First, EPA changed its allocation methodology to be based on historic heat input and emissions data that is generally reported by the sources' DR who testifies to its accuracy and completeness.  This change was in response to comments that expressed concern/disagreement about the IPM unit level projected emissions on which the proposed allocations were based.  By switching to a historically-data based methodology, the degree to which any discrepancy between a units actual future operation and its projected future operation would impact the unit's allocation is greatly diminished.  EPA recognizes that IPM is a dynamic linear programming model that generates optimal decisions under the assumptions of perfect foresight and results in a least cost method of meeting demand.  However, invariably, there will be discrepancies between IPM unit level projections and a unit's actual future operations due to non-economic or other variables that IPM does not capture.  While at the state and regional level, the discrepancies are small and random and thus do not result in biases.  However, their impact at the unit level may be significant and this was one of the drivers behind switching to an allocation method based on historic data. Changing the methodology also either corrected or obviated the need to change issues that some commenters raised about incomplete or incorrect data in the allocation worksheets. For more information on the allocation method, see Preamble Section VII D.
Second, EPA reviewed the comments and has made significant updates to its IPM v.3.02 modeling used at proposal.  These updates include changes to both the more general IPM assumptions (e.g., gas price assumptions) and specific unit level assumptions (e.g., that current retrofit status at a unit).  These updates were made to the IPM model, and the updated versions (EPA IPM v.4.10) was used for all the final rule analysis.  In regard to unit specific adjustments, EPA did not manually adjust projected unit level modeling outputs, but instead made unit level updates to its NEEDS database used as a model input that impacted the unit level model outputs.   Some of the most frequent general IPM comments that were addressed in the updates are: FGD removal efficiency was adjusted for new retrofits, and for existing retrofits it was indexed to historic performance at the unit.  Additionally, many comments were focused on a source's ability to switch coals.  EPA modified its modeling to better reflect the cost and feasibility of switching and blending coals.  For more detailed discussion of EPA IPM v.4.10 assumptions and assumption updates, see the EPA IPM v.4.10 documentation and the "Transport Rule IPM Assumptions Response to Comments" in the Appendix.
These two adjustments, updates to the modeling and updates to the allocation methodology, work in concert to comprehensively address many of the concerns expressed by commenters on their unit level projections and allocations.
EPA posted the signed version of the Proposed Transport Rule to the web when it was signed on July 6, 2010.  The proposal was published in the Federal Register on August 2, 2010.  EPA held three public hearings on the rule on August 19, 2010 (Chicago, IL), August 26, 2010 (Philadelphia, PA), and September 1, 2010 (Atlanta, GA) and the public comment period closed on October 1, 2010.  The comment period was thus open for 60 days from the date of publication in the Federal Register and 90 days from the date the rule was widely disseminated to the public via publication on the web.  EPA posted the signed version of the first Transport Rule Notice of Data Availability (NODA) (IPM) to the web when it was signed on August 25, 2010.  The first NODA was published in the Federal Register on September 1, 2010, and the public comment period closed on October 15, 2010.  The comment period was open for 45 days from the date of publication in the Federal Register and 52 days from the date the NODA was widely disseminated to the public via publication on the web on August 25, 2010.  The second NODA (addressing emissions inventories) was published in the Federal Register on October 27, 2010 and the public comment period closed on November 26, 2010.  The comment period was open for 30 days from the date of publication in the Federal Register (and was widely disseminated to the public via publication on the web at the same time).  The third NODA (allocations and related matters) was published in the Federal Register on January 7, 2011 and the public comment period closed on February 7, 2011.  The comment period was open for 30 days from the date of publication in the Federal Register and 38 days from the date the NODA was widely disseminated to the public via publication on the web on December 30, 2010.

EPA provided an adequate opportunity for public comment on the proposal and all three NODAs.  EPA complied with the procedural requirements of CAA section 307(d) including those regarding the length of the comment period.  EPA also received several hundred substantive comments during the comment period.  Many of these contained detailed data and analyses.   The volume and depth of the comments received suggests that the opportunity for public comment was adequate.  The fact that more comments could have been provided had the comment periods been extended, does not establish that the comment period was inadequate or not consistent with the procedural requirements of section 307(d).  EPA is mindful both of its obligation to provide an opportunity for public comment and of its obligation to proceed with this rule in a timely manner.
For comments related to the compliance deadline, please see Preamble Section VII C. EPA notes that SO2 and NOX trading are well established practices under ARP, NBP, and CAIR, with an existing knowledge base of compliance options and how likely a entity is to have and need allowances. Additionally, EPA proposed the Transport Rule last July. Finally, the compliance programs start January 1 and May 1, 2012 but the coverage of emissions with allowances awarded and purchased is much later, leaving ample time for companies to adapt.
Finally, EPA notes that as stated in NODA3, the purpose of the NODA was to provide the proportion of a state budget that units would receive under the various methodologies, not the exact allocation that each unit would receive.
Organization: Tenaska, Inc.
Comment:
Tenaska, Inc.
Tenaska is concerned that EPA's preferred allocation scheme provides insufficient flexibility and could result in: (1) an allowance market without the liquidity necessary for Tenaska to comply with the generation obligations of these contracts; and (2) decreased growth in the use of natural gas. As explained further in these comments, Tenaska believes greater flexibility, specifically initial allocation of allowances based on heat input, periodic reevaluation and readjustment of allowance allocations, and an opt-out provision for very low-emitting sources, are necessary to address market dynamics and avoid unintended adverse consequences. [EPA-HQ-OAR-2009-0491-3705, p.2]
Response:

Thank you for your comment.

V.D.2.b.i. Comments on Allocations Data/Corrections to Allocations Data

Organization: American Electric Power
Comment:
American Electric Power
Transmission/Black Start with Retirements
AEP's current transmission grid restoration plan is built around the control functionality of its smaller subcritical unit turbines successfully load rejecting during a system or national electrical grid emergency. This functionality is premised around our fleet's subcritical generators that are in operation at the time of emergency, needing to successfully separate, or load reject from a voltage decaying grid. Units that have successfully load rejected will remain lb, only generating enough to support their own auxiliary loads, until at such time, they are advised to re-parallel in a systematic manner in an effort to re-energize the electrical transmission grid. All of AEP's 18 subcritical units capable of automatic load rejection are now being threatened by the currently proposed Clean Air Transport Rule, and thus facing probable unit retirement. The economics of localized transmission constraints and ancillary services provided by ALR and blackstart units should be included in future modeling scenarios and reviewed with increased scrutiny, particularly as individual units are selected for retirement. [EPA-HQ-OAR-2009-0491-2665.1, p.23] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.8]
Response:
EPA finds that the commenter identifies no specific basis on which the Transport Rule negatively affects a utility's ability to maintain "black start" units.  EPA notes that the Agency does not "select" any units for retirement.  While it is possible that EPA's power sector modeling may project a cost-effective retirement of a unit that a utility currently maintains for ancillary services or as a black start unit, the Transport Rule in no way constraints the utility's ability to determine whether to operate or retire such a unit in real-life compliance with the rule's state emission budgets.  As explained in the Reliability and Resource Adequacy Final Rule TSD, EPA's power sector modeling projections are entirely consistent with reliable operation of the power grid, and because EPA is not basing any individual unit's compliance requirements off of that specific unit's projected behavior, it is illogical and incorrect for the commenter to assert that the Transport Rule impairs in any way a utility's capacity for maintaining reliable grid operations while also complying with state emission budgets.  Furthermore, EPA explains in the Allowance Allocation Final Rule TSD that the economic determination of unit dispatch will reflect the market value of emitting (i.e., the allowance price) regardless of whether the relevant allowances were initially allocated to that unit, and notwithstanding that important point, EPA is basing existing unit allocations under the FIPs on historic data, which renders any specific existing unit's projected behavior moot insofar as allowance allocations are concerned.
Birchwood Power Partners, L.P.
A. EPA's Proposed Allocation of Annual NOx Allowances for Birchwood is Insufficient to Meet Pre-Recessionary Demand
Birchwood Power is concerned that the number of allowances EPA has proposed to allocate to it for annual NOx emissions may be insufficient to meet its contractual demand in years when the facility is called to dispatch as frequently as it was prior to the recession. According to the Proposed Transport Rule, EPA has proposed to allocate 676 tons of annual NOx allowances to Birchwood Power. See Technical Support Document, State Budgets Unit Allocations, and Unit Emissions Rates, EPA Office of Air and Radiation, July 2010, Appendix: Table of Unit-Level Allocations and Rate Limits. This is less than Birchwood Power's reported NOx emissions in two of the past five calendar years: in 2008, Birchwood Power's annual NOx emissions were 678.6 tons and, in 2005, they were 741.4 tons. While the proposed number of allowances would have been sufficient to cover emissions during other years (including 2009, when utilization was significantly lower throughout the country due to the recession), Birchwood Power anticipates that demand for electricity will return to pre-recessionary levels, and it could again be called to dispatch at levels that will require the purchase of additional NOx allowances. Table 1 below shows Birchwood Power's annual NOx emissions, heat input, operating hours and capacity factor for calendar years 2005 through 2010 (year to-date). While the year 2009 shows a substantial reduction in dispatch, Birchwood has already started seeing an increase in demand during 2010. [EPA-HQ-OAR-2009-0491-2706.1, pp.2-3]
[Table 1 can be found on page 3 of this comment.]
Response:
EPA has finalized an allowance allocation methodology that is different from the one proposed and may address some of Birchwood's concerns.  Specifically, the final allocation approach is based purely on historic data and used a larger, five year baseline to determine a representative "heat input".  Because the approach takes the three highest years of data among a five year baseline, it could potentially be selecting pre-recessionary years for the Birchwood unit if reported heat input were higher during those years.  However, EPA also notes that the purpose of allowance allocation is to implement the state emission budgets that reflect the elimination of significant contribution.  The purpose is not to allocate in a manner that fully covers historic emission levels for all sources.  Doing so would not result in a program that achieves the necessary emission reductions.  Therefore, EPA emphasizes that some sources will have allocations that are less than their historic emission levels and will comply with Transport Rule budgets through allowance purchase or other compliance options discussed in section VII.C.  See section VII.D of the preamble for more discussion on the final Transport Rule allowance allocation approach under the FIP.
Organization: City of Ames, Iowa
Comment:
City of Ames, Iowa
3) There is no allocation for SO2 and NOx for GT2 (ORIS Code 6463), yet we need to operate this unit for peaking and system reliability purposes, and most likely will need to do so more as native demand (load growth) increases.
4) Why is there no ozone season NOx allocation for any of our units (Unit 7, Unit 8, and GT2)? [EPA-HQ-OAR-2009-0491-2769, p.2]
21) The allocations in 2012 for SO2 for Unit 7 and Unit 8 are so restrictive, they would limit the capacity factors (CF) for Unit 7 at 55% and for Unit 8 at 42%. For our utility, these units are considered baseload units. U.S. EPA's own documentation for new coal steam units uses a default capacity of 84% for SO2 and NOX annual, and 89% during the NOx ozone season. The annual NOx allocation for Unit 8 is also so restrictive, that it would limit Unit 8's capacity factor at 47%. Once again, U.S. EPA's own documentation for new coal steam units uses a default capacity factor of 84% for annual SO2 and NOx, and 89% during the NOx ozone season. [EPA-HQ-OAR-2009-0491-2769, p.4]
Response:
The final Transport Rule allocation methodology under the FIPs is explained in section VII.D of the preamble.  The commenter is mistaken that unit-level allowance allocations "limit the capacity factors" at any given unit.  Allowance allocations are not equivalent to compliance requirements under the Transport Rule air quality-assured trading programs.  Units may emit as many tons for which they hold the relevant allowances, whether or not those allowances were initially allocated to the units in question.  As explained in the Allowance Allocation Final Rule TSD, the economic determination of unit dispatch in the power sector factors in the cost of any emissions under the programs (i.e., the market value of an allowance) whether or not an allowance for that emitted ton was freely allocated to that unit in the first place.
EPA notes that units 7, 8, and GT2 did not receive ozone season allowance allocations in the proposed unit level allocations because Iowa (the state in which those units are located) was not subject to the ozone-season NOX program in the proposal.  EPA has promulgated a Transport Rule SNPR including Iowa as covered under the TR ozone season program; the SNPR includes a presentation of proposed unit-level allocations under those FIPs.
Organization: Formosa Plastics Corporation, LA
Prairie State Generating Company, LLC
CPS Energy
Shell Chemicals
Consolidated Asset Management Services (CAMS)
Illinois Environmental Protection Agency
City of Springfield, Illinois, Office of Public Utilities
we energies
Wabash Valley Power
Lakeland Electric
Seminole Electric Cooperative Inc.
Tennessee Valley Authority (TVA)
Constellation Energy
Vectren Corporation
Southern Company
North Carolina Department of Environment and Natural Resources
Duke Energy
Massachusetts Department of Environmental Protection
State of Missouri Department of Natural Resources
NRG Energy
City Utilities of Springfield
San Miguel Electric Cooperative, Inc.
DTE Energy Services (DTEES)
Dynegy, Inc.
Indiana Energy Association
Great River Energy
Borger Energy Associates (Blackhawk)
East Kentucky Power Cooperative
Sunbury Generation LP
Black River Generation
New York Power Authority
Florida Municipal Power Agency (FMPA)
Associated Electric Cooperative, Inc. (AECI)
Faribault Energy Park
Spruance Genco, LLC
Selkirk Cogeneration Project (SCP)
Morgantown Energy Associates
Entergy Services, Inc.
DTE Energy
Rochester Public Utilities (RPU)
Potomac Power Resources
Sabine Cogen, LP
Denver City Energy Associates, LP
Manitowoc Public Utilities (MPU)
MIT Central Utility Plant
Lafayette Utilities System
Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
Giarmarco, Mullins & Horton, P.C.
AES Corporation (AES)
Comment:
AES Corporation (AES)
The following are examples of errors for the allocations that do not reflect current operations. All of the following facilities have S02 and NOx controls and improvements to these are unlikely due to operational and or market circumstances. [EPA-HQ-OAR-2009-0491-3793.1_NODA, p.7]
:: For AES Warrior Run the NOx and S02 allocations are far lower than current or historical operations. The unit is already very well controlled with no pass through on additional costs to over comply
:: For AES Ironwood, there was no S02 allocations planned and less than a third of the NOx allocations needed. These units already have low NOx gas turbines and SCR and are considered best in class emissions
:: For AES Beaver Valley, the S02 allocation is less than half of current and historical operations. The units are already scrubbed, with no pass through of increased costs to over comply
:: For AES Cayuga, the NOx and S02 allocations are far lower than current or historical operations. Both units have scrubbers and NOx controls. [EPA-HQ-OAR-2009-0491-3793.1_NODA, p.7]
:: For AES Somerset the NOx allocation is less than third of current and historical operations. The unit already has an SCR that cannot be operated at reduced loads
:: For AES Thames the S02 allocation is less than half of current and historical operations. The units are already very well controlled for NOx and S02 and have no pass through option on increased costs to over comply
:: For AES Shady Point the NOx allocation is far less than current and historical operations. The units are already very well controlled with no pass through option on increased costs to over comply. [EPA-HQ-OAR-2009-0491-3793.1_NODA, p.8]
Associated Electric Cooperative, Inc. (AECI)
One of the generating facilities that provide bulk baseload power to Associated and its member-cooperatives is the New Madrid Power Plant. A smaller facility, Chamois Power Plant, also supplies baseload power to the system and is owned by Central Electric Power Cooperative (CEPC). CEPC is one of the six generating and transmission (G&T) cooperatives that own AECI. [EPA-HQ-OAR-2009-0491-2845.1 p.10]
The assumed heat input in EPA's "ParsedFile_TR_SB_Limited_Trading" tables for the affected units at New Madrid and Chamois plants appear to be in significant error. [EPA-HQ-OAR-2009-0491-2845.1 p.10]
[[Data Table Here]]
The comparison values in the "CAMD Actual" column are taken directly from the Clean Air Markets Division (CAMD) "Data and Maps" database (http://camddataandmaps.epa.gov/gdm/). The values in this column are the average of the three highest annual heat input totals from the years 2005 through 2009. It is unclear where data came from that populates the CATR files, but it is clearly in error. With respect to the New Madrid units, even if one were to compare the CATR assumptions to the lowest heat input years during the lookback range (33.0 TBtu and 36.0 TBtu, respectively) the difference is still significant. [EPA-HQ-OAR-2009-0491-2845.1 p.10]
Request: Associated requests that EPA review the heat input assumptions for these units and adjust the allocations accordingly. [EPA-HQ-OAR-2009-0491-2845.1 p.11]
The three identical units at AECI's Holden plant (ORIS 07848) are permitted to operate up to 500 hours each (3 units) burning No. 2 fuel oil up to 0.05 %S. This could be up to 54 TPY SO2 for all 3 units. The CATR FIP includes no allowances for the SO2 program. Given the significant regulatory pressures on coal-fired power plants, it is likely that combustion turbine facilities like Holden will be utilized more in the future. [EPA-HQ-OAR-2009-0491-2845.1 p.11]
Request: Associated requests that EPA consider emissions from combustion turbines that are permitted to burn fuel oil and assign allowances to these facilities according to permit restrictions for burning low sulfur fuel oil per the applicable fuel sulfur limit in the facility's permit. [EPA-HQ-OAR-2009-0491-2845.1 p.11]
The units at AECI's Chouteau power plant in northeastern Oklahoma are impacted by the proposed Transport Rule where they were not under CAIR. The facility is a combined-cycle gas plant with a total of three electricity generators. Two combustion turbines (CTs) drive one shaft each, and a steam turbine powered by waste heat from the CTs drives a third shaft. The CATR erroneously includes a NOx allocation for the steam turbine which does not generate emissions. We assume that this is a mistake. [EPA-HQ-OAR-2009-0491-2845.1 p.11]
The assumed heat inputs for the two emitting units are about 16% lower than the heat input recorded in 2009.
[[Data Table Here]]
Request: Associated requests that EPA remove the steam turbine from the allocation tables and adjust the heat input assumptions for the two emitting combustion turbine units.  [EPA-HQ-OAR-2009-0491-2845.1 p.11]
Black River Generation
Black River Generation, LLC appreciates the opportunity to provide comments on the proposed Transport Rule that was published on August 2,2010. The comments herein are focused on the proposed allowance allocation details presented in the budgets and allocation section of the technical support documents. Primarily, in its proposed allocations, EPA has not provided allowances for the boilers at Black River Generation, LLC (ORIS Code 10464) located in Fort Drum, NY. It appears that EPA assumed that these particular units serve a generator of less than 2S MW and are, therefore exempt from the Transport Rule requirements. [EPA-HQ-OAR-2009-0491-2836.1 p.1]
The Black River Generation facility is configured with three boilers that serve one common steam turbine generator with a rated capacity of 5S MW, as reported on the CAMD database. The MW capacity data provided in the Transport Rule allocation tables is reportedly derived from the NEEDS database and was split across the boilers to arrive at a per-boiler rating of 18.333 MW for each of the boilers. [EPA-HQ-OAR-2009-0491-2836.1 p.1]
However, the applicability provisions of the proposed Transport Rule (proposed Section 97.404(a)(1) for the Annual NOx subpart, proposed Section 97.S04(a)(1) for the Ozone Season subpart; and proposed Section 97.604(a)(1) for the Annual S02 subpart), state that the rule is applicable to the following units:
Any stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine serving at any time, since the later of November 15, 1990 or the start-up of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe producing electricity for sale. [EPA-HQ-OAR-2009-0491-2836.1 p.1]
As stated above, each of the boilers at the Black River Generation facility serves a generator with a nameplate capacity of 55 MWe and, therefore, is subject to the Transport Rule. We also note that EPA included this facility (for these reasons) as an affected facility under the NOx SIP Call and CAIR. As such, this facility should be treated as a CATR-affected facility and EPA should allocate appropriate S02 and NOx allowances to this facility. [EPA-HQ-OAR-2009-0491-2836.1 p.2]
Specifically, the Excel spreadsheet contained on the EPA web page and referenced as 'Budget and Allocations - Detailed Unit-Level Data (Excel)' includes a listing of each unit for which allocation data was determined. The following comments are provided with regard to allocation calculations in that spreadsheet and final Allocations Table provided in the docket. [EPA-HQ-OAR-2009-0491-2836.1 p.2]
The worksheets provide data and analyses for the facility's three boilers (E001, E002, and E003 ). However, in the final worksheet entitled 'Allocations & Rate limits' and in the final Allocation Table provided in the docket, the table lists zero allocations for these units under each of the four programs Annual NOx, Ozone Season NOx, 2012 502, and 2014 S02. There is no explanation to account for the removal of the allocations for these units. However, as explained above, it appears that EPA incorrectly assumed that these units were exempt. [EPA-HQ-OAR-2009-0491-2836.1 p.2]
 :: Black River Generation, LLC requests that EPA review this worksheet and provide the allocations as indicated and calculated in the previous worksheets. Based on review of similar units, the allocations would be calculated as 97% of the Projected Annual NOx and Ozone Season NOx Mass, and as 97% of the Adjusted Annual S02 - Projected Base Case, as provided below. The calculation methodology for the 2014 and Beyond 502 allowances could not be determined. [EPA-HQ-OAR-2009-0491-2836.1 p.2]
[[Data Table Here]]
Borger Energy Associates (Blackhawk)
On behalf of Borger Energy Associates, LP, owner of Blackhawk Station (Blackhawk), Consolidated Asset Management Services respectfully requests that your office review the Environmental Protection Agency's (EPA) database inputs used to calculate the nitrogen oxides (NOx) allocations under the proposed Transport Rule (Federal Register, Vol. 75, NO. 147, Monday, August 2, 2010, Proposed Rules, Environmental Protection Agency, 40 CFR Parts 51, 52, 72, 78 and 97, Federal Implementation Plans to Reduce Interstate transport of Fine Particulate Matter and Ozone).
All comments provided in this letter are related to ORIS code 55064 and the following units:
:: Blackhawk Station Unit UNT1; and
:: Blackhawk Station Unit UNT2.
Errors related to the Air Transport Rule, Technical Information section of the EPA website (http://www.epa.gov/airquality/transporVtech.html). document Budgets and Allocations - Detailed Unit-Level Data (Excel), are identified in this letter. In particular, Blackhawk is represented as not having an SCR for NOx control, when, in fact, there is in an existing SCR system on both units. Blackhawk respectfully requests that EPA consider the information contained in this submittal when determining final allocations under the Transport Rule. [EPA-HQ-OAR-2009-0491-2798.1 p.1]
City of Springfield, Illinois, Office of Public Utilities
[See Docket Number EPA-HQ-OAR-2009-0491-2635.1, pp.4-5 for specific comments on the Affected Units and Assumed Heat Inputs.]
[[See Docket Number EPA-HQ-OAR-2009-0491-2635.1, pp.6- for specific comments on the SO2 and NOx Emission Rates.]]
Since having provided the attached to Illinois EPA and the publication of the NODA (and webinars with speakers from USEPA on the Rule and the NODA) CWLP has noted that the Rule database lists Factory's capacity at 21 MW, whereas the Clean Air Market Division ('CAMD') has its nameplate capacity at 26.6 MW. CWLP also notes that Dallman Unit 31 had a Significant outage due to a turbine generator explosion from November 11, 2007, through April 7, 2009. This outage will cause the unit to have artificially lower emissions and heat input during this period due to this unusual, onetime event. [EPA-HQ-OAR-2009-0491-2635.1, p.2]
[[See Docket Number EPA-HQ-OAR-2009-0491-2635.1, pp.7 for specific comments on the SO2 and NOx Allocations.]]
City Utilities of Springfield
Issue: City Utilities is aware of substantial errors in EPA's operating and emission assumptions regarding our Southwest, James River, and McCartney Generating Stations. We will be submitting comments to this effect under the separate but related NODA but will also briefly describe them here to complete the record. The NEEDS 3.02 database indicates that the Southwest Power Station has a wet FGD in place. As we have indicated in our EIA Form 860 filings and our revised monitoring plan under the Acid Rain Program, the FGD at this facility had to be decommissioned and removed due to severe scaling, corrosion, and structural integrity concerns. Southwest Power Station now complies with all federal and state SO2 requirements by burning compliance coal from the Powder River Basin. This correction in the NEEDS database would materially impact the cost efficiency of additional SO2 control at the Southwest Station and the resulting state budget for Missouri. The database also assumes that the combustion turbines located at our Southwest, James River, and McCartney generating stations will cease to operate following promulgation of this rule. Accordingly, Table A affords them zero allowances. In actuality, combustion turbines will continue to be a valuable generating asset for City Utilities and other Missouri municipal utilities. These units not only provide rapid response to peak demand in ways that our steam units are unable, but also represent spinning reserve capacity required by electric reliability regulators. These factors presumably were not considered in the cost-based IPM modeling analysis. [EPA-HQ-OAR-2009-0491-2721.1 p.3]
Recommendation: The Appendix A allocation table should be corrected to reflect actual existing conditions and expected operating scenarios for affected City Utilities units. [EPA-HQ-OAR-2009-0491-2721.1 p.3]
Consolidated Asset Management Services (CAMS)
EPA posted their current approach calculations of unit allocations and unit descriptive data on their Technical Information website found in the documents titled Allocation Table, revision dated 07/21/2010, and Budgets and Allocations  -  Detailed Unit-Level Data. Below is a list of errors found in the referenced documents. [EPA-HQ-OAR-2009-0491-2612.1, p.2]
1) The Unit ID STG for the Effingham County Power facility (ORIS 55406) is a steam turbine generation and not a TR NOx Annual unit, TR NOx Ozone Season unit, nor a TR SO2 Group 1 unit. However, in EPA's currently posted approach this steam turbine generator has been allocated allowances for the various TR markets. After review of units reported in the above referenced document there are numerous units reported and allocated allowances that are not and should not be a TR unit. [EPA-HQ-OAR-2009-0491-2612.1, p.2]
2) Waterside Power facility (ORIS 56189) consists of 3 simple-cycle combustion turbine units (Unit ID 4, 5, and 7) each with a nameplate capacity of 23.2 MWs. The units have been granted the New Unit Exemption per the Acid Rain Program, however they currently participate in the CAIR NOx Ozone Season Program because Connecticut's revised the definition of a CAIR NOx Ozone Season Unit from a nameplate capacity of 25 MWs to 15 MWs. The capacity for Unit 7 is given as 0, zero, and reported as an affected unit under the various TR programs. Under the definition of the applicable unit to the TR programs Unit 7 should be delisted from the list of applicable units. [EPA-HQ-OAR-2009-0491-2612.1, p.2]
Constellation Energy
In order for the rule to be implemented by January 2012, EPA must be able to make the necessary adjustments to the underlying data to ensure the allocations in 2012 and 2013 properly reflect the planned and installed air pollution controls as well as units' near-term operating circumstances and conditions. Constellation Energy has attached its recommended data corrections in a table to this letter. These corrections include inaccurate emission rates for some of our units which, once corrected, will provide adequate allowances for operation. [EPA-HQ-OAR-2009-0491-3613, pp.2-3] [[See Docket Number EPA-HQ-OAR-2009-0491-3613, p.4 for the data corrections.]]
CPS Energy
The allocation tables provided in the technical documents on the EPA's website are not correct for several of CPS Energy units.  [EPA-HQ-OAR-2009-0491-2524.1, p.1]
The Arthur Von Rosenburg combined cycle unit that is located at our V H Braunig Power Station site is listed in multiple ways and would be receiving double allocations if not corrected. There are three units listed as Arthur Von Rosenburg Units 1, 2, and 3 with the ORIS code 7512. Those units need to be removed from the allocation table; they are duplicates of V H Braunig CT01 and CT02 ORIS code 3612. We do not own/operate any units with ORIS code 7512. However the Energy Information Administration (EIA) has the Arthur Von Rosenburg units listed incorrectly with the ORIS code 7512 in their records. We have tried to correct this with the EIA. For all other reporting, the Arthur Von Rosenburg units are identified by ORIS code 3612 because they are on our V H Braunig Power Station plant site. So to clarify, Arthur Von Rosenburg ORIS code 7512 Units 1,2, and 3 need to be removed from the allocation spreadsheet for the Transport Rule. The Arthur Von Rosenburg units (a combined cycle unit) are correctly listed as V H Braunig ORIS code 3612 Units CT01 and CT02. [EPA-HQ-OAR-2009-0491-2524.1, p.1]
CPS Energy has a second comment regarding two other units at the V H Braunig Power Station site. V H Braunig Units 1 & 2 (gas fired steam boilers) allocations are very low compared to actual emissions. The allocations spreadsheet shows 13 and 8 allocations, respectively for V H Braunig Units 1 & 2. However reported emissions during Ozone season in 2008 and 2009 were in the 90 - 160 tons range. The lb/mmBtu rates for the V H Braunig Units 1 & 2 are also too low. The spreadsheet shows 0.019 and 0.016 lb/mmBtu, respectively. But the reported rates for those two units are typically around 0.15 lb/mmBtu. The units are not equipped with Selective Catalytic Reduction (SCRs), so they would never be able to achieve a rate as low as 0.019 or 0.016 lb/mmBtu. [EPA-HQ-OAR-2009-0491-2524.1, p.2]
The allocations and allowable NOx rates for all of our other units are correct. [EPA-HQ-OAR-2009-0491-2524.1, p.2]
Denver City Energy Associates, LP
Power Station (Mustang), Consolidated Asset Management Services respectfully requests that your office review the Environmental Protection Agency's (EPA) database inputs used to calculate the nitrogen oxides (NOx) allocations under the proposed Transport Rule (Federal Register, Vol. 75, NO. 147, Monday, August 2, 2010, Proposed Rules, Environmental Protection Agency, 40 CFR Parts 51, 52, 72, 78 and 97, Federal Implementation Plans to Reduce Interstate transport of Fine Particulate Matter and Ozone).  [EPA-HQ-OAR-2009-0491-2878.1,p.1]
All comments are directed toward ORIS code 55065 and associated units:
:: Mustang Station Unit GEN1;
:: Mustang Station Unit GEN2; and
:: Mustang Station Unit GEN3. [EPA-HQ-OAR-2009-0491-2878.1,p.1]
Errors related to the Air Transport Rule, Technical Information section of the EPA website (http://www.epa.gov/airguality/transport/tech.html). document Budgets and Allocations - Detailed Unit-Level Data (Excel), are identified in this letter and supporting calculations. In particular, GEN3 is a steam turbine and, therefore, is not an affected source under the Transport Rule. Emissions attributed to this unit should actually be combined with those attributed to unit GEN1 . Denver City respectfully requests that EPA consider the information contained in this submittal, so that the appropriate number of Transport Rule Ozone Season NOx allowances may be allocated. [EPA-HQ-OAR-2009-0491-2878.1,p.1]
DTE Energy
Incorrect Inputs to the Integrated Planning Model (IPM) and Incorrect Emission Model Assumptions; DTE-Specific Comments
The attached table includes specific data extracted from EPA's CATR Allocation Table for sources owned and operated by DTE Energy. These listed values are the product of a number of erroneous results generated by the IPM Model that was used to identify 'least-costly' EGU operation and control device installation, to meet future projected generation needs. The following comments relate to specific IPM Model projections that are inconsistent with our analysis of future operating, and most cost-effective control device installation plans.  [EPA-HQ-OAR-2009-0491-2851.1,p.6] [[See Docket Number EPA-HQ-OAR-2009-0491-2851.1, p.9 for the table with the specific data.]]
1. Projections of future year operation are reasonable except IPM projections that show:
a. Greenwood Energy Center Unit No.1 has zero future generation. This oil and natural gas-fired unit will likely operate with a capacity factor in a range from 2 to 5 percent, based on future load projections from DTE Energy's load forecasting staff. Over the last ten years, this unit's capacity factor has ranged from 2 to 20 percent. Also, depending on fuel price variations and emission allowance costs, it operates with residual oil or natural gas. EPA's assumption that it would only use natural gas is incorrect.
b. The amount of generation that IPM estimates for Marysville Power Plant is too high. The four units at this coal-fired power plant on the St. Clair River have not operated since 2001, and our current plans do not anticipate operating this plant in the near future. [EPA-HQ-OAR-2009-0491-2851.1, p.6]
2. The 502 emission rates that assume 100 percent subbituminous coal for all units that fire even small amounts of this fuel are unrealistic. None of these units can operate at full capacity burning 100 percent subbituminous (i.e., western) coal. Converting to 100 percent subbituminous coal would require all DTE Energy units not currently firing this blend to make significant modifications to existing equipment such as coal mills, coal handling equipment, fans, burners, etc. In addition, this would include modification of particulate matter control devices, and installation of flue gas conditioning systems to meet opacity and particulate matter emission limits. Time and resources necessary to engineer, permit and install these modifications would certainly delay implementing these EPA-predicted operating changes. The only DTE Energy coal-fired units that currently operate with 100 percent subbituminous coal are Belle River Units 1 & 2.  [EPA-HQ-OAR-2009-0491-2851.1,p.6]
a. Units with unrealistic 502 emission rates in 2012 due to 100 percent subbituminous coal use include:
i. Monroe Units 1 & 2
ii. River Rouge Units 2 & 3
iii. St. Clair Units 1-4, 6-7 6 [EPA-HQ-OAR-2009-0491-2851.1,p.6]
iv. Trenton Channel 16-19 & 9A
b. Units with unrealistic S02 emission rates in 2014 due to 100 percent subbituminous coal use include:
i. Harbor Beach Unit 1
ii. Marysville Units 9-12
iii. Monroe Units 1 & 2
iv. River Rouge Units 2 & 3
v. St. Clair Units 1-4, 6-7
vi. Trenton Channel 16-19 & 9A [EPA-HQ-OAR-2009-0491-2851.1, p.7]
3. The SO2 emission rates assumed for the EGUs burning 100 percent subbituminous coal are too low. Since DTE Energy has a long history firing this fuel at Belle River Power Plant, the actual emission rate from that facility provides a very good estimate of the emission rate that is achievable with this coal type. The 0.581 lb/mmBtu figure for Harbor Beach and Marysville is reasonable, but the 0.529 figure for the remainder of DTE's coal-fired units is too low. Belle River Power Plant's SO2 emission rates have ranged from 0.55 to 0.59 lb/mmBtu over the last five years. [EPA-HQ-OAR-2009-0491-2851.1,p.7]
4. The IPM runs for EPA showed that FGD installation on Belle River Units 1 & 2 were 'cost-effective' and possible by January 1, 2014. Considering projects already underway throughout the portfolio, these devices could not be permitted, engineered, constructed and operational by this deadline. DTE Energy has already begun FGD construction on Monroe Power Plant Units 1 & 2 for operation in 2014. We are applying for a PSD permit for SCR installation at Monroe Power Plant Unit 2 with an operational target date of 2015. Completion of these projects already demand a significant amount of resources and capital during the next four years. Also, the electrical system reliability requires other plants such as Belle River Units 1 & 2 to be available to make up for the time these two Monroe Power Plant units will be unavailable during this upcoming construction period. [EPA-HQ-OAR-2009-0491-2851.1,p.7]
5. The assumed SO2 emission rates for Units 3 & 4 at Monroe Power Plant are too low. The figures cited in the allocation table (0.058 (2012) & 0.055 (2014) lb/mmBtu) are too low. The recently issued PSD permit for these sources includes a SO2 emission limit of 0.107 lb/mmBtu, which is the result of a BACT review for these sources. The values that EPA assumed do not account for an adequate amount of actual emission data with the FGD systems operating, and an allowance allocation at, or close to, the emission limit is more appropriate. [EPA-HQ-OAR-2009-0491-2851.1,p.7]
6. EPA's estimated NOx emission rates for DTE Energy's EGUs having combustion controls, but no post-combustion reductions, are too low compared to actual emission rates shown in the enclosed table. The NOx emission rates for the following units are underestimated:
a. Belle River 1 & 2
b. Harbor Beach 1
c. Marysville 9-12
d. Monroe 2
e. River Rouge 2 & 3
f. St. Clair 1-4, 6-7
g. Trenton Channel 16-19  [EPA-HQ-OAR-2009-0491-2851.1,p.8]
7. Monroe Power Plant Units 1, 3 and 4 currently operate with SCRs to reduce NOx emissions. EPA's NOx emission estimate for the controlled emission rate is too low. This value (0.058 lbs/mmBtu) is achievable under optimum operating conditions, but is not sustainable on a long-term basis. DTE Energy believes that the NOx limit finalized in the recent PSD permit for Units 3 & 4 (0.08 lbs/mmBtu) is more appropriate for calculating CATR NOx allowances. [EPA-HQ-OAR-2009-0491-2851.1, p.8]
DTE Energy Services (DTEES)
Unit-specific comments
DTEES owns and operates three facilities that we believe are subject to the Proposed Transport Rule and have either not been identified by EPA as subject to the rule or have not received any allowances under the proposed allocation methodology. Each facility is discussed below.  [EPA-HQ-OAR-2009-0491-2699.1,p.2]
DTE East China. This facility is located in East China, Ml (ORIS Code: 55718). It consists of four natural gas- fired simple cycle turbines each rated at 82 MW. Emissions from these natural gas-fired peaking units are controlled by low NOx burners. EPA's 1PM projections have resulted in each unit receiving zero allowances for the NOx Annual and Ozone Season. We believe that DTE East China is an important facility for supporting the electrical system. These units were called to run by the Regional Transmission Authority, MISC, 28 times thus far in 2010. Our internal forecasts predict demand for power to begin growing over the next several years. With this outlook, we would predict DTE East China to be called to run at least as much as it did in 2010. [EPA-HQ-OAR-2009-0491-2699.1,p.2]
DTEES believes that EPA is underestimating the heat input for DTE East China for the annual NOx allocation and ozone season NOx allocation. In the " BADetailedData" spreadsheet "Allocations and Rate Limits" tab, EPA assumes the following heat inputs (mmBtu) for the annual NOx allocation: Unit 1 --  34,937, Unit 2  --  34,615, Unit 3  --  35,683, Unit 4 --  34,754. In the " BADetailedData" spreadsheet "Allocations and Rate Limits" tab, EPA assumes the following heat inputs ( mmBtu) for the ozone season NOx allocation: Unit 1 --  3,494, Unit 2  --  3,461, Unit 3  -- 3,568, Unit 4 -- 3,475. In 2009 the average annual heat input for the East China units was 43,048 mmBtu and the average ozone season heat input was 20,935 mmBtu. The East China units are on track to reach 50,000 mmBtu heat input for 2010. A table showing DTE East China's heat input, NOx rate, and NOx emissions for the period 2005  --  June 2010 is attached. [EPA-HQ-OAR-2009-0491-2699.1,p.3]
These gas peaking units are already equipped with low NOx burners. DTEES requests that, based on past operations and projections of future operations, EPA increase the projected heat input for the East China units and allocate additional allowances to DTE East China. [EPA-HQ-OAR-2009-0491-2699.1,p.3]
DTE Pontiac North. This facility is located in Pontiac, Michigan (ORIS Code: 880081) and consists of three natural gas-fired boilers with rated capacities of 201.9 mmBtu/hr each and one circulating fluidized bed coal-fired boiler with a rated capacity of 443 mmBtu/hr. The coal-fired boiler was installed August 1, 1984 and operates in cogeneration mode. It is connected to a single steam turbine generator set with a nameplate capacity of 28 MW. High pressure steam from the boiler is fed to the steam turbine to produce electricity and Low pressure steam is extracted from the turbine for process use at the plant. This unit was subject to the NOx budget program, CAIR NOx Annual, CAIR NOx Ozone Season and CAIR S02 programs. The facility has not operated the coal-fired boiler since May 2009. DTE Pontiac North cannot be found in any EPA documentation for the proposed Transport Rule. The facility is not listed in the NEEDs database and is also not listed in the BADetailedData spreadsheet or Allocation spreadsheet. We believe DTE Pontiac North is subject to the proposed Transport Rule and request that EPA update the database to reflect this unit and assign allowances as appropriate. [EPA-HQ-OAR-2009-0491-2699.1,p.3]
E J Stoneman, Cassville, WI, ORIS code 4146. The facility consists of two 340 mmBtu/hr rated boilers serving through cross connected steam headers, 33 MW and 18 MW generators. Emissions are through a combined stack. [EPA-HQ-OAR-2009-0491-2699.1,p.3] [EPA-HQ-OAR-2009-0491-3721.1_NODA, p.3]
This facility is subject to the Acid Rain program and CAIR. The two units were originally built in 1950 and 1951 and designed to burn coal. DTEES purchased the facility in May 2008. Prior to the purchase, the previous owner operated the plant intermittently, selling the electricity through the Midwest Independent System Operator (MISO) at market rates. After the facility was purchased by DTEES, the units were operated intermittently to burn down the remaining coal pile in preparation for the conversion from coal to wood biomass firing. The remaining coal pile was depleted in March 2009. The facility was shut down during the March 2009 to July 28, 2010 period while it was modified and is currently being repowered burning 100% woody biomass. The facility will sell all of the renewable electrical output while firing woody biomass. We believe the historical coal-fired operations are not indicative of future operations burning woody biomass. Once the commissioning process is complete the plant will be operating at full load. [EPA-HQ-OAR-2009-0491-2699.1,pp.3-4] [EPA-HQ-OAR-2009-0491-3721.1_NODA, p.3]
Based on a discussion with EPA staff, EJ Stoneman will not receive allocations due to being exempt from the rule. The proposed rule applies to, 'Any stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine serving at any time, since the later of November IS, 1990 or the start-up of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe producing electricity for sale'. EPA is currently viewing these units as exempt from the rule and does not list them receiving any allowances due to the units being listed as 25 MW in the 'BADetailedData' spreadsheet .. Since the units both serve a 33 MW generator through a cross connected steam header we believe the units are subject to the proposed NOx annual and S02 annual rule and should receive allowances. However, EPA may determine that this is not a correct interpretation. If EPA agrees that the units are subject to the rule, DTEES requests that the appropriate allowance allocations are issued to the units as outlined in the proposed rule. [EPA-HQ-OAR-2009-0491-2699.1, p.4] [EPA-HQ-OAR-2009-0491-3721.1_NODA, p.3]
DTEES believes that EPA has underestimated the projected heat input to the units. Based on the changes to the facility outlined above the heat input will be much greater than EPA has anticipated. The projected heat input in 2012, and in subsequent years, to each unit should be 2,978,400 mmBtu. EPA should use these projected heat input values to determine the NOx and S02 annual allowances for the units. Comparing reported heat input to projected heat input is not appropriate due to the change in fuel type and full utilization of the units once the conversion to woody biomass firing is completed. Additionally, the air pollution construction permit issued by the Wisconsin Department of Natural Resources for the conversion to woody biomass firing required the facility to install Selective NonCatalytic Reduction (SNCR) and over fired air for NOx control. Additional S02 controls are not cost effective. Therefore, using the projected heat inputs and the permitted emission rates of the modified units (0.2 lbs/mmBtu for NOx and 3.17 lbs/mmBtu for S02), each unit should receive 298 NOx annual and 4721 S02 annual allowances. [EPA-HQ-OAR-2009-0491-2699.1,p.4] [EPA-HQ-OAR-2009-0491-3721.1_NODA, p.3]
EPA should also allow the most flexible trading system. E J Stoneman has no other facilities owned by the same parent company within the state with which it might be able to average emissions or trade allowances, making it a small unit/stranded unit. If EPA does not use the most flexible trading system these units will be unable to secure allowances at a reasonable price, or perhaps not at all. This scenario would make future operation of the units uncertain at a time when conversion of coal fired units to woody biomass firing to produce renewable electricity should be encouraged. [EPA-HQ-OAR-2009-0491-2699.1,p.4] [EPA-HQ-OAR-2009-0491-3721.1_NODA, pp.3-4]
Duke Energy
EPA's Proposed Transport Rule Analysis Contains Numerous Unit Specific Errors that Need to Be Corrected.
Edwardsport Units 7-8 are Affected Units under the Transport Rule and Should Receive Allowance Allocations.
The Edwardsport (ORISPL 1004) units 7-1, 7-2, and 8-1are each existing PTR NOx Annual, PTR Ozone Season, and PTR SO2 Group 1 units based on the applicability criteria of §97.404, §97.504, and §97.604 of the PTR. Each of these units reports emissions data to EPA under the Acid Rain Program and the CAIR SO2 and NOx programs. None of these units, however, appear in the NEEDSv3.02_EISA database and are therefore not included in the IPM modeling. EPA states in its PTR State Budget, Unit Allocations, and Unit Emissions Rates Technical Support Document that "IPM is a representation of all units which are capable of supplying electricity to the US electric grid..." Each of these units meets this criterion for inclusion in IPM.  [EPA-HQ-OAR-2009-0491-2689.1, p.33]
It appears that none of these units were included in the inventory of units used by EPA to establish the IndianaSO2 and NOx budgets, but per EPA's stated methodology for establishing state budgets, they should have been included. In addition, per EPA's stated methodology for allocating allowances to individual units, each of these units should have received both SO2 and NOx allowance allocations, but EPA has proposed neither SO2 nor NOx allocations for any of the units.  [EPA-HQ-OAR-2009-0491-2689.1, p.33]
Duke Energy requests that EPA include each of these units in the determination of the Indiana SO2 and NOx budgets, and allocate allowances appropriately. [EPA-HQ-OAR-2009-0491-2689.1, p.33]
IPM Incorrectly Retrofits Dan River Unit 3 with SCR in 2012.
The "Retrofit Control 1" column of the ParsedFile_TR_BaseCase.xls file shows the Dan River (ORISPL 2723) unit 3 getting SCR in 2012. This is an error. An SCR on this unit is neither existing, under construction nor planned for 2012 or for any year after 2012. EPA states in the PTR that it did not assume post combustion controls (SCR) in 2012 that aren't already existing or planned by 2012. The retrofit SCR should be removed from this unit and the North Carolina annual and ozone season NOx budgets and the unit's annual and ozone season NOx allocations should be adjusted upward accordingly. [EPA-HQ-OAR-2009-0491-2689.1, pp.33-34]
IPM Incorrectly Retrofit Buck Units 5, 6, and 7 and Dan River Units 1 and 2 with SNCR in 2012.
The "Retrofit Control 1" column of the ParsedFile_TR_BaseCase.xls file shows the Buck (ORISPL 2720) units 5, 6, and 7 and Dan River (ORISPL 2723) units 1 and 2 getting SNCR in 2012. This is an error. SNCR on these units is neither existing, under construction nor planned for 2012 or for any year after 2012 for these units. The retrofit SNCR should be removed from these units and the North Carolina annual and ozone season NOx budgets and each unit's annual and ozone season NOx allocations should be adjusted upward accordingly. [EPA-HQ-OAR-2009-0491-2689.1, p.34]
The Duke Energy units that IPM has modeled as fuel switching to 100% subbituminous coal (reference ParsedFile TR_SB_Limited Trading 2014) include R Gallagher (ORISPL 1008) units 1-4, Miami Fort (ORISPL 2832) unit 6, and Walter C Beckjord (ORISPL 2830) units 1-5 (Walter C Beckjord (ORISPL 2830) unit 6 is modeled with a small amount of subbituminous coal being blended with bituminous coal, with an FGD). None of these units are capable of burning subbituminous coals. No capital investment has been made that would allow these units to safely handle and burn this fuel type, such as fuel handling upgrades, dust suppression, mill modifications and fire protection, boiler tube surface changes, sootblower additions, etc. Also, the Beckjord Station does not have a coal handling system that would allow for the controlled blending of bituminous and subbituminous coals for Unit 6, and this unit cannot burn straight subbituminous coal (such as with alternating the fuel types). Therefore, EPA must include the cost of an on-site coal blending system (approximately $70 million to manage all six units, or approximately $40 million for Unit 6 only), or increase the cost of the delivered fuel to account for off-site blending cost premiums (approximately $10 to $14 per ton of blended coal from terminals on the Ohio River). In addition to the fact that none of these units have ever burned any subbituminous coal, Duke Energy has estimated the cost of fuel switching these units to be far in excess of EPA's $2,000 per ton cost breakpoint for SO2. It is therefore not appropriate for IPM to model any of these units as burning subbituminous coal. [EPA-HQ-OAR-2009-0491-2689.1, pp.35-36]
EPA's Assumption That Coal Switching within the Bituminous Coal Grade to a Lower Sulfur Coal Will Can Be Accommodated at Relatively Little Cost is Wrong.
EPA states that in its PTR analysis it does not add capital or operations and maintenance costs for coal switching from higher to lower sulfur bituminous coals, and asks for comment on the reasonableness of this assumption. For a number of Duke Energy units that IPM has switched to lower sulfur bituminous coal, this assumption is wrong.  [EPA-HQ-OAR-2009-0491-2689.1,p.36]
The ParsedFile TR_SB_Limited Trading 2014 shows that IPM has switched Duke Energy's Gibson (ORISPL 6113) unit 5 to a 1.4 lb /mmBtu SO2 bituminous coal. The unit is not capable of burning a coal with this low sulfur content without incurring significant costs for precipitator upgrades and increased fuel costs.  [EPA-HQ-OAR-2009-0491-2689.1,p.36]
The existing electrostatic precipitators ("ESP") on Gibson Unit 5 were designed by Buell and installed in 1982. It consists of two casings arranged in a chevron configuration. Each precipitator casing has four chambers, each with forty gas passages spaced at nine inches and ten fields, each nominally three feet long by thirty-one feet tall. Each ESP casing is currently powered by sixteen 45kV, 1400 mA transformer-rectifier sets. The precipitator is a weighted wire design and treats 2,300,000 ACFM of flue gas at 305 degrees Fahrenheit. Design gas velocity is 5.3 feet per second and the SCA is approximately 254. [EPA-HQ-OAR-2009-0491-2689.1, p.36]
The unit's precipitator design particulate removal efficiency is 99.5%, burning 2.6 lb sulfur coal. At present the unit typically burns 4.5 lb coal and at times suffers opacity excursions when one or two fields in the precipitator are out of service. Burning a 1.4 lb/mmBtu SO2 coal in this unit would not be possible without a major precipitator rebuild or baghouse addition. A baghouse addition would cost approximately $200 million. A precipitator rebuild would cost around $25 million. Duke Energy has estimated the $/ton cost of a precipitator upgrade required to allow the unit to burn this lower sulfur coal to be far in excess of the $2000/ton cost breakpoint that EPA is using for SO2. [EPA-HQ-OAR-2009-0491-2689.1, pp.36-37]
Similarly, the ParsedFile TR_SB_Limited Trading 2014 shows that IPM has switched Duke Energy's Wabash River (ORISPL 1010) units 2, 3, 4, and 5 to a 0.83 to 0.93 lb/mmBtu SO2 bituminous coal. However, EPA has not provided any additional detail about the quality and nature of this proposed fuel, including full proximate and/or ultimate analysis or the modeled source region. The constituents of coal can vary dramatically, even within the same seam and general sulfur grade. It is difficult for Duke Energy to assess the potential impact of this fuel on the units without knowing this additional detail. This would include ash content and moisture content, as well as fuel combustion characteristics such as grindability, slagging and fouling indices, and volatility. Knowing these details is critical to making an assessment of whether the unit can manage this fuel. Wabash River Units 2, 3, 4, and 5 have ball mills, which are especially susceptible to changes in coal properties. Higher ash, higher moisture, and/or lower grindability characteristics, which are typical in some combination for most lower sulfur coals (whether bituminous or subbituminous), can result in mill skidding; reduced mill fineness. This usually results in increased boiler slagging and fouling; pluggage; higher NOx and CO emissions; lower unit efficiency; higher opacity; and therefore reduced unit availability and capacity. It can also result in mill explosions, which are a significant safety hazard, and require expensive fire protection and suppression system upgrades (again, even for bituminous coals); and also, in conjunction with ash resistivity impacts, reductions in precipitator performance requiring precipitator conditioning systems and/or expensive precipitator upgrades or replacements, as the precipitators on these specific units are very small (only 130 SCA, with rigid discharge electrodes and 11 inch plate spacing), and were originally designed for 6 to 7 lb/mmBtu SO2 fuels. [EPA-HQ-OAR-2009-0491-2689.1, pp.37-38]
These units have not been able to burn coals with less than 2.8 lb/mmBtu SO2 without suffering constant opacity exceedances. Further, IPM has specified different coal grades for Units 2 through 5, versus Wabash River Unit 6 (approximately 4.6 lb/mmBtu SO2 on Unit 6). Wabash River Station has a common coal handling system for all of the units; a capital investment would be required to separate the system to allow Unit 6 to manage a vastly different fuel from Units 2 through 5. Lastly, the ability to specify a suitable fuel of this sulfur grade in the market that has the requisite composition and characteristics to minimize the operational problems on these specific units may significantly limit the volume of fuel available, thereby resulting in higher coal costs than what IPM may be modeling (and thus affecting the economic assessment of this fuel choice relative to the $2000/ton cost breakpoint for SO2). Otherwise, a considerable capital investment would be required, including investments in the precipitators, mills, (and the coal handling system), again affecting the economic assessment of this option. [EPA-HQ-OAR-2009-0491-2689.1, p.38]
Due to the limited information provided, and the limited time allotted for comments, Duke Energy cannot reasonably research, engineer, and develop a capital cost estimate for this grouping of projects that would be instructive for EPA to consider in its economic assessment. Duke Energy can therefore only recommend, due to the configuration of these specific units and the recognized impact that coals of this general characteristic can have, that these units are not capable of burning the fuel selected by IPM (or equivalently, that given the proper time for project development, cost estimation, and assessment of the impacts on unit availability and capacity, that this option has a high likelihood of exceeding the $2000/ton cost breakpoint for SO2). Duke Energy requests that EPA model no less than a 1.67 lb/mmBtu SO2 bituminous coal for Wabash River Units 2 through 5. Coals of this general sulfur grade represent a vastly larger market share than the ~0.9 lb/mmBtu SO2 coal, offer wider variability in constituents and combustion characteristics (thereby making finding a suitable fuel more likely), and may even represent a mix of higher and lower sulfur fuels, again optimizing sourcing options, and reducing the impacts of incidental bunkering of higher sulfur coal from Unit 6 into Units 2 through 5.  In summary, at least for these Duke Energy units, EPA's assumption that a fuel switch to lower sulfur bituminous coal can be accomplished at relatively little cost is not correct and should be revisited. Any switch to lower sulfur bituminous coals if even feasible, would come at considerable cost that must be evaluated to determine the $/ton cost of such a switch and whether it would be within EPA's $2000/ton cost breakpoint for SO2. [EPA-HQ-OAR-2009-0491-2689.1, pp.38-39]
Duke Energy Recommends Modifications to the Way EPA Is Allocating Allowances to Peaking Turbines.
In review of the IPM projected heat input and emissions for peaking units, it is clear that the model projections consistently under-predict the potential for generation from these units. As a result, the model is then under-projecting the emissions from these units, which leads to an inadequate allocation when the projected emissions are the basis for determining a unit's allocation. It is generally accepted that most dispatch models do a very poor job of predicting peaking unit generation, and a load duration model, such as IPM, is even worse (in comparison to a chronological simulation model, for example). The multiple uses of peaking units make modeling their dispatch difficult; this includes actual coverage of peak load, but also ancillary services, such as operating for spinning reserve, VAR support, fast-startup for forced outage events, fast-response load following, interaction with energy storage (such as pumped storage hydro), and even testing (such as CEM RATAs, load proof tests, etc.). These various uses of peaking units, not just for meeting peak load, but for system reliability, are not well represented in the IPM. Comparing the TR Base Case 2012 and TR SB Limited Trading 2014 IPM projections of heat input on the Duke Energy fleet of natural gas fired combustion turbine units to the average historical heat input over the period 2005-2008, the IPM heat input projection was approximately 57% below the historical actual heat input for the ozone season period, and approximately 67% below the historical actual for the annual period. This very large under-representation of heat input leads directly to an under-prediction of emissions and a smaller allowance allocation than these units should receive. This problem with under-predicting heat input and emissions for combustion turbines would be magnified under the direct control remedy.  [EPA-HQ-OAR-2009-0491-2689.1, pp.41-42]
As a result of this problem, Duke Energy recommends that EPA modify its method for allocating allowances to peaking units from its stated method of using the lower of adjusted projected and adjusted reported emissions at the state level, and for peaking units only (whether combustion turbine or internal combustion, natural gas or oil) select the higher of the adjusted reported or adjusted projected emission, by unit. This will at least ensure that these units are provided an allocation that is consistent with their past level of generation and emissions and not biased downward or even totally eliminated due to an inadequate model representation of peaking units' full range of operation to serve both load and system reliability. [EPA-HQ-OAR-2009-0491-2689.1, p.42]
A Correction Is Needed to the Annual NOx Allowance Allocations for Some Peaking Units
EPA has proposed to allocate ozone season NOx allowances to a large number of peaking units, but it has not proposed to allocate any annual NOx allowances to those same units. Regardless of whether a state's budget and unit allocations were determined based on reported or projected emissions, a unit that receives an ozone season NOx allowance allocation must also receive an annual NOx allowance allocation consisting of at least the same number of allowances. To allocate ozone season but no annual NOx allowances to a unit makes no sense because the ozone season program and the data used to establish the ozone season allocations is a subset of the annual program regardless of whether reported or projected data was used.  [EPA-HQ-OAR-2009-0491-2689.1, p.51]
Duke Energy's Lincoln Combustion Unit 8 (ORIS 7277) located in North Carolina is an example of a unit whose annual NOx allocation exhibits this problem. EPA used adjusted reported emissions to set the North Carolina annual and ozone season NOx budgets and unit-level allocations. Based on the adjusted reported data, EPA determined that this unit should  receive two ozone-season NOx allowances. By definition it therefore must have also emitted at least two annual NOx tons for the annual reported period since the ozone season reporting period data is a subset of the annual reporting period data. However, a zero annual NOx allocation is proposed for this unit. Duke Energy can only conclude that this is an error.  [EPA-HQ-OAR-2009-0491-2689.1, pp.51-52]
Further, reviewing the BADetailedData.xls data file for this unit, the tab "Reported Data tab," row 7727, shows that the reported emission and heat input data was summarized for the ozone season, but that no data was shown in the column AW ("2008 Reported Annual Heat Input (mmBtu)") to represent the annual reported heat input for NOx (since EPA is adjusting reported NOx emissions to year 2008 heat input). In addition, columns F, I, L, (heat input for 2008 quarters 1 through 3 respectively), show reported heat input for this period that should have been summed to determine the 2008 annual heat input to use in calculating the unit's annual NOx allocation. The following table provides a listing of the Duke Energy units that exhibit this problem. [EPA-HQ-OAR-2009-0491-2689.1, p.52] [[See Docket Number EPA-HQ-OAR-2009-0491-2689.1, p.53 for the table.]]
Duke Energy requests that EPA correct the data errors and provide the appropriate annual NOx allocation to the Duke Energy units listed above, and to all other peaking units exhibiting this problem because, logically, a ton emitted in the ozone season is a ton emitted in the annual period. [EPA-HQ-OAR-2009-0491-2689.1, p.53]
Dynegy, Inc.
EPA has incorrectly identified the effective date for an FGD requirement at Baldwin Unit 2 as set out in the applicable NSR settlement action. EPA's Base Case v.4.W, at Appendix 3- 3.9, identifies ' 12/3112011' as the 'effective date' for SO2 Control (install wet or dry FGD) for Baldwin Units 1 and 2 under the Illinois Power Settlement Action. However, by its plain language, the Consent Decree (66) only requires an FGD to be installed and operating on Baldwin Unit 2 'by no later than ... December 31 , 2012'; the Consent Decree does not require an FGD on Baldwin Unit 2 by December 31, 2011.3 In fact, the Baldwin Unit 2 FGD will not be operable until late 2012. Given that the in-service date of the Baldwin Unit 2 FGD will not occur until late 2012 and the correct effective date of the FGD requirement (December 31, 2012), the SO2 allowance allocations for Baldwin Unit 2 in 2012 and 2013 should be based on Baldwin Unit 2's current SO2 emission rate, rather than a fraction of the December 31, 2012 Consent Decree emission limit. By correcting the effective date of the FGD requirement on Baldwin Unit 2 and using Unit 2's current emission rate, the SO2 allowance allocation for Unit 2 should increase from 1,319 allowances per year in 2012 and 2013 to 7,809 allowances per year. [EPA-HQ-OAR-2009-0491-2698.1,pp.3-4] This correction of the FGD effective date and allowance calculation for Baldwin Unit 2 is consistent with EPA's proposed allowance allocation for Dynegy's Havana Unit 6, which is also subject to the same 'no later than' December 3 1,2012 FGD compliance date in the Consent Decree. Because EPA adjusted allocations downward only 'if the unit has additional pollution controls projected to be online by 2012' (75 Fed. Reg. at 45309), and because Baldwin Unit 2 will not have an FOD online by January 1, 2012, the allowance allocation for Baldwin Unit 2 should not have been adjusted downward. Thus, EPA must correct the allocation for Baldwin Unit 2 and Illinois state budget, which can be made without adversely impacting any other EGU. [EPA-HQ-OAR-2009-0491-2698.1,p.4]
EPA's proposed SO2 allowance allocations for units operating existing scrubbers are based on reductions up to the scrubbers ' 'design removal efficiencies'. See 75 Fed. Reg. at 45281. The design removal efficiency EPA has assumed for the Baldwin Unit 1, 2 and 3 scrubbers (i. C., 95%) is incorrect. The incorrect assumptions for the Baldwin scrubbers are found in the NEEDSv3.02 EISA.xls spreadsheet (i.e., see 'Wet/Dry Scrubber' column V which indicates a Wet Scrubber, and the 'Scrubber Efficiency' in column Y that indicates 95% removal efficiency). Also, these incorrect assumptions are found in the NEEDSv4.10.xls spreadsheet, where column W represents 'Wet Scrubbers' but the column Y 'Scrubber Efficiency' now lists 98% removal efficiency. If as indicated in the September I, 2010 NODA EPA uses that IPM and NEEDSv4.10 to determine the final allocations for the Transport Rule, the NEEDSv4.10 file also needs correction. [EPA-HQ-OAR-2009-0491-2698.1,p.4] The correct design emission rate for each of the Baldwin dry scrubbers is 0. 100 lb/mmBtu SO2. That design emission rate -- 0. 100 lbs/mmBtu SO2 (1-hour average) -- is specified in the conformed FGD project specifications, as well as in the air construction permit applications submitted by Dynegy for the dry scrubbers at Baldwin. Furthermore, the Illinois EPA-issued construction permits authorizing installation of the dry scrubbers on Baldwin Units 1, 2 and 3 are based on 0.100 lb/mmBtu SO2. No other more stringent SO2 emission limit applies. Indeed, Dynegy has already entered into contracts and has begun construction of all four dry scrubbers required by the Consent Decree. It is not possible to re-design these dry scrubbers at this point because it would cause Dynegy to violate the compliance deadlines of the Consent Decree. [EPA-HQ-OAR-2009-0491-2698.1,p.4]
Importantly, EPA's incorrect assumption regard ing a 95 percent removal efficiency for the Baldwin scrubbers also fails to recognize a key difference between wet and dry scrubbers. Paragraph 67 o f the Consent Decree (see Attachment A) expressly allows installation of either wet or dry scrubbers at Baldwin. Dynegy has elected to construct dry scrubbers, since it had previously converted the Baldwin units to low sulfur Powder River Basin (PRS) coal. With our PRB coal having uncontrolled S0:2 emissions of 0.4 to 0.5 lbs SO2/mmBtu , Dynegy's dry scrubbers need to achieve 75% to 80% removal efficiency to attain the Consent Decree required emission limit of 0. 1 00 lb/mmBtu S02 30-day rolling average. Only if the Baldwin units were combusting high sulfur coal, which they are not, would wet scrubbers capable of 95 percent (or greater) removal efficiency have been needed. EPA must recognize in this rulemaking and in its IPM model that the design removal capability of wet and dry scrubbers arc appreciably different and that dry scrubbers designed for low sulfur PRB coal do not need to attain the same high removal efficiencies as wet scrubbers. [EPA-HQ-OAR-2009-0491-2698.1,pp.4-5] In short, if EPA retains Phase 1 (2012-2013) of this proposed rule, the Phase 1 SO2 allowance allocations for Baldwin Units 1 and 3 should be based on 0.100 lb/mmBtu SO2 with Baldwin Unit 1 allocated 2,054 SO2 allowances per year in 2012 and 2013 and Baldwin Unit 3 allocated 2,077 SO2 allowances per year in 2012 and 2013. Baldwin Unit 2, which will not have a scrubber until 20 13 (i.e., December 31, 2012), should be allocated 7,809 SO2 allowances per year in 2012 and 2013. Likewise, the Phase 2 allocations for the Baldwin units should based on 0.100 lb/mmBtu SO2 with Baldwin Unit 1 allocated 2, 187 SO2 allowances per year, Baldwin Unit 2 2,255 SO2 allowances per year and Baldwin Unit 3 2,328 allowances per year. [EPA-HQ-OAR-2009-0491-2698.1, p.5]
At several of Dynegy's EGUs the four quarters of heat input data used by EPA to determine allowance allocations were not representative of normal unit operation. See EPA spreadsheet 'BADetailedData.xls' in the Allocations & Rate Limits worksheet. The data are in column O 'Heat Input Assumed in 2012 SO2 Allocation', column Q 'Heat Input Assumed in Annual NOx Allocation', and column R 'Heat Input Assumed in Ozone Season NOx Allocation.' These instances of unusually low heat inputs were largely due to extended outages associated with the installation of new baghouse systems and activated carbon injection systems (i.e., Baldwin Unit 3, Havana Unit 6, Hennepin Units 1 and 2). Economic and weather conditions during 2008 and 2009 also resulted in unit heat inputs that were significantly lower than typical. [EPA-HQ-OAR-2009-0491-2698.1,p.5]
Attachment B to this letter identifies the heat input values EPA used for the affected Dynegy units and the heat input values that Dynegy believes are more representative of normal unit operation. Attachment B also explains the reasons EPA's heat input values are not representative. Dynegy requests that EPA replace its original heat input values with the more representative heat inputs when it recalculates Dynegy's allowance allocations for these units. EPA's recalculation of Dynegy's allocations should result in 6,407 SO2 allowances in 2012 and 2013 for Havana Unit 6; 4,752 SO2 allowances in 2012 and 2013 for Hennepin Unit 2; 993 Annual NOx allowances per year for Baldwin Unit 1; 379 Annual NOx allowances per year for Hennepin Unit 1; 1,279 Annual NOX allowances per year for Hennepin Unit 2; 590 Annual NOx allowances per year for Wood River Unit 4; and 159 ozone season NOx allowances for Hennepin Unit 1. [EPA-HQ-OAR-2009-0491-2698.1,p.5] [[See Docket Number EPA-HQ-OAR-2009-0491-2698.1, pp.20-21 for Attachment B.]]
Other Technical Errors Involving Dynegy EGUs
EPA's data tables and allowance allocations for Dynegy units also include other technical errors. These Dynegy unit-specific errors are identified in Attachment C to this letter. EPA must correct each of these errors and recalculate the allowance allocations accordingly. [EPA-HQ-OAR-2009-0491-2698.1, p.6] [[See Docket Number EPA-HQ-OAR-2009-0491-2698.1, pp.22-30 for Attachment C.]]
Footnote 3: Specifically, 66 of the Consent Decree -- see Attachment A -- requires installation and operation of an FGD on each of the three units at Baldwin according to the following staggered scheduled: on anyone of the three Baldwin units by no later than December 31, 2010, on a second Baldwin unit by December 31, 2011, and on the remaining third Baldwin unit by December 31, 2012. Baldwin Unit 2 is the last of the three Baldwin units on which an FGD will be installed. [EPA-HQ-OAR-2009-0491-2698.1,p.3] [[See Docket Number EPA-HQ-OAR-2009-0491-2698.1, pp.10-19 for Attachment A]]
East Kentucky Power Cooperative
Further, at the EKPC Spurlock Station, Units 3 and 4 have the same NOx control equipment, yet they are given different NOx rates without explanation. Also without explanation, EPA assigned no annual NOx or S02 allocations for the natural gas turbines at EKPC's Smith Station. Again, there are no S02 allocations for EKPC's Dale Stations Units 1 and 2 for 2014. Further, the rated capacities for most of EKPC's units are incorrect and appear to be based on original unit guarantees rather than on actual 2009 operating data or data from EKPC's Consent Decree entered into with EPA. The capacities as stated in the Consent Decrees EKPC entered into with EPA are contained in the following chart: [EPA-HQ-OAR-2009-0491-2776.1, p.2; see p.3 of this comment summary for the capacities as stated in the Consent Decrees EKPC entered into with EPA]
Also, EPA assigned allocations to Cooper Units 1 and 2 based on controls that do not yet exist and thus assigned allocations that are too low. While controls will be installed on these units in the future per a Consent Decree entered into with EPA, the analysis for the rule is based on 2009 data when the units have no scrubbers in operation, no SCRs in operation and have only low NOx burners in operation. Therefore, the allocations are artificially low. [EPA-HQ-OAR-2009-0491-2776.1, p.3]
Additionally, the emission allocation for EKPC Spurlock Unit 4 was based on 2009 which is the year the unit began operation, creating a lower allocation than is appropriate since no emissions were considered from January 1 through March 19, 2009 when the unit experienced initial startup. Along these same lines, EKPC's Spurlock Unit 1 commenced commercial operation of the new pollution control train consisting of a SCR, WFGD and WESP on April 1, 2009. EPA should therefore use 12 months of the unscrubbed allocations based upon this fact, otherwise the rule unfairly penalizes EKPC. [EPA-HQ-OAR-2009-0491-2776.1, p.3]
EKPC is generally concerned that the basis for emissions allocations utilize 2009 emissions data for SO2 and NOx. As with the remainder of the economy, coal-fired generation and emissions were significantly depressed during the 2008 2009 year due to the economic recession. Therefore, data from this period is inappropriate as it is not representative of normal conditions. EPA should utilize data from 2005-2007. A three year averaging methodology, as was used for CAIR, is consistent with EPA historical approaches and the 2005-2007 period provides a more accurate database for establishing allocations. [EPA-HQ-OAR-2009-0491-2776.1, p.3]
The above are just a few examples of questions that arise when examining EPA's underlying data by only one regulated entity. EPA should revisit the rule to examine the underlying data for accuracy or, at the very least, provide valid explanations for such inconsistencies. EPA should also clarify the methodology and calculations used to develop the 2012 and 2014 emissions and allocations for S02 and NOx such that its calculations are transparent and the regulated community can fully understand the allocations assigned. EKPC further requests that EPA clarify that compliance with CATR would be based on a system-wide approach rather than a plant or unit approach. [EPA-HQ-OAR-2009-0491-2776.1, p.3]
Entergy Services, Inc.
Warren Peaking Power Facility
Entergy would like to take this opportunity to correct an error in the Mississippi allocation pool of allowances.  The proposed rule states that the Warren Peaking Power Facility (ORIS 55303) is located in Mississippi when in fact these four peaking units were decommissioned, sold, and relocated to two non-Entergy sites in Texas in 2008.  Two of the units were installed at the San Jacinto County Peaking Facility (ORIS 56603) and the other two units were installed at the Hardin County Peaking Facility (ORIS 56604).  Entergy requests that EPA remove the Warren Peaking Power Facility from the Mississippi pool and add the San Jacinto County and Hardin County Peaking Facilities to the Texas pool of allowances.  [EPA-HQ-OAR-2009-0491-2847.1, p.14]
Nelson Industrial Steam Electric Company (NISCO) Units
Entergy would like to take this opportunity to correct an error in the Louisiana allocation pool of allowances.  The proposed rule states that NOx and SO2 allowances are allocated to R S Nelson, ORIS Code 1393, Units 1A and 2A.  These units are actually named Nelson Industrial Steam and Operating Company (NISCO), ORIS Code 50030, Units 1A and 2A.   Entergy requests that EPA correct this error in the final regulation so the NISCO units are awarded the appropriate allowances. [EPA-HQ-OAR-2009-0491-2847.1, p.14]
Faribault Energy Park
During review of data used by the EPA to calculate projected NOx and SOx emission values for the Faribault Energy Park, MN facility (ORIS ID No. 56164), it appears that the Projected Annual Heat Input values used for SOx and NOx are 437,400 mmBtu and 1,314,500 mmBtu respectively. We feel this basis is neither typical nor representative of our current operation due to the following reasons.
- This was a newly constructed facility in 2005 that operated only for the last 6 months in 2005 in Simple-Cycle mode using natural gas as a fuel source. At that time there was no historical data for this facility to provide information on typical operations.
- In the third quarter of 2007 the plant was converted to a Combined-Cycle operation.
- In 2008, the first full year operating as a combined cycle, the actual reported annual Heat Input value was 3,069,445 mmBtu as reported in our quarterly reports to the EPA.
Due to the significant difference in annual Heat Input values utilized for calculating the two emissions and the actual 2008 reported Heat Input value, we respectfully request the EPA use the actual report 2008 Heat Input value of 3,069,445 mmBtu to calculate both SOx and NOx emissions. [EPA-HQ-OAR-2009-0491-3146 p.1]
Florida Municipal Power Agency (FMPA)
C.     The Allocation Table in the TSDs Contains Errors and Omissions
FMPA believes there are errors and omissions with respect to certain FMPA generating units in the Allocation Table included in the Technical Support Documents for the Proposed Transport Rule, which we understand EPA intends to incorporate into the Final Rule as Appendix A.[2]  The following errors and omissions must be corrected prior to their incorporation into the Final Rule: [EPA-HQ-OAR-2009-0491-2725.1, pp.5-6]
[For additional comments pertaining to errors and omissions, see pp. 5-6 of this comment]

2.  FMPA intends to submit additional comments on errors in the characterization of our generating units in the NEEDS database prior to the October 15, 2010, deadline. [EPA-HQ-OAR-2009-0491-2725.1, p.5]
Formosa Plastics Corporation, LA
A review of the Allocation Table indicates the EPA has allocated 8 tons of Annual and Ozone Seasonal NOx for each of three gas turbines (GT1, GT2, and GT3) operated by FPC. Please know that FPC recently decommissioned GTI and is no longer a source at FPC. [EPA-HQ-OAR-2009-0491-1258, p.1]
Additionally, FPC understands that existing units GT2 and GT3 are cogeneration units as defined in the above referenced rule. However, as these cogeneration units do not serve a generator with a nameplate capacity of more than 25 MWe that supplies for sale more than 219,000 MWh of electricity in a calendar year, these sources are exempted from applicability of the above referenced rule per 40 CFR 97.404(b)(1)(i), 97.504(b)(l)(i), and 97.604(b)(I)(i). As such, FPC requests removal of FPC's sources from the Allocation Table since none of the FPC listed sources meet the applicability criteria in the proposed EPA Federal Implementation Plan. [EPA-HQ-OAR-2009-0491-1258, p.1]
Giarmarco, Mullins & Horton, P.C.
- The unit specific data for MCV does not identify allowances for units 016, 017, 018, 019,020 and 021. MCV commenced operation of these units in the spring of 2009 and seeks allowances commensurate with its anticipated operations from that date forward. [EPA-HQ-OAR-2009-0491-2766.1, p.3]
MCV has reviewed the allocation information contained in the 'Budget and Allocations - Detailed Unit-Level Data' spreadsheets as part of EPA's Notice of Data Availability dated September 1, 2010. Comments related to that review have been submitted to EPA on October 1, 2010. As part of that submittal, MCV referenced and incorporated those comments submitted by the State of Michigan and/or its Department of Natural Resources and Environment. Upon further review of the exhibits to those comments, MCV uncovered typographical errors related to MCV's unit specific allocations for the NOx annual and ozone season. MCV has provided revised tables for the annual and ozone season for consideration by EPA which are attached in Exhibit A and B, respectively.  [EPA-HQ-OAR-2009-0491-3760.1_NODA, p.1] [[See Docket Number EPA-HQ-OAR-2009-0491-3760.1_NODA, pp.3-4 for Exhibits A and B.]]
As is evident in both exhibits, projected TR NOx allocations for MCV are extremely low and represent about 5% of the amount that MCV was expected to receive in the CAIR 2012 allocation. As stated in the previously submitted comments, MCV believes that the cause of this occurrence is EPA's treatment of MCV as a peaker facility in its IPM model assumptions, which would be incorrect. As EPA is aware, a peaking power plant, by definition, is a quick-start resource that generates electricity in periods of high demand. Peaker plants are generally simple cycle gas plants with quick-start capability able to generate within 10 to 30 minutes from start-up. Unlike peakers, MCV is a combined-cycle cogeneration plant without quick start capability and designed to run as a base load plant. MCV has baseload generation serving 100% of the electric energy and process steam process requirements of The Dow Chemical Company's Michigan Division under a long-term contract. Additionally, MCV's steam turbine is synched to the transmission grid on a constant 24/7 basis, and when combined with the gas turbines the facility delivers full plant capacity under its long-term Power Purchase Agreement with Consumers Energy. The baseload operation of the plant is further reflected in the historical heat input values identified in Exhibits A and B. [EPA-HQ-OAR-2009-0491-3760.1_NODA, p.2]
Great River Energy
 :: The model had many inaccuracies. Some specific examples include:
[EPA-HQ-OAR-2009-0491-2758.1 p.3]
o Pleasant Valley Station (ORIS Code 7843) Unit 11 had data missing (heat input, NOx and S02 mass emissions) for the 3rd quarter of2009.
o Elk River Peaking Station (ORIS Code 2039) Unit 11
:: Due to CEMS commissioning, EDR data provided by the Clean Air Markets Division of EPA did not include emissions until Oct. 2009. :: 2009 is not a representative year for this unit. (See Attachment 1.)
o Maple Lake Station (ORIS Code 2042) Unit 1
:: Is listed twice and one of the listings with a capacity of 0 MW is checked as being a covered unit>25 MW.
:: There are no emissions associated with this listing in the model but the second listing has emissions associated with the entry. It has the capacity listed at ~19MW and is not checked as a covered unit> 25 MW.
:: Data are missing for S02 mass emissions for 2008 since this unit reported emissions under the CAIR program prior to it being stayed for Minnesota.
o Rock Lake (ORIS Code 6741) Unit 1
:: Is also listed twice and one of the listings with a capacity of 0 MW is checked as being a covered unit >25 MW.
:: There are no emissions associated with this listing in the model but the second listing has emissions associated with the entry and it has the capacity listed at ~19MW and is not checked as a covered unit> 25 MW.
:: Data are missing for S02 mass emissions for 2008 since this unit reported emissions under the CAIR program prior to it being stayed for Minnesota.
o Cambridge Station (ORIS Code 2038) Unit 1
[EPA-HQ-OAR-2009-0491-2758.1 p.3]
:: Data are missing for S02 mass emissions for 2008 since these units reported emissions under the CAIR program prior to the rules for the state of Minnesota being stayed.
:: Is an identically sized unit as ORIS code 2042 and 6741 and this unit was not included as a covered unit> 25 MW. [EPA-HQ-OAR-2009-0491-2758.1 p.4]
:: At times, EPA uses a different heat input value for determining NOx versus S02 allocations. It is unclear how and why EPA uses these different values. As one example, for Lakefield Junction, EPA uses a much lower S02 heat input (174,306 mmBtu for all units) than different and variable NOx heat input for each unit. The lower S02 heat input results in fewer S02 allowances allocated to our units. [EPA-HQ-OAR-2009-0491-2758.1 p.4]
:: EPA's model incorrectly assumes only natural gas combustion for our dual fuel peaking turbines. The vast majority of our peaking turbines are dual fuel fired, with gas contracts that are interruptible. Each plant has different gas contracts and is supplied by different gas companies and/or lines. In general, the gas fired units can be curtailed in winter, requiring them to run on fuel oil. Unfortunately, EPA does not factor this fuel variability into their modeling. GRE would be forced to shut down units in the winter, when gas is curtailed, and allowances may not be available. EPA must revise the projected emissions to be inclusive of dual fuel capability for both NOx and S02 allowances. [EPA-HQ-OAR-2009-0491-2758.1 p.4]
Illinois Environmental Protection Agency
Technical Corrections Needed for Illinois EGUs
In reviewing U.S. EPA's technical support information accompanying the proposed Transport Rule, Illinois EPA identified several inaccuracies that should be addressed before final allocations are determined. Listed below are brief descriptions of the needed corrections. The Illinois EPA, in conjunction with Illinois utilities, will work with U.S. EPA to provide corrections consistent with the Notice of Data Availability, announced by U.S. EPA on September 1, 2010.
 :: Prairie State Energy Campus, a 1,600-megawatt coal-fired electric generating facility in Illinois, commenced construction in 2007, and will begin operating in late 2011 and early in 2012. This facility has not been included in U.S. EPA's modeling and therefore has not been proposed to receive allocations. The Illinois EPA recommends that Prairie State be considered as an existing source for the purposes of the Transport Rule and should be allocated allowances consistent with an annual and seasonal utilization as a base-load facility. Illinois EPA looks forward to working with U.S. EPA to determine an appropriate allowance allocation for this facility.
 :: U.S. EPA's list of affected sources includes four emission units at Morris Cogeneration (ORIS ill 55216) that should not be included as EGUs. The Illinois EPA has permitted Morris Cogeneration as a non-EGU, and it has not received allowances under Illinois' CAIR rule. Illinois EPA recommends that Morris Cogeneration be removed from the list of EGUs affected by the proposed Transport Rule.
 :: City Water Light & Power's (CWLP) Dalhnan plant Unit 4 (Oris 963) is misidentified as Unit 34. Also, since the Dallman 4 unit has only recently been constructed, the historical heat input used by U.S. EPA in calculating its proposed allocation is not representative of expected operations of this unit. Illinois EPA looks forward to working with U.S. EPA to determine an appropriate allowance allocation for this unit.
 :: The assumed heat input for City Water Light & Power's (CWLP) Dallman Unit 31 is not representative of historic operations of this unit (in fact the heat input is listed as 0 for the annual and seasonal NOx allocations). The heat input for this unit should mirror the value for its sister unit, Dallman Unit 32, with which it shares a common scrubber and stack. Also, the emission rates for Dallman Units 31 and 32 should be the same because they share a common FGD and stack.
 :: U.S. EPA's assumption that the FGD system controlling Dynegy's Baldwin unit 2 will be operational prior to 2012 is incorrect. Based on a Federal consent decree, the FGD system should be in operation by December 31, 2012 for Baldwin unit 2.
 :: U.S. EPA assumed that Ameren's Joppa unit 2 has an existing OFA, which is incorrect. Also, Joppa units 5 and 6 have OF A, but these are not listed.
 :: U.S. EPA's modeling has determined that Ameren's Meredosia units 1 and 2 will be shut down by 2014. Ameren has no plans to shut down these units. U.S. EPA should provide adequate allowances for these units.  [EPA-HQ-OAR-2009-0491-2781.1 p.3-4]
Indiana Energy Association
c. The aforementioned errors in technical assumptions have resulted in such significant errors in allocation budgets that the allocation scheme as proposed is arbitrary. The Indiana Utility Group suggests that the proposed allocation budgets bear little resemblance to existing or projected EGU operations . The Indiana Utility Group urges EPA to develop a revised allocation budget that is consistent with actual EGU operations . [EPA-HQ-OAR-2009-0491-3711 p.3]
Lafayette Utilities System
Comments on NOx Unit Level Allocations
EPA should not regulate NOx emissions from Louisiana EGUs at all, for the reasons stated above. However, in the alternative, and without waiving any legal right to challenge EPA's determination to impose a FIP with annual or ozone season NOx controls, LUS believes that EPA must either allow Louisiana to perform the NOx unit level allocations, or should substantially revise the NOx unit level allocations in Louisiana. [EPA-HQ-OAR-2009-0491-2983.1,p.8]
Errors in the EPA Modeling and Projections
Based on its review of EPA's Allocation Table, LUS has discovered quite a number of errors made by EPA regarding the EGUs' actual emissions rates. LUS believes that this information has directly impacted the units' allocations. [EPA-HQ-OAR-2009-0491-2983.1,p.9]
a. The Louis Doc Bonin Unit 1 and Unit 2 did not receive any NOx allocations under the proposed Transport Rule/FIP.  The Louis Doc Bonin Unit 3 did receive proposed allocations. Under the Direct Control alternative, EPA failed to provide the Louis Doc Bonin Unit 1 and Unit 2 with 0.000 allowable annual and ozone season NOx emission rates.  Unit 1 and 2 are not scheduled to retire and are subject to dispatch by the Southwest Power Pool. They have in fact been dispatched over the past five years. While the allocations for Unit 3 could be used for Units 1 and 2 under some of EPA's proposed options, these may not be sufficient. Further, the ozone season heat input data for the Louis Doc Bonin units appears to be an arbitrary 10% of the annual heat input. This appears to be a data error that should certainly be adjusted in any final projections if they are to be used for unit-level allocations. [EPA-HQ-OAR-2009-0491-2983.1,p.9]
The actual data concerning the utilization of these units, as reported to EPA's CAMD under the CAIR program compared to the Transport Rule/FIP projections are as follows: [EPA-HQ-OAR-2009-0491-2983.1,p .9] [[See Docket Number EPA-HQ-OAR-2009-0491-2983.1,p.10 for the table.]]
It is clear that these units have run every year and are continuing to be utilized. Moreover, they are utilized for a substantial portion of time outside of the May-September ozone season. EPA has provided no transparent or rational reason as to why the Doc Bonin Units 1 and 2 would not be allocated NOx emissions or why they believe these would not run in 2012. EPA did not project that any of these units would require retrofit. If the IPM 'economic' projection is the rationale, EP A must explain the basis for that economic rationale in a maImer that allows LUS comment. LUS does not believe that the Clean Air Act authorizes EPA to 'project' Unit 1 and 2 out of operation for no discernable environmental reason. Similarly, the Act does not authorize EPA to limit operation of the No. 3 unit simply because EPA projects that it will operate less for economic, nonenvironmental reasons. In essence, this is what EP A has done through its unit level allocations for the proposed trading options. [EPA-HQ-OAR-2009-0491-2983.1,p.10]
Under the direct control alternative, as LUS understands it, Units 1 and 2 could not run at all because they are not provided with allowable emission rates. CAMD data show that the NOx emission rates for Units 1 and 2 are as follows:
 Unit 1 has run at annual average rates of 0.03 to 0.19 lb/mmBtu for the last several years
Unit 2 has run at annual average rates of 0.10 to 0.12 lb/mmBtu for the last several years. [EPA-HQ-OAR-2009-0491-2983.1,p.10]
The ozone season and annual NOx emission rates were identical in each year. LUS requests that the direct control option be amended to provide that such units are authorized to run at such rates. [EPA-HQ-OAR-2009-0491-2983.1,p.11]
b. The annual and ozone season NOx allocations for T J Labbe' Unit 1 and Unit 2 and Hargis-Hebert Unit 1 and Unit 2 are significantly less than actual NOx reported emissions and are based on projected heat input much less than actual heat input rates have historically been. Again, as for the Doc Bonin units, the ozone season heat input data for the Louis Doc Bonin units appears to be an arbitrary 10% of the annual heat input. This appears to be a data error as these units clearly run for more than 10% of each year. Further, the annual NOx rates listed under the Direct Control Alternative for T J Labbe' Unit 1 and Unit 2 and Hargis-Hebert Unit 1 and Unit 2 are less than actual reported emission rates.  Because EPA has allocated to these units far less than the allowances necessary to operate at their present operating levels, LUS will be forced to either pay for NOx allowances if it is able to purchase them from another Louisiana utility or install additional controls to keep these units in production. However, these additional controls cannot be put into place by the January 1, 2012 compliance date, which means that LUS may have to cut these units' production to remain in compliance with federal regulations. Such an action will have a devastating impact on the LUS customers relying on these units for their electrical needs. [EPA-HQ-OAR-2009-0491-2983.1,p.11]
It is clear that these units have run every year and are continuing to be utilized. Moreover, they are utilized for a substantial portion of time outside of the May-September ozone season. EPA has provided no transparent or rational reason as to why the Hargis-Hebert and TJ Labbe units would be allocated NOx emissions so far below those that would be indicated by their actual historic operating rates. EPA does not explain at all, other than to say it is an economic output of the IPM, why it believes these units would be utilized so much less in 2012 than the actual historic data would suggest. EPA did not project that any of these units would require retrofit. LUS has no plan to curtail operation of these units in that time period. If the IPM 'economic' projection is the rationale, EPA must explain the basis for that economic rationale in a manner that is transparent and allows LUS comment. LUS does not believe that the Clean Air Act authorizes EPA to limit operation of these units simply because EPA projects that they will operate less in 2012 due to economic, non environmental reasons. In essence, this is what EP A has done through its unit level allocations for the proposed trading options. [EPA-HQ-OAR-2009-0491-2983.1,pp.12-13]
LUS has also discovered additional incomplete and/or inaccurate emissions data for its EGUs in the Excel spreadsheets for the Detailed Unit-Level Allocations. LUS's comments are as follows: [EPA-HQ-OAR-2009-0491-2983.1,p.13]
Reported Table Data:
i. The 2008 reported annual heat input is missing for Louis Doc Bonin Unit 1, Unit 2 and Unit 3.
ii. The 2008 reported annual heat input is missing for T J Labbe' Unit 1.
iii. The most recent fourth quarter emissions of annual NOx mass, annual SO2 mass, and annual heat input are missing for Louis Doc Bonin Unit 3. [EPA-HQ-OAR-2009-0491-2983.1,p.13]
Projected Data Table:
i. The annual heat inputs assumed for Louis Doc Bonin Unit 3, T J Labbe' Unit 1 and Unit 2, and Hargis-Hebert Unit 1 and Unit 2 are significantly lower than reported emissions data. For example, the annual heat input for Hargis-Hebert Unit 1 was 961,796 mmBtu for 2008 and 466,058 mmBtu for 2009. However, EPA listed the Projected Base Case annual heat input in the Projected Data Table as 99,100 mmBtu. [EPA-HQ-OAR-2009-0491-2983.1,p.13]
ii. The heat inputs for Louis Doc Bonin Unit 1 and Unit 2 are listed as 0 mmBtu. These units are not scheduled to retire and are subject to dispatch by the Southwest Power Pool.
iii. The annual and ozone season NOx emissions are significantly lower than reported emissions data. [EPA-HQ-OAR-2009-0491-2983.1,p.14]
Adjusted Data Table:
i. The adjusted annual and ozone season NOx emissions are significantly lower than reported emissions data. [EPA-HQ-OAR-2009-0491-2983.1,p.14]
LUS believes that EPA made the following data errors in the IPM Model Parsed Files:
i. The summer fuel use and total fuel use for Louis Doc Bonin Unit 3, T J Labbe' Unit 1 and Unit 2 and Hargis-Hebert Unit 1 and Unit 2 is significantly lower than reported emissions data.
ii. The summer fuel use and total fuel use for Louis Doc Bonin Unit 3 and T J Labbe' Unit 1 and Unit 2 have the same values in the spreadsheets. However, the total fuel use per year is greater than summer fuel use.
iii. The summer fuel use and total fuel use for Louis Doc Bonin Unit 1 and Unit 2 are listed as 0 TBtu in the Parsed File Tables. These units are not scheduled to retire and are subject to dispatch by the Southwest Power Pool.
IV. Summer and Total NOx emissions are significantly lower than reported emissions data.
v. Total C02 emissions are significantly lower than reported emissions data. [EPA-HQ-OAR-2009-0491-2983.1,p.14]
Lakeland Electric
In Technical Support Document (TSD) #320292, EPA provides a spreadsheet tab labeled "Unit Characteristics" which contains columns for the installation date of SCRs, SNCRs, and FGDs. Unit ID 3 at C.D. McIntosh, Jr. Power Plant (ORIS 0676) has had an FGD scrubber installed since its construction in 1980 and is required to operate under the Plant's Title V operating permit. Unit 3 also has an SCR, which began operating in 2009 and is required to operate under the same Title V operating permit issued by the State of Florida. This appears to be inconsistent with the TSD which does not list either of these two control equipment processes installed and cites that Unit 3 will be required to scrub SO2 by 85.8% in excess of what it is doing presently in the future which will be unobtainable and will force this unit to shut down or change fuel to natural gas. [EPA-HQ-OAR-2009-0491-2630.1 ,p.2]
In the same TSD, EPA has cited Lakeland's Winston Peaking Station as not having SCRs on any of its 20 peaking units. However, the units at Winston Peaking Station are required to run and operate their individual SCRs in order to remain in compliance with the Facility's Title V permit. These Units' SCRs were installed in 2001 and therefore, this TSD should be updated to reflect the actual control equipment present at this facility and EPA should perform an updated modeling run which reflects these changes. [EPA-HQ-OAR-2009-0491-2630.1, p.2]
Lakeland operates multiple units that have the ability to fire pipeline natural gas (PNG) and fuel oil. Most of these units have fired fuel oil in the past 12 months on multiple occasions; however, EPA has not allotted any SO2 allowances to these units. [EPA-HQ-OAR-2009-0491-2630.1, p.3]
A good example is Lakeland's Winston Peaking Station. This power plant consists of 20 peaking stations which, although permitted to fire PNG, at this time only fires #2 fuel oil because of the lack of PNG in the vicinity and thus has been unable to utilize this fuel. EPA, according to the above cited TSD, has not projected any SO2 emissions from this plant even though EPA assumes that the plant will have an annual heat input value of approximately 121,700 mmBtu. In fact, these units are required to operate periodically (i.e., monthly) in order to meet reliability requirements. Therefore, Lakeland requests that this facility be given representative SO2 allowances based on historical operational data. Although Winston plant operates every month consistently throughout the year, and the Plant's highest operations are usually during the summer months, EPA, in the above cited referenced TSD, has only allotted these units a heat input value for non-summer months, thus negating these units from having any Ozone Season allowances. In the same TSD, on the "Allocations and Rate Limits" tab, EPA has cited a heat input value for SO2 allowance allocations, but EPA has not cited any NOx allowance heat input values. These units, when burning #2 fuel oil, emit SO2 AND NOx emissions, however, it appears EPA has not allocated any heat input associated with NOx emissions. Lakeland believes that the Winston Peaking Station units should be allocated heat input values based on its past operation for calculating future NOx allowances because such changes would be consistent with actual operating data. EPA's TSD projected data does not appear to represent past or current operations at this site and therefore EPA should revisit this Plant's data and allocate Ozone Season and Annual NOx allowances and Annual SO2 allowances to this Plant's units. [EPA-HQ-OAR-2009-0491-2630.1 ,p.3]
Unit 8 at Lakeland's Charles Larsen Memorial Power Plant (ORIS 0675) also has dual fuel firing capability (PNG and fuel oil) but has not received any SO2 allowances. Over the past five years annually, Unit 8 has operated on fuel oil and Lakeland believes that this Unit will continue to fire fuel oil in the future and specially when there are natural gas spikes, as has been seen consistently in the past. Records of Unit 8's past fuel oil firing data has been uploaded to EPA's CAMD website and EPA should consider this Unit's current and past actual operation instead of relying completely on modeling software. [EPA-HQ-OAR-2009-0491-2630.1, p.3]
Unit 2 at Lakeland's C.D. McIntosh, Jr. Power Plant was projected by EPA not to operate at all on any fuel in the future per EPA's above cited TSD (see "Projected Data" tab). This reasoning is quite bizarre as EPA has chosen this Unit to perform Part III Emissions Testing per EPA's Utility MACT ICR. This is a dual-fuel fired unit (PNG and fuel oil), which was required to operate on fuel oil in order to satisfy EPA's testing conditions. As it appears, EPA has requested Lakeland to perform over $100,000 in testing on Unit 2, through the Utility MACT ICR, for what EPA projects to be a maximum of one year of additional operation (no operation projected for 2012 and beyond).  [EPA-HQ-OAR-2009-0491-2630.1,p.4]
This surely must be an oversight, as Lakeland Electric has no intention on retiring Unit 2 anytime soon and in fact believes it to be a major contributor to its fleet for at least the next 15-20 years. Additionally, if EPA believes the unit will be retired in the next year, why did EPA require Unit 2 to perform Part III Emissions Testing under the Utility MACT ICR and what will EPA do with the results of an emission unit which it has modeled will be retired before the final MACT rule is implemented? [EPA-HQ-OAR-2009-0491-2630.1, p.4]
Unit 1 at Lakeland's C.D. McIntosh, Jr. Power Plant was also projected not to operate at all on any fuel in the future per EPA's above cited TSD (see "Projected Data" tab). However, Lakeland is currently performing routine maintenance on the Unit in order to bring the Unit back to operation from a forced outage. This unit can fire PNG and or fuel oil, and Lakeland believes that this Unit will operate in the future or else it would not be performing maintenance on the Unit. This is a case where EPA should analyze a different time frame over the past five year period in order to determine a better average heat input and emissions rate for the unit as suggested earlier. [EPA-HQ-OAR-2009-0491-2630.1, p.4]
In addition to the above cited believed discrepancies, the following peaking units at the C.D. McIntosh, Jr. Power Plant and Charles Larsen Memorial Power Plant were all assumed to no longer operate past 2011 per the above cited TSD. Again, each of these units has operated over the past 12 months, which can be verified through the Florida Department of Environmental Protection's (FDEP) Annual Operating Report (AOR) database system. The concerned units are:
(1) Unit ID GT1  -  C.D. McIntosh, Jr. Power Plant
(2) Unit ID 2  - Charles Larsen Memorial Power Plant
(3) Unit ID 3  - Charles Larsen Memorial Power Plant [EPA-HQ-OAR-2009-0491-2630.1, p.4]
Lakeland believes all three of these units should be allotted emissions allowances per their past and current operational capacities. Lakeland also believes that EPA should utilize FDEP's AOR database for these units instead of relying on modeling software which appears to have projected incorrect assumptions for multiple Lakeland's units. The AOR information can readily be obtained from FDEP and should be utilized where EPA has a lack of information, as in the case of many peaking units. [EPA-HQ-OAR-2009-0491-2630.1, pp.4-5]
EPA appears to have utilized 2008 and 2009 unit specific data for certain future allowance allocations calculations. For some of Lakeland's units, 2008 was more representative of a "normal" year than 2009, and for other units, it is the reverse. For example, on the above cited TSD, EPA cites on the "Projected Data" characteristics tab, that Unit 3 (same as above) is projected to emit 1923.7 tons SO2/year by 2012. In 2008, Unit 3 emitted 7599.2 tons of SO2 after scrubber. This represents an unprecedented additional 75% reduction on this Unit's SO2 emissions in one year (beginning of 2012). However, as stated earlier, this Unit already has a scrubber installed and classified under Subpart Da for PSC purposed and is required to operate the scrubber with certain efficiency in order to satisfy conditions in its Title V operating permit. Additionally, this Unit is restricted to a coal sulfur content not exceeding 1.92% sulfur. [EPA-HQ-OAR-2009-0491-2630.1 , p.2]
Lakeland further suspects that EPA may have based some of its calculations using Unit 3 emissions, heat input, or operating capacity from the 2009 operating year. In 2009, Unit 3 was in an extended outage for the installation of its SCR to allow for more compliance flexibility with EPA's Clean Air Interstate Rule (CAIR). This Unit has also experienced forced outages due to unplanned outages caused by the initial startup of the SCR system. Therefore, using 2009 for baseline calculations for Unit 3 is not a representative year for this unit. [EPA-HQ-OAR-2009-0491-2630.1, p.2]
Respectfully Lakeland suggests that EPA chooses a representative period (e.g., 12 months) over the past five years, or use an average of the previous five year period which does not include excessive unplanned outages, for determining a unit's operating parameters instead of selecting the years 2008 and 2009 for NOx and SO2 respectively. Additionally, Lakeland urges EPA to make the aforementioned corrections to the units' parameters that have been cited in this comment letter. Furthermore, Lakeland requests that EPA provide an additional notice and comment period to the electric utility industry for reviewing and correcting EPA's revisions to the allowances and unit parameters so that EPA can develop a more accurate database. [EPA-HQ-OAR-2009-0491-2630.1, pp.2-3]
Manitowoc Public Utilities (MPU)
 MPU (Manitowoc), ORIS 4125, unit 9 is included on the Proposed Transport Rule allocation table. However, the SO2 and NOx emission rates do not appear to be correct. We propose that the SO2 emission rate for 2012 and 2014 should be 0.30 lb/mmBtu and the NOx emission rate should be 0.077 lb/mmBtu.  [EPA-HQ-OAR-2009-0491-2860.1,p]
 MPU (Manitowoc), ORIS 4125, units 6,7 and 8 are not included on the Proposed Transport Rule allocation table. Units 6, 7, and 8 are regulated under CAIR and the ARP and we expect to receive a fair allocation for these existing units.  [EPA-HQ-OAR-2009-0491-2860.1,p.2]
MPU Unit 9 SO2 and NOx Emission Rates
MPU (Manitowoc), ORIS 4125, unit 9 is included on the Proposed Transport Rule allocation table. However, the SO2 and NOx emission rates utilized to make the allocations do not appear to be correct.  [EPA-HQ-OAR-2009-0491-2860.1,p.3]
We propose that the SO2 emission rate (lb/mmBtu) for 2012 and 2014 should be 0.30. The 2012 emission rate of 0.592 and the 2014 rate of 0.498 used in the EPA analysis are not realistic, as the unit 9 permitted emission limit for SO2 is 0.30. The actual annual SO2 emissions for 2012 and 2014 are expected to remain at the 2009 level of 450.2 tons per year.  [EPA-HQ-OAR-2009-0491-2860.1,p.3]
We propose that the NOx emission rate (lb/mmBtu) should be 0.077. We believe the NOx emission rate of 0.048 is not reasonable. During the permitting of unit 9 in 2003 it was believed that the NOx BACT limit for the CFB boiler would be 0.07. However, we could not get the boiler manufacturer to guarantee performance at that level and we utilized an alternate method. In 2009 the actual emission rate for unit 9 was 0.077 and total annual emissions were 131.9 tons, well above the allocated annual allowance of 102 tons. The actual annual NOx emissions for 2012 and 2014 are expected to remain at the 2010 level of 182 tons per year. [EPA-HQ-OAR-2009-0491-2860.1,p.3]
ORIS 4125, Units 6,7 and 8 Missing Allocation
MPU (Manitowoc), ORIS 4125, units 6,7 and 8 are not included on the Proposed Transport Rule allocation table. Units 6,7,and 8 are regulated under CAIR and the ARP and we expect to receive a fair allocation for these existing units. The actual annual SO2 emissions for 2012 and 2014 are expected to remain at the 2009 level of 336.6 tons per year for units 6,7, and 8 at an emission rate of 0.79 lb/mmBtu. The actual annual NOx emissions for 2012 and 2014 are expected to remain at the 2009 level of 85.5 tons per year for units 6,7, and 8 at an emission rate of 0.189 lb/mmBtu. Units 6, 7, 8 received a total CAIR annual allocation of 417 tons. [EPA-HQ-OAR-2009-0491-2860.1,pp.3-4]
Massachusetts Department of Environmental Protection
MassDEP requested that the affected facilities in Massachusetts review the proposed Transport Rule annual NOx and S02 allowance allocations. A number of facilities identified inconsistencies and incorrect assumptions in EPA's technical support documentation, including the IPM assumptions. For several Massachusetts sources, EPA's data on unit specific emission rates and controls used in the base case, 2012, and 2014 appear to omit existing pollution control devices. In addition, there are errors in primary fuel for several oil-fired EGU boilers in Massachusetts. The units and the corrected information are identified in the attached 'Corrections to Data and Assumptions for Massachusetts Facilities.'
EPA needs to correct these omissions and errors for individual units prior to finalizing final state budgets in the final Transport Rule. We encourage EPA to make the revised analysis and outcomes that incorporate the corrected information for units in Massachusetts and other states available for review as soon as possible.  [EPA-HQ-OAR-2009-0491-2787.2 p.10]
A material error for Massachusetts facilities identified in EPA's Technical Support Document (TSD) State Budgets, Unit Allocations and Unit Emissions Rate concerns Brayton Point Unit 3 (ORISPL 1619). In the TSD, EPA states that Brayton Point Unit 3 is 'expected to have a dry flue gas desulfurization unit (dry scrubber) rather than a wet scrubber by 2012.,,24 EPA's TSD accurately reflects the substitution of a wet scrubber with a dry scrubber on this unit, but does it not reflect the current timetable for installation of the dry scrubber.
The current PSD approval and MassDEP modified plan approval allows the operator to begin construction of a dry scrubber by April 2011. Dominion Energy New England, Inc., the operator of the Brayton Point facility, has provided a schedule to MassDEP showing construction of the scrubber commencing in 2012 with full operation by 1st Quarter 2014. We believe that EPA's incorrect assumption concerning the timeframe for installation of the scrubber must be corrected and that the Massachusetts 2012 S02 budget must be revised accordingly.
However, for 2014 and beyond, we believe the S02 allocation for Brayton Point and the Massachusetts Annual S02 budget should reflect the reduced emissions that will result from the installation of the scrubber, which has been in the planning stage since 2002. Assuming that EP A makes the correction to the scrubber installation date and the corresponding increase in the 2012 allocation for Brayton Point Unit 3, Brayton Point will continue to receive this allocation permanently until either EPA issues a subsequent transport rule or MassDEP changes allocations through a SIP.
Because Massachusetts is in the Group 2 S02 trading program it does not have a proposed lower budget in 2014. If Massachusetts remains in Group 2 in the final Transport Rule (see our Comment #7 above concerning switching from Group 2 to Group 1), despite the significantly reduced emissions from Brayton Point Unit 3 once the scrubber is operation, the budget and allocations will not change. We do not support this result and encourage EPA to provide allowances at the 2012 level only through 2013 for this unit.
EPA's revised analysis incorporating the increased 2012 and 2013 emissions from Brayton Point Unit 3 may result in Massachusetts showing an impact on downwind nonattainment and maintenance for PM2.S in 2012. If so, EPA may place Massachusetts in Group 1 in the final rule. In this case, a reduced Massachusetts S02 budget in 2014 should take into account the installation of the scrubber and its full operation in 2014.
Salem Harbor
We note that EPA has assumed that a scrubber will be installed on Unit 3 at the Salem Harbor facility in 2012. There are no plans to install a scrubber on this unit according to comments we have received from Dominion New England, Inc.
[EPA-HQ-OAR-2009-0491-2787.2 p.10-11]
Discrepancies in Allocations
Several facilities reported common concerns and issues identified in several supporting technical documents for the Transport Rule (75 Fed.Reg. 45210, August 2, 2010), including: the Technical Support Document entitled, State Budgets, Unit Allocations and Unit Emissions Rates (July 2010); the Budgets and Allocations Detailed Unit-Level Data spreadsheet. Common concerns included:
:: Heat input generation and emissions data for Steam generator and combustion turbines at combined cycle units were divided out between the combustion turbines and frequently shared steam generator in Budgets and Allocations Detailed Unit-Level Data spreadsheet, several facilities suspected this adversely affected allocation assumptions for low emitting gas/oil-fired combined cycle units for S02 allocations;
:: The 0.000 lbs/mmBtu S02 emission rate for combined cycle units in 2012 and 2014 in the Allocations & Rate Limits tab in the Budgets and Allocations Detailed Unit-Level Data spreadsheet should be replaced with the pipeline natural gas S02 emission factor and applicable emission limit for many affected combined cycle units of 0.0006 lbs/mmBtu when firing natural gas;
:: The Budgets and Allocations Detailed Unit-Level Data spreadsheet NOx and S02 emission rates appear to assume that combined cycle units fire exclusively natural gas, although many such units throughout New England are specifically permitted to also fire distillate fuel for limited periods of time in the event of winter supply interruptions. [EPA-HQ-OAR-2009-0491-2787.2] [EPA-HQ-OAR-2009-0491-3818.1_NODA, pp.7-8]
Blackstone (ORISPL 1594)
Blackstone Units 11 and 12 located at the Harvard University steam generation plant in Cambridge, MA and serve a common steam header along with two other boilers (Units 6 and 13 not affected Transport Rule EGUs). Units 11 and 12 are allocated allowances in the proposed Appendix A, but according to the operator neither qualify as Transport Rule eligible EGUs, with a nameplate capacity equal to or greater than 25 MWe.
:: Unit 11 is a Combustion Engineering VU-60 dual fuel boiler, rated at 252 mmBtu/hr (commenced operation in 1963) firing No.6 Fuel Oil and natural gas
:: Unit 12 is a Combustion Engineering VU-60 dual fuel boiler, rated at 286 mmBtu/hr (commenced operation in 1963) firing NO.6 Fuel Oil and natural gas. Blackstone Units 11 & 12, along with other two boilers (Units 6 and 13) feed at most 5 MW back pressure to a steam turbine that generates electricity. The name plate capacity for each of the boilers is less than 25 MW. Their inclusions in the Appendix A proposed allocations is likely attributable to the fact that Massachusetts included both units in the NOx SIP Call and CAIR NOx Ozone Season control programs as noted in the Transport Rule. As the proposed Transport Rule excludes EGUs below 25 MWe and non-EGUs, neither unit should be included in the Transport Rule 502 or NOx Annual Control Programs. [EPA-HQ-OAR-2009-0491-2787.2] [EPA-HQ-OAR-2009-0491-3818.1_NODA, p.8]
Brayton Point (ORISPL 1619)
Brayton Point (ORISPL 1619) Unit 3 is listed as a 612 MWe coal steam bituminous-fired boiler, equipped with wet scrubber online in 2006 in NEEDS v.4.10 EPA-HQ-OAR-2009-0491-0310. The reported nameplate capacity is 633 MWe, and as of September 2010 no scrubber has been installed. Current PSD approval and modified plan approval allows operator to commence construction of dry scrubber by April 2011. Operator provided construction schedule indicates dry scrubber online by 1st Quarter 2014. The dry scrubber will be equipped with a fabric filter baghouse for particulate control. [EPA-HQ-OAR-2009-0491-2787.2] [EPA-HQ-OAR-2009-0491-3818.1_NODA, p.8]
Montgomery L'Energia (ORSIPL 54586)
Combined cycle Rolls Royce Trent 60 with 545 mmBtu/hr maximum heat input, commenced operation in 2008. Allocated no allowances despite having higher 2009 heat input than other unit types having lower heat inputs. [EPA-HQ-OAR-2009-0491-2787.2]
We have provided above the corrections for NEEDS vA.l0 for this facility, noting that Montgomery L'Energia (ORSIPL 54586) Unit 2 was omitted from NEEDS v4.10 EPA-HQ-OAR-2009-0491-0310. The facility commenced commercial operation on October 29, 2008. We include the following data to demonstrate recent operations of the facility. [EPA-HQ-OAR-2009-0491-3818.1_NODA, p.9]
Mystic Station (ORISPL 1588)
Units 81, 82, 93, and 94 averaged 4.48 tons S02and average over 14,500,000 mmBtu heat input in 2009, but were allocated no 502 allowances, despite being intermediate- to base-loaded in dispatch. [EPA-HQ-OAR-2009-0491-2787.2]
We have provided above the corrections that are needed in NEEDS v4.10 for this facility. Units 81, 82, 93, and 94 (1558_G_GT81, 1558_G_GT81, 1558_G_GT93, 1558_G_GT94) are combined cycle units, consisting of a Mitsubishi Heavy Industries 501G combustion turbine and heat recovery steam generator with supplemental duct burners having in combination a maximum heat input of 2,995 mmBtu/hour HHV when firing natural gas, and a maximum heat input of 2,734 mmBtu/hour HHV when firing distillate oil. These units averaged 4048 tons S02and over 14,500,000 mmBtu heat input in 2009, but were allocated no S02 allowances, despite being intermediate- to base-loaded in dispatch. We are including the following data to demonstrate recent operations of the facility. [EPA-HQ-OAR-2009-0491-3818.1_NODA,pp.9-10]
Pittsfield Generating (ORISPL 50002)
Inconsistent allocation Units 1, 2, 3, received 1, 1, and 2 NOx allowances despite near identical operations and heat input. Doesn't agree with allocation methodology. [EPA-HQ-OAR-2009-0491-2787.2 p.13-17]
The operator reported an adjustment made in reported annual NOx emissions for units with SCRs installed prior to 2009 to equal the ozone season NOx emission rate. EPA also added another unit (50002_G_GEN4) to account for the steam turbine generator output and assigned reported and projected emissions. Assigning emissions to an unfired steam turbine generator is inappropriate and emissions should be allocated in NEEDS v.4.10 to the combustion turbine reporting the emissions. MassDEP agrees with the operator and recommends attributing all emissions and heat input to the fired generating units. [EPA-HQ-OAR-2009-0491-3818.1_NODA, p.10]
Kendall Square (ORISPL 1595)
Kendall Square (ORISPL 1595) Unit 4 (1595_G_GEN4), is a combined cycle unit consisting of a General Electric 7241 FA combustion turbine with a nominal output of 170 MWe and a maximum heat input of 1,766 mmBtu/hour HHV when firing natural gas, and a maximum heat input of 1,927 mmBtu/hour HHV when firing distillate fuel oil. A heat recovery steam generator with supplemental duct burners has maximum heat input of 350 mmBtu/hour HHV when firing natural gas. In their Transport Rule comments, the operator reports a significant discrepancy between NOx allocations for Unit 4 Unit 4 (1595_G_GEN4) and other similar combined cycle units operating elsewhere in Massachusetts, as demonstrated in the following table. [EPA-HQ-OAR-2009-0491-3818.1_NODA, pp.8-9] [[See Docket Number EPA-HQ-OAR-2009-0491-3818.1_NODA, p.9 for the table.]]
With respect to IPM, we recommend that EPA examine the work of the Regional Greenhouse Gas Initiative (RGGI) and the use of IPM for the RGGI 2012 program review. We suggest that EPA review the following attached documents presented at the September 13, 2010 RGGI stakeholder meeting. (These documents are available at www.rggLorg/stakeholder meeting.) [EPA-HQ-OAR-2009-0491-3818.1_NODA, cover letter]
:: A slide presentation entitled Assumptions Development for IPM Modeling to Support RGGI Program Review, September 1,2010. MassDEP believes these assumptions reflect appropriate considerations for the ten state RGGI Region and differ from those assumed by EPA. [[See Docket Number [EPA-HQ-OAR-2009-0491-3818.2_NODA for attachment.]
:: Another slide presentation entitled 'Additional slides presented at stakeholder meeting' describes how energy efficiency and other variables should figure into IPM modeling. [[See Docket Number EPA-HQ-OAR-2009-0491-3818.5_NODA for attachment.]]
:: A spreadsheet entitled 'RGGI Firm Capacity and Retirement Assumptions -Draft' provides a list of new capacity assumptions and a list of firm retirements and fuel switching assumptions. [[See Docket Number EPA-HQ-OAR-2009-0491-3818.4_NODA for attachment.]]
Finally, we suggest that EPA consult the RGGI website for updates to RGGI's IPM modeling assumptions. Updates will be posted before and following a November 12th stakeholder meeting. EPA may also want to review comments submitted to RGGI Inc. after the September stakeholder meeting; those can be found on the same website. [EPA-HQ-OAR-2009-0491-3818.1_NODA, cover letter.]
MIT Central Utility Plant