Minnesota PUC tells Great River Energy to look harder at coal impacts

The Minnesota Public Utilities Commission, in an unusual move, on July 17 decided on a 3-2 vote not to approve the latest resource plan of Great River Energy because the cooperative didn’t do enough to explain how it could back down its coal use.

Therese LaCanne, Manager of Corporate Communications for Great River Energy, said in a July 18 e-mail to GenerationHub that the cooperative has these points to make about the vote.

  • “We are disappointed the commission did not approve our integrated resource plan.”
  • “Our plan met all legal, statutory requirements, and we will carefully consider the commission’s comments in our future planning process.”
  • “The commission’s decision is advisory and does not require us to take any action other than to file our next plan at the time we are required to file it – which is November 2014.”
  • “Great River Energy’s existing generation resources are expected to meet our members’ needs for the foreseeable future.”

PUC chair Beverly Jones Heydinger, as quoted in an Associated Press story, said the plan should have asked a key question about whether generating resources should be taken off-line that are having an environmental impact. Instead, Heydinger said Great River Energy merely stated that its existing plants are adequate to meet demand. The PUC wants Great River Energy to look harder at environmental costs in its next plan.

Commission staff on July 10 filed a briefing paper with the commission ahead of the July 17 meeting to outline the November 2012 resource plan and all of the testimony in the case since then from intervenors like environmental groups and the state Department of Commerce. Under state law, the commission has only an advisory rule in the resource plan of Great River Energy, a generation and transmission cooperative.

GRE said in the integrated resource plan (IRP) that it has no capacity needs for 15 years, but that energy needs must be determined through capacity expansion modeling. GRE’s preferred plan is:

  • Continued conservation and energy efficiency programs;
  • Continued use of existing supply-side resources, except where contracts expire;
  • Interaction with the wholesale market for cost-effective energy purchases and sales;
  • Addition of 600 MW of wind in 2024 to 2026 to meet the renewable energy standards (RES); and
  • No supply-side resources beyond those needed for RES compliance.

There could be valid reasons in support of accepting the plan and moving on, staff noted. The commission’s role on non-rate-regulated utilities’ IRPs is advisory. The forecast, while not perfect, is not required to be perfect and relies on both Woods and Poole data and a review by member coops (ex post adjustments) which actually adjusted the forecast downward. In addition, while the environmental intervenors (EIs) and Al-Corn Clean Fuel look to the last few years to argue that GRE’s past forecasts have been inaccurate, many utilities did not expect the economic downturn to be as severe as it was, staff pointed out.

The EIs stated that the primary causes of past and near-term rate increases are higher expenses resulting from GRE’s surplus generating capacity, reduced sales, and the increase in the price GRE pays for coal.

GRE undertook a number of capacity additions before the ecomomic recession, including Cambridge 2 (181 MW natural gas peaker), Elk River Peaker (204 MW natural gas peaker), and Spiritwood (99 MW combined baseload/peaker combined heat and power facility, completed but not in commercial operation). The EIs provided information on ongoing expenses related to Spiritwood, such as processed coal purchase obligations, a unit train lease, and interest on bonds used to finance the unit. The EIs estimate the total pre-operational cost of Spiritwood to be in excess of $500m.

The EIs also suggested that GRE look into retiring the coal-fired Stanton plant, with GRE responding that the EIs did not take into account the Midcontinent ISO revenues GRE receives from Stanton operations. Stanton, sited near Stanton, N.D., uses about 850,000 tons of Powder River Basin (PRB) coal each year. Stanton’s boilers are equipped with particulate removal systems and the supplemental boiler has an SO2 scrubber.

About Barry Cassell 20414 Articles
Barry Cassell is Chief Analyst for GenerationHub covering coal and emission controls issues, projects and policy. He has covered the coal and power generation industry for more than 24 years, beginning in November 2011 at GenerationHub and prior to that as editor of SNL Energy’s Coal Report. He was formerly with Coal Outlook for 15 years as the publication’s editor and contributing writer, and prior to that he was editor of Coal & Synfuels Technology and associate editor of The Energy Report. He has a bachelor’s degree from Central Michigan University.