The final rule covers fossil-fuel-fired units serving generators with a nameplate capacity greater than 25 MWe producing electricity for sale and defines "fossil-fuel-fired" as combusting any amount of fossil fuel in 2005 or later.  The commenter claimed that biomass units that switch from burning some fossil fuel to burning no fossil fuel should be exempt just as new units that never burn fossil fuel are not covered by the Transport Rule trading programs.  EPA rejects the commenter's claim.  The approach in the final rule is consistent with the approach used in prior EPA trading programs covering the electric generation industry, e.g., the Acid Rain Program, the NOx Budget Trading Program, and the CAIR trading programs.  The commenter did not provide any basis for using a different approach in the Transport Rule trading programs covering the same industry.  Moreover, the commenter essentially suggested that the determination of whether a given biomass unit is subject to the Transport Rule trading programs should not be based on any historical information on whether the unit burned any fossil fuel, but rather only on what the unit is currently burning.  This approach would mean that, for all biomass units, owners and operators, and EPA, would not know at the start of the Transport Rule trading programs, whether the units were subject to the trading programs and that the units' regulatory status could change, and the units become subject to the trading programs, at any time that any fossil fuel was combusted.  Because all biomass units would not be reporting their fuel use to EPA until they became subject to the trading programs, the determination of whether specific units were subject to the trading programs, and assurance of compliance, would be problematic.  EPA believes that its approach is reasonable: biomass units that have recently (i.e., after 2004) operated burning some fossil fuel are treated differently than new biomass units that are initially designed to operate without combusting any fossil fuel and actually operate without any fossil fuel combustion.  The units burning fossil fuel after 2004 are more likely to continue to do so.  EPA maintains that it is reasonable to make these biomass units, like any other units burning at least some fossil fuel after 2004, subject to the Transport Rule trading programs.  Similarly, EPA believes it is reasonable to treat a biomass unit that has not burned and does not burn any fossil fuel (like any other units that have not burned and do not burn) any fossil fuel as not subject to the Transport Rule trading programs, unless and until they begin burning fossil fuel.
The commenter also claims that all biomass units whose fossil fuel use is less than 10% should be exempt from the Transport Rule trading programs.  EPA rejects commenter's claim.  As discussed above, the approach in the final rule is consistent with the approach taken in the Acid Rain Program and the CAIR trading programs, and the commenter failed to show why a different approach is warranted here.  Further, the commenter failed to explain the basis for the suggested 10% level.  As noted by the commenter, the NSPS regulations refer to a 10% level of fossil fuel use in connection with certain NOx (but not SO2) emission requirements for certain types of units.  However, the exemption from NOx emission requirements based on the unit having annual capacity factor for coal, oil, and natural gas of 10% or less is limited to industrial, commercial, and institutional steam generating units and does not apply to electric utility steam generating units.    Compare  40 CFR 60.44Da (setting NOx emissions standard for electric utility steam generating units, without any exemption for units with 10% or less fossil fuel use) and 60.44b (setting NOx emissions standards for industrial, commercial, and institutional steam generating units, with an exemption for units with 10% or less fossil fuel use).  The use of the 10% cutoff in a different set of regulations applicable to a different category of units does not support the commenter's claim that the 10% level should be used to exempt certain units from the Transport Rule emission reduction requirements.  Moreover, the commenter failed to specify, much less justify, any period of time during which fossil fuel use would have to be less than 10%.  If the applicability of the Transport Rule trading programs for all biomass units were to depend on whether the unit's fossil fuel use, during some period, exceeded 10% of total fuel use, such units' regulatory status could change during the course of the year.  A unit's fossil fuel use can vary, depending on, among other things, changes in unit operation and fuels.  As noted by the commenter, some units use fossil fuel for startup and combustion stabilization, and so fossil fuel use can vary depending on the frequency of startups and shutdowns and on factors (such as the moisture content and other characteristics of the other fuels being combusted) affecting the need for combustion stabilization.  A unit that was excluded from the Transport Rule trading programs because of its below-10% fossil fuel use would not report fuel use to EPA, and so determination of which units were subject to the trading programs, and assurance of compliance, would be problematic.
With regard to units serving generators with nameplate capacity at or below 25 MWe, see sections VII.B, IX.A and B, and X of the preamble.
Organization: State of Connecticut
Comment:
State of Connecticut
EPA should move forward and adopt strong national rules for all air pollution sources that contribute to interstate air pollution transport, not just electric generators as proposed in the Transport Rule. For example, the Ozone Transport Commission, of which Connecticut is a member, has repeatedly asked EPA to move forward with national rules limiting pollution from industrial, commercial and institutional boilers. [EPA-HQ-OAR-2009-0491-2534.1 p.2]
Response:
See sections VI.A, VII.B, IX.A and B, and X of the preamble.
Organization: State of Delaware Department of Natural Resources & Environmental Control
Comment:
State of Delaware Department of Natural Resources & Environmental Control
Co-generation Unit Exemption. In the preamble to the proposed rule EPA requested comments regarding the length of the historic period that would be appropriate for a 'look back' to determine if a unit met the efficiency and generation requirements to be eligible for the co-generation unit exemption provided for in the proposed rule. EPA is proposing the use of November 15, 1990 or the date on which the unit first produces electricity, whichever is later, as the date for which the unit must have started meeting the efficiency and generation requirements to be defined as a co-generation unit. In the preamble to the proposed rule EPA indicates that it may be difficult for some units to produce historic data of that age, and requests comments on utilization of a later date. Delaware agrees that the 'look back' period for co-generation unit exemption determination should be shorter than the EPA has included in the proposed rule. Specifically, Delaware believes the 'look back' period for determination of eligibility for the co-generation unit exemption should be the later of the calendar year prior to the effective date of the rule or the first full calendar year after the unit first produces electricity. Using this one year 'look back' for determination of co-generation exemption eligibility would make this requirement more consistent with proposed rule's requirement for co-generation units to re-qualify for the exemption on an annual basis. [EPA-HQ-OAR-2009-0491-2980.1, p.6]
Opt-in Provisions. Somewhat related to the issue of including the smaller size units in a proposed program is the concept of opt-in provisions in the proposed rule. EPA has requested comments regarding the appropriateness of the proposed rule's opt-in provisions. While Delaware does not necessarily oppose the opt-in provisions, Delaware is skeptical that the opt-in provisions would provide sufficient incentive for a source to make the commitment to perform an emission reduction project that would not have occurred anyway without the opt-in provisions. In this event, additional allowances would have been created without any environmental benefit as a direct result of the rule. In any event, it is Delaware's opinion that if the proposed rule addresses the smaller units (EGUs 15MW<>25 MW, co-generation units > 15MW, and ICI boilers > 250 MMBTU/hr) then the population of likely opt-in units will be greatly reduced. [EPA-HQ-OAR-2009-0491-2980.1, pp.9-10]
Response:
With regard to the cogeneration unit exemption, see section VII.B of the preamble.  As discussed in the preamble, EPA is using 2005 as the start of the lookback period because this will provide about 5 years of data, which is consistent with the recordkeeping requirements under the CAA title V permit provisions and provides a representative period for units that have been operating more than 5 years.   The commenter's suggestion of using only one year (i.e., 2011) before the start of the Transport Rule trading programs lacks these advantages.
With regard to opt-in units, see section VII.B of the preamble.
Organization: State of Wisconsin, Department of Natural Resources
Comment:
State of Wisconsin, Department of Natural Resources
As part of this effort to address the Court directed progress, EPA needs to clarify emission sectors in contributing states that are significant relative to the EGD sector including at a minimum ICI boilers, cement kilns and other large non-EGD point sources using fossil fuels. [EPA-HQ-OAR-2009-0491-2829.2, p.2]
Response:
See sections VI.A, VII.B, IX.A and B, and X of the preamble.
Organization: Tenaska, Inc.
Comment:
Tenaska, Inc.
Finally, the Proposed Transport Rule should offer opt-out provisions which: (1) allow low-emitting units to operate outside the state budget with a commensurate reduction in that state budget; and (2) allow natural gas units to opt out of the state sulfur dioxide (SO2) budget altogether. [EPA-HQ-OAR-2009-0491-3705,p.4]
The Transport Rule Should Allow Low-Emitting Units to 'Opt Out.'
The ultimate way to reduce a state's contribution to non-attainment in a neighboring state is to have the lowest-emitting units operate more. One way to effectuate that principle is to allow units meeting the definition of 'low-emitting source' to operate unrestricted under the Transport Rule budgets subject instead to a stringent emission limitation. In order to keep the state budget intact, any allocation to a unit that opts out would be subtracted from the budget. For example, meeting BACT limits should not be subject to the rule. Similarly, units that have permit conditions limiting their fuel to pipeline quality natural gas should be able to opt out of the Proposed Transport Rule SO2 trading program. This feature would encourage owners to achieve state-of-the-art emissions performance while reducing the administrative burden of the program and associated costs. [EPA-HQ-OAR-2009-0491-3705, pp.17-18]
Response:
The commenter suggests that "low-emitting" units in each state should be allowed to operate outside of the state budgets.  The commenter failed to explain exactly how this would be implemented.  However, the commenter's approach would effectively exempt these units from the Transport Rule trading programs.  The state budgets would not cover these units and so the units would not be allocated allowances and the units' owners and operators would not be required to hold allowances to cover the units' emissions.  Because the units would therefore have no emission reduction requirements, presumably the owners and operators would not have to report their emissions to EPA.
EPA rejects commenter's suggestion for several reasons.  The commenter failed to provide a basis for excluding so-called "low emitting" units from the Transport Rule trading programs and failed to explain what level of emissions would make a unit "low -emitting" and to provide any basis for selecting a level.  Specifically, with regard to units included in the Transport Rule trading programs for SO2 (and natural-gas-fired units in particular), the commenter failed to explain what emissions level should be used as the cutoff for including or excluding units from the program.  The commenter also failed to take account of the fact that many natural-gas-fired units are dual-fuel-fired units in that they can also combust oil, which when burned results in significantly higher emissions than natural gas; the mere fact that a unit is generally natural-gas-fired does not guarantee that its emissions will be "low".  EPA notes that historically natural-gas-fired units have been included in SO2 trading programs , such as the Acid Rain Program and the CAIR trading program, and the commenter failed to explain why these units should now be excluded from the Transport Rule trading programs.
More generally, while some units may have relatively low emission rates, that is not a reasonable basis for eliminating the units from the Transport Rule trading programs because it is mass or tons of emissions (not emission rates) that contribute to a state's significant contribution or interference with maintenance, which the final Transport Rule is aimed at eliminating.  Further, a unit's level of emissions can vary depending on the type of fuel combusted, the amount of hours that the unit is operated, and the level of operation of any emission controls.  A unit that might emit at one point of time or during one period at the commenter's unspecified "low emissions" level would not necessarily continue to emit at that level and could have higher emissions at another point of time or during another period.  The commenter failed to suggest a required period for "low emissions", much less providing any basis for selecting such a required period.  Moreover, if "low-emitting" units were exempt from the Transport Rule trading programs and did not report their emissions, EPA would have no way of determining whether the units were continuing to be "low emitting".  In addition, if all "low emitting" units were excluded from the trading programs, utilization for electric generation, and the resulting emissions, could shift to those units from covered units because of the high level of integration of the electric generation, transmission, and distribution system (which has increased with the significant restructuring and deregulation of electric utilities) and thereby threaten achievement of elimination of states' significant contribution and interference with maintenance, which is the goal of the Transport Rule.  Although the exemption of any portion of the electricity generation sector creates the potential for generation shifting, the greater the number and scope of the exemptions, the greater the likelihood and likely magnitude of the potential generation shifting.  After the balancing the commenter's claimed rationale for the requested exemption and the potential adverse effect of such an exemption, EPA rejects the commenter's position and maintains that its approach -- of including all fossil-fuel-fired units serving a generator with a nameplate capacity of over 25 MWe producing electricity for sale and providing for units with low mass emissions alternative monitoring methods that are less expensive than continuous emission monitoring systems -- is a reasonable approach that avoids the above-described flaws in the commenter's vague suggestion of excluding these unit.  EPA also notes that the inclusion of these units (including "low-emitting" units) in the Transport Rule trading programs provides strong economic incentives for units to achieve state-of-the-art emissions performance because the units' owners and operators must hold allowances covering the units' emissions and can sell any allowances that are not needed for covering these emissions.
Organization: Texas Chemical Council
Comment:
Texas Chemical Council
II. The Transport Rule Should Exclude Cogeneration Facilities
In the preamble, EPA states that it is committed to meeting the challenge of achieving "a truly efficient, reliable, cost-effective electric power system." 75 Fed. Reg. at 45,229. Cogeneration  -  also known as recycled energy  -  is the simultaneous production of two or more forms of energy from a single fuel source. Cogeneration plants often operate at 50 to 70 percent higher efficiency rates than single-generation facilities. The cogeneration process uses otherwise wasted heat to produce additional energy, such as to provide heat or electricity for the plant in which it is operating. Cogeneration is both the present and future of energy efficient electricity production, and it also benefits the environment by recycling waste heat, thus preventing additional fossil fuels from being burned. Based on the efficiency, reliability and cost-effectiveness of the typical cogeneration operation, cogeneration should be exempt from any proposal such as the Transport Rule, the effect of which would only limit cogeneration's use and effectiveness. [EPA-HQ-OAR-2009-0491-2815.1, p.2]
Co-located cogeneration units are the primary source of steam for the host petrochemical facility. If the cogeneration operations are limited, then natural gas fired boilers will need to be operated to provide steam. Furthermore, limiting the operation of cogeneration units during the ozone season lowers the electrical output when the demand on the grid is at the highest. In the case of the Houston-Galveston-Brazoria (HGB) nonattainment area, that would likely lead to higher utilization of the coal-fired units or natural gas fired boilers. This in turn would lead to higher emissions. Including cogeneration in the proposed rule and limiting the amount of energy that may be produced by cogeneration is absolutely contrary to EPA's commitment to achieving an efficient, reliable, cost-effective electric power system. [EPA-HQ-OAR-2009-0491-2815.1, p.2]
Cogeneration facilities should also be exempt from the rule proposal because limiting the use of cogeneration directly contradicts the federal Public Utility Regulatory Policies Act (PURPA). PURPA Section 210 requires utilities to purchase excess electricity generated by qualifying facilities (QFs) and to provide backup power at a reasonable cost. QFs include plants that use renewable resources and/or cogeneration technologies to produce electricity. As discussed more fully below, EPA cannot simply put a new regulatory program in place that effectively ignores a class of highly energy efficient cogenerators that the Federal Energy Regulatory Commission (FERC), under its PURPA mandate, is tasked with protecting and encouraging. It is precisely because FERC's regulatory program under PURPA promotes the development of energy efficient cogeneration that EPA should not undercut PURPA by creating new rules that unduly burden the protected class of QFs . Instead, EPA must find ways to harmonize its mission with FERC's mandate under PURPA. [EPA-HQ-OAR-2009-0491-2815.1, p.3]
Obviously, the best way to do this is to exempt all cogeneration QFs entirely from the proposed Transport Rule. This makes particular sense given that the current cogeneration exemption from electric generating unit (EGU) status, as well as the proposed cogeneration exemption, are both based on FERC's cogeneration standards under PURPA. In particular, the exemption relies on the operating and efficiency standards for cogenerators established by FERC under PURPA. [EPA-HQ-OAR-2009-0491-2815.1, p.3]
Short of exempting QFs from the proposed Transport Rule, EPA must ensure that QFs at least have the same access to emissions allowances as under the current CAIR regulatory program. Otherwise, EPA will have created a situation in which coal-fired generators would be made whole with respect to emissions allowances, while clean-burning, energy efficient QFs will be subjected to additional economic burdens. Put another way, unless EPA finds a means of avoiding unnecessary conflict with the PURPA mandate, the result will be two federal agencies working at cross-purposes with respect to the promotion of energy efficiency  -  a result that Congress and this Administration could not have intended. [EPA-HQ-OAR-2009-0491-2815.1, p.3]
III. Cogeneration Facilities Should Not be Required to Submit Data Dating Back to 1990
In the preamble, EPA asked for specific comment on whether it will be problematic for cogeneration facilities to obtain sufficiently detailed information about 1) unit efficiency and operation, and 2) electricity sales information dating back to November 15, 1990. 75 Fed. Reg. at 45,307. TCC's position is that it would be extremely difficult for companies to obtain this information dating back to 1990, and there is no real justification for requiring information dating back this far. [EPA-HQ-OAR-2009-0491-2815.1, p.3]
The proposed regulation excludes cogeneration facilities meeting certain efficiency and operating requirements, as well as sales limitations of electricity to the utility power distribution systems. This exclusion is contingent on obtaining data for assessment purposes beginning in 1990 or the start-up of the unit, whichever is later. In many cases, cogeneration facilities are older energy systems that are integrated with large industrial complexes. Data availability is limited to the type of data collection system installed at each respective facility. These older data collection systems have not always captured the required data to perform these assessments electronically. This lack of electronic data would necessitate evaluating this data by hand, if hardcopy charts and graphs are still available. Local utility power distribution networks were also contacted to obtain relevant data for the specified time period. The Electric Reliability Council of Texas (ERCOT) suggested that the only available data, electrical sales data, would only be available for the time period 2000-present. To the extent that all required data is available, the burden in obtaining this historical data far outweighs the benefit derived from the data itself. [EPA-HQ-OAR-2009-0491-2815.1, pp.3-4]
In addition, many companies have record retention policies that, consistent with other regulatory guidance, require records be kept for five years. For example, Title V Permit recordkeeping requirements and recordkeeping requirements contained in the Clean Air Interstate Rule, 40 CFR § 96.106(e), require records to demonstrate compliance for a period of five years. Moreover, many companies do not have the data required to perform a full assessment of applicability under 40 CFR § 97.504 going back to 1990. Therefore, it is unreasonable and inconsistent with established regulations to require industry to analyze data that no longer exists or is not readily available. [EPA-HQ-OAR-2009-0491-2815.1, p.4]
Furthermore, we recommend that both the unit efficiency and operating standards and the electricity sales data be limited to more recent years by requiring that the unit efficiency and operation standards and the sales limit be met annually at either a more recent year, such as January 1, 2006, or the start-up of a unit's combustion chamber. Historical data dating back to 1990 is neither consistent nor reflective of current operations. Many cogeneration and combustion devices have been upgraded with state-of-the-art nitrogen oxide (NOx) control technology such as low NOx burners, selective catalytic reduction (SCR), and flue gas recirculation to reduce emissions. Consistent with current regulatory recordkeeping requirements, applicability determinations for this regulation must be evaluated based on current data rather than historical data. Therefore, we recommend that applicability determinations be performed based on the last five years worth of data. [EPA-HQ-OAR-2009-0491-2815.1, p.4]
IV. EPA's Annual Standards Should Not Apply to Units Not in Operation
EPA has also requested comment on whether the annual operating and efficiency standards in the definition of "cogeneration" should be applied to a calendar year when the unit did not operate at all. 75 Fed. Reg. at 45,307. It is TCC's position that they should not. [EPA-HQ-OAR-2009-0491-2815.1, p.4]
Under the EPA's proposal, a source could not meet the definition of a cogeneration facility if it was shut-down for an entire calendar year. Cogeneration facility outages could exceed one calendar year based on financial, repair, or other unforeseen requirement. Facilities that do not operate, and therefore have no covered emissions, should not be adversely impacted by this regulation. The regulation is intended to reduce emissions from facilities to prevent downstream impacts on other air sheds. If cogeneration facilities are not operating, nor emitting covered pollutants, there can be no adverse impact on these air sheds. Therefore, facilities that do not operate for a given year, that otherwise would meet the cogeneration exclusion, should be allowed to continue operation provided that the regulatory burdens are met upon start-up. [EPA-HQ-OAR-2009-0491-2815.1, p.4]
Response:
See section VII.B of the preamble.  EPA rejects the commenter's position that all cogeneration facilities (including all QF cogeneration facilities) should be exempt from the Transport Rule trading programs.  The commenter claims that such units are efficient and should be exempt from the Transport Rule trading programs.  In the final rule EPA exempts those cogeneration units that meet certain requirements.  First, the units must meet certain operating and efficiency requirements, and the commenter failed to show that these requirements are unreasonable.  EPA believes that it is reasonable to limit the cogeneration unit exemption to units that demonstrate their efficiency.  Second, the units must meet the electricity sales limitation.  Those units that sell less than the electricity sales limitation are treated as industrial, rather than electric generation, units and are exempt because the final rule is aimed at the electric generation sector. The commenter failed to show that any of these requirements are unreasonable.  In addition, if all cogeneration units or all QF cogeneration units were excluded from the trading programs, utilization for electric generation, and the resulting emissions, could shift to those units from covered units because of the high level of integration of the electric generation, transmission, and distribution system (which has increased with the significant restructuring and deregulation of electric utilities) and thereby threaten achievement of elimination of states' significant contribution and interference with maintenance, which is the goal of the Transport Rule.  Although the exemption of any portion of the electricity generation sector creates the potential for generation shifting, the greater the number and scope of the exemptions, the greater the likelihood and likely magnitude of the potential generation shifting.  After the balancing the commenter's claimed rationale for the requested exemption and the potential adverse effect of such an exemption, EPA rejects the commenter's position and maintains that the approach in the final rule is reasonable.
EPA maintains that the treatment of QF cogeneration units in the final Transport Rule is not inconsistent with PURPA.  PURPA addresses the prices of electricity that QFs produce and sell, not their emission requirements.  In fact, in the Acid Rain Program under CAA title IV, Congress did not exempt all QF cogeneration units from the program, but rather limited the QF cogeneration unit exemption to those units meeting certain requirements (such as having a power purchase agreement as of November 15, 1990 or meeting an electricity sales limitation).  Moreover, under the final Transport Rule, those QF cogeneration units that are not covered by the cogeneration unit exemption have reasonable access to allowances.  The commenter failed to show otherwise.  See section VII.D of the preamble.
Organization: TransCanada
Comment:
TransCanada
Comment 4: Non EGUs and Emission Units Less Than or Equal to 25 MW Should be Included in the Proposed Transport Rule
Under the proposed Transport Rule, certain units' emissions that contribute significantly to downwind fine particulate matter and ozone maintenance, and that are presently regulated under CAIR, are not captured or regulated. TransCanada urges the Agency to include these sources in the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2827.1, p.3]
The proposed Transport Rule applies only to those facilities that serve a generator with a nameplate capacity of more than 25 MW or those that opt-in to the program. The source emissions from non-EGU facilities and EGUs whose nameplate capacity is 25 MW or less significantly contribute and interfere with maintenance of downwind states' NOx and SO2 emissions transport problems. [EPA-HQ-OAR-2009-0491-2827.1, p.3]
CAIR, which was generally implemented through State Implementation Plans ("SIP"), allowed states to include sources equal to or less than 25 MW and non-EGUs. These sources should also be included in the proposed Transport Rule, which would ensure that the smaller EGUs and non-EGUs that are contributing and interfering with downwind maintenance are also contributing to reducing contributions to downwind maintenance. Adding these parties to the proposed Transport Rule could provide compliance flexibility and make for a more robust market for allowances, which may influence companies decisions on implementing emission controls. [EPA-HQ-OAR-2009-0491-2827.1, p.3]
Response:
See sections VI.A, VII.B, IX.A and B, and X of the preamble.  The final rule gives states the option of expanding the applicability provisions of the Transport Rule NOx ozone season trading program to include units serving generators with a nameplate capacity of 15 MWe or greater producing electricity for sale.  This is consistent with the approach taken in the NOx Budget Trading Program, where some state elected to include units serving generators with a nameplate capacity of 15 MWe or greater producing electricity for sale.
Organization: United States Clean Heat & Power Association (USCHPA)
Comment:
United States Clean Heat & Power Association (USCHPA)
Second, define (and qualify) recycled energy, sometimes known as "bottoming-cycle" CHP. By qualifying CHP only according to an efficiency measure based on energy input, EPA's proposed rules reject recycled energy projects that have no fuel inputs because they capture waste heat and pressure drops. A bottoming-cycle project burns no incremental fuel and emits no additional pollution. Legislative tax proposals specifically except recycled energy from CHP's efficiency requirements because of the mathematical impossibility of dividing by zero, which is the fuel input of a bottoming-cycle CHP project. EPA should adopt similar exemptions. [EPA-HQ-OAR-2009-0491-2823.1, p. 2]
Third, remove the sales restriction associated with CHP. Whether the purchaser of the CHP power is the grid or an industrial facility makes no difference to pollution output. EPA's proposal stipulation that CHP facilities can sell no more than a third of its output to the grid is arbitrary. The provision seems to confuse commercial considerations with technical ones. The decision to sell to the grid or to displace a local facility's power purchases should be made solely on economic grounds. Particularly in the industrial sector, CHP developers are often required to sell power to the grid since local retail loads rarely match the electric outputs of CHP facilities, which are most economically sized to the local host's thermal loads. Declaring that only one-third of CHP power can be sold, therefore, has the potential to disqualify many CHP facilities without cause, thereby significantly slowing investments in efficiency and reducing the potential for emissions reductions. Rather than dictate the point of sales, CHP's operative test should be efficiency (noting, as mentioned above, that an exception is needed for bottoming-cycle CHP or recycled energy). EPA must strike the CHP sales restriction. [EPA-HQ-OAR-2009-0491-2823.1, p. 2]
Response:
The commenter's description of "recycled energy projects" is too vague, and lacks sufficient information, to determine what would be the regulatory status of such projects under the proposed Transport Rule and to provide a basis for adopting different provisions in the final Transport Rule.  For example, it is unclear from the commenter's description what types of equipment are associated with these projects and whether such projects depend on the use of a boiler or combustion turbine, which are covered by the Transport Rule trading programs and, of course, have heat input.  EPA notes that the definition of "combustion turbine" includes "any associated duct burner, heat recovery steam generator, and steam turbine".  See sections 97.402, 97.502, 97.602, and 97.702 of the Transport Rule trading program regulations (definition of "combustion turbine").  It is also unclear exactly what revisions of the proposed Transport Rule are sought by the commenter.  For example, the commenter failed to identify or describe the "[l[egislative tax proposals" that the commenter suggested should be used to adopt "similar exemptions" in the Transport Rule.
EPA rejects the commenter's suggestion that the electricity sales limitation in the cogeneration unit exemption be removed.  The purpose of the electricity sales limitation is to distinguish between cogeneration units that are considered industrial and those that are considered part of the electricity generation sector, which is the sector whose emissions the final Transport Rule is aimed at reducing.  EPA notes that the electricity sales limitation has been used in the Acid Rain Program and in the CAIR trading programs to make this distinction.  The commenter failed to provide any support for the claim that the using the electricity sales limitation as a requirement for the cogeneration unit exemption "significantly" slows "investments in efficiency and reducing the potential for emissions reductions".  EPA rejects this claim as speculative and unsupported.  EPA also notes that the inclusion of these units in the Transport Rule trading programs provides strong economic incentives for increasing efficiency and reducing emissions at these units because the units' owners and operators must hold allowances covering the units' emissions and can sell any allowances that are not needed for covering these emissions.
Organization: Virginia Department of Environmental Quality (VDEQ)
Comment:
Virginia Department of Environmental Quality (VDEQ)
The draft Transport Rule does not include many units that were originally part of the NOx Budget trading Program (NBTP) and that States could optionally include in the Clean Air Interstate Rule (CAIR) implementation plans. VDEQ believes that EPA should allow states to choose whether or not NBTP units should be included in the Transport Rule. The document entitled, 'Analysis of NOx Budget Trading Program Units Brought into the CAIR NOx Ozone Season Trading Program,' only looked at whether the expansion of the Clean Air Interstate Rule (CAIR) NOx ozone season trading program applicability to include the NBTP units actually resulted in NOx emission reductions. This comparison took place between 2004 and 2009. Units in the NBTP often chose to retrofit with highly cost effective controls such as low NOx burners (LNB), separated overfire air (SOFA), and/or flue gas recirculation (FGR). Sometimes facilities chose to retire the units. Regardless, the controls for the units located in Virginia were generally in place by 2004, or the retirement occurred shortly thereafter. A comparison of 2004 emission rates by unit to 2009 would not necessarily show the benefit of the continuation of trading program requirements on these units. The result of not including these units in the Transport Rule is that the voluntary controls installed and the voluntary unit retirements in lieu of purchasing credits or retrofit are no longer necessary. This could result in higher emission rates due to controls not being used. States should have the prerogative to analyze the units located within the state borders to determine if inclusion of these units is necessary to ensure that reductions of NOx already achieved are not lost. [EPA-HQ-OAR-2009-0491-2595.1, pp.1-2]
Response:
See sections VI.A, VII.B, IX.A and B, and X of the preamble.  The final rule gives states the option of expanding the applicability provisions of the Transport Rule NOx ozone season trading program to include units serving generators with a nameplate capacity of 15 MWe or greater producing electricity for sale.  This is consistent with the approach taken in the NOx Budget Trading Program, where some state elected to include units serving generators with a nameplate capacity of 15 MWe or greater producing electricity for sale.  The commenter claimed, without support that non-EGUs have installed controls before 2004 and so a comparison of 2004 and 2009 emissions rates would not necessarily show the effect of including these units in the Transport Rule trading programs.  EPA rejects the commenter's claim as speculative and unsupported.  Moreover, the commenter's claim addressed only non-EGUs in Virginia and also failed to address the fact that non-EGUs, as a group, did not make significant emission reductions, were over-allocated allowances, and were net sellers of allowances to covered EGUs.

V.D.2.b. Allocations

Organization: American Clean Skies Foundation (ACSF)
Comment:
American Clean Skies Foundation (ACSF)
EPA proposes a two-step approach to measuring each regulated state's 'significant contribution' to downwind pollution, which informs the emissions caps. First, for each pollutant, EPA uses air quality monitoring to quantify a state's contributions to downwind non-attainment. Second, for states that significantly contribute to downwind pollution problems, EPA determines each state's 'significant contribution' based on an 'appropriate maximum cost' by which power plants could reduce such pollution through control measures. 9 It then applies those control measures to a power plant's actual or projected operations to arrive at emission caps (which are set as state 'budgets' and allocated back to individual power plants). 10 [EPA-HQ-OAR-2009-0491-2759.1, p.3]

9. ACSF's concerns with CATR's allocation method are relevant both to EPA's preferred regulatory option as proposed in CATR, which involves 'limited interstate trading,' as well as similar allocation problems with EPA's 'intrastate trading only' option, since they use comparable allocation methods. [EPA-HQ-OAR-2009-0491-2759.1, p.3]
10. By way of additional detail on CATR's allocation method, for SO2,EPA based the 2014 state budgets on projected generation (per the Integrated Planning Model or 'IPM') times reductions that could be achieved at $2,000 per ton. 75 FR 45290. There is then an 'off-ramp' for certain states ('Group 2') whose downwind pollution contributions can be sufficiently reduced by lesser control measures. For these Group 2 states, EPA set the 2012 SO2 state budgets based on 2009 actual unit performance, unless a source was modeled to install a scrubber by 2012 in which case the 2009 baseline is reduced to account for the new scrubber. 75 FR 45282, 45290. The SO2 caps are not further reduced from these 2012 levels for these Group 2 states. EPA says that CATR's NOx limits, though generally based on emission reductions at $500 are ton, are set similarly to the 2012 SO2 limits: basically requiring the running of control technology that already exists, or is scheduled to be installed by 2012 (SCR for NOx). 75 FR 45290-91. [EPA-HQ-OAR-2009-0491-2759.1, pp.3-4]
Response:
EPA changed its allocation methodology to be based on historic heat input and emissions data that is generally reported by the sources' DR who testifies to its accuracy and completeness.  Because the final rule uses an historically-data based allocation methodology for existing units, those units' allocations under the rule would be unaffected by any potential modeling discrepancy between a unit's projected future operation and its eventual actual future operation.  For more information on the allocation method, see Preamble Section VII D. For more information on the air quality-assured trading structure of the Transport Rule programs, please see Preamble Section VII.A.
With respect to how EPA determined significant contribution, please see Preamble Section V.
Organization: American Coalition for Clean Coal Electricity (ACCCE)
Cleco Corporation
National Rural Electric Cooperative Association (NRECA)
Old Dominion Electric Cooperative
Louisiana Energy and Power Authority (LEPA)
Edison Mission Energy (EME)
Comment:
American Coalition for Clean Coal Electricity (ACCCE)
COMPLIANCE ALTERNATIVES
Under the proposal, the alternatives to deferring the compliance deadlines would not adequately remedy the problem we have discussed above and would, in some cases, create complications. Below we discuss briefly the four most likely remedies if controls could not be installed by an EGU in time to meet the proposed deadlines. [EPA-HQ-OAR-2009-0491-2874.1 p.5]
Purchase Allowances
This alternative presumes that adequate quantities of allowances would be available at a reasonable price to meet the needs of EGUsthat are not able to meet the 2012 and 2014 compliance deadlines. Given the overall stringency of the Transport Rule emission budgets, we do not believe this presumption is valid if, as we expect, a significant number of EGUsare unable to meet the proposed deadlines. Moreover, the proposal to allow limited trading would greatly constrain interstate trading of allowances, thereby making it more difficult to meet reduction requirements through the purchase of allowances. Finally, uncertainty over future requirements may limit the availability of allowances if EGUsdecide to hold, rather than sell, allowances. [EPA-HQ-OAR-2009-0491-2874.1 p.6]
Cleco Corporation
The only realistic compliance option for many plants covered by this rule will be allowance purchases, but the proposed compliance schedule does not allow sufficient time for the new allowance markets to develop. Allowance market development may be particularly challenging in the SO2 market because EPA proposes two completely separate markets for Group 1 and Group 2 states, each with fewer participants than EPA's previous cap and trade programs. [EPA-HQ-OAR-2009-0491-2859.1 p.3]
Edison Mission Energy (EME)
EME has different concerns with respect to the Phase II unit-level emission allocations. Unlike Phase I, Phase II of the Transport Rule expressly contemplates the installation of additional controls to obtain additional SO2 reductions. As explained in Section IV.B.4, EME submits that the Phase II compliance cap should be pushed back until 2016 in order to ensure that affected EGUs actually have the time necessary to install these controls. [EPA-HQ-OAR-2009-0491-2707.1, p.33]
Louisiana Energy and Power Authority (LEPA)
The proposed Transport Rule would impose an initial compliance deadline of January 1, 2012. That would not allow enough time for LEPA to make changes necessary to comply with the rule. LEPA would receive no emission allowances for its critical units and may not be able to purchase any allowances under the constrained trading regime the rule would establish [EPA-HQ-OAR-2009-0491-2700.1, p.17-18].
National Rural Electric Cooperative Association (NRECA)
EPA incorporates these and other emissions reduction assumptions in its CATR modeling to conclude that the proposed CATR would result in one million more tons of SO2 reductions in 2012 than would result under CAIR. This conclusion rests on these assumptions being correct: that these units can undertake needed structural and fuel changes under compressed time constraints and at EPA estimated costs. The apparent fact is that the modeling resulting in this incredibly optimistic conclusion is a good indication that it is highly suspect. Because the proposal's unit allocations rest on this modeling, rational rulemaking dictates that at a minimum EPA delay any first compliance period to at least to 2013 and re-propose unit allocations incorporating sensible, realistic assumptions with particular emphasis on full costs, and consideration of unavoidable constraints. [EPA-HQ-OAR-2009-0491-2723.1, pp.6-7]
Old Dominion Electric Cooperative
EPA incorporates these and other emissions reduction assumptions in its Transport Rule modeling to conclude that the proposed Transport Rule would result in one million more tons of SO2 reductions in 2012 than would result under CAIR. This conclusion rests on these assumptions being correct: that these units can undertake needed structural and fuel changes under compressed time constraints and at EPA estimated costs. The fact that the incredibly optimistic conclusion is based upon modeling of flawed assumptions makes the conclusion itself highly suspect. Because the proposal's unit allocations rest on this modeling, rational rulemaking dictates that at a minimum EPA delay any first compliance period to at least to 2013 and re-propose unit allocations incorporating sensible, realistic assumptions with particular emphasis on fuel costs and constraints. [EPA-HQ-OAR-2009-0491-2877.1,p.5]
Response:
For comments related to the compliance deadline, please see Preamble Section VII C. EPA notes that SO2 and NOX trading are well established practices under ARP, NBP, and CAIR, with an existing knowledge base of compliance options and how likely a entity is to have and need allowances. Additionally, companies have known of the Transport Rule approach since its proposal in July 2010, and past experience has shown that most will have moved to prepare for the new programs ahead of final promulgation of the rule. Finally, while the first control periods begin for the annual programs on January 1, 2012 and for the ozone-season program on May 1, 2012, sources have until the allowance transfer deadlines of March 1, 2013 for the annual programs and December 1, 2012 for the ozone-season program to reconcile total emissions from the control period with allowances submitted.  Although EPA believes that companies already have adequate time to achieve the feasible emission reduction strategies on which the state budgets are based by the beginning of the control periods, this timing for actual compliance demonstration allows individual companies to adapt flexibly to whatever circumstances may arise at their covered units over the course of the entire control period by obtaining the requisite number of allowances to cover total emissions during that time.

The rationale for establishing air quality-assured trading programs can be found in section VII.A. EPA notes that SO2 and NOX trading are well established practices under ARP, NBP, and CAIR, with an existing knowledge base of compliance options and how to obtain sufficient allowances to cover total emissions in a control period. Because this is an emission reduction program, it would be unreasonable to expect that initial allowance allocations would cover current emission levels at all units.  The air quality-assured trading programs provide everyone the incentive to reduce emissions at or below the market price of an allowance for that pollutant, regardless of the initial allocation of allowances to any given unit, as such allocations could be sold and thus have an opportunity cost.  Please see the Allowance Allocation Final Rule TSD for more information.

Organization: Associated Electric Cooperative, Inc. (AECI)
Comment:
Associated Electric Cooperative, Inc. (AECI)
Information contained in the proposal and within the docket is insufficient to allow comprehensive comment on the proposed allowance allocations because many of individual unit control assumptions are unavailable, making the allowance allocations arbitrary. [EPA-HQ-OAR-2009-0491-2845.1 p.3]
Allowance movement should be permitted without restriction to and from unit accounts that fall under the control of a single company. Further, trading restrictions according to state borders should be removed and replaced with the boundaries that consider territories defined by regulated transmission system operators and any adjacent unregulated equivalents. The system operator often dictates the dispatch order and unit output from facilities under ownership of several different companies in multiple states. Consider: If the output of a large nuclear unit in "state A" is lost to an outage, the demand may be filled by one or more coal units in neighboring "state B". While the final destination of the electrical output is state A, the emissions are accounted for at the facility located in state B. Under the proposed Transport Rule, State B would be penalized due to higher coal consumption necessary to cover the loss of output from the nuclear unit in state A. Since the utility in state B won't know until the end of the compliance year whether it can purchase enough (limited) intra- or inter-state at an unknown cost, it cannot recover the additional cost of compliance in the price of the power sold to state A. Even if the utility in state B is able to project annual mass emissions of NOx and SO2, the inflated cost of the (limited) intra- and inter-state micro markets will add unnecessarily to the operating cost of the plants. Scarce allowances will drive up the cost of compliance while adding little or no environmental benefit. If utilities that emit under their CATR allocations decide not to sell the (few) remaining allowances that they hold after assuring their own compliance, many companies that emit above the CATR cap likely will not be able to purchase enough allowances to achieve compliance. [EPA-HQ-OAR-2009-0491-2845.1 P.6]
Associated agrees with the unlimited trading proposed for the initial years of the rule. However, the limited post-2013 trading regime does not allow for the economies inherent to the emissions markets of the past. While we recognize the limitations placed on EPA by the court ruling, we believe there are reasonable steps that could be taken to improve the Transport Rule and lower costs to the regulated utilities. EPA's preferred option is too restrictive and does not recognize the reality of the interconnectedness of facilities by a vast transmission grid. Because FERC rules require open access and coordinated transmission balancing for system reliability, facilities owned by multiple companies are under the control of a single controlling system operator in areas recognized by the North American Electric Reliability Corporation (NERC). Just as stack emissions do not respect state boundaries, neither do transmission systems. Therefore, it does not make sense to limit trading strictly by geographical state boundaries. [EPA-HQ-OAR-2009-0491-2845.1 P.6]
The map below is an example of how the proposed Group 1 and Group 2 states could be further subdivided into trading regions according to the NERC areas. Within these trading regions, utilities could freely trade allowances not to exceed twenty (20) percent of their prior year total mass emissions of either SO2 or NOx. This method would be a self regulating system and would provide utilities some certainty for planning. Further, because the proposed emission caps are so restrictive, the potential for concentrating emissions and negatively impacting ambient air quality in downwind areas must surely be negligible. Under such a plan there is no economic incentive to emit more since doing so would expose the utility to the allowance market. Indeed, emitting less would likely afford an economic opportunity in a semi-liquid market where allowances are certain to be scarce. As written, EPA's preferred option of limited trading does not provide market liquidity or compliance certainty. [EPA-HQ-OAR-2009-0491-2845.1 P.6]
The variability conditions that are proposed to take effect in the second phase are complicated and create compliance uncertainty because the utility cannot know if the state budget for the current year has been exceeded until the data is verified as quality assured at some point in the first quarter of the following year. This leaves a utility at the mercy of other allowance holders in the state to help satisfy its compliance obligation. Under EPA's limited trading option, allowance holders are likely to bank slim compliance margins for use in future years rather than sell to neighboring utilities. Further, a utility will not know whether it can buy out-of-state allowances until someone declares that the state budget is exceeded. Once this occurs, there will be a mad dash to secure scarce allowances at inflated prices in order to achieve compliance. [EPA-HQ-OAR-2009-0491-2845.1 P.7[EPA-HQ-OAR-2009-0491-2845.1]]
Request: AECI requests that EPA amend the Transport Rule to allow for unrestricted movement of allowances between unit accounts for facilities in neighboring states and under common control of a single company. [EPA-HQ-OAR-2009-0491-2845.1 P.7]
Request: AECI requests that EPA amend the Transport Rule to remove trading restriction defined by state borders and replace them with the boundaries of transmission operators recognized by NERC and the unregulated equivalents that border them. Trading regions should be expanded (as described above) to allow for a maximum of twenty (20) percent of a facility's annual SO2 or NOx emissions from the prior operating year. [EPA-HQ-OAR-2009-0491-2845.1 P.7]
Response:
EPA provided unit level data, including controls, in the September 1, 2010 and January 7, 2011 NODAs and believes this data was sufficient for analysis, as evidenced by the numerous comments received on unit-level assumptions.
For an explanation of why EPA chose air quality-assured trading programs for the Transport Rule and responses to related comments, please see Preamble Section VII.A.

Organization: City Utilities of Springfield
Comment:
City Utilities of Springfield
The data sets that form the basis for all of the state allocations contain numerous errors. Since correction of these errors will necessarily affect final allocations, the regulated community has not been and will not be afforded adequate opportunity to review and comment on the overall impacts of this rule making. [EPA-HQ-OAR-2009-0491-2721.1 p.2]
Issue: The docket for this proposal includes data tables with calculated emission rates, assumed operating schedules, and derived emission allowance allocations for units affected by the Transport Rule. According to the proposal, the allocation table will be included in the final rule as Appendix A. However, EPA subsequently published a Notice of Data Availability, based on reported errors in the various data tables (75 FR 53613). Hopefully, the decision to submit public comments will lead EPA to correct the data tables and present more realistic and workable allowance allocations in Table A of the instant rule. However, the regulated community has no assurance that the corrections will be adequate and therefore can not evaluate the ultimate impact of this regulation prior to the close of comments for this docket. Although EPA has made considerable efforts to draft a Transport Rule that will withstand judicial challenge, this appears to be a fatal flaw that could ultimately render it inoperable. [EPA-HQ-OAR-2009-0491-2721.1 p.2]
Recommendation: EPA should hold open the comment period for this docket or, alternatively, reopen the proposal for additional comments following the final publication of corrected allocation data. [EPA-HQ-OAR-2009-0491-2721.1 p.3]

The proposal is ambiguous with respect to the treatment of new units that commence operation between the effective date and January 1, 2012.
Issue: As indicated above, the prepublication version of the proposal appeared to contain an inconsistency regarding new units. Specifically, the prepublication language created tension regarding the treatment of units that commence commercial operation between the effective date of the rule and January 1, 2012. These units were neither listed in Appendix A (since they are not part of the modeled database) nor eligible as post- 2012 units to participate in the new unit set-aside. Inclusion of the definition described above would assist immeasurably in clarifying that these "interstitial" units are to be treated as new. However, additional affirmation could be achieved by emphasizing this point within the text of the new unit set-aside sections. [EPA-HQ-OAR-2009-0491-2721.1 p.4]
Recommendation: We suggest inserting the phrase "including new units that commenced commercial operation prior to January 1, 2012" after the clause "that are not listed in Appendix A to this subpart" at §97.412(a), 97.512(a), 97.612(a), and 97.712(a). [EPA-HQ-OAR-2009-0491-2721.1 p.4]

The proposed treatment of new units inadvertently penalizes low emitting units that undergo extended maintenance outages.
Issue: CU supports the new unit program as described in most aspects. Specifically, we support a set-aside of at least 3% of the state's compliance pool, the proposal to allocate allowances based on actual emissions, and the reallocation of retired unit allowances into the new unit pool. New units will have the lowest emissions profiles of any units affected by these rules. As PSD permitted units, their emissions will naturally be limited by BACT guidelines. Accordingly, they will not have any emissions that fit the definition of significant contributors  -  i.e., those that can be reduced in a cost effective manner - under the Transport Rule, since they are already emitting at the lowest possible rates economically achievable. In addition, the extensive modeling required during the permitting process, including long-range transport modeling for visibility protection, should document their negligible impacts on downwind receptors. For all of these reasons, the operation of new units should be encouraged and their control period emissions should be made whole under the allocation schema. However, allocation based strictly on the previous year's emissions can have the effect of penalizing a unit that experiences extended down time, as might happen during the initial year of operation or resulting from periodic inspection and overhaul. Ironically, one cause of an extended unit outage would be the need to replace SCR catalyst, an event that would not befall a unit with lesser degrees of NOx controls. [EPA-HQ-OAR-2009-0491-2721.1 p.4-5]
Recommendation: We suggest a mechanism whereby a new unit could adjust its previous year's emissions to account for prolonged maintenance outages, catalyst management outages, etc. The mechanism should have a trigger that is activated if the unit availability factor falls below 85%, and should allow up to a 15% upward adjustment. Alternatively, a new unit that experiences prolonged unit unavailability might simply be allowed to revert to the second prior year in applying for current year allowances. [EPA-HQ-OAR-2009-0491-2721.1 p.5]
Response:
EPA reviewed the comments and has made significant updates to its IPM v.3.02 modeling used at proposal.  These updates include changes to both the more general IPM assumptions (e.g., gas price assumptions) and specific unit level assumptions (e.g., that current retrofit status at a unit).  These updates were made to the IPM model, and the updated versions (EPA IPM v.4.10) was used for all the final rule analysis.  In regard to unit specific adjustments, EPA did not manually adjust projected unit level modeling outputs, but instead made unit level updates to its NEEDS database used as a model input that impacted the unit level model outputs.   Some of the most frequent general IPM comments that were addressed in the updates are: FGD removal efficiency was adjusted for new retrofits, and for existing retrofits it was indexed to historic performance at the unit.  Additionally, many comments were focused on a source's ability to switch coals.  EPA modified its modeling to better reflect the cost and feasibility of switching and blending coals.  For more detailed discussion of EPA IPM v.4.10 assumptions and assumption updates, see the EPA IPM v.4.10 documentation and the "Transport Rule IPM Assumptions Response to Comments" in the Appendix.
For information defining "new units" and their allocation, see Preamble Section VII.D and the Allowance Allocation Final Rule TSD.. EPA notes that, except for issues related to the first year of allocations for new units, that the impact of downtime on future allocations can be minimized by units. City Utilities of Springfield commented that downtime one year (year X) would affect the next year's (year X+1) allocation for a new unit. While this is true, that unit's allocation for year X would be based on its emissions in the previous year (year X-1). Since that downtime in year X would mean the unit would not use its full allocation for that year, it could bank those allowances and use them for the following year (year X+1) to cover the shortfall.
EPA posted the signed version of the Proposed Transport Rule to the web when it was signed on July 6, 2010.  The proposal was published in the Federal Register on August 2, 2010.  EPA held three public hearings on the rule on August 19, 2010 (Chicago, IL), August 26, 2010 (Philadelphia, PA), and September 1, 2010 (Atlanta, GA) and the public comment period closed on October 1, 2010.  The comment period was thus open for 60 days from the date of publication in the Federal Register and 90 days from the date the rule was widely disseminated to the public via publication on the web.  EPA posted the signed version of the first Transport Rule Notice of Data Availability (NODA) (IPM) to the web when it was signed on August 25, 2010.  The first NODA was published in the Federal Register on September 1, 2010, and the public comment period closed on October 15, 2010.  The comment period was open for 45 days from the date of publication in the Federal Register and 52 days from the date the NODA was widely disseminated to the public via publication on the web on August 25, 2010.  The second NODA (addressing emissions inventories) was published in the Federal Register on October 27, 2010 and the public comment period closed on November 26, 2010.  The comment period was open for 30 days from the date of publication in the Federal Register (and was widely disseminated to the public via publication on the web at the same time).  The third NODA (allocations and related matters) was published in the Federal Register on January 7, 2011 and the public comment period closed on February 7, 2011.    The comment period was open for 30 days from the date of publication in the Federal Register and 38 days from the date the NODA was widely disseminated to the public via publication on the web on December 30, 2010.

EPA provided an adequate opportunity for public comment on the proposal and all three NODAs.  EPA complied with the procedural requirements of CAA section 307(d) including those regarding the length of the comment period.  EPA also received several hundred substantive comments during the comment period.  Many of these contained detailed data and analyses.   The volume and depth of the comments received suggests that the opportunity for public comment was adequate.  The fact that more comments could have been provided had the comment periods been extended, does not establish that the comment period was inadequate or not consistent with the procedural requirements of section 307(d).    EPA is mindful both of its obligation to provide an opportunity for public comment and of its obligation to proceed with this rule in a timely manner.
Organization: Clean Energy Group
North Carolina Department of Environment and Natural Resources
Great River Energy
Excelsior Energy
Exeter Energy Limited Partnership
Calpine Corporation
Southern IL Power Cooperative
North Carolina Electric Membership Corporation
Massachusetts Department of Environmental Protection
Northeast States for Coordinated Air Use Management (NESCAUM)
Constellation Energy
Comment:
Calpine Corporation
Although, as discussed in our subsequent comments, IPM does not provide a realistic estimate of future heat input for specific units, it is a reasonable macro-level model for the purposes of predicting future emissions and electricity production at the state level. [EPA-HQ-OAR-2009-0491-3614, p.2]
Clean Energy Group
Below, we address several broad topics and include several recommendations. None of these recommended modifications to the proposed rule are intended to delay implementation of the rule on January 1,2012. However, in order for the rule to be implemented by January 2012, EP A must be able to make the necessary adjustments to the underlying data to ensure the allocations in 2012 and 2013 properly reflect the planned and installed air pollution controls as well as units' near-term operating circumstances and conditions. As EPA noted in the preamble, there is insufficient time for companies to install control technologies by 2012 unless they are already in progress, but new controls are possible by the 2014 deadline. [EPA-HQ-OAR-2009-0491-2702.1, p. 2]
We support securing these substantial benefits through the implementation of this rule by January 2012. To achieve these important benefits, EP A must address the data inaccuracies noted below and in individual members' comments or modify the unit allocation methodology as recommended below. [EPA-HQ-OAR-2009-0491-2702.1, p. 2]
Constellation Energy
Initially, it is essential that allocations be undertaken in a way that does not disrupt near-term business operations. These disruptions could spur a lengthy legal battle resulting in unproductive delays of improvements in public health. EPA's allocation proposal is the least operationally disruptive in that it allocates allowances roughly in line with companies' expected future emissions. [EPA-HQ-OAR-2009-0491-3613,p.2]
Excelsior Energy
Comment summary for overall allocation approach:
EPA's proposed approach for unit-by-unit allocation of allowances is inequitable, encourages inefficient behavior, and sets an undesirable precedent. However, EPA's alternative proposal would largely eliminate all three of these problems. [EPA-HQ-OAR-2009-0491-2810.1 p.1]
EPA's proposed allocation methodology, which would make a one-time allocation to existing sources based on 2009 or projected 2012 base case emissions, is inequitable. It is most favorable to the highest emitting (worst performing) units and least favorable to the lowest emitting (best performing) units as measured at the time the allocation is made. As EPA itself acknowledges, the proposed methodology 'means that a unit that installs control equipment receives fewer allowances than a similar unit that did not install control equipment' 7S F.R. 45311 (Aug. 2, 2010). Thus, existing units that have invested or committed to invest in retrofits to reduce emissions prior to the one-time allocation are punished with a reduced allocation, while those with the highest emissions are rewarded with a windfall of allowances for emission reductions that they could have made, but did not. Similarly, new units are punished for reducing emissions: under EPA's proposal, they will receive a reduced allocation, and any remaining portion of the new source set-aside will be allocated to existing sources in proportion to the magnitude of their emissions (again rewarding poor performance). If a state adds two new units of the same size, but one unit uses advanced control technology resulting in emissions 90% lower than the other, the allocation given to the unit with advanced controls will be 90% lower than the allocation given to its under-achieving counterpart. [EPA-HQ-OAR-2009-0491-2810.1 p.1]
Under EPA's currently-proposed approach, new and retrofitted units are effectively bearing the burden of achieving emissions reductions for un-retrofitted units, which is inconsistent with the D.C. Circuit Court of Appeals' opinion rejecting the Clean Air Interstate Rule. There, the Court found that the distribution of the burden is important, and objected to CAlR's allocation methodology in part because states with lower initial emission intensities would subsidize reductions in states with higher initial emission intensities. North Carolina v. EPA, 531 F.3d 896, 920 (D.C. Cir. 2008). The CATR's proposed allocation methodology is similar in principle to the one in CAIR that was rejected: it places heavy burdens upon individual units with low emissions in order to subsidize the inability of poorly-performing existing units with high emissions to achieve reductions-in effect, the proposed Rule makes one unit's significant contribution depend on another's cost of eliminating emissions. While the legal basis for the D.C. Circuit Court's objection to CAIR focused on the illogical (and inequitable) interstate distribution of the burden to reduce emissions, the same principle applies to EPA's proposed intrastate distribution of the same burden. [EPA-HQ-OAR-2009-0491-2810.1 p.1]
Secondly, the proposed approach encourages inefficient and counterproductive behavior. A primary aim of emission cap and trade programs is to achieve the most cost-efficient emissions reductions by requiring emitters who cannot cost effectively reduce their own emissions to purchase allowances from others who can. Such transactions thereby establish a price signal that leads to efficient behavior, minimizing the overall cost of compliance to the overall economy. The proposed approach is lacking in this regard, and in fact has the potential to cause inefficient behaVior. For example, under EPA's proposed approach, owners who might otherwise completely shut down older, economically-marginal, high-emitting units would be compelled to keep those units operating (potentially at diminished capacity factors) in order to continue receiving the financial benefit of their disproportionately large allocation of allowances. New units would be isolated within the new source set-aside, insulating existing sources from competition within emission allowance markets from lower-emitting new sources. Thus, counter productively, the very facilities in each state that have persisted in contributing to downwind non-attainment would be encouraged to continue operating, while facilities that have already made investments to minimize their downwind contributions would be arbitrarily and capriciously be denied the primary benefits of doing so. [EPA-HQ-OAR-2009-0491-2810.1 p.3]
Finally, the proposed approach sets an undesirable precedent. It discourages early action from sources that anticipate potential regulation, since those who reduced emissions early are effectively punished for their reduced emissions through the issuance of reduced allowance allocations. This sends the signal that early reduction of other pollutants (such as greenhouse gases) for which regulation is emerging may also be punished. In light of EPA's treatment of pollutants in this proposed Rule, entities contemplating projects that would reduce greenhouse gas emissions may decide that postponement of those projects is prudent to ensure that their good behavior is not punished with a reduced allocation. [EPA-HQ-OAR-2009-0491-2810.1 p.3]
In contrast, EPA's alternative approach of allocating to units within each state based on heat input would avoid these problems: such a methodology would be more equitable, encourage efficient behavior, and set a good precedent. Units that made early retrofits to reduce emissions would be properly rewarded and compensated by those who did not. Since allocations would be equitable and regularly adjusted, this approach would discourage inefficient behavior like keeping older, high-emitting units running beyond what would otherwise be the end of their useful economic life. A new source setaside would be unnecessary, and new units could capture the benefits of reducing emissions, making them able to freely compete with existing units. [EPA-HQ-OAR-2009-0491-2810.1 p.2]
The alternative heat input-based allocation approach EPA that is contemplating in the CATR differs from those in CAIR and overcomes the deficiencies that prompted the D.C. Circuit Court's rejection of CAIR. In North Carolina v. EPA, the Court rejected EPA's proposed fuel-adjustment factors primarily because EPA was trying to protect states with higher emission intensities out of 'fairness'; EPA adjusted each state's heat input for the mix of fuels its power plants used (i.e., coal-fired EGUs contributed full heat input to the state budget, but oil-fired and gas-fired EGUs contributed only 60% and 40% of their heat inputs respectively). The D.C. Circuit rejected the fuel adjustment factors because it found the effect of the fuel-adjustment factors irrational: 'in essence, a state having mostly coal-fired EGUs gets more credits because Louisiana [a state with EGUs that use more gas and oil than most other states' EGUs] can control emissions more cheaply.' Here, EPA dutifully reports that its proposed methodology for allocating allowances does not consider heat input or fuel adjustment factors-but by seeking to avoid similar objections to its allocation methodology, EPA unwittingly runs afoul of the very problem it seeks to avoid. By failing to adjust emission requirements for each facility based on heat input, EPA essentially gives more credits to (requires less reduction from) older, inefficient facilities because newer facilities can control their emissions more cheaply-making one unit's significant contribution and burden depend on another unit's cost of eliminating emissions. At the same time, EPA's alternative heat-rate based methodology would stand a lesser risk of rejection by a reviewing court because contrary to the method in CAIR, the methodology would not work to protect emitters, and the underlying reasoning for the methodology would be to reward and encourage future emission reductions-the very point of the Rule-rather than to arbitrarily and capriciously achieve 'fairness.' [EPA-HQ-OAR-2009-0491-2810.1 p.3]
Exeter Energy Limited Partnership
2. Annual NOx and SO, Allowance Allocations:
Should the Exeter Facility be subjected to the Proposed Transport Rule, it would be critical to rectify its apparent omission from the annual allowance allocations for either NOx or SO,. In section V.DA.b(2) (page 45309-453 10) of the preamble to the Proposed Transport Rule, EPA references the proposed unit level allocations for existing units (contained in 'State Budgets, Unit Allocations and Unit Emissions Rates' TSD in the docket). Based on review of this document, although Exeter Energy has been allocated ozone season NOx allowances for each unit, no annual NOx or SO, allowances have been allocated to Exeter Energy. In order to assist EPA in calculating allowance allocations, Exeter Energy is submitting documentation in the attached table of its NOx and SO, emissions on a per boiler and per month basis for calendar years 2007 through 2009. Monthly summaries for 20] 0 through June are also provided. [EPA-HQ-OAR-2009-0491-2835.1 p.3]
Great River Energy
As a generation and transmission cooperative, Great River Energy is required to provide the capacity and electrical supply projected for our member distribution cooperatives. As our cooperatives project their load, we are responsible for providing the necessary power to cover their load in MISO ('Midwest Independent System Operator' - our regional transmission operating system). Minnesota has a renewable energy standard requiring electrical suppliers' to provide 25% of their electrical power in a renewable form by 2025 (with interim requirements of 12% by 2012, 17% by 2016, etc.). A by-product ofthis standard is that when the renewable form of energy is not available due to environmental conditions, we must still hold enough capacity with other existing generating facilities to cover our demand on the regional transmission system. GRE utilizes simple cycle combustion turbines to meet this requirement. In addition to covering the renewable sources for the cooperatives our generating facilities are used to cover the peak electrical demand of our 28 distribution cooperatives. Our peak demand typically occurs during the summer months with a smaller peak also occurring in the winter months. Much of our peak demand is due to air conditioning usage during the hottest months in the summer. Projections of expected weather and economic development are used to ascertain the future generation needs of our distribution cooperatives. In mild summers our Minnesota generating sources are not heavily utilized. The summers of 2008 and 2009 were very mild and the data used in 2008 and 2009 were the lowest usage years since the startup of our combustion turbines. This fact, in combination with many data entry errors in the base case modeling information, has led GRE to believe that our allocations are lower than they should be.  [EPA-HQ-OAR-2009-0491-2758.1 p.2]
Great River Energy has reviewed the distribution of allowances in Minnesota and finds the EPA methodology to be illogical, inequitable, and inconsistent with the stated goal of a flexible program. EPA inherently recognizes the potential problem of creating virtual monopolies, as it describes in the allocation of resources within a specific state. 'The distribution of allowances would be modified because of the concentrated nature of numerous state power markets, which would be reflected in the state allowance market if all allowances were distributed in each state based on factors reflecting generation in that state. The electric power sector tends to be highly  concentrated, and, within a state, the majority of generation is often owned by a relatively small number of companies.' (emphasis added) (FR 45326)  [EPA-HQ-OAR-2009-0491-2758.1 p.8]
This is especially true in Minnesota. With respect to NOx allocations, as an example, EPA has allocated ~89% of allowances to two utilities. (See Attachment 3.)
Further, upon deeper review, one Minnesota plant alone accounts for ~40% of state NOx allocations and, by EPA's own analysis, this one plant is not projected to install SCR as a NOx control by 2012, or by 2014 for that matter. Given the concentration of allowances within two companies and the limited allocations to the remaining smaller sources within Minnesota, GRE is extremely concerned about a lack of allowances for intrastate trading. This has significant implications for us. Smaller cooperatives and municipal power providers such as Rochester Public Utilities, Otter Tail Power, Southern Minnesota Municipal Power Agency and Great River Energy will face limited allowance access and, in virtually all instances, cannot cost effectively control their emission sources and remain competitive in the region.  [EPA-HQ-OAR-2009-0491-2758.1 p.9]
As demonstrated in our emissions summary table (Attachment 1), GRE is projected to have a significant NOx allowance deficit from the beginning of the Transport Rule implementation. We disagree with EPA's allocation methodology, for the reasons stated in these comments. In addition, we do not expect a viable intrastate trading program under Option 2, which will force us and other smaller utilities to engage in limited interstate trading under the Preferred Option. GRE has concerns about legal challenges to the Preferred Option, and EPA's ability to address the D.C. Circuit Court's concerns on failing to address upwind state contributions to nonattainment, as was rej ected under CAIR.  [EPA-HQ-OAR-2009-0491-2758.1 p.9]
If allowance trading does not develop, as GRE expects, GRE will be penalized additional allowances, placing us more deeply into allowance deficit, and potentially facing Clean Air Act penalties for not holding sufficient allowances. EPA has made statements that under its Preferred Option, there will not be additional Clean Air Act penalties for failing to hold sufficient allowances. Yet, this is not readily apparent from reading the preamble and proposed Transport Rule. ?  [EPA-HQ-OAR-2009-0491-2758.1 p.9]???
 Under the Transport Rule, Great River Energy is faced with purchasing allowances as a sole compliance strategy. Great River Energy combustion turbines were not correctly allocated for the reasons presented herein. Controls are not cost effective for our combustion turbines, as deemed by EPA's own analysis. Great River Energy is worried that there will not be a viable intrastate trading program. Great River Energy is hopeful that interstate trading will bridge the compliance gap. This extremely awkward compliance strategy could easily result in years of allowance deficits and potential non-compliance, further penalizing Great River Energy's inherently clean simple cycle combustion sources.  [EPA-HQ-OAR-2009-0491-2758.1 p.9]
Massachusetts Department of Environmental Protection
For example, EPA could develop an output-based allocation methodology that would incorporate efficiency considerations. We recommend that rather than basing allocations on historical emissions as proposed in the Transport Rule, EPA allocate allowances using an output-based allocation methodology similar to that incorporated by Massachusetts in its NOx Budget (310 CMR 7.28(6)(c) and (d)) and CAIR NOx Ozone Season programs (310 CMR 7.32(5)(c)1.b.) Under this output-based approach, Massachusetts facilities received NOx allowances based on their net electricity and steam output thereby rewarding more efficient generation. Within the electrical grid system, rewarding allocations based on an output basis will encourage the utilization of the most cost-effective units, so that older, less-efficient units that have historically been dispatched will eventually be replaced with a fleet of newer and cleaner EGUs. [EPA-HQ-OAR-2009-0491-2787.2 p.11]
North Carolina Department of Environment and Natural Resources
In general, it has been recognized that allocations based upon heat input could 'penalize' high efficiency operations by granting less allowances due to lower heat input for a given heat output. It has been argued that allocations based upon output could and should force improvements in operations and increased operation efficiency. As noted, in future regulations where states are preparing SIPs to respond to new guidance and requirements, states may consider using output based allocations. However, it may require a transition period to convert from one method of allocation to another. In the end, both methods must address downwind impacts [EPA-HQ-OAR-2009-0491-2767.1 p.9].
North Carolina Electric Membership Corporation
Please see the attached file for corrections to the North Carolina Electric Membership Corporation (NCEMC) facilities in North Carolina (NCEMC Anson Plant and NCEMC Hamlet Plant). In the files, yellow highlighting indicates corrections of data and blue highlighting is data which should change based on the corrections. This file is based on the Budgets and Allocations table from the Technical Information section of EPA's Transport Rule website. [EPA-HQ-OAR-2009-0491-3764 p.1]
Items to note from the individual spreadsheet tabs. [EPA-HQ-OAR-2009-0491-3764 p.1]
Unit Characteristics tab: The MW capacity apportioned for each of the turbines has been entered, the turbines are Pratt & Whitney Twin-Pacs which are two turbines connected to a single generator. [EPA-HQ-OAR-2009-0491-3764 p.1]
Projected Data tab: This tab appears to be related to the IMP modeling, pursuant to the comment noted below, all of the units should be included in the modeling.
Allocations & Rate Limits tab: The ES6-A and ES6-B units at the Anson Plant should be allocated annual NOx allowances. We feel that this was an error in the data which caused annual heat input to be blank. [EPA-HQ-OAR-2009-0491-3764 p.1]
Also, we have noticed that the NCEMC Hamlet Plant has not been included in the NEEDS database but the NCEMC Anson Plant has. Both plants should be included in the database and subsequent modeling. [EPA-HQ-OAR-2009-0491-3764 p.1]
Northeast States for Coordinated Air Use Management (NESCAUM)
EPA can and should, at minimum, establish allocations based on output.[EPA-HQ-OAR-2009-0491-2694.1 p.8]
Southern IL Power Cooperative
EPA's proposed system relies on computer modeling of future individual unit utilization and emissions controls operation or installation. In other words, the rationale for essentially permanent unit allocations comes from EPA's computerized virtual world containing numerous false assumptions. [EPA-HQ-OAR-2009-0491-2863.1 p.3]
Response:
Thank you for your comment.
Organization: Cogen Technologies Linden Venture, LP
Comment:
Cogen Technologies Linden Venture, LP
Linden Cogen operates a 900 megawatt ('MW') natural gas-fired cogeneration plant in Linden, New Jersey, which provides steam and power to ConocoPhillips' Bayway refinery and power to both the New York City grid operated by the New York Independent System Operator ('NYISO') and the Pennsylvania/Jersey/Maryland ('PJM') Interconnection. Linden Cogen objects to EPA's proposed allocation of allowances for both annual oxides of nitrogen ('NOx') and ozone season NOx for its natural gas-fired facility for the following reasons: [EPA-HQ-OAR-2009-0491-2712.1, p.1]
:: EPA's proposed allocation for Linden Cogen, which is a highly efficient combined-cycle plant equipped with selective catalytic reduction ('SCR'), would provide only a small fraction of the annual and ozone season NOx allowances it will need to continue meeting demand under its long-term contracts with utilities and its cogeneration host. These results are based upon erroneous projections EPA has made using the Integrated Planning Model ('IPM'), which predicted that Linden Cogen will only operate at a fraction of its historical capacity. In essence, IPM has predicted dispatch of Linden Cogen as a peaking plant, rather than a baseload generating plant, because IPM fails to account for the existence of long- term contracts that practically assure operation of Linden Cogen at baseload capacity throughout the term of its contracts. [EPA-HQ-OAR-2009-0491-2712.1, pp.1-2]
:: The IPM projections have no basis in reality and are clearly disproven by Linden Cogen's historical dispatch as a baseload plant and by its ongoing contractual obligations to provide power to New York City and both power and steam to the largest refinery on the East Coast. The D.C. Circuit has previously rejected EPA's reliance upon IPM projections which were based upon certain false assumptions concerning future utilization, where the resulting projections were seemingly implausible and ran contrary to 'real world observations'. See Appalachian Power Co. v. EPA, 249 F.3d 1032, 1054 (D.C. Cir. 2001) ('Appalachian Power f'); Appalachian Power Co. v. EPA, 251 F.3d 1026, 1035 (D.C. Cir. 2001) ('Appalachian Power If'). EPA must resolve these serious deficiencies in IPM, so that it accurately predicts dispatch of facilities subject to long-term contracts. [EPA-HQ-OAR-2009-0491-2712.1, p.2]
:: In addition to IPM's failure to reflect the reality of dispatch for plants with long-term contracts, Linden Cogen believes IPM's inaccurate projections are due to EPA's reliance upon an erroneous heat rate and application of the wrong assumptions concerning fixed operating and maintenance ('FOM') costs, variable operating and maintenance ('VOM') costs and fuel costs for each of Linden's generating units. EPA's IPM runs assumed an erroneous heat rate of 9173 British thermal units per kilowatt hour ('Btu/kWh'), which is dramatically higher than the plant's actual average heat rate of 7965 Btu/kWh. EPA cannot assign FOM, YOM and fuel costs to Linden Cogen significantly greater than a similar combined-cycle facility in New Jersey, without providing specific justification for such disparate treatment. Further, EPA must provide an opportunity for parties to correct these erroneous model inputs and must then re-run the model, before relying upon the results as the basis for allocating allowances. [EPA-HQ-OAR-2009-0491-2712.1, p.2]
:: The preamble to the Proposed Transport Rule says that EPA rejected IPM's projected utilization and emissions as the basis for setting state-wide budgets because IPM's projections were less reliable than actual operating data. EPA has provided no explanation for how it could reject IPM's projections as less reliable than actual data in setting state budgets, but then rely upon those same projections in establishing unit-by-unit allowance allocations. It would be arbitrary and capricious for EPA to rely upon IPM's projections as the basis for establishing allocations, when EPA has already acknowledged that those projections cannot be relied upon to establish the corresponding state budgets. IPM has projected utilization of existing units in New Jersey at heat rates that are wildly inaccurate and, in the case of Linden Cogen, wholly inconsistent with its long-term contractual obligations. EPA cannot simply ignore these discrepancies. To do so would run afoul of the D.C. Circuit's mandate that EPA explain disparities between IPM's projected future utilization rates and 'real world' evidence to the contrary. See Appalachian Power 1,249 F.3d at 1054. [EPA-HQ-OAR-2009-0491-2712.1, pp.2-3]
:: The practical consequences of EPA's allocation methodology for Linden Cogen are that it will likely need to purchase the vast majority of allowances it needs to continue meeting its contractual obligations. In contrast, EPA's proposed allocation methodology would allocate nearly 90% of the State's overall budget to a number of coal generating units in New Jersey, which would also receive a significantly greater number of allowances under the Proposed Transport Rule than they received under the Clean Air Interstate Rule ('CAIR'). Thus, under EPA's proposed methodology for New Jersey, these coal plants would likely become sellers of allowances, while Linden Cogen would become a buyer. As a result, these coal plants may be gaining a substantial subsidy, at the expense of cleaner burning facilities such as Linden Cogen, which will undoubtedly need to purchase NOx allowances to continue meeting its long-term contractual obligations. The costs to obtain such allowances cannot, for the most part, be passed along to Linden Cogen's customers and would therefore place Linden Cogen at a significant disadvantage. Such a policy outcome would be wholly at odds with the Administrator's stated goal of fostering investment in a 'clean, efficient, and completely modem power sector.' 75 Fed. Reg. at 45227. [EPA-HQ-OAR-2009-0491-2712.1, p.3]
:: Before relying upon IPM projections as the basis for setting unit allocations for New Jersey, EPA must re-run IPM using corrected inputs for Linden Cogen's heat rate, FOM costs, VOM costs and fuel costs. EPA must also account for the fact that Linden Cogen is operated pursuant to long-term power sales agreements and a steam sales agreement, which require its continued operation as a baseload plant. Accordingly, in the event that EPA continues to rely upon IPM's projections as the basis for allocating allowances to individual units, EPA must either incorporate the contractual terms governing dispatch into IPM or establish rules within IPM that essentially 'force' the model to predict dispatch of Linden Cogen consistent with the requirements of its power sales and steam sales agreements. [EPA-HQ-OAR-2009-0491-2712.1, p.3]
:: If EPA cannot correct the errors in IPM that have generated arbitrary and unrealistic predictions of future dispatch for Linden Cogen, EPA should instead base the unit-specific NOx allocations for New Jersey on the same methodology which was used to derive the state budgets. The preamble to the Proposed Transport Rule indicates that New Jersey's state budgets (as well as all other state budgets, other than the 2014 SO2 budgets for group I states) were based on historical operating data, as augmented by assumptions about when existing and planned emissions controls will be operated. Accordingly, the unit-specific allocations for New Jersey should similarly be based on such historical data and operating assumptions. An allocation methodology based on historic operating data is not at all inconsistent with the court's decision in North Carolina v. EPA and would assure that the same analyses and data supporting establishment of a state's budget are used to support the unit-specific allocations within the state. In fact, for all allocations but the 2014 sulfur dioxide ('SO2') allocations in group 1 states, EPA has already proposed basing allocations on historical data, augmented by assumptions about the operation of existing and planned controls, wherever those data resulted in lower statewide emissions than projected by IPM. [EPA-HQ-OAR-2009-0491-2712.1, pp.3-4]
:: If EPA cannot correct the errors in IPM that have resulted in its erroneously low projections for dispatch of Linden Cogen, then the agency should instead decide to base New Jersey NOx allocations for individual units on historical data. EPA should base such allocations on data, not from a single year, but from a more representative period of time. Once each facility's representative baseline has been established, EPA should then sum together all facilities' baseline emissions, compare the total with the state budget, and then reduce each facility's allocation by whatever percentage is needed for the total statewide emissions (plus the 3% set aside for new facilities) to fit within the budget. Using only one year's data as the basis for allocations could penalize facilities that had lower emissions in 2008 or 2009 because they operated at a lower capacity factor due to the recession or were down for an extended period of time to install controls in advance of CAIR. [EPA-HQ-OAR-2009-0491-2712.1, p.4]
:: Linden Cogen does not support the alternative allocation methodology described by EPA in the preamble, wherein each facility would be allocated allowances based on its 'share of projected heat input' within the state. 75 Fed. Reg. at 45311. As presented, this alternative allocation methodology would not resolve the serious problems associated with allocating allowances based on IPM's projected dispatch of facilities such as Linden Cogen, which are subject to long-term contractual obligations that mandate their operation. However, if EPA can successfully resolve the errors in IPM that resulted in its erroneously low projected dispatch for Linden Cogen or if EPA's proposal were to allocate allowances based on each source's share of historical (rather than projected) statewide heat input, Linden Cogen agrees that this would be a fair and equitable approach. [EPA-HQ-OAR-2009-0491-2712.1, p.4]
:: As an alternative to resolving the errors in IPM or basing New Jersey NOx allocations on historical heat input data, EPA could refrain altogether from promulgation of the proposed Federal Implementation Plans ('FIPs') and instead support states' efforts to submit adequate State Implementation Plan ('SIP') revisions within a reasonable amount of time. While awaiting states' submission of SIP revisions might delay implementation of the CAIR's replacement program until after 2012, it should not result in any delay in attainment or interference of maintenance of the National Ambient Air Quality Standards ('NAAQS'). It also would provide states the opportunity to develop SIP revisions that also addressed anticipated revisions of the NAAQS, without requiring an unnecessary and duplicative series of rulemakings and SIP revisions. [EPA-HQ-OAR-2009-0491-2712.1, p.4]
:: Linden Cogen believes EPA should provide relief, as Congress previously has, for long-term contract generators who have no means of recovering the cost of emissions allowances. EPA should make any remaining allowances in the new unit set-aside available to long-term contract generators who exceeded their allocation in the preceding control period due solely to an increase in utilization back to levels achieved prior to the recession. This would prevent long-term contract generators from needing to pay potentially significant costs to purchase allowances after the conclusion of a control period. It also could be accomplished without compromising the integrity of the statewide emissions budgets. [EPA-HQ-OAR-2009-0491-2712.1, p.5]
Response:
Regarding allowance allocations and the dispatch of electricity generation, please see the Allowance Allocation Final Rule TSD.
EPA does not agree with the commenter that "providing relief" to specific generators or other detailed considerations of equity are relevant to the statutory mandate of section 110(a)(2)(D)(i)(I); instead, EPA is using a fuel- and control-neutral approach to allocations under the FIPs, as explained in section VII.D of the final rule preamble.
Organization: Connecticut Department of Environmental Protection
Comment:
Connecticut Department of Environmental Protection
Allocation proposal rewards dirtier units. CTDEP does not support the proposed allocation methodology in the Transport Rule because it rewards dirtier units. EPA states that "...all units are allocated allowances consistent with their projected emissions; this means that a unit that installs control equipment receives fewer allowances than a similar unit that did not install control equipment." (75 FR 45311) EPA requested comment on an alternative methodology that would distribute allowances equal to a state's emissions budget without variability to each covered source in the state based on each source's proportional share of total state heat input. EPA should base allocations on individual EGU's electricity output provided that EPA continues to link each state's budget to significant contribution. [EPA-HQ-OAR-2009-0491-2780.1 p.20]
Allocations to non-operating units. CTDEP does not support EPA's proposal to continue allocating allowances to non-operating units for up to 6 years following non-operation. CTDEP believes that allowances should be allocated on the basis of recent history of operations, preferably output based, in proportion to the unit's generation the previous year. At a minimum, allowance allocations should cease after 3 years of non-operation. The financial incentive gained from receiving allowances beyond the 3 year period after non-operation will play a limited role in determining future EGU operations and is insignificant compared to operating costs associated with fuel use. [EPA-HQ-OAR-2009-0491-2780.1 p.20]
Response:
EPA has decided to base allocations made under the FIPs on historic heat input, subject to a maximum allocation limit to any individual unit based on that unit's maximum historic emissions. Further detail on the implementation of this approach, rationale, and response to comments on the allocation method is provided in Preamble Section VII.D. as well as in the Allowance Allocation Final Rule TSD in the docket for this rulemaking.
Please see Preamble Section VII.D.2. for a description of how the Transport Rule will handle allocations to non-operating units and responses to comments on the topic.
Organization: Consumers Energy
Comment:
Consumers Energy
 Allocations should be handled by the states. The states know their jurisdictions and their sources best. A total allowance budget should be assigned to each state. They can handle the distribution schemes.  [EPA-HQ-OAR-2009-0491-3795.1_NODA, p.5]
Response:
For an explanation of FIP Authority for each State and NAAQS Covered and response to relevant comments, see Preamble Section IV C 2.
Organization: Dow Chemical Company
Comment:
Dow Chemical Company
As a separate comment, Dow believes that EPA should provide an exemption to sources that exceed the annual electricity sales limit due solely to the occurrence of an emergency. For instance, EGUs as well as local transmissions systems located in Louisiana can be adversely affected by hurricanes or floods. There have been occasions in the past where EGUs adversely impacted by hurricanes have been unable to provide electricity to their customers. In those cases, sources meeting the cogeneration exemption may be called upon to temporarily increase their electricity production to provide for critical infrastructure power needs until the primary utility systems can return to electrical power production. By selling electricity in these times of crisis, exempt sources may exceed the proposed Transport Rule/FIP electricity sales thresholds and therefore trigger applicability under the Transport Rule/FIP. Dow believes that these sources should not be penalized by triggering regulatory applicability solely due to provision of power during such emergency periods. Dow thus requests that EPA provide an exception to the Transport Rule stating that sources will not lose their exemption for temporary activities that occur in response to emergencies. EPA could impose appropriate criteria to limit the scope of this exception; however, such an emergency exception is needed under the proposed rule. [EPA-HQ-OAR-2009-0491-2775.1 p.9]
Response:
EPA believes that the allowance trading provisions in the Transport Rule will provide sufficient flexibility in such emergency situations. For more information on the trading provisions, please see Preamble Section VII.
Organization: East Texas Electric Cooperative
Comment:
East Texas Electric Cooperative
Units relocated from one state to another should be recognized in the state to which they have been relocated and allocated new unit allowances based upon the most current data available. [EPA-HQ-OAR-2009-0491-2770.1 p.2]
Response:
Please see Preamble Section VII.D.2. for an explanation of how allocations for relocated units will be handled.
Organization: Edison Electric Institute (EEI)
Comment:
Edison Electric Institute (EEI)
EEI supports banking of allowances beginning in 2012 under the preferred approach. The proposed Transport Rule properly recognizes the important environmental and economic benefits of allowance banking, and that allowance banking as an element of EPA's CAIR program was in no way undermined by the court's decision in North Carolina v. EPA. [EPA-HQ-OAR-2009-0491-2697.1, p.16]
Response:
Thank you for the comment. EPA has retained the banking provisions in the final rule. For more information on banking, see Preamble Section XI.
Organization: Exxon Mobil Corporation
Comment:
Exxon Mobil Corporation
Considering the unreasonable and unsupported initial allocations under the proposed FIP, it is also unreasonable for a facility to expend resources prior to final rule promulgation since it is not reasonable to predict how EP A may respond to the significant errors found in the proposed rule. [EPA-HQ-OAR-2009-0491-2841.1, p.16]
Response:
Thank you for your comment.Organization: Green Exchange, LLC
Comment:
Green Exchange, LLC
Green Exchange recognizes EPA's efforts in the proposed Transport Rule to have emissions trading play a central role in the Transport Rule, while working within the bounds of the D.C. Circuit's earlier decision. We appreciate that the EPA understands the importance of maintaining the integrity of allowances as they represent the return on emission reduction investments. [EPA-HQ-OAR-2009-0491-1105.1, p.2]
Response:
Thank you for the comment. EPA has maintained the trading provisions in the final Transport Rule. For more information, please see Preamble Section VII.
Organization: Independence Power & Light (IPL)
Comment:
Independence Power & Light (IPL)
For the reasons stated herein, IPL requests that EPA modify the proposed Rule by:
4. confirming that units in existence but not online, or units that are newly constructed but not online as of the effective date of the proposed Rule are eligible for allocations. [EPA-HQ-OAR-2009-0491-2741.1, p.18]
Response:
Please see Preamble Section VII C for a description of how units are assigned allocations.
Organization: Indiana Energy Association
Comment:
Indiana Energy Association
f. The Indiana Utility Group supports EPA's direct issuance of allowances to affected sources and no auction of allowances. [EPA-HQ-OAR-2009-0491-3711 p.5]
e . The Indiana Utility Group supports unlimited banking of allowances. [EPA-HQ-OAR-2009-0491-3711 p.5]
Response:
Thank you for the comments. EPA has chosen to maintain direct issuance of allowances under the final Transport Rule and banking of allowances. For more information on these topics, see Preamble Sections VII and XI.
Organization: Kansas City Board of Public Utilities (BPU)
Comment:
Kansas City Board of Public Utilities (BPU)
For the reasons stated herein, BPU requests alternative modifications to the proposed Rule by:
2. eliminating the ozone season NOx allocation restrictions for all Kansas EGUs listed in Appendix A;
4. removing BPU's units from the NOx and SO, allocation restrictions listed in Appendix A;
6. clarifying that zero allocation units listed in Appendix A will obtain a positive allocation immediately upon completion of retrofitting;
8. replacing the allowances for BPU's electrical generating units listed in Appendix A with the following allowances:
Quindaro, CT2 - NOx:22 tons; S02:12 tons
Quindaro, CT3 - NOx:34 tons; S02:20 tons
Neannan, CT4 - NOx:40 tons; S02:8 tons
Neannan, Nl - SO2:6390 tons
Quindaro, Q2 - SO2:2079 tons
Quindaro, Ql - NOx:2547 tons; S02:2032 tons 10  [EPA-HQ-OAR-2009-0491-2740.1, p.23]

10 The allocations for the CTs are derived from the highest annual NOx & S02 tons that BPU reported during the period 2005-2009. For S02, the requested allocations match BPU's Acid Rain Permits,
Response:
For a description of the method and response to comments for identifying states that have a significant contribution to nonattainment or interfere with maintenance in other states, please see Preamble Section V.
Organization: Michigan Department of Natural Resources and Environment
Comment:
Michigan Department of Natural Resources and Environment
The EPA has supplied data (in particular the spreadsheets titled BADetailedData.xls and AliocationTable.xls) regarding projected allocation budgets for the years 2012 and 2014 using the preferred compliance option. The TR proposal used the 2004, 2005, and 2006 EGU heat input data to determine the allocations. Michigan used the heat inputs from 2004, 2005, 2006, 2007, and 2008 to determine the CAIR bUdgets for the EGUs within the state. However, the DNRE has concerns about the differences in budgets and allocations from CAIR to TR, so we conducted a careful review of the data. The DNRE would like to add that while we noted the potential for additional allowances under the variability calculations, those amounts are not included in this discussion. [EPA-HQ-OAR-2009-0491-2774.1 p.7]
However, the proposed TR FIP NOx allocations, which are specific to individual sources, are significantly different than under CAIR (see Tables 1, 2, and 3 in Appendix C). Some sources in Michigan's CAIR program were left out of the allocations under the FIP. In addition, other sources were given amounts significantly less or more than under Michigan's CAIR rules. For example, DTE's Maryville's plant has not operated since before 2004 and was not given allowances under the CAIR program for 2012 and beyond. Yet the EPA's FIP allocated large amounts of allowances for these units. The DNRE recommends that state allocations under a SIP would eliminate the uncertainties noted using allowances under the proposed FIP. [EPA-HQ-OAR-2009-0491-2774.1 p.7]
Furthermore, the DNRE would like clarification as to whether the budget totals noted above (and in the attached tables) includes the three percent to be set aside for new sources. [EPA-HQ-OAR-2009-0491-2774.1 p.8]
The proposed TR will 'set-aside' three percent of a state's total budget to be used for new source allowances. A new source would be required to request allowances from the new source set-aside the year following the first year of operation. In the case where assurance provisions (variability) for a state are triggered in the year that a new unit first operates, the new unit would have no allocation for that year. Therefore, the owner's share would necessarily be zero. A specific surrogate emission number would be used to calculate the maximum amount the unit would have emitted in that year before being required to surrender allowances under the assurance provisions. The surrogate emissions number would apply only if the state's assurance provisions were triggered and only in the first year of the new unit's operation. [EPA-HQ-OAR-2009-0491-2774.1 p.9]
The DNRE requests the following clarifications:
1. Does this mean that for the first year of a new source's existence they are not required to hold allowances or does this mean that new sources would be required to obtain allowances for the first year of operations from somewhere else, as in trading?
2. Where do the 'surrogate emissions' come from?
3. Will these 'new' sources ever become existing within the TR framework or will they remain 'new' sources indefinitely?
The DNRE also believes that three percent for the set-aside is an arbitrarily determined number, not based on potential installations or start-ups. During the CAIR program in Michigan, the new source set-aside retained 1 to 2.5 percent of allowances from the original budget. These numbers were determined using a projected number of potential new sources in the state. [EPA-HQ-OAR-2009-0491-2774.1 p.9]

Concern is expressed in the proposed TR that states allocated allowances differently than the CAIR FIP as originally proposed, and whether states implemented the fuel adjustment factor. [EPA-HQ-OAR-2009-0491-2774.1 p.9]
Michigan utilized a 'hybrid' fuel adjustment to determine allowances to sources based on the fuel used by the sources. This hybrid approach used the terms solid, liquid, and gas in place of coal, fuel oil, and natural gas. The DNRE believed that the change in terms better defined the types of fuel used in Michigan. For instance, the solid fuel terminology included biomass, coal and tires, where gas included natural gas, propane, and blast furnace gases. [EPA-HQ-OAR-2009-0491-2774.1 p.10]
Response:
For more information on the new unit set aside and how the size was determined, see Preamble Section VII.D.2.
For information on how surrogate emissions are calculated under the final rule, please see Preamble Section VII.E. and the Capacity Factors Analysis for New Units Final Rule TSD.
Organization: Minnesota Pollution Control Agency (MPCA)
Comment:
Minnesota Pollution Control Agency (MPCA)
If EPA intends to change the unit by unit allocations in the final Transport Rule, the MPCA believes that it is important that EPA provide additional notice on the final allocations, prior to finalizing the rule. The EPA has released the new Integrated Planning Model data, which is being reviewed by states and facilities. If changes to the allocations result from this review or from other comments on the Transport Rule, EPA should release a Notice of Data Availability, supplemental notice, or similar document in order to allow units to review the changes to their allocations. The MPCA believes this can, and should, be done without jeopardizing the overall schedule for rule promulgation. This additional notice is especially important due to the short time frame between the anticipated finalization of the Transport Rule in June 2011 and the start of the program in January 2012. [EPA-HQ-OAR-2009-0491-2521.1, p.2]
Response:
EPA followed guidelines for public comment periods and gave as much time as possible for receiving comments while abiding by the court's order to move as expeditiously as possible in replacing the Clean Air Interstate Rule. For a history of the rulemaking, including a description of supplemental Notices of Data Availability, please see Preamble Section IV B.
EPA received and declined several requests to extend the comment period for the proposed Transport Rule. The comment period on this rule ended on October 1, 2010. The proposed rule and much of the key supporting documentation was posted on our website on July 6, 2010 and the rule was formally published in the Federal Register on August 2, 2010. We believe the comment period provided was sufficient for interested parties to review the rule, prepare and submit input. This time frame allowed EPA to consider public comments and develop a final rule in time to obtain needed emission reductions.
Organization: Morgan Stanly Capital Group
Comment:
Morgan Stanly Capital Group
MSCG generally supports the premise underlying the Administrator's proposal for a multi-state, cap-and-trade program to reduce SO2 and NOx emissions, and appreciates that the Administrator has tried to design a program that will be consistent with the D.C. Circuit Court's decision in North Carolina v. EPA.3 Based on years of experience in both the power and emissions markets, MSCG believes that the primary mechanism for emissions allocation should be an auction process. However, to the extent that such allowances are allocated, the EPA's remedy option utilizing state budgets with limited interstate trading (the "Primary Proposal"), is superior to either of the alternatives developed in the Proposed Rule.4 However, unless it is modified in certain key respects, as described below, MSCG believes that the Primary Proposal is flawed because it presents unmanageable risks for independent power generators generally, and peaking plants in particular.5 The following aspects of the Primary Proposal are particularly problematic: [EPA-HQ-OAR-2009-0491-2819.1 p.2 ]
Many peaking plants, including those owned by MSCG, have been allocated few to no allowances.7 As now designed, the Proposed Rule also would not allow them much, if any, portion of the state's variability limit. Therefore, operation of such facilities in compliance with the Proposed Rule could be very difficult, if not impossible; [EPA-HQ-OAR-2009-0491-2819.1 p.3]
Most, if not all, allowances will be allocated, and the allocations are likely to cover less than the operating capacity of many units. Consequently, MSCG anticipates that the allowance market will be highly illiquid; [EPA-HQ-OAR-2009-0491-2819.1 p.3]
If the allowance market is as illiquid as MSCG (and the EPA) projects, peaking unit operators will not be able to evaluate operating costs and price their product on a timely enough basis to provide a quick response which constitutes their primary function (i.e., to provide power in times of high demand or unusual system events) [EPA-HQ-OAR-2009-0491-2819.1 p.3]
1. Allocation of Allowances on Basis of Currently Permitted Emissions or Exemption of Peaking Plants from Proposed Rule Peaking plants are brought online in times of high demand or unusual system events to ensure the reliability of the electric transmission grid. Yet, under the Proposed Rule, peaking plants are not allocated enough allowances to start up and operate. In fact, in all but two instances, MSCG's peaking plants are not allocated any allowances at all. [EPA-HQ-OAR-2009-0491-2819.1 p.6]
The Administrator should consider allocating emissions allowances to all plants based on currently permitted emissions under CAA permits, rather than on historical or projected emissions. This would better provide the necessary allowances for start-up and operation. In the alternative, the EPA could either (1) allocate allowances to peaking plants only based on permitted emissions for peaking plants only, or (2) exempt peaking plants from the Proposed Rule. [EPA-HQ-OAR-2009-0491-2819.1 p.6]
4. Close-out of Allowance Allocation Upon Plant Closure
Given the likely illiquidity of allowance markets under the Proposed Rule, the EPA should not allocate scarce allowances to closed plants.22 MSCG does not believe that allowance revenue, or the lack thereof, will have a significant impact on closure decisions. Furthermore, the underlying purpose of a market is to use allowance prices to drive investment and closure decisions. Providing allowances to a closed plant as an "extra" incentive to close is unnecessary, distorts the market, and is contrary to the underlying "cap-and-trade" approach. [EPA-HQ-OAR-2009-0491-2819.1 p.8]
Response:
Thank you for your comment.Organization: Nelson Industrial Steam Company (NISCO)
Comment:
Nelson Industrial Steam Company (NISCO)
If NISCO is not allocated sufficient NOx allowances, it will be impossible to meet this deadline. Further, it is not known whether allowances will be available for purchase in such a limited trading market. Considering the unreasonable and unsupported initial allocations under the proposed FIP, it is also unreasonable for a facility to expend resources prior to final rule promulgation since it is not reasonable to predict how EPA may respond to the significant errors found in the proposed rule. [EPA-HQ-OAR-2009-0491-2813.1, p.12]
Response:
Thank you for your comment.Organization: Northern Indiana Public Service Company (NIPSCO)
Comment:
Northern Indiana Public Service Company (NIPSCO)
Regarding specific allocations, NIPSCO appreciates that EPA will include both the state-specific and unit-specific allowance allocations in the body of the rule instead of referencing the unit-specific values in various files within the docket. The current method of including the unit-specific data in various files within the regulatory docket has complicated the efficient and meaningful review of the rule and its effects on companies. [EPA-HQ-OAR-2009-0491-2747.1 p.7]
Response:
Thank you for your comment.
Organization: Oglethorpe Power
Comment:
Oglethorpe Power
VII. Multiple Owner Provisions
Oglethorpe Power supports the inclusion by EPA of provisions that ensure the proper distribution of allowance allocations to the owners and operators of co-owned EGUs, in accordance with their legal, equitable, leasehold or contractual rights. See 75 Fed. Reg. 45379, 45403 & 4, 45428 & 9, & 45452 & 3, to be codified at 40 C.F.R. §§ 97.416, 97.516,97.616 & 97.716 (Certificate of Representation requirements for designated representatives for the four Transport Rule allowance programs). As Congress recognized when enacting the Acid Rain Program as part of the Clean Air Act Amendments of 1990, allowances issued for covered source operation accrue to the benefit and use of all unit co-owners holding a legal, equitable, leasehold or contractual right in a unit that has been allocated allowances. 10 Thus, where a designated representative ('DR') and alternate designated representative ("ADR") (typically employees of the company operating the unit and holding the permit) are appointed to represent a co-owned source (and all covered units of the source) in matters pertaining to an allowance program, the allowances belong to the co-owners, in proportion to their ownership interest in the covered units. Since the enactment of that provision by the Congress, EPA has consistently, for every emission allowance program created, included a 'multiple owner' regulation mirroring the requirements of CAA § 408(i). Oglethorpe Power strongly supports the inclusion of those same § 408(i) requirements in the Transport Rule for its allowance programs, so as to explicitly recognize allowance program duties on a DR and an ADR of co-owned covered sources (and co-owned units). [EPA-HQ-OAR-2009-0491-2732.1, p.12]

10. CAA § 408(i). That provision requires the filing of a certificate of representation by the DR and ADR for matters pertaining to the Acid Rain Program, including the distribution of allowances. The Legislative history of the 1990 amendments to the CAA states that § 408(i) establishes an affirmative responsibility for the DR to hold and distribute allowances to each holder of an interest in a unit, in proportion to each holder's legal, equitable or contractual share of the unit, unless the parties agree otherwise by contract. 136 Cong. Rec. S3380 (March 28, 1990). [EPA-HQ-OAR-2009-0491-2732.1, p.12]
Response:
Thank you for your comment. For more information on designated representatives in the final Transport Rule, see Preamble Section VII.E.
Organization: PPG Industries, Inc.
Comment:
PPG Industries, Inc.
Considering the unreasonable and unsupported initial allocations under the proposed FIP, it is also unreasonable for a facility to expend resources prior to final rule promulgation since it is not reasonable to predict how EPA may respond to the significant errors found in the proposed rule. [EPA-HQ-OAR-2009-0491-2763.1, pp. 18-19]
Response:
Thank you for your comment.Organization: PPL Corporation
Comment:
PPL Corporation
Solution
PPL recommends that the alternative approach EPA is taking comment on in the proposed rule be used. Under this alternative, all units within a state would be allocated allowances based on their proportional share of the total heat input from all affected EGUs in the state. This process would effectively result in unit allocations based on the same emission rates for all units in the state. We also recommend that gas-fired only units not be included in the SO2 program because their SO2 emissions are comparatively low and there is not a feasible control alternative to lower their emissions further that the Transport Rule would encourage. Finally we suggest that EPA allocate allowances based on historical operating levels rather than at the operating levels that IPM projects. [EPA-HQ-OAR-2009-0491-2739.1, p.4]
Although the emission reductions that EPA anticipates for 2012 are not intended to require installation of new FGD or selective catalytic reduction (SCR) systems, the emission rates for which the allocations are based are very low and in some cases at the cutting edge of the technology. To attain these emission rates, companies may need to purchase additional hardware and may need to change fuel supply. This is exacerbated by the 3 percent portion of the unit allocations that would be set aside for new units because it would require that EGUs on average operate below the already low emission rates that are assumed in the proposed rule. [EPA-HQ-OAR-2009-0491-2739.1, p.9]
Response:
Thank you for your comment.Organization: Progress Energy Service Company
Comment:
Progress Energy Service Company
Progress Energy supports EPA's proposal not to permit government run allowance auctioning. In addition, the Company urges EPA to prohibit allowance auctioning under the intrastate trading remedy option. Although Progress Energy does not support the intrastate trading remedy option, in the event that EPA promulgates a final rule based on this option, EPA should avoid government-run allowance auctions. Governmental auctioning of allowances is contrary to the principle that regulated sources are permitted to emit up to their allowance allocation levels without any obligation to pay for the right to emit up to those levels. [EPA-HQ-OAR-2009-0491-2831.1 p.2]
Despite these aspects of the proposal, with which the Company agrees, there are many other aspects of the Proposed Transport Rule that cause considerable concern. [EPA-HQ-OAR-2009-0491-2831.1 p.2]
Response:
Thank you for your comment. EPA has chosen to NOT use auctions in the final Transport Rule. For more information on this decision, see Preamble Section VII.A.
Organization: RRI Energy, Inc.
Comment:
RRI Energy, Inc.
RRI supports allocating unit-level allowances to existing units commensurate with the existing unit's share of its state emissions assumed in developing the budget. This methodology is consistent with EPA's Key Guiding Principles (e.g., to provide for costeffectiveness) and is also consistent with EPA's proposed approach to (i) terminate allowance allocations to non-operating / retired units following an extended period of suspended operations and (ii) distribute any allowances remaining in the new unit setaside to the existing units for each control period in proportion to the existing unit's initial allocation (i.e., propose to allocate allowances to units that actually need such allowances). [EPA-HQ-OAR-2009-0491-2717.1 p.2]
The CATR should allow existing units that are repowered to retain the allowances allocated to the existing units
RRI wishes to acknowledge our support the proposed new source set-aside budget and allowance allocation methodology. However, RRI strongly recommends that existing CATR-affected units that are repowered (using either clean coal technologies or replaced with natural gas-fired combined cycle combustion turbines) be permitted to retain the allowances allocated to the existing units in lieu of receiving an allowance allocation from the new source set-aside budget. The proposed CATR provides a greater incentive for existing units to install emissions controls (by permitting those units to retain their allowance allocation) rather than retire existing units and construct new or replacement units (these new units would likely be allocated fewer allowances as compared with the retired units). RRI believes that acceptance of this recommendation would provide the necessary incentives to EGU operators to retire coal-fired EGUs that are not equipped with contemporary SO2 and NOx emissions controls and replace these units with lower emitting clean coal technology boilers or natural gas-fired combustion turbines. [EPA-HQ-OAR-2009-0491-2717.1 p.5]
Response:
In the final Transport Rule, EPA is basing allocations to existing units on historic data, as explained in section VII.D of the final rule preamble.  If an existing unit repowers in the future, its historic data basis for Transport Rule allocations will not have changed, and therefore an existing unit that repowers in the future will continue to receive the same allocation under the FIPs as originally determined based on its historic data.
Organization: South Carolina Department of Health and Environmental Control
Comment:
South Carolina Department of Health and Environmental Control
DHEC notes that the NODA potentially rendered the comment period for the proposed Transport Rule irrelevant. The new IPM and NEEDS data affect the Budgets and Allocations Spreadsheet in the docket, which includes state emissions budgets and unit-level allowance allocations. The EPA however did not update the Budgets and Allocations Spreadsheet with publication of the NODA, so DHEC will not know the state budgets and unit-level allocations until publication of the Final Rule. State budgets and unit-level allocations are of central relevance to the outcome of the proposed Transport Rule, yet because of the EPA's midstream revisions to the technical foundation of the proposed Transport Rule, the public will not be provided the opportunity to review and provide meaningful comments to this major rule. Further, the new IPM and NEEDS data may influence the EPA's determination of which downwind states that South Carolina affects, and if the EPA does not re-notice the proposal, DHEC would not have opportunity to participate in the comment process on this important question. [EPA-HQ-OAR-2009-0491-3718.1_NODA, p.2]
Response:
EPA's response to these comments on updating unit data and allowance allocation methods in the final Transport Rule is multi-faceted: