MISO is working to create market rules for capacity reserves that can be supplied within 30 minutes, though the RTO won’t have a sophisticated enough technology platform to support the new product for more than two years.
RTO staff told the Market Subcommittee on Nov. 8 that the earliest the new product could be rolled out is the first half of 2021 because it will require the new market platform.
MISO Director of Market Design Kevin Vannoy said the short-term reserve product will address issues that are “more severe” than can be solved by either the ramp product and regulation reserve, which is supplied within seconds, or issues that are “less severe” than the Disturbance Control Standard events requiring the RTO’s 10-minute contingency reserves.
“The idea is to get the 30-minute reserves reflecting actual needs [of the system] rather than trying to have the 10-minute reserves covering it,” Vannoy said.
“We have needs that we make out-of-market commitments for, but they’re not modeled in the market,” said Bill Peters of MISO’s market design team.
The short-term reserves would be furnished by either online generators dispatched according to opportunity costs or offline generators, which would be dispatched based on an offer price.
Peters said short-term reserves would help manage flows on SPP transmission between MISO Midwest and MISO South and aid areas hemmed in by transmission constraints or short on nimble reserves. They also will help meet load and avoid volatility as the RTO adds more intermittent resources.
MISO’s final ranking of Market Roadmap improvements placed the creation of short-term reserves at the highest priority, beating out projects to better model combined cycle generators, and respond to shifting resource availability and need.
Peters said the reserves could have market-wide, regional and local response requirements. He said MISO would dynamically schedule the reserves to a load pocket or region, assessing the state of the system, capacity needs, amount of cleared energy and amount of cleared short-term reserves before dispatch. He also said the RTO is considering applying a demand curve to pricing. Peters said the generators that sign up to provide the service will be tested to demonstrate they’re able to provide capacity within 30 minutes.
MISO has scheduled a Jan. 15 workshop to further discuss the conceptual design of a short-term reserve product.
Pacific Gas and Electric’s stock price rose dramatically Friday after state California Public Utilities Commission President Michael Picker made a series of surprising public statements about the company’s future as it faces potentially billions of dollars in wildfire liability for the current Camp Fire, the deadliest in state history, and a series of devastating blazes in 2017.
On Thursday, Picker took part in a call with Wall Street analysts in which he said allowing PG&E to go bankrupt wouldn’t be good policy, Bloomberg News and other media outlets reported. He reiterated those comments in at least two newspaper interviews, and discussed the possibility of legislative action to relieve PG&E’s financial burden.
But Picker also said he was concerned about the utility’s lack of accountability. He told the Wall Street Journal that breaking up the company might be an option for regulators to consider. In a news release, the PUC president said he intended to expand an ongoing investigation into PG&E’s “safety culture” that the commission opened after the San Bruno gas line explosion in 2010.
“In the existing PG&E Safety Culture investigation proceeding,” Picker said in the statement, “I will open a new phase examining the corporate governance, structure, and operation of PG&E, including in light of the recent wildfires, to determine the best path forward for Northern Californians to receive safe electrical and gas service in the future.”
PG&E’s stock rose back to around $24 per share Friday after it plunged this week as the toll of death and destruction from the Camp Fire, the worst in modern California history, increased. The company fell under suspicion for starting the wildfire after one of the utility’s transmission lines was reported downed at the time and location of the fire’s ignition.
NASA’s Earth Observatory photographed the Camp Fire as it exploded late last week. | NASA
The news sent PG&E Corp.’s stock tumbling from roughly $48 per share on Nov. 8, when the fire started, to less than $18 per share on Thursday – a 62.5% drop in one week.
Similarly, Southern California Edison’s stock fell sharply as the Woolsey Fire raged in Los Angeles and Ventura counties, killing two and destroying more than 500 structures so far. Edison told state regulators it experienced an outage at a substation near where the fire started, the Los Angeles Times reported.
On Nov. 8, PG&E filed a report with the California Public Utilities Commission, saying it had experienced an outage on a 115-kV line near where the Camp Fire started and shortly before it was first reported. The company later wrote in a news release that the “information provided in this report is preliminary, and PG&E will fully cooperate with any investigations. There has been no determination on the causes of the Camp Fire.”
Early Thursday morning, firefighters responded to reports of a vegetation fire under transmission lines near Poe Dam, part of PG&E’s Feather River Canyon Power Project in rural Butte County. The California Department of Forestry and Fire Protection (Cal Fire) has identified the area as the approximate location where the fire started. A property owner in the area has told media outlets that she received an email from PG&E saying the company planned to do work on her land because its power lines were causing sparks.
Fanned by 35-mph winds, the fire quickly grew and destroyed most of the town of Paradise (population 27,000). As of Friday, it had killed 63 civilians, destroyed approximately 9,844 homes and hundreds of other structures and burned 142,000 acres, Cal Fire reported.
Previously the deadliest fire in state history was the Griffith Park Fire in Los Angeles in 1933, which killed 29 people, according to Cal Fire. The most damaging in terms of homes and other structures destroyed previously was the Tubbs Fire in Napa and Sonoma counties in October 2017, the cause of which is still under investigation.
The largest wildfire in modern state history, the Mendocino Complex of fires, occurred this summer, burning 459,000 acres in the rugged mountains north of San Francisco from July to September 2018.
The Camp Fire decimated the town of Paradise in the Sierra Nevada foothills. | Cal Fire
The Camp Fire has revived talk of PG&E’s possible bankruptcy, which became the subject of concern following a series of devastating wildfires in 2017. State fire investigators have said PG&E was responsible for 17 of the 21 blazes. The 2017 fires could subject the company to billions of dollars in liability under California’s unique system of holding utilities strictly liable for damage caused by power lines and equipment, regardless of negligence.
Earlier this year Gov. Jerry Brown proposed doing away with that system, known as inverse condemnation, arguing it threatened electric reliability and the state’s efforts to completely exclude carbon emissions from its power grid by the middle of the century.
Lawmakers tasked with formulating a major wildfire bill, SB 901, ultimately left inverse condemnation intact while creating a method by which utilities could issue long-term bonds to pay for some fire damage. (See California Wildfire Bill Goes to Governor.) Critics called the bill a bailout for the utilities, but Brown signed the legislation in September.
PG&E executives recently said in an earnings call that the new law was insufficient, and they intend to seek an end to inverse condemnation through the courts and legislature. (See PG&E Outlines Fire Strategy in Earnings Call.)
Company CEO Geisha Williams also discussed the company’s new practice of proactively shutting down sections of its grid during conditions that made wildfires especially dangerous. The company warned last week that it might have to shut down power to areas, including Butte County, but then decided conditions there did not warrant it.
In its recent third-quarter earnings call, SCE said its equipment was likely a partial cause of the hugely destructive and deadly Thomas Fire last year. That fire was the largest in state history until this year’s Mendocino Complex far surpassed it. (See Edison Takes Partial Blame for Wildfire in Earnings Call.)
SCE’s stock price fell from more than $25 a share before the Woolsey fire began, also on Nov. 8, to around $21 per share in trading Thursday.
ATLANTA — NERC stakeholders are expected to consider a new standard authorization request (SAR) to address inverter-based resources after the Standards Committee rejected two SARs proposed by CAISO in September, officials said last week.
CAISO submitted the SARs in May, saying it had recorded at least 14 occasions since August 2016 when inverter-based solar generation incorrectly tripped or ceased to operate during the routine high-speed clearing of short circuits on bulk electric system (BES) transmission. NERC has issued several reports and alerts following the two most serious incidents: the August 2016 Blue Cut wildfire, when 1,200 MW of solar disconnected; and the October 2017 Canyon 2 fire, which resulted in the loss of more than 900 MW. (See NERC Chief: Inverter, Fuel Assurance Standards Needed.)
The ISO proposed incorporating performance requirements for inverter-based resources connected to the BES in a revised NERC standard PRC-024, or developing a new standard for such resources and clarifying that PRC-024 applies only to synchronous generation.
At its Sept. 13 meeting, however, the Standards Committee rejected both SARs by a 12-5 vote on a motion by Dominion Energy’s Sean Bodkin, who noted the Institute of Electrical and Electronics Engineers (IEEE) is addressing the issues in Standard 1547-2018.
NERC is working with IEEE on the standards for inverter settings and developing instructions on compliance monitoring and enforcement activities related to the issue, James Merlo, NERC vice president of reliability risk management, told the Member Representatives Committee (MRC) at its quarterly meeting Nov. 6.
FERC Commissioner Cheryl LaFleur, who attended the MRC and Board of Trustees meetings, said she was concerned about the rejection of the SARs, saying “nothing clarifies the mind like an enforceable standard.” She said it was better for NERC and its stakeholders to design standards rather than respond to directives from FERC.
NERC CEO Jim Robb said he was disappointed that the two SARs “met with such headwinds at the Standards Committee.”
“I think we need to get over the notion that any standard creates peril and get to the point where standards create certainty,” he said. “And I think, particularly, in the case of these inverter resources, that’s a very, very important thing for us to do. … These resources are not going away. They’re already at scale in the West, and they will [soon] be at scale … in many parts of the country.”
Merlo said the Operating and Planning committees and the Inverter-Based Resource Performance Task Force will seek a new SAR to modify PRC-024 that will build on a white paper to be released in about two weeks identifying gaps between current standards and what’s needed by grid operators. “The expectation is the Standards Committee would take that up in December,” Merlo said.
“I’m optimistic that that will accomplish much of what we wanted to accomplish through the original two SARs,” Robb said.
The work may not stop with revisions to PRC-024, said Howard Gugel, NERC senior director of engineering and standards. “Then that task force is also going to go forward to say, ‘given that this is a brave new world and we have these resources, is there another standard that we should write that says how they should actually operate?’” he said in an interview. “And it’s not just limited to solar. … [idle EVs injecting energy into the grid are] an inverter resource also.”
NERC has already asked solar generators to modify their inverter settings to ensure voltage excursions don’t result in momentary cessation (MC) — when they stop injecting current into the grid. For inverters that cannot use another ride-through mode, NERC asked that MC settings be reduced to the lowest voltage value possible and that the recovery delay be reduced to one to three electrical cycles.
In arguing for the SARs, CAISO’s Keith E. Casey, vice president of market and infrastructure development, noted that NERC guidelines are not enforceable.
“Due to a lack of any standard addressing the minimum performance of inverter-based generation connected to the BES, original equipment manufacturers often apply standards for resources connected to the distribution system to BES resources,” Casey wrote.
NERC reported that most of the lost solar generation in the Blue Cut fire resulted when inverters incorrectly perceived a low frequency condition and tripped, not returning to service for five minutes or longer. “Five minutes may make sense on a rooftop, but five minutes is an eternity on the bulk electric system,” Merlo said.
NERC, which originally surveyed 13,543 MW of solar PV as potentially using momentary cessation, now believes all but about 1,952 MW do not use it or can overcome it with modified settings. (The survey covered only utility-scale solar generators at or above 75 MW, the threshold for generators that must register with NERC.)
“We understand a lot more than we did when we first saw the event just 18 months” ago, Merlo said.
SAN FRANCISCO — This year’s ACORE Renewable Energy Grid Forum took place in a high-rise hotel within blocks of the headquarters of tech revolutionaries Twitter, Uber and Airbnb, among many others. So it was fitting that the forum’s speakers, including Google’s head of global energy policy, grappled with what keynote speaker and FERC Commissioner Richard Glick called the “energy revolution.”
Coming advances in electricity generation and distribution — such as mass storage, distributed renewables and computer algorithms that can monitor a vastly complicated grid — will make older modes seem like the horse and buggy at the dawn of the automobile era, Glick said. Back then, those invested in buggies would try to dissuade people from buying automobiles, he said.
“Every time a car would drive by someone would yell, ‘Get a horse,’” Glick told the audience at the Grand Hyatt San Francisco, near Union Square. “We’re kind of in that situation now” with fossil fuels and renewables, he said.
Another keynote speaker, CAISO CEO Steve Berberich, said the traditional model of centralized generation using fossil fuels is already “fraying around the edges” as the price of solar and wind power continues to plummet. The cost of storage is also falling, he said, and every state except Idaho has a renewable energy goal.
“Even conservative states such as Utah are pursuing [renewable energy],” Berberich noted.
The third keynote speaker, Laura Nelson, energy adviser to the Utah governor’s office, told the audience that the price of renewables has dropped 50% in the last five years, and Utah has increased its reliance from 1% to 8%, with big investments in utility-scale solar and geothermal power.
In a panel titled “Evolving Models for Electricity Markets,” Ralph Cavanagh, senior attorney with the Natural Resources Defense Council, said the biggest impediment to renewable integration is the fragmented Western grid.
Efforts to expand CAISO to an RTO for Western states had sputtered, he said, because other states were not willing to accept a board appointed by the California governor and confirmed by the State Senate, and California politicians weren’t willing to share control of the RTO. (See Can Calif. Go All Green Without a Western RTO?)
CAISO’s governance structure would need to change for California and neighboring states to participate in an organized wholesale market, he said. Gov. Jerry Brown supported the failed efforts at regionalization, partly as a means of achieving the clean energy goals of SB 100, which he signed in September. (See Calif. Gov. Signs Clean Energy Act Before Climate Summit.)
Mars Hanna, Google’s head of global energy policy and markets, said his company, like California, is trying to reach a goal of relying on 100% carbon-free energy. To get there, he said, “We need to be able to blend Wyoming wind with Nevada solar.”
Addressing the recent election, Rose McKinney-James, managing partner of Nevada-based Energy Works, said state voters had rejected Question 3, a ballot proposal to allow customers to choose their energy providers, largely because they were concerned about rates going up. (See related story, High Failure Rate for Western Ballot Measures.) Nevada’s electricity rates are 45% less than California’s, she said.
Another big factor, she said, was that NV Energy, the state’s monopoly electric provider, had announced plans before the election to develop 1,300 MW of solar generation. But that would only happen if the company remained a monopoly, she said.
Cavanagh agreed. “[NV] Energy reinvented itself” as green and clean, he said. “It gave us something to vote for.” Now “you’re going to have a revitalized [NV] Energy as a player in the West.”
Pat Reiten, senior vice president of government relations for Berkshire Hathaway Energy, also was on the panel. NV Energy is a subsidiary of Berkshire Hathaway, billionaire Warren Buffett’s company.
Reiten said the falling cost of solar had persuaded the company to invest in it. NV Energy once uselessly bid solar into California’s market at $100/MWh, far more than fossil fuels, he said, but the price now is $20 or $30/MWh and competitive with other energy sources. “That’s rather remarkable,” Reiten said.
On the stage at the Grand Hyatt near Union Square, McKinney-James turned to Reiten and said she and many others expect NV Energy to keep its commitments.
“We do have expectations, and there will be feet held to the fire,” she said, eliciting laughs from the audience.
After lunch, conference attendees were invited to submit questions via an app to panelists Angelina Galiteva, a member of CAISO’s Board of Governors and founder and chairwoman of the Renewables 100 Policy Institute, and Dan Reicher, executive director of Stanford University’s Steyer-Taylor Center for Energy Policy and Finance.
The first question was, “What is the biggest issue facing the grid as renewables proliferate?”
Intermittency, both speakers said, but they argued it isn’t as big a problem as many critics have contended.
Galiteva said she grew up in Tanzania, where local solar proved far more reliable than the spotty power supplied by a central generating station. “That’s where I fell in love with renewables,” she said.
Many criticize renewables such as wind and solar as being intermittent and unreliable, but Galiteva said she believes “renewables are more reliable than centralized power,” especially as renewable power sources proliferate.
The fact that renewable energy sources are distributed provides an inherent safety backup compared with centralized power, Galiteva said. “Look at the San Onofre power plant,” she said. The San Onofre Nuclear Generating Station, on the Southern California coast, shut down suddenly in 2012 after problems arose, and the grid lost the plant’s 2,350 MW.
Galiteva also pointed to the Aliso Canyon gas storage facility, a major resource for the Los Angeles area, which shut down after a massive leak was discovered in October 2015. Constraints on natural gas supply have resulted ever since. (See CAISO Seeks to Extend Aliso Canyon Rules.)
Reicher said intermittency was generally considered the main problem with renewables, but not all renewables are intermittent, he said. Hydropower, geothermal and biomass are regular, dependable sources, he said.
Storage, including pumped hydro, will make solar and wind more readily available during peak demand times, he said.
Floating wind farms off the coast of California, if ever approved by federal authorities, would be a reliable source of wind power. California’s coast has some of the most regular winds in the nation, and those winds pick up just as the state’s solar energy tapers off for the day, Reicher said.
“When you go to the beach in California,” he said, “the sun goes down and the wind comes up.”
Walker Pushes for Improved RC-to-RC Agreements with SPP, MISO
Texas Public Utility Chair DeAnn Walker said last week she has asked ERCOT, SPP and MISO to work together to improve the reliability coordination (RC) agreements among the grid operators.
Walker told her fellow commissioners she wants to ensure the grid operators’ RC operators understand their responsibilities and “can act on those responsibilities.”
“I believe all three regional coordinators would agree the documents we have now could have more clarity,” Walker said during the PUC’s Nov. 8 open meeting. “My intent is for them to work through those agreements, so there’s more clarity … for reliability purposes.”
Walker said she last month discussed her intentions with SPP leaders, who assured her their staff would work with ERCOT staff “to get something done by the end of the year.” She said she is also working on setting up a meeting with MISO CEO John Bear.
Separately, SPP and MISO are working to improve coordination across their seam following January and September events this year. (See “SPP-MISO Operating Procedures not yet Documented,” SPP Board of Directors/Member Committee Briefs: Oct. 30, 2018.)
Walker’s concern is over the use of switchable generating units, interconnected to other regions but available to ERCOT. Its most recent seasonal assessment of resource adequacy listed 3.7 GW of installed capacity as being available to the Texas grid operator in an emergency situation.
“We’re not trumping [SPP and MISO] on a reliability need to their system,” Walker said. “If they say they’re not willing to release [switchable units], we have options here in ERCOT we can use for reliability purposes.”
Walker said she was also driven to share her work with Commissioners Arthur D’Andrea and Shelly Botkin because of “a lot of discussion out there misrepresenting what I’m trying to do.” As an example, she pointed to opposition to an ERCOT revision request that would add a new resource status code for switchable units.
“There’s so much pushback on very reasonable things,” Walker said. “To me, it’s all about reliability. Ratepayers in ERCOT have been paying for the transmission to interconnect these units. They should have some reason to be here for reliability.”
PUC to Discuss Market Changes
The commission agreed to reserve time during its Dec. 7 open meeting for a broader discussion of potential changes to ERCOT’s market, including real-time co-optimization and incorporating marginal losses into dispatch decisions (Project 48551).
Both proposals have varying degrees of stakeholder support. Staff have been asked to provide additional information and offer recommendations on the proposed changes, which were the subject of two workshops last year. (See ERCOT, Regulators Discuss Need for Pricing Rule Changes.)
Walker said she is hopeful about “getting those things behind us,” despite apparent stakeholder concerns that the PUC is moving too quickly.
“I’ve been astonished in the past week by people saying we’re rushing to a decision on this,” Walker said, noting potential market reforms were before the commission when she joined last year. “It doesn’t feel like much of a rush to me. I guess people judge rushes differently.”
Enforcement Actions Result in $2.83M in Penalties
The PUCT released a report detailing its enforcement actions for the 2018 fiscal year.
According to the “2018 Summary of Customer Complaints and Enforcement Activities,” commission staff concluded 114 investigations, with results ranging from fines and license revocations to findings of no violation. The PUC approved orders imposing $2.83 million in administrative penalties and returning more than $108,000 in refunds to Texas ratepayers.
“The Texas Legislature created a level playing field for the companies competing to serve utility customers, and it’s our job to throw penalty flags for infractions,” Walker said in a release.
Electric retail and wholesale issues accounted for 40% and 24%, respectively, of the investigations. Water (25%), electric service quality (9%) and telecommunications (2%) made up the rest.
Non-IOUs Get Rate-Review Schedules
In other actions, the PUCT approved a rate-review schedule for non-investor-owned transmission service providers (Project 48377) and modified a previous order granting Oncor a certificate of convenience and necessity for its Far West Texas Project (Project 48095). (See PUCT Grants Oncor CCN for Far West Texas Project.)
During their executive session, the commissioners agreed to intervene in two Entergy dockets before FERC:
Entergy Services’ request to transfer its ownership interests in two transmission control centers to Entergy’s operating companies (EC19-18). The centers are in Jackson, Miss., and Little Rock, Ark.
Entergy Services’ filing of an unexecuted joint ownership and operating agreement that identifies the terms and conditions of the operating companies’ ownership of the control centers (ER19-211).
NERC is proposing a new approach to how it collects and presents metrics, advancing a “dashboard” that separates measures of industry performance from those indicating how well the organization is meeting its goals.
CEO Jim Robb said the dashboard represents a “very different approach to performance management than what we’ve done in the past” and that executives will use it to allocate resources.
The dashboard shows green for risk indicators that are improving, yellow for stable metrics and red for metrics getting worse.
For 2018, the indicators showed improvements in the number of bulk power system events; forced outages because of cold weather or lack of fuel; outages resulting from operator or other human performance issues; and unauthorized physical or electronic access.
Vegetation encroachment metrics were unchanged from 2017, while protection system misoperation rates and failures of substation and circuit equipment got worse.
NERC’s three-year operating plan lists six goals: developing risk-responsive reliability standards; objective, risk-compliance monitoring, mitigation and enforcement; reducing known reliability risks; identifying and assessing emerging risks; reducing cyber and physical security; and improving its efficiency and effectiveness.
FERC Commissioner Cheryl LaFleur, who attended the meetings, said she supports separating the metrics into two categories but questioned the cybersecurity metric. “Losing load from a cyber incident is a pretty gross standard [for measuring cybersecurity]. There must be leading indicators, [numbers of] incursions or whatever. That’s something that [FERC has] been focused on: … trying to get more data.”
Robb acknowledged that the metric was “anemic” and said NERC is seeking ways to capture other indicative data.
In written comments, the ISO/RTO Council (IRC) supported the bifurcation of the metrics but said tools other than standards and enforcement “needs to be a higher priority” for NERC.
“With steady state standards, efficiency reviews and compliance program enhancements to reduce the compliance burden, NERC must develop alternative methods to effectively address new and evolving reliability concerns without having to undo or jeopardize these past improvements and effective compliance behaviors,” the IRC said, adding that some existing metrics “do not have a direct correlation with NERC programs.”
The IRC also expressed concern over the proposed color choices, saying yellow should be replaced with a “neutral” color to illustrate metrics that are unchanged and satisfactory. “A yellow color is associated with caution or imminent threat and can be misinterpreted,” it said.
The North American Generator Forum, the Northeast Power Coordinating Council, the Cooperative Utility sector, the Canadian Electricity Association (CEA) and the Edison Electric Institute all generally supported the revised metrics.
The CEA called for additional metrics to define an “adequate level of reliability.”
EEI questioned a goal focused on enhancing or proposing new standards. “NERC should consider the use of other tools (e.g., Reliability Guidelines, lessons learned, best practices), in addition to reliability standards, similar to the [electric reliability organization’s] compliance and enforcement philosophy, to efficiently and effectively address reliability and security risk,” EEI said.
Robb said the feedback will be incorporated in the final dashboard model.
Addressing Overlap of CIP, Planning and Operating Committees
Mark Lauby, NERC senior vice president and chief reliability officer, briefed the MRC on a proposal to rethink its committee structure to respond to what he called the “increasing convergence” of subjects overseen by the Critical Infrastructure Protection, Planning and Operating committees.
NERC briefed stakeholders on a proposal to rethink its committee structure to respond to the increasing convergence of the subjects overseen by the Critical Infrastructure Protection, Planning and Operating committees. | NERC
Lauby said the MRC should consider eliminating those committees and using “mission-driven” task forces that would study an issue, make recommendations and disband when their missions are complete.
Lauby said the current committee structure, in place for more than a decade, is “expensive and time consuming” for NERC members and that the committee “silos” are blurring in part because of new technologies and changing industry models.
Task forces, he said, could ensure the stakeholders have the right subject matter expertise.
Consultant Herb Schrayshuen, representing the Small End‐Use Electricity Customer sector, and Oncor Vice President of Regulatory Affairs Liz Jones, representing the Regional Entity sector, said the committees are necessary for some recurring tasks such as annual reliability assessments. Jones said the PC and OC don’t need to meet quarterly or separately, but “there is value in retaining” them.
NERC said that in addition to Midwest Reliability Organization, the Florida Reliability Coordinating Council, SERC Reliability and Western Electricity Coordinating Council also have reorganized their committee structures.
The Western Area Power Administration’s Lloyd Linke, a member of the MRO board, said he generally supported the change, calling it “somewhat similar to the process that the MRO” has adopted. “When the MRO did this, they did keep some committees … to provide some of that continuity on some of the yearlong type things,” he said.
Carol Chinn, representing the State/Municipal Utilities sector, said the proposal was a good start but “there needs to be much more dialogue” with MRC members before changes are made.
MRC Vice Chair Greg Ford agreed “it is time to look at our committee structure.”
“The right answer may be: Keep the three committees but streamline them,” he said.
NERC plans to create a staff/stakeholder working group reporting to the board to explore the issue further and develop a restructuring proposal.
“Let’s set some sort of a time frame,” NERC Trustee Dave Goulding said, “because this is a project that could go on and on and on and you’ll never get everybody on board.”
Long-Term Reliability Assessment Sees Shortfalls in CAISO, MISO, Ontario
John Moura, NERC’s director of reliability assessments and technical committees, gave a presentation on the draft 2018 Long-Term Reliability Assessment through 2028, noting it is the first such report to include metrics on “essential reliability services” such as frequency response and ramping capability.
Moura said the projected 10-year compound annual growth rate for North America of 0.57% (summer) and 0.59% (winter) is the lowest on record. None of the regions projects annual load growth of more than 2%.
“For the first time, we’ve seen five areas — New York, New England, Maritimes, Manitoba Hydro and the WECC California-Mexico area — actually reducing [their] peak demand over the 10-year period,” he said. “That’s kind of unheard of.”
In 2008, NERC projected a 30-GW increase in coal generation by 2018. Instead, coal capacity dropped by 50 GW. It also vastly underestimated the increase in natural gas generation, having predicted an increase of only 50 GW. | NERC
The report projects MISO and Ontario will see planning reserve margin shortfalls beginning in 2023. In addition, probabilistic evaluations indicate resource adequacy risks in the California and Mexico region of WECC in off-peak hours after the sun sets and during spring and fall maintenance outages. The loss-of-load expectation for the WECC-CAMX region — most of California and a small northern portion of Baja California — is projected to rise from nine hours in 2020 to 95 in 2022.
Although the grid is losing inertia as renewables replace synchronous generation, all interconnections should have adequate frequency response through 2022, the report says.
The report projects the addition of more than 30 GW of distributed solar PV by the end of 2023, when it said California will have 18 GW and Massachusetts and New Jersey will have 4 GW each.
But Moura said the report should be viewed with humility, saying stakeholders should remember that the only certainty about its projections is that they will be wrong. In 2008, he noted, NERC projected a 30 GW increase in coal generation by 2018. Instead, coal capacity dropped by 50 GW. “That was an 80-GW miss,” he said.
It also vastly underestimated the 200-GW increase in natural gas generation, having predicted an increase of only 50 GW.
The departure of Peak Reliability as the reliability coordinator in the West will create new seams between the RC footprints of CAISO, SPP, the Alberta Electric System Operator (AESO) and BC Hydro. | WECC
Update on Western Reliability Coordinators
WECC CEO Melanie Frye provided the board with an update on efforts by CAISO and SPP to replace Peak Reliability as the reliability coordinators (RCs) in the Western Interconnection. (See Western RC Transition ‘Hot Topic’ at WECC Meeting.)
She said officials have identified tie lines that begin in one RC footprint and end in another, including 114 such lines between CAISO and SPP. “So we’re doing some additional technical analysis to try to understand what could be the change in flows in the system if there were to be elements out of service,” she said. “What that’s really highlighted is the need for both RCs in that example to model the broader footprint.”
Robb said he was “very pleased” with NERC’s collaboration with WECC, CAISO, SPP and others to address the transition, but he acknowledged concerns over seams in the desert Southwest.
“There’s the potential for a couple seams to be developed between Phoenix and San Diego. That’s a very important path and has been a very vulnerable path in the West. So, there’s a lot going on to understand issues that that topology creates and how to manage through it,” Robb said.
NERC Chair Roy Thilly said “it appears that everything is being looked at very, very thoroughly.”
But Robb acknowledged concerns heading into winter 2018/19. “We haven’t completed the inquiry … but there was an awful lot of generation offline during that event, which at least raises the question about whether or not cold-weather preparation is adequate for the circumstances.
“This is the third [winter] in a row that we’ve had some large amounts of generation offline.”
TPL-001-5, a response to FERC’s 2013 Order 786, which will require assessments of single points of failure and inclusion of them in future transmission studies. Based on a cost-benefit analysis and industry feedback, NERC decided not to require eliminating single points of failure, said Howard Gugel, senior director of engineering and standards. “The response that most of industry and NERC staff [agreed on] is no … there is some risk that — as long as you know what that risk is — it’s a risk that’s acceptable to have and at least know how that risk can be mitigated.” Gugel said that out of 12,000 misoperation events in NERC’s database since 2011, less than 30 involved three-phase faults, and “we only had 10 instances where a three-phase fault was also associated with a relay failure. We also [asked], of all the events that we’ve seen on the system, do any of those correlate with any of those 10? … We cannot find an instance in the data we have.”
The standard specifies the types of events and nonredundant protection system components that should be studied. It also eliminates the minimum six-month threshold for including outages in planning studies, which FERC said “could exclude planned maintenance outages of significant facilities from future planning assessments.”
The retirement of IRO-006-TRE, which is redundant to other reliability standards. The Texas Reliability Entity board approved its retirement in September.
The Reliability Standards Development Plan for 2019-2021, which focuses on periodic reviews, FERC directives, the Standards Efficiency Review and the standards grading initiative.
Revisions to sections 600 (Personnel Certification) and 900 (Training and Education) of NERC’s Rules of Procedure. The revisions are in response to a July 19 FERC order (RR17-6) that changes regarding NERC’s training and continuing education programs but rejected deletion of its personnel certification rules. (See “Split Ruling on NERC Rules of Procedure,” FERC Orders Expanded Cybersecurity Reporting.)
The execution of a memorandum of understanding outlining MRO’s compliance monitoring of Manitoba Hydro.
New MRC Officers, Seeking Canadian Trustee
Trustee Fred Gorbet, head of the board’s Nominating Committee, said a five-person interview team has met with candidates to replace him as the Canadian representative on the board. The team will share its recommendation with the committee Dec. 10 with hopes to install the winner in February 2019, said Gorbet, who is leaving because of NERC’s term limits.
The MRC elected Greg Ford as chair and Jennifer Sterling vice chair for 2019. Ford is CEO of Georgia System Operations Corp., which manages 38 distribution cooperatives and Oglethorpe Power. Sterling is vice president of NERC compliance and security for Exelon.
The quarterly Trustee meeting was the last for retiring John P. Hughes, president of the Electricity Consumers Resource Council (ELCON) and NERC’s Tim Roxey, chief operations officer for the Electricity Information Sharing and Analysis Center (E-ISAC).
“I will miss [Hughes’] voice,” LaFleur said. ELCON, which represents industrial customers, has tapped Devin Hartman, formerly of the free-market think tank R Street Institute, as its new chief executive effective Jan. 1. Hughes, who has degrees in engineering and economics, joined ELCON in 1987 and became its CEO in 2015.
Roxey, a former nuclear engineer who began working at the E-ISAC in 2009, received a commemorative resolution and a standing ovation from the approximately 200 stakeholders.
“It has indeed been a long strange trip,” Roxey said. “You cannot have a bulk power system or a distribution system [be] reliable without the support and functioning of all of this,” he said, looking at the dozens of stakeholders in the large hotel ballroom. “I’ve come to understand and appreciate [reliability] standards and compliance — which I used to object to, but I now embrace as a necessary part of the [Compliance Monitoring Enforcement Program]. It is critical … that we be proactive in creating standards because that’s what we do. We don’t have to be told.”
FERC on Friday approved ISO-NE’s plan to correct a key calculation in evaluating delist bids, a change that could reduce capacity prices.
The 2-1 ruling, supported by Commissioners Cheryl LaFleur and Richard Glick, prompted a dissent by Chairman Neil Chatterjee, who said that making the change effective for Forward Capacity Auction 13 violated the commission’s rule against retroactive ratemaking (ER18-1770). Commissioner Kevin McIntyre, who is battling a brain tumor, did not participate.
At issue was how ISO-NE’s Internal Market Monitor calculates the “economic life” of resources that want to retire or permanently leave the capacity market. Such a resource must provide at least five years of cash flow estimates to justify their delist bids, which specify the price at or below which it would retire.
To determine whether the bid price is competitive, the Monitor calculates the expected remaining economic life of the resource — the number of capacity commitment periods in which the resource could continue operating profitably. The Monitor calculates the competitive delist price as the lowest capacity payment at which the resource would be no worse off by retaining its capacity obligation rather than retiring immediately.
ISO-NE said the Monitor recently determined that its calculations — which defined the economic life as the period for which the resource’s cumulative net present value (NPV) is positive — were overstating the true economics of some resources and could result in improperly high delist bids.
The calculation assumed that a resource that earned positive cash flows in the earlier years would continue to operate while suffering losses as long as the cumulative cash flows remained positive — an assumption that ignored that a resource would choose to retire as soon as its cash flows turned negative.
Under the new rules, the economic life of a resource will be the period that maximizes the NPV. The rules are effective Aug. 10, 2018, and will apply for FCA 13 in February 2019.
In ISO-NE’s filing, Hemant Patil, an economist with the Monitor, gave an example of a resource that expects positive cash flows of $5 million in year one and negative cash flows of $3 million in year two and each subsequent year. “The current Tariff calculation would yield an economic life of two years because the resource could operate for two years with resulting cumulative cash flows of $2 million — positive $5 million in year one plus negative $3 million in year two. This assumption is inconsistent with how a competitive supplier would operate a resource. In this example, the supplier would not choose to operate its resource beyond year one and incur the negative cash flows of $3 million in year two. Instead, it would choose to exit the [Forward Capacity Market] after year one in order to maximize its cumulative cash flows at $5 million.”
ISO-NE and the New England Power Pool’s Participants Committee said they sought the change after an unidentified supplier submitted delist bids for four resources totaling 2,000 MW for FCA 13, which they said could harm the competitiveness of the auction.
The RTO gave another example in which its prior rules estimated a resource would need $11 million in revenue to break even, inflating the delist price by $2.5/kW-month over the $8 million revenue requirement under the revised rules. If the supplier has market power, it could also inflate the prices for the remainder of its portfolio. If that unit was the marginal bid affecting 30,000 MW of cleared capacity, the incorrect calculation would raise consumer costs by about $900 million ($2.5/kW-month x 12 months x 30,000 MW), the RTO said.
LaFleur and Glick rejected a protest by the New England Power Generators Association, which complained that the Aug. 10 effective date requested by ISO-NE and NEPOOL disrupted market expectations and violated the commission’s rule against retroactive ratemaking. NEPGA asked the commission to reject the proposal and order the RTO to bring it before stakeholders, with no changes effective before FCA 14 in 2020.
The proposal was approved by NEPOOL’s Markets and Participants committees, both with about 69% in support. The commission said that although the stakeholder review was “expedited, the record reflects that ISO-NE met its burden for stakeholder review … under its Participants Agreement.”
“A rational resource, in exercising competitive bidding behavior, would seek to exit the market, or retire, before it starts incurring consecutive losses,” the commission said in approving the change. “The benefits of the proposed economic life revisions outweigh potential disruptions to market participants’ settled expectations and harm caused by reliance on the existing [capacity market] rules.”
Chatterjee disagreed, saying that making the rules effective for FCA 13 harmed “market participants who relied on the existing Tariff in calculating prices and entering into contracts” in preparation for the auction.
Chatterjee said it was “troubling” that the RTO submitted the proposal after calculating the economic impact of the existing rules. “This change would achieve a specific price-oriented outcome based on information ISO-NE possesses due to its unique role as both system operator and auction administrator,” he said. “This case raises very serious questions about when and how the rule against retroactive ratemaking applies.”
MISO and SPP last week agreed to file changes to their joint operating agreement that they say will smooth the approval of interregional projects.
The changes, to be filed at FERC early next year, will eliminate the $5 million cost threshold for the projects, add avoided costs and adjusted production cost benefits to project evaluation, and remove the joint modeling requirement in favor of individual RTO regional analyses. The RTOs will also increase the regularity with which they produce a coordinated system plan (CSP), the joint study used to identify interregional transmission needs. (See MISO, SPP Loosen Interregional Project Requirements.)
The JOA revisions will not lower a 345-kV voltage requirement mandated by MISO, though the RTOs last month said they might create a category of smaller interregional transmission projects without voltage requirements. (See MISO, SPP Mulling Small Interregional Project Type.)
The RTOs earlier this year said the criteria currently spelled out in JOA might be preventing beneficial interregional projects from gaining approval.
“I think SPP and MISO are on the same page on these JOA changes,” SPP Interregional Coordinator Adam Bell said during a Nov. 9 Interregional Stakeholder Planning Advisory Committee conference call.
However, Bell said the revisions won’t be considered final until they’re reviewed by both RTO legal teams. He said the RTOs hope to file the changes in February and will likely hold another conference call with stakeholders before then.
But Entergy’s Jennifer Amerkhail said the JOA revisions lack the FERC Order 1000 safeguards requiring transmission developers to first propose projects to RTOs jointly before they are evaluated in each individual regional process. She said it was important for interested parties to review projects, especially because relaxed cost requirements will result in a higher number of proposed interregional projects. Amerkhail promised to provide SPP and MISO with proposed redlines so that a joint review is clearly stated as a first step before projects are put to regional review.
RTO staff said the regional analysis design will be a more efficient process than building a joint model, and other stakeholders pointed out that MISO and SPP have never approved an interregional transmission project.
“It’s not like the world is running amuck and there’s thousands of interregional projects getting proposed,” LS Power’s Pat Hayes said.
The revisions also prescribe that the CSP will take place annually automatically unless staff from either RTO vote to skip a year. The new rules require the CSP be developed no less than once every three years. The JOA currently stipulates that CSPs are produced only when either MISO or SPP staff raise the issue and then both agree to a plan.
“It moves the default from not doing a study to doing a study,” Bell said.
SPP and MISO still have at least one JOA revision to iron out: whether to include negative adjusted production costs (APC) in the evaluation of reliability interregional projects as well as economic projects.
The JOA currently requires that negative APC not be considered in the cost allocation of interregional reliability projects. Each RTO calculates APC using its own regional models.
MISO Planning Adviser Davey Lopez said MISO believes the most equitable cost allocation would include the impacts of negative APC. SPP, however, only commits to supporting “continued stakeholder discussion on whether or not negative APC values should be considered.” Bell said by including negative APC, the RTOs might find themselves in a situation where the JOA won’t allow them to pursue an otherwise beneficial reliability project for both regions.
Bell asked stakeholders to submit their opinions on negative APC to SPP. Some stakeholders at the meeting said excluding negative APC from an interregional reliability project assessment results in a biased and less transparent project evaluation.
M2M Payments Again in MISO’s Favor
MISO recorded its third straight month of market-to-market (M2M) payments from SPP in September, with the latter sending the former slightly more than $165,000.
The total, less than a quarter of what SPP sent MISO the month before, reduced the amount of M2M payments SPP has accumulated to $51.2 million since the two RTOs began the M2M process in March 2015.
| SPP
Temporary flowgates were binding for 519 hours in September, resulting in $1.2 million in M2M payments to MISO. That was almost entirely negated by $1.1 million for permanent flowgates binding for 110 hours in SPP’s favor.
PJM stakeholders last week dug in further on the RTO’s proposed revamp to its capacity market, reiterating comments made last month in FERC’s paper hearing on the proposal (EL16-49, ER18-1314, EL18-178).
In reply comments Nov. 6, PJM rebutted “anticipated” criticisms of its Extended Resource Carve-out (RCO) proposal, which would allow specific, state-subsidized resources to opt out of the capacity market and the RTO to adjust market clearing prices as if the resources were still in.
State renewable portfolio standards and impact on PJM (2009-2033) | PJM
PJM’s proposal is a response to the Fixed Resource Requirement (FRR) Alternative FERC recommended when it found the RTO’s minimum offer price rule (MOPR) unjust in June. PJM’s current FRR only allows utilities to opt out of the market if they can serve all of their load through other means, such as bilateral contracts.
“Despite the hundreds of pages of initial comments, barely a handful provided the commission with detailed proposals supported by pro forma tariff changes,” PJM said. “Of those that did, only PJM’s proposal meets both key objectives, i.e., preserving competitive markets while accommodating state policies.” (See Little Common Ground in PJM Capacity Revamp Filings.)
Critics generally fell into two camps. One argued for a rejection of any carve-out, calling instead for a “clean,” MOPR-only construct that extended to all resources. The other generally supported the concept of the FRR Alternative but argued that because of the repricing mechanism, Extended RCO would lead to inflated capacity prices.
Exelon said the FRR Alternative “strikes a just and reasonable balance among equally important policy goals. It makes room for states to pursue energy policy initiatives favoring particular types of generation resources, by allowing states to provide for the procurement of their capacity outside the PJM auction market — but credits load for that capacity, thus avoiding unnecessary costs for customers.”
Exelon said “the Extended RCO results in … massively inflated customer costs because of a fatal design flaw: PJM proposes to set the stage 2 price — which cleared resources would be paid — by removing RCO resources from the supply curve entirely. In other words, rather than resetting the bids of RCO resources to ‘competitive’ levels at stage 2, as the MOPR purports to do, the Extended RCO simply acts as though the RCO resources do not exist. That makes no sense.”
The Maryland Public Service Commission, which also argued that Extended RCO would lead to inflated clearing prices, proposed a separate auction for state-subsidized resources.
“Resources that do not clear the auction but serve to set a higher clearing price would be paid what PJM terms as ‘infra-marginal rent payments,’” the PSC said. “These potentially perpetual payments, in the form of uplift, are characterized as rents those resources would have ‘earned’ had they cleared the auction at the elevated artificial clearing price.”
FirstEnergy Solutions called Extended RCO “a reasonable means of accomplishing the objectives articulated by the commission.” But it also criticized PJM’s proposal to continue applying the MOPR to previously subsidized resources seeking to re-enter the capacity market. “The commission should consider the reality of this proposal: Most resources that elect the [resource-specific FRR] for some period of time would effectively be precluded from ever re-entering” the capacity market, FES said.
Exelon also joined in a reply brief in support of the FRR Alternative filed by a diverse group of stakeholders: the Nuclear Energy Institute, the Illinois Citizens Utility Board, the Natural Resources Defense Council, Talen Energy, the Sierra Club, PSEG Energy Resources & Trade and the D.C. Office of the People’s Counsel.
Noting that they frequently disagree on other issues, the groups said, “We are unified, however, in our belief that the commission and PJM must reasonably accommodate states taking actions to achieve their clean energy policies. …
“The only parties arguing against the concept of balancing an expanded MOPR with adoption of a resource-specific FRR mechanism are the companies that have brought — and lost — legal challenges to the states’ authority to implement clean energy programs.”
Clean MOPR
The Electric Power Supply Association, the PJM Power Providers Group and NRG Power Marketing continued to insist on a clean MOPR, in which all resources, with limited exceptions, are subject to the rule. They also criticized FERC’s FRR Alternative proposal.
“As acknowledged by PJM and others advocating such an approach, the FRR Alternative will negate the remedial benefits of an expanded MOPR and thus perpetuate the price suppression problem that the commission properly found to be unjust and unreasonable in the June 29 order,” EPSA said. “Adopting such a replacement rate would be irrational and unacceptable as a policy matter and unlawful as a statutory and constitutional matter.”
“Let’s call FRR-A what it is: a proposal to reregulate a substantial portion of the competitive wholesale market,” NRG said. “Adopting FRR-A would signal a retreat from the competitive markets that the commission has espoused since its landmark Order No. 888. Like all massive government interventions in the market, FRR-A would stifle the efficient allocation of private capital, shift costs and risks to consumers, and replace private, at-risk investment with ratepayer-backed investment.”
EPSA criticized Exelon, whose nuclear plants in Illinois are the beneficiaries of zero-emission credits, for calling for a blanket waiver of FERC’s affiliate transaction rules in espousing the right of states to choose how they procure energy. In its initial brief, Exelon had said, “At the very least, the commission should treat state involvement in the procurement of capacity by a load-serving entity from an affiliated generation company as strong evidence pointing against any affiliate abuse.”
“Leaving aside the fact that it is a bit rich for Exelon to imply that the Illinois legislature spontaneously decided to award Exelon billions of dollars in subsidies, there is simply no basis for the contention that the commission’s concerns about rates negotiated between affiliates are a function of the level of ‘state involvement,’” EPSA replied. “The commission has a statutory duty to ensure that rates for wholesale sales are just and reasonable and … that duty may not be delegated to the states.”
‘Moral Obligation’
Calpine, which had led a challenge to PJM’s MOPR in 2016, argued that Extended RCO was FERC’s best option, and that it had a duty to it and other generating companies to implement the proposal.
“The commission cannot turn its back on existing generators,” Calpine said. “Not only does the commission have a statutory obligation to ensure that capacity market prices are just and reasonable, the commission also has a moral obligation to implement rules that allow competitive generators the opportunity to recover their investments in the market. …
“Competitive generators have flocked to the PJM market, investing tens of billions of dollars of private money with the understanding that they will have a fair opportunity to recover their investment. There was no guarantee that their investment would be recovered, but there was a regulatory compact that PJM and the commission would protect and defend competitive markets, so investors have the opportunity to compete on a level playing field. … If the commission fails to take the necessary action in this proceeding to shore up the structure of PJM’s capacity market, then the commission must be prepared to develop mechanisms to provide stranded cost recovery for these investors who were otherwise tricked into investing capital in a market with no meaningful opportunity to recover that capital, and a fair return with it.”
Calpine’s claim was rebutted by the Harvard Electricity Law Initiative in the opening lines of its comments. “As the commission considers how to avoid raising wholesale capacity rates, it should discount generators’ warnings that they may demand ‘stranded cost’ recovery if the commission does not approve their preferred approach to the PJM Tariff,” it said.
“Generators’ actual expectations about market rules and prices are premised on a mistaken view of the commission’s ratemaking authority and have no equitable force,” Harvard said. “Generators assert that the commission must approve a ‘clean’ market, untouched by direct and certain indirect government interventions, to ensure that the PJM capacity auction is ‘competitive.’” The judiciary has held that the “just and reasonable” standard in the Federal Power Act does not necessarily mean “structurally competitive,” Harvard noted.
Ari Peskoe of the Harvard Electricity Law Initiative created this wheel to illustrate the range of opinions on PJM’s capacity market. “How will FERC decide? Lots of options. Here’s a handy tool FERC can use to pick the design of the next PJM capacity auction,” he tweeted.
Consumer Responses
A group of industrial customers said the Extended RCO should be rejected because it is essentially identical to the capacity repricing proposal the commission rejected in June as an unjust cost shift. “In addition to discriminating against customers that are captive to states that are subsidizing resources, the Extended RCO is likely to produce pricing outcomes that cannot be defended as being just and reasonable.”
State consumer advocates for Illinois, West Virginia, Delaware, Maryland and D.C. said there is no evidence that state resources are suppressing capacity prices, noting that “PJM has two-thirds more capacity than necessary to meet its reliability requirement, the largest excess of any RTO in North America.”
They also said PJM’s proposed resource-specific criteria for the carve-out are too restrictive. “States should be allowed to count carved-out resources toward resource adequacy requirements according to actual grid needs, which are portfolio-wide and seasonal,” they said.
PJM’s Independent Market Monitor lobbied for its proposed “Sustainable Market Rule,” which would allow all nonmarket resources to participate in the energy market but use the capacity market as a “balancing mechanism” to provide incentives for entry and exit.
“If resources offer at competitive levels and clear the capacity market, the resources are paid the market clearing price. If resources do not clear the capacity market, the resources are not paid for capacity,” the Monitor said. “Any nonmarket revenues required to meet the public policy goals associated with these resources would be provided outside the market in whatever manner the supporters of those resources choose.”
The Organization of MISO States said Friday that Executive Director Tanya Paslawski will depart the organization at the end of the year.
Paslawski has accepted a position as president of the Michigan Gas and Electric Association starting Jan. 1, 2019, and will resign her OMS post effective Dec. 31.
Paslawski joined OMS in 2014 as the organization’s deputy executive director, becoming executive director in 2015. Prior to OMS, she worked for ITC Holdings and was a staffer at the Michigan Public Service Commission.
OMS leaders said Paslawski navigated the organization through a transitional stage as the electric industry itself experiences change.
“Tanya has brought leadership, knowledge of the industry and an ability to forge consensus among regulators in the MISO footprint. She has served with distinction, and I wish her well in her new position,” OMS President Ted Thomas, chairman of the Arkansas Public Service Commission, said in a statement.
“Tanya did an incredible job as OMS executive director, providing astute legal and policy analysis on complex and critical issues … and her ability to facilitate consensus on those issues will be deeply missed,” OMS Vice President and Missouri Public Service Commissioner Daniel Hall said.
Paslawski had lauded the organization’s perseverance and collaborative nature during the OMS Annual Meeting and 15-year anniversary celebration last month. (See Overheard at OMS 2018 Annual Meeting.)
OMS’ executive committee will open a search to select a new executive director, who will be subject to confirmation by the organization’s board of directors. Staff said the search for a replacement will be opened next week, with any next steps, including the potential need for an interim director, determined thereafter.
