Wisconsin commission approves Bay Front retrofit projects

The Wisconsin Public Service Commission on Dec. 5 approved an $18.5m retrofit project for the coal-fired Bay Front power plant of Northern States Power-Wisconsin (NSPW), a unit of Xcel Energy (NYSE: XEL).

On Sept. 12, the commission received an application from NSPW seeking authority to construct new baghouse and activated carbon injection (ACI) facilities on boilers number 1 and 2 at Bay Front.

The Bay Front plant is located on the shore of Chequamegon Bay, Lake Superior. Currently, three boilers feed steam into a combined steam header system that can support three turbine-generator sets. These boilers, known as boilers number 1, 2, and 5, currently burn fuels including coal, waste wood, railroad ties, tire-derived fuel, and natural gas to produce steam that drive the three turbine-generator sets (identified as numbers 4, 5, and 6) to produce electricity.

Of the three existing turbine-generator sets, #4 has a capacity of 22 MW and came into service in 1949, #5 has a capacity of 22 MW and came into service in 1952, and #6 has a capacity of 30 MW and was placed in service in 1957. NSPW told the commission that the current expected life of the plant is five to nine years.

NSPW proposes to construct new baghouse and ACI facilities to reduce particulate matter (PM) and mercury emissions from boilers #1 and #2 at the facility. NSPW said it has no plans to install additional air control equipment on boiler number 5 because it intends to burn only natural gas in that boiler after Jan. 1, 2015, in order to comply with the Wisconsin mercury reduction rule.

Project helps with EPA’s on-again, off-again IB MACT rule

Once the proposed project is installed, the Bay Front facility will comply with the U.S. Environmental Protection Agency National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial and Institutional Boilers and Process Heaters, more commonly referred to as Industrial Boiler Maximum Available Control Technology (IBMACT).

NSPW listed three areas of need for the proposed project:

  • to facilitate compliance with IBMACT;
  • to provide voltage support for the transmission system in the area; and
  • to maintain NSPW’s compliance with Wisconsin’s Renewable Portfolio Standards (RPS).

The final IBMACT was officially issued by EPA in March 2011. IBMACT applies to 15 different subcategories of boilers and process heaters that consume natural gas, oil, coal, biomass, refinery gas, or other gas, including boilers number 1 and 2 at Bay Front. Each subcategory of boiler has specific emission requirements for mercury, PM as a surrogate for non-mercury metals, hydrogen chloride (HCl) as a surrogate for acid gases, carbon monoxide (CO) as a surrogate for organic toxic gases, and dioxins/furans, the commission noted.

On the same day that it issued IBMACT, the EPA also published notice that it intended to reconsider the IBMACT in an effort to address a number of related technical issues that EPA believed would benefit from more public involvement. In December 2011, EPA issued proposed amendments to the IBMACT. The amendments are more stringent than those issued in the March 2011 final IBMACT. Specifically, the December 2011 proposed rule sets new emission limits for PM based on the fuel being combusted in the boiler; sets new emission limits for carbon monoxide based on boiler type; allows an alternative “total selective metals” emission limit instead of a total PM emission limit; and, replaces the numeric dioxin/furan emission limit with work practice standards, among other changes.

While EPA was expected to finalize the reconsideration of the proposed amendments to IBMACT in spring 2012, nothing has yet been published, the commission pointed out. But the utility stated that it is moving forward to install necessary equipment to comply with the March 2011 final rule by its effective date of March 21, 2014. NSPW stated that the installation of the proposed project will ensure boilers 1 and 2 meet the emission limits contained in the March 2011 final rule, as well as the December 2011 proposed amendments. NSPW said that it believes it is appropriate for the commission to approve the proposed project despite uncertainty about the IBMACT. “The Commission finds that NSPW’s approach to compliance with IBMACT is reasonable and prudent given the need for the proposed project,” the commission noted.

Utility shoring up local transmission, but Bay Front still needed

Bay Front also provides voltage and system support for the transmission system in northern Wisconsin. NSPW said that it is unlikely that the Midwest ISO would allow the capacity of the plant to be significantly reduced, or Bay Front to be retired, without additional transmission facilities in place. NSPW anticipates load growth in the area from the addition of sand mines and petroleum pipeline pumping stations.

Currently, NSPW has received or has applied for commission approval for about $95.7m in transmission upgrades that will address some of the existing reliability concerns. These upgrades will help meet North American Electric Reliability Corp. (NERC) standards if the generating capacity of the Bay Front plant were reduced. However, NSPW estimates that an additional $80m to $100m of long-term transmission investments will be needed if the plant capacity is significantly reduced, or the plant is retired. NSPW stated that these projects could be constructed as early as 2018, but that a more realistic timeframe would have the projects completed in the early- to mid-2020s.

In terms of RPS compliance, NSPW currently fires waste wood at Bay Front. The energy generated using this biomass fuel contributes to the utility’s compliance with the Wisconsin RPS. NSPW was required by 2010 to increase its renewable component of Wisconsin retail sales by 2% over its 2001-2003 baseline. By 2015, NSPW is required to increase its renewable component of retail sales by an additional 4%. To comply with these requirements, NSPW currently estimates that it will need to provide 12.89% of its retail sales from renewable energy sources to achieve compliance with the 2015 requirement.

If NSPW retires or mothballs a boiler or plant that contributed to the renewable baseline, it must replace the lost renewable energy with other qualifying renewable energy before it could satisfy the next standard. So, if NSPW reduces the amount of renewable generation from Bay Front, it must make up that lost generation before it can work toward meeting the next RPS threshold. In 2011, Bay Front generated 161,012 megawatt-hours (MWh) from renewable fuel, or about 16% of the renewable generation reported in NSPW’s annual Wisconsin RPS report. The most likely replacement source of renewable energy would be wind generation located outside of Wisconsin, probably in the service territory of Northern States Power-Minnesota.

Bay Front capacity would drop too much just on natural gas

NSPW considered two alternatives to the proposed Bay Front emissions project, including:

  • a no-build alternative including conversion of the existing Bay Front plant to be fired by natural gas only with RPS replacement energy obtained from Minnesota or the Dakotas; and
  • a no-build alternative including conversion of the existing Bay Front plant to be fired by natural gas only and RPS replacement energy obtained from Wisconsin.

These alternatives to the proposed project were rejected because the rated capacity of boilers #1 and #2 would both be reduced from about 22 MW each to about 6 MW each when fired with natural gas only. The capacity of the units is limited because existing natural gas capabilities are intended to improve boiler start-up and enhance combustion of other primary fuels, not to serve as the main fuel source. This reduced generating capacity would be inadequate to provide voltage and system support for the transmission system. In addition, NSPW said it does not have the ability to contract for firm natural gas deliveries to the Bay Front plant.

NSPW plans to commence construction of the proposed Bay Front project in the first quarter of 2013, and place the facilities in service in March 2014.

On Oct. 25, the utility filed with the commission a 2006-2011 rundown of fuel burn at boilers #1, #2 and #5 of Bay Front. All three boilers had a gradually reduced level of coal burn during the period, though the 2011 coal burn picked up a bit for two of them, with #1 burning 6,014 tons of coal in 2011 and #2 burning 12,906 tons. Both of these units burned a lot of wood, railroad ties and some natural gas during the period.

Boiler #5 burned 31,827 tons of coal in 2011, down from 103,070 tons as recently as 2007. It burned petroleum coke in the 2006-2009 period, but none in either 2010 or 2011. Its only other fuel during the period was natural gas.

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.