NERC announced Tuesday that the Board of Trustees has promoted Sonia Mendonca to senior vice president, general counsel and corporate secretary following a nationwide search.
Mendonca, who joined NERC in 2011, had been serving in an interim capacity since the retirement of former General Counsel Charles Berardesco in September.
Before Berardesco’s departure, Mendonca was vice president, deputy general counsel and director of enforcement, responsible for corporate governance, legal compliance, regulatory activities and oversight of the Compliance Monitoring and Enforcement Program for the ERO Enterprise.
She also served as NERC’s acting general counsel from November 2017 to April 2018, when Berardesco filled in as acting CEO after the resignation of Gerry Cauley and before the appointment of Jim Robb.
In her new role, she will be chief legal adviser to Robb, the board, staff and stakeholders.
“During her eight years at NERC, she has been instrumental in streamlining our enforcement process to make it more effective and efficient, among countless other initiatives,” Robb said in a statement. “Sonia’s dedication to the mission of the ERO Enterprise over the years made her a top candidate for this important job. I know she will continue to excel.”
Mendonca is a graduate of the Federal University of Rio de Janeiro Law School and the American University Washington College of Law.
The California Public Utilities Commission opened an investigation Wednesday into the massive power shutoffs that placed millions of residents in the dark several times in October as part of efforts to prevent utility-sparked wildfires.
The purpose of the inquiry is to determine “whether California’s investor-owned utilities prioritized safety and complied with the Commission’s regulations and requirements with respect to their late 2019 Public Safety Power Shutoff [PSPS] event,” according to the order instituting investigation (OII).
“It is important for the CPUC to determine if the utilities complied with using public safety power shutoffs as a last resort and to collect the knowledge gained towards any revisions needed for next year,” Commissioner Genevieve Shiroma said. “It is essential our protocols and the utilities’ practices provide the best service and protections for customers in the face of wildfires.”
The state Public Utilities Code has given utilities authority for more than a decade to intentionally blackout parts of their grids to protect public safety, particularly in the dry windy conditions each fall that have given rise to the state’s most devastating wildfires. But the immense scope of this season’s blackouts far exceeded anything that’s occurred before.
PG&E shut off power to 729,000 residential and business customer accounts over three days starting Oct. 9, the PUC said. It turned off electricity to 975,000 customers in 38 counties Oct. 26. And it shut down power to nearly 516,000 customers three days later on Oct. 29.
The average household size in California is about 2.6 residents per home, according to the U.S. Census Bureau, meaning the blackouts may have affected approximately 1.6 million residents, 2.15 million residents and 1.14 million residents, respectively, after accounting for the roughly 15 percent of PG&E customers that are commercial or industrial users.
Southern California Edison and San Diego Gas and Electric also blacked out customers but not on the scale of PG&E. SCE’s largest shutoff occurred Oct. 30, affecting 86,000 customers, while SDG&E blacked out 24,600 customers on Oct. 29.
The CPUC first wants to know if the IOUs adequately notified the public, communicated with first responders and protected public safety during the blackouts, among other questions.
“In later phases of this proceeding, the Commission may consider taking action if it finds violations of statutes or its decisions or general orders have been committed and to enforce compliance, if necessary,” the CPUC order said.
The CPUC’s Safety and Enforcement Division will conduct the investigation in conjunction with outside consultants, it said. The IOUs must file initial responses to the OII by Dec. 13.
The investigation will examine whether regulations governing power safety shutoffs could be improved, the order said.
“The Commission opens this investigation as a companion to Rulemaking (R.) 18-12-005, the Commission’s rulemaking to examine utility de-energization of powerlines in dangerous condition,” it said. “This investigation will serve as a forum for taking evidence to evaluate both the effectiveness and impacts of all phases of the PSPS events.”
‘Where is Safety?’
Public speakers Wednesday said the shutoffs have upended their lives, leaving them fearful and uncertain.
Will Abrams and his family lost their Sonoma County home in the Tubbs Fire of October 2017, running for their lives as their neighborhood burned down around them. The fire leveled parts of Santa Rosa, Calif., and surrounding communities, killing 22 people and destroying more than 5,600 structures.
The Abrams family had to leave their home during one of the first two PG&E power shutoffs in October, then had to evacuate again as the Kincade Fire swept through Sonoma County during a subsequent PSPS event later in the month.
Like many others, they didn’t know where to go to protect themselves. As they drove south through the San Francisco Bay Area, they saw wildfires along the freeways, and Abrams said he wasn’t sure how far to drive before his family would be out of danger.
“I think many folks in California are wondering ‘where is safety?’” Abrams told the commissioners.
“Many Californians are debating about whether California is still safe,” he added, saying the state is on the front lines of climate change. “Is this a safe place to live?”
Nevada City Mayor Reinette Senum laid out the “laundry list” of impacts PG&E’s shutoffs had on her Sierra Foothills town, including the closure of “mom and pop” businesses, grocery stores and schools, the loss of internet, cell phone and 911 service, and the disruption to tourism.
“Basically, we were sent back into the Dark Ages,” she said.
Senum cautioned the commissioners about the downstream “unintended consequences” of upending the local economy in her region, which is vital to supporting environmental efforts that protect the San Francisco Bay Area’s watershed from the toxic legacy of goldmining.
A catastrophic fire like the one that devastated Paradise, Calif., in November 2018 would scorch the soil in the region and release heavy metals that could leach into the water supply for 25 million end users, including farmers and ranchers in California’s Central Valley and wine country growers, she warned.
Senum advocated for a public takeover of PG&E to put the grid “back in the hands of the people.”
“We have everything to lose and we have everything to gain,” Senum said. “We will take better care of the transmission lines and make sure to decentralize the energy production so that it’s as safe as possible and as reliable as possible.”
She said continued shutoffs mean “we will cease to exist as a community.”
“And the CPUC and PG&E, and all the citizens of California, are going to lose the best stewards of your watershed.”
CARMEL, Ind. — MISO is revising how it handles generator interconnections along its seams with neighboring balancing areas in a bid to satisfy several recent FERC mandates.
FERC issued the directives to MISO, PJM and SPP in September after finding that their joint operating agreements lack transparency around how they manage their affected-system impact studies. The commission ordered study procedures must contain:
Easily referenced business practice manuals;
Descriptions of modeling standards;
Clearer modeling details for interconnection customers;
A description of how MISO and SPP study the impacts on each other;
Descriptions of how the three RTOs monitor each other’s systems during the course of each of their interconnection studies.
Compliance filings are due from the RTOs by Feb. 3.
FERC’s directives were the product of 18 months of examination after EDF Renewable Energy complained about the RTOs’ affected-system coordination. (See Affected-system Rules Unclear, FERC Says.)
At a Nov. 12 meeting of the Interconnection Process Working Group (IPWG), resource interconnection engineer Sumit Mundade said the RTO’s interconnection staff have worked up “preliminary language” in JOAs with both PJM and SPP to comply with all six directives. MISO has set aside time through January to continue revising its JOAs, he said.
MISO seams | MISO
Mundade said MISO and SPP won’t be able comply with FERC’s requirement that they set specific dates to exchange affected-system information and study results and instead proposed they use “formula dates” based on the start of the studies and include deadlines for data exchanges.
“With MISO and now SPP’s adoption of a three-phase group study process, fixed calendar dates are not optimal because kick-off dates are not fixed in advance,” Mundade explained.
MISO will also add JOA language to clarify MISO’s study criteria only apply to its facilities.
“FERC wanted to know whose criteria applies to which facilities,” Mundade said. “SPP study criteria apply to SPP facilities, and MISO criteria apply to MISO facilities.”
MISO is also proposing to apply its external resource interconnection service study criteria when it studies SPP and PJM interconnection projects, rather using its network resource interconnection service criteria.
“FERC only asked us to describe this, not change anything,” Mundade said.
MISO still faces the task of explaining how it monitors neighboring transmission systems for impacts during interconnection studies. Mundade said while monitoring will include “an identification of MISO projects with potential impacts to the SPP or PJM transmission system based on each RTO’s criteria,” those JOA revisions are still in the works.
MISO has also not yet decided how it will detail the process used to determine projects’ queue priority in an affected-system analysis and how it will allocate the costs of network upgrades required on an affected system.
“The proposed language is under development,” Mundade said, promising to return to the January IPWG with more specifics.
In addition to the two compliance filings, MISO plans to make two separate filings to change some aspects of the JOAs with SPP and PJM.
Pending approval from its neighbors, MISO will add separate JOA language requiring MISO and SPP to share cost estimates and construction schedules of network upgrades and to synchronize information-sharing with PJM so studies line up more closely with PJM’s interconnection timeline.
The additional filings will also make clearer that interconnection customers bear the costs of the affected-systems studies. Mundade said the separate JOA filings contain affected-system changes not required by FERC but represent improvements nonetheless.
NERC opened a final ballot Wednesday on a proposal requiring entities that fail to meet performance requirements for “supplemental” geomagnetic disturbances (GMD) to develop corrective action plans (CAP) to minimize their vulnerability.
Voting will be open until 8 p.m. E.T. Nov. 22 on reliability standard TPL-007-4 (Transmission System Planned Performance for Geomagnetic Disturbance Events), which was prompted by FERC Order 851. In addition to requiring CAPs, FERC ordered NERC to authorize extensions of CAP deadlines on a case-by-case basis. (See Revised NERC GMD Standard Approved.)
GMDs, which occur when charged particles ejected from the sun cause changes in Earth’s magnetic fields, can cause voltage instability or collapse, damaging electrical equipment.
NERC’s original GMD standard required applicable entities to assess the vulnerability of their transmission systems to a “benchmark” GMD event, defined as a one-in-100-year event that would cause an 8-V/km “reference peak geoelectric field amplitude” at 60 degrees north geomagnetic latitude using Quebec’s ground conductivity. The standard applies to planning coordinators, transmission planners, transmission owners and generation owners connected at 200 kV or higher.
“Supplemental” GMD events refer to localized “spikes” of intense and damaging magnetic fields that can be created during an event that appears less severe based on spatially averaged measurements over a large area.
The standard opened for comment is virtually identical to the draft that received a 71% affirmative vote, clearing the 67% threshold, in a 45-day ballot period that closed Sept. 9. Organizations that voted in that round will see their votes carried over to the final ballot unless they choose otherwise.
The only change since the initial ballot is language specifying the “Compliance Enforcement Authority” (CEA) — NERC or the regional entity in the U.S. and any entity designated by Canadian officials — will handle requests for extensions. The original version said extensions would be subject to the “ERO.”
TPL-007-4 was created by an 11-member standard drafting team with input from industry and compliance leadership from each regional entity.
Deadlines
The standard requires completion of a CAP within a year after completion of a supplemental GMD vulnerability assessment that concludes the entity does not meet performance requirements. It lists as potential corrective measures the installation, modification or removal of transmission or generation facilities; operating procedures, protection systems or remedial action schemes and demand-side management. Hardware mitigation must be completed within four years after completion of the CAP, with non-hardware measures due within two years.
Under NERC’s CAP Extension Request Review Process, extension requests must be submitted no later than 60 days before the completion date specified in the CAP. The CEA is to convey its decision within 45 days after that.
Extensions will be granted only when implementation has been prevented for reasons outside the control of the responsible entity, such as delays resulting from permitting, equipment lead times or stakeholder processes required by tariff.
“If it was due to a lapse of planning properly or missing a date inadvertently, that’s not beyond the control of the responsible entity,” Steven Noess, NERC director of regulatory programs, said during a webinar Tuesday. “But there might be delays that are [due to] permitting, regulatory processes … [changes in] tariffs or lead times … specific equipment, right of way questions, things of that nature, [and we] certainly want to make it easy for folks to identify them.”
Flexibility Assured
In addition to clarifying the extension process, the standard drafting team also attempted to address industry questions about the level of rigidity in the Implementation Guidance for TPL-007-4 regarding specific mitigation measures. Several of the commenters on the first ballot asked for reassurance the revisions would permit utilities the flexibility to devise their own strategies.
PJM’s Emanuel Bernabeu, who chaired the standard drafting team, emphasized the recommendations in the implementation guidelines are for guidance only. While the team wanted to provide an example of a workable solution, any measure that achieves the goal and is in line with the current scientific understanding may be approved.
“Substantively [it] is the same information we had before, [but] we’ve tried to clarify the language so it’s absolutely clear that this is only [one] acceptable approach, and there are actually other approaches [to] the supplemental events that would be valued,” said Bernabeu.
The NERC Board of Trustees is expected to approve the standard in February 2020.
WASHINGTON — The limits of grid exercises and simulation tools and the need to prepare for a successful cyberattack were recurrent themes at the National Academies’ Committee on the Future of Electric Power in the U.S. daylong conference on computing, communications and cyber resilience.
Observations from the Nov. 1 conference — which featured officials from FERC, NERC, the Department of Homeland Security and Department of Energy — will be in a report by the committee to Congress and DOE, scheduled for release in Fall 2020.
The project was ordered by Congress as part of the 2018 DOE appropriations bill. It directed the National Academies of Science, Engineering, and Medicine to appoint an ad hoc committee of experts to “conduct an evaluation of the expected medium- and long-term evolution of the grid [with a] focus on developments that include the emergence of new technologies, planning and operating techniques, grid architecture, and business models.”
Committee Chair Granger Morgan, professor of engineering at Carnegie Mellon University, asked panelists what recommendations they would like to see in the upcoming report.
“If no one else is jumping on the grenade, I will,” said Scott Aaronson, executive director of security and business continuity for the Edison Electric Institute. “I will continue to beat the drum of resilience.”
Aaronson, part of a panel on moving from a culture of compliance to one of security, decried what he called the “Whack-a-Mole” approach to grid threats, saying the industry should set a goal of “consequence management” that takes advantage of the grid’s inherent redundancy and resilience. Whether it’s “EMP or GMD or cyber or physical or storms or zombies, there’s always going to be a new threat,” he said.
He cited the 2013 sniper attack on Pacific Gas & Electric’s Metcalf substation, in which 17 transformers were damaged at a cost of $15 million. “You know what was cool about that? The lights didn’t blink in San Francisco or Silicon Valley. Why? Because of redundancy.”
“NAS could provide some leadership about how we engineer — on top of this extraordinary machine — more resilient capabilities,” Aaronson said.
Morgan noted the Academies did a report on the resilience of the transmission and distribution system in 2017. What’s new to say? he asked.
Joe McClelland, director of FERC’s Office of Energy Infrastructure Security, suggested the academies could “narrow the focus” to identify what capabilities are required to ensure the continuity of mission critical functions.
“Is it skeletal service, to say, large urban areas? Is it off-site power to a nuclear power plant? There are not very many facilities, but what is the model for a sustainable power source for these facilities — self-sufficient and sustainable — that could dissuade a potential attack by a sophisticated adversary?”
Sobering Reading
McClelland gave his panelists a homework assignment: the February 2017 report of the Defense Science Board Task Force on Cyber Deterrence.
The report concluded Russia and China “have a significant and growing ability to hold U.S. critical infrastructure at risk via cyber attack, and an increasing potential to also use cyber to thwart U.S. military responses to any such attacks.
“This emerging situation threatens to place the United States in an untenable strategic position,” the report continued. “Although progress is being made to reduce the pervasive cyber vulnerabilities of U.S. critical infrastructure, the unfortunate reality is that for at least the next decade, the offensive cyber capabilities of our most capable adversaries are likely to far exceed the United States’ ability to defend key critical infrastructures. The U.S. military itself has a deep and extensive dependence on information technology as well, creating a massive attack surface.”
“That’s sobering,” said McClelland.
The report also called for “additional cost recovery mechanisms” so critical infrastructure owners can invest in resilience that supports U.S. military capabilities.
Vendors’ Roles, Responsibilities
Brian Harrell, assistant director of DHS’s Cybersecurity and Infrastructure Security Agency (CISA), said technology vendors are “part of the solution” and should not be shunned from industry cyber discussions for fear “they just want to sell us a bunch of stuff.”
“I think this industry … is a little apprehensive to bring vendors into the conversation,” he said. “I will say in your time of need, when things go bump in the night, you will be reaching out to your vendor. And so, let’s ensure the vendors are part of the conversation. … We need to build security in from the beginning and not bolt it onto the rear because that is expanding the threat exposure for us.”
Electric Power Research Institute (EPRI) CEO Michael Howard questioned whether software vendors should be held liable for security vulnerabilities in their products.
“In the rush to market with many products, designers will use software languages like C++ with many known vulnerabilities. They will copy sub-routines that also have many known vulnerabilities,” he said. “Should there be regulation so that if these vulnerabilities are then sold and [this] results in a breach — because all the bad actors know what these vulnerabilities are, and they can be prevented with some of the latest software languages — should there be regulation that says if you do this and you rush to market that you will be liable for that?”
In 2016, Taiwan-based Asus agreed to independent audits for 20 years to settle a Federal Trade Commission complaint over a security flaw that allowed hackers to take control of almost 13,000 home routers. Although Asus claimed the routers would “protect computers from any unauthorized access, hacking and virus attacks,” the FTC said it found a “pervasive security bug” in the router would allow an attacker to disable security settings remotely.
Johns Hopkins University computer science professor Yair Amir responded with a cautionary note. “In the cloud domain, there’s a lot of very good use of open source [software] … It’s very effective. If you regulate against it, maybe we lose something.”
Morgan said although Howard was referring to software sold to utilities, “I think the problem exists in spades in the IoT [Internet of Things] space.”
“I don’t even know who would play the role [of regulator],” he said, dismissing the Consumer Product Safety Commission. “They’re totally ineffectual in a lot of other places. They’re not going to be out front, cutting edge, on this,” he said.
“There are several layers of equipment we’re talking about and not all of them are covered by the same regulations,” noted Washington State University Professor in Power Anjan Bose. While relays on the bulk power system are covered by critical infrastructure protection (CIP) standards, “once you start going down the chain into the distribution system … I’m not sure the CIP compliance covers anything, especially if it’s on the other side of the meter.”
“It’s the grid edge things that are now having to send a lot of data into the control center,” he added. “So … the threat surface is increasing.”
The National Institute of Standards and Technology’s (NIST) Information Technology Laboratory recently took comments on a draft discussion paper seeking feedback to identify core cybersecurity capabilities important for IoT devices.
Kevin Stine, chief of the lab’s Applied Cybersecurity division, said feedback was “overall very positive. We hope to move forward with baseline recommendations in the next quarter or so.”
Eliminate Financial Penalties?
Marc Child, chair of the NERC Critical Infrastructure Protection Committee, said he’d like to see an end to the constant churn of standards development.
“I want my [computer science] engineers back,” said Child, information security program manager for Great River Energy. “They have been distracted by spreadsheet land for a decade. I need them working on cutting-edge technology. I want them to go out and buy effective technology, not compliant technology — there is a big difference.
I want them looking at software-defined networks. I want them looking at decoy networks.”
Child said the CIP standards are “a good baseline that covers 75% of the problem. It will raise all of our boats. But I’d like to challenge them to cap the efforts. Any new threats are going to be incremental and could be addressed outside of mandatory standards. I’m going to say something controversial here … I would like to propose we reduce or remove the financial penalties associated with noncompliance. We need a culture of cooperation, and in so doing, we can change the auditor and utility dynamic to one of a shared mission. I want the auditor … on my side of the table.”
Pondering Manual Operations
EEI’s Aaronson said the industry must be prepared for “the inevitability of impact” because “standards simply can’t keep up” with new threats.
He noted grid operators in Ukraine resorted to manual operations to restore power after suspected Russian hackers took remote control of utilities’ SCADA system and cut off service to about 220,000 customers for a few hours in 2016. (See How a ‘Phantom Mouse’ and Weaponized Excel Files Brought Down Ukraine’s Grid.)
“Do we have that capability here in North America? Sort of,” he said. “And that’s not a good answer for chief executives. So, we are beginning to develop the capacity for supplemental operating strategies. I like to call it the MacGyver project. How do we hold the grid together with bubble gum and duct tape?”
“I think the audit regime, and I think [FERC] and state commissions … are starting to realize [the limitations of] check-the-box exercise[s]. ‘Alright, I’ll do x, y and z — I’m secure.’ No, you telegraphed your defenses and you’re complacent,” he said. “… We’re not going to get there overnight, but I think the tide has shifted just a bit to acknowledge the limitations of explicit … binary standards we see today.”
He called for efforts like the Spare Transformer Equipment Program (STEP) and the nuclear industry’s Pooled Inventory Management system (PIM). “What can the electric industry do to mimic that [database] of assets we might need when a bad day comes?” he asked.
David Batz, EEI’s senior director of cyber and infrastructure security, also cited STEP as an example of the efforts industry should pursue. “Let’s broaden the aperture and think about where else within our critical infrastructure we can invest toward resilience and not in all cases drive toward the lowest cost,” he said.
Morgan said guaranteed cost recovery may be needed to fund utilities’ defenses. “Some of the other things that are going to be required if we’re going to address this nation state threat are going to be harder to do and not that cheap,” Morgan said. “The flip side is if I start, as the federal government, providing various cash incentives or other ways to finance stuff, there’s going to be a temptation to gold plate.”
Government Duplicating Private Sector Efforts?
Robert M. Lee, founder of Dragos, said the partnership between government and the private sector is not as effective as it could be.
“I think that we often times publicly spend a lot of time on complimenting each other versus saying, ‘Well, actually this doesn’t work and here are the things that are a waste of time.’ When I look at DHS and DOE, as an example, I see a lot of opportunity. I see a lot of really wonderful people and I see the ability for them to have a significant role in things like amplification, prioritization, helping with … government resources during a time of crisis,” he said.
“But then I see other efforts like, ‘Oh, yeah, let’s go build an incident response team.’ Why? We actually have all of that in the private sector. Why are we spending time and taxpayer money on that? My recommendation is cut out the stuff that we have helped the private sector get really good at and let’s be proud of that momentum and let’s focus on the things like supply chain that actually the private sector shouldn’t take on and that there’s a very significant government role in.”
When corporate boards ask him how to know if they are underspending or overspending on security, Lee said he tells them to meet their regulatory requirements and prepare for known scenarios, such as Ukraine 2015, Ukraine 2016 and ransomware.
“If you prepare for those and then Russia gets crafty and [does] something extra, it happens,” he said. “Your response strategy — that’s your design basis. And everything else above that: invest if you’d like. It’s risk reduction, but there’s no right answer. … If you didn’t prepare for those and you get attacked with the 2015 Ukraine [strategy], you should be in jail. Because it’s an absolute travesty that your community didn’t prepare.”
Unintended Consequences?
Jeff Dagle, chief electrical engineer for electricity infrastructure resilience at the Pacific Northwest National Laboratory (PNNL), said CIP standards have dissuaded some utilities from deploying synchrophasors that can provide situational awareness.
“If an operator can use that data and make a decision within 15 minutes, it is required to be compliant to the NERC cybersecurity requirements,” he said. “There are utilities that are choosing not to deploy technology that’s readily available … because of the … regulatory risk. … If your auditor doesn’t like the way you’ve set it up – bam!”
“And reliability coordinators are having trouble getting this data from the transmission operators because this handoff” is subject to CIP rules, he added. “These … aren’t critical things that somebody could hack in and shut down the grid. This is supplemental information to the operators for better situational awareness to make better decisions. We don’t [require] CIP compliance on some of the other things in the control room. There’s a weather map they can look at and see the thunderstorms coming across their service territory. We don’t require the Weather Channel to be CIP compliant. I suspect this same comment applies to other nascent technologies [and is] slowing innovation,” he added.
FERC’s McClelland noted standards are open to comment at any time. “So, if a standard [or] a requirement is in the way, of security or … reliability, then my expectation is that industry will petition [to change] that requirement.”
McClelland also suggested synchrophasors could be of interest to hackers.
“If you’re saying that … the synchrophasor technology makes [it possible to] react in 15 minutes and that that would be a needed function on the grid, as an adversary, I’m now targeting synchrophasors. … Adversaries are intelligent.”
“If we know adversaries are mapping the power system, you can doggone well bet they’re using electrical engineers to identify critical locations and they’re looking at specific equipment that’s become … absolutely necessary to operate these networks and systems.”
Boundaries Blurring
“The boundaries between utilities and national security are blurring,” said Caitlin Durkovich, director at Toffler Associates, the strategic advisory firm founded by “Future Shock” author Alvin Toffler. “I believe the security and resilience of our country is becoming more intertwined with critical infrastructure than ever before.”
Durkovich, former DHS assistant secretary for infrastructure protection, called for a strategy for an “integrated and resilient modern infrastructure.”
“I think you need a central coordinating body that is different than the post-WWII structure we have today, that is responsible for advancing a modern infrastructure.”
“We have to increasingly focus on this concept of foreign interference and the ability of our adversaries to meddle just enough and not get a kinetic response. We have to rethink what that means given how far they’ll go and what their capabilities are.”
Paul Stockton, managing director of Sonecon, said he expects any attack by the likes of China to be more than just an annoyance. He cited the Worldwide Threat Assessment finding that China could disrupt gas pipelines for days or weeks.
“China is not going to attack a single pipeline. If they’re going to roll the dice and do something that exposes them to such extraordinary risks of U.S. response, they’re going to go whole hog. They’re going to take down as much gas flow as they can to totally disrupt the generation of power to achieve their national security and political goals,” he said. “So, we need to think about this … indirect way of jeopardizing grid reliability in the context of a modernizing grid. Because gas is going to be with us for at least the near- to mid-term and maybe longer.”
“Let’s get going on that because right now owners and operators are left to figure it out for themselves, as are RTOs and ISOs. So, let’s agree on what the threat [is] … . It exists in the classified level. Let’s get something unclassified.”
Stockton said generators in the cranking path for black start plans are also likely to be targeted. “We never really think to test black start in a realistic way because you’d have to have a blackout,” he noted.
In the past, the assumption has been grid operators can import power from outside the blackout footprint to start the cranking path. “Not anymore,” Stockton said. “It is likely — in fact we should expect — Russia and China would like to achieve interconnection-wide blackout or maybe even nationwide. And black start is going to be absolutely vital under those circumstances in a way that just wasn’t true when you think of a New Madrid scenario, as horrible as it would be,” a reference to a worst-case earthquake originating in southeast Missouri.
“The bad guys know that. … They will intentionally target black start assets, cranking paths, generation units, communications — everything they possibly can.”
Limits to Exercises
“I think exercises are getting better,” said Stockton, who is a GridEx facilitator. “But I think they need to focus on this holistic challenge of interdependent infrastructure. That brings the different tribes together. … the tribe of the transmission operators, substation operators, together with cybersecurity personnel. Because they don’t usually kiss on the lips, do they?”
“We don’t have the tools to adequately understand the interactions of these multi systems like gas with electric,” said EPRI’s Howard. “We talk about it. At a high level, we understand it. But it’s the interactions — we don’t have the simulation tools to be able to do a good job with that.”
In addition to participating in national exercises such as GridEx, Harrell said utilities should conduct their own exercises with regularity “to ingrain it into the culture” and ensure familiarity with their response plans.
“I don’t know we do that enough outside of, ‘We have to do this once a year because CIP compliance says we must,’” he said.
Need for Simulation Tools
NERC’s chief engineer Mark Lauby said he would like simulation tools “that allow us — just like we do for an N-1 [scenario] — [to] build to a certain level of risk, understand what the mitigations are that we’re building into the system, and then after that [consider] recovery strategies.”
Lauby said grid operators need to “get in front of” the technology changes, such as the increase in inverters and asynchronous generation on the system, to “be sure we’re not building in more [attack] surface but rather de-risking and taking advantage of the technologies.”
William H. Sanders, interim director of the University of Illinois’ Discovery Partners Institute, said “The trick is to find the models with the right level of detail and abstraction that you can discover things … surprising things emerge, not just you fill everything in, and the model tells you what you knew it would tell you. I think we are making great progress. We have test beds. We have examples of models that can help us understand … I think we need to scale those up in a big way.”
Communication Breakdown?
“There’s no simulation that can fully appreciate the consequences of how things are going to cascade,” Durkovich said. “It all depends on the circumstances and the factors of the day.”
“I know GridEx is continuing to try and [address] this but we do all these exercises and I think live in a fantasy world where somehow communication is not degraded and is fully there.”
In large crowds, cellular service can be difficult because the local network is congested. “What makes us think that’s not going to happen on a really bad day? I was here on 9/11. You couldn’t get anything out.”
She said there aren’t enough exercises at the state and local level. “That’s really where we need to build capacity. Yes, you have DHS. But really, at the end of the day, … they’re not going to be there to respond to critically important state-level assets. … I don’t think states and localities have a full appreciation of how much of the burden they’re going to share on a bad day.”
Morgan said the previous National Academies study “talked precisely to that point and argued there was an urgent need to do something. As best as I can tell, [the report is] sitting on a bunch of shelves around town. We did brief quite a large number of people. But as several of you have said, there needs to be a wider recognition of the urgent [need for] moving towards greater resiliency.”
A fight over potential payments to insurers and wildfire victims has heated up in the Pacific Gas and Electric bankruptcy case and is scheduled to be a major topic of a hearing Nov. 19 before U.S. Bankruptcy Judge Dennis Montali in San Francisco.
Wildfire victims and California Gov. Gavin Newsom have challenged PG&E’s proposed $11 billion settlement with insurance companies and hedge funds — known in the Chapter 11 case as the subrogation claimants — that are seeking reimbursement for insurance payments.
PG&E has hailed the settlement as a milestone in its bankruptcy, which was brought about by billions of dollars in wildfire liability. The utility has asked Montali to approve the agreement at the Nov. 19 hearing.
Newsom’s lawyers, however, said in a court filing Friday that the settlement “is yet another example of legal maneuvering by parties apparently more focused on securing procedural advantages for their own pecuniary interests than on reaching a fair and expeditious resolution of this bankruptcy.”
“Many of the holders of subrogation claims are sophisticated financial institutions that bought the claims at a discount after the insurers paid out claims,” it said. “Certain of those institutions [including Boston-based Baupost Group] also hold equity in PG&E and may be seeking to leverage the settlement of subrogation claims to better position those holdings.”
Newsom asked the judge to delay deciding the matter to allow a competitive process to play out between PG&E and a group of the utility’s bondholders, whose alternative Chapter 11 reorganization plan Montali admitted Oct. 9. (See Judge Admits Takeover Plan as PG&E Starts Blackouts.)
The governor said he wants to continue the closed-door mediation sessions he began with PG&E and its creditors, including wildfire victims, last week. The sessions include a retired bankruptcy judge whom Montali appointed as a mediator at PG&E’s request. (See Pressure Grows for Public Takeover of PG&E.)
The official Tort Claimants Committee (TCC), which represents fire victims, also objected to the $11 billion all-cash agreement. The settlement would lock up those funds, potentially to the detriment of fire victims, the TCC lawyers said. Insurance companies and financial speculators would be given priority, with no guarantee PG&E would have enough liquidity to pay victims’ claims, they said.
“It is time to call this settlement what it is: a mistake,” the TCC lawyers wrote. “The debtors have given away all their cash and placed the wildfire victims in a position of full risk in this case.”
In its current reorganization plan, PG&E has offered fire victims $8.4 billion in cash, but to increase its offer — as many expect will happen — the utility might have to offer a cash-stock combination, the TCC told the judge.
PG&E’s stock fell to a record low of $3.80/share Oct. 28 after it blacked out more than 2 million residents to prevent its from equipment sparking wildfires — yet it also fell under suspicion for sparking the 78,000-acre Kincade Fire in Sonoma County.
Its stock rebounded to $7.06/share at the close of trading Tuesday after several reports in the financial press that PG&E would increase its offer to fire victims to $13.5 billion, the same as bondholders proposed in their alternative reorganization term sheet.
Wildfire Liability Still to be Determined
The amount that fire victims may ultimately be owed is still in question.
PG&E and the TCC agreed Monday to extend the date for wildfire victims to file claims from Oct. 21 to Dec. 31, so that more claims may be submitted. There has yet to be an accounting of the number or amount of individual victims’ damage claims.
Proceedings to estimate the amount of PG&E’s wildfire damages are taking place before a different federal judge in San Francisco. The estimation process is a typical part of bankruptcies involving large numbers of victims.
And blame for one of the biggest fires of the past two years remains in doubt.
Investigators with the California Department of Forestry and Fire Protection (Cal Fire) determined PG&E equipment sparked the Camp Fire in November 2018. That blaze killed 86 people and destroyed more than 14,000 homes in the town of Paradise.
Cal Fire investigators also found PG&E equipment ignited 21 of the 22 wine country (also called North Bay) fires in October 2017.
They found a private landowner’s faulty wiring started the Tubbs Fire, which leveled an entire neighborhood in the city of Santa Rosa, killing 22 residents.
Victims, however, believe jurors should determine who’s to blame. A trial to decide if PG&E caused that blaze is slated to start Jan. 7. The result could add billions of dollars to PG&E’s wildfire liabilities.
Not content with pillorying SPP officials on their home turf, Louisiana Public Service Commissioner Foster Campbell has broadened his complaint over RTO expenses with a letter challenging SPP’s and MISO’s spending on offices and executive salaries.
Campbell last week filed a letter with SPP’s and MISO’s state commissions and the National Association of Regulatory Utility Commissioners’ senior leadership, calling for a “thorough examination of [grid operators’] spending.”
“Turning the American power grid into the electricity equivalent of an interstate highway system is probably a worthwhile goal, but I question how those RTOs freely spend our dollars,” Campbell wrote, adding a new acronym to the industry’s lexicon: Overspending Other Peoples’ Money (OOPM).
The Louisiana commissioner described SPP’s Corporate Center as a “150,000-square-foot Taj Mahal of an office building in a leafy 20-acre suburban setting fit for a Fortune 100 corporation.” He said he hasn’t been to MISO’s corporate offices in Carmel, Ind., and was thus unable to compare them to SPP’s “ornate offices.”
“If MISO’s offices are anything like SPP, then these two [RTOs] have a bad case of OOPM,” he said.
Campbell also lambasted the salaries paid to the grid operators’ top executives. He noted SPP’s Nick Brown and MISO’s John Bear are paid eight and 16 times, respectively, as much as FERC Chairman Neil Chatterjee ($155,500). Campbell cited 2017 data for Brown ($1.5 million in total compensation) and said Bear receives $2.8 million in compensation.
Bear’s salary matches up with the 2017 IRS Form 990 available through nonprofit tracker GuideStar. Brown’s 2016 Form 990 shows his total compensation was $1.2 million.
Campbell contrasted the CEOs’ salaries with Louisiana’s “1.6 million electric customers, many of whom live at or below poverty level.” He said SPP and MISO charge the state’s investor-owned utilities nearly $31 million a year to dispatch energy.
The letter would sound familiar to those who were present last month in Little Rock, Ark., when Campbell livened up the SPP Regional State Committee’s October meeting at the RTO’s corporate headquarters by criticizing the facility’s $62 million price tag and senior executives’ salaries. Several observers found his comments to be political, as Campbell is up for election next year. (See “Louisiana’s Campbell: SPP Spending ‘Extravagant,’” SPP Regional State Committee Briefs: Oct. 28, 2019.)
SPP said it “respectfully but wholeheartedly disagrees” with Campbell’s allegations.
Spokesman Dustin Smith said the grid operator provides “significant” savings to ratepayers in its footprint and listed several examples to back up his point:
“Conservative” cost-benefit studies that indicate the RTO’s services produce $2.2 billion in annual savings across its 14-state region.
FERC’s 2018 State of the Markets report indicating the SPP region enjoys the nation’s lowest wholesale electric costs.
“To anyone who questions SPP’s affordability, stewardship or ethics, we welcome the opportunity to provide answers,” Smith said.
MISO spokesperson Allison Bermudez would only say that the RTO, “as we have for the past 20 years, continue to be good stewards of our members and those customers we work together to serve.”
Louisiana utilities Entergy Louisiana and Southwestern Electric Power Co. both said RTO membership is worth the costs.
Entergy spokesman Mike Burns said the company’s MISO membership has been a “highly effective tool in helping control costs and keeping our rates among the lowest in the nation.” After netting out the RTO’s administrative costs, Louisiana customers realized an estimated $560 million in savings between 2014 and 2018, “largely because of MISO’s organized power markets, which allow power plants to be dispatched more efficiently, resulting in a lower delivered cost of energy,” he said.
“Customers also see significant cost savings from MISO members sharing generation reserves across the organization’s footprint, producing long-term benefits,” Burns said.
SPP’s corporate campus | Nabholz Construction
SWEPCO’s Peter Main said the utility’s customers benefit from SPP’s regional markets through reduced fuel costs and more efficient transmission planning. However, he also said SWEPCO is concerned about the RTO’s rising costs. SPP’s Board of Directors last month approved a record increase in the administrative fee, from 39.4 cents/MWh to 43 cents. (See “Directors Approve 9.1% Administrative Fee Increase for 2020,” SPP Board of Directors/MC Briefs: Oct. 29, 2019.)
“SWEPCO and other SPP members remain concerned about the growing costs of RTO operations,” Main said. “We are actively involved in efforts to ensure that the RTO is cost-effective, efficient and providing good value for our customers.”
SPP is equally concerned about costs. First-year board Chair Larry Altenbaumer created and led a task force focused on finding opportunities to increase value and improve affordability for SPP’s members and stakeholders. The group determined there is work to be done around the edges. (See SPP Value Group Finds No ‘Silver Bullets.)
RTO Insider asked regulatory commissioners in both regions for comment on Campbell’s letter. Arkansas’ Kimberly O’Guinn and Missouri’s Scott Rupp responded.
O’Guinn, who is the RSC’s president this year, said she didn’t agree with Campbell’s assessment, but she “appreciated” his concerns about the costs of participating in SPP.
“The RSC is conscious of SPP’s costs as well as other issues that impact utilities and ultimately the customers,” she said. “Therefore, the majority of the RSC regularly participates in monthly calls and quarterly business meetings to educate ourselves on these matters and engage in dialogue with the SPP Board of Directors and staff, members and stakeholders.”
O’Guinn said the Arkansas Public Service Commission finds that SPP’s services and the Integrated Marketplace have “resulted in net benefits to ratepayers” and justified the commission’s decision to allow certain utilities to transfer functional control of their transmission assets.
“Along with financial benefits,” she said, “participation in SPP has provided increased reliability and a decrease in required reserve margins.”
Rupp said the Missouri Public Service Commission believes “there is a large amount of benefit from RTO membership.” He cited back-of-the-envelope figures from SPP’s last regional cost allocation report that indicated Evergy’s Missouri subsidiaries Kansas City Power & Light and KCP&L Greater Missouri Operations enjoyed 3.97 and 2.15 benefit-to-cost ratios, respectively.
He also said the PSC requires the state’s utilities to file studies every three years that justify their RTO membership.
“In the past few years we have waived the study, believing firmly that benefits are realized and the cost of the study would not be a good expenditure of resources,” Rupp said.
He also noted that that there have been few instances of load shed despite recent severe storms and floods in Missouri. “Before RTO membership, there would have been a shedding of load in Missouri.”
NYISO’s Business Issues Committee on Wednesday voted unanimously to recommend that the Management Committee approve Tariff changes intended to help speed up the interconnection process.
Thinh Nguyen, senior manager for interconnection projects, presented the proposed changes, which seek to expedite the class year portion of the interconnection study and limit the potential for one or two projects to cause delay for other projects.
NYISO is proposing to:
require deliverability evaluation in system reliability impact studies;
remove additional system deliverability upgrade studies from the class year study;
conduct expedited deliverability studies for capacity resource interconnection service (CRIS)-only projects; and
tighten CRIS expiration rules to prevent the retention of CRIS by facilities not participating in the capacity market.
Nguyen noted that stakeholders were keen to ensure the proposal would not change the qualities of the current process most important to them, including:
the identification of system upgrade facilities for projects to reliably interconnect, including detailed design, engineering and construction estimates;
provision of binding, good-faith cost estimates that provide reasonable closure on upgrade costs; and
equitable allocation of upgrade costs.
NYISO intends to make many of the proposals effective for Class Year 2019.
A sample timeline of expedited deliverability of the class year study | NYISO
Competitive Entry Exemptions
The committee also voted unanimously to recommend that the MC approve Tariff changes to make competitive entry exemption (CEE) available to requests for additional CRIS megawatts in a manner consistent with the underlying rationale for the exemption.
Senior ICAP Mitigation Analyst Jonathan Newton presented the proposal, which includes a change in the consequences of withdrawing a CEE request or providing false and misleading information.
The changes also modify the CEE rules in a way that could facilitate the repowering and replacement of existing generators by allowing existing portfolio owners that have entered into competitive short-term hedging contracts to qualify for the CEE.
“The changes are a reasonable way to let people move forward without penalizing normal commodity hedging,” one stakeholder said.
NYISO intends to make the proposed rules effective for Class Year 2019 projects, Newton said.
If the MC approves the queue changes this month, and the Board of Directors approves them in December, the ISO anticipates making the filings with FERC by Dec. 20 and seeking orders from the commission during the third week of February 2020.
More Granular Operating Reserves
The BIC discussed a proposal to implement local reserve requirements in certain New York City (Zone J) load pockets.
Market Design Specialist Ashley Ferrer presented the proposal, as recommended by the Market Monitoring Unit, including the modeling of the requirements based on N-1-1 reliability criteria.
Load pockets in Zone J are areas constrained by load levels and generation capability, as well as by transmission-supported import levels into the pocket. The structure and boundaries of each load pocket varies based on load, generation and transmission imports, Ferrer said.
New York Control Area operating reserves | NYISO
The ISO last June established a reserve region in Zone J based on a market design approved by stakeholders in March.
NYISO is proposing to establish operating reserve demand curves for each load pocket that assign a $25/MWh value to the proposed reserve requirements. The ISO proposes 30-minute reserve requirements of 325 MW in Astoria East/Corona/Jamaica; 225 MW in Astoria West/Queensbridge/Vernon; and 250 MW in Greenwood/Staten Island.
“This issue is not prioritized in 2020, but we still consider it important, and it could go forward conceivably in 2021,” said Rana Mukerji, senior vice president for market structures. “We will actually bring forth the methodology [for an impact analysis] before conducting any consumer impact analysis [with respect to the proposal].”
Broader Regional Markets Report
In presenting the month’s Broader Regional Markets Report, Mukerji highlighted updates to two ongoing proceedings.
The first item concerned five-minute real-time dispatch transaction scheduling with Hydro-Québec (HQ) across controllable interties at the Chateauguay proxy.
The proposed plan includes a project to consider scheduling transactions on a five-minute basis with HQ, instead of either the 15-minute or hourly basis currently in effect using NYISO’s real-time commitment software. The ISO is targeting to complete a study of the potential enhancement in 2020.
The second item concerned an effort to clarify the minimum deliverability requirements for external capacity.
At the MC’s May 20 meeting, stakeholders approved enhancements to the performance requirements for external capacity suppliers in response to a supplemental resource evaluation, a proposal that became effective in August after FERC approval.
IPPNY’s Matt Schwall Elected as Vice Chair
The BIC elected Matthew Schwall as its incoming vice chair for 2019/20. Schwall is director of market policy and regulatory affairs for the Independent Power Producers of New York, where he has worked since 2014, and previously worked in various capacities at the New York State Assembly. He is earning a master of science in global energy management at the University of Colorado Denver.
SPP staff last week told the Seams Steering Committee that they have begun “very preliminary” interregional planning discussions with Canadian electric utility SaskPower.
Clint Savoy, the committee’s staff secretary, said a provision in the RTO’s joint operating agreement with SaskPower allows joint planning analysis and coordinated system planning. The discussions center on reliability needs, he said.
SPP and SaskPower share a direct tie through Basin Electric Power Cooperative’s existing transmission facilities in North Dakota. The grid operator completed its first international transaction in December 2015 when it imported power from SaskPower during an emergency situation. (See SPP, SaskPower Make First International Trade.)
In February 2017, the Department of Energy granted SPP’s request to make electricity exports to Canada. The RTO told the department that it wanted to “address emergency assistance transactions” but that it doesn’t normally purchase from or sell to “such external entities.”
The authorization expires on Feb. 7, 2022.
FERC in 2016 approved SPP’s request to recognize the U.S.-Canadian border as a point of sale for transactions with Canadian transmission providers. The ruling allows Canadian companies to register their resources with and make them available to the RTO under its market rules. (See “FERC OKs Canadian Border Point-of-Sale Filing,” SPP Briefs.)
Pseudo-tie Revisions to SPP-MISO JOA
The SSC reviewed and made changes to a new pseudo-tie section of SPP’s joint operating agreement with MISO, addressing its neighbors’ continued deferral of dispatch decisions to its balancing authorities.
MISO has historically deferred to local BAs in making pseudo-tie decisions in the real-time transfer of a resource or load from its “native” BA to an “attaining” BA in a different location.
“There are some local balancing authorities taking the position that we’re not a BA, so we’re not going to execute it anymore,” Savoy said. “We thought it would be helpful to address this in the JOA and avoid those situations in the future.”
Savoy said staff have taken FERC-approved language from the MISO-PJM JOA as a starting point. SPP hopes to file the changes with FERC early next year.
M2M Settlements Swing in MISO’s Favor
Staff’s regular market-to-market (M2M) report indicated another slow month, with 41 permanent and temporary flowgates binding for a total of 664 hours and resulting in a $197,320 settlement in MISO’s favor.
| SPP
August’s numbers dropped to $64.1 million in SPP’s favor. The two seams neighbors began the process in March 2015. SPP has seen positive settlements in 40 of 54 months through August.
FERC accepted an agreement last week between CAISO and a Calpine plant to provide black start service, but it also agreed with the California Public Utilities Commission that more cost information was needed to determine if the deal was just and reasonable (ER19-2800).
The federal commission accepted the agreement effective Nov. 6 but required additional information to be presented at settlement hearings.
CAISO in 2016 determined it needed additional black start capability in the San Francisco Bay Area. It issued a request for proposals in June 2017 and ultimately selected a plan by Calpine to provide battery storage at the company’s gas-fired Russell City Energy Center in the city of Hayward.
The agreement between Russell City and the ISO — in which Pacific Gas and Electric, the transmission provider in Hayward, is also a participant — stipulates that the plant will collect about $7.4 million annually for five years to cover a $21.8 million capital investment and earn a reasonable rate of return. The plant owner will recover both the variable cost of providing black start service and the fixed cost of constructing the battery system.
Calpine’s Russell City Energy Center in Hayward, Calif. | Calpine
The variable cost represents the sum of a start-up charge, a fired-hours charge, greenhouse gas reimbursement, CAISO charge reimbursement, a performance test field support charge and a power plant outage cost reimbursement — all outlined within a schedule of the agreement. The contract also provides for Russell City to recover a “market revenue shortfall” if the revenues received during energy delivery are less than provided for by the schedule.
Russell City contends that CAISO’s competitive solicitation process guarantees that its rates, terms and conditions for black start service are just and reasonable. The ISO would have the option to renew the agreement for an additional five years after the contract expires.
In its comments to FERC, the CPUC said it supported the development of black start capability in the Bay Area but argued Russell City had not provided underlying cost information to support its filing. The state commission requested that FERC require Russell City to refile the agreement with underlying cost information, or alternatively accept the agreement but also determine that it does not set any precedent. FERC agreed with the CPUC’s concerns.
“Although Russell City, CAISO and PG&E represent that they exchanged information with CPUC about cost allocations during their negotiations of the agreement, that information has not been submitted into the record of this proceeding and therefore is not available for this commission to evaluate in determining whether the proposed rates are just and reasonable under Section 205 of the Federal Power Act,” the commission found.
