How the U.S. Geothermal Market Is and Is Not Growing

Apparently little happened in the way of new, operational geothermal plants in 2011, if you look at the Geothermal Energy Association’s 2012 annual Power Production and Development report. Although the United States remains in the lead globally in terms of installed capacity with 3,187 MW, only 91 MW of additional capacity came on line last year (not subtracting for replaced capacity). And nearly 50 MW of this additional installed capacity was at a single plant: the Hudson Ranch 1 in California.

That’s not to say the geothermal industry hasn’t been working hard. The number of plants in development and the breadth of technologies and geographical area have certainly grown. As of the GEA reporting period, 147 projects are in development (including 17 that are unconfirmed) that could result in roughly 4,900 to 5,300 MW of installed capacity if completed.

Geothermal development has long been centered in western states. But according to GEA, “developers are increasingly exploring for and developing conventional hydrothermal geothermal resources in areas where little or no previous development has taken place.” The number of states with projects in development (15) compared to those with operating plants illustrates the trend of geographical expansion of the market (9) (see the maps below).

Figure 1. Geothermal Capacity Online and Under Development in U.S. States in 2011

Much of this expansion into uncharted geothermal territory is due to the development and application of relatively new technologies. Take, for example, co-production in which fluid byproducts from oil and gas-field developments are used to access low-temperature geothermal resources. The DOE Geothermal Technologies Program (GTP) is supporting co-production projects in North Dakota and Texas, both of which have traditionally been off the geothermal electric map. Co-production projects also are underway in Louisiana and Wyoming.

Of course, there’s also enhanced geothermal systems (EGS), a technique that uses hydraulic fracturing (without the chemicals that characterize gas ‘fracking’) to create commercial production at levels that would otherwise not be allowed by the naturally occurring capacity flow.  Thanks to the Apache County EGS project (2 MW), Arizona is now also part of the geothermal market, where previously it had been absent.  DOE GTP is also supporting EGS demonstration projects in Alaska, California, Nevada Idaho, and Oregon.

In addition to new technologies, state and federal policies (beyond the project support provided by DOE GTP) have in part driven geothermal development.  In the case of California and Nevada, renewable portfolio standards (33 percent by 2020 and 25 percent by 2025, respectively) combined with significant, known resources have led to comparatively large installed capacities in those states.

As new technologies and enhanced drilling techniques have become commercialized, states that previously thought they had limited geothermal market potential are now trying to improve their attractiveness to developers. Alaska provides an interesting policy example in this regard.  The state has adopted a renewable energy goal (non-enforceable) to generate 50 percent of the state’s electricity from renewable energy resources by 2052. This year, Alaska allocated $250 million to support renewable energy projects.  And in 2010 under SB 243, Alaska reduced royalty payments from geothermal projects on state lands and streamlined geothermal permitting and regulatory processes with state agencies.

Alongside states, the federal government has provided several financial incentives. However, as indicated in the figure below from a forthcoming NREL report on geothermal policies, most of these incentives have been phased out over the last couple of years, or in the case of the loan guarantee program, are fully committed.

Figure 2. Timeline of federal geothermal financial incentives

So what will the geothermal market look like in a few years? Without federal financial incentives, additional state support, and easily attainable cost reductions, it’s hard to say. Fifty-megawatt hydrothermal plants could become a thing of the past and could be replaced by smaller, distributed projects accessing lower-temperature resources in states where geothermal had previously been considered unrealistic. And maybe oil and gas companies will start to leverage their resources and drilling expertise and get their hands dirty with coproduction.

This article was originally published on NREL Renewable Energy Finance and was republished with permission.

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Bethany Speer is an Energy Analyst with the National Renewable Energy Laboratory’s project finance team. Her principal areas of focus are in domestic and international clean energy policy and finance analysis, with particular attention to risk mitigation, third party legal and regulatory issues, and local finance innovations.

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