By Rich Heidorn Jr.

ATLANTA — NERC’s Board of Trustees and Member Representatives Committee (MRC) held their quarterly meetings last week at the Grand Hyatt Atlanta. Here are some of the highlights. (See related story, LaFleur, Stakeholders Anxious over NERC Retirement Study and NERC to Try Again on Inverter Rules.)

New ERO Enterprise Dashboard

NERC is proposing a new approach to how it collects and presents metrics, advancing a “dashboard” that separates measures of industry performance from those indicating how well the organization is meeting its goals.

CEO Jim Robb said the dashboard represents a “very different approach to performance management than what we’ve done in the past” and that executives will use it to allocate resources.

The dashboard shows green for risk indicators that are improving, yellow for stable metrics and red for metrics getting worse.

For 2018, the indicators showed improvements in the number of bulk power system events; forced outages because of cold weather or lack of fuel; outages resulting from operator or other human performance issues; and unauthorized physical or electronic access.

Vegetation encroachment metrics were unchanged from 2017, while protection system misoperation rates and failures of substation and circuit equipment got worse.

NERC’s three-year operating plan lists six goals: developing risk-responsive reliability standards; objective, risk-compliance monitoring, mitigation and enforcement; reducing known reliability risks; identifying and assessing emerging risks; reducing cyber and physical security; and improving its efficiency and effectiveness.

FERC Commissioner Cheryl LaFleur, who attended the meetings, said she supports separating the metrics into two categories but questioned the cybersecurity metric. “Losing load from a cyber incident is a pretty gross standard [for measuring cybersecurity]. There must be leading indicators, [numbers of] incursions or whatever. That’s something that [FERC has] been focused on: … trying to get more data.”

Robb acknowledged that the metric was “anemic” and said NERC is seeking ways to capture other indicative data.

In written comments, the ISO/RTO Council (IRC) supported the bifurcation of the metrics but said tools other than standards and enforcement “needs to be a higher priority” for NERC.

“With steady state standards, efficiency reviews and compliance program enhancements to reduce the compliance burden, NERC must develop alternative methods to effectively address new and evolving reliability concerns without having to undo or jeopardize these past improvements and effective compliance behaviors,” the IRC said, adding that some existing metrics “do not have a direct correlation with NERC programs.”

The IRC also expressed concern over the proposed color choices, saying yellow should be replaced with a “neutral” color to illustrate metrics that are unchanged and satisfactory. “A yellow color is associated with caution or imminent threat and can be misinterpreted,” it said.

The North American Generator Forum, the Northeast Power Coordinating Council, the Cooperative Utility sector, the Canadian Electricity Association (CEA) and the Edison Electric Institute all generally supported the revised metrics.

The CEA called for additional metrics to define an “adequate level of reliability.”

EEI questioned a goal focused on enhancing or proposing new standards. “NERC should consider the use of other tools (e.g., Reliability Guidelines, lessons learned, best practices), in addition to reliability standards, similar to the [electric reliability organization’s] compliance and enforcement philosophy, to efficiently and effectively address reliability and security risk,” EEI said.

Robb said the feedback will be incorporated in the final dashboard model.

Addressing Overlap of CIP, Planning and Operating Committees

Mark Lauby, NERC senior vice president and chief reliability officer, briefed the MRC on a proposal to rethink its committee structure to respond to what he called the “increasing convergence” of subjects overseen by the Critical Infrastructure Protection, Planning and Operating committees.

Lauby said the MRC should consider eliminating those committees and using “mission-driven” task forces that would study an issue, make recommendations and disband when their missions are complete.

Lauby said the current committee structure, in place for more than a decade, is “expensive and time consuming” for NERC members and that the committee “silos” are blurring in part because of new technologies and changing industry models.

Task forces, he said, could ensure the stakeholders have the right subject matter expertise.

Consultant Herb Schrayshuen, representing the Small End‐Use Electricity Customer sector, and Oncor Vice President of Regulatory Affairs Liz Jones, representing the Regional Entity sector, said the committees are necessary for some recurring tasks such as annual reliability assessments. Jones said the PC and OC don’t need to meet quarterly or separately, but “there is value in retaining” them.

NERC said that in addition to Midwest Reliability Organization, the Florida Reliability Coordinating Council, SERC Reliability and Western Electricity Coordinating Council also have reorganized their committee structures.

The Western Area Power Administration’s Lloyd Linke, a member of the MRO board, said he generally supported the change, calling it “somewhat similar to the process that the MRO” has adopted. “When the MRO did this, they did keep some committees … to provide some of that continuity on some of the yearlong type things,” he said.

Carol Chinn, representing the State/Municipal Utilities sector, said the proposal was a good start but “there needs to be much more dialogue” with MRC members before changes are made.

MRC Vice Chair Greg Ford agreed “it is time to look at our committee structure.”

“The right answer may be: Keep the three committees but streamline them,” he said.

NERC plans to create a staff/stakeholder working group reporting to the board to explore the issue further and develop a restructuring proposal.

“Let’s set some sort of a time frame,” NERC Trustee Dave Goulding said, “because this is a project that could go on and on and on and you’ll never get everybody on board.”

Long-Term Reliability Assessment Sees Shortfalls in CAISO, MISO, Ontario

John Moura, NERC’s director of reliability assessments and technical committees, gave a presentation on the draft 2018 Long-Term Reliability Assessment through 2028, noting it is the first such report to include metrics on “essential reliability services” such as frequency response and ramping capability.

Moura said the projected 10-year compound annual growth rate for North America of 0.57% (summer) and 0.59% (winter) is the lowest on record. None of the regions projects annual load growth of more than 2%.

“For the first time, we’ve seen five areas — New York, New England, Maritimes, Manitoba Hydro and the WECC California-Mexico area — actually reducing [their] peak demand over the 10-year period,” he said. “That’s kind of unheard of.”

The report projects MISO and Ontario will see planning reserve margin shortfalls beginning in 2023. In addition, probabilistic evaluations indicate resource adequacy risks in the California and Mexico region of WECC in off-peak hours after the sun sets and during spring and fall maintenance outages. The loss-of-load expectation for the WECC-CAMX region — most of California and a small northern portion of Baja California — is projected to rise from nine hours in 2020 to 95 in 2022.

Although the grid is losing inertia as renewables replace synchronous generation, all interconnections should have adequate frequency response through 2022, the report says.

The report projects the addition of more than 30 GW of distributed solar PV by the end of 2023, when it said California will have 18 GW and Massachusetts and New Jersey will have 4 GW each.

But Moura said the report should be viewed with humility, saying stakeholders should remember that the only certainty about its projections is that they will be wrong. In 2008, he noted, NERC projected a 30 GW increase in coal generation by 2018. Instead, coal capacity dropped by 50 GW. “That was an 80-GW miss,” he said.

It also vastly underestimated the 200-GW increase in natural gas generation, having predicted an increase of only 50 GW.

Update on Western Reliability Coordinators

WECC CEO Melanie Frye provided the board with an update on efforts by CAISO and SPP to replace Peak Reliability as the reliability coordinators (RCs) in the Western Interconnection. (See Western RC Transition ‘Hot Topic’ at WECC Meeting.)

She said officials have identified tie lines that begin in one RC footprint and end in another, including 114 such lines between CAISO and SPP. “So we’re doing some additional technical analysis to try to understand what could be the change in flows in the system if there were to be elements out of service,” she said. “What that’s really highlighted is the need for both RCs in that example to model the broader footprint.”

Robb said he was “very pleased” with NERC’s collaboration with WECC, CAISO, SPP and others to address the transition, but he acknowledged concerns over seams in the desert Southwest.

“There’s the potential for a couple seams to be developed between Phoenix and San Diego. That’s a very important path and has been a very vulnerable path in the West. So, there’s a lot going on to understand issues that that topology creates and how to manage through it,” Robb said.

NERC Chair Roy Thilly said “it appears that everything is being looked at very, very thoroughly.”

FERC-NERC Study on Southern Cold Weather Event

NERC officials did not offer any new details on their collaboration with FERC on a report on the Southern cold weather event in January. (See FERC, NERC to Probe January Outages in MISO South.)

But Robb acknowledged concerns heading into winter 2018/19. “We haven’t completed the inquiry … but there was an awful lot of generation offline during that event, which at least raises the question about whether or not cold-weather preparation is adequate for the circumstances.

“This is the third [winter] in a row that we’ve had some large amounts of generation offline.”

Trustee Approvals

The Trustees unanimously approved:

• TPL-001-5, a response to FERC’s 2013 Order 786, which will require assessments of single points of failure and inclusion of them in future transmission studies. Based on a cost-benefit analysis and industry feedback, NERC decided not to require eliminating single points of failure, said Howard Gugel, senior director of engineering and standards. “The response that most of industry and NERC staff [agreed on] is no … there is some risk that — as long as you know what that risk is — it’s a risk that’s acceptable to have and at least know how that risk can be mitigated.” Gugel said that out of 12,000 misoperation events in NERC’s database since 2011, less than 30 involved three-phase faults, and “we only had 10 instances where a three-phase fault was also associated with a relay failure. We also [asked], of all the events that we’ve seen on the system, do any of those correlate with any of those 10? … We cannot find an instance in the data we have.”
• The standard specifies the types of events and nonredundant protection system components that should be studied. It also eliminates the minimum six-month threshold for including outages in planning studies, which FERC said “could exclude planned maintenance outages of significant facilities from future planning assessments.”
• The retirement of IRO-006-TRE, which is redundant to other reliability standards. The Texas Reliability Entity board approved its retirement in September.
• The Reliability Standards Development Plan for 2019-2021, which focuses on periodic reviews, FERC directives, the Standards Efficiency Review and the standards grading initiative.
• Revisions to sections 600 (Personnel Certification) and 900 (Training and Education) of NERC’s Rules of Procedure. The revisions are in response to a July 19 FERC order (RR17-6) that changes regarding NERC’s training and continuing education programs but rejected deletion of its personnel certification rules. (See “Split Ruling on NERC Rules of Procedure,” FERC Orders Expanded Cybersecurity Reporting.)
• The execution of a memorandum of understanding outlining MRO’s compliance monitoring of Manitoba Hydro.

New MRC Officers, Seeking Canadian Trustee

Trustee Fred Gorbet, head of the board’s Nominating Committee, said a five-person interview team has met with candidates to replace him as the Canadian representative on the board. The team will share its recommendation with the committee Dec. 10 with hopes to install the winner in February 2019, said Gorbet, who is leaving because of NERC’s term limits.

The MRC elected Greg Ford as chair and Jennifer Sterling vice chair for 2019. Ford is CEO of Georgia System Operations Corp., which manages 38 distribution cooperatives and Oglethorpe Power. Sterling is vice president of NERC compliance and security for Exelon.

Retirements for ELCON’s Hughes, NERC’s Roxey

The quarterly Trustee meeting was the last for retiring John P. Hughes, president of the Electricity Consumers Resource Council (ELCON) and NERC’s Tim Roxey, chief operations officer for the Electricity Information Sharing and Analysis Center (E-ISAC).

“I will miss [Hughes’] voice,” LaFleur said. ELCON, which represents industrial customers, has tapped Devin Hartman, formerly of the free-market think tank R Street Institute, as its new chief executive effective Jan. 1. Hughes, who has degrees in engineering and economics, joined ELCON in 1987 and became its CEO in 2015.

Roxey, a former nuclear engineer who began working at the E-ISAC in 2009, received a commemorative resolution and a standing ovation from the approximately 200 stakeholders.

“It has indeed been a long strange trip,” Roxey said. “You cannot have a bulk power system or a distribution system [be] reliable without the support and functioning of all of this,” he said, looking at the dozens of stakeholders in the large hotel ballroom. “I’ve come to understand and appreciate [reliability] standards and compliance — which I used to object to, but I now embrace as a necessary part of the [Compliance Monitoring Enforcement Program]. It is critical … that we be proactive in creating standards because that’s what we do. We don’t have to be told.”