Page 1120 – RTO Insider

April 3, 2020

MISO Deepens Insights into Pandemic Impact

By Amanda Durish Cook

MISO is gradually improving its ability to forecast the more sedate load profiles that have emerged in the face of widespread community measures to halt the COVID-19 pandemic, stakeholders learned Thursday.

The RTO is experiencing lower loads that no longer follow a sharp uptick in demand in the morning or evening, Director of Central Region Operations Ron Arness told stakeholders during a Reliability Subcommittee conference call Thursday.

MISO Pandemic Impact — Ron Arness, MISO | © *RTO Insider*

“We have seen significant shifts in the morning and evening peaks. For instance, the morning peak has shifted from the usual 8 a.m. and 9 a.m. to about 11 a.m. or noon and then it’s not dropping off — and it’s staying steady until it dissipates in the evening,” Arness said. “It’s a more gradual increase. We’re seeing more steady peaks across the day, [and] we’ve not seen that evening bump-up in peak.”

MISO officials initially compared evolving load profiles to weekend usage patterns, but RTO staff now find that a slew of business closures have contributed to lower load than even typical weekend days. (See MISO Loads Down as Region Faces COVID-19 Threat.)

“There have been a lot more closures going on, in restaurants as well as industry. So, it’s not an exact weekend profile, but it’s close,” Arness said. “It’s down slightly — it’s still going down.”

MISO has experienced load forecasting errors for both on- and off-peak periods, Arness said, but he added that forecasters since March 23 have begun more aggressively predicting load shapes based on recent demand tracking and are each day manually inserting them into existing models.

Arness said that while MISO’s load was significantly down in March compared with a year earlier, most of the decline can be attributed to higher temperatures. Peak loads decreased 18% from 2019 and were down 13% from the March five-year average. March’s peak usually breaks just above 90 GW, but last month topped out at 79 GW.

“We believe most of that is due to the temperature,” Arness said.

MISO said the few weeks of load forecast errors have not impacted reliable operations.

“These are unprecedented times, and we’re starting to hone [in on] it and get a little better,” Arness said.

Varying Emergency Responses in Footprint

Arness also said the sheer size of MISO’s footprint means that its uncharted load forecasting doesn’t fit neatly into a new model. He pointed out that states in MISO South have not yet clamped down on gatherings or population movement in the stricter ways that Michigan or Illinois have through industry shutdowns and travel restrictions.

“That’s why we’re still seeing some continued changes in our numbers,” he said.

The Energy and Policy Institute reports that 22 state commissions — including seven in the MISO footprint — have so far ordered utilities to suspend disconnections as the pandemic wears on.

Wisconsin in particular has moved proactively to gauge the economic impact of stay-at-home measures on ratepayers and utilities. The state’s Public Service Commission has opened two new dockets: one to ensure customers can continue to access service, and the other to investigate the costs utilities are incurring under the public health emergency orders. Gov. Tony Evers suspended some of the PSC’s administrative rules so public utilities can waive late fees, halt disconnections, connect residents more quickly and without cash deposits, and offer deferred payment agreements for commercial, farm and industrial customers in addition to residential customers. Utilities are beginning to warn of deferred maintenance and financial impacts. (See AEP Warns of ‘Adverse’ Effects from Coronavirus.)

Northern Indiana Public Service Co.’s Bill SeDoris said his company is checking temperatures of employees before they’re allowed into company offices. He also said NIPSCO has brought in trailers to park on-site as temporary offices for customer service representatives.

“We’re giving them more space so they’re not on top of each other,” SeDoris said.

What Lies Ahead

MISO headed into April with the manual, day-by-day load forecasting in place.

“April is a time when we have big variety in temperatures. But generally, the load is lower,” Arness said.

MISO also plans to hold a summer readiness workshop April 28. It’s not yet clear how the pandemic will affect summer operations.

Arness emphasized that MISO needs ample warning from generators that foresee a need for conservative operations or outage rescheduling. He said MISO continued to observe an uptick in outage deferments over the past week. The RTO last month noted increased deferment of maintenance outages as utility work crews were scaled back as social distancing took hold.

“The plea here — I can’t say this often enough — is that you document the request. We’re really imploring the generation owners and operators to please keep MISO updated in terms of your plans. Please document them in writing,” Arness urged market participants, adding that the RTO needs all relevant information on changes in outage plans to navigate outage scheduling.

Jim Dauphinais, an attorney with the Coalition of Midwest Transmission Customers, asked how MISO was dealing with load-modifying resources (LMRs) that aren’t available with no personnel on-hand to lower load. He also wondered if some LMRs could even be considered deployed because they’re already shuttered because of shelter-in-place orders.

“There might be no demand reduction that would come from a MISO call since load is already reduced,” Dauphinais said, adding that the RTO should examine how LMRs in limbo could impact an emergency declaration.

Rob Benbow, MISO’s executive director of energy operations, asked all LMR owners to update their availability in the MISO Communication System. He said MISO would examine how LMRs that are temporarily unavailable or considered already deployed could impact resource adequacy.

Customized Energy Solutions’ Ted Kuhn asked if MISO is contemplating how it will best manage a return to normalcy once social distancing mandates are lifted and load picks up.

“There’s a good argument that load is going to return, but the question is will it return to those historical levels that we experienced a year ago. That’s a good question, and we’re studying it,” Arness said.

MISO will hold another Reliability Subcommittee meeting April 29, in which COVID-19 impacts will again be discussed.

“Be safe, take care of yourselves and your families,” SeDoris said before ending the call.

April 2, 2020

Industry Pandemic Prep Encouraging, NERC Says

By Holden Mann

NERC says it is confident the electric industry is “taking aggressive steps to confront” the COVID-19 pandemic, based on responses to its recent Level 2 alert.

The alert was sent on March 10 and advised registered entities to maintain situational awareness, reinforce good personal hygiene practices, and review and update business continuity plans. (See Coronavirus, Cybersecurity Top WECC Board Discussion.) It directed recipients to inform NERC by March 20 whether their organizations:

have a written response plan that covers pandemic emergencies;
have reviewed staffing requirements and resources for critical roles in a potential pandemic emergency in North America;
anticipate being able to offer mutual aid to other industry participants involved in a pandemic emergency;
have reviewed supply chains for potential disruption of critical goods and services by a pandemic emergency; and
expect to encounter any specific additional risks to reliable and secure operations in a potential pandemic emergency.

According to a press release, risks identified by respondents include staffing and material shortages, along with delays to major construction and maintenance projects that could create constraints over the summer. The “vast majority” of registered entities reported that they either have a written response plan or are in the process of developing one, while a “large majority” have reviewed supply chain needs.

NERC pandemic — NERC CEO Jim Robb | © *ERO Insider*

More than half said they would support mutual aid requests — which NERC CEO Jim Robb called “a key consideration” during the spring and summer storm season — and the majority said they have reviewed staffing requirements.

NERC said reliability coordinators have “generally” activated their backup control centers, isolated key workers and are maintaining deep-cleaning routines, along with participating in weekly situational awareness calls with NERC. Utilities also remain engaged with the Electricity Information Sharing and Analysis Center, which recently detailed its own COVID-19 operations summary.

Along with ordering the Level 2 alert, NERC has activated its Business Continuity Plan and shifted its upcoming meetings to conference calls or video conferences in light of safety restrictions from global health authorities and travel restrictions by many stakeholders. The organization confirmed last month that an employee in its Atlanta office had tested positive for the COVID-19 virus, though the individual had not visited the office since March 10. (See NERC Employee Tests Positive for Coronavirus.)

In light of the outbreak, NERC and FERC, NERC Relax Compliance in Light of COVID-19.)

NERC will provide its report on industry readiness to FERC as an informational filing. The organization is also working on a comprehensive assessment of potential reliability risks and considerations from the pandemic, scheduled for release in April, that will draw on lessons learned from utilities around the world.

April 2, 2020

FERC Rejects Cost Formula for NJ Merchant Tx

By Michael Yoder and Rich Heidorn Jr.

FERC has ruled that two merchant transmission operators in New Jersey are still liable for some cost allocations under PJM’s Regional Transmission Expansion Plan (RTEP) despite converting from firm to non-firm service after the cancellation of the “Con Ed-PSEG wheel” in 2017 (ER18-680).

In its ruling on Wednesday, FERC said despite the conversion from firm to non-firm transmission withdrawal rights (TWRs) that would limit exposure to future RTEP costs, Linden and HTP were still liable for RTEP costs previously allocated while still under their firm TWR status.

Linden VFT and Hudson Transmission Partners (HTP) own merchant transmission facilities that carried power into New York City as part of the former Con Ed-PSEG wheel, in which 1,000 MW were exported from upstate New York to PJM through Public Service Electric and Gas facilities in northern New Jersey, and then exported to the city. Consolidated Edison and PSE&G canceled the agreement in April 2017, prompting HTP and Linden to convert their firm TWRs to non-firm TWRs.

PJM tariff New Jersey — Linden VFT’s exterior | *Joseph Jingoli & Son*

FERC approved the TWR changes in orders in December 2017 (EL17-90, EL17-84). (See NJ Merchant Tx Operators Win Relief on Upgrade Costs.)

The commission had previously found that merchant transmission facilities with firm TWRs are “like loads in that they remove energy from PJM, thus requiring PJM to study deliverability of energy from the PJM system to the point of interconnection.”

PJM interpreted the December 2017 orders as directing that all allocations to Hudson and Linden cease as of Jan. 1, 2018, and proposed to pro-rate the allocations to the remaining zones. But the commission said Tuesday that the companies should only be relieved from ongoing cost allocations in Schedule 12-Appendix A, which PJM redetermines annually based on the level of firm transmission withdrawal rights. It said the companies remain liable for costs of lower-voltage facilities that use the pre-Order No. 1000 violation-based distribution factor (DFAX) method and economic projects that are allocated on the load energy payment method, which is also fixed at the time the projects are included in the RTEP.

“Our finding here accords with the commission’s prior holding that the merchant transmission facilities remain responsible for targeted market efficiency projects, because these calculations were not based on the level of firm transmission withdrawal, but on the basis of congestion savings,” FERC said. “The merchant transmission facilities continue to benefit from these savings regardless of whether they hold firm transmission withdrawal rights. For these reasons, we reject PJM’s proposal to reassign cost responsibility from Hudson and Linden for the economic projects identified in PJM’s compliance filing.”

FERC ordered PJM to submit a filing within 60 days correcting the allocations.

The New Jersey Board of Public Utilities had protested PJM’s filing, arguing that eliminating the RTEP allocation to HTP and Linden would “result in unduly burdensome costs on PJM customers, particularly in northern New Jersey, at a preference to New York load” and was “particularly egregious in light of the benefits retained by New York load regardless of the character of Hudson’s and Linden’s transmission rights.”

FERC ruled that the BPU’s arguments were “beyond the scope of a challenge to a compliance filing” and that they should instead be raised in a rehearing request, not a protest to the compliance filing implementing that order.

Last month, the BPU appealed FERC’s rulings on Linden and HTP’s TWRs, and the reassignment of Con Ed’s cost responsibility assignments for RTEP projects including the Bergen-Linden Corridor project, to the D.C. Circuit Court of Appeals.

Rehearing Denied

In a related ruling Tuesday, the commission rejected rehearing of its March 2018 ruling accepting PJM’s annual cost responsibility assignments for regional transmission facilities and lower-voltage facilities included in the RTEP for 2018 (ER18-579-002).

PJM transmission owners American Electric Power, Dayton Power and Light, Dominion Energy, Exelon, FirstEnergy, PPL and PSE&G challenged PJM’s decision that Linden and HTP should not have a cost assignment for Schedule 12-Appendix A projects for 2018.

“PJM transmission owners advance no argument on rehearing to explain why merchant transmission facilities must be responsible for cost allocation assignments for a year in which they hold no firm transmission withdrawal rights,” the commission said.

The commission also dismissed as moot Dominion’s rehearing request over PJM’s initial assignment of 100% of the costs of the Loudoun-Brambleton 500-kV and 230-kV lines (project b2372) to the Dominion zone.

FERC noted that PJM responded to Dominion’s original protest by conceding the utility was correct and that the project should be allocated as a regional facility needed for reliability, with 50% of costs allocated via the load-ratio share and 50% using the solution-based DFAX. PJM filed a modified allocation assigning two-thirds of the costs to the Dominion zone and one third to the APS zone, which FERC accepted in August 2018 (ER18-2028).

April 2, 2020

Danly Sworn in; Morenoff Named Acting General Counsel

By Michael Brooks

James Danly was sworn in as a FERC commissioner Tuesday, officially beginning a term to end in 2023 and giving Republicans a 3-1 advantage on the commission.

Danly, who had been serving as general counsel for the commission since September 2017, was sworn in by 6th U.S. Circuit Court of Appeals Judge Danny J. Boggs, for whom he once served as law clerk.

“I’m so glad to have James join my colleagues and me as a commissioner, particularly as FERC is dealing with many pressing issues related to the COVID-19 pandemic in addition to continuing the important work of the agency,” FERC Chairman Neil Chatterjee said. “The commission and the American people will benefit from Commissioner Danly’s viewpoint on the many issues that we now have before us.”

FERC Danly — Judge Danny J. Boggs swears in former FERC General Counsel James Danly as a commissioner as his wife, Frankie, looks on. | *FERC Chair Neil Chatterjee*

“Welcome to FERC Commissioner James Danly! I look forward to working with him in his new capacity,” tweeted Commissioner Richard Glick, the lone Democrat.

“Congratulations to James Danly on being sworn in as a commissioner at FERC,” Commissioner Bernard McNamee tweeted. “He has been a valued adviser while general counsel and will be a great colleague on the commission.”

The U.S. Senate confirmed Danly’s nomination to the commission March 12. (See Senate Confirms Danly to FERC.) He fills a seat left open by the death of Commissioner Kevin McIntyre in January 2019. McNamee, whose term ends June 30, has said he would stay on until a replacement for his seat is confirmed or the end of the year.

To replace Danly — at least temporarily — Chatterjee named Deputy General Counsel David Morenoff as acting general counsel.

“David is a consummate professional and outstanding lawyer,” Danly said. “I have relied on his wise counsel since the beginning of my tenure at FERC. I appreciate his willingness to accept this role and am confident that he will provide much-needed continuity during these difficult times.”

April 2, 2020

FERC Approves NorthernGrid Merger

By Hudson Sangree

FERC on Tuesday gave its blessing to the merger of Columbia Grid and Northern Tier Transmission Group to form NorthernGrid, a vast transmission planning region stretching across eight Western states (ER20-882, et al.).

The commission approved the latest revisions to the transmission tariffs filed by NorthernGrid’s seven members: PacifiCorp, NorthWestern Energy, Avista, Puget Sound Energy, Idaho Power, MATL and Portland General Electric.

All the “filing parties’ proposed tariff revisions are hereby accepted, effective April 1, 2020,” FERC wrote.

In late December, FERC had sent the latest round of proposed tariff changes back to the parties, agreeing with independent transmission developer LS Power that the utilities failed to meet Order 1000’s requirement to show the new transmission planning region would do better than the status quo. (See F ERC: NorthernGrid Merger Needs More Work.)

NorthernGrid Merger — The proposed NorthernGrid regional planning organization would consolidate the areas covered by ColumbiaGrid and Northern Tier Transmission Group. | *ColumbiaGrid*

FERC also said more information was needed to show the tariff revisions complied with Order 1000’s principles of openness and coordination in transmission planning.

A major sticking point raised by LS Power was that the tariff changes, as drafted, would have required developers to submit proposed projects before the regional planning process identified transmission needs.

FERC agreed. “We find that this structure deprives developers and stakeholders of a sufficient opportunity to propose solutions in response to needs identified through the regional transmission planning process,” the commission wrote, rejecting the proposal without prejudice and inviting the parties to refile after correcting deficiencies.

The parties filed their proposed revisions to their respective Open Access Transmission Tariffs on Jan. 28.

Among the changes, the parties “added a new 60-day window after posting [a regional transmission needs] draft study scope for stakeholders to submit additional data,” FERC said. The change “provides a meaningful opportunity for transmission developers to submit project proposals after enrolled party needs have been identified.”

LS Power again protested, saying the 60-day window failed to address the concerns it raised, and with which FERC agreed, before.

FERC rejected the argument, saying developers would have opportunities to propose projects in accord with Order 1000.

“We … find that the proposed regional transmission planning process complies with Order No. 1000’s requirement to conduct a regional analysis to identify whether there are more efficient or cost-effective transmission solutions to regional transmission needs,” FERC wrote.

That includes “an affirmative obligation to analyze whether such transmission solutions exist regardless of whether potential transmission solutions have been proposed by transmission developers or stakeholders,” it said.

April 2, 2020

FERC: SPP Withdrawal Deposit not Membership Barrier

By Tom Kleckner

FERC on Monday clarified that non-transmission owning members of SPP are still subject to a $50,000 deposit for if they withdraw from the RTO, rejecting environmental organizations’ complaint that the deposit constitutes a barrier to membership (EL19-11).

The organizations — Advanced Power Alliance (APA), Clean Grid Alliance, Climate + Energy Project, Natural Resources Defense Council, Sierra Club, Southern Renewable Energy Association, Sustainable FERC Project and Western Resource Advocates — filed a request for clarification in early February following FERC’s rejection of SPP’s request for rehearing of the commission’s decision to end the RTO’s exit fee for non-transmission owners. They objected to what they called the commission’s “reinstatement” of the $50,000 deposit in its December order. (See FERC Denies Rehearing of SPP Exit Fee Decision.)

FERC reminded the groups that it had ruled that non-TOs “should only be exempt from paying a share of SPP’s long-term financial obligations, rather than all existing obligations associated with membership withdrawal.” The deposit represents the costs SPP would incur to process a member’s withdrawal from the RTO, while the fee represents the sum of the withdrawing member’s share of SPP’s outstanding long-term financial obligations and its obligations at the time of withdrawal, including any unpaid dues or assessments.

FERC SPP — FERC headquarters | © *RTO Insider*

The commission also rejected their arguments that the deposit requirement represents a barrier to membership and is unjust and unreasonable. FERC also said the groups missed the 30-day deadline following a commission decision to file a request for rehearing and ruled their motion as a late-filed request.

APA and the American Wind Energy Association filed the initial successful complaint that resulted in FERC last April ordering SPP to end charging an exit fee for members that are not TOs or load-serving entities. (See FERC Tells SPP to End Exit Fee for Non-TOs.) SPP had estimated the fee could amount to as much as $630,000 for entities without load.

In December, FERC rejected a rehearing request by SPP and its LSEs, along with the RTO’s proposal to lower the exit fee to $100,000. It ordered the grid operator to submit another proposal “that adequately explains” why the exit fee for non-TOs is just and reasonable and “not a barrier to membership … and not excessive as a means of ensuring stability in membership and members’ financial commitment.”

April 2, 2020

MISO Contemplates ‘DER Balance Problem’

By Amanda Durish Cook

MISO is stepping up efforts to understand how its markets will function with the possible participation of heavy concentrations of distributed energy resources.

The RTO is researching how to manage DER aggregators in its market, DER Program Director Kristin Swenson said during a joint workshop between MISO and the Organization of MISO States (OMS) on Tuesday.

The workshop was held over telephone — rather than in person — because of the COVID-19 pandemic.

“I’m leading a virtual MISO stakeholder workshop upstairs while my wife leads a virtual yoga class downstairs. A lot of ‘virtuality’ these days,” MISO Managing Assistant General Counsel Michael Kessler remarked as he began his presentation.

Swenson said the MISO market platform’s computational abilities cannot handle the addition of several thousand small, distributed resources. She also noted that broad DER aggregation across multiple nodes is difficult to manage from an operations standpoint. The RTO may be unable to handle some issues if it doesn’t precisely know the physical location of some aggregated resources, she said.

“You may not be able to solve the transmission or reliability issues without visibility from an aggregator,” Swensen explained. “That’s what we call the DER balance problem.”

MISO Distributed Energy Resources — Hoosier Energy Power Network Solar Power Plant in Bloomington, Ind. | *Inovateus-Solar*

MISO last held a DER workshop in February, in which it focused on transmission planning challenges as the distribution system takes on more generating resources. (See MISO Mapping Out DER Challenges, Benefits.)

Energy storage may assist in the balancing act. FERC Order 841 mandated RTOs facilitate participation for storage resources over 100 kW located on distribution systems. In response, MISO created a contract in its Tariff to coordinate with distribution utilities that host storage resources.

But a legal challenge to Order 841 is currently pending before the D.C. Circuit Court of Appeals. Opponents of the order, which include the National Association of Regulatory Utility Commissioners and traditional utilities, are suing to block FERC’s ability to mandate DER participation in wholesale markets and seeking an opt-out mechanism for states.

“We’re still waiting to see what the states’ authority will be and what FERC’s jurisdiction will be over storage resources located on the distribution system participating in wholesale markets,” Kessler said.

In addition, FERC’s 2016 Notice of Proposed Rulemaking on the participation of DER aggregation in wholesale markets is still outstanding.

Working Through the Tension

Swenson said MISO’s work with OMS on DERs began in preparation for a federal rulemaking on DER participation.

OMS Executive Director Marcus Hawkins said the increasingly blurred lines between state and federal jurisdiction “has created tension.” He said a DER participation model must respect the “primarily vertically integrated nature of the MISO footprint.”

“Whatever the eventual market model is, it should reflect that fact,” Hawkins said.

Hawkins said a significant number of aggregators selling at the wholesale level could disrupt state-jurisdictional resource adequacy planning.

“There’s just a lot of coordination required when a DER wants to participate in the wholesale market,” Hawkins said, adding that OMS wants to avoid double-counting when a resource on the distribution system participates at both the wholesale and retail levels. However, he said MISO, utilities and states should not all rush to invest in technology that’s ultimately “redundant” in order to gain visibility into DER operations.

“We’ve been fighting against wasteful technology to do that,” Hawkins said.

Swenson said MISO will survey members in mid-April on how they currently communicate with DERs, what investments they have made to improve communications and what approaches they would recommended.

“We’re trying to get a good impression of where folks are in communicating with DERs as MISO prepares to communicate with more resources. Where should MISO be focusing?” Swenson said.

Swenson stressed that the new survey is separate from the annual OMS survey on DER totals in MISO.

Independent Market Monitor staffer Michael Chiasson said the monitoring of DERs isn’t a concern for now. DERs and demand response “typically lack the size and concentration needed to have significant market power,” he said.

However, Chiasson noted, DERs could help lessen the market power wielded by large, traditional generators in load pockets constrained by transmission limitations.

“It’s a good structural thing to have more market participants,” Chiasson said.

Chiasson said if the Monitor eventually discovers that DERs could exercise market power, it could propose to FERC under Federal Power Act Section 205 to adjust the application of market mitigation.

“A lot of market rules evolved that way,” Chiasson said.

April 2, 2020

FERC Extends NERC Compliance Filing Deadline Again

By Holden Mann

FERC on Thursday granted NERC another extension on the deadline for two compliance filings ordered earlier this year so that the organization can focus on its response to the COVID-19 pandemic (RR19-7). The commission ordered the filings Jan. 23 in response to NERC’s five-year performance assessment.

One filing, originally due April 22, required the ERO to detail any audits it has conducted of regional entities during the past five years, or a plan for performing them within the next 18 months. (See NERC Wins Another 5 Years as ERO.) Last month FERC moved the due date of this filing to May 1, acknowledging that responding to “the emergency conditions related to … COVID-19” should be a higher priority for NERC. This week’s order pushes the deadline “to and including June 1.”

NERC Compliance Filing Deadline — NERC headquarters in Atlanta | © *ERO Insider*

The second filing, initially ordered for July 21, demanded a number of revisions to NERC’s Rules of Procedure (ROP), such as updating terminology regarding the Electricity Information Sharing and Analysis Center (E-ISAC); providing greater transparency in its sanction guidelines; and making various improvements to its certification program. FERC last month approved a request by NERC to delay the filing until Aug. 28, which the ERO said would give more time for stakeholder comment and review by the Board of Trustees. (See FERC Approves NERC Rule Change Extension.) The new deadline for the filing is Sept. 28.

Progress Seen in Pandemic Prep

NERC has been working to assist with industry response to the pandemic, including by issuing a Level 2 alert last month and publishing a document titled “Assessing and Mitigating the Novel Coronavirus (COVID-19)” on the Electricity Subsector Coordinating Council’s website. Earlier this week, NERC described the industry as “taking aggressive steps” in response to the pandemic, with most utilities either having a written response plan or currently developing one, and a majority pledging to support mutual aid requests from others involved in a pandemic emergency. (See Industry Pandemic Prep Encouraging, NERC Says.)

The organization’s internal response includes activating its Business Continuity Plan and shifting its upcoming meetings to conference calls or video conferences. This week NERC announced that the E-ISAC’s annual security-focused conference GridSecCon, scheduled for Oct. 20-23, would be canceled. Representatives told ERO Insider that attendees’ commitments to pandemic response made confirming conference details difficult, and it seemed “more prudent” to call the event off completely.

NERC and FERC have also taken steps to relax compliance burdens for utilities through the use of regulatory discretion. Regulatory easing so far is limited to delays in obtaining and maintaining personnel certification, failure to perform required periodic actions and postponing on-site activities such as audits and certifications. (See FERC, NERC Relax Compliance in Light of COVID-19.) NERC has updated the website for its Compliance Monitoring and Enforcement Program (CMEP) with a list of frequently asked questions related to these changes.

April 2, 2020

Former NERC Vice Chair Scherr Dies at 72

Bruce Scherr, a former NERC vice chair and member of SPP’s Board of Directors, died on March 29, according to a NERC press release. He was 72 years old.

Scherr served on NERC’s board from 2002 to 2015. In addition to serving as vice chair, at various times he chaired the Finance and Audit and Compliance committees, and was also a member of the Standards Oversight and Technology Committee and the Nominating Committee. Since he joined SPP’s board in January 2016, Scherr had served on the Finance Committee — becoming its chair in 2018 — and the Oversight Committee, as well as on the Value and Affordability Task Force.

Outside of his roles with NERC and SPP, Scherr served on the boards of E. Ritter & Company, Santa Energy and J.D. Heiskell & Company. He was also an adviser to the Council of Economic Advisers and NASA.

“Bruce was a dedicated and tremendously talented member of our Board and a good friend,” NERC board Chair Roy Thilly said. “The thoughts and prayers of the entire NERC family go out to Bruce’s family during this difficult time.”

In a separate statement, SPP CEO Barbara Sugg said Scherr “gave 100% to SPP and always had our best interests in mind.”

“His financial and executive leadership experience afforded Bruce a unique and valuable perspective regarding our business,” she added.

Scherr’s family conducted a private service on Wednesday in Florida; a larger memorial will be held later this year. NERC did not disclose the cause of death.

– Holden Mann

April 2, 2020

FCC Sets April 23 Vote on Opening 6-GHz Spectrum

By Holden Mann

The Federal Communications Commission has scheduled a vote for its April 23 open meeting on draft rules that would open the 6-GHz wireless spectrum — currently available only to licensed operators — to unlicensed users. However, utilities remain concerned about the potential for disrupted operations.

The commission began considering opening the 6-GHz spectrum in 2017 and issued a Notice of Proposed Rulemaking in 2018 in response to growing demand for wireless broadband access by consumer devices and a congressional directive to identify additional spectra (18-295, 17-183). By some estimates, North American mobile traffic, including unlicensed Wi-Fi devices, is projected to grow nearly 35% annually through 2021.

Advocates of opening up the 6-GHz spectrum include FCC Chairman Ajit Pai, who said in a press release Wednesday that making the spectrum (5,925 to 7,125 MHz) available to consumer devices would “effectively increase the amount of spectrum available for Wi-Fi almost by a factor of five.” Electronic device makers such as Apple, Cisco Systems, Google and Qualcomm — along with wireless companies — have been vocal in their support for allowing unlicensed use of the spectrum in the hopes of easing congestion on existing frequencies, particularly from Internet of things (IoT) devices.

Measures to Prevent Interference

But electric utilities currently use the spectrum for point-to-point microwave links providing communications with substations, fault sensors, two-way meters and service crews. It is also used to provide situational awareness in rural areas where wired networks are not available. Other critical infrastructure such as police and fire dispatch, railroads, and natural gas and oil pipelines also use the spectrum. These users have expressed concern on numerous occasions about the danger of interference with their communications from consumer equipment. (See Utilities Warn of Encroachment on Communications Band.)

FCC 6-GHz Spectrum — Microwave relay dish

The proposed rule change, which Pai called the commission’s “boldest initiative yet” and a “huge benefit to consumers and innovators across the nation,” represents a partial concession to these fears. It would authorize two types of unlicensed operation in the band: a standard-power mode covering 850 MHz of the available range and indoor low-power operations across the full 1,200-MHz spectrum.

The plan would require that standard-power mode use automated frequency coordination (AFC) to avoid interfering with existing services. Utility representatives described the measure as a good start that needs expansion.

“While we appreciate the FCC proposing to require AFC for the standard-power access points, these measures must also be applied to all unlicensed devices in the band to prevent interference to mission-critical utility communications systems,” Sharla Artz, senior vice president of government and external affairs for the Utilities Technology Council (UTC), said in a statement. “We have and will continue to engage with the FCC and interested stakeholders to develop technical requirements that adequately protect critical infrastructure incumbents and allow unlicensed operations to use in the band.”

UTC’s recommendation was echoed in a filing by the National Public Safety Telecommunications Council (NPSTC), citing numerous cases in which unlicensed equipment operating at 5 GHz have interfered with higher-priority authorized services. NPSTC observed that similar situations could easily occur if consumer use of the 6-GHz band becomes more widespread without universal application of AFC, even to low-power devices.

A separate planned NOPR would allow very low-power hardware to operate across the 6-GHz spectrum as well and is intended to facilitate performance by high-bandwidth applications such as wearable technology, virtual reality and augmented reality. The FCC plans to request comment from industry on technical aspects of the proposal, including power levels and operational measures to prevent interference with existing services.