Using heat input to allocate allowances does not affect the size of state budgets or the level of emissions that sources in a state can collectively emit in a given year so it is totally consistent with the overall program objective of eliminating each state's significant contribution to downwind nonattainment and interference with maintenance. A heat input allocation method simply distributes each state's responsibility for reducing emissions in a different way. The environmental endpoint will not be affected. Allocating allowances based on heat input treats all sources equally. In other words, it doesn't differentiate between sources that have installed controls and those that have not installed controls. Duke Energy believes that fundamentally this is a more equitable and preferred method compared to EPA's proposed emissions-based allocation method.  [EPA-HQ-OAR-2009-0491-2689.1, p.18]
In its proposal EPA lays out two possible approaches for allocating allowances using heat input. With one approach EPA would group all covered units in a state into a single group. With the other approach EPA would form subgroups of covered units within a given state with the subgroups formed based on characteristics such as size, fuel type, or age. [EPA-HQ-OAR-2009-0491-2689.1 ,p.18]
For the ozone season and annual NOx programs, Duke Energy recommends forming two subgroups. One subgroup would be made up of all covered coal-fired units and the other subgroup would be made up of all other covered units. EPA would establish budgets for each subgroup that represents each subgroup's collective share of, or contribution to state annual and ozone season NOx budgets. EPA would then allocate a subgroup's budget to all units within a subgroup based on each unit's pro rata share of the subgroup's total heat input.  [EPA-HQ-OAR-2009-0491-2689.1, pp.18-19]
For the annual SO2 program, Duke Energy recommends that units which burn only natural gas or natural gas and distillate oil (mainly combustion turbines) be excluded from the program. EPA's modeling for 2012 shows that total SO2 emissions from the entire universe of oil and gas units across all PTR states is under 40 tons, with most of this coming from just a few oil and gas fired steam units. Because of the small amount of emissions, there is no need to allocate SO2 allowances to these types of units. Removing these types of units from the program will eliminate an administrative burden on industry and EPA, and because these units collectively emit almost no SO2, doing so will not adversely impact the environmental performance of the program.  [EPA-HQ-OAR-2009-0491-2689.1, p.19]
While many gas and oil-fired units may be required to monitor, report, and provide allowances for emissions under the Title IV Acid Rain Program, the additional administrative requirements associated with permitting, allocation, monitoring, reporting, and market transactions for the PTR are unwarranted. Any unit that currently burns exclusively natural gas and/or distillate fuel oil or any new unit permitted to burn exclusively these fuels will not be defined as a covered unit for the PTR SO2 budget program. As EPA proposes, an existing covered unit that switches to natural gas and/or distillate fuel oil for any reason would retain its SO2 allocation provided under the PTR based on its current fuel as long as the unit remains in operation. [EPA-HQ-OAR-2009-0491-2689.1, p.19]
After eliminating natural gas and distillate oil-fired units from the SO2 program, Duke Energy recommends that EPA form two subgroups with the remaining units. One subgroup would consist of only coal-fired units and the other subgroup would consist of all remaining units. Duke Energy recommends that EPA then establish budgets for each subgroup equal to the collective contribution of all units in each subgroup to a state's SO2 budget. For each subgroup, EPA would allocate SO2 allowances to each unit in the subgroup based on each unit's pro rata share of the total heat input of all units in the subgroup.  [EPA-HQ-OAR-2009-0491-2689.1, pp.19-20]
Alternately, if EPA does not remove all natural gas and distillate oil-fired units from the SO2 program, Duke Energy recommends forming two subgroups, one consisting of all covered coal-fired units and the other consisting of all other covered units. EPA would then establish separate budgets for each subgroup based on the contribution of all units in each subgroup to the total state budget. For each subgroup, EPA would allocate SO2 allowances to each unit in the subgroup based on each unit's pro rata share of the total heat input of all units in the subgroup.  [EPA-HQ-OAR-2009-0491-2689.1, p.20]
In the PTR, EPA suggests that under an alternative heat input allocation method the heat input used to make the allocations would be the heat input projected for the initial year of the program. This would be acceptable to Duke Energy's. [EPA-HQ-OAR-2009-0491-2689.1, p.20]
Duke Energy Recommends That EPA Adopt the Following Method for Allocating Allowances to New Units.
Under EPA's proposed method for allocating allowances to new units, a new unit would not receive any allocation for the control period during which it commences commercial operation. In addition, EPA proposes to allocate allowances to a new unit for each subsequent control period based on the unit's reported emissions from the previous control period. EPA requests comment on its proposed approach and on alternative allocation approaches that would provide allowances to new units for the control period during which the unit commences commercial operation. [EPA-HQ-OAR-2009-0491-2689.1, p.20]
EPA's proposed approach for allocating allowances to new units would penalize new units during the control period of initial commercial operation and during the next control period where under EPA's method, allocations would be based on reported emissions during the initial control period (the later in the control period of initial commercial operation a new unit begins operation, the greater the penalty the unit would incur the following year). In order to provide new units with a fair allocation, Duke Energy recommends modifying EPA's proposed allocation approach so new units receive an allocation from the new source set-aside for the control period during which they commence initial commercial operation, and receive an allocation during the following two control periods that is not linked to the reported emissions during the previous control period. [EPA-HQ-OAR-2009-0491-2689.1, pp.20-21]
Duke Energy recommends that EPA adopt the same basic method for allocating to a new unit during its first year of commercial operation that it proposes to use to establish a new unit's surrogate emissions number to calculate the maximum amount a new unit could emit in its initial year of commercial operation before being required to surrender allowances under the assurance provisions.  [EPA-HQ-OAR-2009-0491-2689.1, p.21]
Using this approach, a new unit's allocations for the control period of initial commercial operation would be calculated by multiplying the unit's allowable emissions rate (in lbs/MWe) by the unit's maximum hourly load (in MWe/hr), its expected hours of operation during the control period (defined as the hours remaining in the control period from the date of initial commercial operation), and a default capacity factor specific to the unit type. As EPA proposes for purposes of establishing a new unit's surrogate emission number, the default capacity factors would be 84 percent for coal-fired units, 66 percent for gas-fired combined cycle units, and 15 percent for combustion turbines in the NOx annual and SO2 trading programs; and 89 percent for coal-fired units, 72 percent for gas-fired combined cycle units, and 22 percent for combustion turbines in the NOx ozone season trading program. [EPA-HQ-OAR-2009-0491-2689.1, p.21]
Any request for allocations for new units would need to be submitted on or before May 1 of the control period in which a new unit will begin or has begun initial commercial operation. If a unit begins commercial operation prior to the date the request is submitted, the above specified calculation, which will be the basis for the allocation request, would reflect the actual start date of the unit. If a unit has not begun commercial operation by the date the request is submitted, the above specified calculation and allocation request would reflect the expected start date for the unit. The request for an allocation for the year of initial commercial operation would be required to include information supporting either the actual start date of the unit if it occurred prior to the request being submitted, or the expected start date of the unit if it is to occur after the request is submitted. The supporting information should be based on official filings (for example, to the Department of Energy or state utilities commission) the company has made concerning the schedule for bringing a unit on line. The request for allocation would need to be certified by the Designated Representative as true and accurate based on prudent inquiry. If a state's new source set aside is over subscribed for a given control period, all new units, including any new units beginning commercial operation during the control period the set aside is oversubscribed, would receive a pro rata share of the total number of allowances in the new source set aside. [EPA-HQ-OAR-2009-0491-2689.1, p.22]
At the end of the control period there would be a true-up for all new units that commenced commercial operation in that control period. The true-up would consist of comparing a unit's allocation with its actual control period emissions. Units would be required to surrender to EPA any allocation received in excess of actual emissions. Any surrendered allowances would be allocated to other new sources if the new source set aside was oversubscribed for the subject control period, or returned to the new source set aside and reallocated to existing covered units if the new source set aside was not over-subscribed for the subject control period.  [EPA-HQ-OAR-2009-0491-2689.1, pp.22-23]
For the two control periods immediately following the control period of initial commercial operation, Duke Energy recommends that the number of allowances a new unit is allocated be determined using the above specified calculation based on 8760 hours of operation and application of the appropriate capacity factor. At the end of each of these two control periods for affected new units there would be a true up as described for the control period of initial commercial operation. The true-up would consist of comparing a unit's control period allocation with its actual control period emissions. Affected new units would be required to surrender to EPA any allocation it received in excess of its actual emissions. For all subsequent control periods, Duke Energy recommends that the allocations to a new unit be equal to a unit's reported average emissions during the previous two control periods. There would be no true up for a new unit for any control period following its second control period of full year operation. [EPA-HQ-OAR-2009-0491-2689.1, p.23]
EPA Should Allow EGUs in Group 2 States to Purchase Allowances from EGUs in Group 1 States.
EPA should allow sources in Group 2 states to use SO2 allowances from Group 1 states. Trading allowances from Group 1 to Group 2 sources will not impact EPA's analysis of what it deemed to be cost-effective emission reductions because the Group 1 allocations are based on a much higher cost of control ($2000 per ton vs. $500 per ton). A Group 2 source will, of course, first look for cost-effective measures to control emissions or the availability of allowances from other Group 2 sources before going after higher priced Group 1 allowances. This provision would still be subject to the statewide variability limits, so there would be no impact on the significant impact analysis for each state. In addition, to the extent that allowing such trading would result in fewer emissions in a Group 1 state (in order to free up allowances to trade to the Group 2 state), the overall environmental benefit should be enhanced since the Group 1 state presumably has a greater impact on downwind non-attainment areas. Because of the limited pool of Group 2 allowances due to the small number of states in that category, a utility with limited operations in a Group 2 state may be placed at a disadvantage since it may not have any cost effective reduction opportunities at its units within a Group 2 state.  [EPA-HQ-OAR-2009-0491-2689.1, p.26]
Alternatively, EPA should allow a Group 2 source within a regulated electric utility system to use allowances allocated to any other source within the same regulated utility system. Group 1 sources within the utility system would not be allowed to use Group 2 allowances, thus maintaining the cost-effectiveness assumptions that were the basis for allocations to Group 1 and Group 2 states. Restricting this Group 1 to Group 2 option to trading within a single regulated utility operation will assure that such trades occur within a limited geographical area, which should eliminate any potential concerns over how impacts from each state were modeled. [EPA-HQ-OAR-2009-0491-2689.1, p.26]
Units Should Be Permitted To Use Allowances from Future Year Allowance Accounts, at Least on a Limited Basis
EPA should allow units to use a limited number allowances from future-year accounts for use in compliance in an earlier year. This would allow for increased flexibility, which will be particularly important in the early years of the program, especially if EPA promulgates a final rule that includes the unreasonable compliance schedule that it proposes and it continues to overstate the ability of existing emission controls to reduce emissions. It would also reduce reliance on an uncertain trading market. This feature would still result in units receiving and using a finite number of allowances over the years and, thus, produce no overall increase in emissions, while also potentially encouraging early retirement of some units. [EPA-HQ-OAR-2009-0491-2689.1,p.32]
One possible way to implement this concept would be to allow a given vintage year allowance to be used for compliance in that year plus in the year immediately preceding the vintage year of the allowances. For example, a 2016 vintage allowance could be used for compliance in 2015 or in any year after 2015. A limit on the number of allowances an entity could use in this manner along with a limit on the number of years this option is available might be appropriate. [EPA-HQ-OAR-2009-0491-2689.1, pp.32-33]
Upon making these recommended adjustments to NOx emission rates, EPA should rerun the critical IPM model runs that are the basis for developing state budgets and unit allocations. Because EPA needs to make dramatic technical changes to its calculations, EPA should then repropose the budgets and allocations for public review and comment.  [EPA-HQ-OAR-2009-0491-2689.1, p.47]

Footnote 4: Duke Energy's support for this approach is based on its understanding of the proposal that once a non-operating unit's allocation stops and all future allowances are then transferred to the new source set-aside that the allocation of any unallocated new source set aside allowances to existing covered units will include the reallocation of the allowances from non-operating units. If EPA were to not include these allowances in any reallocation of unused new source set aside allowances to existing covered units then Duke Energy favors the option that continues to allocate allowances for an unlimited period of time to units that discontinue operations. Not to reallocate all unused new source set aside allowances to existing covered units would have the effect of making the state budgets, and therefore the program more and more stringent[EPA-HQ-OAR-2009-0491-2689.1, p.6]
E.ON U.S.
We support EPA's proposal not to permit government-run allowance auctioning.
The costs associated with compliance with the Proposed Transport Rule will be significant and these costs will impact utility customers through higher utility rates. If allowance auctions were authorized, the costs of procuring allowances would be borne by utility customers who ultimately pay the cost of environmental compliance. EPA should avoid placing additional cost burdens on utility customers already impacted by the economic downturn. Consequently, we urge EPA to decline to adopt allowance auctioning as a component of its final program [EPA-HQ-OAR-2009-0491-2797.1, pp.8-9]
East Texas Electric Cooperative
The use of a single year (or four quarters) of emissions or the heat input from a single ozone season as the baseline for allowance allocation breaks with EPA precedent and is likely to produce inequitable results; the use of at least three years of emissions/heat input data would provide a more accurate baseline and is consistent with EPA's previous practices. [EPA-HQ-OAR-2009-0491-2770.1 p.2]
Edison Mission Energy (EME)
The Transport Rule's proposed SO2 and NOX allowance allocations penalize states that have taken early action on emission reductions. Compared to CAIR, the Transport Rule's state-level allocations appear to reward some states and penalize others without explanation or apparent consideration of the aggressive emission reductions that have already been obtained by a state like Illinois, which appears to have been penalized. [EPA-HQ-OAR-2009-0491-2707.1, p.3]
The Transport Rule's proposed SO2 and NOX allowance allocations also penalize sources that have taken early action on emission reductions. By making unrealistic assumptions about the control efficiency that can be obtained by existing emission controls, EPA has not provided sufficient allocations during Phase I such that sources can actually comply by simply operating controls year round as EPA suggests. Similarly, those same unrealistic assumptions are made with respect to Phase II allocations in 2014 and cause the Transport Rule to penalizes sources that have already installed controls. [EPA-HQ-OAR-2009-0491-2707.1, p.3]
THE TRANSPORT RULE'S ALLOWANCE ALLOCATIONS PENALIZE STATES AND SOURCES THAT HAVE TAKEN EARLY ACTION ONE MISSION REDUCTIONS [EPA-HQ-OAR-2009-0491-2707.1, p.29]
The Transport Rule's State-Level Allocations Appear To Reward Some States And Penalize Others Without Justification [EPA-HQ-OAR-2009-0491-2707.1, p.29]
The stated purpose of the Transport Rule is to limit emissions of NOX and SO2 in a 32 state region to ensure that emissions of those constituents in upwind states do not impact attainment of the 1997 and 2006 PM2.5 NAAQSs and the 1997 Ozone NAAQS in downwind states  -  i.e., the same goal as CAIR. Based on this similarity of purpose, it is not surprising that EPA projected that both rules will have the same impact  -  namely, attainment in all but a handful of areas. Given this uniformity of purpose, one would expect that the required reductions under CAIR would bear some relationship to the projected reductions under the Transport Rule. However, if one compares the Agency's state-level allocations under the Transport Rule to those under CAIR, it becomes readily apparent that some states benefited materially, while others appeared to be penalized with respect to their overall allocations. For example, as the data in Table 3 [See p.30 of this comment summary for Table 3 entitled, Comparison of Final NOx Emission Budgets Under the Transport Rule vs. CAIR] illustrate Illinois will be required to reduce its overall NOX emissions 12% further relative to CAIR, while each of its neighbors will be permitted to increase their NOX emissions by at least 10% relative to what would have been required under CAIR. A similar phenomenon can be seen in Table 4 [See p.30 of this comment summary for Table 4 entitled, Comparison of Final SO2 Emission Budgets Under The Transport Rule vs. CAIR] with respect to SO2. The Agency offers no analysis or explanation for the disparity between the allocations under the two rules despite the fact that both rules were intended to achieve the same net result. [EPA-HQ-OAR-2009-0491-2707.1, pp.29-30]
[See EPA-HQ-OAR-2009-0491-2707.1, p.30-31 for additional comments pertaining to The Transport Rule's State-Level Allocations Appear To Reward Some States And Penalize Others Without Justification, including Table 5 at p. 30 entitled, Comparison of Current SO2 and NOx Emission Rates vs. Implied Rates Under the Transport Rule]
EME recognizes that the Agency based the Transport Rule's state-level allocations on new modeling and modeling tools developed specifically for the Rule; however, there are conceptual similarities in the terms of approach with respect to both rules. Thus, logic dictates, given the uniformity in the overall objective of the two rules, that allocations under the new rule should not be dramatically different from the prior one. Since such disparity in the state-level allocations exist, the Agency, at a minimum, should revisit those allocations to insure they are not unfairly penalizing one state vis-à-vis another, especially states like Illinois which have taken aggressive and early action on emission reductions. [EPA-HQ-OAR-2009-0491-2707.1, p.31]
B. The Transport Rule's Unit-Level Allocations Are Not Based On Reliable Assumptions And Penalized Sources That Have Already Installed Controls [EPA-HQ-OAR-2009-0491-2707.1, p.31]
The Transport Rule proposes to distribute allowances to individual EGUs, such that "each unit receives a proportional share of its...[state's allowance allocation] budget based on that unit's share of state emissions assumed in developing the budget."64 In calculating a unit's share of emissions, EPA made assumptions about the types of controls that will be employed by a given unit and the level of emissions reduction that will be obtained as a result of those controls. This approach is problematic because it penalizes sources that have taken early action on emission reductions, but as a result have existing emissions control equipment that does not necessarily achieve the control levels assumed by EPA in the Proposed Rule. Given EPA's longstanding efforts to encourage sources to reduce their emissions, it cannot be the intent of the Rule to punish those sources that provided those early emission reductions. As a result, EME suggests that EPA revise the Proposed Rule to ensure that the allowance allocations in the final Transport Rule do not penalize early actors. The subsections below address EME's concerns with respect to unit-level allocations in Phase I (2012) and Phase II (currently 2014) caps. [EPA-HQ-OAR-2009-0491-2707.1, pp.31-32]
1. The Phase I Unit-Level Allocations Do Not Reflect The Emissions Reductions That Can Actually Be Achieved Using Existing Controls [EPA-HQ-OAR-2009-0491-2707.1, p.32]
As explained in Section IV.B.1, EPA assumes that compliance with the 2012 cap will only require affected EGUs to (i) operate existing emissions controls year-round, and/or (ii) complete the installation of proposed controls that are scheduled to be online by 2012.65 But these assumptions are not technically feasible. EPA's assertions are premised on the erroneous assumption that existing controls will be able to obtain the absolute highest levels of control  - e.g., those that are obtained when control equipment is operating at peak load with fresh catalyst. Thus, EPA has overestimated the level of control that can actually be obtained by 2012, and therefore has imposed state-wide Phase I emissions caps that are too restrictive. As a result unit level allocations for units with existing controls, such as EME's Homer City facility, are not sufficient to cover emissions there. [EPA-HQ-OAR-2009-0491-2707.1, p.32]
By assuming that Homer City's emissions controls can achieve very low emission levels (levels that EME is not even sure are obtainable on an operational basis using new equipment, let alone existing equipment) and allocating allowances on that basis, the Transport Rule effectively penalizes the Homer City facility for having already installed emissions controls (controls which have removed well over 200,000 tons of SO2 and NOX from the facility's emissions stream). If EPA had in fact drafted the Transport Rule such that compliance with the 2012 cap only required sources to operate existing controls, then the Homer City facility should have received allocations equal to its emissions, which it has not. As explained in Section IV.B.1, EME believes that the assumptions underlying the EPA's 2012 cap have caused EPA to overstate the reductions that can actually be obtained using existing controls, and therefore that the Agency should increase the 2012 compliance caps based on more realistic assumptions about the level of control that can actually be obtained using existing controls. In turn, EPA should increase individual unit-level allocations proportionally and, at a minimum, in a manner that ensures that sources with existing controls, such as Homer City, have sufficient allocations to cover their emissions. The CEMs data maintained by affected EGUs means EPA has access to the data it needs to make these adjustments to the Rule. In addition, EPA should amend the Rule to permit affected sources to use previously banked CAIR emissions allowances to comply with Phase I emission caps. [EPA-HQ-OAR-2009-0491-2707.1, pp.32-33]
In addition to that timing concern, EME also believes that EPA should re-evaluate its unit-level allocations for Phase II to ensure that they do not penalize early adopters of emission controls. As explained above, EPA distributed allowances based on its determination of a unit's proportional share of emissions in state  -  a determination that EPA based on its own inaccurate assumptions about the level of control a given unit would obtain. [EPA-HQ-OAR-2009-0491-2707.1, p.33]
EME believes generally that EPA has overestimated a source's ability to control emissions, and as a result may have understated an individual unit's proportional share of emissions causing that unit to receive a smaller allocation than is justified by the Agency's allocation methodology. For example, by projecting emissions at the Homer City's Unit 3 facility using an assumption that its FGD achieves an emissions rate of 0.103 lbs/MMBtu even though it actually achieves 0.180 lbs/MMBtu, EPA has understated Unit 3's 2014 emissions by more than 40%. Lower estimated emissions at Unit 3 means that Homer City's proportional share of total emissions is smaller, which causes Homer City's overall allowance allocation to be smaller. This outcome effectively penalizes Homer City for having existing controls, even though EPA had access to CEMs data that would have permitted it to make more accurate assumptions about actual control rates at the Homer City facility. If the Agency elects to retain the emissions-based allocation approach in the Final Rule, it should verify that its emissions estimates are accurate.[EPA-HQ-OAR-2009-0491-2707.1, pp.33-34]
Alongside its recommendation that the Phase II compliance deadline be pushed back until 2016, EME recommends that EPA retain the banking provisions in the Proposed Rule. By permitting sources to bank allowances for future use, the rule encourages early reductions during Phase I  -  i.e., by allowing sources to bank allowances for future use sources are incented to take capital investment risks on emission controls and/or try promising, but currently unproven, emissions reduction technologies. [EPA-HQ-OAR-2009-0491-2707.1, p.35]
Entergy Services, Inc.
Entergy Does Not Support Using Integrated Planning Model (IPM) Results for Unit Allowance Allocations
Entergy urges EPA to reconsider the use of the IPM results in allocating NOx allowances from the state budgets among the individual sources.  IPM is a production cost simulation model focused on analyzing wholesale power markets and assessing competitive market prices based on an analysis of the fundamentals relating to supply and demand.  While it is capable of producing projections of emissions by taking an integrated approach to regional fuel, power, and emission markets, IPM possesses several characteristics that may contribute to its under-prediction of unit operations and premature retirement or significant reduction of generation from oil/gas steam units.  This is demonstrated in the data contained in Attachment A.  A review of this data reveals IPM modeling marks the early retirement  23 Entergy oil/gas steam units that were utilized significantly in 2007-2010 to supply power to the grid and underutilizes 10 Entergy combustion turbine units that were utilized significantly in 2007-2010 to supply power to the grid.  Entergy does not have any plans to retire the units predicted to retire, nor do we expect utilization of these units or the turbines to change significantly. The table below shows the difference in allowances allocated to these units using the IPM 2012 projected utilization verses an allocation based on the ratio of the unit's average 2007  -  2009 heat input and the 2007-2009 respective state heat input.  [EPA-HQ-OAR-2009-0491-2847.1,p.2] [[See Docket Number EPA-HQ-OAR-2009-0491-2847.2 for Attachment A.]]  [[See Docket Number EPA-HQ-OAR-2009-0491-2847.1, p. 2 for the state heat input table.]]
The first IPM characteristic causing these unrealistic projections is that, as a regional model, IPM represents the electric transmission system on an interregional basis, with regional boundaries determined by known transmission bottlenecks.  Unlike ICF's private sector version of IPM that contains 104 U.S. regions, EPA's version contains only 32.  Entergy is modeled as a single region, an over- simplification that might have limited impact for state-level modeling results, but which becomes problematic when relying on detailed regional results, especially at the individual source level.  Transmission-related issues inherent to IPM's regional models include missing intraregional load pockets, voltage support, ancillary services, local requirements, etc.  These limitations are further exacerbated by the limited number of regions in EPA's IPM, resulting in the premature reduced generation from oil/gas steam units as depicted in Attachment A.  [EPA-HQ-OAR-2009-0491-2847.1,p.3]
The second issue is the lack of time detail in EPA's version of IPM which underestimates the operational value of oil/gas steam units.  Oil/gas steam units are typically responsive to short term fluctuations in demand and are used frequently to provide operational flexibility.  IPM, which is not an hourly model and dispatches to broader time segments, has no way of capturing the daily and hourly dispatch decisions that might drive generation for these units. [EPA-HQ-OAR-2009-0491-2847.1, p.3]
There are additional modeling assumptions that may contribute to reduced oil/gas steam unit dispatch (overstating turndown requirements, such that units may ramp at low levels for a more limited variable cost than what is represented in IPM, etc.), but the core issue is that IPM is a model that assumes perfect system optimization.  The IPM model predicts a least-cost scenario for the electric power system while ignoring these stated system limitations.  In none of the three Base Cases was there any projected generation attributed to the `Oil/Gas Steam' capacity type.  Attachment A contains a brief explanation of why Entergy's oil/gas steam units will be utilized even though the IPM model shows zero utilization. [EPA-HQ-OAR-2009-0491-2847.1,p.3]
In summary, IPM does not consider a range of real-life factors that influence a company's decision to operate a unit.  As a result, allocating allowances to emission units on the basis of IPM modeling creates unrealistic scenarios such as running natural gas combined cycle units at higher utilization than can be accommodated by the local natural gas pipeline network, running coal units so they emit higher than permitted annual emissions, and not running units that are required to operate to meet load/transmission requirements.  These distortions of the electricity market are masked when data are aggregated at the state level for setting state budgets but result in obvious inaccuracies and inequities when used at the unit level to allocate allowances.  For these reasons, Entergy encourages EPA to reconsider the use of the IPM as a fair means of allocating allowances and supports the use of a proven, reliable methodology of allocating allowances, such as historical MW output.  The inequity in the utilization of IPM projections as compared to the proven, reliable method of allocating allowances on historical heat input is depicted in Attachment A.  [EPA-HQ-OAR-2009-0491-2847.1,p.3]
Alternative Unit Allocation Methodologies
Entergy supports output-based allocation approaches.  An output-based allocation relies on energy production (output; megawatt-hour [MWh]) as the basis for determining the number of allowances that a unit will receive.  The benefits of an output-based allocation include promoting more efficient and cleaner production of electricity to maintain economic competitiveness.  Further, the methodology does not penalize companies and their customers for investments made in cleaner generation prior to a regulatory mandate.  Alternatively, Entergy proposes that EPA consider a historic fuel-input basis for unit allocations.  The historic basis should be a unit's proportion of its state's historic heat input (i.e., million British thermal units, mmBtu), as was originally proposed for CAIR, prior to the introduction of the fuel adjustment factors.  We note that the federal appellate court invalidated the use of fuel factors, not the use of historic heat input.  The historic heat input should be based on the maximum annual heat input for units during the period of calendar years 2007 through 2009.  We recommend using the annual maximum of reported data during the three-year period rather than the average of those three years in order to ensure that an atypical year does not dramatically affect the allocation (e.g., the unusually low utilization in 2009).  Such an allocation methodology would address Entergy's concern with allocations based on modeled future emissions with its known inaccuracies and would be based on verified data that companies have already submitted to EPA.   [EPA-HQ-OAR-2009-0491-2847.1,pp.3-4]
Heat Input Adjustment Methodology
In EPA's technical support document "State Budgets, Unit Allocations, and Unit Emission Rates," the motivation and methodology for the heat input adjustment is described:
 "Reported annual and ozone season NOX emissions are adjusted to account for unusually low utilization in 2009. For units reporting emissions (Sets A and B), the annual emissions assumed in the budget calculation are calculated by applying the 2008 heat input to the annual average emissions rate determined from the most recent quarter 1, quarter 2, quarter 3, and quarter 4 (and potentially adjusted for controls, as described above).  2009 heat input is used for units which did not report 2008 heat input data. Ozone season emissions are assumed to be 2008 ozone season heat input multiplied by the most recent ozone season average emissions rate." [EPA-HQ-OAR-2009-0491-2847.1,p.4]
The intent of this adjustment is to rebase emissions on a more historically representative heat input year as a way to increase annual NOx emissions and provide a more appropriate allocation level.  However, in Arkansas the heat input adjustment often works to reduce reported NOx emissions from Entergy's units.  The table below displays each of Entergy's Arkansas units that was assigned a non-zero heat input adjustment by EPA.  [EPA-HQ-OAR-2009-0491-2847.1,p.4] [[See Docket Number EPA-HQ-OAR-2009-0491-2847.1, p.4 for the table.]]
Every heat input adjustment except for the adjustment at Independence 1 revised the reported NOx emissions lower, reducing Entergy's overall allocation by approximately 643 tons.  This outcome appears to stand in direct contradiction to the stated purpose of the heat input adjustment. As demonstrated by the Harvey Couch 2 unit allocation, the methodology for determining the adjustment is problematic and can produce results that are difficult to justify.  Harvey Couch 2 does not have a listed heat input for any quarter of 2008; this fact reduces the unit's 2009 reported emissions of 234 tons to zero as the basis for its 2012 allocation.  [EPA-HQ-OAR-2009-0491-2847.1, p.5]
If any of the state budget methodologies switch from projected to reported emissions, the heat input methodology will become even more important.  In several instances, the current methodology produces counterintuitive results.  For example, Little Gypsy 1 has reported emissions of 636 tons under the Annual NOx program.  EPA then applied a heat input adjustment that zeroes out Little Gypsy 1's emissions.  In EPA's reported data, the unit has heat input values listed for all but the first quarter of 2008.  Under the methodology, if there is a single null value in any quarter of 2008, the annual heat input becomes zero and reported Annual NOx emissions are eliminated.  In this way, the final reported NOx emissions of Little Gypsy 1 are lower under the Annual Program (0 tons) than under the Seasonal Program (407 tons), because the null heat input value happens to be in the first quarter of 2008. [EPA-HQ-OAR-2009-0491-2847.1,p.5]
For a revision intended to produce a more equitable NOx allocation level, the heat input adjustment may be functioning to produce the opposite result. Using the highest heat input value in a consecutive three year period as outlined in the section of these comments describing the Alternative Unit Allocation Methodologies would alleviate undesirable results when adjusting heat input to produce a more equitable NOx allocation level.  [EPA-HQ-OAR-2009-0491-2847.1, p.5]
Excelsior Energy
Comment summarv for allocation among unit groups:
Within the alternative heat input allocation method, units using natural gas as a primary fuel should not be allocated SO, allowances.
Under the alternative heat input allocation approach, EPA contemplates creation of subcategories:
'There are other approaches to allocation. For example, EPA could identify groups of units in each state that are capable of having similar emissions characteristics (e.g., grouped by size, fuel type, or age). EPA would distribute a state's emissions budget without variability to each group of units in the state (in effect, distributing the responsibility for eliminating all or part of significant contribution) perhaps based on each group's proportional share ofthe state budget as projected in the initial year of the program. After apportioning a state's budget to the groups ofunits, under such an approach EPA could distribute allocations to individual sources within each group based on each source's proportional share ofprojected heat input.' (Federal Register, Vol. 75, No. 147, Aug 2, 2010, p. 45311). [EPA-HQ-OAR-2009-0491-2810.1 p.3]
There is one group or subcategory that would be appropriate. The allocation process should take into account whether a unit (as defined in the Rule) has negligible emissions of SO, without controls (i.e., units for which natural gas is the primary fuel) and should limit the distribution of allowances to those units accordingly. Allowances should not be 'diluted', which is to say that they should not be given to units that have virtually no SO, emissions and are unable to reduce emissions with addition of such controls. Allocating allowances to units physically incapable of reducing emissions would not result in any emission reduction and would therefore not serve the purposes behind the CATR.
The allocation process described above would only require the creation of two categories across all units covered under the Rule and would only apply to SO, (since all units emit NOx). One category would include units with negligible uncontrolled emissions of SO,; the other, all remaining units. As described above, units in the former category would not receive allowances. Allowances for a given unit in the latter category would be allocated in accordance with that unit's proportional heat input across the total annual heat input of all emitting units in the same category, i.e., exclusive of the units for which natural gas is used as a primary fuel. [EPA-HQ-OAR-2009-0491-2810.1 p.3]
As discussed above, in North Carolina v. EPA, the Court rejected EPA's proposed fuel-adjustment factors because EPA used the impermissible grounds of 'fairness' as the only legal justification for the use of the factors. By contrast, dividing units within a state into the two categories described above is consistent with North Carolina v. EPA, because the justification in this case is that allocating S0, allowances to units unable to make any reductions would not reduce emissions and would not reduce contributions to downwind attainment. On the contrary, it would have the potential to reduce the incentive for sources that do emit S0, to implement emission reduction retrofits. [EPA-HQ-OAR-2009-0491-2810.1 p.4]
Exxon Mobil Corporation
THE NOx ALLOWANCE ALLOCATIONS FOR THE LOUISIANA 1 UNITS ARE WHOLLY INSUFFICIENT AND BASED UPON FLAWED MODELING AND PROJECTIONS
It is arbitrary and capricious for EPA to provide unit-level allocations based upon the Integrated Planning Model (IPM). EPA's proposed NOx allowance allocations would provide the Louisiana 1 units with only about 4.5% of the allowances that they need to operate at the levels they have operated at for the past 5 years and intend to operate at in the foreseeable future. These units are well controlled with low NOx burners and/or water injection systems. They are critical to meeting EM's electrical demand and continued manufacturing operations. [EPA-HQ-OAR-2009-0491-2841.1,p.12]
To meet the requirements of the proposed FIP, EM may have to expend more than $1.2 million dollars per year to acquire NOx allowances.19 TIns is solely because EPA is basing the allocations on the IPM projections, not due to any need for NOx emission controls at these units. [EPA-HQ-OAR-2009-0491-2841.1,p.12]
EM believes that it is unreasonable for EPA to use the IPM results to allocate NOx allowances from the state budgets at the unit-level basis. The IPM is a production cost simulation model that was designed to investigate wholesale power markets and assist in making projections about competitive electrical market prices. It was not designed for the purposes for which EPA is using the model. It has several important deficiencies for such service. It is clear from the comments of the Louisiana Chemical Association that the model erroneously predicts premature retirement or significant reduction of generation from oil/gas fired units.20 In addition, as discussed in the comments of the Louisiana Public Service Commission staff, the IPM fails to recognize important transmission constraints that exist within Louisiana.21 Further, the IPM appears to have problem with realistically projecting utilization rates for cogeneration units such as the Louisiana 1 units. A comparison of actual data for fuel input and S02 and NOx emissions for the Louisiana 1 units to the values for these projected by the EPA IPM model v. 3.02 follows: [EPA-HQ-OAR-2009-0491-2841.1, p.12] [[See Docket Number EPA-HQ-OAR-2009-0491-2841.1, p.13 for a table with the comparison.]]
EM's Louisiana 1 units have total SO2 allocations based on an assumed total 2012 heat input for 32,976,586 mmBtu. This is a reasonable value based on past and projected future operations as can be seen from the certified data reported to EPA under the Acid Rain and CAIR programs. However, the same units have an assumed heat input for NOx annual allocations of only 614,500 mmBtu and an ozone season assumption of only 61,450 mmBtu. Thus, the assumed heat input for NOx is only 1.9% of the actual adjusted reported value used for SO2. The projected heat input values are not reasonable and because they were the product of the IPM model, EM has grave questions about the accuracy of the model to predict heat input in future years. EM does not understand the basis for the modeled predictions and believes that they are arbitrary and capricious. If EPA is going to undertake to make unit level allocations, it has a duty to gather sufficient empirical data about the regulated units before doing so. [EPA-HQ-OAR-2009-0491-2841.1, p.13]
It appears that the ozone season allocation heat input basis is exactly 10% of the annual NOx heat input basis (which as noted is already woefully short of an accurate prediction). This assumption clearly does not comport with actual data. EM's units operate year around on the same basic operational schedule and therefore the ozone season heat input should be based on a realistic percentage based on May-September operation. EPA has the data in its quarterly CAMD reports and could have reviewed those from recent years to confirm that these units operate year round. [EPA-HQ-OAR-2009-0491-2841.1,pp.13-14]
Although the difference between reported and projected values improves very slightly under the IPM v.4.1 0, the same fundamental problem exists there as well. The annual and ozone season heat input and corresponding NOx emissions are only a tiny fraction of the Louisiana 1 facility actual heat input and emission levels. [EPA-HQ-OAR-2009-0491-2841.1,p.14]
EM is diligently reviewing updates to the IPM announced in the September 1, 2010 Notice of Data Availability, but to date cannot understand how IPM v.4.10 projects such limited operation of the Louisiana 1 units. EM's manufacturing operations depend on continuous large volumes of steam and electricity from reliable and highly efficient cogeneration units. These cogeneration units are significantly more fuel-efficient and have better emissions controls than typical utility electricity generation and stand-alone boilers; further, the steam demand can only be supplied from these sources and is not available from an external 'pipeline grid'. Therefore, there is no known reason to expect the curtailed operation predicted by the IPM, either version 3.02 or version 4.10. [EPA-HQ-OAR-2009-0491-2841.1, p.14]
EM requests EPA abandon use of the IPM model for projecting electric utility operation in Louisiana for purposes of allocating unit-level allowances under CATR for cogeneration units as well as other EGUs. There are several fundamental issues with EPA's use of the IPM for this purpose. One of the foremost reasons is the lack of transparency concerning how the IPM accounts for economic and fuel cost factors in determining how much a unit will be utilized in future years. As clearly shown above, the output of the IPM does not come close to matching actual utilization for EM's cogeneration facilities. The year 2012 is less than one and one-half years away and therefore is well within EM's reasonable ability to project operations. The assumed heat inputs associated with NOx allocations for 2012 are not consistent with EM projections. [EPA-HQ-OAR-2009-0491-2841.1,p.14]
If EPA insists upon enacting a FIP for Louisiana based upon its IPM projections to date, EM recommends that EPA at least use a different system for unit level allocations. One possibility would be for use the adjusted reported heat input data for NOx rather than the IPM projections. In the event EPA chooses to continue using projected emission for NOx allocations, EM requests EPA modify the model to accurately project emissions from cogeneration facilities co-located with production facilities dependent upon cogeneration power. [EPA-HQ-OAR-2009-0491-2841.1,p.14]
As an alternative to the TR/FIP proposed unit allocation methodology, EPA could make NOx allocations (both annual and ozone season) in the same relative percentages to the state budget that Louisiana used under its approved CAIR SIP as NOx allocations. EM does not believe there are any significant new sources that would cause a need to substantially revise that ratio. While EM has a new CLECO Rodemacher/Madison 3 pet coke generation unit, EM believes the unit will not cause a substantial impact on the allocations of the total state emissions budget. [EPA-HQ-OAR-2009-0491-2841.1,pp.14-15]
The IPM based unit-level allocations are illogical and unfair. EM's Louisiana 1 units are efficient gas turbines equipped with both low NOx burner technology or other controls. Under the proposed TR/FIP, EPA's NOx unit-level allocations penalize these units even though they are some of the most efficient and lowest-polluting units. Projecting the cost of purchasing allowances is difficult as their costs will be market driven. In addition, allowance costs may vary widely based on the trading scheme chosen for the final rule. However, based on historical costs from CAIR trading, the additional annual cost for allowances for the Louisiana 1 units could well exceed $1.2 million dollars annually. Adding additional control to these units is not likely to be effective since they are already efficient and well controlled. As EPA is aware, cost per ton for NOx control rises exponentially with additional control and reaches the point of diminishing returns after the control technology currently in place for these units. EPA has simply provided no rational basis for this inequitable treatment for the Louisiana 1 units. [EPA-HQ-OAR-2009-0491-2841.1,p.15]
EM also urges EPA to abandon its proposed unit-level allocations and allow Louisiana DEQ to make allocations through a state SIP, if it is finally concluded that a SIP is even needed to address interstate transport of PM2.5 and/or ozone precursors from Louisiana. In the alternative, EPA should substantially revise the allocations under the FIP and re-propose such allocations for further comment. [EPA-HQ-OAR-2009-0491-2841.1, p.15]

19 The Louisiana Public Service Commission conducted an economic analysis of the proposed TR/FIP that indicates that the annual impact to the Louisiana 1 station for purchases of annual NOx allowances would be approximately $1,224,000 more per year than was the cost to Louisiana 1 to comply with CAIR. This amount is based on an assumption that the cost per ton of a NOx allowance is only $1200. The estimate did not include the additional cost for ozone season NOx allowance purchases and therefore understates the estimate. See comments of Louisiana Public Service Commission submitted in this docket. [EPA-HQ-OAR-2009-0491-2841.1, p.12]
20 See also the comments ofEntergy Corporation filed in this docket. [EPA-HQ-OAR-2009-0491-2841.1,p.12]
21 EM incorporates by reference the comments of the Louisiana Public Service Commission staff. [EPA-HQ-OAR-2009-0491-2841.1,p.12]
First Energy
EPA's unprecedented use of the proprietary Integrated Planning Model to model every significant source in the entire industry produces results that appear to inappropriately reward some sources with allowances over others, and those results cannot be independently substantiated or verified. The output of IPM essentially defines which sources are awarded allowances and which aren't, and, when coupled with limited emission trading opportunities this may very well define those sources that survive and continue to operate and those that do not. The financial and human capital implications for individual plants and Companies associated with this exercise are profound. [EPA-HQ-OAR-2009-0491-2657.1, p.4; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.4 10/15/2010]
Use of a proprietary model is not appropriate for this purpose as it deprives the public and regulated community of the opportunity to independently evaluate the inner workings of the model and ensure that it is accurate, precise and robust enough to perform this enormous task. Likewise, the public and regulated community cannot tell whether questionable output is the result of an error in a modeling assumption or algorithm, or if the model itself inappropriately amplifies irregularities in the input database. [EPA-HQ-OAR-2009-0491-2657.1, p.4; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.4 10/15/2010]
The model also appears to inappropriately apply the same financial metrics to all sources, irrespective of whether they are regulated, municipal or merchant facilities. As an owner of merchant generating facilities, FE appears to be unfairly handicapped by the use of the same financial assumptions for all classes of generators. As noted by Du and Parsons (2009),
"It is important to understand that these costs of capital are meant to reflect a `merchant model' in which the nuclear plant delivers power into a competitive wholesale market without any assured rate of return. A nuclear plant built by a regulated utility, with the construction costs approved and passed along to customers with greater certainty could probably be financed at a lower cost of capital. This would reflect the fact that some of the construction, completion, operating and price risks are being shared between the shareholders in the regulated utility and the customers of the regulated utility. The total risks are the same, but in the merchant model the shareholders bear all of the risk." (p. 20) [EPA-HQ-OAR-2009-0491-2657.1,p.5; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.4 10/15/2010]
The input files for the model should reflect the very different financial and operating environments of regulated, municipal and merchant EGU's and IPM should be rerun. [EPA-HQ-OAR-2009-0491-2657.1,p.5; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.4 10/15/2010]
FE strongly suggests that EPA provide the regulated community sufficient detail and opportunity to comment on the IPM and its application to ensure that the model is appropriate and it is appropriately applied to this purpose.[EPA-HQ-OAR-2009-0491-2657.1, p.5; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.4 10/15/2010]
Potential Reliability Issues
The EPA assumption for unit retirements range from 2GW in 2012 to 12 GW in 2014. This does not match up with other analyses and actual utility announcements concerning shutdowns or transitioning units into a moth-balled state. FE has seen estimates from knowledgeable sources that state that as much 15% of the affected capacity could be retired. EPA's unit retirement assumptions should be evaluated by each Independent System Operator to ensure system reliability after EPA corrects all the assumptions used in IPM. [EPA-HQ-OAR-2009-0491-2657.1,p.13]
Florida Electric Power Coordinating Group, Inc. (FCG)
In EPA's posted 'Projected Data' spreadsheet which was published with the proposed rule, the FCG realized that EPA had not allotted S02 allowances for those units which burn fuel oil and natural gas. Following conversations with EPA representatives, the FCG understands that IPM predicted that these dual-fuel fired units will only be burning natural gas in the future. This is one of the many flaws in EPA's methods. [EPA-HQ-OAR-2009-0491-2658.1, p.8]
First, fuel oil currently consists of 16% of Florida's electric generating Summer capacity (MW) and is being assumed to represent 13% of such capacity in 2019 (Florida Public Service Commission, Fuel Diversity Workshop, August 5, 2010). Florida receives gas from only three pipelines. During the 2005 Hurricane Season, Florida nearly depleted its supplies of natural gas supplies due to interruptions in the Gulf of Mexico. During this emergency period, utilities held daily meetings to assess the situation and discuss possible contingency plans, many of which centered on utilities ability to burn fuel oil in their dual-fuel fired natural gas units. As EPA has cited in their Endangerment Finding, the U.S. should be encountering increased storm activity in the near future, and so the U.S. should plan accordingly. Assuming arguendo, this rule proposal merely pushes Florida sources to become much more reliant on natural gas, which will only exacerbate any future issues with curtailed or jeopardized gas supplies. [EPA-HQ-OAR-2009-0491-2658.1,p.9]
It also appears that IPM predicts that coal units can and will switch to lower sulfur coals in order to meet S02 reduction requirements. Many of the same questions apply with coal as did natural gas, namely EPA's lack of analysis on current permitted coal sulfur limits, the cost and availability of the targeted fuel, and the railroad line capacity to meet the predicted dramatic increase in fuel switching. [EPA-HQ-OAR-2009-0491-2658.1, p.9]
EPA must conduct an analysis of the capacity of Florida's natural gas pipelines to accommodate the increased requirement in natural gas consumption needed to meet EPA's assumptions by 2012. EPA must also perform reliability analysis as to Florida's unique situation as a peninsula regarding FCG members' ability to meet reliability requirements in the future. And EPA's analysis must consider the parasitic load from new control equipment, such as FGD and SCR systems. [EPA-HQ-OAR-2009-0491-2658.1,p.9]
Florida Municipal Power Agency (FMPA)
B. Heat Input Allocation Method Should be Used Instead of the Proposed Allowance Allocation Method
FMPA supports FMEA's comments regarding the use of the heat input allocation method instead of the proposed allowance allocation method. FMPA believes the heat input method results in a more fair allocation. EPA's proposed allocation method results in an unfairly low allocation of allowances to low-emitting facilities with existing control equipment. As shown in Table 1, below, FMPA's units already have NOx controls installed and operating which are required to meet the emissions limits in our Title V operating permits. Furthermore, other than Stock Island CT4 which does not have access to natural gas, all FMPA units fire primarily natural gas, a low sulfur fuel, and either low sulfur or ultra low sulfur diesel as a necessary backup fuel source. Because FMPA's units already have NOx controls and burn very low sulfur fuels, and therefore do not have the ability to add additional measures to reduce emissions, FMPA would have no choice under the proposed allocation but to purchase additional allowances to keep these units running. For these reasons, FMPA does not support EPA's proposed emissions-based allowance allocation method and believes that EPA should instead utilize a heat input-based allowance allocation method. [EPA-HQ-OAR-2009-0491-2725.1, pp.2-3]
[Table 1 can be found on pages 3-4 of this comment.]
Furthermore, EPA's procedure for determining reported NOx emissions, which applied the 2008 heat input to the 2009 NOx emissions data, results in unjust and unreasonable allowance allocations to all FMPA units. EPA's assumption of unusually low utilization in 2009 (Technical Support Document "State Budgets, Unit Allocations, and Unit Emissions Rates") is not valid for any of FMPA's affected units, as shown in Table 2 below. Please also note that Treasure Coast Unit 1 was a new unit in 2008 and only operated for approximately the second half of that calendar year, whereas 2009 was a full operating year. [EPA-HQ-OAR-2009-0491-2725.1, p.4]
[Table 2 can be found on page 4 of this comment.]
Although we understand that EPA is attempting to account for abnormally low usage rates by applying this adjustment, it is not fair to utilities for which this assumption is invalid, particularly when the overall allocation methodology is already shortchanging well-controlled units. FMPA believes that EPA should not adjust the 2009 emissions data for 2008 heat input for any units for which this will result in lower NOx emissions and thus, lower NOx allowance allocations. We would also like to restate our preference for a heat input-based allowance allocation method since EPA's proposed method punishes low-emitters regardless of what calendar year it is based on. [EPA-HQ-OAR-2009-0491-2725.1, p.4]
4. The following FMPA units were improperly assigned SO2 allowance allocations of zero tons and SO2 emission rates under the direct control option of 0.000 lb/mmBtu:
Cane Island (ORIS Code 7238) - Units 1, 2+2A, 3+3A  4
Hansel (ORIS Code 672) - Unit 21
Stock Island (ORIS Code 6584) - Unit CT4. [EPA-HQ-OAR-2009-0491-2725.1, p.6]
According to the proposed Allocation Table, these assigned values are based on "projected" emissions. It is our understanding that, in assigning SO2 allowance allocations, EPA has assumed that dual-fuel fired units will burn only natural gas in the future and will not burn any fuel oil. We believe this is an improper assumption that leads to improper SO2 allowance allocations. This assumption ignores factors, such as, for example, reliability issues associated with hurricanes or the limited peninsular supply of natural gas in Florida, that necessitate the use of fuel oil as a back-up fuel. This issue is discussed in more detail in the comments submitted by the FCG, which FMPA fully supports. [EPA-HQ-OAR-2009-0491-2725.1, p.6]
Specific to FMPA, the "gas-only" assumption is an erroneous assumption for FMPA's Stock Island CT4 because it can only fire fuel oil due to its location. Stock Island CT4 is located in Key West, Florida, on an island on which there is no access to natural gas. Therefore, EPA's assumption that all dual-fuel-fired units will burn only natural gas for purposes of calculating and assigning SO2 allowance allocations is improper and leads to unreasonable results. [EPA-HQ-OAR-2009-0491-2725.1, p.6]
Finally, even if dual-fuel fired units did only fire natural gas in the future, the assumption of zero SO2 emissions is still erroneous. Reported emissions would be at least 0.0006 lb/mmBtu under the direct control option (due to the emissions reporting methods of 40 CFR 75, Appendix D, which allow the use of this emission factor for pipeline quality natural gas). This emission factor rounds up to 0.001 lb/mmBtu, thus the assignment of SO2 emission rates of 0.000 lb/mmBtu under the direct control option is inappropriate. Additionally, the 0.0006 lb/mmBtu emission factor frequently results in reported SO2 tons greater than zero for gas-fired units with higher capacity factors. For this reason, the proposed SO2 allocations of zero tons are also inappropriate. Table 3 below gives specific examples of SO2 emissions for calendar years in which FMPA units fired natural gas exclusively. [EPA-HQ-OAR-2009-0491-2725.1, pp.6-7]
[Table 3 can be found on page 7 of this comment.]

4. See infra at paragraph II.C.5. [EPA-HQ-OAR-2009-0491-2725.1, p.6]
Gainesville Regional Utilities (GRU)
In addition, EPA should not add provisions and new methodologies in the proposed CATR that are not designed to directly respond to the Court remand directing EPA to retain the environmental values of CAIR to the greatest degree practical. As currently proposed, the allowance allocation scheme in this rule will disadvantage utilities like GRU that have made major expenditures to add air pollution controls to meet the CAIR emission caps compared with those that have not. EPA's preferred allowance allocation option has the effect of punishing utilities that have taken early actions to comply with CAIR. [EPA-HQ-OAR-2009-0491-2674.1, p.2]
The Proposed CATR Unfairly Financially Punishes GRU for Its Installation of Advanced Air Pollution Control Equipment
GRU's decision to install air pollution control equipment to meet CAIR was based in part on the assumption that EPA would support CAIR to the greatest extent allowed by the Court. The preferred allocation scheme outlined in the proposed CATR is blatantly unfair in that it determines allowance allocations based on the maximum removal efficiency of installed or planned air pollution control systems. This means the utility installing the air pollution control system will lose the benefit of over controlling a source to accrue surplus allowances. GRU can find nothing in the Court Ruling to justify the move to the EPA preferred allowance allocation scheme. GRU believes that EPA should allocate allowances based on heat input in a similar manner as the CAIR NOx allocation but without the fuel factor. This method will answer the Court remand and also return some fairness to the allocation process. [EPA-HQ-OAR-2009-0491-2674.1, p.3]
The Proposed CATR Disadvantages GRU Relative to Utilities that Elected Not to Control Their Emissions Early
A major consideration in GRU's decision to add air pollution controls to DH#2 was the ability to have surplus allowances to support new generation resources. Currently a 100 MW (net) biomass generating unit is in the final approval stage for construction at the Deerhaven Generating Station (DGS). Under the CAIR allowance allocation methodology, GRU would have been allocated sufficient allowances to cover this new unit. As currently proposed, there will be insufficient allowances for both DH#2 and the new biomass unit. [EPA-HQ-OAR-2009-0491-2674.1, p.3]
EPA's Emission Allowance Allocations are Unfair and Are Counter to Cap and Trade Market Based Principles
The allocations proposed by EPA will be based on the 'Optimized' operation of the pollution reduction equipment of each EGU. This means a utility that installed a new flue gas desulfurization (FGD) scrubber to meet CAIR requirements that gets up to 90% or better SO2 removal would get SO2 allowances based on the equipment running at 90% or better. The same situation applies to utilities that installed new selective catalytic reduction (SCR) equipment. At the same time, EPA proposes to allocate allowances to those utilities that have not made the expensive control technology investments based on the far lower cost compliance options of using low sulfur fuels or low NOx burners. [EPA-HQ-OAR-2009-0491-2674.1, p.5]
GRU believes that a serious equity and fairness issue is created by the allocation methodology used in the proposed CATR. While the Court found fault with EPA's attempt address equity with the fuel factor, there is no indication that the Court required EPA to go to the other extreme. Gainesville Regional Utilities (GRU) spent more than $140 million to install state of the art SO2 and NOx controls on its Deerhaven #2 coal-fired generating unit to meet and exceed CAIR requirements. Under CAIR GRU was expected to receive about 3,136 SO2 allowances but under the proposed CATR the utility would receive only 614 SO2 allowances. [EPA-HQ-OAR-2009-0491-2674.1, p.5]
The Proposed CATR Allowance Allocation Methodology is Poor Public Policy for Several Reasons
First, the proposed allowance allocation methodology violates a key cap and trade success principle. The proposed allocation method fails to allow utilities to choose to over-control their emissions at electric generating units (EGUs) where it is cost-effective and under control at sources where it is less cost-effective. For example, if under CAIR an 80% removal of SO2 would achieve compliance and running at 95% removal could generate surplus allowances for sale, the proposed CATR would not allow that benefit for installing expensive pollution controls. [EPA-HQ-OAR-2009-0491-2674.1, p.6]
Second, the proposed CATR punishes aggressive early emission reductions. Unlike the CAIR rule, by reducing allowances to those who installed expensive air pollution control equipment, EPA is actually financially punishing utilities like GRU for both early compliance and aggressive emission reductions. In addition, EPA proposes that units that haven't installed any controls will get allowances based on operation with lower cost low sulfur fuels and low NOx burners. [EPA-HQ-OAR-2009-0491-2674.1, p.6]
Third, the proposed CATR allowance allocation methodology will hurt future proactive emission reductions by industry. The shift away from the CAIR allocation methodology, one that rewards over control and early emission reductions, to the proposed CATR methodology that punishes the very same behavior, will create a long lasting chilling effect on future proactive emission reductions by industry. [EPA-HQ-OAR-2009-0491-2674.1, p.6]
Finally, the proposed CATR allowance allocation method ignores the fact that many costly decisions were made by the utility industry based on the provisions of CAIR. To meet the CAIR compliance requirements GRU committed to costly emission control systems while the rule was under court challenge. That commitment by GRU was based in part on the assumption that EPA would keep as much of CAIR intact as the Court would allow. [EPA-HQ-OAR-2009-0491-2674.1, p.6]
In response to EPA's request for suggestions for an alternative allowance allocation method, GRU strongly recommends that EPA allocate both SO2 and NOx allowances based on heat input without a fuel factor at the emission rates necessary to achieve the state emission budget. Using that allocation method would not only address the Court's remands based on the fuel factor and improper use of Acid Rain SO2 allowances, it would bring fairness back to the allocation methodology. [EPA-HQ-OAR-2009-0491-2674.1, p.6]
The EPA Preferred Cap and Trading Program is Overly Complicated
Intrastate trading is unlimited but interstate trading is limited to - 10% of the state's budget. However, Florida can only trade with Group 2 states. These include Alabama and Mississippi but not Georgia which is a Group 1 state. Since the EGUs with controls in place or planned are given allowances based on estimated emissions with controls operating at full rated capability, what is there left to trade? The key principle of the cap and trade methodology is over control of some units to allow under control of others with utility decisions based on where the cheapest reductions can be made. Again, GRU urges EPA to use a methodology for allocating allowances for compliance with the proposed CATR based on heat input. This would operate similar to the NOx allowance allocation methodology without a fuel factor. [EPA-HQ-OAR-2009-0491-2674.1, p.7]
GE Energy Financial Services (GE EFS)
EPA Cannot Rely Upon Projections of Dispatch Generated by Its Integrated Planning Model ('IPM') as the Basis for Allocating Allowances to Individual Units, Unless EPA First Resolves Serious Errors With the Model
While GE EFS supports EPA's use of the Integrated Planning Model ('IPM') to establish statewide budgets and facilitate policy development, GE EFS does not believe EPA can or should rely upon IPM's projections of future dispatch to establish allocations of emissions allowances down to the level of the individual unit, unless EPA first resolves a number of significant errors in the model and its underlying data set. [EPA-HQ-OAR-2009-0491-2701.1,p.2]
EPA Must Account for the Impact That Long-Term Contracts Have on Facility Dispatch by Revising IPM So That It Models Dispatch of Facilities Consistent With the Requirements of Their Long-Term Contractual Obligations
GE EFS is aware of instances in which IPM has predicted incredibly low dispatch levels for facilities subject to long-term contracts. As an example of such erroneous projections, GE EFS would refer to the comments submitted by Cogen Technologies Linden Venture, L.P. ('Linden Cogen') regarding its combined cycle cogeneration plant. Linden Cogen is owned by GE EFS. These projections of future dispatch have no basis in reality and are proven false by both the facility's operating history and its ongoing contractual obligations. To avoid such arbitrary model results for both Linden Cogen and the many other facilities subject to long-term contracts in which GE EFS has an interest, EPA must account for the impact that long-term contracts have on facility dispatch by revising its model, so that it predicts dispatch of facilities consistent with the requirements of their long-term contractual obligations. EPA must then re-run the model, incorporating real-world assumptions about dispatch of facilities operated pursuant to contracts. [EPA-HQ-OAR-2009-0491-2701.1, p.2]
If EPA cannot correct the errors in IPM that have generated arbitrary and unrealistic predictions of future dispatch at a unit level, including the failure to model facilities' dispatch consistent with their long-term contractual obligations, EPA should instead base allocations on historical operating data, just as it has proposed as the basis for state budgets (other than the 2014 sulfur dioxide ('S02') budgets for group 1 states). [EPA-HQ-OAR-2009-0491-2701.1,p.3]
If actual performance data are more accurate and representative in predicting emissions at the statewide level, they certainly should be deemed more accurate and representative in predicting the dispatch and emissions of individual facilities. It would be arbitrary and capricious for EPA to rely upon IPM's projections as the basis for establishing allocations, when EPA has already acknowledged that those projections cannot be relied upon to establish the corresponding state budgets. Accordingly, should EPA fail to correct the errors in IPM that have resulted in its erroneously low projections of dispatch for facilities operated pursuant to long-term contracts, EPA should instead base allocations on historic operating data, as adjusted to reflect the operation of existing and planned emissions controls. An allocation methodology based on historic operating data is not inconsistent with the court's decision in North Carolina v. EPA and would assure that the same analyses and data relied upon by EPA to establish a state's budget are used to establish the unit-specific allocations for that state. [EPA-HQ-OAR-2009-0491-2701.1,p.3]
Where Allocations Area Based on Historic Heat Input Data, They Should Be Based on Data From a More Representative Period of Time Than a Single Year
For those states in which EPA has already proposed to base allocations of allowances upon historical heat input data and for any other states where it should decide to do so because of the unreliability of IPM's projections, EPA should base allocations upon historical data not from a single year, but from a more representative period of time. Using only one year's data as the basis for allocations could penalize facilities that had lower emissions in 2008 or 2009 because they had lower utilization during that period due to the recession or were down for an extended period of time to install controls to comply with the requirements of CAIR. [EPA-HQ-OAR-2009-0491-2701.1,p.3]
GE EFS Does Not Support the Alternative Allocation Methodology, Whereby Each Facility Would Be Allocated Allowances Based on Its Share of Projected Statewide Heat Input
GE EFS 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' within the state. 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 erroneous projections of future dispatch for facilities subject to long-term contractual obligations. However, if EPA's proposed alternative were to allocate allowances based on each source's share of historical, rather than projected, statewide heat input, GE EFS agrees that this would be a fair and equitable approach. [EPA-HQ-OAR-2009-0491-2701.1,p.4]
EPA Should Make Remaining Allowances in the New Unit Set-Aside Available to Long-Term Contract Generators Who Experience a Shortfall One to a Return of Utilization Back to Levels Achieved Prior to the Recession
GE EFS believes EPA should make any remaining allowances in the new unit set-aside available to long-term contract generators who exceeded their allocation due solely to an increase in utilization back to levels achieved prior to the recession. Unlike a utility that can seek to recover costs associated with emissions allowances from its ratepayers or a merchant generator that can recover such costs through the market price of electricity, long-term contractor generators can be severely impacted by the requirement to purchase emissions allowances. Further, long-term contractor generators do not exercise control over when their facilities can be dispatched, but must operate whenever called upon by their customers. GE EFS holds interest in many long-term contract generators whose interests may be prejudiced by the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2701.1,p.5]
Congress has previously recognized the economic realities faced by long-term contract . generators who have no way of recovering the cost of emissions allowances, both upon enacting the Acid Rain Program under the 1990 Clean Air Act Amendments and more recently as part of the development of a federal cap and trade program for emissions of greenhouse gases. By making allowances remaining in the new unit set-aside available to long-term contract generators before distributing the remainder of the set-aside to eligible existing facilities, EPA could prevent long-term contract generators from needing to pay potentially significant costs for allowances that cannot be passed along to their customers. This would provide needed relief if a long-term contract generator experiences a shortfall in allowances due to a return of demand to pre-recessionary levels, without compromising the integrity of the statewide emissions budgets. A more detailed description of this proposal is contained in the comments filed by Birchwood Power Partners, L.P. ('Birchwood'), which is co-owned by GE EFS and a partner. [EPA-HQ-OAR-2009-0491-2701.1, p.5]
Great River Energy
Even if given more time to review EPA's technical supporting documentation, Great River Energy is not convinced that it could fully understand EPA's modeling and unit specific allocations. The proposed rule, and its underlying documentation, present something like a 'black box,' as described by the National Rural Electric Cooperative Association ('NRECA') in its comments to the proposed rule. EPA fails to present adequate information so as to allow full comment on unit emission allocations and other issues important to affected electric utilities. [EPA-HQ-OAR-2009-0491-2758.1 p.2]
Like NRECA, Great River Energy believes that EPA has a legal obligation to develop a rational rulemaking process that provides all the information needed to fully understand the proposal's rationale and interworking. The present 'black box' approach falls short. Accordingly, Great River Energy urges EPA to issue a supplemental Transport Rule proposal that specifies in adequate detail how specific unit emissions were determined so that we can provide more constructive comments for our specific units. [EPA-HQ-OAR-2009-0491-2758.1 p.2]
Notwithstanding these concerns, Great River Energy hereby provides some key comments and observations of errors in EPA's database concerning our units. We have also attached an emissions summary table (Attachment 1, Great River Energy - Emissions Summary) in an attempt to address the errors in EPA's IPM database:
 :: 2009 is not a representative year for Great River Energy's emission sources. EPA projects unit-by-unit heat input that differs greatly from historical values. (See Attachment 2, Great River Energy - Heat Input Variability and Attachment 1.)
o Load variability was at its lowest point in a 5 year period. See Attachment 2 as an indication of overall unit-by-unit variability. This table shows each unit's 5 year average heat input in addition to the plotted range of possible minimums and maXImums.
o Weather variability provided one ofthe coolest summers in Minnesota's history, resulting in very limited peaking turbine run times. (Again, see Attachment 2.)
o Fuel variability was non-existent, as GRE was able to run almost entirely on natural gas, even though historically gas is curtailed in the winter requiring fuel oil combustion and its corresponding higher NOx and S02 emissions.
o Elk River Peaking Station (ORIS Code 2039) began commercial operation in mid 2009, and completed CEMS certification in the 4th quarter. Reported emissions for 2009 are not indicative of future operation. EPA does not recognize this unit as new. As such, its emissions should be considered on a prorated basis. (See Attachment 1.) [EPA-HQ-OAR-2009-0491-2758.1 p.2]
For a relatively small cooperative representing a very minor percentage ofthe state's overall budget, these inaccuracies may seem insignificant to EPA and are arguably insignificant in downwind contributions to non-attainment areas. Nevertheless, these errors and false assumptions are extremely significant to our cooperative, our members and customers. Given load variability, temperature variability, fuel variability, and potential growth, Great River Energy will not have sufficient allocations to cover emissions, does not expect a viable trading program, and cannot cost effectively control our simple cycle peaking turbines, by EPA's own analysis, while remaining competitive in the Upper Midwest. EPA has unfairly punished clean burning peaking turbines, some of which already have BACT emission controls, with this rule. Further, from our very limited assessment ofthe data upon which the allocations were based, Great River Energy speculates that there are similar data inaccuracies, which if corrected, would lead to different allocation outcomes, at a minimum, and may also lead to different modeling results, which, like CAIR, could result in Minnesota being dropped from Transport Rule coverage. Great River Energy submits for EPA consideration our emissions summary table in Attachment 1 to best project our emissions, including variability issues, as discussed, and assuming that EPA does not intend to require beyond-BACT controls for our peaking plants. [EPA-HQ-OAR-2009-0491-2758.1 p.4]
Unfortunately, as a small rural electric cooperative, Great River Energy does not have the resources to review all of the data and re-evaluate EPA modeling assumptions in order to adequately question Minnesota's inclusion in the Transport Rule.. Nevertheless, Great River Energy does call attention to the electric generating unit ('EGU') category, which is the only source category covered by the Transport Rule. Given that the vast majority of state allowances will be given to two utilities in Minnesota, and primarily to their baseload units, Great River Energy questions the logic ofinc1uding simple cycle combustion turbines as part of the EGU source category. [EPA-HQ-OAR-2009-0491-2758.1 p.5]
It appears that Minnesota EGU simple cycle combustion turbines are included in the Transport Rule as an artifact from CAIR. In CAIR, as a generality, it may have made sense, in most states, to include combustion turbines with other EGUs, due to their increased operation and assumed significant contribution to ozone season non-attainment in those areas. However, with respect to the Transport Rule, EPA has determined that Minnesota does not contribute significantly to ozone season non-attainment. In fact, like CAIR, Minnesota may only contribute to annual PM2.5 non-attainment in certain areas. [EPA-HQ-OAR-2009-0491-2758.1 p.5]
Great River Energy questions some assumptions made by EPA that could lead to inclusion of simple cycle peaking plants. Upon reviewing the 'Technical Support Document (TSD) for the Transport Rule Docket ID No. EPA-HQ-OAR-2009-0491 State Budgets, Unit Allocations, and Unit Emissions Rates,' we first find EPA's lumping of all EGU's into one source category of '>25MW fossil fuel fired units,' even though there are distinct emission differences and cost effectiveness thresholds between baseload coal fired units and peaking units, as an example. There is no discussion or reference within the Transport Rule as to the EPA's rationale for including combustion turbines with all fossil fuel fired >25MW, other than for simple convenience. [EPA-HQ-OAR-2009-0491-2758.1 p.6]
As a different point of reference, in the IPM Base Case model v3.02 Table 21 , EPA assumes that 'advanced combustion turbines' are projected to have 92% availability. Clearly, with this incorrectly projected availability and assumed comparable 'capacity' factor, SCR retrofits may consequently be viewed as cost effective in EPA's modeling effort. However, our peaking turbines typically operate at a 10%, or less, annual capacity factor, which would cause a much higher $/ton cost and would be viewed as not cost effective by EPA's own thresholds. [EPA-HQ-OAR-2009-0491-2758.1 p.6]
While EPA cannot be expected to understand the nuances of each source and its existing permits and associated emission limits and controls, EPA must take into consideration Great River Energy's unique situation with respect to already controlled peaking plants, and its reduction of allowances to this small source category. [EPA-HQ-OAR-2009-0491-2758.1 p.6]
Certainly EPA has modeled a contribution from Minnesota to downwind annual non-attainment, despite numerous errors within the IPM dataset. Upon reviewing the broad category ofEGUs as the only regulated 'source' under the Transport Rule it is clear, based on both emissions and EPA's projected allowance allocations, that only a few sources in Minnesota are responsible for the downwind modeled contribution. (See Attachment 3, Transport Rule - Minnesota Allocations by Company.) Therefore, it does not make sense that a few smaller sources, within the broader EGU category, are included. They neither 'contribute significantly,' nor could add any significant economic incentives to a state trading program, given the concentration of allowances as proposed by EPA. Finally, EPA's distribution of allowances to these smaller sources is inequitable, relative to other larger sources in the state, and will place these smaller sources at a competitive disadvantage. Specifically, the larger sources are expected to reduce their NOx emission by a lesser percentage (30-38%) versus the smaller sources that range from 50-70%, based on our projections. Great River Energy cannot understand EPA's logic for including its combustion turbines in Minnesota. [EPA-HQ-OAR-2009-0491-2758.1 p.6]
Holland Board of Public Works
The methodology document that the EPA provides ('State Budgets, Unit Allocations and Unit Emission Rates', prepared July 2010) in support of this rule, states on page 12 'Units in group 1 states without an IPM projection do not receive S02 allocations in 2014 and beyond'. Why? We are unclear after reviewing the document how and why this allocation was made. The HBPW has no intention of retiring this unit at any time in the near future. We are confident that certain control methodologies can be implemented to reduce emissions consistent with the average percentage reduction required of the State of Michigan. The modeling program is arbitrary and fails to consider the real-life evaluations and decisions that will be made by municipal entities like the HBPW. [EPA-HQ-OAR-2009-0491-2861.1, p.2]
Illinois Environmental Protection Agency
U.S. EPA has proposed to establish S02 emissions budgets for the second phase of the Transport Rule based on unit-specific cost-effectiveness calculations using the Integrated Planning Model (IPM). While the IPM model is a useful and sophisticated planning tool, the Illinois EPA
believes that it is inappropriate to use the rPM for unit-by-unit allocations. For example, rPM does not allocate allowances to two units in illinois, Ameren's Meredosia units I and 2, because the model assumes that it is not cost-effective to control these units. However, Ameren has not announced any plans to shut down these units, and more importantly, it should be up to Ameren to make the determination of how best to comply. Illinois EPA recommends that rPM's costeffectiveness calculations be used regionally, or to establish state budgets, but that it not be used on a unit-by-unit basis.
To allocate allowances on a company or unit basis, Illinois EPA recommends that such allocations be based on gross electrical output. Illinois uses this approach to allocate allowances in CAIR. Historical output data on a unit basis are readily available and it would be a straightforward process to allocate a state's budget to existing units. This approach would be more equitable than U.S. EPA's proposed approach and would encourage utilization of the most efficient generating units.
Illinois EPA further recommends an approach to allow new emission units to be rolled in to the existing-source allocation pool. Illinois' current rules under CAIR requires the state to revise unit allocations periodically to include new sources as existing sources and to remove allocations to units that have been permanently shut down. This approach provides a mechanism for new, more efficient and better controlled uuits to receive allowances without permanently relying on allowances under the New Source Set-Aside. Illinois EPA recommends that future allocations be updated periodically to allow new units into the pool of existing units. [EPA-HQ-OAR-2009-0491-2781.1 p.2-3]
Independence Power & Light (IPL)
The Rule Creates A Perverse Incentive for EGU's Given 'Zero Allocations'to Refrain from Retrofitting
Another factor ignored in the Rule concerns the perverse incentive created in situations where an EGU has been allocated zero emissions allowance in 2014. The proposed rule does not appear to offer any prompt means to increase the zero allowance should an owner decide to retrofit that unit with the controls assumed in the Rule to lead to state compliance with allocations as to individual EGUs by 2014. Under the proposal, it appears that a 2014 zero allowance unit can obtain a positive allowance only by fitting within the definition of 'new unit' For this purpose, the applicable part of the definition states: 'any unit listed in Appendix A that stopped operating for three consecutive years, is no longer allocated allowances as an existing unit, but resumes operation' would be considered a new unit. 75 FR at 4531011-2.4 Even assuming this applies to a zero allowance EGU, that would mean at a minimum three, and possibly up to seven, years of non-operation before the retrofitted EGU qualifies for a positive allowance. During that time, and not withstanding that the EGU is in compliance, its owner would be required to purchase allowances to run the unit or purchase replacement electricity if the unit is shut down. [EPA-HQ-OAR-2009-0491-2741.1, pp.15-16]
This creates a perverse incentive for zero allowance EGU owners not to retrofit those units because the owners incur the substantial retrofit costs without any assurance that they will gain any benefit from their action. Unless owners are clearly assured that a zero allowance unit will promptly receive a positive allowance upon compliance, they face the real possibility of paying the same costs (for buying allowances or for purchasing replacement electricity) that they would face if the unit remained non-compliant. Even in a situation where the new unit definition would permit a positive allowance, that would not occur for several years, thus delaying the owner's opportunity to recoup the costs of retrofitting through the sale of electricity from that unit. From a rational economic perspective, the least cost approach in these circumstances would be not to retrofit the zero allowance unit. But that option serves neither the public interest related to air quality nor the public interest to increasing the availability of low cost electricity. Consequently, EPA should act to provide reasonable assurance on this point. [EPA-HQ-OAR-2009-0491-2741.1, p.16]

4 It is not entirely clear whether the three years is really seven years, given 'EPA proposes that, once an EGU does not operate ... for 3 consecutive years, the Agency would no longer allocate allowances to the unit, starting in the seventh year after the first year of non-operation.' 75 FR at 45310/3. This coupled with the new unit definition creates confusion as it relates to zero allowance EGUs: Does a zero allowance constitute an allowance that EPA must no longer allocate before the EGU meets the new unit definition? The preamble may also be inconsistent with the proposed rule, § 97.412(a)(2), which states an allowance may be request for 'the first control period after the control period in which the unit resumes operations (for a unit listed in appendix A of this subpart)' 75 FR at 45377/2.
Indiana Department of Environmental Management
Although the currently proposed rule does not contain unit by unit emission caps, Indiana has several concerns regarding the accuracy of the data used for justifying the proposed rule, establishing state budgets, and sub-state allocations. There are several sources that are not 25 MWe electric generating units (EGUs), as well as some nonEGUs and utilities that have not operated for five years receiving allowances, and some non-EGUs and utilities that are operational but did not receive allowances or sufficient allowances. Especially with the 2014 budget, the allocation process is not transparent and it is impossible to determine if the distribution is fair and balanced. [EPA-HQ-OAR-2009-0491-2645.1, p.3]
Kansas City Board of Public Utilities (BPU)
The Rule Creates A Perverse Incentive for EGU's Given 'Zero Allocations' to Refrain from Retrofitting
Another factor ignored in the Rule concerns the perverse incentive created in situations where an EGU has been allocated zero emissions allowance in 2014. The proposed rule does not appear to offer any prompt means to increase the zero allowance should an owner decide to retrofit that unit with the controls assumed in the Rule to lead to state compliance with allocations as to individual EGUs by 2014. Under the proposal, it appears that a 2014 zero allowance unit can obtain a positive allowance only by fitting within the definition of 'new unit.' For this purpose, the applicable part of the definition states: 'any unit listed in Appendix A that stopped operating for three consecutive years, is no longer allocated allowances as an existing unit, but resumes operation' would be considered a new unit. 75 FR at 45310/1-2. 9 Even assuming this applies to a zero allowance EGU that would mean at a minimum three, and possibly up to seven, years of non-operation are required before the retrofitted EOU qualifies for a positive allowance. During that time, and notwithstanding that the EGU is in compliance, its owner would be required to purchase allowances to run the unit or purchase replacement electricity if the unit is shut down. [EPA-HQ-OAR-2009-0491-2740.1, pp.20-21]
This creates a perverse incentive for zero allowance EGU owners not to retrofit those units because the owners incur the substantial retrofit costs without any assurance that they will gain any benefit from their action. Unless owners are clearly assured that a zero allowance unit will promptly receive a positive allowance upon compliance, they face the real possibility of paying the same costs (for buying allowances or for purchasing replacement electricity) that they would face if the unit remained non-compliant. Even in a situation where the new unit definition would permit a positive allowance, that would not occur for several years, thus delaying the owner's opportunity to recoup the costs of retrofitting through the sale of electricity from that unit. From a rational economic perspective, the least cost approach in these circumstances would be not to retrofit the zero allowance unit. But that option serves neither the public interest related to air quality nor the public interest to increasing the availability of reasonably-priced electricity. Consequently, EPA should act to provide reasonable assurance on this point. [EPA-HQ-OAR-2009-0491-2740.1, pp.21-22]

9 It is not entirely clear whether the three years is really seven years, given 'EPA proposes that, once an EGU does not operate ... for 3 consecutive years, the Agency would no longer allocate allowances to the unit, starting in the seventh year after the first year of non-operation.' 75 FR at 45310/3. This coupled with the new unit definition creates confusion as it relates to zero allowance EGUs: Does a zero allowance constitute an allowance that EPA must no longer allocate before the EGU meets the new unit definition? The preamble may also be inconsistent with the proposed rule, § 97.412(a)(2), which states an allowance may be request for 'the first control period after the control period in which the unit resumes operations (for a unit listed in appendix A of this subpart).' 75 FR at 45377/2.
Lansing Board of Water & Light
BWL is extremely concerned about the lack of explanation regarding the methodology to determine a source's allocation, and the apparent errors found within the available spreadsheets. [EPA-HQ-OAR-2009-0491-2752.1, p.2]
Louisiana Chemical Association (LCA)
LCA also has grave concerns about the proposed allocation of NO x allowances under the FIP. LCA has individual members that own and/or operate highly efficient, well controlled natural gas fired cogeneration units that supply power to their industrial sources as well as some portion of their electrical output to the grid. Each of these cogeneration units received allocations less than 20% of their 2009 actual NOx emissions and their 5 year average historic emissions. Under EPA's proposal, these 'must run' EGUs received allocations that do not allow them to operate at needed rates without significant annual expenditures in the millions of dollars needed to purchase allowances. We are continuing to review the technical support documents, but have found no legitimate reason readily stated for EPA to penalize these sources in this fashion. The technical support documents are formatted in such a manner that they lack transparency and ease of use. [EPA-HQ-OAR-2009-0491-1925.1, p. 3]
LCA is also concerned about the proposed allocation of NOx allowances to public utilities from which LCA members purchase power. Many of the Louisiana Public Service Commission regulated EGUs in Louisiana received zero NOx allocations even though they have been providing critical power to Louisiana businesses and residential consumers for the past 5 years and have no announced plans to curtail operations. EP A's support documents indicated these same units do not need retrofits to reduce emissions. Other publicly regulated EGUs appear to have been allocated significantly more NOx allowances than their historical NOx emissions under EPA's proposal and stand to gain a significant financial windfall from the EPA allocation scheme. After weeks of communications with EPA trying to understand the basis of these proposed unit allocations, we have been informed that the basis for this allocation scheme was EPA's IPM TR Base Case 3.02 modeling, which simply projects that due to economic factors unrelated to environmental issues, some units will not be running in 2012 or will be running at greatly reduced rates. The allocations among units were based on these projected, modeled economic consequences, not on any determination of environmental need. The result will be millions of dollars in windfall profits to certain units and significant costs to others, including the industrial consumers of such power. [EPA-HQ-OAR-2009-0491-1925.1, p. 3]
EP A staff also informed LCA that the IPM model does not account for transmission constraints or other factors that make these 'must run' units. We are concerned that all of the units in the New Orleans area and across much of South Louisiana did not receive adequate allowances to allow operation at a level commensurate with local needs and that there are significant deficiencies in the IPM and/or with economic assumptions used therein that do not reflect real world constraints. See attached map. [See docket number EPA-HQ-OAR-2009-0491-1925.1, p. 6 for the map.] Addressing such assumptions requires gathering of a significant amount of data from a number of EGUs, including those that arc not LeA members, to demonstrate why such units are 'must run' units, what the transmission constraints are, and how other factors that the model did not take into account will impact the utilization of those EGUs. This will take more time than EPA has allowed. [EPA-HQ-OAR-2009-0491-1925.1, p. 3]
If Interstate Transport Needs to be Addressed, EPA Should Allow Louisiana to Make any Required NOx and SO2 Allocations in a SIP.
 As discussed in Section III., above, EPA should recognize the requirements of federalism inherent in the Clean Air Act and should allow Louisiana adequate opportunity to adopt a SIP with any required allocations. Louisiana may choose to regulate sources other than EGUs and /or could rely upon a combination of reductions from sources under consent decrees not included by EPA in its projections and reductions from EGUs or other emissions. Louisiana DEQ and the Louisiana Public Service Commission are in the best position to determine fair and equitable allocations that will avoid unnecessary impacts on the ability of the state's EGUs to provide its citizens and businesses with electrical power. [EPA-HQ-OAR-2009-0491-3527.1, p. 43]
As an Alternative, EPA Should Allow Sources the Same Percentage of the Budget that They Received Under CAIR Allocations.
As an alternative, and only in the event that it is determined a FIP is needed and justified to address intrastate transport of Louisiana emissions on Texas receptors (which is denied), then LCA requests that EPA allocate the NOx allowances by providing EGUs with the same % of the total state budget that they had under the approved Louisiana NOx CAIR SIP. [EPA-HQ-OAR-2009-0491-3527.1, p. 43]
Louisiana Energy and Power Authority (LEPA)
The EPA's methodology for allocating emission allowances to Electric Generating Units ('EGUs') is seriously flawed. That methodology fails to allocate any allowances to critical EGUs that must run to serve load in communities across Louisiana. Although the 60-day time frame allowed by the EPA for review and comment was grossly insufficient to permit a detailed analysis of the complex technical modeling supporting the allocations, this error appears to result from a lack of model inputs to properly capture transmission constraints or to otherwise reflect the fact that some EGUs, like LEPA's Morgan City and Houma units, must run to serve load. [EPA-HQ-OAR-2009-0491-2700.1, p.3]
The failure to allocate emission allowances to LEPA's critical units located in transmission constrained areas would significantly raise costs and could very possibly prevent LEPA from running those units. If LEPA cannot run those critical units and has insufficient time to secure necessary upgrades to serve its constrained areas in another way, there would be blackouts in LEPA's control area, and the North American Electric Reliability Corporation ('NERC') could revoke LEPA's designation as a balancing authority and control area, leaving LEPA's member communities unserved. LEPA urges the EPA to address this serious omission in any final rule it may promulgate. [EPA-HQ-OAR-2009-0491-2700.1, pp.3-4; These comments can also be found at EPA-HQ-OAR-2009-0491-3738.1_NODA, p.2, 10/15/2010]
LEPA MUST RUN ITS GAS-FIRED GENERATING UNITS IN HOUMA AND MORGAN CITY TO PROVIDE ELECTRICITY TO THE RESIDENTS AND BUSINESSES IN LEPA'S CONTROL AREA BECAUSE OF A CONGESTED TRANSMISSION GRID. [EPA-HQ-OAR-2009-0491-2700.1, p.6; To see additional comments pertaining to LEPA MUST RUN ITS GAS-FIRED GENERATING UNITS IN HOUMA AND MORGAN CITY TO PROVIDE ELECTRICITY TO THE RESIDENTS AND BUSINESSES IN LEPA'S CONTROL AREA BECAUSE OF A CONGESTED TRANSMISSION GRID, see pp.6-9]
Thus, LEPA's Houma and Morgan City units must run to serve load in LEPA's control area because of transmission constraints and there are no other options for serving load in that area. Those units must run when the transmission grid is overloaded, and they must be turned on and ramped up with sufficient lead time to ensure those units are available when transmission constraints are present. Yet, the proposed Transport Rule assumes those units never run and thus assigns those units no emission allowances. [EPA-HQ-OAR-2009-0491-2700.1, p.9]
IF THE MORGAN CITY AND HOUMA UNITS RECEIVE NO ALLOWANCES, LEPA COULD BE FORCED TO SHUT THOSE UNITS DOWN, CAUSING BLACKOUTS IN LEPA'S CONTROL AREA AND SUSPENSION OF LEPA'S BALANCING AND CONTROL AREA AUTHORITY.[EPA-HQ-OAR-2009-0491-2700.1, p.14]
The proposed Transport Rule allocates no emission allowances to LEPA's must run units, and at the same time would impose a more limited trading regime for allowances and a shorter time frame for compliance. LEPA could thus be facing an extremely tight market for available emission allowances, with little or no allowances available for purchase. If LEPA has no allowances of its own and is not able to purchase any allowances, it would be forced to shut down the Morgan City and Houma units. When transmission is not available to deliver power to LEPA's control area, there would be blackouts in LEPA's service territory and thousands of residents and businesses would be left without power. This would include a shut down in delivery of power to hospitals, schools, nursing homes, other critical businesses, government operations and thousands of residences. [EPA-HQ-OAR-2009-0491-2700.1, pp.13-14]
In addition, if LEP A cannot rely on the Houma and Morgan City units, it would not have sufficient capacity to cover the load in its control area, one of NERC's requirements for recognition as a balancing authority and control area. Thus, NERC potentially could withdraw or suspend LEP A's recognition as a balancing authority and control area. If that happens, LEP A would be unable to service many of its members' needs and the small cities and towns of Louisiana would lose the operational support and economies of scale that LEPA provides. [EPA-HQ-OAR-2009-0491-2700.1, p.15]
THE FAILURE OF THE PROPOSED TRANSPORT RULE TO ALLOCATE ALLOWANCES TO GENERATING UNITS IN TRANSMISSION CONSTRAINED AREAS IS INCONSISTENT WITH THE PUBLIC INTEREST AND WITH SEVERAL KEY PRINCIPLES UNDERLYING THE RULE. [EPA-HQ-OAR-2009-0491-2700.1, p.15; for additional comments pertaining to THE FAILURE OF THE PROPOSED TRANSPORT RULE TO ALLOCATE ALLOWANCES TO GENERATING UNITS IN TRANSMISSION CONSTRAINED AREAS IS INCONSISTENT WITH THE PUBLIC INTEREST AND WITH SEVERAL KEY PRINCIPLES UNDERLYING THE RULE, see pp.15-17]
In addition, by allocating no allowances to units that must run to serve load, the proposed Transport Rule provides LEPA with no flexibility III complying with the rules and no cost-effective means of complying with the rules. [EPA-HQ-OAR-2009-0491-2700.1, pp.15-16]
Louisiana Public Service Commission
Likewise, the LPSC Staff has concerns about the EPA's assumptions regarding how certain EGUs mayor may not be utilized (dispatched) on a forward-going basis. For instance, our initial review of the proposed rule indicates that there are several 'regulatory must-run' units modeled under the EPA Transport Rule as not running on a forward-going basis. It would appear that the model rule, and its associated allowance allocations, is not adequately recognizing the important voltage and load following support functions of these limited run units. However, our analysis is still in its early stages and we need additional time to review the reasonableness of this assumption, and to determine how the costs to our regulated utilities, and ultimately ratepayers, will change under these unit-specific operating estimates/assumptions.[EPA-HQ-OAR-2009-0491-1928.1, p.2]
The LPSC Staff is also concerned about the limitations for interstate allowance trading and the implications this has for Louisiana in meeting the overall emissions reductions envisioned by EPA. While interstate transactions were included in the CAIR, they are excluded in the proposed CATR. Recognizing the legal considerations leading to EPA's decision, the LPSC Staff notes that the restriction has important implications regarding how quickly, how costly, and how reliably Louisiana can move towards the EPA's emission goals. The use of tradable allowances for clean air and renewable markets is reflected by a number of important successes that, as a general matter, have helped drive down emissions compliance costs. The LPSC Staff is concerned that the removal of the interstate trading provisions, coupled with the speed of the implementation period, will drive-up compliance costs by reducing the supply of available credits relative to demand. [EPA-HQ-OAR-2009-0491-2670.1, pp.5-6]
The LPSC Staff has serious reservations about how allowances will be used, and the impact the interstate trading restriction will have on multi-state holding companies like Entergy Corporation, which operates in five different Gulf Coast states. Most holding companies attempt to reduce overhead and other general costs by pooling resources and optimizing their generation dispatch across a broad geographic region and diverse generation resource mix. The provisions in the EPA's proposed rule may negatively affect these synergies and increase rates for Louisiana and the other utilities that are subject to the multi-state operating agreements regulated by the Federal Energy Regulatory Commission ('FERC'). [EPA-HQ-OAR-2009-0491-2670.1, p.6]
Machaver, Bob
Allocations: If allowed in the FIP process, it is suggested that the rule establish State NOx and SO2 Budgets and allow the states to make allocations to the individual sources, rather than directly specifying unit level allocations in the rule. There are several reasons this approach is preferred:
− Initial review of the Allocations for sources in Massachusetts, indicates that in many cases these allocations do not seem reasonable. Small peaking type sources have been allocated significant allocations, while larger sources have not been provided any allocations. More generally, it does not seem appropriate to designate Allocations based on a single operating year.
− There is no provision for Allocations to be set aside for new sources. It would seem that EPA, and the states, would want to promote operation by new sources, and a set aside would seem an appropriate means to accomplish this. In most states, the NOx Budget rules have included a New Source set-aside.
− There does not appear to be any mechanism for updating Unit level annual Allocations based on changing operating patterns among sources.  [EPA-HQ-OAR-2009-0491-2873.1, p.1]
While most of these issues might be addressed in a final rule that retains direct source allocations, it would seem more likely that an appropriate Allocation distribution would result if states were given responsibility for developing an Allocation scheme, as they are more familiar with the sources in their jurisdiction.  [EPA-HQ-OAR-2009-0491-2873.1, p.1]
If for some reason, EPA believes certain sources within states should be targeted for achieving emission reductions (and discouraged from using allowances) due to their interstate transport impacts, the State Budgets could perhaps be disaggregated to smaller sub-state regional areas.[EPA-HQ-OAR-2009-0491-2873.1, p.1]
Manitowoc Public Utilities (MPU)
 MPU supports the U. S. EPA's proposal not to include any allowance auctioning under its Proposed Remedy Option. No need or reason exists to use allowance auctions to implement the Proposed Transport Rule's emission reduction requirements.   [EPA-HQ-OAR-2009-0491-2860.1,p.3]
Allowance Auctioning Under the Proposed Remedy Option
MPU supports the U. S. EPA's proposal not to include any allowance auctioning under its Proposed Remedy Option. No need or reason exists to use allowance auctions to implement the Proposed Transport Rule's emission reduction requirements. [EPA-HQ-OAR-2009-0491-2860.1, p.5]
Marquette Board of Light and Power
Inaccurate Projected Data for Heat Input
The Budgets and Allocations  - Detailed Unit-Level Data (Excel) file available at http://www.epa.gov/airquality/transport/tech.html contained inaccurate projected data. The heat input for Shiras Unit 3 has increased an average of 4% annually for calendar years 2005 to 2008. The recession of 2009 appears to be an anomaly on the heat input of Shiras Unit 3 because it appears that the 2010 heat input will be more representative of pre-2009 operating levels. Using the historical average of the past three years of heat input prior to the recession yields 4,114,467 mmBtu/yr. Assuming a much more conservative growth rate of 2% annually, will provide a projected heat input of 4,196,756 mmBtu/yr in 2012 and 4,336,305 mmBtu in 2014. This is an accurate representation of the projected operation of Shiras Unit 3. [EPA-HQ-OAR-2009-0491-2764.1, p.2]
Unintended Incentives to Pollute to Permitted Levels
The BLP has made significant reductions in Shiras Unit 3 NOx emission rates from 0.301 lbs/mmBtu (525 tons) in 1998 to our current rate of 0.150 lbs/mmBtu (246 tons) in 2009 by focusing our efforts of maximizing the efficient combustion in Shiras Unit 3. This transport rule is unintentionally structured to prohibit utilities from taking such measures proactively. In the future, out of concern of establishing a lower than needed baseline, rules such as this will force utilities to operate up to the permitted limit. The Clean Air Interstate Rule took this concept into account and set a flat emission rate for all applicable units and allocated allowances based on a consistent set of emission rates for all applicable units and historical heat input reported values. If the EPA's intention is to set systems up to proactively lower emissions on combustion units then the approach used in CAIR of allocating allowances should be incorporated in future rules. The other option would be to use the permitted emission limits as a baseline and require every applicable unit to make a standard percentage reduction from that baseline. [EPA-HQ-OAR-2009-0491-2764.1, p.3]
Establishing a Precedent that Eliminates Over Controlling of Emissions Perhaps most troubling about the Transport rule is that it is structured to prohibit controlling beyond what the rule requires. There are financial incentives to over control when a rule is structured such that it collaborates with a solid market based approach. However, it would be within short sightedness for companies in the future to over control to reduce costs through market trading of allowance only to have that market devalued by a future rule set upon a baseline of over controlled emissions. Companies will be looking at the approach taken by the EPA in the transport rule and apply the lessons learned to make sure they are not negatively affected on rules for other pollutants (specifically carbon dioxide emissions). Taking percentage reductions from permitted levels and establishing a solid banking system provides incentives for companies to control today and bank allowances that may carry them through the useful life span of their unit even taking into account further reductions from future rules. CAIR recognized this, which is why the EPA saw an immediate reduction in SO2 and NOx (28% reduction in ozone season emissions and 43% reduction in annual emissions) reported in the EPA Released 2009 Clean Air Interstate Rule Analysis Report. The benefits from the early results of the Clean Air Interstate Rule need to be taken into account in the IPM to determine the necessity and the extent of future emission reduction requirements. The EPA may discover, by modeling the effects of CAIR, that the proactive measures have resulted in the desired effect of bringing downstream nonattainment areas into attainment status. [EPA-HQ-OAR-2009-0491-2764.1, p.3]
Maryland Department of Environment (MDE)
State Budgets and Allocations, Trading, and Variability
Maryland has concerns over EPA's approach to setting state emissions budgets and the allocation of allowances, variability, and intrastate and other trading options. Maryland's comments are as follows. [EPA-HQ-OAR-2009-0491-2639.2, p.11]
State Budgets and Allocations
Maryland disagrees with EPA's methodology for allocating annual and ozone season NOx and annual SO2 allowances. EPA's methodology includes the use of historical emissions rates to determine the number of allowances to  allocate to a given EGU. Since emissions rates of units that are uncontrolled for NOx and SO2 are greater than those of controlled units, this methodology results in EPA awarding more allowances to dirtier units. Units that acted early to reduce their emissions, such as those controlled under Maryland's Healthy Air Act (HAA), are penalized with fewer allowances. Maryland urges EPA to redo its allocations based on heat input or output based emissions limits, rewarding the early actors and forcing dirtier units to buy allowances.  [EPA-HQ-OAR-2009-0491-2639.2, p.11]
Maryland also believes that 2009 was a low emission rate year, due to economic slowdowns and cooler than normal temperatures across the eastern seaboard. Lowered electrical demand would result in many of the dirtiest units running less or not at all. When OTC runs the numbers to compare emissions rates from EPA's modeling to the actual 2009 rates, EPA is predicting very low emission rates at the $500 per ton level, and Maryland believes that the emissions rates listed may be unattainable, especially at that cost level. [EPA-HQ-OAR-2009-0491-2639.2, p.12]
In addition, because EPA based its allocations on 2009 data, an unusually low emission rate year due to economic slowdowns and cooler than normal temperatures across the eastern seaboard, Maryland and other eastern states' EGUs may experience an unlevel playing field in the allocations they receive. [EPA-HQ-OAR-2009-0491-2639.2, p.12]
Maryland supports EPA's focus on reducing NOx and SO2 emissions from EGUs but we believe that EPA should also look into reductions from non-EGU sources as a means of controlling transported pollution. In the first of the three remedies, the "State Budgets/Limited Trading Proposed Remedy", sources would receive allocations based on state budgets alone (variability would not be included). There would be four trading groups established and banking of allowances would be permitted.
The proposed Transport Rule also allows sources to carryover allowances from one year to the next. Maryland is opposed to a large accumulation of carryover allowances and requests that EPA explicitly limit it in the rule. [EPA-HQ-OAR-2009-0491-2639.2, p.14]
Maryland has not found an explicit limit to the trading as it is outlined in the Transport Rule proposal. The only limit to trading seems to be the inherent fact that the trading is among the states in each trading category. [EPA-HQ-OAR-2009-0491-2639.2, p.15]
In allocating allowances EPA proposes to allocate any unused new source set asides proportionally to existing units. Maryland would like to see the new source set asides remain just that  -  set asides. In allocating these set-asides to existing units, newer cleaner generation is discouraged because allowances would have to be purchased from existing sources. [EPA-HQ-OAR-2009-0491-2639.2, p.15]
Michigan Municipal Electric Association (MMEA)
However, the proposed Transport Rule approach is neither justified nor workable for Michigan public power communities. EPA's proposed rule, allocation methodology and unit-specific allocations will pose particularly drastic and disproportionate impacts on Michigan public power; [EPA-HQ-OAR-2009-0491-2828.1, p.2]
1.) EPA Should Not Allocate Allowances to Specific Units Based on IPM Model Runs that Ignore Reality on the Ground in Public Power Communities
The fates of Michigan's municipal utility generators are left in the hands of a modeling tool that is unaware and unable to process the reality on the ground in Michigan public power communities, where decisions about owning, operating, or potentially closing power plants are made by real people who must take into account legal obligations to serve, costs to ratepayers, the viability of their local communities, the economic and business climate of their regions, the long-term plans for environmental stewardship, and other important factors that are simply lost in the void of IPM model runs. And while it may be proper for EPA to use IPM to establish the structure of EPA Clean Air policies, the overall parameters for emission controls, and even the establishment of state emission budgets for targeted pollutants, in the case of this Transport Rule, EPA is making actual allowance allocations to specific units in specific communities based on IPM model runs  -  and thus allowing the IPM predictions to determine the fate of these units and communities. Coupled with EPA's proposal to virtually eliminate the potential for State-based allowance allocation decisions through State Implementation Plans (SIPs) and the numerous errors that are apparent in EPA's IPM modeling with respect to specific municipal utilities, this decision to allow IPM predictions to supplant the decisions of actual managers, community board members and city councils in public power systems is unwarranted and potentially very harmful to these communities. [EPA-HQ-OAR-2009-0491-2828.1, pp.4-5]
[For additional comments pertaining to IPM, see pages 5-7 of this comment.]
2.) EPA's Allowance Allocation Methodology Ignores the Cornerstone of Compliance for Michigan Public Power Communities
Michigan public power communities have been subject to NOx emission limitations for more than a decade, under the NOx SIP Call, the Section 126 NOx rule, the Clean Air Implementation Rule and, of course, the State of Michigan's implementation of these NOx requirements. What EPA might not (but should) know is that Michigan public power systems have complied with NOx regulations through a State of Michigan approach that distributes "hardship allowances" to small EGUs that will suffer drastic, disproportionate impacts from Clean Air Act rules. The proposed EPA Transport rule ignores the Michigan hardship allowance approach in a way that could cause sudden and drastic impacts on covered Michigan communities. Thus, EPA (and the IPM) must take the Michigan hardship allowance program into account when assessing the six Michigan municipal utilities and their units affected here. [EPA-HQ-OAR-2009-0491-2828.1, p.7]
[For additional comments pertaining to EPA's Allowance Allocation Methodology, see pages 7-9 of this comment.]
1.) Correct the data errors and information regarding specific municipal units.
2.) Drop erroneous assumptions that units will install pollution controls that have never been required nor planned, and erroneous assumptions that units will close prematurely.
3.) Adopt factors in the Transport rule, including in IPM modeling runs, which account for the obligation to serve and unique roles of Michigan public power communities to keep these plants cost-effectively operating.
4.) If projections regarding these Michigan municipal units cannot be corrected as stated herein, EPA should shift its allocation model entirely away from current and predicted actions at units, and return to the tried-and-true method of allocating emissions limitations based on historical heat input utilization. [EPA-HQ-OAR-2009-0491-2828.1, p.16]
Mirant Corporation
1. The proposed allowance allocation scheme is fundamentally unfair to companies like Mirant that have made substantial investments in pollution control technology. [EPA-HQ-OAR-2009-0491-2843.1, p.1]
2. To avoid penalizing companies that install expensive control technology and to ensure that pollution control costs are shared equitably, allowances should be allocated based on heat input, as in past EPA programs. Alternatively, for EGUs located in Maryland, allowances could be based on the approach that the Maryland already adopted in the Healthy Air Act (HAA) and the accompanying regulations. [EPA-HQ-OAR-2009-0491-2843.1, p.2]
I. The Proposed Approach for Distributing Allowances is Unfair and Inconsistent with EPA's Long-standing Concerns about Penalizing Units That Have Installed Emission Controls
In the past, EPA has always emphasized the need to maintain a level playing field by distributing allowances based on heat input, rather than emissions. The Agency has specifically stated that it would be improper to distribute allowances based on historic emissions, because such an approach would penalize facilities with the best controls. Yet that is precisely what the Agency has proposed in the Transport Rule, without providing any rational justification. [EPA-HQ-OAR-2009-0491-2843.1, p.2]
It appears that EPA has simply used the same approach for distributing allowances to individual units that it has used for setting state budgets  -  using the lower of historic emissions or projected future emissions. This simply makes no sense and fails to recognize the fundamental difference between (1) setting a state-wide emission level and (2) deciding how to allocate the burden of achieving that level. [EPA-HQ-OAR-2009-0491-2843.1, p.2]
The purpose for setting a state budget is to ensure that each state will eliminate all emissions that are "significantly contributing" to nonattainment or maintenance problems in other states. To accomplish this objective, the Transport Rule requires each state to eliminate all EGU emissions that can be reduced cost effectively. This is sensible and consistent with both the NOx SIP and CAIR. [EPA-HQ-OAR-2009-0491-2843.1, p.2]
The purpose of distributing allowances is to allocate, among individual plants, the burden of meeting the state budget. Rather than giving each plant the allowances it will need to cover its expected emissions, the Agency should try to ensure that the cost of reducing state-wide emissions will be shared equitably among all the plants in the state. For example, even if EPA's modeling predicts that it will not be cost-effective to install controls on Plant A, Plant A should not be given a free ride. Like all EGUs in the state, it should bear its fair share of the costs that will be incurred for the state to meets its budget. Under a well-designed cap-and-trade program, this is accomplished largely by requiring uncontrolled units to purchase allowances from units that have incurred the cost of installing and operating expensive emission controls, and thus to help pay for those controls. This equitable sharing arrangement -  all plants cover their share of the cost of emission controls that are installed only on some plants  -  cannot be accomplished under the allocation scheme in the proposed rule. [EPA-HQ-OAR-2009-0491-2843.1, p.3]
The proposed allocation scheme also creates the wrong incentives and sends the wrong signal to the marketplace. If a company anticipates that additional emission reductions will be required in the future and that allowances under a future program will be based on emissions, it will have an incentive to keep its emissions relatively high. This has long been a problem with the new source review (NSR) program. The Acid Rain program, the NOx SIP Call, and CAIR were all designed, in part, to overcome this problem. It would be unfortunate for the Agency to perpetuate it in the Transport Rule. [EPA-HQ-OAR-2009-0491-2843.1, p.3]