Finally, EPA has provided no rationale for rejecting IPM projections as the basis for establishing statewide budgets (for all but the 2014 SO2 budgets for group 1 states), but then relying upon those same projections as the basis for unit-specific allocations. This apparent and unexplained contradiction alone would provide a basis for remand of the resulting rule. See New York v. EPA, 413 F.3d 3,35-36 (D.C. Cir. 2005) (remanding a rule in part because the EPA contradicted its own rationale in its responses to comments). Given the acknowledged limitations of IPM at predicting accurately how actual units will be dispatched, it would be wholly illogical for EPA to rely upon IPM projections as the basis for establishing unit allocations, when it specifically declined to adopt those projections as the basis for statewide budgets. [EPA-HQ-OAR-2009-0491-2712.1, p.17]
G. Before Relying Upon IPM Projections For Allocation of Allowances, EPA Must Both Revise IPM to Accurately Project Dispatch of Contracted Facilities and Use the Correct Inputs for Linden Cogen
Before EPA can rely upon IPM projections as the basis for NOx allocations in New Jersey, EPA must revise the model so that it accurately predicts the dispatch of facilities such as Linden Cogen that operate to supply power pursuant to long-term power sales agreements and are required to run to provide steam to a cogeneration host. Understanding that any modeling exercise involves some degree of simplification, EPA must endeavor to capture the often complex terms governing dispatch of facilities in long-term contracts, before it relies upon the model results as the basis for allocations of emissions allowances. If EPA cannot make adjustments to IPM so that it can incorporate and reflect these real-world assumptions governing dispatch and, as a consequence, provide a reliable prediction of contracted facilities' actual dispatch, then EPA cannot continue to rely upon the model results, but must resort instead to the historic dispatch data it has already deemed a better predictor of future dispatch than IPM's projections. [EPA-HQ-OAR-2009-0491-2712.1, pp.18-19]
Linden Cogen's long-term contracts practically assure that it will be operated as frequently as demonstrated by historical operating data. If IPM cannot accommodate the numerous complex contractual terms governing dispatch of Linden Cogen's units, then EPA must at the very least establish some set of rules within IPM, which effectively 'force' the model to predict dispatch of Linden Cogen and other contracted facilities at heat input levels representative of historic operations. EPA also must incorporate Linden Cogen's correct plantwide heat rate into the model and reflect dispatch of Units 1 through 5 consistent with their service of the NYC region through dedicated transmission lines. Additionally, EPA must apply the correct FOM assumptions (12.6 $/kW/yr) for each of Linden Cogen's generating units. It also must apply VOM and fuel costs no greater than assumed for a similar facility located in New Jersey (AES Red Oak) (2.75 to 3.02 mill/kWh for VOM costs and 32.55 to 44.09 mill/kWh for fuel costs). [EPA-HQ-OAR-2009-0491-2712.1, p.19]
As the court held in the section 126 litigation, '[w]hile courts routinely defer to agency modeling complex phenomena, model assumptions must have a 'rational relationship' to the real world.' Appalachian Power 1,249 F.3d 1032 (internal citations to Chemical Mfrs. Ass'n v EPA, 28 F.3d at 1265). Accordingly, EPA has an obligation to incorporate real-world expectations for contracted facilities into its model. Further, EPA cannot inflexibly apply its model when it has been demonstrated to have a 'poor fit' with reality. Chemical Mfrs. Ass'n v EPA, 28 F.3d at 1265. ('The more inflexibly the agency intends to apply the model, however, the more searchingly will the court review the agency's response when an affected party presents specific detailed evidence of a poor fit between the agency's model and that party's reality.') Finally, in the face of data and real world information demonstrating that the assumptions used by EPA are false and the results are simply implausible, EPA must provide sources the opportunity to correct those assumptions. See, e.g., Columbia Falls Aluminum Co. v. EPA, 139 F.3d 914, 923 (D.C. Cir 1998) (vacating and remanding a rule for reliance upon 'a test [the EPA] knew to be inaccurate.'). If the model cannot accommodate real-world assumptions, EPA must abandon the model. [EPA-HQ-OAR-2009-0491-2712.1, p.19]
H. If EPA Cannot Revise IPM To Accurately Predict Dispatch of Facilities in New Jersey, EPA Should Apply the Same Methodology It Used to Establish New Jersey's Budget and Rely Upon Historical Data Instead of IPM's Projections
If EPA cannot make appropriate change to IPM so that it would accurately predict the dispatch of facilities in New Jersey such as Linden Cogen, EPA should instead base NOx allocations in New Jersey on reported data. In setting state budgets (except for the 2014 802 budgets for group 1 states), EPA reportedly relied on reported data, as augmented by assumptions about operation of existing and planned emissions controls. See 75 Fed. Reg. at 45291. Thus, if IPM cannot be revised to produce reliable results for New Jersey or for contracted facilities such as Linden Cogen, EPA should adopt the same approach it used to develop the proposed state budgets and base the unit allocations on reported data, augmented by assumptions concerning the operation of emissions controls. This would make true EPA's statement in the preamble that its proposed allocation methodology 'allocat[es] down to the individual unit level using all of the same assumptions used in developing the proposed budgets.' 75 Fed. Reg. at 45311. For New Jersey, using those same assumptions would require that EPA not rely upon IPM projections for either the annual or ozone season NOx allocations, but instead base those allocations upon historic data, as augmented by assumptions about existing and planned controls. [EPA-HQ-OAR-2009-0491-2712.1, pp.19-20]
I. Basing Allocations on Reported Data Rather Than Projected Dispatch Is Not At All Inconsistent With the Court's Decision in North Carolina v. EPA
Basing unit allocations for New Jersey on historic data is not at all inconsistent with the principles articulated by the D.C. Circuit in North Carolina v. EPA, 531 F.3d 896 (DC Cir. 2008). Indeed, EPA has already proposed to base unit allocations on historic data for any state in which 2009 emissions were lower than IPM's projected 2012 emissions. Thus, assuming EPA cannot fix the errors in IPM that have resulted in wildly inaccurate projections of dispatch in New Jersey and for Linden Cogen in particular, EPA could adopt the same approach for allocating allowances that it says it adopted in setting statewide budgets: It could base each unit's allocation on historic data, which EPA has concluded are more representative of actual operations than IPM's projections. [EPA-HQ-OAR-2009-0491-2712.1, p.20]
J. EPA Should Establish Allocations Based Upon a More Representative Period of Time Than One Year
Assuming EPA cannot modify IPM to accurately predict dispatch of contracted facilities in New Jersey and should therefore decide to base NOx allocations for New Jersey on reported data, EPA should base emissions allocations for individual units, not upon data from only one year, but on a facility's average heat input over a longer period of time. Once each facility's representative baseline has been established, EPA should add together all facilities' baseline emissions, compare the resulting sum with the state budget and then reduce each facility's allocation by whatever percentage is needed for the total statewide emissions (plus the 3% set aside for new facilities) to fit within the budget. [EPA-HQ-OAR-2009-0491-2712.1, p.20]
Using only one year's data as the baseline for allocations would unfairly prejudice facilities that might have experienced reduced dispatch in 2008 or 2009. In particular, it could penalize facilities that had lower emissions in 2008 or 2009 because they were down for an extended period of time to install controls in advance of CAIR. Furthermore, as EPA has acknowledged upon adjusting reported heat input and emissions rates to reflect unusually low utilization in 2009 15, 2009 data represented significantly lower utilization due to the global recession. As a consequence, 2009 data cannot be deemed representative and EPA should more equitably account for anomalously low utilization during the recession by using a longer-term average as the basis for establishing allocations. [EPA-HQ-OAR-2009-0491-2712.1, pp.20-21]
III. CONCLUSION
Linden Cogen objects to EPA's proposed NOx allocations for New Jersey because they are based upon projections of utilization generated by IPM, which have no basis in reality and fail to reflect Linden Cogen's long-term contractual obligations. Due to several other errors in the model inputs, IPM has erroneously modeled Linden Cogen as though it would only be dispatched as infrequently as a simple cycle peaking plant, although both historical data from Linden Cogen and its long-term contractual obligations clearly demonstrate that it is a baseload cogeneration facility. EPA's error in relying upon IPM projections as the basis for New Jersey NOx allocations is compounded by the fact that EPA rejected these projections as an appropriate basis for setting the statewide budgets, finding instead that actual historical data were more reliable than IPM's predicted dispatch patterns. [EPA-HQ-OAR-2009-0491-2712.1, p.23]
Before relying upon IPM projections as the basis for allocating allowances, EPA must fix the model, so that it accurately predicts dispatch of facilities subject to long-term contractual obligations, such as Linden Cogen. EPA must also re-run the model to reflect the correct heat input and FOM, VOM and fuel costs for Linden Cogen. [EPA-HQ-OAR-2009-0491-2712.1, p.23]
If EPA cannot revise IPM so that it provides a reasonable and accurate projection of facility dispatch in New Jersey, EPA should base NOx allocations in New Jersey on historical data, as augmented by assumptions about the operation of existing and planned emissions controls. Further, rather than rely upon only one year's data to establish a facility's heat input, EPA should base the allocations on historical heat input over a longer period of time. Such an allocation would be more representative and fairer to facilities that may have experienced reduced utilization during 2008 or 2009 because of the recession or to install emissions controls in advance of the CAIR. [EPA-HQ-OAR-2009-0491-2712.1, p.23]
If EPA does not either correct the serious problems with IPM that have resulted in its erroneous projections of dispatch or establish unit-specific allocations based on historic heat input, it could, as an altogether different approach, refrain from promulgation of the proposed FIPs and instead support states' efforts to submit adequate SIP revisions within a reasonable amount of time. [EPA-HQ-OAR-2009-0491-2712.1, p.23]
As conveyed by Linden Cogen's comments submitted on the Proposed Transport Rule, Linden Cogen objects to EPA's proposed allocations of allowances for nitrogen oxides ('NOx') for New Jersey because they are based upon projections of utilization generated by EPA's Integrated Planning Model ('IMP'), which have no basis in reality and fail to reflect Linden Cogen's long-term contractual obligations. Due to several other errors in the model inputs. lPM has erroneously modeled Linden Cogen as thought it would only be dispatched as infrequently as a simple cycle peaking plant, although both historical data from Linden Cogen and its long-term contractual obligations clearly demonstrate that it is a baseload cogeneration facility ('cogen'). [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.1]
As argued by our comments on the Proposed Transport Rule, EPA cannot rely upon IPM projections as the basis for allocating allowances. unless it revises IPM so that the model accurately predicts dispatch of facilities subject to long-term contractual obligations such as Linden Cogen. For cogeneration facilities, which are operated to provide both power and steam to their cogeneration hosts and power to the grid, Linden Cogen believes that the only way IPM can be modified to avoid such erroneous projections of dispatch is to incorporate the specific contractual obligations governing operation of cogen units into IPM. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.2]
However, Linden Cogen understands from conversations with EPA representatives that EPA intends to use only publicly available information in IPM and, as a consequence, has no current intention of incorporating the requirements of cogenerators' contracts into the model. This approach would support Linden Cogen's conclusion that IPM may not be able to effectively model the often highly complex contractual provisions governing dispatch of cogens, Although Linden Cogen does not believe EPA should limit the inputs to IPM to publicly available information, Linden Cogen has attempted to determine whether a methodology could be developed for modeling cogenerators that relies solely on publicly reported data. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.2]
To develop such a methodology, EPA would need, at a minimum, information on the minimum operating levels that cogenerators must maintain to supply adequate steam and power to their cogeneration hosts, as well as the incremental heat rates to be applied to dispatch of their additional capacity. If such information were contained within publicly available databases, EPA could, in theory, develop certain model plant types for cogenerators that could then be applied to individual cogenerators based upon reported data. The model would assume operations of cogenerators at certain minimum operating levels and then solve for dispatch of additional capacity above such operating levels. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.2]
However, Linden Cogen has determined that public databases (EPA and Energy Information Administration ('EIA')) are inadequate and do not provide sufficiently detailed information concerning the operation of cogens to enable such a modeling exercise. Therefore. if EPA wants to continue to rely upon IPM results as the basis for allocating allowances to individual units, Linden Cogen believes EPA must set the dispatch module for cogenerators within IPM at a level equivalent to their historic heat input and then let the model solve for the dispatch of other electric generating facilities. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.2]
As conveyed by Linden Cogen' s comments on the Proposed Transport Rule, if EPA cannot modify IPM so that it provides a reasonable and accurate projection of Linden Cogen and other facilities subject to long-term contractual obligations, EPA should base NOx allocations in New Jersey on historical data, as augmented by assumptions about the operation of existing and planned emissions controls. Alternatively, EPA could refrain from promulgation of the proposed Federal Implementation Plans ('FIPs')and instead support states' efforts to submit adequate State Implementation Plan ('SIP') revisions within a reasonable amount of time. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.2]
Before EPA Relies Upon IPM Results as the Basis for Allocating Emissions Allowances to Individual Units, EPA Must Adopt an Approach for Modeling of Cogens That Accurately Reflects Their Obligations to Provide Both Power and Useful Thermal Output to Their Cogeneration Hosts and Electricity to the Grid [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.4]
Representatives of Linden Cogen have spoken with EPA staff responsible for maintenance and development of the IPM. Linden Cogen understands from these conversations that EPA recognizes that there are problems associated with modeling the future dispatch of cogeneration facilities. In addition, in our preliminary review of comments filed on the Proposed Transport Rule, we noted several other owners of cogeneration facilities who identified similarly erroneous projections of dispatch for their units. EPA must resolve these problems, before relying upon IPM results as the basis for allocating emissions allowances under the Proposed Transport Rule. Further, EPA should resolve these problems to assure that any future application of IPM in agency planning and decision-making is rooted in an accurate understanding of how cogens operate. With these goals in mind, Linden Cogen provides the following supplemental comments on how EPA might develop a sound technical approach for modeling of cogens in IPM. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.4]
Cogens typically have certain minimum 'must run' operating levels established by contract with their cogeneration host, at which they must be operated at all times to provide a base level of steam sales and/or to satisfy contractual obligations in the power and steam sales contract. Thus, to model cogens' operation, Linden Cogen believes that, at a minimum, EPA would need to incorporate these minimum 'must run' operating levels into IPM. EPA would also need to apply an appropriate 'incremental' heat rate for dispatch above such minimum operating levels. This incremental heat rate is often substantially lower than the actual heat rate for the plant because it only reflects the additional fuel needed to increase generating capacity, once the plant is already operating to satisfy the minimum steam and power requirements of the cogeneration host and/or the requirements of the long-term contract. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.4]
In addition, as suggested by our October 1,2010 Comments, EPA also would need to incorporate the specific contractual terms governing dispatch of facilities like Linden Cogen into the model because some contracts may have requirements that differ from a 'typical' cogeneration contract. Contracts for sale of power and steam often include detailed provisions that mandate operation at certain minimum load levels or for specific minimum durations. For example, while dispatch of Linden Cogen Units 1 through 5 is controlled by ConEd, ConEd cannot dispatch Units 1 through 5 at a lower load than 303 MW. Additionally, once ConEd has dispatched the plant above 303 MW for only one hour, it must operate the plant at a load of at least 379 MW for no less than fifty consecutive hours. Moreover, as pointed out in our October 1, 2010 Comments, Linden Units 1- 5 dispatch into New York City, and not into the PJM grid. See October 1, 2010 Comments, 11. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.4]
Given these contractual obligations, if EPA wanted to accurately reflect the operation of Linden cogen, Units 1 through 5 would need to be modeled with a minimum 'must run' operating level of 303 MW. The heat rate assigned to this must run component of Units 1 through 5 operations would be substantially higher than the overall plant rate, since it also accounts for the production of dispatch from Units 1 through 5, dispatch would need to be modeled at an incremental heat rate that the plant's contractual requirements. Further, even if EPA were to make these changes, IPM still may provide grossly unrealistic projections for dispatch of Units 1 through 5, unless the model could also accommodate the fifty hour-minimum dispatch requirement. In reality, Linden Cogen's annual capacity factor has ranged from 62% to 75%  under the ConEd power sales agreement. and the quarterly capacity factors have been as high as 80%. See id.. 9, The power sales agreement for Linden Units I through 5 significantly differs from that of a typical cogeneration facility because it reflects unique contractual arrangements to supply ConEd with power for sale into the New York City market. [EPA-HQ-OAR-2009-0491-3743.1_NODA, pp.4-5]
In the same fashion. but more consistent with a 'typical' cogen's operation, dispatch of Linden Cogen Unit 6 would need to be modeled with a minimum 'must nm' operating level of 134 MW due to Linden Cogen's contractual obligations to provide a base level of electric load to ConocoPhillips. This 'must run' component of Unit 6's operations would need to be modeled with a substantially higher heat rate than the plant's overall heat rate, since it also accounts for the fuel needed to generate such steam; the additional 36 MW of capacity from Unit 6 would need to be modeled with an incremental heat rate that is significantly lower. Linden Cogen provides this example merely for purposes of illustration of how real-world assumptions concerning the operation of cogeneration facilities might possibly be incorporated into IPM. It also is intended to illustrate the complexity of the contractual terms governing the dispatch of cogens, both for sale of steam to their thermal host and for generation of electricity to the grid. As described by our October 1, 2010 comments, EPA cannot rely upon IPM as the basis for allocating allowances unless it fixes several errors in the model and underlying assumptions and adapts IPM to accommodate the often complex requirements governing dispatch of facilities subject to long-term contracts. See October l, 2010 Comments, 18-19. As we previously stated, '[if] IPM cannot accommodate the numerous complex contractual terms governing dispatch of Linden Cogen' s units, then EPA must at the very least establish some set of rules within IPM, which effectively 'force' the model to predict dispatch of Linden Cogen and other contracted facilities at heat input levels representative of historic operations.' Id., 19 [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.5]
As EPA has recognized, cogeneration represents a highly efficient solution to meeting our nation's demand for power, while reducing emissions. According to the U.S. Clean Heat and Power Association, cogeneration systems currently comprise almost 8% of the U.S. power sector, resulting in a net reduction of  NOx and sulfur dioxide ('SOx') emissions of 0.4 and 0.9 million tons per year, respectively, when compared to emissions that would result if the needs being met by these cogeneration systems were met by conventional generating sources instead. Moreover, an even greater percentage of new generating capacity built since the 1990's consists of cogens. Thus, cogens represent a significant, highly efficient and dean component of the electric generating sector. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.5]
For these reasons, EPA cannot and should not rely upon model results that fail to account for the tremendous benefits achieved by cogeneration, either as the basis for allocating allowances under the Proposed Transport Rule or in support of broader agency policy and planning objectives. To do so would not only prejudice individual cogens, which will need to purchase allowances to operate under the Proposed Transport Rule, but would frustrate the goal articulated by the Administrator upon proposing the Transport Rule of fostering investments in compliance that represent the most efficient and forward-looking expenditure of investor, shareholder, and public funds, resulting, in turn, in the creation of a dean, efficient, and completely modem power sector.' 75 Fed. Reg at 45227.
Because EPA Intends to Rely Only Upon Publicly Available Information in IPM and Linden Cogen Does Not Believe EPA Can Accurately Model Cogens Based Solely on Public Information, EPA Should Set the Dispatch of Cogens Within IPM at Their Historic Heat Input and Then Let IPM Solve for Dispatch of All Other Generating facilities [EPA-HQ-OAR-2009-0491-3743.1_NODA, pp.5-6]
Linden Cogen understands from conversations with EPA representatives that, in revising IPM to reflect more realistic and accurate assumptions based upon comments it has received on the Proposed Transport Rule, EPA currently intends to rely only upon publicly available information. As a consequence, EPA does not intend to make any effort to incorporate non-public information, such as the requirements of specific contracts, into IPM. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.6]
Acknowledging that any modeling exercise involves some degree of simplification, Linden Cogen believes that limiting IPM to publicly available information would represent an arbitrary restriction, particularly given the wildly inaccurate results that IPM has generated for cogens and the fact that no effort has been made within IPM to reflect cogens' generation of power and useful thermal output to meet the demand of their thermal hosts. Further, it is ironic that EPA has expressed its intention to rely only upon publicly available information in future iterations of IPM, when IPM is itself a proprietary model, about which EPA has revealed only limited information due to restrictions imposed by the model's developer. As suggested by our October 1, 2010 Comments, Linden Cogen believes EPA has an obligation to incorporate contractual obligations into IPM to the greatest extent possible, before relying upon IPM results as the basis for allocating allowances to individual units. See October 1, 2010 Comments, 9. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.6]
Nevertheless, Linden Cogen reviewed publicly available databases to assess whether and to what extent EPA could obtain information on how cogens are operated from such databases that could then be incorporated into IPM to produce more accurate results for cogens, without relying upon the specific contractual provisions governing dispatch of actual plants. As suggested by the example concerning Linden Cogen presented above, at a minimum, EPA would need at least two pieces of information concerning operation of cogens to successfully model their operations with IPM: [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.6]
(1) The percentage of capacity that represents 'must run' operations; and [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.6]
(2) The incremental heat rate to be applied to generation of additional capacity, above the minimum 'must run' operating levels. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.6]
If such information were publicly available, EPA might, in theory, develop certain generic cogeneration plant types within IPM (e.g., those with minimum "must run" operations representing less than 50% of their annual capacity and those over 50% of capacity) and then assign individual cogens to one of these plant types by reference to information reported to the EPA or EIA. EPA would also need to develop appropriate incremental heat rates for different categories of generating units based on their size, configuration in combined-cycle, and year of construction. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.6]
However, based on our review of databases of historic operating data compiled from EIA 920 (Combined Heat and Power Plant Report) and EIA 923 (Power Plant Operations Report), as wells as private subscriber databases that compile data reported to EPA into a more usable format. we do not believe that the information needed to perform such a modeling exercise is publicly available. None of these databases captures data on cogens' minimum operating levels and the incremental heat rates applicable to generation of additional capacity above those minimum operating levels. Accordingly, we do not believe EPA can develop a methodology that would result in realistic and reliable projections of dispatch for cogens, unless IPM can accommodate the specific contractual terms governing dispatch of actual plants. [EPA-HQ-OAR-2009-0491-3743.1_NODA, pp.6-7]
Moreover. the contractual provisions governing dispatch of plants subject to long-term contracts are often highly complex and may not be amenable to modeling within IPM. Thus, without undertaking a major overhaul of the IPM itself, we are doubtful that EPA could feasibly incorporate the relevant contractual dispatch parameters into IPM. even if such parameters were already known to EPA. The fact that EPA currently intends to rely only upon publicly available information further supports our conclusion that IPM is unsuitable for modeling of cogens. In light of this, we must conclude that, assuming EPA cannot incorporate the long-term contract parameters governing dispatch of Linden Cogen and other cogens into the model. EPA must set the dispatch for cogens within IPM at historic heat input levels using readily available information from EPA databases, and then let IPM solve for the dispatch of other electric generating facilities. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.7]
Because most cogeneration facilities were built after 1990, they are less likely than other facilities to be operated without emissions controls. As a consequence, historic dispatch information is more likely to be representative of future dispatch for cogenerators than it is for older facilities, which may need to either curtail their operations or install additional emissions controls to comply with the Transport Rule. For this reason. Linden Cogen does not believe that setting the dispatch of cogens at their historic heat inputs should result in an unrealistic representation of their future operations. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.7]

4. Technical Support Document, State Budgets, Unit Allocations, and Unit Emissions Rates, EPA Office of Air and Radiation, July 20 I0, at 9 ('Reported annual and ozone season NOx emissions are adjusted to account for unusually low utilization in 2009.') ('Because 2009 was an unusually low year, rebasing emissions on 2008 heat input in this way typically results in larger annual NOx emissions.'). [EPA-HQ-OAR-2009-0491-2712.1, p.7]
7. See Documentation for EPA Base Case v.4.10, 4-9, Table 3-4. [EPA-HQ-OAR-2009-0491-2712.1, p.11]
13. These preamble statements are inconsistent with other statements appearing in the Technical Support Document, where EPA said that statewide budgets (other than the 2014 SO2 budgets for group 1 states) were based on 'the lower of the recent actual emissions or projected base case emissions, at the state level.' Technical Support Document, State Budgets, Unit Allocations, and Unit Emissions Rates, 9-11. Thus, the Technical Support Document suggests that statewide budgets were set the same way as unit allocations (by taking the lower of IPM projections or actual reported data), while the preamble to the Proposed Transport Rule indicates that EPA disregarded IPM projections as the basis for setting state-wide budgets because IPM projections are not as accurate as actual emissions data in predicting how individual units will be operated. [EPA-HQ-OAR-2009-0491-2712.1, p.15]
15. See supra nt. 4. [EPA-HQ-OAR-2009-0491-2712.1, p.20]
Exxon Mobil Corporation
6. EPA overestimated Louisiana emissions inventory used for making the projections, in both the IPM v. 3.02 and v. 4.10 models; thus, even the minimal contributions by Louisiana are likely grossly overstated. The primary reasons the inventories were overstated are:  [EPA-HQ-OAR-2009-0491-2841.1, p.5]
2. EPA's projections of significant contribution and reasonable interference at the HGB and DFW monitors were based on the IPM v. 3.02 Base Case modeling for 2012. On September 1,2010, EPA published a Notice of Data Availability for the IPM v. 4.10 modeling, including a revised TR Base Case 2012 scenario. Under the revised modeling, projected emissions of ozone season NOx are 6,061 tpy less than projected under the IPM v. 3.02 version. Based on this factor alone, it is believed that any revised air quality analysis based on the IPM v. 4.10 modeling will demonstrate no impact whatsoever on ozone design values in the HGB or DFW areas. As noted, while EM has reservations about some of the other inputs to the IPM model, as discussed herein, EM believes that the v. 4.10 estimates rely upon a more accurate forecasting of natural gas prices and that version should be used to determine, at least as a screening mechanism, the potential for significant contribution or interference with maintenance of a NAAQS. [EPA-HQ-OAR-2009-0491-2841.1, p.7]
4. Due to the inherent uncertainty in the IPM modeling, as unmistakably illustrated by the material differences between IPM v. 3.02 and v. 4.10 projections, a projected impact of less than 2 ppb based on modeling should never be used as a level indicating 'significant contribution' or 'interference with maintenance' from an upwind to a downwind state under the 'good neighbor' provisions of the Clean Air Act, 42 U.S.c. 7410(a)(2)(D). At most, the IPM should be used as a screening tool for making rebuttable presumptions for 'significant contribution' or 'interference with maintenance' determinations. However, such presumptions should be always subject to a reasonable opportunity for rebuttal by empirical evidence. [EPA-HQ-OAR-2009-0491-2841.1,p.8]
5. EPA overestimated Louisiana emissions inventory used for making the projections, in both the IPM v. 3.02 and v. 4.10 models for the reasons stated in Section II.A, above; thus, even the minimal contributions of ozone season NOx by Louisiana emissions to Texas are likely grossly overstated. [EPA-HQ-OAR-2009-0491-2841.1,pp.8-9]
EM supports use of the updated IPM for use in making screening decisions to assist in making findings of 'significant contribution' or 'interference with maintenance' under Clean Air Act Section 110(d). EM urges EPA, however, to make certain updates to the assumptions and inputs for IPM v. 4.10 as discussed in these comments. Further, as indicated in EM's original comments, the IPM Base Case, whether premised on v. 3.02, v. 4.10 or some future version, should only be a screening tool for indications, of potential 'significant contribution' or 'interference with maintenance'. The IPM is simply not accurate enough and is dependent upon too many uncertain assumptions and imprecise inputs to make binding decisions of 'significant contribution' or 'interference with maintenance.' EPA should always place great weight on empirical data to modify projected model conclusions when making these determinations. [EPA-HQ-OAR-2009-0491-3736.1_NODA, p.2]
The significant difference between the results of the v. 3.02 and v. 4.10 Base Case show the imprecision of the IPM model. Due to this imprecision and the uncertainties attendant to the many assumptions made for the IPM modeling, EM believes that an IPM projected impact of less than 2 ppb from an upwind to a downwind state should never be used as a level indicating 'significant contribution' or 'interference with maintenance' trader the 'good neighbor' provisions of the Clean Air Act, 42 U.S.C. 7410(a)(2)(D). At most, the IPM should be used as a screening tool for making rebuttable presumptions for 'significant contribution' or 'interference with maintenance' determinations if a value above 2 ppb contribution is modeled. However, such presumptions should be always subject to a reasonable opportunity for rebuttal by empirical evidence and a weight of evidence approach used to determine if there is actually such contribution or interference. EM urges EPA to adopt this 2 ppb rule as a bright-line cut-off for screening. If the modeled contribution is 2 ppb or below, then no contribution or interference should be presumed. If the modeled contribution is above 2 ppb, then there could be a rebuttable presumption of contribution or interference. [EPA-HQ-OAR-2009-0491-3736.1_NODA, p.4]
EM believes, for the reasons stated in the comments of the staff of the Louisiana Public Service Commission (LPSC) on the proposed CATR/FIP, that the IPM fails to adequately consider transmission constraints within Louisiana. EM believes this is a deficiency in both the IPM v. 3.02 and v. 4.10. EM urges EPA to carefully consider the comments of the LPSC staff. [EPA-HQ-OAR-2009-0491-3736.1_NODA, p.6]
Gainesville Regional Utilities (GRU)
EPA Has Set Unachievable Emission Limits for GRU's Main Generating Unit In response to the CAIR rule emission caps, GRU committed more than $140,000,000 to add an SCR, a dry circulating SO2 scrubber, and a fabric filter to the Deerhaven Generating Station Unit #2 (DH#2). Those systems are installed and are operating. To take advantage of the fuel flexibility allowed by the SO2 scrubber, the design allows for the combustion of up to 2.5% sulfur coal. The guaranteed SO2 emission rate for the scrubber while combusting the 2.5% sulfur coal is 0.10 lb/mmBtu. Recent performance tests for the unit indicate that significant reductions below the guaranteed emission rate are not likely. As can be seen from the table below design limits and performance test results are significantly more than the proposed limit of 0.07 lb/mmBtu for the EPA second alternative compliance option. We believe it is unreasonable to set an SO2 limit for DH#2 that is well below the normal design and capability of the unit. [EPA-HQ-OAR-2009-0491-2674.1, p.2]
[Table 1 can be found on page 2 of this comment.]
EPA Modeling for Determining Significant Interstate Transport Maybe Flawed
GRU is concerned that the modeling done to determine an upwind state's significant contribution to a downwind state's non-attainment with a NAAQS may be flawed. Further, it is not appropriate to model EGU emissions based on pre-CAIR 2005 emissions since the CAIR reductions for many states, including Florida, may be real and enforceable under existing state permits. In addition, the model projections of significant impacts appear to defy common sense. For example, it is very unlikely that Florida emissions could result in a significant impact on non-attainment on Texas. [EPA-HQ-OAR-2009-0491-2674.1, pp.6-7]
Kansas City Board of Public Utilities (BPU)
EPA'S MODEL PRODUCES RESULTS THAT OVERSTATE KANSAS EMISSIONS LEVELS
Besides EPA overstepping its legal bounds by effectively subjecting Kansas to the requirements of the new rule prior to the time authorized by the CAA, the modeling on which the proposed rule relies overestimates the significant contribution and interference of maintenance in identified nonattainment areas that can be attributed to Kansas. See 75 FR at 45262 (24-hour PM25 list shows three Milwaukee, WI sites); at 45266 (24-hour PM25 list shows Muscatine, IA and Milwaukee, WI sites for maintenance); at 45269 (8-hour ozone shows Dallas, TX site for maintenance). The pre-NODA emission rates used as the basis for the modeling, although identifying NOx and SO2 controls that have been installed on Kansas EGUs, does not incorporate emissions levels that are already being achieved or that must be achieved by 2012 under enforceable permits and agreements. This failure leads to an overstatement of Kansas projected 2012 emissions levels used to identify States that are to be included in the rule. [EPA-HQ-OAR-2009-0491-2740.1, pp.11-12]
When the appropriate EGU emissions level adjustments are made, as shown in the attached Trinity Consultants Report ('Trinity Report'), [See p. 25 of this comment to see comments pertaining to the Trinity Report] the most significant change relates to the supposed linkage between Kansas' downwind emissions and a nonattainment site in Dallas. After the appropriate adjustments are made, downwind modeling at the Dallas site shifts from being above to falling below the 'single 'bright line' threshold for ozone that is one percent of the 1997 8-hour ozone standard of 0.08 ppm,' making the threshold 'a value of 0.8 ppb.' 75 FR at 45237/3. Consequently, the properly adjusted modeling no longer supports a finding that Kansas emissions meet the threshold for contributing to interference with maintenance at the Dallas site. As this is the only site to which Kansas is linked for 8-hour ozone maintenance, 75 FR at 45269, it follows that Kansas should be removed from the list of States subject to the proposed 8-hour ozone rule. [EPA-HQ-OAR-2009-0491-2740.1, p.12]
[See pp. 12-14 of this comments for additional comments pertaining to EPA's Model Produces Results That Overstate Kansas Emission Levels]
Kansas City Power and Light Company (KCP&L)
2. Due to the identification of numerous inaccuracies in the unit-level data, EPA changes to the NEEDS database, as well as changes to the IPM model itself, regulated entities will remain in a state of uncertainty until the final Transport Rule is published in mid-2011. The new modeling runs will likely lead to substantially different state budgets and may even change the number of states affected. For these reasons, EPA should reissue the rule for public comment as a Supplemental Notice of Proposed Rulemaking. [EPA-HQ-OAR-2009-0491-2709.1, p.3] [EPA-HQ-OAR-2009-0491-3757.1_NODA, p.2]
While the IPM emission projections were intended to account for emission reductions that would be required by 2012, a review of the IPM projections shows that emission reductions required by 2012 for NOx and SO2 at Westar Energy's Jeffrey Energy Center were not accounted for. [EPA-HQ-OAR-2009-0491-2709.1, p.3]
6. KCP&L disagrees with the way EPA adjusted reported NOx emission by using 2008 heat input with the most recent four quarters of emissions rate data. EPA's assumption that utilization was unusually low in 2009 for all units is incorrect. For some units, 2008 annual heat input was lower than Q4 2008 through Q3 2009, and the 2008 ozone season heat input was lower than the 2009 ozone season. Since EPA's goal in adjusting the data was to calculate "typically" larger NOx emissions, it should use the larger of the two heat input rates (i.e., 2008 vs. the most recent four quarters for annual heat input and 2008 vs. 2009 ozone season heat input), combined with the most recent four quarters or ozone season emission rate (lb/mmBtu) data. EPA did not explain why it made this correction for NOx, but not for SO2. [EPA-HQ-OAR-2009-0491-2709.1, p.4]
2. There are errors in adjustments made when calculating unit level allowances, based on review of the data contained in the Budgets and Allocations  -  Detailed Unit-Level Data TSD and the IPM TR SB Limited Trading 2014 parsed file. [EPA-HQ-OAR-2009-0491-2709.1, p.5]
a. The Hawthorn Unit 5A (ID 2079_B_5A) annual NOx emissions were incorrectly adjusted downward by 30.4 tpy. According to the State Budgets, Unit Allocations, and Unit Emissions Rates TSD (page 5), "... reported and projected emissions for annual NOx are adjusted to account for the year-round operation of post-combustion controls which may only have operated during the ozone season." Hawthorn Unit 5A has a permit limit of 0.08 lb/mmBtu (30-day rolling average). Compliance with this limit requires year-round operation of the SCR. A downward adjustment based on the 2009 ozone season emission rate is therefore inappropriate. The annual NOx allowances for this unit should be based on the emission rate over the most recent four quarters of reported data without additional adjustment for the post-combustion control. [EPA-HQ-OAR-2009-0491-2709.1, p.5]
b. The La Cygne Unit 1 (ID 1241_B_1) annual NOx emissions were incorrectly adjusted downward by 761.6 tpy. According to the State Budgets, Unit Allocations, and Unit Emissions Rates TSD (page 5), "... reported and projected emissions for annual NOx are adjusted to account for the year-round operation of post-combustion controls which may only have operated during the ozone season." La Cygne Unit 1 has a current permit limit of 0.15 lb/mmBtu (12-month rolling average). Compliance with this limit requires year-round operation of the SCR. A downward adjustment based on the 2009 ozone season emission rate is therefore inappropriate. The annual NOx allowances for this unit should be based on the emission rate over the most recent four quarters of reported data without additional adjustment for the post-combustion control. [EPA-HQ-OAR-2009-0491-2709.1, p.5]
c. The time period used for reported NOx emissions for Iatan Unit 1 is incorrect. The Iatan Unit 1 SCR came online in Q1 2009. The unit was off line for parts of Q4 2008 and Q1 2009 for the installation of the SCR and other emission controls and the reported heat input was well below what it would have been under normal operating conditions. It is therefore not appropriate to use those two quarters in calculating the reported annual NOx rate. Appropriate quarters for the annual heat input and unadjusted emission rate would be Q2 2009 through Q1 2010 (post- SCR). Note that to comply with its NOx emission limit of 0.09 lb/mmBtu (30- day rolling average), this unit must operate its SCR year-round. Therefore any downward adjustments to the reported data to account for the SCR would be inappropriate. The available post-installation data should be used without adjustment. [EPA-HQ-OAR-2009-0491-2709.1, p.6]
d. The Hawthorn Unit 5A 2014 SO2 allowances are based on an emission rate of 0.06 lb/mmBtu. The basis for this rate is not clear, as it does not appear to originate from the IPM data. Regardless, it is beyond the capability of the existing dry scrubber and the unit already burns low sulfur coal. The BACT determined limit for this unit, as stated in its current Title V operating permit, is 0.12 lb/mmBtu. [EPA-HQ-OAR-2009-0491-2709.1, p.6]
e. Reported data for Lake Road Unit 6 appears on two separates lines in the spreadsheet. The reported values from the two lines should be added together and included as a single entry. [EPA-HQ-OAR-2009-0491-2709.1, p.6]
3. General comments on the use of IPM 2014 projected SO2 emissions to determine allowances. [EPA-HQ-OAR-2009-0491-2709.1, p.6]
a. Unit level allocations are a proportional share of the state's budget based on projected SO2 emissions in the TR SB Limited Trading IPM run as apportioned in the 2014 parsed file. It is not clear from the documentation provided by EPA how allowances were allocated based on the IPM emissions prediction. It is also not clear how the heat inputs used to calculate 2014 SO2 allowances were determined. Clearly there is a disconnect between the 2014 IPM emission rates and the 2014 SO2 allocations that is not explained by EPA's inadequate documentation. Overall in Missouri, when compared at the unit level, allocations range from 0.5 to 3.6 times the IPM emission rate. These discrepancies illustrate why reductions would be more appropriately addressed through a SIP rather than a FIP. [EPA-HQ-OAR-2009-0491-2709.1, p.6]
i. The 2014 IPM heat inputs for Montrose Units 1, 2, and 3 (ID 2080_B_1, 2, and 3) are 44% below the 2012 heat inputs with no explanation given. The 2014 SO2 state budget for Missouri (154,000 tpy) is 91% of the 2014 IPM Limited Trading scenario emissions (168,911 tpy). However, the ratio of 2014 IPM modeled SO2 emissions to allowances for Montrose Units 1-3 ranges from 55 to 59%. It is not clear why those units received a much smaller portion of the 2014 IPM predicted emission rate. [EPA-HQ-OAR-2009-0491-2709.1, p.6]
ii. The 2014 heat input predicted by IPM for Sibley Unit 2 is 19% below the 2012 value with no explanation given. This unit is not anticipated to operate less in 2014 than it does currently or in 2012. [EPA-HQ-OAR-2009-0491-2709.1, p.6]
4. IPM predicts changes in operation regarding individual units that are inaccurate. [EPA-HQ-OAR-2009-0491-2709.1, p.7] [EPA-HQ-OAR-2009-0491-3757.1_NODA,p.5]
a. Sibley Units 1 and 3 are projected for "early coal retirement" and therefore do not receive any 2014 SO2 allowances. This modeled outcome is incorrect. There is no intention of retiring those units in that time frame and they should receive allowances. KCP&L has recently invested significant capital in NOx controls on both of these units (SCR on Unit 3 and SNCR on Unit 1) and retirement by 2014 would not allow for an acceptable return on that investment. In addition, operation of these units is necessary during periods of transmission curtailment elsewhere in the system. [EPA-HQ-OAR-2009-0491-2709.1, p.7] [EPA-HQ-OAR-2009-0491-3757.1_NODA,p.5]
b. Northeast Units 11-18 (ID 2081_G_11  -  2081_G_18) are projected for "early CT retirement" in the 2014 Limited Trading IPM run and therefore do not receive any 2014 SO2 allowances. This modeled outcome is incorrect. There is no intention of retiring those units in that timeframe. In fact, even if they are not economical to operate, their occasional operation is vital to grid stability. They contribute to grid stability by providing volt amp reactance (VAR) when necessary, and are used during periods of transmission curtailment elsewhere in the system. As oil-fired units, they can also provide power during periods of natural gas curtailment. [EPA-HQ-OAR-2009-0491-2709.1, p.7] [EPA-HQ-OAR-2009-0491-3757.1_NODA, pp.5-6]
c. Lake Road Unit 5 (ID 2098_G_5) is projected for "early CT retirement" and Lake Road Unit 6 is projected for "early coal retirement" in the 2014 Limited Trading IPM run. This modeled outcome is incorrect. There is no intention of retiring these units in that timeframe. In fact, even if this unit is not economical to operate, occasional operation is vital to grid stability. These units contribute to grid stability by providing volt amp reactance (VAR) when necessary, and can be used during periods of transmission curtailment elsewhere in the system. As an oil-fired unit, Lake Road Unit 5 can also provide power during periods of natural gas curtailment. [EPA-HQ-OAR-2009-0491-2709.1, p.7] [EPA-HQ-OAR-2009-0491-3757.1_NODA, p.6]
d. Hawthorn Units 6 and 9 (ID 2079_G_6 and 2079_G_9) are projected for "CC early retirement" in the 2014 Limited Trading IPM fun. This modeled outcome in incorrect. There is no intention of retiring those units in that timeframe. In fact, even if they are not economical to operate, their occasional operation is vital to grid stability. They contribute to grid stability by providing volt amp reactance (VAR) when necessary, and are used during periods of transmission curtailment elsewhere in the system. [EPA-HQ-OAR-2009-0491-2709.1, p.7] [EPA-HQ-OAR-2009-0491-3757.1_NODA, p.6]
Kansas Department of Health and Environment
During our review of the rule we have identified several inconsistencies in the emissions modeling inputs that we believe could lead to a significant overestimation of contribution to nonattainment from Kansas sources. Specifically, emissions from several electric utility generation units in the state are overestimated in the 2012 base year used for the contribution assessment. This appears to occur due to the use of older data, which EPA has stated it intends to correct in the Notice of Data Availability (NODA) that was published in the Federal Register on September 1, 2010. KDHE encourages EPA to follow through and use the latest available data for both emission rates and heat inputs for the electric utility sector. [EPA-HQ-OAR-2009-0491-2606.1, p.2]
In sum, these are very significant reductions in overall NOx emissions that have not been properly accounted for, and if counted, would likely remove the currently modeled Kansas 'linkage' with Dallas, TX monitors for ozone. In addition, the NOx and S02 reductions that have not been accounted for will also reduce the modeled Kansas contribution to PM2.5 in all areas of the country. [EPA-HQ-OAR-2009-0491-2606.1, p.5]
Louisiana Chemical Association (LCA)
2. Our review thus far indicates that EPA may have significantly overestimated the emissions inventory for Louisiana for both S02 and NOx and that the modeled projections resulting from these errant emissions are likewise overestimated. [EPA-HQ-OAR-2009-0491-1925.1, p. 2]
Louisiana Energy and Power Authority (LEPA)
THE PROPOSED TRANSPORT RULE FAILS TO ALLOCATE EMISSION ALLOWANCES TO UNITS THAT MUST RUN TO SERVE LOAD DURING PEAK HOURS BECAUSE EPA'S METHODOLOGY DOES NOT ACCOUNT FOR TRANSMISSION CONSTRAINTS AND ASSOCIATED OPERATIONAL REQUIREMENTS. [EPA-HQ-OAR-2009-0491-2700.1, p.12]
EPA's methodology for developing the state budgets and unit level allocations is set forth in the Technical Support Document entitled State Budgets, Unit Allocations, and Unit Emissions Rates. According to that document, state budgets, unit allocations and direct control rate limits are '[e]ach derived from a combination of recent emissions and heat input data and electric power sector projections from the Integrated Planning Model (IPM) affecting an inventory of fossil-fuel fired EGUs of more than 25MW capacity. Specifically, each state's budget was constructed from a combination of data and IPM projections for the EGUs in that state, and each EGU's contribution to the budget formed the basis of its allocation and direct control rate limit calculations.' Unit allocations thus apparently were set primarily based on projections on how much each EGU would run as determined by the IPM. [EPA-HQ-OAR-2009-0491-2700.1, p.12; for additional comments pertaining to THE PROPOSED TRANSPORT RULE FAILS TO ALLOCATE EMISSION ALLOWANCES TO UNITS THAT MUST RUN TO SERVE LOAD DURING PEAK HOURS BECAUSE EPA'S METHODOLOGY DOES NOT ACCOUNT FOR TRANSMISSION CONSTRAINTS AND ASSOCIATED OPERATIONAL REQUIREMENTS, see pp.12-14]
Vectren Corporation
EPA's assumptions regarding Vectren's control technology are inaccurate. [EPA-HQ-OAR-2009-0491-2654.1, p. 6]
EPA's NEEDS database inaccurately reflects not only the actual S02 permit limits for the Vectren units, but EPA's control efficiency assumptions do not adequately take into account the efficiency levels of the scrubbers for Vectren's AB Brown units 1 and 2.
EPA's NEEDS database lists the SO2 Permit Rates for Vectren's units as the following: [EPA-HQ-OAR-2009-0491-2654.1, p. 6]
FB Culley Unit 3-0.25 lb/mmBtu
AB Brown Unit 1-0.69 lb/mmBtu
AB Brown Unit 2-0.12 lb/mmBtu
The permit limit assumptions are inaccurate, The actual S02 permit limits for the Vectren units, as included in the source's applicable Title V operating permit, are the following: [EPA-HQ-OAR-2009-0491-2654.1, pp. 6-7]
FB Culley Unit 3-Scrubber to be operated at all times that unit is in operation at 95% removal efficiency.
AB Brown Unit 1-1.2 lb/mmBtu
AB Brown Unit 2-0.69 lb/mmBtu
As indicated above, the actual S02 permitted limits for the two Brown units are virtually double what is assumed in EPA's modeling runs. In addition, EPA's assumptions around the efficiencies of an FOD scrubber system fail to take into account that the scrubbers on AB Brown Units I and 2 are the original scrubbers constructed with the units (I 979 and 1986, respectively). The two AB Brown scrubbers are the only remaining dual alkali scrubbers currently in operation (to our knowledge), and they are not capable of achieving the efficiency assumptions ascribed to scrubbed units in the model. In reality, the dual alkali scrubbers at AB Brown Units I and 2 are capable of achieving an average S02 removal efficiency of 80-85%, instead of the assumed efficiencies of 87.7% (AB Brown Unit I) and 95.3% (AB Brown Unit 2) in the NEEDS database.  [EPA-HQ-OAR-2009-0491-2654.1, p. 7]
Response:
EPA reviewed the comments and has made significant updates to its IPM v.3.02 modeling used at proposal.  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 updated to its NEEDS database used as a model input that impacted the unit level model outputs.
Some of the most frequent general IPM comments noted above that were addressed in the updates are: FGD removal efficiency was adjusted for new retrofits, and for existing retrofits it was indexed to historic performance at the unit.  Additionally, many of the above comments were focused on a sources ability to switch coals.  EPA modified its modeling to better reflect the cost and feasibility of switching and blending coals.  State Rule and consent decrees were updated according to comments - among others, there were updates made to state rules and/or consent decrees impacting sources in Kansas and Louisiana as highlighted by the commenters above.  EPA also made significant updates to its modeling of cogeneration units to address concerns expressed by commenters.  Additionally, there were more than 1000 unit specific modeling changes made in response to corrections provided by the commenter.  For more detailed discussion of EPA IPM v.4.10 assumptions and assumption updates, see the EPA IPM v.4.10 documentation and the "Transport Rule IPM Assumptions Response to Comments" in the Appendix

XVIII.C.1. NPR: EGU Projections Using IPM/NEEDS V.3.02EISA

Organization: American Electric Power
Comment:
American Electric Power
Incorrect Data - The NEEDS database lists certain units with inaccurate emission controls. Additionally, the IPM model structure does not take into account all necessary unit specific operating constraints, specifically those relating to fuel suitability. Furthermore, EPA's data on purportedly 'actual' costs of scrubbers and SCRs are lower than actual industry and AEP-specific experience. [EPA-HQ-OAR-2009-0491-2665.1, p.4]
AEP has output driven comments from both versions of IPM, as we remain unsure which underlying errors might have been corrected in the modeling update process. Many of our concerns are directly related to how underlying unit limitations are factored into the modeling, specifically as ultimate allocation and/or potential emission rate limits are proposed to be tied directly to modeled emissions and performance. Furthermore, AEP requests that EPA produce modeling outputs disaggregated and reported at the unit level. It is highly unclear from the parsed data files provided exactly what coal types are being utilized and what constraints individual units are tied to. This level of data is needed to ensure that a proper third-party review can be conducted of the runs used to support the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2665.1, pp.20-21] [[These comments can also be found in XVIII.C.2.]]
At a minimum, EPA should correct the data and assumption issues identified, remodel the air quality impacts assuming a continuation of CAIR-like standards, revise the compliance dates based on reasonable timelines for environmental controls and rerun the economics and subsequent allocations that would result from these changes. A supplemental Transport Rule should then be proposed for comment. [EPA-HQ-OAR-2009-0491-2665.1, p.21] [[These comments can also be found in XVIII.C.2.]]
Response:
EPA has made significant updates to its IPM v.3.03 modeling used in the proposal.  The final EPA IPM v.4.10 modeling used for the Final Transport Rule reflects both general and unit level assumption updates based on comments.  See IPM v.4.10 documentation for more details on the final modeling, assumptions, and updates to assumptions in response to comments.  Additionally, the "Transport Rule IPM Assumptions Response to Comments" in the RTC Appendix contains a detailed list of unit level changes.  Subsequent to these changes, EPA remodeled air quality impacts on the updated base case modeling.  The preamble and TSDs explain the results of the updated modeling and the compliance deadlines for Final Transport Rule.
Organization: Cogen Technologies Linden Venture, LP
Comment:
Cogen Technologies Linden Venture, LP
K. Basing Allocations on Each Facility's Share of Projected Heat Input Would Not Avoid the Arbitrary and Inaccurate Results Generated by IPM
Linden Cogen does not support the alternative allocation methodology described by EPA in the preamble, wherein each facility would be allocated allowances based on its 'share of projected heat input.' 75 Fed. Reg. at 45311. As presented, this alternative allocation methodology would not resolve the serious problems associated with allocating allowances based on IPM's projected dispatch of facilities such as Linden Cogen, which are subject to contractual obligations that will mandate their operation, irrespective of IPM's erroneously low projections. While this alternative allocation methodology would generally favor clean units such as Linden Cogen, it would still base unit allocations on IPM's wildly inaccurate projections and, as a consequence, would fail to avoid the arbitrary results of EPA's proposed allocations. However, if EPA can successfully resolve the errors in IPM that resulted in its erroneously low projections for dispatch of Linden Cogen or if EPA's proposal were instead to allocate allowances based on each source's share of historical statewide heat input, irrespective of IPM's projections for same, Linden Cogen agrees that this would be a fair and equitable approach. [EPA-HQ-OAR-2009-0491-2712.1, p.21]
Response:
EPA's response to Linden Cogen's concern is three fold
1) EPA changed its general approach to modeling cogeneration units in IPM
2) EPA changed the IPM heat rate specific to Linden Cogen unit which results in more dispatch
3) EPA changed the unit level allocation methodology.  It is no longer based on projected emissions, but was finalized to be based on historic data.  See preamble section VII.D
For changes to IPM noted in 1 & 2 above, see "Transport Rule IPM Assumptions Response to Comments" in RTC Appendix.
Organization: Dominion
Comment:
Dominion
Low-Sulfur Fuel Availability Issues
It appears that EPA modeled projections for several of Dominion's coal-fired units assume the availability of low sulfur fuel as a viable compliance option going forward. However, over the last several years, Dominion has observed a steady increase in the sulfur content and a steady decrease in the higher heating value (HHV) for the coal burned at many of our facilities (i.e., South American or Central Appalachian-CAPP). As an example, at one of our facilities, we used primarily South American coal from 2006 to 2009 at an average S02 rate of O.7 lb/mmBtu and a HHV of 11,600 Btu/lb. In 2010, with the same coal supplier, the average S02 emission rate is approximately 0.9 lb/mmBtu and a HHV of 11,300 Btu/lb. This represents an approximate 20 percent increase in fuel sulfur content. We understand from our coal suppliers that in general the lower sulfur / high Btu coal has been mined and is no longer available. The coal suppliers have had to move to different seams of the coal mines that contain higher sulfur content. It is our understanding that this trend will continue in the future. [EPA-HQ-OAR-2009-0491-2715.1, p.10]
In addition, there has also been a dramatic decline in the amount of CAPP coal currently being produced. CAPP production dropped by approximately 50 million tons from 2008 to 2010 forecast and is expected to continue to decline. The EIA Annual Energy Outlook 2010 report states that 'Total production of Appalachian coal declines from current levels, as output shifts from the extensively mined, lower cost reserves of Central Appalachia to higher cost supplies from the Interior region and the northern part of the Appalachian basin.' Figure 88 of the same report shows that the Appalachia coal production is projected to steadily decline over the next few decades by about 25% from 2008 levels. This shift in the coal supply agrees with the general trend of increased sulfur contents as the northern Appalachian coals typically have S02 emission rates of approximately 3.5 to 6.0 lb/mmBtu. [EPA-HQ-OAR-2009-0491-2715.1, p.10]
Dominion bums lower sulfur western Powder River Basin (PRB) coal at its State Line (Indiana) and Kincaid (Illinois) facilities. However, this is not a viable option for our eastern coal fleet. Switching fuels for a boiler designed for CAPP coal to a western PRB coal presents several technical issues. A typical PRB coal has a S02 rate of 0.5 to 0.8 lb/mmBtu and a HHV of 8,300 to 8,800 Btu/lb. Converting a boiler designed for CAPP coal to PRB coal would result in de-rating the unit by approximately 30 to 40 percent. It would also require significant upgrades to the coal handling equipment in order to safely handle the more volatile PRB coal. The coal handling upgrades required to safely handle the PRB coal would more than likely require environmental permitting which would only add to the project's timeline. The coal handling upgrades can take a significant amount of time to complete because the schedule for the upgrades has to be balanced against the plant being able to continue to operate which requires using the same coal handling system to be upgraded. Dominion performed coal handling upgrades at our Salem Harbor Station (Massachusetts) and that project took approximately 2 years to complete. Therefore, a switch to lower-sulfur PRB coal poses significant technical, scheduling and economical concerns for Dominion. [EPA-HQ-OAR-2009-0491-2715.1, pp.10-11]
For these reasons, EPA should not assume that the use of lower sulfur coals in the 0.6 to 0.8 lb/mmBtu range that were used in the past and are represented in the NEEDS Version 3.02 EISA database (which reflects EPA-ETS 2006 boiler level emissions, fuel characteristics and pollution control equipment) are a readily available and technically or economically viable option for achieving significant S02 emission reductions going forward, particularly in the short-term. [EPA-HQ-OAR-2009-0491-2715.1, p.11]
EPA Should Justify Its Use of a Single Year Baseline and Explain Its Complex Methodology Used to Determine 2012 State Budgets [EPA-HQ-OAR-2009-0491-2715.1, p.15]
In the Technical Support Document (TSD) addressing the state budgets, EPA indicates that the 2012 budgets were calculated using a combination of reported emissions and heat input data (actual historical data) as of 2009 and IPM projections for 2012 for individual electric generating units, each adjusted to reflect emission control equipment projected to be in place by 2012. The budget for each state is established based on either the aggregate of the individual unit emissions based on the reported data or the projected IPM data, whichever is lower. We have several concerns with this approach: [EPA-HQ-OAR-2009-0491-2715.1, p.15]
It is not clear why two different approaches were used that resulted in the use of budgets based exclusively on reported (actual data) in some states, based solely on IPM projections in other states and a combination (actual data for S02 and reported data for NOx or visa-versa) in yet others. EPA should provide a more detailed explanation for this mixed and confusing methodology. [EPA-HQ-OAR-2009-0491-2715.1, p.15]
It is questionable why state budgets were determined using a baseline of only a single year of emissions and heat inputs. Under the NOx SIP call and CAIR rulemakings, EPA more appropriately used data averaged over a multi-year period to account for year-to-year variability and assure a more accurate representation of utilization for electric generating units. [EPA-HQ-OAR-2009-0491-2715.1, p.15]
EPA further notes that for NOx, 2008 data were used to 'account for unusually low utilization [or heat input] in 2009', while 2009 data were used for S02. While we agree with EPA's conclusion that 2009 was an unusual and unrepresentative year with respect to utilization and that, to the extent a single year of data is used, 2008 is more representative (than 2009), we question why EPA used 2009 data for S02 instead of 2008. EPA should provide an adequate explanation for its decision to use 2009 data for determining state S02 budgets. [EPA-HQ-OAR-2009-0491-2715.1, p.15]
Response:
EPA modeling includes assumptions regarding coal depletion over time.  EPA has based coal quality estimates on the most recent available information.  EPA IPMv4.10 documentation explains this in more detail.  EPA also notes that model unit level projections are not intended nor serve as unit level compliance requirements.
In regards to State budgets, EPA received significant comment during the Transport Rule public comment period and has revised its approach for determining state budgets.  The final Transport Rule process for determining state budgets is explained in preamble section VI.D and further discussed in the "Significant Contribution and State Emissions Budgets Final Rule TSD".
Organization: Duke Energy
Comment:
Duke Energy
EPA's NEEDSv3.02_Database Incorrectly Shows Duke Energy's W H Zimmer Scrubber at a 98% Removal Efficiency.
In its modeling, EPA incorrectly assumed that the existing Zimmer (ORISPL 6019) Unit 1 FGD system ("scrubber") is capable of a 98% SO2 removal efficiency. This unit cannot average 98% removal and EPA should use a lower assumed removal percentage for setting the Ohio state SO2 budgets and allocating SO2 allowances. Duke Energy strongly recommends a removal efficiency of no greater than 95%. The Zimmer Station Unit 1 scrubber was designed in the late 1980's. As an NSPS unit, it was permitted and constructed at that time to meet a 91% removal requirement. Its scrubber tower size and configuration was designed to use a magnesium enhanced lime process which places significant restrictions on its performance. This unit has a much smaller tower height compared to limestone scrubbers and is limited to a much lower liquid to gas ratio. These physical limitations coupled with the process's chemical reaction kinetics make 98% removal efficiency unattainable. If Zimmer's scrubber were intended to achieve 98% removal, it would have been designed and constructed very differently. These changes cannot be retrofitted into the existing unit.  [EPA-HQ-OAR-2009-0491-2689.1, pp.39-40]
Duke Energy projects that this unit at best can achieve a 95% removal, but even this level of performance has not been demonstrated on a sustained basis. Achieving even this level exceeds the scrubber's original design envelope and operating outside the air permit's specification to operate with installed spare equipment. As another example, to prevent pluggage due to scaling, the mist eliminators in each module must undergo regular cleaning. This requires that one of the six modules is almost always out of service an any given time. This necessity was reflected in the original facility air permit. For these reasons, Duke Energy therefore recommends that EPA assume a removal efficiency of no more than 95% for Zimmer's scrubber. [EPA-HQ-OAR-2009-0491-2689.1, p.40]
Duke Energy's Miami Fort Units 7 and 8 Have Very Limited Capability to Burn Subbituminous Coal.
The NEEDSv3.02 database shows that Duke Energy's Miami Fort (ORISPL 2832) units 7 and 8 are capable of burning both bituminous and subbituminous coal. These units are capable of burning up to a 20% blend of subbituminous coal. Significant capital investment would be required to allow the unit to safely handle and burn this fuel type in blends higher than 20%, such as fuel handling upgrades, dust suppression, mill modifications and fire protection, boiler tube surface changes, sootblower additions, etc. However, Miami Fort Station does not have a coal handling system that would allow for the controlled blending of bituminous and subbituminous coals, and these units cannot burn straight subbituminous coal (such as with alternating the fuel types). Therefore, EPA must include the cost of an on-site coal blending system (approximately $55 million for the two units), or increase the cost of the delivered fuel to account for off-site blending cost premiums (approximately $10 to $14 per ton of blended coal from terminals on the Ohio River) in any consideration of subbituminous coal at these units. [EPA-HQ-OAR-2009-0491-2689.1, pp.40-41]
Response:
In response to concerns such as those expressed above, EPA updated its modeling to better reflect the removal efficiencies of existing scrubbers and the ability of units to switch coals.  See EPA IPM v.4.10 documentation for a complete explanation of these updates and others.  FGD removal efficiencies were indexed to historic performance for the unit - this resulted in the Zimmer unit's removal efficiency being adjusted to 95% as suggested by commenter.
Organization: Edison Electric Institute (EEI)
Comment:
Edison Electric Institute (EEI)
In the proposed Transport Rule, EPA asserts that the vast majority of 2012 compliance actions are already in the pipeline, which some EEI member companies believe to be the case. Other EEI member companies have expressed concern that EPA's assumptions regarding their current unit operation and new control technology projects may be inaccurate and that they will have difficulty achieving the initial 2012 compliance deadlines. If such EPA assumptions are incorrect, it could make compliance difficult or unrealistic for some companies. Examples of such concerns are presented in the next section of these comments.  [EPA-HQ-OAR-2009-0491-2697.1, p.9]
Some examples of the types of inaccuracies that companies are concerned about include:
-American Electric Power (AEP) (in a written statement submitted to the Senate Environment & Public Works Committee hearing on July 22, 2010) stated that "EPA assumed that AEP will have scrubbed its 585 MW Muskingum River Unit No. 5 in Ohio by January 1, 2011 or only 6 months from now. However, while preliminary engineering was begun several years ago, there is no ongoing construction activity associated with this retrofit project. Even if engineering and construction recommenced today, the actual in-service date for the scrubber would still be at least three years from now." AEP also stated that "
EPA assumes that the AEP Muskingum 1-4 units (830 MW) are able shift to lower sulfur coals in its analysis (1.0-1.4 lb-SO2/mmBtu). However, these units are wet bottom / cyclone-fired boilers, which cannot tolerate most low-sulfur Eastern coals due to their high ash fusion temperatures. Thus, this is a very unrealistic assumption."    [EPA-HQ-OAR-2009-0491-2697.1, p.11]
-Empire District Electric has identified discrepancies which it will ask EPA to correct, such as: "In the TSD "State Budgets, Unit Allocations, and Unit Emissions Rates" some units in Missouri (Iatan, Lake Road, New Madrid 2, and Thomas Hill) are to receive an increase in the number of SO2 allowances in 2014 compared to 2012. The company also notes that a new coal unit, Iatan 2, constructed by KCP&L that will be on-line before 2012 is not included in the Missouri data in the TSD "State Budgets, Unit Allocations, and Unit Emissions Rates".   [EPA-HQ-OAR-2009-0491-2697.1, p.11]
-Consumers Energy will report numerous company-specific issues with EPA assumptions, such as the fact that "There appears to be an assumed retirements at the following units, which at this time Consumers has no plans to retire: B C Cobb Units 1, 2, 3; D E Karn Units 3, 4; and Thetford Units 1, 2, 3, 4. Also, Consumers Energy observes that "It is assumed that J H Campbell Unit 2 will have an SCR operational in 2012, which it will not." Finally, the company will comment that "There appears to be an assumption that Consumers will be fuel switching to an extremely low sulfur coal on the following units in 2012: B C Cobb Units 4, 5; and J R Whiting Units 1, 2, 3. This option is not feasible due to the limited time constraints and outstanding coal, rail-line, vessel and rail-car contracts."   [EPA-HQ-OAR-2009-0491-2697.1, p.12]
-Tampa Electric, in testimony at EPA's public hearings on the Proposed Rule in Philadelphia, observed that: "Just within our mid-sized electric generation fleet, a number of model input assumption errors have been identified. Examples of the type of errors include: allocating different emission budgets to identically sized and controlled units, or dispatching the same unit differently for estimated NOx and SO2 future emissions and consequential downwind effects."  [EPA-HQ-OAR-2009-0491-2697.1, p.12]
-Dominion Resources notes that EPA assumes the installation of a wet scrubber at the Brayton Point Power Station Unit 3 by 2012. Instead, under a state-approved Emission Control Plan, a dry scrubber will be installed on Brayton Point Unit 3 that will commence operation in 2014. The company also finds that EPA has not allocated NOx emissions to Salem Harbor Units 1 and 2 even through the IPM model for the base case 2012 run predicts these units will operate. [EPA-HQ-OAR-2009-0491-2697.1, p.12]
Response:
In response to concerns such as those expressed by the commenter, EPA has taken two actions for this final Transport Rule
1) It has updated its IPMv.4.10 model used in the final Transport Rule from that used in the proposed Transport Rule.  These updates capture and correct many of the unit level discrepancies highlighted by commenters.  For example, the IPM base case no longer assumes a scrubber at Muskingham River un 5 by 2011, instead it is projected to occur in 2014 and the timing is much more consistent with those installation dates imposed by consent decrees impacting the unit.  For a more detailed description of the IPM v.4.10 platform, assumptions, and updates to assumptions, see the IPMv.4.10 documentation.  Also, the "Transport Rule IPM Assumptions Response to Comments" in the Appendix further describes some of the unit level changes that were made.
2) EPA also finalized an allocation methodology that relies on historic data instead of projected data.  By relying on historic data, many of the comments that expresses concerns over the direct impact that IPM unit level projections had on their unit's allocation are addressed.  The final allocation methodology is based on historic data that is reported by the source's DR who has testified to its accuracy and completeness.
Organization: Edison Mission Energy (EME)
Comment:
Edison Mission Energy (EME)
With respect to the first assumption, EPA states in the preamble that the reductions required during Phase I of the Transport Rule represent those NOx and SO2 emissions reductions that can be obtained using existing controls that are already in place and those controls that EPA believes will be installed and available by 2012. The Agency's assumption about the level of control that will be obtained by existing controls relies on unrealistic assumptions about the level of performance that can be obtained by those controls, calling into question the feasibility of meeting the Phase I cap (see Section III.B.1). [EPA-HQ-OAR-2009-0491-2707.1, p.17]
Response:
EPA has modified its removal assumptions for existing controls.  See "Transport Rule IPM Assumptions Response to Comments" in Appendix for details on how existing FGD removal rates have been indexed to historic performance.  Furthermore, EPA does not believe that compliance with Transport Rule Budgets hinges on any one specific technology or compliance strategy, nor does it require one.  As discussed in section VII.C of the preamble, there are multiple compliance options available to sources to collectively comply with their state budget.
Organization: Entergy Services, Inc.
Comment:
Entergy Services, Inc.
Entergy Supports The Integrated Planning Model (IPM) Results to Determine State Budgets, With Qualifications
Results from the IPM market simulation tool played a significant role in developing the budgets EPA has proposed for the Transport Rule.  As a result, the EPA's IPM input assumptions have a significant impact on the nature and stringency of the proposed Transport Rule.  One such key assumption is natural gas resources, as gas price projections have the potential to strongly affect the dispatch of generating units.  In the original Base Case (v3.02), natural gas input assumptions produced gas prices that differ considerably from forward market projections (used to represent an objective "industry view").  For example, Henry Hub gas prices average about $7.25/mmBtu from 2012-2015 in the original Base Case (v.3.02), whereas the current futures for that timeframe average approximately $5.75/mmBtu.  Entergy agrees with EPA's use of the IPM in determining the NOx emissions budgets of the affected states and believes that with the right assumptions, IPM adequately depicts future demand needs at regional and state levels.  However, Entergy encourages EPA to use the Energy Information Administration's Annual Energy Outlook natural gas resource forecast contained in v4.10_AEO Gas in the final rule, as these assumptions more accurately predict market futures based on current information.  [EPA-HQ-OAR-2009-0491-2847.1,p.2]
Response:
EPA has made significant changes to its proposed IPM modeling.  These changes are reflected in the EPA IPM v.4.10 that was used for the final Transport Rule.  Among the updates made, natural gas input assumptions were modified from those used in the proposed modeling.  See EPA IPM v.4.10 documentation for more explanation on the final model, assumptions, and updates to assumptions.
Organization: Exxon Mobil Corporation
Comment:
Exxon Mobil Corporation
EPA's original modeling, using the IPM version 3.02 for the Base Case, projected that Louisiana emissions may interfere with maintenance of the annual PM2.5 NAAQS in 2012, by contributing only 0.34 ug/m3 to the annual PM2.5 values at the Clinton Drive monitor in Houston, Harris Co., TX. Of that total, EPA projected that 0.33 ug/m3 is from sulfate emissions and only 0.004 ug/m3 from nitrate emissions. The projected design value for the Clinton Drive monitor in 2012 was 14.74 ug/m3 average and 15.14 ug/m3 maximum compared to the 15.0 NAAQS ug/m3. The 2008 PM2.5 annual average at Clinton Drive was 14.0 ug/m3, even when exceptional event days are included. The annual average PM2.5 in 2009 was only 12.8 ug/m35 and from January 1 through August 29, 2010, the average is 12.72 ug/m3. 6 The design value dropped to 14.4 ug/m3 for the 2007-2009 period and is expected to drop to a value of approximately 13.2 ug/m3 further this year due to 2007 dropping out of the 3-year average. 7 So, it is clear that Louisiana emissions now are not interfering with maintenance of the NAAQS in any way.
EPA also projected, under the IPM version 3.02 Base Case, that Louisiana emissions will significantly contribute to nonattainment with the 1997 8-hour ozone NAAQS at certain monitoring sites in the Houston-Galveston-Brazoria ('HGB') and the Dallas-Ft. Worth ('DFW') Areas of Texas in 2012. EPA has projected that Louisiana emissions will interfere with maintenance of that NAAQS at other monitoring sites in the HGB and the DFW Areas of Texas in 2012. But, again, real data cast doubt on these projections. All monitors in the HGB Area are currently in attainment with the 1997 8-hour ozone NAAQS and have been since 2008 (based upon the 2006-2008 monitoring data). All of the DFW monitors that EPA projected were adversely impacted by Louisiana emissions, save one, are also currently in attainment with that NAAQS. The design value at that one monitor at issue in DFW is 86 ppb, just 2 ppb above the standard.

6 Texas Commission on Environmental Quality, CAMS 403, PM-2.5 (Local Conditions) Acceptable Summary for 2010, http://www.tceq.state.tx.us/cgi-bin/compliance/monops/vearlv_summary.pl (last visited Sep. 21, 2010).
7 Texas Commission on Environmental Quality, PM2.5 Data: Soot, Dust, Particulate Matter, (last visited Oct. 1, 2010)
Response:
EPA has updated its IPM modeling and EGU emissions inventories in response to comments on the IPM version 3.02 for the base case.  As a consequence, the base case EGU emissions for states have changed.  EPA conducted its final air quality modeling off the updated base case.  In the final Transport Rule, Louisiana is no longer subject to Transport Rule annual PM2.5 programs.  However, the updated IPM and air quality modeling indicate the state is still "linked" to Texas receptors sites at Brazoria and Harris for 8-hour ozone.  See section V.D of the preamble for more details.  Additionally, see IPM documentation,  "Documentation Supplement for EPA Base Case v.4.10_FTransport  -  Updates for Final Transport Rule" and "Transport Rule IPM Assumptions Response to Comments" for details regarding IPM updates and assumptions in the v.4.10 used in the final Transport Rule.
Organization: Florida Department of Environmental Protection
Comment:
Florida Department of Environmental Protection
  The Division has reviewed the IPM model results that were used to generate the emissions for 2012 and 2014. Because the IPM model results do not appear to reflect actual Florida generation dispatch, the proposed allocations, especially for NOx, are very different than 2009 actual emissions, or what we anticipate emissions will be in 2012 and 2014. We were not able to actually replicate the NOx unit allocations and we would like to see an explicit accounting of these calculations to understand how they were derived. However, probably due to the combination of the use of the IPM model and incorrect current emissions, the NOx allocations seem to be random and will result in a great deal of intrastate trading to more closely align allocations with actual emissions in 2012. [EPA-HQ-OAR-2009-0491-2624.1, p.1]
In reviewing Florida-specific source attribution, we are concerned that the emissions from Gulf Power's Crist facility were dramatically overestimated. For example, the NOx emissions were modeled at approximately twice the allowable federally enforceable limits. Since Florida's only linkage to downwind nonattainment of ozone is to Harris and Tarrant counties in Texas, it is critical that Gulf Power's emissions be accurately reflected in the modeling. In fact, since Florida's impact was 0.8 ppb, which is the threshold for significance, and the Crist facility is the furthest westward facility in Florida, it is possible Florida may have no significant impact if the correct emissions were modeled. [EPA-HQ-OAR-2009-0491-2624.1, p.1]
Response:
EPA response to FL DEP is threefold
1) In response to concerns such as those expressed above, EPA has modified its allocation methodology to be based on historic data.  Furthermore, the approach chosen limits any units allocation to an amount less than or equal to its historic maximum emissions.  EPA is no longer relying on the IPM model, as it did in the proposal to determine allowance allocations
2) In response to these concerns, EPA has also updated its model.  As a result the 2012 and 2014 generation dispatch for the state have changed.  See "EPA's IPM Base Case v.4.10 documentation", "Documentation Supplement for EPA Base Case v.4.10_FTransport  -  Updates for Final Transport Rule", and "Transport Rule IPM Assumptions Response to Comments" for more details on updates to IPM.
3) In regards to the NOx emissions modeled for the Crist facility, EPA has made a series of updates that are covered in the sources documented above.  The final TR base case has emissions for the Crist facility that are significantly less than those in the proposal.  The air quality modeling for the final rule was conducted on these updated model values.
Organization: Florida Municipal Electric Association (FMEA)
Comment:
Florida Municipal Electric Association (FMEA)
EPA Must Give Affected Sources an Opportunity to Participate in Additional Modeling Before the Rule Is Finalized. FMEA members have noticed multiple errors in EPA's "Unit Characteristic" spreadsheet and other spreadsheets which were utilized to base future reductions per this rulemaking, e.g., unit pollution control equipment in place and operating. In some cases, the pollution control device which is not listed in the spreadsheet has been installed for multiple years and is required to operate in order to meet State permit specific emission limits. [EPA-HQ-OAR-2009-0491-2731.1, p. 9]
As stated above, FMEA members will be sending comments on an entity-specific basis regarding the needed changes to EPA during this comment period. FMEA, however, is concerned that it will be deprived of an opportunity to comment after EPA makes the necessary corrections to their dataset. In sum, EPA will need to perform additional modeling and calculations after corrections have been made to many regulated units, and such changes will be substantial enough to warrant an additional notice and comment period. The correction of these extensive errors 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, and parties can meet their new compliance obligations. [EPA-HQ-OAR-2009-0491-2731.1, p. 9]
EPA modeling for determining significant interstate transport may be flawed: FMEA is concerned that the modeling done to determine an upwind state's significant contribution to a downwind state's non-attainment with a NAAQS may be flawed. Further, it is not appropriate to model EGU emissions based on pre-CAIR 2005 emissions. Since the CAIR reductions for many states, including Florida, may be real and enforceable under existing state permits, it is incorrect to model state impacts based on pre-CAIR emissions. [EPA-HQ-OAR-2009-0491-2731.1, pp. 9-10]
Response:
EPA issued updated modeling (EPA IPMv.4.10) and gave commenters a chance to review and comment on the data in its September 1, 2010 NODA.  EPA reviewed comments submitted and updated the modeling based on new input received from stakeholders.  EPA used the updated modeling in its final Transport Rule modeling to determine the appropriate Transport Rule Geography.  See section V of the preamble.  The preamble also discusses why CAIR was not included in the base case modeling.  In regards to reductions that are enforceable because of existing permit rates, those are reflected in the base case modeling and EPA made updates to this field indicator based on comments.
Organization: Kansas Department of Health and Environment
Kansas City Power and Light Company (KCP&L)
Comment:
Kansas City Power and Light Company (KCP&L)
1. There are errors in the unit information contained in the NEEDS Version 3.02 database.
a. Iatan Unit 1 (ID 6065_B_1)  -  The wet scrubber and SCR are not included. The PM control is incorrectly specified as an ESPC; it should be a baghouse. The wet scrubber, SCR, and baghouse became operational in Q1 2009. The SO2 permit rate should be 0.07 lb/mmBtu, per the current Title V operating permit, instead of 1.2 lb/MmBtu.
b. Lake Road Unit 6 (ID 2098_B_6)  -  The SO2 permit rate should be 1.43 lb/mmBtu, per the current Title V operating permit, instead of 8.6 lb/mmBtu.
c. Sibley Units 1 and 2 (ID 2094_B_1 and 2094_B_2)  -  SNCR is not included as post-combustion NOx control. The SNCR systems came online in Q2 2008.
d. Sibley Unit 3 (ID 2094_B_3)  -  The SCR is not included as post-combustion NOx control. The SCR came online in Q1 2009.
e. Iatan Unit 2 is not included in the database. [EPA-HQ-OAR-2009-0491-2709.1, p.5]
3. There are errors in the IPM 2012 Base model data.
a. The La Cygne Unit 1 NOx emission rate in the IPM 2012 Base model of 0.06 lb/mmBtu is incorrect. Correction of the Mode 4 rate to 0.094 lb/mmBtu, as discussed in 2.d.iv(1) above will resolve this inconsistency. However, modeling a rate based on the assumption that every SCR can achieve 90% control is not appropriate and represents a flaw in EPA's methodology. The SCR on this unit was designed to achieve the reductions necessary for compliance with its BACT-based construction permit limit of 0.15 lb/mmBtu. The IPM base case would yield more relevant results if units were modeled at their permitted emission rates, rather than an unachievable rate based either on 90% reduction or a floor of 0.06 lb/mmBtu. [EPA-HQ-OAR-2009-0491-2709.1, p.9][EPA-HQ-OAR-2009-0491-3757.1_NODA,p.5]
Comments Iatan Unit 2
Iatan Unit 2 is not included in the NEEDS 3.02 database. It may be represented by facility "SPPN_MO_Coal Steam" (ID 82710_B_1), but it is not clear what the data are based on. Because it is not included in the NEEDS 3.02 database, it did not receive any emissions allowances under the proposed rule. [EPA-HQ-OAR-2009-0491-2709.1, p.10]
The NEEDS v.4.10 database does not contain Iatan Unit 2 as an individual unit. According to the Documentation for EPA Base Case v.4.10, any units online or scheduled to come online between 2007 and the end of 2011 should be included as planned-committed units. While it is assumed Unit 2 is included in the aggregated record with similar units, it is not possible to verify any of its model input data. It can also only be assumed that Unit 2 will receive emissions allowances under the final rule; however it is not clear how planned-committed units will be able to verify the calculation of unit-level allowances. [EPA-HQ-OAR-2009-0491-2709.1, p.10][EPA-HQ-OAR-2009-0491-3757.1_NODA,p.6]
Details of Iatan Unit 2 are provided below.
- Iatan Unit 2 has a heat input capacity of 8,100 mmBtu/hr with a nominal gross generation capacity of 930 MW firing subbituminous coal. It includes an SCR, wet scrubber, baghouse, and ACI injection for mercury control.
- Construction permit issued January 31, 2006
- Acid Rain Program Permit Amendment filed to include Iatan Unit 2 on April 18, 2008. On June 16, 2009 the renewal of the Iatan Acid Rain Program five-year permit was filed, which included Unit 2 as "under construction".
- A Title V Operating Permit amendment application to include Unit 2 was filed on September 30, 2009.
- On February 3, 2010, the MDNR issued an Acid Rain Program Permit that included Unit 2 as "under construction". [EPA-HQ-OAR-2009-0491-2709.1, p.10][EPA-HQ-OAR-2009-0491-3757.1_NODA,pp.6-7]
- Unit 2 achieved start-up on July 20, 2010. The EPA and MDNR were notified of this by a letter dated July 23, 2010. [EPA-HQ-OAR-2009-0491-2709.1, p.11] [EPA-HQ-OAR-2009-0491-3757.1_NODA, p.7]
Kansas Department of Health and Environment
KDHE has compared the projected 2012 emissions estimates with actual emissions for our EGU sector. Figures 2 and 3 provide comparisons of recent actual emissions at the unit level with EPA 2012 estimates for NOx and SO2, respectively. These comparisons were made with the original IPM estimates. We have left the original IPM numbers in, since it is unclear how these NODA revisions will impact final allocations. Appendix A contains tables comparing historic unit level emissions with projected IPM emissions and proposed allocations. [EPA-HQ-OAR-2009-0491-2606.1, p.2] [[See Docket Number EPA-HQ-OAR-2009-0491-2606.1, pp.9-11 for Appendix A.]]
For NOx, Figure 2 clearly indicates the projected 2012 emissions are much higher than recent historic actual emissions. This is an indication that the 2012 IPM estimates don't accurately reflect control equipment installed on Kansas EGUs. [EPA-HQ-OAR-2009-0491-2606.1, p.2] [[See Docket Number EPA-HQ-OAR-2009-0491-2606.1, p.3 for Figure 2.]]
For SO2, Figure 3 indicates the recent actual SO2 emissions are very close to the future IPM emissions. While the future SO2 estimates appear close to likely actual emissions, a detailed unit-level look at the future emissions estimates indicates that further reductions need to be accounted for. These reductions are discussed in detail below with KDHE recommendations. [EPA-HQ-OAR-2009-0491-2606.1, p.3] [[See Docket Number EPA-HQ-OAR-2009-0491-2606.1, p.3 for Figure 3.]]
Based on these comparisons, KDHE believes several significant differences in the 2012 emissions estimates EPA is using will result in an overestimate of our modeled contribution to downwind nonattainment areas. These overestimates may be large enough that if corrected would remove Kansas from the list of ozone-contributing states. Specifically, the 2012 NOx estimates for KCP&L's La Cygne Unit 1 were too high in the original version of the IPM run and did not account for the SCR that is currently installed and operating on this unit. This appears to have been corrected in the latest version of the IPM run, possibly even being overcorrected. In addition, 2012 emission estimates for Westar Energy's Jeffrey Units 1-3 do not take into account the recent consent decree this company entered into with the United States Department of Justice (USDOJ) that will require NOx and SO2 reductions by 2012. This problem appears in both IPM runs. [EPA-HQ-OAR-2009-0491-2606.1, p.4]
La Cygne Unit 1 currently has a 2009 Clean Air Markets Division (CAMD) annual NOx rate of 0.11 lb/mmBtu. This is also the average rate for two years of actual operations with its SCR in operation. KDHE recommends for purposes of modeling that the 2009 average NOx rate of 0.11 lb/mmBtu be used in conjunction with the projected 2012 IPM heat input to estimate the emissions for La Cygne Unit 1 in 2012. KDHE believes this rate will be reflective of future operations for this control equipment. This recommended 0.11 lb/mmBtu rate is higher than the latest IPM rate of 0.06 lb/mmBtu, which appears to KDHE to be too optimistic based on historic operations of the SCR. La Cygne Unit 1 is required to continually operate this SCR for NOx control. The requirement for this unit to operate the SCR is included in a state construction permit issued by KDHE on November 18,2005. This permit limits this unit to 0.15 lb/mmBtu annually for NOx emissions. This permit condition will continue to apply in 2012 and thereafter. In addition to the construction permit, KCP&L has signed an agreement incorporating the 0.15 lb/mmBtu limit that will be submitted to Region 7 for incorporation in the Kansas State Implementation Plan (SIP) in the near future. This agreement is intended to ensure 'SIP enforceable' limits. The limits for the two coal-fired units at this facility will be further strengthened with upcoming BART controls as part of the Regional Haze Program, once approved by EPA. These BART control requirements will occur after the 2012 timeframe, however. The SCR construction permit and agreement for La Cygne Unit 1 is included in Appendix B. [EPA-HQ-OAR-2009-0491-2606.1][EPA-HQ-OAR-2009-0491-2606.1, p.4] [[See Docket Number EPA-HQ-OAR-2009-0491-2606.1, pp.12-16 for Appendix B.]]
For Jeffrey Units 1-3, a consent decree between the USDOJ and Westar Energy went into effect on March 26th , 2010, that requires substantial reductions in both NOx and SO2. For NOx the consent decree requires a 30-day rolling average unit emission rate for NOx of no greater than 0.180 lb/mmBtu beginning on December 31, 2011, and continuing thereafter. This rate applies to all three units at all times of the year. The new IPM runs and 2009 CAMD rates should therefore reflect emissions for Unit 3 with controls. However, the 2009 rates for Units 1 and 2 do not yet reflect the limits that will be required on these units by 2012. [EPA-HQ-OAR-2009-0491-2606.1, p.4]
KDHE recommends using the average 2010 CAMD emission rates of Units 1 and 3 for a proxy of the 2012 emission rate of Unit 2. For Unit 1 we recommend using the 2010 CAMD average rate. We make these recommendations based on the similar characteristics of the units' design and controls and the fact that all three units are subject to the same limits in the consent decree. Because these controls have just recently been installed, 2010 CAMD data is a more accurate estimate of future emission rates for Unit 1. Unit 2 does not currently have the controls to meet the limit but will by 2012, thus the average of like unit rates with controls should be a good estimate for this unit. At a minimum, Unit 2 should not be modeled higher than the consent decree limit of 0.18 lb/mmBtu. [EPA-HQ-OAR-2009-0491-2606.1, pp.4-5]
For SO2 at Jeffrey, the consent decree limits the three Jeffrey units to 6,600 tons total SO2 on a rolling 12-month basis. The agreement also limits the units to 0.07 lb/mmBtu SO2. These units all recently had scrubber rebuilds and all units are now operating with scrubbers. KDHE recommends that 2009 CAMD SO2 emission rates for Units 1 and 3 be used to reflect 2012 emission rates. For Unit 2, KDHE recommends the average emission rate in 2010 be used as this unit's flue gas desulfurization was not operational until 2009. [EPA-HQ-OAR-2009-0491-2606.1, p.5]
The Westar Energy consent decree can be found at: http://www.epa. gov/compliance/resources/decrees/civil/caa/westarenergy-cd.pdf.  [EPA-HQ-OAR-2009-0491-2606.1, p.5]
Emissions from EGUs in the Kansas City area are subject to a Kansas NOx emissions reduction rule, K.A.R. 28-19-713a. This rule will impact the emissions of two units in the Kansas City area. The units are Kansas City BPU's Nearman Creek Unit 1 (N1) and BPU Quindaro Unit 2 (Q2). The rule limit requirements are identified below. [EPA-HQ-OAR-2009-0491-2606.1, p.5]
28-19-713a. Emission limitation requirements. No owner or operator subject to K.A.R. 28-19-713 shall allow any emission unit to emit nitrogen oxides in excess of the following emission limitations based on a 30-day rolling average: (a) From electric generating units, for the purposes of K.A.R. 28-19-713 through K.A.R. 28-19-713d, the following: (l) 0.26 pounds per million British thermal units (lbs/ mmBtu) for unit 1, a turbo wall-fired Riley Stoker boiler located at the Nearman Creek power station in Kansas City, Kansas; and (2) 0.20 lbs/mmBtu for unit 2, a wall-fired Riley Stoker boiler located at the Quindaro power station in Kansas City, Kansas; and (b) from flat glass furnaces, 7.0 pounds per ton of glass produced. (Authorized by K.S.A. 2009 Supp. 65-3005; implementing K.S.A. 65-3010; effective June 25, 2010.) [EPA-HQ-OAR-2009-0491-2606.1, p.5]
In the original IPM runs N1 had an emission rate of 0.46 lb/mmBtu, while in the new version of IPM the rate is 0.441 lb/mmBtu. Both of these rates are higher than permitted in the rule above. Q2 has an emission rate of 0.304 lb/mmBtu in the original IPM run, while the new IPM run has a rate of 0.281 lb/mmBtu. Both of these rates are higher than permitted in the rule above. KDHE recommends a rate of0.26 lb/MmBtu for N1 and a rate of 0.20 lb/MmBtu for Q2 for the 2012 modeling. Using total heat input values in the new 2012 IPM runs of 13,801,240 MmBtu for N1 and 7,146,396 MmBtu for Q2 gives emissions reductions of 1290 tons and 289 tons, respectively. While the N1 reductions are not required by Jan 1, 2012, they will come into effect during the 2012 ozone season and KDHE believes they should be accounted for. [EPA-HQ-OAR-2009-0491-2606.1, p.5]
IPM modeling and cost curves appear to give unrealistic results for Kansas. One example is Table 1-1 in the TSD for significant contribution. This table indicates that, according to IPM modeling, annual NOx emissions from the Kansas EGU sector would be 33,000 tons (a decrease of 37,915 tons from the assumed 2012 base case without controls) if a marginal control cost of $500/ton is applied across the state. This large decrease seems very suspect using a $500/ton marginal cost, however, since as marginal control costs are increased (i.e., there is more spending on controls), the projected annual emissions increase rather than decrease in Kansas. If Kansas EGUs can get to 33,000 tons of reductions at a marginal cost of $500/ton, at a minimum they will also get to 33,000 tons of reductions (presumably even more reductions) at a marginal cost of $1,250/ton. To have the modeled emissions increase at a marginal control cost 2.5 times higher seems unlikely even when accounting for system-wide costs and demand. Perhaps these emission results can be explained by additional load being exported out of state under the higher control cost scenarios. If this is the case, it should be included so readers can better understand these results. At a minimum, this counterintuitive result of emissions increasing with increasing marginal costs of controls needs to be better described. [EPA-HQ-OAR-2009-0491-2606.1, p.7]
Response:
EPA carefully reviewed and updated its IPM modeling based on unit specific comments for these sources as well as broader modeling assumptions (i.e., state rules, consent decrees) based on comments provided.  It then used the updated EPA IPMv.4.10 modeling to analyze contribution to nonattainment and interference with maintenance, see section V of the preamble for a discussion of the air quality modeling results.  EPA updated its model to reflect unit specific comments - for example the SCR and SNCRs at the Sibley units are reflected in the updated 4.10 model version.  EPA also updated its constraints to reflect the Westar Consent Decree and the Kansas Rule K.A.R. 28-19-713a.
In regards to an observed emissions increase at higher cost thresholds, EPA notes that SO2 emissions in this final rule are only examined at the $500/ton cost threshold level.  Examination of higher SO2 cost thresholds for the state is not necessary because Kansas is a Group 2 state and its significant contribution to nonattainment and interference with maintenance is eliminated at this cost threshold.  Therefore, in this final rule, there are no emission results from higher SO2 cost thresholds for the state of Kansas to which the $500/ton cost thresholds emission levels would be compared to.  However, it is worth noting that the final cost curves reflect the appropriate cost thresholds for all covered states and covered pollutants simultaneously to best reflect how industry faces the cost and compliance requirement simultaneously.  As cost thresholds increase in Group 1 states, but stay constant in Group 2 states - there can be some generation re-balancing in the model optimization that results in an emissions increase in a Group 2 state.  This occurs because the generating resources in those states become more cost competitive relative to generating resources in Group 1 states with increasing cost thresholds.  Even as cost thresholds increase equally among of group of states, there may still be some generation shifting as low emission-rate sources in one state become increasingly cost competitive to higher emission-rate sources in another state.  Therefore, EPA notes that, while not common, it is possible to observe slightly higher emissions in a particular state at a higher cost threshold.
Organization: Louisiana Chemical Association (LCA)
Comment:
Louisiana Chemical Association (LCA)
3. Further, we believe that other errors were made in EPA's modeled projections of operating scenarios for various units. [EPA-HQ-OAR-2009-0491-1925.1, p. 2]
Failure to Include Reductions from Louisiana NOx RACT EPA failed to include NOx emission reductions that occurred in 2005 and since 2005 as a result of the LDEQ NOx RACT rule in LAC 33:III.Chapter 22 and reductions due to amendments to that rule. In the documentation of IPM v. 3.02, there is no mention of this rule at all. [EPA-HQ-OAR-2009-0491-3527.1, p. 27; see pp. 27-29 for extensive discussion of this issue.]
EPA's original modeling, using the IPM version 3.02 for the Base Case, projected that Louisiana emissions may interfere with maintenance of the annual PM2.5 NAAQS in 2012, by contributing only 0.34 ug/m3 to the annual PM2.5 values at the Clinton Drive monitor in Houston, Harris Co., TX. Of that total, EPA projected that 0.33 ug/m3 is from sulfate emissions and only 0.004 ug/m3 from nitrate emissions. The projected design value for the Clinton Drive monitor in 2012 was 14.74 ug/m3 average and 15.14 ug/m3 maximum compared to the 15.0 NAAQS ug/m3. The 2008 PM2.5 annual average at Clinton Drive was 14.0 btg/m3, even when exceptional event days are included. The annual average PM2.5 in 2009 was only 12.8 ug/m3 and from January 1 through August 29, 2010, the average is 12.72 ug/m3. 8 The design value dropped to 14.4 ug/m; for the 2007-2009 period and is expected to drop to a value of approximately 13.2 ug/m3 further this year due to 2007 dropping out of the 3-year average. 9 So, it is clear that Louisiana emissions now are not interfering with maintenance of the NAAQS in any way These Louisiana emissions are projected by EPA to drop even farther without the CATR/FIP. [EPA-HQ-OAR-2009-0491-3790.1_NODA, pp.2-3]
EPA also projected, under the IPM version 3.02 Base Case, that Louisiana emissions will significantly contribute to nonattaimnent with the 1997 8-hour ozone NAAQS at certain monitoring sites in the Houston-Galveston-Brazoria ('HOB') and the Dallas-Ft. Worth ('DFW') Areas of Texas in 2012. EPA has projected that Louisiana emissions will interfere with maintenance of that NAAQS at other monitoring sites in the HOB and the DFW Areas of Texas in 2012. But, again, real data cast doubt on these projections. All monitors in the HGB Area are currently in attainment with the 1997 8-hour ozone NAAQS and have been since 2008 (based upon the 2006-2008 monitoring data). All of the DFW monitors that EPA projected were adversely impacted by Louisiana emissions, save one, are also currently in attainment with that NAAQS. The design value at that one monitor at issue in DFW is 86 ppb, just 2 ppb above the standard. [EPA-HQ-OAR-2009-0491-3790.1_NODA, p.3]

8 Texas Commission on Environmental Quality, CAMS 403, PM-2.5 (Local Conditions) Acceptable Summary for 2010, http://www.tceq.state.tx.us/cgi-bin/compliance/monops/yearly_summarv.pl (last visited Sep. 21, 2010).
9 Texas Commission on Environmental Quality, PM2.5 Data: Soot, Dust, Particulate Matter, (last visited Oct. 1, 2010).
Response:
EPA has updated its IPM modeling and EGU emissions inventories in response to comments on the IPM version 3.02 for the base case.  As a consequence, the base case EGU emissions for states have changed.  EPA conducted its final air quality modeling off the updated base case.  In the final Transport Rule, Louisiana is no longer subject to Transport Rule annual PM2.5 programs.  However, the updated IPM and air quality modeling indicate the state is still "linked" to Texas receptors sites at Brazoria and Harris for 8-hour ozone.  See section V.D of the preamble for more details.  Additionally, see IPM documentation,  "Documentation Supplement for EPA Base Case v.4.10_FTransport  -  Updates for Final Transport Rule" and "Transport Rule IPM Assumptions Response to Comments" for details regarding IPM updates and assumptions in the v.4.10 used in the final Transport Rule.  Also, EPA notes that the 2012 base case used in air quality modeling represents power sector operations in the absence of CAIR.  Both the proposal and final rule preamble explain why this is necessary.  Therefore, comments suggesting that 2012 base case emissions data and receptor status in the final Transport Rule are incorrect simply because they do not reflect recent emissions data and receptor status observed once the CAIR rule was final are misguided, as EPA has clearly stated that the base case represents a world without CAIR.
Organization: Massachusetts Department of Environmental Protection
Comment:
Massachusetts Department of Environmental Protection
We encourage EPA to rigorously review the input files and assertions made in several technical support documents found in the proposed Transport Rule regulatory docket that appear to need additional quality assurance of internal and external data sources. MassDEP and other OTC member states collaborated in the review of IPM documentation, including the Technical Support Document, Updates to EPA Base Case v3.02 EISA Using the Integrated Planning Model, and other materials and found common concerns and issues. A number of Massachusetts facilities have indicated that they have concerns with the quality and accuracy of the technical support documentation that mirror those of MassDEP and other states.
In addition to questions related to data accuracy, we have concerns about the assumptions in the IPM input files and documentation and, as a consequence, with the IPM outcomes. MassDEP, like other States, is concerned with the lack of transparency in the proprietary IPM and its anomalous modeling results. 17 For example, under the proposed Transport Rule allocations, the Massachusetts residual oil-and natural gas-fired steam (oil/gas steam) units receive no allocations of S02 allowances (although the same units do receive NOx allocations). We believe that certain assumptions built into the IPM analysis are contributing to a bias in the S02 allocation that favors the coal-fired units in Massachusetts. We urge EPA to closely review recent trends in the capacity factors and dispatch trends of regional transmission organizations for certain plant types, particularly oil/gas steam units and gas/oil combined cycle units in ensure that the appropriate units are being allocated allowances.
We note IPM technical documentation identifies 'turndown assumptions that prevent coal and oil/gas steam units from operating strictly as peaking units, which would be inconsistent with their operating capabilities.' 1 8 While the original operational parameters for these oil/gas steam units did not contemplate their utilization as peaking units, operators have responded to changing market conditions. Examining peak demand episodes between 2005 and 2008 in New England, ISO-NE has observed an increased utilization of oil/gas steam units in the dispatch of the last 500 MW decrement during high energy demand episodes. 19 In Massachusetts and other New England States, oil/gas steam units are being utilized as peaking assets during high energy demand episodes; this contradicts the IPM turndown assumptions that prohibit modeling of these market conditions.
We urge EPA to more closely review actual operational behavior of individual plant type units in regional power pools rather than relying so heavily on the IPM macro assumptions, which do not incorporate evolving market conditions in projecting future operations. IPM assumptions, inventories, and output results should be re-examined so that Massachusetts final budget for S02 and NOx reflect the continued operation of, and emissions from, oil/gas steam and gas/oil combined cycle units. We believe the present IPM output results are inconsistent with existing and projected market trends that I80-NE considers most likely in their regional system reliability planning.
We understand that the IPM treatment of combined cycle units reflects an allocation methodology based upon historical heat input and multiplying that against the S02 pipeline natural gas emission factor of 0.0006 lb/mmBtu. Since the IPM module builds out the model combined cycle units across the four quarters, and S02emissions are between 2-4 tons for the largest combined cycle units in Massachusetts, IPM appears to be calculating quarterly emissions at less than 0.5 tons and then rounding down to 0 tons. Hence the units are allocated zero 802 allowances. EPA should modify the application of the rounding convention to extremely low emitting base-load and intermediate-load following combined cycle units to allow rounding up to a level that will reflect the historical emissions level on an adjusting three-year rolling average.
Response:
EPA has made substantial updates to the IPM v.3.02 modeling used in the proposal.  The final EPA IPMv.4.10 modeling reflects updates to unit level and macro level assumptions.  See EPA IPMv.4.10 documentation for further details.  In addition, EPA notes that it changed its allocation methodology from one based on projected data to one based on historic data.  This, in concert with the IPM modeling updates, address many of the concerns expressed above.  Additionally, EPA notes that Massachusetts is not covered under the final Transport Rule geography.
Organization: Minnesota Power
Comment:
Minnesota emission reductions.  Minnesota utility sources are already providing for SO2 and NOx reductions under the Northeast Minnesota Regional Emission Reduction Program filed as part of Minnesota's Regional Haze State Implementation Plan (SIP) currently before EPA for approval.  These emission reductions combine with the effect of the Minnesota Renewable Energy Performance Standard which requires delivery of up to 25% of Minnesota retail energy sales from qualifying renewable energy resources by 2025.  Collectively, these Minnesota initiated measures are delivering reductions in emissions comparable to the EPA Transport Rule Group 2 State requirements.  The impact from both state and regional renewable energy performance standards should be included in EPA's modeling analysis and it is not clear from review of EPA technical support documentation that the effects of state mandated renewable energy have been included.    [EPA-HQ-OAR-2009-0491-2750.1, p.8]
Response:
In EPA Base Case modeling, the state Renewable Portfolio Standards (RPS) are represented at a regional level utilizing the aggregate regional representation of RPS requirements that is implemented in AEO 2010, as shown in Appendix 3-6.  This appendix shows the RPS requirements that apply to the NEMS (National Energy Modeling System) regions used in AEO. The RPS requirement for a particular NEMS region applies to all IPM regions that are predominantly contained in that NEMS region.
Organization: National Grid
Allegheny Energy
Tennessee Valley Authority (TVA)
Council of Industrial Boiler Owners (CIBO)
Dayton Power and Light Company (DP&L)
Consolidated Edison Company of New York, Inc, (CECONY)
Wabash Valley Power
Utility Air Regulatory Group (UARG)
NextEra Energy, Inc.
RRI Energy, Inc.
First Energy
Progress Energy Service Company
Kentucky Chamber of Commerce
Comment:
Allegheny Energy
Two errors, covering multiple AE stations, in the IPM results are identified below:
1] Two units at AE's Fort Martin power station in West Virginia and one unit at the Hatfield's Ferry power station in Pennsylvania have SNCR listed as control devices with an assumed year-round 35% removal efficiency. These SNCR's are single point injection (identified as SNCR-trim) that are only capable of 10% to possibly 15% reductions.
2) Year round selective catalytic reduction (SCR) controls are assumed at AE's Harrison and Pleasants power stations located in West Virginia at NOx rates (as low as 0.04 - 0.05 lb/mmBtu) that were established during the first few years of operation during the ozone season (May 1 to September 30) only. Subsequently, AE has found that these NOx rates cannot be sustained during year round operation as the catalyst ages and operational anomalies arise. In fact, AE's experience indicates that annual NOx rates on the order of 0.09 - 0.11 lb/mmBtu are more realistically achievable for year round SCR operation. [EPA-HQ-OAR-2009-0491-2605.1, p.5]
Three discrepancies in IPM's results are identified below:
1] The IPM results presume scrubbers on two units at AE's Armstrong power station in Pennsylvania and one unit at Willow Island in West Virginia. For the record, AE does not currently have plans to install scrubbers on these stations by 2014.
2] The IPM results retire AE's Rivesville power station's two units and one unit at Willow Island power station, both located in West Virginia, by 2014. For the record, AE has no current plans to retire these units by that date.
3] Fuel switches are assumed in the IPM results at three units at AE's Albright power station in West Virginia and two units at AE's R. Paul Smith power station located in Maryland before 2014. For the record, AE has no current plans to make fuel switches at these units by that date. [EPA-HQ-OAR-2009-0491-2605.1, p.5]
Consolidated Edison Company of New York, Inc, (CECONY)
Recommended Changes to 'Parsed File_TR Base Case_2012'
The Company understands that the data file entitled 'Parsed File TR Base_ Case_2012' (hereinafter, 'Base Case file') is intended to represent the IPM model's projection of which units within the United State's electrical system are likely to run in the first year of the proposed rule's applicability, 2012. The output is provided on both an ozone season basis and an annual basis. In the comments below, the Company presents a data element from the Base Case file, and offers an alternative outcome. The reasons supporting the alternative outcome are provided with each item. [EPA-HQ-OAR-2009-0491-2653.1, p.8; See EPA-HQ-OAR-2009-0491-2653.1, pp.8-1 for comments pertaining to Recommended Changes to 'Parsed File_TR Base Case_2012; See EPA-HQ-OAR-2009-0491-2653.1, pp.8-11 for tables: Data Issue No. B-1 (ozone season) fuel use, Data Issue No. B-2: Total Fuel Use, Data Issue No. B-3: Summer (ozone season) NOx Emissions, Data Issue No. B-4: Total NOx Emissions, and Data Issue No. B-5: Total SO2 Emission (MTon]
Recommended Changes to 'Parsed File_TR SB Limited TradinV014'
Data Issue No. C-l: All Columns Identified in Section B The Company notes that the incorrect modeling assumptions that led to inappropriate results for the output file described in Section B (above) are also incorrect in this output file. Specifically, Summer Fuel Use (column U), Total Fuel Use (column V), Summer NOx Emission (column AC), Total NOx Emission (column AD), Total C02 Emission (column AF) and Total Mercury Emission (column AG) have all be incorrectly characterized or calculated. [EPA-HQ-OAR-2009-0491-2653.1, p.11]
Council of Industrial Boiler Owners (CIBO)
Many other concerns are raised by EPA's analysis including: [EPA-HQ-OAR-2009-0491-2751.1 p.9; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, p.5, 10/15/2010]
The IPM Model does not account for past operating experiences and represents a snapshot in time.  these comments also appeared in [EPA-HQ-OAR-2009-0491-2751.1 p.9; EPA-HQ-OAR-2009-0491-3754.1_NODA, p.5, 10/15/2010]
The assumptions made and inputted by EPA determine winners and losers. EPA should be tying the facilities' heat input to historical operation and historical heat inputs. EPA's approach provides units that EPA is determining to be losers (lower availability and lower total heat inputs) and provides others with higher availability and higher heat inputs. The result is the facility receives its allowances based on the heat input. This does not provide the opportunity for those facilities based on past operating conditions a chance to make independent economic decisions to run.  [EPA-HQ-OAR-2009-0491-2751.1 p.9; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, p.5, 10/15/2010]
EPA has tied the model to electric output, but there are numerous cases where plants continue to operate and supply VARS rather than MWs. Also, the model does not account for contracts for energy, capacity, Renewable Energy Credits, or cogeneration contracts to supply heat and steam or other financial obligations.  [EPA-HQ-OAR-2009-0491-2751.1 p.9; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, p.5, 10/15/2010]
The NEEDs data bases (used for v3.02 and v4.10 of the IPM Model runs) are significantly different. One area of this difference is tied to the facilities' heat rate. Lowering the heat rate (as occurs for some plants in comparing v3.02 and v4.10 data) leads to lower total heat input and will most likely result in lower allowances for these plants. The availability information prepared by EPA does not recognize plants that may have had extended forced outages, resulting in EPA lowering the normal availability rates for some plants below their typical historical availability.  [EPA-HQ-OAR-2009-0491-2751.1 p.9; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, pp.5-6, 10/15/2010]
There are numerous factors regarding dispatch. Fuel costs and fuel supply curves specifically for waste coal are inaccurate and not reflective of the fuels costs for waste coal plants. Further, States divided into different model regions further complicates the issues dealing with projecting future operations and thus increased heat inputs.  [EPA-HQ-OAR-2009-0491-2751.1 p.9; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, p.6, 10/15/2010]
EPA's failure to consider the impact on units that must meet contractual or other obligations is significant. Some units must supply VARS (Volt  - Amps-Reactive) to maintain grid reliability rather than actual energy in MWs. Long runs of conductors and many industrial motor loads tend to resist actual power flow. This condition is called Inductive Reactance and generally makes current flow lag voltage. This condition increases as the distance from the generation site increases. To counteract this effect, distributed generation units in remote areas often produce both MWs and VARs.  Doing so inhibits the actual MW output of the facility, but restores the quality of the grid system. The current rule does not recognize this reality, basing analysis entirely on MW loading. [EPA-HQ-OAR-2009-0491-2751.1 p.10; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, p.6, 10/15/2010]
Many small generation units are PURPA plants that operate under a long term contract. The contracts normally include a requirement that each year, peak generation must be at least a high percentage of the last three year average peak generation, or the facility may be charged a fee as well as the cost of any replacement power. Currently in Pennsylvania, waste coal power is a Tier II source and has RECs associated with those operations that are owned by the Transmission and Distribution company that purchases the power. T & D companies are required to produce various amounts of alternate energy annually, or purchase credits. If all waste coal generation is capped through inaccurate heat input data, they will not be able to obtain these credits as the credits will not be created. [EPA-HQ-OAR-2009-0491-2751.1 p.10; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, p.6, 10/15/2010]
EPA's analysis reflects no consideration and accommodation of these critical elements and is therefore not rational. [EPA-HQ-OAR-2009-0491-2751.1 p.10; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, p.6, 10/15/2010]]
Dayton Power and Light Company (DP&L)
Necessary Corrections Should Be Made
DP&L appreciates and commends the EPA for requesting that utilities provide it with any incorrect assumptions that EPA is using in the modeling associated with this proposal. Although DP&L is not aware of all the assumptions used by EPA, the following items have been identified for correction: [EPA-HQ-OAR-2009-0491-2637.1, p. 7]
1. The EPA proposal appears to be based on the assumption that DP&L's Stuart and Killen Stations are capable of burning sub-bituminous coal. Please note that combustion of sub-bituminous coal would violate the Title V permits for Stuart and Killen Stations, which specify the use of bituminous coal. Additionally, these stations have a 25+ year history of burning only bituminous coal, DP&L has no operating experience with subbituminous coal. DP&L has no plans to burn sub-bituminous coal. Accordingly, the EPA model should be adjusted to the extent it includes an erroneous assumption that Killen or Stuart Stations have the option to burn sub-bituminous coal. [EPA-HQ-OAR-2009-0491-2637.1, p. 7]
2. The EPA IPM model appears to include an assumption that DP&L's Stuart and Killen Stations can shift coal sourcing from higher sulfur coals to lower sulfur coals without incurring additional cost. Cost differentials between coal regions are substantial and widely recognized. For example, the price spread between Central Appalachian coals and Illinois Basin coals has averaged $16/ton over the past five years (and generally in the range of $1 0-$20/ton when the highly volatile 2008 history is excluded). There is nothing in the past, present or future market prices for CAPP and ILB to support a belief that differences in their costs are minimal or likely to shrink. DP&L notes these additional facts can be verified from utility FERC reports and data available from the Energy Information Administration. A shift of coal sourcing at DP&L could have a financial impact approaching $50 million per year. EPA's model should be adjusted to reflect an appropriate level of change in costs. [EPA-HQ-OAR-2009-0491-2637.1, p. 7]