The New England Power Pool Reliability Committee last week indicated its displeasure with the re–evaluation of the fuel-security reliability review for Mystic Units 8 and 9, rejecting a motion that the review had been performed in accordance with ISO-NE’s market rules and planning procedures.

The motion, which required a two-thirds vote to pass, failed with only 26.65% in favor, with overwhelming opposition from the Generation, Transmission and Alternative Resources sectors. The Supplier and Publicly Owned Entity sectors were split, and the End User sector lacked a quorum.

ISO-NE sought to retain Mystic 8 and 9 for Forward Capacity Auction 13 after Exelon said in March that it would retire the entire 2,274-MW facility, including Mystic 7 and Mystic Jet, when its capacity supply obligations expire on May 31, 2022. FERC last December ordered hearing and settlement procedures on ISO-NE’s cost-of-service agreement with Exelon (ER18-1509). (See FERC Approves Mystic Cost-of-Service Agreement.)

For the re-evaluation for FCA 14, the RTO’s analysis looked at 18 scenarios and included increases in the amount of natural gas and fuel oil modeled and increases in the capacity values of some renewable resources.

The new analysis concluded that Mystic should continue to be retained because its retirement would violate two triggers: the use of load shedding in any hour under Operating Procedure 7 and the depletion of 10-minute reserves below 700 MW in an hour in the absence of a contingency in more than one LNG supply scenario.

[Editor’s Note: Speakers who raised objections to the analysis declined to be quoted on the nature of their concerns.]

The RTO’s assistant general counsel for markets, Christopher Hamlen, said the analysis was well vetted by the RC over the last year, so the methodology employed for the re-evaluation should have come as no surprise.

Norm Sproehnle, the RTO’s manager for outage coordination, said four generators that submitted retirement delist bid requests for FCA 14 — Yarmouth 1 (summer capacity of 50 MW), Yarmouth 2 (48 MW), Ipswich Diesels (9.3 MW) and Pinetree Power (16.9 MW) — did not need to be retained for fuel security.

Transmission operability analyses also found the resources could retire because none resulted in voltage or thermal criteria violations, said Abimael Santana, senior engineer in system planning.

The RC voted unanimously that the analyses for the four resources were in accordance with the market rules and planning procedures.

ICAP Requirements and Tie Benefits

The RTO’s manager of resource studies and assessments, Peter Wong, presented a review of the installed capacity requirements (ICR) and tie benefits for capacity commitment period 2023/24 (FCA 14), with and without Mystic 8 and 9.

For FCA 14, including or excluding the units in the New England resource mix will change the total tie benefits to New England by 30 MW, he said.

FCA 14 tie benefits assumptions for the calculation of the ICR-Related Values will be 1,940 MW for the scenario including the units, and 1,910 MW for the scenario excluding them.

Hydro-Québec interconnection capability credits for FCA 14 for the “including Mystic” scenario will be 941 MW, while for the “excluding” scenario will be 943 MW, he said.

Assuming RC approval Sept. 25 and Participants Committee approval Oct. 4, the RTO plans to file with FERC by Nov. 5 ICR-related values for FCA 14, both including and excluding Mystic 8 and 9, Wong said.

The RTO will be sharing additional results with the NEPOOL Power Supply Planning Committee on Thursday.

FCM Planning Procedures

ISO-NE Director of Transmission Strategy and Services Al McBride revisited the topic of moving recently developed changes to Planning Procedure 10 (PP10) to the Tariff to support the Forward Capacity Market, as discussed at the combined RC and Transmission Committee meeting in July. (See “Modifying Interconnection Procedures,” NEPOOL RC/TC Briefs: July 16-17, 2019.)

McBride said the RTO is proposing to create a new section in the Open Access Transmission Tariff for the PP10 provisions. Changes include methodologies to update the levels of interconnection service for generators after the clearing of a retirement delist bid, permanent delist bid or substitution auction demand bid in the FCM.

If approved by NEPOOL committees in September and October, and by the PC on Nov. 1, the changes would take effect in January 2020, he said.

The PP10 revisions will become effective after the proposed Tariff revisions are accepted by FERC and become effective, McBride said.

Revising Operating Procedure 14E

The RC voted to recommend that the PC support revisions to OP-14E to incorporate energy storage as a type of asset-related demand that can be selected on ISO-NE’s form NX-12E, which provides the RTO with details that are not included in bid information.

Jerry Elliott, a principal analyst in system operations at ISO-NE, presented the proposed revisions, which the PC will vote on at its Sept. 13 meeting.

Elliott also presented proposed revisions to OP-19, for a future vote. They would add the use of phase shifting transformers and adjustments of reactive flow to normal system actions performed by the RTO and each local control center to ensure transmission reliability.

In addition, he notified the RC of changes to OP-19 Appendix K to reconcile National Grid and NSTAR operating voltage limits with Master/Local Control Center Procedure 15 Attachment H – Voltage System Operating Limit Identification Procedure.

ISO-NE Lead Operations Analyst Kory Haag presented proposed revisions to OP-23 Appendix H, for a vote in September. They would clarify the data that are required for reactive capability test requests. The proposed effective date is in October 2019.

Maine Dominates PPAs

The RC approved several proposed plan application (PPA) notifications for solar and wind generation, as well as related transmission upgrades, most of them in Maine.

The committee voted to recommend to ISO-NE that the following projects will not have a significant adverse effect on the stability, reliability or operating characteristics of the transmission facilities of the applicant, the transmission facilities of another transmission owner or the system of a market participant:

• Central Maine Power to install the 7.2-MW BD Solar Augusta solar array in Augusta, Maine, and interconnect it to the Blair Road Substation, with a proposed in-service date of Sept. 1, 2020.
• CMP to install the 9.2-MW BD Solar Oxford solar array in Norway, Maine, and interconnect it to the Oxford Substation, with a proposed in-service date of Sept. 1, 2020.
• NextEra Energy Resources to install the 75-MW Dawn Land Solar project in Washington County, Maine, as well as a transmission application to install a station transformer at the Deblois Substation to interconnect the solar array. Proposed in-service date is May 31, 2022.
• Emera Maine to construct a new 115-kV substation and expand the Deblois Substation, adding one 115-kV breaker at the new substation and four 115-kV breakers at Deblois; adding 13.4 miles of 115-kV transmission line from the new substation to the Deblois substation; a new transformer and three new breakers at the new substation; and other associated transmission work. The proposed in-service date is May 31, 2022.
• Con Edison Energy to replace the existing automatic voltage regulation on the Schiller CT 1 with a Basler DECS-250 digital pilot exciter. Proposed in-service date is in September 2019.
• NextEra to install the 20-MW Randolph Center solar array in Randolph, Vt., and interconnect it to the Randolph Center 46-kV substation, with a proposed in-service date of Nov. 1, 2021.
• SWEB Development to install the 20-MW Silver Maple wind farm in Penobscot County, Maine, and interconnect it to the Randolph Center 46-kV substation and to the Silver Maple four-breaker ring bus substation, with a proposed in-service date of Dec. 16, 2020.
• Emera Maine to install a four-breaker ring bus substation in Penobscot County for the Silver Maple project, with a proposed in-service date of Oct. 1, 2020.
• NextEra to install the 50-MW Chariot Solar facility in Hinsdale, N.H., and interconnect it to the 115-kV line between the Vernon Road Tap and Vernon Road Substation. The proposed in-service date is Nov. 1, 2023.
• NextEra to build a new 115-kV three-breaker ring bus substation in Hinsdale to interconnect the solar project (proposed in-service date Oct. 1, 2021), as well as to install a station transformer that interconnects to the new substation, with a proposed in-service date of Sept. 27, 2023.

Competitive Tx RFP

ISO-NE Transmission Planning Director Brent Oberlin led the fourth discussion at the RC of competitive transmission solicitation enhancements. The package of changes being presented at the RC and TC includes proposed clarifications to Attachment K of section II of the Tariff, the draft Selected Qualified Transmission Project Sponsor (SQTPS) agreement, and to sections I.2.2 and I.3.9 of the Tariff associated with preparing for competitive transmission solicitations under FERC Order 1000.

The focus of the discussion with the RC was on the changes to the Tariff in section III.12.6 and the definitions in section I.2.2. Oberlin said that no comments had been received since the RC meeting in July, so the language remains unchanged from what had been presented previously.

Oberlin also said ISO-NE is still looking to act on the issue at the RC meeting in September.

Based on the results of the 2028 Boston Needs Assessment, the RTO plans to issue its first solicitation for a competitively developed transmission solution in December 2019.

Tx Cost Allocation

The RC voted unanimously to recommend that ISO-NE approve pool-supported costs estimated at $28.1 million for New England Power to replace 345-kV structures on the 303 and 3520 lines in Massachusetts.

NEP will replace 126 of 142 structures on the 303 line from Berry Street Substation to the ANP Bellingham Station and on the 3520 line from ANP Bellingham Station to the West Medway Substation because of asset conditions and installation of optical ground wire (OPGW) on both lines.

The committee accepted that none of the costs associated with the upgrade are considered localized costs.

Capacity Cost Compensation

The RC voted unanimously to recommend that ISO-NE approve two dynamic reactive resources as meeting the capacity cost compensation program (CCCP) eligibility requirements defined in the Tariff.

The resources, Canal 3 (Asset ID No. 38310) and Lisbon Resource Recovery (Asset ID No. 462), were recommended to have their qualified resource recovery designation to be effective Sept. 1.

Consent Agenda

The RC did not vote on its consent agenda that included one level 1 and 50 level 0 PPA notifications for solar generation, with 25% of the projects paired with battery storage.

One stakeholder noted the large number of hybrid solar/storage projects and wondered if ISO-NE was keeping tabs on the amount of energy storage being paired with solar each month.

McBride said the RTO has not been keeping that statistic separately but would consider the request. RC Chair Mariah Winkler said it appeared to be an issue of categorization.

Winkler said that the RTO would bring a revised consent agenda to the RC next month.

— Michael Kuser