Sometimes one stat is all it takes: 46 of the 50 states had solar policy debates going on in 2015. That makes solar literally the talk of the nation.

Only residents in Alaska, North Dakota, Wyoming and Alabama were spared from solar policy last year. Everywhere else, regulators, utilities, solar providers and the like have been wrestling to find the proper valuation, aggregation and ownership models for the fast-growing renewable resource, according to a new report from the North Carolina Clean Energy Technology Center (NC CETC).

“It has created an uproar in different places and it is hard to say what has affected the regulators’ thinking because each commission is different and each is persuaded by different evidence,” said NC CETC Sr. Policy Analyst Autumn Proudlove, co-author of “The 50 States of Solar; 2015 Policy Review.”

The extensive policy review is the product of ongoing research by NC CETC and Meister Consultants Group. In the report, the analysts break down the year's developments into five key categories:

• Net Metering: 27 states considered changes to how solar owners are compensated for energy their systems send back to the grid.
• Fixed Charges: 61 utilities in 30 states proposed monthly fixed charge increases, and 21 utilities in 13 states propose new or increased existing charges specific to rooftop solar customers.
• Value of Solar: 24 states undertook studies to better define the value of solar and other distributed energy resources (DERs), expected to influence the future of NEM and the design of successor tariffs.
• Community solar: 7 states advanced policies on community solar, including the resolution of Xcel Energy's concerns over a Minnesota program with a current queue of 1,500 applications representing over 1,400 MW of new capacity
• Solar Ownership: 5 states considered utility ownership of rooftop solar and 6 faced debates on third-party ownership (TPO), including legislation making Georgia the first southeastern state to allow the practice.

From net metering to 'net billing'

“One of the biggest things we saw in this edition was net metering successor tariffs,” Proudlove said. “Nevada and Hawaii re-evaluated net metering altogether and came up with very different policies. Now similar changes are being considered in other states. It is a turn toward something other than traditional net metering, something new and different. We call it net billing.”

Regulators in Hawaii and Nevada were the first in the U.S. last year to change the value of credits solar owners receive for electricity they export back to the grid, lowering them to the utility’s avoided cost or wholesale rate, the review reports.

The changes being considered in California’s NEM 2.0 proceeding are another example of a successor tariff, though that commission decided to delay changing retail rate NEM until 2019 in a January decision. Mississippi’s “avoided cost with a temporary adder” credit to solar owners for their exported generation is another successor tariff, Proudlove said.

Louisiana is preparing an avoided cost “net billing” successor tariff while Maine and Vermont are developing successor tariffs not based on avoided cost, she added.

“Maine’s alternative policy could range from $0.10/kWh to $0.185/kWh,” Proudlove said. “Vermont is considering something still called net metering but it would effectively be more of a buy-all, sell-all agreement.”

Not all places are doing away with traditional net metering. The South Carolina retail rate credit implemented last March is a departure from the trend away from NEM, the review reports. 

“There is a lot of uncertainty to solar customers with these new policies because they may end up reducing the financial value of solar,” Proudlove said. “They could increase it but we don’t know what many of the final values will be yet.”

Fixed and demand charges

The fixed charge, “also called a “customer charge” or a “basic service charge,” is a per-month charge that applies to every customer,” according to the review. Fixed charges, typically for $5 to $10 per residential customer, cover “customer-specific costs associated with one additional residential customer.”

Faced with stagnant load growth and the proliferation of distributed generation, utilities across the nation have made a trend of pushing for higher fixed charges to cover “grid infrastructure, maintenance on generation assets, and other costs that do not vary in the short term with the amount of electricity sold,” the review reports.

Of the 61 utilities that proposed fixed charge increases across 30 states last year, the median increase requested was 62%, according to the report. The trend is a troubling one for solar installers, whose value proposition to customers can be seriously compromised when charges rise. A $5 monthly fixed charge increase is “equivalent to an extra $1,500 in charges over a 25-year PV system lifetime," according to the report.

Proposals for high fixed charge increases have been met with skepticism from regulators in many states, the review reports. A rate design that uses fixed charges instead of customer-specific costs “deviates from long-established rate design principles,” the review explains, referencing a recent Regulatory Assistance Project study.

That may help explain why in 16 of the 37 regulatory decisions on fixed charges in 2015, regulators dismissed the request completely. Of those approved, the median approved fixed charge was $10.85. 

Of the 21 examples in 13 states of utilities proposing extra charges or fees specifically on solar, distributed generation, or net metering customers in 2015, the most common was a monthly demand charge. The median requested charge was $4.80 per kW per month.

Only a few IOUs, including Alabama Power and Dominion Virginia Power, have implemented such charges. But proposals are becoming more common as fixed charge increases get turned away or reduced by regulators.

Because they attempt to turn solar owners into a separate rate class, “proposals generally faced organized opposition and few have been approved by regulators,” the review reports.

In 2013 and 2014, “state regulators rejected, or utilities withdrew, solar charges proposed by Idaho Power, Black Hills Power, Rocky Mountain Power, Central Maine Power, and Georgia Power,” it adds. A We Energies charge was approved by state regulators but was overruled in Wisconsin District Court as inadequately justified by the utility.

Demand charges have been allowed for some electric cooperatives, municipal utilities, public utility districts, and state-owned utilities, probably because they did not require the approval of state regulators, the review notes.

NV Energy was the only U.S. IOU that was granted a solar-specific demand charge in 2015. It came in a proceeding in which regulators had become so hostile to solar advocates that their decisions were described as “punitive.”

“In some places utilities have moved from requesting fixed charges to requesting a demand charge for solar customers as a different instrument,” Proudlove said. “We may therefore see more. It is still a relatively new concept and we still have to see what will happen.”

Demand charges are significantly easier to work with than fixed charges, according to GTM Research Sr. Solar Analyst Cory Honeyman. In conjunction with time of use (TOU) rates, demand charges “allow more opportunities for customers to adapt their habits.”

TOU rates “are an important part of this conversation and it is something we want to look more closely at in the future,” Proudlove agreed.

The valuation debate

The other major policy activity in 2015 was the beginning of examination, in at least 24 states, of “some element of the value of distributed generation,” the review reports. That could add significantly to the only 10 completed valuation studies at the end of 2015.

The studies were undertaken as part of regulatory proceedings ranging “from direct rate design or net metering policy changes, to informing and refining approaches to DG valuation, to general education of decision-makers and the public,” the review adds. “The ultimate policy significance of these studies is highly variable because they have arisen for state-specific needs and motivations.”

Hawaii and New York studies have been part of wider regulatory reforms. Florida and Ohio studies were taken on to educate the commissions. Georgia and Tennessee ordered studies to improve integrated resource planning. Oregon, South Carolina, and West Virginia ordered studies as part of NEM proceedings. Utah, Minnesota, and Texas did so as part of a study of solar-specific rate designs.

Stakeholder groups undertook studies in South Carolina, Tennessee, Georgia, Vermont, Maine, and other states.

“Although the stated end goal of many of these inquiries and studies is to come to a more thoughtful, data-driven understanding and policy direction for distributed generation, it is still largely unclear what, if any, trends will emerge,” the review concludes. “The inquiries themselves demonstrate a pathway towards deriving solar policy outcomes through participation by multiple stakeholder groups.”

The problem is that the studies “tend to be all over the place.” Proudlove said.

“It is hard to say what is right and wrong about them," she explained. "The solution might be standardizing methodologies so their conclusions could be compared. But that doesn’t seem very practical because there are state specific factors that have to be included.”

Working through the issues in a stakeholder group “can lead to a result with much less controversy in the process,” Proudlove added. “It allows states to be pro-active and avoid the debates we have seen in some other states.”

Solar ownership

As solar adoption has increased throughout the nation, much of the growth has come through third-party ownership models, but the practice remains outlawed in many states. 

More than 72% of residential systems were TPO-financed in 2014 and 63% of 2015’s systems were expected to be TPO-financed, the review reports. TPO is allowed in at least 26 states, the District of Columbia, and Puerto Rico. Eight states prohibit it and its legal status in unclear in 16 states, the review adds. There were six policy actions on TPO in 2015. Only Georgia’s proposal was enacted.

When Georgia's legislation made it the first southeastern state to legalize TPO, it was hailed as a success for the stakeholder process as well as for solar.

There was a lot of “set-up” in passing the Georgia legislation, including stakeholder talks with Georgia Power, Proudlove observed.

In other southeastern states, TPO proposals produced fights. Solar advocates’ 2016 ballot measure legalizing TPO in Florida lost to utility-backed opposition. Efforts to pass TPO-enabling legislation in North Carolina without Duke Energy’s backing failed.

Utility ownership of rooftop solar is a business model that is still emerging and there was policy action on it in only five states last year, the review reports. The question is how regulated utilities can participate in the highly competitive rooftop solar marketplace.

While 59% of utility executives surveyed by Utility Dive at the beginning of 2016 thought their utility should build a business model around owning and operating DERs and rate-basing these investments, only 29% thought it should be done through a regulated subsidiary and only 5% thought their utility should not have a business model around DERs.

But national solar installers have been vocal in their opposition to regulated entities in the marketplace. The “market context and program design” will be determinative, the review notes.

Arizona Public Service and Tucson Electric Power led with regulator-approved pilots of utility-owned rooftop solar. They are just now being implemented. Georgia Power and New York’s Consolidated Edison are developing trial programs through unregulated affiliates. CPS Energy, the San Antonio municipal utility, is in the process of implementing utility-led rooftop solar and community solar programs.

“Utilities in four states implemented or announced plans to develop programs for utility ownership of customer-sited rooftop solar systems, and regulators in New Mexico are weighing the pros and cons of utility-ownership of distributed generation more broadly,” the review reports.

“Not a lot of utilities looking at it right now,” Proudlove acknowledged.

Community solar

Only seven states and the District of Columbia took on community solar policy in 2015.

“There doesn’t seem to be any controversy or special challenge,” Proudlove said. “There just seem to be other priorities.”

There are about 75 community solar projects representing about 100 MW of capacity across the country but only 14 states and D.C. have enacted legislation. That means the vast majority of households and businesses without solar-suitable circumstances still do not have access to community solar.

Enabling legislation is necessary to remove regulatory barriers. It can, for instance, require utilities to provide participating customers on-bill credits for electricity generated by an off-site installation. There is also utility-sponsored community solar in about six states without enabling legislation

In 2015, Oregon and Maryland enacted key enabling legislation. New York and Hawaii directed utilities to file enabling tariffs. California moved ahead with its 600 MW Green Tariff Shared Renewables program.

After months of debate, Xcel Energy resolved much of its opposition to Minnesota’s community solar policy. It is preparing to move ahead on implementing “one of the most ambitious community solar solicitations in the country,” the review reports. Though only one project had been completed by January 2016, it adds, there are “over 1,500 additional applications in the queue, totaling more than 1,400 MW.”

Four surprises

There were four surprises in the year’s policy activity, Proudlove found. First, given the buildup about community solar, it surprised her that “there wasn’t more happening at the state policy level.”

It was also surprising that the final decision from Mississippi’s Public Service Commission sharply reduced the proposed net billing credit. Something happened between the draft and the final rule, she said.

The decision by Nevada regulators to not grandfather existing solar owners at the retail rate credit was one of the year’s biggest surprises.

“I don’t think many people considered that possibility,” Proudlove said. But it set a precedent that could lead to similar decisions elsewhere. “Louisiana’s proposed rule, which is far from being final, does not include a grandfathering provision.”

The spread in the valuation of solar, ranging from a very low avoided cost rate to as high as $0.33/kWh in Maine “is the most surprising piece of that topic,” she observed. “It indicates the methodologies must be very different.”

It did not surprise the CTEC analyst that regulators so consistently rejected fixed fee proposals because they were being used outside historical patterns. But, Proudlove said, it does anticipate a shift toward debates about demand charges and TOU rates going forward.