ReliabilityFirst briefed members Monday on spot checks it plans for about 35 generation owners (GOs) and operators (GOPs) in 2020.
Brian Thiry, RF’s manager of operations and planning compliance monitoring, said the spot checks will focus on risks of insufficient long-term and operations planning that were identified in the 2019 and 2020 NERC Compliance Monitoring and Enforcement Program implementation plans. These include inadequate models, failure to report generator capabilities, resource adequacy and the ability to ride through grid disturbances.
Entities receive notice of the spot check five weeks in advance of when RF needs the evidence. During the first three weeks, the entity works with the RF team lead on collecting sampling data. “The team lead is there to help you — to walk you through the process,” Thiry said during RF’s monthly compliance call.
Some of the entities are subject to spot checks because of compliance oversight plans from audits in the last several years. For others, the notices are “unanticipated and unexpected,” he said.
Auditors testing GOs on PRC-019-2 R1 and PRC-024-2 R1 and R2 will review implementation plans, check to see whether all required testing was performed and whether the generator will trip in the “no trip” zone. They will test compliance with MOD-025-2 R1 and R2 by reviewing implementation plans and testing, and ensure there are no gaps in the information requested by transmission planners.
GOPs will be evaluated on VAR-002-4.1 R2. Auditors will be evaluating internal controls on situational awareness, alarming, notifications and training, and conducting sampling to ensure generators are operating within their voltage schedules.
“These are some of our most frequently violated requirements [for generators] over the last two years or so” as the generation mix has changed with the increase in renewables with inverter-based relays, Thiry said. “Even though [there’s] less … penetration in the Midwest, we still want to stay ahead of this risk.”
Thiry described spot checks as “a mini, more targeted audit.”
“It has a lot less moving parts than an audit. During an audit, it’s a longer period. We would take a harder look at your culture and your controls.”
For a spot check of VAR-02, for example, “we don’t look at every single one of your generators for every single day. We’d be looking at a sample scope of certain generators on certain days.”
Thiry suggested GOPs document the reasons for any excursions above or below their bandwidths and provide graphical representations in 10-minute increments.
“A picture’s worth 1,000 words. If it’s something that you could graph, that really helps us out and helps us [conduct] a fast, efficient review, so these spot checks can stay within that two-week time frame.”
Self-reports
Thiry said internal controls should be monitored continuously and that entities should self-report before the spot checks if they failed to meet an implementation milestone or perform required tests.
“We don’t want to wait until the spot check notification letter comes out to identify an issue. Because whatever this issue is, it can be identified, addressed and mitigated now. We don’t have to wait five months to put a control or mitigating plan in place,” Thiry said. “If you self-report it now, we can get to the bottom of it, [and] work with you on the fixes and the mitigation. And you get the credit for identifying it on your own without us having to find it.”
Thiry said self-reports should include the root cause of the problem. “That helps [enforcement] identify the extent of condition and what other risks may exist,” he said.
Thiry said he would provide additional communications on the spot checks during future reliability calls or in the RF newsletter.
PJM on Monday named former Direct Energy executive Manu Asthana as its choice for president and CEO, ushering in a new era of leadership at the RTO after a tumultuous year of internal reorganization and executive departures. He will join PJM on Jan. 1.
“We welcome Manu to lead PJM into the future,” PJM Chairman Ake Almgren said in a press release. “The electric industry is rapidly changing and PJM needs to continue to evolve. Manu comes to PJM with a wealth of experience from the electricity value chain and we are confident that he will bring new and important perspectives to the organization.”
Manu Asthana | PJM
Asthana’s two-decade career in the energy industry includes a stint as TXU Corp.’s chief risk officer and overseeing both power generation operations and energy trading for Direct Energy, a subsidiary of U.K.-based Centrica.
As president of Direct Energy Home in North America from 2015 through 2018, he led a staff of more than 2,600. The company, which offers retail electricity, home warranties, HVAC services and appliance rentals, claims to serve 3.4 million residential and small business customers in the U.S. and Canada.
Almgren said Asthana’s expertise will enhance PJM’s engagement with members and policymakers. Asthana has a bachelor’s degree in economics from The Wharton School at the University of Pennsylvania.
Asthana, his wife, Aparna, and their family will relocate to the Philadelphia area from Texas, where he served on the boards of Texas Children’s Hospital, the Houston Food Bank and Child Advocates.
Year of Change
PJM’s year of change began in February when longtime CFO Suzanne Daugherty announced her retirement amid the RTO’s overhaul of its credit policies and financial risk procedures following the default of GreenHat Energy.
Daugherty found herself the target of PJM members’ ire after GreenHat amassed 890 million MWh of financial transmission rights while putting up only $600,000 in collateral.
Manu Asthana (right) and then-Direct Energy CEO Badar Khan, (left) announce a $5 million donation to Texas Children’s Hospital in 2015. | Direct Energy
Her retirement was announced by CEO Andy Ott, who himself retired in May, two months after an independent probe into the GreenHat debacle concluded PJM staff ignored red flags about the company’s assets and exhortations from other members about the portfolio’s financial shortcomings. (See ‘Naive’ PJM Underestimated GreenHat Risks.)
The executive departures continued after interim CEO Susan Riley stepped in for Ott. In September, Riley announced the resignation of Vice President Denise Foster and the restructuring of the State and Member Services Division that she had headed. Foster had no role in the GreenHat episode. (See Stakeholders, States in Dark over PJM Personnel Moves.)
Last week, General Counsel and Senior Vice President Vince Duane resigned after more than 16 years “to pursue other opportunities.”
Almgren said Riley will resume her position with the board once Asthana assumes his role next year.
“We highly appreciate Sue Riley for her leadership during this challenging time,” he said. “She has been working with PJM management, members and policymakers in dealing with the many issues at hand at PJM and has laid a strong foundation for Manu to build on going forward.”
California officials hammered Pacific Gas and Electric executives on Monday over the utility’s mishandling of multiple public safety power shutoffs (PSPS) that left nearly 2.4 million residents in the dark last month.
PG&E, Southern California Edison and San Diego Gas & Electric all implemented PSPS events in October after the National Weather Service issued multiple red flag alerts that predicted dry, windy conditions at the height of the state’s wildfire season.
The California Senate Energy, Utilities and Communications Committee convenes Nov. 18 to discuss lessons learned from recent power shutoffs.
It was PG&E’s dereliction of long-established protocols for public notification and emergency preparedness, however, that set the investor-owned utility apart from the rest, officials told the Senate Energy, Utilities and Communications Committee during a six-hour hearing Monday.
“This was a world-class emergency response from the state of California,” California Public Utilities Commission President Marybel Batjer said. “I was also provided with insight into how a tool like PSPS intended to protect people and communities from harm can, when implemented haphazardly, generate the opposite effect.”
PG&E Response
California’s IOUs began using PSPS as a wildfire mitigation tool only within the last decade after damaged transmission lines sparked some of the deadliest blazes in state history, including last year’s Camp Fire that killed 85 people and leveled the town of Paradise.
Some officials, however, worry that utilities lean too much on the controversial practice to shield their companies from liability over faulty and neglected equipment. IOU shutoffs have nearly tripled since 2017, with 14 called so far this year.
PG&E CEO Bill Johnson
PG&E CEO Bill Johnson rejected that perception and said the utility has spent $30 billion over the last decade upgrading its transmission system. He blamed some of the company’s reliance on PSPS on the growth of high-risk fire areas within its 75,000-square-mile service territory — up from 15% in 2012 to more than 50% in 2019 — and predicted that the utility will continue the practice for another 10 years while it completes system-hardening initiatives.
“Let me emphasize the basic fact that should be obvious … we don’t actually want to turn anybody’s power off,” he said. “We recognize that living without power is more than just an inconvenience. For many, it’s a hardship. None of us want to live in that world, but we are doing this to prevent the spread of deadly catastrophic fires we’ve experienced in the last few years.”
But officials said PG&E seemed ill-prepared to manage the strategic shutoffs, despite months of preparation in coordination with state agencies.
Mark Ghilarducci, director of the governor’s Office of Emergency Services, said despite his office’s outreach to PG&E, the utility’s response during last month’s events lacked consistency and generated widespread confusion. He said PG&E didn’t provide detailed and timely notification of planned outages to its affected customers and couldn’t offer enough support via backup generators to critical medical baseline ratepayers or oversee other essential infrastructure during the three dayslong shutoffs that occurred on Oct. 9, 26 and 29.
“This was quite frustrating to us, particularly when we started to roll into these bigger problems, which we anticipated in those meetings that we talked about and wanted to address then,” he said.
Some of those bigger problems included widespread communications outages that prevented customers from contacting emergency services or accessing updates about the shutoffs. Residents in Mendocino and Marin counties lost complete access — via landlines, cell phones or internet — after 1,600 cell sites failed.
Ghilarducci said the issues suggest that privately owned and managed telecommunications companies lack appropriate battery backups for extended power outages. Regulatory hurdles thwarted attempts to ship diesel generators from other states, further slowing the restoration process, he said.
“Given the utility’s sole notification strategy for the public was to drive customers to a website that they couldn’t get on because they couldn’t get through the wireline system, it was a very frustrating loop of cascading failures that really created a major threat to life and safety,” he said. “We have seen this scenario over and over now following one disaster after another.”
Approximately 750,000 of PG&E customers de-energized during the Oct. 26 event went without power for a week or more, Ghilarducci said, because of the overlapping shutoffs implemented before the utility could clear the lines for restoration.
“The details here matter,” he said. “A detail about how you’re going to put a community resource center in place and what’s going to be there and how long it’s going to be open and what kind of demographics are going to be served there … those details matter. You can’t hit that with a 30,000-foot overview and then expect to have the ability to respond.”
Indeed, the state’s Government Operations Agency scrambled during the PSPS events called Oct. 26 and 29 to get PG&E’s website running again after it crashed following an uptick in traffic — an issue acting Secretary Julie Lee said the state warned the utility about in advance. Other officials said the number and availability of PG&E’s resource centers — where de-energized customers sought water, ice, blankets and power generation — fell short of best practices.
“These are fairly easy things that you think about ahead of time and you do well ahead of time and not at the moment of crisis,” Batjer said. “That was well pointed out to PG&E’s [officials], and they admitted it.”
Johnson painted a different picture of PG&E’s preparations, noting that the utility completed 18 months’ worth of line inspections within four months, trimmed 7 million trees and cleared vegetation — including 500,000 dead trees — from its lines. Although he admitted removing brush and debris does nothing to protect transmission lines against high winds, he said it’s a good start.
“Turning off power for safety is an effective tool and really only one of the many tools we are using,” he said. “We will get better at using it.”
Sumeet Singh, PG&E
Sumeet Singh, vice president of asset and risk management for PG&E’s Community Wildfire Safety Program, told the committee that the utility is indeed getting better at managing PSPS events. During the Oct. 26 shutoff, PG&E restored service to 970,000 customer accounts within 12 hours — a far cry from the 51 hours spent resupplying 60,000 customers during a shutoff last year.
He also said the grid’s design with long radial lines traversing high fire-risk areas presents challenges not faced in other service territories with higher customer densities. The structure means PG&E is focused on de-energizing lines with surgical precision and restoring power quickly to prevent more widespread impacts.
Still, officials insisted the utility should have done more.
“While PG&E spent significant resources warning the public about the risks of the power shutoff events and what the public should do to prepare for an event, it is not clear that PG&E spent the time it should have to make sure the utility was prepared,” Batjer said.
The SDG&E Model
Power shutoffs in SDG&E’s service territory carried far less impacts last month compared to outages in IOUs to the north thanks to years of planning and investment, COO Caroline Winn told the committee.
“I think what’s needed in California is to think beyond ourselves,” she said. “PSPS is the right solution for now, but what’s next? I’ve set that as an aspirational goal for our organization … how do we eliminate it? [At] SDG&E, that is our North Star.”
Winn said a devastating rash of wildfires in 2007 that “hit home” for the utility’s staff resulted in a cultural shift from reliability to public safety.
“Having gone through those experiences and saw those changes happen before my eyes, those were the fires that really changed the DNA of our company,” she said. “Back at that time, there was really no proscriptive plan of how we should engineer our system to protect our infrastructure from the increasing threat of violent wildfires.”
So, piece by piece, Winn said, SDG&E hardened its infrastructure: replacing bare wire and wooden poles with covered conductor and steel poles; hiring scientists and meteorologists to improve fire-risk forecasting; installing sectionalizing switches and weather stations on lines to monitor conditions; bolstering patrols of de-energized lines to ensure damage is mitigated before restoring power; and investing in falling conductor technology that will prevent broken wires from igniting.
“We have been very thoughtful about installing sectionalizing switches, which only limits shut offs to the most endangered communities,” Winn said.
The utility also turned community engagement into a year-round event, she said, noting that SDG&E hosts open houses and town halls to share information about how to prepare for a power outage. TV stations start broadcasting PSPS notices during red flag warnings, while the utility itself notifies customers at 48, 24, and one to four hours before a shutoff.
“Our goal is that no customer is surprised,” Winn said. “We want our customers to be able to plan around this.”
California Energy Czar Ana Matosantos
So, when Santa Anna winds triggered four red flag warning in SDG&E’s territory last month, the utility managed to de-energize just 25,000 customers, with outages resolved in less than 24 hours. Winn clarified that winds topped 80 mph in some areas, but no “major” fires tore through the territory either. For comparison, PG&E territory saw wind speeds exceed 100 mph.
Winn said the company’s PSPS wasn’t perfect: The event underscored the need for more backup generators and stronger coordination with nonprofit partners to speed up response time in vulnerable communities.
Ana Matosantos, California’s cabinet secretary and energy czar, said the utility’s actions — despite operating within the same regulatory scheme as PG&E — produced better outcomes for its customers.
“San Diego has made great strides in a much narrower way, for a much shorter period of time, impacting far fewer communities,” she said. “When you look at all three utilities, the use of PSPS in terms of size of event, the duration, the back-to-back outages, it’s a different story from all three.”
Southern California Edison
Like its IOU counterparts, Southern California Edison said its PSPS events only cut off power to a tiny fraction of its service area — less than 2% of its 5 million customers.
Phil Herrington, SCE
Phil Herrington, SCE’s vice president of transmission and distribution, said the utility develops its own fire-risk forecasts and uses high-definition cameras to monitor line conditions. Field workers will also install some 6,000 miles of covered conductor by 2023, three years ahead of schedule.
“We used granular real-time weather [information] to de-energize sections rather than entire lengths [of transmission line],” he said. “The ability to use the weather to make de-energization decisions and having the technology to do so, it serves a vital purpose.”
Both SCE and SDG&E said they deployed these more cost-effective mitigation tools to prioritize “undergrounding” where it’s most effective. The technique, which trenches electricity infrastructure below ground, costs approximately $3 million per mile — a pricey solution that IOUs say takes longer to build — and to troubleshoot during outages.
“It’s over eight times more expensive than covered conductor,” Herrington said. “There will be areas that are so consequential in the event of a wildfire that undergrounding is the best option and we will deploy it when necessary.”
Officials pushed Herrington on the utility’s responsiveness to cell tower outages during the shutoffs and pointed out that its process for registering medical baseline customers leaves out residents who aren’t account holders. He said the company offers zip code-based PSPS alerts to residents’ cell phones as a backstop — though such messages failed in some parts of the utility’s territory last month because of the outages.
“We do look at lines and if they have telecommunications; that is one of the many factors we consider in the restoration sequence,” he said. “PSPSes are just one of the many ways customers could lose power, so that is why we are encouraging customers to register as medical baseline customers. It could be an earthquake, it could be a major storm, where there won’t be warning.”
It’s not enough for Ghilarducci, who said bolstering cell sites will help assure a resilient system — something utilities have a stake in too.
“That means cell sites need to be hardened with battery or fuel backup beyond four hours to know they will sustain for multiple days,” he said. “Protecting the backline from fires or earthquake damage. It’s a simple request that we are asking and it’s a priority on the part of the utilities to do that.”
CPUC Action
Batjer said PG&E’s response provided a “sharper understanding” of how “one entity’s decisions can result in broad societal costs,” admitting that it’s her agency’s responsibility to prevent it from happening again.
Marybel Batjer, Calif. PUC
“Although the utilities are ultimately responsible for managing their electric systems, the CPUC cannot and should not stop demanding better ways to reduce the scope and impacts of power shutoffs without compromising public safety,” she said. “This cannot and should not be repeated.”
The CPUC launched an investigation into PG&E’s shutoffs last week to determine if the utility followed state law. (See Calif. PUC Orders Investigation of Power Shutoffs.) Batjer also issued a show-cause order and said a preconference hearing scheduled for Dec. 4 will give the utility a chance to convince the commission why it shouldn’t be sanctioned for its actions, though she doesn’t expect much in the way of changed behavior.
The commission will also work with utilities to expand their wildfire mitigation plans and create a Safety Policy Division dedicated to the enforcement of public safety during emergency events. It’s a conversation that must include telecommunications companies too, Batjer concluded.
“Despite the importance of the regulatory processes and actions we have put in motion, they are meaningless to the public unless they translate into real-world demonstrations that utilities are truly taking actions that prioritize the safety of the public,” she said.
State officials also won’t give PG&E another decade to harden its grid and discontinue power shutoffs. Matosantos said the state’s timeline “has been very clear.”
“We cannot have another year like this year,” she said. “We have to be looking at our goals and progress in a matter of days, weeks and months and what has to happen at every point in time before next fire season.”
Anbaric Development Partners asked FERC on Monday to order PJM to allow developers of offshore transmission “platforms” to obtain injection rights, saying the RTO’s Tariff violates the commission’s open access requirements and is discriminatory.
The transmission developer said it was forced to file its complaint after a stakeholder initiative to consider changing PJM’s rules stalled in September.
PJM’s Tariff allows merchant transmission developers to obtain transmission injection and withdrawal rights for DC facilities or controllable AC facilities connected to a control area outside the RTO. Under a problem statement approved in February, stakeholders considered allowing merchant transmission developers to request injection rights for non-controllable AC transmission offshore. But after six special sessions, stakeholders opted against recommending changes. (See “PJM Recommends Sunsetting Offshore Wind Special Sessions,” PJM PC/TEAC Briefs: Sept. 12, 2019.)
“The nature and scope of fundamental open access rights under the PJM Tariff cannot be left to the whims and commercial interests of stakeholders,” Anbaric said in its complaint. “Put simply, the PJM Tariff does not contemplate the interconnection of transmission platform projects and denies them the opportunity to interconnect to the PJM transmission system and obtain meaningful and material interconnection rights.”
In response to the complaint, PJM spokesman Jeff Shields said the RTO “has been and will continue to engage with members, project developers, and impacted states on the procedures that will enable states to integrate offshore wind into their generation portfolios.”
Bottlenecks
Anbaric and other transmission developers have argued that having individual wind farms build separate radial lines to shore will be more expensive, more environmentally intrusive and less resilient than networked open access facilities that multiple wind farms could use. (See Anbaric Pushes Offshore Grid Plans.)
“What we’ve seen is — and this is true in New York and New England too — if you’re going to scale offshore wind up past the first couple thousand megawatts, radials are going to run into a bottleneck,” Theodore Paradise, Anbaric’s senior vice president for transmission strategy, said in an interview. “There’s not enough interconnection points.”
The company said there are no technical reasons for blocking transmission platform projects, citing transmission built to deliver onshore wind from Texas’ Competitive Renewable Energy Zones and California’s Tehachapi Pass.
Anbaric CEO Ed Krapels said he’d like to see PJM adopt the European model of allowing states to offer solicitations for multiple transmission developers to compete for OSW transmission.
“That’s how the Dutch and the Germans are now getting responses from wind generators that don’t even require long-term contracts,” he said in an interview.
Anbaric — which helped build the 660-MW Neptune HVDC cable linking PJM to Long Island and the 660-MW Hudson project connecting Manhattan to the RTO — envisions a network of transmission “platforms” that could deliver 52 GW or more of offshore wind generation to PJM, NYISO and ISO-NE.
Anbaric envisions a network of transmission “platforms” that could deliver 52 GW or more of offshore wind generation to PJM, NYISO and ISO-NE. | Anbaric Development Partners
New England’s states are seeking 5,200 MW of OSW by 2035, and New York has ordered 9,000 MW by 2035.
New Jersey has a goal of developing 3,500 MW of OSW by 2030. The state’s Board of Public Utilities in June 2019 selected a 1,100-MW project off the coast of Atlantic City and plans additional solicitations for 1,200 MW in 2020 and 2022. Last week, the BPU held a stakeholder meeting at which officials discussed developing a separate solicitation for offshore transmission.
Maryland has ordered the development of at least 400 MW of offshore wind generation by 2026, at least 800 MW by 2028 and 1,200 MW by 2030.
In Virginia, Dominion Energy plans to develop 2,600 MW of OSW in three 880-MW phases between 2024 and 2026.
Relief Sought
In March 2018, Anbaric submitted interconnection requests for two proposed AC transmission platform projects, each requesting 1,100 MW of injection rights. PJM told the company it would need to partner with a generator to obtain the rights under current rules.
In June 2018, Anbaric submitted an interconnection request for a proposed DC transmission platform project seeking a 1,200-MW injection into Public Service Electric and Gas’ transmission system in North Brunswick, N.J. More than a year later, after completing a feasibility study that assumed the injection, PJM informed Anbaric on Nov. 1 that it would only model the project without injection rights. Anbaric said the project has obtained almost all its required environmental permits.
Anbaric said it was seeking relief like that granted by FERC’s Order 845, which required RTOs to improve the interconnection process and expand the definition of “generating facilities” to include electric storage. (See FERC Order Seeks to Reduce Time, Uncertainty on Interconnections.)
It said the current rules effectively give offshore generation developers a right of first refusal like one that the commission outlawed for incumbent transmission owners in Order 1000.
Anbaric asked FERC to order PJM to revise its Tariff to remove the requirement that all merchant transmission facilities interconnect with another control area and to create a new category of merchant transmission facilities called a “remote generation resource interconnection platform” (ReGRIP).
The company also asked the commission not to order a PJM stakeholder process, saying that could result in delays that would prevent states from issuing solicitations for offshore transmission.
Krapels and Paradise said they are hopeful the commission will respond to the PJM complaint with an order that sets a precedent for other RTOs, saying they have similar concerns in New York and New England.
VALLEY FORGE, Pa. — The PJM Planning Committee deferred voting again on a problem statement and issue charge for a proposed review of the RTO’s critical infrastructure management.
The second delay follows a plea from Exelon and other transmission owners on Thursday to hold off on the issue until after a webinar scheduled for Friday to address stakeholders’ concerns about a proposed Tariff attachment that creates a process to mitigate existing facilities on NERC’s CIP-014 list. (See “Critical Infrastructure Vote Deferred,” PJM PC/TEAC Briefs: Oct. 17, 2019.)
“A number of things on this issue charge could be removed or modified,” said Pulin Shah, director of transmission strategy and contracts for Exelon. “The M4 [attachment] hasn’t been approved. We are still working through this process. A lot of the things that are in here may or may not even be applicable [after the webinar].”
He clarified that a second 30-day delay would give stakeholders more time to “focus the scope on the areas of concerns that everyone has alignment on in terms of creating new CIP-014 facilities.”
DER Ride Through Task Force Sunset
PJM wants to sunset the Distributed Energy Resources Ride Through Task Force after saying its work considering a default standard is done.
The RTO said distributed energy resources currently function on settings designed to respond to unexpected system malfunctions that disrupt power flow. Some sources “ride through” the event, providing much-needed reliability, while others trip off to prevent system damage. Solar panels and other DERs also can’t tell the difference between a transmission fault and a distribution fault, causing inappropriate responses and overstressing the system.
The task force had been considering ways to fix this problem — even going so far as to bring in federal experts to help develop new standards — but decided against an RTO-wide rule because of the uniqueness of local distribution systems. (See DER Ride Through Task Force Considers New Direction.) Instead, the task force suggested that PJM create a recommendation when a local distribution system lacks an official policy.
As PJM moves forward with its proposed fee restructuring for competitive transmission proposals, stakeholders remain concerned about the associated revisions to Manual 14F required as part of the update.
The revisions, borne out of a stakeholder motion endorsed by the Markets and Reliability Committee last year, will codify the comparative cost framework the RTO will use to evaluate these projects. (See “PJM Unveils Flat Fee Cost-containment Plan,” PJM PC/TEAC Briefs: Aug. 8, 2019.) Since implementation of FERC Order 1000 in 2014, PJM has reviewed 850 competitive proposals, of which less than 20% included cost-commitment provisions.
TOs continue to question the appropriateness of revisions proposed by both PJM and the Independent Market Monitor that would memorialize an ongoing collaborative role between the two entities in reviewing competitive transmission proposals. (See PJM TOs Wary of Cost Containment Rules.)
In an effort to bridge the gap, LS Power proposed a paragraph that would clarify PJM’s precedence over the Monitor in reviewing proposals, a suggestion that fellow TOs found promising but still imperfect.
Some 77% of stakeholders at the PC approved of PJM’s current proposal. PJM’s Mark Sims said staff will take the restructured fee and its associated Operating Agreement and manual changes to the MRC for endorsement next month.
Manual 19 Revisions Endorsed
Stakeholders endorsed revisions to Manual 19: Load Forecasting and Analysis, a periodic cover-to-cover review that also removes load forecast model overview from the manual and adds it to an annual white paper. The revisions also update sections 3.2, 3.4 and 4.2 to update the weather-normalization procedure for peak load and energy to be directly tied to the load forecast model.
Supplementals from AEP, ComEd, Dominion, PSE&G
American Electric Power wants to replace 18 remaining ELF-SL8-4 Type SF6 breakers at its Sullivan 765/345-kV and Rockport 765-kV substations in Rockport, Ind., after documenting more than 16 issues, including compressor failures, since 2002.
Commonwealth Edison proposed a $200,000 rebuild of its Quad Cities-Cordova 345-kV line to fix obsolete relays and servicing difficulties. The line is an intertie between PJM and MISO and needs the upgrade to address equipment condition, performance and risk.
A second ComEd project to rebuild 16 miles of the 345-kV Kendall-Lockport double-circuit towers, increase the line rating and eliminate 10.5 miles of wood poles that are 60 years old will cost $12 million, Exelon said. The utility considered two other $20 million solutions as part of its review process but instead settled on a cheaper plan to install quad-circuit towers between the Kendall and Lockport substations, string 138-kV conductor and cut part of line 9117 over new towers.
PSEG’s proposed solution for the overloaded Marlton substation in the Voorhees, N.J., area | PSE&G
Dominion Energy wants to spend $69 million to preserve its remaining outdoor equipment at the Mt. Storm substation in West Virginia. The utility proposes installing a second gas-insulated substation (GIS) building in the switchyard to house the breakers and switches for Lines 550 and 536 and two generators. The existing GIS building would be expanded to include breakers and switches for lines 529, 572 and Capbank 3.
The company also presented a $400,000 plan to install a 1,200-ampere, 50-kAIC circuit switcher and associated equipment to feed a new transformer at Poland Road.
Finally, Public Service Electric and Gas proposed a $39 million plan to build a new 230-kV substation in Echelon, N.J., to alleviate the overloaded Marlton substation nearby. The utility also considered building a $68 million 69/13-kV substation but decided on the less expensive proposal because it decreases the amount of exposure and increases the reliability of the 230-kV circuit.
SPP COO Carl Monroe, one of the key players behind the grid operator’s growing footprint, has said he will retire in early 2020.
Monroe is a 22-year veteran with SPP. As executive vice president and COO, he has been responsible for operations across the RTO’s 14-state balancing authority area and administration of the wholesale electricity market.
“It has been the opportunity of a lifetime to work at SPP and a privilege to work alongside such bright, talented and caring people in the interest of a worthwhile shared mission,” Monroe said in a statement. “SPP is poised for continued success, which I’ll observe with great interest, but the time is right for me to begin a new chapter with regard to family, travel and other experiences.”
“I’ve had the great privilege of working with Carl during his entire career at SPP,” Mike Wise of Golden Spread Electric Cooperative — one of the RTO’s more prominent members — told RTO Insider. “I believe his personal efforts, contributions and leadership were critical to the tremendous development and success of the Southwest Power Pool.”
Monroe has been credited with the expansion of SPP’s service territory from eight to all or part of 14 states. He also led the organization’s recent growth into the Western Electricity Coordinating Council, where the RTO will begin offering reliability coordination and market services over the next two years.
“In nearly 15 years as a director at SPP, I’ve met no one with greater knowledge of markets and operations or with such ability to collaboratively address complex issues,” Board of Directors Chair Larry Alternbaumer said.
“Carl has helped to shepherd us through tremendous change and growth. We just wouldn’t be where we are today without his leadership,” CEO Nick Brown said.
An SPP spokesman said Monroe’s responsibilities for westward expansion, implementing the Holistic Integrated Tariff Team’s recommendations and other duties “will be transitioned to other members of the officer team.”
Monroe’s retirement — along with Brown’s in April 2020 and the year-end departures of former board Chair Jim Eckelberger and Directors Phyllis Bernard and Harry Skilton — will wipe out much of the leadership that has been in place at SPP since 2004.
The COO vacancy has opened up a potential slot for inside candidates for Brown’s position. SPP is looking at both internal and external candidates for the CEO’s position.
Monroe joined SPP from Entergy, originally being hired to manage the RTO’s growing information technology department. He was elected as an officer and promoted to executive vice president and COO in 2004.
Texas regulators last week granted a request by staff and Texas Industrial Energy Consumers (TIEC) for a list of investors behind the investment fund involved in a $4.3 billion acquisition of El Paso Electric. An administrative law judge had ruled against the intervenors’ request during discovery in October (49849).
TIEC’s attorney Katie Coleman, a partner with Thompson & Knight, noted during the Public Utility Commission’s open meeting Thursday that the state’s Public Utility Regulatory Act allows the PUC to require a utility or its affiliates to identify owners of more than 1% of the company.
“This seems pretty straightforward,” Coleman said. “We have a fund that consists of private equity coming in to buy a Texas utility. We are asking, ‘Who is that fund? Who provides this capital?’ This is going to be [EPE’s] long-term source of capital. We feel it’s relevant to get a list of the investors and their ownership shares.”
Eversheds Sutherland’s Lino Mendiola, representing J.P. Morgan Investment Management’s Infrastructure Investments Fund (IIF), said the investors behind the $12.2 billion fund were not trying to hide anything and offered to share a list of the pension funds that make up the top 100 investors. The fund is composed of 517 limited partners and three general partners, he said.
“It’s an open-ended infrastructure fund. It invests in buy-and-hold strategies. It’s not a hedge fund,” Mendiola said. “These are passive investors: limited partners that have no ability to control capital deployment. They don’t control the fund; they don’t control any company in the fund. Our argument is the identity of the passive investors, who change over time and who have no control over anything, are not relevant.”
The commission determined otherwise. “If this were a contract dispute, we might give you the discovery win,” Commissioner Arthur D’Andrea told Mendiola.
The PUC will hold a public hearing on the merger Nov. 20 to 22 in Austin. Coleman said TIEC could likely review the list before then and address any issues during the hearing.
The identities of IIF’s investors have also drawn the attention of consumer watchdog Public Citizen, which has protested the proposed deal at FERC (EC19-120). FERC and the Texas PUC are among several regulatory agencies that must approve the acquisition.
EPE and IIF announced the deal in June. It is expected to close in the first half of 2020.
Briefings on CenterPoint Rate Case
The commission requested briefings from CenterPoint Energy and intervenors following a discussion attempting to iron out a preliminary order approving CenterPoint’s Houston electric utility rate case (49421).
The commission discussed and adopted several ring-fencing proposals made by staff and TIEC, including requirements limiting CenterPoint’s dividend payments to an amount not to exceed its net income and suspending the payments if the utility’s credit rating falls below a certain level.
CenterPoint Houston Electric’s adherence to the PUC’s 60-40 debt-to-equity ratio would require it to make an $800 million payment to its corporate parent, the company said.
The commission asked CenterPoint and the intervenors to file briefings on whether the recommended 60-40 capitalization would “necessitate noncompliance” on CenterPoint’s part. It also asked the parties to suggest options to avoid or mitigate the conflict.
An ALJ in September reduced the utility’s proposed $154.6 million rate increase to $2.6 million, or 0.11% of its present rate base. CenterPoint CEO Scott Prochazka made the decision a central point of the company’s third-quarter earnings report. (See Hot Summer Yields Positive Earnings for CenterPoint.)
PUC Approves ERCOT 2020-21 Budget
The PUC approved ERCOT’s 2020-21 biennialbudget and its 55.05-cents/MWh administrative fee. The budget includes $268.3 million in 2020 and $275.2 million in 2021 for operating expenses, project spending and debt-service obligations (38533).
The system administrative fee has remained level since 2016. The fee and the budget were approved by ERCOT’s Board of Directors in June. (See “Board Approves Budget, Change Requests,” ERCOT Board of Directors Briefs: June 11, 2019.)
AEP’s Purchase of Oncor South Texas Assets OK’d
The commission approved the sale of Oncor’s distribution facilities in the Rio Grande Valley cities of McAllen and Mission to AEP Texas for $18 million. (49402). The deal affects approximately 3,000 residential and small commercial customers in the area.
Gexa Energy Docked $35,000
In other business, the commission:
Agreed to consider a rehearing request by two landowners over its earlier selection of a preferred route for the second of two 345-kV transmission lines needed to integrate about 470 MW of the city of Lubbock’s load into ERCOT. (See “Commission Approves 1 of 2 Lubbock Projects,” Texas PUC Briefs: Sept. 26, 2019.) Applicants Oncor and Lubbock Power & Light said the two routes have “very similar characteristics, and either one would be a reasonable option” in submitting additional testimony. The move allows the commission to further contemplate and consider the scope of the rehearing (48668).
Ordered retailer Gexa Energy to pay $35,000 in administrative fees and issue refunds to 7,610 customers for using misleading energy charges on electric bills (49930). Gexa has already refunded more than $10,423 to 37,122 current customers. The penalties raised the commission’s assessments in 2019 to $2.96 million, according to the PUC’s Oversight and Enforcement Division and the Customer Protection Division. The commission has also ordered more than $89,800 in customer refunds through its enforcement actions this year (50019).
Approved requests by Entergy Texas and EPE to adjust their energy-efficiency cost recovery factors. Entergy can recover $8.01 million in costs (49493) and EPE $5.47 million in costs (49496) for the 2020 program year.
Agreed to intervene in three FERC dockets: MISO’s proposal to prevent generating resources expecting full or partial outages lasting more than 90 days of the planning year’s first 120 calendar days from participating in a fixed resource adequacy plan and the RTO’s Planning Resource Auction (PRA) (ER20-129); MISO’s Tariff changes regarding the market procurement of short-term reserves (ER20-42); and Wolverine Power Supply Cooperative’s Federal Power Act Section 206 complaint that MISO’s PRA fails to establish an appropriate forward price signal (EL19-102).
CARMEL, Ind. — MISO’s system can operate on 50% renewable generation if the RTO greenlights dramatically more transmission and ups reserve requirements, and if its members embrace new technologies, new study results show.
MISO laid out the possible realities of a 50% scenario at a special Nov. 14-15 workshop to discuss the third round of results of the RTO’s ongoing Renewable Integration Impact Assessment.
To reach 50% renewables, MISO could retire 17 GW of its existing thermal fleet and add about 100 GW of renewable capacity. Results show even at a 50% renewable penetration, “the majority of the thermal fleet remains available to maintain adequacy,” Policy Studies Manager Jordan Bakke said.
According to the study, renewables would reach 50% of the generation mix as utility-scale solar proliferates in MISO South while wind generation multiplies in the northwestern portion of the footprint. MISO also foresees distributed solar generation becoming more commonplace and concentrated near major cities.
The RTO also said the complementary characteristics of wind and solar generation — on a daily and seasonal basis, solar is generally available when wind isn’t as plentiful — “decreases the probability of not serving load during periods of high risk.”
MISO’s current generation interconnection queue contains 569 projects with 89 GW of estimated capacity, including 51 GW worth of solar and 22 GW of wind. According to a recent report, MISO expects about 3.5 GW of new wind generation to interconnect this year and more than 6 GW to come online throughout 2020.
MISO at 10% and 50% renewables | MISO
MISO reported that it executed 43 generation interconnection agreements in 2019, breaking the previous record of 38 set in 2003. However, the RTO also reported 157 project withdrawals so far this year, just short of the record 168 withdrawals set in 2017.
President of Market Development Strategy Richard Doying said MISO now is nearing 20 GW of wind generation, which can have zero marginal cost.
“That is the right economic price, but it’s terrible for baseload generation,” Doying said at an Organization of MISO States meeting in October.
Pad Reserves?
The latest results also line up with earlier studies that conclude MISO’s daily loss-of-load risk compresses into a sharper risk during a smaller set of hours later in the day under a high-renewables scenario. (See MISO Renewable Study Predicts Later Peak, Narrower LOLE Risk.)
At 40% renewables, MISO may need to increase its reserve requirement to manage quick changes in load, the study found.
MISO research and development adviser Long Zhao said the RTO will need ramping capability to manage discrepancies between early evening reductions in solar generation and increases in wind generation and load. Going forward, sunset would probably be a particularly challenging time of day for MISO to manage, Zhao said.
When renewable generation climbs from a 40 to 50% share of the generation mix, it begins to nudge out nuclear and natural gas resources footprint-wide in economic dispatch. MISO envisions its footprint will contain a wind-dominated northern region, a southern region where solar and natural-gas fired generation begin jockeying for position, and a central region that draws on both types of renewables. It also found a significant increase in imports as renewables climb to 50% — more than 10 GW in some cases during summer days. Today, MISO does not exceed 5 GW in imports, even on summer days.
Veriquest Group’s David Harlan said he had a problem with MISO assuming that solar generation could replace the baseload generation of MISO South. He argued that solar’s production capability is simply not predictable enough for heavily industrial areas of the South.
“In MISO South, we have a heavy industrial load planned to be served by coal and nuclear and later by combined cycle,” Harlan said.
Clean Grid Alliance’s Natalie McIntire asked if the shorter and more pronounced loss-of-load risk is good or bad from MISO’s standpoint.
MISO adviser Brandon Heath said the sharper risk is simply a future reality. “It’s neutral. It’s not a good thing or a bad thing just yet,” he said.
Miles and Miles of Lines
It’s not until renewables take a 40% share of the generation mix that MISO foresees a need for transmission projects to “significantly reduce curtailment.” Without transmission solutions, renewable additions beyond a 40% penetration cannot continue displacing thermal generation because there isn’t enough transmission capacity, the RTO found.
“We see needs at the very beginning, but the needs are very small. We see energy adequacy needs when we get to 40%,” Bakke said.
MISO Policy Studies Engineer Yifan Li said while some areas might exhibit needs for local transmission solutions, there’s no need for anything major beyond the normal annual planning cycles until 40% renewable penetration.
“From the bulk amount of energy flow paths to deliver energy and reduce curtailment, an overall systemwide [extra-high-voltage] rebuild is not needed until the 40% milestone,” he said.
MISO transmission addition locations at 40 to 50% renewbles | MISO
But McIntire pushed back on the idea that a 40% renewables mix is the inflection point for new transmission needs. She argued that MISO will require steady transmission buildout as renewable generation rises.
“I just don’t want us to minimize that message. We’re going to need significant transmission before 40%,” McIntire said.
Li agreed that annual transmission buildouts would continue to be needed, but at the 40% penetration level, MISO’s usual annual plans would fail to keep pace with transmission capacity needs.
“I like to compare it to a fever. … Our system is having a high fever around 40% renewables without significant amount of additional transmission,” he said.
At a 40% penetration, Li said, about 80 new transmission projects located all over the footprint might provide the necessary energy delivery. The bundle of projects includes 2,400 miles of 345-kV and lower-voltage lines, 320 miles of 500-kV lines, 270 miles of 765-kV lines and 410 miles of HVDC lines.
At 50% penetration, an additional 70 projects across the footprint could help, including 590 miles of 345-kV and lower-voltage lines, 820 miles of 500-kV, 2,040 miles of 765-kV and 640 miles of HVDC. Li said the transmission additions would be particularly helpful in reducing wind curtailment in the northern part of the footprint, where wind capacity will be ubiquitous.
“We evaluated more than 11,000 [transmission project] candidates,” Li said. MISO staff have repeatedly said the results will not be used directly in transmission planning. They also clarified the study was not conducted with the goal of carbon reduction, saying it only demonstrates the challenges the system might encounter as solar and wind generation flourish.
“That’s a lot of transmission,” McIntire quipped to laughter. She urged MISO to examine the benefits of co-located storage and other ways to maximize existing transmission capability before it starts studying new transmission plans.
Other stakeholders agreed that MISO was suggesting a need for a staggering amount of transmission. Some said the jump in transmission needs from a 30% to 40% share of renewables seemed too high to be believable.
No Agenda
“We do see these drastic needs at certain intervals. It’s a non-linear trend as we deploy renewables,” Bakke said. “That discontinuity at very high renewable levels requires more transfer capacity.”
Bakke said MISO will begin relying more on regional energy transfers, which in turn will become more unpredictable, leading to a need for increased EHV thermal line capabilities.
“Existing infrastructure becomes inadequate for fully accessing the diverse resources across the MISO footprint,” Bakke said.
Not only will the footprint eventually need new physical lines, but it will require more technology on transmission lines, including synchronous condensers, more transformers and HVDC capabilities, staff said.
“As we see more renewable integration, we see additional types of technology needed to help support the system,” Bakke said. “It’s a portfolio of solutions that best enable renewable deployment in the system.”
Bakke said MISO is making no proposals for new technology or lines as a result of the study. “We’re trying to point out where we see these issues … to see if our processes should change and what we need on the system long-term,” he said.
MISO found that a diversity of technologies and geography improves the ability of renewables to serve load. Bakke said storage facilities, the load-taming abilities of electrification and other demand-side management can enable more renewable penetration. He also noted that thermal generation can begin scheduling outages during times where renewable output is predicted to be abundant.
The RTO also said the number and severity of thermal overloads starts to increase at a 20% renewable penetration and becomes widespread especially in the western portion of the footprint at a 50% penetration. It said it will need more thermal mitigations on higher-voltage lines. Likewise, it will encounter dynamic stability issues beyond a 20% penetration.
To counter small-signal instability, MISO said it may need must-run units equipped with power system stabilizers or specially tuned batteries to support grid reliability beyond a 30% penetration.
But MISO now says frequency response performance remains stable up to 60% renewable penetration. The newest result is even more optimistic than its July announcement that its grid can withstand major reliability risks even when renewables reach 40% of the generation mix. (See MISO: Grid Can be Stable at 40% Renewables.)
“We see needs on the thermal side greater than needs on the voltage side,” Bakke said.
WPPI Energy’s Steve Leovy said MISO may need to more thoroughly examine steady-state issues starting with the generation interconnection queue. He recommended the RTO screen for such issues there.
Where’s the Storage?
McIntire pointed out that much of future solar development is predicted to be solar paired with storage, which could change what system needs MISO identifies.
Examining how storage can help a future fleet mix will be included in the upcoming phase of MISO’s renewable impact study. Stakeholders have repeatedly asked the RTO to study heavy wind and solar generation balanced by storage facilities. Some stakeholders predicted that if storage is optimizing wind and solar generation, MISO won’t forecast nearly as many energy delivery issues.
McIntire urged that the next phase of the study examine other less traditional solutions.
“Largely you’ve been looking to transmission and the existing thermal generation,” she said.
Bakke asked stakeholders to send his team examples of nontraditional solutions for evaluation.
The changes, endorsed by the Markets and Reliability Committee in April, require existing capacity resources not offered in three consecutive auctions to change to energy-only status. A resource receiving a must-offer exception must also file a plan showing how it will satisfy Capacity Performance requirements or forfeit its capacity interconnection rights. Resources would be granted exceptions for no more than two auctions. (See Load Interests Endorse PJM-IMM Must-offer Proposal.)
Manual 15 Clarifications on VOM Costs
PJM offered a first read of Manual 15 revisions that clarify that market sellers can only change the format of maintenance adders — such as $/MMBtu, $/MWh or $/start — during the annual review period for energy offer components.
Staff will add section 2.6: Variable Maintenance Costs to reflect this after promising to do so in the proceedings for ER19-210, PJM’s filing to include variable operations and maintenance costs in energy offers. FERC partially accepted the RTO’s Tariff revisions in April but asked for more clarity on what maintenance costs sellers can include in their energy market offers. (See FERC to PJM: Clarify Allowable Costs for Energy Offers.) FERC accepted that compliance filing in August.
PJM will seek endorsement from the MRC in December and from the Members Committee and Board of Managers in January.
Border Rates
PJM presented a first read of revisions to Manual 27: Open Access Transmission Tariff Accounting that will reflect FERC’s recent order on border rate calculations (ER19-2105).
In June, PJM transmission owners submitted a filing that updates the yearly border charge to prevent network integrated transmission service (NITS) customers — network load located outside the RTO’s boundaries but served from within — from subsidizing border and non-zone service rate customers who use transmission service through and out of PJM. (See Settlement Hearing Set for PJM Border Dispute.)
FERC accepted the TOs’ filing subject to refund, with an implementation date of Jan. 1, 2020, but also set a paper hearing and settlement procedures for involved parties to work out their differences over the proposed methodology behind the rates.
Ray Fernandez, of PJM’s market settlements development department, said the manual revisions will move forward but acknowledged that refunds will be issued if changes to the methodology are approved in a settlement.
Fuel-cost Policies
Stakeholders from the MIC special session for fuel-cost policies brought updated proposals to the committee on Thursday, five months after a first round of debates among stakeholders produced no further consensus. (See PJM Stakeholders Still Divided on Fuel-cost Policies.)
PJM moved off the status quo and offered an alternative package of rule changes that included a much desired “impact factor” when assessing penalties on market sellers for breaking their fuel-cost policies. A joint stakeholder plan and another sponsored by the Independent Market Monitor would also offer impact factors — though the specific calculations differ — and reduce penalties when market sellers self-identify violations.
Adrien Ford of Old Dominion Electric Cooperative said the joint plan aims to “encourage a culture of compliance” among market sellers.
“According to PJM, 75% of the penalties were assessed on generators that had no market impacts,” she said. “That’s why we want to introduce the impact factor. We are just trying to say, ‘Look, if there’s an impact, there should be a penalty. If there’s no impact, there should be a penalty, but it should be a traffic ticket approach.’”
PJM’s interpretation of the fuel-cost policy debate | PJM
While PJM’s plan would reduce penalties by 50% when market sellers self-identify, the RTO did not agree with stakeholders’ creation of a safe harbor provision that protects against situations “not contemplated by the fuel-cost policy.” Melissa Pilong, of PJM’s operations analysis and compliance department, said the provision would encourage market sellers to provide less detailed fuel-cost policies.
Then there’s the issue of temporary fuel-cost policies and PJM’s ability to revoke existing policies, potentially forcing market sellers to submit a zero cost-based offer. Current practice allows market sellers to provide temporary policies that include just heat rate and selling hub — a rule that PJM’s alternative package would eliminate.
“If a fuel-cost policy were to be revoked and mitigation would be offered at zero, the incentives for the generation owner would be, in many cases, submit a forced outage,” said E-Cubed Policy Associates President Paul Sotkiewicz, representing Elwood Energy. “From a reliability standpoint, I can’t imagine why PJM would want to do that.”
PJM staff bristled at the implication that they would revoke fuel-cost policies randomly and at will, noting that the RTO would act in good faith to discuss issues with a market seller first.
“We’ve never revoked a policy,” said Glen Boyle, a manager in PJM’s operations analysis and compliance department. “But we need to have the ability to do so.”
Ford said existing manual language about revocation “isn’t precise” and leaves too much undefined for market sellers.
“The market sellers are just looking to understand when and why something might be revoked and not be forced into a must-offer obligation or a must-offer of zero,” she said. “I don’t think it’s reasonable to have this unclear, looming threat that can really turn things completely upside down for a company. The more we talk about it, the more uncomfortable I am with the status quo.”
Boyle agreed that further consensus could be reached where the RTO allows temporary fuel-cost policies to be submitted alongside their permanent counterparts in the event that revocation occurred.
VALLEY FORGE, Pa. — PJM staff told the Operating Committee last week that questions still remain about why their load forecast veered so far off course during a two-day spell of hot weather across the region last month.
Speaking at the committee’s Nov. 12 meeting, Rebecca Carroll, PJM’s director of dispatch, said staff’s backcasting analysis found that an early-arriving cold front in the ComEd and FirstEnergy zones on Oct. 2 impacted temperatures during the two-hour demand response event, accounting for a portion of the 4,500 MW of anticipated load that never materialized on the system. (See PJM, Stakeholders Baffled by DR Event.)
That same analysis, however, revealed that temperatures in the Mid-Atlantic and AEP zones were higher than initially forecast — meaning the missing load and unusual price signals have a different, unknown cause.
“According to all of our data, the load in AEP should have come in higher and quicker and more significant than what it did, even though we called the pre-load management in this area,” she said. “There’s several hundred megawatts we can’t account for.”
The trouble began Oct. 1, when PJM’s peak load exceeded its forecast by 5,500 MW, knocking the RTO into a spinning reserves event and triggering shortage pricing for three five-minute intervals. Carroll said PJM also called upon 800 MW of shared reserves from the Northeast Power Coordinating Council to compensate.
The following morning, operators lost a 765-kV line in the AEP zone, and 2,000 MW of generation called upon the day before failed to start. Those losses, in combination with a peak load forecast of 131,000 MW and anticipated congestion over the Hyatt transformer and the Peach Bottom-Conastone 500-kV line, prompted staff to call up 725 MW of long-lead DR resources for a pre-emergency load management event. The decision triggered a performance assessment interval (PAI) that lasted from 2 p.m. until approximately 4 p.m. in the AEP, Dominion, Pepco and BGE zones.
What should have happened next, according to several stakeholders, was a rise in LMPs for those zones, set by DR operating during the PAI. Instead, prices in the AEP zone tanked, and 4,500 MW of load never came onto the system.
PJM had hoped backcasting could solve the mystery of the missing megawatts, but Carroll said last week that more answers will likely come when the official DR data become available next month.
“I don’t buy this missing load argument,” said Dave Mabry, of McNees Wallace & Nurick. “I’m not sure we’ve got a missing load issue as much as we have a forecast issue. It seems like there is something else going on with the backcasting.”
Zonal contribution to load forecast error on Oct. 2, 2019 | PJM
Mabry suggested that a large industrial-use customer participating in DR could account for the “missing nodal load” — a possibility that Joseph Mulhern, a senior engineer at PJM, said staff were still considering.
“That’s one of the things that we are trying to look into now … mapping the nodes where we see this behavior to demand response customers,” he said. “It’s the first time we’ve looked into anything like this, so we aren’t sure what we will get or what the outcome will look like.”
He said staff attribute “a significant amount of missing load to DR,” but not all of it. He also said a lack of visibility at the distribution level and the rarity of 90-degree weather in October may also have played a role.
“When there is an unusual day that’s not got a lot of history, that can lead to errors,” he said.
Black Start Packages Anticipated in ‘Early 2020’
PJM’s Janell Fabiano said that stakeholders will present new rules for black start resource fuel requirements in “early 2020.”
Stakeholders began meeting in July 2018 to reconsider whether the existing fuel requirement of 16 hours proved sufficient given PJM’s focus on resilience in recent years. The group is also considering ways to mitigate high-impact, low-frequency events across all black start resources and fuel types.
The D.C. Office of the People’s Counsel, Calpine, PJM and Monitoring Analytics continue to work on four similar plans to define fuel assurance and tweak the hourly reserve requirement. Fabiano said stakeholders will bring the finalized packages to both the OC and the Market Implementation Committee for votes early next year. Changes will not move forward without support from both committees, she said.
Winter Weekly Reserve Target Endorsed
The OC endorsed weekly winter reserve targets for 2019 that remain unchanged from last year. The targets for December, January and February are 22%, 28% and 24%, respectively.
Part of the reserve requirement study, the targets help staff coordinate planned generator maintenance scheduling during the winter and cover against uncertainties associated with load and forced outages.
PJM also sets a 0% goal for its loss-of-load expectation (LOLE) in the winter, preferring instead to expect higher LOLEs throughout the summer.
The committee also endorsed PJM’s new day-ahead scheduling reserve requirement (DASR) of 5.07%.
The DASR is the sum of the requirements for all zones within PJM and any additional reserves scheduled in response to a weather alert or other conservative operations.
PJM will seek endorsement for the change at the Markets and Reliability Committee and implement the new requirement in Manual 13 revisions.
Stakeholders Sunset NERC Ratings Initiative Task Force
Stakeholders approved PJM’s request to sunset the 2011 NERC Ratings Initiative Task Force.
The group held more than 30 webinars over three years to address a NERC alert that asked RTOs to “verify that field conditions are consistent with established ratings.”
The task force created an automated process to notify members of pending NERC outages. Since adopting the new procedures, PJM has received 1,386 outage and derate tickets, completing about 65% of submitted requests. About 9% impacted the system, according to PJM’s data.
OC Meetings Moving to Thursday in 2020
PJM’s standing committee week will look a little different in 2020.
The OC will convene on Thursdays, while PJM’s Planning Committee and Transmission Expansion Advisory Committee will move to Tuesdays. The MIC will remain on Wednesdays.
PJM Manuals Endorsed
Manual 03A: Energy Management system (EMS) Model Updates and Quality Assurance (QA) — Cover-to-cover periodic review. Adds a new section on PJM’s modeling philosophy.
Manual 3: Transmission Operations — Cover-to-cover periodic review. Updates dozens of terms and values in sections 1, 3, 4 and 5 and Attachments A and B.
Manual 14D: Generator Operational Requirements — Minor changes identified through the Distributed Energy Resources Ride Through Task Force that apply to distribution-connected generators connected to radial distribution lines of voltage less than 50 kV. The revisions also direct DERs to appropriate transmission owner engineering and construction standards, a standalone document on PJM’s website. The term “generating facilities” was also added in section 7.1.1: Generator Real-Power Control.
