Energy Management in an Insular Region with Renewable Energy Sources and Hydrogen: The Case of Graciosa, Azores

Abstract

Insular regions face unique energy management challenges due to physical isolation. Graciosa (Azores) has high renewable energy sources (RES) potential, theoretically enabling a 100% green system. However, RES intermittency combined with the lack of energy storage solutions reduces renewable penetration and raises curtailment. This article studies the technical and economic feasibility of producing green hydrogen from curtailment energy in Graciosa through two distinct case studies. Case Study 1 targets maximum renewable penetration with green hydrogen serving as chemical storage, converted back to electricity via fuel cells during RES shortages. Case Study 2 focuses on maximum profitability, where produced gases are sold to monetize curtailment, without additional electricity production. Levelized Cost of Hydrogen (LCOH) values of €3.06/kgH₂ and €2.68/kgH₂, respectively, and Internal Rate of Return (IRR) values of 3.7% and 17.1% were obtained for Case Studies 1 and 2, with payback periods of 15.2 and 6.1 years. Hence, only Case Study 2 is economically viable, but it does not allow increasing the renewable share in the energy mix. Sensitivity analysis for Case Study 1 shows that overall efficiency and CAPEX are the main factors affecting viability, highlighting the need for technological advances and economies of scale, as well as the importance of public funding to promote projects like this.

1. Introduction

Insular regions are particularly vulnerable to energy management, both because of their physical isolation from continental electricity grids and of the transport costs of importing fossil fuels [1,2]. These are interesting case studies [2,3,4] for the implementation of hybrid energy systems, which combine various energy sources and storage technologies. These can make those regions energy autonomous and up to 100% green. Furthermore, these regions often have a high potential for electricity generation from renewable sources (RES-E), as is the case on Graciosa Island, Azores, Portugal. However, due to the intermittency of these sources, it is necessary to complement them with other technologies. Additionally, installed capacity for RES-E generation may be higher than the electricity consumption at the time of generation, resulting in a high level of curtailment energy. This represents not only an economic loss, but also an opportunity to decarbonize the remaining energy mix through storage.

Managing energy systems in insular regions can contribute to the decarbonization of the energy sector worldwide and serve as an example for the implementation of decentralized management models that promote self-consumption and energy communities. In fact, the contribution of energy management to decarbonization has been studied for several decades [5], since it became evident that fossil fuels generated an unsustainable increase in Greenhouse Gases (GHG). They caused climate change and increasingly violent natural phenomena impacting the biosphere [6]. Decarbonization objectives are also present in several international agreements such as the Paris Agreement.

The gradual electrification of the economy and the increase in energy efficiency are fundamental for the energy transition process. However, they have to be complemented with other technologies, namely renewable fuels, such as green hydrogen (H₂) [7]. H₂ will be useful in sectors difficult to electrify, and for storage, as it is a flexible and versatile energy carrier [8]. Green H₂ differs from other types of H₂ by being produced through electrolysis exclusively powered by RES-E. For example, the IRENA report [7] gives great importance to H₂, predicting that by 2050 14% of all energy consumed will come from this molecule, and that 94% of it will be of green origin.

Green H₂ is a promising option to leverage the energy transition and achieve carbon neutrality, as identified in the “European Green Deal” presented by the European Commission in 2019. The European Union (EU) leads the race for H₂ with 80% of large-scale projects by 2021, as well as the largest number of electrolyzers installed worldwide [9]. According to Hesel et al. [10], the EU aims to build 40 GW of electrolysis capacity by 2030 to produce 333 TWh of H₂. Kakoulaki et al. [8] report that all regions in the EU could be able to meet domestic electricity demand with endogenous renewable resources. It is estimated that by 2050 the production of green H₂ will exceed 106 Mton/year, with domestic demand being 76 Mton/year. This represents a surplus of 30 Mton/year that can be marketed.

H₂ is already used in different sectors, such as refining (41 Mt), heavy industries (53 Mt), and transport (33 kt). For example, H₂ used in industry is mostly consumed in the production of ammonia (60%) and methanol (30%). However, most of the H₂ currently produced comes from non-renewable sources (95%), and it is therefore a major source of GHGs [7]. More recently, the use of this molecule has been explored as a storage mechanism for electricity, fuel for transport, and production of synthetic fuels [11].

There are several challenges related to the use of green H₂, including technical and economic challenges and geopolitical implications [5]. Currently, according to IRENA [7], the biggest obstacle to the development of green H₂ is low competitiveness when compared to non-green H₂. In addition, costs associated with the operation and transport of H₂ are very high, lowering its competitiveness in the absence of governmental support. According to IRENA [7], current investment needs in this technology to achieve the proposed objectives are €1.1 billion per year in production and associated infrastructure.

To achieve the goal set in the Paris Agreement of global temperature increase at 1.5 °C compared to pre-industrial levels by 2050, 94% of H₂ will have to be green. This means it will be about 14% of the global energy mix and represents an exponential increase in this technology that currently has residual values [7]. It will be necessary to improve and innovate the H₂ distribution and storage chain, and to develop more efficient technologies and new infrastructure. With the expected reduction in RES production costs and improvement in electrolysis technologies, producing green H₂ should be competitive against fossil energy sources by 2030.

An important aspect is the articulation of green H₂ production with the generation of RES-E. Some authors point to the need to increase installed capacity of RES-E [12] despite their intermittent generation. Scafidi et al. [13] indicate that the key factor to solve the intermittences of RES is to interconnect them with large-scale storage systems, which can respond to temporal fluctuations in demand. Thus, H₂ can be used to store non-consumed energy.

This work studies this possibility of using curtailment energy for green H₂ production on the Graciosa Island in Azores, Portugal. Previously, Nogueira et al. [14] showed the importance of hybrid energy systems in Graciosa but focused on the evolution of the production costs of these systems. Melo et al. [15] explored socio-economic and environmental advantages of the transition to sustainable hybrid energy systems in Azores. Silva et al. [16] showed the importance of energy storage systems on the Graciosa Island to increase RES-E penetration and the quality of its electrical system. This article complements the studies previously carried out by making a techno-economic analysis (TEA) of the feasibility of using curtailment energy to produce green H₂.

TEA is one of several methods that can be applied to assess the technical and economic feasibility of hydrogen energy systems, being particularly well-suited for early-stage assessments, where the main objective is to select the best technologies, estimate costs, identify key sensitivities, and provide actionable insights for decision-makers. It is important to note that internationally harmonized methodologies in this field are only now beginning to emerge. In fact, the first formal technical specification for environmental techno-economic assessment, ISO/TS 14076:2025 “Environmental management—Environmental techno-economic assessment—Principles, requirements and guidance” [17], was released very recently. As such, its principles and requirements are not yet widely known or adopted within the scientific community. Still, the methodology adopted in this work is consistent with other techno-economic assessment studies reported in the literature for comparable systems, following a commonly established framework similar to that used in life cycle assessment (LCA) [18,19]. In essence, it consists of the following: (i) defining the scope and objectives of the study and identifying the system boundaries; (ii) mapping and comparing the relevant technologies capable of addressing the main objective; (iii) compiling a complete inventory of material and energy inputs and outputs, together with CAPEX and OPEX data; (iv) deriving key performance indicators, such as IRR (Internal Rate of Return), LCOH (Levelized Cost of Hydrogen), and payback period; (v) interpreting the results to determine whether the selected technologies are economically feasible and able to fully or partially meet the study’s objectives; and (vi) optionally, conducting a sensitivity analysis to identify operational parameters and variables with the greatest influence on economic indicators, thereby establishing a hierarchy of parameters to be optimized. On the one hand, we look at whether the island can become 100% green and energy-independent when using green H₂ to replace the diesel generators currently used. Alternatively, we consider the possibility of selling green H₂ and O₂ to achieve higher profitability. The possibility of selling green H₂ by insular regions was explored by Xu et al. [20]. These authors compared two forms of RES export, green H₂ and electricity, and concluded that direct electricity export is generally more efficient. The export of H₂ becomes more interesting in more distant regions, with logistical difficulties.

Thus, this study contributes to the literature mainly by (i) studying and comparing possibilities for curtailment energy use in an insular region; and (ii) exploring options to make an island 100% green and energy-independent. This analysis may be replicated for other regions. Therefore, the main objective of this study is not to introduce new theoretical models of techno-economic analysis or technological innovations, but rather to apply the established methodology of techno-economic assessment to a real case of energy management in an island context. We aim to assess whether the conversion of renewable curtailment energy into H₂ can represent an economically viable solution, based on actual consumption and production data and on CAPEX and OPEX values derived from market surveys. This enables the identification of critical gaps and challenges, paving the way for further research.

Portugal is an interesting case study because it has a privileged position when it comes to RES-E generation. It has also carried out active policies to increase its participation in the energy mix. According to Nuñez-Jumenez & De Blasio [9], Portugal is one of the EU member states with the potential to meet domestic demand and still emerge as an exporter of RES. In addition, the country has channeled government funds to the development of H₂ production technologies.

The structure of the article is as follows: after this introduction, Section 2 discusses some important aspects regarding green hydrogen, such as production and storage; Section 3 exposes the case under study, i.e., energy management in Graciosa, Azores; Section 4 describes the methodology implemented; Section 5 presents the main results of the analysis including the main techno-economic indicators and a sensitivity analysis; finally, Section 6 concludes the paper.

2. Green Hydrogen

2.1. Hydrogen Production

H₂ is the lightest molecule, but its energy potential is three times greater than that of gasoline [21]. Despite being the most abundant gas in the universe, it is laborious to obtain it in its molecular form. There are several technologies for its production, ranging from electrolysis to gasification, pyrolysis, and fermentation, among others. Still, most remain based on non-renewable sources of energy (95%), such as natural gas, coal or nuclear power. The negative environmental impacts that these methods cause, such as high GHG emissions, make non-green H₂ production unsustainable [22].

Table 1. Hydrogen production through non-renewable energy sources.

Non-Renewable Energy Sources	Cost ($/kg H2)	Disadvantages	Advantages
Natural Gas	0.9–3.2	High GHG emissions; High capital costs	Commercially proven, technologically mature, and widely available; More effective and cleaner than coal
Coal	1.2–2.2	High GHG emissions; If carbon capture is not considered, the cost of the process can escalate with high carbon taxes	Efficient process in the conversion of hydrocarbon fuels to H2; Low rate of return; Low water usage
Nuclear Energy	3.2–3.6	Energy-intensive process and release of toxic gases during production; Security issues	Nuclear energy production itself already produces electricity and heat necessary for the production of H2; Low GHG emissions

Source: Own elaboration based on [22,23].

summarizes the costs and main advantages/disadvantages of producing H₂ from non-renewable sources.

Given the decarbonization targets by 2050 [24] and recent technological advances in the RES sector, green H₂ is expected to be the dominant technology. For example, the production of green H₂ through biomass, solar, wind, hydro, geothermal, and other thermochemical and biochemical processes, has evolved significantly in recent years.

Table 2. Hydrogen production through renewable energy sources.

Renewable Energy Sources	Disadvantages	Advantages
Solar	Solar intermittency incompatible with some electrolyzers; Large area occupation required; Critical materials used in panel production	Mature and developed technology; Renewable and clean source
Wind	High capital cost; Wind resource burst incompatible with some electrolyzers; High visual impact on natural landscape; Disruption of some bird migration paths	Mature and developed technology; Renewable and clean source; Low occupation area

Source: Own elaboration based on [23].

presents the main advantages/disadvantages of using wind and solar energy (the most mature and widely used RES) in H₂ generation.

Green H₂ can be produced using RES-E that powers the water electrolysis process, separating the H₂O molecules into H₂ and Oxygen (O₂) with zero carbon emissions [25]. Among the existing technologies to produce green H₂, electrolysis is the most mature and cost-effective on the market. There are other technologies, such as, 100% biological, photo-electrochemical or thermochemical processes. These processes still need market development to be profitable alternatives.

According to Shiva Kumar & Lim [25], there are four main electrolysis technologies for H₂ production: Alkaline Electrolysis; Anion Exchange Membrane (AEM) electrolysis; Proton Exchange Membrane (PEM) electrolysis; and Solid Oxide Electrolysis (SOE). Alkaline electrolysis is currently the most developed process.

Table 3. Comparison of electrolysis technologies.

Characteristics	Technological Maturity	Theoretical Efficiency (%)	Lifespan (Hours)	Minimum Capital Costs 1 MW ($/kW)	Minimum Capital Costs 10 MW ($/kW)	Advantages	Disadvantages
Alkaline water electrolysis	Developed	50 to 78	60,000	250	460 to 930	Marketable on a large scale; low-cost technology—does not require high-purity inlet water; simple and easy-to-operate equipment	Low operation dynamics with little pressure; high start-up time; highly corrosive operating environment; lower hydrogen purity; carbonate formation in the electrodes; high susceptibility to power fluctuations
AEM electrolysis	Recent in the market	57 to 59	30,000	unknown	unknown
PEM electrolysis	Recent in the market for large-scale	50 to 83	50,000 to 100,000	370	650 to 1300	Highly dynamic operation; compact design; higher H2 purity ratio; fast response and high current densities; reduced susceptibility to power fluctuations	Lower durability; acidic environment; high cost of components; high degree of water purity;
SOE	In development	89	20,000	1855	unknown	Operation pressure is high; no noble materials are needed for the catalysts; high efficiency	Low durability; still in the laboratory phase;

Source: Own elaboration based on [25].

presents a comparison of the main characteristics of these technologies.

Jang et al. [26] emphasize that H₂ allows energy stored in chemical form to be transported over long distances at lower costs than those of building a high-voltage electricity transmission station. This transportation can be performed either by appropriate pipelines, ships or other suitable transport method for liquefied or compressed gas form.

Given the intermittency of RES, there is often curtailment, i.e., the underutilization of installed production capacity [27]. This results from the fact that at times of higher production, there is not enough consumption, leading to the loss of part of the available production capacity. If this happens, H₂ will be a good form of storage.

2.2. Green Hydrogen Storage

According to Abdin et al. [28], for green H₂ to become a relevant element in the global energy scenario, it is necessary to establish large-scale distribution channels. Thus, physical storage is considered crucial to respond to fluctuations between production and demand. Gahleitner [29] states that, with increasing production of intermittent and variable RES-E, it is necessary to increase storage capacity. Excess renewable electricity (curtailment) can be stored as H₂ and, when necessary, reconverted to electricity by fuel cells. Ma et al. [30] report that, currently, most H₂ produced is used locally, but as demand increases globally, it will be necessary to develop effective methods of large-scale storage and transport. There are already some available technologies that could be used for this purpose, such as pressurized gaseous H₂, liquid H₂, blend H₂ in natural gas pipelines, and synthetic fuels. However, the high energy consumption required to compress H₂ can increase its storage and transportation costs. Thus, the role of government policies, incentives, and regulation becomes essential to promote economies of scale. Supportive policies such as subsidies and carbon monetization can make green H₂ competitive [30]. Despite all these challenges, the price of green H₂ is expected to fall due to technological advances and the emergence of economies of scale.

Table 4. Hydrogen types of storage.

Technology		Local	Applications	Disadvantages	Advantages
Hydrogen compression gaseous	Physical storage using own containers	Production site	Hydrogen fuel stations, stationary storage at the production site	Energy losses in the process	Fast refueling times and high energy density
	Geological storage	Salt caves, aquifers, depleted oil and gas fields	Dedicated hydrogen storage	Geographical limitations, limited capacity, compromised long-term stability and safety, energy losses in the process	Fast refueling times and high energy density
Liquid hydrogen	Liquid storage	Varied	Aerospace, automotive, energy production	High energy consumption for H2 liquefaction	Large gravimetric energy density, low volumetric density, and ease of transport
Introduction of hydrogen in natural gas pipelines	Power-to-gas	Use of existing natural gas infrastructure	Replacement or addition to natural gas	Existing pipelines can have a greater risk of failure, combustion stability, equipment damage if not adapted	Safer and better cost-effectiveness, greater reduction in greenhouse gas emissions, greater potential for scale-up
Fuels	H2-to-ammonia/H2-to-methanol	Ammonia and methanol production plants	Hydrogen long-distance transport, chemical industry, heavy transport.	High synthesis CAPEX, transport leakage toxicity	Use of current infrastructure, high market potential, high energy density

Source: Own elaboration based on [28,30].

presents a comparison of existing and most used technologies in H₂ storage. Abdin et al. [28] argue that the most economically competitive technology in the current scenario for long-term storage is geological storage, followed by conversion into fuels. This may be the most viable alternative when, due to geographical limitations, geological storage is not possible.

3. The Case of the Graciosa Island, Azores, Portugal

In line with the EU, Portugal has developed a national strategy for hydrogen (EN-H₂), in which a set of objectives to boost an economy based on this molecule was outlined. The following are highlighted: (i) to promote an industrial policy focused on green H₂, in order to decarbonize electricity; (ii) to offer incentives and stability to the energy sector; and (iii) to highlight the crucial role of green H₂ in the decarbonization of various sectors, especially in industry and transport.

Table 5. National strategy for hydrogen.

National Hydrogen Strategy	Injection of Green H2 into Natural Gas Networks (%)	Green H2 in the Energy Consumption of the Industry Sector (%)	Green H2 in the Energy Consumption of the Road Transport Sector (%)	Green H2 in the Energy Consumption of the Domestic Shipping Sector (%)	Green H2 on Final Energy Consumption (%)	Installed Capacity of Electrolyzers (GW)	Hydrogen Refueling Stations
Targets by 2030	10 to 15	2 to 5	1 to 5	3 to 5	1.5 to 2	2 to 2.5	50 to 100
Targets by 2050	75 to 80	20 to 25	20 to 25	20 to 25	15 to 20	10	1000 to 1500

Source: Own elaboration based on [31].

details the targets to be achieved by 2030 and 2050.

To achieve the objectives, several strategies were considered (

Table 6. Portugal’s strategies for the hydrogen value chain.

Portugal’s Strategies for the Hydrogen Value Chain	Description
Power to Gas (P2G)	Green H2 can be injected directly into natural gas networks or by converting hydrogen into synthetic methane
Power to Mobility (P2M)	Green H2 is transported, or produced locally, to provide vehicle fueling stations
Power to Industry (P2I)	Replacing natural gas with green H2 in the industrial sector
Power to Synfuel (P2Fuel)	Replacing fossil fuels with synthetic fuels from renewable sources
Power to Power (P2P)	Excess renewable electricity can be converted into green H2, and later reconverted into electricity

Source: Own elaboration based on [31].

), and several support mechanisms were drawn (

Table 7. Support Mechanisms in Portugal.

Support Mechanisms in Portugal	Description
Differentiated tariff treatment	Total or partial exemption of the payment to access grids
Production support	Production support mechanism covering the difference between the production price of green H2 and the price of natural gas in MIBGAS
System services market share	Opportunity for increased remuneration
Taxation	Green taxation that internalizes environmental impacts and positively discriminates against products/services with high environmental performance, penalizing natural gas and benefiting green H2

Source: Own elaboration based on [31].

).

Graciosa is located in the central group of the Azores archipelago, has approximately 60 km² of area, 4301 inhabitants, and is the least mountainous of the Azorean islands. The low altitude gives the island a temperate oceanic climate [32].

The island has an energy production system that aims to be 100% renewable. It comprises a hybrid production system, with a 4.5 MWp wind farm, a 1 MWp photovoltaic plant, and a 7.5 MVA/2.6 MWh battery plant. The system is coupled to diesel electricity generators that start operating when there is not enough renewable energy production to feed the island’s energy needs.

The hybrid production system is oversized, with a high level of curtailment. However, due to the intermittency of RES, to date there has been a maximum penetration of these sources in the electricity grid of 62%, with the remainder produced by diesel generators. It should be noted that when generators are used, they must continue running for an additional two hours even if renewables are again available to meet grid demand. Due to these constraints and the fact that the system is oversized, there is a considerable amount of renewable energy that is lost. Figure 1 illustrates the hybrid power plant in Graciosa.

The hybrid energy system of Graciosa thus presents two potentially complementary problems. On the one hand, there is a high level of curtailment. On the other hand, due to the intermittency of RES, diesel generators come into operation frequently. It thus becomes evident the need to find a way to store lost energy so that it can be used when there is no RES-E generation. The production of green H₂ by electrolysis fed with curtailment energy seems to be a suitable solution.

4. Methodology

This study performs a technical–economic analysis (TEA) focused on the production of green H₂. Langhorst et al. [33] define TEA as a methodological framework for analyzing the performance of a product, service or process at an economic and technical level, highlighting production costs and market opportunities.

Table 8. Economic indicators used in the analysis.

Indicators	Formula	Variables
Levelized Cost of Energy $\left(€/\mathrm{kWh}\right)$	$\mathrm{L}\mathrm{C}\mathrm{O}\mathrm{E}={\displaystyle \frac{\mathrm{Capex}+{\sum }_{\mathrm{i}=1}^{\mathrm{n}}\frac{{\left(\mathrm{O}\mathrm{p}\mathrm{e}\mathrm{x}+\mathrm{R}\mathrm{E}\mathrm{P}-\mathrm{E}\mathrm{N}\mathrm{V}\right)}_{\mathrm{i}}}{{\left(\frac{1+\mathrm{f}}{1+\mathrm{r}}\right)}^{\mathrm{i}}} }{{\sum }_{\mathrm{i}=1}^{\mathrm{n}}\frac{{\mathrm{E}}_{\mathrm{i}}}{{(1+\mathrm{d})}^{\mathrm{i}}}}}$	Capex: Initial investment costs (€); ${\mathrm{O}\mathrm{p}\mathrm{e}\mathrm{x}}_{\mathrm{i}}$: Operating and maintenance costs (€); ${\mathrm{R}\mathrm{E}\mathrm{P}}_{\mathrm{i}}$: Equipment replacement costs (€); ${\mathrm{E}\mathrm{N}\mathrm{V}}_{\mathrm{i}}$: Environmental costs (€); ${\mathrm{E}}_{\mathrm{i}}$: Energy generated in year i (kWh); $\mathrm{f}$: Inflation rate; $\mathrm{d}$: Degradation rate; $\mathrm{r}$: Annual discount rate; $\mathrm{i}$: Project life (years)
Levelized Cost of Hydrogen $\left(\mathrm{€}/\mathrm{K}\mathrm{g}\right)$	$\mathrm{L}\mathrm{C}\mathrm{O}\mathrm{H}={\displaystyle \frac{{\mathrm{C}}_{\mathrm{e}\mathrm{z}}+{\mathrm{C}}_{\mathrm{e}\mathrm{l}\mathrm{e}\mathrm{c}}}{\sum _{\mathrm{i}=1}^{\mathrm{t}}{{\mathrm{M}}_{\mathrm{h}2}}_{\mathrm{i}}}}$	${\mathrm{C}}_{\mathrm{e}\mathrm{z}}$: Electrolyzer costs (€): ${\mathrm{C}}_{\mathrm{e}\mathrm{l}\mathrm{e}\mathrm{c}}$: Electricity costs (€); ${{\mathrm{M}}_{\mathrm{h}2}}_{\mathrm{i}}$: Hydrogen produced in year i (Kg)
Electrolyzer Costs (€)	${\mathrm{C}}_{\mathrm{e}\mathrm{z}}={\mathrm{C}}_{\mathrm{u},\mathrm{e}}\times {\displaystyle \frac{\sum _{\mathrm{i}=1}^{\mathrm{t}}{{(\mathrm{M}}_{\mathrm{h}2}\times {\mathrm{E}}_{\mathrm{e}})}_{\mathrm{i}}}{\mathrm{t}\times 8760\times \mathrm{S}\mathrm{C}\mathrm{F}\times {\mathrm{n}}_{\mathrm{e},\mathrm{E}\mathrm{Z}}}}$	${\mathrm{C}}_{\mathrm{u},\mathrm{e}}$: CAPEX of electrolyzer (€); ${\mathrm{E}}_{\mathrm{e}}$: Amount of electricity required by the electrolyzer (kWh/Kg); ${\mathrm{n}}_{\mathrm{e},\mathrm{E}\mathrm{Z}}$: Electrolyzer efficiency (%); t: Electrolyzer lifetime (years); 8760: Number of hours in a year; SCF: System capacity factor (%)
Electricity Costs (€)	${\mathrm{C}}_{\mathrm{e}\mathrm{l}\mathrm{e}\mathrm{c}}=\mathrm{L}\mathrm{C}\mathrm{O}\mathrm{E}\times {\displaystyle \frac{\sum _{\mathrm{i}=1}^{\mathrm{t}}{\mathrm{E}}_{\mathrm{i}}}{\mathrm{t}}}$	${\mathrm{E}}_{\mathrm{i}}$: Energy needed each year (kWh); t: Years of activity
Payback Period (years)	$\mathrm{P}\mathrm{B}\mathrm{P}={\displaystyle \frac{\mathrm{C}\mathrm{a}\mathrm{p}\mathrm{e}\mathrm{x}}{{\mathrm{C}\mathrm{I}}_{\mathrm{i}}}}$	${\mathrm{C}\mathrm{I}}_{\mathrm{i}}$: Cash inflow per period (€/year)
Cash Inflow per period (€/year)	${\mathrm{C}\mathrm{I}}_{\mathrm{i}}=\mathrm{H}\mathrm{y}\mathrm{d}\mathrm{r}\mathrm{o}\mathrm{g}\mathrm{e}\mathrm{n}\mathrm{r}\mathrm{e}\mathrm{v}\mathrm{e}\mathrm{n}\mathrm{u}\mathrm{e}-\mathrm{O}\mathrm{p}\mathrm{e}\mathrm{x}-\mathrm{S}\mathrm{t}\mathrm{o}\mathrm{c}\mathrm{k}\mathrm{r}\mathrm{e}\mathrm{p}\mathrm{l}\mathrm{a}\mathrm{c}\mathrm{e}\mathrm{m}\mathrm{e}\mathrm{n}\mathrm{t}\mathrm{c}\mathrm{o}\mathrm{s}\mathrm{t}$
Net Present Value (€)	$\mathrm{N}\mathrm{P}\mathrm{V}={\sum }_{\mathrm{i}=0}^{\mathrm{t}}{\displaystyle \frac{{\mathrm{C}\mathrm{F}}_{\mathrm{i}}}{{\left(1-\mathrm{r}\right)}^{\mathrm{i}}}}$	${\mathrm{C}\mathrm{F}}_{\mathrm{i}}$: Net cash flow in year i (€); r: Annual discount rate
Internal Rate of Return (%)	$\mathrm{I}\mathrm{R}\mathrm{R}={\sum }_{\mathrm{i}=0}^{\mathrm{t}}{\displaystyle \frac{{\mathrm{C}\mathrm{F}}_{\mathrm{t}}}{{(1+\mathrm{r})}^{\mathrm{i}}}}$

Source: Own elaboration.

presents a detailed overview and precise definitions of the formulas used in our technical–economic analysis. These formulas include essential financial and performance metrics, enabling a rigorous evaluation of the economic viability and overall efficiency of the two scenarios assumed. The main economic indicators used were LCOH (Levelized Cost of Hydrogen), LCOE (Levelized Cost of Energy), IRR (Internal Rate of Return), NPV (Net Present Value), payback period, and WACC (Weighted Average Cost of Capital).

4.1. Case Studies

To analyze the most effective energy system to be implemented in this specific case study, two case studies (Figure 2) were considered, with different objectives and profitability, shortly described in

Table 9. Brief description of the two scenarios considered for the Graciosa case study.

Case Study	Description	Main Energy Source	CAPEX and OPEX Included	Main Profit Sources
1	Green H2 production and subsequent electricity conversion through fuel cells, generating carbon credits	Curtailment energy	Electrolyzer; storage and fuel cells	Additional green electricity; carbon credits
2	Sales of produced H2 and O2 without additional electricity generation	Curtailment energy	Electrolyzer; storage	Green H2 and O2 sales

Source: Own elaboration.

. Figure 3 provides a clear schematic of the system boundaries for the different case studies.

In Case Study 1, the island’s production system could become 100% green. In this case, curtailment energy is used to produce H₂, which is then stored and reconverted into electricity through fuel cells. A 2 MW PEM electrolyzer, 2500 kg storage systems for H₂ and O₂, and a 1 MW fuel cell were designed.

For this particular hybrid energy system, PEM electrolysis was selected over alkaline and solid oxide technologies due to its superior suitability for highly intermittent renewable energy integration. Despite alkaline electrolyzers being a mature and cost-effective technology, they are generally limited by slower dynamic response, reduced operational flexibility, and larger footprint. These characteristics make them less suitable for systems dominated by variable solar and wind resources, where rapid load-following capabilities are essential to absorb fluctuating renewable surplus. Alkaline electrolyzers operate optimally at steady-state conditions and show reduced efficiency when subjected to frequent load variations. Their slower ramping capability and longer minimum operating times hinder their ability to capture short bursts of excess renewable power, which are common in systems dominated by wind and solar. Furthermore, alkaline units generally require more complex balance-of-plant components, including liquid electrolyte handling, which can increase maintenance needs in remote island environments. SOECs, on the other hand, exhibit very high efficiency and potential for future large-scale applications. However, they require high-temperature operation, imposing significant technical and economic challenges. Also, they are less robust under frequent start-stop cycles, which are unavoidable in insular grids with strong renewable intermittency. The high capital cost and lower commercial maturity also represent barriers to near-term deployment [34]. Additionally, some authors highlight important operational constraints for SOE electrolyzers, namely mechanically unstable electrodes, cracking, safety concerns of improper sealing, high-temperature maintenance, bulky system design, and they are unsuitable for fluctuating and dynamic situations, undermining their choice for real-case applications [35]. PEM electrolyzers, by contrast, offer fast response times, high current density, compact design, and the ability to operate efficiently under variable power input. These features align well with the operational needs of an island hybrid power system. Thus, PEM technology provides the most reliable and flexible option for enabling H₂ production and reconversion, ultimately supporting higher renewable penetration and reducing diesel dependency. Given that the island system is not covered by the EU-ETS system, due to the non-use of diesel generators, it becomes possible to generate emission credits in the voluntary carbon market.

In Case Study 2, the economic component and the profitability of the solution were prioritized through the sale of the produced gases. This component cannot exist in Case Study 1, since both H₂ and O₂ from electrolysis are consumed in the fuel cell to produce electricity. In this case study, the same electrolysis and storage systems were designed, but without placing a downstream fuel cell. Therefore, since the produced gases are not converted back to electricity, the operation of the diesel generators is maintained, and it is not possible to increase the percentage of RES-E penetration on the island, with the subsequent monetization of carbon credits. However, from a life cycle analysis perspective, the emissions avoided by the production of H₂ and O₂ through more carbon-intensive routes could be quantified, if these gases were able to directly replace those equivalents. As such, in Case Study 2, H₂ and O₂ are sold as commodities, enabling to reduce CAPEX and OPEX related to the fuel cell and achieving higher revenues associated with the liquid gas market, overcoming the limitations of the squeezed profit margins of green electricity. For this case, liquid gas transport from Graciosa to other islands of the archipelago or to continental areas would need to be considered. According to the latest version of the International Energy Agency Global Hydrogen Review report (IEA), H₂ demand remains concentrated in refining and industry applications, where it has been used for decades. Its adoption in new applications where H₂ should play a key role in the clean energy transition, such as heavy industry, long-distance transport and energy storage, accounts for less than 1% of global demand, despite 40% growth compared with 2022 data [36,37]. As a result, demand for low-emission H₂ grew about 10% in 2023. However, in the specific context of this study, it is neither realistic nor relevant to extend the scope of analysis to those end-users in a small island such as Graciosa. First, the scale of the island’s energy system is extremely limited, with a stable grid demand at about 2 MW, with no significant industrial activity that could justify or sustain continuous H₂ consumption. Large-scale industrial applications, such as refining, steel production, or chemicals, simply do not exist. Second, the transport sector on Graciosa is also small in scale and already well-suited to alternative decarbonization pathways, particularly direct electrification. The local vehicle fleet is limited in number, distances are short, and infrastructure constraints are modest. Under such conditions, battery electric mobility represents a far more efficient and practical option than introducing hydrogen-based mobility. Therefore, H₂ and O₂ should be shipped to locations where the aforementioned end-users could sustain a stable demand for these liquid gases.

The case studies propose a green H₂ production system coupled to the hybrid electricity production system, i.e., a 4.5 MWp wind farm, a 1 MWp photovoltaic plant, and a 7.5 MVA/2.6 MWh battery plant. The energy used for H₂ production will only be curtailment that would otherwise be wasted, with no additional cost for its use. Hence, the envisioned H₂ subsystem is designed not as a replacement but as a complementary layer to enhance flexibility and long-term balancing. During periods of surplus generation, particularly when both wind and solar coincide, the batteries can already absorb short-term fluctuations, while the PEM electrolyzer is dispatched to capture sustained excess energy that would otherwise be curtailed. This ensures efficient use of renewable resources while preventing battery oversizing. Conversely, during low renewable availability, the fuel cell is dispatched in coordination with the batteries to provide additional firm capacity, thereby minimizing diesel operation. This coordinated dispatch strategy allows the system to exploit the fast-response capability of batteries for short-term balancing and the long-duration storage potential of hydrogen, significantly improving renewable penetration and overall system resilience.

As mentioned, for the case studies the LCOE, LCOH, return period, Net Present Value and Internal Rate of Return will be calculated. Comparing the results obtained for each scenario will provide a more detailed overview of the most appropriate strategies and their profitability, which will support decision-making.

4.2. Data Collection and Assumptions

The data collected (

Table 10. Data used for the techno-economic analysis.

Process Block	Data	Proposed Value	Source	Description
Existing system	Curtailment energy data	5500.9 MWh/year	Local operator	Sum of the data provided regarding the curtailment generated in photovoltaic and wind power plants
Existing system	Diesel consumed annually by generators	1,300,000 L/year	Literature	[14]
Existing system	Electricity injected into the grid by generators	5551 MWh/year	Calculation	Sum of actual data provided by the operator
Electrolyzer	Amount of hydrogen produced by the electrolyzer	86,773 H2 kg/year	Technology supplier 1	Obtained in a commercial proposal for the case study presented, based on the actual curtailment values
Electrolyzer	Electricity Consumed Electrolyzer	50.50 MWh/H2 ton	Technology supplier 1	Obtained in a commercial proposal for the case study presented, based on the actual curtailment values
Electrolyzer	Electricity required electrolyzer	4380 MWh/year	Calculation	Obtained in a commercial proposal for the case study presented, based on the actual curtailment values
Electrolyzer	Amount of oxygen produced	686,991 kg/year	Calculation	Obtained by the stoichiometric relationship between O2 and H2 in the electrolysis of water
Electrolyzer	CAPEX	€2,891,836	Technology supplier 1	Obtained in a commercial proposal for the case study presented, based on the actual curtailment values
Electrolyzer	H2 Sale Price	€6/kg	Local operator	Based on market procurement
Electrolyzer	O2 Sale Price	€0.25/kg	The literature
Electrolyzer	Water price	€0.5/m3	Technology supplier 1	Obtained in a commercial proposal for the case study presented, based on the actual curtailment values
Electrolyzer	OPEX	€57,836/year	Technology supplier 1	Obtained in a commercial proposal for the case study presented; corresponds to 2% of the total CAPEX of electrolysis
Electrolyzer	Stack replacement every 10 years	€86,755/year	Technology supplier 2	Obtained in a commercial proposal for the case study presented; a value of 30% of the CAPEX is considered for stack replacement every 10 years
Storage and compression	Storage capacity	2500 kg H2	Technology supplier 2	Obtained in commercial proposal for the case study presented; considers a 2.5-ton H2 tank, stored at 100 bar
Storage and compression	Total CAPEX (compression + tanks, for H2 and O2)	€1,430,000	Technology supplier 2	Obtained in a commercial proposal for the case study presented
Fuel Cell	Power required	1 MW	Calculation	Assumption to ensure peak supply considering 50% efficiency
Fuel Cell	CAPEX	€1,500,000	[38]	Assuming a unity of 1 MW
Fuel Cell	OPEX	€44,495/year	[38]
Electricity production system from green H2	Electricity selling price	€300/MWh	Local operator	Real data
Electricity production system through green H2	Round-trip efficiency	33%	Calculation	Combined efficiency of the fuel cell and the electrolyzer, assuming a 100% efficiency in storage because the latter is performed with the remaining curtailment
Carbon credits	Diesel consumption avoided	338,470 L/year	Calculation	Diesel equivalent avoided
Carbon credits	CO2 avoided by diesel combustion	1103.4 CO2 ton eq./year	Calculation	Product of the amount of diesel avoided by its emission factor (supply + combustion based on the report [39]
Carbon credits	National voluntary market	€25/year	Assumed	Average expected value for the voluntary carbon market in Portugal, starting in 2025
BoP	Project lifespan	20 years	Technologist 1	Given by the limiting element, in this case, the electrolyzer, whose value comes directly from the commercial proposal
BoP	Days of operation	365 d	Assumed	For a typical electrolysis system, it is assumed that it can operate in continuous mode every day of the year
Depreciation Rate		5%	According project lifespan
WACC		7%	Assumed	Weighted average cost of financing
Inflation rate		2%	[40]

Source: Own elaboration. CO₂: Carbon dioxide.

) for this study came from different sources. Whenever possible, data were obtained directly from technology suppliers and operators, namely the operators of the Graciosa hybrid park and suppliers of electrolysis, storage, and fuel cell technologies with products available on the market. In a second iteration, when information from these sources was not available, data was obtained from technical documentation, such as technical brochures. Finally, reference values from the literature or published technical studies were used in the absence of information from the sources mentioned above.

Additionally, it should be noted that, for both case studies, an incentive percentage of 25% was assumed, that is, the State’s contribution to the investment cost. Although some projects have higher incentive percentages, we have chosen a conservative value, based on the average incentives received in recent years. Grid consumption and curtailment data were obtained directly from the local system operator, covering all months of a reference year, assuring proper coverage of operational variability and resulting in aggregate inputs that could more easily be used in techno-economic analysis.

For Case Study 1, it is important to note that a fixed fuel cell efficiency of 50% was assumed. This value was chosen in alignment with the key performance indicators (KPIs) defined by the fuel cells and Hydrogen 2 Joint Undertaking (FCH 2 JU) in its Multi-Annual Work Plan (MAWP), which includes efficiency targets consistent with the figure we adopted. While fuel cell efficiency can vary under partial load conditions, several considerations justify the use of a constant average value. Published techno-economic studies and industry reports often rely on fixed efficiency assumptions for system-level modeling, as this simplifies the analysis without significantly affecting long-term results. Moreover, even in partial-load conditions, fuel cells have proven to be quite stable, in different operating scenarios and applications [41,42]. Issues related to durability and stability are being consistently addressed by the literature with technical innovations being expected to overcome such constraints in the short term [43,44]. In addition, the search for market data was deliberately focused on electrolyzers rather than fuel cells, since the electrolyzer technology lies at the core of addressing the island’s main challenge and is the enabling technology that determines both the technical feasibility and the economic competitiveness of this pathway. While fuel cells are an important complementary component for reconversion to electricity, their role in this specific case study is secondary, as the decisive factor for the project’s viability is the cost and performance of electrolyzers. For this reason, reliable CAPEX and OPEX from electrolyzer suppliers’ values were prioritized.

Also, regarding case study 1, the calculation of avoided diesel-related emissions considers steady-state operation as well as start-up and shut-down emissions. Total diesel consumption was obtained from the local operator, which accounts for start-up and shut-down operations. Based on the amount of electricity that the Case Study 1 solution could supply to the system, i.e., 1445.4 MWh, assuming round-trip efficiency of 33% and considering the technical characteristics of the diesel generator (with an efficiency of 43%), this would correspond to an energy input requirement of 3364 MWh, which translates into approximately 338 kL of diesel consumed. Using an emission factor of 3.26 kg CO₂e/L (for B7 commercial diesel, including production, supply, and combustion) the total avoided emissions amount to 1103 tCO₂e.

The data and assumptions mentioned above allowed the calculation of the main inputs used to obtain the relevant financial indicators (

Table 11. Main values used for obtaining relevant financial indicators.

Revenues and Cost Values
		Case Study 1	Case Study 2
Revenues	H2 sales	€0/year	€520,396/year
	O2 sales	€0/year	€176,238/year
	Emission allowances sales	€27,585/year	€0/year
	Electricity sales	€433,620	€0/year
Costs	CAPEX electrolyzer	€2,891,836	€2,891,836
	CAPEX H2 storage	€1,300,000	€1,300,000
	CAPEX O2 storage	€130,000	€130,000
	CAPEX Fuel cell	€1,500,000	€0
	OPEX electrolyzer	€57,836/year	€57,836/year
	OPEX stack replacement	€86,755/year	€86,755/year
	OPEX Fuel cell	€44,495/year	€0/year
	Water costs	€736/year	€736/year

Source: Own elaboration.

).

When operating with intermittent power sources, the impact of degradation on long-term performance on electrolyzers is a common concern. For the selected lifetime of the present techno-economic analysis, i.e., 20 years, this aspect was not modeled explicitly as the current literature and manufacturer specifications indicate that PEM electrolyzers are capable of operating for more than 50,000 to 100,000 h, as indicated on Table 3. This corresponds well to 20 years of operation in typical renewable-based hybrid systems. In this context, no significant loss of efficiency is anticipated during the system lifetime. Instead, the expected operational costs related to aging and performance decline are captured through the annual maintenance costs that were already included in the model, as detailed in Table 11. Similarly, for the fuel cells, the analysis assumed commercially available units with lifetimes compatible with the case study timespan, and any necessary stack replacements or performance-related interventions are also implicitly reflected in the annual maintenance cost assumptions. This aspect was already examined in previous works which have demonstrated that the island mode operation of PEM water electrolyzers is possible and that negative effects related to regular system shut-downs/start-ups can be easily mitigated [45]. Furthermore, this reinforces the choice of PEM electrolyzers over other options.

For calculating the revenues occurring from H₂ and O₂ sales, selling prices of 6.0 €/kg and 0.25 €/kg were assumed, following a conservative approach, in line with recent studies and market trends [46]. For green H₂, despite several studies that reference LCOH values in the range of 8.0–9.0 €/kg, it would realistically be difficult to find buyers willing to pay the additional green premium over the current price of 1.5–2.0 €/kg for gray H₂ from SMR [47]. For the particular case of oxygen, in this case a co-product of green hydrogen production, market studies for medical-grade oxygen reference prices ranging from 0.11 to 0.45 €/kg [48].

Logistic costs are a critical aspect when evaluating the feasibility of renewable gases production and commercialization, particularly in the context of island systems. The presented values in Table 11 for H₂ and O₂ revenues are based on H₂ and O₂ selling prices that implicitly comprise logistics and transport costs. In practice, these selling prices can be interpreted as net prices, which already reflect both the potential benefits and the associated expenses, including transportation and external sales logistics. In the specific context of island environments, these challenges, such as limited transport infrastructure and additional handling requirements, are indeed reflected in the higher H₂ prices typically reported in the literature. A study by Collis and Schomäcker [49] shows that there are two main ways of exporting pure H₂ from an island to continental areas, namely pipeline transport and ship transport. Transport by pipeline is a more predictable route, given that pipeline transport is not affected by weather and is highly reliable. On the other hand, liquidizing H₂ is necessary for shipboard transportation, where large-capacity liquid H₂ storage tanks are loaded into the ship, being more suited for long-distance transportation than pipeline [49]. Despite the authors concluding that exporting H₂ does not provide reasonable economic benefits for islands with integrated energy systems, it is important to highlight the singularity of the case under study, due to the high available curtailment, which allows the hydrogen production cost to be significantly lowered. In another study by Hassan and El-Amary [50], the authors highlight that the cost of transporting H₂, whether via pipelines or shipping, when combined with WACC, heavily impacts the overall cost of delivering H₂ to end-users [50]. The authors concluded that for a production cost of $ 4.5/kg, transportation costs in Egypt would account for a 16–38% of total H₂ costs, resulting in a LCOH of $ 8.7–9.3/kg. In our case, assuming a 30% representativeness for transport costs results in a production cost of ca. 4€/kg, which perfectly fits the techno-economic analysis model. It is also worth noting that, in this case, several singular transportation conditions could be explored, given the proximity of Gaciosa to other islands in the archipelago, particularly São Miguel, where there could eventually be a demand for both H₂ and O₂. Alternatively, H₂ and O₂ could be used on-site to produce other liquid fuels that are easier to transport, namely ammonia or methanol. However, this would fall outside the boundaries of the present system, being therefore excluded from the present analysis.

Another important aspect is related to the possibility of trading carbon credits in Case Study 1. As previously mentioned, the existing system on the island does not fall under the scope of the EU ETS, as it does not meet the requirements of Directive 2003/87/EC of the European Parliament and of the Council that established a scheme for GHG emission allowance trading within the community. Nevertheless, the system currently emits 1103.4 tCO₂e per year, associated with the operation of diesel generators. Therefore, in Case Study 1, by replacing the diesel generators with green H₂, which in turn enables additional electricity production through fuel cells to support grid operation, these annual emissions can be avoided. This corresponds to mitigation carbon credits, since the project does not involve carbon sequestration but rather the prevention of emissions. Being excluded from the EU ETS, the project becomes eligible for voluntary carbon markets which, in Portugal, is regulated by Decree-Law No. 4/2024 of 5 January, which establishes and regulates the functioning of the Portuguese Voluntary Carbon Market. Based on national data and comparative studies with other voluntary markets, it is expected that mitigation carbon credits will generally be traded at around € 25 per ton of CO₂e.

For the calculation of the LCOH, and considering that only curtailment energy would be used, hidden costs related to grid dispatching and reserve capacity were not included, as they were considered negligible and would not change the qualitative conclusions of this study. This assumption agrees with other studies on similar cases [51,52]. First, regarding system scale and stability, since there is a relatively stable base demand (ca. 2 MW) and a hybrid renewable and storage setup, the marginal costs for dispatching and reserves would contribute little to overall H₂ cost. The electrolyzer’s operation occurs largely during surplus renewable periods, when the grid has spare capacity, minimizing the need for expensive reserve or dispatch adjustments. Second, regarding maintenance, ramping, and variable operations, associated costs were already included in annual OPEX and maintenance, which absorb small inefficiencies and operational balancing costs.

Finally, with regard to electricity price evolution and potential cost reductions in technologies, these aspects were not considered in the present analysis, as current values of electricity prices, CAPEX, and OPEX were considered, derived from market quotations and published references. While incorporating projections for future price trends could potentially improve the economic outlook, such forecasts are inherently uncertain and highly dependent on policy, market dynamics, and regional circumstances.

5. Results

5.1. Initial Scenarios

Afterwards, we calculate the relevant financial indicators for both case studies, presented below in

Table 12. Financial indicators for the two scenarios.

Techno-Economic Indicators	Case Study 1	Case Study 2
IRR	3.7%	17.1%
Payback time	15.2 years	6.1 years
LCOH	€3.06/kg	€2.68/kg
NPV	€−1,067,411	€2,740,564

Source: Own elaboration.

.

Results show that, in Case Study 1, with higher CAPEX and OPEX, the IRR value is 3.7%, well below the WACC. Although positive, this IRR reflects low profitability, with a very high payback period (15.2 years). This implies that the initial investment will not be recovered in a reasonable period. However, the LCOH in this case presents a competitive value, which can be explained by the fact that the LCOE in the production of H₂ is zero, since only curtailment energy is used. The NPV is negative, which can result in a loss of value for investors. Thus, this case study does not present competitiveness and economic viability. Subsequently, a sensitivity analysis was carried out to understand which factors could improve the economic viability of this case.

Case Study 2, where there is no downstream electricity production, allowed obtaining values closer to the desired profitability. The IRR of 17.1% outperforms the WACC by 10.1 percentage points, showing that the project can be financially viable. The payback period is 6.1 years. The LCOH drops to €2.68/kg, a very competitive market value, even when compared with blue H₂ (with carbon capture). The feasibility of this case study shows that curtailment energy can be harnessed, although it does not directly contribute to making Graciosa Island 100% green (as it would happen in Case Study 1).

5.2. Sensitivity Analysis

To analyze more deeply the decarbonization potential for the electricity sector in Graciosa Island, a sensitivity analysis was performed to assess which parameters could have a greater impact on the project’s IRR. We focused on Case Study 1 since, in addition to being the one with the least economic viability, it would be the one that would allow the main environmental objectives to be achieved and directly answer the initial objective. The selected parameters were value of carbon credits, percentage of the incentive, round-trip efficiency, electrolysis CAPEX, electricity sale price, and inflation rate. Figure 4 summarizes the results, representing the variation in the IRR as a function of the variation in the different parameters.

Figure 4 shows that the factors that most positively influence the IRR are the sale price of electricity, the round-trip efficiency of the technologies, and the CAPEX of electrolysis.

A closer look at two of the most relevant factors (Figure 5) shows that both the combined round-trip efficiency and the incentive percentage can increase the IRR value very quickly. In particular, the percentage of supported CAPEX has an exponential effect.

With the technological improvements foreseen for the technologies considered, as well as a greater weight of government incentives for this type of project, they may become financially viable.

5.3. Simulation of Possible Scenarios

To complement the analysis, eight alternative sub-scenarios (1-A to 1-H) related to Case Study 1 (H₂ production with electricity production downstream) were also considered (

Table 13. Scenario simulations.

	Scenarios
Parameters	Case Study 1	1-A	1-B	1-C	1-D	1-E	1-F	1-G	1-H
Carbon permits	€25.00	€100.00	€25.00	€25.00	€25.00	€25.00	€25.00	€62.50	€100.00
Funding rate	25%	25%	40%	25%	25%	25%	25%	33%	40%
Round-trip efficiency	33%	33%	33%	45%	33%	33%	33%	39%	45%
CAPEX Electrolysis	€2.89 M	€2.89 M	€2.89 M	€2.89 M	€2 M	€2.89 M	€2.89 M	€2.45 M	€2 M
Electricity selling price	€300.00	€300.00	€300.00	€300.00	€300.00	€250.00	€300.00	€275.00	€300.00
Inflation rate	2%	2%	2%	2%	2%	2%	4%	3%	4%
IRR	3.7%	6.1%	6.1%	8.0%	6.6%	1.2%	5.3%	9.8%	19.8%
NPV	€−1.07 M	€−2.93 k	€−2.51 k	€3.57 k	€−1.18 k	€−1.75 M	€−5.97 k	€8.85 k	€4.05 M
Payback time (years)	15.2	13.9	13.9	11.5	12.3	19.4	14.6	10.6	6.6

Source: Own elaboration.

) based on the parameters that most influence the profitability of the project. For each sub-scenario, the value of the corresponding IRR, NPV, and payback time are also presented. Each additional scenario can thus be compared with the values implemented in Case Study 1.

From Scenarios 1-A to 1-E, only one of the parameters under study was changed to assess its relative influence on the project’s techno-economic indicators. It is expected that there will be a favorable evolution of the project for all indicators, except for the sale price of electricity, for which a reduction is expected in the coming years. Thus, in Scenario 1-A, the value of carbon credits on the market goes from €25 to €100 per ton of avoided CO₂; in Scenario 1-B, the percentage of incentive on CAPEX is changed to 40%; in Scenario 1-C, the combined efficiency of the process increases to 45%; in Scenario 1-D, the CAPEX of electrolysis decreases to €2 M; in Scenario 1-E, the selling price of electricity decreases to €250/MWh, following the expected market trend; and, in Scenario 1-F, the inflation rate rises to 4%. Finally, in Scenarios 1-G and 1-H, the combined effect of variations in several parameters was simulated. In Scenario 1-G, a favorable variation for the project corresponding to 50% of the simulated values in Scenarios 1-A to 1-F was assumed. In turn, in Scenario 1-H, the most favorable scenario for the project was simulated, i.e., a combination of all simulated values in Scenarios 1-A to 1-F.

Analyzing Table 12, the following is concluded: i. changing only the value of the incentive, it would need to be higher than 40% for the IRR to be attractive, which is something unreasonable; ii. the round-trip efficiency of the technologies significantly affects the IRR, and an increase to 45% (a relative increase of 36%), which is expected soon, would result in an IRR increase by 4.3 percentage points; iii. the CAPEX of the electrolyzer significantly affects the IRR and, in the coming years—with the maturation of the technologies, together with the increase in demand and supply—assuming a reduction of 45% will become plausible, which would increase the IRR by 3 percentage points; iv. with the expected trend of reducing the final value of electricity for consumers, it is imperative that there is a favorable combined variation in the remaining parameters so that the IRR becomes attractive; in other words, to simultaneously buy greener electricity at a more affordable price, it is necessary that there are government incentives, increasing appreciation of carbon allowances in the market and CAPEX reduction in the core technologies; v. verifying a combined variation within the expected medium-term trend of the parameters that most impact the profitability of the project, it is possible that very favorable technical–economic indicators will be obtained to support the implementation of the technological route of this case study.

Non-technical aspects, such as H₂ safety and social acceptance were not included in the present study, as they fall out of the scope of techno-economic analysis. Nonetheless, H₂ safety considerations, such as handling, storage, and transportation risks, as well as the public’s perception and acceptance of H₂ projects, represent essential dimensions for any real implementation. These topics typically fall within the scope of broader cost–benefit or socio-technical analyses, which integrate technical results with environmental, regulatory, and social dimensions. Nevertheless, studies addressing these non-technical aspects have shown that the social acceptance of green H₂ projects has been increasing, largely driven by growing awareness of their environmental benefits and by concerns over dependence on imported fossil fuels [53,54]. In particular, the geopolitical risks associated with fossil energy supply have reinforced public support for locally produced renewable H₂, which is increasingly perceived as both a sustainable and a strategically secure energy option. Therefore, the prevailing trend suggests that a study of this nature, if applied to the present work, would likely support the deployment of the proposed system.

6. Conclusions

This paper evaluated the technical and economic feasibility of using curtailment energy on the Graciosa Island, Azores, to produce green hydrogen (H₂). The analysis focuses on two case studies that differ in the source of income, i.e., production and sale of additional electricity vs. direct sale of the produced gases. A detailed analysis is also carried out on the parameters of the hybrid energy system with greater influence on the relevant economic indicators for decision-making.

In the first case study, green H₂ would be used to produce additional electricity from a fuel cell, aiming to replace the diesel generator, thus making the island’s electricity consumption 100% green. This would be the ideal case. However, it would result in an IRR of 3.7%, lower than the WACC, a negative NPV, and a payback time of 15.2 years, which, considering the current parameters, is not economically viable.

In the alternative case study, curtailment energy would be used for green H₂ production, which would then be sold as a commodity, along with O₂. This case study does not allow the replacement of diesel generators but allows for the profitability of the curtailment energy. Results show that this option is economically viable, resulting in an IRR of 17.1%, an NPV of €2.7 million and a payback time of 6.1 years. This economic viability assumes that the off taking of the produced gases is ensured, which, in an insular system, naturally has associated limitations. Nevertheless, this case shows that in energy systems where there is a significant amount of curtailment from renewable energy, it is financially feasible to implement a green H₂ production system. This takes advantage of the once wasted energy, resulting in an extremely competitive LCOH.

Finally, the sensitivity analysis shows that the parameters with greater influence in the economic profitability of the project in Scenario 1 are the final sale price of electricity, the round-trip efficiency of the system, and the CAPEX. Thus, we show, for example, that public funding is crucial for assuring economic competitiveness of these projects. Additionally, as the high cost of investment in technologies is a limiting factor, with economies of scale, through increased supply and technological maturity, the project would become more viable.

Two main conclusions emerge. First, technical progress is still needed to lower the costs associated with the production and use of H₂ to generate electricity in island systems. Second, government support in the form of grants is key, particularly in the early stages of the project. This support is also an indirect way of contributing to technological progress. This phenomenon has occurred in the past for many technologies, including, for example, photovoltaics.

In the future, there is a need to continue technical and economic research into the technologies involved in the value chain, especially regarding the energy efficiency of both electrolyzers and fuel cells, hydrogen storage, and transport. It will be important to investigate how national and international tax incentives and subsidies can accelerate the creation of economies of scale to produce green H₂ and how the market will respond to the transaction of carbon allowances generated by these projects.