Carbon dioxide requirements will require ‘major changes’ in electricity generation
BISMARCK — As North Dakota begins drafting a plan to reduce carbon dioxide emissions by 45 percent in the state as recently mandated by the U.S. Environmental Protection Agency, utility companies stand behind state actions and offer input.
“The state has been very proactive,” said Dale Niezwaag, senior legislative representative for Basin Electric Power Cooperative, adding that Basin has had regular meetings with state officials.
The companies support Attorney General Wayne Stenehjem’s filing a lawsuit to fight the EPA’s Clean Power Plan in court as well as developing a state implementation plan in tandem should legal challenges fail.
“It’s so much better than having the federal government impose one,” said Eric Olsen, vice president and general counsel for Great River Energy Power Cooperative.
“It’s going to be really tough,” said Dave Glatt, environmental health section chief for the North Dakota Department of Health. “I don’t think we’re going to be able to meet the plan’s stringent requirements without some major changes in how we generate electricity.”
Regional partnership needed
All of the utilities encourage a system in which credits can be purchased or exchanged while taking into consideration their operations in multiple states.
“I think it would be better if we could use fleet-wide flexibility,” said Abbie Krebsbach, environmental director for Montana-Dakota Utilities Co.
Besides North Dakota, MDU has plants in Montana, Wyoming and South Dakota. The company also has the benefit of the 107-megawatt Thunder Spirit Wind Farm coming online by the end of the year, which may earn the company some rate credits should a rate-based plan be adopted.
The big question is rate versus mass, Niezwaag said. States have the option of adopting a plan that limits carbon to a specific mass produced or a rate of carbon production.
Mac McLennan, president of Minnkota Power Cooperative, said, in some situations, such as if a plant needed only 100,000 credits to continue operating, he would like for his company to have the option to buy it from someone else.
But Basin is not counting on credits and questions how much it will cost.
“A lot of utilities want to buy credits,” Niezwaag said. “We’re not convinced there’s going to be enough out there.”Looking for more time
All of the utilities are supportive of the state seeking a two-year extension to complete its plan once it has been filed with the EPA.
“The final rule came out so massively different,” said Niezwaag, adding that Basin has eight to 10 people whose sole job is to interpret the EPA rule.
However, Basin still does not have a complete understanding of the rule’s effects, Niezwaag said.
“We’ll have more time to develop (a plan), but implementation is going to be squeezed,” said Niezwaag, adding that infrastructure development takes a minimum of five years when taking into account engineering and permits.
Rate vs. mass
Not knowing the method to be used for measuring carbon emissions — rate of production or mass produced — is leaving the utility companies with many unanswered questions.
“We really don’t know what the state is thinking at this point,” Kresbach said. “We haven’t put any cost together because too many variables are not defined. ... Until it’s defined how allowances are allocated, it’s hard to know which would be least costly.”
Niezwaag said rate might be better for Basin, but the company is still trying to understand the rule’s restrictions on accounting for growth.
“We’ve got a lot of growth coming up that we’re going to have to meet, and it’s important for us to keep what we have running plus add more,” he said.
Niezwaag said Basin is aggravated that the wind and gas development it has done doesn’t count toward meeting its emission goals. The company has reduced generation from 80 percent coal 15 years ago to 58 percent today.
“We thought we would have excess credits because of wind power,” said Niezwaag, adding that Basin had hoped to use it in Wyoming, where it has more coal power. “We felt we had a good plan in place. It was going to cost but not out of hand.”
Now, Basin is looking into GRE’s DryFining technology, which reduces carbon by drying down coal and making it burn more efficiently. At the company’s Dry Forks Station in Wyoming, Basin is allowing people to come in and test developing technologies on its flue gas and, in 2010, the company evaluated carbon capture on its Antelope Valley Station. The cost went from $300 million to $500 million, and the company found it was unaffordable.
As far as its preparations for the changes, Otter Tail Power Cooperative’s manager of public relations, Stephanie Hoff, said Otter Tail is always working on efficiency improvements, including an air quality control system installed at one of its plants in South Dakota.
Federal modeling is wrong
Those affected agree that a model plan developed by the U.S. Environmental Protection Agency for the state is inaccurate.
The model assumes two power plants and units at two others will close by 2018 to meet goals. Based on production, those would be Montana-Dakota Utilities’ R.M. Heskett Station in Mandan, Coyote Station near Beulah, one unit of Milton R. Young Station near Center and one unit of Coal Creek Station near Underwood.
But company owners say they are committed to continue operating those operations.
McLennan said the EPA’s model is aimed at justifying the Clean Power Plan. Minnkota has debt on Young Station until the early 2040s. Reducing operations to one unit at the plant “makes things much tighter, particularly in the winter months where we have the greatest demand.”
“It’s there for a purpose. You can’t just shut it off,” McLennan said.
Minnkota has invested $25 million in Young Station over the past seven years, primarily for environmental upgrades. McLennan said it is important that it be allowed to operate into the early 2040s to cover the cost of those upgrades and use the full life of the plant.
Glatt said closing plants is one way to get into compliance but the state will look for “a reasonable path forward” based on public comments. Whether that involves closing plants or not, he’s unsure, but he said other options like renewables and switching the fuel burned at plants will all be considered.
Without a sure path forward, Basin has been trying to determine how much land would be required to run wind turbines to replace coal energy.
“That’s a lot of wind turbines,” said Tracy Bettenhausen, Basin’s senior staff writer.
Krebsbach said a plant also couldn’t be entirely replaced by a wind farm because wind power is intermittent. McLennan said companies will have to look for ways to replace coal generation with gas and wind.
“When you retire a baseload unit like that, you have to replace it with something,” said Krebsbach, adding that MDU hasn’t considered whether it would stop operations at any of its plants.
Hoff said Otter Tail does not have a position on what should be included in a state plan and needs more time to understand the different options and their effects. She did say Otter Tail has no plans to shutter Coyote Station and is committed to running it through 2040.
GRE also does not expect to shut down a unit at Coal Creek, which produces more than 50 percent of the company’s electricity.