Investment and interest in energy storage technologies has never been higher — too high, in fact, for the comfort of some analysts.

The energy storage market added about 475 MWh in 2016, almost 300% more than 2015 numbers, according to GTM Research’s senior vice president Shayle Kann.

“This extraordinary amount of attention and investment to an energy storage market where not much is getting deployed has all the makings of a bubble,” Kann told industry representatives at the U.S. Energy Storage Summit in December. “That should give everyone pause – but it is not a foregone conclusion that the bubble will pop.”

A handful of policies and events have spurred investments in energy storage, particularly in California and the PJM Interconnect region, and companies like Tesla have brought batteries into the mainstream with sleek new products.

But rising interest and investment didn’t necessarily manifest itself in actual deployments or regulatory approval. Pacific Gas & Electric, for instance is under a mandate to procure 580 MW of storage by the end of 2020. But so far, only 70 MW of its first 76 MW in contracts were approved by the California Public Utilities Commission (CPUC), according to PG&E’s senior vice president of regulator affairs, Steve Malnight.

The commission rejected some contracts on the grounds that they were not cost-effective, Malnight said. “Buying solar to meet the RPS was easier. Storage is a more complex technology with a more complex value stream and we are still learning how understand and monetize that value stream and address cost-effectiveness.”

Tesla expects economies of scale to drive down energy storage prices to as low as $0.05/kWh by 2030, said Mateo Jaramillo, who was vice president of Tesla’s products and programs before departing the company after the conference.

“We bet the whole company on it,” Jaramillo said. “It will take a lot of work to get the battery, the power electronics, and the mechanical and electrical systems down the cost curve. But it is engineering work, not science work, and Tesla is doing that work.”

But the market is still a nascent one, GTM’s Kann warned, similar to what the photovoltaic solar sector looked like in 2005. Unlike solar at that time, “energy storage has so many values and is so versatile that it has to prove its capabilities in each use case,” Kann said.

If the potential of energy storage is to be realized, all three agreed, more supportive policies and market reforms will be key to ensuring the battery bubble does not pop.

Storage growth by the numbers

Data from the residential and non-residential behind-the-meter (BTM) energy storage sectors and from the utility-scale in-front-of-the-meter (FTM) sector underscore market’s nascence, according to Kann.

For the residential storage sector, the buildout moved between 2.5 MWh to 4.0 MWh per quarter because “for most residential customers, there is not an economic case [for battery storage],” Kann said.

California and Hawaii account for more than half of all residential battery storage capacity because of high residential solar penetrations and relatively high electricity rates, but other states lag behind. And in non-residential storage capacity, California accounts for 86%, with a buildout of 15 MWh to 30 MWh per quarter, Kann said.

Experience there could make the case for energy storage in other markets, he added. As commercial and industrial customers face higher TOU rates and demand charges, they could use battery storage to stow excess energy from rooftop solar arrays and off-peak, low priced generation for later use.

Utility-scale storage deployment has so far been almost entirely dependent on the wholesale market opportunity offered in the PJM region and on California’s mandate, Kann said. That is why 42% of total FTM deployments are in the PJM region, and 36% in California.

“This kind of deployment to a single or a few locations based on a particular set of conditions is indicative of a nascent market,” Kann said.

New market opportunities: Aliso Canyon and FERC action

Two key developments in 2016 hold promise for moving storage out of its early deployment phase and toward widespread, grid-scale adoption.

While the gas leak at Southern California Gas’s Aliso Canyon storage facility prompted concerns over shortages and environmental impacts, it also opened a path to more energy storage procurement.

Potential shortages in natural gas supply could hurt the SoCal Gas’ ability to meet demand from local power plants. But the CPUC’s decision to fast-track energy storage deployment to forestall any demand shortages played a part in boosting the market there.

By early 2017, Southern California Edison and San Diego Gas and Electric will have a combined 84.5 MW of storage online to help fill that gap.

"It is hard to imagine any other resource could be brought into service in the mere eight months since the state’s agencies called on the utilities and the storage providers," Kann said. “And when the storage is online and shows it can fulfill its promise, that will be proof of concept.”

But Aliso Canyon is “a specific and unusual instance of an emergency where there is a mandate and utility procurements in the works and developers already working on originating assets,” Kann said.

To boost the future of energy storage “more places with the right supportive mechanisms,” will be necessary, he said.

State policy changes have already had some impact. Almost all rate changes on rooftop solar users—with the exception of fixed charges—have boosted the value proposition of adding storage. Some states are copying California’s example with mandates, incentives, and grid modernization planning. On the other hand, utilities are initiating pilots to test the grid services potential of storage.

But a recent effort by the Federal Energy Regulatory Commission to take a look at energy storage in wholesale power markets could dwarf all those efforts, Kann said. “It may be the biggest thing for energy storage in years.”

The FERC’s Notice of Proposed Rulemaking (NOPR) on energy storage requires regional system operators to develop rules guiding storage participation in their wholesale power markets. Storage historically has not owned a significant share of those markets, Kann said, but

The NOPR requires the regional system operators that serve 70% of U.S. electricity customers to develop rules governing the participation of storage in their wholesale power markets. Clarifying the rules and regulators could boost the economic viability of the resource, Kann said.

The rulemaking also specifies that system operators must make storage eligible for whatever capacity, energy, and ancillary services markets it can serve. Grid operators must also institute appropriate bidding parameters and a size requirement that makes it possible for smaller systems to compete as well.

If storage providers won just 1% of the bids in the capacity markets, the current installed storage capacity would be “be five times the current cumulative installed capacity of U.S. energy storage,” Kann said.

Tesla sees opportunity behind the meter

From Tesla’s point of view, the potential for growth has never been greater, especially since its purchase of sister company SolarCity, the nation’s leading rooftop solar installer.

By merging forces with SolarCity, Tesla is poised to become more than just a battery storage and car provider, officials said during the deal, by moving to an energy-as-a-service model. And since the deal, GTM Research reported that “Tesla expects recognized revenues from SolarCity in 2016 to increase from a total of $8.0 million to $44.0 million.”

By 2030, Tesla’s Jaramillo said the role of the role of energy storage in the electricity system will be across every sector, and include both BTM and FTM stationary applications and transportation electrification.

“A huge diversity of solutions will come to market because the solutions the competitive market is willing to compensate for will win out,” Jaramillo said. “Even Tesla, as big as our ambitions are, may not do all of those things. But the value streams available from storage will be enough of an incentive to drive solutions to the market.”

Whether or not the FERC proceeding leads to the kind of capacity market opportunities for storage, “capacity is always up for consideration,” Jaramillo said. “It is a fundamental feature of any market whether it is compensated directly or through PPAs.”

As the storage value proposition proves itself, the shift from third party financing from solar companies like SolarCity toward loans and direct sales will accelerate, driving customers toward DER opportunities, Jaramillo said. “We see a convergence around the home use of these technologies.”

Tesla’s vision of the future of the home storage market is linked with an understanding that ownership and operation of transmission and distribution is a natural monopoly, Jaramillo said.

The role of the vertically integrated utility may change, but a network operator will be necessary because “there will not be competitive wires running to people’s homes,” he said. “Network operators have a regulated monopoly function and that is not going away.”

This reflects recent assertions by Tesla CEO Elon Musk that utilities will continue to deliver up to two-thirds of consumers’ electricity despite the boom in distributed generation.

Tesla is addressing all the energy storage sizes and markets because “the entire electric industry has no inventory,” Jaramillo said.

The revolution in the energy storage market is similar to the one seen in fruit and vegetable industries, he said. When refrigeration and other forms of cold storage proliferated, it changed the way consumers bought and ate their fruit and vegetables. Once energy can be stored on the grid like apples at a store, a similar transformation could happen on the power grid.

“If there is value to be had at all those locations, providers should put it in all those locations and address that value,” he said.

The utility view from PG&E

As a California utility, PG&E is uniquely positioned to understand the the relationship between distributed energy resources and the delivery network.

The utility can lay claim to 25% of the nation’s solar capacity, 20% of the national electric vehicle charging stations and two of the earliest grid-scale battery storage projects in its territory. The utility’s 2 MW Vaca Dixon and 4 MW Yerba Buena utility-scale storage pilot projects were the first non-generating resources bid into the California Independent System Operator’s market, Malnight said. Those projects initiated a discussion over market rules for resources that can be both load and supply.

Malnight agreed with Jaramillo that the grid operating system isn’t going away anytime soon, and is necessary to the smooth integration of DERs.

“The utility plans and operates the system and those are vital services,” he said, but it’s not yet clear how to compensate the utility for those services.

The distribution system was designed for one-way power flows, but now is dealing with an explosion of BTM resources that demand a deeper understanding of customer behavior

To underline those efforts, PG&E is developing a major pilot involving residential solar with smart inverters and storage. It will be “an exciting opportunity” to add to the utility’s understanding of customer acquisition and DER,” Malnight said, as well as offer insight into how solar-plus-storage projects can defer investments in the utility’s distribution system, a key argument made by solar and storage advocates.

“We will be able to explore what DER is delivering to the grid and how we can control it and how we make sure it is there when we need it.”

But finding the right rate structure to support DER usage is one of the biggest hurdles in the utility’s way. Malnight said the “the current rate structure has to and will change.”

Right now, two competing priorities are informing how regulators are looking at rates: the utility’s cost structure and protecting ratepayers from costly investments and price volatility.

The CPUC’s decision to introduce time-of-use rates in its revised net metering policy in 2015 was a step in the right direction, Malnight said. “It moves us closer to rates that look more like our cost structure.”

Beyond TOU rates, Malnight said “charging customers solely by the kWh delivered is not going to work in the future because the value customers get from those grid-delivered kWh differs,” Malnight said. “I don’t know what the right rates will be. We have to collectively figure that out.”

Like other regulated utilities, PG&E is compensated on the basis of its capital investments, Malnight said. But “our compensation is really for the planning that went into deciding they were the right investments and for operating the assets. That's why the compensation model has to change. There are a lot of options on the table and we need to work together to figure it out.”

For instance, utility-scale storage does not have to be located with renewables, though proximity offers an enhanced opportunity for joint control, he said. “Integrating intermittent renewables and storage, whether on the wholesale grid or the customer side, can effectively firm and shape power for both the wholesale and distribution sides.”

An example of this can be seen in PG&E’s controversial landmark decision to replace the 2,200 MW baseload generation from its Diablo Canyon nuclear facility with emissions-free resources. That decision will require a significant commitment to energy storage, Malnight said.

The utility plans to procure energy efficiency first to replace the lost generation from Diablo Canyon, and then plans to follow with renewables.

“Storage will likely be needed to help integrate those resources,” he said. How those procurement will take place will hinge on cooperation with the state’s energy regulators and stakeholders.

The utility is “technology agnostic,” Malnight said. “Lithium-ion batteries have a cost advantage right now but different technologies offer different values. There is not likely to be a battery storage silver bullet. If our approach is that one technology will always win, we run the risk of missing different values that different technologies might offer. I want them all to win.”

Big questions and uncertainties still linger

As system conditions change while California moves toward 50% renewables in 2030, the utility has to be measured in deploying storage, Malnight said. “How much prices will fall is uncertain, but it is likely they will drop as storage scales up. We want to be able to take advantage of those lower prices for our customers instead of going all in today.”

On the flip side, Tesla see the role of network operators as a significant uncertainty. Providers may be limited to providing a distribution system platform or allowed to compete in the market with private sector providers on new hardware and services, Jaramillo said. “Residential products will participate but the market will be much broader and a rate mechanism may be necessary to keep the playing field level."

Aligning with these concerns, Kann cautioned that the sector still has a long way to go to address uncertainties.

"Is there an energy storage bubble about to burst, leading to a crash and a consolidation before growth can resume?" he asked. “Or will the technical and financial regulatory issues be resolved, allowing the market to scale? Can we get this market built to the point where the bubble does not pop?”