b. Do 3rd party consultants who are commissioned by the EPA have an unavoidable bias to skew the inputs in a way that supports the EPA's political objectives?
c. Has the EPA at least worked obtained a certification from the DOE that any and all energy related inputs that were obtained from 3rd party consultants are consistent with the DOE's official forecast. [EPA-HQ-OAR-2009-0491-2742.1, p.11]
d. Why does the American taxpayer fund the DOE if even a sister agency of the United States Government like the EPA looks to 3rd party consultant for key energy related assumptions?
e. Why does the DOE, our countries experts on energy, not 'own' the energy related modeling aspects of the Proposed Transport Rule?
I request the EPA that obtain a 'certification of reasonableness' for all energy related assumptions from the Department of Energy. [EPA-HQ-OAR-2009-0491-2742.1, p.12]
14. Coal EGU Retirements - The EPA estimates that under the provisions of the Proposed Transport Rule approximately 1,200 MW of coal-fired generation may be removed from operation by 2014.75 Fed Reg. at 45357. This estimate is significantly lower than the estimates calculated by notable blue-chip energy consulting firms. Because of confidentiality issues that prevent the disclosure of proprietary analysis, I am unable to convey the specific results of their analysis as part of these comment since these comments will be made part of the public record. However, I will comment that the range of estimated coal EGU retirements provided blue-chip energy consulting firms through 2015 ranges from 30,000 100,000 MW. I urge the EPA to challenge the validity of their estimate. [EPA-HQ-OAR-2009-0491-2742.1, p.12]
I request that the EPA commission a independent review of their estimated number of retirements for at least three blue-chip energy consulting firms. [EPA-HQ-OAR-2009-0491-2742.1, p.12]
15. Control Efficiency Assumptions - The EPA makes inconsistent assumptions about the control efficiencies of existing control equipment compared to similar control equipment which is expected to be constructed. For example, some existing SO2 control equipments is being modeled assuming control efficiencies as high as 98% while expected new scrubbers are being modeled at 95%. Because of the variation in existing control equipment and across states and the expectations of future control equipment, this inconsistency bias the methodology for determining individual state allowance budgets. [EPA-HQ-OAR-2009-0491-2742.1, p.12]
I request that the EPA make uniform internally consistent assumptions about the control efficiencies of all SO2 control equipment to prevent biasing existing control equipment any future allowance allocation budgets. [EPA-HQ-OAR-2009-0491-2742.1, p.12]
17. Oklahoma Inclusion in Seasonal Ozone Region -- The EPA contents that base on its state by state contribution analysis Oklahoma had one 'linkage' where it contributed 0.8 ppm or more to downwind 8-hour nonattainment in Tarrant County Texas. 75 Fed. Reg. 45269. The EPA also contends that ozone emission from Oklahoma is linked to maintenance issues in 3-counties including Dallas TX. Dallas TX, and Tarrant TX. The Proposed Transport Rule goes on to define ozone season as May through September. 75 Fed. Reg. 45214. A review. An analysis of climatologically data from the National Climate Data Center ('NCDC') challenges the validity of EPA's linkage of Oklahoma to non-attainment or maintenance issues in Texas. Based on actual wind direction data from the NCDC from 2000-2009 for the aggregate months of May through September. The pervading wind measured at the Tulsa International Airport (TIA) and Will Rogers (OKC) averages from the south 71.4% and 72.4% of the time, respectively. Further, in the traditionally higher ozone months of July the proportion of time that the prevailing wind is from the south as measured TIA and OKC is higher measuring 78.1% and 80.6%. For August, the proportions for TUL and OKC are 74.8% and 77.1%. Given these patterns it is hard to imagine that Oklahoma has a downwind impact on Texas. [EPA-HQ-OAR-2009-0491-2742.1, p.13]
I request that the EPA provide a explanation as to how Oklahoma is supposedly creating downwind problems for Texas during the May-Sep Ozone season when during that time of year the prevailing wind direction is from the South. [EPA-HQ-OAR-2009-0491-2742.1, p.14]
18. International Transport of Emissions - There is recent scientific research that indicates increasing emissions from Asia that are being transported through the atmosphere to the United States are outpacing domestic emission reductions. Did the EPA attempt to estimate these international emissions and remove (i.e. normalize) them from the air quality modeling prior to estimating states significant contribution? Downwind states should not be held responsible for reducing emissions that come from another country.
I request the EPA provide documentation about how the attempted to quantify the impact of emission that are transported from countries outside the United States. [EPA-HQ-OAR-2009-0491-2742.1, p.14]
Piney Creek LP
The modeled fuel costs are more than twice the costs experienced by Piney Creek and exceed the current actual fuel costs for five representative Anthracite Region Independent Power Producer Association (ARIPPA) plants cost which averages $1.48/mmBtu. This average is actually somewhat inflated insofar as it includes, on some cases, costs not directly attributable to the cost of fuel, including ash disposal. [EPA-HQ-OAR-2009-0491-2849.1 p.1] [EPA-HQ-OAR-2009-0491-3809.1_NODA, p.1]
The Proposed Rule's reliance on fuel cost as the primary basis for projecting future generating rates fails to adequately account for numerous other factors affecting generating rates. For example, in Pennsylvania, electricity distribution facilities and suppliers are required to supply a certain percentage of energy from Tier I or Tier II renewable energy sources, irrespective of electricity prices. Therefore, distribution of the generation of electricity will not strictly adhere to lowest cost of generation, as other operative criteria dictate distribution. Because waste coal-generated electricity qualifies as a renewable energy source, waste coal-fired sources such as Piney Creek will operate at a higher generating rate than cost alone would suggest. [EPA-HQ-OAR-2009-0491-2849.1 p.1] [EPA-HQ-OAR-2009-0491-3809.1_NODA, pp.1-2]
EPA's estimated heat input also does not take into account Piney Creek's long term ( through 2017) Power Purchase Agreement (PPA) with First Energy. Piney Creek is contractually required to operate as a base loaded plant, subject to certain allowances for maintenance and downtime, regardless of relative costs of generation. [EPA-HQ-OAR-2009-0491-3809.1_NODA, p.2]
PPG Industries, Inc.
PPG supports use of the updated IPM for use in making screening decisions to assist in making findings of 'significant contribution' or 'interference with maintenance' under Clean Air Act Section 110(d). PPG urges EPA, however, to make certain updates to the assumptions and inputs for IPM v. 4.10 as discussed in these comments. Further, as indicated in PPG's original comments, the IPM Base Case, whether premised on v. 3.02, v. 4.10 or some future version, should only be a screening tool for indications of potential 'significant contribution' or 'interference with maintenance'. The IPM is simply not accurate enough and is dependent upon too many uncertain assumptions and imprecise inputs to make binding decisions of 'significant contribution' or 'interference with maintenance.' EPA should always place great weight on empirical data to modify projected model conclusions when making these determinations. [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.2]
The significant difference between the results of the v. 3.02 and v. 4.10 Base Case show the imprecision of the IPM model. Due to this imprecision and the uncertainties attendant to the many assumptions made for the IPM modeling, PPG believes that an IPM projected impact of less than 2 ppb from an upwind to a downwind state should never be used as a level indicating 'significant contribution' or 'interference with maintenance' under the 'good neighbor' provisions of the Clean Air Act, 42 U.S.C. 7410(a)(2)(D). At most, the IPM should be used as a screening tool for making rebuttable presumptions for 'significant contribution' or 'interference with maintenance' determinations if a value above 2 ppb contribution is modeled. However, such presumptions should be always subject to a reasonable opportunity for rebuttal by empirical evidence and a weight of evidence approach used to determine if there is actually such contribution or interference. PPG urges EPA to adopt this 2 ppb rule as a bright-line cut-off for screening. If the modeled contribution is 2 ppb or below, then no contribution or interference should be presumed. If the modeled contribution is above 2 ppb, then there could be a rebuttable presumption of contribution or interference. [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.4]
PPG believes, for the reasons stated in the comments of the staff of the Louisiana Public Service Commission (LPSC) on the proposed CATR/FIP, that the IPM fails to adequately consider transmission constraints within Louisiana. PPG believes this is a deficiency in both the IPM v. 3.02 and v. 4.10. PPG urges EPA to carefully consider the comments of the LPSC staff. [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.7]
PPL Corporation
Additionally, allocating allowances based on future unit-specific emission rates modeled by IPM penalizes units whose future operation and emission rates are inaccurately characterized by a model that may form a basis for forecasting statewide conditions, but realistically cannot be expected to accurately characterize each unit individually. [EPA-HQ-OAR-2009-0491-2739.1, cover letter]
PPL believes that EPA's proposed approach is not legally defensible. A sounder and more equitable approach is an alternative for which the EPA is seeking comment. It would allocate portions of the state budget to each unit within the state based on each unit's proportional share of the state's total heat input from all affected electrical generation units. PPL requests that EPA adopt this alternative approach. [EPA-HQ-OAR-2009-0491-2739.1, cover letter]
[See page 1 of this comment, EPA-HQ-OAR-2009-0491-2739.1, for a table listing EGUs with a MW capacity of over 25 MW that are affected by the rule.]
PPL understands EPA's desire to reduce interstate transport to help bring downwind states into attainment of the PM2.5 and ozone NAAQS. We believe this should be done in an equitable manner and one that provides sources with the greatest degree of flexibility to comply with the rule. Our comments address the following: [EPA-HQ-OAR-2009-0491-2739.1, p.2]
:: EPA's approach toward allocating allowances to individual units
:: Allocations for Martins Creek Units 3&4 and LMBE
:: Apparent errors in the 2012 allocations listed in the proposed rule for PPL's Montour Units 1&2 and Lower Mount Bethel Energy
:: Allocations for Shutdown Units
:: Future Allocations
:: Opt-in Requirements
:: Implementation schedule
:: Support of EPA's preferred, limited interstate trading option
:: Use of CAIR banked NOx allowances
:: Banked allowances under the proposed rule [EPA-HQ-OAR-2009-0491-2739.1, p.2]
Finally, EPA's use of the IPM model to predict unit utilization as a means of allocating allowances is unreasonable and unfair. [EPA-HQ-OAR-2009-0491-2739.1, p.3]
Allocations Based on Assumed Utilization
PPL understands that the EGU allocations were calculated from a combination of recent data and projections by the Integrated Planning Model (IPM). The allocations for most of the units in Pennsylvania are listed as having been based on projections, so, apparently, the emission rates assigned for these units are based on results from IPM runs. IPM is a linear programming model that can project capacity utilization and emissions control strategies based on a least-cost optimization of constraints such as demand, environmental requirements, fuel, transmission capabilities, reliability, control technologies, the dynamics of the allowance market and dispatch strategies. [EPA-HQ-OAR-2009-0491-2739.1, p.4]
PPL agrees with the use of IPM as a tool for projections of overall utilization and costs. We believe that it is valuable for projections of statewide emissions that would be smoothed or averaged over all units. But, to be assumed to be accurate for each individual unit is expecting too much of the model. [EPA-HQ-OAR-2009-0491-2739.1, p.4]
It is hard for PPL to understand why EPA would rely on unit-specific IPM output, which obviously has error bars around it concerning individual unit projections, to allocate specific emission rates to individual units. In addition to it being inequitable to assign different emission rates to different units, to do this with a model subject to uncertainty makes this even more inappropriate. [EPA-HQ-OAR-2009-0491-2739.1, p.4]
2. Allocations for Martins Creek Units 3&4 and LMBE
PPL's Martins Creek Units 3&4 are 850 MW natural gas and residual oil-fired units that were installed in the 1970's. They presently operate at less than 10 percent annual capacity factors. The IPM model projects in its projected base case that they will not be operating in the future and they are not provided an allocation. However, PPL plans to keep operating these units into the future. [EPA-HQ-OAR-2009-0491-2739.1, p.5]
PPL understands that EPA does not want to grant allocations to units that do not operate and may in their view be permanently shutdown. However, PPL believes that the Martins Creek units and other units in similar situations should receive an allocation based on recent operation until it is demonstrated with actual operating data that they, in fact, cease to operate. [EPA-HQ-OAR-2009-0491-2739.1, p.5]
[For additional comments pertaining to Allocations for Martins Creek Units 3&4 and LMBE, see p.5 of this comment]
The following table lists the annual amounts that these units would be allocated if their base year operating levels and emission rates as presented in the draft Transport Rule data were used rather than the IPM projected operating levels. An even better alternative would be to assign and adjust the allocation based on updated three-year average heat inputs similar to the approach of the NOx SIP Call (as we discuss in Comment 5 below). In the following table PPL provides recommended SO2 allocation levels for LMBE, a natural gas only fired facility. If EPA decides to exclude natural gas-fired units from the SO2 program, as PPL recommends in Comment 1 above, there would be no need for those SO2 allocations. [[EPA-HQ-OAR-2009-0491-2739.1, p.5] [See page 6 of this comment for the table.]]
3. Apparent Errors in the 2012 Allocations Listed in the Proposed Rule for PPL's Montour Units 1&2 and Lower Mount Bethel Energy.
Under EPA's proposal for allocating allowances to individual EGUs, there appear to be errors in the allocation for PPL's Montour generating units (ORIS Code 3149). As PPL discussed in Comment 1 above, PPL does not believe that this proposed approach is equitable and recommends that EPA select an alternative approach. Nevertheless, PPL wants to identify the apparent errors. [EPA-HQ-OAR-2009-0491-2739.1, p.6]
[For additional comments on Montour and Lower Mount Bethel Energy units annual NOx allocation, see pp.6-7 of this comment.]
Prairie State Generating Company, LLC
Prairie State Generating Company, LLC ('PSGC') is a new, mine-mouth, coal-fired electric generating station located in Washington County, Illinois . PSGC has 'planned units' as described in footnote 85 of the proposed Transport Rule at 75 Fed. Reg. 45309 (August 2, 2010). The power station consists of two coal-fired supercritical steam boilers . This facility is planned and fully funded with construction well under way and will produce approximately 1750 GMWe when operational. The PSGC units will be equipped state of the art air pollution control technology, including low NOx burners and selective catalytic reduction to control emissions of nitrogen oxides, dry and wet electrostatic precipitators to control particulate emissions, and wet flue gas desulfurization to control emissions of sulfur dioxide. Upon review of the NEEDS v4.10 data presented in the Notice of Data Availability (75 Fed. Reg. 53613), PSGC has been unable to locate data for its units (PC 1 and PC2).
PSGC has included an enclosure with this letter which provides data to be added to the NEEDS database for appropriate consideration of PSGC's two coal steam boilers .
The link to the PSGC PSD Construction Permit is as follows :
http://yosemite epa gov/r5/inpermt nsf/6f1ebc583aad45448625763fI)053e08e/4332eb42380489a286257 7a4004aaa43/$FILE/ATTB513Z/O 1 100065.pdf
[EPA-HQ-OAR-2009-0491-3712 p.1]
In addition, the U.S. EPA has failed to account for the improvements which have occurred in air quality in recent years. For example, in the case of Illinois, the IPM projects that multiple counties will violate or that maintenance will be compromised for the 1996 and 2006 PM2.5 standards without (and, in one instance, with) the Transport Rule in place, yet based on 2007-2009 data, all monitoring sites in the state meet both the 35 ug/m[3] 24-hour standard and the 15 ug/m[3] annual standard with 2010 continuing this trend. The U.S. EPA designated the entire state attainment for the 2006 24-hour PM2.5 standard. 74 Fed. Reg. 58688 (November 30, 2009). The U.S. EPA has also found that air quality in the Chicago area attains the 1997 PM2.5 standard. 74 Fed. Reg. 62243 (November 27, 2009). PSGC understands that the U.S. EPA plans to issue the same finding for the Metro-East area in the near future. Using design values based on ozone data through 2009 would yield far different results from the model. The fact that using more current data would provide very different results should be ample reason for the U.S. EPA to revise its modeling. The U.S. EPA's projected results do not comport with the attainment situation based on current data in Illinois and elsewhere in the region. [EPA-HQ-OAR-2009-0491-2842.1, pp.10-11]
By not using more recent data in the entire region, Illinois is penalized for downwind impacts which are not occurring, and in turn, the U.S. EPA has set Illinois' state-wide budget at too low a level. Using more current information will significantly change the conclusions that the U.S. EPA has drawn from its analysis. [EPA-HQ-OAR-2009-0491-2842.1, p.11]
15. NEEDS DATABASE
Enclosure 1 provides the data necessary for the U.S. EPA to update the NEEDS database with PSGC's current information. This data was submitted under separate cover to this docket and to the Clean Air Markets Division by letter dated September 28, 2010.
[Enclosure 1 can be found on page 12 of this comment.]
Progress Energy Service Company
EPA proposes to set state emission budgets for annual and ozone season NOx and for S02 based on the quantity of emissions that remain after elimination of significant contribution to nonattainment and interference with maintenance, but before accounting for variability. In its technical support document (TSD) addressing state budgets, EPA explains that it calculated state budgets using a combination of emissions and heat input data reported to EPA as of 2009 and projections by the Integrated Planning Model ('IPM') for 2012, each adjusted to reflect emissions control equipment projected to be in place by 2012. See 'State Budgets, Unit Allocations, and Unit Emissions Rates' TSD at 3, 5. [EPA-HQ-OAR-2009-0491-2831.1 p.6]
In that TSD, EPA notes that in creating the state budgets for annual and ozone season NOx, it 'rebased' annual and ozone season NOx emissions for units reporting emissions data to EPA by using 2008 rather than 2009 heat input. According to EPA, this adjustment was made 'to account for unusually low utilization in 2009.' However, EPA did not make a similar adjustment for unit-reported S02 emissions. EPA does not provide an explanation for this differential treatment between the two pollutants. Progress Energy requests that EPA clarify and explain more fully why it chose to use 2008 instead of 2009 data for Ox and explain why it did not do the same for S02 data reported to EPA. In addition, many utilities, including Progress Energy, burned more natural gas in their units in 2008 than in many other years. A longer baseline period, such as a 5-year average, would be more appropriate to address the year-la-year fluctuations in fuel use and associated emissions.  [EPA-HQ-OAR-2009-0491-2831.1 p.6]
lPM-Modeled Outcomes Often Do Not Reflect Actual Source Operations
IPM predicted that the vast majority of dual-fuel units would run exclusively on natural gas. Therefore, EPA did not allocate S02 allowances to many dual-fuel units. Apparently, IPM concluded that it was most 'economical' to run these units on natural gas and failed to consider seasonal constraints on natural gas supply (e.g., shortage of supply during the winter months). The reality is that many of these units burn oil for significant parts of the year.  [EPA-HQ-OAR-2009-0491-2831.1 p.7]
IPM assumed early retirement for many units by 2014 based on a prediction that these plants would not be economical to run. However, other constraints such as system reliability make this assumption inaccurate in many cases. [EPA-HQ-OAR-2009-0491-2831.1 p.7]
Based on comments and corrections received, Progress Energy urges EPA to revise and re· perform the modeling analysis and, if necessary, re·propose the Transport Rule. This very significant and entirely new regulatory program is much too important and has too many far-reaching implications for the electric sector and the economy as a whole to rely on hastily completed modeling analyses. As stated earlier in this letter, the court did not establish a schedule for EPA to complete a revision to the CAIR. The Agency can and should take the necessary time in order to assure that the Transport Rule is established on a solid factual foundation.  [EPA-HQ-OAR-2009-0491-2831.1 p.7-8]
PSEG Services Corporation
PSEG also supports EPA's use of Integrated Planning Model ("IPM") to set state budgets for 2014 Group 1 SO2 emissions using pollution control cost thresholds. PSEG understands and supports that this methodology would be the basis for establishing any revised state budgets necessary to comply with future NAAQS. [EPA-HQ-OAR-2009-0491-2627.1, p.5]
PSEG recommends that EPA modify the unit allocation methodology. [EPA-HQ-OAR-2009-0491-2627.1, p.5]
Given the nature of what an allocation represents to emission units, the allocation methodology is understandably one of the most complex and controversial aspects of the proposed Transport Rule. To ensure EPA's methodology is defensible on legal and policy grounds, we recommend that EPA develop an allocation method that is based on an approach that is legally defensible, effective, promotes market dynamics to reveal the cost of pollution and engages market pressure to decreasing emissions. [EPA-HQ-OAR-2009-0491-2627.1, p.5]
While PSEG supports the proposed methodology for developing state budgets, it does not support the proposed methodology for allocating allowances to units. PSEG does not support the use of projected emissions from the IPM modeling as the basis for unit-level allocations in 2012 or 2014. The IPM does not consider a range of non-economic factors that influence a company's decision to operate a unit or for the ISO to call upon a unit. As a result, allocating allowances to emission units on the basis of IPM results creates unrealistic scenarios such as running natural gas combined cycle units at higher utilization than can be accommodated by the natural gas pipeline network or not running oil-fired units that are required to operate to meet reliability and capacity requirements. These distortions of the electricity market are masked when data are aggregated at the state level for setting state budgets but result in inequities when used at the unit level to allocate allowances. As we note above, PSEG believes it is important for EPA to propose a rule that withstands, and preferably forestalls litigation and that can be implemented as quickly and smoothly as practicable. We are concerned that using modeled projections for the emission unit allocation is inherently complex and has the potential for significant flaws that the rulemaking process cannot appropriately address for the rule to be implemented by January 2012. [EPA-HQ-OAR-2009-0491-2627.1, p.6]
Therefore, PSEG recommends that EPA modify the unit allocation scheme. As EPA recognizes in its approach for the 2014 Group 1 SO2 program, there is no strong policy reason, and no legal reason, that the methodology for determining state budgets and the methodology for distributing allowances to units need to be the same. Below, PSEG proposes an alternative emission unit allocation approaches that is consistent with the D.C. Circuit court's decision because it does not alter the state budgets, which are based on each state's significant contribution. Additionally, PSEG's proposed approach is fuel neutral and would not raise the concerns similar to those identified by the court regarding CAIR's use of fuel adjustment factors. The court rejected the fuel adjustment factors because they placed a disproportionate burden on downwind sources compared to the upwind sources contributing to the nonattainment problems. [EPA-HQ-OAR-2009-0491-2627.1, p.6]
We strongly recommend that EPA consider basing the unit allocations on a unit's proportion of its state's historic heat input (i.e., million British thermal units, mmBtu). The historic heat input should be based on the maximum annual heat input for units during the period of calendar years 2007 through 2009. We recommend using the annual maximum of reported data during the three year period rather than the average of those three years in order to ensure an outlier year does not dramatically affect the allocation (e.g., the unusually low utilization in 2009 related to the economic downturn). In cases where an owner has not reported heat input data for one or all of the years, we propose that EPA allow the owner to submit such data for consideration. [EPA-HQ-OAR-2009-0491-2627.1, pp.6-7]
Such an allocation methodology would address many of PSEG's concerns with EPA's preferred approach. Most significantly, it would not be based on modeled future emissions and it is based on data EPA already has from companies. Additionally, it would correct the proposed methodology that disadvantages early actors that EPA acknowledged in the preamble to the proposed rule. It is important to note that PSEG is proposing this approach with the ultimate goal of having the rule be implemented by January 1, 2012. Thus, we would welcome the opportunity to discuss and provide feedback on any additional allocation approaches suggested in other stakeholders' comments. However, PSEG would strongly oppose an allocation approach that was based solely on historic emissions as that approach would again penalize early actors, and their customers, that are already paying for the installation of control technologies. Emissions-based allocations, similar to the fuel adjusted heat input-based allocation rejected by the D.C. Circuit, reward higher emitting facilities at the expense of early actors and discourage future early action by companies. Penalizing early actors and rewarding high emitters is exactly the wrong signal EPA should send to industry as the Agency works to develop and implement the multiple regulations for the electric sector and other industries. [EPA-HQ-OAR-2009-0491-2627.1, p.7]
If EPA finalizes the allocation methodology approach using the preferred option, PSEG recommends that EPA revise specific aspects to support EPA's ability to implement the rule by January 1, 2012. [EPA-HQ-OAR-2009-0491-2627.1, p.8]
PSEG is concerned that EPA's proposed methodology disadvantages natural gas peaking units relative to other higher emitting units. Because these units have low annual emissions and typically are only run at times of high demand, the IPM model projects SO2 emissions of less than 0.5 tons. Based on the proposed methodology, EPA would round these allocations to zero when calculating the unit's allowance allocations. If EPA retains the preferred allocation methodology, PSEG recommends that EPA at least round-upward each of these units' allocations to one ton so as not to discourage use of cleaner fuels during periods of electric peak demand. [EPA-HQ-OAR-2009-0491-2627.1, p.8]
San Miguel Electric Cooperative, Inc.
2) The following correction to the IPM Parsed files of the TR base case, SB limited trading case, SB intrastate trading case and Direct control case runs are required:
-The SCR needs to be deleted as a retrofit in each of the Transport Rule model runs.   [EPA-HQ-OAR-2009-0491-2641.1,p.3]
-The heat input should indicate a base load unit. If San Miguel were allocated allowances based on the current IPM model TR Base Case, San Miguel would be operating only during the ozone season and at reduced capacity of approximately 61.3%. As stated above San Miguel is a low cost unit to our members and is operated as a base load unit.   [EPA-HQ-OAR-2009-0491-2641.1, p.4]
Santee Cooper
The unreasonableness of the EPA allocation scheme is further evidenced by EPA's decision to base allowance allocations to existing units on projected emissions from these units after eliminating significant contribution and interference with maintenance. Specifically, EPA proposes to project each unit's emissions based on the Integrated Planning Model (IPM), which may be a useful analytic tool for forecasting region wide trends, but is highly unreliable for forecasting how specific units will actually operate in the future. Chart V [See p. 24 of this comment summary for Chart V] illustrates the coal system emission rates utilized by the IPM for allowance allocation. Again, Santee Cooper receives allowances at rates far below the other South Carolina utilities and far below what its consent decree limits require. [EPA-HQ-OAR-2009-0491-2820.1, pp.23-24]
At best, projecting future emissions for any particular unit based on IPM analyses can forecast on only how that unit could perform based on a range of assumptions and other data input - much of which may not ultimately have a close correspondence to actual conditions and circumstances. IPM modeling, for example, must make assumptions on a wide range of factors, including electricity demand, fuel prices, use of specific coal type, control costs, resource mix (both among fossil and non-fossil generation), marginal cost of power, timing and type of capacity additions. Further, the IPM model does not consider transmission constraints or variations in demand growth on the state or sub-regional level. Transmission constraints playa large role on dispatch decisions, particularly at times of high demand. Variations in demand growth are very important in South Carolina where certain service territories of some electric utilities are expected to experience high growth, while the electric demand of other electric utility service territories may remain flat or have low growth. As part of its integrated resource plan (IRP), Santee Cooper undertakes extensive modeling of economic growth and electricity demand at multiple areas within the state. Even accounting for the current economic downturn, Santee Cooper serves some of the most rapidly developing areas of South Carolina. These include the growing suburban areas outside of Charleston, Columbia, Aiken, and North Augusta as well as the coastal areas of Myrtle Beach and the Grand Strand, Hilton Head Island, Kiawah Island, and Seabrook Island. [EPA-HQ-OAR-2009-0491-2820.1, pp.24-25]
It is unrealistic to expect that even the most reasonable assumptions will prove to be accurate to make reasonable projections on how specific units will actually operate and what their emissions levels will be.  [EPA-HQ-OAR-2009-0491-2820.1, p.25]
At worst, the IPM analyses are based on arbitrary assumptions and erroneous data that further distorts the accuracy of projected emissions levels, particularly at the unit specific levels. As discussed in subsection C below, the assumptions and data used for the IPM analyses contain significant errors and inaccuracies with respect to operation and performance of the affected units within Santee Cooper system.  [EPA-HQ-OAR-2009-0491-2820.1, p.25]
For these reasons, Santee Cooper believes that IPM modeling is an inappropriate methodology for allocating allowances to existing affected units under the Transport Rule. The use of theoretical models like IPM will- by definition - have arbitrary, random, and illogical results that - among other things - will penalize electric utilities that have made the capital investments to control their emissions. If, however, EPA decides to allocate allowances based on projected emissions levels, EPA must greatly improve the quality of modeling inputs, including the assumptions and data used in the IPM modeling. Subsection C below briefly describes the faulty assumptions and inaccurate data that need to be corrected in the IPM analysis for the Santee Cooper system units. [EPA-HQ-OAR-2009-0491-2820.1, p.25]
THE ASSUMPTIONS AND DATA USED FOR THE IPM ANALYSES NEED TO BE CORRECTED FOR UNITS WITHIN THE SANTEE COOPER SYSTEM. [EPA-HQ-OAR-2009-0491-2820.1, p.25]
The principal analytical tool on which EPA relied in developing the unit allowance allocations and statewide emission budgets in the Proposed Transport Rule is IPM. As explained in a technical support document for the proposed Transport Rule, the IPM 'provides forecasts of least-cost capacity expansion, electricity dispatch, and emission control strategies for meeting electricity demand, environmental, transmission, dispatch, and reliability constraints." Notwithstanding the considerable analytic power of the IPM, there are important limitations on the accuracy and usefulness of the model. One important limitation is the quality of the inputs to the model. Among the most critical inputs to IPM are the emission inventory and unit-level characteristics and operating parameters. The primary source for unit-level emission information for IPM is the National Electric Energy Data System (NEEDS), which provides the unit-level EGU characteristics used as input for the IPM. The NEEDS database is fraught with significant errors, as illustrated below with respect to the Santee Cooper system. In addition, other inputs can be used for, and limitations placed on, IPM analyses to reflect particular, unique situations such as state-specific regulations of EGU emissions and NSR settlements that may limit those emissions. IPM refers to such inputs as 'constraints.' The discussion below also details various errors in the 'constraints' EPA placed on the IPM model runs with respect to the Santee Cooper system. [EPA-HQ-OAR-2009-0491-2820.1, p.26]
Finally, the outputs from EPA's IPM runs, when compared to actual unit-specific data and individual companies' plans, are inaccurate and unrealistic. The validity of a given set of outputs from an application of any modeling tool is brought into question when the modeled results do not reflect real-world conditions. The discussion below provides specific examples of inconsistencies between EPA's IPM projections and Santee Cooper's plans for its units. [EPA-HQ-OAR-2009-0491-2820.1, p.26]
Santee Cooper has compared projected heat inputs with data assumptions for the Santee Cooper system in the EPA-HQ-OAR-2009-0491-0074 1 data sheets. Heat inputs for Cross 2, Grainger Units I and 2, Jefferies Units 3 and 4, and Winyah Units 1,2, and 3 are not indicative of normal or future projected operation levels. The following are discrepancies so far identified: [EPA-HQ-OAR-2009-0491-2820.1, p.27]
Heat input for Cross Unit 2 is significantly lower in the data sheet when compared to expected operation of Cross Unit 2 in 2012 and 2014. [EPA-HQ-OAR-2009-0491-2820.1, p.27]
Heat input levels for Grainger Units 1 and 2 are lower in the data sheet when compared to expected operation of these units in 2012. [EPA-HQ-OAR-2009-0491-2820.1, p.28]
Heat input levels for Jefferies Units 3 and 4 are much lower in the data sheet when compared to expected operation of these units in 2012 and 2014. [EPA-HQ-OAR-2009-0491-2820.1, p.28]
Heat input for Winyah station is lower in the data sheet when compared to the expected operation of these units in 2012. [EPA-HQ-OAR-2009-0491-2820.1, p.28]
One reason for the heat input shortfall is that the IPM projections only reflect native load demands and do not include off-system sales. Once off-system sales are factored into future load projections, heat input levels for the Santee Cooper's system increase by almost an additional 5 percent - much of which will be concentrated in the higher-emitting Grainger and Jefferies units.' [EPA-HQ-OAR-2009-0491-2820.1, p.28]
These discrepancies further demonstrate that allowance allocations under the Transport Rule should not be based on the results of the IPM projections for individual units. However, even if this method is used, the use of unit emission rates and other operating data from a single year (2009) is unrepresentative and therefore will by definition have arbitrary effects. Among other things, one year's emission rates are not a reasonable indicator of unit performance due to control equipment degradation and maintenance cycles as well as variations in the sulfur content of coal. At the very least, EPA should base allocation based on a multi-year average of IPM projections if EPA insists on using this approach. [EPA-HQ-OAR-2009-0491-2820.1, p.28]
Finally, IPM projection errors of this sort appear to be a function of inherent limitations of IPM and EPA's limited knowledge of certain local factors. IPM is a least-cost economic model designed to predict operations at a fairly broad regional level. In many instances, EPA lacks sufficient information about local issues such as transmission constraints, capacity commitments, fuel-contract commitments, and other cost-related considerations that have not been input to the IPM model. EPA's insufficient information, coupled with the limitations of the regional IPM model, result in inherently unreliable and arbitrary projections at the unit-specific level that are inappropriate for use in allocating allowances to affected units under Transport Rule. [EPA-HQ-OAR-2009-0491-2820.1, p.28]
South Carolina Department of Health and Environmental Control
It is important that the EPA use appropriate modeling tools and assumptions in the final Transport Rule, since it will use this same modeling approach in future iterations of the Transport Rule. Also, the EPA is relying on IPM as the sole solution in determining budgets and allocations. DHEC has encountered problems with IPM while modeling for regional haze with VISTAS, the Visibility Improvement State and Tribal Association of the Southeast. The problems included mistaken control efficiencies and missing information. We found similar problems in the Transport Rule supporting data, though, because of time constraints, we are unsure that we have caught every problem. Under the NOX SIP Call and CAIR, states and the EPA based allocations on actual usage data from the EPA Clean Air Markets Division (CAMD) database, a much more transparent and reliable process than uncertain IPM projections. IPM, a registered trademark of the ICF Corporation, is a proprietary system, and we do not have the opportunity to review all of its assumptions. With IPM making many of the regulatory determinations, it is important to ensure its assumptions are correct and its use within the Transport Rule is sound. [EPA-HQ-OAR-2009-0491-2677.1 p.5]
Southern Company
1. EPA Made Significant Errors in the Base Case Emissions Inventory As discussed previously, EPA attempted to remove the existence of CAIR from the base case emissions. This is not a correct assumption, because in the absence of a final Transport Rule, emission reductions from CAIR and state rules will continue. Thus, even if the Transport Rule were not promulgated in 2012, CAIR would remain in place. In removing CAIR from the base case, EPA made numerous unreasonable assumptions. For Georgia, in particular, the IPM modeling projects unreasonably high S02 emissions from several coal units in the 2012 base case. [EPA-HQ-OAR-2009-0491-2864.1, p. 39]
IPM projects 2012 base case emissions for seven Georgia Power units to be nearly three times their historical emissions (See table below). The over-projection by IPM is so large that it is equivalent to the entire 2012 Transport Rule budget for Georgia. Using our replicated version of the AQAT, we found if EPA used appropriate emissions for Georgia in the 2012 base case, Georgia would not be linked to the Baltimore City, MD, monitor and would, therefore, not be classified as a Group 1 state. Furthermore, as is documented in Section X of these comments and in comments submitted by others, including UARG and the FCG, IPM made erroneous 2012 emissions projections for a number of other states as well.  [EPA-HQ-OAR-2009-0491-2864.1, p. 39]
2. EPA's Methodology Did Not Adequately Consider Emissions Reductions That Are Required By Other Rules
Because of flaws in the 2012 base case that have been discussed in previous sections, EPA should not have used those emissions in their current form for determining which states are included in the Transport Rule. The state of Georgia, in an effort to address transport issues, local nonattainment issues, and hazardous air pollutants, developed its own Multi-pollutant Rule. The Multipollutant rule requires the installation of specific control technologies at all of the larger coal-fired power plants in the state. As a result, Georgia Power is in the midst of a massive construction program installing NOx and S02 controls on many of its coal-fired units. By 2012, over 50 % of the coal generation operated by Georgia Power will be scrubbed. By 2014 that number will grow to over 70% and by 2015 nearly 90% of Georgia Power's coal generation will be scrubbed. These emissions controls are reflected in the 2014 IPM modeling for the Transport Rule (see Figure XI-3 below) [See EPA-HQ-OAR-2009-0491-2864.1, p. 41 for the Figure]. The 2012 $0 per ton emissions used for the significant contribution test were extremely high. Had EPA evaluated the contribution from Georgia to downwind nonattainment and maintenance monitors in 2014 at $0 per ton of S02, they would have found that Georgia was not linked to nonattainment or maintenance issues at the Baltimore City, MD, monitor. In fact, the only monitors that Georgia is linked to at $0 per ton in 2014 are the two Birmingham monitors, both of which are impacted by local sources. Birmingham has demonstrated monitored attainment for the daily standard and is projected to achieve attainment of the annual standard by 2012 in the Birmingham PM2.5 SIP through reductions achieved by the local sources and CAIR. [EPA-HQ-OAR-2009-0491-2864.1, p. 40]
Sunflower Electric Power Corporation
EPA has received and denied without reasoned basis a number of requests for extension of the comment period to afford concerned parties the opportunity to fully review and consider the proposed rule and the assumptions on which it is founded. Comment 1 above is one small example of the type of errors found in the modeling on which the agency relies. [EPA-HQ-OAR-2009-0491-2833.1 p.2]
EPA analysis did not take into consideration federally enforceable emissions reductions that have already been recently achieved with major Kansas EGUs. The revised analysis, presented separately for all Kansas utilities by Trinity Consultants, a copy of the cover letter for which is attached as Exhibit A, clearly shows that the revised levels of NOX emissions, which have already been achieved by the indicated Kansas sources , reduces the determined impact level below that determined by EPA to be significant. [EPA-HQ-OAR-2009-0491-2833.1 p.2]
Sunflower respectfully requests that EPA remove Kansas for the list of States determined to make a significant ozone contribution to downwind states. [EPA-HQ-OAR-2009-0491-2833.1 p.2]
Tennessee Department of Environment and Conservation, Division of Air Pollution Control
Comment #1 on 2012 Baseline Emissions for Tennessee: The baseline analysis considers emissions reductions associated with the implementation of all federal rules promulgated by December 2008 and assumes that CAIR is not in effect. The following numbers were used for Tennessee: [[See Docket Number OAR-2009-0491-0553.1, p.3 for the table]].
EPA appears to have omitted the SO2 emission limit established at TVA Cumberland in the Regional Haze SIP. Rule 1200-03-23-.03 of the Tennessee Air Pollution Control Regulations (TAPCR)
Upon mutual agreement of the owner or operator of any source and the Technical Secretly, operating hours, process flow rates, or any other operating parameters may be established as a binding limit(s). The mutually acceptable limits shall be stated as a special condition(s) for any permit or order concerning the source. [EPA-HQ-OAR-2009-0491-0553.1, p.3]
BART permit 061875H was issued for TVA Cumberland on March 31, 2008, and submitted to EPA as part of the Regional Haze SIP on March 31, 2008. A copy of this permit is attached (see Attachment #2) [[See Docket Number OAR-2009-0491-0553.1, pp.6-7 for Attachment 2]]. This permit establishes an SO2 BART limit (non-CAIR) of 0.5 lb/mmBtu for regional haze compliance. The permit requires TVA to comply "as expeditiously as possible", but no later than 5 years after approval of TN Regional Haze SIP. [EPA-HQ-OAR-2009-0491-0553.1,p.3]
Our recent discussions with EPA Region 4 indicate that the Agency is in the process of issuing a conditional approval of the non-CAIR portions of Tennessee's Regional Haze SIP. Since TVA Cumberland has existing controls that would allow the facility to meet the 0.5 lb/mmBtu SO2 requirement, we believe that TVA's requirement to meet the BART limit "as expeditiously as possible" at Cumberland by 2012.2 We therefore believe that this limit should be included in Tennessee's 2012 baseline SO2 emissions. [EPA-HQ-OAR-2009-0491-0553.1, p.3]
Assuming a BART limit (non-CAIR) of 0.5 lb/mmBtu SO2 for TVA Cumberland, baseline SO2 emissions for Tennessee would decrease from 596,987 tons to 268,629 tons, as follows:
Existing 2012 Tennessee Baseline: 596,987 tons
Existing 2012 Baseline for TVA Cumberland: 370,891 tons
Revised 2012 Baseline for TVA Cumberland: 42,533 tons
Revised 2012 Tennessee Baseline: 268,629 tons (596,987 tons  -  370,891 tons + 42,533 tons) [EPA-HQ-OAR-2009-0491-0553.1,p.3]
EPA should revise Tennessee's 2012 baseline SO2 emissions from 596,987 tons to 268,629 tons. [EPA-HQ-OAR-2009-0491-0553.1, p.3]
Comment #2 on 2012 Baseline Emissions for Tennessee: The baseline analysis considers all known controls required under consent decrees and other enforceable binding commitments through 2014. We note that "other enforceable binding commitments" appears to include the U. S. District Court decision in North Carolina vs. TVA, since the 2012 baseline includes add-on SO2 and NOX controls at Bull Run, John Sevier, and Kingston fossil plants. That decision was overturned by the 4th Circuit Court of Appeals on July 26, 2010, and EPA may need to adjust the 2012 baseline emissions for Bull Run, Kingston, and John Sevier fossil plants. Adjustments to the baseline emissions for these facilities would increase the baseline emissions above the 268,629 tons indicated in the previous comment. [EPA-HQ-OAR-2009-0491-0553.1, p.3]

Footnote 2: Because the permit language for TVA Cumberland states that TVA must comply with the BART limit "as expeditiously as practicable, but in no event later than five (5) years after publication in the Federal Register of U.S. EPA's approval of Tennessee's Regional Haze State Implementation Plan revision," it could be argued that compliance with the BART limit would not be required prior to 2015. While this assertion may be true for sources that are not using existing controls to comply with BART, we note that, since TVA Cumberland is currently operating below 0.5 lb/mmBtu SO2 using existing controls, the requirement to comply with this limit "as expeditiously as practicable" could be applicable upon approval of Tennessee's Regional Haze SIP. We also note that this limit would be enforceable by EPA upon approval of the Regional Haze SIP (i. e., prior to incorporation of the BART limit into the Title V permit), since the BART permit was submitted to EPA as part of the SIP.
Tennessee Valley Authority (TVA)
TVA Comment: TVA believes it is unreasonable to expect emission reductions by January 2012; a mere 6 months after the date EPA plans to finalize the Transport Rule. EPA explains the establishment of this short deadline on the basis that emission reduction required in 2012 would occur even in the absence of the Transport Rule. As explained above, EPA has made incorrect assumptions about the emission reductions that will occur by 2012. [EPA-HQ-OAR-2009-0491-2782.1, pp. 4-5]
Texas Commission on Environmental Quality
The TCEQ finds that the basic information about the current state of NOx control for EGUs in Texas that the EPA used in the Integrated Planning Model (IPM) runs has substantial errors, which results in unreliable assumptions and predictions produced by the IPM modeling. For this reason, the TCEQ objects to the use of the IPM results in regulatory decision making. [EPA-HQ-OAR-2009-0491-2857.1, p.2]
The basic information about the current state of NOx control for EGUs in Texas that EPA used in the IPM modeling runs has substantial errors. Therefore, the assumptions and predictions produced by the IPM modeling are unreliable and should not be used for regulatory decisions. The TCEQ has found significant errors in the EPA's basecase IPM modeling files that call into question the results of the IPM runs. Units that EPA predicts to be making significant NOx reductions, to a NOx pound per million British thermal units (lb/mmBtu) control level the TCEQ finds to be likely beyond low NOx burner technology, are actually already at that control level from the installation of SCR required by state permit or rule. Yet the IPM basecase model files show only basic NOx controls like low NOx burners or no controls at all. The following are just a few examples of sites where the IPM data files have inaccurate information about the base case NOx control level and the facilities are actually already at SCR NOx control levels: Colorado Bend Energy Center; South Texas Electric Coop (Sam Rayburn); Midlothian Energy Center; Hays Energy Facility; Cottonwood Energy Company; and SRW Cogeneration. Since the EPA obviously does not have an adequate understanding of the current NOx control level for the EGUs in Texas, the EPA should not be rushing forward with rulemaking based on fundamentally flawed data and modeling. Additionally, the TCEQ finds it unreasonable for the EPA to expect that states to correct these errors within the limited time provided. In response to the TCEQ's (and others') requests for time to adequately review this rule, the EPA stated 'We believe the comment period provided is sufficient for interested parties to review the rule, prepare and submit input.' The EPA is misleading the public and itself about the quality of information used to form the cornerstone of the Transport Rule and should allow sufficient comment time to review and correct this clearly flawed data. [EPA-HQ-OAR-2009-0491-2857.2, pp.11-12]
TransCanada
Comment 2: Errors with the National Electric Data System (NEEDS) Data Have Caused Inaccurate Emission Allocation for EGUs and the New York State Budget
There are numerous errors with The National Electric Data System ("NEEDS"), which was used in the proposed Transport Rule to determine each state's significant contribution and interference with maintenance of downwind states. These errors have resulted in inaccurate data and the inappropriate allocation of allowances to New York State and individual units, such as Ravenswood. The SO2 and NOx emission data contained in the proposed Transport Rule's spreadsheets are not consistent with actual emissions data reported and, therefore, should not be used to allocate allowances to New York State or to individual units. [EPA-HQ-OAR-2009-0491-2827.1, p.2]
The inaccurate data has resulted in potential overestimates or underestimates in the proposed Transport Rule's unit specific and state budget allocation process. Since the state budgets for SO2, annual NOx, and ozone season NOx are based on the measurement of each state's significant contribution and interference with maintenance of downwind states, the impact of the inaccuracies in NEEDS may significantly impact EGUs in New York State, such as Ravenswood, by not allocating the appropriate amount of allowances to some units. [EPA-HQ-OAR-2009-0491-2827.1, p.2]
EPA should, therefore, correct the errors and inaccuracies in the data, document the source of the data, account for variability and recalculate the unit specific and state budget allocations. [EPA-HQ-OAR-2009-0491-2827.1, p.2]
Utility Air Regulatory Group (UARG)
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-2009-0491-2756.1, p.9]
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 and having CAIR's allowance trading and enforcement mechanisms remain in effect pending implementation of the Transport Rule. It is unreasonable and unrealistic, for example, 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-2009-0491-2756.1, pp.16-17]
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 ("LNBs"), and in many cases, would not allow sufficient time for sources to switch to burning lower sulfur coal. See section V infra. [EPA-HQ-OAR-2009-0491-2756.1, p.17]
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 the proposed rule and reinitiate rulemaking with a new proposal or issue a supplemental notice of proposed rulemaking for public comment. Under these circumstances, rulemaking could not be completed before the beginning of 2012. [EPA-HQ-OAR-2009-0491-2756.1, p.17]
In any event, 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, 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-2009-0491-2756.1, pp.19-20]
UARG is 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. 16 [EPA-HQ-OAR-2009-0491-2756.1, p.22]
Moreover, EPA ignores the fact that many electric generating companies are not in a position to undertake fuel switching in the near term because of binding fuel contracts. Many electric generating companies may also face capital-access or other constraints that would prevent them from undertaking emission control projects, except perhaps at prohibitively high interest rates, in the near term. In addition, electric generating companies have fiduciary obligations that prevent them from making commitments to capital projects while the nature and scope of emission reductions remain uncertain. As described above in section III.A, the scope of emission reductions that will ultimately be required under the Transport Rule is far from certain. [EPA-HQ-OAR-2009-0491-2756.1, pp.22-23]
In sum, the fact that EPA's proposal to set an initial compliance deadline of January 1, 2012, is so fraught with difficulty and uncertainty is a stark illustration of the ill-advised nature of this attempt to force implementation of such a complex and demanding rule in only six months. [EPA-HQ-OAR-2009-0491-2756.1, p.24]
The January 2012 and January 2014 Compliance Deadlines Set Forth in the Proposed Transport Rule Are Unreasonable and Unrealistic.
In materials prepared to explain its Proposed Transport Rule, EPA made the following assumptions about how low SO2 and NOx emission levels from EGUs 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:
Table V-1 demonstrates that EPA expects its PTR to require substantial additional EGU emission 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-2009-0491-2756.1, pp.32-33] [[See Docket Number EPA-HQ-OAR-2009-0491-2756.1, p.33 for Table V-1]]
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 PTR22) and January 1, 2012. This reduction, says EPA, can be accomplished if affected companies (a) just complete the installations of FGD units 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, EPA takes pieces of information from retrofit experiences at two power stations and uses those scant 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. [EPA-HQ-OAR-2009-0491-2756.1, pp.33-34]
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 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 electric generating 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-2009-0491-2756.1, p.34]
As discussed in greater detail in other portions of these comments and in the comments being filed by individual UARG members, EPA has substantially overestimated the number of FGD and SCR installations that are now under construction and can be operational by January 1, 2012. Therefore, the Agency has greatly underestimated the number of FGD and SCR installations that affected utilities would have to undertake and complete between January 1. 2012, and January 1, 2014, to meet the PTR's requirements. [EPA-HQ-OAR-2009-0491-2756.1, pp.34-35]
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 companies to retrofit FGD and SCR units at existing EGUs. For all of these reasons, it will not be possible for affected EGUs to achieve the substantial SO2 and NOx emission reductions that -- under the terms of the PTR -- must be achieved by that rule's January 2012 and January 2014 deadlines. [EPA-HQ-OAR-2009-0491-2756.1, pp.34-35]
Section V.A provides an overview of the many steps that power plant owners must follow in order to retrofit their power plants with control equipment like FGD and SCR units. A more detailed discussion of these steps is provided in a separate report, which is attached hereto as Attachment I, and is incorporated by reference herein: Cichanowicz, J.E., "Implementation Schedules for Selective Catalytic Reduction (SCR) and Flue Gas Desulfurization (FGD) Process Equipment" (Oct. 1, 2010) (hereinafter "Implementation Schedules Report"). The Implementation Schedules Report was prepared by J. Edward Cichanowicz, who has been involved in -- and has first-hand knowledge of the challenges that can be posed by -- the design, permitting, and construction of FGD and SCR retrofits at many power plants throughout the United States. Next, section V.B of these comments directly addresses the few examples and arguments that EPA has made in support of its highly abbreviated compliance deadlines. Then sections V.C and V.D of these comments provide a broad range of more current examples of FGD and SCR retrofits, respectively. These examples demonstrate the complexity and time-consuming nature of the retrofit installation processes at most sites. EPA's failure to understand this has led the Agency to systematically underestimate the length of time it now takes to retrofit FGD and SCR systems at power plants. [EPA-HQ-OAR-2009-0491-2756.1, pp.35-36] [[See Docket Number EPA-HQ-OAR-2009-0491-2756.1, pp.104-146 for Attachment I.]] [[These comments can also be found in Section VII.C.]]
EPA places all FGD and SCR installation activities into one of essentially three broad overlapping categories: (1) conducting an engineering review of the facility and awarding a procurement contract; (2) obtaining a construction permit; and (3) installing the control technology. EPA, "Engineering and Economic Factors Affecting the Installation of Control Technologies for Multipoint Strategies" (2002) at 7-8, 20, available at www.epa.gov/clearskies/pdfs/multi102902.pdf (hereinafter "2002 EPA Report"). Categorizing the numerous activities involved in installing FGD and SCR systems in such a general way, however, tends to mask the overall complexity of the numerous steps that electric generating companies must actually follow in order to design, permit, and construct FGD and SCR systems at their power stations. The following is a more detailed discussion of all the steps that power plant owners typically take when they retrofit FGD and SCR systems at their stations. [EPA-HQ-OAR-2009-0491-2756.1, pp.36-37]
Step One Requires More Than Conducting an Engineering Review. [[See Docket Number EPA-HQ-OAR-2009-0491-2756.1, pp.27-39 for a detailed discussion on this issue.
A Construction Permit Is Only One of the Many Authorizations that Affected Plant Owners May Need. [[See Docket Number EPA-HQ-OAR-2009-0491-2756.1, pp.39-42 for a detailed discussion on this issue.]]
The Actual Construction of FGD and SCR Systems at Existing Sites Will Take Longer than EPA Suggests. [[See Docket Number EPA-HQ-OAR-2009-0491-2756.1, pp.42-43 for a detailed discussion on this issue.]]
EPA Relies Upon Incomplete and Outdated Information in Concluding that FGD and SCR Retrofits Can Be Installed in a Total of Less than 30 Months. [[See Docket Number EPA-HQ-OAR-2009-0491-2756.1, pp.43-45 for a detailed discussion on this issue.]]
FGD Installations: Real-World Examples Demonstrate that EPA Has Substantially Underestimated How Long It Typically Takes To Retrofit FGD Systems at Power Plants.  [[See Docket Number EPA-HQ-OAR-2009-0491-2756.1, pp.46-49 for a detailed discussion on this issue.]]
SCR Installations: Real-World Examples Demonstrate that EPA Has Substantially Underestimated How Long It Typically Takes To Retrofit SCR Systems at Power Plants. [[See Docket Number EPA-HQ-OAR-2009-0491-2756.1, pp.49-51 for detailed discussion on this issue.
Summary and Conclusions.
Solid information from individual UARG members and detailed information in the Implementation Schedules Report demonstrate that it now takes longer -- often much longer -- than 21 and 27 months to complete retrofits of SCR and FGD equipment, respectively. There are many reasons why FGD and SCR installations take as long as they do, including the complicated physical constraints posed by the sites at which the equipment will be installed (retrofits at any "simple" sites have likely already been done); the complexities of the overall permitting/authorization process that plant owners face today; and the high demand now for the skilled labor force needed to undertake these projects. The extensive amount of information presented in these comments and in the attached report, as well as information in comments from individual UARG members, refute any EPA claim that FGD and SCR installations can generally be conducted and completed in a total of less than 30 months. [EPA-HQ-OAR-2009-0491-2756.1, p.51]
There is also no basis for any suggestion that electric generating companies could cut installation times by 30% to 50% if only they had the will to do so. Such a "field of dreams" approach (something akin to "demand it and it will happen") does not apply to the construction of FGD and SCR systems. If electric generating companies could build such systems in less than 30 months, they would. For these companies, time is money, and the longer it takes to build a mandated project, the more it will cost. Electric generators may not -- and should not -- undertake FGD and SCR retrofits until it is clear that such installations are required and are prudent and consistent with fiduciary obligations to undertake. Once the companies commit to such projects, however, they are highly motivated to complete them quickly in order to minimize costs. [EPA-HQ-OAR-2009-0491-2756.1, pp.51-52]
In summary, EPA has greatly underestimated the amount of time that it takes electric generating companies to design, permit, construct, and start up new FGD and SCR units. It will take longer than 30 months -- in many cases, considerably longer than 30 months -- for companies to complete the retrofits of 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 EPA's proposed January 2012 and January 2014 deadlines. [EPA-HQ-OAR-2009-0491-2756.1, p.52]
In light of this, EPA either should decide not to call for the steep additional emission reductions demanded by the PTR -- because such reductions are not, for reasons discussed in these comments and in comments of individual UARG members, necessary to reduce significant regional contributions to downwind nonattainment and interference with maintenance -- or should extend the PTR's compliance schedule by at least a two-year period beyond the proposed 2014 compliance date (plus an additional interval of time that reflects (i) any additional time that EPA takes to complete this rulemaking beyond mid-2011 and (ii) the reasonable period of time needed by states to implement emission budgets through SIP revisions after final promulgation of EPA's rule). [EPA-HQ-OAR-2009-0491-2756.1, p.52]
EPA's Analysis Significantly Understates the Amount of Electric Generating Capacity that Would Have To Undergo FGD and SCR Retrofits in the 2012-2014 Period and the Associated Demands on Resources; Constraints on Labor Resources Make Compliance With the PTR's Timeline Impossible.
Marchetti, et al., evaluated the likely operational dates for new FGD and SCR projects during this period. They used owner-announced dates where available (as they were for a minority of the projects). For other projects, they used an assumed project-start date of the third quarter of 2011 to reflect EPA's projected date of final promulgation of the PTR, and then assigned implementation schedules for the retrofit installations, applying information derived from the Implementation Schedules Report, as discussed in the previous section of these comments. The analysis shows that the majority of the projects could not be completed until well after January 2014; the largest number of FGD and SCR projects are projected to become operational at various dates between early 2015 and mid-2016. [EPA-HQ-OAR-2009-0491-2756.1, p.54]
This analysis then examined a key resource constraint considered by EPA in the CAIR proceeding, i.e., the demand for boilermaker labor for retrofit installations. The analysis found that boilermaker demand for FGD and SCR installations can be accommodated if the realistic installation schedules applied from the Implementation Schedules Report are assumed. In contrast, if the retrofit projects were somehow otherwise able to be accomplished by 2014, as EPA assumes (a scenario that the Implementation Schedules Report shows is infeasible), then the resulting "logjam" of retrofit projects would require an amount of boilermaker hours that is far in excess of the boilermaker labor supply that was called on for EGU control retrofits in the 2008- 2010 period. Thus, even if EPA's proposed compliance schedule could otherwise be met (and it cannot), there is no basis for concluding that a sufficient supply of skilled labor would be available to do the work necessary to meet the schedule. [EPA-HQ-OAR-2009-0491-2756.1, p.54]
Accordingly, EPA should recognize that under the PTR, the 2012-2014 period could be expected to involve far more FGD and SCR retrofits than its statement in the PTR preamble would suggest. Given the demands that will be imposed on retrofit resources, such as boilermaker labor, due to the congestion of control project installations during this highly compressed period, requiring the PTR's 2014 emission budgets to be met by accelerating retrofit projects that cannot realistically be projected to be completed by that year would both (1) be inconsistent with documented installation schedules (as described in the Implementation Schedules Report and in the previous section of these comments) and (2) be infeasible in any event in light of the available labor, and perhaps other resources, needed to accomplish these retrofits. [EPA-HQ-OAR-2009-0491-2756.1, pp.54-55]
Footnote 15: Nothing in these comments should be construed as suggesting that a compliance date as early as 2015 is necessarily appropriate or could be justified.
Footnote 16: According to LADCO, a fundamental assumption for this state-by-state analysis was a July 2012 start date for the planning, engineering, and construction of any new NOx or SO2 controls, reflecting a January 2011 promulgation date for the final Transport Rule and another 18 months for adoption of SIPs. See id. at 1, attachment at 4. Thus, LADCO properly recognized that a substantial amount of time would be necessary after promulgation of EPA's final rule for states to develop SIPs and submit them to EPA for approval. [[These comments can also be found in Section VII.C.]]
Footnote 22: In presenting the schedule that affected source owners would face in making the additional emission reductions that the final Transport Rule will impose, EPA implies throughout the PTR preamble that the appropriate time for source owners to initiate work on any emission controls that are needed to meet the rule's requirements is when the Transport Rule is finalized. For example, at 75 Fed. Reg. at 45273/1, EPA makes "mid-2011 (when the Agency anticipates finalizing this rule)" the start of the time period in which source owners are to design and construct additional FGD and SCR systems at their plants. EPA is correct in taking this approach. It would be entirely inappropriate for EPA either to require affected source owners to initiate serious work on additional control systems, or to assume that source owners will voluntarily start such efforts, before the Transport Rule is final. Indeed, it would be imprudent for regulated sources, and inconsistent with fiduciary obligations for any affected electric generator, to start making in the near term any major investments in the design and construction of controls that may or may not be needed depending on the terms of the final Transport Rule and the terms of other emission control rules that are scheduled to be published by EPA in the near future and that could affect the control options faced by power plant owners. This is particularly so given the uncertainty as to the outcome of the present rulemaking that EPA has created by publishing the NODA and indicating that the emission budgets and allowance allocations in the final Transport Rule could be very different from those that EPA has proposed.
Virginia Department of Environmental Quality (VDEQ)
VDEQ staff has reviewed several spreadsheets and Technical Support Documents included in the proposed Transport Rule and the NODA, as well as the draft allocations of NOx and SO2 allowances under the preferred option in the rule. This review has highlighted a number of issues I would like to bring to your attention, a number of baseline premises that are obsolete or incorrect, and a number of Unit specific assumptions that should be updated. This information is provided so that EPA can use the best, most representative data and the most accurate future predictions for units in Virginia when modeling downwind impact and when calculating future year allocations. [EPA-HQ-OAR-2009-0491-2595.1, p.3]
VDEQ believes that no facility or unit should have modeled downwind contributions based on future year emissions that are in excess of federally enforceable limits on potential to emit. Modeling excessively high emissions rates may show downwind impacts where none actually occur, thereby inappropriately penalizing states and units by subjecting them to potential Section 126 petitions and additional controls. Accordingly, allocations should also reflect federally enforceable limits. Copies of relevant permits with such federally enforceable limits may be found on VDEQ~s website at http://www.deg.virginia.gov/air/permitting/Mirant.html and at http://www.deq.virginia.gov/info/vchecPermits.html. [EPA-HQ-OAR-2009-0491-2595.1, p.3]
Wabash Valley Power
Notwithstanding the specific errors previously noted, it would seem that the EPA modeling run does not account for the almost certain and substantial increase in operation of natural gas-fired combined cycle units. The myriad of EPA regulations will reduce the economic vitality of smaller and older coal units. With the retirement of these aging small coal units, demand will likely be met by increased utilization of gas-fired facilities. [EPA-HQ-OAR-2009-0491-2627.1,p.6]
we energies
We Energies review of the data inputs used by EPA has uncovered numerous errors, missing values, and other data issues with respect to EGUs that we operate. Unfortunately, the proposed rule has assigned nonattainment and maintenance contributions and made facility-specific allocations based on this erroneous data. EPA must perform a complete data review and use the correct data in its impact and allocation modeling. [EPA-HQ-OAR-2009-0491-2629.1, p.3]
Westar Energy, Inc.
EPA'S MODEL PRODUCES RESULTS THAT OVERSTATE KANSAS EMISSIONS LEVELS [EPA-HQ-OAR-2009-0491-2757.1, p.11]
Besides EPA overstepping its legal bounds by effectively subjecting Kansas to the requirements of the new rule prior to the time authorized by the CAA, the modeling on which the proposed rule relies over estimates the significant contribution and interference of maintenance in identified nonattainment areas that can be attributed to Kansas. See 75 FR at 45262 (24-hour PM2.5 list shows three Milwaukee, WI sites); at 45266 (24-hour PM2.5 list shows Muscatine, IA and Milwaukee, WI sites for maintenance); at 45269 (8-hour ozone shows Dallas, TX site for maintenance). The pre-NODA emission rates used as the basis for the modeling, although identifying NOx and SO2 controls that have been installed on Kansas EGUs, does not incorporate emissions levels that are already being achieved or that must be achieved by 2012 under enforceable permits and agreements. This failure leads to an overstatement of Kansas projected 2012 emissions levels used to identify States that are to be included in the rule. [EPA-HQ-OAR-2009-0491-2757.1, pp.11-12]
When the appropriate EGU emissions level adjustments are made, as shown in the attached Trinity Consultants Report ('Trinity Report') [See p.28 of this comment summary for the Trinity Report], the most significant change relates to the supposed linkage between Kansas' downwind emissions and a nonattainment site in Dallas.3 After the appropriate adjustments are made, downwind modeling at the Dallas site shifts from being above to falling below the 'single 'bright line' threshold for ozone that is one percent of the 1997 8-hour ozone standard of 0.08 ppm,' making the threshold 'a value of 0.8 ppb.' 75 FRat 45237/3. Consequently, the properly adjusted modeling no longer supports a finding that Kansas emissions meet the threshold for contributing to interference with maintenance at the Dallas site. As this is the only site to which Kansas is linked for 8-hour ozone maintenance, 75 FR at 45269, it follows that Kansas should be removed from the list of States subject to the proposed 8-hour ozone rule. [EPA-HQ-OAR-2009-0491-2757.1, p.12]
[See EPA-HQ-OAR-2009-0491-2757.1, pp.11-14 for additional comments pertaining to EPA'S MODEL PRODUCES RESULTS THAT OVERSTATE KANSAS EMISSIONS LEVELS]
Besides EPA overstepping its legal bounds by effectively subjecting Kansas to the requirements of the new rule prior to the time authorized by the CAA, the modeling on which the proposed rule relies overestimates the significant contribution and interference of maintenance in identified nonattainment areas that can be attributed to Kansas. See 75 FR at 45262 (24-hour PM2.s lists shows three Milwaukee, WI sites); at 45266 (24-hour PM2.5 lists shows Muscatine, IA and Milwaukee, WI sites for maintenance); at 45269 (8-hour ozone shows Dallas, TX site for maintenance). The pre-NODA modeling used for those projections, although identifying NOx and S02 controls that have been installed on certain Kansas EGUs, does not incorporate emissions levels that are already being achieved or that must be achieved under enforceable permits and agreements by 2012 and 2014. [EPA-HQ-OAR-2009-0491-2757.1, p.23]
This failure leads to an overstatement of projected Kansas' emissions levels, and thus its significant contribution and interference with maintenance, in the above-identified downwind nonattainment sites. When the appropriate EGU emissions level adjustments are made, as shown in the attached Trinity Consultants Report ('Trinity Report') [See p. 28 of this comment summary for the Trinity Report], Kansas' downwind emissions at the identified sites fall below the minimum levels necessary to support a finding that Kansas emission constitute significant contribution and interference with maintenance at the sites. It follows that Kansas should be removed from the list of States subject to the proposed rule. As explained more fully in the Trinity Report, the affected Kansas EGUs include Westar's Jeffrey Energy Center, Units 1-3 and Kansas City Power & Light's LaCygne Unit 1. EPA's pre-NODA modeling identifies both S02 and NOx controls installed on these EGUs, but does not include the actual emissions levels that are currently being achieved or expected to be achieved by these controls by 2012. [EPA-HQ-OAR-2009-0491-2757.1, p.24]
EPA'S DATA SUPPLEMENT DOES NOT REFLECT IMPORTANT REDUCTIONS IN EMISSIONS IN KANSAS AND DOES NOT ACCURATELY INCORPORATE THE LATEST SCIENTIFIC KNOWLEDGE [EPA-HQ-OAR-2009-0491-3737.1_NODA, p.2]
Westar and other significant emission sources in Kansas are subject to recently executed federally enforceable requirements for emissions reductions which require substantial reductions in both NOx and SO2 in the timeframe addressed by the Rule. EPA should have included this information in formulating the predictions about future emission levels on which its decision-making is made, but has not. For example, Westar's Jeffrey Energy Center Units 1 - 3, are subject to a Consent Decree with EPA, effective March 26, 2010 ('Consent Decree'), which requires a thirty-day rolling average unit emission rate for NOx of no greater than 0.180 lb/mmBtu, beginning December 31, 2011. This rate will apply continuously throughout each year. EPA's initial IPM computer analysis and 2009 CAMD rates should be adjusted to reflect emission reductions resulting from these controls. EPA's IPM computer runs and 2009 CAMD rates for Units 1 and 2 should be adjusted to reflect the emission limits required by 2012. EPA should also note that the 2009 rates for Units 1 and 2 do not yet reflect the limits on these units that will be required by 2012. [EPA-HQ-OAR-2009-0491-3737.1_NODA, p.2]
These federally enforceable emission reductions have been recognized by the Kansas Department of Health and Environment (KDHE). As shown in KDHE's letter of September 29, 2010, to the Honorable Lisa Jackson, Administrator, EPA, these federally enforceable requirements will result in emissions of NOx and SO2 by Westar that are significantly less than EPA's projections. KDHE notes and Westar agrees that EPA's 2012 IPM estimates do not accurately reflect control equipment installed or to be installed on Westar's units as required under the Consent Decree. As a result, Westar's future emissions are overstated by EPA and should be reevaluated and calibrated to match real world emissions prior to issuance of any final rulemaking. [EPA-HQ-OAR-2009-0491-3737.1_NODA, pp.2-3]
As noted, the Consent Decree provides a limit of 0.180 lb/mmBtu for NOx, for all three units. The units are similar to each other in design, construction and physical characteristics, and will have similar emission control systems, as already installed or as required by the schedule under the Consent Decree. Emission control systems have recently been installed on Units 1 and 3. As KDHE has suggested, Unit 2 should not be modeled higher than the Consent Decree limit of 0.180 lb/mmBtu. [EPA-HQ-OAR-2009-0491-3737.1_NODA, p.3]
For SO2, the Consent Decree requires all three Jeffrey Units to be limited to 6,600 tons total SO2 on a rolling twelve month basis. The Consent Decree also limits the units to 0.070 lb/mmBtu SO2. New scrubbers have been installed on all three Jeffrey units and all three units are operating with scrubbers. [EPA-HQ-OAR-2009-0491-3737.1_NODA, p.3]
In addition, KDHE has correctly pointed out that Kansas City Power & Light Company's La Cygne Unit 1 operates at an annual NOx rate of 0.11 lb/mmBtu. This level is based upon two years of actual operations with a selective catalytic reduction control system (SCR) in operation. Westar notes the recommendation of KDHE for the purposes of modeling that the 2009 average NOx rate of 0.11 lb/mmBtu be used in conjunction with projected 2012 IPM heat input to estimate emissions from La Cygne Unit 1 in 2012. [EPA-HQ-OAR-2009-0491-3737.1_NODA, p.3]
ANY FINAL DETERMINATION BY EPA OF THE INCLUSION OF KANSAS AS A CLEAN AIR TRANSPORT RULE STATE SHOULD BE BASED ON THE LATEST SCIENTIFIC INFORMATION [EPA-HQ-OAR-2009-0491-3737.1_NODA, p.3]
In setting rules, EPA is obliged to rely on the latest available data. See 42 U.S.C. Sec. 7408(a)(2). NAAQS must 'accurately reflect the latest scientific knowledge.' Information submitted in Westar's comments on the Clean Air Transport Rule ('CATR') already demonstrates that Kansas should not be included as a CATR state. EPA has proposed to include Kansas, based upon EPA's predicted impact of emissions from Kansas on ozone at monitors in Dallas, Texas. Westar's October 1 submittal to EPA included the Trinity Consultants' 'Clean Air Transport Rule: Review of EPA's CAMx Modeling That Is The Basis for Kansas Inclusion,' ('Trinity Report. ') The Trinity Report is based on revised emission projections, including federally enforceable reductions in NOx and SO2 at Westar's Jeffrey Energy Center and other Kansas generating sites, thus recognizing Westar's Consent Decree and other federally enforceable requirements. These corrected data inputs were incorporated into CAMx, and were included in a full repeat of EPA's modeling analysis by Trinity. [EPA-HQ-OAR-2009-0491-3737.1_NODA, pp.3-4]
After those adjustments were made, Trinity concluded that Kansas does not make a significant contribution to ozone concentration at Dallas, Texas, as projected by EPA, and Kansas should not be included in the Transport Rule for ozone season NOx allocations. Similar information has been provided to EPA by Westar, KDHE and other interested parties, and is available for EPA in its final decision on whether Kansas should be included in the Transport Rule as a contributor to ozone in Dallas. Failure of EPA to rely upon the best available scientific information would be inconsistent with its obligations under the Clean Air Act and constitute arbitrary and capricious action. Further, the reductions of NOx and SO2 through the Westar Consent Decree and the other federally enforceable requirements on emission sources in Kansas as noted by Westar and KDHE will also reduce Kansas' predicted contribution to PM2.5 in areas including Muscatine, Iowa and Milwaukee, Wisconsin. These reductions in emissions from Kansas are significant and should be taken into account in any final decision by EPA. [EPA-HQ-OAR-2009-0491-3737.1_NODA, p.4]
FAILURE TO REVIEW AND REVISE EPA'S MODEL WILL RESULT IN UNREASONABLE RELIANCE UPON A LIMITED MODELING TOOL [EPA-HQ-OAR-2009-0491-3737.1_NODA, p.5]
EPA has relied upon CAMx, which knowledgeable experts recognize as having limited reliability at ranges beyond 200 kilometers. (See Westar submittal, October 1,2010) In addition to the limited reliability of CAMx, as KDHE noted, EPA's IPM assessment tool assumes a linear relationship between the NOx emission reductions in Kansas, and, the state's contribution to downwind ozone levels. This approach is flawed and unreliable because ozone formation is a non-linear process, and any reliable modeling would need to take into consideration photochemical modeling and non-linear variables. EPA described its rationale for the use of CAMx as its selected modeling tool in the August 2, 2010, proposal, 75 C.F.R. 45238-9, but has not addressed the limitations of CAMx and IPM as stated on the record by KDHE, Westar and others. As KDHE has stated, the approach EPA uses to assess the effect NOx reductions will have on downwind ozone is 'fundamentally flawed.' Similar concerns apply to SO2 assessments by EPA. These concerns need to be addressed in any final action by EPA. [EPA-HQ-OAR-2009-0491-3737.1_NODA, p.5]
As suggested by KDHE, Westar supports use of the modeling done by EPA through CAMx and the IPM as a tool to inform more sophisticated analysis taking into account varying responses to emission changes based on source receptor proximity, sources of emission reductions and additional factors, prior to any final determination, not as the final predictors of what those levels would be. [EPA-HQ-OAR-2009-0491-3737.1_NODA, p.5]

3 The text of the Trinity Report is attached [See p.28 of this comment summary for the Trinity Report]. In addition, detailed analysis and computer files of the Trinity Report was submitted to the docket by Trinity Consultants through its overnight letter and enclosed DVD, dated September 30, 2010. The DVD contains approximately 150mb of information. Trinity has been advised by EPA that this size is too large to be accepted by the electronic docket filing system, so the DVD has been submitted by overnight delivery addressed to the docket, per EPA's directions. The entire Trinity Report is adopted and made part of this submittal. As explained in Sec. II, above, EPA did not allow adequate time for review of EPA's modeling data and inputs. Trinity has made a good faith effort to analyze EPA's modeling analysis supporting of the Rule, but has not had sufficient time to complete its full data verification analysis following EPA's production of additional data to correct corrupt or otherwise unusable files, and has not completed its full data verification analysis.
Wisconsin Power and Light Company
EPA's approach for S02 of using the lower of actual emissions versus projected emissions for 2012 allocations creates unrealistic results that could require construction of scrubbers by 2012. For example, WPL's fleet in Wisconsin would require a 50% reduction in S02 emissions in 2012 compared to 2009 actual emissions under EPA's proposed CATR. The IPM projections used to determine these allocations are illogical results that do not account for our company's requirement to supply reliable power service to our customers. For example, WPL operates two identical EGUs at the Columbia Energy Center (ORIS 8023). The IPM results would have the Columbia Unit I running at significantly lower utilization (less than half) as compared to Columbia Unit 2. Yet these are both base load units in WPL's fleet that have historically and will continue operate at capacity in order to supply reliable power to our customers. Similarly, the model indicates that Edgewater Unit 3 (ORIS 4050) would not operate and does not assign it any S02 allowances, which is contradictory to historical information that clearly demonstrates this unit does routinely run. [EPA-HQ-OAR-2009-0491-2844.1 p.5]
Xcel Energy Inc.
2. Xcel Energy is concerned that the computer simulation modeling analysis underpinning the CATR creates a number of risks that are not addressed in the proposal.
Xcel Energy has a number of concerns about the modeling analysis. First, the modeling system used is new, untested, and updated in many critical areas including emission control inputs, natural gas markets, demand and price-demand response parameters, and energy efficiency assumptions. EPA should provide the proposed unit allocations and other modeling output from this new modeling system for public review and comment prior to finalization of the CATR. Second, the combination of very low electric demand growth and low natural gas prices results in a baseline forecast of very slow growth in air emissions. This low baseline emission growth makes air regulations appear to be more cost-effective than they would be in a higher baseline emissions scenario. EPA should account for this risk and consider modeling scenarios in which both electric demand and natural gas prices are higher; because this combination of critical factors is historically unprecedented, more detailed comparative analysis and risk assessment should be provided. Third, natural gas units appear to dispatch at unrealistically low levels in the model. This should be investigated and either justified or corrected. Finally, coal unit retirements appear to be very low in EPA's modeling and this also warrants further analysis given the critical role of coal generation for economic and reliable electric supply in several regions of the nation. [EPA-HQ-OAR-2009-0491-2728.1, pp.8-9]
Response:
Many of the above comments are centered around concerns with EPA's modeling, and the subsequent use of that modeling to determine state budgets and unit level allocations.  EPA took significant action to respond to these concerns in its final Transport Rule.
First, EPA changed its allocation methodology to be based on historic heat input and emissions data that is generally reported by the sources' DR who testifies to its accuracy and completeness.  This was done in response to comments that expressed concern/disagreement about the IPM unit level projected emissions on which the proposed allocations were based.  By switching to a historic data based methodology, the degree to which any discrepancy between a unit's actual future operation and its projected future operation would impact the unit's allocation is greatly diminished.  EPA recognizes that IPM is a dynamic linear programming model that generates optimal decisions under the assumptions of perfect foresight and results in a least cost method of meeting demand.  However, invariably, there will be discrepancies between IPM unit level projections and a unit's actual future operations due to non-economic or other variables that IPM does not capture.  At the state and regional level, the discrepancies are small and random and thus do not result in biases.  However, their impact at the unit level may be significant and this was one of the drivers behind switching to an allocation method based on historic data. For more information on the allocation method, see Preamble Section VII D.
Second, EPA reviewed the comments and has made significant updates to its IPM v.3.02 modeling used at proposal.  These updates include changes to both the more general IPM assumptions (e.g., gas price assumptions) and specific unit level assumptions (e.g., that current retrofit status at a unit).  These updates were made to the IPM model, and the updated version (EPA IPM v.4.10) was used for all the final rule analysis.  In regards to unit specific adjustments, EPA did not manually adjust projected unit level modeling outputs, but it did make unit level updated to its NEEDS database used as a model input that impacted the unit level model outputs.   Some of the most frequent general IPM comments noted above that were addressed in the updates are: FGD removal efficiency was adjusted for new retrofits, and for existing retrofits it was indexed to historic performance at the unit.  Additionally, many of the above comments were focused on a sources ability to switch coals.  EPA modified its modeling to better reflect the cost and feasibility of switching and blending coals.  State Rule and consent decrees were updated according to comments.  Additionally, there were more than 1000 unit specific modeling changes made in response to corrections provided by the commenter.  For more detailed discussion of EPA IPM v.4.10 assumptions and assumption updates, see the EPA IPM v.4.10 documentation and the "Transport Rule IPM Assumptions Response to Comments" in the Appendix
These two adjustments, updates to the modeling and updates to the allocation methodology, work in concert to comprehensively address many of the concerns expressed by commenters on their unit level projections and allocations.
In regards to state budgets, many commenters objected to the use of model projections to determine unit level allocations noting that it may not account for certain non-economic factors that influence and Independent Service Operator (ISO) to call upon specific unit.  They noted this could result in IPM projecting unrealistic scenarios for particular units because it does not reflect these non-economic factors.  EPA's change to the final TR allocation methodology noted above and in section VII.D of the TR preamble addresses this concern.  Some commenters proceeded to note that while modeling projections were note reasonable for use of unit level allocations, they are reasonable to use for state and/or regional budgets.  Other commenters noted that model projections should not be used for state budgets for the same reason that they are inappropriate for unit level allocations.  Those supporting the use of model projections for determining state level budgets noted that discrepancies at the unit level are typically mitigated at the state level when the unit level data is aggregated.
EPA does use IPM projections to determine state level budgets.  As described in section VI of the preamble, state budgets are set equal to the projected state level emissions once significant contribution has been eliminated.  EPA believes that it is reasonable to use IPM for determining state budgets.  While there is significant potential variation at the unit level which commenters highlighted and served as part of EPA's rationale for finalizing a different allocation methodology, this variation is diminished and/or eliminated as unit level data is aggregated to get the state totals.  That is, potential variation between projected results and observed results is reduced as data is aggregated.  The well documented law of large numbers theorem indicates that the average results from a trial or sample will more closely approximate the actual value as the number of trials or samples increases.  While the unit level projection constitutes a sample or trial of just 1, the average # of modeled units within a Transport Rule state is approximately 370.  Because of the large number of units (e.g., samples) that comprise the state level total, the average variation at the state level is significantly less than it is at the unit level.
In the final Transport Rule, EPA does not use historic emissions data to set the Transport Rule state budgets, but instead relies on projected emissions data under the marginal cost thresholds selected to define significant contribution and interference with maintenance.  EPA uses the same budget-setting methodology in the final rule on all pollutants analyzed (including ozone-season NOx, annual NOx, and SO2).  EPA believes this budget-setting methodology is more clear and easier to understand in connection with the Agency's modeling projections.  EPA believes the state budgets set under the final Transport Rule are an accurate reflection of its modeling of the removal of emissions identified as significant contribution and interference with maintenance from the states controlled.  For a discussion of this method and its results, please refer to section VI of the preamble for the final Transport Rule as well as the Significant Contribution and State Emissions Budgets Final Rule Technical Support Document.
In regards to the timing of the compliance deadlines, EPA chose the 2012 and 2014 dates to coordinate with the NAAQS attainment deadlines and to assure that reductions are made as expeditiously as practicable.  The Preamble discusses how the compliance deadlines address the Court's concern about timing.  See more in Section VII.C for more discussion on compliance deadline.
Many commenters expressed concern regarding unit level compliance and making the operating or investment decisions suggested in EPA's modeling projections.  EPA's adjustment to the final allocation methodology to delink unit level allocations from model projections largely address this concern.  Additionally, EPA notes that the Transport Rule does not impose unit level compliance strategies.  While IPM may project a particular least cost compliance strategy, sources have the flexibility to comply with the state budgets through a variety of mechanisms (e.g., control installation, fuel switching, efficiency improvements, dispatch changes, allowance purchase, etc.)
Organization: Vectren Corporation
Louisiana Chemical Association (LCA)
Kansas City Board of Public Utilities (BPU)
Kansas Department of Health and Environment
Louisiana Energy and Power Authority (LEPA)
Cogen Technologies Linden Venture, LP
Kansas City Power and Light Company (KCP&L)
Gainesville Regional Utilities (GRU)
Exxon Mobil Corporation
Comment:
Cogen Technologies Linden Venture, LP
II. DISCUSSION
Linden Cogen is a combined-cycle plant consisting of six (6) natural gas-fired combustion turbines and three (3) steam turbines. It provides 645 MW of capacity to Consolidated Edison ('ConEd') pursuant to a power purchase agreement. It also provides 169 MW of electricity and 1.09 million lbs per hour of steam to ConocoPhillips' Bayway Refinery, which is the largest refinery operated on the East Coast. Linden Cogen's operation is governed by long-term contracts, which have historically resulted in its dispatch as a baseload plant. [EPA-HQ-OAR-2009-0491-2712.1, p.5]
Linden Cogen objects to EPA's proposed allocations of annual and ozone season NOx for Linden Cogen because the proposed allocations are wholly inconsistent with the facility's historic dispatch and fail to account for the fact that the facility is operated pursuant to long-term power sales and steam sales agreements. These erroneous projections are also due to several errors in the data set relied upon by IPM, as described below. Linden Cogen does not believe EPA can rely upon IPM's projected dispatch and emissions as the basis for any allocations in New Jersey, unless EPA makes changes to IPM so that it accurately predicts the operation of contracted facilities such as Linden Cogen. EPA also must correct the inputs for Linden Cogen's heat rate, FOM costs, VOM costs and fuel costs before re-running the model. If EPA cannot make these corrections to IPM, Linden Cogen believes NOx allocations in New Jersey should instead be based on historical data, as augmented by assumptions concerning operation of existing and planned controls, but using a more representative baseline than just one year's data. [EPA-HQ-OAR-2009-0491-2712.1, p.5]
A. EPA Has Proposed to Allocate Allowances to Linden Cogen Representing Only a Fraction of Its Historic Capacity
EPA's proposed NOx allocations for Linden Cogen would provide allowances for only a small fraction of the plant's historic operating capacity. A comparison of EPA's proposed allocations and Linden Cogen's historic actual emissions is shown in the following Table 1. [EPA-HQ-OAR-2009-0491-2712.1, p.5]
[Table 1 can be found on page 6 of this comment. This table includes footnotes 1, 2, and 3.]
As indicated by Table 1, EPA's proposed allocations for annual and ozone season NOx would respectively represent approximately only 10% and 19% of historic emissions, as reported during the four most recent calendar quarters. These proposed allocations would also represent only a fraction of the allocations made for Linden Cogen by the New Jersey Department of Environmental Protection ('NJDEP') under the CAIR, as also shown by Table 1 above. Furthermore, in comparison to average historic emissions over the past seven calendar years, as shown by Tables 3 and 4 below, EPA's proposed allocations amount to approximately only 9% and 16% of historic annual and ozone season NOx emissions, respectively. [EPA-HQ-OAR-2009-0491-2712.1, p.6]
As illustrated by Tables 2 and 3, annual and ozone season NOx emissions were substantially lower in 2009 than the historic average due to lower dispatch levels caused by the recession. In the Technical Support Document, 'State Budgets, Unit Allocations, and Unit Emissions Rates,' EPA expressly acknowledged the impacts of the recession on 2009 dispatch and emissions levels and adjusted reported NOx emissions to account for these impacts.- As described below in Section U.K, EPA should not base allocations on data for only one year, but should instead base allocations on a representative baseline established over a longer period of time. Basing allocations on a long-term average would assure that allocations are based on the most representative data concerning historic emissions and not impacted drastically by circumstances that may have resulted in lower than average dispatch during 2008 or 2009, when facilities may not have been operated at typical levels due to the recession or extended outages related to the installation of controls needed to comply with the CAIR. [EPA-HQ-OAR-2009-0491-2712.1, pp.7-8]
[Tables 2 and 3 can be found on page 7 of this comment.]
EPA's proposed allocations - 41 tons of annual NOx and 30 tons of ozone season NOx - would only provide enough allowances for operation of one of Linden Cogen's six combustion turbines consistent with Linden Cogen's historic operating rates. This gross discrepancy between Linden Cogen's historic NOx emissions and EPA's proposed NOx allocations in the Proposed Transport Rule is based on EPA's projected utilization of Linden Cogen at significantly lower rates than has historically been the case. According to the results of EPA's IPM, annual and ozone season heat input for Linden Cogen are expected to be significantly lower than the historic heat input values for the four most recent calendar quarters and ozone season, as shown by Table 4 below: EPA's projections amount to only 12.88% of historic annual heat input and only 21.57% of historic ozone season heat input. Further, if a more representative baseline than 2009 data were used instead, EPA's IPM projections would amount to an even smaller fraction of historic heat input. [EPA-HQ-OAR-2009-0491-2712.1, p.8]
[Table 4 can be found on page 8 of this comment. This table includes footnotes 5 and 6.]
In sum, IPM has projected that Linden Cogen will operate at only a fraction of its historic operating capacity, which has been greater than 68% on average over the past three calendar years for each of Linden Cogen's six combustion turbines, as illustrated by Table 5 below. In essence, IPM has erroneously predicted dispatch of Linden Cogen as a peaking plant, rather than a baseload generating station. [EPA-HQ-OAR-2009-0491-2712.1, p.8]
[Table 5 can be found on page 9 of this comment.]
B. IPM Wrongly Projects Dispatch of Linden Cogen at Only a Fraction of Its Historical Capacity Because It Arbitrarily Ignores the Impact That Long-Term Contracts Have on Dispatch
IPM's projections of Linden Cogen's dispatch at levels so drastically below its historic operating levels wholly fail to account for the fact that Linden Cogen is operated pursuant to long-term power sales and steam sales agreements, which practically assure that Linden Cogen's future dispatch will be consistent with historic dispatch levels while the contracts remain in effect. Further, the provisions governing dispatch of both Linden Cogen and other facilities subject to long-term contracts are often highly complex and prescribe very specific dispatch instructions. While ConEd controls the dispatch of Linden Cogen's Units 1 through 5, the terms of the power sales agreement require dispatch at certain minimum percentages of the baseline dispatch level and for certain minimum lengths of time. As an example, ConEd can dispatch Units 1 through 5 at 47% of the baseline dispatch level; but, if it does, ConEd is obligated to run Units 1 through 5 for at least 50 hours, with one exception per year. In modeling least-cost dispatch, IPM completely fails to capture the complexities of such long-term contractual obligations. [EPA-HQ-OAR-2009-0491-2712.1, p.9]
Because EPA has failed to account for the existence of long-term contracts within IPM and the specific dispatch requirements prescribed by those contracts, its model results have no basis in reality. By using IPM's projections for dispatch as the basis for NOx allocations in New Jersey, EPA's proposed allocations would run afoul of the principles articulated by the D.C. Circuit in the two prior instances when it rejected EPA's reliance upon projections of future utilization generated by IPM, which were unsupported by 'the best information available to the Agency' and 'flatly inconsistent' with 'real world observations' concerning future demand and dispatch. See Appalachian Power 1,249 F.3d at 1053-54 (remanding 'EPA's use of growth rates generated by IPM for 2001-2010 to estimate facility utilization growth for the period of 1996-2007' in light of EPA's failure to address 'what appear to be stark disparities between its projections and real world observations'); see also Appalachian Power II, 251 F.3d at 1034-35 (remanding EPA's reliance without explanation upon 'IPM to generate growth assumptions for 1996-2001, as well as to generate state-by-state EGU utilization estimates for 2007', 'that generated seemingly implausible results'). [EPA-HQ-OAR-2009-0491-2712.1, p.9]
C. IPM Wrongly Projects Dispatch of Linden Cogen at Only a Fraction of Its Historical Capacity Because It Relies Upon an Erroneously High Heat Rate and Erroneously High Fixed and Variable Operating Costs and Fuel Costs
Linden Cogen has examined EPA's IPM output files and the underlying assumptions to attempt to explain how the projected dispatch for Linden Cogen could depart so dramatically from historical and anticipated dispatch. Our examination has identified several errors in EPA's modeling inputs that appear to have resulted in IPM's projected dispatch of the facility at only a fraction of its historic capacity: [EPA-HQ-OAR-2009-0491-2712.1, p.10]
:: The heat rate appearing within the NEEDS database for each of Linden Cogen's generating units is incorrect: It is reported in the NEEDS database as 9173 Btu/kWh, when, in fact, the average heat rate for the entire plant is approximately 7965 btu/kWh. A heat rate above 9000 Btu/kWh is not at all consistent with a highly efficient combined cycle natural gas-fired cogeneration plant, but is more typical of a simple-cycle unit. The inaccurate assignment of such a high heat rate to Linden Cogen in IPM appears to have resulted in dramatically reduced projections of the plant's future dispatch that in no way approximate the current operations of the facility. [EPA-HQ-OAR-2009-0491-2712.1, p.10]
:: EPA appears to have incorrectly assigned fixed operating and maintenance ('FOM') costs to Linden Cogen's three steam turbines as though they were separately fired steam generating units and not part of a combined-cycle plant. At Linden Cogen's request, EPA provided the 'model plant' codes for each of Linden Cogen's generating units, as well as for a number of other facilities in New Jersey. This enabled Linden Cogen to compare the cost data assigned to the various model plants through reference to the IPM output files. For six of Linden Cogen's generating units (presumably its six combustion turbines), the IPM output files, 'TR_SB_Limited_Trading.tac', indicate that EPA has applied the correct FOM cost assumption of $12.6 per kilowatt hour-generated per year ('$/kW/yr') for combined cycle gas/oil plants. See Table 6 attached as Attachment 1; see also Documentation for EPA Base Case v.4.10, 4-11, Table 49. However, for three of its generating units - presumably its three steam turbines, which have no separate fuel source and are not a source of emissions EPA has wrongly applied an assumption of FOM costs of 23.57 $/kW/yr. See Table 6. This incorrect assumption would appear to correlate with the assumed FOM costs for either an MSW/landfill gas plant, which are 23.6 $/kW/yr, or an 30-40 year-old oil & gas-fired steam turbine equipped with SCR, which are 23.2 $/kW/yr. See Documentation for EPA Base Case v.4.10, 4-11, Table 4-9. EPA cannot apply the assumed FOM costs for either an MSW/landfill gas plant or a 30-40 year-old oil & gas-fired steam turbine to any of Linden Cogen's units. [EPA-HQ-OAR-2009-0491-2712.1, p.10]
[Table 6 can be found on page 25 as Attachment 1 of this comment.]
:: Linden Cogen objects to the variable operating and maintenance costs ('VOM') assumed by EPA for the model plants associated with Linden Cogen's generating units. According to EPA's model output files, VOM costs for Linden Cogen are between 7.5 and 7.54 mill/kWh for each of its nine generating units. See Table 6 at Attachment 1. The range of VOM for combined cycle plants with SCR is, according to EPA, 2.75 to 7.79 mill/kWh. See Documentation for EPA Base Case v.4.10, 4-9, Table 4-8. In contrast, YOM costs for a similarly-sized gas-fired combined-cycle plant in New Jersey, AES Red Oak LLC, are between 2.75 and 3.02 mill/kWh. See Table 6. EPA has provided no explanation or support for why it has assigned significantly higher VOM costs to Linden Cogen than to a substantially similar facility located in the same state. Linden Cogen is aware of no explanation for this difference and believes it has no basis in fact. [EPA-HQ-OAR-2009-0491-2712.1, pp.10-11]
:: Linden Cogen also objects to the fuel costs EPA has assumed for the model plants associated with Linden Cogen's generating units. According to EPA's model output files, fuel costs for Linden Cogen are between 47.9 and 66.46 mill/kWh. See Table 6. In contrast, for the model plant associated with AES Red Oak, LLC, fuel costs range between 32.55 and 44.09 mill/kWh. [d. Linden Cogen is unaware of any basis for assuming that its fuel costs are so much greater than for a similar combined cycle facility located in New Jersey. [EPA-HQ-OAR-2009-0491-2712.1, p.11]
:: According to the model plant names assigned to Linden Cogen's units, all such units were modeled as serving the Legacy Mid-Atlantic Area Council - East ('MACE'), when, in fact, Linden Cogen Units I through 5 are fully contracted to ConEd to provide power to New York City ('NYC'). Thus, although Units I through 5 are physically located in New Jersey and were modeled as part of MACE, they serve NYC through dedicated transmission lines. While IPM is equipped to model certain inter-regional transmission capabilities, it would be plainly inconsistent with both the physical and contractual limitations governing dispatch of Linden Cogen to model delivery of power from Units 1 through 5 to NYC as an inter-regional transfer or to apply any 'Wheeling Charge' related to such delivery, as suggested by the Documentation for EPA Base Case v.4.10. 7 [EPA-HQ-OAR-2009-0491-2712.1, p.11]
In light of our understanding of how IPM models which units will be dispatched given certain operating constraints and assumptions, we believe the foregoing errors have resulted in IPM's projected dispatch of Linden Cogen at only a small fraction of its historic generating capacity, a scenario that is belied by the facility's contractual obligations to provide steam and power to its steam host and power to the critical New York and PJM power markets. The net result of these errors is that the IPM projections EPA relied upon in establishing unit-by-unit allocations wrongly conclude that Linden Cogen will only operate at a small percentage of its actual capacity and with a fraction of its actual NOx emissions. These projections are erroneous and cannot establish the basis for unit allocations. [EPA-HQ-OAR-2009-0491-2712.1, p.11]
The D.C. Circuit has twice previously thrown-out EPA's reliance upon IPM's projected future utilization rates, where IPM 'generated seemingly implausible results' and no attempt was made to explain 'what appear to be stark disparities between its projections and real world observations.' See Appalachian Power 1,249 F.3d at 1035; Appalachian Power II, 251 F.3d at 1054. While 'courts routinely defer to agency modeling of complex phenomena, model assumptions must have a 'rational relationship' to the real world.' Appalachian Power I, 249 F.3d at 1053 (citing Chemical Mfrs. Ass'n v. EPA 28 F.3d 1259, 1265 (D.C. Cir. 1994)). Accordingly, before relying upon IPM results as the basis for allocating allowances, EPA must assure that it has relied upon appropriate assumptions and must explain its reliance upon assumptions that appear to have no basis in fact. [EPA-HQ-OAR-2009-0491-2712.1, pp.11-12]
E. EPA Should Not Rely Upon IPM Projections to Establish Unit-by-Unit Allocations When It Has Rejected Those Projections as Less Reliable Than Actual Data in Setting Statewide Budgets
For those states in which the IPM projection of total statewide emissions in 2012 was lower than actual emissions in 2009, EPA relied upon the unit-specific IPM projections as the basis for the proposed unit allocations, even though it rejected those projections in setting the statewide budgets in favor of more accurate historic emissions data, as augmented by assumptions about the operation of existing and planned emissions controls. It is simply illogical to make unit-specific allocations based on the IPM, when that model has been demonstrated to generate wildly inaccurate projections. This is doubly true when EPA has itself acknowledged that the model does a relatively poor job of making unit-level projections, concluding that using ''the actual performance units achieved in 2009 is more representative of expected emissions than what EPA modeled using IPM.' Proposed Transport Rule, 75 Fed. Reg. at 45290 (emphasis added). Accordingly, basing the unit allocations on IPM results would represent an arbitrary decision. [EPA-HQ-OAR-2009-0491-2712.1, p.14]
1. Although New Jersey NOx Allocations Were Based on IPM Projections, the Corresponding Budgets Were Based on Historic Data, Augmented by Assumptions about Operation of Existing and Planned Controls
In setting the unit allocations, 'EPA proposes that, for 2012, each existing unit in a given state receives allowances commensurate with the unit's emissions reflected in whichever total emissions amount is lower for the state, 2009 emissions or 2012 base case emissions projections.' 75 Fed. Reg. at 45309. However, in setting the 2012 802 budgets, EPA did not rely upon IPM projections (as it did in establishing the 2014 budgets for the group 1 states), but 'took a different approach', as explained by the preamble to the Proposed Transport Rule: [EPA-HQ-OAR-2009-0491-2712.1, p.14]
These states are only required to make 802 reductions that could be made through (1) the operation of existing scrubbers, (2) scrubbers that are expected to be built in 2012 and (3) the use of low sulfur coal. Because those strategies were already being applied in most states covered by this rule in 2009, EPA believes that the actual performance units achieved in 2009 is more representative of expected emissions than what EPA modeled using IPM. This is because real data takes into account actual unit by unit information that is represented at a more aggregate level in IPM.
75 Fed. Reg. at 45290 (emphasis added). [EPA-HQ-OAR-2009-0491-2712.1, p.14]
Additionally, in setting the annual and ozone season NOx budgets for all states, 'EPA used the same general methodology for all states that was used for the group 2 states for SO2.' Id. As EPA explained in the preamble to the Proposed Transport Rule, 'EPA believes that instead of defining the budgets based on IPM projections of what will happen when SCR units are turned on, it is better to use real data, therefore EPA has developed budgets based on a combination of historical heat input, historical emissions rates, and, where new SCR units are expected between now and 2012, projected emissions rates for those new SCR units.' 75 Fed. Reg. at 45291 (emphasis added). 13 [EPA-HQ-OAR-2009-0491-2712.1, p.15]
Thus, for all but the 2014 SO2 reductions required of group 1 SO2 states, EPA based the state budgets on actual reported data, augmented by expectations about how existing and planned controls will be dispatched, rather than IPM projections. Similarly, for both annual and ozone season NOx budgets, EPA relied upon historic data, along with certain assumptions about how existing and planned controls will be dispatched, rather than IPM projections. [EPA-HQ-OAR-2009-0491-2712.1, p.15]
2. IPM's Projections for Dispatch in New Jersey Are Wildly Inaccurate Linden Cogen believes that reliance upon IPM projections as the basis for allocations within a state, when EPA has disregarded those projections as the basis for setting the overall state budget, represents a poor policy choice that is susceptible to production of arbitrary and inconsistent results. While discrepancies in the data set might not be expected to impact the overall model results on a statewide basis, such errors can lead to grossly aberrant outcomes at the unit level. As illustrated by Table 7 (attached as Attachment 2), IPM has yielded wildly inaccurate results in predicting the future dispatch of combined-cycle facilities in New Jersey, in comparison to their historic reported dispatch (heat input) levels. [EPA-HQ-OAR-2009-0491-2712.1, p.15]
[Table 7 can be found on page 26 as Attachment 2 of this comment.]
:: For Linden Cogen's six combustion turbines, which are all already operated with SCR controls, IPM projections for annual heat input ranged from only 8.6% to 33.71% of reported heat input during the most recent four calendar quarters. Similarly, for the ozone season, IPM's projections for the six combustion turbines ranged from 14.43% to 54.57% of reported fuel usage in the 2009 ozone season. [EPA-HQ-OAR-2009-0491-2712.1, p.15]
:: Even greater deviations from historic fuel usage can be observed in the IPM results for other combined cycle facilities in New Jersey: For the Bergen Generating Station, IPM has predicted dispatch of its turbines at heat inputs representing as little as 3.59% of historic capacity. At the other extreme, for the PSEG Linden Generating Station, IPM has predicted dispatch of one of the generating units at 5,144.06% of its historic annual heat input and 11,367.89% of its ozone season heat input. [EPA-HQ-OAR-2009-0491-2712.1, pp.15-16]
Given these aberrant results, it is easy to understand why EPA jettisoned IPM projections as the basis for the 2012 SO2 budgets and all NOx budgets because, as EPA stated in the preamble to the Proposed Transport Rule, 'EPA believes that the actual performance units achieved in 2009 is more representative of expected emissions than what EPA modeled using IPM.' 75 Fed. Reg. at 45290. 'This is because real data takes into account actual unit by unit information that is represented at a more aggregate level in IPM.' Id. [EPA-HQ-OAR-2009-0491-2712.1, p.16]
3. EPA Cannot Rely Upon a Model Known to Generate Arbitrary and Inaccurate Results When More Reliable Data Is Available
For EPA to acknowledge that IPM is not as reliable as actual data at predicting how units will be dispatched, but then rely upon IPM's projected results as the basis for unit-specific allocations would reflect a poor policy choice that is both arbitrary and capricious. In the case of Linden Cogen, it would result in a significantly lower allocation than similar facilities in New Jersey. [EPA-HQ-OAR-2009-0491-2712.1, p.16]
The D.C. Circuit has made clear that while 'courts routinely defer to agency modeling of complex phenomena, model assumptions must have a 'rational relationship' to the real world.' Appalachian Power L 249 F.3d at 1053-55 (citing Chemical Mfrs. Ass'n v. EPA, 28 F.3d 1259, 1265 (D.C. Cir. 1994). Certainly, '[m]odels need not fit every application perfectly.' Columbia Falls Aluminum Co. v. EPA, 139 F.3d 914, 923 (D.C. Cir 1998). However, EPA cannot rely upon an application of IPM 'that generates apparently arbitrary results'. See Appalachian Power 11,251 F.3d at 1035. This error is only 'compounded by the fact that more representative ... estimates [are] available.' Id., at 1034. [EPA-HQ-OAR-2009-0491-2712.1, p.16]
Here, EPA concedes in setting the statewide budgets that IPM is not as representative as the actual historical performance data (except in the case of the 2014 SO2 budgets for group 1 states). If actual performance data are more accurate and representative at the statewide level, they certainly should be deemed more accurate and representative for predicting the dispatch and emissions of individual units. Indeed, the reason EPA jettisoned IPM's projections as the basis for setting state budgets, in favor of historic data augmented by such operating assumptions, is because 'real data takes into account actual unit by unit information that is [only] represented at a more aggregate level in IPM.' Proposed Transport Rule, 75 Fed. Reg. at 42390. [EPA-HQ-OAR-2009-0491-2712.1, p.16]
This is not the first time that the IPM has produced nonsensical projections. In fact, the D.C. Circuit has previously remanded IPM projections of future utilization because they were 'flatly inconsistent' with actual operational data and implied negative growth in several states from 1998-2007. Appalachian Power 1, 249 F.3d at 1051. 'This, on its face, raises questions about the reliability of the EPA's projections.' Id. Without an explanation for 'why results that appear arbitrary on their face are, in fact, reasonable determinations', the court remanded that portion of the section 126 rulemaking to EPA. Id. at 1055. The 2000 'NOx SIP Call' also was remanded due to 'stark disparities between [IPM's] projections and real world observations' absent a full explanation from EPA. Appalachian Power II, 251 F.3d at 1035. There, the court could not 'excuse the EPA's reliance upon a methodology that generates apparently arbitrary results particularly where, as here, the agency has failed to justify its choice.' Id. [EPA-HQ-OAR-2009-0491-2712.1, pp.16-17]
Here again, IPM's projections of future dispatch of facilities in New Jersey are flatly inconsistent with observed operational data from Linden Cogen. As discussed above, IPM has projected dispatch of Linden Cogen at only one-tenth of its historical capacity and nowhere near the levels at which Linden Cogen is contractually obligated to operate under its long-term contracts. As a consequence, under IPM's projections for future dispatch, a highly efficient combined cycle baseload cogeneration facility has been modeled to operate as infrequently as a simple-cycle peaking plant. While all modeling exercises involve some degree of imprecision, these results are entirely implausible and illustrative of the 'poor fit between the agency's model and [ ] reality' that has resulted in remand of prior EPA rulemakings. See Chemical Mfrs. Ass 'n v. EPA, 28 F.3d at 1265. The implausibility of these results makes clear that, while appropriate for predicting energy market behavior at a broader level and supporting policy-making decisions, EPA has simply no reasonable basis for using IPM to predict the behavior of and allocate allowances to individual units. [EPA-HQ-OAR-2009-0491-2712.1, p.17]