Three Ways Energy Storage Can Generate Revenue In America’s Organized Power Markets
Energy storage is surging across America. Total installed capacity passed 1,000 megawatt-hours (MWh) during a record-setting 2017, and the U.S. market is forecast to nearly double by adding more than 1,000 MWh new capacity in 2018 – adding as much capacity in one year as it did in the previous four.
However, this exponential growth has mainly been limited to vertically integrated utilities operating outside of the country’s organized power markets, which serve two-thirds of all U.S. electricity consumers. So how can energy storage plug into these markets?
In a word, revenue.
Energy storage can collect revenue in America’s organized power markets three ways: platforms, products, and pay-days . However, different projects will tap these potential revenue streams in different ways, and investors should seek nimble developers who can navigate a complex and evolving regulatory and market landscape.
In part two of this series, we’ll explore how storage will disrupt power markets as more and more capacity comes online, but first let’s cover the three ways it can tap the U.S. organized market opportunity.
Platforms: The Best Laid Plans…
Independent system operators (ISOs) go through a planning process where they identify opportunities for new transmission to improve reliability or market efficiency. Similarly, it’s normal to think about energy storage as a reliability asset, and it can become integrated 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 will then be built, and paid on a cost-of-service basis financed through transmissions charges.
If storage in this example plays the same role as transmission for so-called “reliability transmission expansion”, it should also enjoy an analog to “economic transmission” – transmission built to move surplus energy to constrained areas to create benefits for market buyers and sellers. But to date, only one such project exists within the U.S. independent system operators (ISOs), located near Baltimore on the PJM grid.
One reason ISOs have hesitated to fund such projects is that while “reliability” storage is tied to a definite risk of an emergency on the grid 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 the way they dispatch storage will invariably affect prices, and could make them look like self-dealing market participants.
However, ISOs already regulate power flow over transmission lines, which certainly affects power prices. When a new transmission project is proposed 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 this case is 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.
If or when markets start doing more multi-period dispatch, they can dispatch storage in the same way, according the transparent optimization, and assign financial storage rights to whomever pays the costs of economic storage.
Products: Fee for Services
While ISOs are uncomfortable paying for storage services through transmission access charges that passively incorporate storage into the grid, they have been receptive to storage competing to provide fixed services like fast frequency response, capacity, or regulation that projects can compete to provide on a “technology-neutral” basis. But keep in mind these services were defined by markets before batteries and other clean technologies like renewables changed the game.
Theoretically, fitting energy storage into these technology-neutral products should be simple. But storage resources are energy limited (they can’t just convert fuel to electricity ad infinitum), they must be charged, they 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 resources also have attributes that are not always valued in markets, 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. 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 megawatt (MW)/4 MWh battery, so you might expect that product definition.
However, shoehorning batteries this way is not necessarily economically efficient – some peak needs may last longer, some may be more sporadic, and a battery’s highest value application may involve a different power ratio.
Collecting storage revenue by providing grid-need products will always be dependent on the fine print. As a new competitive entrant to most market, storage – especially battery storage – is not always in the best position to make sure rules value them at their best.