The Minnesota Public Utilities Commission is due at its July 17 meeting to look at whether to accept Great River Energy’s latest resource plan and whether to take any action on a recent change in the plan related to the coal-fired Genoa Unit 3.
Commission staff on July 10 filed a briefing paper with the commission 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.
Commission doesn’t have to make any firm decisions right now
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.
“Even if the Commission were to conclude that GRE’s forecasting process is defective, GRE does not plan to add any resources so the debate, as GRE points out, is an academic one,” staff added. “In addition, the newly filed information on Genoa 3 is interesting but the dispute is in arbitration, the generating unit is not owned by GRE, and GRE is long on capacity.”
Staff noted that the EIs and GRE refer to GRE’s next IRP as being due in 2015. But staff believes that it is clear under the commission’s rules GRE’s next IRP would be due Nov. 1, 2014, unless a variance is granted to the commission’s resource plan rules.
“Since no resources will be acquired for several years, it may not make sense to prolong this docket when the parties will be able to take a fresh look at a November 2014 plan,” staff pointed out. “One option, given the EIs’ and Al-Corn’s concern over the forecast, is to accept the plan but make no finding on the forecast. The Commission has done this in past IRP Orders to memorialize the fact that it is not endorsing a particular utility’s methodology on forecasting. The Commission could also ‘neither accept nor reject’ the plan, which is what it did with GRE’s 2005 resource plan. This action closed the docket and moved on with recommendations for additional information and analysis in the next plan.”
Great River says Genoa 3 is about dead, Dairyland disagrees
Somewhat separate to the quality of analysis issue raised in comments is the Notice of Changed Circumstances (NoCC) GRE filed in its May 20 reply comments. GRE notified the commission that it and Dairyland Power Cooperative are in a dispute over the fate of Genoa 3, a coal unit in Wisconsin. GRE purchases 50% of the capacity and energy of that unit, which is owned by Dairyland. GRE believes the unit is no longer economic to operate and believes it should be retired, and Dairyland disagrees. The matter is being arbitrated.
“The Environmental Intervenors believe that because GRE only notified parties and the Commission recently, there should be an additional opportunity for discovery and comments,” said staff on the Genoa 3 issue. “If the Commission agrees that this development merits additional time for the parties to review, the Commission could defer action on the plan for this reason. However, staff notes that no one has alleged that the case is not properly in arbitration. In addition, if the matter is to be examined in a Commission docket, it could also be examined in the Dairyland resource report docket since Dairyland is the owner and operator of the unit.”
GRE is a party to a long-term cost-sharing power purchase agreement (called the “G3 Agreement”) with Dairyland which entitles GRE to 50% of the energy and capacity of Genoa 3 (G3). G3 is a nominal 350-MW coal-fired facility located in Genoa, Wisc., on the site of two other long-shut units. GRE’s 50% share of the capacity of G3 is currently 116 MW (representing MISO’s Planning Reserve Credit designation).
Under the G3 Agreement, DPC is obligated to operate and maintain the plant for the economic benefit of both GRE and DPC. “GRE believes, and has informed DPC, that the useful physical and economic life of G3 has ended, and, consistent with DPC’s obligations to GRE under the terms of the G3 Agreement, DPC is obligated to retire G3,” GRE told the commission in the May 20 update. “Evidence that G3 is at the end of its physical and economic life includes its escalating fuel and transportation costs, its failure to be competitive in the MISO market, an increasing incidence of forced outages, increasing operating and maintenance costs and the increased capital and operating costs associated with known and future environmental regulations.”
Notable is that under the terms of a settlement of a lawsuit with the U.S. Environmental Protection Agency and the Sierra Club, Dairyland is required to install at G3 selective non-catalytic reduction for NOx control by June 1, 2015.
GRE rebuts environmental critics on continued life for Stanton coal plant
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 power plant, with GRE responding that the EIs did not take into account the Midcontinent ISO revenues GRE receives from Stanton operations.
“Their analysis of the cost implications to our members is flawed,” GRE told the commission in the May 20 filing. “Their analysis takes into consideration only the variable operating costs of the Stanton facility, and fails to take into consideration the revenues generated by Stanton in the MISO market. Stanton is an efficient baseload facility that is routinely dispatched by MISO. The Environmental Intervenors’ analysis also fails to take into account the value of Stanton’s capacity and its contribution to our member-owners’ resource adequacy requirements. Therefore, GRE does not agree that Stanton Station should be retired.”
Stanton, sited near Stanton, N.D., is located on a bank of the Missouri River. The plant has a unique steam path involving two boilers feeding a single turbine on a common steam header. Stanton uses about 850,000 tons of Power River Basin (PRB) coal each year, which is rail delivered. Stanton’s boilers are equipped with particulate removal systems and the supplemental boiler has an SO2 scrubber.