The road to bringing more distributed solar into the utility resource mix runs through long-term planners.

Solar complicates utility planning decisions, according to the findings presented in Treatment of Solar Generation in Electric Utility Resource Planning, a survey of 28 utilities and load-serving entities in twenty-two states from the National Renewable Energy Laboratory.  What planners consistently say is that they want more and better data.

A utility’s integrated resource plan (IRP) “is a long-term view to balance resources and ensure reliable service for fifteen to twenty years into the future,” explained report co-author and Solar Electric Power Association Utility Strategy Director John Sterling during a SEPA webinar. “The two key factors are load growth and available resources.”

Utilities look at a wide range of factors to determine “the best set of future decisions” to serve customers “at the lowest possible cost.” 

More recently, IRPs have begun to consider renewables mandates and generation diversification. Though such factors may not meet least-cost standards, NREL’s report says that they address “non-cost metrics” like emissions requirements and risk reductions. “Some utilities note that an exclusive focus on ‘least-cost’ may not yield the optimal portfolio of resources.”

Most planners anticipate more distributed and utility-scale solar coming into their systems, but they need more data to do long-range modeling.

How utilities will work with increasing levels of solar will be one of the themes of the upcoming U.S. Solar Market Insight Conference. The panel "Tomorrow's Utility in a Distributed Generation World" will include FERC Chair Jon Wellinghoff, while "Innovation at the Grid Edge: The Foundation for a High-Penetration PV Future" will include PG&E Renewable Integration Senior Manager Michael Avidan.

The newest edition of the GTM Research/SEIA U.S. Solar Market Insight quarterly report will be released at the conference.

Planners have solar generation profiles from existing plants and sources like PVsyst and NREL’s PVWatts program, which provide a year's worth of typical data, albeit limited in scope. Cost information is the “key uncertainty,” the survey found. Some planners “believed that U.S. Department of Energy SunShot goals for PV may be achieved by 2020; others said costs will continue to go down but at a slower pace, and still others said that solar costs have reached their minimum and will flatten out.”

Planning assumptions, which reflect that range of cost forecasts, could slow solar growth. “It is a chicken-and-egg problem. They may see solar as too expensive,” said report co-author Karlynn Cory, an NREL Senior Energy Analyst. “But some of the recent cost reductions are the result of deployment. If planners wait for prices to drop, prices won’t drop because deployment won’t grow.”

Planners, however, are charged to protect their customers and stockholders. “If a lot of solar is procured at a high cost and the price drops,” Sterling said, “it could trigger a prudency review.”

MidAmerican Holdings protected itself from such a review in a recent wind buy, Cory said, by getting pre-approval from regulators.

Solar’s capacity value is identified as a “key question” for planners. “A solar generator’s capacity value is the percentage of its nameplate capacity that is anticipated to be reliably available to meet daily and seasonal peak demand,” the report explains. Utilities count on “fully dispatchable conventional generation” as load fluctuates. “In contrast, the most commonly deployed solar technology, fixed-axis solar PV, generates only when the sun is available…so solar energy may not correlate perfectly with a utility’s need.”


Between 60 percent and 76 percent of the planners assigned a capacity value of 0 percent to 60 percent for fixed PV and up to 80 percent for PV with tracking. Only 26 percent to 44 percent of utility planners assigned any capacity value to CSP with or without storage, PV with battery storage or concentrating photovoltaics. Between 56 percent and 74 percent of planners used a 0 percent capacity value for solar.

Utility planners also use values ranging from $2.00 per megawatt-hour to $11.00 per megawatt-hour for the cost of integrating variable solar into the grid. The combination of storage and PV is not included in modeling by the majority of planners because of a “lack of credible data and analysis.”

The majority of utilities treat customer-sited solar as “a net load impact,” Sterling explained, but it may be more accurate to treat it as “a resource option.” Though it is difficult in a twenty-year planning study, he said, modeling solar capacity value on an intra-hourly basis could allow planners to “put the price curve on the resource side of the equation at a zero-fuel cost and see how much lower the overall revenue requirements are.”

“Separating DG out of the load provides more granularity into one of the key drivers of planning decisions, which is load,” Cory added, “and allows the utility to better understand the impact of the DG.”