By Rich Heidorn Jr.
In a big boost to the energy storage industry, FERC on Thursday proposed a sweeping order aimed at knocking down market barriers to storage and distributed energy resources.
The Notice of Proposed Rulemaking would require RTOs to allow aggregated distributed energy resources and storage resources of 100 kW and above to participate in capacity, energy and ancillary services markets. It also would allow storage to provide services not procured through markets, such as black start, primary frequency response and reactive power (RM16-23, AD16-20).
“As the costs of electric storage resources continue to decline and their technical potential expands, the ability of these resources to provide operational and economic benefits to the organized wholesale electric markets will increase,” the commission said. “We preliminarily find that it is important to remove barriers to participation now so that the competitive benefits are realized without delay.”
In a separate order, the commission also issued a NOPR proposing to require all newly interconnecting large and small generating facilities to install and enable primary frequency response — a requirement new to renewable generators (RM16-6). (See related story, FERC Proposes Frequency Response Requirements for Renewables.)
FERC’s Heard Enough
In the rhythm of FERC rulemaking, staff-led technical conferences are part of a process that is followed by post-conference comments and months of deliberation before the issuance of a NOPR.
Not so with the commission’s deliberations on RTOs’ rules on energy storage and DERs.
Thursday’s NOPR came only eight days after a daylong technical conference at which representatives of RTOs, utilities and technology companies debated the breadth of storage’s potential uses and ways to avoid overcompensating resources performing multiple functions (AD16-25). (See FERC Panelists Debate Storage Uses, Compensation.)
It also followed an Oct. 21 complaint by AES’ Indianapolis Power and Light seeking to goose rule changes in MISO. (See related story, MISO Asks FERC to Dismiss IPL Storage Complaint.)
It’s now apparent that FERC had already heard enough even before convening the conference. The 139-page NOPR was likely the result of months of internal debate and negotiations.
In April, the commission issued data requests to the six jurisdictional RTOs and ISOs seeking information on their rules on storage and DER participation. The RTOs’ responses were followed by dozens of comments from other stakeholders.
“As numerous commenters state, existing RTO/ISO rules that govern participation of electric storage resources in some organized wholesale electric markets fail to ensure that electric storage resources that are technically capable of providing specific services are permitted to do so,” the commission said Thursday.
FERC said outdated and inflexible market rules have hampered innovation. “For instance, some electric storage resources have chosen to participate as demand response resources simply because, absent other participation models, that is the participation model that more closely resembles the manner in which electric storage resources might participate in the organized wholesale electric markets.”
‘Participatory Model’
The NOPR would require RTOs to revise their rules to create a “participation model” that accommodates “the physical and operational characteristics” of storage to allow them to provide any services they are physically capable of.
“Where compensation for these services exists, electric storage resources should also receive such compensation commensurate with the service provided,” the commission added.
One key change would be the requirement that RTOs’ bidding parameters reflect storage’s unique characteristics, including allowing storage to de-rate its capacity to meet minimum run-time requirements to provide capacity or other services.
In addition, RTO criteria for qualifying storage resources “must not limit participation to any particular type of electric storage resource or other technology,” FERC said.
“For example, resources such as thermal storage that can both increase and decrease their energy consumption could aggregate with other distributed energy resources with common physical or operational characteristics and qualify as a market participant using the participation model proposed here.”
In addition to batteries, the commission said the rules also must accommodate “flywheels, compressed air [and] pumped hydro … whether located on the interstate grid or on a distribution system.”
State-of-Charge
The commission said bidding parameters must take into account storage’s state-of-charge to ensure resources are dispatched in a way that maximizes their operational effectiveness.
“While some existing bidding parameters were developed for older electric storage technologies (such as pumped hydro facilities), newer storage technologies (such as battery storage) have greater flexibility to transition between charging and discharging. Therefore, bidding parameters designed for slower storage technologies or other types of generation resources that are not capable of charging and discharging energy may limit the opportunity for faster electric storage resources to participate in the organized wholesale electric markets.”
For RTOs with capacity markets, the commission proposed that the de-rated capacity value for electric storage “be consistent with the quantity of energy that must be offered into the day-ahead energy market for resources with capacity obligations.”
The commission said storage’s participation also should not be barred by requirements, designed for synchronous generators, that the resource be online and synchronized to the grid to be eligible to provide ancillary services.
“Newer technologies, particularly electric storage resources, tend to be capable of faster start-up times and higher ramp rates than traditional synchronous generators and are therefore able to provide ramping, spinning and regulating reserve services without already being online and running,” the commission said. “Therefore, we preliminarily find that participation in ancillary service markets should be based on a resource’s ability to provide services when it is called upon rather than on the real-time operating status of the resource.”
Energy Schedules
But the commission acknowledged that because RTOs co-optimize energy and ancillary services dispatch and pricing, they may require ancillary services providers to have an energy schedule. “As a result, it is not clear whether eliminating the requirement for a resource to be online and synchronized to the grid would be impactful given the continued need to have an energy schedule,” it said, asking for comment on whether the requirement for energy schedules could be relaxed.
“Specifically, we seek comment on whether dispatch and pricing of energy and ancillary services would continue to be internally consistent if a resource were not required to offer to provide energy in order to offer to provide ancillary services.”
Size
The NOPR says that the RTOs’ minimum size requirement for participation in the markets should be no more than 100 kW, a threshold the commission said “balances the benefits of increased competition with the ability of RTO/ISO market clearing software to effectively model and dispatch smaller resources often located on the distribution system.”
The limit would apply to any minimum capacity requirements, minimum offer requirements and minimum bid requirements.
Pricing
The NOPR proposes that the energy that storage resources purchases from RTO markets and then resells back to those markets must be at the wholesale LMP. It also said storage should be permitted to set LMPs both as buyers and sellers.
“This proposal includes the requirements that the RTOs/ISOs accept wholesale bids from electric storage resources to buy energy so that the economic preferences of the electric storage resources are fully integrated into the market, the electric storage resource can set the price as a load resource where market rules allow and the electric storage resource can be available to the RTO/ISO as a dispatchable demand asset. However, we note that these requirements must not prohibit electric storage resources from participating in organized wholesale electric markets as price takers, consistent with the existing rules for self-scheduled load resources.”
Smaller DER
The NOPR also acknowledged the expected growth of DER in requiring RTOs to “remove any unnecessary limitations on how the distributed energy resources that participate in such aggregations must be operated.”
“It is clear from the comments that the ability to meaningfully participate in the organized wholesale electric markets for these smaller distributed energy resources is through aggregations,” the commission said.
“For example, combining the discharge times of multiple electric storage resources and/or combining them with distributed generation resources could allow aggregated resources to meet minimum run-time requirements that individual electric storage resources may not be able to meet.”
Under FERC’s proposal, a DER aggregator could register as a generation asset “if that is the participation model that best reflects its physical characteristics.”
The commission expressed hope that price signals will encourage DER to locate in areas where new capacity is most needed, helping reduce congestion costs during load peaks and to reducing transmission investments for delivering energy into high-priced load pockets.
“Unlike larger fossil fuel generators that often are not able to locate in load pockets due to environmental or other citing concerns, distributed energy resources are more able to co-locate with load and provide associated benefits,” the commission said. “We also believe that the shorter lead time to develop many forms of distributed energy resources compared to traditional generators or transmission lines allows them to rapidly respond to near-term generation or transmission reliability-related requirements, further improving their ability to enhance reliability and reduce system costs.”
Transaction Costs
The commission said the changes should remove the commercial and transactional barriers to DER participation in wholesale markets.
“Owners and operators of individual distributed energy resources may be reluctant to incur the significant costs of participating in the organized wholesale electric markets, such as the costs of the necessary metering, telemetry and communication equipment,” it noted.
“The smaller a resource is, the more likely the transaction costs to sell services into the organized wholesale electric markets outweigh the benefits that the prospective market participant may realize from selling wholesale services. However, some of these costs can be reduced by participating in the organized wholesale electric markets through a distributed energy resource aggregation; for example, the time and resources necessary to learn the market rules and actively submit bids and/or offers into the organized wholesale electric markets.”
FERC said integrating DERs into the markets will help RTOs account for them in calculating installed capacity requirements and day-ahead energy demand, “thereby reducing uncertainty in load forecasts and reducing the risk of over procurement of resources and the associated costs.”
LaFleur Statement
Commissioner Cheryl LaFleur issued a statement saying that DERs “will play a critical role in the future of the grid” but noting that they present “unique issues since they are connected to the grid at the distribution level.”
She called for “close coordination among the RTO/ISOs, the distribution control centers that operate the systems to which they are connected and the distributed energy resource aggregators. … This coordination could include, for example, real-time operating procedures and software-enabled communications among the control centers.”
The commission noted that it was awaiting an informational report from CAISO, which recently began implementing rules for DER aggregations.
CAISO’s Tariff also includes participation models for Generators, Proxy Demand Resources, Reliability Demand Response Resources and Non-Generator Resources.
Comment Period
The commission will accept comments for 60 days after the NOPR is published in the Federal Register. In particular, the commission solicited comment from the RTOs on the rule and software changes that would be required to implement the new requirements as well as the associated costs and how they can be minimized.
