Minnesota Power told the Minnesota Public Utilities Commission on July 3 that its latest integrated resource plan (IRP) is still the way to go, despite some criticism by parties to the IRP case.
The utility in the July 3 filing responded to comments from the state Department of Commerce–Division of Energy Resources, the Large Power Intervenors Group (LPI) and the Minnesota Center for Environmental Advocacy (MCEA). On March 1, Minnesota Power filed with the commission its 2013 IRP for the 2013-2027 timeframe.
Under the plan, transformation of the company’s resource base continues through investment in renewable generation, adding natural gas to the fuel portfolio, installing additional emissions-control technology at core, coal-fired assets while also reducing coal utilization at several baseload generating facilities, and maintaining strong energy conservation and demand side management programs for customers. The resulting fleet will be more flexible, efficient and diverse while reducing multiple emissions including carbon, the utility noted.
Minnesota Power’s Preferred Plan includes these primary actions:
- Ceasing coal energy conversion at the 75-MW Taconite Harbor Unit 3 and refueling the 110-MW Laskin Energy Center (LEC) with natural gas in 2015;
- Optimizing the company’s renewable energy supply with the evaluation of an additional 100 MW to 200 MW of competitive wind generation that would be installed in the next two to three years; and
- Investigating, for inclusion in its next resource plan, an intermediate natural gas generation resource to meet expected capacity and energy needs in the post-2020 timeframe. Minnesota Power will use bilateral market purchase contracts with secured pricing in the 2014-2020 period as a bridge to implementation of a natural gas unit.
Three primary areas of focus emerged from the comments provided by the Department, LPI and MCEA regarding Minnesota Power’s 2013 Plan and elements of its Preferred Plan: load forecasting, resource modeling, and plan cost.
Among the points covered in the July response had to do with fuel cost inputs at two plants and explanation of a sharply lower natural gas price forecast.
- Square Butte’s Milton R. Young 2: The coal cost estimates for Young 2 in North Dakota are higher in the 2013 Plan because the costs were refined to be more specific to delivering fuel to the facility. The coal cost used in the 2013 Plan was based on the latest projections for coal produced from the adjoining lignite coal mine at the Young 2 facility and includes cost specific to mining and delivering the coal supply. Minnesota Power is presently phasing out its power purchases from Young 2. Minnesota Power’s current entitlement will be gradually reduced beginning in 2014, and by 2026, the company will no longer be taking any of the Young 2 output for its customers.
- Hibbard Renewable Energy Center (HREC): Biomass fuel cost outlooks were updated with the latest information, which is lower than the biomass fuel pricing used in a prior baseload diversification study. The lower biomass pricing used in the 2013 Plan for the Hibbard Expansion and existing Hibbard reflects the available surplus of biomass fuel due to the continued decline in the wood and paper industry located around HREC.
- Natural Gas: The projected natural gas price used in the 2013 Plan Strategist model is approximately 25% lower than prices used in the baseload diversification study. The first reason for the decrease is Minnesota Power shifted Firm Delivery Charge costs from a natural gas price adder to a fixed charge associated with the natural gas generator. This is consistent with how the fixed rate components on interstate gas pipelines have increased as pipelines have shifted cost recovery from variable commodity rates to fixed capacity rates. In the baseload diversification study the Firm Delivery Charge was added directly to the natural gas price modeled in Strategist. In contrast, in the 2013 Plan, the Firm Delivery Charge was still included though it was added to the cost of the gas unit as a fixed charge, not to the price of the natural gas commodity. This change was made to reflect the fact that the Firm Delivery Charge is not a variable cost dependent on natural gas usage, but instead a fixed cost that is dependent upon how much of the gas pipeline is reserved for delivery of natural gas. The second aspect of the update includes about a 10% decrease in the commodity outlook for natural gas since 2011.
Minnesota Power looks at issues related to Rapids Energy Center
The Department conducted a very high level scenario analysis that included removing the Rapids Energy Center (Rapids) from Minnesota Power’s 2013 Plan. Minnesota Power currently has before the commission a petition to request that Rapids be moved to the company’s regulated rate base in order to provide valuable and flexible renewable biomass energy to customers. The Department identified that its analysis did not contain all the necessary information to fully evaluate removing Rapids from Minnesota Power’s long term power supply plan in its modeling analysis and requested that Minnesota Power provide the present value of the cost to shut down the Rapids facility.
Rapids is a combined heat and power plant which provides Blandin Paper with steam, compressed air, and electric services. Because several aspects of Rapids’ and Blandin’s operations are interdependent, a shutdown evaluation of Rapids would require that the Blandin paper mill also be shut down as it requires steam from Rapids to operate, the utility noted. The implications of a shutdown of this magnitude in Minnesota would bring significant job losses and costs that have not been contemplated to date.
The 2013 Plan identified that coal-fired Laskin Energy Center (LEC) will be converted to a natural gas-fired facility in 2015. Its operation schedule will be significantly impacted by this conversion. LEC will move from a baseload resource that runs each day to a peaking resource. LPI requested that Minnesota Power clarify how the company intends to address the reduction in output from these units after the conversion to natural gas is complete.
When lower cost resources are available, they will dispatch ahead of LEC. Expected resources in the near term include power supply from Minnesota Power’s existing thermal units, new and existing wind, hydro generation and bilateral power purchases. Expected resources in the long term, in addition to these near term resources, will include long term purchases from Manitoba Hydro and natural gas. Together, these multiple resources provide Minnesota Power’s customers with a least cost power supply. If market purchases are higher cost than the cost to run LEC, or the regional market requires the resource for reliability reasons, the company said it will operate LEC to serve customers.
Minnesota Power says BEC4 retrofit still very much the cheapest option
To clarify the treatment of the coal-fired Boswell Energy Center Unit 4 (BEC4) in its 2013 Plan and address the concern raised by MCEA, the utility provided an overview of the customer evaluation of the BEC4 Environmental Retrofit Project (BEC4 Project) and how it is aligned with the 2013 Plan.
The least cost plan for customers in the 2013 Plan evaluation included the BEC4 Project. For the separate March 7 BEC4 Project cost recovery petition filed with the commission, Minnesota Power provided a customer impact evaluation that was refreshed from the baseload diversification study and BEC4 Plan Petition to be directly in line with its 2013 Plan assumptions and outlooks. Similar to its 2013 Plan evaluation process for its other coal-fired generation that require action due to the Mercury and Air Toxics Standards (MATS), Minnesota Power identified that the BEC4 Project was the best compliance path forward for the unit with “resounding economics” that provided a range of $150m to $320m of benefit to customers over the planning period when compared to alternatives.
Minnesota Power compared the BEC4 Project with a shutdown of BEC4 and the two possible natural gas replacement options. The BEC4 Project and the two natural gas replacement scenarios were then stressed over a range of planning sensitivities with the updated assumptions from the 2013 Plan. In only two sensitivities, including severely low and sustained natural gas prices (between $2 and $3/mmBtu for the entire planning period) and a high carbon regulation tax structure ($34 per ton), did a natural gas direct replacement begin to show benefits for customers.
Minnesota Power and joint BEC4 owner WPPI Energy completed a turbine conservation and efficiency project in 2010, increasing the BEC4’s capacity and energy output by more than 10%, or 60 MW while requiring no additional fuel. Continued operation of BEC4 will sustain this very significant conservation project.
“Minnesota Power is confident that moving forward with the BEC4 Project is in the best interest of its customers and that its evaluations are complete and robust,” the utility added. “At 585 MW of net capacity, BEC4 is the newest and single largest base load generator in Minnesota Power’s fleet, providing cost-effective and reliable power to Minnesota Power’s customer 24 hours a day, 7 days a week. Because more than 50 percent of Minnesota Power’s total energy supply is used by its 12 largest industrial customers that operate around the clock, the Company has a uniquely high load factor, requiring a power supply that is available more hours of the day than that of most electric utilities. Retrofitting BEC4 to reduce mercury emissions by 90 percent, and improving other aspects of environmental performance, is in the public interest as it will help to ensure BEC4 continues to deliver a large volume of essential, efficient and environmentally compliant energy to residents, communities and businesses in Northeastern Minnesota at a reasonable cost.”