If EPA is concerned that operators will have an incentive to operate a unit for a limited period on an annual basis (less than 24 hours), then it should consider other alternatives, including using the 40 CFR Part 75 definition of an reliable operating quarter with a minimum of 168 hours, and require that to continue as eligible Transport Rule units, each unit must have a minimum of 2 or more quarters with more than 168 hours of operation during any year in order for it not to be a Transport Rule non-operating year.  [EPA-HQ-OAR-2009-0491-2787.2 p.9-10]
EPA proposes that, for 2012, each existing unit in a given state receives allowances commensurate with the unit's emissions. We have been unable to determine whether the proposed unit allocations in EPA's proposed Appendix A20 for the Annual NOx and 802 Transport programs for Massachusetts, or any other OTC jurisdiction, actually follow the specified methodology in the preamble or relevant Technical SuppOli Document. We recommend that, at a minimum, EPA identify whether individual unit allocations are based on projected or actual emissions and provide the actual spreadsheet calculations to facilities and states for evaluation well before the proposed initial allocation deadline of September 2011.   [EPA-HQ-OAR-2009-0491-2787.2 p.9]
Response:
Thank you for your comment.Organization: Minnesota Pollution Control Agency (MPCA)
Comment:
Minnesota Pollution Control Agency (MPCA)
In addition, the MPCA has some specific concerns for the current Transport Rule. First is the determination of unit budgets. The MPCA is concerned that the historical baseline emissions used as part of determining unit budgets looked only at 2008 and 2009 emission data. This is a short time frame, and one that is likely to be affected by the recent economic downturn. The MPCA would encourage BPA to look at emissions over a slightly longer period in order to determine baseline data. Looking at earlier data, from 2007 for example, could be used to alter the baseline, or at least to determine if 2008 and 2009 data are representative of facility operations. [EPA-HQ-OAR-2009-0491-2521.1, p.2]
Response:
In the final Transport Rule, EPA uses projected data, not historic data, to determine state budgets.  Please see preamble section VI.D and the Significant Contribution Final Rule TSD for more information.
Organization: Minnesota Power
Comment:
Minnesota Power
These new developments regarding treatment of Minnesota's status under the CAIR or proposed treatment under the Transport Rule raise multiple areas of factual questions as well as areas of concern about the methodology that EPA has applied in their assessment of Transport Rule requirements.  From the standpoint of Minnesota compliance planning, Minnesota Power had communicated with EPA during the CAIR promulgation process that Minnesota was already in the process of providing for reductions in PM2.5 precursor emissions as part of Minnesota programs designed to reduce Minnesota utility emissions in a cost effective manner. These emission reductions improve the air quality in Minnesota and address Minnesota requirements like making reasonable further progress on reducing visibility impairment in Northern Minnesota Class 1 Wilderness Areas.  These control measures were established even though Minnesota is in attainment with all of the NAAQS.    [EPA-HQ-OAR-2009-0491-2750.1, p.3]
Access to emission allowances needed for compliance.  EPA has not clarified what a unit operator is to do to continue operations if their budget allocations are insufficient to support designed or intended electricity production and no Transport Rule allowances are available for purchase.  All units accredited for dispatch should have a means by which they can provide for compliance with their Transport Rule budget. [EPA-HQ-OAR-2009-0491-2750.1, p.9]
Response:
EPA notes that the commenter provides no technical basis for the concern that "no Transport Rule allowances are available for purchase."  EPA's modeling of the final Transport Rule air quality-assured trading programs shows that cost-effective compliance would, in many states, lead to emission levels below the 2012 state budgets, showing that there will be more than enough allowances in the system to support a liquid interstate market in each program.
The commenter also mistakenly refers to Transport Rule budgets applicable to "units accredited for dispatch."  The Transport Rule does not apply any emission budget to any specific unit; instead, the Transport Rule establishes emission budgets at the state level and gives individual units the flexibility to determine their cost-effective emissions under that state-level budget.  Therefore, for purposes of the Transport Rule, units may emit in whatever amount for which they can provide sufficient allowances to cover in that control period.  As with prior emission trading programs, no unit is limited by its initial allocation and may acquire additional allowances in the marketplace.
Organization: Missouri Public Utilities Alliance (MPUA)
Comment:
Missouri Public Utilities Alliance (MPUA)
7. Because EPA has decided that all power plants regardless of age or current pollution control equipment will need to make ongoing reductions in emissions, new power plants will be placed at a particular disadvantage.  During the permitting process, these plants have already had to meet much more stringent regulations for SO2, NOX and PM2.5 as part of the BACT process.  Because their current emission control equipment and processes are already the best available, it may not be possible to achieve any significant reductions for several years.  The current approach penalizes the regions cleanest plants while rewarding those which can more easily reduce much larger amounts of pollution. [EPA-HQ-OAR-2009-0491-2785.1, pp.3-4]
8. The EPA compliance strategy appears to ignore the realities of transmission congestion.  The Agency assumes that utilities that shutter older plants with higher amounts of emissions can easily replace that power with electricity generated outside the area.  While the existing utilities grid is marginally capable of shifting power within the region to meet shifting needs, it was not designed and does have the capacity to handle the level of shifts that will be necessary should power plant retirements meet the estimates identified in a number of studies.  It appears that within Missouri, those retirements are likely to be significantly higher than EPA is projecting. [EPA-HQ-OAR-2009-0491-2785.1, p.4]
While problems will develop with transmission congestion for individual utilities, the problem will be more complicated within a state or region as the impact is multiplied by many more utilities. [EPA-HQ-OAR-2009-0491-2785.1, p.4]
9. There does not appear to be clear process for units receiving emission allowance under NUSA to become classified as existing units.  EPA should identify that critical process and then resubmit for additional public comments. [EPA-HQ-OAR-2009-0491-2785.1, p.4]
Response:
The commenter does not provide a technical basis for alleging that retirements within Missouri should be different than EPA projects.  EPA's power sector modeling accounts for interregional transmission limitations which are described in detail in the Resource Adequacy and Reliability in the IPM Projections for the Transport Rule TSD.
Organization: National Tribal Air Association (NTAA)
Comment:
National Tribal Air Association (NTAA)
Need for Tribal Set-Aside
Aside from the above, the Transport Rule fails to provide Indian Tribes with an opportunity to become part of EPA's proposed trading scenarios. As drafted, the Rule provides allowance allocations solely to states and the District of Columbia. Under the Tribal Authority Rule, however, Tribes may adopt whole or parts of air programs based on 'reasonable severability' without being subject to deadlines or other requirements imposed upon states and other jurisdictions. This is something that the Agency acknowledged in the former Clean Air Interstate Rule (CAIR) in which it went to great lengths to address the unique circumstances of Indian Tribes and the need to accommodate future electrical generating units (EGUs) that should locate on Tribal lands. 8 Unfortunately, the EPA chose to ignore this earlier assessment of Tribal issues without providing a valid reason for doing so. The NTAA therefore recommends that the Agency revisit its earlier analysis under the CAIR concerning Tribes and establish a mechanism which allows such Tribes to enter into any trading program adopted under the Rule, specifically providing EGUs locating on Tribal lands with an appropriate portion of allowances. [EPA-HQ-OAR-2009-0491-2778.1, pp.4-5]
In addition, the EPA should provide for the inclusion of a Tribal set-aside under the Transport Rule that is based on factors other than EGUs located on state lands. As reference, the Agency only needs to look to an effort in the Western U.S. which provided for a similar set-aside that received support from a wide range of stakeholders. [EPA-HQ-OAR-2009-0491-2778.1, p.5]
The Western Regional Air Partnership (WRAP), a partnership between Indian Tribes, states and federal agencies (including the EPA) and with participation from such entities as environmental organizations and industry, advocated for a Tribal set-aside during the late 1990s that was eventually adopted as part of the Annex to the Regional Haze Rule (RHR). The Annex established declining SO2 emission milestones for major sources. If the milestones were exceeded, then a cap-and-trade program would be initiated to ensure continued SO2 reductions. As part of the Annex, an annual SO2 Tribal set-aside of 20,000 tons was made available to Tribes within a nine-state region, regardless if such Tribes had major industrial sources emitting SO2. This set-aside was to be distributed as determined by the region's Tribes (e.g., for future industrial sources, other economic development purposes, Tribal scholarships, etc.). This annual Tribal set-aside also grew out multiple discussions among the WRAP's partners and participants where issues of equity and economic development kept coming up during conversations with respect to the Tribes that had hardly contributed to visibility impairment in the West but whose environment and health had been adversely affected by neighboring jurisdictions with sources emitting significant amounts of SO2. At that time, neither the WRAP partners or participants had sufficient information about future EGUs in Indian Country but they felt it imperative to address equity issues properly before and not after the Annex was implemented. [EPA-HQ-OAR-2009-0491-2778.1, p.5]
The NTAA therefore recommends that the EPA include a Tribal set-aside as part of any trading program adopted in accordance with the Transport Rule. A determination about the appropriate size for such a set-aside and the means for its allocation requires the Agency to consult with Tribes. In this effort, the NTAA offers its assistance to the Agency by bringing a great deal of experience and involvement with the Tribal set-aside that was created under the RHR Annex, and also based on its longstanding relationships within Indian Country. [EPA-HQ-OAR-2009-0491-2778.1, p.6]
8. Rule To Reduce Interstate Transport of Fine Particulate Matter and Ozone (Clean Air Interstate Rule); Revisions to Acid Rain Program; Revisions to the NOx SIP Call; Final Rule, 70 Fed. Reg. 25162, 25167 (May 12, 2005) (to be codified at 40 CFR Parts 51, 72, 73, 74, 77, 78 and 96) ('[I]n the event of any future planned construction of EGUs on Tribal lands within the CAIR region, EPA intends to work with the relevant Tribal government to regulate the EGU through either a Tribal implementation plan (TIP) or a Federal implementation plan (FIP). We anticipate that at a minimum, a proposed EGU on a reservation within a State participating in the CAIR cap and trade program would need to be made subject to the cap and trade program. In the case of a new EGU on a reservation in a CAIR-affected State which chose not to participate in the cap and trade program, the new EGU might also be required, through a TIP or FIP, to participate in the program. This would depend on the potential for emissions shifting and other specific circumstances (e.g., whether the EGU would service the electric grid of States involved in the cap and trade program.) Again, EPA will work with the relevant Tribal government to determine the appropriate application of the CAIR.'). [EPA-HQ-OAR-2009-0491-2778.1, pp.4-5]
Response:
As described in Preamble Section VII.D, the final Transport Rule establishes Indian country new unit set-asides to provide allowances for new units built in Indian country.
Organization: North Carolina Department of Environment and Natural Resources
Comment:
North Carolina Department of Environment and Natural Resources
Handling of Biomass Units
Some sources are transitioning from fossil fuel to biomass to meet state Renewable Portfolio Standards. Some are cogeneration units and some are not. If the source has burned any amount of fossil fuel in 1990 or any year thereafter, and it meets the other applicability criteria, and does not meet the cogeneration exemption, it is subject to FTR. NCDAQ requests a clarification on how existing fossil-fuel fired units that convert to biomass are to be treated under the Transport Rule including what the allocations will be based on for such units (total heat input or jnst fossil fuel used for start-up). What if an existing fossil-fired unit converts completely to biomass (no fossil fuel for start-up)? Also, please clarify how new biomass units are treated and what the associated allocations methodology is. For instance, does it matter whether the source was previously a NOx SIP Call source that also later met the CAIR applicability criteria? [EPA-HQ-OAR-2009-0491-2767.1 p.4]
The allocation method relies on historical emissions. NCDAQ believes it would be beneficial to look at energy output as a way to promote energy efficiency. Heat input could also be used as an alternate allocation methodology. [EPA-HQ-OAR-2009-0491-2767.1 p.7]
Response:
The final rule covers fossil-fuel-fired units serving generators with a nameplate capacity greater than 25 MWe producing electricity for sale and defines "fossil-fuel-fired" as combusting any amount of fossil fuel in 2005 or later.  The commenter claimed that biomass units that switch from burning some fossil fuel to burning no fossil fuel should be exempt just as new units that never burn fossil fuel are not covered by the Transport Rule trading programs.  EPA rejects the commenter's claim.  The approach in the final rule is consistent with the approach used in prior EPA trading programs covering the electric generation industry, e.g., the Acid Rain Program, the NOx Budget Trading Program, and the CAIR trading programs.  The commenter did not provide any basis for using a different approach in the Transport Rule trading programs covering the same industry.  Moreover, the commenter essentially suggested that the determination of whether a given biomass unit is subject to the Transport Rule trading programs should not be based on any historical information on whether the unit burned any fossil fuel, but rather only on what the unit is currently burning.  This approach would mean that, for all biomass units, owners and operators, and EPA, would not know at the start of the Transport Rule trading programs, whether the units were subject to the trading programs and that the units' regulatory status could change, and the units become subject to the trading programs, at any time that any fossil fuel was combusted.  Because all biomass units would not be reporting their fuel use to EPA until they became subject to the trading programs, the determination of whether specific units were subject to the trading programs, and assurance of compliance, would be problematic.  EPA believes that its approach is reasonable: biomass units that have recently (i.e., after 2004) operated burning some fossil fuel are treated differently than new biomass units that are initially designed to operate without combusting any fossil fuel and actually operate without any fossil fuel combustion.  The units burning fossil fuel after 2004 are more likely to continue to do so.  EPA maintains that it is reasonable to make these biomass units, like any other units burning at least some fossil fuel after 2004, subject to the Transport Rule trading programs.  Similarly, EPA believes it is reasonable to treat a biomass unit that has not burned and does not burn any fossil fuel (like any other units that have not burned and do not burn) any fossil fuel as not subject to the Transport Rule trading programs, unless and until they begin burning fossil fuel.
Organization: NRG Energy
Comment:
NRG Energy
Use of projected emissions for developing state budgets and source allocations NRG supports the overall methodology to base state budgets and source allocations on projected emissions. While we are disappointed that no credit is given to the investments already made in emission controls, we recognize that this approach brings parity to the industry. Energy markets have gone through a sea change based on lower gas prices, increased renewables, and lower demand in strained economic conditions. Even estimates based on recent historical emissions, heat input or output will not reflect the future. This is true in both the short term (2012-2014) and beyond. Other allocation methodologies such as historical output or emissions can create large windfalls for some sources and leave huge shortfalls for others. The projected methodology is most equitable in that EGUs should all receive allocations approaching their expected emissions. This recognizes the need for a diverse set of fuels and technologies to meet the needs of the energy markets. [EPA-HQ-OAR-2009-0491-2749.1, p. 3]
An alternative method for allocations to new units The proposed Transport Rule contains the methodology to allocate allowances to new units. The methodology is identical for all four allowances programs (Group 1 SO2, Group 2 SO2, Annual NOx, and Seasonal NOx). NRG assumes that a new unit would be one that is not listed in Appendix A as having an allocation, but operates on or after January 1, 2012. It is presumed that EPA will capture in Appendix A all sources that are operational prior to January 1, 2012 (or May 1, 2012 in the case of Seasonal NOx). [EPA-HQ-OAR-2009-0491-2749.1, p. 5]
A new unit must submit to EPA a request for an allocation of allowances based on actual emissions from the prior control period. This proposed allocation methodology will penalize a source that is operational prior to the beginning of a control period in that the request for an allocation may only be based on emissions from a partial control period. For example, a source that commences operation on June 1, 2013, would only have emissions data for 7/12th of the annual and 4/5th of the Ozone Season control periods. [EPA-HQ-OAR-2009-0491-2749.1, p. 5]
NRG proposes that a new unit be allocated allowances based on 97% of its permitted emissions in tons per year. The 97% allocation is similar to the allocation given to existing units; i.e., existing units' allocations are minus 3% in order to fund the New Unit Set Aside Account. A new unit however, should not profit from the allocation, in that if actual emissions were less than permitted emissions, the new unit would have a surplus of allowances. Instead, EPA could use a method similar to that used in the NOx SIP and CAIR programs. That is, the state would hold the allowances in the state Set Aside Account. After the end of the relevant control period, the state would deduct from the Set Aside Account, allowances equal to 97% of actual control period emissions. If the Set Aside Account is oversubscribed (i.e., total emissions from new units in the state are greater than the amount of allowances in the Set Aside Account) then, the allowances would be allocated to each new unit would be adjusted by the percent the account is undersubscribed. That is, if the account has only 90% of the needed allowances then, each new unit would receive allowances based on 90% of their emissions. This methodology would continue for the first five control periods for the new unit. [EPA-HQ-OAR-2009-0491-2749.1, p. 5]
EPA allocations should account for self-scheduled operations by using historical emissions. EPA proposes in the Transport Rule to allocate SO2 and NOx allowances based on a generating unit's projected operation using IPM outputs. This model is an energy dispatch model and does not account for operations that are self-scheduled. This is an especially critical issue for steam electric generating units projected to have little or no operations in IPM. These units are commonly called "peaking units." [EPA-HQ-OAR-2009-0491-2749.1, p. 7]
Self-scheduled operations are due to two main requirements: energy market rules and environmental regulations. These Peaking Units may operate to stabilize transmission lines which would not be recognized in IPM. They also run to conduct mandatory energy market seasonal capacity demonstrations. For a Peaking Unit, this means that it would likely be scheduled to operate outside of its dispatch order for a short period. Similarly, most NRG Peaking Units measure their emissions via a Continuous Emissions Monitoring System (CEMS) and therefore are required to perform an annual RATA and/or particulate matter stack testing. [EPA-HQ-OAR-2009-0491-2749.1, pp. 7-8]
As a result, NRG peaking units located in Connecticut, Maryland, and New York are not properly allocated allowances in the proposed Rule. These requirements and the historic operations are further discussed in the following paragraphs. While NRG supports allocation on projected emissions, this type of unit should be allocated allowances based on historical emissions. NRG suggests, at a minimum, each peaking unit receive SO2 and NOx allowances equal to their three year average historic emissions from required testing, and that state budgets are amended accordingly to account for these allocations. Three year average historic emissions from self-scheduled operations for NRG peaking units are listed in Table 2-1. [EPA-HQ-OAR-2009-0491-2749.1, p. 8; see pp. 8 for information on three peaking units and p. 9 for Table 2-1]
Response:
.Because EPA allocates to existing units based on historic data under the final Transport Rule FIPs, peaking unit operations should be accurately reflected in the historic data basis for existing unit allocations.  Please see section VII.D of the preamble and the Allowance Allocation Final Rule TSD for more information.
Organization: Occidental Chemical Corporation (OCC)
Comment:
Occidental Chemical Corporation (OCC)
If adopted in its current form, the proposed rule could have a significant negative impact on OCC's modern, clean-burning cogeneration facility at Taft, Louisiana, if the facility cannot meet the proposed exemption for cogeneration units. Commissioned in 2002, this facility is equipped with drylow NOX burners and is permitted to emit approximately 1,463 tons of NOX per year. However, the proposed rule provides annual allowances to this facility totaling only 26 tons of NOX per year beginning in 2012. In other words, EPA has proposed to grant only about 2% of the annual NOx allowances needed to run the Taft facility at its full capacity. For the sake of argument, assuming that Taft is running at full capacity and NOX allowances are valued at $1,200 per ton, OCC would need to purchase 1,438 tons of NOX allowances at an annual cost of about $1.7 million. This presumes, of course, that such allowances would be available on the market. OCC has significant concerns with EPA's modeling efforts and methodology used to develop overall emissions allowances and to allocate allowances to individual units. [EPA-HQ-OAR-2009-0491-2754.1, p. 3]
While the ozone season NOX allowances for our Ingleside, Texas facility are sufficient for current operating rates (227 tons) if the facility is not exempt, we do not know how the allocation was developed and ask that EPA provide additional information explaining how the allocation was made. [EPA-HQ-OAR-2009-0491-2754.1, p. 3]
The Proposed Rule Contradicts Current EPA Policy and Programs
If EPA will not exempt all QF cogeneration units, it should ensure that such units are allocated sufficient allowances to continue operating and supplying clean energy to the Louisiana electricity market. [EPA-HQ-OAR-2009-0491-2754.1, p. 14]
For many years, EPA has encouraged the installation of cogeneration facilities. Recently, EPA Administrator Jackson stated the following with regard to combined cycle/cogeneration facilities during a speech on November 20, 2009 at the White House Clean Energy Forum on Public Health: "Win-win changes for our health and environment  -  like installing co-generation units at a manufacturing plant or mass transit expansions  -  require large up-front investments...." In this case, we believe that the Administrator is correct. Cogeneration is costly to install, but is a win-win for the environment and industry when compared to traditional EGUs because it produces low-cost, clean power and steam with less energy. In support of cogeneration, EPA established the Combined Heat and Power Partnership. According to EPA,'The CHP Partnership is a voluntary program seeking to reduce the environmental impact of power generation by promoting the use of CHP. The Partnership works closely with energy users, the CHP industry, state and local governments, and other clean energy stakeholders to facilitate the development of new projects and to promote their environmental and economic benefits.'  [EPA-HQ-OAR-2009-0491-2754.1, p. 14]
However, it would seem that the "win-win" identified by the Administrator and the types of units promoted by the EPA CHP partnership - which are the types of units that OCC has installed at Taft, - are the types of units that the IPM predicts will no longer operate and that EPA penalizes by failing to allocate sufficient emissions allowances in the CATR program. [EPA-HQ-OAR-2009-0491-2754.1, p. 14]
In the report entitled "Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model" (August 2010), EPA states the following on page 7-1: "...existing generating units have the option of maintaining their current system configuration, retrofitting with pollution controls, or retiring early. The decision to retrofit or retire is endogenous to IPM and based on the least cost approach to meeting the system and other operating constraints...Table 7-2 and 7-3 present the first and second stage retrofit options respectively." [EPA-HQ-OAR-2009-0491-2754.1, p. 14]
We interpret this explanation to mean that the IPM assumes that decisions to retire or retrofit EGUs, including cogeneration units, will be based on the assumed least cost approach to meeting regional power system requirements, not environmental concerns or other business interests of the cogeneration facility operator. The assumptions contained in Table 7-2 for combined cycle (cogeneration) and combustion turbines are as follows: [see 2754.1, p. 15 for Table 7-2.] [EPA-HQ-OAR-2009-0491-2754.1, p. 15]
Thus, EPA's IPM predicts that all cogeneration and combustion turbine units will retire early because it may be more cost effective, on a regional system basis, to generate electricity with, for example, coal-fired units. Apparently following this rationale, EPA allocates almost no allowances to the Taft cogeneration units (and units like it), presumably because EPA assumes that the 8-year old facility will be retired in 2012 (or run at only about 5% of usual operating rates), and granted other units all the allowances they will need to continue business as usual. We randomly selected emission rate data contained in the Parsed File Transport Rule Base Case for 201231 and the Budgets and Allocations - Detailed Unit-Level Data Base32 for a Midwest coal unit and noted the following comparison of historic emissions and CATR allocated allowances:  [EPA-HQ-OAR-2009-0491-2754.1, p. 15] [See 2754.1, p. 15 for the comparison.]
This particular unit is receiving 212 tons of annual allowances and 982 tons of ozone season emission allowances more than it currently needs (presuming that annual emissions remain consistent). We are baffled as to why a clean burning and energy efficient facility like OCC's natural gas cogeneration plant at Taft, assuming it is not exempt, would be provided allowances to cover only a small fraction of what it emits and that another higher emitting facility would be given excess allowances. In an interim public notice, we respectively request that the EPA respond to this apparently unprincipled discrepancy. [EPA-HQ-OAR-2009-0491-2754.1, pp. 15-16]
Not only is this result contrary to EPA's public remarks and programs, it unfortunately will do nothing to reduce air emissions. It appears that EPA's reliance on the IPM would result in increased emissions rates, not emissions reductions, in order to promote electric generation system efficiencies. We do not believe, however, that decisions regarding the efficient dispatch of electricity and the appropriate inventory of regional EGU fleets are within EPA's area of expertise or jurisdiction. [EPA-HQ-OAR-2009-0491-2754.1, p. 16]
As noted above, OCC has no intention of idling the Taft cogeneration facility or its steam host, or any of our cogeneration and steam host facilities. Thus, we strongly object to the assumption that cogeneration units should be retired in 2012 and recommend that EPA abandon the use of the IPM for making unit-level allocations to EGUs under the CATR, and rather rely on historic emission rate information to establish allowance allocations, as it did with SO2 allowances. [EPA-HQ-OAR-2009-0491-2754.1, p. 16]
Problems with the Use of the Model for Unit Level Allocations
EPA used the IPM to determine unit-level emissions allowances for 2012 and beyond for facilities affected by the proposed Transport Rule. Our limited information about the IPM suggests that the proper use of the model is for electric utilities, public utility commissions and investors to mysterious factors not explained in any of the docket materials. Nowhere were we able to identify any environmental considerations in the IPM, other than assumptions about how much it would cost to install control technology. In that regard, we question whether EPA is qualified, let alone authorized, to impose regulations that effectively reconfigure a large portion of the nation's power generating fleet  -  the domain traditionally addressed by FERC, the Department of Energy and state utility commissions. In any event, given the distorted pattern of allocations distributed by the IPM, we firmly believe that EPA should NOT use the IPM to allocate emissions allowances. [EPA-HQ-OAR-2009-0491-2754.1, pp. 18-19]
The IPM appears to predict that electricity from coal-fired units will be less expensive than electricity from gas-fired cogeneration units in 2012. Based on that assumption, it appears the model projected that coal-fired units will run at significantly higher rates that natural gas-fired units. Given the model's prediction that coal units will face higher demand than gas units, EPA generously awarded coal units with enough allowances to run at recent, or even higher operating rates. By relying on the IPM's economic predictions to grant generous allocations to coal units while drastically short-changing cogeneration units, EPA would effectively force modern, clean and efficient cogeneration units, such as OCC's Taft units, to buy a huge number of allowances simply in order to run, thus providing an enormous financial windfall to higher-emitting coal units. In essence, EPA has endorsed the idea that coal-fired plants should keep on running, displacing the power previously supplied by ultra efficient and clean cogeneration units. Furthermore, although one might argue that high-emitting coal units would be able to pay for SCR technology with the revenue generated by cogeneration payments for allowances, we find no incentive in the proposed rule for coal units to install SCRs, given that such units will receive a sufficient number of allowances to operate without SCRs. One can only conclude that not only does EPA's proposed rule directly contradict the Congressional objectives of the PURPA cogeneration exemption, it is, with respect to the purported objective of reducing air emissions, arbitrary and capricious and an abuse of power. [EPA-HQ-OAR-2009-0491-2754.1, p. 19]
Allocating Allowances to Non-Operating Units We are confused as to why the EPA would provide allocations for non-operating units, and not provide enough for those that operate. In the preamble to the proposed rule, EPA states the following  [EPA-HQ-OAR-2009-0491-2754.1, p. 28; see pp. 28-29 for quote from 75 FR 45310-11]
Response:
Thank you for your comment.Organization: Old Dominion Electric Cooperative
Comment:
Old Dominion Electric Cooperative
The emission reductions compliance deadlines under both the 2012 and 2014 are overly optimistic and unachievable, certainly for many units. As close as can be reckoned from the proposed Transport Rule preamble and technical information contained in the rulemaking docket, EPA has modeled emission reductions capabilities for each unit within the trading programs based on generic assumptions. Moreover when queried to explain individual allocation unit outcomes, EPA staff have been in some cases unable to meaningfully respond. Considering that the proposed allocation of emission allowances to individual units is based on this modeling and that these allocations are essentially permanent, EPA should have gone above merely assembling broad based and inaccurate assumptions, and modeling unit allowance destinies based on them, as it seems to have done in this case. [EPA-HQ-OAR-2009-0491-2877.1,pp.3-4]
The proposed Transport Rule would significantly restrict emissions within the 32 trading areas and therefore allowance allocations. EPA has offered limited explanation to explain the proposal's continuing allocation of allowances to retired or non-operating units for a full six years after operation ceases at full allocation rate under existing unit formulas, except to surmise it would discourage older units from operating, Id. at 45,311. Not discussed in the proposal, however, is the fact that older units will be discouraged from retiring. Further, no data or documentation is offered to explain the six year time period or the full allocation rationale. A certain fact here is non-operating units would receive allowances not needed for compliance. [EPA-HQ-OAR-2009-0491-2877.1, pp.6-7]
The proposed Transport Rule states, '...once an EGU does not operate (i.e., does not combust any fuel) for 3 consecutive years, the Agency would no longer allocate allowances to the unit, starting in the seventh year after the first year of non-operation', ld. at 45,310. However, an unintended consequence would be to award older less-effìcient units with allowances. A utility could combust fuel once every three years to be considered operational and continue receiving allowances. [EPA-HQ-OAR-2009-0491-2877.1,p.7]
The proposed Transport Rule should allow economics to determine if a unit will operate or not. The proposed Transport Rule should use 50 percent of the default capacity factors found on page 45313 of the proposed rule to determine if a unit is an operating unit. ln that same thought, ODEC believes that the default capacity factor for the simple cycle peaking facilities of 15% is overestimated. For planning and financing purposes, peaking facilities will typically be forecasted to not run more than 5%. lf a unit does not meet the minimum default capacity factor, for 3 years, it would not be provided allowances. The non-operating units' allowances would go to the new source set-aside pool and should remain in the pool for a minimum of 10 years to ensure there are adequate allowances for new generation. After 10 years, the unused allowances should be returned to existing operating units on a pro-rata basis. [EPA-HQ-OAR-2009-0491-2877.1,p.7]
EPA proposes a 3% set-aside from state allowance budgets for new units, but proposes no allowances for the initial control period after the unit comes on line, ld. at 45,310. ln the event of insufficient allowances in the set-aside, available allowances are distributed pro-rata to new units. So under EPA's proposal non-operating units receive un-needed allowances and new units may well end up with a fraction of what's needed and none for the first year of operation. As stated previously, construction of a new multi-billion dollar power station requires certainty that there will be allowances available to operate. Without this certainty it is unlikely that new, cleaner and more efficient generation plants will be able to obtain financing to construct. [EPA-HQ-OAR-2009-0491-2877.1, p.7]
EPA's proposed non-operating and new unit allowance policies are arbitrary and exemplify the importance of letting states determine these types of policies based on local considerations and needs. ln this context, it is a mistake for EPA to short circuit the SIP process. The Transport Rule allowance allocation methodology should ensure new units equipped with best technologies and techniques to minimize emissions receive 100% of allowances needed for commercial operation, including initial year requirements. [EPA-HQ-OAR-2009-0491-2877.1,p.7]
The proposed Transport Rule should be changed to accommodate new unit allowance allocations. As stated above, the allowances from non-operating units need to go to the new source set-aside pool and be provided to new sources at no charge. As EPA points out in the proposal, retired units do not need them, ld. at 45,311. Additionally, instead of eliminating unused CAIR allowances, at least a portion of them could be set-aside for new unit utilization in the event of a shortfall in the new unit set-aside. [EPA-HQ-OAR-2009-0491-2877.1, p.7]
The proposed Transport Rule allowance allocation scheme is flawed for numerous reasons. lt is based on EPA computer model projections of both future individual unit utilization and emission reduction capabilities at specified marginal cost of emission reduction levels. The model attempts to predict the future of literally thousands of electric utility fossil fuel units located within the proposed 32 trading areas. Regardless of the purported sophistication of EPA's model, it does not and cannot accurately forecast how each and every fossil fuel unit among thousands will be utilized. For example, the model cannot account for the presence or ramifications of short and long term wholesale power agreements under which unit owner obligations include future system and individual unit power demands. The model cannot account for future business decisions, the necessity of which is not yet presently known or anticipated. This uncertainty would have a significant effect on an individual unit's utilization within the utility system. The model cannot predict or account for how units will operate through the regional transmission organization (RTO) that coordinates the movement of wholesale electricity. There are literally dozens of significant factors that affect future unit utilization of which the model does not and cannot take into account. [EPA-HQ-OAR-2009-0491-2877.1,pp.8-9]
The model does not and cannot accurately forecast for each and every fossil fuel unit within the 32 trading regions the actual future costs of meeting the emission reduction obligations dictated by the model. For example, the model cannot account for costs, on a unit basis, associated with contract breaches associated with early termination of coal and associated transportation contracts necessitated by the model to switch coals. The model cannot account for costs associated with obtaining new contracts for new coal deliveries especially when potential contracting parties for supply are aware of reduction obligations dictated by EPA's model and the essence of time. The model assumes 'just in time' expanded natural gas transportation capabilities to meet the aggregate demand the model's emission reduction mandates place on affected units within a geographic area. Likewise, there are literally dozens of significant factors that affect future costs of emissions controls of which the model cannot take into account. [EPA-HQ-OAR-2009-0491-2877.1,p.9]
ln short, EPA's model puts real life units within its virtual world and dictates unit utilization and emissions reduction destinies based on this fantasy. EPA may argue that emissions trading allowed under its remedy and preferred options would correct all the deficiencies inherent in this entire scheme. As EPA is well aware, however, trading is necessarily limited by the North Carolina decisions and is even entirely prohibited by at least one option in the proposed Transport Rule, so it is unlikely trading would save the day. [EPA-HQ-OAR-2009-0491-2877.1,p.9]
Additionally, EPA's proposed allowance allocation trading scheme fails to reward cleaner emissions units and the electric consumers who have borne higher electricity costs because they must pay for existing, expensive emission controls. The model metrics do not consider existing unit generation costs, and as such some of the most costly fossil fuel generation affected by the proposal would have to incur even higher costs as compared to Transport Rule compliance costs associated with more polluting less efficient affected units. [EPA-HQ-OAR-2009-0491-2877.1, p.9]
ODEC, however, commends EPA for willingly opening up its proposed allocation methodology for comment on alternative methods that still link unit allowances directly to the way state budgets were developed, ld. at 45,311. ODEC construes this EPA-stated limitation on alternatives to mean that so long as the aggregate allowable emissions within individual state budgets are not affected or altered by the unit allowance allocation methodology, EPA would deem it within its regulatory discretion. EPA's limitation here appears to be based on the North Carolina decisions in that it limits EPA's discretion in allocating allowances for S 110(a)(2)(D)(i) purposes to the extent that the distribution cannot in effect determine or partially determine state's emissions budgets. ODEC believes the North Carolina decisions do in fact impose this limitation but it does not prohibit allocations methods under state budgets determined based on the need to address interstate air pollution. [EPA-HQ-OAR-2009-0491-2877.1,pp.9-10]
Alternative Allocation Methodology
ODEC believes many of the troublesome aspects of the proposed Transport Rule could be addressed if the allocation methodology were structured in a manner similar to that contained in CAIR for annual NO' allocations as a SIP (or FIP option as the case may be) for all the Transport Rule trading programs. Specifically the salient features of this methodology include allocating allowances to existing units based on historic heat in-put using the 3 highest heat inputs of the past 5 years to derive annual averages (seasonal for ozone), and allocating allowances to new units based on a set aside and folding new units into existing unit category after 5 years of operation. [EPA-HQ-OAR-2009-0491-2877.1,p.10]
EPA mentions an option for allowance distribution to units placed into various subcategories of units that have similar characteristics, ld. at 45,311. lf this is implemented, ODEC suggests that coal, gas and oil units be divided into three categories and that allowances be distributed pro rata to units in each category based on unit heat in-puts as a percentage of categorical heat inputs, ODEC believes that this methodology is rational and well within the bounds of the North Carolina decisions. Additionally, this allocation rewards not punishes electric consumers that have already incurred high costs of emissions controls. [EPA-HQ-OAR-2009-0491-2877.1,p.10]
As with EPA's proposed Transport Rule approach, this methodology could provide options for each state to consider whether new units should receive allowances from a set-aside during their initial year of operation and whether retired/non-operating units should continue to receive allowances, and if so how long or at a diminished allocation. [EPA-HQ-OAR-2009-0491-2877.1,p.10]
Response:
Thank you for your comment.Organization: Omaha Public Power District
Comment:
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: [EPA-HQ-OAR-2009-0491-2680.1, p. 6]
As indicated in the Transport Rule documentation, Nebraska is a Group 2 state for S02. As such, the basis for the proposed Nebraska State S02 budget and the unit specific S02 allowance allocations was actual emissions with given adjustments to include continuous use of existing add-on controls and add-on controls that are planned to be added for reasons other than the transport rule. There were no such adjustments for Nebraska units, so the allowance allocations are based on actual emissions. In setting the S02 emissions budget, the actual emissions from the last quarter of 2008 and the first three quarters of 2009 were used as a basis. Four continuous quarters of operation is simply a snapshot of the actual operation of a utility boiler. This snapshot does not account for the variability in individual utility unit operation and utility operation throughout the state. This was recognized by EPA in their development of the CAIR rule, where four years of operating data were used as a basis to establish allowance allocations. The fact that a single four quarter period is inadequate to establish state budgets or unit allowance allocations was also recognized to some extent in the methodology used to establish the Transport Rule proposed NOx state budgets and unit specific allowance allocations. On page 9 of the Technical Support Document for the Transport Rule titled 'State Budgets, Unit Allocations, and Emission Rates' it is indicated that in setting the NOx budgets and unit allowance allocations, reported annual and ozone season NOx emissions were adjusted to account for unusually low utilization in 2009. Therefore, EPA based NOx budgets and unit allowance allocations on 2008 heat input data, presumably because it was considered more representative of typical operations. However, the same data set that EPA deemed inappropriate for use in setting the NOx budgets and unit allowance allocations was used to set the S02 budgets and unit allowance allocations, with no apparent reason given for using this data that represents ''unusually low utilization'. We request that EPA use a data set with a longer timeframe in setting S02 budgets and unit allowance allocations, such as the most recent three full years of data, or make adjustments to the S02 budgets and unit allowance allocations as was done in setting the NOx budgets and unit allowance allocations. [EPA-HQ-OAR-2009-0491-2680.1, pp. 6-7]
Response:
Preamble Section V has a description of EPA's air quality analysis used to determine states that should be covered under the final Transport Rule.
Organization: Pennsylvania Department of Environmental Protection
Comment:
Pennsylvania Department of Environmental Protection
The DEP supports EPA's use of air quality factors and a health benefits assessment in calculating states' emissions budgets, rather than basing the budgets solely on the availability of highly cost-effective controls. However, we do not believe that EPA established a transparent process for determining budgets and allocations. [EPA-HQ-OAR-2009-0491-2660.1, p.5]
We understand that the allocations arc based upon a model that uses fuel prices, cost of controls, unit operation practices, a unit's business environment, electricity prices, demand, growth, and renewable energy and energy efficiency programs, as well as a host of other economic and environmental variables that may reflect future outcomes. However, allowance allocations should nut be based solely upon a unit's past heat input or electric output. Allowance allocations based upon heat input or electric output might not result in individual units eliminating their significant contribution to another State's nonattainment of the NAAQS. Instead, heat input and output methods can result in greater allocations for EGUs that contribute significantly to nonattainment in downwind areas. The DEP understands that EPA has indicated that such allocations would be in conflict with the Court's decision. While DEP is supportive of EPA's allocation methodology, we strongly recommend that EPA use an average of several years for its modeling run inputs. [EPA-HQ-OAR-2009-0491-2660.1, p.5]
Variability within Budgets
The DEP acknowledges the need for some flexibility to account for differences in weather, unplanned outages, and other factors between years, and supports the approach EPA has used to allow variability in interstate trading. However, DEP has concerns with placing the variability outside each state emissions budget. EPA should consider containing variability within the proposed budgets rather than in addition to the proposed budgets. This approach should help to ensure that the emission reductions achieve EPA's modeling projections related to significant contribution and interference with attainment and maintenance. The DEP would also support the suggestion made by the National Association of Clean Air Agencies to set aside an emergency reserve of allowances each year (subtracted proportionately from each state's budget) that can be used in states to address weather, unplanned outages, and other factors that result in emission variability. This recommendation should help to ensure the integrity of the emissions budget while accounting for variability. [EPA-HQ-OAR-2009-0491-2660.1, p.7]
Response:
A description of and rationale for EPA's approach to variability limits can be found in Preamble Section VI.E.
Organization: Pfeiff, Mike
Comment:
Pfeiff, Mike
6. Title IV allowance auction - The EPA's modeling shows that if the EPA's preferred FIP is implemented as part of the Proposed Transport Rule, the quantity of SO2 emissions will decrease substantially (TR SB Limited Trading System Summary Report.xls). Since the Title IV allowance allocation does not decrease commensurate with the Proposed Transport Rule budgets, the quantity of previously unused (a/k/a 'Banked') Title IV allowances will increase substantially each year. The EPA Administrator should use her existing authority granted under section 416(e) of the CAA to mitigate this impact by limiting the quantity of allowances allocated in the ARP annual allowance auction. [EPA-HQ-OAR-2009-0491-2742.1, p.4]
Because of the existing massive surplus of Title IV allowance, restricting the quantity of Title IV allowances would provide benefits regardless of the direction the EPA ultimately pursues regarding the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2742.1, p.5]
The Administrator should initiate a separate new stand alone to institute a new mechanism to link the quantity of Title IV allowances auctioned annually by the EPA to the quantity of previously unused (aka Banked) Title IV allowances. For example, if the quantity of banked Title IV allowances is greater some percentage (say 20%) of the current year's Title IV allocation, allowances that would ordinarily be introduced into the market through the annual auction would be withheld. A 'Title IV Allowance Auction Quantity' rule should be undertaken separate from the Proposed Transport Rule to prevent its demise if the Proposed Transport Rule is struck down during judicial review. [EPA-HQ-OAR-2009-0491-2742.1, p.5]
While the quantity of allowances auctioned in the Title IV program may seem small relative to the existing bank and/or annual allocation, the cumulative effect of withholding this supply over multiple years would not be insignificant. Under the Title IV program, 250,000 additional allowances are introduced each year trough the annual auction. While, the annual incremental quantity of these allowances represent a modest percentage relative to the approximately 9 million allowances allocated each year, their cumulative effect can be substantial. Elimination of the 250,000 allowances that are introduced each year beginning 2011 through the last analytical year (2030) would prevent the Title IV bank from building by approximately 5 million tons. [EPA-HQ-OAR-2009-0491-2742.1, p.5]
It simply dose not make any sense to continue to inject a new supply of Title IV allowances into the market that is already significantly oversupplied. I request that the EPA Administrator initiate a new rulemaking proceeding to establish a mechanism for limit the quantity of new Title IV ARP allowances which are introduced into the market each year thought the annual allowance auction. [EPA-HQ-OAR-2009-0491-2742.1, p.5]
7. Pollution by Wire - The EPA's preferred FIP creates perverse economic incentive to Electric Generating Units ('EGU') located outside of the proposed Sulfur Dioxide ('SO2') control regions to increase emissions. [EPA-HQ-OAR-2009-0491-2742.1, p.5]
The Proposed Transport Rule would operate concurrently with the existing Acid Rain Program ('ARP') created by Congress in 1990 through Title IV of the Clean Air Act ('CAA'). As proposed the preferred FIP would establish a new separate allowance 'currency' for SO2 emissions. Since the Proposed Transport Rule will allocate fewer allowances (i.e. the emission cap) than the existing ARP allocation, there will be less S02 emissions inside the proposed SO2 control regions. However, since the ARP allowance allocation which was explicitly set by Congress as part of the CAA amendments of 1990 will not be lowered commensurate with the Proposed Transport Rule allowance allocations, the de facto impact will be a net increase in the quantity of ARP allowances that are available for use with compliance with the ARP. [EPA-HQ-OAR-2009-0491-2742.1, p.5]
[For additional comments pertaining to Pollution by Wire, see pages 5-7 of this comment.]
Response:
EPA's analysis accounted for the impacts of the Transport Rule on emissions from states outside of the programs.  EPA did not find that the Transport Rule would lead to any meaningful increases in SO2 or NOx emissions outside of the covered states.
Organization: PPG Industries, Inc.
Comment:
PPG Industries, Inc.
  EPA's proposed NOx allowances would provide the RS Cogen units with less than 5% of the allowances that they need to operate at the levels they have operated at for the past 5 years and intend to operate at in the forseeable future. These units are well controlled with low NOx burners and an SCR system. To meet the requirements of the proposed FIP, PPG may have to expend a million dollars per year or more to acquire NOx allowances. For this reason, PPG has spent a great deal of time in trying to understand the basis for EPA's proposed allocation scheme, but this has been difficult due to the tremendous volume of technical support data and lack of transparency concerning the assumptions used by EPA in their IPM runs upon which the rule is based. [EPA-HQ-OAR-2009-0491-1926.1, pp.1-2]
The NOx Allowance Allocations for the RS Cogen Units Are Wholly Insufficient and Based Upon Flawed Modeling and Projections. It is arbitrary and capricious for EPA to provide unit-level allocations based upon the Integrated Planning Model (IPM). EPA's proposed NOx allowance allocations would provide the RS Cogen units with less than 5% of the allowances that they need to operate at the levels they have operated at for the past 5 years and intend to operate at in the foreseeable future. These units are well controlled with low NOx burners and an SCR system. They are critical to meeting PPG's electrical demand and continued manufacturing operations. PPG has invested heavily in the construction and maintenance of these units, which went on-line in 2002.  To meet the requirements of the proposed FIP, PPG may have to expend a million dollars per year or more to acquire NOx allowances.18 For this reason, PPG has spent a great deal of time in trying to understand the basis for EPA's proposed allocation scheme, but this has been difficult due to the tremendous volume of technical support data and lack of transparency concerning the assumptions used by EPA in their IPM runs upon which the rule is based. PPG is diligently reviewing updates to the IPM announced in the September 1, 2010 Notice of Data Availability, but to date cannot understand why that IPM v.4.10 projects such limited operation of the RS Cogen units. PPG's manufacturing operations depend on the steam and electricity produced from the RS Cogen units. There is no reason to expect the curtailed operation predicted by the IPM. [EPA-HQ-OAR-2009-0491-2763.1, p. 11]
As indicated in the table above, RS Cogen has been significantly under-allocated both in comparison with actual operations and also with the final allocations under CAIR. It should be noted that the CAIR allocations are based on a Louisiana SIP approved by EPA. As an alternative to the CATR, EPA could make NOx allocations (both annual and ozone season) in the same relative percentages to the state budget that Louisiana used under the CAIR allocations. PPG does not believe there are any significant new sources that would cause a need to substantially revise that ratio. [EPA-HQ-OAR-2009-0491-2763.1, p. 14, see p. 14 for the table.]
The IPM based unit-level allocations are illogical and unfair. PPG's RS Cogen units are less than 10-year old, highly efficient gas turbines equipped with both low NOx burner technology and selective catalytic reductions (SCR) post-combustion control technology. The allocations provided by EPA under the proposed CATR FIP penalize these units even though they are some of the most efficient and lowest-polluting units. Projecting the cost of purchasing allowances is difficult as their costs will be market driven. In addition, allowance costs may vary widely based on the trading scheme chosen for the final rule. However, based on historical costs from CAIR trading, the additional annual cost for allowances for the RS Cogen units could well exceed one million dollars annually. Adding additional control to these units is not likely to be effective since they are already efficient and aggressively controlled. As EPA is aware, cost per ton for NOx control rises exponentially with additional control and reaches the point of diminishing returns after the control technology currently in place for these units. EPA has simply provided no rational basis for this inequitable treatment for the RS Cogen units. [EPA-HQ-OAR-2009-0491-2763.1, pp. 14-15]
PPG urges EPA to abandon its proposed unit-level allocations and allow Louisiana DEQ to make allocations through a state SIP, if it is finally concluded that a SIP is even needed to address interstate transport of PM2.5 and/or ozone precursors. In the alternative, EPA should substantially revise the allocations under the FIP and re-propose such allocations for further comment. [EPA-HQ-OAR-2009-0491-2763.1, p. 15]
Comments on Non-Applicability of Proposed Rule to PPG Powerhouse C Units.  PPG Powerhouse C units C1, C2, C3, C4 and C5 are listed in the proposed allocation table under ORIS code 50489. Each unit has proposed NOx allocations under the CATR as follows: [EPA-HQ-OAR-2009-0491-2763.1, p. 15; see p. 15 for allocation table.]
Units C1, C2, C4 and C5 all meet the criteria for not selling more than the greater of one-third of the potential electrical output capacity (PEOC) or 219,000 MWh to any utility power system since November 15, 1990. Therefore, PPG Powerhouse C1, C2, C4 and C5 units -are not subject to the proposed CATR and are not TR NOx Annual Units. [EPA-HQ-OAR-2009-0491-2763.1, p. 17; see pp. 15-17 for extensive discussion of this issue.]
The PPG Powerhouse C unit C-3 is a steam turbine that does not, by itself fall within the definition of TR NOx Annual unit, the definition of TR NOx Ozone unit or the definition of TR SO2 Unit under the proposed CATR because it is not a fossil-fuel fired unit.  [EPA-HQ-OAR-2009-0491-2763.1, p. 17; see pp. 15-17 for extensive discussion of this issue.]
Without waiving any legal rights to contest the necessity for the proposed FIP or any part thereof, PPG also requests that EPA abandon the use of the IPM-based method for allocation of unit-level NOx allowances. Further, to the extent EPA relies upon the IPM for any purpose, it should correct all of the data errors noted herein.  [EPA-HQ-OAR-2009-0491-2763.1, p. 19]
Response:
Thank you for your comment.Organization: Prairie State Generating Company, LLC
Comment:
Prairie State Generating Company, LLC
2. ALLOCATIONS FOR NEW UNITS
If the U.S. EPA is not willing to expand the definition of what comprises 'existing' units to include those that are permitted, funded, and under construction by January 1, 2012, and will have commenced commercial operation by January 1, 2014, the Transport Rule should provide permanent allocations for 'new units' as quickly as possible after they commence commercial operation. [EPA-HQ-OAR-2009-0491-2842.1, pp.2-3]
In the U.S. EPA's proposal, allocations to existing units are permanent and new units must forever obtain allowances from the New Unit Set-Aside ('NUSA'). pp. 45309-45310. PSGC is concerned that there will be insufficient allowances available for new units because of the restrictions on trading the U.S. EPA believes is necessary to respond to the court's order in North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008). [EPA-HQ-OAR-2009-0491-2842.1, p.3]
PSGC proposes that 'new' units become 'existing' units at some point in time, preferably as soon as possible. Since the U.S. EPA proposes to allocate allowances three years in advance of their vintage date, PSGC proposes that 'new' units should become 'existing' units in the fourth year after the new unit commences commercial operation. [EPA-HQ-OAR-2009-0491-2842.1, p.3]
PSGC recognizes that the U.S. EPA may not be willing to expand the statewide budgets to provide allowances for 'new existing' units. However, there are potential sources of allowances for 'new existing' units:
a. The allocations for all 'existing' units in a state could be adjusted to provide allowances for the 'new existing' unit, thereby maintaining the state's cap.
b. In the alternative, allowances normally allocated to the NUSA could be made permanent allocations to the 'new existing' unit.
c. Adjust current allocations to existing units to account for federal and state agreements already in place, including to units which are required to be shut down as a result of those agreements and where the agreements restrict trading. [EPA-HQ-OAR-2009-0491-2842.1, p.3]
Consistent with this suggested alternative, PSGC proposes that 'existing' units that shut down should not receive their allocations beginning in the fourth year after their shutdown, rather than in the seventh as EPA has proposed. Additionally, there should be some other mechanism besides non-operation to trigger unit allowance reduction or elimination, thereby increasing the size of the NUSA and of allowances available for 'new existing' units. [EPA-HQ-OAR-2009-0491-2842.1, p.3]
The U.S. EPA has proposed that units shut down more than three years that are then restarted are to be treated as 'new' units. Because the U.S. EPA has proposed that shutdown units receive allowances for six years following their shutdown, theoretically a unit could shut down in year 1 and start up again in year 4 or 5 as a new unit, thus making it eligible to receive both its 'permanent' allocation plus allowances from the NUSA. PSGC suggests that EPA prohibit this potential for double-dipping. [EPA-HQ-OAR-2009-0491-2842.1, p.3]
One way to prohibit such double-dipping is as PSGC has suggested: shutdown units should receive their 'permanent' allocations for only the three years for which it would have been allocated allowances in advance (except for those units that are shut down prior to January 1, 2012 which should not receive any). That is, the unit would have received allowances in year 1 for year 4, year 2 for year 5, and year 3 for year 6. If it shuts down in year 3, it has already received allocations for years 3, 4, and 5 and should not receive an allocation for year 6 and thereafter. [EPA-HQ-OAR-2009-0491-2842.1, p.3]
3. SIZE OF THE NUSA
The U.S. EPA has proposed that the NUSA be 3% of the state's emissions cap (without the variability limit). p.45310. The U.S. EPA determined that 3% was the appropriate size for the NUSA because it predicts that there will be new generation equal to 3% of the existing generation in the entire region. Id. However, the U.S. EPA's assignment of the NUSA failed to consider the location of the predicted new generation. That is, the U.S. EPA's analysis and ultimate assignment of a 3% NUSA to each state does not reflect what is actually projected for each state, thereby creating inequities across the region, in part because of the constraints inherent with the application of the variability limits. [EPA-HQ-OAR-2009-0491-2842.1, p.4]
The IPM projected that there will be a significant increase in electrical demand in Illinois. The IPM accounted for alternative types of generation, including, among others, wind, nuclear, biomass, and so forth on a regional basis. However, the U.S. EPA did not provide sufficient data for PSGC to determine whether a 3% NUSA is sufficient to meet Illinois' new demand and whether the alternative sources of energy are sufficiently reliable to meet that demand. Coal-fired energy is reliable and could be sufficient to meet the new demand. [EPA-HQ-OAR-2009-0491-2842.1, p.4]
PSGC suggest that the NUSA be appropriate for the units currently under construction rather than randomly selected based on the entire region. [EPA-HQ-OAR-2009-0491-2842.1, p.4]
In the alternative, PSGC suggests that the U.S. EPA provide for more flexibility in the variability limits as they apply to states with new units, particularly if the gross new generation is in excess of 3% of the statewide cap. [EPA-HQ-OAR-2009-0491-2842.1, p.4]
The U.S. EPA should ensure that there are enough allowances accumulated in the NUSA to accommodate the additional emissions from new units. New units are likely to be more efficient and less polluting and so should be encouraged to be developed and operated. [EPA-HQ-OAR-2009-0491-2842.1, p.4]
4. BASIS OF ALLOCATIONS
The U.S. EPA has based allocations on actual 2009 emissions projected to 2012, incorporating the reductions that will occur with planned emission controls and required emission reductions. PSGC believes this approach creates unacceptable inequities. Both weather conditions and the economy caused 2009 to be a low utilization year and an inappropriate base year for determining allowance allocations. [EPA-HQ-OAR-2009-0491-2842.1, p.4]
Further, the U.S. EPA's reliance on emissions as the basis for determining allocations rewards sources that deferred controls under previous programs, perhaps preferring to buy allowances rather than to invest in pollution control equipment. At the same time, this approach effectively penalizes sources that have invested in and operated pollution controls and units that are very efficient. [EPA-HQ-OAR-2009-0491-2842.1, p.4]
In the case of PSGC, a merchant plant, it penalizes PSGC for being a state-of-the-art, extremely well-controlled, very efficient plant, because the PSD permit limits, which would have to be the basis of allocations to PSGC, already incorporate operation of the pollution control equipment and the efficiencies of the new plant. To further 'ratchet' the PSGC units downward in their allowance allocations on the basis of emissions projected directly or indirectly by the IPM confers unfair economic and competitive advantages to PSGC's competitors. [EPA-HQ-OAR-2009-0491-2842.1, p.4]
PSGC requests that the U.S. EPA base allocations on either gross megawatt output or heat input, of which PSGC prefers gross megawatt output. Either approach would level the playing field among generators, something that the U.S. EPA's approach clearly does not do, as the U.S. EPA acknowledges. p. 45311. However, basing allocations on gross megawatt output would reward efficiencies and encourage electrical dispatch of newer, better-controlled plants as well as improvements in efficiencies at older plants. [EPA-HQ-OAR-2009-0491-2842.1, p.5]
In Illinois, state rules limit emissions from certain plants. Those plants should not be allocated allowances in excess of their agreements reflected in state rules, particularly where those rules preclude emissions trading despite the proposal for limited interstate trading in the Transport Rule. [EPA-HQ-OAR-2009-0491-2842.1, p.5]
5. NUMBER OF ALLOWANCES THAT SHOULD BE ALLOCATED TO PSGC
PSGC should receive 2,282 annual NOx allowances for Unit 1 and 2,282 annual NOx allowances for Unit 2.
PSGC should receive 957 seasonal NOx allowances for Unit 1 and 957 seasonal NOx allowances for Unit 2.
PSGC should receive 5,933 SO2 allowances for Unit 1 and 5,933 SO2 allowances for Unit 2. [EPA-HQ-OAR-2009-0491-2842.1, p.5]
PSGC was issued a PSD permit on April 28, 2005, that includes emissions caps that reflect operation of a state-of-the-art, extremely well-controlled, very efficient coal-fired power plant. At the time the caps were developed, they reflected what the designers of the plant and the permitting authority determined was best available control technology limits ('BACT'). Moreover, these caps were developed in cooperation with the Federal Land Manager and determined to be protective of the downwind wilderness area that could otherwise have been affected by the plant. Additionally, projected emissions from the plant have been modeled to determine whether they would negatively impact downwind areas. The plant has been designed and constrained through its PSD permit so that downwind impacts would not occur. Therefore, the downwind impacts of this plant in particular have already been assessed and addressed at the level of the enforceable emission caps contained in the PSD permit. [EPA-HQ-OAR-2009-0491-2842.1, p.5]
Moreover, an examination of the data that EPA has posted indicates that the planned-committed coal-fired generation modeled for the Gateway Region was not attributable to any specific units. The level of this generation was approximately equivalent to PSGC's projected generation. Therefore, allocating allowances to PSGC in the amounts requested has already been included in the U.S. EPA's evaluation of downwind impacts and poses no potential disruption to the overall analysis. Documentation for EPA `s Basecase v.4.10, Ch. 4, Table 4-12, p. 4-14. Essentially, the U.S. EPA analyzed emissions from 'planned-committed' and new units on a regional basis, but must implement the program on the basis of political boundaries, yielding inconsistencies between the two analytical boundaries. [EPA-HQ-OAR-2009-0491-2842.1, p.5]
The U.S. EPA announced in the Preamble to the proposal that it views the Transport Rule to be a template for addressing the requirements of the Clean Air Act § 110(a)(2)(D) as new national ambient air quality standards ('NAAQS') are developed or existing NAAQS are revised. p. 45213. When this occurs, it is reasonable to expect that the number of allowances assigned to each unit will be reduced. Since PSGC is already extremely well-controlled and since all the alternatives that the U.S. EPA has proposed restrict or even preclude emissions trading, PSGC, already subject to BACT limits, may not be able to further control in order to comply with future amendments to the proposal. Therefore, assigning PSGC with at least the number of allowances corresponding to the emissions caps in its PSD permit is reasonable and protective of the environment. [EPA-HQ-OAR-2009-0491-2842.1, pp.5-6]
10. GENERAL CONCERN WITH THE BUDGETS
In proposed Appendix A, the U.S. EPA has listed the proposed allocations for each unit as well as the emission rates that would be assigned under the Direct Control option. p.45310. In the Technical Support Document ('TSD') addressing state budgets and unit allocations, the U.S. EPA claims the NOx, budgets were projected on emission rates of no less than 0.06 lb/mmBtu, because this is the lowest rate the U.S. EPA believes is attainable by new SCRs. State Budgets, Unit Allocations, and Unit Emissions Rates, TSD, p. 6. Additionally, the U.S. EPA says the rates assigned under the Direct Control option were based upon projected emissions. p. 45330. If the U.S. EPA were to adopt the Direct Control option, sources would remain subject to the same mass caps comprising the statewide budgets proposed for the U.S. EPA's 'preferred' option in addition to the rate limitations of the Direct Control option. Therefore, the rates of the Direct Control option appear to generally reflect the rates that the U.S. EPA projects units will have to achieve in order to comply with the statewide budgets. [EPA-HQ-OAR-2009-0491-2842.1, p.8]
Some of the assigned rates are less than 0.06 lb/mmBtu, and in some cases, the assigned rates are considerably less than 0.06 lb/mmBtu. See, e.g., Baldwin Units 1 and 2 (0.047 and 0.046, respectively), Havana Unit 9 (0.028), Marion Unit 4 (0.031), Powerton (0.058). The fact that some of the rates are less than 0.06 lb/mmBtu and that some are so much lower than 0.06 lb/mmBtu calls into question the validity of the statewide caps. If the Direct Control rates were back-calculated from the projected emissions that are the basis of the caps and those rates are below 0.06 lb/mmBtu, then the caps must be unattainable. [EPA-HQ-OAR-2009-0491-2842.1, p.8]
Allowances for PSGC have not been incorporated into Illinois' statewide budgets, but PSGC requests the U.S. EPA to recognize and allocate allowances to both Unit 1 and Unit 2, whose construction is well underway, as existing units, with the effect of increasing Illinois' budgets by those amounts. 3  The number of allowances in the NUSA and in the variability limits are directly dependent upon the size of the statewide budgets. If the U.S. EPA has been overly aggressive in establishing the appropriate levels of the budgets, PSGC is directly affected because the sizes of the NUSAs and variability limits will be less than they should be. PSGC's permitted NOx rate is 0.07 lb/mmBtu. As a new plant, its SCRs are also new and will operate better than SCRs installed years ago, exacerbating PSGC's concerns with the statewide budget that the U.S. EPA proposes. [EPA-HQ-OAR-2009-0491-2842.1, pp.8-9]
The data that the U.S. EPA has provided is insufficiently detailed for sources to determine the veracity of the results of the modeling. Moreover, a 60-day comment period is insufficient for sources to review modeling inputs once the U.S.. EPA makes them available. Evaluation of the modeling inputs requires expert analysis. As a result, it is infeasible for sources to realistically comment on the budgets and the allocations to individual units. [EPA-HQ-OAR-2009-0491-2842.1, p.9]
Additionally, PSGC, as a new plant, is very concerned with whether there will be sufficient allowances available. PSGC is not only concerned that the NUSA will not be sufficient but also that the allowance market will not be robust. PSGC is very concerned that the constraints on trading and the stringency of the reductions will cause sources to hoard their allowances. The U.S. EPA should encourage the operation of new, efficient plants such as PSGC rather than effectively penalize them through market constraints. Adding PSGC's emissions allocations to the current state budget and higher, more reasonable variability limits could help to effectuate this goal. [EPA-HQ-OAR-2009-0491-2842.1, p.9]
11. ALLOCATION METHODOLOGY
The U.S. EPA requested comment on its proposed allocation methodology that keeps all EGUs subject to the program, i.e., those serving generators with nameplate capacities greater than 25 MWe, in a single group as opposed to grouping EGUs according to size or percentage of generation in a state. pp. 45311-45312. PSGC agrees that EGUs should not be subgrouped and treated differently depending upon their group placements. [EPA-HQ-OAR-2009-0491-2842.1, p.9]
Moreover, PSGC believes that allocations based preferably on electrical output (or heat input) would offer a more equitable basis for allocations than projected emissions that incorporate planned and implemented pollution controls. A heat input- or electrical output-based allocation methodology would create a more level playing field among electrical generating units ('EGUs') in that those who deferred installation of controls would not be rewarded with more allowances because their emissions were higher during the base-year period. Likewise, those units that are controlled and are more efficient would not be placed at a disadvantage because of their improvements or, as in the case of PSGC, their initial design caused them to emit less. Using gross megawatt output would reward efficiencies while using heat input would not penalize early controllers. Either approach would level the playing field among generators, with gross electrical output actually rewarding efficient units, thereby promoting the operation of newer, highly controlled units to the benefit of the environment. [EPA-HQ-OAR-2009-0491-2842.1, p.9]
The U.S. EPA also requested comment on an allocation methodology that assumes operation of identified control measures and state and federal requirements in 2012 and 2013 and without variability limits. p. 45315. As stated above, PSGC believes that an allocation methodology based on heat input or electrical output would be more equitable than one based on projected emissions that automatically reflects reductions not required by rule that occurred prior to 2012. Early reducers and greater operational efficiencies should be rewarded, not penalized. [EPA-HQ-OAR-2009-0491-2842.1, p.9]
PSGC recognizes the U.S. EPA's stated interpretation of the North Carolina decision is to require reductions in the 2012-2013 timeframe. Perpetuating the approach that penalizes early reducers or low emitters and rewards those who delayed, however, is not an equitable approach or the approach that is best for the environment. The 2012 base-case upon which allowances are proposed includes adjustments intended to reflect reductions that are required by states and consent decrees and that can be achieved by currently-installed control equipment that is not otherwise required to be operated. That allocation base-case is less than the projected 2012 base-case that reflects only emissions projected to 2012 without assuming operation of installed control equipment not otherwise required to be operated. PSGC suggests that the U.S. EPA apply that percentage of reduction in either the overall region-wide budget or on a state-by-state basis and then allocate allowances to existing units pro-rata based on gross electrical output (or heat input). The exception to this is sources such as PSGC that are new but 'existing' and have permits that require them to be extremely well-controlled. Such sources' allocations should be equal to those permit limits. In PSGC's case, the permit includes emission caps already approved by the U.S. EPA through the PSD permitting process that should be honored in this rulemaking. This approach would put all EGUs, including 'new existing' EGUs such as PSGC, on an equal footing on a going-forward basis. [EPA-HQ-OAR-2009-0491-2842.1, pp.9-10]
13. ALLOWANCE SURRENDER FOR EXCESS EMISSIONS AND EMISSIONS IN EXCESS OF THE VARIABILITY LIMITS
The U.S. EPA requested comment regarding the number of allowances to be surrendered for failure to hold sufficient allowances in a source's compliance account on the date of true-up. p. 45314. The U.S. EPA proposes that the sources surrender an allowance for each ton of excess emissions plus an additional allowance per excess ton as an automatic penalty. p. 45314. Additionally, the source is potentially subject to discretionary enforcement action, including statutory penalties, for each ton of excess emissions. p. 45314. PSGC agrees that the surrender of one allowance for each ton of excess emissions as an automatic penalty is appropriate. [EPA-HQ-OAR-2009-0491-2842.1, p.10]
The U.S. EPA also requested comment on whether the proposed surrender of one allowance for each ton of emissions in excess of a unit's share of the state's variability limit, if statewide emissions are in excess of the statewide variability limit, is appropriate. p. 45314. PSGC agrees that the surrender of one allowance per ton of emissions equaling the owner's share of the total in excess of the variability limits is reasonable. PSGC also supports the U.S. EPA's proposal that exceedance of the variability limits not be violation of the Clean Air Act. [EPA-HQ-OAR-2009-0491-2842.1, p.10]

 3. On September 28, 2010, PSGC submitted its data for updating the NEEDS database to the docket and to the Clean Air Markets Division. [EPA-HQ-OAR-2009-0491-2842.1, p.8]
Response:
Thank you for your comment.Organization: Progress Energy Service Company
Comment:
Progress Energy Service Company
Progress Energy recommends that EPA allow units to borrow allowances from future years for use in compliance. This would provide increased flexibility, which will be particularly important in the early years of the program. This flexibility will be especially important if EPA promulgates a final rule that includes the ambitious compliance schedule that it proposes. [EPA-HQ-OAR-2009-0491-2831.1 p.8]
Response:
EPA believes that borrowing allowances from future control periods would contradict the mandate underlying the Transport Rule programs, which is to eliminate significant contribution to nonattainment and interference with maintenance as expeditiously as practicable.  EPA's power sector modeling show that far from needing future control period allowances, most states are capable of overcomplying with their 2012 emission budgets and thus establishing a bank of allowances to carry forward for year-to-year flexibility under the programs where needed.  EPA's prior trading programs, including the ARP, NOx SIP Call, and CAIR, have not included an allowance borrowing feature and have revealed no flaw for lacking such a feature; on the contrary, all of those programs have established substantial allowance banks near their outset. Additionally the final Transport Rule is designed to ensure that states achieve highly cost-effective emission reductions on a schedule compatible with attainment deadlines in downwind states. Allowing borrowing of allowances from future control periods would risk undermining that schedule by allowing EGUs to delay emission reductions beyond the time in which they are required to eliminate significant contribution to nonattainment and interference with maintenance in downwind states.
Organization: Public Power Generation Agency
Comment:
Public Power Generation Agency
Allowance Allocation for WEC Unit 2
According to the PTR and technical support documents ('TSDs') associated with it, Nebraska is a 'Group 2 state' and the PTR bases the nitrogen oxide ('NOx') and sulfur dioxide ('SO2') allowance allocations for Nebraska existing units on their 2009 'reported' emissions. Because WEC Unit 2 was not in commercial operation in 2009, it of course did not report any emissions in 2009. Neither the PTR nor the TSDs describe a specific methodology to calculate allowances for a unit that did not operate in 2009 and was not included in the IPM projections, yet meets the definition of an existing unit that will be in commercial operation before 2012. [EPA-HQ-OAR-2009-0491-2705.1,p.5]
In the absence of any other methodology or guidance on the issue, PPGA believes that its NOx and SO2 allowance allocations should be calculated and based on the information contained in its PSD permit. The permitted SO2 emission rate limit in the PSD permit is 0.12 lb/MMBtu and the permitted NOx emission rate limit is 0.08 lb/MMBtu (30-day rolling averages). The heat input capacity of WEC Unit 2 is 2,211 MMBtu/hr. These emission rates and heat input translate into annual emissions of 1,162 tons of SO2 and at least 775 tons of NOx. The emission rates and heat input - and annual emissions calculated from those two parameters -- were the basis ofWEC Unit 2's PSD permit, and allocation of PTR allowances should be based on these amounts, minus the 3% new source set aside. Accounting for the new source set aside, WEC Unit 2 should be allocated 1,127 SO2 allowances and at least 752 NOx allowances in the final rule.8 [EPA-HQ-OAR-2009-0491-2705.1,pp.5-6]
Counsel for PPGA contacted EPA's Clean Air Markets Division on multiple occasions to discuss an appropriate methodology for allocating allowances for WEC Unit 2, but no guidance or suggestions were provided by EPA. To the extent EPA may have a different view as to the appropriate allowance allocation from the position stated in these comments, PPGA respectfully requests that EPA provide its view and the specific basis for any alternative allocation methodology. PPGA would also be willing to meet with EPA prior to promulgation of the final rule to discuss any questions concerning the appropriate allowance allocation for WEC Unit 2. [EPA-HQ-OAR-2009-0491-2705.1,p.6]

8 If the NOx emission rate is raised to 0.12 lb/MMBtu, WEe Unit 2 should be allocated 1,127 NOx allowances.
Response:
Thank you for your comment.Organization: Santee Cooper
Comment:
Santee Cooper
Santee Cooper supports the limited interstate trading approach over EPA's alternative remedies because it allows electric generating units (EGUs) to achieve the emissions reductions and environmental objectives in the least cost manner that are within the constraints of the law. [EPA-HQ-OAR-2009-0491-2820.1, p.2]
EPA should eliminate the prohibition on trading of SO2 allowances between Group 1 and Group 2 states. The prohibition is not mandated by law, is economically inefficient, and has no environmental benefits. [EPA-HQ-OAR-2009-0491-2820.1, p.2]
EPA should extend the allowance transfer deadline for the annual SO2 and NOx emissions trading programs by an additional month. [EPA-HQ-OAR-2009-0491-2820.1, p.2]
EPA's proposed methodology for allocating allowances to existing affected W1itsis neither mandated by the statute (as interpreted by court decisions) nor establishes a reasonable method for allocating allowances to affected W1its within a state. In the case of Santee Cooper, EPA's allocations are completely inadequate to accommodate anticipated growth in electricity demand within our service territory. Like the states themselves, EPA has significant discretion to adopt an alternative allocation methodology that results in more logical assignments to individual EGUs. [EPA-HQ-OAR-2009-0491-2820.1, p.2]
If EPA decides to use the proposed allowance allocation methodology for existing affected units, the assumptions and data used for calculating the allowance allocations need to be corrected within the Santee Cooper system. [EPA-HQ-OAR-2009-0491-2820.1, p.3]
To avoid penalizing utilities that have already invested heavily in controlling emissions from their EGUs, EPA should consider adopting an alternative approach for allocating allowances to existing affected units based on 'well controlled' emissions benchmarks and historic baseline activity levels. [EPA-HQ-OAR-2009-0491-2820.1, p.3]
In the event that EPA chooses not to adjust the compliance deadlines for the Transport Rule and thus prevents states from submitting revised SIPs, EPA should at least solicit each state's preferences as to allowance allocation methodology and incorporate those preferences into each state's FIP. States could submit these allocation preferences to EPA on an informal basis before the finalization of the Transport Rule rather than as part of a full-blown SIP revision. [EPA-HQ-OAR-2009-0491-2820.1, p.3]
THE PROPOSED PROHIBITION ON TRADING OF S02 ALLOWANCES BETWEEN GROUP 1 AND GROUP 2 STATES IS ECONOMICALLY INEFFICIENT AND HAS No ENVIRONMENTAL BENEFITS [EPA-HQ-OAR-2009-0491-2820.1, p.5]
As proposed, the Transport Rule would establish two groups of states for purposes of interstate trading of SO2 allowances - a 'Group 1' consisting of states that would be required to achieve more stringent SO2 reductions in 2014 to fully address downwind air quality problems, and a 'Group 2' consisting of states that would be held to less costly and stringent SO2 reductions beginning in 2012. Trading of SO2 allowances among EGUs in different groups would be prohibited, even though the two groupings are not geographically contiguous. For example, the proposed rule would prohibit Santee Cooper's EGUs in South Carolina (a Group 2 state) from trading allowances with EGUs in the neighboring states of Georgia and North Carolina (both Group 1 states), even if doing so would prove more cost-effective than trading with EGUs in other, more distant Group 2 states. [EPA-HQ-OAR-2009-0491-2820.1, p.5]
Santee Cooper believes the proposed prohibition on trading among Group 1 and Group 2 states is arbitrary because it has no environmental benefit and could even have counterproductive impacts by forcing trading between EGUs located in two distant Group 2 states. As noted above, the prohibition against trading with neighboring Group 1 states will force Santee Cooper to trade allowances with EGUs located in far-off states, including Connecticut, Delaware, Kansas, Massachusetts, Nebraska and New Jersey. In addition, the proposed prohibition makes compliance with the Transport Rule needlessly costly and complex. With respect to SO2 emissions, the proposed Transport Rule already ensures that each state addresses its significant contributions to downwind nonattainment, or interference with maintenance of attainment, through the imposition of strict state-specific SO2 emission budgets (with variability limits on trading). The variability limits provide the necessary assurances that states achieve within the state the emissions reductions that are necessary to eliminate significant contribution. In other words, compliance with Section II0(a)(2)(D) of the Clean Air Act is assured so long as EGUs within a given state submit a quantity of SO2 allowances that falls within that state's budget. Whether those allowances were originally allocated within a Group 1 or Group 2 state simply has no bearing on the environmental performance of the Transport Rule. [EPA-HQ-OAR-2009-0491-2820.1, pp.5-6]
However, the prohibition on trading between Group 1 and Group 2 states does affect the cost of the Transport Rule. The most economically efficient way to meet the objectives of the Transport Rule is for EGUs that face the lowest cost of abatement (whether they be located in Group I or Group 2 states) to reduce their SO2 emissions. Yet under the proposed rule, an EGU in a Group 1 state that cost-effectively reduced its SO2 emissions could not sell its excess allowances to an EGU in a Group 2 state, or vice versa. The impediments to efficient trading are aggravated by the geographic distribution of Group 1 and Group 2 states; as a South Carolina utility, Santee Cooper expects that it would have significant opportunities to trade with utilities in the neighboring states of Georgia and North Carolina. These opportunities would be blocked - with no apparent environmental benefit - under EPA's proposal. Santee Cooper therefore urges EPA to dispense with the ban on trading between Group 1 and Group 2 states in the final version of the Transport Rule. [EPA-HQ-OAR-2009-0491-2820.1, p.6]
EPA HAS FAILED TO RECOGNIZE THE BROAD DISCRETION CONVEYED WITH REGARD TO THE ALLOCATION OF ALLOWANCES TO AFFECTED UNITS UNDER THE TRANSPORT RULE. [EPA-HQ-OAR-2009-0491-2820.1, p.9]
In contrast to the development of state emission budgets (as discussed in the previous section), we believe that EPA has significant discretion to determine the best method for allocating allowances to individual EGUs within each state. Neither the statute nor the D.C. Circuit's opinion in North Carolina require EPA to allocate allowances to EGUs on the basis of modeled or measured emissions, as EPA has proposed to do. First, North Carolina's discussion of the CAIR emission budgets did not, of course, place any explicit constraint on the method for allocating each state budget among individual emitting units - requiring EPA to instead only 'evaluate contributing emissions on a state-by-state basis.' Second, if North Carolina were interpreted to require individual EGU allocations to be based on projected emissions (as suggested by EPA in the proposed Transport Rule), then the necessary implication is that any SIP that does not make EGU allocations on this basis is somehow inconsistent with Section 110(a)(2)(D). We do not believe EPA can justify an interpretation of the statute that so narrowly constrains each state's allocations to individual EGUs. And if states have authority to prescribe alternative allocation methodologies in their SIPs, then EPA a fortiori has that same authority in prescribing a FIP under the Transport Rule. In Section II below, we urge EPA to exercise this discretion by adopting an allocation method that better accommodates projected growth and is more equitable to units that have already made costly pollution control investments. [EPA-HQ-OAR-2009-0491-2820.1, p.9]
EPA SHOULD EXTEND THE ALLOWANCE TRANSFER DEADLINE BY AN ADDITIONAL MONTH. [EPA-HQ-OAR-2009-0491-2820.1, p.17]
Under the proposed Transport Rule, the date by which affected units must surrender annual NOx, seasonal NOx, and annual SO2 allowances to cover their emissions - the 'allowance transfer deadline' - is March I after the relevant control period. Santee Cooper respectfully requests that EPA modify this deadline to April I in the final version of the Transport Rule. [EPA-HQ-OAR-2009-0491-2820.1, p.17]
An April deadline would ease the administrative burdens on both the regulated entities and the regulators. Practically all affected units under the Transport Rule are also covered units under the Title IV Acid Rain Program, and must hold Title V permits. Accordingly, these units already must comply with a series of data submission requirements in the first months of the year. Santee Cooper, for example, faces: (1) an annual January 30 deadline for fourth quarter Electronic Data Reporting under the Acid Rain Program, and submission of a Title V semi-annual report to the South Carolina Department of Health and Envirornnenta1 Control (S.c. DHEC); (2) an annual February 15 deadline for submitting a 'long form' Title V annual compliance report to S.C. DHEC; and (3) an annual March 1st allowance transfer deadline for the Acid Rain Program. In light of these existing report and data submission deadlines, it would be significantly easier for entities such as Santee Cooper to have an April 1 allowance transfer deadline under the CATR. [EPA-HQ-OAR-2009-0491-2820.1, p.17]
Furthermore, the shift from March to April would have no environmental impacts; an affected unit would still be required to hold allowances to cover its emissions in the relevant control period. The modification only would apply to accounting, not environmental performance. [EPA-HQ-OAR-2009-0491-2820.1, p.18]
Establishing an April 1 deadline falls well within the authority of the EPA and its broad discretion to design a regulatory program that is administratively manageable. While the Clean Air Act specified a March I deadline for the Acid Rain Program, the statute is silent on the deadline for allowance reconciliation for an emissions trading program to address interstate pollutant transport pursuant to section 110(a)(2)(D). [EPA-HQ-OAR-2009-0491-2820.1, p.18]
For the above reasons, Santee Cooper respectfully urges EPA to shift the allowance transfer deadline for the CATR trading programs to April 1. [EPA-HQ-OAR-2009-0491-2820.1, p.18]
COMMENTS ON PROPOSED ALLOWANCE ALLOCATIONS TO SANTEE COOPER [EPA-HQ-OAR-2009-0491-2820.1, p.18]
As discussed above in Section I, Santee Cooper supports EPA's proposed approach for setting the state emissions budgets based state-specific factors that analyze both control costs and air quality impacts in downwind nonattainment areas. EPA's proposed approach corrects the legal flaws inherent in the regional significant contribution analysis that was used in the CAIR program and establishes a reasonable state-specific methodology for quantifying each state's significant contribution. However, Santee Cooper has major objections to the proposed approach for allocating allowances to affected existing units from the newly established state emissions budgets. The EPA proposal would base allowance allocations to existing units on projected emissions from these units after elimination of some or all of the significant contribution and interference with maintenance. Specifically, EPA would allocate allowances to existing units by using the same theoretical method and assumptions that were used in developing the proposed emissions budgets. Santee Cooper believes that the EPA approach is neither mandated by statute (as interpreted by court decisions) nor establishes a reasonable method for allocating allowances to affected units within a state. [EPA-HQ-OAR-2009-0491-2820.1, p.18]
EPA's PROPOSED METHODOLOGY IS NOT MANDATED BY THE CLEAN AIR ACT. In Section I.E. above, Santee Cooper discussed the legal reasons why EPA is not required to adhere to the same methodology used in setting the state emissions budgets. The statute focuses on eliminating significant contribution and interference with maintenance within the state and requires that the state develop a SIP control program that achieves the emissions reductions necessary for achieving this objective (specifically, meeting its section 110(a)(2)(D) requirement). Both the statute and North Carolina decision make it clear that each state has wide latitude in crafting a control program for achieving the necessary emissions reductions within the state, which - in this case - involves achieving the applicable state emissions budget set for EGUs within the particular state. A state, on the one hand, may elect to adopt any mix of command-and control requirements that achieve the requisite emissions reductions from EGUs and other types of sources within the state. If, on the other hand, a state elects to opt-into the model regional trading program established by EPA, the state may choose any allocation scheme it deems appropriate so long as the state trading program can achieve the emissions reductions necessary for meeting its significant contribution requirement under section 110(a)(2)(D). [EPA-HQ-OAR-2009-0491-2820.1, p.19]
The fact that EPA itself is proposing to implement control requirements of the Transport Rule through a FIP does nothing to diminish EPA's discretion in selecting an appropriate allocation methodology. Notably, EPA has effectively recognized its broad discretion on this element of the proposed Transport Rule by seeking public comment on a wide-range of alternative allocation methods. Furthermore, recognizing the broad discretion on the allowance allocation method is consistent with how EPA has implemented past regional trading programs pursuant to section 110(a)(2)(D), including the NOx SIP Call and the CAIR programs. [EPA-HQ-OAR-2009-0491-2820.1, p.19]
EPA's PROPOSED METHODOLOGY IS NOT A REASONABLE METHOD FOR ALLOCATING ALLOWANCES. [EPA-HQ-OAR-2009-0491-2820.1, p.20]
In addition to not being mandated by statute, the EPA proposal does not establish a reasonable method for allocating allowances to affected units within a state. This is first and foremost reflected by the fact the proposed EPA approach fails to provide appropriate recognition of the action that electric utilities have achieved to lower their emissions prior to 2012. In the case of the Santee Cooper system, for example, Santee Cooper has installed FGD scrubbers for reducing SO2 on 88 percent of its coal-fired generation. Similarly, Santee Cooper has installed SCR systems for controlling NOx emissions on 88 percent of its coal-fired generation. As result of these control efforts, Santee Cooper has reduced its annual SO2 emissions by approximately 70,000 tons per year based on a comparison of 2005 and 2009 emissions levels. This amounts to about an 80 percent reduction in SO2 emissions. Similarly, Santee Cooper has reduced its NOx emissions by approximately 35,000 tons per year between 2000 and 2009, which amounts to a 77 percent reduction in annual NOx emissions. Notwithstanding, Santee Cooper is projected to have a substantial short fall in annual SO2 allowances given that - in EPA's own words - 'a unit that installs control equipment receives fewer allowances than a similar unit that did not install control equipment." [EPA-HQ-OAR-2009-0491-2820.1, p.20]
The punitive effect of the proposed EPA allocation scheme is illustrated in the following two charts. In particular, Chart I [See p.22 of this comment summary for Chart I] below compares the SO2 emissions in 2000, 2005 and 2009, to allowance allocations to the coal-fired units owned and operated by Santee Cooper under the EPA proposal. A similar comparison is made for NOx emissions and allowances allocations in Chart II [See p.22 of this comment summary for Chart II] below. These two charts clearly demonstrate that Santee Cooper has made extraordinary efforts to reduce its SO2 and NOx emissions by very substantial amounts over the last decade. Notably, Santee Cooper achieved in 2009 system-wide emissions rates for its coal-fired generation of 0.16 Ibs/mmBtu for SO2 and 0.09 Ibs/mmBtu for NOx Moreover, the two charts show that not only are these efforts entirely overlooked by EPA, but also that EPA's allocation methodology effectively penalizes clean electric utilities like Santee Cooper by lowering their allowance allocation to the extent that they have reduced their emissions through the installation (or upgrading) of pollution control equipment. [EPA-HQ-OAR-2009-0491-2820.1, pp.20-21]
This is especially the case with respect to SO2. Specifically, Chart III [See p.23 of this comment summary for Chart III] below shows that the Santee Cooper coal-fired system will have a substantial short fall of SO2 allowances in 2012 and future years thereafter of the Transport Rule program. The shortfall of allowances identified in Chart III ranges from 11,038 allowances in 2012, to 5,848 allowances in 2015. This means that Santee Cooper will have to purchase a large number of SO2 allowances from other electric utilities, not withstanding its very substantial efforts to control its SO2 emissions and achieve a very low system-wide SO2 emissions rate of 0.16 lbs/mmBtu in 2009. [EPA-HQ-OAR-2009-0491-2820.1, p.21]
The unreasonableness of the EPA approach is further demonstrated in Charts IV [See p.23 of this comment summary for Chart III] and V [See p.24 of this comment summary for Chart V] below. These charts provide a comparison of the coal unit emissions levels and the 2012 Transport Rule allowance allocations for Santee Cooper and the other major electric utility systems in South Carolina. Chart IV provides such a comparison of SO2 and NOx emissions to allowance allocations based on a MW of coal capacity basis. Chart V provides a similar comparison of coal unit system-wide allocation SO2 and NOx emission rates for Santee Cooper and the other major South Carolina electric utility systems. In each chart, the comparison illustrates that both SCANA and Progress will be rewarded for not installing pollution control equipment or undertaking other measures for reducing their emissions. The egregiousness of the EPA approach is particularly illustrated in the case of SO2. SCANA and Progress will receive proportionately more allowances than Santee Cooper to cover emissions from their units - a high percentage of which operate without stringent emissions controls. Notably, Progress is allocated SO2 allowance at a rate 8.6 times higher, and SCANA 5 times higher, than Santee Cooper based on a MW of capacity basis in Chart IV. [EPA-HQ-OAR-2009-0491-2820.1, p.23]
SUMMARY OF DISCREPANCIES IDENTIFIED IN SANTEE COOPER DATA [EPA-HQ-OAR-2009-0491-2820.1, p.26]
The following items are discrepancies that Santee Cooper has identified in EPA-HQ-OAR- 2009-0491-0074 1 data sheets: [EPA-HQ-OAR-2009-0491-2820.1, p.27]
Winyah Unit 3 received no ozone season NO, allowances despite the fact the unit is projected to operate as a baseload unit. [EPA-HQ-OAR-2009-0491-2820.1, p.27]
Jefferies Unit 3 SO2 allowances appear to be based on arbitrary assumptions and data input that do not reflect normal operation of the unit. Historically, Jefferies Units 3 and 4 are dispatched at similar utilization levels and Santee Cooper's model projects similar dispatch levels to continue in the future. In addition, the two units bum the same coal. These similarities clearly indicate that the allocations should be set at similar levels. Although the allocations for NOx for the two units are similar, the SO2 allocation for Unit 4 is 4.7 times higher than Unit 3. [EPA-HQ-OAR-2009-0491-2820.1, p.27]
Cross Units I, 3, and 4 have projected SO2 rates that are approximately one half of the PSD netting rates for these units that reflected in federally enforceable permit conditions. [EPA-HQ-OAR-2009-0491-2820.1, p.27]
Grainger Units I and 2 and Jefferies Units 3 and 4 have projected SO2 rates that are approximately one half of the expected rates for these units. [EPA-HQ-OAR-2009-0491-2820.1, p.27]
The NEEDS data show NOx emission rates for Cross Units I & 2 and Winyall Units I, 2 and 4 are well below their consent decree limits:  [EPA-HQ-OAR-2009-0491-2820.1, p.27; See p.27 of this comment summary for NEEDS data showing NOx emission rates for Cross Units 1 & 2 and Winyah Units 1, 2 and 4 are well below their consent decree limits]
EPA SHOULD ALLOCATE ALLOWANCES TO EXISTING UNITS BASED ON WELL-CONTROLLED EMISSIONS BENCHMARKS AND HISTORIC BASELINE ACTIVITY LEVELS. [EPA-HQ-OAR-2009-0491-2820.1, p.29]
Santee Cooper urges the adoption of an alterative approach that avoids the unreasonable and arbitrary effects of EPA's proposed scheme for allocating allowances to existing units affected under the Transport Rule. Key objectives of such an alterative allocation scheme should include the following: [EPA-HQ-OAR-2009-0491-2820.1, p.29]
Allocate equivalent allowances to same types of units burning the same fuels; [EPA-HQ-OAR-2009-0491-2820.1, p.29]
Do not penalize those units that have reduced their emissions through the installation of pollution control equipment or other such emissions reduction measures prior to the start of the control period; and [EPA-HQ-OAR-2009-0491-2820.1, p.29]
Do not reward uncontrolled units, but rather provide incentives for such units to reduce their emissions. [EPA-HQ-OAR-2009-0491-2820.1, p.29]
One approach deserving special consideration is a system that would allocate allowances based on the SO2 and NOx emissions levels of a well-controlled electric generating unit. Under this approach, EPA would make a determination on what would be the SO2 and NOx emissions rates of a well-controlled coal unit, well-controlled gas unit, and a well-controlled oil unit. Such a determination could be made based on representative average control levels for each category of affected units. Once the emissions rate has been determined for each category of units, the allowances then would be allocated in accordance with the following formula: [EPA-HQ-OAR-2009-0491-2820.1, p.29]
A = WC EMISSION RATE X BASELINE [EPA-HQ-OAR-2009-0491-2820.1, p.29]
Where: A = Number of allowances allocated to an existing affected electric generating unit [EPA-HQ-OAR-2009-0491-2820.1, p.29]
WC Emissions Rate = Emissions rate established for well-controlled electric generating unit for the particular category of units (expressed in terms of either Ibs/mmBtn or IbsIMWH) [EPA-HQ-OAR-2009-0491-2820.1, p.29]
Baseline = Historic activity level of the affected electric generating unit (either heat input or MWH output) [EPA-HQ-OAR-2009-0491-2820.1, p.30]
Baseline levels should be determined based on actual activity levels of the unit (either heat input or MWH output) during a representative historic period. Santee Cooper suggests that the initial baseline period should be the annual average of the 3 highest years during the previous prior 5 years. This flexibility in setting the initial baseline period is appropriate in order to ensure a representative baseline period and given the general economic downturn in many parts of the country over the past few years. Santee Cooper would also recommend an updating baseline on a periodic basis (such as every five years) to reflect major shifts in the utilization of affected units in future years of the program. Such an updating function is critical for states such as South Carolina where certain service territories of some electric utilities are expected to experience high growth, while the electric demand of other electric utility service territories may remain flat or have low growth. [EPA-HQ-OAR-2009-0491-2820.1, p.30]
Finally, EPA should adopt an adjustment mechanism to ensure that the total number of allowances allocated to all affected units within a state does not exceed the emissions budget established for that state. This adjustment mechanism could be modeled after the ratchet mechanism established under the acid rain program, whereby EPA will reduce each unit's allocation on a pro rata basis based on the number of allowances allocated to each unit under the preceding formula. [EPA-HQ-OAR-2009-0491-2820.1, p.30]
Response:
EPA disagrees with the commenter's assertion that an "updating function" for existing unit allocations is "critical... where certain service territories of some electric utilities are expected to experience high growth."  This comment ignores the fact that the economic determination of unit dispatch to meet electricity demand will factor in the cost of emitting (i.e., the market price of an allowance) whether or not an allowance was freely allocated for a ton emitted from that unit's generation.  It is not necessary, therefore, for EPA to update the allocation pattern to existing units because utilities will continue to meet electricity demand (no matter the rate of growth) with the least-cost generation available, including the cost of such generation's emissions under the state budgets whether or not such emissions are covered by initially allocated or purchased allowances.  A utility whose service territory experiences future load growth will seek to minimize operating costs of meeting that increased load; that cost accounting will always incorporate the cost of emitting because such emissions will require allowances (with market value) to be submitted whether or not those allowances were originally allocated to the unit in question,  In addition to being unnecessary, EPA believes updating allocations to existing units would introduce unwarranted uncertainty into the programs as administered under the FIPs, whose existing unit allocations are being presented with the promulgation of this final rulemaking in order to aid advance allowance transaction planning among sources in the marketplace.  While states have the prerogative to replace the FIPs with SIPs and determine a different allocation methodology for future control periods under that SIP, EPA does not believe it is reasonable to introduce further uncertainty into the FIP structure by shifting the allocation pattern to existing units in future control periods in ways that are difficult, if not impossible, to anticipate.
Organization: Southern Company
Duke Energy
American Electric Power
National Rural Electric Cooperative Association (NRECA)
Louisiana Chemical Association (LCA)
National Grid
Consolidated Asset Management Services (CAMS)
Mississippi Department of Environmental Quality
City of Dover, Delaware
Indiana Department of Environmental Management
Clean Energy Group
New Jersey Department of Environmental Protection (NJDEP)
Illinois Environmental Protection Agency
West Virginia Department of Environmental Protection
we energies
New York State Department of Environmental Conservation
Seminole Electric Cooperative Inc.
State of Delaware Department of Natural Resources & Environmental Control
Maryland Department of Environment (MDE)
Constellation Energy
Council of Industrial Boiler Owners (CIBO)
State of Wisconsin, Department of Natural Resources
Vectren Corporation
Louisiana Public Service Commission
State of Ohio Environmental Protection Agency (Ohio EPA)
Oklahoma Department of Environmental Quality
State of Louisiana, Department of Environmental Quality
Virginia Department of Environmental Quality (VDEQ)
Kansas City Board of Public Utilities (BPU)
Virginia Independent Power Producers
Independence Power & Light (IPL)
NextEra Energy, Inc.
Florida Electric Power Coordinating Group, Inc. (FCG)
GE Energy Financial Services (GE EFS)
East Texas Electric Cooperative
San Miguel Electric Cooperative, Inc.
Lansing Board of Water & Light
Northern Indiana Public Service Company (NIPSCO)
PSEG Services Corporation
Xcel Energy Inc.
PPL Corporation
Connecticut Department of Environmental Protection
Wolverine Power Supply Cooperative
Edison Mission Energy (EME)
City of Tallahasse
Buckeye Power, Inc.
Great River Energy
Louisiana Energy and Power Authority (LEPA)
Excelsior Energy
AES Corporation (AES)
First Energy
Sunbury Generation LP
Calpine Corporation
New York Power Authority
Oglethorpe Power
Alcoa Power Generating Inc. - Warrick Power Plant
Florida Municipal Power Agency (FMPA)
PowerSouth Energy Cooperative
Tenaska, Inc.
Cleco Corporation
Associated Electric Cooperative, Inc. (AECI)
Southern IL Power Cooperative
Northern Star Generation LLC
Marquette Board of Light and Power
ARIPPA
Entergy Services, Inc.
DTE Energy
Rochester Public Utilities (RPU)
Potomac Power Resources
Dow Chemical Company
Manitowoc Public Utilities (MPU)
Holland Board of Public Works
Exxon Mobil Corporation
Piney Creek LP
Mirant Corporation
Michigan Municipal Electric Association (MMEA)
American Public Power Association (APPA)
Alliance to Save Energy
New York University School of Law, Institute for Policy Integrity
American Clean Skies Foundation (ACSF)
Texas Chemical Council
Gainesville Regional Utilities (GRU)
Reiss, J.
Machaver, Bob
E.ON U.S.
Northeast States for Coordinated Air Use Management (NESCAUM)
Comment:
AES Corporation (AES)
The proposed allowance allocations in the proposed rule and supporting technical information are flawed. The allowance allocations in the Technical Support Documents are based on flawed historical data and emissions level model inputs that do not incorporate startup, shutdown and malfunction periods. EPA is aware of the limitations of FGD and SCR technology, especially on start-up and low-load operation. Without compliance flexibility for low-load, startup, shutdown and malfunction events, it is probable that some units will have to comply by either increasing minimum generation or discontinuing operations. Reduced operating flexibility or discontinuation of operations could result in system reliability related issues especially since this applies to a large fleet of assets. [EPA-HQ-OAR-2009-0491-2791, p.3] [EPA-HQ-OAR-2009-0491-3793.1_NODA, p.3]
The use of one year for base line allowances does not account for normal fluctuations in markets, operations, major outages, long term forced outages, etc. We request that the rule be revised to incorporate a more realistic multi-year baseline to incorporate the changes in emissions levels due to system demand, fuel pricing, and operational variances. A simple 24 month out of the past 60 month is an easy method to ensure that the likely operations are taken into account for setting budgets. [EPA-HQ-OAR-2009-0491-2791, p.6]
The proposed allowance allocations in the NODA for the proposed rule and supporting technical information are flawed. The NODA states that some of the data used is reported and in inaccurate for many cases. Also the results do not incorporate startup, shutdown and malfunction periods. [EPA-HQ-OAR-2009-0491-3793.1_NODA, p.3]
The short time period to determine base line allowances does not account for normal fluctuations in markets, operations, major outages, long term forced outages, etc. We request that the rule be revised to incorporate a more realistic multi-year baseline to incorporate the changes in emissions levels due to system demand, fuel pricing, and operational variances. A simple 24 month out of the past 60 month is an easy method to ensure that the likely operations are taken into account for setting budgets. [EPA-HQ-OAR-2009-0491-3793.1_NODA,p.7]
Alcoa Power Generating Inc. - Warrick Power Plant
Warrick 4 had a selective catalytic reduction unit for NQx control during the ozone season installed in 2004, and a wet flue gas desulfurization scrubber installed in 2008 for SO2 control as required by CAIR at capital costs in excess of $200 MM, The allocation procedure described on 75FR45311,i.e
'...all units are allocated allowances consistent with their projected emissions; this means that a unit that installs control equipment receives fewer allowances than a similar unit that did not install control equipment.'
thus unfairly penalizes EGU' s, such as Warrick 4, that have gone to the expense of installing the control device hardware needed to meet previous requirements, and appears to reward BGU' s that have not installed control equipment. [EPA-HQ-OAR-2009-0491-3648,p.3]
APGI recommends a 2-step approach for allowance allocation, after EPA re-examines the emission reductions, as suggested in the first two comments. Step 1 would be to reduce each EGU's emissions in 2005 by the efficiencies required to reduce emissions to the state budgets for SO2 and NOx 2012 and 2014 levels. If, after the application of Step 1, emissions equal the state budget, allowances would be established at those emission levels, minus the new source set-asides. If Step 1 exceeds the budgets, a Step 2 calculated adjustment for additional emission reductions would be derived by each EGU's proportional share of total state EGU heat input, multiplied by the amount that Step 1 exceeds the budget. The Step 1 allowance for each EGU would then be reduced by its Step 2 calculated adjustment. [EPA-HQ-OAR-2009-0491-3648, p.3]
Alliance to Save Energy
As noted in the NOPR, under a FIP the EPA allocates emission allowances directly to individual sources. However, we understand that some states may prefer to use their own procedures, rather than EPA's, to allocate emissions allowances to in-state sources. In some cases states may wish to include set-asides for energy efficiency and renewable energy (EERE) measures. The Alliance believes that states following their own procedures, including inclusion ofEERE set-asides, should not affect the approvability of SIPs because the distribution of allowances within a state does not affect overall emissions in the state. [EPA-HQ-OAR-2009-0491-2800.1 p.3]
However, the NOPR does not provide guidance to states on what EPA would accept asallowance distribution approaches or mechanisms. The Alliance urges EPA to:
:: indicate to states that it will duly consider state SIPs that incorporate FIPcomponents but only differ in terms of allowance allocation mechanisms;
:: provide guidance on what allowance distribution approaches or mechanisms itwill accept; and
:: provide guidance on criteria that state SIPs would have to meet to allowapplicable emission sources in a state to participate in the interstate emissions trading program. [EPA-HQ-OAR-2009-0491-2800.1 p.2]
The Alliance understands that those states that incorporated EERE set-asides under CAIR required significant technical assistance from EPA, the Department of Energy (DOE), and outside consultants. Each of those states individually struggled to determine EPA-acceptable SIP parameters, including such things as, among others, additionality and enforceability concerns, measurement & verification (M&Y) issues, and types of energy efficiency measures that could be eligible for set-asides. Guidance offered in the previously cited 2004 EPA document 'Guidance on State Implementation Plan (SIP) Credits for Emission Reductions from Electric-Sector Energy Efficiency and Renewable Energy Measures' is at a very high and broad level and was of limited utility for state and local air quality agencies seeking to incorporate EERE set-asides into their programs. [EPA-HQ-OAR-2009-0491-2800.1 p.2]
Thus, the Alliance urges the EPA to provide greater guidance and technical assistance to states on incorporating EERE set-asides or other energy efficiency provisions into a SIP, including:
[EPA-HQ-OAR-2009-0491-2800.1 p.2]
 :: model rules; and
:: adviee on measure eligibility, M&Y, and other parameters that must be met for EPA aeceptanee of a SIP.
We note that the Commonwealth of Massachusetts implemented a successful EERENOx allowance set-aside program under CAIR in which EERE set-asides have been oversubscribed and such allowances have been sold in the market. Thus,Massachusetts may serve as a good case for guidance and assistanee to other states. [EPA-HQ-OAR-2009-0491-2800.1 p.2]
(We also recognize that some states may opt for an alternative EERE set-aside program in which emissions allowances attributed to EERE are retired as creditable NOx reductions under the SIP rather than sold into the market.) [EPA-HQ-OAR-2009-0491-2800.1 p.3]
The Alliance recognizes that establishing emissions allowances on an output basis may be more complex than using a heat-input basis in the case of combined heat and power (CHP) systems, where useful heat energy is captured and utilized. However, very few existing utility power generators that would be regulated under the Transport Rule are CHP facilities, a number of states have successfully enacted output-based standards that accommodate and credit CHP facilities for useful thermal output, and an existing NSPS for electric utility steam generating units incorporates output-based standards. These facts suggest that EPA can use output-bases for developing emissions allocations. [EPA-HQ-OAR-2009-0491-3926[1].1, p.4]
American Clean Skies Foundation (ACSF)
Despite supporting much of the Proposed Rule, ACSF has significant concerns regarding CATR's proposed method for allocating emission allowances that cap power plant emissions. In particular, the Proposed Rule's emission-based allocation method irrationally subsidizes high-emitting coal-fired generation, to the disadvantage of clean-burning gas generation and in contravention of air quality and public health goals. Furthermore, failing to adequately address upwind pollution from coal-fired power plants violates the statutory language of the Clean Air Act. [EPA-HQ-OAR-2009-0491-2759.1, p.2]
As noted above, the Proposed Rule would regulate NOx and SO2 emissions from power plants that drift across state borders and contribute to downwind states failing to attain compliance with national air quality standards. However, CATR's proposed emission reductions are just a first step, as EPA anticipates additional reductions will be needed through updates to the transport rule. Thus, adopting a rational and appropriate allocation method now is crucial because it is likely to affect future transport rulemakings as well. [EPA-HQ-OAR-2009-0491-2759.1, p.3]
ACSF submits that the purpose of the Proposed Rule is unnecessarily jeopardized by basing allocations on historic emissions. [EPA-HQ-OAR-2009-0491-2759.1, p.4]
a. Basing allocations on historic emissions penalizes utilities--and ratepayers--who have incurred costs to switch to cleaner forms of generation, including renewables and natural gas.
An emissions based allocation method provides a subsidy to those utilities with higher-emitting units, to the detriment of those utilities with lower-emitting units. CATR's emission-based allocation penalizes utilities (and states in which those utilities are located) that have installed control equipment, or converted to cleaner-burning generation sources, prior to the baseline years used by EPA for setting allocations. Simply put, utilities that have switched to natural gas (or installed scrubbers and SCRs or 'greened' their portfolios with wind and solar generation) should not be required to subsidize the installation of new emission controls on coal plants by utilities (and states) that have delayed such measures. In addition to the patent unfairness and ratepayer impacts, historic emissions allocations may encourage power plants (and states) to avoid installing needed controls (or taking other measures) for as long as possible so as to maximize their baseline allocations. [EPA-HQ-OAR-2009-0491-2759.1, p.4]
EPA's previous allocation method in CAIR favored coal over gas and was rejected by the D.C. Circuit. CAIR was rejected by the D.C. Circuit, among other reasons, because of a flawed system that disproportionately taxed gas-fired generators. For instance, because Louisiana's power plants used more gas than coal, its NOx budget was reduced to 29,000 tons, from the 42,000 tons that it would have otherwise received. The court found 'the net result will be that states with mainly oil- and gas-fired EGUs will subsidize reductions in states with mainly coal-fired EGUS.' The court rejected this subsidy. In its CAIR decision, the court found that "those states with the greatest emissions are those with mainly coal-fired EGUs, which are precisely the states that get extra credits." The court determined that EPA had favored high-emitting coal based on a misguided sense of 'equity among upwind states,' which was 'improper,' and that the resulting emission budgets were arbitrary and capricious. Unfortunately, as further explained below, the Proposed Rule allocation method continues to subsidize high-emitting coal plants to the detriment of cleaner-burning gas generation and is similarly arbitrary and capricious. [EPA-HQ-OAR-2009-0491-2759.1, pp.4-5]
b. EPA should consider other allocation methods besides CATR's proposed emission-based approach.