QUEBEC CITY, Quebec — NERC will delay the first release of its Align software project from September to 2020 to allow inclusion of security features originally planned for a later release.
NERC Chief Technology Officer Stan Hoptroff announced the change at a meeting of the Technology and Security Committee on Wednesday, saying the regional entities wanted to see security capabilities planned for Release 3 included in the initial rollout.
“The board was in full support of this delay,” committee Chair Suzanne Keenan said. “We’ve got to get it right, and we will.”
Hoptroff said the additional security features concern “evidence lockers” to hold data from enforcement cases. Release 1 is now expected in the first or second quarter of 2020.
The announcement came after it was disclosed at SERC’s quarterly open forum July 29 that only two REs, Midwest Reliability Organization and Texas Reliability Entity, would be involved in the initial rollout of Align Release 1. (See Align Rollout to be Staggered.)
Hoptroff said MRO and TRE will still be the first two REs brought online.
“I still like the idea of starting with Texas and the MRO because [TRE Chief Operating Officer] Jim Albright is our [Align] Steering Committee chairman and [MRO CEO] Sara Patrick is our executive sponsor,” he said in an interview after the meeting. “So, it’s only appropriate they go first. It would be inappropriate for them to ask another region to go [first]. They are also using the system [currently]. So, if we had to roll back, it would be easier than having to go back to two different separate systems.”
Hoptroff also said NERC management has resolved its concerns over the sale of the organization’s vendor, BWISE Information Security, to SAI Global, an Australia-based company whose investors include a private equity fund managed by a Hong Kong company. (See NERC Investigating Chinese Tie to Software Vendor.)
“I am confident” the ownership poses no security concerns, he said.
Hoptroff said the most recent survey on Align, which ended June 28, documented increasing awareness, with 63% indicating familiarity with the project, up from 47% during the baseline assessment in March. About 67% agreed or strongly agreed with the business need and value of Align, an increase from 58% in March.
Hoptroff emphasized training on Align will not be a “one-time” event. With 5,000 users expected to use Align, a 10% annual turnover would mean the need to train 500 new people per year, he said.
CORES Rollout
Ryan Stewart, senior manager registration and certification, gave the committee an update on the Centralized Organization Registration ERO System (CORES) project, which will become the single registration tool for the ERO Enterprise.
Data entered into CORES will be integrated with Align. “Everything starts with registration data,” Stewart said.
He likened the system to airport security, with the user name and login functioning like a passport and boarding pass. Once inside, “going from one application to another” will not require additional security, he explained. “You don’t need to log out. You don’t need to log back in.”
It will provide a “one-stop shop” for contact information and include filtering tools for generating customized reports, Stewart said.
CORES will be introduced over the next several months in a “managed rollout” that will include one- to five-minute “how to” videos. Twenty entities in the ReliabilityFirst region have begun validating their data in the system.
“This is a truly transformational way for us to manage our registration process and database,” NERC CEO Jim Robb said.
SAFNR
Hoptroff also briefed the committee on version three of the Situational Awareness for NERC, FERC and Regions (SAFNR) system, which is scheduled to launch in the third quarter.
SAFNR was initiated by NERC in 2009 in response to recommendations from the U.S.-Canada Power System Outage Task Force, which concluded that the 2003 blackout was caused by a lack of situational awareness.
The new version will provide more detailed data than the existing program, which is limited to systems 230 kV and above and generation units of 500 MW and higher. It will also include visual indicators to alert users of state changes and visualization features on weather and geography.
Displays will show hourly balancing authority loads, forecasted loads and net interchanges, and detailed outage data by geography or company.
“It’s not a single-use application,” Hoptroff said. “It’s a platform that can then be expanded.”
Attorneys are battling now over the matter at the heart of Pacific Gas and Electric’s bankruptcy — the billions of dollars it’s likely to owe victims of the massive blazes of 2017 and 2018 that wiped out a Northern California town and part of a midsized city.
In the U.S. Bankruptcy Court for the Northern District of California in San Francisco on Wednesday, lawyers representing the utility and fire victims argued over how to estimate the potential liability.
The estimation of liability is something Judge Dennis Montali must deal with as he oversees PG&E’s Chapter 11 reorganization. Estimation of potential claims is “a fairly unique process in the bankruptcy world,” Montali said in a hearing Wednesday.
The federal bankruptcy code requires judges to estimate contingent or unliquidated claims that could otherwise “unduly delay the administration of the case.”
Litigating wildfire claims in state court could cause long delays, when PG&E is under the gun to reorganize by next spring. A new state law, AB 1054, requires the company to exit bankruptcy by June 2020 if it wants to take advantage of the law’s $21 billion fund to pay wildfire damages. (See Calif. Wildfire Relief Bill Signed After Quick Passage.)
PG&E Corp. and its utility subsidiary, the debtors in the case, are pressing Montali to conduct an estimation proceeding and settle on a figure soon.
“There is no dispute by any stakeholder on the core issue presented by this motion: Estimation proceedings are required in these Chapter 11 cases absent a consensual resolution,” PG&E’s lawyers wrote in an Aug. 11 motion. “Equally inescapable is the conclusion that estimation has to begin now.”
The California Public Utilities Commission also must approve PG&E’s reorganization and needs a workable plan by January to meet the new law’s June deadline, PG&E attorneys told Montali in their brief.
“All parties acknowledge the importance of meeting that legislative deadline,” they wrote. “Failure to do so would materially reduce the value of the estate by precluding the reorganized debtors from participating in the newly created wildfire fund.”
Tort Lawyers Reject ‘Fixed Pool’
For many of the 2017-18 fires, state investigators have already determined PG&E’s equipment was at fault. As a consequence, the utility could be held responsible for all resulting damages under California’s strict liability law. That includes damages in November’s Camp Fire, which burned down most of the town of Paradise and killed 85 people. It was the deadliest and most destructive blaze in the state’s recorded history.
A major sticking point, however, is the Tubbs Fire, a blaze that tore through Northern California wine country in October 2017 and razed sections of Santa Rosa, a city with 175,000 residents in Sonoma County.
Investigators with the California Department of Forestry and Fire Protection determined a private landowners’ faulty wiring, not PG&E equipment, started the fire. (See PG&E Cleared in Fire that Burned Santa Rosa.) Plaintiffs’ lawyers still hope to convince a jury that PG&E was responsible for the blaze because of the huge amount of damages involved. The fire killed 22 residents and leveled more than 5,600 structures.
The Tubbs Fire swept into Santa Rosa, Calif., in October 2017, destroying a large swath of the city.
“The state court should make determinations as to debtors’ liability on the Tubbs Fire,” two law firms representing about 5,200 fire victims wrote in their brief. “Once the state court determines liability relating to the Tubbs Fire (or once the issues are settled), then the parties can get together and create estimations of all fire claims within an acceptable range.
“Estimation was not created for the purposes for which it is being used — i.e. to cap the funds available for all claimants regardless of individualized damages and with disregard to due process,” the lawyers wrote.
Other plaintiffs’ attorneys urged Montali to reject a fixed pool of money to pay fire victims.
“The debtors would like to cram down a plan that pays contract creditors in full, permits shareholders to retain their equity in the utility, channels tort claims to a trust that has a limited fund to pay tort claimants and discharges the debtors from liability on the claims,” lawyers representing the Official Committee of Tort Claimants victims wrote in a court filing.
“There can be no assurance the trust would have enough funding to pay the claimants in full when they liquidate their claims via settlements or jury trials. If the capitalization of the trust fund is insufficient to pay the tort claims in full, the result would be contract creditors and shareholders will have been paid in full and retain their interests, and the victims lose; the only question is by how much.”
The tort claimants committee has asked Montali to lift an automatic stay on lawsuits against PG&E, allowing a Tubbs Fire trial to proceed in state court on an expedited basis.
Montali said he would try to rule on the estimation issue and the lifting of the automatic stay by a hearing on Aug. 27.
Faced with an increase in demand and generation outages, ERCOT declared another energy emergency alert Thursday afternoon, its second in three days after five years without calling one.
The Texas grid operator issued the Level 1 EEA when power reserves dropped below their 2.3-GW threshold just after 3 p.m. System load was 69.7 GW at the time, below that of Monday and Tuesday’s record peak demands.
Prices again hit the $9,000/MWh maximum for several 15-minute intervals during the late afternoon.
ERCOT Senior Director of System Operations Dan Woodfin said reserves were “tighter than expected” because the grid operator was without 5.2 GW of capacity that was available earlier in the week. (See ERCOT Survives Another Day in the Roaster.)
“Almost all the generation in the system has been online every day this week,” he said. “We knew we were going to be tight, but I think we’re tighter than expected.”
The EEA allows ERCOT to “take advantage of certain resources that are used for just this type of situation,” Woodfin said. The grid operator called on all available resources, deployed operating reserves and its 30-minute emergency response service, and requested energy imports over its ties with neighboring RTOs.
Woodfin also said the system’s wind production was lower than seen in previous days, contributing to the tight conditions.
Earlier this week, ERCOT CEO Bill Magness said the grid operator sees a “trough” of wind generation in the early afternoon before the Gulf Coast wind facilities begin filling in the gap.
“You see higher levels of wind in the evening and into the morning,” he said. “So, often, even though we’re at peak load, some of our tightest conditions may show up earlier than you might expect, but we recover by the time we get over the peak.”
The ERCOT system at 3:34 p.m. Thursday | ERCOT
Both ERCOT and the Texas Public Utility Commission called on consumers to reduce their consumption through 7 p.m.
“The hot weather has continued throughout the month of August, and the Texas economy is strong, so two calls for conservation in the same week is not surprising,” PUC Chair DeAnn Walker said in a statement.
“Occasional calls for conservation are a natural part of running the most efficient electrical system in the world,” Commissioner Arthur D’Andrea said.
“Barring any other things that could happen, it doesn’t look like we’ll need a further [EEA] level today,” Woodfin said. “We don’t like to get into these conservation situations, but it’s something our operators train on.”
ERCOT declares a Level 2 EEA when operating reserves drop under 1.75 GW.
“This is a fluid situation, and can change at any time,” ERCOT spokesperson Leslie Sopko said during a media call.
Statewide temperatures were in the upper 90s on Thursday, but heat indexes were in triple figures.
ERCOT’s Board of Directors on Tuesday got its first look at the work being done to implement real-time co-optimization (RTC), which will add ancillary services to the real-time security-constrained economic dispatch engine.
ENGIE’s Bob Helton, who chairs the Technical Advisory Committee, and Matt Mereness, ERCOT’s compliance director and chair of the Real-Time Co-Optimization Task Force, briefed directors on the intricate design work and approval process during the board’s bimonthly meeting.
“We’re on our way,” Helton said. “We’ve got a long road to go. It’s a very tight schedule, but there are a lot of meetings to try and get this through.”
Mereness’ task force faces a February deadline to present a final package of RTC principles to the board for approval. Once consensus is reached on the design, the group will begin drafting the protocols, which will set the stage for the 2.5 to 3.5 years of implementation. ERCOT has estimated the project will take four or five years to complete.
“We’re not focused on the protocols yet,” Mereness said. “We’re determining the building blocks for real-time co-optimization.”
Helton was quick to say the RTC implementation would not follow the same course as ERCOT’s nodal market project, which was marred by cost overruns and blown timelines before going live in December 2010.
“Give me some comfort that we’re going to design the system, harden that and stop people from hanging their ornaments on the Christmas tree before we start building it,” said Director Clifton Karnei, general manager of Brazos Electric Power Cooperative and representative for the Cooperative market segment.
Claiming Karnei had stolen his words, Helton said, “What we’re trying to do is real-time co-optimization and not redesign the market. That nodal stuff was painful.”
Board Vice Chair Judy Walsh asked Mereness how the task force would respond when it gets stuck on an issue.
“We won’t be stuck silently,” Mereness responded. “If we get stuck, we’re going to let people know.”
IMM: Wind not Outpacing Coal — Yet
Responding to a recent spate of media articles noting that wind generation is outpacing coal generation in ERCOT, Independent Market Monitor Beth Garza tapped the brakes on what she said was a “zeitgeist” moment.
“There were a zillion articles over how wind has surpassed coal,” she said during her midyear market review. “That was absolutely true year-to-date through June. It’s no longer true through July.”
Garza said coal generation reasserted itself over wind generation in July. Coal now accounts for 21.1% of the fuel mix and wind 20.7% through July, she said.
“I do believe at one point, there will be more wind generation than coal generation in ERCOT, because we are very, very close now,” Garza said. She noted the switch is more about a decrease in coal generation, than an increase in wind.
Garza said ERCOT’s average energy prices are down through the first half of the year when compared with 2018 — $27.81/MWh versus $32.45/MWh — despite similar load conditions. She attributed the decrease to a 13% decrease in gas prices, which averaged $2.62/MMBtu through July, compared to $3.03/MMBtu in the first half of 2018.
Lange Approved as TAC Vice Chair
The board formally approved Clif Lange, South Texas Electric Cooperative’s manager of wholesale marketing, as TAC vice chair. Lange replaces Diana Coleman, who stepped down from the TAC when she accepted a position with San Antonio’s CPS Energy.
“We appreciate your willingness to serve,” board Chair Craven Crowell told Lange.
The directors also approved the Finance and Audit Committee’s recommendation to accept Maxwell, Locke & Ritter’s audit report of ERCOT’s 401(k) savings plan. The auditors said they were unable to obtain “sufficient appropriate audit evidence to provide … an audit opinion,” noting they were told not to audit, but did accept the plan’s investments and notes receivable. That information was certified by Fidelity Management Trust Co., the plan’s trustee.
Board OKs 14 Changes
The board approved a Nodal Protocol revision request (NPRR917) that replaces load zone energy pricing with nodal pricing for settlement-only distribution and transmission generators (SODGs and SOTGs). The NPRR allows SODGs and SOTGs to request ERCOT continue to provide them load zone pricing until they opt in for nodal pricing or until Jan. 1, 2030, whichever comes sooner.
The directors unanimously approved their consent agenda, which included nine other NPRRs, a change to the Nodal Operating Guide (NOGRR), an Other Binding Document (OBDRR) and two system change requests (SCRs):
NPRR823: Synchronizes the protocols’ “affiliate” definition with state law to allow exemptions for portfolio affiliates (two or more publicly traded companies in the same industry with common shareholders).
NPRR904: Revises the categories of ERCOT-directed actions that trigger the real-time online reliability deployment price adder (RTRDPA) pricing run to include DC tie-related actions to reflect current system conditions and corrects identified flaws with current RTRDPA design.
NPRR931: Modifies the hub average 345-kV price calculation to reflect the use of aggregated shift factors, as opposed to simple averaging of the component hubs’ prices.
NPRR932: Clarifies that new load added to an existing ERCOT system zone (including load from a non-ERCOT control area) can take effect immediately without board approval.
NPRR935: Requires ERCOT to post values for wind and solar forecasts and include an indication of which model is being used for each forecast. Also requires ERCOT to issue a market notice and sponsor an NPRR proposing requirements for any new future forecasts.
NPRR942: Clarifies in the protocols the timing of the posting of the final allocated transaction limit for the congestion revenue rights auction, also known as the second-round limit.
NPRR943: Adds Martin Luther King Jr. Day to the list of ERCOT-observed holidays.
NPRR944: Updates the day-ahead market’s energy bid curve criteria language to align with current validation.
NPRR949: Removes the use of standard voice telephone circuits as an option for the grid operator to retrieve ERCOT-polled settlement meter data, effective Jan. 1, 2023.
NOGRR187: Aligns the NOG with NPRR863’s revisions to ancillary services.
OBDRR009: Paired with NPRR904, the change revises the online and offline capacity reserves for out-of-market actions related to DC ties, preventing price reversal and price distortion whenever ERCOT makes out-of-market actions.
SCR801: Corrects the global process ID for Texas standard electronic transaction (Texas SET) 867_03 by applying the same data lifecycle cross-reference consistency for all 867-03 usage transactions.
SCR802: Improves system inertia communications by showing the real-time system inertia value under the Real-Time System Conditions display on the ERCOT website.
The Northeast Power Coordinating Council’s Regional Standards Committee last week held a forum on reliability issues related to distributed energy resources, featuring presentations by Hydro-Québec, Duke Energy, Ontario’s Independent Electricity System Operator and others. Here’s some of what we heard.
Duke Energy: Donuts and Data Sharing
Adam Guinn, lead system operations engineer for Duke Energy, gave a presentation on his work on modeling and processes to integrate DERs to support real-time monitoring and forecasting. Guinn said tighter coordination among transmission and distribution operators and planners is essential to managing the changes brought by DERs.
How does Duke do it?
“They [planners] buy me donuts,” Guinn joked.
Guinn said he has daily phone calls and in-person meetings at least quarterly with system planners, and also trades data with his counterpart who does solar studies for Duke’s planning group.
“Anything he sees he immediately sends to me, so we’re on the exactly same email chain in communication groups for any new solar, any new facility changes that may impact current solar dispatch. … We’re both tapped into the interconnection queue, and we do data analytics and tracking for growth and penetration so that we make sure that his longer-term stuff is keeping up with what we’re seeing in real time.
“We’re essentially coupled at the hip now, and that’s not just planning. It’s the same way with distribution. Distribution planners, transmission planners and operations … we’re essentially all transferring data and information and things that we’re seeing, lessons learned, back and forth in somewhat of a real-time fashion just because this stuff changes so fast.”
Guinn said having a common “knowledge base” is the key.
“What I’m finding is that all of these problems [would be] somewhat more manageable if people would stop talking past each other or stop working in silos and start transferring information,” he said. “So, if I were to wave a [magic] wand, I would get everyone on the same sheet music … and stop bringing people in who don’t have any operations experience to implement solar, to implement processes — or don’t have any planning experience.”
Task Force Guidelines for Interconnections
NextEra Energy’s Allen Schriver, chief operating officer of the North American Generator Forum (NAGF), discussed the work of NERC’s Inverter-Based Resource Performance Task Force, which is working with the Institute of Electrical and Electronics Engineers to develop the P2800 standard (Interconnection and Interoperability of Inverter-Based Resources Interconnecting with Associated Transmission Electric Power Systems).
Schriver said the task force is currently reviewing comments on its guidelines recommending improvements to interconnection agreements. The comment period closed July 24.
“What do you need to ask when you’re interconnecting inverter-based resources? … Essentially what you’re asking is: What do you want them to do? When do you want them to do it, and how fast?”
One recommendation is that DERs do not attempt to reconnect during black start events.
“If you come off during a black start, do not come back on until the [balancing authority] wants you to come back on. Do not automatically reconnect because … you may take the system back out,” Schriver said.
NERC, the NAGF and the Energy Systems Integration Group (ESIG) will hold a workshop Sept. 17-18 on storage, hybrid resources and frequency response. The workshop will be held at NERC’s D.C. office with a teleconference link to the organization’s Atlanta headquarters.
The workshop will include discussions on the capabilities of battery energy storage; motivations, drivers and challenges of hybrid projects; planning, interconnection and modeling; and ISO/RTO market rules.
Canada Adapts to DERs
The forum included presentations by several Canadian representatives.
Adnan Akhtar, supervising network management engineer for Hydro One, said his company is looking to change how it applies thermal limits on its system because more than 50% of its feeders in Ontario have less than 3 MW of generation capacity left.
“We’ve found that the non-exporting generation isn’t contributing to the thermal limit. We’re able to relax our thermal requirements to allow some more non-exporting generation to connect, at least at the feeder level,” he said, adding that the utility still must observe short circuit limits.
Akhtar said the company is implementing DER management systems to allow higher outputs. “We’ve always based our planning criteria on the worst case — minimum load, maximum generation — and that ends up leaving you underutilizing your assets for the majority of the year because your worst-case scenario probably happens maybe a few hours a year or maybe a few days a year.”
Mohab Elnashar, a senior engineer for performance validation and modeling for Ontario’s IESO, discussed the ISO’s 2019Operability Assessment, which looked at the impact of increased penetration of inverter-based DERs on the bulk power system, with a focus on light loading conditions.
DER management systems (DERMS) can allow higher outputs. | Siemens Industry
IESO has already seen instances of reduced power system responses after transmission faults. It also has identified a new single largest contingency (SLC), recognizing that under certain conditions, three-quarters of the province’s DERs could trip from a transmission fault, Elnashar said.
The loss of a single 878-MW unit at the Darlington nuclear plant has been Ontario’s SLC. “If the fault occurs at Darlington, a Darlington generator and DERs will trip, causing a new and very large SLC for Ontario,” Elnashar said.
The report found IESO has enough synchronous hydroelectric and nuclear generators to support system inertia and primary frequency response after a fault, but it recommended changing the voltage trip settings on inverter-based DERs. It is working with the Ontario Energy Board to adopt the new Canadian Standards Association rules on DER performance.
It’s also considering occasionally increasing operating reserves and seeking cost-effective transmission reinforcements that could reduce the DERs lost because of a single contingency.
“The only time we would need to increase the operating reserve is when we have light loading conditions [and] high penetration levels from the distributed energy resources,” he said. “During light loading conditions, we don’t have the gas units [to provide] voltage support in the load centers.”
Transmission planning engineer Nicolas Compas, of Hydro-Québec TransÉnergie, said that because his company’s generation is already 99% renewable, it has very few DERs and no decarbonization goals. Thus, it expects electric vehicles to be a bigger impact than solar PV generation. By 2030, it projects it may have 25% EV penetration but only 5% PV penetration.
Compas said the company tested the eight most popular inverter models to see how they react in low-voltage or low-frequency situations, how they manage ramping power, and how to change their settings. “None of them meets Hydro-Québec requirements,” he said.
“DER will grow in Hydro-Québec, that’s for sure. It will still be different from other utilities because of our weather, because of the [low] energy prices. … We have a slower adoption curve, so we can learn from many of the other utilities that already have a lot of DERs and can see issues coming up.”
SPIDER Working Group
Dan Kopin of Utility Services briefed the group on the work of NERC’s System Planning Impacts from Distributed Energy Resources (SPIDER) Working Group, which in June issued a draft reliability guideline with recommendations on developing underfrequency load shedding (UFLS) programs that can work with increasing DER penetration.
It is reviewing reliability standard MOD-032-1 to consider including DERs in interconnection-wide planning cases.
For insight on the impact on island-level system frequency as higher levels of load are served by DERs, the group has examined research by ISO-NE. It also found lessons in a September 2016 incident in which 850,000 customers in South Australia lost power after two tornadoes damaged three 275-kV transmission lines. According to a report by the Australian Energy Market Operator, the damage caused the lines to trip, resulting in six voltage dips over a two-minute period. The faults caused a drop in wind production and a surge in imported power that tripped an interconnector offline. The South Australia grid then islanded from the rest of the National Electricity Market.
“Without any substantial load shedding following the system separation, the remaining generation was much less than the connected load and unable to maintain the islanded system frequency. As a result, all supply to the [South Australia] region was lost,” the grid operator reported. It said the incident highlighted the need for more inertia to slow down the rate of change of frequency and allow automatic load shedding to stabilize the grid within a few seconds.
“The rate of change of frequency following separation (6.25 Hz/s) was too great for the UFLS scheme to operate effectively,” Kopin said.
He said he’s encouraged by the analysis that ISO-NE and others are doing on the growth of DERs. “I think it’s fair to say that all the planning coordinators involved with SPIDER are there because they get that this is a problem,” he said.
DES MOINES, Iowa — To mitigate cyberthreats to grid infrastructure, utilities must train their employees and become less wary of sharing information with other utilities, according to experts speaking at the Mid-America Regulatory Conference (MARC) on Monday.
Illinois Commerce Commissioner D. Ethan Kimbrel kicked off a panel on the subject with a reminder of last month’s ransomware attack on Johannesburg’s City Power, which encrypted the utility’s databases, applications and network, crippling its payment system.
Joe Randazzo, ITC Holdings’ director of networks and information security, said the most sophisticated “bear” (read: Russian) group of hackers can take as little as 18 minutes to gain access to a utility’s operational technology.
“A lot of times we’re fighting the ‘bears’ singlehandedly without the help of the federal government,” said Peter Grandgeorge, MidAmerican Energy program manager.
“Everybody in this room, whether you’re a vendor or a regulator, you’re a risk,” Grandgeorge said of the proliferation of phishing campaigns coming from compromised third-party emails.
“Most hackers are preying on the goodwill of people,” Randazzo agreed. “And hackers only need to be right once; employees have to be right 100% of the time. A person clicking on an email because they think they won a $50 Amazon gift card can have huge implications.”
Grandgeorge said when MidAmerican began conducting phishing tests among its employees a few years ago, the failure rate was at about 20%. He expects an upcoming test will yield just one or two failures out of the company’s approximately 3,750 employees.
“That sounds good, but we think it sounds terrible. Because it only takes one,” Grandgeorge said.
“I don’t want to say people are the weakest link, but if you can do phishing activities, you’ve plugged a big hole,” said Paul Hofman, vice president of IT at Central Iowa Power Cooperative.
Hofman said it’s preferable to provide cybersecurity training for an employee already well versed in utility operations than to a bring in a standard cybersecurity expert.
“You can’t just treat your operational technology like printers and PCs,” Hofman said, adding that one cybersecurity scan at his co-op set off several alarms to the exasperation of system operators.
Sam Ellis, SPP’s director of cybersecurity and controls, said finding talented people with cybersecurity experience is fast becoming a challenge as more positions open up.
Ellis also advocated for utility IT professionals to network among themselves to learn about different cybersecurity strategies. He said grid operators regularly share experiences at ISO/RTO Council meetings.
“There’s a saying that when you need a friend, it’s too late to make a friend,” Ellis said.
If SPP’s market system goes down, he said, “we feel confident that we can maintain reliability,” but the RTO has less confidence its system will continue to operate reliably if its energy management system is taken out. In that case, others — such as the transmission owners — still “have eyes on the system.”
Randazzo said cybersecurity intelligence is not regarded as the proprietary information it once was, and utilities are less “skittish” now about sharing threat possibilities with one another.
“This is a team effort,” he said. “We can share what we call IOCs: ‘indications of compromise.’”
Hofman said state utility commissions could help create a safe, secure space where utilities can confidentially share cybersecurity information without risking public exposure of sensitive materials.
Multiple panelists also urged utilities to submit cyberthreats to the Kansas City Regional Fusion Center, which can compare possible threats against its database of known ones.
Grandgeorge noted that cybersecurity can also require physical efforts, recounting that he’s taken FBI agents along on a wind tower climb to better understand how to regain control of hacked equipment. He said he didn’t consider the move an extraordinary measure after Chinese espionage agents were caught stealing seed corn in Iowa in 2016 in order to extract intellectual property from the genetically modified seeds.
PG&E Corp. named a new utility chief Tuesday, submitted a broad outline of a bankruptcy reorganization plan and tried to fend off competing proposals during a federal court hearing in San Francisco.
The behemoth bankruptcy of California’s largest utility lumbered forward in the U.S. Bankruptcy Court for the Northern District of California, as pressure mounted to speed up the court proceedings, and stakeholders fought over control of the company and the billions of dollars they hope to win.
Judge Dennis Montali opened Tuesday’s hearing, one of the most significant in the case so far, with a reminder of the thousands of victims of fires sparked by PG&E equipment in the past four years. The company filed for bankruptcy protection in January, after November’s Camp Fire killed 85 people and destroyed most of the town of Paradise, Calif.
San Francisco Bay Area residents remember the smoke that filled the air last fall and the television images of the devastation in Paradise, but “that’s really not much,” Montali said.
“It’s nothing like the nightmares and the horrors that were experienced by all of the victims and their families and their loved ones, and that they are no doubt reliving endlessly,” he said. “And that’s why we’re here. That’s why we’re working in this community, in the bankruptcy world, to deal with one aspect of that tragedy.”
Next, Montali heard lengthy arguments from bondholders and insurance companies over why he should end PG&E’s exclusivity period — the time it has to file its own reorganization plan without the judge considering competing proposals.
Both groups want to make sure they get paid, and perhaps even profit from the process.
Efforts by the California Public Utilities Commission to broker talks among the competing parties broke down, a CPUC lawyer told Montali on Friday. (See Bankruptcy Judge Questions PG&E Exec Compensation.)
A proposal by company bondholders would inject more than $30 billion into PG&E, including about $18.4 billion for fire victims, lawyer Michael Stamer told the judge. Stamer represents an ad hoc committee of senior unsecured noteholders, including banks and mutual funds that collectively hold more than $10 billion in PG&E bonds.
Stamer and others argued for expediency because of recent legislative action. Under Assembly Bill 1054, passed last month, the PUC must approve a bankruptcy plan by June 30, 2020, for PG&E to be able to access a $21 billion fund to pay wildfire claims. (See California PUC Jumps into PG&E Bankruptcy Fray.)
PG&E attorney Stephen Karotkin argued the plan was a way for bondholders to seize control of the company for pennies on the dollar. He urged the judge to give PG&E until Sept. 9 to file its own reorganization plan with the court.
Court papers filed by PG&E on Monday gave a clearer idea of what that plan might entail. It would raise billions of dollars in equity capital to settle wildfire claims and would honor all pre-bankruptcy debts and power purchase agreements.
PG&E’s bankruptcy raised concerns that it would try to reject many of its 387 PPAs worth about $42 billion, especially contracts for solar and wind power. That led to a dispute with FERC about who had authority over the agreements. (See Judge Sides with PG&E over FERC in PPA Dispute.)
Montali took the motions to end exclusivity under submission. He could rule on them as early as Wednesday, when he’s also scheduled to hear arguments over estimates of wildfire damages.
New CEO
Also on Tuesday, PG&E announced its board of directors had appointed Andrew Vesey as president and CEO of its primary subsidiary, utility Pacific Gas and Electric.
Andrew Vesey
Vesey was employed as CEO of AGL Energy, a company based in Sydney, Australia, from 2015 to 2018. AGL has about 3.7 million gas and electric customers and controls around 20% of Australia’s generating capacity, PG&E said in a news release.
Before AGL, Vesey was a longtime executive, including serving as COO for AES.
Vesey starts Aug. 19, according to PG&E. His compensation includes a $1 million annual salary and a $1 million “transition payment,” according to a Securities and Exchange Commission filing. He may also be eligible for roughly $2 million a year in incentive bonuses if Montali approves PG&E’s Key Employee Incentive Plan.
“Andy is a focused and talented leader with the demonstrated experience to help PG&E improve our safety and operational performance, while also being a strong advocate for clean energy solutions,” PG&E Corp. CEO Bill Johnson said in a statement. “We have full confidence in Andy to lead change and deliver results across our safety and operational areas, including electric, gas, generation and customer teams.”
Texas power prices bumped up against the market’s cap as the state registered another day of soaring temperatures and demand on Tuesday, just as ERCOT CEO Bill Magness predicted early in the day.
Addressing the grid operator’s Board of Directors during its regular bimonthly meeting, Magness said, “It’s going to be a tight day on the ERCOT system as we go through the afternoon.”
And indeed it was. With triple-digit temperatures once again driving up the use of air conditioners, ERCOT was forced to call a Level 1 energy emergency alert at 3:12 p.m. — its first such alert since 2014. The grid operator asked for conservation measures as its operating reserves dipped below their 2.3-GW threshold.
Image from ERCOT’s website Tuesday afternoon | ERCOT
The EEA was canceled at 5:02 p.m., but not before demand came close to Monday’s record of 74.5 GW, topping out at 74.2 GW during the interval ending 5 p.m. Still, that broke the 2018 record of 73.5 GW, the sixth time in two days ERCOT has exceeded that mark. Eight of the system’s top 10 highest demand peaks have come since Monday. (See ERCOT Sets New Demand Mark, Smashes ’18 Record.)
Settlement prices hit quadruple digits during the 15-minute interval that ended at 2 p.m. and reached ERCOT’s maximum of $9,000/MWh at 3:45 p.m., staying in that range through the 5 p.m. interval. Monday’s prices had peaked at $6,537.45/MWh.
Day-ahead prices for Tuesday were trading in the $2,600 to $2,700/MWh range, said Potomac Economics’ Beth Garza, director of ERCOT’s Independent Market Monitor.
ERCOT’s website became sluggish during the afternoon as interested visitors watched the lines in a graph depicting capacity and demand nearly touch.
During his presentation to the board, Magness drew attention to a slide in his deck. It noted “warmer” temperatures during the second half of the summer, as opposed to the first half.
“Our expectations for August have advanced quite a bit in the last week,” he said.
Magness exuded confidence in ERCOT’s staff, which knew what was coming this summer. The grid operator had projected peak demand of 74.9 GW.
“If you ask any of the men and women working in the control room today, they’ll tell you this is what we train for,” Magness said. “That circle of support extends beyond the control room … into every part of ERCOT. This is what we train for; this is what we do; this is the service we’re supposed to provide. So let’s have it.”
After the meeting, ERCOT called on consumers and businesses to reduce their energy use through 7 p.m.
The Public Utility Commission of Texas also issued a press release calling for conservation, suggesting consumers make a few “simple choices” by raising their thermostats a couple of degrees, reducing lighting and using heavy appliances after sunset.
“When the energy demands of our state’s steadily growing population and booming economy intersect with hot summer temperatures, the supply of power can get a little tight,” PUC Chair DeAnn Walker said in the release.
ERCOT sent out a market notice Tuesday morning, alerting participants that the Texas Commission on Environmental Quality (TCEQ) will “exercise its enforcement discretion for exceedances of emission and operational limits of power generating facilities” should the generators exceed air-permit limits.
Generating facilities expecting to exceed their limits were directed to notify the TCEQ, and ERCOT said it would notify market participants when the agency’s “enforcement discretion” ends.
John Hall, the Environmental Defense Fund’s state director of regulatory and legislative affairs, suggested other alternatives to increased generation.
“While this may look like a zero-sum game, it doesn’t have to be,” Hall told RTO Insider. “Policymakers have a suite of tools — such as energy efficiency and demand response — to avoid the false choice between Texans’ air quality and a reliable grid.”
Ohio Attorney General Dave Yost on Monday rejected a draft petition to repeal the state’s nuclear subsidy program via ballot referendum, but the disgruntled parties behind the measure say they aren’t discouraged.
Gene Pierce, spokesperson for Ohioans Against Corporate Bailouts, told RTO Insider the development doesn’t change the group’s ultimate goal: overturning House Bill 6 in the November 2020 election.
Ohio Attorney General Dave Yost | Dave Yost
“We have a plan to get the signatures that we need, and we’ve been lining up the resources that we need to make this happen,” he said. “We are confident that we can make the deadlines to get on the ballot next year.”
The 90-day countdown to get the ballot petition approved began July 23, when Gov. Mike DeWine signed the Ohio Clean Air Act into law. The act replaces the state’s renewable energy mandates with ratepayer surcharges to support FirstEnergy Solutions’ Davis-Besse and Perry nuclear plants and two Ohio Valley Electric Corp. (OVEC) coal plants. (See Ohio Approves Nuke Subsidy.)
The controversial law makes Ohio the third state in Monitor: PJM Markets Remain ‘Under Attack’.) Supporters say keeping the reactors operating will reduce carbon emissions — a primary target of clean energy bills across the country — and provide around-the-clock reliability to support the intermittency of solar and wind power.
Pierce’s group argues the law amounts to a “corporate bailout” that wastes money on less efficient resources at the expense of continuing to expand Ohio’s renewable energy portfolio. And they’ve got some powerful, if not unlikely, allies on their side: the natural gas industry, independent power producers, environmental activists and clean energy groups.
“The bottom line is we will take the attorney general’s suggestions and critiques and work very quickly to provide another draft as soon as possible and hope that we can solve these issues very quickly,” Pierce said.The group filed its revised petition Friday and said the state has 10 business days to certify the draft.
Yost highlighted 21 errors in the petition summary that prevented him from certifying the document as “a fair and truthful statement of the measure to be referred.” The inaccuracies relate to misstated definitions for “electric distribution utility” and “renewable credits,” among other terms, as well as missteps in the way petitioners described the responsibilities, calculations and procedures detailed in the law itself.
“It’s not atypical for a first draft of a petition on a complicated bill like this one was to need some corrections,” Pierce said. “We are still on plan. We know how many signatures we have to get and we know how much time it takes to get them.”
ClearView Energy Partners agrees with Pierce’s cautious optimism, noting that while the 21 errors seem a bit excessive, Yost has rejected four of the last 10 petition drafts submitted to his office. Three of those drafts were subsequently approved upon resubmission — an outcome the analysts believe is likely in this case too, given that Yost expressed no opposition to the petition’s merits.
Timing also appears key for the group, the analysts said. With a broad coalition of allies, the “corporate bailout” narrative and the act’s structure itself — ratepayers won’t see those monthly surcharges until 2021 — ClearView suggests that a ballot referendum could succeed, overturning the subsidies before FirstEnergy and OVEC collect a single penny.
Pierce told RTO Insider that his group will disclose its financial supporters as required by Ohio campaign finance law.
“Until then, I can say that you will find that they are many of the same groups and individuals who testified against the bill in the legislative debate over the bill,” he said.
If the revised petition is approved, Pierce’s group will then begin collecting the roughly 265,000 signatures ahead of the Oct. 21 deadline for inclusion on the ballot next year.
DES MOINES, Iowa — MISO and SPP are making earnest efforts to coordinate transmission development along their shared seam, but much more remains to be done to manage an impending influx of renewable resources, regulators and industry participants said Monday.
And time is of the essence for making needed changes, according to some of the experts participating on a panel devoted to addressing shortcomings in the MISO-SPP interregional process at this year’s Mid-America Regulatory Conference (MARC).
The panel marked the first time that MISO and SPP representatives appeared together on a stage to express support the creation of a smaller, interregional project category such as the MISO-MISO, PJM Endorsing 2 TMEPs for Year-end Approval.)
MISO Director of Seams Coordination Jeremiah Doner said that MISO-SPP interregional projects — currently elusive — will become essential as more variable generation comes online. A larger transmission network is more beneficial because it can draw on more types of resources to firm up supply, he said.
“The bigger region you have to manage, that need for flexibility is going to be key,” Doner said.
MISO is eager to begin working with SPP to create a TMEP project template, he said.
“We don’t just want to take [the] PJM [TMEP model] and copy and paste it,” Doner said, although he added MISO has gained valuable experience through two rounds of TMEPs with its eastern neighbor.
SPP Director of Seams and Market Design David Kelley said his RTO would also like to develop something akin to TMEPs with MISO.
“We’ve seen the success between PJM and MISO. We’re very interested in getting a process like that in place,” Kelley said, adding that the idea must still be advanced through MISO’s and SPP’s separate stakeholder processes.
Missouri Public Service Commissioner Daniel Hall spoke about the recent endorsement by the Organization of MISO States and the SPP Regional State Committee to engage the RTOs’ monitors to conduct joint studies on seams issues. (See RSC, OMS Approve Monitors’ Seams Study.)
“There was a growing problem, and the problem is two RTOs run their grids independent of one another,” Hall said in explaining the need for the effort. “There are fundamental differences between MISO’s and SPP’s management styles: On the MISO side it’s, ‘If it’s built, use it.’ On the SPP side, it’s, ‘If it’s ours, you pay us.’”
Hall also noted that the RTOs’ executives don’t always agree: “I think those philosophical differences get overplayed, but they still exist.”
Neither OMS nor the RSC are under any illusion that they can force the RTOs to adopt new interregional planning processes, he said.
Invenergy Director of Regulatory Affairs Nicole Luckey said the RTOs’ current process is encumbered by voltage and cost thresholds that are no longer appropriate and an interregional planning approach that has “too many cooks in the kitchen,” preventing cross-border transmission projects that could deliver low-cost wind energy.
“We have a [joint operating agreement] that’s way too prescriptive,” she said. “If I were a regulator, I would be pissed that my customers weren’t getting access to the lowest-cost generation in the country.”
However, Luckey also acknowledged MISO’s recent failed proposal to lower voltages on interregional projects to 230 kV for regional cost allocation, calling the filing a good start. (See MISO Allocation Plan Fails on Local Project Treatment.)
“I do think we’re much too prescriptive in what we look at” for projects, Kelley allowed. He said simply sizing up projects based on adjusted production costs makes less sense as the marginal cost of renewable energy approaches zero.
Kelley expressed hope about changes, saying SPP would work to identify and remove barriers. But he also contended the two RTOs were unlikely to reach total transmission planning consensus without a national energy policy and “leadership on a national scale.”
“And I would argue we’d all be dead before we get federal energy policy,” Luckey said.
Hall said it’s not well understood that the cost of congestion on RTO seams is socialized among ratepayers situated far from those seams.
“Even if you’re not on a seam, your ratepayers are paying for congestion. … That has to be acknowledged,” Hall told attendees. “The more [efficiently] the entire grid works, it serves as a benefit. It’s not just a function of bringing cheap energy to market; it’s moving it around in the most efficient way.”
“You can’t look at just whether your state is going to benefit,” Luckey told regulators.
Hall said the dearth of interregional projects is best illustrated by Ameren Missouri’s proposed northwest Missouri wind farm, which originally had a $10 million interconnection price tag that later escalated to $40 million because of needed transmission upgrades. Ameren recently scrapped plans for the 157-MW project because of sticker shock.
“And the reason was all of the congestion in the area,” Hall said. He said the Ameren wind farm was a “poster child” for the lack of interregional transmission planning.
“We cannot build transmission plans interconnection upgrade by interconnection upgrade,” Hall said.
MISO and SPP have so far undertaken three 18-month coordinated system plan (CSP) studies — in 2014, 2016 and 2019. The first two CSPs failed to identify a worthwhile interregional seams project, and early indications are that the most recent hasn’t identified a contender either. The 2019 CSP relied on only the RTOs’ respective regional models, removing the additional joint model.
“I’m going to take a little shot at MISO, but I warned Jeremiah [Doner], so he knows it’s coming,” Luckey said before criticizing what she called the RTO’s “old, stale” planning assumptions in its annual Transmission Expansion Plan (MTEP). MISO is dramatically underestimating the amount of renewable penetration in its four future scenarios used to inform MTEP, she contended, especially considering carbon-reduction pledges by Midwestern utilities.
“No comment,” Doner joked, although he addressed the criticism by noting MISO is seeking to rework its futures for the 2021 MTEP cycle.
Luckey said “massive” energy infrastructure upgrades are needed, and they can’t wait until MISO can “perfectly forecast” renewable penetration.
