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The earth's subsurface is estimated to contain many times more energy as heat than as oil and gas resources. Yet a discovery of hot water and steam has traditionally been considered to be a poor substitute for oil.
Although there are key similarities between these two industries, with a few exceptions there has been limited crossover among the players. But with increased oil price turbulence—coupled with the need for a new form of green, flexible baseload power to stabilise grids and operate alongside expanding intermittent renewable sources—there may be renewed motivation for government policymakers to encourage exploitation of geothermal resources across volcanically active hotspots worldwide.
In new frontier jurisdictions, geothermal exploration and development might have more in common with oil and gas exploration and development than first thought.
Licensing and state participation
Due to the nature of geothermal—straddling the infrastructure, energy and natural resources sectors—regulation of activity differs vastly between markets and is often over- or under-regulated.
Where jurisdictions have bespoke geothermal legislation it may be derived from oil and gas legislation, as similar structures are involved. Licensing typically involves state authorities issuing licences for specified areas, for specific categories (such as prospecting, exploration and development) and for set periods during which a certain level of expenditure and activity must be implemented.
As with oil and gas exploration, host governments need to be concerned about inactive speculators and take measures to deter them. The Chilean government’s initial exploration campaigns to establish a geothermal sector later ran into delays due to inactive licensees, in part due to poor filtering of licence applications.
The problem of inactive licensees was also highlighted more recently in International Centre for Settlement of Investment Disputes proceedings between the Kenyan government and a Canadian developer regarding the revocation of a licence for the Suswa geothermal fields due to inactivity. The tribunal awarded in favour of the Kenyan government.
Conversely, a private developer’s concern would be unlawful revocation of licences or failure to renew licences, or failure of the host government to give an exploration licensee pre-emption rights to acquire a development licence. Developers must also consider the general regime in a jurisdiction for the sequencing of geothermal licences alongside the timing and duration of the generation licence, the effective date and term of the power-purchase agreement and finally the tenor of debt financing, so as to make sure that it flows appropriately for the project.
Where geothermal resources are unexploited, in weighing up the regulatory and permitting regime investors should also ascertain the extent to which the government itself intends to develop the sector alongside private developers. It is a tension that has been seen in some geothermal jurisdictions. There is also the potential for an ‘inherent conflicts’ concern where a host government is at the same time a regulator, a licensing authority and a player in the geothermal sector.
Funding the unknown
The key challenge in developing greenfield geothermal projects is the high upfront cost and risk during the exploration and drilling phase. As with oil and gas exploration, the exact potential of a site and the ultimate generation capacity of a power plant—and therefore the forecast revenue—cannot be accurately quantified until drilling has been substantially completed.
But, unlike for oil and gas, the immediate rewards of a successful well do not necessarily outweigh the risk of a failed well. While surface studies and shallow slim-hole drilling can confirm the existence of a heat source and hydrothermal system, test-drilling of deep, usually full-size, wells is necessary to confirm the presence and quality of the geothermal resource.
In some projects. the cost and risk of this phase is taken by the public sector, particularly where the public sector has developed its own geothermal expertise and is therefore ahead of, or on a par with, private sector developers.
In other projects this risk is fully allocated to the private sector, particularly in jurisdictions which are at a nascent stage in geothermal development, such as Uganda. Likewise, in Zambia the UK-funded Renewable Energy Performance Platform has provided a $3.2mn staged convertible facility for the drilling of slim wells on a project.
While no lender may wish to finance this high-risk stage, third-party forms of risk or cost sharing for exploration and drilling are increasingly available. An active example of this is the Geothermal Risk Mitigation Facility grant deployed in Africa, which is in its sixth application round and will fund up to 40pc of drilling costs. A new funding and underwriting package is being developed through the GeoFutures GreenInvest fund.
Where exploration and drilling are publicly funded, the question is how, or whether, the public sector could recover these costs. Where it is privately funded, the question is more about the costs the project can stand while ensuring an affordable tariff and viable return on equity.
Downwards costs trajectory
The capital cost of geothermal depends on the technology used but is anticipated to continue to decline, according to a 2015 European Commission report (Sigfusson and Uihlein). A stable levelised cost of electricity (LCOE) price trajectory is aided by the fact that the fuel cost for geothermal fuel would be relatively stable relative to thermal power plants that rely on volatile hydrocarbons pricing—a key benefit of geothermal to the consumer.
Project structuring for geothermal varies, with notable differences being whether the project is a first project on a greenfield geothermal concession or a later project on an existing steamfield development—where data on the reservoir geology, characteristics and other subsurface conditions have already been collated—which is being packaged by the host government.
Additionally, tolling structures may apply where the private developer is paid a fee for converting the resource supplied by the state-owned entity to power, and delivering the power back to the state-owned entity without taking resource risk. Whatever structure is adopted, demarcation of public and private participation and risk allocation is particularly critical in structuring geothermal projects.
With varying structures, it is hard to pinpoint offtake tariff trends for geothermal. Further aspects such as government or third-party support or underwriting and the creditworthiness of the offtaker impact the cost of finance and therefore the tariff, and there may also be impacts from tax exemptions and incentives and regulatory oversight.
According to the International Renewable Energy Agency, the LCOE for geothermal ranges from $0.04-0.14, assuming operations and maintenance costs of $110/KW/yr and a 25-year economic life. The lower end of the scale enables geothermal to be highly competitive, but the challenge is then hitting a level below the upper end of the scale, particularly on greenfield geothermal projects in new markets.
However, here the benefits of geothermal as a stable, clean and flexible baseload generating source, and the potential for reduced costs of subsequent geothermal projects relying on the same known geothermal resource area should be taken into consideration by governments as a matter of policy.
Feeling the heat
Geothermal is not solely about electricity. The heat energy created by geothermal resources has been scarcely exploited, save for geothermal-rich jurisdictions such as Iceland. Harnessing this heat and diverting it into solutions such as greenhouse heating, drying, textiles and dairy production is where geothermal becomes very interesting. There are early stage plans in parts of Africa for co-located geothermal industrial parks. Furthermore, the extraction of lithium from geothermal brine, as has been contemplated in recent studies in Europe and the US, may be a gamechanger for the industry.
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