A version of this article was published on Greentech Media on January 24, 2019.
By Eric Gimon
Energy storage is surging across America. The U.S. Energy Storage Monitor Q4 2018 report estimates 338 megawatts (MWs) of installations in 2018, growing to 3.9 gigawatts (GWs) by 2023, much of it “front-of-the-meter” utility-scale projects.
However, this exponential growth has mainly been driven by state mandates and regulatory actions (especially in California) or limited to vertically integrated utilities operating outside of organized power markets, which serve two-thirds of all U.S. electricity consumers. Despite the value storage can provide the grid, it has not found matching success in wholesale markets.
The reason behind this mismatch is best captured in two words: rules and revenue. Wholesale market rules are organized around legacy assets, restricting storage from selling all its potential services if owners were able to operate in the most advantageous ways. These rules in turn limit storage’s wholesale revenue streams.
Last February, recognizing these barriers, the Federal Energy Regulatory Commission (FERC) issued Order 841 to stimulate access to U.S. wholesale markets. At the end of 2018, FERC-regulated independent system operators (ISO) responded by submitting their implementation plans.
The Energy Storage Association (ESA) provided a helpful overview of these proposals (see chart), and further filtering comments by affects upon possible revenue streams for storage provides additional insight.
Source: Estimation by Customized Energy Solutions, Ltd.
*Topic letters and numbers correspond to layout of Order 841
**Green: Likely compliant; Yellow: Potentially non-compliant; Red: Non-compliant
Storage can generate revenue in America’s organized power markets three ways: platforms, products, and pay-days. Because different projects tap these potential revenue streams in different ways, implementation plans for Order 841 will affect them quite differently, so let’s follow this taxonomy.
Platforms: The Best Laid Plans…
ISOs conduct planning processes that identify opportunities for new transmission to improve reliability or market efficiency, and storage is increasingly being considered as a reliability asset as a lower-cost, non-transmission alternative to boost reliability.
Here’s an example: A relatively isolated area on the grid must plan for losing a transmission line or local generator during peak demand. Rather than adding new transmission or local generation, building a storage project can carry a local grid through an emergency. If the economics add up, the project can then be built and paid on a cost-of-service basis financed through regulator-approved transmission charges.
Storage in this example plays the same role as transmission for so-called “reliability transmission expansion,” but it can also play the role of “economic transmission” – transmission built to move surplus energy to constrained areas to create benefits (reduced prices) for market buyers and sellers. This was part of the vision of Order 1000, which required regional transmission operators (RTOs) to consider “non-transmission alternatives” as part of their planning process. But to date, only one economic storage-as-transmission project exists within U.S. ISOs, located near Baltimore on the PJM grid.
ISOs have hesitated to fund such projects because while “reliability” storage is tied to a definite risk of grid emergency which determines how it will be used, “economic” storage requires instructions from the ISO about when to buy and sell power. ISOs worry this could challenge their market independence since how they dispatch storage invariably affects prices, which could make them look like self-dealing market participants.
However, ISOs already regulate power flow over transmission, which certainly affects power prices. When ISOs propose a new transmission project to relieve congestion in an area of the grid with high demand (and thus high prices), local generators are first in line to complain about lost revenue.
What preserves ISO independence in these cases is a combination of transparent cost-benefit-analysis and security constrained economic dispatch with financial transmission rights – a standard methodology for fairly moving power across transmission lines and distributing revenue from arbitraging local price differences. Markets can dispatch storage in similar ways, according to the transparent optimization, and assign financial storage rights to whomever paid for the storage. Like transmission, storage would essentially become “open access,” for the benefit of consumers.
Even as storage provides similar services, it must consider benefits over transmission like ease of siting compared to transmission siting and permitting, which can take years to resolve, depending on the proposal’s complexity. For example, it only took Tesla six months to construct and put into operation a 100 MW storage facility in South Australia providing reliability services comparable to transmission upgrades and saving customers $40 million in one year.
Storage-as-a-Transmission-Asset (SATA) is very much in its infancy, with almost all the focus on its possible role as a reliability asset. ISOs seem to have had very little to say on how Order 841 will shape this potential revenue stream – but this is a space to watch.
Products: Fee for Services
While ISOs are uncomfortable paying for storage services through transmission access charges that passively incorporate storage into the grid, some have been receptive to storage competing to provide fixed services like fast frequency response, capacity, or regulation that projects can provide on a technology-neutral basis. But technological neutrality may not be achievable in many cases where services were defined before batteries and other clean technologies like renewables changed the game. Order 841 was meant to push open this door, but implementation plans still leave much to be desired.
Source: Lazard Levelized Cost of Storage 4.0 (2018) https://www.lazard.com/media/450774/lazards-levelized-cost-of-storage-version-40-vfinal.pdf
Theoretically, fitting storage into technology-neutral products should be simple. But storage resources are energy-limited (they can’t just convert fuel to electricity forever), they must be charged and take more energy to charge then they provide back, and they may be entirely driven by power electronics (no spinning inertia).
These differences mean existing market product definitions are often ill-suited to include storage. And while most incumbent participants often provide ancillary services for just a fraction of their revenues, storage projects dedicated to a single service (such as regulation) could have their entire business model upended by simple rule changes.
Storage resource attributes like how fast they can change their output, their ability to reduce air pollution, or the quick and modular pace at which they can be deployed, are not always valued in markets. These attributes provide grid benefits but need revised power market rules to be properly valued. The standard equivalence for utilities between batteries and natural gas peakers seems to require a 1:4 power ratio, i.e. a 1 MW/4 megawatt-hour (MWh) battery.
Impact of 4-hour storage dispatch on net load in California on the peak demand.
Source: National renewable energy Laboratory, 2018. https://www.nrel.gov/docs/fy18osti/70905.pdf
However, shoehorning batteries into definitions based on other technologies is not necessarily economically efficient – some peak needs may last longer, some may be more sporadic, and others will change over time with the economics of generation sources. A battery’s highest value application may involve a portfolio including different power ratios.
Incremental peak demand reduction credit as a function of storage capacity in California using 2011 data.
Source: National Renewable Energy Laboratory, 2018. https://www.nrel.gov/docs/fy18osti/70905.pdf.
Collecting storage revenue by providing grid-needs through products aspiring for technology neutrality will always depend on the fine print. But shaping these products will be an uphill battle without proactive support from regulators and market operators. As a new competitive entrant to most markets, storage – especially battery storage – is not always in the best position to make sure rules value them at their best.
Consider PJM’s approach to incorporating storage into its capacity performance model. They propose that storage systems only qualify for capacity payments if they can provide ten hours of storage, a duration that severely disadvantages battery storage economics, even though it may provide much-needed capacity over shorter timescales.
Pay-days: Profiteer or Just an Independent Businessman?
One way for storage resources to avoid being shoehorned into the wrong glass slipper is to compete directly in energy markets. What could be simpler than arbitrage: buy low, sell high?
Unfortunately, today’s markets just don’t provide enough revenue this way. Consider daily wholesale electricity price differentials in two ISOs with the most market spikes, California’s CAISO and Texas’ ERCOT, where crudely estimated annual revenues from buying low and selling high each day (with no roundtrip losses) come out to $10-20 per kilowatt-hour (kWh) of storage capacity per year, not quite enough to be in the money yet but close to some of the prices we see coming out of vertical utilities like NV Energy’s recent announcement to add 100 MW of battery storage.
The closer to a real-time market storage operates in, and the higher the power ratio, the more revenue is available from arbitrage. For example, a battery storage unit with a 4:1 power ratio (4MW to 1 MWh) and 20 percent round-trip losses operating in the 2017 Houston load-zone real-time market could make as much as $57/kWh-year. This system would likely cost $300-400/kWh plus some extra costs associated to the high power ratio, making it a possibly attractive investment, especially with high prices expected across ERCOT in coming summers.
This contrasts with other ISOs with lower price differentials, and thus highlights the efficiency with which energy-only power markets can point to where investments have the most value.
Even if energy arbitrage revenues become sufficient to support storage investments, today’s markets still maintain some barriers. In ESA’s analysis of Order 841 compliance plans for participation models, bidding parameters, and state-of-charge-management, almost all the ISOs failed to fully comply.
Today’s Energy Storage Opportunity, Tomorrow’s Energy System Disruptor
Storage has jumped from tomorrow’s clean technology to one of today’s regulatory agenda drivers, but the industry’s true potential has yet to be tapped, especially as it covers multiple value streams.
Storage projects are innately well-suited to access multiple value streams. A clever storage operator in ERCOT will switch between bidding into ancillary regulation markets one day to arbitraging energy price in another day for maximum revenue potential. But Order 841 compliance proposals can make this type of switching problematic.
Like many leading ISOs, ISO-NE co-optimizes energy and ancillary markets, obviating the need for participating resources to figure which market they should bid in for best revenues. Theoretically, this arrangement should help storage economics, but instead ISO-NE rules for ancillary markets force resources to “de-rate” (i.e. pretend they can only run at a lower power output) whenever they are bid in the energy market. This prevents a battery from squeezing out as much output as possible during system peak because it must maintain the ability to provide a full hour of output on the back side of that peak (when it is less necessary) to satisfy ancillary market rules.
These type of issues illustrate how disruptive storage can be to existing market paradigms. As more and more storage comes online, ISOs will need to evolve through new rules and market structures to accommodate the technology’s potential – and make a better showing of implementing FERC’s Order 841 – in order to maximize benefits for today’s electricity consumers.