GREENTECH MEDIA — 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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