FEATURE
Why Arizona's long-awaited
value of solar schemes please
no one
A year of hearings and a new recommended order leave the ACC
right where it began — with utilities and solar at odds
By Herman K. Trabish • Oct. 24, 2016
J
ust 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 SolarCitybacked 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 fiveyear 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 nonDG-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.”