DTE Electric (formerly known as Detroit Edison) will make capital expenditures of approximately $335m in 2013 and up to approximately $1.6bn of additional capital expenditures through 2020 based on current environmental regulations, said parent DTE Energy (NYSE: DTE) in its Feb. 20 annual Form 10-K report.
DTE Electric, which has several coal-fired power plants, including the 3,047-MW Monroe facility, is subject to the U.S. Environmental Protection Agency’s ozone and fine particulate transport and acid rain regulations that limit power plant emissions of SO2 and NOx. Since 2005, the EPA and the state of Michigan have issued additional emission reduction regulations relating to ozone, fine particulate, regional haze, mercury, and other air pollution. These rules have led to additional controls on fossil-fueled power plants to reduce NOx, SO2, mercury and other emissions. To comply with these requirements, DTE Electric has spent around $1.9bn through 2012.
Additional rulemakings are expected over the next few years which could require additional controls for SO2, NOx and hazardous air pollutants.
DTE Electric’s generating capability is heavily dependent upon the availability of coal. The company has long-term and short-term contracts to buy about 22.1 million tons of low-sulfur western coal to be delivered from 2013 through 2015 and about 3.5 million tons of Appalachian coal to be delivered from 2013 through 2014. It has approximately 81% of its 2013 expected coal requirements under contract.
DTE Electric’s capital investments over the 2013-2017 period are estimated at $4.7bn for base infrastructure, $1.2bn for mandated environmental compliance requirements and $500m for renewable energy and energy efficiency expenditures.
In 2008, a renewable portfolio standard was established for Michigan electric providers targeting 10% of electricity sold to retail customers from renewable energy by 2015. DTE Electric has about 720 MW of owned or contracted renewable energy, principally wind turbines located in Gratiot, Tuscola, Huron and Sanilac counties in Michigan, as of Dec. 31, 2012, representing about 8% of electricity sold to retail customers. About 510 MW was in commercial operation as of Dec. 31, 2012, with an additional 210 MW expected in commercial operation in 2013 or early 2014.
Company outlined compliance planning to Michigan PSC
The company didn’t give details about compliance plans in the Form 10-K. But DTE Electric said in a September 2012 filing at the Michigan Public Service Commission that it has determined that the most cost-effective mercury reductions at its coal-fired power plants will occur as a co-benefit through the combination of wet flue gas desulfurization (FGD) and selective catalytic reduction (SCR) systems on Monroe Units 1-4.
The most cost-effective mercury reductions on the remaining coal-fired units operating without wet FGD will be achieved with the installation and operation of activated carbon injection (ACI) systems. Also, the company has determined that using reduced emission fuel (REF), which is coal with chemical additives, improves the performance of both FGD and ACI in meeting the required mercury reductions in the most cost-effective manner, wrote William Rogers, employed by DTE Energy Corporate Services LLC as a Senior Technological Specialist–Environmental Strategies.
Rogers was one of several company officials supplying testimony filed Sept. 28 with the Michigan Public Service Commission as part of an annual Power Supply Cost Recovery (PSCR) case. Notable is that the PSCR case begun in September 2011 is still ongoing and lately has featured arguments about expenses to Detroit Edison customers from the REF program.
The utility said new emissions controls testing has been so successful that it now expects to keep open for the time being several coal-fired generating units that it once planned to close.
The purpose of his testimony was to explain Detroit Edison’s mercury control requirements, strategy for compliance, and to explain how the use of REF at the St. Clair and Belle River power plants, combined with ACI, supports compliance with mercury rules at the lowest reasonable cost to the customer. The use of REF at Monroe, combined with FGD, supports compliance with mercury rules at the lowest reasonable cost, he added. He also explained how the company plans to use dry sorbent injection (DSI) technology to comply with EPA’s Mercury and Air Toxics Standards (MATS).
Besides MATS, mercury reduction needs at Detroit Edison are driven by 2009 regulations known as the Michigan Part 15 Air Pollution Control Rules. These rules require every regulated coal-fired power plant in Michigan to comply on and after Jan. 1, 2015.
At the giant Monroe plant, FGD and SCR have been and are being installed primarily for SO2 and NOx reductions required by separate rules from Michigan Part 15 Rules and EPA’s MATS. FGD and SCR on Monroe Units 1-4, along with fuel blending and combustion controls on other units, cost-effectively meet the SO2 and NOx reductions required by current regulations. If further reductions are required in the future, equipment installations on additional units may be a cost-effective solution for compliance, Rogers noted.
Since the FGDs were put into service on Monroe Units 3 and 4, mercury emissions have been frequently measured and compared to Michigan Rule 1503 and EPA’s MATS mercury limits. While the Monroe Units 3 and 4 FGDs consistently meet Michigan Rule 1503 mercury standards, additives have been required to maximize vapor phase mercury oxidation, which would increase mercury removal by the FGD for continuous compliance with EPA’s more stringent MATs standards and assure compliance with Rule 1503 requirements. These are the same additives that are used in REF.
Emissions retrofits now look better than further coal retirements
Robert Palmer, Manager of Asset Optimization in the Fossil Generation Organization of Detroit Edison, also offered Sept. 28 testimony that concentrated on equipment installations and power plant retirements.
A projected capacity decrease in 2013 is associated with the retirement of the Dayton and Conners Creek diesel peakers, Palmer wrote. A projected capacity increase in 2014 is associated with the 26.3-MW Ludington Unit 4 upgrade that is partly offset by a decrease associated with increased auxiliary power usage from FGD scheduled for installation in late 2013 and early 2014 on Monroe Units 1 and 2. Monroe Unit 1 will have a 12 MW decrease in net demonstrated capacity (NDC) in December 2013 and Monroe Unit 2 will experience a similar 12 MW decrease in NDC in May 2014 when it returns from its scrubber tie-in outage.
A projected capacity decrease in 2015 is associated with planned retirement of Harbor Beach (-103 MW) and Trenton Channel Units 7 and 8 (-210 MW) which are partially offset by the scheduled Ludington Unit 5 upgrade (+26.3 MW). Projected capacity increases in 2016 and 2017 are associated with the Ludington Units 1 and 2 upgrades.
Detroit Edison had indicated in a prior PSCR case that a projected capacity decrease in 2015 was associated with possible retirements of Harbor Beach, River Rouge Units 2-3, St. Clair Unit 7 and Trenton Channel Units 7-9, which were to be offset by the assumed addition of a combined cycle unit and the Ludington Unit 5 upgrade. Modified environmental rules and DSI/ACI testing performed by the company indicate that River Rouge Units 2 and 3, St Clair Unit 7 and Trenton Channel Unit 9 can cost-effectively comply with the MATS rules utilizing DSI for acid gas emissions reductions and ACI for mercury emissions reductions, Palmer reported.
Operation of River Rouge Units 2-3, St Clair Unit 7 and Trenton Channel Unit 9 beyond 2015 will also allow the deferral of the assumed need to build a new combined-cycle power plant. The company has assumed for PSCR planning purposes the retirement of Trenton Channel Units 7-8 in 2015. However, the ultimate retirement remains uncertain, Palmer added.