Utility-scale solar is still something of a novelty in the renewable energy ecosystem. Large-scale deployment of these multi-megawatt (MW) installations has only recently been enabled in the United States by two key pieces of federal legislation and state-level implementation of renewable energy standards. The market boomed in 2011, adding more than 760 MW of capacity and ending the year with a bullish outlook for 2012. In April, the National Renewable Energy Laboratory (NREL) published a series of three reports on the market, technologies, policies, and cost of energy of utility-scale solar facilities in the United States. These reports provide a comprehensive portrait of this dynamic segment of the solar market.
|Figure 1. U.S. utility-scale solar capacity in development as of January 2012|
The first report in the series, Utility-Scale Concentrating Solar Power and Photovoltaics Projects: A Technology and Market Overview, offers a rundown of all the technologies that have been and are currently employed in producing solar power at the utility-scale (defined in the report as projects of 5 MW or above). Several of these technologies are familiar (e.g., crystalline silicon PV and parabolic trough solar thermal systems), but some exotic representatives are also in the mix (e.g., linear Fresnel, and the far-out “solar chimney” and “space solar” projects currently under contract with California utilities).
The report also provides a snapshot of the utility-scale solar development pipeline as of January 2012. According to NREL’s count, 1,176 MW of utility-scale solar capacity were operational and 16,043 MW were under development with utility or load-serving entity power purchase agreements (PPAs).
Approximately 72% of the capacity in development was comprised of PV technologies, primarily crystalline silicon and cadmium telluride thin-films (which were used almost exclusively on First Solar projects). A full quarter of the 16,043 MW were from concentrated solar thermal power projects: 9% parabolic troughs and 16% tower systems. Tower technology is a newcomer to the U.S. solar scene—presently there is only one operational tower plant, the 5-MW Sierra Sun Tower in Lancaster, California. BrightSource Energy plans to develop the majority of the tower projects in the pipeline (approx. 2.4 GW), and it will sell the power to California’s two largest utilities. Another up-and-coming technology to watch is concentrating PV (CPV), which uses lenses or mirrors to focus sunlight on small and highly efficient solar cells. As of January 2012, 471 MW of CPV were under PPAs.
|Figure 2. Leading utilities with utility-scale solar PPAs|
California’s three investor owned utilities—Pacific Gas and Electric PG&E), Southern California Edison (SCE), and San Diego Gas and Electric (SDG&E)—held PPAs with 72% of the total U.S. capacity in development as of the report’s publication. This is largely due to California’s aggressive renewable portfolio standard (RPS), which mandates that these three utilities derive 33% of their generation from renewable resources. The four states of California, Arizona, Nevada, and Florida—all but the last of which have coupled favorable RPSs with outstanding solar resources—are slated to host approximately 90% of the utility-scale solar projects in the United States.
State RPSs, in concert with the federal loan guarantee program and federal tax benefits (including the investment tax credit, accelerated depreciation schedule, and the Treasury’s 1603 grant program), comprise a policy trinity that is largely responsible for the utility-scale solar boom. This is one of the conclusions of the second utility-scale report from NREL, Federal and State Structures to Support Financing Utility-Scale Solar Projects and the Business Models Designed to Utilize Them.
The report also finds that state RPS requirements (for all eligible renewable technologies) will require an additional 200,000 gigawatt-hours be produced each year through 2020. The hypothetical analysis in Table 1 indicates 2,283 MW of solar resources would be required (assuming they provide 20% of the energy and produce at a 20% capacity factor). That value represents 570 MW per quarter, slightly more than the quarterly PV capacity installed in Q3 2011, but less than that achieved in Q4 2011.
|Table 1. Potential Renewable Energy Annual Capacity Additions|
|Technology||% of Assumed Portfolio||Annual Energy Produced||Assumed Capacity Factor||Avg. Annual Capacity Addition (MW)|
It also appears that some states will hit their solar targets early because of the robust build-out in the last two years. Nine states and D.C. have specific solar renewable energy certificate (SREC) requirements and will need incremental solar capacity of 6,729 MW by 2025. That represents roughly 480 MW of solar capacity installed per year, less than half the total domestic installations in 2010. Of the nine states—and D.C.—with SREC requirements, New Jersey is the most aggressive. The state’s RPS dictates more than a 10-fold increase over its current solar capacity to 3,700 by 2025; that value represents only 264 MW per year (66 MW/quarter). To put that in perspective, the state reached 64 MW of solar installations in Q3 2011, thus achieving the pace required through 2025.
In addition to exploring the impacts of the various policies and mechanisms designed to spur the U.S. solar market, this second report also details the innovative project financial structures that have been engineered to use federal tax benefits. The third report in the series, Impact of Financial Structure on the Cost of Solar Energy, which I discussed in a previous post, performs System Advisor Model runs to determine how these structures affect the levelized cost of energy. All three reports are available at https://www.nrel.gov/publications/.