BOSTON — The NEPOOL Participants Committee on Friday retroactively approved Tariff revisions filed by ISO-NE on May 1 to address FERC’s concerns over the RTO’s initial compliance filing in response to the commission’s Order 841 rulemaking on energy storage.

ISO-NE’s initial Dec. 3 compliance filing proposed two types of energy storage: continuous storage (batteries and other resources that can transition nearly instantaneously between charging and discharging at any MW level within their range) and binary storage (facilities such as pumped storage whose physical constraints prevent them from quickly changing from charging to discharging) (ER19-470).

The commission issued a deficiency letter on April 1 asking the RTO to explain whether a continuous storage facility would be compensated for lost opportunity costs if it were dispatched for reserves rather than energy. (See “Questions to ISO-NE Touch on Reserves” in FERC Asks RTOs for more Details on Storage Rules.)

The RTO’s May 1 response said “any resource, including a continuous storage facility, dispatched for reserves rather than energy is compensated for lost opportunity costs (which would result from foregone energy sales) via the real-time reserve clearing price, not [net commitment period compensation].”

Facilities that have insufficient available energy to run at their full capacity for a full hour should not receive an opportunity cost payment because their own physical limitation creates the suboptimal dispatch, the filing said.

ISO-NE said it “is very concerned” that paying an opportunity cost payment would likely entail complicated settlement calculations and could create perverse incentive for continuous storage facilities “to maintain relatively small amounts of stored energy in order to be paid this opportunity cost frequently.”

The commission also had asked whether some continuous storage facilities may have start-up or no-load costs, such as costs for cooling a storage facility that is online but not dispatched.

The RTO said such a case was more likely to be an example of a fixed cost, incurred independent of its commitment and dispatch instructions, rather than a no-load cost.

“In a hypothetical universe in which batteries were committed and decommitted by ISO-NE, it seems likely a battery would incur the same cooling costs when it was offline awaiting a start-up instruction as it would incur once it was online at zero megawatts. If this is the case, these costs would be fixed costs,” it said.

Alternatively, it said, if a portion of cooling costs varies with output, that portion would be considered a variable cost. Cooling costs would be characterized as a no-load cost only if, when ISO-NE issues a shut-down instruction to an online resource dispatched to zero megawatts, the resource’s costs decrease by a discrete amount.

ISO-NE said it does not believe this to be the case for any costs likely to be incurred by continuous storage facilities.

Fuel Security Reliability Reviews

The committee approved revisions to Planning Procedure (PP) 10, Appendix I regarding fuel security reliability reviews for Forward Capacity Auction 14 (delivery year 2023/24) with 69.5% support.

The RTO conducts the review on resources that submit retirement de-list bids to determine whether they are needed for reliability.

The changes were approved after NEPOOL attorneys added language to the motion to clarify that supporting the changes to the PP “shall not be construed as support for the ISO’s broader planning for fuel security and resource retention.”

But that wasn’t sufficient to win the votes of the End Users sector, which was unanimous in opposition. End Users Chair Liz Delaney said many in her sector believe ISO-NE’s fuel security model is overly conservative and could lead to expensive contracts to retain unnecessary generators. “It’s hard to separate the assumptions from the operation of the model,” she said in an interview.

The Generators, Transmission and Publicly Owned Entity sectors were unanimous in support. Suppliers were mostly in support (13.43% in favor) and Alternative Resources mostly opposed (5.66% in favor).

The proposal had fallen just short of the required two-thirds vote at the Reliability Committee April 24.

ISO-NE asked for the changes, saying they would:

• Improve modeling of injections from local gas distribution company satellite LNG storage facilities;
• Maintain the oil inventory levels from the 2017/2018 winter;
• Shape the conventional hydroelectric generation output;
• Provide additional time for offshore wind resources to demonstrate their contractual commitments; and
• Expand the kinds of entities that can provide evidence of contractual commitments under state procurements to include transmission companies, distribution companies and the New England States Committee on Electricity (NESCOE).

The RTO’s Norman Sproehnle told the Reliability Committee in April the changes “cover a variety of optimistic scenarios which minimize the potential for retaining resources unnecessarily.”

Among other things, the changes replaced the assumed replenishment for oil-fired generation from “one proxy tanker truck per hour” to 202 barrels per hour when reorder levels are reached. The RTO clarified oil inventory levels apply to oil-only resources and dual-fuel resources that operate primarily on oil during the winter; it said dual-fuel resource tank inventory levels apply to dual-fuel resources that operate primarily on natural gas during the winter.

It also promised to perform an “informational analysis” for an additional 500 MW of offshore wind being developed under a state procurement with an in-service date for winter 2023/24, which is not included in the base model.

Resources participating in Forward Capacity Auction 14 will be modeled in the study with an in-service date of Jan. 1, 2024, one month later than the original Dec. 1, 2023, deadline.

Consent Agenda

The PC approved four rule changes on the consent agenda, following unanimous approvals at lower committees:

• Operating Procedure (OP) 17 (Load Power Factor Correction): Revisions to Appendix C to update company names, and additional, minor grammatical revisions. Approved by the Reliability Committee March 20.
• Market Rule Section III.1.9.1.2(a) (Offer and Bid Caps): Revisions to simplify implementation of the day-ahead market (DAM) offer capping approach under Order 831. Recommended by Markets Committee at its April 9-10 meeting.
• GIS Operating Rules: Revisions to the NEPOOL generation information system (GIS) operating rules to enhance searching and sorting capabilities of public reports and importation of requested billing adjustment (RBA) data into the GIS. Recommended by the Markets Committee at its April 9-10 meeting.
• Reasonable Effort Timelines for Interconnection Studies: Tariff revisions increase from 45 to 90 days the “reasonable efforts” deadline for ISO-NE and transmission owners to complete interconnection feasibility studies after receipt of an executed study agreement. Increases the deadline for completing system impact studies from 90 to 270 days after the receipt of the study agreement, deposit, technical data and demonstration of site control, if required. ISO-NE requested the change to “better align with the expected duration of the study efforts given the scopes of work involved” in the studies. Recommended by the Transmission Committee April 17.

Load Relief, GMD

The committee approved on a single vote changes to OP-2, -4, -4A and PP-11, which were recommended by the Reliability Committee in separate votes on April 24.

Revisions to OP-4 and OP-4A adjust the estimates of load relief from OP-4 actions to be based on a generic 25,000-MW load amount rather than the 50/50 load forecast in the capacity, energy, loads and transmission (CELT) report. Revisions to PP-11 implement requirements under NERC reliability standard TPL–007-3 (Transmission System Planned Performance for Geomagnetic Disturbance (GMD) Events). The NERC standard includes requirements for performing a GMD vulnerability assessment; providing geomagnetically induced current (GIC) flow information; performing transformer thermal impact assessments for a GMD event; and gathering GIC monitor and geomagnetic field data.

— Michael Kuser and Rich Heidorn Jr.

[See our Editor’s Note: We’re in the Room in NEPOOL!]