A year of hearings and a new recommended order leave the ACC right where it began — with utilities and solar at odds
Just as Solomon’s decision to split the baby displeased both mothers claiming it, the long-awaited preliminary decision in Arizona’s value of solar proceeding displeases both utilities and solar advocates.
In October of last year, the Arizona Corporation Commission (ACC) attempted to stem two years of contention between utilities and solar companies over the the value of residential solar energy to the grid.
Commissioners ordered a new evidentiary proceeding on whether a cost of service valuation, a cost-benefit analysis, or another methodology best captures the value of rooftop solar to the utilities paying for it. The hope was that the value determined in the proceeding would replace the retail rate net metering program now used to compensate rooftop solar owners for the power their systems send back to the grid.
On Oct. 7, that proceeding (docket E-00000J-14-023) was supposed to near its conclusion when Administrative Law Judge (ALJ) Teena Jabilian issued “Recommended Opinion and Order” (ROO) to the commissioners that called for a shorter-term valuation for rooftop solar customers and recognized their right to be compensated for their generation.
From the start, Jabilian’s order signals a tectonic shift in the Arizona solar market, calling unequivocally for the end to net metering.
“Net metering, and the banking of [distributed generation (DG)] exports associated with net metering, should eventually be eliminated and replaced with a mechanism for the direct purchase by utilities of DG exports,” Jabilian wrote in the her recommended order.
In upcoming utility rate cases, the longstanding NEM retail rate credit must be replaced, and “[t]he value of DG exports should be used to inform compensation rates to be paid to DG customers for their exports.”
Jabilian’s order is a recommendation to regulators, who must make the final decision on how to compensate rooftop solar. And unfortunately for them, the two methods the ROO describes to determine the value of solar leave both sides of the debate unsatisfied.
“The Recommended Order from the ALJ states that ‘it is time to provide certainty and a path forward to resolve disputes surrounding the successful integration of DG with the utility's electrical systems,’” observed Greg Bernosky, director for state regulation at Arizona Public Service, the state’s largest electric utility.
But, Bernosky said, the implementation of the methodologies proposed in the ROO to calculate the value of rooftop solar to the utilities “may simply take too long…[and] unnecessarily results in the large majority of our customers without rooftop solar paying more than they should.”
Solar advocates, like Bernosky, praised the ALJ’s efforts in framing the valuation discussion, but worried the valuation techniques would shortchange solar in comparison to other generation resources.
“This ALJ has done tremendous work and there is an opportunity for the commission to come in and finish things,” said former ACC Chair Kris Mayes, now executive director of Solar Strong America, a SolarCity-backed advocacy group.
But “the commission needs to calculate all the values from distributed solar,” Mayes added. The opinion “calls for the benefits of solar to be calculated out five years. Other forms of generation are valued over 20 years or 25 years and there is no reason for solar to be discriminated against in this way.”
After a year of hearings and input, Arizona's commissioners now face the same dilemma they did before the proceeding of how to set the NEM replacement tariff. And while the recommended order lays out two detailed valuation methodologies, stakeholders say they need more guidance from regulators on how the schemes would be implemented — guidance that won’t come until after the conclusion of November’s critical ACC election.
Uncontroversial provisions
Some 30 parties took part in the VOS proceeding, including Arizona’s investor-owned utilities, electric cooperatives, and public power providers. Vote Solar, The Alliance for Solar Choice (TASC), Western Resource Advocates, and other environmental and solar advocates also participated, as did the Residential Utility Consumer Office (RUCO), and other consumer, labor, and industrial power user advocates.
The ROO highlights input on valuation from APS, the Tuscon Electric Power/UNS Electric utilities (TEP/UNSE), Vote Solar, TASC, RUCO, and ACC staff. Although much of the opinion divides utilities and solar supporters, it succeeds in finding limited agreement in two areas of significance.
First, to avoid the turmoil created earlier this year in Nevada, Jibilian recommended that DG owners interconnected before the effective date “be fully grandfathered” into the new rate structure “and continue to utilize currently-implemented rate design and net metering.”
All those interviewed for this piece applauded that determination.
Second, the ROO recommends setting the solar compensation rate through a solar valuation methodology and not a cost of service study (COSS).
Though COSS was proposed in detail by APS, the record “does not support approval of a specific COSS methodology in this proceeding,” Jibilian writes. “Valuation of DG exports should be based on an avoided cost methodology.”
None of those interviewed objected to that determination, though it was only tentatively endorsed.
The avoided cost approach, one of the two methodologies proposed by staff and recommended by Jibilian, “is related to what has been done in value of solar analyses in other states,” said Briana Kobor, program director for Vote Solar.
Though APS argued for retaining the COSS, both of the proposed methodologies “have sound elements that we can support,” Bernosky said. “If we were to pick, we think the avoided cost methodology gets us closer to the cost that we know we can transact for solar in the market now.”
Other utility executives reached by Utility Dive generally agreed, but declined to speak on the record about the ongoing proceeding.
Two solar valuation methods
Along with the avoided cost methodology, Jibilian wrote the “best and most reasonable option available in the record” is to use a Resource Comparison Proxy Methodology with a five-year rolling average.
The avoided cost methodology is to be based on “specific eligible costs and values of energy, capacity, and other services delivered to the grid by DG (of all types) over a five-year horizon, during each electric utility's rate case.”
The ROO recommends including DG’s environmental benefits and costs in an avoided cost analysis, but it gives utilities the option of excluding those elements if they were part of the integrated planning process and were included in operating costs.
Including DG’s societal and economic development benefits “is speculative and inappropriate for ratemaking purposes,” and including fuel hedging costs is also “inappropriate,” the ROO determines.
The proxy methodology is the other option offered in the ROO. It is to be based on the price of generation from central station resources that came online within five years of the rate case in question.
In the ROO, the Staff proxy method calculation, based on APS PPAs, derives an average cost of $0.113/kWh. For resources both owned and contracted for by APS power purchase agreements, it is $0.109/kWh.
For TEP PPAs, the average cost is $0.106/kWh and the average cost for TEP-owned and PPA resources is $0.111/kWh. For TEP's entire project portfolio, the proxy method produces an average cost of $0.133/kWh.
As newer vintage, lower cost PPAs enter the utilities’ portfolios, the five year rolling average price is expected to decline.
Those rates are near the current ones paid to Arizona solar customers, and Jibilian writes the proxy valuation may not change those rates right away. Instead, they “will provide a path for a gradual transition away from the current net metering model to one that better reflects the value of DG.”
Utility executives welcomed the two valuations, but largely preferred the avoided cost methodology.
“Our position has been that we believe we can justify a cost that is closer to avoided cost in what we can acquire solar for right now,” APS’s Bernosky said.
Another utility executive, who was not authorized to speak in detail on the proceeding, was more direct.
PPAs for central station arrays that can be built adjacent to utility distribution systems in Arizona are now in the range of $0.03/kWh, the executive said. That makes it difficult in the existing regulatory paradigm to justify spending $0.10/kWh to $0.13/kWh for rooftop generation.
But, the executive added, "the solar industry and its customers need a transition period and this gives them time to examine their toolbox and respond."
The proxy method has sound inputs, relies on real data, and can step down over a period of time, but it “does not get to what we think the right price is quickly enough,” Bernosky said.
APS has, however, “consistently supported gradualism and finding ways to transition to a steady state going forward that allows for everybody to have some certainty.”
The problem with the avoided cost methodology, Mayes said, is that “a value of solar determination needs to include the values of solar.” Excluding distributed solar values such as water savings, emissions reductions, and societal benefits is “a fundamental problem.”
How will valuation work, anyway?
The ROO states that the avoided cost methodology is to be used “in conjunction” with the proxy methodology to “provide the strongest and most flexible tool to inform our determinations in rate cases regarding the appropriate level of compensation for rooftop solar exports.” It does not say how this is to be done.
Data is to be provided by utilities during their rate cases. Commission staff is to perform the analysis and make its “assumptions and inputs” available to the rate case participants.
It is not clear to Vote Solar’s Kobor what “in conjunction” means or how the two different analyses will interact to create a rate to compensate rooftop solar exports.
“Both of the methodologies fall short of recognizing the full stream of costs and benefits that result from customers’ installation of local renewable resources,” she said. “I am looking forward to getting more detail from Staff about how they imagine they can work together.”
Both utility executives said they also await further guidance from the commission on how the methodologies will be applied.
The ROO offers no demonstration calculations using the avoided cost methodology but that method excludes significant streams of benefits and costs, Kobor said. It will give commissioners “only a partial picture of the impacts that rooftop solar has on the system.”
The proxy method “is not an approach I am aware has been relied on in any other state or context and so it also opens a lot of questions,” she added. “The numbers are based on utility-scale solar prices and have nothing to do with the costs and benefits of rooftop solar.”
The time factors
There are two time factors in the opinion and both stirred strong objections.
Solar advocates reacted strongly to the ROO’s assertion that “long-term forecasts should not be used to establish the value of DG.” Following the ACC staff proposal, it recommends using a five year forecast.
But that five year time horizon would break with the commission’s “many decisions that view solar as a long term resource,” Mayes said. “You don’t take solar panels off your roof after five years. They are going to be there providing benefit for the state and the utility for decades and the final ruling needs to reflect that.”
“Nearly every other cost-benefit analysis completed by a public entity has looked at the long term value over 20 years to 30 years,” Kobor said. She cited independent, state-commissioned valuation studies from Maine, Vermont, Mississippi, Nevada, and Minnesota that were not funded by a utility or the DG industry.
Looking at long term benefits and costs is an integral part of utility planning, she added. “The integrated resource plans for all three major Arizona IOUs include the level of distributed generation they expect to contribute to system peak over their fifteen year planning processes.”
Mayes agreed. “The norm for IRPs, PPAs, and contracts for power plants is always 20 years to 25 years. The benefits of solar don’t drop off a cliff at five years.”
Neither utility executive addressed the long-term forecasting versus five-year forecasting issue. Both were focused instead on how long solar rate credits would stay in place before being recalculated under the proxy valuation.
Waiting four or five years for the next rate case could be too long, they said.
“The ALJ’s position is that the five year rolling average that determines the proxy rate should be locked in between rate cases,” Bernosky said. A separate proposal from RUCO, which avoids locking in solar value and insteads recalculates it each year, might be preferable, he added.
Arizona utilities can currently obtain utility-scale solar at record low PPA prices, Bernosky said. It would unfairly impose costs on the utility’s non-DG-owning APS customers if the initial proxy value calculated in the ROO was not reset until the next APS rate case.
Mayes disagreed. An independent analysis of solar that includes solar's full range of benefits over a 25 year period might make it possible to work outside rate cases, she said.
“Without that analysis, doing the calculation in rate cases that come every four years to five years gives people who go solar some certainty,” she said. “Doing it every year is a recipe for uncertainty and instability in the solar market.”
The coming commission decision
Bernosky expects the commission’s ruling on solar valuation to come next meeting on Nov. 29 and 30.
“Our final position is that both methodologies have sound elements we can support,” he said. “If we had to pick, we think the avoided cost methodology gets us closer to the market cost of solar. But we can support the proxy methodology with the right transition plan, the right timing, and the right step-downs.”
APS, he added, will be “happy to work with all parties on any of the models the commission adopts."
Stakeholders should not assume the AJL’s recommended order will be approved as written, Mayes said.
When she was ACC Chair, “we amended recommended orders many, many times,” Mayes said. “These recommendations are just a starting place for the commission. It is not over until it is over. The commission has the chance to include all the benefits and values of solar in the final order.”
The outcome of the November election, in which three ACC seats will be decided, could be determinative, Mayes added. “Both Commissioners Burns and Tobin have identified the fact during campaigning that we need to have the full value of solar quantified.”
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