Chapter 3 estimates that scaling Egypt’s green hydrogen sector to achieve a production capacity of 1.5 Mt per year is estimated to require approximately USD 46 billion in cumulative investment between 2025 and 2030. To help attract this investment and the related financing need, an investor survey was conducted to identify effective financial solutions that comprise a suite of economic and de-risking instruments such as CAPEX grants, green premiums, carbon price, foreign exchange guarantees, offtake guarantees and concessional loans. Building on the survey results, further analysis and stakeholder consultations identified a blended approach – prioritising CAPEX grants and concessional loans – as the most practical and cost-effective option for scaling green hydrogen and its derivatives. In addition, Contracts for Difference (CfDs) emerge as a critical instrument for providing offtake certainty in uncertain market conditions.
Implementing the OECD Framework for Industry’s Net‑Zero Transition in Egypt
Abstract
Based on the cost competitiveness analysis of green hydrogen and its derivatives compared to fossil fuels counterparts (Chapter 2), this chapter aims to assess viable financial solutions and enabling investment conditions that can reduce this cost-competitive gap. To ensure their applicability in Egypt, the chapter assesses: (i) the required infrastructure for green hydrogen production in Egypt, including transmission grid and green hydrogen pipelines; (ii) investment needs required to fulfill Egypt’s National Low-Carbon Hydrogen Strategy targets; and (iii) the relevant economic or de-risking instruments identified based on discussions with key stakeholders, including industry representatives, policymakers, investors and international partners.
3.2.1. Renewable energy and battery energy storage systems
Deploying additional renewable energy capacity is critical to unlock green hydrogen production in Egypt. As discussed in Chapter 1, Egypt aims to improve its regulatory framework and enabling environment to encourage green investment, notably in renewable energy projects (i.e. Benban Solar Park expansions, ACWA Power’s 2 GW wind farm, AMEA Power’s 1 GW solar project, and the Masdar-led 10 GW wind farm). Battery Storage Energy Systems (BESS) help mitigate the intermittency of solar and wind power generation by storing excess energy during peak production for later use. This enables more stable and efficient electrolyser operation, reduces reliance on grid power and avoids the need to oversize renewable energy capacity, ultimately reducing the LCOH (Kwon et al., 2024[1]). Deployment of renewable energy and BESS can ensure consistent and reliable renewable power supply, lowers the LCOH and enhances the overall economic viability and efficiency of green hydrogen production, making it a more competitive and scalable solution for decarbonising various sectors.
Recent project developments in Egypt indicate a clear preference for integrating BESS with large-scale renewable energy projects. AMEA Power is actively developing major standalone BESS projects (totalling 1.5 Gigawatt-hour [GWh] across Zafarana and Benban) alongside solar-plus-storage initiatives, including a 1 GW solar project paired with 600 MWh of BESS in Benban and a 500 MW solar expansion at Abydos with 300 MWh of BESS (Colthorpe, 2025[2]). Similarly, Scatec is progressing with a 1 GW solar project combined with a 100 MW/200 MWh BESS (Scatec, 2025[3]). These investments demonstrate a strategic move to stabilise the grid and enhance the reliability of intermittent renewable energy sources, both of which are essential for supporting a steady and cost-effective power supply for developing green hydrogen electrolysers in the future.
3.2.2. Transmission grid and hydrogen pipelines
Transmission grid
Unlocking transmission grid capacity and investment is critical to ensure grid-scale renewable integration and green hydrogen production in Egypt (Denis, 2026[4]). To support Egypt’s growing generation capacity in line with its renewable and clean energy targets for its power mix – 42% by 2030 – as well as the deployment of green hydrogen projects requiring between 19 GW and 41 GW of installed renewable energy capacity (as outlined in the National Low-Carbon Hydrogen Strategy), EETC is actively expanding and modernising the high-voltage grid infrastructure. In 2020 alone, EETC allocated approximately EGP 7.7 billion to improve network efficiency and reduce transmission losses (United Nations Economic Commission for Africa, 2023[5]). The MoERE developed a USD 2 billion investment programme to 2028 to strengthen the transmission network and enhance grid stability as the system shifts to a new model based on increasing volumes of intermittent renewable energy (EBRD, 2024[6]). Concurrently, the government is advancing the reform of distribution utilities and promoting private sector investment to further enhance the sector’s performance. Several business and financing models for transmission grid investment – for supporting grid-scale renewable power integration and other objectives – are discussed, along with as the challenges and unique conditions for unlocking transmission grid investment in Egypt. These insights are based on their implementation experiences in four different countries as presented in Transmission grid financing: international case studies for Egypt1 (Denis, 2026[4]).
Given Egypt’s abundant renewable energy resources, a key strategy to optimise green hydrogen costs involves reinforcing the national grid capacity. This is a way not just to accommodate the variability of solar and wind energy by improving system-wide flexibility of its power sector, but also to transmit power from renewable energy resource areas to energy demand centres (Chapter 2). For the specific case of green hydrogen production, a strong grid system can improve cost-effectiveness by enabling the grid to absorb surplus electricity and drawing power from the grid when needed, which prevents oversizing of renewable energy generation solely for hydrogen production. Simultaneously, developing regional energy trade infrastructure is crucial for mitigating renewable energy curtailment and intermittency, thereby improving power system flexibility. By facilitating the export of excess renewable power and allowing for energy exchange with neighbouring countries, Egypt can ensure greater utilisation of its renewable assets, thereby improving the reliability of renewable electricity supply for green hydrogen production and enhancing the overall economic viability of the sector. This aligns with recent developments, most notably the planned 2 GW Euro-Africa interconnection through Cyprus and Greece, which will enhance regional energy integration. While natural gas remains the primary source of electricity generation in Egypt, cross-border electricity trade is gaining momentum. For instance, the Egypt-Sudan grid connection is expected to reach a capacity of 300 MW upon full completion. These efforts are part of Egypt’s broader strategy to export up to 20% of its electricity production (Hamilton, 2021[7]).
Hydrogen pipelines
Repurposing gas pipelines to support hydrogen transport can support green hydrogen production in Egypt. This potential for interconnection and export is closely linked to Egypt’s well established gas infrastructure. While Egypt is accelerating its green transition, the country still relies heavily on fossil fuels, with natural gas accounting for 53% of energy supply in 2022/2023, of which 27% is used in the industrial sector (the highest consumption was in fertiliser and methanol) (Arab Republic of Egypt, 2025[8]). The Egyptian Natural Gas Company (GASCO) operates the gas grid with a total length of 22 000 kilometres (Development Aid, 2023[9]). Egypt’s national Low-Carbon Hydrogen Strategy acknowledges the potential for blending up to 20% hydrogen into the existing natural gas grid with minimal infrastructure modifications (HyWay 27, 2021[10]) which equates to 11 million tonnes of hydrogen per year. While Egypt does not have an extensive hydrogen pipeline to export hydrogen, this could serve as an initial step to integrate hydrogen into industrial and energy sectors, utilising the existing pipeline infrastructure for hydrogen transport over shorter distances to industrial clusters. According to the European Network of Transmission System Operators for Gas (ENTSOG), there is significant opportunity to reduce hydrogen infrastructure investment costs by 50% to 80% through the strategic repurposing of existing natural gas pipelines. However, other analyses highlight critical concerns regarding the integrity of repurposed pipelines for hydrogen transport, particularly due to risks such as hydrogen embrittlement, leakage, combustion and explosion (Li, Song and Zhang, 2024[11]). Therefore, hydrogen-mixed natural gas pipelines must be carefully assessed to ensure safety and reliability.
Currently, there are about 70 ongoing retrofitting/repurposing gas pipeline projects to ensure gas infrastructure can support hydrogen transport in Europe, with potential to integrate Egypt’s future hydrogen supply into the European market (European Parliament, 2024[12]). The development of major hydrogen transport corridors like H2MED (connecting the Iberian Peninsula and France, with potential links to Germany) and the SoutH2 Corridor (aiming to connect North Africa, including Algeria and potentially Tunisia, to Italy, Austria and Germany) further underscore the strategic importance of leveraging existing gas infrastructure. The potential to integrate Egypt’s future hydrogen supply into the European market via these emerging corridors is significant. Direct interconnection via new or repurposed pipelines, or indirect connection through North African partners in the SoutH2 Corridor, could provide a pathway for Egypt to export its green hydrogen to meet European demand. The EU hydrogen and gas decarbonisation package, adopted in May 2024, is expected to provide momentum for the development of hydrogen infrastructure (European Commission, 2025[13]).
3.2.3. Electrolyser
Electrolyser is a critical technology to produce green hydrogen from renewable electricity. Global electrolysis capacity for dedicated hydrogen production has been growing in the past few years, reaching an installed capacity of 1.4 GW at the end of 2023 (IEA, 2024[14]). Moreover, electrolyser manufacturing capacity has doubled since 2022, reaching 25 GW per year by the end of 2023. The electrolyser market is currently dominated by a few key players. In 2024, about 68% of global electrolyser manufacturing capacity was located in China with manufacturing capacity to GW electrolyser (BloombergNEF, 2024[15]). However, in terms of track record of reliable technology performance, only a limited number of green hydrogen projects globally have shown reliable results, typically over operational periods of approximately three years or less. In Egypt, there is currently no domestic electrolyser manufacturer or onshore manufacturing plant. Electrolysers are mainly imported from European manufacturers such as a recent shipment of a 5 MW electrolyser module by Plug Power to Fertiglobe in Ain Sokhna, Egypt. This initial module is part of a larger 100 MW project under the Egypt Green initiative, a consortium involving the Sovereign Fund of Egypt, Fertiglobe (OCI and ADNOC), Scatec and Orascom Construction (OCI, 2021[16]).
3.2.4. Desalination
Access to purified water is a critical enabler for green hydrogen production, as electrolysis – the primary method for producing green hydrogen requires large volumes of purified water as an input. In regions with limited freshwater availability, such as Egypt, desalination infrastructure plays a pivotal role in securing the water supply needed to scale up hydrogen production. Egypt has significantly expanded its desalinated water infrastructure, with 125 desalination plants across six governorates: North Sinai, South Sinai, Red Sea, Matrouh, Ismailia and Suez (Daily News Egypt, 2025[17]). These operational plants collectively contribute with a total capacity of 1.31 million m3 per day. Within current installed capacity, there are two desalination plants in Suez with approximately 286 000 m3 per day, which is approximately 31% of Egypt’s current desalination plant capacity and where most announced green hydrogen projects are located (Elsaie et al., 2023[18]). The current cost structure indicates an average desalination expense range between USD 0.7 (Elsaie et al., 2023[18]) and USD 1.6 (Wahish, 2022[19]) per m3, a crucial economic factor influencing the feasibility and scalability of future projects. Within the Suez Canal Zone, the port authority aims to construct additional desalination plants to have a production capacity of around 250 000 m3 per day with support from EBRD to support hydrogen production (Smart Water Magazine, 2024[20]).
3.2.5. Port infrastructure for export of low-carbon hydrogen and its derivatives
Developing adequate port infrastructure is paramount for the successful export of green hydrogen and its derivatives. This necessitates the construction of specialised terminals and berths capable of handling vessels designed for liquid hydrogen, ammonia or methanol, along with new jetties to accommodate large carriers (as seen in projects like the Ras Shukeir green ammonia terminal). Substantial investment in dedicated, safe storage facilities for these carriers, considering their specific properties like cryogenic temperatures (U.S. Department of Energy, 2025[21]) or toxicity, is essential, alongside buffer storage to manage production and shipping variations. Efficient handling and loading/unloading equipment, including specialised marine loading arms (FCW, 2024[22]) and robust pumping/compression systems, will be required (Notteboom and Haralambides, 2023[23]). Ports may also house optional but likely on-site conversion facilities such as liquefaction plants for liquefied hydrogen (LH2) and synthesis or cracking/reforming plants for ammonia and methanol to facilitate both import and export (UNCTAD, 2024[24]). Seamless integration with inland transportation networks, including pipelines, road and rail is needed to ensure efficient distribution. Finally, establishing bunkering infrastructure for green ammonia and methanol will capitalise on the growing demand for sustainable maritime. in 2024, Egypt signed a memorandum of understanding with the Port of Rotterdam to further strengthen necessary infrastructure investment to upgrade its port to export hydrogen or hydrogen derivatives.
While the previous section highlights the substantial infrastructure investment required to scale up green hydrogen in Egypt, this section offers an estimate of investment needs to meet the targets of Egypt’s National Low-Carbon Hydrogen Strategy, based on two selected scenarios from Chapter 2. To determine the level of investments needed to achieve the production target of the National Low-Carbon Hydrogen Strategy, this report uses the conservative scenario from the national strategy, targeting 1.5 Mt/year green hydrogen production capacity by 2030.2 Scenarios B and C are evaluated, as they demonstrated the lowest LCOH while assuming a 2% national grid-connected electricity share (Figure 3.1). The same assumptions outlined in Chapter 2 are applied, including for the CAPEX of various components of the green hydrogen plant configurations.
Note: H2: hydrogen; HVDC: High Voltage Direct Current.
Source: Results of the techno-economic assessment prepared by the OECD Secretariat.
Analysis shows that considering the central scenario of Egypt Green Hydrogen strategy to achieve production capacity of 1.5 Mt/year by 2030, USD 45.6 billion needs to be invested with high initial investment requirement in electrolyser and renewable energy systems. Scenario B is found to be somewhat less investment intensive due to higher availability of renewable energy sources (i.e. higher capacity factors) as presented in Figure 3.1. While electricity transmission infrastructure is less expensive than hydrogen transport infrastructure, this cost advantage does not fully offset the solar PV installation costs associated with Scenario C. Nonetheless, the overall cost differences are relatively modest and installation decisions may ultimately depend on additional factors such as safety, operational management and regulatory considerations.
The key difference between two scenarios lies in how energy is managed over time. Greater storage capacity or a more robust grid connection provides more flexibility in utilising renewable energy sources, which can lead to minor adjustments in the optimal RES mix (e.g. a slightly higher proportion of solar PV in one scenario). The system components were sized to ensure continuous production of 1.5 Mt/year of green hydrogen. As detailed in Annex C, the analysis indicates that storage needs and grid connections differ between the scenarios, while the installed capacity of renewable energy plants and electrolysers shows only minor variations (+17% for PV, with wind and electrolysis capacity remaining stable). Essentially, both scenarios are designed to produce the same amount of hydrogen. Therefore, the total energy input required from RES and the size of the electrolyser to process that energy will be broadly similar. Annex C provides a detailed breakdown of this assessment.
The OECD, with support from the Federation of Egyptian Industries (FEI), undertook an investor survey to identify the necessary financial solutions for closing the competitiveness gap in green hydrogen. Because low-carbon hydrogen projects are not yet widely implemented, it is difficult to identify and assess the effectiveness of frequently employed economic and de-risking instruments designed to mitigate risk (OECD/The World Bank, 2024[25]). Given the limited track record of large-scale green hydrogen projects, the analysis extended to examining instruments previously deployed in other asset types, namely LNG, offshore wind, thermal power and grey hydrogen. The following criteria were considered to select instruments for further investigation (OECD/The World Bank, 2024[25]):
Amount of private investment mobilised and leverage ratio of public finance used.
Proven track record or implementation globally (where data on single instruments was preferred, as it gives a better understanding of their replicability potential, compared to complex packaged risks which may be specific to a given project structure).
Proven impact on financing costs if project level information is available (e.g. in a very few cases the improvement of the debt-service coverage ratio [DSCR] and its positive on debt sizing has been considered.
Egyptian stakeholders were surveyed to prioritise a list of instruments relevant to the country’s green hydrogen projects. The survey comprised three principal sections designed to elucidate investment in and financing of green hydrogen initiatives. The initial section aimed to categorise the organisations active in the hydrogen sector. The subsequent section investigated the current and anticipated investment allocations of these organisations within Egypt’s hydrogen value chain, encompassing clean energy sources, hydrogen production, storage, transportation, utilisation and vertically integrated projects, as well as their typical investment scales. The final section explored potential financial instruments to enhance the fundability of green hydrogen projects in Egypt. Annex D provides the survey methodology and questionnaires.
Economic instruments,3 including auctions and CfD, carbon credits, carbon taxes and emissions trading systems, carbon removal certificates, extended producer responsibility fees, grants and subsidies, green procurement incentives and tax credits.
De-risking instruments,4 such as buyer credit guarantees, contractors-all-risk insurance, credit default swaps, foreign currency guarantees, interest rate swaps, loan loss reserves, offtake guarantees, partial credit guarantees, performance guarantees, political risk investment insurance and subsidised or performance-linked loans.
The survey identified priority instruments, categorised as: (i) economic instruments, including carbon pricing and green procurement, along with direct financial support such as grants and subsidies; and (ii) de-risking instruments, encompassing foreign currency guarantees, offtake guarantees and political risk guarantees (Figure 3.2). However, the number of survey responses was limited (14 out of 66 identified stakeholders), and the results should therefore be interpreted with caution.
Note: The survey was distributed to 66 stakeholders between 30 January and 27 February 2025, with 14 completed responses. The survey methodology and results are available in Annex D. CfD: contracts for difference; CO2: carbon dioxide; EPR: extended producer responsibility; ETS: emission trading system.
Source: Key findings from the OECD investors survey conducted by the OECD Secretariat.
Based on the survey results, the following economic and de-risking instruments were identified: carbon pricing, CAPEX grant, green premium (as proxy to green procurement5), FX guarantee, offtake guarantee and concessional loans to assess its effectiveness on closing competitiveness gap. The competitiveness gap refers to the difference between the estimated LCOH and the price of USD 1.8/kg H2 by 2040 as envisioned in Egypt’s National Low-Carbon Hydrogen Strategy.
FX risk mitigation and offtake guarantees were identified as important instruments from the survey, but they were excluded from the impact assessment scope in this chapter. Assessing the impact of FX guarantees was challenging due to the limited availability of project-level data on actual hedging costs and the highly context-specific nature of currency exposure. These factors constrained the application of a consistent quantitative methodology across all instruments. Similarly, offtake guarantees are more closely linked to the broader investment climate and the maturity of green hydrogen markets. As such, their direct quantitative impact on narrowing the competitiveness gap could not be reliably captured within the applied assessment framework.
Instead, both instruments are discussed in Chapter 4 within the broader analysis of financial solutions and enabling investment conditions, where their potential applications are examined in the context of Egypt’s green hydrogen market. Their contribution to reducing perceived investor risk and enhancing project bankability is assessed qualitatively, reflecting local market dynamics and institutional realities. This approach is further informed by expert interviews with practitioners actively involved in Egypt’s green hydrogen sector.
As a result, the following instruments were selected for detailed impact assessment: carbon pricing, green premium, CAPEX grants and concessional loans while the latter also providing partial insights into the role of guarantees (Box 3.1). These instruments were then evaluated to assess their effectiveness in closing the competitiveness gap between green hydrogen (or its derivatives) and fossil-based alternatives.
While the analysis focuses on the impact of concessional loans – modelled through adjusted discount rates – it is important to recognise that guarantees can achieve a similar outcome in improving the competitiveness of green hydrogen relative to grey hydrogen. By mitigating specific project risks, guarantees can lead to more favourable financing conditions, such as lower interest rates, effectively reducing the cost of capital. Although guarantees and concessional loans differ in their financial structures, the reduction in the discount rate observed under concessional lending can serve as a reasonable proxy for the potential impact of guarantees on project valuation and competitiveness.
However, the actual impact of a guarantee on the discount rate depends on factors such as the scope of risk coverage, market perceptions and the credibility of the guarantor. Moreover, the fees or costs associated with obtaining guarantees must be taken into account, as they may partially offset the financing benefits. For instance, the cost of guarantees can typically vary per coverage, credit rating of applying entities and project structure. They are typically priced as an annual premium range from 0.2‑3% in the case of partial credit guarantees (PCGs) (SystemIQ, 2023[26]). It is also important to note that guarantees may offer additional strategic benefits, such as attracting private capital or enabling participation in riskier markets, that are not fully captured through a simple discount rate adjustment.
While discount rate adjustments provide a useful lens for approximating the financial impact of guarantees, the indirect nature of this modelling approach requires careful interpretation. Assumptions should be clearly stated. Where feasible, complementary analysis should also explore the broader implications and costs of deploying guarantees to better inform financing strategies for green hydrogen projects.
3.5.1. Green premium
A green premium is the price differential reflecting the extra cost associated with producing or purchasing lower-carbon product or service relative to its traditional counterpart (CRU Group, 2023[27]). This analysis evaluates the financial benefits of applying a green premium to the selling price of green hydrogen, methanol and steel, reflecting their lower carbon footprint compared to conventional production. Two green premium scenarios – 15% and 30% above the total production cost – are considered, and the study evaluates how the share of green product sales achieved at these premium prices impacts overall economic viability. The green premium acts as a potential revenue enhancer for green producers, aiming to close the cost gap with fossil fuel-based alternatives.
Willingness to pay (WtP) varies significantly across sectors, with stronger demand observed for green steel (Eurometal, 2024[28]) and increasing momentum for green fuels in hard-to-abate sectors such as aviation (BCG, 2025[29]). These differences in WtP reflect how the value of the green premium is perceived across end-use markets and determine its potential as a revenue-enhancing mechanism. These sectoral differences in WtP directly influence the effectiveness and viability of green premium strategies as a tool for closing the competitiveness gap. WtP for green premium could be triggered by multiple aspects. At the industry or company level, players often driven by company’s ESG mandate, sectoral net-zero target, ambition to reduce Scope 3 emission, as well as to obtain stronger market share in green export markets to advance company’s reputation (Shi and Jiang, 2022[30]). The green premium could be also triggered by regulatory instruments such as carbon pricing, green public procurement mandates, border carbon adjustment mechanisms, and low-carbon product certification schemes, which reinforce market differentiation (Bryant, 2023[31]). Uptake varies across sectors. For example, buyers of green steel (OECD, 2023[32]) may show higher WtP than construction firms, while interest in green fuels is growing in hard-to-abate sectors like aviation and shipping.
3.5.2. CAPEX grant
CAPEX grants and subsidies are prominent and frequently discussed economic instruments for advancing hydrogen deployment at project level. For instance, Scatec’’s green hydrogen project in Egypt, with a total CAPEX of around EUR 500 million, received a EUR 30 million grant from the German PtX Development Fund (Markosyan, 2024[33]), highlighting the role of development co-operation in mitigating risks associated with significant investments. Similarly, the EU Innovation Fund provided Elcogen in Estonia with a EUR 24.9 million grant to scale up its production of solid oxide electrolyser cells, a critical component in green hydrogen production, directly supporting the capital investment needed for expansion. National initiatives like the UK’s Net Zero Hydrogen Fund also feature dedicated CAPEX support, offering grants up to GBP 30 million to cover a significant portion of the initial costs for new low-carbon hydrogen facilities. In addition, the European Hydrogen Bank also extends CAPEX support, underscoring the multifaceted approach to financially backing green hydrogen deployment. These instances collectively illustrate the crucial role of CAPEX grants in mitigating the high initial investment barriers associated with green hydrogen projects and accelerating their realisation.
The CAPEX grant leads to a decrease in the LCOH, thus narrowing the competitiveness gap with fossil‑based products. As such in this analysis, three cases are evaluated: (1) Grant to cover percentage of the total CAPEX, (2) to cover percentage of the RES CAPEX, (3) to cover percentage of the electrolyser CAPEX.
3.5.3. Concessional loans
Concessional loans (inclusive to subsidised loan) are emerging as a significant financial instrument to support the capital-intensive development of hydrogen projects. These loans, characterised by favourable terms such as lower interest rates and extended repayment periods, aim to reduce the overall cost of capital for developers, thereby enhancing the economic viability of hydrogen initiatives. For instance, the EBRD provided a concessional loan as part of a larger financial package for a green hydrogen pilot facility in Uzbekistan (EBRD, 2024[34]), specifically to help decarbonize fertiliser production and power generation. Similarly, the Green Climate Fund (GCF) has offered concessional financing to support IFC’s investment in a green hydrogen and battery storage project in Barbados, aiming to lower electricity tariffs and enhance grid resilience. These examples highlight how concessional loans from development banks and climate funds are being strategically deployed to mitigate risks of early-stage hydrogen projects and make them more attractive to investors, ultimately contributing to developing a nascent green hydrogen economy. To evaluate the effect of concessional financing on project feasibility and investment attractiveness, a sensitivity analysis is conducted on the discount rate, which reflects the cost of the capital. A lower discount rate, representing the terms of a concessional loan, enhances the economic appeal of the investment.
3.5.4. Carbon price
A carbon price – whether through a carbon tax or an emissions trading system (ETS) – would primarily affect industrial users of fossil-based hydrogen and its derivatives, particularly in the fertiliser, chemical and steel sectors by increasing their OPEX. This is due to the high emission intensity of grey hydrogen production (approximately USD 10 kg CO2/kg H2). In Egypt, the estimated cost of grey hydrogen is around USD 1.8/kg H2, which is also the price for green hydrogen envisioned in Egypt’s National Low-Carbon Hydrogen Strategy by 2040.
Grey methanol production emits around 0.8 tonnes of CO2 per tonne of methanol (Zaryab et al., 2024[35]), while traditional steelmaking via the BF-BOF route emits approximately 1.84 t CO2 per tonne of iron, compared to around 1.44 t CO2 for gas-based DRI (Rhee et al., 2024[36]) (Box 3.2). These emission intensities mean that carbon pricing would directly affect cost structures in these sectors, influencing their competitiveness and their incentive to shift to low-carbon alternatives.
In this context, the EU CBAM is particularly relevant. Designed to prevent carbon leakage, CBAM imposes a carbon cost on imports of high-emission goods such as iron, steel, fertilisers and hydrogen (Dechezleprêtre et al., 2025[37]). For exporters like Egypt, CBAM introduces a compliance cost that reinforces the economic rationale for adopting low-carbon production pathways. In sectors such as steel, fertilisers and petrochemicals, aligning with low-emission standards is becoming essential to maintain access to the EU market and avoid potential trade-related risks. This externally induced regulatory shift underscores the strategic importance of accelerating the transition to green hydrogen in Egypt as a means to safeguard competitiveness and secure long-term market opportunities.
However, the implementation of carbon pricing in Egypt poses considerable political economy challenges. Egypt currently levies no explicit carbon tax, and fuel excise taxes apply to only about 53% of GHG emissions (OECD, 2023[38]). Moreover, fossil fuel subsidies remain significant, covering roughly 7% of emissions and resulting in a net effective carbon rate of EUR 6.47 per tonne of CO2 (OECD, 2023[38]), indicating that subsidisation outweighs taxation. These distortions suppress the price signals needed to drive low-carbon investment.
From the perspective of industrial users, particularly in energy- and trade-intensive sectors who benefit from subsidised energy prices, passing through the cost of carbon could undermine their competitiveness in both domestic and export markets. Moreover, extending carbon pricing to residential or transport sectors raises equity concerns, as this may disproportionately impact vulnerable households (Carnegie Endowment for International Peace, 2025[39]). Therefore, any carbon pricing mechanism must be accompanied by social safeguards and mechanisms for revenue recycling.
The impact assessment on the competitiveness gap indicates that full CAPEX grants consistently emerge as the most effective instrument to bridge the cost gap between low-carbon products (such as green hydrogen, green ammonia, green iron and e-methanol) and their conventional fossil-based counterparts. To ensure alignment with Egypt’s National Low-Carbon Hydrogen Strategy – which targets a production capacity of 1.5 Mt H2 per year – an optimisation modelling was undertaken. This model was based on the LCOH from Scenario B, which yielded the lowest production cost in the previous analysis (Chapter 2). Under these assumptions, the estimated hydrogen production cost was calculated at USD 4.14/kg H2 (Table 3.1).
Source: Results of techno-economic assessment conducted by the OECD Secretariat.
With a calculated LCOH of USD 4.14/kg H2 for green hydrogen and an estimated cost of USD 1.8/kg H2 for grey hydrogen in Egypt (a target aligned with the National Low-Carbon Hydrogen Strategy); the initial competitiveness gap stands at around USD 2.34/kg H2. The following analysis assesses how instruments such as carbon prices, concessional loans, green premiums and CAPEX grants can narrow this identified USD 2.34/kg H2 difference.
Competitiveness gap
Note: CAPEX: capital expenditure: CO2: carbon dioxide; H2: hydrogen; RES: renewable energy sources
Source: Results of the techno-economic assessment conducted by the OECD Secretariat.
The analysis revealed the following results:
Green premium: Even with a substantial 30% green premium applied to all green hydrogen sales, this financial instrument alone is insufficient to bridge the competitiveness gap.
CAPEX grant: Closing the competitiveness gap would require a CAPEX grant covering approximately 70% of the total investment. While a CAPEX grant specifically targeting renewable power generation significantly reduces the competitiveness gap, it is not sufficient on its own to fully close the gap. Similarly, providing a CAPEX grant for electrolysers decreases significantly the competitiveness gap, reducing it from USD 2.34/kg H2 to USD 1.36/kg H2. However, securing a consistent and widespread 70% CAPEX subsidy for green hydrogen projects may be economically and politically challenging for governments. Current international practices reflect a more measured approach: the UK Net Zero Hydrogen Fund offers CAPEX grants covering up to 30% of eligible costs; the EU Innovation Fund typically supports 40-60% of the incremental costs for innovative low-carbon technologies, including hydrogen; and the German PtX Development Fund’s contribution to Scatec’s Egypt project covers about 6% of total CAPEX. These examples illustrate the broader policy trend of balancing early-stage support with the goal of establishing a competitive, self-sustaining green hydrogen sector without excessive reliance on public funding.
Concessional loans: Reducing the discount rate from 10% to 2% through concessional loans is shown to significantly narrow the competitiveness gap from USD 2.34 to USD 0.6/kg H2.
Carbon price: A carbon price of USD 230/t CO2 is projected to eliminate the competitiveness gap, raising the market price of grey hydrogen to USD 4.14/kg. Impact of instruments on e-methanol and green iron.
In addition to previous assessment on green hydrogen, the same assessment has been conducted for green derivatives. An indicative recent market price for grey methanol in Europe is USD 550/t MeOH (Methanenx, 2025[40]) while green e-methanol is expected to be around USD 1 150/t MeOH. The competitiveness gap for methanol is determined by the difference between the LCOM of e-methanol and the indicative market price of grey methanol.
Competitiveness gap
Note: CAPEX: capital expenditure: CO2: carbon dioxide; MeOH: methanol; RES: renewable energy sources.
Source: Results of the techno-economic assessment conducted by the OECD Secretariat.
The analysis revealed the following results:
Green premium: With a 30% green premium across all produced e-methanol, a substantial competitiveness gap of USD 256/t MeOH persists, indicating that this instrument alone has a limited effect in making green hydrogen cost-competitive.
CAPEX grant: Addressing the competitiveness gap for e-methanol would necessitate a full CAPEX grant. The analysis of targeted grants shows that covering the initial investment in renewable energy power generation reduces the gap from USD 601/t MeOH to USD 268/t MeOH. In contrast, a grant for the electrolyser CAPEX alone lowers the gap to USD 421/t MeOH only.
Concessional loans: Reducing the discount rate via concessional loans from 10% to 2% is shown to have a considerable impact on the e-methanol competitiveness gap, bringing it down from USD 601/t MeOH to USD 292/t MeOH.
Carbon price: A carbon price, even at a substantial level of USD 300/tCO2, is insufficient to close the competitiveness gap for methanol despite a reduction in the cost of e-methanol from USD 601/t MeOH to USD 352/t MeOH.
For green iron, the LCOI for production in Egypt is estimated at USD 733/t DRI (Chapter 2). The competitiveness gap with BF-based grey iron is estimated at USD 174/t DRI while for methane DRI a competitiveness gap of USD 132/t DRI is estimated, assuming that the cost of BF-based iron and methane DRI are USD 670/t DRI and USD 720/t DRI.
Competitiveness gap
Note: BF-BOF: blast furnace - basic oxygen furnace; CAPEX: capital expenditure: CO2: carbon dioxide; DRI: Directed Reduced Iron; RES: renewable energy sources.
Source: Results of the techno-economic assessment conducted by the OECD Secretariat.
The analysis revealed the following results:
Green premium: When applying a 15% premium on all the produced DRI, a significant competitiveness gap of USD 65/t DRI remains. A premium of 30% could potentially bridge the gap given that 80% of the produced DRI is sold at the premium price.
CAPEX grant: A full CAPEX grant for green iron production is required to achieve cost competitiveness. Focusing on specific components revealed that a grant for renewable energy power generation CAPEX reduces the gap from USD 174/t DRI to USD 63/t DRI, whereas a grant for electrolyser CAPEX lowers it to USD 123/t DRI.
Concessional loans: A reduction in the discount rate from 10% to 2% via concessional loans is shown to considerably narrow the competitiveness gap for green iron, from USD 174/t DRI down to USD 83/t DRI.
Carbon price: A carbon price of about USD 90/tCO2 would allow closing the competitiveness gap for green iron compared to BF route. A higher carbon price of USD 110/t CO2 is needed to close the gap with natural gas DRI.
CAPEX grants and concessional loans are the most effective instruments, reducing the cost gap by up to 70-90% across green hydrogen, e-methanol and green iron (Table 3.2). In contrast, green premiums and carbon pricing alone are insufficient to fully close the competitiveness gap.
Source: Results of the techno-economic assessment conducted by the OECD Secretariat.
While the instruments show the potential viability to closing the competitiveness gap,6 practical implementation remains constrained. Effectively addressing this constraint necessitates a strategic combination of various instruments to optimise cost burden and de-risk the project (Lee and Saygin, 2023[41]; OECD/The World Bank, 2024[25]). For instance, a combined strategy prioritising CAPEX grants and concessional loans, supplemented by moderate carbon pricing or market-based incentives, offers the most pragmatic and effective approach to scale up green hydrogen, e-methanol and green iron competitively (Box 3.2).
Numerous combinations of the analysed instruments can be employed to bridge the cost gap between green and grey hydrogen. The results presented here illustrate one potential combination of multiple instruments for closing the competitiveness gap and do not necessarily represent an absolute optimum solution.
Note: CAPEX: capital expenditure; CO2: carbon dioxide; H2: hydrogen.
Source: Results of the techno-economic assessment conducted by the OECD Secretariat.
Building on the survey findings and the analysis in Section 3.5, additional stakeholder consultations were conducted during the stakeholder workshop that was conducted in Egypt in April 2025 (Annex E). The discussions aimed to reflect Egypt’s specific country context, as well as the enabling investment conditions necessary to effectively apply each of the identified instruments.
Consistent with the assessment presented in Section 3.5., across green hydrogen, e-methanol and green iron production, CAPEX grant consistently emerges as the most effective instrument for closing the competitiveness gap with conventional fossil-based alternatives. While recognising the effectiveness of the grant, political and fiscal challenges are likely to limit the feasibility of providing full grant support. Alternatively, deploying CAPEX grant blending with concessional loans that reduce financing costs are identified as a highly attractive complementary measure across all three sectors, substantially narrowing the cost gap at lower public expense. The potential application of these instruments in the context of Egypt is further discussed in Chapter 4.
Green premiums and carbon pricing were not considered further in the discussion of enabling investment conditions and financial solutions at Chapter 4 for the following reasons: for green premiums, the analysis in Section 3.5. shows only partial improvements, which are insufficient on their own. Therefore, this instrument has not been considered further. While carbon pricing could be particularly relevant for green iron, achieving sufficiently high carbon prices remains politically challenging. However, it could be developed as part of a broader climate policy framework.
The feedback received during the workshop also indicated a cautious approach toward the implementation of carbon pricing in Egypt. While the long-term benefits of a carbon market in driving emissions reductions and attracting green finance are recognised, the prevailing limitations in institutional readiness, industrial competitiveness and the need for further development of essential monitoring and regulatory frameworks suggest that widespread and effective implementation remains a considerable challenge for the Egyptian market (Arab Finance, 2024[42]). For instance, Monitoring, Reporting and Verification (MRV) systems need to be further developed. While Egypt has submitted its first biennial transparency report (UNFCCC, 2024[43]), indicating progress in this area, the comprehensive and granular data collection and verification across all relevant sectors required for a functional ETS may still need further development and investment. Nevertheless, green premiums and carbon pricing remain important long-term instruments and should be revisited in future policy analysis as Egypt’s regulatory and institutional frameworks continue to mature.
Beyond the assessed instruments, the consultation revealed the importance of CfD which was not discussed in the survey. CfDs is critical for providing revenue certainty to green hydrogen producers by guaranteeing a pre-agreed ‘“strike price” for their output over a specified period. This mechanism effectively mitigates market price volatility risks, which are particularly acute for emerging green hydrogen markets that currently lack stable demand and clear price signals. CfDs can be referenced against gas market prices, material input costs or carbon prices. When linked to a carbon price, the effectiveness of the CfDs depends on the existence of a functional carbon market, which introduces certain caveats related to market liquidity, price stability and regulatory robustness. Although the precise quantitative impact of CfDs is difficult to assess, the next chapter will explore key design considerations for their successful implementation, alongside other financial mechanisms and enabling investment conditions for accelerating green hydrogen deployment in Egypt.
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← 1. The report finds that while common challenges persist across financing models, stable regulation and long-term planning are essential for investment security and effective grid design. Egypt’s renewable targets and rising demand point to high near-term investment needs, with existing PPP capacity supporting the potential for independent and generation-linked transmission projects.
← 2. According to Egypt’s National Low-Carbon Hydrogen Strategy, two key scenarios – the Central Scenario and the Green Scenario – outline pathways to scale up low-carbon hydrogen production by 2030 and 2040. Under the Central Scenario, Egypt aims to produce 1.5 Mt of green hydrogen by 2030 and 5.7 Mt by 2040 per year. In contrast, the Green Scenario sets more ambitious annual production targets of 3.2 Mt by 2030 and 9.2 Mt by 2040. For the purposes of this report, the Central Scenario has been considered.
← 3. The OECD defines economic instruments as “a means by which decisions or actions of government affect the behaviour of producers and consumers by causing changes in the prices to be paid for these activities (Svatikova, Brown and Börkey, 2025[46]). It includes market-based instruments which are policy instruments that use markets, prices and/or other monetary means to provide incentives for producers and consumers to reduce or eliminate environmental and other externalities (Nachtigall et al., 2022[45]).
← 4. De-risking instruments refer to tools designed to reduce or mitigate specific financial, operational or political risks in investment projects to enhance their bankability and attract private capital (OECD/The World Bank, 2024[25]).
← 5. Green premium analysis offers a useful proxy for assessing the financial viability of green procurement by indicating market willingness to pay and the level of support needed to bridge cost gaps, particularly in price-sensitive sectors . (Clean Energy Ministerial, 2013[47]).
← 6. The competitiveness gap is estimated as the difference between the cost of producing low-carbon products and the cost of fossil fuel-based products, including the cost of their associated CO₂emissions.