by Julian Spector
July 30, 2019

The summer news doldrums, if they were ever here, have officially ended.

I often like to pick a unifying theme for my weekly Storage Plus column, but lately, too much has happened in the market that's just too big to ignore. 

There's been a flurry of activity in the long-simmering market of the Northeast. Commercial storage leaders are moving into bigger territory and tapping the wholesale markets in unprecedented ways. At the same time, a rule buried in Massachusetts' landmark solar-plus-storage incentive could stymie the state's efforts to get more batteries on the grid.

And GTM just wrapped up a daylong forum exploring how to make money in this region, with a special emphasis on Massachusetts and New York. Since you're already reading this, you have access to the archived videos of the sessions through GTM Squared.

But the news did not sequester itself in the Northeast. As analyst Daniel Finn-Foley put it to me recently, "We are not a nation of red states and blue states — we are a nation of energy storage states." That oratory came in response to Georgia Power's latest resource plan, which calls for 80 megawatts of storage. More on that below.

Heading west, a rural electric cooperative in Oklahoma made waves by contracting with NextEra for what will be the nation's largest wind-plus-solar-plus-storage plant. How'd that happen, one may well ask? It's cheaper than a peaker.

Which brings us back to the golden shores of California, or at least the sun-toasted city of Glendale, nestled betwixt mountain ridges inland from Los Angeles. A grassroots push against a proposed gas peaker encouraged the city council to pump the brakes last spring. Since then, the municipal utility underwent perhaps the fastest energy transition I've ever seen. It's now overhauled its entire portfolio plan and replaced the gas plant with storage, distributed energy and a small number of reciprocating engines.

Enough exposition, let's get to it.

Wholesale power, without all the stress

Remember when all those massive European energy companies bought American storage startups, and the market braced for impact?

It's actually been pretty quiet since, as corporate integration trundles along and the lengthy commercial and industrial storage sales cycle does its thing. But a revelation from Engie Storage this week sheds light on what you can do with a diversified corporate parent and a fat balance sheet.

Developers in ISO New England can now get paid for their batteries' wholesale market participation, but not in the usual way. Engie will run the numbers on expected lifetime market revenues, then cut a check up front to pay the developer for the dispatch rights.

This gives storage developers more guaranteed money in their pocket, while putting the responsibility on Engie Storage to navigate the ups and downs of merchant activity. Engie, of course, has ample corporate experience generating and trading power in wholesale markets, and for them the storage plants will be just another asset in a diverse portfolio. They have a comparative advantage in this arena, but have found a way to share that benefit with their customers.

Now the question is, how big a difference will this make in attracting customers? Finn-Foley, of Wood Mackenzie Power & Renewables, thinks it could be a big differentiator. 

"A steady revenue stream instead of worrying about market bidding, volatility, and program compliance?" he said. "That's going to have many investors swooning."

The Massachusetts market has finally been picking up momentum. Recall that earlier in July, Engie competitor Stem revealed it too was moving into larger-scale, front-of-the-meter storage projects paired with solar. Both companies are stacking federal investment tax credit, Solar Massachusetts Renewable Target incentives and wholesale market participation.

Both companies also found a developer partner in Syncarpha Capital, a New York-based private equity firm that develops its own solar and storage. That firm clearly saw the trends coming in Massachusetts and got in early. 

Friction in Massachusetts, but how much?

Things seem to be rolling along in Massachusetts at the non-residential or community solar scale. Residential batteries, though, have hit an obstacle, I reported recently.

SMART, which has become the backbone of any Massachusetts storage project's business case, pays out based on solar production. To incentivize storage deployment, the state created a per kilowatt-hour adder for systems paired with storage. Naturally, such an incentive needs to verify exactly how much customers produce in order to credit them appropriately.

As currently written, the program requires customers to buy a new utility meter. For basic solar customers, that adds a few hundred dollars to the total project price. For customers seeking a DC-coupled solar and storage combination, which has become the big installers' preferred offering, the price rises considerably. 

Eversource, the state's largest distribution utility, has quoted a metering price of around $1,700 for DC-coupled storage systems, due to complications in the metering installation for that system design. For Eversource, that's a "rare exception" prompted by requests from larger solar installers.

For the solar installers, that expense deals a blow to the incentive dollars that are supposed to be putting solar panels and batteries to work. And the expense has prompted them to hold back on storage-paired systems until the situation is resolved. They see it as a meaningful obstacle to deploying DC-coupled systems, which have become the market-leading home battery arrangement elsewhere.

The metering need is valid, of course, but they propose using smart inverters that meet a verified threshold for accuracy. Programs in several other states already use this technology for metering. Eversource wasn't as enthusiastic, telling me, "We do not bill using customer-reported data from customer-owned meters."

The state Department of Energy Resources is looking into the dispute, but didn't have anything more to say just yet. How this story unfolds will say a lot about whether the SMART storage adder produces a meaningful uptake in the residential space.

The South keeps getting hotter

As a young energy transition enthusiast, my grandmother always told me, "You're never going to break open a new energy storage market in a vertically integrated monopoly territory if you don't ask."

The people of Georgia heeded that folk wisdom when their utility finalized its new integrated resource plan. In addition to bargaining Georgia Power up from 1,000 megawatts of renewables to 2,260 megawatts, stakeholders got 80 megawatts of storage thrown in for good measure (up from an initial proposal of 50 megawatts).

That marks one more big Southern utility ready to spend some money on batteries. I profiled the others joining the movement for Storage Plus in April; they include: Alabama Power, Entergy Arkansas, Duke Energy, Tennessee Valley Authority and Florida Power & Light.

They all realize that storage could be a great way to put capital to work and earn a regulated return. Not great news for independent operators, perhaps, but a potent opportunity for storage vendors, EPCs and developers looking to flip to utilities.

I was struck by a phrase in Georgia Power's proposal, which called for storage investment "to evaluate the technical and economic performance relative to expectations." That's quite a benchmark for utility attitudes toward this technology: instead of demonstrating storage in pint sized projects and studying them for years, Georgia Power is starting off the demonstration at the 80-megawatt scale.

"Cheaper than a peaker" in Oklahoma

The geography majors among us will recall that Oklahoma goes by the nickname "The Sooner State," as in, "Hybrid storage beats gas peakers here sooner than you'd think."

This striking development had local roots: the Western Farmers Electric Cooperative needed 400 megawatts of capacity, but decided to look at solar-plus-storage bids rather than just buying a new gas peaker. The results looked good.

"It’s actually cheaper, economically, than a gas peaker plant of similar size, particularly with the tax credits that are available right now," said Phillip Schaeffer, the principal resource planning engineer at the cooperative.

Then Schaeffer's team decided to add some wind to the mix, given the very low prices and high capacity factors in the central U.S. wind belt, and suddenly this corner of Oklahoma is on track to host the nation's largest wind-plus-solar-plus-storage plant, courtesy of developer NextEra Energy Resources.

This elusive trifecta represents a new type of grid resource. It checks the box for peaking power, as far as resource adequacy is concerned. But it will pump cheap, clean energy onto the grid round the clock, thanks to the complementary timing of the local wind and solar resource. It's not quite baseload, but it's much more steady than either wind or solar on its own. 

Last gas gasp?

But don't worry, I'm not going to leave you with only one story of energy storage and other clean resources knocking out new gas peaker investment. I'll leave you with another one.

When last we left the City of Glendale in April of last year, a grassroots push convinced City Council, in a dramatic early morning vote, to pause a $500 million gas peaker development and examine clean alternatives.

The municipal utility dutifully rolled up its sleeves and came back over a year later with an entirely new outlook. The City Council approved a resource plan that acquires 75 megawatts of four-hour Tesla batteries, 50 megawatts of distributed demand reduction, including home storage from Sunrun, and up to five Wärtsilä engines for backup power in a pinch.

Glendale Power & Light executed, in effect the fastest utility-wide energy transition I have ever seen. Plenty of utilities have arrived at a vision for decarbonized, distributed, digital grids, but never has it happened in a year.

The municipal model played a crucial role in this: with the utility answering to local government, the community had a more direct pathway to ask for clean alternatives than it would in an investor-owned utility. That said, the staff of the utility deserve credit for willingness to take a new approach, even though it meant tossing out the old playbook.

"Nobody made a mistake; it was just that technologies have advanced and it’s worth stepping back and taking another look," General Manager Steve Zurn told me.

Many more communities besides Glendale face that choice to re-evaluate a capacity procurement in light of changes in the cleantech market. Local air quality, greenhouse gas emissions and millions of ratepayer dollars hang in the balance.