A television station in Sacramento, California, ABC10, took an extended look at the deaths caused by wildfires started by Pacific Gas and Electric’s powerlines and how the company has avoided serious legal repercussions after pleading guilty to the manslaughter of 84 people.
The video below is a combination of the first four episodes of their series examining the connection between wildfires, PG&E, and its influence on state politics.
Four people died in the fire southwest of Redding, California
Investigators from the California Department of Forestry and Fire Protection looking for the cause of the Zogg Fire seized Pacific Gas and Electric equipment, the utility said Friday in a notification to the state Public Utilities Commission.
The Zogg Fire started about 9 miles southwest of Redding, California during hot, dry, and windy conditions on September 27, 2020 and ran south for 16 miles until firefighters were able to stop it at Highway 36 about 9 miles east of Platina.
Four people were killed in the fire and 103 residences and 101 other structures were destroyed. The estimated costs of suppressing the fire through October 9 are $29 million.
In PG&E’s filing to the PUC, the company said their equipment reported alarms and other activity in the area of Zogg Mine Road and Jenny bird Lane between approximately 2:40 p.m. and 3:06 p.m. on September 27, when the line recloser de-energized that portion of the circuit. The filing says wildfire detection cameras and satellite data showed heat or signs of smoke at that location between approximately 2:43 p.m. and 2:46 p.m.
The Shasta County Sheriff’s Office identified one of the victims as Alaina Michelle Rowe, 45, who was found dead along a road on Sept. 28. The sheriff’s department said another victim was a minor but did not report the identity. KRCR-TV in Redding reported that Rowe and her eight-year-old daughter Feyla died as they tried to escape the fire.
The two other victims, also found a day after the fire started, are Karin King, 79, who was found on the road where the fire started, and Kenneth Vossen, 52, who suffered serious burns that day and later died in a hospital.
Neither PG&E or CAL FIRE have disclosed exactly what equipment the investigators seized.
CAL FIRE has not released their findings about the cause of the Zogg Fire.
After their equipment was blamed for starting the Camp Fire, in June of this year PG&E pleaded guilty to involuntary manslaughter for the 84 people that were killed when the fire burned through Paradise, California November 8, 2018. The fire also burned 154,000 acres and destroyed more than 18,000 structures. As part of the investigation for that fire, CAL FIRE personnel seized electrical equipment on or near a 100-year old PG&E transmission tower near the point of origin.
Previously the power company has reached settlements with victims from wildfires in 2015, 2017 and 2018, totaling about $25.5 billion, NBC news reported.
Earlier, power companies agreed to pay the seriously injured lone survivor $5 million
The Okanogan County Electric Co-op has agreed to a $1.1 million settlement for the suppression costs of the deadly 2015 Twisp River Fire.
U.S. Attorney William D. Hyslop announced that the settlement had been reached with Okanogan County Electric Cooperative, Inc. (“OCEC”) and its insurer, requiring the payment of $1.1 million to the United States in fire suppression costs resulting from the Twisp River Fire that began on August 19, 2015 in north-central Washington.
The $1.1 million recovers a large portion of the U.S. Forest Service’s costs incurred in suppressing the fire. It was part of a larger settlement of claims that were brought separately by other plaintiffs, including U.S. Forest Service firefighter Daniel Lyon and the State of Washington, who sought to recover damages for personal injury and property damage caused by the fire.
The Twisp River Fire ultimately burned approximately 11,200 acres, claimed the lives of three USFS firefighters, and severely injured Mr. Lyon. He suffered third degree burns over nearly 70 percent of his body, but three other firefighters in the same engine died in the vehicle, according to the corner’s report, from smoke inhalation and thermal injuries. They were Richard Wheeler, 31; Andrew Zajac, 26; and Tom Zbyszewski, 20. All four were employees of the USFS working on the Okanogan/Wenatchee National Forest out of Twisp, Washington.
In January Mr. Lyon reached a settlement with two utility companies, OCEC and Douglas County PUD, just before an appeal of his $100 million civil suit was to be heard before the state Supreme Court. In that settlement the companies agreed to pay $5 million.
From the Wenatchee World, when the $5 million settlement was announced in January:
“I am very grateful that my case calls attention to the plight of injured first responders,” said Lyon, who was burned over most of his body and has undergone more than a dozen surgeries and 100 medical procedures. “I am also grateful my case has reached a settlement so that I can now move on with my life knowing I will have the resources I need for the future.”
Last July, his attorneys, in an appeals brief, argued the Professional Rescue Doctrine that largely bars such claims violates the state constitution, which gives people equal protection under the law and offers the right to seek compensation for damages.
Lyon’s attorneys note that courts in some other states, where the doctrine once held sway, have opted to throw it out.
An attorney for one of the two defendants, in an earlier interview, says the wounds Lyon suffered — however grievous — resulted from risks inherent to the dangerous job of firefighting.
“The law does not allow them (professional first responders) to sue — and there are good policy reasons behind that,” said A. Grant Lingg, who represents the Okanogan County Electric Cooperative. “You don’t want the people who start a fire to be afraid to call the fire department for fear that that an injured first responder will sue them.”
The video below is about the January settlement.
Thanks and a tip of the hat go out to Tom. Typos or errors, report them HERE.
PG&E CEO says preemptive power shut offs during periods of high fire danger in California are likely to continue “for some period of time”
Today the U.S. Senate Committee on Energy and Natural Resources held a hearing to examine the impacts of wildfire on electric grid reliability, efforts to mitigate wildfire risk, and how to increase grid resiliency.
The five witnesses at the hearing were Bill Johnson (PG&E), Michael Wara (Stanford Woods Institute for the Environment), Scott Corwin (Northwest Public Power Association), Carl Imhoff (USFS Pacific Northwest National Laboratory), and Dr. B. Don Russell (Texas A&M).
The Senators and witnesses talked about Pacific Gas and Electric’s bankruptcy following the fires caused by their system, the future of preemptive power shutoffs during periods of high fire danger, and two new advances in technology that could help prevent some fires that are caused by power lines.
Dr. B. Don Russel, a professor at Texas A & M, told the committee about distribution fault anticipation technology developed at his university that uses intelligent algorithms to continually monitor electric circuits to detect the very earliest stages of failing devices and missed operations. The concept is simple, he said. You find and fix it before the catastrophic failure causes a fire or an outage. Dr. Russel repeatedly advocated the adoption of this system.
San Diego Gas and Electric’s research found that it takes 1.37 seconds for a broken conductor to hit the ground, for example, if a tree falls into the line or a vehicle hits a power pole. When the line contacts the ground sparks can ignite vegetation. The system is designed to detect a break and shut off the power before the clock hits 1.37 seconds — hopefully, avoiding what could become a dangerous wildfire.
Bill Johnson became the CEO of Pacific Gas & Electric about 8 months ago about the time the company began going into bankruptcy. Senator Murkowski asked him how much longer residents in California would continue to be affected by the electricity being shut off during periods of high fire danger.
Mr. Johnson said San Diego Gas & Electric is still doing Public Safety Power Shutoffs (PSPS) in Southern California during periods of high fire danger 12 years after their power lines started multiple large fires in 2007, but the shutoffs are “surgical” and very localized. He said “[I]n Northern California it would take us probably five years to get to the point where we can largely eliminate this tool… So I think over the next couple of years you’ll see a progression of shorter, fewer PSPS events. But the climate change and the weather change is dramatic enough that I don’t think we will see the end of it for some period of time.”
Dr. Michael Wara discussed the effect of PSPS on residents:
The use of PSPSs has both prevented wildfire and caused widespread disruption to families and businesses, especially in Northern California. PSPS events, though they do dramatically improve safety, are likely very costly to the health of the economy, especially in smaller communities. My best estimate, using the Interruption Cost Estimator tool developed by Lawrence Berkeley Laboratory indicates that PG&E PSPS events in 2019 cost customers more than $10 billion – that’s 0.3% of gross state product or 10% of overall economic growth this year in California.
Below is an excerpt from Mr. Johnson’s prepared testimony about PG&E:
PG&E is deeply sorry for the role our equipment had in those fires and the losses that occurred because of them. And we’re taking action to prevent it ever happening again.
And today we’re taking that work a step further by increasing vegetation management in the high risk areas, incorporating analytical and predictive capabilities, and expanding the scope and intrusiveness of our inspection processes.
We deployed 600 weather stations and 130 high resolution cameras across our service areas to bolster situational awareness and emergency response. We’re using satellite data and modeling techniques to predict wildfire spread and behavior. And we’re hardening our system in those areas where the fire threat is highest by installing stronger and more resilient poles and covered line, as well as undergrounding.
And this year we took the unprecedented step of intentionally turning off the power for safety during a string of severe wind events where we saw up to 100 mile an hour winds on shore in Northern California. And this decision affected millions of our customers, caused them disruption and hardship even if it succeeded in protecting human life.
We are operating on all fronts to make the system safer and more resilient.
A new system being tested seeks to provide continuous situational awareness of the condition of each circuit
Technology recently developed can shut off the power to a broken overhead electrical line before it hits the ground, possibly avoiding the ignition of a disastrous wildfire. But not all of the numerous large fires started by power lines in California were caused by broken conductors. Often they originate from failing hardware, two wires blown by the wind briefly touching, or a tree limb coming in contact with a line. These situations do not always start a fire when they first occur, but over time can become more serious problems.
A team of Texas A&M researchers has developed a new technology that helps electrical providers find the cause of outages, and anticipate and predict some failures before outages occur. A few utility companies in Texas started using it a few years ago and tests in California by PG&E and Southern California Edison have just begun.
From Texas A&M:
When your power goes out, you probably assume that your utility provider has a monitoring system quickly telling them exactly where the problem is. After all, this is the era of smart technology and big data.
But the electric grid wasn’t designed or built in this era. Utility companies may know if there is an outage, but they likely don’t know exactly where or what the problem is until crews inspect it and find the problem. Utility providers are essentially blind to developing problems in the grid other than whether the power is on or off.
Not only is their ability to assess a current outage limited, they also have no way of identifying a problem that may not actually be causing an outage or anticipating where a problem may occur in the future. For example, a failing device could be sparking, creating a dangerous situation that nobody is aware of for days or weeks before it completely fails and causes an outage.
But, not anymore.
Applying concepts of pattern recognition and advanced signal processing to more than a decade of data, a team of Texas A&M University researchers has developed a new technology called Distribution Fault Anticipation (DFA). It has the capability to not only help utility providers find the cause of outages, but to also anticipate and predict some failures before outages occur. (Their published research, Application of DFA Technology for Improved Reliability and Operations, was presented at the 2017 Institute of Electrical and Electronics Engineers Rural Electric Power Conference in Columbus, Ohio.)
“Power distribution system electrical signals include specific failure signatures, which tell a story — for instance whether potential faults and outages are about to occur,” said Dr. B. Don Russell, a power engineer and the Engineering Research Chair Professor and Distinguished Professor in the Department of Electrical and Computer Engineering at Texas A&M.
An entirely new technology
Simply put, they’ve been ‘listening’ to the electric grid for more than a decade to analyze signals and identify which ones indicate a potential problem. Conceptually, it is not much different from an auto mechanic who can hear a problem in an old engine and know exactly what is causing it. Practically, however, this is an entirely new technology.
“A practical benefit of using DFA is the ability to detect and repair arcing and misoperating devices that often cause wildfires. In a four-year study just completed at Texas A&M, it has been proven that many fires can be prevented with this technology,” Russell said.
The Texas A&M research team led by Russell includes Carl Benner, Jeff Wischkaemper and Karthick Manivannan. Their research, sponsored by the Electric Power Research Institute, developed the DFA technology. It is an autonomous, distributed computing system that provides electric utility operators a continuous situational awareness of the condition of each circuit. The result is increased reliability of their network and reduced outages. It enables the utility operator to predict adverse power line conditions and events generally not detected by conventional technologies.
“DFA recognizes the impending failure mechanisms of most distribution hardware, often allowing operators to find and fix failing devices before catastrophic failure,” said Russell. “The devices report line events to a master station server, which provides access to reports from a fleet of DFA devices on circuits across the power system.”
An obvious example of the benefits from this technology is wildfire prevention. High winds can cause electric lines to contact, causing arcing on the line and damaging it, but not causing a complete outage. The sparks from these faults have been known to start wildfires, especially during dry conditions and often without the knowledge of utility personnel. Repeated contact can burn the line down. DFA has also helped utilities detect and locate tree branches making contact with power lines and causing faults, which can start fires directly or break a line and cause it to fall to the ground.
An example of this situation was the devastating fire of 2011 in Bastrop, Texas, where a true worst-case scenario unfolded when high winds and severe drought conditions caused the most damaging wildfire in Texas history. Many wildfires in the western United States last year were also linked to electric faults.
Russell explained that awareness of adverse events and conditions, even before they cause a failure, enables utility companies to take preventive action by performing repairs or condition-based maintenance. The DFA technology is a result of more than 15 years of continuous research collaboration, resulting in the only system of its kind.
“A practical benefit of using DFA is the ability to detect and repair arcing and misoperating devices that often cause wildfires,” said Russell. “In a four-year study just completed at Texas A&M, it has been proven that many fires can be prevented with this technology. Whether preventing wildfires or dangerous power lines on the ground, DFA is the new tool that improves reliability and safety.”
This technology is not just lab tested, it is field proven as well.
Robert Peterson, director of control center and emergency preparedness at Pedernales Electric Cooperative, the nation’s largest distribution electric cooperative, said DFA has been invaluable in providing information that is not available any other way.
“DFA has enabled us to identify potential issues like trees on lines, failing clamps, failing arrestors, etc. and resolve those issues before they create power interruptions,” he said. “In one case, we were able to pinpoint the location of a branch on an overhead line that could have become an ignition source for wildfire in a rural subdivision. We have also used the monitors to provide information allowing us to proactively address issues with capacitor switches in order to keep our power factor within regulatory prescribed limits. Overall, the technology has proven itself to the extent that our plans now include expanding their use to the rest of our distribution system.”
Dr. Comfort Manyame, senior manager of research and technical strategy, and Robert Taylor, engineering specialist, at Mid-South Synergy were also complimentary of the technology. Taylor said, “It makes me wonder what we did before DFA,” while Manyame said they are hoping to expand their use of DFA in the coming years.
“DFA has so far been the single most important operational technology we have implemented which has given us wins in the shortest amount of time,” Manyame said. “We want to multiply our DFA benefits and improve our overall system reliability and resilience by expanding our installation, possibly to our whole system, in the next few years.”
Thomas Ellis, manager of engineering at Bluebonnet Electric Cooperative, said that their control center operators have used DFA information to accurately determine the cause and location of multiple faults, including a fault that affected just one single customer on a stretch of circuit with more than 160 miles of overhead line.
Thanks and a tip of the hat go out to MrCAPT1409. Typos or errors, report them HERE.