8 Key Highlights from FERC’s Energy Storage and DER Aggregation NOPR
Last week, FERC issued a new Notice of Proposed Rulemaking (NOPR) to “remove barriers to the participation of electric storage resources and Distributed Energy Resource (DER) aggregations in the capacity, energy, and ancillary service markets” run by ISOs/RTOs. At 134 pages, the NOPR can take some effort to get through, so I’ve compiled eight quick highlights that all energy market participants and distribution utilities will want to be aware of:
1. FERC wants ISOs/RTOs to establish a “participation model” for electric storage resources, consisting of market rules that acknowledge the unique attributes and characteristics of storage, and that will allow storage to effectively participate in organized wholesale electric markets. The NOPR explains that the new participation model must:
- Ensure that electric storage resources are eligible to provide all capacity, energy and ancillary services that they are technically able to provide
- Incorporate bidding parameters that reflect the physical and operational characteristics of electric storage resources, including minimum and maximum charge times and run times
- Ensure that electric storage resources can be dispatched, set the market clearing price as both a wholesale seller and a wholesale buyer, and participate as a price taker
- Establish a minimum size requirement for participation (no more than 100 kW)
- Specify that the sale of power from the market to the electric storage resource that is subsequently resold back to the market must be at the wholesale locational marginal price
2. In addition, the NOPR outlines how RTOs/ISOs must allow DER aggregators to register their aggregations under whichever tariff rules best suit their physical and operational characteristics and establish market rules that address:
- Eligibility for direct participation in the organized market through a DER aggregator
- Locational requirements for DER aggregations that are as geographically broad as possible
- Distribution factors and bidding parameters for DER aggregations
- Information and data requirements for DER aggregations, including total capacity, operating limits, ramp rate, minimum run time, and default distribution factors
- Ability to modify the list of resources in a DER aggregation, without having to re-register all resources if the modification raises no safety or reliability concerns
- Metering and telemetry system requirements for provision of real-time data
- Coordination between the RTO/ISO, DER aggregator, and the distribution utility to avoid reliability or safety concerns, including allowing the distribution utility to review the list of DERs in a DER aggregation
- Market participation agreements for DER aggregators that define their roles, responsibilities, and relationship with the RTO/ISO but do not limit the business models under which aggregators may operate
3. While these agreements will define the roles and responsibilities of the DER aggregator, FERC says they should not limit the business models under which DER aggregators can operate. For example, while the third-party aggregator is a common business model, the market participation agreement for DER aggregators should not preclude distribution utilities, cooperatives, or municipalities from aggregating DERs on their systems or even microgrids from participating in the organized wholesale electric markets as a DER aggregation.
4. The proposed rule calls for RTOs/ISOs to ensure that their tariffs do not prohibit any particular type of technology (though FERC does not seek to upend existing RTO/ISO rules that explicitly prohibit certain technologies).
5. To avoid duplicative compensation, FERC proposes to limit participation by sellers that are receiving compensation for the same service as part of another program.
6. DER aggregators will be required to maintain settlement data.
7. Unlike FERC’s demand response rule, this proposal does not make provision for states to limit DER participation.
8. RTOs/ISOs would be required to submit their compliance filings within six months after publication of any final rule in the Federal Register, with implementation to take effect 12 months thereafter.
As with any major FERC rule change, this one is sure to inspire lots of discussion and debate. The NOPR was officially published on the Federal Register on November 30, 2016, and the due date for comments is January 30, 2017.
About the Author:
Dr. Farrokh Rahimi, Ph.D. has more than 40 years of experience in the electric power industry. In his current role as Senior Vice President, Market Design and Consulting at OATI, Dr. Rahimi oversees development of market design and consulting activities. He is also a key contributor to OATI Smart Grid activities. Dr. Rahimi is an expert in restructured energy market design and related systems, including operations, commercial and business systems, and market monitoring applications.