WASHINGTON — Deputy Energy Secretary Dan Brouillette appeared well on his way to taking over for his outgoing boss after facing little substantive questioning at his confirmation hearing Thursday and little, if any, opposition from Democrats.
Much of the hearing was taken up by members of the Senate Energy and Natural Resources Committee, on both sides of the dais, extolling the virtues of a particular technology and cordially asking Brouillette for his commitment and assurances that he would continue the Department of Energy’s work in advancing the research and commercialization of those technologies, including LNG, carbon capture and sequestration, battery storage, and advanced nuclear energy.
Brouillette has been serving as deputy to Energy Secretary Rick Perry since August 2017, when the Senate confirmed him 79-17. He was considered by the committee in May of that year alongside eventual FERC Chairman Neil Chatterjee and former Commissioner Robert Powelson. (See No Fireworks for FERC Nominees at Senate Hearing.) Chatterjee was among those in a packed audience Thursday that included five National Laboratory directors and Brouillette’s nine children.
Brouillette previously worked at the department in the George W. Bush administration as assistant secretary for congressional and intergovernmental affairs from 2001 to 2003. He worked as staff director for the House Energy and Commerce Committee for a year after leaving the department. Before returning to DOE, he had been a senior vice president for USAA since 2006.
President Trump formally nominated Brouillette on Nov. 7. Calling him “the obvious choice to replace Secretary Perry,” Senate ENR Committee Chair Lisa Murkowski (R-Alaska) told Brouillette it was her “intention to try and move you through the committee process just as rapidly as possible.” But regardless of if — or when — the Senate confirms him, Brouillette will take over leadership of the department, at least in an acting capacity, when Perry retires on Dec. 1.
Baseload and Resilience
Sen. Steve Daines (R-Mont.) said his state’s “balanced energy portfolio is coming under attack with the premature, forced closures” of two units at the coal-fired Colstrip plant because of “extreme, radical groups that litigate.” He told Brouillette he believed “that there is a role for you and the Department of Energy to play in order to maintain baseload supply in Montana” before asking him to “commit to working with me and this committee to protecting and growing baseload power like Colstrip and maintaining a secure and balanced energy portfolio.”
“It’s been the policy of this administration, and possibly the previous administration, to pursue an all-of-the-above energy strategy,” Brouillette replied. “In our view, diversity of energy supply means energy security, not only for our nation but for our allies across the world. … Until we are able to develop battery storage that has more capacity, is longer lasting [and] is perhaps more flexible in some respects, it is important that baseload power exist, because without it, if we are objective and candid, the introduction of renewables to our electric grid is very, very difficult.”
Through the department’s in-development North American Energy Resilience Model, “we’re going to look at these types of facilities and see if they fit that potential model and see if there’s anything that we should be concerned about potentially about the loss of those” plants, he said.
Asked by reporters after the hearing how he would go about saving baseload plants, Brouillette answered, “It’s not about saving the plants. It’s about working with regulators; showing them the things that we’re seeing; allowing the FERC to do its job.
“It’s not about simply ‘saving the plants.’ It’s about looking at the entirety of the grid, looking at the entirety of the energy sector and making sure that we have either distortions or artificial impacts on it that might preclude us from either adopting renewable technology or create some level of a security risk. … We’re looking at that resilience model as a way to show us in real time what’s happening on the grid.”
Ukraine Matters
The breezy hearing intersected briefly with the political firestorm taking place on the other side of Capitol Hill. Brouillette said he had no knowledge of or involvement in conversations with Ukrainian officials about matters at the heart of the House of Representatives’ inquiry into impeaching Trump.
“I have not been involved in any of the conversations that are related to the House’s inquiry,” Brouillette told ranking member Joe Manchin (D-W.Va.). He did say the department has worked with Ukraine, “at their request, to help them interconnect their electricity grid [and] their pipeline grid,” and that it has advised U.S. allies in Eastern Europe on building LNG import facilities as part of an effort to lessen their dependence on Russian natural gas.
Perry — along with U.S. Ambassador to the E.U. Gordon Sondland and Kurt Volker, special U.S. envoy to Ukraine — is one of the White House’s “three amigos” on Ukraine policy, according to Sondland. Perry had traveled to Ukraine in May for the inauguration of President Volodymyr Zelenskiy and provided him with a list of suggestions for the supervisory board of Naftogaz, the country’s state-owned energy company.
Sen. Ron Wyden (D-Ore.) asked if Brouillette was aware of “any contacts between Secretary Perry, or any other senior DOE officials, and representatives of Naftogaz.”
“I am aware that the secretary met on occasion with individuals who were asking for assistance with the restructuring” of the company, Brouillette replied. But he said he was not aware of any conversations between Perry and Trump’s personal lawyer, Rudy Giuliani, or anyone in the Ukrainian government about the makeup of the board.
CARMEL, Ind. — MISO’s grid will be only minimally susceptible to the impacts of possible water scarcity in the future, in part because of increased adoption of renewables, new RTO models show.
The RTO will only have a “relatively modest” need for incremental new generation to meet demand under water scarcity, Senior Adviser Eli Massey told stakeholders at a Planning Advisory Committee meeting Wednesday.
“The results of this first round of modeling suggest that MISO isn’t susceptible to either a short-term or long-term water scarcity scenario,” Massey said.
The modeling relied on data from Sandia National Laboratory to estimate the “water intensity factor” for MISO generation, which represents the relationship between the amount of cooling water and fuel needed to produce 1 MWh of energy. That data point was cross-referenced with estimates for the volume of water available for generation under short- and long-term scarcity conditions.
The Fermi 2 Power Plant on Lake Erie | DTE Energy
Most water scarcity concerns can be mitigated by economically redispatching MISO’s resource portfolio “around low to moderate water scarcity.” He also said the continued evolution of the resource portfolio toward renewables “is moving MISO in a direction that makes it less susceptible to water scarcity in the future.”
“Wind doesn’t need water,” he said.
MISO doesn’t collect cooling water use statistics from its members, and Sandia could only provide usage stats for about half the generation in its footprint, Massey said. He said MISO consulted with Sandia and the National Renewable Energy Laboratory on their methodology to fill in missing estimates.
MISO modeled both a six-year drought and recovery, and a 15-year water scarcity scenario in which water available for generation is limited by varying degrees. Scientists have repeatedly predicted that climate change, bringing long dry spells and more severe flooding, will intensify water shortages in some geographic areas. RTO staff did not mention climate change during the presentation.
Massey said energy served by MISO’s thermal resources is disrupted only in the most extreme water shortage scenarios.
“MISO is always looking at environmental issues or operational risks to reliability,” Massey explained to stakeholders. “We always felt like we thought we were OK, but we never quantified it.”
The effort is MISO’s first attempt to understand the potential impacts of water scarcity, Massey said, adding that the RTO will perform more analyses, possibly on a seasonal or subregional level, to understand the impacts of water constraints in the footprint.
“This isn’t the only avenue we’re exploring. MISO is partnering with NREL and other labs to understand water risk,” Massey said.
He also said MISO may explore requesting more accurate water use statistics from its thermal generation operators. He asked stakeholders to communicate their interest in having the RTO analyze more detailed data.
CARMEL, Ind. — MISO on Wednesday dismayed some stakeholders when it doubled back on a cost allocation proposal that would have lowered voltage thresholds and raised cost minimums for economically beneficial transmission projects.
FERC rejected MISO’s first cost allocation filing in June, finding it would have violated the principle of cost causation because projects proposed under the local economic transmission category would be required to demonstrate regional benefits while only being cost-shared on a local level.
That plan also sought to lower the regional market efficiency project (MEP) voltage threshold from 345 kV to 230 kV while keeping the current $5 million cost minimum for those projects, a measure that FERC did not address in its rejection.
In September, MISO circulated a proposal that sought to address the local project issue by lowering the voltage thresholds for regional MEPs to 100 kV, while increasing cost minimums to $25 million, a move intended to cover local projects with wider benefits. The plan would have also set a 100-kV threshold for interregional MEPs with Key Details Change in MISO MEP Cost Allocation Plan.)
MISO’s latest proposal, revealed during a Wednesday conference call of the Regional Expansion Criteria and Benefits Working Group (RECBWG), would restore key points of the original filing, including setting the voltage threshold for regional MEPs to 230 kV and observing a $5 million cost minimum. It would also require that local economic projects between 100 and 230 kV be allocated only locally.
But unlike the rejected plan, the proposal would also stipulate that local projects be reviewed on a local basis only, and not have to show regional benefits. MISO Senior Manager of System Planning Jarred Miland said the RTO now plans to perform only local benefit-to-cost analyses for local economic projects that are based on transmission pricing zones. If the lower-voltage projects show at least a 1.25:1 benefit-to-cost ratio to the transmission pricing zone where the project is located, then the costs of that project would be allocated to that zone.
MISO would first screen projects for possible benefits, then test them in modeling, Miland explained during Wednesday’s call.
“Since there’s not regional test, there’s not regional allocation. The difference is the local economic projects are going to be locally allocated to the local” transmission pricing zone, Miland said.
Blind to Benefits?
But several stakeholders said MISO’s new proposal is still at odds with cost causation.
They said MISO is wrongly presuming that all sub-230 kV projects cannot deliver regional benefits. Some asked if the RTO planned allocation exceptions for highly beneficial lower-voltage projects.
“I would say right now, the plan is what the plan is. There’s no intention to try to make those projects regional,” Miland responded. He said the new proposal is similar to MISO’s current practice, where all projects below 345 kV cannot be considered MEPs.
“We’re still dropping down from 345 kV to 230 kV. So that still helps,” Miland said, adding that MISO would still be positioned to approve more MEPs than it does now.
LS Power Manager of Transmission Policy Pat Hayes argued that because MISO would already screen lower-voltage projects for footprint-wide benefits, it wouldn’t take much additional effort to estimate regional benefits.
“You just can’t turn the model off and shield yourself from seeing adjusted production costs,” he argued.
MISO officials confirmed that they would see possible regional benefits in modeling lower-voltage projects but wouldn’t share them externally.
‘Head in the Sand’
WEC Energy Group’s Chris Plante said the regional economic benefits of projects 230 kV and below exist even if MISO doesn’t name them.
“The first proposal failed because we failed to identify beneficiaries of projects. This proposal is akin to putting a bucket of sand in the corner and sticking your head in it. Just because we don’t look elsewhere and don’t identify beneficiaries, doesn’t meant they don’t exist. … I think that this thought process is dead-on-arrival at FERC — it’s not going to fly,” Plante said.
Clean Grid Alliance’s Natalie McIntire agreed, saying MISO is choosing to be willfully blind to some project benefits and setting itself up to block some beneficial projects from proceeding.
“There isn’t a clear path forward for lower-voltage projects that bring wider benefits to zones,” she said.
However, other stakeholders said the new allocation plan was reasonable and that the 230-kV threshold isn’t arbitrary. Some pointed out that MISO only discloses regional benefits for projects 345 kV and above.
Plante said MISO might “temper” its proposal by making cost allocation “optional” for the zone that might host a regionally beneficial local economic project. That way, single zones wouldn’t be forced to foot the bill on projects positioned to benefit other transmission pricing zones, he said.
Miland said stakeholder opinions on the September proposal can be broken down into “those that didn’t like what we did and those that did like it.” MISO said a majority of its state regulators wanted it to follow FERC’s June rejection and refile the proposal, this time scrapping the local economic project category altogether, leaving projects below 230 kV again relegated to the RTO’s “economic other” project category, which also dictates that smaller economically beneficial projects are allocated to the transmission pricing zone where they are located.
Still other stakeholders said they didn’t support MISO’s proposed $25 million threshold or the competitive bidding exception for reliability projects that it determines have an immediate need. As in the first filing, the new plan would exempt from competitive bidding any MEPs needed within three years to mitigate reliability issues. The new proposal preserves that option.
MISO maintains that its proposal will better “align who pays with who benefits over time from a regional transmission expansion perspective.”
Stakeholders on the call asked if MISO has met with FERC staff to vet its newest proposal. Staff said they had not.
“We’ve been trying to weigh the feedback we received with what we think is the best path forward,” Miland said. “This hasn’t been taken lightly by any means internally here in MISO. This has been a full-time job for several of us for a handful of months.”
The change in tack on lower-voltage projects pushes out MISO’s refiling target.
“We were hoping to get a filing out the door before Thanksgiving. That’s probably not going to happen now,” Miland said.
A simulated social media hack was among the surprises lobbed at participants in GridEx V, the latest entry in NERC’s series of exercises testing industry preparedness for cyber and physical attacks.
More than 425 organizations across industry and government participated in the two-day exercise, which began on Wednesday with a distributed play model representing a wide array of threat vectors that Steve McElwee, PJM’s chief information security officer, called a “true doomsday scenario.”
Along with utility companies and regulators, the drill included representatives from farther-flung sectors, such as natural gas, electrical equipment manufacturing, telecommunications and even finance, in an attempt to game out the broader social impacts of an attack on the shared electrical grid.
An unnamed staffer at NERC’s Electricity Information Sharing and Analysis Center (E-ISAC) participates in day one of GridEx V. | NERC
Stacking the Deck
“One of the important design parameters that we use when we develop GridEx is we essentially break the system,” NERC CEO Jim Robb said in a media briefing Thursday. “That’s how the electricity industry learns: We break things, and then we figure out how to fix them and prevent the breakage from happening next time. So, it’s purposefully an overwhelming act of violence.”
This year’s challenges included the takeover of one utility’s Twitter account by malicious hackers that then used it to spread disinformation to the public and other participants, which one player described as the major “curveball” of the scenario. Additional threats included technological incursions such as the use of rogue USB devices and ransomware, which — along with physical attacks such as intruders in headquarters buildings and vehicle fires at regional facilities — put essential infrastructure out of commission. Utilities were tested both on their ability to handle the initial attacks and their capacity to ride out the damage and get their systems back online.
NERC CEO Jim Robb (left) with Southern Co. CEO Tom Fanning at a press briefing | NERC
The distributed play exercise was joined in its second day by a similarly comprehensive but more targeted scenario in Thursday’s executive tabletop session, which presented an attack on the northeastern part of the North American grid. Test designers decided on this scenario, the first region-specific exercise in the history of GridEx, in hopes of gaining deeper insights than were available in previous years. The northeastern setting gave participants the opportunity to explore characteristics of the region such as U.S.-Canada relations, the interdependence of the electric and natural gas sectors, and the impact of a prolonged outage on financial players in New York City.
“There are very few cyber-only or physical-only incidents, and as our world grows more interconnected and our infrastructure grows more interdependent with other systems and functions, we must look at our risks [from] both a physical and cyber perspective,” said Brian Harrell, assistant director of the Cybersecurity and Infrastructure Security Agency at the Department of Homeland Security. “The scenario is real, it’s relevant, and it focuses on industry and government partnerships and how we [can] collectively get better.”
Fighting Back
As Harrell suggested, risk is not the sole focus of GridEx. The scenario also provides a sandbox for the public and private sector to test mitigation tools without danger to the general public. This year’s scenario was no different, with participants aiming to address vulnerabilities identified in previous GridEx iterations.
One focus for industry players in this year’s scenario was to actively engage with the vendor supply chain. Vulnerabilities often center on specific equipment, yet in the public report following GridEx IV, NERC called out utility operators for failing to engage with vendors to the degree they did with other utilities, government, and law enforcement. (See Ukraine Attacks, ‘Fake News’ Color NERC GridEx IV Drill.) The criticism spurred greater efforts in this year’s exercise, though participants acknowledged that considerable work is still needed.
Kevin Wailes (left), Lincoln Electric, and Brian Harrell, DHS, at a press briefing | NERC
“The supply chain issue is extraordinarily complex and hard to think about over time, because the threat vectors change continuously and … a good device today may be exposed tomorrow,” said Southern Co. CEO Tom Fanning, co-chair of the Electricity Subsector Coordinating Council. “So, it isn’t [enough to] have certified equipment in our supply chain. … We must have a process of cyber hygiene and collaboration over time.”
On the public side, GridEx V provided a chance to test out the responsibilities granted to the Department of Energy since the last exercise under the FAST Act, amended in 2018 to designate the department as the lead agency on cybersecurity for the energy sector. The change gave broad new authority to DOE to coordinate with state and local governments, in addition to utilities, and GridEx provided an opportunity to test the practical limits of these powers prior to a real emergency.
“What we don’t want … is to be in an actual situation where we’re figuring out the right policies and how we share that information, and what type of information [to share], so that we can have the situational awareness to advise the president,” said Karen Evans, assistant secretary in DOE’s Office of Cybersecurity, Energy Security and Emergency Response.
Ongoing Development
The GridEx exercises have expanded considerably since the first iteration in 2011, which involved just 75 industry and government organizations across the U.S. and Canada. Unlike that scenario, which was inspired by the Stuxnet attack in Iran and focused exclusively on cybersecurity, GridEx now aims to include the widest possible range of participants so that every aspect of the system can be tested.
ERCOT staff participate in GridEx V. | ERCOT
This has led to criticism that the scenarios presented are unrealistic, with participants in previous years comparing the prepared situations to a “disaster movie” rather than helpful practice for recovery. NERC acknowledged these issues but said they overlook the true goal of the exercise.
“The grid is designed with a tremendous amount of redundancy, it operates in real time, and the loss of even a major power station in many cases is not a catastrophic consequence because the industry is prepared for that and designs around it,” Robb said.
“That makes a scenario [such as the one] we’ve laid out implausible but still worth testing,” he added, citing the potential to uncover unsuspected vulnerabilities and suggest new avenues of cooperation.
NERC will release its report on GridEx V by March 2020.
RTOs Take Part
RTO officials also gave their take on the exercise Thursday.
Keri Glitch, MISO’s vice president and chief information security officer, said the scenarios included “network breaches caused by an internal source, a potential intruder in the headquarters building, as well as a vehicle fire near a regional facility.”
“Our employees and industry partners collaborated well and learned a lot from the drill,” Glitch said.
About 120 CAISO employees took part in the exercise, along with representatives from federal, state and local agencies and 39 RC West participants, IT Enterprise Support and Campus Operations Director Matt Turner said.
“We assessed how employees reacted and communicated the scenario injects, which included a plan to return to normal operations. During the simulation, we injected additional issues, such as making key personnel unavailable, to evaluate the depth we have on the team and their ability to adapt to the situation,” Turner said. “Our exercise is designed to push the limits, as far as we could, to identify areas for improvement.”
New York state was “hit” hard during GridEx V, which included a “focused regional attack in the Northeast,” according to NERC CEO Jim Robb. Above, New York Power Authority staff participate in the exercise. | NYPA
SPP said more than 200 staffers took part, after more than a year of preparation by the RTO’s leadership team. “SPP’s incident coordination team led IT, operations and other staff in response to simulated threats to system reliability, communications channels and cyber assets, all in the interest of strengthening defenses, enhancing resilience and refining emergency response procedures,” spokesman Derek Wingfield said. “In the weeks leading up to the go-live of our Western reliability coordination service, GridEx also gave us the opportunity to test our preparedness alongside some of our new customers in the Western Interconnection.”
NYISO, ISO-NE and ERCOT also confirmed their participation. “Physical and cybersecurity measures are a constant practice of vigilance and focus of attention,” NYISO CEO Rich Dewey said.
“Past GridEx exercises have proven to be valuable training opportunities for many departments within ISO New England, and we look forward to practicing and improving our response capabilities,” RTO spokesman Matthew Kakley said.
While PJM regularly conducts simulator drills with its transmission owners and other critical players, GridEx allows the RTO to test its operations under extreme conditions, McElwee said. “It’s far beyond any situation we’ve experienced.”
Amanda Durish Cook, Tom Kleckner, Michael Kuser, Hudson Sangree and Christen Smith contributed to this article.
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.
