Green methanol production from photovoltaics in Europe

Green methanol production from photovoltaics in Europe D.A. Rodriguez-Pastor a,* , V.M. Soltero b , R. Chacartegui a,c a University of Seville, Escuela T´ ecnica Superior de Ingenieros, Camino de los Descubrimientos s/n, 41092, Seville, Spain b University of Seville, Escuela Polit´ ecnica Superior, 41011, Seville, Spain c University of Seville, Laboratory of Engineering for Energy and Environmental Sustainability, Seville, 41092, Spain ABSTRACT The European Union’s objective for non-biological fuels is 10 Mt by 2030. The massive implementation of green hydrogen facilities predicts cost overruns for adapting the existing industry towards H 2 -ready, making the development of alternative e-fuels imperative. Based on European GIS data, this work analyses the potential implementation of green methanol from CO 2 capture in existing industries. The study is based on hydrogen fraction limits on existing natural gas grids, with maximum volumetric blends of 5–20 % H 2 . The analysis of boundary conditions based on water resources and proximity to the networks yields 3016 potential municipalities for implementing green methanol valleys. The analysis projects a potential of ~30 Mton H 2 /year in PV to produce 5 Mton of methanol, with a carbon capture capacity above 7 Mton CO 2 /year. The economic analysis of different scenarios shows that in 2030, the levelized cost of methanol could reach values around ~450 € /ton MeOH, with IRR>15 %, showing the viability of the approach. 1. Introduction Energy transition involves reducing the dependence on fossil fuels, which are non-renewable and lead to global warming [1,2]. Europe has developed the REPowerEU plan to respond to the disruption of the energy market caused by the Ukrainian war in 2022 and Russian coercion [3]. It has established a target of 10 million tons of fuel of non-biological origin by 2030 [4]. This is driven by project funding and other strategies that result in increased production costs per equivalent ton of CO 2 produced by the Emission Trading Scheme (ETS) [5]. Massive implementation of green hydrogen production in the European industrial fleet is expected to require the adaptation of a large part of thermal processes, with an estimated cost overrun of 60 % for stakeholders [6]. From the reduction of GHG emissions generated by conventional processes, green hydrogen projects could reach competitive production prices by 2035 [7,8]. The transformation of hydrogen to other molecules, presented as “green fuels”, is already a new paradigm for the energy transition [9,10]. Synthesis of green hydrogen and carbon monoxide/dioxide, as well as nitrogen, is the main process to produce highly useable fuels such as green methanol or green ammonia [11]. The transport and use of these green fuels pose fewer limitations than the direct use of hydrogen [12], which is a very important asset for the fertiliser and cosmetic industries and for naval transport [13,14]. Methanol is a promising candidate for green fuel due to its high volumetric energy density (15.6 MJ/L CH 3 OH >0.0107 MJ/L H 2 ) and its liquid nature under ambient conditions [15]. It is produced worldwide through CO and CO 2 hydrogenation processes, which allows it to take advantage of CO 2 capture systems in existing industries for its production [16]. Although green hydrogen production in the EU is expected to increase, no studies have been conducted on the potential of green methanol facilities. Neumann et al. [17] examined the potential role of hydrogen grid connection in Europe, reducing costs by 26 bn € /a, based on the open PyPSA-Eur-Sec model [18]. Kakoulaki et al. [19] studied 109 European regions for the implementation of hydrogen projects, where 84 of them had >50 % excess energy with abundant renewable sources. The work of Fasihi et al. [20] obtained values of 370–450 € /ton of green NH 3 on all continents by 2030. In the case of the green methanol potential, the work of Bazaluk et al. [21] concluded that in China, there is a theoretical potential of 4.35–29.95 million tons. The work proposed by the authors studies the potential for e-methanol in the EU zone area from solar PV, based on a Geographical Information System (GIS) study of future facilities based on water resource availability, solar resource, the capacity of the nearby land for solar photovoltaic plants, as well as the nodes of the nearby natural gas grid for the injection of surplus hydrogen, and finally the proximity to energy-intensive industrial plants for the synthesis of CO 2 and green H 2 to green methanol. This article is part of a special issue entitled: SI ECOS2024 published in Renewable Energy. * Corresponding author. E-mail address: [email protected] (D.A. Rodriguez-Pastor). Contents lists available at ScienceDirect Renewable Energy journal homepage: www.elsevier.com/locate/renene https://doi.org/10.1016/j.renene.2025.123751 Received 25 October 2024; Received in revised form 2 April 2025; Accepted 11 June 2025 Renewable Energy 254 (2025) 123751 Available online 12 June 2025 0960-1481/© 2025 The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY-NC license ( http://creativecommons.org/licenses/bync/4.0/ ). 2. Methodology According to Eurostat, industrial fuel consumption is responsible for 2.4 Gt of carbon dioxide emissions. CO 2 capture can be performed using amine (MEA) systems, direct air capture, and Selexol, among others [22]. Natural gas consumption in industry and power plants is estimated to be shared in the grid, with a mixture of natural gas and hydrogen, and it will be very difficult to completely adapt the current fleet to H 2 -ready [23]. In the first phase of the energy transition, it is estimated that CO 2 emissions will not be completely reduced, indicating that there will be a potential for capture and utilization [24]. The proposed solution, based on the methanol CO 2 cycle, is shown in Fig. 1. One of the boundary conditions is given by the water resources to produce green hydrogen by electrolysis, which requires at least 0.3 m 3 /h raw water per kg of H 2 [25]. The proposed methodology considers water from wastewater treatment plants and electricity from a nearby solar photovoltaic installation as inputs, and methanol as an output for sale. The aim is to promote hydrogen valleys for self-consumption in the vicinity of industrial plants, which will have MEA capture systems, as detailed in Section 2.2. Proximity to the natural gas network will be simple in areas of high industrial consumption, but it will pose a cost overrun for hydrogen transport in facilities that have a nearby injection point but a distant industry. Data management is critical to assessing the geographic potential of the proposed technology. Natural gas infrastructure is provided by the work of Diettrich et al. [26], the CO 2 estimation produced by the European OpenGHGMap project [27], the existing wastewater treatment plants, as well as the administrative limits by the European Commission, and the solar PV production resource (kWh/kWp) from SolarGIS™ maps. From the creation of land buffers around the injection points planned for this purpose, a series of environmentally feasible plots will be selected that do not compromise other land uses, implementing the Copernicus database, “CORINE Land Cover.” The details of the methodology are explained in the following sections. 2.1. Europe natural gas infrastructure According to the work of Pluta et al. [28] from the DLR, the IGGIELGNC-1 model has a total natural gas pipeline length of 237,000 km, and the details of the facilities are shown in Fig. 2. This work focused on the industrial consumption of natural gas, as detailed in Fig. 2B, due to the better integration of the methanol synthesis plant into the industrial environment. Having natural gas compressors nearby will be of interest (Fig. 2D), as it will allow the construction of a nearby pipeline to inject excess hydrogen produced in the hydrolysis plant. Fig. 2 shows the large potential for hydrogen blending in the current grid, considering 5–20 % blends. Specifically, 183 natural gas compressors accumulate a daily maximum of 6800 M m 3 of NG. Compression of natural gas to 273 power plants and >75 large natural gas consumers present an opportunity to implement the synthesis of methanol from CO 2 capture. Fig. 3 shows the boundary conditions required for the implementation of the proposed system. Fig. 3B, corresponding to OpenGHGMap data [27], indicates the areas of Europe with the highest concentration of CO 2 emissions in Europe. This analysis is consistent with Fig. 3A and C, which show that these are areas, especially in southern Spain, where there is a large average annual solar resource and a water resource (23965 TSW) for the generation of green hydrogen. The following distances were established around the installation boundary conditions, as listed in Table 1. The assumptions were made based on the evaluation of existing plants and according to the protected areas of the Natura2000 layers. The authors assume that the proposed distance values can be reduced, which can improve the economic profitability of installations. 2.2. CO 2 capture There are two main methods to produce methanol from CO 2 : direct hydrogenation of CO 2 to methanol as a one-step conversion and the reverse water gas shift reaction (RWGS), which converts CO 2 into CO in the first step and its hydrogenation to produce methanol as a two-step conversion. In this work, the conversion of CO 2 in a single step was used. Considering previous studies in the literature, capture by chemical absorption of exhaust gases with MEA (monoethanolamine) solvent at a concentration of 30 % has been considered. Fig. 4 shows the CO 2 absorption process using MEA with solvent regeneration via heating. Before the capture process, flue gases must be treated and compressed to compensate for the pressure decrease in the absorption column. The low-CO 2 solvent is then added at the top of the absorption column (stream 6), while it is added at the bottom. MEA reacts with CO 2 through the column. After being preheated by the regenerated solvent exiting the regeneration column, the CO 2 -rich solvent from the bottom of the absorption column is delivered to the regeneration column, where there is a condenser and a reboiler. To reverse the reaction between the amine and CO 2 , the reboiler recovers energy from the condensation of low-pressure steam (LP). Condensed water vapour from the regeneration column’s gas flow is then reinjected into the column. After preheating the CO 2 -rich solvent, the regenerated solvent is injected back into the absorption column. Given the focus of this work, a CO 2 capture Fig. 1. Conceptual scheme of the proposed methanol (MeOH) cycle. Produced e-methanol at the output can be sold, and water and electricity are required as inputs in the electrolysis process. D.A. Rodriguez-Pastor et al. Renewable Energy 254 (2025) 123751 2 ratio of 85 % was considered, assuming a consumption of 44 kWh el /ton CO 2 , with the validation of a wide observation in the literature [29,30]. 2.3. Hydrogen production Three primary methods for water electrolysis range from solid oxide electrolyzers, proton exchange membranes (PEM), and alkaline electrolysis [31]. During proton-exchange membrane electrolysis, protons move through a membrane. At the anode, protons are created together with oxygen. At the cathode, protons cross the membrane and combine to form hydrogen. Noble metals are needed for electrodes due to corrosive acidic conditions, which increases the capital cost of the PEM Fig. 2. Natural gas infrastructure for the EU zone in 2022. Figure A details the natural gas network and the maximum daily capacity in M m 3 /day, Figure B the industrial consumption, Figure C the power plants consuming NG and Figure D the NG compressors and their maximum daily capacity in M m 3 /day. Fig. 3. Resource map for green methanol deployment in Europe. Figure A indicates the number of average daily solar hours obtained from SolarGIS. Figure B indicates the total CO 2 emission potential (ton/year) in different regions of Europe according to Ref. [27]. Figure C shows Europe’s water resources in 2022 according to the European Commission. (For interpretation of the references to colour in this figure legend, the reader is referred to the Web version of this article.) Table 1 Buffer distances for GIS analysis for the evaluation of green methanol facilities. Installation Buffer Natural Gas Node 20 km Natural Gas Consumer 10 km Water Treatment Station 10 km Urban Zones 10 km CO 2 Emissions (ton/year) >140,000 D.A. Rodriguez-Pastor et al. Renewable Energy 254 (2025) 123751 3 electrolyzer [32]. PEM electrolysis was used in this work and its conditions in all integrated cases are shown in Table 2. Alkaline electrolysis electrodes are submerged in a liquid electrolyte and kept apart by a diaphragm. The electrolyte is typically a KOH solution, and as OHions move through the diaphragm, they release water and oxygen at the anode and hydrogen at the cathode. Because thermal activation occurs at temperatures between 700 and 900 ◦C, these electrolyzers should be more efficient than PEM and alkaline electrolyzers if they have good heat integration. 2.4. Methanol synthesis The two-step method for synthesizing methanol has a higher yield than the one-step method according to Joo et al. [33]. A method for producing methanol from CO 2 extracted from coal power plant flue gas and electrolytic hydrogen was presented in Ref. [34]. The commercial catalyst Cu/ZnO/Al 2 O 3 has been studied by several authors to produce methanol from CO 2 [35]. Exothermic reactions to produce methanol and RWGS reaction that occurs in parallel are listed in Equations (1)–(3): CO +2H2↔CH3OH (1) CO2+3H2↔CH3OH +H2O(2) CO2+H2↔CO +H2O(3) The process flow diagram optimized by Van-Dal et al. [29] is shown in Fig. 5. At 25 ◦C, 1 bar of CO 2 and 30 bar of H 2 are fed. A sequence of intercooling compressors compresses CO 2 to 78 bar, and hydrogen is compressed to 78 bar in one-step. After mixing both gases, the recycle stream is added again. After reaching 210 ◦C, the stream 14 is injected into a fixed bed adiabatic reactor. The reactor’s gases are split into two streams: the first stream, which makes up 60 % of the initial stream, is used to heat the new feed (stream 13), while the second stream is used to heat the feed of the distillation column as well as the reboiler (REB 1 ). In a knock-out drum (FL 2 ), condensed water and methanol are isolated from the unreacted gases. To minimise the buildup of inert gases and by-products in the reaction loop, 1 % of the non-reacted gases are purged. Methanol, water, and residual dissolved gases make up the crude methanol liquid stream that exits the knockout drum (FL 1 ). Two valves increase the crude methanol to 1.2 bar. The remaining gases are then virtually eliminated in a flash tank. After passing through exchanger HX b and reaching 80 ◦C, the residual stream is directed to a distillation column (COL 1 ). At 102 ◦C, water with 23 wt parts per billion methanol is released from the bottom of the column. At 1 bar pressure and 64 ◦C, methanol exits as a gas and contains 69 ppm (weight) of water and unreacted gases. After that, methanol is chilled to 40 ◦C and compressed. Non-reacted gases exit the top of a knock-out drum (FL 3 ), whereas the liquid methanol product exits the bottom. 2.5. Economic considerations The economic considerations for the evaluation of capital expenditures (CAPEX) are based on a scope of scalability, where for this work the model developed by Ny´ ari [36] for the reference total capital investment (TCI). This model integrates direct costs, such as equipment procurement, piping, and installation, with indirect costs, including land acquisition, civil and architectural works, licensing, and research and development (R&D). The TCI shows a proportionality with the cost of purchased equipment (PEC), as defined in Equation (4), which reflects the general practice for cost estimation in chemical plants, where indirect costs constitute the largest upfront investment. TCI =6.32⋅PEC (4) Being PEC the total cost of the equipment purchased. The cost of CO 2 capture infrastructure (CCO2) is given by the Chemical Engineering Plant Cost Index (CEPCI) adjusted for 2022, being a power-law scaling relationship (Equation (5)). This definition implies that marginal costs decrease as capacity increases. CCO2=61.7⋅106⋅(COout 2 2.71⋅106ton)0.72 (5) Similarly, the methanol synthesis block costs (CMeOH) follow a scaleup factor of 0.6 (Equation (6)), according to the literature for tubular reactors in the chemical industry. This reflects a non-linear relationship between reactor sizing and capital cost, derived from material and manufacturing costs as the scale increases. CMeOH =16.39 ⋅106⋅(MeOHout 1.71⋅106ton)0.6 (6) The cost of hydrogen production is based on an estimated price per kW. Based on market benchmarks and future predictions, values of € 600/kW, € 750/kW and € 900/kW are defined. The photovoltaic system is set at € 600/kW, according to reports from the International Energy Agency (IEA) in 2022 [37], which will take the self-consumption configuration to avoid grid consumption. The costs of renewable gas transport infrastructure are estimated at 416 € /m, adjusted using the CEPCI index, and the annual operating expenses (OPEX) are set at 2.5 % of the global CAPEX. To address uncertainties in markets and energy policy frameworks, three different production/sale scenarios are proposed (Table 3), which include optimistic, baseline, and conservative projections for methanol, hydrogen, and CO 2 capture prices. The Future (optimistic) scenario assumes declining CAPEX for green hydrogen (1200 € /kW) and reduced CO2 capture costs (70 € /ton), reflecting the EU decarbonisation targets and subsidies under the REPowerEU initiative. The current (baseline) scenario aligns with the market conditions of 2023, incorporating moderate hydrogen electrolyzer costs (1350 € /kW) and CO2 prices (80 € /ton). The high (conservative) scenario projects elevated green hydrogen production CAPEX (1500 € /kW) and CO2 capture costs (90 € /ton), simulating potential supply chain disruptions or stricter carbon taxation regimes, but higher hydrogen and methanol sales prices to compensate for cost overruns. The volatility in renewable gas sales prices is addressed with a range of € 30–50/MWh, according to natural gas prices in 2023 and without Fig. 4. Process flow diagram of the CO 2 capture phase by chemical absorption with monoethanolamine (MEA). Table 2 Thermodynamic hypotheses for the evaluation of electrolysis for methanol synthesis. Variable Value Temperature, Telec 120 ◦C Pressure, pelec 30 bar Electric Energy Required, Eelec 4.8 kWh/m 3 H 2 Electrolyzer Efficiency, η elec 0.65 D.A. Rodriguez-Pastor et al. Renewable Energy 254 (2025) 123751 4 considering disruptive events that raise prices in 2022. The Levelized Cost of Methanol (LCOM) (Equation (7)) serves as a metric that evaluates the discounted lifetime cost of methanol production in the proposed scenarios. Assuming a 30-year plant lifetime (N), a 2.5 % discount rate (r), and a 25 % corporate tax rate, the LCOM indicator provides a comprehensive comparison of economic viability under varying market conditions: LCOM =∑ N n=1 OPEXn+Taxesn (1+r)n+CAPEX ∑ N n=1 MeOHn (1+r)n (7) Complementing this, the Internal Rate of Return (IRRN), derived from the net present value (NPV) and the definition of the cashflow (CFn), quantifies project profitability and investor decision parameter (Equation (8)): 0=NPV =∑ N n=0 CFn (1+IRRN)n(8) The explicit linkage of CO 2 pricing to EU ETS trajectories ensures policy relevance, while economic analysis provides stakeholders with a probabilistic risk assessment tailored to volatile energy markets. LCOM and IRR estimations transcend conventional cost-benefit analyses by incorporating tax regimes and discount rates reflective of current macroeconomic conditions. This approach enables direct comparisons with fossil-based methanol, demonstrating the economic competitiveness of green methanol based on our strategy. 3. Results and discussion Fig. 6 shows the potential for green methanol production in Europe, based on a geospatial analysis of 9213 theoretically viable municipalities, identified by their proximity to natural gas infrastructure, industrial CO 2 sources and water treatment plants. After applying land use filters, such as protections to urban and protected areas, as well as requirements for PV installations (50 MW on >100 ha), 3016 technically viable municipalities are selected, concentrated in regions of high average irradiance (4–5 kWh/kWp/day) and close to industrial hubs. In regions with low solar resources (~1500 h/year of peak sunshine), such as in northern Europe, production reaches 1709 kton/year of methanol and 185 kton/year of hydrogen, which requires 400 TWh/year of photovoltaics. In contrast, southern European regions (2500 peak sun hours), such as Spain and Italy, aggregate up to 1900 kton/year of methanol and 13,500 kton/year of hydrogen with 1600 TWh/year of solar PV production, implying a reduction in the levelised cost of methanol of up to 35 % compared to other regions with lower solar resources. Challenges such as water scarcity, regulatory and land acquisition barriers, and grid constraints require coordinated policies. Fig. 5. Methanol synthesis from CO 2 hydrogenation process flow diagram. C: Compressor, CT: Cooler/Condenser, HX: Heat Exchanger, FL: Drum, R: Reactor, COL: Column. Table 3 Economic values of production and sales assumed for the scenarios studied in this work. Scenario Sell Price Green H 2 CAPEX ( € /kW) CO 2 ( € /ton) H 2 ( € /MWh) MeOH ( € /ton) Future production/ sale prices 70 30 350 1200 Current production/ sale prices 80 40 450 1350 High production/sale prices 90 50 550 1500 Fig. 6. Hydrogen and green methanol production results according to the assumptions of this work in kt/year and equivalent solar PV electricity production in TWh/yr. (For interpretation of the references to colour in this figure legend, the reader is referred to the Web version of this article.) D.A. Rodriguez-Pastor et al. Renewable Energy 254 (2025) 123751 5 Fig. 7 quantifies the economic viability of green methanol production as a function of hydrogen production and solar energy input. The analysis reveals that the proposed green methanol facilities could produce 4.65 million tons/year of e-methanol, capturing ~7.7 million tons of CO 2 annually, which is equivalent to neutralizing the carbon footprint of 615,000 European households. This aligns with the EU’s ambition to scale non-biological renewable fuels since the associated green hydrogen production potential (~32.5 million tons/year) triples the 2030 target for renewable hydrogen derivatives. The total CAPEX for the deployment of these facilities is estimated at € 700 billion, with an annual OPEX of € 10 billion. Fig. 7A shows how small-scale installations in low-solar resource regions (<1600 kWh/m 2 /yr), generating less than 400 GWh/year of photovoltaic (PV) energy, exhibit IRR <5 % due to the suboptimal size of the plant and the excessive land requirements. A 200 GWh/year PV plant in Northern Europe (e.g., Scotland) requires ~1200 ha of land but yields only 12,000 tons/year of hydrogen, resulting in prohibitively high LCOM (> € 1100/ton) and negative NPV. Facilities in high solar resource regions (>2200 kWh/m 2 /yr), such as Andalusia (South Spain) or Sicily, achieve IRR >15 % at PV outputs (energy production) exceeding 1200 GWh/year. These large-scale installations benefit from economies of scale, reducing land use intensity and hydrogen production costs. The nonlinear relationship between hydrogen output and IRR implies that double hydrogen production from 50,000 to 100,000 tons/year boosts IRR by 6–8 percentage points (Fig. 7A), while LCOM declines from € 850/ton to € 520/ton (Fig. 7B). The colour gradient in Fig. 7A and B shows the interdependence of PV production, hydrogen output, and economic metrics. A mid-sized facility producing 600 GWh/year of solar energy (green gradient) generates ~35,000 tons/year of hydrogen, achieving an IRR of 9–11 % and LCOM of € 620–680/ton. This places green methanol within striking distance of fossil-based methanol prices (~ € 375/ton) when paired with carbon pricing (> € 80/ton CO2). The steepest LCOM reductions occur in the 800–1200 GWh/year PV range, where LCOM drops by € 180–220/ton for each incremental 100 GWh of solar energy, driven by lower electrolyzer utilization costs. Southern Europe, with its abundant solar resources, can achieve IRR >12 % even without subsidies, while continental and northern regions require targeted interventions (EU Innovation Fund or state-aid exemptions) to bridge the € 250–400/ton LCOM gap. Fig. 8 illustrates the relationship between solar resource availability (annual peak sun hours) and key economic metrics, such as levelized cost of methanol (LCOM) and internal rate of return (IRR), across the three proposed production/sales price scenarios (future, current and high). The analysis reveals a strong correlation between solar irradiance and economic viability, particularly in regions exceeding 2000 sun hours annually. Under the Future scenario (optimistic market conditions), facilities in high solar resource regions (e.g., Southern Europe, with 2300–2500 sun hours) achieve LCOM values as low as € 400–600/ ton, competitive with conventional methanol prices (~ € 375/ton) when accounting for carbon pricing. These results align with the EU target of 20 million tons of renewable hydrogen derivatives by 2030, since largescale green hydrogen valleys (for example, the Iberian Peninsula) leverage economies of scale to reduce LCOM by ~30 % compared to isolated facilities. IRR values in these regions reach 8–12 %, incentivising private sector investment. In the current scenario, LCOM increases to € 600–800/ton for medium solar resource regions (1700–2000 sun hours), such as central Italy or southern France. Here, the IRR drops to 5 %–7 %, reflecting higher electrolyzer CAPEX ( € 750–900/kW) and grid balance costs. However, clustering facilities near industrial CO 2 sources) mitigates costs, achieving LCOM parity (< € 700/ton) through shared infrastructure, emphasized by the € 44.56–98.75/ton cost reduction. The high-price scenario highlights the risks of elevated CAPEX and volatile markets. Despite aggressive sales prices, facilities in low solar resource areas (<1500 sun hours, e.g., Northern Europe) face LCOM exceeding € 1000/ton, with IRR stagnating at 2–4 %. Regions combining high annual solar hours (>2200) sustain LCOM below € 500/ton, even with hydrogen electrolyzer costs of € 900/ kW. A 20 % increase in sun hours (1700 to 2040) reduces LCOM by € 200–250/ton, while IRR improves by 4–6 %. Southern Europe’s solarrich zones require targeted CAPEX subsidies to accelerate project scalability, while continental and northern regions depend on cross-border hydrogen corridors and carbon capture partnerships. The € 53.33–71.9/tons cost differential between clustered and isolated facilities further validates the EU Hydrogen Valleys Initiative, which prioritises stakeholder collaboration to consolidate supply chains. Currently, in continental, Atlantic, boreal, and Alpine climate zones, green methanol installations that rely exclusively on solar photovoltaic (PV) energy are deemed economically unviable according to the assumptions of this study, due to lower solar irradiance and pronounced seasonal variability in these regions, which reduces the annual capacity factor of photovoltaic systems. Integrating complementary renewable energy sources, such as offshore or offshore wind, could significantly improve economic feasibility in these areas. For instance, Northern European regions with high wind potential (e.g., North Sea coastal zones or Scandinavian fjords) could mitigate solar intermittency by leveraging wind energy, capitalising on seasonal synergies: wind generation peaks during winter months when solar output declines, ensuring a more stable electricity supply for hydrogen electrolysis and methanol synthesis. Furthermore, the exclusion of energy storage technologies, such as hydrogen buffer storage or battery systems, represents a simplification in this analysis. Incorporating electric energy storage could enable the continuous operation of electrolyzers and methanol reactors, decoupling them from renewable variability. Grid interaction (excluded here) could provide operational flexibility, allowing surplus renewable electricity to be fed into the grid during peak demand periods, thus reducing operational costs. These enhancements, while beyond the scope of the current work, underscore strategies to improve the resilience of green methanol production in regions less suited to solar-centric systems. Geographically, as illustrated in Fig. 9, approximately 3000 proposed facilities are evaluated based on their internal rate of return Fig. 7. Economic results as a function of hydrogen production (ton/year) for A) IRR of the e-Methanol plant in % B) Levelised cost of e-Methanol in € /tonne. The colour gradient in the background indicates the equivalent photovoltaic production in each case in GWh/year. (For interpretation of the references to colour in this figure legend, the reader is referred to the Web version of this article.) D.A. Rodriguez-Pastor et al. Renewable Energy 254 (2025) 123751 6 (IRR) in all scenarios. The analysis reveals that the energy market dynamics, particularly the prices of blending hydrogen and methanol selling, exert a stronger influence on profitability than the high CAPEX of hydrogen technologies, although the latter remains a critical barrier. In Fig. 9C, which assumes elevated prices for hydrogen and methanol analogous to the early 2023 market conditions, facilities in solar-rich regions achieve IRRs exceeding 15 %, despite high upfront costs. This suggests that hybrid wind-PV storage systems in temperate climates could replicate such outcomes, particularly if aligned with policy initiatives such as the European Hydrogen Bank, which prioritises integrated infrastructure and subsidies. Future work will explore these synergies, quantifying how multi-technology renewable systems and active grid management could optimise the energy mix for e-fuel production, accelerating Europe’s transition to a climate-neutral economy. Fig. 10 presents a geospatial analysis of green methanol production costs in Europe under three pricing scenarios, mapped through levelized methanol cost ranges (LCOM) ( € /ton). In the future production/sales scenario (Fig. 10A), 553 facilities (27 % of the total) achieve competitive LCOM values between € 432 to 632/ton, concentrated predominantly in southern Europe, the Iberian Peninsula, southern Italy and Greece, where the high solar irradiance (>2000 kWh/m 2 /yr) minimises renewable energy costs. Even in these optimal regions, green methanol requires a premium selling price (400–600 € /ton) to offset the initial CAPEX barriers, particularly for electrolyzers (> € 700/kW). Under Fig. 8. Maximum economic values as a function of solar resource for IRR and LCOM, scaled for the different production/sales price scenarios proposed. Fig. 9. European map with selected green methanol facilities according to their internal rate of return (IRR 30 ), for each proposed production/sales price scenario. (For interpretation of the references to colour in this figure legend, the reader is referred to the Web version of this article.) Fig. 10. European map with selected green methanol facilities according to their LCOM ( € /ton), for each proposed production/sales price scenario. (For interpretation of the references to colour in this figure legend, the reader is referred to the Web version of this article.) D.A. Rodriguez-Pastor et al. Renewable Energy 254 (2025) 123751 7 current market conditions (Fig. 10B), 1609 facilities (52 % of the total) exhibit LCOM values clustered between € 832 and 1032/ton, with hotspots in continental Europe (e.g., western Germany, and northern France). These areas benefit from the existing industrial infrastructure for CO 2 capture (steel/cement factories) and the proximity to hydrogen pipelines, which reduces transportation costs. The dominance of midrange LCOM values ( € 800–1000/ton) highlights the persistent cost gap compared to fossil-derived methanol (~ € 200–300 € /ton), underscoring the need for policy mechanisms such as carbon contracts to make a difference. The high production/sales scenario (Fig. 10C) demonstrates the potential of reduced electrolyzer CAPEX (< € 700/kW), with 1120 facilities (34 % of total) achieving LCOM values of <1032 € /ton despite the elevated prices of hydrogen and methanol. 735 facilities in this scenario operate at € 632–832/ton, concentrated in regions, where wind energy could complement solar PV to stabilise input costs (e.g., coastal Denmark, Ireland). Even in high-cost brackets ( € 1232–1432/ton), 119 facilities remain viable in strategic industrial hubs (e.g., Rotterdam), where EU-funded hydrogen valleys and carbon pricing (> € 80/ton CO 2 ) offset economic hurdles. Southern Europe leverages solar abundance for low LCOM, while continental and northern regions rely on industrial synergies and policy support. Future cost reductions in electrolysis (< € 600/kW) and grid balance storage could expand low-cost clusters ( € 432–632/ton) into temperate zones. 4. Conclusions There is an opportunity for a massive deployment of green methanol from solar photovoltaic hydrogen in Europe. This work has studied the potential to produce green methanol from GIS analysis, considering existing natural gas facilities and the emissions related to their processes. Based on the solar resource, 3016 potential European municipalities have been considered for the implementation of green methanol plants, considering the sale of CO 2 emissions, the sale of surplus H 2 to the NG grid through blending, and the sale of methanol to other industries, allowing the capacity of other innovative uses of methanol proposed by the authors in previous works. Future prices of electrolysis facilities offer obtained values of ~480 € /ton MeOH, with internal rates of return >15 %, showing the economic viability of the facilities. If the installations did not inject hydrogen by blending, viability would not be obtained, as for solar installations with a capacity below 200 MWp. It is estimated that the European administration’s joint contribution and alliances between stakeholders can contribute to large power and production plants that ensure lower production costs. The costs are highly determined by the CAPEX of the green H 2 installation, but the natural gas market and ETS are shown to be determinants for investors. The combined investment of ~700 bn € would enable Europe to produce 5 Mton MeOH annually from self-consumption solar PV, reducing GHG emissions by 7.7 Mton CO 2 /yr and making a decisive contribution to climate change mitigation. CRediT authorship contribution statement D.A. Rodriguez-Pastor: Writing – original draft, Visualization, Software, Resources, Methodology, Investigation, Formal analysis, Data curation. V.M. Soltero: Writing – review & editing, Visualization, Validation, Supervision, Formal analysis. R. Chacartegui: Writing – review & editing, Validation, Supervision, Resources, Project administration, Funding acquisition. Declaration of competing interest The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper. Acknowledgement This work was partially funded from the EU Next Generation funds and from the Spanish Ministry of Science and Innovation, through the projects ’Nuevo concepto modular de almacenamiento termoquímico de energía a alta temperatura basado en procesos innovadores’ - MOTHERESE, grant TED2021-131839B-C21 and ’Procesos y componentes para el almacenamiento híbrido de energía t´ ermica basado en sales fundidas y carbonatos’ - HIPERTES, grant PID2022-140815OB-C21. References [1] C. McGlade, P. Ekins, The geographical distribution of fossil fuels unused when limiting global warming to 2 ◦C, Nature 517 (2015), https://doi.org/10.1038/ nature14016, 7533 2015;517:187–90. [2] T. Abbasi, S.A. Abbasi, Decarbonization of fossil fuels as a strategy to control global warming, Renew. 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