Minnesota Power has lately taken a number of steps to reduce its coal-fired capacity, including putting in place a target of shutting the coal-fired Boswell Energy Center Units 1 and 2 by the end of 2018, and reducing the coal burn in the largely biomass-fired Hibbard plant.
Joshua J. Skelton, employed by ALLETE Inc. d/b/a Minnesota Power as Vice President – Generation Operations for Minnesota Power, described the latest power capacity moves in Nov. 2 testimony filed at the Minnesota Public Utilities Commission to support a rate increase application.
Skelton noted that in February 2015, the last trainload of coal was unloaded at the Laskin Energy Center and the plant was subsequently converted to use cleaner-burning natural gas as an environmental improvement project. In addition, in June 2015, Minnesota Power’s coal-fired Taconite Harbor Energy Center Unit 3 (THEC3) ceased generation after 48 years. As a result of these changes, the percentage of coal-fired generation on the Minnesota Power system has declined from about 95% in 2005 to less than 60% in 2015.
Additionally, major emission reduction projects at Boswell Energy Center Unit 4 (BEC4) and Boswell Energy Center Unit 3 (BEC3), the two largest coal generators remaining on the Minnesota Power system, are contributing to the company’s lower emission profile. A major environmental retrofit was completed at BEC3 in 2009 and substantially completed at BEC4 in December 2015. Both retrofits reduced mercury, particulate matter (PM), acid gases, and SO2 emissions.
On Oct. 19, 2016, Minnesota Power announced its plan to retire Boswell Energy Center Units 1 and 2 (BEC1&2) by the end of 2018.
At the same time as it is cutting coal, over the past decade the company has undertaken a systematic effort to increase its deployment of renewable energy. In 2006 and 2007, Minnesota Power began purchasing, through a power purchase agreement (PPA), the entire output of the Oliver 1 and Oliver 2 wind farms (approximately 100 MW combined) built in North Dakota by NextEra Energy. In 2008, Minnesota Power constructed and began operation of the 25-MW Taconite Ridge Energy Center, which was the first commercial wind station in northern Minnesota. Between 2010 and 2014, Minnesota Power constructed and began operation of the four Bison Wind Energy Center phases in North Dakota. Bison is now the largest wind farm in North Dakota with just under 500 MW of generation. Combined, these wind projects added more than 600 MW of renewable generation to the company’s energy portfolio.
The Generation segment’s capital investments for 2017 are planned to be $40.4 million, including capital expenditures and decommissioning costs, Skelton reported. While the utility continues to move its resource portfolio to one-third gas, one-third coal, and one-third renewable, it will also need to maintain the assets currently serving customers. The planned capital investments for 2017 reflect a movement from large investments in environmental and renewable projects to an “optimize, maintain, and improve” approach. The $40.4 million of planned capital investments can generally be characterized in the three categories:
- $25 million of base capital expenditures;
- $10.8 million for decommissioning expense related to the Coal Combustion Residuals (CCR) regulations (called the “Environmental Improvement Projects”); and
- $4.6 million in capital expenditures for remaining rider projects at Thomson hydroelectric facility refurbishment project.
Two Boswell units got retrofitted, two others targeted for extinction
The Boswell Energy Center, located in Cohasset, Minnesota, is Minnesota Power’s largest thermal facility. It includes four units with a combined capability of nearly 1,000 MW that have historically provided approximately half the energy needs of Minnesota Power’s customers. Major environmental and efficiency improvements have been made at the facility in recent years, with the most recent investment being the environmental retrofit of the BEC4 that was substantially completed in December 2015.
BEC4 was placed into service in 1980 and at that time had 535 MW of net nameplate capacity, making it Minnesota Power’s largest baseload generator. Subsequent turbine efficiency investments in 2010 expanded the net nameplate capacity of this unit to 585 MW. WPPI Energy (formerly Wisconsin Public Power Inc.) has a 20% (117 MW) ownership interest in BEC4. BEC4 was originally constructed with first generation low oxides of nitrogen burners (LNB) and close-coupled over-fire air, and a then-state-of-art wet spray tower absorber/particulate removal system.
In November 2013, the commission approving a BEC$ retrofit plan and associated cost recovery in the BEC4 Emission Reduction Rider (BEC4 Rider). The environmental upgrades involved replacing the BEC4 existing wet scrubber and PM control technology with a semi-dry system that uses less water and removes additional sulfur oxides and acid gases, installing a powdered activated-carbon injection system to capture flue gas mercury, and adding a fabric filter to further control particulates. The new circulating dry scrubber (CDS) technology has substantially less equipment than the existing wet system so equal or lower electrical loads than the current station service requirements were anticipated. As expected, Skelton wrote, the retrofit is providing the benefit of a nominally lower station service draw by approximately 1.5 MW, overall making it slightly more energy efficient. These improvements were needed to comply with both the Minnesota Mercury Reduction Act (MERA) requirements and the mercury, PM, and hydrochloric acid emissions standards mandated by the Mercury and Air Toxics Standards (MATS) issued by the U.S. Environmental Protection Agency.
Minnesota Power has been at work on these BEC4 improvements since 2013 and the majority of these capital improvements were placed in-service in 2015. All remaining site finishing work will likely be finalized at the end of 2016. However, components of the Boswell Ash Management project will be incrementally completed and placed in-service during the coming years, concluding in 2030. The portions of the Boswell Ash Management project that are still being constructed include the ash disposal facilities, construction of additional ash haul roads, the addition of heavy equipment dozers, trailers, and dust mitigation water trucks that are required as a complement to the emissions reduction upgrades at BEC4.
At BEC4, in 2017, Minnesota Power proposes to inspect, repair, and rebuild the existing gear box as necessary for the BEC4 “G” pulverizer. The scope of this project is to assess and repair the gear box’s internal bearings, gearing, and shaft for defects or damage and repair with like-in-kind components. The reliable function of this asset is necessary to maintain compliance with emission regulations as it plays a critical role in a clean and efficient combustion process. In total, capital expenditures for BEC4 are expected to be $3.8 million in 2017.
BEC3 typically operates at a high load factor, providing baseload energy to the Minnesota Power system. In 2009, Minnesota Power replaced the original turbine with a more efficient design that has nameplate capacity of 364 MW of net output without increasing the steam flow or consuming additional fuel. This was an increase from the original design of approximately 10 MW. In combination with the turbine efficiency upgrade, a major environmental upgrade was also completed at BEC3 in 2009 to meet state and federal environmental requirements.
At BEC3, Minnestoa Power is planning several capital projects in 2017. These projects are routine investments aimed at supporting the designed performance of the assets, replacing worn parts, maintaining efficiencies and environmental compliance, and supporting continued reliability of this important baseload resource. For instance, in 2017 it will undertake an overhaul of the BEC3 coal pulverizers. These pulverizers are exposed to considerable erosion and by replacing the internal components to original size and improving the wear properties of these components will allow BEC3 to operate with proper mill fineness, fuel balance, and improve the efficiency of the combustion process.
BEC1&2 operate at a high load factor, providing both baseload energy and ancillary services to the market. BEC1&2 each operate with a net capability of 67 MW. The units provide station service to operate auxiliary equipment, as well as maintain a steady and reliable steam supply to heat the entire Boswell Energy Center during the winter months. BEC1&2 also house the water intake for the Boswell Energy Center, as well as the boiler water treatment systems that feed all Boswell units.
As noted above, Minnesota Power recently announced plans to retire BEC1&2 in 2018. The retirement of BEC1&2 is part of a strategy to reduce small coal-fired generation on the system. In addition, under the terms of an agreement between Minnesota Power and the EPA, BEC1&2 will require additional SO2 emissions controls if they continue to operate as coal-fired units past 2018. Options considered for BEC1&2 included retrofitting the units to reduce SO2 through use of the BEC3 scrubber, refueling the boilers to natural gas, or retirement. Considering in part that the commission required the shutdown of these units by no later than 2022 as part of its decision on the 2015 integrated resource plan (IRP), the company determined that the most cost-effective option was retirement of BEC1&2 by Dec. 31, 2018.
While it is planning to retire BEC1&2 at the end of 2018, the utility will continue to operate them through 2018 and must make certain necessary investments to ensure they are capable of continued operation. For instance, in 2017, it plans to replace all bags in eight compartments in the Unit 1 baghouse that have reached their end-of-life and require replacement to maintain permit compliance until retirement in 2018.
Last two units at Taconite Harbor are on standby
The Taconite Harbor Energy Center (THEC) is located near Schroeder, Minnesota, on the North Shore of Lake Superior with an originally-designed generation capability of 225 MW. THEC is comprised of three units – Unit 1 (THEC1), Unit 2 (THEC2) and Unit 3 (THEC3) – that were purchased from bankrupt LTV Steel Mining Co. in 2001. The three units are each 75-MW tangentially-fired coal boilers and steam generators.
In May 2015, after 48 years of operation, Minnesota Power ceased coal-fired generation at THEC3 in response to the MATS regulation taking effect on April 15, 2015. This unit was then retired in place. Minnesota Power plans to cease coal-fired operations at THEC1&2 by the end of 2020 and, as part of that transition, these units were idled in the fall of 2016. This plan was approved by the commission in its July 18, 2016, decision on Minnesota Power’s 2015 IRP.
Minnesota Power decided to idle THEC1&2 so that these units can be called upon as needed to provide regional reliability. Specifically, these idled units could be restarted and produce electric power if needed to maintain grid reliability in an area where there are limited alternatives to address potential local transmission and distribution interruptions. Idling of THEC1&2 also provides the company with more flexibility during this time of significant change in state and federal energy and environmental policies. The THEC facility has several favorable attributes including a deep water port, rail line, and power generation infrastructure. These assets have been prudently maintained and could be used for alternative energy generation or other industrial infrastructure in the future.
There are no capital additions planned for THEC in 2017 and any repairs or modifications required to return the units to service for any possible start-up and re-idle sequence will be addressed on an as-needed basis.
The Laskin Energy Center is located in Hoyt Lakes, Minnesota, and was commissioned in 1953 as a coal-fired facility. Laskin has two 55-MW net nameplate capacity generating units, Units 1 and 2, that are similar in design and intended operation. To help achieve the EnergyForward goal of having a mix of power generation that is one-third renewable, one-third-natural gas, and one-third coal, the conversion of Laskin from coal to natural gas was completed in July 2015. In March 2015, the two generating units were taken offline and the coal firing systems were replaced with new natural gas burners and electronic controls. In addition, a new mile-long natural gas pipeline was constructed to Laskin to provide fuel for these new natural gas burners.
While the conversion to natural gas has changed the accredited output to 77 MW for planning year 2016 to 2017, Minnesota Power is now operating Laskin as a peaking facility rather than a baseload resource. As a peaking facility, Laskin will operate considerably less than it did as a baseload resource. However, Laskin still provides value to customers in that it provides a hedge against high regional power prices and provides needed capacity when called upon for grid reliability. With its new mission, Laskin was called upon to operate on nine occasions in August 2016.
The Hibbard Renewable Energy Center is located in west Duluth, Minnesota. In 1985, an affiliate of the City of Duluth was formed to retrofit and own the Hibbard Units 3 and 4 boilers to supply steam to a newly constructed paper mill and Minnesota Power’s electric generating units in the facility. Hibbard Units 3 and 4 have been providing a portion of Minnesota Power’s renewable generation, regulation services, and spinning reserves for over twenty years, and currently provides 62 MW of net capacity along with dispatchable renewable energy. Hibbard is capable of burning wood and wood wastes, coal, and natural gas.
Changes in Hibbard’s fuel supply were required by the MATS regulation. Prior to these regulation changes, Hibbard’s fuel mix was 25% to 30% coal and 70% to 75% biomass. To achieve compliance with MATS, capital improvements were completed to facilitate increasing and constantly maintaining at least 90% biomass in Hibbard’s fuel supply, thus reducing the coal utilization to less than 10%. This compliance approach was chosen because it was the most cost-effective solution of the alternatives considered, which included converting to new natural gas boilers and installing additional pollution control equipment. Today, Hibbard’s coal utilization is less than 10%.
At Hibbard in 2017, Minnesota Power plans to replace the wood/coal feeders in Units 3 and 4 as the feeders are original and need to be replaced. These feeders are needed to maintain adequate fuel supply and distribution to the boilers. In addition, it plans to replace the boiler grates in Unit 3 as they are at the end of their useful life. These grates are critical to allowing the use of solid fuel; if these grates are not replaced, they have a tendency to warp or jam causing the solid fuel capability to be shut down.