Throughout the preamble to the Transport Rule, EPA purports to create a cost effective and flexible program to address each state's significant contribution to downwind states. Unfortunately, EPA has punished inherently clean burning simple cycle combustion turbines, at least in Minnesota, by lumping them into the EGU category and by allocating limited allowances to them. Great River Energy firmly believes that our simple cycle combustion turbines, as emission sources, do not 'contribute significantly' to downwind annual non-attainment and should be treated separately from 'EGUs' under the Transport Rule. [EPA-HQ-OAR-2009-0491-2758.1 p.7]
Given the extent of the supporting documentation with associated references back to the CAIR rule, and its associated technical support documentation, it is virtually impossible to determine EPA's precise methodology for including simple cycle combustion turbines as part of the 'EGU' source category. [EPA-HQ-OAR-2009-0491-2758.1 p.7]
EPA makes the argument that controls are not cost effective for industrial boilers, as a source category, with estimates well below EPA's break point of$5,000/ton for the Transport Rule,2 and then proceeds to exempt them from the Transport Rule. As discussed elsewhere, Great River Energy's simple cycle combustion turbines generally have DLN and water injection for NOx control, and bum ULSD fuel oil for S02 control. Additional NOx reductions for these emission sources would require costly controls, such as SCR, approaching significantly more than $10,000/ton of emission reductions. Similarly, several of Great River Energy's peaking plants have state synthetic minor restrictions <<250 tpy NOx and S02), resulting in even less of a potential contribution to downwind annual non-attainment. [EPA-HQ-OAR-2009-0491-2758.1 p.7]
In addition, with respect to Minnesota state emissions, and other states for that matter, EPA argues that industrial boilers contribute relatively less to downwind non-attainment. As a source category, combustion turbines contribute even less to interstate transport than industrial boilers, and other exempted sources for that matter.3 Certainly, EPA can argue that a general SIC code determination has been made to include all 'EGUs,' as was made with CAIR. Yet, upon a more detailed review of the data, it is clear that the inclusion of combustion turbines, and the exemption of industrial boilers, is both arbitrary and capricious. [EPA-HQ-OAR-2009-0491-2758.1 p.7]
In summary, Great River Energy's peaking plants would be more costly to control than industrial, commercial and institutional boilers and represent a smaller portion of state emissions and associated contribution to downwind annual non-attainment. Consequently, they should be excluded as a source category from the Transport Rule, like the non-EGU boilers and turbines. [EPA-HQ-OAR-2009-0491-2758.1 p.7]
Response:
With regard to allocations simple cycle combustion turbines, see section VII.D of the preamble.
With regard to applicability to simple cycle combustion turbines, see section VII.B of the preamble.  EPA rejects the commenter's approach of separating units using one combustion technology -- i.e., simple cycle combustion turbines -- to generate electricity for sale from units using other types of combustion technology -- such as boilers and combined cycle combustion turbines -- to generate electricity for sale.  EPA maintains that it is reasonable to consider the electricity generation section as a whole in determining the cost of available emission reductions and in determining a state's significant contribution and interference with maintenance.  In past trading programs (such as the Acid Rain Program, NOx Budget Trading Program, and CAIR trading programs), EPA has taken the general approach of regulating the entire electricity generation sector, rather than treating the different combustion technologies separately.  Further, if entire groups of units with different combustion technologies were treated differently for purposes of regulating their emissions, utilization for electricity generation, and the resulting emissions, could shift to those units from covered units because of the high level of integration of the electric generation, transmission, and distribution system (which has increased with the significant restructuring and deregulation of electric utilities) and thereby threaten achievement of elimination of states' significant contribution and interference with maintenance, which is the goal of the Transport Rule.  Although the exemption of any portion of the electricity generation sector creates the potential for generation shifting, the greater the number and scope of the exemptions, the greater the likelihood and likely magnitude of the potential generation shifting.  After the balancing the commenter's claimed rationale for the requested exemption and the potential adverse effect of such an exemption, EPA rejects the commenter's position and maintains that EPA's approach of regulating emissions from essentially the entire electricity generation sector -- with a few, limited exemptions, e.g., for certain cogeneration units and solid waste incineration units -- is consistent with the goal of the Transport Rule.
Organization: Indiana Department of Environmental Management
Clean Energy Group
Pennsylvania Department of Environmental Protection
Maryland Department of Environment (MDE)
Eco Power Solutions (USA) Corp.
State of Missouri Department of Natural Resources
Exelon
PPL Corporation
Class of '85 Regulatory Group
Fond du Lac Reservation
National Tribal Air Association (NTAA)
Portland Cement Association (PCA)
Comment:
Class of '85 Regulatory Group
EPA Should Allow Additional Units to Opt-In.
The Class of '85 supports opt-in provisions, and believes that EPA can further broaden the scope of the preferred option's opt in provisions without any adverse impact on in-state emissions reductions. Specifically, units below the current 25 MW threshold are typically used for peaking purposes. As a result, many of those units do not operate for a sufficient amount of time to satisfy the requirement that an opt-in unit operate for at least 876 hours within six months. EPA should consider eliminating the 876-hour requirement and allow smaller units to opt in regardless of operating time. This change will increase the number of covered sources without affecting state budgets or emissions reductions in any way. Because many of these units are natural gas-fired peaking units with low emissions rates, the inclusion of additional smaller units will help to reduce emissions in a highly cost-effective manner. In addition, eliminating the 876-hour requirement will remove the perverse incentive to operate smaller units for additional hours simply to satisfy the opt-in requirement. [EPA-HQ-OAR-2009-0491-2854.1, p.14]
Clean Energy Group
Opt-in Provisions
At certain points on hot summer days, electric demand increases to accommodate air conditioning and other requirements, and a portion of the increase in electric demand is typically satisfied by peaking units such as combustion turbines and internal combustion engines. These 'peakers' are capable of responding to a dispatch request quickly and can attain full load in less than thirty minutes. Typically, peakers have high operating costs, and thus run as rarely and only when no more cost-effective EGUs are available to meet demand. Certain states, such as in the Northeast's Ozone Transport Region in particular, are adopting measures to require NOx emission controls on combustion turbines and other electric generating units of less than 25 MW capacity as part of 'high electric demand day' (HEDD) programs. Typical HEDD units operate less than 100 hours during the ozone season and are generally permitted to operate for less than one month at full load on a rolling 12-month basis (a five percent annual capacity factor). [EPA-HQ-OAR-2009-0491-2702.1, p. 11]
The Transport Rule allows units below the rule's 25 MW threshold to join the allowance trading programs. However, the owner of any unit opting in would be required to certify that the unit operated at least 876 hours in the six months prior to the opt-in request (a ten-percent capacity factor). As explained above, small peaking units below the proposed Transport Rule's 25 MW threshold typically do not operate for a sufficient amount of time to satisfy this criterion. Many units are in fact prohibited by permit or state law from operating even half that much on an annual basis. EPA should consider removing the 876-hour threshold and allow these small EGUs to opt-in regardless of the annual operating time. This change would increase the number of sources covered by the rule, resulting in an even greater improvement in air quality. Further, such an action would remove the perverse incentive to operate and emit more as a way to qualify as an opt-in unit. Finally, if state regulatory authorities allow these units' participation in the Transport Rule to fulfill state-level HEDD requirements, companies would be able to make more rational capital and operational decisions within a more efficient and integrated regulatory framework. If peaking units are allowed to opt in, states would see air quality benefits from reductions in HEDD emissions as soon as 2012, whereas state regulatory processes are unlikely to show results for several years beyond 2012.  [EPA-HQ-OAR-2009-0491-2702.1, p. 11]
Eco Power Solutions (USA) Corp.
Additionally, to the extent that the voluntary "opt-in" method for the non-EGU sector is to be encouraged, the "opt-out" provisions of the proposed rule need to be simplified. The current proposal creates an unnecessary "lock in" for four years and a risk of a further "lock in" that will likely discourage many in the non-EGU sector from participating on a voluntary "opt in" basis. [EPA-HQ-OAR-2009-0491-2692.1, p. 2]
In light of the foregoing, EPA has at least two options. First, it could simply reconsider its decision not to include non-EGUs. Since EPA did not in the original proposed rule give notice that it intended to regulate non-EGUs, it would likely have to give at least 60 days notice of its potential intention to do so. This would provide non-EGUs with an opportunity to comment on whether, in light of the availability of new more cost-effective technology, non-EGUs should be included in the Air Transport rule. Consideration would also have to be given to establishing the timing and structure for full integration of ICI boilers and potentially other industrial component sources in the context of the new Ozone rule and SO2 rule. [EPA-HQ-OAR-2009-0491-2692.1, p. 7]
A second alternative would be to not only allow non-EGUs to 'opt-in' to one or more of the proposed trading programs (as EPA has already proposed to do) but also to encourage such voluntary "opt-in" actions through liberalized "opt out" rules that would avoid the risk of a "lock in". Since the COMPLY 2000(R) costs for non-EGUs to control NOx and SO2 would be far less than EPA has estimated, non-EGUs might still want to "opt-in" because they will eventually need to reduce SO2 and NOx to conform to the newly adopted SO2 standards and the new proposed more stringent ozone regulations that EPA has said it will finalize in October 2010. And the salable SO2 and NOx credits from voluntary reductions made before final compliance dates would help reduce the potentially high cost to industry of implementing a new more stringent ozone rule. The more non-EGUs that voluntarily "opt-in" the sooner non-EGU emissions will be reduced. [EPA-HQ-OAR-2009-0491-2692.1, p. 8] [See 2692.1, pp. 8-10 for extensive discussion of 'opt-out' rules.]
Exelon
EXELON URGES EPA TO MODIFY THE OPT-IN REQUIREMENTS BYREMOVING THE "HOURS OF OPERATION" REQUIREMENT THAT RENDERS MANY "PEAKER"UNITS INELIGIBLE TO OPT IN TO TRANSPORT RULE ALLOWANCE PROGRAMS.
At certain points on hot summer days, electric demand increases to accommodate air conditioning demand, and a portion of the increase in electric demand is typically achieved with peaking units such as combustion turbines and internal combustion engines. The "peakers" are capable of responding to a dispatch request quickly and can be at full load in less than thirty minutes, which makes them suitable for this purpose. Typically, peakers have high operating costs, and thus run as rarely as possible, and only when no more cost-effective EGUs are available to meet demand. Certain states in the Northeast Ozone Transport Region are adopting measures to require NOX emission controls on combustion turbines and other electric generating units of less than 25 MW capacity as part of "high electric demand day" ("HEDD") programs.  For example, Pennsylvania is developing a regulatory program that would address fossil fuel combustion turbines and internal combustion engines that are electric generating units and operate less than 1,200 hours during the ozone season. [EPA-HQ-OAR-2009-0491-2666.1, p.42]
Exelon owns and operates twenty-three peaker turbines in the Philadelphia area that would be subject to Pennsylvania's HEDD program. These units typically operate less than 100 hours during the ozone season and indeed are not permitted to operate more than 438 hours at full load on a rolling 12-month basis (a five percent annual capacity factor). Under the Pennsylvania HEDD program, beginning as soon as 2012, these units would be required to retrofit NOX emission controls. The capital cost of those controls, combined with the very low capacity factors of these units, would likely make a retrofit economically infeasible. However, Pennsylvania's proposed HEDD program contemplates that units could opt in to the Transport Rule program in lieu of complying with the HEDD program. [EPA-HQ-OAR-2009-0491-2666.1, p.42]
The Transport Rule allows units below the rule's 25 MW threshold to opt in to the allowance trading programs under the rule. However, the owner of any unit opting in must certify that the unit operated at least 876 hours in the six months prior to the opt in request. Small EGUs of less than 25 MW typically do not operate for a sufficient amount of time to satisfy this criterion. Exelon's units, which are prohibited by permit from operating even half that much on an annual basis, certainly do not. Yet, Exelon's units are typical of peaking units operating all across the Transport Rule region. These units play an important role in electric reliability. [EPA-HQ-OAR-2009-0491-2666.1, p.43]
Exelon proposes that the Transport Rule be modified to allow EGUs of less than 25 MW to opt in to any of the Transport Rule allowance programs, regardless of hours of operation. Exelon does not propose that state emission budgets be expanded to provide additional allowances for sources opting in to the programs. Rather, units opting in will be required to purchase allowances at auction or from other facilities. The inclusion of small peakers would certainly not interfere with the objective of the Transport Rule to reduce impacts in downwind areas. The total amount of emissions from peaking units would likely be too small to influence liquidity or prices in allowance markets. If there were any influence at all, the inclusion of peakers would tend to increase demand, and thus prices, which could ultimately result in a decision by one or more large EGU owners to install additional controls. By allowing peakers to opt in, EPA would potentially increase the number of sources covered by the Transport Rule without increasing the state emission budgets, necessarily resulting in an even greater improvement in air quality. [EPA-HQ-OAR-2009-0491-2666.1, p.43]
HEDD programs are by nature state programs directed primarily to addressing local air quality concerns. Ultimately, it will be up to each state to determine whether it would be appropriate to allow a unit to opt in to a Transport Rule allowance program in lieu of complying with the requirements of the state program. Some states may provide that option, as Pennsylvania seems inclined to do, and some states may not. However, by allowing peaking units to opt in to the Transport Rule program, EPA would provide each state adopting a HEDD program with an additional regulatory option that would allow greater flexibility in meeting the state's air quality goals. [EPA-HQ-OAR-2009-0491-2666.1, p.43]
Fond du Lac Reservation
Opt-In of Non-Covered Sources
The Transport Rule also provides for non-covered sources (e.g., operating boiler, combustion turbine, or other stationary combustion device) to voluntarily enter trade programs with allowance allocations given to them based on their historical emissions. While the expectation of EPA is that these sources might be better able to make lower cost emissions reductions than EGUs within a state, thereby reducing the program's overall costs, this approach offers a more important benefit in advancing the Rule's larger purpose of limiting the 'interstate transport of emissions of nitrogen oxides (NOx) and sulfur dioxide (SO2).' As such, the Agency should be utilizing every opportunity to further this purpose which should include non-covered sources on tribal lands that lie contiguous or near to those states covered by the Rule. These sources, like those located on the lands of states, are not otherwise be obligated to reduce their NOx and/or SO2 emissions unless covered by the Rule. With coverage, however, the EPA could seize a valuable opportunity to further the Rule's purpose, and ultimately help improve the health and welfare of all people and lands in the Eastern U.S. [EPA-HQ-OAR-2009-0491-3707, p.6]
The Band therefore recommends that the EPA allow non-covered sources on tribal lands beyond EGUs to be covered under the Transport Rule but only on a voluntary basis, as is true for similar sources on state lands. [EPA-HQ-OAR-2009-0491-3707, p.6]
Indiana Department of Environmental Management
Indiana generally favors the idea of 'opt-ins' if the opt-in sources can obtain reductions that are as cost-efficient as those for the EGUs. However, these various opt-in source categories are best addressed separately, which is reported to be the intent of the second Transport Rule that U.S. EPA is developing. It would help States if U.S. EPA would provide the States with timelines early in the rule development process so that those choosing to develop their own SIPs can do so in a timely manner. Further, any future Transport Rule should fully consider the needs of states in relation to the anticipated 2010 ozone and 2011 fine particulate (PM2.5) NAAQS' by aligning emissions reductions and attainment dates. [EPA-HQ-OAR-2009-0491-2645.1, p.3]
Maryland Department of Environment (MDE)
Opt-ins
EPA has made corrections to the preamble to the proposed Transport Rule, indicating that they allow units to opt-in to each trading program included in the proposed rule (see 75 Federal Register 55711). Maryland opposes the inclusion of these opt-in provisions as outlined in the proposed Transport Rule. We recall that EPA allowed opt-ins with the NOx SIP call, and these provisions were not successful. With regard to the proposed Transport Rule, we note two specific aspects of the opt-in provisions that we consider completely unworkable. [EPA-HQ-OAR-2009-0491-2639.2, pp.10-11]
First is EPA's presumption that non-EGUs should be allowed to opt-in to any of the trading programs because non-EGUs may be able to make reductions at a lower cost than other covered (EGU) sources (75 FR 45308). This is particularly troubling because earlier in the preamble EPA claims that non-EGUs are not included as covered sources because they exceed EPA's $500 per ton cost threshold and EPA has not had sufficient time to develop the technical information necessary to include them in this proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2639.2, p.11]
Second, EPA proposes that "the allowances created for and allocated to the opt-in units would be in addition to the allowances issued from the state budget and would be usable in compliance by any covered unit (or opt-in unit) just like the allowances allocated from the state budget to covered sources" (75 FR 45308). Maryland opposes inclusion of these opt-in provisions unless the opting-in units are included under existing state caps. [EPA-HQ-OAR-2009-0491-2639.2, p.11]
Maryland holds this position despite EPA's assurance provisions and penalties. Otherwise, the proposed opt-in provisions will result in reduced pressure on EGUs to limit their own emissions, and the provisions provide too much opportunity for states to exceed the emissions budgets established by the Transport Rule and put public health at risk. [EPA-HQ-OAR-2009-0491-2639.2, p.11]
National Tribal Air Association (NTAA)
Opt-In of Non-Covered Sources
The Transport Rule also provides for non-covered sources (e.g., operating boiler, combustion turbine, or other stationary combustion device) to voluntarily enter trade programs with allowance allocations given to them based on their historical emissions. While the expectation of EPA is that these sources might be better able to make lower cost emissions reductions than EGUs within a state, thereby reducing the program's overall costs, this approach offers a more important benefit in advancing the Rule's larger purpose of limiting the 'interstate transport of emissions of nitrogen oxides (NOx) and sulfur dioxide (SO2). As such, the Agency should be utilizing every opportunity to further this purpose which should include non-covered sources on Tribal lands that lie contiguous or near to those states covered by the Rule. These sources, like those located on the lands of states, are not otherwise be obligated to reduce their NOx and/or SO2 emissions unless covered by the Rule. With coverage, however, the EPA could seize a valuable opportunity to further the Rule's purpose, and ultimately help improve the health and welfare of all people and lands in the Eastern U.S. [EPA-HQ-OAR-2009-0491-2778.1, p.6]
The NTAA therefore recommends that the EPA allow non-covered sources on Tribal lands beyond EGUs to be covered under the Transport Rule but only on a voluntary basis as is true for similar sources on state lands. [EPA-HQ-OAR-2009-0491-2778.1, p.6]
Pennsylvania Department of Environmental Protection
EPA has requested comment on the opt-in process proposed in 40 CFR §§ 97.441- 97.444. The opt-in provisions include the requirement that a unit 'has documented heat input (greater than 0 mmBtu) for more than 876 hours during the 6 months immediately preceding submission of the TR opt-in application.' Proposed 40 CFR § 97.441(a)(2)(iv). EPA should reconsider the use of 876 hours of operation six months prior to the control period as an opt-in requirement, as it provides an unnecessary obstacle for units that wish to opt in. There are regulated EGUs under the current CATR rule and EGUs that will be regulated under the Transport Rule that have not and do not meet this requirement. Units should be able to opt into the Transport Rule based upon their actual operations and emission rate identified per control period using a three-year base period, adjusting the baseline allocations each time the regulatory emission standard is modified. This would prevent sources from generating allowances by making reductions that were required anyway. New units should also need to operate below their permitted emission rate to get allowances. The DEP also recommends that once a unit opts into the program, it may not withdraw from the program. [EPA-HQ-OAR-2009-0491-2660.1, p.8]
Opt-in provisions in previous trading programs did not provide an incentive to participate. The large allowance banks of previous trading programs and state budgets that were large enough to provide plenty of allowances to the affected units to comply with regulatory requirements did not provide the right mix to spark interest for opting into those market-based programs. The key element necessary to drive an opt-in program is scarcity. The scarcity imposed by intrastate trading along with tighter emission budgets may make the opt-in provisions in the Transport Rule more inviting than opt-in provisions of previous trading programs, provided EPA removes unnecessary road blocks. [EPA-HQ-OAR-2009-0491-2660.1, p.8]
It is also important to require that units opting into the Transport Rule get allocated opt-in allowances based upon their updated regulatory requirements; those allowances could only be sold if the EGO owners or operators went beyond their regulatory obligations. [EPA-HQ-OAR-2009-0491-2660.1, p.8]
Pennsylvania's Existing Non-EGU Program
In the CAIR SIP approval, EPA approved Pennsylvania's treatment of non-EGUs covered by the NOx Budget Trading Program, in 25 Pa. Code §145.8 (relating to the transition to CAIR NOx Trading Programs). The DEP did not incorporate NOx requirements for non- EGUs in the Commonwealth's CAIR program. Non-EGUs remain subject to the statewide emission budget of the NOx Budget Trading Program; and under 25 Pa. Code Chapter 129, small sources of NO x emissions may surrender NOx allowances as an option for compliance demonstrations. In the final Transport Rule, we recommend that EPA clarify whether Pennsylvania will continue to allow a NOx allowance surrender option for its non-EGU program after adjusting some of its provisions to comport with the new Transport Rule. The DEP recommends that the final Transport Rule provide for the use of Transport Rule NOx allowances as a compliance alternative. [EPA-HQ-OAR-2009-0491-2660.1, pp.8-9]
Portland Cement Association (PCA)
Discussion:
The proposed opt-in provisions would allow a non-covered unit to enter a proposed trading program voluntarily and obtain an allocation of allowances reflecting the unit's emissions before opting in. Once in the program, the unit could make emissions reductions at a lower cost than other units in the program and then sell, to covered sources for use in compliance, allocated allowances that are in excess of the unit's reduced emissions. The allowances created for and allocated to the opt-in unit would be in addition to the allowances issued from the state budget and would be usable in compliance by any covered unit (or opt-in unit) just like the allowances allocated from the state budget to covered sources. Replacing higher cost reductions by covered units by lower cost reductions by opt-in units could reduce the overall cost of controlling emissions. In the event EPA moves forward with stringent requirements as outlined in the proposed Clean Air Interstate Transport Rule - requirements that will result in higher electricity costs - cement manufacturers support the option to voluntarily participate in an emissions trading scheme as a means of offsetting the costs of multiple mandates from EPA. [EPA-HQ-OAR-2009-0491-2789.1, p. 12]
The proposed opt-in provisions would establish the following procedures, which are similar to those set forth in the CAIR FIPs. A unit would be eligible to opt into one of the proposed trading programs if the unit: (1) Is an operating boiler, combustion turbine, or other stationary combustion device; (2) is in a facility that is located in a state subject to that proposed trading program; (3) vents all its emissions through a stack or duct; and (4) would be able to meet the monitoring, reporting, and recordkeeping requirements for covered units under the proposed trading program. The owners and operators, through a designated representative, of a source with a unit seeking to opt in would submit to EPA an opt-in application, which must include an emissions monitoring plan for the unit. If EPA approved the monitoring plan, the unit would operate, monitor, and report emissions in accordance with the monitoring plan and monitoring and reporting requirements under Part 75, for at least one or for up to three full calendar years (or full ozone seasons, in the case of an opt-in unit in the proposed NOX ozone season trading program). [EPA-HQ-OAR-2009-0491-2789.1, p. 3]
As stated previously, the cement industry advocates an inclusive approach to the trading program to maximize the number of facilities that would be eligible to participate. Cement facilities typically emit nitrogen oxides and sulfur dioxide at various levels, and the industry has made great progress to reduce these emissions since the introduction of the Clean Air Act. Some facilities might be able to offer significant reductions of these compounds that could further the goals of the Clean Air Transport Rule. It is in EPA's interest to encourage participation by a broader universe of potential sources. [EPA-HQ-OAR-2009-0491-2789.1, p. 3]
PCA recommends flexibility and inclusive criteria with respect to establishing criteria for manufacturers' opt-in to intra-state trading of emissions credits. EPA should assure that the final rule takes additional steps to encourage participation by manufacturing facilities that utilize industrial furnaces and other sources that have historically measured emissions on an output basis. EPA can accomplish this objective by including 'industrial furnaces' within the regulatory definition of 'covered units,' further clarifying eligibility for cement plants. With respect to measuring emissions on an output basis, for example, this has always been the case for Portland cement plants. Such plants, when they opt in, should be evaluated on an output based basis. This is the traditional method by which sources in that industry calculate their emissions, and it would be very difficult if not impracticable for them to change. Inserting language that clarifies that the program includes those sources that could take advantage of an output-based basis would expand the universe of potential opt-in participants to the benefit of the program and the other participants.  [EPA-HQ-OAR-2009-0491-2789.1, p. 3]
Conclusion:
The Portland Cement Association appreciates the opportunity to comment on EPA's proposed Clean Air Transport Rule. Although cement manufacturers oppose mandates that will increase electricity costs for its members, cement manufacturers prefer to use market-based incentives to achieve environmental goals in the most efficient manner possible. PCA advocates an inclusive approach featured by the flexibility and incentives necessary to encourage participation by a broad spectrum of sources. [EPA-HQ-OAR-2009-0491-2789.1, p. 3]
PPL Corporation
6. Opt-in Requirements
The proposed rule has opt-in provisions for combustion units other than the units that are required to be in the program (EGUs over 25 MW). Units eligible to opt-in include EGUs of 25 MW or less. However, there is a requirement that they operate at least 876 hours in the six months prior to submittal of their opt-in application (i.e., 20 percent of the hours). PPL understands that this is to allow EPA to establish reliable baselines for the units. We question the need for this requirement. [EPA-HQ-OAR-2009-0491-2739.1, p.8]
PPL owns and operates several combustion turbines of less than 25 MW that we may want to opt-in to the program. However, they are peaking units with annual capacity factors well under 10 percent and therefore would not be eligible to opt-in. We believe that existing units such as these have a long history of operation from which baseline conditions can be determined and which is as reliable as or more reliable than operating conditions over the previous six months. [EPA-HQ-OAR-2009-0491-2739.1, p.8]
PPL recommends that operating characteristics over the previous three years be an allowed substitute to establish baseline conditions for opt-in units if they did not operate 20 percent of the hours of the previous six months. [EPA-HQ-OAR-2009-0491-2739.1, p.8]
State of Missouri Department of Natural Resources
As prescribed on page 45308 of the proposed rule the opt-in provisions would allow non-electric generating units the option to enter a Transport Rule trading program as was similarly done in CAIR. The concern with allowing opt-in units is that it could elevate a state above their state-wide NOX and SO2 allocations and increase contributions to downwind nonattainment and maintenance areas which would not fully satisfy the CAA Section 110(a)(2)(D) mandate to eliminate upwind emissions that prevent downwind nonattainment or maintenance areas. [EPA-HQ-OAR-2009-0491-3806, p.4]
Response:
See section VII.B of the preamble.
Organization: Louisiana Chemical Association (LCA)
Comment:
Louisiana Chemical Association (LCA)
Comments on Applicability and The Cogeneration Exemption.
EPA Erroneously Included Projections and Allowances for Units that Meet the Cogeneration Exemption.
As support documentation to the proposed rule and FIP, EPA made available an Allocation Table which provides annual and ozone season NOx allocations for regulated EGUs. Without waiving any of the above and foregoing comments, LCA believes that if EPA persists in adopting a FIP, a number of EGUs belonging to its member companies that EPA purports to cover under the proposed applicability of the rule/FIP are actually exempt under the proposed "cogeneration exemption" not regulated under the proposed rule. LCA requests that EPA delete these units from any Technical Support Documents implying applicability and from the FIP Allocation tables and from any modeling associated with covered EGUs. [EPA-HQ-OAR-2009-0491-3527.1, pp., 43-44; see pp. 44-46 for extensive discussion of this issue.]
Additional Comments on the Cogeneration Exemption.
Date for Commencement of Limitations to Qualify for Cogeneration Exemption.
 EPA has also requested comments on certain aspects of its proposed rule. One of the areas where EPA requested comments concerns whether it would be problematic for sources to obtain detailed information about the disposition of a unit's generation back to November 15, 1990 and whether the efficiency and operating standards should be limited to more recent years rather than November 15, 1990. EPA suggested as an alternative for comment whether the exemption requirements should only be met every year starting the later of a date of a more recent year (e.g., 2000, 2005, or 2009) or the date on which the unit first produces electricity.118 EPA also requests comment on whether the electricity sales limit should be restricted to more recent years by requiring that the limit be met every year starting the later of a date of a more recent year (e.g., 2000, 2005, or 2009) or the start-up of a unit's combustion chamber. [EPA-HQ-OAR-2009-0491-3527.1, p. 46]
LCA believes that it could be problematic to produce detailed information about the disposition of a unit's generation, its efficiency and operating standards, and its electricity sales from as far back as November 15, 1990, which is nearly twenty years ago. The time period for recordkeeping under the Clean Air Act Title V permit program and similar programs is generally only five years. While most sources will have records of this type of information on major EGUs for the last 5 years, they may not have kept detailed information for prior years. Thus, the "start-date" for the exemption criteria should extend no further back than five years prior to the adoption of the final Transport Rule/FIP. [EPA-HQ-OAR-2009-0491-3527.1, p. 46]
Definition/Efficiency Standard for Cogeneration Units.
The "cogeneration unit" definition proposed under the Transport Rule/FIP differs from that under the Clean Air Interstate Rule ("CAIR"). Under CAIR, each unit had to meet individually the efficiency standard. Under the proposed rule, however, if the cogeneration system of which a topping-cycle unit is a part meets the efficiency standard on a system-wide basis, then the unit is also deemed to meet that efficiency standard. EPA requested comments on whether this approach should also be applied to bottoming-cycle units. [EPA-HQ-OAR-2009-0491-3527.1, p. 46]
LCA supports applying the approach of meeting efficiency standards on a system-wide basis to bottom-cycle units for the same reason that EPA has applied this approach to topping-cycle units. Allowing one unit in a cogeneration system to act as a "swing" unit and operate at a lower efficiency will allow the other units in the system to operate at higher efficiencies. Further, there is no basis for EPA to treat these two types of units differently for the purposes of meeting efficiency standards. Topping-cycle units and bottoming-cycle units have the same purpose -- to produce electricity and thermal power. The fundamental difference between these two types of units is the order in which electricity and thermal energy are produced. In topping-cycle units, the energy input to the unit is first used to produce useful power, including electricity, and then some of the reject heat from the electricity production is used to provide useful thermal energy. In bottoming-cycle units, the process is reversed, with the energy input to the unit first being used to produce useful thermal energy and then some of the reject heat from the useful thermal energy process being used for electricity production. As topping-cycle units and bottoming-cycle units have the same purpose and produce the same products, EPA should apply the same efficiency standards requirements to both types of units. [EPA-HQ-OAR-2009-0491-3527.1, p. 47]
EPA requested comment on whether the agency should exclude, from the requirement to meet the operating and efficiency standards, calendar years -- if any -- during which a unit does not operate at all. Under the proposed Transport Rule, the operating and efficiency standards in the "cogeneration unit" definition must be met every year. EPA is concerned because, as the rule is currently written, these annual standards would be applied in calendar years when a unit does not operate at all. LCA agrees with this concern and requests EPA to exclude these requirements in calendar years when the unit does not operate at all. [EPA-HQ-OAR-2009-0491-3527.1, p. 47]
LCA requests that EPA consider an additional option  -  revising the requirements for application of the cogeneration exemption to be exactly the same as the cogeneration exemption under the Acid Rain program, per 40 C.F.R. 72.6(b)(4). LCA does not believe that EPA has articulated a reason to adopt requirements for such exemption that would be different from the requirements under the Acid Rain rule. The Acid Rain cogeneration exemption is a statutory exemption that clearly indicates Congressional concern with regulating units that meet these criteria. Sections 402(17)(A) and 405(g)(6)(A)of the Clean Air Act include provisions discussing in detail the conditions under which a cogeneration unit is exempt from the Acid Rain Program. See, e.g., 42 U.S.C. 7651d(g)(6)(A) (stating that Clean Air Act title IV does not apply to qualifying cogeneration facility that meets certain conditions as of November 15, 1990, the date of enactment of title IV). LCA requests that EPA revise the cogeneration exemption under the proposed Transport Rule/FIP to be equivalent to the Acid Rain program exemption. [EPA-HQ-OAR-2009-0491-3527.1, p. 47]
Request for Emergency Exemption.
As a separate comment, LCA believes that EPA should provide an exemption to sources that exceed the annual electricity sales limit due solely to the occurrence of an emergency. This should apply to any EGU, not just to cogeneration units. For instance, EGUs as well as local transmissions systems located in Louisiana can be adversely affected by hurricanes or floods. There have been occasions in the past where EGUs adversely impacted by hurricanes have been unable to provide electricity to their customers. In those cases, sources meeting the cogeneration exemption may be called upon to temporarily increase their electricity production to provide for critical infrastructure power needs until the primary utility systems can return to electrical power production. By selling electricity in these times of crisis, exempt sources may exceed the proposed Transport Rule/FIP electricity sales thresholds and therefore trigger applicability under the Transport Rule/FIP. LCA believes that these sources should not be penalized by triggering regulatory applicability solely due to provision of power during such emergency periods. LCA thus requests that EPA provide an exception to the Transport Rule stating that sources will not lose their exemption for temporary activities that occur in response to emergencies. EPA could impose appropriate criteria to limit the scope of this exception; however, such an emergency exception is needed under the proposed rule. [EPA-HQ-OAR-2009-0491-3527.1, p. 48]
Response:
See  section VII.B of the preamble.  EPA rejects the commenter's position that QF cogeneration facilities with long-term power purchase contracts in place since 1990 should be exempt from the Transport Rule trading programs.  While these facilities have an exemption under the Acid Rain Program established in 1990 under CAA title IV, EPA maintains that the commenter failed to provide a basis for establishing such an exemption under the final Transport Rule.  The Acid Rain Program began in 1995, and the exemption for these facilities provided a transition for them from non-regulation, or limited regulation, of their emissions to more stringent regulation of their emissions under CAA title IV.  In effect, the commenter claimed that CAA title IV created a permanent exemption for these facilities (until certain changes occur in their power purchase contracts) covering not only the Acid Rain Program, but also in all trading programs covering the electricity generation sector.  However, neither the statutory language nor the legislative history of CAA title IV supports the commenter's claim that Congress intended that the IPP and QF exemptions apply in trading programs established after the Acid Rain Program that had not even been proposed, much less implemented, when CAA title IV was passed.  Further, the circumstances under which the Acid Rain Program exemption was established have changed.  The Acid Rain Program was one of the first programs to require significant emission reductions throughout the electricity generation sector.  An exemption for IPPs and QFs with such long-term power contracts was not adopted in subsequent trading programs covering electricity generation, i.e., the NOx Budget Trading Program and the CAIR trading programs.  Also, the current market for electricity is much broader and less geographically segmented than it was in 1990, before the introduction of significant utility rate deregulation and electric industry restructuring.  Under these circumstances, EPA maintains that an exemption providing a transition from non- or limited emissions regulation to more stringent regulation is not appropriate since this category of units is already subject to emissions regulation.  In addition, an exemption for QF cogeneration facilities with long-term power purchase agreements could result in shifting of generation and emissions from units regulated under the Transport Rule to these units (the potential for which is enhanced by the existence of a broader, less segmented electricity market).  Such a shift could threaten achievement of elimination of states' significant contribution and interference with maintenance, which is the goal of the Transport Rule.  Although the exemption of any portion of the electricity generation sector creates the potential for generation shifting, the greater the number and scope of the exemptions, the greater the likelihood and likely magnitude of the potential generation shifting.  After the balancing the commenter's claimed rationale for the requested exemption and the potential adverse effect of such an exemption, EPA rejects the commenter's position.
EPA also rejects the commenter's position that the operating and efficiency requirements in the cogeneration unit exemption should be removed.  In the final rule EPA exempts those cogeneration units that meet certain requirements.  First, the units must meet certain operating and efficiency requirements, and the commenter failed to show that these requirements are unreasonable.  EPA believes that it is reasonable to limit the exemption to units that demonstrate their efficiency.  Second, the units must meet the electricity sales limitation. Those units that sell less than the electricity sales limitation are treated as industrial, rather than electric generation, units and are exempt because the final rule is aimed at the electric generation sector.
The commenter suggested that EPA create an exemption to the electricity sale limitation under the cogeneration unit exemption.  EPA rejects the commenter's approach.  Whatever the motivation behind a unit's  electricity sales, EPA believes that the level of the electricity sales limitation provides a reasonable, objective way of differentiating between cogeneration units treated as industrial units and those treated as electricity generation units.   The commenter's approach would introduce a major subjective element into the cogeneration unit exemption by requiring EPA to define what constitutes an "emergency" and to determine whether particular circumstances constituted such an "emergency".  The commenter did not suggest, much less support, any specific "emergency" definition.  In addition, EPA notes that the Clean Air Act already includes provisions for addressing national or regional energy emergencies, as described in the CAA.  See 42 U.S.C. 7410(f).
Organization: Manitowoc Public Utilities (MPU)
Comment:
Manitowoc Public Utilities (MPU)
 MPU requests EPA to confirm that the Proposed Transport Rule intends to follow the CAIR and Acid Rain Program (ARP) applicability standard that includes all units that are connected to a steam generator of more than 25 MW.  [EPA-HQ-OAR-2009-0491-2860.1, p.2]
Applicable Units
MPU recommends that EPA clarify the applicability requirements for a small EGU. It is our understanding that the Proposed Transport Rule intends to follow the CAIR and Acid Rain Program (ARP) applicability standard that includes all units that are connected to a steam generator of more than 25 MW. We are confused because our steam generating units of less than 25 MW were not included in the allocation analysis. We have three steam generating units that have an MCR of less than 25 MW, however they are connected to steam turbine generator of more than 25 MW. The units are therefore currently regulated by CAIR and the ARP. [EPA-HQ-OAR-2009-0491-2860.1,p.4]
Response:
See section VII.B of the preamble.
Organization: Massachusetts Department of Environmental Protection
Comment:
Massachusetts Department of Environmental Protection
EPA seeks comment on whether it should include non-EGU NOx and S02 emissions in the Transport Rule programs. It also seeks comment on lowering the greater-than-25 megawatt (MWe) applicability threshold for EGUs during the ozone season. MassDEP believes additional cost-effective and timely reductions of NO x and S02 are available from both non-EGUs and smaller EGUs.4 It urges EPA to consider inclusion of these sources in the proposed Transport Rule. If the final Transport Rule does not include these sources, EPA should require reductions from non-EGUs and smaller EGUs under the next Transport Rule in the shortest possible time frame. [EPA-HQ-OAR-2009-0491-2787.2]
MassDEP also supports lowering the 25MWe applicability threshold for EGUs to include EGUs in the 15-25 MWe range. Although the overall emissions from these units are small in proportion to the larger EGUs, these units may be called upon on high-energy-demand days (HEDD), when ozone concentrations are often high. Because EPA has not proposed to otherwise address the concerns of ozone nonattainment areas related to HEDD, inclusion of these smaller units is one way to address HEDD emissions. [EPA-HQ-OAR-2009-0491-2787.2]
MassDEP believes that EPA is overlooking the significant S02 emissions reductions available from ICI boilers through fuel- switching, which can be cost-effective within the 2012-2014 timeframe. Several states within the Ozone Transport Region are pursuing sulfur in fuel reduction strategies.9 Recent amendments to the New Jersey Sulfur in Fuels regulation will further reduce the sulfur content of fuel oils beginning in 2014 through 2016. 10 The delay in implementation until 2016 in the revised New Jersey Sulfur in Fuels regulation is attributable in part to the reluctance of refiners to add desulfurization capacity absent strong market or regulatory signals. 11 Expanding the Transport Rule to require significant S02 emissions reductions available from ICI boilers through fuel- switching would send the necessary market and regulatory signals. For Massachusetts, S02 reductions in the 2012-2014 timeframe could also serve to meet requirements related to Regional Haze.   [EPA-HQ-OAR-2009-0491-2787.2 p.5]
Response:
See sections VI.A, VII.B, IX.A and B, and X of the preamble. The final rule gives states the option of expanding the applicability provisions of the Transport Rule NOx ozone season trading program to include units serving generators with a nameplate capacity of 15 MWe or greater producing electricity for sale.  This is consistent with the approach taken in the NOx Budget Trading Program, where some state elected to include units serving generators with a nameplate capacity of 15 MWe or greater producing electricity for sale.
Organization: Michigan Department of Natural Resources and Environment
Comment:
Michigan Department of Natural Resources and Environment
The proposal has electric generating units (EGUs) greater than 25 megawatt (MW) output subject to the TR. However, when reviewing Michigan subject source data, units with outputs less than 25 MW were included. The EPA apparently used these additional units to determine the electricity reliability in a given area. [EPA-HQ-OAR-2009-0491-2774.1 p.5]
The DNRE has concerns about this methodology and requests clarification as to why the smaller sources were included. First, the use of non-subject units to affect reliability is miniscule at best and is in direct opposition to the methods used by the Federal Electric Regulation Commission to indicate which unit will be 'turned on' to meet electricity demands. Coal-fired units have been the determining reliability factor in Michigan for several years. When additional demand occurs, the independent natural gas-fired units are utilized to meet additional electrical needs. The amount of electricity supplied by the smaller MW units is not sufficient to maintain reliability. The DNRE believes that these units should not be addressed in the TR, nor should they be used to determine electricity needs in Michigan. [EPA-HQ-OAR-2009-0491-2774.1 p.5]
The proposed TR opt-in provisions allow a non-covered unit to enter the proposed trading program voluntarily and obtain an allocation of allowances reflecting the unit's emissions prior to opting in. Sources choosing to participate in the opt-in program are required to remain in the program for a minimum of four years (or compliance periods). The allowances created for and allocated to the opt-in unit would be in addition to the allowances issued from the state budget. [EPA-HQ-OAR-2009-0491-2774.1 p.6]
The DNRE supports allowing non-affected sources to opt-in to the TR program and the opt-in provisions allowing a source to opt-in to a subset of the trading category (groups 1 or 2 for sulfur, NOx annual and NOx ozone season). [EPA-HQ-OAR-2009-0491-2774.1 p.6]
The proposed TR rule allows non-EGUs to opt-in under the FIP and includes the option of bringing in non-EGUs under the SIP as long as the FIP emissions budgets are not changed. However, it appears that states cannot require the sources to participate. The proposed TR envisions states addressing the non-EGUs as a NOx-SIP fix-up package, as once the CAIR program has been removed from the state rules an 'anti-backsliding' issue may exist for the NOx Budget Program.  [EPA-HQ-OAR-2009-0491-2774.1 p.6]
The DNRE supports the opt-in provisions because it allows the non-EGUs from CAIR to participate in the ozone season NOx program under the TR, which widens the non-EGUs trading capabilities from a small intrastate pool to the entire TR region.  [EPA-HQ-OAR-2009-0491-2774.1 p.6]
The DNRE has concerns about the length of time required to revise the state's rules, which will be necessary for the non-EGUs currently subject to the NOx SIP Budget Program. Our concerns include how the non-EGUs will address their ozone season NOx emissions, in particular when the FIP goes into effect prior to any SIP provisions by the state. To address the changes from the proposed TR, Michigan will need to revise the NOx rules that allowed the addition of the non-EGUs into the CAIR program and rescind the current state CAIR rules.  [EPA-HQ-OAR-2009-0491-2774.1 p.6]

The proposed TR exempts cogeneration units that supply, in any given calendar year, no more than one-third of its potential electric capacity, or 219,000 MWh, whichever is greater, to any utility power distribution system for sale.
The DNRE supports the concept of exempting cogeneration units meeting the above criteria. However, we have concerns that sources may, due to yearly determinations, be 'in and out' of the proposed TR requirements. The DNRE believes that source exemption determination should not be made on a yearly basis. Once a source has become subject to the program, they should remain subject and not be allowed to use the exemption for at least four future years and contrarily if a source is exempted, it should remain so for the next four year cycle, similar to the opt-in provisions within the TR. [EPA-HQ-OAR-2009-0491-2774.1 p.7]

Solid Waste Incineration Exemption
The proposed TR exempts solid waste incineration units using 80 percent or more non-fossil fuel, consistent with an EPA interpretation made during implementation of CAIR. The EPA interpretation limits the term 'fossil fuel' to natural gas, petroleum, coal, or any form of fuel derived from the previous types for the expressed purpose of creating useful heat. Following the previous interpretation, solid waste incineration units with 80 percent or more non-fossil fuel used would be exempt from TR. This eliminates tires and other products from becoming defined as fossil fuel as they were not manufactured to create a fuel source. [EPA-HQ-OAR-2009-0491-2774.1 p.7]
The DNRE agrees with this exemption; however, we request c1arifiQation regarding the limitations on the term fossil fuel fired. Several sources in Michigan incinerate solid waste, i.e., tires, trees, and other wood refuse to create electricity or steam. Are these units exempt if they use 80 percent or more of non-fossil fuel although they sell electricity to the grid from a unit with capacities greater than 25 MW? [EPA-HQ-OAR-2009-0491-2774.1 p.7]
The DNRE believes that sources which primarily use non-fossil fuels but generate electricity and are greater than 25 MW should be subject to the proposed TR programs. [EPA-HQ-OAR-2009-0491-2774.1 p.7]
The proposed TR includes a 'cogeneration' definition different than used under CAIR. The major significant change is the ability for topping-cycle units to meet the 'efficiency requirements' on a system-wide basis. Topping-cycle units produce steam to generate electricity and leftover steam is utilized in the facility for heat or hot water. Bottoming-cycle units typically produce steam for heat or hot water and any remaining steam is used to generate electricity. The EPA also requested comments regarding the use of the same system-wide efficiency for the bottom-cycling units. [EPA-HQ-OAR-2009-0491-2774.1 p.7]
The DNRE agrees that a system-wide basis for meeting efficiency is appropriate for topping cycle units. However, we have reservations about using the system-wide basis for the bottoming-cycle units. Most of the bottoming-cycle units consist of various process heaters and boilers. The DNRE believes these units could have a difficult time demonstrating efficiency on a system-wide basis due to the differences in sizes and capabilities of these process units. [EPA-HQ-OAR-2009-0491-2774.1 p.7]
Response:
See sections VI.B, IX.A and B, and X of the preamble.  EPA notes that, even assuming that the commenter is correct that the electricity provided by small EGUs is alone insufficient to maintain reliability, the commenter failed to show why such units should be ignored in considering issues concerning electric reliability.  EPA also notes that, under the cogeneration unit and solid waste incineration unit exemptions in the final rule, a unit cannot "go in and out" of the exemption.  Once an exempt unit no longer meets the requirements for the exemption for a given year, that unit, by the terms of the exemption provisions, cannot meet the exemption requirements in any subsequent year and continues to be a covered unit.  See sections 97.404(b), 97.504(b), 97.604(b), and 97.704(b).
Organization: Mostardi Platt Environmental
Comment:
Mostardi Platt Environmental
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.91-92.]
I have not read the Rule yet. I'm going to be, but going back to the original CAIR rule, in the applicability section there was something I think the Agency did not intend, to bring a lot of new biomass projects coming on line into the CAIR rule, but it unintentionally did, because of the fossil fuel provision that said if you ever use any fossil fuel...
A lot of these biomass projects do use natural gas for startup, and startup alone for load balancing, but it's a very small percentage of the actual heat input into the biomass projects.
If that same language is contained in the new Transport Rule, it might be beneficial to encourage biomass to take a look at that language and maybe come up with some de minimis fossil fuel use, if used for startup and load balancing only, and that will certainly help encourage the biomass industry without I think sacrificing air quality.
Response:
See section VII.B of the preamble.  The final rule covers fossil-fuel-fired units serving a generator with a nameplate capacity greater than 25 MWe and defines "fossil-fuel-fired" as combusting any amount of fossil fuel in 2005 or later.  EPA rejects, for several reasons, the commenter's approach of excluding units with so-called "de minimis" amounts of fossil fuel use.  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 and did not specify a level of fossil fuel use (as a percentage of total fuel use) as the cut-off for what would constitute "de minimis" fossil fuel use in these programs.  Moreover, if the applicability of the Transport Rule trading programs for all units were to depend on exceeding a specific level of fossil fuel use, a significant number of units' regulatory status could change during the course of the year.  Specifically, a unit's fossil fuel use can vary, depending on, among other things,  changes in unit operation and fuels.  As noted by the commenter, some units use fossil fuel for startup and combustion stabilization, and so fossil fuel use can vary depending on the frequency of startups and shutdowns and on factors (such as the moisture content and other characteristics of the other fuels being combusted) affecting the need for combustion stabilization.  Units that were excluded from the Transport Rule trading programs because of their "de minimis" fossil fuel use would not report fuel use to EPA, and so determination of whether a significant number of units were subject to the trading programs, and assurance of compliance, would be problematic.  Although units that burned no fossil fuel starting in 2005 are excluded from the Transport Rule and could potentially have their regulatory status change by beginning to burn fossil fuel, EPA believes that this is less likely to occur than in the case of units have been burning some fossil fuel.  EPA therefore maintains that the approach in the final rule of covering units that burned any fossil fuel starting in 2005 and that serve a generator with a nameplate capacity greater than 25 MWe producing electricity for sale and excluding units that burned no fossil fuel starting in 2005 is reasonable.
Organization: National Environmental Development Association
Comment:
National Environmental Development Association
NEDA/CAP Agrees That Many Cogeneration Owners Will Find It Difficult To Substantiate Electricity Generation And Meet Other Requirements of the Proposal in Order to Qualify for the Proposed CATR Exemption.
On pages 45306-7 of the Federal Register Notice, EPA discusses the rule's proposed exemption for "cogeneration units." In order to qualify for such exemption, however, the owner or operator of the proposed unit would be required to have records demonstrating that since November 15, 1990, that unit met the efficiency and operating standards set forth for such units in the proposal (e.g., the owner/operator of the unit would need to supply evidence that in every calendar year since 1990, that that no more than one-third of the unit's potential electric output capacity or 219,000MWh, whichever is greater, was supplied to any utility power distribution system for sale, and that the useful power plus one-half of useful thermal energy output of the unit must equal no less than a certain percentage of the total energy input). Id. EPA requests comment on whether it may be problematic to obtain sufficiently detailed information about the disposition of a unit's generation . . . back to November 15, 1990 and whether the electricity sales limit should be restricted to more recent years by requiring that the limit be met every year starting the later of a date (e.g., 2000, 2005, or 2009) or the start-up of the unit's combustion chamber. [EPA-HQ-OAR-2009-0491-2744.1 p.2]
NEDA/CAP's members appreciate EPA's sensitivity to this issue. The record-retention requirements of the Clean Air Act are also limited to five (5) years. Moreover, most, if not all of NEDA/CAP's members, have corporate document retention policies which limit records retained by a facility to no more than five (5) years. Thus, unless facilities retained records in violation of these corporate policies, they would be unable to meet the requirements to demonstrate they are exempt from the CATR rule. Yet to fail to exempt these units from CATR, we believe, would be counter to the nation's energy policies promoting construction and operation of cogeneration facilities. Regulation under the proposed CATR rule also may impose significant costs and potential feasibility issues on certain units. For these reasons, we recommend that EPA provide in the final rule that the exemption be based on a demonstration of information including but not limited to information on electricity sales every year starting the later of the date five years before the effective date of the final rule or the start-up of the unit's combustion chamber, whichever is later. [EPA-HQ-OAR-2009-0491-2744.1 p.2]
Response:
See section VII.B of the preamble.
Organization: Nelson Industrial Steam Company (NISCO)
Comment:
Nelson Industrial Steam Company (NISCO)
NISCO believes that it should not be subject to the CATR because its two units are efficient cogeneration units and because NISCO sells such a de minimis amount of electricity neither of the two units should be considered to be an Electric Generating Unit ('EGU') within the meaning of the proposed CATR. These two units meet the definition of cogeneration units under the Public Utilities Regulatory Policies Act ('PURPA'). In addition, they are exempt from the Clean Air Act's Acid Rain rules under the 'cogeneration exemption' of 40 C.F.R. 72.6(b)(4) because neither of the units provides more than 1/3 of its potential electrical output capacity ('PEOC') or more than 219,000 MWh to a utility power distribution system for sale. The NISCO facility is not regulated as a public utility by the Louisiana Public Service Commission. [EPA-HQ-OAR-2009-0491-2813.1, p.1]
Neither of the NISCO units has ever sold more than 1% of its electrical output to a utility power distribution system, except during the aftermath of Hurricanes Katrina and Rita in 2005 when the annual sale of electrical output from the two units combined was only 2.58% of the total annual output. In five of the last seventeen years, NISCO has not sold any electricity to the grid. In six or more of those years, sales were below 0.2% of total generation. Only in 2005 did sales to the grid exceed 1% and because 2005 was the year of Hurricanes Katrina and Rita, the special force majeure circumstances of those storms account for these extra sales. [EPA-HQ-OAR-2009-0491-2813.1, p.2]
III. EPA Should Revise the Requirements for the Cogeneration Exemption and/or Should Create an Exemption for De Minimis Sales of Electricity from Non-Cogeneration EGUs
As noted above, it is believed that very little, if any, NOx and SO2 reductions should be required of Louisiana EGUs in order to satisfy the 'good neighbor' provisions of the CAA by preventing interstate transport of Louisiana emissions that would adversely impact the annual PM2.5 design values or 1997 8-hour design values in areas of Texas. NISCO believes that even use of the IPM 4.10 Base Case values, will result in findings that Louisiana does not impact these NAAQS, even without the downward emission inventory revisions and other adjustments requested in these comments. However, in the unlikely event that EPA still finds that there is a requirement for reduction of Louisiana sources, there is no mandate that such reduction come from EGUs or even substantially from EGUs. Where, as indicated above, there are enforceable consent decree reductions already scheduled from other non-EGUs in an amount likely to reduce any significant contribution or interference with maintenance, it would be arbitrary for EPA to require more than is needed under a FIP (or SIP). After these reductions, very little, if any further reductions should be required in Louisiana from EGUs. For this reason, there is no need for EPA to go beyond the Acid Rain definitions of cogeneration unit to include an efficiency requirement.. EPA did not make any finding that NISCO needed to retrofit to meet the CATR. NISCO requests that if EPA moves forward with a Louisiana FIP, EPA should create a Louisiana-only exclusion for cogeneration units meeting the Acid Rain cogeneration exemption but not meeting the generic CATR proposed efficiency standard. [EPA-HQ-OAR-2009-0491-2813.1, pp.11-12]
EPA has not articulated a basis under CATR for requiring an efficiency requirement in addition to a unit meeting the other 'Acid Rain' requirements for a unit to qualify as a cogeneration unit, and thus be eligible for the proposed 'cogeneration exemption.' NISCO believes that in order for EPA to enact such a requirement that goes beyond the Acid Rain program, it must have a basis that is linked to the purpose of the good neighbor clause of the CAA. The purpose of the proposed CATR/FIP is to reduce interstate transport of PM2.5 and ozone precursors, not necessarily to penalize certain types of cogeneration units that EPA believes to be less efficient than other types of cogeneration units. The NISCO units received PSD permits and their S02 and NOx emissions meet Best Available Control Technology levels. They provide a valuable function by using readily available pet-coke supplies as fuel to power local manufacturing facilities. Thus, NISCO believes EPA should revise the cogeneration unit definition under the final CATR (nationwide) to be equivalent to the cogeneration unit definition under the Acid Rain program. But, as noted, if EPA does not make that a nationwide provision, it certainly should enact such a provision in any FIP for Louisiana, or should specify that if a state enacts a SIP to implement CATR, such state may provide for such a definition. [EPA-HQ-OAR-2009-0491-2813.1, p.12]
In the further alternative, NISCO believes that EPA should create an exemption from classification as a CATR applicable unit for facilities that sell de minimis amounts of electricity to the grid. As noted above, neither of the NISCO units has ever sold more than 1% of its electrical output to a utility power distribution system, except during the aftermath of Hurricanes Katrina and Rita. NISCO believes that EPA has the inherent authority to interpret the phrase 'producing electricity for sale' within the definition of EGU so as to exclude: a) incidental production of electricity for sale when it amounts to less than 1% of the unit's annual output and b) production of a small amount of electricity for sale only for limited periods during or in response to natural disasters. See Alabama Power Co. v. Castle, 636 F.2d 323 (D.C. Cir. 1979); United States v. American Trucking Ass'ns, 310 U.S. 534, 543, 60 S.Ct. 1059, 1063, 84 L.Ed. 1345 (1939); District of Columbia v. Orleans, 132 U.S.App.D.C. 139, 141, 406 F.2d 957, 959 (1968)); Ober v. Whitman, 243 F.3d 1190 (9th Cir. 2001); and Environmental Defense Fund, Inc. v. EPA, 82 F.3d 451 (D.C. Cir. 1996). [EPA-HQ-OAR-2009-0491-2813.1, p.12]
NISCO requests that EPA amend the proposed CATR to provide for a definition of 'cogeneration facility' equivalent to that found under the Acid Rain program, without the additional efficiency requirement proposed by EPA. Further, or in the alternative, NISCO requests that EPA amend the proposed CATR to provide for an exemption for EGUs that sell less than 1% of the PEOC to the grid. If such revisions are not made, and without waiving any legal rights to contest the necessity for the proposed FIP or any part thereof, NISCO also requests that to the extent EPA relies upon the IPM for any purpose, it should correct all of the data errors noted herein. [EPA-HQ-OAR-2009-0491-2813.1, p.13]
Response:
See section VII.B of the preamble.  The commenter claimed, without providing any support, that its cogeneration units are "efficient" and argued that cogeneration facilities should be exempt from the Transport Rule trading programs without meeting any efficiency requirements simply because the Acid Rain Program included cogeneration unit exemptions without efficiency requirements.  EPA rejects the commenter's approach. In the final rule EPA exempts those cogeneration units that meet certain requirements.  First, the units must meet certain operating and efficiency requirements, and the commenter failed to show that these requirements are unreasonable.  EPA believes that it is reasonable to limit the cogeneration unit exemption to units that demonstrate their efficiency.  In effect, the commenter claims that CAA title IV created a permanent exemption for cogeneration units covering not only the Acid Rain Program, but also in all trading programs covering the electric generation sector including those that were not even proposed, much less implemented, when CAA title IV was passed.  Neither the statutory language nor the legislative history of CAA title IV supports such a claim.  EPA notes that the NOx Budget Trading Program did not include any exemption for cogeneration units.  Further, the circumstances under which the Acid Rain Program exemption was established have changed.  The current market for electricity is much broader and less geographically segmented than it was in 1990, before the introduction of significant utility rate deregulation and electric industry restructuring.  The broadening of the cogeneration unit exemption beyond that in the final Transport Rule could result in shifting of generation and emissions from units regulated under the Transport Rule to some of the additional cogeneration units that would be exempt because of the high level of integration of the electric generation, transmission, and distribution system (which has increased with the broader, less segmented electricity market) and thereby threaten achievement of elimination of states' significant contribution and interference with maintenance, which is the goal of the Transport Rule.  Although the exemption of any portion of the electricity generation sector creates the potential for generation shifting, the greater the number and scope of the exemptions, the greater the likelihood and likely magnitude of the potential generation shifting.  After the balancing the commenter's claimed rationale for the requested exemption and the potential adverse effect of such an exemption, EPA rejects the commenter's position
The second requirement for qualifying for the cogeneration unit exemption under the final Transport Rule is that the cogeneration unit must meet the electricity sales limitation.  Those units that sell less than the electricity sales limitation (i.e., the greater of 219,000 MWh, or one-third of the unit's potential electrical output capacity, per year) are treated as industrial, rather than electricity generation, units and are exempt because the final rule is aimed at the electricity generation sector.  The commenter claimed that the sales limitation should be changed.  The commenter's alternative to the sales limitation is unclear in that, at one point in the comments, the commenter suggested a limit of 1% of a unit's annual output, at another point the commenter suggested a limit of 1% of a unit's potential electrical output capacity (PEOC), and at another point the commenter seemed to limit the alternative limit to sales for only "limited periods during or in response to natural disasters".  EPA rejects commenter's approach.  First, it is unclear why the commenter suggested limits of 1% of annual output or 1% of PEOC when the final rule already sets a higher limit of the greater of 219,000 MWh, or one-third of PEOC, per year.  If the commenter intended to suggest that one of its three alternative electricity sales limitations be used and no operating and efficiency requirements be imposed, EPA rejects this for the reasons discussed above.  Further, the purpose of the electricity sales limitation is to distinguish between cogeneration units that are considered industrial and those that are considered part of the electricity generation sector, which is the sector whose emissions the final Transport Rule is aimed at reducing.  EPA notes that the electricity sales limitation has been used in the Acid Rain Program and in the CAIR trading programs to make this distinction.  Whatever the motivation behind a unit's  (e.g., the NISCO units) electricity sales, EPA believes that the level of the electricity sales limitation provides a reasonable, objective way of differentiating between cogeneration units treated as industrial units and those treated as electricity generation units.   The commenter's approach would introduce a subjective element into the cogeneration unit exemption by requiring EPA to determine what constitutes "a small amount" of sales for a "limited period" during a "natural disaster".  In addition, EPA notes that the Clean Air Act already includes provisions for addressing national or regional energy emergencies, as described in the CAA.  See 42 U.S.C. 7410(f).
Organization: North Carolina Department of Environment and Natural Resources
Comment:
North Carolina Department of Environment and Natural Resources
We concur with proposal to exempt cogeneration units on the basis of electrical generation and unit efficiency (although such units may choose to use the opt-in provisions discussed later). It appears beneficial! to encourage such energy efficient designs through the exemption process. Furthermore, future projects and an increase in co-generation projects would be reviewed under other regulatory programs I such as PSD and MACT to address emissions control technology and strategies to minimize downwind impacts concerns of FTR, if only in an indirect way, Complete and accurate records for older units may provide data challenges, as noted in the preamble, back to the signing of the 1990 Clean Air Act Amendments and the nature of unit operation may favor using the first complete set of operation data for a unit, selecting a later data may provide a more level regulatory basis for review of a cogeneration unit.  However operational records for periods after 2000 and certainly after 2003 should be retrievable, for most units. Use of this time period should provide a satisfactory basis for reviewing the exemption status. finally calendar years without any operation should not count against a unit's annual efficiency calculation. EPA could consider a minimum hour threshold to determine if the unit operated in the calendar year (e.g., 1000hr). [EPA-HQ-OAR-2009-0491-2767.1 p.7]
Response:
See section VII.B of the preamble.
Organization: Northshore Mining Company
Comment:
Northshore Mining Company
Northshore appreciates that allocations for NOx and S02 have been provided to SBP as noted in the Technical Support Document to the Proposed Rule at Docket ID No. EPA-HQ-:-OAR-2009- 0491-0057-1. However, Northshore remains concerned that privately owned and operated cogeneration power plants, which are not public utilities, are subject to the Transport Rule. EPA justifies the economic impact of the Transport Rule from the perspective that the cost of compliance will be passed on to electric utility rate payers. In drafting the proposed rule EPA states:

'Ultimately, we believe the electric power industry will pass along most of the costs of the rule to consumers, so that the costs of the rule will largely fall upon the consumers of electricity. ' [EPA-HQ-OAR-2009-0491-2822.1 p.1]

75 Fed. Reg. 45352 (August 2,2010). It is clear that EPA intended the Transport Rule to apply specifically to electric utilities, which have the ability to 'pass along most of the costs of the rule to consumers' and not to privately owned, industrial facilities. As EPA has explained since at least 1979, the Agency draws a distinction between 'electric utility steam generating units and industrial boilers because there are significant differences between the economic structure of utilities and the industrial sector.' See 44 Fed. Reg. 33580,33589 (June 11, 1979). Whereas a utility may pass on the costs of a rule such as the Transport Rule to its retail customers, an industrial facility, such as Northshore, which sells a wholesale product, concentrated iron ore pellets, to a limited customer base may not. To the contrary, the price for iron ore pellets is established in the world market place and Northshore must sell its pellets at that price. If Northshore were to add to the price of its pellets the cost of compliance with the Transport Rule, its customers would refuse to buy the pellets because they could buy pellets at the market price from other suppliers. [EPA-HQ-OAR-2009-0491-2822.1 p.1]

During 2010 EPA promulgated far more stringent National Ambient Ail' Quality Standards (NAAQS) for N02 and S02. During the next few years each state must designate areas of the state that are either in attainment or nonattainment with the NAAQS. As a result of the more stringent standards now in effect, there is high likelihood that more nonattainment areas will be designated in more states. This in turn will require reductions in emissions from sources in upwind states pursuant to the Transport Rule that are contributing to the nonattainment designations of areas in downwind states. [EPA-HQ-OAR-2009-0491-2822.1 p.2]

Assuming sufficient allocations would not be available for purchase and additional emission controls would have to be installed, the cost of the additional emission controls at public utilities will be passed on to the electricity rate payers. However, the cost of such increased emission controls at Northshore' s power plant, which could be several tens of millions of dollars, would have to be borne by Northshore. Installation of the emission control equipment at this level of cost would be cost prohibitive for Northshore and could lead to the shutdown of the iron ore operations. This would result in the loss of approximately 640 direct jobs and an estimated 1150 additional indirect jobs involved with supporting Northshore's operations. Mining is the single largest contributor to the region's economy. During 2009 Northshore's purchases of local services and supplies were more than $110 million, and it paid over $11 million in state and local taxes for a total economic impact of$121 million. These figures demonstrate that if Northshore were to shut down because it could not afford to comply with the Transport Rule, the economic impact to Northeastern Minnesota would be tremendous at a time when the country is just beginning to emerge from the longest recorded economic recession since the Great Depression. [EPA-HQ-OAR-2009-0491-2822.1 p.2]
For these reasons, Northshore requests that EPA clarify in the final Transport Rule that the rule is applicable to only public utilities that can pass the cost of compliance on to rate payers. Specifically, Northshore requests that EPA clearly state that the Transport Rule applies to the electric power sector (Electric Utilities and Independent Power Producers), which refers to that sector of the power generating industry that comprises electricity-only and combined-heat-and power (CHP) plants whose primary business is to sell electricity, or electricity and heat, to the public. In so doing, EPA will promulgate the Transport Rule in accordance with its premise as stated in the economic impact assessment of the rule that most of the cost of compliance with the rule will, in fact, be passed on to a wide array of consumers of electricity. With this approach, no industrial facility or single electricity rate payer will suffer a significant economic hardship from the Transport Rule while ail' quality improves in downwind states. [EPA-HQ-OAR-2009-0491-2822.1 p.2]
Response:
EPA rejects the "clarification" requested by the commenter concerning the applicability of the Transport Rule.  The applicability criteria determining what units are subject to the Transport Rule trading programs, and the reasons for adopting these criteria, are set forth in section VII.B of the preamble.  These criteria cover units, like the commenter's units, that produce electricity for sale.  EPA maintains that it is reasonable to treat units (serving generators of the requisite size) producing electricity for sale as part of the electricity generation sector, which is subject to the Transport Rule trading programs.  While EPA believes that units subject to the Transport Rule trading programs will ultimately be able to pass through most costs of compliance, the ability to pass through is not one of the requirements for a unit to be subject to the trading programs.  See sections VIII.D and XII.H of the preamble.
The commenter claimed that its cogeneration units should not be treated "more stringently than their less-efficient industrial boiler counterparts" and argued that "historic" cogeneration units should be exempt from the Transport Rule trading programs without meeting any efficiency requirements.  EPA rejects the commenter's approach.  In the final rule EPA exempts those cogeneration units that meet certain requirements.  In particular, the units must meet certain operating and efficiency requirements, and the commenter failed to show that these requirements are unreasonable.  EPA believes that it is reasonable to limit the cogeneration unit exemption to units that demonstrate their efficiency.  See section VII.B of the preamble.
In addition, EPA rejects the commenter's claims that compliance with the final Transport Rule would be "cost prohibitive", and "could lead to the shutdown of [its] iron ore operations" as vague, unsupported, and speculative.  The commenter seemed to assume, without support, that sufficient allowances would not be available for purchase for compliance.  EPA's experience with prior trading programs, such as the Acid Rain Program, the NOx Budget Trading Program, and the CAIR trading programs, is that the trading programs result in robust allowance markets in which allowances are available for purchase.
Organization: NRG Energy
Comment:
NRG Energy
NRG recommends that EPA lower the CATR Applicability Threshold for Ozone Season CATR proposes an applicability threshold of 25 MWe for electric generating units (EGUs). EPA is requesting comment on the need to lower this EGU threshold for the Ozone Season to 15 MWe for sources within the Northeast region. [EPA-HQ-OAR-2009-0491-2749.1, p. 9]
The reasoning for the lower threshold is based on perceived issues related to NOx emission on High Electric Demand Days (HEDDs). On March 2, 2007 representatives from the Ozone Transport Commission (OTC) states signed a Memorandum of Understanding (MOU) regarding reductions of NOx emissions during HEDDs. Only five of the twelve OTC member states are listed in the MOU as having a tons per day reduction goal from historic NOx tons emitted by HEDD units. The MOU also lists seven actions that states may implement to meet their HEDD goals. [EPA-HQ-OAR-2009-0491-2749.1, p. 9]
In addition to addressing some HEDD issues, the inclusion of the 15  -  25 MWe units would address states' concerns on potentially having to regulate sources that are currently regulated by CAIR but would not be included in the TR. This could result in a state implementing its own Ozone Season cap-and-trade program and/or implementing regulations to lower the allowable NOx rate for these sources. [EPA-HQ-OAR-2009-0491-2749.1, p. 9]
A cap-and-trade program with a larger geographic area results in more emission reductions, a common platform for compliance, and a more liquid allowance market than a state-only program. Because source owners are currently included in the CAIR Ozone Season program, the transition to TR would not impose the financial burden and learning curve associated with individual state-only actions. Including the 15  -  25 MWe sources in TR's Ozone Season program will eliminate the time and financial burden that a state only program would place on state agencies and all affected sources. It is also doubtful that any state program would be developed and implemented as soon as the TR. [EPA-HQ-OAR-2009-0491-2749.1, pp. 9-10]
NRG supports the inclusion of the Northeast region 15  -  25 MWe sources in the TR Ozone Season programs provided the following design elements are included in the program: 1. The Northeast region is defined as the Ozone Transport Region, 2. Affected sources will be defined in the same manner as in CAIR, 3. State only programs are not required unless the individual states demonstrate that additional reductions from the 15  -  25 MWe sources are required to meet attainments, and 4. Affected states' Ozone Season budgets are adjusted to include allocations for affected sources based on the affected sources' Ozone Season 2008 emissions. [EPA-HQ-OAR-2009-0491-2749.1, p. 10]
Response:
See sections VII.B, IX.A and B, and X of the preamble.
Organization: Occidental Chemical Corporation (OCC)
Comment:
Occidental Chemical Corporation (OCC)
Each of OCC's cogeneration units meets the definition in the proposed rule for "cogeneration units". However, the test for determining whether these units meet the "cogeneration exemption" is extremely complex and we are continuing to review our data and apply EPA's criteria to determine whether the units qualify for the proposed exemption. In either case, as a preliminary yet fundamental matter, we identified numerous factual errors in the databases EPA used for modeling emissions transport and unit level allocations, as discussed in greater detail below. Consequently, one can only infer that the modeled output is also incorrect. [EPA-HQ-OAR-2009-0491-2754.1, p. 3]
Furthermore, we reject on policy grounds the idea that any cogeneration facility, let alone a cogeneration facility meeting the definition of "qualified facility" under the federal Public Utility Regulatory Policies Act ("QF"), should be subject to the Transport Rule, regardless of unit size, efficiency or the amount of power sold on the grid. [EPA-HQ-OAR-2009-0491-2754.1, pp. 3-4]
Consistent with PURPA, EPA Should Exempt All Qualifying Facility Cogeneration Units We have not been able to discern from the docket materials whether EPA has consciously adopted a unique allocation policy for cogeneration units. However, whether conscious or not, it is not rational for EPA to financially penalize modern, clean, efficient gas-fired cogeneration facilities under the CATR in order to "reduce" NOx emissions. Under the final Transport Rule, EPA should exempt all cogeneration units, regardless of size, efficiency and amount of power supplied to the grid.  [EPA-HQ-OAR-2009-0491-2754.1, p. 5] [See 2754.1, pp. 5-13 for extensive discussion of the following topics:  Occidental's Taft Generating Facility, a Qualifying Facility Under PURPA, Is Entitled to an Exemption from the Proposed Clean Air Transport Rule; EPA's Decision to Provide an Exemption to Some, but not All, Cogenerators Is Arbitrary, Capricious and an Abuse of Discretion; EPA's Failure to Provide a Rationale for Regulating Cogeneration Units as EGUs Rather Than Industrial Sources Is Arbitrary and Capricious and an Abuse of Discretion; EPA Must Avoid Issuing a Final Rule That Undermines FERC's Mandatory Obligation under PURPA to "Encourage Cogeneration"; EPA's Proposed Regulations are Arbitrary and Capricious and an Abuse of Discretion Because They Fail to Give Any Deference to the Federal Policy of Encouraging Cogeneration under PURPA; The Economic Benefits Afforded to QFs under FERC's PURPA Regulations Must Be Protected; QFs, Unlike Other Generators, Cannot Raise Their Rates for QF Sales To Cover the Compliance Costs Associated with the Proposed Transport Rule; Imposition of the Proposed Transport Rule on OCC's Taft QF Facility Is Arbitrary and Capricious and an Abuse of Discretion]
Review Period for Cogeneration Exemption We believe that consistent with data maintenance activities with other state and federal statutes and programs, that a review of the period of 5 years previous to the effective date should be sufficient to determine whether a facility qualifies for the cogeneration exemption. EPA has not modeled air quality and emissions since 1990, thus we do not see any value is such a lengthy review period to qualify for the exemption. Furthermore, it is not reasonable to expect that facilities will have the necessary data dating back beyond five years. [EPA-HQ-OAR-2009-0491-2754.1, p. 29]
Response:
See section VII.B of the preamble.  EPA rejects the commenter's position that all cogeneration facilities (including all QF cogeneration facilities) should be exempt from the Transport Rule trading programs.  The commenter claims that such units are efficient and should be exempt from the Transport Rule trading programs.  In the final rule EPA exempts those cogeneration units that meet certain requirements.  First, the units must meet certain operating and efficiency requirements.  The commenter failed to show that these requirements are unreasonable, and in fact noted that the efficiency requirements as applied to its facilities are the same as under PURPA.  EPA believes that it is reasonable to limit the cogeneration unit exemption to units that demonstrate their efficiency.  Second, the units must meet the electricity sales limitation.  Those units that sell less than the electricity sales limitation are treated as industrial, rather than electricity generation, units and are exempt because the final rule is aimed at the electricity generation sector. The commenter claimed that electricity generation by its facilities is limited by the thermal load that the facilities need to provide for the host industrial facilities because of the operating and efficiency standards under PURPA, which has applied to the commenter's facilities, are the same as the operating and efficiency requirements for the cogeneration unit exemption under the Transport Rule.  However, these operating and efficiency requirements provide some flexibility in that, for example, the minimum percentage that thermal load must comprise of total energy output under these requirements is 5% and, in order for the lowest efficiency requirement to apply, is 15%.  The commenter failed to explain why these requirements do not provide some flexibility to the commenter in deciding what level of electricity to generate for sale.  In addition, the relationship between thermal load and electricity generation does not change the fact that the commenter's cogeneration facilities produce for sale on the grid a significant amount of electricity, and EPA maintains that the level of the electricity sales limitation provides a reasonable way of distinguishing between facilities that are substantially in the electricity generation business and thus should be treated as part of the electricity generation sector regulated under the Transport Rule and facilities that are not substantially in the electricity generation business and so are not covered by the Transport Rule.  Under the commenter's approach, there would be no electricity sales limitation and so all cogeneration units would be treated as outside of the electricity generation sector no matter how much electricity they sold on the grid and how important a role the units played in providing electricity supply to meet electricity demand on the grid.  Contrary to the commenter's claims, merely because a cogeneration facility is meeting a legitimate industrial or commercial need does not mean that the facility is not also reasonably treated as part of the electricity generation sector.  Moreover, if all cogeneration units were excluded from the Transport Rule trading programs, utilization for electric generation, and the resulting emissions, could shift to those units from covered units because of the high level of integration of the electric generation, transmission, and distribution system (which has increased with the significant restructuring and deregulation of electric utilities) and thereby threaten achievement of elimination of states' significant contribution and interference with maintenance, which is the goal of the Transport Rule.  Contrary to the commenter's claim that such shifting could not occur because many of the cogeneration facilities are not owned by utilities, such shifting could occur regardless in states where other electricity providers or end-users can purchase electricity from non-utility generators, who can make such sales whether or not the utilities want the sales to occur.  Although the exemption of any portion of the electricity generation sector creates the potential for generation shifting, the greater the number and scope of the exemptions, the greater the likelihood and likely magnitude of the potential generation shifting.  After the balancing the commenter's claimed rationale for the requested exemption and the potential adverse effect of such an exemption, EPA rejects the commenter's position
EPA maintains that the treatment of QF cogeneration units in the final Transport Rule is not inconsistent with PURPA.  PURPA addresses the prices of electricity that QFs produce and sell, not their emission requirements.  It is not inconsistent with PURPA to regulate the emissions of cogeneration units (including QF cogeneration units).  In fact, the Acid Rain Program established by Congress in CAA title IV did not contain a blanket exemption for all cogeneration units or all QF cogeneration units.  Only QF cogeneration units that either had power purchase agreements that were in place on November 15, 1990 and continued to be in place or that met the electricity sales limitation were exempt.  In addition. although the cogeneration unit exemption in both the final Transport Rule and in CAIR included the efficiency requirements and the electricity sale limitation and so cogeneration units not qualifying for the exemption have been subject to the emission reduction requirements of the CAIR trading programs, the commenter did not show that the regulation of the emissions of cogeneration units not qualifying for the exemption CAIR has had any significant, adverse financial consequences for the units under CAIR or will have any significant, adverse financial consequences for the units under the Transport Rule trading programs.  The mere assertion that these units cannot charge more than "avoided cost" does not demonstrate that compliance with the Transport Rule would have a significant, adverse effect.  The commenter's claim that its facilities might need to reduce their production of thermal output and electricity is speculative and unsupported.  Moreover, the commenter's suggestion that its facilities might need to reduce their electricity production and sales in order to meet the requirements of the cogeneration unit exemption is factually incorrect: because under the cogeneration unit exemption the electricity sales limitation must be met every year starting in 2005, a reduction in electricity production and sales by the commenter's facilities in a future year will not qualify the facilities for the cogeneration unit exemption.  EPA notes that many of the commenter's concerns stem from the allocations to the commenter's units in the proposed Transport Rule.  The final Transport Rule adopts a different method of allowance allocation and provides non-exempt cogeneration units reasonable access to allowances.  See section VII.D of the preamble.
Organization: Oglethorpe Power
Comment:
Oglethorpe Power
XI. Biomass
The proposal would apply the Transport Rule FIPs to 'large' EGUs, defined as any stationary, fossil fuel-fired boiler or stationary, fossil fuel-fired combustion turbine serving at any time, since the later of November 15, 1990 or the start-up of the unit's combustion device, a generator with nameplate capacity> 25 MWe producing electricity for sale. 'Fossil fuel' is defined as including natural gas, petroleum, coal or any form of fuel derived from natural gas, petroleum or coal, regardless of the purpose for which such material is derived. While there are certain exemptions written in to the proposed rule for cogeneration units or solid waste incinerators, biomass-fired units that might use small quantities of fossil fuels (e.g., for start-up purposes) do not appear to be exempt from coverage in the rule. EPA should consider including such an exemption in the rule, similar perhaps to that found for solid waste incineration units that stay below set percentages of fossil fuel usage. [EPA-HQ-OAR-2009-0491-2732.1, p.15]
Response:
See section VII.B of the preamble.  The final rule covers fossil-fuel-fired units serving a generator with a nameplate capacity greater than 25 MWe and defines "fossil-fuel-fired" as combusting any amount of fossil fuel in 2005 or later.  EPA rejects, for several reasons, the commenter's approach of excluding all biomass units whose fossil fuel use is below some unspecified percentage of total fuel use.  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 different approach in the Transport Rule trading programs covering the same industry and did not specify, much less support, a level of fossil fuel use (as a percentage of total fuel use) as the cut-off for determining which biomass units would be exempt from these programs.  Moreover, if the applicability of the Transport Rule trading programs to a significant number of units were to depend on exceeding a specific level of fossil fuel use, the units' regulatory status could change during the course of the year.  Specifically, a unit's fossil fuel use can vary, depending on, among other things, fluctuations in the fuel prices (e.g., natural gas prices) and changes in unit operation.  Some units use fossil fuel for startup and combustion stabilization, and so fossil fuel use can vary depending on the frequency of startups and shutdowns and on factors (such as the moisture content and other characteristics of the other fuels being combusted) affecting the need for combustion stabilization.  Units that were excluded from the Transport Rule trading programs because fossil fuel use was below the commenter's unspecified percentage of total fuel use would not report fuel use to EPA, and so determination of whether a significant number of units were subject to the trading programs, and assurance of compliance, would be problematic.
Organization: Ozone Transport Commission (OTC)
Comment:
Ozone Transport Commission (OTC)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.117-118.]
A third problem with the proposed rule is its failure to include emission reductions from all NOX sources that contribute to transport, particularly from large industrial, commercial and institutional (ICI) boilers. However, we urge EPA to examine the technical evaluation the OTC developed jointly with the Lake Michigan Air Directors Consortium (LADCO) for ICI boilers and include NOX and SO2 reductions from this sector in the final rulemaking for this proposed rule if possible. If not, we urge EPA to address emissions from ICI boilers in the second Transport Rule, as well as emissions from cement kilns, on-road vehicles, marine engines and locomotives.
EPA data shows that emissions from power plants, along with emissions from these other source categories, represent about 75% of the NOX emissions that remain to be regulated. These source categories are most effectively regulated by national rules promulgated by EPA.
Response:
See sections VI.A, VII.B, IX.A and B, and X of the preamble.
Organization: PowerSouth Energy Cooperative
Comment:
PowerSouth Energy Cooperative
No emission allowance allocations should be made to non-operating units.  PowerSouth opposes provisions in the Proposal to continue allocating allowances for 6 years to units that are shut down.  EPA need not incent power plant closures.  Such a provision further clouds and complicates the cap and trade mechanism, and precludes availability of allowances to units that need them.  [EPA-HQ-OAR-2009-0491-2693.1, p.6]
Response:
See section VII.D.1 of the preamble.
Organization: PSEG Services Corporation
Comment:
PSEG Services Corporation
Additional areas for EPA's consideration on the proposed Transport Rule.
Small peaking units below the proposed Transport Rule's 25 megawatt threshold typically do not operate for a sufficient amount of time to satisfy the criterion that an opt-in unit demonstrate operation at least 876 hours in six months. EPA should consider removing the 876 hour threshold and allow small units to opt-in regardless of the operating time. This change would increase the number of sources covered by the rule without increasing the state budgets, resulting in an even greater improvement in air quality. Further, such as action would remove the perverse incentive to exceed the threshold as a way to qualify as an opt-in unit [EPA-HQ-OAR-2009-0491-2627.1, p.11]
Response:
See section VII.B of the preamble.
Organization: Recycled Energy Development
Comment:
Recycled Energy Development
Second, define (and qualify) recycled energy, sometimes known as the bottoming-cycle of CHP. By qualifying CHP only according to an efficiency measure based on energy input, EPA's proposed rules reject recycled energy projects that have no fuel inputs because they capture waste heat and pressure drops. A bottoming-cycle project, such as at the silicon manufacturer mentioned above, burns no incremental fuel and emits no additional pollution. Legislative tax proposals specifically except recycled energy from CHP's efficiency requirements because of the mathematical impossibility of dividing by zero, which is the fuel input of a bottoming-cycle CHP project. EPA should adopt similar exemptions. [EPA-HQ-OAR-2009-0491-2601.1, p.2]
Third, remove the sales restriction associated with CHP. Whether the purchaser of the CHP power is the grid or an industrial facility makes no difference to pollution output. EPA's proposal stipulation that CHP facilities can sell no more than a third of its output to the grid is arbitrary. The provision seems to confuse commercial considerations with technical ones. The decision to sell to the grid or to displace a local facility's power purchases should be made solely on economic grounds. Particularly in the industrial sector, CHP developers are inclined to sell power to the grid since wholesale prices typically exceed retail rates. Declaring that only one-third of CHP power can be sold, therefore, reduces the economic proposition of CHP in many industrial settings, thereby slowing investments in efficiency. Rather than dictate the point of sales, CHP's operative test should be efficiency (noting, as mentioned above, that an exception is needed for bottoming-cycle CHP or recycled energy). RED, therefore, recommends EPA strike the CHP sales restriction. [EPA-HQ-OAR-2009-0491-2601.1, p.2]
Response:
The commenter's description of "recycled energy projects" is too vague, and lacks sufficient information, to determine what would be the regulatory status of such projects under the proposed Transport Rule and to provide a basis for adopting different provisions in the final Transport Rule.  For example, it is unclear from the commenter's description what types of equipment are associated with these projects and whether such projects depend on the use of a boiler or combustion turbine, which are covered by the Transport Rule trading programs and, of course, have heat input.  EPA notes that the definition of "combustion turbine" includes "any associated duct burner, heat recovery steam generator, and steam turbine".  See sections 97.402, 97.502, 97.602, and 97.702 of the Transport Rule trading program regulations (definition of "combustion turbine").  It is also unclear exactly what revisions of the proposed Transport Rule are sought by the commenter.  For example, the commenter failed to identify or describe the "[l[egislative tax proposals" that the commenter suggests should be used to adopt "similar exemptions" in the Transport Rule.
EPA rejects the commenter's suggestion that the electricity sales limitation in the cogeneration unit exemption be removed.  The purpose of the electricity sales limitation is to distinguish between cogeneration units that are considered industrial and those that are considered part of the electricity generation sector, which is the sector whose emissions the final Transport Rule is aimed at reducing.  EPA notes that the electricity sales limitation has been used in the Acid Rain Program and in the CAIR trading programs to make this distinction.  The commenter failed to provide any support for the claim that the using the electricity sales limitation as a requirement for the cogeneration unit exemption "significantly" slows "investments in efficiency and reducing the potential for emissions reductions".  EPA rejects this claim as speculative and unsupported.  EPA also notes that the inclusion of these units in the Transport Rule trading programs provides strong economic incentives for increasing efficiency and reducing emissions at these units because the units' owners and operators must hold allowances covering the units' emissions and can sell any allowances that are not needed for covering these emissions.
Organization: RRI Energy, Inc.
Comment:
RRI Energy, Inc.
The CATR must not prohibit opt-in of EGUs with nameplate capacity less than or equal to 25 MWe as a means to satisfy any state agency-issued High Electric Demand Day (HEDD) / Demand Response (DR) requirements.
The proposed CATR includes provisions for non-CATR affected units (e.g., boilers, combustion turbines with a nameplate capacity less than or equal to 25 MWe or other stationary combustion sources) located in a state subject to a CATR emissions trading program to voluntarily opt-in to the CATR and obtain an allocation of allowances reflecting the unit's historic emissions. RRI supports this provision provided CATR does not prevent state efforts to utilize the program as part of their HEDD / DR plans. RRI has previously communicated with the Pennsylvania Department of Environmental (PA DEP) and EPA Clean Air Markets Division3 on the importance and benefits of including this provision within the proposed CATR. In summary, RRI has communicated that a local electrical system operator (PJM) is considering significant changes that will require customers to curtail operations (or turn on distributed generation) more frequently and for longer duration. This is essentially a new electric generation business that is being fostered by the system operator for the purpose of lowering wholesale electricity prices, but to the dis-benefit of the existing and likely new and more stringent ozone and PM2.5 standards. While curtailing operations during a HEDD period is a beneficial option, an unwelcome outcome is the proliferation of distributed generation. These emissions, regardless of their allowable emissions rates, are growing outside the EGU emissions budget and are priced more favorably due to a lack of permits, emissions limits and emissions allowance surrender requirements. This situation is also exacerbated by a recent proposal by PJM to allow DR, including distributed generation, to set market prices. While reducing prices to customers, this means that EGUs will be less able to recover the costs of controls, particularly for the peaking generation component, because their units will be competing against a demand response option that includes generating sources, many of which effectively have no environmental costs. Although several states are considering or proposing direct control emission limitations for these types of non-CATR EGUs, RRI believes that the opt-in provision outlined above provides for a flexible and more cost-effective option to address the air quality issues associated with non- CATR affected EGUs. Importantly, although the IPM includes all known EGUs regardless of nameplate generating capacity, EPA has admitted4 that IPM performs poorly with respect to utilization of small peaking oil-fired EGUs (IPM predicts that these unit will not operate when historic data have demonstrated otherwise). Consequently, the provision to allow EGU operators to include these units as CATR opt-in units would result in improved air quality and provide a cost-effective means for operators to account for their emissions. [EPA-HQ-OAR-2009-0491-2717.1 p.4]
Lastly, to further encourage non-CATR affected units to opt-in to CATR, the proposed rule must eliminate the requirement that the applicable unit have documented heat input (greater than 0 mmBtu) for more than 876 hours during the six months immediately preceding submission of the opt-in application. RRI believes that this requirement is unnecessary because (i) this provision is not required for CATR-affected units and (ii) allowances for opt-in units are allocated in proportion to the unit's baseline emissions (i.e., allowances are allocated to units that need such allowances). [EPA-HQ-OAR-2009-0491-2717.1 p.4]
Response:
See sections VII.B, IXA. and B, and X of the preamble.  For the reasons set forth in the preamble, the final rule does not provide for units to opt into the Transport Rule trading programs, but allows states' SIPs to expand the applicability of the Transport Rule NOx Ozone Season trading program to make all small EGUs serving generators of a requisite size subject to that program.  Allowing states to expand the applicability of that trading program better addresses the concern raised by the commenter, who claimed that large EGUs subject to the Transport Rule trading programs would be competing against small EGUs that lack emission reduction requirements and costs.  Opt-in provisions would only apply to small EGUs that voluntarily decided to enter the Transport Rule trading programs and not to all small EGUs.  EPA also notes that the commenter did not claim, much less demonstrate, that. even if small EGUs are not brought into the Transport Rule trading programs through SIPs, there would be significant adverse impacts on air quality or on the owners and operators of large EGUs subject to the trading programs.
Organization: Shell Chemicals
Comment:
Shell Chemicals
Date for Commencement of Limitations to Qualify for Cogeneration Exemption
EPA has also requested comments on certain aspects of its proposed rule. One of these areas concerns whether it would be problematic for sources to obtain detailed information about the disposition of a unit's generation back to November 15, 1990 and whether the efficiency and operating standards should be limited to more recent years rather than November 15, 1990. EPA suggested as an alternative for comment whether the exemption requirements should only be met every year starting the later of a date of a more recent year (e.g., 2000, 2005, or 2009) or the date on which the unit first produces electricity.' EPA also requests comment on whether the electricity sales limit should be restricted to more recent years by requiring that the limit be met every year starting the later of a date of a more recent year (e.g., 2000, 2005, or 2009) or the start-up of a unit's combustion chamber. [EPA-HQ-OAR-2009-0491-2614, pp.4-5]
Shell believes that it could be problematic to produce detailed information about the disposition of a unit's generation, its efficiency and operating standards, and its electricity sales from as far back as November 15, 1990, which is nearly twenty years ago. The time period for record keeping under the Clean Air Act Title V permit program and similar programs is generally only five years. While most sources will have records of this type of information on major EGUs for the last 5 years, they may not have kept detailed information for prior years. Thus, the 'start-date' for the exemption criteria should extend no further back than five years prior to the adoption of the final Transport Rule/FIP. [EPA-HQ-OAR-2009-0491-2614, p.5]
Definition/Efficiency Standard for Cogeneration Units
The 'cogeneration unit' definition proposed under the Transport Rule/FIP differs from that under the Clean Air Interstate Rule ('CAIR'). Under CAIR, each unit had to individually meet the efficiency standard. Under the proposed rule, however, if the cogeneration system of which a topping-cycle unit is a part meets the efficiency standard on a system-wide basis, then the unit is also deemed to meet that efficiency standard. EPA requested comments on whether this approach should also be applied to bottoming-cycle units. [EPA-HQ-OAR-2009-0491-2614, p.5]
Shell supports applying the approach of meeting efficiency standards on a system-wide basis to bottom-cycle units for the same reason that EPA has applied this approach to topping-cycle units. Allowing one unit in a cogeneration system to act as a 'swing' unit and operate at a lower efficiency will allow the other units in the system to operate at higher efficiencies. Further, there is no basis for EPA to treat these two types of units differently for the purposes of meeting efficiency standards. Topping-cycle units and bottoming-cycle units have the same purpose- to produce electricity and thermal power. The fundamental difference between these two types of units is the order in which electricity and thermal energy are produced. In topping-cycle units, the energy input to the unit is first used to produce useful power, including electricity, and then some of the reject heat from the electricity production is used to provide useful thermal energy. In bottoming-cycle units, the process is reversed, with the energy input to the unit first being used to produce useful thermal energy and then some of the reject heat from the useful thermal energy process being used for electricity production. As topping-cycle units and bottoming-cycle units have the same purpose and produce the same products, EPA should apply the same efficiency standards requirements to both types of units. [EPA-HQ-OAR-2009-0491-2614, p.5]
EPA requested comment on whether the agency should exclude, from the requirement to meet the operating and efficiency standards, calendar years- if any-during which a unit does not operate at all. Under the proposed Transport Rule, the operating and efficiency standards in the 'cogeneration unit' definition must be met every year. EPA is concerned because, as the rule is currently written, these annual standards would be applied in calendar years when a unit does not operate at all. Shell agrees with this concern and requests EPA to exclude these requirements in calendar years when the unit does not operate at all. [EPA-HQ-OAR-2009-0491-2614, p.5]
Request for Emergency Exemption
As a separate comment, Shell believes that EPA should provide an exemption to sources that exceed the annual electricity sales limit due solely to the occurrence of an emergency. For instance, EGUs as well as local transmissions systems located in Louisiana can be adversely affected by hurricanes or floods. There have been occasions in the past where EGUs adversely impacted by hurricanes have been unable to provide electricity to their customers. In those cases, sources meeting the cogeneration exemption may be called upon to temporarily increase their electricity production to provide for critical infrastructure power needs until the primary utility systems can return to electrical power production. By selling electricity in these times of crisis, exempt sources may exceed the proposed Transport Rule/FIP electricity sales thresholds and therefore trigger applicability under the Transport Rule/FIP. Shell believes that these sources should not be penalized by triggering regulatory applicability solely due to provision of power during such emergency periods. Shell thus requests that EPA provide an exception to the Transport Rule stating that sources will not lose their exemption for temporary activities that occur in response to emergencies. EPA could impose appropriate criteria to limit the scope of this exception; however, such an emergency exception is needed under the proposed rule. [EPA-HQ-OAR-2009-0491-2614, p.6]
Response:
See section VII.B of the preamble.  With regard to the electricity sales limitation, the commenter argued that EPA should establish an emergency exemption from the sales limitation.  EPA rejects the commenter's approach.  Whatever the motivation behind a unit's electricity sales, EPA believes that the level of the electricity sales limitation provides a reasonable, objective way of differentiating between cogeneration units treated as industrial units and those treated as electricity generation units.   The commenter's approach would introduce a major subjective element into the cogeneration unit exemption by requiring EPA to define what constitutes an "emergency" and to determine whether particular circumstances constituted such an "emergency".  The commenter did not suggest, much less support, any specific "emergency" definition.  In addition, EPA notes that the Clean Air Act already includes provisions for addressing national or regional energy emergencies, as described in the CAA.  See 42 U.S.C. 7410(f).
Organization: Sierra Club, New Jersey Chapter
Comment:
Sierra Club, New Jersey Chapter
It is also quite appropriate that the proposed rules (as noted in Section 'II General Information' of the subject document will apply to all Electric Generating Utilities (electric, natural gas, and other systems) in these states. [EPA-HQ-OAR-2009-0491-3649, p.1]
Response:
See sections VI.A, VII.B, IX.A and B, and X of the preamble.
Organization: South Carolina Department of Health and Environmental Control
Comment:
South Carolina Department of Health and Environmental Control
The EPA articulates the applicability of the proposed Transport Rule to biomass-fired EGUs only as they pertain to the cogeneration exemption.53 This leaves some questions that DHEC has encountered in making applicability determinations under the CAIR unanswered. The EPA should clarify Transport Rule applicability for a biomass-fired EGU that is not a cogeneration unit and is allowed to burn fossil fuel only at start-up. Simply relying on the definitions of "fossil-fuel-fired" and "commence operation" is unnecessarily opaque.  [EPA-HQ-OAR-2009-0491-2677.1 p.21]
Response:
EPA maintains that the definition in the final rule clearly states that a unit that combusts any amount of fossil fuel (whether for start-up, combustion stabilization, or general operation) during 2005 or later is fossil-fuel-fired.  Obviously, a unit may also combust non-fossil fuel in addition to the fossil fuel and still be "fossil-fuel-fired".   See sections 97.402, 987.502.,97.602, and 97.702 of the Transport Rule trading program regulations (definition of "fossil-fuel-fired").   The commenter did not suggest that fuel use at start-up should be excluded from the determination of whether a unit is fossil-fuel-fired, much less any basis for such an approach.  Under the final rule, any fossil-fuel-fired boiler or combustion turbine serving a generator with a nameplate capacity greater than 25 MWe providing electricity for sale is a covered unit, unless the unit qualifies for the cogeneration unit or solid waste incineration unit exemption.  The final rule does not use, and does not include a definition of, the term "commence operation".
Organization: Southern Company
Comment:
Southern Company
XV. EPA Should Encourage - Not Discourage - Fossil to Biomass Conversions
Southern Company encourages EPA to reconsider its definition of covered unit and allow for a limited exclusion for biomass facilities. As proposed, the Transport Rule covers any unit greater than 25 MW that bums (or has burned) any amount of fossil fuel since 1990. Under this structure, biomass-fired power plants that bum no fossil fuel are excluded, unless they have burned fossil fuel at some point since 1990. Thus, a facility that converts from fossil fuel to biomass is treated differently than a new biomass facility that has never burned fossil fuel. The former must hold allowances. The latter has no such requirement. There is no rational basis for such a distinction. To the contrary, EPA should encourage conversions from fossil fuels to renewable fuels. Furthermore, the Transport Rule concerns current and future air quality. That a given facility once burned fossil-fuel is wholly irrelevant to current and future air quality. Put simply, for purposes of this rule, there is no difference between a greenfield biomass facility and a new greenfield biomass facility, and EPA has no basis for including one and excluding the other. [EPA-HQ-OAR-2009-0491-2864.1, p. 52]
In addition, in order to promote the development of renewable biomass energy, Southern Company encourages EPA to exclude all biomass facilities that bum less than 10% fossil-fuel. Many biomass facilities use small amounts of fossil fuel to minimize emissions during startup and shutdown. Burning fuel oil or natural gas during these periods helps provide combustion stability and control during startup and shutdown, which can help operators optimize the fire to limit or prevent high emission events. As the fire becomes more stable through the startup process, biomass is introduced until combustion is optimal. EPA should encourage, not discourage, the use of minimal amounts of fossil fuels to reduce emissions. This proposed 10% fossil-fuel exclusion is consistent with New Source Performance Standard methods for categorizing multi-fuel units that bum one primary fuel with a very limited amount of another fuel. EPA should adopt a similar approach in this rule. [EPA-HQ-OAR-2009-0491-2864.1, p. 52]
XVI. Southern Company Supports Several of EPA's Decisions in the Proposed Transport Rule
As discussed throughout these comments, Southern Company has many concerns with the Proposed Transport Rule. However, we support several of EPA's decisions in the proposed rule including EPA's decision to limit the applicability for the Transport Rule to units greater than 25 megawatts. [EPA-HQ-OAR-2009-0491-2864.1, p. 52]
D. EPA's Decision to Limit the Applicability to Units Greater Than 25 MW Southern Company fully supports EPA's proposal to exclude small EGUs of less than 25 MW. Most units this size are used only rarely, for example, as emergency or backup units or during extreme peaks in demand. Accordingly, they are dispatched for short periods of time, primarily for electric reliability reasons. A cap and trade program, which determines compliance over an annual or seasonal basis, is ill-suited for addressing any emission concerns associated with such units. If these smaller units were included in the rule, they would become subject to costly monitoring requirements in addition to the S02 and NOx compliance obligations. Given the de minimis emissions involved, these costs far exceed any potential benefits and thus would not be cost-effective. EPA should retain its consistent practice of excluding these small units. In the unlikely event that EPA breaks from its historical practice, it should only do so after determining on an individual unit (or state-by-state) level that smaller units are linked to actual air quality concerns to an extent that warrants their inclusion in the program and that there are cost-effective means available to address those impacts.  [EPA-HQ-OAR-2009-0491-2864.1, p. 53]
Response: