PPG's RS Cogen for example, has SO2 allocations based on an assumed 2012 heat input for RS-6 of 13,329,878 mmBtu.21 This is a reasonable value based on past and projected future operations as can be seen from the certified data reported to EPA under the Acid Rain and CAIR programs. However, the same unit (RS-5) has an assumed heat input for NOx annual allocations of only 214,246 mmBtu and an ozone season assumption of only 21,425 mmBtu. Thus, the assumed heat input for NOx is only 1.6% of the actual adjusted reported value used for SO2. The same is true for the IPM projected heat input values for the RS5 unit. These values are not reasonable and since they were the product of the IPM model, PPG has grave questions about the accuracy of the model to predict heat input in future years. PPG does not understand the basis for the modeled prediction. It appears that the ozone season allocation heat input basis is exactly 10% of the annual NOx heat input basis (which as noted is already woefully short of an accurate prediction). This also does not make sense to PPG. PPG's units operate year around on the same basic operational schedule and therefore the ozone season heat input should be based on a realistic percentage based on May-September operation. EPA has the data in its quarterly CAMD reports to have seen that these units operate year round. Although the difference between reported and projected values improves very slightly under the IPM v.4.10, the same fundamental problem exists there as well. The annual and ozone season heat input and corresponding NOx emissions are only a tiny fraction of the RS Cogen's actual heat input and emission levels. [EPA-HQ-OAR-2009-0491-2763.1, p. 13]
In addition, PPG believes EPA made an error in providing allocations to the RS Cogen RS4 unit. RS Cogen unit RS-4 is a steam turbine. As such, it is an unfired unit and does not have its own emissions. The allocation table has an assumed heat input for 2012 SO2 for RS-4 of 6,445,585 mmBtu. PPG RS Cogen unit RS-5 is included as well and the allocation table also shows an assumed 2012 heat rate of 6,445,585 mmBtu. RS-5 is an identical unit to RS-6 and generally operated in tandem with RS-6 and therefore allocations should be based in similar heat inputs. It appears that EPA incorrectly included RS-4 (steam turbine) and arbitrarily gave it an assumed heat input of one-half the heat input of RS-5. The allocations should be for RS-5 and RS-6 as they are the fossil-fuel fired units with emissions. Although electricity is made from RS-4, it is not a fired unit. PPG recognizes that EPA has proposed to include the steam turbine in a combined cycle system within the definition of 'combustion turbine'. However, that does not alter the fact that the steam turbine is not a fired unit and does not generate emissions. [EPA-HQ-OAR-2009-0491-2763.1, p. 13]
PPG requests EPA abandon use of the IPM model for projecting electric utility operation in Louisiana for purposes of allocating unit-level allowances under CATR for cogeneration units as well as other EGUs. There are several fundamental issues with EPA's use of the IPM for this purpose. One of the foremost reasons is the lack of transparency concerning how the IPM accounts for economic and fuel cost factors in determining how much a unit will be utilized in future years. As clearly shown above, the output of the IPM does not come close to matching actual utilization for PPG's RS Cogen cogeneration facilities. The year 2012 is less than one and one-half years away and therefore is well within PPG's reasonable ability to project operations. The assumed heat inputs associated with NOx allocations for 2012 are not consistent with PPG projections. PPG utilizes a significant portion of the power generated by RS-5 and RS-6 for chemical manufacturing operations and is under long-term contract obligations to produce power for transfer to the power grid. [EPA-HQ-OAR-2009-0491-2763.1, pp. 13-14]
PPG recommends that EPA utilize the methodology for NOx allocations utilizing previously reported operations exactly like used for SO2. In the event EPA chooses to continue using projected emission for NOx allocations, PPG requests EPA modify the model to accurately project emissions from cogeneration facilities co-located with production facilities dependent upon cogeneration power. [EPA-HQ-OAR-2009-0491-2763.1, p. 14]
Currently RS-Cogen units RS-5 and RS-6 are subject to CAIR and would be the only units at the PPG Lake Charles site subject to CATR. The following table lists the 2012 NOx annual and ozone season allocations under CAIR via the EPA approved Louisiana SIP, the allocations proposed by EPA under CATR and the differences. [EPA-HQ-OAR-2009-0491-2763.1, p. 14; see p. 14 for the table.]
Note: PPG also notes that the heat rate information used by EPA for the RS5 and RS 6 units from the NEEDs data varies from the value reported by RS Cogen on its Annual Electric Generator Report Form EIA-860 to the US Department of Energy, Energy Information Administration. EPA stated that the NEEDs data was based on the EIA data, but for the RS Cogen units, this was not the case, or EPA made an error in transcription from the EIA-860 reports. PPG requests that EPA use the correct EIA data. [EPA-HQ-OAR-2009-0491-2763.1, p. 15]
On September 1, 2010, EPA published the NODA indicating that EPA intends to use the IPM version 4.10 modeling, including a revised TR Base Case 2012 scenario, for revising the determinations of significant impact and interference with maintenance. Under the revised IPM TR v. 4.10 Base Case, projected emissions of SO2 from Louisiana EGUs are more than 20,000 tpy less than was projected under the IPM v. 3.02 version. (See Table below.) Based on this factor alone, because EPA'S own data showed sulfate to be the culprit, it is believed that any revised air quality analysis based on the IPM v. 4.10 will demonstrate no impact whatsoever on Harris Co. PM2.5 levels. The same is true with respect to reductions of annual and ozone season NOx, EPA's revised IPM v. 4.10 Base Case 2012 model results show significant reductions in projected SO2 and NOx emissions that will occur even without implementation of the CATR/FIP (or CAIR). If these values are used in revised air quality modeling, it is virtually certain-that the conclusion will be that Louisiana emissions do not impact the annual PM2.5 or 1997 8-hour ozone standards in Texas.8 [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.3]
Even without a revised air quality analysis, however, PPG believes that use of the TR Base Case v. 4.10 data supports the conclusion that Louisiana should not be included in the CATR/FIP. The original CATR/FIP determined that a certain level of emission reductions from EGUs would remove 'significant contribution' and 'interference with maintenance.' The revised IPM v. 4.10 Base Case shows that emission reductions greater than that level will occur by 2012, even without CATR. The following table demonstrates this conclusion: [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.3; see p.4 of this comment summary for a table entitled, Comparison of TR Base Case v. 3.02 to TR Base Case v. 4.10 for Louisiana EGUs] 9
Even without air quality modeling, these results demonstrate on their face that because the quantity of SO2 and NOx emissions that were required to be removed to prevent 'significant contribution' 'interference with maintenance' are now projected to be removed by 2012 through factors other than the CATR/FIP, there is no legal basis for a CATR/FIP for annual SO2 or annual or ozone season NOx control for Louisiana EGUs. [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.4]
If Louisiana is still included under the CATR/FIP after revised modeling and air quality analysis, PPG requests that EPA not use the IPM v. 4.10 (or any other version of the IPM) to make unit level allocations under the CATR/FIP. EPA should make SO2 and NOx allocations proportionate to the of each unit's existing SO2 and NOx allocations to the state CAIR budgets already approved by both EPA and LDEQ. Although the court in North Carolina v. EPA struck down CAIR and required a revised look at the actual state budget needed to eliminate significant contribution or interference with maintenance, the court did not find any problem with the Louisiana (or other state's) unit level allocations. Louisiana DEQ, together with the Louisiana Public Service Commission, worked very hard on a fair allocation scheme for NOx allowances. This scheme was enacted into rule by the State after public notice and comment and was approved by EPA. [EPA-HQ-OAR-2009-0491-3735.1_NODA, pp.4-5]
On September 27, 2006, the Louisiana Department of Environmental Quality (LDEQ) submitted a SIP revision to EPA adopting the CAIR SO2 Trading Program to address its 'good neighbor' obligations under CAA Section 110(a)(2)(D) with respect to the potential impact of Louisiana emissions on downwind PM2.5 receptors in the State of Alabama. EPA approved this SIP revision on July 20, 2007 at 72 Fed.Reg. 39741.11 On July 12, 2007, LDEQ submitted a SIP revision to EPA adopting a SIP - for a CAIR NOx Trading Program to address both the 1997 8-hour ozone standard and the 1997 annual PM2.5 standard. EPA approved this SIP revision on September 28, 2007 at 72 Fed. Reg. 55064. LDEQ submitted amendments to its NOx CAIR SIP on July 1, 2009, which are pending before EPA for decision. EPA should base its allocation system as closely on these prior approved Louisiana CAIR provisions as is possible. [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.5]
EPA lacks a credible rationale for premising its NOx and SO2 allocations on the IPM v. 4.10. Although the allocations are slightly more generous than were the allocations under version 3.02, they are woefully inadequate to allow PPG to normally operate the RS Cogen units without incurring enormous costs. PPG incorporates by reference its comments on the improper use of the IPM model for NOx allocations made in PPG's original comments. [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.5]
The IPM is an economic model that fails to account for realistic operations at many Louisiana facilities, in particular, cogeneration units serving industrial sources. The unit level allocation scheme based on the IPM (as distinguished from the state budget) has nothing to do with preventing significant contribution or interference with maintenance. In fact, huge economic inequities are being created with no underlying environmental reason. The following table shows a comparison of the allocations that PPG would likely receive under IPM v. 4.10 version as well as actual reported emissions to CAMD for 2005-2010. [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.5; see p. 6 of this comment summary for a table showing a comparison of the allocations that PPG would likely receive under IPM v. 410 version as well as actual reported emissions to CAMD for 2005-2010]
As indicated in its original comments, the PPG RS Cogen units are must run units for the PPG manufacturing facility. The assumptions made in the IPM are obviously grossly in error with respect to the utilization of these units. It would be arbitrary and capricious for EPA to base its allocations on the IPM- either v. 3.02 or v. 4.10 given these facts. [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.6]
EPA's approach for projected emissions inventories, as well as considerations of control technology under the IPM v. 4.10, eliminated the consideration of any reductions required by CAIR, due - to the fact that the CAIR rule was overturned in North Carolina v. EPA, 531 F.3d 896, 901 (D.C. Cir. 2008). However, this results in overly conservative projections. The CAIR rule was remanded, but not vacated. Many regulated public utilities already invested in capital projects for reduction that were approved by their regulatory bodies and/or ratepayers. In most cases, legal obstacles would prevent the undoing of these projects. In addition, each physical project undertaken for purposes of CAIR reductions was of necessity permitted under an enforceable Title V permit. Those projects and permit limits cannot be relaxed without the facilities triggering Prevention of Significant Deterioration (PSD) rules. Triggering PSD would involve imposition of Best Available Control Technology, which, in most cases, would mean that the facilities would have to keep the pollution control equipment they installed for CAIR, or would have to meet even more stringent requirements. EPA should have undertaken a much more rigorous analysis for projecting what steps EGUs would take if CAIR were vacated completely, with no replacement. EPA has tools to easily accomplish this, such as a Clean Air Act Section 114 request for information. In short, EPA overestimated Base Case emissions for both 2012 and 2014 by eliminating all CAIR control requirements. [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.6]
The documentation for the IPM v. 4.10 does not clearly indicate whether EPA included only the grid-demand for electricity or also industrial facility demand. Section 3.2 of the Documentation for the EPA's IPM v. 4.10 Base Case tends to indicate that EPA considered only the grid-demand. This have discounted the total electrical demand in Louisiana as many industries have cogeneration units. Some of these units provide power to the grid, as does PPG. However, if EPA did not appropriately account for the fact that industries that partially self-generate need continuous and reliable electrical and steam output, then the IPM may make deficient economic choices in its selection of EGU behavior. [EPA-HQ-OAR-2009-0491-3735.1_NODA, pp.6-7]
The Documentation for the IPM v. 4.10 Base Case, Chapter 3.5.1 indicates that EPA made certain assumptions about EGU availability in its modeling. EPA stated 'Power plant availability is the percentage of time that a generating unit is available to produce electricity to the grid. Availability takes into account both scheduled maintenance and forced outages...' EPA indicated that Appendix 3-9 shows the availability assumptions for all EGUs in EPA Base Case 4.10. In Appendix 3.9, EPA indicated that the 'availability' for the RS Cogen units was as follows: [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.7; see p. 7 of this comment summary for a table containing EPA's indicated availability for the RS Cogen units]
PPG disputes these assumptions. PPG must operate the RS Cogen units year round in order to provide adequate electricity and steam to the PPG manufacturing complex. Actual data submitted to EPA CAMD reflects PPG's actual utilization of these RS Cogen units. Further, the annual on-stream time for each of these units in the past several years is as follows: [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.7]
2008:
R4 - 99.8 %
R5 - 95.4%
R6 - 89.0% [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.7]
2009:
R4 - 99.3%
R5- 94.6%
R6 - 88.0% [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.7]
2010 (thru Sept)
R4 - 77.0%
R5 - 94.4%
R6 - 96.5% [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.7]
PPG requests that EPA revise these values to adequately reflect actual availability and utilization of these units. [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.7]
In Section 3.9.2 of the Documentation for the IPM v. 4.10 Base Case (pages 3-18 through 3-20), EPA indicates that it used four different NOx rates in NEEDS 4,10 'to allow all possible modeling scenarios involving NOx controls to be set up.' The 4 modes of operation were set forth in the NEEDs 4.10. PPG believes that EPA erred in its assignment of NOx rates to the RS Cogen units under these 4 modes. [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.8; see p.9 of this comment summary for a table containing information about RS Cogen 5, 6 and 4]
PPG has consistently reported to CAMD that its RS Cogen units each meet a NOx emission rate of 0.5 to 0.6 lbs/mmBtu, throughout the year, for units 5 and 6. These units are equipped with low NOx burners and SCR. {Unit 4 does not emit, so it is not clear why EPA has included it in the NEEDS data base as having emissions.} There is no reason that the Mode 2 and Mode 4 rates should be 0.0122 lbs/MmBtu. The units are not capable of achieving those levels and have never been required to achieve those levels. No other Louisiana natural gas fired combined Cycle cogeneration units had such a disparity between Modes. The basis for this is unstated and appears to be in error. [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.8]
The documentation for the IPM v. 4.10 indicates that EPA continued an error that was also made in the IPM v. 3.02 Base Case with respect to existing environmental regulations. In Section 3.9.4 of the Documentation of EPA's IPM v. 4.10 Base Case, EPA listed the state rules that it included in the model. As indicated in PPG's original comments, EPA improperly considered the Louisiana NOx Reasonably Available Control Technology rule in LAC 33:III.Ch. 22 reductions of NOx in the modeling used to project future impact. In Appendix 3-2.2, EPA had the following entry for Louisiana: [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.8; see p. 9 of this comment summary for a table showing EPA's entry for Louisiana in Appendix 3-2.2]
The cited rule does apply to NOX, but the information in the 'Emission Specifications' column is totally erroneous. The NOx emission limits are much lower than this, but different limits apply to different types of units. Further there are different limits for different parishes. PPG requests that EPA update the model by using the actual limits of the rule, as set forth at LAC 33:III.Chapter 22, available at: http ://www.deq.louisiana.gov/portal/DIVISIONS/LegalAffairs/RulesandRegulations/Title33.aspx [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.8]

8 If EPA conducts revised air quality modeling, PPG urges EPA to also make the revisions to the Louisiana emissions inventory discussed in PPG's original comments.
9 Data obtained from 75 Fed. Reg. at 45,210, 45,291, Tables.IV-E-1 and IV-E-2 (Aug. 2, 2010). This is the value PPG believes that EPA used in the modeling to determine significant contribution or interference with. maintenance. See Environmental Protection Agency, Technical Support Document for the Transport Rule, Air Quality Modeling (2010), http://www.epa.gov/airquality_/transport/pdfs/TR__AQModeling_TSD.pdf. It is possible that EPA used the Transport Rule Base Case v. 3.02 value for SO2 rather than the lower SO2 state budget, which was based on adjusted, reported data; however, PPG took the conservative approach of determining that EPA used the lower value. For NOx, EPA used the Transport Rule Base Case v. 3.02 projection as the budget.
Louisiana Department of Environmental Quality, Louisiana SIP Revisions, http://www.deq.louisiana.gov/portal/Default.aspx?tabid=2381.
PPL Corporation
Errors in Data Files used to Develop the Transport Rule Budgets.
PPL is providing corrections to data characterizing PPL's units that are in the NEEDS 4.10.xls data file located on EPA's established website for the rule (www.epa.gov/airtransport). These corrections are provided in a table at the end of these comments. [[EPA-HQ-OAR-2009-0491-2739.1, p.7] [See page 11 of this comment for the table.]]
As described in the attachment, PPL is particularly concerned about very low sulfur dioxide emission rates (0.06 lb/MmBtu) that appear to be assigned to our Pennsylvania coal-fired units in some of the NEEDS version 4.10 data bases that we have reviewed. The emission rates appear to be much lower than those for any other similar size coal-fired units that have or are projected to install flue gas desulfurization systems and are much lower than the emission rates to which these units presently operate.  [EPA-HQ-OAR-2009-0491-3766.1_NODA, p.1]
1. Montour Units 1 &2 NOx Emission Rates.
Montour Units 1&2 are coal-fired units equipped with selective catalytic reduction (SCR) to reduce NOx emissions. The 'Controlled NOx Base Rate' and 'Controlled NOx Policy Rate' emission rates shown in the NEEDSv410.xls data file available on the proposed Transport Rule website (www.epa.gov/airtransport) appear incorrect. The emission rates shown are just under 0.056 lb/MmBtu. [EPA-HQ-OAR-2009-0491-3766.1_NODA, p.2]
The following table shows annual and ozone season heat input and NOx emissions data from the BADetailedData.xls file available on the Transport Rule website. The data are for the most recent four quarters (4th quarter 2008 and 1st, 2nd, 3rd quarters 2009) and most recent ozone season (2009) presented in the ''''reported data' sheet of the file. The corresponding emission rates (lb/MmBtu) were calculated by PPL based on those data and are also shown in the following table. [EPA-HQ-OAR-2009-0491-3766.1_NODA, p.2][[See Docket Number EPA-HQ-OAR-2009-0491-3766.1_NODA, p.3 for the table.]]
As shown in the table, the ozone season emission rates are lower than the annual rates because the SCR systems operated during part of the four quarters (including the ozone season) but not during the entire four quarters during those specific four quarters. [EPA-HQ-OAR-2009-0491-3766.1_NODA, p.3]
The emission rates presented in the NEEDS version 4.10 data base (NEEDSv41O.xls) and calculated from data in the ''TR SB Limited Trading v4.10' and 'TR SB Limited Trading AEO Gas v4,10' parsed files (and maybe others) are considerably lower than the actual emission rates during either the annual or ozone base periods as shown in the above table. PPL is not sure of the basis of these low rates and is concerned that they are being used to represent emission rates under present operations in the NEEDS database. In fact, during that base period ozone season, monthly average NOx emission rates for only one of those units and for only one of the five ozone season months were operated at an emission rate at that low level (actually, 0.057 lb/MmBtu). [EPA-HQ-OAR-2009-0491-3766.1_NODA, p.3]
PPL understands that the floor for NOx emission rates under the Transport Rule allocation scheme as presented in technical support document 'State Budgets, Unit Allocations, and Unit Emission Rates,' is 0.06 lb/MmBtu. Additionally, data for these units do not indicate that they have been operating consistently at or below 0.06 lb/MmBtu. Therefore, NOx emission rates of 0.0561 lb/MmBtu are not appropriate. PPL requests that the base year ozone season emission rates presented in the above table (0.087 and 0.1121 lb/MmBtu for Units 1&2 respectively) be used as representing present operation in the NEEDS data base, not an emission rate of 0.056 lb/MmBtu. [EPA-HQ-OAR-2009-0491-3766.1_NODA, p.3]
2. Status of SO2 Flue Gas Desulfurization (FGD) Systems at the Montour and Brunner Island Plants.
PPL wants to clarify that Montour Units 1&2 and Brunner Island Units 1,2&3 presently operate with PGD systems to reduce SO2 emissions. As correctly presented in the NEEDSv410.xls data file, the Montour FGD systems began operating in 2008 and the Brunner Island systems in 2009. The permitted SO2 emission rates for these units is 0.85 lb/MmBtu. The NEEDSv41O.xls data file incorrectly lists the permitted rates as 3.7 lb/mmBtu for the Brunner Island Units and Montour Unit 1. [EPA-HQ-OAR-2009-0491-3766.1_NODA, pp.3-4]
The NEEDSv41O.xls file reports that the units have FGD systems under both the 'Wet/Dry Scrubbers' column and also under the 'Dispatchable Scrubbers' column. PPL is not sure if EPA intends both columns to be used. There is no column for the scrubber control efficiency in this NEEDSv410.xls file, but PPL notes that an unrealistic control efficiency of 97% is presented in an earlier NEEDS file (NEEDSv3[I].02_EISA.xls) in the 'Dispatchable Scrubber Efficiency' column. That percentage provides no cushion for any pumps to be out on maintenance or for any degradation in the equipment. This is not a condition that can be achieved on a continuous basis into the future even with the most aggressive maintenance. In fact, PPL is not even sure that its scrubbers can achieve a 95% control efficiency as even this level would require all pumps to be running and there is no room to add any spare pumps to operate if maintenance is being performed on a pump. Therefore, a control efficiency of less than 95% should be used. [EPA-HQ-OAR-2009-0491-3766.1_NODA, p.4]
3. Future S02 Control Levels Projected for Montour Units 1&2 and Brunner Island Units 1,2&3.
Run files 'TR Base Case v4.10,' 'TR SB Limited Trading v4.10,' 'TR Base Case AEO Gas v4.1O' and 'TR SB Limited Trading AEO Gas v4.1O' presented on the Transport Rule website present annual heat input and SO2 emissions data that correspond to annual SO2 emission rates that are confusing. These emission rates may also be presented in other version 4.10 runs. [EPA-HQ-OAR-2009-0491-3766.1_NODA, p.4]
The SO2 emission rate calculated from annual heat input and annual SO2 emissions presented in the 'TR Base Case v4.10' and 'TR Base Case AEO Gas v4.10' parsed files for Montour Unit 2 is 0.06 lb/MmBtu. In previous PPL comments to the proposed Transport Rule submitted on October 1,2010, PPL noted that this value also appeared in the 2012 Allocation Table (and, it also would be calculated from annual heat input and NOx emissions data in the 'BADetailedData.xls' file, 'Projected Data' screen). As we noted at the time, the value is excessively low and appears to be an error. [EPA-HQ-OAR-2009-0491-3766.1_NODA, p.4]
PPL also observes that the SO2 emission rates calculated from annual heat input and annual SO2 emissions data in the 'TR SB Limited Trading v4.1 0' and 'TR SB Limited Trading AEO Gas v4.10' parsed data files also come out to this apparently ultra-low SO2 emission rate error of 0.06 lb/MmBtu. But, in these files the problem exists for all of PPL's coal-fired units at the Montour and Brunner Island plants. PPL is very confused and very concerned that this is happening. An SO2 emission rate of 0.06 lb/MmBtu is much lower than the emission rates at which the units presently operate and is much lower than the emission rates for which allocations in the proposed Transport Rule are based for other similar size coal-fired power plants in Pennsylvania that have or that IPM assumes will install FGD systems. The allocation tables for the proposed rule show allocations for all other such units in Pennsylvania based on emission rates over 1 lb/MmBtu and in some cases over 2 lb/MmBtu. [EPA-HQ-OAR-2009-0491-3766.1_NODA, p.4]
PPL requests that this inconsistency and apparent error in the emission rates being assigned to Montour Units 1&2 and Brunner Island Units 1,2&3 be corrected. [EPA-HQ-OAR-2009-0491-3766.1_NODA, p.4]
PSEG Services Corporation
When reviewing EPA's modeling assumptions and results, PSEG has noted a number of incorrect assumptions and unrealistic results. The individual unit corrections are noted below in a table and in reference to the NEEDS database version 4.10. Additionally, one area of particular concern is the model's treatment of dual-fuel oil and gas units. During a July 7, 2010 EPA briefing hosted by the Edison Electric Institute ("EEI"), EPA staff acknowledged that the IPM has difficulty handling dual-fuel units because there are non-economic reasons that a company must run such units that are not considered by the model. PSEG strongly encourages EPA to correct this modeling limitation through adjustments to the model or through post-modeling adjustments to unit emissions. We also note that this issue is not limited to dual-fueled units. [EPA-HQ-OAR-2009-0491-2627.1, p.8]
There are a number of other issues that are not appropriately handled by the model. For Example, PSEG has units located in load pockets with high demand that are modeled as having a lower heat input than has historically been required to maintain reliability. This is a clear example of why EPA should move away from the model-based approach to allocating allowances and toward a historic basis as recommended. If EPA elects not to change the allocation approach, then EPA will need to make the appropriate adjustments to the model or its output. [EPA-HQ-OAR-2009-0491-2627.1, pp.8-9]
We also recommend that prior to finalizing the Transport Rule, EPA release a Supplemental Notice of Proposed Rulemaking and/or a Notice of Data Availability ("NODA") that allows owners of covered units to verify the data underlying the allocations in the final rule and provide any necessary comments correcting the data. For example, if EPA decides to retain the proposed allocation methodology, PSEG recommends that EPA release the updated assumptions and modeling results used as the basis for the allocations along with revised unit allocations. Such a process would provide stakeholders with an opportunity to submit additional corrections before EPA implements the rule and would ensure the final data underlying the rule is as accurate as possible. [EPA-HQ-OAR-2009-0491-2627.1, p.9]
Finally, for future rulemakings, including any companion rules to the Transport Rule, PSEG recommends that EPA publicly distribute any information and data that will be used in the rulemaking through an advanced notice of proposed rulemaking to ensure there is sufficient time to verify the information. This process would allow data verification to occur simultaneously to EPA's development of the proposed rule. Through this process, EPA and owners of covered sources can ensure that the rulemaking is based on the most up-to-date and accurate information, thereby resulting in a more effective and legally-defensible program. [EPA-HQ-OAR-2009-0491-2627.1, p.9]
[See EPA-HQ-OAR-2009-0491-2627.1, p.9 for Table entitled: PSEG corrections to NEEDS database version 4.10]
Documentation for EPA Base Case v.4.10 Using the IPM Document [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.1]
Comment 1: Appendix 3-2.4 only lists NOx RACT regulations from New Jersey that were implemented in 2007, there were significant changes to NOx RACT requirements in 2009, with some taking effect in 2010, 2012 and 2015. Please ensure that these are reflected in EPA's analyses. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.1]
Comment 2: Appendix 3-3.2 erroneously refers to PSEG Fossil's Mercer Generating Station Unit Nos. 1 and 2 NOx control requirements for its NSR Settlement. A NOx Control Rate of 0.13 pounds per million British thermal units (lb/mmBtu) is listed, which was the original commitment of the Consent Decree. However, PSEG Fossil entered into an Amended Consent Decree which lowered the NOx requirements for these units to 0.1 lb/mmBtu, among other changes. This limit took effect on January 1, 2007. Also, these units must meet a PM emission limit of 0.015 lb/mmBtu by December 31, 2010 through the amended Consent Decree. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.1]
Comment 3: Section 4.3 states that EPA Base Case v.4.10 includes all planed-committed units that are likely to come online because ground has been broken, financing obtained, or other demonstrable factors indicate a high probability that the unit will be built before 2012. PSEG Fossil is currently permitting a simple cycle project at its New Haven Harbor Generating Station in New Haven, Connecticut. The proposed project will consist of three GE LM6000PC combustion turbines. The turbines are used to meet peak power demands. The turbines will fire both natural gas and ultra-low sulfur distillate oil (ULSD), and they will utilize water injection and selective catalytic reduction (SCR) for NOx emissions control. The project will provide a summer electrical generating capacity of 129.6 megawatts (MW) and a winter capacity of 145.5 MW. These units are expected to commence commercial operation in June 2012. As such, PSEG Fossil requests that these units be included in EPA's analyses. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.2]
PSEG Fossil is also currently permitting a simple cycle project at its Kearny Generating Station in Kearny, New Jersey. The proposed project will consist of six GE LM6000PC combustion turbines. The turbines are used to meet peak power demands. The turbines will fire natural gas exclusively, and they will utilize water injection and SCR for NOx emissions control. The combined maximum electricity generated by the six turbines will be 294 MW. These units are expected to commence commercial operation in May 2012. As such, PSEG Fossil requests that these units be included in EPA's analyses. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.2]
NEEDS v.4.10 Spreadsheet [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.2]
Comment 4: Rows 4675 through 4679 list Unit No. 1 at the PSEG Bergen Generating Station. The unit's SO2 Permit Rate is listed as 0. This unit emits SO2 when combusting natural gas at approximately 0.00083 lb/mmBtu which is based on its permitted SO2 emission limit of 1.25 pounds per hour (lb/hr). [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.2]
Comment 5: Rows 4675 through 4679 list Unit No. 1 at the PSEG Bergen Generating Station. This unit employs dry low NOx burners (DLNB) and water injection (H2O) as NOx combustion controls. Please add DLNB and H2O to the NOx Comb Control column. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.2]
Comment 6: Rows 4680 through 4682 list Unit No. 2 at the PSEG Bergen Generating Station. The unit's SO2 Permit Rate is listed as 0. This unit emits SO2 when combusting natural gas at approximately 0.00084 lb/mmBtu which is based on its permitted SO2 emission limit of 2 lb/hr. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.2]
Comment 7: Rows 4685 through 4687 and Row 4696 list Unit No. 9 at the PSEG Burlington Generating Station. Rows 4692 through 4695 list Unit No. 11 at the Burlington Generating Station. Based on a review of the facility's EDRs submitted in 2007 in accordance with 40 CFR 75, PSEG Fossil believes the NOx emissions reflected in the spreadsheet should be switched since the facility reported approximately 0.692 lb/mmBtu NOx for Unit No. 9 and 1.2 lb/mmBtu for Unit No. 11. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.2]
Comment 8: Row 4684 and Rows 4689 through 4691 list Unit No. 12 at the PSEG Burlington Generating Station. This unit employs water injection (H2O) as NOx combustion controls. However, this unit does not employ SCR as NOx post-combustion control. Please remove SCR from the NOx Post-Comb Control column. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.2]
Comment 9: Row 4684 and Rows 4689 through 4691 list Unit No. 12 at the PSEG Burlington Generating Station. The controlled NOx rates are listed as approximately 0.02 lb/mmBtu while the uncontrolled NOx rates are listed as approximately 0.1 lb/mmBtu. As stated in Comment 8, this unit does not employ SCR for NOx emissions controls, thus the uncontrolled and controlled NOx emission rates should be identical. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.3]
Comment 10: Row 4710 lists one generator connected to two combustion turbines that are part of Unit No. 12 at the PSEG Essex Generating Station. This unit does not employ water injection (H2O) as NOx post-combustion control for any days except high electric demand days (HEDD) as determined by the New Jersey Department of Environmental Protection. There are approximately 5 to 15 HEDDs per year. The facility does not have discretion to use this control technology on any non-HEDDs. As such, it would make send to remove H2O from the NOx Post-Comb Control column as it would unnecessarily complicate EPA's analyses. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.3]
Comment 11: Row 4710 lists one generator connected to two combustion turbines that are part of Unit No. 12 at the PSEG Essex Generating Station. As stated in Comment 10, this unit does not employ water injection (H2O) for NOx emissions controls, thus the uncontrolled and controlled NOx emission rates should be identical and should be similar to the other units that comprise Unit No. 12 (Rows 4711 through 4713). [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.3]
Comment 12: Row 4722 lists Unit No. 1 at the PSEG Hudson Generating Station. This unit does not employ water injection (H2O) as NOx combustion controls. This unit also does not employ SCR as NOx post-combustion control. Please remove H2O from the NOx Post-Comb Control column and SCR from the NOx Post-Comb Control column. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.3]
Comment 13: Row 4722 lists Unit No. 1 at the PSEG Hudson Generating Station. This unit does not employ water injection (H2O) as NOx combustion controls. As stated in Comment 12, this unit does not employ water injection (H2O) for NOx emissions controls or SCR as NOx postcombustion control, thus the uncontrolled and controlled NOx emission rates should be identical. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.3]
Comment 14: Row 4723 lists Unit No. 2 at the PSEG Hudson Generating Station. This unit does not yet employ SCR as NOx post-combustion control. The SCR is required to be operational on December 31, 2010. Please change the SCR On-Line Year column from 2007 to 2010. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.3]
Comment 15: Row 4723 lists Unit No. 2 at the PSEG Hudson Generating Station. The controlled NOx rates are listed as 0.06 lb/mmBtu. As stated in Comment 14, this unit will employ SCR for NOx emissions controls on December 31, 2010 to achieve a NOx emission limit of 0.1 lb/mmBtu. Thus, the controlled NOx emission rates should be changed to 0.1 lb/mmBtu. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.3]
Comment 16: Rows 4725 and 4726 list Unit Nos. 10 and 11 at the PSEG Kearny Generating Station. These units are committed to being retired on May 1, 2012, commensurate with the startup of four out of six proposed simple cycle combustion turbines referenced in Comment 3 of this letter. Please add May 1, 2012 to the Retirement Date column for these units. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.3]
Comment 17: Row 4728 lists Unit No. 9 at the PSEG Kearny Generating Station. This unit is committed to being retired on May 1, 2013, commensurate with the startup of the remaining two out of six proposed simple cycle combustion turbines referenced in Comment 3 of this letter. Please add May 1, 2013 to the Retirement Date column for these units. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.4]
Comment 18: Rows 4724, 4727, 4729 and 4730 list Unit No. 12 at the PSEG Kearny Generating Station. This unit does not employ a post-combustion NOx emissions control device. As such, the uncontrolled and controlled NOx emission rates for all four columns should be identical. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.4]
Comment 19: Row 4735 lists Unit No. 3 at the PSEG Linden Generating Station. This unit was permanently retired several years ago. Please remove this unit from EPA's analyses. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.4]
Comment 20: Rows 4736 through 4741 list Unit Nos. 1 and 2 at the PSEG Linden Generating Station. These units employ SCR as NOx post-combustion controls. These units also employ dry low NOx burners (DLNB) and water injection (H2O) as NOx combustion controls. Please add DLNB and H2O to the NOx Comb Control column. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.4]
Comment 21: Rows 4736 through 4741 list Unit Nos. 1 and 2 at the PSEG Linden Generating Station. These unit's SO2 Permit Rates are listed as 9999. These units emit SO2 when combusting natural gas at approximately 0.00082 lb/mmBtu which is based on its permitted SO2 emission limit of 2 lb/hr. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.4]
Comment 22: Rows 4731 through 4734 list Unit Nos. 5, 6, 7 and 8 at the PSEG Linden Generating Station. These units do not employ a post-combustion NOx emissions control device. As such, the uncontrolled and controlled NOx emission rates for all four columns should be identical. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.4]
Comment 23: Rows 4743 and 4744 list Unit Nos. 1 and 2 at the PSEG Mercer Generating Station. These units employ SCR as NOx post-combustion control. The SCR became operational in 2004. Please change the SCR On-Line Year column from 1995 to 2004. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.4]
Comment 24: Rows 4743 and 4744 list Unit Nos. 1 and 2 at the PSEG Mercer Generating Station. These units employ Baghouses as PM controls. These units also employ cold side electrostatic precipitators with flue gas conditioning (ESPC) as PM controls. Please add ESPC to the PM Control column. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.4]
Comment 25: Rows 4743 and 4744 list Unit Nos. 1 and 2 at the PSEG Mercer Generating Station. The controlled NOx rates are listed as 0.06 lb/mmBtu. These units employ SCR for NOx emissions controls to achieve a NOx emission limit of 0.1 lb/mmBtu. Thus, the controlled NOx emission rates should be changed to 0.1 lb/mmBtu. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.4]
Comment 26: Rows 4750 through 4753 list Unit Nos. 1, 2, 3 and 4 at the PSEG Sewaren Generating Station. These units do not employ a post-combustion NOx emissions control device. As such, the uncontrolled and controlled NOx emission rates for all four columns should be identical. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.4]
Comment 27: Rows 4952 through 4955 list Unit Nos. 1, 2 and 3 at the PSEG Bethlehem Energy Center. These units employ SCR as NOx post-combustion control. These units also employ dry low NOx burners (DLNB) and water injection (H2O) as NOx combustion controls. Please add DLNB and H2O to the NOx Comb Control column. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.5]
San Miguel Electric Cooperative, Inc.
Corrections to the Unit Level IPM  [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.2]
San Miguel reviewed the NEEDS (v4.10) and believes the information is correct. San Miguel discovered errors in the IPM Base Case for 2012 parsed file and TR SB Limited Trading Case for 2014 parsed file. The discovered errors are for the San Miguel generating unit and require correction. The ID number for the San Miguel generating unit is 6183_B_SM-1. Similar errors were in the original IPM (v3.02) and were commented on by San Miguel on September 29, 2010. [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.2]
In reviewing the parsed file for the Base Case and the TR SB Limited Trading case discrepancies were discovered:  [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.2]
1. Base Case for 2012: column Q, Retrofit Control 1; and column S, Retrofit SO2/NOx Controls- states "SCR". This is incorrect! The San Miguel unit does not have an SCR, nor is one under construction and there is no plan to install an SCR.  [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.2]
2. Base Case 2012: columns U and V - Summer and Total Fuel Use; column AA and AB - Summer Lignite and Total Lignite Fuel Use; column AC and AD - Summer NOx and Total NOx Emission; column AE - Total SO2 Emission, column AF - Total CO2 Emission; and column AG - Total Hg Emission. All values indicate the unit will only be run during the summer season. This is not correct! The projected values are unrealistic for the following reasons: [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.2]
a. The San Miguel unit is a base load unit, as such the annual heat input varies between 32,000,000 and 35,000,000 mmBtu. [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.2]
b. The San Miguel unit is the least cost energy generator for our consumer -owners and no change in load is expected during the TR base case and limited trading case projections (2012  - 2014). [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.2]
c. Since the San Miguel unit is base loaded the heat input during the ozone season should be approximately 50% of the annual heat input. This is higher than the percentage of the calendar year due to the fact that planned outages are not scheduled during the peak generating season, which coincides with the ozone season. [EPA-HQ-OAR-2009-0491-3740.1_NODA, pp.2-3]
3. TR SB Limited Trading Case for 2014: column Q, Retrofit Control 1 and column S, Retrofit SO2/NOx Controls; states "Coal Early Retirement". This is not correct! The San Miguel unit is the least cost energy generator for our consumer-owners and no change in load is expected during the TR Base Case and TR SB Limited Trading Case projections (2012  - 2014). There are no plans to retire the San Miguel unit in 2014. The unit is and has been a base load unit running at an annual load factor above 80% for years. The San Miguel recently signed wholesale power contracts for the entire output of the unit until the year 2037. [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.3]
4. TR SB Limited Trading Case for 2014: columns U and V - Summer and Total Fuel Use; column AA and AB - Summer Lignite and Total Lignite Fuel Use; column AC and AD - Summer NOx and Total NOx Emission; column AE - Total SO2 Emission; column AF - Total CO2 Emission; and column AG - Total Hg Emission; need to be corrected to show a unit that is base loaded. See discussion above in bullet items 2 and 3 [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.3]
5. Column AE - Total SO2 Emission - in both the Base Case and The TR SB Limited Trading Case emission is unbelievably low for a high sulfur fuel and a scrubber that was designed in 1979. The low SO2 mass emissions indicate the fuel projection or scrubber efficiency in the model is incorrect for the San Miguel unit. San Miguel is a mine mouth plant. In 2009 the fuel averaged 5,280 Btu/lb, and sulfur in the fuel was 2.72%. The San Miguel unit was built with a wet scrubber and in 2009 the actual SO2 removal efficiency averaged 93.8%. Based on the fuel analysis from 2009 the Projected Base Case Annual SO2 Mass emission would specify 98.5% SO2 removal efficiency. This needs to be corrected to the existing scrubber efficiency rather than a new scrubber efficiency projection. [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.3]
6. Column AF  -  Total CO2 Emissions - in both the Base Case and The TR SB Limited Trading Case emission is very low and needs to be corrected for a base loaded unit. [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.3]
7.Column AG - Total Mercury Emissions - in both the Base Case and The TR SB Limited Trading Case emission is very low and needs to be corrected for a base loaded unit. In addition the mercury emissions does not accurately reflect the amount of mercury in our fuel, please see discussion in Fuel Assumptions in IPM for San Miguel Unit in the next section. Mercury emissions need to be corrected for the high levels of mercury in our coal and for a base loaded unit. [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.3]
San Miguel requests the discrepancies be corrected to reflect how the San Miguel unit is actually run. Corrections need to be made in all IPM model runs, not just the models runs outlined above. [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.4]
Fuel Assumptions in IPM for San Miguel Unit  In the documentation for the EPA base case v. 4.10 (Base Case) chapter 9 discusses coal assumptions. We are commenting on the assumptions used for Texas lignite. San Miguel uses a very poor quality of fuel as compared to the fuel characteristics in table 9-3, 9-4 and 9-5.  The table below compares IPM Texas lignite, TX LE, (table 9-5) to San Miguel lignite: [See p. 4 of this comment summary for the table comparing IPM Texas lignite, TX LE, (table 9-5) to San Miguel lignite; EPA-HQ-OAR-2009-0491-3740.1_NODA, p.4]
Per the documentation in Chapter 9, the assumptions in the Base Case on the heat, mercury SO2 and ash content of the coal were derived from the EPA's Information Collection Request of 1998-2000. As you can see from the table above San Miguel fuel does not match the Base Case fuel TX LE. [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.4]
Additionally one of the aspects of the 1998-2000 ICR was to collect accurate information on mercury content of the as-fired fuel. The mercury content information from San Miguel was incorrect. San Miguel commented on this in our comments to the Docket ID No. OAR-2002-0056, on June 22, 2004. The error in mercury content is significant - reported data, approximately 7 lbs/TBtu as compared to the corrected analysis of approximately 32 lbs/TBtu. San Miguel will supply copies to the EPA of the June 22, 2004 comments if requested. [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.4]
San Miguel believes the fuel characteristics needs to be corrected to accurately model the San Miguel Generating Station. [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.4]
Method of Allowance Allocation  EPA is proposing to use the updated version (4.10) of the IPM in the final transport rule. San Miguel believes the corrections state above need to be made to accurately predict emissions for the San Miguel Generating Station. As stated in our comments to the Transport Rule, the EPA should use historic data not model results to establish emissions allocations. Regardless of the sophistication of EPA's model, it does not and cannot accurately forecast how each and every fossil fuel unit among thousands will be utilized. Case in point is the numerous errors, outlined above, of the San Miguel generating unit. It is not likely that the San Miguel unit is the only unit where errors have occurred. [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.4-5]
The model also cannot account for future business decisions, the necessity of which is not yet presently known or anticipated but nonetheless may need to be made that would significantly affect an individual unit's utilization within the utility system. There are literally dozens of significant factors that affect future unit utilization of which the model does not and cannot take into account. [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.5]
San Miguel believes most of the problems inherent in the proposal's methodology could be resolved if state budgeted allowances were distributed to each unit within the state based pro-rata on the unit's portion of the state historic heat rate updated periodically to include new units. Such distribution should sub-categorize between coal, gas, and oil. The allocation methodology could be structured in a manner similar to that contained in Clean Air Interstate Rule (CAIR) for annual NOx allocations as a SIP for all the CATR trading programs. Specifically, the salient features of this methodology include allocating allowances to existing units based on historic heat input using the three highest heat inputs of the past five years to derive annual averages (seasonal for ozone), and allocating allowances to new units based on a set-aside and folding new units into existing unit category after five years of operation. As with the CAIR approach, this methodology could provide options for each state to consider whether new units should receive allowances from a set-aside during their initial year of operation and if retired units should continue to receive allowances, and if so how long or at a diminished allocation. [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.5]
San Miguel encourages the EPA to revise the methodology for unit allocations from the proposed method to a historically based system similar to the CAIR proposal. [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.5]
Seminole Electric Cooperative Inc.
EPA Must Publish another Proposed Rule
As explained in Seminole's comments on the proposed Transport Rule, EPA's proposal suffers from numerous errors in methodologies and numerous incorrect assumptions which impact every aspect of the proposed rule. In fact, the new information associated with the NODA revises assumptions underlying the rule's modeling platform, yet itself does not represent final refinement of EPA's assumptions. Specifically, EPA includes in the NODA a list of further planned revisions to modeling assumptions and inputs that it intends to undertake prior to final rulemaking. [EPA-HQ-OAR-2009-0491-3723.1_NODA, p.1]
EPA acknowledges that changes from using an updated model could impact the final rule in a number of ways, including, but not limited to (1) changing emission projections that were used to determine which downwind areas have air quality concerns absent rulemaking and to determine which states contribute to those problems, and (2) changing cost and emission projections used in the multi-factor test to determine the amount of emissions that represent significant contribution. 75 Fed. Reg. 53614. These changes affect the heart of the proposed rule; changes to the modeling platform will necessarily change the compliance obligations of every state, company and unit, and affected parties must be given an opportunity to review and comment as to whether EPA has corrected its mistakes, made new mistakes, and whether parties can meet their new compliance obligations. Further, EPA's NODA did not provide sufficient information to calculate the air quality impacts, state budgets, or unit allocations resulting from the NODA's revised information. Accordingly, EPA is obligated to publish a second proposal to provide the public an opportunity to review and comment on the accuracy and achievability of EPA's corrected approach before this rule is finalized. [EPA-HQ-OAR-2009-0491-3723.1_NODA, p.2]
EPA Has Not Provided Sufficient Time to Develop Comments
On September 1,2010, EPA published the NODA and placed new information relevant to EPA's proposed Transport Rule in the Transport Rule's docket. This new information modified assumptions integral to the proposed Transport Rule, yet EPA did not extend the already insufficient 60-day commenting period for the proposed rule; rather, EPA provided only an additional 14 days to review and comment on the extensive and complex, newly-provided information. EPA's new and modified information contains assumptions that result in significant changes in cost and generation from the proposed Transport Rule-assumptions and changes that must be analyzed by review of complex data files and spreadsheets. Initial reviews of this data have revealed that EPA has provided only a portion of the information needed to evaluate its implications. Accordingly, EPA has effectively precluded meaningful public involvement by providing insufficient time to review and develop meaningful comment on the proposed Transport Rule and NODA. [EPA-HQ-OAR-2009-0491-3723.1_NODA, p.2]
EPA's IPM Results for Seminole are Materially Wrong
EPA's IPM Base Case v4.10 projects that Seminole's annual fuel use for Unit 1 and 2 will be 41.27 and 40.63 TBtu, respectively.1 This projection is not representative of existing and historic fuel use, which is approximately 50 TBtu per unit per year. As explained in Seminole's comments on the proposed Transport Rule, Units 1 and 2 are baseload units, operating historically between 80 and 85 capacity factor and supplying approximately 60 percent of Seminole's distribution cooperatives' needs. Accordingly, it is materially wrong for IPM to predict that Seminole's units will operate approximately 20 percent less than historic levels. [EPA-HQ-OAR-2009-0491-3723.1_NODA, pp.2-3]
Moreover, the decrease in projected fuel use from IPM Base Case v4.10 to v.3.02 is unexplained by available information. EPA's IPM Base Case v.3.02 projected Units 1 and 2's annual fuel use to be 48.31 and 47.56 TBtu, respectively. EPA has not indicated what changes in assumptions or input into the modeling platform effected this change; therefore, Seminole is unable to adequately comment on this issue, and must be given an opportunity to directly comment once EPA explains the basis for this result. [EPA-HQ-OAR-2009-0491-3723.1_NODA, p.3]
Seminole is also unable to adequately assess, and, therefore, specifically comment on, the fuel quality (I.e., sulfur content) that IPM projects it will use. Seminole provided extensive comments on this issue in its submittal regarding the proposed Transport Rule. While it appears that Seminole's predicted sulfur content has increased between IPM v.3.02 and IPM v4.10, it is still less than current, historic, and permitted values. EPA must explain why and how these values for Seminole changed between v.3.02 and v4.10, and more importantly, EPA must correct its inputs and assumptions such that the IPM results match reality. [EPA-HQ-OAR-2009-0491-3723.1_NODA, p.3]
Seminole was not given sufficient time to review and comment on all of the documents and issues that EPA published as part of its proposed rule on August 2, 2010, and as part of its NODA on September 1,2010. The data and assumptions EPA chose, and the predictions resulting from EPA's IPM modeling, do not resemble reality. Specific corrections must be made to EPA's data, approach, and allocations. In order for Seminole to meaningfully participate in this rulemaking, EPA must publish a corrected version of its proposed rule, and allow an adequate time for review and comment, before it becomes final. [EPA-HQ-OAR-2009-0491-3723.1_NODA, p.3]

1 The IPM unique ID for Unit 1 is '136_B_1'; the ID for Unit 2 is '136_B_2/1. [EPA-HQ-OAR-2009-0491-3723.1_NODA,p.2]
South Carolina Department of Health and Environmental Control
DHEC notes that the EPA over-relies on IPM in the proposed Transport Rule. The uncertainty inherent in the model means that the EPA should reconsider its use in developing state budgets and unit-level allocations, and instead use empirical heat-input data as it did in the NOx SIP Call and the Clean Air Interstate Rule ('CAIR). The uncertainty in IPM led DHEC to request more appropriate thresholds for including states in the in the Transport Rule. With thresholds of 1 ug/m3 for the 1997 and 2006 Particulate Matter National Ambient Air Quality Standards ('NAAQS') and 1 ppb for the 1997 Ozone NAAQS, South Carolina would not be subject to the Transport Rule trading programs. If the EPA changes the modeling approach used in making threshold determinations based on new data on the NODA, DHEC requests that the EPA re-notice the proposal to provide adequate opportunity for review and meaningful comments to be developed. [EPA-HQ-OAR-2009-0491-3718.1_NODA, p.2]
DHEC notes that even if the NEEDS data is correct, then the Budgets and Allocations Spreadsheet still indicates that the EPA does not necessarily include all of the actual controls listed in NEEDS, in part because it determined that the controls were installed to comply with the CAR. The EPA should reconsider this decision not to include CAIR-based controls. South Carolina's utilities, and their rate payers, committed considerable resources to installing and operating controls on several coal-fired units to meet the requirements of the CAIR. [EPA-HQ-OAR-2009-0491-3718.1_NODA, p.2]
Southern IL Power Cooperative
The "NEEDSv410" spreadsheet shows uncontrolled NOX emission rates for SIPC's Unit 123 boiler as 0.0920 lb/MBtu and Unit 4 boiler as 0.999 lb/MBtu. These numbers are incorrect, and the proper uncontrolled emission rates should show Unit 123 boiler uncontrolled NOX emission rate as 0.16 lbs/MBtu and Unit 4 (cyclone) boiler as 1.2 lbs/MBtu. Similarly, the 2014 SO2 emission rate shown for Unit 123 is 0.318 lbs/MBtu and Unit 4 is 0.325 lb/MBtu. Our average emission rates for these boilers from 2006 through 2009 have been 0.499 lbs/MBtu for U123 and 0.484 lbs/MBtu for U4. These values equate to 90  -  92% reduction of SO2 because of SIPC's pollution control strategies and equipment. The various pollution control equipment that is employed by Southern Illinois Power Cooperative were state-of-the-art when they were constructed (wet FGD & ESP for Unit 4 in 1978 & SCR for U4 and CFB with SNCR in 2003), and it is not logical to "assume" that higher reduction efficiencies can be obtained from such equipment. The proposed allocation methodology departs radically from previous Clean Air Act allowance allocation without explanation. By requiring such additional reductions, EPA is punishing facilities that have chosen to reduce their emission footprint by installing such pollution control equipment early. In doing so, EPA is also punishing their customers who have paid for such emission reduction improvements through rate increases over the years. SIPC believes this is bad policy, and such actions will dissuade utilities from investing in the cleanest generation technology in the future. [EPA-HQ-OAR-2009-0491-2863.1 p.3]
State of Louisiana, Department of Environmental Quality
Comment: Based on the new data, Louisiana should be removed from the Transport Rule. [EPA-HQ-OAR-2009-0491-3725.1_NODA, p.1]
Louisiana is included in the proposed Transport Rule as a state that shows 'significant contribution' and 'interference with maintenance' with monitors located in Texas. Based on new information contained in the NODA, LDEQ's position is that Louisiana should be removed· from this rulemaking. [EPA-HQ-OAR-2009-0491-3725.1_NODA, p.1]
In the proposed rulemaking, EPA used as its base case the following inventories: [EPA-HQ-OAR-2009-0491-3725.1_NODA, p.2]
Sulfur dioxide (S02): 98,110 tpy [EPA-HQ-OAR-2009-0491-3725.1_NODA, p.2]
Annual nitrogen dioxide (NOx): 43,946 tpy [EPA-HQ-OAR-2009-0491-3725.1_NODA, p.2]
Ozone season: NOx 21,220 tpy [EPA-HQ-OAR-2009-0491-3725.1_NODA, p.2]
When using these emissions as the base case for the IPM v3.02, Louisiana was considered to either contribute to or interfere with the attainment/maintenance of monitors located in Texas. However in this NODA (IPM vA.l0), EPA used the following emissions inventories, which accurately reflect the actual emissions inventories, as inputs: [EPA-HQ-OAR-2009-0491-3725.1_NODA, p.2]
S02: 80,381 tpy [EPA-HQ-OAR-2009-0491-3725.1_NODA, p.2]
Annual NOx: 32,804 tpy [EPA-HQ-OAR-2009-0491-3725.1_NODA, p.2]
Ozone season NOx: 15,159 tpy [EPA-HQ-OAR-2009-0491-3725.1_NODA, p.2]
The differences in the base case inventories are now greater than the required emission reductions that are necessary to eliminate significant contribution or interference with maintenance as listed in the Transport Rule. The reductions in the base case for S02 are greater than two times the reductions that the proposal required. The NOx reductions are approximately one and one-half times greater than those required by the proposed rulemaking. This mathematical equation indicates that Louisiana is no longer a significant contributor and should therefore be removed from the proposed rule. [EPA-HQ-OAR-2009-0491-3725.1_NODA, p.2]
West Virginia Department of Environmental Protection
The WV DEP also requests an extension of the public comment period on EPA's Notice of Data Availability Supporting Federal Implementation Plans To Reduce Interstate Transport of Fine Particulate Matter and Ozone, as published at 75 FR 53613, 01 SEP 2010. EPA announced a 45-day public comment period on this Notice of Data Availability (NODA), requiring comments to be submitted by October 15, 2010. WV DEP is requesting an extension of the public comment period by 45 days, to November 30, 2010. [EPA-HQ-OAR-2009-0491-2057, p.1]
Subsequent to the proposed Transport Rule, EPA released the NODA, which contains a substantial amount of additional information directly related to the proposed Transport Rule. EPA has allowed only 45 days for review of the NODA, 30 days of which are concurrent with the review of the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2057,p.1]
The issuance of the NODA, which contain new data and modeling results shows that EPA has acknowledged inaccurate or flawed data in the development of the proposed rule . EPA should reevaluate the results caused by these changes and the updated evaluation should be placed in the rule -making docket so that states, affected industry sources and the general public can understand the ramifications of the new NODA information . It is apparent that states' previously developed comments regarding data and modeling for the Transport Rule also may need to be reevaluated in light of the new data contained in the NODA, whether or not agencies have formally submitted them to the docket. An extension of the comment deadline will allow the WV DEP to prepare detailed constructive comments that may be useful to the EPA in finalizing this rule. [EPA-HQ-OAR-2009-0491-2057, p.2]
Given that the Clean Air Interstate Rule (CAIR) is still in place, we do not believe there will be any environmental harm caused by extending the comment period on the proposed Transport Rule and the NODA until November 30, 2010, to allow for a proper review of the technical information and the development of constructive comments for how the proposal can be improved . We urge EPA to grant this extension and provide adequate time for meaningful feedback. [EPA-HQ-OAR-2009-0491-2057, p.2]
The West Virginia Division of Air Quality (WVDAQ) previously commented on the proposed Transport Rule and offers the following comments regarding EPA's subsequent, related Notice of Data Availability (NODA) [75 FR 53613]. WVDAQ believes that EPA has once again provided a totally inadequate time for meaningful review and comment on the voluminous technical documentation. The agency's web-page lists four IPM runs comprising over 27 megabytes of information and 11 chapters describing Base Case v4.10 comprising over 24 Mb of information. Despite the brief review time, WVDAQ staff have identified the following significant inaccuracies in the inputs to the IPM model. It is likely that other corrections and improvements may have been detected had more review time been available. It also seems likely that the cumulative effect of mistakes, both known and unknown, could alter some of EPA's original conclusions. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.1]
Mt. Storm Unit JF1 (3954_G_JF1) is an emergency generator and should not be included in the NEEDS v4.10 database. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.1]
Morgantown Energy Associates (l0743B_CFB1 and CFB2) is identified in NEEDS v4.10, however, it was not allocated allowances under the Transport Rule, as proposed. The WVDAQ believes that EPA did not include MEA in the proposed allocations because it was erroneously assumed that the facility would meet the exemption requirements for cogeneration units. However, MEA does not meet the exemption requirements as proposed. Therefore, the facility should be treated as an existing unit under the Transport Rule and allocated allowances accordingly. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.1]
Alloy Steam Station (500 12_B_BLR4) does not provide power to the grid and should not be included in the NEEDS v4.10 database. The Alloy Steam Station should not receive allocations under the Transport Rule. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.2]
Philip Sporn Unit 51 is a 450 MW operational unit which was not included in the NEEDS v4.10 database, and should be included. EPA should refer to EIA for the unit characteristics and include this unit in an updated NEEDS database. Philip Sporn Unit 51 should receive allocations under the Transport Rule. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.2]
RFCP _WV_Coal_Steam (82914_C_1) in the NEEDS v4.10 database refers to the Longview Power Plant under construction in Monongalia County. The correct ORIS Code for this facility is 56671. The facility was allocated allowances in the proposed Transport Rule for 2012 and 2013, but not 2014 and beyond. The facility meets the proposed definition of an existing unit and, therefore, should receive allocations for 2014 and beyond, as well as for 2012 and 2013. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.2]
Ft. Martin Unit 1(3943_B_1) is identified in NEEDS v4.10 as having a scrubber which came online in 2006, the scrubber did not come online until October 31, 2009. It is also identified as having an SNCR which came online in 1997, however, the unit is equipped with SNCR-Trim, a single point injection system, which is not designed with a 35% removal efficiency, but rather a 10-15% removal efficiency. Furthermore, the SNCR-trim was installed in 2004, not 1997. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.2]
Ft. Martin Unit 2 (3943_B_2) is identified in NEEDS v4.10 as having a scrubber which came online in 2006, however, the scrubber did not come online until August 26, 2009. It is also identified as having an SNCR which came online in 1997, however, the unit is equipped with SNCR- Trim, a single point injection system, which is not designed with a 35% removal efficiency, but rather a 10-15% removal efficiency. Furthermore, the SNCR-trim was installed in 2004, not 1997. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.2]
Harrison Unit (3944_ B_) is identified in NEEDS v4.10 as having a PM scrubber, the unit is not equipped with a PM scrubber, instead it is equipped with a wet FGD for S02 control. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.2]
Harrison Unit 2 (3944_ B_2) is identified in NEEDS v4.10 as having had an SCR installed in 2000, however, the SCR came online April 1, 2003. NEEDS v4.10 also indicates that Unit 2 is equipped with a PM scrubber, instead it is equipped with a wet FGD for S02 control. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.2]
Harrison Unit 3 (3944_B_3) is identified in NEEDS v4.10 as having had an SCR installed in 2000, however, the SCR came online April 1, 2003. NEEDS v4.10 also indicates that Unit 3 is equipped with a PM scrubber, instead it is equipped with a wet FGD for S02 control. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.2]
John Amos Unit 1 (3539 _B_1) is identified in NEEDS v4.10 as having a wet scrubber with an online year of2008, however, the scrubber is not scheduled to come online until 2011. John Amos Unit 2 (3539_B_2) is identified in NEEDS v4.10 as having a wet scrubber with an online year of 2008, however, the scrubber did not come online until March of 2010. NEEDS also indicated that the SCR came online in 2005, when it actually came online May 16, 2004. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.3]
John Amos Unit 3 (3539_B_3) is identified in NEEDS v4.10 as having a wet scrubber with an online year of 2007, however, the scrubber did not come online until May of 2009. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.3]
Kammer Unit 1 (3947 _B_1) is identified in NEEDS v4.10 as having a scrubber with an online year of 2007. This unit has never been, and is not currently, equipped with a scrubber. Furthermore, the WVDAQ has no knowledge of any plans for a scrubber to be installed on this unit by 2014. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.3]
Karnmer Unit 2 (3947_B_2) is identified in NEEDS v4.10 as having a scrubber with an online year of 2007. This unit has never been, and is not currently, equipped with a scrubber. Furthermore, the WVDAQ has no knowledge of any plans for a scrubber to be installed on this unit by 2014. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.3]
Mitchell Unit 2 (3948 _B_2) is identified in NEEDS v4.10 as having a scrubber with an online year of2006, when the scrubber did not come online until January 15, 2007. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.3]
Response:
In regards to comments received suggesting a longer comment period, supplemental proposal, re-proposal of the Transport Rule, EPA feels that it provided reasonable comment periods for the TR proposals and subsequent NODAs.  Furthermore, EPA made materials available to the public through its website before each comment period began.  This had the effect of adding additional time beyond the stated comment period for review, effectively extending the stated 30, 45, or 60 day comment period.  Furthermore, the Court did not specify a definitive date by which EPA should promulgate the Transport Rule, it did not give the Agency an infinite stay on CAIR and did, in fact, indicate that the Transport Rule was to be completed in a timely manner.  Section 307(d)(5) of the CAA requires the Administrator to give an opportunity for written or oral comments.  The Act does not specify the length of time, other than the record must be open 30 days after holding public hearings - with which EPA complied.  Given the time frame EPA provided to the public for submission of comments, and indicative of the fact that the Agency received several thousand substantive comments, commenters did, in fact, have sufficient time to submit their comments for consideration.  Section XVII of this RTC document addresses these comments more thoroughly.
EPA recognized that there was significant comment regarding IPM assumptions, the impact of those assumptions on unit level IPM projections, and the proposed allocation methodology which relied on IPM projections for unit level allocations.  EPA's response to these concerns was twofold.  First, EPA changed its allocation methodology to be based on historic heat input and emissions data that is generally reported by the sources' Designated Representative who testifies to its accuracy and completeness.  By switching to a historic data based methodology, the degree to which any discrepancy between a unit's actual future operation and its IPM projected future operation would impact the unit's allocation is greatly diminished.  EPA recognizes that IPM is a dynamic linear programming model that generates optimal decisions under the assumptions of perfect foresight and results in a least cost method of meeting demand.  However, invariably, there will be discrepancies between IPM unit level projections and a unit's actual future operations due to non-economic or other variables that IPM does not capture.  Stakeholders emphasized this point  through the comments  At the state and regional level, as pointed out by some commenters, these non-economic variables do not have a significant impact because the sample of units being examined is large and unit level disparities between projected and observed data generally balance out.  However, their impact at the unit level may be significant and this was one of the drivers behind switching to an allocation method based on historic data.
Second, EPA reviewed the comments and has made significant updates to its IPM v.3.02 modeling used at proposal and the initial IPMv.4.10 made available in the September 1, 2010 NODA .  These updates include changes to both the more general IPM assumptions (e.g., gas price assumptions) and specific unit level assumptions (e.g., that current retrofit status at a unit).  These updates were made to the IPM model, and the updated version (EPA IPM v.4.10) was used for all the final rule analysis.  In regards to unit specific adjustments, EPA did not manually adjust projected unit level modeling outputs, but it did make unit level updates to its NEEDS database used as a model input which impacts the modeling projections when rerun for final Transport Rule analysis.  Some of the more prevalent IPM comments regarding IPM were addressed through major modeling updates.  For instance, FGD removal efficiency was adjusted for new retrofits, and for existing retrofits it was indexed to historic performance at the unit.  Additionally, EPA modified its modeling to better reflect the cost and feasibility of switching and blending coals.  EPA also modified its capital cost for control technologies, added new control technologies (e.g., DSI), adjusted it approach to cogeneration modeling, incorporated additional state rules and consent decrees and made thousands of adjustments to unit level assumptions based on comments received from stakeholders.  For more detailed discussion of EPA IPM v.4.10 assumptions and assumption updates, see the EPA IPM v.4.10 documentation (specifically "Documentation Supplement for EPA Base Case v.4.10_FTransport - Updates for Final Transport Rule") and the "Transport Rule IPM Assumptions Response to Comments" in the Appendix.  This later document categorizes and indexes many of the unit level adjustments that were made in response to corrected data submitted by commenter.  For instance, if the commenter suggested that EPA's data did not accurately reflect the control status at a particular unit and suggested a change, EPA reviewed the comment and made such changes where the comment was significant and reasonable.  The Appendix contains a record of the several thousand unit level changes made in IPM of this nature.
Also, in regards to unit level compliance concerns, EPA notes that there are a variety of options available to sources and that the rule does not require any one particular compliance option for a particular source, but affords flexibility for the source to determine its least cost option.  See section VII.C of the preamble for further discussion regarding compliance with the 2012 and 2014 compliance timeframes.
Organization: Kansas Department of Health and Environment
Kansas City Power and Light Company (KCP&L)
Kansas City Board of Public Utilities (BPU)
Comment:
Kansas City Board of Public Utilities (BPU)
EPA FAILED TO FULLY UTILIZE THE ADDITIONAL INFORMATION IN THE NODA LEADING TO INCORRECT STATE BUDGETS AND UNIT ALLOCATIONS [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.6]
The NODA Fails to Fully Evaluate the Effects of the Revised IPM Data on the Rule [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.6]
The NODA includes an updated version of the power sector modeling platform with different unit level input data and new IPM runs. EPA proposes to use the new IPM runs in the final Transport Rule; however, as more fully explained in the attached October 14, 2010 letter from Trinity Consultants [see p.11 of this comment summary for the Trinity Consultants' letter], EPA failed to publish revised projected 2012 emissions in the NODA. Id. at 53614/3. The NODA recognizes that '[c]hanges from the projections relied on in the proposed rule, from using an updated model, could impact the final rulemaking in a number of ways....' Id. Such impacts include '(1)[c]hanging emission projections that were used to determine which downwind areas have air quality concerns ... and to determine which States contribute to those problems[]'; and '(2) [c]hanging cost and emission projections used in the multi-factor test to determine the amount of emissions that represent significant contribution.' Id. [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.7]
The revised IPM data would affect the projected 2012 emissions. Projected 2012 emissions in turn affect evaluation and quantification of an upwind state's contribution and interference with maintenance. Consequently, a state's emission budget, which is tied to EPA's quantification of each individual state's significant contribution and interference with maintenance, will be affected by the revised IPM data. It follows that individual unit allocations will change by virtue of a change in the state emissions budget. Therefore, EPA's failure to publish revised projected 2012 emissions results in a failure to provide reasonable notice to EGUs about how state budgets and individual unit allocations will be made under the Rule. [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.7]
Reported emissions should be adjusted using a five-year look-back period [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.7]
EPA's Technical Support Document entitled 'State Budgets, Unit Allocations, and Unit Emissions Rates' ('TSD') describes the process used to determine a state's budget. State budgets were based on the lesser of the state's adjusted projected emissions versus the state's adjusted reported emissions for the fourth quarter of2008 and the first three quarters of 2009. Annual and ozone season NOx emissions were adjusted 'to account for unusually low utilization in 2009' which will 'typically result[] in larger annual NOx emissions.' Id. at 9. This adjustment was calculated by multiplying the emissions by the ratio of the 2008 heat input to the heat input determined for the fourth quarter of 2008 and the first three quarters of 2009. Id. The ozone season emissions were adjusted by multiplying the emissions by the ratio of the 2008 ozone season heat input to the 2009 ozone season heat input. Id. [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.7]
Although EPA through this adjustment exercise implicitly recognized the need to use representative data, the heat input data used fails to be representative and, therefore, fails to provide a supportable basis for the requirements that will be imposed under the Rule. EPA should implement a five-year look-back period to provide representative heat input data from which to calculate emissions. Five years provides an adequate period of evaluation to accommodate variation in utilization. In addition, a five-year look-back is consistent with other data evaluation regulations under the Clean Air Act such as the New Source Review regulations. [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.8]
EPA failed to make heat input adjustments in calculating SO2 emissions in contravention to the recognized need to make adjustments. Thus, the SO2 emissions used to calculate state budgets and then individual allocations are not representative under EPA's own view. This leads to inconsistent regulatory results and a flawed basis for SO2 state budgets and consequent individual unit allocations. [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.8]
Adjusted reported emissions should include emissions for units that lawfully operate yet are not required to report to the Clean Air Markets Database [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.8]
The state budgets are based on the lesser of the State's adjusted projected emissions and its adjusted reported emissions. Reported emissions were gathered from units that report to the Clean Air Markets database; however, the Rule applies to individual units that are not required to report to the Clean Air Markets database. Consequently, a state's adjusted reported emissions does not account for emissions from units not included in the Clean Air Markets database regardless if the units were in operation during the relevant time period. Units lawfully operating yet not required to report to the Clean Air Markets database received zero allocations in Appendix A to the TSD accompanying the Rule. [EPA-HQ-OAR-2009-0491-3750.1_NODA, pp.8-9]
BPU has three units at its Quindaro plant, GT1, GT2 and GT3 and one unit, CT4, at its Nearman plant that received zero allocations in Appendix A to the TSD. All of these units operated under authorization of Clean Air Act permits during the relevant time period for consideration in the Rule and NODA and will continue to operate. The units are not required to report emissions on the Clean Air Markets database and the state of Kansas was not included in the NOx SIP Call. Failure to provide allocations for these units cannot be supported under applicable law including the Clean Air Act and implementing regulations. [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.9]
NODA does not contemplate enforceable NOx reductions from additional emissions controls [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.9]
The IPM data included in the NODA fails to include NOx reductions from the addition of low NOx burners at BPU's Quindaro Unit 2 and Nearman Unit 1. Pursuant to Section 28-19-713 of the Kansas Administrative Regulations, BPU is required to achieve NOx reductions at Quindaro Unit 2 to 0.20 lb/mmBtu by January 1,2012 and reductions at Nearman Unit 1 to 0.26 lb/mmBtu by July 1,2012. BPU believes EPA should have accounted for such reductions in the NODA model runs. Such reductions would minimize the contribution of these units to attainment and maintenance in downwind states and therefore should have been included in the IPM projections. [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.9]
For the reasons stated herein, BPU requests that EPA recalculate state budgets and individual unit allocations using the revised IPM projections included in the NODA and incorporate the following modifications in the recalculation: [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.10]
1. Recalculate significant contribution and state budgets/individual unit allocations using the revised IPM modeling from the NODA; [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.10]
2. Recalculate SO2 emissions based on heat input adjustments; [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.10]
3. Use a five-year look-back period when adjusting heat input for reported NOx and SO2 emissions; and [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.10]
4. Provide Appendix A allocations for units not required by law to report to the Clean Air Markets database. [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.10]
[See p.14 of this comment summary for Attachment 1 entitled, Annual SO2]
Kansas City Power and Light Company (KCP&L)
Comments on EPA Base Case v.4.10
1. In Base Case v.4.10, EPA has provided two IPM scenarios, one including the AEO Gas module and one without. EPA does not state which set of runs will be used, and there are significant differences between the results for individual units. EPA should state its intent so that comments may be focused on one scenario or the other. [EPA-HQ-OAR-2009-0491-2709.1, p.7] [EPA-HQ-OAR-2009-0491-3757.1_NODA, pp.3-4]
2. There are errors in the unit information contained in the NEEDS v.4.10 database.
a. The Iatan Unit 1 wet scrubber and baghouse not included (this is identified in EPA's Planned Updates to IPM v.4.10).
b. The SNCR for Sibley Units 1 and 2 is not included, nor is the SCR for Sibley Unit 3 (this is identified in EPA's Planned Updates to IPM v.4.10)
c. SO2 Emission Rates
i. The SO2 permit rate for Iatan Unit 1 should be 0.07 lb/MmBtu, per the current Title V operating permit, instead of 1.2 lb/MmBtu.
ii. The SO2 permit rate for Lake Road Unit 6 should be 1.43 lb/MmBtu, per the current Title V operating permit, instead of 8.6 lb/MmBtu. [EPA-HQ-OAR-2009-0491-2709.1, pp.7-8] [EPA-HQ-OAR-2009-0491-3757.1_NODA, p.4]
d. NOx Emission Rates
i. Mode 1 Uncontrolled NOx Base Rates
(1) Hawthorn Unit 5A has a rate of 0.0714 lb/MmBtu, which is clearly with the SCR online. This is incorrect, as Mode 1 should represent the uncontrolled emission rate. This unit has never reported uncontrolled emissions, and it operates the SCR year-round, so it is not clear how EPA would obtain an uncontrolled emission rate.
(2) The rate of 0.5103 lb/MmBtu for La Cygne Unit 1 (ID 1241_B_1) is incorrect. That unit began operating an SCR on June 1, 2007. The SCR operates year-round in order to meet the unit's construction permit limit of 0.15 lb/MmBtu. An appropriate uncontrolled rate for Unit 1, taken from 2006 (pre-SCR) ARP reported data, would be 0.94 lb/MmBtu. [EPA-HQ-OAR-2009-0491-2709.1, p.8] [EPA-HQ-OAR-2009-0491-3757.1_NODA,p.4]
ii. Mode 2 Controlled NOx Base Rate
(1) For Hawthorn Unit 5A, the rate of 0.06 lb/MmBtu may or may not be correct depending on the resolution of 2.d.i.(1) above. It should be the lesser of [0.1* the correct Uncontrolled NOx Base Rate] or 0.06 lb/MmBtu.
(2) For La Cygne Unit 1, the rate of 0.06 lb/MmBtu is incorrect. Using the Mode 1 rate and 90% removal efficiency yields 0.094 lb/MmBtu, which is greater than the floor rate of 0.06 lb/MmBtu. According to EPA's methodology, the Mode 2 rate equals the lesser of 0.094 and the ETS summer NOx rate, which for this unit is 0.30 lb/MmBtu. Therefore, the Mode 2 NOx rate for La Cygne Unit 1 should be 0.094 lb/MmBtu. [EPA-HQ-OAR-2009-0491-2709.1, p.8][EPA-HQ-OAR-2009-0491-3757.1_NODA,p.4]
iii. Mode 3 Uncontrolled NOx Policy Rate
(1) The rate of 0.5103 lb/MmBtu for La Cygne Unit 1 is incorrect. Because Mode 3 = Mode 1 for units with SCR post-combustion NOx control, this rate is also incorrect and should be 0.94 lb/MmBtu.
(2) The rate of 0.23 lb/MmBtu for La Cygne Unit 2 (ID 1241_B_2) appears to have been calculated using the equations in Table 3-1.3 of Appendix 3-1, but that is incorrect. La Cygne Unit 2 is a coal unit without post-combustion NOx controls. Regardless of whether or not it has combustion controls, the Mode 1 rate is less than the cutoff rate in Table 3-1.2. It therefore has SOA control and its Mode 3 rate is determined per Step 5 (see Appendix 3-1.2 and 3-1.3). The summer NOx rate is less than the provisional SOA NOx rate, so the Mode 3 rate should be equal to the summer NOx rate.  The 2007 ozone season rate was 0.30 lb/MmBtu. [EPA-HQ-OAR-2009-0491-2709.1,pp.8-9][EPA-HQ-OAR-2009-0491-3757.1_NODA, pp.4-5]
iv. Mode 4 Controlled NOx Policy Rate
(1) For La Cygne Unit 1, Mode 4 = Mode 2. The Mode 4 rate should be corrected to 0.094 lb/MmBtu per 2.d.ii.(2) above. [EPA-HQ-OAR-2009-0491-2709.1, p.9] [EPA-HQ-OAR-2009-0491-3757.1_NODA, p.5]
2 EPA has not provided the necessary data to allow meaningful comment on the data provided in the NODA and the docket omits much of the information necessary to evaluate the nature and extent of the likely changes to the Proposed Transport Rule ("PTR"). In support of the PTR, EPA provided the results of 48 IPM runs, which provided at least some basis for evaluating and commenting on the various steps in EPA's process of developing unit-specific allowance allocations. [EPA-HQ-OAR-2009-0491-3757.1_NODA, p.2]
Due to its decision to apply the revised inventory and model as the last step in its methodology in developing a final rule, EPA provided in the NODA only a fraction of the IPM runs necessary to allow electric utilities to understand and comment on the impact of the NODA on unit-specific allocations as well as to attempt to replicate EPA's methodology for determining such allocations. Utilities therefore have no way of predicting what their allocations will be or to verify that the allocations contained in the final rule are appropriate.  [EPA-HQ-OAR-2009-0491-3757.1_NODA, p.2]
In the PTR, the information contained in the "Allocation Table  -  Technical Support Document for the Transport Rule  -  State Budgets, Unit Allocations, and Unit Emission Rates" provided electric generating companies at least some ability to evaluate the accuracy of EPA's assumptions with respect to their individual units. Such tables were not provided to account for the changes contained in the NODA.[EPA-HQ-OAR-2009-0491-3757.1_NODA, p.2]
This lack of IPM data also makes it impossible for even the states themselves to determine the revised 2012 statewide annual emissions budgets for SO2 and NOx and the seasonal budgets for NOx based on EPA's updated NEEDS database and revised platform because, as stated in the "State Budgets, Unit Allocations, and Unit Emission Rates" ("State Budgets") TSD, the 2012 budgets are based on the lower of the recent actual emissions or the 2012 IPM-projected base case emissions at the state level. Without a revised 2012 IPM-projected basis, there is no means of comparison to the actual data to determine which scenario results in lower state-wide emissions. [EPA-HQ-OAR-2009-0491-3757.1_NODA, pp.2-3]
3. EPA's decision to base the 2014 SO2 allowance allocations for units in Group 1 states on the same statewide caps proposed in the PTR is arbitrary and unjustified, given that the purpose of the NODA was to correct and update unit level input data in NEEDS v.4.10. EPA has not provided justification for not providing an updated "TR SO2 2000" IPM run using the updated NEEDS database and IPM modeling platform. [EPA-HQ-OAR-2009-0491-3757.1_NODA, p.3]
EPA's decision to re-run the Limited Trading unit-level parsed file for 2014 with the revised NEEDS database and updated IPM platform while leaving state budgets based on the unrevised data used in the PTR results in an incorrect state budgets and therefore incorrect unit-level allocations. [EPA-HQ-OAR-2009-0491-3757.1_NODA, p.3]
4. EPA continues to ignore the effects of CAIR, even though it remains binding law until it is replaced by a valid rule. EGUs, even in states covered by CAIR but that may not be regulated under the Transport Rule, have already made emissions reductions pursuant to CAIR and it is not certain that they will increase their emissions to pre-CAIR levels, or it if will even be legal for them to do so, once CAIR expires. [EPA-HQ-OAR-2009-0491-3757.1_NODA, p.3]
5. Even EPA, by issuing the Planned Updates to IPM v.4.10 Technical Support Document (TSD), has identified the need for further refinement of the IPM input data. The regulated community should have an additional opportunity to review and comment on the changes once they have been made. [EPA-HQ-OAR-2009-0491-3757.1_NODA, p.3]
Kansas Department of Health and Environment
It is unclear how the new IPM runs will affect the cost curves as this was not discussed in the NODA issued on September 1, 2010. KDHE recommends future rulemakings include the latest data for all aspects of the rule so stakeholders can comment on one set of data that affect various parts of the rule and the underlying decisions therein. [EPA-HQ-OAR-2009-0491-2606.1, p.7]
One large concern that KDHE has on the rulemaking process, and our ability to effectively comment, concerns the late arrival of additional data coupled with a virtually overwhelming amount of technical data and documentation on this proposed rule. Providing the NODA at such a late date is useful for better understanding what final emissions might be, but at the same time it makes the CAMx modeling and allocations obsolete as there is now a large disconnect between the CAMx modeling and underlying emissions along with questions on what the final allocations may look like in light of this new data. KDHE recommends in future rulemaking that EP A provides the latest inventory data and modeling concurrently so all stakeholders can effectively comment and review the entire package without wasting precious resources reviewing data that is changed midcourse in the review process. [EPA-HQ-OAR-2009-0491-2606.1, p.8]
Response:
EPA has responded to the above concerns through two primary changes in its final Transport Rule analysis.
First, EPA finalized an allocation methodology that is based on unit level historic, not projected, data.  This addresses the significant body of public comment expressing concern over the IPM unit level projections and their impact on unit level allocations.  See section VII.D of the preamble for more discussion on the final allocation approach under a FIP.
Second, EPA has made significant updates to its IPMv.4.10 model based on comments received in both the Transport Rule and NODA1 comment periods.  These changes include unit level changes (e.g., updating the SCR and SNCR status at Sibley units per commenters corrections) and more universal updates (e.g., including constraints to reflect Section 28-19-713 of the Kansas Administrative Regulations per commenters corrections).  These types of updates improved the models representation of EGUs.  EPA conducted all of its final rule air quality and multi-factor analysis using values provided  by this updated IPM.v4.10 model.  See EPA IPMv.4.10 documentation and the RTC Appendix for further discussion on IPM assumptions and updates made in response to comments.
EPA's decision to base the 2014 SO2 allowances in the NODA3 on the same caps as those that were proposed was not arbitrary as those budgets reflected EPA's best available data at the time.  At the point of issuing the NODA3, EPA had not determined the final Transport Rule geography nor had it redone budget analysis with the IPMv.4.10 model.  Furthermore, as EPA pointed out in the NODA3, the intention of the NODA was to provide the public with final allocations, but to demonstrate the new methodologies, the underlying data that would be part of those allocation approaches, and the percentage of state budgets that would be allocated to a source under that alternative approach.  The NODA3 provided commenters the opportunity to review and comment on each of these inputs to the final allocation methodology.  For the final allocation methodology, EPA was able to review the significant body of public comment received on the allocation alternatives and corrections to underlying data, and appropriately incorporate those comments.
In regards to comments received suggesting a longer comment period, supplemental proposal, re-proposal of the Transport Rule, EPA feels that it provided reasonable comment periods for the TR proposals and subsequent NODAs.  Furthermore, EPA made materials available to the public through its website before each comment period began.  This had the effect of adding additional time beyond the stated comment period for review, effectively extending the stated 30, 45, or 60 day comment period.  Furthermore, the Court did not specify a definitive date by which EPA should promulgate the Transport Rule, it did not give the Agency an infinite stay on CAIR and did, in fact, indicate that the Transport Rule was to be completed in a timely manner.  Section 307(d)(5) of the CAA requires the Administrator to give an opportunity for written or oral comments.  The Act does not specify the length of time, other than the record must be open 30 days after holding public hearings - with which EPA complied.  Given the time frame EPA provided to the public for submission of comments, and indicative of the fact that the Agency received several thousand substantive comments, commenters did, in fact, have sufficient time to submit their comments for consideration.  Section XVII of this RTC document addresses these comments more thoroughly.
Organization: Midwest Ozone Group
Utility Air Regulatory Group (UARG)
Wisconsin Power and Light Company
New York Power Authority
Rochester Public Utilities (RPU)
Minnesota Power
Greenmont Energy Consulting LLC.
Connecticut Department of Environmental Protection
New York State Department of Environmental Conservation
Tennessee Valley Authority (TVA)
Southern Company
NRG Energy
State of Ohio Environmental Protection Agency (Ohio EPA)
Comment:
Connecticut Department of Environmental Protection
CTDEP offers current, quality controlled data to replace out-of date or inaccurate information for certain Connecticut units. CTDEP also offers corrections to the statutory and regulatory information used in preparing the base case modeling. These inaccuracies in data and assumptions are compounded by the inherent limitations of the Integrated Planning Model (IPM) in projecting unit-level operations in small geographic areas such as the State of Connecticut. The issues of concern, more fully described below, must be corrected for the Transport Rule to function as intended and protect public health within Connecticut. [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.1]
I. DOCUMENTATION FOR EPA BASE CASE V. 4.10, CHAPTER 3, POWER SYSTEM OPERATION ASSUMPTIONS
Appendix 3-2 State Power Sector Regulations included in EPA Base Case v. 4.10
NOx - The 'Emission Specifications' field states that a 0.15 lbs/MmBtu annual rate limit applies for all fossil electric generating units > 15 MW. However, the 0.15 lbs/MmBtu limit specified in Regulations of Connecticut State Agencies (RCSA) section 22a-174-22 (Control of NOx) is a non-ozone season limit (from October 1 through April 30, inclusive), not an annual limit. The non-ozone season NOx limit does not apply to fossil-fired units unless the units are subject to both RCSA section 22a-174-22 and the NOx Budget Program.! The Environmental Protection Agency (EPA) should revise the 'Emissions Specifications' field as follows: [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.1]
Emission Specifications: 0.15 lbs/MmBtu non-ozone season rate limit (October 1 through April 30, inclusive) for all sources subject to RCSA section 22a-174-22 that are also NOx Budget Program sources. [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.1]
SO2: The 'Bill' field states that the relevant legal references are Executive Order 19, RCSA 22a-198 and Connecticut General Statues (sic) (CGS) 22a-198. However, the correct regulatory references are RCSA section 22a-174-19a and Connecticut General Statutes section 22a-198. Executive Order 19 directed CTDEP to adopt regulations and laid out the framework for the requirements but did not apply directly to sources, so the reference to it should be deleted. In addition, the 0.33 lbs/MmBtu rate referenced in the 'Emission Specifications' field is a quarterly rate instead of an annual rate, and the 0.33 lbs/MmBtu rate only applies to Title IV sources that are also equal to or greater than 15 MW or equal to or greater than 250 MmBtu/hr. As alternatives, sources can combust fuel with a fuel sulfur limit of equal to or less than 0.3% sulfur or can average and meet a quarterly emission rate of 0.3 lb/MMBtu.2 For fossil fuel-fired sources equal to or greater than 15 MW or equal to or greater than 250 MmBtu/hr that are not Title IV sources, a 0.55 lb/MmBtu emission rate applies starting January 1, 2002 (as alternatives, sources can combust fuel with a fuel sulfur limit equal to or less than 0.5% sulfur or can average and meet a quarterly emission rate of 0.5 lb/MmBtu). [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.2]
EPA should revise the Bill, Emission Specifications and Implementation Status fields as follows: [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.2][[See Docket Number EPA-HQ-OAR-2009-0491-3715.1_NODA, pp.2-3 for the revisions.]]
Mercury (Hg) -The 'Bill' field references RCSA 22a-198, however the correct statutory reference is CGS section 22a-199. The reference to Public Act No. 03-72 should be removed since it was codified in CGS section 22a-199. In addition, the 'Emission Specifications' field includes incorrect emission limit information. EPA should revise the 'Bill' and 'Emissions Specifications' fields as follows: [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.3]
Bill: CGS section 22a-199
Emissions Specifications: (A) Meet an emissions rate of equal to or less than 0.6 pounds of mercury per TBtu, or (B) meet a mercury emissions rate equal to a ninety per cent reduction of mercury from the measured inlet conditions for the affected unit, whichever emissions rate is more readily achievable by such affected unit. [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.3]
II. TR 2012 BASE-CASE V 4.10 IPM RUN
As explained in CTDEP's comments on the Transport Rule submitted on September 30, 2010, the IPM Base Case model run for 2012 projects that the 9 oil/gas load following boilers (LFBs) in Connecticut will not operate in 2012. However, all 9 LFBs have already bid into the ISO-NE Forward Capacity Market through May 2013 and are contractually obligated to be available through that date, making it highly unlikely that they will cease operations by 2012. Furthermore, 8 of the 9 LFBs are contractually obligated to be available in the Forward Capacity Market through May 2014. Only Bridgeport 2 is not contractually obligated through May 2014. CTDEP recommends that EPA consider the Integrated Resource Plan model results (see Attachment C of CTDEP's September 30, 2010 Transport Rule comments) and contractual obligations of the LFBs and revise the IPM model results accordingly. [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.3] [[See Docket Number EPA-HQ-OAR-2009-0491-2780.1, pp.26-367 for Attachment C.]]
III. NEEDS V. 4.10
The items described below are also highlighted or changed in red in the spreadsheet in Attachment A: [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.3][[see Docket Number EPA-HQ-OAR-2009-0491-3715.2_NODA for Attachment A.]]
Peaking unit NOx rates
NEEDS v. 4.10 includes either a 0.1490 lb/MmBtu NOx rate (all four modes) or a 1.2 lb/MmBtu default rate (all four modes) for the following units: [EPA-HQ-OAR-2009-0491-3715.1_NODA,p.4] [[See Docket Number EPA-HQ-OAR-2009-0491-3715.1_NODA, p.4 for the table.]]
Presumably, the 0.1490 lb/MmBtu emission rate is from the non-ozone season restriction of 0.15 lbs/MmBtu in RCSA section 22a-174-22. However, with the exception of the Cos Cob units, these units are not controlled. All units have actual emission rates higher than 0.:1490 lb/MmBtu and with the exception of the Cos Cob units, higher than 75 ppmvd (24-hr limit}. These units do not have continuous emissions monitors, so the actual emission rates provided in Table 1 are from emissions test data. All of the units currently comply with permitted and/or regulatory limits by operating under Trading Agreements and Orders (see Attachment B} that allow the sources to purchase NOx discrete emission reduction credits and/or NOx allowances through May 31, 2014. The Trading Agreements and Orders set the framework by which the owners and operators of the peaking units will assess energy market conditions and current and planned environmental restrictions in order to determine operational status beyond May 31, 2014. CTDEP recommends that EPA revise NEEDS v. 4.10 to reflect the actual emission rates of the turbines in Table 1.[EPA-HQ-OAR-2009-0491-3715.1_NODA, p.5]
Kleen Energy
NEEDS v. 4.10 lists the on-line year of the two combined cycle turbines at Kleen Energy as 2008. However, Kleen Energy has not started operating yet, and will not likely begin operating until at least mid-2021. CTDEP recommends that EPA change the on-line year for gleen Energy in NEEDS v. 4.10 from 2008 to 2011 and the ORIS plant code from 56798 G to 56798 C. [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.5]
Unlisted existing/committed units
There are several existing and committed units that are not listed in NEEDS v. 4.20. CTDEP recommends that EPA include the units listed on Attachment A to NEEDS v. 4.10. [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.5]
SO2 Emission rates for Covanta Bristol Energy, Covanta Wallingford Energy and Wheelabrator Lisbon
The SO2 emission rates listed in NEEDS v. 4.10 for Covanta Bristol Energy (units 1 & 2), Covanta Wallingford Energy (units 101-103) and Wheelabrator Lisbon (BW1 & BW2) are 0.5S lb/MmBtu, 0.55 lb/MmBtu and 0.3 lb/MMgtu, respectively. However, the permitted SO2 emission rate for all of the units is 29 ppmvd, or 0.07 lb/MmBtu. CTDEP recommends that EPA revise the SO2 emission rates for all of the Covanta Bristol Energy, Covanta Wallingford Energy, and Wheelabrator Lisbon units to 0.07 lb/MmBtu.
NOx combustion control for Bridgeport Energy Project, Milford Power, Wallingford Energy, Kleen Energy, Waterside Power and Algonquin Windsor Locks
NEEDS v. 4.10 does not list NOx combustion control for the Bridgeport Energy turbines. The turbines have low NOx burners and water injection for NOx controls. NEEDS v. 4.10 lists dry low NOx Burners (with water injection for Wallingford Energy and Kleen Energy) for Milford Power, Wallingford Energy and Kleen Energy for NOx controls, but NOx controls consist of regular low NOx burners. All of Waterside Power's turbines have water injection, but unit 7 in NEEDS v. 4.10 does not have water injection listed as a NOx control. Algonquin Windsor Locks has ammonia injection for post-combustion NOx control, but it is not listed in NEEDS v. 4.10. CTDEP recommends that EPA revise NEEDS v. 4.10 with the correct NOx controls. [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.5]
Committed units to be removed
EPA lists 2 committed units, a 24 MW combined cycle unit and a 100 MW combustion turbine that EPA should remove from NEEDS v. 4.10. The 200 MW combustion turbine may be Waterbury Generation that is separately listed as an additional unit and CTDEP does not have knowledge of a 24 MW combined cycle unit that has started construction or secured financing to ensure start-up prior to the end of 2011. [EPA-HQ-OAR-2009-0491-3715.1_NODA, pp.5-6]
Covanta Mid-CT Energy, units 11-13 mercury controls efficiencies
The mercury controls efficiency column entries for Covanta Mid-CT Energy, units 11-13 are blank but the units have permitted mercury controls efficiencies of 85%. CTDEP recommends that EPA add the appropriate mercury controls efficiencies for Covanta Mid-CT Energy, units 11-13.  [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.6]
Waterside Power, LLC, unit 7 modeled fuels
Distillate fuel oil is the only modeled fuel listed for Waterside Power, LLC's unit 7. However, the unit is also permitted to burn natural gas. CTDEP recommends that EPA add natural gas as a modeled fuel for Waterside Power, LLC, unit 7.  [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.6]
John Street 1 & 2 and Cytec 1 & 2 NOx limits and controls
The John Street 1 & 2 and Cytec 1 & 2 units were issued revised permits in 2008. The NOx limit in the old permits was 2.67 lb/MMgtu. The NOx limit in the new permits is 0.27 lb/MmBtu. All of the units installed SCR for NOx control. Although NEEDS v. 4.1 is based on 2007 data, comments were added to the spreadsheet regarding the revised permit limits and NOx controls so that EPA may make updates in future versions of NEEDS. [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.6]
Bushranger Ingelheim and CMEEC 8 on-line years
NEEDS v. 4.10 lists 2011 as the on-line year for Boehringer Ingelheim and CMEEC 8. However, both units started operating in 2008. [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.6]
CTDEP urges EPA to make the changes recommended in this letter. Previously, CTDEP has expressed significant concerns to the EPA about the IPM and its documented inability to accurately project unit level operations in smaller states such as Connecticut. It is CTDEP's expectation that EPA's incorporation of the recommended changes will improve the accuracy of the modeling used for the final Transport Rule. [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.6]

1. NOx Budget Program units are fossil fuel-fired stationary sources serving a generator with a nameplate capacity of 15 MW or greater or a fossil fuel-fired boiler or indirect heat exchanger with a maximum heat input capacity of 250 MmBtu/hr or more. [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.1]
2 RCSA section 22a-t74-19a(e), Sulfur dioxide emissions standards and fuel sulfur limits effective on and after January I, 2003. Notwithstanding the provisions of subsection (b) of this section, this subsection shall apply, on and after January 1, 2003, to the owner or operator of a Title iV source that is also an affected unit or units. On and after January 1, 2003, such owner or operator shall: (1) Combust liquid fuel, gaseous fuel or a combination of each provided that each fuel possess a fuel sulfur limit of equal to or less than 0.3 % sulfur, by weight (dry basis); (2) Meet an average emission rate of equal to or less than 0.33 pounds SO2 per MmBtu for each calendar quarter for an affected unit at a premises; or (3) Meet an average emission rate of equal to or less than 0.3 pounds SO2 per MmBtu calculated for each calendar quarter, if such owner or operator averages the emissions from two or more affected units at a premises. [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.2]
3. RCSA section 22a-174-19a(c), Sulfur dioxide emission standards and fuel sulfur limits effective on and after January 1, 2002. On and after January 1, 2002 and except as provided in subsection (f) of this section, the owner or operator of an affected unit or units shall: (1) Combust liquid fuel, gaseous fuel or a combination of each provided that each fuel possess a fuel sulfur limit of equal to or less than 0.5 % sulfur, by weight (dry basis); (2) Meet an average emission rate of equal to or less than 0.55 pounds SO2 per MmBtu for each calendar quarter for an affected unit at the premises; or (3) Meet an average emission rate of equal to or less than 0.5 pounds SO2 per MmBtu calculated for each calendar quarter, if such owner or operator averages the emissions from two or more affected units at the premises. [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.2]
Greenmont Energy Consulting LLC.
My analysis shows that the Integrated Planning Model (IPM), which is used in the various modeling run cases made public by EPA, has numerous problems which make it unreliable as a predictor of future industry and market impacts and is therefore inconsistent with the 'Objectivity' guideline of the federal 'Data Quality Act' as promulgated by the Office of Management and Budget. Based on my many years of experience and study, it is my opinion that the disseminated data generated by IPM for this purpose is not presented in a manner that is accurate, clear, complete and unbiased; neither is it accurate, reliable and unbiased in a matter of substance. [EPA-HQ-OAR-2009-0491-3713.1_NODA, p.1]
The following are deficiencies in the Integrated Planning Model (IPM):
- IPM's use of 'prototype' plants on the demand side and 'prototype' mines on the coal supply side of the modeling does not provide sufficient specificity to determine reliable forecasts.
- IPM does not approach the exploitation of existing coal mines in the appropriate way because of the manner in which IPM handles the use of mining cost curves to provide coal supply. [EPA-HQ-OAR-2009-0491-3713.1_NODA, p.1]
- IPM uses overly simplified coal transportation cost estimates which are often not representative of the actual cost of movement of coal to specific coal-fired plants and therefore result in incorrect economic decision-making in the model.
-IPM does not solve in an integrated manner of simultaneously considering the variation of several key variables, but rather runs separate 'modules' in a looping fashion which often leads to a failure of the composite to 'converge' to the correct optimal solution.
- IPM does not adequately account for all of the driving forces behind increases and decreases in allowance prices under a cap and trade system.  [EPA-HQ-OAR-2009-0491-3713.1_NODA, p.2]
For these reasons, it is my opinion that the data upon which EPA relied in proposing its regulations is unreliable. [EPA-HQ-OAR-2009-0491-3713.1_NODA, p.2]
Midwest Ozone Group
In the September 1, 2010 NODA, EPA gives notice that it has placed additional information that EPA admits is 'relevant' to the proposed Transport Rule, including 'an updated version of the power sector modeling platform that EPA proposes to use to support the final rule.' 75 Fed. Reg. 53,613/1. The additional information is voluminous and consists of at least thirty-four files, some of which are large 'zipped' files, and totals over 3,000 pages. Most importantly, and as EPA acknowledges in the NODA the additional information '[c]hanges ... the projections relied on in the proposed [Transport Rule]'. Id. at 53,614/3. The projections form the foundation for EPA's determining the upwind states to be covered by the final rule and the amount of emissions reductions to be required by those states in the final rule. [EPA-HQ-OAR-2009-0491-1921.1, p.2]
The changes are not minor, technical corrections. In EPA's own words:
Changes from the projections relied on in the proposed rule, from using an updated model, could impact the final rulemaking in a number of ways including, but not limited to:
1. Changing emissions projections that were used to determine which downwind areas have air quality concerns (i.e., non-attainment or maintenance) absent this rulemaking and to determine which States contribute to those problems.
2. Changing cost and emission projections used in the multi-factor test to determine the amount of emissions that represent significant contribution. Id. at 56,314/3. [EPA-HQ-OAR-2009-0491-1921.1, p.2]
MOG recognizes that EPA has established a separate comment period for its "Notice of Data Availability Supporting Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone; Notice of Data Availability (NODA) for the Proposed Transport Rule," published September 1, 2010 (75 Fed. Reg. 53,613). MOG is reviewing the NODA at this time and will offer comments by the established deadline. [EPA-HQ-OAR-2009-0491-2809.1, p.2]
MOG also notes that the NODA deals mainly with the allocation process. MOG believes that allocations should be reserved to the affected states. At most, MOG believes that EPA might establish state specific emissions caps, but the allocations of those emissions within the cap should be done at the option of the individual states, not EPA. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.cover page 1]
The comment period on the NODA is arbitrarily and unreasonably short and MOG joins many others in requesting that EPA reopen the comment period, allowing a reasonable comment period and providing supporting technical documents that were not made available to the public as part of the NODA. It is impossible based on the short comment period allotted and the lack of supporting data for anyone to make meaningful comments on either the NODA or the CATR. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.cover page 1]
With respect to the IPM projections, Mr. Marchetti concludes that there are major significant modeling disconnects between the CATR and the NODA, including errors in specific unit emission rates, mistakes in projected unit retirements, disparities in installed SCR and FGD capacity between the CATR and NODA, suspect allowance pricing assumptions, erroneous and arbitrary assumptions regarding availability of new pulverized coal and wind capacity and erroneous NODA base case emissions. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.cover page 2]
General Comments on the NODA [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.2]
The NODA was released in the middle of the comment period on the Proposed Transport Rule (TR), at which time EPA announced a new modeling platform IPM version 4.10. The information in the NODA is both voluminous and substantially different (e.g., new generation forecast, revised control assumptions) from the information used in the TR. EPA has provided only a 45 day comment period on the NODA, which ran concurrently with the comment period on the TR, ending a mere 14 days after the comment period for the TR. As a result EPA has failed to provide adequate time for commenters to review this large body of new information and provide meaningful comments. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.2]
Unlike the TR, EPA failed to provide any Technical Support Documents (TSDs) on the NODA, which are critical in understanding the new modeling platform, specifically in regard to unit allowance allocations. Without this type of information, electric generators are unable to thoroughly identify and assess errors and inaccuracies and evaluate how those errors and inaccuracies should be corrected, and are left to guess what these values will be under the NODA [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.2]
EPA Should Provide Proposed Revised Unit Allocations [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.2]
In the NODA, EPA indicated the information and assumptions in the documents issued with the NODA will be the information and assumptions used in a new modeling platform (4.10) that will be used to develop the final rule. As pointed out by EPA, there are significant modeling changes to IPM in version 4.10, in comparison to the modeling information used in the TR. For example, EPA used a different electrical generation forecast in version 4.10 in comparison to the TR. As mentioned earlier, version 4.10 incorporated the electrical generation forecast from EIA's Annual Energy Outlook 2010 (AE020 I0); whereas, the TR modeling used AEO 2008. As shown in the figure below [see p.3 of this comment summary for Figure 1 entitled, Forecasted National Generation: AEO 2008, 2009 & 2010], there are significant differences between the two forecasts. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.2]
The primary underlying factor impacting these generation forecasts is the economic recession of 2009. AEO 2008 was completed (January 2008) prior to the economic events beginning in late 2008, while the modeling for AEO 2010 includes data from the recession and reflects the effects of economic downturn in its electrical generation forecast. Since the 2014 SO2 allocations are based upon forecasted heat input and emissions it is critical that EPA provide information on how the incorporation of this new generation forecast, along with changes in other assumptions, will impact 2014 SO2 unit allocations. This will allow electric generators to compare their allocations under the TR and NODA and be able to more thoroughly identify and assess errors and inconsistencies. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.3]
Potential Implications for 2014 Allocations in Using AEO 2010 and Modeling Outputs [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.3]
As indicated earlier, the forecasted electrical generation from AEO 2010 is significantly lower than AEO 2008. A major consequence of using a lower generation forecast is that on the whole, units will have lower heat input, which is a major component in the computing of 2014 unit SO2 allocations for Group 1 States. To assist in analyzing the NODA modeling we used two electric generating unit data sets and they are: (i) Ameren's electric generating units in Illinois; and, (ii) AEP's electric generating units in West Virginia. The primary purpose of using these two data sets is to identify and track potential errors and modeling inconsistencies with regard to the NODA, which might be prevalent throughout EPA's modeling. The two parsed files that were the focus of this initial evaluation are: (i) the Proposed Transport Rule (TR) 2014 TR_SB_Limited Trading file; and, (ii) the NODA's 2014 TR_SB_Limited Trading file. [EPA-HQ-OAR-2009-0491-3746.1_NODA, pp.3-4]
Using Ameren's Illinois and AEP's West Virginia units as examples and replicating EPA's 2014 SO2 allocation methodology using the NODA file 2014 TR_SB_LT and the same 2014 state budgets as the TR, it was found that both systems could experience a significant decrease in their 2014 SO2 allocations primarily due to changes in projected heat input, as well as some modeling outputs. The modeling concerns relate to some changes in technology deployment/retirements and SO2 emission rates between the Transport Rule's 2014 TR_SB_LT parsed file and the NODA 2014 TR_SB_LT parsed file. Many of these changes seem to be attributable to modeling disconnects and/or data base errors which are discussed later. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.4]
[See p.4 of this comment summary for Table 1 entitled, Comparison of 2014 Heat Input and SO2 Allocation - Transport Rule and NODA]
EPA use of modeled projections for individual unit utilization and emission reduction capability, as a basis for permanent unit allocations will result in gross inequities in the allocation of allowances. To avoid these types of allocation issues, it is recommended that EPA use a historical time series based upon heat input, similar to the CAIR NOx allocation methodology to allocate unit allowances. This historical time series can be adjusted every year based upon new operating information. The use of historical data better reflects how a unit has actually operated instead of some future projection, which is based upon assumptions related to future operation and technology deployment. Consequently, the use of historical information avoids many of these pitfalls. In addition it is also recommended that the states handle the unit allocations, as they do in CAIR NOx. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.4]
Modeling Disconnects between the Proposed Transport Rule and the NODA [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.5]
In an attempt to better understand the modeling information presented in the NODA, two parsed files were examined and compared and they were: (i) TR's 2014 TR_SB_LT (2014) parsed file for SO2 and NOx; and, (ii) the NODA's 2014 TR_SB_LT (2014) parsed file for SO2 and NOx. To undertake the SO2 analysis, the same two data sets - Ameren - IL and AEP - WV - were used to highlight these modeling disconnects and data base errors. As shown in Table 2 [See p.6 of this comment summary for Table 2 entitled, SO2 Modeling and Data Issues - Transport Rule and the NODA], several modeling issues have been identified. If analysis of small data sets like these has identified several problems, there is a major concern that these same types of issues exist throughout the entire modeling results of the NODA. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.5]
In the TR 2014 Joppa 1 - 6 is retrofitted with an FGD; however, in the NODA 2014 the unit is retired. In addition, the Joppa units in NODA 2014 have SO2 emission rates comparable to a retrofitted FGD; however, their heat input is 84 percent less than TR 2014 heat input due to a projected retirement in 2014. (The parsed file seems to indicate the Joppa units are projected to be retired sometime during 2014.) It should be noted Ameren does not have any plans to retire Joppa by 2014. Moreover, in any event, it does not seem logical that a unit, which is a candidate for an FGD in one simulation, is retired in another simulation. Understanding there are changes in control cost assumptions, which may make a retrofit uneconomical, it would seem more plausible that the Joppa units be treated like Meredosia 3 and be economical to operate in NODA 2014 without an FGD. NODA 2014 modeling does retire almost 3,000 MW of FGD capacity that was retrofitted under TR 2014. Some of this retired capacity is under agreements with either EPA or a state to retire, repower or retrofit by a specific date. If this is the case EPA needs to identify these units in the NEEDS Data Base 4.10 that they are candidates for retirement. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.5]
Another modeling/data base disconnect relates to the Kammer units. In TR 2014 the three units are retrofitted with FGD systems (even though AEP does not have plans to install FGD systems on any of these units); however, in NODA 2014, Kammer 1 and 2 have existing FGD systems, which is incorrect. There are no existing FGD systems on either Kammer 1 and 2. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.5]
There also seem to be some unusual emission rate differences between the two parsed files, specifically units with an FGD system. For example Duck Creek's SO2 emission rate moves from 0.133 in TR 2014 to 0.295 in NODA 2014, and the Philip Sporn units' emission rate more than doubles. These radical changes in SO2 emission rates seem to indicate some kind of modeling error. Also, it seems the 0.087 SO2 emission rate for an FGD is some kind of default value; EPA should explain whether and why that is the case. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.5]
In evaluating NOx, the NODA modeling seems to have applied some very aggressive NOx emission rates on some coal units. Using the Ameren - IL data set as an example, the table below illustrates some of these concerns. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.6; see p.7 of this comment summary for Table 3 entitled, NODA NOx Modeling Issues]
Coffeen I & 2 are cyclone boilers with an existing SCR and are burning a sub-bituminous coal and it is unlikely that either of these units could achieve a NOx rate of 0.06 lbs/mmBtu. The Joppa units in 2009 had NOx rates that ranged between 0.112 and 0.121 lbs/mmBtu, while burning a sub-bituminous coal and operating Low NOx Burners (LNB) and Separated Overfire Air (SOFA). The NODA modeling of these units has them being retired, which was discussed earlier, as well as achieving very aggressive NOx emission rates of 0.063 and below. The combination of retiring units and achieving SCR-like emission rates at the same time does not make sense. Moreover, it should be noted, such low NOx emission rates clearly cannot be achieved with the use of LNB/SOFA without the addition of post-combustion controls (which the NODA information does not project will be installed on these units). Both Newton 1 & 2 have LNB and OFA, along with Operational Modifications (OPMOD) and burn a subbituminous coal and achieved 2009 NOx emission rates of 0.092 and 0.100 lbs/mmBtu, respectively. NODA modeling has Newton 1 at a 0.060 lbs/mmBtu rate with a retrofitted SCR and Newton 2 at 0.082 lbs/mmBtu. It is unlikely an SCR would be retrofitted on Newton 1 to move from 0.092 to 0.060 lbs/mmBtu due to the high cost of an SCR, and the availability of cheaper alternatives (e.g., SNCR). Secondly, the Newton 2 NODA NOx rate is very aggressive and to achieve that type of rate would require some additional post-combustion technology. [EPA-HQ-OAR-2009-0491-3746.1_NODA, pp.7-8]
Changes in FGD and SCR Capacity [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.8]
With the changes in both generation forecast (AEO 2008 to AEO 2010) and other assumptions in the NODA modeling, there is a considerable decline in 2014 of retrofit FGD capacity and a smaller, but still significant, decline in retrofit SCR capacity, as compared with EPA's original projections in this rulemaking, as shown in Figures 2 & 3. [See p.8 of this comment summary for Figure 2 entitled, Comparison of 2014 Retrofit FGD Capacity Under the Transport Rule and NODA; see p.9 of this comment summary for Figure 3 entitled, Comparison of 2014 Retrofit SCR Capacity Under the Transport Rule and NODA] Specifically, the NODA modeling estimates almost 12 GW of FGD capacity and 7.4 GW of SCR capacity will have to be installed by 2014 to achieve the targets of the TR. On the other hand earlier TR modeling estimated almost 25 GW of FGD capacity and 8.3 GW of SCR capacity would be installed by 2014. This is a significant drop between the two simulations. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.8]