Reviews are mixed on the California Public Utilities Commission's final community solar rule.

The good news and the bad news is that the rule is not actually final and lacks vital details, according to the sector’s two leading developers.

“The CPUC designed programs that allow collaboration between community solar companies and utilities,” said SunShare Business and Communications Director Karen Gados. “The Enhanced Community Renewables program is the creative part of the plan and SB 43 didn’t give a lot of direction on it so the commission left it up to the utilities and the solar industry.”

“In a way it is good that there is uncertainty because it encourages utilities and other stakeholders to work together and innovate,” said Clean Energy Collective (CEC) Corporate Development VP Tom Hunt. “But the things that could make the market work are still up in the air and maybe even questionable.”

The CPUC decision, driven by California Senate Bill 43’s mandate for a 600 MW community solar program, lists four key findings:

• Careful rate design and procurement can create ratepayer indifference and prevent program costs from being shifted to non-participating utility customers
• The proposed Green Tariff Shared Renewables (GTSR) Program, which allows Pacific Gas and Electric, Southern California Edison, and San Diego Gas and Electric to develop and sell shares in solar arrays of between 500 KW and 20 MW, is SB 43 compliant
• Utility procurement methods for the state’s renewables mandate should be used for the program
• Minimum “advance procurement goals” for 2015 are necessary

The first finding was central for the IOUs. “Our program adheres to a principle that program costs should be borne by participants,” noted PG&E Community Solar Program Manager Molly Hoyt. “There is no cross-subsidy paid by non-participating customers.”

But in accepting the utilities’ proposals for rates and contract terms, said VoteSolar Western Region Director Susannah Churchill, it is possible the commission compromised affordability.

“I am worried that affordability is going to be a problem and the limitation that customers can only subscribe to the program for a maximum of one year means that they can’t lock in their credits and charges long term,” Churchill explained. “That is going to create uncertainty and may be a big barrier for program uptake.”

While mid-size solar projects remain more expensive than conventional generation, a small premium for renewables makes sense, she said. Many customers will be willing to pay more for 50% or 100% renewables-generated electricity.

But ratepayer indifference goes both ways, she added. “It is not just the costs of the program but the benefits as well that need to accrue to participants.”

The CPUC's community solar timeline

The CPUC's decision approving shared renewables programs was “extremely well vetted by numerous parties to the CPUC proceeding over a period of almost three years,” Hoyt explained.

The decision concluded phase III of the program’s development and established a problem-solving phase IV that began by requiring the utilities to submit advice letters within 100 days.

Utilities are required to provide community shared renewables to meet “up to the 600 MW statutory cap,” with 269 MW required from SCE, 272 MW from PG&E, and 59 MW from SDG&E.

In anticipation of a solar rush before the federal investment tax credit sunsets at the close of 2016, signed contracts for a minimum of 50 MW from SCE and PG&E and 10.5 MW from SDG&E are required in 2015 to kick-start the program. 

The Enhanced Community Renewables (ECR) program is directed mainly at developers. It allows them to sell shares of arrays of up to 3 MW through long term contracts to utility customers without access to rooftop solar. The utilities are more interested in the GTSR program. It allows them to develop smaller scale renewables and sell the generation in green premium-like programs.

GTSR program participants will like the ease of just checking a box to have 50% or 100% renewables-generated electricity, Churchill said. The ECR program will allow more engaged customers to choose their own project from a developer’s offerings.

SB 43 requires 16.67% of GTSR capacity to be residential. In PG&E’s GTSR program, the typical residential customers using 500 kWhs monthly will pay less than $15 per month for 100% renewables-generated power, according to Hoyt. “That premium is likely to decline over time as the cost of solar decreases relative to the cost of our standard generation mix”.

The good things about the CPUC's decision 

The ECR project size, contract structure, residential and small business customer inclusions, and its utility-developer-customer relationship are all good, Hunt said.

Developers can market directly to consumers. Utilities get the arrays’ output and credit subscribers’ bills. “That is exactly the model for community solar we know works legally and for consumers,” Hunt said. “They chose a model that can work.”

It also works for SunShare, Gados said. And excluding capacity applied to the SB 43 mandate from applying to the state renewables mandate is something SunShare has found to be effective. It makes programs “market-driven and consumer-driven” and “broadens access to solar.”

Two other noteworthy inclusions for SunShare are:

• The 100 MW of solar required in “areas disproportionately affected by environmental pollution and other hazards that can lead to negative public health effects, exposure or environmental degradation" and "areas with socioeconomic vulnerability"
• Contract completion, except for institutional or municipal developments, requires developers to document three subscribers and to demonstrate community interest by obtaining commitments for 30% of the project’s capacity or documentation of a potential 51% subscription rate

The problems with the decision

“Whether California will be an important community solar market is still questionable,” Hunt said. CEC particularly needs to know more about the “fairly marginal” rate.

“Until you know the number your customers are going to get on their bill credit, it is hard to do anything,” he said

Rules on procurement allow a lot of potential restrictions, Hunt added.

SunShare generally supports programs in which size and scope are based on consumer demand because they allow the market to regulate growth and customers to drive product offerings, Gados said. “There are a lot of advantages to an uncapped program like Minnesota’s,” Gados said. “It is not yet clear what the strengths and challenges in this plan are.” Simple and uniform billing processes are best, she added.

“We will be using competitive procurement to get the best possible price for solar,” Hoyt explained, “and we will pass the savings on to program participants.”

The biggest downside is “unfair and unaffordable” premiums which utility estimates put at 15% to 35% for residential customers, according to Churchill. “The CPUC accepted the utilities’ flawed pricing proposal, which doesn’t convey to subscribers the full, long-term value of the shared renewable generation on their bills, and also allows bill credits and charges to fluctuate significantly year to year.”

Utilities are only required to offer one year contracts and customers can move to month-to-month billing after the first year, she explained. But to obtain financing, a developer must obtain long term commitments from a significant portion of subscribers.

“How many customers are going to be interested in signing a long term agreement with the developer when they don’t know what their bill charges and credits will be from the utilities in two years?” Chruchill asked. They will save utilities many long term costs. Not conveying that long term value to those customers unfairly shifts those long term savings to the non-participants. Ratepayer indifference means “a fair credit and charge allocation.”

“The [ECR] developer and customer can develop a contract term as long as they wish,” Hoyt explained, and “the customer can be on the utility tariff for whatever length of time corresponds to their agreement with the developer.”

Though details about ECR remain to be determined, Hoyt explained, her understanding is that subscribers can have long term commitments from utilities that match their long term commitments with developers, as in other community solar programs.

What's coming for the community solar market in CA

“We don’t have projections about the potential market,” Hoyt said, but PG&E’s program cap of 272 MW imposes “a practical cap of about 35,000 customers to 40,000 customers.”

 “We need a little more information,” Hunt stressed. “When SB 43 passed, there weren’t a lot of examples of big successful community solar markets. But with Massachusetts, Colorado, and Minnesota showing a lot of growth in the last year or two, California can see what structures and prices work.”

There are a lot of unanswered questions, the more upbeat Gados agreed. “A lot more of the details will come out in the utility advice letters,” she thinks, “and the CPUC has been effective in a guidance role.”

SunShare has met with PG&E and SDG&E, Gados added. Based on the striking response in Minnesota to Xcel Energy’s initial community solar offering, she foresees “an enthusiastic response” in California’s already “robust” solar market.

Churchill hopes two issues flagged in phase IV’s preliminary hearing will get priority reconsideration:

1. Can customers lock in their rate over the long term?
2. Will participation be affordable?

She does not foresee those questions being resolved ahead of the 2015 utility offerings. “If there aren’t many ECR projects offered, the commission will need to take a hard look at how they can restructure the program so customers have expanded options.”