ISO-NE Load Forecasting Manager Jon Black last week presented the New England Power Pool’s Reliability Committee with a proposal to improve how the RTO measures the impact of passive demand resources (PDRs) participating in its Forward Capacity Auctions. (See “Load Forecasting Methods Evolving,” NEPOOL Reliability Committee Briefs: May 19, 2020.)

To ensure that PDRs are not double counted as both a load-reduction and a supply resource in the FCA, the RTO “reconstitutes” PDR demand reductions — most of which is energy efficiency — into historical loads. The goal is to ensure the EE in the gross demand forecast approximates how much EE that will participate in the upcoming FCA.

Since 2010, the RTO has performed reconstitution using total EE measures installed, believing it to be roughly equal with the amount of capacity supply obligations (CSOs) obtained by EE resources cleared in the FCA. But the RTO says it now realizes that EE program administrators install and report EE measure quantities above the CSOs acquired in the FCA. The RTO has no way to differentiate which measures are installed to meet a CSO and which measures are not.

Under the revised methodology, the gross load forecast will be tied to EE’s participation in each FCA rather than all EE that is installed and reported to ISO-NE.

“What we’ve seen is the CSOs for the [Annual] Reconfiguration Auctions are higher than the primary auctions, so we’re trying to correct things for the upcoming primary auction, and now we’re trying to adjust that gross load forecast accordingly to reflect the known differences in the amount of CSOs and PDR that clears in the Reconfiguration Auctions,” Black said.

[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]

The proposed methodology for adjusting the gross load forecast for the ARAs is based on the average difference between the two most recent reconfiguration auction CSOs and those of the FCAs for the corresponding capacity commitment periods.

The proposed changes would cut forecast 2020 50/50 gross summer peak demand by 652 MW, rising to 1,355 MW for the 2029 forecast. No changes will be made to the existing methodology utilized to reconstitute active demand resources.

The change in load forecasting methodology is the first of three related initiatives the RTO introduced to NEPOOL technical committees so far this year. The second initiative considers the impact of behind-the-meter solar PV on future planning assessments, and the third is intended to improve integration of the FERC Order 1000 solicitation process into the reliability delist bid review, starting with FCA 15.

The RTO will present the load forecasting methodology changes to the RC for an advisory vote in July. If the Participants Committee approves them in August, the RTO will file the Tariff changes with FERC with a requested effective date of Oct. 5.

Operating Changes for Storage

The committee recommended PC support for revisions to Operating Procedure 18 (OP-18) to enable DC-coupled facilities to participate in ISO-NE markets as separate assets.

ISO-NE Manager of Demand Resource Administration Doug Smith presented the proposal, which passed with opposition from two Publicly Owned Entity sector members and an abstention from one Transmission Owner. The proposed effective date is Aug. 6, 2020. (See “Metering for DC-coupled Assets,” NEPOOL Reliability Committee Briefs: May 19, 2020.)

Several market participants are installing electric storage and intermittent generation behind the same point of interconnection. Because some of those co-located facilities are DC-coupled — both the storage and intermittent components share one or more inverters — there is a need to address the metering of such assets.

Load Power Factor Correction

ISO-NE Manager of Real Time Studies Dean LaForest delivered an introductory presentation on improvements proposed for the tracking of the load power factor, the ratio of real power flowing to load versus apparent power in the circuit.

Under Operating Procedure 17 (OP-17), the RTO monitors load power factor by requiring participants to submit survey data for six discrete points in time over the 12-month survey period. But there are “no significant consequence[s]” for failing to meet load power factor standards, LaForest said.

Under the proposed change, the RTO would monitor performance using data from its supervisory control and data acquisition system, allowing it to track every hour of the year.

Poor load factor at high loads — in which reactive power is absorbed from the system — can require unit commitments to support post-contingent low voltage. Poor load power factor at light loads — with reactive power injected into the system — is more common and can require unit commitments to support pre- or post-contingent high voltage, LaForest said.

The RTO would use the more robust data to report on areas where poor performance hurts reliability or increases unit commitment costs.

Compliance with the load power standards for each area would be “consistent” with current operating procedure compliance practices, LaForest said.

Noncompliant entities would be allowed an opportunity to improve their performance; continued failures would result in actions under “existing compliance mechanisms,” he said. The RC will review redline changes to OP-17 in July, with a vote expected in September and PC action in October.

Committee Actions

The RC’s notice of actions included approval of several power purchase agreements.

The committee approved the New England Clean Energy Connect HVDC transmission project from Eversource Energy and Central Maine Power. Based on a voice vote, the motion passed with two Publicly Owned Entity members opposed and eight abstentions.

Also approved were the:

• King Street Comprehensive Solar Cluster Project (New England Power);
• ASO South Comprehensive Cluster Project (New England Power);
• Wareham Cluster Solar and Battery Project (Eversource);
• Versant Power Cluster Solar Project (Versant Power/Emera Maine);
• Great River Hydro AVR Replacement and Digital Governor Retrofit Project (Great River Hydro);
• Highland Avenue Dartmouth Cluster Solar and Battery Project (Eversource);
• Bridgeport Fuel Cell Project (Avangrid/United Illuminating);
• CMEEC New London Navy Fuel Cell Project (Connecticut Municipal Energy Electric Co.); and
• Waterford Solar Project (Eversource).

The committee also recommended PC approval of revisions to Planning Procedure No. 5-1 to update the form for submitting PPAs, with a proposed effective date of Aug. 6. In response to an increase in PPAs and generator notification forms (GNFs) being processed monthly, the revised procedures require submittals 10 business days before the monthly RC meeting date.