EPA is finalizing a method of emissions allowance allocation to individual units under the FIP base on based on that unit's share of the state's historic heat-input, but ensuring that no unit's allocations exceed that unit's historic emissions.  EPA decided to use the allocation methodology originally presented as heat input "option 2" in the January 7, 2011 NODA, modified in response to public comments.  EPA decided to use heat input option 2 but without the application of the "reasonable upper-bound capacity utilization factor and a well-controlled emission rate" factors. See final rule preamble section VII.D for further of discussion EPA's rationale for this approach and response to comments in favor of and in opposition to this approach.

XX.A.1.b. Option 2

Organization: ARIPPA
Ameren Services Company
Duke Energy
Dominion
Cleco Corporation
AES Corporation (AES)
Constellation Energy
Exxon Mobil Corporation
National Rural Electric Cooperative Association (NRECA)
National Mining Association (NMA)
Nelson Industrial Steam Company (NISCO)
Comment:
AES Corporation (AES)
EPA should not select Option 2 as the final allocation methodology. Even though Option 2 would yield the same initial allocation pattern as Option 1 (based on historic heat input), the additional constraint (i.e., a limit on allocations) is based on a unit's "reasonably foreseeable maximum emissions" and under the proposed Transport Rule trading programs, will produce an inequitable allocation. The "reasonably foreseeable maximum emissions" are calculated with inaccurate heat input, heat rate, capacity factor and emission rates that are not achievable by some well controlled units. Allocation methods based in part or in full by modeling or projections will also result in unintended consequences. [EPA-HQ-OAR-2009-0491-4016, p. 3]
Data Issues: The EIA data often has large errors contained within the database. Facilities should have ample opportunity to correct these errors before the rule is finalized. Other data used in option 2 are not identified as to the source but also contains errors. The Heat Rate used in Option 2 is one such example. [EPA-HQ-OAR-2009-0491-4016, p. 4]
Option 2 Issues: The Step 4, Annual SO2 Rate Cap (tons), Annual NOx Rate Cap (tons), Ozone Season NOx Rate Cap (tons) and Ozone Season NOx Maximum Cap (tons) were left incomplete for many facilities. Without this data, proper evaluation cannot be completed. [EPA-HQ-OAR-2009-0491-4016, p. 4]
Additional comments
The Capacity Factors used in Option 2 are inaccurate in many cases. Shady Point, like many facilities do not take outages in the summer months and often reach Capacity Factors close to 100%. In fact there are steep penalties if the Capacity Factors falls below 95%. Other facilities like Beaver Valley and Warrior Run have similar contract situations. Errors like this should have ample opportunity to remedy. The Capacity Factors and heat rate should be based on a highest three years out of five if this option 2 (or similar option) is chosen. [EPA-HQ-OAR-2009-0491-4016, p. 4]
Ameren Services Company
On page 1115 of the Federal Register Notice Step 4a uses the reported heat input where available from the Part 75 reporting. EPA should realize that in many instances this 'maximum heat input' is based on a unit's design rating and not CEM data collected as part of Part 75. From Ameren's experience the heat input determined from the Part 75 monitoring is 5% :: 20% higher than that determined from fuel input based on amount of coal burned and analyses of the coal. The CEM heat input is based on either an EPA specified F-factor (based on fuel type) and flow or an F-factor based on coal analysis and flow. While every unit has the option to use the coal based F-factor determination it is Ameren's experience that many units use the EPA default F-factor. In Step 5 EPA is comparing the CEM emissions (generally based on CEM heat input) with most likely a manufacturer's design rating based emissions estimation. EPA should give consideration to calculating these emissions based on the same basis. Ameren suggests that EPA should use the CEM based emissions for both calculations (i.e. use the maximum CEM measured heat input). [EPA-HQ-OAR-2009-0491-3894[1].1, pp.1-2]
ARIPPA
The second allocation option presented by EPA through the Second NODA is based on historic heat input, but proposes to modify the allocations so that they do not exceed the higher of either historic actual emissions or emissions calculated using a "clean emission factor" and the reasonably expected maximum future heat input.  ARIPPA favors the objective behind this second option as a more equitable allocation approach.  However, as proposed by EPA, this second allocation option contains serious inequities.  Specifically, use of the "clean" SO2 emission factor of 0.06 lb/MMBtu is clearly inappropriate for certain sources, such as the ARIPPA facilities, that cannot achieve such emission rate through application of emission controls that are cost effective for such sources.  In the Second NODA, EPA describes the SO2 emission factor of 0.06 lb/MMBtu as "a well-controlled emission rate that all units (regardless of the type of fuel they combust) can meet for the pollutant."  This statement is unsupported in the NODA for retrofitted coal refuse-fired CFBs.  In fact, most, if not all, ARIPPA facilities cannot meet this emission rate in any "cost effective" manner.  [EPA-HQ-OAR-2009-0491-3903[1].1, p.4]
ARIPPA supports the Second NODA to the extent that it would constrain the allowance allocation methodology to prevent allocations to individual sources beyond potential emission rates based on past operating history.
In developing its second alternative allocation methodology within the Second NODA, EPA proposes a redistribution of allowances by taking into account historic emission rates for lower emitting sources.  In particular, this second alternative would allow for additional allowances to be distributed to those sources that require higher initial allocations in order to satisfy EPA's emission cap objectives.  The allowances would be secured through redistribution of allowances from sources that would otherwise receive allowance allocations that materially exceed historic emission rates. [EPA-HQ-OAR-2009-0491-3903[1].1, p.12]
ARIPPA endorses this approach for multiple reasons.  First, unlike the Proposed Transport Rule, this second alternative identified by EPA through the Second NODA would base allowance allocations on established emission rates for lower emitting sources, and not projected emission rates based upon EPA models of future operating and electricity generating rates.  Such projections are based upon assumptions that are inherently vulnerable to inaccuracies in forecasting. [EPA-HQ-OAR-2009-0491-3903[1].1, p.12]
Second, this alternative allocation method would prevent any "windfall" of allowances from being provided to sources merely because of EPA's selection of the allocation methodology.  As stated by EPA within the Proposed Transport Rule and Second NODA, EPA's approach toward this regulation should not create incentives for sources to increase emissions.  Further, by redistributing the allowances to sources that currently exceed unit-specific emission allocations, EPA would be acting consistent with its stated objective of pursuing cost effective emission control options.  [EPA-HQ-OAR-2009-0491-3903[1].1, pp.12-13]
EPA proposes through the Second NODA to constrain the allowance allocation levels for lower emitting sources to ensure that such sources do not receive substantially more allowances than historical actual emissions would support.  However, the proposed allocations identified through the second allocation method described in the Second NODA would clearly not fully implement EPA's conceptual proposal.  In addition, the Second NODA would not address another significant circumstance that would result in the allocation of allowances substantially in excess of the quantity required for sources' compliance with the Transport Rule  -  continued allocations to shutdown sources.  Consistent with EPA's statements in the Second NODA that the allocation methodology under the Proposed Transport Rule should not provide an allowance windfall to affected sources, the rule should not provide allowances to any source that has ceased operations.  Instead, the allocations for such sources should be redirected to increase the new source set-aside for the relevant state. [EPA-HQ-OAR-2009-0491-3903[1].1, p.13]
Further, EPA's proposed "clean" SO2 emission factor of 0.06 lb/MMBtu is two orders of magnitude higher than typical emission rates for the combustion of pipeline quality natural gas.  As a result, under the second allocation option in the NODA, EGUs that combust natural gas will receive windfall SO2 allowance allocations that may be two orders of magnitude more than they can physically emit (or are allowed to emit under their permits).  These allowances are therefore unavailable for allocation to those emission sources that have allowance shortfalls and no cost effective means of emission control.  [EPA-HQ-OAR-2009-0491-3903[1].1, p.13]
In summary, consistent with EPA's proposed approach, the allowance allocation methodology should not result in a "windfall" to any facility; this can be ensured by limiting the maximum allocation to any affected facility to emission levels established by that source, and by ensuring that shutdown sources will not continue to receive an allocation.  Such approach would also be consistent with the objectives of the Clean Air Act and the D.C. Circuit Court's decision in North Carolina, by ensuring that the proposed program does not result in an emissions increase for any source.  [EPA-HQ-OAR-2009-0491-3903[1].1, p.13]
Further, ARIPPA also supports EPA's position articulated through the Second NODA's second alternative allocation methodology that allocations to affected sources should be limited based on established actual emission rates, in order to avoid any substantial "windfall" of excess allowances to certain sources.  This approach is consistent with EPA's stated objective under the Proposed Transport Rule to pursue cost effective emission reductions in support of the emission goals of the regulatory program.  [EPA-HQ-OAR-2009-0491-3903[1].1, p.15]
Cleco Corporation
In recognition of this unjustified windfall, EPA has proposed to add an emission constraint in its Option 2 method. Again, if EPA uses heat input as its basis for allocations, we encourage it to use an emission constraint. However, the NODA3 Option 2 emission constraint is significantly flawed. It fails to adequately mitigate the windfall and leads in many cases to only slightly less absurd results. By way of example, even under Option 2, many natural gas units would receive allocations that exceed their record emission levels (from 2003 to 2009) by over 15,000%. [EPA-HQ-OAR-2009-0491-4007[1].1, p.4]
EPA can and should correct Option 2's deficiencies by throwing out its use of the "well-controlled- rate maximum." EPA's method for calculating this value has no basis in reality. Even for gas units this method would determine a unit's "reasonable foreseeable maximum emissions level," i.e., its allocation cap, based on a 0.06 lbs/mmBtu for both SO2 and NOx. Admittedly this is an emission rate unique to well-controlled coal. EPA's use of capacity factors does not correct this error. EPA must take a hard look at this methodology and develop a more appropriate emission constraint. EPA should avoid the "well-controlled-rate maximum" concept and use each unit's "maximum historical baseline emissions" as its allocation cap, i.e., its "reasonable foreseeable maximum emissions level."  [EPA-HQ-OAR-2009-0491-4007[1].1, p.5]
If EPA insists on retaining the "well-controlled-rate maximum" concept, it should improve that method to provide sensible, realistic results. To do so, EPA could, for example, take into consideration reasonable emission factors based on fuel and generator type, rather than use the clearly erroneous, coal-specific emission rates of 0.06 lbs/mmBtu for SO2 and NOx. [EPA-HQ-OAR-2009-0491-4007[1].1, p.5]
Constellation Energy
Option 2 in contrast, Involves assumptions about plant operations that are complicated and likely more liable to litigation challenges, as well as probably providing less liquidity in the allowance market. [EPA-HQ-OAR-2009-0491-4031, p.2]
Dominion
Under the alternative options in the NODA, facilities in Massachusetts are allocated SO2 allowances based on a 0.043 Ib/mmBtu SO2 emission rate, which is much lower than the effective emission rate in most other states, below best available control technology (BACT) limits and below the 0.06 Ib/mmBtu emission rate that has been assumed for a 'well-controlled' unit that is applied as a constraint under the NODA Alternative Option #2. The NODA states that these 'well-controlled' emission rates represent the' lowest emission rates assumed achievable when state-of-the-art pollution control technologies are installed at coal units in the IPM modeling' and 'are intended to reflect the lower bound of emission rates that suppliers are willing to guarantee when installing state-of-the-art pollution control equipment."  Allowance allocations should not be based on emission rates that are below levels that can be achieved by state-of-the-art control technology. [EPA-HQ-OAR-2009-0491-3987[1].1, pp.4-5]
Any facility like Brayton Point that has spent significant capital for environmental improvements and will be well-controlled should receive sufficient allowances to enable it to continue to operate fully both during the period of time when control equipment is being installed and after the station is fully controlled. In addition, stations that are not controlled should receive sufficient allowances to allow for a coordinated transition with all other key stakeholders, including regional transmission organizations (RTOs), station employees and affected communities. [EPA-HQ-OAR-2009-0491-3987[1].1, p.5]
Alternative Option 2
Alternative Option 2 applies the same multi-year heat-input based approach used under Alternative Option I, but then applies a modification method that reduces allocations for units that are expected to be controlled if the projected emissions based on an assumed emission rate for a 'well controlled plant' are less than either the unit's historical emissions or the allocations determined under Alternative Option 1. This method would disadvantage units that plan to invest in controls by providing them fewer allowances than under Alternative Option 1. This could result in these well-controlled units being dispatched less than uncontrolled plants. EPA should abandon this approach. [EPA-HQ-OAR-2009-0491-3987[1].1, p.6]
Duke Energy
Problems With and Remedies for Option 2
The Option 2 SO2 allocation methodology, for combustion turbines and combined cycle units, with the exception of two combustion turbine units, results in unit level SO2 allocations equal to either a unit's Initial SO2 Allocation plus reapportionment or its Annual SO2 Rate Cap . While the inclusion of the Annual SO2 Rate Cap in the Option 2 methodology reduces the total number of SO2 allowances collectively allocated to combustion turbine and combined cycle units relative to Option 1, as shown in the following table, the total allocation of SO2 allowances to combustion turbines and combined cycle units under Option 2 are still far in excess of the historic or potential SO2 emissions from these groups of units and are not appropriate. [EPA-HQ-OAR-2009-0491-3965[1].1, p.6]
As discussed above with respect to Option 1, one way to fix this problem is to exclude these low emitting units from the Transport Rule for SO2. A second option, if EPA does not choose to do this, is to modify the Option 2 SO2 allocation methodology so low emitting units do not receive as large an allocation windfall at the expense of coal units.  [EPA-HQ-OAR-2009-0491-3965[1].1, p.7]
As noted above, the Option 2 methodology includes what EPA terms an Annual SO2 Rate Cap, and this has the effect of slightly reducing the size of the SO2 allocation to combustion turbine and combined cycle units. EPA refers to the Annual SO2 Rate Cap as a "reasonably foreseeable maximum emissions level." EPA states in NODA 3 that it believes the Option 2 approach, which incorporates the Annual SO2 Rate Cap, results in a reasonable initial allocation of allowances that is consistent with the goals of CAA section 110(a)(2)(D)(i)(I). While just about any allocation methodology could be described as being consistent with the goals of the CAA, not any allocation methodology can be described as reasonable. For SO2, the Option 2 allocation methodology is not reasonable. [EPA-HQ-OAR-2009-0491-3965[1].1, pp.7-8]
The Annual SO2 Rate Cap calculation that is included in Option 2 uses an assumed SO2 emission rate of 0.06 lbs/mmBtu. This SO2 emission rate is several orders of magnitude greater than the SO2 emission rate for units burning natural gas and more than an order of magnitude greater that the SO2 emission rate for units burning fuel oil. Therefore, it is puzzling why EPA would use such a high emission rate for these units and also state that its use produces reasonable allocations. The use of this extremely high emission rate produces SO2 allocations that are far in excess of the SO2 emissions combustion turbines and combined cycle units could possibly produce. If EPA is taking the approach of using a single emission rate for all sources in response to the D.C. Circuit's decision in the Clean Air Interstate Rule NOx fuel adjustment factor litigation, EPA is misapplying that decision. The decision requires EPA to use a consistent allocation methodology but it does not require EPA to use a methodology that produces the absurd allocations Option 2 produces for SO2. By choosing such a high emission rate for gas- and oil-fired units, EPA is essentially saying that these units do not need to make emission reductions under the TR. [EPA-HQ-OAR-2009-0491-3965[1].1, p.8]
While Duke Energy favors the remedy that removes combustion turbine and combined cycle units from the Transport Rule, an alternative remedy to fix the Option 2 SO2 allocation problem is to eliminate the Annual SO2 Rate Cap test and allocate SO2 allowances to all units based on the lower of a unit's Initial 2012 and 2014 historic heat input based SO2 Allocation plus reapportionment and its Annual SO2 Historical Cap (Column AA in the Option 2 underlying data tab of EPA's altallocationtablesdata.xls file. Applying this consistent methodology across all units will not run afoul of the D.C. Circuit's NOx fuel adjustment factor decision and will result in more rational SO2 allocations that will still more than cover the projected emissions from these units. [EPA-HQ-OAR-2009-0491-3965[1].1, p.9]
With regard to annual and ozone season NOx allocations, Option 2 would over allocate NOx allowances to combustion turbine and combined cycle units, although to a lesser degree than it would over allocate SO2 allowances to these units. The remedy for Option 2 for annual and ozone season NOx is the same as for SO2; eliminate the Annual NOx Rate Cap test and allocate NOx allowances to all units based on the lower of a unit's historic heat input based 2012 Initial NOx Allocation plus reapportionment, and Annual NOx Historical Cap.[EPA-HQ-OAR-2009-0491-3965[1].1, p.9]
Duke Energy recommends EPA adopt the Option 2 allocation approach for SO2 and NOx with the following adjustments. For the reasons stated above, EPA should exclude combustion turbine and combined cycle units from the SO2 portion of the Transport Rule before applying the Option 2 methodology to the remaining units. With combustion turbine and combined cycle units removed from the Transport Rule SO2 program, Duke Energy feels that Option 2 produces a more appropriate SO2 allocation to the remaining units than Option 1 with or without the combustion turbine and combined cycle units included in the program. If EPA chooses not to exclude combustion turbine and combined cycle units from the Transport Rule SO2 program, Duke Energy recommends that EPA adopt the Option 2 approach for SO2, but as discussed above, eliminate the Annual SO2 Rate Cap test and allocate SO2 allowances to all units based on the lower of a unit's heat input based 2012 and 2014 Initial SO2 Allocation plus reapportionment and its Annual SO2 Historical Cap. [EPA-HQ-OAR-2009-0491-3965[1].1, pp.9-10]
For NOx, Duke Energy recommends that EPA modify the Option 2 methodology by eliminating the Annual NOx Rate Cap test and allocate NOx allowances to all units based on the lower of a unit's historic heat input based 2012 Initial NOx Allocation plus reapportionment and its Annual NOx Historical Cap. [EPA-HQ-OAR-2009-0491-3965[1].1, p.10]
If EPA decides not to adopt these recommendations, Duke Energy recommends EPA adopt Option 2 because it results in slightly more reasonable SO2 and NOx allocations for low emitting units than Option 1. Despite its flaws, however, Option 2, because it relies on historic heat input, is a better approach that the allocation approach EPA used to develop the PTR. [EPA-HQ-OAR-2009-0491-3965[1].1, p.10]
Exxon Mobil Corporation
5. Allocation Method Option 2 - Option 2 starts with Option 1 allocations, and then modifies the allowances by applying a Capacity Factor and historical emissions to change the Option 1 allocations. We support Option 2 compared to the CATR proposal method for similar reasons to those outlined above for Option 1 but note that it disadvantages facilities that we analyzed that have lower emissions per unit of heat input. It is not our preferred option of the two in this proposal. Though Option 2 also remedies a major problem with the CATR proposal allocation method that we attributed to the use of modeling projections and assumptions about future operations and emissions, the introduction of the use of historic emissions for example units we analyzed suggest Option 2 disadvantages lower emitting units compared to Option 1. [EPA-HQ-OAR-2009-0491-3999[1].1, p.2]
6. Option 2 improvement suggestion-We suggest that as EPA continues to improve allocation methods for this rule or Clean Air Transport Rule-2 for the new Ozone NAAQS. We request EPA develop a separate capacity factor class for Cogeneration facilities supplying steam and power to industrial clients. We believe that a specific Cogeneration facility technology type in the capacity factor analysis will result in a higher capacity factor for these units more aligned with their actual operation. [EPA-HQ-OAR-2009-0491-3999[1].1, p.2]
Comment on Option 2
We note a preference for Option 1. We support Option 2 compared to the CATR proposal method for similar reasons to those outlined above for Option 1 but note that it disadvantages facilities that we analyzed that have lower emissions per unit of heat input. Though Option 2 also remedies a major problem with the CATR proposal allocation method that we attributed to the use of modeling projections and assumptions about future operations and emissions, the introduction of the use of historic emissions we believe disadvantages lower emitting units compared to Option 1. [EPA-HQ-OAR-2009-0491-3999[1].1, p.6]
Differentiating Cogen from Combined Cycle units
We recommend EPA clearly differentiate between combined cycle and cogeneration plants with respect to capacity factor. Combined cycle units are used by utility and merchant generators to produce electricity only; all steam is condensed to make more electricity with the significant remaining heat absorbed (wasted) by cooling towers. Cogeneration units produce large volumes of electricity and steam continuously because the host plant needs both 24 hours every day. The only downtime is for maintenance, so a reasonable capacity factor would be 95% both annually and for the ozone season. Cogen units occasionally have a year when a generator is undergoing a major overhaul, so in that year the capacity factor will be less than 95%. [EPA-HQ-OAR-2009-0491-3999[1].1, p.7]
Comment
We suggest EPA provide an option for Cogen units to provide historic use data in a request to have a higher than default (0.70) capacity factor to address this issue. [EPA-HQ-OAR-2009-0491-3999[1].1, p.7]
Option 2 is an emissions adjusted methodology that uses the same initial allocation pattern as Option 1 but then adds a constraint based upon a unit's 'reasonably foreseeable' maximum emissions under proposed CATR trading programs. Once a unit's initial Option 1 allowance has been determined, then EPA has to determine the maximum sulfur dioxide (SO2) and nitrogen oxide (NOx) annual emission from the 2003-2009 period and the maximum annual ozone season emissions for NOx from the ozone season of that same time period. If a unit's allocation under Option 1 exceeds the maximum annual SO2 or NOx rate, or the maximum ozone season rate, then an adjustment would be made downwards to the higher of the maximum annual emissions rate in this period or to an adjusted rate. This adjustment rate would assume an emission rate of 0.06 lbs/mmBtu for SO2 and for NOx . Further, the adjustment would include a '.reasonable upper bound capacity factor.' Simply stated, this Option 2 allocation methodology is overly burdensome and is based on inadequate capacity factors. [EPA-HQ-OAR-2009-0491-4028, p.4]
Comment 4: If EPA does decide to implement Option 2, it should revise the capacity factor (utilization factor) for combined cycle units that is used as an adjustment factor under the calculations for this option. For combined cycle cogeneration units Option 2 proposes to use only a 70% capacity factor for annual and 73% for ozone season calculations . Although EPA stated that this value was based upon data reported to EPA by source owners, EM questions such assertion. [EPA-HQ-OAR-2009-0491-4028, p.4]
It is difficult to determine whether EPA is equating the terms utilization factor and capacity factor. For a reasonable upper-bound estimate, EPA should be looking at a reasonable utilization factor - in other words, on-stream time. It appears that this is what EPA is trying to determine as the Preamble discussion in the 2011 NODA states: 'These upper-bounds would be calculated as the utilization values at the 95th percentile in each technology class.' (Emphasis added.) [EPA-HQ-OAR-2009-0491-4028, p.4]
The cogeneration units owned and/or operated by or on behalf of ExxonMobil, produce large volumes of electricity and steam continuously because the host plant (EM's refinery and chemical manufacturing -units) needs both 24 hours every day. These units occasionally have a year when a generator is undergoing a major overhaul; however, this generally does not happen on an annual basis. [EPA-HQ-OAR-2009-0491-4028, p.4]
Two of the Louisiana Station 1 generating units are combined cycle units. The utilization rates for both of these for the past 6 years are shown below: [EPA-HQ-OAR-2009-0491-4028, p.4]
[Table can be found on page 5 of comment letter 4028.]
EM requests that EPA revise the upper bound capacity factors for combined cycle units to be 98.5% annual and for the ozone season. [EPA-HQ-OAR-2009-0491-4028, p.5]
These combined cycle cogeneration units are fuel efficient - and therefore produce less emissions - than most other RGUs . The gas turbine generator makes electricity directly, then supplemental fuel is added to its very hot exhaust to make even more high pressure steam. The attached Heat Recovery Steam Generator / boiler may have a second, lower pressure steam generating section, and certainly will have a boiler feed water preheat section, both of which capture even more of the heat versus letting it go out the stack. In addition, the high pressure steam is used to run big turbines in place of motors or to spin a steam turbine generator to make more electricity and lower pressure steam. The lower pressure steam then goes to the host plant where it is used for multiple purposes, and often exhausts as low pressure steam / heat that is used elsewhere. In short, little if any energy is wasted. These units are distinguishable from utility combined cycle units which use steam only to produce electricity and waste much of the steam. [EPA-HQ-OAR-2009-0491-4028, p.5]
National Mining Association (NMA)
NMA appreciates that Option 2 is designed to limit the windfall. But as discussed below, even under Option 2, natural gas units nevertheless receive an extremely large windfall from coal-fired units for reasons that are not based on the underlying statute. [EPA-HQ-OAR-2009-0491-4013[1].1, p.1]
Nevertheless, while reserving the right to challenge whatever rule EPA adopts, if EPA is determined to adopt a heat-input methodology, NMA urges EPA to adopt Option 2. [EPA-HQ-OAR-2009-0491-4013[1].1, p.2]
C. Under Option 2, Coal-Fired Generation Bears the Full Brunt of Any Reductions in the State Budgets.
Because the public at this point does not know what the state budgets will be, it is at least possible  -  and seems likely  -  that some or many of the state budgets will be lower than those that were published with the proposed rule. If EPA uses the Option 2 method, all or substantially all of the state budget reduction will come from coal units. Natural gas unit allocations are essentially capped at the "reasonable foreseeable maximum emissions level." 3 Thus, they would be immune from reductions in the state budget to a certain point. Coal units on the other hand  -  particularly uncontrolled coal units  -  would bear the full brunt of the reduction because those allowances representing the reduction between the proposed state budget and the actual final state budget would not be available in the reapportioning step of the Option 2 method. Thus, coal alone bears the full brunt of any reductions in state budgets from proposed rule to final rule. [EPA-HQ-OAR-2009-0491-4013[1].1, p.7]
As shown above, even under Option 2  -  EPA's attempt to mitigate the windfall  -  many units are severely over-allocated allowances. [EPA-HQ-OAR-2009-0491-4013[1].1, p.7]
There are numerous other similar examples. An allocation method that results in over-allocations of this magnitude is frankly absurd. [EPA-HQ-OAR-2009-0491-4013[1].1, p.7]
In determining a given unit's "reasonable foreseeable maximum emissions level" EPA calculates, among other things, a "maximum historical baseline emissions" value for each covered unit under the rule. The maximum historical baseline emissions value is simply the single highest annual (or ozone season, depending on the program) reported emissions for a seven-year period from 2003 to 2009 for each unit. Put simply, the maximum historical baseline emissions value represents each unit's seven-year record high emissions. EPA recorded these record-high emissions values for each unit in its NODA-3 Database. [EPA-HQ-OAR-2009-0491-4013[1].2, p.10]

3 There are significant flaws in EPA's method for determining a unit's "reasonable foreseeable maximum emission level." To note just one flaw, EPA uses an emission rate specific to coal to calculate reasonable foreseeable maximum emissions for all units  -  including gas units, which in reality have emission rates for SO2 that are orders of magnitude lower than emission rates for coal units. [EPA-HQ-OAR-2009-0491-4013[1].1, p.7]

National Rural Electric Cooperative Association (NRECA)
NODA III option 2 attempts to somewhat correct the fallacies in option 1, but the end result is likewise unreasonably gas bias.  Option 2 attempts to avoid an unconscionable over allocation of allowances to gas units by incorporating a "reasonably foreseeable maximum emissions level reflecting a reasonable upper-bound capacity utilization factor and well controlled emission rate that all units (regardless of the type of fuel they combust) can meet for the pollutant." The fundamental problem with option 2 is the incorporation of a one-size-fits-all approach for the "well controlled emission rate" factor used to determine the "reasonably foreseeable maximum emissions level."  Since gas has inherently lower sulfur and nitrogen content than coal, as previously mentioned, this one-size approach, as applied in the option 2 allocation methodology, functions poorly in so far as more reasonably allocating allowances.   NRECA is under the impression that option 2 was constructed to be fair and equitable, while meeting the North Carolina requirements. NRECA believes EPA must recognize the obvious flaws in option 2.  [EPA-HQ-OAR-2009-0491-3943[1].2, pp.5-6]
The proposed NODA III option 2 "well controlled emission rate" of .06 lbs/mmbtu for both NOx and SO2 is a significant component in determining EPA's proposed "reasonably foreseeable maximum emissions level.  Use of this emissions standard as EPA admits is a one-size-fits-all emissions rate metric.  An analysis of the data, as follows, show that this "well controlled emission" standard functions poorly to effectively limit allowances to combined cycle and turbine units to a "reasonable initial distribution" as EPA maintains option 2 achieves in the NODA III. [EPA-HQ-OAR-2009-0491-3943[1].2, p.7]
Lastly, EPA maintains that "well controlled emissions rate" is one that "all units (regardless of the type fuel they combust) can meet."  Again, an analysis of the EPA's database in the docket of this rulemaking as follows show that "well controlled emissions rates" have little applicability to coal-fueled units within the CATR region: [EPA-HQ-OAR-2009-0491-3943[1].2, pp.7-8]
Thus, the EPA proposed one-size NOx and SO2 "well controlled emissions" standard as applied to coal-fueled units is a standard that less that .8% of the coal-fueled units in the CATR region can meet.   EPA has presented no information or analysis in connection with this rulemaking that show that any of the remaining 1050 units could meet the  proposed "well controlled emission rate" standard and if so, when.  Additionally as the attached summary of EPA data contained the CATR rulemaking docket shows, no coal unit currently meeting the "well controlled standard for SO2" is burning other than low sulfur coal.  [EPA-HQ-OAR-2009-0491-3943[1].2, p.8]
In summary, EPA's choice of a one-size-fits-all "well controlled emissions rate" standard does not function to meet EPA's stated objective in proposing NODA III option 2, which is to institute an approach to result in "reasonable initial distribution" of allowances consistent with CAA Section 110. [EPA-HQ-OAR-2009-0491-3943[1].2, p.8]
EPA's proposed "well controlled emission rates" for coal units under option 2, in some cases, is better than what a BACT analysis would conclude. On the other hand, the proposed "well controlled emission rate" is one that every combined cycle unit in the CATR can achieve. In summary, as shown in these comments, information from EPA's own database as part of the CATR rulemaking docket demonstrates the one-size-fits-all approach does not produce sensible allowance allocations.  [EPA-HQ-OAR-2009-0491-3943[1].2, p.9]
Nelson Industrial Steam Company (NISCO)
Of the two alternative allocation methodologies proposed in the 2011 NODA, NISCO supports the use of the second methodology, referred to as the Emissions-Rate-Informed Historic Heat Input Approach or Option 2, over the first methodology, referred to as the Historic Heat Input Approach or Option 1. NISCO believes that Option 2 is a more equitable method that is based on more realistic factors that will prevent some sources from receiving unwarranted windfall allocations. [EPA-HQ-OAR-2009-0491-4026, p.4]
If EPA decides to implement Option 2 proposed in this NODA, NISCO believes that the capacity factor component of the methodology utilized by EPA for the NISCO units is too low. EPA used a capacity factor of 87% annual, 89% ozone season. for the two NISCO units. The NISCO units have higher capacity factors because they exist solely to support three industrial facilities that are dependent upon NISCO for their steam and electrical needs. Actual data reflects that the highest annual capacity factor for NISCO in the 2003-2009 period was 92%. The highest ozone season capacity factor for NISCO during that time period was 93%. NISCO requests that EPA revise its capacity factor values to more accurately reflect the actual operations of these units. [EPA-HQ-OAR-2009-0491-4026, p.6]
Response:
EPA is finalizing a method of emissions allowance allocation to individual units under the FIP base on based on that unit's share of the state's historic heat-input, but ensuring that no unit's allocations exceed that unit's historic emissions.  EPA decided to use the allocation methodology originally presented as heat input "option 2" in the January 7, 2011 NODA, modified in response to public comments.  EPA decided to use heat input option 2 but without the application of the "reasonable upper-bound capacity utilization factor and a well-controlled emission rate" factors. See final rule preamble section VII.D for further of discussion EPA's rationale for this approach and response to comments in favor of and in opposition to this approach.
Organization: Southern Company
Clean Energy Group
State of Ohio Environmental Protection Agency (Ohio EPA)
Mississippi Department of Environmental Quality
PPG Industries, Inc.
City of Tallahasse
Lafayette Utilities System
Santee Cooper
Nebraska Public Power District
Connecticut Department of Environmental Protection
Southern IL Power Cooperative
Buckeye Power, Inc.
Exelon
First Energy
Virginia Independent Power Producers
Gainesville Regional Utilities (GRU)
Tennessee Valley Authority (TVA)
Florida Municipal Power Agency, Gainesville Regional Utilities, JEA, Orlando Utilities Commission, and City of Tallahassee
Sunbury Generation LP
Otter Tail Power Company
Oglethorpe Power
Great River Energy
Gulf Coast Lignite Coalition
NextEra Energy, Inc.
Associated Electric Cooperative, Inc. (AECI)
Entergy Services, Inc.
Tampa Electric Company
City of Dover, Delaware
Empire District Electric Company (Empire District)
City of Springfield, Illinois, Office of Public Utilities
DTE Energy
PSEG Services Corporation
Birchwood Power Partners, L.P.
Massachusetts Department of Environmental Protection
Texas Commission on Environmental Quality
Wolverine Power Supply Cooperative
Louisiana Chemical Association (LCA)
San Miguel Electric Cooperative, Inc.
America's Natural Gas Alliance
North Carolina Electric Membership Corporation
Horsehead Corporation
PowerSouth Energy Cooperative
Northshore Mining Company
Cogen Technologies Linden Venture, LP
Old Dominion Electric Cooperative
NRG Energy
Independence Power & Light (IPL)
Dayton Power and Light Company (DP&L)
American Petroleum Institute (API)
Northern Indiana Public Service Company (NIPSCO)
Seminole Electric Cooperative Inc.
GenOn Energy, Inc.
Consumers Energy
National Grid
PPL Corporation
Tenaska, Inc.
Comment:
America's Natural Gas Alliance
Both the originally proposed emission-based methodology and the Option II methodology could result in allocations that are reduced, in effect penalizing those companies that have taken or that are scheduled to implement projects to reduce emissions of the regulated pollutants, whether by fuel switching, installation of controls, or otherwise. ANGA submits that such 'penalties' run counter to the broader goals of the CAA, as well as the specific goals regarding transport of air pollutants to downwind areas. [EPA-HQ-OAR-2009-0491-3939[1].1, p.3] [[This comment can also be found in Section XX.]]
American Petroleum Institute (API)
B. API does not support this option, although, notes Option 2 is still better than the base CATR proposal of August 20, 2010. [EPA-HQ-OAR-2009-0491-3982[1].1, p.2]
Option 2 "Emissions Informed" or "Emissions Adjusted" Heat Input Methodology - starts with Option 1 allocations and adds a limit on allocations based on a unit's reasonably foreseeable maximum emissions under the proposed Transport Rule trading programs. API does not support this option, although notes Option 2 is still better than the base CATR as outlined in the August 2, 2010 proposal. [EPA-HQ-OAR-2009-0491-3982[1].1, p.3]
For those units with heat input-based allocations that would exceed historic emissions, this option would limit allocations so that the units would not be given allowances in excess of their reasonably foreseeable maximum emissions. [EPA-HQ-OAR-2009-0491-3982[1].1, p.3]
EPA's attempt to use 'reasonable foreseeable maximum emissions' is admirable but deficient in the proposed Option 2. Allocation to low-emitting units by using a general calculation based on historical emissions would have to be improved by working with owner/operators to better estimate 'reasonably foreseeable maximum emissions' which are dependent on many factors beyond historical emissions. Historical emissions for many units in the time period of interest are NOT reflective of 'reasonably foreseeable maximum emissions'. Note that this is a reason to support allowing States to develop allocation methods which can better address this principle. [EPA-HQ-OAR-2009-0491-3982[1].1, pp.3-4]
Though Option 2 remedies a major problem with the CATR proposal allocation method that we attributed to the use of modeling projections and assumptions about future operations and emissions, the introduction of the use of historic emissions we believe disadvantages lower emitting units. [EPA-HQ-OAR-2009-0491-3982[1].1, p.4]
API does not support Option 2, although we note Option 2 is still better than the base CATR proposal of August 20, 2010. [EPA-HQ-OAR-2009-0491-3982[1].1, p.5]
Associated Electric Cooperative, Inc. (AECI)
NODA III option 2 attempts to somewhat correct the shortcomings of option 1, but the end result is likewise biased too much toward gas.  Option 2 attempts to avoid the over allocation of allowances to gas units by incorporating a "reasonably foreseeable maximum emissions level reflecting a reasonable upper-bound capacity utilization factor and well controlled emission rate that all units (regardless of the type of fuel they combust) can meet for the pollutant."  The fundamental problem with option 2 is the incorporation of a one size fits all for the "well controlled emission rate" factor used to determine the "reasonably foreseeable maximum emissions level."  Since gas has inherently lower sulfur and nitrogen content than coal, this one size approach as applied in the option 2 allocation methodology functions poorly in so far as more reasonably allocating allowances. [EPA-HQ-OAR-2009-0491-3989[1].1, p.4]
Further, EPA's choice of a one size fits all "well controlled emissions rate" standard does not function to meet EPA's stated objective in proposing NODA III option 2, which is to institute an approach to result in "reasonable initial distribution" of allowances consistent with CAA Section 110. [EPA-HQ-OAR-2009-0491-3989[1].1, p.4]
Birchwood Power Partners, L.P.
Birchwood Power can support the goal of Option 2 - of 'limit[ing] historic-heat-input-based allocations' to the 'reasonably foreseeable maximum emissions', which is calculated by taking the higher of 'maximum historic baseline emissions' or a 'well-controlled-rate maximum'. 76 Fed. Reg. at 1115. A heat input-based approach would generally favor cleaner units, which Birchwood Power agrees is consistent with goals of CAA Section 110(a)(2)(D)(i)(1). See 76 Fed. Reg. at 1114.  By limiting cleaner units' allocation to their reasonably foreseeable maximum emissions, EPA would make more allowances available to those units that may face greater burdens under a heat input-based approach. Birchwood Power believes this is fair and would alleviate the challenges that higher emitting units will face under such an approach. [EPA-HQ-OAR-2009-0491-3940[1].1, p.3]
Moreover, the Option 2 assumptions may fail to account for the specific contractual obligations of long-term contract generators, like Birchwood Power, who must operate whenever dispatched by the power purchaser without the ability to pass along the costs of the NOx and S02 allowances to the off taker under a long term contract. [EPA-HQ-OAR-2009-0491-3940[1].1, p.3]
Buckeye Power, Inc.
While Option 2 is preferable to EPA's initially proposed historic emissions-based allocation, it is flawed in several important respects. [EPA-HQ-OAR-2009-0491-3900[1].1, p.4]
First, the calculation of the 'constraint,' or limit, on a unit's allocation based on its 'reasonably foreseeable maximum emissions' is far less clear and easy to follow than Option 1, and it employs certain factors and uniform inputs that are unreasonable and inappropriate for many units, such as the Buckeye's. For instance, one component of the allocation's constraint is the calculation of a unit's 'well controlled rate maximum.' EPA uses a 'well controlled emissions rate' of 0.06 lbs/mmbtu for S02 and NOx, representing, according to EPA, the 'lowest annual emission rates assumed achievable when state-of-the-art pollution control technologies are installed at coal units in the IPM modeling.' However, application of EPA's 'well controlled emission rate' over-allocates allowances to natural gas-fired units and under-allocates allowances to coal-fired units. For example, Buckeye, which indeed employs state-of-the-art emissions controls, would be required to operate its coal-fired units at 99% control efficiency in order to meet its unit limits under Option 2. That is unfair, unreasonable, and, bottom line, infeasible. This is not a challenge unique to Buckeye. Of the more than 1,050 coal units identified in EPA's CEMS database for the CATR states that will be required to control S02 and NOx emissions, it appears that only 8 meet the 'well controlled emissions rate' for both S02 and NOx. Just 45 coal units meet the NOx 'well controlled emissions rate,' and only 27 coal units meet the S02 ''well controlled emissions rate' (and all of those units utilize low sulfur coal). Among other shortcomings, EPA's 'one rate fits all' approach clearly penalizes Midwest users of locally produced, higher sulfur coal. [EPA-HQ-OAR-2009-0491-3900[1].1, p.4]
It is also clear that EPA's ''well controlled emissions rate' over-allocates allowances to natural gas-fired units. Not one combined cycle gas unit has emissions in excess of S02 ''well controlled emissions rate' and less than 8% of combustion turbines have S02 emissions in excess of such rate. Even though the vast majority of combined cycle units are not equipped with selective catalytic reduction technology, only 20% of combined gas units have emissions in excess of the NOx 'well controlled emissions rate.' Despite constraints based on 'reasonably foreseeable maximum emissions' under Option 2, combined cycle and combustion turbine units receive significantly more allowances than their combined emissions. For example, although combined cycle and combustion turbine units emit only approximately 5.52% of the total CATR tons of Seasonal NOx, 2.98% of the total CATR tons of Particulate NOx and 0.5% of total CATR tons of Particulate S02, such units receive approximately 16% of the Seasonal NOx allowances, 10% of Particulate NOx allowances, and 5% of the Particulate S02 allowances in 2012 and 7% of such allowances in 2014. [EPA-HQ-OAR-2009-0491-3900[1].1, p.4]
Option 2 also makes and applies assumptions regarding units' utilization values - 95th percentile for each technology class, based on a series of capacity factors. Buckeye respectfully suggests that Option 2 is unnecessarily complex and, with each assumption that is utilized, its allocation drifts dangerously from the reality of electric generation economics. [EPA-HQ-OAR-2009-0491-3900[1].1, p.4]
City of Dover, Delaware
Further, the City believes that the second option of the Alternative Proposed Allocation Methodologies will result in the most equitable distribution of allowances. The City agrees with the logic of Option 2, that would act to limit instances where units receive substantially more allowances than they have ever needed in the past. By restraining allocations using the Reasonably Foreseeable Maximum Emission Methodology, and taking into account a 7 year emission profile, EPA will increase the likelihood that allowances are allocated to the appropriate units. [EPA-HQ-OAR-2009-0491-3881[1].1, p.1]
City of Springfield, Illinois, Office of Public Utilities
Given CWLP's support for the Heat Input allowance allocation methodology described in the NODA, it is clear that Option 2 is an inferior method to that described in Option 1. CWLP believes that the Emissions-Rate-Informed cap on allowance distribution would unfairly penalize utilities that consciously chose to reduce emissions before and during the previous decade with the installation of capital-intensive pollution control projects. In our case, CWLP chose to invest in control technologies for the removal of both SO2 and NOx at two aging, coal-fired, cyclone units that were not inherently low-emitting in either boiler design or fuel-type. CWLP believes that our proactive efforts would be penalized in the use of Option 2 over Option 1. [EPA-HQ-OAR-2009-0491-3885[1].1, p.2]
City of Tallahasse
While both options presented in the January NODA are preferable to EPA's original allocation proposal, the City believes that Option #2 represents a more equitable proposal, yet both options could be further refined. [EPA-HQ-OAR-2009-0491-3912[1].1, p.3]
Clean Energy Group
We are concerned that Option 2 introduces too many potential adjustment factors to be cleanly implemented without legal challenge in the short time EPA has to finalize the rule. [EPA-HQ-OAR-2009-0491-4002[1].1, p.1]
Cogen Technologies Linden Venture, LP
Linden Cogen can support the goal of Option 2, in which allocations would be limited to units' reasonably foreseeable maximum emissions level, since this would make more allowances available for higher emitting units that will face greater burdens covering their emissions under a heat input-based approach. [EPA-HQ-OAR-2009-0491-3938[1].1, p.3]
As between Option 1 and Option 2, Linden Cogen supports the goal of Option 2 - of 'limit[ing] historic-heat-input-based allocations' to the 'reasonably foreseeable maximum emissions', which is calculated by taking the higher of 'maximum historic baseline emissions' or a 'well-controlled- rate maximum'. 76 Fed. Reg. at 1115. A heat input-based approach would generally favor cleaner units, which Linden Cogen agrees is consistent with goals of CAA Section 1I0(a)(2)(D)(i)(l). See 76 Fed. Reg. at 1114. By limiting cleaner units' allocation to their reasonably foreseeable maximum emissions, EPA would make more allowances available to those units which will bear a greater burden under a heat input-based approach. Linden Cogen believes this is fair and would help alleviate the challenges that higher emitting units will face under such an approach.[EPA-HQ-OAR-2009-0491-3938[1].1, p.6]
While Linden Cogen believes the capacity factors established for combined cycle facilities - 0.70 and 0.73 for annual and ozone-season heat inputs, respectively under Option 2 - are reasonably representative of its operations, use of such capacity factors could fail to account for specific contractual requirements, particularly for cogeneration facilities, which must supply steam on a continuous basis for ongoing industrial operations. [EPA-HQ-OAR-2009-0491-3938[1].1, p.6]
Connecticut Department of Environmental Protection
CTDEP does not agree that Option 2 of the alternative heat input allocation methodologies is clear and easy to understand. Option 2 is cumbersome and does not necessarily result in significant differences in allocations compared with Option 1, at least in Connecticut. [EPA-HQ-OAR-2009-0491-3884[1]., p.1]
Consumers Energy
When comparing the allocations contained in the Proposed Transport Rule to the Option 1 and Option 2 allocations outlined in NODA 3, the preference of Consumers Energy would be Option 2. As always, that preference is subject to the details for the allocation scheme contained in the final Transport Rule. A key concern lies with how frequently EPA will change the size of the total allowance pool, with the ensuing reallocation of available allowances. [EPA-HQ-OAR-2009-0491-4008[1].1, p.4]
Dayton Power and Light Company (DP&L)
D. Alternative Allocation Methodologies - Option 2 - Emissions-Rate-Informed Historic Heat Input Approach
This methodology, like the first, places historic heat input at the center of the allocation methodology. DP&L supports that aspect of this method. DP&L further notes that this method contains within it a mechanism to make the kind of adjustments DP&L recommended above to distribute more SO2 allowances to units that combust fuels that contain sulfur and fewer allowances to units that combust fuels containing no sulfur. [EPA-HQ-OAR-2009-0491-3973[1].1, p.3]
However, DP&L is concerned that there is a degree of arbitrariness, future uncertainty, and complexity inherent in establishing allocations based on a so-called 'rate-informed' standard. On a long-term basis, this approach could be used to ratchet down the allowances provided to the best-performing units. In other words, 'rate-informed' may someday mean 'your SCR and FGD have performed well, and now you will receive fewer allowances.' [EPA-HQ-OAR-2009-0491-3973[1].1, p.3]
The potentially arbitrary nature of the term 'rate informed' is demonstrated by the definition in the proposed regulation that ''well-controlled'' means 0.06 lbs/mmBtu of NOx and 0.06 lbs/mmBtu for SO2. As a utility that has installed state-of-the-art FGDs on its major units within the last five years, DP&L submits that these values do not appropriately define ''well-controlled' for coal units. A value of 0.10 lbs/mmBtu may be a better representation of well-controlled. Subjective definitions of this nature may suggest that this approach is not easily feasible for implementation. [EPA-HQ-OAR-2009-0491-3973[1].1, p.3]
:: A new definition of well-controlled' SO2 and NOx emitters may not be appropriate. [EPA-HQ-OAR-2009-0491-3973[1].1, p.4]
DTE Energy
Of the two historical heat-input based options proposed by EPA, Option 2, with the consideration of historic emissions to allocations, would provide a more accurate distribution of required allocations. [EPA-HQ-OAR-2009-0491-3932[1].1, p.2]
Empire District Electric Company (Empire District)
d) The formulas used in option 2 appear to exceed BACT and emulate MACT. [EPA-HQ-OAR-2009-0491-3883[1].1, p.2]
Entergy Services, Inc.
We are concerned that Option 2 introduces too many potential adjustment factors to be cleanly implemented without legal challenge in the short time EPA has to finalize the rule. [EPA-HQ-OAR-2009-0491-3986[1].1, p.2]
Exelon
For this reason, among others, Exelon prefers EPA's Option 1, because Option 2 reintroduces the possibility of error by basing the allocation, in part, on modeling (e.g., assumed capacity factors by technology class) rather than a purely historic metric. [EPA-HQ-OAR-2009-0491-3919[1].1, p.4]
First Energy
Specific to Option 2, FirstEnergy favors the allocation method based on the established "Reasonable Foreseeable Maximum." Though a unit should not be awarded allocated allowances above their annual 7-year maximum and thereby be rewarded with allowances that would arguably allow it to exceed historical emission levels. Allocating allowances above historical levels may lead to increased localized emissions that could impact the local ambient maintenance limits. Minimizing localized impacts of all sectors, not just utilities, should remain a priority throughout this rulemaking. [EPA-HQ-OAR-2009-0491-3904[1].1, p.2]
Florida Municipal Power Agency, Gainesville Regional Utilities, JEA, Orlando Utilities Commission, and City of Tallahassee
While both Options #1 and #2 are superior to EPA's original allocation proposal, we believe that Option #2 represents better public policy and can be more easily defended by EPA. [EPA-HQ-OAR-2009-0491-3907[1].1, p.1]
Option #2 attempts to address both of these issues. First by using a multi-year look back for the "maximum actual" emission test; Option #2 does not disadvantage utilities that have spent significant resources to meet CAIR requirements since emissions levels prior to adding controls are considered in the allocation process. In addition, the "well controlled unit" test mitigates in large part the over allocation issue with gas-fired units, while still allowing sufficient allocations to dual fuel capable gas-fired units which must occasionally fire oil. Nearly all Florida gas-fired combined cycle units and many gas-fired steam units are dual fuel capable. [EPA-HQ-OAR-2009-0491-3907[1].1, pp.1-2]
Overall, Option 2 is the most favorable and defensible option because it strikes a reasonable balance between providing sufficient allowances to "well controlled units" (including those units that undertook early reductions to comply with CAIR) and providing a mechanism to prevent over allocation to these units. [EPA-HQ-OAR-2009-0491-3907[1].1, p.2]
Different Allocations Options for Different Trading Programs: The short time period allowed for comment on this NODA did not let us look at this issue fully. However, we believe that Option#2, with its heat input based allocation methodology and its provisions for dealing with over allocation issues, is the best of the three current allocation options for all four trading programs. [EPA-HQ-OAR-2009-0491-3907[1].1, p.2]
Gainesville Regional Utilities (GRU)
While both Options #1 and #2 are superior to EPA's original allocation proposal, we believe that Option #2 represents better public policy and can be more easily defended by EPA. [EPA-HQ-OAR-2009-0491-3922[1].1, p.1]
Option #2 attempts to address both of these issues. By using a multi-year look back for the 'maximum actual' emission test, Option #2 does not disadvantage utilities that have spent significant resources to meet CAIR requirements since emissions levels prior to adding controls are considered in the allocation process. In the case of GRU, this was over $140 million. In addition, the 'well controlled unit' test mitigates in large part the over allocation issue with gas-fired units. White this does not fully eliminate over allocations for these units, it is mitigated in many cases in that gas-fired units are often dual fuel capable. This is the case with nearly all Florida gas-fired combined cycle units and many gas-fired steam units. [EPA-HQ-OAR-2009-0491-3922[1].1, pp.1-2]
The short time period allowed for comment on this NODA did not let us look at this issue fully. However, assuming that EPA finds that the 'well controlled unit' test in Option #2 is sufficient to deal with over allocation issues for the whole CATR region , GRU finds that Option #2 is the best of the three current allocation options for all four trading programs. [EPA-HQ-OAR-2009-0491-3922[1].1, p.2]
GenOn Energy, Inc.
The 2nd Option discussed in NODA 3 would reduce this wealth transfer somewhat, but still give gas-fired plants orders of magnitude more SO2 allowances than they would ever need. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 2]
If EPA proceed to issue a final Transport Rule without preparing a comprehensive supplemental proposal and allowing adequate time for public comment, then it should either: c. Adopt a modified version of Option 2 from NODA3 that recognizes that (1) there is a vast difference between SO2 emission rates from well-controlled coal, gas, and oil-fired units and (2) there must be a more rational approach for considering the wide range of capacity factors. In particular, the use of the 95th percentile overstates actual operations for 95 percent of all units, and drastically overstates the operations of many peaking units. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 4]
Option 2 results in the same inequities as option 1, although it does reduce, to some extent, the windfall to gas-fired plants. Option 2 in NODA 3 is based on historic heat input, just as option 1, but restricts the allocation based on a 'well-controlled emission rate of 0.06 lbs/mmBtu for SO2.' 76 Fed. Reg. 1109, 1115. While 0.06 lbs/mmBTU may be a well-controlled emission rate for a coal-fired power plant, there is no way a natural gas fired power plant would ever have such a high emission rate. EPA's own compilation of AP-42 factors states that large uncontrolled gas turbines should use a 0.0006 lb/mmBtu to estimate emissions when the sulfur content is not available. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 7]
Great River Energy
To a lesser extent, Great River Energy views the NODA Option 2 as better than EPA's original 'Preferred Option." However, like the Preferred Option, Option 2 also allocates allowances based on emissions, which  inherently rewards dirtier plants at the expense of the cleaner plants. [EPA-HQ-OAR-2009-0491-3898[1].1, pp.4-5]
Gulf Coast Lignite Coalition
Option 2 proposes allocations in a similar fashion as Option 1, but includes an upper-bound capacity utilization factor and 'well-controlled' emission rate for all units, irrespective of fuel type. Again, due to coal carrying a higher sulfur and nitrogen content, coal-fired units will have a more difficult time meeting the 'well-controlled' emission rate than other fuel types. Meanwhile sources firing lower sulfur fuels will not only meet the emission rate, but also accumulate allocations more readily. The unique characteristics of fuel types and regional needs must be given adequate consideration, particularly with regard to coal and subcategories of coal, such as lignite. [EPA-HQ-OAR-2009-0491-3963[1].1, p.2]
To further highlight this issue, Option 2 proposes a 'well-controlled' emission rate of 0.06 lb/mmBtu for all units, irrespective of fuel type. According to the EPA's Continuous Emissions Monitor (CEMs) database, less than 1% of 1050 coal units could meet the 'well-controlled' emissions rate for nitrogen oxide (NOx) and sulfur dioxide (S02). Note that the 1 % of these coal units that meet the emissions rate, include those that bum low-sulfur fuels, which is not representative of the coal type utilized in all Transport Rule states. Natural gas units fared better with the 'well-controlled' emission rate, and ultimately are put in a position to earn allowances. [EPA-HQ-OAR-2009-0491-3963[1].1, p.3]
Horsehead Corporation
To the extent that EPA chooses to allocate allowances under the final Transport Rule based on one of the two allocation approaches described in the Second NODA, rather than the allocation method set forth in the Proposed Transport Rule, then EPA should rely on Option 2 under the Second NODA. As between the two options, Option 2 takes into account historic actual emissions, as well as reasonably foreseeable maximum emissions based on a well-controlled- rate emission factor for the relevant pollutant. Although neither allocation method described in the Second NODA is fully consistent with EPA's stated objectives for the Transport Rule, Horsehead believes reliance on Option 2 would be more consistent with the objective of developing a final Transport Rule that ensures a reliability power supply, as compared to Option 1, under which allowance allocations are based solely on historic heat input. [EPA-HQ-OAR-2009-0491-4003[1].1, p.2]
Independence Power & Light (IPL)
Indeed, Option 2 appears to undercut such a notion by reducing the burden on higher-emission-rate units through a reapportionment of the lower-emission-rate units' allowances. See 76 FR at 1116, Table II (giving example). [EPA-HQ-OAR-2009-0491-3949[1].1, p.4]
For example, Option 2 takes into account different capacity factors that are largely fuel-oriented, 76 FR at 1115, Table 1 & n. 4, and makes other adjustments that are not emissions-control-neutral. Id., steps 5 and 6. Making adjustments to offset 'neutrality' leaves an open question of whether a better approach would consider fuel differences and emission-control differences as integral parts the estimation process, as is done in the Original Methodology. [EPA-HQ-OAR-2009-0491-3949[1].1, p.5]
Lafayette Utilities System
Of the two alternative allocation methodologies proposed in the 2011 NODA, LUS supports the use of the second methodology, referred to as the Emissions-Rate-Informed Historic Heat Input Approach or Option 2, over the first methodology, referred to as the Historic Heat Input Approach or Option 1, due to the fact that Option 2 is a more equitable method that is based on more realistic factors, such as being based on a unit's actual emissions. [EPA-HQ-OAR-2009-0491-3914[1].1, p.3]
Option 2 is an emissions adjusted methodology, however, that uses the same initial allocation pattern as Option 1 but, if a unit's maximum annual emissions for a pollutant over the prior seven years are less than the Option 1 allocation, then adds a constraint based upon a unit's 'reasonably foreseeable' maximum emissions under proposed CATR trading programs. Option 2 is superior to Option 1 in that the allowances issued to each unit are constrained by the actual emissions from that unit. . Simply stated, no unit will be allocated more allowances than they would actually use. [EPA-HQ-OAR-2009-0491-3914[1].1,p.3]
The occurrence of over-allocations-and the substantial windfalls to those particular units that have more allowances than they can realistically use-is much less likely under Option 2 than under Option 1. The allowances granted under Option 2 are more realistic as to the actual operations of the units subject to CATR. [EPA-HQ-OAR-2009-0491-3914[1].1, p.4]
Louisiana Chemical Association (LCA)
3 . If EPA selects Option 2 - the Emissions-Rate-Informed Historic Heat Input method, LCA agrees that the look back period should be at least seven years (2003-2009); however, LCA believes a ten year period would provide more flexibility and would be more representative of actual capabilities of the units. This is particularly the case with respect to facilities that have more than one EGU where utilization of one unit may have been artificially low due to utilization of other available units. [EPA-HQ-OAR-2009-0491-4027, p. 5]
4. If EPA selects Option 2, LCA requests that EPA either revise the 'reasonable upper bound capacity factor' for combined cycle waits or create a separate category for combined cycle units that serve dedicated industrial manufacturing and refining facilities. EPA has indicated that these upperbound capacity factors for combined cycle units are 70% annually and 73% for ozone season. However, actual data for all of the LCA members with combined cycle units reveal capacity factors that are much higher, in the 95 to 98% range. It is difficult to determine whether EPA is equating the terms utilization factor and capacity factor. For a reasonable-upperbound estimate, EPA should be looking at a reasonable utilization factor - in other words, on-stream time. It appears that this is what EPA is trying to determine as the Preamble discussion in the 2011 NODA states : 'These upper-bounds would be calculated as the utilization values at the 95th percentile in each technology class.'  [EPA-HQ-OAR-2009-0491-4027, pp. 5-6]
The cogeneration units owned and/or operated by ox on behalf of Dow, ExxonMobil, Occidental, PPG produce large volumes of electricity and steam continuously because the host plant needs both 24 hours every day. The only downtime is for maintenance, so a reasonable utilization/capacity factor would be 95% both annually and for the ozone season . These units occasionally have a year when a generator is undergoing a major overhaul, so that year will be less than 95% capacity factor, however, this generally does not happen on an annual basis. [EPA-HQ-OAR-2009-0491-4027, p. 6]
In addition, cogeneration units are fuel efficient - and therefore produce less emissions - than most other EGUs. The gas turbine generator makes electricity directly, then supplemental fuel is added to its very hot exhaust to make even more high pressure steam. The attached Heat Recovery Steam Generator / boiler may have a second, lower pressure steam generating section, and certainly will have a boiler feed water preheat section, both of which capture even more of the heat versus letting it go out the stack. In addition, the high pressure steam is used to run big turbines in place of motors or to spin a steam turbine generator to make more electricity and lower pressure steam. The lower pressure steam then goes to the host plant where it is used for multiple purposes, and often  exhausts as low pressure steam / heat that is used elsewhere. In short, these units are designed to 'get the squeal out of the pig.' [EPA-HQ-OAR-2009-0491-4027, p. 6]
LCA believes a reasonable upper-bound utilization/capacity factor for these units is 98% to 99% both annually and during ozone season as several of the LCA members have had units with on-stream utilization time in this range within the past several years. If EPA is trying instead to determine the electrical and steam percent-of maximum-capacity factor, LCA believes that EPA does not have adequate data to do so. This is significantly more difficult and labor intensive as the ambient temperature and total steam and power demand is constantly moving. This data is not reported to EPA under CAMD and is not reflected in NEEDS 4.10. Further for combined cycle units with supplementally fired HRSGs- electrical utilization and steam utilization can be independent. [EPA-HQ-OAR-2009-0491-4027, p. 6]
Massachusetts Department of Environmental Protection
Option 2 is also based on historic heat input, but adds a formula to limit the number of allowances allocated to low-emission rate units by re-apportioning the allocation based on a 7-year baseline and a number of other complicated parameters (e.g., 'well-controlled-rate maximum' and 'reasonable foreseeable maximum emissions level'). MassDEP believes that EPA's attempt to limit the award of allowances in certain instances may be well-founded. However, because of the complexity of the proposed formula, we do not fully understand the implications of what is proposed in Option 2 and are not able to advocate for or against its adoption. [EPA-HQ-OAR-2009-0491-4017[1].1, p.3]
Mississippi Department of Environmental Quality
In allocating allowances to a unit level, Mississippi supports using a method like that described in option 2 which uses the historic heat input based approach, but limits the allowances given to a unit based on a unit's reasonably foreseeable maximum emissions. However we would recommend using the unit's maximum allowable permitted emissions to limit the allowances to a unit as well. While EPA may not be directly privy to this information it can be relatively quickly and easily obtained from the state or local permitting authorities by request. [EPA-HQ-OAR-2009-0491-3917[1].1, p.1]
National Grid
Option 2 introduces too many adjustment factors that may cause objections that would result in a delay of the implementation of the rule. [EPA-HQ-OAR-2009-0491-3921[1].1, p.1]
Nebraska Public Power District
However, if Nebraska remains in the TR, NPPD supports Option 2 as the preferred method for allowance allocations. Option 2 is preferred since it takes into account a unit's reasonably foreseeable maximum emissions. This reduces the allowances allocated to lower emitting units and redistributes those allowances to higher emitting units. [EPA-HQ-OAR-2009-0491-3886[1].1, p.1]
NextEra Energy, Inc.
We are concerned that Option 2 introduces too many potential adjustment factors to be cleanly implemented without legal challenge in the short time EPA has to finalize the rule. [EPA-HQ-OAR-2009-0491-3962[1].1, p.2]
North Carolina Electric Membership Corporation
The second option results in the fairest allocations to individual units. NCEMC supports the logic of the second alternative, which would use the Reasonably Foreseeable Maximum Emissions to limit instances where units would receive substantially more allocations than ever needed historically. [EPA-HQ-OAR-2009-0491-4001[1].2, p.1]
Northern Indiana Public Service Company (NIPSCO)
Without retreating from its view that the allocation methodology should be left to states, NIPSCO prefers Option II over all of the other proposed allocation methodologies. [EPA-HQ-OAR-2009-0491-3995[1].1, p. 2]
NIPSCO has not been able to replicate EPA's methodology employed in Option II; nevertheless, the allocation identified for NIPSCO's EGUs under Option II most closely reflect NIPSCO's calculations as to the number of allowances appropriate for NIPSCO under the proposed statewide budget. [EPA-HQ-OAR-2009-0491-3995[1].1, p. 2]
Northshore Mining Company
EPA has requested comment on two competing allocation methodologies presented in NODA III.  Northshore generally prefers the Option 2 Allocation Methodology, which caps allowances to avoid over-allocation windfalls for certain units. [EPA-HQ-OAR-2009-0491-3957[1].1, p.7]
NRG Energy
Option 2 attempts to correct this imbalance, but does not go far enough. See suggested improvement 2 below. [EPA-HQ-OAR-2009-0491-3933[1].1, p.3]
This imbalance is apparent when comparing the allocation distribution of Option 1 to EPA's proposed projected method, or even to the more accommodating Option 2. [EPA-HQ-OAR-2009-0491-3933[1].1, p.3] [[This comment can also be found in Section XX.A.1.a.]]
 In contrast, using historical emissions or adjustments as recommended for Option 2 (see comment 4, improvements below) are ways to return fairness and impartiality to the allocation and in turn, continue to support Americans' access to affordable and reliable power while transitioning to cleaner technologies and fuels. [EPA-HQ-OAR-2009-0491-3933[1].1, p.4]
 Improvement 3  -  In proposed Option 2, the calculation uses the top 95th percentile for calculating capacity factors to determine potential emissions. Based on our review of generation data, these factors appear high. We recommend EPA consider using ISO regional or CATR average capacity factors for this calculation.   [EPA-HQ-OAR-2009-0491-3933[1].1, p.7]
 EPA Question  -  Are the alternative methodologies clear and easy to understand?  Option 2 and the original methodologies proposed in July 2010, while necessarily complex, are understandable. [EPA-HQ-OAR-2009-0491-3933[1].1, p.8]
 EPA Question  -  Do these alternatives yield a reasonable distribution of allowances?  By contrast, the July projected emissions method and Option 2 (with recommended improvements) better reflect emissions, and a plant's compliance costs are buffered in a fair and comparable manner. This protects both investors and consumers, conserves capital needed for massive investments in emission control equipment and clean energy projects, and provides a stronger incentive to make those investments. This maintains the proper balance in protecting health and the environment while promoting economic growth.   [EPA-HQ-OAR-2009-0491-3933[1].1, p.9] [[This comment can also be found in Section XX.A.]]
Oglethorpe Power
This option retains the Option 1 approach, but adds a constraint for those units whose initial Option 1 allocations would exceed the highest annual emissions in a 7-year historic emissions baseline - 2003 through 2009. For such units, this option would establish, based again on historic data, a 'reasonaably foreseeable maximum emissions' level, using an upper-bound capacity utilization factor and a well-controlled emission rate that EPA believes all units (regardless of the type of fuel they combust) can meet for the pollutant. EPA's stated goal is that for those units whose heat-input-based allocations would exceed historic emissions, this option would limit the historic-heat-input-based allocations to a maximum emissions level, preventing units from being allocated allowances in excess of their reasonably foreseeable maximum emissions. [EPA-HQ-OAR-2009-0491-3896[1].1, p.4]
Old Dominion Electric Cooperative
NOOA III option 2 attempts to somewhat correct the inadequacies in option 1 but the end result is likewise unreasonably gas bias. Option 2 attempts to avoid an unconscionable over allocation of allowances to gas units by incorporating a 'reasonably foreseeable maximum emissions level reflecting a reasonable upper-bound capacity utilization factor and well controlled emission rate that all units (regardless of the type of fuel they combust) can meet for the pollutant." The fundamental problem with option 2 is the incorporation of a 'one size fits all' approach for the 'well controlled emission rate' factor used to determine the 'reasonably foreseeable maximum emissions level.' Since gas has inherently lower sulfur and nitrogen content than coal, as previously mentioned, this approach as applied in the option 2 allocation methodology continues to function poorly for reasonably allocating allowances. OOEC is under the impression that option 2 was constructed to be fair and equitable, while meeting the North Carolina requirements. [EPA-HQ-OAR-2009-0491-4004[1].1, p.3]
In addition, use of 'well controlled emission rate' of 0.06 Ibs/MMBtu for both NOx and SO2 as EPA admits is a 'one size fits all' emissions rate metric. NRECA's analysis of the data demonstrates that this 'well controlled emission' standard functions poorly to effectively limit allowances to combined cycle and turbine units to a 'reasonable initial distribution as EPA maintains in the NODA III and has little applicability to coal-fired units within the CATR region. [EPA-HQ-OAR-2009-0491-4004[1].1, p.4]
NRECA's summary also outlines that less that 0.8% of the coal fueled units in the CATR region can meet the 'well controlled emission standard' in option 2. Also, EPA has presented no information or analysis in connection with this rulemaking that shows that any of the remaining 1050 units could meet the well controlled standard and if so when. Additionally, no coal unit currently meeting the 'well controlled standard for S02' is burning other than low sulfur coal. [EPA-HQ-OAR-2009-0491-4004[1].1, p.4]
In summary, EPA's choice of a one size fits all 'well controlled emissions rate' standard does not function to meet EPA's stated objective in proposing the NODA III option 2, which is to institute an approach to result in 'reasonable initial distribution' of allowances consistent with CAA Section 110. [EPA-HQ-OAR-2009-0491-4004[1].1, p.4]
Otter Tail Power Company
Even focusing on Option 2, which in theory limits allowance allocations to a maximum emissions level, Table 1 below shows that existing natural gas-fired units in Minnesota would receive a windfall of SO2 allowances that far exceeds their actual historical maximum emissions. [EPA-HQ-OAR-2009-0491-3888[1].1, pp.1-2] [[See Docket Number EPA-HQ-OAR-2009-0491-3888[1].1, pp.2-3 for Table 1.]]
As shown in Table 1, under the Option 2 allocation methodology, in every case but one Minnesota combustion turbine and combined cycle units would receive significantly more SO2 allowances than their historical actual maximum emissions, and in some cases individual units would receive hundreds more allowances than needed. [EPA-HQ-OAR-2009-0491-3888[1].1, p.3]
Comment 2: If EPA finalizes a heat input-based methodology, the Option 2 methodology must be altered prior to issuing a final Transport Rule. [EPA-HQ-OAR-2009-0491-3888[1].1, p.3]
If EPA decides to finalize a heat input-based allocation methodology, Option 2 must be revised to correct the disproportionate number of SO2 allowances that natural gas-fired generating units would receive. Otter Tail suggests that this could be accomplished by simply using the maximum historical SO2 emissions as the capped allocation level. This is reasonable because EPA used a seven-year lookback period to determine the maximum historical emissions, which is an adequate period to reasonably indicate future maximum emissions. [EPA-HQ-OAR-2009-0491-3888[1].1, p.3]
EPA could also improve the Option 2 methodology by applying a different "well-controlled" SO2 emission rate to natural gas-fired generation when determining reasonably foreseeable maximum emissions. As proposed, Option 2 would use a well-controlled SO2 rate of 0.06 lbs/mmBtu for all units. For facilities that use pipeline natural gas, this factor is one hundred times too high. This is recognized by EPA in 40 CFR Part 75 Appendix D Section <IP_ADDRESS>, which allows units that combust pipeline natural gas to use a default SO2 emission rate of 0.0006 lbs/mmBtu. [EPA-HQ-OAR-2009-0491-3888[1].1, p.4]
PowerSouth Energy Cooperative
This proposed methodology is an improvement on NODA Option 1, and the best of the three allocation methodologies described. Option 2 is a significant improvement over Option 1 since a methodology for accounting for differences in emissions sources is an essential part of any fair and equitable allocation scheme.  However, this alternative is NOT the final methodology that should be incorporated into the final rule.  The major flaw with Option 2 is that proposed "well controlled emission rates" are still too high for most gas fired units, and still result in significant over allocations of both SO2 and NOx allowances.  Option 2 can be modified and built upon to establish the final allocation methodology.  Fuel type and combustion technology must be incorporated to fairly distribute allowances to emissions sources.  [EPA-HQ-OAR-2009-0491-3956[1].1, p.7]
PPG Industries, Inc.
Option 2 is an emissions adjusted methodology that uses the same initial allocation pattern as Option 1 but then adds a constraint based upon a unit's 'reasonably foreseeable' maximum emissions under proposed CATR trading programs. [EPA-HQ-OAR-2009-0491-3911[1].1, p.2]
While PPG believes that Option 2 is superior to the IPM-based methodology due to its utilization of actual historic heat input data [EPA-HQ-OAR-2009-0491-3911[1].1, p.3]
Without waiving its position that Option 1 is superior to Option 2, if EPA decides to implement Option 2, PPG believes that the capacity factor component of the methodology utilized by EPA for combined cycle cogeneration units is artificially low. The capacity factor proposed by EPA as a reasonable upper bound capacity factor for such units is 0.70 annual and 0.73 ozone season, and EPA stated that this value was based upon data reported to EPA by source owners. PPG disputes the accuracy of this capacity factor for cogeneration units. Actual data submitted to EPA reflects that PPG's capacity factor for its cogeneration units is approximately 0.98 annually and [to be added] _ during ozone season. PPG believes that other combined-cycle cogeneration facilities within the State of Louisiana that serve industrial steam production use have similar capacity factors. PPG requests that EPA revise its capacity factor values to more accurately reflect the actual operations of these types of combined-cycle cogeneration units. [EPA-HQ-OAR-2009-0491-3911[1].1, p.3]
PPL Corporation
PPL PA Generation requests that EPA adopt Option 2 of the proposed alternatives. However either of the proposed options is preferable over the initial method proposed by EPA. [EPA-HQ-OAR-2009-0491-3935[1].1, p.3-4]
PSEG Services Corporation
We are concerned that Option 2 introduces too many potential adjustment factors to be cleanly implemented without legal challenge in the short time EPA has to finalize the rule. [EPA-HQ-OAR-2009-0491-3936[1].1, p.2]
San Miguel Electric Cooperative, Inc.
Option Two makes a feeble attempt to adjust for historical emissions but fails to allocate allowances fairly. [EPA-HQ-OAR-2009-0491-3997[1].1, p.2]
The NRECA analysis also indicated using the one-size-fits-all approach to the "well controlled emission rates" " (.06 lb/mmbtu for SO2 and NOx) is not representative of coal or gas units"
- No combined cycle (CC) gas unit emissions exceed the well-controlled SO2 rate.
- Only 20% of the CC gas units have emissions that exceed the well-controlled emissions rate for NOx and the vast majority of these units are not equipped with SCRs.
- Less than 8% of the combustion turbines have emissions that exceed the well-controlled rate for SO2 emissions. The vast majority of these units appear to use gas/diesel as a duel fuel. [EPA-HQ-OAR-2009-0491-3997[1].1, p.3]
- Of the more than 1050 coal units contained in EPA's CEMS database for the CATR states that will be required to control for both SO2 and NOx, just 8 units meet or are below the "well controlled emission rate" for both SO2 and NOX.
- 45 coal units in the CATR meet or are below the well-controlled rate for NOx.
- 27 coal units meet or are below the well-controlled rate for SO2, and all of these units utilize low sulfur coal. [EPA-HQ-OAR-2009-0491-3997[1].1, p.4]
Santee Cooper
The proposed Option 2 relies upon a complex formula to 'cap' allocations for individual EGUs at 'reasonably foreseeable maximum emissions,' yet EPA's proposed methodology for determining the cap on allocations relies upon assumed 'well-controlled emission rates' and capacity factors that may not accurately predict maximum emissions for individual EGUs subject to the Transport Rule. Moreover, the NODA provides no information as to how this methodology was crafted and whether it provides a representative estimate of maximum foreseeable emissions for most EGUs. Option 2 is also likely to be particularly inappropriate for predicting maximum foreseeable emissions for utilities that are experiencing rapid load growth, such as Santee Cooper. Santee Cooper believes the complex and untested nature of the maximum emissions formula in Option 2. [EPA-HQ-OAR-2009-0491-3913[1].1, pp.3-4]
Seminole Electric Cooperative Inc.
Allocations should be based on a unit's reasonably foreseeable maximum emissions. A so-called 'emissions-rate-informed' historic heat input approach would ensure no individual unit is allocated excess allowances. Such an approach would properly reflect the shared burden among electric generating units to reduce emissions in order to eliminate the state's significant contribution and interference with maintenance. [EPA-HQ-OAR-2009-0491-3992[1].1, p.2]
Southern Company
Third, if EPA uses a heat-input based allocation method, it must use an emission constraint that grounds a unit's allocations in reality  -  using real and credible emissions data. In NODA3 Option 2, EPA attempts to correct the inconceivable over-allocations that result from a straight heat-input based method (i.e., Option 1). To do so, EPA essentially caps a unit's allocation at the greater of its "maximum historical baseline emissions" (i.e., highest emissions for each compliance period from 2003 to 2009) and its "well-controlled-rate-maximum" (a calculated value). Option 2 contains hundreds and hundreds of examples of gross under- and over-allocations after applying Option 2's emission constraint. Put simply, EPA's emission constraint failed. The bulk of that failure is due to the flawed "well-controlled-rate-maximum" value. [EPA-HQ-OAR-2009-0491-3946[1].1, pp.8-9]
For a unit that reports hourly heat input, the "well-controlled-rate maximum" equals:
:: that unit's maximum hourly heat input,
:: multiplied by 0.06 lbs/mmBtu (for both SO2 and NOx allocations),
:: multiplied by 8,760 hours (or 3,672 for ozone season),
:: multiplied by set-technology-specific capacity factors. [EPA-HQ-OAR-2009-0491-3946[1].1, p.9]
This approach is fundamentally flawed. Option 2 can still lead to allocations that are 200 times greater than a unit's "maximum historical baseline emissions" (see Table 1 above and EPA's NODA3 Allocation Tables in the Docket). Also, there is no basis to use an emission rate (0.06 lbs/mmBtu for both SO2 and NOx) that is admittedly based on a well-controlled coal unit for all units. Individual units have significantly different emission rates depending on the fuel used; there is no reason for EPA to ignore such a fact when calculating an emissions value. Further, EPA's use of technology-specific capacity factors does not remedy the flaw. EPA's capacity factors are based on its effort to determine a realistic average capacity for certain technology types. Doing so might lead to a defensible prediction of maximum emissions if a proper fuel- or technology-specific emission rate were used, but given EPA's use of a coal-specific emission rate, the capacity adjustment is wholly ineffective at correcting the error. If EPA proceeds with this allocation methodology, it should throw out the flawed "well-controlled-rate-maximum" concept and allocate based on the "maximum historical baseline emissions." [EPA-HQ-OAR-2009-0491-3946[1].1, p.9]
Southern IL Power Cooperative
NODA III option 2 attempts to somewhat correct the fallacies in option 1, but the end result is still unreasonably gas biased.  Option 2 attempts to avoid an over allocation of allowances to gas units by incorporating a "reasonably foreseeable maximum emissions level reflecting a reasonable upper-bound capacity utilization factor and well-controlled emission rate that all units (regardless of the type of fuel they combust) can meet for the pollutant."    The fundamental problem with option 2 is the incorporation of a one size fits all for the "well-controlled emission rate" factor used to determine the "reasonably foreseeable maximum emissions level."  Since gas has inherently lower sulfur and nitrogen content than coal, as previously mentioned, this one size approach as applied in the option 2 allocation methodology functions poorly in reasonably allocating allowances.  [EPA-HQ-OAR-2009-0491-3901[1].1, p.3]
As a group combined cycle (CC) and turbine units receive the following windfalls of allowances in all the CATR trading programs:
-Under the ozone NOx trading program:   While emitting about 5.52 % of total CATR tons, CC and turbine units receive about 16% of the allowances, over 300% more than their current emissions.   [EPA-HQ-OAR-2009-0491-3901[1].1, p.3]
-Under the fine particulate trading program for annual NOx:  While emitting about 2.98% of the total CATR tons, CC and turbine units receive about 10% of the allowances, over 300% more that their current emissions.
-Under the fine particulate trading for annual SO2:  While emitting about .5% of the total CATR tons, CC and turbine units receive about 5% of the allowances in 2012 and about 7% of the allowances in 2014, over 6200% of their current emissions.  [EPA-HQ-OAR-2009-0491-3901[1].1, p.4]
Thus in the aggregate combined cycle and turbines units receive far more allowances than these units can ever use.  [EPA-HQ-OAR-2009-0491-3901[1].1, p.4]
The proposed option 2 "well -controlled emission rate" of .06 lbs/mmbtu for both NOx and SO2 is a significant component in determining EPA's proposed "reasonably foreseeable" maximum emissions level.  Use of this emissions standard as EPA admits is a one size fits all emissions rate metric.  An analysis of the data, as follows, show that this "well-controlled emission" standard functions poorly to effectively limit allowances to combined cycle and turbine units to a "reasonable initial distribution as EPA maintains in the NODAIII.   [EPA-HQ-OAR-2009-0491-3901[1].1, p.4]
-No combined cycle (CC) gas unit emissions exceed the "well-controlled emissions rate" for SO2
-Only 20% of the CC gas units have emissions that exceed the "well-controlled emissions rate" for NOx and the vast majority of these units are not equipped with SCRs.
-Less than 8% of the combustion turbines have emissions that exceed the "well-controlled emissions rate" for SO2 emissions.  The vast majority of these units appear to use gas/oil as a duel fuel.  [EPA-HQ-OAR-2009-0491-3901[1].1, p.4]
Lastly, EPA maintains that "well-controlled emissions rate" is one that "all units (regardless of the type fuel they combust) can meet."  Again an analysis of the EPA's database in the docket of this rulemaking shows the "well-controlled emissions rates" have little applicability to coal-fueled units within the CATR region as follows:
-Of the more than 1050 coal units contained in EPA's CEMS data base for the CATR states that will be required to control for both SO2 and NOx just 8 units meet or are below the "well-controlled emission rate" for both SO2 and NOX.
-45 coal units in the CATR meet or are below the "well-controlled emissions rate" for NOx  [EPA-HQ-OAR-2009-0491-3901[1].1, p.4]
-27 coal units meet or are below the "well-controlled emissions rate" for SO2, and all of these units utilize low sulfur coal.  [EPA-HQ-OAR-2009-0491-3901[1].1, p.5]
Thus the EPA has proposed one size NOx and SO2 "well-controlled emissions" standard as applied to coal-fueled units is a standard that less that .8% of the coal-fueled units in the CATR region can meet.   EPA has presented no information or analysis in connection with this rulemaking that shows that any of the remaining 1050 units could meet the well controlled standard and if so when.  Additionally, as the attached summary of EPA data contained the CATR rulemaking docket shows, no coal unit currently meeting the "well-controlled standard for SO2" is burning other than low sulfur coal.     [EPA-HQ-OAR-2009-0491-3901[1].1, p.5]
Therefore, EPA's choice of a one size fits all "well-controlled emissions rate" standard does not function to meet EPA's stated objective in proposing NODA III option 2, which is to institute an approach to result in "reasonable initial distribution" of allowances consistent with CAA Section 110.   [EPA-HQ-OAR-2009-0491-3901[1].1, p.5]
State of Ohio Environmental Protection Agency (Ohio EPA)
Option 2 distributes allocations in the same manner as Option 1 but then constrains the allocation based on a unit's reasonable foreseeable maximum emissions, limiting a unit's ability to exceed historic emissions (from 2003 to 2009). Under Option 2, when a unit's heat input based allocation would exceed the maximum historic emissions baseline, a well-controlled-rate maximum would be calculated based on 0.06 lbs/MMBtu for S02 and NOx. [EPA-HQ-OAR-2009-0491-3915[1].1, p.1]
First, Ohio EPA does not agree that a well controlled rate of 0.06 lbs/mmBTU for S02 or NOx is appropriate. As noted in the NODA, this rate represents the 'lowest' annual emission rates assumed achievable when state-of-the art-technology is installed on coal units. A well controlled rate should be just that, not a lowest achievable rate. Ohio EPA reiterates the comment in our October 15, 2010 comments:
In Chapter 5 of the documentation (Emissions Control Technology) U.S.EPA states 'Potential (new) coal-fired, combined cycle, and IGCC units are modeled to be constructed with SCR systems and designed to have emission rates ranging between 0.01 and 0.06 lb NOx/MMBtu. In Appendix 5.2A, 'IPM Model - Revisions to Cost and Performance for APC Technologies, SCR Cost Development Methodology' by Sargent and Lundy it is recommended that the 'lower level of NOx removal is recommended as 0.07 NOx lb/mmBtu' for bituminous coal. Yet, U.S.EPA appears to make the assumption that older coal-fired units retrofitted with SCRs can also achieve a 0.06 lb NOx/mmBTU rate. Ohio EPA is not as confident that this one size fits all rate is achievable for retrofits. [EPA-HQ-OAR-2009-0491-3915[1].1, p.2]
For many controlled units, like the examples above for Gavin and Cardinal, there are excess allocations, except units with older control devices when Option 2 is applied. While Option 2 has attempted to limit the amount of excess allocations, the method used does have issues. The NODA acknowledges that 'for the majority of units, the historic heat input-based allocation will not be sufficient to cover historic emission levels' and that 'heat input-based allocations only exceed historic emissions for units at the lower end of the range of historic emission rates for the pollutant involved' and therefore, for these units, Option 2 would 'establish, based on historic data, a reasonably foreseeable maximum emissions level' based on a 'well-controlled emission rate that all units can meet.' However, in comparing emission rates for Gavin and Cardinal, Cardinal's much newer FGD is capable of achieving lower emission rates. [EPA-HQ-OAR-2009-0491-3915[1].1, p.4]
When comparing the Gavin unit and the Cardinal unit above, Gavin has an older FGD pre-dating the years of data used in this analysis and allocation method while Cardinal has a newer FGD. This seems to have worked as an advantage for Cardinal. Option 1 and the first steps of Option 2 results in allocations for Cardinal well above actual controlled emissions, but because the control device was installed within the years used for this analysis and the year of highest actual emissions (uncontrolled) is well above the heat-rate based calculation, there is no restriction under the second part of calculations under Option 22. However, for Gavin, because the control device was installed prior to the years of analysis, the year of highest actual emissions is a controlled year triggering the limitation on allocations under the second part of calculations under Option 2. While Option 2 attempts to constrain allocations based on a unit's reasonable foreseeable maximum emissions it does it in a manner that places a disadvantage to units with control devices installed prior to 2003. Also note that Gavin's average of the three highest annual heat inputs (96,340,367) is over three times larger than Cardinal's (32,060,238). This is obviously reflected in the allocations under Option 1, but Option 2 does not effectively discount both units in an equal manner. [EPA-HQ-OAR-2009-0491-3915[1].1, pp.4-5]

2 Note that Cardinal's allocations under Option 2 are actually higher than Option 1. This is due to re-distributing allocations among all units in the State after units restricted under Option 2 have their emissions reduced similar to Gavin's.
Sunbury Generation LP
EPA's proposed unit-specific allowance allocations under Option 2 of the Second NODA do not fully implement EPA's stated objective of avoiding a windfall of allowances for certain sources. [EPA-HQ-OAR-2009-0491-3920[1].1, p.1]
Like Option 1, Option 2 is based on historic heat input, but proposes to modify the allocations so that they do not exceed the higher of either historic actual emissions or emissions calculated using a 'clean emission factor' (referred to by EPA in the Second NODA as the 'well-controlled-rate maximum'), and the reasonably expected maximum future heat input. Id That is, allowance allocations for sources whose heat-input-based allocation would exceed historic emissions would be capped based on the sources' reasonably foreseeable maximum emissions. Id [EPA-HQ-OAR-2009-0491-3920[1].1, p.2]
Sunbury supports the conceptual methodology underlying the Option 2 approach of modifying allocations so that sources whose heat-input-based allocations would exceed historic emissions do not receive a windfall of allowances. However, EPA has not fully implemented this conceptual methodology in its specific proposed allocation approach, as described in the Second NODA. Specifically, under Option 2, a source's allowance allocation would be determined based on the higher of either the unit's historic actual emissions or the well-controlled- rate-maximum for the relevant pollutant (i.e., 0.06 lbs/mmBtu for S02). As a result, many low-emitting sources would receive an allocation dictated by a well-controlled-rate emission factor which substantially exceeds their actual emissions, thereby providing these sources with a windfall. This result is directly inconsistent with EPA's stated objectives in support of Option 2. EPA explains that the proposed approach is intended to 'reflect[] the shared burden on units to reduce emissions in order to eliminate the state's significant contribution and interference with maintenance.' Id at 1115. [EPA-HQ-OAR-2009-0491-3920[1].1, p.2]
The inequity resulting from this allocation approach is further compounded when considered in conjunction with the potential implications of the emission allowance trading options described under the Proposed Transport Rule. As addressed more fully in Sunbury's comments on the Proposed Transport Rule, EPA has proposed to limit the scope of the proposed trading programs; if finalized, this approach could substantially restrict the ability of affected facilities to trade allowances on the market. Relative to Option 2 under the Second NODA, if EPA elects to allocate allowances under the final Transport Rule using this approach, then any sources whose actual emissions are lower than the well-controlled-rate emission factor would receive more allowances than they need to operate in compliance with the Transport Rule. However, depending on the specific trading program provisions in the final Transport Rule, these excess allowances may not be fully avail able for transfer on the market. Likewise, other affected sources whose initial allowance allocations would be insufficient to cover their emissions would be unable to secure through trading the additional all owances they need to continue operating. Simply put, any 'extra' allowances distributed to low-emitting sources under Option 2 would be effectively 'tied up' and unable to be used by other affected sources. [EPA-HQ-OAR-2009-0491-3920[1].1, p.2]
In the Proposed Transport Rule, EPA identifies several 'key guiding principles' for implementing the Transport Rule, including but not limited to, consideration of cost-effectiveness, providing flexibility to the regulated community, and ensuring a reliable power supply. See 75 Fed Reg. 45226-7. However, for the reasons discussed above, the use of Option 2 for purposes of allocating unit-specific allocations in the manner described in the Second NODA would be directly inconsistent with these stated objectives. [EPA-HQ-OAR-2009-0491-3920[1].1 p.3]
For the foregoing reasons, if EPA elects to finalize a Transport Rule that relies upon the allocation methods described in the Second NODA, Sunbury urges EPA to fully implement the conceptual methodology underlying Option 2 by ensuring that allowance allocations are limited to a unit's actual historic emission rates during the relevant time period considered under the Second NODA. Failure to do so would run counter to EPA's enumerated guiding principles in the Proposed Transport Rule and the Second NODA, including cost effectiveness, providing flexibility to the regulated community, ensuring a reliable power supply, and avoiding a windfall for certain source categories. Id [EPA-HQ-OAR-2009-0491-3920[1].1, p.3]
Sunbury generally supports the conceptual methodology underlying the Option 2 allocation approach of modifying allocations so that sources whose heat-input-based allocations would exceed historic emissions do not receive; a windfall. However, Sunbury asserts that EPA has not fully implemented this conceptual methodology in its specific proposed allocation approach, as set forth in the Second NODA, because, under this approach, many low-emitting sources would receive an allocation dictated by a well-controlled-rate emission factor which substantially exceeds their actual emissions. In this way, these sources would receive more allowances than they need to operate in compliance with the Transport Rule and, as such, experience a windfall. Adding further to this inequitable result are the potential implications of the emission allowance trading options described under the Proposed Transport Rule. Depending on the specific trading program provisions in the final Transport Rule, any 'extra' allowances allocated to low-emitting sources under Option 2 may not be fully available for transfer on the market. Similarly, other affected sources whose initial allowance allocations would be insufficient to cover their emissions would be unable to secure through trading the additional allowances they need to continue operating. For these reasons, Sunbury contends that EPA's specific proposed allocation approach under Option 2 is directly inconsistent with EPA's stated key guiding principles for implementing the Transport Rule, including cost-effectiveness, providing flexibility to the regulated community, ensuring a reliable power supply, and avoiding a windfall for certain source categories. [EPA-HQ-OAR-2009-0491-3920[1].1, pp.6-7]
Tampa Electric Company
Tampa Electric supports Option 2 of the most recent Notice of Data Availability. [EPA-HQ-OAR-2009-0491-3959[1].1, p.2]
Tenaska, Inc.
The second option offers an attempt to adjust the allocation to reflect reasonably foreseeable emissions; however, it adds additional complexity because it would require an estimate of the reasonable upper-bound capacity utilization factor for each unit and determination of a well-controlled emission rate. This essentially equates to the difficult task of determining the potential to emit of a unit. While emission limitations are imposed typically in Title V permits for large units, minor sources do not have Title V permits. Moreover, the Title V permits do not always contain heat input limitations. Thus, states will need to exercise judgment and this may lead to disputes. [EPA-R03-OAR-2010-1027-DRAFT-0005.1[1],p.2]
Tennessee Valley Authority (TVA)
  By contrast, a modified Option 2 provides a rational and equitable allocation of allowances by reducing allocations of the low-emitting units to realistic and achievable levels, freeing up allowances for distribution to all other units. [EPA-HQ-OAR-2009-0491-3983[1].1, p.1]
  3) With regard to your request for comments on the other allocation alternatives, we recommend the elimination in Option 2 of the "Well-controlled-rate maximum" for lower-emission rate units. The use of the "maximum historic baseline emissions" within a seven-year baseline (2003 through 2009) would be sufficient to establish allowances at the appropriate level for lower-emission rate units. The use of an assumed, fixed emission rate 0.06 lb/MMBTU for both SO2 & NOx, and of assumed, fixed generation capacity factors appear arbitrary, and will likely result in the calculation of allowance levels for low-emitting units that are much higher than those allowance levels established by the "maximum historic baseline emissions" method alone. We do not see the necessity of providing low-emitting units additional allowances, which they have historically demonstrated they do not need. [EPA-HQ-OAR-2009-0491-3983[1].1, pp.1-2]
Texas Commission on Environmental Quality
Option Two appears to remove allowances from units that installed controls earlier and/or are better controlled and redistribute them to units that were less controlled during the baseline years of 2003 through 2009. Further, there appears to be some redistribution of allocations bused on source type. There appears to be no discernable pattern or purpose to this allocation redistribution in Option Two. Without understanding fully the EPA's premises for Option Two or the assumptions on which the data relies, it is difficult to determine if this complicated allocation methodology meets its intended purpose, and therefore the TCEQ is unable to provide meaningful comment on Option Two at this time. The EPA's alternative allocation tables (Excel files) released with this NODA do not appear to include complete formulas,  which must be found in the Federal Register publication, making the data more difficult to work with, and TCEQ staff has been unable to replicate or understand the EPA's procedures. [EPA-HQ-OAR-2009-0491-4030, p.4]
Virginia Independent Power Producers
Option 2's assumptions may fail to account for the specific contractual obligations of long-term contract generators such as VIPP's members who must operate whenever dispatched by the power purchaser and who lack the ability to pass along the costs of the NOx and SO2 allowances to the offtaker under a long term contract. Additionally, VIPP is concerned that Option 2, as proposed, would introduce a number of potential adjustment factors that likely would result in numerous legal challenges. Such legal challenges could be difficult to resolve in the short time available for EPA to finalize the rule. [EPA-HQ-OAR-2009-0491-3925[1].1, p.2]
Wolverine Power Supply Cooperative
We also strongly support the use of projected future heat inputs in Option 2, because the baseline period represents bad economic times coupled with cool summers in the Midwest, that collectively resulted in depressed electric demand that we do not believe is representative of the future. [EPA-HQ-OAR-2009-0491-4014[1].1, p. 4]
Wolverine is inclined to favor allocation mechanism of Option 2 over that of Option 1, because Option 2 is designed to prevent windfall allocations that exceed historical emissions as well as future projected needs for well-controlled units. [EPA-HQ-OAR-2009-0491-4014[1].1, p. 4]
Response:
EPA is finalizing a method of emissions allowance allocation to individual units under the FIP base on based on that unit's share of the state's historic heat-input, but ensuring that no unit's allocations exceed that unit's historic emissions.  EPA decided to use the allocation methodology originally presented as heat input "option 2" in the January 7, 2011 NODA, modified in response to public comments.  EPA decided to use heat input option 2 but without the application of the "reasonable upper-bound capacity utilization factor and a well-controlled emission rate" factors. See final rule preamble section VII.D for further of discussion EPA's rationale for this approach and response to comments in favor of and in opposition to this approach.
Organization: Tri-State Generation and Transmission Association, Inc.
Comment:
Tri-State Generation and Transmission Association, Inc.
The well controlled emission rate concept discussed in the NODA Option 2 is a useful concept but it must be an emission rate that is reasonably achievable by the units in a given grouping, and must consider the ability of the unit to install and operate the emission controls. Tri-State strongly disagrees that setting a well controlled emission rate for NOx or S02 at a coal fired unit at 0.06 lbs/MMBtu could be reasonably achieved. There are only a few new and retrofitted units in the United States that meet this assumed limit and to date, manufacturer/vendors will not give guarantees that units can meet these emissions rates. To ensure 100% compliance 100% of the time, EOUs will need to target achieving emission rates of 0.03 - 0.04 lbs/MMBtu on a regular basis so they can be assured of meeting this value. For many EOUs, this would be an insurmountable challenge. Tri-State also believes that a well controlled emission rate that is reasonably achievable should be linked to a reasonably achievable time frame. [EPA-HQ-OAR-2009-0491-3902[1].1, pp.4-5]
The time frames set forth in the NODA are unrealistic and unachievable. [EPA-HQ-OAR-2009-0491-3902[1].1, p.5]
Response:
EPA is finalizing a method of emissions allowance allocation to individual units under the FIP base on based on that unit's share of the state's historic heat-input, but ensuring that no unit's allocations exceed that unit's historic emissions.  EPA decided to use the allocation methodology originally presented as heat input "option 2" in the January 7, 2011 NODA, modified in response to public comments.  EPA decided to use heat input option 2 but without the application of the "reasonable upper-bound capacity utilization factor and a well-controlled emission rate" factors. See final rule preamble section VII.D for further of discussion EPA's rationale for this approach and response to comments in favor of and in opposition to this approach.

XX.A.2. Unit-level Comments on Data

Organization: AES Corporation (AES)
Comment:
AES Corporation (AES)
The Shady Point facility (ORIS 10671) is missing Heat Input for 2009 and inaccurate (low) for the other four years. A mechanism is needed to repair these issues. [EPA-HQ-OAR-2009-0491-4016, p. 4]
The Beaver Valley facility (ORIS 10676) data for annual Heat Input for 2005, 2006, and 2007 are actually the ozone season Heat Input. This results in a much lower allocation. A mechanism is needed to repair these issues. [EPA-HQ-OAR-2009-0491-4016, p. 4]
Red Oak (ORIS 55239) and Ironwood (ORIS 55337) are CCGTs that have seen a three and four fold increase in demand in the past two years. This will require many more allowances than in the baseline period in the option 1 and 2 proposals. This very recent market change has been dramatic and should be rectified in this rulemaking. The EPA should allow for extraneous circumstances and approve alternate baseline periods that more closely reflect the current operation of the facilities. The use of 2010 data and averaging two years instead of three are examples of potential alternate baselines. [EPA-HQ-OAR-2009-0491-4016, p. 4]
Response:
EPA has updated its final allocation tables to be consistent with the final allocation methodology in the Transport Rule that is described in section VII.D of the preamble.  The Shady Point facility has 2009 heat input.  Furthermore, the heat input baseline includes 2010 which addresses some of the commenter concerns regarding the capture of increased facility operation in the baseline period.  In regards to Beaver Valley, the allocation methodology uses the three highest years among the five year baseline.  This would apparently include 2008, 2009, and 2010 for Beaver Valley if the source feels that the pre-2008 values are understated.  EPA made corrections to data in instances where corrected data was provided by commenter with explanation on why it was superior to that previously reported to EPA.
Organization: American Electric Power
we energies
Luminant
Comment:
American Electric Power
NODA-3 requests comment on two alternative allocation options. However, the input errors identified in the original proposal and subsequent NODAs have not been corrected, and the resulting IPM model runs based on this incorrect data do not provide a valid basis for comparison. EPA has simply used the invalid and inaccurate state budgets from the original proposal. Until new model runs are completed, based on the information received during comment periods to correct the inaccuracies in the database and the control addition or retirement assumptions made by EPA, the public has no basis to evaluate the ultimate requirements and submit informed comments. While the allocation formulas described in NODA-3 are more easily verified because they use data currently reported to the Agency, the incorrect original IPM model output does not provide a basis for evaluation of what the actual allocations will be. [EPA-HQ-OAR-2009-0491-3934[1].1, pp.3-4]
Luminant
 Luminant believes that the assumptions and projections made in the modeling for this rulemaking are inconsistent with available information and data. EPA should update and correct the assumptions and modeling prior to proceeding with the rulemaking.   [EPA-HQ-OAR-2009-0491-3980[1].1, p.2]
The Integrated Planning Model Results Create Erroneous Predictions
The Integrated Planning Model results that EPA has made available imply a number of surface mines will no longer operate after 2011. However, Luminant has just permitted a new mining area (Turlington Mine) to supply Big Brown plant. Also, we have permitted a new lignite surface mine (Leesburg Mine) to supply Monticello plant. Not all Texas coal-fired units can fire 100% subbituminous coal by 2012.[EPA-HQ-OAR-2009-0491-3980[1].1, p.4]
we energies
As identified by We Energies in September 2010, the data used by the agency contained numerous errors, missing values and other data issues with respect to the electric generating units ("EGUs") we operate, and the agency's modeling was based on outdated assumptions. Corrected data was provided as an attachment to our original comments. [EPA-HQ-OAR-2009-0491-3976[1].1, p.1]
Alternatively, We Energies requests that EPA, 1) correct all inaccuracies in its data set, 2) update all modeling assumptions and 3) re-run the models to establish updated state budgets and proposed unit allocations. [EPA-HQ-OAR-2009-0491-3976[1].1, p.2]
Because of the significant impact this rule and its allocations will have on We Energies and other EGUs, we recommend that EPA should re-propose the rule with all the data deficiencies corrected. Given corrections of the data issues identified, along with proper recognition of emission control equipment installations made to date or in progress, an updated rule proposal would probably identify a modified future attainment scenario and implementation schedule. This possibility was identified in our September 2010 comments wherein we identified modeling and analyses performed by Alpine Geophysics and Environ Corp. that had been presented to the Lake Michigan Air Directors Consortium. There is no recognition in the current NODA that this information was considered. [EPA-HQ-OAR-2009-0491-3976[1].1, p.2]
Response:
In the final Transport Rule, EPA has updated its IPM modeling and used the updated modeling to determine state emission budgets.  These modeling updates reflect comments received during the comment period that corrected data inaccuracies and that would have a significant impact on the modeling.  The final allocations are based off budgets that were determined using the updated IPM model.  However, as EPA explained in the January 7, 2011 NODA, EPA wanted to give sources a chance to review and comment on data that would potentially be used in the final Transport Rule allocations under a FIP.  The purpose of the NODA was not to convey final, updated budgets, but to provide sources with a chance to provide additional comment on allocation methodology and underlying data.  See section VII.D of the preamble for a description of the final allocation methodology and the TSD for Allowance Allocation for a list of potential existing Transport Rule units and their allocations under a FIP.
Regarding Luminant's comment, EPA understands that for any mine-mouth lignite unit there could be a need for additional coal handling systems and improvements to any existing rail spur serving the site in order to receive large trainloads of subbituminous coal in lieu of the lignite currently delivered from nearby mining operations. However, EPA also understands that, except for the coal handling systems, any unit designed to burn a low rank coal like lignite can burn higher rank subbituminous coal with only a few relatively minor changes to the boiler and its related systems. This is because a lignite unit is in almost all respects "over designed" for the requirements of a higher rank coal. For a switch from lignite to subbituminous, the primary boiler improvement needed might only be the simple addition of modern "intelligent sootblowing" systems to manage the effects of "ash reflectivity" in the boiler furnace and convection pass with subbituminous. EPA believes that with such relatively minor boiler improvements a switch from lignite to subbituminous should result in no derating of electrical output, improved boiler efficiency, and reduced stack emissions.
Organization: Associated Industries of Massachusetts (AIM)
Comment:
Associated Industries of Massachusetts (AIM)
Additionally, Massachusetts seems to be unfairly targeted by EPA. Under the alternative options in the NODA, facilities in Massachusetts are allocated SO2 allowances based on a 0.043 lb/mm Btu SO2 emission rate, which is much lower than the effective emission rate in most other states. EPA's allowance allocations should not be based on emission rates that are below levels that can be achieved by state-of-the-art control technology. [EPA-HQ-OAR-2009-0491-3906[1].1, p.2]
Response:
In the final Transport Rule, Massachusetts was not identified as a contributing upwind state.  Therefore, it is not subject to the final Transport Rule and has not Transport Rule state emission budgets.
Organization: City of Ames, Iowa
Comment:
City of Ames, Iowa
The original allowance allocations (Sept 1, 2010) granted us 1,154 tons of NOx allowances.

Under options 1 & 2, our emissions allowances are greatly reduced due to the calculation methods and our relative small size compared to the other EGUs in our state. The percentage decrease in NOx allowances from the original proposal to options 1 & 2 is on average 35% (706 or 765 tons of NOx respectively)

Our historic emissions for NOx are:

Year  NOx
2005 1,380
2006 1,296
2007 1,212
2008 1,129
2009 944
[EPA-HQ-OAR-2009-0491-3942-cp, p.1]
Response:
See section VII.D of the preamble for a description of the final Transport Rule allocation methodology.  The TSD for Allowance Allocation also describes the list of potentially covered Transport Rule units and their allocation under a FIP.  EPA has reviewed the NOX emissions data noted above and confirmed that it matches the values being used in its allocation tables for the historic emissions baseline.  Furthermore, EPA notes that while the historic emission are correctly recorded, that for many units the allocation will be lower than historic emission levels.  Having allocations lower than historic emission levels is a necessary component of a program seeking emission reductions.
Organization: City of Tallahasse
Lafayette Utilities System
Madison Gas and Electric Company (MGE)
Illinois Environmental Protection Agency
Great River Energy
Edgecombe Genco, LLC
Indiantown Cogeneration, L.P.
Northshore Mining Company
Edison Mission Energy (EME)
Spruance Genco, LLC
Kansas City Board of Public Utilities (BPU)
Comment:
City of Tallahasse
Option #2 attempts to correct this disadvantage to utilities that have spent significant resources to install control equipment to meet emissions reduction targets (such as CAIR). However, what Option #2 does not address is the retiring of more inefficient units which have been replaced promptly by more efficient and cleaner units. In the case of the City's Hopkins Generating Station, allowances were allocated to Unit 2A on the basis of emissions from the 2008 and 2009 timeframe. However, in the year 2008, Unit 2A did not initiate operation until May 2008 and therefore operated only part of the year (approximately June to December 2008). Thus the heat input data from this time does not accurately represent actual annual operation. Yet this data was averaged with a full year of operation (2009) and was used as the basis for allocations for the unit. This unfairly limits the amount of allocations that the unit would have received, as the average is not weighted to account for partial years of operation. [EPA-HQ-OAR-2009-0491-3912[1].1, p.3]
Edgecombe Genco, LLC
Specifically, Edgecombe is providing corrections to the underlying heat input and emissions data used to calculate the allocations. [EPA-HQ-OAR-2009-0491-3971[1].1, p.1]
The allocation tables calculate the baseline heat input as the average of the three highest years between 200S and 2009. However, the data presented in the Annual Heat Input columns from 200S to 2007 is actually the ozone season heat input, which was reported to CAMD under the NOx Budget Program. Edgecombe was not able to obtain all of the archived data prior to the comment date; however, we will provide this data prior to finalization of the allocations if one of the heat input-based allocation schemes is chosen. [EPA-HQ-OAR-2009-0491-3971[1].1, p.1]
Edison Mission Energy (EME)
EME hereby submits the data needed for EPA to perform the calculations under the two methodologies proposed in the Transport Rule NODA. [EPA-HQ-OAR-2009-0491-3953[1].1, p.3]
Great River Energy
Further, EPA has updated the state emission sources and has again used incorrect information for our emission units. Specifically, the data from the model included only one entry for our combustion turbine facility St. Bonifacius. This facility consists of two combustion turbines serving one electric generator. The combined output of the facility is nominally 50 MW. The data from the model only included the data from one of the combustion turbines. Details of both units are included in Table 1. [EPA-HQ-OAR-2009-0491-3898[1].1, p.2] [[See Docket Number EPA-HQ-OAR-2009-0491-3898[1].1, p.3 for Table 1.]]
In summary, Great River Energy requests that EPA fix the data inaccuracies associated with our emission units as explained herein. [EPA-HQ-OAR-2009-0491-3898[1].1, p.5]
Illinois Environmental Protection Agency
Accordingly, the heat input for Dallman Unit 4 should be 13,000,000 mmBTU/year and 6,000,000 mmBTU/ozone season. Also, the total heat input for all units in Illinois should be increased by these corresponding amounts before allocations to individual units are calculated. [EPA-HQ-OAR-2009-0491-3899[1].1, p.1]
Indiantown Cogeneration, L.P.
Specifically, Indiantown is providing corrections to the underlying heat input and emissions data used to calculate the allocations. [EPA-HQ-OAR-2009-0491-3954[1].1,p.1]
The allocation tables calculate the baseline heat input as the average of the three highest years between 2005 and 2009. However, Indiantown was not subject to any allowance trading programs and, therefore, did not submit data to CAMD prior to 2008. The tables use the 2008 and 2009 data only to generate the baseline heat input. This results in lower baseline heat input than it should be since those were historically low generation years for the facility. The NODA indicates that for facilities that were not subject to the EPA allowance trading programs, EPA used historic heat input data as submitted to the Energy Information Administration (EIA). Indiantown has provided this missing data in the attached tables and requests that these data be used to calculate the baseline heat input. [EPA-HQ-OAR-2009-0491-3954[1].1, p.1] [[See Docket number EPA-HQ-OAR-2009-0491-3954[1].1, pp. 2-7 for the tables.]]
In the same way, the tables are missing Annual and Ozone Season NOx and Annual SO2 and NOx Emissions data from 2003 through 2007. This data has been provided from the facility's annual emissions inventory data and we request that this information be used to calculate the facility's allowances under the selected allocation scheme. [EPA-HQ-OAR-2009-0491-3954[1].1, p.1]
Kansas City Board of Public Utilities (BPU)
[Attachment 1 (7 pages) can be found at the end of this comment.]
Lafayette Utilities System
For instance, EPA used the 2005,2006, and 2009 annual heat input data from LUS's Bonin Unit 3 to calculate the unit's average heat input, even though the year 2006 data was based on a year when the Bonin Unit 3 did not produce any electricity. A table of Bonin Unit 3' s annual heat input during the entire baseline period is provided below: