Northern States Power d/b/a Xcel Energy (NYSE: XEL) is planning several major capital projects at the coal-fired Sherburne County (Sherco) plant for 2014, including environmental control refinements for Units 1 and 2.
Steven Mills, Vice President of Energy Supply Operations at Xcel Energy Services Inc., was one of several Xcel officials that supplied testimony filed Nov. 4 with the Minnesota Public Utilities Commission in a new rate case.
Mills noted that as part of a compliance plan for the Minnesota Mercury Emissions Control Act, Xcel is in the process of installing a sorbent injection system on Sherco Units 1 and 2 in 2014 using activated carbon as the sorbent, which will reduce mercury emissions. The in-service date for these projects is consistent with a compliance date of Dec. 31, 2014.
“We have completed full-scale testing to validate that this sorbent injection system will effectively remove mercury from Units 1 and 2,” Mills wrote. Scrubbers and other equipment, including coal pulverizers, are being upgraded to reduce emissions, he said.
Xcel is also planning to proceed with the continued replacement of the selective catalytic reduction (SCR) catalyst layers at the Allen S. King coal plant. Xcel is also undertaking other system refresh projects at the King plant to replace worn or outdated equipment.
Xcel is also seeking to recover in 2015 the costs related to the installation of a new baghouse at NSP-Wisconsin’s Bayfront plant. The Bayfront plant is located in Ashland, Wisc., where boilers 1 and 2 have burned wood since 1979. The boilers are stoker fired and dated to the 1950s. The baghouse addition is scheduled to go in-service in 2015.
Newly-restored Sherco Unit 3 to get extensive overhaul in 2014
Xcel will be performing an overhaul on the 884-MW Sherco Unit 3 in 2014. Because the Southern Minnesota Municipal Power Agency (SMMPA) owns 41% of Sherco 3, Xcel would share the costs of this overhaul with them. The total cost to Xcel for the Unit 3 overhaul in 2014 is expected to be about $8.4m less than the Unit 2 overhaul it performed during 2013. The lower overhaul costs reflect the fact that SMMPA will bare 41% of the overhaul costs as a part owner of the unit, as opposed to Xcel’s 100% ownership of Unit 2. This lower cost also reflects the reduced overhaul scope for 2014 due to the proximity of the overhaul to the recent return to service of Unit 3 after an equipment failure threw it out of service in November 2011.
Despite the nearly two years of repairs needed to get Sherco Unit 3 back in operation, this 2014 overhaul is needed to complete required warranty work and other capital projects. The entire unit was not addressed after the November 2011 event, only damaged areas within the plant and certain accelerated capital projects. With an expected one-year run from unit restoration to the 2014 overhaul, the overhaul scope is reduced from a typical three-year scope. The goal for the 2014 overhaul is to provide a reliable unit in 2015, 2016, and 2017.
In addition, the planned 2014 overhaul completes a number of significant capital projects which are required to replace worn or obsolete equipment that risk reliable operations. The replacement of the Sherco 3 motor controls programmable logic controllers and the boiler feed pumps over speed controls are two of the critical projects planned to be completed in 2014 to ensure safe and reliable long-term operation of Sherco Unit 3.
The Minnesota commission has been taking comment on an Xcel life-cycle study that recommends the long-term operation of Sherco Units 1 and 2. Asked why the utility plans upgrade projects there now, despite this uncertainty, Mills responded: “These investments are needed to comply with environmental regulation and to preserve the reliable operation of these units in the near term, independent of a decision on their future operation. Foregoing these investments now could risk non-compliance and present safety, reliability, and operational risks, which could ultimately result in higher costs for customers. We committed to these projects as part of our State Implementation Plan and believe that implementing these emission control projects now we are able to achieve compliance with BACT emissions levels in a less costly manner. If we wait to implement these projects, we may have needed to install different technologies, such as selective catalytic reduction at a current estimated cost of more than $300 million which is significantly higher than the costs of these projects. Thus, it is important that these units are well-maintained until such time as they are removed from service.”
The company is proposing plant additions at Sherco that will be placed in-service in 2015 comprising a series of reliability projects at Sherco Unit 1. These projects are replacement of the electro-hydraulic control system, replacement of the distributed control system, and replacement of the boiler couton bottom.
Black Dog coal units to be decommissioned in 2015
Mills said that Xcel is planning on decommissioning the coal-fired Units 3 and 4 at Black Dog in 2015. Consequently, it is managing so that it does not spend more than is absolutely necessary to keep the units running until they are decommissioned. However, the capital projects planned at the plant are necessary to keep the plant operational in 2014 and also support ongoing gas-fired operations at Black Dog.
The NSP Electric System (comprising NSP-Minnesota and NSP-Wisconsin) serves over 1.6 million electric customers in Minnesota, North Dakota, South Dakota, Wisconsin, and Michigan. Together, NSP’s generating plants have a net maximum capacity of over 8,300 MW. These generating facilities use a variety of fuel sources including coal, natural gas, nuclear fuel, water (hydro), oil, and refuse. Coal now represents 31% of accredited capacity, with gas leading at 39% and nuclear at 18%.
“We expect our resource mix to gradually shift away from coal resources and incorporate higher levels of renewable and natural gas resources,” Mills reported. “This is a response to several factors, including the potential for significant carbon and other environmental regulation, new or changing renewable energy standards, the declining cost of renewable energy and natural gas, and the age of our some of our existing generation units.”