DTE Electric retrofitting some coal capacity for MATS compliance

DTE Electric has plans to retire minimal coal-fired capacity in the near term, but has placed some of its other coal-fired capacity in a lower-ranked maintenance tier that indicates longer term doubt about the viability of that capacity.

DTE Electric, a unit of DTE Energy (NYSE: DTE), on Dec. 19 filed a major rate case application at the Michigan Public Service Commission.

In that application, DTE Electric Vice President Fossil Generation Franklin Warren said about power plant retirements: “Fossil Generation has retired Marysville and Conners Creek Power Plants. These plants were in a cold standby status at the time the last main rate case was filed. Marysville and Conners Creek Power Plants had a combined generation capability of 406 megawatts at the time they were retired. On March 1, 2013 Fossil Generation retired the diesel peaking units at the Conners Creek and Dayton sites for a total of 9 MW. As of January 2014 DTE Electric also retired Harbor Beach Unit 1 which was a coal fired steam unit rated at 103 MW and 4 MW of diesel peaking units also located at the Harbor Beach site.”

As for future retirements, he added: “Trenton Channel Unit 8, a 100 MW coal fired unit, is currently scheduled to be retired as of April 15, 2015 and Trenton Channel Unit 7A’s 110 MWs is scheduled to be retired on or before April 16, 2016.”

Capacity reductions to existing units are planned between 2014 and 2016. Capacity reductions of 12.5 MW have occurred on both the coal-fired Monroe Unit 1 and Unit 2 due to increased internal load requirements associated with startup of new Flue Gas Desulfurization (FGD) equipment. Trenton Channel Unit 9 is forecasted to have its capacity reduced to 480 MWs, a 40 MW decrease, when Trenton Channel Unit 7A is retired in the spring of 2016. River Rouge Unit 2 and River Rouge Unit 3 are forecasted to also experience capacity reductions of 10 MW and 35 MW respectively starting in April of 2016 due to using increased low sulfur western coal blends to allow the units to comply with the expected 1 hour SO2 limit associated with the National Ambient Air Quality Standards (NAAQS). Trenton Channel Unit 9 is also expected to operate on increased low sulfur western coal blends to allow the units to comply with NAAQS.

Warren noted about future plant operations: “The availability of the Fossil Generation base load coal units is forecasted to be 77.8%, 79.9%, 79.8%, 80.4%, 79.9% and 80.3% for the years 2014-2019 respectively. This is slightly lower than the actual 2013 level of 80.4%. Base load coal plants include all coal fired units/plants. The non-base load coal plants/units at Harbor Beach and Trenton Channel Unit 8 have or will be retired in 2014/2015.

“In anticipation that certain coal fired generating units will be retired years before others, Fossil Generation created a tiered maintenance and investment strategy. Three tiers were established for long-term, mid-term and short-term units. The short-term units were identified as Harbor Beach and Trenton Units 8. The long-term coal fired units were identified as Belle River and Monroe. Fundamental in this tiered strategy was establishment of different operating performance metric targets which drive both the O&M and capital investment plans for these units. In support of this strategy [random outage factor] ROF targets for Monroe and Belle River Power Plants are currently being set at 1st quartile or better while ROF targets for the remainder of the base load coal units are being set at 3rd quartile or better based on three year historic industry benchmarks of similar units.”

He added: “The Company’s efforts to maintain overall Fossil Generation availability is based on placing priority on maintenance investment in the Monroe and Belle River units to sustain high levels of performance while minimizing future investments in the coal fired units at Trenton Channel, River Rouge and St Clair Power Plants. Although investments are being minimized at these three plant sites, all necessary work to safely operate the units and to comply with legal and regulatory requirements will be completed.”

Coal units are getting DSI and SCI retrofits to meet air emissions needs

Warren wrote about air emissions control needs: “Approximately $265 million is being invested at Monroe Power Plant to complete the installation of the FGD/Selective Catalytic Reduction (SCR) environmental emissions control technology. Fossil Generation is also investing approximately $239 million at Belle River, Trenton Channel, St Clair and River Rouge Power Plants to meet new Mercury and Air Toxics Standards (MATS) environmental rules. Without this Activated Carbon Injection/Dry Sorbent Injection (ACI/DSI) investment, environmental regulations would not allow these plants to operate and over 3,000 MW of capacity provided by these four power plants would be lost from the system by April 2016. The requirements, timing and economic alternatives evaluated in the justification and testing process associated with DTE Electric’s ACI/DSI investment plan has been well documented.”

DTE Electric applied for and was granted by the Michigan Department of Environmental Quality (MDEQ) one-year extensions to MATS compliance dates at its Belle River, St. Clair, River Rouge, and Trenton Channel plants. Therefore, the compliance deadline for those four plants is currently April 16, 2016. The compliance date for the Monroe Power Plant remains April 15, 2015.

The FGD scrubber on Monroe Unit 1 began testing operations in December of 2013 and the Unit 2 scrubber began testing operations in June 2014. The scrubbers on Units 3 and 4 were placed into service in 2009. The SCR’s on Units 1 and 4 at Monroe were placed into service in 2002 and the SCR on Unit 3 was placed into service in 2006. Once the final SCR installation was completed in October 2014, Monroe Power Plant can achieve a 90% reduction in NOX emission rate compared to emissions without SCRs in service.

DTE Electric’s coal steam plants and their net winter capability are:

  • Belle River (less MPPA ownership), 1,035 MW, two units
  • Harbor Beach, 103 MW, one unit
  • Monroe, 3,110 MW, four units
  • River Rouge, 540 MW, two units
  • St. Clair, 1,416 MW, six units
  • Trenton Channel, 730 MW, three units

The Michigan Public Power Agency (MPPA) is joint owner of Belle River Power Plant and its ownership entitlement is effectively 18.61% (234 MW) of the plant.

DSI/ACI are low-cost systems for plants with questionable futures

Irene Dimitry, Vice President of Business Planning & Development for DTE Energy Corporate Services LLC, said in accompanying testimony: “DSI/ACI installation requires much lower capital costs compared to FGD/SCR installation. Capital cost for DSI/ACI installation on St. Clair, Belle River, Trenton 9 and River Rouge is estimated to be approximately $238 million or $73/kW (on approximately 3,280 MW DTE Electric owned net demonstrated operating capacity). Included in the $238 million total, the capital cost for DSI/ACI installation on Belle River is estimated to be approximately $55 million or $53/kW (on 1,034 MW DTE Electric owned net demonstrated operating capacity). In contrast, capital cost for FGD/SCR installation on Belle River is estimated to be6 $890 million or $860/kW (on 1,034 MW DTE Electric owned net demonstrated operating capacity).”

Dimitry added: “[T]he installation of DSI/ACI provides DTE Electric the flexibility to retire our fleet in an orderly manner, which is important for maintaining system grid reliability. St. Clair, Belle River, Trenton 9 and River Rouge are the base-load generation DTE Electric has relied on to supply electricity to DTE Electric customers. Retiring the plants all at once could potentially bring profound reliability challenges to the local electric grid, and could disrupt MISO wholesale energy markets thereby increasing transmission congestion and causing energy price spikes.”

  • “Based on our evaluation, the installation of DSI/ACI on St Clair units 1-4, compared to retiring the units and replacing with market purchases and new generation plant construction, results in a reduction for our customers of $54 million in the [net present value of revenue requirements] over the period of 2014-2035.”
  • “The installation of DSI/ACI on St Clair units 1-4, 6 and 7, compared to retiring the units and replacing with market purchases and new generation plant construction, results in a reduction of $105 million in the NPVRR over the period of 2014-2035 for our customers.”
  • “The installation of DSI/ACI on Trenton 9, compared to retiring the unit and replacing with market purchases and new generation plant construction, results in a reduction of $83 million in the NPVRR over the period of 2014-2035 for our customers.”
  • “The installation of modular DSI/ACI on River Rouge 2 and 3, compared to retiring the units and replacing with market purchases, results in a reduction of $16 million in the NPVRR over the period of 2014-2035 for our customers.”

The Modular DSI system for River Rouge differs from the full DSI/ACI system in that the sorbent storage is in trailers rather than silos. In addition, the injection equipment is leased rather than owned. This lowers the cost and revenue requirement for the DSI/ACI installation. River Rouge will be burning 100% Low Sulfur Western (LSW) coal, and as a result, the Trona requirements will be less than if it were to have the ability to blend higher sulfur coals. Therefore, a smaller DSI/ACI storage system at River Rouge is adequate. This contrasts with St. Clair and Trenton 9, in which the ability to blend to higher capacities has more value than the savings that would be achieved by using modular DSI. The system size requirement at Belle River is simply too large for a modular system.

“Belle River was not analyzed like the other coal units,” Dimitry noted. “Belle River, at 1,034 MW DTE Electric-owned net demonstrated operating capacity, is the newest coal plant owned by the Company. With the exception of Monroe, Belle River has the lowest fossil-fueled dispatch cost and the best long-term economics. It is a coal plant that the Company does not consider as a candidate for early retirement.

“Instead, we analyzed two different scenarios on Belle River: 1) installing FGD on Belle River in 2016 (FGD scenario) and 2) installing DSI/ACI on Belle River in 2016, followed by FGD installation in 2020 (DSI/ACI scenario). The study indicated that the DSI/ACI scenario reduced the net present value of the revenue requirement for Belle River by approximately $40 million when compared to the FGD “only” scenario. More importantly, the economic risk of making the large capital expenditure of FGD on a plant in an environment of uncertain CO2 regulations is eliminated. The pressure to replace such a large generating plant of high capacity factor in a short timeframe is also eliminated.

“The Company has addressed the uncertainty of potential future CO2 regulation in its analysis. By implementing a plan that minimizes capital expenditures while fully meeting EPA MATS regulation, the DSI/ACI installation generates the “lowest cost” for our customers, even if the plants were subsequently shut down for any reason (e.g., future CO2 regulations, other legislation/regulation, economics, etc.) in the early 2020’s.”

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.