DTE Electric eyes coal unit retrofits and retirements

DTE Electric plans to comply with EPA’s Mercury and Air Toxics Standards through completion of air controls on the giant Monroe coal plant, and a combination of activated carbon injection (ACI) and dry sorbent injection (DSI) on several other coal units.

Barry Marietta Jr., employed by DTE Energy Corporate Services LLC as a Supervisor–Emissions Quality, outlined the utility’s air plans in a Sept. 30 filing of a power supply cost recovery plan at the Michigan Public Service Commission. DTE Electric is a unit of DTE Energy (NYSE: DTE).

The Monroe Power Plant will comply with MATS by installing and operating flue gas desulfurization (FGD) and selective catalytic reduction (SCR) systems on all four units by April 2015, which is the initial compliance deadline under MATS. The remaining coal-fired units in operation will comply with MATS emission limitations with a combination of DSI and ACI by April 2016 due to receiving MATS compliance extensions from the Michigan Department of Environmental Quality (MDEQ).

DTE Electric applied for and received one-year extensions to the April 2015 MATS compliance date at its Belle River, St. Clair, River Rouge, and Trenton Channel plants.

Also, the State of Michigan promulgated regulations establishing limits on emissions of mercury from Electric Generating Units that were finalized in 2009 and are known as Michigan Part 15 Air Pollution Control Rules. The specific mercury emission standards are specified in Rule 1503 and require every regulated coal-fired power plant in Michigan to comply with these standards. The state rule has since been modified to coincide with the MATS rule. As long as the MATS rule is in place, the Michigan Rule will defer to the MATS regulations.

DTE Electric currently plans on utilizing ACI technology at Belle River, St. Clair, River Rouge and Trenton Channel. The installation and operation of FGD and SCR on all four Monroe Power Plant units by April 2015 along with Reduced Emission Fuel (REF), which is coal with certain chemical additives that reduce emissions when that coal is burned, will provide compliance with mercury emission limitations.

As for the MATS HCl emission limitations, FGD has been proven to meet the MATS acid gas limits and will be operational on all four Monroe units for MATS compliance. FGD, while an effective acid gas technology, is a technology that requires significant capital investment. This larger capital investment may not be justified on some units in the DTE Electric portfolio, Marrieta noted. DSI is another technology that has been used in the industry primarily to reduce SO3 emissions for some units that burn higher sulfur coals.

The combination of DSI and ACI sorbents injected into the flue gas prior to the existing electrostatic precipitator (ESP) was demonstrated to meet MATS particulate matter (PM) emission limitations. Tests demonstrated that DSI, using either Trona or sodium bicarbonate (SBC), was able to measurably improve the efficiency of the existing ESPs. This increased particulate collection performance, along with some existing ESP and ash handling equipment enhancements, allow the existing ESPs to meet MATS PM emission limitations.

Refined coal helps with emissions needs, DTE Electric says

The consumption of REF at the St. Clair, Belle River, and Monroe power plants is beneficial to DTE Electric’s customers and also helps the company comply with MATS, Marietta wrote. “At coal burning plants with no FGD, such as Belle River and St. Clair power plants, consuming REF will significantly lower [powdered activated carbon] cost to reduce mercury emissions. DTE Electric has conducted tests on those units in 2010 and 2011 demonstrating that while consuming REF, compliance-level mercury removal can be achieved using the lower cost standard PAC rather than the chemically treated [brominated powdered activated carbon]. This is to be expected since one of the components of REF is an effective agent for oxidizing vapor phase mercury. The combination of REF and ACI will not be optimized until permanent ACI systems are installed. Until this combination of systems can be optimized, the exact cost savings (both $/pound for less expensive PAC and lower PAC consumption) cannot be determined. PAC costs, however, will be lower with REF than they would be while operating ACI without REF.

“At coal burning plants with FGD, such as Monroe Power Plant, the use of REF eliminates the need to install an additional chemical injection system to reduce mercury emissions. One of the components of REF is an effective agent for oxidizing vapor phase mercury, minimizing the amount of vapor phase mercury in the elemental form. Because this same additive is used in REF, the vapor phase mercury entering the FGD is highly oxidized which promotes very effective mercury removal in the Wet FGD. REF removes the need for additional costly additives necessary to achieve full compliance with the MATS mercury standard.

“Additionally, using REF is expected to result in other environmental benefits such as lower emissions of nitrogen oxides (NOx) and sulfur dioxides (SO2). The largest benefit, however, will be realized for mercury control.”

As construction and implementation schedules have been finalized, a timeline for implementing DSI and ACI systems was developed. Along with finalizing this schedule, DTE Electric has committed to operating the systems prior to the MATS  compliance date should the systems be available at that time. This means that several locations will have operational systems in place in 2015.

Two Trenton Channel units targeted for shutdown in 2015 and 2016

Coal-fired retirements are also part of the plan. Derek Arnold, a principal market engineer in the Fossil Generation Strategic Planning Organization of DTE Electric, said in companion Sept. 30 testimony about future capacity: “From 2014 to 2015 there is a net 72 MW decrease of capacity in the owned DTE Electric generation fleet. The retirement of Trenton Channel Power Plant Unit 8 is partially offset by an increase in Ludington capacity and solar capacity. In 2016, the retirement of Trenton Channel Unit 7 is mostly offset by new wind capacity coming online in January 2016 along with increases in Ludington generating capacity in August 2016. Trenton Channel Unit 9’s capacity rating is lowered in 2016 due to the combined effects of the retirement of Trenton Channel Units 7 and 8 in 2016 and 2015, respectively. In 2017, River Rouge Power Plant capacity is lowered [from 540 MW net demonstrated capacity to 495 MW] due to proposed National Ambient Air Quality Standards (NAAQS) that may require the plant to operate with lower sulfur, lower heat content fuel, resulting in a lower capability. River Rouge’s lower capacity is partially offset by increases in Ludington generating capacity. For 2018-2019, the generation capacity of the DTE Electric fleet increases by approximately 24 MW each year as the Ludington [pumped storage hydro] upgrade project continues with one unit being completed each year.”

Trenton Channel 8 will retire by April 15, 2015. At this point, Trenton Channel 7 is forecasted to retire by April 15, 2016. An Attachment Y retirement notice has been submitted to the Midcontinent ISO for both units. Trenton Channel 8’s retirement has been approved by MISO. Trenton Channel 7’s Attachment Y is pending. With these planned retirements, Trenton Channel’s net demonstrated capacity is projected to fall from 730 MW in 2014, to 630 MW in 2015, and then to 480 MW in 2016 and the years thereafter.

DTE Electric currently has a request for proposals (RFP) to acquire an operational natural gas-fired generating plant. A final selection has not been completed from the competing proposals submitted.

SCRs are currently installed on Monroe Units 1, 3, and 4. Monroe Unit 2 is scheduled to have an SCR operational in October 2014, Arnold noted. FGDs are currently installed and operational on Monroe Units 1, 2, 3, and 4.

DTE Electric expects to utilize REF at Monroe, St Clair, and Belle River during the 2015-2019 timeframe on some or all of the units operating at those plants. For Monroe, it is expected at this time that 98% or more of all the coal consumed on all the units from 2015-2019 will be treated with REF. For the St Clair units, the company expects at the time of the filing of this PSCR Plan case to use 1.8 million tons per year of REF treated low-sulfur western coal. The 1.8 million tons of low-sulfur western coal equals about 55% of all the coal consumed at St Clair for 2015-2019. At Belle River, the company expects that 80% of the coal being burned will be treated with REF.

Gas and petcoke are fuels used in coal units

David Milo, a Fuel Resources Specialist in the Planning and Procurement section of the Fuel Supply department, made several points in his Sept. 30 testimony:

  • The company’s 2015 PSCR plan and five-year forecast include projections for the continued use of coke oven gas at the River Rouge plant. Coke oven gas is supplied under an agreement that began in June 2009. Coke oven gas is priced at a discount to the coal expense displaced. The discounted price is 80% of the actual unit cost of coal expense for the River Rouge plant. Blast furnace gas is another source of low cost fuel in this plan and is expected to be used only at the River Rouge plant. Blast furnace gas will be supplied under an agreement that was executed in 2014. Blast furnace gas is priced at 77% discount of the average cost of coal at the plant.
  • The company’s 2015 PSCR plan and five-year forecast again include projections for the use of petroleum coke at DTE Electric’s Monroe coal plant. “Petroleum coke is our lowest cost fossil fuel and will replace higher priced coal thereby reducing the fuel expense for our customers,” Milo noted.
  • The long-term forecast of coal prices assumes the company’s continued reliance on low-cost low-sulfur western (LSW) coal. For 2015, about 87% of all coal and petroleum coke tonnage consumed is projected to be LSW coal. The LSW coal is procured from the Powder River Basin in Montana and Wyoming. The balance of the company’s coal is purchased from Central and Northern Appalachia.
  • In 2014, rail transportation providers experienced some difficulties in delivering coal at a normal scheduled rate for various reasons. However, the company has taken steps to mitigate rail supply delays during 2014 including procuring additional rail cars and utilizing alternate delivery routes and modes. The company plans to continue these mitigating activities for the 2015 PSCR Year as required.
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.