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.
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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.
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.”
Industry tested 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.
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Pacific Gas & Electric (PG&E) told a judge on November 29 that it is investigating whether there is a systemic problem with a piece of hardware on their high voltage electrical transmission towers that can start wildfires, the San Francisco Chronicle reported. Investigators with PG&E and the California Department of Forestry and Fire Protection are looking at the possible failure of jumper cables on towers near the points of origin of two huge recent fires, the 2017 Camp Fire at Paradise, California and the Kincade Fire that started near the Geysers north of Santa Rosa October 23, 2019.
The Chronicle reported that “PG&E is also seeking more generally to determine whether there may be jumper cables that may be susceptible to failure for any reason in PG&E’s system,” the company told U.S. District Judge William Alsup.
It has been determined that PG&E equipment started the Camp Fire, but officially the cause of the Kincade fire is still under investigation.
On October 24 PG&E filed a required preliminary report with the California Public Utilities Commission that stated “at approximately (9:20 p.m.) on Oct. 23, PG&E became aware of a Transmission level outage on the Geysers No. 9 Lakeville 230kV line when the line relayed and did not reclose. At approximately (7:30 a.m.) on Oct. 24, a responding PG&E Troubleman patrolling the Geysers No. 9 Lakeville 230 kV line observed that CalFire had taped off the area around the base of transmission tower 001/006. On site CalFire personnel brought to the Troubleman’s attention what appeared to be a broken jumper on the same tower.”
Jumper cables are used on high voltage lines to route the wires around the metal tower so the electricity is not conducted into the structure. If a piece of hardware that supports the jumpers fails, the jumper wire breaks, or if it comes in contact with the steel tower, massive arcing will occur sending sparks and molten metal flying, which can ignite anything on the ground that is flammable.
The video below shows the ignition of the Kincade Fire on October 23 as seen in near infrared from a camera at Barham near Geyserville, California. Keep your eye on the bright light on the horizon left of center. It disappears at about 21:19:55 and 15 seconds later the fire can be seen growing rapidly.
Above: 3-D map of the Thomas Fire, looking north. The red line was the perimeter at 12:30 a.m. PST December 17, 2017.
Southern California Edison has reached an agreement to settle lawsuits with 23 public entities for taxpayer losses caused by wildfires attributed to the power company’s equipment. The settlement is related to damage and expenses incurred during and after three fires in 2017 and 2018, the Thomas Fire, Woolsey Fire, as well as the Koenigstein Fire which burned into the Thomas Fire. The agreement also addresses the debris flows that killed 20 people in Montecito when rains washed mud off the barren slopes of the Thomas Fire.
The $360 million settlement is for public entities only and does not affect the claims of residents, individuals, or businesses affected by the fires and debris flows.
“While this is not 100%, it’s not pennies on the dollar,” said John Fiske an attorney who represented local governments. “A lot of these communities … were hit very hard. In the aftermath of these wildfires, all sorts of public resources and taxpayer resources are lost.”
In December, 2017 the Thomas Fire burned over 281,000 acres and 1,000 homes in Ventura and Santa Barbara Counties in Southern California. The Woolsey Fire destroyed over 1,600 structures and burned nearly 97,000 acres north of Malibu, California in November, 2018.
The public entities involved in the agreement include Los Angeles County, Los Angeles County Flood Control District, Consolidated Fire Protection District of Los Angeles, Ventura County, Ventura County Watershed Protection, Ventura County Fire Protection District, City of Malibu, City of Agoura Hills, City of Calabasas, City of Hidden Hills, City of Thousand Oaks, City of Westlake Village, Conejo Recreation and Park District, Rancho Simi Recreation and Park District, Conejo Open Space Conservation Agency, Santa Barbara County, Santa Barbara County Flood Control and Water Conservation District, Santa Barbara County Fire Protection District, City of Santa Barbara, City of San Buenaventura, Montecito Water District, Montecito Fire Protection District, and Carpinteria Summerland Fire Protection District.