ISO-NE energy demand has fallen 3 to 5% since stay-at-home orders began being implemented across New England around March 16, the RTO’s Load Forecasting Manager Jon Black told the New England Power Pool’s Reliability Committee on Wednesday.

“System operations as well as load forecasting in planning are doing ongoing analysis [and] monitoring the situation very closely,” Black said.

That situation is changing by the week, and ongoing changes are likely, especially as the stay-at-home orders may become relaxed or lifted in various parts of the region, he said.

“While we’re seeing impacts today, there’s a lot of uncertainty about the ongoing duration of the effects of the stay-at-home orders, first and foremost in terms of the duration of what we’re witnessing and observing now, but perhaps more importantly from a long-term forecast perspective, what will be the recessionary impacts of the fallout of the pandemic,” Black said.

It’s still too early to understand the longer-term impacts of the pandemic, but the RTO relies on sources like Moody’s Analytics to inform its thinking, he said. (See Moody’s: Coronavirus Recession to Cut GDP 2.3%.)

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

CELT 2020 Forecasts up on Electrification

Black presented the final data behind the long-term energy and demand forecasts to be published May 1 in the 2020 Capacity, Energy, Loads and Transmission (CELT) report.

Both the gross and net annual energy forecasts for 2028 are up from last year’s CELT, by 1.5% and 5.4%, respectively, “largely due to the forecast impacts of large-scale electrification expected throughout the region,” Black said.

“The numbers have all been finalized, but there’s a lot of work that goes into publishing all the final reports,” he said.

The RTO has posted the 2020 Forecast Data workbook.

CAGR up Slightly

Black explained that, other than adding electrification forecasts, the RTO adopted no significant modeling changes compared to the 2019 CELT.

“This year’s compound annual growth rate [CAGR] is up a bit from last year over the 10 years, at 1.4% from 2020 through 2029, up from 1.1% in last year’s CELT.”

The final 2020 net annual energy forecast for the region has a CAGR of 0.4% from 2020 through 2029, up from the -0.4% reported in CELT 2019, he said.

Other highlights from the 2020 CELT:

• The gross 50/50 summer peak demand forecast exceeds the 2019 CELT’s by 0.3% for 2020 and 1.5% for 2028, and is forecast to increase at a CAGR of 0.9% from 2020 through 2029, up slightly from 0.7% in CELT 2019.
• The final net 50/50 summer peak demand forecast for the region is 0.4% higher in 2020 and 1.2% in 2028. It’s expected to decrease at a CAGR of -0.2% from 2020 through 2029, up slightly from -0.4% for CELT 2019.
• The final 2020 gross 50/50 winter peak demand forecast is up 0.4% for the winter of 2020/21 and by 4.2% for the winter of 2028/29, and forecast to increase at a CAGR of 1.1% from 2020 through 2029.
• The final net 50/50 winter peak demand forecast for the region is down by 0.2% for the winter of 2020/21 and up by 4.3% for the winter of 2028/29. It is expected to increase at a CAGR of 0.1% from 2020 through 2029, up from -0.6% as reported in last year’s CELT.

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EE Reconstitution

Black also provided the RC with background on energy efficiency participation in the Forward Capacity Market and its “reconstitution” in the gross load forecast.

“Taking it all the way back to the beginning of the Forward Capacity Market, as part of that inception, it was decided that EE would be treated as a capacity supply-side resource and receive capacity supply obligations [CSOs] in the same manner as any other supply-side resource,” Black said.

“In order for that to work, we have a section of our Tariff that requires us to reconstitute — in other words, add back —the demand savings associated with the EE that participates as supply, and that reconstitution is done on the historical loads that we use to develop a long-term load forecast, and in particular the long-term gross load forecast,” he said.

The intent of the gross load forecast is to ensure that passive demand resources are not double-counted in the Forward Capacity Auction as both a load reduction and a capacity supply resource, Black said.

ISO-NE has observed over time that the total amount of EE measures installed exceeds the amount of such CSOs acquired in the primary auction, meaning that reconstituting all installed EE measures results in a forecast of gross demand that overestimates the amount of EE CSOs acquired in the FCA.

Shifting to EE CSO as the basis of its gross load reconstitution will better approximate future EE supply-side participation, Black said.

The change in load forecasting methodology is the first of three initiatives the RTO is introducing to relevant NEPOOL technical committees over the next several months, as detailed in a memo posted after the meeting from COO Vamsi Chadalavada. The second initiative considers the impact of behind-the-meter solar PV on future planning assessments, and the third will better integrate the FERC Order 1000 request-for-proposals process into the reliability delist bid review, starting with FCA 15.

The RTO will present the EE methodology topic for further discussion next month ahead of an advisory vote in June. If the Participants Committee approves them, the Tariff changes will be filed with FERC with a requested effective date of Aug. 30.

FCA 15 Fuel Security Reliability Review

ISO-NE Manager of Outage Coordination Norm Sproehnle presented initial inputs to the fuel security reliability review for FCA 15, feedback from the March RC meeting and preliminary results.

Stakeholders in March pushed back on ISO-NE’s draft assumptions showing that several variable changes between FCAs 14 and 15 would improve system fuel security. (See NEPOOL Reliability Committee Briefs; March 17, 2020.)

Appendix L of the Tariff stipulates the RTO must apply a multiprong trigger for the FCA 15 preliminary analysis that would result in a resource being retained for fuel security if its retirement would: result in the depletion of 10-minute reserves below 700 MW in any hour in the absence of a contingency in more than one LNG supply scenario case; or precipitate the use of load shedding in any hour pursuant to Operating Procedure No. 7.

Using the trigger criteria and the existing Planning Procedure 10 (PP10) inputs, as updated for FCA 15, the RTO has been able to assess the preliminary results of resources that have submitted retirement delist bids (1,935 MW total). Appendix I of PP10 requires the RTO to consult with the RC on 18 static inputs and three variable inputs: imports, LNG injections and dual-fuel resource tank inventory.

The preliminary results indicate that no resources that submitted a retirement delist bid for the FCA 15 capacity commitment period or were previously retained for fuel security — both totaling 1,935 MW — will be retained for fuel security for the period.

The additional work to complete the analysis will not change the outcome of the fuel security reliability review, as the items to be finalized will further improve fuel security, Sproehnle said.

Given the preliminary results of the FCA 15 fuel security reliability review, the additional changes suggested thus far would not materially alter the outcome, he said.

For example, stakeholders asked if the Distrigas LNG tanks will be available and utilized in the fuel security reliability model if Mystic Units 8 and 9 retire.

The RTO derived the three LNG scenarios — 0.8, 1 and 1.2 Bcfd — based on the output of the region’s three LNG facilities and their previously observed winter production. If the Distrigas facility is excluded, the capability of the remaining LNG facilities can support the three scenarios, he said. Therefore, ISO-NE will continue to use them for the review.

The RTO timeline calls for the RC in August to review FCA 15 fuel security analysis results for submitted retirement delist bids. Participants that have submitted a retirement delist bid will be notified by the RTO if their resource is needed for fuel security reliability reasons no later than 90 days after the existing capacity June 11 retirement deadline.

ICR and Related Values Development

Manasa Kotha, ISO-NE senior engineer for resource studies and assessment, presented the RC with the 2020 development schedule for installed capacity requirement (ICR) values that will be used in auctions conducted in 2021.

The ICR, as well as the net installed capacity requirement, are calculated for each FCA and annual reconfiguration auction and are inputs to the sloped demand curves, Kotha said. The ICR represents the minimum total system capacity needed in New England to meet the Northeast Power Coordinating Council’s resource adequacy criteria.

Details of the ICR-related values development will be discussed with the NEPOOL Power Supply Planning Committee over the summer and brought back to the RC for review and a vote in September. If approved by the Participants Committee in October, the RTO plans to file the values with FERC by Nov. 10.

Committee Actions

The RC’s notice of actions included approval of several motions, noting that all sectors had a quorum.

The committee approved a 10-MW fuel cell interconnecting to the 23-kV bus of the Judd Brook substation in Connecticut, with an in-service date of Dec. 1.

Also approved was NextEra Energy’s 20-MW Keay Brook solar facility in York County, Maine, interconnecting to the 34.5-kV Lebanon-Sanford line, which went into service Feb. 12.

The RC approved pool transmission facility (PTF) cost allocation of $18.5 million to Eversource Energy for transmission upgrade costs associated with the replacement of wooden structures on the 115-kV 1655 line with steel poles.

Eversource also had $16.6 million in PTF cost allocation approved for work associated with the replacement of the high creep insulator system at the Millstone 15G substation in Waterford, Conn.

The RC approved National Grid PTF cost allocation of $212 million in transmission upgrade costs for work associated with the 345-kV 327 and 315 lines and asset condition refurbishment as submitted to ISO-NE by New England Power.

It also approved a revision to Operating Procedure 14 (OP-14) related to technical requirements for generators, demand response resources, asset-related demands and alternative technology regulation resources.