DTE Electric defends air emissions plans for coal-fired units

DTE Electric (until recently known as Detroit Edison) says that environmental group critics are wrong and that it is justified in moving forward with coal-unit saving emissions control systems and reduced emissions fuel (REF) use at certain power plants.

DTE Electric, a unit of DTE Energy (NYSE: DTE), on July 18 filed with the Michigan Public Service Commission its latest arguments in its 2013 power supply cost recovery (PSCR) case, which began in September 2012. Briefs in the case have also been filed lately by commission staff, the Michigan Attorney General (AG), the Michigan Community Action Agency Association (MCAAA), and the Michigan Environmental Council and Natural Resources Defense Council (collectively called “MEC/NRDC”).

“MEC/NRDC attempt to pursue their anti-coal agenda in this case, suggesting that Edison’s PSCR plan and five-year forecast are not reasonable and prudent because Edison allegedly would have lower PSCR costs if it had different (more gas; fewer coal) generating units,” said DTE’s July 18 brief. “This topic is not relevant to this PSCR proceeding pursuant to Act 304’s plain statutory language, which must be applied as written. Based on MEC/NRDC’s flawed premises (unfounded criticism of Edison’s forecast methodology and unlawful contention that a five-year forecast is not restricted to an evaluation of the utility’s existing generation resources), MEC/NRDC further asserts that Edison’s ‘aging generation fleet’ is becoming ‘less competitive,’ so the Commission should indicate that it would be ‘unlikely to permit full recovery of the PSCR costs for continued operation of DTE Electric’s aging coal plants.’”

DTE requests that the commission in its order in this PSCR case decline to issue a warning that the commission is unlikely to permit the company to recover the mercury emission-related expense associated with sorbents (e.g., powdered activated carbon (PAC) and Brominated PAC (BrPAC)) for 2015 and thereafter, as well as declining to issue a warning that the commission is unlikely to permit the company to recover the trona and sodium bicarbonate (SBC) expenses related to control of particulate matter and acid-gas emissions for 2015 and thereafter.

MEC/NRDC assert that the commission should inform DTE that it is unlikely to authorize recovery of PSCR costs for Dry Sorbent Injection (DSI) and Activated Carbon Injection (ACI) sorbents at plants for which use of such sorbents is allegedly not part of a least cost compliance plan. The commission rejected similar arguments in Edison’s 2012 PSCR plan case, DTE noted.

In 2015, DTE is faced with new emissions mandates for mercury under the federal Mercury and Air Toxics Standards (MATS), as well as a Michigan mercury rule. DTE plans to save some of its coal units by using DSI technology to comply with the MATS HCl emission limitations. DSI is designed to remove acid gases from the flue gas stream by injecting alkaline sorbents in the flue gas leaving a coal-fired boiler. DTE’s test program demonstrated that trona and SBC are the most cost-effective sorbents to use for the MATS requirements. The company currently forecasts that it will use trona to control acid gases and PM.

The company expects to use activated carbon as the mercury sorbent to address the mercury reduction requirements at several of its power plants, and that DSI in combination with ACI will allow it to meet the MATS acid gas and particulate matter environmental requirements at some of its coal-fired generating units.

The company said it expects to request recovery in 2015 of the cost of mercury sorbents (PAC and BrPAC) and alkaline sorbents (trona and SBC) used in these processes through the PSCR as an integral part of the cost of power supply, a cost of fuel burned, and a disposal cost of fuel.

DTE argues for continued use of treated coal program

Another major point of rebuttal in the July 18 DTE filing was about the REF program, where chemicals are added to coal before it is burned to reduce emissions of mercury and other pollutants. Under that program, non-regulated units of DTE Energy buy coal out of stockpile, treat it, and then sell it back to the regulated DE Electric for use at the power plants. In essence, DTE Electric ratepayers are paying these costs, with DTE Energy deriving profits from them. DTE Electric says that the REF deals with non-regulated affiliates were worked out in “arms length” negotiations and have several benefits for utility ratepayers, including that the non-regulated affiliates are taking on the technology and federal tax credit risks of the REF systems.

In addition to the environmental benefits of the emission reductions, DTE’s use of REF is expected to reduce the need for NOx and SO2 emission allowances, the cost of which are recovered in its PSCR process. In addition, mercury emissions will become regulated in 2015, and REF use will also reduce the expense for reducing mercury emissions, the utility argued.

“The cost of REF is a cost of fuel burned for electric generation, is an integral part of prudent fuel procurement and utilization, and constitutes a disposal cost of fuel,” DTE wrote. “Therefore, it is properly recovered in Edison’s PSCR for the same reasons that urea is recovered in the Company’s PSCR, as there would be a direct tradeoff between the use of REF and Detroit Edison’s consumption of NOx and SO2 emission allowances, and the reduction of mercury emissions.”

REF is being consumed at the St. Clair Power Plant (SCPP) Units 1-4 and 6, with a targeted annual REF consumption of approximately 1.8 million tons. The Monroe Power Plant (MPP) has been consuming REF at all four units since November 2011. REF is continuing to be tested at the Belle River Power Plant (BRPP), and the company’s PSCR forecast assumes both units at Belle River will begin consuming REF fulltime in 2014.

“The REF business arrangements at the St. Clair and Belle River power plants allow Detroit Edison customers to receive cost reductions through their base rates without increasing costs to PSCR customers, since the Refined Coal Adder at St. Clair and Belle River will never exceed the environmental benefits realized by customers,” DTE wrote. “The REF business arrangement at Monroe allows Detroit Edison 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 (‘MFC’) and the value of reduced NOx, SO2, and mercury emissions. In all instances, Detroit Edison’s customers benefit without assuming any technology, tax or capital risk.”

The company has determined that the most cost-effective mercury reductions will occur as a co-benefit through the combination of wet flue gas desulfurization (FGD) systems (installed primarily for reduction of SO2) and selective catalytic reduction (SCR) systems (installed primarily for NOx reduction) at the giant Monroe power plant. REF improves the operation and efficiency of the wet FGD at Monroe, avoids capital expenditures by DTE, and removes the need for additional costly additives to achieve full mercury control requirements, the company said.

At its coal-fired plants that do not have wet FGD systems, including St. Clair and Belle River, the most cost-effective means of mercury reductions will be achieved with installation and operation of ACI systems. REF improves the economics of the operation of these ACI systems by permitting use of a less expensive form of powdered activated carbon (PAC), DTE noted.

PSC staff said in its July 18 brief that it continues to support what it said in its initial brief in this case. “In Staff’s initial brief, Staff indicated that it supported a finding by the Commission that the Company’s plan is reasonable and prudent. Staff further indicated that it supported a finding with respect to the Company’s five-year forecast that, on the basis of present evidence, there are not any cost items that the Commission would be unlikely to permit the utility to recover from its customers in the future. Staff also noted that with respect to the issue concerning the REF additive, the Commission had not yet issued its 2012 plan order where essentially the same issue was pending.”

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.