As states debate solar, contentious rate cases give way to broader valuation proceedings
Fixed charges and net metering dominated solar debates in the second quarter, but the rate case is increasingly not the forum
Heated regulatory proceedings on rooftop solar and other distributed resources across the country continue to pit utilities against clean energy interests, but a close look shows the dialogue in some states could point to common ground.
The vast majority of the 121 policy actions on distributed solar and rate design in the second quarter of 2016 involved the most contentious and familiar of utility solar issues — net metering and fixed charges.
There were 42 actions on residential fixed charge increases and 37 on net energy metering (NEM), according to the recently-released 50 States of Solar report, the quarterly national solar policy update from the North Carolina Clean Energy Technology Center (CETC). Q2's 84 regulatory dockets and 15 legislative proposals on solar also included 16 actions involving less contentious studies on the value of solar or the impacts of net metering.
Many policy watchers had expected utilities’ proposals to evolve away from fixed charge increases and toward more nuanced rate designs where utilities and advocates might find some consensus, said Autumn Proudlove, senior policy analyst the CETC.
From a raw numbers standpoint, policy actions in the second quarter did not bear that out, Proudlove said. But a closer look at regulatory dockets in some states suggests the trend may indeed be changing, with more comprehensive valuation proceedings emerging from the most heated rate case debates.
“It was expected that fixed charge proposals would fall off as utilities moved toward demand charges but we have seen few demand charge proposals,” Proudlove told Utility Dive. The amounts of the fixed charge increases utilities asked of regulators in Q2 also “remained relatively stable.”
Q2 solar actions
Jesse Morris, the electricity program principal at the Rocky Mountain Institute, has seen similar patterns this year.
“The three biggest trends in solar policy seem to be proposals from utilities to increase residential fixed charges, challenges to net energy metering, and more and deeper studies on solar valuation,” he said.
Utilities’ fixed charge requests have, according to CETC numbers, continued to meet with resistance from regulators.
“More than half of requests for fixed charge increases made in 2016 were not granted any increase, and in Q2 2016 none of the utilities’ fixed charge increases were fully granted,” Proudlove said. Two utilities got less of a hike than they asked for and four got no fixed charge at all.
Regulatory apprehension last quarter builds on a trend in the sector. In 2015, 16 of the 37 fixed charge requests decided by regulators were dismissed outright. Of those approved, the utilities’ median fixed charge increase request of 92% was reduced to only 20%.
Net metering and potential replacements for it were the other big solar issues in Q2, building on persistent debates over the past three years. Here, there seems to be a trend toward utility proposals to reduce the retail rate NEM credit to something lower, typically an avoided cost rate, Proudlove said.
The retail rate credit was lowered significantly in Hawaii and Nevada last year, but left in place in California, she pointed out, but said that is too few examples to identify a trend. Many net metering dockets, notably in Arizona, remain unresolved as regulators look at larger issues of solar valuation.
Beyond altering NEM rates themselves, some regulators also looked to alter caps on net metering programs that limit them to a certain percentage of utility load. Where caps were raised, the new caps were often quickly threatened, Proudlove pointed out, such as in Hawaii, where one NEM successor tariff approved last year is already approaching its cap.
What has become clear this year is “how strong an impact uncertain policy can have on the solar market,” Proudlove said. “The Nevada commission’s decision had a huge impact on the state’s solar industry and the ongoing Massachusetts debate over the cap seems to be creating a boom and bust cycle.”
The biggest uncertainty may be coming from persistent utility efforts to increase fixed charges on customer bills.
Smart technologies allow distributed energy resources (DER) like rooftop solar to respond to some rate design changes like demand charges or reductions in the NEM credit, Morris said, but none of the smart tools effectively maintain the DER value proposition against high fixed charges.
“These actions by utilities are part of a political morass,” he said. “Utilities are responding to flat or declining electricity sales under the traditional cost of service ratemaking model and they need a way to recover costs. Increasing fixed charges is an effective way to do that. But it is not the best solution.”
More nuanced rate design solutions now being developed as part of comprehensive reforms in California, New York, Hawaii, and Minnesota have not registered strongly in the CETC statistics, Morris said, but “will enable a better way forward for everybody.”
“These proposals go beyond traditional cost of service ratemaking to tease apart rates, deploy market mechanisms, and build a least cost, most reliable electricity system in which consumers, utilities, and private providers can all emerge winners,” he said.
A sector in flux
The regulatory actions compiled by the CETC are the result of DER markets “racing ahead of the policy changes that might be needed to best accommodate them,” the 50 States update reports. “Fair compensation for both solar customers and utilities is at the heart of ongoing state solar policy and rate design discussions.”
Utilities argue that because net-metered customers significantly reduce the variable portion of their bill, they are not paying for their fair share of fixed operating costs. This, they say, creates a cost shift from DG owners to the rest of utility customers.
Solar advocates argue their systems provide benefits to the grid that utilities fail to acknowledge and compensate. There are many cross-subsidies inherent in utility rate designs, they say, and solar shouldn’t be singled out even if one does exist.
“It is reasonable for utilities to argue to their regulators that they need to deal with the cross-subsidy before solar adoption gets too big,” said Synapse Energy Economics Sr. Associate Tommy Vitolo.
But recent proposals are for dramatic increases in fixed charges and reductions in the NEM credit, he said. “Those proposals are not well aligned with Bonbright’s principles of good ratemaking and the utilities have not done a good job at justifying them, which is why regulators have rejected most of them.”
Utilities often assume revenue erosion from DER results in “an inadequacy of cost recovery for the utility and therefore a shift of costs to non-participating customers,” Solar Energy Industries Association VP Sean Gallagher recently told Utility Dive. “You can’t just assume that. You have to do the math on all the benefits and costs.”
The CETC update specifically excludes “a review of state actions pertaining to solar incentives, as well as more general utility cost recovery and rate design changes.” Those are the regulatory proceedings in which Gallagher’s math is currently being done. But a close look at many rate cases reveals that the contention in individual cases can often lead to broader, more comprehensive attempts to value distributed generation.
Rate cases evolve to broader valuation proceedings
The most notable example of policy action in the Q2 report is the most recent rate case filed by Arizona Public Service (APS), Proudlove said.
Though controversial, it and a lesser-known proposal in New Hampshire illustrate how contentiousness in rate cases can lead to higher-level proceedings, where solutions can be sought outside the pressures of a general rate case.
APS asked the Arizona Corporation Commission (ACC) for new fixed charges, a significant reduction in the retail rate NEM credit, and demand charges.
The set of changes reflects a longstanding APS concern about the cost shift. It “already totals $42.7 million and is growing rapidly,” its rate case filing reports.
If no change is made to the net metering credit, the utility expects to come to its next rate case, in three years, with an annual cost shift of $102.9 million. Extending the value of the 20-year life of the rooftop solar arrays, the utility estimates the “nominal value” of the cost shift to be at least $1 billion.
These cost shift calculations are based on the standard utility cost-of-service methodology, Vice President Jeff Guldner told Utility Dive. That method of establishing cost has long been used for rate cases.
When APS previously asked the commission to reset the net metering credit last fall, solar advocates protested that the cost of service methodology does not work for distributed generation, and an assessment that included the benefits of solar to the system would be more appropriate.
In response, the ACC moved the debate out of the rate case and initiated a value of solar proceeding.
Despite that value of solar docket is ongoing, APS moved ahead with their controversial rate filing in June.
“We recognize the decisions in that proceeding could have an effect on the final outcome of our rate review,” Guldner said.
That now seems more likely than ever. Last week, Arizona regulators delayed a ruling on demand charges for solar customers in a separate rate case for utility UES Electric, saying they wanted to wait until the conclusion of the value of solar docket. The decision builds on a ruling from an administrative law judge in June, which said new rate designs and incentive structures for rooftop solar customers — such as a net metering reform — should wait until after the value of solar docket concluded.
“It is anticipated that the Value of DG docket will yield significant new information about how DG solar should be compensated,” Judge Jane Rodda wrote.
Arizona’s utility-solar debates are well-known, but another notable example of a request for a fixed charge increase was the April 2016 general rate case filing by Unitil in New Hampshire, Proudlove said. The utility proposed that its $10.27 per month residential fixed charge be upped to $15.00.
But later in April, the New Hampshire legislature ordered its Public Utilities Commission “to create a long term regulatory solution for the interconnection of new net metering facilities,” Unitil Media Relations Manager Alec O’Meara told Utility Dive.
As a result, Unitil removed the fixed charge increase proposal from the rate case. The higher level proceeding on net metered distributed generation “will be more collaborative in nature and will involve all utilities in New Hampshire,” O’Meara said.
Short vs. long-term thinking
The controversial proposals for fixed charge increases and net metering cuts are coming from rate cases, like the APS and Unitil proposals, RMI’s Morris pointed out. But the most important and replicable solutions are coming from the higher level proceedings that often result.
Ironically, many utilities ask for fixed charge increases or reductions to NEM credits in rate cases at the same time as advocating for larger solutions in proceedings or legislative efforts to set comprehensive energy policies, determine accurate DER valuation, or implement grid modernizations, he added.
The APS case is one such example, and data CETC’s 2015 report seem to support Morris’s point.
While participating in the California Public Utilities Commission NEM 2.0 proceeding, both Pacific Gas & Electric and San Diego Gas & Electric proposed residential demand charges in their 2015 rate cases.
While participating in the landmark New York REV proceeding to revamp the state’s energy policy, Consolidated Edison proposed a residential fixed charge increase in its 2015 rate case.
And while Xcel Energy was instrumental in Minnesota’s grid modernization proceeding and working cooperatively in the state’s E21 initiative on energy policy innovation, subsidiary Northern Power proposed a residential fixed charge increase in its 2015 rate case.
“Utilities are doing what they are supposed to do in the rate cases to protect their shareholders’ interests and keep the lights on,” Morris said. “That is what their incentives lead them to do under the current utility paradigm. That is the challenge.”
In proceedings with a more comprehensive approach, utilities are being asked to start by defining the services necessary to maintain today’s delivery of electricity and then to identify the technologies, programs, and rates they can implement to continue the cost-effective, safe, reliable delivery of electricity, Morris said.
“That is the conversation that is happening in the higher level proceedings and it does not fit with the short term perspective of traditional cost of service ratemaking used in rate cases,” he added.
While longer-term thinking has so far been confined to a few states, there are indications that approach could spread.
The National Association of Regulatory Utility Commissioners (NARUC) — the convening body for state utility regulators — recently published a Manual on Distributed Energy Resources Compensation, aiming to help commissions address DER issues in a standard, comprehensive method.
The NARUC manual points out that utilities tend to focus on short term fixed costs, leading them to see the “overwhelming majority” of their costs as fixed, explained Minnesota Public Utilities Commission Policy Director Chris Villarreal, who led the NARUC effort to draft the manual.
This perspective on fixed costs inclines utilities to seek recovery of those costs through rate designs like demand charges and fixed charges, he added. “But in the long term, a much smaller percentage of costs are fixed.”
Each state’s regulators must understand this and then decide whether to focus on the short term or the long term, Villarreal said. “The manual hopefully provides pros and cons of each, without reaching a conclusion.”
Third quarter and beyond
As direction emerges from the higher level proceedings, it will be possible for utilities to align their proposals with larger energy policy objectives, Morris said. For now, they must operate according to existing incentives.
Approaches to distributed solar policy and rate design remain widely varied and the only constant is that the majority of states are considering changes, CETC reports. But the outcomes “will be instrumental in determining future solar market growth and which markets see this growth.”
In addition to the actions described, the update summarizes twelve actions on community solar, three actions on third party ownership of solar, and three on utility-led efforts to own distributed solar.
In the upcoming quarter, only eleven state legislatures will be in session, so fewer lawmakers will be weighing in on policy than in the past two quarters of 2016. Proceedings in Massachusetts, New Hampshire, Maine, and Vermont are expected to be determinative for NEM but will not necessarily conclude in Q3.
The 36 residential fixed charge increases pending at the end of Q2 2016 included general rate cases for Duke Energy Progress in South Carolina and Ameren in Missouri. By the end of the year, Nevada’s turmoil could be affected by its utilities’ general rate cases and a decision by the state Supreme Court on the Bring Back Solar ballot referendum, NC CETC reports.
Demand charges for residential solar customers, NC CETC adds, remains “an area to watch, especially as decisions are made on demand charge requests in Arizona, Oklahoma, and Texas in the coming quarters.”