Massive utility-scale solar projects under development in the deserts of California and the Southwest have been in the spotlight in recent months as they win slow approval from state and federal regulators. But a study released in September by the U.S. Department of Energy’s Lawrence Berkeley National Laboratory found that smaller solar photovoltaic (PV) installations may collectively offer similar promise for increasing the amount of renewable power on the grid.
Traditionally, the reliability of small PV systems’ power output has been a concern for utilities, project developers and grid operators, since all it takes is a few clouds to disrupt the power flow of a small array. But the Berkeley Lab study suggests that when PV plant arrays are spread out over a geographic area, the variability in power output is largely eliminated.
This means that for utilities, the distributed generation of small PV arrays could mean increased efficiency, reduced costs and a quicker path to a cleaner energy portfolio.
There’s been a huge interest in adding more PV power to the grid, but there are concerns about how much can be added because of its output variability, said Andrew Mills, one of the report’s authors. The power output of a PV plant can fluctuate more than 70 percent in less than 10 minutes on a partly cloudy day, according to the report. That makes it difficult for grid operators to maintain a balance between power generation and demands.
Following the model set by wind energy field, where researchers and project developers have long relied on the geographic diversity of turbines to mitigate the fluctuations in power output, the LBL study looked at synchronized solar data from 23 sites in Oklahoma and Kansas located between 20 kilometers and 440 km apart. It found that variability of solar output was six times less than that of a single site over short time periods for site that were 20 km apart. At sites that were 50 km apart, the variability of solar was virtually identical to that of wind over time scales of five minutes to 15 minutes.
That kind of short-term fluctuation is especially challenging to accommodate, according to the report, so finding a way to minimize output variation could cut the costs of balancing reserve power and potentially allow more PV to be added to the grid.
“In short time scales, you don’t have to go very far to get the benefits of smoothing,” or reducing fluctuations of power output, Mills said. “All you have to do is go a little down the road.”
More Power, Less Energy Storage
The report’s findings could also have implications for the cost of managing the integration of more solar power into utility grids by lessening the need for energy storage.
“Geography matters and does change costs,” Mills said. “Accounting for diversity, there’s less cost for managing variability. Geographic diversity reduces costs of generation to a level people are comfortable with.”
For utilities, especially those that are required to meet state renewable portfolio standards, figuring out how to integrate renewable power into the grid is becoming increasingly pressing, and understanding how siting projects will affect output is critical.
Mills said he hoped the study’s findings would help to inform utilities as they make decisions about how to incorporate more renewable power into their portfolios. “Utilities are starting to raise questions internally” about whether to add storage or put limits on PV, he said.
“The structure of the [solar] market is growing to include utility perspective,” said Tom Hoff, founder and president of Clean Power Research, a research and consulting firm that also makes software to calculate the benefits and costs of solar systems.
In California, where utilities are required to get 33 percent of their power from renewables by 2020, a lot of PV growth has come from utility programs, Hoff said. While many of those are large-scale centralized projects, two of the state’s biggest utilities have launched widespread distributed generation initiatives that are expected to produce more than 1,000 megawatts (MW) through rooftop and ground-mounted PV arrays.
500 MW, 1 to 2 MW at a Time
Earlier this year, Southern California Edison (SCE) received approval from state regulators for its plan to install 500 MW worth of mostly small—1 to 2 MW—installations, half of which will be owned and operated by the utility, with the other half coming from independent power producers. The California Public Utility Commission (CPUC) this year also greenlighted a proposal from Pacific Gas and Electric (PG&E) for 500 MW worth solar projects of between 1 and 20 MW, for which the utility plans to spend $1.45 billion over five years.
On the opposite coast, in early 2010 the New York Power Authority launched an initiative to deploy 100 MW worth of rooftop and ground-mounted solar installations across the state.
While PG&E and SCE are also banking on large solar plants, such as a 370 MW plant being developed by BrightSource Energy in the California desert, smaller distributed generation projects can avoid some of the hurdles that make building large utility projects complicated and time consuming.
“Smaller scale projects can avoid many of the pitfalls that have plagued larger renewable projects in California, including permitting and transmission challenges,” CPUC president Michael Peevey said in a statement announcing the approval of PG&E’s initiative. “Because of this, programs targeting these resources can serve as a valuable complement to the existing Renewables Portfolio Standard program.”