California regulators work the check-out at the solar market

  •   The average contract price approved by the CPUC has increased since 2003.
    Looking back at data since 2003, the average contract price approved by the CPUC has increased
  •   PV installed cost forecast.
    Myles O’Kelly of Itron forecast some impressive figures for PV costs, with a mid-range of $1,500 per kilowatt by 2030
  •   CSP installed cost forecast.
    Concentrating solar power with thermal storage could also see similarly attractive price declines from just below $8,000 per kilowatt today.

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Felicity Carus
Felicity Carus
Felicity Carus is the only UK journalist to be regularly reporting on clean energy policy and finance from California for a global audience. Before arriving in San Francisco in 2010, Felicity was on the Guardian's environment desk in London after stints at the Sydney Morning Herald in Australia and Interfax in Russia. She first "broke" into the renewables industry with a commission in the mid-90s to write a book on how to install a solar water heating system with a rusty old radiator. The industry has come a long way since then, thankfully…

California's Public Utility Commission (CPUC) last month reported to the state legislature on the cost of renewables. The Padilla report, so-called because of a bill introduced by Senator Alex Padilla and passed in 2011, mandates the CPUC to publish the costs of renewable contracts and utility-owned generation every six months.

The first report was published in February last year and its aim is to at least partially lift the veil on the true cost of the secretive power purchase agreements in the Renewable Portfolio Standards.

Overall, the news was good. Contracts approved in 2012 were priced at an average of 9.6c/kWh to 9.9c/kWh. These costs are slightly lower than those approved in 2011, which were 12.6 c/kWh on average, said the report.

RPS procurement expenditures for 2012 were approximately 7.7c/kWh to 7.8c/kWh compared with last year's average of 8.0c/kWh.

"Contract prices for 2012 show a steady decline from the prices in prior years (2003-2010). The downward trending prices prove that the renewable market in California is robust and competitive, and has matured since the start of the RPS programme," it said.

But looking back at the data since 2003, the average contract price approved by the CPUC has increased (see first slide).

"One reason for this increase is that the IOUs contracted with existing renewable facilities at the beginning of the RPS programme and with mostly new facilities in more recent years in order to meet the ambitious 20% and 33% RPS target," it said.

"These new facilities typically result in higher contract costs in order to recover the capital needed to develop new facilities. In addition, contract costs have increased in part due to changes in the technology mix, increases in commodity costs, and demand exceeding supply."

The CPUC's report confines itself to renewables, but the California Energy Commission (CEC) mandated another report that will actually shape the state's energy mix over the next several decades.

Every year, the CEC prepares an Integrated Energy Policy Report (IEPR) that provides an overview of major energy issues and trends facing California and makes recommendations for the governor based on reliability, demand, resources, the environment, enhancing the state’s economy and protecting public health and safety.

The final scoping order was released last month, public workshops will continue through August and the final IEPR will be ready for adoption in November.

New electricity infrastructure, possible 2030 RPS targets, climate change impacts, energy efficiency, electric vehicles, energy contingency planning, reliability implications of outages at California’s nuclear plants are all high on the CEC's agenda.

Last month, the CEC met to discuss with stakeholders (largely utilities and generators) how much new utility-scale renewable and fossil fuelled generation would cost over the next decade.

Some very revealing observations were made by those presenting their forecasts to commissioners who want to have some idea of how much it costs to build new generation in California before making their recommendations to the governor.

Ivin Rhyne, the CEC's project lead for the IEPR, said: "Incorporating other elements of the investment decision is the key to keeping the levelised cost and the cost component pieces that we're studying in their proper context, because the system itself, and the decisions associated with those systems are built on more than simply brute economics.

"In other words, it's not just a payback to any particular investor, but in fact, it's meant to be a public good …that the Public Utilities Commission, the Energy Commission and a number of regulatory agencies are involved in making sure that it stays a public good.

"So, elements like the environmental benefits, as well as other pieces, are a part of that decision and it's something we want to make sure is properly held in its place so that the cost doesn't become the one and only thing we ever talk about."

Richard McCann of consultants Aspen Environmental Group offered insight into the financing structures for renewable projects.

"For renewables, the wind and solar projects are considered less risky than biomass and geothermal projects, and in large part because of the technology and fuel source risks that they perceive.

"That biomass, for example, has a cost associated with the acquiring the biomass to burn in their boilers, that solar doesn’t have, for example.

Although good for the market overall, rapid cost declines were introducing a level of uncertainty that was difficult to price into a project.

"Lenders are structuring their debt to account for the technology risks of solar projects," he said. "One of the risks for solar projects is that the costs are dropping so rapidly for particular projects that the timing of when you sign your PPA and the construction period that you have for the project can actually present a risk for those solar projects."

McCann also said that they found that debt financing for gas-fired generation could be higher than renewables.

"We think, or we were told to a certain extent that was because the projects are typically larger than the renewables projects that are being financed out there.

"The tenors for the gas projects are typically also shorter than for the renewables and that, we understand, is likely due to differences in the terms for the PPAs… renewables often get 20 to 25-year PPAs, where the gas-fired PPAs are 10 years or less."

Another reason for the difference in debt is that "long-term" contracts for natural gas supply tend to be much shorter, perhaps only a couple of years as opposed to solar's free feedstock.

Meanwhile, Myles O’Kelly of Itron forecast some impressive figures for PV costs, with a mid-range of $1,500 per kilowatt by 2030 (see slide). He also said that concentrating solar power with thermal storage could also see similarly attractive price declines (see slide) from just below $8,000 per kilowatt today.

The CEC still has a lot of work ahead of it, particularly given that pieces of California's energy system seem to be missing from the process. Distributed generation, anyone?

Manuel Alvarez, manager of regulatory policy and affairs at Southern California Edison, said: "The Energy Commission should expand beyond central station generation and address distributed solar applications in both urban and rural environments.

"In SCE’s experience, the cost to construct, including interconnection and land acquisition, can vary substantially depending on location. Given the state’s interest in exploring distributed generation, a public source for solar photovoltaic costs that considers these differences will help policymakers and stakeholders evaluate the cost implications of various decisions in this area."

The Clean Coalition has also pressed for consideration of DG and Pacific Gas & Electric is also on a shortlist of those who have thrown their hat into the policy development ring. So far BrightSource appears to be the only solar company to be directly involved; other businesses will no doubt follow through the summer to make sure the regulatory daylight hits their particular market segment.

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