DTE Electric to retire a little over 200 MW of coal capacity

DTE Electric has successfully tested dry sorbent injection (DSI) at several of its coal-fired units, and because DSI testing has been so successful, it expects to use alkaline sorbents such as trona or sodium bicarbonate (SBC) to assist it in meeting the Mercury and Air Toxics Standards (MATS) at certain coal units.

This DTE Energy (NYSE: DTE) subsidiary, formerly known as Detroit Edison, described its latest clean-air planning in a power supply cost recovery (PSCR) plan filed Sept. 30 at the Michigan Public Service Commission. Barry Marietta Jr., employed by DTE Energy Corporate Services LLC within Environmental Management & Resources as a Supervisor–Emissions Quality, provided much of that testimony.

The MATS rule has an initial compliance date of April 16, 2015. However, DTE Electric applied for and received one-year extensions for the compliance date at its Belle River, St. Clair, River Rouge, and Trenton Channel plants, Marietta noted. Therefore, the compliance deadline for those four plants is currently April 16, 2016. The compliance date for the massive Monroe coal plant, which has gotten extensive new emissions controls in recent years, remains April 15, 2015.

The state of Michigan promulgated regulations establishing limits for emissions of mercury from Electric Generating Units (EGUs) that were finalized in October 2009 and are known as Michigan Part 15 Air Pollution Control Rules. 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 beginning in 2016 at Belle River, St. Clair, River Rouge and Trenton Channel. The installation and operation of flue gas desulfurization (FGD) and selective catalytic reduction (SCR) on all four Monroe units by April 2015 along with reduced emissions rule (REF) will provide compliance with mercury emission limitations. REF is coal treated with chemical additives prior to combustion.

EPA identifies DSI as an alternative to FGD for MATS compliance with acid gas limits, and, in fact, forecasts 44 GWs of DSI installations across the country for MATS compliance, Marietta noted. DSI was tested on two separate DTE Electric coal-fired units, corroborating EPA and vendor forecasts for performance. These tests clearly demonstrated that DSI technology is capable of reducing emissions to MATS-compliance levels on DTE Electric units burning predominantly subbituminous coals.

“In summary, the Company will comply with MATS emission limitations at Monroe Power Plant by installing and operating FGD and SCR systems on all four units by April 2015,” Marietta wrote. “The remaining coal-fired units in operation will comply with MATS emission limitations with a combination of DSI and ACI emission control systems by April 2016 due to receiving MATS compliance extensions from [the Michigan Department of Environmental Quality]. 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 the state and federal mercury rules at the lowest reasonable cost.”

REF coal, which has kicked up past controversy, to be used extensively

At coal burning plants with no FGD, such as Belle River and St. Clair, consuming REF will significantly lower powder activated carbon (PAC) 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 BrPAC. 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.

At coal-burning plants with FGD, such as Monroe, 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, Marietta said. 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.

Use of REF is expected to also result in other environmental benefits such as lower emissions of NOx and SO2. The largest benefit, however, will be realized for mercury control.

The use of REF, which is basically stockpile coal that is treated by non-regulated DTE Energy subsidiaries and then sold back to the regulated DTE Electric, caused controversy in last year’s PSCR case due to the profits DTE Energy will make from this program at the expense of ratepayers. Kevin O’Neill, employed by DTE Energy Corporate Services LLC within Regulatory Affairs as a Principal Case Manager, addressed that issue in this year’s case filing.

“The consumption of REF never increases the Company’s requested maximum PSCR factor,” O’Neill said. “Quite simply, if the use of REF does not provide cost savings in reducing mercury emissions, then the REF adder for purposes of the PSCR will be zero. The Commission-approved REF business arrangements at the St. Clair and Belle River power plants allow DTE Electric customers to receive cost reductions  through their base rates without increasing costs to PSCR customers since the REF adder at St. Clair and Belle River never exceeds the environmental benefit realized by the customer. The Commission-approved REF business arrangement at the Monroe Power Plant allows DTE Electric customers to receive cost reductions through their base rates while PSCR customers realize lower cost through the Coal Fee Rate paid by the Monroe Fuels Company and the value of reduced NOx, SO2, and mercury compliance costs. In all instances, DTE Electric’s customers benefit without assuming any technology, tax or capital risk.”

The “tax” reference is to the fact that this treated coal qualifies for federal tax credits.

Only Harbor Beach and Trenton Channel 8 on the coal retirement list

Robert Palmer, the Manager of Asset Optimization in the Fossil Generation Organization of DTE Electric, addressed issues like planned coal unit retirements.

From 2013 to 2014 there is a net 27 MW decrease of capacity in the owned DTE Electric generation fleet. The retirement of the Harbor Beach Power site and the increased parasitic load at Monroe as the FGD equipment become operational on Units 1 and 2 are mostly offset by an increase in Ludington pumped storage hydro generation, plus new wind and solar capacity. In 2015, Trenton Channel Unit 8 retires and this is mostly offset by more increases in Ludington output along with new wind and solar. For 2016-2018, the generation capacity of the DTE Electric fleet increases by about 26 MW each year as the Ludington upgrade project continues with one unit being completed each year.

In a prior case Palmer indicated that Harbor Beach would retire at the end of 2015 and that Trenton Channel 7 and 8 would both be retired in 2015. He didn’t mention before that the 4 MW of peakers located at the Harbor Beach plant site are also being retired in 2014.

As a participant in the MISO market the company cannot unilaterally retire units. The company must make a request to MISO to study the system reliability impacts of any retirements and obtain their permission to retire units on a certain date. In November 2010 the company made such a request to MISO for Harbor Beach. The request was updated in December 2011 to request a retirement date of Jan. 1, 2012.

In its response, MISO declared Harbor Beach a System Security Resource (SSR) and stated that the earliest date the plant would be allowed to retire would be Dec. 31, 2015. That date was based on the schedule for transmission upgrades being performed in the thumb of Michigan by ITC Transmission.

DTE held further discussions with MISO and ITC during late 2012 and early 2013 in an attempt to find a mutually acceptable retirement date for Harbor Beach that could take effect before the April 2015 MATS rules would otherwise force the economic retirement of the coal-fired Harbor Beach capacity. MISO and ITC performed further transmission system reliability analysis at the request of the company and determined that a partial completion of the thumb transmission upgrade would allow Harbor Beach to retire while still maintaining MISO reliability standards for the transmission grid. That partial transmission system upgrade was planned to be completed near the end of 2013. For purposes of this 2014 PSCR plan case, the Harbor Beach Power plant (103 MW) and the 4 MW of diesel peakers located on the site are assumed to be retired as of Jan. 1, 2014.

The company received a letter dated Sept. 10 from MISO indicating that MISO will not seek an extension of the SSR agreement which expires on Sept. 30. Based on this information, the company is moving ahead with the retirement of Harbor Beach in 2013.

Trenton Channel Unit 7 falls off the retirement list

As for Trenton Channel Units 7 and 8, further engineering analysis of the combined DSI/ACI) testing performed by the company indicate that conversion of the Trenton Channel Boilers 16-19 to a fuel blend of 100% low sulfur Western (LSW) coal combined  with a reduction in plant output by 100 MW with the retirement of Trenton Channel Unit 8 could allow the DSI/ACI technology to be employed on Trenton Channel Boilers 16-19 without the need to install a baghouse to augment the performance of the electrostatic precipitators.

Current plans are to retire Trenton Channel Unit 8 while Trenton Channel Unit 7 will have DSI/ACI technology installed to make the boilers compliant with the MATS rules that are now required to be completed at Trenton Channel by April 2016 (after a one-year MATS compliance extension from Michigan regulators).

DTE Electric expects to utilize REF at Monroe, St Clair and Belle River during the 2014-2018 timeframe on some or all of the units operating at those plants. For Monroe, it is expected at this time that 96% of all the coal consumed on all the units from 2014-2018 will be treated with REF. For St Clair, 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 LSW coal. The 1.8 million tons of LSW coal equals approximately 60% of all the coal consumed at St Clair for 2014-2018. Belle River Power Plant expects to continue testing of REF in 2014 and starting in 2015 through 2018 the company at the time of the filing of this PSCR plan case expects that 75% of the coal being burned at Belle River will be treated with REF, dependent upon the outcome of testing.

The mentioned power plants, with current net capacities for the 2013-2018 period, are:

  • Belle River (DTE ownership share), 1,034 MW;
  • Harbor Beach, 103 MW, falling to zero in 2014 with plant retirement;
  • Monroe, 3,110 MW;
  • River Rouge, 540 MW;
  • St. Clair, 1,416 MW; and
  • Trenton Channel, 730 MW, falling to 630 MW in 2015 with Unit 8 retirement.
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.