The New England Power Pool Markets Committee last week rejected ISO-NE’s proposal for recalculating the dynamic delist bid threshold (DDBT) for Forward Capacity Auction 16, along with several proposed amendments to the RTO’s plan, none of which attracted the necessary 60% for endorsement.
The DDBT issue consumed half of the first day of the committee’s three-day meeting.
The DDBT for FCA 15 for 2024/25 is $4.30/kW-month. The Tariff requires the threshold, which was last updated in 2017/18, be recalculated for FCA 16 (2025/26).
The RTO proposed recalculating the DDBT annually using publicly available data, saying it would address transparency concerns and keep the threshold aligned with current and expected market conditions.
It would make the DDBT the average of the preceding FCA price and the price the capacity that cleared in the preceding FCA intersects with the estimated system-wide demand curve for the upcoming FCA. The threshold would not exceed the net cost of new entry (CONE) or fall below 75% of the preceding FCA price; the net CONE limit would apply if the two overlapped.
Jeffrey Bentz, director of analysis for the New England States Committee on Electricity (NESCOE), expressed concern in his presentation that setting the DDBT too high or at net CONE could improperly allow some bids to escape the scrutiny of a market power review. NESCOE proposed lowering the upper bound to 85% of net CONE or 125% of the prior auction clearing price, saying it would strike a better balance between the design objectives of providing adequate review to prevent market power and limiting unnecessary administrative interference.
NESCOE also proposed limiting the maximum rate of change in the DDBT from auction to auction to 30% of net CONE.
In a memo to the committee, ISO-NE’s Matthew Brewster wrote that NESCOE’s proposals would “constrain the DDBT value relative to the [RTOs’] proposal under various conditions, which could undermine this key enhancement achieved with the new DDBT calculation method. … By preventing the DDBT from adjusting to reflect projected market conditions for the next FCA, the amendments would cause the DDBT to remain a lagging, or ‘stale’ estimate of the appropriate delist bid review threshold.”
The memo also said that “while NESCOE suggests a one-directional remedy within the DDBT for (potential) errors” in net CONE, it does “not appear to provide a reasoned basis for the numerical value of the proposed cap at 85% of net CONE.” Additionally, NESCOE’s other proposed DDBT cap of 125% of the last FCA clearing price “has only a superficial symmetry with the floor present in the ISO’s design.
“The underlying assumption of this 125% cap is that the supply curve becomes flat at prices 25% higher than the last FCA clearing price,” the memo continued. “However, that outcome is not supported by theory … nor is it plausible in practice. The supply curve generally is increasingly steep as quantity increases (up to the point where prices reach true net CONE).”
The NESCOE amendments failed with only 34% support.
The committee also rejected proposals by Calpine and Vistra Energy’s Dynegy unit to address what Bill Fowler, president of Sigma Consultants, said is the disadvantage faced by resource owners having to lock in static delist bids four months before the FCA.
At the September Markets Committee meeting, Fowler said the DDBT should be set at a “reasonable margin” — 50 cents to $1/kW-month — above the expected clearing price. (See “Change to Delist Bid Threshold,” ISO-NE Challenged on Wind, Solar, Storage Revenues.) Fowler revised the proposal last week, calling for “a small cushion” varying with the level of the expected clearing price, declining to zero if the expected clear is at net CONE. It won only 49% support.
Also rejected was a Calpine/Dynegy proposal to eliminate the obligation to commit to a bid price in October and make the October static delist finalization requirement a cap on auction prices.
ISO-NE’s proposed DDBT changes, the last vote, received only 44.5%. The RTO will file the proposal with FERC despite the lack of stakeholder endorsement.
Support for Forward Reserve Market Sunset
On a voice vote, the committee approved ISO-NE’s proposal to sunset the forward reserve market (FRM) to avoid conflicts with its proposed Energy Security Improvements (ESI) initiative, which is awaiting FERC action. (See ISO-NE Sending 2 Energy Security Plans to FERC.)
The FRM awards obligations for 10-minute non-spinning reserves and 30-minute operating reserves, but the RTO said it is becoming unnecessary because of ESI and transmission investments and market changes that address locational constraints and reward resource flexibility.
The RTO’s proposal included two alternatives. If FERC issues an order approving ESI as filed before Dec. 31, the RTO will file a “non-contingent” Tariff change by the end of 2020 to sunset the FRM on June 1, 2025, coinciding with the start of the 2025/26 capacity commitment period.
If FERC does not rule on ESI before the end of the year, the RTO would file a “contingent” FRM sunset that would take effect if FERC approves ESI as filed.
If FERC rejects ESI, the RTO will not file either Tariff change. The RTO said future discussions with stakeholders on reserves might be necessary if this is the eventual outcome.
The RTO plans a vote by the Participants Committee in November.
RTO Seeks Modifications for EERs, RAs
Ryan McCarthy of ISO-NE presented proposed modifications to the qualification process for energy efficiency resources (EERs) to better account for expiring measures. The RTO also wants to change the monthly reconfiguration auction (RA) and bilateral qualification rules to better account for new financial assurance and performance accounting rules.
The proposal would set the seasonal qualified capacity to the lower of the amount of capacity that has cleared as “new” in prior FCAs or the amount of measures marked commercial plus FCA cleared non-commercial MWs on critical path schedule (CPS) monitoring. The proposed methodology would apply to both the FCA and all annual RA qualifications.
An EER will have two years from the start of the commitment period in which it first received a capacity supply obligation to install its measures. Previously cleared EERs will have until May 31, 2027, to install all measures.
As additional EE clears in the FCA, the capacity will be factored directly into the load reconstitution process. The RTO said the proposal will better align qualified capacity with its performance capabilities.
The RTO would assign monthly qualification to resources that become commercial during the capacity commitment period. The monthly qualification will track delayed commercial resources and allow non-commercial capacity to participate in monthly RAs and bilateral qualifications.
The Markets Committee will vote on the proposals next month. EER qualification changes would become effective in February 2021 for FCA 16. The monthly qualification changes would become effective in January 2022 and implemented for the March 2022 monthly reconfiguration auction and bilateral qualification period.
GIS Working Group to Consider Massachusetts ‘Clean Generation’ Changes
The MC agreed to direct the Generation Information System (GIS) Operating Rules Working Group to consider changes to the GIS and the GIS Operating Rules to reflect the addition of “Clean Existing Generation” (CES-E) to the Massachusetts Clean Energy Standard. The changes were requested by the Massachusetts Department of Environmental Protection.
NEPOOL counsel Paul Belval of Day Pitney said in a memo that DEP revised its regulations to include a requirement that retail load-serving entities subject to the standard have a certain percentage of energy from “Clean Existing Generation Units.”
Clean existing generation units are nuclear or hydroelectric units with a nameplate capacity of at least 30 MW that began commercial operation before Jan. 1, 2011, and satisfy specific geographic requirements. In addition to adding a new category in the GIS, the DEP regulations pose two additional rule changes. Multiple co-located GIS generators could have their generation aggregated, and certain annual caps on qualifying output would have to be allocated among those GIS generators. Also, certain generators in Newfoundland and Labrador could be eligible. That would require a slight expansion of the area where qualified generators can receive unit-specific certificates in the GIS.
The committee is not being asked to vote on any changes to GIS rules, the memo said, but should refer issues to the working group to discuss and determine potential rule revisions.
Order 841 Compliance Update
Jennifer Wolfson of ISO-NE updated the committee on the RTO’s plan for responding to an Aug. 4 FERC order on the RTO’s second Order 841 compliance filing. (See FERC OKs Most of ISO-NE 2nd Storage Compliance.)
The RTO proposes Tariff changes to comply with two FERC directives. The first change would address FERC’s concern that the Tariff language preventing double payment for charging energy at the retail and wholesale levels would allow host utilities to decide whether an electric storage resource (ESR) may participate in its markets. It would be effective in the first quarter of 2021.
The second responds to FERC’s directive that the Tariff include the bidding parameters the RTO will use to account for the state of charge and duration characteristics in the day-ahead energy market. It would be effective Jan. 1, 2026.
The RTO will seek votes on the proposed revisions at the committee’s next gathering on Nov. 9-10 and at the Participants Committee’s Dec. 3 meeting.