When people think of renewable energy they usually think of wind and solar power first, and then maybe hydroelectric power. And those three sources of electricity, along with biomass, constitute the largest sources of renewable power in the U.S. electricity mix. But geothermal power deserves more attention than it gets.
Wind and solar are increasing their market shares because they are inexpensive, and their power output over the long run is relatively predictable, making them attractive to investors. They tend to be first in the dispatch queue: i.e., because their operating costs are the lowest of any electric generating technology, grid operators use them to serve demand before gas-fired plants and other technologies with higher operating costs.
But as wind and solar plants grow their market shares, they displace fossil fueled generators that are less weather-dependent, and otherwise more available to provide power during more of the day and year. So, finding cleaner ways to “firm” or “firm up” wind and solar power — that is, to back them up when the wind isn’t blowing or the sun shining — is an important energy policy problem. When we think about the cost of firm clean power, geothermal electricity looks more attractive.
Geothermal electricity is not new. In regions of California and Nevada where geothermal resources are not far below the surface of the earth, geothermal power plants have existed since the 1960s. And the use of geothermal steam for district heating was once fairly common, particularly in places with “springs” in their name — like Hot Springs, Arkansas and Saratoga Springs, New York. The Geothermal Steam Act of 1970 (authorizing the Department of Interior to lease federal lands for geothermal development), the Public Utilities Regulatory Policies Act of 1978 (including geothermal power in a class of “alternative” energy technologies from which utilities must buy power), and the Geothermal Energy Act of 1980 (financial assistance for geothermal development) are all part of this history.
But the latest generation of geothermal power– so-called “enhanced geothermal systems” — don’t rely on steam at or near the earth’s surface. Rather, it uses newer drilling technologies and hydraulic fracturing to access deep* subterranean heat for power generation. It injects liquid into the fracked well bore where it becomes superheated, then brings the superheated water to the surface under pressure, where it is turned into steam to drive a turbine. The Bureau of Land Management (BLM) just gave the green light to a new commercial scale EGS pilot project in Utah, which will be built by Houston-based Fervo Energy.
EGS technology is more expensive than wind and solar power, but also much less weather-dependent. Like a gas-fired power plant, it can be available to produce power day or night, in all the seasons of the year. The most recent estimates of the levelized cost of energy estimates (LCOE)* from Lazard illustrate how marginal cost pricing disadvantages geothermal power.
Page (or slide) 15 of the Lazard document linked above shows the cost of firming up wind and solar in each of the different organized wholesale power markets in the U.S. Lazard assumes that in most of these markets, natural gas-fired plants (without carbon capture) will fill in the gaps when wind and solar cannot, except in CAISO (California) where Lazard assumes that lithium ion batteries will provide that back up function. Those “solar + lithium battery” estimates far exceed Lazard’s LCOE estimate for geothermal power, which can be found on page (slide) #9.
But, and this is a crucial “but,” those LCOE numbers for geothermal must be taken with a grain of salt for two reasons. First, the technology is in its infancy. The environmental impact statement for the Fervo project notes that the supply of heat in deep rock is not infinitely renewable, and the rate at which it dissipates won’t be known until the project is operational. That means that the actual power production curves of deep geothermal wells will decline over time at an unknown rate. (This stands in contrast to the kind of near surface geothermal heat used by ground source heat pumps, which is replenished by solar radiation.) That, in turn, means that LCOE estimates for EGS are really just educated guesses.
Second, Lazard’s LCOE estimates for EGS are based on the assumption that the plant runs 80-90% of the time. If grid operators use goethermal mostly to back up wind and solar, it will be forced to recover its costs by selling many fewer megawatt-hours of electricity. In that case, it must command a much higher price for its electricity in order to break even. That is, its LCOE will be significantly higher than the Lazard estimate.
In this way, the success of inexpensive wind and solar comes at the expense of all the technologies that can be available more often, geothermal included. It is possible that this increases the average cost of providing net zero electricity in competitive wholesale markets. And because geothermal is likely to be used to back up unknown amounts of wind and solar power, the lack of future revenue certainty makes investors warier of investing in firm technologies.
This problem can be overcome in several ways. In states that still have traditional public utility regulation, a geothermal plant can be put in the utility’s rate base, ensuring that ratepayers will pay for it. If “base load” geothermal turns out to be less expensive than wind/solar plus backup, regulators in those traditional states can make that happen. And in some competitive power markets EGS plants might hope to earn additional revenues in capacity markets that pay them for their superior availability, or through ad hoc bilateral agreements with grid operators to ensure reliability in a mostly-renewables grid of the future.
The Inflation Reduction Act offers powerful tax credits for all sorts of new energy projects, including geothermal development. And the supposedly bipartisan “Energy Permitting Reform Act” bill currently before Congress would ease some of the permitting and political barriers to developing new EGS projects.
Perhaps all of this top-down encouragement can help reassure skittish investors. In a world run by benevolent central planners, we might expect them to choose more clean firm technologies like EGS whose levelized costs are lower than renewables + battery storage. But competitive wholesale power markets are not centrally planned. They rely on market competition to drive prices downward, and the growth of wind and solar is driving down spot power prices. But it also requires grid overseers to make adjustments designed to ensure a reliable supply. In the absence of regulatory limits on greenhouse gas emissions, the market will favor natural gas as the cheapest backup option. — David Spence
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* “Levelized cost” is the average cost of producing power over the lifetime of the project, or the average price per mwh it must receive over its lifetime in order to break even.
** In its previous set of LCOE estimates published in April 2023 Lazard estimated the LCOE of natural gas + carbon capture and storage (CCS). Those estimates were also lower than solar + storage. However, like EGS, carbon capture technology is relatively new, and has less of a track record than utility scale solar and wind.
