Among a record level of U.S. solar policy actions tallied by the North Carolina Clean Energy Technology Center (NC CETC) in its latest quarterly report, a potentially important new approach to the renewable resource emerged. 

“Some utilities proposed separating customers who own distributed generation into their own rate class, but without actually proposing any rate increases or rate changes,” Autumn Proudlove, the center's manager of policy research, said.

Utilities have typically included proposals to increase fixed charges and add demand charges. “Now some seem to want to test regulators about the idea of a separate Distributed Generation (DG) customer class,” Proudlove said. “Or it could be they want to set the stage for later rate design changes.”

The NC CETC's “50 States of Solar; Q3 2017 Quarterly Report” found 142 solar policy actions nationally in Q3 2017, a 21% increase from the 117 actions in Q3 2016. It was the highest number of single quarter actions in the 12 quarters the center has been detailing solar policy activity. Proudlove said there was increased activity in almost all policy categories.

The design of rates for solar and other DG continues to dominate. Of the 142 state and utility-level proposals pending or enacted, 44 were related to residential fixed charge and minimum bill increases. There were 36 actions on net energy metering (NEM) and 23 on solar valuation or NEM studies.

Among the actions, new approaches to ratemaking have started new debates between utilities and solar advocates.

Demand and fixed charges opposed

Solar advocates argue demand and fixed charges for solar are not good ratemaking. Regulators have tended to agree.

Decisions were reached on eight of Q3’s 26 pending or decided utility requests for fixed charges. Only the Superior Water, Light and Power request in Wisconsin for a monthly increase from $7 to $9 was granted in full, NC CETC reported.

Proudlove said utilities were granted, on average, only 33% of their requested fixed charge increases.

Mandatory demand charges for DG customers have had even less success. There were only five demand charge and two demand-based minimum bill actions in Q3, Proudlove said. Two were decisions rejecting them and another proposal was dropped. No new mandatory demand charges have been proposed since Q1 2017.

“But they're not gone yet,” she added. If regulators greenlight a separate DG customer class, it “could lead to demand charges for that customer class being approved, or at least proposed.” NC CETC's Q3 report details states and utilities leading the charge to new classes and charges.

Separating classes

There were both legislative and regulatory efforts to create separate rate classes for DG owners, NC CETC reported. New laws in Montana and North Carolina allow establishing a separate rate class as part of a comprehensive DG proceeding. Iowa and Idaho regulators were working through the concept in Q3 and the Kansas Corporation Commission (KCC) approved it.

The Kansas decision “is really important because regulators have essentially said the separate class is acceptable,” Proudlove said.

In approving a September settlement between Kansas utilities and stakeholders, the KCC also ruled demand and other charges can be applied to the new DG class. But “any specific tariff changes will take place in utility-specific filings,” NC CETC reported.

Westar had 550 DG-owning Kansas customers in 2016, out of its 700,000 electricity customers. They represented 5 MW, or 0.11%, of Westar’s 4,500 MW peak load. 

Westar Media Relations Manager Gina Penzig emailed that the settlement allows utilities to design rate structures “with more accurate economic signals” for those customers. That will grow solar in Kansas, she added.

The KCC ruled that DG owners' rates should be based on “quantifiable and verifiable, prudently incurred costs needed to provide electricity,” Penzig wrote. This means utility rate design proposals also do not need to consider benefits provided by DG.

The KCC docket that led to the settlement included “a diverse group of stakeholders” such as Kansas environmental groups and three Kansas solar companies — King Solar, Cromwell Solar and Good Energy.

Westar VP Greg Greenwood told the Kansas Journal that settlement-compliant rate designs will ensure that DG owners pay “their fair share for the cost of the grid.”

King Solar President Mark Horst responded that Westar is inadequately transparent about the numbers that determine its cost of service. “For Westar to just be telling us what the fixed costs are — without any supporting data — feels unfair.”

The proceeding that produced the settlement “was not to reach an agreement with all the parties,” Penzig said. It was to inform stakeholders about the complexities, differences and importance of designing rates for DG owners.

That could be the stage-setting Proudlove suggested. And Penzig confirmed Westar is planning for new rates.

“In our last full regulatory rate review, a tariff that matches our standard residential rate was established for customers with private generation,” Penzig said. “In 2018 we plan to file for a new full rate review and will include establishing rates that better reflect how private solar customers use our services.”

Vote Solar Manager of DG Regulatory Policy Rick Gilliam said the KCC ruling includes “several successive poor decisions not based on a factual record.” One is that it assumes electricity usage of DG customers is "potentially significantly different" than non-DG owning customers, he said.

Another is its unsubstantiated conclusion that utilities’ current two-part rate structure, based largely on volumetric charges, is "problematic for utilities and residential private DG customers." Finally, he said, it concludes without data that other rate designs will better serve DG owners.

More leverage for utilities

In Iowa and Idaho, Idaho Power and Interstate Power and Light (IPL) have also proposed separating out DG owners and neither requested new rates, NC CETC reported.

Proudlove said dividing the issues could give utilities more leverage because regulatory approval of a separate rate class could seem to justify new charges for it. Gilliam agreed. Regulators generally tend to give utilities “some of what they ask for,” he added. “So, the more they ask for, the more likely they are to get something.”

Pace Center for Climate and Energy Executive Director Karl Rabago was an expert witness in the Iowa Utilities Board (IUB) proceeding that considered IPL’s proposal for separating rate classes. The former Texas utilities commissioner and DOE Deputy Assistant Secretary argued against the proposal.

Separating out DG customers without introducing a new tariff is “a highly unusual proposal,” he testified. Previous IUB orders required “three-year pilot programs” to develop “the datasets and understanding necessary to determine the appropriate ratemaking treatment for DG customers.”

Creating a new class is “premature” because IPL DG owners are “less than 3/10th of 1% of total residential customers and about ¼ of 1% of total residential sales,” Rabago testified. “Creating new customer classes for such a tiny fraction of the customers and load served is administratively inefficient, statistically dubious and ultimately unjustified.”

IPL “has the process exactly backwards” because new rate classes should be “the last step in addressing substantial and significant differences in cost-causation and usage between customers within a single class,” Rabago argued. First, IPL should determine “the actual costs” so that any proposal is “based on solid evidence of cost causation.”

Like IPL, Idaho Power asked regulators to approve separate customer classes without proposing rate changes, NC CETC reported. But Idaho Power also asked its commission to open “a generic docket” in which “a new compensation structure” for DER can be determined.

Idaho Power, the state’s dominant electric utility, has 1,468 active and pending net-metered systems among its 534,000-plus customers.

According to the filing, it will be up to regulators to determine the details of the rate classes and to guide the structuring of a successor NEM tariff. A new tariff is necessary to prevent “unfair cost shifting between customers who choose to install on-site generation and those who do not," the filing added.

Proudlove agreed that a BonBright principle of good ratemaking is to make changes incrementally to avoid creating shocks to ratepayers. She also agreed that creating a separate rate class without a new rate design or charge could be that incrementalism. But, she said, “it might lead to the next step, which is proposing actual rate changes.”

Incrementalism as a good thing?

A trend that first appeared in NC CETC’s Q2 2017 update seemed to get stronger in Q3, Proudlove said. Many states “are adopting smaller changes and obtaining more data from studies and pilots before shifting direction quickly or making radical reforms.”

Early examples were set by NEM decisions involving Xcel Colorado, Arizona Public Service and California’s three dominant IOUs.

“The principle of gradualism has emerged as a common thread,” NC CETC reported. Both the Louisiana and New Hampshire commissions made “minor changes” in NEM policies during Q3 and postponed structuring successor tariffs until “comprehensive reforms” are evaluated.

Michigan’s commission postponed the design of an NEM successor tariff until a legislatively-mandated cost-benefit study is completed, Proudlove said. Both the Indiana and Maine commissions similarly postponed final successor tariff designs until data from pilots are available. Nevada’s experience showed the importance of incrementalism, she added. 

Nevada regulators “went to an extreme by essentially terminating NEM in 2015,” NC CETC reported. But “the legislature’s A.B. 405 restored order.”

In September, the commission complied with the law by restoring the state’s retail rate NEM tariff. Equally important, it affirmed the use of monthly netting to calculate DG owners’ import-export electricity balance, NC CETC noted. 

Netting is the major remaining difference between DG advocates and Rocky Mountain Power (RMP) in an important Utah action. 

A Utah commission-approved settlement was a Q3 example of an incremental NEM adjustment ahead of a bigger change, Proudlove said. A “transition tariff” that only reduced retail rate NEM compensation from $0.102/kWh to $0.092/kWh goes into effect in November. A two-year to three-year comprehensive proceeding will then determine a final successor tariff.

RMP Sr. VP/Chief Commercial Officer Gary Hoogeveen said the settlement was the product of an ongoing stakeholder debate that started in 2014 and considered both fixed and demand charges. “Governor Herbert firmly asked the stakeholders to reach a settlement instead of making the commission rule on the question,” he said.

The transition tariff and comprehensive proceeding seem the appropriate incremental approach to dealing with the 25,632 net-metered customers in RMP’s 875,000-plus Utah customer base.

But under the agreement, “RMP will charge rooftop solar customers for whatever electricity they consume and they will be credited at 15-minute intervals for whatever they export to the system.” Hoogeveen said. “There will be no monthly netting.”

Vote Solar’s Gilliam said the reduction from the retail NEM compensation rate will only cause a “modest” change in compensation to DG owners. But “the 15-minute netting is a real problem for the future,” he said.

Nevada’s resolution of its turmoil was through a “measured approach” to replacing NEM, he said. In it, a customer's “monthly net excess generation is compensated at a rate that decreases as overall penetration of rooftop solar increases.” 

The Utah commission’s 15-minute import-export netting “increases exports, reduces customer control and leaves solar customers vulnerable to higher prices,” Gilliam said. In the comprehensive proceeding, solar advocates will be watching to see “that all customers are treated fairly.” 

Hoogeveen said the successor tariff proceeding is likely to include “a full evaluation of the costs and benefits that solar provides to all customers.” But, he said, “the utility can purchase solar electricity on the market at $0.03/kWh to $0.04/kWh wholesale rates and that is what it should be purchasing solar at from solar-owning customers.”

There are other benefits from distributed solar, like line losses, that can be considered, he added. But the utility’s cost of electricity, which does not include external costs, should be what it pays because customers are not paying them in their rates. That would not be fair to the rest of our customers.”

So the new debate, in defense of fairness to customers, appears to be on.