A tale of 2 states: Massachusetts and California provide different lessons on growing community solar
The Golden State has no privately developed community solar while the Bay State has the second most in the U.S. — Why?
There are lessons to be learned in why sunny California has built 0 MW of privately developed community solar and shady Massachusetts has 130 MW in place and more coming.
While Minnesota leads the U.S. with 168 MW of private-sector-led community solar, Massachusetts, with much less open land and cloudier skies, is second. California, with wide deserts under abundant sun, has none.
There are two important areas of “distinct difference” between Massachusetts and California, according to Tom Hunt, director of policy for U.S.-leading private sector community solar developer Clean Energy Collective (CEC). The overall rate of compensation in Massachusetts is much higher, more easily understood and stable. And the regulations, though not easy, are “manageable and rational.”
Through October 2017, the Smart Electric Power Alliance counted at least 183 utility-led community solar programs with almost 380 MW in online capacity. Policymakers across the country now designing emerging community solar programs led both by utilities and the private sector can learn from the flops and achievements in California and Massachusetts.
Those lessons are especially important to New York policymakers now designing what could be the next important community solar market.
New York intends to include community solar in its 50% by 2030 renewable energy portfolio, according to David Sandbank, director of New York State Energy Research and Development Authority's (NYSERDA) New York Sun program. “And when it comes to community solar, the key to sustainable growth is not sun but regulatory decision-making,” Sandbank told Utility Dive.
The Massachusetts achievement
Clean Energy Collective has built 34 projects and almost 50 MW of installed community solar capacity in Massachusetts, part of 130 projects across the U.S. representing more than 350 MW of installed capacity. Hunt said the regulatory hurdles and required timelines in Massachusetts “line up with a developer’s business practices.”
Incentives under Massachusetts’ existing Solar Renewable Energy Certificate II (SREC II) program have been clearly defined and are sufficient, Hunt said. And the Solar Massachusetts Renewable Target (SMART) program, designed to replace SREC II and expected to be in effect by mid-2018, appears to be equally workable, he said. SREC II allowed for “a stable development business” and the SMART program “will likely offer a few more years of stable development.”
Laura Pagliarulo, director of community solar for customer acquisition specialist CleanChoice Energy (CCE), agreed. Like SREC II, the SMART program appears to offer certainty over the full development cycle, she told Utility Dive. CCE is targeting 100 MW of new capacity over the next three years.
The value to the customer will no longer be tied to the retail rate net energy metering (NEM) credit but to the generation portion of the bill, Pagliarulo said. The new program includes other incentives and will enlarge the market by allowing allocation of credits across a wider range of customers.
Mark LeBel, staff attorney for renewables policy advocate Acadia Center, agreed. Massachusetts’ already liberal transfer of credits provision is key, he said. Often called virtual net metering, it has no formal label in Massachusetts.
“The easy allocation of credits and a stable and predictable credit value are both key to financing and development,” LeBel said. “Once a developer has site control, has subscribers, and meets other development thresholds, there is a relatively well-defined process to apply incentives and interconnection,” he said. “It is not easy, but it is relatively straightforward.”
There are big questions still to be confronted in the SMART program’s community solar framework, LeBel said. National Grid and Eversource jointly proposed stricter credit allocation rules, a reduced credit value and limits on total credits, LeBel said. “Together, they would make it difficult for community solar providers to offer a good value proposition.”
CCE CEO Tom Matzzie told Utility Dive the SMART program includes one especially important new feature. “This program’s adequate but lower compensation structure will allow many more projects to be built.” He would, however, like to see SMART's community solar adder uncapped “so that all residents — including low-income residents — can go solar,” he added.
The California flop
By the numbers, the Green Tariff Shared Renewables (GTSR) program, authorized by California’s 2013 Senate Bill 43 and implemented by state regulators in 2015, has been an abysmal flop. Under the GTSR label, a total of 600 MW of community solar is authorized through utility-led initiatives and the Enhanced Community Renewables program for private developers.
About 33 MW of capacity has been built, all of it by the state’s three investor-owned utilities (IOUs). In November, Pacific Gas and Electric (PG&E) emailed Utility Dive it had about 22 MW of installed capacity in its Solar Choice program. Southern California Edison (SCE) reported 7.05 MW for its Green Rate program. And San Diego Gas and Electric (SDG&E) reported 4.3 MW in its Green Tariff program.
Matthew Freedman, staff attorney for ratepayer advocacy group The Utility Reform Network (TURN), told Utility Dive the utility programs will gain momentum. They are presently priced at above-retail rates to prevent imposing costs on non-GTSR-participating customers, but that price will come down, he said.
For the GTSR utility-led programs, the utility charges subscribers the actual energy cost for an existing portfolio of 20 MW or smaller solar projects built as long ago as 2010, he said. It then procures a matching portfolio of new projects. That ensures additionality.
“When the new projects are online, subscribers’ charges are reset to their actual energy cost,” Freedman said. “Those prices are expected to be substantially lower, possibly below the retail rate, but the design keeps other customers indifferent.”
PG&E spokesperson Ari Vanrenen emailed Utility Dive that the price drop has begun. “For 2017, the cost to participate in the program dropped 30% for residential customers and nearly 50% for some business customers.”
No growth for ECR
The Enhanced Community Renewables (ECR) program allows a Massachusetts-like direct transaction between developers and customers. But it has produced no growth in California because regulatory complications and high prices have discouraged developer participation, Freedman said.
Private community solar developers can offer only a credit for generation. It is offset by several charges, including a power charge indifference adjustment (PCIA) added by the utilities to protect non-participating customers from the load loss produced by community solar users. The PCIAs fluctuate according to market factors.
The result is an unpredictable but higher than retail price to subscribers. Long-term contracts will likely provide a hedge against the price of electricity over time, Freedman said. “But today’s solar customers are attracted by immediate cost savings.”
In March, the IOUs announced there were no contracts awarded in the first ECR solicitation, according to a blog post by Brian Orion, an attorney with renewable energy legal specialist Stoel Rives.
At $0.068/kWh, the current level of credits for the program makes it difficult for developers to cover project costs, especially the cost of acquiring and managing “hundreds, or thousands, of retail solar customers," Orion wrote. Also daunting are several “pre-qualification and ongoing compliance obligations,” he added.
The first obligation is a catch-22: Developers cannot market their projects until their marketing materials are approved by the utility offering the contract. But they must demonstrate proof of either customer commitments or interest within 60 days of the contract approval.
Another obligation is a legal opinion guaranteeing the project does not represent a violation of securities law, which would require a prohibitively expensive legal analysis, according to Orion.
Of 15 bids submitted in the first ECR solicitations, 11 did not meet the basic site control and interconnection eligibility standards, he reported. The other 4 were either caught in the catch-22 or did not produce the legal opinion.
Legislative or regulatory action required
TURN’s Freedman said the structural compliance obligations must be fixed but acknowledged it would likely take legislative or regulatory action that will not come readily. The fix would remove a significant barrier “but the developers still must find long-term off-takers,” he said.
Solar Energy Industries Association (SEIA) Director of California State Affairs Brandon Smithwood said the “over-programmified” ECR is the solar industry’s focus.
Besides its regulatory complications, the PCIA adds cost uncertainty and is unwarranted, Smithwood said. And crediting subscribers with only the energy charge fails to acknowledge the system-wide benefits of community solar.
He agreed with Freedman that only legislative or California Public Utilities Commission action, which are unlikely, will rectify the regulatory obstructions. “So we are trying to create alternative options,” Smithwood said. A disadvantaged community's virtual net metering program would widen its availability if at least 10% of a project’s subscribers are low-income customers and no more than 20% of subscribers are non-residential.
“We are also developing legislation that will create new options for non-residential customers and solve other pieces of the community solar puzzle,” Smithwood said. And, with California’s 2017 market down, “extending retail rate net metering could also be on the table.”
TURN’s Freedman does not think so. “California is a whole other ballgame. If community solar takes off, there will be subscribers for thousands of megawatts. It is crucial to get it right, but for solar to grow sustainably, net metering must evolve.”
Both TURN and SEIA agree compensation should be based on the actual value of solar. “It could include the whole suite of ways solar delivers value to the system," Freedman said. "If the stakeholders can agree on that value, it could go to any solar owner, whether it is rooftop or community solar.”
The New York plan
CCE’s Pagliarulo said New York policymakers are committed “at the highest level” to very aggressive renewables goals and to making community solar "a part of that." They are also committed to the market transitional credit (MTC), a version of the state’s value of distributed energy resources (VDER) tariff designed to replace the retail rate for community solar, she added.
Acadia Center’s LeBel acknowledged the MTC is more complicated than the Massachusetts credit. But it offers the certainty needed for financing and the clarity needed by customers and their utilities, he said.
NYSERDA’s Sandbank said the MTC provides a stable, long-term, predictable tariff that includes benefits recognized by the VDER value stack. “Certainty and transparency are what drive development over the long term,” he added.
The MTC will “bridge the gap” between the retail rate and the VDER, with the first tranche of projects qualifying for the full retail rate, the second tranche for 5% less, and the third tranche for 10% less. “We're taking a step away from net metering, which is a blunt evaluation of how solar affects the grid, and we're going into something more about time and place,” Sandbank said.
“The word ‘transition’ is important, he added. "We're trying to normalize community solar so we can build it cheaper.”
Eventually, when financiers, developers, and customers understand the concept, Sandbank expects to have introduce an innovative on-bill debiting and inter-zonal crediting. These things are expected to also help make acquiring and servicing customers “drastically less expensive,” he said.
New York has already instituted a “next month” swap out provision unavailable In Massachusetts, he noted. Exiting subscribers can be replaced from the waiting list at the end of each month, with no lapse in revenue. “That makes the project more financeable,” Sandbank said.
Monetary credits, which he argues are more workable than kWh credits, can roll over through the entire 25-year term of the community solar subscription, he added. And the program targets “the low-income demographic” through an innovative Department of Public Services financing plan.
To avoid California’s cost shift controversy, the MTC has a 2% rate payer impact, or 7% of peak load cap, Sandbank said. It is likely to support the installation of 500 MW of community solar while a more granular, next-phase tariff is being planned.
Clean Energy Collective's Hunt said New York’s program has more complications than the Massachusetts program but has “skirted the fatal flaws” in the California program. “It's almost certain to drive community solar growth, maybe even hundreds of megawatts, over the next couple years.”