Regulators reject Great River Energy's business plan

  • Article by: DAVID SHAFFER , Star Tribune
  • Updated: July 17, 2013 - 9:10 PM

Regulators also ordered the Minnesota power company to supply more information on costs.

In an unprecedented rebuke to a major electric utility, Minnesota regulators on Wednesday rejected as inadequate a long-term business plan offered by the state’s second-largest power company, Great River Energy.

In a 3-2 decision, the state Public Utilities Commission (PUC) sided with environmental groups and some major customers who accused the utility of making bad investments in new fossil fuel power plants that helped drive up its rates 58 percent over seven years.

Regulators also ordered the Maple Grove-based nonprofit wholesale power cooperative to report next year on its environmental costs, including costs for greenhouse gases, and to analyze the economic benefits of conservation vs. retaining power plants, including older coal-burning units.

“We are hoping that this leads the GRE board to more closely scrutinize the cost and expense side of its business,” said Minneapolis attorney David Aafedt, representing two ethanol producers who had complained to the PUC about Great River’s electric rates and investments.

Laureen Ross McCalib, resource planning manager for Great River, said she was disappointed by the commission’s decision, but that the utility would “go back to the office and take the commission’s concerns very deeply to heart.”

The rejection is the latest case of Great River Energy’s business decisions being called into question. In June, Elk River Municipal Utilities, which long has relied on Great River to generate its electricity, said it had signed a deal to purchase less-expensive power from a municipal power agency.

Also last month, Great River CEO David Saggau pledged at the company’s annual meeting that no rate hike is planned for 2014.

Cooperative utilities like Great River, which serves 645,000 customers in 28 local co-ops from the Arrowhead to the Iowa border, are not as heavily regulated as investor-owned power companies in Minnesota. In almost all cases, the PUC doesn’t set their electric rates because state law assumes that co-op board members, who are elected by customers, can fairly set them.

But every two years, electric utilities, including co-ops, are required to show regulators their 15-year business outlooks, known as “integrated resource plans.’’ The plans are supposed to contain electrical demand forecasts, projections for adding or retiring power plants and information about environmental compliance and other matters that ultimately can affect what customers pay in rates.

“If you do it right, you are going to have information to make a better decision,” said Beth Goodpaster, an attorney for the Minnesota Center for Environmental Advocacy and other environmental groups that questioned Great River’s plan. “If you do it wrong, and you don’t take it seriously, the decisions based on it are going to be bad.”

Environmental groups and the two industrial customers argued that Great River has made bad business judgments, including building its $437 million coal-burning Spiritwood, N.D., power plant that’s never been put into service. They argued for closing an older coal-burning plant in North Dakota that the utility contends is still economical to run.

Aafedt, representing industrial customers, argued that regulators should closely examine how Great River’s resource plan affects what customers pay in rates. While the commission didn’t explicitly endorse that idea, it unanimously ordered Great River to supply far more information in a new plan due next year.

A PUC official said that to the best of staff’s knowledge, the commission has never before rejected a resource plan from a utility.

Great River executives have defended past investments, saying that until the recession struck late in the past decade, power use was growing, and construction of new generation projects already was underway. The utility has since scaled back its annual electric growth forecast to just 1.3 percent. Even so, the utility will have excess generating capacity for years, and sees no need to build new power plants, except for some wind turbines to meet the state’s renewable energy mandate after 2020.

David Shaffer • 612-673-7090 Twitter: @ShafferStrib

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