The Rise of Green Hydrogen in Namibia and Morocco: Africa’s New Export Frontier

This article is in BOH Infrastructure’s 2026 Energy and the Green Transition series. The full series establishes that Africa’s energy deficit is overwhelmingly a financing and perception problem rather than a resource one. This briefing focuses on the specific assets, corridors, and technologies that translate that argument into investable, bankable energy infrastructure.

Why Europe’s Energy Crisis Reshaped the African Hydrogen Map

Before February 2022, green hydrogen was a credible but distant ambition in most European energy planning documents. The invasion of Ukraine and the subsequent disruption of Russian gas supply to Europe compressed a decade of energy transition planning into roughly eighteen months. Governments that had been cautiously piloting hydrogen strategies were suddenly mandating import targets, signing memoranda of understanding with supplier nations, and allocating public capital to de-risk early projects.

The European Union’s REPowerEU plan, published in May 2022, set a target of importing 10 million tonnes of green hydrogen annually by 2030. Africa, particularly the northern and southern Atlantic coastlines, sits within viable shipping or pipeline distance of major European import terminals. Germany signed hydrogen cooperation agreements with Namibia, Morocco, South Africa, and Kenya in the same 18-month window. The Netherlands signed with Morocco. Spain, already connected to Morocco by an existing gas pipeline corridor, began feasibility studies on hydrogen blending and dedicated hydrogen pipelines.

This geopolitical context matters for the investment analysis. Green hydrogen projects in Africa are not purely commercial propositions priced against spot energy markets. They carry strategic value for European governments that are willing to deploy concessional finance, export credit guarantees, and diplomatic weight to accelerate specific projects. This blended finance dimension substantially changes the risk-return calculus for co-investing private capital.

Namibia

Building an Industry from the Ground Up

Namibia’s green hydrogen story is striking precisely because the country had almost no prior renewable energy export infrastructure when the conversation began. What it does have is an Atlantic coastline with some of the highest and most consistent wind speeds on earth, vast uninhabited interior land with exceptional solar irradiation, and a stable, investor-friendly governance framework that has received consistently high marks from international credit rating agencies relative to its regional peers.

The flagship project is Hyphen Hydrogen Energy, a joint venture between Nicholas Holdings and Enertrag that was awarded development rights over a 4,000 square kilometre zone in the Tsau Khaeb National Park in southern Namibia, adjacent to the port of Luderitz. The project’s ambition is extraordinary in scale: at full build-out, it targets 3 GW of electrolyser capacity producing up to 300,000 tonnes of green hydrogen annually, most of it converted to ammonia for export. Capital expenditure estimates have ranged from USD 10 billion to USD 15 billion over the full development cycle.

For context, that investment figure exceeds Namibia’s annual GDP. It will not be financed by a single institution or through a conventional project finance structure. The Namibian government, advised by the African Development Bank and the German development finance institution KfW, has structured the project to attract layered capital: sovereign wealth fund equity, development finance institution debt at concessional rates, export credit agency guarantees from European governments whose industries will benefit from the ammonia offtake, and commercial bank debt for the portions of the project with the clearest revenue visibility.

The Luderitz port is the critical infrastructure choke point. Currently a small fishing harbour, it requires substantial investment in deep-water berth capacity, ammonia storage terminals, and dedicated loading infrastructure before the first export cargo can leave. Namibia’s government has secured preliminary commitments from the German government’s development finance arm and from the European Investment Bank for port expansion funding, but construction timelines are tight against the 2030 offtake targets that anchor the project’s revenue model.

Water is the other constraint that investors must understand carefully. Electrolysis consumes approximately nine litres of water per kilogram of hydrogen produced. At the scale Hyphen is targeting, freshwater demand would exceed Namibia’s available surface water resources in the project area by several orders of magnitude. The solution is seawater desalination, powered by dedicated renewable capacity, but the desalination plants themselves represent a multi-billion dollar capital requirement and introduce additional operational complexity into an already technically sophisticated value chain.

Morocco

The Industrialised Hydrogen Pioneer

Morocco’s position is fundamentally different from Namibia’s. The country already has over 4 GW of installed renewable energy capacity, a functioning electricity grid interconnected with Spain, an established industrial base in phosphates and fertilisers through the OCP Group, and a track record of executing large-scale infrastructure projects on time and within budget that few African nations can match.

The Nour and Aman projects, developed under Morocco’s National Green Hydrogen Roadmap published in 2021, target initial production of 4 TWh of renewable electricity dedicated to hydrogen by 2027, scaling to 20 TWh by 2030. The OCP Group, one of the world’s largest phosphate and fertiliser companies, has positioned itself as the anchor industrial consumer of Moroccan green hydrogen, using it to produce green ammonia for its fertiliser plants. This is a direct import substitution play that reduces OCP’s dependence on imported natural gas for ammonia synthesis.

Morocco’s geographic position is its most distinctive advantage for European export. The country shares a land border with the Spanish enclave of Ceuta, and the existing Maghreb-Europe Gas Pipeline runs from Algeria through Morocco to Spain and Portugal. While this pipeline is currently configured for natural gas, the physical infrastructure provides a template for a future dedicated hydrogen pipeline corridor. That corridor would dramatically reduce the cost and complexity of European hydrogen imports compared to shipping liquefied hydrogen or ammonia from southern Africa.

The Xlinks Morocco-UK Power Project, while primarily a renewable electricity export project rather than a pure hydrogen play, illustrates the depth of European appetite for Moroccan energy assets. The project proposes a 3,800 kilometre subsea cable carrying solar and wind electricity from Morocco directly to the United Kingdom. If commercially validated, it confirms Morocco’s credentials as a multi-pathway renewable energy exporter capable of attracting institutional capital at scale.

Morocco also benefits from its relationship with the European Bank for Reconstruction and Development, the European Investment Bank, and bilateral development finance from France, Germany, and the Netherlands. These institutions have long track records of financing Moroccan infrastructure and understand the country’s regulatory and contractual environment, reducing the due diligence burden and accelerating decision timelines for private co-investors.

The Power-to-X Economics

What Makes a Project Bankable

Neither liquefied hydrogen shipping nor pipeline hydrogen at commercial scale exists today at the volumes required by 2030 offtake targets. This is why the Power-to-X conversion step, producing ammonia, methanol, or synthetic fuels rather than shipping pure hydrogen, is central to almost every near-term African green hydrogen export project.

Ammonia is the most commercially mature pathway. It is already traded globally at scale, with established shipping infrastructure, storage terminals, and industrial end users. Green ammonia, produced from green hydrogen, can enter existing ammonia supply chains with minimal modification to the receiving infrastructure. It can also be used directly as a shipping fuel, a use case gaining regulatory support in the International Maritime Organization’s decarbonisation framework.

The economics of green ammonia production in Namibia and Morocco hinge on three cost variables: the levelised cost of renewable electricity, the capital cost of electrolysers, and the cost of financing. On the first variable, both countries are genuinely advantaged. Solar and wind resources capable of generating electricity at USD 0.02 to USD 0.04 per kilowatt-hour place their production costs at the low end of the global range. Electrolyser costs have fallen by approximately 60 percent over the past five years and are projected to fall further as manufacturing scale increases. Financing cost is the variable most sensitive to project-specific risk perception, and it is here that the blended finance structures being assembled by development finance institutions are doing the most work.

A project that achieves a blended cost of capital of 7 to 8 percent, through combining concessional development finance with commercial debt and equity, can produce green ammonia at costs that are competitive with grey ammonia (produced from natural gas) at current European gas prices. Projects that must finance entirely at commercial rates face a harder economics case, particularly as gas prices have moderated from their 2022 peaks. This is why the composition of the financing stack is not a secondary question for investors. It is the primary determinant of whether a project proceeds.

The Enabling Infrastructure Imperative

No green hydrogen project in Africa will reach financial close without resolving three enabling infrastructure requirements simultaneously: port capacity, water supply, and dedicated renewable power and transmission.

Luderitz in Namibia and the Atlantic port of Jorf Lasfar in Morocco are both receiving infrastructure investment commitments, but the scale and speed of port development will be the most visible near-term indicator of project momentum. Investors watching these projects should track port construction milestones as a leading indicator of overall project viability.

Desalination, as noted in the Namibia context, is not optional. It is a core project component that must be sized, financed, and contracted alongside the electrolyser and renewable generation capacity. Projects that treat desalination as a secondary concern are underestimating a material cost and execution risk.

Dedicated renewable generation, separate from the national grid, is the preferred structure for most export projects because it allows for direct renewable energy certification of the hydrogen produced. This certification is increasingly required by European import regulations under the EU’s Renewable Energy Directive. Grid-connected production introduces certification complexity that some offtake agreements are not yet structured to absorb.

Investor Positioning

Where the Opportunities Lie

For institutional investors, the direct equity opportunities in early-stage green hydrogen projects carry significant execution and technology risk. The more immediately accessible opportunities are in the enabling infrastructure layer: port development, desalination plant construction and operation, logistics and storage, and the manufacturing supply chain for electrolysers and balance-of-plant equipment.

Sovereign wealth funds from the Gulf Cooperation Council are already active in this space, with ADNOC, Mubadala, and Saudi Aramco’s investment arms all evaluating African green hydrogen positions. Their appetite is driven partly by the recognition that green hydrogen represents a long-term structural shift in global energy trade and partly by the opportunity to diversify energy export portfolios beyond hydrocarbons.

For private equity and infrastructure funds, the most defensible entry point is probably the operational phase of projects that have passed final investment decision, accepting lower headline returns in exchange for substantially reduced construction and regulatory risk. The first wave of African green hydrogen projects reaching this stage is likely to occur between 2026 and 2029.

This article is part of Energy and the Green Transition series. The full series establishes that Africa’s energy deficit is overwhelmingly a financing and perception problem rather than a resource one. This briefing focuses on the specific assets, corridors, and technologies that translate that argument into investable, bankable energy infrastructure. Read the full Energy and the Green Transition series.

Within this series:

• Kenya’s low-cost geothermal electricity positions it as a future green hydrogen producer alongside North and Southern African pioneers. → Read The Rise of Green Hydrogen in Namibia and Morocco: Africa’s New Export Frontier
• Geothermal baseload reduces Africa’s dependence on battery storage as a grid stabiliser, but hybrid systems combining geothermal and storage are emerging. → Read Battery Storage and Grid Resilience: Solving the Intermittency Gap in 2026
• Kenya’s low-cost geothermal electricity positions it as a complementary green hydrogen producer to Namibia and Morocco, with a different feedstock profile and a primarily domestic industrialisation focus in the near term. → Read Kenya’s Geothermal Advantage: A Blueprint for Regional Energy Security
  
  

Related Articles

• The blended finance structures being developed for green hydrogen projects draw on the same multilateral and domestic capital mobilisation logic that underpins AfCFTA infrastructure financing. The risk-sharing models being pioneered in hydrogen are directly transferable to cross-border transport and energy infrastructure. → Read Financing the AfCFTA: The Role of Infrastructure Bonds and Domestic Pension Funds
• Tanger Med is directly relevant to Morocco’s green hydrogen export ambitions. Port infrastructure investment is the most immediate physical constraint on green hydrogen project timelines in both Namibia and Morocco, and the lessons from Tanger Med’s modernisation programme apply directly to Luderitz and Jorf Lasfar. → Read Port Modernization: Lessons from Tanger Med and Mombasa in 2026

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