by Julian Spector
October 13, 2017

The apocalyptic ash blotting out the sun here in Northern California reminds me how helpless even the most technologically advanced regions can be in the face of broader climatic forces.

In this case, an exceptionally wet winter prompted a growth spurt of underbrush, which by October lay parched and crackling across the inland landscape. We don't know what exactly caused it to ignite, but once it did, heavy gusts carried the embers, and a few hundred acres of burn soon gobbled up more than 200,000.

A few of the individual blazes have been contained. Some are just 5 or 10 percent contained, meaning the effort to ring them with a cleared perimeter has scarcely advanced. Firefighters have been in the trenches for days with minimal sleep.

We don't know exactly what role climate change played in this conflagration, but directionally it's bringing more extreme weather, both in terms of storms and hot spells. And though humans had the agency to set climate change in motion, and settle in regions known to experience massive wildfires, we quickly find ourselves unable to control the effects of those decisions.

The distant, blood-red sun and the opacity of the San Francisco skyline also attest to what happens to the air when you burn lots of fuel. In neighborhoods that host coal plants or peakers, combustion produces particulates like this on a regular basis. 

The deleterious effects of those plants on nearby residents have been well documented in the public health literature. Energy storage can't put out forest fires, but it may be the best tool available to displace the power plants that emit particles in and around people's homes during business as usual. The first substantive step in that direction happened last week.

Storage put a dent in Puente

And it happened fast.

First, the California Independent System Operator was saying batteries could replace the proposed gas peaker on Oxnard's coastline, but at considerable cost. We pointed out that those cost assumptions were outdated, and CAISO followed up, saying the best way to tell how much distributed energy resources would cost to fill the reliability need would be to run an expedited request for offers and let the industry bring their best proposals.

That was enough to prompt a pre-emptive rejection last week from the members of the California Energy Commission tasked with writing a preliminary decision on whether to approve NRG's Puente gas plant.

They believe the evidence shows Puente would violate the state's environmental laws and regulation. Since CAISO testified that another option exists that wouldn't pose an environmental problem, the commissioners don't see a compelling reason to override the regulations and let Puente move forward.

They shared their thinking ahead of the official completion of their decision because of the timeliness of the process. To meet the deadline for local reliability, the procurement needs to get going and give the industry time to get permits and build. 

This isn't final. After a few more steps, the full commission still needs to make a final ruling. Then there's the matter of running the RFO. That will require some work from the California Public Utilities Commission, essentially to re-run a process it already conducted and concluded (back in the days before batteries were a proven solution for local reliability).

It's unclear where this saga will go next. What is clear is that we're watching a new precedent emerge for how new peaker plants get evaluated. They aren't the only game in town anymore.

It's not hard to see lessons taken from this fight applied to other permitting battles, especially if a proposed plant will cost a lot of money and not run very often. Stakeholders will have grounds to at least explore whether storage and DERs can fill the need. 

And if they find that the costs would be comparable, it gets a lot harder to argue for the plant's necessity.

That's not to say storage will succeed in other cases like this. California's regulators have blazed trails in storage permitting and procurement, and they've gained confidence from watching it perform in cases like Aliso Canyon. States without that history of dealing with storage -- which is almost every other state, after all -- aren't going to toss out the tried-and-true gas plants easily.

Someone has to do it first if this whole transition away from fossil fuels is going to happen. If California follows through on the concept and things work out fine for Oxnard (or better -- they could get their beach back), it will make it that much easier for others to swap peakers for storage too.

Got any bets on which proposed gas plant could be the next storage vs. peaker showdown? Send me your picks at [email protected].

Let's hang out!

Speaking of storage in California, GTM is hosting the third annual Energy Storage Summit in San Francisco, December 12-13.

It'll be the hippest place to catch up on the latest happenings in the industry, not least because I'll be there. I'm leading a panel discussion on what elements of state storage pilots actually work, and another in which we'll debate whether lithium-ion hegemony is really a good thing for the industry.

Moreover, I'd like to seize the opportunity to get to know you, Storage+ readers. Let's cross over the digital fence and meet in terrestrial space, namely the Hilton Union Square. I'm sure we'll have plenty to talk about.

And if intellectual curiosity doesn't win you over, here's some cash: Type in promo code SQUARED and take $200 off. It's hip to be Square.

Wind execs, financiers aren't impressed with storage yet

A confluence of wildfire-related travel disruptions landed me on stage at the ACORE Finance West conference Thursday, interviewing a trio of wind power CEOs about the future of their business.

One thing they didn't see in that future: storage.

At least the folks on my panel hadn't yet seen a reason to add storage as a way to time-shift wind production. They operate in the Eastern U.S. and Midwest, and said there isn't enough of a price differential between high-demand and low-demand times to justify the cost of a battery system.

“There’s no value from the arbitrage of the energy,” said Jim Spencer, CEO of Pittsburgh-based EverPower Wind Holdings. "[Storage] is useful, I’m just not sure it’s profitable -- that’s the problem."

Absent policies like California's to require a storage build-out, or regulations like the proposed Clean Peak Standard to ensure a certain amount of peak power comes from clean energy, they didn't see a reason to invest in storage just yet.

Steve Vavrik, chief commercial officer at Apex Clean Energy, echoed that sentiment on a separate panel on project financing. He doesn't see a load-shifting opportunity for storage with wind unless it's mandated, but allowed for some opportunities in ancillary services and island grids.

"I don't know if market conditions are going to reward energy storage until gas gets more volatile," he said.

Financiers, like Jack Cargas, managing director of renewable energy finance at Bank of America Merrill Lynch, said they are seeing greater interest in storage financing, but scale is a challenge. Big money isn't going to get involved with small, standalone projects, which have characterized most of the deployments thus far. 

To move beyond balance-sheet financing, storage will need more expensive projects, or larger fleets of projects that can be financed together.

Sonnen making VPP a thing in the U.S.

If you've been to a cleantech conference any time recently, you've heard talk of virtual power plants and how exciting they are. It's a lot harder to actually find one.

German storage startup Sonnen has linked up thousands of its European customers into just such a network though, and they've been trying to bring the model to the U.S. Energy regulations here make it impossible to directly replicate that approach, however, so Sonnen attacked it from a different angle.

The company is working with an Arizona homebuilder, Mandalay Homes, to construct a 2,900-home community where each house comes with 3.9 kilowatts of rooftop solar and an 8-kilowatt-hour Sonnen battery. They're trying out a new pilot rate from Arizona Public Service that rewards homes with very low on-peak usage by offering low energy rates the rest of the time. 

This is a massive project relative to the tiny U.S. home storage industry. And once finished, it will have 11.6 megawatts of power input and output and 23 megawatt-hours of energy storage capacity, with the option to add more if needed.

The companies chose to go ahead and build it without a utility contract for use of the asset, at a time when most companies wait to secure grant funding or contracts before deploying their concept. They feel confident that the economics are covered by the price of the high-performance home; any utility revenue down the road would be an added benefit, with ratepayers potentially saving as well.

Will that boldness be repaid with profits? Will others follow with their own creative workarounds to the meager drip of pilot funding? Stay tuned.

Green Charge crosses the meter

Also notable, longtime C&I stalwart Green Charge is jumping the fence. The company announced its first utility-scale project, a 3-megawatt/6-megawatt-hour deal for the municipal utility in Holyoke, Massachusetts.

The increase in scale follows naturally from the acquisition by energy giant Engie. Green Charge CEO Vic Shao even hinted that international expansion is on its way. 

This also marks an early entrant into the Massachusetts storage market, which was expected to take off following the announcement of a state target earlier this year, but has actually stayed pretty quiet.

In the future, look for Green Charge to roll out this model with other municipals in Massachusetts, performing demand-charge management on behalf of the utility, which has to pay for its annual peak. The company got a bank to own the asset and claim the tax credit, so more of this financing could be on its way too.