Highlights from the September FERC Open Meeting

September 17, 2015 by Miles Farmer, NRDC Legal Fellow

Improving Price Formation: Settlement Intervals and Shortage Pricing in Markets Operated by Regional Transmission Organizations and Independent System Operators (RM15-24).  FERC issued a notice of proposed rulemaking to require ISOs and RTOs to (1) settle energy and operating reserve transactions in their real-time markets in the same time interval that they dispatch energy or price operating reserves (as applicable); and (2) trigger shortage pricing during any dispatch interval in which a shortage of energy or operating reserves occurs.  FERC’s proposal was driven by a concern that there are instances in which RTO/ISO practices currently fail to accurately price energy and operating reserves.  For example, some RTOs and ISOs dispatch resources every five minutes but perform settlements based on an hourly price.  This creates a delay in shortage pricing, which renders the market unable to adequately incentivize resource availability to address an immediate reliability need.  If adopted, this rule should incentivize resources that have the ability to respond quickly to shortage pricing signals, including for example storage and some demand response.

FERC specifically seeks comment on two aspects of this proposal: (1) whether this reform should be extended to intertie transactions (which are not covered in the NOPR); and (2) whether FERC should require RTOs and ISOs to settle real-time energy transactions and real-time operating reserve transactions in the same time interval (the NOPR does not contain such a requirement).  Comments on this NOPR are due sixty days after the date on which it is published in the Federal Register.

Fighting Market Manipulation: Collection of Connected Entity Data from Regional Transmission Organizations and Independent System Operators (RM15-23).  In order to assist the Commission in detecting market manipulation, FERC issued a notice of proposed rulemaking to require ISOs and RTOs to deliver to FERC the following information about market participants: (1) an alpha-numeric identifier known as a “Legal Entity Identifier” (LEI) for each market participant; (2) a list of all “Connected Entities” to that market participant; and (3) a brief description of the nature of the market participant’s relationship with each Connected Entity.

This NOPR proposes an expansive definition of “Connected Entity,” which includes, among other entities, (i) any entity that owns, controls, or holds voting power over 10 percent or more of the ownership instruments of the market participant; (ii) the chief executive officer, chief financial officer, chief compliance officer, and traders of the market participant; (iii) any entity that holds a debt interest in the market participant that gives it the right to share in the market participant’s profitability, above a de minimis amount; (iv) entities that have entered into agreements relating to the management or control of the market participant’s resources, such as a tolling agreement, energy management agreement, fuel management agreement, or energy marketing agreement.

The Commissioners indicated at the meeting that due to the novel nature of this proposal, they are especially interested in feedback through the comment process.  Commissioner LaFleur issued a concurring statement inviting market participants to submit comments on the costs and benefits of this proposal, indicating that she will weigh the costs and benefits carefully in deciding whether to support the final rule.  Comments on this NOPR are due sixty days after the date on which it is published in the Federal Register.

Seeking More NERC Data: Availability of Certain North American Electric Reliability Corporation Databases to the Commission (RM15-25).  FERC issued a notice of proposed rulemaking to require the North American Electric Reliability Corporation (NERC) to provide FERC with access to certain NERC databases.  The NOPR indicates that FERC plans to use this data in assessing the need for new or modified Reliability Standards, and to better understand NERC’s periodic reliability and resource adequacy assessments.  Commissioner LaFleur issued a concurring statement that expressed her support, but emphasized that FERC must continue to recognize that NERC has primary responsibility to monitor reliability issues and FERC plays only an oversight role.  The Commissioners stressed at the meeting that FERC’s use of this data to create new Reliability Standards will be limited. Nevertheless, the rulemaking reflects a desire by FERC to apply a more granular level of scrutiny to Reliability Standards.  Commissioner Bay described this rulemaking as an effort to take a “moneyball” approach to reliability.  Comments on this NOPR are due sixty days after the date on which it is published in the Federal Register.

Rejecting MISO’s Proposed Generic Rate Schedule for Must-Run Plants: Midcontinent Independent System Operator, Inc. (ER14-2952 et al.).  In a proceeding concerning cost allocation for three must-run power plants (which in MISO are known as “system support resources” (SSRs)) on Michigan’s Upper Peninsula, FERC approved MISO’s revised cost allocation methodology with regard to the specific plants at issue, but rejected MISO’s generic rate schedule filing that would have allowed MISO to automatically apply this new methodology to all future SSRs.  MISO had proposed its new methodology after its previous cost allocation proposal was rejected by FERC.  FERC’s order here leaves open the possibility that in a future SSR proceeding, MISO could even apply the cost allocation methodology that FERC previously rejected for the Upper Peninsula generators, so long as MISO demonstrates how that methodology would allocate SSR costs to those load-serving entities that require the SSR’s operation for reliability purposes.

 Affirming NSP’s PURPA Obligations: Northern States Power Company (QM15-2).  Earlier this year, FERC issued an order denying Northern States Power Company’s (NSP) application to terminate its PURPA obligation to purchase electric energy and capacity from a qualifying facility owned by Twin Cities Hydro LLC (Twin Cities). It held that while PURPA does not require purchase from qualifying facilities with nondiscriminatory access to certain markets, including the MISO capacity market, Twin Cities’ access to MISO’s capacity market was restricted by transmission constraints and NSP failed to show that Twin Cities had nondiscriminatory access to MISO’s capacity market.  At the September meeting, FERC denied NSP’s request for rehearing of this order.

Affirming the Ability of Interruptible Gas Shippers to Retain Some Scheduling Certainty: Coordination of the Scheduling Processes of Interstate Natural Gas Pipelines and Public Utilities (RM14-2).  At its April meeting, in order to improve gas-electric coordination, FERC issued Order No. 809.  Among other things, Order No. 809 added a third intraday gas nominations cycle during the gas operating day in order to allow shippers an additional opportunity to adjust their gas scheduling in order to reflect changes in demand.  FERC did not, however, modify or eliminate the “No-Bump Rule,” which prevents a higher-priority shipper seeking to increase its gas volumes from “bumping” a lower-priority shipper after the gas deliveries have been set in the final intraday nominations cycle.

At the September meeting, FERC denied a request for rehearing of Order No. 809 from the Desert Southwest Pipeline Stakeholders (DSPS), who had argued, among other things, that FERC erred in retaining the No-Bump Rule.  FERC explained that the No-Bump rule reflects a fair balance between the interests of firm and interruptible shippers, because interruptible shippers need to obtain some level of certainty from the nomination system.

 Grid Operators Report on Winter Outlook: Winter 2015-2016 Operations and Market Performance in Regional Transmission Organizations and Independent System Operators (AD15-14).  At the September meeting, representatives from each RTO and ISO each gave presentations and engaged in a panel discussion concerning their preparations for this winter.  RTOs and ISOs explained changes that they have implemented in order to better ensure reliability during the winter season.  For many RTOs and ISOs, these included new protocols to facilitate better communication between gas generators and pipelines, and enhanced procedures to ensure that generators have adequate fuel reserves.  For example, PJM entered into a Memorandum of Understanding with several natural gas pipelines serving the PJM region in which these entities agreed upon measures to improve gas-electric coordination.

Notably, shortly before its September meeting, FERC approved a proposed program of reliability measures for the 2015-16 – 2017-18 winters put forth by the New England Power Pool (NEPOOL) (ER15-2208).  FERC selected NEPOOL’s proposal over a competing proposal put forth by ISO New England (ISO NE).  NEPOOL’s proposal, unlike ISO NE’s, includes compensation for demand response resources.

With the exception of ISO NE, each RTO and ISO expressed comfort with their reserve margins heading into this winter.  ISO NE expressed uncertainty as to the amount of gas that will be available this winter from the Deep Panuke, Canaport, and Sable Island projects, but nevertheless indicated that it has sufficient coordination and emergency procedures in place in order to implement any necessary operational actions in a timely manner.

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