NERC has finished transitioning to the latest version of its situational awareness tool and plans to introduce it to reliability coordinators once the vendor developing the system has implemented new modeling software, the vendor’s CEO told the ERO’s Operating Reliability Subcommittee on Feb. 11.
Additional features being added to the tool include separate views for RCs, FERC and the ERO Enterprise, along with advanced data visualization tools incorporating a range of information such as substation performance, space weather, gas pipeline availability and fire tracking.
“We’re building a process that will allow you, the RCs, at very little manual work other than review, to continue to push updated model information into SAFNR v.3,” Legatt said. “Therefore, the impact to the RCs will be lower, and the accuracy of the tool will go up significantly.”
SAFNR v.3 went live for NERC and the ERO Enterprise in December 2019. Darrell Moore of NERC said that the tool will be rolled out to remaining stakeholders after ResilientGrid finishes building models with updated information from the RCs.
Clarity Sought on IROL Exceedance Metric
The task force revising the metric for identification of interconnection reliability operating limits (IROLs) brought two recommendations to the subcommittee for feedback: to ensure consistency in reporting by requiring operators to report all IROL exceedances with no operating margin added, and to change the threshold for reporting from 10 seconds to one minute.
“As the ORS is kind of our [forum] to talk to subject matter experts, we want your feedback on the proposed changes — should we start taking the steps to make this modification so that we can have a better, more valuable metric?” asked Maggie Peacock, manager of advanced analytics at SERC Reliability and chair of NERC’s Performance Analysis Subcommittee.
Several members of the subcommittee urged the task force to address what they saw as a lack of clarity in the recommendations. In particular, John Norden, director of operations at ISO-NE, said the metric should be clear as to whether it includes any buffer an operator has built into its system.
“It probably should be consistent, because the last thing we want to do is give doubt to an operator,” Norden said. “[If] you have a 1,000-MW transfer limit as your limit, and the operator gets to 28 minutes and he’s at 1,050, should he take action to get below 1,000 in the [last] two minutes, or should he say I have a buffer? … The limit’s the limit, as far as I’m concerned, and that’s what you should operate to, whatever you put in front of the operator.”
Members Object to RCIS 2021 Development
The group developing the successor to the Reliability Coordinator Information System (RCIS) is currently working on a request for proposals. It hopes to choose a vendor by the second quarter and introduce the tool by early next year.
Creation of the new software, called RCIS 2021, is being conducted by the Eastern Interconnect Data Sharing Network (EIDSN), a group created in 2014 to further develop industry tools that NERC has decided it no longer wants to maintain. NERC initiated the project in 2017 to replace the current RCIS with a more modern architecture and provide a common platform for instant communication between RCs, as well as between RCs, NERC, and transmission owners and operators.
Some at the meeting raised strong concerns about a perceived lack of input from Western operators into the system, as EIDSN is composed of representatives from the Eastern and Quebec interconnections. These were amplified when EIDSN Executive Director Jim Schinski said that use of RCIS 2021, which is required by several NERC standards, will be subject to a fee paid to EIDSN.
“Speaking for my company, and I think for others, we’re going to have some strong objections to that,” said Tim Beach, director of reliability coordination at RC West. “Because you’re [requiring] us to participate … and pay, with no control over requirements or cost in the future.
“I understand the tool needs to be replaced. Full agreement with that. … But the process of getting there and the requirement to use it seems a little upside-down to us in the West,” he added. [Editor’s Note: A previous version of this article mistakenly attributed this quote to Tim Reynolds, manager of event analysis and situation awareness for the Western Electricity Coordinating Council.]
Richard Mandes of EIDSN told members that “they’re paying for that functionality today through NERC” and that the fee paid to EIDSN would cover the same services they are getting now. He also promised that members would have an opportunity to provide input into the design of the system through NERC before it is introduced.
Electric vehicle makers are now offering 90 models for sale in the U.S., and the nation’s charging infrastructure grew by 17% last year, according to data released last week by BloombergNEF.
Yet U.S. EV sales dropped 11% in 2019, accounting for just 1.8% of total vehicle sales, Bloomberg reported.
Nevertheless, state regulators said during a panel discussion at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit last week they remain upbeat about the potential for vehicle electrification to help decarbonization efforts — and maybe reduce system costs.
The number of public and workplace EV charging points rose 17% to 71,000 in 2019. Through 2018, about one-third of the EV chargers were in California. Most EV charging, however, is done at home. | BloombergNEF
“This is a really exciting time to talk about EVs,” said Al Freeman, an adviser for the Michigan Public Service Commission, who keeps a very busy Google alert to keep track of industry developments.
Michigan’s utilities have made “some really neat [pilot] proposals” to the commission, he said, including $13 million, three-year pilots by both Consumers Energy and DTE Energy, which were approved by the commission last year.
“There’s a lot of challenges, but they’re responding to it very well and being aggressive in the marketing and the education of it,” he said of Consumers. DTE has been similarly aggressive, he said. “A lot of their costs have come in below what they estimated, which will allow them to have a little bit more money for additional rebates.”
U.S. sales of electric vehicles dropped 11% in 2019, with battery electric vehicle (BEV) sales up 2% to 235,000 units while plug-in hybrid electric vehicle (PHEV) sales fell 36% to 76,000. Fuel cell vehicle (FCV) sales dropped 12% to 2,090 (too small to be visible on the chart). | BloombergNEF
2 Questions
Hanna Terwilliger, economic analyst for the Minnesota Public Utilities Commission, said EV growth is outpacing rooftop solar in her state, although enrolling owners in time-of-use rates remains a key challenge.
Terwilliger said Minnesota is seeking to integrate EVs in a way that benefits all customers and avoids adverse system impacts. It’s also considering whether it should encourage widespread adoption of EVs to meet policy goals, such as carbon reductions.
“Each state will have different answers to these questions, but we all need to … make sure we’re prepared because … even just one EV charging at a house can double their electric consumption, and they’re coming faster than other types of [distributed energy resources] like rooftop solar,” she said.
Americans have purchased or leased 1.4 million battery-electric and plug-in hybrid electric vehicles since 2010, according to BloombergNEF. Minnesota has about 10,000 EVs, most in its metro areas but with some penetration in rural areas as well.
But while the Dakota Electric Association has almost half of their EVs enrolled in TOU or off-peak rates, Minnesota Power, Otter Tail Power and Xcel Energy have struggled to get participation above 10%. Terwilliger said a big challenge is the expense of installing a second TOU meter.
Asked to explain the disparity, Terwilliger noted that Dakota is an electric cooperative. “Anecdotally, from other co-ops that have similar rates, they’re also around 50%,” she said.
“There’s a number of reasons why co-ops have been more successful. They historically have had a lot more demand-response programs, and they’ve been able to expand those programs to include EVs. So, a lot of the infrastructure is already there. It’s less expensive to enroll customers in the rate. I think that co-ops also have a lot more direct communication with their members. Members want to read the newsletters that come out, versus if you’re trying to [communicate] something on a bill insert, there’s a lot of times people just throw it away.” Some customers get electronic bills and don’t receive bill inserts, she added.
U.S. sales of conventional hybrid electric vehicles (HEVs) such as the Toyota Prius rose 10% to 373,000 units in 2019. Conventional hybrids can only recharge their battery through regenerative braking. | BloombergNEF
She said utilities must enroll EV drivers in some type of managed charging rate when they purchase their cars. “Even if it’s not perfect, it’s much easier to switch a customer to more sophisticated program than it is to try and go and find them” after the sale.
It’s also important to have the rate structure ready to accommodate and encourage fleets switching to EVs, she said, noting Amazon’s plan to purchase 100,000 EV delivery vans, reportedly the largest EV order ever. “When they start coming into your service territory, Amazon does not want to wait for you to go through a regulatory process. They want a good solution there right now that’s going to save them money.”
Tim Echols, vice chair of the Georgia Public Service Commission, lamented that his state in 2015 abolished the $5,000 tax credit that had made it one of the early leaders in EV growth. He said the credit died because messaging about EVs’ environmental benefits took “all the oxygen in the … room.”
“I’m on my fourth EV. I’m a big proponent. But we’re making a switch [in messaging]. We have five Republican commissioners. Every constitutional officer in Georgia is a Republican. And we’re beginning to talk about how EVs charged at home overnight put downward pressure on rates. That’s the new red state message. Nothing else about the environment, because our left-leaning friends are going to come with us no matter what. … It’s the Republicans that are holding us up on this.”
WASHINGTON — Cybersecurity and resilience were the subject of numerous discussions at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit this week, with NERC CEO Jim Robb previewing an upcoming report on GridEx V and a FERC official urging regulators to get security clearances.
As the primary foreign assistance arm of the U.S. government, the Agency for International Development is known for “sacks of grain, digging wells [and] collective farms, and that is a lot of what we do,” said Steve Burns, chief of the agency’s energy and infrastructure bureau for Europe and Eurasia. “But we are also engaged in pretty advanced energy market structuring work and … critical infrastructure work.”
He cited USAID and NARUC’s work with Eastern European utilities on the development of cyber standards and tools for evaluating utility cyber preparedness.
“There’s probably a 12- to 18-month lag from when we introduce concepts until they’re taken on. We’ve been working with NARUC on this since late 2016, and we’re really starting to see the uptake now,” he said. “We’re actually seeing a lot of that come back to the United States. For instance, the regulatory cybersecurity strategy development guide that has been put out, some of the stuff that we’re working on now was actually done through the international partnership and then ported over … and there was more work done here to make it appropriate for a U.S. audience. We have seen several states actually start to develop strategies based on that. There’s a lot of that information sharing that goes back and forth.”
Michigan Public Service Commissioner Dan Scripps said he benefited from a three-day trip to Estonia and North Macedonia in October, where he met with regulatory agencies from 10 countries.
“In some ways, they’re ahead of us, and in some ways, we’re ahead of them [on cybersecurity],” he said. “There was a real opportunity for dialogue as opposed to, ‘Hey, we know all the answers.’ … This is very much a two-way street. The questions that were asked, the examples that they provided, all helped me as a Michigan regulator ensure that we’ve got the right protections.”
DOE Praises State Cyber Efforts
Assistant Energy Secretary Karen Evans, head of the Department of Energy’s Office of Cybersecurity, Energy Security, and Emergency Response (CESER) praised states for stepping up their cybersecurity efforts. She noted the increased state participation in GridEx V and said 16 states considered about 50 legislative measures to address cybersecurity of the electric grid and other critical infrastructure in 2019. “This an increase of around 30% over the previous year,” she said.
She also discussed her office’s role in helping the Department of Homeland Security and states respond to manmade and natural disasters, including cyberattacks, electromagnetic pulses and geomagnetic disturbances (GMD) under Emergency Support Function (ESF) 12.
Each state and territory was required to identify an energy emergency assurance coordinator, some of whom are officials of state regulatory agencies, while others are part of state energy or emergency preparedness offices.
South Carolina Public Service Commissioner Swain E. Whitfield, who chaired the commission between 2016 and 2018, complained that state law limits the commission’s emergency role.
“The ESF12 function goes to the Office of Regulatory Staff, which by law has to be housed in a separate building from us,” he said. “When I was chairman and hurricanes were hitting South Carolina, I was getting calls from my fellow state chairmen all around the nation offering everything from 8,000 National Guard troops to water to all kinds of resources. It was really frustrating because I wanted to be right there in the forefront of helping. But we’re not allowed to be in the operations center because some of our utility heads are in there and they don’t want us interacting.”
But that doesn’t mean the commission isn’t important, he said, noting that regulators have to approve utility spending on capital investments and other preparedness measures. He also noted NARUC’s work on recovering from “black sky” events. “Those are certainly two areas where you as a regulator can … be involved even if you’re in a state like mine, where its clearly defined that you don’t have an ESF12 function,” he said.
FERC: State Regulators Need Security Clearances
Joe McClelland, director of FERC’s Office of Energy Infrastructure Security, told regulators their commissions should obtain security clearances for at least one commissioner and one subject matter expert so they understand cyber threats and are capable of responding to them.
McClelland said he tells utilities the same thing. “My personal opinion is there should be at least two people that have those clearances. One would be the subject matter expert; it could be anybody. The second person is the CEO. Why both? Because if they’re both in a secure facility and the subject matter expert is saying, ‘We’re just getting murdered here. We’ve got adversaries that are able to do x, y and z because of a vulnerability that we have,’ the CEO, if they’ve got the trust of the board of directors, can say, ‘Let’s fix it.’”
He noted that in 2017, the Defense Department’s Defense Science Board Task Force on Cyber Deterrence issued a report that recommended increased information sharing with regulators considering cost recovery requests for resilience investments.
“We’re not going to force you to do it,” he told the regulators. “But if you work with us, our office will make sure you have access to that intel and you have an understanding of what those threats are, [that] you understand what our position is, what the consensus of the security community is. We bring them into that conversation too and identify fixes for those vulnerabilities.”
Prudent Resilience Spending vs. Gold Plating
Scott Aaronson, vice president of security and preparedness for the Edison Electric Institute, said industry needs to find a way to quantify the value of resilience investments to win the support of consumer advocates suspicious of excessive spending on “gold plating.”
“Instead of being in this defensive, ‘Hey just let us spend this money’ [posture], it is incumbent upon the companies and our federal partners … to make the case to consumer advocates that … [these are] not just prudent investments, but actually can ultimately have better outcomes for customers.”
Aaronson cited the example of Florida Power and Light, which spent $3 billion in 2005-15 on storm-hardening measures, including replacing poles with stronger wood or concrete ones, installing flood monitors and improving maintenance through more aggressive vegetation management and increased inspections.
The utility won regulatory approval for the spending after Hurricane Rita knocked out power to 4.8 million people for up to 13 days in 2005. About 4.6 million people lost power during Hurricane Irma in 2017, but all were restored within five days, Aaronson said.
“That eight-day delta — if you just used the $1 billion of GDP for the state of Florida per day — saved $8 billion. They spent $3 [billion]; they saved $8 [billion].
“There’s a great case for resilience investment. The problem with resilience investments is you’re proving a negative. So, until a bad thing happens, you can’t prove that resilience investments had economic benefits. I can do it anecdotally. We really need to work together to find a way to do it quantitatively.”
The Critical Consumer Issues Forum, which includes state regulators, consumer advocates and industry, began an initiative on the resilience issue at NARUC’s annual meeting last November in San Antonio, Texas. It is continuing its work this year with summits in Tampa, Fla. (Feb. 27-28), Denver (March 25-26) and Arlington, Va. (April 30-May 1).
GridEx V Report Previewed
NERC CEO Jim Robb provided regulators with a preview of the after-action report that NERC plans to release next month on last November’s GridEx V. (See GridEx V Throws New Tech Curveball.)
He praised NARUC, the National Governor’s Association and the National Association of State Energy Officials for promoting the event to their members, saying 25 state governments took part, six more than in GridEx IV in 2017. “As we start planning the next installment … we’d like to see those numbers go even higher,” Robb said.
State participants included regulatory commissions, emergency managers, the National Guard, intelligence “fusion centers,” law enforcement and state energy offices.
NERC used a different approach for the tabletop portion of the drill last year.
“Rather than signaling another national or continental crisis, we really focused in on a regional attack. Much to John McAvoy’s — the CEO of Con Ed’s — dismay, we chose New York City, New York state and southern Ontario as the focus of that attack,” Robb explained.
“We felt by limiting it to a regional attack and then really focusing in on the operational issues as opposed to the policy issues that would be required to restore a system, we thought it would be much richer and [produce] more operational lessons learned than previous exercises.”
Robb said the drill provided good lessons on the role of natural gas, which he noted has become “the key fuel for keeping the lights on” in some regions and is “also very key to how you restore the system in a black start scenario.”
“This is an area where state commissions also need to play a role, particularly on the intrastate pipelines and the [local distribution companies] that you all have jurisdiction over. When it comes to the question of prioritizing restoration of electric service, the hard questions around where to send the next molecule of gas is one that at some point you all may have to deal with. And it would be good to practice those decisions and [uncover] the underlying issues in advance of an actual emergency. That will be one of the things we’ll really test in a big way in GridEx VI.”
WASHINGTON — State regulators this week endorsed Institute of Electrical and Electronics Engineers’ updated standard 1547-2018 on the interconnection and interoperability of distributed energy resources.
The National Association of Regulatory Utility Commissioners’ board of directors approved a resolution Wednesday recommending state commissions adopt the standard. The vote came at NARUC’s Winter Policy Summit, where cybersecurity and reliability were the subject of numerous discussions. (See Cybersecurity, Resilience Talks Highlight NARUC Meeting.)
Published in April 2018, IEEE’s standard requires DER to perform grid-support functions for voltage, frequency, communications and controls “to ensure that increasing levels of DERs are reliable at both the distribution and bulk power system levels, and can be visible to grid operators,” NARUC said.
DER equipment compliant with the standard is expected to be available next year.
“Delaying implementation of IEEE 1547-2018 could result in new DERs being connected to the grid using legacy technical requirements and standards that could prevail for the duration of the DER’s lifetime,” NARUC said. “Significant logistical and legal barriers exist to modifying DER interconnection requirements post-installation, such that it is preferable to apply the desired DER configuration at the time of initial DER installation.”
NERC also backed the standard in a draft reliability guideline and the Electric Power Research Institute, National Renewable Energy Laboratory, Regulatory Assistance Project, Interstate Renewable Energy Council and National Rural Electric Cooperative Association have produced resources to help states implementing the standard, which will require integrating it into interconnection tariffs.
During a panel discussion on the standard Sunday, Ryan Quint, NERC’s senior manager of advanced system analytics and modeling, said planners and real-time operators in North America are currently relying on estimates of DER because of a limited information.
“Under low-penetration conditions, it’s a reasonable estimate,” he said. But he added that CAISO is growing increasingly concerned “because it has so much behind-the-meter generation that is not readily visible. Those forecasts are getting a little less solid, and they’re getting faced with new challenges because they don’t have the knobs that they used to be able to turn.
“If they’re already having problems, and they have requirements that every new rooftop [in California] must have a mini solar plant on it that we can’t see and can’t control,” problems will increase, Quint said. “We don’t necessarily need to control those things, but making sure they meet requirements and are tracked, and we know where they are and we can forecast them into the future — those things become really important.
“We’re going to need to change the paradigm of the way we operate the overall grid into the future,” he continued. “In North America, we’re not so sure how we’re going to do that. In Europe, for example, we have distribution system operators that coordinate a lot of this at the distribution level that are running real-time tools like the grid operator is doing.”
WASHINGTON — A panel at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit on Monday on the cybersecurity of natural gas infrastructure waded into the world of insurance.
Brian Finch, a partner with Pillsbury Winthrop Shaw Pittman, provided NARUC’s committees on Telecommunications, Critical Infrastructure and Gas with a stark reminder that it’s a matter of when, not if, a cyberattack on critical infrastructure occurs.
“The Defense Department, the Intelligence Community, the National Security Agency — all of whom spend billions of dollars on an annual basis to implement cybersecurity, have some of the smartest minds in the world working on their problems — have a saying: ‘We’ve learned to live with the adversary on the system.’”
The government expects U.S. enemies to penetrate every major defense and weapons system on a daily basis, Finch said, and there’s nothing it can do to prevent it. So too is it with the country’s energy systems.
“There’s no such thing as the elimination of the cyber risk. We are always, always vulnerable, and no matter what we you’ve done, there will always be another methodology, another way to bring risk and effectuate harm.”
Therefore, Finch argued, regulators should consider liability when crafting their requirements for how utilities manage their risk against cyberattacks.
“Sometimes the presumption is that if there is a successful cyberattack, someone must have failed somewhere,” Finch said. “When something does go wrong, is someone liable? … That’s a challenge that you as commissioners … need to contemplate on a daily basis. Is it really someone’s fault that a successful cyberattack occurred? Or should you be looking at, was it one that was inevitable, and did they recover in a sufficient amount of time? …
“We have to make sure that we’re not unintentionally creating new avenues of liability that would unfairly place the blame on entities who, in reality, could do nothing to stop, say, a foreign military.”
Finch encouraged commissioners to look at the Support Anti-Terrorism by Fostering Effective Technologies (SAFETY) Act, signed into law in 2002 in the aftermath of the Sept. 11 terrorist attacks. Among other provisions, the law provides legal liability protections for providers and users of anti-terrorism technologies that are qualified by the Department of Homeland Security.
He noted that law doesn’t cover penalties administered by state agencies, “but it does minimize the likelihood of civil liability.” Finch’s bio on Pillsbury’s website notes that “he has helped more than 150 clients take advantage of SAFETY Act liability protections following terrorist or cyberattacks.” He said that of the estimated 350 entities that have been given protection, he’s aware of only two that for utility security programs.
Alaska Regulatory Commissioner Robert Pickett brought up the surge in ransomware attacks on municipalities last year, ranging from major cities such as Atlanta and Baltimore, to small towns across the country. Pickett said his own community was attacked, costing it about $4 million to $5 million, but their insurance coverage “was totally different from what the people thought they had.”
That prompted Finch to repeat an anecdote he heard from a friend: “‘If you’ve seen one cyber insurance policy, you’ve seen one.’
“There’s no standardization in the industry. Coverage varies widely depending on who you are, what you have to offer and how much you can pay,” he said.
Finch recalled the NotPetya attack of 2017, the victims of which included food producer Mondelēz. Because the perpetrator of the attack had been determined to be the Russian government, the company’s insurance provider did not cover the damages because it was an act of war.
Kansas Corporation Commissioner Dwight Keen asked to what extent are cyber threats state-sponsored, and which countries posed the most threats. Finch listed North Korea, China, Russia and Iran.
But Finch warned that attribution was almost irrelevant when it came to managing risk. He recalled the story of the Russian hacking group known as Turla. The NSA and the U.K.’s Secret Intelligence Service (MI6) had been tracking what they thought were a group of Iranian hackers for 18 months until they realized that the group was actually Russian: Turla had breached an Iranian hacking group and stolen their code and cyber tools to masquerade as them.
MANHATTAN BEACH, Calif. — NERC and utility operators see considerable benefit from applying digital technologies to the power grid, but adopters must take their vulnerabilities into account as well.
During a panel on digitization at NERC’s Member Representatives Committee meeting on Feb. 5, moderator Sylvain Clermont, director of operational technologies convergence at Hydro-Québec TransÉnergie, said operators are only scratching the surface of the long-term implications of new technologies — both positive and negative. Even at this early stage, the capabilities are too enticing to ignore.
“Most of us have started some kind of digitization of our grid and our facilities, but we are at the beginning of trying to see all the potential of that,” Clermont said. “Now you can access a relay … from any kind of control center. … So we will change the way we do maintenance by having all that data.”
Reward and Risk
However, participants in the panel also raised familiar warnings that bringing in smarter systems can also mean inviting unwanted guests. In the case of new hardware like drones, that could involve backdoors engineered by the manufacturers. Communication software can also contain inadvertent vulnerabilities that can be exploited by a growing list of unscrupulous actors targeting U.S. utilities. (See Report: Oil, Gas Hackers Expanding to Grid.)
Mukund Kaushik, director of digital at Southern California Edison, observed that most utilities are well aware of the risks of introducing new technology into their systems. At the same time, those who want to provide better service to their customers or keep their performance in line with the broader industry may feel they have no choice but to upgrade and address the risks that might arise as they go.
“Most of the innovation that’s happening on the IT side is happening on the cloud,” Kaushik said. “I’m constantly going back and forth [with] my cyber team in terms of how do we make sure we’re not compromising our security, but at the same [time] take advantage of some of the technology that exists out there to move the ball forward.”
Evolving Cybersecurity Threats
The danger of cyberattacks was a major focus of discussion, with Eric Udren, an executive advisor at Quanta Technology, admitting that “the adversaries will always be getting better at this.” However, utilities cannot become so focused on security risks that they fail to adopt new technologies to address a rapidly changing generation environment.
“There are some that would say — from a knee-jerk reaction — ‘Well, because of the cyber exposure of a microprocessor-based relay, let’s go back,’” said Howard Gugel, vice president and director of engineering and standards at NERC. “But there was a reason why we went to microprocessor-based relays. … In the ‘good old days,’ we were flying in the dark a lot of times.”
Gugel pointed out that security is only one challenge posed by integrating digital communication into the grid. Distributed energy resources such as rooftop solar panels and batteries are made possible by such technologies, but they have also been found to cause significant issues with monitoring and planning for grid stability. (See Rooftop PV’s ‘Hidden Loads’ Challenge Grid Planners.)
In light of these emerging concerns, panelists agreed that NERC will need to move quickly to establish standards and procedures to ensure reliability and safety. At the same time, the ERO Enterprise must ensure that entities have the flexibility needed to pursue future innovations.
“In all new reliability standards, we should be thinking not only about what is the problem we’re solving now, but what will the industry be like in 10 or 20 years, and what are we putting in this standard that would not inhibit a direction that we see coming?” Udren said. “By all means, solve the current problem, but look ahead also.”
MISO will sharpen its focus on the northern portion of its footprint with two supplemental studies to be included in its 2020 Transmission Expansion Plan (MTEP 20) cycle.
The RTO has planned special transmission studies for both Michigan and the Minnesota-Wisconsin border, both of which it discussed at the Planning Advisory Committee’s meeting Wednesday.
MTEP 20 will contain a special study into the increasingly tight capacity import and export limits (CILs/CELs) in lower Michigan’s Zone 7. The study is being performed at the request of the Michigan Public Service Commission and will help the state “better understand the effects” of increasing either the CIL or CEL for Zone 7, according to MISO.
Tony Rowan, MISO senior manager of seasonal and generator deliverability, said decisions to move ahead with any projects to increase Zone 7’s CIL and CEL values would be up to transmission owners and the state, not RTO staff. He said the study “will help Michigan to meet it reliability goals and evaluate the potential costs and benefits of increased CILs and CELs.”
Zone 7 has a preliminary 3,200-MW CIL for the 2020/21 planning year, a five-year low. Last year, the zone had a 1,358-MW CEL, down from 2,578 MW in 2018/19. For the 2020/21 planning year, MISO’s analysis could not identify a CEL, officially listing it as “no limit found.”
As requested by the Michigan PSC, MISO will examine 500-, 1,500- and 3,000-MW incremental increases to the Zone 7 CIL. The RTO expects to have results by November.
Zone 7 requirements 2016-2021 | MISO
PSC Commissioner Dan Scripps said that while the commission only requested MISO investigate lower Michigan, Zone 2 (Wisconsin and the Upper Peninsula) and Mississippi’s Zone 10 also have narrow limits that could be ripe for study.
MISO staff late last year said Zones 2 and 7 are the closest to being unable to meet their local clearing requirements based on results from the RTO’s 2019 resource adequacy survey with the Organization of MISO States (OMS). (See MISO Planning Reserve Margin to Climb in 2020.)
WEC Energy Group’s Chris Plante asked whether the PSC’s study request could strain MISO planners, wondering what would happen if several other stakeholders requested one-off studies.
“At what point does this become a burden on MISO’s resources?” he asked.
“We’ll let you know,” MISO Director of Planning Jeff Webb joked, then adding more seriously that the RTO will monitor its ability to accommodate targeted study requests. He said MISO might one day institute “a global import study of all zones.”
“We have a special place in our hearts for state regulators, and when they ask, we try to do our best to accommodate them,” Webb said.
Indiana Utility Regulatory Commission staffer David Johnston also pointed out that OMS rarely exercises its right to request studies from MISO.
Meanwhile, MISO will hold a special meeting at the end of the month on its special analysis of the Minnesota-Wisconsin export (MWEX) interface limitation.
The MWEX transfer limit is the subject of another special MTEP 20 study, dubbed the North Region Economic Transfer Study. MISO said it’s expecting “bottle necks” especially in its North Region, which already contains high wind penetration. (See MWEX Study Could Elicit New Tx Planning for MISO.)
MISO has scheduled a Feb. 28 workshop for a technical discussion of the study’s assumptions and scope.
“Our focus here is to really study how this constraint limits economic dispatch,” MISO Resource Interconnection Planning Manager Neil Shah said.
MTEP 20 Schedule Change
The approval of MTEP 20 will also be held to a different timeline than in previous years.
MISO Project Manager Sandy Boegeman said the RTO will this year revise the schedule to allow the Board of Directors’ System Planning Committee more time to review the MTEP package prior to the full board vote in early December.
That means the PAC will also review, then vote on, whether to recommend the draft MTEP 20 report about a month earlier than usual. MISO plans to post the report on Aug. 19 instead of the usual mid-September. The PAC vote will move up to the committee’s Sept. 23 meeting instead of mid- to late-October.
Finally, the System Planning Committee will decide whether to advance the MTEP 20 report to the full board on Oct. 26 instead of late November.
NYISO can import 505 MW above grandfathered rights from its neighboring control areas for capability year 2020/21, with 332 MW available from ISO-NE and 152 MW from PJM, under the revised installed capacity (ICAP) values approved by the Business Issues Committee on Wednesday. Quebec and Ontario can add another 21 MW.
Including existing transmission capacity for native load, and other grandfathered rights, the ISO’s biggest import sources are PJM (1,232 MW) and Quebec (1,116 MW).
The individual limits allowed under the ISO’s MARS simulations were prorated to ensure they do not violate the loss-of-load expectation criterion. All of the resulting imports were deemed deliverable, said Frank Ciani, of NYISO’s capacity market operations unit.
NYISO can import 505 MW above grandfathered rights from its neighboring control areas for capability year 2020/21, with 332 MW available from ISO-NE and 152 MW from PJM. The grandfathered rights include existing transmission capacity for native load. | NYISO
The analysis excluded interface facilities with unforced capacity deliverability rights, controllable lines from PJM into the New York Control Area and the Northeast Utilities Service Co. 1385 line.
The BIC approved a motion to update Section 4.9.6 of the Installed Capacity Manual to reflect the results without opposition or discussion during the brief meeting.
The revised limits represent an increase of 62 MW over 2019/20, with PJM’s limit increased by 120 MW and Ontario’s reduced by 113 MW. The summer capability period strip auction opens March 30.
Transmission Congestion Contracts
In its only other action, the BIC approved revisions to the Transmission Congestion Contracts Manual, which was last updated in 2017.
The revisions add the historic fixed-price transmission congestion contracts extension product and incorporate technical bulletins on the PJM-NYISO interconnection scheduling protocol and modeling of the Rainey and Blissville phase-angle regulators.
The cost estimation guide for MISO’s 2020 transmission planning cycle will for the first time include upfront and long-term cost estimates for HVDC lines.
MISO circulated the draft guide for the 2020 MISO Transmission Expansion Plan (MTEP 20) at the Planning Subcommittee’s meeting Tuesday. The guide is used to evaluate alternatives to some of the proposed projects in the plan.
The RTO is proposing that the new guide increase the costs of lines, substation equipment, breakers and transformers across all voltage classes. Costs of land clearing are similarly set to rise, and costs for the land itself will go up almost across the board.
This year, MISO is also adding cost estimates for HVDC lines and their converter stations, Principal Transmission Design Engineer Devang Joshi said.
All project cost estimates include a 20% contingency cost adder and an additional 7.5% allowance for funds used during construction.
MISO is requesting stakeholder reactions to the cost estimation guide by March 13. It plans to post a final version to its website by June 23.
Extreme Event Results in
MISO’s recently completed an extreme events analysis for MTEP 19 finds the West planning region — Minnesota, Iowa, parts of the Dakotas and western Wisconsin — contains the highest potential for cascading failures on the transmission system.
However, reliability planners said only a few events show cascading failures out of the thousands of extreme events tested.
MTEP 19 extreme event study results | MISO
The annual analysis was performed with two-, five- and 10-year models using contingencies submitted by transmission owners and developed by MISO. Simulated events included single instances and combinations of substation, generation and transmission losses and natural gas pipeline outages.
MISO expansion planner Fatou Thiam said paired element outages on the system present the most common cause of hypothetical cascading in nearly the entire RTO. However, common right-of-way circuit outages are the most prevalent cause in lower Michigan.
After completing the analysis, MISO works with its TOs to pinpoint actions that would minimize the risk or severity of cascading failures. The extreme events study is meant to give TOs a better understanding of the effects of various low-frequency, high-impact events.
MISO is now in the process of compiling extreme event contingencies as part of its MTEP 20 reliability assessment. Additionally, the RTO is asking stakeholders how it might improve its process of developing and evaluating extreme events. Stakeholders are asked to respond in writing by Feb. 28.
The countdown is on for Pacific Gas and Electric’s exit from bankruptcy, which all parties agree needs to happen by the end of June so the utility can participate in a state insurance fund to protect it from future wildfire liabilities, a key to its financial stability.
Lawyers for PG&E and its creditors, together with U.S. Bankruptcy Judge Dennis Montali in San Francisco, are trying to keep things moving toward that goal. Yet significant hurdles remain before PG&E — which the U.S. Energy Information Administration calls the nation’s largest electric utility, with nearly 5.5 million customer accounts — can free itself from legal entanglements and political threats.
The repeated insistence by Gov. Gavin Newsom that PG&E must undergo a fundamental shift in its leadership and safety culture or face a state takeover recently was joined by a legislative proposal that would create a mechanism to seize the company from its shareholders. (See PG&E Tries to Appease Governor with New Plan.)
Another threat has arisen recently from wildfire victims who don’t want the federal and state governments taking nearly $4 billion from a $13.5 billion fire victims’ trust promised by PG&E. The 70,000-plus victims of utility-sparked wildfires in 2015, 2017 and 2018 must ultimately vote on PG&E’s proposed reorganization plan.
And the California Public Utilities Commission, led by Newsom appointee Marybel Batjer, must approve any restructuring plan, including under the auspices of Assembly Bill 1054, the measure that created the wildfire insurance fund last year.
PG&E has to overcome those hurdles and more in the next four-and-a-half months. Here’s a look at this spring’s agenda and possible hurdles.
Fire Victims Object
PG&E filed its proposed disclosure statement Feb. 7, an important step in its Chapter 11 reorganization. The document is intended to lay out in relatively plain language the terms of the utility’s restructuring so that fire victims and others can weigh the plan and eventually vote on it.
In particular, the document describes the creation of the $13.5 billion trust, funded half in cash and half in PG&E common stock. The expectation is that the stock will be liquidated over time to provide money to pay claims.
Smoke from the Camp Fire in Paradise, Calif., filled the sky above the nearby town of Chico on Nov. 8, 2018, when 86 people died in a matter of hours.
Some victims don’t like the stock component. They’ve told their lawyers and Montali they worry the stock could decline in value if PG&E experiences financial setbacks after bankruptcy. Some fire victims wrongly believe they will be given stock directly in lieu of a check, the judge and lawyers said at PG&E’s latest bankruptcy hearing on Tuesday.
That’s why the disclosure statement says in bold letters, “No Fire Victim will receive stock of Reorganized PG&E Corp. directly.”
A more serious problem, however, is that federal and state agencies, including the Federal Emergency Management Agency and the California Office of Emergency Services, say they will seek recovery of their wildfire claims, totaling as much as $3.9 billion, from the victims’ trust.
The case’s official Tort Claimants Committee, PG&E and others have objected to that outcome, which could unravel PG&E’s reorganization plan. They say the government agencies must pursue other means of compensation under the law.
Montali tried to reassure fire victims that highly experienced lawyers were addressing the matter.
“They are issues that are being dealt with by principal players,” Montali said at Tuesday’s hearing, in response to objections from one fire victim, Will Abrams, who has appeared in person at the bankruptcy court to voice his criticisms of PG&E’s restructuring plan.
A hearing on the government agency claims is scheduled for Feb. 26, and a hearing on the proposed disclosure statement is planned for March 10.
Montali noted that other individual victims have been writing to him, expressing their concerns.
“Please hold PG&E fully accountable,” Tina Rezler, a survivor of the November 2018 Camp Fire, wrote to the judge earlier this month. “The current amount set aside isn’t enough. Please do not allow FEMA, insurance companies or any other organization to take funds set aside for survivors that the funds are intended for.”
Rezler said she lost her home and dog in the fire, which tore through the town of Paradise in a few hours early on a Thursday morning, killing 86 residents and destroying more than 18,800 homes and businesses.
The other large, deadly fires that PG&E plans to pay victims for are the Butte Fire in September 2015 and the North Bay or wine country fires of October 2017. The latter fires in Napa and Sonoma counties included the Tubbs Fire, which killed 22 residents and burned down a residential neighborhood in Santa Rosa, Calif.
In all, more than 70,000 fire victims have filed claims, attorneys said. Once the court adopts PG&E’s disclosure statement, the victims will have the opportunity to comment and vote on the plan. PG&E has to mail out the disclosure statements and ballots by March 31, and ballots have to be returned to the court by May 15.
“We are weeks away from my being asked to approve a disclosure statement and supporting documents that will be designed to explain to them — every one of them, if they are inclined to read it — what should influence their decision,” Montali told Abrams. “You and all 70,000 fire survivors have the right to vote the plan down if you choose to. That’s the way the system was designed.”
Governor Objects, Too
Another major obstacle to PG&E’s hopes of exiting bankruptcy by June lies with Newsom, who has said on a number of occasions that he will seek a state takeover of PG&E if the utility doesn’t meet his list of demands, such as an entirely new board of directors and a mechanism for the state to quickly assume control of the company if circumstances warrant.
Recently, state Sen. Scott Wiener (D-San Francisco) introduced a bill, SB 917, that would allow a state-created public-benefit corporation to acquire a utility through eminent domain, moving its assets to a proposed new entity called the Northern California Energy Utility District.
The bill doesn’t specifically mention PG&E, but Wiener made clear his intentions at a Feb. 3 news conference, saying his bill would “put an end to the dangerous roller-coaster ride that we have been on with PG&E over the past decade,” the San Francisco Chronicle reported.
The Camp Fire destroyed 18,804 structures in and around Paradise, Calif., in November 2018.
Another of the governor’s primary concerns is the tens of billions of dollars in new shares and bonds PG&E would issue to pay for its restructuring plan. Newsom has said an over-leveraged PG&E would be unable to pay for the estimated $40 billion to $50 billion it needs to upgrade and harden its aging infrastructure, the source of catastrophic wildfires and the San Bruno gas pipeline explosion of 2010.
On Tuesday, Newsom’s lawyers told Montali they wanted to question witnesses about PG&E’s plan, which could happen on Feb. 19, Feb. 26 or in sworn depositions, attorneys said.
While Newsom has no authority over Montali, the judge is taking the governor’s objections seriously because Newsom could have significant influence on the proceedings.
The California Public Utilities Commission, whose members the governor appoints, has responsibility for approving PG&E’s Chapter 11 plan under the commission’s order instituting investigation (OII) and under AB 1054. The measure, championed by Newsom and quickly passed in July, would give PG&E access to a $21 billion wildfire insurance fund, paid for equally by ratepayers and the state’s big three investor-owned utilities.
The bill requires PG&E to exit bankruptcy by June 30 to participate in the fund. The utility also must compensate victims of past fires ignited by its equipment and demonstrate that its post-bankruptcy governance structure is acceptable “in light of the utility’s safety history, criminal probation, recent financial condition and other factors deemed relevant by the CPUC.”
PG&E was convicted in 2016 of six felonies related to the San Bruno pipeline explosion.
Without the AB 1054 funds to protect it from future liabilities, PG&E’s financial future could be in jeopardy and its bankruptcy plan could fall to pieces.
The CPUC is scheduled to gather evidence in its PG&E investigation during hearings from Feb. 25 to March 4 at its San Francisco headquarters.
