NYISO may shift 500 MW of the statewide reserve requirement to Southeastern New York (SENY) in order to boost resource flexibility and provide ready access to resource capability following a contingency event, ISO officials said Monday.
The proposal would not change the New York Control Area’s 2,620 MW of 30-minute total reserves but would add to the existing 1,300 MW of reserves in SENY, the Installed Capacity/Market Issues Working Group (ICAP-MIWG) heard during a teleconference.
However, the proposal would not add to the existing reserve requirements currently applicable to Zones J and K covering New York City and Long Island, respectively. The proposal seeks to increase the current 30-minute reserve requirement for the broader SENY region, which encompasses Zones G through K. The proposal would also reduce the NYC real-time reserve requirements to zero megawatts during thunderstorm alerts (TSAs).
“The proposal here is to have a reserve requirement that allows us to bring transmission facilities back to normal transfer criteria following a contingency,” said Ethan Avallone, the ISO’s technical specialist in energy market design, who presented the analysis on reserves for resource flexibility.
The proposal is based on the current system topology. However, it was acknowledged that NYISO continually evaluates its reserve requirements to account for material system changes.
“In the future, if we have to reevaluate the requirement to account for anticipated transmission upgrades, or after any large change to transmission, we would still look to procure enough reserve to bring transmission facilities back to normal transfer criteria in that case,” Avallone said.
Market Mechanics
Absent procuring the proposed additional SENY reserves, the ISO could at times need to use out-of-market actions to return transmission facilities to normal transfer criteria, Avallone said.
The additional reserve would be procured at all times in the day-ahead and real-time markets.
“Up until this point, the reserve requirement for SENY is designed to allow the ISO to take the system back to emergency transfer criteria, and if the system doesn’t recover post-contingency, out-of-market actions may potentially be taken to bring the transmission facilities back to normal transfer criteria,” he said.
Couch White attorney Kevin Lang, representing the city of New York, asked how often the ISO has needed to resort to out-of-market actions for such cases. The ISO did not have immediate access at the meeting to the specific data to quantify the frequency. The ISO was asked to provide such data as part of future discussions related to the proposal.
“You’re looking at procuring these additional reserves on an ongoing basis, so there’s a payment required for that from Zone J,” Lang said. “If you’ve only been required to use out-of-market actions once a year or once every two or three years, then there isn’t a justification for increasing these costs to Zone J and adding this new requirement, even though it’s just shifting the location for procuring reserves from NYCA to SENY.”
| NYISO
The ISO needs to demonstrate a reason to increase the reserve requirement to SENY, Lang said. Without knowing how many times the grid operator has needed to resort to out-of-market actions, market participants “have no way of knowing whether this is really necessary, or whether this is just a hypothetical concern,” he said.
“We look at this proposal as a market-based way to reflect the flexibility operators are looking for on a reliability basis into the market,” Avallone said.
Aaron Breidenbaugh of Luthin Associates, who represents a group of nonprofit institutional customers known as Consumer Power Advocates, echoed Lang’s concern.
“Right now, with what’s going on in New York City and what’s going on in our state, this isn’t the time to start layering more costs on New York City customers,” Breidenbaugh said.
Mark Younger of Hudson Energy Economics suggested that the ISO not look at the data only in terms of what percent of the time the ISO had to take out-of-market actions to secure the transmission, but what portion of time there was a contingency that required action by the ISO.
“Contingencies are rare,” Younger said. “We have reserves to make sure we can operate when contingencies happen, so looking at it in terms of all time is not the appropriate way to do it.”
Consumer Impact Analysis
In addition to estimating potential energy market impacts, the NYISO will estimate both the potential short-term and long-term capacity market impacts of the proposal using revised reference prices calculated for the 2020/21 capability year ICAP demand curves, said NYISO Senior Manager and Consumer Interest Liaison Tariq N. Niazi.
He presented an outline of the methodology to be used in a consumer impact analysis of the proposed change in SENY reserves.
Niazi assured stakeholders that the results of the consumer impact analysis would be presented before seeking approval before the Business Issues Committee and Management Committee. “So just in case we have to revise the analysis, I think there should be time. … We actually seek to present the impact analyses at least 30 days before seeking a vote at BIC,” he said.
A Dec. 2018 transformer explosion at a Con Edison substation in Queens, NY caused a power outage at LaGuardia Airport. | Con Edison
The ISO also will evaluate reliability and environmental impacts, as well as the impact on transparency as part of its consumer impact assessment. In terms of the future timeline, if the proposal obtains stakeholder approval, the ISO would seek to begin developing the necessary software in 2021 to facilitate implementing the proposed enhancements in 2022.
Pallavi Jain, a NYISO market design specialist, presented a related project to revise ancillary services shortage pricing.
The shortage price for the current 1,300-MW SENY 30-minute reserves is $500/MWh, and the ISO proposes a shortage price value of $25/MWh for the 500-MW increase in the SENY 30-minute reserve requirement.
The ISO has proposed to increase the initial $25/MWh shortage pricing value for these additional SENY 30-minute reserves to $40/MWh upon implementation of the subsequent proposed enhancements related to the separate ongoing effort to reevaluate the current reserve shortage pricing values for all products and locations. However, for the reserve requirements applicable to Zones J and K, the ISO is not proposing to increase the current $25/MWh shortage pricing value due to the limited number of eligible suppliers in New York City and Long Island, respectively.
The Illinois Commerce Commission’s “NextGrid: Illinois’ Utility of the Future” study, which began with grand hopes three years ago, ended with barely a whimper Friday.
“A lot of eyes are on Illinois,” said then-FERC Commissioner Rob Powelson at the NextGrid kickoff in September 2017. “I’m bullish.” | Commonwealth Edison
“A lot of eyes are on Illinois as an early adopter,” then-FERC Commissioner Robert Powelson told an audience of more than 400 stakeholders at the NextGrid kickoff event at the University of Illinois at Chicago’s Dorin Forum in September 2017.
“This is really a terrific opportunity for the ICC and the state of Illinois to lead the nation in terms of the thinking around what the grid is going to look like in the next 10 to 15 years,” said then-ICC Chair Brien Sheahan.
But Sheahan lost his chairmanship and then saw his term expire before his legacy project was complete. And on Friday, the ICC quietly agreed to settle a lawsuit that claimed Sheahan had allowed Commonwealth Edison and Ameren, the state’s two dominant distribution utilities, to exclude some consumer advocates and others from participating in the study.
Although the ICC did not admit wrongdoing in the settlement, it agreed to pay $220,000 in plaintiff legal fees and to add a disclaimer that the study is “not a consensus document, and it is not intended to advise or guide legislators, regulators or other policymakers, or to otherwise be used as a basis for legislation, regulation, policy or ratemaking.”
The disclaimer appears to be moot, however: “The ICC will not be releasing the study,” spokeswoman Vicki Crawford told RTO Insider.
A Case Study in Regulatory Capture
While the study may be a dead letter, Sheahan’s stewardship of NextGrid could provide lessons for public policy classes on the subject of regulatory capture. The ICC’s disavowal of the report also leaves uncertainty about the state’s plans for addressing issues such as vehicle electrification, energy storage and ratemaking. Crain’s Chicago Business headlined its story on the settlement: “Plaintiffs win unusual concession from ICC: Please disregard our report.”
Then-ICC Chair Brien Sheahan at the NextGrid kickoff event in 2017 | Illinois Commerce Commission
The Illinois Public Interest Research Group’s (PIRG) Education Fund and GlidePath, an energy storage developer and independent power producer, sued Sheahan and the ICC in June 2018, complaining they had been excluded from NextGrid working groups.
The suit also accused Sheahan and the ICC of violating the Illinois Open Meetings Act by refusing to allow the public to attend working group meetings. Days after the suit, the ICC admitted that its meetings did not comply with the law and agreed to open meetings going forward. (See Groups Sue ICC over NextGrid Study Process.)
Utilities Dominated Membership
Although the commission had publicly invited applicants to volunteer for the seven NextGrid working groups, the plaintiffs said depositions and discovery showed that ComEd and Ameren worked with Sheahan to determine which companies and individuals would be allowed to participate. ComEd, a PJM member, serves 4 million customers in Chicago and Northern Illinois; Ameren Illinois, a MISO member, serves 1.2 million electric customers in Central and Southern Illinois.
Of the 196 task force members, 19 were from the utility sponsors: nine each from Ameren and ComEd, and one from ComEd parent Exelon, according to a count by RTO Insider. No other organization had more than four representatives.
Interestingly, Sheahan’s three-page introductory letter, which described the purpose of the study and the roles of the participants, made not a single mention of Ameren or ComEd.
“The documents in this case show a state regulator working to benefit the very utilities it should be regulating by cherry-picking utility-friendly participants and excluding those that would challenge the utilities’ control,” GlidePath founder Dan Foley, a former ComEd risk manager, said in a statement Friday.
“When utilities are allowed to shape energy policy and regulation, the public suffers,” said Abe Scarr, executive director of Illinois PIRG.
Scarr said PIRG agreed to sue after it, like GlidePath, was initially blocked from participating in the working groups.
“We have been one of the most outspoken utility critics in the state. Our positioning in the policy debate had taken a stronger line than even some of the other consumer groups,” he said, noting that PIRG opposed the 2016 Future Energy Jobs Act, which the state’s Citizens Utility Board and major environmental groups joined ComEd in supporting. In addition to increasing energy efficiency requirements and creating a community solar program, the act authorized $2.4 billion in zero-emission credits (ZECs) for Exelon’s Clinton and Quad Cities nuclear units.
Foley had clashed with ComEd in 2014 over the utility’s fees for its “Smart Grid Test Bed,” and in 2017, he challenged its application to construct a microgrid in the Bronzeville area of Chicago.
When the lawsuit was filed, Crawford, the ICC spokeswoman, denounced it as “frivolous.”
She had a different message Friday, after the commission voted unanimously to approve the settlement.
“The current administration had no part in the formation or implementation of the NextGrid process and inherited this legacy litigation,” she said. Sheahan, who had been appointed by former Republican Gov. Bruce Rauner, was replaced as chairman in April 2019, when Democratic Gov. J.B. Pritzker tapped current Chair Carrie Zalewski. His term expired in January 2020.
Crawford said the commission approved the settlement “so that ICC efforts and resources may be better spent dealing with our response to the COVID-19 pandemic and other emergent issues. The commission is committed to fortifying openness and transparency as we move forward.”
Sheahan declined to comment. “Unfortunately, I cannot comment while the litigation is pending, but I would be happy to discuss after the case is finally resolved,” he told RTO Insider on Saturday.
Sheahan’s ‘Pet Project’
The ICC approved the NextGrid study in a resolution in March 2017. Although it was to be led by facilitators from the University of Illinois at Urbana-Champaign, it was to be funded by ComEd and Ameren.
Peter Gray, a spokesman for GlidePath, said attorneys in the case would not release documents obtained during discovery. But he shared some of the highlights, including testimony by the head of a local business group who said Sheahan told him, “I choose the participants in the working groups, and [your chosen representative] will not be allowed to participate.”
Gray said ICC attorneys acknowledged that commission staff met with ComEd and Ameren representatives to select the working group facilitators and advisors. Staff testified that ComEd objected to the participation of specific employees from independent energy businesses, Gray added.
ICC staff also testified that they were directed by Sheahan to disconnect the phone line of an individual during a working group meeting.
Ameren and ComEd did not respond to requests for comment Friday.
The lead facilitators for the study were UIUC professors George Gross, a Ph.D. in electrical engineering and computer sciences, and Peter Sauer, a Ph.D. in electrical engineering. Sauer did not respond to a request for comment.
Gross said in an interview that he and Sauer worked with Sheahan and two ICC staffers to select the working group members. He said he worked to ensure a diversity of interests, including the American Petroleum Institute on a panel discussing electric vehicles, and technology experts in addition to regulatory “policy wonks.”
“I think [the report is] a very complete and thorough representation of all the views that were aired. We didn’t try to hold back anything,” said University of Illinois electrical engineering professor George Gross, one of the lead facilitators for the project. | Commonwealth Edison
“We basically met and talked about the candidates and then we came up with a list,” Gross said. “The chair had two assistants put full-time on this. … I’m sure the chairman was informed about all of those developments because he took a personal interest in this. This was basically his pet project, and he was shepherding it through.”
Gross said he did not recall Ameren or ComEd making any comments about the composition of the working groups and had no knowledge if Sheahan gave the companies veto power.
“They did not veto anything I did,” he said. “The contract said the veto power came from the commission. The commission had to bless with their holy water the work that we did.”
Despite the controversy, Gross said, “I thought we had a very good representative segment of the industry. … I think [the report is] a very complete and thorough representation of all the views that were aired. We didn’t try to hold back anything. This was not supposed to be a consensus document.”
The seven working groups looked at subjects including new technology deployment and grid integration, metering, electricity markets and environmental issues. After more than 40 meetings over 21 months, the ICC opened the final draft report to public comments on Dec. 14, 2018, with plans to release the final report a month later. But the plaintiffs won an injunction from the Cook County Circuit Court preventing the release until the litigation was resolved.
The disclaimer the ICC agreed to states in part: “This report was funded by Commonwealth Edison and Ameren at a cost to the ratepayers of Illinois. The contract executed as part of the process states that the report is to be compiled for the ICC, under the direction of Commonwealth Edison and Ameren, and requires prior review by Commonwealth Edison and Ameren to be deemed complete.”
Reports Paved Way for Utility Spending
Reports like the NextGrid study have been used to justify several major spending initiatives that benefited ComEd and Exelon. In 2014, the ICC and other state agencies prepared a report on potential nuclear plant retirements that helped build support for the ZEC subsidies.
Then-Commonwealth Edison CEO Anne Pramaggiore was promoted to CEO of Exelon Utilities the year after the NextGrid launch. She abruptly retired last October, less than a week after the company disclosed it had been subpoenaed in an FBI pay-for-play investigation involving state legislators. | Commonwealth Edison
In 2010, the Statewide Smart Grid Collaborative issued a report that provided the foundation for the Energy Infrastructure Modernization Act, which authorized ComEd and Ameren to spend $3.2 billion over 10 years for upgrades, distributed automation and smart meter implementation. The spending was done under a streamlined formula rate process to reduce regulatory lag and allow quicker inclusion of costs into rates. The rate of return on equity, incentive compensation, rate-case expense and other variables were set in advance. ROEs could be reduced for failing to meet performance targets.
An analysis by Scott Madden management consultants after the first six annual formula rate filings concluded that the utilities had increased their earnings despite below-average ROEs. It said ComEd and Ameren Illinois’ rate bases had increased by 34% and 24%, respectively, boosting their authorized earnings by 16% and 6% since 2012.
PIRG’s Scarr said he believed ComEd hoped to use the NextGrid report to justify additional smart grid investments and to extend the formula ratemaking.
“They seemed to make headway until mid-May 2019,” he said, when news broke of an FBI investigation into “pay-to-play” allegations involving state House Speaker Mike Madigan and lobbyists for ComEd and Exelon. Last October, Exelon Utilities CEO Anne Pramaggiore — who had been a featured speaker at the NextGrid kickoff as ComEd’s CEO — abruptly retired, less than a week after Exelon disclosed it had been subpoenaed in the probe. (See Exelon Pledges Reforms amid Grand Jury Probe.)
“Had the study been published,” Scarr said, “they would have used that to say, ‘Here’s all this stuff we need to do. That’s why we need to continue regulatory treatment.’”
Three Recommendations
The final draft report made three main recommendations, at least two of which could result in new revenue streams for ComEd and Ameren if they are endorsed by the ICC.
In addition to calling for enhanced privacy protections in response to the growing digitalization of the grid, the report urged an expansion of EV-charging infrastructure to address climate change and “to maintain Illinois’ leading position in grid modernization.”
“For many years now, a major causal factor of the slow growth in EV sales has been tied to the lack of an adequate EV-charging infrastructure,” it said. “There is a need to put an end to this chicken-and-egg syndrome so that the rapid adoption of EVs can proceed in order to remove the millions of polluting fossil-fueled internal combustion engine vehicles from the roads.”
The report also bemoaned the “slow pace” of energy storage resource (ESR) development in Illinois, saying the need for storage is increasing with the rising penetration of renewable energy resources in the distribution network.
“There is the opportunity to formulate meaningful incentives for utilities or other entities” to install storage, it said, adding that the ICC “can play a leadership role” in increasing ESR deployment.
The report did not, however, endorse continuation of Ameren’s and ComEd’s formula rates, which have been extended twice beyond their initial sunset in 2017. The current extension ends in 2022.
“Some contend that utility customers have benefited from formula rates through improved resiliency and stable rates [while maintaining the ICC’s ability] to review the prudence of all costs included in customer rates,” the report said. “There is a contention by others that rate stability has been due primarily to wholesale power costs, not delivery-service rates, which are the only component covered by formula rates. …
“Some stakeholders expressed concerns that formula rates have allowed utilities to pass through costs without adequate review, and that utilities are effectively guaranteed their authorized rate of return. In effect, they argue that formula rates have shifted risks from utility shareholders to customers. This was an issue over which different [working group] members strongly disagreed.”
The Midwest requires a more comprehensive approach to transmission planning to meet the region’s varied goals, industry experts said last week during a Mid-Grid virtual meetup.
The Midwestern Governors Association (MGA) formed the Mid-Grid collaboration to examine the Midwest’s long-term transmission system design and planning. The group is currently focused on a vision for 2035.
MGA Executive Director Jesse Heier joked that the 200-strong turnout for the virtual meeting was either a sign that the 2035 vision is important work or people “had finally run out of things to watch on Netflix.”
The association was supposed to hold the panel session April 2 in Des Moines but was prevented by the ongoing COVID-19 pandemic.
Heier said that while different Midwestern states have different goals, he believes they can find common ground in transmission planning. States involved in Mid-Grid include Arkansas, Illinois, Indiana, Iowa, Michigan, Minnesota, Missouri, North Dakota and Wisconsin.
MGA Executive Director Jesse Heier on MGA’s Zoom call
ITC Holdings Senior Vice President Krista Tanner said the pandemic demonstrates how crucial the grid is. “Everything we do from caring for the ill, keeping people fed and letting the videos run to keep the kids occupied underscores the importance of the grid.”
But long-term RTO transmission planning, especially in the upper Midwest, has “slowed to a crawl,” she said, and that FERC’s Order 1000 has resulted in sluggish electricity infrastructure growth in a “natural monopoly.”
“I believe the answer is once again for states to step forward and take responsibility,” Tanner said.
“The current system is at capacity or perhaps beyond,” American Wind Energy Association Central Region Director Daniel Hall said.
MISO must develop a long-term transmission study and stop relying on interconnection customers’ network upgrades to expand transmission capacity, he said. The RTO’s reliance on network upgrades is a “haphazard” approach that results in an “inefficient system,” according to Hall. In his previous role at the Missouri Public Service Commission, Hall similarly pushed MISO to create another long-term plan.
Holly Lahd, Target’s lead energy program manager, said the retailer has similarly encountered prohibitively expensive network upgrade costs for grid access.
“We’re setting clean energy goals, and yet, how are we going to get there?” she asked. “We’re making plans, but we don’t have the energy infrastructure to meet them.”
Target, headquartered in Minneapolis, has committed to completely sourcing its electricity from renewable sources by 2030.
Hall said the corporate community should make appeals directly to regulators and elected officials for more transmission to support their clean energy goals. He also said that if network upgrades can show wider benefits, costs should be shared among beneficiaries and not solely be the responsibility of the generation developer.
“We think, in fact, it might be required by the [MISO] Tariff,” Hall said.
ITC Holdings Senior Vice President Krista Tanner
Scott Blankman, Clean Wisconsin’s Energy & Air Program director, said the sites of retired coal generators could be “repurposed” because they already contain grid infrastructure.
Michigan Public Service Commissioner Dan Scripps said his state is beset by limited import and export capability, which came into sharp focus in MISO’s recent Planning Resource Auction, where the Lower Peninsula’s capacity prices cleared at the cost of new entry because the region fell short of its local clearing requirement. Scripps said Michigan’s transmission needs are complicated by its two-peninsula geography and seams with PJM and Ontario’s Independent Electricity System Operator.
“Transmission is front of mind in Michigan right now,” Scripps said.
Former MISO staffer Matt Ellis, now policy program manager with Great River Energy Regional Transmission and Policy, said his company hopes the recent CapX2050 study eventually prescribes transmission projects. (See CapX2050 Calls for More Tx, Dispatchability in Midwest.)
“Optimal solutions are not going to occur with each of us working in a vacuum,” Ellis said.
He said people sometimes ask, referring to the first CapX 2020 effort, “Didn’t we do this 10 years ago?” He said planners should take a look into long-term transmission needs every decade.
“Technology continues to evolve, and it’s imperative as planners for us to explore all options,” he said.
Several panelists brought up the idea of stitching together CapX studies with network upgrade studies, MISO’s ongoing renewable integration impact assessment and annual Transmission Expansion Plan studies to identify long-term transmission needs.
New England’s grid will see diminishing returns from the incremental addition of offshore wind as more megawatts are added, with as much as 13.9% spilled annually, analysis from ISO-NE shows.
The yearly production pattern does not follow the pattern of load, causing spillage to be highest during low-load months and lowest during high-load months, according to Richard Kornitsky, ISO-NE assistant engineer for system planning.
Kornitsky was presenting a follow-up to questions from last month’s meeting related to the economic study conducted for the New England States Committee on Electricity. The organization, Anbaric and RENEW Northeast last year each requested separate studies from ISO-NE. (See “Modeling More Offshore Wind, Slowly,” ISO-NE Planning Advisory Committee: March 18, 2020.)
Annual spilled energy vs. total available energy of offshore wind for all scenarios, as shown in the NESCOE study (0 to 8,000 MW) | ISO-NE
Kornitsky’s presentation focused on spillage stemming from oversupply, building on analyses performed for the NESCOE study for the year 2030.
Theodore Paradise, Anbaric senior vice president for transmission strategy, asked about the assumptions around the dispatch of the non-wind resources.
“Have we taken off all the oil units and any remaining coal, which is barely any, and all the natural gas we can, save for the stuff that needs to ramp and load follow? Or are we keeping a fair bit of that on, causing more spillage than you might have if it was off?”
“It more depends on how the wind is behaving at that specific hour, since in some hours, even in months such as April or May, you’ll have moments when you’ll have quite a bit of offshore wind,” Kornitsky said. “So, there might be hours where offshore wind is the main generation that’s serving load and you won’t have much of that conventional natural gas generation online.”
But Kornitsky also pointed to situations where the system will have very little or no offshore wind, at which point natural gas will be coming back online — and points in between.
“The main thing, especially when you get up to 8,000-MW cases, is there wind available, and that really dictates what other generation is online,” Kornitsky said.
The RTO’s next steps are to complete the ancillary services component of the NESCOE study for presentation in May and to publish the final report by June 1. The final Anbaric study will be published by June or July.
RENEW Study Shows Minimal Spillage
Kornitsky also presented the preliminary RENEW study results for 2025, reminding participants the study does not focus on offshore wind additions “but rather the impacts of the conceptual increases in hourly operating limits of the Orrington-South interface from conceptual transmission upgrades.”
The study has two scenarios based on estimated 2016 limits, which were modified to approximate the addition last year of a voltage regulating system at the Cooper Mills substation in Windsor, Maine.
Scenario 1 shows the same limits as the base case but has a transmission device at the Orrington-South interface with the equivalent impact of a large synchronous generator dispatched nearby, meaning all monthly limits are equal to or higher than the base scenario.
The RENEW study’s assumed “pipe and bubble” New England system representation for 2025 | ISO-NE
Scenario 2 also shows similar limits to the base case but includes a new 345-kV transmission path from the Orrington substation to the Maine Yankee station, with monthly limits higher than base or Scenario 1.
“We use threshold prices to decrease production of $0/MWh resources during oversupply and use of different threshold prices than indicated will produce different outcomes, particularly spillage by resource,” Kornitsky said.
“Under our base assumptions, we see New Brunswick imports, Hydro-Quebec imports, native New England hydro and utility PV would be all curtailed before curtailing NECEC [New England Clean Energy Connect], and finally, behind-the-meter PV would be curtailed last,” he said.
NECEC is a $950 million project to deliver 1,200 MW of Canadian hydropower to the New England grid in Lewiston, Maine, along a 145-mile transmission line controlled by Avangrid subsidiary Central Maine Power.
A set of NECEC sensitivity scenarios were performed assuming a higher threshold price of $11/MWh, which results in the curtailment of the line before other resources.
However, raising the NECEC threshold price from $2/MWh to $11/MWh does not greatly change the amount of total spilled energy systemwide.
Among the key observations: Systemwide production costs and load-serving entity energy expenses are similar among all the scenarios, and varying price separation is seen in LMPs at Bangor Hydro because of congestion at the Orrington-South interface.
Congestion cost by interface, as shown in the RENEW study | ISO-NE
Also, the base case provides the most congestion at the Orrington-South interface, while Scenario 2 provides the least congestion. Spillage is minimal across all scenarios.
“The scale of what’s being changed in this study is very different and smaller than the scale of what was being changed in the other two studies here, so there won’t be much impact on the total system,” Boreas Renewables President Abigail Krich said. “We’re looking at a very small pocket of the system, so in terms of looking at the results, I would hesitate to describe them as not significant on a system scale and more look at the impacts it has on the local area being studied.”
The RTO will publish the final RENEW report by July.
National Grid Study Request
National Grid lead analyst Kai Van Horn presented a new economic study request that would aim to build on earlier studies, modeling year 2035 to provide insight on wholesale energy market impacts, unit economics, utilization of resources, and the role of transmission and battery storage on a system with a high proportion of variable resources.
“The significant decarbonization targets are being set at the state level, which have major ramifications for the energy system,” Van Horn said. “Meeting those targets is going to require a lot of changes, and there are a lot of ways to get there. The broader set of solutions that we can consider, the better outcome we can get to in terms of meeting those targets.”
The proposed study focuses on two pathways: the efficient use of clean energy resources, and leveraging transmission and storage in order to do so, Van Horn said.
ISO-NE energy demand has fallen 3 to 5% since stay-at-home orders began being implemented across New England around March 16, the RTO’s Load Forecasting Manager Jon Black told the New England Power Pool’s Reliability Committee on Wednesday.
“System operations as well as load forecasting in planning are doing ongoing analysis [and] monitoring the situation very closely,” Black said.
That situation is changing by the week, and ongoing changes are likely, especially as the stay-at-home orders may become relaxed or lifted in various parts of the region, he said.
“While we’re seeing impacts today, there’s a lot of uncertainty about the ongoing duration of the effects of the stay-at-home orders, first and foremost in terms of the duration of what we’re witnessing and observing now, but perhaps more importantly from a long-term forecast perspective, what will be the recessionary impacts of the fallout of the pandemic,” Black said.
It’s still too early to understand the longer-term impacts of the pandemic, but the RTO relies on sources like Moody’s Analytics to inform its thinking, he said. (See Moody’s: Coronavirus Recession to Cut GDP 2.3%.)
[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]
CELT 2020 Forecasts up on Electrification
Black presented the final data behind the long-term energy and demand forecasts to be published May 1 in the 2020 Capacity, Energy, Loads and Transmission (CELT) report.
Both the gross and net annual energy forecasts for 2028 are up from last year’s CELT, by 1.5% and 5.4%, respectively, “largely due to the forecast impacts of large-scale electrification expected throughout the region,” Black said.
“The numbers have all been finalized, but there’s a lot of work that goes into publishing all the final reports,” he said.
New England 2020 CELT final gross annual energy forecast | ISO-NE
The RTO has posted the 2020 Forecast Data workbook.
CAGR up Slightly
Black explained that, other than adding electrification forecasts, the RTO adopted no significant modeling changes compared to the 2019 CELT.
“This year’s compound annual growth rate [CAGR] is up a bit from last year over the 10 years, at 1.4% from 2020 through 2029, up from 1.1% in last year’s CELT.”
The final 2020 net annual energy forecast for the region has a CAGR of 0.4% from 2020 through 2029, up from the -0.4% reported in CELT 2019, he said.
Other highlights from the 2020 CELT:
The gross 50/50 summer peak demand forecast exceeds the 2019 CELT’s by 0.3% for 2020 and 1.5% for 2028, and is forecast to increase at a CAGR of 0.9% from 2020 through 2029, up slightly from 0.7% in CELT 2019.
The final net 50/50 summer peak demand forecast for the region is 0.4% higher in 2020 and 1.2% in 2028. It’s expected to decrease at a CAGR of -0.2% from 2020 through 2029, up slightly from -0.4% for CELT 2019.
The final 2020 gross 50/50 winter peak demand forecast is up 0.4% for the winter of 2020/21 and by 4.2% for the winter of 2028/29, and forecast to increase at a CAGR of 1.1% from 2020 through 2029.
The final net 50/50 winter peak demand forecast for the region is down by 0.2% for the winter of 2020/21 and up by 4.3% for the winter of 2028/29. It is expected to increase at a CAGR of 0.1% from 2020 through 2029, up from -0.6% as reported in last year’s CELT.
New England 2020 CELT final gross 50/50 summer peak forecast | ISO-NE
EE Reconstitution
Black also provided the RC with background on energy efficiency participation in the Forward Capacity Market and its “reconstitution” in the gross load forecast.
“Taking it all the way back to the beginning of the Forward Capacity Market, as part of that inception, it was decided that EE would be treated as a capacity supply-side resource and receive capacity supply obligations [CSOs] in the same manner as any other supply-side resource,” Black said.
“In order for that to work, we have a section of our Tariff that requires us to reconstitute — in other words, add back —the demand savings associated with the EE that participates as supply, and that reconstitution is done on the historical loads that we use to develop a long-term load forecast, and in particular the long-term gross load forecast,” he said.
The intent of the gross load forecast is to ensure that passive demand resources are not double-counted in the Forward Capacity Auction as both a load reduction and a capacity supply resource, Black said.
ISO-NE has observed over time that the total amount of EE measures installed exceeds the amount of such CSOs acquired in the primary auction, meaning that reconstituting all installed EE measures results in a forecast of gross demand that overestimates the amount of EE CSOs acquired in the FCA.
Shifting to EE CSO as the basis of its gross load reconstitution will better approximate future EE supply-side participation, Black said.
The change in load forecasting methodology is the first of three initiatives the RTO is introducing to relevant NEPOOL technical committees over the next several months, as detailed in a memo posted after the meeting from COO Vamsi Chadalavada. The second initiative considers the impact of behind-the-meter solar PV on future planning assessments, and the third will better integrate the FERC Order 1000 request-for-proposals process into the reliability delist bid review, starting with FCA 15.
The RTO will present the EE methodology topic for further discussion next month ahead of an advisory vote in June. If the Participants Committee approves them, the Tariff changes will be filed with FERC with a requested effective date of Aug. 30.
FCA 15 Fuel Security Reliability Review
ISO-NE Manager of Outage Coordination Norm Sproehnle presented initial inputs to the fuel security reliability review for FCA 15, feedback from the March RC meeting and preliminary results.
Stakeholders in March pushed back on ISO-NE’s draft assumptions showing that several variable changes between FCAs 14 and 15 would improve system fuel security. (See NEPOOL Reliability Committee Briefs; March 17, 2020.)
Appendix L of the Tariff stipulates the RTO must apply a multiprong trigger for the FCA 15 preliminary analysis that would result in a resource being retained for fuel security if its retirement would: result in the depletion of 10-minute reserves below 700 MW in any hour in the absence of a contingency in more than one LNG supply scenario case; or precipitate the use of load shedding in any hour pursuant to Operating Procedure No. 7.
Using the trigger criteria and the existing Planning Procedure 10 (PP10) inputs, as updated for FCA 15, the RTO has been able to assess the preliminary results of resources that have submitted retirement delist bids (1,935 MW total). Appendix I of PP10 requires the RTO to consult with the RC on 18 static inputs and three variable inputs: imports, LNG injections and dual-fuel resource tank inventory.
The preliminary results indicate that no resources that submitted a retirement delist bid for the FCA 15 capacity commitment period or were previously retained for fuel security — both totaling 1,935 MW — will be retained for fuel security for the period.
| ISO-NE
The additional work to complete the analysis will not change the outcome of the fuel security reliability review, as the items to be finalized will further improve fuel security, Sproehnle said.
Given the preliminary results of the FCA 15 fuel security reliability review, the additional changes suggested thus far would not materially alter the outcome, he said.
For example, stakeholders asked if the Distrigas LNG tanks will be available and utilized in the fuel security reliability model if Mystic Units 8 and 9 retire.
The RTO derived the three LNG scenarios — 0.8, 1 and 1.2 Bcfd — based on the output of the region’s three LNG facilities and their previously observed winter production. If the Distrigas facility is excluded, the capability of the remaining LNG facilities can support the three scenarios, he said. Therefore, ISO-NE will continue to use them for the review.
The RTO timeline calls for the RC in August to review FCA 15 fuel security analysis results for submitted retirement delist bids. Participants that have submitted a retirement delist bid will be notified by the RTO if their resource is needed for fuel security reliability reasons no later than 90 days after the existing capacity June 11 retirement deadline.
ICR and Related Values Development
Manasa Kotha, ISO-NE senior engineer for resource studies and assessment, presented the RC with the 2020 development schedule for installed capacity requirement (ICR) values that will be used in auctions conducted in 2021.
The ICR, as well as the net installed capacity requirement, are calculated for each FCA and annual reconfiguration auction and are inputs to the sloped demand curves, Kotha said. The ICR represents the minimum total system capacity needed in New England to meet the Northeast Power Coordinating Council’s resource adequacy criteria.
Load forecast and FCA ICR values development timeline | ISO-NE
Details of the ICR-related values development will be discussed with the NEPOOL Power Supply Planning Committee over the summer and brought back to the RC for review and a vote in September. If approved by the Participants Committee in October, the RTO plans to file the values with FERC by Nov. 10.
Committee Actions
The RC’s notice of actions included approval of several motions, noting that all sectors had a quorum.
The committee approved a 10-MW fuel cell interconnecting to the 23-kV bus of the Judd Brook substation in Connecticut, with an in-service date of Dec. 1.
Also approved was NextEra Energy’s 20-MW Keay Brook solar facility in York County, Maine, interconnecting to the 34.5-kV Lebanon-Sanford line, which went into service Feb. 12.
The RC approved pool transmission facility (PTF) cost allocation of $18.5 million to Eversource Energy for transmission upgrade costs associated with the replacement of wooden structures on the 115-kV 1655 line with steel poles.
Eversource also had $16.6 million in PTF cost allocation approved for work associated with the replacement of the high creep insulator system at the Millstone 15G substation in Waterford, Conn.
The RC approved National Grid PTF cost allocation of $212 million in transmission upgrade costs for work associated with the 345-kV 327 and 315 lines and asset condition refurbishment as submitted to ISO-NE by New England Power.
It also approved a revision to Operating Procedure 14 (OP-14) related to technical requirements for generators, demand response resources, asset-related demands and alternative technology regulation resources.
Ohio regulators last week approved the application of a FirstEnergy subsidiary to operate as an energy broker and aggregator despite protests from consumer advocates and competitors over what they called a conflict of interest.
The Public Utilities Commission of Ohio on Wednesday granted approval for Suvon, doing business as FirstEnergy Advisors, as a competitive retail electric service (CRES) provider to help customers select electricity suppliers. FirstEnergy filed its application in January, and PUCO staff recommended approval of it earlier this month.
Critics, including the Ohio Consumers’ Counsel and the Northeast Ohio Public Energy Council (NOPEC), challenged the filing, saying use of the FirstEnergy name provided an unfair advantage and represented “too great a threat” to Ohio consumers in the retail electric market.
The OCC and NOPEC argued that having Suvon’s offices in the same building as the FirstEnergy’s headquarters in Akron, and having the company controlled by members of the same management team that controls the FirstEnergy utilities, violates state law requiring that a competitive retail electric supplier be “fully separated” from its regulated utilities.
FirstEnergy owns three utilities — Ohio Edison, Toledo Edison and The Illuminating Co. — with monopoly electricity distribution services regulated by PUCO.
NOPEC and the OCC argued that barring the use of the FirstEnergy name was consistent with a 2018 report filed by SAGE Management Consultants, PUCO’s outside auditor, in the commission’s corporate separation audit. The report recommended disallowing a former FirstEnergy affiliate, CRES provider FirstEnergy Solutions (FES), from using the FirstEnergy name.
FES recently emerged from bankruptcy under a new name, Energy Harbor, but the corporate separation case remains pending before the commission (17-974-EL-UNC).
FirstEnergy’s Akron, Ohio, headquarters
The commission said that issues regarding Suvon’s use of the trade name and compliance with corporate separation requirements “are best raised” in that proceeding, noting that the commission has not adopted the SAGE report’s conclusions. “The finding and conclusions of the auditor should be litigated in that proceeding rather than this case,” it said.
PUCO also determined that the shared service arrangement between FirstEnergy and Suvon does not present a conflict of interest and is permissible under federal law. The commission cited other utility subsidiaries that have been certified as CRES providers, including a case involving Interstate Gas Supply’s (IGS) DPL Energy Resources in 2000.
“We note that the existing requirements for proper disclosure of the affiliate relationship has been considered to be a necessary and sufficient protection in all prior cases,” the commission ruled. “We expect Suvon to include and present the required disclosure in a conspicuous and efficacious manner in all communications with consumers.”
The OCC, Vistra Energy and NOPEC, Ohio’s largest nonprofit energy aggregator, filed motions opposing the certification. The Northwest Aggregation Coalition called for a hearing on it.
“In the long run, what we know in Ohio is when there is no competition, prices go up,” Chuck Keiper, NOPEC’s executive director, said in an email to RTO Insider. “We’ll be moving back to a toxic environment where the utilities control the marketplace.”
In a separate request, NOPEC and the OCC also asked PUCO to release public records of any communications the commissioners or staff had with FirstEnergy Advisors. Keiper said his concern that the commission did not hold a hearing in the case led to the public records request.
“We’re not afraid of another electricity broker coming into the market,” Keiper said. “In fact, we welcome it. But bring it on in a fair, honest, legal and transparent way. Let everyone see communications, if any, between FirstEnergy Advisors and the public body PUCO. Taxpayers and electricity consumers in Ohio are owed that and a fully public process to investigate this application.”
The commission noted that several of those intervening in the case were competitors of Suvon. “Competition should be determined ultimately by acumen in the marketplace, not by presumptive inhibition through a commission certification proceeding,” it said. “Although we have granted intervention in this case to Suvon’s competitors, we will carefully monitor the practice of competitors intervening in certification proceedings to ensure that this does not become a widespread, abusive practice and that competition is not unduly stifled by unnecessary litigation.”
PUCO denied the public records request, saying the staff determination that Suvon has the capabilities to serve as a power broker make the request “moot.”
“Staff has thoroughly reviewed Suvon’s managerial, technical and financial capability and has recommended that Suvon’s application should be approved,” the commission said. “Upon review of the many motions and memoranda filed in this case, we find that no other parties have raised material issues regarding Suvon’s managerial, technical and financial capability.”
J.P. Blackwood, a spokesperson for the OCC, said Thursday the organization was not satisfied by the decision.
“The Ohio Consumers’ Counsel is disappointed that the PUCO granted FirstEnergy Advisors’ operating certificate without imposing the conditions that we and many local governments recommended for consumer protection and fair competition,” Blackwood said.
SPP’s effort to stand up the Western Energy Imbalance Service market is on budget and on schedule, the grid operator’s staff told the Western Markets Executive Committee last week.
“It’s going to take all of us to make that happen,” SPP’s David Kelley, director of seams and market design, told the WMEC during a conference call Thursday. “Understand when we’re pushing you and you’re pushing us, it’s to keep us marching to the same objective, and that’s to get the market up and running.”
SPP plans to begin operating the WEIS in February 2021. Modeled on the Energy Imbalance Market the RTO operated from 2007 to 2014, the WEIS has attracted eight participants. (See SPP Board OKs $9.5M to Build Western EIS Market.)
SPP’s legacy and WEIS footprints | SPP
Kelley said that while the overall market development project’s status is yellow because some tasks are behind schedule, the project’s end date is “not in jeopardy.”
“We’ve been able to make up lots of lost ground we had early in the project,” Kelley said. “I’m still comfortable with where we are. The delays in some of the tasks won’t affect the overall health of the program.”
SPP staff are currently testing the first markets release from its vendor and have taken delivery of two key software systems. They are also preparing for various system tests, with market trials scheduled for the month of October. Parallel operations are scheduled to begin Dec. 10.
Kelley said SPP has yet to fill five of the 13 positions necessary to run a Western markets desk in its operations center because the RTO’s two control rooms have been “basically” locked down during the COVID-19 pandemic to protect the operators, he said.
“We have ample time to get the desk stood up and tested,” Kelley said.
The pandemic has also caused a change in training WEIS participants. SPP originally planned for in-person training in July but has now shifted to virtual, instructor-led classes.
FERC Finds SPP’s WEIS Tariff Deficient
FERC on April 20 issued a letter notifying SPP that its proposed WEIS Tariff, Western joint dispatch agreements and WMEC charter are deficient and requested additional information for the filings (ER20-1059, ER20-1060).
The commission asked for a response to 12 different categories by June 4, throwing into doubt SPP’s original requested effective date of May 21. The RTO filed the Tariff and other documents in February.
The Rocky Mountains loom large in SPP’s WEIS footprint. | Rocky Mountain National Park
FERC asked SPP to break down the six categories of costs included in both its projected $9.5 million implementation costs and its ongoing administrative costs to be recovered through the WEIS rate. The RTO has proposed a WEIS rate of 22 cents/MWh of net energy for load, based on an estimated annual $5 million operating cost. That number includes the annualized payback of implementation costs.
FERC also asked SPP to explain why using its Integrated Marketplace market power mitigation thresholds are appropriate for the WEIS. The RTO said the market will be subject to market power monitoring and mitigation performed by its Market Monitoring Unit.
The proposed Tariff includes provisions for demand response and notes that aggregators of retail customers “shall be treated comparably to other market participants offering resources.” FERC said there was no mention of compensation for DR resources and asked the RTO to clarify whether those resources would be compensated at LMP like other participants; “if not, please explain how they will be compensated and why.”
Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability Committee meeting on Thursday. The Members Committee will next meet May 4.
Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Consent Agenda (9:05-9:10)
Members will be asked to approve the following revisions to the PJM Tariff and other documents:
B. Administrative revisions to the PJM Tariff, Operating Agreement and Reliability Assurance Agreement as recommended by the Governing Document Enhancement & Clarification Subcommittee.
1. Hybrid Resources Issue Charge (9:10-9:35)
PJM will seek approval of an issue charge to create a new senior task force to clarify how existing rules for intermittent and energy storage resources would apply to inverter-based solar-battery hybrids. Some stakeholders at the March 26 MRC meeting questioned why some areas of hybrid resources are being considered out of scope for the proposed task force, including PJM’s compliance with FERC Order 845. (See PJM MRC Moves Forward on Storage, Hybrids.)
The Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) has provided a list of guidelines for safely operating control centers during the COVID-19 pandemic.
The Operations Centers and Control Rooms Guide for Pandemic Response applies to “operations centers and control rooms across the 16 critical infrastructure sectors required to operate in a pandemic environment.” As defined by CISA in its Guidance on Essential Critical Infrastructure Workers, these sectors include the electricity, natural gas, petroleum and other energy-related industries; health care and public health; law enforcement and other first responders; transportation and logistics; and water, among others.
“Operations centers and control rooms often operate 24/7, depend on unique equipment, and require specially trained staff who are difficult to replace,” CISA said. “As a result, specialized equipment and long lead times required to train personnel mean there is a higher risk to sustaining reliable operations.”
PPL’s control room | Barco
Recommendations in the guidelines cover preventive measures to keep workers and equipment from coming in contact with the coronavirus; mitigating actions when exposure has occurred; and coordination with federal, state and other authorities to prioritize testing and arrange for free movement of essential personnel during periods of travel restrictions. The measures are advisory and “should not be considered a federal directive.” Owners and operators are also advised to tailor their approaches based on industry and site-specific needs.
COVID-19 Mitigation to Continue
CISA’s guidelines complement the ongoing actions by NERC and the broader electric industry to mitigate the impact of COVID-19. In a recent report, NERC noted that while there are “no specific threats or degradations” to the operation of the bulk power system at this time, utilities must be prepared “to operate with a significantly smaller workforce, an encumbered supply chain and limited support services” as a result of the outbreak. Cybersecurity and shortages of protective equipment are also significant concerns. (See PPE, Testing Top Coronavirus Concerns for NERC.)
Since issuing a Align Tool Set for 2021 Rollout.) NERC has either canceled all external meetings through June or converted them to conference calls.
NERC has signaled that it will continue its pandemic response even as state governments begin taking steps to end shelter-in-place orders in hopes of restarting their economies. On Friday, the organization announced it would extend its suspension of on-site activities, including audits and certifications, through Sept. 7. FERC and NERC announced the suspension — originally scheduled to end July 31 — in March, along with other regulatory relief measures. (See FERC, NERC Relax Compliance in Light of COVID-19.)
“The ERO Enterprise recognizes that there are significant uncertainties regarding the duration of the outbreak and the subsequent recovery and will continue to evaluate the circumstances to determine when on-site activities may resume safely or whether additional regulatory relief is necessary,” NERC said. “In the interim, the regional entities are actively involved in remote oversight activities and are experimenting with innovative approaches … to continue assuring the reliability and security of the bulk power system.”
The Federal Communications Commission on Thursday agreed to open a portion of the 6-GHz band for unlicensed use over the objections of utilities, which fear their communications in the spectrum could be disrupted.
The FCC said its ruling “will usher in Wi-Fi 6, the next generation of Wi-Fi, and play a major role in the growth of the Internet of Things,” noting Wi-Fi 6 will be more than two-and-a-half times faster than the current standard. It said it will nearly quintuple the amount of spectrum available for Wi-Fi and improve rural connectivity (Docket 18-295).
But the Utilities Technology Council blasted the move, saying the FCC had failed to balance protection of critical communications in its desire to be innovative.
“Opening the 6-GHz band can be done in such a way that can both unleash the new innovations the FCC and others hope for while also protecting the CII [critical-infrastructure industries] systems already in the band. Doing so would take time, additional study and stronger protections for incumbent systems,” the UTC said in a statement. “Today, the FCC appears to have decided on taking a much riskier approach that does not control low-power indoor operations using AFC [automated frequency coordination systems]. Nor does the FCC order provide additional testing to prevent interference from occurring or enforcement processes to resolve interference that does occur.”
“While we support the goal of using spectrum more efficiently, today’s decision by the FCC means there will be no field testing or AFC mechanism in place to protect incumbent users from interference by indoor low-power devices,” said Phil Moeller, the Edison Electric Institute’s executive vice president for business operations and regulatory affairs. “EEI’s member companies remain committed to providing their customers with reliable and secure energy, and we will carefully monitor the band for interference to prevent any significant impacts to mission-critical communications systems.”
Electric utilities use the 6-GHz band 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. (See Utilities Warn of Encroachment on Communications Band.)
A point-to-point microwave receiver “views” a region of about 37 kilometers by 6.5 kilometers. Given the population density of a city like Houston, such a receiver could face potential interference from more than 62,000 unlicensed Wi-Fi access points, according to a study conducted for utilities. | Roberson and Associates
The commission authorized indoor low-power operations over the full 1,200 MHz (5.925–7.125 GHz) and standard-power devices in 850 MHz of the 6-GHz band.
The FCC also issued a Further Notice of Proposed Rulemaking seeking comment on permitting very low-power devices to operate across the 6-GHz band to support high data rate applications such as wearable augmented-reality and virtual-reality devices. The notice also seeks comment on increasing the power at which low-power indoor access points can operate.
The commission said its order was critical to realizing its goal of “making broadband connectivity available to all Americans, especially those in rural and underserved areas.”
FCC Chairman Ajit Pai noted in a statement the importance of Wi-Fi during the COVID-19 pandemic.
“Sheltering in place would be a lot more difficult without Wi-Fi,” he said. “Of course, even before anyone had heard of COVID-19, Wi-Fi already carried more than half of the Internet’s traffic, and offloading mobile data traffic to Wi-Fi was vital to keeping our cellular networks from being overwhelmed. In a very real sense, Wi-Fi is the fabric that binds together all our digital devices.”
[NOTE: The commission’s order had not been posted as of press time Thursday evening.]
The FCC insists the AFC system will prevent standard power access points from operating where they could cause interference to existing services. But utilities say AFC — which uses a “database lookup scheme” to ensure that unlicensed users are not encroaching on an existing user’s priority access to the frequency in a specific area — should be required for low-power devices also.
‘Real-world’ Study
UTC, EEI, the American Gas Association, the American Public Power Association and the National Rural Electric Cooperative Association submitted a study to the FCC in January that looked at the impact of the proposed rule on 520 microwave sites and 2,325 point-to-point communications receivers in the nine-county Houston Metropolitan Statistical Area, chosen because its flat terrain simplified “propagation path loss issues.”
“The analysis clearly demonstrates that allowing unlicensed devices to operate in the 6-GHz band will render fixed point-to-point communications receivers serving critical infrastructure in [the] Houston MSA unreliable and unable to meet minimal performance objectives, specifically geographic coverage (i.e., long links), high bit rates, low latency and high reliability,” said the study, which was conducted by Roberson and Associates, a technology and management consulting company.
A study conducted for EEI, APPA and NRECA concluded that automated frequency coordination systems cannot control interference from indoor RLANs in central Houston without “degenerating to complete exclusion of the entire U-NII-5 and U-NII-7” sub-bands, which make up most of the 6-GHz band. | Roberson and Associates
Utilities use the 6-GHz band because it allows microwave networks with multiple links to cover large areas with very low latency time delays, high bit rates and high reliability, with resilience to “rain fading.”
“Given the critical nature of the communications carried on the 6-GHz band, the public safety and CII networks operating in this band are built to extremely high standards of reliability — 99.999% or 99.9999% availability. These networks must also transmit with extremely low levels of latency — 20 milliseconds or less of roundtrip delay from one point to another over long distances. No other band has sufficient bandwidth with all key characteristics (large geographical distances, low latency time delays, high bit rates, high reliability) to permit reliable operations in large, dense metropolitan networks such as Houston,” the study said.
Millions, Billions
EEI noted in an April 15 letter to the FCC that “unlicensed advocates themselves predict the deployment and operation of millions if not billions of unlicensed devices in the band. The combination of this vast number of devices, the bandwidth of their operation, the duty cycle of their transmissions and that most will not be identifiable or controllable after sale make harmful interference a virtual certainty.”
Such interference, EEI said, “can lead to power outages, wildfires and other potential disasters.”
The Houston metropolitan area has 520 point-to-point microwave sites in the U-NII-5 and U-NII-7 sub-bands. | Roberson and Associates
It said the commission should form a stakeholder group including utilities to respond to interference and that AFC should be more widely required.
But even AFC is not a panacea, the utilities’ study said. “AFC cannot control interference from indoor RLANs [radio local area networks] in central Houston without degenerating to complete exclusion of the entire U-NII-5 and U-NII-7” sub-bands, which comprises most of the 6-GHz band.
