Methane emanating from coal mine powers plant’s electricity

Oxbow Mining LLC, owner of Elk Creek Mine in Somerset, is capturing methane from the mine to power a new $6million plant that is generating electricity.

The sharp slowdown of coal production at the Elk Creek Mine in Somerset this year hasn’t prevented the ramping up of electricity generation at a new plant powered by methane emanating from the site.

A $6 million plant reached full operational capacity by September, said Auden Schendler, vice president of sustainability for the Aspen Skiing Co., which invested $5.5 million into the project because of its environmental benefits.

The first of the plant’s three generation units went into operation later last year, making Elk Creek the first active underground coal mine west of the Mississippi River where electricity is being generated from methane.

Fortunately, the plant’s methane supply, even in the long term, shouldn’t be affected by mine production problems that began Dec. 2 of last year.

That’s when the mine suffered what’s called a “bump,” or basically a “catastrophic failure” of support pillars in a previously mined-out area, as the incident is described by Mike Ludlow, executive vice president of Oxbow Mining LLC. Oxbow owns the mine and itself is owned by billionaire Bill Koch.

The bump created an air blast that disrupted normal ventilation of the mine, eventually leading to spontaneous combustion and an unseen fire that the mine was able to detect through a rise in carbon monoxide and other gases.

The situation required everyone to be withdrawn from the mine in early January, but miners were later brought back to work in other areas where it was safe. Officials have given up on being able to recover its longwall mining equipment, which is worth tens of millions of dollars and is in an area sealed off after the incident to try to cut off oxygen supplying the fire. Forced to abandon the equipment and the part of the mine it was in, the company laid off about 150 workers at the start of October.

Mining is occurring now at a limited level as 134 remaining workers prepare a new lease area for production for future longwall mining.

“We’re actively pursuing acquiring another longwall mining system,” Ludlow said, but there’s no timeline for getting one bought and installed.

As it happens, the new power plant’s operation doesn’t rely on continuing full-bore mine production, or for that matter any production at all.

“We’re still draining methane from the mine and the methane generators are running. We expect it to continue for the long term,” said Ludlow, although he said reconstruction of some concrete wall mine seals next summer could cause some temporary interruption in generation.


The reason generation can continue even without much coal production is because the mine “is in effect a big gas well,” Ludlow said.

“It continues to liberate methane just like a gas well would.”

As in the case of a well, methane production will deplete over the years, and Ludlow said he’s not sure how long that will take. But it won’t be overnight, and it will continue to drain the surrounding geologic strata even without active mining, he said.

“We expect it to go 30 years,” Schendler said about the plant.

He said that even as the plant was being planned, it wasn’t clear whether the mine would be able to continue operating more than a few years anyway. But the business pro forma for the generation project nevertheless was able to assume a 15-year life span, and Schendler’s optimism about operations lasting twice that long are based on things such as an analysis of gas production in the geology in the mine.

“One of the first iterations, in France, of this technology, it was developed 30 years ago and it’s still going,” he added.

Gas wells in Garfield County have been producing for decades, after hydraulic fracturing was used to crack open formations and foster flow.

“A way to think about coal mining is it’s manual fracking, so they’ve fracked this area and it’s producing gas. It will continue to produce whether the mine is open or not,” Schendler said.

The broad-based partnership in the methane-capture project also includes Oxbow’s sister company, Gunnison Energy, which owns the oil and gas rights in the mine area; Denver-based Vessels Coal Gas, Inc.; and Holy Cross Energy, a utility based in Glenwood Springs that is buying the electricity.

The project makes use of gas that previously was being vented into the atmosphere. Methane is considered more than 20 times as potent as carbon dioxide as a greenhouse gas.

Aspen Skiing got involved in part because it is worried about the long-term impacts on its business from global warming, and it also didn’t want to see methane going to waste.

With all three generating units now running, the 3-megawatt facility produces enough electricity to meet the needs of about 2,000 homes, or the equivalent of all of Aspen Skiing’s operations, including four mountains as well as hotels and restaurants.



Aspen Skiing’s role is simply as an investor in the project, and it is interested in helping build another 15 megawatts or more additional electricity production at the Oxbow mine.

“The big challenge is getting a contract from a utility that pays enough that you can do the project,” Schendler said.

“Essentially if you don’t care about the carbon benefits, (the) carbon intensity of your power, there’s not really an incentive to buy this kind of power over cheaper power,” he said.

One interested entity is the Delta-Montrose Electric Association, but it’s currently constrained by its contract with its electricity provider, Tri-State Generation and Transmission Association, of which DMEA is one of 44 member-owners.

Schendler said it’s hard for a “little boutique project” like a methane-capture plant, which taps free gas but has high costs, to compete with big-scale power available to Tri-State and generated by coal and natural gas.

“By far on (reduced) carbon intensity it crushes any other kind of power production but we don’t have a carbon tax so it’s not reflected in the market,” he said.

DMEA general manager Dan McClendon said his utility would love to tap gas from coal mines in the North Fork Valley, in part as a way of supporting the local economy.

However, it is required under its Tri-State contract to obtain 95 percent of its power from Tri-State, and DMEA has reached its 5 percent cap for locally produced power.

This year it completed its South Canal hydroelectric project near Montrose.

While DMEA has asked Tri-State to relax the 5 percent cap, “we are coming up against a wall right now,” McClendon said.

Controversial state legislation passed this year will require Tri-State to get 20 percent of its power from renewables by 2020. Methane from coal qualifies as a source under the legislation.

But McClendon thinks Tri-State will meet that goal by buying renewable energy credits through a marketplace, which could result in cheap wind and other renewable projects being funded, even outside Colorado. Tri-State’s goal is to be a low-cost provider, and wouldn’t be interested in paying a premium for coal mine methane power, he said.

But McClendon thinks the Environmental Protection Agency’s plans to require reduced carbon emissions from coal power plants will make renewable energy more cost-competitive.

“That is going to make it such that (coal mine) gas will one day be affordably tapped and generation can come from it. It has a lot of value from that standpoint as far as I’m concerned,” he said.


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