Community solar’s dilemma is described in the old saying that a giraffe is a horse designed by a committee.

Community solar was supposed to be the “promised land” where utilities, solar advocates, and environmentalists could forget bickering over net energy metering (NEM) and fight together for economically-viable clean energy. But instead of a boom, there are mostly unresolved debates over policies that seem to distort the promise.

Community solar, also referred to as “community shared solar” or “community solar gardens,” allow utility customers who cannot access rooftop solar to own a portion of a central-station array located near their power supplier’s distribution system.

The total U.S. installed community solar capacity will “reach 1.5 GW by 2020, growing an additional four-fold from 2020 to 2025,” Navigant Research reported in March 2016. Many say this underestimates the potential.

Yet the total installed community solar capacity at the end of 2015 was an estimated 88 MW, according to a Smart Electric Power Alliance (SEPA) report.

While Navigant estimated an addressable market potential of up to $2.5 billion by 2020, it found a U.S. market valued at only $175 million today.

Given the segment’s immense potential, the statistics beg the question: why?

Steady forecasted growth for community solar could be curtailed if state regulations are too onorus or complex, developers say. Community Solar Value Project

Focus on state policy

State policy is crucial to growth because it impacts “the economics of all customer solar options,” according to Navigant. “In the likely case that full retail net metering is replaced, more customers could see community solar as their best, competitive solar choice.”

But Jill Cliburn, principal investigator at the Community Solar Value Project, said state policies are not yet working.

“Community solar is an incipient technology and these programs are tests to see what works,” she said. Policies that keep utilities from working effectively with developers “could be a lost opportunity.”

Tom Stanton, lead author of the just-released “Ecology of Community Solar Gardening” report from the National Regulatory Research Institute (NRRI), agreed.

“There is concern about getting these policies right and some states are moving slowly,” he said. “Once a design proves it is driving growth without causing a cost shift, policymakers will likely implement it.”

There are now community solar laws, rules, or policies completed or in development in 15 states and DC, NRRI reports. Investor-owned utilities (IOUs), municipal utilities, and electric cooperatives in other states are pursuing individual plan approvals from regulators, it adds.

California should own half the market by the end of this decade because of a 2015 mandate requiring its IOUs to deploy a total of 600 MW of community solar by 2020, according to Navigant.

Yet results from California IOUs’ first solicitation will not be announced until early 2017, and community solar developers have low expectations.

“It is not that California policymakers’ intentions are bad,” said Tom Hunt, policy director at Clean Energy Collective (CEC), the leading U.S. community solar developer. “But it seems the commission did not fully think through the effects of adding requirements on top of one another.”

Many state policies have become complicated to the point that they could be described as “policymaking run amuck,” Hunt added.

NRRI

A good policy is hard to find

The Massachusetts community solar policy is one of the best for developers, according to Hunt.

“It effectively defines community solar and resolves debates about small and big subscriber participation without mandates,” he said, “but it’s easy to understand and comply with.”

Joseph Goodman, a manager at the clean energy think tank Rocky Mountain Institute, said the state’s policy aligns with many of the recommendations laid out in RMI’s recent marketplace paper on community solar.

The first theme is clarity in the program process, he said. Without clarity, proposed projects may fail to meet ill-defined standards and be dropped. “In some places, developers expect only one in ten proposed projects will be built,” Goodman said.

A second thing important in policy design is certainty in pricing and scheduling, he said.

Without certainty on the cost and time required by utilities for interconnection reviews and for permitting, developers may lose financial backing by being unable to put investors' money to work on schedule, Goodman said.

His third policy key is making collaboration between utilities and developers on siting possible. In New York and Minnesota, promised booms fizzled because policies did not deliver utility system information to developers. That made siting “a unilateral pin-the-tail-on-the-donkey process, with developers largely blindfolded,” Goodman said.

When utilities and developers work together, the reduced risk compresses the project cycle and leads to better value for the utility, developers, and customers. Without collaboration, “interconnection prices are absurdly high,” Goodman said. “In NY, we have seen prices of $500,000 or $750,000 for a 2 MW site.”

A fourth policy key is effective consumer protections, Goodman said. “A lot of projects are being sold with charges that make my stomach churn.”

The charges are typically hidden in the complexity of an estimated utility rate escalation which starts at or near the current retail rate “but grows almost exponentially,” he said. “Some developers could be facing class action lawsuits.”

Clarity and certainty for output value, interconnection standards, permitting and siting are vital, CEC’s Hunt agreed, but several other elements come into play.

First, the output of the portion of the central station array owned by each subscriber should be applied directly to the utility bill. If it is not, the payment “will run afoul of securities law, limiting the market,” Hunt said. “Residential customers are virtually impossible to reach on a large scale without this.”

Value must fairly reflect the savings solar offers because those savings are why customers invest, he added.

Possibly the biggest challenge for policymakers is structuring an effective competitive market, Hunt said. “Community solar can work when led by third parties, when led by utilities, or when done by a variety of parties in competition."

Competitive markets can drive innovation and efficiency when developers and utilities have equal access, he added. With the right choice of private sector partners and practices, utility-led programs can also be “very effective.”

While the Massachusetts program is effective because it is relatively simple, simplicity can also be a liability, Hunt said. The controversy over co-location of projects that stopped growth in Minnesota showed “it is important to define some things so the system is not gamed.”

Case in point: Maryland

Maryland’s community solar program mandates 218 MW over three years and specifically defines product categories — so specifically that Phillip VanderHeyden, a staffer at the PSC, acknowledged that it could seem complicated to developers.

“There are something like 36 different categories and they are good in and of themselves but it is confusing for developers,” Hunt said. “The commission’s working group is still trying understand how it will work.”

The policy makes the state’s three main intents clear, VanderHeyden said. It will create a community solar industry, obtain a practical understanding of community solar costs and benefits, and “provide distributed generation and net metering to customers who can’t participate in rooftop solar, including low and moderate income customers.”

The law targets obtaining 1.5% of Maryland’s peak demand from community solar over three years, he added. Each of the state’s four IOUs would be required to develop projects in Small, Open, and Low and Moderate Income (LMI) categories.

Each IOU must obtain 30% of its community solar kWh from projects of 500 kW or less in the Small category. They can be on rooftops, parking lots, roadways or parking structures or on brownfield locations. Or they can be located to deliver over 51% of their output to LMI customers.

For the Open category, each utility can obtain 40% of its portion from any array of up to 2 MW. This category is expected to be subscribed quickly, VanderHeyden said.

The last 30% of the community solar kWh obtained by each utility must serve LMI customers and 10% of the kWh must go to low income subscribers.

Multiple provisions in the law clarify precisely how kWh are to be divided in each category, how they will contracted for, how consumers will be protected, and how to guarantee that allocations meet the state’s intents, VanderHeyden said.

The regulations became effective in July. IOU tariff proposals are still being studied by the commission’s longstanding solar policy working group. When they are approved, each utility will begin accepting project applications.

“The tariffs will include interconnection and colocation regulations and how projects will be prioritized within the interconnection queue,” VanderHeyden said.

A subscriber organization authorized by the commission will administer the program. Developers will propose projects at the commission-approved tariffs for the categories, he added. “The policy allows utilities to credit the customer’s bill as a dollar amount on the bill or on a per kWh basis.”

The commission’s flexibility on tariff regulation will allow it to intercede if the program does not provide the same value to community solar subscribers that rooftop solar provides, VanderHeyden said. The commission is also charged with delivering a report to lawmakers when the three-year program ends or the 1.5% of peak demand capacity is deployed.

No new projects can be built until the report determines whether the program has had “tangible and observable benefits and until whatever recommendations it makes can be implemented,” he added.

Clarity is primarily lacking in the Maryland policy because there are so many categories, Hunt believes. Incentives might be more workable than mandates because they would allow the market to determine if and where policy goals make financial sense.

“By requiring these categories, the policy limits the flexibility to adjust to market conditions,” he said.

Case in point: California

California’s policy offers two other ways to complicate community solar programs, Hunt said.

First, the economics don’t work, largely due to an interpretation of the legislation that allowed a utility-backed reduction to the NEM credit and a special added charge.

“The way it is worked out delivers a pretty poor rate for the subscribers,” he said.

To protect against a perceived cost shift to non-participants, community solar subscribers will not get the full NEM retail rate credit. Instead, they will pay for generation, transmission, and distribution and get a bill credit for their solar generation.

The Power Charge Indifference Adjustment (PCIA) troubles solar advocates because the charge is likely to result in a premium on the price of electricity, according to Brandon Smithwood, California affairs manager at the Solar Energy Industries Association (SEIA).

“It is a departing load charge,” said Smithwood. “The commission’s original decision found that community solar customers do not depart but remain with their utility. But it was decided the PCIA could be used to protect non-participating customers.”

In addition to unworkable economics, the California policy has “a lot of programmatic restrictions that are hard to interpret and may not be very effective,” Hunt said. None of the restrictions are wrong on their own, “but they are stacked up to the point that it makes it hard to make the program work.”

California’s long and deep experience with solar shows there are positives and negatives with rooftop solar and utility-scale solar, said Mark Nelson, director of planning and analysis at Southern California Edison (SCE).

The reduced credit in the Green Tariff Shared Renewables (GTSR) program reflects policymakers understanding that community renewables are “squarely up the middle” between the rooftop and utility-scale segments, he said.

It is an effort by the stakeholder-led policy process to balance “the cost to program participants with the costs non-participants also bear,” Nelson added.

Initiatives in California’s Distributed Resource Planning (DRP) and Integrated Distributed Energy Resources (IDER) proceedings may allow developers to build projects that target additional revenue streams, according to Nelson.

“We will need more experience with the current program to judge its success,” he said.

SEIA’s Smithwood, who has been part of the stakeholder group for 18 months, believes the structure of the policy allowing utility-led and private developer-led programs is not the issue.

“The challenge is how the credits and charges limit the customer value proposition,” he said.

One component of the GTSR program allows utilities to market premium-priced renewables-generated electricity from projects they develop.

Solar advocates’ concern is with the other component, the enhanced community renewables (ECR) program. Developers will contract directly with subscribers to deliver solar energy-generated electricity at a specified rate, and IOUs will apply the credits and charges to subscribers’ bills.

The real solution to a fair credit rate for community solar can only come with a full investigation of “whether, to what extent, and in what direction cost or benefit shifts actually occur between ECR customers and nonparticipants,” according to Smithwood. “Utilities should assign a zero-value placeholder until an appropriate indifference charge is calculated based on actual data.”

The PCIA does protect utilities against stranded costs, Smithwood acknowledged, but he said those charges are more commonly applied to utility customers who actually leave their utilities for alternative electricity suppliers such as community choice aggregators (CCAs).

Because of the reduced NEM credit and the PCIA, “it will be hard for private developers to meet the utilities’ community solar prices because their customer acquisition and marketing costs are likely higher,” Smithwood predicted.

Is locational value the answer?

Both the integration capacity analysis (ICA) in the California commission’s DRP proceeding and the locational net benefit analysis (LNBA) in the IDER proceeding are intended to identify where on the distribution system distributed resources will have the greatest value, SCE’s Nelson said.

Either or both analyses, which should be in place within the next year or two, could improve the value proposition of community solar and make it more economically viable, he said.

Maryland’s policy explicitly specifies “that utilities make reasonable attempts to assist developers in identifying locations that have system benefits,” VanderHeyden said. “We expect to have more insight into how to implement that after the initial projects are rolled out.”

community solar has many of the same economies of scale as larger central station arrays and should be able to “capture those economics,” RMI’s Goodman said.

The obstacle is a development and regulatory environment that is adding costs and constraints, he added. “We are hoping that attributing locational value with clarity and transparency will contribute significantly to resolving those constraints.”

The Community Solar Value Project (CSVP), funded in part by the Department of Energy’s SunShot program, is helping develop partnerships between utilities and private sector DER providers to demonstrate how community solar projects are “part of the DER puzzle,” CSVP’s Cliburn said.

The Sacramento Municipal Utility District (SMUD), Public Service Company of New Mexico (PNM) and other utilities are building “market-based laboratories” in which properly-sited community solar will be paired with energy efficiency, demand response, and storage.

Market research shows that if customers are told only that community solar will save them money, they will want the lowest cost offering, Cliburn said. “But a lot more value is possible.”

Policy should bring utilities and private sector providers together to do something more innovative than lowest cost projects, she said.

“When something is defined before it is completely invented, it is put in a box,” Cliburn said. “If a utility RFP gives no guidance on locational value, developers will make proposals without reference to locational value.”

It is challenging to identify where the greatest community solar locational value is but “no utility would procure poles or capacitors without specifying what they want and where they want it,” Cliburn said. “It is time for utilities to take up this challenge.”

NRRI’s Stanton said such an analysis would resolve one of utilities’ biggest concerns.

“A careful analysis that includes locational values along with energy and capacity values can identify where any cost shift to non-participants from deploying community solar can be avoided,” he said.

And, he added, not considering “specific locational values” could reduce a community solar project’s benefits to both participating and non-participating customers by as much as half.

Such an analysis should be based on carefully collected and analyzed real time system data, Stanton said. “If the price is not based on real time market data, it is just an estimate but it could result in an inaccurately set rate that is locked in for 25 years.”

Utilities and community solar developers should be gathering and reporting data now, Stanton said. A study based on transparently collected long term data analyzed in detail “would help reduce all the finger pointing and name calling about the value of the solar.”