Almost two months after a ruptured pipeline sent at least 210,000 gallons of oil flowing through a neighborhood in Mayflower, Ark., the line’s owner—oil giant ExxonMobil—remains largely silent on the future of its failed pipeline.
Most of the visible oil has been removed from the neighborhood and the ruptured section of pipe has been replaced and reburied. Yet Exxon hasn’t asked the U.S. Pipeline and Hazardous Materials Safety Administration (PHMSA) for permission to restart the 850-mile Pegasus line, which runs across four states from Patoka, Ill. to Nederland, Texas.
A company spokesman said Exxon is simply being thorough and cautious.
“This pipeline will not be restarted until we are convinced it is safe to do so,” said Aaron Stryk. “We need to identify the cause of the incident and the mitigation steps necessary to prevent an incident like this from occurring again.”
Some industry analysts say there could also be other reasons for the delay. The 65-year-old Pegasus line could be riddled with defects and require extensive repairs. Or perhaps Exxon is considering other alternatives, including replacing the Pegasus with a larger line.
The Pegasus pipeline is one of the few pipelines currently supplying a heavy Canadian crude oil known as diluted bitumen, or dilbit, to refineries on the Texas Gulf Coast. But at 20 inches in diameter, it can carry only about 95,000 barrels or 3.9 million gallons per day. That’s roughly a tenth as much as the 36-inch Keystone XL pipeline would carry to the coast if it is approved. The Keystone also would carry dilbit.
In order to reopen the Pegasus pipeline, Exxon must comply with the corrective action order PHMSA issued two days after the March 29 spill. The order lists a dozen conditions the company must meet, including tests on the section of pipe that burst and a comprehensive safety evaluation of the entire pipeline.
On May 2, Exxon appealed four of these conditions, including PHMSA’s stipulation that it operate the line at a lower pressure when it is restarted. The appeal did not challenge PHMSA’s pipeline integrity requirements or mention the company’s plans for the line.
On May 10, PHMSA granted two of those requests but rejected the other two, including the request for a higher pressure if the line is restarted.
Peter Howard, president of the Canadian Energy Research Institute, a nonprofit energy and environmental research organization, said the lengthy shutdown is unusual.
After a 41-year-old pipeline owned by Enbridge Inc. spilled more than a million gallons of dilbit into Michigan’s Kalamazoo River in 2010, Enbridge filed for permission to restart the line 13 days later. That request was denied and the line was restarted almost two months after the accident, which was the largest inland oil spill in U.S. history and is still being cleaned up today.
Two years later, another Enbridge pipeline burst in Wisconsin, spewing 50,000 gallons of dilbit into a pasture. Enbridge got permission to restart that line eight days later.
Howard thinks Exxon’s caution may be part of the company’s business approach.
“To them, the most embarrassing thing would be to restart it and come across another leak,” he said. “I think you’ll find that in all cases, especially with older lines, they’ll take the opportunity to inspect them inside and out.”
Carl Weimer, executive director of the Pipeline Safety Trust, a nonprofit watchdog organization based in Bellingham, Wash., said clues about why Exxon isn’t pushing harder to get the line reopened might be found in tests Exxon conducted on the line in February, two months before the rupture.
Exxon used a sophisticated monitoring device known as a pig to inspect the interior of the pipeline along the section that ruptured. The test is designed to detect cracks or flaws.
“The answers could be in those findings,” Weimer said. “Generally what you would expect to get out of that is whether the rupture was an anomaly that can be fixed or does the test show that the whole pipeline has similar problems that need to be addressed.”
Stryk, the Exxon spokesman, said data from the pigging is still being evaluated and that the results will be shared with PHMSA “in the coming months.”
Because the Pegasus is a small pipeline, the consequences of an extended shutdown aren’t too dramatic, said Martin Tallet, president of EnSys Energy, a business management consulting company that prepared a report on the Keystone XL’s impact on oil markets for the U.S. Department of Energy.
Nevertheless, he said, the oil that normally would flow though the Pegasus pipeline isn’t getting to the refineries.
“That brings up the question of the flexibility for the refinery to find an alternative to the crude or absorb the loss,” Tallet said.
Stryk wouldn’t disclose the names of the companies that receive oil from the Pegasus or discuss the financial impacts of the line’s closure.
John Stoody, director of government and public relations for the Association of Oil Pipe Lines, a Washington D.C.-based industry organization, said the closure of any oil pipeline has some kind of effect.
“Every pipeline, every amount of oil transported is accounted for in terms of meeting the energy needs of the country,” Stoody said. “So no matter the size of the pipeline delivering oil to the refineries, that oil is part of a pretty precise calculation designed to meet those energy needs.”
Bruce Bullock, director of the Maguire Energy Institute at Southern Methodist University Cox School of Business in Dallas, said Exxon is financially stable enough that it doesn’t need to rush the Pegasus pipeline back into operation.
“They have the wherewithal to be able to step back and make informed decisions on how best to move forward,” Bullock said.
That includes everything from considering the possibility of replacing the pipeline to improving the existing line.
As part of that assessment, Bullock expects Exxon executives to evaluate the demand for Canadian tars oil on the Gulf Coast and consider how massive projects like TransCanada’s Keystone XL pipeline and Enbridge’s pipeline expansion plans might affect business on the Pegasus.
“I think there’s going to a lot of wait and see,” he said.
Exxon is a major oil sands producer as well as a pipeline operator. At its Cold Lake oil field in Alberta alone, Exxon extracts 123,000 barrels of bitumen a day from 4,000 wells using steam injection, according to the company’s 2012 Operating and Financial Review. At another of its Alberta sites, Exxon estimates 4 billion barrels of bitumen is available for extraction.
The March 29 spill in Arkansas forced the evacuation of 83 people from almost two dozen homes and raised health concerns for those exposed to fumes from the oil. Exxon is maintaining a high profile in the community, replacing damaged landscaping, cleaning pollution from a secluded section of a shoreline and making buy-out offers to affected property owners.
Exxon put the cost of the spill at $16.4 million in an April 26 PHMSA accident report.
The northern 648-mile section of the pipeline, which includes the portion that burst, is 65 years old and is buried an average of 24 inches below ground. An examination of the failed section showed a split 22 feet long and 2 inches wide that allowed the oil to spew out under high pressure. The southern section of the line is 59 years old.
Exxon has said it shut down the pipeline within 16 minutes of discovering a pressure drop on the line, but enough oil spilled over the next three hours to affect aquatic animals and wildlife; contaminate the soil, coat vegetation and taint surface water, according to the April 26 accident report.
The report said an estimated 5,000 barrels—210,000 gallons, or enough to fill about a third of an Olympic-sized swimming pool—of heavy crude oil poured from the ruptured pipeline. Of that, 2,000 barrels—84,000 gallons—had been cleaned up by April 26. The report also noted that 2,000 barrels of the oil had fouled drainage ditches and a cove south of Lake Conway, a popular recreation area renowned for its fishing and scenic setting.
InsideClimate News reporter Lisa Song contributed to this report.