Deployment of energy storage, especially batteries, will increase substantially in the next few years.
Three underlying trends in the energy markets will drive the growth. They are favorable federal and state regulations on energy storage, falling costs for batteries due to advances in technologies, and an improved ability by energy storage owners to tap into multiple revenue streams.
However, as with any novel technology, the array of opportunities for storage brings new types of risks. Project developers and investors need to understand the risks so that they can plan for contingencies and mitigate risks.
This article describes changes in the market that are driving deployment and improving the economics of storage. Part two of this article will identify unique risks for storage projects and how participants in such projects can mitigate the risks.
The storage market is poised for exponential growth, with analysts projecting an annual market of 2,600 MW by 2022, which is nearly 12 times the size of the 2016 market.
New market rules will enable owners of energy storage systems to earn revenue from a growing number of sources, such as deferred transmission and distribution upgrades, integration of intermittent resources, reduced demand or increased generating capacity to address peak load, the provision of ancillary services, and enhanced grid reliability and resiliency.
Until recently, storage was a square peg jammed into the round hole of historic regulation.
The existing federal regulation of wholesale power sales and transmission in interstate commerce was designed for a world largely devoid of any significant energy storage. Although pumped-storage hydroelectricity has been around for a long time, it has very different characteristics from modern storage technologies such as batteries, flywheels or thermal energy storage projects.
Federal and state governments are moving to encourage storage. Storage has benefited at the federal level from targeted loan and incentive programs offered by the U.S. Department of Energy and from efforts by the Federal Energy Regulatory Commission (FERC) to clear a path to wholesale market participation.
FERC has issued four orders in recent years that help energy storage. It also issued a notice of proposed rulemaking, or NOPR, in November 2016 proposing transparent market rules for energy storage facilities to participate in organized markets run by regional transmission organizations (RTOs) and independent system operators (ISOs). If the NOPR is adopted as proposed, storage would be eligible to provide all capacity, energy and ancillary services in such markets. The problem storage faces trying to participate in such markets today is the rules were developed for power plants and demand response companies and may unnecessarily limit the scope (and therefore compensation) of storage services. Most comments received by FERC in response to the NOPR were favorable — the comment window closed in February 2017 — but the proceeding was placed on hold while FERC sat without quorum for much of 2017. It remains to be seen whether the newly-reconstituted commission will pursue the NOPR.
The federal government also allows a 30 percent investment tax credit to be claimed on some storage facilities that are seen as part of solar and some wind projects. The key to eligibility is the storage equipment must be coupled to a renewable energy project and operated in a manner that it is considered power conditioning equipment or part of the generating equipment. At least 75 percent of the energy stored by the storage device should come from the renewable generator to which it is coupled. A stand-alone energy storage project would not qualify.
Many state governments have enacted, or are in the process of enacting, mandates or regulations to promote storage (see box 1). States will probably lead the charge on storage development in the near term since they have smaller constituencies and tend to be more nimble than the federal government in responding to market conditions. Some state and local governments also have a stronger appetite for renewable energy deployment than the current federal government. For example, the governors of 11 states and Puerto Rico and the mayor of the District of Columbia committed to comply with the Paris climate agreement after the Trump administration pulled out the United States.
Energy storage should follow the same pattern as other new technologies, such as solar.
Battery cell costs declined from $3,000 a kilowatt hour in the 1990s to $200 a kilowatt hour by 2016.
Utility-scale energy storage systems with four-hour storage capacity installed in the third quarter of 2017 had a median price of $525 a kilowatt hour. Analysts project this price to drop to $450 a kilowatt hour by 2019. The cost per unit capacity for these systems was in the range of $1,300 to $1,500 a kilowatt in 2017. It is expected to decline to $800 to $1,100 a kilowatt by 2020. This compares to an installed cost of $978 to $1,100 a kilowatt for a combined-cycle gas-fired power plant today.
Bloomberg New Energy Finance projected in 2015 that the installation costs of battery technologies will decline at 6 percent a year, meaning that the unit installation cost should, by 2025, be half of what it was in 2015.
ICF recently simulated the operation of a battery storage device for a utility in the U.S. Eastern Interconnection system and estimated that $2 million a year, or $102 per kilowatt hour, would be earned from capacity, energy and ancillary services (Exhibit 1). At a fixed charge rate of 10 percent, the break-even capital expenditures for the project would be about $900 per kilowatt of capacity. Considering the current installation cost for a lithium-based energy storage resources is $1,300 to $1,500 per kilowatt, the modeled application would not currently be economically viable. However, this type of storage should cross the break-even point in the next few years, even if these are the only revenue streams available to storage.
The true value of storage resources is not limited to capacity, energy and ancillary services. There are numerous sources of potential additional value (see box 2). Many regions already have markets that let energy storage owners tap into some of these additional revenue streams, and others will follow as government policies change.
Storage projects have unique risks stemming from unstable regulatory regimes, unprepared market structures, unique liability exposure, and unproven performance records. Creativity, flexibility and preparedness will help manage these risks.
Check back tomorrow for part two on risks for storage projects and how to mitigate them.
This article was originally published in Norton Rose Fulbright’s Project Finance NewsWire here and was republished with permission.
Lead image credit: CC0 Creative Commons, modified | Pixabay
Caileen Kateri Gamache is Sr. Counsel with Norton Rose Fulbright. She works with project developers, investors, utilities and financial marketers to find solutions to complex energy regulatory issues, develop ideas into operational projects, draft and negotiate material contracts and close deals.
Deanne Barrow is an Associate with Norton Rose Fulbright. Her practice focuses on the representation of sponsors and lenders in the development and financing of energy and infrastructure projects in the US, Latin America and the Caribbean.
Ken Collison is Vice President, ICF. He has expertise in transmission studies, power system reliability studies, critical infrastructure protection, transmission and ancillary services valuation, generation analysis, utility restructuring, and strategic studies.
Shankar Chandramowli is a Senior Associate with ICF. He has over five years of experience in energy policy research, transmission and distribution planning in ISO/RTO markets, economic analysis of energy systems, optimization modeling, drafting policy memos and public stakeholder engagement for research inputs.