San Francisco Geothermal Innovation & Investment part 4

A week after the conference, I finally manage to write up the rest of my notes on the conference.

Major developers’ insights into current challenges and opportunities: The fifth speaker of this session was Gary Thompson of Sierra Geothermal Power. Gary was giving an overview into his company, which has projects with an overall capacity potential of around 500 MW. He sees the biggest challenges for geothermal financing in the drilling cost, generally the overall high cost to reach the feasibility stage (which essentially is high risk capital needed). The cost he sees at US$ 1 million/MW in the feasibility stage and about 70% of MW behind pipe. So drilling makes up about 25% of Capex.

There are limited drilling technology advancements and there is a need for lowering drillign costs and the risks involved in drilling.

Sierra needs about US$ 186 million to the feasibility stage (for its Tier 1 projects) to be financed by JV partners, DOE cost share and limited equity. The debt required for the company is about US$ 558 million assuming the 30% cash grant (ITC) would save about US$176 million, which would leave a need for US$384 million term debt. The company sees an overall capacity in the U.S. of 6,000 MW (in the 10 year time frame ) and about 40,000 MW by 2050, which still constitutes only 4% of total U.S. power market. There simply is a need for higher priced PPAs.

The last talk of this session was by Yannis Banks, who spoke on behalf of Caldera Geothermal. Caldera is a relatively new player with some interesting background mostly in exploration methodologies. Those were mostly also the topic of the speech.

In the Q&A part, it was discussed that transmission can also end up as a high cost with the developer, as he would have to cover the studies. Regarding what it needs to prove new technologies, e.g. on UTC, it was talked about that a 15-20 year reliability through a performance guarantee is needed. The high cost of getting through to the feasibility stage was mentioned. General opinion was that running an own drilling rig isn’t feasible as one simply doesn’t have the the people.

Enhanced Geothermal Systems: Prospects for large-scale commercialization: That was the second big session of the day with Ralph Weidler of Q-Con/ Geothermeon AG in Germany and Susan Petty of AltaRock.  Both made a point of clarifying the definition of EGS, which was described by Ralph as “integrating advanced technologies into the reservoir development program.”

In the end they made a good case for EGS, while confirming challenges in approaching financing, given that there aren’t that many reference projects out there.

Advances in drilling and fracturing technologies, were than discussed by Lou Capuano of ThermaSource and Jared Potter of Potter Drilling.

Lou Capuano started with going into the major cost elements of drilling, which are mostly the casing (tangible cost), well heads (some have a lead time of 40+ weeks), the transport of the rig, logging and fuel cost. There are now more oil rig firms coming into the markets, but they don’t have the experience. So the only way to lower cost is to be found in casing, streamlining cementing, and saving cost in mobilization of rigs.

Jared Potter than discussed his firm and his view on the industry. Basic message there aren’t enough rigs out there to reach the ambitious EGS goals. To reach 100,000 MW, so Jared, one would need to drill one borewell per day for the next 50 years. The other big point he made was the high cost of drilling deeper for EGS projects, casing and cementing cost is exponentially higher and as well any other subsurface work.

Low-temperature geothermal resource exploitation was then covered by Brent Cook the CEO of Raser Technologies. He gave an overview on his companies view on why they went into Geothermal and what he sees as the current geothermal financing issues. The overall provisions are getting better through all stimulus activities by new legislation and companies have possibilities to “recession proofing” their funding. Raser admitted that the Thermal 1 plant of the company is more expensive than traditional geothermal plants with one big turbine rather than a set of small-scale set of lower-heat turbines (here UTC)., but modularity and diversified project base make things more smoothly and particularly speedier. The UTC units can handle 315 degrees Fahrenheit (around 150 centigrades) with an option up to 400 F and are providing about 3-5% more than name plate capacity.

The rest of the sessions I unfortunately missed, so I cannot write about them. These were Hydrocarbon/ Geothermal co-production (Josh Nordquist, Ormat Technologies), Electricity generation from waste heat (Richard Langson, Electratherm) and Potential for operating EGS with CO2 as heat transmission fluid (Karsten Pruess, Lawrence Berkely Laboratory).