By Michael Kuser and Rich Heidorn Jr.
The New England Power Pool Markets Committee last week rejected ISO-NE’s interim proposal for compensating generators for fuel security. But the RTO plans to file the plan with FERC with or without stakeholder endorsement, it said Monday.
The proposal, which would cover capacity commitment period 14 (2023/24) and 15 (2024/25), received only 42% support, short of the 60% threshold to recommend it to the Participants Committee.
[Editor’s Note: This account of the meeting is based on the committee actions notice posted after the two-day session March 5-6. Like most NEPOOL meetings, it was closed to the public and the press.]
ISO-NE spokeswoman Marcia Blomberg said the RTO will seek a vote on its proposal at the NEPOOL Participants Committee meeting Wednesday and plans a FERC filing by the end of the month regardless of the outcome. “In its advisory role, NEPOOL provides input on ISO proposals, and the ISO has filed proposals in the past when we haven’t had the full support of NEPOOL,” she said via email. “The ISO always evaluates NEPOOL’s input, but I can say that we are working toward a filing on the interim compensation proposal.”
ISO-NE said the plan — which it estimated could cost more than $100 million over the last winter reliability program — is intended to prevent otherwise economic resources from retiring because they are not fully compensated for their winter energy security attributes. It would trigger when gas availability is low and system conditions were tight.
Under a two-settlement structure, resources would be paid or charged for deviations between the inventoried energy purchased in a forward position for the entire winter season and the spot settlement rate — representing energy maintained during each trigger condition.
The plan is intended to be an interim measure until the RTO completes development of a market-based compensation scheme for energy security, which will not be filed before retirement bids are due for Forward Capacity Auction 14 this month.
Amendments also Rejected
The committee also rejected efforts by the Union of Concerned Scientists (UCS), PSEG Energy Resources & Trade and energy services firm Energy New England (ENE) to amend the ISO-NE proposal.
ENE argued that the RTO’s proposal “far exceeds” its stated goal of retaining resources for fuel security reliability and preventing uneconomic retirement bids, saying its “resource eligibility is too broad and extends beyond target resources.”
The company recommended limiting compensation to oil, natural gas, demand response and electric storage, “resources capable of improving winter energy security by providing incremental reliability benefits.” ENE said its proposal would reduce the cost of the program by about $50 million.
ENE’s amendment received only 48% support, winning backing from most End Users and Publicly Owned Entities but overwhelmingly opposed by the Generators, Suppliers, Alternative Resources and Transmission sectors.
The PSEG amendment would have set the inventoried energy base payment rate on April 30 immediately prior to the delivery period.
“It is widely recognized that setting the energy base payment rate for the winter delivery period over four years prior to when the contracts are expected to be obtained increases the likelihood that the rate will be inconsistent with market conditions when resources are expected to go to market to obtain those contracts,” PSEG’s Joel Gordon said in a memo to the committee. “If the rate is too low, the program will fail to procure the additional fuel security needs of the system. Conversely, if the rate is too high, the overall cost of the program will be greater than otherwise required to achieve its objectives.”
It failed with 42% support, with strong backing from Generators and strong opposition from End Users.
Abigail Krich, president of Boreas Renewables, was to present on behalf of the UCS a proposal guaranteeing that energy actually provided would receive the same compensation as inventoried energy.
Krich’s presentation said that renewable resources that provide energy during cold weather are also essential to reliability but that they would not be compensated like fossil fuel plants because they have no “inventoried” energy. The UCS proposal, which would have amended Tariff Section I.2.2 and Appendix K of Market Rule 1, failed on a show of hands.
Energy Efficiency Exemption Impact
The Markets Committee also rejected a proposal by the New England Power Generators Association (NEPGA) to address a disconnect in the calculation of Pay-for-Performance penalties during scarcity conditions in off-peak hours. The proposal was introduced by NEPGA member Dynegy Marketing and Trade.
Because of an exemption ordered by FERC, energy efficiency resources are subject to ISO-NE’s PfP requirements only during DR on-peak and seasonal-peak hours. That became an issue on Labor Day 2018, when EE resources were treated as if they had hit the stop-loss limits, resulting in $9.7 million in settlement imbalance charges to other capacity resources, according to NEPGA.
The association said because most EE resources are in Massachusetts and Connecticut, the cost of the exempted performance obligations should be allocated to the states based on their shares.
NEPGA’s proposal received less than 35% support, winning majorities from only the Generation, Supplier and Alternative Resources sectors.
An alternative amendment by Vermont Energy Investment Corp. (VEIC) fell just short of approval with 58.4% support, strongly backed by End Users, Publicly Owned Entities and Transmission and strongly opposed by Generation, Suppliers and Alternative Resources.
VEIC’s proposal was presented by Synapse Energy’s Doug Hurley, who said the balancing ratio (BR) used to compute penalties removes EE from the numerator but not from the denominator during non-peak hours.
Hurley said the proposal would revert the mutual insurance pool to its original intent of covering resources that reach stop-loss limits. “The BR for any interval would be calculated based upon those resources that are subject to payments or penalties in that interval, as the FERC order intended,” he said.
In a related matter, the committee agreed to ask the Demand Resources Working Group to consider how EE resources’ performance could be established in all hours and what standards and reporting mechanisms are necessary to make the change. The committee acted on a problem statement that noted the lack of a consensus on EE performance measurements in off-peak hours.
New Ancillary Services and Multi-day-ahead Market
The meeting also featured a presentation on the introduction of three categories of new ancillary services to be procured in the day-ahead market and an update on the previously introduced multi-day-ahead market (M-DAM).
ISO-NE Principal Analyst Andrew Gillespie was scheduled to present the committee with conceptual details, as well as a timeline for a FERC filing by Nov. 15, in line with the RTO’s January request for a four-month extension to file a plan. The delay request is currently pending before the commission (EL18-182).
The presentation to the committee acknowledges the RTO has “heard a number of questions and concerns about the length of the market horizon, primarily how this may not align with participants’ hedging strategies.”
The Massachusetts attorney general’s office commissioned London Economics International (LEI) to prepare an alternative to the RTO’s M-DAM proposal, which LEI found “conceptually and operationally complex” and said would “require substantial administrative costs.”
Complete revamping of the day-ahead market into an M-DAM is an unproven mechanism and may not meet all the RTO’s goals, LEI concluded, proposing instead a “forward stored energy reserve” ancillary service.
The advisory firm contends that while the RTO’s proposal might increase revenues for some power plants and prevent inefficient retirement, the resulting higher energy prices may lower net cost of new entry, which would suppress capacity market prices and potentially accelerate retirement.
Calpine was scheduled to present its case for a “forward enhanced reserves market” (FERM), with analyst Rebecca Hunter arguing all problems that fall within a planning horizon time frame are left unsolved without a forward price signal. (See “Market Reaction,” New England Talks Energy Security, Public Policy.)
The FERM would have no offer cap, but awards to resources with capacity supply obligations would be incremental to the clearing price. In addition, FERM resources would have daily day-ahead must-offer obligations in winter months only. The construct would allow participation from resources without a supply obligation, such as energy-only resources that only plan to be available for peak days in the winter.