As shown in both figures there are sizeable amounts of modeled FGD and SCR capacity that are either retired or for some other reason do not receive a retrofit in the NODA modeling. Some of the retired capacity is on units that have been identified as potential retirements stemming from either consent decrees or state programs. However, there is still slightly over 10 GW of FGD capacity from the TR modeling that is projected not to receive FGD systems. Even after accounting for a projected reduction in future electrical generation in moving from ABO 2008 to ABO 2010, which will affect emissions, EPA still needs to better explain the underlying factors leading to this 10 GW reduction in projected FGD capacity. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.9]
Allowance Prices Seem Unrealistic [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.9]
In the NODA TR_SB_Limited Trading System Summary Report, EPA presents SO2 allowance prices under the TR for both Group 1and 2 states. For 2015 EPA estimates Group 1 SO2 allowance prices at $313 and Group 2 allowance prices at $184. These values seem very unrealistically low given the marginal cost of control for FGD systems based upon EPA's revised FGD control assumptions, and a focus on intra-state trading due to the limitations on regional trading. In an analysis of an SO2 allowance market for a Group 1 state under the TR and allowing for only intra-state trading, the projected SO2 allowance prices were around $1,900 in  2015. Consequently, it seems EPA has significantly underestimated the prices of SO2 allowances under TR. [EPA-HQ-OAR-2009-0491-3746.1_NODA, pp.9-10]
Also, there is a NOx allowance market under TR, both seasonal and annual; however, EPA provides no NOx allowance prices. Does this mean that under TR no entity will have to buy or sell allowances for compliance or did EPA just miss computing both seasonal and NOx allowance prices? EPA needs to explain why no NOx allowance values are present in the NODA TR_SB_Limited Trading System Summary Report. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.10]
NODA Coal Retirements and Data Base Issues [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.10]
In a quick review of the NODA Parsed File_TR SB Limited Trading, there seem to be some potential errors/issues with regard to coal units projected to be retired by EPA. The table below [see p.10 of this comment summary for Table 4 entitled, Example Concerns Related to EPA Unit Retirements] presents some examples of these modeling concerns. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.10]
Consequently, EPA not only needs to further explain how these additional retirements were determined, but thoroughly review the modeling results to insure they are plausible given the future plans of many coal-fired units. If a unit has been retired due to a consent decree and/or state agreement, this information should be contained either in the NEEDS 4.10 Data Base or the parsed file. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.11]
Given the very short time allowed by EPA to evaluate the entire NODA information package, it is difficult to thoroughly identify all the potential data base issues. However, here are examples of a few data base issues that could be quickly identified and they are: [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.11]
No existing FGDs on Kammer 1 & 2 (as noted above), Bay Shore 4 and Shawville 2, which are identified in the NEEDS Data Base 4.10 as having existing FGDs. Also in the new NEEDS Data Base, Potomac River I - 5 and Dunkirk 3 & 4 have been identified as having a DFGD system, when in reality they have a TRONA system. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.11]
Sunbury 1 - 4 in the NEEDS Data Base 4.10 are projected to have a WFGD installed in 20 I0, but these retrofits have been put on hold. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.11]
Cape Fear 5 in the NEEDS Data Base 4.10 is expected to have a WFGD installed by 2011, but the unit will be retired between 2013 and 2017. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.11]
John Sevier 1-2 in the NEEDS Data Base 4.10 is expected to have a WFGD installed by 2011, but these two units will be idled between 2014 and 2015. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.11]
Kyger Creek in the NEEDS Data Base 4.10 is expected to have a WFGD installed by 2012, but the FGD system is planned for 2013 at the earliest. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.11]
EPA Estimate of New Pulverized Coal Capacity and Wind Capacity Do Not Seem Plausible [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.11]
In the TR, EPA estimates by 2020 there would be 54.7 GW of new pulverized coal capacity; however, in the NODA there is 0 GW of new pulverized coal projected capacity for 2020. On the other hand EPA estimates 4.0 GW of wind capacity in 2020 under the TR, but in the NODA EPA estimates 22 GW of wind capacity in 2020. This is almost a complete inverse of the two energy sources and does not seem plausible. EPA needs to explain how one iteration of the model yields one result, while a second iteration yields a completely opposite result. Even AEO 2010 predicts a modest increase in new coal capacity by 2020 of 15.6 GW under a remanded Clean Air Interstate Rule (CAIR) regulatory regime. AEO 2010 uses the same 3 percentage-point capital charge adder for the lack of a CO2 policy, but their capital costs for a new pulverized coal unit are slightly below those assumed in IPM version 4.10. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.11]
NODA Base Case Emissions are Unrealistic [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.12]
As mentioned in our comments filed on October 1,2010 on the Proposed Transport Rule, EPA fails to consider the extensive amounts of controls installed after 2005, resulting in a large and erroneous overestimation of emissions, because EPA assumes that CAIR is not in effect. 2 This erroneous assumption continues in the NODA's Base Case SO2 and NOx emission projections, even though in 2009 electric generators in the CAIR region began complying with the rule's NOx requirements and this year (2010) began meeting the rule's SO2 requirements. Electric generators will continue to comply with CAIR until the first year of compliance with the replacement rule. The table below [See p.12 of this comment summary for Table 5 entitled, EPA and MOG National Emission Forecast Comparison - 2012 & 2015] illustrates the significant overestimation of emissions in EPA's NODA Base Case compared to MOG's Business As Usual (BAU) forecast, which includes compliance with CAIR. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.12]
Minnesota Power
Review time.  The magnitude of Proposed Transport Rule and NODA data offered by EPA for review is vast and time for review has been scant.  Minnesota Power has observed deviations between the initial Transport Rule and NODA/NEEDS data ascribed to Minnesota sources.  EPA has indicated that it intends to make final determinations about State significant contributions and prospective Group 1 and Group 2 State SO2 and NOx budgets using some data that has not yet been generated or made available for review and comment. Conceivably, Minnesota affected utility units could be determined to be out of the Transport Rule, subject to Group 2 State requirements or prospectively subject to Transport Rule 2, State requirements.  Consequently, Minnesota Power requests that EPA provide another opportunity for data review and comment after EPA makes its proposed final determinations.  It is important that EPA provide the regulated community the opportunity to understand the basis for data discrepancies and seek corrections before the Transport Rule is finalized.   [EPA-HQ-OAR-2009-0491-3742.1_NODA, p.3]
Clear basis for determining Transport Rule compliance obligations.  There are still apparent discrepancies in Minnesota source emissions data and model input assumptions used by EPA in their modeling and the Minnesota actual emissions and projected emissions at modeled output levels and permitted emission rates. For example, the EPA projected budget for Minnesota presented in the Transport Rule tallies to a different amount than is referenced by EPA in the NODA unit level allocations.  EPA has indicated that further adjustments in proposed Minnesota emissions budgets may occur through the use of updated data and modeling analysis.  EPA should clearly identify the basis for unit level emissions applied when they estimated state significant contributions to nonattainment and state emission budgets calculated relative to a 2005 base year, emission control retrofit estimates and assumptions about future unit generation output.  [EPA-HQ-OAR-2009-0491-3742.1_NODA, p.3]
Credit for controls installed from 2000 to Transport Rule enactment.  The Clean Air Act, Acid Rain Program established requirements for emission reductions in 1995 and 2000 for the same group of emission sources EPA is proposing for regulation under the Transport Rule.  EPA is citing 2005 as a base line for determining the percent emission reductions to be achieved by Transport Rule, proposed 2012 or 2014 compliance dates.  Yet, EPA in the Transport Rule Technical Support Documents and related inputs cited in the NODA for IPM modeling indicates that utility units that have provided for emission control retrofits since 2005 will have their emissions budgets adjusted to reflect post control emission rates, without consideration of the Transport Rule percent emission reduction targets.  Since Group 2 States are targeted for an approximate 50% reduction in emissions, a generating unit that provided for 90% emission reductions after 2005 (e.g. installed selective catalytic reduction technology for NOx reductions) may receive no credit for outperforming targeted reductions when receiving its budget allocation.  Generating units that did not provide for emission reductions do not experience this write down of their budget allocation.  Consequently, it is not clear if EPA is giving reasonable consideration or credit for early controls installation in the Transport Rule. [EPA-HQ-OAR-2009-0491-3742.1_NODA, pp.3-4]
Wind backup duty.  As the production of wind based generation increases in a region subject to renewables performance standards, there is an increasing need for backup resources like natural gas and coal based generation to provide reliability to the electric system when the wind is not blowing.  That sort of service can require that coal and natural gas units targeted for control under the proposed Transport Rule can fall short of budget allocations needed to preserve electric system reliability.  EPA's NODA does not appear to include information about how EPA addresses the need for dispatch of fossil fueled generation sources to support system reliability under wide scale deployment of renewables. [EPA-HQ-OAR-2009-0491-3742.1_NODA, p.5]
Smaller generating unit retrofit costs.  EPA NODA information cites how EPA is extending IPM model control retrofits for smaller units, under 100 Megawatt (MW) Capacity by assuming costs per kilowatt assigned to the 100 MW capacity units.  EPA itself acknowledges that the size of the unit being retrofit with controls makes a difference in control costs, with larger units posted with a lower cost per kilowatt capacity for control retrofits than smaller units.  EPRI Technical Assessment Guide analysis affirms that units of size under 100 megawatts continue to incur higher costs for control retrofits per unit of capacity than for larger units.  EPA should provide substantiation that controls like selective catalytic reduction, scrubbers and fabric filters can be installed on units in the 25 to 100 MW size range at pricing for a 100 MW unit. [EPA-HQ-OAR-2009-0491-3742.1_NODA, p.5]
Well controlled units under 100 Megawatt Capacity.  Minnesota Power operates nine units in the size group of 25 to 100 MW and has demonstrated that emissions of SO2, NOx, mercury and particulates can be well controlled by using technologies other than EPA's IPM model presumed technologies.  For example, substantial emission reductions have been delivered by Minnesota Power units in the 25 to 100 MW size range that utilized technologies like Rotating Opposed Fire Air, Furnace Sorbent Injection, Selective Non Catalytic Reduction, Wet Particulate Scrubbers and Low NOx Burners with Over Fire Air.  EPA has not provided information in the NODA that justifies their presumed retrofits of SCR, scrubbers and fabric filters in lieu of these technologies that also deliver cost effective, well controlled operation.  For smaller units, EPA should also give consideration to performance coal (lower sulfur, low mercury) as a control option.  Similarly, the need for preservation of transmission system reliability can justify allowing "well controlled" units under 100 MWs to operate with restricted dispatch in lieu of requirements for BACT-like retrofit of controls that would make the unit uneconomic.  [EPA-HQ-OAR-2009-0491-3742.1_NODA, p.5]
Optimal performance emission rates vs. long term average emission rates.  EPA has selected fairly aggressive emission rate performance values for IPM model inputs that likely reflect optimal performance rather than practical, long term (e.g. 30 day rolling average, annual average) performance.  For example, 98% SO2 removal is cited for scrubber performance input to the IPM model, whereas 30 day rolling average values that address output variability, start up and shut downs might more realistically deliver 90% SO2 removal. EPA IPM 4.10 modeling assumptions for emissions performance should reflect sustainable operational performance. [EPA-HQ-OAR-2009-0491-3742.1_NODA, p.6]
Annual Energy Outlook reference year assumptions.  EPA has indicated that IPM 4.10 will apply EIA AEO 2010 assumptions for rule finalization assessments, whereas 2008 data was applied when EPA determined utility emission budgets cited in the proposed Transport Rule.  2008 through 2010 represents a period when many utilities have been significantly impacted by a recession, where customer demand for electricity has been depressed and utility electricity generation output has significantly shifted.  EPA should perform analysis that examines how economy related electricity production levels and related environmental emissions impact Transport Rule budgets and relative stringency for emissions performance on individual units.  Electricity generating units should not be compelled to install costly environmental controls to compensate for economy related swings in customer demand. [EPA-HQ-OAR-2009-0491-3742.1_NODA, p.6]
New York Power Authority
EPA's National Electric Energy Data System (NEEDS)DATA does not reflect permitted or actual historical emissions.
NYPA reviewed the EPA NEEDS data version 4.10. The NEEDS data file indicates that SO2 emission rate for Flynn as zero, where as the emission rate for SO2 while burning 0.2% sulfur oil is approximately 0.2 lb/mmBtu. [EPA-HQ-OAR-2009-0491-3820, p.3]
Similarly, the NOx emission rate for Flynn was identified as 0.0537 lbs/mmBtu, however, when the unit burns fuel oil the NOx emission rate is 0.1743 lbs/mmBtu.
In addition NEEDS data shows uncontrolled and controlled NOx policy rate as 0.0280 lbs/mmBtu. Both these NOx policy rates are lower than the permitted value burning natural gas. As stated earlier the permit limit is 9.0 ppm (0.04 lbs/mmBtu) while burning natural gas and 42.0 ppm (0.1743 lbs/mmBtu) while burning fuel oil. [EPA-HQ-OAR-2009-0491-3820, p.3]
Similarly, the NEEDS data identifies the SO2 emission rate for 500 MW Combined Cycle Unit as zero while the unit is permitted to burn 0.04%sulfur kerosene for 30 days a year. Also for this unit, a single uncontrolled NOx emission rate of 0.0083 lbs/mmBtu was identified. The NEEDS data identified a controlled NOx policy emission rate of 0.0064 lbs/mmBtu which is lower than the value of 0.0074 lbs/mmBtu permitted while burning natural gas. This unit is equipped with state of the art Selective Catalyst Reduction (SCR) and reduces the NOx emission to 2 ppm (0.0074 lbs/mmBtu). Achieving lower than permitted value is technically not feasible. [EPA-HQ-OAR-2009-0491-3820, p.3]
NYPA respectfully requests that EPA review the input data for the models. [EPA-HQ-OAR-2009-0491-3820, p.3]
New York State Department of Environmental Conservation
Since the comment period for this NODA comes on the heels of the comment period for the proposed Transport Rule, Department staff have had limited time to fully evaluate the implications of this new data. The comments that follow are therefore not a complete evaluation of the dataset and the Department is requesting that EPA provide more time to allow for a full review of this data as well as an evaluation of how the final rule would be adjusted based upon this data. [EPA-HQ-OAR-2009-0491-3763.1_NODA, p.1]
The Department expects that a new set of model run results with the updated modeling platform (Integrated Planning Model (IPM) v4.10) will significantly modify the allocations provided to the affected units within the Transport Rule. These modified allocations have not been made available and the Department urges EPA not to adjust the allocations without providing states and other interested parties the opportunity to review and comment on the changes prior to the release of the final version of the Transport Rule. [EPA-HQ-OAR-2009-0491-3763.1_NODA, p.2]
The Department remains very concerned that IPM does not do an adequate job of estimating or projecting emissions for many units in New York State. In our original comments dated October 1, 2010, the Department commented on the proposed allocation to New York facilities of about 11,000 tons for the ozone season. That allocation was based upon EPA's criteria of the lower value of 2009 actual emissions or IPM version 3.02 base case emissions. In the NODA, EPA is proposing to update the IPM analysis to version 4.10. Since EPA has not completed its work nor has determined how the modified IPM run will impact the final allocations, the Department can only compare the two IPM runs in an attempt to anticipate how this might impact New York. EPA's IPM model version 3.02 predicts 15,686 tons of NOx emissions for New York in the base case, but in the base case for version 4.10, the model predicts only 6,949 tons - a discrepancy of over 100%. As we explained in our comments dated October 1, 2010, the proposed allocation for New York does not accurately reflect the emissions baseline and it is very inequitable. An allocation based upon these updated and extremely low emissions would be even more inequitable to New York and some other states. [EPA-HQ-OAR-2009-0491-3763.1_NODA, p.2]
NRG Energy
The following is a discussion of plant by plant data corrections as they relate to EPA's Notice of Data Availability (NODA) that supports the proposed Clean Air Transport Rule (Transport Rule). The comments discuss:
1. GenConn Energy LLC's new generating units in Connecticut
2. NRG's Dunkirk and CJ Huntley Generating Stations in New York
3. NRG's Indian River Generating Station Units 3 and 4 in Delaware
4. The NRG Texas generation fleet
5. NRG's Big Cajun II facility in Louisiana [EPA-HQ-OAR-2009-0491-3792.1_NODA, p.2]
1.1 GenConn Energy LLC New Generating Units
GenConn Energy LLC (GenConn) is a 50/50 partnership between The United Illuminating Company and NRG. GenConn Devon LLC is the owner of four new 50 MW simple cycle combustion turbines at NRG's Devon Station (Devon), ORIS Code 544. These units came on-line in 2010 and should be Existing Units under the Transport Rule because their commercial operation dates are prior to January 1, 2012. [EPA-HQ-OAR-2009-0491-3792.1_NODA, p.2]
The units are designated as Units 15, 16, 17, and 18 at Devon. Each unit is equipped with an inlet air chiller, a Selective Catalytic Reduction (SCR) system, and a carbon monoxide catalyst reduction system. The units combust either natural gas or ultralow sulfur (15 ppm) distillate oil (ULSD) and are limited to a combined 10.8 tons per year of NOx and 0.9 ton per year of SO2 under the NSR permits Nos.105-0098 through 105-0101, as issued by the Connecticut Department of Environmental Protection (CTDEP). [EPA-HQ-OAR-2009-0491-3792.1_NODA, p.2]
Similarly, GenConn Middletown LLC is the owner of four new 50 MW simple cycle combustion turbines at NRG's Middletown Station (Middletown), ORIS Code 562. These units are currently under construction with a scheduled in-service date of June 1, 2011. These units should be Existing Units under the Transport Rule because their commercial operation dates are prior to January 1, 2012. The units are designated as Units 12, 13, 14, and 15 at Middletown. Their design, operational, and permit limits are identical to the Devon units and contained in the NSR permits Nos.104-0144 through 104-0147, as issued by the CTDEP. [EPA-HQ-OAR-2009-0491-3792.1_NODA, p.2]
Technical design information and permitted emission rates are shown in the Attachment 2 spreadsheet. [EPA-HQ-OAR-2009-0491-3792.1_NODA, p.2] [[See Docket Number EPA-HQ-OAR-2009-0491-3792.1_NODA, pp.5-23 for Attachment 2.]]
1.2 Dunkirk Generating Station
NRG's Dunkirk Generating Station (Dunkirk) located in New York consists of four coal fired steam generating boilers, Units 1, 2, 3, and 4. Units 1 and 2 each have a net capacity of 75 MW; Units 3 and 4 are each 190 MW units. All of the units are equipped with SNCR, trona injection and baghouses for the control of particulate matter, NOx and SO2. The equipment was installed per NY Consent Order No. 02-CV-00245 signed on January 11, 2005. The corrected rates in the Attachment 2 spreadsheet reflect emission limitations required by the Consent Order and which the control equipment is designed to meet. [EPA-HQ-OAR-2009-0491-3792.1_NODA, pp.2-3] [[See Docket Number EPA-HQ-OAR-2009-0491-3792.1_NODA, pp.5-23 for Attachment 2.]]
1.3 CJ Huntley Generating Station
NRG's CJ Huntley Generating Station (Huntley) located in New York consists of two coal fired steam generating boilers, Units 67 and 68. The units each have a net capacity of 190 MW units, equipped with SNCR, trona injection and baghouses for the control of particulate matter, NOx and SO2. Like Dunkirk, the equipment was installed per NY Consent Order No. 02-CV-00245 signed on January 11, 2005. The corrected rates in the Attachment 2 spreadsheet reflect emission limitations required by the Consent Order and which the control equipment is designed to meet. [EPA-HQ-OAR-2009-0491-3792.1_NODA, p.3] [[See Docket Number EPA-HQ-OAR-2009-0491-3792.1_NODA, pp.5-23 for Attachment 2.]]
1.4 Indian River Generating Station Units 3 and 4
The current EPA NEEDS database does not reflect a recent Consent Order which will determine the way this plant is operated in the future. Effective 5/1/2011 the Indian River Generating Station will operate only two baseload units subject to CATR, Units 3 and 4. Unit 3 is a load following coal fired unit with a net capacity of approximately 155 MW and a nominal heat input of 1,904 MmBtu/hr. In addition to pollution controls for mercury and particulate, the unit has Low NOx Burners (LNB), Overfire Air (OFA), and Selective Non-Catalytic Reduction (SNCR) for NOx. It utilizes low (1.2%) sulfur coal. Unit 4 is a load following coal fired unit with a net capacity of approximately 410 MW and a nominal heat input of 5,091 MmBtu/hr. By 2012, the unit will operate with an SCR for NOx control and a circulating dry scrubber (CDS) for SO2 removal as well as mercury and particulate controls. The Delaware DNREC and NRG signed a consent order for shut down of Units 1 and 2 and installation of controls on Unit 4 on July 16, 2010. Operating parameters and emission rates associated with this recently signed consent order are provided in the spreadsheet in Attachment 2. The current data for the units are not correct. It should be noted that this Consent Order requires the retirement of Units 1 and 2 in 2011 and 2010 respectively, retirement of Unit 3 before January 1, 2014 and installation of advanced controls on Indian River 4 by 12/31/2011. [EPA-HQ-OAR-2009-0491-3792.1_NODA, p.3] [[See Docket Number EPA-HQ-OAR-2009-0491-3792.1_NODA, pp.5-23 for Attachment 2.]]
It is also important to discuss PJM Variables and dispatch of this plant. In 2009 and 2010, coal-fired generation in PJM has been impacted by lower than usual natural gas pricing, the infusion of Marcellus Shale Gas supply, and the current economic recession. Even under these conditions, which will likely continue through 2014, annual capacity factors for Units 3 and 4 have remained in the range of 45% to 65%. For the first three operating quarters of 2010, Unit 3 and 4 realized capacity factors of 44% and 45%. It is a concern that EPA's model does not accurately reflect operation now or in the future because it disregards non-economic dispatch for VAR support and PJM grid stability. Indian River Unit 4 dispatch, for example, through September 2010 ran 9% for reactive support and this number is expected to increase to 13% by year end as we go through the temperate shoulder months. It also appears that EPA has included the proposed MAPP transmission line project and Blue Water Wind off shore wind farm in advance of their current installation dates of 2015 and 2016, respectively. Considering these facts, we believe that the model and allocations should reflect more realistic operations with annual capacity factors for Units 3 and 4 in the 55% to 65% range. [EPA-HQ-OAR-2009-0491-3792.1_NODA, pp.3-4]
Three back up documents can be found in Attachment 3, which support the discussion on Indian River dispatch.
1. A Letter from PJM to Pepco Holdings Inc dated August 16, 2010 which approves the June 1, 2015 in-service date for the MAPP transmission line.
2. Excerpts from Operating Agreement of PJM Interconnection LLC  -  Intra -PJM Tariffs that reference mandates to respond to PJM and Reactive Power Payments
3. Section 12.1 of the 2009- PJM RTEP that addresses the state of Delaware 4. NERC Voltage and Reactive Standards- PJM Training Guide [EPA-HQ-OAR-2009-0491-3792.1_NODA, p.4] [[See Docket Number EPA-HQ-OAR-2009-0491-3792.1_NODA, pp.24-28 for Attachment 3.]]
1.5 NRG Texas Fleet
The attached spreadsheet includes revisions to EPA's NEEDS database regarding our Texas plants. Explanations for each change are included in the comments section. [EPA-HQ-OAR-2009-0491-3792.1_NODA, p.4] [[See Docket Number EPA-HQ-OAR-2009-0491-3792.2_NODA for attached spreadsheet.]]
1.6 Big Cajun II Units 1, 2, and 3
The 2012 and 2014 projected SO2 rate based on the coal specifications for Big Cajun II is 0.65lb/mmBtu. The corrections in the attached spreadsheet reflect this change. [EPA-HQ-OAR-2009-0491-3792.1_NODA, p.4] [[See Docket Number EPA-HQ-OAR-2009-0491-3792.2_NODA for attached spreadsheet.]]
Rochester Public Utilities (RPU)
General Comments on EPA's proposed Transport Rule and the NODA  [EPA-HQ-OAR-2009-0491-3729.1_NODA, p.2]
Given the complexity and breadth of the proposed Transport Rule (accompanied by the vast amount of supporting technical data in the docket), the significant differences between the data on which EPA based the proposed rule and the data EPA released pursuant to the NODA, RPU believes that EPA should withdraw the Proposed Transport Rule, revise it using corrected, quality-assured data with appropriate input from the affected facilities, and republish it for public comment with an adequate comment period. [EPA-HQ-OAR-2009-0491-3729.1_NODA, p.2]
Comments on NEEDS Version 4.10 EISA Database [EPA-HQ-OAR-2009-0491-3729.1_NODA, p.2]
Our review of the NEEDS Version 4.10 Database generated the following comments: [EPA-HQ-OAR-2009-0491-3729.1_NODA, p.2]
The Scrubber_Online_Year listed for ORISPL 2008, Unit 4 (UniqueID 2008_B_4) is incorrect. The correct year is 2009, not 2010, as outlined in RPU's Background comments above. [EPA-HQ-OAR-2009-0491-3729.1_NODA, p.2]
The SNCR_Online_Year listed for ORISPL 2008, Unit 4 (UniqueID 2008_B_4) is incorrect. The correct year is 2009, not 2005, as outlined in RPU's Background comments above. [EPA-HQ-OAR-2009-0491-3729.1_NODA, p.2]
The SO2 Permit Rate (lbs/mmBtu) listed for ORISPL 2008, Unit 4 (UniqueID 2008_B_4) is incorrect. This is the maximum allowable by MN State rule but is not applicable to Unit 4. The permitted SO2 rate for Unit 4 prior to 1/26/10 was 2.1 lbs/mmBtu. On 1/26/10 the permitted level dropped to 0.6 lbs/mmBtu. [EPA-HQ-OAR-2009-0491-3729.1_NODA, p.2]
The uncontrolled NOX rate (Mode1) for ORISPL 2008, Unit 4 assumes the use of Low NOX Burners (LNB). However, during the AQCS retrofit the LNBs needed to be removed for placement of the ROFA system and SNCR. The successful operation of the new AQCS precludes the reinstallation of the LNB. [EPA-HQ-OAR-2009-0491-3729.1_NODA, p.2]
Comments on ParsedFile_TR Base Case_2012 [EPA-HQ-OAR-2009-0491-3729.1_NODA, p.2]
A review of the ParsedFile_TR_Base Case_2012 generated the following comments: [EPA-HQ-OAR-2009-0491-3729.1_NODA, p.2]
The Retrofit Control 1 column incorrectly lists SCR on ORISPL 2008, Unit 4. As described above, RPU has recently installed a $38 million state of the art control system on this unit that includes ROFA for combustion control and SNCR for post combustion control of NOX. An SCR is neither existing, under construction nor planned on this unit for 2012 or for any year after 2012. [EPA-HQ-OAR-2009-0491-3729.1_NODA, p.2]
The IPM projections in this parsed file incorrectly assume fuel switching for ORISPL 2008, Unit 4. The fuel use is identified as 100% sub-bituminous coal. While this unit is permitted to combust either bituminous or sub-bituminous coal, this unit has never successfully operated on sub-bituminous coal. At this point, RPU is not prepared to operate this unit on sub-bituminous coal. [EPA-HQ-OAR-2009-0491-3729.1_NODA, pp.2-3]
The IPM incorrectly projects fuel use for UniqueID 6058_G_1 and 6058_G_2 at 100% natural gas. The two combustion turbines at Cascade Creek are peaking units that are permitted to operate on either natural gas or distillate oil. These units are subject to gas curtailments and the current natural gas infrastructure coming into Rochester does not allow for both turbines to operate on natural gas simultaneously during the winter months. Thus the IPM projections need to reflect operation of these units on both natural gas and distillate oil. [EPA-HQ-OAR-2009-0491-3729.1_NODA, p.3]
Southern Company
As explained in the attached comments., Southern Company strongly urges EPA to correct the underlying data and modeling flaws included in the NODA. Furthermore, 'EPA. must determine which dataset will be used in the final Transport Rule; completely redo its air quality and significant contribution analysis; update. the state budgets and unit allocations; and issue a supplemental proposed role with an adequate time for public comment. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p. Cover page 1]
As explained in Southern Company's Transport Rule comments to EPA, the proposed Transport Rule suffers from numerous errors in methodologies and numerous incorrect data and assumptions which impact every aspect of the proposed Transport Rule. Commenting on the proposed Transport Rule was exceedingly difficult given 1) the unreasonably. short time allowed for public comment, 2) the lack of clarity provided for EPA's methodology, and 3) the numerous flaws identified in EPA's data and methodologies. Further complicating the process was the fact that EPA added 'updated' data and modeling files to the docket in the middle of the proposed rule comment period, issued a Notice of Data Availability (NODA), and declared that the new data will be used in the final Transport Rule. Because EPA did not extend 'the comment period for either the proposed Transport Rule or the NODA, stakeholders were forced to evaluate and comment on two sets of data--each of which have different implications to the final Transport Rule-at the same time. The new information adds hundreds of pages of documentation to the docket for this rulemaking and will ultimately cause many changes to the Transport Rule. However, with the NODA, EPA has provided only a small portion of the data, assumptions, and analyses needed to evaluate its implications and has expressly declined to illustrate how these changes will affect the final rule. Additionally, EPA has declared that 'between now and the time that EPA finalizes the Transport Rule, additional information used to support the final transport rulemaking maybe placed in the docket.' It is unreasonable to expect stakeholders to provide meaningful comments on a 'moving target.' Each time that EPA changes the underlying data set and planning model, the underpinnings of EPA's proposed rule will change from emissions and air quality impacts to the statewide budgets and allocations. And, while the new data introduced in the NODA corrects some of the errors identified in the data used for the proposed Transport Rule, it contains new errors that did not exist in EPA's original data set. Given the magnitude of errors and flawed methodologies that still remain and given the fact that CAIR is in place and achieving significant environmental benefits, EPA must take the necessary time to: [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.5]
correct the errors (in data and assumptions); [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.5]
re-run all the models (IPM, CAMx, OSAT, PSAT, AQAT); [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.5]
adjust its methodology; [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.5]
apply the revised methodology with the corrected data, assumptions, and model outputs; [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.5]
update the proposed budgets and allocations; and [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.5]
issue a supplemental proposed rule-with all supporting data, files, and models-allowing adequate time for public comment. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.5]
At minimum, EPA should provide all the necessary files and documentation for stakeholders to assess how the revised data will impact the final rule. Without this information on how the new data impacts the final rule, stakeholders cannot understand the implication nor make meaningful comments. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.5]
EPA Should Have Issued a Supplemental Proposed Rule with the New Data and New Modeling [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.6]
While EPA provided this new information to the docket, the Agency expressly declined to provide updated Transport Rule analyses and instead implied that it would unveil the revised emissions, air quality impacts and significant contribution analysis, and state budgets and unit allocations in the final rule (i.e., with no opportunity for public comment). The proposed Transport Rule depends heavily on the results of the IPM outcomes and the outcomes provide significantly different emission results (see section III below). In the NODA, EPA acknowledged the potential changes by stating: [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.6]
Changes from the projections relied on in the proposed rule, from using an updated model, could impact the final rulemaking in a number of ways including, but not limited to: [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.6]
1. 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-2009-0491-3767.1_NODA, p.6]
2. Changing cost and emission projections used in the multi-factor [i.e., cost curve] test to determine the amount of emissions that represent significant contribution. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.6]
Though quite complex, the proposed Transport Rule allowance allocation methodology can be broken down into approximately eight major steps: [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.6]
1. IPM projects EGU emissions. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.6]
2. The IPM projected EGU emissions are used in CAMx atmospheric modeling to project downwind nonattainment and maintenance monitors. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.6]
3. The source apportionment tools OSAT and PSAT are used within the IPM dependent CAMx modeling to assess interstate contributions to nonattainment and maintenance. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.7]
4. Cost curves are developed from IPM outputs to determine the amount of pollutant reduction available at varying cost, and to determine control cost thresholds or 'breakpoints.' [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.7]
5. The IPM-dependent cost curves developed in Step 4 above are used in AQAT to estimate the air quality benefits of upwind emission reductions.
6. The IPM-dependent AQAT is used to establish air quality 'breakpoints.' [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.7] [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.7]
7. IPM results are used to establish state budgets. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.7]
8. Various IPM parsed files (along with other factors) are used to calculate EGU unit-specific allowance allocations. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.7]
As the list above indicates, at every major step in EPA's methodology -- e.g., creating emission inventory cases as inputs to CAMx modeling, projecting future nonattainment and maintenance problem areas, establishing linkages of upwind states to downwind nonattainment and maintenance problem areas, defining significant contribution to nonattainment and interference with maintenance, and establishment of unit-specific allocations -- IPM plays an indisputably critical role in ultimately determining unit-specific allowance allocations. Despite EPA having the latest NEEDS emission inventory data and revised IPM platform to calculate (and then allow public review and comment on) updated unit-specific allocations and knowing that the resulting emissions would be significantly different, EPA chose not to update the results of the proposed rule. EPA must revisit the basis for its proposal if it intends to proceed with this rulemaking and to continue to use its proposed approach to implementing section 110(a)(2)(D)(i)(I) of the Act. In doing so, EPA should redo each step of its methodology as outlined above using the revised NEEDS inventory and revised IPM. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.7]
In summary, the NODA completely undermines stakeholders' opportunity to provide meaningful comments on this proposed rule - comments on the original proposal were based on data and a version of the planning model now abandoned by EPA and meaningful comments on the new data and modeling cannot be formulated because EPA has not illustrated how the new data and modeling impacts the Transport Rule. Because EPA has declined to illustrate how the new data and modeling may affect the final rule, Southern Company cannot possibly provide the type of comments this rulemaking deserves and is essentially denied the opportunity to comment that the regulatory process requires. Accordingly, EPA must issue a supplemental proposed rule, one that includes the agency's revised regulatory analyses based on the new data, new IPM model results, and a modified methodology; all with an adequate time for public review and comment. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.7]
EPA Did Not Provide Enough Information in the NODA for Stakeholders to Calculate Air Quality Impacts or State Budgets and Unit Allocations [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.8]
In the NODA, EPA requested comments on the new data, plus comments on the impact of the new data on the proposed Transport Rule. '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 until October 15th, 2010.' While we commend EPA for publishing this information, we are disappointed that EPA has published only a small portion of the data necessary to evaluate the potential impacts on the proposed Transport Rule and then expects us to provide comments on its implications. Furthermore, EPA plans to make additional changes to the datasets to support the final rulemaking. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.8]
Since EPA did not publish or post all of the information necessary to evaluate the potential impacts of the NODA, stakeholders can only speculate on how these changes may impact the final rule. Additionally, since the data will change again, comments made on the regulatory impacts from the data will be irrelevant to the final rule. EPA has placed the burden of deciphering the impacts of the NODA on the stakeholders. EPA must provide a coherent and thorough assessment of the changes to the proposed rule and must seek comment on the implications of the changes. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.8]
EPA should, at a minimum, 1) make all pertinent IPM parsed files available, 2) provide updated CAMx air quality modeling results (using PSAT and OSAT for determining state contributions), 3) provide updated cost curves based on the updated IPM modeling, 4) provide an updated significant contribution analysis, and 5) publish updated state budgets and unit allocations for all affected states and units. We also suggest, as EPA updates the significant contribution analysis, that they reconsider their methodology for determining significant contribution, giving due consideration to the comments and suggestions that were submitted by Southern Company and UARG on the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.8]
The New Data Will Impact The Transport Rule Air Quality Analysis [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.8]
EPA published in the NODA updated IPM results (v4.10) for the 2012 Base case and the 2014 State Budget Limited Trading case, including parsed files containing model output for EGUs that are greater than 25 MW (i.e., those units being considered in the Transport Rule). From the parsed files projected statewide emissions for those two scenarios could be calculated. After applying the assumption that non-EGU emissions and emissions from EGUs that are less than 25 MW do not change from the v3.02 IPM Base Case, we calculated statewide anthropogenic emissions of SO2 and NOx. Using this information, we applied our replicated version of the AQAT to estimate new 'Base Case' air quality at each monitor and upwind contribution from each state. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.8]
Table 1 [See p.9 of this comment summary for Table 1. Comparison of the number of monitors with nonattainment and maintenance issues based on emissions derived from IPM 2012 Base Case v3.02 and v4.10.] shows our estimate, using the replicated version of the AQAT, of the number of monitors that are projected to be in nonattainment or maintenance for each of the three NAAQS considered in the Proposed Transport Rule (Annual PM2.s, 24-Hour PM2.5 and 8-Hour Ozone), using the 2012 Base Case emissions from IPM v3.02 and v4.10 (the number of maintenance monitors includes nonattainment monitors). The result is astonishing in that, even though significant flaws still exist in the modeling methodology that overestimate emissions, close to half of the PM2.5 monitors no longer have nonattainment or maintenance issues. [EPA-HQ-OAR-2009-0491-3767.1_NODA, pp.8-9]
Table 2 [See p.9 of this comment summary for Table 2. Comparison of the number of states linked to downwind nonattainment and maintenance monitors based on emissions derived from IPM 2012 Base Case v3.02 and 4.10.] shows our estimate of the number of states that are linked to downwind nonattainment and maintenance monitors, using the 2012 Base Case emissions from IPM v3.02 and v4.10 (the number of states linked to maintenance monitors includes states linked to nonattainment monitors). The table demonstrates that the updated emissions (which are overestimated in some cases) may result in fewer states being included in the Transport Rule program, especially for ozone. Florida is one of the states that no longer contribute significantly to downwind nonattainment or maintenance. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.9]
This change in estimated air quality is significant and should motivate EPA to re-run the CAMx air quality modeling using the updated IPM v4.1 0 emissions. Only because Southern Company invested significant time and resources in attempting to replicate the AQAT for our initial Transport Rule review were we able to make these estimates of the impact of the new data on the predictions of air quality. EPA should use the new data, or whichever data it intends to use in the final rule, update all of the analyses and calculations made in the proposed Transport Rule, and issue a supplemental proposed rule for comment. [EPA-HQ-OAR-2009-0491-3767.1_NODA, pp.9-10]
The New Data Will Impact State Budgets and Unit Allocations [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.10]
The updated assumptions in the IPMv4.10 model runs have impacted both the 2012 and 2014 projected emissions for the states that cover the Southern Company territory. For the 2012 Base Case, projected annual and seasonal NOx emissions go down in all states, most dramatically in Florida (43% annual, 45% seasonal). 2012 Base case SO2 emissions are unchanged for Florida, but are significantly changed for Alabama, Georgia and Mississippi--emissions increased by 47,932 tons (14%) in Alabama, decreased by 48,233 tons (9%) in Georgia and increased by 12,102 tons (29%) in Mississippi. (See Table 111-3 and Table-III-4.) [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.10]
These changes in the 2012 Base Case emissions are not trivial and will affect the significant contribution analysis. These emissions would also most certainly affect the 2012 NOx and SO2 budgets and allocations. However, EPA has not provided updated tables of budgets and allocations, nor have they provided all the files necessary to apply the state budget and unit allocations algorithm documented in the Budgets and Allocations TSD. (See Section III-C for a list of files that we think are necessary to make this calculation). [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.10]
[See p. 10 of this comment summary for Table 3. Change In 2012 Base Case Emissions Between IPM V3.02 And V4.10 and Table 4. Percent Change In 2012 Base Case Emissions Between IPM V3.02 And V4.10]
For the 2014 State Budget Limited Trading Case, EPA states that they limited the emissions budgets to the caps modeled in the Proposed Transport Rule: 'These policy runs include the same State-level caps that EPA modeled in the Proposed Transport Rule. The caps have not been modified to account for any changes that the new modeling might suggest; they are merely provided for informational purposes to allow commenters to understand the impact that changes in the model platform have on the projected impacts of the caps.  However, there are sizable differences in individual state emissions projections between v3.02 and v4.10. Most noteworthy is that Florida's SO2 emissions increased 34,074 tons (25%). Both Florida and Georgia had sizable decreases in emissions for both annual and seasonal NOx, greater than a 20% reduction. (See Tables 5 and 6.) [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.11; See p.11 of this comment summary for tables 5, Changes In 2014 Limited Trading Case Emissions Between IPM V3.02 and V4.10 and table 6, Percent Changes In 2014 Limited Trading Case Emissions Between IPM V3.02 And V4.10]
EPA also posted in the NODA alternative IPM model runs with altered gas price assumptions. In these four state, these assumptions led to an increase in NOx emissions of 2 - 5% over the default v4.10, and an increase in 802 emissions of 0 - 9% in the 2012 Base Case for these four states. (See Table 7.) [See p.12 of this comment summary for table 7, Percent Changes In 2012 Base Case Emissions Between IPM V4.10 and V4.10 With Updated Gas Assumptions] The increase in Florida SO2 emissions of 9% is an especially important indicator of the value of doing multiple runs with different assumptions about unknown future availability and price of natural gas. The fact that IPM results are this sensitive to unknown future fuel prices suggests that EPA needs to be much more respectful of uncertainties if it intends to base state budgets and EGD allocations on IPM results. We would prefer an approach based on multiple years of historical data rather than projections. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.11]
EPA Should At Minimum Provide the Following Files in Order For Stakeholders to Determine How the New Data May Impact the Transport Rule [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.12]
As noted in Section II of these comments, EPA added new information to the docket. However, it did not provide the same documentation and data files for the new IPM and NEEDS v4.1 0 that it provided under the proposed rule for the old IPM and NEEDS v3.02-including the summary state budget and unit allocation data. Further, the agency did not provide all the files necessary for stakeholders to calculate the impacts of the new data and modeling on the proposed Transport Rule. If EPA does not provide the updated state budgets and unit allocations for public comment, then it must at a minimum provide enough data for stakeholder to evaluate how EPA's reliance on the new versions will impact the rule and its critical components (e.g., state budgets and unit allocations). In the interest of transparency and to allow stakeholders to provide meaningful comments, EPA must allow public comment on the additional data and modeling files and their subsequent impacts to the final rule. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.12]
The following files are necessary to calculate state budgets and unit allocations for the 2012 Base Case, and EPA should make them available as expeditiously as practicable: [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.12]
:: IPM Parsed data for $5001ton NOx for annual and ozone season (TR_NOX_500 and TR_NOX_OS_500) [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.12]
:: IPM Parsed data for $1600lton SO2 (TR_SO2_1600) [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.12]
The following additional files were made available in the proposed Transport Rule with the original data. The corresponding 'updated' files are necessary to fully understand the impact of the new data to the proposed Transport Rule and to provide meaningful comments: [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.12]
:: Revised Budgets and Allocations - Detailed Unit-Level Data (Excel) (i.e., BADetailedData.xls) [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.12]
:: Updated cost curves, summary reports, and parsed files derived from the suite of IPM runs: [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
o 2012 and 2014 $0 to $5000 per ton for seasonal NOx [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
o 2012 and 2014 $0 to $2500 per ton for annual NOx [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
o 2012 and 2014 $0 to $2400 per ton for annual SO2 [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
:: New 2014 IPM Base Case parsed file (v4.10) [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
:: Allocation Table (Excel) [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
:: Air Quality Contributions Data File (Excel) [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
:: TR SB Limited Trading Files for 2012 (Input and Output Files, TR_SB_Limited_Trading System Summary Report.xls, ParsedFile_TR_SB_Limited_Trading.xls) [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
:: TR SB Intrastate Trading Files for 2012 and 2014 (Input and Output Files, TR_SB_Intrastate_TradingSystemSummaryReport.xis, ParsedFile_TR_SB_Intrastate_Trading.xls) [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
:: TR Direct Control Files for 2012 and 2014 (Input and Output Files, TR_Direct_Control System Summary Report.xls, ParsedFile_TR_ Direct_Control.xls) [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
In addition, EPA should provide the following information and update the following technical support documents based on its new data and the new IPM and NEEDS versions: [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
:: Non-EGU Emissions Reductions Cost and Potential (PDF). EPA updates its pollution control retrofit cost and performance assumptions, U.S. Environmental Protection Agency, Clean Air Markets Division, Integrated Planning Model (IPM) Version 4.10 Summary of Model Updates (Sept. 22, 2010)., yet it does not provide information on how this might impact the cost effectiveness of including other emission source categories in the rule or whether it made similar adjustments to control cost and performance assumptions for other emission source categories. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
:: Emissions Inventories. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
:: State Budgets, unit Allocations, and Unit Emissions Rates (PDF). [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
The New IPM Assumptions Result in Significant Changes in Generation From the Proposed Transport Rule Southern Company compared the four new IPM (v4.10) summary results with the comparable results in the proposed Transport Rule (v3.02). This comparison included the following: [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
:: IPM v3.02 base case IPM results; [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
:: IPM v4.1 0 base case IPM results; [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
:: IPM v4.10 base case IPM results with the AEO 2010 gas resource assumptions;- [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
:: IPM v3.02 policy case IPM results; [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
:: IPM v4.10 policy case IPM results; [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
:: IPM v4.10 policy case IPM results with the AEO 2010 gas resource assumptions; [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
A key difference between IPM v3.02 and v4.10 is that projected coal generation has decreased significantly. For example, projected total national coal generation for 2015 is about 15% lower in the v4.IO (in the base case and both policy cases). This is not a small change. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
Overall projected generation for 2015 is also substantially lower (about 5%) in IPM v4.10. These changes have brought EPA projections into closer agreement with EIA's projections in ABO 2010. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.14]
Although notable changes have occurred in IPM v4.10 over v3.02, the NODA and associated documentation provided by EPA do not adequately explain the relative decrease in projected energy demand. For example, the heat input for the state of Georgia projected by IPM v4.10 in the base case is approximately 20% lower compared to IPM v3.02. However, the impact on the capacity factors of individual units is often disproportionate. It appears that IPM v4.10, likely inaccurately, places the brunt of the decrease on certain units. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.14]
EPA proposes to use revised modeling assumptions in the final Transport Rule, including new projections on future natural gas prices. Both the IPM v4.1 0 and the IPM v4.1 0 with the AEO 2010 gas resource assumptions assume natural gas prices prior to 2016 to be much lower than assumed in IPM v3.02. EPA has stated a preference for its IPM v4.10 natural gas resource assumptions as compared to the previous projections and the new ABO 2010 gas resource assumptions. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.14]
Natural gas prices, however, are notoriously volatile; therefore, future natural gas prices are difficult to predict. Much of the future uncertainty surrounds the availability of shale gas production. In Appendix 10-1 of the documentation for EPA Base Case v.4.10, EPA acknowledges this, noting that the view of shale gas availability in the EPA base case v.4.1 0 is about three times as large as EIA's view in AEO 2010 (see also Figure 2 below). [See p.15 of this comment summary for Figure 2,IPM Natural Gas Price Assumptions] Figure 1 below [See p.14 of this comment summary for Figure 1, Monthly Georgia Natural Gas Price Sold to Electric Power Consumers] shows a large volatility of natural gas prices in Georgia over an eight year period, from January 2002 to June 2010. The minimum price was 2.97 dollars per thousand cubic feet in February 2002 and the maximum 15.82 in September 2005. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.14]
Fuel price is a primary driver of economic dispatch; therefore, EPA's assumptions about relative fuel prices can significantly change the results of its modeling - from emissions to cost and allocations. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.14]
While electric utilities routinely rely on relative fuel price predictions for purposes of dispatch planning, compliance planning, and integrated resource planning, these predictions and the related analyses are updated on an ongoing basis. In contrast, EPA intends to use today's projections and develop federally enforceable requirements based on these. This improper reliance can significantly impact the cost of the proposed rule. Figure 2 below illustrates that the IPM v4.1 0 AEO runs show that the future costs of the Transport Rule may be much greater than published in the proposal. While AEO predicts relatively low natural gas prices in the near term, it predicts that prices will almost double in less than 15 years. This comparison illustrates the potential risks in setting permanent allocations derived from modeling projections that only account for a short period of time (2012 and 2014). At minimum, EPA must recalculate the costs of the final Transport Rule given the revised fuel price assumptions (EPA's preferred and alternate assumptions) and provide· them for review and comment. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.15]
The NODA Includes Many Inaccurate Inputs and Assumptions for-and Unrealistic Outputs from-EPA's Integrated Planning Model (IPM) [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.15]
EPA Made Many Assumptions in NEEDS v4.10 Regarding Individual Units that Are Inaccurate [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.15]
In reviewing the NEEDS v4.10, Southern Company found several flaws that need to be corrected. These are listed below: [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.16]
NOx Emission Rates: EPA's methodology for determining NOx emission rates is not sufficiently clear. Further, EPA's proposed NOx emission rates do not match how we project our units to operate and do not match up with past actual NOx rates for any single year that we can determine. We are continuing to review the NOx emission rate methodology and may provide further comments as soon as possible. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.16]
SO2 Emission Rates: For SO2, EPA represents that it has relied on NEEDS for the SO2 emission rates used to develop the proposed rule. However, in some cases, it appears that the Agency has not used the most recent update to NEEDS and in other cases, it appears that NEEDS itself contains inaccurate information. If EPA insists on relying on NEEDS for purposes of this rulemaking, the Agency should correct the errors. However, Southern Company urges EPA to reconsider its reliance on NEEDS and instead use actual SO2 emission rates to better represent historical operation. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.16]
Emission Controls: [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.16]
:: EPA needs to correct the timing of planned controls. The control online years listed in NEEDS (including corrections listed below) appear to represent the actual calendar year the pollution control either came online or is required to come online. This does not necessarily represent a full year in which the control will be operational. IPM modeling should not account for controls until the year after NEEDS indicates they come online. FGD online dates for the following units were correct for NEEDS v3.02 but are incorrect in NEEDS v4.10. The correct years are: [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.16]
o Bowen 1- 2010 [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.16]
o Bowen 2 - 2009 [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.16]
o Bowen 3 - 2008 [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.16]
o Bowen 4 - 2008 [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.16]
o Hammond 4 - 2008 [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.16]
:: To accurately reflect Georgia State Rule 391-3-1-.02(2)(sss), the Multipollutant Rule, the Scherer 4 FGD online year should be listed as 2012 (required 12/31/2012). The first full year that the Scherer 4 FGD is required to be online is 2013. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.16]
:: In the NODA, EPA has changed its assumed scrubber removal efficiencies from 95 to 98%. EPA should not assume a continuous removal efficiency of 98% because this level is not sustainable on any medium or long-term basis taking into account startups, shutdowns, and other fuel or operational variability. While vendors may guarantee 98% removal, those guarantees are on a one-time, instantaneous basis. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.16]
:: States recognize that variability factors must be taken into account when setting expectations for long term operation of control equipment. As noted above, Georgia State Rule 391-3-1-.02(2)(uuu) regulates SO2 emissions from electric utility steam generating units and requires a 95% removal on a 30-day rolling average basis for affected units, not 98%. The scrubbers most recently installed Georgia Power units are designed to meet 98% removal on an instantaneous basis, but 95% on a 3D-day rolling average. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.17]
:: EPA should also recognize that not all scrubbers were designed to achieve 95% removal, much less 98%. For example, EPA assumes an SO2 removal for the Yates Unit 1 scrubber of 95% but the actual removal rate should be 90%. consistent with Georgia State Rule 391-3-1-.02(2)(uuu). The scrubber on this unit was a full scale demonstration project installed in the early 1990s without the type of vendor guarantees associated with more recent installations. The Georgia Power Title V application has always indicated an expected 90% removal by the Yates 1 scrubber. The recent Georgia Rule (uuu) also made a distinction between the Yates 1 scrubber and the more recently installed scrubbers with a removal requirement of 90% for Yates instead of 95% for more recent scrubbers. We believe this distinction is proper in recognizing that the Yates 1 scrubber is both already nearly 20 years old and the first full-scale version of its design. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.17]
:: The scrubber efficiencies (95%) appear to be missing for: [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.17]
o Barry 5 [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.17]
o Gaston 5 [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.17]
o Gorgas 8-10 [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.17]
:: The actual historical NOx Emission Rates for coal-fired units with SCRs are larger than the value in NEEDS. Specifically, the 0.06 lb/mmBtu rate assigned to coal-fired units with SCRs has not been historically demonstrated. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.17]
:: NEEDS v4.10 incorrectly identifies Crist unit 6 as having OFA for NOx control. Crist 6 does not have a functional OFA system. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.17]
:: NEEDS v4.10 incorrectly identifies Crist unit 7 as having an SCR in 2004. Crist unit 7 should be listed with an SCR in 2005 with full-time operation. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.17]
:: NEEDS v4.10 lists Crist units 6-7 as 'yes' to having dispatchable scrubbers. These units have scrubbers that are required to operate by Crist FGD Air Construction Permit 0330045-023-AC.9 Therefore, Crist units 6-7 should not be listed as 'yes' to having dispatchable scrubbers. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.17]
:: NEEDS v4.10 does not list Crist units 4-5 as having a wet scrubber. Crist units 45 have a wet scrubber and it is required to operate by Crist FGD Air Construction Permit 0330045-023-AC. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.17]
:: EPA's 2012 Base Case data indicates that Crist Units 4, 5, 6, and 7 are unscrubbed. As explained in Southern Company's comments on the proposed Transport Rule, all of these units have installed wet FGD systems and are required to operate them by permit. Further, EPA's 2014 Limited Trading data in v4.10 incorrectly indicates that Gulf Power's Crist Units 4, 5, and 7 are unscrubbed. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.18]
Other: [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.18]
:: The NEEDS v4.1 0 database appears to be using net capacity in Megawatts for the 'Capacity' input. Plant Joseph M. Farley operates 2 Nuclear Units in Houston County which are inaccurately listed as 851 and 860 MW each. The appropriate net capacity for these units is 883MW each. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.18]
:: Heat Rates in NEEDS v4.10 are the same Heat Rates in NEEDS 3.02, just rounded to the nearest whole number, which can cause significant impacts to modeled emissions when applied to many Megawatts-hours of electric generation. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.18]
:: NEEDS has divided combined cycle units (CCs) into the two combustion turbines (CT) and the steam turbine (ST), which is different from how these units report emissions to the Clean Air Markets Division of EPA. If EPA chooses to treat CCs in this manner, it must ensure that the total megawatts under this method add up to the total megawatts for the unit. For example, Lansing Smith CC unit 3 should be a total of 556 MW. EPA has listed Smith unit 3 as: 3A (158 MW); 3B (158 MW); and 3S (166 MW). This only adds up to 482 MW. If EPA continues to treat the ST as a separate entity, it must first correct the total to 556 MW and then it must correct the individual megawatts to: 3A (175 MW); 3B (175 MW); and 3S (206 MW). [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.18]
EPA Made Many Assumptions in IPM Regarding Individual Units that Are Inaccurate [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.18]
:: Plant Mitchell Unit 3 is a coal-fired unit. It is incorrectly listed in NEEDS 4.10 as a biomass unit, and it is not included in any of the IPM.4.10 runs. Georgia Power is considering a switch from coal to biomass for this unit but has not made a decision about this potential conversion due to regulatory uncertainty surrounding pending EPA regulations. Any conversion would happen well after EPA's proposed 2012 compliance date for the proposed rule. This unit should be listed as a coal-fired unit, as it was in NEEDS 3.02, and should be included in the IPM 4.10 runs. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.18]
:: The IPM v4.10 runs list Scherer 4 NOx controls as 'LNB + SOFA' while all other Scherer units are listed with only 'OFA.' The proper existing NOx control for all four units at Scherer is overfire air, or OFA. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.18]
:: For Scherer 4, the 2014 IPM run lists only SCR as a retrofit control and does not list FGD. Both the SCR and FGD are required by the Georgia Multipollutant Rule by 12/31/2012. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.19]
:: For Scherer 1, the 2014 IPM run lists SCR/FGD as a retrofit control. The Georgia Multipollutant Rule does not require the SCR and FGD until 12/31/2014. As stated above, EPA should not account for controls until the year after they come online which, in this case, is 2015. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.19]
:: Greene County 1 is a wall-fired boiler. It is incorrectly classified as a cell-fired boiler in IPM v4.10. IPM v4.1 0 also lists Greene County CTs 2-10 with no fuel consumption in 2012 and 2014, which likely means the model assumes that these units will not run. This is inaccurate and inconsistent with our expectations. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.19]
:: IPM v4.10 lists the fuel type for Greene County CTS 2-10 as burning No.2 fuel oil beginning 2012. These units currently bum natural gas. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.19]
Many of the Control Technology Cost Assumptions in IPM v4.10 Are Improved, Yet Some Require Additional Improvements [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.19]
EPA revised the cost inputs for the IPM model by sponsoring an architect/engineering company - Sargent & Lundy Engineers (S&L) - to derive control technology costs based on a database of component costs and installation charges. For a complete analysis of EPA's new assessment see 'Overview of Projected Costs for Control Technology -as Developed for EPA's Integrated Planning Model (IPM)', prepared by J. Edward Cichanowicz, October 15,2010, included with the October 15, 2010 comments of UARG. The following are additional points regarding control technology assumptions. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.19]
:: FGD Systems: EPA has significantly raised retrofit control costs in many categories in IPM, including those for wet Flue Gas Desulfurization (FGD) systems. While EPA has raised the wet FGD control costs to a more reasonable level, due to site constraints such as space these projections still fall $100-150/kw short across all unit sizes. Additionally, EPA has incorrectly assumed that FGD systems can continuously achieve a 98% SO2 removal rate. Southern Company's newest FGDs are designed for a 98% instantaneous SO2 removal in order to meet a 95% 30-day rolling average. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.19]
:: SCR Systems: EPA has implemented modest increases to the cost of Selective Catalytic Reduction systems (SCRs). EPA's SCR costs are still too low. The SCR control costs used in the IPM model do not reflect reality for Southern Company. With more than 10,000 MWs of the most economical SCRs already installed, retrofitting the remainder of the fleet would cost 2 - 3.5 times the EPA assumptions depending on the site. Additionally, EPA has incorrectly assumed that units with SCRs can consistently achieve a NOx rate lower than 0.07 lbs/mmBtu. Southern Company does not have demonstrated experience operating SCRs consistently below 0.07 lbs/mmBtu, especially when SCRs are operated year-round instead of seasonally. [EPA-HQ-OAR-2009-0491-3767.1_NODA, pp.19-20]
:: Fabric Filter: EPA should give a cost range for fabric filters with activated carbon injection with an upper bound $50-100/kw higher. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.20]
:: CCS: Southern Company supports EPA's consideration of CCS in its updated IPM modeling. However, the rate of introduction of this technology is of concern. In the IPM v4.1 0 data, thirteen thousand gig watt hours are included in the generation mix by 2012. This seems unreasonable due to the fact there are no commercial scale coal projects with CCS scheduled to be online by 2012. Southern Company understands that because CCS is a developing technology, projecting the rate at which it will be introduced is challenging and warrants EPA's attention. Southern Company supports the comments of the Coal Utilization Research Council (CURC), especially CURC's suggestion that EPA should develop and offer for comment a more rigorous approach to address limits to the rate of introduction of CCS technology. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.20]
IPM Results Are Being Inappropriately Used In The Proposed Transport Rule [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.20]
IPM simulates the operation and evolution of the US electricity system, including the investments made to reduce emissions while increasing energy output. In particular, EPA uses IPM to 'guess' about whether particular control technologies will be installed at individual EGUs and estimates future emissions of those EGUs based on these 'guesses.' Many of these 'guesses' (and thus emissions estimates for many EGUs) will likely turn out to be wrong. Nevertheless, EPA prescribes EGU allowance allocations based on the IPM model as if the 'guesses' are absolute. IPM does not take into account all of the relevant factors that utilities use to make investment decisions. These are incredibly complex decisions involving many site and situation-specific considerations that are not part of IPM (such as unit space and construction challenges, unit-specific boiler design issues, transmission issues, fuel sourcing issues, local or company-specific regulatory issues, etc.). Further, IPM makes these 'guesses' assuming that it accurately predicts future fuel prices (while ignoring any feedback from changes in electricity fuel use on fuel prices) and assuming that it accurately predicts the future costs and performance of technologies. Making predictions to this level of accuracy is unrealistic. Models such as IPM are iterative - not static - and should not be used to establish federally enforceable, fixed budgets and allocations. EPA's misuse and overreliance on IPM results in this rulemaking is particularly egregious because in this proposed rule EPA is not planning to allow the states an opportunity to develop their own allocations. EPA must recognize the limitations of IPM and should not rely on IPM results to prescribe future emissions budgets for states and allowance allocations at the unit level. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.20]
State of Ohio Environmental Protection Agency (Ohio EPA)
In this notice U.S. EPA acknowledges that the changes in assumptions in the latest modeling platform could impact the final rulemaking in a number of ways including changing emission projections that were used to determine which downwind areas have air quality concerns, which States contribute to those problems, and/or changing cost and emission projections used in the multi-factor test to determine the amount of emissions that represent significant contribution. In turn these changes will likely impact budget allocations. Ohio EPA is extremely concerned that given the ramifications of these data changes, additional concerns may arise, without the ability to comment, when the final rule is promulgated. Ohio EPA requests U.S. EPA provides additional opportunities for notice and comment on the final data changes, including state budgets and allocations to specific units, prior to finalizing the Transport Rule. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.1]
Ohio EPA staff reviewed the background documentation the best that they could; however, finding the actual technical reason for the unit specific allocations was not clear in all cases. The basis for unit specific allocations was NEEDS V3.02. This was updated to NEEDS V4.1 0 (herein referred to as 'NEEDS') as a part of this NODA. Ohio EPA has found it difficult, in the time afforded, to extensively investigate the accuracy of all of the information in NEEDS and the NODA and its potential affect on the proposal. However, Ohio EPA has found that it still contains errors that necessitate correction before a final Transport Rule can be completed. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.2]
Ohio EPA is concerned with the lack of transparency on exactly which assumptions, and therefore, numbers, are used in determining allocations. For example, the 'State Budgets, Unit Allocations, and Unit Emissions Rates' Technical Support Document (TSD) from July 2010 contains Table 1 'Adjustments to Report Emissions to Account for Controls' and Table 2 'Adjustments to Reported Emissions to Account for Controls.' These tables contain a matrix of decisions for the procedure for adjustments. For NOx, one such procedure includes choosing the greater of 0.06 lbs/mmBtu or the 'removal rate from IPM documentation' under Table 1. Similarly for Table 2, a procedure for choosing the greater of the 'removal rate from IPM documentation' or 'emissions rate in controlled model projection.' A footnote for both tables states the removal rate in the Integrated Planning Model (IPM) is 90% for Selective Catalytic Reduction (SCR). In the IPM documentation NEEDS, there are four NOx rates in lbs/mmBtu identified: Uncontrolled NOx Base Rate, Controlled NOx Base Rate, Controlled NOx Policy Rate, and Uncontrolled NOx Policy Rate. In Appendix 3-1.1 'NOx Rate Development in EPA Base Case vA.10' there is an additional decision making table describing how rates, and ultimately allocations, are decided. However, ultimately, within all of this documentation there is no indication as to which decision, rate, etc. is associated with each individual unit allocation. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.3]
Furthermore, within Appendix 3-1.1 it states: [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.3]
'Calculations can get complex, so we'll illustrate it here for coal units only and with the assumption that the data were absolutely complete and consistent with what engineering theory tells us its values should be. Otherwise, we apply additional screens. Explaining them is beyond the scope of this illustration. Basically, here's how the values would be derived:' [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.3]
It is very difficult to give meaningful comments regarding unit-by-unit level assumptions in NEEDS and the associated modeling results when it is not clear which of the multiple 'complex' levels of .calculations, adjustments (or screens) and assumptions are applied to a specific unit. While we understand the desire to produce a rule as soon as possible and the amount of work involved, U.S. EPA is not allowed to forgo the appropriate procedural mechanism because it is too complex or difficult. It is imperative that states and owners of these units are provided detailed unit-by-unit information as to the basis of allocations in order to ensure appropriate information is used for future allocations. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.3]
Ohio EPA is concerned with the Integrated Planning Model's (IPM) one size fits all assumptions and the affect of these assumptions on unit level allocations and costs. In Chapter 5 of the documentation (Emissions Control Technology), U.S. EPA describes the two types of Flue Gas Desulfurization (FGD) technologies applied to the modeling and states 'In EPA Base Casev4.10 when a unit retrofits with a Lime Spray Dryer (LSD)  SO2 scrubber, it loses the option of BG, BH, and LG coals due to their high sulfur content.' Ohio EPA is concerned with the model applying these types of one size fits all assumptions that do not take into account the specific circumstances of each plant. For example, for some 'mine - mouth' plants, the infrastructure (no barge or inadequate rail) may not be available to handle large quantities of low sulfur coal. If an LSD type scrubber is assumed for one of these plants, at a specific cost threshold, it may be incorrect or impractical. And ultimately, those assumptions will dictate the unit level allocations received forcing certain plants to install a wet FGD system, when an LSD system was assumed, which could ultimately affect the cost thresholds and allocations received. [EPA-HQ-OAR-2009-0491-3747.1_NODA, pp.3-4]
Ohio EPA has concerns regarding the level of emission reduction assumed for NOx controls. In Chapter 5 of the documentation (Emissions Control Technology) U.S. EPA states 'Potential (new) coal-fired, combined cycle, and IGCC units are modeled to be constructed with SCR systems and designed to have emission rates ranging between 0.01 and 0.06 lb NOx/mmBtu. In Appendix 5.2A, 'IPM Model - Revisions to Cost and Performance for APe Technologies, SCR Cost Development Methodology' by Sargent and Lundy it is recommended that the 'Lower level of NOx removal is recommended as 0.07 NOx lb/mmBtu' for bituminous coal. Yet, U.S.EPA appears to make the assumption that older coal-fired units retrofitted with SCRs can also achieve a 0.06 lb NOx/mmBtu rate.  Ohio EPA is not as confident that this one size fits all rate is achievable for retrofits.
Cardinal Units 1, 2 and 3 [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.4]
NEEDS identifies units 1 and 2 as having a wet scrubber installed in 2007. Our records indicate March 2008. NEEDS identifies a 98% removal efficiency for unit 1. The owner indicates unit 1 is achieving approximately 95.5%. No assumptions are identified for unit 2. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.4]
NEEDS identifies unit 3 as having a wet scrubber in 2010 with no indication of removal efficiency. This unit is currently not scrubbed; however, it is required to have scrubbing by 12/31/2011. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.4]
It appears there have been adjustments to annual NOx emissions under both the reported and projected methods for all three units. NEEDS identifies a SCR install date of 2003 which is consistent with our records. However, it is not clear if U.S. EPA accounted for this SCR beginning continuous operation starting in 2009 based upon a Consent Decree. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.4]
J M Stuart Units 1, 2, 3 and 4 [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.5]
NEEDS identifies the installation of a wet scrubber in 2008. Although these were installed in early 2008 full operation did not begin until July of 2009 which is apparent by the actual emissions identified for these units. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.5]
NEEDS identifies these units as achieving 96% (unit 1) to 98% (units 2, 3 and 4) scrubber efficiency; however, these units are more closely achieving 95% according to the owner. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.5]
All units at J M Stuart installed SCRs in 2004 and began continuous operation of the SCRs in May of 2009. With the understanding that 2009 was a year of low demand due to the economic state of the country, Ohio EPA looked at the 2007 to 2009 average ozone season NOx emissions for each of these units. Ohio EPA is concerned regarding the ozone season NOx allocations for these units and believes they may not be sufficient. Each unit, controlled by an SCR, is receiving allocations that are only 44 to 57 % of the average 2007 to 2009 ozone season emissions. It is not transparent as to what assumptions were made as part of the IPM process that would result in such a drastic reduction in allocations for highly controlled units and just how those allocations may be affected by the newest IPM runs. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.5]
Gavin Units 1 and 2 [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.5]
NEEDS identifies these units as being controlled by scrubbers achieving 96.6% (unit 1) and 98% (unit 2) efficiency while the owner indicates they are in the range of 94.5%. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.5]
Similar to the J M Stuart units, Gavin installed SCRs in 2001 and began continuous operation in 2009; yet allocations are 69-89% of the average 20072009 ozone season emissions. Looking at allocations (based upon the IPM modeling), annual NOx allocations do not appear to be sufficient. Gavin's units, controlled by an SCR for all of only the first three quarters of 2009, had NOx emissions of 2,469 to 2,516 tons while allocations for four quarters are 2,384 to 2,584. Based on these historical controlled operations, Gavin will be left with insufficient allocations for at least a quarter of the year. Again, it is not transparent as to what assumptions were made and how allocations may be affected by the newest IPM runs. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.5]
Avon Lake Units 10 and 12 [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.5]
Avon Lake unit 10 received no SO2 allocations for 2014 based upon IPM model runs. There is no indication of this unit ceasing operations and it is not transparent as to whether the revised IPM runs have corrected this. Ohio EPA does not believe it is appropriate to allow IPM to retire units when allocations are based upon these runs. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.6]
Unit 12, a 671 MW uncontrolled unit with 2007 to 2009 average annual  SO2 emissions of 29,382 tons, received 2014 allocations of 2,466 tons of  SO2 based upon the IPM runs. Yet a similar sized unit with recent scrubber technology installed in 2008, J M Stuart unit 4 (573 MW, and 2007 uncontrolled SO2 annual emissions of 27,610 tons), received allocations of 3,529 tons of SO2 for 2014. And IPM, based on NEEDS, assumed a 98% efficiency for the J M Stuart unit. Ohio EPA is concerned that the multitude of assumptions made by IPM, for which allocations are made, does not make practical sense and creates inconsistencies. It is not transparent as to what assumptions were made and how allocations may be affected by the newest IPM runs. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.6]
Conesville Units 3, 4, 5 and 6 [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.6]
Conesville unit 3 appears not to exist in the NEEDS file and, therefore has received no allocations. This unit is running and the owner has indicated no intent of retiring this unit. It should receive allocations. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.6]
Conesville unit 4 received 266 tons of SO2 allowances in 2012 and 5,539 tons in 2014. It is not transparent as to what data or assumptions resulted in this 2012 allocation and if it has been corrected. Ohio EPA assumes the 2012 allocation must be an error that has been or will be corrected in the IPM runs. This unit installed a 98% efficient scrubber in 2009; however, it is an 800 MW unit with historical uncontrolled emissions of 72-92,000+ annual SO2 emissions. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.6]
The Proposed Transport Rule states that 2012 NOx reductions will come from operating 'existing SCRs on a year-round basis and up to their design removal efficiencies and the installation of limited amounts of low NOX burners are possible by 2012.' Conesville units 5 and 6 do not have advance NOx control and their 2007 to 2009 average annual NOx emissions are 5,172 and 4,838 tons, respectively. Yet they received NOx allocations of 2,855 and 2,808. It is not transparent as to what assumptions were made but it appears in order to maintain emissions commiserate with the allocations these units may need to be underutilized or install advanced controls, which was not the intent of this proposal. This analysis is also applicable to the ozone NOx season allocation. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.6]
Zimmer Unit 1 [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.6]
This unit is controlled by a wet scrubber installed in 1990 operating year-round. NEEDS identifies this scrubber with a 98% control efficiency yet the owner approximates a 91-93% efficiency is achieved and that it may be possible to optimize to 95%; however, 98% would not be achievable from this unit. The 2007 to 2009 average annual controlled SO2 emissions are 15,661 tons, yet they only received allocations of 5,775 tons in 2014. This would not be achievable without replacement of the wet scrubber which would be very difficult by 2014. [EPA-HQ-OAR-2009-0491-3747.1_NODA, pp.6-7]
NEEDS accurately identifies an SCR installed in 2004. The owner has operated the SCR continuously since 2009. However, this unit was allocated 13,515 tons of annual NOx but only 882 tons of ozone season NOx. Ozone season NOx emissions for 2009, when the SCR was being operated continuously, were 1,457 tons. It is not transparent as to what assumptions were made, but it appears unrealistic that this newer SCR could be optimized to a point to make up for a 40% reduction in NOx ozone season allocations compared to 2009 emissions. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.7]
Hamilton Unit 1 This unit does not have advance NOx control and the 2007 to 2009 average annual NOx emissions are 245 tons. Yet they received NOx allocations of 141 tons. It is not transparent as to what assumptions were made but it appears in order to maintain emissions commiserate with the allocations this unit, which serves a municipality, must be underutilized or install advanced controls, which was not the intent of this proposal. This analysis is also applicable to the ozone NOx season allocation. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.7]
Killen Unit 2 NEEDS accurately identifies an SCR installed in 2004. This unit was allocated 494 tons of ozone season NOx and 1,127 tons of annual NOx. Ozone season NOx emissions for 2009 were 901 tons and the 2007 to 2009 average ozone seasons NOx emissions are 1,393 tons. It is not transparent as to what assumptions were made, but it appears unrealistic that this newer SCR could be optimized to a point to meet the NOx ozone season and annual allocations. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.7]
Lake Road Unit 11 This unit is identified in NEEDS as having a capacity of 85 MW, and therefore subject to this program. However, this unit has a name plate capacity of 20.2 MW as confirmed by the owner. It should not be a subject source. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.7]
Kyger Units 1, 2, 3, 4 and 5 [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.7]
Currently these units are not controlled by an FGD. The owner is in the process of installing FGDs but, due to technically difficulties they do not anticipate installation will be complete by the 2014 deadline. However, it was assumed these FGDs would be installed based on their allocations. We wish to reiterate, as identified in our October 1, 2010 comments, that it may be difficult for some units to achieve the schedule, which has no case-by-case flexibility built in. [EPA-HQ-OAR-2009-0491-3747.1_NODA, pp.7-8]
NEEDS accurately identifies an SCR installed in 2003 for these units. The owner has operated the SCRs continuously since 2009. It is not transparent as to what assumptions were made, but it may difficult for these newer SCRs to achieve the NOx ozone season and annual allocations compared to 2009 emissions, which were low due to the economic down turn. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.8]
Lima Energy Unit 1 This unit received allocations although it does not appear to meet the criteria for consideration as an existing unit. The owner did begin some construction in late 2005 which was suspended in the middle of 2006. Significant additional construction will be necessary before this unit could begin operating. We believe it is more appropriate to treat this source as a new source. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.8]
Miami Fort Units 5-1, 5-2, 6, 7, and 8 Units 5-1 and 5-2 are not identified in NEEDS V4.10 but were identified in NEEDS V3.02, which was the basis for the unit level allocation$. These units are permanently shutdown. Although not transparent in the information provided for the new IPM modeling, it is assumed allocations provided to these units will not be in the final Transport Rule.  [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.8]
NEEDS accurately identifies an SCR installed in 2003 on units 7 and 8. The owner has operated the SCRs continuously since 2009. However, unit 7 was allocated 355 tons of ozone season NOx and 879 tons of annual ozone NOx. Ozone season NOx emissions for 2009, when the SCR was being operated continuously, were 520 tons. Likewise, unit 8 was allocated 368 tons of ozone· season NOx and 2,505 tons of annual ozone NOx. Ozone season NOx emissions for 2009, when the SCR was being operated continuously, were 442 tons. It is not transparent as to what assumptions were made and why there is such a disparity between annual NOx for each of these units. It appears unrealistic that this newer SCR on unit 7 could be optimized to a point achieve the allocations compared to 2009 emissions. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.8]
Muskingum River Units 1, 2, 3, 4 and 5 [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.8]
Currently these units are not controlled by a scrubber. The owner is required by a Consent Decree to retire, retrofit, or repower by the end of 2015. Based upon allocations it appears IPM has 'assumed' units 1 and 2 will retire prior to 2014 as no allocations were provided. Ohio EPA does not believe it is appropriate for U.S. EPA to use IPM to predict retirement and therefore eliminate allocations. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.8]
It appears based on allocations and documentation that the IPM modeling has assumed unit 5 will install an FGD by 2011. The owner has indicated an FGD will not be on line in 2012, and that it may be difficult by 2014. It is not apparent if the updated modeling will affect allocations to account for the FGD not being installed in 2011. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.9]
Units 1 through 4 do not have advanced NOx control. The 2007 to 2009 average annual NOx emissions range from 2,890 to 3,399 tons. Yet the annual NOx allocations range from 1,842 to 2,047 tons. It is not transparent as to what assumptions were made but it may be difficult, if not impossible, to meet the annual allocation budget without installation of more advanced controls. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.9]
Niles Units 1 and 2 [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.9]
Units 1 and 2 are both 120 MW units. NEEDS correctly identifies a wet scrubber was installed in 1995 on unit 1. Unit 1 has 2007 to 2009 average annual controlled SO2 emissions of 6,486 tons while allocations are set at 4,925 tons in 2012 and 870 tons in 2014. Unit 2 does not have advanced SO2 control. Unit 2 has 2007 to 2009 average annual controlled SO2 emissions of 5,717 tons while allocations are set at 2,913 tons in 2012 and 1,852 tons in 2014. It appears from these allocations IPM is assuming an FGD will be installed on unit 2. It is not transparent as to what assumptions were made, and why the disparity between 2014 allocations for these units. It appears unrealistic that the scrubber on unit 1 could be optimized to a point to meet the 2014 allocations. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.9]
Orrville Unit 12 [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.9]
This unit is identified in NEEDS as having a capacity of 28.7 MW, and therefore subject to this program. However, this unit has a name plate capacity of 25.0 MW as confirmed by the owner. It should not be a subject source. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.9]
Picway Unit 5 (identified as unit 9 in NEEDS) [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.9]
Based upon allocations it appears IPM has 'assumed' this unit will retire prior to 2012 as no NOx allocations were provided or 2014  SO2 allocations (although 2012  SO2 allocations were provided). Ohio EPA does not believe it is appropriate for U.S. EPA to use IPM to predict retirement and therefore eliminate allocations. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.9]
R.E. Burger Units 5, 6, 7 and 8 [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.9]
Units 5 and 6 did not operate in 2009 due to the economic down turn. Therefore, it appears 2012 SO2 allocations were based upon IPM rather than historical emissions during periods of running. For example, 2007 SO2 emissions were 723 (unit 5) and 671 (unit 6) tons.  SO2 allocations for each of these units during 2012 are 7,793 tons. This analysis is also applicable to the annual and ozone NOx season allocations. [EPA-HQ-OAR-2009-0491-3747.1_NODA, pp.9-10]
Units 7 and 8 are accurately identified as converting to biomass. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.10]
Gorsuch Units 1, 2, 3 and 4 [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.10]
The owner, AMP Ohio, has signed a Consent Decree that requires shutdown of the facility by the end of 2012. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.10]
W.H. Sammis Units 1, 2, 3, 4, 5, 6 and 7 [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.10]
These units are currently operating under a Consent Decree agreed to by U.S. EPA. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.10]
Lastly, Ohio EPA would like to reiterate an October 1, 2010 comment made regarding the Proposed Transport Rule: [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.10]
Ohio EPA has concerns regarding the methodology to determine allocation budgets based on actual emissions. U.S. EPA must use appropriate years representative of normal operation when calculating allocations based upon actual emissions. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.10]
Ohio EPA is concerned with what appears to be an arbitrary decision; using quarter 4 of 2008 and quarters 1, 2 and 3 of 2009 to establish 2012 budgets1 - both of which were low demand years yet U.S. EPA believes this more accurately represent emissions from these sources. It appears U.S. EPA is not recognizing the nation, and particularly the Midwest, was in a severe economic downturn during in 2008 and 2009. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.10]
Ohio's budget, and unit specific allocations, are being established based on a specific period of time, a time of economic crisis, without any future adjustment to being considered to those base budgets for improvement in economics, and therefore, demand. The variability limits are not sufficient to make up for this situation of severely low demand years in the base budgets. In addition, some units were not operating for some or all of this period in order to install controls to address CAIR. While it appears from the technical support documents U.S. EPA intended to substitute other quarters in the calculations when emissions were zero; however, if emissions were obviously drastically under previous quarter emissions (e.g., a unit may have operated for only a small part of a quarter) there was no such adjustment. In many cases, units are allocated budgets for 2012 and 2013 that assumes demand is as low as it was in 2008 and 2009. Such units may be forced to be underutilized if demand does improve. [EPA-HQ-OAR-2009-0491-3747.1_NODA, pp.10-11]
Ohio EPA believes it is imperative U.S. EPA take the time to ensure the appropriate historical emissions and assumptions are used when establishing allocations of the budgets as these allocations are not adjusted in the future. Ohio EPA believes it would be appropriate to use a similar methodology used when establishing the variability limits; averaging a series of years. The variability limit is based on the average heat input over several years but starting budget allocations account for emissions in one arbitrary year only and in this case, a low demand year. A multi-year averaging approach should be used, continuing to account for controls put in place since such time, and making appropriate corrections and substitutions for periods of non (or very low)- operation. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.11]
This comment applies to the following units' emissions: [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.11]
Ashtabula unit 1: all quarters used to establish the 2012 SO2 allowances were well below historical emissions due to the economic down turn. Especially 02 and 03 of 2009. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.11]
Eastlake units 1 to 4: 01 and 02 SO2 emissions were significantly below historical emissions due to the economic down turn. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.11]
Hamilton unit 9: all quarters used to establish the 2012 SO2 allowances were well below historical emissions due to the economic down turn. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.11]
Lake Shore unit 18: all quarters used to establish the 2012 SO2 allowances were well below historical emissions due to the economic down turn. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.11]
Muskingum River units 1 to 4: all quarters used to establish the 2012 SO2 allowances were well below historical emissions due to the economic down turn. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.11]
Niles units 1 and 2: all quarters used to establish the 2012 SO2 allowances were well below historical emissions due to the economic down turn. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.11]
O.H. Hutchings units H-1 to H-6: all quarters used to establish the 2012 SO2 allowances were well below historical emissions due to the economic down turn. Also, some of the smaller units are peaking units and given the 2014 modeled allocations, the 2012 SO2 allocations do not appear to be sufficient if additional utilization is needed. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.11]
Picway unit 5: all quarters used to establish the 2012 SO2 allowances were well below historical emissions due to the economic down turn. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.11]
W.H. Sammis units 3 and 5: 02 emissions were very low due to the tie in of the scrubber. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.11]
Bayshore units 2 to 4: all 2009 quarters used to establish the 2012 SO2 allowances were well below historical emissions due to the economic down turn.[EPA-HQ-OAR-2009-0491-3747.1_NODA, p.11]
Tennessee Valley Authority (TVA)
While TVA submitted substantial comments on the Proposed Rule published in the Federal Register on August 2, 2010, it would only be fair for EPA to provide the public another opportunity to submit comments on the next version that will be substantially different from the proposed version. Furthermore, the NODA lists additional planned updates EPA is going to undertake in future to support the final rulemaking prior to issuance. This constantly- moving-target approach to rulemaking makes it almost impossible to formulate meaningful comments for lack of an opportunity to review the comprehensive proposal. Accordingly, TVA encourages EPA to carefully assimilate all data and revised modeling results, and then re-propose the rule with an aligned set of technical supporting documentation, providing additional opportunity for meaningful public comment. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.1]
Issue: EPA's NEEDs Version 4.10 has a errors concerning installed TVA controls. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.1]
While the database correctly lists an SNCR for Johnsonville Unit 1, revisions are needed to Johnsonville Units 2, 3 and 4. include operating SNCRs for John Sevier units 1, 2, 3 and 4 and [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.2]
Shawnee 1 does not have an SNCR. (That SNCR was only for purposes of d demonstration, and was subsequently removed from service.) [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.2]
The database incorrectly assumes that both Wet Scrubbers and SCRs will be installed on John Sevier Units 1-4 in 2011. TVA does not have any such controls under construction... [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.2]
Issue: In both the NEEDs Version 4.10 database and the 2014 trade case, the EPA has two future plants listed as being constructed within the TVA region in Kentucky. The units are listed with the plant names "TVAK_Ky_Coal steam" and "TVAK_Ky_Combustion TurbineTurbine". [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.2]
TVA Comment: TVA does not have any plans to construct coal steam plants or combustion turbine plants in Kentucky. These units should be removed from the database or ascribed to some other utility that may be actively planning to construct these units. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.2]
Issue: The EPA NEEDs Version 4.10 database list various TVA plants as being capable of burning both 100% bituminous and 100% sub-bituminous coal. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.2]
TVA Comment: Gallatin units 1-4 are the only TVA units capable of routinely burning 100% sub-bituminous (PRB) coal. The NEEDs Version 4.10 database incorrectly lists the following units as being capable of burning 100% sub-bituminous coal: Allen 1-3, Colbert 1-5, Johnsonville 1-10, Kingston 1-9, Paradise 1-3, Shawnee 1-10, and Widows Creek 1-8. Except for the Gallatin plant, TVA recommends the NEEDs Version 4.10 database be modified to remove sub-bituminous coal as a "Modeled Fuel" for TVA's plants. (See Comment G herein for additional information on sub-bituminous coal use at TVA plants.) [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.2]
Issue: EPA's 2014 Limited trading case erroneously assumes Widow Creek Units 1-6 will be retired in 2014. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.2]
TVA Comment: TVA has not announced plans to retire Widows Creek Units 1-6. TVA has announced plans only to "idle" these units, in a phased approach, between now and 2015. TVA defines "idling" as temporarily removing a unit from service until needed for economic dispatch. Such removal from service could be temporary, depending on other generating issues such as gas prices, nuclear plant performance, etc. Allocations should not be zeroed out to sources that EPA unilaterally, without any basis, decides should be retired. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.2]
Moreover, EPA's use of "retirements" as a "control technology" for reducing SO2 or NOx emission is not a credible alternative. It does not appear that the costs of retiring units have been properly integrated into the marginal cost curves, as the marginal cost for retiring a unit would be much higher than $2,000/ton for SO2 or $500/ton for NOx. The inclusion of such retirements in the EPA analysis seriously undermines the credibility of EPA's IPM-based marginal cost approach.  [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.3]
Accordingly, all retirement assumptions should be removed from the Proposed Rule's trading case assessments, unless EPA has been officially notified that a utility intends to permanently retire a specific EGU and a fixed prior retirement date has been assigned. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.3]
Issue: The net heat rates listed for TVA's coal plants in EPA's NEEDs Version 4.10 are approximately 2.3% lower, on the average, than recent historical TVA levels. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.3]
TVA Comment: The net heat rates listed in the NEEDs Version 4.10 database are low compared to average annual 2006-2008 heat rate derived from TVA's "Data Fuser" database. Larger errors were observed for TVA's Alabama units, where the EPA average net heat rate was 4.3% lower than TVA historical rates. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.3]
TVA recommends the EPA use of the TVA net heat rate data for 2006-08 as listed in Attachment A [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.3; See p.7 of this comment summary for Attachment A]
Issue: The EPA assumes NOx emission rates for both controlled and uncontrolled units that are not achievable in the long term. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.3]
TVA Comment: The EPA estimated NOx rates for controlled SCR units tend to be low and track the performance of ozone season SCR operations prior to the CAIR requirement for annual operation. The EPA rates tend to seriously overestimate TVA's SCR capabilities when the units are in year-around continuous operation. Example data for TVA's SCRs are provided in Attachment B. [;See p.8 of this comment summary for Attachment B] This data shows that the rates the EPA's used are an average of 0.006 lb/Mbtu lower than the rate TVA actually achieved in the 2006-2008 timeframe. Further, 2009 annual data shows TVA could not maintain the relatively low "ozone season" rates when compelled to operate round the year. As shown in Attachment 3 [;See p.9 of this comment summary for Attachment C] , the achievable annual rate for NOx was an average of 0.0149 lb/Mbtu higher than the estimated EPA rates. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.3]
It appears the EPA is using rates based on SCR guaranteed control efficiencies. These "guaranteed" rates are "idealized" in the sense that the rates reflect the performance of new units undergoing steady state short term acceptance testing and do not reflect sustainable rates. Sustainable SCR rates vary from the "guaranteed" standard due to practical considerations such as process variability during periods of startup, shutdown, and load change. In addition, the SCRs experience normal equipment deterioration and catalyst deactivation which further reduce performance until scheduled maintenance can be performed. [EPA-HQ-OAR-2009-0491-3769.1_NODA, pp.3-4]
For units with existing post combustion NOx controls, TVA recommends using the average of annual unit specific NOx rates for calendar year 2009, since annual NOx reductions were not achieved for most units until January 2009. (TVA did operate SCRs in 2008 from May thru December.)  [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.4]
For units where future post-combustion NOx controls are projected to be needed, TVA recommends nominal annual rates no lower than 0.08 lb/MM-Btu, considering site specific issues, SCR inlet gas an ammonia injection distribution issues with changing loads, and startup/shutdown issues where units are not operating with gas temperatures high enough for ammonia injection into SCRs. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.4]
For units with no post combustion NOx controls (no SCR, SNCR, ect.), TVA recommends EPA use unit specific three year average annual NOx rates from calendar year 2006-2008. Averaging emission rates over multiple years for units without SCR or SNCR minimizes the distorting effects of NOx fluctuations associated with operational boiler combustion or burner problems during specific time periods for individual plants. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.4]
Attachment C [See p.9 of this comment summary for Attachment C] provides what TVA believes are sustainable NOx rates for year round operation of TVA's units. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.4]
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. Data in the NEEDs Version 4.10 database indicates that TVA's units used sub-bituminous coals that have unrealistically low SO2 rates. These rates are as low as 0.58 lb/MM-Btu.
TVA Comment: Although the sub-bituminous SO2 rates used by NEEDs Version 4.10 database has increased compared to the NEEDs Version 3.02 database, these rates continue to be unrealistically low and often reflect the unrealistic assumption that TVA units can use 100% sub-bituminous coal. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.4]
As indicated in TVA's October 1, 2010, comments to the Transport Rule, EPA's assumed SO2 rates are not achievable long term for TVA's units (without FGD) when burning low sulfur coal. Coal sulfur content is not homogenous even in the same seam, and coal suppliers will not guarantee sulfur contents that support EPA's assumed rates on TVA's uncontrolled units. [EPA-HQ-OAR-2009-0491-3769.1_NODA, pp.4-5]
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 cost-effective means of achieving low sulfur coal fuel switches on its unscrubbed units. 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-2009-0491-3769.1_NODA, p.5]
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 form 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 earliest most of these fuel switch changes could be implemented is mid-2015. Some changes would likely require additional time. Ironically, capital upgrades that enable the use of lower sulfur fuel would present an impediment to further clean air controls on our plants as multiple design changes complicate the permitting and design of major control equipments. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.5]
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 o begin before mid 2013 where extensive equipment changes are not required. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.5]
For SO2 rates, TVA recommends that EPA use, at a minimum, unit-specific three year average annual SO2 rates from calendar years 2006-2008 with adjustments for controls added since 2006. Averaging emission rates over multiple years minimizes the distorting effects of SO2 fluctuations resulting from both the variations in coal deliveries over limited time periods and the variations due to operational problems at individual plants. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.6]
For units with new SO2 scrubbers built after 2006, TVA recommends EPA assumed rates for SO2 be modified to be no less than 0.15 lb/MM-Btu for units expected to burn high or medium sulfur coal and 0.08 lb/MM-Btu for units burning low sulfur coal (PRB). SO2 rates on controlled units can be found lower than these stated rates, but considering normal equipment deterioration and reliability between maintenance opportunities and lack of equipment sparing typical for scrubbers designed for cap and trade programs, these rates are the most realistic annual average sustainable rates TVA can recommend for new SO2 controls. These rates allow for the following realistic scenarios: [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.6]
Wet FGD for units burning high sulfur coal (approximately 5 lb SO2/MM-Btu) to be designed for 98% removal for short term performance tests, but to operate with a small degree of upsets with annual average SO2 removal down to 97% (achieving a 0.15 lb SO2/MM-Btu rate). [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.6]
Wet or dry FGD for units burning medium sulfur coal (approximately 2.5 lb SO2/MM-Btu) to be designed for 95% removal for short term performance tests, but to operate with a small degree of upsets with annual average SO2 removal down to 94% (achieving a 0.15 lSO2/MM-Btu rate). [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.6]
Dry FGD for units already burning 100% PRB (with an SO2 rate around 0.80 lb SO2/MM-Btu) to be designed for 95% removal for short term performance tests, but to operate with a small degree of upsets with annual average SO2 removal down to 90% (achieving a 0.08 lb SO2/MM-Btu rate). Annual average 90% removal is typical of dry scrubber spray dryer designs requiring brief periods of time with no SO2 removal, while a unit's atomizer is pulled for maintenance. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.6]
Attachment C [See p.9 of this comment summary for Attachment C] provides yearly SO2 emission rates that TVA believes are achievable by 2014 for all of  TVA's coal fired units. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.6]
Utility Air Regulatory Group (UARG)
The tight implementation schedule that EPA proposes is in effect made even tighter by the fact that EPA is already changing the terms of the proposed rule. As discussed above, on September 1, 2010, midway through the public comment period on the proposed rule, EPA published its NODA, announcing information that in effect will result in substantial changes to the proposed rule and noting that further changes are to come. Among other things, the NODA announced the release of (i) an updated version of the National Electric Energy Data System ("NEEDS"), which provides the unit-level EGU characteristics used as inputs for the Integrated Planning Model ("IPM"), (ii) results of new base case and policy case modeling runs using an updated version of IPM, and (iii) results of new base case and policy case modeling runs using an updated version of IPM and including data from the Energy Information Administration's Annual Energy Outlook 2010 natural gas resource assumptions. 75 Fed. Reg. at 53614/2-3. It also announces the release of "[a] summary of other planned input updates to be implemented in the final rulemaking." 75 Fed. Reg. at 53614/3. The data released in connection with the NODA will, when applied by EPA, change substantially the statewide budgets and allowance allocations for 2012 and the allowance allocations for 2014, and there will presumably be additional changes leading up to promulgation of a final rule based on the planned input updates that EPA says will be implemented later. [EPA-HQ-OAR-2009-0491-2756.1, pp.17-18]
The scope of the impact that the new data will have is clear at a glance. For example, the parsed file that EPA released in connection with the proposed rule, showing the initial IPM run, indicates that IPM projected about 23,723 MW of new coal generation from unidentified plants yet to be built in 10 different states. See IPM Run File "TR SB Limited Trading", available at http://www.epa.gov/airmarkets/progsregs/epa-ipm/transport.html. By contrast, the updated parsed file that EPA added to the docket in connection with the NODA appears to indicate that IPM projected only about 2,001 MW of new coal generation from unidentified plants yet to be built in four states. See Docket ID No. EPA-HQ-OAR-2009-0491-0312, IPM Run - TR SB Limited Trading v.4.10 - 2014 Parsed File (Sept. 1, 2010), available at http://www.regulations.gov/search/Regs/home.html#docketDetail?R=EPA-HQ-OAR-2009- 0491. This is likely to be merely one indicator of the substantial changes in EPA's proposal that will result from use of the NODA information, and the impact of the future changes that EPA anticipates remains to be seen. Clearly, there is no way for sources to begin planning for compliance based on the information that EPA has provided in the docket. [EPA-HQ-OAR-2009-0491-2756.1, pp.18-19]
On September 10, 2010, EPA denied UARG's August 19, 2010 request for an extension of the comment period on the PTR, and on October 5, 2010, the Agency denied UARG's September 10, 2010 request for a comment deadline extension for the NODA as well as for the PTR itself.1 In light of the significant differences between the data on which EPA based (or says it based) the PTR and the data EPA released later pursuant to the NODA, EPA should withdraw the PTR, revise the PTR using the NODA data or whatever other data EPA may now deem most appropriate -- while addressing as well the many other deficiencies discussed in UARG's comments on the PTR and the present comments -- and publish a complete, properly supported proposal for public comment with an adequate comment period. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.3]
The Comment Period on the NODA Is Inadequate To Allow for Adequate Public Review of the Extensive Material Associated with It. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.4]
Despite this large quantity of new information, the NODA provides only an additional 14 days for public comment beyond the comment deadline that UARG and other members of the public were required to meet for the PTR. This does not allow enough time for a comprehensive review of the new material provided, much less enough time to analyze the material, determine its implications for the underlying rule, and develop and submit complete comments. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.4]
The substantial impact of the NODA on the Proposed Transport Rule was apparent in recent comments by EPA representatives. During an EPA webinar held on September 22, 2010, in response to a question regarding which aspects of the PTR would be affected by the NODA, a representative of EPA's Clean Air Markets Division indicated that the information contained in the NODA would affect, among other things, EPA's "significant contribution" analysis, the creation and evaluation of the "cost curves" in EPA's multi-factor analysis for determining emission reduction obligations under the PTR, and the cost-effectiveness "breakpoints" for emission controls that EPA will select based on the cost curves and the multi-factor analysis. This EPA representative acknowledged that the NODA may result in changes in EPA's determinations of which states are regulated under the Transport Rule, which states will be classified as group 1 rather than as group 2 states with respect to additional SO2 emission control obligations in the second phase of the program, the emission budgets to which regulated states will be subject, and unit-level allowance allocations. These matters are far from tangential to EPA's development of the Transport Rule. To the contrary, they go to the very heart of the rulemaking. Yet, EPA provided only 14 days for public comment on the NODA beyond the comment period on the PTR. [EPA-HQ-OAR-2009-0491-3773.1_NODA, pp.4-5]
Equally important, as discussed below, EPA has unreasonably withheld information necessary to allow UARG, members of UARG, other members of the public, and states to develop and provide meaningful and comprehensive comments on the NODA and on the Proposed Transport Rule itself. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.5]
Despite the Quantity of New Information Added to the Docket Pursuant to the NODA, EPA Has Failed To Provide Data Necessary To Allow Meaningful Comment on That Information. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.5]
The problems associated with the unreasonably abbreviated period EPA has provided for comment on the voluminous and complex information issued pursuant to the NODA are exacerbated by EPA's failure to provide much of the information necessary to evaluate and meaningfully comment on the NODA. The docket omits much of the information that is necessary to properly evaluate the nature and extent of the changes that are likely to the PTR based on the addition to the docket of the data listed in the NODA. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.5]
In support of the PTR, EPA provided in the docket the results of 48 IPM runs. These runs provided the public at least some basis for evaluating and commenting on the various steps in EPA's process of developing unit-specific allowance allocations. In contrast, in support of the NODA, EPA provided the results of only eight IPM runs. Of these eight runs, four relate to an entirely new alternative proposal based on the Energy Information Administration's ("EIA") Annual Energy Outlook 2010 natural gas resource assumptions -- leaving only four IPM runs that constitute a repeat of runs used to support the PTR. The paucity of IPM runs that EPA has provided with the NODA, using the revised National Electric Energy Data System ("NEEDS") inventory and IPM v.4.10 frustrates the public's ability to comment knowledgeably on the effects on the PTR of the updated NEEDS database and IPM platform. See section VII infra. Despite EPA's limited use of the revised NEEDS inventory and IPM model in the allowance allocation step of its analysis,2 EPA still has not provided the IPM runs necessary for electric generating companies and others, including states, to understand and comment knowledgeably on the impact of the NODA on statewide emission budgets and unit-specific allocations. [EPA-HQ-OAR-2009-0491-3773.1_NODA, pp.5-6]
In addition to failing to provide many critical updated IPM runs using the NODA information, EPA has failed to provide key summary tables that it did provide in conjunction with the PTR. The key summary tables provided in support of the PTR include the "Allocation Table - Technical Support Document for the Transport Rule - State Budgets, Unit Allocations, and Unit Emission Rates" (EPA-HQ-OAR-2009-0491-0057.1) and the "Detailed Unit-Level Data for State-Budgets, Unit Allocations, and Unit Emission Rates" (EPA-HQ-OAR-2009-0491-0074.1). In the PTR, these tables provided important guidance regarding a unit's allowance allocations under the PTR and provided electric generating companies at least some ability to evaluate the accuracy of EPA's assumptions (or apparent assumptions) with respect to their individual units. For reasons that UARG explained in its comments on the PTR, EPA's calculation of allowance allocations in the PTR was hardly a model of clarity. But EPA's failure to provide with the NODA tables comparable to the above-described PTR tables leaves UARG members and other electric utilities and electric generating companies even further in the dark about what their unit allowance allocations will be, based on the outcome of EPA's 2012 allowance allocation determinations using the updated NEEDS database and the updated IPM platform. [EPA-HQ-OAR-2009-0491-3773.1_NODA, pp.6-7]
Perhaps the single most important file EPA did not provide with the NODA was a file comparable to the PTR "Detailed Unit-Level Data for State-Budgets, Unit Allocations, and Unit Emission Rates" (EPA-HQ-OAR-2009-0491-0074.1) (an Excel spreadsheet entitled "BADetailedData.xls"). Without this file, electric generating companies cannot determine the impact of the NODA on their allowance allocations. Although EPA did provide a new "IPM Run  -  TR Base Case v.4.10  -  2012 Parsed File" and a new "IPM Run-TR SB Limited Trading v.4.10  -  2014 Parsed File," without critically important additional information, electric generating companies cannot calculate the SO2 or NOx allowance allocations for their units for 2012 or (where applicable) 2014. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.7]
EPA made "adjustments" to the IPM-projected unit-specific emissions for 2012, and provided these adjustments in the BADetailedData.xls file for the PTR. See BADetailedData.xls at the "Adjustments" tab. In addition to providing these EPA adjustments to the IPM results, the BADetailedData.xls file provided the projected unit-specific operating parameters (e.g., heat rates, emission rates, and controls) in one location, allowing electric generating companies to check EPA's assumptions and better understand how EPA calculated each unit's allocations. The BADetailedData.xls file also clarified whether a state's annual 2012 NOx and SO2 unit allocations and seasonal NOx unit allocations were based on reported data or on the 2012 IPM projections. As described in EPA's Technical Support Document ("TSD") on "State Budgets, Unit Allocations, and Unit Emissions Rates" ("State Budgets TSD"),3 EPA based the 2012 budgets (annual SO2 and NOx and seasonal NOx) on the lower of the recent actual emissions (essentially the 2009 reported emissions for existing units, aggregated by state) or the 2012 IPM projected base case emissions at the state level. In the BADetailedData.xls file, EPA indicated which emission amount was lower for each state and, thus, whether the 2009 "reported" emission amount or the 2012 "projected" emission amount served as the basis for the allowance allocations in that state. Without the BADetailedData.xls file, it is not possible to determine from the NODA the statewide budgets and the unit allowance allocations for 2012.4 EPA should not proceed further with this rulemaking until it has provided this critical information for public review and comment. [EPA-HQ-OAR-2009-0491-3773.1_NODA, pp.7-8]
In addition to not providing information needed to evaluate the effects of the NODA on state budgets and unit allowance allocations, EPA states in the NODA that it intends to change the NOx emission rates used in its calculations again before it takes final action in this rulemaking: [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.8]
EPA intends to update the NOx rates for fossil-fuel fired units in the final rule to reflect the more recent 2009 data. IPM v.4.10 and the previous version of IPM used for the Proposed Transport Rule analysis relied on 2007 unit level NOx rates. The updated NOx rates will more accurately portray the unit level control installations that have occurred at power plants during the past several years. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.9]