrolysis capacity of 5 GW by 2025 [11]. In the initial stages, green hydrogen production in Chile has been envisioned to be directed toward producing e-fuels for transportation in large-scale mining operations and producing ammonia for explosives [11].

From a policy standpoint, Chile has made substantial commitments to renewable energy. Chilean law 20.698, enacted in 2013, mandated that at least 20% of electricity must be generated from non-conventional renewable sources by 2025, a target that has already been achieved [12]. The country aims to further increase this share to 40% by 2030 [13]. Moreover, Chile recently updated its Nationally Determined Contribution (NDC) in 2020, pledging to achieve carbon neutrality by 2050. It is worth noting that Chile is one of the few countries worldwide that has initiated the process of enacting a Framework Law on Climate Change [14].

Over the past decade, Chile has experienced a notable shift in its electricity generation mix towards non-conventional renewable technologies The installed power capacity has been steadily increasing and currently stands at around 14 GW, accounting for over 41% of the country’s electricity generation [15]. Alongside this transition, Chile has incorporated seawater desalination plants into its infrastructure. The country currently produces approximately 6 m³∙s⁻¹ of desalinated water, and ongoing desalination projects in various evaluation stages are expected to increase production by more than 12 m³∙s⁻¹ in the coming years [16,17].

This progress indicates that the necessary technology for autonomous green hydrogen production is already available in Chile, with a significant level of maturity for industrial applications. The existing renewable energy capacity and the development of seawater desalination facilities provide a favorable environment for implementing independent, green hydrogen projects in the country.

From a commercial standpoint, successful implementation of green hydrogen projects relies on supportive government policies and the assurance of competitive production costs compared to conventional technologies that are reliant on fossil fuels. In a 2019 report, the International Energy Agency (IEA) estimated the levelized cost of hydrogen production from natural gas. The cost range was estimated to be USD 0.9–3.2 kg⁻¹ H₂ for processes without emissions mitigation (commonly known as grey hydrogen) and USD 1.5–2.9 kg⁻¹ H₂ for techniques incorporating pollutant emissions capture and storage (commonly known as blue hydrogen) [18]. The report further projected that these costs would remain relatively stable in the coming decades.

These cost considerations highlight the importance of cost competitiveness for green hydrogen production. Green hydrogen must be economically viable compared to conventional hydrogen production methods based on fossil fuel sources. Therefore, efforts to optimize production processes, to utilize renewable energy sources efficiently, and to reduce capital and operational costs are necessary to ensure the commercial viability of green hydrogen projects.

From an off-grid green hydrogen point of view, studies such as that of the International Renewable Energy Agency (IRENA), in 2019, have estimated a cost between USD 3.77 kg⁻¹ H₂ and USD 4.34 kg⁻¹ H₂ using a capacity of 30% in Australia and a cost of USD 2.7 kg⁻¹ H₂ using photovoltaic solar energy (solar PV) and a capacity factor of 50% in Chile [19]. In addition, Yates et al., in 2020, delivered an average of USD 3.71 kg⁻¹ H₂ using solar PV and a capacity factor of 34% [20]. Recent studies, such as the study by Ibagon et al. in 2023, have delivered a cost of USD 3.5 kg⁻¹ H₂ using renewable energy [21]. In another report, Hassan et al., in 2023, reported a cost of USD 3.23–5.39 kg⁻¹ H₂, using solar PV and a capacity factor close to 50% [22].

The existing technical-economic studies in the literature have primarily focused on estimating production costs for green hydrogen rather than conducting comprehensive evaluations that included net cash flows and concepts of project profitability. However, it is crucial to develop economic analyses for green hydrogen production plants to provide updated insights into the production costs of this emerging industry. This is especially important considering the continuous decrease in the price of renewable electricity in countries such as Chile, where rapid development and large-scale implementation of renewable technologies have been witnessed. Additionally, the capital costs of electrolyzer equipment have also decreased due to technological advancements and increased maturity.

The present work addresses this gap by updating, complementing, and discussing new economic approaches for implementing a stand-alone green hydrogen production plant. The primary focus of this study is to incorporate a robust financial analysis from an investor’s perspective, assessing the profitability of a project using economic indicators such as net present value (NPV) and internal rate of return (IRR). By considering these financial metrics, this study aims to provide valuable insights for business decision making and to facilitate a comprehensive evaluation of the economic viability of green hydrogen production plants.

In this study, particular emphasis has been given to implementing autonomous hydrogen production systems, enabling them to be deployed in remote locations without access to the grid. While this approach offers the advantage of independence from the conventional grid, it also introduces limitations regarding a system’s capacity factor. The capacity factor of an autonomous system was assumed to be equivalent to that of the renewable energy plant supplying the system. This means that the capacity factor of the system is dependent on the availability and intermittency of the renewable energy source.

The precision of this study is highly dependent on variations in the costs of the main equipment and the estimated operating conditions of the production process. Another weakness may be related to using the factorial method to estimate the total capital investment used to calculate the economic indicators of profitability.

It is also important to acknowledge that limitations are associated with the selected operating conditions and parameters for the chosen production process. These limitations may affect the accuracy and applicability of the economic evaluation. It is essential to consider these limitations when interpreting the results to ensure they are appropriately addressed and accounted for in the analysis.

By acknowledging and considering these limitations, this study aims to provide an adequate initial technical basis for economically evaluating an autonomous hydrogen production system. It is crucial to continuously refine and update the assumptions and parameters used in the evaluation as more data and insights become available to improve the accuracy and reliability of the economic analysis.

Future work should be directed toward optimizing the selected production process using suitable chemical process simulation software. This information would significantly improve this economic study.

While existing studies in the literature have made substantial contributions to understanding the technical and economic aspects of green hydrogen production, there is a need for comprehensive studies that incorporate the specific context of individual regions and evaluate the unique challenges and opportunities they present. This study aims to address this gap by conducting a pre-feasibility analysis of autonomous green hydrogen production plants in strategic regions of Chile. By integrating a financial analysis and considering the abundant renewable energy resources in the country, this study provides valuable insights into the economic viability and potential of green hydrogen production in Chile.

The selection of Chile as the focus of this study is motivated by its significant potential for solar and wind energy resources. While previous research has explored green hydrogen production in various regions, this study offers a novel contribution by conducting a comprehensive financial analysis specifically tailored to the unique geographical areas of Chile. This study incorporates advanced sizing techniques for an alkaline electrolyzer stack, a seawater desalination system, and renewable energy farms, considering the specific conditions and characteristics of the chosen locations. Additionally, this research employs a rigorous methodology that integrates data from reputable sources, which allows for accurate cost estimation and financial evaluation. By addressing the challenges and opportunities of green hydrogen production in Chile, this study provides valuable insights for policymakers, investors, and stakeholders who interested in developing sustainable hydrogen projects in the region.

This study presents a comprehensive evaluation of the capital expenditures and operating expenses associated with green hydrogen production in Chile, considering specific factors such as the sizing of electrolyzer stacks, renewable energy farm configurations, and market conditions. Additionally, this study incorporates a sensitivity analysis to assess the robustness of the economic evaluation under variations in investment and operational costs. The findings of this study contribute to the existing body of knowledge by providing region-specific insights into the feasibility and economic potential of green hydrogen production, supporting informed decision making, and facilitating the development of green hydrogen projects globally.

2. Materials and Methods

2.1. Production System

The production process and operational parameters proposed in this study were based on recent bibliographical data. In the water electrolysis process, the most common technologies in the commercial stage can be classified into alkaline electrolyzers (AEs) and polymer electrolyte membrane electrolyzers (PEMEs). Among these, on the one hand, PEMEs can be up to 60% more expensive than AEs, which presents a barrier to market penetration for the former [23]. AEs, on the other hand, can utilize less costly materials, offering potential cost reduction advantages. However, both technologies can potentially reduce costs through economies of scale, automation, and increased market demand [23]. This study chose alkaline electrolyzers due to their cost-effectiveness and potential for cost reduction.

In the alkaline electrolysis process [5], feed water is introduced through the cathode, where a reduction process splits the water molecule, forming molecular hydrogen and hydroxide ions, as described in Equation (1). Subsequently, the hydroxide ions obtained in the previous stage are transferred to the anode, which undergoes an oxidation process, forming molecular oxygen, as shown in Equation (2). The overall balance of the system can be represented by Equation (3):

$$4{\mathrm{H}}_2\mathrm{O}+{4\mathrm{e}}^{-}\to {4\mathrm{O}\mathrm{H}}^{-}+2{\mathrm{H}}_2$$

(1)

$${4\mathrm{O}\mathrm{H}}^{-}\to {\mathrm{O}}_2+2{\mathrm{H}}_2\mathrm{O}+{4\mathrm{e}}^{-}$$

(2)

$$2{\mathrm{H}}_2\mathrm{O}\to 2{\mathrm{H}}_2+{\mathrm{O}}_2$$

(3)

The above equations illustrate the electrochemical reactions involved in the alkaline electrolysis process, highlighting the production of molecular hydrogen and oxygen from the splitting of water molecules. In the hydrogen production process (Figure 1), the electrolysis system is central and includes a stack of alkaline electrolyzers. Other process equipment is also incorporated into the system, such as transformers, rectifiers, a water purification unit, a hydrogen processing unit (including separation, purification, compression, and storage components), oxygen separation and output units, and cooling components.

Furthermore, the process considers a supply of desalinated water from a reverse osmosis system and electricity from a renewable energy system. The renewable energy system combines wind and solar photovoltaic farms, providing the necessary electrical energy for electrolysis. Integrating these various components and systems ensures a comprehensive approach to green hydrogen production, incorporating the electrolysis process, water purification, hydrogen processing, oxygen separation, and cooling while relying on a sustainable and renewable source of electricity and a reliable supply of desalinated water.

2.2. Production Process Description (Base Case)

To produce one kiloton (1000 metric tons) per year of hydrogen using the described production process, the following operational parameters and flows are involved:

• Supply of Deionized Water: The process requires deionized water from a reverse osmosis (RO) desalination plant. The flow rate of deionized water needed is 2.0 cubic meters per hour (m³·h⁻¹) when using wind energy and 3.1 m³·h⁻¹ when using solar energy.
• Purification and Storage: The deionized water is purified and directed to a storage tank and a gas scrubber.
• Electrolyzer Stack: The purified water flows into an electrolyzer stack, mixed with a potassium hydroxide (KOH) solution. The stack generates flows of gaseous hydrogen and oxygen. The conversion rate of the water is unity, which means that 100% of the water is converted/decomposed into hydrogen and oxygen.
• Gaseous Hydrogen and Oxygen Flows: The flow rate of gaseous hydrogen produced in an electrolyzer stack is 219.5 kg per hour (kg·h⁻¹) when using wind energy and 345.9 kg·h⁻¹ when using solar energy. The flow rate of gaseous oxygen produced in an electrolyzer stack is 1742.3 kg·h⁻¹ when using wind energy and 2745.5 kg·h⁻¹ when using solar energy.
• Gas/Lye Separators: The gaseous hydrogen and oxygen that flow from an electrolyzer stack pass independently through two gas/lye separators. The oxygen is released into the atmosphere, while the hydrogen continues to the next steps.
• Gas Scrubber, Gasholder, and Gas/Water Separator: The hydrogen flow goes through a gas scrubber, a gasholder, and a gas/water separator for further purification and separation.
• Deoxygenator and Dryer: The hydrogen obtained after the previous steps is injected into a deoxygenator and a dryer to remove any remaining impurities and moisture.
• Compression and Storage: The purified hydrogen is compressed and stored if required. The information does not mention the specific storage capacity and compression parameters.
• High Purity: Throughout the separation, purification, compression, and storage steps, the hydrogen needs to achieve a high purity level close to 99.99%.

These operational parameters and flows are crucial for understanding the hydrogen production process and ensuring the desired purity and quality of the produced hydrogen.

2.3. Economic Analysis

The total capital expenditures (CAPEX) of the hydrogen production process, denoted as Ct, encompass the capital investments in the electrolysis system (ES), the renewable energy system (RS), and the desalination system by reverse osmosis (DS). Similarly, the total operating expenses (OPEX), denoted as Ot, were estimated. To determine the levelized cost of green hydrogen produced, Equation (4) was applied, considering the relevant capital and operational cost contributions [24,25]. This equation allows for assessing the overall cost of hydrogen production, considering the various cost components.

Furthermore, a cash flow analysis was conducted, which considered a 20 year project duration, a weighted average cost of capital (WACC) of 4% per year, straight-line depreciation for the depreciable capital investment, and an income tax rate of 25% [26], by current regulations in Chile. The cash flow was established by adjusting the sale price of the green hydrogen produced to achieve profitability equal to the minimum expected in the study. This resulted in a zero net present value (NPV), as per Equation (4) [27].

Subsequently, an economic sensitivity analysis was performed by varying the investment and operational costs by ±50% to assess the impact on the levelized cost of hydrogen produced and economic indicators such as the internal rate of return (IRR), as calculated using Equation (5):

$$\mathrm{N}\mathrm{P}\mathrm{V}=\sum _{\mathrm{t}=0}^{\mathrm{N}}\frac{{\mathrm{F}}_{\mathrm{t}}}{{\left(1+\mathrm{d}\right)}^{\mathrm{t}}}$$

(4)

$${\mathrm{d}}^{*}=\mathrm{I}\mathrm{R}\mathrm{R}\to \mathrm{N}\mathrm{P}\mathrm{V}=\sum _{\mathrm{t}=0}^{\mathrm{N}}\frac{{\mathrm{F}}_{\mathrm{t}}}{{\left(1+{\mathrm{d}}^{*}\right)}^{\mathrm{t}}}=0$$

(5)

where N represents the project duration (years), t is the annual period (from 0, 1, 2, … to N = 20), d is the weighted average cost of capital, and F_t is the net cash flow in period t (USD).

Table 1. Net investment cash flow structure.

	Item	Sign
1	Income (sales)	(+)
2	OPEX (without depreciation)	(−)
3	Depreciation	(−)
4	Income before tax = (1) − (2) − (3)	(=)
5	Taxes = Tax Rate × (4)	(−)
6	Income after tax = (4) − (5)	(=)
7	Depreciation	(+)
8	CAPEX	(−)
9	Net cash flow = (6) + (7) − (8)	(=)

, below, shows the structure of the net investment cash flow [28,29]. By conducting this analysis, variations in the levelized cost of hydrogen produced and the economic indicators can be determined, providing insights into the project’s sensitivity to changes in investment and operational costs.

In Table 1, the income (1) is reduced by OPEX (without depreciation) (2) and depreciation (3), which gives income before tax (4). Taxes (5) are calculated by multiplying the tax rate (25%) by income before tax (4). Income after tax (6) is income before tax (4) minus taxes (5). Finally, net cash flow (9) is income before tax (6) plus depreciation (7) minus CAPEX (8).

2.3.1. Electrolysis System

The capital investment for the electrolysis system was determined using the percentage of the main equipment cost method, which is commonly used for estimating capital costs in processing plants. The operating expenses included various components such as labor costs (operating labor, direct supervisory, and clerical labor), maintenance and repairs, and other related expenses. The cost of the main equipment, specifically the alkaline electrolyzer, was estimated based on actual local commercial quotations and costs mentioned in the available literature. For this study, the cost of the alkaline electrolyzer was assumed to be USD 270 kW⁻¹. This cost served as the primary basis for calculating the investment costs of the hydrogen production plant [23]. By considering the cost of the main equipment and by utilizing the percentage of the main equipment cost method, the capital investment for the electrolysis system was determined. This allowed for a comprehensive assessment of the investment required to successfully implement the hydrogen production plant.

2.3.2. Renewable Energy System

In 2020, the Chilean National Energy Commission (CNE) provided estimates for the capital expenditures (CAPEX) and operating expenses (OPEX) of solar and wind farms based on ongoing generation projects and studies on different electricity production technologies [30].

For solar farms, the estimated CAPEX ranged from USD 807 to 1228 kW⁻¹, with fixed OPEX between 1% and 2% of the CAPEX value. This means that for every kilowatt (kW) of solar capacity installed, the capital investment would be within that range, and the annual operating expenses would be a percentage of the CAPEX.

For wind farms, the estimated CAPEX ranged from USD 1170 to 1435 kW⁻¹, with fixed OPEX between 1% and 2% of the CAPEX value. Similarly, the value of CAPEX represents the investment required per kilowatt of wind capacity, and the value of OPEX represents the annual operating expenses as a percentage of the CAPEX.

This study considered renewable electricity generation systems for the hydrogen production plants, specifically onshore wind and solar photovoltaic (PV) energy. Two locations in Chile were chosen as examples for installing the production plants (Figure 2). The first location is in the north of the country, in the Atacama Desert (Antofagasta region), which has suitable potential for solar energy generation. The second location is in the south, in Patagonia (Magallanes region), which has suitable potential for wind energy generation.

For the wind energy system in Patagonia, average CAPEX of USD 1266 kW⁻¹ and fixed OPEX of 2% of the CAPEX were assumed. The capacity factor, representing the actual energy output as a percentage of the maximum possible output, was assumed to be approximately 56% for this location [31]. For the solar PV system in the Atacama Desert, average CAPEX of USD 871 kW⁻¹ and fixed OPEX of 2% of the CAPEX were assumed. The capacity factor for this location was estimated to be around 33% [32]. These estimates for CAPEX, OPEX, and capacity factors provided important inputs for the economic analysis of a green hydrogen production plant, and allowed us to conduct a comprehensive evaluation of the costs and potential energy generation from renewable sources in different geographical areas of Chile.

2.3.3. Desalination System

For a water desalination plant using reverse osmosis (RO) technology, the capital expenditures (CAPEX) were estimated to be approximately USD 2500–7400 per cubic meter per day (USD m⁻³ day⁻¹). This represents the investment required to install the desalination plant per unit of daily water production [33]. The fixed operating expenses (OPEX) for the desalination plant were estimated to be USD 0.47 per cubic meter (USD m⁻³) or close to 3% of CAPEX. This includes various costs such as labor, maintenance, and administrative expenses that do not vary with the amount of water produced.

Additionally, the variable OPEX associated with renewable electricity for the desalination plant were estimated to be 4 kilowatt-hours per cubic meter (kWh·m⁻³). This represents the electricity consumption required per cubic meter of water produced, and it is influenced by the renewable energy sources used in the electricity generation system. These cost estimates for CAPEX and OPEX are essential for evaluating the economic viability of incorporating desalination plants into the green hydrogen production process. By considering the costs associated with water desalination, along with the costs of electrolysis and renewable energy systems, a comprehensive analysis could be performed to determine the levelized cost of green hydrogen production and to assess the overall project profitability.

3. Results

Cost Estimation (Base Case)

Based on the provided information, the CAPEX (see

Table 2. Total CAPEX for the base case considering wind energy.

	ITEM	(%)	(USD)
A	TOTAL FIXED-CAPITAL INVESTMENT (A1 + A2)		16,311,907
A1	TOTAL DIRECT PLANT COST		11,532,139
1	Purchased equipment delivered	100%	3,793,467
2	Purchased equipment installation	39%	1,479,452
3	Instrumentation and controls	26%	986,301
4	Piping	31%	1,175,975
5	Electrical systems	10%	379,347
6	Buildings	29%	1,100,105
7	Yard improvements	12%	455,216
8	Services facilities	55%	2,086,407
9	Land (Estimated)	2%	75,869
A2	TOTAL INDIRECT PLANT COST		4,779,768
10	Engineering and supervision	32%	1,213,909
11	Construction expenses	34%	1,289,779
12	Legal expenses	4%	151,739
13	Contractor’s fee	19%	720,759
14	Contingency	37%	1,403,583
B	WORKING CAPITAL (10% of total capital investment)		1,812,434
I	CAPEX ELECTROLYSIS SYSTEM (A + B)		18,124,341
II	CAPEX RENEWABLE ENERGY SYSTEM		17,787,144
III	CAPEX REVERSE OSMOSIS SYSTEM		348,427
	TOTAL CAPEX (I + II + III)		36,259,913

and

Table 3. Total CAPEX for the base case considering solar energy.

	ITEM	(%)	(USD)
A	TOTAL FIXED-CAPITAL INVESTMENT (A1 + A2)		25,703,611
A1	TOTAL DIRECT PLANT COST		18,171,856
1	Purchased equipment delivered	100%	5,977,584
2	Purchased equipment installation	39%	2,331,258
3	Instrumentation and controls	26%	1,554,172
4	Piping	31%	1,853,051
5	Electrical systems	10%	597,758
6	Buildings	29%	1,733,499
7	Yard improvements	12%	717,310
8	Services facilities	55%	3,287,671
9	Land (Estimated)	2%	119,552
A2	TOTAL INDIRECT PLANT COST		7,531,756
10	Engineering and supervision	32%	1,912,827
11	Construction expenses	34%	2,032,379
12	Legal expenses	4%	239,103
13	Contractor’s fee	19%	1,135,741
14	Contingency	37%	2,211,706
B	WORKING CAPITAL (10% of total capital investment)		2,855,957
I	CAPEX ELECTROLYSIS SYSTEM (A + B)		28,559,568
II	CAPEX RENEWABLE ENERGY SYSTEM		19,283,243
III	CAPEX REVERSE OSMOSIS SYSTEM		549,037
	TOTAL CAPEX (I + II + III)		48,391,848

) and OPEX (see

Table 4. Total OPEX for the base case considering wind energy.

	ITEM	(%)	(USD)
C	MANUFACTURING COST (C1 + C2 + C3)		3,531,944
C1	Direct Production Costs		1,439,878
1	Raw Materials (not applicable)	-	-
2	Operating labor (calculated)	-	237,250
3	Direct supervisory and clerical labor (17.5% of 2)	17.5%	41,519
4	Utilities (not applicable)	-	-
5	Maintenance and repairs (6% of fixed-capital investment)	6.0%	978,714
6	Operating supplies (15% of 5)	15.0%	146,807
7	Laboratory charges (15% of 2)	15.0%	35,588
C2	Indirect Production Costs		1,337,576
8	Depreciation (straight line depreciation)	-	815,595
9	Local taxes (2.5% of fixed-capital investment)	2.5%	407,798
10	Insurance (0.7% of fixed-capital investment)	0.7%	114,183
C3	Plant-Overhead Costs (60% of 2 + 3 + 5)	60.0%	754,490
D	GENERAL EXPENSES (11 + 12 + 13)		897,302
11	Administrative costs (15% of 2 + 3 + 5)	15.0%	188,622
12	Distribution and selling costs (11% of IIl)	11.0%	487,217
13	Research and development costs (5% of III)	5.0%	221,462
I	OPEX ELECTROLYSIS SYSTEM (C + D)		4,429,246
II	OPEX RENEWABLE ENERGY SYSTEM		355,743
III	OPEX REVERSE OSMOSIS SYSTEM		10,453
	TOTAL OPEX (I + II + III)		4,795,442

and

Table 5. Total OPEX for the base case considering solar energy.

	ITEM	(%)	(USD)
C	MANUFACTURING COST (C1 + C2 + C3)		5,288,193
C1	Direct Production Costs		2,087,905
1	Raw Materials (not applicable)	-	-
2	Operating labor (calculated)	-	237,250
3	Direct supervisory and clerical labor (17.5% of 2)	17.5%	41,519
4	Utilities (not applicable)	-	-
5	Maintenance and repairs (6% of fixed-capital investment)	6.0%	1,542,217
6	Operating supplies (15% of 5)	15.0%	231,333
7	Laboratory charges (15% of 2)	15.0%	35,588
C2	Indirect Production Costs		2,107,696
8	Depreciation (straight line depreciation)	-	1,285,181
9	Local taxes (2.5% of fixed-capital investment)	2.5%	642,590
10	Insurance (0.7% of fixed-capital investment)	0.7%	179,925
C3	Plant-Overhead Costs (60% of 2 + 3 + 5)	60.0%	1,092,591
D	GENERAL EXPENSES (11 + 12 + 13)		1,332,451
11	Administrative costs (15% of 2 + 3 + 5)	15.0%	273,148
12	Distribution and selling costs (11% of IIl)	11.0%	728,271
13	Research and development costs (5% of III)	5.0%	331,032
I	OPEX ELECTROLYSIS SYSTEM (C + D)		6,620,644
II	OPEX RENEWABLE ENERGY SYSTEM		385,665
III	OPEX REVERSE OSMOSIS SYSTEM		16,471
	TOTAL OPEX (I + II + III)		7,022,780

) for the electrolysis system using wind energy and the electrolysis system using solar energy can be summarized as follows:

Electrolysis System CAPEX:

• Wind Energy: The cost of the main equipment for the wind energy electrolysis system was estimated to be USD 3,793,467, considering that the electrolyzers had a total installed power of 14.05 MW. The cost per kW of electrolyzers was assumed to be USD 270. Therefore, the value of the CAPEX for the wind energy electrolysis system is USD 18,124,341.
• Solar Energy: The cost of the main equipment for the solar energy electrolysis system was estimated to be USD 5,977,584, considering the electrolyzers had a total installed capacity of 22.14 MW. The cost per kW of electrolyzers was assumed to be USD 270. Therefore, the value of the CAPEX for the solar energy electrolysis system is USD 28,559,568.

Total CAPEX: The total CAPEX includes the capital costs of the electrolysis system, the renewable energy system, and the reverse osmosis desalination system. For the wind system, the total CAPEX is USD 36,259,913, and for the solar system, the total CAPEX value is USD 48,391,848.

Electrolysis System OPEX: The OPEX of the electrolysis system includes operating labor costs. It was estimated based on a 20-hour working day, five process stages, 365 operating days per year, and a labor cost of USD 6.5 per working hour.

• Wind Energy: The OPEX for the wind energy electrolysis system are USD 3,751,841.
• Solar Energy: The OPEX for the solar energy electrolysis system are USD 5,553,218.

Total OPEX: The total OPEX include the operating costs of the electrolysis system, the renewable energy system, and the reverse osmosis desalination system. For the wind system, the total OPEX value is USD 4,118,037, and for the solar system, the total OPEX value is USD 5,955,354.

In Table 2 and Table 3, each component is calculated based on a percentage of the purchased equipment.

The economic analysis of green hydrogen production in Chile suggests that the manufacturing cost of green hydrogen is estimated to be USD 3.53 kg⁻¹, while the production cost is USD 4.80 kg⁻¹ when utilizing an autonomous wind energy system in the Chilean Patagonia region. These costs are starting to approach those of fossil fuel hydrogen production with carbon capture and storage.

In terms of a comparative context, it is important to note that green hydrogen production costs vary depending on factors such as location, renewable energy source, the scale of a project, and technological advancements. However, the findings indicate that green hydrogen production costs are becoming increasingly competitive with conventional hydrogen production from fossil fuels. This trend is expected to continue as capital costs of hydrogen production technologies decrease, and carbon taxes potentially lead to further cost reductions.

The results of the economic analysis provide insights into the feasibility and potential economic benefits of green hydrogen production in Chile. They can be valuable references for comparing and complementing other current estimates and methodologies in the field. Additionally, this study contributes to future economic forecasts and the establishment of green hydrogen production plants, considering the anticipated cost reductions and the evolving energy landscape.

It is worth noting that the economic analysis presented in this study is specific to the analyzed scenario and assumptions made. Actual costs and profitability may vary based on market conditions, project-specific factors, and advancements in renewable energy technologies.

4. Discussion

4.1. Wind Energy Base Case

For the base case, the results yielded manufacturing and production costs (calculated as total OPEX obtained) per kilogram of hydrogen of USD 3.53 kg⁻¹ and USD 4.80 kg⁻¹, respectively. In addition, the net investment cash flow was obtained (

Table 6. Net investment cash flow.

	Item	Sign	Year 0	Year 1	-	Year 19	Year 20
1	Income (sales)	(+)		8,081,000	-	8,081,000	8,081,000
2	OPEX (without depreciation)	(−)		4,795,442	-	4,795,442	4,795,442
3	Depreciation	(−)		815,595	-	815,595	815,595
4	Income before tax	(=)		2,469,963	-	2,469,963	2,469,963
5	Tax = Tax Rate × (4)	(−)		617,491	-	617,491	617,491
6	Income after tax	(=)		1,852,472	-	1,852,472	1,852,472
7	Depreciation	(+)		815,595	-	815,595	815,595
8	CAPEX	(−)	36,259,913		-
9	Net cash flow	(=)	−36,259,913	2,668,068	-	2,668,068	2,668,068
10	CCF	(=)	−36,259,913	−33,591,845	-	14,433,376	17,101,444
11	DCF	(=)	−36,259,913	2,565,450	-	1,266,378	1,217,671
12	CDCF	(=)	−36,259,913	−33,694,463	-	−1,217,671	0

CCF, cumulative net cash flow; DCF, discounted net cash flow; CDCF, cumulative discounted net cash flow.

), without considering external financing, at 20 years of project life, with no salvage value and no working capital recovery. However, the selling price of the green hydrogen and oxygen produced (USD 7.84 kg⁻¹ and USD 0.03 kg⁻¹, respectively) was considered.

4.1.1. Economic Evaluation (Twenty-Year Production Investment Project)

Figure 3 shows the CDCF diagrams with different discount rates. The cash flow was adjusted so that, at a WACC of 4%, the calculated net present value (NPV) was zero, thus becoming equal to the internal return rate (IRR), which implied that the minimum selling price of the green hydrogen and oxygen produced for those conditions was USD 7.84 kg⁻¹ and USD 0.03 kg⁻¹, respectively. The graphs are shown below at a WACC of 0 and 4%.

4.1.2. Sensitivity Analysis

Figure 4 above shows the effect on the NPV of the project cash flow at 20 years of production as a base case (using a tax rate of 25% and a WACC of 4% per year) due to variations of ±50% in the cost of the equipment, total CAPEX, and total OPEX. When the cost of equipment changed by −50%, a maximum NPV of USD 27,074,007 was obtained; therefore, it was the most sensitive parameter. When the total OPEX changed by −50%, a maximum NPV of USD 24,439,356 was obtained; therefore, it was the second most sensitive parameter. Finally, when the total CAPEX changed by –50%, a maximum NPV of USD 18,129,956 was obtained; therefore, it was the least sensitive parameter.

4.2. Solar Energy Base Case

The base case yielded manufacturing and production costs per kilogram of hydrogen of USD 5.29 kg⁻¹ and USD 7.02 kg⁻¹, respectively. The investment net cash flow was obtained based on

Table 7. Net investment cash flow.

	Item	Sign	Year 0	Year 1	-	Year 19	Year 20
1	Income (sales)	(+)		11,342,062	-	11,342,062	11,342,062
2	OPEX (without depreciation)	(−)		7,022,780	-	7,022,780	7,022,780
3	Depreciation	(−)		1,285,181	-	1,285,181	1,285,181
4	Income before tax	(=)		3,034,102	-	3,034,102	3,034,102
5	Tax = Tax Rate × (4)	(−)		758,525	-	758,525	758,525
6	Income after tax	(=)		2,275,576	-	2,275,576	2,275,576
7	Depreciation	(+)		1,285,181	-	1,285,181	1,285,181
8	CAPEX	(−)	48,391,848		-
9	Net cash flow	(=)	−48,391,848	3,560,757	-	3,560,757	3,560,757
10	CCF	(=)	−48,391,848	−44,831,091	-	19,262,533	22,823,290
11	DCF	(=)	−48,391,848	3,423,805	-	1,690,086	1,625,083
12	CDCF	(=)	−48,391,848	−44,968,044	-	−1,625,083	0

, without considering external financing, at 20 years of project life, with no salvage value, and no working capital recovery. In addition, the selling price of the green hydrogen and oxygen produced (USD 11.01 kg⁻¹ and USD 0.03 kg⁻¹, respectively) was considered.

4.2.1. Economic Evaluation (Twenty-Year Production Investment Project)

Figure 5 shows the cumulative discounted cash-flow diagrams (CDCF) with different discount rates. The cash flow was adjusted so that, at a WACC of 4%, the calculated net present value (NPV) was zero, thus becoming equal to the internal return rate (IRR), which implied that the minimum selling prices of the hydrogen and green oxygen produced for those conditions were USD 11.10 kg⁻¹ and USD 0.03 kg⁻¹, respectively. The graphs are shown below at a WACC of 0 and 4%.

4.2.2. Sensitivity Analysis

Figure 6 shows the effect on the NPV of the project cash flow at 20 years of production as a base case (using a tax rate of 25% and a WACC of 4% per year) due to variations of ±50% in the cost of the equipment, total CAPEX, and total OPEX. When the cost of equipment changed by –50%, a maximum NPV of USD 42,662,072 was obtained; therefore, it was the most sensitive parameter. When the total OPEX changed by −50%, a maximum NPV of USD 35,790,700 was obtained; therefore, it was the second most sensitive parameter. Finally, when the total CAPEX changed by −50%, a maximum NPV of USD 24,195,924 was obtained; therefore, it was the least sensitive parameter.

It is important to note that the results provided are specific to the given scenario and assumptions made in the analysis. Actual costs and cash flows may vary depending on various factors such as market conditions, project scale, location, and technology advancements.

Table 6 presents the net investment cash flow for the base case scenario of the wind energy-based green hydrogen production project. It outlines various items such as income (sales), operating expenses (OPEX), depreciation, income before tax, tax, income after tax, capital expenditures (CAPEX), net cash flow, cumulative net cash flow (CCF), discounted net cash flow (DCF), and cumulative discounted net cash flow (CDCF) at 20 years of project life. The table shows the cash flows for each year and provides cumulative and discounted values. This information allows for a comprehensive assessment of the financial performance over its lifetime.

Figure 3 depicts the cumulative discounted cash flow (CDCF) diagrams with different discount rates for the wind energy-based green hydrogen production project. It shows the relationship between the discount rate and the net present value (NPV). The cash flows were adjusted to achieve a zero NPV at a weighted average cost of capital (WACC) of 4%. The graph demonstrates how changes in the discount rate impact project profitability, with lower discount rates resulting in higher NPV values. The minimum selling prices of green hydrogen and oxygen produced for these conditions are also mentioned.

Table 7 presents the net investment cash flow for the base case scenario of the solar energy-based green hydrogen production project. It provides similar information as Table 6 except it applies to the solar energy-based project, including income, OPEX, depreciation, tax, CAPEX, net cash flow, CCF, DCF, and CDCF. The table outlines the cash flows at each year, cumulative and discounted values, allowing for a thorough evaluation of the financial viability.

Figure 5 shows the CDCF diagrams with different discount rates for the solar energy-based green hydrogen production project. It illustrates how changes in the discount rate affect the NPV of the project. The cash flows were adjusted to attain a zero NPV at a WACC of 4%. The graph demonstrates the relationship between the discount rate and the project’s profitability, highlighting the minimum selling prices of green hydrogen and oxygen required to achieve the desired return on investment.

The sensitivity analyses, presented in Figure 4 and Figure 6, examine the impacts of varying the cost of equipment, total CAPEX, and total OPEX on the NPV of the projects. These figures illustrate how a ±50% change in these parameters influences the project’s financial performance. The sensitivity analyses help to identify the most sensitive parameters and their impacts on project profitability. For example, in the wind energy-based project, the cost of equipment is identified as the most sensitive parameter, while total CAPEX is the least sensitive parameter. In the solar energy-based project, the cost of equipment also emerges as the most sensitive parameter, followed by total OPEX.

Based on the findings of this study regarding the feasibility of green hydrogen production in Chile, the following policy recommendations can be made specifically for Chile:

Renewable energy incentives The Chilean government should consider implementing renewable energy incentives, such as feed-in tariffs or tax benefits, to attract investments in renewable energy projects. These incentives would help to accelerate the development of solar and wind farms, which are crucial for green hydrogen production.

Research and development funding The Chilean government should allocate funds for research and development in green hydrogen technologies. This could include supporting research institutions, universities, and private companies to drive innovation, improve efficiency, and to reduce costs in electrolyzer stacks, desalination systems, and other relevant components.

Regulatory framework for green hydrogen Chile should establish a clear and supportive regulatory framework for green hydrogen production. This framework should address permits, grid integration, quality standards, and safety regulations. A stable and transparent regulatory environment would provide investors and project developers with confidence.

International collaboration Chile should actively seek international collaboration in the green hydrogen sector. This could involve partnerships with countries with expertise in hydrogen technologies and markets, facilitating knowledge sharing, technology transfer, and joint research initiatives. International collaboration would help Chile to access global markets and benefit from shared experiences.

Public–private partnerships The Chilean government should encourage public–private partnerships to promote green hydrogen projects. By fostering collaboration among the public sector, private companies, and financial institutions, Chile could leverage resources, expertise, and funding to accelerate the deployment of green hydrogen production infrastructure.

Capacity building and workforce development Chile should invest in training programs and educational initiatives to build a skilled workforce for the green hydrogen industry. This could include vocational training, university programs, and specialized courses to equip individuals with the necessary skills and knowledge to develop, operate, and maintain green hydrogen facilities.

Carbon pricing and market mechanisms Implementing carbon pricing mechanisms or market-based instruments could provide additional economic incentives for adopting green hydrogen. By putting a price on carbon emissions, Chile could create a market demand for low-carbon hydrogen and encourage industries to transition towards cleaner energy sources.

5. Conclusions

Based on this economic analysis, it can be concluded that hydrogen generation from renewable energy sources is feasible in Chile. The results of this study suggest that, for the viability of green hydrogen production, it is essential for the capital costs of hydrogen production technologies, including the electrolyzer stack and other plant components, to continue decreasing in the short term. Similarly, a decrease in the investment costs associated with renewable electricity generation, specifically in wind and solar farms, is necessary.

In the base case scenario, the manufacturing cost of green hydrogen was estimated to be USD 3.53 kg⁻¹ as compared with the plant located in Chilean Patagonia utilizing an autonomous wind energy system, in which the production cost was USD 4.80 kg⁻¹. This case was identified as the most favorable in terms of evaluation.

It is important to note that the costs of green hydrogen production are starting to approach those of fossil fuel hydrogen production with carbon capture and storage. Additionally, the potential increase in carbon taxes could lead to further cost reductions in the short term.

Furthermore, it is highlighted that the findings of the study can serve as a valuable reference for comparing and complementing other current estimates and methodologies. They can also contribute to future economic forecasts for establishing green hydrogen production plants.

Given the anticipated cost reductions and the evolving energy landscape, this economic analysis provides insights into the feasibility and potential economic benefits of green hydrogen production in Chile.