Hang around any debate about clean energy and you’re bound to hear one question: What do you do when the sun isn’t shining and the wind isn’t blowing?
The answer, at least in theory, is straightforward: energy storage.
Storage can be thought of as the third leg of the stool Virginia will use to reach its clean energy goals.
It’s what Virginia Advanced Energy Economy Executive Director Harry Godfrey calls “the Swiss army knife of the energy space,” a way to fill gaps by more intermittent renewable sources while also balancing out the push and pull of energy supply and demand that bedevils every electric grid.
Every plan crafted by utilities for transitioning from fossil fuels to renewables relies on energy storage. But this keystone is also today the weakest link of most clean energy portfolios. Utilities and states see storage as a powerful way to balance out the intermittency of renewables like wind and solar; California, for example, is hoping storage coupled with wind and solar will help replace natural gas and coal plants now facing retirement.
Batteries, though, remain hampered by limitations in how much energy they can store and how long it can be pumped onto the grid. Standard batteries today have a duration of four hours; extending that time span on a broad scale will take further research and investment. Nor is the technology very widespread yet: Recent estimates from the U.S. Energy Information Administration put battery capacity at under 1,000 megawatts.
“If you look at all of the operational grid-scale batteries throughout the country, they store collectively less energy than our nuclear facilities in Virginia produce in just a couple of hours,” said Dominion Vice President of Public Policy and State Affairs Katharine Bond.
Still, the technology may be approaching a turning point: global information and analytics firm IHS Markit in a white paper earlier this year forecast that “battery storage will continue to grow rapidly, with all trends pointing to a maturing battery industry that is well beyond the demonstration phase.”
Energy storage “is the single most important technology and policy issue facing energy right now,” said Bill Murray, vice president of corporate affairs and communications at Dominion Energy. “Storage has gotten better, no question about it. We need it to get geometrically better.”
Dominion already has several efforts underway. In February 2020, as the Virginia Clean Economy Act was still being hammered out at the General Assembly, regulators approved four Dominion pilots that aim to examine issues such as how batteries can be coupled with solar and how they can be used to avoid costly upgrades the utility would otherwise have to make to substations and distribution wires. The company has also been experimenting with electric school bus batteries as a potential storage solution.
Appalachian Power’s interest in the technology has ramped up as well. In October, the utility announced a partnership with Dominion and economic development group InvestSWVA to advance energy storage development in the region.
“Much of Appalachian Power’s service territory in Virginia is rural and storage could aid service reliability for customers,” wrote spokesperson Teresa Hall in an email. “The area is also well suited for overall storage development. Land is available and costs are reasonable, but developing Southwestern Virginia into a hub for storage has to be done responsibly.”
How extensive the southwestern partnership will be remains to be seen. The VCEA set an energy storage target for Virginia of 3,100 megawatts, putting it among the most aggressive states in the U.S. when it comes to deploying the technology. As with most other VCEA targets, the bulk of that development will fall to Dominion, which is responsible for proposing 2,700 megawatts of storage compared to Appalachian’s 400 megawatts.
For both utilities, there’s more than one persuasive argument for investing in storage. Like solar and wind, storage can act as a power generator that can add electricity to the grid when demand rises. But batteries in particular “can sort of play in all spaces,” said Southern Environmental Law Center attorney Will Cleveland. Unlike other renewables, storage can also play critical roles in a utility’s distribution and transmission systems — the complex and costly network of wires, substations and technology that ensure the grid functions smoothly and efficiently.
“Storage can be used to improve distribution system reliability and also serve as a non-wires alternative for capacity upgrades,” said Hall.
Other states have already reported savings with storage. The New York Public Service Commission reported earlier this year that electric utility Con Edison had successfully used a two megawatt battery as part of an effort to avoid paying $1.2 billion to upgrade a substation.
Exactly how far storage solutions might stretch isn’t yet clear. “You want to use a battery every hour that it’s available when it’s not charging,” said Cleveland. “You want to use it in whatever the highest economic value is at any hour.”
Determining that value will be a tricky proposition, though — one that’s likely to take years. Much of the responsibility will fall to a new Energy Storage Task Force that a 2020 law ordered the State Corporation Commission to create “to evaluate and analyze the regulatory, market and local barriers to the deployment” of storage solutions. That body hasn’t yet been formed, and its final report isn’t due until October 2021.
“I don’t know that any state has fully gotten up to speed on those things,” said Cleveland, “but certainly Virginia has not.”
Does pumped storage count as storage?
First on the list of unresolved storage issues is what exactly falls under that umbrella. Everyone agrees that batteries do, and it’s advancements in that technology that are largely driving growth in storage around the world. More controversial is pumped hydropower, which today is the most common type of storage used worldwide, accounting for more than nine-tenths of all storage in the U.S..
A form of power generation that would have been familiar to our forebears, pumped storage systems create electricity when demand is high by channeling water from one reservoir into another, turning turbines as it flows. As demand drops, the water is then pumped back into the original reservoir. Virginia’s utilities have been using it for decades. Dominion touts its 3,000 megawatt Bath County Pumped Storage Station as the largest battery in the world, and Appalachian Power has operated its 636 megawatt Smith Mountain Lake facility since the 1960s.
While tried and true, these systems aren’t accepted by all clean energy advocates as part of the path forward. Pumped storage is expensive to build and has a large footprint; furthermore, it requires external electricity to operate, so whether or not it’s “renewable” depends on what resources are supporting it.
The Virginia Clean Economy Act’s wording also doesn’t make it clear whether or not pumped storage is part of the renewable energy future lawmakers are envisioning. The law explicitly states that “renewable energy” doesn’t include “electricity generated from pumped storage,” and it excludes energy from pumped storage from being counted toward utilities’ yearly targets for how much of their energy must come from renewables, a benchmark called the renewable portfolio standard.
Crucially, though, the VCEA doesn’t explicitly exempt pumped storage from being counted toward the 2,700 and 400 megawatt storage development targets Dominion and Appalachian Power must meet by the end of 2035. Further complicating the picture is a 2017 law passed by the General Assembly nearly unanimously that declared one or more pumped hydro facilities in Virginia’s coalfield region that at least partially rely on renewables to be in the public interest.
Dominion has already signaled it sees pumped hydro as part of its energy storage approach. Among the new capital projects the company listed in its 2020 Integrated Resource Plan, the first long-range plan to be filed in the wake of the VCEA, is a 300 megawatt pumped storage project in Tazewell — outside the utility’s territory — that would cost $2.9 billion. In 2017, three years before the VCEA’s passage, plans filed by the company with federal regulators indicated interest in a much larger facility capable of generating 870 megawatts.
“In the energy storage space, we’ve got to take an all-of-the-above approach,” Bond told the Mercury this fall. “If it’s proven technology and it’s cost effective, we should deploy it as part of this clean energy transition and a carbon-free grid.”
Not everyone agrees. Among renewable energy advocates, “there’s very much a divide” as to whether pumped storage should be seen as a clean energy solution or simply an economic development driver, said Cliona Robb, an energy attorney with Thompson McMullan who also chairs Virginia’s Solar Energy Development and Energy Storage Authority.
One such opponent is Arlington-based utility-scale storage developer Delorean Power, which has strongly argued against the inclusion of pumped hydro on the grounds that it would “largely undermine” the VCEA’s “intent of creating storage targets in the first place.”
Pumped hydro “is a proven, legacy technology and offers very little benefits for grid modernization, economic development and energy storage innovation in Virginia,” the company wrote in a State Corporation Commission filing this summer.
Absent direction from the General Assembly, the decision seems likely to fall to the SCC — as will any approvals of Dominion’s Tazewell pumped storage facility that the utility submits to regulators.
The VCEA “is an important public policy, but it’s also going to require significant investments and significant costs,” energy attorney Will Reisinger told regulators this October as part of a case against Dominion’s Tazewell plans. “That heightens the importance of the planning process, and it makes it more critical to ensure that Dominion only invests in reasonable projects that are required to comply with the Clean Economy Act or are required for the company to provide quality and reliable service.”
How soon and how fast
What qualifies as energy storage isn’t the only question facing regulators this fall. Also at issue is how quickly that storage ought to be rolled out.
While the VCEA mandated the development of 3.1 gigawatts of storage by the beginning of 2035, it left the nuts and bolts of how that would occur to the State Corporation Commission, which was charged with crafting regulations for energy storage deployment and setting interim targets leading up to the Jan. 1, 2035 deadline.
“These were the kind of things that we didn’t really have the bandwidth — I don’t think anyone had the bandwidth — to nail down,” said David Murray, executive director of the Maryland-Delaware-D.C.- Virginia chapter of the Solar Energy Industries Association.
As they did with the shared solar rules, regulators have largely deferred to Dominion and Appalachian Power. Draft regulations hewed closely to the utilities’ proposal, including a set of interim targets that would delay the rollout of most energy storage until 2030. Dominion and Appalachian have justified the “back-loading” of targets on the grounds that waiting to fully deploy storage until closer to the 2035 deadline will let Virginia take advantage of technological advancements made elsewhere at a cheaper price.
“We are expecting more renewables (solar and wind) to be connected to our grid towards the end of the 15-year period, creating the need for more storage to balance generation output,” wrote Dominion spokesperson Rayhan Daudani in an email. “We are also expecting energy storage cost reductions and technology improvements to materialize in the latter half of the 2020s and 2030s, which will drive value and additional benefits for ratepayers and the power grid.”
Clean energy advocates and the storage industry are pushing for more aggressive targets, however. A group including MDV-SEIA and the Energy Storage Association complained that delays could cause Virginia to miss out on early cost savings and could “lock in other investments that may reduce the utility of storage in the future.”
Delorean meanwhile argued for a more aggressive timeline on economic grounds, citing the ongoing financial constrictions due to the pandemic: “The Virginia legislature wanted to do something big for energy storage, and this was clearly articulated in the VCEA,” the company wrote in a commission filing. “The regulations adopted by the SCC need to send that same business-friendly message so that companies across the supply chain migrate to Virginia and the clean-energy industry can continue growing in earnest.”
How big a role will non-utilities play?
In Virginia, which has prized its identity as the U.S.’ top state for business, friendliness toward a growing industry might seem a given. The electric grid is a different story, however. Since the state re-regulated its electricity markets and handed monopolies back to Dominion and Appalachian Power in 2007, the utilities have carefully guarded their territory. Lawmakers too have frequently been cautious in allowing third-party companies to enter state markets and affect the monopolies’ customer bases.
That could be changing. The last two big pieces of energy legislation to pass the General Assembly — the Grid Transformation and Security Act of 2018 and the VCEA of 2020 — have included mandatory carveouts for non-utility companies to take on certain capital projects. The State Corporation Commission has also increasingly shown favor toward utility proposals to buy power or other assets from non-utility developers in order to offload some of the financial risk that would otherwise be borne by Virginia residents and businesses. Among the VCEA carveouts was one requiring that 35 percent of the storage target be developed by third parties. (Another also carved out 35 percent of the solar and onshore wind goal.)
“When we drafted the bills that authorized these new programs, we envisioned policies and program rules that will unleash a competitive clean energy market that creates (a) maximum number of local jobs and attract(s) millions of dollars in investment to the commonwealth,” six Democratic lawmakers, including VCEA sponsors Sen. Jennifer McClellan and Del. Richard “Rip” Sullivan, wrote to the State Corporation Commission in an early November letter.
The letter, a four-page list of the legislators’ concerns with commission proposals for both energy storage and shared solar regulations, also issued a veiled rebuke of SCC’s approach: The bills, lawmakers asserted, “were intended to open competition for new entrants, and not simply make incremental changes that largely maintain the status quo.”
Of particular concern to many industry players are the permitting requirements regulators have proposed for non-utility companies to build storage. An early recommendation by SCC staff that would have required any project larger than 100 kilowatts to undergo a rigorous permitting process led by the commission provoked a strong backlash. The Virginia Department of Mines, Minerals and Energy said the low threshold imposed “onerous” requirements on a wide swath of projects, while the Southern Environmental Law Center labeled it “a transparent attempt to ensure non-utility storage is never built in Virginia.”
Dominion, for its part, said the 100 kilowatt threshold was reasonable and consistent with a threshold set by regional electric transmission organization PJM for projects to sell power into wholesale markets.
This November, commission staff conceded the 100 kilowatt threshold might be too low and bumped their recommendation up to one megawatt — still far lower than what many advocates sought. But they held tight to many of the permitting requirements, stating that while “certain aspects may be perceived as burdensome, they are intended to ensure that developers seeking to operate within the commonwealth will operate safely, will not negatively impact the reliability of the electric power system and will be ethically responsible in their interactions with Virginia consumers.”
That sense of caution is also evident elsewhere. The Rural Solar Development Coalition that convened last year in response to a flurry of solar applications in Southside and Tidewater Virginia is also beginning to eye storage as the “next wave” of the renewables transition, said Halifax County Administrator Scott Simpson.
“We want to be sure that our localities are prepared and understand what storage means, and if any of us were to be proposed a storage facility, what questions are there,” he said.