3. EPA assumptions appear to include that FODs are capable of an S02 removal rate of 95% on a sustained basis. In reality, the removal rate varies. Bypassing is occasionally required, start-up has lower efficiencies, malfunctions occur, and other factors result in an annual average removal rate that may be lower than the 95% level assumed by EPA. It is inappropriate for EPA to model the removal rates for FODs as if start-ups and malfunctions never occur. [EPA-HQ-OAR-2009-0491-2637.1, p. 7]
First Energy
FE believes the NEEDS v3.02 data generated inaccurate model outputs, which are then the basis for setting flawed state allocations. [EPA-HQ-OAR-2009-0491-2657.1, p.4]
FE strongly suggests the EPA rerun all model data since the inputs to the model have changed between NEEDS v3.02 and NEEDS v4.10, to accurately reflect the current economic conditions and database updates and generate reliable and accurate model outputs. Not to do so would be internally inconsistent with EPA's admission that the original database was flawed enough to require correction with NEEDS v4.10, and would represent flawed regulatory development. Following remodeling and issuance of updated results, if would be appropriate to provide the public with an additional 60 days for the public to review and comment on the corrected IPM outputs. [EPA-HQ-OAR-2009-0491-2657.1,p.4] [[This comment can also be found in Section XVIII.C.2.]]
Unit Availability Data
The NEEDS database dramatically understates FE generating unit availability and must be corrected.[EPA-HQ-OAR-2009-0491-2657.1, p.7]
The average unit availability for the FE system in NEEDS for the period 2001-2005 is 72.5%, versus the actual availability of 82% as reported to GADS. For the period 2005- 2009, the average availability for the FE system rose to 84%. As FE understands the operation of the IPM model, this erroneous assumption on unit availability translates directly into an under-allocation of allowances to FE of at least 10%. This error must be corrected, and consistent with our earlier comments, we urge EPA to use the most recent, most accurate data available. [EPA-HQ-OAR-2009-0491-2657.1, p.8]
Further, FE's Bruce Mansfield plant was assigned an annual availability of 67.4% based on EPA referenced NERC GADS data from 2001-2005. It appears the EPA selected a 67% availability reported for a single unit at Bruce Mansfield in 2001 and applied that value to the entire plant. The availability data used by the EPA is clearly in error, and therefore translates directly into significantly lower allocations than appropriate. FE reported the following 5-year average unit availability from 2001-2005 for Bruce Mansfield: 83.2% for Unit 1, 86.4% for Unit 2, and 88.4% for Unit 3. The 5-year average availability from 2005-2009 for Bruce Mansfield Unit 1 is 83.5%, Unit 2 was 86.3% and Unit 3 was 92.9%. As FE understands the operation of the IPM model, these erroneous assumptions on unit availability at Bruce Mansfield translate directly into an under-allocation of allowances to the FE Bruce Mansfield Plant of at least 30%. This error must be corrected, and consistent with our earlier comments, we urge EPA to use the most recent, most accurate data available.  [EPA-HQ-OAR-2009-0491-2657.1, p.8; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.7 10/15/2010]
NERC GADS data is reported voluntarily and is not QA/QC'd, unlike the data reported into the Clean Air Market Division. A more accurate way to determine availability for a unit would have been to use QA/QC'd CAMD data. [EPA-HQ-OAR-2009-0491-2657.1, p.8]
In general, the EPA should correct all incorrect control equipment assumptions placed into the IPM model through the inaccurate NEEDS data. The IPM model should be rerun to reflect the correct baseline model inputs. Correcting this information will improve the accuracy and reliability of the model outputs. [EPA-HQ-OAR-2009-0491-2657.1,p.10]
RE Burger Plant (Boiler 7&8)
NEEDS v3.02 reports Burger as being scrubbed in 2010. This assumption is in error. FE has not installed a scrubber at RE Burger and has no plans to do so. The RE Burger Plant (BU7&8) will convert to biomass by 12/31/2012 under a Consent Decree. Per the Consent Decree, the boilers will be capable of burning up to 20% sub-bituminous coal with the biomass. In order to improve data accuracy, please correct the NEEDS v3.02 database and IPM model assumptions to reflect the BU7&8 biomass project.  [EPA-HQ-OAR-2009-0491-2657.1, p.10]
Eastlake Unit 5 (EL5)
The EL5 SNCR online year is incorrect in v3.02 & v4.10. The SNCR installation year should be 2007 not 2000. EL5 is required to operate and meet reduction targets per a Consent Decree. The SNCR driven NOx reductions reflected in the 2007-2009 emissions from EL5 represents the controlled NOx emission rate for NEEDS v4.10 reported as Mode 1, but this should be Mode 4 for a controlled rate. The NEEDS v3.02 EL5 Mode 1 rate is in line with typical uncontrolled NOx emissions from EL5. The EPA incorrectly assumes the EL5 uncontrolled NOx rate (Mode1) to be 0.29 in NEEDS v4.10. This is actually the controlled rate. EPA uses 0.29 as their uncontrolled Mode 1 then incorrectly applies a 35% SNCR NOx reduction to this controlled 0.29 rate. The application of the SNCR removal efficiency to the 0.29 SNCR controlled rate applies additional 35% removal efficiency on top of the actual removal efficiency from EL5's operating SNCR. This error not only double-counts the control efficiency, but also assumes the overstated rate of 35% reduction, as discussed earlier. This is clearly in error and must be corrected. [EPA-HQ-OAR-2009-0491-2657.1 ,p.11] [[This comment is also in Section XVIII.C.2.]]
WH Sammis
Units 1-5 are listed as dry scrubbed, but a wet FGD was placed in service in 2010. The FGD for Sammis 6&7 was online in 2010, not 2011. [EPA-HQ-OAR-2009-0491-2657.1 ,p.11] [[This comment is also in Section XVIII.C.2.]]
The reported NOx rates for Sammis Uncontrolled MODE 1 & 3 are representative of the typical controlled NOx rates. The Sammis SNCR's operate annually per the Consent Decree so the data used to project the uncontrolled rate is actually representative of the controlled rate. As in the case of Eastlake 5 above, the application of the SNCR removal efficiency to the SNCR controlled rate on the Sammis Units applies additional overstated 35% removal efficiency on top of the actual removal efficiency by all operating SNCR's. This is clearly in error and must be corrected. [EPA-HQ-OAR-2009-0491-2657.1 ,p.11] [[This comment is also in Section XVIII.C.2.]]
NEEDS v3.02 is missing the Sammis 6&7 SCR installation in 2010. The SNCR installation dates for Sammis SNCR's should also be corrected. The correct dates are: SA1-2006, SA2-2000, SA3-2000 then upgraded in 2006: SA4-2006: SA5-2006: SA6- 2005: SA7-2003. The correction of installation dates for NEEDS v4.10 is the same as above except the SA6 SNCR installation date is missing for Sammis 6. [EPA-HQ-OAR-2009-0491-2657.1 ,p.11] [[This comment is also in Section XVIII.C.2.]]
Kentucky Chamber of Commerce
Additionally, EPA's analysis of the proposed rule includes emissions control equipment that is not currently installed, and therefore inaccurately minimizes the number of retrofits and the cost of achieving the additional emission reduction levels. [EPA-HQ-OAR-2009-0491-2760.1 p.1]
National Grid
In the original IPM model run, a review of the TR _ SB Limited Trading Parsed File raises questions as to why the model has run Northport and Port Jefferson on oil in this case. The six units at those facilities are all dual fuel capable and it is expected that the majority of projected run time would be on natural gas. Some uneconomic firing on oil may occur either during times when there are constraints on the gas supply (typically on very cold winter days when the gas heating load gets preference) or during times of very high electric demand when NYS reliability rules require oil firing. The IPM model should be revised to more accurately represent operation of gas/oil fired units. Furthermore, EPA has incorrectly identified SCR installations on Northport (ORIS 2516) Units 2 and 4, which appear to have been corrected in the NODA IPM version 4.10 model results. [EPA-HQ-OAR-2009-0491-2583.1, p.3]
NextEra Energy, Inc.
Inaccuracies identified in the NEEDS database and EPA's modeling assumption for NextEra Energy's EGUs need to be corrected
Upon reviewing EPA's modeling assumptions and results, including data the Agency relied on from the NEEDS database, NextEra Energy has noted a number of incorrect assumptions/data associated with EGUs operated by its FPL subsidiary. These inaccuracies in EPA's modeling assumptions/data are identified in the attached spreadsheet (Appendix A). [EPA-HQ-OAR-2009-0491-2718.1, p.6]
In addition to the corrections for FPL generating units identified in Appendix A, the most recent IPM projections show gas only operation for FPL's dual fuel-fired fossil steam generating units. With respect to the FPL units which IPM projects operation for in 2012, we have calculated that there would be a potential system demand for natural gas use in excess of 132,125 MmBtu/hr. FPL currently has under contract a maximum daily demand of 1,596,000 MmBtu/day for both Gulfstream and FGT pipelines which is an equivalent hourly demand of 66,374 MmBtu/hr. FPL also has under contract a 2011 expansion of FGT capacity of an additional 400,000 MmBtu/day, which would give FPL a total hourly pipeline capacity of approximately 83,040 MmBtu/hr. Currently there is only 210,000 MmBtu/day), of unsubscribed pipeline capacity in 2010, or roughly an additional 8,750 MmBtu/hr that could be available. Even if FPL could obtain all of the available pipeline capacity we would have only 69% of the gas needed to meet system demand under the natural gas unit operations that the IPM model is projecting for FPL's units. [EPA-HQ-OAR-2009-0491-2718.1, p.6]
A review of the IPM model and its assumptions shows that EPA relies on adjusted price curves to address fuel supply and does not model physical constraints resulting from limited pipeline capacity for electric generation. While other utilities have identified issues with the IPM not modeling of their "must run' units at designated load constraint areas, NextEra Energy has not identified any of the FPL units being designated as such. We believe that the only units in our system that might be designated as must run on oil would be the Turkey Point fossil steam units where gas availability constraints would likely prohibit operation on oil during times of system peak demand. [EPA-HQ-OAR-2009-0491-2718.1, pp.6-7]
During a July 7, 2010 EPA briefing hosted by the Edison Electric Institute (EEl), EPA staff acknowledged that IPM has difficulty handling dual-fuel units because there are non-economic reasons that a company must run such units that are not considered by the model such as grid stability considerations, contractual generation commitments, reliability must-run requirements and fuel availability constraints. NextEra Energy strongly encourages EPA to correct this modeling limitation through adjustments to the model or through post-modeling adjustments to unit emissions.[EPA-HQ-OAR-2009-0491-2718.1, p.7]
Progress Energy Service Company
There Are Inaccurate Data Inputs to the IPM Modeling
The NEEDS Emission Inventory, which constituted the primary emissions input to IPM, contains numerous errors for individual units. For example, the NEEDS database omitted a unit at one of Progress Energy's coal·fired power plants in North Carolina, Cape Fear Unit S. Cape Fear Unit 6, which is a very similar unit at the plant, was included in the database and received allowance allocations. Cape Fear Unit 5, which was omitted, inexplicably received a NOx allocation but no S02 allocation. The NEEDS database contains numerous errors regarding existing units and emission rates for both S02 and NOx that likely make the (PM runs inaccurate. [EPA-HQ-OAR-2009-0491-2831.1 p.7]
RRI Energy, Inc.
RRI has reviewed the future SO2 and NOx emission rates predicted by IPM. Comments to selected RRI units are as follows:
[[Data Table Here]]
[EPA-HQ-OAR-2009-0491-2717.1 p.7-10]
Tennessee Valley Authority (TVA)
A. Issue: EPA states that the use of lower sulfur coals to reduce SO2 emissions is achievable by 2012. [p. 45281] EPA's projected SO2 emission rates indicate switches to lower sulfur coals for several TVA units by 2012. TVA Comment: TVA has been switching to low sulfur coal on units without scrubbers since 1995 for compliance with the 1990 Clean Air Act Amendments. Over that time, TVA has incrementally exhausted all reasonably cost-effective means of achieving low sulfur coal fuel switches on its unscrubbed units. [EPA-HQ-OAR-2009-0491-2782.1, p. 1]
For most of TVA's unscrubbed units, Powder River Basin (PRB) sub-bituminous coal is both the lowest sulfur coal available and the lowest cost low sulfur coal available. Therefore, TVA has already maximized the use of PRB coal on all unscrubbed units wherever feasible. Most TVA units cannot accommodate 100% PRB coal; only Gallatin routinely burns 100% PRB coal. Allen routinely burns a blend of around 80% PRB coal, and units 1-6 at Johnsonville can burn 75% PRB coal. All other unscrubbed units generally burn 0-30% PRB coal with a few units on occasion increasing their PRB burn rate by 20% when the coal system can economically accept some capacity derates. Over these 15 years, TVA has increased the use of low sulfur coals wherever possible each year, and has not reverted back to burning medium or high sulfur coals (until units are scrubbed). [EPA-HQ-OAR-2009-0491-2782.1, p. 2]
Extensive equipment changes at significant cost would be required for TVA to significantly further reduce emission levels through increased use of lower sulfur coals. This is contrary to EPA's assumption that "switching from bituminous to sub-bituminous has no cost or schedule impact" [p. 45273]. These equipment changes include those that would have to be made to the coal handling and processing equipment (pulverizers, feeders, etc.), as well as the particulate control equipment. Making such expensive changes for just a few years before scrubber installations are potentially required for implementing hazardous air pollutant regulations, SIPs for achieving revised fine particulate ambient air quality standards, or other regulations promulgated under the CAA does not make economic or practical sense. The expected time for test burns, environmental review, permitting, design, procurement and construction of such fuel switch projects is approximately 48 months. Outages would need to be staggered to ensure reliability. With the final Transport Rule expected in mid-2011, the soonest most of these fuel switch changes could be implemented is mid-2015. Some changes would likely require additional time. [EPA-HQ-OAR-2009-0491-2782.1, p. 2]
Utilities, including TVA, contract long term for a significant portion of their coal supplies. Upon final release of the Transport Rule near mid 2011, utilities would have to renegotiate some fuel contracts, cancel others, and enter into some new fuel contracts. Any sudden shift to lower sulfur coals has the potential to cause major contractual and coal supply disruptions that would affect both coal companies and utilities in 2012. Such shifts in coal supply without a two to three year notice are not reasonable under existing contracts. EPA should not expect significant coal switches to begin before mid-2013 where extensive equipment changes are not required. [EPA-HQ-OAR-2009-0491-2782.1, p. 2]
A. Issue: EPA's analysis projects emission rates incorrectly as it assumes all TVA units can readily switch to very low sulfur sub-bituminous coal by 2012 (see I.A above) [See [EPA-HQ-OAR-2009-0491-2782.1, pp. 1-2 for TVA section I.A]. Data in the NEEDs Version 3.02 database indicates that all sub-bituminous coals have very low SO2 rates around 0.58 lb/MM-Btu. [EPA-HQ-OAR-2009-0491-2782.1, p. 6]
TVA Comment: EPA's use of 0.58 lb SO2/MM-Btu for sub-bituminous coals is unrealistically low. Most sub-bituminous coals used by TVA over the last 15 years have an average SO2 rate of just under 0.8 lb/MM-Btu. [EPA-HQ-OAR-2009-0491-2782.1, p. 6]
As explained above (paragraph I.A), most uncontrolled TVA units are incapable of burning 100% subbituminous coals, however bituminous and sub-bituminous coal blends are common. Appropriate modeling should include blends of bituminous and sub-bituminous coals. [EPA-HQ-OAR-2009-0491-2782.1, p. 6]
E. Issue: EPA's NEEDS Version 3.02 Emission Inventory for TVA units has numerous errors in installed controls, emission rates, heat rates, and new TVA coal unit additions, which do not exist and are not planned. [EPA-HQ-OAR-2009-0491-2782.1, p. 9]
TVA Comment: Instead of providing comments to Version 3.02 of the NEEDS database which has been replaced by the September 1 NODA release of Version 4.10 of that database, TVA defers all comments for this area of response to October 15th. [EPA-HQ-OAR-2009-0491-2782.1, p. 9]
Utility Air Regulatory Group (UARG)
As noted above, EPA states in the preamble to the PTR that it "expects about 14 GW of FGD and less than 1 GW of SCR capacity to be retrofit for Phase 2 of this rule [i.e., by January 1, 2014]." 75 Fed. Reg. at 45273/1. This projection omits the very substantial amounts of FGD and SCR retrofits that will be undertaken as part of the baseline when CAIR requirements are included in the baseline (as they should be, for reasons discussed elsewhere in these comments). In addition, because, as discussed in the preceding section of these comments, EPA has significantly underestimated the amount of time it takes to install these controls, a substantial number of retrofit projects that EPA assumes will be accomplished by the beginning of 2012 will in fact not be completed until the critical 2012-2014 period (while, for the same reason, some of the retrofit projects EPA predicts will be completed after January 1, 2012, but before January 1, 2014, will in fact not be completed until after the latter date). [EPA-HQ-OAR-2009-0491-2756.1, p.53]
According to estimates prepared by UARG's consultants James Marchetti, J. Edward Cichanowicz, and Michael C. Hein, a total of approximately 25 new GW of installed FGD capacity -- far higher than EPA's assumed 14 GW -- would be needed to meet the PTR's 2014 emission reduction requirements. [[See Docket Number EPA-HQ-OAR-2009-0491-2756.1, pp.147-168 for Attachment II.]] In addition, their report projects that a total of about 8.2 new GW of installed SCR capacity would need to be installed by 2014. These numbers include emission control projects that will be needed under the 2014 base case, including CAIR. These 2014 numbers do not include retrofit capacity that would be installed by 2012. [EPA-HQ-OAR-2009-0491-2756.1, p.53]
EPA's Use of Inaccurate Inputs and Assumptions for -- and Unrealistic Outputs from -- EPA's Use of the Integrated Planning Model Makes the Proposed Transport Rule Inadequate for Public Comment.
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. The results of EPA's numerous IPM runs provide the Agency with substantially all of the key data points to make its decisions on these critical elements of the PTR. As EPA explains in its TSD discussing its use of IPM, that model provides forecasts of least-cost capacity expansion, electricity dispatch, and emission control strategies for meeting electricity demand, environmental, transmission, dispatch, and reliability constraints. IPM can be used to evaluate the cost and emissions impacts of proposed policies to limit emissions of sulfur dioxide (SO2), nitrogen oxides (NOx), carbon dioxide (CO2) and mercury (Hg) from the electrical power sector and is used extensively by EPA to support regulatory activities. [EPA-HQ-OAR-2009-0491-2756.1, pp.80-81]
A fundamental limitation on the accuracy of any model 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 NEEDS database. The NEEDS database is fraught with significant errors, as illustrated in section VIII.A below. 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." Section VIII.A below also details various errors in the "constraints" EPA placed on the IPM model runs. [EPA-HQ-OAR-2009-0491-2756.1,p.81]
Moreover, 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.49 The second subsection below provides specific examples of inconsistencies between EPA's IPM projections and individual companies' plans for their units. The following examples are an illustrative, but by no means an exhaustive, list of problems in the NEEDS database and EPA's application of IPM to support the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2756.1, p.81]
Many of the IPM Inputs for Individual Units Are Inaccurate.
Errors in the NEEDS database identified by UARG members generally fall into three categories: (1) emission controls that were assumed to exist currently but do not; (2) overestimated emission control efficiencies of existing control equipment; and (3) failure to account for emission controls or limits that do exist. Examples of pollution controls that were assumed to exist but do not include the following: [EPA-HQ-OAR-2009-0491-2756.1, p.82]
:: NEEDS reports that PM scrubbers are already installed and operational at the Harrison power plant in West Virginia. PM scrubbers do not exist at that plant.
:: NEEDS reports that selective non-catalytic reduction ("SNCR") is already installed and operational at two units at the Armstrong power plant in West Virginia. SNCR does not exist at these two units.
:: NEEDS reports that FGD is to be installed at unit 4 at the Scherer power plant in Georgia in 2011. The current target installation date is August 2012.
:: NEEDS reports that SNCR is to be installed at units 4 and 5 at the Jack Watson power plant and units 1 and 2 at the Daniel power plant in Mississippi. No SNCRs exist or are planned for these units.
:: NEEDS reports that a wet scrubber will be installed at unit 3 at the Brayton Point power plant in Massachusetts by 2012. Under a state-approved Emission Control Plan, a dry scrubber will be installed and will commence operation in 2014.
:: NEEDS data indicate that an SCR on unit 3 at the E.W. Brown power plant in Kentucky is to be installed by the beginning of 2012. An SCR is under construction at that unit but will not be completed until the end of 2012.
:: NEEDS data indicate that an SCR exists on unit 2 at the Ghent power plant in Kentucky as of 2009. SCR neither exists nor is planned for this unit. [EPA-HQ-OAR-2009-0491-2756.1, p.82]
Examples of overestimation by NEEDS of removal efficiency of controls that currently exist: [EPA-HQ-OAR-2009-0491-2756.1, p.82]
:: NEEDS reports the FGD control efficiency at the Mitchell power plant in West Virginia at 99.9% -- an impossible figure to achieve. The actual average removal efficiency is 97%.
:: NEEDS reports the FGD control efficiency at the Pleasants power plant in West Virginia at 97%. The actual average removal efficiency is 95%. Examples of emission controls that do exist but were not included:
:: NEEDS fails to account for FGD systems at the Harrison power plant in West Virginia.
:: NEEDS fails to account for FGD systems at three units at the Hatfield's Ferry power plant in West Virginia
:: NEEDS fails to account for FGD systems at two units at the Fort Martin power plant in West Virginia.
:: NEEDS fails to account for a state SO2 emission limitation on the Cumberland power plant in Tennessee of 0.5 lb/mmBtu and instead reports SO2 emissions at that plant at a rate of 5.0 lb/MmBtu.  [EPA-HQ-OAR-2009-0491-2756.1, p.83]
In addition, errors in IPM constraints and inputs appear to be related to inaccurate interpretation of state regulations and NSR settlements, and there are other errors as well. Examples include:
:: IPM assumes (in the 2014 base case) that units 1 and 2 at the Harllee Branch power plant in Georgia will each have an FGD and SCR in place by 2014 (presumably, January 1, 2014). The Georgia Multi-pollutant Rule instead requires that these be in place by December 31, 2014.
 IPM assumes (in the 2014 base case) that unit 4 at the Harllee Branch power plant in Georgia will have an FGD and SCR in place by 2014 (presumably, January 1, 2014). The Georgia Multi-pollutant Rule instead requires that these be in place by June 1, 2014.
:: IPM assumes (in the 2014 base case) that units 6 and 7 at the Yates power plant in Georgia will each have an FGD and SCR in place by 2014 (presumably, January 1, 2014). The Georgia Multipollutant Rule instead requires that these be in place by June 1, 2015.
:: IPM assumes (in the 2014 base case) that unit 1 at the Scherer power plant in Georgia will have an FGD and SCR in place by 2014 (presumably, January 1, 2014). The Georgia Multi-pollutant Rule instead requires that these be in place by December 31,  2014. [EPA-HQ-OAR-2009-0491-2756.1, pp.83-84]
 :: IPM assumes that FGD retrofits at the Kyger Creek and Clifty Creek power plants in Ohio are complete and operational. These retrofits are not complete, and construction is currently suspended.
:: IPM assumes that one of the primary units of the Cumberland power plant in Tennessee has an SO2 emission rate of 5.0 lbs/mmBtu. The unit is currently regulated by and is complying with a state regulation that limits its SO2 emissions to 0.5 lbs/mmBtu.
:: IPM assumes that the Maryland Healthy Air Act allows for limited interstate trading and/or intrastate trading, depending on the proposed remedy, and IPM appears to treat similar sources in Maryland very differently, judging from the IPM-based allowance allocations for units. The Maryland Healthy Air Act in fact only allows for intra company trading of allowances and the unit-specific allowances established in the Maryland Healthy Air Act appear to have been ignored.  [EPA-HQ-OAR-2009-0491-2756.1, p.84]
 EPA's IPM Outcomes Do Not Reflect Actual Source Operations
UARG members have found many inconsistencies between EPA's IPM-projected operating scenarios for units in 2012 and 2014 and their own plans and projections. While EPA may argue that IPM accounts for the impact of the proposed controls and that generators are not capable of appreciating the influence of the proposed controls on their future operations, UARG members believe that their economic models, as well as their understanding of their operations, supply capabilities, and energy demand forecasts are more accurate than outputs of EPA's proprietary IPM. IPM was not designed for this level of specificity -- it is a regional-scale model. IPM often does not reflect real-world operations with respect to a number of key factors, including unit availability. Generators have years of experience with a greater level of specificity that allows them to understand the real-world constraints and demands on individual units and to better predict which units will run, how often they will run, and how long they will continue to run. [EPA-HQ-OAR-2009-0491-2756.1, p.85]
The inaccurate IPM projections fall into four categories: (1) inaccurate assumptions of emission controls; (2) inaccurate estimates of emission control efficiencies; (3) inaccurate assumptions of early retirement of particular units; and (4) inaccurate assumptions regarding fuel switching at particular units. [EPA-HQ-OAR-2009-0491-2756.1 , p.85]
Examples of inaccurate assumptions of emission controls include the following:
:: IPM projects FGD installations at the Armstrong power plant in Pennsylvania by 2014. No such installations are planned by the company.
:: IPM projects FGD installation at the Willow Island power plant in West Virginia by 2014. No such installation is planned by the company.
:: IPM projects SCR installation at unit 2 at the J.H. Campbell power plant in Michigan by 2012. No such installation is planned by the company.
:: IPM projects installation and operation of LNBs with overfire air -- based on the listed emission rate -- at the J. R. Whiting power plant (units 1-3) in Michigan. The owner of the units does not believe such controls are viable options at these units due to operational and configuration constraints.
:: IPM projects FGD installation and operation at unit 2 at the Muskingum River power plant in Ohio by 2011. Although a preliminary engineering study was conducted for unit 2, there is no ongoing construction and it would take at least three years to permit and build an FGD even if construction began immediately.
:: IPM has not allocated NOx emission allowances to units 1 and 2 at the Salem Harbor power plant even through the IPM model for the 2012 base case predicts that these units will operate. This appears to be the result of erroneous adjustments made to projected IPM emissions to account for annual operation of each unit's SNCR. No adjustment was necessary. Actual emissions already represent annual operation of SNCR -- both SNCRs have been operating on a year-round basis since October 2005 to comply with a stationwide NOx limit in accordance with a state Administrative Consent Order. [EPA-HQ-OAR-2009-0491-2756.1, p.86]
Examples of inaccurate estimates of emission control efficiencies include the following:
:: IPM projects an annual 35% NOx removal efficiency for two units at the Fort Martin power plant in West Virginia and one unit at the Hatfield's Ferry power plant in Pennsylvania. In fact, however, these units have only single-point injection controls capable of roughly 10% to 15% removal efficiency.
:: IPM projects annual NOx emission rates at the Harrison power plant and the Pleasants power plant in West Virginia from SCR as low as 0.04 to 0.05 lb/mmBtu. Such low rates were periodically achievable when the SCR was initially installed, but representative operation of the controls demonstrates that such rates are not sustainable on a long-term basis and as the effectiveness of the SCR reduces as the catalyst ages. [EPA-HQ-OAR-2009-0491-2756.1, p.86]
Examples of inaccurate assumptions of early retirement of particular units include the following:
:: IPM projects early retirement of two units at the Rivesville power plant and one unit at the Willow Island power plant in West Virginia by 2014. No retirements by 2014 are planned by the company.
:: IPM projects early retirement -- by 2014 -- of units 1 and 2 at the McManus power plant in Georgia, and of units 1 and 3 at the Watson power plant, and units 1 and 2 at the Sweatt power plant, both in Mississippi. There are no plans by the company to retire these units by 2014.
:: IPM projects early retirement of nine units in Michigan (B. C. Cobb units 1-3; D. E. Karn units 3 and 4; and Thetford units 1-4). There are no plans by the company to retire these units by 2014. [EPA-HQ-OAR-2009-0491-2756.1, p.87]
Examples of inaccurate assumptions regarding fuel switching for particular units include the following:
:: IPM projects fuel switching from coal to natural gas for three units at the Albright power plant in West Virginia and for two units at the R. Paul Smith power plant in Maryland. These fuel switches are not planned by the company.
:: IPM projects fuel switching from coal to natural gas for the McManus power plant in Georgia. This fuel switching is not planned by the company.
:: IPM projects fuel switching from higher sulfur coal to 100% Powder River Basin coal by 2012 at units 4 and 5 at the B.C. Cobb power plant and units 1-3 at the J. R. Whiting power plant in Michigan. Such a fuel switch is not feasible due to the limited timeframe and outstanding coal, rail-line, and rail-car contracts.
:: IPM projects fuel switching to low-sulfur Eastern coals at units 1-4 of the Muskingum River power plant in Ohio. These units are wet bottom/cyclone-fired boilers that, historically, do not tolerate such coal because of its high ash-fusion temperatures. [EPA-HQ-OAR-2009-0491-2756.1, p.87]
In addition to these facility-specific errors, EPA's application of IPM reveals certain systemic errors in the analysis supporting the PTR. Perhaps most notable is IPM's treatment of dual-fuel units, i.e., units capable of burning either natural gas or oil. Of the 493 dual-fuel units in the NEEDS database, IPM predicted in the 2014 limited trading control strategy that 34 units would burn oil as the primary fuel. EPA proposes to allocate any SO2 allowances to only 8 of those 34 units. This result ignores the reality that many dual-fuel units do regularly burn oil for some part of the year, whether due to natural gas supply limitations, price factors, or facility-specific constraints. The mere fact that the IPM analysis may project that it will be more economical to run these units on natural gas than on oil does not mean that the real-world factors that lead to combustion of oil at these units simply disappear. [EPA-HQ-OAR-2009-0491-2756.1, pp.87-88]
IPM projection errors of this sort appear to be a function of inherent limitations of IPM and/or 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, for example, in inaccurate projections for oil-fired units and dual-fuel units. When IPM predicts natural gas is less expensive than oil or that burning oil at an oil-fired unit is for some reason not "economical" within the terms of IPM's protocol, no SO2 emissions are projected from -- and thus no SO2 allowances are allotted to -- that unit. [EPA-HQ-OAR-2009-0491-2756.1, p.88]
EPA must recognize the limitations of IPM and must consider local issues and allow UARG members, other generators, and other members of the public to comment on EPA's adjustments to address those issues. For example, it should be self-evident that particular units that have burned oil in the past, and that continue to burn oil, can be expected to burn oil in the future and should receive allowance allocations; the presumption should be in such cases that allowance allocations to those units are appropriate in the absence of compelling reasons to the contrary. At a minimum, EPA should not blindly insist that IPM's projections for these types of units are accurate and should instead make adjustments to the allocation determinations for these types of units, based on comments of companies with interests in those units. [EPA-HQ-OAR-2009-0491-2756.1, pp.88-89]
Another systemic error involves the heat input rates listed in the "BADetaileddata.xls" spreadsheet associated with the proposed direct control alternative remedy. Heat input is overstated by a factor of 10 in this spreadsheet. Because of the absolute tonnage cap in the direct control case, these artificially high heat input levels are essentially meaningless in this context. Nonetheless, these types of errors draw into further question the accuracy and validity of the NEEDS database and IPM modeling runs. [EPA-HQ-OAR-2009-0491-2756.1, p.89]
Accordingly, EPA should correct the errors in the NEEDS database and correct the erroneous and inaccurate IPM inputs and then rerun the critical IPM model runs, to the extent EPA continues to use IPM modeling as a basis to develop state budgets. Given the serious limitations in IPM's capabilities as discussed above, EPA should develop for public review and comment alternative methods of calculating unit allowance allocations (for example, alternative methods that use appropriate measurements of units' historical heat input, as EPA did in the NOx SIP Call rule and CAIR). EPA should then publish revised proposed budgets and allocations for public review and comment. However, any proposed allocations should at most be "model" allocations for consideration by the states; for the reasons discussed elsewhere in these comments, EPA has an obligation to allow each state to make -- and to give each state adequate time to make -- any emission control decisions for sources within the state and to incorporate those decisions in SIPs. [EPA-HQ-OAR-2009-0491-2756.1, pp.89-90]
Footnote 49: Another problem with the outputs from IPM results from the fact that IPM does not perform a probabilistic analysis. IPM outputs give the illusion that they are precise even though they are not. It would be more realistic for EPA to consider a range of projected data than to treat a single data point from IPM as a precise data point for purposes of calculating budgets and allowance allocations.
Wabash Valley Power
WVPA has reviewed the data input tables used in EPA's technical and financial modeling for the proposed Transport Rule as well as the modeled projections of unit operation. We noted several instances in which the data appear to be in error for WVPA's generation units. [EPA-HQ-OAR-2009-0491-2627.1, p.2]
Holland Energy Facility:
EPA lists the Holland facility as having two (2) combustion turbines, CTG 1 and CTG2, each with a capacity of 147 MW, and a steam turbine with a capacity of 155 MW. We would like to point out that the capacity of these units changes based on ambient weather conditions. More specifically, CTG 1 and CTG2 each have a capacity of 172 MW at ISO conditions while the STG 1 has a nominal capacity of 343.3 MW. [EPA-HQ-OAR-2009-0491-2627.1, p.2]
Additionally, EPA's preferred option base case for 2012 shows the units operating only in the summer months and projects a total heat input for the plant of 0.526 TBtu. It should be noted that this facility is a two-on-one natural gas fired combined cycle facility equipped with natural gas fired duct burners in each of the two heat recovery steam generator (HRSG) units. The plant operates as an intermediate load resource and has been dispatched in every quarter since its construction; not solely limited to summer operation as EPA's model suggests. WVPA's forecast for 2012 shows a projected heat input to the two combustion turbines of 2.8572 TBtu. As such, the EPA's projection for 2012 is roughly 18.4% of WVPA's anticipated consumption. [EPA-HQ-OAR-2009-0491-2627.1, p.2]
Similarly, in 2014, EPA's preferred option base case again shows the Holland facility running only in the summer months with a total heat input for the plant of 1.2354 TBtu. WVPA's 2014 forecast projects a heat input to the two combustion turbines alone of 4.9724 TBtu. As such, the EPA projection for 2014 is less than 25% of that of WVPA's. [EPA-HQ-OAR-2009-0491-2627.1, p.2]
Furthermore, WVP A believes that its own forecast may be conservative (low) as it does not reflect increased demand for gas-fired generation due to the anticipated retirement of small, older coal units as a result of this rule. [EPA-HQ-OAR-2009-0491-2627.1, p.2]
We also note that EPA's BADetailedData spreadsheet lists NOx emission rates for CTG 1, CTG2, and STG 1 of 0.025, 0.014, and 0.025 lb NOx/mmBtu respectively. Upon review of the data, EPA appears to have redistributed heat input values and total mass emissions associated with CTG 1 by evenly dividing them between CTG 1 and the STG 1 (steam turbine). We believe that the same was done with respect to the NOx emission rate. Based on 2009 EDR submissions, the NOx rate for CTG1 is 0.05 lb NOx/mmBtu and 0.017 lb NOx/mmBtu for CTG2. However, EPA's spreadsheet lists 0.025 lb NOx/mmBtu for CTG 1 and STG 1. While it generally does not cause a problem to evenly divide and redistribute mass emissions among the units, the same is not true for a concentration based emission rate. As a result we are concerned that EPA may have made an error which will negatively impact our NOx allowance allocations. [EPA-HQ-OAR-2009-0491-2627.1, p.3]
Wabash River Unit 1 and 1A:
This former coal fired unit was repowered in 1994 as an Integrated Gasification Combined Cycle (IGCC) facility. WVPA acquired controlling interest in the gasification facility in 2005 and subsequently purchased the associated combined cycle facility from Duke Energy in 2008. EPA's Wabash River Unit 1 d~signati6n is the repowered 85 MW steam turbine and the Unit 1A designation represents the nominal 192 MW (incorrectly listed at 189 MW) combustion turbine. Being IGCC, the removed sulfur is > 99% pure and is sold for reuse. Furthermore, as sulfur is removed before combustion, there is no need and little benefit to installing a post-combustion FGD system. EPA also incorrectly lists this unit as needing a 97% FGD removal rate. This is an IGCC facility and has no FGD. The gasification facility is permitted to gasify either coal or petroleum coke. The gasification process treats the resulting syngas to remove particulate and sulfur prior to utilizing the syngas as a fuel in .the combustion turbine. EP A has incorrectly classified this facility as a coal facility. The electrical generation (combined cycle) portion of the facility is fueled solely by syngas or natural gas. EPA incorrectly lists existing NOx control as nitrogen diluent injection (NDI). The combustion turbine is equipped with steam injection for NOx control. [EPA-HQ-OAR-2009-0491-2627.1, p.3]
We also note that EPA's BADetailedData spreadsheet lists an annual NOx emission rate of 0.068 lb/mmBtu for Units 1 and 1A. This facility can not currently meet this limit. As stated above, the combined cycle portion of this IGCC facility does utilize steam injection to control NOx emissions. However, due to other differences in the IGCC process, conventional application of an SCR is not viewed as a viable technical solution for achieving additional NOx reductions. [EPA-HQ-OAR-2009-0491-2627.1, p.3]
Response:
EPA's response to these comments in the final Transport Rule is multi-faceted:
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 units 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.  While 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.
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 versions (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.  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.
Additionally, some commenters noted small discrepancies between the universe of units allocated allowances, and the universe of units included in the IPM modeling.  The EGUS reflected in the modeling are a comprehensive list of existing and planned units and are a reasonable proxy of the existing EGU fleet.  There is the possibility of some units being allocated to that are not included in the modeling projections (e.g., a unit that is planning on retiring in 2011), additionally there could likewise be some units that the IPM modeling list as two units (i.e., one plant with a combustion turbine and steam turbine - each 30 MW), but where the source actually reports as one 60 MW unit.
Organization: Nebraska Public Power District
Comment:
2) Nebraska Non-point SO2 Emissions Inventory. In evaluating whether Nebraska should be included in the proposed TR, EPA modeled 2005 total emissions, purported to be from all sources, as a baseline case. EPA cites a Nebraska 2005 baseline total SO2 emission inventory of 121,589 tons/year in the preamble of the proposed TR. Of this total amount of SO2 emissions for the State, the so-called "nonpoint" portion modeled by EPA is 29,575 tons/year. Review of the detailed emission inventory 1 reveals that this "nonpoint" inventory includes SO2 emissions from industrial and commercial/ institutional boilers of almost 29,000 tons/year. Such boilers would really not be nonpoint sources. While certain industrial and commercial/institutional boilers not inventoried as specific point sources can be classified as nonpoint sources, EPA appears to grossly overestimate the contribution of such boilers to the nonpoint emissions inventory for Nebraska. [EPA-HQ-OAR-2009-0491-2711.1, pp.1-2]
Most of the nearly 29,000 tons of SO2 emissions attributed to nonpoint industrial and commercial/institutional boilers in the inventory database are attributed to subbituminous or bituminous coal usage. While EPA's TR modeling "non-EGU" point source SO2 emissions inventory for Nebraska -- 6,429 tons/year -- appears to be a reasonable estimate based on our review of facility-by-facility emissions included in the NEI database, and Energy Information Administration (EIA) data, EPA's estimate that noninventoried boilers in Nebraska account for 450% more SO2 per year than point source boilers appears to be so inaccurate that a modeling mistake may have been made. EIA coal consumption data for 2007 and 2008 show that, industrial and commercial/ institutional boiler usage of coal in Nebraska was less than 432,000 short tons per year (EIA's "Other Industrial" end user category accounts for small amounts of coal consumed by sources other than boilers). Based on typical sulfur levels in the Powder River Basin coal (~0.5% sulfur by weight) burned in virtually all of Nebraska, this is generally consistent with the "non-EGU" emission level cited above. While EIA's consumption data excludes smaller sources (end users that consume less than 1,000 short tons of coal per year) that may fall within the nonpoint source category, we find it extremely improbable that these smaller, non-inventoried sources account for approximately 29,000 tons per year of SO2 emissions (nearly 25% of the Nebraska 2005 baseline inventory) for EPA's modeled 2005 SO2 inventory for Nebraska. EPA compounds this apparent error by carrying forward this incorrect estimate as the basis of the 2012 and 2014 base case emissions inventories. [EPA-HQ-OAR-2009-0491-2711.1, p.2]
3) Nebraska Non-point NOx Emissions Inventory. As with the SO2 emissions overestimation described in Item 2, the NOx emissions for "non-point" Nebraska sources appears to be significantly overstated by EPA, because approximately half the reported non-point NOx total in the 2005 baseline inventory is listed in the database as being associated with fossil fuel combustion in industrial, commercial and institutional coal boilers. If EPA made the same error in estimating nonpoint industrial and commercial/institutional coal boiler NOx emissions as it did for the SO2 inventory, then EPA's 2012 and 2014 NOx base case emissions inventories for Nebraska are also improperly inflated, reflecting the inaccurate 2005 NOx baseline. [EPA-HQ-OAR-2009-0491-2711.1, p.2]
4) Nebraska EGU SO2 Emissions Inventory Overview. EPA has grossly overestimated the amount of SO2 emissions from EGUs for purposes of establishing the 2012 base case for Nebraska. As discussed below, NPPD estimates that EPA has inflated the Nebraska SO2 base case by about 40,000 tons of SO2. This amounts to a 50% overestimation in SO2 emissions and it will increase the Nebraska EGU emissions for SO2 from about 80,000 tons to over 120,000 tons. Furthermore, EPA has provided no explanation that can justify such a steep increase in EGU SO2 emissions. Rather, EPA relies on Integrated Planning Model (IPM) projections that are intended to forecast EGU SO2 emissions for Nebraska and other States without the regulatory constraints of the Clean Air Interstate Rule (CAIR). In support of this approach, EPA states: "without the CAIR SO2 program, emission requirements in many areas would revert to the comparatively less stringent requirements of the Title IV Acid Rain Program" and that as a result affected utilities would comply with the Acid Rain Program "without the operation of existing scrubbers through use of readily available, inexpensive Title IV allowances."2 While NPPD generally agrees with this approach in the case of those states subject CAIR, the EPA approach is entirely unnecessary for States, like Nebraska, that are not subject to the CAIR program. [EPA-HQ-OAR-2009-0491-2711.1, p.3]
Furthermore, EPA has used inaccurate and erroneous IPM modeling assumptions to project the 2012 base case EGU emissions. The modeling assumption of greatest concern relates to the sulfur content of coal that Nebraska EGUs will burn during the 2012 base case. As explained below, all coal-fired Nebraska EGUs have historically consumed low-sulfur subbituminous coal and thereby have collectively achieved an average annual SO2 emissions rate ranging from 0.57 to 0.69 lb/MmBtu during the last decade. Notably, the Nebraska coal-fired EGUs have continuously used this low-sulfur subbituminous coal and achieved these low annual SO2 emissions rates before and during the Acid Rain program. In addition, they have done so while not being subject to the CAIR program. [EPA-HQ-OAR-2009-0491-2711.1, p.3]
Viewed in this context, EPA must provide specific technical support that can plausibly justify why the Nebraska coal-fired EGUs would suddenly deviate from this longstanding practice and start using coals with a higher sulfur content that would greatly increase the average SO2 emissions for all Nebraska coal units to almost 0.9 lb/MmBtu. To put in other words, EPA cannot rely on IPM projections to claim such a radical departure in the SO2 emissions levels for Nebraska coal-fired EGUs values without identifying changed circumstances that can credibly explain this departure under the IPM modeling. [EPA-HQ-OAR-2009-0491-2711.1, p.3]
[For additional comments pertaining to Nebraska EGU SO2 Emissions Inventory, see pp. 3-5 of this comment. Attachments 1-3 can be found on pp. 10-12 of this comment.]

1. See http://www.epa.gov/ttn/chief/net/2005inventory.html#inventorydata. [EPA-HQ-OAR-2009-0491-2711.1, p.2]
2. 75 Fed. Reg. at 45,234. [EPA-HQ-OAR-2009-0491-2711.1, p.3]
3. 75 Fed. Reg. at 45,290 (emphasis added). [EPA-HQ-OAR-2009-0491-2711.1, p.4]
Response:
In regards to EGU emissions inventories, EPA reviewed comments received on the Transport Rule proposal and subsequent NODA for the EPA IPMv.4.10 model.  EPA made significant updates to both unit level and macro level assumptions in its modeling based on these comments.  This updated modeling was then used to conduct the air quality modeling anew for the final Transport Rule.  Nebraska's inclusion in the final Transport Rule geography for the PM2.5 NAAQS is based on this final rule air quality modeling of their 2012 base case emissions from the final rule power sector modeling, which includes a substantial reduction compared to the proposal's base case modeling of Nebraska's base case SO2 emissions from EGUs. Notwithstanding these revised results, the final rule's air quality modeling continued to support EPA's conclusion that Nebraska should be included in the Transport Rule's programs for addressing significant contribution to nonattainment and interference with maintenance in downwind states for the PM2.5 NAAQS assessed in this rulemaking.
Organization: Nelson Industrial Steam Company (NISCO)
Comment:
Nelson Industrial Steam Company (NISCO)
EPA's original modeling, using the IPM version 3.02 for the Base Case, projected that Louisiana emissions may interfere with maintenance of the annual PM2.5 NAAQS in 2012, by contributing only 0.34 ug/m3 to the annual PM2.5 values at the Clinton Drive monitor in Houston, Harris Co., TX. Of that total, EPA projected that 0.33 ug/m3 is from sulfate emissions and only 0.004 ug/m3 from nitrate emissions. The projected design value for the Clinton Drive monitor in 2012 was 14.74 ug/m3 average and 15.14 ug/m3 maximum compared to the 15.0 NAAQS ug/m3. The 2008 PM2.5 annual average at Clinton Drive was 14.0 ug/m3, even when exceptional event days are included. The annual average PM2.5 in 2009 was only 12.8 ug/m3 and from January 1 through August 29, 2010, the average is 12.72 ug/m3. 5 The design value dropped to 14.4 ug/m3 for the 2007-2009 period and is expected to drop to a value of approximately 13.2 ug/m3 further this year due to 2007 dropping out of the 3-year average. 6 So, it is clear that current Louisiana emissions are not interfering with maintenance of the NAAQS in any way. These Louisiana emissions are projected by EPA to drop even further without the CATR/FIP. [EPA-HQ-OAR-2009-0491-3789_NODA, p.2]
EPA also projected, under the IPM version 3.02 Base Case, that Louisiana emissions will significantly contribute to nonattainment with the 1997 8-hour ozone NAAQS at certain monitoring sites in the Houston-Galveston-Brazoria ('HGB') and the Dallas-Ft. Worth ('DFW') Areas of Texas in 2012. EPA has projected that Louisiana emissions will interfere with maintenance of that NAAQS at other monitoring sites in the HGB and the DFW Areas of Texas in 2012. But, again, real data cast doubt on these projections. All monitors in the HGB Area are currently in attainment with the 1997 8-hour ozone NAAQS and have been since 2008 (based upon the 2006-2008 monitoring data). All of the DFW monitors that EPA projected were adversely impacted by Louisiana emissions, save one, are also currently in attainment with that NAAQS. The design value at that one monitor at issue in DFW is 86 ppb, just 2 ppb above the standard. [EPA-HQ-OAR-2009-0491-3789.1_NODA, pp.2-3]

5 Texas Commission on Environmental Quality, CAMS 403, PM-2.5 (Local Conditions) Acceptable Summary for 2010, http://www.tceq.state.tx.us/cgi-birdcompliance/monops/yearly_summarv.pl (last visited Sep. 21, 2010).
6 Texas Commission on Environmental Quality, PM2.5 Data: Soot, Dust, Particulate Matter, (last visited Oct. 1, 2010)
Response:
EPA has updated its IPM modeling and EGU emissions inventories in response to comments on the IPM version 3.02 for the base case.  As a consequence, the base case EGU emissions for states have changed.  EPA conducted its final air quality modeling off the updated base case.  In the final Transport Rule, Louisiana is no longer subject to Transport Rule annual PM2.5 programs.  However, the updated IPM and air quality modeling indicate the state is still "linked" to Texas receptors sites at Brazoria and Harris for 8-hour ozone.  See section V.D of the preamble for more details.  Additionally, see IPM documentation,  "Documentation Supplement for EPA Base Case v.4.10_FTransport  -  Updates for Final Transport Rule" and "Transport Rule IPM Assumptions Response to Comments" for details regarding IPM updates and assumptions in the v.4.10 used in the final Transport Rule.  Also, EPA notes that the 2012 base case used in air quality modeling represents power sector operations in the absence of CAIR.  Both the proposal and final rule preamble explain why this is necessary.  Therefore, comments suggesting that 2012 base case emissions data and receptor status in the final Transport Rule are incorrect simply because they do not reflect recent emissions data and receptor status observed once the CAIR rule was final are misguided, as EPA has clearly stated that the base case represents a world without CAIR.
Organization: NRG Energy
Comment:
NRG Energy
Correction for EPA Database: NRG Units that should not be in the TR NRG's Cos Cob Units 13 and 14 (Cos Cob) appear in the EPA Allocation Table; however, they are not included in the results of the Integrated Planning Model (IPM) work. The proposed Transport Rule states that affected units are included in Appendix A; however, a draft Appendix A is not published on the website. It is assumed that the draft Allocation Table is the draft Appendix A. It is unclear if the Cos Cob units will be included in the Rule. The Cos Cob units are combustion turbines operational in June 2008 that were initially listed as each unit having a nameplate capacity of 25 MW. Each unit is in actuality a 20 MW unit and therefore should not be included in CATR. A copy of the New Unit Exemption form as filed with the Connecticut Department of Environmental Protection and the EPA is attached to this document as Attachment 3. [EPA-HQ-OAR-2009-0491-2749.1, p. 6; see p. 11-17 for New Unit Exemption form.]
Correction for EPA Database: NRG Units that Should be in the TR EPA has included in its IPM work generating units that exist or are expected to be operational by January 1, 2012. Missing from the database are eight new units in Connecticut that are or will be operational prior to January 1, 2012. [EPA-HQ-OAR-2009-0491-2749.1, p. 6]
GenConn Devon LLC ("GenConn Devon") is the owner of the four 50 MW simple-cycle combustion turbines (CTs) that were deemed commercial between June and August 2010. The four CTs are located at Devon Station in Milford, Connecticut. Devon Power LLC (DPL), a wholly owned subsidiary of NRG, is the operator of the turbines, pursuant to an Operations and Maintenance Agreement between GenConn Devon and DPL. [EPA-HQ-OAR-2009-0491-2749.1, p. 6]
There are four existing CTs owned by DPL (Units 11, 12, 13 and 14) located at Devon Station that are in EPA's current database. GenConn Devon's four new units are designated as Units 15, 16, 17, and 18 (Units 15 -18), are designed to combust natural gas or ultra-low sulfur distillate oil, and are equipped with a Selective Catalytic Reduction (SCR) system. The specific data needed to model these units will be submitted in NRG's comments on the Notice of Data Availability (NODA). [EPA-HQ-OAR-2009-0491-2749.1, p. 6]
GenConn Middletown LLC (GenConn Middletown) is the owner of the four, 50 MW simple-cycle combustion turbines (CTs) currently being constructed at Middletown Station located in Middletown, Connecticut. The GenConn Middletown CTs will be commercial by June 1, 2011. Middletown Power LLC (MPL), a wholly owned subsidiary of NRG, will be the operator of the turbines, pursuant to an Operations and Maintenance Agreement between GenConn Middletown and MPL. [EPA-HQ-OAR-2009-0491-2749.1, p. 6]
GenConn Middletown's four new units are designated as Units 12, 13, 14 and 15 (Units 12-15) and are identical to the GenConn Devon units. The specific data needed to model these units will be submitted in NRG's comments on the NODA. [EPA-HQ-OAR-2009-0491-2749.1, p. 6]
Response:
See Transport Rule final allocation tables and final IPM modeling parsed outputs for unit level details.  Cos Cob is included in the modeling, but not included in the final allocation tables as Connecticut is not covered under the final Transport Rule geography.
EPA IPMv.4.10 modeling was also updated between proposal and final to reflect the Devon and Middletown units mentioned in the comment.
Organization: PPG Industries, Inc.
Comment:
PPG Industries, Inc.
EPA's original modeling, using the IPM version 3.02 for the Base Case, projected that Louisiana emissions may interfere with maintenance of the annual PM2.5 NAAQS in 2012, by contributing only 0.34 ug/m3 to the annual PM2.5 values at the Clinton Drive monitor in Houston, Harris Co., TX. Of that total, EPA projected that 0.33 ug/m3 is from sulfate emissions and only 0.004 ug/m3 from nitrate emissions. The projected design value for the Clinton Drive monitor in 2012 was 14.74 ug/m3 average and 15.14 ug/m3 maximum compared to the 15.0 NAAQS ug/m3. The 2008 PM2.5 annual average at Clinton Drive was 14.0 ug/m3, even when exceptional event days are included. The annual average PM2.5 in 2009 was only 12.8 ug/m34 and from January 1 through August 29, 2010, the average is 12.72 ug/m3. 5 The design value dropped to 14.4 ug/m3 for the 2007-2009 period and is expected to drop to a value of approximately 13.2 ug/m3 further this year due to 2007 dropping out of the 3-year average.6 So, it is clear that Louisiana emissions now are not interfering with maintenance of the NAAQS in any way. [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.2]
EPA also projected, under the IPM version 3.02 Base Case, that Louisiana emissions will significantly contribute to nonattainment with the 1997 8-hour ozone NAAQS at certain monitoring sites in the Houston-Galveston-Brazoria ('HGB') and the Dallas-Ft. Worth ('DFW') Areas of Texas in 2012. EPA has projected that Louisiana emissions will interfere with maintenance of that NAAQS at other monitoring sites in the HGB and the DFW Areas of Texas in 2012. But, again, real data cast doubt on these projections. All monitors in the HGB Area are currently in attainment with the 1997 8-hour ozone NAAQS and have been since 2008 (based upon the 2006-2008 monitoring data). All of the DFW monitors that EPA projected were adversely impacted by Louisiana emissions, save one, are also currently in attainment with that NAAQS. The design value at that one monitor at issue in DFW is 86 ppb, just 2 ppb above the standard. [EPA-HQ-OAR-2009-0491-3735.1_NODA, pp.2-3]

5 Texas Commission on Environmental Quality, CAMS 403, PM-2.5 (Local Conditions) Acceptable Summary for 2010, http://www.tceq.state.tx.us/cgi-bin/compliance/monops/yearly summary.pl (last visited Sep. 21, 2010).
6 Texas Commission on Environmental Quality, PM2.5 Data: Soot, Dust, Particulate Matter, (last visited Oct. 1, 2010)
Response:
EPA has updated its IPM modeling and EGU emissions inventories in response to comments on the IPM version 3.02 for the base case.  As a consequence, the base case EGU emissions for states have changed.  EPA conducted its final air quality modeling off the updated base case.  In the final Transport Rule, Louisiana is no longer subject to Transport Rule annual PM2.5 programs.  However, the updated IPM and air quality modeling indicate the state is still "linked" to Texas receptors sites at Brazoria and Harris for 8-hour ozone.  See section V.D of the preamble for more details.  Additionally, see IPM documentation,  "Documentation Supplement for EPA Base Case v.4.10_FTransport  -  Updates for Final Transport Rule" and "Transport Rule IPM Assumptions Response to Comments" for details regarding IPM updates and assumptions in the v.4.10 used in the final Transport Rule.  Also, EPA notes that the 2012 base case used in air quality modeling represents power sector operations in the absence of CAIR.  Both the proposal and final rule preamble explain why this is necessary.  Therefore, comments suggesting that 2012 base case emissions data and receptor status in the final Transport Rule are incorrect simply because they do not reflect recent emissions data and receptor status observed once the CAIR rule was final are misguided, as EPA has clearly stated that the base case represents a world without CAIR.
Organization: Southern Company
Comment:
Southern Company
X. EPA Used Many Inaccurate Inputs and Assumptions for-and Unrealistic Outputs from-EPA's Integrated Planning Model (IPM)
Note that while EPA made numerous errors in assumptions on emission rates, control technologies and other parameters, we are not including comprehensive specific comments on those errors since EPA has already proposed new data through the NODA. Some of the errors identified to date are listed below. [EPA-HQ-OAR-2009-0491-2864.1, p. 23]
A. EPA Made Many Assumptions in NEEDS 3.02 Regarding Individual Units that Are Inaccurate
Our review has found that EPA incorrectly characterized a number of the existing dispatchable FGDs for some of Alabama Power Company's units as not existing until 2012. [See EPA-HQ-OAR-2009-0491-2864.1, pp. 23-25 for list of individual units.] [EPA-HQ-OAR-2009-0491-2864.1, p. 23]
B. EPA Made Many Assumptions in IPM Regarding Individual Units that Are Inaccurate Below are errors identified in the IPM Modeling Inputs. Most of the errors we have found in IPM model files are related to the Georgia Multipollutant Rule (see Attachment A) and timing of controls. [See EPA-HQ-OAR-2009-0491-2864.1, p. 25 for list of individual units.] [EPA-HQ-OAR-2009-0491-2864.1, p. 25]
Although not explicitly explained, IPM predicted that the vast majority of dual fuel units would run exclusively on natural gas. Therefore, EPA did not allocate any S02 allowances to 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). For example, IPM modeling assumes the Plant McManus will burn natural gas in 2014, and yet we have no plans to do so. Plant McManus is not currently permitted to bum natural gas and does not even have a current gas supply. Also, the 'preferred' remedy IPM cases for 2012 and 2014 show Plant McManus not operating at all (e.g., no heat input and no emissions). Georgia Power conducted a study on conversion to natural gas thirty years ago that found that while an existing natural gas line was near the plant site, the supply from that line would not be adequate for the plant. The study has not been updated recently. Suppliers also generally ask for a commitment to consume a certain amount of natural gas, which we may be unable to do considering McManus is a peaking facility. Conversion to natural gas would also involve building a gas lateral from the supplier's lines, which we may or may not be able to accomplish quickly. Additional cost and schedule considerations involved in building a gas lateral include acquiring right-of-way property and potential permitting activities. In summary, there are no plans to convert McManus to natural gas by 2014 and, because of potential regulatory permitting and technical limits of the existing pipeline, it is unlikely that it is possible to do so in that timeframe. [EPA-HQ-OAR-2009-0491-2864.1, pp. 25-26]
Below are additional errors identified in the IPM-Modeled outcomes
IPM assumes as a control strategy 'early retirements' for McManus (1 & 2), Watson (1 & 3), and Sweatt (1 & 2). The 'preferred' remedy IPM case in 2012 and 2014 does not project that any of these will operate (e.g., no heat input and no emissions). Retirement of any unit is a complex decision based on projected need, transmission requirements, reliability requirements, and cost. An assumption by IPM of an early retirement of a unit may be greatly flawed and should not dictate future allocations for that unit. The Company currently has no plans to retire these units.  [EPA-HQ-OAR-2009-0491-2864.1, p. 26]
-When compared to recent historical data, there appear to be some assumptions for switching to lower sulfur coals within grade for certain units in the 2012 base case. We will defer our detailed comments for the NODA comment period. However, in particular, the S02 emission rates for Plant Yates Unit 2-7 all appear to be much lower than recent actual S02 emission rates and may indicate a switch to lower sulfur coal within grade (or may be due to incorrect fuel assignment of 'Coal Steam' in NEEDS). Some other units, such as Kraft and McIntosh also appear to have lower S02 rates than recent actual, although the differences are less drastic than Yates. As noted earlier, even simple coal switches can take years to implement. The emission rates assumed for these three plants imply an average bituminous coal sulfur content in the 0.6-0.7% range, for which such considerations as coal availability and supply reliability, transportation availability, and cost become extremely important. [EPA-HQ-OAR-2009-0491-2864.1, p26-27]
Furthermore, EPA erred in assuming that units 4, 5, 6 and 7 at Plant Crist in Escambia County, Florida, and units 4 and 5 at Plant Crystal River in Citrus County, Florida, have dispatchable wet FGDs that would not operate in the 2012 base case. In fact, the operation of these wet FGDs are required by the state of Florida (see construction permits No. 0330045-023-AC (Crist) (Attachment C) and No. 0170004-019-AC (Crystal River), both of which are being incorporated in their Title V permits) and would reduce the total combined Florida EGU (> 25 MW) S02 emissions by almost 40% from the 2012 base case. Had EPA properly accounted for a) the reduction in local emissions in the Birmingham area and b) emissions reductions from Florida sources in the base case, that analysis would almost certainly have found that Florida did not interfere with maintenance of the annual PM2.5 standard in Birmingham, AL. Therefore, Florida should not be considered for inclusion as a Group 1 state. [EPA-HQ-OAR-2009-0491-2864.1, p. 43]
Response:
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 units 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 versions (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
Organization: State of Wisconsin, Department of Natural Resources
Comment:
State of Wisconsin, Department of Natural Resources
At a minimum EPA needs to consider critical fixes to the IPM model which address several basic assumptions and parameters for individual units. One such assumption is that EPA needs to consider that equipment installations typically require approval from several state agencies which adds to installation timeframes. The IPM model also backslides on S02 emissions for individual units by providing for allowances up to permitted emission rates several times higher than actual emission rates. Corrections are also provided for existing and committed emission rates and addition of missing generation units. Other issues include facilities that have dedicated service loads such as Valley, Milwaukee County Power Plant and Presque Isle which must be considered in both scheduling outages and overall operation in setting emission budgets and allowing for modeled retirement. Specific comments to the IPM model and Wisconsin units, compiled to date, are provided in Appendix B [See EPA-HQ-OAR-2009-0491-2829.3, p.6 for comments pertaining to Appendix B]. An updated version of these fixes will be submitted in comment to the EPA's NODA request for the Transport Rule. [EPA-HQ-OAR-2009-0491-2829.2, p.13] [See EPA-HQ-OAR-2009-0491-2829.2, pp.14-18 for figures 1-5: Figure 1: Total Heat Input to EGU Generation - 9 States, Figure 2: NOx Mass (Annual Tons) - Historic & Projected Programs in 9 states, Figure 3: Average Annual EGU NOx Emission Rate Trend 2002 and 2005-09 in 9 States compared to TR 2014, Figure 4: SO2 Mass (Annual Tons) - Historic & Projected Programs in 9 States, Figure 5: Average Annual EGU SO2 Emission Rate Trend 2002 and 2005-09 in 9 States compared to TR 2014]
From an inventory perspective, EPA had to project baseline uncontrolled and FIP-controlled future EGU inventories in order to assess contribution and remedy impacts, but the Agency places too much weight on the projection of EGU regional loading patterns and emissions controls exclusively using the IPM model. The model uses a perfect foresight approach to EGU sector operation and controls investment algorithms. (This concern is more fully addressed in comments below dealing with the setting of EGU program budgets to fully address EGU contribution.) [See EPA-HQ-OAR-2009-0491-2829.2, p.7 for comments pertaining to the setting of EGU program budgets to fully address EGU contributions; See EPA-HQ-OAR-2009-0491-2829.2, pp.6-7]
Response:
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 units 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.
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 versions (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
EPA notes that while its final allocation methodology does not directly consider emission limits at a source due to permit rates or consent decrees, it does, however, indirectly factor in these requirements to the extent they are reflected in the source's historic baseline emissions that used to determine final allocations.  The maximum historic emissions over the baseline period serve as a ceiling on the total allocation to any particular source.  Therefore, if the permit rate limits or consent decree requirements are reflected in the historic baseline emissions that form the basis of this ceiling on allocations, then they are indirectly factored into the final allocations.  Furthermore, regardless of the initial allocation to a source under a Transport Rule FIP, it by no means changes that source's legal responsibility to comply with pre-existing permit or consent decree limits regarding its emissions.  The allocation to any particular source does not allow for "backsliding".
As discussed in section VII.D, the state budget is determined independently of the allowance allocation, and therefore the allocation methodology has no bearing on whether a state fully eliminates its significant contribution and interference with maintenance to downwind states.  Such elimination is assured by the imposition of the state budgets.
Organization: Virginia Department of Environmental Quality (VDEQ)
Comment:
Virginia Department of Environmental Quality (VDEQ)
EPA should review the NEEDS inputs and IPM outputs for Mirant-Potomac River (ORIS Code 3788). All units as this facility have been retrofitted with sorbent injection for S02 control. Copies of the relevant permits for this facility may be found at the above websites. This control does not appear to be reflected in the NEEDS input for the units. IPM outputs for the limited trading case for this facility indicate that SNCR may be installed in future years on units 1 and 2. This conclusion by IPM is quite puzzling since 1 and 2 are smaller, older units than 3, 4, or 5. VDEQ knows of no plans for this facility to install additional NOx control devices beyond those listed in the facility's permits. [EPA-HQ-OAR-2009-0491-2595.1, p.4]
Response:
SO2 control is reflected for units at the Mirant-Potomac River Facility in the final IPM modeling.  In addition the updated IPM modeling does not reflect SNCR installation on units 1 & 2.
Organization: Xcel Energy Inc.
Comment:
Xcel Energy Inc.
4. Xcel Energy has identified errors in the NEEDS database and the IPM input files.
Xcel Energy has conducted a detailed analysis of EPA's modeling to ensure all inputs are correct and has found several errors. A complete listing of these errors is shown in Appendix A [see page A-1 of this comment for Appendix A]. A few main points about these errors are summarized below. [EPA-HQ-OAR-2009-0491-2728.1, p.10]
- EPA has indicated in the IPM 3.02 runs that the Jones Unit 1, Plant x Units 1, 2, 3 and 4 will have SCR retrofits in 2012. These units are currently gas fired units used for load following and peaking purposes. Xcel Energy has no plans at this time to install SCR on these units. EPA also indicates that these units as well as Moore County Unit 3 will be retired in 2014. Xcel Energy does not plan to retire Jones Unit 1, nor Plant X Unit 3, nor Plant X Unit 4 by 2014. Plant X Units 1 and 2 as well as Moore County Unit 3 are planned to be retired by 2014. [EPA-HQ-OAR-2009-0491-2728.1, p.10]
- In its documentation EPA indicates there was unusually low utilization of generation facilities in 2009, so the Agency used 2008 data to adjust NOx allocations. Some of Xcel Energy's facilities had higher utilization in 2009 than 2008. This affects Black Dog Units 3 and 5; Sherburne County Units 1, 2 and 3; Blue Lake Units 2 and 4; and Inver Hills Unit 3; Bay Front Units 1 and 2; French Island Unit 3; and Wheaton Unit 5. EPA should use the higher of the heat inputs from 2008 or 2009 rather than automatically using 2008 data. This would better capture both the impact of economic downturns and scheduled outage activities that affected utilization in both years. [EPA-HQ-OAR-2009-0491-2728.1, p.10]
- Some peaking units had no projected heat input from IPM, and therefore no projected NOx or SO2 emissions. According to the protocols set forth in the CATR, EPA would then have used actual data to determine allocations. Unfortunately, some of these peaking units did not have four quarters of actual data, which results in the zeroing of emissions over these years instead of the summation of the data within this time period. This resulted in the elimination of NOx allocations for Blue Lake Units 1 and 3; Inver Hills Units 2, 4 and 5; French Island Units 3 and 4; and Wheaton Units 5 and 6. EPA should use the sum of the available emissions data from the greater of 2008 or 2009 rather than zeroing out these emissions. [EPA-HQ-OAR-2009-0491-2728.1, pp.10-11]
- For facilities with a SCR installed, EPA adjusted the allocations from actual data by applying the most recent NOx ozone season rate to 2008 heat input instead of using actual annual emissions data. This effectively decreased the number of allocations for King (1330 vs. 1478). EPA did this to account for facilities which do not run their SCR year-round or at full capacity. Since we do not bypass the SCR at any facility, or run SCRs at less than their capability, EPA should use unadjusted data for King. [EPA-HQ-OAR-2009-0491-2728.1, p.11]
- In general, IPM v3.02 tends to either not dispatch combustion turbine ('CT') / combined cycle ('CC') units (e.g., Blue Lake Units 1 through 4 and Inver Hills Units 1 through 6) or greatly underpredict generation as compared to internal forecast models (e.g., Black Dog Unit 5; High Bridge Units 7 and 8), thus depriving these facilities of some or all NOx allocations. EPA should examine the IPM model to determine whether this is a consistent outcome on a national basis or a regional one impacting only Minnesota. If EPA finds this to be a national issue, EPA should correct the IPM model to more accurately reflect actual operation of these units. [EPA-HQ-OAR-2009-0491-2728.1, p.11]
Response:
In response to the concerns expressed above,
EPA first modified its allocation methodology from one based on projected data, to one based on historic data.  This addresses many of the concerns that commenter expresses above regarding allocations to specific units.  As a result of the allocation methodology change, allocations to specific units have changed as well.  See section VII.D of the preamble for more discussion on this, and the Technical Support Document on allocations and the allocation tables themselves for a listing of the revised allocations under the FIP.  Furthermore, EPA has made significant changes to its IPM modeling based on concerns such as those expressed above.  The IPM modeling has been updated, and these changes are reflected in the final EPA IPM v.4.10.  The IPM documentation and supplemental documentation describes changes and assumptions in the final model version.  See Appendix to RTC for "Transport Rule IPM Assumptions Response to Comments".  Generally speaking, EPA did not make direct modifications to IPM projections in response to unit level comments.  It did however make modifications to modeling inputs that reflect the current status of generating resources.  These modifications often do impact the unit level projections for the units.  However, EPA notes that IPM is a dynamic linear programming model that generates optimal decisions under the assumptions of perfect foresight and least cost.  EPA acknowledges that there may be instances where unit level projections under such a model are different than the sources actual future operating patterns (e.g., IPM projects a unit not to operate, but the unit does operate for potential non-economic or other factors that the model does not capture).  This, in part, was one of the drivers for switching to a historic data based approach for allocations.  Doing so, minimizes any direct monetary impact that a discrepancy between projections and future unit operation would have on a source.

XVIII.C.2. September 1, 2010 NODA: EGU Projections Using IPM/NEEDS V.4.10

Organization: America's Natural Gas Alliance
Comment:
America's Natural Gas Alliance
In that regard, ANGA welcomes the Agency's decision to use the updated IPM power sector modeling platform (VA.10), including integrating natural gas modeling directly into the IPM. As discussed in the Agency documentation of IPM Base Case VA10, the new natural gas module contains several improvements over prior base cases which were developed outside of the IPM.2 For the first time, natural gas supply dynamics will be directly modeled into the base case, ensuring that the most accurate, up-to-date information is used in the development of this critical program. ANGA does suggest that it would be appropriate to use the model results from the updated IPM VA.10 runs to modify the State-level caps, both from a good science and good clean air policy perspective. Finally, ANGA encourages EPA to revise the allowance allocation methodology proposed in the CATR, both with respect to the fundamental methodology and the issue of subsequent updating of the inventory.  [EPA-HQ-OAR-2009-0491-3748.1_NODA, p.2]
Given the importance of this rulemaking and the opportunity to make the CATR as effective as it can be in reducing NOx and SO2 emissions and the impact of interstate transport of those emissions, ANGA believes that modeling used to support the final CATR must use the most current, accurate and up-to-date information and assumptions. In that regard, we concur with the Agency that 'the assumptions regarding natural gas resources in the primary IPM v4.10 base case are the appropriate ones to use.' EPA also suggests in the NODA and in information available in the docket, that it is considering another option regarding gas price assumptions. EPA specifically requests comment on: [P]erforming an additional set of reference and policy runs with a gas scenario that starts with the resources assumptions in the EPA primary case but limits production of those resources due to uncertainties affecting their development. These uncertainties include still to be resolved environmental and land use issues affecting shale development. [EPA-HQ-OAR-2009-0491-3748.1_NODA, p.3]
ANGA submits that this option should not be developed and run. As stated above, we believe that the EPA Base Case VA.10, which was run using a resource base that reflects economically recoverable resources using current technology under existing regulatory frameworks, utilizes the correct set of assumptions regarding the natural gas market. The Agency has not indicated with any degree of specificity the manner in which it would seek to, or the assumptions it would use to, change the assumptions to limit production of natural gas. In the absence of any such information in either the proposed CATR or in the NODA, we cannot comment on what production limitation assumptions the Agency might consider using in the model the Agency ultimately decides to deploy and, as a result, we do not believe that the Agency can consider this third option in the CATR. [EPA-HQ-OAR-2009-0491-3748.1_NODA, p.3]
The Agency also indicates that 'during the comment period, EPA will accept comments on both the specific data that EPA is placing in the docket as well as any potential impacts of that data on the Proposed Transport Rule.  In terms of the potential impact of using the new IPM VA.10 runs to support the CATR, ANGA believes that the Agency should in fact modify the State-level caps that were modeled using the old IPM in the proposed CATR to reflect changes that the new modeling may suggest and, as we discuss in more detail below, adjust the allocation methodology. [EPA-HQ-OAR-2009-0491-3748.1_NODA, p.3]
Specifically, ANGA suggests that the significantly higher gas demand and significantly lower gas prices in the Agency's preferred resource assumptions result in significantly greater incentives for companies with coal-fired generation that is uncontrolled (or under-controlled) and/or close to the end of its useful life to switch fuels to natural gas. Models run using this higher demand and lower gas prices would therefore reflect more rapid and extensive fuel switching, and the resulting changes that the modeling would suggest could in turn result in lower State-level caps going forward. These models would then reflect more accurately overall emission reductions and improved air quality that result from earlier and more frequent fuel switching. [EPA-HQ-OAR-2009-0491-3748.1_NODA, pp.3-4]
In addition, depending on the methodology utilized to allocate emissions, use of new State-level caps based on the updated IPM V.l0 modeling may serve to reduce the level of allocations to coal plants in individual states, thus helping to promote fuel switching from coal to gas in those states. [EPA-HQ-OAR-2009-0491-3748.1_NODA, p.4]
Unit Level Allocation Method and Periodic Updating [EPA-HQ-OAR-2009-0491-3748.1_NODA, p.4]
The issues raised in the NODA also underscore ANGA's concerns with the Agency's proposed approach to allocating emission allowances to individual units based on modeled or historic actual emissions. Allocating allowances to high emitting units, based on their historical emissions of the pollutants that the Agency is seeking to reduce, essentially subsidizes the continued operation of older, uncontrolled (or undercontrolled) high emitting units. On the other hand, allocation methodologies utilizing historic output (megawatt-hour) or input (heat such as million British thermal units) provide incentives for utilizing cleaner, more efficient sources, such as natural gas-fired units. Historic energy output or heat input methods also promote the early adoption of control technologies, which would be discouraged under an emissions-based allocation. [EPA-HQ-OAR-2009-0491-3748.1_NODA, p.4]
Accordingly, ANGA suggests that that the Agency consider the use of either an output-based unit level allocation methodology (similar to that deployed in Massachusetts' NOx cap and trade program) or an input-based methodology (similar to the methodology employed by the Agency in the NOx SIP Call and in the Clean Air Interstate Rule, but without the fuel-adjustment factors that were explicitly rejected by the U.S. Court of Appeals for the District of Columbia Circuit). These unit level allocation methodologies will ensure that the CATR sends the right economic signals to achieve the purpose of the rule - cleaner air. [EPA-HQ-OAR-2009-0491-3748.1_NODA, p.4]
Energy output and heat input methodologies also reduce the risk of legal challenges and their attendant delay. Energy output and heat input provide a clear, simple way to allocate emissions, while modeled future emissions are complex and likely to generate a number of errors that could be considered arbitrary and capricious. [EPA-HQ-OAR-2009-0491-3748.1_NODA, p.4]
Finally, assuming the Agency were to allocate allowances on either an output or input basis, ANGA also suggests that the Agency reverse its decision to allocate allowances to existing units once, and to periodically update allowance allocations going forward. to As increased fuel switching continues to result in greater use of natural gas in the power generating sector, it is good environmental policy to periodically update the allocation of allowances, as doing so would both avoid imposing a defacto penalty on companies that switch to cleaner burning fuels and provide greater incentive for fuel switching at existing coal-fired units. [EPA-HQ-OAR-2009-0491-3748.1_NODA, pp.4-5]
ANGA recognizes that there needs to be some degree of predictability in allowance allocation for purposes of ensuring a robust and stable allowance trading market; however, we suggest that the Agency consider updating the allocation system every three years to allow the allowance market to take into consideration modernization of the power generating sector. [EPA-HQ-OAR-2009-0491-3748.1_NODA, p.5]
Response:
EPA finalized an allocation methodology based on heat input, as suggested by the commenter.  See section VII.D of the preamble for a description of the finalized allocation methodology.  Additionally, see EPA IPMv.4.10 documentation for a discussion on the gas assumption used in the final rule analysis.
Organization: City Utilities of Springfield
Comment:
City Utilities of Springfield
Specific issues: [EPA-HQ-OAR-2009-0491-3733.1_NODA, p.1]
The data table contains known errors regarding our Southwest Power Station. [EPA-HQ-OAR-2009-0491-3733.1_NODA, p.1]
Issue: The NEEDS 4.10 database indicates that the Southwest Power Station has a wet FGD in place. As we have indicated in our EIA Form 860 filings and our revised monitoring plan under the Acid Rain Program, the FGD at this facility had to be decommissioned and removed due to severe scaling, corrosion, and structural integrity concerns. Southwest Power Station now complies with all federal and state SO2 requirements by burning compliance coal from the Powder River Basin. This correction in the NEEDS database would materially impact the cost efficiency of additional SO2 control at the Southwest Station and the resulting state budget for Missouri. [EPA-HQ-OAR-2009-0491-3733.1_NODA, pp.1-2]
Recommendation: The NEEDS database must be corrected to reflect actual baseline conditions at the Southwest Power Station. The economics of additional (Phase 2) SO2 control at Southwest requires recalculation and Appendix A adjusted accordingly. [EPA-HQ-OAR-2009-0491-3733.1_NODA, p.2]
The data table contains errors regarding control equipment on combustion turbines at our McCartney Generating Station and James River and Southwest Power Station. [EPA-HQ-OAR-2009-0491-3733.1_NODA, p.2]
Issue: NEEDS 4.10 indicates that our McCartney Generating Station Units 1 and 2 (ORIS 7903; MGS1 and MGS2) are equipped with water injection and SCR for NOx control. In actuality the turbines only have water injection. There are no SCR controls on the McCartney units. Further, NEEDS 4.10 does not indicate usage of water injection to control NOx emissions for our James River Power Station Gas Turbine 1 (ORIS 2161; **GT1) and Southwest Power Station Combustion Turbines (ORIS 6195; CT1 and CT2). [EPA-HQ-OAR-2009-0491-3733.1_NODA, p.2]
Recommendation: The NEEDS database must be corrected to remove the SCR designation and include water injection controls for the listed combustion turbines. [EPA-HQ-OAR-2009-0491-3733.1_NODA, p.2]
The data table appears to underestimate the future operation of combustion turbines at our Southwest, James River, and McCartney Stations. [EPA-HQ-OAR-2009-0491-3733.1_NODA, p.2]
Issue: The draft version of Table A included with the pre-publication version of the Transport Rule allocated zero allowances to combustion turbines located at our James River, Southwest, and McCartney generating stations. Presumably, this was a result of the IPM model result indicating that the combustion turbines will cease to operate following promulgation of this rule. However, we are unable to trace this result from the information provided in the NODA. In actuality, combustion turbines will continue to be a valuable generating asset for City Utilities and other Missouri municipal utilities. Our internal PROSYM modeling indicates that we will continue to run these units for hundreds of hours per year well into the future. These units not only provide rapid response to peak demand in ways that our steam units are unable, but also represent spinning reserve capacity required by electric reliability regulators. These factors presumably were not considered in the cost-based IPM modeling analysis. [EPA-HQ-OAR-2009-0491-3733.1_NODA, p.2]
Recommendation: The Appendix A allocation table should be corrected to reflect expected operating scenarios for affected combustion turbines owned by City Utilities and other Missouri utilities. As a starting point, all turbines should be assumed to operate up to 1,500 hours per year. [EPA-HQ-OAR-2009-0491-3733.1_NODA, p.3]
The data table does not include our Southwest Unit 2, scheduled to come on line on or about January 1, 2011. [EPA-HQ-OAR-2009-0491-3733.1_NODA, p.3]
Issue: The NEEDS 4.10 database does not contain an entry or a placeholder for our Southwest Unit 2, a 300 MW coal-fired unit permitted in late 2004. This unit should have been included as a "Planned-committed" resource in the IPM 4.10 model run. As we indicated in comments to the rule proper, Southwest 2 appears to fall in with a handful of new units that will be placed in regulatory Neverland with respect to the new rule. Our earlier comments requested clarification in the Transport Rule definitions that this unit would be eligible for allocation from the New Unit pool. However, it might be more appropriate to list them in the database, assign a permanent allocation, and avoid confusion and administrative costs in the future. If this approach is taken, City Utilities would be prepared to provide additional data concerning the Southwest 2 project. [EPA-HQ-OAR-2009-0491-3733.1_NODA, p.3]
Recommendation: Confirm that Southwest Unit 2 was included in the IPM model run and allocate Appendix A allowances accordingly. [EPA-HQ-OAR-2009-0491-3733.1_NODA, p.3]
Response:
EPA appreciates the commenters correction data and its response is twofold:
1) EPA adjusted its IPMv.4.10 NEEDS database to reflect the comments.  For example, the Southwest Power Station no longer is listed as having an FGD in place, as suggested by commenter.  Also, the McCartney Generating Station is no longer listed as having SCR controls.
2) These unit level corrections suggested by commenter were linked to concerns expressed about unit level allocations.  EPA has finalized an allocation approach that is based on historic, not projected data, which also addresses the concern that a unit level discrepancy between the model and a unit would have a large impact on the unit's allocation.
Organization: Consumers Energy
Louisiana Chemical Association (LCA)
PPG Industries, Inc.
National Grid
Electric Energy, Inc.
Edison Electric Institute (EEI)
Allegheny Energy
Consolidated Edison Company of New York, Inc, (CECONY)
Massachusetts Department of Environmental Protection
American Electric Power
Occidental Chemical Corporation (OCC)
Capital Power Corporation
DTE Energy Services (DTEES)
PSEG Services Corporation
Dominion
PPL Corporation
Buckeye Power, Inc.
Cogen Technologies Linden Venture, LP
First Energy
Southern IL Power Cooperative
West Virginia Department of Environmental Protection
Northern Star Generation LLC
Marquette Board of Light and Power
Lafayette Utilities System
International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers and Helpers (AFL-CIO Boilermakers Union)
San Miguel Electric Cooperative, Inc.
Coal Utilization Research Council
Louisiana Energy and Power Authority (LEPA)
Exxon Mobil Corporation
Gulf Coast Lignite Coalition
National Mining Association (NMA)
Cleco Corporation
DTE Energy
Exeter Energy Limited Partnership
Big Rivers Electric Corporation
South Carolina Department of Health and Environmental Control
Duke Energy
Seminole Electric Cooperative Inc.
Florida Municipal Power Agency (FMPA)
Council of Industrial Boiler Owners (CIBO)
Clean Air Task Force
State of Louisiana, Department of Environmental Quality
Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
Ameren Services Company
Florida Electric Power Coordinating Group, Inc. (FCG)
Oglethorpe Power
Institute of Clean Air Companies (ICAC)
Dairyland Power Cooperative
National Rural Electric Cooperative Association (NRECA)
Louisville Gas and Electric Company (LG&E) and Kentucky Utilities Company (KU)
Old Dominion Electric Cooperative
Peabody Energy Company
Mirant Corporation
Nelson Industrial Steam Company (NISCO)
Ohio Utility Group (OUG)
AES Corporation (AES)
Comment:
AES Corporation (AES)
Additionally and most importantly, this comment period does not allow time for complete review of all NODA data, NEEDS data and additional errors are likely to commiserate with the many other company inaccuracy notices. [EPA-HQ-OAR-2009-0491-3793.1_NODA,p.8]
Allegheny Energy
The NEEDS V4.10 (NEEDS) database (released September 1, 2010 as an update to NEEDS V3.02) used by EPA contains errors relative to AE power stations. These errors when used as input data for the IPM can propagate errors in modeling results which in turn could skew EPA's regulatory analysis. Specifically, the NEEDS errors identified by AE are:
1) Cold side electrostatic precipitators with flue gas conditioning and wet scrubbers are listed as a control device for particulate matter (PM) on the three units at AE's Harrison power station located in West Virginia. Harrison power station does not have PM scrubbers.
2) Selective non-catalytic reduction controls are listed for the two units at AE's Armstrong power station in Pennsylvania. These units had Mobotech Rotamix systems installed in 2003, but they have since been removed because of operating problems.
3) AE's Mitchell power station in Pennsylvania has a FGD scrubber S02 removal efficiency listed as 99.9%. Actual scrubber removal efficiency at Mitchell power station averages 97%. [EPA-HQ-OAR-2009-0491-2605.1, p.4]
4) The FGD scrubber S02 removal efficiency for AE's Pleasants power station in West Virginia is listed at 97%. Actual scrubber removal efficiency at Pleasants power station for 2008 - 2009 averages 95%. [EPA-HQ-OAR-2009-0491-2605.1, p.5]
Ameren Services Company
The NODA continues to assume that CAIR is not in place [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.3]
In 2008 the U.S. Court of Appeals for the D.C. Circuit found the Clean Air Interstate Rule (CAIR) to be 'fundamentally flawed,' initially vacating and remanding it to EPA See North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008). However some months later in December, the D.C. Circuit Court of Appeals remanded the CAIR without vacatur, North Carolina v. EPA, 550 F.3d 1176 (D.C. Cir. 2008), instead, leaving CAIR in place until EPA cured the flaws in CAIR. Therefore CAIR is a viable rule and utilities must currently comply with the stringent nitrogen oxide (NOx) and sulfur dioxide (SO2) limits prescribed by the rule. [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.3]
EPA has assumed in this NODA as in the original analysis (IPM 3.02) that the CAIR program is not in place and that affected sources are not complying with the rules. This assumption is in error. By not including compliance with CAIR in its assumptions, the EPA analyses have over stated the impact of these sources prior to the imposition of the proposed transport rule considered here. This assumption completely invalidates EPA's analysis and the results produced. EPA should redo the analysis assuming that CAIR is fully in place and the affected sources are complying with the regulations. EPA should view CAIR as the valid control program that it is and allow sources to smoothly transition to the future rules to be promulgated, just as was done between the NOx SIP Call trading program and the CAIR. [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.3]
EPA bas not supplied all the information necessary to properly review the NODA and its affect on the Transport Rule [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.3]
EPA in the NODA has admitted that the IPM 4.10 information will be used for but not limited to: [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.3]
'Changing emission projections that were used to determine which downwind areas have air quality concerns (i. e., non-attainment or maintenance) absent this rulemaking and to determine which States contribute to those problems. [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.3]
Changing cost and emission projections used in the multi-factor test to determine the amount of emissions that represent significant contribution.' [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.4]
These changes are far ranging and could affect many aspects of the final rule. EPA needs to supply additional information on how this IPM 4.10 modeling will affect the final Transport Rule. For example consider the following [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.4]
The difference in using AEO 2008 and AEO 2010 projections for utilization is dramatic. In Ameren's case projected heat input for 2014 for Ameren Illinois units in the IPM 4.10 case is 32% less than that projected in the IPM 3.02. This most likely will have an effect on the allocation of NOx and SO2 allowances and this information has not been given. It is critical that EPA provide information how the incorporation of this new generation forecast, along with changes in other assumptions will impact 2012 and 2014 unit allocations. [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.4]
EPA has not provided information on how the IPM 4.10 modeling will affect the air quality projections used to identify non-attainment and maintenance areas and the significant impacts various states have on these areas. EPA needs to redo the air quality modeling analysis using emissions and monitored air quality data representative of the conditions represented in the AEO 2010 modeling. Specifically EPA needs to use more recent base case emissions and meteorology and monitored air quality data. Only after EPA conducted the additional analyses needed and has given the proper public notice and opportunity for public comment can EPA finalize the Transport Rule. [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.4]
Too many inconsistencies in the projections produced by IPM 4.10 similar to those found in IPM 3.02. [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.4]
As mentioned above in section I. the projections produced by IPM 4.10 are not in line with Ameren's projections for these units. Consider the following, [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.4]
Ameren has no plans to retire or made any commitment to install SO2 scrubbers on the Joppa units. The SO2 emission rates shown in the 2014 AEO gas case of 0.295 lb/mmBtu are not achievable without some additional controls and none are shown for this scenario in the IPM 4.10 modeling. Ameren has not committed to install SO2 controls for the Joppa units at this time. [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.4]
Ameren's Duck Creek plant currently has operating selective catalytic reduction (SCR) and FGD systems. However the IPM 4.10 modeling exhibits a change in SO2 emissions rates from the IPM 3.02 rates. These rates for IPM 3.02 and IPM 4.10 are 0.133 lb/mmBtu and 0.295 lb/mmBtu respectively. This change in rates seems unexplainable. Is IPM changing fuels, the control efficiency of the FGD or something else? [EPA-HQ-OAR-2009-0491-3739.1_NODA, pp.4-5]
Ameren Illinois' Newton plant has submitted a permit application to construct a wet flue gas desulfurization (FGD) on each of the two units at Newton to meet the Illinois mercury rule and CAIR requirements for SO2. The IPM 4.10 modeling apparently assigns significantly different SO2 lb/mmBtu rates to each of these units. These FGDs have the same design criteria and are on boilers of similar design. This difference makes no sense. For example, since there is no flue gas bypass in the design of these FGD systems the units cannot operate without the scrubbers in service or risk destruction of the FGD. [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.5]
In both of the NODA TR_SB_Limited Trading and TR_SB_Limited Trading ABO Gas IPM 4.10 model simulations Newton Unit 2 is assumed to install an SCR. There are currently no plans to install an SCR on Newton Unit 2 or as described in Ameren's comments on the Transport Rule sufficient time to design, permit and construct one. [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.5]
The Union Electric d/b/a Ameren Missouri Labadie and Rush Island plants are shown in the IPM 4.10 modeling to have SO2 rates around 0.55 lb/mmBtu and no SO2 controls are assumed. These plants currently are averaging in the 0.7Ib/mmBtu range. As mentioned in Ameren's previous comments on the Transport Rule and the IPM 3.02 modeling this would require a change in fuel which may not be possible based the on the projected limited availability of this lower sulfur fuel and other balance of plant issues. [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.5]
American Electric Power
In reviewing the various sensitivity cases run using both the older and new version of IPM, AEP is often confused by the resulting model outputs as it pertains to the operation of our generating fleet. For example, in the updated 2012 base case (new IPM v.4.10 Runs) SCRs were listed as installed at Pirkey, Welsh 2-3 and Rockport 1-2 units. While AEP does face some NOx constraints at Rockport due to the NSR Consent Degree with EPA, it is not projecting additional SCR installations in the near-term. Additionally, Pirkey and Welsh are not subject to any existing NOx emission constraints and it is unclear why the model would be selecting SCRs as economic control technologies under a business as usual scenario. Furthermore, these SCRs do not appear to be achieving 90% removal in the policy runs, so it is unclear why they are being added. Additionally, the IPM v.4.1 0 results show SCR installations at Kammer 2-3 and Clinch River 1-3 in the 2014 policy case which are also puzzling. AEP requests that EPA look into the full rationale behind these illogical modeling results and correct any underlying data or modeling errors. These modeling and/or input errors ultimately manifest themselves in the budget development process. As a result, within the proposed Rule, projected base case SCR installations resulted in the NOx budgets for several AEP units being arbitrarily reduced. [EPA-HQ-OAR-2009-0491-2665.1, p.13] [EPA-HQ-OAR-2009-0491-3719.1_NODA, pp.7-8]
AEP has output driven comments from both versions of IPM, as we remain unsure which underlying errors might have been corrected in the modeling update process. Many of our concerns are directly related to how underlying unit limitations are factored into the modeling, specifically as ultimate allocation and/or potential emission rate limits are proposed to be tied directly to modeled emissions and performance. Furthermore, AEP requests that EPA produce modeling outputs disaggregated and reported at the unit level. It is highly unclear from the parsed data files provided exactly what coal types are being utilized and what constraints individual units are tied to. This level of data is needed to ensure that a proper third-party review can be conducted of the runs used to support the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2665.1, pp.20-21] [[These comments can also be found in XVIII.C.1.]]
At a minimum, EPA should correct the data and assumption issues identified, remodel the air quality impacts assuming a continuation of CAIR-like standards, revise the compliance dates based on reasonable timelines for environmental controls and rerun the economics and subsequent allocations that would result from these changes. A supplemental Transport Rule should then be proposed for comment. [EPA-HQ-OAR-2009-0491-2665.1, p.21] [[These comments can also be found in XVIII.C.1.]]
NEEDS Emission Rates
Several of AEP's units are projected to have NOx rates in NEEDS v.4.l0 scenarios which are inconsistent with either historical or projected operations. The following units should be corrected as listed in the recommended rates below. The recommended control rates are based on AEP's experience operating these units. [EPA-HQ-OAR-2009-0491-2665.1, p.21] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.3][[See Docket Number EPA-HQ-OAR-2009-0491-3719.1_NODA,p.3 for table of units.]]
NEEDS Existing Controls
There are several instances where wet scrubbers are incorrectly listed at AEP owned/operated units within the NEEDS v.4.l 0 database. Kammer Units I & 2 are listed as having had a wet scrubber installed in 2007 though no such controls were added or are planned to be added. Additionally there are incorrect references to wet scrubber installations at John E. Amos Unit 1 (2008), Cardinal Unit 3 (2010) and Kyger Creek Units 1-5 (2010). These are projected to have wet scrubber systems come online within the next few years, but not by the dates assumed in the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2665.1, p.21] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.3]
NEEDS FGD Removal Assumptions
EPA's IPM v.4.10 modeling assumed that all new wet FGD systems average 98% S02 removal with a floor of 0.06 lb/mmBtu. Additionally, its appears all units with FGD controls installed in 2005 or later were defaulted to the 98% removal criteria based on the lack of more recent data availability within the EIA-767 database. While many new wet FGD systems might be able to achieve 98% removal or higher on an intermittent basis, 98% S02 removal is very difficult, if not impossible, to achieve on most units on a year-round basis due to operational upsets and operating variability. AEP recommends revising the assumptions to show 96.5% SO2 removal for all new(er) FGD systems. [EPA-HQ-OAR-2009-0491-2665.1, pp.21-22] [EPA-HQ-OAR-2009-0491-3719.1_NODA, pp.3-4]
For other units operating with older FGD systems, targeted SO2 removal performance based on current operation or design basis is different than the scrubber efficiency listed within the NEEDS database. Scrubber efficiency at Gavin Units 1 &2 should be revised to 94.5% and Dolet Hills Unit 1 revised to 70%. Additionally, the most recent information from Duke Energy on the co-owned Zimmer unit indicates a scrubber efficiency of 93% and should be revised. [EPA-HQ-OAR-2009-0491-2665.1, p.22] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.4]
NEEDS Missing Units
Two operational AEP units are currently missing from the NEEDS database, the Philip Sporn Unit 5 in Mason County, WV and the Conesville Unit 3 in Coshocton County, OH. EPA should refer to EIA for unit characteristics and incorporate these units into the NEEDS database for purposes of further modeling and allocations. [EPA-HQ-OAR-2009-0491-2665.1, p.22] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.4]
IPM Environmental Retrofit Capital Costs
AEP is appreciative of the efforts EPA undertook to update the IPM study with new numbers to better reflect the current costs of procuring and constructing pollution controls. While these updated costs are more accurate, they still underestimate cost of controls for many units due to other factors not currently considered within the cost structure. [EPA-HQ-OAR-2009-0491-2665.1, p.22] [EPA-HQ-OAR-2009-0491-3719.1_NODA,p.5]
The ability to retrofit control technologies remains a major issue at some units due to plant layout and design. Most of the newer and easier to retrofit units have already been retrofitted. As such, the next round of units required to retrofit are likely to be significantly more difficult and costly than previous experience would suggest. Between similarly sized units, costs could vary by two times or more based on unit-specific constraints. AEP recommends EPA include unit-specific multiplier as an IPM input parameter to adjust retrofit costs versus perceived difficulty. [EPA-HQ-OAR-2009-0491-2665.1, p.22] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.5]
It is also apparent that landfill costs were included only as a variable cost within the cost structure for new FGD installations. However, construction of new landfill space to support FGD byproduct disposal are almost always undertaken on-site and require significant capital to be deployed. As such, the initial landfill development cost should be factored into the capital cost of the FGD installation as well as the ongoing variable cost of operation. Landfill development costs are approximately $5 to $40 per kW and should be factored into the model as a capital cost. These costs could increase substantially as a result of the coal combustion residuals rule EPA proposed on June 21, 2010. [EPA-HQ-OAR-2009-0491-2665.1, p.22] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.5]
Because of the low projected capital costs of environmental retrofits, the model is biased in the direction of retrofit versus retire for emissions reductions on uncontrolled units. However, AEP feels that the actual economics, in conjunction with capital requirements to address other forthcoming environmental liabilities, will favor retirement on most uncontrolled units. This will have a definite impact on cost and reliability outcomes. [EPA-HQ-OAR-2009-0491-2665.1, p.23] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.5]
IPM Financial Assumptions
AEP has concerns with how capital recovery factors are calculated for use within IPM as they pertain to retrofit decisions on older coal units. Specifically, the model assumes that these retrofit investments would have a book life of 30 years and a debt and depreciation life of 20 years. However, as the majority of uncontrolled units are older less efficient units, an additional 20-30 years of life expectancy is not guaranteed or even likely. Furthermore, uncertainty as it pertains to additional future EPA regulations means that these investment decisions must clear an even higher hurdle of prudency, which would likely result in the investment needing to be recovered over a 10-15 year time horizon. [EPA-HQ-OAR-2009-0491-2665.1, p.23] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.5]
A similar risk adjustment is already present in the IPM model as investments in new coal are subject to a 'Capital Cost Adder for Climate Change Uncertainty' which results in 3% added to the cost of equity and debt. Old coal is not likely to be treated any different than new coal under climate and other EPA regulations and thus any investment in coal technology should be subject to either an adder or an accelerated timeframe for capital recovery. [EPA-HQ-OAR-2009-0491-2665.1, p.23] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.6]
IPM Coal Suitability
AEP has significant concerns about how various coal types are selected and utilized within the IPM model, ultimately leading to an inaccurate portrayal of the economics and viability of emission reductions through coal switching. In using the parsed IPM output files to back into unit emission rates, it was determined that several of AEP's units are burning coals which they cannot physically use without significant operational limitations or the addition of major capital equipment not currently considered in IPM. [EPA-HQ-OAR-2009-0491-2665.1, pp.23-24] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.6]
One set of concerns relates to the apparent lack of a minimum coal sulfur content model parameter. Many coal-fired boilers are limited to a minimum specification for coal sulfur content due to their boiler configuration, and their electrostatic precipitator (ESP) and/or air permit limitations. For example, wet-bottom boilers capture the majority of their ash in a molten form within the boiler and require coals with low ash fusion temperatures. For eastern bituminous coal, this property is generally correlated with high sulfur fuels. Other limitations due to ESP performance are also found on both wet and dry-bottom units that were initially designed to utilize higher sulfur coals. Lower sulfur coals do not have the same electrical resistivity properties as higher sulfur coals and thus the ash is harder to collect. Therefore use of low sulfur coals at some units could cause opacity to exceed permitted limits. Given these unit specific operational limitations, the NEEDS database and IPM model structure should be updated to reflect these actual limitations. AEP offers two examples of where the lack of fuel constraints resulted in a modeled operating situation that is not currently feasible. [EPA-HQ-OAR-2009-0491-2665.1, p.24] [EPA-HQ-OAR-2009-0491-3719.1_NODA,p.6]
1. In the recently released IPM runs in conjunction with the NODA, emission rates for the Muskingum River units 1-4 were as low as 1.42 lb-SO2/MmBtu based on the modeled emissions and heat input. In previous runs used to support the Transport Rule the emission rates were as low as 1.01 lb- SO2/MmBtu. As these are uncontrolled units, the emission rate is largely indicative of the sulfur content of the underlying fuel. However, low sulfur eastern fuel(s) are not compatible with these wet-bottom boilers due to ash fusion and ESP limitations. These units are currently limited to coal(s) with an S02 content of 4.0 lb per mmBtu or above. [EPA-HQ-OAR-2009-0491-2665.1, p.24] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.6]
2. A similar concern was observed when viewing the model outputs for Kammer Units 1-3. While these units can bum coal with slightly lower S02 content than Muskingum River Units 1-4 due to an ability to blend limited portions of PRB, they similarly cannot burn very low sulfur coal. In new NODA IPM runs, one Kammer Unit was exhibiting an emission rate of 1.34 lb- SO2/MmBtu. In earlier IPM runs the emission rate was as low as 0.95 lb- SO2/MmBtu. With current blend capability, AEP is only able to achieve emission rates slightly below 2.0 lb S02/MmBtu. [EPA-HQ-OAR-2009-0491-2665.1, pp.24] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.6]
An additional concern related to fuel suitability is based on how the IPM model treats units that can burn subbituminous coal. Many boilers are flagged within the model as having the ability to bum subbituminous coal based on past utilization. While keeping this designation within the model structure is important, not all units that can burn subbituminous coal have demonstrated the ability to burn exclusively subbituminous coal. Many units utilize subbituminous coal for a portion of their coal, but not all of their coal, due to boiler limitations. [EPA-HQ-OAR-2009-0491-2665.1, p.24] [EPA-HQ-OAR-2009-0491-3719.1_NODA, pp.6-7]
For example, AEP-operated Rockport Units 1&2 and Tanners Creek Unit 4 all currently bum a percentage of subbituminous coal due to combination of economics and emission limitations. However, as the boilers were originally designed to burn bituminous coal, 100% subbituminous coal cannot be used without significant changes to unit output and operation. (Generally speaking, we have already pushed the subbituminous portion as high as these boilers will allow). As subbituminous coal has lower energy and higher moisture content than bituminous coal, a larger boiler design is typically needed to produce the same thermal and electrical output. Thus, burning 100% sub bituminous coal in a boiler designed for bituminous coal will result in a unit having to be derated, or limited in electrical output. Also, units switching to 100% subbituminous coal will have to undergo more frequent outages related to slag formation and boiler maintenance given the physical properties of subbituminous coal. IPM runs indicating uncontrolled emission rates below 0.60 for Rockport Units 1 & 2 and Tanners Creek Unit 4 suggest that these units are exclusively utilizing very-low sulfur subbituminous coals, as this coal type is the only one capable of meeting this low emission rate. Therefore, output constraints regarding the use of 100% subbituminous fuel and/or maximum blend percentages for the use of subbituminous in boilers currently utilizing blends need to be incorporated in EPA's modeling for the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2665.1, pp.24-25] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.7]
Coal Procurement
In addition to coal limitations, AEP is also concerned about coal flexibility as it pertains to short term shifts in supply. The IPM model was able to optimize coal selection based on relative economics of different coals. However, the modeling does not take into account long-term coal purchase contract obligations and the ability to quickly ramp production up and down. The IPM model allowed full switching to low sulfur coal in 2012, but in the real world, this could not occur. Given that this rule is not going to be finalized until spring 2011, it will be too late to switch coal contracts. Generally, almost all of AEP's coal (like other electric generators) is contracted more than one year in advance. Thus, the IPM model should be recalibrated and constrained to make sure that transitions in coal type occur over a reasonable period. [EPA-HQ-OAR-2009-0491-2665.1, p.25]