Dynegy Midwest needs variance on SO2 credit rules for coal plants

Dynegy Midwest Generation LLC (DMG) applied June 8 at the Illinois Pollution Control Board for a variance from the Illinois Multi-Pollutant Standard that would last from the time of any final board approval order, whenever that is, until April 1, 2015.

This variance would be applicable to vintage 2013 and 2014 SO2 allowances allocated by the U.S. Environmental Protection Agency or the Illinois EPA under the Cross-State Air Pollution Rule (CSAPR).

Dynegy Midwest seeks a variance from the MPS requirement that prohibits owners or operators of electricity generating units (EGUs) in an MPS Group from selling or trading to or otherwise exchanging with any person SO2 allowances allocated to EGUs starting with vintage year 2013 that would otherwise be available for sale or trade as a result of actions taken to comply with the SO2 standards under the MPS. The MPS requires that, in 2013 and 2014, EGUs in an MPS Group comply with an overall SO2 annual emission rate of 0.33 lbs/mmBtu or a rate equivalent to 44% of the base rate of SO2 emissions, whichever is more stringent.

Also, Dynegy Midwest is requesting a variance from the companion requirement that it surrender such excess SO2 allowances to the Illinois EPA. DMG noted that granting this request does not affect the requirement for DMG to comply with applicable SO2 emission rates, nor would it directly result in an air quality impact in Illinois. “DMG will suffer arbitrary or unreasonable hardship if the Board does not grant this requested variance,” the company added.

“DMG seeks this variance because surrendering, during the first two years of implementation of the CSAPR, a large quantity of SO2 allowances with significant economic value generated by DMG’s significant capital investments in SO2 pollution control equipment deprives DMG of that significant economic value, causing DMG unreasonable hardship,” explained the variation request.

DMG said that while parent Dynegy Inc. (NYSE: DYN) generally supports CSAPR as a well-designed program for emissions reduction, there are complications between CSAPR and the MPS related to how SO2 credits are handled.

Under existing regulations, DMG could not sell or transfer CSAPR SO2 allowances with vintage years of 2013 or later that are allocated in excess of the MPS SO2 standard. Because Dynegy Midwest has already installed and is operating dry scrubbers at two of its coal units and will commence operation of dry scrubbers at two other units by Dec. 31, 2012, DMG estimates it will have about 23,000 excess allocated vintage year 2013 CSAPR SO2 allowances. The monetary value of these excess cross-state SO2 allowances in the first two-year phase of CSAPR cannot be estimated with reasonable certainty at this time because the CSAPR is stayed by a federal appeals court and there currently is no active market.

“However, the value of CSAPR Group 1 SO2 allowances in the first phase of CSAPR is potentially significant,” DMG added. “The USEPA projected the price of CSAPR SO2 Group 1 allowances in 2012 at $1,000 per allowance. Before the CSAPR was stayed, vintage 2012 CSAPR SO2 Group 1 allowances traded between approximately $2,500 and $400 per ton, albeit in limited quantities in the incipient market. Trading vintage 2012 CSAPR allowances could occur now, as USEPA has left the allocated allowances in source accounts. Currently there is no market for the CSAPR allowances. However, as soon as the appeals of the CSAPR are completed, there is a possibility, if not a probability, that the CSAPR allowance market will revive. Certainly, the CSAPR allowance trading market will be revitalized when the program is reinstated. In order to optimize its SO2 allowance trading opportunities, it is important that DMG be allowed to trade allowances as soon as the market returns. Therefore, DMG seeks this variance now.”

The company also wrote: “The inability to trade or sell those excess SO2 allowances also interferes with a robust SO2 allowance trading market consistent with air quality goals of the CSAPR that would protect jobs and encourage investment in the Illinois electric generation industry.” Dynegy Midwest goes on to say that regulators should not undermine the state trading program envisioned by the CSAPR.

“Importantly, the USEPA has determined that, for 2012-2013, the CSAPR cap-and-trade program, with fully transferable SO2 allowances, ensures the elimination of each state’s significant contribution to nonattainment and interference with maintenance. Thus, DMG’s ability to trade or sell those excess allowances will not defeat the State’s effort to achieve and maintain compliance with the ozone and PM2.5 NAAQS in Illinois, nor will it defeat the efforts of other states,” the company said.

Dynegy has four operating coal plants in Illinois

Dynegy Midwest currently owns and operates four coal plants in Illinois: Baldwin in Randolph County, Havana in Mason County, Hennepin in Putnam County, and Wood River in Madison County. In November 2011, DMG permanently retired a fifth coal plant, Vermilion in Vermilion County.

The principal emissions at DMG’s coal-fired power plants are SO2. DMG generally controls SO2 emissions through the use of low-sulfur coal from the Powder River Basin with a sulfur content less than 0.3%. DMG said it does not expect to use any different type of coal during the proposed variance period, nor will the variance change the hourly rate of PRB coal use. In addition, to control SO2 emissions further, DMG has installed and is operating spray dryer absorbers (i.e., dry scrubbers) with fabric filter (i.e., baghouse) systems on two Baldwin units. DMG also is constructing a dry scrubber and fabric filter system on the third Baldwin unit (Unit 2), which will be operational by Dec. 31, 2012, and has installed a dry scrubber on Havana 6, which also will be operational by Dec. 31, 2012.

“DMG did not defer its plans to install dry scrubbers in light of the remand of the federal Clean Air Interstate Rule (‘CAIR’) in North Carolina v. EPA,” DMG noted. “These dry scrubbers have significantly reduced DMG’s system-wide SO2 emission rate. For example, SO2 average emissions over the period of 2007-2010 were 46,776 tons per year; after installation and operation of dry scrubbers on only Baldwin Unit 3 and Baldwin Unit 1 (the latter of which operated for only a little over two months in 2011), SO2 emissions in 2011 were 41,537 tons, an 11 percent reduction. DMG has determined that once the Baldwin Unit 2 and Havana Unit 6 dry scrubbers become operational in late 2012, these SO2 control measures will be sufficient for DMG to meet the SO2 limitations of the MPS rule.”

DMG controls NOx emissions at its coal-fired plants by various combinations of low-sulfur coal, low NOx burners, over-fire air, and selective catalytic reduction (SCR) systems. These installed NOx controls already allow DMG to meet the annual and seasonal NOx limits of the MPS rule; in fact, DMG has met or over-complied with the NOx limitations since 2007, the company said.

Particulate matter (PM) is generally controlled through the use of flue gas conditioning, electrostatic precipitators (ESPs), and fabric filter systems. More specifically, DMG has installed and is operating a fabric filter system on Baldwin units 1 and 3 (the Baldwin Unit 2 fabric filter system is under construction and will be operational by Dec. 31, 2012), Havana Unit 6 and Hennepin Units 1 and 2.

Under the MPS provisions established in the Illinois mercury rule, DMG currently controls mercury emissions at its coal-fired plants (except Wood River Unit 4, which has an initial MPS compliance date of Jan. 1, 2013) by using activated carbon injection or mercury oxidation systems in conjunction with SCRs, dry scrubbers, ESPs, and fabric filters. DMG will be able to meet the MPS mercury requirement at Wood River 4.

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.