Year-end numbers from the front lines of the struggle between utilities and renewables advocates for the future of solar reveal something too often unnoticed: The sometimes collaborative, sometimes contentious interactions have moved to higher ground — where the questions are more substantive and nuanced, but the answers are harder to find.
This shift only becomes evident by reading between the lines of a new report summarizing 2017 solar policy developments and understanding the implications of its data.
In 2017, there were a record 249 solar policy actions debated at state commissions and legislatures — up 17% from 2016’s 212 actions and 30% from the 175 actions only two years ago, according to the 50 States of Solar annual policy review.
The review shows that the solar policy debate is moving toward substantive engagement and a deeper understanding of distributed solar.
A key indicator of the new, higher level debate is that activity increased in all solar policy categories last year except compensation for distributed generation (DG), according to the North Carolina Clean Energy Technology Center (NCCETC). That category was originally used for early, often data-free debates about limits on retail rate net energy metering (NEM), NCCETC Manager of Policy Research and report lead author Autumn Proudlove told Utility Dive.
Hawaii’s commission does “a pretty darn good job in threading the needle between supporting solar and over-subsidizing it."
Marco Mangelsdorf
President, ProVision Solar
For its 50 States of Solar report, NCCETC tracks a wide range of policy actions, including rate changes, solar valuation and benefit-cost studies, and solar ownership policies.
"Deeper, more nuanced and granular discussions" are now about rate design, market analysis and how both utilities and the private sector can benefit from meeting customer demand for solar, she said. “The options are often more complex, involving locational and time-based factors."
For instance, laws in Michigan, Montana and North Carolina permit regulators to introduce an NEM successor tariff “only after cost-benefit studies are conducted,” she said.
Polarization between parties in many energy sector debates persists, NCCETC acknowledges. Examples are the Federal Energy Regulatory Commission debate over subsidies for coal and nuclear plants and President Trump's decision to impose tariffs on imported solar cells and modules from China. But while dialogue polarizes at the federal level, something very different is happening with energy policy questions in many states.
The review’s nine solar policy “trends” describe examples of a new type of debate in the solar sector. It led to 2017 policy settlements between utilities and solar advocates in Arizona and Utah that required only the state commission’s consent. And even where parties only agreed to disagree, as in the multi-faceted solar policy disputes in New Hampshire and Arkansas, “stakeholders were working toward the goal of compromise,” Proudlove said.
As usual, Hawaii’s solar industry sent critical postcards from the solar policy future that gave solar installers reason to see the potential for more substantive engagement and hope for resolutions that satisfy all stakeholders.
Net Billing, alternative compensation and data
Hawaii regulators ordered the first U.S. NEM successor tariff in 2015. It was the first time a tariff designed as a successor to NEM was put in place. It was called net billing. Last year, the Hawaii Public Utilities Commission revised the state's net billing tariffs.
Like NEM, net billing allows solar owners to offset the retail price of electricity by using their own generation. Unlike NEM, net billing remunerates them at a less than the retail rate for the generation their systems export.
The 2015 tariffs’ lower compensations sharply reduced Hawaii solar installations. On Oahu, the most populous island, they fell from 16,715 MW in 2012 to 4,591 MW in 2016, and 2,993 MW in 2017, according to Marco Mangelsdorf, President of ProVision Solar, one of Hawaii’s original solar businesses.
Hawaii’s commission does “a pretty darn good job in threading the needle between supporting solar and over-subsidizing it,” Mangelsdorf emailed Utility Dive.
NEM may have over-subsidized and the 2015 tariffs under-supported, but Hawaii's new Customer Grid Supply Plus and Smart Export tariffs “will allow for thousands more rooftop solar systems to go in,” he wrote.
The Smart Export tariff is designed to encourage the use of battery energy storage, according to NCCETC. Introducing it where there are roughly 80,000 distributed solar installations without storage could drive “a significant and growing market,” Mangelsdorf agreed.
In 2017, Indiana, Maine, New Hampshire, New York and Utah followed the lead set by Hawaii, Nevada, California, Vermont and Arizona by adopting successor tariffs, NCCETC reports. Among states adopting or considering NEM reform, “three basic compensation structures have emerged: net metering, net billing, and buy-all, sell all.”
At least five states, in anticipation of a successor tariff, are doing mandated or commission-ordered solar valuation studies or cost-benefit analyses, NCCETC reports. After years of debate, Montana’s H.B. 219 granted the state commission the power to revise its NEM in 2017, but only if a cost-benefit study, due this year, supports it.
California's successor tariff work will not conclude until 2019, but several initiatives clarified key elements in 2017. One was the kickoff of the state's integrated resource planning effort, which renewables advocates said will be where many policy dilemmas will finally be resolved.
Another was the release by CPUC President Michael Picker of a DER Action Plan that was hailed by policymakers as the crucial missing link in the state's DER efforts.
Interstate Renewable Energy Council (IREC) Policy Program Director Sara Baldwin Auck, who oversees IREC’s work in state proceedings, called California's work “foundational.”
The influential Gridworks think tank, led by former California regulators, recently recommended NEM be replaced by a net billing tariff based on the state’s rigorous and controversial locational net benefit analysis, which will establish a consistent methodology for determining DER locational value. That effort struggled in 2017 to meet commission-set mileposts.
NEM “is intertwined with retail ratemaking, a clunky policy-making process with implications and complications extending far beyond customer generation,” Gridworks argued. Compensation for exported generation could be set through a more nuanced, policymaker-designed rate that includes "anchors and adders.”
NCCETC’s Proudlove said many states are studying the data-based analyses being done in California, and the similarly high quality analyses on DER value being done in New York. When they see how those states have raised the bar on the solar and grid modernization policy debate, they respond by working to raise the tenor of their own debates in similar ways.
The complexities of rate design
Instead of choosing data analysis, many utilities respond to revenue losses perceived to be due to rising penetrations of solar and other DER with requests to regulators for increased rates or charges.
Fixed charge increases for residential customers, a common response to those perceptions that solar and DER are causing revenue losses, remained unappealing to regulators in 2017, NCCETC reported. There were 84 pending or decided utility proposals to increase them. Only 6 were fully approved, while 13 were denied and 25 got a part of the requested increase. Nevertheless, 41 new requests were filed during the year.
Demand charges for residential owners of DG — another response to revenue losses perceived to be due to rising solar and DER penetrations — continued to be even less appealing. There were eight decided and two pending demand charge cases in 2017. Only three were from investor-owned utilities, down from 2016’s five and significantly down from 2015’s ten.
In the eight decisions, regulators either rejected the demand charges, allowed their withdrawal as part of a settlement, or allowed them only as opt-in rates.
Rejection suggests regulators expect something better, Proudlove said. An example is the New Hampshire successor tariff settlement agreement, which included a pilot that will evaluate a variety of rates, including real time pricing, critical peak pricing and demand charges.
It provided no specific conclusion about a specific tariff, which would create winners and losers in the debate. Instead, the stakeholders agreed to gather data through pilots that test the competing successor tariff possibilities. This was also a theme in the Arizona stakeholder settlement.
The New Hampshire demand charge was a settlement concession from solar interests and the time-varying structures were a concession from the utility side. Both were part of a broader package of reforms that policymakers and stakeholders hope will lead to a successor tariff, several participants told Utility Dive.
But months of work to reach an agreement did not achieve the compromise they wanted, the participants said. Finally, a utility-consumer advocate coalition submitted one proposal and a coalition of renewables and environmental advocates submitted another.
The effort, however, moved the parties toward mutual understanding. “The compromises from original positions were the result of both sides trying to accommodate one another and work toward one big settlement,” Donald Kreis, the head of the consumer advocate’s office, told Utility Dive. “Both proposals are more reasonable than they were originally.”
There were also important rate design innovations that impacted the solar sector during the year in Arizona, Illinois and Minnesota.
A voluntary three-part rate design with time-of-use (TOU) rates and demand charges was central to a settlement between solar advocates and Arizona Public Service (APS). Implementation has just begun, APS Director of Technology Innovation Scott Bordenkircher told Utility Dive. The utility’s hope is that the rates will support deployment of many types of distributed energy resources.
The Illinois Future Energy Jobs Act (FEJA) was another broader reform effort. It was the result of a new level of cooperation between distributed solar and community solar advocates and the major electric utility in the state, Commonwealth Edison (ComEd), both sides told Utility Dive. One key to FEJA’s success will be its unique compromise provision, allowing ComEd to ratebase DER investments to displace utility infrastructure expenditures.
Xcel Energy’s proposed residential TOU pilot, filed with the Minnesota Public Utilities Commission in December, takes rate design innovation to a new level, proceeding intervenors agreed. Among its key features are opt-out participation, a relatively narrow peak period, and a high peak-to-off-peak price differential.
Solar, environmental and consumer advocates as well as a TOU design expert and a pilot project design expert all told Utility Dive the proposal raises the bar for utilities considering TOU rate pilot projects.
Community solar
Advances in community solar policy also followed the year's trend toward more nuanced thinking.
The private sector likes community solar because it significantly widens the market. And utilities like it because they can market to residential customers and locate solar where it serves their distribution systems, the NCCETC report finds.
In 2017, lawmakers made Virginia and North Carolina the 17th and 18th states with community solar policies, the report notes. Many utilities have proposed or implemented community solar programs in states without a policy. Utility-led programs grew from 83 in 2015 to 171 in 2017, with at least 23 new programs added last year, according to NCCETC.
There were 30 total community solar policy actions last year, with the most attention on setting and managing the credits subscribers to projects get on their bills, because the value of those credits "determines the cost-effectiveness of program participation," the report says.
States with virtual net metering can compensate community solar subscribers at the retail rate. But the increasingly nuanced discussions about solar have more recently led to value-based or alternative compensation.
Four states made important policy advances in this area in 2017.
North Carolina’s House Bill 589 was a broad package of solar policies produced by months of settlement negotiations and considered “a win for both the solar industry and the utility,” according to Chris Vlahoplus, partner and clean tech & sustainability practice leader for consulting firm ScottMadden.
It calls for Duke Energy Carolinas and Duke Energy Progress to each deploy a 20 MW community solar program. Some activists are concerned about utility control of the programs because of the Duke companies' complicated record on residential rooftop solar. But most solar advocates say the settlement, which also legalizes solar leasing, is a breakthrough because it opened solar access.
Work continued throughout 2017 on the Solar Massachusetts Renewable Target (SMART) program. Expected to be in effect by mid-2018, it includes several important additions to an already successful community solar offering. Debate centered around a set of adders designed to increase the subscriber credit rate for projects developed in ways and at locations that drive energy and environmental policy goals.
In contrast, California's private sector-led community solar market has no completed projects. The obstacle is a credit rate made unwieldy by the state’s power charge indifference adjustment (PCIA). Utilities demanded the PCIA be added to the credit rate to protect non-participating customers.
California's nation-leading solar sector will likely continue to have an undeveloped private sector-led community solar market until regulators adjust the PCIA in a separate proceeding on consumer choice aggregation, advocates told Utility Dive.
But Hawaii is expected to soon advance community solar with a rate design breakthrough. Its recently enacted community-based renewable energy (CBRE) law got regulatory approval in 2017 for an 8 MW phase one build in yet to be selected locations.
In the CBRE program’s phase two, developers will add 64 MW of capacity and, for the first time, the credit rates will include time-varying compensation. That will provide the first real-world answers to two of the newest questions about community solar: how will the time-varying rates affect customers' use of battery storage? and how will the complications of time-varying rates affect community solar's value proposition?
ProVision’s Mangelsdorf told Utility Dive the complexities of managing the credit rate are likely to slow the program’s roll out. “It is a well-intentioned idea that will be very difficult to actually implement.”
The same might be said of efforts across the country by utility policy executives and solar advocates at the state level. Yet NCCETC reports at least seven states have just-introduced or pending Q1 2018 solar policy legislation and at least 13 more have pending solar policy regulatory actions. There are also 35 unresolved requests for fixed charge increases and two for new demand charges.
The policy debates are not slowing or compromising utilities’ focus on protecting customers and shareholders, or advocates’ ambitions to protect customer choice and expand solar.
