by Debra Kahn
A new chapter in utilities’ relationship with rooftop solar is evolving in California.
The state’s three major investor-owned utilities are developing proposals to buy rooftop solar power and sell it to customers who want to be greener than the norm.
There are community renewables programs under development or already being implemented in several other states, including Colorado, Massachusetts, Minnesota, Nebraska, Texas and Wisconsin. California’s is being looked to as a potential model because of its large size — a maximum of 600 megawatts among the three utilities through 2019 — and the state’s history of pioneering renewable energy policies.
“The way California’s program ends up being implemented will have an influence on the broad appeal of shared renewables across the country,” said Michael Wheeler, vice president of policy initiatives at Recurrent Energy, a solar developer interested in participating in the program.
This summer, Pacific Gas and Electric Co. plans to solicit an initial 50 megawatts of small-scale renewables from throughout its territory, under a new program currently known as “green tariff shared renewables.”
“We don’t have our customer-facing name yet,” said Molly Hoyt, PG&E’s principal program manager. “It’ll be better than that.” The other two utilities, Southern California Edison and San Diego Gas & Electric, plan to start their programs early next year.
The program, mandated by a 2013 bill by state Sen. Lois Wolk (D), is capped at 600 megawatts among the three IOUs through its sunset date in 2019. PG&E’s share of that is 272 MW, 45 MW of which will be reserved exclusively for residential customers.
This isn’t the utilities’ first foray into marketing renewables to individual customers. PG&E had a program in 2007-11 called “ClimateSmart” that sold customers carbon offsets, but due to low demand, it had to dip into shareholder money to meet its goal of offsetting 1.36 million tons of carbon dioxide (Greenwire, May 14, 2012).
This time, the utilities plan to sign contracts with small-scale developers in their service territories and also allow customers to enter directly into agreements with developers for hyper-local projects, defined as installations within 10 miles of at least 51 percent of the subscribers. Both forms of power will still be delivered over the utilities’ infrastructure and use the utilities’ billing services.
PG&E had originally considered just selling renewable energy credits, which represent the environmental attributes of green energy generated elsewhere on the grid, but decided to go with actual renewables in order to ensure that the projects are “additional,” meaning they would not have been built if the customer hadn’t signed up to buy the power.
“You know what? We know 860 utilities have this other type of program. Let’s go a step beyond here,” Hoyt said. “Let’s be leaders; let’s ensure for our customers that additional renewables will be built.”
The latest offering has been in the works since 2012 and, unlike ClimateSmart, doesn’t rely on any shareholder funding. It also is designed to function independently of regular customers, so all of the money will flow from customers who sign up either for the generic “green tariff” or the hyper-local option, known as “enhanced community renewables,” or ECR.
The green tariff will be offered as either 50 percent or 100 percent of a customer’s power mix, and the renewables will come from projects sized between 0.5 and 20 MW. ECR projects will be sized between 0.5 and 3 MW and can replace up to 120 percent of a customer’s energy use, depending on the customer’s agreement with the developer.
If the green tariff projects aren’t fully subscribed, the excess power can be used to fulfill the state’s renewables portfolio standard, which is currently set at 33 percent by 2020. Legislation currently moving in the state Senate would extend the RPS to 50 percent by 2030.
PG&E is taking some wisdom gained from ClimateSmart by attempting to locate the new projects where the previous program was most popular. The utility envisions three procurement “buckets” for the ECR portion: within the communities with the highest ClimateSmart uptake, within the nine-county San Francisco Bay Area region, and in the largest communities outside of the Bay Area.
Is it affordable?
The program’s financial independence from the utilities could be a liability for the hyper-local option, according to a solar advocate. Under the rules being written at the California Public Utilities Commission, customers that want to buy power from a specific project can sign a service contract of any length with the developer, but they can only commit to a maximum one-year subscription with the utilities themselves. That means the price on the customer’s utility bill can be recalculated annually, which would make it less attractive to potential customers.
“One of the main concerns we have about the pricing structure is unpredictability,” said Susannah Churchill, West Coast regional director for Vote Solar.
“If I’m a customer that’s trying to decide whether I want to subscribe to the cool new local solar project near my kid’s school … it’s a very risky proposition for me to sign up over the long term with that renewables developer,” she said.
Another concern is the sheer cost of the program. Based on the utilities’ filings, Churchill calculated a premium of 2.5 to 6 cents per kilowatt-hour, which translates to a 15-35 percent increase over regular rates.
“It’s unfairly high, and it’s not going to be affordable to many people,” Churchill said. “How many low-income renters are going to be able to pay 15-35 percent more on their bill to subscribe to renewables?”
Wheeler, of Recurrent, also said the ECR side of the program could prove difficult. Under the normal solar development process used for the RPS or the green tariff, a developer finds a suitable site and pursues interconnection and environmental permits before signing a utility contract and committing to a price. Since ECR projects have to be sited close to the customers, it creates a chicken-and-egg situation where developers have to quote a price without knowing the site’s specifics and may have to change their cost projections after settling on a final site.
“That makes it very challenging to promise to a customer what a project’s value or cost will actually be and then go find it, spend the two years that it takes to bring it to the point of groundbreaking, and then go back and say ‘We did it,’ or, ‘It’s going to cost a little more than we thought,'” Wheeler said.
State Sen. Wolk is trying to address the funding issue with a new bill this year, S.B. 793. The bill would specify that customers are allowed to receive a “predictable” bill credit and charge for up to 20 years. It passed the Senate Energy, Utilities and Communications Committee last month and is now awaiting a hearing in the Senate Appropriations Committee.
PG&E has not taken a position on the bill but said in an April 1 letter that changing the rules to allow a 20-year fixed charge could delay CPUC’s implementation of the overall program. CPUC is already nearly a year late in approving the final rules, according to the schedule set out in S.B. 43.
“We hope the author will consider the potential unintended consequences of this bill,” PG&E’s state government relations manager DaVina Flemings wrote.
The programs don’t appear to have engendered opposition from independent rooftop solar developers, who have been active in California on policy debates over the charges and rebates customers receive when they install their own solar panels.
Southern California Edison projects that they will have 26,000 subscribers by 2019 — a total of 0.5 percent of their customer base — while PG&E is estimating a maximum of 40,000.
Wheeler said the programs pose “almost no competition between rooftop developers and utilities,” citing a report released by the National Renewable Energy Laboratory earlier this week that estimated nearly half of households and businesses aren’t suitable for rooftop solar, often because they are renters, have insufficient roof space or are in locations with too much shade (ClimateWire, April 28). “Utilities have a market to serve here,” he said. “It does not have to be an either-or type of situation here; there’s plenty of market share.”
The programs could compete with another renewable energy option that has been gaining steam in California, known as community-choice aggregation. It allows local governments to buy their own electricity and deliver it using the incumbent utility’s infrastructure; several jurisdictions in PG&E’s territory have implemented it, including Marin and Sonoma counties, and San Francisco is also considering it. All of the CCA programs so far have emphasized their electricity’s renewables content as an advantage.
A renewables advocate who has been involved in the proceedings said the competition would be welcome.
“To the extent that CCAs may be competing with the IOU projects in this area, that’s definitely an issue that’s on the table right now at the PUC,” said Stephanie Chen, energy and telecommunications policy director for the Greenlining Institute, a nonprofit that advocates for racial and economic equality and has been encouraging the utilities to site the projects and advertise them in low-income neighborhoods.
“For Greenlining, we sort of hope it works out that way,” Chen said. “Within the safety of the regulated structure, we can create a little bit of competition for who’s going to do it greener, who’s going to do it better.”