by Julian Spector
December 22, 2016

For energy storage to achieve its potential in the transformation of the grid, it requires not only technological advancement, but also the emergence of new business models for deploying the technology.

A smattering of models are already established, but so far, few real-world deployments have taken the form most conventional to grid improvements: ownership by the utility, paid for through the rate base.

It’s pretty clear by now that storage, whether placed on the grid or behind the meter, has tremendous potential to optimize the grid’s performance at a cheaper cost than traditional big-ticket upgrades to wires and generation. It would seem to make sense, then, to finance storage through the system in place for utilities to extract capital from ratepayers to update the grid on their behalf.

From the storage industry’s perspective, this could open up considerable new capital from very trustworthy buyers. A few big utility contracts on the resume give any storage startup a better case to make for other kinds of equity or project financing investments.

Lack of capital, per se, isn’t what’s holding back the growth of storage. It’s the dearth of avenues to deploy that capital. 

"Utilities are not unique in their ability to apply capital to that space, but they have a position, if they're going to rate-base and own it, that simplifies the situation," said industry veteran Julie Blunden, who consults on energy storage and chairs the board at CalCEF Catalyst.

Most states lack market designs that allow for storage to receive compensation for the services it can provide. The U.S. industry operates in select markets like California, Hawaii and New York, with Massachusetts perhaps joining soon.

Allowing utilities to not just own but profit from the purchase of storage, like they do from other capital investments, could win a powerful institutional ally for the fledgling industry. Utilities have to keep the system running, and as such they may feel the benefits of storage and be willing to pay for it in situations where the open market does not yet support it. That geographical expansion and acceleration would be the biggest boon to the industry from such a policy.

This ownership model is nowhere near that simple, though, or it likely would have already sorted itself out.

When utilities own and operate storage, that changes the competitive landscape for third-party developers operating in that market. Beyond that, the regulatory framework governing utilities differs by market across the U.S., so one policy won’t fit every system. On top of that, storage provides so many services that it blurs the existing categories for grid assets that utilities can rate base, meaning the very usefulness of the technology makes it harder to integrate in the regulatory system.

"No one has figured this out in the true sense of the term -- there's no 'This is how you do it, end of story,'" said Jason Burwen, policy and advocacy director at the Energy Storage Association. "We have different regulatory environments in different states, and it will probably be that way for a while."

These questions won’t be resolved in the space of one article. Consider this the first in a series of installments on the emergence of utility ownership models for storage around the country. The stakes are high and the wheels are starting to turn.

Early days

Models for utility-owned storage assets are still developing, because the technology itself is still developing. There haven’t been enough years with advanced energy storage on the market for utilities to fill out a robust portfolio of deployments.

For a utility to use the rate base for a purchase, it must prove to the commission that the asset is used and useful, the exact cost is known and measurable, and the investment is prudent, said former regulator Andrew Kaplan, now a partner at Pierce Atwood specializing in energy storage.

Traditionally, the utility would then own the asset, although some regions are experimenting with that variable. In Con Edison's Brooklyn-Queens Demand Management project (now called Brooklyn-Queens Neighborhood Project), the utility is allowed to use ratepayer money to make demand response payments to third parties, rather than paying for much more expensive substation upgrades.

A few storage ownership models have emerged thus far. On the customer-sited side, customers typically own the system outright or the storage company owns it and operates it in exchange for a service fee. Vermont’s Green Mountain Power launched a pilot in which the utility buys Tesla Powerwall batteries and sells them to homes to serve both the customer and the grid.

On the distribution grid, regulated utilities can generally own storage used specifically for distribution needs, although this has not been a frequent occurrence.

In deregulated markets, storage is often categorized as a generation asset, which means distribution and transmission utilities cannot own it. Massachusetts notably changed this in its omnibus energy bill this summer, declaring that distribution utilities can henceforth own storage to fulfill their duties.

California's groundbreaking 1.3-gigawatt storage procurement mandate came with a limit: utilities could not own more than 50 percent of the total amount of energy storage procured across the three “grid domains” of transmission, distribution and customer-located storage. AB 2868, passed this year, authorizes cost recovery for utilities to own another 500 megawatts of storage, including some behind the meter, provided they "do not unreasonably limit or impair the ability of non-utility enterprises to market and deploy energy storage systems."

At the highest scale, wholesale electricity market products cannot be owned by regulated utilities, precluding them from owning storage for the sake of frequency regulation, for instance. In PJM, which pioneered the use of energy storage to handle frequency regulation, independent power producers own most of the batteries. Those merchant owners come from the deregulated arms of utilities, like Duke, NextEra and AES.

The broad picture that emerges is a mishmash of differing policies depending on location and the type of utility involved.

What’s in a name?

The variety of regulatory frameworks complicates the evolution of utility ownership of storage, but so does the multifaceted nature of storage itself.

Utilities and public utility commissions plan and operate the grid using a set of established categories. You procure generation a certain way, and transmission has its own rules, as does capacity, and so on. Advanced storage technologies, though, disregard the existing nomenclature by performing all of those roles.

Variety may be the spice of life, but it tastes like turpentine to utilities tasked with following the letter of the law in their procurements.

Consider the experience of an early success in the field of utility-owned storage, down in Presidio, Texas.

This border town, powered by a 70-year-old radial transmission line from nearby Marfa, struggled with electrical reliability issues back in 2009. That’s when the transmission utility Electric Transmission Texas (ETT), a joint venture between American Electric Power (AEP) and Berkshire Hathaway Energy, got permission from ERCOT for a novel two-stage solution: It would install a hefty battery to tackle reliability issues while launching the longer-term project of upgrading the wires, which required regulatory approval, the granting of easements and such.

The approval came through. ETT installed an 8-hour, 4-megawatt sodium sulfur battery in March 2010, affectionately nicknamed BOB for "Big Old Battery." It was treated as a transmission asset for the purposes of financing the cost through the rate base. The new transmission line arrived in 2012.

By that time, BOB had earned its stripes. The battery improved reliability, smoothed out voltage fluctuations and improved power stability. If the radial line wasn’t working, the battery could island itself and power the town with imports from across the border from Mexico. It was doing things that went beyond the role of mere wires.

The conventional alternative would have been to build a generator down by Presidio, said Kip Fox, managing director of ETT. But generation companies weren't interested.

"It wouldn’t run that much, and they tend to make their money by running all the time," Fox said. "The battery was definitely the lower-cost alternative to new generation out there."

The battery approach also kept the responsibility for Presidio's electrical reliability in-house.

"We found a transmission solution for a transmission problem," said Leo York, transmission business development manager at ETT. "A battery plays a much larger role than just the charging and discharging."

That solution is now off-limits. The Texas legislature has since blocked the use of energy storage as a transmission asset. Batteries can still operate under the label of generation, but transmission utilities like ETT aren't allowed to own generation. That prevents ETT from financing additional batteries through the rate base, limiting the useful transmission services that BOB showed storage can provide.

Rules vs. reality

Utilities thus find themselves in a paradoxical situation when it comes to storage.

They have to follow the rules set by the legislatures and utility commissions in states where they operate; the penalties for disregarding them are steep.

Yet the rules on the books thwart the use of storage as a lower-cost alternative to big capital upgrades for distribution and transmission for the simple fact that storage can also behave like generation, which deregulated T&D utilities cannot touch.

Conversely, storage deployed as a generation asset in competitive markets cannot access compensation for the full range of benefits it could provide to the grid, or even to commercial and residential customers.

"The rules that we enacted 10 or 15 years ago worked well then, but some of these new technologies should be forcing a review of those things to ensure we’re making the best decisions for our customers," said Phil Dion, vice president of technology business development at AEP. "Calling it a transmission bucket or a generation bucket, you might miss the total value that is being presented."

In the near future, utilities may take the simpler route of narrowly defining storage in order to get it approved through the existing regulatory channels. This will limit the range of services it provides, but could lay the groundwork for a more nuanced regulatory regime down the road.

One model for that would be to separate the uses a battery project provides into roles that can be rate-based and those that cannot. A utility could finance and own storage for the roles it is allowed to play; the utility would then offer the remaining capacity for competitive bids from third-party companies to use it for services they are allowed to provide.

Texas utility Oncor proposed a model along these lines last year. It hasn't moved ahead yet, though. There are still a lot of questions to be answered about how to effectively divvy up the capacity of storage used for one role versus another. The Federal Energy Regulatory Commission held a conference in November on valuing multiple uses of storage and has been gathering information on the topic.

Regulated utilities are in a better position to rate-base storage, because they control and are responsible for more of the value stream. The risk there, Burwen pointed out, is that since the different grid services haven't been unbundled in the way deregulated markets have had to do, there might be less transparency about the value of discrete services. That makes it harder to argue storage will be a good deal for ratepayers for particular functions.

Keep the competition

The good deal for ratepayers will also be lost if utility ownership precludes robust competition to provide high value at low cost. This is a possibility, but not a huge risk.

The skeptical view goes like this: Sure, utilities have an interest in using storage to optimize the grid, and they have the best knowledge of where and how the grid needs help. But if utilities start developing and owning storage in-house, they'll have an incentive to disregard all the other vendors in the space, who could do the job at a lower price. And utilities' knowledge of their customer base and cheap cost of capital give them an unfair advantage over third parties.

This argument appeared in force during the debate over how much control California utility PG&E should have over electric-vehicle chargers. The California Public Utilities Commission approved a compromise last week that limited the utility's control, following pushback from EV charging companies and advocates worried about consumer choice.

The storage situation is a bit different, though.

"Storage can be competitively provided," Burwen said. "There's not a natural monopoly on storage."

That said, storage interacts with the complexities of the grid in ways that the utility is best suited to understand and take advantage of.

"Especially in some deregulated markets, utilities are at a significant advantage if they are also allowed to own these systems and get value streams that otherwise won’t be open to other players," said Ravi Manghani, energy storage director at GTM Research.

If a transmission and distribution utility owned and controlled a storage system near a solar plant, for example, it could benefit from renewable integration, but also perhaps voltage control and frequency response. An indepedent power producer (IPP) wouldn't be able to monetize all the uses a utility could.

A society that bars utilities from leveraging ratepayer dollars to invest in storage directly, then, would forfeit a valuable tool to deploy this early technology. 

One alternative is to allow utility ownership of storage with appropriate safeguards on competition.

"You do not want to limit the degrees of freedom for how to deliver services," said Julie Blunden, the storage industry consultant. "You want to make sure there’s a competitive component to just about everything on the grid, because that creates lower prices and better outcomes with more creativity."

California created appropriate safeguards for competition when it authorized utility ownership behind the meter, by capping the capacity that utilities can own and instructing the CPUC to block any anti-competitive applications, said Ted Ko, director of policy at Stem. The California-based company owns and operates customer-sited storage for the benefit of commercial clients and the grid, so it has a definite stake in whether the utility owns storage outright.

Focusing the debate squarely on ownership leaves out a critical piece of the storage puzzle, he added.

"The question doesn’t come down so much to who owns the asset, but who controls the asset and what it’s doing," Ko said.

The software running the system generates most of the value. Utilities know what to do with batteries to optimize the overall grid, but companies like Stem have the expertise to optimize for the grid and for the customer.

"Until the utilities have that kind of expertise, that kind of technology, it doesn't really make sense for them to have complete control over what the storage is doing," Ko said.

This view suggests a binary model for utility ownership. In front of the meter, the utility can have more leeway to own storage and control it for the benefit of the grid. Behind the meter, where the interests of the customer deserve more attention, there should be a higher competitive standard to ensure the customers are best served. The utility can own it and competitively bid out control over the systems to third party companies.

A powerful ally

By striking the right balance, states can make both utilities and the storage industry happy.

For utilities, there's a tradeoff between control and responsibility. Owning storage allows them to put it exactly where they need it, and to know it will perform when they call on it. But it also exposes them to the risks of an emerging technology, whereas contracting out to a third party creates a legal buffer.

Storage procurements also promise utilities a growth area in a landscape where electricity demand growth has flattened out and traditional investments aren't as needed.

"In an era when we’re seeing declining energy usage, where do utilities increase their rate base if they don’t need to increase wires and transformers?" Ko said.

For storage vendors, there are risks but also considerable rewards. One is business. There's a way to do this in which the utilities own and rate-base storage, but contract with the third parties that have the expertise to actually carry out the job.

"Storage IPPs probably won't care if they are the ones that own the systems or if they build and transfer to utilities, as long as they're paid for the resource adequately," Manghani said.

Another is bankability. Utilities pay their bills, and utility contracts have already helped storage startups prove that they're serious and score better financing from lenders.

"Investors will say, ‘Hey, if it’s going to be paid for by ratepayers, there’s a good chance utilities will buy storage’" said Kaplan, the energy regulatory lawyer. He acknowledged that ceding ownership to utilities might not seem ideal to companies fighting to break into this space, but added, "Sometimes, when you’re dealing with new rules and putting things in place, you have to take more baby steps."

The small but growing storage industry has won some notable successes so far in a few key markets. Having the clout of a few big utilities behind it could prove valuable in cracking open even bigger markets.

"Utilities have the potential to help drive the conversation from a regulatory perspective in a way that has the potential to move the market faster," Blunden said. "When the utilities want something and are sure about it, things tend to move faster. [...] If that means that they get a part of the pie which is going from a minute, cupcake-sized pie to a dinner-table-sized pie, giving the utility a slice of that is not necessarily a bad outcome."

That exact balance that satisfies both the storage professionals and the utilities has not been nailed down. It will look slightly different from state to state. It will look very different from regulated to deregulated markets, and behind the meter versus in front of it. Check back regularly, then, for what is sure to be one of the key storage stories of 2017.

"Must we build Rome in a day?" Burwen mused. "This is probably less about getting it all right in one go and more about taking on territory that is manageable and resolving questions there, and then taking on more territory."