What's next in the energy storage boom, and what utilities need to know
Where is storage growing, where will it grow next, and what does it all mean for the utility industry?
Elon Musk showed the world earlier this week that there is no sexier technology in the power sector today than energy storage. The Tesla CEO and SolarCity chairman hinted at the unveiling of a new home battery product in a pair of tweets on Monday, sending the Twittersphere into an absolute conniption and Tesla share prices soaring.
But it's not all internet hype. There’s real buzz in the industry for storage. In Utility Dive’s survey of over 400 electric utility executives earlier this year, more than half of them said their company should be investing more in storage, ranking it above other emerging technologies such as efficiency, rooftop solar, and microgrids. Cost-effective energy storage is widely seen as the “holy grail” for reaching higher penetrations of renewables and distributed energy resources — it’s the one emerging technology that enables the rest.
Enthusiasm for storage is reflected in the industry’s growth numbers. The U.S. energy storage market last year grew 40% over 2013, according to a new study from GTM Research and the Energy Storage Association. And if their report is any indication, those numbers are only going to accelerate in the years to come.
“[2014 was] one of the best years we’ve seen in the U.S. market we’ve seen in a while,” GTM’s Ravi Manghani, who authored the report, told Utility Dive. Throughout the year, he said, nearly 62 MW of storage went online.
Manghani said that 2014 almost surpassed 2011 in terms of MW of storage deployed. 2011 remains the best year ever for storage, due to an infusion of funding from the American Recovery and Reinvestment Act, commonly known as the stimulus package.
Manghani says that “speaks a lot to where the industry is heading,” since no nationwide spending program was in place to boost storage last year — and there’s plenty of room to grow.
“The upside to that is that we’ve only started to see a few of these markets pop up given the right sort of economics based on demand charge reduction applications in California or the ancillary services market in PJM,” Manghani said.
GTM estimates that in 2015 more than 220 MW of storage will come online in the U.S. — a big leap from the 61.9 MW last year, or the 44.2 MW in 2013. But the growth likely won't stop there. The team projects that after “a short lull in utility projects in 2016,” storage growth will kick up again, resulting in more than 800 MW of installations in 2019.
“We expect more markets to open up as utilities, system operators, regulators and different program administrators recognize the value of storage,” Manghani said, “and that’s the belief behind the forecast we have for the market this year and in fact for the next four years going forward.”
California, the state-level storage leader
While the energy storage market is growing steadily, that growth has been mostly confined to a few booming markets. And California is the clear national leader.
“In California there are a couple of different levels that storage is functioning at today,” Manghani said. “For behind the meter applications, it's largely been driven by the Self Generation Incentive Program that in 2015 provides an incentive of up to $1.46 per watt of installed capacity, or up to 60% of the total project cost.”
"It provides a substantial incentive for an end customer to install storage,” he added.
But even if those state level incentives in California were suddenly to disappear, Manghani believes that storage could still be economically attractive for a number of non-residential customers. Because many commercial and industrial customers are subject to demand charges that cost them more during peak hours, many companies see an opportunity in using storage to reduce demand charge.
“Even without these incentives, among specific customer types, storage could make sense,” he said. “We’re looking at specifically demand charge reduction as the key end customer use case that storage is economical for.”
But there’s more to California’s storage market than behind-the-meter storage, Manghani explained. California's groundbreaking energy storage mandate, which requires the state’s investor-owned utilities to procure 1,325 MW of storage by 2020, is also driving investment in the technology.
“Although not a lot of systems as of today are deployed under that mandate, it definitely started the impetus for more storage projects,” Manghani said, “and we’ve already seen tens of MW of storage be awarded, which will be deployed in the next four to five years.”
Last year, Southern California Edison made a big storage buy under that mandate. While it was only required to purchase 50 MW of storage at the time, the utility announced it it was buying 250 MW, aiming to ensure grid reliability after the retirements of the controversial San Onofre nuclear facility and a few older gas plants.
That big storage buy points to a larger trend for storage not to just be used in wholesale markets, but also in capacity-based applications “as a means to defer building larger peaker plants or other forms of fossil-based plants,” Manghani said.
PJM, the leading wholesale market for storage
The second market that GTM highlighted for leadership in storage isn’t a state market at all, but rather a regional one: the PJM Interconnection. The independent system operator, which serves the near Midwest and Mid-Atlantic states, “has so far been the leader in that RTO-type of market” for utility-scale storage. Of the 62 MW of storage deployed last year, about two-thirds of it was located in the PJM's territory, Manghani said.
The key to PJM’s success is the structure of its markets.
“What makes PJM different from some of the other RTOs and ISOs is that they have a fast regulation market in place which incentivizes fast and accurate regulation services, which are a type of ancillary service,” Manghani said.
While most other RTOs and ISOs were ordered to allow storage to participate in ancillary services markets and explore what benefits it can provide to grid operations by FERC Order 755, PJM is ahead of the game. But it’s not because they started first.
“All the other RTOs and ISOs are at different stages of implementing FERC 755 … some of the others started before PJM, but the level of competition that most of them have provided is not sufficient for storage to make sense economically,” Manghani said.
“PJM is not the only RTO that has established a pay for performance premium for storage,” he added, “but the premium itself is definitely higher than the other RTOs.”
New York: The Empire State strikes back
California and PJM may have taken top honors in this year’s storage report, but a new market is emerging fast in New York. Proactive utility programs to deploy storage along with the transformative efforts to reshape the distribution system under the REV docket are making the Empire State a huge growth market for storage.
“In New York there are a couple of different activities happening in parallel,” Manghani said. “One of them already underway is the Con Edison program to basically make up for its loss of the Indian Point nuclear plant, and to defer investments in a couple of their substations within their New York territory.”
Like SCE’s large storage procurement, Manghani says ConEd’s plan to use storage and other demand side management strategies to defer billion dollar investments in substations and other grid upgrades shows energy storage's potential for capacity deployments.
ConEd's new strategy gets its origins from how New York utility regulators are fundamentally rethinking the way the distribution system operates. In February, the Public Service Commission issued a groundbreaking order on the REV docket designating utilities as the distributed system platform providers for New York's grid of the future — a vision wherein utilities will play the role of air traffic controllers on the distribution grid, coordinating the integration of and the marketplace for distributed energy resources.
The REV initiative is still in its early stages, Manghani said, but it is clear thatstorage has a major role to play. The exact details still need to be worked out, he said, but we can expect to see more storage deployments under the initiative sooner than many might expect.
“We’re probably looking at 12-24 months until we start to see systems start to be deployed under that initiative,” Manghani predicted.
Energy storage and its impact on the utility industry's solar challenges
While the most storage growth by far has taken place in the top three markets, expect to see big gains in places like Arizona and Hawaii as well.
“Arizona is sort of disparate in a lot of ways, similar to Hawaii,” Manghani said.
In both those states, utilities are attempting to reduce the rates at which they compensate rooftop solar owners for the electricity they put back onto the grid. As Utility Dive has reported, Hawaiian Electric proposed last year to end retail net metering and reduce kWh payments to solar customers, saying it needed to distribute grid costs more equitably. More recently, Arizona municipal utility Salt River Project instituted a higher demand charge for solar customers based on their peak energy usage each month.
Manghani said those changes, while reviled by the solar industry, could actually help spur solar-plus-storage growth in the states.
“Any kind of changes in net energy metering reforms can, under certain conditions, make storage attractive as a means to store the excess solar generation for a customer and then using it peak hours when solar is not available,” he said.
The keys to this unintentional storage incentive are either an increase in demand charges or a reduction in the rate that solar customers are compensated for their excess generation. When those changes are instituted, customers are able to save money by storing their self-generated solar power and using it during a time when the price of grid-supplied electricity is high. Over time, those savings can wind up being significant enough to significantly enhance storage’s value proposition, especially as technology prices keep falling.
When a utility institutes a demand charge on residential customers, Manghani said, their customer data begins to look a lot like the data for commercial and industrial consumers. Just like in California — where Manghani said many non-residential customers would find storage economic without subsidies —residential customers that are exposed to new demand charges have a greater economic incentive to invest in behind-the-meter batteries.
“We’ve talked about demand charge reduction as a use case for commercial customers that’s already looking attractive for a good segment of end customers,” Manghani said.
This unintended consequence could take the sting out of the utility industry's efforts to decrease payments to solar customers, but the new value proposition doesn’t hold in all cases. Where utilities simply impose higher fixed charges on solar customers — as Arizona Public Service and We Energies have done — storage will not see the same boost. Because fixed charges are applied to a customer’s bill each month regardless of consumption, there is no extra value to be gained from storing solar now than before the fixed charge was instituted.
“Some fixed charges are going to be more per meter or per customer, in which case storage is not going to make economic sense,” Manghani said. “However, if those charges are, say, on a customer’s demand or under those [net metering] instances, you could see storage provide benefits to the end customer.”
The big opportunity for utilities
The next few years will bear witness to utilities across the country attempting to make bigger and bigger storage investments, Manghani said. If they don’t do it quickly, they run the risk of third party vendors taking control of the market.
But for many utilities, that means proving to state regulators that storage is a good investment. That can be a problem, Manghani said, because coming up with a reliable ROI number for a storage project is difficult. That’s because storage can provide so many disparate benefits to the grid — from voltage regulation to load smoothing and resiliency.
“You have to look at all the benefits storage can provide both from a reliability standpoint and if there are any wholesale market activities in which storage can participate,” Manghani said.
Utilities should “look for a way to stack these benefits together and allow a single entity or a group of entities to monetize those benefits and get paid for them,” he added.
“Once you get to a point where such rules and regulations exist and such market opportunities exist,” Manghani said, “you will see the right kind of players jumping in and come in with the right business models to own and operate these systems, and as a result provide not just wholesale market services, but reliability services such as resiliency."
Manghani pointed to Texas as the final market to watch for storage growth, mostly due to one company — Oncor. The utility has been lobbying the state legislature for months to alter Texas law so it can invest in 3-5 GW of grid-scale storage by 2018. Currently, state law prohibits transmission and distribution utilities from owning resources such as storage. If that changes, it could unlock a model for utilities across the nation looking into storage. However, it doesn't appear it will happen soon. The Dallas Business Journal reports that with the end of the Texas legislative session fast approaching, no lawmaker has filed a bill to change distribution system rules, perhaps due to opposition from generation companies.
The discussion over utility ownership of storage in Texas is an example of the frequent turf battles occurring in the last mile of the distribution system between utilities and third parties. As states explore what the utility role will be in the grid of the future, designating clear rules of the road for ownership of distributed energy resources will be crucial.
All in all, utilities should be excited about the opportunities that storage offers, Manghani said. Most often, the benefits of storage are “more tied to the utility side of the meter than to the customer.”
“If the utilities can understand the use cases that they can benefit from ... either from rate basing them or coming up with more deregulated business models, it’s more of an opportunity than a risk in my opinion,” he said.
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