This Annex describes detailed technical assessment results that is presented in Chapter 2, using methodology and input data from Annex A.
Implementing the OECD Framework for Industry’s Net‑Zero Transition in Egypt
Accelerating Green Hydrogen Development
Scenario A involves setting up a co-located production hub near hydrogen demand locations, with Suez chosen as a potential site for the calculations. In this setup, hydrogen demand is met by an electrolyser powered primarily by local, dedicated PV and/or wind energy, with up to 10% of the required electricity sourced from the national grid. The analysis explores different shares of dedicated renewable energy supply (98%, 95% and 90%), with the remaining electricity (2%, 5% and10%) coming from the grid. This is significant to prevent oversized PV and wind power generation plants.
Scenario A: case without hydrogen storage
In this scenario, the analysis first considers a case without hydrogen storage. The results, shown in Figure A B.1, highlight a significant need for BESS, which decreases as grid electricity contribution increases. When the grid share rises from 2% to 10%, storage capacity requirements drop accordingly. Additionally, a higher grid contribution reduces surplus generation by allowing for smaller renewable capacity.
The optimisation process reveals that increasing grid electricity from 2% to 10% leads to a 42% reduction in optimised PV capacity and an 11% decrease in wind power generation size. In the absence of hydrogen storage, the electrolyser must operate continuously at full capacity to meet hydrogen demand. Since hydrogen demand solely determines electrolyser size, grid electricity contribution has no impact on its capacity.
Note: BESS: Battery Storage Energy System; RES: renewable energy sources.
Source: Results of the techno-economic assessment prepared by the OECD Secretariat.
Increasing the grid electricity share reduces renewable oversizing and optimises electricity storage capacity, as well as economic approach that can significantly lower the LCOH. As shown in Figure B.2 Panel 1, without selling surplus electricity, LCOH drops from USD 8.5/kg H2 (98% renewable contribution) to USD 6.8/kg H2. (95%) and USD 5.5/kg H2. (90%). If surplus electricity is sold, these values further decline to USD 7.37, USD 5.88 and USD 4.67/kg H2, respectively. The surplus electricity contribution, shown in red in Figure B.2 Panel 1, can be considered when assessing LCOH without surplus sales. In addition, grid contribution has impact on LCOE. At high RE shares, LCOE rises sharply due to the need for larger BESS capacity and oversized renewable generation. As illustrated in Figure A B.2, Panel 2, the calculated LCOE at high-RE shares is significantly higher than the assumed grid electricity price, making partial grid integration a more cost-effective approach.
Source: Results of the techno-economic assessment prepared by the OECD Secretariat.
With the rapid advancement of BESS technology and declining capital costs, a sensitivity analysis on LCOH shows that reducing BESS CAPEX to USD 200/kWh lowers LCOH of the 98% RES share from USD 7.37/kg H2 to USD 6.10/kg H2 (Figure A B.3). This also optimises the renewable energy mix, increasing PV capacity from 1.82 GW to 2.21 GW while reducing wind capacity from 2.32 GW to 1.82 GW. Additionally, BESS capacity increases by 41.8%, reducing the need for oversized renewable generation and lowering the RES/electrolyser nominal capacity ratio from 6.57 to 5.89. The decreased oversizing minimises surplus electricity production, ultimately reducing both capital and operational costs for renewables and storage, leading to a lower LCOH.
Source: Results of the techno-economic assessment prepared by the OECD Secretariat.
Scenario A: Case with hydrogen storage
The next scenario considers the use of pressurised hydrogen tanks, which optimises renewable energy utilisation by reducing the need for oversized renewable power plants while increasing electrolyser capacity. This approach helps in efficiently managing renewable energy output and enhances hydrogen production, resulting in a more cost-effective and balanced system. When excess electricity is available, the oversized electrolyser produces additional hydrogen, which is stored in pressurised tanks for use during periods of lower renewable generation under 98% share of dedicated renewable energy. The equivalent storage capacity in hours is used to compare BESS and pressurised hydrogen tanks, incorporating key efficiency and energy storage parameters into the calculations. Notably, one equivalent operating hour corresponds to 0.64 GWh of BESS or 11.4 tons of stored hydrogen, providing a clear comparison between the two storage options in terms of capacity and performance.
The LCOH decreases as hydrogen storage capacity increases, due to a gradual reduction in the size of renewable power generation plants (Figure B.4, Panel 1). Initially, this reduction is balanced by an increase in the electrolyser’s nominal capacity. However, beyond a certain threshold – when hydrogen storage exceeds one equivalent operating day – it becomes more cost-effective to reduce the electrolyser size, leveraging the larger storage capacity to ensure stable hydrogen supply. Similar trends are evident when considering only 90% of dedicated RES (Figure A B.4), Panel 2), coupling the possibility to use grid electricity with the presence of H2 storage in pressurised tanks leads to a significant reduction of the LCOH (Figure B.4, Panel 2), dropping down to 3.89 USD/kg H₂.
Panel 1: 98% RES Panel 2: 90% RES
Source: Results of the techno-economic assessment prepared by the OECD Secretariat.
Scenario A: case with the renewable nominal power to electrolyser nominal power ratio (RES/ELC)
Building on the previous analysis of hydrogen storage under Scenario A, additional assessments were conducted to evaluate the impact of the renewable nominal power to electrolyser nominal power ratio (RES/ELC). The RES/ELC ratio represents the proportion between the installed capacity of renewable power generation and the electrolyser’s nominal capacity. In all simulated cases, this ratio exceeds two, leading to an analysis of a scenario with a constrained RES/ELC ratio of 1.5 to assess its impact on the system’s performance and cost efficiency.
A constrained renewable-to-electrolyser capacity ratio (RES/ELC) of 1.5 leads to a higher LCOH, increasing from USD 4.23/kg H2 to USD 5.73/kg H2 (Figure A B.5). This is due to significant electrolyser oversizing and a substantial increase in hydrogen storage to meet constant demand. Unlike the unconstrained case, a BESS is required to maintain the electrolyser’s minimum capacity factor. These factors collectively drive-up costs, making the system less economically efficient compared to higher RES/ELC ratios.
Source: Results of the techno-economic assessment prepared by the OECD Secretariat.
Scenario A: hydrogen carrier options
The storage of hydrogen can be achieved in the form of another hydrogen carrier, such as ammonia (NH3). Several studies suggest converting green hydrogen into green ammonia, which is then stored in liquid form in refrigerated atmospheric tanks. This method, widely used in the fertiliser industry, is technically and economically feasible (Pagani, Hajimolana and Acar, 2024[1]). However, if hydrogen is the final product, additional processing via ammonia cracking is required to re-release hydrogen. While thermodynamically possible at high temperatures and catalysed, this technology is still at a low technology readiness level. Therefore, analysis focused on identifying economical storage option for hydrogen.
Regarding energy efficiencies, the pressurised hydrogen tank system achieves the highest power‑to‑hydrogen efficiency at 58.6%, followed by the BESS at 47.7% and liquid ammonia storage at 41.2%. Each hydrogen storage option has different round-trip energy efficiencies, influenced by the losses in their respective components. Notably, the hydrogen-to-hydrogen efficiency for ammonia-based storage is 67.9%, factoring in ammonia synthesis, cracking and hydrogen compression losses, which is significantly lower than the 96.3% efficiency observed in pressurised hydrogen storage systems.
Besides energy efficiency, storing hydrogen in pressurised tanks is also resulting lowest LCOH USD 4.23/kg H2 (Figure A B.6). BESS has been showing highest LCOH followed by the option of using NH3 as H2 storage vector. It is worth to note that given the high level of uncertainty arising from the low technology readiness level of NH3 cracking, the analysis of using liquid NH3 as H2 storage vector considers a sensitivity of the ammonia cracking CAPEX on the LCOH.
Note: Configuration at 98% dedicated renewable energy sources.
Source: Results of the techno-economic assessment prepared by the OECD Secretariat.
The analysis shows that storing hydrogen in pressurised tanks requires the lowest initial investment (USD 3.4 billion) compared to the other storage options. The assessment considered the initial investment required for a system capable of producing 100ktH2 (Figure A B.7).
Note: Configuration at 98% dedicated renewable energy sources.
Source: Results of the techno-economic assessment prepared by the OECD Secretariat.
Scenario B: hydrogen transport
In this scenario, green hydrogen is produced at a dedicated hub where renewable energy powers electrolysis. The hydrogen is then transported through a 230 km pipeline to Suez to demand centres. Gharib Cape is chosen as the location for this production hub. The higher availability of renewable energy in the Gharib Cape area leads to smaller renewable energy capacities and less need for storage, resulting in a significant reduction in the LCOH, even after including the hydrogen transport costs.
Under this scenario the lowest LCOH was USD 3.71/kg H2 when the storage capacity is increased, reducing the oversizing of renewable energy systems and minimising surplus electricity generation. This optimisation leads to more efficient use of renewable energy and a significant reduction in LCOH (Figure A B.8). In this optimised case, with 353 tonnes of hydrogen storage, CAPEX represents 81.6% of the LCOH. Of this, only 2.6% is attributed to the cost of the hydrogen transport pipeline.
Note: Configuration at 98% dedicated renewable energy sources.
Source: Results of the techno-economic assessment prepared by the OECD Secretariat.
The analysis in Scenario 2 demonstrates that the LCOH could be significantly reduced in the future through two combined factors: a reduction in electrolyser CAPEX and a decrease in hydrogen storage size. The anticipated decrease in electrolyser CAPEX allows for lower capacity factors and larger installed capacities, while the reduction in hydrogen storage size further contributes to cost reductions. Additionally, the ratio between the nominal power of RES and electrolyser nominal power decreases from 2.5 to 2.1. The expected drop in PV CAPEX also influences the optimal PV-wind mix determined through optimisation. These changes collectively lead to a significant reduction in the LCOH (Figure A B.9).
Source: Results of the techno-economic assessment prepared by the OECD Secretariat.
Scenario C: electricity transport
Scenario C involves decentralising electricity generation from the green hydrogen production process. Electricity is transmitted through a dedicated grid to green hydrogen production site, which is located near the demand. For this scenario, Gharib Cape is selected for power generation. The electricity is then transmitted via 230 km transmission lines to Suez, where both green hydrogen production and consumption occur.
Under this scenario, optimising the hydrogen storage capacity to 338 tonnes yields the lowest LCOH at USD 3.70/kg H2, cheaper than USD 5.54/kg H2 with no storage or USD 4.28/kg H2 with 50 tonnes of storage (Figure A B.10). When hydrogen storage is included, a slight oversizing of the electrolyser is observed. This occurs because the electrolyser needs extra capacity to handle periods of excess renewable energy generation, producing more hydrogen to fill the storage. However, as the hydrogen storage capacity increases, the electrolyser’s oversizing decreases. This is because the system becomes more flexible, allowing it to better adapt to fluctuations in renewable energy generation. The larger storage capacity helps the system manage variations more efficiently, reducing the need for an oversized electrolyser.
Note: Configuration at 98% dedicated renewable energy sources.
Source: Results of the techno-economic assessment prepared by the OECD Secretariat.
Scenario D: electricity and hydrogen transport
In this scenario, electricity generation, green hydrogen production and green hydrogen demand are in different regions, requiring both electricity transmission and hydrogen transport. Power is generated in the Aswan area and transmitted via a 525 km transmission line to Gharib Cape, where green hydrogen production occurs. The produced hydrogen is then transported through a 230 km pipeline to Suez to meet the demand.
This scenario explores the use of renewable power sources located far from a sustainable water source, requiring both electricity transmission and hydrogen transport, which adds extra costs compared to previous scenarios. Due to Aswan’s lower wind potential compared to Suez and Gharib Cape, the optimal renewable energy mix differs from the other scenarios.
Scenario D shows that increasing the percentage of dedicated RES from 90% to 100% raises the LCOH from 4.19 USD/kg H2 to 5.34 USD/kg H2 (Figure A B.11, Panel 1) due to the additional RES and H2 storage capacity required. A similar trend is observed in the analysis considering only PV power generation (Figure A B.11, Panel 2), which results in significant oversizing of the electrolyser and the need for higher hydrogen storage capacity. This results the PV-only system leads to a higher LCOH compared to a system that combines both PV and wind. For example, at 98% dedicated RES, the PV and wind scenario results in an LCOH of USD 5.63/kgH2, whereas the PV-only system reaches USD 6.76/kgH2. This difference highlights the advantage of incorporating varies RES and grid electricity to reduce RES oversizing, minimise curtailment, and lower overall costs. As in previous scenarios, the optimisation analysis continues to favour hydrogen storage in pressurised storage over BESS.
Panel 1- PV and Wind Panel 2- PV Only
Source: Results of the techno-economic assessment prepared by the OECD Secretariat.
A higher dedicated RES share increases the need for hydrogen storage to enhance system flexibility, ultimately reducing LCOH. This trend is consistent with Scenarios A and B, demonstrating that regardless of geographic location within Egypt, an optimal green hydrogen production system with 98% dedicated RES converges toward a RES-to-electrolyser nominal power ratio of 3, coupled with several tens of equivalent hours of hydrogen storage.
Note: Configuration at 98% dedicated renewable energy sources.
Source: Results of the techno-economic assessment prepared by the OECD Secretariat.
For blue hydrogen, two technologies are compared for the blue hydrogen production, namely the steam methane reforming (SMR) with post-combustion carbon capture and the autothermal reforming (ATR) with carbon capture. The analysis includes a comparison between the two plants, all having the same capacity of 100 000 Nm3/h (9 tH2/h) of hydrogen, with the CO2 to be transported for 250 km to a potential carbon capture and storage (CCS) hub.
Steam methane reforming with post-combustion carbon capture
As shown Figure A B.13 in the modelled plant includes a desulfurization section, a pre-reformer, the primary reformer, water gas shift (WGS) reactors, hydrogen purification using pressure swing adsorption (PSA) and a CO2 separation unit for the SMR furnace flue gas. SMR technology can be used to retrofit existing grey hydrogen production plants. Technical operating conditions and data are provided in Table A B.1. The simulations show an overall hydrogen production efficiency of 77.3%, with 90.2% of the carbon in the feedstock captured. The different key performance indicators (KPIs) calculated for the SMR plant with post combustion CCS are summarised in Table A B.2.
Source: Schematic representation prepared by the OECD Secretariat.
Source: Results of the techno-economic assessment prepared by the OECD Secretariat.
Note: KPIs: key performance indicators. The simulations show an overall hydrogen production efficiency of 77.3% while capturing 90.2% of the fed carbon.
Source: Results of the techno-economic assessment prepared by the OECD Secretariat.
Autothermal reforming with post combustion carbon capture
The second technology evaluated is ATR with post-combustion CCS. A typical plant setup (Figure A B.14) includes several key components: a desulfurization section, an air separation unit (ASU), a pre-reformer, an autothermal reformer, water gas shift (WGS) reactors, a CO2 separation unit and hydrogen purification using pressure swing adsorption (PSA). This analysis assumes the construction of a new hydrogen production plant. Technical details and input data can be found in Annex A. The simulation results show an overall hydrogen production efficiency of 73.5%, with 93.8% of the carbon in the feedstock captured.
Source: Schematic representation prepared by the OECD Secretariat.
Blue hydrogen LCOH analysis
The two different technologies are compared to a commercially available grey hydrogen production plant using SMR technology without CCS. For CO2 transport, two scenarios are considered: constructing a new pipeline and retrofitting existing assets. The computed LCOH for the benchmark plant at the same operating conditions reported in without considering CO2 separation is USD 1.40 /kgH2.
Considering the hypothetical case without the added cost of CO2 transport, the LCOH increases to USD 1.82/kgH2 and USD 1.81/kgH2 on considering the SMR with CCS and the ATR with CCS technologies respectively. The calculated LCOH increases by USD 0.28 /kgH2 and 0.81 USD/kgH2 for retrofitting of existing pipelines and the construction of new pipeline respectively. It is worth mentioning that the assumed cost of the CO2 transport pipeline does not depend on the amount of CO2 transported, which could lead to discrepancies in the results. The LCOH for the simulated cases is shown in Figure A B.15.
While both SMR with CCS and ATR with CCS technologies yield comparable LCOH, ATR with CCS demonstrates a slight advantage over SMR with CCS in terms of economic efficiency. Both SMR with CCS and ATR with CCS technologies result in a higher LCOH compared to the benchmark plant without CO2 separation, primarily due to the added costs of CO2 capture and transport. Specifically, the LCOH increases to USD 1.82 /kg H2 for SMR with CCS and USD 1.81 /kg H2 for ATR with CCS when considering the CO2 capture. Furthermore, when CO2 transport is included, the calculated LCOH increases by USD 0.28 /kgH2 for retrofitting existing pipelines and by USD 0.81 /kg H2 for constructing a new pipeline. The assumed cost of the CO2 transport pipeline, which does not depend on the amount of CO2 transported, could result in discrepancies in the results, highlighting the importance of accurate cost assumptions in evaluating overall economics.
Source: Results of the techno-economic assessment prepared by the OECD Secretariat.
Blue hydrogen cost of CO2 avoided
The cost of CO2 avoided (CCA) for the two technologies, SMR with CCS and ATR with CCS, also favours ATR. The CCA analysis is instrumental in assessing both the environmental and economic benefits of CO2 capture and storage. This analysis plays a vital role in determining the cost-effectiveness of implementing CCS in blue hydrogen production and comparing it to other emission-reduction technologies. The findings indicate that ATR offers a slight economic advantage, whether retrofitting an existing pipeline or constructing a new CO2 pipeline, as its CCA is lower than SMR in both cases (Figure A B.16).
Source: Results of the techno-economic assessment prepared by the OECD Secretariat.
Blue hydrogen initial investment required for production per different technology choices
The high upfront investment required for both technologies was assessed, with the results consistently favouring ATR with CCS. The calculated initial investment for an SMR with CCS plant is USD 522.9 million, while for an ATR with CCS, it is USD 517.4 million. The breakdown of the initial investment for both simulated plants is shown in Figure A B.17. Additionally, the estimated investment for retrofitting a 250 km pipeline is USD 75 million, which increases to USD 302.5 million if a new pipeline is constructed.
Source: Results of the techno-economic assessment prepared by the OECD Secretariat.