Bonin Unit 3 had exceptionally low heat input during the years 2006, 2007, and 2008 because during these particular years, Bonin Unit 3 was not used to produce electricity (i.e., it had no megawatt hours). In these years, the boiler was out of service. As such, nitrogen caps were being used and the heat input was based solely from the process of capping the boiler. In comparison to the years when Bonin Unit 3 is in normal operating mode, the heat input from 2006, 2007, and 2008 are essentially negligible. However, EPA used the data from 2006, one of the years that Bonin Unit 3 was out of service, to help determine its 'average' heat input and, thus, its allowance allocation under CATR. This method does not accurately reflect Boriin Unit 3's average emissions. LUS requests that EPA instead use only the data from 2005 and 2009 to determine the 'average heat input' from the Bonin Unit 3. [EPA-HQ-OAR-2009-0491-3914[1].1, pp.4-5] [[See Docket Number EPA-HQ-OAR-2009-0491-3914[1].1, p.4 for the table.]]
Madison Gas and Electric Company (MGE)
Fitchburg Generating Station Units 1 and 2 with ORIS 3991 were given allocations based only on the years 2008 and 2009 because MGE began reporting to Environmental Protection Agency (EPA) for the Clean Air Interstate Rule (CAIR) in 2008.  Since the alternative allocation methodologies in this NODA use heat input data starting with 2005 and emissions data starting with 2003, we have provided this information in the attached table.  If these alternative methods are used to calculate allocations, the EPA will have a complete set of data for these units, MGE reported the information in the attached table to the Wisconsin Department on Natural Resources in the Annual Emissions Inventory Reports for each of the years provided. [EPA-HQ-OAR-2009-0491-3924[1].1, p.1] [[See Docket Number EPA-HQ-OAR-2009-0491-3924[1].2 for the attached table.]]
Northshore Mining Company
The data in the January 7, 2011 NODA specific to the Northshore Units is inaccurate and incomplete and must be updated.
EPA also seeks comment on the data used in the NODA III preliminary allocation spreadsheets.  Since Northshore was not required to conduct Part 75 monitoring prior to CAIR, the data used by EPA to calculate allowance allocations is incomplete.  In the table below, Northshore provides the additional heat input data from 2005-2007 necessary to complete the record.  This increases the unit level average used to calculate allowances.  Please use this data to update your records. [EPA-HQ-OAR-2009-0491-3957[1].1, pp.6-7] [[See Docket number EPA-HQ-OAR-2009-0491-3957[1].1, p.7 for the table.]]
Additional information for the EPA database is included in Attachment A.    [EPA-HQ-OAR-2009-0491-3957[1].1, p.7] [[See Docket Number EPA-HQ-OAR-2009-0491-3957[1].1, pp.9-12 for Attachment A.]]
Spruance Genco, LLC
Specifically, Spruance is providing corrections to the underlying heat input and emissions data used to calculate the allocations. [EPA-HQ-OAR-2009-0491-3974[1].1, p. 1]
The allocation tables calculate the baseline heat input as the average of the three highest years between 2005 and 2009. However, the data presented in the Annual Heat Input columns from 2005 to 2007 is actually the ozone season heat input, which was reported to CAMD under the NOx Budget Program. Spruance was not able to obtain all of the historical data prior to the comment date; however, we are providing an attachment that contains the correct annual heat input data for these units and time periods. We will provide the remainder of the data prior to finalization of the allocations if one of the heat input-based allocation schemes is chosen. [EPA-HQ-OAR-2009-0491-3974[1].1, p. 1; see 3974[1].1, pp. 2-3 for attachment]
Response:
See section VII.D of the preamble for a description of the allowance allocation methodology finalized under Transport Rule.  The TSD for Allowance Allocation provides more details as well as a list of potential existing Transport Rule units, their allocations, and underlying data used to calculate the allocation.  In response to comments on the January 7, 2011 NODA, EPA updated its underlying data tables for allocations where appropriate.  Specifically, it made updates to its unit level heat input and emission values where submitted by commenter with a reasonable explanation on why the previous values were incorrect.  As stated in the NODA, EPA did not anticipate many changes to historic data used for allocation purposes as it was generally reported by the sources designated representative who testified to its accuracy and completeness.  However, some sources did provide data where none had been reported previously (e.g., during years in which data was not required to be reported for a particular source).  Also, some sources noted that the data being used for annual heat input prior to 2008 actually just reflected the ozone season heat input for that year.  The reason being that the source was not required to report a full years worth of data at that time for a given pollutant.   Another case of data correction are instances where sources suggested the data for a particular year at their source was not representative because the source  began operation that year and therefore the annual data just reflect a partial year's worth of operation.  In these instances, EPA made adjustments to its historic emissions and heat input values used to determine allowance allocations.  There is a column in the allocation tables that flags where data values were adjusted based on comment.  If the commenter noted that a value was incorrect, but did not explain why and/or did not provide replacement values, EPA was unable to make adjustments in these cases.
Organization: DTE Energy Services (DTEES)
Comment:
DTE Energy Services (DTEES)
DTE Pontiac North. This facility is located in Pontiac, Michigan (ORIS Code: 10111) and consists of three natural gas-fired boilers with rated capacities of 201.9MMBtu/hr each and one circulating fluidized bed coal-fired boiler with a rated capacity of 443MMBtu/hr. [EPA-HQ-OAR-2009-0491-3950[1].1, p.2]
The coal-fired boiler was installed August 1, 1984 and operates in cogeneration mode. It is connected to a single steam turbine generator set with a nameplate capacity of 28 MW. High pressure steam from the boiler is fed to the steam turbine to produce electricity and Low pressure steam is extracted from the turbine for process use at the plant. This unit was subject to the NOx budget program, CAIR NOx Annual, CAIR NOx Ozone Season and CAIR S02 programs. The facility has not operated the coal-fired boiler since May 2009.
DTEES believes the heat inputs used for NOx and S02 allowances is low. The records maintained by DTEES reflect the historic heat inputs below:
2007 Ozone Season 332,129MMBtu
2007 Annual 667,780MMBtu
2008 Ozone Season 568,277MMBtu
2008 Annual 2,039,304MMBtu
2009 Ozone Season 238,082MMBtu
2009 Annual 925,305MMBtu
The historic heat input of this unit reflects 6 months of operation in 2007 and 2009 and a full year of operation in 2008 using coal as the primary fuel. The intent of DTEES is to re-fire this boiler using woody biomass as the primary fuel with a projected annual heat input of 2,927,850 MMBtu/yr. The allocations currently assigned to DTE Pontiac North under Option 1 or 2 are insufficient for operations using woody biomass as the primary fuel. DTEES believes the allocations should be recalculated using the heat inputs above. [EPA-HQ-OAR-2009-0491-3950[1].1, p.2]
Since DTEES purchased the units and converted them to combust woody biomass, the utilization of the units is expected to be much higher (expected 87% capacity factor, compared to 3% to 17% during the baseline period combusting coal). [EPA-HQ-OAR-2009-0491-3950[1].1, p.3]
DTEES believes that EPA has underestimated the projected heat input to the DTE Stoneman units. Based on the changes to the facility outlined above, the heat input will be much greater than EPA has recorded as baseline heat input in the 3rd NODA allocation tables. The projected heat input to each unit should be 2,978,400 MMbtu. EPA should use these projected heat input values to determine the NOx and S02 annual allowances for the units. Using projected heat input values results in each unit receiving 298 NOx annual and 4,721 S02 annual allowances when using the projected heat inputs and the permitted emission rates of the modified units (0.2 lbs/MMbtu for NOx and 3.17 lbs/MMbtu for S02). These values are much higher than Option 1 in this NODA, which results in Unit 1 receiving 25 NOx annual allowances and 53 502 annual allowances in 2012 and 72 annual allowances in 2014. Unit 2 receives 34 NOx annual allowances and 72 S02 annual allowances in 2012 and 50 annual allowances in 2014. Option 2 provides for a small increase with Unit 1 receiving 26 NOx annual allowances and 58 S02 annual allowances in 2012 and 39 annual allowances in 2014. Unit 2 receives 34 NOx annual allowances and 78 S02 annual allowances in 2012 and 52 annual allowances in 2014. The two options provide only a small fraction of the allowances that will be required for compliance with the Transport Rule. [EPA-HQ-OAR-2009-0491-3950[1].1, p.3]
If EPA were to adjust the heat input to the expected value of 2,978,400 MMbtu per unit and then recalculate the reasonably foreseeable maximum emissions then these methods may yield the appropriate portion of S02 and NOx allowances to the units. [EPA-HQ-OAR-2009-0491-3950[1].1, pp.3-4]
Response:
EPA updated its historic heat input baseline to 2006-2010.  See section VII.D of the preamble for a description of the final allocation methodology and The Allowance Allocation Final Rule TSD for a detailed list of potential covered units, their allocations, and underlying data used to determine allocations.  EPA made some corrections to its underlying historic data in instances where the commenter had provided corrected data as well as an explanation as to why the data previously reported by the designated representative was incorrect.  However, EPA saw no such explanation in the above comment, and has not made adjustments to the reported heat input values consequently.
Organization: EquiPower Resources Corp.
Comment:
EquiPower Resources Corp.
The Transport Rule NODA does not address critical flaws in state budgets and underlying data and assumptions.
o The Transport Rule NODA relies upon the same mistaken data and assumptions as the Transport Rule, and EPA's attempt to obscure these flaws by using heat input data is an inadequate solution. [EPA-HQ-OAR-2009-0491-3928[1].1, p.2]
As an example, Massachusetts is still under-allocated in 2012 due to these mistaken assumptions on the status of controls in the state, and the Transport Rule NODA's approach to unit-level allocations does not fix this problem. EPA has adjusted the 2012 SO2 budget for Unit 3 at Dominion's Brayton Point Power Plant by assuming that the unit's FGD will be online in 2012. However, Massachusetts Department of Environmental Protection has reported that construction of that FGD is not scheduled to begin until April 2011, and therefore that the FGD will not be in full operation until the first quarter of 2014. Unit 3 is the largest unit at Brayton Point, which in turn is the largest coal-fired power plant in New England. As a result, the Agency has seriously understated the level of emissions that will be produced by Brayton Point in 2012, and as a result has under-allocated its (and by extension, the entire state's) allowances. As a result, EPA's state budget for Massachusetts is inaccurate. [EPA-HQ-OAR-2009-0491-3928[1].1, p.10]
Response:
EPA has updated its IPM modeling so that no FGD is reflected at Brayton Point unit 3 in 2012.  Furthermore, EPA conducted is contribution analysis anew with the updated modeling, EGU and non-EGU inventories.  The final rule analysis did not suggest that Massachusetts was a contributing upwind state, and the state is not covered under any of the programs in the final Transport Rule geography.
Organization: Exelon
Wolverine Power Supply Cooperative
CPS Energy
Cogen Technologies Linden Venture, LP
Comment:
Cogen Technologies Linden Venture, LP
Linden Cogen has also examined the underlying unit-level data used to generate the illustrative allocations and agrees that these data are correct for Linden Cogen's generating units. [EPA-HQ-OAR-2009-0491-3938[1].1, p.5]
CPS Energy
The data used in the allocation tables provided in the technical documents on the EPA's website is correct for CPS Energy units. [EPA-HQ-OAR-2009-0491-3947[1].1, p.1]
Exelon
Exelon's review of the proposed allocations set forth in the data tables accompanying the NODA reveals that the allocations to its fossil-fuel fired units have been properly calculated under this method and are more appropriate than the allocations appeared to be under the methodology presented in the original Transport Rule proposal. [EPA-HQ-OAR-2009-0491-3919[1].1, p.4]
To this end, Exelon's retiring units have properly been awarded allowances in the data tables accompanying the NODA. [EPA-HQ-OAR-2009-0491-3919[1].1, p.5]
Wolverine Power Supply Cooperative
Regarding the USEPA's request for comment on underlying unit-level data and allowance calculations, we have reviewed these data for Wolverine's Sumpter Plant, and find them to be accurate and complete. [EPA-HQ-OAR-2009-0491-4014[1].1, p. 4]
Response:
See section VII.D for a description of the allocation methodology used in the final Transport Rule.  Additionally, the allocations and underlying data are described in the Technical Support Document for Allowance Allocations.
Organization: Exxon Mobil Corporation
Comment:
Exxon Mobil Corporation
7. We would like to request an error correction. Our ExxonMobil Beaumont Cogeneration unit has been assigned a Capacity Factor of 0.22 (like a unit that delivers electricity only intermittently during high electricity demand days - 'Combustion Turbine'). This is instead a Cogeneration unit supplying steam and power to an industrial source to meet steam and power needs constantly for our local ExxonMobil Refining and Chemical complex and supplying supplemental electricity to the grid. Following the EPA logic in the proposal, it should have a 0.70 capacity factor or greater. [EPA-HQ-OAR-2009-0491-3999[1].1, p.3]
Error Correction Request
Our ExxonMobil Beaumont Cogen unit has in error been assigned a Capacity Factor of 0.22 (like a unit that delivers electricity only intermittently during high electricity demand days - 'Combustion Turbine')). We would like to request an error correction. This is a Cogeneration unit supplying steam and power to an industrial source to meet steam and power needs and supplying supplemental electricity to the grid and following the EPA logic should have a 0.70 capacity factor or greater. [EPA-HQ-OAR-2009-0491-3999[1].1, p.7]
[Table can be found on page 2 of comment letter 4028.]
EM requests that EPA correct any data used in development of the CATR to reflect the unit data provided above. [EPA-HQ-OAR-2009-0491-4028, p.2]
Response:
The allocation methodology used in the final Transport Rule does not use a capacity factor assignment in its determination of allowance allocations.  The final allocation methodology eliminates the concern addressed by commenter regarding potential under allocation because of capacity factor assignment.  This concern only applies to option 2 of the January 7, 2011 NODA.  EPA did not finalize this option.  See section VII.D of the preamble for a complete description of the final allocation methodology.
Organization: Florida Department of Environmental Protection
Comment:
Florida Department of Environmental Protection
In reviewing the allocation tables for both option 1 and 2, we note that when allocations are distributed as whole values, the total number of allowances actually distributed in a given state will usually not equal the amount allocated to the state. This is because of the rounding that takes place when allocating the fractional values. The actual distribution could be higher or lower than the amount allocated to the state. We did not see where the rule indicates how these orphan allocations would be dealt with. One option is that these extra or deficit allowances be added or subtracted from the new unit set-aside allocations. In any case, when any left-over new unit set-aside allocations are redistributed to the existing pool, there is also a need for a procedure to allocate orphan allowances. Florida has developed an "adjusted rounding" procedure for CAIR allowances that could be used. See attached spreadsheet.   [EPA-HQ-OAR-2009-0491-3879[1].1, p.2] [[See Docket Number EPA-HQ-OAR-2009-0491-3879[2].2 for the spreadsheet.]]
Response:
Allocations to existing units under the Transport Rule FIPs are rounded to the nearest ton using conventional rounding.  This rounding may result in small differences between the sum of allocations to existing units in a specific state under a FIP, and the size of the existing unit pool of allowances from the state's trading budget.  Any such differences resulting from the existing unit allocations are reflected by adding or subtracting allowances, as appropriate, in calculating the number of allowances in the new unit set-aside for that state, and the resulting set-aside amounts are set forth in Tables XXX in section XX of the preamble. Similarly, small differences between the sum of allocations from the new unit set-aside to units in a state and the size of the new unit set-aside may also occur because of rounding in calculating unit-by-unit allocations, and EPA has established a procedure for handling such scenarios in the new unit-set-aside provisions (as well as in the Indian country new unit-set-aside provisions) in the Transport Rule text.  EPA notes that under  no circumstances will rounding result in total state allocations for a given control period in a FIP exceeding or falling short of the state budget for that control period in the FIP.  Total state allocations for a vintage year will equal the state budget.
Organization: Horsehead Corporation
Comment:
Horsehead Corporation
C. Horsehead is addressing certain corrected heat input data in response to EPA's request in the Second NODA to comment on the accuracy of the data used to calculate the proposed allowance allocations.
EPA states in the Second NODA that, 'in order to ensure the accuracy of the allocation calculations, the EPA is providing this opportunity for source owners and operators ... to comment on the ... data used or that should be used to calculate the allocations and the resulting allocations ....' 76 Fed. Reg. 1116. [EPA-HQ-OAR-2009-0491-4003[1].1, p.2]
Horsehead previously reported to EPA certain incorrect heat input data for the Facility's boilers for the period from 2005 to 2010.  Upon discovering this reporting error in August 2010, Horsehead promptly began working with EPA to correct the relevant information. Horsehead was instructed by EPA that the Facility could submit corrected heat input data for calendar years 2009 and beyond, using EPA's electronic Emissions Collection and Monitoring Plan System (the 'ECMPS'). Accordingly, in October 2010, Horsehead submitted corrected heat input for 2009 and the first two quarters of 2010. However, EPA informed Horsehead that the ECMPS does not allow users to submit corrected data for years prior to 2009; therefore, Horsehead's reported heat input data for calendars years 2005 through 2008 has not been corrected within the ECMPS.  Horsehead has corrected the heat input data for calendar years 2005 through 2008 and is maintaining this information at the Facility. Horsehead is in the process of determining with EPA the best method for submitting this updated information to the Agency. [EPA-HQ-OAR-2009-0491-4003[1].1, pp.2-3]
Additionally, in response to EPA's specific request in the Second NODA that source owners and operators comment on the accuracy of the data relied upon by EPA in calculating the proposed allowance allocations, Horsehead is addressing within this letter certain corrected historic heat input data for the relevant time period considered under the Second NODA. [EPA-HQ-OAR-2009-0491-4003[1].1, p.3]
Response:
EPA updated its heat input baseline to include 2010.  This should provide the Horsehead source with one additional year of complete and accurate data.  In regards to the pre-2009 data, EPA's final allocation tables continue to use the CAMD data available for these sources.  The comment did not specify the unit or the corrected heat input values for pre-2009 years, so EPA made no changes to those data points for purposes of these allocation tables.
Organization: Morgantown Energy Associates
Massachusetts Department of Environmental Protection
Comment:
Massachusetts Department of Environmental Protection
b. Underlying data and assumptions
With respect to corrections to underlying data and assumptions that we previously submitted, to our knowledge, EPA has not made publicly available any changes made to its NEEDS data base in response to comments submitted on the proposed Transport Rule and first NODA. Therefore, we are unable to determine if EPA has made corrections to the underlying data and assumptions for Massachusetts facilities that we recommended. We understand that EPA is still making adjustments to the data and assumptions on which the final Transport Rule will be based. We encourage EPA to make the needed corrections for Massachusetts units so that final Transport Rule budgets and allocations for Massachusetts will be based on accurate descriptions of the Massachusetts units' characteristics and operations. [EPA-HQ-OAR-2009-0491-4017[1].1, p.4]
Brayton Point
We wish to again bring attention to a significant error in the underlying assumptions in the proposed Transport Rule for Brayton Point. As noted in our previous comments on the proposed Transport Rule, EPA's data reflects operation of a scrubber at Brayton Point (ORIS ID 1619) Unit 3 in 2012 while the current Prevention of Significant Deterioration (PSD) approval and MassDEP modified plan approval allows the operator to begin construction of a dry scrubber by April 2011; it will not be ready to operate in 2012. Dominion Energy New England, Inc., the operator of the Brayton Point facility, has provided a schedule to MassDEP showing construction of the scrubber commencing in 2012, with full operation by the 1st Quarter of 2014. EPA's incorrect assumption concerning the timeframe for installation of the scrubber must be corrected and the Massachusetts SO2 budget should be adjusted upward to account for SO2 emissions from Brayton Point Unit 3 in 2012 and 2013 - prior to installation and operation of the scrubber. Because the third NODA does not reflect changes in emissions controls on covered units, we cannot determine if EPA has made the correction to its underlying assumptions for this unit. [EPA-HQ-OAR-2009-0491-4017[1].1, pp.4-5]
As we previously commented, for 2014 and beyond, we believe the SO2 allocation for Brayton Point and the Massachusetts annual SO2 budget should reflect the reduced emissions that will result from the installation of the scrubber, which has been in the planning stage since 2002. Therefore, we encourage EPA in the final Transport Rule to provide Unit 3 with a higher level of allowances for 2012 and 2013 only, and provide a lower level of allowances for 2014 and beyond. [EPA-HQ-OAR-2009-0491-4017[1].1, p.5]
Salem Harbor
As we noted in our comments on the proposed Transport Rule, EPA assumed that a scrubber will be installed on Unit 3 at the Salem Harbor facility (ORIS ID 1626) in 2012. There are no plans to install a scrubber on this unit according to comments we have received from Dominion New England, Inc. [EPA-HQ-OAR-2009-0491-4017[1].1, p.5]
Morgantown Energy Associates
Specifically, MEA is providing corrections to the underlying heat input and emissions data used to calculate the allocations. [EPA-HQ-OAR-2009-0491-3966[1].1, p.1]
The allocation tables calculate the baseline heat input as the average of the three highest years between 2005 and 2009. However, the data presented in the Annual Heat Input columns from 2005 to 2007 is actually the ozone season heat input, which was reported to CAMD under the NOx Budget Program. MEA is providing an attachment that contains the correct annual heat input data for these units and time periods. [EPA-HQ-OAR-2009-0491-3966[1].1, p.1]
In addition, the data presented as Annual NOx Emissions from 2003 through 2007 is also incorrectly reported from ozone season emissions and the SO2 data is missing prior to 2009. The correct annual NOx and SO2 emissions data is also provided in the attached tables. [EPA-HQ-OAR-2009-0491-3966[1].1, p.1] [[See Docket Number EPA-HQ-OAR-2009-0491-3966[1].1, pp.2-6 for attached tables.]]
Response:
EPA has updated its modeling, and the final EPA IPM base case used in the Transport Rule analysis does not include a scrubber at Brayton Point Unit 3.  Additionally, Massachusetts was not determined to be a contributing state in the final Transport Rule, which obviates the Mass DEP concerns regarding allocations to specific units.
Organization: Nelson Industrial Steam Company (NISCO)
Comment:
Nelson Industrial Steam Company (NISCO)
NISCO appreciates the fact that EPA correctly identified its two units in the 2011 NODA; [EPA-HQ-OAR-2009-0491-4026, p.1]
However, as discussed below, EPA did not use the prior reported heat input data for the units in calculating NISCO's heat input under the two options for allocations proposed in the 2011 NODA. [EPA-HQ-OAR-2009-0491-4026, p.2]
In the underlying data supporting the allocations proposed in both Options 1 and Option 2 for NISCO in this 2011 NODA, EPA used an average of only two years of heat input data for the NISCO units. This was based on averaging only two years of data, that of 2008 and 2009. That is likely due to EPA's prior misidentification of the units. NISCO became subject to the CAIR program and in 2008 began reporting data directly to EPA's Clean Air Markets database. The heat input data that EPA shows for NISCO's two units in 2008 and 2009 does reflect actual heat input data for those years. However, 2009 was not representative of normal NISCO operation as Unit 1 was down from May 4, 2009 until early September 2009 due to significant damage to the turbine that required an extended outage to repair. [EPA-HQ-OAR-2009-0491-4026, p.5]
NISCO's units heat input data was reported to the Energy Information Administration ('EIA') for prior years by Entergy, the operator of the NISCO units. Ibis heat input data for 2005-2007 is available for these two units in the EIA database under ''Facility ID 1393, Facility Name RS Nelson Units - lA & 2A. NISCO requests that EPA recalculate the 3 year average heat input for its units by using the EIA data. The 2007 to 2010 data for fuel input to each boiler is available in the annual downloads at: http://www.eia.gov/cneaf/electricity/page/eia906 920.html, which is data collected on the Form EIA-923. Prior to 2006, the boiler fuel data was collected on the EIA-767. The F767 was discontinued in 2005 and no boiler data was collected fat 2006. F923 took up the collection in 2007. The F767 data is published at http://www.eia.gov/cneaf/electricity/page/forms.html [EPA-HQ-OAR-2009-0491-4026, p.5]
For your convenience, we have downloaded the 2005, and 2007 through October 2010 fuel input data for the two units from the EIA databases in one spreadsheet. The boiler data for 2007 to 2010 is on one tab, and the 2005 data is on another due to the F767's different format. The first tab is the total fuel and generation data for the plant by prime mover type. We are .attaching this spreadsheet as Exhibit 1. [EPA-HQ-OAR-2009-0491-4026, p.5]
[Exhibit 1 (24 pages) can be found on pages 7-30 of this comment.]
In summary, the heat input data for each unit is as follows: [EPA-HQ-OAR-2009-0491-4026, p.5]
[Table can be found on page 5 of this comment.]
In the underlying data supporting Options 1 and Option 2 in this 2011 NODA, EPA lists the capacity of the two units as 107 MW for Unit lA and 106 MW for Unit 2A. In actuality the maximum gross generating capacity is 130 MW for Unit 1A and 130 MW for Unit 2A. NISCO requests that this information be corrected. [EPA-HQ-OAR-2009-0491-4026, pp.5-6]
Response:
EPA has updated its 2006 and 2007 ozone season heat input data with those values provided by commenter.  Additionally, EPA has finalized an allocation methodology that relies on a 2006-2010 emissions baseline.  EPA final allocation methodology does not use or report maximum gross generating capacity in its underlying data to determine its allocation methodology.  See section VII.D of the preamble for further detail on the Transport Rule allocation methodology under a FIP.
Organization: New Jersey Department of Environmental Protection (NJDEP)
Comment:
New Jersey Department of Environmental Protection (NJDEP)
The Department has identified two errors in the New Jersey unit-level allocation calculated using the alternative methodologies. Firstly, the American Ref-Fuel of Essex unit (ORISID = 10643, UNITID = 3) in the allocation table should not be identified as a Transport Rule unit. Based on data the facility submits annually to the New Jersey Emission Statement Program, none of units at this facility has consumed enough fossil fuel to be anywhere close to 20% of the total heat input criteria under the Transport Rule. [EPA-HQ-OAR-2009-0491-3891[1].1, p.2]
Secondly, the allocation file appears to have omitted one of the units at the Cumberland Energy Center (ORISID = 5083, UNITID = 5001). There are two units at this facility, 4001 and 5001. Unit 5001 is a newer combustion turbine unit rated at 103 MWe that began operation in 2008. This unit should be included as a Transport Rule unit, and therefore, be allocated allowances.[EPA-HQ-OAR-2009-0491-3891[1].1, p.2]
Response:
The final allocation tables have been updated based on the above comments.  Commenter may see section VII.D of the preamble for an explanation of how EPA determined its list of potentially covered Transport Rule units.  As suggested by the commenter, the Cumberland Energy Center unit 5001 has been added to the final allocation tables.
Organization: New York State Department of Environmental Conservation
Louisville Gas and Electric Company (LG&E) and Kentucky Utilities Company (KU)
Association of Electric Companies of Texas (AECT)
Vectren Corporation
Lakeland Electric
Minnesota Power
Progress Energy Service Company
NRG Energy
National Rural Electric Cooperative Association (NRECA)
Wisconsin Public Service Corporation (WPSC)
National Mining Association (NMA)
Comment:
Association of Electric Companies of Texas (AECT)
EPA's Modeling Assumptions and Projections are Inconsistent with Available Information
EPA has a long history of rulemakings that recognize the inherent differences in fuels with regard to regulatory compliance. EPA, therefore, should return to the initial CATR allocation incorporated into the initial proposed CATR of August 2,2010. This would provide correction to EPA's subsequent assumptions and modeling prior to proceeding with the rulemaking. [EPA-HQ-OAR-2009-0491-3981[1].1, p.2]
Lakeland Electric
In 2008, Lakeland Electric's Unit 3 coal fired boiler at the C.D. McIntosh, Jr. Power Plant emitted 7,626.8 tons of SO2 (see EPA CAMD 2008). In 2008, Unit 3 operated its wet scrubber above 73% SO2 reduction efficiency on average for the entire year. In addition to the scrubber's high efficiency, Unit 3's coal annual average sulfur content was 1.14% for 2008. Notwithstanding these facts, EPA has only allocated Unit 3 the following allowances: 2,411 tons SO2 under Option 1 and 3,506 tons SO2 under Option 2. These allowances amount to a 68% and 54% reduction respectively by the year 2012 from 2008 SO2 emission values. [EPA-HQ-OAR-2009-0491-3892[1].1, p.2]
In order to reach an additional 68% or 54% SO2 reduction, Unit 3 would be required to undergo a major retrofit to its system before 2012 in order to meet these reductions. Unit 3 is not designed and is unable to run at full load on natural gas and retrofitting Unit 3's SO2 control equipment may still not result in the needed reductions. In addition, the ability to attempt and finish any major modifications by 2012 is not possible. It should also be noted that there is no additional room in the surrounding area around Unit 3 to even install an additional or larger scrubber, not to mention that it may be unattainable, or at least economically unattainable, to scrub an additional 54%-68% of sulfur dioxide from a flue gas made from 1.14% sulfur coal. [EPA-HQ-OAR-2009-0491-3892[1].1, p.2]
Additionally, EPA has not posted new modeling information with each option modeled, so Lakeland Electric cannot support either option at this time. Unit 3's SO2 allowances under the Clean Air Interstate Rule (CAIR) cover approximately 4,974 tons of SO2 emissions annually, not counting banked allowances, for the period 2010-2014. However, Option 1 allocates only 2,411 SO2 allowances for Unit 3 annually; this is a 52% reduction. Lakeland Electric would like EPA to explain why such a dramatic reduction is required from the earlier issued CAIR allowance scheme. Lakeland Electric would also like EPA to discuss how they are confident that the new disbursement of allowances under Options 1 or 2, as opposed to the original proposed Transport Rule allowance scheme, will still bring downwind states into attainment as allowance banks have now varied from facility to facility. [EPA-HQ-OAR-2009-0491-3892[1].1,p.4]
6) Has modeling been performed for Options 1 and 2 that demonstrates that downwind states will not be affected adversely, i.e., upwind states will still contribute a significant portion of the nonattainment pollutant, as opposed to the allowance schemes initially proposed, and if so, will EPA publish that data on the docket? [EPA-HQ-OAR-2009-0491-3892[1].1, p.6]
Louisville Gas and Electric Company (LG&E) and Kentucky Utilities Company (KU)
Comparing the original allocation proposal with the alternatives illustrates the magnitude of uncertainty regarding the number of allowances that units and companies might receive. The number of allowances that companies would receive at their Kentucky plants varies by tens of thousands, equating to variations of over 50% for several companies. Attachment A provides additional details. In some cases, companies will be in compliance, will curtail or retire unit operations, or will need to install additional controls, depending on the allocation method selected. [EPA-HQ-OAR-2009-0491-3909[1].1, p.2] [[This comment can also be found in Section XX.]]  [[See Docket Number EPA-HQ-OAR-2009-0491-3909[1].1, p.3 for Attachment A.]]
Minnesota Power
The MP staff review of data provided by EPA in this rule making affirms that EPA's characterization of emissions and calculations for budget allocations has improved since the August 2 2010 NODA, with MP being able to confirm EPA calculations for most MP unit budget allocations. However, MP notes that while some units appear to be properly characterized by EPA in the NEEDS data base, MP cannot replicate the calculated result EPA has developed for budget allocations for all MP units. It is unclear to MP why EPA budget allocation calculation methodology appears to be different for similar units posted in the NEEDS data base. It is apparent to MP that emissions performance from control equipment retrofit on MP units that reduce SO2 and NOx emissions since 2005 have received some consideration in EPA calculations for budgets but calculation particulars are not clearly defined and MP staff cannot replicate some of the results. Regardless, MP notes that EPA has determined budget allocations for Minnesota sources that are significantly lower than emissions pre-2005, of a magnitude that tracks with EPA's targeted Group 2 State percent reductions in emissions of SO2 and NOx. MP notes that it is important that EPA provide the regulated community the opportunity to understand the basis for data discrepancies and seek corrections before the Transport Rule is finalized. [EPA-HQ-OAR-2009-0491-4009[1].1, pp.3-4]
National Mining Association (NMA)
:: Combined cycle 2012 SO2 allocations under Option 1 represent a 46,443% increase over the same allocation under the PTR Method. Under Option 2 the increase is just under half that  -  a 21,153% increase over the PTR Method allocation. For 2014 SO2 allocations are 51,049% (Option 1) and 29,183% (Option 2) greater than the PTR Method allocations. [EPA-HQ-OAR-2009-0491-4013[1].1, p.3]
:: The sum of all combined cycle units' annual historical cap value (which for each unit is its seven-year record high annual emissions) is 2,946. To emit this much SO2 in a single year, every single combined cycle unit covered by the rule would have to have record emissions in the same year all at the same time. Yet under Option 1 these units are allocated 311,631 allowances (an excess of 308,685) and under Option 2 they are allocated 141,934 allowances (an excess of 138,988). These gross over-allocations are annual over-allocations. That is, every year these units receive this windfall. These over-allocations  -  as compared with seven-year record high emissions  -  drop slightly in 2014 (when the SO2 allocations shrink for Group 1 states) to 233,805 (Option 1) and 133,662 (Option 2). Nonetheless, by just the forth year of the program Option 1 will have allocated well over a million excess SO2 allowances  -  that these units could never actually need to cover emissions. [EPA-HQ-OAR-2009-0491-4013[1].1, p.3]
:: Combined cycle annual NOx allocations under Option 1 represent a 485% increase over PTR allocations. Under Option 2 this increase is still 394%. Combined Cycle ozone season NOx allocations are 394% (Option 1) and 305% (Option 2) higher than PTR allocations. [EPA-HQ-OAR-2009-0491-4013[1].1, pp.3-4]
:: Under Option 1, combined cycle units are allocated 58,812 and 68,095 allowances more than historical record emissions for annual NOx and ozone season NOx respectively. That is, each year combined cycle units will receive over 125,000 NOx allowances to sell or bank. [EPA-HQ-OAR-2009-0491-4013[1].1, p.4]
Under Option 1, coal-fired EGUs would received 349,249 (2012 SO2), 282,357 (2014 SO2), 126,498 (annual NOx), and 96,131 (ozone season NOx) fewer allowances than they would under the PTR Method. That is, hundreds of thousands of allowances fewer than are needed to cover coal-fired EGUs lawful emissions. [EPA-HQ-OAR-2009-0491-4013[1].1, p.4]
Under Option 2, EPA's proposed under-allocation to coal-fired EGUs is 155,791 (2012 SO2), 167,756 (2014 SO2), 101,399 (annual NOx) and 74,681 (ozone season NOx) fewer than under the PTR Method. [EPA-HQ-OAR-2009-0491-4013[1].1, p.4]
[Tables can be found on pages 4-6 of this comment.]
This unit's lifetime-of-the-plant SO2 emissions are significantly less than its annual SO2 allocation for a single year. If the life-of-the-facility were fifty years, it would emit at most 70 tons of SO2. Under Option 1, it would be allocated 8,846 SO2 allowances each year. Thus, its first year allocation is 126 times its potential SO2 emissions over the life of the plant (assuming a fifty years). That is frankly absurd. [EPA-HQ-OAR-2009-0491-4013[1].1, p.6]
By way of example, the Whiting Clean Energy facility in Indiana is allocated over 200 times what it was allocated under the emissions-based PTR Method and over 200 times its record annual actual emissions. [EPA-HQ-OAR-2009-0491-4013[1].1, p.7]
EPA provides tables showing how the initial state budgets from the proposed rule would be allocated to the unit level under the two new allocation methods. In doing so, EPA notes that "[a] number of commenters requested that EPA publish allocations and underlying data for any potential alternative allocation methodologies before issuing a final Transport Rule." To be absolutely clear, that is not what EPA has provided. Instead, EPA has provided obsolete data based on obsolete state budgets. [EPA-HQ-OAR-2009-0491-4013[1].1, p.11]
Further, the new allocations that EPA provides in the Option 1 and Option 2 tables are based on the state budgets in the proposed Transport Rule, which are again obsolete. An individual unit, or the owners or operators of groups of units, cannot rely on the data for compliance planning. All that these tables allow is for owners and operators to evaluate how their proportionate share of the budget will change if EPA switches from Option 1 to Option 2. As noted above, because of changes identified in the first NODA, units cannot rely on their allocations under the proposed Transport Rule to determine their proportionate share of the state budget assuming EPA uses the allocation method in the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-4013[1].1, p.12]
A. Problems with Data EPA Has Provided.
EPA has not provided sufficient information that would allow the public to efficiently and comprehensively compare and analyze the unit-level allocations that result from these three vastly different allocation methods. EPA made numerous changes between the proposed Transport Rule and NODA-3 to the available unit-level databases that prevent us from completing a complete line-by-line, unit-by-unit comparison for all units. For example, the universe of units changed between the proposed rule and NODA-3 because EPA proposes different cut-off dates for determining when a unit will be treated as a new unit. Additionally, EPA treats and lists steam turbines at combined cycle facilities differently under NODA-3 than it did under the proposed rule. Further, EPA did not provide any single field (i.e., column) that is unique to each unit in all databases. Finally, there are numerous other changes and anomalies in the data that we were not able to resolve in the short time permitted for public review. [EPA-HQ-OAR-2009-0491-4013[1].2, p.1]
In the NODA-3 Database, EPA does not provide information about the fuel used by each unit. To perform our analysis we used EPA's unique "technology class capacity factors" as identified in the NODA-3 Database. Those factors were for the following five Technology Classes: Coal-Fired Boiler (0.87); Combined Cycle (0.70); Combustion Turbine (0.14); Oil or Gas Fired Boiler (0.46); and Other (0.71). This allowed us to group the units based on technology class. [EPA-HQ-OAR-2009-0491-4013[1].2, p.2]
Our analysis in Part III (comparing NODA-3 allocations to maximum emissions) and Part IV (providing sample unit data) relied solely on the information contained in the NODA-3 Database. [EPA-HQ-OAR-2009-0491-4013[1].2, p.3]
A. Comparisons of PTR Allocations to NODA-3 Option 1 Allocations.
The following charts show the change in total allocation to all units grouped by technology class/plant type that results from switching from the PTR Method to the Option 1 Method. [EPA-HQ-OAR-2009-0491-4013[1].2, p.3]
[Charts can be found on pages 4-6 of this comment.]
In the first year allocation alone (2012), combined cycle units and combustion turbines will receive a total of almost 600,000 more allowances under the Option 1 Method (as compared to the PTR Method). Coal-fired boilers would receive 571,877 fewer allowances under the Option 1 Method. These extra allocations to combined cycle units and combustion turbines would be realized each year of the program. That is, these combined cycle units and combustion turbines would collectively received an additional roughly 600,000 extra allowances in the second year (2013), and so on. Thus, by the beginning of the third year (2014), the Option 1 Method will allocate an extra 1.2 million allowances to combine cycle and combustion turbines collectively. Over this same period of time, coal-fired boilers collectively will receive over 1.1 million fewer allowances under the Option 1 Method. [EPA-HQ-OAR-2009-0491-4013[1].2, p.3]
The Option 2 Method still results in a significant shift of allowances from coal-fired boilers to other technology classes. In the first year allocation alone (2012), combined cycle units and combustion turbines will receive a total of 340,041 more allowances under the Option 2 Method (as compared to the PTR Method). Coal-fired boilers would receive 331,871 fewer allowances under the Option 2 Method. These extra allocations to combined cycle units and combustion turbines would be realized each year of the program. That is, these combined cycle and combustion turbines would collectively received an additional 340,041 extra allowances in the second year (2013), and so on. Thus, by the beginning of the third year (2014), the Option 2 Method will allocate an extra 680,082 allowances to combine cycle and combustion turbines collectively. Over this same period of time, coal-fired boilers collectively will receive over 660,000 fewer allowances under the Option 2 Method. [EPA-HQ-OAR-2009-0491-4013[1].2, p.7]
[Charts can be found on pages 7-9 of this comment.]
Under Option 1, in the first year alone, combined cycle units will receive over 300,000 allowances that they could never need. Even under Option 2, combined cycle units will receive nearly 140,000 allowances that they do not need  -  even in a year where every combined cycle unit has emissions equal to their seven-year record high. These over-allocations are realized every year of the program. [EPA-HQ-OAR-2009-0491-4013[1].2, p.10]
[Charts can be found on pages 11-13 of this comment.]
These tables demonstrate the severe over-allocation to many natural gas combined cycle units and the severe under-allocation to many coal-fired units. [EPA-HQ-OAR-2009-0491-4013[1].2, p.14]
[Tables can be found on pages 15-16 of this comment.]
National Rural Electric Cooperative Association (NRECA)
NRECA has closely examined the underlying CATR unit data and unit allowance allocations provided in the CATR rulemaking docket.  The NRECA spreadsheet submitted separately to the CATR docket is comprised from data contained in this rulemaking docket and serves as a reference for the following observations regarding allowance distributions under NODA III option 2.  [EPA-HQ-OAR-2009-0491-3943[1].2, p.6]
As a group, combined cycle (CC) and turbine units receive the following windfalls of allowances in all the CATR trading programs:
-Under the ozone NOx trading program:   While emitting about 5.52% of total CATR tons, CC and turbine units receive about 16% of the allowances, over 300% more than their current emissions.
-Under the fine particulate trading program for annual NOx:  While emitting about 2.98% of the total CATR tons, CC and turbine units receive about 10% of the allowances, over 300% more than their current emissions.   [EPA-HQ-OAR-2009-0491-3943[1].2, p.6]
- Under the fine particulate trading for annual SO2:  While emitting about .5% of the total CATR tons, CC and turbine units receive about 5% of the allowances in 2012 and about 7% of the allowances in 2014, over 6200% of their current emissions.   [EPA-HQ-OAR-2009-0491-3943[1].2, p.7]
Thus in the aggregate, combined cycle and turbine units receive far more allowances than these units can ever use.     [EPA-HQ-OAR-2009-0491-3943[1].2, p.7]
-Of the 420 CC gas units within the CATR region, not one has emissions that exceed the "well controlled emissions rate" for SO2.
-Only 20% of the CC gas units have emissions that exceed the "well controlled emissions rate" for NOx, and the vast majority of these units are not equipped with SCRs.
-Less than 8% of the turbines have emissions that exceed the "well controlled emissions rate" for SO2 emissions.  The vast majority of these units appear to use gas/oil as a duel fuel. [EPA-HQ-OAR-2009-0491-3943[1].2, p.7]
-Of the more than 1050 coal units contained in EPA's CEMS data base for the CATR states, just 8 units' emissions meet or are below the "well controlled emission rate" for both SO2 and NOx.
-45 coal units' emissions in the CATR meet or are below the "well controlled emissions rate" for NOx.
-27 coal units meet or are below the well "controlled emissions rate" for SO2, and all of these units utilize low-sulfur coal.   [EPA-HQ-OAR-2009-0491-3943[1].2, p.8]
New York State Department of Environmental Conservation
The Iatan facility in Missouri is a good example of EPA's proposed NODA over-allocating (and therefore requiring other facilities within the state to buy allowances from a facility that could not possibly use its entire allocation).  Iatan Unit 1 installed both SO2 and NOx controls which came on-line beginning in 2009.  SO2 emissions from this unit went from over 15,000 tons in 2008 to 152 tons in 2009.  Using the limits contained in the permit (8100 MMBtu/hr and 0.1 lb/MMBtu) provides a maximum emission of about 3,550 tons per year.  Both allocation methods in the NODA provide more than 12,000 tons in 2012 and 9,000 in 2014 for this unit.    [EPA-HQ-OAR-2009-0491-3937[1].1, p.2]
NRG Energy
Louisiana
In Louisiana, 81% of capacity is natural gas generation; however, coal generation provides 99% of all SO2 emissions. Still the heat input method allocates 62% of the allowances to the non coal units compared to the July NODA which afforded 1% to these same units. Using EPA's projected allowance value of $500/ton and our calculated allowance transfer which exceeds 49,000 allowances, this would result in a transfer of wealth of $24.5 million dollars annually. [EPA-HQ-OAR-2009-0491-3933[1].1, p.5]
New York
New York provides another example of this disparity. For example, compare a typical coal unit (Huntley Station) and a natural gas combined cycle unit (Poletti Station in New York City). The following graph shows a comparison of actual emissions to the allocations that would occur in each of EPA's preferred methods; the original July NODA (projected emissions), Option 1 (Heat Input) and Option 2 (Modified Heat Input). [EPA-HQ-OAR-2009-0491-3933[1].1, p.5]
The Huntley facility is a coal fired station which has made significant emission reductions of both NOx and SO2 over the baseline period (2003  -  2009). During this baseline period the facility switched from bituminous coal to low sulfur Powder River Basin coal, installed selective non catalytic reduction technology to control NOx, and dry sorbent injection and fabric filter baghouses to reduce SO2, particulate, and HAP emissions. Even though annual emissions of SO2 have been reduced by 73%, annual NOx by 52% and ozone season NOx by 51%, the heat input based allocations of NOx and SO2 under options 1 and 2 fall far short of 2009 actual emissions. [EPA-HQ-OAR-2009-0491-3933[1].1, p.5]
The graph reveals the combined cycle natural gas facility, with similar annual heat input, will receive SO2 allocations under Option 1 in excess of 250 times its actual emissions and in the case of annual NOx, more than 4 times its permit cap. As noted in the Louisiana example, the coal unit would have to buy allowances from the oversubscribed natural gas unit. In contrast, the July approach provides a reasonable allocation for both facilities: the gas unit receives all allocations needed to operate and the coal unit is still short and can make decisions on how to comply. [EPA-HQ-OAR-2009-0491-3933[1].1, p.5] [[See Docket Number EPA-HQ-OAR-2009-0491-3933[1].1, p.6 for the graph.]]
Delaware
This concern is equally compelling when looking at the Indian River Generating Station, Unit 4 located in Millsboro Delaware. The four unit facility has retired one unit with two additional unit retirements planned for 2011 and 2013 leaving only Unit 4 in operation. The facility has invested over $360M in capital for the addition of an SCR to control NOx, a circulating dry scrubber and a fabric filter (baghouse) to reduce SO2, particulate, and HAP emissions. For Indian River, the allocation differential between the July approach and Option 1 is 1,238 tons representing and estimated $2.5 million dollars annually.  [EPA-HQ-OAR-2009-0491-3933[1].1, p.6]
Beyond New York, Delaware, and Louisiana, looking at the aggregation of all CATR states, this transfer of wealth is profound. Comparing the July projected method to Option 1, coal units would lose an estimated 199,679 allowances at a value of $99,839,500 annually. The latter represents an annual transfer of wealth or windfall to gas generation owners.  [EPA-HQ-OAR-2009-0491-3933[1].1, p.6]
An unfair allocation that provides windfall profits for one sector and at the same time excessive compliance burden to others is in conflict with the Clean Air Act, CATR, and recent mandates for fair policy and regulation that do not impede economic recovery.[EPA-HQ-OAR-2009-0491-3933[1].1, .6]
Progress Energy Service Company
Although the allocations for certain units increase under Options 1 and 2. those increases are overwhelmed by significant decreases at other units. A case in point involves Progress Energy's Crystal River Units 1 and 2 (ORIS Code 628). The SO2 allocations for these units decreased by 85 percent for Option 1 and by 78 percent for Option 2 when compared with the original draft allocations. These coal-fired units are currently unscrubbed, and it is impossible to install controls on them during the early years of the program. The loss of from 22,000 to 24,000 SO2 allowances, depending on the option, would have to be made up mainly through allowance purchases. [EPA-HQ-OAR-2009-0491-4011[1].1, p.4]
Vectren Corporation
Vectren was able to completely reproduce the allocations to its units under Option 1. By contrast, the assumptions used to calculate the reasonably foreseeable maximum emissions constraint in Option 2, particularly the support for the maximum hourly heat input attributed to each unit, are not clear from the technical support material provided in the NOOA and Vectren was unable to reproduce these numbers by any means or by using the unit data included in the NEEDS IPM v4.1 O. The maximum hourly heat inputs assumed in the technical support documents exceed the Vectren units' operating capacities. Additionally, the 'clean S02 and NOx input rates' are lower than historic operating capabilities. The rates are BACT level, and can not necessarily be attained at existing units, even well-controlled units, without significant modifications. For example, EPA's assumptions around the efficiencies of an FOO scrubber system fail to take into account that the scrubbers on AB Brown Units 1 and 2 are the original scrubbers constructed with the units (1979 and 1986, respectively). The two AB Brown scrubbers are two of the few remaining dual alkali scrubbers currently in operation, and they are not capable of achieving the efficiency assumptions ascribed to scrubbed units in the model. In reality, the dual alkali scrubbers at AB Brown Units 1 and 2 are capable of achieving an average S02 removal efficiency of80-85%, instead of the assumed efficiencies of 87.7% (AB Brown Unit I) and 95.3% (AB Brown Unit 2) in the NEEDS database. [EPA-HQ-OAR-2009-0491-3923[1].1, pp.3-4]
Wisconsin Public Service Corporation (WPSC)
In particular, WPSC is concerned that the proposed unit average heat input calculation method is not representative for Weston Unit 4 (ORIS ID: 4078) by not characterizing operation in 2008 for which only 6 months of emission data were reported. During this startup year, the annual capacity factor was only 22.5%, in large part because it operated in only 6 months in 2008. In 2009,the unit had its first full year of operation. Emission data was reported for 12 months and the annual capacity factor was 64.7%. In 2010, Weston Units 4's second full year of operation, the annual capacity factor was 72.7%. Please see the operating summary below in Table 1.  [EPA-HQ-OAR-2009-0491-3994[1].1, pp. 1-2; see 3994.1, p. 2 for Table 1. Weston Unit 4 Operating Data 2005-2010]
In the NODA allowance allocation method, Weston Unit 4's unit level average of the 3 year highest annual heat input is determined by averaging the heat input values from 2 years of heat input data: 2008 and 2009. The heat input in 2008 and 2009 is not representative of normal unit operation due to unit startup and testing. The data from 2010 is more representative of the way this unit will operate but still less than the longterm projected capacity factor of 75 percent. [EPA-HQ-OAR-2009-0491-3994[1].1, p. 2]
We request that the methodology for the calculation of Weston Unit's 4 average heat input be altered so that partial reporting years are not included in the baseline data. For new units, such as Weston 4, the most recent available data from years with fulltime operation should be used - in this case, 2009 and 2010. If 2010 data cannot be used, then the unit heat input should be based on the one year with 12 months of reported data (2009). [EPA-HQ-OAR-2009-0491-3994[1].1, p. 2]
Response:
EPA has finalized a heat input based allocation methodology that limits unit level allocation to levels that do not exceed emissions during a historic emission baseline period.  See discussion in section VII.D for why EPA chose this approach and how it addresses concerns expressed by commenters.  In this final allocation methodology, EPA uses a 2006-2010 heat input baseline.  Because final approach the highest three years, those units who expressed concern about pre-2008 annual data not being complete because the particular unit only reported for ozone season would still have three full years worth of data (2008, 2009, 2010) with this new baseline.  Additionally, EPA updated its heat input and emissions data used in the allocation tables based on data presented in comments.  The final approach does not rely on technology specific capacity factors to which some commenters had expressed concerns.
Organization: North Carolina Electric Membership Corporation
Comment:
North Carolina Electric Membership Corporation
The twelve electric generating units located at Anson (Oris Code 56249) and the ten units located at Hamlet (Oris Code 56292) would be regulated by the EPA's proposed Clean Air Transport Rule ("Transport Rule") for SO2 and NOX emissions. These units have incorrect/missing MW capacity and Btu/kWh heat rate information in the Option #2 underlying data. Each unit should have a listed 28.3 MW capacity and 4980 Btu/kWh heat rate under columns BP and BQ, respectively. Although these values are not used in the calculations, we would like these values added/corrected for the record. [EPA-HQ-OAR-2009-0491-4001[1].2, p.1]
[An Excel spreadsheet can be found in the comment attachment, 4001.1.]
Response:
EPA did not finalize option 2 from the January 7, 2011 NODA in the Transport Rule.  It uses a methodology that is described in section VII.D of the preamble. That methodology does not rely on capacity and heat rate information, and thus the corrects listed above would no longer directly enter the formula used to determine a units allowance allocation.  Section VII.D of the preamble describes the final allocation methodology under the Transport Rule FIP.
Organization: Prairie State Generating Company, LLC
Comment:
Prairie State Generating Company, LLC
The size of the NUSA budget is of critical importance to PSGC since these units were designed, permitted, funded and began construction under regulations which provided adequate allowances for them to operate. PSGC expects to operate these extremely efficient units at a 90%+ annual capacity factor and at nearly 100% capacity during the ozone season once in normal routine operations. Although the NUSA was already underfunded for known new units in Illinois as originally proposed in the Transport Rule, this most recent NODA will exacerbate the underfunding problem in Illinois' NUSA, leaving PSGC with only 33%- 38% of the allowances needed to operate once both units are fully operational under either of the currently proposed alternatives. [EPA-HQ-OAR-2009-0491-3897[1].1, p.4]
Moreover, EPA even acknowledges that the allocations identified in this NODA are not final and are only approximations. 76 F ed.Reg. 1109, 1111. Therefore, the 'data' that are 'available' are not final and do not really provide a basis for more than approximate comments on that data, since the data themselves are only approximations. [EPA-HQ-OAR-2009-0491-3897[1].1, p.7]
Response:
Organization: Rochester Public Utilities (RPU)
Comment:
Rochester Public Utilities (RPU)
b. The underlying unit-level data:
o RPU reviewed the underlying data used in the allocation calculation for RPU units Silver Lake Plant Unit 4, Cascade Creek CT2 and Cascade Creek CT3. This data appears to be accurately represented with the exception of the generation capacity of CT2 and CT3. In the Option 2 underlying data tab of the "Updated Alternative allocation tables and underlying data - Jan. 7, 2011" document ID EPA-HQ-OAR-2009-0491-3875, the generation capacity for CT2 and CT3 are incorrectly listed as 28 and 48 MW, respectively. CT2 and CT3 are combustion turbine engines used for operating a single generator, CAMR Generator ID 2. This generator has a generation capacity of 49.9 MW. [EPA-HQ-OAR-2009-0491-3998[1].1, p.2]
Response:
Generating capacity is not used in the allocation methodology finalized for Transport Rule.  See section VII.D of the preamble for more description of the final allocation approach.
Organization: San Miguel Electric Cooperative, Inc.
Comment:
San Miguel Electric Cooperative, Inc.
[See Attachment - Coal Units - at the end of this comment letter (30 pages).]
Response:
EPA has finalized an allowance allocation methodology based on historic heat input, but limited to maximum historic emission levels.  See section VII.D for a more detailed explanation of the allocation methodology.
Organization: Southern Company
Comment:
Although the unit ID errors identified in the proposed Transport Rule appear to be correct in the NODA3, data flaws still exist. Below are specific examples of flaws that we identified. However, due to having only 30 days to review the data, other errors may still be present in NODA3.
:: The 2004 ozone season historical NOx emissions are incorrect. This is perhaps due to EPA pulling information from the CAMD database by program, i.e., the NOx SIP Call. In 2004, seasonal NOx compliance started on May 31, rather than May 1. EPA should use data from the entire ozone season, not just the data when the seasonal NOx program began.
:: There are some unit-level heat input errors for units sharing a common stack. For example, in 2009 Branch Unit 1 heat input is over by 26,484 while Branch unit 2 is under by 26,482. Overall, Plant Branch as an entire facility is approximately correct. There are similar errors in seasonal heat input for 2007-2009 for Plants McDonough and Yates.[EPA-HQ-OAR-2009-0491-3946[1].1, p.10]
Response:

EPA used its best available data when it issued the January 7, 2011 NODA containing allocations under alternative methodologies and underlying heat input.  Commenters had the chance to review and submit corrected data which EPA considered and made updates to the underlying data where appropriate.  Additionally, EPA modified its approach for determining ozone-season emissions in the final allocation tables by using data from the five ozone-season months instead of data reported under the ozone-season for that year.  Therefore, the 2004 ozone season emissions in the final allocation tables include the emissions from the month of May (even though it was not considered part of the ozone-season at that time) and the first concern expressed above is no longer an issue in the final allocation tables.  Furthermore, EPA notes that this adjustment in the final allocation tables has little or no impact on most units.  The 2004 ozone-season emissions value is only factored into the final allocation if: 1) it was the highest year for ozone season emissions at a particular unit over the eight year baseline period, and 2) if the unit's initial heat input allocation was exceeding its historic maximum level.

In regards to the second bullet in the comment above, EPA has made this correction in the final allocation tables.  However, it notes that the change has no impact on total allocations to the facility.
Organization: Southern IL Power Cooperative
Comment:
Southern Illinois Power Cooperative believes the NODA proposal unfairly treats plants that had added BACT prior to EPA's current proposal.  Plants that initiated the capital expense to reduce emissions earlier experienced higher generation costs, and, in today's power marketing scheme, would have been called upon for power later, as opposed to plants that didn't have the added expense of pollutions control equipment and have the capital expenses  calculated into the price of their power.  Thus, generated megawatt sales and the associated heat inputs for the early BACT plants will be lower than those who did not add pollution control equipment.  In addition, financial gains were seen by those who did NOT add pollution control equipment.  Under this rule, such facilities that did NOT add pollution control equipment are rewarded with more NOX & SOX allowances from higher heat input AND enjoy the additional financial improvement from selling more power over the years to now help finance (BACT) pollution control equipment.  The Heat Inputs for "controlled plants" should be raised, while the Heat Inputs for "uncontrolled" plants should be lowered to adjust for the inequity described above. [EPA-HQ-OAR-2009-0491-3901[1].1, pp.2-3]
Response:
See section VII.D of the Transport Rule preamble for a description of the final allocation methodology under the Transport Rule FIP.  EPA disagrees with the commenter's characterization of the impacts of the final Transport Rule's allocation methodology.  FIP allowance allocations to existing units are largely based on historic heat input, which is neutral to a unit's historic choice of fuel or pollution control technology.  The commenter is effectively requesting that EPA adjust the Transport Rule's allocation methodology to compensate specific unit owners' prior investments in pollution control equipment; however, such investment was in many instances required by other state or federal environmental regulations.  EPA does not believe this kind of data adjustment would be appropriate considering the other potential legal and regulatory requirements leading to pollution control retrofit decisions at specific units.  Furthermore, EPA disagrees with the validity of the commenter's requested data adjustments even if EPA were to accept the premise of the adjustments.  EPA notes that under market-based programs already in place during this historic baseline period, all covered units would face the marginal price of emitting (as reflected by the market value of an allowance), and thus units which installed pollution controls would have a lower emission cost impact to factor in to their dispatch bids than uncontrolled units.  The commenter's assertion that pollution controls negatively affect unit dispatch ignores this positive side of the dispatch equation under existing market-based emission trading programs.   As a result, EPA finds the requested adjustments to be incorrect and inappropriate for the purpose of allowance allocations to existing units under the final Transport Rule.
Organization: West Virginia Department of Environmental Protection
Tenaska, Inc.
Comment:
Tenaska, Inc.
Tenaska has reviewed the unit level heat input data and resulting projected allocations provided on the EPA website and finds no significant discrepancy from its own data and calculations. [EPA-R03-OAR-2010-1027-DRAFT-0005.1[1], p.2]
West Virginia Department of Environmental Protection
Underlying unit-level data and resulting allocations for the alternative methodologies
The WVDAQ supports the use of the most current continuous emissions monitoring system (CEMS) data available from EPA's Clean Air Markets Division ( CAMD) as the basis for the allocations. [EPA-HQ-OAR-2009-0491-4000[1].1, p.2]
Response:
EPA is finalizing a historic heat input methodology for allocation of emissions allowances under the FIP.  This approach is analogous to "option 1" in the January 7, 2011 NODA.  See final rule preamble section VII.D for further of discussion EPA's rationale for this approach and response to comments in favor of and in opposition to this approach.
Organization: Westar Energy, Inc.
Comment:
Westar Energy, Inc.
Westar's concerns about Options 1 and 2 reliance on historical data arise in light of the recent consent decree between Westar and EPA in United States v. Westar Energy, Inc., Civil Action No. 09-CV-2059 JAR/DJW ('consent decree'). That decree set maximum emissions levels for Westar's three Jeffrey Energy Center ("JEC") units combined for both NOx and SO2. As an example, under some conditions the consent decree sets maximum SO2 emissions level of 6600 t/y for all three JEC units combined, yet Options 1 and 2 propose an allowance greater than that for each unit separately, which translates on a combined basis to more than triple the consent decree maximum. [EPA-HQ-OAR-2009-0491-3952[1].1, p.2]
For NOx Annual, under some conditions the consent decree places a 12,400 t/y limit for all three JEC units combined by 2014, and 9,600 t/y by 2016. Options 1 and 2 allocate over 6,000 t/y to each unit, for a combined total that is about 50% more than the consent decree maximum. [EPA-HQ-OAR-2009-0491-3952[1].1, p.2]
Response:
EPA has finalized an alternative allocation methodology slightly different than those described in the January 7, 2011 NODA.  See section VII.D for a description of this final allocation methodology.  EPA notes, that while it did updates its modeling to reflect consent decrees, unit specific allocations are determined purely on historic data and are not limited by permit and or consent decree requirements.  However, those emission limits will still apply regardless of the unit's allocation under Transport Rule, extra allowances would be sold or retired
Organization: Western Farmers Electric Cooperative (WFEC)
Comment:
Western Farmers Electric Cooperative (WFEC)
It appears that data from three of WFEC's units (Anadarko unit 4, 5, and 6) was not included in EPA's Acid Rain database because these units were exempt from Acid Rain in the past and was further complicated because Oklahoma was one of the few states that were not included in CAIR but are now included in CATR.  Not having had this data in the original data bases has obviously resulted in no allocations for these three units.  Your help in resolving this unique problem will be greatly appreciated!  [EPA-HQ-OAR-2009-0491-3945[1].1, p.1]
Anadarko units #4, 5 and 6  -  These units have been completely overlooked and are not included in the allocation database.  During recent telephone conversations, I understand how this oversight might have occurred.  All three of these units have been exempt from acid rain reporting and are not included in the CAMD database used in this proposal; however, this results in the CATR Allocation Database being incorrect.  This should be corrected by using data from other sources such as the Oklahoma Emission Inventory if these units are to be included in CATR.  [EPA-HQ-OAR-2009-0491-3945[1].1, p.3]
Anadarko #9  -  11- There is limited data available for these three units as they began operation in mid - summer of 2009.  WFEC would like to suggest that the annual emissions be prorated for a full year  to determine the allocations for these three units. [EPA-HQ-OAR-2009-0491-3945[1].1, p.3]
Anadarko units #1 and #2  -  These units have not been given allowances in the CATR Allocation Database.  Units #1 and #2 are very small units (15 MW) are therefore exempt from acid rain; therefore, allowances have not been provide.  WFEC would request allowances be provided for these units in the future if CATR is applicable to these small units. [EPA-HQ-OAR-2009-0491-3945[1].1, pp.3-4]
Hugo unit #1  -  This unit is the only coal unit in the state of Oklahoma that already has installed low NOx burners and can achieve emission rates below 0.26 lb/mmBTU.  The other utilities have coal units that are allowed to meet emission rates much higher (0.286 lb/mmBTU) than WFEC's Hugo plant limit of .179 lb/mmBTU.  EPA's proposal fails to recognize units and the electric consumer who have borne the higher electricity costs because they must pay for existing, expensive emission controls. [EPA-HQ-OAR-2009-0491-3945[1].1, p.4]
Response:
EPA has updated its allocation tables for the final Transport Rule, and they now include Anadarko units 4,5, and 6.  Additionally, it has updated its baseline to 2006-2010 for historic heat input, which addresses some of the commenters concern about Anadarko units 9-11 having only partial data for 2009.

XX.A.3. Unit-level Comments on Applicability (e.g., Remove or Add Unit to Inventory of Potential Existing Units)

Organization: Alcoa Power Generating Inc. - Warrick Power Plant
Comment:
Alcoa Power Generating Inc. - Warrick Power Plant
1.) This NODA specifically invites comment regarding existing units listed in the initial Clean Air Transport Rule (CATR) that should not have been included. The CATR, as proposed, specified that the proposed rule would be applicable for electricity generating units producing electricity for sale. APGI consists of units 1-4. Units 1-3 are industrial boilers that produce electricity, steam, and hot process water for the· Alcoa Inc. - Warrick Operations primary aluminum smelter and aluminum fabrication plant. Electricity produced by these units is used for the exclusive use of Alcoa Inc., and is not sold on the grid. Unit 4 is jointly owned by APGI and Vectren. 50% of the electricity produced by this unit is sold to the grid, so it will be subject to the CATR. APGI requests that Units 1-3 be removed from the list of existing potential units, since they do not sell to the grid. [EPA-HQ-OAR-2009-0491-4024, p.1]
Response:
As suggested by commenter, Warrick Units 1-3 are not included in the final list of existing potential Transport Rule units.  Sources should see section VII.D of the preamble for a description of how this list was developed.
Organization: Ameren Services Company
Comment:
Ameren Services Company
EPA on page 1112 of the Federal Register Notice states 'In particular, if the unit was retired or in cold storage in 2010 or is a steam turbine at a combined cycle (CC) plant, then it was not included as a unit in the list of potential existing Transport Rule Units.' EPA may have inadvertently omitted some heat input by generalizing that all CC plants have only a turbine on the steam side of the generation. In many cases these CC plants also include Duct Burners that supplement the heat generated by the gas turbine. Has EPA arbitrarily omitted the heat input from these Duct Burners by eliminating the steam turbine part of the plant? [EPA-HQ-OAR-2009-0491-3894[1].1, p.1]
Response:
The heat input values were used in their entirety, as reported, for allocations under the final Transport Rule.  No heat input has been omitted, the omissions references above reference an accounting of units corrections where an entity was reporting as one unit, but disaggregated into two units for modeling purposes.  However, the heat input would not change.
Organization: Cogentrix Energy, LLC
Comment:
Cogentrix Energy, LLC
Cogentrix has found conflicts in definitions of applicability between the proposed Transport Rule and the Acid Rain and CAIR Rules that have resulted in the exclusion of our two Virginia facilities from receiving allocations in the draft Rule. Cogentrix has reviewed proposed allocations listed in EPA's Technical Information for the Transport Rule, revised January 7, 2011. Cogentrix-owned sites in Hopewell, VA (ORIS Code 10377) and Portsmouth, VA (ORIS Code 10071) were not included in 'Altemative allocation tables.pdf.' Both sites operate with two 'three-on-one' boiler to generator designs, where three boilers provide steam to one 55-MWe electric generator. The Transport Rule provides applicability requirements listed under Title 40 Code of Federal Regulations 97.404(a)(J) as follows:
The following units in a State shall be TR NOy Annual units, and an source that includes one or more such units shall be a TR NOx Annual source, subject to the requirements of this subpart: Any stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine serving at any time, since the later of November 15, 1990 or the start-up of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe producing electricity for sale. [EPA-HQ-OAR-2009-0491-3916[1].1, pp.1-2]
Since the 'generator. .. nameplate capacity' for each generator (emphasis added) at each site is greater than 25 MWe, Cogentrix sites are included within the scope of the Transport Rule and therefore allocations for each site should be assigned. Cogentrix also reviewed EPA's Technical Information file entitled 'BADetailData.xls.' The analysis shown in this file appears to use the definition of applicability taken from the Acid Rain rules, where 'units' (interpreted to be boilers) with a capacity of less than 25 MWe are not included within the scope of the Acid Rain rule. Both Cogentrix facilities opted into the Acid Rain Program in 2008, and should have been included in EPA's allocation analysis on that basis alone. Both Cogentrix facilities have also participated in the CAIR program since its inception and likewise, should have been included in EPA's allocation analysis on that basis alone. [EPA-HQ-OAR-2009-0491-3916[1].1, p.2]
Because both units meet the applicability definition in the proposed Transport Rule, Cogentrix has conducted an analysis of allocations and required reductions from 2005 baseline emissions data using the methodology discussed in the preamble of the proposed rule. The calculation methodology is presented in Attachment 1 and the results are presented in Table 1. [EPA-HQ-OAR-2009-0491-3916[1].1, p.2] [[See Docket Number EPA-HQ-OAR-2009-0491-3916[1].1, p.2 for Table 1.]]
Cogentrix reiterates its request that EPA include the Cogentrix-owned sites in Hopewell, VA (ORIS Code 10377) and Portsmouth, VA (ORIS Code 10071) in the Transport Rule's Allocation Analysis. [EPA-HQ-OAR-2009-0491-3916[1].1, p.3]
Response:
As suggested by commenter, Hopewell and Cogentrix Units are included in the final allocations tables as potentially covered Transport Rule units and have allocations based on the methodology laid out in section VII.D of the preamble.
Organization: Connecticut Department of Environmental Protection
Comment:
Connecticut Department of Environmental Protection
In Attachment B of CTDEP's September 30, 2010 comments on the proposed Transport Rule (see Appendix 1 to this letter), CTDEP requested the following: [[See Docket Number EPA-HQ-OAR-2009-0491-3884[1].1, pp. 4-8 for Appendix 1.]]
-That Norwich be removed from the Transport Rule Allocation Table as the unit has a nameplate capacity less than 25 MWe and therefore does not meet EPA's proposed Transport Rule applicability criteria. [EPA-HQ-OAR-2009-0491-3884[1].1, p.2]
-That the qualification requirement date for solid waste incineration units be changed to a more recent year, such as 2002. If EPA changes the qualification requirement date and if Exeter Energy (Exeter) is determined to combust 'solid waste,' it is CTDEP's understanding that Exeter would be considered a solid waste incineration unit and would not be subject to the Transport Rule.
-That the Pratt & Whitney cogeneration unit be removed from the Transport Rule Allocation Table as the annual data since 2003 show that Pratt & Whitney has consistently sold energy in amounts less than the 219,000 MWh cogeneration exemption threshold. [EPA-HQ-OAR-2009-0491-3884[1].1, p.3]
CTDEP again requests EPA to take action to remove Norwich and Pratt & Whitney from the existing unit list and to remove Exeter from the existing unit list if EPA changes the qualification requirement date for solid waste incineration units and if Exeter is determined to combust 'solid waste'. [EPA-HQ-OAR-2009-0491-3884[1].1,p.3]
Response:
Connecticut was not determined to be a contributing state in the final Transport Rule.  Therefore, the state and units located in the state are not subject to the final Transport Rule.
Organization: Consolidated Edison Company of New York, Inc, (CECONY)
Capital Power Corporation
Kentucky Division for Air Quality
DTE Energy Services (DTEES)
Nelson Industrial Steam Company (NISCO)
Comment:
Capital Power Corporation
1. The Portside Energy facility (ORIS No. 55096) is listed in and allocated emissions to in the NODA. The facility is a cogeneration unit and sells all the electricity (and steam) to the host facility. It does not sell any power to the grid. It appears to us that it should be exempted. EPA needs to clarify whether it is exempt from CATR. [EPA-HQ-OAR-2009-0491-3930 ,p.1]
2. We have several questions regarding the Morris Cogeneration facility (ORIS No. 55216).
a. In the original proposal, it was correctly identified as the "Morris Generation Facility". In the January 7, 2011 NODA database, it was listed as the "Aera (sic) South Belridge Cogen Facility." That is incorrect and we have no idea why it was so termed. This needs to be corrected in the database.
b. The Morris Cogeneration is and has always been a cogeneration facility. It appears to us that it should be exempted EPA needs to clarify that it is exempt from CATR. [EPA-HQ-OAR-2009-0491-3930, p.1]
3. We have several questions regarding Capital Power's CPI USA North Carolina, LLC  -  Roxboro facility (ORIS No. 10379), which is listed by a former name, EPCOR USA NC Roxboro, in the database.
a. The facility is a Qualifying Facility (QF) small power producer that burns greater than or equal to 75 percent non-fossil fuels. It was also a former QF cogeneration facility that lost its steam host but retains the capability to cogenerate. EPA needs to clarify whether it is exempt from CATR.
b. If the biomass portion of the fuel is removed from the equation, the resultant total generation capacity would be less than 25 Megawatts (MW). EPA needs to clarify whether it is exempt from CATR.
c. .The facility has 3 combustion units that exhaust to one stack and serve a single steam turbine generator. Even including biomass, each unit cannot generate 25 MWs. EPA needs to clarify whether it is exempt from CATR. [EPA-HQ-OAR-2009-0491-3930, p.1]
4. Capital Power's CPI USA North Carolina, LLC  -  Southport facility (ORIS No. 10378), which is listed by a former name, EPCOR USA NC Southport, in the database is a cogeneration facility.
a. The facility is a Qualifying Facility (QF) cogeneration facility that burns a significant portion of non-fossil fuel. EPA needs to clarify whether it is exempt from CATR.
b. The facility has 6 combustion units that exhaust to two stacks and serve two steam turbine generators. Even including the non-fossil fuels, each unit cannot generate 25 MWs. EPA needs to clarify whether it is exempt from CATR. [EPA-HQ-OAR-2009-0491-3930, p.1]
5. The EF Kenilworth facility in Kenilworth, NJ (ORIS No. 10806) is not listed in the database and was not subject to the Clean Air Interstate Rule (CAIR). Its generation capacity is less than 25 MW. We do not believe CATR would apply to this facility.. EPA needs to clarify that it is exempt from CATR. [EPA-HQ-OAR-2009-0491-3930, .1]
Consolidated Edison Company of New York, Inc, (CECONY)
The Allocation Table associated with the subject NODA lists three Con Edison-owned units at its 74th Street Steam Station that do not operate as electric generating units ('EGUs'). Specifically, the units shown in the table below (data taken from the Allocation Table) do not generate electricity but only provide steam to the Company's district steam system. [EPA-HQ-OAR-2009-0491-3910[1].1, p.2] [[See Docket Number EPA-HQ-OAR-2009-0491-3910[1].1, p.2 for the above referenced table.]]
Notwithstanding their non-electric generating operation, these units would be considered 'Transport Rule units', as defined in Section IV.A of the NODA, which states the following:
Under the proposed Transport Rule, a covered Transport Rule unit is generally any stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine located in a proposed Transport Rule state and serving at any time, since the later of November 15, 1990 or the start-up of the unit's combustion device, a generator with a nameplate capacity greater than 25 MWe producing electricity for sale. [EPA-HQ-OAR-2009-0491-3910[1].1, p.2]
These three units at the Company's 74th Street Steam Station did generate electricity between April 26, 1962, and December 31, 1999, and, based on EPA's definition in the NODA, would be subject to the CATR. However, because these units have not generated electricity in more than 11 years, including the baseline period chosen by EPA - 2005 through 2009 - for establishing allowance allocations, Con Edison believes these units should be exempt from participation in the CA TR, which would obviate the need for their receipt of allowance allocations. [EPA-HQ-OAR-2009-0491-3910[1].1, p.2]
DTE Energy Services (DTEES)
DTEES supports the revised definition of existing unit to include any facility that began commercial operation before January 1, 2009, thereby making any facility that began on or after that date a new unit.  New units would receive allowances from the State's new-unit set-aside pool. By setting January 1, 2009 as the delineation between new/existing units EPA should give repowered facilities the opportunity to receive allowances at a level that reflect current, not historical, operation. [EPA-HQ-OAR-2009-0491-3950[1].1, p.1]
DTEES also believes EPA should expand the definition of new units to include those that have recently been redeveloped or repowered with a renewable fuel that is different than what was used when their original commercial operation commenced. Excluding such repowering projects from the new unit definition and in turn its ability to obtain allowances will likely cause significant economic hardship to these projects and in turn present a disincentive for continuing with such investments. [EPA-HQ-OAR-2009-0491-3950[1].1, p.2]
DTE Stoneman, Cassville, WI, ORIS code 4146. The facility consists of two 340 mmbtu/hr rated boilers serving through cross connected steam headers, 33 MW and 18 MW generators. Emissions are through a combined stack. [EPA-HQ-OAR-2009-0491-3950[1].1, p.2]
This facility is subject to the Acid Rain program and CAIR. The two units were originally built in 1949 and 1951 and designed to burn coal. DTEES purchased the facility in May 2008. Prior to the purchase, the previous owner operated the plant intermittently, selling the electricity through the Midwest Independent System Operator (MISO) at market rates. After the facility was purchased by DTEES, the units were operated intermittently to burn down the remaining coal pile in preparation for the conversion from coal to wood biomass firing. The remaining coal pile was depleted in March 2009. The facility was shut down during the March 2009 to August 2010 period while it was modified to be repowered burning 100% woody biomass. The facility will sell all of the renewable electrical output while firing woody biomass to one customer under a power purchase agreement. The facility declared the commissioning period that began July 28, 2010 completed on October 8, 2010. The customer was also notified of the electric delivery start date (commercial operation date) under the power purchase agreement. We believe the historical coal-fired operations are not indicative of future operations burning woody biomass. [EPA-HQ-OAR-2009-0491-3950[1].1, pp.2-3]
EPA should expand the definition of new units to include those that have recently been redeveloped or repowered with a renewable fuel that is different than what was used when the original commercial operation commenced. For example, the units at DTE Stoneman began commercial operation in 1949 and 1951 combusting pulverized coal. Prior to DTEES purchasing the units, they were underutilized as coal units and not economically viable to operate. This resulted in low historic heat input compared to the potential heat input that is expected while burning woody biomass. [EPA-HQ-OAR-2009-0491-3950[1].1, p.3]
Kentucky Division for Air Quality
As for the proposed Transport Rule (75 FR 45210), the below comment remains relevant to the January 7, 2011 NODA since the Calvert City Cogeneration unit (26 MWe turbine - ORIS - 55308-Genl) should be examined to determine its applicability for the Transport Rule and the existing unit allowance allocations. Therefore, the Division requests that EPA contact and work with the Division to properly determine the Calvert City Cogeneration turbine's status pursuant to the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3970[1].1, p.2]
As for the proposed Transport Rule (75 FR 45210), the below comment remains relevant to the January 7, 2011 NODA since the Calvert City Cogeneration unit (26 MWe turbine - ORIS - 55308-Genl) should be examined to determine its applicability for the Transport Rule and the existing unit allowance allocations. Therefore, the Division requests that EPA contact and work with the Division to properly determine the Calvert City Cogeneration turbine's status pursuant to the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3970[1].1, p.3]
Pursuant to the proposed Transport Rule Preamble Section V.D.4.b.(I), the Calvert City Cogeneration EGU (turbine - ORIS - 55308-Genl) as shown in EPA's Technical Support detailed allocation file (BADetailedData.xls, Units Characteristics Worksheet) should indicate a capacity of 26 MWe instead of 23 MWe as is listed. This cogeneration EGU was part of the NOx SIP Call NOx ozone season trading program and was brought into the CAIR NOx ozone season program. However, the unit was exempted from the CAIR NOx annual program since it met the CAIR NOx annual program cogeneration exemption. Even with the CAIR ozone season cogeneration exemption, the unit was subject to the CAIR NOx ozone season trading program since it was previously subject to the NOx SIP Call NOx ozone season program, which did not provide a cogeneration exemption. For the Calvert City Cogeneration EGU, the Division requests that EPA work with the Division to: (1) verify that the unit is exempt from the proposed Transport Rule NOx annual trading program pursuant to the cogeneration exemption; and (2) determine whether the unit is subject to the proposed Transport Rule NOx ozone season trading program given that the unit was first subject to the NOx SIP Call ozone season trading program. [EPA-HQ-OAR-2009-0491-3970[1].1, p.3]
Nelson Industrial Steam Company (NISCO)
These units meet the definition of cogeneration unit and are exempt under the Acid Rain program. However, they do not meet the proposed efficiency standard to meet the definition of cogeneration unit under the proposed CATR. NISCO reiterates its prior comments requesting that EPA exempt the NISCO units from CAIR as they have not sold electricity to the grid for a number of years, and have never sold more than 1% of their potential electrical output to the grid. [EPA-HQ-OAR-2009-0491-4026, p.4]
Response:
These units are currently being left in the list of potential existing Transport Rule units that receive final allowance allocations.  However, EPA notes that the inclusion of such units in no way suggests that EPA has made a determination about the applicability of the proposed Transport Rule to any unit.  EPA is including the units in the allocation tables finalized for the Transport Rule because based on its best available data and that submitted by the commenter, the sources' applicability status is unclear.  Therefore, EPA is including the unit so that it has allocations in the event that it a covered Transport Rule unit.  If the unit is subsequently determined not to be subject to the final Transport Rule, than EPA has established procedures for taking back any allocated allowances.  Therefore, their inclusion in the list of potentially covered Transport Rule units reflects a conservative approach by EPA to guard against the possibility of the units being subject to the Transport Rule without having any allowance allocation.
Organization: Edison Mission Energy (EME)
Comment:
Edison Mission Energy (EME)
EME's Waukegan 6 (Boiler 17) unit should have been included in EPA's list of potential existing Transport Rule units provided in the Transport Rule NODA.
Since the Transport Rule proposes unit level allocations for non-operating units in the six years post retirement and Waukegan 6 (Blr. 17) was not retired until late 2007, it should receive allocations in 2012 and 2013. [EPA-HQ-OAR-2009-0491-3953[1].1, p.3]
EME submits that EPA improperly excluded Waukegan 6 (Blr. 17) from its list of existing units in the Transport Rule NODA. Waukegan 6 (Blr. 17) should have been included pursuant to the Transport Rule applicability provisions because Waukegan 6 (Blr. 17) was not retired until late 2007. Since the Transport Rule proposes unit level allocations for nonoperating units in the six years post retirement, Waukegan 6 (Blr. 17) would receive allocations under the Transport Rule applicability provisions in years 2012 and 2013. Waukegan 6 (Blr. 17) was included as an existing Transport Rule unit in the Transport Rule proposal. The agreement between Midwest Generation and IL EPA (described in III.B above), required Waukegan 6 (Blr. 17) to be shutdown. Since, Waukegan 6 (Blr. 17) is entitled allocations in 2012 and 2013 under the Transport Rule applicability provisions, EME submits the following data needed to perform the calculations under the two methodologies proposed in the Transport Rule NODA. [EPA-HQ-OAR-2009-0491-3953[1].1, pp.23-24] [[See Docket Number EPA-HQ-OAR-2009-0491-3953[1].1, p.24 for the data tables.]]
EME's Waukegan 6 (Blr. 17) unit should have been included in EPA's list of potential existing Transport Rule units provided in the Transport Rule NODA. [EPA-HQ-OAR-2009-0491-3953[1].1, p.25]
Response:
See section VII.D of the preamble for a description of how EPA determined its list of potentially covered existing Transport Rule units to which it allocates allowances.  This final list is also given in the Technical Support Document for Allowance Allocations.  As described in each of these documents, EPA looked at units reporting as "operating" in 2010 as an initial filter for developing this list.  Units that were listed as retired or in long term cold storage were not considered as potential existing Transport Rule units, and do not get, nor is its EPA intention, to allocate to these units.  The provisions cited by the commenter only apply to units that are considered existing Transport Rule units and that subsequently retire.  The provisions do not apply to units that retired, for example, in 2007.  The temporary continued allocation to Transport Rule units upon their retirement.
Continuing temporary allocations to Transport Rule units that retire has the benefit of reducing the incentive to keep units in operation that should otherwise be, for instance, permanently retired due to age and inefficiency.  There is clearly no such benefit from extending this provision to sources who retired years prior to the Transport Rule.
Organization: Exelon
Birchwood Power Partners, L.P.
Wolverine Power Supply Cooperative
America's Natural Gas Alliance
West Virginia Department of Environmental Protection
Comment:
America's Natural Gas Alliance
ANGA supports the manner in which EPA would identify 'existing Transport Rule units' and establish allocations for existing units subject to the CATR. Use of data from the myriad ongoing EPA trading programs plus data from Integrated Planning Model IPM V.4.10 (National Electric Energy Data System - NEEDS) to identify potential existing Transport Rule units ensures that the Agency will capture the appropriate universe of units using the most up-to-date data. ANGA also supports retention of some flexibility to add or subtract individual units based on information supplied to EPA as part of the comment process. [EPA-HQ-OAR-2009-0491-3939[1].1, p.4]
Birchwood Power Partners, L.P.
As one of the cleanest coal-fired power plants in Virginia, Birchwood Power would generally receive adequate allowances under the proposed alternatives to cover its emissions when dispatch returns to pre-recession levels. [EPA-HQ-OAR-2009-0491-3940[1].1, p.2]
Exelon
Exelon thanks EPA for responding to its Original Comments by making corrections to EPA's alternative allocation data sets. See, Original Comments at 43-45. These corrections include the addition of Fairless Hills Units 4 and 5 to EPA's alternative allocation data sets. EPA should add these units to its database of units receiving allocations. Exelon also thanks EPA for including Mountain Creek Units 6 and 7 to its alternative allocation data sets. These units were inappropriately retired by the IPM model in EPA's original Transport Rule allocation tables, as discussed in Exelon's Original Comments. [EPA-HQ-OAR-2009-0491-3919[1].1, pp.15-16]
West Virginia Department of Environmental Protection
List of units used in applying the alternative methodologies, including the classification of "existing unit"
Under either of the proposed alternative allocation methodologies in the current NODA, allocations would be based on historical data not IPM projections, and no historical basis would exist for allocations to units that were not operating in the baseline period of 2005 through 2009. Under the originally proposed applicability provisions, allocations would be made to those units "that commenced commercial operation or are planned to commence commercial operation prior to January 1, 2012". Allocations made in accordance with those provisions would be problematic with the use of either of the newly proposed alternative allocation methodologies. Therefore, the WVDAQ supports the new classification of "existing unit" as those that commenced commercial operation prior to January 1, 2009. Units that began operation after that date could obtain allocations from the new unit set aside pool. [EPA-HQ-OAR-2009-0491-4000[1].1, p.2]
Wolverine Power Supply Cooperative
Regarding the USEPA's request for comment on appropriateness of the list of affected units, Wolverine finds the list to be correct as to units within which Wolverine has an ownership interest. [EPA-HQ-OAR-2009-0491-4014[1].1, p. 4]
Response:
Thank you for your comment.  The final allocation methodology and description for determining potentially covered existing Transport Rule units and new source set-asides can be found in preamble section VII.D.  The Technical Support Document for Allowance Allocation has the final list of potentially covered existing Transport Rule units to which allowances are allocated in its appendix.
Organization: First Energy
Madison Gas and Electric Company (MGE)
Georgia-Pacific LLC (GP)
International Paper
City of Hamilton
Comment:
City of Hamilton
Additionally, U.S. EPA's allowance allocation tables incorrectly include references to Hamilton's B008 unit at its municipal power plant. Hamilton's B008 unit is not a large electric generating unit ('EGU') and, therefore, is not subject to the proposed Transport Rule. 75 Fed. Reg. 45,210, 45,299, no. 77. Hamilton brought this mistake to the attention of Brian Fisher, U.S. EPA, Clean Air Markets Division, during a January 24, 2011 telephone conversation. As such, the letter serves as confirmation of the discussion and as Hamilton's written request that U.S. EPA remove B008 from the Transport Rule, the NODA and the accompanying allowance allocation tables. [EPA-HQ-OAR-2009-0491-3984[1].1, pp.1-2]
First Energy
FirstEnergy identified the Edgewater plant boiler A&B listed in both alternative allocation options. The Edgewater units (Oris # 2857) were removed from service indefinitely and should be removed from both NODA III alternative allocation databases, Option 1 & Option 2.    [EPA-HQ-OAR-2009-0491-3904[1].1, p.3]
Georgia-Pacific LLC (GP)
As explained below, the Georgia-Pacific LLC boilers that are listed in the Alternative Allocation Tables are not subject to the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3967[1].1, p.1]
Alabama River Cellulose LLC-(listed as Alabama Pine Pulp ORIS No. 54429 Power Boiler No.2)
The legal name for this mill is Alabama River Cellulose LLC. The facility operates several boilers that supply steam to two turbine generator sets at the facility. The turbine generators produce electricity, most of which is used to operate process equipment onsite. A small percentage of the total electrical power generated onsite is sold to the 'Grid'. One of the turbine generators produces approximately 40 MWh of electrical energy and the other turbine generator produces approximately 70 MWh of electrical energy. The estimated electrical generating capacity of Power Boiler No.2 is approximately 35 MWh. The total quantity of electricity sold by both turbine generators, based on available records from 2000 through 2010, has never exceeded 219,000 MWh in any calendar year. A list of the total quantity of electricity generated onsite by both hlrbine generators and sold to the 'Grid' from 2000 through 2010 is shown below: [EPA-HQ-OAR-2009-0491-3967[1].1, pp.1-2]
Calendar Year 2000     2001     2002     2003     2004     2005    2006    2007    2008    2009      2010
MWhsold       51,247 102,567 103,908 97,835 136,472 112,804 66,971 79,833 84,974 148,814 124,180
As shown by the data listed above, Alabama River Cellulose LLC has not triggered the criteria under which either of its turbine generators would be subject to the Transport Rule since the combined quantity of electricity sold is far less than the threshold for a single generator with a capacity greater than 25 MWh. Based on these facts, Power Boiler No. 2 qualifies for the cogeneration exemption under the proposed Transport Rule. We therefore request that EPA remove Power Boiler No.2 from its Alternative Allocation Tables as the facility does not meet the criteria for operating an EGU under the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3967[1].1, p.2]
Leaf River Cellulose LLC-(ORIS No. 10233 Power Boiler)
Leaf River Cellulose LLC operates several boilers that supply steam to two turbine generator sets at the facility. The turbine generators produce electricity, most of which is used to operate process equipment onsite. A small percentage of the total electrical power generated onsite is sold to the 'Grid'. Each of the turbine generators at the facility has an estimated electrical generating capacity of approximately 31.5 MWh. The total quantity of electricity sold by both turbine generators, based on available records from 2000 through 2010, has never exceeded 219,000 MWh in any calendar year. A list of the total quantity of electricity generated onsite by both turbine generators and sold to the 'Grid' from 2000 through 2010 is shown below: [EPA-HQ-OAR-2009-0491-3967[1].1, p.2]
Calendar Year 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
MWhsold          9       7     11     10    17    22     13     21    10     13    14
As shown by the data listed above, Leaf River Cellulose LLC has not triggered the criteria under which either of its turbine generators would be subject to the Transport Rule since the combined quantity of electricity sold is far less than the threshold for a single generator with a capacity greater than 25 MWh. Based on these facts, the Power Boiler qualifies for the cogeneration exemption under the proposed Transport Rule. We therefore request that EPA remove the Power Boiler from its Alternative Allocation Tables, as the facility does not meet the criteria for operating an EGU under the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3967[1].1, p.3]
Green Bay, Wisconsin (listed as the Broadway Mill ORIS No. 10360 Boiler B25)
The legal owner/operator of this mill is Georgia-Pacific Consumer Products LP. In addition to the legal name, GP suggests that EPA also designate this mill as 'Green Bay Broadway Operations' in any listings. The Broadway Mill operates five boilers (B25, B26, B27, B28, B29) that serve three turbine generators with electrical generating capacities greater than 25 MWh, designated as Nos. 7, 9 and 10, whose ratings are identified in the CAIR Certificate of Representation as 28.9, 43.2, and 28.2 MWe, respectively, after the application of their power factors. The turbine generators produce extraction steam and electricity, most of which is used to operate process equipment onsite. A small percentage of the total electrical power generated on site is sold to the 'Grid'. The total quantity of electricity sold by the facility, based on available records from 1999 through 2010 has never exceeded 219,000 MWh in any calendar year. Prior to 1999, the capability of the utility tie-in was only 10 MW pel' hour (87,600 MWh per year maximum), thereby precluding sales of electricity above the 219,000 MWh annual threshold value. The tie line is physically limited in its capability by relays that are designed to protect the equipment from over-current situations. A list of the total quantity of electricity generated on-site by all turbine generators (there are two other turbine generators on-site with capacities less than 25 MWh) and sold to the 'Grid' from 1999 through 2010 is shown below: [EPA-HQ-OAR-2009-0491-3967[1].1, p.3]
Calendar Year 1999 2000 2001 2002 2003    2004    2005    2006    2007    2008     2009    2010
MWh sold      1,184   250   534    42     8,780 12,174 19,568 30,329 22,891 35,408 46,945 29,830
The thermal efficiency of the five boilers functioning on a system-wide basis exceeds the 42.5% criteria, with an average value for the time period of 2005 through 2009 of approximately 48%. Based on the proposed revised definition of a cogeneration unit, and the fact that the Green Bay Broadway Operations' system-wide thermal efficiency exceeds the 42.5% thermal efficiency criteria, Boiler B25 should be designated by EPA as a cogeneration unit. Furthermore, since the Green Bay Broadway Operations' turbine generator system has not sold more than 219,000 MWh of electricity to the 'Grid' in any calendar year, the system should be exempted from the CArR Rule and the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3967[1].1, p.4]
International Paper
The NODA directs us to the associated tables where the potentially applicable units are listed. International Paper's Augusta Mill units are on that list. Based on the applicability of the proposed rule, the International Paper sources RB2A and RB3A should not be on the list. [EPA-HQ-OAR-2009-0491-4006[1].1, p.1]
The units show up on the table for both alternative allocation methodologies. Regardless on which methodology is used, the International Paper units should be removed from the list prior to final publication of the rule. Please see attached previous comments provided on the Transport Rule that discusses the status of those units compared to the rule applicability. [EPA-HQ-OAR-2009-0491-4006[1].1, p.1]
I spoke with Mr. Brian Fisher of EPA's Clean Air Markets Division. He indicated that the list of sources on the database was intended to be a comprehensive listing of all potential units compiled from various lists available to EPA from various other programs, and just because a unit is on the list does not necessarily make the unit applicable to the Transport Rule. With our submission of these comments, we ask EPA to make sure that the nonapplicable Augusta Mill units are removed from the database of units. [EPA-HQ-OAR-2009-0491-4006[1].1, p.1]
International Paper was alerted to the fact that its units were listed on Transport Rule Allocation tables associated with the proposed Transport rule. International Paper operates its Augusta Mill under Part 70 PermiI2631-245-()()()6..V-02-0; Facility AIRS Number 04-13·245-00006. [EPA-HQ-OAR-2009-0491-4006[1].1, p.2]
Specifically, International Paper-Augusta Mill's Kraft pulping liquor recovery furnaces, RB2A NO.2 Recovery Boiler and RB3A NO.3 Recovery Boiler, were listed as affected units (ORIS 54358) in Georgia. These units, prior to EPA revising the cogeneration definition on October 19, 2007 72FR59,190, where affected facilities under the CAIR rule. However, based on EPA's current definition RB2A and RB3A are cogeneration units and not subject to CAIR or the Transport rule. [EPA-HQ-OAR-2009-0491-4006[1].1, p.2]
Augusta Mill's Recovery Boilers meet the definition of cogeneration units with useful power efficiencies consistently in the 100% to 10,000 % range for the RB2 and RB3. The high power efficiencies are a result of the boilers primarily being biomass burners. [EPA-HQ-OAR-2009-0491-4006[1].1, p.2]
Recovery Boilers at Augusta are not subject to the various sections of the Transport Rule as outlined in the proposed applicability sections (§§ 97.404 and 97.405,97.504 and 97.505, 97.604 and 97.605, and 97.704 and 97.705-Applicability). Specifically, these units are not applicable unit because they qualify as exempt cogeneration units as outlined in, for example, 97.404(b)(1 )(i). [EPA-HQ-OAR-2009-0491-4006[1].1, p.2]
Madison Gas and Electric Company (MGE)
West Campus Cogeneration Facility (WCCF) units listed as U1 and U2 with ORIS  7991 are included in the Allocation Table and should be removed because WCCF meets the exemption for cogeneration facilities.  WCCF is not currently subject to the CAIR and will continue to meet the criteria for exemption from the Transport Rule. [EPA-HQ-OAR-2009-0491-3924[1].1, p.1]
Response:
These units have been removed from the final Transport Rule list of potentially covered existing units and do not receive allocations.  Several of these units have (West Campus Cogen and Broadway Mil)l had applicability determinations under CAIR that suggest they are not subject to the Transport Rule.  EPA has removed several others based on information received from the commenter that suggests, given the best data currently available to EPA, that they would not be subject to the final Transport Rule.  However, EPA notes that the units presented in this list of potential existing Transport Rule units reflects only a preliminary assessment of the applicability of the proposed Transport Rule and in no way suggests that EPA has made a determination about the applicability of the proposed Transport Rule to any specific unit.
Organization: Great River Energy
Rochester Public Utilities (RPU)
Comment:
Great River Energy
  Great River Energy notes that SEVERAL OF OUR UNITS WERE NOT INCLUDED in the NODA tables and should appropriately be added as applicable units. [EPA-HQ-OAR-2009-0491-3898[1].1, p.1]
Surprisingly, the January 7, 2011 NODA did not even include these emissions units. As a result, no emissions were attributed to these units, thus providing no basis for allowance allocation. Table 1 provides another update of our emission units, specifying those units incorrectly omitted from the NODA tables. Table 1 includes the omitted units and provides associated heat input and emissions information. Again, these are considered to be existing facilities and qualify for allowance allocation under the current proposed rule applicability requirements. [EPA-HQ-OAR-2009-0491-3898[1].1, p.2] [[See Docket Number EPA-HQ-OAR-2009-0491-3898[1].1, p.3 for Table 1.]]
Rochester Public Utilities (RPU)
One unit previously listed on the allocation tables for the Transport Rule is missing from the current tables, Cascade Creek CT1, ORIS code 6058, CAMD Unit ID 90209. This unit should qualify as an existing Transport Rule unit. This unit was subject to and reported under CAIR in 2008 and 2009 until the courts stayed the effectiveness of CAIR in Minnesota. This unit operates a single generator, Cascade Creek CAMR Generator ID 1, has a nameplate capacity of 38 MW and operated during each of the years from 2005-2009. Unless EPA has reason to believe otherwise, this unit should be added to the list of Transport Rule units and allocated allowances. The applicable information on the unit is as follows: [EPA-HQ-OAR-2009-0491-3998[1].1, p.2]
[Table can be found on page 2 of this comment.]
Response:
EPA is including these facilities, per commenters suggestion, in the final list of potential existing Transport Rule units that receive allowance allocations.
Organization: Illinois Environmental Protection Agency
Comment:
Illinois Environmental Protection Agency
The Illinois EPA recommends that the existing-unit cut-off date should be January 1, 2010 rather than January 1, 2009, as proposed. The effect of this change would be to include City Water, Light, and Power's Dallman Unit 4 (ORIS plant code 963, CAMD Unit ID 4, and in NEEDS v4.10 referred to in error as Unit ID 34) as an existing unit. Dallman Unit 4 commenced commercial operation on May 11, 2009, and is the cleanest and most efficient unit operating at City Water, Light, and Power. [EPA-HQ-OAR-2009-0491-3899[1].1, p.1]
Response:
EPA agrees that the existing unit cut-off date should be changed to January 1, 2010.  The Rule has been finalized to reflect this change and the allocation tables have been updated accordingly.  EPA was able to make this change due between the January 7, 2011 NODA and the Rule's finalization because the 2010 data was reported and verified during that time period.  Having the complete 2010 data, allowed EPA to use January 1, 2010 as a cut-off date for existing units because the 2010 data afforded at least one full year of historic data on which to base a unit's allocation.  See Section VII.D of the Preamble for further discussion.
Organization: Mississippi Department of Environmental Quality
Florida Department of Environmental Protection
Covanta Energy Corporation
Dominion
Comment:
Covanta Energy Corporation
Our comment concerns the mistaken inclusion of two of Covanta's MWC facilities in the unit inventories.  The allocation tables and underlying data include 3 units at the "SEMASS Resource Recovery Facility" in Massachusetts and one unit at the "American Ref-Fuel of Essex" in New Jersey.  The SEMASS facility is an energy-from-waste facility comprised of three MWCs.  It generates about 80 MW of electricity from the combustion of about 3,000 tons per day of MSW.  The Essex facility is also an energy-from-waste facility comprised of three MWCs and generates approximately 70 MW of electricity from the combustion of about 2,800 tons per day of MSW.  [EPA-HQ-OAR-2009-0491-3908[1].1, p.1]
The proposed transport rule includes a "solid waste incineration exemption" for such units as defined in Section 129(g)(1) of the Clean Air Act.  The SEMASS and Essex units referenced in the Allocation Tables meet this definition.  Sections 97.404(b)(2)(i) and (ii), 97.504(b)(2)(i) and (ii), 97.603(b)(2)(i) and (ii), and 97.704(b)(2)(i) and (ii) of the proposed rule provide the exemption for these units that have an average annual fuel consumption of fossil fuel of less 20 percent.  The MWCs at SEMASS and Essex are designed for the combustion of MSW and as such utilize fossil fuel only for start up and occasional stabilization. The percentage of fossil fuel used on a heat input basis is typically only 1 or 2 percent.  [EPA-HQ-OAR-2009-0491-3908[1].1, p.1]
The categorization of SEMASS and Essex as a Transport Rule unit appears to have been an inadvertent error. No other MWCs in the states of Massachusetts or New Jersey with a generating capacity greater than 25 MW are included.   [EPA-HQ-OAR-2009-0491-3908[1].1, p.2]
Dominion
Additional Issues
Inclusion of Biomass Units
Our review of the list of potential existing Transport Rule sources in the NODA indicates that units burning exclusively biomass, such as Dominion's Pittsylvania facility in Virginia, have now been included as affected sources. We believe this may not have been intentional and is an artifact of the use of a number of different and additional data sets that have been used in this NODA to identify potential units that would be subject to CATR. [EPA-HQ-OAR-2009-0491-3987[1].1, p.6]
The Pittsylvania facility bums wood and the units do not meet the definition of a fossil-fuel-fired unit in the proposed rule. Units that bum biomass were not subject to the NOx SIP Call or to the Clean Air Interstate Rule (CAIR). Accordingly, we request that EPA remove the Pittsylvania facility from its list of units potentially subject to the Transport Rule. In doing so, however, the Virginia SO2 and NOx state budgets should not be reduced since emissions from the Pittsylvania facility were not included in the initial determination of those budgets. [EPA-HQ-OAR-2009-0491-3987[1].1, p.6]
Should EPA decide to now include biomass units as affected units under the Transport Rule, the state budgets must be recalculated (and increased) to account for the emissions from these units. In addition, to the extent EPA were to now consider including biomass units, it should issue a supplemental notice and seek comment on this matter. [EPA-HQ-OAR-2009-0491-3987[1].1, p.7]
Florida Department of Environmental Protection
  We have several units in the state that are currently not operating or retired, but operated within the period 2005-2009. These units are left out of the proposed allocations for either option 1 or 2. Should allocations be made to these units? In accordance with the non-operating provisions of the proposed rule, a unit whose first non-operation year is 2007 or later would qualify for allocations. It should be noted that most of these units operated so little that they would receive very few allowances. See attached spreadsheet.   [EPA-HQ-OAR-2009-0491-3879[1].1, p.1] [[See Docket Number EPA-HQ-OAR-2009-0491-3879[2].2 for the spreadsheet.]]
 Several units in the state did not operate during the 2005-2009 period, but retain valid permits and may operate at any time. These units are not included on the allocation list. Since the list contains other units with zero allocations, we assume the list is supposed to represent all units subject to the program. If these units otherwise meet the applicability requirements, and retain valid permits, should they be included on the allowance list? See attached spreadsheet.   [EPA-HQ-OAR-2009-0491-3879[1].1, p.2] [[See Docket Number EPA-HQ-OAR-2009-0491-3879[2].2 for the spreadsheet.]]
It appears that a unit in the allocation list, Reedy Creek (ORIS code 7254, unit ID 32432), is the same unit as Central Energy Plant (ORIS code 7294, unit ID CTG). We have no record of the latter unit in the state database. Both were allocated allowances, but not the same amounts.  [EPA-HQ-OAR-2009-0491-3879[1].1, p.2]
Two units listed on the allocation tables (Ridge Generating Station, ORIS code 54529 and Okeelanta Cogeneration, ORIS code 54627) were each determined by their owners to not be subject to the CAIR program. The Ridge Generating Station was not allocated allowances, but Okeelanta was. Unless EPA has reason to believe otherwise, these sources should not be listed on the allocation table.   [EPA-HQ-OAR-2009-0491-3879[1].1, p.2]
Mississippi Department of Environmental Quality
The NODA request comment on any units listed in the allocation tables that should not be included. For Mississippi, one of the listed units, Leaf River Cellulose LLC (Oris ID 10233), should not be included. This unit is a Power Boiler at a pulp mill that only uses fossil fuel for start-up and otherwise uses wood-waste and should be exempted. [EPA-HQ-OAR-2009-0491-3917[1].1, p.1]
Response:
As suggested by commenter, these units have been removed from the final Transport Rule list of potential existing TR units.  EPA has removed these units based on information received from the commenter that suggests, given the best data currently available to EPA, that they would not be subject to the final Transport Rule.  However, EPA notes that the units presented in this list of potential existing Transport Rule units reflect only a preliminary assessment of the applicability of the proposed Transport Rule and in no way suggest that EPA has made a determination about the applicability of the proposed Transport Rule to any specific unit. Additionally, the SEMASS unit was removed from the list regardless of any comment received as it is located in the state of Massachusetts which is not subject to the final Transport Rule.
Organization: NextEra Energy, Inc.
Comment:
NextEra Energy, Inc.
For purposes of the NODA, EPA indicates that a potential existing unit is assumed to be a unit that would potentially meet the proposed applicability criteria (i.e., the criteria in proposed §§ 97.404,97.504, 97.604, and 97.704 in the proposed Transport Rule) for covered units and that commenced commercial operation prior to January 1, 2009. According to EPA, this cutoff date was chosen for existing units because it assured that at least 1 full year of historic data would be available to determine each existing unit's allocation. NextEra Energy recommends that the cutoff date for existing units be revised to January 1, 2010, or possibly even January 1, 2011, since data for 2009 and 2010 are now available to the Agency. This will allow emissions from clean and efficient units that commenced operation in 2009 or 2010 to be covered under the Transport Rule S02 and NOx caps and not have to rely on allowances from the new unit set-aside to cover their emissions. [EPA-HQ-OAR-2009-0491-3962[1].1, p.5]
Response:
EPA agrees that the existing unit cut-off date should be changed to January 1, 2010.  The Rule has been finalized to reflect this change and the allocation tables have been updated accordingly.  EPA was able to make this change due between the January 7, 2011 NODA and the Rule's finalization because the 2010 data was reported and verified during that time period.  Having the complete 2010 data, allowed EPA to use January 1, 2010 as a cut-off date for existing units because the 2010 data afforded at least one full year of historic data on which to base a unit's allocation.  See Section VII.D of the Preamble for further discussion.
Organization: Northshore Mining Company
Comment:
Northshore Units 1 and 2 should be removed from EPA's list of potential existing units for the CATR.
Northshore has two existing cogeneration units at its Silver Bay, Minnesota facility (Northshore Units 1 and 2) that provide process steam and electricity for Northshore's taconite production facility in Northeastern Minnesota.  These units are among a small group of industrial boilers that are subject to the CATR because they have produced small amounts of electricity for sale to the grid.  These units have been exempt from the Acid Rain program as cogeneration units but do not appear to meet the new cogeneration exemption criteria in the CATR due to the addition of an efficiency standard that these older units cannot meet.  EPA expressly requests comment in NODA III on units that owners believe should not be included on the list of potential existing units subject to the CATR (76 Fed. Reg. at 1113).  For the reasons set forth below and in the Cliffs Natural Resources Northshore Mining Comment Letter dated October 1, 2010 submitted in response to the proposed CATR, Northshore believes that its two cogeneration units should not be on this list and that they should be excluded from CATR like other legitimate cogeneration units.  [EPA-HQ-OAR-2009-0491-3957[1].1, p.2]
EPA has long distinguished between industrial cogeneration units and utility units when applying regulations under the Clean Air Act.   The Northshore units have qualified as cogeneration units under all previous Clean Air Act programs, including those targeting new sources (see e.g., 40 CFR 60.41a), hazardous air pollutants (see 40 CFR 63.41) and acid rain reductions (see 40 CFR 72.2).  EPA has consistently drawn a distinction between "electric utility steam generating units and industrial boilers because there are significant differences between the economic structure of utilities and the industrial sector."  See e.g., 44 Fed. Reg. 33580, 33589 (June 11, 1979).  Whereas a utility may pass on the costs of a rule such as the CATR to its retail electricity customers, an industrial facility like Northshore, which sells a wholesale product in a globally-competitive market, may not.  The amount of electricity generated for sale by Northshore and other industrial cogeneration units is relatively small and often produced inconsistently because the primary driver for operation is the industrial process, and electricity is a secondary product generated from excess steam to improve the energy efficiency of the system.  [EPA-HQ-OAR-2009-0491-3957[1].1 p.2]
EPA has recognized the environmental benefits that arise from adding cogeneration to an industrial steam system. Generating electricity from excess steam can significantly improve energy efficiency and provide a corresponding reduction in emissions from the reduced demand for electricity from off-site sources.  EPA appropriately seeks ways to encourage the development and operation of cogeneration systems and to avoid disincentives.  In the CATR, like its predecessor Acid Rain program, EPA appropriately exempts most industrial cogeneration units.  This exemption removes a disincentive to cogeneration that may otherwise exist if an industrial boiler operator had to comply with an entirely new and burdensome regulatory program like CATR just because it generates more electricity than it may need on a given day and sells that electricity to the grid.  Northshore supports the cogeneration exemption in the CATR, but we ask that EPA broaden the exemption to excuse from the CATR all legitimate cogeneration systems. [EPA-HQ-OAR-2009-0491-3957[1].1, p.2]
EPA recently narrowed the cogeneration exemption to remove a potential loophole.  In drafting the Clean Air Interstate Rule (CAIR), EPA added a requirement not found in the Acid Rain program that requires cogeneration units to meet specified efficiency standards to qualify for the cogeneration exemption.  As EPA explained,
The purpose of this efficiency standard in the cogeneration unit definition is to prevent a potential loophole where a unit might send only a nominal or insignificant amount of thermal energy to a process and not achieve significant efficiency gains through cogeneration, but still qualify as a cogeneration unit and potentially qualify for the cogeneration unit exemption.  [EPA-HQ-OAR-2009-0491-3957[1].1, pp.2-3]
Final Rule Revising the Definition of Cogeneration, 72 Fed. Reg. 59190, 59194 (October 19, 2007).  This same efficiency standard was also incorporated into the CATR to ensure that the cogeneration exemption only excludes legitimate cogeneration systems from the CATR.    [EPA-HQ-OAR-2009-0491-3957[1].1, p.3]