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FERC Acts to Address Offer Price Caps, Electric Storage, Primary Frequency Response, and Hydroelectric Policies

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On November 17, 2016, the Federal Energy Regulatory Commission ("FERC") took several actions that could have significant implications for the administration and operation of organized wholesale electricity markets. FERC issued a final rule addressing price caps on incremental energy offers and proposed rules on the participation of energy storage resources in organized markets and the provision of primary frequency response. FERC also issued a notice seeking comment on its policy governing hydroelectric license terms. The discussion below provides an overview of these issuances.


FERC issued a final rule (Order No. 831) revising its regulations regarding offer caps on incremental energy offered in markets operated by Regional Transmission Organizations ("RTOs") and Independent System Operators ("ISOs"). The final rule is designed to improve price formation by ensuring that locational marginal prices ("LMPs") are more reflective of resources' true marginal costs, and by providing resources with a better opportunity to recover their short-run marginal costs.

To accomplish these objectives, each RTO and ISO is required to adopt a uniform offer cap structure. Under the new rule, a resource may only submit an incremental energy offer equal to or above $1,000/MWh if the offer is cost-based (i.e., the offer accurately reflects the resources' actual or expected short-run marginal costs). For an incremental energy offer equal to or above $1,000/MWh and less than or equal to $2,000/MWh, the RTO/ISO or Market Monitoring Unit must verify that the offer is cost-based before the RTO/ISO may use the offer to calculate LMPs. For an incremental energy offer above $2,000/MWh, the RTO/ISO or Market Monitoring Unit must also verify that the offer is cost-based, but offers in excess of $2,000/MWh will be capped at $2,000/MWh for purposes of calculating LMPs. Resulting LMPs, however, may exceed $2,000/MWh due to losses and congestion, and resources with verified cost-based incremental energy offers above $2,000/MWh are eligible to receive uplift.

Each RTO and ISO is required to submit a revised tariff to FERC implementing Order No. 831 within 75 days after the rule is published in the Federal Register. A copy of Order No. 831 can be found here.


FERC issued a Notice of Proposed Rulemaking ("NOPR") proposing to require all new large and small generating facilities (both synchronous and non-synchronous) to install, operate, and maintain equipment capable of providing primary frequency response and to comply with proposed operating requirements. These requirements would be a required condition for new facilities interconnecting through both Large Generator Interconnection Agreement ("LGIAs") and Small Generator Interconnection Agreement ("SGIAs"),1 and would be implemented through modification of the pro forma LGIA and SGIA. FERC proposes to define primary frequency response equipment as “the required hardware and/or software that provides frequency responsive real power control with the ability to sense changes in system frequency and autonomously adjust the generating facility's real power output in accordance with the proposed maximum droop and dead band parameters and in the direction needed to correct frequency deviations.” The rationale behind adopting the new requirements is to improve upon the current limited frequency response requirements applicable to only synchronous facilities and extend the requirements to both non-synchronous and small generators.

If the final rule is adopted, it would apply to new generating facilities that execute an LGIA or SGIA, or request the filing of an unexecuted LGIA or SGIA, on or after the effective date of the final rule. Public utility transmission providers would have 60 days after publication of the final rule in the Federal Register to make the required changes to the LGIA and SGIA in their Open Access Transmission Tariffs.2 Non-public utility transmission providers would also be required to comply with the final rule as a condition of maintaining the status of their safe harbor tariff or satisfying the Order No. 888 reciprocity requirements.

Interested parties have 60 days from the publication of the NOPR to submit comments to FERC on the proposal. FERC has also requested comment on whether additional primary frequency response requirements are necessary for existing resources. A copy of the NOPR can be found here.


FERC issued a NOPR that would significantly expand the ability of energy storage resources and distributed energy resources to participate in wholesale electricity markets. The proposal, described as a "continuation of the [FERC's] efforts to promote competition in organized wholesale electric markets by removing barriers to the participation of new technologies," would require that RTOs and ISOs update their market rules to allow energy storage resources to sell all of the electric services they are technically capable of providing, including capacity, energy, and ancillary services. The NOPR would also require that RTOs and ISOs permit aggregators of distributed energy resources to participate directly in markets, while establishing rules for their participation. The impacts of both sets of provisions could be far-reaching. Energy-storage provisions would markedly increase the potential for a growing class of energy storage providers, ranging from flywheels and batteries to pumped-storage hydroelectric facilities, to more fully participate in - and receive payment from - organized energy markets. The NOPR would also provide enhanced wholesale market access for distributed resources, while providing for greater uniformity in treatment among RTOs and ISOs.

Parties seeking to comment on the NOPR must file comments within 60 days after the NOPR is published in the Federal Register. The NOPR is available here.


Section 15(e) of the Federal Power Act requires that "new" hydroelectric licenses (i.e., relicenses) be issued for terms not less than 30 years or more than 50 years. For hydroelectric facilities located at non-federal dams, FERC generally issues 30-year licenses for projects with minimal improvements, 40-year licenses for projects with moderate improvements, and 50-year licenses for projects with extensive improvements. Improvements implemented during a current license term, however, are not considered by FERC when determining new license terms. FERC also looks to coordinate the license terms of projects in a given basin and may take into consideration settlement agreements that provide for a specific license term.

Through a Notice of Inquiry ("NOI"), FERC is requesting stakeholder comment on whether it should: (1) retain its existing license term policy; (2) consider measures implemented during the prior license term in determining the term of the new license; (3) adopt a 50-year license term as a default license term; (4) employ a quantitative cost-based analysis to inform license terms; and (5) allow settlement agreements to play a role in determining license terms. Given the administrative costs associated with the relicensing process, the resources needed to undertake relicensing, and the increased costs generally associated with new license terms, the NOI provides an opportunity for licensees to make the case for a FERC policy that generally provides for longer license terms (i.e., license terms of 50 years).

Comments are due 60 days after the NOI is published in the Federal Register. A copy of the NOI can be found here.

1Nuclear generating facilities would be exempt from the new requirements.

2Public transmission providers would also have the opportunity to demonstrate that their current tariffs are superior to or consistent with the proposed modifications, as well as seek "independent entity variations" if eligible.

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