No One Is Owning Up to Releasing Cloud of Methane in Florida

Photo: Andrew Caplan / Gainesville Sun

July 27, 2020

By Aaron Clark and Naureen S Malik, Bloomberg Green

It was 12 miles wide, invisible to the naked eye and traveled across six counties to Florida’s largest city. And it’s still unclear who — or what — was responsible.

The mysterious plume of methane, estimated to total 300 metric tons, was released north of Gainesville between May 2 and May 3, when it reached Jacksonville, according to Bluefield Technologies Inc., which analyzed data from the European Space Agency’s Sentinel-5P satellite.

A global-warming agent that’s 80 times more potent than carbon dioxide, methane has become a major source of concern for environmentalists and climate-minded investors who are stepping up pressure on energy companies to curb emissions of the gas from oil fields, pipelines, gas storage facilities and power plants. Satellite observations are beginning to make those leaks more transparent. Last year, Montreal-based GHGSat Inc. identified a giant methane cloud apparently from an oil and gas field in Turkmenistan, billing it the first discovery of an unknown industrial methane release from space. 

Florida Methane Release

About 300 metric tons of methane was released near Gainesville, Florida between May 2 and May 3, spreading beyond Jacksonville.

“This capability means we no longer need to fight climate change blindfolded,” Yotam Ariel, the founder of Bluefield said. “We now have a tool to directly see what was once invisible and channel resources to reduce emissions quickly and effectively.”

The source of the Florida emission remains unknown, however. Its volume was equivalent to roughly 1% of total daily emissions from the U.S. natural gas system in 2018, Stanford University professor Adam Brandt said. Its epicenter was in Alachua County, according to Bluefield.

Staff at the Alachua County Environmental Protection Department “are unaware of any incidents that may have contributed to methane emissions” on those dates, Stacie Greco, a coordinator at the agency, said in response to a public records request. The county doesn’t have an air quality program and deferred reports of air emission violations to the state’s environmental agency. Alachua didn’t receive any reports of hazardous material spills on those days, she said.

The Florida Department of Environmental Protection, which tracks emissions and issues air permits, said it’s working to track down the source of the release.

“This scale seems like an industrial facility, power plant, or gas compression or handling system,” said Brandt, who studies methane emissions and called it “a significant leak.”

While the technology to spot leaks is improving, there can often be the challenge of pinpointing the perpetrator. There aren’t many industrial facilities nearby and among the closest potential heavy-emitter candidates are a natural gas pipeline system and power plants, public records show.

On April 24, Gainesville Regional Utilities requested an exemption for air permitting to replace a steam turbine generator at its J.R. Kelly power plant, which is less than 12 miles south of the epicenter of the methane cloud. The request was made because the switch would not result in an increase in usage or capacity of the plant, the utility said in a filing made to with Florida Department of Environmental Protection filing in June. “Consequently, the proposed work does not need an air construction permit to proceed,” GRU said.

GRU didn’t disclose the date for replacing the turbine, but said it planned to file performance test reports for the project on or after July 1, within 60 days of competing those tests.

At the southwestern rim of the plume, the utility owns two more power plants. The 471-megawatt Deerhaven Generating Station has units running on natural gas and coal that began operating in 1972 to 1996. Nearby is the 103-megawatt Deerhaven Renewable Generating Station, which burns woody biomass.

Energy Transfer LP’s Florida Gas Transmission has natural gas pipelines circling the area where the methane was detected and a compressor station north of the site. The company didn’t report any planned or unplanned outages at compressor station No. 16 in Bradford County, according to pipeline notices.

Weyerhauser Co., the Seattle-based forest products company, owns the land at the center of the May 2 methane emissions event, said Christine Berish, development review manager for Alachua County’s Department of Growth. “We don’t have any development projects in that area.”

GRU, Energy Transfer and Weyerhauser didn’t respond to requests for comment.

— With assistance by Hannah Dormido, Samuel Dodge, and Cedric SamUP NEXT

A Look Back: 10 years After The Largest Inland Oil Spill In The U.S.

Photo: NTSB

July 23, 2020

By Rebecca Williams, Michigan Radio

The worst oil spill into an inland waterway in U.S. history happened right here in Michigan, 10 years ago.

It happened on a Sunday evening: 5:58 p.m. on July 25, 2010. Enbridge’s Line 6B was carrying diluted bitumen. It’s a dark, thick oil from Canada’s tar sands.. The pipeline split open in a wetland near the small town of Marshall.

Oil gushed into Talmadge Creek, then the Kalamazoo River, polluting almost 40 river miles. Enbridge estimated more than 840,000 gallons of oil spilled. The EPA put the amount at more than 1 million gallons.

People who lived near the spill site, like Debbie Trescott, said there was an intense smell hanging in the air that Sunday.

 “I smelled this oil or gas or something. It was just a horrible smell and I knew then that something must be wrong,” Trescott said.

But Enbridge did not realize anything was wrong for more than 17 hours.

The control room operators were far away, in Alberta.

federal investigation later found those operators thought they had a pressure problem, and an issue called column separation, in the pipeline. They shut the pipeline down twice. And twice, they restarted it, sending massive amounts of oil through the ruptured pipeline.

81% of the oil that spilled was a result of those mistakes, according to the National Transportation Safety Board’s investigation.

People who lived nearby or spent time on the Kalamazoo River said the river ran black.

“The water going over the rocks didn’t sound like water going over the rocks. It almost sounded like a kid sucking on a super thick milkshake,” outdoorsman Craig Ritter told us.

“I think I can sum it up in one word and that is nightmare,” resident Deb Miller recalled. “The smell, I don’t even know how to describe the smell, there are no words. You could not be outside.”

Miller told us in 2011 she had health problems that lasted for months after the spill.

“The headaches were just absolutely intense, watering eyes. The cough, it was chronic,” Miller said.

In late 2010, the state health department issued a report on acute health effects from the oil spill. The report says people in the area had headaches, nausea and respiratory symptoms.

In the early days, there was a major wildlife rescue effort. Turtles, and muskrats and great blue herons were covered in oil. Rescue teams collected more than 2,000 birds and animals.

Back then, herpetologist Dave Mifsud said turtles made up the most of the wildlife rescued from the spill site.

“We had some, that were, their mouths were so tacky with the oil they could barely open their mouths. We saw some pretty devastating things,” Mifsud said.

The state is still monitoring the health of aquatic life in the area. The river re-opened for recreation in 2012. But it took many years to clean up and restore the river.

The main reason? The kind of oil that was spilled. Because it was so heavy and thick, a lot of it sank to the bottom of the river. Federal and state officials said that made the cleanup more difficult.

Two years after the spill, crews were still searching for oil on the bottom of the Kalamazoo River.

In 2012, Mark Ducharme with the state’s environment agency told us they were struggling to learn how to clean up this kind of oil.

“We’re writing the book on how to clean up oil sands out of cold water streams in freshwater systems. We’ve been looking elsewhere, we’ve been trying to find other examples – they’re just not there,” Ducharme said.

An investigation by the National Transportation Safety Board said the pipeline ruptured because of corrosion and cracking. It found that Enbridge was aware of six crack-like defects in Line 6B five years before the pipeline broke open. But did nothing to fix them. Investigators said there were quote: “pervasive organizational failures” by Enbridge. 

The NTSB also blamed weak regulations and “ineffective oversight” by the federal agency that oversees pipelines.

In a statement, Enbridge spokesman Ryan Duffy says the company transformed itself as a result of the spill. He says since 2011, Enbridge has invested more than $8 billion dollars on maintenance, inspection and leak detection across its crude-oil pipeline system. He says they’ve added staff to the control center and revised their procedures.


The Kalamazoo River where the incident occurred is clean and has been open to the public since 2012.

The result of the spill in Marshall is a company with increased awareness of safety and focused attention on proactive measures to maintain safe operation. Enbridge transformed itself to prevent a similar incident from happening in the future.

  • Since 2011, Enbridge has invested more than $8 billion on maintenance, inspection and leak detection across our crude-oil pipeline system. This is the largest, most comprehensive and sophisticated maintenance and inspection program of any pipeline system in the world.
  • We’ve increased the number of inline inspections conducted on the liquids pipeline mainline system using high-tech tools that are similar to mini-MRI machines.
  • Enbridge has added staff to the Control Center, while also revising and enhancing all control center procedures related to decision making, pipeline startup and shutdown, leak detection system alarms and communication protocols. We have also increased staffing for the emergency response and safety teams for our liquids pipelines system.
  • Enbridge has significantly increased its readiness to respond to any incident by conducting hundreds of emergency response drills annually to be sure the right equipment and trained professionals are in place and prepared to respond.
    • In the last several years, we have conducted thousands of exercises, drills and deployment events across the company. 

Carl Weimer heads the watchdog group Pipeline Safety Trust. He agrees: some things have improved since the Kalamazoo spill. 

“If they hadn’t spilled a million gallons I’m not sure there’d be this much attention to all the other lines in the Midwest right now,” he said.

Weimer said there have been several changes in the industry, including how control room operators are trained. And there are new federal regulations on pipelines that are just now going into effect this month, 10 years later.

“But there are good things in those rules, about how do you deal with oil spills, integrating risks so you don’t look at corrosion and cracking separately, you have to integrate those risks, that’s been changed,” he said.

But he said there’s one major thing that has not changed in the past decade.

Pipeline companies still do their own inspections.

“You know the regulators, when they say they inspect pipelines, they’re inspecting the paperwork, they’re not going out there and inspecting the pipeline, for the most part,” said Weimer. “So you have to trust the companies and you have to trust that the regulators are at least spending enough time on the paperwork and overseeing the company that there’s some hope there.” 

He said the federal agency that oversees pipelines doesn’t put their inspection reports online.

“You can get them if you go through the FOIA process, but sometimes that’s a godawful thing to try to do.” 

But Weimer said states can ask the federal government to do additional inspections.

“One of the things I’m surprised about that didn’t come out of Michigan is that the state still hasn’t stepped up and taken any regulatory authority over these types of pipelines. I’m surprised state of Michigan hasn’t done that,” he said.

A spokesman for the Michigan Public Service Commission says it’s true – states can ask to take on more inspection responsibility over pipelines that cross state lines. But spokesman Matt Helms said in a statement that first, the Legislature would have to make some changes to give his agency the authority to adopt federal pipeline rules. 

The Pipeline Safety Trust’s Carl Weimer noted the spill also woke a lot of people up to the existence of the pipelines that crisscross our region.

“I think a lot of the attention you’re seeing on Enbridge lines in, Wisconsin, Minnesota, the Upper Peninsula of Michigan, some of the tribal issues in northern Wisconsin, certainly the Line 5 now has all been heightened because of Enbridge’s spill,” said Weimer.

He said there is a lot more attention now to how pipeline companies assess their risks. But he says it’s unfortunate that in the U.S. we often don’t change laws or the way we do things until after a tragedy happens.

National Transportation Safety Board (NTSB) Enbridge Incorporated Hazardous Liquid Pipeline Rupture and Release 2012 Pipeline Accident Report and Related Recommendations

Industry Seeks Flexibility in Federal Pipeline Safety Rules for Rupture Response

Photo by Robert Nickelsberg/Getty Images

July 23, 2020

By Tom DiChristopher, S&P Global Market Intelligence

Proposed federal rules governing the response of natural gas pipeline operators to ruptures on their systems could have unintended consequences if the rules do not allow the companies adequate flexibility, the gas industry warned.

In lodging their concerns, industry representatives sought to influence the final version of rules proposed in February by the U.S. Pipeline and Hazardous Materials Safety Administration, or PHMSA. The long-overdue rules would require gas pipeline operators to install remote-controlled or automatic shutoff valves on certain new or replacement pipelines and meet new standards for isolating transmission lines following a rupture.

The rulemaking would satisfy congressional mandates and National Transportation Safety Board recommendations that sought to prevent problems that contributed to the 2010 pipeline disasters in San Bruno, Calif., and Marshall, Mich. In both cases, investigators said the operators’ failure to promptly shut off the supply to the lines exacerbated the catastrophes.

Government, industry and civil society representatives on PHMSA’s Gas Pipeline Advisory Committee, or GPAC, debated the technical feasibility, reasonableness, cost-effectiveness and practicability of the proposed rules during a remote July 22 meeting.

Regulating rupture response time

Several industry representatives argued against a proposed rule that would require pipeline operators to identify a rupture within 10 minutes of the initial indication. They said operators face the challenge of confirming information that arrives through several avenues. The 10-minute time limit would put pressure on companies to shut down a line even if they have not confirmed a rupture, potentially disrupting supply to manufacturers, residents and power plant operators without good reason, the industry representatives said.

Sudden demand spikes from large customers can produce changes in pressure typical of ruptures, particularly in the Northeast, according to Andrew Drake, vice president for asset integrity and technical services for gas transmission and midstream at Enbridge Inc. Control room operators may need more than 10 minutes to rule out a rupture after detecting a sudden pressure change, he said.

“I don’t think you want me to say, ‘Well, it’s 10 minutes — close the valve, boys, and shut off New England on a cold day in the winter,'” Drake said. “You want me to go through that diligent process. It may take me 12 minutes or 13 minutes, but I think the key is a performance standard probably saves everyone a lot of headaches.”

Richard Worsinger, director of North Carolina municipal utility Wilson Energy, said unnecessary pipeline shutdowns could cause significant difficulties for gas utilities by causing a loss of pressure that requires multiple visits to customer homes.

“That was a challenge before COVID-19 hit,” Worsinger said. “Now with many systems having a prohibition of employees entering customers’ homes [and] using contractors, or making sure we’ve got the right masks and [personal protective equipment], it’s even more problematic.”

GPAC members voted to eliminate the 10-minute threshold and to require companies to close valves within 30 minutes of identifying a rupture, down from 40 minutes in the proposed rule. The committee’s decisions help to inform PHMSA final rules.

Balancing safety and environmental protection

Royce Brown of Enable Midstream Partners asked PHMSA to consider allowing pipeline operators to leave rupture mitigation valves open during certain rupture events, provided that emergency responders approve the action.

Brown, who is responsible for pipeline integrity, said gas utilities have implored his company to avoid service shutoffs because customers do not want workers entering their home during the coronavirus pandemic. Public safety is sometimes best served by venting gas through open valves in rural areas, rather than shutting down service, in order to observe social distancing or avoid disruptions during cold snaps, he said.

Mary Palkovich, vice president for gas engineering and supply at Consumers Energy Co., said allowing valves to vent following damage to distribution systems could help companies identify potential repair locations without disrupting service during the winter.

The final rule should reflect that venting methane, a potent greenhouse gas, is not ideal, said Sara Gosman, an assistant professor at the University of Arkansas School of Law. “I think it’s important to point out that there are environmental consequences to continuing to release gas that we need to take into account here and balance against the safety set of issues,” said Gosman, who sits on the board of directors of the Pipeline Safety Trust, which represents the public on the GPAC.

PHMSA staff resolved to consider allowing certain valves to remain open in select circumstances, with consideration paid to minimizing environmental damage.

Wisconsin: Michigan Excavation Firm Sanctioned in Fatal Sun Prairie Explosion Yet to Pay $25,000 Fine

Photo: John Hart, Wisconsin State Journal Archives

By Toni Galli, WKOW, July 10, 2020

SUN PRAIRIE (WKOW) – The company found to have improperly done underground excavation before a deadly explosion in Sun Prairie in 2018 has yet to pay a state-ordered fine of $25,000.

“Two years later, they’ve yet to pay that fine,” says Executive Director Robb Kahl of Construction Business Group of Michigan-based, VC Tech. Kahl’s industry trade group is pushing for stricter enforcement and more regulation in connection to violations in digging projects.

Authorities say VC Tech failed to properly obtain a ticket from Diggers Hotline to bore underground, yet did directional drilling in downtown Sun Prairie and ruptured a natural gas line. A subsequent explosion killed responding Sun Prairie Fire Captain Cory Barr and injured others.

In August 2019, Wisconsin Public Service Commissioners fined VC Tech $25,000 for relying on an elapsed permission to excavate from Diggers Hotline and failing to obtain a necessary ticket from the safety organization. Commissioners also required the company’s leadership to take an educational course. Officials say that requirements have also been ignored.

State officials say they’re still pursuing the fine from the firm.

“The PSC has fully exercised the authority provided to us under state law to gain compliance from VC Tech, Inc.,” Public Service Commission Spokesperson Matthew Sweeney says. “We’ve referred the matter to other state agencies to facilitate collection.”

VC Tech attorney John Coleman has yet to respond to a request for comment from 27 News on the company’s intentions with the amount due the state of Wisconsin.

While PSC officials have the power to cite violators of rules relating to excavation, Kahl says there’s no teeth to sanctions. “They’re not consequential,” he says. “They’re not significant enough.”

Kahl’s group is also calling for state lawmakers to follow neighboring states by prioritizing the response to excavation mistakes.

“Unlike…Minnesota, Michigan, Indiana, Ohio, to name a few, we do not require utility strikes to be reported or investigated and that’s a problem,” Kahl says.

Kahl concedes the more than four thousand utility strikes in Wisconsin since 2018 typically involve no injury or collateral damage. But he says digging projects for utility, fiber optic, and water lines are only increasing.

“And once you start actually regulating an industry, word gets around pretty quick,” Kahl says. “The people who make it their business to cut corners realize they could get themselves in trouble.”

PSC officials say Wisconsin ranked third nationally in the most recent safety data in connection to incidents per underground infrastructure miles.

Sun Prairie explosion: Read the original reports about the blast that killed firefighter, damaged downtown

Pennsylvania: Family that Lost Hundreds of Trees to Failed Pipeline Project Settles with Company, Gets Land Back

Photo: Angela Vogel

By Susan Phillips, State Impact Pennsylvania, July 3, 2020

A Northeastern Pennsylvania family who watched as work crews, accompanied by armed federal marshals, destroyed their budding maple tree farm to make way for the failed Constitution Pipeline has settled with the company Williams for an undisclosed amount. A federal court has also vacated the eminent domain taking of about five acres, reversing an order it made more than five years ago.

“We’re really glad that it’s ended,” said Catherine Holleran, co-owner of the 23-acre property that has been in the family for 50 years. “We’ve gotten our land returned to us. That was our main objective right from the first.”

The Constitution Pipeline project would have carried Marcellus Shale gas  from Pennsylvania to New York state. Though the project received federal approval and the necessary permits from Pennsylvania regulators, New York blocked the pipeline by not issuing permits. Williams dropped the project in February.

The Holleran family of New Milford fought a lengthy battle to prevent the company from building the pipeline across their property. But in March 2016, the crews arrived at the 23-acre farm in rural Susquehanna County along with the federal marshalls, who wore bullet proof vests and carried semi-automatic weapons. The crew spent several days clearing about 558 trees, including some that were hundreds of years old.

In a 2018 statement filed with the court, Holleran described how the company left the trees lying on the ground, and did not remove them for a full year after the clear cut. The stumps were left in the ground.

Holleran described the stress weathered by her and her family.

“The entire ordeal has had an enormous emotional toll,” Holleran wrote. “The court proceedings followed by the armed guards on the property created immeasurable stress. …After the trees came down, I experienced a terrible period of despair.”

The Hollerans’ attorney Carolyn Elefant said the Hollerans are happy to have regained ownership of the farm.

“My clients are relieved to move on from the stress and uncertainty of the past few years,” Elefant said. “It was heartbreaking for the family to watch their trees come down, but with full ownership of the property restored and compensation paid, they can reclaim their land and replant their trees.”

Elefant said the family wants to continue to build upon their maple syrup business.

Holleran said she and her family want to work to change the Natural Gas Act, which governs how pipeline companies can seize private property through eminent domain. She said it’s difficult for individual landowners to take on large corporations, especially since the process is so legalistic and technical.

“That can create a lot of hardship for families,” she said. “You have to have a lot of money, and you have to have resources to even go that route, which is why a lot of people don’t.”

Williams could not be reached for comment.

DEVELOPING STORY: Court orders a shut down and removal of oil from the Dakota Access Pipeline

Photo: Amy Sisk/Inside Energy

Order says Dakota Access assumed much of its economic risk knowingly, and the potential harm each day the pipeline operates.

Indian Country Today, July 6, 2020

A federal judge has ordered the Dakota Access Pipeline to shut down and remove all oil within 30 days, a huge win for Standing Rock Sioux Tribe, the Cheyenne River Sioux Tribe, and the other plaintiffs.

“Following multiple twists and turns in this long-running litigation, this Court recently found that Defendant U.S. Army Corps of Engineers had violated the National Environmental Policy Act when it granted an easement to Defendant-Intervenor Dakota Access, LLC to construct and operate a segment of that crude-oil pipeline running beneath the lake,” said the opinion from U.S. District Judge James Boasberg.

The pipeline extends more than 1,000 miles from North Dakota to Illinois – but the issue is the portion of the project that is buried under the Missouri River. The Standing Rock Sioux tribe said a leak will contaminate their drinking water and sacred lands.

Late in the Obama administration the Corps of Army Engineers announced it would suspend approval of the project while an Environmental Impact Statement was prepared. “A few months later, however, following the change of administration in January 2017 and a presidential memorandum urging acceleration of the project, the Corps again reconsidered and decided to move forward,” the opinion said. “It granted the sought permit, construction was completed, and oil commenced flowing through the Dakota Access Pipeline. “

This the court found was a substantial error and a violation of the National Environmental Environmental Policy Act.

The bottom line: “The Corps had not been able to substantiate its decision to publish” only an Environmental Assessment and not an Environmental Impact Statement.

“Dakota Access’s central and strongest argument … is that shutting down the pipeline would cause it, and the industries that rely on it, significant economic harm, including substantial job losses,” the court said.

The pipeline company said it could lose $643 million in the second half of 2020 and $1.4 billion in 2021 if shut down. The court said: “All of these financial losses would be absorbed by the owners of Dakota Access,” particularly Energy Transfer Partners, the current parent company of DAPL after a merger with Sunoco.”

But Boasberg’s ruling is clear on that point. “Yet, given the seriousness of the Corps’ NEPA error, the impossibility of a simple fix, the fact that Dakota Access did assume much of its economic risk knowingly, and the potential harm each day the pipeline operates, the Court is forced to conclude that the flow of oil must cease.”

This story is developing and will be updated.

Energy Companies Abandon Long-Delayed Atlantic Coast Pipeline

Photo: Steve Helber, AP file photo

By Erin Cox and Gregory S. Schneider, Washington Post, July 5, 2020

The two energy companies behind the controversial 600-mile Atlantic Coast Pipeline on Sunday abandoned their six-year bid to build it, saying the project has become too costly and the regulatory environment too uncertain to justify further investment.

The natural-gas pipeline would have tunneled under the Appalachian Trail on its way from West Virginia through Virginia and into North Carolina, building an energy infrastructure proponents said would attract economic development to the region.

The abrupt abandonment sparked jubilation among environmental and community groups who had fought the pipeline all along its path, which included some of the most scenic and rugged terrain in Virginia. Property rights advocates in the Appalachians joined with an ashram in central Virginia and black Baptists from a rural county to make opposing the pipeline a high-profile political and social justice issue.

“The courageous leadership of impacted community members who refused to bow in the face of overwhelming odds is an inspiration to all Americans,” former vice president Al Gore and the Rev. William Barber, a civil rights leader, said Sunday in a joint statement. They had visited Virginia together to shed light on the pipeline’s impact on rural African American communities.

Virginia-based Dominion Energy and North Carolina-based Duke Energy spent $3.4 billion on the project, fighting regulatory battles that went all the way to the Supreme Court, which ruled favorably for the companies last month.

But company officials said in a statement that other recent federal court rulings linked to the Keystone XL pipeline have heightened the litigation risk, extended the project’s timeline and further ballooned the cost of the project, which had risen from an estimated $5 billion in 2014 to $8 billion today. When announced, the energy companies had hoped to have the pipeline operational by 2018.

“This announcement reflects the increasing legal uncertainty that overhangs large-scale energy and industrial infrastructure development in the United States,” Dominion chief executive Thomas F. Farrell II and Duke Energy chief executive Lynn J. Good said in a joint statement. “Until these issues are resolved, the ability to satisfy the country’s energy needs will be significantly challenged.”

The decision to cancel the Atlantic Coast Pipeline came the same day Dominion announced it would sell its other natural gas pipelines and storage assets to Warren Buffett’s Berkshire Hathaway Energy for $10 billion, focusing exclusively on state-regulated natural gas utility markets and some renewable energy projects. The deal is subject to regulatory approval and is expected to close in the fourth quarter of 2020.

Dominion is arguably the most powerful corporation in Virginia, and its commitment to the pipeline made the company a political target in the past several years after a new generation of Democrats won control of the state legislature. Faced with leaders in the General Assembly who pledged to weaken Dominion’s influence in Richmond, the utility cooperated this year on legislation that requires it to phase out carbon-based energy by 2050.

Just last week, Dominion touted completion of the initial phase of a wind farm project it is developing 27 miles off the coast of Virginia Beach that is slated to be the biggest in the country.

A spokeswoman for Gov. Ralph Northam (D) said Sunday that he had spoken “with Dominion Energy leaders today and told them he supports this decision and the company’s transition to clean energy.”

In West Virginia, U.S. Sen. Joe Manchin III and Attorney General Patrick Morrisey (R) said in separate statements they were disappointed the companies chose to walk away from a critical infrastructure investment.

“The pipeline would have created good paying construction and manufacturing jobs for hard working West Virginians, reinvested in our energy markets increasing our domestic energy supply, and strengthened national security with reliable energy to key military installations,” said Manchin, the ranking Democrat on the Energy and Natural Resources Committee.

The Virginia Chamber of Commerce also lamented losing the potential economic benefits of the pipeline, saying it was projected to support 8,800 jobs and $1.4 billion in economic activity in the state.

“Unfortunately, today’s announcement detrimentally impacts the Commonwealth’s access to affordable, reliable energy. It also demonstrates the significant regulatory burdens businesses must deal with in order to operate,” Virginia Chamber President Barry DuVal said in a statement.

Environmental advocates had stalled the project with court challenges in which judges found that the federal permitting process had been hasty and slipshod. With permits being reevaluated, work on the pipeline in Virginia has been paused for more than a year and a half.

“This is a victory for all the communities that were in the path of this risky and unnecessary project,” the Southern Environmental Law Center, which represented conservation groups in many of the court challenges, said in a statement.

“Finally, after causing so much pain and worry for so many, these companies have made a decision that is actually in the interest of their customers and the people their actions affect,” said David Sligh, a former Virginia environmental regulator who is conservation director of the advocacy group Wild Virginia.

Dominion and Duke cited a May 28 ruling by a U.S. District judge in Montana as a death knell to the Atlantic Coast Pipeline project.

The ruling threw into question the U.S. Army Corps of Engineers’ permitting program, known as Nationwide 12, which allowed gas and oil pipelines to traverse wetlands and bodies of water. Energy industry experts said the decision, made in a case brought to block the Keystone XL oil pipeline from Canada, ultimately endangered as many as 70 other projects across the country.

The legal challenges, Dominion and Duke officials said, made it impossible to reliably calculate whether Atlantic Coast Pipeline construction could continue this year or how far it would be pushed into the horizon.

The cancellation comes despite President Trump’s efforts to bolster oil and gas pipelines across the country by weakening enforcement of some of the country’s landmark environmental laws, including provisions of the Clean Water Act, the Endangered Species Act and the National Environmental Policy Act.

Columbia Gas Sentenced in Connection with September 2018 Gas Explosions in Merrimack Valley

Photo: Nina Flores and jliss 1979 via CNN

June 23, 2020

U.S. Department of Justice Press Release

Company to sell its business in Massachusetts and pay $53 million fine, the largest criminal fine ever imposed under the Pipeline Safety Act

BOSTON – Columbia Gas of Massachusetts (CMA) was sentenced today in connection with the gas explosions on Sept. 13, 2018, in Lawrence, Andover and North Andover that killed one individual, injured 22, and damaged homes and businesses.

Bay State Gas Company, d/b/a Columbia Gas of Massachusetts, was ordered by U.S. District Court Chief Judge F. Dennis Saylor IV to pay a criminal fine of $53,030,116 which represents twice the amount of profits that CMA earned between 2015 and 2018 from a pipeline infrastructure program called the Gas System Enhancement Plan (GSEP). In addition to a fine, the Court also sentenced CMA to a three-year period of probation during which CMA’s operations will be subject to a monitor to ensure CMA’s compliance with federal and state safety regulations. The three year period of probation will continue until CMA is sold to a qualified buyer.

In February 2020, the company agreed to plead guilty to violating a minimum safety standard of the Natural Gas Pipeline Safety Act relating to the failure to implement procedures to prevent the over-pressurization of its low-pressure gas distribution system in South Lawrence during a pipe replacement project known as the South Union Project.

“We expect utility companies operating in our communities to do so safely and responsibly,” said United States Attorney Andrew E. Lelling. “Instead Columbia Gas acted with reckless disregard for safety by cutting corners and relying on lax protocols. The result was catastrophic – stealing one life, harming dozens and impacting the home and livelihoods of hundreds more. Today’s sentence serves as little comfort to the victims, but is another step towards terminating Columbia Gas’s business in Massachusetts.”

“Today’s sentencing of Columbia Gas makes clear that those entrusted with the public’s safety have a solemn obligation to make it their highest priority,” said Douglas Shoemaker, Regional Special Agent in Charge, Department of Transportation Office of Inspector General.  “Pipelines are a critical part of our Nation’s infrastructure, and working with our Federal, state and local law enforcement and prosecutorial colleagues, we will continue to protect the safety and integrity of our pipeline transportation system from violations of regulation and law.”

“With today’s sentence, Columbia Gas of Massachusetts has finally been held criminally and financially responsible for their sheer greed and reckless disregard for public safety. That said, we realize that the excruciating pain, suffering, and heartbreaking loss of life the citizens of Merrimack Valley endured is beyond reparation,” said Joseph R. Bonavolonta, Special Agent in Charge of the FBI Boston Division. “It is the FBI’s hope that the departure of Columbia Gas from Massachusetts will bring the residents of these cities and towns some much-needed peace of mind.”

The U.S. Attorney’s Office has also entered into a Deferred Prosecution Agreement (DPA) with CMA’s parent company, NiSource, Inc. based in Indiana. As part of the DPA, NiSource has agreed to undertake their best reasonable best efforts to sell CMA after which NiSource and CMA would stop all gas pipeline operations in Massachusetts. In exchange for the U.S. Attorney’s Office’s agreement to defer prosecution of NiSource, NiSource has also agreed to forfeit any profit it may earn from the sale of CMA and implement each of the safety recommendations from the National Transportation Safety Board (NTSB). 

During the afternoon of Sept. 13, 2018, the over-pressurization of a low pressure gas distribution system in South Lawrence caused multiple fires and explosions in the communities of Lawrence, Andover and North Andover. As a result, one individual in Lawrence was killed and another severely disabled, 22 people were injured and approximately 131 residential homes and commercial buildings were damaged.

CMA recklessly disregarded a known safety risk related to regulator control lines – sections of pipe connected to regulator stations that helped monitor and control downstream gas pressure. By at least 2015, according to an internal company notice, CMA knew that the failure to properly account for control lines in construction projects could lead to a “catastrophic event,” including fires and explosions. Aging cast iron pipes were being replaced, but the failure to remove or relocate control line pipes that were later abandoned would automatically cause regulator stations to continually increase pressure to the point of dangerous over-pressurization.

The DPA with NiSource acknowledges the fact that NiSource has previously made substantial voluntary restitution payments to the victims of the September 2018 incident, and has agreed to seek to resolve all pending civil claims. Most of the $53 million fine will be directed to the Justice Department’s Crime Victims Fund, which is a major funding source for victim services throughout the United States. 

For more information regarding the case, please visit:

U.S. Attorney Lelling, DOT-OIG SAC Shoemaker and FBI Boston SAC Bonavolonta made the announcement today. Critical assistance was provided by the Massachusetts State Police and Lawrence Fire Department. Assistant U.S. Attorneys Neil J. Gallagher, Jr. and Evan Gotlob of Lelling’s Public Corruption and Special Prosecutions Unit prosecuted the case.

Feds Green Light Use of Trains to Transport LNG

Photo: Chart Inc. 2013

June 27, 2020

By Tim Faulkner, ecoRI News

President Trump has followed through on his pledge to allow trains to transport liquefied natural gas (LNG), a decision opposed by environmental groups and 15 states, including Rhode Island and Massachusetts.

The U.S. Pipeline and Hazardous Materials Safety Administration (PHMSA) issued the final rule June 19. The regulation takes effect 30 days later.

Prior to the agency’s final decision, objections were raised via online comments from across the country. Washington Gov. Jay Inslee said the rule was illegal because it lacked required environmental and safety reviews.

“This proposed rule is rushed and ill-advised, and, if finalized, will pose a serious risk to public health and safety — not just in my state but nationwide,” Inslee said.

Others noted the health risks from a leak or fire, especially in densely populated urban areas. They accused PHMSA of rushing approval to benefit the domestic fracking industry.

“We must not be used as guinea pigs by this untested and high-consequence rush to grease the rails for special interests,” wrote Tamar Dick of Bethlehem, Pa.

Dick noted that LNG volume expands significantly when released in the air and is “capable of a far-reaching catastrophe, including a fire too hot to extinguish.”

PHMSA argued in its decision that the rule change was necessary to address regional inadequacies in natural-gas pipeline infrastructure. The federal agency said more natural gas is needed to satisfy growing domestic and international markets.

Train transportation, the agency maintained, is less risky than shipping by highway. LNG is similar to other flammable, cryogenic liquids currently transported by rail. The rule requires the use of an existing class of tank cars, called DOT-113, that is refrigerated and protected with a double-pressure vessel design.

The National Transportation Safety Board (NTSB), however, has refuted some of PHMSA’s claims, saying a thorough safety assessment of the DOT-113 tank cars is needed because the colorless, odorless gas is easily ignitable and hard to detect.

“Specifically, an analysis should address fireballs, flash fire, and explosions from ground-level vapor clouds that may expand far beyond the point of release to an ignition source,” according to a letter signed by Robert L. Sumwalt III, chairman of the NTSB.

The NTSB also noted that many more LNG tank cars will be traveling by rail than projected by PHMSA. Without added safety equipment and testing certifications, there isn’t enough data proving LNG can be transported safely, according to the safety board. The NTSB said lower train speed limits should be mandated in high-risk urban areas, special braking is needed, and training required to detect leaks and gas accumulations.

“We believe the risks of catastrophic LNG releases in accidents is too great not to have operational controls in place before large blocks of tank cars and unit trains proliferate,” Sumwalt said.

Sumwalt noted that derailments of DOT-113 tank cars, although rare, can release larger quantities of hazardous material than a truck accident, and that federal regulators have a poor track record of responding to “fiery flammable-liquids accidents.”

The Pennsylvania Independent Oil & Gas Association argued that the refrigerated rail cars have been proven safe to transport flammable cryogenic liquids such as ethylene and hydrogen. Increasing transportation options, the trade group argued, would allow natural-gas producers to make more money selling the fossil fuel around the world.

In a 43-page letter sent earlier this year, attorneys general from 15 states called for safety studies and a full environmental impact report. They noted that LNG would travel through densely populated areas in trains of up to 100 tank cars, on the same rail line used by high-speed passenger trains.

The “finding of no significant impact” by PHMSA, according to the letter, is fundamentally flawed and failed to consider the expected greenhouse-gas emissions attributable to the extraction and use of natural gas and the potential harm to public safety and the environment from accidental releases of LNG.

The letter explained that, in the event of a spill, vaporization creates an extremely cold, gaseous vapor cloud that can embrittle steel, cause severe burns, damage infrastructure, and further complicate an emergency response.

The Surfrider Foundation has pointed to a government study that put the hazard range of such a vapor cloud at more than 1.5 miles.

Under the new rule, there are no limits placed on where LNG trains can travel. Instead, the rail companies must evaluate 27 safety and security risk factors when considering potential routes.

The decision doesn’t mention frontline communities or health and environmental justice areas.

The other states objecting are California,Delaware, Illinois, Maryland, Michigan, Minnesota, New Jersey, New York, North Carolina, Oregon, Pennsylvania, Vermont, and Washington. The District of Columbia also opposes the rule.

NTSB Pipeline Preliminary Report: Enbridge Inc. Natural Gas Pipeline Rupture and Fire in Hillsboro, KY on May 4, 2020

Fleming County, Kentucky hillside burnt by gas pipeline rupture and fire on May 4, 2020. Photo: Screencapture Via WLEX

Executive Summary

The information in this report is preliminary and will be either supplemented or corrected during the course of the investigation

On May 4, 2020, at 4:36 p.m. local time, a 30-inch-diameter natural gas transmission pipeline owned and operated by Enbridge Inc. (Enbridge) ruptured near Hillsboro, Kentucky. The resulting fire burned vegetation over 5 acres of heavily forested land. (See figure.) There were no injuries, fatalities, or evacuations. About 148 million cubic feet of natural gas was released during the rupture and resulting emergency response blowdown.[1] A parallel pipeline in the same right-of-way ruptured at a location about 100 miles away in Danville, Kentucky, on August 1, 2019. In that 2019 accident, one person died and five nearby residents were injured when a rupture released natural gas and ignited. Preliminary information indicates the two events are not related. The 2019 accident is also being investigated by the National Transportation Safety Board (NTSB).[2]

A member of the public notified Enbridge gas control of the rupture at 4:40 p.m. At the same time, a field technician was notified of the rupture by a friend at 911 dispatch. Gas controllers did not observe any rate-of-change alarms, as Enbridge does not employ the use of rate-of-change alarms on the suction side of their compressor stations.[3] Field personnel isolated the damaged system by closing manual valves at the Owingsville Compressor Station and the Muses Mill Valve Station 44 minutes later.

The rupture occurred at a girth weld and resulted in a crater that was about 20-feet wide.[4] No pipe was ejected by the rupture and no structures were damaged by the ensuing fire. The failed pipeline, Line 10, was a 30-inch-diameter transmission line that transported natural gas between Mississippi and Pennsylvania. At the time of the rupture, Line 10 was flowing north-to-south and was operating at 657 pounds per square inch, gauge (psig), which is within the normal pressure range for this segment during this time of year.[5] At the failure site, Line 10 was the northernmost of three parallel pipelines along the same right-of-way. The failure occurred at milepost 509.9, about 8 miles northeast of the Owingsville Compressor Station. This portion of Line 10 was installed in 1952 and was manufactured by National Tube Works.

In 2018, Enbridge initiated a geohazard management program to identify and assess areas of increased geohazard risk. Geohazard threats encompass a wide variety of geological conditions that can affect the integrity of pipelines, including landslides, sinkholes, frost heave, and earthquakes. On October 9, 2018, the area around the Line 10 rupture was identified as one of these areas of increased geohazard risk. Enbridge planned to remediate the pipelines at that location sometime in 2020 by alleviating strain where necessary and installing strain gauges to further monitor the force on the pipeline.

The NTSB’s investigation into the Hillsboro accident is ongoing and will include a metallurgical examination of the pipe, a geohazard causation assessment, and an evaluation of Enbridge’s supervisory control and data acquisition alarm management and its geohazard management program.[6] The NTSB also plans to examine data gathered from a rupture that occurred under similar circumstances on Enbridge’s Line 10 in Summerfield, Ohio, on January 12, 2019. According to the Pipeline and Hazardous Materials Safety Administration (PHMSA), that rupture was caused by “ground movement overstressing a girth weld to failure.”[7] Due to the similarities, the Summerfield rupture may help inform the direction of the NTSB’s Hillsboro investigation. Parties to the investigation include PHMSA and Enbridge.

  1. During a blowdown, the natural gas in the pipeline is vented to the atmosphere in a controlled manner to lower the pressure in the pipeline to atmospheric pressure (zero gauge).
  2. For more information on the August 1, 2019, accident, see National Transportation Safety Board, Enbridge Inc. Natural Gas Pipeline Rupture and Fire, Danville, Kentucky, August 1, 2019 PLD19FR002 (Washington, DC: National Transportation Safety Board, 2019).
  3. The suction side of a compressor station is the input side. At a compressor station, lower-pressure gas is taken in on the suction side, compressed, and then discharged at a higher pressure on the discharge side.
  4. Girth welds are used to connect two pipes along their circumference.
  5. Line 10 is a bidirectional pipeline with a maximum allowable operating pressure of 936 psig when flowing north to south.
  6. Supervisory control and data acquisition is a system used to control and monitor complex systems, such as natural gas transmission pipelines.
  7. Pipeline and Hazardous Materials Safety Administration, Enbridge/Texas Eastern Summerfield Natural Gas Release (Washington, DC: US Department of Transportation, Pipeline and Hazardous Materials Safety Administration, 2019).