Geothermal Power’s Competitive Landscape
July 11, 2020
Amory B. Lovins, Cofounder and Chairman Emeritus, Rocky Mountain Institute
I’m delighted to see so many experts and leaders from the hydrocarbon industries coming together at the Pivot2020 virtual conference to explore how their unique skills could be applied to geothermal energy. As a 47-year advisor to their industries, I also want to help them understand the challenges facing geothermal entrepreneurs in a rapidly changing electricity market. I hope this note could add a useful thread to the conversation, early enough to ensure that resources are efficiently and effectively applied to realistic goals. This didn’t occur in the nuclear fusion business, where many startups assumed they had to beat coal or nuclear plants that were already severalfold to manyfold out of the money. Hitting the wrong target doesn’t win.
A historical analogy may be useful here. Our 2004 book for the Pentagon, Winning the Oil Endgame, summarized it thus: “In the early 1980s, Royal Dutch/Shell Group’s engineers were designing the equipment to bring oil ashore from the new Kittiwake field in the North Sea. They were sweating out the last few percent of cost when the strategic planners told them, ‘You’re assuming that you’ll be able to sell this oil for $18 a barrel. But by the time it gets here, we think the market will have crashed and you’ll only be able to sell it for $12. If you can’t beat that, then you can all go home and we’ll leave the oil where it is, because we can’t lose money on every barrel and make it up on volume.’ Once the engineers recovered from the shock, they realized they’d previously been asked the wrong question—how to land the oil as quickly as possible, whatever it cost, rather than how to land it as cheaply as possible even if it took a bit longer. By asking that new question, they got very different engineering answers. And not only did they cut the landed cost so much that the oil made money even at $12 (the price in fact hit slightly below $12 right on cue), but the new cost-conscious technologies they invented also made, for example, $30 oil into [roughly] $18 oil. Most importantly, this new approach postponed the economic depletion of oil, buying precious time in which to develop still better technology that could postpone economic depletion still further. Today, the inexpensive new ways to save and substitute for oil have a similarly critical function: they don’t simply save money, but also buy time for fuller adaptation and further innovation.”
Like Kittiwake oil, geothermal projects will need to be designed against a fast-moving cost target. The competitive target is no longer coal power: IRENA found 1200+ GW of coal plants will be uncompetitive by next year (if not already), and RMI showed how closing all the world’s coal plants and replacing them with new renewables could be cost-neutral within two years and within five years could return >$100 billion in annual savings.
The target is no longer nuclear power: its average US operating cost alone, though among the world’s lowest, averaged $30/MWh in 2019, making it often uneconomic to operate, so its premature closure—if the saved opex were reinvested in least-cost carbon-free resources like efficiency—could save more carbon sooner than continuing operation. And as we’ll see in a moment, the target isn’t gas power either. It’s now renewables and efficient end-use.
For the United States, Lazard’s v13.0 November 2019 assessment of unsubsidized levelized busbar electricity prices benchmarked US onshore windpower at $28–54/MWh and utility-scale photovoltaics (PVs) at $32–42/MWh. Five months later, Bloomberg New Energy Finance’s 1H20 update, based on observed market prices for ~7,000 projects worldwide. found the best unsubsidized price for wind was $26/MWh (in Brazil), and for PVs in Australia, Chile, China, and UAE, $23–29/MWh—using the developers’ actual costs of capital, rather than the uniform costs of capital assumed by Lazard. International Energy Agency data show that recent years have seen renewables’ weighted-average cost of capital dropping roughly three percentage points and hydrocarbon projects’ rising by three, reflecting capital markets’ view of relative risk (and perhaps also including capital velocity). This is consistent not only with sector-specific objective risks but also with Soros’s theory of reflexivity, which causes rising costs of capital for declining industries and falling costs of capital for rising industries.
Standard empirically grounded datasets like Bloomberg, Lazard, and IRENA show that in unsubsidized competitive markets, wholesale power prices for new large-scale well-sited wind and PV projects’ output have generally fallen through $30/MWh toward $20, and are expected to drop below $20 in this decade. Some already did: in Mexico, near the Texas border, unsubsidized PV contracts fetched as little as $19 and wind $17 in 2017 (before the new Mexican government blocked such competition and killed renewables). Continuing innovation, learning, and scaling are likely to keep these prices falling toward $10 over the next two decades.
Obviously combined-cycle gas turbines (CCGTs) can’t withstand such competition: they’re already being pushed up the load-duration curve by relentless renewable competition for economic dispatch. As they run fewer hours, they can’t support their cashflow needs and must be written down or off. That’s already happening even without yet (in most countries) pricing their CO2 emissions or their supply chain’s CH4 emissions, nor the market value of gas price volatility, which basic financial economics says must be included for fair comparison or competition with constant-price efficiency and renewables.
Two other formidable competitors are emerging too. The first, already routinely beating CCGTs, is the “Clean Energy Portfolio” (CEP) combination, locally optimizing a bundle of end-use efficiency, demand response, modern renewables, and perhaps storage or other grid-flexibility resources. The emerging competitive landscape prominently includes such portfolios, not just single technologies, because CEPs can be tuned to provide any desired mix of energy, capacity, ramp rate, and other attributes important to grid operators or customers. Whether such portfolios will beat geothermal power or can add value by including it is an empirical question.
The second competitor is on the demand side. Integrative design—designing buildings, vehicles, equipment, and factories as whole systems for multiple benefits, not as isolated parts for single benefits—can make end-use efficiency severalfold bigger and cheaper than had been thought. As this method spreads, it may keep efficiency (whose cost to utilities buying it for US customers averages ~$20/MWh, with wide variations) ahead of the plummeting price of renewables, though the two are synergistic natural partners, and both are needed. Partly because of integrative design, electrification might not make long-run electricity demand rise; our 2011 Reinventing Fire synthesis showed how three-fourths of 2010 US electricity use could be saved by historically reasonable adoption of best 2010 technologies costing, on average, a tenth today’s retail tariff, yet using little of the integrative design potential.
Some geothermal proponents believe their projects’ ordinarily steady output will win far greater market value. It might in a dwindling set of markets where such “baseload” operation has wangled political preference. However, in others it might be penalized as inflexible (losing value for the grid operator): of course geothermal output can be throttled back, but that loses operator revenue and raises unit cost. Today the “baseload” concept is widely considered obsolete. It describes the historical role of big thermal power plants (chiefly coal and nuclear) that were dispatched whenever available because they had the lowest operating cost (except hydropower). However, modern renewables, chiefly solar and wind, provided 78% of the world’s 2019 net additions of generating capacity, and met more than all the growth in demand, so fossil-fueled generation worldwide peaked in 2018. Thus cost-minimizing grid operators now dispatch renewables whenever available, reducing fueled plants’ run hours and inexorably pushing them toward insolvency. As Michael Liebreich says, the game has changed from baseload to base-cost. Electricity systems that compete all resources, including renewables and efficiency, no longer buy more fossil-fueled or nuclear plants, because those have no business case. The old case for capacity payments and markets, to ensure the grid isn’t caught short, also fails because the new winners can be built so quickly that they can add very substantial capacity while regulators are still docketing hearings about what to buy.
To be sure, PVs and windpower have highly variable output. (The right word is “variable,” because their output can generally be forecast at least as accurately as demand. The term “intermittent” is best reserved for unpredictable—forced—outages, which are far more characteristic of big thermal power stations.) Keeping the grid in instantaneous supply/demand balance requires careful planning, attention, and execution. However, it is no longer considered unduly difficult or materially costly. The Scottish grid was 90% renewably powered in 2019 and should hit 100% this year; Denmark, at least 79% (including 50% wind and solar) last year; Germany, 46% last year and 56% in the first half of 2020; Portugal, 66% in 2018; peninsular Spain, 46% in 2016; and so on. Of these, Denmark and Germany have no or little hydropower, but their electric reliability is about ten times that of the United States. And none of these countries is yet using the full portfolio of nine carbon-free grid flexibility resources. Of those, batteries are currently the costliest but are rapidly becoming cheaper, so wind-or-PV-plus-batteries, as recent US market choices show, can generally beat gas peakers.
The levelized costs and prices quoted throughout this article do not include grid balancing (integration) costs for any resource. However, including them would strengthen renewables’ case, because PV and wind integration costs are empirically just a few $/MWh, while the corresponding balancing costs for big thermal stations, though traditionally ignored and socialized, appear to be severalfold larger because the capacity is lumpier and more prone to sudden and long forced outages.
Where in this landscape might geothermal power compete? Traditional geothermal systems generating at perhaps $80+/MWh won’t win save perhaps in exceptional sites (Alaskan villages?) combining a great resource with diesel-powered grids, if they can beat local solar and wind. Promising innovations like those proposed by Sage Geosystems aim to achieve pricing around $50/MWh in three years, with the ambition of halving that in a decade. This too may win in specific niches—though in the western US with the hottest, cheapest-to-access resources, solar and wind already broadly beat Sage Geosystems’ 2030 price target. Renewable power prices are falling so fast that a further halving, into the $10–20 range, will probably be needed for geothermal to compete in enough places to achieve major scaling and learning.
An intriguing possibility in some places might be geothermal process heat. The delivered ~190–200˚C contemplated by Sage Geosystems is already available from the best industrial heat pumps. Those deliver several units of heat per unit of electricity, which in turn is increasingly clean, cheap, and renewable. Some processes need even higher temperatures, so cheaper-and-deeper drilling or special (near-volcanic) sites offering >300˚C may beat heat pumps and open up new process-heat markets. But perhaps by the time those geothermal sources’ technical and economic challenges are met, heat pumps too may have raised the ante—or new processes, products, and uses may have redesigned out those high temperature requirements.
Certain geothermal approaches, including Sage Geosystems’ ~10-MWe unit scale, could enable distributed heat and power production with very flexible siting. Many of the 207 “distributed benefits” described in Small Is Profitable: The Hidden Economic Benefits of Making Electrical Resources the Right Size (2002) would apply at that scale. Whether they prove more or less valuable than similar distributed benefits of solar, wind, and efficiency remains to be seen.
In summary: I’m rooting for well-done geothermal innovation, not because it’s essential but because it could usefully apply important existing skills, and competition creates useful optionality. Some geothermal techniques may overcome concerns about older methods. Disparate impacts, costs, and benefits will need thoughtful proof and comparison. But the biggest questions are economic.
Market competition with the actual winners so far—wind, PV, and end-use efficiency—will be ferocious and become more so. Steady operation is no longer an especially valuable attribute, so claims that geothermal need compete only with “baseload resources” merit caution. Our diverse world is full of niche markets, but niches scale slower, cost more, risk more, and earn less than versatile win-anywhere options. The most successful developers may be those who, remembering Kittiwake, skate where the cost puck is going to be, not where it was a decade ago. It’s now commonly below $30/MWh, passing through $20, on the way to $10. Electricity is becoming nearly free at wholesale (though delivering it to your meter adds a US average of ~$42/MWh). Does your technology has a realistic prospect of reaching such demanding cost goals? Innovation can be powerful: in recent years, an RMI project called SHINE led three rounds of industry collaborations that cut the installed system cost of groundmount PVs by twofold per round or about eightfold in all. Can geothermal do that? Let’s find out. As Henry Ford said, “Whether you think you can or whether you think you can’t, you’re right.”
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