If cost were no barrier to renewable energy development, what would policymakers choose? Geothermal would come out top, without question. Geothermal is a perfect complement to intermittent renewable sources such as solar and wind and provides baseload power.
But geothermal is the long-lost favourite hippy uncle who dropped out before reaching his potential. At the GEA Geothermal Energy Finance and Development Forum 2012 earlier this month, it was clear why the technology had been left behind in the 1970s along with flared trousers, CND and tie-dye.
Thanks to the Geysers just north of the Napa valley, geothermal energy produces around 40% of the state's renewable energy in California. But that figure could be much higher. Nationally, geothermal provides 13% of non-hydro renewable electricity generation, or less than 1% of total US electricity.
According to a recent report from Pike Research, total US geothermal capacity will reach 4.2GW in 2020, a 36% increase from the 2010 level and significantly more than any other country. That represents almost 30% of total worldwide geothermal power capacity in 2020.
In the Philippines and Indonesia, most of their energy is geothermal. But in the US, geothermal is treated like the long, grey-haired hippy uncle who's never quite realised his potential.
Subsidies over the past 30 or 40 years have favoured the sun and wind. The entire industry received $368.2m from the Recovery Act 2009 - less than Solyndra's half billion. There are 24 ARRA projects which should bring online around 400 MW of new hydrothermal resources by 2014. The main driver for investors, however, is a tax credit hybrid from the wind industry which will expire next year.
The DoE's Geothermal Technologies Program has requested an unlikely $100m for 2012. But the real story of the rise and fall of geothermal's funding fortunes is on page 6 of this GTP presentation.
From 1976, the US geothermal industry enjoyed sustained government funding. For almost three decades the industry was lucky to receive $50m a year. It peaked thanks to ARRA again in 2009. But funding has now collapsed.
But given the resource in the US, geothermal should not be stuck in the 1970s and should be primed for technological breakthroughs.
Investment focus has in recent years turned from California to Nevada. But Enhanced geothermal systems (EGS) which inject water into fractured rock would expand resource potential beyond the western states. More than 100,000 MWe of economically viable capacity may be available in the continental United States, representing a 40-fold increase over present geothermal power generating capacity, according to NREL.
But like all good ageing hippy uncles, the geothermal industry is full of fantastic apocryphal yarns. Salton Sea in Southern California's Imperial Valley now owned by Calpine was so rich in geothermal resource that its first developer used to crumple a cigarette packet and throw it on the ground telling his engineers to drill where it landed.
It's rarely that easy. Last September the US finalized a loan guarantee of up to $350 million for the Ormat project in Nevada with a nameplate capacity of 113MW. But whether the operators will achieve that capacity is difficult to determine.
And although some wells strike it lucky with more resource than was expected, many more come up dry - much more so than in the oil industry.
One industry analyst told me that this was because resources, ie boiling water, tend to be found under "angry" crushed rock which makes seismic surveying more difficult than exploration for oil which tends to be trapped between strata of rock.
This is only one of many technical reasons why geothermal is so expensive.
Conversion technology, depth, pressure, temperature and draw down all play a part. The capital cost of a geothermal plant can range from $1,600 to more than $5,000/kW of capacity, according to the California Public Utilities Commission.
Mackinnon Lawrence, an analyst at Pike Research, described geothermal as the "workhorse of renewables" and the "tortoise that won the race". But acknowledged that geothermal can take 6-8 years to come to market, much longer than solar and wind.
He said that Pike forecast 16GW of global capacity by 2020, an increase from around 10.7GW today. But the market is too dense - 43 developers in the US alone - and Pike expects contraction among industry players.
Rick Rodgers at Montgomery St Financial said that typical drilling costs were an estimated $3m/MW - $6m/MW, 100% more expensive than oil and gas partly because drill heads are around three times more expensive in geothermal. He also pointed out that as solar costs were being driven down, it has received 30x more 1705 support than geothermal.
Jonathan Weisgall of CalEnergy and MidAmerican described geothermal as an art, not a science and a leading cleantech VC recently told me that two areas VCs weren't interested in: wind and geothermal…
But geothermal strikes me as an industry primed for technology innovation, but it won't come without investors, who won't dip their toes in the water without subsidies or longer term horizons for tax credits that more appropriately reflect the longer development period for projects.
As Lachlan Mclean from the US Renewables Group said: "Investors are waiting for catalytic events and industry leaders to emerge before investing."
But as a potential for baseload power to complement intermittent solar and wind as existing generation retires, policymakers need to revisit the ageing uncle of clean energy and bring the structure of subsidies up to date.
Anne Simpson, senior portfolio manager at CalPERS, told the conference that $7bn had been allocated to the pension fund's clean tech investments. The CalPERS cleantech portfolio is very heavy on solar which makes sense when utilities agree 20-year long Power Purchase Agreements with developers. But Simpson could not say whether geothermal made it into the cleantech portfolio.
But its long-term horizon of valuable energy production (Geysers has been pumping power for 50 years) makes geothermal a perfect fit for pension funds - especially given Simpson's admission that even if the scheme ended tomorrow, they'd still need to manage funds for the next 70 years.