Újbuda Gets Approval to Explore Its Geothermal Energy Potential Budapest’s Újbuda district has received approval to examine whether geothermal energy can contribute to its future heating and energy needs. The decision places one of the capital’s most densely populated districts at the centre of Hungary’s broader effort to make better use of its underground thermal resources. The approval does not mean that a geothermal power plant or district-heating system will be built immediately. Instead, it allows the district and its partners to investigate the geological conditions, technical feasibility, environmental implications and financial requirements of using heat stored beneath the city. The project could eventually support cleaner heating, reduce dependence on imported natural gas and strengthen Budapest’s energy resilience. Its success, however, will depend on careful geological research, responsible water management, transparent public consultation and a realistic financing model. Wh...
Menengai’s Broken Promise: How Kenya’s Geothermal Model Lost the Steam
Thematic image of the Olkaria Geothermal Field
Kenya’s Menengai geothermal project was sold as a model of modern public-private partnership.
The state would carry the difficult and expensive burden of geothermal exploration and drilling. Private power producers would then build, own and operate power plants. Geothermal Development Company would supply the steam; the independent power producers would convert it into electricity; Kenya Power would buy the output.
On paper, the arrangement was elegant. In practice, Menengai has exposed a far more uncomfortable reality: Kenya’s public steam-supply model is not delivering the certainty it promised.
Menengai Phase I was designed to produce 105 megawatts from three 35 MW plants. GDC’s own project page says the three plants were awarded to Globeleq Menengai Geothermal, Sosian Menengai Geothermal Power and OrPower Twenty Two under a build-own-operate structure. Yet the same page still describes commissioning as ongoing, years after the project was expected to begin commercial generation.
The project is not a clean example of the state successfully removing geothermal risk for private investors. It is a case study in how risk can be moved from one balance sheet to another without actually being eliminated.
The public side absorbed the drilling risk. The private side built generation assets around an expected steam supply. But when steam availability, drilling performance, environmental approvals and project schedules failed to align, the model had no easy place to hide.
The turbines could be built. The contracts could be signed. The financiers could be mobilised. The transmission infrastructure could be prepared.
But without reliable steam, none of that produces power.
The Promise Was Simple
Menengai’s model depended on a division of labour.
GDC would explore and develop the geothermal field, drill production wells and construct the steam-gathering system. The IPPs would finance and build the power plants. Kenya Power would purchase the electricity through long-term power purchase agreements.
GDC describes the arrangement through a Project Implementation and Steam Supply Agreement, or PISSA. Under that framework, GDC provides steam to the IPPs, which convert it into electricity.
That structure was supposed to make geothermal investment easier. Private developers would not need to carry the full uncertainty of finding a commercially productive reservoir. They would receive steam from a public entity that had already undertaken the expensive subsurface work.
The principle is reasonable. Geothermal power is uniquely difficult because the most important asset is underground and cannot be fully verified before drilling. A power plant can be inspected, tested and engineered with considerable precision. A reservoir cannot.
The success of the model therefore depends on GDC performing the most uncertain part of the project well enough to make the private plants bankable.
That is where Menengai began to unravel.
A Project That Kept Moving
Menengai’s first phase was not supposed to remain an unfinished promise deep into the 2020s.
The three plants were repeatedly associated with earlier completion dates, including expectations around 2016. Instead, commissioning has stretched across years. GDC’s current project information lists Sosian’s plant as completed and synchronised to the grid in 2023, OrPower Twenty Two’s plant as synchronised in March 2026, and Globeleq’s 35 MW plant as still under construction, with an expected final commercial operation date of April 2026.
Those dates do not describe a smooth rollout. They describe a project whose components have advanced at different speeds while the overall promise of a functioning 105 MW phase remained incomplete.
The time gap matters. Every year of delay increases the cost of borrowed capital, extends construction overheads, postpones revenue and weakens the assumptions used by lenders and investors.
A geothermal project does not become financially neutral merely because drilling has already happened. The state must maintain wells, steam infrastructure, roads, pipelines and field operations while the private plants wait to earn revenue. The longer the plants remain incomplete or underutilised, the longer the public side carries those costs without receiving the full steam revenue expected from the model.
GDC says Menengai has potential of about 1,600 MW and that 53 wells with a potential of 169 MW had been drilled by 2023. It also says the first phase requires 105 MW of electricity generation from steam supplied by GDC. [1]
The numbers create a striking contrast: substantial drilling activity and significant stated steam potential, yet a project still struggling to translate underground resources into dependable commercial generation.
The Steam Supplier Became the Bottleneck
The central failure of Menengai is not that private developers were unable to build power plants.
It is that the model treated steam supply as a solved problem before it had been proven as a reliable commercial service.
Globeleq’s own project description states that its 35 MW plant depends on steam supplied by GDC under a 25-year PISSA. The electricity is intended for sale to Kenya Power under a power purchase agreement of the same duration.
This creates a chain of dependency. Globeleq can finance the plant, appoint an engineering contractor, install a turbine and prepare the facility for operation. But it cannot generate electricity at the contracted scale if GDC does not deliver the required steam.
That dependency became public in 2026 when Globeleq postponed commercial operations because GDC could not supply the necessary steam, according to reporting cited in the project’s coverage. The postponement was not a minor construction inconvenience. It struck directly at the foundation of the Menengai model: the private plant was ready to operate, but the public steam supplier was not ready to perform.
The result was a reversal of the original logic.
The state was supposed to make private investment easier by removing resource risk. Instead, the state became the source of operational uncertainty after private capital had already been committed.
That is the nightmare scenario for an IPP. The plant owner has invested in equipment, financing, construction and operations, but the essential input is controlled by another entity. If steam is unavailable, the plant cannot simply purchase fuel from another supplier or switch to a different resource.
A gas plant can buy more gas. A geothermal plant cannot replace an absent reservoir with a truck delivery.
The Geology Was Never Simple
Menengai’s drilling record shows why geothermal development cannot be reduced to a clean handover between a public steam developer and private power producers.
Technical literature on the field records serious circulation problems. A World Geothermal Congress case study reported that circulation losses had been encountered in most of the wells drilled at Menengai. Some wells experienced severe losses through large portions of the wellbore, particularly in fractured formations.
The same study described loss of circulation as the biggest drilling challenge because untreated losses can lead to stuck pipe and, in some cases, abandonment of wells.
A separate technical paper on stuck pipe and lost circulation identified non-productive time as a major issue and recorded a case in which a stuck-pipe incident led to the abandonment of a Menengai well.
These are not cosmetic engineering complications. They affect the cost, sequence and commercial usefulness of the entire field.
When drilling fluid disappears into fractured rock, crews lose control of the drilling process. Hole cleaning becomes more difficult. Equipment can become stuck. The well may need additional treatment, sidetracking or abandonment. Each event consumes time and money while producing no electricity.
A failed well does not simply remove one line from a spreadsheet. It can force redesigns of the steam-gathering network, alter pressure assumptions, increase dependence on other wells and compel the developer to drill additional wells to compensate.
The original model assumed that GDC could absorb this risk before handing the field to IPPs. Menengai demonstrated that the risk remained active after private plant construction had begun.
More Wells Did Not Mean More Certainty
GDC’s published figures emphasise the volume of work completed: dozens of wells, a substantial steam field and a completed steam-gathering system. But drilling quantity is not the same as dependable steam delivery.
A geothermal field may contain many wells without all of them producing the required mass flow, pressure or enthalpy. A well can be technically successful but commercially inadequate. Another may initially produce well but require careful management to avoid pressure decline or interference with neighbouring wells.
The distinction between “steam potential” and “contracted steam delivery” is therefore crucial.
GDC has stated that the Menengai steam wells have an output equivalent to 169 MW, more than the 105 MW required for Phase I. Kenyan government reporting has repeated that the field has sufficient steam for the three initial plants.
Yet the delayed operation of Globeleq’s plant shows that aggregate resource estimates do not automatically translate into steam available at the right pressure, at the right location, at the right time and under the contractual conditions required by an IPP.
A field can look adequate on paper while the steam-gathering system, well performance, pressure management or individual well availability prevents the plant from running at full capacity.
That gap between theoretical capacity and dependable deliverability is where Menengai’s credibility has taken the greatest damage.
The Private Side Was Not Blameless
The failure cannot be placed entirely on GDC.
The IPP model also created incentives for private developers to focus on the plant boundary while relying on public assurances about the field. Once a project is structured around a government-owned steam supplier, private investors naturally build their financial case around the contractual promise of steam.
That is not necessarily negligent. It is the basic structure they were invited to use.
But it does create a divided project. One entity owns and operates the power plant. Another controls the wells and steam gathering. A third, Kenya Power, takes the electricity. Different contracts bind the parties together, but the physical system remains one integrated geothermal project.
A power plant cannot be separated from the reservoir merely because the contracts separate ownership.
When one section falls behind, the entire project falls behind. Yet the parties may still have different timelines, financing pressures, performance standards and interpretations of responsibility.
Globeleq’s project was financed by the African Development Bank, the Trade and Development Bank and Finnfund, with Toyota Tsusho Corporation appointed as engineering, procurement and construction contractor. [2]
The presence of major development financiers and an international EPC contractor shows that Menengai was not an informal experiment. It was structured as a serious infrastructure investment with institutional backing.
That makes the steam shortfall more damaging, not less. The project had the appearance of bankability above ground while its most important operating assumption remained vulnerable below ground.
The Social Licence Was Not Secure
Menengai’s problems were not confined to drilling and contracts.
The project also exposed the consequences of treating affected communities as a procedural requirement rather than as stakeholders with the power to challenge a project.
In March 2025, Kenya’s Environment and Land Court cancelled the EIA licence issued to Sosian Energy for geothermal activities at Menengai. The court found that the public participation process was inadequate and ordered a comprehensive environmental and social impact assessment that would take account of affected communities’ views.
The ruling also addressed the need for climate impact assessment before approval.
The decision was not a technical rejection of geothermal energy. It was a rejection of how the project had been authorised.
That distinction matters. Geothermal power is often presented as clean, reliable and nationally beneficial. But “clean” at the national level does not automatically mean harmless at the local level. Drilling brings noise, heavy vehicles, dust, water use, land access, well testing, hydrogen sulphide concerns and changes to the physical environment.
Communities that experience those effects do not necessarily accept promises of national electricity supply as compensation.
Reports associated with the case described concerns over noise, vibration, pollution, inadequate consultation and limited local benefits. The court’s finding that meaningful participation had not occurred turned those complaints from public-relations problems into a legal obstacle.
The lesson from the litigation was severe: environmental approval was not a box that could be ticked once and forgotten. If consultation was inadequate, the licence could be cancelled after the project had already advanced.
That introduces another form of uncertainty into the model. The state may carry the drilling risk, while the IPP carries construction risk, but both remain exposed to community and regulatory risk.
The Sosian Setback Was Symbolic
The Sosian case carried additional political weight because the company is associated with the family of former President Daniel arap Moi. Its director, Kigen Moi, was identified in reporting on the case.
The court’s ruling did not establish criminal wrongdoing by Sosian or its directors. It did, however, invalidate the EIA licence and require a new assessment because the court found that the public participation process had fallen short of legal requirements. [6]
For Menengai, that was more than a setback for one IPP.
Sosian was one of the three companies selected to develop the first 105 MW phase. GDC’s own project page identifies Sosian Menengai Geothermal Power as one of the Phase I IPPs and says its plant was completed and synchronised to the grid in 2023. [1]
A completed or synchronised plant does not erase the legal and social questions surrounding the project. Nor does grid connection prove that the broader development model is functioning as intended.
Instead, the case revealed a troubling sequence: a major geothermal project advanced, a private company prepared to develop its plant, and only later did the courts determine that the environmental participation process was legally deficient.
That is not how a predictable infrastructure pipeline is supposed to operate.
GDC’s Financial Sustainability Depends on Delayed Success
The financial story is just as uncomfortable.
GDC is expected to spend heavily before it earns substantial steam revenue. It must fund resource assessment, drilling, well testing, well maintenance, steam gathering and field infrastructure. The IPPs only begin to pay for steam when their plants operate and generate electricity.
That creates a long financial valley. Costs arrive early. Revenue arrives later, assuming the wells perform and the plants reach commercial operation.
Kenyan government reporting in October 2026 said GDC expects the Menengai and Baringo-Silali projects to increase revenue and support financial sustainability by 2029. [7]
The statement is revealing because it confirms that GDC’s financial sustainability depends on future project revenues rather than on a currently self-sustaining business model.
The 2029 target also exposes the circular nature of the problem. GDC needs operating IPPs to pay for steam. The IPPs need reliable steam to operate. Reliable steam requires continued drilling, maintenance and field management. Those activities require money before the associated revenue is fully available.
When commercial operation is delayed, the financial recovery date moves further away.
Public money remains exposed while the promised private-sector transformation remains incomplete.
The Infrastructure Exists, But the Promise Does Not
Menengai has roads. It has wells. It has a steam-gathering system. It has transmission infrastructure. It has investors, contractors, development banks and government backing.
It also has power plants that have advanced at different speeds and a steam-supply arrangement that has failed to provide the certainty required for smooth commercial operation.
This is what makes the project so difficult to dismiss as a normal construction delay.
A normal delay affects a project. Menengai’s delays expose the weakness of the model itself.
The model promised that public drilling would make private generation straightforward. Instead, public drilling remained technically difficult, public finances remained exposed, communities remained dissatisfied, regulatory approval remained vulnerable and private plants remained dependent on an input that was not consistently available.
The result is not a clean transfer of risk. It is a chain of interlocking risks, distributed across institutions that cannot operate independently of one another.
The Model Has Been Unmasked
Menengai was supposed to demonstrate that Kenya had found a way to accelerate geothermal development without forcing private investors to gamble on the underground resource.
What it has demonstrated is that geothermal risk does not disappear when the state takes ownership of it.
It reappears as drilling delays, abandoned wells, non-productive time, steam shortfalls, financing pressure, idle equipment, delayed revenue, regulatory litigation and community opposition.
GDC’s role was meant to make the field investable. But when GDC cannot deliver the steam required by the plant, its role changes from de-risking partner to project bottleneck.
The private IPPs were supposed to bring speed and efficiency. Yet their plants became captive to a public resource-development programme whose performance they did not control.
The government was supposed to gain a scalable model for geothermal expansion. Instead, it inherited the cost of drilling while postponing the revenue that was meant to make the model sustainable.
Communities were supposed to benefit from clean energy and local development. Instead, at least one major project lost its environmental licence after a court found that participation had not been meaningful enough.
None of this means Menengai has no geothermal resource. It means the existence of the resource was never the same thing as the existence of a functioning project.
The field may still generate power. The plants may still eventually operate. GDC may still become financially sustainable. But those future possibilities cannot erase what the project has already revealed.
Menengai was marketed as a breakthrough in risk allocation.
It has turned out to be a demonstration that risk allocation is not risk removal.
The state took the underground risk. Private companies took the power-plant risk. Kenya Power took the offtake obligation. Financiers took construction and payment exposure. Communities took the environmental and social consequences.
And after all those risks were divided among them, the steam still did not reliably arrive.
That is the Menengai model stripped of its promotional language: a public agency carrying the hardest risk, private developers waiting on the resource, communities challenging the process, and a national power system still waiting for the promised output.
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