Does 112% growth in 2017 mean community solar has finally solved its complexity problem?
Solar developers and utilities are moving into the sector fast, writing new rules as they go.
Utilities like big solar projects that they can own, and consumers like rooftop solar that they can own, but there is a third kind of solar emerging that may finally be ready to work for both utilities and consumers.
Community solar projects are interconnected with utilities’ distribution systems in ways that give utilities the same control they get with larger projects. But they are owned or leased by individual customers like rooftop solar. And they are big enough to get economies of scale that make them more affordable than rooftop solar.
Community solar has been held back by the complexities that come with being the right choice for everybody. But recent growth shows it may have begun to resolve those complexities.
The appeal is clear. Community solar's installed U.S. capacity grew 112%, from 387 MW at the end of 2016 to 734 MW at the end of 2017, according to a report released May 1 from the Smart Electric Power Alliance (SEPA) and the Coalition for Community Solar Access (CCSA). This includes utility-administered projects in 33 states and private developer-administered projects in 19 states.
The potential market is huge as it includes all electricity customers without solar-suitable roofs or the financial status or inclination to contract for or own it. The National Renewable Energy Laboratory in 2015 estimated the potential market at between 32% to 49% of the projected 2020 overall 5.5 GW to 11 GW distributed solar market, representing between $8.2 billion and $16.3 billion in cumulative investment.
Community solar’s rapid recent growth shows that potential can become real. Utilities are beginning to understand its system benefits. Financial backers are starting to appreciate its value. And SEPA and CCSA are beginning to standardize policy and make the new concept more familiar to customers.
The industry has begun to provide solutions for community solar’s complications. Financial backers and utility regulators have sometimes been reluctant to commit to projects dependent on subscribers. Consumers have been reluctant to buy portions of promised projects with less than familiar contractual obligations.
To resolve consumers’ uncertainties, community solar advocates created legal and transactional frameworks that led to a state policy matrix, a state policy template, and utility best practices. Pioneering laws in Colorado, Minnesota and Massachusetts led to 2017’s explosion of activity by private sector developers while utilities continue to refine their offerings.
SEPA Manager and report co-author Dan Chwastyk said there are now at least 228 utilities with community solar offerings. “That is almost 10% of U.S. utilities, which is a significant penetration since it is a new concept to them,” he told Utility Dive.
By the end of 2017, the 228 utilities with offerings broke down as follows: 160 cooperative utilities, 37 public power utilities and 31 investor-owned utilities. Only 30% of these programs had a capacity of over 1 MW. But only 20% of programs had a capacity of over 1 MW in 2015.
Utility-administered community solar projects represented 239 MW of total installed capacity, which lags private developers’ 495 MW. But 246 MW were built by the private sector in Minnesota alone, Chwastyk said. “Everybody is lagging Minnesota.”
Tom Hunt, policy director for sector-leading Clean Energy Collective, said Minnesota proves community solar’s potential. “It shows how big private developer-administered programs can be and how much customer interest they can drive in an open market with a workable policy.”
The size of the market and the number of markets “is also starting to make a difference in financing,” Hunt said. “They allow developers to build project portfolios that attract more and lower-cost capital, and financial markets see less risk, which increases the sources of capital and makes the discussions about financing easier.”
The key selling point for community solar is that it increases access, the new SEPA-CCSA paper acknowledges. But it also can offer the cost, reliability, economic, utility-system, climate, health, jobs, and flexibility benefits of other distributed and utility-scale renewables. And “some utilities are starting to explore how community solar can aid grid reliability and other ancillary services,” the report adds.
The new numbers
CCSA Executive Director Jeff Cramer acknowledged that community solar is still a small percentage of overall and new capacities. “But it is the fastest growing sector of the solar industry,” he told Utility Dive.
There are state policies that shape community solar and facilitate private developer participation in 17 states and the District of Columbia, the paper reports. Legislation in at least nine states would add or expand policies. State policy supports growth but does not guarantee growth because some state policies are poorly designed, the report adds.
Community solar's 112% capacity growth in 2017 was preceded by “an average annual growth rate of 68% over the last 10 years,” the SEPA paper notes.
Both Cramer and SEPA's Chwastyk estimated that over 250 MW have been added this year and, by May 1, the sector’s cumulative installed capacity had reached 1 GW. Continued growth in the near term will be driven by “declining solar costs, increasing customer awareness of the business model, and the opening of new state markets by policy,” the paper reports.
The only real limiting factor in the near term is the availability of state policy to support private sector developers because “community solar grows in states that have favorable policy,” SEPA’s Chwastyk said.
Beyond 5 years, Chwastyk sees a growth-limiting factor. As states expand their renewables mandates, the penetration of renewables in utility portfolios will become significant, he said. “Candidates for community solar might be satisfied with utility-delivered electricity and might not want to pay for more renewables generation.”
But as of now, community solar projects are 83% subscribed. Programs administered by utilities and private developers have comparable subscription levels, despite differing priorities. The experience of Poudre Valley Rural Electric Association (PVREA) demonstrates those differences.
Utility v. private developer considerations
PVREA, in northern Colorado, sold out its 116 kW community solar array in 2012 and its 632 kW array in 2015. It brought a 1,500 kW community solar array on line last year that is “about 50% subscribed,” according to Member Relations Manager David White.
Two-thirds of the new array is allotted to low-to-moderate income, non-profit and public service customers. The other third is for residential customers and offers a value proposition comparable to that from rooftop solar, White told Utility Dive. PVREA is using the array’s unsubscribed portions as utility generation while it markets the offerings.
This reveals utility considerations that differ from private developer considerations. Private providers are driven by market factors, while utilities are obligated to serve all customers. It benefits utilities to have an offering that will attract customers considering moving to rooftop solar. And utilities can use unsubscribed output to serve load.
Hunt agreed these are important differentiations. “Third parties must have projects subscribed or they don’t get paid and their financiers don’t get paid,” he said. “That natural market mechanism makes the projects work.” An example is the Clean Energy Collective's 21 MW project for South Carolina Electric and Gas. Though not yet interconnected, it is already oversubscribed, he said.
“Some utilities have been very strategic about designing programs with excess capacity that gives them flexibility in allocating capacity, especially with solar as cheap as it is,” Hunt said. “The question is whether a project is unsubscribed for strategic reasons or because it was poorly designed.”
The new plan
Despite the growth in community solar, costs are already something of an obstacle, according to the SEPA-CCSA report.
Administrative costs, which include customer acquisition and customer billing and crediting costs, are $0.12/watt for projects of less than 1 MW. They fall to $0.09/watt for projects bigger than 1 MW, which are more often built by private sector developers.
To address the complexities of customer acquisition and customer billing and credit handling that drive costs, SEPA obtained a grant from the U.S. Department of Energy Solar Energy Technologies Office. Using extensive industry feedback, Chwastyk led efforts that resulted in the “Decision Tree” detailed in the new report.
Over half of utilities told SEPA their biggest challenge is customer acquisition. By contrast, private developers “overwhelmingly indicated that working to meet complex and diverse policy requirements is their major challenge,” the paper reports.
“The original idea was to create basic models that every utility could use, but there is too much market variability,” Chwastyk said. “The Decision Tree begins with four basic questions that need to be answered for any market.”
The first question is whether the utility or a private sector developer will be the program administrator or whether responsibilities will be shared. The next decision is whether the customers will have an up-front payment or an ongoing monthly payment. Some programs are moving toward offering customers both options.
The third decision is whether or how to limit participation. Subscriptions can be open to residential and commercial electricity users or can be strategically apportioned among various customer classes, including low income and non-profit customers. Finally, decisions must determine the “key terms and conditions” of the subscription, including how long a customer is required to participate and how long the program administrator guarantees the terms of the subscription.
The approach is already working for utilities. A July 2016 Entergy Mississippi community solar proposal filed with state regulators references extensive SEPA guidance on program design choices.
Chwastyk said the Decision Tree revealed two crucial takeaways. First, “implementing it is almost worthless if the market research has not been done, because so much of the design should be defined by who the program is being marketed to and what they want,” he said.
Second, utility-administered programs “need a champion within the utility who will be [their] advocate,” Chwastyk said. Building a community solar project requires people from rates, customer engagement, the distribution system, engineering, and other utility departments to come together and somebody has to make sure it gets moved through the system.”
Clean Energy Collective’s Hunt said the next questions facing community solar are how many states will develop policies and how the product can be better. “Those answers are not necessary right away because we can grow by GWs with the present products,” he said. “But they might be necessary to grow beyond that.”
Energy consultant Jill K. Cliburn led the DOE-funded three-year Community Solar Value Project, which was aimed at advancing understanding of the sector's value proposition. She saw in the new report indicators of community solar's greater potential. “If policymakers get it right, community solar could rival the rooftop solar market within a decade,” she emailed Utility Dive. “But that’s a big if.”
The growth in Minnesota is “impressive,” but “success is not all about speed to scale,” she said. “It is worth taking the time to develop community solar options that are truly rooted in the community.”
Utilities, and especially investor-owned utilities, are concerned that regulators and policymakers will undermine their efforts with overly rigid or prescriptive requirements, she said. Instead, utilities should be encouraged to develop a “portfolio” of projects with a full range of offerings for all customer classes.
Finally, community solar “is fairly complicated” but “does not have to look complicated to the customer,” Cliburn said. With a simpler presentation, it could fulfill its potential to satisfy both consumers and utilities because it could be offered “with pricing signals or solar-plus service packages that address the duck curve or other emerging grid issues.”