This chapter presents a techno-economic assessment of low-carbon hydrogen production in Egypt, examining both green and blue hydrogen pathways. Using scenario-based modelling tailored to Egypt, the analysis estimates the levelised cost of hydrogen across various configurations and identifies the most cost-competitive production routes. The chapter also evaluates production cost of key green hydrogen derivatives – ammonia, iron and e-methanol – highlighting Egypt’s potential as major exporter. These findings provide critical input for identifying financial solutions and enabling investment conditions, further explored in Chapters 3 and 4.
Implementing the OECD Framework for Industry’s Net‑Zero Transition in Egypt
Accelerating Green Hydrogen Development
Abstract
This chapter assesses the cost-competitiveness of low-carbon hydrogen production in Egypt including green and blue hydrogen, as well as green derivatives such as green ammonia, green iron and e-methanol. The analysis is designed to inform recommendations on enabling investment conditions and financial solutions for Egypt’s low-carbon hydrogen development. Given that no operational low-carbon hydrogen projects currently exist in the country, the results do not reflect actual on-the-ground conditions. Instead, they provide an indicative assessment of Egypt’s potential cost-competitiveness, based on assumptions and data drawn from both national and international sources. These findings should be interpreted with caution due to inherent uncertainties in input assumptions. The OECD conducted extensive consultations with key public and private stakeholders throughout the assessment process to ensure relevance and alignment with Egypt’s emerging hydrogen market (Annex E).
The main assessment was conducted by calculating the Levelised Cost of Hydrogen (LCOH) using a dedicated techno-economic model, with different hydrogen production scenarios specifically tailored to Egypt. The LCOH represents the total production cost over the investment’s lifespan, covering capital expenditures (CAPEX) and operating costs (OPEX), such as maintenance, feedstock and other inputs. Details of methodology, input data and assumptions are summarised in Annex A. The techno-economic model used by the study simulated the full hydrogen production process by tracking energy and material flows throughout the defined system boundaries for a number of scenarios. The system boundary of each scenario is explained in Section 2.2.1. A key distinguishing feature is the integration of a power system model for green hydrogen production, enabling a full-year simulation with hourly temporal resolution. This approach optimises the sizing and operational dispatch of solar PV and onshore wind generation assets, low-temperature electrolysis units and both battery and hydrogen storage systems. By simulating renewable electricity supply and green hydrogen production on an hourly basis, the model captures the variability of renewable energy resources and operational dynamics more realistically. This results in a more robust estimation of production costs and system requirements, reflecting the technical complexities associated with achieving continuous electrolyser operation under variable renewable energy inputs.
The LCOH for the blue hydrogen case is calculated by developing process models, using the commercial process simulation software Aspen Plus. Instead, for green hydrogen production, mixed integer linear programming (MILP) models are developed in MATLAB to compute the economic optimal size and optimal operation strategy for the different system components. A bottom-up approach is adopted for calculating the CAPEX of each of the modelled plants. Finally, the LCOH is calculated coupling the estimated CAPEX with the OPEX for each of the simulated scenarios.
The LCOH for both blue and green hydrogen was estimated under four scenarios to identify the most suitable technological and production conditions for Egypt. Additionally, the second part of Chapter 2 evaluates green hydrogen derivatives – green ammonia, green iron and e-methanol – by analysing their cost competitiveness and export potential, leveraging Egypt’s renewable energy strengths and corresponding production pathways. Each derivative pathway was assessed by calculating the levelised cost of the final product, factoring in the cost of green hydrogen as a key input. For consistency, the hydrogen input cost was derived from the low-cost scenario identified in the LCOH analysis (Scenario B), assuming a dedicated renewable energy share of 98%. The models incorporated detailed process configurations and energy requirements for each conversion pathway.
The Chapter 2 analysis informs Chapter 3, which examines economic and de-risking instruments to help bridge the cost gap toward the price of USD 1.8/kg H2 envisioned in Egypt’s National Low-Carbon Hydrogen Strategy by 2040 – a key parameter considered throughout this report, which should be considered indicative and comparative rather than definitive.1
2.2.1. Green hydrogen production system
The cost of green hydrogen production depends on the cost of renewable power and the capital cost of equipment, notably electrolysers, as well as financing costs (indicated by the cost of capital) (OECD/The World Bank, 2024[1]; Lee and Saygin, 2023[2]). Indeed, green hydrogen is produced by splitting water into hydrogen and oxygen through electrolysis powered by renewable energy sources. The systematic approach encompassing the entire green hydrogen value chain is complex and varies based on national circumstances (Cordonnier and Saygin, 2022[3]). Figure 2.1 provides a schematic representation of the green hydrogen production system assessed for cost competitiveness.
Note: BESS: Battery Energy Storage System; CAPEX: capital expenditure; OPEX: operating expenditure; fOPEX: fixed operating expenditure; H2: hydrogen.
Source: Schematic representation prepared by the OECD Secretariat.
CAPEX and OPEX include a range of costs associated with the development and operation of a green hydrogen system producing 100 kilotonnes (kt) of H2 per year, covering renewable power generation, electrolysis, storage, transmission infrastructure and grid electricity use, with OPEX calculated as a percentage of CAPEX across components. The CAPEX includes costs for the renewable power generation plant, battery energy storage system (BESS), low-temperature electrolysis system and hydrogen storage system. Additionally, investment costs for constructing new electricity transmission lines and hydrogen transport pipelines are factored in based on different scenarios set up. For OPEX, annual fixed Operations and Maintenance (O&M) costs are calculated as a percentage of the CAPEX for each component. Grid electricity prices in Egypt are also incorporated for the portion of power sourced from the grid. The technological parameters for each part of the value chain are summarised as below. The underlined assumption is that the green hydrogen production system generates 100 kt H2 per year, maintaining a constant hourly production rate of 11 414 tonnes of H2 throughout the year (Annex A).
The following production factors have been considered (Annex A):
Electricity: The cost of electricity has substantial impact on LCOH as it powers electrolyser to produce green hydrogen. The electrolyser can be powered by electricity produced from either: (i) a dedicated renewable energy source, such as wind or solar power with or without battery storage; or (ii) the power grid. However, the contribution of electricity from the national grid is limited to a maximum of 10%2 of the total electricity required for hydrogen production and compression. The analysis reflected recent regulatory change in Egypt allowing surplus electricity sales through business-to-business (B2B) agreements. It is to consider a scenario of selling excess renewable electricity at the same rate as grid electricity purchases, set at 21 EUR/MWh.3 It is important to note that selling excess renewable electricity to the grid at this rate assumes that the electricity will be absorbed by the grid when surplus is generated. However, in a future scenario with high renewable energy penetration, this may coincide with periods of low demand or oversupply from other renewable sources. For the purposes of this analysis, this potential constraint has not been considered.
Water: Given the need for water as feedstock to green hydrogen production and its scarcity in Egypt, the production route of hydrogen must include desalination from sea water using renewable electricity. Considering an average water consumption of 10 kg water per kg of H2, the levelised cost of desalination would add up to USD 0.02/kg H2 to the LCOH. The analysis does not detail the operation of a desalination unit and considers a specific consumption of electricity and a specific total cost.
Electrolyser: Besides electricity cost, electrolyser is another key factor influencing hydrogen production costs (Cordonnier and Saygin, 2022[3]). The analysis assumes low-temperature electrolysis with a minimum load factor of 20%. Downstream, a compressor is included to pressurise hydrogen up to 220 bars for storage.
Storage: To enhance system efficiency and prevent excessive oversizing of the renewable power generation plant, both lithium-ion battery energy storage systems (Li-ion BESS) and pressurised hydrogen storage vessels are incorporated for short-duration energy storage.
For the green hydrogen production system, the model is structured within an optimisation framework that determines the optimal sizes of system components and their operation schedule, aiming to minimise the LCOH while ensuring a constant hourly hydrogen output throughout the year. This objective is formulated as a mixed-integer linear programming (MILP) optimisation problem. A cost-optimisation algorithm is implemented in MATLAB and solved using the Gurobi™ solver. The model simulates system operations over an entire year with hourly time resolution. Hourly solar PV and wind electricity generation profiles are based on historical data for the selected plant location, representing a typical year. For each hourly time step, the equations governing the behaviour of each system component are solved, determining the energy flows entering and exiting each component. Economic assumptions for green hydrogen are summarised in Table 2.1.
Note: Annex A provides the full set of economic assumptions. The analysis adopts a one-year operational time horizon with hourly resolution to assess the Levelised Cost of Hydrogen, allowing for realistic simulation of renewable generation variability and system performance. USD/kWhe refers to dollars per kilowatt-hour of electricity. The USD value assumptions are selected to be in line with the various references in the available literature.
Source: Economic assumptions defined by the OECD Secretariat for the main model system components.
2.2.2. Scenarios for green hydrogen production
Four scenarios are analysed, each differing in the geographic location of renewable electricity generation, hydrogen production and hydrogen demand (Figure 2.2). These variations help identify the optimal system configuration for Egypt to produce the most cost-competitive green hydrogen. For instance, one of key factors that was key aspect to develop these scenarios was availability of renewable energy sources which is key to produce low-cost electricity. In this work, data are extracted for the historical year 2019 from Ninja Renewables (Ninja Renewables, 2025[4]). The generation output is assumed to increase proportionally with the installed capacity, leveraging the modular nature of the systems considered. The selected locations are Suez area, Gharib Cape and Aswan area. Table 2.2 summarises the renewable generation potential. It is worth mentioning that the PV power generation profiles assume a tilt of 30 degrees, an azimuth of 180 degrees, without tracking. Additionally, 10% system electricity losses4 are considered.
Note: The assumption in this analysis is that PV plants do not generate electricity from sunset to sunrise. Since the model uses an hourly resolution, the number of “dark” hours must be considered. Further details are provided in Annex A.
Source: (Ninja Renewables, 2025[4]).
The scenarios are defined as follows (Figure 2.2):
Scenario A: This scenario involves establishing a co-located hydrogen production hub near the demand site, with Suez identified as a potential location. Green hydrogen production would be powered by a dedicated local PV and/or wind energy system, with the option to source up to 2%, 5% or 10% of the required electricity from the national grid. Additionally, a sub-scenario is considered, exploring the use of ammonia as an intermediate storage solution. This alternative eliminates the need for pressurised hydrogen tanks and instead requires an ammonia production unit, an ammonia storage tank and an ammonia cracking unit (Section 2.5.1).
Scenario B: This scenario involves establishing a co-located production hub that integrates renewable power generation and electrolysis, with hydrogen transported to demand centres. Gharib Cape has been selected as the production hub, where hydrogen will be generated and then transported via a 230 km pipeline to Suez, the designated demand location.
Scenario C: This scenario involves separating electricity generation from hydrogen production. Renewable power is generated in Gharib Cape and transmitted via a dedicated 230 km high‑voltage direct current (HVDC) transmission line to Suez, where green hydrogen is produced and consumed. This approach ensures that green hydrogen production remains close to the demand centre while utilising optimal renewable energy resources from a different location.
Scenario D: In this scenario, electricity generation, green hydrogen production and green hydrogen demand are in different regions, necessitating both electricity transmission and hydrogen transport. Renewable power is generated in the Aswan area and transmitted via a 525 km HVDC transmission line to Gharib Cape, where green hydrogen production occurs. The produced green hydrogen is then transported through a 230 km pipeline to Suez, the designated demand centre.
Note: These maps do not reflect Egypt’s full territory and are used solely to illustrate the four proposed scenarios. The maps use the administrative divisions of Egypt’s governorates. They are sourced from Egypt’s Central Agency for Public Mobilization and Statistics (CAPMAS).
Source: Prepared by the OECD Secretariat on the basis of chosen scenarios.
The cost of blue hydrogen depends on the chosen production technology, gas prices and CO2 transport and storage costs, with carbon capture typically adding USD 0.3-0.5/kg to grey hydrogen cost (Oni et al., 2022[5]). An additional uncertainty in the estimation of the expected cost of blue hydrogen is associated to the gas price, transportation and storage costs of CO2 (Oxford Institute for Energy Studies, 2024[6]).
The analysis considers two different technological options for blue hydrogen production: steam methane reforming (SMR) with post-combustion carbon capture (Figure 2.3) and autothermal reforming (ATR) with carbon capture improving energy efficiency (Figure 2.4).
SMR, in which a typical industrial plant consists of a desulphurization section, a pre-reformer, the primary reformer, water gas shift (WGS) reactors, H2 purification by pressure swing adsorption (PSA) and a CO2 separation section from the SMR furnace flue gas. This can be implemented as a retrofit on existing grey hydrogen production plants.
ATR, in which a typical industrial plant consists of a desulphurization section, an air separation unit (ASU), a pre-reformer, the primary reformer, water gas shift (WGS) reactors, a CO2 separation section from the syngas flow and H2 purification by PSA.
Both options assume an hourly production capacity of 100 000 normal cubic meters (Nm³) of hydrogen and include the transport of captured CO2 with a dedicated 250 km pipeline to a potential CCS hub. Details of the methodology, plant configurations and input data can be found in Annex A.
Note: CAPEX: capital expenditure; CCS: Carbon Capture and Storage; CO2: carbon dioxide; H2: hydrogen; HRSG: Heat Recovery Steam Generator; OPEX: operating expenditure; fOPEX: fixed operating expenditure.
Source: Schematic representation prepared by the OECD Secretariat.
Note: ASU: Air Separation Unit; CAPEX: capital expenditure; CCS: Carbon Capture and Storage; CO2: carbon dioxide; H2: hydrogen; HRSG: Heat Recovery Steam Generator; OPEX: operating expenditure; fOPEX: fixed operating expenditure.
Source: Schematic representation prepared by the OECD Secretariat.
Blue hydrogen was included in this report following initial OECD consultations held during the interministerial scoping meeting in June 2023. However, several factors impose significant limitations on its consideration. Existing blue hydrogen projects are not often driven by strict environmental regulations or carbon market mechanisms. Therefore, most plants have been designed to achieve only partial carbon capture rates (typically around 60-70%), which helps in achieving a business case under the current regulatory and market conditions. Higher capture efficiencies of over 90% have not been pursued so far because of the lack of policies justifying the higher cost of CO2 capture. In a context of stronger regulatory pressure or significantly higher carbon pricing, plants could be designed differently to achieve much higher capture rates, but this has not been the case in large-scale projects so far.
Technically, achieving high capture rates, particularly using ATR, is believed to be feasible, despite the lack of blue hydrogen industrial references. Existing ammonia plants combining SMR and ATR already demonstrate CO2 capture efficiencies greater than 99% for syngas streams. However, achieving 90% capture from SMR flue gases remains less common, although certain industrial plants have been designed for such purposes, particularly for supplying CO2 for urea manufacturing (Maporti et al., 2024[7]). Publicly available performance data from operating facilities remains limited, which introduces uncertainty around real-world capture efficiencies at scale.
Additionally, methane leakages across the natural gas supply chain pose a significant challenge to the environmental credibility of blue hydrogen. Leakage rates are highly site-dependent and given methane’s high global warming potential, even small leakages can severely impact the life-cycle emissions of blue hydrogen (Sanchez, 2022[8]), making robust monitoring and supply chain management essential (Goita et al., 2025[9]).
Broader uncertainties persist regarding the economic viability, market acceptance, scalability and the management of captured CO2 in the production process of blue hydrogen. Carbon capture and storage (CCS) remains an emerging technology. Confidence in its commercial viability will depend on the successful realisation of upcoming projects over the next few years (Martin-Roberts et al., 2021[10]). Finally, cost and emission intensity estimations for blue hydrogen vary significantly depending on assumptions about capture rates, methane leakage and technology choices (IEEFA, 2022[11]).
These findings reinforce the view that green hydrogen, despite its higher production cost, offers higher overall viability and is increasingly recognised as the preferred pathway to replace fossil fuel based conventional hydrogen production, accelerate industrial decarbonisation and to decarbonise hard-to-abate sectors. While the analysis presented for blue hydrogen illustrates its theoretical cost competitiveness, the practical limitations – including incomplete CO2 capture rates, methane leakage risks, regulatory uncertainty and challenges in large-scale CCS deployment – constrain its real-world effectiveness. In contrast, green hydrogen eliminates direct carbon emissions and aligns more closely with Egypt’s long‑term policy ambitions for sustainable, low-carbon growth. Given Egypt’s abundant solar and wind resources, green hydrogen presents a more economically, politically and environmentally viable solution for driving both domestic industrial decarbonisation and green hydrogen exports positioning the country as a competitive player in the global hydrogen economy.
2.5.1. Green hydrogen
A geographical area with higher wind and solar availability leads to the lowest LCOH, even when accounting for the additional cost of building hydrogen pipelines or HVDC transmission lines (Figure 2.6). This is evident in Scenario B where hydrogen is produced at a co-located hub in Gharib Cape and transported via a 230 km pipeline to Suez and Scenario C where electricity is generated in Gharib Cape and transmitted 230 km via HVDC to Suez for hydrogen production near demand centres. In both cases, superior renewable resource availability in Gharib Cape significantly offsets transport infrastructure costs (Annex B).
The LCOH for optimised systems is estimated at USD 3.7-4.2 per kg H2 (Figure 2.6). However, the cost remains highly sensitive to electrolyser CAPEX. For instance, doubling the electrolyser cost from USD 800 to 1 600 per kW results in a 27% increase in hydrogen production cost from USD 4.14 to 5.27 per kg of H2 (Figure 2.5).
Note: Values refer to the case constrained to 4 h of hydrogen storage.
Source: Results of sensitivity analysis prepared by the OECD Secretariat.
Increasing the share of grid electricity reduces oversizing of renewable energy systems and lowers the need for battery storage, leading to a more cost-effective solution and a significant reduction in LCOH. This approach also stabilises power supply to the electrolyser and helps minimise overall capital costs. However, sourcing electricity from a non-decarbonised grid results in significant indirect emissions, which is incompatible with low-carbon hydrogen standards. For instance, in Scenario A, when taking into account the potential revenue from selling surplus electricity to the grid (rather than curtailing it), the LCOH is USD 8.5/kg H2 at 98% dedicated renewable input. Allowing for larger grid purchase (e.g. 5% or 10% of the annual electrolyser consumption) leads to lower LCOH values of USD 6.8/kg H2 and USD 5.5/kg H2, respectively. The possibility of selling surplus electricity to the grid impacts in a more moderate way the LCOH, for instance by increasing it by approximately USD 1.5/kg H2. Such increase is, in absolute terms, larger at higher share of dedicated renewable energy sources (RES).
Scenario D demonstrates the benefit of incorporating a mix of RES and grid electricity to reduce oversizing, minimise curtailment and lower overall costs. However, there is a trade-off: increasing the share of dedicated RES from 90% to 100% raises the LCOH from USD 4.19/kg H₂ to USD 5.34/kg H₂ due to additional RES and hydrogen storage capacity required. This illustrates that full reliance on RES is rarely the most cost-effective option.
The most efficient hydrogen production systems have a RES-to-electrolyser nominal power ratio close to 3, supporting higher renewable integration and improved system performance. The RES-to-electrolyser nominal power ratio refers to the ratio between the installed capacity of the RES and the nominal power capacity of the electrolyser (Hofrichter et al., 2023[12]). High renewable availability and low seasonal fluctuations allow optimised systems to operate with minimal hydrogen storage, reducing costs and improving overall efficiency. Modelling based on solar and wind profiles in the Suez and Gharib areas identifies an optimal PV/wind capacity ratio of 0.6-0.8 and a renewable-to-electrolyser capacity ratio between 2.5 and 4, supporting cost-effective system performance (Table 2.3).
Note: CAPEX RES: capital expenditure for renewable energy sources; H2: hydrogen; OPEX: operating expenditure.
Source: Results of the techno-economic assessment prepared by the OECD Secretariat. $
Note: PV: photovoltaic; RES: renewable energy sources
Source: Results of the techno-economic assessment prepared by the OECD Secretariat
Pressurised hydrogen tanks emerge as the most cost-effective storage option for hydrogen with lowest LCOH of USD 4.23/kg H2 (Figure 2.7). Using ammonia as a hydrogen storage vector results in a higher LCOH, increasing by 33% under the low CAPEX estimate and up to 43% under the high CAPEX estimate. The increased storage costs are due both to higher CAPEX of the ammonia production and cracking plants and to the higher energy losses in hydrogen-to-ammonia-to-hydrogen conversions. The highest LCOH is observed in BESS cases, reaching USD 7.37/kg H2 for the high CAPEX estimate. The LCOH calculations account for surplus electricity sales at grid price, reflected as negative values in Figure 2.7. Annex B provides a detailed analysis of the four green hydrogen LCOH scenarios.
Note: The estimates are calculated at 98% dedicated renewable energy sources. BESS: Battery Energy Storage System; CAPEX: capital expenditure; H2: hydrogen; LCOH: Levelised Cost of Hydrogen; NH3: ammonia; OPEX: operating expenditure.
Source: Results of the techno-economic assessment prepared by the OECD Secretariat.
2.5.2. Blue hydrogen
Blue hydrogen produced with ATR or SMR technologies have very similar results with a slightly lower LCOH for ATR. The retrofitting of existing pipelines is cheaper compared to building new CO2 pipelines. While ATR with pre-combustion capture and the potential use of an existing pipeline shows the lowest LCOH, the cost advantage over SMR is marginal. However, a key cost driver in both cases is the CO2 transport and storage infrastructure. These costs could be significantly reduced if shared with other emitters, such as cement plants, highlighting the potential value of a co-ordinated, hub-based approach to CO2 infrastructure.
Natural gas prices are the dominant cost driver for blue hydrogen production, making the overall cost structure highly sensitive to fuel price volatility. In this analysis, a natural gas price of USD 6.0/MMBtu is assumed (Annex B), consistent with Egypt’s regional market conditions. The results show only a marginal difference between the two technologies. These findings highlight the critical importance of transparent and realistic gas price assumptions when assessing the cost competitiveness of blue hydrogen relative to green alternatives. Even modest shifts in gas prices could substantially alter the LCOH, reinforcing the economic uncertainty surrounding blue hydrogen pathways.
Comparing blue hydrogen with the best-case scenario for green hydrogen production, blue hydrogen production (using both SMR and ATR technologies) remains 43% cheaper than green hydrogen (Figure 2.8). However, for blue hydrogen to be classified as low carbon, emissions across the entire value chain, particularly methane leakage, must be carefully monitored.
Note: ATR: autothermal reforming; CAPEX: capital expenditure; CO2: carbon dioxide; LCOH: Levelised Cost of Hydrogen; OPEX: operating expenditure; SMR: steam methane reforming.
Source: Results of the techno-economic assessment prepared by the OECD Secretariat.
Green hydrogen derivatives include green ammonia, green steel/reduced iron and e-methanol. Green hydrogen can be converted or synthesised into other energy carriers or hydrogen-based products when refined with either nitrogen for e-ammonia or CO2 for e-methanol and e-kerosene. Derivative commodities produced using green hydrogen will play a significant role in low-carbon hydrogen market growth (IRENA, 2024[13]). Moving gaseous green hydrogen itself over long distances may be technically challenging due to its low volumetric energy density. Therefore, the derivatives may be easier to ship intercontinentally. To ensure the credibility and market acceptance of these products, reliable certification schemes are essential to verify their environmental integrity and build consumer confidence (IRENA-RMI, 2023[14]). The following sections present the results of the assessment on green hydrogen derivatives, focusing on green ammonia, green steel and reduced iron, as well as e-methanol.
2.6.1. Green ammonia
Ammonia has been produced on an industrial scale and serves as a fundamental chemical with various applications globally. Particularly, ammonia plays a crucial role in the agriculture sector as about 80% of ammonia is used to produce fertilisers. Egypt is considered the 8th largest ammonia exporter and the average ammonia production reaching 5.5 million tonnes in 2020 (UNIDO, 2023[15]). Currently, ammonia is primarily produced using the Haber-Bosch (HB) process, which combines hydrogen and nitrogen (Kojima and Yamaguchi, 2022[16]). The hydrogen required for this process is sourced from natural gas through steam reforming, making the ammonia industry a significant CO2 emitter, contributing over 400 Mt of CO2-eq annually worldwide (Müller et al., 2024[17]) and accounting for more than 1.2% of the world’s carbon emissions (Irfan et al., 2024[18]).
Ammonia is emerging as a promising low-emission energy carrier, particularly for hydrogen transport globally (IEA, 2024[19]). Ammonia has a key advantage over pure hydrogen due to its higher energy density and lower liquefaction temperature, making it much easier to store and transport (IEA, 2021[20]). Additionally, unlike hydrogen, ammonia already has well-established infrastructure and handling practices for storage, distribution and export (Erdemir and Dincer, 2024[21]). As such ammonia is widely recognised as cost-effective hydrogen carrier, particularly for long-distance transport (e.g. Australia to Japan or Chile to Europe (Thyssenkrupp, n.d.[22]). However, ammonia is highly toxic, and the safety measures required for its use are stringent and comprehensive, involving strict protocols for transport and handling. While ammonia holds significant potential as a low-emission energy carrier, its deployment at scale will depend on balancing its logistical benefits with robust safety standards and risk management practices.
In Scenario 1 of the green hydrogen analysis presented earlier, the cost competitiveness of green ammonia production was evaluated by examining the Levelised Cost of Ammonia (LCOA). The case is considered as an alternative approach to short term hydrogen storage. Instead of using pressurised hydrogen tanks, the system boundary converts hydrogen into ammonia for storage, later breaking it back down into hydrogen to ensure a steady and reliable supply (Figure 2.9).
Note: BESS: Battery Energy Storage System; CAPEX: capital expenditures; H2: hydrogen; N2: nitrogen gas; NH3: ammonia; OPEX: operating expenditure; fOPEX: fixed operating expenditure.
Source: Schematic representation prepared by the OECD Secretariat.
The analysis has been conducted under the assumption that 50 kt/year of green ammonia (corresponding to 8.8 kt H2/year) is produced for export. The system size assumption aligns with Egypt’s Scatec project. The hydrogen is assumed to be produced in Gharib Cape, then transported 230 km to the Suez area where the production of ammonia will take place as illustrated in Figure 2.10. The green ammonia is then exported to northern Europe considering a shipping distance of 6 000 km with an added cost of USD 1 per gigajoule (GJLHV) (USD 18.8/tNH3) (Figure 2.10).
Note: This map does not reflect Egypt’s full territory and is used solely to illustrate the proposed scenario. The map uses the administrative divisions of Egypt’s governorates, sourced from Egypt’s Central Agency for Public Mobilization and Statistics (CAPMAS).
Source: Prepared by the OECD Secretariat on the basis of the chosen scenario.
The lowest LCOA was USD 844/t NH3, assuming a flexible ammonia plant with 30% minimum capacity factor (Figure 2.11). The added flexibility on ammonia plant results in a reduction of the LCOA compared to inflexible ammonia plant with flat production profile. Similar to the green hydrogen cases, green ammonia production CAPEX is intensive, representing more than 79% of the LCOA with the RES plant representing more than 51% of the total CAPEX.
Note: CAPEX: capital expenditure; H2: hydrogen; LCOA: Levelised Cost of Ammonia; NH3: ammonia; OPEX: operating expenditure; RES: renewable energy sources.
Source: Results of the techno-economic assessment prepared by the OECD Secretariat.
2.6.2. Green steel: green iron for export to the European Union
The steel industry is the second-largest emission intensive sector globally, accounting for approximately 8% of the total global CO2 emissions, primarily due to its reliance on coal (Aziz et al., 2022[23]). Iron is manufactured through two major routes, namely blast furnace (BF) and direct reduction iron (DRI) (Fan and Friedmann, 2021[24]). The integrated blast furnace - basic oxygen furnace (BF-BOF) steel production route is the most common steel production route, accounting for roughly 70% of global steel production (IEA, 2020[25]). The large majority of emissions of steel production stem from the iron-making stage (Aziz et al., 2022[23]). In the BF-BOF route, representing around 70% of steel production worldwide, the production of one tonne of crude steel results in approximately 1.8 tonnes of CO2, reflecting best available technology (BAT) levels or the performance of newly constructed facilities. However, Egypt does not operate BF-BOF plants, and its iron production primarily relies on natural gas – based direct reduced iron (DRI) processes, which emit approximately 1 tonne of CO2 per tonne of crude steel (Worldsteel, 2024[26]).
The use of green hydrogen presents a transformative solution for decarbonising the steel industry. In DRI plants, iron is typically produced by a H2-CO-CH4 reducing gas produced from natural gas. By replacing coal- or natural gas-based methods with green hydrogen, the world steel industry could cut significantly emissions annually while maintaining high-quality iron and steel production (Bararzadeh Ledari et al., 2023[27]). Replacing conventional blast furnace steelmaking with green hydrogen-based DRI can reduce carbon emissions by up to 95%, cutting CO2 intensity from around 1.8-2 t CO2/t steel to as low as 0.1‑0.76 t CO2/t steel. In Egypt, three steel companies operate DRI plants, namely Ezz Steel, Beshay Steel and Suez Steel Company (Oxford Institute For Energy Studies, 2021[28]). However, green hydrogen is not yet used as it lacks economic competitiveness.
For all three scenarios analysed, Suez is selected as a potential hydrogen production location and shipping port connecting Egypt to the European market. The analysis uses a simplified approach in which hydrogen is considered to be purchased at a cost equal to the LCOH, selecting the lowest value obtained in LCOH analysis for green hydrogen earlier. The percentage of the dedicated renewable electricity selected for this analysis is 98%. The analysis is also limited to the DRI production, without including the costs for the conversion of DRI into steel in electric arc furnaces. Detailed assumptions for this analysis are specified in Annex A.
In order to assess the current cost competitiveness of green iron production in Egypt, the assessment explores three scenarios reflecting the country-specific context and production conditions (Figure 2.12):
Scenario 1, local production: green hydrogen and green DRI are co-produced in Egypt and shipped 6 000 km to Germany via Gibraltar.
Scenario 2, pipeline hydrogen transport: green hydrogen is produced in Egypt and transported via a 1 000 km submarine pipeline to Greece, then continues 2 000 km via pipeline to Germany for green steel production.
Scenario 3, green ammonia as a hydrogen carrier: green hydrogen from Egypt is converted into green ammonia to reduce transportation costs. The liquefied NH3 is shipped 6 000 km to Germany, where it is reconverted (cracked) into hydrogen for green steel production.
Source: Prepared by the OECD Secretariat on the basis of chosen scenarios.
The analysis shows that producing green iron in Egypt offers a significant cost advantage. This is primarily driven by Egypt’s access to low-cost green hydrogen and renewable electricity, maritime transport having minimal impact on overall costs. Scenario 1 yielded the lowest Levelised Cost of Iron (LCOI), at USD 732.8 per tonne of Direct Reduced Iron (DRI), largely due to Egypt’s competitive energy inputs. It makes nearly 25% more cost-effective than EU-based green iron production (Figure 2.13).
Maritime transport is found to have a minor impact on the cost by adding only USD 1.8/t DRI. It is because producing green hydrogen in Egypt significantly reduces the LCOI, nearly halving the hydrogen cost per tonne of DRI from USD 416.8 in the EU to USD 220.4 in Egypt. Additionally, Egypt’s lower renewable electricity costs reduce DRI production electricity expenses from USD 50.6/t DRI in the EU to USD 10.6/t DRI. The green section of Figure 2.13 represents the base cost, which includes iron ore supply, DRI CAPEX depreciation and DRI OPEX. Scenario 3 is the second most cost-effective option at USD 780.4/t DRI, while Scenario 2 results in the highest LCOI with USD 872.4/t DRI. This is however still more competitive than the EU-based production cost of green iron estimated at USD 967.4/t DRI (Table 2.4).
Note: DRI: Direct Reduced Iron.
Source: Results of the techno-economic assessment prepared by the OECD Secretariat.
Note: DRI: Direct Reduced Iron; EU: European Union; H2: hydrogen; NH3: ammonia.
Source: Results of techno-economic assessment prepared by the OECD Secretariat.
2.6.3. E-methanol
Methanol (MeOH) is produced from synthesis gas, a mixture of hydrogen, carbon dioxide and carbon monoxide. As of 2019, global methanol production reached approximately 98 million tonnes per year, generating an estimated 300 Mt of CO2 emissions annually – around 10% of total emissions from the chemical and petrochemical sector (IRENA and Methanol Institute, 2021[29]). Methanol production can transition to biomass-derived or synthetic feedstocks using CO2 and renewable hydrogen, thereby significantly reducing emissions (Saygin and Gielen, 2021[30]).
As the global push toward carbon neutrality and associated socio-economic benefits increases, market demand for sustainable alternatives to fossil fuels is rising, particularly in hard-to-abate sectors such as shipping and chemical production. Produced by combining green hydrogen with captured CO2, e-methanol offers a viable low-carbon shipping fuel and feedstock solution for chemicals production (Palys and Daoutidis, 2022[31]; Mærsk Mc-Kinney Møller Center, 2011[32]). E-methanol has several benefits compared to fossil fuels. The combustion of this fuel results in lower levels of harmful pollutants, and thereby also contributes to improving air quality. As a liquid, it is easier, safer and more cost-effective to store, transport and handle, especially since existing infrastructure can be leveraged. It is also a highly efficient and versatile fuel as it is produced from renewable hydrogen (IRENA and Methanol Institute, 2021[29]).
According to ECHEM,5 Egypt produced one million tonnes of methanol in 2019, and half of the production is consumed domestically. As of April 2025, Egypt is discussing the implementation of e-methanol projects.6 Egypt’s growing pipeline on green methanol production, despite the differing production routes and feedstocks of green methanol and e-methanol,7 presents a significant opportunity to decarbonise the sector. Leveraging its ample renewable energy resources, Egypt can utilise these resources for green hydrogen production, specifically enabling large-scale e-methanol manufacturing, and thereby contributing to a circular carbon economy and substantial GHG emission reductions.
Reflecting these market developments, the analysis explores the potential conversion of hydrogen to methanol for export with a view to evaluating the cost competitiveness of e-methanol production in Egypt. The analysis assumes the production of 500 kt/year of e-methanol, corresponding to 93.5 kt H2/year. The evaluated e-methanol production system is schematised in Figure 2.11. Under this scenario, green hydrogen is produced in Gharib Cape, then transported for 230 km through a pipeline to the Suez area where the production of e-methanol takes place. Flexible operation of the methanol production plant is considered with a minimum capacity factor of 30%. The technical and economic assumptions are specified in Annex A.
The analysis evaluates three scenarios to assess the impact of renewable electricity share and CO₂ sourcing on the Levelised Cost of Methanol (LCOM):
Scenario 1: 100% dedicated renewable energy sources with CO2 supplied via direct air capture (DAC), assuming a cost of USD 300/t CO2.
Scenario 2: 98% dedicated renewable energy sources (allowing up to 2% grid electricity) with CO2 also sourced via DAC at the same cost assumption.
Scenario 3: 98% dedicated renewable energy sources, with CO2 captured from an industrial emitter, assuming zero CO2 cost since capture costs are borne by the emitter.
The CO2 supply is adjusted based on hydrogen availability in all cases. These scenarios are compared based on their resulting LCOM to identify the most cost-effective configuration.
Note: BESS: Battery Energy Storage System; CAPEX: capital expenditure; CH3OH: methanol; CO2: carbon dioxide; H2: hydrogen; N2: nitrogen gas; NH3: ammonia; OPEX: operating expenditure; fOPEX: fixed operating expenditure.
Source: Schematic representation prepared by the OECD Secretariat.
Utilising CO2 from industrial emitters, combined with the option to sell surplus electricity, offers the lowest‑cost pathway for green methanol production. Scenario 3, which utilises CO2 from an industrial emitter with 98% dedicated renewable energy sources, results in an LCOM of USD 732/t MeOH. This estimate slightly decreases to USD 715/t MeOH when the revenues from excess electricity sales are factored in. Scenario 2, which uses CO2 from DAC with 98% dedicated RES (allowing up to 2% grid electricity for flexibility), has an estimated LCOM of USD 1 127-1 144/t MeOH, depending on how excess electricity sales are accounted for. Scenario 1, relying on CO₂ from DAC with 100% dedicated renewable energy supply, results in the highest LCOM at USD 1 368-1 438/t MeOH. In all three scenarios, the CAPEX of the renewable energy plants and electrolysers represents the biggest contributor (Figure 2.15). For Scenarios 2 and 3, considering DAC, the provision of CO2 accounts for USD 412.5/t MeOH.
The LCOM for e-methanol is highly sensitive to the renewable energy configuration and the degree of grid reliance. In Scenario 1, which relies on 100% dedicated renewable energy, the LCOM reaches USD 1 368/t MeOH. This is due to the need for significant oversizing of renewable capacity and the inclusion of 486 MWh of BESS and 855 t of H2 storage to ensure uninterrupted production. The RES‑to‑electrolyser capacity ratio in this case is 2.3 (Table 2.5). By comparison, Scenario 2 allows up to 2% of electricity demand to be met by grid supply, reducing the LCOM to USD 1 127/t MeOH. This flexibility lowers the RES-to-electrolyser ratio to 1.9 and eliminates the need for BESS and H₂ storage. The increase in LCOM between Scenario 2 and Scenario 1 highlights the cost penalty of achieving a fully off-grid renewable configuration.
Note: BESS: Battery Energy Storage System; CAPEX: capital expenditure; eMeOH: methanol; H2: hydrogen; LCOM: Levelised Cost of Methanol; OPEX: operating expenditure; RES: renewable energy sources.
Source: Results of the techno-economic assessment prepared by the OECD Secretariat.
Source: Techno-economic assessment prepared by the OECD Secretariat.
This chapter presented a comprehensive techno-economic assessment of low-carbon hydrogen production in Egypt, focusing on both green and blue hydrogen pathways. Using a robust modelling framework tailored to Egypt’s context, the analysis simulates hourly system operations to estimate the LCOH across four green hydrogen scenarios.
Results indicate that Egypt’s abundant and stable renewable energy resources enable highly cost‑competitive green hydrogen production. The most efficient configurations achieve an LCOH as low as USD 3.7/kg H2, supported by optimal renewable-to-electrolyser capacity ratios and minimal reliance on costly storage. This remains, however, above the price of USD 1.8/kg H2 by 2040 envisioned in Egypt’s National Low-Carbon Hydrogen Strategy, which assumes a production scale of 6-10 Mt per year.
Egypt could significantly narrow the gap between cost estimates in this report and strategic price targets by implementing measures to strengthen its enabling investment environment. Moreover, potential reductions in CAPEX thanks to technological learning are expected between by 2040. While such advancements – driven by innovation, economies of scale and policy support – are likely to lower costs over time, their impact is deliberately excluded from this assessment to maintain consistency in assumptions. Readers should therefore interpret the findings as indicative and comparative rather than definitive.
In assessing green hydrogen derivatives, the findings highlight Egypt’s potential to competitively produce green ammonia, green iron and e-methanol for export markets. Producing green iron domestically and exporting it results in a 25% cost advantage over producing green hydrogen based DRI in the EU, primarily due to lower green hydrogen production and renewable electricity generation costs. For e-methanol, sourcing CO2 from industrial emitters yields the lowest production cost at USD 732/t MeOH, underlining the importance of accessible CO2 sources.
These findings reinforce Egypt’s potential to become a regional hub for low-carbon hydrogen and its derivatives, if investment conditions and infrastructure are strengthened. Building on this analysis, Chapter 3 assesses investment needs to scale up low-carbon hydrogen in Egypt and relevant financial solutions required to close the competitiveness gap for green hydrogen and its derivatives against fossil fuel-based counterpart in Egypt.
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← 1. As indicated earlier in the report, the OECD estimations are not derived from Egypt’s National Low-Carbon Hydrogen Strategy. Instead, they result from a technical-economic assessment based on a consistent set of assumptions. As with any such assessment, results may vary depending on underlying assumptions, including technology costs, financing conditions and operational parameters.
← 2. The 10% grid electricity share reflects the upper bound of a sensitivity analysis, not a fixed design parameter. Incorporating a limited grid contribution can significantly reduce the required installed capacity of renewables and storage, whose production and deployment carry notable embedded emissions. Although this may slightly increase operational emissions, the net impact can be a lower overall carbon footprint. The final scenario assumes only 2% grid electricity, limiting its influence on both LCOH and lifecycle emissions negligible.
← 3. This is the wholesale price announced by EgyptERA. While this reflects currently subsidised tariffs, subsidies may be phased out in the future.
← 4. The 10% system losses account for internal losses within the generation plant such as inverters, transformers, self‑consumption, etc. In scenarios with electricity transmission, additional transmission losses are included.
← 5. Methanex is the only company that produces methanol in Egypt and the plant is located in Damietta with a total annual production capacity of 1.3 Mt.
← 6. In 2023, Egypt has made a step towards establishing the country’s first green methanol production project which will include investments of about USD 450 million and produce 40 000 tonnes of green methanol per year led by Egypt’s Alexandria National Refining and Petrochemicals Company (ANRPC) and Norwegian renewable energy solutions provider Scatec in collaboration with the Egyptian Bioethanol Company (Minister of Petroleum and Mineral Resources, 2023[34]). In addition, in December 2024, Scatec ASA signed a memorandum of understanding to develop a USD 1.1 billion green methanol facility near the Suez Canal, featuring a 190-MW electrolysis plant powered by 317 MW of wind and 140 MW of solar energy, to produce 100 000 tonnes of green methanol annually by 2027 for ship bunkering.
← 7. Green methanol is produced form biomethanol (i.e. gasification of biomass and agricultural wastes) and e-methanol (i.e. CO2 captured and green hydrogen from electrolysis) (Varela et al., 2024[33]).