PURPA wars are heating up again, and self-dealing conflicts are re-emerging. A Montana commissioner identifies weaknesses in supply procurement processes.
Cali Gets it Right
Not your father’s feed-in tariff.
bad things can happen. If subsidy levels are set too low, then the program will fail and few projects will get developed. If subsidy levels are set too high, then there will be a flood of demand as developers and equipment providers look to take advantage of an over-subsidized market. The date-based mechanism doesn’t easily allow for the government or utilities to cap their exposure. As a result, an over-subsidized market can result in aggregate payouts of subsidy dollars far higher than anticipated or budgeted.
The highest-profile case of these risks happened in Spain during 2008. The Spanish government put a FiT into place similar to the program that had been successful in Germany. They used a date-based trigger, allowing developers who completed their projects before year-end to sign a 20-year fixed-price PPA with the government. Unfortunately the program designers set the subsidy level far too high. The Spanish market grew from negligible size to more than 2 GW in a single year. This resulted in far more solar being developed in Spain than the government had hoped for—or could really even afford. As a result, the Spanish government was forced to completely overhaul the program and essentially default on its obligations by reducing FiT payments to projects already up and running. All these changes brought turmoil in the Spanish and global solar markets, resulting in the Spanish market shrinking back to almost zero before climbing back to a more sustainable level of approximately 500 MW per year.
The elegance of the reverse auction mechanism is that it relieves the pressure on the program designers to set the correct incentive level. Instead the mechanism allows the market to set the incentive levels by forcing developers to compete to participate in the program. The mechanism also easily allows program designers to cap their risk and achieve their goal of developing a specific amount of generation capacity. The only apparent danger here is that it could attract bidders developing highly speculative projects. If participation hurdles—cash deposits, development experience, and demonstration of project viability—aren’t set sufficiently high, then the program will be flooded with projects that will never be built.
This is a problem that California is already facing, with previous efforts to meet the state’s renewable energy portfolio (REP) standard through the development of large utility-scale power plants. Unfortunately, to date, the vast majority of the PPAs signed by the utilities haven’t resulted in renewable energy being produced. If the program designers can avoid this trap, then the program should successfully result in the rapid development of a massive amount of solar energy at the best market prices.
Lastly this program seeks to encourage growth in distributed generation by allowing only projects between 1 MW and 20 MW in size to participate.
Distributed generation can offer several advantages over central plant or utility-scale renewable projects, most notably that distributed projects have a higher success rate, in terms of actually getting built. Also they don’t have the same transmission, interconnection or environmental approval hurdles that large solar farm projects usually face. Utilities can