New England Power Pool Counsel Eric Runge provided the Transmission Committee with an update on the hearing procedures in the proceeding under Federal Power Act Section 206 on network service formula rates (EL16-19-002).

FERC ordered hearing proceedings in May after rejecting a contested offer of settlement on network service rates for a group of New England transmission owners (NETOs). The commission said the record was insufficient to determine whether the settlement’s benefits outweigh the objections to it, citing municipals’ evidence in opposition. (See FERC Rejects New England Tx Rate Settlement.)

The settlement proposed new rates and a new rate design for regional network service (RNS), local network integration transmission service (LNS) and point-to-point (PTP) transmission service for all the TOs in the region. It would have replaced the existing RNS and LNS rates with new formula rate templates and associated protocols.

FERC trial staff argued that the settlement was unfair because it would have set unreasonable rates and “contains fundamental defects.” Staff cited the TOs’ ability to conduct “extra-formulaic, ad hoc” ratemaking for all externally sourced inputs every year and over-recover certain plant costs.

The commission instituted the proceeding in December 2015, saying ISO-NE’s Tariff “lacks adequate transparency and challenge procedures” on the NETOs’ formula rates and that the network rates “lack sufficient detail” to determine how costs are derived and recovered.

Under a scheduling order approved Aug. 13, direct testimony from witnesses seeking changes to the existing rates is due Oct. 10, with answering testimony to defend the existing rate due Jan. 10, 2020. Rebuttal testimony responding to answering testimony is due March 2, and discovery requests must be submitted by March 12. A hearing is scheduled for April 27 through May 12. Oral arguments, if necessary, will be held Aug. 10 with an initial decision targeted for Sept. 21.

Runge said the commission could issue an order by the end of next year. The order, he noted, could be followed by rehearing requests.

Changing Interconnection Capability Following Partial Market Exits

Director of Transmission Strategy and Services Alan McBride led a discussion of ISO-NE’s proposed procedural changes to clarify how the RTO adjusts interconnection capability after partial market exits.

The RTO is drafting Tariff changes to collect in one place the rules now in three schedules and Planning Procedure No. 10 that detail how it updates interconnection service limits for generators. The rules would apply after the clearing of a retirement delist bid, permanent delist bid or substitution auction demand bid in the Forward Capacity Market. The changes, to be collected in a new section II.48 of the Tariff, also would apply to external elective transmission upgrades.

The changes include an exception process for reducing summer capacity without changing winter limits. The exception would allow generators to provide engineering information to the RTO to prove that the formula-based, proportional winter capability adjustments for a partial retirement do not accurately calculate their winter interconnection capability.

The RTO hopes to make the changes effective in January following approvals by the Reliability Committee in September, the TC in October and the Participants Committee in November.

Competitive Transmission Solicitation Enhancements

ISO-NE Director of Transmission Planning Brent Oberlin outlined proposed Tariff revisions to accommodate Order 1000 competitive transmission solicitations.

The RTO said the changes are needed because the selected qualified transmission project sponsor agreement (SQTPSA) did not specify that project modifications may be required under section I.3.9 of the Tariff and that failure to reach agreement on modifications may be grounds for termination. It also said changes were needed to Attachment K of the Tariff to consider system performance as an evaluation factor and specify that participating TOs must stop work on projects related to the upgrade of existing facilities once a developer has been selected as the “stage two” solution. It is also refining the definition of “localized costs” to make it consistent with the intent of the competitive process and differentiate it from asset condition projects.

Oberlin outlined several changes to the SQTSPA and Attachment K since the July TC meeting.

The TC will vote on the revisions Sept. 17 with a PC vote expected Oct. 4.

Cost Recovery for CIP Standard Compliance

ISO-NE’s Jonathan Lowell presented the RTO’s proposal for a cost recovery procedure for generators’ compliance with NERC’s critical infrastructure protection (CIP) standards. Generators designated by the RTO as “critical” to the determination of interconnection reliability operating limits face higher CIP standards than “non-critical” generators, and the costs cannot be competitively offered and recovered through the energy and capacity markets.

Lowell said the RTO’s goal is to reduce the time and expense involved in the cost filings and provide guidance on cost identification and categorization while avoiding the need for reconciliation and true-up procedures. It will “emulate a ‘formula rate’ construct as much as possible,” Lowell said.

A new Schedule 17 will set out a procedure for generators to make FPA Section 205 filings to gain FERC approval of the costs. The proposed costs would be posted for at least a 60-day review period before the FERC filing, and there will be Webex or in-person briefings for interested stakeholders. The prefiling review is intended to result in uncontested FERC filings and definitive orders that the RTO can rely on for billing.

The RTO will support “direct cost” categories identified in the Schedule 17 template. Generators would have to support other costs not covered by the template.

Once approved by FERC, ISO-NE will bill the costs over 12 equal payments over a year.

Lowell said the RTO has eliminated previous proposals for 24-month and 36-month amortization periods and differentiations for “recurring” and “nonrecurring” costs.

ISO-NE proposes costs be allocated to transmission customers based on monthly regional network load and monthly average through or out service. “Incremental CIP compliance costs are not a transmission cost, but it is correct and efficient to allocate these costs to transmission customers as beneficiaries,” the RTO said.

Charges will be separately identified on RTO customers’ monthly non-hourly charges statements.

In his own presentation, Eversource Energy’s Paul Krawczyk reiterated the company’s contention that “recovering these costs through transmission charges is inappropriate.” (See Eversource Balks at ISO-NE Plan on CIP Costs.)

Eversource, which had previously suggested several alternatives, is now proposing the costs be allocated to real-time load obligations.

The TC is expected to vote on the proposal at its Oct. 10 meeting with a PC vote Nov. 1.

— Rich Heidorn Jr.