Energy storage and market rules

Energy storage is experiencing a boom in popularity. In the U.S. Energy Storage Monitor Q4 2018, it is estimated that 338 megawatts were installed in 2018, and this will grow to 3.9 gigawatts in 2023, most of them front-of-the- meter utility-scale projects.

The surge in this exponential growth has been driven by state mandates and regulatory actions (especially in California) and limited to vertically integrated utilities outside of the organized power markets that serve two- thirds of all consumers of electricity in the United States. Despite storage's importance to the grid, it has not been a success in wholesale markets despite its potential. In case you are looking for wholesale batteries and retail batteries, you can use this website. Batteryroot store offers a wide selection.

There are two words that best describe this mismatch: rules and revenue. Wholesale market rules are structured around legacy assets, which means that storage is unable to sell all potential services, which in turn limits storage's wholesale revenue streams. 

Having recognized these obstacles, the Federal Energy Regulatory Commission (FERC) issued Order 841 as a means of encouraging wholesale market access. On December 31, 2018, FERC's regulated independent system operators (ISOs) filed their implementation plans with the agency. 

Energy Storage Association provides helpful insight into what these proposals are all about, including filtered comments according to their effects on possible revenue streams.

In organized power markets, storage is able to generate revenue in three ways: platforms, products, and payouts. In the sense that different projects tap these potential revenue streams in different ways, the implementation plans for Order 841 will affect them in various ways.

The most important thing to remember is to plan ahead.

ISOs conduct planning processes to identify opportunities for new transmission to improve reliability or market efficiency, and storage is increasingly being thought of as a lower- cost, non-transmission alternative for improving reliability.

Here is an example: A relatively isolated area on the grid needs to prepare for the possibility of losing a transmission line or a local generator during peak demand. By building storage rather than adding transmission or local generation, the local grid can be able to survive in the face of emergency situations. There is a possibility that the project could be built and paid for on a cost-of-service basis, financed through transmission charges approved by the regulatory authorities.

A storage project here plays the same role as a reliability transmission expansion project, but it can also be viewed as a transmission project with the purpose of moving surplus energy to constrained areas and lowering prices as a result. I believe this was part of FERC Order 1000's vision, which mandated regional transmission operators to consider "non-transmission alternatives" as part of the planning process.

However, only one economic storage-as-transmission project is known to have been proposed under an Order 1000 solicitation within any ISO territory today, a project that is located near Baltimore on the PJM grid. After PJM evaluated the project, it concluded the project did not meet the required cost- benefit threshold and was therefore not included in the grid operator's Regional Transmission Expansion Plan.

As a result, ISOs have hesitated to fund such projects, because, while "reliability" storage is tied to an definite grid emergency risk, which determines its use, "economic" storage requires ISOs to give instructions on when to buy and sell power. As a result, ISO's might be challenged in their market independence since how they dispatch their storage invariably affects their prices, which could make them look like self-dealing market participants.

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