The timeframes assumed in the Transport rule for installation of pollution control equipment is unrealistic. The Transport rule is expected to be issued as final in June 2011, with SO2 compliance by January 1, 2014. It is not reasonable to engineer, permit, procure, and construct a scrubber beginning in June 2011 and have it operational by 1/1/2014, a period of less than thirty months. Based on experience obtained from other Utilities, it would take approximately 48 months to install an FGD. In addition, adding an FGD to a plant involves more than the FGD itself. The disposition of the gypsum that is generated requires construction of a landfill. Permitting a landfill in Illinois takes 3-5 years. Also wastewater treatment and water discharge permitting have to be addressed for an FGD, which can take 3-5 years. [EPA-HQ-OAR-2009-0491-2628.1, p.2]
Empire District Electric Company (Empire District)
Empire District recommends that 2016 or later should be considered as the initial compliance date to allow for the efficient planning, budgeting, permitting, financing and construction of the required pollution controls. [EPA-HQ-OAR-2009-0491-2659.1, p.2]
Empire District began a study of our Asbury facility in early 2010 to determine the needed Air Quality Control Systems (ACQS) to equip the facility for the future.  We have expedited this study as quickly as feasible and practicable. Initial draft results indicate that installation of AQCS that includes a scrubber will be difficult to accomplish before sometime in 2015.  Meeting the 1/1/2014 date is impossible.  The actual projected timeline from the planning process to the construction completion process is approximately 60 months, not the 27 months stated in the CATR. [EPA-HQ-OAR-2009-0491-2659.1, pp.2-3]
EPA stated in the proposed CATR that a scrubber could be installed in 27 months.  As explained previously, this is not possible and 60 months is a much more realistic time frame for the planning, budgeting, permitting, financing, outage scheduling within the utility and the regional control authority, and installation of a scrubber.  Therefore, Empire District urges EPA to delay the effective date of Phase II of the CATR to the 1/1/2016 time period.  This would provide marginal time for scrubber installation and would more closely align CATR with other developing regulations.  In addition, we question EPA's statement that Low NOx Burners (LNB) can be installed in 6 months.  The permit for LNB can take 6 month to a year.  Planning and budgeting must occur before the beginning of the permitting period.  An outage must be scheduled for installation.  This outage must be coordinated not only within the local utility, but also with the regional control authority.  From planning to completion of installation for LNB a more realistic time period is 24 to 36 months.  In order to provide for an adequate period for AQCS installation, EPA should reconsider revising phase 2 date of 2014 to 2016 or later and the proposed dates of 2014 for one-year variability and 2016 three-year variability. [EPA-HQ-OAR-2009-0491-2659.1, p.7]
Energy Future Coalition
The Energy Future Coalition appreciates EPA's interest in the rapid implementation of the CATR. [EPA-HQ-OAR-2009-0491-2623.1, p.2]
Entergy Services, Inc.
Proposed Compliance Date
If a final rule is not issued until the middle of 2011, as suggested by EPA, it is unreasonable to assume that a utility can develop a compliance strategy based on short allowance budgets for each State's fleet, schedule outages, install controls, and train operators to operate these controls efficiently by January 1, 2012.  Even after the most cost effective compliance strategy is developed, it has been Entergy's experience that this will take a minimum of 2 years to evaluate, finance, award a bid, schedule outages, permit, construct, train, and have fully operational pollution control equipment.  Entergy has reviewed EPA's technical document, EPA-HQ-OAR-2009-0491  -  Installation Timing for Low NOx Burners, and disagrees that utilities can complete "engineering, fabrication, delivery and installation" of pollution control equipment in a 6 month time frame, much less at a time when pollution controls will be offered at a premium and contractor availability throughout the country may be limited. [EPA-HQ-OAR-2009-0491-2847.1,p.6]
Environmental Defense Fund (EDF)
Emissions Reductions are Achievable and Forward-thinking Investment Can Help Industry Comply with Future Regulations
a. Background on the Clean Air Interstate Rule Process and Timeline
EPA first proposed the Clean Air Interstate Rule (CAIR) in December 2003. After a comment period and lengthy review, EPA finalized CAIR in March 2005. NOx reductions were scheduled to begin in 2009 and SO2 reductions in 2010. In response to petitions for judicial review filed by the state of North Carolina and numerous power companies, the U.S. Circuit Court of Appeals for the District of Columbia vacated CAIR in July 2008. In December 2008, the Court reinstated CAIR until EPA adopted a replacement. The Phase I NOx program under CAIR began in 2009 and regulated entities were required to begin meeting the emission reductions requirements as promulgated under CAIR. In response to the Court's decisions, EPA proposed the Transport Rule in July 2010. [EPA-HQ-OAR-2009-0491-2834.1 p.13]
It has been more than seven years since EPA proposed to address the interstate transport of SO2 and NOx emissions from EGUs in the Eastern US. Many regulated entities have already taken steps to reduce their emissions to comply with Phase I of CAIR and many others are in the process of retrofitting their plants with emissions control technology. There has been a significant amount of time for industries to prepare for the proposed Transport Rule and the first compliance deadline of 2012 provides adequate time for industry to meet the new standards. [EPA-HQ-OAR-2009-0491-2834.1 p.14]
b. Emission controls are affordable and widely available, can be installed in a timely manner, and will not negatively impact electricity reliability
An analysis by M.J. Bradley & Associates demonstrates that emission controls are affordable and widely available, have been installed in a short period of time, and will not negatively impact electricity reliability with proper planning by industry officials.39 Sixty-five percent of existing coal-fired power plants have already installed or plan to install flue gas desulfurization systems (i.e. scrubbers) to control SO2 emissions and 50 percent have installed or will install NOx controls. The analysis noted that from 2008 - 2010, 60 gigawatts (GW) of coal capacity was retrofitted with scrubbers, indicating that industry can make substantial retrofits in a short timeframe. Scrubbers can reduce SO2 emissions substantially (by at least 95 percent) and selective catalytic reduction can reduce NOx emissions by 90 percent or more. The analysis also concluded that electricity reliability will not be impacted by the timely implementation of the proposed Transport Rule in any of the NERC regions. All NERC regions are expected to have between 22 - 42 percent reserve generating capacity in 2013. [EPA-HQ-OAR-2009-0491-2834.1 p.14]
EPA notes in its Regulatory Impact Analysis that only about 1.2 GW of coal-fired capacity, or 0.3 percent of the nation's coal-fired generating capacity, will be uneconomic to maintain under the proposed Transport Rule and will be retired or maintained as back-up generation for reliability purposes only. Under EPA's proposed remedy, only an additional 14 GW of coal-fired capacity will need to be retrofit with scrubbers for Phase II, which is less than one-fourth the 60 GW of retrofits that occurred between 2008 and 2010. Additionally, EPA projects that less than 1 GW of SCR controls will be installed for Phase II. [EPA-HQ-OAR-2009-0491-2834.1 p.14]
EquiPower Resources Corp.
Second, with respect to the Phase II unit-level emission allocations, which, unlike Phase I, expressly contemplate the installation of additional controls to obtain additional SO2 reductions, EquiPower believes that the Phase II compliance caps are infeasible. EPA presumes that the 14 gigawatts ("GW") of coal-fired capacity to be retrofit with FGD units (for SO2 control) and 1 GW of capacity to be retrofit with SCR units (for NOx control), can occur during the brief time window between when the Transport Rule is finalized (assumed to be mid-2011 by EPA) and 2014. EPA based its conclusion on its assumption that it only "takes approximately 27 months" to install an FGD and "21 months" to install an SCR. EquiPower understands that EPA's estimates are taken from a 2002 document in which TECO estimated it could install controls within those timelines. In fact, however, it appears that this utility's SCRs and FGDs did not become operational until approximately 5 years later  -  suggesting that the estimated timelines were overly optimistic. Moreover, based on industry's experience installing such systems, EquiPower believes that EPA's installation timelines are plainly inadequate. [EPA-HQ-OAR-2009-0491-2704.1, p.28]
For example, the Utility Air Regulatory Group ("UARG") has indicated that it actually takes between 40 and 60 months to install an FGD system and make it fully operational. Installation of an FGD requires a number of steps  -  (i) permitting, (ii) design and engineering, and (iii) actual construction and operation, all of which are time consuming. We would note that the preceding time estimates assume only one FGD and would have to be extended if multiple units at the same facility were all receiving FGDs.  PSD review, if it were determined to apply, would obviously further delay the installation of these controls. EquiPower notes that there are similar problems with respect to EPA's assumptions about the time it takes to install additional Nox controls. Again, the Agency has made assumptions with respect to the time it takes to design, engineer, permit and install an SCR that are unrealistic, and which face the same potential installation delays as an FGD. UARG has indicated that it takes approximately 32 to 46 months to install an SCR from start to finish. And to the extent a facility needs to install both an SCR and an FGD, the timelines for the individual installations would necessarily be extended even further, as it is not always possible to conduct these installations in parallel; more typically they are installed serially. Given the large numbers of scrubbers and SCRs that must be constructed to comply with the 2014 caps, the two and a half year control equipment installation window to satisfy the 2014 caps currently contemplated by the Transport Rule (from mid-2011 through 2014) is plainly insufficient. [EPA-HQ-OAR-2009-0491-2704.1, pp.28-29]
Put simply, the Transport Rule does not allow sufficient time for affected EGUs to install all of the necessary emission controls at all of its units. Further complicating the timeline, we would also note that some EGUs would not be in a position to even start work on addition controls until the Proposed Rule is finalized because of various regulatory and practical constraints. As noted above, waiting to begin the FGD or SCR installation process until the Transport Rule is finalized simply does not provide enough time to finish the installation before 2014. As such, EPA's rule places companies in a truly impossible position: They cannot obtain the financing or regulatory approvals necessary to begin design and construction until the Proposed Rule is final, but if they wait until that happens they will not be in a position to install the controls in the time that remains. Similarly, compliance with the Phase I and Phase II caps are likely to result in shortages of the skilled labor necessary to install and maintain all of the emissions controls required by the Transport Rule. Finally, implicit in EPA's timing is an assumption that all EGUs in need of control equipment can install it at the same time. This also ignores the fact that the outages required to complete installation and bring an FGD or SCR online cannot occur simultaneously. The outages have to be coordinated or electricity system reliability will be negatively impacted. Regulators typically only allow the tie-in period for a new piece of control equipment during periods of off-peak demand (i.e., fall and spring), and even then the outages would have to be staggered to ensure that they do not interrupt the electricity supply. These limitations can all materially impact the feasibility of the Transport Rule's compliance deadlines and suggest that they are unrealistic. [EPA-HQ-OAR-2009-0491-2704.1, pp.29-30]
Exxon Mobil Corporation
EM is concerned with the nearly immediate effective date of the rule. EPA has suggested they will promulgate a final rule in late spring 2011 and it will become effective January 1,2012. This is obviously unreasonable considering the costly impact to affected facilities. It is beyond reason to expect a facility to engineer, procure, and install controls in six months or even budget for purchasing additional allocations. [EPA-HQ-OAR-2009-0491-2841.1, p.16]
Florida Electric Power Coordinating Group, Inc. (FCG)
EPA has also substantially underestimated the time required for facilities to install emission controls, meaning that additional emission reductions will take much longer to achieve than EPA has assumed. EPA's erroneous assumption is that it takes 27 months to design, permit and build an FGD system, and 21 months to design, permit and build an SCR. EPA's timeline apparently only considered the time needed to actually build the system, and disregarded the critical time necessary to design and permit the equipment. Substantial recent experience reveals the actual time needed. Specifically, the Southern Company recently installed 15 FGD systems and 15 SCRs. The average time needed for an FGD system was 54 months (the range was 40 - 69 months), and for an SCR was 36 months (the range was from 28 - 42 months). Progress Energy recently installed nine FGD systems and nine SCRs, and it took approximately 44 months for an FGD system, and 38 months for an SCR. In addition, utilities typically put emission control projects out for competitive bid, which adds several months to the process to help ensure that the most cost-effective expenditure is being made. Also, the resolution of other environmental issues takes time, including water use and discharge permitting, and ash and gypsum management. A recent control project in Florida was installed, and yet delayed several months to address such issues. None of these factors appear to have been considered by EPA. EPA must correct its control-installation timeline assumptions to match reality. [EPA-HQ-OAR-2009-0491-2658.1,p.3]
Four Flags Area Chamber of Commerce
Under the existing proposal, there is not enough time for power generators to design, permit, fabricate and install pollution control equipment to comply with the new emissions levels established in the rule's second phase. [EPA-HQ-OAR-2009-0491-3807, p.1]
Georgia Department of Natural Resources, Air Protection Branch
In determining the base case emissions for 2014, EPA moved controls and emissions for modeling from 2015 to 2014.
As stated previously, Georgia has a multipollutant rule that requires SCRs and SO2 scrubbers to be installed on 22 large coal-fired units by July 1, 2015. The State rule includes a timetable that specifies equipment and dates of installation for each unit. The dates in the rule were negotiated with the owners of the affected units to install the equipment as expeditiously as practicable while taking into consideration the limited construction resources and to accommodate the CAIR and the State's extensive nonattainment planning requirements for fine particulate matter and ozone. Additionally, this control schedule was negotiated around power outage schedules to accommodate this construction while still meeting the demands of the electrical grid. Ten (10) units have already been retrofitted and are in operation. Based on real experience at these 10 units, the time required to retrofit a unit with an SCR and scrubber is approximately 48 months for each unit, not the 27 months assumed in the Transport Rule. Moving the date from 2015 to 2014 affects the dates of 6 units that are currently scheduled for retrofit between June 2014 and June 2015. EPA must reconsider their assumptions on how quickly these controls can be constructed and provide adequate support for those assumptions in the record. This is especially true if the final rule is issued later than currently reported by EPA. [EPA-HQ-OAR-2009-0491-2647.1, p.2]
Great River Energy
Great River Energy appreciates EPA's efforts to address non-attainment and interstate transport of pollution, especially as it can be achieved through both flexible and highly cost effective means. Unfortunately, for several reasons, as discussed throughout these comments, Great River Energy finds neither a cost effective nor flexible compliance program for our Minnesota combustion turbines.
EPA must realize several facts about our peaking turbines, which may not have been reflected in the IPM modeling and associated conclusions. Great River Energy has seven peaking plants, with a nominal capacity of approximately 1700 MW. With limited allowances, as currently proposed by EPA, GRE will effectively have two non-flexible compliance options. Our preferred option is to purchase allowances through intrastate or interstate trading. As discussed elsewhere, we have strong reservations regarding the viability of both intrastate and, to a lesser extent, interstate trading. This presents significant compliance and operational risks.
Failing our preferred' allowance purchasing' option, GRE must consider installation of pollution controls, namely selective catalytic reduction ('SCR'), on our already controlled and, in certain instances, annually limited to synthetic minor thresholds per plant Title V permits. Our combustion turbines have been using Ultra Low Sulfur Diesel (15ppm) since 2006. Therefore, we cannot expect to reduce S02 emissions any further. With respect to NOx emissions, all of our units have dry low NOx (DLN) burners and water injection for oil combustion. These peaking plants are already controlled for Transport Rule pollutants, yet will not be able to meet EPA's proposed NOx allowance allocations. While simple cycle SCR installations may have been completed in California and other non-attainment areas, these controls fall well outside of EPA's cost thresholds for the Transport Rule.
Even if GRE could justify the cost of these controls, EPA's control installation timelines are overly optimistic. There are numerous reasons, including detailed engineering design, permitting, construction, labor, financing, and resource availability, which call into question the industry's collective ability to bring SCR NOx controls on-line in 20 months, or FGD S02 controls on-line in 27 months. A single source with a detailed engineering design and associated construction documents could potentially issue for bid and optimistically complete a control proj ect as proposed by EPA's timeline, but it should not be the basis for a regional compliance program. In short, EPA has failed to provide a flexible and cost effective compliance program for peaking plants located in Minnesota. [EPA-HQ-OAR-2009-0491-2758.1 p.5]
Holland Board of Public Works
A compliance deadline of 2012 does not leave much time after the anticipated final rule is promulgated in 2011 to determine a cost-effective, cost-stable method of operating our affected unit.  [EPA-HQ-OAR-2009-0491-2861.1,p.1]
Hoosier Rural Electric Cooperative
The control efficiencies seem to be across the board limits and not indicative of technology and age of the units. [EPA-HQ-OAR-2009-0491-3758.1_NODA, p.2]
Independence Power & Light (IPL)
EPA failed to consider the constraints on the financial means and timetable for capital expenditures and the lack of economies of scale for controls called for by the Rule as to municipal EGUs. In addition, it is unlikely that municipal utilities, given their relatively small size, would be able to obtain a favorable queue position in what will undoubted by a long line of utilities seeking to fabricate the necessary controls. These problems place municipal utilities, like IPL, in a most difficult position because under certain circumstances they will be obliged to run units that will not have timely met the Rule's requirements to serve their customers' load, as they are obligated to do by statute. [EPA-HQ-OAR-2009-0491-2741.1, p.17]
Many municipal utilities such as IPL must undergo a series of prescribed steps in order to fund capital expenditures for the controls such as those assumed to be installed under the Rule. For capital expenditures of the order called for by the Rule IPL must first engage in cost of service studies to support subsequent ratemaking proceedings to raise electric rates to then establish the basis for bond issuance. This process alone requires at least one year of time and assumes that the bond capability of the utility at the time is sufficient for the amount of capital expenditure needed. At each step lies the potential for failure of achieving the ability to make the capital expenditure. The Rule finds that SCRs can be installed to meet enforceable allocations effective January 1, 2014 allocation requirements. See, e.g., 75 FR at 454286/3 ('a single SCR unit on average takes 21 months to install'). It is apparent from the length of time needed to accomplish the steps described above that this assumption is flawed. [EPA-HQ-OAR-2009-0491-2741.1, p.17]
For the reasons stated herein, IPL requests that EPA modify the proposed Rule by: 2 considering the time and burden on municipal utilities of obtaining the necessary capital for the controls mandated by the rules and the other obstacles that they face in meeting the rules in a timely manner. [EPA-HQ-OAR-2009-0491-2741.1, p.18]
Indiana Builders Association
Under the existing proposal, there is not enough time for power generators to design, permit, fabricate and install pollution control equipment to comply with the new emissions levels established in the rule's second phase. [EPA-HQ-OAR-2009-0491-2871.1,p.1]
The most significant reductions under the current proposal occur in 2014  -  only twoand- a-half years after the Rule is expected to become effective. Two-and-a-half years are not enough to design, permit, fabricate and install the necessary equipment. This unrealistic deadline could affect grid reliability if power companies are forced to prematurely close generation units to comply. If new scrubber byproduct storage facilities are needed in addition to emissions control equipment, the time line becomes much longer. [EPA-HQ-OAR-2009-0491-2871.1, p.2]
Indiana Cast Metals Association (INCMA)
The Indiana Cast Metals Association is one of the largest energy dependent sectors in Indiana and we strongly urge the EPA to delay implementation of the Transport Rule as it is proposed. The current proposal has several shortcomings that will result in needless economic harm to our members and the State of Indiana. [EPA-HQ-OAR-2009-0491-2178.1, p.1]
The most significant reductions under the current proposal occur in 2014  -  only two-and-a-half years after the Rule is expected to become effective. Two-and-a-half years are not enough to design, permit, fabricate and install the necessary equipment. This unrealistic deadline could affect grid reliability if power companies are forced to prematurely close generation units to comply. If new scrubber byproduct storage facilities are needed in addition to emissions control equipment, the time line becomes much longer. [EPA-HQ-OAR-2009-0491-2178.1, p.2]
Indiana Department of Environmental Management
While Indiana welcomes the aggressive implementation schedule in the proposed rule, it is unlikely that all control systems can be built in the amount of time provided by the proposed rule. [EPA-HQ-OAR-2009-0491-2645.1, p.2]
Indiana Municipal Power Agency
Under the existing proposal, there is not enough time for power generators to design, permit, fabricate and install pollution control equipment to comply with the new emissions levels established in the rule's second phase. [EPA-HQ-OAR-2009-0491-3057.1,p.1]
IMP A questions whether the modeling the EPA used to determine the Rule's compliance requirements is up to date and accurate. The EPA based its assessments on equipment and capabilities that in some cases are not yet in place. In order for generation companies to comply with the emissions targets, they will have to install equipment that the EPA has mistakenly indicated is already operational or will be in service soon. This error underestimates the cost of compliance and exacerbates another inaccuracy in the EPA's compliance assumptions - the time and cost needed to design, permit, fabricate and install control equipment. [EPA-HQ-OAR-2009-0491-3057.1,p.2]
The most significant reductions under the current proposal occur in 2014 - only two-anda- half years after the Rule is expected to become effective. Two-and-a-half years are not enough to design, permit, fabricate and install the necessary equipment. This unrealistic deadline could affect grid reliability if power companies are forced to prematurely close generation units to comply. If new scrubber byproduct storage facilities are needed in addition to emissions control equipment, the time line becomes much longer. [EPA-HQ-OAR-2009-0491-3057.1,p.2]
Indiana Utility Shareholders Association
The most significant reductions under the current proposal occur in 2014- only two-and-a-half years after the Rule is expected to become effective. Two and- a-half years are not enough to design, permit, fabricate and install the necessary equipment. If new scrubber byproduct storage facilities are needed in addition to emissions control equipment, the time line becomes much longer. [EPA-HQ-OAR-2009-0491-3845 p.2]
International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers and Helpers (AFL-CIO Boilermakers Union)
Although the Boilermakers Union supports aggressive action to regulate interstate transport of SO2 and NOx emissions within a 32-state region the proposed form of the Transport Rule sets deadlines that are based on inaccurate or outdated assumptions regarding the feasibility of installing pollution control measures. [EPA-HQ-OAR-2009-0491-2672.1, p.3]
Neither the Clean Air Act itself nor the D.C. Circuit's opinions in North Carolina v. EPA require these outcomes. To address our concerns, the Boilermakers Union urges EPA to defer implementation of the Transport Rule for one year. Such a deferral would give utilities an opportunity to make the necessary investments in their EGUs and allow states to develop SIPs that address interstate emissions transport. In addition, the Boilermakers Union urges a one-year extension of the second phase of SO2 reductions that would apply in 2014. Providing such extra time would address major concerns with the tight timeframes to permit, design, fabricate and install the FGD units at existing coal-fired generating units, while ensuring that meaningful steps are taken towards achieving attainment in downwind states by 2015. [EPA-HQ-OAR-2009-0491-2672.1, p.3]
EPA's proposal to impose Transport Rule emission budgets beginning in 2012 is based on three major errors. First, EPA unrealistically assumes that many EGUs can install low-NOx burners and or switch to burning lower sulfur coal by January 1, 2012. [EPA-HQ-OAR-2009-0491-2672.1, pp.3-4]
1. Feasibility of Controlling Pollution by 2012. There is little evidence in the record to support EPA's assertion that Transport Rule requirements can be met by 2012. EPA's two-page Technical Support Document (TSD) regarding the availability of NOx control technology provides just two anecdotal cases to support the claim that low-NOx burners can be installed by 2012. Absent from the TSD is any broader analysis showing that those two cases are comparable to the thirty facilities that would have to be retrofit with low-NOx burners under the proposed Transport Rule. Neither does the TSD assess whether SNCR and burner upgrades would be adequate to meet the 2012 emission budgets. [EPA-HQ-OAR-2009-0491-2672.1, p.4]
Our own assessment is that the 2012 deadline would give utilities little time approximately six months from the expected promulgation of the Transport Rule - to switch coal supplies and, in many cases and make the boiler modifications that are necessary to burn the lower sulfur subbituminous coals. Similarly, six months is not enough time to schedule outages and install necessary NO, controls at existing EGUs. 5 EPA's timetable may not be achievable for all facilities, and leaves no room for inevitable construction delays that often result from ordinary material shortages or regulatory complications. [EPA-HQ-OAR-2009-0491-2672.1, p.4]
Finally, EPA fails to account for the additional time that it will take to complete permit reviews and obtain the necessary construction permits for going forward with these projects. [EPA-HQ-OAR-2009-0491-2672.1, p.4]
B. The deep S02 reductions required by 2014 are infeasible.
The 2014 deadline for achieving additional SO2 reductions in 'Group 1' states is likely to be just as infeasible to meet as the initial 2012 deadline for SO2 and NOx reductions. First, EPA bases the 2014 deadline in part on a 2005 analysis (Boilermaker Labor Analysis and Installation Timing) indicating that a FGD unit takes 27 months to install. However, this estimate of construction time is actually drawn from a considerably more dated EPA analysis published in 2002.8 It is not clear whether this eight-year old analysis remains applicable to EGUs now being retrofitted. Even accepting the timetables in the 2005 study as valid, those timetables also show that 27 months is required to install FGD on a single generating unit. A multi-unit facility that seeks to avoid a complete shutdown would, necessarily, have to engage in successive retrofits of generating units that would take considerably longer than 27 months. For example, the 2005 study relied upon by EPA indicates that a four-unit facility would require almost 37 months to complete the installation of FGD equipment. If this timetable is correct, many facilities in Group 1 states would not have sufficient time to install additional SO2 controls by 2014. [EPA-HQ-OAR-2009-0491-2672.1, p.6]
EPA also says that the 2014 deadline is feasible because the amount of electric capacity anticipated to be retrofitted with FGD is less than was ultimately retrofitted under CAIR. This argument implicitly assumes that those EGUs remaining to be retrofitted can undertake modifications on a timetable comparable to units that have already installed pollution control equipment. The Boilermakers Union believes that this assumption is likely to be incorrect. In general, the population of EGUs that have already been retrofitted with FGD equipment includes a significant proportion of newer and larger generating units located away from urban areas. These EGUs were the first to be retrofitted under CAIR and similar programs because they offered the most straightforward and cost-effective emission reduction opportunities. By contrast, the population of EGUs that remains to be retrofitted is dominated by older, less-efficient facilities where modifications will be relatively more complex and difficult. EPA's analysis fails to take this phenomenon into account, assuming instead - without any support - that future retrofits will proceed as quickly as past retrofits. This assumption is arbitrary and has led EPA to an unjustifiably optimistic projection as to the amount of time it will take to meet the Group 1 SO2 requirements. [EPA-HQ-OAR-2009-0491-2672.1, p.7]
EPA's analysis of the feasibility of meeting the 2014 deadline is also flawed because it omits any consideration of the cumulative effects of impending rulemakings namely, Maximum Achievable Control Technology (MACT) standards for boilers and standards for cooling water intake structures on demand for boilermakers and equipment. These rulemakings, which are expected to be completed over the next two years, will also likely require EGUs to undertake extensive modifications. It is inappropriate to neglect the impact of these rulemakings on the availability of resources to complete retrofits required under the Transport Rule. [EPA-HQ-OAR-2009-0491-2672.1, p.7]
In light of the above-described problems with EPA's basis for the implementation timetable of the Transport Rule, the Boilermakers Union urges EPA to defer implementation of the Transport Rule for one year. Such a deferral would enhance the feasibility of the Transport Rule, enable the submission of SIPs that are compliant with Section 110, and avoid unnecessary elimination of jobs or missed employment opportunities. [EPA-HQ-OAR-2009-0491-2672.1, pp.9-10]

5. Through internal inquiries among our members, we have learned that a typical installation of a low-NOx burner at a 750 MW generating unit requires the plant to be out of service for approximately ten weeks (not including time required for design and manufacturing of the equipment, and acquisition of necessary permits). It may not be possible for many EGUs to arrange for such a long closure of facilities, and complete all necessary preparation for installation, in the time between the promulgation of the Transport Rule and the proposed 2012 deadline. [EPA-HQ-OAR-2009-0491-2672.1, p.4]
10. EPA's estimates also entail potentially heroic assumptions about the ability of electric utilities to obtain the other permits necessary for installing FGD systems. Such permits are not limited to air quality construction permits, but also include general construction permits, solid waste disposal permits, revisions to water use/discharge permits, etc. Such permits can take months and, in some cases, years to obtain. In addition, EGUs will have to arrange for funding - in the case of public power entities, this could involve the sale of bonds. Finally, it will be necessary to coordinate the construction work, including the scheduling of outages in order to ensure system reliability. [EPA-HQ-OAR-2009-0491-2672.1, p.7]
Jessee, Robert
I am also concerned about the timing required in the rule. The time frame from the proposed rule_s effective date until the second phase of required reductions is to be obtained is right at 2.5 years. The expectation to have installed the necessary equipment and have it fully functional within this short time frame is not obtainable. [EPA-HQ-OAR-2009-0491-3288, p.1]
Kansas City Board of Public Utilities (BPU)
EPA Gave No Consideration to the Unique Challenges Faced by Municipal Utilities
EPA failed to consider the constraints on the financial means and timetables for securing capital and the lack of economies of scale for air emission controls called for by the Rule in regards to municipally-owned EGUs like BPU. [EPA-HQ-OAR-0491-2009-0491-2740.1, p.22]
Many municipal utilities such as BPU must undergo a series of prescribed steps before they can fund capital expenditures for the controls such as those assumed to be installed under the Rule. For capital expenditures of the order called for by the Rule, BPU must first engage in cost of service studies as support for subsequent ratemaking proceedings to raise electric rates that will establish a basis for the issuance of municipal bonds. This process alone requires at least one year and assumes that the bond capability of the utility at the time is sufficient for the amount of capital needed. The potential for failure to achieve bond capital is very real. [EPA-HQ-OAR-0491-2009-0491-2740.1, p.22]
The Rule finds that SCRs can be installed to meet enforceable allocations effective January 1, 2014 allocation requirements. See. e.g., 75 FR at 454286/3 ('a single SCR unit on average takes 21 months to install'). It is apparent from the length of time needed to accomplish the steps described above, this assumption is flawed because it does include the time needed to raise the necessary capital. [EPA-HQ-OAR-0491-2009-0491-2740.1, p.22]
Finally, many municipal utilities own and operate a relatively small number of relatively small EGUs units. The ability to achieve the required emissions reductions on small units is not reflected in the Rule. Due to simple lack of economies of scale, the cost of controls on smaller units can be as much as three times the cost per MW that the Rule assigns meet required air emission reductions. See, e.g., 75 FR at 45277-79 (cost curves). This calls into question the validity of costs per ton needed to reach the reductions postulated that forms the basis for regulation of many small municipal EGUs subject to the Rule. [EPA-HQ-OAR-0491-2009-0491-2740.1, p.23]
For the reasons stated herein, BPU requests alternative modifications to the proposed Rule by:
7. considering the unique circumstances regarding time and burden on municipal utilities of obtaining the necessary capital for the controls mandated by the rules;  [EPA-HQ-OAR-2009-0491-2740.1, p.23]
Kansas City Power and Light Company (KCP&L)
3. EPA underestimates the amount of time necessary to bring new controls online. For example, EPA estimates that a new scrubber can be installed in 27 months, from conceptualization to regulatory approvals by financial regulators and air quality permitting agencies, to operation. Engineering and permitting for KCP&L's Iatan Unit 1 controls began in early 2005 and the controls were installed, operational, and compliant by the end of 2009 or nearly 60 months. [EPA-HQ-OAR-2009-0491-2709.1, p.3]
Kansas Department of Health and Environment
Kansas is in the unique situation that several of our EGUs are slated for installation of low NOx burners (LNBs) as part of the proposed Transport Rule to meet statewide budgets. The timing for these installations as laid out in the rule is very aggressive, and KDHE believes likely unattainable without disruption of service. In the TSD discussing installation timing, EPA provides several examples where engineering analyses and retrofits are completed in a short time window (see http://www.epa.gov/airquality/transport/pdfs/TSD Installation timing for LNBs 07-6-10.pdf). Unfortunately, not all EGU units are the same and each brings its own unique challenges in design, engineering, and retrofitting controls. Making the assumption that all units required to install LNBs in the state could perform the retrofit in a six-month time window because it has been done at several sources elsewhere is not real-world reality, and in fact it is likely the exception rather than the rule that LNB retrofits are completed in this timeframe. Several of the Kansas units that would be looking at retrofits are co-located or operated by the same company, and could not be retrofitted at the same time for demand reliability reasons even if the design and engineering could be performed in this timeframe. In reality it is also unlikely LNB retrofits for these units can be designed and installed in a six-month window if all the variables unique to Kansas generators are factored in. KDHE strongly believes this portion of the rule is unattainable for Kansas sources. KDHE recommends language requiring LNB controls be installed as expeditiously as practicable, allowing for a more reasonable timeframe beyond the beginning of 2012. [EPA-HQ-OAR-2009-0491-2606.1, p.6]
Kentucky Chamber of Commerce
The Kentucky Chamber feels strongly the proposed Transport Rule is based on outdated and inaccurate data, proposes unrealistic time frames for achieving reductions and ignores significant constraints on how reductions can be achieved. The Kentucky Chamber feels it is simply not possible to design, permit, fabricate and install the equipment necessary to meet the new requirements within the timelines in the proposal, particularly considering how long it will take to finalize the rule and the limited amount of emissions trading that will be permitted. [EPA-HQ-OAR-2009-0491-2760.1 p.1]
The deadlines in the Transport Rule provide no practical way for power companies to install any needed pollution control equipment or for the states to develop their own state implementation plans (SIPs). SIPs have always been a cornerstone for compliance and enforcement of the Clean Air Act.  [EPA-HQ-OAR-2009-0491-2760.1 p.2] [[These comments can also be found in Section VII.C.]]
Kentucky Division for Air Quality
Deadlines for achieving mandated emission reductions should be designed to support the attainment deadlines prescribed for the standards. At the same time, the regulated community must be granted the required time to design and implement control equipment and operational changes necessary to meet new emissions limits. [EPA-HQ-OAR-2009-0491-2805.1, p.1]
More Time Needed to Install Controls
Pursuant to the rule preamble Section IV.D., Emissions Reductions Cost Curves (75 FR 45273), the time available for affected units to install new SO2 and NOx controls by the 2012 and 2014 timeframes is not sufficient, especially for NOx, which has less flexibility in the emission reduction options available. Therefore, the Division requests EPA to take this comment into consideration when finalizing the Transport Rule. [EPA-HQ-OAR-2009-0491-2805.1, p.6]
Lansing Board of Water & Light
BWL strongly disagrees with EPAs statement that low NOx burners could be installed by 2012 to meet this rule. EPA cannot expect any entity to spend exorbitant amounts of money to meet proposed restrictions in a proposed rule. By EPAs own admission, the Transport Rule is not expected to be finalized until Summer 2011. An expected date for pollution control installation of January 1, 2012 is completely preposterous. Permitting alone can take up to 12 months (see Michigan Permit to Install 390-08 which took more than 12 months to approve for the installation of two LNB systems on two boilers) and that is not including the time to design, fabricate and actually install the equipment. [EPA-HQ-OAR-2009-0491-2752.1,p.4]
Timing of the proposed rule and installation schedule
There is simply not enough time for electrical generators to design, permit, fabricate and install pollution control equipment to comply with the new emissions levels established by this proposed rule. BWL has begun preliminary discussions with various consultants and determined that the minimum time to design, fabricate, and install a selective non-catalytic reduction (SNCR) system is 24 months. With all of the uncertainty regarding regulatory applicability, the permitting phase will likely require additional 9-12 months to complete. Thus, an SNCR (which is relatively easy compared to scrubbers or SCR) will need three years to become operational. [EPA-HQ-OAR-2009-0491-2752.1,p.7]
To add to the uncertainty, EPA has already proposed to revise the proposed rule in regards to emissions of NOx, based upon the forthcoming Ozone NAAQS Reconsideration. The level of uncertainty this creates throughout the electrical generation industry is beyond fathom. Pollution control equipment for this industry is not something that can be bought at a local supermarket, only to be discarded when a new one is needed. This equipment takes years to design and install requiring investments of several million dollars. The utility industry is being asked to comply with a rule that is still just a proposal when there is already a proposal to revise the proposed rule! [EPA-HQ-OAR-2009-0491-2752.1,p.7]
EPA should not adopt the proposed 2012 compliance deadline and should not consider any compliance date earlier than 2015. This would give the utility a clear emissions reduction target and allow proper time to design, permit, fabricate and install the necessary control equipment. Furthermore, with CAIR remaining in place through 2015, emissions would continue to be reduced until the Transport rule would be fully implemented. [EPA-HQ-OAR-2009-0491-2752.1,p.7]
Large Public Power Council (LPPC)
LPPC understands EPA's desire to craft a Transport Rule that effectively addresses interstate transport of ozone and particulate matter (PM), complies with the D.C. Circuit's 2008 opinion in North Carolina v. EPA, 2 and achieves an orderly EPA's decision to propose a limited interstate trading program instead of a program that prohibits interstate trading or requires "direct control" of emissions on a source-by-source basis. [EPA-HQ-OAR-2009-0491-2667.1, pp.1-2]
However, LPPC believes that the proposed Transport Rule exceeds the D.C. Circuit's instructions in North Carolinpa, and creates a potentially disruptive break with CAIR, by imposing an unrealistically aggressive timetable that bypasses the traditional prerogatives of states to develop implementation plans that address interstate emissions. [EPA-HQ-OAR-2009-0491-2667.1, p.2]
Briefly stated, our principal recommendations to EPA are:
- Adjust the 2012 and 2014 compliance deadlines to reflect a more realistic assessment of the time required to implement SO2 and NOx controls; [EPA-HQ-OAR-2009-0491-2667.1, p.2]
EPA has proposed an extremely aggressive timetable for implementing the Transport Rule and enforcing compliance with its emissions limitations. As proposed, the Transport Rule would take effect and state emissions budgets would become binding in 2012  -  less than one year after the Transport Rule is expected to become final. So called "Group 1" states that are required to undertake additional SO2 reductions would have until 2014 to comply with these subsequent emission limitations. 4 LPPC believes the proposed implementation timetable and compliance deadlines raise two concerns. [EPA-HQ-OAR-2009-0491-2667.1, p.3]
Second, the aggressive compliance deadlines overlook legitimate concerns over the ability of the power sector to implement the requisite pollution controls within the contemplated timeframe. [EPA-HQ-OAR-2009-0491-2667.1, p.3] [[This comment can also be found in Section VII.C.]]
In addition, a one to two-year deferral would provide a realistic window for the installation of necessary pollution control technology. [EPA-HQ-OAR-2009-0491-2667.1, p.3]
B. The Proposed Compliance Deadlines Are Infeasible to Meet
The ambitious compliance deadlines in the proposed Transport Rule rest on unrealistic assumptions about the feasibility of implementing pollution control measures. EPA's initial compliance deadline of 2012 is based on its assessment that low-NOx burners or other NOx control strategies can be installed in a relatively short time frame, and that coal-burning EGUs can switch to low-sulfur coal without extensive retrofits. EPA bases its 2014 compliance deadline for further SO2 reductions in "Group 1" states on a 2005 analysis indicating that a flue gas desulfurization (FGD) system takes 27 months to install, and claims that the amount of electric capacity anticipated to be retrofitted with FGD is less than was ultimately retrofitted under CAIR. 23 [EPA-HQ-OAR-2009-0491-2725.1, p.7]
EPA has marshaled scant and questionable evidence to support these claims. First, EPA's two-page Technical Support Document (TSD) on the availability of NOx control technology is woefully inadequate. The TSD presents only anecdotal evidence from two EGUs to support EPA's claim that low-NOx burners can be installed by 2012, without showing that those two cases are comparable to or representative of the thirty facilities that EPA claims would have to be retrofitted with low-NOx burners under the proposed Transport Rule. The TSD also asserts that selective non-catalytic reduction (SNCR) and upgrades to existing burners can be implemented "quickly" (without indicating a particular timeframe), citing as sole support for this statement a conversation with an official representing an association of pollution control equipment manufacturers; 24 the TSD does not provide a factual basis for this statement or otherwise attempt to bolster the credibility of this assertion. Neither does the TSD assess whether SNCR and burner upgrades alone would be adequate to meet the 2012 emission budgets. [EPA-HQ-OAR-2009-0491-2725.1, p.7]
Second, EPA's reliance on the 2005 study entitled Boilermaker Labor Analysis and Installation Timing is misplaced. 25 EPA's claim that a FGD unit requires only 27 months to install appears to be based on the project timetables displayed on pages 14 and 15 of that report. Those timetables are themselves drawn from a considerably older EPA analysis completed in 2002. 26 EPA does not explain whether this eight-year old analysis remains applicable to EGUs now being retrofitted. Even setting aside this concern, the project timetables themselves show that 27 months is the expected time for installation of FGD equipment on a single generating unit. A multi-unit facility that seeks to avoid a complete shutdown would, necessarily, have to engage in successive retrofits of generating units that would take considerably longer than 27 months. Indeed, the timetables in the 2005 study indicate that a four-unit facility would require almost 37 months to complete installation of FGD equipment. 27 Similarly, a separate 2010 study commissioned by the electric power industry concluded that a typical installation of a single FGD unit would require 36 months. [EPA-HQ-OAR-2009-0491-2725.1, pp.7-8]
By noting that the amount of capacity expected to be retrofitted under the Transport Rule is no greater than under CAIR, EPA also implicitly assumes that those EGUs remaining to be retrofitted can undertake these modifications on a timetable comparable to units that have already installed pollution control equipment. LPPC believes that this assumption is incorrect. In general, utilities have installed existing FGD and SCR systems on larger and newer EGUs where those systems could be most cost effectively implemented. EGUs that remain to be retrofitted are, on the average, older, smaller, and less-efficient facilities where modifications will be relatively more complex and difficult. According to a recent study conducted by ICF International, approximately 92 GW of the total coal-fired generating fleet will lack both SO2 and NOx controls; of that amount, approximately 50 GW are units that are more than 40 years old and have heat rates greater than 10,000 BTU/kWh. 28 EPA's analysis fails to take this trend into account, assuming instead that future retrofits will proceed as quickly as past retrofits  -  an assumption that is inappropriate for many facilities. [EPA-HQ-OAR-2009-0491-2725.1, p.8]
Further, EPA's analysis of resource availability neglects to consider the cumulative effects of impending rulemakings  -  namely, Maximum Achievable Control Technology (MACT) standards for boilers and standards for cooling water intake structures  -  on demand for boilermakers and equipment. These rulemakings, which are expected to be completed over the next two years, will also likely require EGUs to undertake extensive modifications. Although it may be difficult to precisely quantify the resource demands associated with these still-pending rules, it is inappropriate to entirely overlook the impact of these rulemakings on the availability of personnel and funding to complete retrofits required under the Transport Rule. [EPA-HQ-OAR-2009-0491-2725.1, p.8]
Louisiana Energy and Power Authority (LEPA)
THE PROPOSED TRANSPORT RULE WOULD IMPOSE AN INAPPROPRIATELY SHORT INITIAL COMPLIANCE DEADLINE OFJANUARY 1, 2012. [EPA-HQ-OAR-2009-0491-2700.1, p.17]
LEPA's critical units are 40-year old simple cycle gas units. LEPA does not know if pollution control technology is available to eliminate the NOx emissions from those generators. Even if such technology is available, LEPA would have great difficulty securing the capital to install that equipment on its 40-year-old units. [EPA-HQ-OAR-2009-0491-2700.1, p.17-18]
Luminant
:: In addition, EPA anticipates the need for retrofitting existing generation with pollution control equipment or fuel switching however, EPA's compliance dates for pollution control equipment does not allow enough time for permitting, design, procurement, installation and testing of this pollution control equipment. Thus, the timeline is unacceptably short. [EPA-HQ-OAR-2009-0491-2729.1, p.3]
Based on the experiences of two plants in the first decade of the 21st  century, EPA believes that a selective catalytic reduction (SCR) system can be designed, permitted and installed in 21 months, and a flue gas desulfurization (FGD) system, in 27 months. Those timelines are not adequate for all necessary activities, especially if many sources are vying for design, materials, equipment, and construction resources concurrently. Furthermore, permitting can be a real unknown variable, particularly in states that have the public participation feature of a contested case hearing. For example, in Texas it can easily take 2 years or more to complete the air permitting process. Thus, EPA's proposed compliance timeline does not give a reasonable amount of time for compliance and should be extended. [EPA-HQ-OAR-2009-0491-2729.1, p.7]
Manitowoc Public Utilities (MPU)
 MPU believes that the EPA should consider the implications of fuel switching for the many States where budgets will be inadequate for SO2 and NOx.   [EPA-HQ-OAR-2009-0491-2860.1,p.2]
 MPU believes that EPA has vastly underestimated the amount of time that it takes utilities to design, permit, construct, and start up new FGD and SCR units. The SO2 and NOx emission reductions expected under the terms of the Proposed Transport Rule will be difficult to achieve with out additional control equipment.   [EPA-HQ-OAR-2009-0491-2860.1, p.2]
EPA Fuel Switching Expectations
MPU believes that the EPA should consider the implications of fuel switching for the many states where budgets will be inadequate for SO2 and NOx. Utilities have long-term contracts for the supply of fuels that need to be honored to avoid significant penalties. Fuel contracts take time to develop and rapid changes are not practical and often times have operating permit issues that may need to be addressed. Expectations of significant switching to natural gas are also not reasonable due to operating permit issues, gas infrastructure shortfalls, and the time to design, install, and fund the installation of new gas burners to accommodate fuel switching to natural gas. [EPA-HQ-OAR-2009-0491-2860.1,p.4]
Installation of New Emission Control Systems
MPU believes that EPA has vastly underestimated the amount of time that it takes utilities to design, permit, construct, and start up new FGD and SCR units. It will take longer than 30 months, in some cases significantly longer than 30 months, for affected EGUs to retrofit FGD and SCR units at existing EGUs. Thus, it will not be possible for affected EGUs to achieve all the SO2 and NOx emission reductions that must be achieved by the January 2012 and 2014 deadlines under the terms of the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2860.1,p.5]
Marquette Board of Light and Power
Inadequate Time for Implementation
The Agency has announced that it anticipates taking final action in the rulemaking in June 2011 and imposing an initial compliance date of January 1, 2012. There will not be sufficient time to evaluate the best control option, budget, permit, order, and install within the six month time frame that the Agency is proposing. Control options cannot be evaluated until allowances are allocated in a final rule. Budgeting is contingent on the control option selected. A permit application packet must be prepared, submitted, and obtained for the selected control option prior to making the equipment purchase. [EPA-HQ-OAR-2009-0491-2764.1, p.2]
Negotiating performance guarantees and manufacturer availability will restrict time of delivery. Installation time will vary depending on the control option selected. Marquette is located in the Wisconsin and Upper Michigan System (WUMS) subregion of the Midwest Impendent Transmission System Operator (MISO). Scheduling routine maintenance outages of a few days has proven difficult; scheduling an extended outage in such a short time frame will be challenging. [EPA-HQ-OAR-2009-0491-2764.1, p.3]
Mass Comment Campaign (221) (American Electric Power)
The Transport Rule does not allow enough time for power companies to install the equipment needed to reduce emissions by the 2014 deadline.  [EPA-HQ-OAR-2009-0491-3528_Mass, p.1]
Mass Comment Campaign (245) (American Electric Power)
I support the agency's efforts to reduce the amount of sulfur dioxide and nitrogen oxide in the atmosphere, but I am concerned about the the timing required in the rule. From the time the rule would become effective until the second phase of reductions are to begin is barely two-and-a-half years -- hardly enough time for power companies to install the needed equipment.
Michigan Chamber of Commerce
Under the existing proposal, there is not enough time for power generators to design, permit, fabricate and install pollution-control equipment to comply with the new emissions levels established in the rule's first and second phases. [EPA-HQ-OAR-2009-0491-2696.1, p.1]
Michigan Department of Natural Resources and Environment
One of most critical concerns of the Michigan Department of Natural Resources and Environment (DNRE) is the implementation timing for the proposed Interstate Transport Rules (TR), where Phase One begins in 2012 and Phase Two in 2014. The DNRE believes the shortened timeline for implementation of the TR has adverse impacts on the sources affected. [EPA-HQ-OAR-2009-0491-2774.1 p.3
In September 2009, states of the Lake Michigan Air Directors Consortium (LADCO) offered recommendations to the Environmental Protection Agency (EPA) regarding a framework for addressing transport (see attached letter, Appendix A). Along with other LADCO states, we were involved in the state-by-state analysis of what levels of electric generating unit (EGU) controls are achievable over the next several years. Per the letter from the LADCO states to the EPA, a fundamental assumption made was a JUly 2012 start date for planning, engineering, and construction of any new oxides of nitrogen (NOx) and sulfur dioxide (502) controls. This date reflects a January 2011 promulgation date for the replacement rule and approximately 18 months for adoption of state rules. Based on the analysis completed, the DNRE believes that the following three layers of controls can be completed by 2015 at the earliest:
:: All NOx and 502 controls installed to comply with original Clean Air Interstate Rule (CAIR) Phase I program;
:: Optimization of existing NOx and 502 controls by 2014; and
:: Application of low capital cost NOx controls by 2015.
As a result, the DNRE believes that the earliest installation of new major NOx and 502 controls to sources within Michigan can be achieved is 2017. [EPA-HQ-OAR-2009-0491-2774.1 p.3
Michigan Manufacturers Association (MMA)
- Under the existing proposal, there is not enough time for power generators to design, permit, fabricate and install pollution control equipment to comply with the new emissions levels established in the rule's first and second phases. In September 2009, the Lake Michigan Air Directors Consortium (LADCO), which includes Michigan, conducted a state-by-state analysis and informed EPA that significant additions of new controls would not be possible before 2017. [EPA-HQ-OAR-2009-0491-2762.1, p.1]
If new scrubber byproduct storage facilities are needed in addition to emissions control equipment, the time line becomes much longer. [EPA-HQ-OAR-2009-0491-2762.1, p.3]
Michigan Municipal Electric Association (MMEA)
the timeline for compliance with the Transport Rule is unachievable; [EPA-HQ-OAR-2009-0491-2828.1, p.2]
3.) EPA's Transport Rule Has Unrealistic and Unachievable Compliance Deadlines
Michigan's public power communities do not have the ability to reach EPA's proposed 2012 and 2014 compliance timelines, even if the drastic impacts on our units could be justified. Given that these utilities are relying on hardship allowances provided by the State of Michigan and affirmed by EPA in its approvals of Michigan's SIPs, these further pollution controls for NOx (such as SNCR or SCR) and SO2 (such as FGD or fuel switching) have not been planned and are not feasible now, let alone after the EPA finalizes this Transport Rule. As the Manager of Utility Compliance in Marquette states about the Transport Rule's impact on the Shiras unit, "I will not be able to obtain funds, conduct studies comparing the best control options, decide on a control option, pick a manufacturer, get it permitted, schedule, and have it installed by 2012. The time table is impossible to meet." [EPA-HQ-OAR-2009-0491-2828.1, p.9]
Regarding the compliance deadlines proposed for the Transport Rule, MMEA supports the comments filed by the Michigan Department of Natural Resources and Environment, which states that the earliest that additional NOx and SO2 controls could be installed in Michigan is 2017. We also support MMEA's national trade group the American Public Power Association, which comments extensively on why the proposed 2012 / 2014 compliance deadlines are not feasible and not necessary, and which requests later a later compliance deadline of no earlier than 2015. [EPA-HQ-OAR-2009-0491-2828.1, pp.9-10]
5.) Extend Transport Rule compliance deadlines to at least 2015, preferably the 2017 timeframe suggested by the Michigan Department of Natural Resources and Environment.[EPA-HQ-OAR-2009-0491-2828.1, p.16]
Midamerican Energy Holdings Company
It has taken EPA two years to propose the Transport Rule in response to the D.C. Circuit Court of Appeals decision determining that the Clean Air Interstate Rule was fatally flawed and it will take another six months  -  mid-2011  -  to finalize the Transport Rule. EPA will have had 30 months to draft and finalize a rule while sources with compliance obligations during the initial phase of reductions have a maximum of 15 months to comply with the rule beginning January 1, 2012. Even if sources in states covered by the initial phase of emission reductions started installing controls today, they could not comply with this aggressive deadline. Only if a facility has already engineered and designed the necessary control system, purchased equipment, negotiated a contract, retained a vendor, contractor and skilled labor to install the controls, obtained an air quality construction permit, obtained other necessary regulatory approvals2, and scheduled an outage to tie in equipment, can it have any hope of meeting these aggressive deadlines. Given current economic conditions and the potential rate impacts on customers associated with large capital expenditures, companies are not likely to fully engage in negotiations and enter into contractual commitments until the final rules are known -- particularly since EPA has proposed three different compliance scenarios that will influence a company's control suite. At the same time, given the aggressive compliance dates of 2012 and 2014, companies cannot wait until the outcome of the final rule to initiate their emission reduction projects. [EPA-HQ-OAR-2009-0491-2748.1 p.3-4]
EPA's optimistic estimates regarding the length of time necessary for the installation of controls are unrealistic and unachievable. At the outset, companies in states affected in the first phase of the SO2 reductions have approximately 15 months, not 27 months, to install controls. Given the gravity of the penalties associated with noncompliance, companies cannot afford contractor delays, labor strikes, or the myriad of other unanticipated circumstances that arise in projects of this nature. Taken in isolation, and without consideration of other regulatory requirements, a 27 month equipment installation (after, of course, a contract is negotiated  -  which alone frequently takes approximately six months, particularly when the equipment suppliers and contractors are in high demand) may be achievable. However, not only are the facilities in the 31 affected states competing for resources and equipment to reduce SO2 and NOx emissions between 2012 and 2014, but those states are also competing with skilled labor, equipment and other services with companies in the Western states that are required to install controls beginning in the same time frame to implement their BART determinations and Regional Haze State Implementation Plans. [EPA-HQ-OAR-2009-0491-2748.1 p.3-4]
Minnesota Power
Similarly, it is questionable as to why EPA would expect Transport Rule budget compliance only about six months after the Transport Rule might be finalized and specific provisions for 2012 compliance have been identified and publically noticed, unless EPA expects such sources to be able to comply with 2012 requirements with controls already in place without the Proposed Transport Rule.   [EPA-HQ-OAR-2009-0491-2750.1, p.5]
National Mining Association (NMA)
2012 Is Too Soon to Begin Phase One Regulation, and 2014 Is Too Soon to Begin Phase Two Regulation
1. 2012
The phase one emission reduction obligations are significant. EPA indicates that the 2012 SO2 emission reductions required under the rule will be 4.1 million tons per year, as compared with 5.1 million tons that would be expected otherwise. EPA evidently believes that this significant amount of emission reductions is feasible by the beginning of 2012 because, in EPA's analysis, sources will not be required to install new pollution control equipment, beyond those already planned and in development, to meet the requirements of the rule. Instead, EPA believes that the rule's NOX requirements can be met by operating NOX control equipment year round, and the rule's SO2 requirements can be met principally through coal-switching from high sulfur to low sulfur coal and from low sulfur coal to very low sulfur coal. [EPA-HQ-OAR-2009-0491-2868.1,pp.15-16]
Moreover, NMA is unable to find any documentation in the record of whether EPA considered whether utilities are constrained by coal supply or rail contracts from switching coal suppliers or coal sources. Many coal and rail contracts extend for a period of years, in many cases for five or ten years or longer. Certainly, as of mid- 2011 when the Transport Rule is final, many utilities will be contractually locked into their sources of coal for the 2012-14 period and will therefore be unable to switch coal as EPA anticipates. If they are unable to do so, the 2012 budgets will be unattainable, except by closing coal-fueled units or ramping back production, which in turn will produce different impacts than those that the Agency has analyzed. EPA must at least produce some form of analysis taking into account coal supply and rail contract constraints. [EPA-HQ-OAR-2009-0491-2868.1,p.16]
Similarly, NMA is unable to find any documentation in the record of whether EPA considered any physical constraints on substitution of one type of coal for another, except where the switch would entail substitution of very low sulfur subbituminous coal for bituminous coal. But many other types of coal characteristics affect whether coal can be burned in a particular unit even for coal within a single coal region. Unless EPA produces a unit-by-unit analysis demonstrating that coal can be substituted in the manner that EPA anticipates, there will be no certainty that utilities can meet the 2012 compliance deadline through coal-switching and that unit closures or reductions in operations will not be required. [EPA-HQ-OAR-2009-0491-2868.1,p.16]
2. 2014
For compliance with the 2014 SO2 budgets, EPA projects the installation of scrubbers on 14 GW of generation, in addition to the very substantial amount otherwise planned for that period. For NOX compliance in 2014, EPA projects the addition of SCRs on 51 GW of capacity. EPA expresses confidence that utilities can install scrubbers on 14 GW of capacity during the three year period between 2011 when the Transport Rule goes into effect and 2014 because utilities installed more than that amount of scrubbers in past three-year periods in response to CAIR. But that statement ignores the fact that EPA expects utilities to install scrubbers on an additional 26 GW of capacity by 2014 under what EPA calls other requirements. [EPA-HQ-OAR-2009-0491-2868.1,pp.16-17]
This is a great deal of construction activity in a very limited amount of time. In the first place, since EPA has overstated the number of scrubbers that will be brought on line by the beginning of 2012, it has underestimated the number that must be brought on line between 2012 and 2014. Based on comments that will be submitted by utility industry entities, industry estimates show that approximately 25 GW of new scrubbers will be required by 2014, not the 14 GW assumed by EPA. [EPA-HQ-OAR-2009-0491-2868.1,p.17]
Moreover, NMA understands that utility industry commenters will also be providing information showing that EPA has severely underestimated the time it takes to plan for, design and engineer, and construct scrubbers and SCRs. For example, EPA's estimate that a scrubber can be brought on line in 30 months is based on general industry information taken from a period that did not experience the extremely high volume of scrubber construction that EPA projects in the 2012-14 time period, and the even higher volume of construction that will likely take place in actuality. Furthermore, using general figures masks difficulties that may arise at individual locations. Yet EPA's ambitious schedule requires that every scrubber project be completed by 2014, not just a hypothetical "average" project. [EPA-HQ-OAR-2009-0491-2868.1,p.17]
National Rural Electric Cooperative Association (NRECA)
For example, EPA modeled that units are capable of higher to lower sulfur bituminous coal switching by the 2012 compliance deadline. Presuming, as EPA does, CATR rule finalization in mid-2011, units would have about six months to switch coals, alter transportation contracts, and potentially upgrade ESPs. EPA has failed to provide any actual data to support these presumptions. No information is available in the docket regarding actual capabilities to break existing contracts including financially absorbing resulting penalties for contract breaches, to acquire new coal transportation from the low sulfur bituminous mining regions, or to evaluate actual necessary time to study and install any needed ESP upgrades. Further, EPA assumes unit coal switching from high to very low sulfur subbituminous coal is viable if the unit has demonstrated that capability in the past. Again, EPA has provided no information to this supposition or to explain what it determines is adequate for demonstration. Is a onetime burn at the unit adequate demonstration? Is a burn with coal blending adequate demonstration? What information has EPA utilized regarding transportation contracts and availability? What about costs? [EPA-HQ-OAR-2009-0491-2723.1, p.6]
Similar problems are inherent in many of EPA presumptions regarding installation of FGDs and SCRs in a time to meet 2014 deadline mandates. For example, EPA believes that 14 gigawatts (GWs) of FGDs can be planned and installed is 30 months from CATR finalization to the 2014 compliance date. The proposal provides no background or indication that EPA has considered relative increased difficulties inherent in this next round of FDG retrofits, i.e. the more retrofits within the existing coal-fired generating fleet the harder, more time consuming and less cost effective they are. [EPA-HQ-OAR-2009-0491-2723.1, p.7]
Additionally, EPA has apparently not analyzed the additional material resources and skilled labor required in connection with other regulations the agency has proposed or may soon finalize that will compete with CATR resource and labor needs, thereby quite probably affecting timely installation of the approximately 28 additional FGDs by 2014.8 For example, EPA has recently proposed the Industrial Boiler maximum achievable control technology (MACT) Rule less than 60 days before the proposed CATR publication. According to that proposal, more than 1,000 coal and biomass units among other types will be affected by a final MACT Rule requiring similar emissions control technologies as required with the CATR. Relying on statutory timetables for MACT implementation, affected units under a final Industrial Boiler MACT Rule would be retrofitting units with required controls during time periods that coincide with those associated with CATR emissions control installation, thus competing with demands for similar resources required for CATR compliance. EPA needs to evaluate MACT and other rulemaking requirements on abilities of affected CATR units to meet their obligations within the proposed compliance periods. [EPA-HQ-OAR-2009-0491-2723.1, pp.7-8]
NRECA's concerns with the 2014 deadline and associated modeled emission reductions presumptions are similar to those outlined above for the 2012 deadline. Many units modeled by EPA to undertake and complete necessary retrofits by the 2014 deadline will not be able to accomplish the task. Accordingly, at a minimum EPA should extend the 2014 compliance deadline by at least one year to rationally accommodate emissions reduction requirements. [EPA-HQ-OAR-2009-0491-2723.1, p.8]
Footnote 8: The proposal assumes an additional 14 GWs of FGDs. Assuming an average commercial-sized affected coal-fueled unit at 500 MWs, the proposal would require 28 separate FGD installations. [EPA-HQ-OAR-2009-0491-2723.1, p. 7]
As a matter of substance, the NODA appears to be incorporating the same compressed 2012 and 2014 timelines that, as pointed out in our CATR comments, are unrealistic given the proposed emissions reduction goals. [EPA-HQ-OAR-2009-0491-3756.1_NODA, p.1]
Nelson Industrial Steam Company (NISCO)
IV. Comments on Effective Date of the Rule
NISCO is concerned with the nearly immediate effective date of the rule. EPA has suggested it will promulgate a final rule in late spring 2011 and it will become effective January 1, 2012. This is obviously unreasonable considering the costly impact to affected facilities. It is unreasonable to expect a facility to engineer, procure, and install controls in six months or even budget for purchasing additional allocations. [EPA-HQ-OAR-2009-0491-2813.1, p.12]
North Carolina Department of Environment and Natural Resources
Vendors and contractors specialized in the design and construction of 502 scrubbers and SCRs can more appropriately comment on and provide inputs on this issue. But, empirically, it can be said that it would be hard for the suppliers to provide their services (design and construction) at the same time to every owner/operator of power plant for installation of scrubbers and SCRs. For example, it is hard to imagine if many scrubbers are required to be Installed to comply with January 1, 2014 date in Group 1 States, whether there are enough qualified  suppliers available to design and construct this kind of scrubbers to meet this deadline. [EPA-HQ-OAR-2009-0491-2767.1 p.6]
Northern Indiana Public Service Company (NIPSCO)
NIPSCO agrees with EPA's acknowledgement in the preamble that the 2012 and 2013 timeframe does not allow companies enough time to install pollution control technologies. The 2014 timeframe does not allow enough time to complete projects needed to achieve required reductions, and is limited to projects that are already well in the planning cycle. [EPA-HQ-OAR-2009-0491-2747.1 p.10]
NRG Energy
An extension of the Group 1 second compliance deadline EPA is proposing a second compliance deadline in 2014 based on the assumption that "it takes about 27 months to install a scrubber and 21 months to install an SCR." While it may be possible to install a scrubber or SCR within these timeframes, it is not enough time to conduct engineering, obtain any required construction and/or operation permits, and go through the bid process. This is further complicated by the scheduling challenges of multiple controls at a single plant or multiple facilities in a single region and the construction of replacement generation to supplant coal retirements. In addition, NRG recommends that EPA carefully consider not only the challenges of multiple retrofits, but also the timing and implementation of the impending suite of rules that will impact EGUs. In short, an extension is warranted to maintain an orderly and efficient transition to new and cleaner generation. [EPA-HQ-OAR-2009-0491-2749.1, P. 5]
Occidental Chemical Corporation (OCC)
Compliance Deadline The scope of the proposal and required compliance activities are complex and may require the development of projects and capital expenditures. If the final rule is issued in 2011 and emission reductions are required in 2012, there is not sufficient time for a regulated entity to assess and plan future production, identify projects for compliance, and implement compliance activities. Respectfully, a 3-year compliance schedule should be provided in the final rule.[EPA-HQ-OAR-2009-0491-2754.1, p. 28]
Ohio Coal Association
:: The compliance deadlines are not reasonable and do not take into account the significant lead time necessary for electric power generators to consider, plan, design and construct necessary control equipment. Additionally, it is unreasonable for EPA to move towards a 2012 implementation deadline while EPA continues to contemplate changes to the Transport Rule and additions to the NODA. [EPA-HQ-OAR-2009-0491-2743.1, p.2]
Ohio Manufacturers Association (OMA)
The short timeline also makes it virtually impossible for power generators to design, permit, build and install new equipment that will likely be needed to satisfy the 2014 pollution reduction benchmarks. [EPA-HQ-OAR-2009-0491-2651.1, p. 1]
Ohio Utility Group (OUG)
The compliance deadlines are infeasible [EPA-HQ-OAR-2009-0491-2679.1, p.5]
EPA maintains that the Transport Rule's two phases of emissions reductions will help there remaining nonattainment areas reach attainment by their assigned deadline. 13 As such, EPA's emissions reductions deadlines under the Transport Rule - the latest being May 1, 2014 - are set to precede the NAAQS attainment deadlines - the earliest being April 2015. The unreasonableness of EPA's proposal is highlighted by the fact that EPA previously declared such a timeline unfeasible 'based on engineering and financial factors." What was impracticable then cannot be practicable now. [EPA-HQ-OAR-2009-0491-2679.1, p.5]
EPA attempts to rectify the discrepancy illustrated above by determining that a flue gas desulfurization unit takes approximately 27 months to build, while a selective catalytic reduction unit takes only 21 months. IS The Utilities assert that such a timeline is unrealistic. If state budgets are not reevaluated, the Utilities suggest that extending implementation deadlines is a necessity. [EPA-HQ-OAR-2009-0491-2679.1, pp.5-6]
In their own comments, AEP went into great detail about how long it takes to engineer, construct, and install the control technology that will be necessary to comply with the proposed Transport Rule. The OUG wishes to highlight some of AEP's real-world experiences and conclusions: [EPA-HQ-OAR-2009-0491-2679.1, p.6]
:: Engineering and construction of the FGD system takes up to 52 months to complete [EPA-HQ-OAR-2009-0491-2679.1, p.6]
:: The FGD-corresponding landfill takes 54 months on average to complete [EPA-HQ-OAR-2009-0491-2679.1, p.6]
:: Engineering and construction of the SCR systems takes up to 42 months to complete [EPA-HQ-OAR-2009-0491-2679.1, p.6]
Switching coal is not a viable option [EPA-HQ-OAR-2009-0491-2679.1, p.6]
EPA's response to curbing emissions in a timely manner is for sources to switch to low sulfur coal by 2012. The Utilities assert a two-prong objection to the fuel switch. First, the Transport Rule is to be based on technological feasibility and development. Switching coal is not a technology-based rationale. [EPA-HQ-OAR-2009-0491-2679.1, p.6]
In addition to engineering complications, switching coal raises permitting issues. For example, combustion of sub-bituminous coal would violate the Title V permits for DP&L's Stuart and Killen Stations, which specify the use of bituminous coal. Furthermore, these stations have a 25+ year history of burning only bituminous coal, DP&L has no operating experience with sub-bituminous coal, and DP&L has no plans to bum sub-bituminous coal. [EPA-HQ-OAR-2009-0491-2679.1, p.6]
Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
On May 11, 2006, OVEC announced its plan to retrofit its entire fleet with FGD. See May 11, 2006 Press Release, attached. At that time, the estimated cost of the retrofit was approximately $820 million, and the expected efficiency 'as much as 98%.' Id.The FGD system selected was a Chiyoda Jet Bubbling Reactor - a technology that to the best of OVEC's knowledge has only recently been installed on a very limited number of coal-fired utility units in the United States. The original target dates for completion of the FGD systems were 2009 for Kyger Creek and 2010 for Clifty Creek. [EPA-HQ-OAR-2009-0491-2803.1, p.3]
In December 2008, OVEC announced an indefinite delay in the construction of the FGD at Clifty Creek due to the severe downturn in the national economy and the uncertainty of obtaining the capital funding necessary to complete the project. See December 17, 2008 Press Release, attached. At the time, the Clifty Creek project was approximately 35% complete. It should be noted, however, that most of the parts and prefabricated equipment to complete the FGD project had already been purchased and continued to be delivered to the site and placed in storage. In addition, work on the landfill upgrade and other material handling facilities associated with the Clifty Creek FGD project was never halted and is currently continuing. However, given the continued harsh economic circumstances and scrubber design problems (explained below), Clifty Creek will not have FGD installed by January 1, 2012. The current estimated completion date for Clifty Creek to be fully retrofitted is mid-2013. [EPA-HQ-OAR-2009-0491-2803.1, p.4]
While construction continued on the FGD at Kyger Creek, very serious problems surfaced with the scrubber design and the materials being used. If not effectively addressed, the problems would severely impact the reliability and 802 removal efficiency of the scrubbers. See March 17, 2009 Press Release, attached. OVEC delayed the tie-in of the FGD system until a full engineering analysis could be performed and a solution to the problems could be found. OVEC is still working on these issues, and the current estimated completion date for Kyger Creek to be fully retrofitted is mid-2012. [EPA-HQ-OAR-2009-0491-2803.1, p.4]
It is important to note that, while OVEC is diligently working on all of the issues surrounding the delay of the FGD retrofit, all of the projected installation dates are subject to change due to the uncertainty with the scrubber design deficiencies. OVEC also does not know how long it will take for the operation of the FGDs to be optimized and achieve expected operating performance, particularly given the lack of industry experience with the Chiyoda Jet Bubbling Reactors. While the initial press release stated that the scrubbers could achieve 'as much as 98%' removal, that number is not a continuous, everyday, lifetime average expected removal efficiency. [EPA-HQ-OAR-2009-0491-2803.1, p.4]
Oklahoma Department of Environmental Quality
This rule may prove difficult to comply with both financially and with regard to physical/engineering constraints. From a financial standpoint, some companies may not have the capital to pay for the installation of controls in the short time frame allowed. Physically, while the installation of some controls may be possible within the time constraints, some units may not be able to physically accommodate the control equipment without major modifications. Additionally, the installation of controls will require that units be shut down. To install the controls likely to be required to ensure compliance on all of the units needed to generate sufficient excess allowances in all of the covered states, multiple units are likely to have outages at the same time, and rolling blackouts could result. Outages will mean that companies will be forced to purchase power over the grid to provide to their customers, at a substantial cost to the company, which cost will be passed on to the customers. That said, we are supportive of the public health benefits that will occur if this rule is implemented. However, we would urge EPA to reconsider the implementation timetable and consider a more phased in approach that will garner the public health benefits with a less burdensome financial impact to the public.[EPA-HQ-OAR-2009-0491-2662.1, p. 1]
Old Dominion Electric Cooperative
For example, EPA modeled that units are capable of switching from higher to lower sulfur bituminous coal by the 2012 compliance deadline , ld. at 45,273. Presuming, as EPA does, the Transport Rule fìnalization in mid 2011, units would only have approximately six (6) months to switch coals, alter transportation contracts, and potentially upgrade particulate controls. This approaches physical impossibility and leaves absolutely no room for any sort of contingency planning on the part of the utilities. EPA has failed to provide any actual data to support these presumptions. No information is available in the docket regarding actual ability (1) to break existing contracts including resulting penalties for contract breaches, (2) to acquire new coal transportation from the low sulfur bituminous mining regions, or (3) to evaluate actual necessary time to study and install any needed particulate controls upgrades. Further, EPA assumes unit coal switching from high to very low sulfur subbituminous coal is viable if the unit has demonstrated that capability in the past, Id. Again, EPA has provided no information to this supposition or to explain what it considers as adequate for demonstration. Adequacy should never be contingent upon a single test point. ODEC requests that EPA outline the specific information used with regard to transportation contracts, supply availability, and costs. [EPA-HQ-OAR-2009-0491-2877.1,p.4]
Similar problems are inherent in many of EPA's presumptions regarding installation of flue gas desulfurization units (FGDs) and selective catalytic reduction units (SCRs) in time to meet 2014 deadline mandates. For example, EPA believes that 14 GWs of FGD's can be planned and installed in 30 months from the Transport Rule finalization to the 2014 compliance date, Id. at 45,273. The proposal provides no background or indication that EPA has considered relative increased difficulties inherent in this next round of FGD retrofits, i.e. the more retrofits within the existing coal-fìred generating fleet, the harder and more time consuming and less cost effective the process becomes. Additionally, EPA has apparently not analyzed the additional material resources and skilled labor required in connection with other regulations the agency has proposed or may soon finalize. This will no doubt create competition for these additional resource and labor needs, thereby likely affecting timely installation of the pollution control equipment. [EPA-HQ-OAR-2009-0491-2877.1,p.5]
EPA should also consider that the pollution control vendors will be working with the utilities with the largest number of facilities needing upgrades. This will significantly reduce the ability to procure materials and acquire skilled trade labor for the smaller utilities (cooperatives and municipalities) that own fewer power stations. These smaller utilities may be put at an even greater disadvantage in meeting the 2012 and 2014 deadlines. [EPA-HQ-OAR-2009-0491-2877.1,p.5]
ODEC's concerns with the 2014 deadline and the associated modeled emission reductions presumptions are similar to those outlined above for the 2012 deadline. Many units modeled by EPA to undertake and complete necessary retrofits by the 2014 deadline will not be able to accomplish the task. Accordingly, at a minimum, EPA should extend the 2014 compliance deadline at least one year to rationally accommodate emissions reduction requirements. [EPA-HQ-OAR-2009-0491-2877.1,pp.5-6]
Owensboro Municipal Utilities (OMU)
The Schedule for Meeting Phase I Emission Caps Beginning In 2012 is Unreasonable.
Assuming the final Transport Rule is promulgated less than a year from now (EPA's current schedule is Spring of 20 II), Phase I of the program would allow only about 6-9 months to implement the new emission budgets, establish emission trading programs and make the needed investments to comply with the new emission caps. Having these new emission caps, state budgets and allowance allocations in 2012 creates major logistical challenges for the electric power sector and for the states that must implement the programs. [EPA-HQ-OAR-2009-0491-2811.1,p.2]
While the EPA claims that Phase I will require little investment in the way of new controls, its assumption is predicated upon high-level modeling and not the actual physical, contractual and financial constraints at electric generating facilities during such a short time frame. In reality, implementation of further reductions by a utility will require an engineering analysis for each generating unit, and any analysis must be based on promulgated targets. Until a final rule is in hand, a utility can only establish the framework for securing funding and procurement of the project. [EPA-HQ-OAR-2009-0491-2811.1,p.2]
Peabody Municipal Light Plant
The unit could and has continued to profitably operate on pipeline natural gas with a mix of some diesel oil. The facility intends to operate Unit 2 each year for the foreseeable future (at least through 2012) and at a similar capacity factor as has been observed in recent years. Unit 2 uses water injection for NOx control and a catalytic oxidizer to control CO. It is not reasonable to expect the unit to install additional NOx controls by the year 2012 and therefore emissions should not be adjusted downward to reflect such additional NOx control. [EPA-HQ-OAR-2009-0491-3730.1 p.1]
Pendleton, Mark
I am concerned about the the timing required in the rule. From the time the rule would become effective until the second phase of reductions are to begin is barely two-and-a-half years -- not nearly enough time for power companies to install the needed equipment. [EPA-HQ-OAR-2009-0491-1596, p.1]
Pfeiff, Mike
16. Unrealistic Implementation Schedule - Requiring affected sources to be in compliance by January 1, 2012 is nothing short of a fantasy. Not only is the proposed implementation period unrealistic from a technical standpoint but it is also unrealistic from an administrative standpoint. Many other commenters' have already provided comments on the technical limitations of the implementation schedule so I will not regurgitate those reasons here. [EPA-HQ-OAR-2009-0491-2742.1, p.12]
PPG Industries, Inc.
Comments on Effective Date of the Rule. Additionally, PPG is concerned with the nearly immediate effective date of the rule. EPA has suggested they will promulgate a final rule in late spring 2011 and it will become effective January 1, 2012. This is obviously very unreasonable considering the costly impact to affected facilities. It is beyond reason to expect a facility to engineer, procure, and install controls in six months or even budget for purchasing additional allocations. [EPA-HQ-OAR-2009-0491-2763.1, pp. 18-19]
PPL Corporation
7. Implementation Schedule
The proposed rule's implementation schedule of 2012 is very optimistic and not practical. [EPA-HQ-OAR-2009-0491-2739.1, p.9]
Public Utilities Commission of Ohio
While we applaud the efforts of EPA to create and support a model that provides the states and the regulated community with flexibility, we believe that the implementation schedule and regulatory framework proposed is unfortunately unworkable. EPA states in the proposed rule that in a best case scenario it takes about 27 months to install a flue-gas desulfurization scrubber and 21 months to install a selective catalytic reduction system to control NOx emissions. However, historically, in situations other than the best case scenarios the proposed rule assumes, three and a half to four years are necessary to build a scrubber. Given this situation, the time frame proposed in the rule is unreasonable for even the construction phase of the project. Potential delay due to complicating circumstances on the front end of any project, combined with the potential for complications during implementation phases, neither which have been contemplated by the proposed rule, also create a significant risk of delay for even the best managed projects. The PUCO feels that it is prudent and necessary to take these potential circumstances into account when developing any hard and fast timetable for implementation of a proposed rule. Accordingly, we ask EPA to reconsider its time frame for implementation of the Transport Rule. [EPA-HQ-OAR-2009-0491-2855.1 p.13]
In addition to the circumstances already set forth, other situations arise when pollution control equipment is being developed and assembled. Special stack liners typically need to be made "on-site." They are usually made of fiberglass. The impact of this is that a maximum achievable control technology (MACT) applies to the process, and Ohio can only enforce this MACT standard via a permitting process. [EPA-HQ-OAR-2009-0491-2855.1 p.14]
The proposed rule allows no time for companies or the states to develop implementation plans. Further, other regulatory steps, such as public utility commission approvals and environmental permitting, unfortunately seem to have been brushed aside in the development of the timetable for implementation of the rule. We urge EPA to take these routine, yet sometimes time-consuming matters into account when revisiting the implementation timeframe. [EPA-HQ-OAR-2009-0491-2855.1 p.14] [[These comments can also be found in Section VII.C.]]
RRI Energy, Inc.
The proposed Phase 2 implementation date (reduction in SO2 emissions budgets for the Group 1 states) must be changed from January 1, 2014 to January 1, 2015.
RRI understands that one of EPA's primary goals of the proposed CATR is to provide for a smooth transition from the existing programs, and RRI fully supports this goal. However, a Phase 2 implementation date of January 1, 2014 is not in accordance with this goal, and consequently the Phase 2 implementation date needs to be changed from January 1, 2014 to January 1, 2015 as outlined below. [EPA-HQ-OAR-2009-0491-2717.1 p.2]
Existing EGUs with a nameplate generating capacity greater than 25 MWe are currently subject to the requirements of the Clean Air Interstate Rule (CAIR), and these units will be subject to the final CATR beginning January 1, 2012. CAIR Phase 1 NOx and SO2 emission reductions were implemented beginning January 1, 2009 and January 1, 2010, respectively. Additional SO2 emissions reductions under CAIR Phase 2 were due to become effective on January 1, 2015. Planning and construction of emissions control devices such as a flue gas desulphurization (FGD) system require several years to complete the required activities (i.e., engineering design, bidding, budgeting, final engineering design, project approvals, financing, permitting / licensing, scheduling, construction and initiation of operations). Existing EGUs subject to CAIR have been planning future (nominally five year projections) operations in part in accordance with the requirements and implementation schedule under CAIR Phases 1 and 2. An acceleration of the Phase 2 SO2 emissions reductions simply can not be accommodated without subjecting the applicable EGU to substantial disruptions in the financial and operational plans. Note that EPA has identified that there are approximately 30 months between mid-2011 (expected promulgation of the final CATR) and January 2014 (implementation of proposed CATR Phase 2), which EPA believes is sufficient period of time to construct an FGD system (nominally 27 months based on EPA's analysis). However, even if all of the engineering design work is completed by mid-2011, EPA's analysis inexplicably omits the time required to obtain a permit from the local regulatory agency to construct such an FGD system. It is RRI's recent experience that regulatory agencies require at least six months and more typically one year to complete their review of FGD construction permit applications and issue the permits required (likely longer now because of the increased burden of applications and requests upon the agencies and decrease in available resources within the agencies). Consequently, EPA must change the implementation schedule for the proposed CATR Phase 2 SO2 emissions reductions from January 1, 2014 to January 1, 2015 to allow sufficient time to complete all activities associated with the planning and construction of emissions control devices such as an FGD system.[EPA-HQ-OAR-2009-0491-2717.1 p.3]
A January 1, 2015 CATR Phase 2 implementation date would allow applicable EGUs to synchronize their SO2 emission reductions with reductions in emissions of hazardous air pollutants (HAPs) expected through the promulgation of the MACT standards for coal and oilfired EGU boilers. Compliance with the MACT standards is currently projected to be due by November 2014. It is expected that installation and operation of emission control systems for acid gas HAPs will also yield co-beneficial reductions in SO2 emissions. Lastly, because of the logistical constraints associated with the expected installation of acid gas / SO2 emission control devices in the upcoming years, it is likely that these control devices will become operational over an extended period of time (e.g., mid-2013 through November 2014). Consequently, SO2 emissions reductions will also occur during that time period, which should result in decreases in ambient PM2.5 concentrations sufficient to demonstrate attainment with the (i) 1997 PM2.5 NAAQS (annual standard) by the April 2015 maximum attainment deadline and (ii) 2006 PM2.5 NAAQS (24-hour standard) by the December 2014 deadline. Areas unable to meet the December 2014 deadline may seek a maximum 5-year extension to 2019. [EPA-HQ-OAR-2009-0491-2717.1 p.3]
San Miguel Electric Cooperative, Inc.
 The proposed 2012 and 2014 compliance deadlines and associated emissions reductions are unrealistic and are not supported by real world assumptions.  [EPA-HQ-OAR-2009-0491-2641.1, p.6]
Southern Company
In addition to the methodological flaws, Southern Company believes that the Proposed Transport Rule compliance dates of 2012 and 2014 are unreasonable and unjustified. EPA should not seek a compliance date any earlier than 2015. [EPA-HQ-OAR-2009-0491-2864.1, p. 6]
The proposed compliance schedule is problematic since most states, if not all, will not have time to develop a SIP alternative to replace the FIP proposed by this rule; utilities will be faced with the extremely difficult task of developing and implementing several entirely new allowance strategies from unknown new allowance markets; implementation of fuel switching or the installation of new emission controls will be difficult if not impossible; and the compliance dates are uncoordinated with expected EPA regulations and are disruptive to compliance planning. [EPA-HQ-OAR-2009-0491-2864.1, p. 6] [[The SIP comment can also be found in Section VII.C.]]
III. The Proposed Compliance Deadlines are Unreasonable, Unnecessary, and Disruptive to Compliance Planning
even implementing fuel switching or installing low NOx burners at a facility will be virtually impossible. Furthermore, coal procurement strategies, fuel inventory levels, and the system dispatch procedures, which are carefully planned over the long term, may be negatively impacted and may not be able to be adjusted in such a short time frame. [EPA-HQ-OAR-2009-0491-2864.1, pp. 8-9] [[These comments can also be found in Section VII.C.]]
A later compliance date (no earlier than 2015) will allow states to exercise their right to develop their own SIP, something many states, including Alabama, Mississippi, and Georgia have expressed a desire to do. [EPA-HQ-OAR-2009-0491-2864.1, p. 9] [[This comment can also be found in Section VII.C.]]
B. EPA Should Discard the 2014 Compliance Date
The January 1, 2014 compliance deadline is only about 30 months after the expected final Transport Rule, which is an insufficient amount of time to install Selective Catalytic Reduction (SCR) for NOx control or Flue Gas Desulfurization (FGD) for S02 control. Even if these controls could be built by 2014, in some states, large investment decisions must be approved through the state Public Service Commission (PSC) processes. [EPA-HQ-OAR-2009-0491-2864.1, p. 9]
Furthermore, the 2014 compliance date does not represent a coordinated approach with the numerous other upcoming environmental regulations affecting the power sector such as future Transport Rules, Clean Air Act Section 112(d) standards (i.e., IB and EGU MACT), New Source Performance Standards (NSPS), Best Available Retrofit Technology (BART) requirements, Greenhouse Gas (GHG) regulations, as water and ash regulations. Indeed, EPA has acknowledged the numerous upcoming regulations in the Proposed Transport Rule and EPA has stated its intent to coordinate these rules with the 'goal of fostering investments in compliance that represent the most efficient and forward-looking expenditure of investor, shareholder, and public funds.' Despite EPA's stated intent, the proposed Transport Rule compliance deadlines are not being coordinated with the other upcoming regulations and fail to accommodate the need for coordinating important compliance planning and investment decisions. In the midst of all the uncertainty of the upcoming environmental regulations and the impacts of those rules on the investment decisions, it is difficult for the utilities and the PSCs to determine the best path forward from both a customer and business perspective. [EPA-HQ-OAR-2009-0491-2864.1, p. 9]
In fact, the 2014 compliance deadline is disruptive to the compliance planning of companies, which were planning for a CAIR Phase II deadline of 2015 and adds costs for little if any overall environmental benefit beyond what CAIR would have accomplished in either Phase I as discussed above or in Phase II (2015) (see Section N). Because no additional controls can be built before 2014, the proposed Transport Rule requirements in 2014 will greatly increase the compliance cost for utilities (in terms of allowances) over CAIR and the 'hard' caps may present a reliability concern. Therefore, EPA should not require a compliance date sooner than that of CAIR Phase II (2015). [EPA-HQ-OAR-2009-0491-2864.1, p. 9]
A compliance date any sooner than 2015 is unreasonable since: 1) new emission controls cannot be built in 30 months; 2) companies cannot make important compliance planning and investment decisions without regulatory certainty and coordination; and 3) the existing CAIR program is achieving and expected to achieve the similar benefits to the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2864.1, p. 10]
VI. EPA's Control Installation Assumptions are Flawed
In the proposed Transport Rule EPA states that it takes approximately 27 months to install a single Flue Gas Desulfurization (FGD) system and 21 months to install a single Selective Catalytic Reduction (SCR) system. 9 The agency further believes that 30 months between the final rule and compliance is sufficient time to install such controls. 10 In developing its timelines, EPA used only two facilities as the basis for its FGD timeline (2 Units at Big Bend Station and 2 Units at Centralia) and two facilities for its SCR timeline (1 unit at Somerset Station and 2 units at Keystone))). As discussed below, EPA's examples and assumptions about FGD and SCR time frames are neither representative nor common. Southern Company's historical experience has shown that it takes an average of 54 months to install an FGD and 36 months to install an SCR. These timelines include all of the steps necessary to plan, design, construct and start up an FGD or SCR system on an existing unit. Although our individual project schedules vary depending on site-specific factors and requirements, none of our FGD or SCR installations have occurred in the timeframes that EPA suggests. Further, none of our FGD or SCR installations were completed within the 30 months that EPA proposes to allow before the 2014 Transport Rule compliance date. [EPA-HQ-OAR-2009-0491-2864.1, p. 13]
In summary, EPA has greatly underestimated the amount of time that it takes to design, permit, construct, and start up new FGDs and SCRs. It will take longer than 30 months -- in some cases significantly longer than 30 months -- to complete the retrofits of FGD and SCR units at existing EGUs. While considering a compliance date no earlier than 2015, EPA must also update its control installation assumptions taking into account 1) a larger and more recent representation of installations-taking into consideration that quick installations can result in post-commercial problems; and 2) changes in the regulatory landscape since the adoption of CAIR and pending regulations for water and ash management that increase the likelihood of control installations requiring permitting; and 3) schedules that represent the installation of multiple controls at a facility at the same time. [EPA-HQ-OAR-2009-0491-2864.1, p. 20]
[See EPA-HQ-OAR-2009-0491-2864.1, pp. 13-20 for extensive discussion of control installation and schedules.]
VII. EPA's Fuel Switch Assumptions Are Flawed
EPA made the assumption that coal switching within the bituminous coal grades will have relatively little cost or schedule impact on most units and has requested comment on this issue. EPA's assumption is flawed because coal switching occurs over a longer timeframe than EPA has assumed; this is due to how coal purchases are layered in over time, the time it takes for plants to tune operations to the new fuel as well as the ability of the coal market to accommodate such a large switch as has been assumed. Currently, about two-thirds of Southern Company's required coal supply for 2012 is under contract; and this percent will likely increase prior to issuance of the final Transport Rule. Because of the layering approach that is common in the industry, new long-term contracts are negotiated well before existing contracts expire. Southern Company's coal procurement evaluations and decisions factor in the current and/or projected value of sulfur, which will necessarily change after the final Transport Rule is issued and new SO2 allowances enter the market. Because the allowance price discovery for SO2 will not be possible until the second half of 2011 at the earliest, the lead time to assess true costs of procurement decisions for 2012 and beyond will be severely limited. (A spring 2011 Long Term purchase may include purchases not only for 2012 but potentially for 2013,2014, and 2015, etc). Although coal contracts typically include clauses allowing us to be released from our contractual obligations in the event of a significant regulatory change, these clauses are narrow in nature and could not be relied on to release the Company from the obligation to purchase a large number of contracted tons. Exercising such a clause could be costly, time consuming, and potentially detrimental to coal producers. Of additional concern are rail and barge transportation contracts which are negotiated independently from coal contracts and would have to be revised or terminated on an extremely short time frame if the coal supply associated with those agreements is reduced or eliminated. This could also prove to be a costly and inefficient process. Furthermore, cancelling contracts of this magnitude invites protracted and expensive litigation. [EPA-HQ-OAR-2009-0491-2864.1, p. 21]
Even the most straightforward coal switches can take well over a year to implement. A typical timeline for a 'simple' coal switch would follow the steps below:
1. 4 - 6 months to procure test fuel; (4 - 6 months cumulative) 2. 1 - 4 months test bum; (5 - 10 months cumulative) 3. 2 - 3 months data evaluation; (7 - 13 months cumulative) 4. 2 - 6 months to procure first production fuel; (9 - 19 months cumulative) 5. 2 - 6 months for delivery of production fuel; (11 - 25 months cumulative) 6. 3 to 5 years for existing contracts to expire and achieve 100% switch (47 - 85 months cumulative) [EPA-HQ-OAR-2009-0491-2864.1, p. 21]
Furthermore, EPA's assumption that national coal markets can shift large volumes of production from higher sulfur grades to lower sulfur grades by 2012 is unreasonable and impractical. First, mine operators are currently reeling from the recession, and many cannot absorb additional costs associated with shutting-in existing production sites and opening new sites or expanding existing sites. Second, lead times, costs and regulatory challenges associated with permitting and starting operations at new mines or increasing production at existing mines may be insurmountable by 2012. And lastly, the ability for transportation infrastructure and capacity to absorb large volume swings in such a short time frame is uncertain. EPA's assumptions indicate that it believes the power, transportation, and coal industries can stop and tum their operations on a dime. These assumptions reveal EPA's complete lack of appreciation for the scale of these operations and the complex, long-term planning these industries must employ. [EPA-HQ-OAR-2009-0491-2864.1, pp. 21-22]
Southern IL Power Cooperative
Requiring coal-fired power plants to construct additional pollution control equipment and have it operational by 2012 to 2014 is not feasible. Manufacturing lead times for much of this equipment would be eight to twelve months within a normal business time, but for such a volume of equipment that would be required to meet the demands of the proposed rule, lead times would certainly be extended. Similarly, sufficient quantities of skilled labor to install such equipment would be difficult to obtain and still meet the 2012 to 2014 deadlines. [EPA-HQ-OAR-2009-0491-2863.1 p.2]
State of Delaware Department of Natural Resources & Environmental Control
An EGU Cap-and-Trade Program alone is not sufficient to mitigate a states impact on downwind states. Delaware understands the bottom line of the EPA proposal is that the control of EGUs is all that is needed in order for a state to mitigate its significant impact on downwind states. This conclusion is inconsistent with much of the information Delaware has learned in its efforts to address the ozone problem over the past 40 years, and the more recent fine particulate matter problems. The installation of all reasonably available control technology (RACT) on all volatile organic, nitrogen oxide, and sulfur dioxide emitting sources is needed. In addition, advanced best available control technology (BACT) level controls on EGUs and other large sources stationary sources is needed. And, based on Delaware's experience the timing associated with the design, permitting and construction of advanced emission controls on EGUs is relatively short; on the order of 24-months. If upwind states were to implement these measures (i.e., RACT on all sources, and BACT on all large stationary sources), as Delaware already has, attainment of the current and upcoming ozone and PM2.5 NAAQSs would be in reach. Delaware believes these measures must be added as required elements of this proposal. [EPA-HQ-OAR-2009-0491-2980.1, p.10]
State of Louisiana, Department of Environmental Quality
EPA has based compliance deadlines on the basis of 'time necessary for installation' of control technology. While LDEQ agrees that the equipment necessary to achieve emission reductions can indeed be installed within this time frame, LDEQ disagrees that the compliance deadlines are achievable. These facilities schedule major 'outages' on a rolling 5-year basis and cannot arbitrarily shut a unit down to install control technology without having back-up power sources. Additionally, it is infeasible for all units to shut down simultaneously so that controls can be installed prior to the unreasonable compliance dates imposed by the rule. Further, owners or operators must apply for and secure any necessary authorizations from their respective permitting authorities before modification of affected sources may commence. [EPA-HQ-OAR-2009-0491-2655.1, p.5]
State of Ohio Environmental Protection Agency (Ohio EPA)
b. Ohio EPA is concerned with the 'one size fits all' approach by which U.S. EPA assumes all sources can install controls or perform fuel switching. U.S. EPA must provide an implementation schedule that is reasonably achievable considering the ramifications for not complying. [EPA-HQ-OAR-2009-0491-2793.2, p. 2]
U.S. EPA believes that sources have sufficient time to install the advanced emissions controls that will be necessary to meet the proposed allocations. However, Ohio EPA believes this will be quite challenging if not impossible for a number of Ohio sources. For example, U.S. EPA assumes that Beckjord Unit #6 will install a scrubber by 2014. However, this unit's location lacks available surrounding land for a scrubber installation, which thereby would necessitate a 'custom fit'. While three years (from final rule effective date) may be plausible for an ideal situation, in the Beckjord situation three years will not provide enough time for the necessary planning and installation. As another example, the unit at the Zimmer plant already has a scrubber (installed in 1991) with an original design efficiency of approximately 91 %. Improvements have increased the efficiency of this unit but not to the 98% level assumed in this proposal, and for which the basis of allocations will be made. If a requirement for 98% is still assumed for this unit in the final rule, there would likely be no choice but to dismantle the current scrubber to make room for a new scrubber in exactly the same location. This would not be a 'typical' retrofit and will certainly necessitate more time than this proposal allows, and would be extremely costly in light of the pollution control investment already made at the plant. [EPA-HQ-OAR-2009-0491-2793.2, pp. 2-3]
With respect to the fuel switching which is assumed for some sources, Ohio EPA also believes there may be cases where the 'one size fits all' approach is not appropriate. For example, some sources are contractually bound to yertain fuels which will make fuel SWitching by the deadline impossible. Also, natural gas may not be available at all locations, making fuel switching an impractical control option. [EPA-HQ-OAR-2009-0491-2793.2, p. 3]
Because of the compliance with emissions limitation provisions and assurance provisions, units that can't meet this 'one size fits all' deadline of 2014 may face serious consequences. Therefore, Ohio EPA believes U.S. EPA should reconsider the 2014 deadline''or, alternatively provide additional flexibility, without legal consequences, for sources that are simply unable to install required controls by the deadline. Certainly, due to the limited trading opportunities provided for in the proposed rule, U.S. EPA cannot assume that an owner can just 'trade' to obtain the needed allowances. [EPA-HQ-OAR-2009-0491-2793.2, p. 3]
This proposal requires significant reductions in Ohio of S02 between 2012 and 2014. Ohio's 802 emissions have been declining significantly over the past eight years. In 2002 emissions of 802 were over 1,132,000 tons while in 2009 they were at 600,686 tons. This proposal budgets S02 emissions at 464,964 tons in 2012 and 189,583 tons in 2014, while CAIR had provided for an estimated 2015 budget of 233,464 tons. While many sources are already in the planning and/or construction stages of implementing the installation of scrubbers to address CAIR, this proposal will require significantly more sources to install scrubbers over the next several years. Small emissions budget allocations to a number of smaller units will necessitate retirement or retrofitting with controls. We fully support the comments of the Public Utilities Commission of Ohio (PUCO) regarding reliability concerns and the inability. to install controls in the time frames provided under this proposed rule. [EPA-HQ-OAR-2009-0491-2793.2, p. 3-4]
Texas Mining and Reclamation Association
I. EPA Should Extend the Transport Rule Compliance Dates to Accommodate Pending Federal Standards and State Emission Reduction Target Deadlines.
EPA proposes that the initial phase of emission reductions will begin in 2012 (less than one year after the rule is finalized), requiring sulfur dioxide (SO2) and nitrogen oxide (NOX) reductions in those 31 states covered for the 24-hour and/or annual PM2.5 National Ambient Air Quality Standards (NAAQS) as well as the 8-hour ozone NAAQS.1 A second round of additional SO2 reductions would be required for "Group 1" states in 2014 and EPA is considering additional NOX reductions in a future proposal for the ozone NAAQS (Transport Rule II). [EPA-HQ-OAR-2009-0491-2734.1 p.1]
EPA has set out a number of "Key Guiding Principles" in the preamble of the proposed Transport Rule, one of which is to "Provide [a] Workable Approach for EPA and States." Here, EPA is requesting compliance with the Transport Rule by 2012, a very short compliance timeframe considering the myriad of environmental regulations undergoing review and revision during the next few years, some of which form the basis of the Transport Rule (e.g., 1997 8-hour ozone NAAQS). EPA should consider the breadth of environmental regulations, including but not limited to regulations for hazardous air pollutants, new source performance standards, and greenhouse gas regulations. Failure to consider these ongoing emission reduction efforts by the states and pending regulations does not comport with the Key Guiding Principle to Provide a Workable Approach for EPA and the states. [EPA-HQ-OAR-2009-0491-2734.1 p.3]
 Regulations with a short shelf life do not afford regulated entities sufficient time to request, acquire and implement the necessary control technology to meet the changing standards. The regulated community requires regulatory stability and certainty in order to properly plan and execute capital expenditures required for additional control technology.   [EPA-HQ-OAR-2009-0491-2734.1 p.4]
Tennessee Valley Authority (TVA)
B. Issue: EPA's projection that utilities can meet 2012 NOx caps by installing low NOx burners (LNBs) is unrealistic.  [EPA-HQ-OAR-2009-0491-2782.1, p. 2]
TVA Comment: With the final Transport Rule expected in mid 2011, utilities will have only 6 months to design, permit, procure, and install LNBs or LNB upgrades. Such a short schedule is unreasonable for the installation of LNBs on even a single unit. LNB addition or upgrades require a minimum of a year from project initiation to completion, and can take several years when the work must be aligned with boiler outage schedules. [EPA-HQ-OAR-2009-0491-2782.1, p. 3]
C. Issue: EPA takes the position that it takes approximately 27 months to build a FGD unit and approximately 21 months to construct an SCR unit. [p. 45273] TVA Comment: TVA has extensive experience constructing FGDs and SCRs and has studied this timing issue in depth. TVA's fossil generation system currently operates FGDs on 17 units and SCRs on 21 units. The enclosed report (Attachment 1) [Note that Attachment 1 was not available in the docket at the time of this summary.] entitled Issues Associated with the Acceleration of Tennessee Valley Authority's Clean Air Program, prepared by a TVA expert in conjunction with the nuisance lawsuit (North Carolina v. TVA), sheds light on scheduling issues relating to the construction of FGDs and SCRs. The report states in pertinent part: A typical FGD project installation duration from conceptual design to commercial operation averages 5 years. A typical SCR project installation duration from conceptual design to commercial operation averages 3 to 4 years depending on the size of the unit and complexity with the retrofit installation. There are also schedule implications of the SNCR and SO3 mitigation projects that must be worked in conjunction with the new installation of FGDs and SCRs. TVA is confident in our projections for the time needed to complete FGD and SCR projects, which are based on TVA's actual experience to install FGDs and SCRs on several units, input from Advatech (TVA's FGD partner), benchmarking with other utilities and an extensive program review on cost and schedule conducted by Bechtel Power Corporation. (Executive Summary, p. 5) [EPA-HQ-OAR-2009-0491-2782.1, p. 3]
he above expert report was prepared in February 2007, a period when CAIR was being implemented. The report explains that the scheduling pressures placed on utilities by CAIR have stretched the market capacity for many critical resources. The rigorous schedules of the proposed Transport Rule would place even greater demands since the rule seeks deeper reductions in SO2 and NOx emissions on an accelerated schedule. The schedules assumed by the Transport Rule for construction of SCRs and FGDs are in fact impractical and unachievable. [EPA-HQ-OAR-2009-0491-2782.1, p. 4]
As an example, TVA completed the installation of the FGD on Paradise Fossil Plant Unit 3 in approximately 5 years, considering the time from conceptual design to commercial operations. The actual project schedule for the Paradise FGD is shown as Figure 3 in the attached expert report (Attachment 1, p. 16). Even this schedule may not be achievable at some sites due to space and other site specific constraints. For plants requiring installation of both FGD and SCR, physical site constraints commonly result in sequencing the installations and lengthening schedules approximately 2 years. [EPA-HQ-OAR-2009-0491-2782.1, p. 4]
TVA estimates that it would take 9 to 12 months (and possibly longer) to develop a permit application and obtain a permit for an air pollution control project that has the potential for significant emission increases. The permitting process would add several months to the overall project schedule. [EPA-HQ-OAR-2009-0491-2782.1, p. 4]
Further, permitting and construction of scrubber by-product disposal areas is required for most FGD projects, and for virtually all where the FGD is the first FGD for a particular facility. Typically this work can be completed concurrently with the normal 5 year period for FGD design and construction. If EPA determines, as identified as an option in EPA's proposed Coal Combustion Residuals Rule, that scrubber by-product must be disposed of as hazardous waste in landfills permitted under subtitle C requirements, more time will be required. Subtitle C landfills have often required 6 to 8 years for permitting and construction. Moreover, schedules must also be adjusted to accommodate the permitting process for any modifications to the facility's NPDES permit for the wastewater discharge from the scrubber. [EPA-HQ-OAR-2009-0491-2782.1, pp. 4-5]
s a federal agency, TVA must also comply with the environmental review requirements under the National Environmental Policy Act, Endangered Species Act, National Historic Preservation Act and other environmental statutes prior to undertaking these projects, often resulting in additional time necessary to complete the projects. [EPA-HQ-OAR-2009-0491-2782.1, p. 5]
TVA and other utilities have many older, smaller coal fired units, some of which may not be economical to control and operate in the future in light of anticipated air, water, and waste regulatory regulations. As a result, TVA is evaluating plans to idle a portion of its coal fleet. Additional gas-fired and nuclear generating units on the TVA system or elsewhere will be required to replace much of this idled capacity. These new cleaner units would in effect be constructed in lieu of constructing controls on some of the idled units. For example, TVA is currently constructing two new gas fired units at its existing Lagoon Creek Plant in Tennessee. For such natural gas units at an existing site, the project duration from air permitting to commercial operation is approximately three years. Gas fired units at greenfield sites would take significantly longer to complete. The overly stringent schedule in the proposed Transport Rule does not allow for such conversions from coal to cleaner fuel. [EPA-HQ-OAR-2009-0491-2782.1, p. 5]
The controls and new capacity required over a 31 state region to comply with the proposed Transport Rule will require a significant increase in skilled labor, manufacturing, and material resources for the construction of pollution control equipment and will cost billions of dollars. We anticipate schedule impacts and cost increases due to resource constraints. Unit outages for controls installations must be staggered and avoid peak demand seasons to ensure reliability. With the final Transport Rule expected in mid 2011, the earliest that construction of the required FGDs, SCRs, and new gas fired units could be achieved is 2016. The resource and schedule constraints described above, including permitting and environmental review, may result in even later completion dates for many pollution control projects. [EPA-HQ-OAR-2009-0491-2782.1, p. 5]
D. Issue: The compliance deadlines in the proposed Transport Rule are unreasonable and unrealistic. [EPA-HQ-OAR-2009-0491-2782.1, p. 5]
In the event that EPA promulgates a Transport Rule that requires the level of emission reductions set out in the proposal, the compliance date should be no earlier than 2016. As indicated in our other comments, utilities will need time at least until 2016 to install the controls necessary to achieve these reductions. [EPA-HQ-OAR-2009-0491-2782.1, pp. 4-5] [[This comment can also be found in Section VII.C.]]
U.S. Congressman Pete Hoekstra
The over-riding concern of 'why push this rule through so fasf is paramount. A compliance deadline of 2012 does not leave much time after the anticipated final rule is promulgated in 2011 to determine a cost effective, cost stable method of operating our affected unit. [EPA-HQ-OAR-2009-0491-3662, p.2]
we energies
Schedules for the construction of selective catalytic reduction (SCR) and flue gas desulfurization (FGD) units are assumed by EPA to be 21 and 27 months, respectively. These are unrealistic schedules and do not reflect the reality exhibited by combined SCR and FGD installations at two plants owned by We Energies. It is unclear if EPA's proposed schedules included the up front planning and regulatory approval time frames for such projects. This timeframe alone can be in excess of 12 months. [EPA-HQ-OAR-2009-0491-2629.1, p.4]