MOG and its Industrial Modeling Coalition commissioned Alpine Geophysics to perform regular CAMx simulations that examined a 2008 base case along with as business as usual case for 2014 and 2018. In this exercise, the business as usual case takes the correct legal interpretation of the final order of the DC Circuit Court of Appeals in the CAIR case that the rule is still fully in effect as promulgated until such time as USEPA corrects the errors the court found in that rule. In examining that modeling, the results show similar or better results than the Proposed Transport Rule results, with essentially similar emission inventories based on different base years. [EPA-HQ-OAR-2009-0491-2665.1, pp.14-15]
USEPA has also failed to recognize that its existing rules and programs for interstate nonattainment areas apply to several of the previously referenced counties that are shown to not reach attainment. These processes, which have been in existence for at least 20 years call for the states directly involved in the nonattainment area to work together to solve the issue. A transport rule helps these areas be assured that the problem is indeed local, and the analysis above shows that this criteria is met. [EPA-HQ-OAR-2009-0491-2665.1, p.15]
The MOG modeling shows that by 2018 nearly all areas will be in attainment with the current ozone standard of 75 ppb, not the 85 ppb level used by USEPA, and with the exception of areas that are part of or adjacent to highly urbanized areas (Bucks County, Pennsylvania, Suffolk County, New York, and Harford County, Maryland) or have known local issues (Allegheny County, Pennsylvania and Brooke County, West Virginia) demonstrates that the CAIR pathway with its unfettered trading, that the court ruled was not sufficiently justified, works equally well as the far more costly program proposed by USEPA in the Transport Rule. AEP supports providing a properly formulated analysis similar to that developed by MOG that would demonstrate to the Court that its concern about emissions trading in a regional transport solution is not well founded. The modeling submitted by MOG should offer a foundation for such a demonstration. [EPA-HQ-OAR-2009-0491-2665.1, p.15]
Response:
See the Transport Rule preamble for an explanation of why EPA did not consider CAIR in its baseline, why EPA established compliance deadlines of 2012 and 2014, and why it is not considering non-EGU sources in this rulemaking.  See "Documentation Supplement for EPA Base Case v.4.10_FTransport  -  Updates for Final Transport Rule" for an explanation on why the 30 year life assumption for emission control retrofits was retained.  With respect to air quality modeling conducted by MOG, EPA's evaluation of this modeling can be found in section V.C.2 of the preamble for the final Transport Rule.
Organization: Arkansas Department of Environmental Quality
Comment:
In Section IIl.e - Anticipated Rules Affecting Power Sector: Regional Haze Rule/Best Available Retrofit Technology ('BART') is included in the category of 'anticipated rules' when, in fact, the Regional Haze Rule and the BART Rule are already federally promulgated and state enforceable. These rules contain specific compliance deadlines that have been delayed by EPA's inability or reluctance to approve states', including Arkansas's, Regional Haze SIPs. Many of the pollutants associated with regional haze are also associated with ozone. Required reductions associated with Arkansas's Regional Haze SIP should have been taken into account for Transport Rule modeling purposes but do not appear to have been. [EPA-HQ-OAR-2009-0491-2676.2, p. 2]
EPA appears to have dismissed the quantity and effectiveness of emission reductions associated with the Best Achievable Retrofit Technology (BART) provisions of the federal Regional Haze Rule when conducting the modeling associated with the Transport Rule. ADEQ did not rely on the 'CAIR = BART' approach when establishing the BART reductions contained in the State of Arkansas Regional Haze Rule SIP. Once fully implemented, reductions in NOx, S02 and PM10 from Arkansas BART facilities will be substantial. If these reductions were taken into account in the EPA modeling, it is possible that Arkansas might not have been included in the list of states causing or contributing to downwind ozone nonattainment. For these reasons, the Transport Rule's conclusion that Arkansas significantly contributes to nonattainment or interferes with maintenance in downwind states is specious. [EPA-HQ-OAR-2009-0491-2676.2, p. 2]
Response:

Thank you for your comments.
Organization: Midwest Ozone Group
Comment:
2. EPA arbitrarily removed the Clean Air Visibility Rule from its 2005 base case. Although the Clean Air Visibility Rule (CAVR) was published July 6, 2005 (70 Fed. Reg. 39104), EPA removed the CAVR from its base case modeling for the proposed CATR. See TSD IPM EPA Base Case v.3.02 EISA at 13 available on the Internet at:http://www.epa.gov/airquality/transport/tech.html ("The Clean Air Visibility Rule(CAVR)...[was] removed from the baseline...."). EPA seeks to justify the removal of the CAVR, summarily stating that: "In June 2005, EPA finalized guidelines for States to use in determining which facilities must install controls and the type of controls the facilities must use to satisfy Best Available Retrofit Technology (BART) requirements to address regional haze(also known as the CAVR). Because of uncertainty regarding the precise measures and requirements States will adopt, the specific CAVR power sector assumptions that were formerly modeled in IPM have been removed."). EPA's modeling analyses use assumptions because they lack "precise measures and requirements". While some states do not yet have approved regional haze state implementation plans (SIPs), some states do. For those states that have submitted regional haze SIPs, including regulations, EPA needs to include the measures and requirements those states have adopted. Significantly the D.C. Circuit in NC v. EPA, 550 F.3d 1176, 1178(D.C. Cir. 2008) did not address the CAVR. In addition, EPA's previous regulatory determination that the CAIR satisfies EGU BART requirements was upheld by the DC Circuit in UARG v. EPA (471 F. 3d 1333, D.C. Cir. 2006). EPA's failure to include these controls in its analysis is another illustration of arbitrary and capricious assumptions in the proposed CATR. [EPA-HQ-OAR-2009-0491-2809.1, pp.4-5]
d) Mercury controls See Emissions Inventories TSD at 12 ("[EPA] did not include Hg in our future year modeling...."). e) Aerosol Coatings: National Volatile Organic Compound Emission Standards: Final Amendments (74 Fed. Reg. 29,595, June 23, 2009). See http://www.epa.gov/ttn/oarpg/t1pfpr.html (last visited September 28, 2010). This rule reduces VOC emissions contributing to ozone formation. Id. at 29,596/3. [EPA-HQ-OAR-2009-0491-2809.1, pp.8-9]
Response:

See IPM documentation for a list of state rules included in the IPM modeling used for the Transport Rule.
Organization: Nederhand, Frank
Comment:
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.128.]
Frank brings up two points that we've talked about and that's not only the scrubber technology, but it's the type of coal that's purchased. I believe that EPA has noted that importing coal from western states would be lower in sulfur and, therefore, recommended by this rule.
Frank states that the Transport Rule really needs to include the emissions reductions and the emissions and environmental impact of transporting that coal from the Powder River Basin in Wyoming. While you increase the transportation of coal from western states, what you're doing is just eliminating the cost of that. So we're paying for it because of raised fuel costs, but the utilities aren't covering the costs. So I'd like to encourage EPA to look at the transportation costs associated with hauling in this low-sulfur fuel.
Response:
EPA IPM modeling does reflect the transportation costs of supplying coal to each modeled generator.  This is explained in the IPM documentation which describes the coal transportation network, the methodology used to assign costs to the links in the network, and a discussion of the geographic,infrastructure and regulatory considerations that come into play in developing specific rail, barge and truck transport rates.

 Organization: State of Missouri Department of Natural Resources

Comment:
Future emissions from EGUs from Mexico and Canada need to be accounted for and not be held constant. EPA should show contribution from this sector to nonattainment and maintenance areas. [EPA-HQ-OAR-2009-0491-3806, p.3]
Response:
EPA lacks sufficiently detailed information to determine "trends" in Canadian or Mexican emissions beyond the inventory data used in the Transport Rule air quality analyses.  EPA used the latest comprehensive available data from Canada and Mexico.  EPA does not have access to any similarly detailed and consistent emission forecasts for Canada or Mexico that EPA could integrate into the Transport Rule air quality projections.  EPA believes this rule's air quality analysis reflects the most accurate information available to account for the role of foreign emissions in air quality outcomes at the state level in the context of the Transport Rule.  EPA also believes this analytic approach allows the Agency to accurately assess each U.S. state's contributions to air quality in another U.S. state, which is necessarily the focus of the relevant Clean Air Act requirements.
 Organization: Texas Commission on Environmental Quality
Virginia Department of Environmental Quality (VDEQ)
Edison Electric Institute (EEI)
Allegheny Energy
Tennessee Department of Environment and Conservation, Division of Air Pollution Control
New York State Department of Environmental Conservation
Oklahoma Department of Environmental Quality
Electric Energy, Inc.
we energies
Wabash Valley Power
Southern Company
NRG Energy
Environmental Energy Alliance of New York, LLC
Boston Generating
Exelon
Peabody Municipal Light Plant
Florida Electric Power Coordinating Group, Inc. (FCG)
East Texas Electric Cooperative
San Miguel Electric Cooperative, Inc.
Northern Indiana Public Service Company (NIPSCO)
PSEG Services Corporation
Ameren Services Company
Xcel Energy Inc.
Dominion
South Carolina Department of Health and Environmental Control
Indiana Energy Association
PPL Corporation
Nebraska Public Power District
Buckeye Power, Inc.
East Kentucky Power Cooperative
E.ON U.S.
Madison Gas and Electric Company (MGE)
AES Corporation (AES)
Oglethorpe Power
Progress Energy Service Company
Sunflower Electric Power Corporation
Wisconsin Power and Light Company
Westar Energy, Inc.
EquiPower Resources Corp.
Florida Municipal Power Agency (FMPA)
Big Rivers Electric Corporation
Empire District Electric Company (Empire District)
Omaha Public Power District
Ohio Utility Group (OUG)
Prairie State Generating Company, LLC
Associated Electric Cooperative, Inc. (AECI)
Louisiana Public Service Commission
Marquette Board of Light and Power
Giarmarco, Mullins & Horton, P.C.
City of Ames, Iowa
Santee Cooper
TransCanada
Consumers Energy
Piney Creek LP
Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
Mirant Corporation
American Public Power Association (APPA)
Nelson Industrial Steam Company (NISCO)
George Washington University Regulatory Study Center
Four Flags Area Chamber of Commerce
Pfeiff, Mike
Minnesota Power
PPG Industries, Inc.
Gulf Coast Lignite Coalition
National Mining Association (NMA)
Cleco Corporation
Duke Energy
Council of Industrial Boiler Owners (CIBO)
Northern Star Generation LLC
First Energy
Georgia Department of Natural Resources, Air Protection Branch
Luminant
Michigan Manufacturers Association (MMA)
Edison Mission Energy (EME)
DTE Energy
Indiana Builders Association
Indiana Cast Metals Association (INCMA)
Indiana Manufacturers Association, Inc. (IMA)
Utility Air Regulatory Group (UARG)
Tennessee Valley Authority (TVA)
Comment:
AES Corporation (AES)
EPA's assumptions regarding current unit operation and new control technology projects may be inaccurate. If such EPA assumptions are incorrect, it could make compliance difficult or impossible. Inaccurate factual inputs into the Integrated Planning Model (IPM) and erroneous modeling assumptions raise questions about the foundation of the Proposed Transport Rule. For example, EPA has made incorrect assumptions regarding individual EGUs, including in the NEEDS data base (e.g., incorrectly describing pollution control retrofits), and IPM modeling run outputs in some cases are erroneous (e.g., incorrectly projecting the fuels to be used, retirements, etc.). [EPA-HQ-OAR-2009-0491-2791, p.3] [EPA-HQ-OAR-2009-0491-3793.1_NODA, p.4]

For example, the AES Somerset facility is allotted NOx allowances for the NOx Annual and Ozone Season Program based upon a continuous NOx rate of 0.05 lb/mmBtu. Somerset installed an SCR in 1999 and it is evident that it will be difficult or impossible to develop and implement technology that can achieve the new, more restrictive budgets. Existing SCR technology may not allow for this limit to be met. Load following and cycling of the units during on-peak and off-peak periods requires the SCR to be taken out of service to avoid damage to equipment. Minimum flue gas operating temperatures are required to prevent fouling of the SCR catalyst and downstream equipment, especially air preheaters. Further, as more intermittent assets are introduced to the electric energy grid, the need for rapid ramp rates and flexible minimum/maximum operating levels on existing baseload facilities will become more important to supplement intermittent resources and to maintain system reliability. [EPA-HQ-OAR-2009-0491-2791, p.3][EPA-HQ-OAR-2009-0491-3793.1_NODA, p.4]

EPA assumptions include FGD retrofits and/or fuel switching to lower sulfur coal at the AES Warrior Run facilities. CFB boilers use limestone in the operation to reduce SO2 emissions and are not contemplating FGD retrofits and fuel specification changes. The allocation must be corrected to reflect actual operations and accurate emission baselines. [EPA-HQ-OAR-2009-0491-2791, p.4] [EPA-HQ-OAR-2009-0491-3793.1_NODA, p.4]

The NEEDS model assumes a NOx Policy rate of 0.06 lb/mmBtu for the AES Greenidge and AES Westover facilities. These facilities have been retrofitted with multi-pollutant control technology including baghouses, SCR and dry scrubbers but will not allow for this limit to be met. Load following and cycling of the units during on-peak and off-peak periods requires the SCR to be taken out of service to avoid damage to equipment. Minimum flue gas operating temperatures are required to prevent fouling of the SCR catalyst and downstream equipment, especially air preheaters. [EPA-HQ-OAR-2009-0491-2791, p.4] [EPA-HQ-OAR-2009-0491-3793.1_NODA, p.5]

The allocations provided for the AES Thames facility in Connecticut do not reflect reality, perhaps because AES Thames, as a Qualifying Facility (QF), is not an Acid Rain source. According to the Unit Allocation Table in the Administrative Record, the source of the SO2 data for AES Thames is reported data and the source for the NOx data is projected. Neither allocation makes sense in light of the true base case emissions for AES Thames. First, AES Thames was allocated 847 SO2 allowances in 2012 supposedly based operational data despite the fact that AES Thames reported 2298 tons of SO2 emissions in 2009. The AES Thames units already have stringent SO2 controls (flue gas desulfurization accomplished by in-bed injection of limestone reagent into the boilers for a minimum 75% SOx control efficiency), so further controls should not be required for these units for the small incremental reduction. Second, the IPM projection-based allocation for NOx is also well below historic operating levels. Actual reported emissions of NOx for the two AES Thames units was 455 tons in 2009, but the proposed allocation for the two units in 2012 is only 371 tons of NOx. Since the units are operated pursuant to contracts to sell both electricity and steam to an adjacent cardboard recycling plant beyond 2012, there is no reason to expect emissions to be significantly lower in 2012 than in prior years. Excerpts from the AES Thames emission reports for 2009 and from the facility's contracts to sell electricity and steam are attached as exhibits to this letter. [EPA-HQ-OAR-2009-0491-2791, p.4] [EPA-HQ-OAR-2009-0491-3793.1_NODA, pp.5-6]
Similar allocations are given to other contract facilities that have obligation to operate with no provision to recoup any of the additional cost for compliance [EPA-HQ-OAR-2009-0491-2791, p.4] [EPA-HQ-OAR-2009-0491-3793.1_NODA,p.6]

f. The unit level detail has several other mistakes with respect to facility details. Following are some examples and are not exhaustive.
i. AES Ironwood shows the third unit as consuming gas, however, the third unit is the combined cycle steam turbine generator for the heat recovery from the two gas turbines. This generator does not consume fuel. This same unit is shown to have DLNB and produce emissions. The accompanying units Combustion Turbine (CT) 1 and 2 show only DLNBs but actually have SCR and CO Catalyst as well.
ii. AES Red Oak has identical errors as the Ironwood facility above, however, Red Oak has Three CTs and one steam turbine generator.
iii. AES Greenidge Units 4 and 5 are shown to have Cold-side ESP + Cyclone + SCR + Dry Scrubbers. Only Unit 6 has this configuration. Units 4 and 5 had Cold-side ESP + Cyclone and are retired.
iv. AES Deepwater is shown to have Cold-side ESP + Wet Scrubber. AES Deepwater actually has Cold-side ESP (Wet and Dry) + Wet Scrubber +_LNBO + SCR. [EPA-HQ-OAR-2009-0491-2791, p.4] [EPA-HQ-OAR-2009-0491-3793.1_NODA,p.6]

The fuel usage is changed for some facilities in the IPM Base case from 2012 to 2014 and other cases (positive and negative) without explanation. For instance, AES Ironwood is a gas plant in PA and shows fuel use is lowered by 36% in the base case. AES Beaver Valley is a coal plant in PA and shows an increase in fuel use by 36% in the base case. AES Deepwater is a pet coke facility in TX and shows an increase of 7% in the base case. All three changes are unlikely. Other facilities sampled show no changes in fuel use. [EPA-HQ-OAR-2009-0491-2791, p.5] [EPA-HQ-OAR-2009-0491-3793.1_NODA, pp.6-7]
Allegheny Energy
If such errors and discrepancies exist for other generating companies subject to this proposed rule, EPA's estimates of what reductions can be achieved by 2012 are significantly overstated. AE, therefore, recommends that EPA correct the errors and discrepancies in the NEEDS database, rerun the IPM, and conduct a new analysis to determine if any adjustments to implementation dates or state allowance budget allocations are warranted. Due to the significance of this data in the proposed rule, this will necessitate the rule then be re-proposed for more informed comment by affected industry. This is also driven by EPA's updating of technical support documents to the proposed rule as recently as September 1, 2010. [EPA-HQ-OAR-2009-0491-2605.1, p.6]
Ameren Services Company
Fuel switching even between lower sulfur coal within coal ranks may not be easily accomplished [EPA-HQ-OAR-2009-0491-2722.1, p.7]
Based on the allocation table supplied by EPA, the S02 emissions for Ameren's Labadie plant are reduced by 15,634 tons from 2012 to 2014. Since IPM assumes no additional add on controls and no reduction in utilization of the Labadie plant in 2014 IPM must assume a reduction in sulfur content of the coal that Labadie plant uses. This is problematic for a couple of reasons. [EPA-HQ-OAR-2009-0491-2722.1, p.7]
1) Labadie currently burns coal in the 0.7 lb S02/mmBtu range. Meeting the reduction required in 2014 would require switching to a 0.5 lb S02/mmBtu coal. There currently exist 2 mines in the Powder River Basin that can meet this low sulfur requirement, Antelope and North Antelope Rochelle Mines. However these mines are currently sold out as they have limited production. Ameren has tested lower sulfur coals from Colorado but has been unsuccessful in burning these fuels due to boiler fouling. [EPA-HQ-OAR-2009-0491-2722.1, p.7]
2) Given there is a limited supply of these lower sulfur coals and assuming there would be some availability of such coals additional costs would likely be incurred. While the exact cost of a lower sulfur coal is unknown at this time Ameren's fuel buyers estimate that there could be a surcharge as high as $5 per ton of coal received. This would mean an additional cost of $50,000,000 per year in increased operating expenditures for the Labadie plant. [EPA-HQ-OAR-2009-0491-2722.1, p.8]
3) In order to help minimize costs and keep electric rates low utilities will negotiate long term coal contracts to lock in pricing. These contracts can span up to 5 to 10 years in length. As part of these long term contracts utilities must give some assurance that they will buy a certain amount or pay a penalty. While this penalty will vary EPA has not included this potential cost adder in its IPM modeling. [EPA-HQ-OAR-2009-0491-2722.1, p.8]
EPA has apparently also ignored that going to a lower sulfur fuel may require system modifications to accommodate this fuel. For example: [EPA-HQ-OAR-2009-0491-2722.1, p.8]
1) Precipitator modifications or flue gas conditioning may be require to be installed to assure compliance with opacity and particulate standards. [EPA-HQ-OAR-2009-0491-2722.1, p.8]
2) Coal handling systems may need to be modified to handle the different coals. This could include additional dust controls as well as increased capacity to handle lower BTU coal. Based on the above issues EPA should take a closer look at the costs of fuel switching. [EPA-HQ-OAR-2009-0491-2722.1, p.8]
Use of IPM to assign allocations on a unit by unit basis is inappropriate.
IPM should not be used for the allocation of allowances on a unit basis as it is not an appropriate tool for this purpose. While IPM is a useful planning tool for looking at different control scenarios it does not contain sufficient information on each utility company and unit to make reasonable assumptions about controls or operation. Rather on a system or regional basis it can produce reasonable results. A good example of this is how it has treated Ameren's Joppa plant under the scenarios EPA has modeled. Joppa located in Massac County Illinois under the IPM 3.02 TR SB Limited Trading case is assumed to install an FGD on each unit. Under IPM 4.10 TR SB Limited Trading case IPM labels these same units as Coal Early Retirement. And under IPM 4.10 TR SB Limited Trading AEO gas case no controls are assigned and none of the units are retired. Which of these is most representative of Joppa's future destiny? [EPA-HQ-OAR-2009-0491-2722.1, p.10]
Considering how this would affect allowance allocation, under the first IPM scenario Joppa would be issued limited allowances, as IPM assumes an FGD is installed. In the second case it would be issued no allowances, as IPM is projecting Joppa to be retired. And in the third case Joppa would be issued allowances based on no controls. Based on these drastic variations in IPM results for the Joppa plant it is absurd to believe that this model has any skill for determining what the fate of Joppa's units will be under the Transport Rule as proposed. [EPA-HQ-OAR-2009-0491-2722.1, p.11]
Rather than using IPM to assign allowance allocations on the unit level EPA should consider using the units past utilization as has been done with the NOx SIP Call rule and CAIR. This is the best estimate of future utilization and produces a fair and equitable distribution of allowances. Ameren suggests in the allocation of allowances that heat input be used as this was used in the NOx SIP Call and CAIR and created a generally fair and equitable distribution of allowances. [EPA-HQ-OAR-2009-0491-2722.1, p.11]
B. Current 2007-2009 8-hour ozone design values show major inconsistencies with the results of EPA's analysis for the Transport Rule.
Table 1 below [See p.12 of this comment summary for Table 1 entitled, Summary of Current Design Values versus EPA 2014] shows a comparison of 2007-2009 8-hour ozone design values and EPA's 2014 control case for selected monitors in the eastern United States. As is evident from the table many monitors in the Midwest (i.e. Chicago, S1. Louis) and on the East Coast are already lower than what EPA predicts for its 2014 control case. Attachment A [See p.28 of this comment summary for Attachment A] contains an analysis of current air quality performed by Environ and states' ...over 80% of the sites predicted by EPA to be in nonattainment of the ozone or PM2.5 standards in 2012 are already in attainment as of 2009...'. EPA by overestimating the impact of states on downwind nonattainment and maintenance areas will tend to increase the level of control perceived to be required to meet the desired goals. This will lead to the installation controls that in reality may not be needed. EPA's base case selection and control assumptions are fatally flawed and need be re-analyzed using a more recent and relevant information. [EPA-HQ-OAR-2009-0491-2722.1, pp.11-12]
C. Current 8-hour design values show attainment of the 1997 standard [EPA-HQ-OAR-2009-0491-2722.1, p.13]
Table 2 [See p.14 of this comment summary for Table 2 entitled, Designated 1997 8-hour Ozone Nonattainment Areas 2004-2009 Design Values] below shows the design values for the current 1997 8hour ozone designated nonattainment areas included in EPA's Transport Rule analysis. [EPA-HQ-OAR-2009-0491-2722.1, p.13]
As is evident from the table all but 5 nonattainment areas in the eastern United States based on the 2007-2009 design values are attaining the 1997 8-hour standard. Out of the 5 areas in the Eastern US not currently attaining the 1997 8-hour ozone standard 1 area is at 88 ppb, 2 are at 87 ppb and 2 are at 86 ppb. [EPA-HQ-OAR-2009-0491-2722.1, p.16]
A regional transport rule over and above CAIR is not required considering the small number of areas still not attaining the 1997 8-hour ozone standard. Ozone design values for 2007-2009 at these sites are barely above the standard. [EPA-HQ-OAR-2009-0491-2722.1, p.16]
D. Modeling performed by the Midwest Ozone Group shows attainment of the 8-hour ozone standard [EPA-HQ-OAR-2009-0491-2722.1, p.16]
The Midwest Ozone Group has performed air quality modeling of 8-hour ozone levels (see comments submitted by the Midwest Ozone Group, October 1, 2010) using 2008 as the base case year. In addition the Midwest Ozone Group performed modeling for the future years of 2014 and 2018 assuming on-the-books controls and CAIR in place. [EPA-HQ-OAR-2009-0491-2722.1, p.16]
The results for 8-hour ozone modeling for 2014 and 2018 along with the actual measured 2008 (i.e. 2007-2009) design values are shown in Figure 1 [See p.18 of this comment summary for Figure 1 entitled, 2008 Design Values versus 2014 and 2018 Modeled 8-hour Ozone] for monitors exhibiting the highest 8-hour ozone concentrations. All monitors attain the 1997 8-hour ozone standard in 2014 and all but 3 attain the current 2008 standard of 75 ppb by 2018. [EPA-HQ-OAR-2009-0491-2722.1, pp.16-17]
A regional transport rule is not required as on-the-books control and full implementation of CAIR results in all but 3 monitors attaining the 2008 standard of 75 ppb. The 3 monitors that aren't as of 2018 attaining the 2008 standard are within a couple of ppb of attaining that goal. [EPA-HQ-OAR-2009-0491-2722.1, p.17]
E. Modeling performed by the Midwest Ozone Group shows attainment of the PM25 annual standard [EPA-HQ-OAR-2009-0491-2722.1, p.18]
The Midwest Ozone Group has performed air quality modeling (see comments submitted by the Midwest Ozone Group, October 1, 2010) of the PM25 annual levels using 2008 as the base case year. In addition the Midwest Ozone Group performed modeling for the future years of 2014 and 2018 assuming on-the-books controls and CAIR in place. [EPA-HQ-OAR-2009-0491-2722.1, p.18]
Figure 2 [See p.20 of this comment summary for Figure 2 entitled, 2008 Design Values versus 2014 and 2018 Modeled Annual PM25] shows the results of this modeling for the annual PM25 standard for 2014 and 2018 as well as the 2008 (Le. 2007-2009) design values for the highest PM25 annual concentration monitors. Figure 2 is a comparison of the 2008 measured annual PM25 design values and the 2014 and 2018 modeled design values. As is evident from the figure all but one monitor attains the current PM25 annual standard. Review of the individual component data for this monitor indicates that almost half of the annual concentration is from organics (see comments submitted by the Midwest Ozone Group, October 1,2010) meaning this monitor is dominated by local sources. Attainment at this monitor will only be achieved with the implementation of local controls on organic emissions or its precursors.  [EPA-HQ-OAR-2009-0491-2722.1, p.19]
The Transport Rule will not aid in attainment at this monitor and is not needed. The implementation of CAIR is sufficient to meet the current PM25 standards.  [EPA-HQ-OAR-2009-0491-2722.1, p.19]
F. Modeling performed by the Midwest Ozone Group shows attainment of the PM25 24-hour standard
The Midwest Ozone Group has performed air quality modeling (see comments submitted by the Midwest Ozone Group, October 1, 2010) of the PM25 24-hour levels using 2008 as the base case year. In addition the Midwest Ozone Group performed modeling for the future years of2014 and 2018 assuming on-the-books controls and CAIR in place.
Figure 3 [See p.22 of this comment summary for Figure 3 entitled, 2008 Design Values versus 2014 and 2018 Modeled 24-hour PM25] shows the modeled results for the 24-hour PM25 2014 and 2018 modeled design values with the actual measured 2008 (i.e. 2007-2009) design values for the highest PM25 concentration monitors. Both the results from 2014 and 2018 show all but 2 of the monitors attain the current PM25 24-hour standard. Review of the individual component data for the 2014 and 2018 modeled design values indicate these monitors are dominated by organics as was shown for the annual exceeding monitor discussed above. For example for the 2018 simulation the Allegheny Pennsylvania monitor exhibited a large contribution (35.5 ugm-3) from organics while the Brooke West Virginia monitor was similar at 10.8 ugm-3 from organics. Generally organic emissions are local in nature thus reducing PM25 levels at these monitors will require implementation of local controls on organic emissions or their precursors. [EPA-HQ-OAR-2009-0491-2722.1, pp.20-21]
As is evident from the results of this modeling the Transport Rule is not needed. The implementation of CAIR is sufficient to meet the current PM25 standards along with local controls at the offending monitors. [EPA-HQ-OAR-2009-0491-2722.1, p.21]
G. EPAs analysis looks only at state wide contributions but considers only EGU controls [EPA-HQ-OAR-2009-0491-2722.1, p.22]
In its modeling EPA considered a state's total impact on nonattainment and maintenance areas but proposes applying controls only to electric generating units (EGU). If EPA is only going to consider controls on EGUs then it should consider the impacts only EGUs have on the maintenance and nonattainment areas rather than statewide emission impacts. Currently because of the NOx SIP Call and CAIR, EGU NOx emissions are only a small portion of the total NOx emissions in the Eastern U.S. Figure 4 [See p.24 of this comment summary for Figure 4 entitled Midwest Region NOx Emission Trends 1999-2009] shows the distribution of NOx emissions for the Midwestern states of Wisconsin, Michigan, Illinois, Indiana and Ohio. This information was assembled from EPA's National Emission Inventory and Trends Websites by Alpine Geophysics under contract to MOG. The NOx emission trends show actual emissions of NOx from 1999 thru 2009. For the EGUs actual Continuous Emissions Monitoring data as reported to EPA was used. As is evident from the figure emissions of NOx from EGUs is less than 20% of the total NOx emitted for these states. Similar and somewhat smaller results were found for the Northeast States as well as the Southeast States. All other source categories (Highway and Off-highway are the largest contributors) contribute more than 80% of the NOx emissions. [EPA-HQ-OAR-2009-0491-2722.1, pp.22-23]
As you are aware Ozone is formed from the interaction of Volatile Organic Compounds and NOx in the presence of sunlight. Considering that EGUs emit less than 20% of the available NOx the impact of these emissions is most likely considerably diminished from what the total state impact would be. EPA needs to investigate the actual impacts EGUs are having and demonstrate that the EGUs themselves are significantly contributing to nonattainment and maintenance areas. [EPA-HQ-OAR-2009-0491-2722.1, p.23]
Use of IPM to assign allocations on a unit by unit basis is inappropriate. [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.2]
IPM should not be used for the allocation of allowances on a unit basis as it is not an appropriate tool for this purpose. While IPM is a useful planning tool for looking at different control scenarios it does not contain sufficient information on each utility company and unit to make reasonable assumptions about controls or operation. Rather on a system or regional basis it can produce reasonable results. A good example of this is how it has treated Ameren's Joppa plant under the scenarios EPA has modeled. Joppa located in Massac County Illinois under the IPM 3.02 TR SB Limited Trading case is assumed to install wet flue gas desulfurization (FGD) on each unit. Under IPM 4.10 TR SB Limited Trading case IPM labels these same units as Coal Early Retirement. And under IPM 4.10 TR SB Limited Trading ABO gas case no controls are assigned and none of the units are retired. Which of these is most representative of Joppa's future destiny? [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.2]
Considering how this would affect allowance allocation, under the first !PM scenario Joppa would be issued limited allowances, as IPM assumes an FGD is installed. In the second case it would be issued no allowances, as IPM is projecting Joppa to be -retired. And in the third case Joppa would be issued allowances based on no controls. Based on these drastic variations in the IPM results for the Joppa plant it is absurd to believe that this model has any skill for determining what the fate of Joppa's units will be under the Transport Rule as proposed. [EPA-HQ-OAR-2009-0491-3739.1_NODA, pp.2-3]
Rather than using IPM to assign allowance allocations on the unit level EPA should consider using the units past utilization as has been done with the NOx SIP Call rule and the Clean Air Interstate Rule (CAIR). This is the best estimate of future utilization and produces a fair and equitable distribution of allowances. Ameren suggests in the allocation of allowances that heat input be used as this was used in the NOx SIP Call and CAIR and created a generally fair and equitable distribution of allowances. [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.3]
American Public Power Association (APPA)
4. APPA believes that the EPA must consider the implications of fuel switching for the many states where budgets will be inadequate for SO2 and NOx. [EPA-HQ-OAR-2009-0491-2812.1, p.3]
6. APPA believes that failure to have realistic dates and state budgets for coal fired power plants will result in 'the dash to gas.' It is tempting for the U.S. EPA to view any fuel switching to gas away from coal as a success because of reductions in SO2, NOx (and CO2) perhaps even more quickly than under this proposed rule. However, APPA strongly believes that fuel switching to gas presumes available infrastructure for natural gas delivery that is inadequate in many of the 31 RT covered states. APPA strongly encourages the U.S. EPA to read APPA's study on natural gas ("Implications of Greater Reliance on Natural Gas for Electricity Generation," http://www.appanet.org/files/PDFs/ImplicationsOfGreaterRelianceOnNGforElectricityGeneration.pdf) to better understand the inadequate infrastructure for gas storage and delivery. APPA does not question that there is an adequate source or supply of natural gas (considering conventional and shale based formations). APPA provides this natural gas study for review under SBREFA, Executive Order 12866 and the Unfunded Mandates Reduction Act (UMRA). [EPA-HQ-OAR-2009-0491-2812.1, p.4]
The PTR`s compliance schedule is wholly unreasonable, particularly its imposition of a January 1, 2012, initial compliance deadline that will fall only a few months after EPA plans to take final action in this rulemaking. [EPA-HQ-OAR-2009-0491-2812.1, p.7]
Many of the flaws in the Proposed Transport Rule, described in the sections that follow, could be resolved or at least somewhat ameliorated by deferring the initial 2012 compliance date. It is unreasonable and unrealistic to expect emission reductions required by the proposal to be achieved by January 1, 2012, barely six months after the date on which EPA expects to issue a final Transport Rule. [EPA-HQ-OAR-2009-0491-2812.1, p.14]
An initial compliance deadline of January 1, 2012, will not allow sufficient time for sources to make the adjustments necessary to comply with the rule. For example, a compliance deadline of 2012, following a mid-2011 date for final promulgation of the rule, would not allow enough time for sources to install low NOx burners, and in many cases, does not allow sufficient time for sources to switch to burning lower sulfur coal. See section VIII infra. Additionally, much of the modeling that EPA used to develop the proposed rule is flawed, due to the approach that EPA adopted, as well as many of the assumptions EPA made with respect to issues such as the emission controls that will be installed on, and retirement of, specific units by 2012. EPA must resolve and correct these problems, and either withdraw this proposed rule and reinitiate rulemaking with a new proposal or issue a supplemental notice of proposed rulemaking for public comment. See sections VII and IX infra. Under these circumstances, rulemaking could not be completed before the beginning of 2012. [EPA-HQ-OAR-2009-0491-2812.1, pp.14-15]
The U.S. EPA has provided absolutely no reasonable justification for its proposal to require a compliance date as early as 2012. According to statements by EPA representatives, the emission levels required in the 2012 phase for the most part reflect the emission reductions that would occur even in the absence of the Transport Rule. However, as noted above, in a number of cases, EPA has made incorrect assumptions regarding emission reductions that, in the absence of this new rule, would occur at units by 2012. See section VIII.A infra. [EPA-HQ-OAR-2009-0491-2812.1, p.17]
APPA believes that the EPA should not adopt the 2012 compliance deadline in the Proposed Transport Rule and should not consider any compliance date earlier than 2015.13 If EPA promulgates a Transport Rule that, like this proposed rule, includes requirements more stringent than CAIR, the compliance deadline should reflect the degree of stringency of those requirements. [EPA-HQ-OAR-2009-0491-2812.1, p.19]
APPA and UARG are not alone in its concern regarding the initial compliance date. Last year, for example, the Lake Michigan Air Directors Consortium ("LADCO") strongly recommended that any CAIR replacement rule include an initial compliance date no earlier than 2017 for any significant additional emission reduction requirements. See Letter from LADCO to Administrator Jackson (Sept. 10, 2009) ("LADCO Letter") at 1. LADCO explained in its recommendations to EPA that it had conducted a state-by-state analysis that indicated that installation of significant new NOx and SO2 controls -- specifically, installation of selective catalytic reduction systems ("SCRs") and flue gas desulfurization systems ("FGDs" or "scrubbers") -- would not be possible in LADCO states before 2017. Id. at 1, attachment at 4-5.  [EPA-HQ-OAR-2009-0491-2812.1, pp.19-20]
In materials prepared to explain its Proposed Transport Rule, EPA made the following assumptions about how low SO2 and NOx emission levels would be as a result of (a) the implementation of CAIR and other on-the-books regulations, and (b) the implementation of the Proposed Transport Rule:  [EPA-HQ-OAR-2009-0491-2812.1, p.29]
[Table V-1 can be found on page 30 of this comment.]
Table V-1 demonstrates that EPA expects its PTR to achieve substantial additional reductions beyond those that have been (or would be) achieved through implementation of CAIR. Despite how much EPA expects its PTR to accomplish in terms of achieving additional emission reductions, however, EPA proposes to give affected sources very little time to achieve those additional reductions. [EPA-HQ-OAR-2009-0491-2812.1, p.30]
Specifically, EPA assumes that affected EGUs will be able to reduce their SO2 emissions from 5.1 million tons per year to 4.1 million tons per year between mid-2011 (when EPA expects to take final action on the PTR19) and January 1, 2012. This reduction, says EPA, can be accomplished if affected companies (a) just complete the installations of FGD units or "scrubbers") that are already underway, and (b) supplement the emission reductions from those controls by switching some of their units to burning lower sulfur fuels. See 75 Fed. Reg. at 45273/2. Then, relying in large part on information from a March 2005 study,20 EPA takes pieces of information from retrofit experiences at two power stations and uses those negligible data to conclude that it is possible for owners of EGUs to reduce their emissions even further (down to 3.3 million tons annually) by January 1, 2014, through the installation of additional FGD units, which -- EPA claims -- can be designed, permitted, and constructed in just 27 months. Id. at 45273/1. For installations of pollution controls of this magnitude, many public power utilities would likely fuel switch to natural gas instead. [EPA-HQ-OAR-2009-0491-2812.1, pp.30-31]
APPA "real world" examples of pollution control installation timing:
- See CPS Energy letter in Appendix B [[See Docket Number EPA-HQ-OAR-2009-0491-3041.3 for Appendix B.]]
Similarly, EPA assumes power plant owners will be able to reduce their EGUs` annual and seasonal NOx emissions by substantial amounts by January 1, 2012, by completing already-in-the-pipeline projects to install SCR reactors and by constructing more low NOx burner ("LNB") systems that -- according to EPA -- can be installed in the few months between the time that the PTR is scheduled to be finalized in mid-2011 and January 1, 2012. And if any additional NOx reductions are needed (although EPA`s projections as summarized in Table V-1 above suggest that no such additional NOx reductions will be needed), then affected utility companies can install additional SCR units by January 1, 2014, because -- according to EPA (again relying on its 2005 Report) -- it takes only "approximately 21 months" to design, permit, and construct SCR units. Id. at 45273/1. [EPA-HQ-OAR-2009-0491-2812.1, pp.31-32]
In the alternative, EPA should extend the PTR`s emission reduction deadlines by at least one year in the case of NOx and two years in the case of SO2. [EPA-HQ-OAR-2009-0491-2812.1, p.32]
EPA has substantially overestimated the number of SCR and FGD installations that are now under construction and can be operational by January 1, 2012. The EPA has greatly underestimated the number of FGD and SCR installations that affected utilities would have to undertake between mid-2011 and January 1, 2014, to meet the PTR`s requirements. Even worse than this, though, 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 -- under the terms of the PTR -- must be achieved by that rule's January 2012 and 2014 deadlines. [EPA-HQ-OAR-2009-0491-2812.1, p.32]
APPA, as a member of UARG, recognizes that UARG`s comment provide more details on the unreasonableness of the emission reduction requirements that EPA has proposed. APPA seeks to incorporate the submittal by UARG and incorporates that significant section submitted by UARG by reference herein: Cichanowicz, J.E., "Implementation Schedules for Selective Catalytic Reduction (SCR) and Flue Gas Desulfurization (FGD) Process Equipment" (Oct. 1, 2010) [EPA-HQ-OAR-2009-0491-2812.1, p.32]
Associated Electric Cooperative, Inc. (AECI)
Reference: IPM Constraint Name: #2 - State Level Cap - SO2 Annual Constraint (MO) Constraint #: 570 [EPA-HQ-OAR-2009-0491-2845.1 p.11]
EPA assumes the following (total) heat input for the state of Missouri:
TBtu (years)
755.0 ('12-'13)
772.4 ('14-'17)
780.1 ('18-'22)
783.4 ('23-'27)
795.3 ('28-'35)
[EPA-HQ-OAR-2009-0491-2845.1 p.12]
Actual (CAMD) heat input for the state during the years 2005 - 2009 is as follows:
TBtu (year)
813.7 (2005)
812.5 (2006)
800.6 (2007)
770.3 (2008)
761.6 (2009)
[EPA-HQ-OAR-2009-0491-2845.1 p.12]
Average CAMD heat input over the period 2005-2009 was 792.0
TBtu Maximum CAMD heat input over the period 2005-2009 was 813.7
TBtu Minimum CAMD heat input over the period 2005-2009 was 761.6
TBtu Observations:
:: Missouri's lowest CAMD heat input for the years 2005-2009 (761.6 TBtu) is higher than EPA's 2012/2013 assumption for the state;
:: Missouri's average CAMD heat input for the years 2005-2009 (792.0 TBtu) is not matched by EPA's assumptions until 2028;
:: EPA's heat input assumptions for the state are too low and it appears as if Missouri is being shorted.   [EPA-HQ-OAR-2009-0491-2845.1 p.12]
Big Rivers Electric Corporation
The proposed rule relied on information from EPA's Integrated Planning Model (IPM) to make assumptions regarding the ability of a utility to further reduce emissions.  The model does not take into account the required engineering analysis needed to reduce emissions on each generation unit as well as possible impacts to the overall generation station site to achieve those reductions. [EPA-HQ-OAR-2009-0491-2661.1, p.2]
Specific Comments to EPA's Technical Information Documents regarding BREC units: [EPA-HQ-OAR-2009-0491-2661.1, p.3]
Reid Combustion Turbine ORIS # 1383. The data utilized by the TR does not include any heat input or emissions for this unit. [EPA-HQ-OAR-2009-0491-2661.1, p.3]
Reid Unit 1 ORIS # 1383. The NOx emission rate estimated in the TR for the Reid Unit 1 cannot be achieved without the installation of additional NOx control equipment and the additional control equipment cannot be installed by 2012. [EPA-HQ-OAR-2009-0491-2661.1, p.3]
Henderson Station Two, Units 1 and 2 ORIS # 1382. The data utilized in the model (0.16 lbs/MMBTU) for the 2012 SO2 allocations cannot be achieved without a significant fuel switch.  [EPA-HQ-OAR-2009-0491-2661.1, p.3]
The NOx emission rate and heat input data utilized by EPA for the Ozone Season allocations is high by a factor of 10. [EPA-HQ-OAR-2009-0491-2661.1, p.3]
The parsed data files for both 2012 and 2014 show 0 TBtu for the D.B. Wilson Station for both the summer and total.  Perhaps this is due to a fuel listing of "petroleum coke".  The actual fuel that has been utilized over the last several years at this plant is a blend of bituminous coal and petroleum coke.   In future years, we are planning for potential petroleum coke blending; however, our primary fuel is forecasted to be bituminous coal for both summer and total. [EPA-HQ-OAR-2009-0491-2661.1, pp.3-4]
Boston Generating
EPA proposes zero NO, and SO, allocations for the Mystic Generating Station, Unit ID 7. It appears that this is because the !PM model does not project the unit to operate in 2012, which is an unfounded assumption. The unit could and has continued to profitably operate on pipeline natural gas with a mix of some residual oil (sulfur content 1.0%, wt). The following table summarizes unit variability over the past three years based on data reported to the EPA Clean Air Markets Division. [EPA-HQ-OAR-2009-0491-3804.1 p.1]
[[Next entry in docket is a table of EGU characteristics]]
The facility has no plans to shut down the unit in the foreseeable future, even in light of the potential economic burden of the Clean Air Transport Rule. The boiler is equipped with low NO, burners to minimize NO, formation and an electrostatic precipitator for PM capture. It is not reasonable to expect the unit to install add-on NO, or SO, controls by the year 2012. The cost of CATR SO, allowances may weigh into the facility's decision to bum natural gas instead of oil. This is because operating on natural gas yields minimal SO, emissions, certainly not enough to assume the unit will not operate. However, it is important for the unit to retain a cost effective alternative to natural gas in the event of a natural gas shortage, curtailment or emergency situation impacting the North Eastern Management Area (NEMA). [EPA-HQ-OAR-2009-0491-3804.1 p.1]
In light of this information, the facility proposes a 2012 NO, allocation of 357 tons and an SO, allocation of 1,034 tons, equivalent to the average actual emissions from a 3-year look back period. [EPA-HQ-OAR-2009-0491-3804.1 p.1-2]
Buckeye Power, Inc.
In addition, factual errors in the data EPA proposes to use in its CATR emission control allowance methodology and modeling should be corrected, as such errors relate to Buckeye's electric generating units. For example, Buckeye's Cardinal Unit No. 3 scrubber will be in place by the end of 20l2 rather than in 2010 or 2011 as contemplated by EPA's CATR modeling. [EPA-HQ-OAR-2009-0491-2710.1, p.3]
Finally, for Buckeye's natural gas-fired peaking units, specifically National Power Cooperative, Inc.'s Robert P. Mone Plant, and Buckeye's Greenville Electric Generating Station, they have been allocated no NOx emission allowances, in the case of the Mone Plant, and 14 NOx emission allowances, in the case of the Greenville Station, which are less than required to operate these natural-gas fired peaking units. These units, by the very nature of peakers, only operate when needed to support grid reliability at times of peak load, therefore, baseline emissions are not easily established. Because baseline emissions are difficult to establish for peaking power plants, and because these units are critical to grid reliability and are classified as minor sources (contributing little to overall NOx - and greenhouse gas - emissions), they should receive allocations equal to the lesser of actual or permitted emission limits. [EPA-HQ-OAR-2009-0491-2710.1, p.3]
b. EPA's allocation methodology and modeling contains numerous errors.
It appears that EPA utilized existing modeled emissions as the basis for establishment of baseline SO2 emissions. Once baseline emissions were calculated, EPA then ratcheted these baseline emissions down based on erroneous assumptions regarding the installation of additional control equipment or some presumed ability to fuel switch. With respect to Buckeye, for example, and as mentioned above, EPA shows that the Cardinal Unit No. 3 scrubber will be on line in the 2010-2011 time period. In fact, even following an aggressive installation schedule, without the sort of unforeseen circumstances that are inherent in large construction projects such as a scrubber installation, this scrubber is unlikely to be online until early 2012. EPA's proposed scheme will result in Buckeye having a deficiency in necessary allowances for 2012, since it will be allocated allowances for 2012 based upon the mistaken assumption that a scrubber will be installed on Cardinal Unit No. 3 prior to 2012. Allowance allocations for Cardinal Unit No. 3 will not be sufficient in 2012 even though it bums low sulfur coal. Fairness dictates that, if emission levels are utilized for allowance allocations, Buckeye's baseline should reflect a December 31, 2012 installation of this technology and not a 2011 installation. [EPA-HQ-OAR-2009-0491-2710.1, p.8]
G. Before Relying Upon IPM Projections For Allocation of Allowances, EPA Must Both Revise IPM to Accurately Project Dispatch of Contracted Facilities and Use the Correct Inputs for Linden Cogen
Before EPA can rely upon IPM projections as the basis for NOx allocations in New Jersey, EPA must revise the model so that it accurately predicts the dispatch of facilities such as Linden Cogen that operate to supply power pursuant to long-term power sales agreements and are required to run to provide steam to a cogeneration host. Understanding that any modeling exercise involves some degree of simplification, EPA must endeavor to capture the often complex terms governing dispatch of facilities in long-term contracts, before it relies upon the model results as the basis for allocations of emissions allowances. If EPA cannot make adjustments to IPM so that it can incorporate and reflect these real-world assumptions governing dispatch and, as a consequence, provide a reliable prediction of contracted facilities' actual dispatch, then EPA cannot continue to rely upon the model results, but must resort instead to the historic dispatch data it has already deemed a better predictor of future dispatch than IPM's projections. [EPA-HQ-OAR-2009-0491-2710.1, pp.18-19]
Linden Cogen's long-term contracts practically assure that it will be operated as frequently as demonstrated by historical operating data. If IPM cannot accommodate the numerous complex contractual terms governing dispatch of Linden Cogen's units, then EPA must at the very least establish some set of rules within IPM, which effectively 'force' the model to predict dispatch of Linden Cogen and other contracted facilities at heat input levels representative of historic operations. EPA also must incorporate Linden Cogen's correct plantwide heat rate into the model and reflect dispatch of Units 1 through 5 consistent with their service of the NYC region through dedicated transmission lines. Additionally, EPA must apply the correct FOM assumptions (12.6 $/kW/yr) for each of Linden Cogen's generating units. It also must apply VOM and fuel costs no greater than assumed for a similar facility located in New Jersey (AES Red Oak) (2.75 to 3.02 mill/kWh for VOM costs and 32.55 to 44.09 mill/kWh for fuel costs). [EPA-HQ-OAR-2009-0491-2710.1, p.19]
As the court held in the section 126 litigation, '[w]hile courts routinely defer to agency modeling complex phenomena, model assumptions must have a 'rational relationship' to the real world.' Appalachian Power 1,249 F.3d 1032 (internal citations to Chemical Mfrs. Ass'n v EPA, 28 F.3d at 1265). Accordingly, EPA has an obligation to incorporate real-world expectations for contracted facilities into its model. Further, EPA cannot inflexibly apply its model when it has been demonstrated to have a 'poor fit' with reality. Chemical Mfrs. Ass'n v EPA, 28 F.3d at 1265. ('The more inflexibly the agency intends to apply the model, however, the more searchingly will the court review the agency's response when an affected party presents specific detailed evidence of a poor fit between the agency's model and that party's reality.') Finally, in the face of data and real world information demonstrating that the assumptions used by EPA are false and the results are simply implausible, EPA must provide sources the opportunity to correct those assumptions. See, e.g., Columbia Falls Aluminum Co. v. EPA, 139 F.3d 914, 923 (D.C. Cir 1998) (vacating and remanding a rule for reliance upon 'a test [the EPA] knew to be inaccurate.'). If the model cannot accommodate real-world assumptions, EPA must abandon the model. [EPA-HQ-OAR-2009-0491-2710.1, p.19]
H. If EPA Cannot Revise IPM To Accurately Predict Dispatch of Facilities in New Jersey, EPA Should Apply the Same Methodology It Used to Establish New Jersey's Budget and Rely Upon Historical Data Instead of IPM's Projections
If EPA cannot make appropriate change to IPM so that it would accurately predict the dispatch of facilities in New Jersey such as Linden Cogen, EPA should instead base NOx allocations in New Jersey on reported data. In setting state budgets (except for the 2014 802 budgets for group 1 states), EPA reportedly relied on reported data, as augmented by assumptions about operation of existing and planned emissions controls. See 75 Fed. Reg. at 45291. Thus, if IPM cannot be revised to produce reliable results for New Jersey or for contracted facilities such as Linden Cogen, EPA should adopt the same approach it used to develop the proposed state budgets and base the unit allocations on reported data, augmented by assumptions concerning the operation of emissions controls. This would make true EPA's statement in the preamble that its proposed allocation methodology 'allocat[es] down to the individual unit level using all of the same assumptions used in developing the proposed budgets.' 75 Fed. Reg. at 45311. For New Jersey, using those same assumptions would require that EPA not rely upon IPM projections for either the annual or ozone season NOx allocations, but instead base those allocations upon historic data, as augmented by assumptions about existing and planned controls. [EPA-HQ-OAR-2009-0491-2710.1, pp.19-20]
I. Basing Allocations on Reported Data Rather Than Projected Dispatch Is Not At All Inconsistent With the Court's Decision in North Carolina v. EPA
Basing unit allocations for New Jersey on historic data is not at all inconsistent with the principles articulated by the D.C. Circuit in North Carolina v. EPA, 531 F.3d 896 (DC Cir. 2008). Indeed, EPA has already proposed to base unit allocations on historic data for any state in which 2009 emissions were lower than IPM's projected 2012 emissions. Thus, assuming EPA cannot fix the errors in IPM that have resulted in wildly inaccurate projections of dispatch in New Jersey and for Linden Cogen in particular, EPA could adopt the same approach for allocating allowances that it says it adopted in setting statewide budgets: It could base each unit's allocation on historic data, which EPA has concluded are more representative of actual operations than IPM's projections. [EPA-HQ-OAR-2009-0491-2710.1, p.20]
J. EPA Should Establish Allocations Based Upon a More Representative Period of Time Than One Year
Assuming EPA cannot modify IPM to accurately predict dispatch of contracted facilities in New Jersey and should therefore decide to base NOx allocations for New Jersey on reported data, EPA should base emissions allocations for individual units, not upon data from only one year, but on a facility's average heat input over a longer period of time. Once each facility's representative baseline has been established, EPA should add together all facilities' baseline emissions, compare the resulting sum with the state budget and then reduce each facility's allocation by whatever percentage is needed for the total statewide emissions (plus the 3% set aside for new facilities) to fit within the budget. [EPA-HQ-OAR-2009-0491-2710.1, p.20]
Using only one year's data as the baseline for allocations would unfairly prejudice facilities that might have experienced reduced dispatch in 2008 or 2009. In particular, it could penalize facilities that had lower emissions in 2008 or 2009 because they were down for an extended period of time to install controls in advance of CAIR. Furthermore, as EPA has acknowledged upon adjusting reported heat input and emissions rates to reflect unusually low utilization in 2009 15, 2009 data represented significantly lower utilization due to the global recession. As a consequence, 2009 data cannot be deemed representative and EPA should more equitably account for anomalously low utilization during the recession by using a longer-term average as the basis for establishing allocations. [EPA-HQ-OAR-2009-0491-2710.1, pp.20-21]

15. See supra nt. 4. [EPA-HQ-OAR-2009-0491-2710.1, p.20]
City of Ames, Iowa
It seems that U.S. EPA believes that an alternative to compliance with this rule is for coal-fired generation to convert over to natural gas. While there may be enough natural gas reserves to support more electric generation, the natural gas infrastructure (pipeline system) to deliver natural gas adequately for electric generation is not in place and may never be in place. The City of Ames does not have access to natural gas resources sufficient to support conversion of our coal-fired generation over to natural gas. Moreover, natural gas is not a reliable resource for electric generation during extreme winter weather conditions due to the demand for natural gas for residential space heating to support life. This author has had at least two personal career experiences in Wisconsin where use of natural gas for electric generation was curtailed (prohibited) during extreme winter weather in order to preserve and maintain natural gas for residential space heating. Even with curtailment, in one case the demand on the natural gas pipeline for space heating was so great that the gas pressure failed to support furnace and water heater pilot lights. [EPA-HQ-OAR-2009-0491-2769, p.2]
Cleco Corporation
We appreciate the opportunity to submit these comments, but we are very concerned about the process by which this rule was developed and the lack of opportunity for meaningful review, especially of the data associated with the NODA. The D.C. Circuit identified the fundamental flaws in the Clean Air Interstate Rule ("CAIR") in July 2008. The proposed rule is voluminous and complicated, and EPA intends this rule to be the model for future transport rules. Yet EPA has allowed only sixty days (or less) for public review and comment and has denied modest requests for extensions from multiple stakeholders. We have worked very hard to evaluate this rule within the time allowed, but sixty days is simply not enough time to prepare the thorough comments this rule requires. In addition, EPA's Notice of Data Availability (NODA), issued in the middle of the public comment period, impacts literally every aspect of this proposed rule. The timing and the short comment period have significantly strained our limited resources to provide for meaningful and thorough evaluation of the significant impacts this rule could have on Cleco Midstream's wholesale operations. We urge EPA to issue a more refined supplemental rule to allow us an opportunity to better evaluate the proposal and submit more meaningful public comments. [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.2]
EPA's Most Recent IPM Projections Penalize Low Emitting, Efficient Units [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.2]
Under EPA's most recent IPM projections (Version 4.10), natural gas-fired units that are very efficient (heat rates below 8,000 btu/kw) and low emitting (equipped with NOx reduction technology such as SCR) are projected to have very low utilization levels. Cleco Midstream's Evangeline Power Station illustrates this effect. [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.2]
Evangeline Power Station's Forecasted Heat Input Is Too Low [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.2]
Evangeline Power Station is a 775 MW combined cycled generating station (CCGT). In 2000, the facility abandoned two existing boilers and repowered two steam turbines with F-Class combustion turbine technology. The facility now consists of Unit 6, a 1x1 CCGT, and Unit 7, a 2x1 CCGT. The IPM 4.10 parsed file shows that EPA forecasts the annual heat input for this facility to be 4.5 trillion British thermal units (tBtu) in 2012. IPM Version 3.02 projected 11.24 tBtu. This represents a 60% reduction in the forecasted heat input for the facility from Version 3.02 to Version 4.10. It is inconceivable that a state-of-the-art combined cycle generating unit will be effectively limited to an equivalent 8.6 percent capacity factor over the longer term. While the projected heat input from IPM Version 3.02 is more reasonable by comparison, Cleco Midstream is still concerned about the impacts of effectively ascribing a 21.5 percent capacity factor to this facility, as Version 3.02 does. As discussed below, because these units already have state-of-the art controls, a severe under-allocation of allowances based on these heat input projections could negatively impact the facility's future marketing opportunities, especially given that it is a wholesale generator. [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.2]
EPA Misuses IPM Projections in this Rulemaking [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.4]
Cleco Midstream recognizes that the EPA, in addition to other state air regulatory agencies, utilities and public and private sector clients, have used IPM for various air regulatory analyses, market studies, strategy planning, and economic impact assessments. And although IPM is a well established model of the electric power sector for strategic and other planning tools, it in no way should be used as the sole basis for designing and constructing a specific environmental rule such as the Clean Air Transport Rule (CATR). The IPM model is useful as a tool in the user's arsenal of tools for capacity planning, compliance planning, wholesale price forecasting, and asset valuation; however, it is only one of several tools used to make such critical decisions. In addition, the IPM is not a static, one time analysis that is run once. It is updated on a continuing basis with key data from energy markets, fuel markets, emission markets, and electricity markets. In contrast, the proposed CATR is designed whereby allowances are issued now to facilities on a long term basis, similar to the Acid Rain Program and there are essentially no provisions for future changes in the key model inputs mentioned above. [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.4]
Transport Rule II [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.6]
In section V of the preamble to the proposed Transport Rule, EPA states that for future ozone and PM 2.5 NAAQS, EPA intends to quantify the amount of emission reductions needed to satisfy the requirements of 110 (a) (2) (D) (i) (I) with respect to those NAAQS. EPA states that it has not made any determinations regarding whether reductions from source categories other than EGU's will be needed to achieve the necessary reductions in each state. However, EPA has verbally mentioned that it is likely that other source categories will be required to reduce SO2 and NOx emissions to eliminate significant contribution or interference with maintenance of the 1997 PM NAAQS. Given that this IPM modeling methodology will form the basis for allowance allocations and will set a precedent going forward, how does EPA expect to address other source categories with similar performance modeling tools? Cleco Midstream isn't aware of any such IPM models for all other source categories, and EPA has had the luxury of developing these rules with data from a heavily regulated industry that is required to report inputs and outputs much more rigorously than most other source categories. It seems that by using this projected modeling methodology for EGU's, EPA will find itself allocating allowances to other source categories on a different basis and will thus be faced with many challenges on future versions of the Transport Rule due to inequitable allowance allocations. [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.6]
EPA's Proposed Rule Is Insufficient for Public Comment [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.6]
While Cleco has attempted a full review and analysis of this proposed rule within the time provided, it has found it almost impossible to do so given the voluminous and complex nature of the proposal and supporting documentation. This is an important rule, and EPA expects it will form the basis for future transport rules. Yet EPA's processes and methodologies are in many cases unclear and in other cases are lost within the thousands of pages of preamble and technical support documents. [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.6]
Furthermore, given the many errors we have identified thus far and EPA's release just weeks ago of new data and modeling runs which will form the basis of revised unit allocations yet to be provided, the proposal is not sufficiently developed for meaningful public comment. We urge the Agency to issue a supplemental proposal that provides the revised data which will form the basis of the final rule and revised unit allocations for review and comment before finalizing this rule. In doing so, EPA will produce a better, more effective product that can inform future rules, decrease the scope and extent of legal challenges, and improve the likelihood that the rule will survive such challenges. The electric power industry, the fuel industry and the transportation industry all involve massive, complex operations with long term planning horizons (with respect to financing, integrated resource planning etc.). The rule as proposed gives these industries little to no indication of what might be required in the final rule, no time to plan, and almost no time to comply. EPA simply has not allowed sufficient opportunity for public review and comment. Given the importance of this rule, the Agency should take the additional time necessary to issue a supplemental proposal. [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.6]
EPA Must Not Establish State Budgets and Unit Allocations Based on Projected Data. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.4]
As noted in our comments on the proposed rule, we oppose EPA's sole reliance, in some cases, on projected data to set state budgets and unit allocations.1 In our initial comments we noted that there is too much variability in EPA's projections  -  and in projected data generally  -  to determine state budgets and to allocate to the unit-level. We also noted that EPA's projections simply do not reflect reality. Having more fully evaluated EPA's numerous projections (e.g., IPM 3.02, IPM 4.10, and IPM 4.10 (AEO)) and having compared those projections with our own, we are confident that EPA's sole reliance on its best guess work to establish allocations and state budgets is arbitrary and capricious. Model outputs vary too much, between various models or versions of the same model and with minor adjustments to key assumptions, to support precise state budget and unit allocation development, and EPA's model outputs prove this point by predicting unrealistic results. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.4]
Projections Have Too Much Variability to Support Allocations and State Budgets. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.4]
Numerous state budgets and unit allocations are based solely on EPA's IPM projections. Essentially, EPA guesses how units will run in the future and then based on those guesses allocates allowances to units and establishes state budgets. This is an inappropriate use of IPM projections. In recognition of modeling limitations, industry and agencies rely on modeled/projected data for very limited purposes. Here, EPA proposes to rely on projected data from the IPM to set detailed, long-term, unit-level, allocations. But the IPM is not a static, onetime analysis. IPM and other model analyses are updated on a continuing basis with key data from energy markets, fuel markets, emission markets, and electricity markets. As a result, the IPM is not a suitable tool for establishing unit allocations that will be federally enforceable for the foreseeable future. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.4]
As an initial matter, there is simply too much variation in projections from one model to the next. Less than a month after publishing the proposed rule  -  based on IPM 3.02  -  EPA proposed a newer model  -  IPM 4.10. This simple switch from one version to the next leads to dramatic changes in the most critical predicted outputs. For Louisiana EGUs alone, EPA's new version 4.10 predicts a 12% decrease in summer fuel use, an 8% decrease in total fuel use, a 29% decrease in ozone season NOx emissions, a 25% decrease in total NOx emissions and an 18% decrease in total SO2 emissions.2 With the NODA, simply by converting from one IPM version to the next, EPA projects NOx and SO2 emission reductions from Louisiana EGUs that far exceed the emissions the August 2 Transport Rule alleged were Louisiana's significant contribution and interference with maintenance. See Table 1 below [See p.5 of this comment summary for Table 1 entitled, Comparison of Emission Reductions Required for Louisiana EGUs under the Proposed Transport Rule with Projected Emission Reductions Resulting from EPA's Switch from IMP Version 3.02 to IPM Version 4.10]. In short, from one month to the next the Agency's predictions bear no resemblance to one another. Yet EPA proposes to establish federally enforceable reduction requirements based on similar modeling yet to be provided. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.4]
To further illustrate this point, we have compared 2012 heat input projections from EPA's IPM versions 4.10 and 3.02 with 2012 heat input projections from two of the modeling programs we use  -  again for limited purposes. This comparison is included as Attachment "A" [See p.11 of this comment summary for Attachment A entitled, CONFIDENTIAL BUSINESS INFORMATION REDACTED] and is claimed as confidential business information in accordance with 40 C.F.R. Part 2. The comparison demonstrates two important points. First, projected heat input varies widely depending on the model selected. And second, with limited exceptions, both EPA projections underestimate heat input for 2012 as compared to the two models we use. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.5]
In addition to the wide variation in important outputs from one model to the next, minor adjustments to some key assumptions will similarly lead to significant variations in the outputs from a single model. Take for example the natural gas fuel price assumptions. For 2012, EPA has proposed three different gas fuel price assumptions: $6.76 (IPM 3.02), $4.27 (IPM 4.10) and $5.19 (AEO). EPA's best guess in September of this year (IPM 4.10) is 37% lower than its best guess in August (IPM 3.02). Thus from one month to the next EPA adjusted its fuel price assumptions by 37%. This underscores the difficulty and uncertainty in predicting just one of the inputs for EPA's model. Natural gas fuel prices are volatile. They are also one of the most significant assumptions with respect to projected outputs (e.g., projected NOx emissions). Yet EPA proposes to establish state budgets and unit allocations based in large part on its assumptions of natural gas prices. This is wholly inappropriate, and, given the legal import EPA proposes to place on these modeled outputs, it is arbitrary and capricious. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.5]
Because of the significant limitations of modeling noted above, the wide variations in outputs and volatility of key inputs, EPA's proposal to rely solely on general modeling projections from IPM to set the most significant federally enforceable limits in the rule is arbitrary and capricious. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.5]
Errors, Mistaken Assumptions and Methodology Flaws [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.7]
In the time permitted for review and comment, we have identified the following apparent errors, mistaken assumptions and methodology flaws. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.7]
Errors in NEEDS [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.7]
Teche 3 (1400_B_3). EPA correctly notes in NEEDS that this unit can burn distillate fuel oil. Its ability to burn fuel oil, however, is typically reserved for emergency situations when natural gas is unavailable. By way of example, it has not burned any fuel oil in the last three years, and burned only de minimis amounts in the two years before that. It is unclear to us, whether and how, EPA accounts for such limitations on the use of alternative fuels. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.7]
Rodemacher 1 (6190_B_1). Like Teche 3, Rodemacher 1 is permitted to burn alternate fuels and typically does so only in emergency situations (distillate fuel oil and residual fuel oil). Over the last three years this unit has not burned any fuel oil and before that used distillate in de minimus amounts, except for a period of time following Hurricane Katrina when natural gas was unavailable. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.7]
Dolet Hills (51_B_1). EPA correctly notes in NEEDS that this unit can burn subbituminous coal. While the unit can physically burn subbituminous, it is a minemouth plant. It is connected by conveyor to a nearby lignite mine and has no facilities for accepting shipment by rail. Based on our review of the available IPM runs under 3.02 and 4.10, it appears that EPA correctly projects that Dolet Hills will burn 100% lignite fuel.5 As noted, however, EPA has not made available the results of numerous other IPM runs. To the extent that EPA has modeled or plans to model use of any fuel at Dolet Hills other than lignite, we object on the basis that this is a mine mouth facility that is fully contracted to burn lignite coal. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.7]
Dolet Hills (51_B_1). EPA erroneously assumes that this facility's scrubber efficiency is 88%, presumably on a continuous basis. Dolet Hills is a NSPS Subpart D facility. The historical removal efficiency has ranged from 50% to 70%. A more accurate efficiency would be 60%, which represents the annual average. Because EPA is developing an annual SO2 emission reduction program, the Agency should focus on annual average removal efficiencies which take into account variability in operations, fuel sulfur and other parameters over the course of the relevant compliance period. Sulfur content of the lignite fuel, in particular, varies greatly depending on the particular vein being mined. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.7]
Errors in IPM Inputs and Assumptions [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.7]
Teche 4 (1400_B_4). EPA has not included Teche 4 in the proposed rule. Teche 4 is planned to commence commercial operation prior to January 1, 2012 and has broken ground and received approval from the Louisiana Public Service Commission.6 It is a permitted facility natural gas fired combustion turbine with a name plate rating of 35MW. Accordingly, it should be included as an existing unit (to the extent EPA's proposed Transport Rule ultimately applies to Louisiana) and should receive an allowance allocation as an existing unit. [EPA-HQ-OAR-2009-0491-3726.1_NODA, pp.7-8]
Rodemacher 1 (6190_B_1). The NOx combustion control input (NOx Comb Cont) for this unit indicates it has flue gas recirculation, low NOx burner technology and overfire air. The unit does not have flue gas recirculation, low NOx burner technology or overfire air. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.8]
Rodemacher 2 (6190_B_2). The NOx combustion control input (NOx Comb Cont) for this unit indicates it has an overfired air system. The unit has both an overfired air system and low NOx burner technology. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.8]
Rodemacher 3 (6190_B_3a and 6190_B_3b). The Hg EMF input for these units indicates cold side ESP with a fabric filter and SNCR. Neither unit has a cold side ESP. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.8]
EPA Erroneously Assumes Controls Are Dispatchable, Ignoring LAC 33:III.905. EPA makes adjustments to reported NOx emissions for several facilities in Louisiana to reflect EPA's assumption/preference that NOx controls operate year round.8 These adjustments are in error, because Louisiana law requires units to operate installed controls year round. "When facilities have been installed on a property, they shall be used and diligently maintained in proper working order whenever any emissions are being made which can be controlled by the facilities, even though the ambient air quality standards in affected areas are not exceeded."9 Thus, the adjustments EPA made for Louisiana facilities with SCR or SNCR installed before 2009 are in error and are based on the mistaken assumption that NOx controls are not operated year round in Louisiana. They are. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.8]
Methodology Flaws (Emission Rates) [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.8]
EPA's use of the various emission rates from NEEDS in the IPM is unclear. EPA appears to use a maximum allowable "SO2 permit rate" for modeling SO2 emissions in the IPM and one of four NOx rates (the controlled base rate, the uncontrolled base rate, the controlled policy rate, or the uncontrolled policy rate). Where these rates are derived from and how they are used is unclear to us. We request that EPA explain the rates and how they are used, before issuing a final rule, so that we can provide meaningful comment. Until that time, we offer the following comments on these rates. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.8]
SO2 Permit Rates. EPA should not use a maximum allowable SO2 permit rate and should instead use rates based on past actual annual emission rates. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.9]
Teche 3 (1400_B_3). The Teche 3 SO2 permit rate in NEEDS is 4.94 lbs/mmBtu. As explained above, Teche 3 burns natural gas (with exceptionally rare use of distillate fuel oil when natural gas is unavailable). [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.9]
Rodemacher 1 (6190_B_1). The Rodemacher 1 SO2 permit rate is 1.4 lbs/mmBtu. As explained above, Rodemacher 1 burns natural gas (with exceptionally rare use of fuel oil when natural gas is unavailable). [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.9]
These SO2 rates are unreasonable, and EPA should use the default SO2 emission rate of 0.006 lbs/mmBtu prescribed for gas units in 40 C.F.R. Part 75. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.9]
NOx Rates. EPA should explain these four rates in more detail. From what we have been able to tell so far these NOx rates do not resemble the historical actual NOx rates for many units. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.9]
EPA's Complex Methodologies May Bias Future Transport Rules Towards EGU Emission Reductions. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.9]
Having worked through EPA's proposed methodologies for defining significant contribution and interference with maintenance and setting state budgets and unit allocations, we find that for EPA's complex methodologies to work they require extraordinary amounts of data about electricity demand, fuel cost, fuel content, control technology cost and efficiency, emissions, etc. That quantity of information is simply not available to the Agency for any other emission source category. Accordingly, we are concerned that EPA's proposed methodology is too complex and is unworkable for other source categories. The approach thus biases future transport rules towards EGU reductions. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.9]
[See EPA-HQ-OAR-200-0491-3726.1_NODA, p.11 for Attachment A: Projected Total Heat Input Comparison of Various Models (Contains Confidential Business Information, p.12 for Attachment B: State of Louisiana Department of Environmental Quality, Part 70 Operating Permit Significant Modification, CLECO Power, LLC, Teche Power Station, Baldwin, St. Mary Parish, Louisiana, Permit No. 2660-00007-V1 (November 6, 2009). And Cleco Power, LLC, Teche Power Station, Title V and Acid Rain Monitor Modification Application, Agency Interest No. 2432, prepared by Providence Engineering and Environmental Group LLC (December 2008)., p.104 for Attachment C: Louisiana Administrative Code 33:III.905.
Consumers Energy
E. EPA's Proposal Is Based On Numerous Errors and Assumptions In the Data Bases Used With Respect to Consumers Energy Units
In the EPA's table of unit specific allowance allocations and direct control emission rates we found several flaws:
:: There appears to be an assumed retirements at the following units:
o B C Cobb Units 1,2, 3
o DEKarn Units 3, 4
o Thetford Units 1, 2, 3, 4
At this time Consumers Energy has no plans to retire any of these units. [EPA-HQ-OAR-2009-0491-2837.1, pp.9-10]
[For additional comments pertaining to EPA's Proposal Is Based On Numerous Errors and Assumptions In the Databases Used With Respect to Consumers Energy Units, see page 10.]
G. Modeling Based on Current Emissions Inventories and Ambient Ail' Quality Indicates that EPA's Proposal is Not Necessary to Achieve the Desired Air Quality Improvements
Consumers Energy is aware of the air quality modeling effort that has been conducted by the Midwest Ozone Group (MOG). MOG conducted an independent analysis which utilizes a more recent base year, 2008, and alternate business as usual (BAU) future year scenario for 2014 and 2018 to develop a residual ozone and particulate matter nonattainment picture for a l2km domain over the Midwestern and northeastern United States. MOG also relies upon ambient air quality monitoring data collected through the most recent year that has been quality assured and reported by EPA, 2009. [EPA-HQ-OAR-2009-0491-2837.1, p.14]
The objective of this work was to perform technically credible photochemical modeling analyses, including the EPA attainment test, for three key years: 2008, 2014, and 2018. Modeling for year 2008 served the important function of providing a recent 'typical baseline' year for the purpose of calculating relative reduction factors (RRFs). Most importantly, moving to 2008 takes direct advantage of recent reductions in 8-hr design values measured across the modeling region. Results of this work clarify when the effects of the BAU state and federal control programs would begin to significantly lower the 8-hr ozone and annual and daily PM design values at key monitors in the modeling domain. [EPA-HQ-OAR-2009-0491-2837.1, p.14]
Consumers Energy notes, with interest, that even the updated emissions inventory and ambient air quality monitoring data result in a model that over predicts 2014 PM2.5 design values for Michigan. MOG's analysis indicates that a monitor in Wayne County, presumably the Dearborn monitor, will exceed the 24-hour 2006 PM25 NAAQS in 2014. The model predicts attainment in 2018. As of 2009, the Dearborn monitor has the 3-year data set that demonstrates measured attainment for both the 1997 and 2006 PM2.5 NAAQS. [EPA-HQ-OAR-2009-0491-2837.1, p.14]
The limited comment period for this proposed rule has not permitted adequate time for Consumers Energy to fully critique MOG's efforts. We will continue to do so on our own, and with the MDNRE, and with LADCO. [EPA-HQ-OAR-2009-0491-2837.1, p.14]
We are confident that MOG's effort shows that, at a minimum, EPA's proposed rule is based on incorrect assumptions that result in a control program that is too extreme. MOG's effort may go so far as to demonstrate that EPA's proposed rule is not even required to reach attainment of the 1997 ozone NAAQS and the 2006 PM2.5 NAAQS. If MOG's analysis holds true, then, to put it bluntly, EPA has elected to go back in time, to a world that no longer exists, to find solutions for problems that are already being solved. [EPA-HQ-OAR-2009-0491-2837.1, p.14]
In either case, Consumers Energy believes the prudent course for EPA is to retract and rethink this proposal, with more upfront transparency and a greater degree of involvement by the States and affected sources. [EPA-HQ-OAR-2009-0491-2837.1, p.14]
:: It has been developed using emissions inventory data that has no relevance to the situation that exists today. EPA ignores the major reductions that are in place and on the book through the ongoing implementation of CAIR, which remains in effect and is enforceable. EPA ignores the reductions that are in place and on the books that have been incorporated into consent orders that are in effect and enforceable. EPA also ignores the reductions that have resulted from the permanent shutdowns of major sources that contribute to the pollutants and standards addressed by the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2837.1, p.15]
:: EPA's choices of emissions inventory and ambient air quality monitoring data result in allowance totals that will be inadequate to support even a limited emissions trading program. [EPA-HQ-OAR-2009-0491-2837.1, p.15]
:: EPA must work with the states and affected sources to correct the numerous errors and assumption, with respect to source emissions, control plans and decommissioning plans contained within the proposed rule. [EPA-HQ-OAR-2009-0491-2837.1, p.16]
Council of Industrial Boiler Owners (CIBO)
Assumptions regarding emission rates of SO2 and NOx fail to account for key features of some units [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.6]
The total heat input is used to determine allocations of allowances. However, allocations are based on the premise that the plants will be able to achieve a lower emission rate for SO2 and NOx than they currently emit. In the case of waste coal plants using circulating fluidized bed (CFB) technology, the projected reduced emission rates cannot easily be achieved and may not be achievable.
SO2 and NOx emission rates are based on EPA's definition of highly cost effective controls -  made not on a plant basis but on a model plant basis. In regard to the waste coal plants, the assumptions in the documents refer to bituminous coal, not waste coal from anthracite or bituminous operations. Because waste coal plants utilize CFB combustion and inject limestone to control SO2 emissions, the incremental costs for controlling SO2 by adding a scrubber (wet or dry) is higher than what is projected. In many cases, the CFB unit cannot simply add more limestone to obtain 95% to 98% reduction in SO2. Assuming the concept is to reduce emissions by simply increasing limestone, this is problematic for several reasons: [EPA-HQ-OAR-2009-0491-3754.1_NODA, pp.6-7]
increased limestone means increased fuel usage to calcine the limestone, increasing the total heat input to the boiler; [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.7]
the amount of limestone required to achieve a 95% to 98% emission reduction from current emission levels is not linear, but exponential; and [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.7]
while the emission rate on a lbs/mmBtu basis may be lowered, the heat rate is increased and the projected total reduction of SO2 would not be achieved. [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.7]
In regard to NOx reductions, several complications arise: [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.7]
as limestone consumption is increased (and more fuel with more sulfur goes to the boiler), and total heat input to the boiler increases, NOx, mercury and CO2 emissions increase; and [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.7]
increased uncontrolled NOx cannot necessarily be rectified by increasing ammonia usage, because the amount of ammonia that can be utilized is limited by permitted levels of ammonia slip (5ppm). [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.7]
Spinoff problems from these unaccounted for-variables make the base case assumptions even more irrational. CFB plants have experienced visible plumes when injecting larger amounts of ammonia to control NOx resulting in ammonia slip approaching its permit levels; in this way, overly steep emission reductions could result in opacity violations. The costs to reduce emissions per plant vary significantly and in many cases exceed the EPA projections in terms of costs per ton of reduction. A related fundamental problem is that many of the existing add-on systems used for the model plant cannot be simply 'bolted on' to waste coal CFB units (and most of the coal-fired CFB units) due to the actual parameters that are required for their operation. The engineered design of operation of SCRs and some post-combustion wet scrubbers, combined with the existing back-pass thermal efficiency devices already installed, restrict the operation of both. To graft additional partial-flow devices into existing systems will require major redesign of the existing thermal designs, if it can be done at all. These additions will exacerbate the concern noted above, by increasing the already underestimated heat rates used for waste coal CFBs. [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.7]
These issues are not accounted for in EPA's model unit approach to allocating allowances. EPA needs to evaluate actual unit operation in order to achieve an equitable distribution of allowances, and one that reflects other longstanding priorities such as encouraging the use of CFB and other low-emitting technologies for the production of power. [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.7]
Dominion
First, EPA has over estimated the number of retrofit installations that are either already under construction or will be completed in the 2012 to 2014 timeframe. [EPA-HQ-OAR-2009-0491-2715.1, pp.12-13]
Model/Allocation Inaccuracies
EPA has indicated that its intent in setting the state emission budgets for 2012 was to reflect a level of emissions representative of pollution controls that were already in place or what companies had already announced or committed to install by 2012 in order to comply with existing federal and state rules. However, inaccuracies in EPA assumptions used to establish the proposed state emission budgets and individual unit allocations (through the use of its Integrated Planning Model- IPM) raise serious questions about the proposed rule. These inaccuracies include (1) erroneous assumptions about existing and future/planned installation of pollution control equipment - for example, EPA has assumed pollution controls exist or would be installed for certain facilities by 2012 where controls have not been implemented to date and there are no such plans to install equipment or where installations are not expected/planned until after 2012; (2) inaccurate assumptions of early retirement for some units or assumptions that certain units (especially oil-fired units) would not operate in the future (even for units with exiting capacity supply commitments); (3) inaccurate assumptions regarding fuel switching and the availability of lower-sulfur fuels as a viable compliance option; and (4) inaccuracies in the National Electric Energy Data System (NEEDS) database. These inconsistencies, if uncorrected, will result in overly stringent state emission budgets and significant gaps in allowance allocations to many units that will render compliance with the proposed reduction requirements extremely difficult and very costly. To the extent allowances are not available, curtailments could be necessary. [EPA-HQ-OAR-2009-0491-2715.1, p.6]
We provide the following detailed descriptions of assumption errors and issues specific to Dominion facilities and electric generating units: [EPA-HQ-OAR-2009-0491-2715.1, p.6]
[See EPA-HQ-OAR-2009-0491-2715.1, pp.6-10 for detailed descriptions of assumption errors and issues specific to Dominion Facilities and electric generating units]
DTE Energy
Even more problematic is the fact that EPA has made incorrect assumptions regarding emission reductions that will occur at units by 2012. The vast majority of DTE's fossil-fired EGUs (all but 2%) have been retrofitted with combustion controls for NOx emission reductions. DTE coal-fired EGUs all fire the maximum blend of low sulfur subbituminous within their capability. [EPA-HQ-OAR-2009-0491-2851.1, p.4]
Duke Energy
A Compliance Deadline in 2012 Is Neither Necessary Nor Appropriate.
EPA has provided no reasonable justification for its proposal to require a compliance date as early as 2012. To begin with, according to statements by EPA representatives, the emission levels required in the 2012 phase for the most part reflect the emission reductions that would occur even in the absence of the Transport Rule. However, in a number of cases, EPA has made incorrect assumptions regarding emission reductions that, in the absence of this new rule, would occur at units by 2012. [EPA-HQ-OAR-2009-0491-2689.1, p.8]
The NOx Emission Rates of Duke Energy Units With Currently Operating SNCR Should Not Be Further Reduced By 35% to Account for SNCR Operation. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.10]
When EPA updates the emission rates for Duke Energy units with SNCR to the 2009 rates, it should not apply an additional 35% reduction factor to account for SNCR operation because the 2009 rates already reflect year round SNCR operation. The following Duke Energy units have SNCR that were in service for the entire year of 2009 for North Carolina Clean Smokestack Act, CAIR annual NOx and CAIR ozone season NOx compliance. The 2009 NOx rates for these units should therefore be used without further adjustment, and should be considered the controlled rates and the rates used in the IPM modeling. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.10]
[See p.10 of this comment summary for a table listing: Plant name, Units, ORISPL]
For Units with an Existing SCR or SNCR, EPA Should Update Reported Unit NOx Emission Rates to Reflect 2009 Data and Use Separate Ozone Season and Non-Ozone Season Emission Rates to Represent a Unit's NOx Emissions Over the Course of a Year. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.17]
As a general statement, EPA's use of a 0.06 lb/mmBtu NOx emissions rates ceiling for SCR controlled units is inconsistent with how SCR controlled units actually work. The key element of SCR performance is the condition and amount of catalyst used. SCR reactors are fixed in size at their time of construction and units do not have the capability to add additional catalyst layers beyond what was included in their original design. Where SCR has been installed on existing units, in general these have been shoe-horned into very tight spaces. Even where there may be some marginal additional room, the structural steel is a custom design for the specific size and weight of the SCR, and the design will not allow for any enlargement without completely replacing the system. In addition, while in operation, catalyst ages as it is poisoned by materials in the flue gas and steadily degrades in its performance. Once its performance reaches an unacceptable level, it must be replaced. Catalyst replacement is expensive and can only be performed during a unit shutdown of sufficient length. Because of these factors, units will have significant differences in the levels of NOx removal performance when catalyst is new, and then just before it is replaced. An uninformed response to the issue of catalyst degradation would be to call for more frequent catalyst replacement. Clearly this is not an option because it would require frequent unit shutdowns, and scrapping expensive catalyst prematurely which would also increase the amount of waste materials. The marginal costs for the incremental reductions that would result would wildly exceed the $500 per ton cost breakpoint. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.17-18]
Duke Energy recommends that EPA use separate ozone season and non-ozone season NOx emission rates for units with an existing SCR instead of using a unit's ozone season emission rate to represent its emissions over the entire year because a unit's ozone season NOx emission rate is not representative of its non-ozone season emission rate, and therefore is not representative of a unit's capability over an entire year (a review of 2009 ozone season and non-ozone season NOx emission rates for units with SCRs operating year around shows that the ozone season NOx emission rates are typically lower than the non-ozone season rates). EPA cannot ignore the fact that there is a demonstrated difference in performance of SCR between ozone season operation and operation across the entire year. Therefore, applying a unit's ozone season NOx emission rate to the non-ozone season under predicts a unit's annual NOx emissions, the state budgets, and the unit allowance allocations. The fact that the ozone season NOx emission rate is not representative of the non-ozone season emission rate is due to many factors, including the following: 1) most units have the fewest number of outages during the ozone season which results in the most continuous period of SCR operation, whereas outside of the ozone season, most units experience the bulk of planned and maintenance outage activity. This results in higher occurrences of unit start-up and shut-down when emission rates are higher than during continuous operation. 2) Lower ambient temperatures in the winter season generally result in a higher propensity for ammonium bisulfate formation in the air heaters and downstream ductwork on SCR units, resulting in air heater and ductwork pluggage, and the need to reduce NOx removal to maintain unit output capacity. Generating units do this by reducing the level of ammonia feed and/or regulating the temperature of the gas entering the SCR. 3) Many units tend to have catalyst replacement outages in the spring outage season, resulting in peak SCR removal capability during the ozone season immediately following the outage. This "brand new" catalyst will show the best overall performance for the next several months immediately following the outage, and thus lower average ozone season emissions may be influenced by SCR catalyst outage schedules. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.18-19]
Upon making these recommended adjustments to NOx emission rates, EPA should rerun the critical IPM model runs that are the basis for developing state budgets and unit allocations. Because EPA needs to make dramatic technical changes to its calculations, EPA should then repropose the budgets and allocations for public review and comment. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.19]
The following table presents 2009 unit level ozone season and non-ozone season NOx emission rates that Duke Energy recommends EPA use for each of the listed Duke Energy units equipped with an SCR. In each case, the SCR was operated to the maximum extent possible in 2009, given the operating conditions of the units. In each case, it would require extensive and costly upgrades to each SCR to get it to perform at or below 0.06 lb/mmBtu at a $/ton cost far in excess of $500/ton. In addition, it would not be possible to complete an upgrade by January 1, 2012. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.19-20]
When a unit's 2009 emission rate is below 0.06 lbs/mmBtu, Duke Energy recommends using the 0.06 lbs/mmBtu floor rate consistent with using 0.06 lbs/mmBtu as a floor. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.20]
[See p.20 of this comment summary for a table listing Duke Energy's Plants, the plant's unit, ORISPL, 2009 Ozone Season NOx Emission Rate, and 2009 Non-Ozone Season NOx Emission Rate]
E.ON U.S.
Comments Associated with EPA's NEEDS Database and IPM Modeling [EPA-HQ-OAR-2009-0491-2797.1, p.10]
Some NOx allocations are based on incorrect unit control equipment information. [EPA-HQ-OAR-2009-0491-2797.1, p.10]
The information in EPA's NEEDS database provided with the notice of proposed rulemaking (NEEDS v3.02) contains the following incorrect information: For E.W. Brown Unit 3, it shows an existing SCR in "post combustion control", although "SCR_Online_Year" field is blank, and it shows "Controlled NOx Base Rate" of 0.06 lb/mmBtu, reflecting existence of SCR in the Base Case. E.W. Brown 3 is under a Consent Decree to install an SCR by December 31, 2012. The compliance date is an aggressive deadline that resulted from extensive negotiations between EPA, the Department of Justice, and KU. KU anticipates completing the installation of the SCR on the Brown 3 unit near the end of 2012. It is infeasible to revise the schedule to achieve an expedited installation and thus the SCR will not be operating for most of 2012. EPA's updated NEEDS database v4.10 has corrected E.W. Brown 3 information; e.g., no SCR shown in "post combustion control" and a "Controlled NOx Base Rate" of 0.31 lb/mmBtu, which is reasonable. However, EPA has not to our knowledge provided updated allocations to reflect this. As such, EPA has provided incomplete information on which to comment. [EPA-HQ-OAR-2009-0491-2797.1, pp.10-11]
For Ghent unit 2, NEEDS v3.02 shows an SCR in "post combustion control" and SCR_Online_Year of 2009. The unit does not have an SCR and none is planned. It also shows a "Controlled NOx Base Rate" of 0.06 lb/mmBtu, reflecting existence of SCR in Base Case. The unit does not have an installed SCR and the company has no current plans to install one. EPA's updated NEEDS database v4.10 still has incorrect information for Ghent 2. [EPA-HQ-OAR-2009-0491-2797.1, p.11]
The incorrect information on both of these units resulted in very significantly incorrect unit allocations for these KU generating units and the overall state budgets in the proposed rule. [EPA-HQ-OAR-2009-0491-2797.1, p.11]
EPA has corrected Brown 3 post-combustion control information in its updated NEEDS database v4.10, but the most recent database is still incorrect in showing post-combustion control at KU Ghent Unit 2. The allocations for both units should be revised to reflect correct unit control equipment information. [EPA-HQ-OAR-2009-0491-2797.1, p.11]
There is inconsistency between data in the NEEDS database and that used for IPM modeling provided in the NODA. As examples, in NEEDS v4.10, Ghent unit 2 is shown to have a NOx emission rate of 0.03 lb/mmBtu, but IPM data shows that a rate of 0.06 lb/mmBtu was used.12For Ghent unit 4, NEEDS shows a rate of 0.06 lb/mmBtu, while the IPM modeling shows a rate of 0.03 was used. [EPA-HQ-OAR-2009-0491-2797.1, pp.11-12]
Discussions with other utility companies reveal that there were numerous other errors in basic information about units and control equipment that formed the basis of EPA's analyses. Correction of these errors will lead to revised modeling results, revised allocation values, and continued uncertainty regarding the actual requirements of the rule until it is finalized, which is expected to be mid-2011  -  only six months before the 2012 compliance date. [EPA-HQ-OAR-2009-0491-2797.1, p.12]
EPA should correct the inaccurate data, resulting analyses, state budgets, and unit allocations, and reissue the rule for public comment as a Supplemental Notice of Proposed Rulemaking. [EPA-HQ-OAR-2009-0491-2797.1, p.12]
NOx projected emissions for many KU and LG&E units are based on unrealistically low NOx emission rates. [EPA-HQ-OAR-2009-0491-2797.1, p.12]
EPA states that it assumes SCR's can achieve 90% removal, down to a floor of 0.06lb/mmBtu. However, EPA's projections include units achieving much lower rates (as low as 0.03 lb/mmBtu). EPA has clarified that the floor of 0.06 lb/mmBtu is only for new SCR's, and that lower emission rates were used for existing SCR's that temporarily achieved lower rates. Analysis of the historic data shows that EPA is assuming these lower rates based on a very limited time frame. Their TSD methodology uses emission rates based on historic ozone season emission rates. However, this is not representative of an achievable annual average emission rate. Units generally operate at high capacity levels during the summer ozone season, resulting in atypically low emission rates. During lower electricity demand periods when units operate at lower capacity levels, SCR's may not be operable due to low boiler exit combustion gas temperatures to the SCR. [EPA-HQ-OAR-2009-0491-2797.1, p.12]
Also EPA must consider degradation of catalyst reactivity over time, variations in unit design, and other factors which make it impossible for a unit to repeat its best short-term performance on a year after year basis. Our experience with year round operation (2009) and at units with relatively new catalyst layers indicates emission rates not lower than 0.05513lb/mmBtu. And even these low rates were only achieved at units equipped with economizer bypass which allowed SCR operation at an extended (lower) operating range. [EPA-HQ-OAR-2009-0491-2797.1, pp.12-13]
Unnamed new unit in Trimble County, Kentucky. [EPA-HQ-OAR-2009-0491-2797.1, p.13]
There is a unit in the allocation table designated "TVAK_KY_Coal Steam Unit 1." The "TVA" portion of the name appears to refer to the region, rather than the utility company. Other information indicates it is a 732 MW unit located in Trimble County. Since no other generating units are similar to the description, this suggests that the reference is to the 760MW Trimble County plant Unit 2. However, it has a different plant ORIS code than the Trimble County plant (ORIS 6071) and is called unit 1. [EPA-HQ-OAR-2009-0491-2797.1, p.13]
The allowance allocation table shows an SO2 allocation for 2012, but zero allowances allocated for 2014. [EPA-HQ-OAR-2009-0491-2797.1, p.13]
In the updated NEEDS database (v4.10), the unit information has been revised to list the unnamed unit with the county as "unknown" and with capacity of 750 MW. [EPA-HQ-OAR-2009-0491-2797.1, p.13]
Trimble County Unit 2 commenced commercial operation, as defined in the proposed rule, in 2010. Accordingly, it should receive an allocation for both 2012 and 2014 as an "existing unit" as defined in the proposed regulations. [EPA-HQ-OAR-2009-0491-2797.1, p.13]
4) SO2 projected emissions are unrealistically low. EPA appears to be assuming that even older FGD's can achieve 95% removal. LG&E's Cane Run and Mill Creek FGD's were among the first built in the U.S. in the late 1970's and early 1980's. They were designed to meet their emission limit of 1.2 lb/mmBtu and historical data shows that they are achieving approximately 90% removal efficiency. It is unrealistic to assume such units can reduce their emissions in half without substantial costs. For SO2 in Kentucky, EPA based 2012 allocations on "actual" recent emissions, with downward adjustments as deemed appropriate. The selected actual emissions are typically the first 3 quarters of 2009 and the fourth quarter of 2008. This period was not only the heart of the recent economic downturn, but ambient temperatures were milder than normal. Summer temperatures in the Midwest were over 25% below the 30-year average. Therefore, this period had significantly reduced electric generation and is unrepresentative of normal operations. Indeed, EPA's Base Case heat input projections for Kentucky are 17% higher than this time period. The low historic emissions combined with the higher projected heat input results in unrealistically low emission reduction targets; i.e., utilities in Kentucky would have to reduce emission rates by approximately 17% to meet the allocations for 2012. This is contrary to EPA's assertion that the 2012 reductions can be achieved without significant new equipment. [EPA-HQ-OAR-2009-0491-2797.1, pp.13-14]
East Kentucky Power Cooperative
EKPC Concerns Regarding EPA's Underlying Technical Data  [EPA-HQ-OAR-2009-0491-2776.1, p.2]
There are inconsistencies in the underlying technical data reviewed by EKPC that indicates the need to revisit the rule. For instance, EPA calculated the 2014 S02 allocation for EKPC's Spurlock Unit 1 to be 0.067lb/MMBTU and also calculated the 2014 allocation for EKPC's Spurlock Unit 2 at 0.093 lb/MMBTU. Both units have the same S02 emissions controls, thus a reason cannot be discerned for the differing allocations. The heat input 'assumed' for 2012 and 2014 at EKPC's Spurlock Unit 1 is listed at 17,179,025 (this represents a 56% capacity factor) for 2012 and 22,244,000 (this represents a 72.5% capacity factor) for 2014. [EPA-HQ-OAR-2009-0491-2776.1, p.2]
Moreover, EPA should not expect the same total heat input for nonscrubbed units to be a predictor of future emissions, emission allocations, electric demand and dispatch. A non-scrubbed unit can become a scrubbed unit that reduces the S02 emissions. A unit can be modified to accept a Selective Catalytic Reactor that reduces nitrous oxide. The total heat input of a unit and dispatch order will change once the unit receives the additional pollution controls, (i.e. from unscrubbed to scrubbed). Because the unit has lowered its emissions, the dispatch pecking order may change, thereby enhancing the number of hours operated in a calendar year, and thus increasing its total heat input and capacity factor. (Capacity Factor is a term that calculates the unit's utilization on a calendar year basis.) The Methodology of using the 2009 total heat input as a predictor of the future total heat input for 2012 and 2014 is incorrect. This approach can actually hinder usage of the lowest emitting units to meet demand.  [EPA-HQ-OAR-2009-0491-2776.1, p.2]
EKPC Practical and Technical Concerns [EPA-HQ-OAR-2009-0491-2776.1, p.5]
In drafting the rule, EPA appears to rely heavily on the ability of utilities to utilize lower sulfur coal. However, EPA should consider that, from a technical perspective, as sulfur is removed from coal, typically through scrubbing, the removal efficiency declines as a lower sulfur coal is utilized. Therefore, the efficiencies gained from using lower sulfur coal are not likely to be as great in practicality as in theory. [EPA-HQ-OAR-2009-0491-2776.1, p.5]
From a compliance perspective, EKPC requests EPA to acknowledge that often several units will share a common stack. For example, at its Dale Station, Units 1 and 2 have a common stack and Units 3 and 4 also share a common stack. Cooper Station has a common stack for Unit 1 and Unit 2 as well. Such technical realities may pose compliance issues. Technically speaking, it would be difficult for EKPC or any utility to determine which unit was not in compliance under the CATR rules since two units are tied to a common stack. CATR does not address how compliance will be determined, measured or verified on either a state or federal level. [EPA-HQ-OAR-2009-0491-2776.1, p.5]
East Texas Electric Cooperative
III. NELSON 6
Roy S. Nelson Unit 6 is a 550 MW PRB coal-fired unit located in Westlake, Louisiana. The unit's majority owner and operator is Entergy Gulf States. ETEC has concluded that Nelson 6 has been allocated adequate CATR seasonal and annual NOx allowances to permit continued operation without restriction. However, by choosing Nelson 6 SO2 emissions from the fourth quarter of 2008 and the first three quarters of 2009 as a baseline for determining CATR SO2 allowance allocations, the EPA has severely reduced the number of allowances from the level that would have been available had a longer baseline period been used. The nature of prudent coal unit operations and maintenance practices, where scheduled maintenance hours can vary by a factor of four from year to year makes it entirely unreasonable to select a single year for allowance allocation purposes. As shown below, during the four quarters selected by EPA (the most recent four quarters available at the time the Rule was developed) Nelson 6 emissions were significantly below those for any recent year and nearly 5% below those for most recent three year average (2007-2009). [EPA-HQ-OAR-2009-0491-2770.1 p.3]
[[Data table here]]
This anomaly was driven largely by a series of furnace tube leaks in October and November 2008 which resulted in an average forced outage rate of over 25% in those two months and a scheduled outage in February  -  April 2009 which extended to over 1,640 hours (nearly 10 weeks). In contrast, generation (directly tied to emissions) for the fourth quarter of 2009 was 15% higher than that recorded in the fourth quarter of 2008, and the average Nelson 6 scheduled outage time for 2005-2008 was less than 875 hours. The period chosen by EPA for its SO2 emissions baseline does not accurately reflect historical Nelson 6 operations and will not produce an allowance allocation that is consistent with the CATR seasonal NOx policy objectives. [EPA-HQ-OAR-2009-0491-2770.1 p.3]
IV. INDEPENDENCE UNIT 2
 Independence Unit 2 is an 842 MW PRB coal-fired unit located near Newark, Arkansas. ISES-2 is operated by Entergy Arkansas. Located in Arkansas, ISES-2 is subject only to CATR seasonal NOx emission limitations. By choosing ISES-2 heat input from the fourth quarter of 2008 and the first three quarters of 2009 as a baseline for determining CATR SO2 allowance allocations the EPA has severely reduced the number of allowances from the level that would have been available had a longer baseline period been used. As noted above, the nature of prudent coal unit operations and maintenance practices, where scheduled maintenance hours can vary by a factor of four from year to year makes it entirely unreasonable to select a single year for allowance allocation purposes. As shown below, during the 2008 ozone season selected by EPA ISES-2 heat input was significantly below that for any recent year and 18% below the average for the three most recent ozone seasons (2007-2009). [EPA-HQ-OAR-2009-0491-2770.1 p.3]
[[Data table here]]
This anomaly was largely driven by an abnormally high number (320 hours) of equivalent forced outage hours during June and July of 2008 and the commencement of scheduled maintenance in September 2008. The incident which caused the June outage and the majority of the forced outage hours  -  the failure of a low pressure turbine rotating blade (L-1 row)  -  required a summer outage lasting more than 264 hours (11 days) to remove the affected blade section and the blade section opposite the damaged section on the turbine shaft. The average number of forced outages hours during the 2005, 2006, 2007, and 2009 ozone seasons was less than 112. Entergy also removed ISES-2 from service for 385 hours (16 days) for scheduled maintenance. That event is the only time in the last five years that ISES-2 has been removed from service for scheduled maintenance for more than a week during the May-September ozone season. It is therefore very clear that the period chosen by EPA for its heat input baseline is not representative of typical ISES-2 operation. [EPA-HQ-OAR-2009-0491-2770.1 p.4]
The allowance allocation impacts of EPA selecting a single ozone season, particularly the 2008 season, upon its ISES-2 CATR seasonal NOx allowance allocation are demonstrated in the table above. [EPA-HQ-OAR-2009-0491-2770.1 p.4]
V. SAN JACINTO COUNTY AND HARDIN COUNTY PEAKING FACILITIES
ETEC wholly owns and contracts for the operation of the San Jacinto County Peaking Facility (SJCPF) located near Cleveland, Texas and the Hardin County Peaking Facility (HCPF) located near Lumberton, Texas. Each facility contains two GE Frame 7EA combustion turbine generators (CTGs). All four CTGs were relocated from a generating facility Warren County (near Vicksburg) Mississippi which rarely operated. Since entering commercial operation in Texas in July 2009 (SJCPF) and January 2010 (HCPF) these units have been operated extensively to support the reliability of the western reaches of Entergy's electric transmission and distribution system. Despite ETEC's timely notification of both the EPA and EIA, these units are still listed as being located in Mississippi in the EPA CATR allocation table. Seasonal NOx emissions for both plants are shown in the table below. An update with September 2010 data will be provided upon receipt of CEMS output for the month. [EPA-HQ-OAR-2009-0491-2770.1 p.4]
[[Data table here]]
ETEC solely wishes to ensure that the EPA recognizes that the SJCPF and HCPF generating units have been relocated from Mississippi to Texas and that they have operated extensively since their relocation. ETEC leaves it to EPA's discretion to determine from what pool of allowances and to what extent CATR seasonal NOx allowances should be fairly allocated to these facilities.  [EPA-HQ-OAR-2009-0491-2770.1 p.5]
Edison Electric Institute (EEI)
Many companies will report in their comments on the Proposed Rule that EPA has made incorrect assumptions regarding individual EGUs, including in the NEEDS data base (e.g., incorrectly describing pollution control retrofits), and that IPM modeling run outputs in some cases are erroneous (e.g., incorrectly projecting the fuels to be used, retirements, etc.). [EPA-HQ-OAR-2009-0491-2697.1, p.10]
New EGU information supplied by companies, combined with changes to the NEEDS database and the IPM identified in EPA's Transport Rule NODA, will lead to new model runs and state budgets supporting the final Transport Rule. If the new modeling runs lead to substantially different state budgets and company impacts, EPA may need to reissue the Proposed Rule for public comment as a Supplemental Notice of Proposed Rulemaking. [EPA-HQ-OAR-2009-0491-2697.1, p.12]
Edison Mission Energy (EME)
EPA's aggressive emission reduction timelines are also technically infeasible. EPA's claim that compliance with the Phase I emissions caps will only require electric generating units ("EGUs") to operate their existing controls year-round is simply incorrect. It is based on inaccurate assumptions by EPA about the control efficiency provided by existing controls (e.g., EPA assumed that existing SCRs will achieve a NOX emissions rate of 0.058 lbs/mmBtu, even though industry experiences suggests that 0.1 lbs/mmBtu is more appropriate for SCRs installed over the last decade). [EPA-HQ-OAR-2009-0491-2707.1, p.3]
EPA's Phase I NOx and SO2 Caps Are Premised On Incorrect Assumptions About The Level Of Emissions Controls Actually Achieved By Existing Emission Controls [EPA-HQ-OAR-2009-0491-2707.1, p.18]
As noted above, the Proposed Rule assumes that compliance with the Phase I deadline will be relatively easy because it will only require EGUs to either: (i) operate emissions controls year-round that are currently operated less frequently, such as NOx controls that have, until 2009,only been operated during the summer ozone season (May 1st  -  September 30th), and (ii)complete the installation of proposed controls that are scheduled to go online by 2012. Using these assumptions about the emission controls which will be in place by 2012, the Agency developed emissions estimates for each affected EGU based on its assumptions about the level of NOx and SO2 removal provided by those controls. For example, under the Proposed Rule, EPA assumed that existing SCRs will achieve a NOx removal efficiency of 90%, resulting in an emissions rate of 0.058 lbs/mmBtu. EPA may presume this assumption is reasonable for newly installed NOx controls operating under ideal conditions (e.g., at peak load, with fresh catalyst, and not accounting for start-up and shut down periods; see below). However, EME does not believe EPA's assumption is accurate for existing SCR systems that may only achieve approximately a 0.1 lbs/mmBtu NOx emissions rate. [EPA-HQ-OAR-2009-0491-2707.1, pp.18-19]
EME submits that the EGUs covered by the Proposed Rule will not be able to comply with the emission caps proposed in either Phase I or Phase II of the Rule. With respect to Phase I, EPA claims to have set those caps based on emissions reductions that are obtainable using existing controls that are currently available, or will those that will be installed by 2012. 59  [EPA-HQ-OAR-2009-0491-2707.1, pp.27-28]
However, EPA's assertion with respect to the feasibility of the 2012 deadline relies exclusively on its assumptions about the emissions rate reductions that will be achieved by those "existing controls." As explained above, EME has concluded that EPA relied on unrealistic assumptions about the control rates obtained by controls that have been installed over the last decade, and therefore has overstated the emission reductions that can be obtained by 2012. EME does not object to the premise that sources should be required to obtain by 2012 the maximum level of emission reductions that can be achieved using existing controls; EME simply believes that EPA has overstated the level of achievable reductions by assuming control efficiencies that are not supported by the available data. EME submits that EPA should recalculate the 2012emissions caps to reflect the emissions reductions that are actually available based on existing controls. Data on the performance of these controls is readily available as all sources affected by the Transport Rule monitor their emissions using CEMs. EME believes that any reanalysis will result in an increase the emissions budgets during the Transport Rule's Phase I compliance period. [EPA-HQ-OAR-2009-0491-2707.1, p.28]
Footnote 46: 75 Fed. Reg. at 45273. However, EPA may be greatly underestimating the controls required to meet the Transport Rule caps. For example, recent investment company research suggests that in order to comply with the Transport Rule and Utility MACT caps, companies will need to invest in approximately 40 GW of scrubbers. See UBS Investment Research, E&C and Utilities Call with ICF on EPA Regulations 1 (Sept. 16, 2010). Other investment company research suggests that meeting the Transport Rule's 2014 target for SO2 emissions will require the installation of SO2 scrubbers at 6% of U.S. coal fired power plants that generate 118 million MWh. See Bernstein Research, U.S. Utilities: EPA Announces Its Proposed Transport Rule to Replace CAIR; How Will the Coal Fleet Be Affected? 2 (July 7, 2010). [EPA-HQ-OAR-2009-0491-2707.1, p. 18]
Footnote 59: EME notes that EPA is not in the best position to know precisely for each EGU the types of controls in place, how they are performing, what additional controls are contemplated, and the timeline for installing such controls. Such information gathering and generation is better left to the states, which have a much closer connection to the actual sources themselves because they are dealing with a smaller universe of potential sources. In addition to the concerns above, EME is concerned that in bypassing the State SIP development process, EPA may have relied on assumptions about available controls that are not supported by real world conditions because the Agency did not have the most current or accurate data. EME anticipates that other groups, such UARG, will provide examples of such omissions/errors, and therefore endorses any concerns raised by those comments. [EPA-HQ-OAR-2009-0491-2707.1, p. 28]
Electric Energy, Inc.
While the IPM model may be a useful planning tool for looking at different control scenarios it does not contain sufficient information on each Utility company and unit to make reasonable assumptions about controls or operation. For example in the IPM V 3.02, Joppa was shown as having FGD's on all six units by 2014. The IPM V 4.10 TR SB Limited Trading case shows these same units as 'Coal Early Retirement. And under IMP 4.10 TR SB Limited Trading AEO Gas no controls are assigned and none of the units are retired. These are vastly different outcomes with the likelihood of different allowance allocations from three separate runs of the IPM model. [EPA-HQ-OAR-2009-0491-2628.1, p.2]
Empire District Electric Company (Empire District)
The IPM data used as the base case to develop CATR is flawed due to the fact that it uses 2005 information which does not account for current pollution control equipment installed since 2005 as well as accurate projected emissions for 2012.  Corrected data should be utilized in all modeling platforms that EPA used to develop the CATR including IPM, SMOKE, and CAMx modeling.   Once all the modeling is completed revisions to CATR, if any, should be made and CATR revised. [EPA-HQ-OAR-2009-0491-2659.1, p.3]