Georgia Power, a unit of Southern Co. (NYSE:SO), has managed to avoid environmental retrofits on plants like the coal-fired Kraft facility under regional haze rules by planning to slash the utilization of those plants over the next few years.
In the Feb. 27 Federal Register, the U.S. Environmental Protection Agency published a decision to approve parts of a revision of Georgia’s state implementation plan (SIP). It had also previously decided to disapprove part of the SIP proposal, but that disapproval was not detailed in the Feb. 27 notice. The partial disapproval was because of deficiencies in the state’s regional haze SIP submittal arising from the fact that the revised SIP depended on EPA’s Clean Air Interstate Rule, which was remanded back to EPA by the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit).
The proposed revision was submitted to EPA by the Georgia Department of Natural Resources, Environmental Protection Division (GA EPD), in February 2010, and supplemented in November 2010. This SIP revision addresses the requirements of the Clean Air Act (CAA) and EPA’s rules that require states to prevent any future and remedy any existing anthropogenic impairment of visibility in mandatory Class I areas (national parks and wilderness areas) caused by emissions of air pollutants from numerous sources located over a wide geographic area. States are required to assure reasonable progress toward the national goal of achieving natural visibility conditions in Class I areas. Comments on the partial approval are being taken through March 28.
In the partial approval is GA EPD’s decision to accept reasonable progress decisions related to several industrial and utility plants. Among them is Georgia Power’s coal-fired Kraft Units 1-3. These units are rated at 50, 54, and 104 MW, respectively. Units 1 and 2 each contribute to the total sulfate visibility impairment at the Wolf Island Class I area. Unit 3 was initially determined to contribute to the total sulfate visibility impairment at three Class I areas. However, with projected reductions in SO2 emissions by 2018, the visibility impacts on the Okefenokee and Cape Romain Class I areas from Units 1-3 are expected to drop below Georgia’s minimum threshold for reasonable progress evaluation, and the visibility impact at Wolf Island should drop below 2%.
The 2018 projected SO2 emissions for Kraft Units 1-3 were initially estimated at 691 tons per year (tpy), 704 tpy, and 4,474 tpy, respectively. As part of the supporting documentation for the reasonable progress control analyses, Georgia Power provided projected heat input through 2018 for these units, which indicates that SO2 emissions for Units 1-3 will be 632 tpy, 889 tpy, and 2,455 tpy, respectively.
While the heat inputs provided by Georgia Power for Kraft Units 1 and 2 are similar to the 2018 projections, Georgia Power’s projection for Unit 3 represents a 45% reduction in heat input and SO2 emissions from the projections. This was explained by Georgia Power as the result of additional capacity coming on-line elsewhere between 2010 and 2017. The reduction in heat input for Kraft is expected to occur around 2015. GA EPD utilized these revised heat inputs in conducting the reasonable progress control analyses, and GA EPD plans to verify the heat input reduction during development of the next regional haze SIP (due in 2018).
The following control measures were analyzed for the four statutory factors for all three Kraft units: wet flue gas desulfurization (FGD): switching to a lower-sulfur coal; and coal washing to remove sulfur. Wet FGD, also known as SO2 scrubbers, could not be installed until 2016 because of other required control device installations scheduled up until 2015 in Georgia Power’s system. The company did not address the implementation time for the other control options, so GA EPD assumed the controls could be implemented by Jan. 1, 2012.
All three control options would require additional energy usage. Wet FGD and coal washing would result in increased water usage and wastewater discharges as well as additional solid waste generation. The remaining useful life of the units extends past 2018 and past the control equipment amortization periods. The state eliminated coal switching and FGD from consideration due to cost effectiveness considerations and coal washing because it would have minimal impact on plant emissions. Based on these considerations, no additional controls were required for any of the Kraft units.
McIntosh to also get heat input slashed
Another facility subject to reasonable progress provisions is McIntosh Unit 1, a 178-MW coal unit. The 2018 projected SO2 emissions were initially estimated at 7,015 tpy. As part of the supporting documentation for the reasonable progress control analyses, Georgia Power provided projected heat input through 2018 for this unit. Those projections indicate that SO2 emissions will drop to 1,860 tpy by 2018. Georgia Power’s projection represents a 73% reduction in heat input and SO2 emissions. This was explained by Georgia Power as a result of additional capacity coming on line elsewhere between 2010 and 2017.
The state initially determined that the McIntosh unit impacts visibility at five Class I areas. However, with the projected reduction in SO2 emissions by 2018, the visibility impacts on all of these areas except Wolf Island are expected to drop below Georgia’s evaluation threshold. The reduction in heat input for McIntosh is to occur between around 2011 and 2016. Georgia Power also analyzed wet FGD, coal switching and coal washing as options for this unit. Wet FGD could not be installed until 2016 because required control device installations are scheduled up until 2015 in Georgia Power’s system. Again, those three options were rejected, like they were for Kraft.
Georgia Power’s Mitchell Unit 3, a coal-fired steam-generating unit rated at 163 MW and the only remaining operational boiler at Mitchell, was also subject to reasonable progress evaluation. The 2018 projected SO2 emissions were initially estimated at 4,930 tpy. Georgia Power provided projected heat input through 2018 for this unit that indicate that SO2 emissions will drop to 1,189 tpy by 2018. Georgia Power’s projection represents a 76% reduction in heat input and SO2 emissions. This was explained by Georgia Power as a result of additional capacity coming online elsewhere starting in 2010. The reduction in heat input for Mitchell was to occur between around 2008 and 2010. GA EPD plans to verify the heat input reduction during the regional haze periodic progress review.
Georgia Power analyzed wet FGD and coal switching as possible control measures at Mitchell Unit 3. Wet FGD could not be installed until 2016 because required control device installations are scheduled up until 2015 in Georgia Power’s system. Both options were ultimately rejected.
Another category in EPA’s proposed approval of Georgia’s revised SIP is Best Available Retrofit Technology determinations. Georgia Power’s coal-fired Bowen plant is in that category. Bowen has four BART-eligible emissions units that comprise the BART-eligible source. These units are Units 1-4.
Each of the Bowen units now controls particulate emissions with electrostatic precipitators (ESPs) and wet FGD. The SO2 scrubbers were installed on Bowen between 2008 and 2010. But modeling results estimate that visibility impacts from Bowen will exceed a limit for at least one Class I area even with the particulate emissions reductions that occur from scrubbing. Georgia Power identified the following four potential additional control technologies: high voltage power conditioners (juice cans); particle agglomerators; the combination of juice cans and particle agglomerators; and a wet ESP. GA EPD, however, determined that no additional control was reasonable for BART for Bowen.