Commenters generally back FERC’s proposal to approve new standards for electric transmission but urged the commission to reject two replacement rules that they said could lead to less efficient use of the grid.

In July, FERC issued a Notice of Proposed Rulemaking to approve Version 003.3 of the North American Energy Standards Board’s (NAESB) Standards for Business Practices and Communications Protocols for Public Utilities (RM05-5-29, et al.). (See FERC Backs Latest NAESB Rules.)

Comments filed earlier this month by the Edison Electric Institute, the Bonneville Power Authority, the ISO/RTO Council (IRC) and Open Access Technology International (OATI) all generally supported the standards adopted by NAESB’s Wholesale Electric Quadrant (WEQ). Version 003.3 includes revisions responding to recommendations by Sandia National Laboratories to strengthen cybersecurity protections; change rules on redispatch services and transmission curtailments; and replace 56 requirements in NERC’s Modeling, Data and Analysis (MOD A) reliability standards addressing the calculation of available transfer capability (ATC). NERC asked that the rules be removed from its standards because they deal primarily with commercial terms rather than reliability.

But none of the commenters agreed with FERC’s suggestion that it might revise its own regulations on ATC. And both BPA and the IRC asked the commission to reject standards WEQ-023-1.4 and WEQ-023-1.4.1, which they said would prevent transmission providers from maximizing the utilization of their systems.

Scheduling Limits

Requirement 1.4 would prohibit transmission providers from granting firm transmission service exceeding the sum of facility ratings for an ATC path; 1.4.1 would limit net interchange schedules to this same amount.

The IRC said the requirements could expose transmission providers to compliance risks when there is a sudden, unexpected outage or derate of a transmission facility on an ATC path, “as there may not be sufficient time to adjust posted ATC or modify the current interchange schedule in a manner that would completely avoid a violation of the requirement language.” The requirements would also require transmission providers to disregard “expected usage” and account for full reservation capacity granted when calculating firm transmission service transactions. “Treating every firm transmission service reservation as if it is being used in full, regardless of the transmission customer’s scheduling activity, will undoubtedly result in less efficient use of the transmission system,” the IRC said.

BPA said the proposals “address regional seams issues arising primarily in the Eastern Interconnection and are not requirements migrated from the NERC MOD A reliability standards.” It said the rules would require transmission providers and operators to continually balance schedules so that the schedules never exceed the path ratings.

“These standards appear to be inconsistent with how Bonneville and other providers/operators in the Western Interconnection operate their systems,” BPA continued. “For Bonneville and others, an ATC path is allowed to be overscheduled up to 20 minutes prior to flow, at which point interruptions of non-firm service, curtailments or economic dispatches are then performed to ensure path limits are not exceeded. This practice supports the maximum utilization of the transmission system, a key commission objective with respect to transmission, including the integration of variable resources scheduled within the hour. There are many situations that arise which may allow additional schedules or non-firm reservations to stand prior to flow, such as changes in system conditions or the receipt of counterflow schedules.”

BPA said its concern “is particularly relevant in light of the recent heat wave events of August and September 2020 in California, wherein energy supply and transmission availability were severely constrained, which led to energy emergency alerts and ultimately rolling blackouts. Eliminating the practice of overscheduling until 20 minutes [prior to flow] on transmission facilities such as the California-Oregon Intertie … could exacerbate the problem by artificially restricting energy supply and transmission availability even further.”

The IRC said the requirements were included in WEQ-023 even though they were initially rejected by the NAESB Business Practices Subcommittee and opposed in comments by PJM, MISO, SPP, ERCOT and Ontario’s Independent Electricity System Operator.

ATC

In the NOPR, the commission expressed concern that WEQ-023 may lack the transparency and consistency of MOD A, noting that it does not contain replacements for MOD-001-1a requirements R6 and R7, which direct transmission operators to use assumptions no more limiting than those used in its planning of operations calculations.

The commenters were unconcerned. EEI and OATI said the commission should not attempt to address ATC calculations within its regulations and that any additional changes should be considered in the NAESB standard development process.

“By its directives in Order No. 890 and its provisions in the pro forma Open Access Transmission Tariff (OATT), the commission has ensured that the ATC calculation is consistent and nondiscriminatory,” EEI said.

NAESB provides “an open, transparent and industry-participant-driven process” for considering additional rule changes, said OATI, which offers transmission providers software and processes for automation and decision support.

“This fosters a working environment where both transmission providers and transmission customers can come together to discuss solutions to issues that address the unique needs of both parties. This process is then documented for those not in attendance,” OATI said. “In contrast, unilateral alteration of the pro forma OATT lacks the collection of input from impacted industry participants. Without the input from such parties, the commission could unintentionally and unnecessarily burden industry participants with regulatory changes.”

The IRC said WEQ-023 contains “sufficient detail to protect transmission customers and ensure transparent, consistent and non-discriminatory ATC calculations” and increase transparency by requiring transmission providers to document and post their calculation methodologies.

“The WEQ-023 standards reflect an industry-wide consensus on the treatment ATC and TTC [total transfer capability] from a commercial perspective,” BPA said. “There is no need for the commission add additional requirements.”

BPA also said FERC’s proposed language “includes ambiguous references to technical concepts such as using ‘factors derived from operations and planning data’ in the calculation of ATC and TTC.”

If the commission does order NAESB to pursue additional standards, BPA said, it and industry should “avoid conflating commercial and reliability standards. Any further work done by NAESB should be focused strictly on commercial-related standards, whereas NERC should be focused on reliability matters.”

Sequence

FERC also got pushback on whether it should cancel NAESB Version 3.2 and proceed directly to Version 3.3.

“Implementation of the different versions simultaneously are not necessarily simple upgrades,” EEI said. “Additionally, [Open Access Same-Time Information System] updates, training and testing are required for successful implementation.”

OATI said the implementation periods for 3.2 and 3.3 should be “separate and consecutive … to prevent wasted industry effort and cost” because combining the two would force companies to cancel or heavily revise their implementation plans.

“Keeping the Version 3.2 and Version 3.3 separate also decreases the impact to the industry and therefore reduces risk of implementation failure and errors,” OATI said. “The business practices included in Version 3.2 are significant changes to the currently established business practices. The impacts of pre-emption, right of refusal and consolidation affect many aspects of the transmission service procurement and approval process. The fundamental changes begin with transmission customer actions and extend into areas such as line capacity calculations, settlement calculations and billing notification systems. Combining the implementation of Version 3.2 and 3.3 exponentially increases the number of impacts changing in one period.”

The 18-month implementation period for Version 3.3 should begin after implementation of Version 3.2 ends, OATI added.

BPA said FERC should allow at least a 12-month implementation period for Version 003.3, after the final compliance deadline for 003.2.

Parallel Flow Visualization

The IRC asked FERC for an accelerated implementation of rules that it said will improve congestion management in the Eastern Interconnection by incorporating “parallel flow visualization” (PFV) into the transmission loading relief process.

The IRC said PFV, the result of a 14-year industry effort, “will more accurately account for internal flows [i.e., network native load] by incorporating the use of real-time data into relief obligations calculated by the interchange distribution calculator (IDC). Rather than estimating generator output based on load and whether or not units are on outage, the calculation will utilize real-time output and projected next-hour output to calculate native load and network service. This approach is similar to an approach currently used by PJM, MISO and SPP to calculate market flows that was incorporated into the IDC in 2003.”

It asked that the PFV standards be implemented on an expedited timeline, with compliance filings due nine months after the publication of a final rule in the NAESB proceeding and implementation required three months later.