Arizona’s energy future took an unexpected turn this week.
At a hearing Tuesday for the routine assessment of major
utilities’ long-term resource plans, regulators rebuked
the proposals and instituted a nine-month moratorium on new gas plants
larger than 150 megawatts.
The commissioners are in the midst of examining an energy
system overhaul to pursue 80 percent clean energy with a focus on
energy storage to meet peak power with clean sources. The building freeze will
prevent near-term investments in gas infrastructure that could become stranded
assets if the grid overhaul comes into force.
Halting gas construction was an unusual move, especially for
a panel of five Republicans in a state without a political mandate to tackle
emissions from electricity, as seen in California or Massachusetts. Indeed, the
nine-month freeze appears to be the first of its kind.
In contrast to the recently proposed grid reform, the
utilities’ integrated resource plans (IRPs), originally submitted last year,
relied primarily on natural gas for keeping the lights over the next 15 years.
Arizona Public Service, for instance, calls for more than 5,000 megawatts of natural-gas additions (some
of which replace retiring capacity), but negligible new utility-scale
renewables. The plan does anticipate 3,315 megawatts of distributed solar,
though, and several hundred megawatts of energy storage.
In Arizona, the utility regulators don’t approve or reject
IRPs; they “acknowledge” them -- or not.
“This is the first time the commission did not acknowledge
the utility IRPs,” said Jeff Schlegel, who testified at the meeting on behalf
of the public interest group Southwest Energy Efficiency Project.
“For the
commission to not acknowledge meant essentially that they had some pretty
serious concerns with what’s in the utility plans.”
The regulators then made their concerns explicit in an
amendment that called on the utilities to consider a scenario where fossil fuel
additions are capped
at 20 percent.
Another
amendment asks them to model a case with 1,000 megawatts of energy
storage, 50 percent clean energy and 20 percent demand-side management. That
mix of resources more closely resembles the grid overhaul proposed in January
by Commissioner Andy Tobin.
The freeze
on new large gas plants expires January 1, 2019 and includes a process
for utilities to seek special approval if needed.
APS didn't have any plans to build new gas facilities in
that timeframe, said Greg Bernosky, director of state regulation and
compliance, so the moratorium will not affect any utility operations. The
decision also applies to utilities Tucson Electric Power and UNS Electric.
Fast times on the Arizona grid
Tuesday's outcome highlights a difficulty of the energy
transition: Utility planning takes a long time, while new energy technologies
move very fast.
"It’s a multi-year process, so information gets
outdated," Bernosky said of the IRP process. He supports a commission
decision Tuesday to begin streamlining the IRP process.
As a result of that procedural pace, the vision described in
APS' plan, based on the view from Q3 2016, now looks out of date compared to
APS' own actions.
Last month, the utility announced a groundbreaking
solar-plus-storage plant to be built by First Solar, which will store
solar production in a 50-megawatt battery to dispatch precisely during the
summer peak hours of 3 p.m. to 8 p.m.
That project won an open-ended request for proposals,
beating out gas plants and standalone solar and batteries. In doing so, it
exceeds the IRP's expectations for new batteries and utility-scale solar in the
next five years.
"When we went to market and saw what was available to
meet the need, that project was there and we were able to obtain it,"
Bernosky said.
That experience reveals a disconnect between the official
projections of grid planning and what's available now from the clean energy
industry. The utility won't insist on outdated projections in the face of
changing market dynamics, Bernosky added.
"The IRP is a planning document -- it’s not a rigid,
static document," Bernosky said. "It’s something we use to look out
over a period of time, but we are making short-term procurement decisions based
on what is available in the market and what meets our customer and system
needs."
The right kind of solar
Still, the planning document carries weight as an expression
of where the utility thinks its energy mix is heading. It's already looking
probable that the next iteration will differ in significant ways.
APS remains skeptical of standalone utility-scale solar.
Given the expected influx of distributed solar, the grid will see a large
influx of generation in the middle of the day that drops off before the evening
peak hours. APS isn't interested in simply getting more surplus generation at
noon.
"If we were to just keep doing more solar without that
blend of [storage] technology, we would be almost causing more harm to the
system or additional costs to customers," Bernosky said.
"The ability
to catch and release solar with that technology pair is really exciting to us
now, and we'd love to see more in the future."
A year or two ago, that asset hadn't materialized, and APS
turned primarily to gas as the future tool to balance the fluctuations of
solar. In the meantime, APS itself has proven that another option exists and
can even beat a gas plant's economics.
The utility does not have any procurement processes going on
currently, but is evaluating what will come next, said Jeff Burke, director of
resource planning. New rounds of procurement, in turn, will inform future
planning efforts.
The commissioners' skepticism will influence which
investments Arizona utilities can expect to achieve rate recovery on in the
coming years, said Stacy Tellinghuisen, senior climate policy analyst at
Western Resource Advocates. That organization modeled a high-renewables
scenario for APS that it says would save ratepayers roughly $300 million
compared to the official IRP.
"I hope that we will see the utilities put out RFPs for
clean energy resources to meet their growing loads," she said.
APS has also pursued ways to procure capacity from merchant
gas plants in shorter time increments, Bernosky said, like seven years instead
of 20. That allows the utility to get capacity it needs in the short term
without committing to an unnecessary expense in the long run. But, he noted,
that was not described clearly in the last IRP.
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