Whatever assumptions EPA used to reach this result must be modified to comport with reality. The adverse financial impact to each of these facilities associated with the cost of purchasing NOx allocations would be enormous. The staff for the Louisiana Public Service Commission has estimated at least the following annual costs to these facilities for annual NOx allowances (i.e., not including ozone season allowances): Dow $159,768, ExxonMobil $1,224,000, Occidental $ 509,502, PPG $ 880,000. This estimate was based on a conservative assumption that annual NOx allowances would be valued at $1,200 per ton. With such a limited trading market as proposed by EPA, the adverse economic impact could be much higher. These are highly efficient, low emitting cogeneration units. EPA has no rational reason for imposing such costs on these facilities. [EPA-HQ-OAR-2009-0491-3527.1, p. 42]
The IPM is Deficient Through Failure to Consider Transmission Constraints.
LCA is also concerned about the proposed allocation of NOx allowances to public utilities from which LCA members purchase power. Many of the Louisiana Public Service Commission regulated EGUs in Louisiana received zero NOx allocations even though they have been providing critical power to Louisiana businesses and residential consumers for the past 5 years and have no announced plans to curtail operations. EPA's support documents indicated these same units do not need retrofits to reduce emissions. After weeks of communications with EPA trying to understand the basis of these proposed unit allocations, LCA was informed that the basis for this allocation scheme was EPA's IPM TR Base Case 3.02 modeling, which simply projects that due to economic factors unrelated to environmental issues, some units will not be running in 2012 or will be running at greatly reduced rates. As with the industrial cogeneration units discussed in the prior sub-section, the allocations among units were based on these projected, modeled economic consequences, not on any determination of environmental need. The result will be millions of dollars in windfall profits to certain units and significant costs to others, including the industrial consumers of such power. [EPA-HQ-OAR-2009-0491-3527.1, p. 42]
EPA staff also informed LCA that the IPM model does not account for transmission constraints or other factors that make these "must run" units.111 We are concerned that all of the units in the New Orleans area and across much of South Louisiana did not receive adequate allowances to allow operation at a level commensurate with local needs and that there are significant deficiencies in the IPM and/or with economic assumptions used therein that do not reflect real world constraints. See the map attached as Exhibit 12. As can be readily seen, EPA's projection via the IPM would have one believe that most of the power plants in south Louisiana will be shut down. Addressing such assumptions requires gathering of a significant amount of data from a number of EGUs, including those that are not LCA members, to demonstrate why such units are "must run" units, what the transmission constraints are, and how other factors that the model did not take into account will impact the utilization of those EGUs. This will take more time than EPA has allowed for the comment period. LCA will supplement this data as it becomes available. LCA urges EPA to consider the comments of the staff of the Louisiana Public Service Commission and the comments of the Louisiana Energy and Power Authority filed in this docket concerning this issue.  [EPA-HQ-OAR-2009-0491-3527.1, p. 43]
Louisiana Energy and Power Authority (LEPA)
LEPA is a political subdivision of the State of Louisiana created by statute to assist small and medium-sized towns and cities throughout Louisiana in obtaining reliable and economic wholesale power and energy. Many of LEPA's member municipalities are located in transmission constrained areas and have limited options for serving load. LEPA and its member cities and towns obtain the most economic, efficient resources available to it, but have limited access to such resources because of limited available transmission capacity. As a result, LEPA has several must run generating units that must run to serve load in LEPA's service area. Yet, the proposed Transport Rule allocates no emission allowances to those must-run units. LEPA's member cities and towns would be disproportionately and detrimentally impacted by this lack of emission allowances by way of dramatically increased costs, and/or total lack of electric power during thousands of hours of peak usage annually. [EPA-HQ-OAR-2009-0491-2700.1, pp.1-2]
THE PROPOSED RULE WOULD SIGNIFICANTLY RAISE ECONOMIC AND SOCIAL COSTS IN TRANSMISSION CONSTRAINED AREAS, DISPROPORTIONATE TO THEIR CONTRIBUTION TO THE POLLUTION EPA SEEKS TO ADDRESS. [EPA-HQ-OAR-2009-0491-2700.1, p.19]
The proposed Transport Rule does not allocate allowances in a manner that appropriately recognizes must-run capacity in transmission constrained areas, and allocates no allowances to LEPA's critical must-run units. LEPA would be forced to buy expensive allowances in a constrained trading market, if allowances are available at all. More likely, LEPA would be forced to rely on capital investment to achieve compliance. That investment would require the expenditure of unknown millions of dollars that may be spread over the very small population of LEPA's member communities. The costs per electric customer in LEPA's service area could be significant. [EPA-HQ-OAR-2009-0491-2700.1, p.19; for additional comments pertaining to see pp.19-20]
Louisiana Public Service Commission
The LPSC Staff is particularly concerned about the baseline data used in developing the allocations for each of the electric generating units ('EGUs') under the newly proposed Transport Rule. Louisiana has a complicated set of generation and transmission arrangements, largely the result of a diversity of both regulated utility EGUs and non-regulated independent power producers ('IPPs') and industrial cogeneration units. The LPSC Staff has a number of analysts examining EPA's baseline data, models, and model assumptions as they relate to our unit EGU mix. [EPA-HQ-OAR-2009-0491-1928.1, p.1]
Furthermore, the LPSC Staff is concerned about the proposed allocation of NOx allowances under the proposed rule, particularly the allocations estimated for many of Louisiana's highly efficient natural gas-fired cogeneration units that supply up to 25 percent of the state's electricity to regulated customers. Inappropriate allocations to these industrial facilities could increase the cost and/or availability of electricity generated on behalf of the state's regulated customers (through their qualifying power sales to regulated utilities). An inappropriate allocation also impacts these industrial facilities' economic competitiveness.[EPA-HQ-OAR-2009-0491-1928.1, p.2]
The LPSC Staff's initial review of the cogeneration allocations suggests that these units have received allocations that are some 20 percent below their 2009 actual NOx emissions, as well as below their 5 year average historic emissions. However, additional time is necessary to prepare comments on these issues and their impact on the reliable generation of power for Louisiana ratepayers. [EPA-HQ-OAR-2009-0491-1928.1, p.2]
The EPA's proposed allocation for cogeneration facilities fails to appreciate the state-specific solution all stakeholders reached during the CAIR process of 2006. The original CAIR Model Rule, which set allocations on a heat input basis, would have provided cogeneration facilities with considerable extra allowances given their efficiency and state-of-the-art controls since most of the cogeneration and IPP generators were either developed or repowered after 1999. Recognizing this potential windfall, the Commission recommended, and LDEQ adopted, an allocation mechanism that would make every cogeneration and IPP facility whole for their reported emissions and no more. The LPSC recommended 'clawing back' part of those allowances to serve as offsets to support older regulated generation, including the new unit addition at the Brame Energy Center. The EPA's proposal in CATR, however, undermines close to a year's worth of effort in developing a compromise in this regard. [EPA-HQ-OAR-2009-0491-2670.1, pp.13-14]
Schedule LPSC-6 summarizes the NOx allocation changes from CAIR to CATR on a summary basis for each of the EGU operators, per fuel type, in Louisiana. Under CAIR, Dolet Hills and the Brame Energy Center were scheduled to receive meaningful and significant allocations of between 9.0 percent and 11.5 percent of the statewide total allocation. Under EPA's proposal, both of those units will retain 26.2 and 21.0 percent of the statewide total, respectively. Looked at differently, almost half (47.2 percent) of the total NOx statewide allowances have been allocated to two units that generate less than 10 percent of the fossil-fired electricity in Louisiana. [EPA-HQ-OAR-2009-0491-2670.1, p.14]
Schedule LPSC-6 clearly shows those that are advantaged versus disadvantage under EPA's CATR proposals. Utility gas units are significantly disadvantaged, with ELL being penalized the most significantly of the entire group. EPA would allocate 13 percent fewer allowances to ELL relative to CAIR, or a 96 percent reduction in the amount ELL has anticipated, to date. The same is true for ENO, which will see its share of the statewide total reduced by 4.2 percent. Since ENO only received a 4.2 percent allocation in the first place under CAIR, the EPA proposal represents an unexplained 100 percent reduction in ENO's NOx allocations. The LPSC finds this result to be unacceptable. [EPA-HQ-OAR-2009-0491-2670.1, pp.14-15]
[Schedule LPSC-6 can found at the end of this comment.]
Michigan Municipal Electric Association (MMEA)
EPA's assumptions and unit-specific allocation methodologies for several Michigan municipal utility units are in error. [EPA-HQ-OAR-2009-0491-2828.1, p.2]
6.) EPA's Unit-Specific Allowance Allocations Have Significant Errors & Problems
These comments provide input on several data errors with respect to Michigan public power EGUs that have impacted the rule and allowance allocations. The prevalence of data errors and misassumptions with respect to our relatively small group of covered sources makes the entire emissions and allocation model suspect, and makes the imposition of a FIP and its unit-specific allocations even more of a concern. These errors include: [EPA-HQ-OAR-2009-0491-2828.1, p.11]
[For tables and additional comments pertaining to EPA's Unit-Specific Allowance Allocations, see pages 11-14 of this comment.]
Minnesota Power
Data discrepancies.  There are still apparent discrepancies in Minnesota source emissions data used by EPA in their modeling and the Minnesota actual emissions and projected emissions at modeled output levels and permitted emission rates.  It creates difficulties in assessing the correctness of unit data when the same unit can be posted with projected emissions based on historic actual emissions, projected emissions at the actual emission rate or projected emissions at the permitted emission rate.  EPA should clearly identify the basis for unit level emissions applied when they estimated state significant contributions to nonattainment and state emission budgets calculated relative to a 2005 base year, emission control retrofit estimates and assumptions about future unit generation output.  It is not clear if EPA is giving reasonable consideration or credit for early controls installation in the Transport Rule.   [EPA-HQ-OAR-2009-0491-2750.1, pp.8-9]
Unit level data and budget calculation discrepancies. Several Minnesota generating units are presented by EPA with little or no budget allocations. Some units appear to have discrepancies with how EPA described permitted emission limitations. Examples include the M.L. Hibbard Energy Center Units 3 and 4, which are not included in EPA's unit allocations listing. Taconite Harbor Energy Center Unit 3 permitted emission rates do not match. Estimates for unit level budget allocations assigned under EPA's methodology appear to assign smaller allocations for units that provided for post 2005 emission controls than for units that have implemented no emission reduction measures.  Minnesota Power intends to provide further commentary to address such matters when submitting comments to the Transport Rule Notice of Data Availability. Regardless, EPA needs to provide information that explains the basis for budget allocations and emission projections on a unit specific basis.    [EPA-HQ-OAR-2009-0491-2750.1, p.9]
Correction review time before rule finalization. If EPA corrections in proposed Transport Rule data inputs or modeling design are made, EPA should offer those changes for public review and comment before EPA finalizes the Transport Rule. [EPA-HQ-OAR-2009-0491-2750.1, p.9]
Missouri Public Utilities Alliance (MPUA)
4. We believe that 2009 is an inappropriate and misleading baseline year for determining emissions both for reasons related to weather and to the economy.  NOAA ranked the Midwest as in the lower range of normal temperatures for the year of 2009.  Additionally the region also saw significant cuts in demand for electric power as businesses, especially manufacturing, cut operations because of the financial recession.   As a result our power plants operated at lower levels and emitted lower emissions than what would be considered "normal".  We request that EPA provide greater justification for the selection of the year and demonstrate that emissions were in a normal ranger or explain how lower emissions for weather and the economy were considered in setting the final limits. [EPA-HQ-OAR-2009-0491-2785.1, p.3]
New York State Department of Environmental Conservation
In the supplemental notice, EPA specifically requests comment on the appropriate natural gas assumptions to use. When attempting to analyze the data from the original Transport Rule proposal, in the 'Budgets and Allocations - Detailed Unit-Level Data,' to determine the appropriateness and accuracy of EPA proposed allocations to generating units in New York, Department staff found that the heat input data was misstated by a factor of ten. Given the incorrect values provided in the data tables, the Department was unable to properly analyze the data and is not comfortable with the allocations EPA has provided to any of the units. Despite the poor quality of the data presented in EPA's original analysis, the Department was able to identify serious inequities in the proposed state level allocations. See Department comment letter to the docket dated October 1, 2010. [EPA-HQ-OAR-2009-0491-3763.1_NODA, p.1]
Occidental Chemical Corporation (OCC)
Furthermore, EPA's databases supporting the proposed rule do not include any information with regard to OCC's La Porte, Texas cogeneration facility, despite the fact that it is located in a state subject to the ozone season NOx control and allowance trading requirements of the proposed rule. OCC has no plans to close this facility. We agree that the La Porte facility need not receive emissions allocations if we conclude that it is an exempt cogeneration facility. However, we believe that EPA should include technical information on the facility in the relevant modeling databases. [EPA-HQ-OAR-2009-0491-2754.1, p. 3]
However, should EPA feel compelled to include certain QF cogeneration units in Texas and Louisiana in the Transport Rule's emissions allocation scheme, we respectfully request that if our units are not exempt, EPA grant at least 1,463 tons of annual NOx allowances, 17.7 tons of annual SO2 allowances, and 610 ozone season NOx allowances to OCC's Taft cogeneration units; grant at least 200 tons of ozone season NOx allowances to our La Porte facility; and retain the Ingleside facility's proposed ozone season NOx allowances. These allocations will ensure that we may continue to generate power and steam for internal and external consumption from our modern, clean-burning and ultra-efficient units. [EPA-HQ-OAR-2009-0491-2754.1, p. 4]
Problems with the Modeling and Resulting Unit-Level Allowance Allocations
In the event EPA elects to retain cogeneration units in the final CATR, it is imperative that EPA correct the various databases and modeling efforts supporting the proposed rule. EPA used either faulty assumptions and incorrect inputs or a faulty model. The model and its associated documentation are not transparent. EPA's allocation system is flawed and inconsistent with reductions possible at a cogeneration facility.  [EPA-HQ-OAR-2009-0491-2754.1, p.16]
Summary of OCC Unit Information Set forth in the following chart is a technical summary of OCC's cogeneration units covered, or potentially covered, by the proposed Transport Rule. This information provides the basis for identifying several errors in EPA's databases.  [EPA-HQ-OAR-2009-0491-2754.1, p. 16; see pp. 16-17 for the chart.]
NOx Emissions Abatement Technology and Unit-Level Allocations OCC has extensive experience with NOX emissions abatement technology. OCC has installed dry low NOx burner technology at the Taft and Ingleside facilities; ultra dry low NOx burner technology at the La Porte facility; and Selective Catalytic Reduction ("SCR") technology at the La Porte facility. A summary of emission rates from these facilities is as follows:   [EPA-HQ-OAR-2009-0491-2754.1, pp. 17-18; see p. 18 for the table.]
The Taft cogeneration facility fires pipeline quality natural gas in combustion turbines and natural gas and hydrogen in heat recovery steam generators ("HRSGs"). Both the combustion turbines and HRSGs are equipped with dry low NOX burner control technology. On average, in 2009 the facility's NOX emission rate was approximately 0.027 pounds per MMBTU. The facility's 2009 estimated emissions totaled 505 tons of NOX. However, OCC anticipates that steam demand from the host facility and electricity demand will increase over the next decade in response to an improving U.S. economy and OCC's long-term power supply agreement with the local utility. OCC anticipates increased demand in 2010 over 2009 requirements, such that 2010 NOx emissions are expected to increase.  [EPA-HQ-OAR-2009-0491-2754.1, p.18]
Based on information provided in EPA's emissions allocation table associated with the proposed rule,34 the Taft cogeneration facility would be allocated only 26 tons per year ("tpy") of NOX emissions in 2012. Thus, assuming that the Taft facility is not exempt and assuming operating rates equivalent to 2009 rates, OCC would be required in 2012 either to abate 479 tons of NOX emissions (which is not technically feasible), purchase 479 allowances (equivalent to 479 tons of emissions), or a combination thereof. At full rates, it is estimated that the facility would need to abate and or obtain allowances for an additional 1,437 tons of NOX emissions.  [EPA-HQ-OAR-2009-0491-2754.1, p.18]
As noted further in our comments, there is not any mention of the La Porte, Texas facility in any of the IPM information, including any of the supporting data bases. If this facility is not exempt and is subject to the final CATR, it must be allocated 200 tons of NOX for ozone season emissions.  [EPA-HQ-OAR-2009-0491-2754.1, p.18]
We support the ozone season NOx allowances (227 tons) provided to the Ingleside cogeneration facility. [EPA-HQ-OAR-2009-0491-2754.1, p.18]
The information contained Budgets and Allocations - Detailed Unit-Level Data Base3 is not accurate. We reviewed the information contained in the following spreadsheets that were presented in the Budgets and Allocations  -  Detailed Unit Level Data base: Unit Characteristics, Reported Data, Projected Data, Adjustments, Adjusted Data, Allocations and rate Limits. Our comments on information contained in each of the spreadsheets (where applicable) are as follows:  [EPA-HQ-OAR-2009-0491-2754.1, p.21; see pp. 21-27 for spreadsheets and comments]
In summary, we are extremely concerned that since the Agency does not have accurate information regarding certain model parameters, the output from the IPM is flawed. In particular, we are concerned that the there is no reference to our La Porte Cogeneration facility; the steam turbines at both the Ingleside and Taft facilities are being modeled as emission sources; and further, that erroneous heat rates are being used to develop power distribution and emissions analyses. Consequently, due to the numerous data inconsistencies and errors noted above, we seriously question the validity of the output from the IPM. [EPA-HQ-OAR-2009-0491-2754.1, p.27]
We presume that since the IPM uses historical data to determine future fuel use and power projections and emission allowances, the use of Ingleside's historical data would be needed to develop an accurate assessment of both power distribution and emissions. Thus, we request that historical information for the Ingleside facility be included in the IPM for this rulemaking. [EPA-HQ-OAR-2009-0491-2754.1, p.27]
We request that modeling inputs be corrected to account for the information listed above before any additional modeling occurs. Furthermore, while the record provides some information on the IPM, based on the fact that the model predicts different heat inputs for the same facility in 2012, we question whether it can be used to model unit specific power generation, emissions and emission rates across half of the United States. [EPA-HQ-OAR-2009-0491-2754.1, p.27]
In particular, we question EPA's use of the Integrated Planning Model ('I PM') for developing emissions allowance allocations. It is our understanding that the I PM is an economic model that cannot account for the complex and realistic operations of power generating facilities and transmission grids. For example, the IPM apparently does not take into account electric load or steam demand by a co-located power/steam host. Thus, the operation of a facility like our Taft cogeneration plant, which provides both a significant amount of steam and electricity to the co-located OCC-owned manufacturing facility, is not modeled correctly. EPA's failure to recognize, model and allocate allowances to cover nondiscretionary emissions generated in connection with the legitimate operation of a manufacturing facility constitutes a fundamental flaw in EPA's allocation of emissions allowances and the CA TR. Furthermore, the model does not take into account legally binding power contracts or other supply mechanisms that exist now and into the future, or state and federal regulations governing electricity pricing and cost recovery. [EPA-HQ-OAR-2009-0491-3796.1, p. 2]
The Documentation for the IPM v. 4.10 Base Case, Chapter 3.5.1 indicates that EPA made certain assumptions about EGU availability in its modeling. EPA stated 'Power plant availability is the percentage of time that a generating unit is available to produce electricity to the grid. Availability takes into account both scheduled maintenance and forced outages ... ' EPA indicated that Appendix 3-9 shows the availability assumptions for all EGUs in EPA Base Case 4.10. EPA indicated that it used an 85% availability assumption for all combined cycle units. With the exception of total plant outages which occur infrequently, combined cycle facilities provide power on a nearly continuous basis. Percent availability information for our Taft Cogeneration plant is as follows:
:: 2007 97.3 Percent Availability
:: 2008 89.3 Percent Availability
:: 2009 87.3 Percent Availability
:: 2010 (YTD) 97.3 Percent Availability
:: Average 92.8 Percent Availability [EPA-HQ-OAR-2009-0491-3796.1, p. 2]
These values take into account scheduled and unscheduled maintenance outages. Note that even in 2009 when the facility had several significant outages for scheduled maintenance, the percent availability was still above EPA's assumption. Thus, we question the validity and value of using the 85% availability assumption. Presuming that other combined cycle plants operate similarly, the IPM v. 4.10 Base Case would seem to be flawed. [EPA-HQ-OAR-2009-0491-3796.1, pp. 2-3]
We noted that the IPM v. 4.10 Base Case contains revised emission rates for the Taft Cogeneration plant. Specifically, it appears that emissions for the Taft Cogeneration plant are estimated to be approximately 49 tons of NOx per year. We presume that EPA will base a revised allowance allocation for OCC's Taft cogeneration facility on this revised emission rate, even though the allocation table provided by EPA for the IPM v. 4.10 Base Case does not appear to reflect this change. Irrespective of the presumed re-allocation, however, the revised emissions estimates are less than 10 percent of what the Taft cogeneration facility emitted in 2009, and only 3 percent of what it is authorized to emit. As mentioned in our previous comments, we respectfully request that EPA grant at least 1,463 tons of annual NOx allowances, 17.7 tons of annual S02 allowances, and 610 ozone season NOx allowances to OCC's Taft cogeneration facility so that if the facility does not meet the rule's current cogeneration exemptions, we may continue to generate power and steam for internal and external consumption from our modern, clean-burning and ultra-efficient units. [EPA-HQ-OAR-2009-0491-3796.1, p. 3]
In light of the deficiencies in the IPM capabilities, data inputs and assumptions, we strongly recommend that EPA abandon the use of the IPM (any version) for allocating unit level allocations. If fact, we are not aware of the IPM being used to model individual emission sources like, for example, single gas turbines at a multi-turbine facility. As an alternative, EPA should rely on the unit-level allocations previously established in State Implementation Plans ('SIPs') pursuant to the CAIR as the basis for allocating emissions in the CATR, including the Louisiana SIP. It is particularly important for EPA to allocate allowances in a manner consistent with existing SIP allocations because many EGU owners have already invested heavily in control technology strategies. These activities cannot be undone with any degree of economic rationality in response to EPA's proposed misallocation of allowances in the CATR. In this regard, EPA should take note of the fact that the Court's remand of CAIR had nothing to do with unit-level allocations. [EPA-HQ-OAR-2009-0491-3796.1, p. 3]
Oklahoma Department of Environmental Quality
[[2662.1 p.2-3]]
Oklahoma's Budget Allocation
Identification of Affected EGUs in Oklahoma
Based on our review of the Electric Generating Unit ("EGUs") listed by EPA in the proposed rule, we do not believe that any of Oklahoma's EGUs have been overlooked; all seem to have been accounted for.
Allocations to Specific Facilities
An analysis of the allocations proposed to be distributed to the Western Farmers Electric Cooperative Anadarko Facility indicates that the allocations were not properly calculated for all the units at that facility. That facility is comprised of some units that are required to report to the Acid Rain Program and some that are not. This may have been overlooked when EPA was developing the emissions data. The Acid Rain units for that facility usually emit about 10 tons of NOx per year, but the emissions for the Acid Rain and non-Acid Rain units approach 3,000 tons of NOx per year.
I. Natural Gas versus Coal-Fired Facilities
In Oklahoma, and perhaps elsewhere, natural gas-fired units were given much smaller budgets as compared to coal-fired units. The coal-fired power plants were allotted 27,088 credits, 3.41% more than their three year (2007  -  2009) average ozone season emissions of 26,194.  The gas-fired plants were allotted 8,064 credits, 6.20% less than their three year average ozone season emissions of 8,597. We are interested to know if this result was purposeful and, if so, why. It seems that EPA would want to incentivize facilities to switch to natural gas, a cleaner burning fuel; however, allotting fewer allocations for natural gas-fired units will not have that result.
[[2662.1 p.3]]
Oklahoma wishes to call EPA's attention to the Western Farmers Anadarko Facility's allocation as well as the apparent discrepancy between the allocations given to natural gas-fired versus coal-fired units.
Old Dominion Electric Cooperative
Based upon this assumption, the Louisa Generation Facility (ORIS Code 7837) and Marsh Run Generation Facility (ORIS Code 7836) were not provided any SO2 allocations and less than adequate allowances for NOx. ODEC requests that these units be provided allowances as listed in the following table. The number of allowances is based upon an average of the annual emissions for the calendar years 2007 through 2010. The ozone season allocations are based upon the maximum ozone season emissions for the same time period. ODEC's peaking units typically operate on natural gas during the ozone season, are very efficient, and, unlike base load units, have no technically feasible controls to reduce NOx emissions beyond the current design. Therefore, ODEC is requesting additional allocations to a maximum value from representative years. These numbers are still significantly below the maximum emissions reported during the same period. [EPA-HQ-OAR-2009-0491-2877.1,p p.4-5] [[See Docket Number EPA-HQ-OAR-2009-0491-2877.1, p.5 for the table.]]
Omaha Public Power District
Given the substantive issues with the Nebraska emission inventory used by EPA for its analysis, the appropriateness of using an episode-based procedure (see comment #8 above) for establishing significant contributions for 24-hour PM2.5, and the need for consistency in setting and rounding of significant impact levels, EP A should revise its analysis to determine if the TR should be applied to Nebraska.[EPA-HQ-OAR-2009-0491-2680.1, p. 6]
If after revising its analysis as appropriate to determine if Nebraska should be included in the TR, and if Nebraska is still determined to be included in the rule, we have the following additional comments:
1. EPA should clarify whether the allocations for the Nebraska 'MRO Coal Steam' unit listed in the allocation table are actually intended for OPPD's Nebraska City Station Unit 2, which came on-line in 2009. If these are meant to apply to Nebraska City Station Unit 2, the basis for the allocation is not consistent with the prevention of significant deterioration (PSD) BACT determination for this unit. While this unit has a PSD permit BACT S02 limit of 0.095 lb/MmBtu, the allowance allocation is based on an S02 emission rate of 0.06lb/MmBtu. It is not reasonable to assume that a unit will operate at a level that is over 35 percent lower than a recent stringent BACT limit. We request that EPA assign an S02 allowance allocation for this new well controlled unit based on an S02 emission rate of 0.095lb/MmBtu, commensurate with the BACT limit. [EPA-HQ-OAR-2009-0491-2680.1, p. 6]
Piney Creek LP
Supporting data for emissions values is incorrect.
1. The method is `generic', essentially using a ratio of annual unit heat values for each state to the total heat values reported to `divide up' the emissions that will be allowed from units in that state.
2. The method of calculating heat rates/heat input is `biased' using a cost value to `simulate' constant MW output within the state to the grid; this cost value is from `real coal' and about three times the actual cost of transport and preparation of waste coal for most of our units, which in the end reduces that `amount of heat input' on each ARIPPA unit to control total emissions within the state and yet provide grid reliability. It falsely approximates total heat input annually to operate at the reported MW net value from Part 75 reporting.
3. Additionally, a `false heat rate' is derived from previously reported data under NOx budget reporting that `back calculates' heat input using a `default' `f' factor that ignores heat input to Calcine limestone in addition to the absorbed heat loss in a high ash fuel which is not recovered into the `steam cycle' but lost to ash processing. This problem is `enhanced by item 2 above, by `adjusting' an incorrect heat input with an incorrect cost bias. A more realistic approach is to directly multiply the mass of fuel put into the boiler times it's heat value as that method was `mandated' when these plants were designed.
4. The result of the above `errors' results in an annual reduced heat input allowance for each ARIPPA unit, often to the point of listing annual heat inputs as calculated with the current `cost bias' method of about 2/3 of the real value. This often will cause units to `violate' terms of their existing PPA's, that require 80-85% peak generation of the last few years. It also `falsely' causes `winners' and `losers' in a deregulated market though `caps' that are disproportionately applied to ARIPPA CFB units.   [EPA-HQ-OAR-2009-0491-2535, p.1]
PowerSouth Energy Cooperative
The data period used to develop the Proposal is too short to fairly represent each plant's range of operations and penalizes units for planned and unplanned outages that occurred during the extremely brief data period.  The Proposal uses only four strategically selected quarters of data to determine heat inputs and emission rates.  While this tact may have made it easier for EPA to design its regulatory remedy, it is inappropriate for such an important part of the Proposal.  EPA must use more data.  An alternative EPA has successfully used in the past is the highest three of five year methodology for heat inputs in the NOx SIP Call.   A larger data period more representative of plant operations is absolutely vital if the Proposal is enacted. [EPA-HQ-OAR-2009-0491-2693.1,p.5]
The Proposal as written contains grievous errors and should be discarded.  As noted above, the Proposal is ill-conceived on so many levels.  To add insult to injury, the Detailed Unit Level Data Spreadsheet omits units, mislabels units and allocates allowances to units not entitled to allowances.  The Proposal should be scrapped and a new rule should be developed with input from the stakeholders.  [EPA-HQ-OAR-2009-0491-2693.1,p.7]
Renaissance Power
In review of the budget allocations for the Renaissance Power Plant in Michigan, ORIS 55402, Renaissance Power believes that the use of the projected data to estimate the allowances for this project significantly misrepresents the expected usage of the plant. Renaissance Power has had capacity factors of
2005  -  7.41%
2006  -  4.89%
2007  -  5.29%
2008  -  4.07%
2009  -  3.33% 2010  -  6.44% (YTD)  [EPA-HQ-OAR-2009-0491-3018,p.1]
The allocation uses projected data which shows that the capacity factor for the plant will drop to 0.6% - a significant change (88% reduction from the 5 year average) from the above historical capacity factors. As Renaissance Power is a peaker facility, the addition of new controls on major units won't change their ability to provide power during peak periods so Renaissance Power does not believe that the use of projected data is appropriate for its facility. [EPA-HQ-OAR-2009-0491-3018,p.1]
State of Delaware Department of Natural Resources & Environmental Control
The first recommendation is that EPA reconsiders the use of the most recent quarterly data from the period 2007 through 2009 as the baseline. It is popularly viewed that calendar year 2007 is the last calendar year that has little effect from the current economic downturn. As such, it is assumed that the operation of EGUs in 2007 is more representative of expected normal operation for the units that operated during that period. For many of the units not incorporating post-combustion controls, unit hourly loading and average capacity factor can have a noticeable effect on emission rates (in terms of 1b/MMBTU or lb/MW). Therefore, it is Delaware's opinion that utilizing 2007 operating data would provide a more accurate indication of both the units' uncontrolled emission rate and the emission rate resulting from the theoretical installation of emission controls. For units that did not operate in 2007, such as new units, emissions data from the earliest of 2008 or 2009, as applicable to the individual unit, could be utilized. EPA-HQ-OAR-2009-0491-2980.1, p.5]
EGU Inventories. During review of EPA's technical support documents for budgets and allocations for the proposed rule, Delaware has identified a number of problems with the inventory of EGU's included by EPA in the development of the budget and allocation levels for Delaware. 4 The problems noted during Delaware's review include the following: [EPA-HQ-OAR-2009-0491-2980.1, p.7]
EPA's proposed rule unit inventory has included in Delaware's unit inventory a number of units that are co-generation units. [EPA-HQ-OAR-2009-0491-2980.1, p.7]By combining sources of data and information concerning units, as discussed in EPA's TSD State Budgets, Unit Allocations, and Unit Emissions Rates, EPA 'double counted' emissions among three Delaware units, by accounting for emissions for two header supplied steam turbine- generators from one data source, and then from another data source accounting for emissions from a boiler that supplies that steam header for the two header supplied steam turbine-generators. [EPA-HQ-OAR-2009-0491-2980.1, p.7]
EPA's emissions data and allowance allocations have included header steam turbine generating units that are supplied by multiple non-fired heat recovery steam generating units. As the boilers are not fired, it is uncertain how they would produce emissions given that the emissions associated with related combustion turbines are attributed directly to those combustion turbines. [EPA-HQ-OAR-2009-0491-2980.1, p.7]
EPA excluded two Delaware units from the proposed program, apparently due to the EPA's data assigning the units output ratings less than 25 MW. It appears that the EPA based this rating on data that indicates that these units have 'summer' ratings of 22 MW on a net output basis. However, these particular units have 'nameplate' ratings in excess of 25 MW, and also have 'winter' ratings of 25 MW on a net basis. There are three apparent issues demonstrated within this problem. [EPA-HQ-OAR-2009-0491-2980.1, p.7]
The first apparent issue is the use of 'summer' output ratings, which includes the effect of higher summer temperatures reducing the output of the unit, which is contrary to the definition of nameplate rating included in the EPA's proposed rule which states, 'Nameplate capacity means, starting from the initial installation of a generator, the maximum electrical generating output (in MWe) that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings) as of such installation as specified by the manufacturer of the generator ... ' [EPA-HQ-OAR-2009-0491-2980.1, pp.7-8]
The second apparent issue with the use of 'summer' output ratings, is that the 'summer' output ratings includes the effect of higher summer temperatures that . tend to reduce the output of some units (combustion turbines and steam units). This appears to be contrary to EPA's definition in the proposed rule, as noted above, that indicates that the nameplate rating should not include any capacity restrictions due to 'seasonal or other deratings'. [EPA-HQ-OAR-2009-0491-2980.1, p.8]
The third apparent issue is the use of these values that are 'net' unit electrical outputs, or the electrical output available to the grid after subtracting any electrical energy that is utilized by the unit in the generation of the total electrical energy. The definition of nameplate capacity in EPA's proposed rule, as noted above, clearly indicates that EPA intends that nameplate capacity be the gross electrical output, or total electrical output from the generator. [EPA-HQ-OAR-2009-0491-2980.1, p.8]

Footnote:
4 Because of the generic nature of some of these apparent problems, Delaware is of the opinion that similar issues may exist for some other states subject to this proposed rule. These problems that appear to have the potential to generic in nature should be investigated by EPA and corrected as necessary in establishing final emissions budgets, allocations, etc. [EPA-HQ-OAR-2009-0491-2980.1, p.7]
Tampa Electric Company
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.55.]
Given the short period of time to evaluate, that's been a recurring theme I guess in talking with our other -- our peers, colleagues.
If we could have -- I know I've gotten a lot of information on the website, spreadsheets with maybe formulas and links. It's just data in there.
Sometimes it's difficult and time-consuming to decipher how we got those, so that would be helpful, and then maybe we can get with the specific people, some specific people on that.
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.70-71.]
However, we are still unable to determine how the allocation spreadsheet inputs are related to one another and are utilized in determining the models outputs.
One suggestion, please provide the links within the spreadsheets, unless only macros are used, to help us follow along the allocation logic. We believe the models outputs can be used as a powerful tool to aid in the development of the Transport Rule, but it should not be a definitive artifact in the formation of the rule and determining states emission budgets. EPA has already identified that a number of data errors exist in the model. These errors can have potentially dramatic impacts on the results of the model.
Just within our mid-sized electric generation fleet, a number of model input assumption errors have been identified. Examples of the types of errors found include: Allocating different emission budgets to identically sized and controlled units, or dispatching the same unit differently for estimated NOX and SO2 future emissions and consequential downwind effects.
Tennessee Department of Environment and Conservation, Division of Air Pollution Control
Comment #3 on Emissions Budgets: We reviewed the annual SO2 budgets for 2012 and 2014, annual and ozone season NOX budgets for 2012, estimated emissions, and IPM projections for several States (see Attachment #3) [[See Docket Number OAR-2009-0491-0553.1, pp.8-13 for Attachment 3]]. When variability is considered, the 2014 budgets appear to be fairly close to the IPM predictions, but IPM predicts that emissions from most of these States will be slightly above their three-year allowance (see Table 1b in Attachment #3, column #6). EPA should consider adjustments to bring the 2014 budgets plus variability into line with IPM predictions. [EPA-HQ-OAR-2009-0491-0553.1, p.4]
Comparison of the 2012 budgets with actual emissions, rather than IPM predictions (see Table 1b in Attachment 3, columns #5 and #8), suggests that many States will require greater SO2 reductions than predicted by IPM. The Transport Rule analysis assumes no additional add-on controls between 2010 and 2012, but we are concerned that the necessary reductions for 2012 may not be achievable with existing controls and low-sulfur coal. This analysis is based on lowest corrected emissions (i.e., lowest emission rate and lowest heat input), and greater reductions would be required at higher heat inputs. [EPA-HQ-OAR-2009-0491-0553.1, p.4]
To a lesser extent, we have similar concerns with annual and ozone season NOX emissions (see Tables 2 and 3 in Attachment #3). The 2012 emissions budgets appear to be attainable at lower heat inputs, but some States may encounter similar difficulties with NOX reductions at higher heat inputs. [EPA-HQ-OAR-2009-0491-0553.1,p.4]
We understand that EPA has reviewed these issues in detail, but we request that EPA take a closer look at IPM data and historic emissions to ensure that all factors have been taken into consideration. [EPA-HQ-OAR-2009-0491-0553.1, p.4]
Utility Air Regulatory Group (UARG)
In addition to the NEEDS and IPM input errors, it appears EPA made downward adjustments to NOx emission rates in IPM that are unwarranted, unreasonable, and inaccurately described in the State Budgets TSD. The State Budgets TSD indicates that "NOx controls were assumed not to control beyond a floor of 0.06 lb/mmBtu." The 0.06 lb/mmBtu rate would be more accurately described as a ceiling than a floor because of the adjustments EPA made to NOx emission rates. If a unit reported historical data that supported a NOx emission rate lower than 0.06 lb/mmBtu, EPA used that lower emission rate. Yet if a unit reported historical data that demonstrated a NOx emission rate higher than 0.06 lb/mmBtu, EPA -- apparently arbitrarily -- made a downward adjustment of that rate to 0.06 lb/mmBtu. Such downward adjustments are unfair and unwarranted. Incentives exist in most cases to emit at the lowest reasonably achievable NOx emission rate, and if a given unit reports NOx emissions at rates above 0.06 lbs/mmBtu, it is likely that that unit cannot physically and consistently operate at a lower rate. At a minimum, an across-the-board downward adjustment to 0.06 lb/mmBtu, without consideration of case-by-case factors, cannot be justified. Under EPA's proposed approach, where an existing unit cannot in fact meet the 0.06 lb/mmBtu rate, that unit may well be forced to upgrade its pollution control device or acquire allowances. EPA did not anticipate either of these options in the PTR and does not seem to have accounted for the costs associated with these options in the PTR. EPA should abandon its approach of making across-the-board downward adjustments to 0.06 lb/mmBtu and should instead use historical reported emission rates on a unit-by-unit basis. [EPA-HQ-OAR-2009-0491-2756.1, pp.84-85]
Wisconsin Power and Light Company
Finally, WPL is highly concerned that flawed data and operational assumptions will negatively and disproportionately impact the implementation of EPA's preferred option. As a consequence of the NODA, the EPA has stated that issuance of the final rule will require significant changes to modeled outcomes impacting both state budgets and individual EGU allocations. WPL recommends that prior to issuing a final rule, EPA release a Supplemental Notice of Proposed Rulemaking and/or a Notice of Data Availability ('NODA') that allows owners of covered units to verify the data underlying the allocations in the final rule and provide any necessary comments correcting the data. Without the critical step, it is inconceivable that the EPA will be able to realistically revise its state budgets and source allowance allocations to accurately reflect when and where emissions reductions can be achieved in a highly cost-effective manner. EPA must allow affected sources to validate the use of these models on the operation of their electric generation fleet and ensure sufficient time to prepare for compliance. [EPA-HQ-OAR-2009-0491-2844.1 p.6]
Response:
The final Transport Rule allowance allocation tables can be found in the Allowance Allocation Final Rule TSD.  EPA also notes that, as requested by commenters, it made all the historic data used in the heat input allocation alternatives available to the public for review and comment through the January 7, 2011 NODA.  Because those approaches were based on historic data that had been reported by the source's designated representative who had testified to its accuracy and completeness, EPA did not expect many corrections.  Nevertheless, the Agency still allowed for a public review of the data and subsequently made corrections to historic heat input and emissions data where the commenters provided reasonable corrections.
The final Transport Rule approach to determining state budgets reflects improvements made from the proposal based on comments.  Some commenters noted that the proposal's budgets did not appear to match the IPM projected state-level emissions at the final cost thresholds determined in the multi-factor analysis.  EPA used an approach for determining budgets in the final rule that is directly based on projected IPM emission levels from fossil fuel-fired units greater than 25 MW that remain after significant contribution has been eliminated in an average year.  Additionally, EPA notes that there is no relationship between final Transport Rule state emission budgets and CAIR state emission budgets.  As discussed in the preamble (see section III, V.B, and VI), the Court determined those budgets to be illegal and the Transport Rule was designed to replace those budgets with new budgets that reflected the elimination of significant contribution at the state level.
EPA also made updated to its IPM modeling (see EPA IPMv.4.10 documentation) to better reflect the feasibility and cost-effectiveness of coal switching.
Organization: International Paper
Comment:
International Paper
International Paper was alerted to the fact that its units were listed on Transport Rule Allocation tables associated with the proposed Transport rule. International Paper operates its Augusta Mill under Part 70 Permit 2631-245-0006-V-02-0; Facility AIRS Number 04-13-245-00006 [EPA-HQ-OAR-2009-0491-2784.1 p.1]
Specifically, International Paper-Augusta Mill's Kraft pulping liquor recovery furnaces, RB2A No.2 Recovery Boiler and RB3A No.3 Recovery Boiler, were listed as affected units (ORIS 54358) in Georgia. These units, prior to EPA revising the cogeneration definition on October 19, 2007 72FR59,190, where affected facilities under the CAIR rule. However, based on EPA's current definition RB2A and RB3A are cogeneration units and not subject to CAIR or the Transport rule. [EPA-HQ-OAR-2009-0491-2784.1 p.1]
Augusta Mill's Recovery Boilers meet the definition of cogeneration units with useful power efficiencies consistently in the 100% to 10,000 % range for the RB2 and RB3. The high power efficiencies are a result of the boilers primarily being biomass burners. [EPA-HQ-OAR-2009-0491-2784.1 p.1]
Recovery Boilers at Augusta are not subject to the various sections of the Transport Rule as outlined in the proposed applicability sections (§§ 97.404 and 97.405, 97.504 and 97.505, 97.604 and 97.605, and 97.704 and 97.705-Applicability). Specifically, these units are not applicable unit because they qualify as exempt cogeneration units as outlined in, for example, 97.404(b)(1 )(i). [EPA-HQ-OAR-2009-0491-2784.1 p.1]
We support EPA's applicability definitions. However, please remove the recovery boilers from the applicable units table.' If you would like to contact us, feel free to call or write<EMAIL_ADDRESS>or<PHONE_NUMBER>. Thank you. [EPA-HQ-OAR-2009-0491-2784.1 p.1]
[[These comments are also posted under section V.F.3]]
Response:
EPA is not making any applicability determinations in its final Transport Rule.  As explained in the TSD for Allowance Allocation, EPA developed a list of potential covered Transport Rule units based on best available data.  Updated were made to the list based on commenter data, and EPA notes that the final allocation tables do not list the above units as potential existing Transport Rule units.
Organization: Kentucky Division for Air Quality
Public Power Generation Agency
Virginia Department of Environmental Quality (VDEQ)
Comment:
Kentucky Division for Air Quality
Proposed Transport Rule SO2 Unit Allocation
Pursuant to the proposed Transport Rule Preamble Section V.D.4., Allocation of Emissions Allowances (75 FR 45309-45312), the EPA SO2 unit allocations may be incorrect. Even though the 2014 Transport Rule SO2 budget decreased by 48% from the 2012 Transport Rule SO2 budget, certain unit's SO2 allocation in 2014 actually increased and in some cases significantly. Based on the Division's experience in providing previous allocations for the NOx SIP Call and Clean Air Interstate Rule (CAIR) NOx emissions trading programs, the Division contends that the 2014 allocation could not have been performed on a proportional (pro rata) basis since in that instance no unit's allocation for 2014 would have increased from its 2012 allowance allocation. Therefore, the Division requests that EPA verify the SO2 unit allocations to ensure that they were allocated properly. [EPA-HQ-OAR-2009-0491-2805.1, p.3]
Proposed Transport Rule NOx Unit Allocation
Pursuant to the proposed Transport Rule Preamble Section V.D.4., Allocation of Emissions Allowances (75 FR 45309-45312), in light of the Division's comments on EPAs SO2 unit allocations, the Division requests that EPA verify the NOx unit allocations to ensure that they were allocated properly. [EPA-HQ-OAR-2009-0491-2805.1, p.4]
Applicable Units
Pursuant to the proposed Transport Rule Preamble Section V.D.4., How the proposal Would Be Implemented, Applicability (75 FR 45306-45309), the Calvert City Cogeneration EGU (turbine  -  ORIS - 55308-Gen1) as shown in EPA's Technical Support detailed allocation file (BADetailedData.xls, Units Characteristics Worksheet) should indicate a capacity of 26 MWe instead of 23 MWe as is listed. This cogeneration EGU was part of the NOx SIP Call NOx ozone season trading program and was brought into the CAIR NOx ozone season program. However, the unit was exempted from the CAIR NOx annual program since it met the CAIR NOx annual program cogeneration exemption. Even with the CAIR ozone season cogeneration exemption, the unit was subject to the CAIR NOx ozone season trading program since it was previously subject to the NOx SIP Call NOx ozone season program which did not provide a cogeneration exemption. The Division requests that EPA work with the Division to verify that the Calvert City Cogeneration EGU is also exempt from the proposed Transport Rule NOx annual trading program pursuant to the Transport Rule cogeneration exemption and to include this unit in the proposed Transport Rule NOx ozone season trading program. [EPA-HQ-OAR-2009-0491-2805.1, pp.4-5]
E.ON U.S., (ORISID 6071) Trimble Unit 2, which started operation in 2010, should be included in the proposed Transport Rule emissions trading programs. In addition, the Division recommends that before the Transport Rule unit allocations are finalized and recorded that EPA consult with the Division to make sure that all existing units subject to the proposed Transport Rule have been properly accounted for in the proposed rule's unit allocations. The Division reserves the right to inform EPA of any additional unit omission or incorrect inclusion for EPA's Transport Rule even after the comment period deadline has passed. [EPA-HQ-OAR-2009-0491-2805.1, p.5]
Public Power Generation Agency
WEC Unit 2 meets the applicability requirements of the PTR to be characterized as an 'existing unit' and should have been allocated allowances. WEC Unit 2 was not included in either the NEEDS database or the IPM modeling and did not receive any allowances in the PTR. The purpose of these comments is to describe the relevant characteristics of WEC Unit 2, explain why it constitutes an existing unit under the PTR, and address the number of allowances WEC Unit 2 should receive in the final rule. [EPA-HQ-OAR-2009-0491-2705.1, p.1]
PTR Applicability and 'Existing Units'
According to the PTR, 'a covered source would be any stationary, fossil-fuel-fired boiler or stationary, fossil -fuel-fired combustion turbine serving at any time, since the later of November 15, 1990 or the start-up of the unit's combustion device, a generator with nameplate capacity of more than 25 MWe producing electricity for sale.' 75 Fed. Reg. at 45306. The units to which the PTR applies are further parsed into two categories: 'existing units' and 'new units.' An existing unit is a 'unit[ ], as described in the Applicability section, [quoted above] .. . , that commenced commercial operation, or [is] planned to commence commercial operation, prior to January 1, 2012.'3 1d. at 45309 (footnote omitted) (emphasis added). 'Planned' units are defined as 'units that had broken ground or secured financing and were expected to be online by the end of 2011.' [d. at n.85. The section of the PTR that provides the definitions of existing and planned units also describes how those units are allocated allowances. [EPA-HQ-OAR-2009-0491-2705.1,p.4]
WEC Unit 2 meets the definition of a planned unit as described in the PTR preamble and thus is an existing unit as defined by EPA. WEC Unit 2 has broken ground and obtained financing and is currently planned to be in commercial operation well before January 1, 2012, and thus meets the definition of a planned unit - and therefore is an existing unit. WEC Unit 2 is scheduled to come online in early 2011 and begin producing electricity for sale from its 220-MW generator at that time. According to the provisions set forth in the PTR, WEC Unit 2 is entitled to an allocation of allowances. [EPA-HQ-OAR-2009-0491-2705.1,pp.4-5]

3 The proposed regulatory language for §§ 97.411 and 97.711, found at 75 Fed. Reg. 45376 and 45450, respectively, discusses the allowance allocation process for 'existing units' but does not provide the same explicit discussion of 'existing' and 'planned' units that is provided in the preamble discussion.
Virginia Department of Environmental Quality (VDEQ)
It is unclear why allocations were provided to Dominion Bear Garden and Dominion Warren County, two planned facilities that will burn natural gas in combined cyc1e units, but allocations were not provided to the Virginia City Hybrid Energy Center (VCHEC), a 585 MW state of the art facility that will mainly burn coal and coal refuse. Construction began at VCHEC in June 2008 and as of July, 2010, is approximately 65 percent complete. VCHEC is on schedule to begin generating electricity commercially in the summer of2012. See the websites listed above for the relevant permits. [EPA-HQ-OAR-2009-0491-2595.1, p.4]
Spruance Erigenco (ORIS 54081) and Hopewell Cogeneration (ORIS 10633) received allocations but James River Cogentrix (ORIS 10377) and Portsmouth Cogentrix (ORIS 10071) did not. It is unclear why these facilities were not included. Both are large emitters of SO2 and burn coal. Both installed dry scrubbers 10 participate in CMR, and these scrubbers are capable of reducing SO2 emissions by 90% or more. However, if they are not included in the Transport Rule trading scheme as applicable units, then there will be no impetus for them to operate the dry lime scrubbers. James River does have a steam host that uses some steam from the facility. However, Portsmouth Cogentrix has no steam host and operates only to produce power. [EPA-HQ-OAR-2009-0491-2595.1,p.4]
For certain units such as Birchwood Power (ORIS 54304), the 2012 annual NOx allowances and the 2012 annual SO2 allowances are based on significantly different heat inputs (for Birchwood, about 15,000,000 mmBtu and 18,000,000 mmBtu respectively). This inconsistency appears to be due to the fact that NOx allocations are based on 2008 actual heat input whereas SO2 allocations are based on predicted heat input using IPM. Putting aside the relative merits of using real data versus using predicted data from a model that has performed very poorly in the past, this inconsistent use of heat inputs to calculate allocations unnecessarily complicates the allocation process. Additionally, the purpose of trying to estimate future heat input is to calculate expected emissions and the resultant downwind impacts. Therefore, the most likely heat input scenario should be chosen to estimate emissions and allowances for both pollutants. Using disparate heat input estimates for the same unit for the same year creates emissions estimates that are not based on the same amounts of fuel used, adding not only confusion but also inaccuracies to the process. For any given unit, one value for heat input should be used for 2012, and that heat input should be the basis for 2012 allocations of allowances for both NOx and SO2 for that unit. As noted in previous comments, VDEQ suggests abandoning the use of IPM for future allocations and using previous years' activity data to calculate allocations. [EPA-HQ-OAR-2009-0491-2595.1, p.4]
Ladysmith Combustion Turbine Power Station has several units that are incorrectly assigned to ORIS 7838. The correct ORIS for this facility is 7839. This issue may be the result of an incorrect cross index between units reporting to CAMD and unit information in the NEI. VDEQ recommends that EPA acquire the most recent MARAMA crosswalk between CAMD and NEI identifiers and that EP A ensure that this information is applied to both the modeling inventories as well as the data used for determining allocations. [EPA-HQ-OAR-2009-0491-2595.1, pp.4-5]
There are instances where steam generators that have no emissions are assigned allocations, such as Hopewell Cogeneration, ORIS 10633. CAMD data clearly show only 3 emission points, as does the NEI (facility code 51-670-0058). However, the 'Budget and Allocations Details.xls' spreadsheet has 4 emissions points from the facility with allocations assigned. [EPA-HQ-OAR-2009-0491-2595.1, p.5]
Response:
Units commencing commercial operation after January 1, 2010 would not be included in the list of potential existing Transport Rule units because they would be considered new, not existing, units under the final Transport Rule.  Such units would be able to receive allowances through the state's new unit set-aside account.  Additionally, the list of potential existing covered units under the Transport Rule that EPA identifies for receiving allowances under the FIP by no means reflects a Transport Rule applicability determination for EGUs.  It simply reflects EPA's preliminary assessment of covered sources based on best available data and comment received during the Transport Rule comment periods.
Organization: Michigan Department of Natural Resources and Environment
Comment:
Michigan Department of Natural Resources and Environment
The proposed TR allowance/budget data supplied in the BADetailedData.xls spreadsheet shows major differences as compared to the state's CAIR program in the projected emissions for several of Michigan's municipally owned and operated EGUs. [EPA-HQ-OAR-2009-0491-2774.1 p.8]
The DNRE disagrees with the EPA's assumptions in this area. We believe that several sources were erroneously projected to have zero emissions in 2012 and after. The DNRE notes that several of these smaller municipally owned EGUs, which have the obligation to serve, will continue to operate far into the future. We believe that making these assumptions in the proposed TR has created an area of economic hardship for small business sources within Michigan. [EPA-HQ-OAR-2009-0491-2774.1 p.8]
In particular, the DNRE would like to point out that:
 :: MSCPA Endicott and Wyandotte's units were not given any allowances. The DNRE has no knowledge that these sources will cease to operate and expects that they will continue to operate as they have in the past.
:: Holland Board of Public Works' 48th Street Unit #7 was given not any allowances, but the other units were at the location were allocated for 2012 and beyond. Once again, the DNRE expects that Unit # 7 will continue to operate as in the past.
:: Holland Board of Public Works' De Young plant received more allowances under the proposed TR than the CAIR program.
:: Genesee Power and Grayling Generation were left out of the allocations. The DNRE expects these plants will continue to operate as they have in the past.
:: Cadillac Renewable, Lansing Board of Water and Light, Grand Haven Power Plant, and the City of Marquette's Shiras Power Plant all received significant allowances, but very different than in CAlR.
:: Michigan Power Limited received token allowances, not anywhere near what they received under CAIR. In recent conversations with the facility, they said they are under an obligation to serve their community for quite some time into the future.
The DNRE's review raises serious concerns about the accuracy of the assumptions used to identify units that would not be operating in the future and with the allocation method in general. [EPA-HQ-OAR-2009-0491-2774.1 p.8]
Response:
EPA received significant comment on the proposed Transport Rule allocation methodology that expressed concerns similar to those expressed by commenter.  EPA subsequently developed two alternative historic heat input alternatives, took comment on the approaches, and is finalizing an allocation methodology that does not rely on IPM projections.  This addresses concerns about units not receiving allocations because IPM projected them not to operate.  Under the final allocation methodology approach, a unit's allocation is indexed to its historic operation.  This approach is described in section VII.D of the preamble.  Many of the units described above as receiving 0 allocations, do receive allocations under the allocation methodology finalized for the Transport Rule.
Organization: Pratt & Whitney
Comment:
Pratt & Whitney
Pratt & Whitney notes that the Pratt & Whitney Cogeneration unit (Cogen), ORIS 54605, located in East Hartford, CT, is included in the Allocation Table, which is listed in the Technical Support Documents for the Proposed Transport Rule. This unit should not be included in the documentation for the Transport Rule as it meets the cogeneration exemption of not 'supplying in any calendar year more than one-third of the unit's potential electric output capacity [104,292 MWe-hrs] or 219,000 MWh, whichever is greater'. [EPA-HQ-OAR-2009-0491-2584.1, p.1]
The Pratt & Whitney Cogen permit was upgraded to allow a 32 MW unit at the end of 2002. The cogeneration unit provides a portion of the electrical power required by the facility and also provides steam for process and building heating and cooling. If at any time the cogeneration unit creates more power than the facility is using at the moment, the excess power is sold to the grid. The annual data since 2003 clearly indicates that Pratt & Whitney has consistently sold below the 219,000 MWh cogeneration exemption threshold:[[See [EPA-HQ-OAR-2009-0491-2584.1, p.1 for a table that shows Power sold to the grid by Pratt & Whitney.]]
Pratt & Whitney requests that our cogeneration unit, ORIS 54605, be removed from the proposed Transport Rule FIPs Allocation Table and that the EPA confirms that this regulation will not apply to the Pratt & Whitney Cogen. [EPA-HQ-OAR-2009-0491-2584.1, p.1]
Response:
Connecticut, and the units located in the state (including Pratt & Whitney), were not determined to be a contributing state in the final Transport Rule.  Therefore, the units of concern to the commenter are not subject to the Transport Rule and are not in the final allocation tables.
Organization: South Carolina Department of Health and Environmental Control
Comment:
South Carolina Department of Health and Environmental Control
The Budgets and Allocations Spreadsheet fails to include SO2 controls that Santee Cooper installed at its Cross25 and Winyah facilities, and NOX controls at its Grainger and Jeffries facilities, to comply with its 2004 consent decree,26 yet the EPA notes these consent decree requirements in other areas of the proposed Transport Rule.27 DHEC notes that without the projected SO2 reductions from the flue gas desulfurization ("FGD") units at Cross and Winyah, and NOX reductions from the low NOX burners at Grainger and Jeffries, South Carolina's emissions projections are unnecessarily high. As discussed earlier, the EPA failed to include other controls in the Budgets and Allocations Spreadsheet, but those are most likely because the EPA is assuming that they were installed to comply with the CAIR. With the Santee Cooper controls, however, the consent decree is an independent reason for Santee Cooper to maintain these controls, and thus there is no apparent justification for not including the controls in the budgets and allocations analysis. [EPA-HQ-OAR-2009-0491-2677.1 p.13]
If the EPA adds the mandated Cross FGD units to its Transport Rule modeling, then South Carolina's projected SO2 emissions would be significantly lower. This offers additional evidence that the uncertainty surrounding the IPM projections should lead the EPA to adopt the higher 1 μg/m3 threshold and remove South Carolina from the SO2 Group 2 trading program. Even if the EPA retains its proposed thresholds, South Carolina may fall under the thresholds if the EPA uses the actual SO2 emissions data that includes the correct Cross controls rather than fallacious projections. [EPA-HQ-OAR-2009-0491-2677.1 p.13]
Response:
EPA updated its IPM modeling and reran its analysis to determine states that contribute to downwind nonattainment and/or interference with maintenance.  The updated model reflects the FGDs at Cross and Winyah, and the LNB at Grainger and Jeffries as described above.  The final Transport Rule air quality analysis still linked, even with the modeling updates, South Carolina to states with nonattainment and or maintenance issue.
Organization: Sunflower Electric Power Corporation
Comment:
Sunflower Electric Power Corporation
Sunflower requests that EPA provide annual NOX allowances for the Garden City S2 unit (Oris ID Code 1336) in the appropriate manner as it has allocated allowances to that unit for the ozone season. EPA, we think by oversight, did not include an annual allocation for S2. As an example, our Great Bend Station (Oris ID Code 1235) was allocated both annual and ozone season allowances. Both the S2 and Great Bend units are operated for intermediate-duty, both are dispatched in much the same manner throughout the year, and both should be allocated annual and ozone season allowances in much the same manner. We think these facts substantiate our analysis, and we respectfully request that EPA correct the oversight by promptly allocating an appropriate number of annual NOX allowances to the facility (Oris ID Code 1336). [EPA-HQ-OAR-2009-0491-2833.1 p.2]
Response:
Under the final Transport Rule allocation methodology, a unit's allocation is indexed to its historic operation over a five year baseline (see section VII.D of the preamble).  This results in the Garden City S2 unit receiving an allocation.
Organization: U.S. Congressman Pete Hoekstra
Comment:
U.S. Congressman Pete Hoekstra
Specifically, we are concerned with the proposed SO2 allocation of '0' given to our Unit 5 starting in 2014. The methodology document that the EPA provides ('State Budgets, Unit Allocations and Unit Emission Rates', prepared July 2010 in support of this rule, states on page 12 'Units in group 1 states without an IPM projection do not receive SO2 allocations in 2014 and beyond'. Why? We are unclear after reviewing the document how and why this allocation was made. The HBPW has no intention of retiring this unit at any time in the near future. We are confident that certain control methodologies can be implemented to reduce emissions consistent with the average percentage reduction required of the State of Michigan. The modeling program is arbitrary and fails to consider the real-life evaluations and decisions that will be made by municipalities like the HBPW. [EPA-HQ-OAR-2009-0491-3662, p.3]
In addition, the Holland BPW was recently denied by the State of Michigan to build a new larger coal-fired electric generating unit with state-of the-art pollution controls (78 MW unit with emissions similar to our smallest, oldest unit 3, 11.5 MW.; and would be able to bum biomass fuels). Now, as a result of this rule, we would be mandated to cease coal-firing our 'newest' existing Unit 5 by 2014. [EPA-HQ-OAR-2009-0491-3662, p.3]
As pointed out in the comments from MMEA, Holland is the site for two recently announced lithium-ion battery advanced energy storage plants. Three months ago President Obama visited Holland for the ground breaking for one of those plants, LG Chern. Unit 5 will be critical to meeting the power supply needs of these facilities in a cost-effective manner [EPA-HQ-OAR-2009-0491-3662, p.3].
Response:
EPA has revised its allocation methodology to address concerns about units receiving 0 allocations because IPM projected them to not operate.  The final Transport Rule allocation methodology is based on historic heat input over a five year baseline.  Therefore, if the unit operated during that time period, it would be receiving an allocation amount that reflected such operation.  The specific allocation methodology is described in section VI of the preamble.  Also, for any new units commencing operation, they would have access to the new source set-aside allowances.  This set-aside account in the final rule has been modified (increased in some states) to reflect planned units under construction and/or coming online after Jan. 1, 2010.  This approach for determining set asides in the final rule makes more allowances available to newer, cleaner units as a percentage of state budgets relative to the proposal.
Organization: West Virginia Department of Environmental Protection
Comment:
West Virginia Department of Environmental Protection
[[2790.1 p.4]]
While both the ozone season and annual NOx budgets for 2012 and 2014 for West Virginia have been reduced from CAIR levels under the proposed Transport Rule, the budgets for some other states have increased by significant amounts. Florida and Pennsylvania both receive large proposed increases in their annual NOx budgets - 20,556 and 14,854 tons, respectively in 2012, and 37,130 and 31,362 tons, respectively in 2015; and their ozone season NOx budgets are proposed to increase by 9,027 and 6,100 tons, respectively, in 2012 and 17,013 and 13,128 tons, respectively in 2015. It is difficult to perform a comparison of the regional budgets because the states affected by the Transport Rule and CAIR vary. An analysis of the budgets of the states affected by both CAIR and the Transport Rule for annual NOx shows there are twelve states that have increased annual NOx budgets under the proposed Transport Rule, and twelve states with decreased annual NOx budgets, resulting in a decrease of 49,858 tons for the states covered under both rules for 2012. However, only seven states show a decrease in their annual NOx budgets for 2015, and there is a regional increase of 170,621 tons of annual NOx in 2015. Similar issues arise with the ozone season NOx budgets.
Under the proposed Transport Rule, the 2014 annual NOx emission cap is too generous - more than CAIR Phase II. It is widely assumed that Transport Rule II will rectify this, as the intended rule will address a new ozone standard. Leaving the 2014 NOx cap at its proposed level will hinder efforts to mitigate interstate transport and significant contribution, especially if Transport Rule II is not promulgated for some reason. In the final rule, EPA should include a 2014 annual NOx emission budget which is technologically feasible and cost effective. WVDAQ questions whether the proposed 2014 NOx cap might be considered backsliding under the Clean Air Act.
Pennsylvania is central to the Northeast's nonattainment problems, and Pennsylvania sources have 'rented compliance' in past and current transport programs. Comparing the proposed Transport Rule 2012 budgets to the budgets under CAIR, Pennsylvania would receive 15 percent more of the annual NOx budget over that state's allotment under CAIR, while West Virginia would receive a 30 percent decrease in annual NOx budget from CAIR. Considering that West Virginia sources have made significant reductions in S02 and NOx emissions, this and similar comparisons indicate that the proposed budget methodology in the Transport Rule creates a situation where states that already have highly controlled sources (under the NOx Budget Trading Program and CAIR) receive budgets that disadvantage the units that controlled their emissions earlier in favor of states with many yet uncontrolled units. EPA should revise the Transport Rule allocation methodology to minimize such disadvantages, provide increased incentive to control uncontrolled units, and distribute allowances in a more equitable manner.
[[2790.1 p.2-3]]
WVDAQ has analyzed the initial data contained in the proposed Transfer Rule docket, and have found the following errors that should be corrected in the final rule:
a. The Alloy Steam Plant is a non-EGU source and should not be grouped with EGU sources nor included in the IPM modeling or allocated allowances in the Transport Rule. The Alloy Steam Plant was erroneously included in both the NEEDS v3.02 EISA and NEEDS v4.l0 databases (ORIS 50012, Unique ID 50012_B_BLR4), and was allocated allowances in the TSD Allocation Table. The allowances allocated to Alloy should be redistributed to existing EGU sources in West Virginia.
b. The Longview Power Plant was incorrectly identified in the NEEDS v3.02 EISA database as RFCP _WV_Coal steam, ORIS Code 82716, Unique ID 82716_B_l, and was incorrectly identified in NEEDS v4.l0 database as RFCP _WV_Coal steam, ORIS Plant Code 82914, Unique ID 82914_C_1. Longview Power Plant's correct ORIS Code is 56671. Although Longview was included as an existing unit in 2012 and allocated allowances for 2012 in the TSD Allocation Table, the source was not allocated any allowances in 2014, even though it was included in the modeling and parsed files for 2014. Longview is scheduled to be online in early 2011, and by definition will be an existing EGU under the proposed rule. Longview Power Plant identification data should be corrected, and the source should receive allowances for both 2012 and 2014, along with other existing EGU sources in West Virginia.
c. The Big Sandy Peaker Plant (ORIS ID 55284) was allocated allowances for its twelve units identified in the TSD Allocation Table as units BSG 1,BSG2, BSG3, BSG4, BSG5 and BSG6; GS07, GS08, GS09, GS10, GSII and GSI2. However, only six of the units (BSGl, BSG2, BSG3, BSG4, BSG5 and BSG6), are included in the parsed files. Big Sandy Peaker Plant has six generators, each served by two turbines, for a total of twelve turbines with a combined generation capacity of 300 MWe.

Response:
See section VI of the preamble for a detailed explanation of why EPA does not consider CAIR state emission budgets when determining Transport Rule State budgets.  Transport Rule budgets are determined through a state-by-state multifactor analysis and reflect the elimination of significant contribution or interference with maintenance at each state.  CAIR did not determine state budgets in this manner, and the Court subsequently determined that this aspect of CAIR was flawed.  Because Transport Rule is designed to replace CAIR and correct its flaws, EPA has no legal basis for setting Transport Rule budgets based on CAIR budgets that were explicitly found by the Court to be flawed.
Section III of the preamble discusses future rulemakings to address future ozone NAAQS.  Finally, EPA notes that it has finalized an allocation methodology under a FIP scenario that improves upon that which was proposed.  The updated methodology obviates some of the concerns addressed above.  Specifically, Longview Power would be considered a "new unit" under the final allocation methodology and the new unit set-asides under the final rule are determined specifically to accommodate emissions from these planned units, as explained in detail in section VII.D.  Furthermore, in regards to comment C, EPA notes that the inventories in the allocation tables will not always match the representation of units in the parsed IPM modeling files.  This is due to the list of potential existing Transport Rule units being based on units as they report, and the parsed file presents units as modeled.  In most cases, there is 1:1 alignment.  However, there may be some units that report emissions data to EPA at the boiler level but are identified at the generator level in IPM modeling, or vice-versa.  This can lead to instances where, for example, Unit A that is 50 MW in the reported data is disaggregated and listed as two units in the parsed file (each being approximately 25 MW).  These are unit-level accounting differences between reported data and modeling inventories that do not affect the modeling of aggregate facility- or state-level emission projections.
Organization: Westar Energy, Inc.
Comment:
Westar Energy, Inc.
THE ALLOCATION ADJUSTMENT METHODOLOGY FOR WESTAR AS APPLIED BY EPA IS NOT CORRECT [EPA-HQ-OAR-2009-0491-2757.1, p.24]
The Technical Support Document for State Budgets, Unit Allocations, and Unit Emission Rates describes EPA's approach for determining the allocations that comprise the state budgets. In short, EPA based allocations on the lesser of adjusted reported emissions or adjusted 2012 emission projections. In adjusting reported emissions, one step in EPA's methodology was to adjust reported annual and ozone season NOx emissions to account for 'unusually low utilization in 2009'. The annual emissions were adjusted by multiplying the emissions by the ratio of the 2008 heat input to the heat input determined for the fourth quarter of 2008 and the first three quarters of 2009. Similarly, the ozone season emissions were adjusted by multiplying the emissions by the ratio of the 2008 ozone season heat input to the 2009 ozone season heat input. EPA states that 'because 2009 was an unusually low year, rebasing emissions on 2008 heat input typically results in larger NOx emissions.' But applying this adjustment to all units fails to recognize that some units did not have an unusually low year, and are therefore adversely affected by the adjustment. [EPA-HQ-OAR-2009-0491-2757.1, pp.24-25]
As it appears that the adjustment was intended as a step to increase allocations to offset the abnormally low 2009 numbers, it is unnecessary to make the adjustment for those units that were not abnormally affected. One way to measure whether 2009 was abnormal in comparison to 2008 is to determine if units had a lower heat input for 2008 than 2009. In Westar's view, such units do need adjustment. Specifically for Westar, the following units had negative annual NOx adjustments between 2008 and 2009: Jeffrey Energy Center Unit 4, Lawrence Energy Center Unit 4, Tecumseh Energy Center Unit 9, and Gordon Evans Energy Center Units 1 and 2. Also, the following units had negative ozone season adjustments between those years: Lawrence Energy Center Unit 4, Tecumseh Energy Center Unit 9, and Emporia Energy Center Units (EEC) 1 - 5. Since allocations in the state of Kansas were based on reported emission as adjusted by EPA, the use of a negative adjustment factor for those units that with lower heat input in 2008 than 2009 unfairly reduces the NOx allocations below what was normal for those units. Further, as emission limitations under the direct control option are also based on reported emissions as adjusted by EPA, the direct control limits are biased low for units with lower heat input in 2008 than 2009. [EPA-HQ-OAR-2009-0491-2757.1, p.25]
In addition to artificially allocations for those units several of Westar' s units have zero allocations. This includes annual NOx allocations for EECI -7, Hutchison Energy Center GT 14, Murray Gill Unit 1 and 2, and Neosho Unit 7, ozone season NOx allocations for EECl - 5 and Hutchison Energy Center GT 1-4, and annual S02 allocations for Hutchison Energy Center GT 1 - 4, EEC Units 1 -7, Murray Gill Unit 4, Neosho Unit 7. As all of these units operated in 2009, and all but two of the Emporia Energy Center units operated in 2008, none of the units should have zero allocations. [EPA-HQ-OAR-2009-0491-2757.1, p.25-26]
Also, it should be noticed that the seven gas turbines at the Emporia Energy Center are listed twice in EPA's allocation tables. This double listing of units appears to have caused some misrepresentation of the heat input and emissions information and ultimately resulted in incorrect allocations. [EPA-HQ-OAR-2009-0491-2757.1, p.26]
Response:
Based on these comments, EPA updated its representation of the Emporia facility to include seven units, and EPA has included the historic heat input for Westar facilities that operated between 2006 and 2010 in the underlying data used to establish allowance allocations for these units under the final rule FIPs.  See section VII.D of the preamble for more discussion on the final allocation methodology and the Allowance Allocation Final Transport Rule TSD for unit level allowance allocations under the FIPs.
Organization: Weyerhaeuser Company
PPG Industries, Inc.
Dow Chemical Company
Comment:
Dow Chemical Company
As support documentation to the proposed rule and FIP, EPA made available an Allocation Table which provides annual and ozone season NOx allocations for regulated EGUs. Dow currently owns and operates the following EGUs which EPA purports to cover under the proposed applicability of the rule/FIP: [EPA-HQ-OAR-2009-0491-2775.1 p.6]
[[Data Table Here]]
Because each of these EGUs qualifies under the Transport Rule/FIP's definition of 'cogeneration unit ,' and has never supplied more than one-third of its potential electrical output capacity or more than or 219,000 MWh of electricity to the electrical grid for sale within the applicable time periods proposed in the rule/FIP, Dow believes its units have been erroneously listed as regulated EGUs and requests that EPA delete these units from any documents implying applicability and from the allocation tables. [EPA-HQ-OAR-2009-0491-2775.1 p.6]
Under the proposed Transport Rule/FIP, a covered source is any stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine serving at any time, since the later of November 15, 1990 or the startup of the unit's combustion device, a generator with nameplate capacity of more than 25 MWe producing electricity for sale.3 Certain cogeneration units4 are exempt, however, from these requirements. A source qualifies for the ?cogeneration unit exemption? if the unit meets the following conditions: [EPA-HQ-OAR-2009-0491-2775.1 p.6]
1. operates as part of a 'cogeneration system,'
2. meets, on an annual basis, specified efficiency and operating standards, and
3. supplies in any calendar year -- starting the later of November 15, 1990 or the start-up of the unit's combustion chamber -- no more than one-third of its potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale.  [EPA-HQ-OAR-2009-0491-2775.1 p.7]
Dow believes that the Saint Charles Operations (SCO) EGUs qualify under the 'cogeneration unit exemption' and, thus, have been improperly listed as being subject to the proposed Transport Rule/FIP. While the Dow units are cogeneration units, as defined under the proposed Transport Rule, these units do not meet the electricity sales thresholds that would subject them to regulation under the proposal. These units, on an individual unit-by-unit basis, do not distribute the greater of more than one-third of their potential electric output or 219,000 MWh for sale. As such, because none of units meet the applicability criteria in the proposed Transport Rule, Dow requests the removal of the SCO units from the Allocation Table and from any other Technical Support Documents pertaining to regulated EGUs under the rule/FIP. [EPA-HQ-OAR-2009-0491-2775.1 p.7]
PPG Industries, Inc.
In addition, PPG is the owner and operator of five combined cycle units identified by EPA in the proposed Transport Rule/FIP as "PPG Powerhouse C" Units C1-C5 (EPA Plant ID 50489) that are also located at PPG's Lake Charles Chemical Complex. Although EPA has included these five units under the scope of the proposed Transport Rule/FIP, such units are exempt cogeneration units that do not sell sufficient power to the grid to be within the applicability requirements of the proposed rule/FIP. [EPA-HQ-OAR-2009-0491-1926.1, p.1]
In addition, PPG is the owner and operator of five combined cycle units identified by EPA in the proposed CATR/FIP as ?PPG Powerhouse C? Units C1-C5 (EPA Plant ID 50489) that are also located at PPG's Lake Charles Chemical Complex. Although EPA has included these five units under the scope of the proposed CATR/FIP, such units are exempt cogeneration units that do not sell sufficient power to the grid to be within the applicability requirements of the proposed CATR/FIP. [EPA-HQ-OAR-2009-0491-2763.1, p. 1]
Weyerhaeuser Company
Weyerhaeuser Company ("Weyerhaeuser") is filing this request to remove a unit belonging to the Weyerhaeuser - Flint River mill located in Oglethorpe, Georgia, from the analyses and allocations tables included in the support materials for this rulemaking. [EPA-HQ-OAR-2009-0491-2602.1, p.1]
The facility is listed in two key technical support documents to the proposed rule made available at http://www.epa.gov/airquality/transport/tech.html, EPA's BADetailedDatat.xls (on the web page this is titled "Budgets and Allocations - Detailed Unit-Level Data (Excel)") and Allocation Table.xls, and has the identifiers:  Weyerhaeuser Company  -  Flint River  ORIS ID: 50465  Unit ID: U500  [EPA-HQ-OAR-2009-0491-2602.1, p.1]
The listing and inclusion of this facility in the proposed Clean Air Transport rule (CATR) is an error, presumably due to residual records of the unit stemming from its potential applicability under the Clean Air Interstate Transport Rule (CAIR) prior to the October 2007 amendments to CAIR that modified how biomass fuel heat input is evaluated to qualify cogeneration units. [EPA-HQ-OAR-2009-0491-2602.1, p.1]
This unit is a pulp mill recovery furnace that Weyerhaeuser determined to be exempt from the current CAIR (see Exhibit 1), and based on the definitions and applicability sections of proposed Subparts AAAAA -- TR NOX Annual Trading Program, BBBBB -- TR NOX Ozone Season Trading Program, CCCCC -- TR SO2 Group 1 Trading Program, and DDDDD -- TR SO2 Group 2 Trading Program, will be exempt from the proposed CATR for the same reason. [EPA-HQ-OAR-2009-0491-2602.1, p.2]
That reason is that the unit meets the requirements to be an exempt cogeneration unit. That is: (a) it predominantly burns biomass (> 99.5 % on an annual average heat input basis) and therefore easily meets the criteria in the proposed definition for a topping cycle cogeneration unit, and; (b) per the applicability provisions it "...does not serve at any time, since the later of November 15, 1990 or the startup of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe supplying in any calendar year more than one-third of the unit's potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale."  [EPA-HQ-OAR-2009-0491-2602.1, p.2]
The unit therefore will not be subject to the CATR, and we request EPA eliminate the unit from further CATR analyses and actions under this rulemaking. [EPA-HQ-OAR-2009-0491-2602.1, p.2]
Response:
See section VII.B of the Transport Rule preamble for a description of final Transport Rule applicability.  EPA is issuing a list of potential existing covered units to receive allocations under a FIP, but notes that inclusion of a unit in, or exclusion of a unit from, the list of potential existing Transport Rule units reflects only a preliminary assessment of the applicability of the Transport Rule and in no way suggests that EPA has made a determination about the applicability of the Transport Rule to any unit.  While allocations calculated for the final Transport Rule FIP are based on the best available data provided to EPA by the time of the calculation, the applicability of the final Transport Rule to an individual unit would be determined based on all relevant data, whether or not EPA would have such data at the time that allocations would be calculated.  The list of potential existing covered units was updated to reflect comments received on the proposed Transport Rule and subsequent NODAs.
V.D.2.b.ii. Comments on Allocations Methodology

Organization: Allegheny Energy
Comment:
Allegheny Energy
To establish state allocation budgets under the proposed rule, EPA modeled assumed reductions based on installed controls listed in the National Electric Energy Data System (NEEDS) database, rather than using actual emissions or heat input data. EPA assumed in their Integrated Planning Model (IPM) program that certain controls were already installed on certain units and, moreover, that those controls would operate at certain efficiencies, stations would use specific fuels and additional controls would be installed by dates certain. [EPA-HQ-OAR-2009-0491-2605.1, p.3]
A major problem with EPA's approach is the vast number of assumptions made on how companies will decide to comply with the regulation. In addition, EPA distinguishes between the control efficiencies of existing controls as compared to the same control yet to be constructed. For example, some existing scrubbers are being modeled at control efficiencies as high as 98% while planned scrubbers yet to be constructed are being modeled at 95%. This creates a disadvantage for states with existing controlled units and ultimately the units themselves, when smaller state budgets are allocated among the EGUs. Controlled units are being allocated fewer allowances than their 'to be constructed' counterparts even though they already 1) have made the capital investments, 2) have significant operation and maintenance costs, and 3) have created the emissions reductions currently realized. As a result, both the units and the states they are located in receive a reduced allocation of allowances. If EPA insists on using predictive models rather than actual heat inputs to establish allowance budgets then the allocation of those allowances should at least be done on a consistent basis for the type of control equipment used. A scrubber should be considered 95% efficient for the IPM regardless of whether it already exists or is yet to be constructed. [EPA-HQ-OAR-2009-0491-2605.1, pp.3-4]
Response:
Based on comments received both on the Transport Rule proposal and the January 7, 2011 NODA on alternative allocation methodology, EPA has made significant changes to its methodology for allocating allowances to existing units and new units under a FIP.  This is discussed in detail in Section VII of the preamble.  Additionally, the "Allowance Allocation Final Rule Technical Support Document" provides a more detailed description of the methodology and data used to determine final unit level allocations under a FIP.  Furthermore, the "Documentation Supplement for EPA Base Case v.4.10_FTransport - Updates for Final Transport Rule" discusses some of the broader modeling comments and subsequent modeling changes that were submitted in the context of "allocation methodology" comments.  Finally, the "Transport Rule IPM Assumptions Response to Comments" in the Response to Comment Document summarizes individual unit level changes that were made to the IPM model in response to comments received in the context of "allocation methodology" comments.
The proposed Transport Rule linked unit level allocations directly to unit level model emissions projections.  As discussed in Preamble Section VII, EPA received many comments objecting to the use of the model at this level of granularity.  As the unit level model projections were the basis for allocations, many commenters submitted corrections or comments on the unit level attributes that they disagreed with in the model.  EPA reviewed and revised its modeling given the new information submitted.  EPA also eliminated the use of unit-level modeling projections in its determination of existing unit-level allocations under the final Transport Rule FIPs.  As explained in Preamble Section VII, the final Transport Rule allocations to existing units are based on a methodology that relies on historic heat input values, not projected data.
Please see section X of the preamble for discussion of Transport Rule SIPs and abbreviated SIPs for state-determined allocations.
Organization: Ameren Services Company
Comment:
Ameren Services Company
EPA should allow full trading between the group 1 and group 2 states
The proposed Transport Rule imposes an additional reduction in the number of allowances to be allocated to electric generating units (EGUs) in group 1 states in 2014. Group 2 states will not suffer that additional reduction. The Transport Rule also imposes variability limits on all states. The combination of the variability limits and the reduction in allocations in 2014 make any restrictions on trading between group 1 and group 2 states unnecessary. The environmental protections created by the statewide budgets with variability limits are sufficient without further limiting trading to the group in which a state happens to be placed. EPA has not identified any environmental benefit that would result from restricting trading between the two groups beyond that conferred by the budgets with variability limits. Therefore, there does not appear to be a rational reason for the restriction on trading between the two groups. EPA should remove that restriction. [EPA-HQ-OAR-2009-0491-2722.1, p.8]
The allocation scheme that the Transport Rule uses appears to penalize units that have installed controls by 2012 [EPA-HQ-OAR-2009-0491-2722.1, p.8]
Based on the EPAs analysis EPA has assigned allowance allocations for both NOx and S02 in the 2012 timeframe based on the actual controls in place or planned to be in place by 2012. This scheme basically penalizes utilities that have installed controls early to meet the requirements of CAIR or other state programs. Utilities that have installed these controls have spent 100s of millions of dollars on these control devices to reduce NOx and S02 and are now penalized by this allocation scheme. Allocation of both NOx and S02 as has been done in previous rules should be based on past utilization of the unit not on its current emission capabilities. Ameren suggests in the allocation of allowances that heat input be used as this was used in the NOx SIP Call and CAIR and created a generally fair and equitable result. [EPA-HQ-OAR-2009-0491-2722.1, pp.8-9]
EPA should provide for borrowing allowances from future years [EPA-HQ-OAR-2009-0491-2722.1, p.26]
EPA should allow units to borrow allowances from future-year accounts for use in compliance with in the first 5 years of the program at least on a limited basis. This would allow for increased flexibility, especially if the final rule promulgated by EPA includes the ambitious compliance schedule that is currently proposed. Allowing for borrowing of allowances would still result in units receiving and using a finite number of allowances over the years and thus, produce no overall increase in emissions and still achieve the air quality results required. [EPA-HQ-OAR-2009-0491-2722.1, pp. 26-27]
Response:
Preamble Section VI.D.2. explains EPA's rationale for not allowing sources in Group 1 states to use Group 2 SO2 allowances for compliance, and likewise not to allow sources in Group 2 states to use Group 1 SO2 allowances for compliance at any time.
Organization: American Municipal Power, Inc. (AMP)
Comment:
American Municipal Power, Inc. (AMP)
The New Source Set-Aside Should Encourage Power Sector Growth EPA proposes to set aside 3% of each state's emissions budgets for new units. This new unit set-aside is deficient and discourages growth of new units that are designed and operated with advanced pollution control equipment. The blanket 3% per state new unit set-aside also fails to account for states experiencing significant growth in the electric power sector. This failure by EPA to account for such growth could likewise overlook other factors affecting power sector growth, such as growth in manufacturing or similar development. Thus, growing states or regions are stymied by a one-size-fits-all approach to new unit emission budgets. Finally, EPA should clarify the Transport Rule to provide that 'new units' move from the new unit set-aside to an existing unit allocation pool after a certain period of time to assure a long-term allowance structure and in order to free up new unit set-asides for future projects. Just as EPA should clarify when new units have existed for a sufficient period to warrant classification as existing units, EPA should clarify the time periods associated with allocations for retired or retiring units. Such clarification is necessary to assure that trading markets and new units will not be unnecessarily impacted by unit retirement. [EPA-HQ-OAR-2009-0491-2678.1, pp.3-4]
Response:
The methodology for allocating allowances two new units and the size of the new unit set-aside in the final rule are reasonable and provide for a reasonable allocation of allowances to new units.  The final rule entails state-specific set-asides that are tailored to the amount of planned new units (online after January 1, 2010) in each covered state.  The result is a greater percentage of the state budget set-aside for new units than would have otherwise occurred under the proposed method for calculating new source-set aside budgets.  As existing units are retired, the allocations for those units are eventually redirected to the new unit set-asides, as described in Preamble Section VII.D.2. In this manner, additional allowances will become available in the new unit set-asides in the future as existing units retire and the EGU fleet turns over to newer sources of generation.
Organization: Attorney General of North Carolina
Comment:
Attorney General of North Carolina
The rule text does not make clear that each State's new unit set-aside for a particular pollutant is a subcategory of the State's total allocation for that pollutant. That is, the rules are not clear that the new unit set-aside is to be 36 subtracted from the State's total budget and is not an allocation that is in addition to the State's budget. Appendix A, when developed, will list the allocations for each unit. These allocations, if they track the allocations in EPA-HQ-OAR-2009- 0491-0057.1, will presumably demonstrate that the total of the existing unit allocations plus the new unit set-aside equals the State's total budget. However, the rule should be revised to clarify that the new unit set-asides are a part of, and not in addition to, the State's total budget. [EPA-HQ-OAR-2009-0491-2685.1, p. 36]
Response:
The commenter is correct that the new unit set-aside is a portion of the total state allowance budget, not an addition to it. For more information on new-unit allocations, please see Preamble Section VII.D.2.
Organization: Big Rivers Electric Corporation
Comment:
Big Rivers Electric Corporation
The cap and trade option for compliance will only work if allowances are available.  It is likely that utilities that are allocated more allowances than are needed to meet compliance will hold onto those allowances to meet future needs.  EPA should consider creating a pool of allowances that are available for purchase in the early years, following the effective date of the regulation to cover the time utilities are required to comply with the new regulation and the installation of control equipment.  Without this pool of allowances, it is likely that a reduction in generation will be the only option for compliance in the early years following the program inception. [EPA-HQ-OAR-2009-0491-2661.1, pp.2-3]
Response:
Thank you for your comment.Organization: Birchwood Power Partners, L.P.
Comment:
Birchwood Power Partners, L.P.
Birchwood Power is concerned that EPA's proposed allocation of annual NOx allowances will be insufficient when demand for electricity returns to levels experienced prior to the recession. Already, dispatch in 2010 has shown a significant increase over dispatch in 2009. [EPA-HQ-OAR-2009-0491-2706.1, p.1]
Birchwood Power is operated pursuant to a long-term contract that does not allow for the recovery of the costs for emissions allowances. Further, under this contract, Birchwood does not exercise control over when the facility can be dispatched, but must operate whenever called upon by Dominion. Accordingly, any shortfall in allowances could have drastic consequences on the facility's continued operation by significantly increasing the plant's operating costs. [EPA-HQ-OAR-2009-0491-2706.1, p.2]
Birchwood Power 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. As described in more detail below, 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 for allowances on the spot market after the conclusion of a control period. It also could be accomplished without compromising the integrity of the statewide emissions budgets. [EPA-HQ-OAR-2009-0491-2706.1, p.2]
The Proposed Transport Rule's 'assurance provisions' will unfairly prejudice the .interest of long-term contract generators vis-a.-vis utility-owned or merchant generating facilities, which can recover the costs for additional allowances from ratepayers or through the market price of electricity. Birchwood Power would encourage EPA to include provisions in the final rule that would provide relief to long-term contract generators from the impacts that the assurance provisions could have on their operating costs and competitiveness. At the very least, Birchwood Power believes that this concern supports EPA's proposal to delay implementation of the assurance provisions until 2014. Birchwood Power would also suggest that EPA increase both the one-year and three-year variability limits to 15% and 10%, respectively, of a state's budget. [EPA-HQ-OAR-2009-0491-2706.1, p.2]
B. As a Long-Term Contract Generator, Birchwood Power Cannot Pass Along the Costs for Emissions Allowances to Its Customers
Birchwood Power is operated pursuant to a contract with Dominion (Virginia Power) that does not allow for the pass-through of costs associated with emissions allowances. Unlike a utility that can seek to recover costs associated with emissions allowances from its ratepayers or a merchant generator that can recover such costs through the market price of electricity, long-term contractor generators such as Birchwood Power can be severely impacted by the requirement to purchase emissions allowances. Further, long-term contractor generators do not exercise control over when their facilities can be dispatched, but must operate whenever called upon by their customers. [EPA-HQ-OAR-2009-0491-2706.1, p.3]
Congress previously recognized that long-term contract generators do not have a mechanism to pass through new environmental costs to their power purchasers, and exempted these plants from the Acid Rain Program under the 1990 Clean Air Act Amendments so long as the long-term agreements remained in effect. More recently, under The American Clean Energy and Security Act of 2009,' (H.R. 2454) ('Waxman-Markey'), the House of Representatives passed legislation that would have made a pool of allowances available at no cost to long-term contract generators with an agreement executed before March 1, 2007 'that does not allow for recovery of the costs of compliance with the limitation on greenhouse gas emissions under this title.' (Id. § 783(a)(5)(B).) Similar provisions were included in the 'Clean Energy Jobs and American Power Act,' ('Kerry-Boxer') that was reported out of the Senate Environment and Public Works Committee in November 2009. [EPA-HQ-OAR-2009-0491-2706.1, pp.3-4]
C. EPA Should Make the Remaining Allowances in the New Unit Set-Aside Available to Long-Term Contract Generators That Exceed Their Allocation Due to an Increase in Dispatch Back to a Level Achieved Since 2005, Before Distributing Any Remaining Portion of the Set-Aside to Other Existing Sources
As Congress has previously done, EPA should recognize the unique situation of long-term contract generators that cannot pass along the costs of emissions allowances. to their customers. EPA could do this by making available any allowances that remain in the new unit set-aside for any control period in which the long term contract generator's emissions exceeded its allocation due solely to a return of the facility's dispatch back to pre-recessionary levels, i.e., where emissions increased because the facility's heat input had increased to a level that the generator had, in fact, achieved in any calendar year or ozone season since 2005. This would provide relief for long-term contact generators who experience an increase in utilization from the levels EPA has relied upon in establishing allocations, without providing a permanent allocation that could be sold to others. [EPA-HQ-OAR-2009-0491-2706.1, p.4]
Our proposed approach could be implemented as follows:
:: EPA would make allocations to new units from the new unit set-aside as currently proposed (by September 1 of any control period for the annual NOx and S02 trading programs and June 1 for the ozone season NOx trading program). [EPA-HQ-OAR-2009-0491-2706.1, p.4]
:: However, rather than distribute any remaining allowances in the new unit set-aside to existing eligible sources, EPA would wait until after completion of the control period (i.e., after December 31 for the annual programs or September 30 for the ozone season program) and would then provide any long-term contract generator the opportunity to demonstrate, upon submission of an application to the Administrator (within 30 days of the end of the control period), that it exceeded its allocation in the preceding control period due solely to an increase in its dispatch (i.e., heat input), back to a level that it had achieved during any calendar year or ozone season since 2005. The long-term contact generator would also need to demonstrate that it was operated during the control period pursuant to one or more contracts that do not allow for recovery of costs associated with purchase of emissions allowances and were executed prior to the effective date of the Transport Rule. [EPA-HQ-OAR-2009-0491-2706.1, p.4]
:: Then, at least 30 days prior to the allowance transfer deadline for each control period (March 1 of the subsequent year for the annual trading programs and December 1 of the same year for the ozone season trading program), the Administrator would record in the account of any contract generator that has adequately demonstrated its eligibility per preceding paragraph an amount of allowances equal to the number of tons by which the long-term contract generator had exceeded its allocation in the preceding control period. [EPA-HQ-OAR-2009-0491-2706.1, pp.4-5]
:: If the total amount of allowances requested by long-term contract generators for any control period should be greater than the remaining portion of the new unit set-aside, each qualifying generator would receive a proportionate share of the remaining portion of the set-aside, just as EPA has already proposed for new units. [EPA-HQ-OAR-2009-0491-2706.1, p.5]
:: If some portion of the new unit set-aside should still remain after recording allowances in the accounts of long-term contract generators per the preceding paragraphs, the Administrator would then allocate that remaining portion to all other existing eligible units, as EPA has already proposed in the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2706.1, p.5]
For facilities like Birchwood Power, which already operates with state-of-the-art emissions control technology, our proposed approach would provide needed relief should the facility be called to dispatch more frequently than in the period upon which EPA based its allocation, but no more frequently than it was operated prior to the recession. Moreover, this relief could be provided to such generators without compromising the integrity of the cap. [EPA-HQ-OAR-2009-0491-2706.1, p.5]
By providing priority access to remaining allowances in the new unit set-aside, EPA could spare long-term contract generators the potentially significant cost of purchasing allowances from the spot market after the conclusion of a control period. In addition, the proposed approach would not alter investment decisions, since a long-term contract generator that anticipates increased utilization and can achieve additional cost-effective reductions or purchase additional allowances at a reasonable cost will presumably do so, rather than risk that no allowances will remain in the new unit set-aside. [EPA-HQ-OAR-2009-0491-2706.1, p.5]
Response:
Thank you for your comment.Organization: City of Ames, Iowa
Comment:
City of Ames, Iowa
2) The SO2 allocations for 2012 for the City of Ames Units 7 & 8 (ORIS Code 1122) are inadequate to serve the citizens of Ames who rely upon us for electricity, steam for the hospital, and the burning of municipal solid waste (refuse-derived-fuel a.k.a. RDF). [EPA-HQ-OAR-2009-0491-2769, p.2]
6) The allowances allocated under this proposed rule are inadequate to allow the electric utility for the City of Ames to supply the electricity to meet the demand of the city, especially so when accounting for the city's load growth which will increase the utilization of the existing generation infrastructure. [EPA-HQ-OAR-2009-0491-2769, p.2]
8) The SO2 allocations for Unit 7 and Unit 8 in 2012 are not adequate to meet the generation requirements of the utility . We already are using one of if not the premier super low sulfur Powder River Basin (PRB) coals available. The combination of high Btu value (8800 Btu/lb) and low sulfur (0.21%) yields the least SO2 (0.48 lbs. SO2/mmBtu) available. Yet we still are short of SO2 allocations.
9) The heat input (HI) allocation in 2012 for Unit 8 for SO2 of 2,839,221 mmBtus must be a mistake . The value is so low that it cripples the use of the unit to meet the needs of the utility to supply electrical power (and steam to the hospital ) for the City of Ames (Iowa). In fact, the HI allocation for Unit 8 is lower than the actual HI for Unit 8 for the past ten (10) years, 2000 through 2009.
10) The combined HI allocations in 2012 for Unit 7 and Unit 8 for SO2 of 5,021,132 mmBtus (2,181,911 + 2,839,221 = 5,021,132) is also inadequate to meet the generation needs of the utility to serve the City of Ames . The value of 5,021,132 mmBtus is less than the combined actual HI for Unit 7 and Unit 8 for every year but one in the past ten (10) years, 2000-2009. The only exception is in year 2009, which as was already discussed in Item 7 above was a very unusual year due to reduced sales due to the recession, and reduced native generation due to extremely low priced purchased power, also a result of the recession. (See Item 7 above.) The combined allocation of 5,021,132 mmBtus is 15% less than the average actual HI for both units (Unit 7 & 8) for the period 2000-2009, and is 40% less than the actual HI (7,009,958 mmBtus) for both units that occurred in 2005. [EPA-HQ-OAR-2009-0491-2769, p.3]
11) Why are the allocated Heat Inputs for NOx different than the allocated Heat Inputs for SO2?
12) Why are there no ozone season allocations for NOx?
13) Why are there no allocations for GT2?
14) Ames Diesel Generating Stations 1 & 2 (ORIS code 1052) are not active generating units for the City of Ames (Iowa) Municipal Electric Services.
15) In the technical supporting document (BADetailedData.xls; tab sheet 'Projected Data'; column E), the values for Units 7 & 8 are in error. The are shown as 120,700 and 256,030 mmBtus for Units 7 & 8, respectively. It appears the intended values should have been 1,207,000 and 2,560,300. [EPA-HQ-OAR-2009-0491-2769, p.4]
17) The 'Air Transport Rule' itself and the HI, SO2, and NOx allocations assigned to the individual EGUs are so complex, confusing, and nearly untraceable, that we were so far unable to understand the logic and the path of calculations that led to the assignment of allocations to our units. [EPA-HQ-OAR-2009-0491-2769, p.4]
19) As of September 1, 2009, the City of Ames Municipal Electric Services became a market participant of the Midwest Independent Transmission System Operator (Midwest ISO) headquartered in Carmel, Indiana. As such, the power generation philosophy and requirements to serve load and provide for system reliability and stability, is vastly different from historical and traditional philosophy. Whereas we used to operate units almost exclusively to serve native load, now we may be required to provide generation and/or voltage support for a regional problem. For example, this may require the utilization of our peakers (GT1 and GT2) more than what we have used them for in the past. We need sufficient allocations for our units to carry out our responsibilities in the market. [EPA-HQ-OAR-2009-0491-2769, p.4]
20) The HI allocations for NOx , and the allocations for NOX are not adequate to serve the needs of the City of Ames. This is especially true for Unit 8. The NOx allocation for Unit 8 is less than the actual NOx emissions for every year but one in the past ten (10) years. In fact, the one exception is a tie , 605 tons to 605 tons. The Unit 8 NOx emissions for the past ten (10) years averages 42% more than the allocation. [EPA-HQ-OAR-2009-0491-2769, p.4]
Response:
Thank you for your comment.Organization: Class of '85 Regulatory Group
Comment:
Class of '85 Regulatory Group
EPA Should Allow Trading Between Both SO2 Groups
The 'State Budgets/Limited Trading' remedy currently divides covered states into two groups for the purposes of SO2 emissions budgeting and trading. The 'Group One' states face additional reductions in their SO2 budgets beginning in 2014, while 'Group Two' states do not face additional SO2 reductions. At the same time, EGU owners are limited to their SO2 group for allowance trading purposes. In other words, an EGU owner cannot purchase SO2 allowances from an entity in a 'Group Two' state to comply with allowance requirements in a 'Group One' state. While creating two separate SO2 groups for emissions budgeting and allocation may be a reasonable mechanism for achieving further SO2 reductions in some states, the proposed prohibition on SO2 allowance trading between groups is unnecessary in light of the variability requirements, appears arbitrary, and will not further EPA's goal of assuring state-specific emission reductions. [EPA-HQ-OAR-2009-0491-2854.1,p.10]
The emissions markets established by the preferred option are already small because they are limited by the ten percent variability limits. But a liquid market is essential for the successful implementation of the Transport Rule within EPA's proposed timeframe. Without allowances available for purchase, or with concentrated market power distorting allowance markets, the variability limits are all but useless. By limiting SO2 allowance trading to within an individual SO2 group, the preferred option effectively halves the SO2 allowance market, exacerbating many of the same market power problems, allowance shortages, and other market inefficiencies identified as shortcomings in the 'State Budgets/Intrastate Trading' alternative. As EPA correctly observes, limited markets are less efficient, raise costs, and may reduce benefits, which is clearly demonstrated by a comparison of the interstate and intrastate trading remedy options. [EPA-HQ-OAR-2009-0491-2854.1, pp.10-11]
The preferred option relies on strict annual variability limits at both the unit and state levels, additional state-level rolling three-year variability limits, and allowance surrender requirements to assure that state-specific emissions reductions occur. Because it is these provisions that assure that emissions reductions take place in a given state, and not any limits on the geographic source of allowances, allowing trading across SO2 groups does nothing to undermine the goal of state-specific emissions reductions and is consistent with North Carolina. And, by 2014, the state SO2 budgets are very similar in any event, further indicating that restricting trading to within each SO2 group is unnecessary. EPA has not provided any valid justification for restricting trading to within a given SO2 group. Accordingly, EPA should remove this artificial and unnecessary limitation and allow emission allowance trading across S02 groups. This will improve emissions markets and have no adverse impact on specific instate emissions reductions. [EPA-HQ-OAR-2009-0491-2854.1,p.11]
EP A Should Clarify That Retired Unit Allowances Remain Available to New Units.
The Class of '85 supports a new unit allowance allocation set-aside. The Class of '85 also supports the expansion of the new unit set-aside through the addition of allowances from retired units. EPA should retain this provision and clarify that all allowances from retired units will become available to new units through the mechanism described in the preferred option. At the same time, EPA should retain the continuing allocation provisions for non-operating units, which will decrease incentives to continue operating certain units. EPA also should clarify that repowered units are not 'new' and allow those units to retain their initial allowance allocations. Because repowered units face uncertainty in the current new-unit allocation process, this clarification will remove a disincentive to repower existing units. [EPA-HQ-OAR-2009-0491-2854.1,pp.13-14]
Response:
Thank you for your comment.Organization: Cogen Technologies Linden Venture, LP
Comment:
Cogen Technologies Linden Venture, LP
M. EPA Should Make Remaining Allowances in the New Unit Set-Aside Available to Long-Term Contract Generators Who Experience a Shortfall Due to a Return of Utilization Back to Levels Achieved Prior to the Recession
Linden Cogen believes EPA should make any remaining allowances in the new unit set-aside available to long-term contract generators who exceeded their allocation due solely to an increase in utilization back to levels achieved prior to the recession. Unlike a utility that can seek to recover costs associated with emissions allowances from its ratepayers or a merchant generator that can recover such costs through the market price of electricity, long-term contractor generators can be severely impacted by the requirement to purchase emissions allowances. Further, long-term contractor generators do not exercise control over when their facilities can be dispatched, but must operate whenever called upon by their customers. [EPA-HQ-OAR-2009-0491-2712.1, p.22]
Congress has previously recognized the economic realities faced by long-term contract generators who have no way of recovering the cost of emissions allowances, both upon enacting the Acid Rain Program under the 1990 Clean Air Act Amendments and more recently as part of the development of a federal cap and trade program for emissions of greenhouse gases. By making allowances remaining in the new unit set-aside available to long-term contract generators before distributing the remainder of the set-aside to eligible existing facilities, EPA could prevent long-term contract generators from needing to pay potentially significant costs for allowances that cannot be passed along to their customers. [EPA-HQ-OAR-2009-0491-2712.1, p.22]
As described previously, EPA must either address the errors in IPM that have resulted in its unrealistically low projections for dispatch of Linden Cogen or base allocations for individual units in New Jersey on historic heat input data. Even if EPA should take either of those two approaches to resolve Linden Cogen's concerns regarding the proposed NOx allocations, EPA should nonetheless make any remaining allowances in the new unit set-aside available to long-term contract generators. This would provide needed relief if a long-term contract generator experiences a shortfall in allowances due to a return of demand to pre-recessionary levels, without compromising the integrity of the statewide emissions budgets. [EPA-HQ-OAR-2009-0491-2712.1, p.22]
Response:
Thank you for your comment.Organization: Cogentrix Energy, LLC
Comment:
Cogentrix Energy, LLC
Cogentrix has found conflicts in definitions of applicability between the proposed Transport Rule and the Acid Rain and CAIR Rules that have resulted in our two Virginia units being excluded from allocations in the draft Rule, In addition, Cogentrix supports any opportunity to trade credits to promote economic efficiency. By doing so, electricity consumers will not bear unnecessary economic costs in their rates and service. Finally, we believe the implementation process may be more efficient - for both generators and regulators - if state agencies are given a more active role. Our more detailed comments on each of these items follow. [EPA-HQ-OAR-2009-0491-2772.1, p.1]
Cogentrix Sites in Hopewell, VA and Portsmouth, VA are not included in proposed allocations. Cogentrix has reviewed proposed allocations listed in EPA's Technical Information for the Transport Rule. Cogentrix-owned sites in Hopewell, VA (ORIS Code 10377) and Portsmouth, VA (ORIS Code 10071) were not included in either 'AllocationTable.pdf' or 'AllocationTable.xls.' Both sites operate with two 'three on one' boiler to generator designs, where three boilers provide steam to one 55-MWe electric generator. The Transport Rule provides applicability requirements listed under Title 40 Code of Federal Regulations 97.404(a)(1) as follows: [EPA-HQ-OAR-2009-0491-2772.1, pp.1-2]
The following units in a State shall be TR NOx Annual units, and an source that includes one or more such units shall be a TR NOx Annual source, subject to the requirements of this subpart: Any stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine serving at any time, since the later of November 15, 1990 or the startup of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe producing electricity for sale. [EPA-HQ-OAR-2009-0491-2772.1, p.2]
Since the 'generator... nameplate capacity' for each generator (emphasis added) at each site is greater than 25 MWe, Cogentrix sites are included within the scope of the Transport Rule and therefore allocations for each site should be assigned. Cogentrix also reviewed EPA's Technical Infonnation file entitled 'BADetailData.xls.' The analysis shown in this file appears to use the definition of applicability taken from the Acid Rain rules, where 'units' (interpreted to be boilers) with a capacity of less than 25 MWe are not included within the scope of the Acid Rain rule. Both Cogentrix facilities opted into the Acid Rain Program in 2008; and should have been included in EPA's al1ocation analysis on that basis alone. Both Cogentrix facilities have also been participants in the CAIR program since its inception and likewise, should have been included in EPA's al1ocation analysis on that basis alone. [EPA-HQ-OAR-2009-0491-2772.1, p.2]