FIP Revisions

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1 DOCKET NUMBER EPA
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- 0491 Response to Comments on the Proposed Revisions to FIPs to Reduce Interstate Transport of Fine PM and Ozone 76 FR 63860; October 14, 2011

February 3 , 2012FIP Revisions

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2 Table of Contents Page
1. Unit
- Specific Modeling Assumptions
Issue 1.1: Florida Modeling Assumptions Issue 1.2: Louisiana and Mississippi Modeling Assumptions Issue 1.3 Michigan Modeling Assumptions Issue 1.4: Nebraska and Wisconsin Modeling Assumptions Issue 1.5: New Jersey Modeling Assumptions Issue 1.6: New York Modeling Assumptions Issue 1.7: Texas Modeling Assumptions Issue 1.8: Other States / Unit Operational Issues Issue 1.9: Georgia Modeling Assumptions Issue 1.10: Kansas Modeling Assumpt ions Issue 1.11: Ohio Modeling Assumptions
2. New Unit Set
- Asides
Issue 2.1: Arkansas New Unit Set

- Asides Issue 2.2: Texas New Unit Set

- Asides Issue 2.3: Other Set

- Aside Issues
3. Consent Decrees
- Allowance Allocations
4. Assurance Penalty Provisions
Issue 4.1: General Support / Opposition to Assurance Provisions Deferral Issue 4.2: Impact of Assurance Penalty Provisions on Allowance Market Liquidity Issue 4.3: Other Assurance Penalty Issues
5. General Comments
Issue 5.1: General Sup port for Proposed Rule Revisions Issue 5.2: General Opposition to Proposed Rule Revisions Issue 5.3: Miscellaneous Issues Issue 5.4: Out of Scope IssuesFIP Revisions

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3 1. Unit
- Specific Modeling Assumptions Issue 1.1: Florida Modeling Assumptions
Points Raised: (A) Commenter questions in crease in Florida ozone season NO X budget without modeling to demonstrate it will not cause NAAQS violations. Comment (A)(1)

[Letters: Lakeland Electric (EPA

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- 2] : EPA is proposing to allocate Florida utilities with 819 additional ozone season allowances for 2012 and 2013 through this propo sal without performing an additional modeling run. 1. Does this additional allocation of ozone season allowances, Florida’s 819 additional allowances, create additional downwind NAAQS violations? 2. Please explain how EPA knows the answer to #1 above. 3. What is the maximum number of ozone season allowances that can be awarded to Florida without requiring EPA to remodel for NAAQS violations, e.g., re

- run the model? 4. How does EPA know the value for #3 above and where are the calculations/assumptions for this value represented in EPA’s docket for this rulemaking?

RESPONSE : As described in section VI of the Transport Rule preamble (76 FR 48208, 48246 (August 8, 2011)), significant contributi on is defined on both a cost and air quality basis, through a multifactor analysis. Florida’s significant contribution and interference with maintenance is equal to all of the emissions that can be removed at or below the selected cost threshold from the regulated units within the state. As explained in the final Transport Rule, the state budget represents the emissions remaining in an average year after the elimination of this significant contribution; in this revisions rule, EPA finds a reasonable basis to requantify this amount of remaining emissions at a level 819 tons higher than previously estimated for 2012 and 2013. This approach maintains the elimination of emissions at the cost threshold selected in the final Transport Rule to quantify significa nt contribution and interference with maintenance. EPA examined Florida’s ozone contributions to receptors in Harris County, Texas, and assessed why the contributions changed between the proposed Transport Rule and Final Transport Rule, finding that “in b oth cases, the maximum contribution was significantly above the threshold used for establishing linkages between upwind states and downwind nonattainment and maintenance receptors “ (pg. 2, Declaration of Brian S. Timin, dated December 1, 2011, filed in su pport of EPA’s Consolidated Opposition , EME Homer City Generation v. US EPA , and consolidated cases , No. 11

- 1302 (D.C. Cir.), which can be found in the docket for this rulemaking ). (B) Progress Energy's Crystal River nuclear unit 3 will be on extended rep air outage until sometime in 2014, therefore additional allowances are also needed for 2014. Comment (B)(1) : Commenters appreciate EPA's recognition of several of the errors contained in the CSAPR and opportunity to comment on the proposed corrections. Specifically, following input from the Florida Electric Power Coordinating Group, EPA recognized that Progress EnergyFIP Revisions

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4 Crystal Unit 3, a nuclear unit, will not be operating in 2012 and 2013 because of an extended repair outage, and EPA has proposed to alloc ate additional allowances to account for non

- nuclear replacement generation. The company expects the unit to return to operation sometime in 2014 at the earliest, therefore commenters request that EPA also allocate additional allowances for 2014, and allo cated an additional 819 tons for both 2012 and 2014. [Letters: Florida Electric Power Coordinating Group, Inc. (EPA

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RESPONSE : See section IV of the preamble to the final R evisions Rule (76 FR 48208, August 8, 2011), where EPA responded to this comment. (C) There are significant errors in EPA's unit
- level NO X emission rate assumptions for a number of Florida units. Comment (C)(1) : As the Florida Electric Power Coordinati ng Group (FCG) noted in its September 30, 2011, letter to EPA, there are significant errors in EPA's unit level NO X emission rate assumptions for a number of Florida units. Several of EPA ’ s NO X rate inputs to the model are off by as much as 100% and are c learly unachievable and erroneous. The corrected NO X rates provided by the FCG are based on actual operations or permitted emission limits and represent realistically achievable ozone season emission rates utilizing existing controls at their design level s. The result of these corrections when conservatively using EPA's projected heat input is an increase of 3,423 tons of ozone season NO X emissions from EPA's base case projections. EPA should review carefully the FCG corrections, re

- run the modeling if n ecessary, and accordingly increase Florida's 2012 and 2014 ozone season NO X budget by 3,423 allowances. The corrections are provided in an attachment to FCG's comments (Exhibit B). [Letters: Florida Electric Power Coordinating Group, Inc. (EPA

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RESPONSE : See section 6.2(b) of this document for information addressing NO X emission rates. A look at recent historic data submitted by Florida sources themselves illustrate the com menter misunderstands the compliance picture for the State of Florida and the significance of the impact that the NO X rates assumptions have on Florida’s ability to comply with its state budget. For example, the most recent four quarters of emissions data for the State of Florida demonstrate that the state is already emitting less than its assurance level and close to its budget level. The source

- reported 2011 ozone

- season emissions data suggest that Florida EGUs are collectively emitting approximately 29 ,000 tons of ozone

- season NO X , whereas their revised Transport Rule budget is approximately 28,500 tons. The fact that the state is already emitting so close to its state budget a year in advance of the 2012 control period illustrates the soundness and re asonableness of EPA’s assumed NO X emission rates applied to projected ozone

- season NO X emissions for Florida under the Transport Rule program.FIP Revisions

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5 Comment (C)(2) : Commenter (FCG) provides supplemental comments to clarify and updates their previously sub mitted comments dated November 28, 2011. With respect to FCG’s statement that EPA overestimates Florida’s natural gas transmission capacity, FCG cited to the Florida Reliability Coordinating Council (FRCC) 2011 Ten

- Year Site Plan Presentation to the Flori da Public Service Commission (dated September 7, 2011) to show that Florida’s natural gas demands are currently served by pipelines with a maximum gross capacity of 4.35 billion cubic feet per day. The FCG now understands, however, that this number repres ents the capacity for the FRCC region and does not include the natural gas capacity of the Gulf South Pipeline, which serves the far western portion of the Florida panhandle outside of the FRCC region. In addition, this figure predates very recent facilit y improvements that increased capacity within the FRCC region. Accordingly, the correct maximum statewide natural gas pipeline capacity for Florida is 4.7 billion cubic feet per day. Commenter provides additional information in a revised Exhibit D as an attachment to their letter and concludes that based on these revisions and other errors identified in their November 28th letter, EPA should increase Florida’s 2012 and 2014 ozone

season NO X budgets by a total of 10,794 allowances as reflected in a Revised Exhibit E (also provided as an attachment). [Letters: Florida Electric Power Coordinating Group, Inc. (EPA

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– all pgs]
RESPONSE: This response addresses both the comment of FCG and the next comment of Progre ss Energy. The problem with these comments is that they misunderstand the operation of IPM, make errors in calculation, and falsely attribute estimates to IPM that were never made. This comment incorrectly characterizes the IPM model and its use in dev eloping state bu d gets, and the comment also contains errors in the calculations employed. IPM contains a detailed natural gas transmission network but it is not an hourly model and does not project the hourly use of natural gas by IPM region. IPM also us es a very detailed representation of the electricity load curve, to capture generation and fuel use by load level and season of the year (see IPM documentation, Chapter 10) and limits natural gas pipeline supply in each separate segment of that load curve to reflect available pipeline capacity. The calculations used by the commenter to obtain the recommended changes in this comment are flawed, because they assume that all natural gas generation operated in the model is run simultaneously in a single hour, whereas IPM projects the total gas use in each segment of the load curve that is modeled, based on all conditions present throughout the electricity and natural gas transmission systems.. This IPM modeling approach ensures that natural gas flows into each IPM region (such as FRCC) will not exceed pipeline capacity in any time segment modeled. Since the smallest peak segment in the summer represents only one percent of the summer load (or 36 hours of operation), IPM is matching gas consumption to pipeline capacity down to a refined level of detail is more than adequate for projecting reliable state

- level EGU emissions used by EPA to develop state budgets under the Transport Rule programs. In addition, the commenter's calculations assume that all generators operate at maximum capacity at the same time; the commenter fails to take into account the fact that in IPM modeling projections, generators are not available to operate at all times (see IPM documentation, Chapter 3.)FIP Revisions

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6 Data from the EIA confirms that t he EPA projections do not overestimate power sector gas use in Florida. The IPM modeling projects 437 TBtu of ozone season natural gas use in Florida in 2012; this projection of power sector natural consumption is from 9% to 22% below the natural gas powe r sector consumption reported to EIA in the last three years (http://www.eia.gov/dnav/ng/ng_cons_sum_dcu_sfl_m.htm, for years 2009 to 2011, assuming 1034 Btu/cf). Therefore, EPA finds that its Transport Rule emission projections (on which the state budget is premised) are compatible with available natural gas pipeline capacity serving Florida EGUs and EPA is not making any revisions to the Transport Rule based on this comment. (D ) EPA overestimates Florida's gas transmission capacity. Comment (D)(1) : EPA overestimates the gas transmission capacity in Florida, and must appropriately account for replacement generation to cover the natural gas deficit in EPA's model. Florida's natural gas demands are serviced by three pipelines with a daily gross capaci ty of 4.66 billion cubic feet per day. However, the maximum demand for gas

- fired electric generation based on EPA's projections, and assuming generation at full capacity during a 24

- hour period, is 5.76 billion cubic feet per day. This creates a natural gas shortage of 1.10 billion cubic feet per day. In addition, this supply shortfall may be exacerbated by such events as tropical storms, which EPA has not accounted for in modeling. EPA should account for the replacement generation necessary to address this natural gas supply deficit. At 1,034 Btu per cubic feet, the deficit described above is equivalent to a heat input shortage of 1,137,400 mmBtu/day. Covering this deficit with coal or oil for fuel on a peak ozone season day would result in an additio nal 170 tons per day of NO X emissions. [Letters: Progress Energy (EPA

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RESPONSE : See response to comment 1.1(C)(2) above. Comment (D)(2) : EPA overestimates the gas transmission capacity in Florida, and must appropriately account for replacement generation to cover the natural gas deficit in EPA's model. Florida's natural gas demands are serviced by three pipelines with a daily gross capacity of 4.35 billion cubic feet per day. However, the maximum demand for gas

- fired e lectric generation based on EPA's projections, and assuming generation at full capacity during a 24

- hour period, is 5.76 billion cubic feet per day. This creates a natural gas shortage of 1.41 billion cubic feet per day without even accounting for the nee ds of other natural gas users. Commenter provides calculations in an attachment (Exhibit D). This supply shortfall is exacerbated by EPA's failure to provide any accommodation for disruptions in natural gas supply from storms.
EPA should account for the replacement generation necessary to address this natural gas supply deficit. At 1,034 Btu per cubic feet, the deficit described above is equivalent to a heat input shortage of 1,457,940 mmBtus. Assuming an estimated average natural gas fired NO X emissio n rate of 0.4 lbs/mmBtu for replacement generation the net effect of a shift in generation away from natural gas in a 0.3 lb/mmBtu increase in NO X emissions. Because this is scattered across the state it is appropriate to utilize average emission rates, r ather than unit specific rates FurtherFIP Revisions

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7 0.1 lb/mmBtu is a conservative estimate for an average NO X emission rate for the natural gas fired generation being replaced given most natural gas fired generation emits NO X well below that rate. In addition 0.4 lb /mmBtu is a reasonable rate for non natural gas fired replacement equipment. In this peak demand scenario replacement generation will come from uncontrolled less efficient non natural gas fired units at the bottom of the dispatch list with emission rates ranging between 0.3 and 0.8 lb/mmBtu. The result is an increase of 218.69 tons of NO X per day in a worst

- case scenario (i.e., 1,457,940 mmBtus and 0.3 lb NO X /mmBtu). There is no constraint in EPA's IPM model that addresses this scenario, and it is impera tive EPA account for this. This worst

- case scenario is reasonably foreseen during the hot summer months and the increasing reliance statewide on natural gas fired generation to ensure compliance with the CSAPR. Based on recent summer data, two weeks is a reasonably conservative estimate of the number of days during which this worst

- case scenario may exist during the 153 day ozone season. Accordingly EPA should allocate an additional 3,062 NO X ozone season allowances for 2012 and 2014. [Letters: Florid a Electric Power Coordinating Group, Inc. (EPA

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RESPONSE : See response to comment s 1.1(C) (1) and (2) above. (E) EPA fails to account for transmission line import constraints, and must increase Florida's ozone season NO X bud get to account for this modeling error. Comment (E)(1) : EPA has over projected Florida's capacity to import power and must allocate additional allowances to account for necessary in

- state replacement generation. Based on 2011 data, the Florida Reliabili ty Coordinating Council, Inc. (FRCC), projects that the FRCC region for 2012 ozone season demand will be 109,494 GWh. This ozone season demand projection is the most current, reliable, and accurate available. EPA's IPM model only projects that facilities in the FRCC region will generate 86,362.68 GWh for the 2012 five month ozone season. Based on FRCC's and EPA's projections, Florida will need to import 23, 131.32 GWh from outside of the FRCC region to meet Florida's 2012 demand. However, the maximum tr ansmission capacity into the FRCC region is 3600 MW (See EPA's IPM base case documentation). This means that if electricity is imported into the FRCC region at maximum capacity 24 hours a day, every day of the ozone season, only 13,586.40 GWh can be impor ted. This assumes no increase in demand. These are obviously extremely conservative assumptions, but are used for calculation purposes. Accordingly, if the FRCC region only generates the power EPA projects, and imports at maximum capacity, supply will b e short demand by 9,544.92 GWh, and this must be generated within the FRCC region, and this generation must be accounted in determining the ozone season NO X budget.
The additional ozone season NO X emissions can be estimated based on available capacity wei ghted averages in a way similar to that used by EPA in calculating capacity weighted heat rate and emission rate averages for Crystal River Unit 3 replacement generation. However, where EPA's capacity weighted averages are biased towards the units with th e most base generating capacity, available capacity weighted averages are biased towards units with the mostFIP Revisions

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8 generating capacity after already generating some baseline amount. In this case, the available capacity weighted FRCC region average heat and emis sion rates utilized are based on the remaining ozone season capacity of each FRCC region unit dispatched in EPA's IPM Remedy Case after accounting for the GWs IPM already projects each unit will generate during the 2012 ozone season. The available capacit y weighted approach makes sense because larger more efficient, more controlled units will likely already be dispatched at or near capacity as projected by IPM and thus the additional generation required due to import constraints will fall more heavily towa rd the remaining less utilized, less efficient units. The calculated available capacity weighted heat rate and emission averages for the FRCC region are provided in an attachment to the comment letter (Exhibit A). Using this approach commenter estimates Florida will emit an additional 4,239.86 tons of ozone season NO X to meet demand. Thus EPA must increase Florida's ozone season NO X budget by 4,240 allowances to account for this EPA modeling error. [Letters: Florida Electric Power Coordinating Group, Inc. (EPA

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- 5]
RESPONSE : There is no basis in this comment for claiming a modeling error in transmission line import limits. As the comment correctly notes, the IPM represents the transmission capacity into FRCC as 3600 MW. T his transmission capacity is never questioned. This comment assumes FRCC demand projections for 2012 and EPA projections for generation in 2012 and then argues that IPM has not provided sufficient import capacity. This is an apple

- and

- oranges comparison, which ignores the fact that IPM uses a different source for demand projections. FCG is implicitly claiming that IPM is flawed because it has a smaller load growth rate for the FRCC grid region than that projected by the FRCC. The IPM load growth is deriv ed from data from the EIA, an authoritative source within the energy modeling community. The EIA data incorporates assumptions about short

- and long

- term growth and macroeconomics, yielding a growth rate that evolves over time to reflect economic recovery and growth. EPA therefore believes the approach taken in modeling is therefore reasonable, from both a load and transmission capacity standpoint, and there is no basis for revising the Florida budgets. (F) Projected Florida ozone
- season NO X emissions an d NO X emission rates In response to numerous comments on errors in the IPM runs supporting EPA’s Proposed Transport Rule, EPA made corrections to its IPM inputs for emission sources in Florida. Left unaddressed in the IPM runs supporting CSAPR, however, was a concern raised by Florida and sources in Florida concerning the overall level of seasonal NO X emissions in the state. In comments to EPA on the Proposed Transport Rule, concerns were raised that EPA’s projected emissions do not reflect the level of emissions that the state anticipates for 2012 and 2014. In particular, concerns were raised during the rulemaking that EPA was overstating by a substantial amount the overall level of ozone season NO X emissions from coal

- fired EGUs in Florida. In response to such comments, EPA did

– in the modeling runs for CSAPR

– reduce the state’s seasonal NO X emissions from 94,000 tons in BC_P_12 to 41,700 tons in BC_F_12. EPAFIP Revisions

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9 did this by reducing heat input by almost 150 TBtu and making some adjustments to emission ra tes, as shown in the following table.
Scenario Heat Input (TBtu) Seasonal NO X (tons) BC_P_12 897.8 94,000 BC_F_12 748.5 41,700 CEMS_2010 848.4 37,100 In addressing the comments on the proposed rule on NO X emissions, EPA may have incorrectly model ed the state’s coal

- fired generating sources. Specifically, EPA has acknowledged that many coal

- fired EGUs in Florida already have dispatchable selective catalytic reduction (SCR) systems; however, in the IPM runs supporting CSAPR, EPA modeled many of thos e SCR

equipped units as if they do not have or are not operating their dispatchable SCRs. By doing this, the BC_ F_12 run predicts that 80% of the state’s projected 41,700 tons of ozone season NO X will come from coal

- fired EGUs. In fact, however, in 2010, only 56.6% of the state’s ozone season NO X emissions (or 21,000 tons) came from coal

- fired generating facilities. Modeling most of Florida’s SCR

- equipped coal units as though they do not have SCR in operation has resulted in EPA’s predicting much higher se asonal NO X emissions than are really occurring and this, in turn, has resulted in EPA’s predicting that EGU NO X emissions from Florida sources will have higher impacts on ozone season concentrations downwind than are actually occurring. In addition, error s were made in the parsed IPM files concerning the NO X emission rates for Crist Units 4 and 5 and Smith Unit 1. They are projected in the EPA Remedy runs (e.g., RC_F_12) to emit at an emission rate of 0.18 lb/ mmBtu . In fact, each unit has an SNCR that is o perational full time and is designed to reduce NO X (and is reducing NO X ) by approximately 25% and these units are achieving emission rates of 0.36 lbs/ mmBtu (Crist Unit 4), 0.40 lbs/ mmBtu (Crist Unit 5), and 0.29 lbs/ mmBtu (Smith Unit 1).
Errors were also made in the parsed IPM files concerning the NO X emission rates for Scholz Units 1 and 2. They are projected in EPA Remedy Cases (e.g., RC_F_12) to be emitting at rates of 0.245 lbs/ mmBtu (Unit 1) and 0.334 lb/ mmBtu (Unit 2). In fact, these units have his torically operated at emission rates of approximately 0.58 lb/ mmBtu

. [Attachment to UARG comment letter, “J. Marchetti, J. E. Cichanowicz, Initial Identification of Unit Errors in Integrated Planning Model (IPM) Runs (Oct. 7, 2011)” (EPA

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RESPONSE : See response to comment 1.1(C)( 1 ) above regarding general application of historic NO X emission rate data to the IPM model and Florida’s current emissions profile. As to comments noting that some SCRs do not operate in EPA’s base case modeling, that is correct and intentional. As repeatedly described by EPA in its f inal Transport Rule p reamble and IPM documentation, dispatchable controls may not be operated in the base case scenarios , as the economic incentives in that base case scenario (without either the Clean Air Interstate Rule (CAIR) or the Transport Rule) may not be suffic i ent to cover the O&M cost of operating the control. Furthermore, the alleged discrepancies regarding “dispatchable” SCR operation in theFIP Revisions

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10 base case have no bearing on EPA’s quantification of the state’s budget under the Transport Rule program, which is the subject of this revisions rulemaking. Finally, in alleging that incorrect representation of dispatchable SCR operation “ has resulted in EPA’s predictin g that EGU NO X emissions from Florida sources will have higher impacts on ozone season concentrations downwind than are actually occurring,” the commenter has misunderstood the air quality basis EPA established for the inclusion of upwind states in the Tra nsport Rule, which relied on emission projections from all sources in the upwind state (not just EGUs). EPA examined Florida’s ozone contributions to receptors in Harris County, Texas, and assessed why the contributions changed between the proposed Transp ort Rule and Final Transport Rule, finding that “in both cases, the maximum contribution was significantly above the threshold used for establishing linkages between upwind states and downwind nonattainment and maintenance receptors “ (pg. 2, Declaration o f Brian S. Timin, dated December 1, 2011, filed in support of EPA’s Consolidated Opposition , EME Homer City Generation v. US EPA , and consolidated cases, No

. 11

- 1302 (D.C.Cir.) , which can be found in the docket f o r this rulemaking ). (G) Must
- run requireme nts at Lansing Smith
Comment : EPA should allocate additional allowances to Florida to ensure that certain units can meet must

- run requirements. In Particular, Gulf Power’s Lansing Smith Plant requires two units to operate at a minimum load for voltage and area protection. Under a lowest

- emissions must

- run scenario operating both the Lansing Smith Unit 2 coal

- fired boiler and Unit 3 combined

- cycle combustion turbine at minimum load, the Lansing Smith Plant will emit a total of 756.4 tons of ozone
- season NO X . However, EPA only allocated 686 allowances to these units, resulting in a shortage of 70 allowances. The allowance market should not be relied upon to meet this critical infrastructure need. Moreover, the existence of any viable, liquid allowance market is doubtful in light of EPA’s drastic reductions to nearly all of the state budgets in the final rule and EPA’s commitment to revise CSAPR based on the 2009 revisions to the ozone national ambient air quality standard. To address this serious issue, EPA mu st allocate an additional 70 allowances to Florida’s budget to provide some assurance that sufficient allowances will be available through the market for Lansing Smith Plant to meet its must

- run requirements. It should be noted that EPA’s 2012 Remedy Case did not dispatch any of the Lansing Smith Plant’s combined

- cycle units. If EPA relies on its 2012 Remedy Case to determine this shortfall, where only Lansing Smith Units 1 and 2 are dispatched, an additional 590 allowances should be allocated to meet the L ansing Smith Plant’s must

- run requirements. Further description of the Lansing Smith Plant’s must

- run needs are provided in Exhibit C. [Letters: Florida Electric Power Coordinating Group, Inc. (EPA

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RESPONSE: FCG’s comment is based upon a comparison of a plant’s allocations versus its projected emissions, which EPA responds to in section 6.4 , below

. EPA also notes that in the modeling for the Transport Rule, units at Lansing Smith generate at sufficient levels to meet the ope rational requirement that FCG describes. (see “WebReady_ParsedFile_TR_Remedy_Final_2012,” EPA

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11 Issue 1.2: Louisiana and Mississippi Modeling Assumptions
Points Raised: (A) EPA's proposed revisions in IPM to account for local constra ints in Mississippi (i.e., for EMI) are insufficient and ignore all other systems in the state. Comment (A)(1) : The additional 2,299.1 tons of emissions identified for the Entergy Mississippi, Inc. (EMI) units falls well

- short of these unit's actual 2010 NO X emissions. The impact of this underestimation on generation remains striking. Having previously projected that the EMI units would be retired by 2012, EPA now projects that the heat inputs for these units will be 15.81 TBtu, compared to the 2010 act ual heat input of 33.34 TBtu. EPA's projections equate to a reduction in generation of nearly 53% from 2010 to 2012, a severely unrealistic expectation. Commenter provides additional discussion, asserting that the IPM assumptions do not adequately addres s reliability and local transmission constraints. [Letters: Mississippi Public Service Commission (EPA

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RESPONSE : EPA reviewed the comments and information submitted by Entergy, the operator of those units, which resulted i n the revisions to the Mississippi budget described in the p reamble for the f inal Revisions Rule. Entergy specifically identified the level of generation required for voltage support and grid stability; some historic generation from these units may have b een for economic reasons, not out

- of

- merit

- order dispatch reasons, and therefore the IPM results should not be adjusted to reflect that portion of the generation. Also, comparisons to historic heat, while relevant, are not sufficient by themselves to make revisions to the IPM results since the historic data does not reflect operation under the Transport Rule. Finally, where commenters, including MPSC (see response to comment (A)(2) , below), identified specific constraints that would require units to run mo re frequently than they did in IPM, EPA considered making revisions. EPA also notes that the commenter incorrectly states that EPA’s modeling had projected retirement of these units in 2012. While IPM did not choose to run the units in the model, these units continued to offer available generating capacity in the model in 2012. Comment (A)(2) : The South Mississippi Electric Power Association (SMEPA) operates a generation and transmission system ("G&T area") that serves as a NERC Balancing Authority and is interconnected with four neighboring utilities through six transmission interconnections. The Final Rule will effectively require SMEPA

- owned generation to reduce NO X emissions by approximately 70% from the actual 2010 ozone season emissions, correlat ing to a 32% curtailment of generation within SMEPA's G&T area. The impact of the Final Rule on two SMEPA

- owned facilities, Plants Morrow and Moselle, is of particular concern. The units at these facilities combine to provide 64% of the generation capaci ty within the G&T area and also provide voltage support and regulation to the SMEPA system. In the Final Rule's base case, Plant Moselle was effectively "retired," and Plant Morrow's emissions were reduced by 66%, even though both plants ran as required i n 2010, continue to run as needed, and are projected to operate at capacity factors important to system operations and reliability in 2012. However, EPAFIP Revisions

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12 has offered no revisions to SMEPA's units. Commenters provide additional discussion on these faciliti es, noting that due to its geographic location and the transmission configuration, generation at Plant Moselle is considered "must run" during peak system loading conditions and that both facilities provide more than 82% of the dynamic reactive reserves re quired for the G&T system. Commenter also asserts that overreliance on transmission to the detriment of local generation exposes a system to greater reliability risks related to "normal" emergencies, such as inclement weather and that IPM assumptions shou ld accurately reflect the importance and role of local generation. [Letters: Mississippi Public Service Commission (EPA

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RESPONSE : EPA consid ered the operating constraints MPSC and SMEPA described that may require plants Morrow and Moselle to run out

- of

- merit

- order. This analysis found that plant Morrow ran sufficiently in the Transport Rule Remedy modeling to meet the operating constraints des cribed by MPSC and SMEPA (see “WebReady_ParsedFile_TR_REmedy_Final_2012,” EPA

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- 4431). The analysis also found the one unit at plant Moselle was subject to out

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- order dispatch to provide voltage support and regulation as described b y the commenter, and revisions were made accordingly . See the Final Revisions Rule State Budgets and New Unit Set

- Asides TSD in the docket to this rulemaking. (B) Commenter appreciates and supports the proposed technical revisions but asserts that the m ethod used to determine the Mississippi state budget is erroneous and still results in a budget that is insufficient. Comment (B)(1) : In the revision, EPA states that "EPA is proposing to adjust Mississippi's 2012 and 2014 ozone season NO X emission budge ts based on an analysis projecting the minimum frequency these units will have to run in the immediate

- term for non

- economic purposes, according to the data provided by the utility operating those units." The additional allocations given to Mississippi re sult from this "minimal" restoration, but it was erroneous in the first place to remove the units from service, and those that were restored should have been restored to at least an average ozone season utilization based on historical data. As part of the Base Case utilization, IPM assumed the shutdown of gas/oil steam plants in MS (provided in Table 1 within the commenter's letter). This includes Entergy's Gerald Andrus and Baxter Wilson units, which are base load units that supply a significant amount o f power for MS and there are no plans for them to be removed from service in the near future. The other units assumed to be shut down are not as large but are needed for grid stability and will be operated in the future. [Letters: Mississippi Department of Environmental Quality (EPA

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- 4786) p. 1]
RESPONSE : Revisions to the operation of units in Mississippi that are being finalized in the f inal Revisions Rule , based on information that meets requirements described in proposed revisions [ 7 6 FR 63868], can be found in the p reamble and in the TSD called, Final Revisions Rule State Budgets and New Unit Set

- Asides

. For EPA’s response to comments on the rationaleFIP Revisions

- RTC Febru ary 7 , 2012 Page 13

13 behind the out

- of

- merit

- order dispatch generation revisions, see section 6.1a , bel ow, of this document. Comment (B)(2) : The 2012 IPM removes heat input from units and facilities that were not shut down resulting in 111 trillion BTU compared to 205 trillion BTU for the 2010 ozone season. This is a 42% reduction in heat input for MS u tilities. Commenter provides the IPM 2012 and actual 2010 heat input for these facilities in their letter (as Table 2) and notes that almost all facilities had reduced heat input for 2012. Commenter adds that not only were some facilities shut down, but rather than redistributing their load to other facilities in the state, the IPM removed heat input from other facilities and that it is not reasonable or rational for the model to do this. Commenter provides additional discussion noting that this error ha s been historically committed (e.g., IPM 2006 estimates are 130 trillion BTU and 12,940 tons NO X for ozone season 2010 but the actual data reported to CAMD are 205 trillion BTU and 16,089 tons NO X ) and that the IPM Base Case models should reflect the opera tion of EGUs without the implementation of the proposed standards (the comparisons between projected and actual data indicate that the model does not do this). [Letters: Mississippi Department of Environmental Quality (EPA

- HQ

- OAR

- 2009

- 0491

- 4786) p. 1
R ESPONSE : See section 6.3 , below, in this document for EPA’s response to comments comparing state

- level heat input in IPM to historic data. EPA notes that it reviewed comments pertaining to out

- of

- merit

- order dispatch at specific units and made revisions when the information provided met the requirements described in the proposed revisions [ 76 FR 63868 , October 14, 2011 ]. (C) Many of Louisiana's natural gas
- fired boilers that EPA predicted to no longer be online are actually units that are frequently dis patched to meet demand and if necessary, the budget should be modified so that these units are not penalized. Comment(C)(1) : Louisiana has many natural gas

- fired boilers that are frequently dispatched out of regional economic order as a result of short

- r un limitations on the ability to meet local electricity demand with generation from outside the area. Commenter (LDEQ) notes that these units were identified in their comments to the proposed Transport Rule. Should any of these units be included in the e missions budget and the calculated net change reflects a "material impact," EPA should take the necessary steps to adjust the emissions budget so that these "must

run" units may operate without penalty. In recalculating Louisiana's NO X budget, EPA assumes that Entergy's "must

- run" facilities will replace "in

- state combined cycle units" and subtracts slightly more than 700 tons from the Entergy emissions before adding these emissions back into the Louisiana inventory. However, EPA does not specifically ide ntify the "in

- state combined cycle" facilities. EPA makes assumptions that would limit the ability of generators in Louisiana to produce electricity and has no basis in reality potentially resulting in rolling black or brown

outs that the revision to the rule is intended to avoid. [Letters: Louisiana Department of Environmental Quality (EPA

- HQ

- OAR

- 2009

- 0491

- 4787) p. 1]FIP Revisions

- RTC Febru ary 7 , 2012 Page 14

14 RESPONSE : EPA reviewed comments related to units dispatched out

- of

- merit

- order that met the requirements described in the proposed revi sions [ 76 FR 63868]. Revisions to units in Louisiana that EPA is finalizing are in the f inal Revisions Rule. Also see the Final Revisions Rule State Budgets and New Unit Set

- Asides TSD in the docket to this rulemaking . For EPA’s response to comments on t he rationale behind offsetting the added out

- of

- merit

- order dispatch generation , see section 6.1b , below, of this document. (D) Supports the EPA’s proposal to increase Louisiana’s ozone season NO X allowances by an additional 4,201 tons, but comments on the analysis related to units that will be required to run in the immediate term for non
- economic purposes. Comment(D)(1) : The EPA explains in its technical revisions that it based the 4,201 ton allowance increase upon a calculation that estimates the ne t change in the state’s total emissions to account for the increased generation (and emissions) from the reliability must run “RMR” units. These calculated adjustments to the overall budget are purportedly based on an analysis projecting the minimum frequ ency that these units will be required to run in the immediate term for non

- economic purposes, according to data provided by utilities operating those RMR units (76 FR 63866). Commenter (LPSC) supports EPA’s increased allowances, but these technical revis ions should be based on the average frequency in which these units are run, not the minimum level. Reliability standards for electricity dispatch are typically not set at minimum levels; rather, these standards are set at a more conservative, average leve l to ensure system reliability under various operating scenarios. Setting the technical adjustments at a minimum level only provides these EGUs the bare minimum of allowance that they may need, rather than the amount they would likely need to ensure relia bility in what EPA has already recognized as a uniquely constrained geographic region. If EPA proceeds with this rule, the Agency should re

consider its position on this issue, particularly during the critical 2012

- 2014 transition period and grant additio nal allowances to these generators based on the average operating frequency of each unit. [Letters: Louisiana Public Service Commission (EPA

- HQ

- OAR

- 2009

- 0491

- 4799) p. 2

- 4]
RESPONSE : For EPA’s response to comments on the rationale behind the out

- of

- meri t

- order dispatch generation revisions, see section 6.1a , below, in this document. The commenter refers to the "Dismukes affidavit," attached to the commenters Motion for Stay. EPA extensively responded to the Dismukes Affidavit ( Declaration of Sam Napoli tano dated November 7, 2011, filed in support of EPA's opposition to motion filed by State of Louisiana, Louisiana DEQ, and Louisiana PSC, EME Homer City Generation v. US EPA, and consolidated cases, No. 11

- 1302 (D.C. Cir.) which can be found in the docket for this rulemaking ), which included several important factual errors. EPA notes that when commenters provided information, as detailed in the proposed revisions (76 FR 63868), about specific units that may be required to run out

- of

- merit order, EPA mad e revisions to state budgets, as described in the Final Revisions Rule State Budgets and New Unit Set

- Aside TSD in the docket to this rulemaking.FIP Revisions

- RTC Febru ary 7 , 2012 Page 15

15 (E) Supports the increased allocations for must
- run units, but there should be no offset or a reduced offse t of combined cycle emissions. Comment (E)(1) : Louisiana commenters support EPA's acknowledgement that significant transmission constraints exist within Louisiana that negatively impact the ability of Louisiana utility providers to receive power from out of state sources and even from in state sources in many cases. However, commenters do not agree with EPA that the increases in allowances due to the need to run these five Entergy plants for out of merit order dispatch due to load pocket/transmission con straints should be offset by projected decreases in combined cycle cogeneration related emissions. EPA in its discussion of the offset calculation nowhere discusses why the combined cycle units would have lower generation due to increased generation by th e five Entergy plants, and commenters question this assumption. Of the cogeneration units, the Dow St Charles Operations, PPG Powerhouse C, and Formosa Plastics (and perhaps other o the identified cogeneration units) are all Qualified Facilities under PUR PA that are not regulated by the Louisiana Public Service Commission (LPSC) nor by the Acid Rain Program, CAIR, or CSAPR. These units are not subject to dispatch. All sell electricity subject to PURPA and must be purchased by the public power provider u nless there is an emergency condition. As such, these three plants are not likely to have generation displaced by the Entergy units. The Louisiana 1 stations consists of five units, four of which are leased by ExxonMobil and one owned by Exxon Mobil. Al l five are operated by Entergy. They are also Qualified Facilities under PURPA that are not regulated by the LPSC. These facilities primarily exist to serve an industrial host. In addition EPA made a number of other errors in its offset analysis which t he commenter lists with respect to number of units and emission rates for the Carville Energy Center, Louisiana 1 Station, Ouachita Power Station, Perryville Power Station, Sterlington, and PPG Powerhouse C. [Letters: Lafayette Utility Systems (EPA

- HQ

- OA R

- 2009

- 0491

- 4807) p. 8

- 15; Louisiana Chemical Association (LCA) (EPA

- HQ

- OAR

- 2009

- 0491

- 4803) p. 7

- 13]
RESPONSE : For EPA’s response to comments on the rationale behind offsetting the added out

of

- merit

- order dispatch generation , see section 6.1b , below, in this document. EPA agrees that given the operating characteristics of cogen eration units, they should not be used for offsetting under this approach and has adjusted its method accordingly, as described in the p reamble of the final Revisions Rule. (F) EPA should consider the CLECO RFP for 750 MW of purchased power and provide additional allocations to cover the shortage. Comment (F)(1) : Cleco Corp. is an energy services company based in Pineville, Louisiana. A subsidiary Cleco Power LLC is a regulat ed electric utility and serves Louisiana exclusively. Cleco Power operates four power plants with 3,843 MW of nameplate capacity. On SeptemberFIP Revisions

- RTC Febru ary 7 , 2012 Page 16

16 7, 2011, Cleco Power issued a Request for Proposals for Contractual Resources to Meet the CSAPR Beginning in Ma y 2012. Cleco Power indicated that with the allowances afforded by the proposal, Cleco Power will be approximately 930 MW short of generation needed to service its customers during the ozone season. Cleco Power indicated with some technical adjustments a nd improvements to environmental controls it would be able to cover 180 MW of the shortage, but would still need to purchase 750 MW to reliably service customers. If Cleco Power cannot obtain sufficient generation through this RFP, it will demonstrate the inadequacy of EPA's assumption that Louisiana EGUs would be able to purchase cleaner out of state generation in order to meet the ozone season NO X budget. EPA should obtain the results of the RFP, and if sufficient generation is not available, EPA should increase the Louisiana budget by the amount of the shortfall. All information in response to the RFP should be provided by December 14, 2011, at the latest. [Letters: Lafayette Utility Systems (EPA

- HQ

- OAR

- 2009

- 0491

- 4807) p. 16

- 18; Louisiana Chemical A ssociation (LCA) (EPA

- HQ

- OAR

- 2009

- 0491

- 4803) p. 14

- 15]
RESPONSE : EPA followed the CLECO RFP and notes that according to the CLECO Website ( http :// www
. cleco

. com / site 574. php ; last accessed 1/30/12) CLECO did receive bids for the RFP and selected CLECO Evangeline LLC as the winner. (G) Proposed technical amendments failed to con sider transmission constraints. Comment (G)(1) : As indicated above, LUS operations are within the SPPS subregion. The SPP, reliability coordinator for the entire region, has officially informed EPA of its concern that CSAPR, as enacted in the final rule, will result in blackouts and other reliability problems within the region. While the proposed amendments address load pockets within the ENTG subregion, EPA failed to consider transmission constraints in this SPSS power region and thus fails to address th e SPP concerns. Historically, LUS operations have been affected by the Acadian Load Pocket as well as the Weber

- Wilcox constraint. While the load pocket should be alleviated by the 2012 ozone season due to projects underway, some constrains will continue to exist. In order to support local transmission stability LUS must plan for local generation in the event the largest system unit is down (Rodemacher Unit 2). LUS has modeled system operations without Rodemacher Unit 2 and provides the resulting unit N O X emissions. LUS requests that EPA increase the ozone season NO X allocations for its units to 828 allowances in order to allow LUS system units to run in such a contingency. [Letters: Lafayette Utility Systems (EPA

- HQ

- OAR

- 2009

- 0491

- 4807) p. 15

- 16]
Com ment (G)(2): As LUS stated in its October 7, 2011 petition to EPA for reconsideration and stay of CSAPR as it applies to the State of Louisiana, EPA did not adequately consider transmission constraints and load pockets in the IPM modeling undertaken for CS APR. The commenter lists several load pockets in the SPP and Entergy regions, including the Amite South, Acadiana, WOTAB, Downstream of Little Gypsy, and the South Louisiana Bulk Area Load Pockets. [Letters: Lafayette Utility Systems (EPA

- HQ

- OAR

- 2009

- 0491

- 4807) p. 9]FIP Revisions

- RTC Febru ary 7 , 2012 Page 17

17 RESPONSE : EPA notes that many of the load pockets identified in LUS’s comments, including references to their Petition for Reconsideration and Stay, have been addressed by responding to comments from Entergy and making revisions , as supporte d (see the p reamble for the f inal Revisions Rule and the Final Revisions Rule State Budgets and New Unit Set

- Asides TSD in the docket to this rulemaking ). EPA also notes that, as LUS describes, the Weber

- Wilcox constraint should be addressed by the 2012 o zone season through projects currently being undertaken. EPA extensively analyzed and responded to the SPP transmission study in the Declaration of Sam Napolitano ( Declaration of Sam Napolitano dated December 1, 2011, filed in support of EPA's Consolidat ed Opposition, EME Homer City Generation v. US EPA, and consolidated cases, No. 11

- 1302 (D.C. Cir.) which can be found in the docket for this rulemaking ( EPA

- HQ

OAR

- 2009

- 0491

- 4834 ) ; paragraphs 58

- 61

. ) and did not find the analysis a credible basis for maki ng revisions. LUS’s comments do not meet the information requirements described in the proposed revisions [76 FR 63868]. Additionally, LUS bases its comment and request for revisions based on a contingency that Rodemacher 2 is down. EPA notes that the variability limits were designed to allow flexibility in the event of a unit being down. Finally, LUS comments are also based on a comparison between allocations and projected emissions, which is discussed in section 6.4 , below, in this document.
Commen t (G)(2) : Commenter (LEPA) notes that in order to provide reliable and affordable service to its customers, they utilize resources from Rodemacher Unit #2, Houma Units #15 and #16, and Morgan City Unit #4. Historically, LEPA has relied heavily on Rodemac her Unit #2 to cover baseload requirements and has utilized the natural gas fired units only when transmission on the grid is unavailable to support market purchases. However, LEPA’s operational procedures have been severely altered by the CSAPR, since Ro demacher Unit #2 will be limited to about 58% of its normal energy production. Market purchases for Summer 2012 remain unavailable to LEPA as of September 2011. Vendors in the region have declined to sell LEPA power given the uncertainty regarding how th ey intend to supply their own native load with limited NO X ozone season allowances. As such, LEPA must rely on its own generation fleet, which is now limited by available NO X allowances. CSAPR has changed market conditions and made economic purchases una vailable, therefore these units must operate to meet load requirements. LEPA notes that they will use their allowances by the end of July 2012 and will need to begin invoking power outages. Through uneconomic dispatch of resources, LEPA could defer power outages until late August 2012, but that will raise rates by more than $60 per month on average for each metered customer. CSAPR has provided adequate allowances and its removal of market purchases from the grid has created an environment that requires L EPA to increase the level of generation from their fleet to well above historical amounts. As such, LEPA will need 345 additional NO X ozone season allowances to provide affordable power. [Letters: Louisiana Energy and Power Authority (EPA

- HQ

- OAR

- 2009

- 0 491

- 4864) p. 1

- 2]FIP Revisions

- RTC Febru ary 7 , 2012 Page 18

18 RESPONSE : LEPA’s unit

- specific comments are based on a comparison between allocations and projected emissions, which is discussed in section 6.4 , below, in this document. Furthermore, EPA notes that the initial allocation of allowances is not a l imit on unit emissions and that utilities can purchase additional allowances through the market ( Declaration of Sam Napolitano dated December 1, 2011, filed in support of EPA's Consolidated Opposition, EME Homer City Generation v. US EPA, and co nsolidated cases, No. 11

- 1302 (D.C. Cir.) which can be found in the docket for this rulemaking ( EPA

- HQ

- OAR

- 2009

- 0491

- 4834 ) ; paragraphs 11, 13

- 20 ). (H) EPA should correct the assumptions made in its IPM modeling and re
- run the model for Louisiana, Missis sippi, and Arkansas and if the Agency is unwilling to do this, then EPA should finalize the Proposed Rule and further increase the budgets for these states. Comment (H)(1) : The emissions budgets for the Entergy States (i.e., Louisiana, Mississippi, and A rkansas) are manifestly flawed because they require significant unintended emissions reductions. Unlike the emissions budgets for the majority of states covered by CSAPR, the budgets for Louisiana, Mississippi and Arkansas were not meant to force EGUs in these states to make drastic emissions reductions, or indeed any reductions at all, because EPA found that there were no available cost

- effective emission reductions and EPA’s express purpose for capping 2012 emissions in the Entergy States was to prevent “emissions leakage” from the states covered by CSAPR (see 76 FR 48263). Commenter (Entergy) references their Petition for Reconsideration and notes that a comparison of the proposed emissions budgets and actual 2010 emissions in the Entergy States makes i t readily apparent that the arithmetic changes applied by EPA in the Proposed Rule do not fully address the errors in EPA’s IPM modeling. The Proposed Rule is an improvement but the emissions reductions required for 2012 are unreasonable given that EPA fo und that no cost effective emissions reduction are available in these states. Moreover, because of the extremely short compliance period, Entergy’s compliance with the emissions reductions that would be required by the Proposed Rule will require the Compa ny to reduce generation, purchase a significant number of allowances, or install pollution controls in a very compressed time frame. Commenter provides additional discussion on this issue as well as a table summarizing the emissions, budgets, percent redu ctions, and allowance shortfalls. [Letters: Entergy (EPA

- HQ

- OAR

- 2009

- 0491

- 4820) p. 2

- 4]
RESPONSE : This comment is outside the scope of the revisions proposed and upon which EPA solicited comment. However, the docket to this rulemaking (EPA

- HQ

- OAR

- 2009

- 0491) contains previous responses to comments regarding IPM modeling. Comment (H)(2) : EPA must re

- run the IPM with revised, and more accurate, assumptions regarding unit operation and transmission constraints. EPA’s piecemeal arithmetic approach to cor recting state budgets will necessarily result in low state budgets, since there is no way to ensure that all sources within a state review EPA’s data and submit corrected information. Because low state emissions budgets necessarily impact each individual source within a state, it is inappropriate for EPA to place the impetus for correcting state emissions budgets on sources. Commenter provides additional discussion noting that allowance shortages due to inadequateFIP Revisions

- RTC Febru ary 7 , 2012 Page 19

19 state emissions budgets threaten to under mine both the premise of CSAPR and the reliable supply of electricity in covered states. Thus, it is in both EPA’s and the public’s interest for EPA to stay implementation of CSAPR while it revises state emissions budgets. [Letters: Entergy (EPA

- HQ

- OAR

- 2009

- 0491

- 4820) p. 4]
RESPONSE : EPA disagrees with the commenter, as th e revisions rule represents the fifth iteration of a public notice

- and

- comment process that the Agency has engaged in with regards to the construction of the Transport Rule programs (following the original proposed Transport Rule and three Notices of Da ta Availability), providing all sources in all affected states repeated opportunities to notify the Agency of any data discrepancies. Of the information submitted to the Agency since f inalization of the Transport Rule, EPA finds no basis for replacing the comprehensive analyses conducted as part of that rulemaking process. Instead, EPA has structured a series of targeted technical revisions to the implementation of the Transport Rule p rograms in accordance with newly submitted technical information relevant to the rule’s implementation. Comment (H)(3) : If EPA remains unwilling to re

- run the IPM modeling, it is imperative that EPA recalculate the emissions budgets for the Entergy state s using correct data and assumptions. At a minimum, there are three errors that EPA should correct (which would help, but not fully rectify, the flawed IPM results in the Entergy States). First, when EPA adjusted the Louisiana emissions budget to includ e increased generation (and emissions) from Entergy’s must run units, it removed a comparable amount of generation from combined cycle generation within the state, and in doing so EPA deducted too many emissions from the Louisiana budget based on the displ aced generation and emissions from the combined cycle units. Commenter references the TSD and NEEDS data, noting that the higher emission rate used by EPA in the TSD artificially inflates the number of emissions associated with the displaced combined cycl e generation and, as a result, improperly lowers the final proposed emissions budget for Louisiana. Second, EPA calculated the emissions for each of Entergy’s affected unit in Louisiana and Mississippi using the unit’s most efficient heat rate and as such , the amount of additional emissions calculated by EPA is lower than the actual emissions associated with operation of these units. As supporting documentation for these first two points, commenter provides data in Exhibits 3, 4, and 5 as attachments to t heir comment letter (which provide revised data for Tables 11a through d and Tables 12a through 12d of EPA's TSD). Third, EPA failed to propose any increase to the Arkansas emissions budgets despite Entergy’s request that the Agency adjust Arkansas’ emiss ions budgets to account for the non

- economic dispatch of the McClellan unit (see Petition for Reconsideration, Exhibit J). Operation of the McClellan unit is necessary to provide voltage in south Arkansas. As such, EPA should adjust the Arkansas budget t o account for non

economic dispatch at the McClellan unit. [Letters: Entergy (EPA

- HQ

- OAR

- 2009

- 0491

- 4820) p. 4

- 5]
RESPONSE : EPA is finalizing revisions for units in Louisiana, Mississippi, and Arkansas, as described in the preamble to this final rule. S ee the Final Revisions Rule State Budgets and New Unit Set

- Asides TSD in the docket to this rulemaking. For EPA’s response to commentsFIP Revisions

- RTC Febru ary 7 , 2012 Page 20

20 pertaining to heat rate and emission rate changes, please see section 6.2a and 6.2b , below, in this document. (I) Comm ents on Dispatch of Units in Louisiana Comment (I)(1) are subject to dispatch by the Sou thwest Power Pool, and LUS has historically operated : Errors were made in the parsed IPM files concerning the operation of

– and NO X emissions from

– Lafayette Utilities System’s (LUS’s) Bonin Units 1 and 2. Those units
those units

– and plans to continue to operate those units

– as called for by the Power Pool. Despite this record and although LUS presented comments about this during the rulemaking, EPA did not have Bo nin Units 1 and 2 operating in BC_P_12, and EPA still does not have those units operating in BC_F_12. In addition, LUS provided comments to EPA concerning the projected heat inputs for TJ Labbe Units 1 and 2 and Hargis

- Hebert Units 1 and 2. In the proposed rule (BC_P_12), EPA listed heat inputs that are significantly lower than actually occurred (as reported in the available data bases). LUS provided this information to EPA during the comment period, but in the final CSAPR, EPA appears

– in BC_F_12

– to hav e lowered even further the year

- 2012 heat inputs being used for these units. Similarly, errors were made in the parsed IPM files concerning the operation of

– and NO X emissions from

– Louisiana Electric & Power Authority’s (LEPA’s) Houma and Morgan City E GUs. In its comments on the PTR, LEPA noted that both the Houma and Morgan City generating facilities are “must run” units due to transmission constraints and congestion in their grid, and LEPA provided EPA with data that showed these units had operated in the years immediately preceding the PTR. EPA, however, failed to take this information into account and thus mistakenly assumes

– in both BC_P_12 and BC_F_12

– that these units will not be operating in 2012. Entergy pointed out in its rulemaking comments on the PTR that EPA’s IPM modeling assumes too little usage of the state’s oil

- fired and gas

- fired units.
These and other errors all contributed to the overall concern that the State of Louisiana and others raised during the comment period on the PTR, i. e., that EPA was mistakenly assuming that many of the state’s oil

- fired and gas

- fired units would not be operating at all in 2012 or that they would then be operating at much lower levels than they have historically operated. As a result of making such ass umptions, the heat inputs for Louisiana sources and ozone season NO X emissions in BC_P_12 and BC_F_12 are much lower than actually occurred in 2010. This is summarized in the following table.
Scenario Heat Input (TBtu) Seasonal NO X (tons) BC_P_12 22 4.9 21,200 BC_F_12 235.1 13,400 CEMS_2010 336.1 23,200FIP Revisions

- RTC Febru ary 7 , 2012 Page 21

21 [Attachment to UARG comment letter, “J. Marchetti, J. E. Cichanowicz, Initial Identification of Unit Errors in Integrated Planning Model (IPM) Runs (Oct. 7, 2011)” (EPA

- HQ

- OAR

- 2009

- 0491

- 4823) p. 46

- 47]
RESPONSE : The response to this comment has been combined with the response to comment (I.)(2.), below. Comment (I)(2) identified many of the state’s oil

- and ga s
- fired units as non

- economic/out

- of

- merit units : In evaluating projected NO X emissions in Louisiana in 2012, EPA’s modeling that either would not be operating at all or would be operating at below historical levels. Many of these units, however, are “must

- run” units that are needed for grid stability due to transmission constrain ts and congestion. As a result of making erroneous assumptions about the status of many of Louisiana’s oil

- and gas

- fired units, the IPM heat inputs for and ozone season NO X emissions from those sources are significantly below what is expected in 2012. Som e of the must

- run units that were identified in the October 2011 Report are Lafayette Utilities System’s Bonin Units 1 and 2, TJ Labbe Units 1 and 2 and Hargis

- Hebert Units 1 and 2 and Louisiana Electric & Power Authority’s Houma and Morgan City EGUs.
EPA ’s Proposed Revisions propose to assign generation to several other noneconomic gas
- fired units that are needed to maintain grid stability: R.S. Nelson 3 & 4, Little Gypsy 1

– 3, Nine Mile Point 3

– 5, Michoud 1

– 3 and Waterford 1 & 2. The Proposed Revisi ons, however, do not address the status of the other units listed above. [Attachment to UARG comment letter, “J. Marchetti, J. E. Cichanowicz, Addendum Report, Unit Errors in the Integrated Planning Model (IPM) Runs for the Final Cross

- State Air Pollution Rule (CSAPR): A Comparison of Errors Addressed by EPA’s Proposed Revisions to CSAPR and Errors Identified by Rulemaking Participants (Nov. 28, 2011).” (EPA

- HQ

- OAR

- 2009

- 0491

- 4823) p. 72]
RESPONSE : EPA has responded to comments received from LUS and LEPA on the proposed revisions concerning these units in section 1.2 of this document. EPA notes that the LUS and LEPA comments on the proposed Transport Rule that UARG cites pertained to allocation methodology. In those comments LUS and LEPA disagreed with th e proposed allocation methodology that was based upon IPM output. EPA considered these comments, along with others, and ultimately revised the allocation methodology to be based upon historic heat input. Under the final Transport Rule unit

- level allowanc e allocation methodology, the LUS and LEPA units in question receive initial allowance allocations. The allocation methodology is described in section VII.D of the preamble of the f inal Transport Rule. While the Marchetti report attached to UARG’s commen ts identifies units that it claims are “must run”, neither the report nor UARG’s comments detail how frequently conditions occur that require out

- of

- merit

- order dispatch at these units nor the minimum amount these units need toFIP Revisions

- RTC Febru ary 7 , 2012 Page 22

22 run to provide voltage suppo rt or provide grid stability due to congestion, as specifically requested in the proposed revisions [76 FR 63868]. Unit level comparisons to historic levels of heat input are, while relevant, insufficient in and of themselves as a basis for Transport Ru le revisions based on out

- of

- merit

- order dispatch issues, since the historic data do not necessarily reflect future dispatch under the Transport Rule. Furthermore, commenters appear to mistake heat input as an input assumption in IPM modeling, while it is actually an output of the modeling projections based on the model’s determination of least

- cost dispatch to meet electricity demand. In the revisions rulemaking, EPA has considered whether new information presented after the finalization of the Transport Rule would support any unit

- level technical revisions to the previous modeling projections of immediate

- term least

cost dispatch (and associated emissions) that supported quantification of the programs’ state budgets. Such technical revisions are designed to maintain a projected, future

- year least

- cost dispatch pattern (that achieves all cost

- effective emission reductions available under the Transport Rule programs) while factoring in certain immediate

- term non

- economic operational constraints identified b y commenters affecting certain units. As such, it is not possible or analytically sound for EPA to replace its modeling projections wholesale with historic operational data (including heat input). EPA’s response to comparisons of statewide historic heat input to IPM heat input is in section 6.3 , below

.FIP Revisions

- RTC Febru ary 7 , 2012 Page 23

23 Issue 1.3 Michigan Modeling Assumptions (A) It is appropriate for EPA to adjust allowance allocations and new unit set
- asides to fix miscalculations in projected emission and erroneous modeling assumptions. Comment (A)(1) : Commenter (MDEQ) notes that companies and local governments in Michigan have raised many concerns about the achievability and sustainability of strategies enumerated in the Transport Rule analysis and provides as an attachment, a letter submitted by the Michigan Municipal Electric Association (MMEA) in October 2011 as an example of such concerns. MMEA raises concerns related to the generation dispatch resulting from under
- allocation, localized reliability risks, and the inherent penalti es for early actions to reduce emissions. Commenter notes that MMEA is also very concerned that some of its members with small EGUs just above the 25 MW threshold (e.g., Holland Board of Public Works and Wyandotte Municipal Services) will be unable to cos t effectively comply without EPA flexibility to allow these units to reduce capacity and opt out of compliance obligations. In addition, resolving the conflict of Upper Peninsula system reliability and the CSAPR under
- allocation of allowances for the We E nergies’ Presque Isle plant should be a priority concern for EPA. [Letters: Michigan Department of Environmental Quality (EPA
- HQ
- OAR
- 2009
- 0491
- 4859) p. 1]
RESPONSE : EPA believes these concerns are misplaced. EPA points out that the flexibility of the Transport Rule program does not require any individual unit to reduce emissions for compliance, but only to hold sufficient emission allowance s to cover the emission s the unit actually produces. Moreover, local reliability conditions are recognized in all ocating allowance to units, because allowances are not based on model projections, but on actual use of the units; consequently a unit that must be used and has been used for reliability will receive allowances commensurate with these historical reliabilit y uses. Additionally, EPA reviewed the information provided by W e Energies on the need for the Presque Isle plant to operate to provide power and grid stability to the Upper Peninsula. Based on the information provided, EPA determined that the plant ran s ufficiently in the IPM analysis of the final Transport Rule [“WebReady_ParsedFile_TR_Remedy_Final_2012,” EPA

- HQ

- OAR

2009

- 0491

- 4431] such that EPA’s previous projections are consistent with the information provided by the commenter to satisfy this plant’s m inimum operational requirements; therefore, no revisions to the state budget are considered necessary. (B) Comments on Control Installations and Emission Rates at Michigan Units
Comment would be installed at the Monroe Power Plant. For FGD, the actual installation schedule : Errors were made in the parsed IPM files as to when FGD and SCR sy stems at Monroe is the following: FGD systems were installed at Monroe Units 3 and 4 in 2009; FGD will be installed at Monroe Unit 1 by November 2013; and FGD will be i nstalled at Monroe Unit 2 by April 2014. BC_P_12 correctly reflected that the installation of WFGDs would be complete at two units

– Monroe Units 3 and 4

– byFIP Revisions

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24 2012. BC_F_12, however, erroneously assumes that WFGDs will be installed on all four units at Mon roe by 2012. Similarly, when evaluating SCR retrofits at Monroe, BC_P_12 correctly reflected that no SCR system will be installed on Monroe Unit 2 until 2014; however, BC_F_12 erroneously assumes that an SCR system already has been installed and is in oper ation at Monroe 2. In the PTR, errors were also made in the parsed IPM files concerning the SO 2 emission rates for River Rouge Units 2 and 3 and St. Clair Units 1

- 4 and 6

- 7. In response to rulemaking comments on the incorrect emission rates reflected in B C_P_12, EPA made some corrections to take fuel blending into account, but the SO 2 emission rates in BC_F_12 for River Rouge Units 2 and 3 and St. Clair Units 1

- 4 and 6

- 7 are still unrealistically high (much higher than historical levels) when those units a re burning 100% subbituminous coal. Rulemaking comments also pointed out errors made by EPA (in BC_P_12) concerning the SO 2 and NO X emission rates for Trenton Channel Units 16

- 19 and 9A. In BC_F_12, however, EPA continues to use unrealistically low SO 2 an d NO X emission rates for these units.
Errors were also made as to the NO X and SO 2 emission rates for Eckert Station Unit 2. Specifically, EPA assumed

– in the PTR (as reflected in BC_P_12)

– that Unit 2 was equipped with low

- NO X burners and overfire air ( LNB/OFA) and that Unit 2’s NO X emission rate was thus 0.12 lbs/ mmBtu . In response to rulemaking comments indicating that Unit 2 was not equipped with LNB/OFA (although other units at Eckert Station are equipped with such technology), EPA appropriately note d in BC_F_12 that Unit 2 is not equipped with LNB/OFA, but failed to correct the NO X emission rate for Unit 2. Thus BC_F_12 erroneously uses a NO X emission rate of 0.13 lbs/ mmBtu for Eckert Unit 2, rather than the unit’s actual rate of about 0.26 lbs/ mmBtu . Errors were also made as to the appropriate SO 2 emission rate for Eckert Unit 2. Although (as pointed out in rulemaking comments) the SO 2 emission rate for Eckert Unit 2 (as reflected in actual SO 2 emissions data for the plant) is about 0.53 lbs/ mmBtu , E PA continued

– in BC_F_12

– to use an SO 2 emission rate of 0.94 lbs/ mmBtu . A similar SO 2 emission rate error was made for Erickson Unit 1: the actual emission rate for that unit is 0.56 lbs/ mmBtu , but EPA used an SO 2 emission rate of 0.94 lbs/ mmBtu for Eri ckson 1 in both BC_P_12 and BC_F_12. [Attachment to UARG comment letter, “J. Marchetti, J. E. Cichanowicz, Initial Identification of Unit Errors in Integrated Planning Model (IPM) Runs (Oct. 7, 2011)” (EPA

- HQ

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- 48]
RESPONSE : As no ted in the final Transport Rule TSD on Significant Contribution and the p reamble for the final Revi si ons Rule, appropriate budget adjustments have been made to reflect the timing on control installation at the Monroe Power Plant. In regards to NO X emissio n rates, see section 6.2b , below, of this document. In regards to SO 2 emission rates, see section 6.2c , below, of this document. For SO 2 emission rates, EPA notes that, like NO X emission rates, thatFIP Revisions

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25 the future emission rate values projected take into acc ount a variety of factors including future regulatory requirements and market fundamentals. They are not simply meant to reflect historic values as implied by commenter. The Transport Rule programs include cost

- effective emission reductions available thr ough coal switching, which can result in substantially different emission rates being observed at a unit relative to that unit’s historic emission rate or emission rate in a scenario where there are no emission reduction requirements.
Issue 1.4: Nebraska and Wisconsin Modeling Assumptions
Points Raised: (A) Commenters agree with some of the technical adjustment made to the Nebraska state NO X budget (e.g., to correct the assumption that OPPD's Nebraska City Station Unit 1 is equipped with SCR (since this u nit does not have SCR)), but indicates that additional revisions need to be made to the assumptions EPA used to develop Nebraska's state budget. Comment (A)(1) : The EPA spreadsheet named "WebReady_ParsedFile_TR_Remedy_Final_2012.xlsx" lists Whelan Energy Center Unit 1 as having a dry scrubber with total SO 2 emissions of approximately 256 tons per year, reflecting an SO 2 emission rate of 0.08 lb/mmBtu. However, this unit does not have a dry scrubber as evidenced by the 2010 data for this unit found on the EPA Clean Air Markets website that gives 2010 SO 2 emissions of 2,300.7 tons and heat input of approximately 5,689,332 mmBtu. This calculates to a SO 2 emissions rate of approximately 0.81 lb/mmBtu, which indicates use of low sulfur PRB coal without scrubb er controls. As such, the SO 2 emission level is nearly 10 times the value EPA used. This correction should result in an approximately 2,000 ton increase in the Nebraska state SO 2 budget (a 3% increase). [Letters: Omaha Public Power District (EPA

- HQ

OAR

- 2009

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- 4747) p. 1

- 2]
RESPONSE : EPA is finalizing revisions to the Nebraska 2012 and 2014 SO 2 budgets, based on comments on the revisions rule, to correct assumptions regarding FGD pollution control technology at Whelan Energy Center Units 1 and 2 and Nebraska City Unit 2. The commenter noted that the technology at Nebraska Unit 2 and Whelan Unit 2 is dry FGD technology, whereas EPA had assumed wet FGD technology with a higher SO 2 removal efficiency than the actual dry FGD technology that those units achieve. Additionally, EPA is also revising its assumption of FGD technology at Whelan Energy Center Unit 1. There is no FGD present, planned, or under construction at the unit. These adjustments result in increases to the 2012 and 2014 annual SO 2 budge ts for the state. See “Final Revisions Rule State Budgets and new Unit Set

- Asides TSD” in the docket for this final rule. Comment (A)(2) : The EPA spreadsheet named "WebReady_ParsedFile_TR_Remedy_Final_2012.xlsx" lists Nebraska City Unit 2 and Whelan Energy Center Unit 2 as having wet scrubbers. These two units in fact have dry scrubbers. The SO 2 emission rate for these two units was assumed to be 0.06 lb/mmBtu, but should be 0.08FIP Revisions

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26 lb/mmBtu (i.e., the lowest SO 2 emission rate that EPA assumed for any units firing subbituminous coal equipped with dry scrubbers). These changes would increase the Nebraska state SO 2 budget by at least 514 allowances per year (and when combined with the Whelan Unit 1 correction, would result in a 4% increase in the Nebras ka state SO 2 budget). [Letters: Omaha Public Power District (EPA

- HQ

- OAR

- 2009

- 0491

- 4747) p. 2]
RESPONSE : See response to comment (A)(1) above. Comment (A)(3) : Based on review of an EPA spreadsheet named "NEEDSv410_FTransport.xls," there are a number o f assumptions that went into determining the Nebraska state NO X budget that are incorrect. EPA assumed that state of the art combustion controls were in place on several Nebraska units that in fact do not have these controls and could not possibly install these controls in time to comply with the 2012 budget. Commenter provides a table with specific adjustments to correct these technical errors in the Nebraska state budget calculation. Commenter also provides additional discussion on this issue, includin g the details behind why it is not feasible to implement the assumed controls within the timeframe EPA assumes (including significant implications regarding reliability). Commenter concludes that if EPA is assuming that half of Nebraska's coal

- fired units will need to go through major modifications to comply with the TR, the drastic reductions in the Nebraska NO X budgets should go into effect in 2014, not 2012. [Letters: Omaha Public Power District (EPA

- HQ

- OAR

- 2009

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- 4747) p. 2

- 3, 5]
RESPONSE : The final Transport Rule state budgets, inclusive of the revisions made to them, assume no new post combustion controls beyond those already planned for sources in Nebraska. Furthermore, there are no unit level requirements under the rule. The final Transpor t Rule provides flexibility of an emission s trading program, which means sources can buy, trade, or sell allowances if they emit more/less than they plan to emit. Finally, in regards to combustion control installation, Section VII of the f inal Transport R ule discusses the timing and feasibility of Low NO X Burner (LNB) installation. In addition to that discussion, EPA notes that the major emitters in the state of Nebraska already have planning and/or installation of such controls underway due to regulation s or economic drivers outside of the Transport Rule. EPA also notes that the s tate is already operating at levels less than its NO X assurance level and close to the s tate budget. The level of current emissions in the state illustrate s that no additional controls are necessary in order for compliance with the rule. Comment (A)(4) : The proposal does not correct erroneous assumptions for Whelan Energy Center Units 1 and 2 and Nebraska City Station Unit 2. IPM inputs show Whelan Unit 1 with a dispatchable dry scrubber for SO 2 control. This unit has no SO 2 control. The IPM inputs also incorrectly list Whelan Unit 2 and Nebraska City Station Unit 2 as having wet scrubbers. These units have dry scrubbers. As discussed in Pages 4 and 5 of NPPD's Petition fo r Reconsideration and Stay of the final CSAPR, EPA's analysis and/or budget allocations have basic errors. One of the errors discussed is EPA's assertion that the emissions budgets allocated to Nebraska for both SO 2 and NO X are lower (by 6,287 and 1,771 t ons/yr respectively) than the EGU emissions EPA claimed it modeled as part of its 2014 Remedy Case. The proposed revised emissions allocationsFIP Revisions

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27 for Nebraska do not account for these errors, and EPA should correct these errors and revise the Nebraska allo cations accordingly. [Letters: Nebraska Public Power District (NPPD) (EPA

- HQ

OAR

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- 4754) p. 1

- 2]
RESPONSE : See response to comment (A)(1) above. (B) Significant errors persist in the EPA base case and remedy runs for Wisconsin. Comment (B)(1 ) : There are still mistakes in the data, above and beyond those identified in EPA’s Proposal. EPA’s 2012 and 2014 remedy data sets (which set the state budgets) do not appear to contain the same emission rate errors as are contained in the 2012 base case for Wisconsin. However, EPA assumed in its 2012 remedy data set that two of the four South Oak Creek units will have SO 2 controls in place by January 1, 2012, but in fact those units are subject to a consent decree that does not require such controls unt il December of 2012. This data error, if corrected, would raise Wisconsin’s state budget of SO 2 allowances in 2012 by approximately 6,000 tons. The Cross

- State Rule petitions for reconsideration filed with EPA by UARG, WDNR, WPL, and Dairyland all identi fy additional errors in the 2012 and 2014 remedy files for Wisconsin that EPA has not yet corrected. [Letters: Inte r gys Business Support (EPA

- HQ

- OAR

2009

- 0491

- 4757) p. 2

- 4]
RESPONSE : This c omment simply point s out when controls are required to be on, not when they will actually be installed and available. The 2012 TR_Remedy_Modeling is not designed to reflect the “required” dates of operation of controls, but the operation of controls that are available and economic to operate. For controls that are online before their “required” deadline, EPA’s IPM model assumes it will be economic to operate such controls at a given threshold. This informs the budgets determined for the state. EPA has received comment that these controls will come on during 2012, well before the deadline. Outages leading up to final tie

- in, will likely result in lower emissions, not higher emissions than those modeled by EPA

- making the EPA analysis conservative. Furthermore, while 4 units seem to be getting retrofitted during 2 012, EPA is only showing retrofits on two units as operating for the entire year. For example, 2010 SO 2 emissions for the facility were approximately 12,000 tons. In spite of four units gaining controls at the facility during 2012, EPA is only forecastin g an approximate 33% reduction for the facility in 2012

- to about 8,000 tons. This modest decrease given the major pollution control installation underway is both achievable and likely for South Oak Creek. At the plant level, EPA believes its forecast f or the South Oak Creek facility is very reasonable and that it shows two units retrofitted for the entire year

— which has an emission consequence very similar to four units being retrofitted for part of the year. In this case, EPA fully expects the South Oak Creek to emit at levels that are consistent with what is projected in its 2012 remedy modeling and thus there are no grounds for a budget adjustment. However, in any case, sources are free to emit as they cho o se given the flexibility of the trading p rogram and there is no requirement that sources perform as modeled. Regardless of whether the controls come on before or after the year modeled by the EPA, the source will be free to use the allowance market to buy or sell allowances. In addition to bei ng planned to be online in 2012, the controls areFIP Revisions

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28 required to come online in 2012, making any further adjustment unnecessary for Transport Rule implementation. Comment (B)(2) : EPA's 2012 and 2014 remedy IPM modeling runs did not take into account CSAPR's own regulatory constraints. For example, under the rule, WPSC's units are effectively capped since the units cannot emit more than WPSC's total allowance allocation plus the variability limit, or WPSC could be subject to substantial penalties if the Stat e of Wisconsin also exceeds its allowance cap. Yet EPA's 2012 remedy modeling run assumed that WPSC's units would emit 22,804 tons of SO 2 in 2012, but WPSC's total SO 2 allowance allocation under the rule in 2012 is 16,137 (increased to 16,303 under the pr oposed revision), which means its assurance cap will be 19,042 tons of SO 2 in 2012 (19,238 under the proposed revision). EPA's 2012 remedy run therefore assumes that WPSC would do something it would not do: emit above its own Cross

- State Rule cap and subj ect itself to potential penalties. Although the proposed revisions would eliminate the penalty provisions in 2012 and 2013, this example further demonstrates the significant errors in the EPA analysis and rule. [Letters: Integrys Business Support (EPA

- H Q

- OAR

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- 4]
RESPONSE : The commenter’s criticism of the modeling is incorrect, as the commenter ignores the fact that the rule’s assurance provisions are applied at the designated representative level, and owners and operators have the f lexibility to rearrange the relationship of covered units to designated representatives as they see fit (including across units owned or operated by multiple utilities and/or companies , as they so choose ) . There is no such thing as an “assurance cap” at t he unit or utility level under the Transport Rule; instead, the assurance level is relevant to total emissions in the given state, and any potential penalties are assessed for individual designated representatives, which owners and operators have the flexi bility to elect to represent whatever configuration of units they prefer. Therefore, the projected emission pattern from EPA’s IPM modeling of the Transport Rule is fully consistent with all covered sources meeting the rule’s requirements. Comment (B)(3) : Wisconsin cannot achieve the reductions from historical emissions needed to comply with the 2012 and 2014 allowance allocations at a cost of $500/ton and $2300/ton, respectively. The reductions needed to achieve emissions at the allocation level would require installation of major pollution control equipment that would take 3.5 to 5 years to design, obtain regulatory approval for, and install in Wisconsin. Moreover, the errors that EPA proposes to correct for the annual NO X program also require adjustm ent of the Wisconsin ozone

- season NO X state budgets. In other words, Wisconsin and WPSC should receive additional allowances under the ozone

- season NO X program for the same reasons that additional allowances will be allocated to these sources for the annu al SO 2 and NO X programs under EPA’s Proposal. [Letters: Integrys Business Support (EPA

- HQ

- OAR

- 2009

- 0491

- 4757) p. 2

- 4]
RESPONSE : The adjustments to the ozone

- season NO X program referenced in the comment above were already implemented in the Supplemental Notice of Final Rulemaking (76 FR 80760, December 27, 2011) . As to the viability of th e Wisconsin budget s , EPA notes that the state is already operating at or below its budget level for annual and ozone

- season NO X . For SO 2 , noFIP Revisions

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29 additional advanced pollut ion controls are expected other than those that have already been planned and/or are under construction. EPA believes the reductions necessary to comply with final budgets and assurance levels are in some cases already realized in the state of Wisconsin, and in others only require the completion and operation of already planned controls along with other non

- control based compliance options such as fuel switching at some units. For instance, the phase 1 SO 2 budget is approximately 20 percent lower than the past year’s emissions. However, with completion and continued operation of the South Oak Creek controls, Genoa facility controls, and a switch from petroleum coke to subbituminous coal at Nelson Dewey (all already existing or indicated) will, in themselv es , bring the state’s emissions below the state assurance level and possibly below the state budget for SO 2 . Comment (B)(4)

Natural Resources (EPA

- HQ

- OAR

- 2009

- 0491

- 4824) p. 6] : The Valley power plant is specifically designed and operated as a combined heat and power plant. The plant is contracted to supp ly heat and cooling to customers in downtown Milwaukee as well as generate electricity. Currently this facility is last in dispatch across the We Energies coal

- fired power plants. As such, a reasonable surrogate for minimum operating levels may be the re cent operation of these units from 2008 through 2010. This operation level is closely tied to actual heat and cooling needs versus operational levels dispatch of only electric generation to the grid. However, the 1PM model remedy run predicted higher ope ration and dispatch in 2012 than this 2008 to 2010 historic average. Because the model found this configuration of Valley to economically dispatch at higher levels in 2012, commenter (WDNR) recommends EPA use the 2012 operation for projecting minimum oper ation of the Valley unit through 2014 and provides a summary of their requested revisions in Table 5 of their comment letter. [Letters: Wisconsin Department of

RESPONSE : The 2014 state budgets are b ased on a distinct set of emission projections specifically tied to modeling of a least

- cost equilibrium between electricity supply and demand in that year. The model does not simply assume that 2014 operation of a particular unit will mirror 2012 operati on , as suggested by commenter, as that would imply a static industry (unchanging over time). Comment (B)(5) : The IPM Remedy run for the final CSAPR does not appear to include several generation units at two Wisconsin utility plants which feed generators greater than 25 MW: the Manitowoc Public Utility plant unit 8, and Bay Front plant units 1, 2, and 5. The Bay Front units 1 and 2 burn primarily biomass but fire coal intermittently as needed. Further evaluation may be needed whether these two units are a ctually fossil fuel fired and subject to the CSAPR. The emission characteristics of the Manitowoc and Bayfront missing units are summarized in Table 6 of the commenter's letter. [Letters: Wisconsin Department of Natural Resources (EPA

- HQ

OAR

- 2009

- 0491

- 4824) p. 6

- 7]
RESPONSE : These units are included in the final IPM Remedy run , for the final Transport Rule involves all units that are listed in the NEEDs database. This includes the Bay Front units and the Manitowoc unit referenced by the commenter. T herefore, these units are included in the final IPM remedy run. The commenter is likely assuming that the only units included are in the runFIP Revisions

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30 are those listed in the parsed results. However, this is a misconception. The parsed results do not show all uni ts, but only those that are fossil and have boilers greater than 25 MW. (C) Commenter provides information on currently approved plans for future emissions controls on Wisconsin and Iowa plants since EPA's application of this information has been quest ioned. Comment (C)(1) : Alliant provides information regarding currently approved company plans for future emissions controls at four facilities in Wisconsin and Iowa. The projected commence operation dates provided in a table are subject to future revis ions pending the outcome of construction activities. There will also be a period of start

- up and shakedown of the air pollution control equipment after the commence operation date. Due to these uncertainties the full emission reduction benefits are not l ikely to be realized in the year that the pollution control commences operation. Consequently EPA's modeling for the Transport Rule should apply these additional emissions reductions no sooner than six months following the commence operation date. The pr ovided table includes: WPL Columbia Energy Center, Units 1 and 2, Baghouse and Spray Dryer; Absorber, April and June 2014; WPL Edgewater Generating Station, Unit 5, SCR, January 2013; IPL Ottumwa Generating Station, Unit 1, Baghouse and Spray Dryer; Absorb er, June 2014; IPL Lansing Generating Station, Unit 4, Baghouse and SCR in 2010; and Circulating Dryer Scrubber, June 2015. [Letters: Alliant Energy (EPA

- HQ

- OAR

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- 0491

- 4762) p. 4]
RESPONSE : EPA does not assume the scrubber at Lansing Unit 4 is inst alled in 2014. It honors the 2015 start date noted by the commenter above. In regards to the other unit control issues, EPA does not agree with commenter assertion that controls should not be assumed to be operational until the year following the year of their installation. First, given the fact that these controls are in a group 1 state, it is entirely reasonable that their pre

- Transport Rule installation schedule is accelerated slightly due to the $2300/ton cost threshold modeled in EPA’s multi

factor analysis. Second, even if no changes were made to the control’s installation date and it was installed at some hypothetical month in 2014 (June for example), it is still likely that the outages prior to final tie

- in would result in an emission decrease, w hereas the commenter is suggesting that the facility would be operating at normal loads before and after installation. For these reasons, EPA believes it is most reasonable to reflect control installations for Group 1 states in the year in which they occu r, not at some later year. (D) Commenters request additional Wisconsin post
- combustion control corrections (including emission rate corrections). Comment (D)(1) : There are a number of errors associated with We Energies (WE) power plants and if not alre ady corrected, the state emission budget should be adjusted upward. Commenter (WE) notes that there are three main areas where corrections are needed. First, errors were made in the parsed files for when WFGD and SCR systems will be retrofit on Oak Creek Units 5

- 8. Under the terms of an enforceable consent decree, WFGD and SCR systems are to be installed on Oak Creek Units 5

- 8 by December 31, 2012. The company anticipates that the controls at Oak Creek Unit 5 will be operational in December 2011 and at Units 6

- 8 in 2012. In BC_P_12FIP Revisions

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31 and BC_F_12, EPA erroneously failed to reflect that the WFGD/SCR systems on Units 5 and 6 would be operational in 2012. Second, errors were made in the parsed files concerning the installation and operation of SCR systems fo r Valley Units 1 and 2. No SCR retrofits are planned for Valley. In BC_F_12, however, EPA appears to assume erroneously that Valley will be operating SCR systems to reduce NO X emissions from the Valley units. Third, errors were made in the parsed files for Elm Road Units 1 and 2. Unit 1 began commercial operation in February 2010; Unit 2 began commercial operation in February 2011. Under the terms of CSAPR, both units should receive SO 2 allowance allocations from the new unit set

- aside pool. In the fi nal rule, however, EPA erroneously gives Elm Road Unit 1 allowances from the main allocation pool instead of from the new unit set

- aside pool (also see Issue 2.3 for new unit set aside issue). EPA should revise state budgets and assurance levels to reflec t these late changes to the underlying data and related rule assumptions. [Letters: We Energies (EPA

- HQ

- OAR

2009

- 0491

- 4781) p. 5

- 6]
RESPONSE : In regards to the South Oak Creek concerns, see response to Integrys Business Support Comment above (1.4(B)(1) ). In regards to the Valley units, while the IPM model outputs denote an “SCR” for Valley Units 1 and 2, that designation is a surrogate for other types of emission rate controls including, in Valley’s case, emission limitations imposed by state law requi rements. While these individual units may not need to install actual “SCR” to comply with the state law requirements, the IPM emission projections for the full set of units subject to the state law requirements matches that law’s required reductions such that the state

- level emissions projection is valid and no state budget revision is warranted. As EPA noted in its IPM documentation for the Final Transport Rule, some controls may be represented as the model’s estimate of how sources collectively covered under a state rule or consent decree would respond to rate or tonnage requirements. However, in no way does EPA intend for actual unit level response to perfectly mirror these estimates. States may very well find different way of complying. However, bec ause the rate or tonnage requirements are legally binding, the emissions consequences projected are still valid even if the state or covered sources chose a different compliance option to reach the target levels. For example, sources have commented the Ed gewater 5 will actually install a control and emit at a lower emission rate than EPA assumed for it in 2014. This is an example of reductions coming from a different covered source, but coming nevertheless. In regards to the Elm Road units, EPA treated u nit 2 as a new unit as noted by the commenter. For Unit 1, the commence commercial operation date of October 2009 reported to EPA was used to determine its status as an existing unit, commenter has not provided sufficient evidence as to why that reported date is incorrect. Comment (D)(2) : For the Columbia power plant, EPA assumed wet scrubbers operating at generating units 1 and 2 beginning January 1, 2014 under both the finalized Cross

- State Air Pollution Rule (CSAPR) baseline and remedy emission budget s. EPA in this rule making is correctly identifying that dry scrubbers rather than wet scrubbers will be installed on the Columbia units as approved by the Wisconsin Public Service Commission (PSC) in March 2012. However, in making this change EPA is sti ll assuming SO 2 scrubbing begins by January 1, 2014, which is incorrect. The project will take up to 36 months to complete and based on this schedule the reductions cannot be achieved prior to April 2014 (as such, the emissions budgets should notFIP Revisions

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32 reflect SO 2 scrubbing prior to May 2014, and preferably EPA should expect variable operation throughout 2014). [Letters: Wisconsin Department of Natural Resources (EPA

- HQ

- OAR

- 2009

- 0491

- 4824) p. 1

- 2]
RESPONSE : See Response to Alliant Energy comment 1.4(C)(1), above. Comment (D)(3) : EPA, under the finalized CSAPR, identified SCR equipment operating in 2012 at the Wisconsin coal

- fired units Valley 2 and 3, and at Edgewater unit 5. Currently, there are no SCR installations approved or planned for the Valley uni ts. Further, in developing Wisconsin NO X RACT rules in 2007, the WDNR estimated SCR controls for Valley to cost well in excess of the $500/ton cost level identified for Wisconsin NO X emissions under CSAPR. Therefore, assuming SCRs at Valley is incorrect. WDNR recommends that emission budgets through 2014 reflect the current NO X emission rate for Valley units. [Letters: Wisconsin Department of Natural Resources (EPA

- HQ

- OAR

- 2009

- 0491

- 4824) p. 2]
RESPONSE : See response to We Energies comment (1.4(D)(1)) above in regards to Valley units. As to the Edgewater unit 5, the emission rate that EPA assumed for Edgewater Unit 5 is consistent with recent emission rates achieved by that unit without operating a SCR. Comments provided on this rulemaking suggest the unit is installing a SCR and will be able to achieve a lower emission rate than that projected by EPA modeling. This would suggest a budget decrease for the Wisconsin state budget. However, because these reductions are collectively covered under the sta te rule requirements, EPA does not believe that any adjustments are necessary or appropriate. Comment (D)(4) : The Edgewater 5 unit is currently in the process of installing an SCR to meet lower NO X RACT emission requirements starting May 1, 2013. WPL or iginally submitted a request for construction to the Wisconsin PSC in early 2008 with an anticipated start

- up date late in 2011. The PSC, however, did not grant approval until May 2010. The most recent construction progress report from WPL forecasts an i n
- service date of December 2012 for the SCR. Therefore assuming a 2012 start date under CSAPR is incorrect, the full emission reduction should be applied to emission budgets from May 1, 2013 and after (the effective date for the state RACT requirement). Commenter provides additional discussion on the implementation schedule and the correct NO X emission rate data for all Edgewater units in Table 2 of their letter. Commenter observes that after the SCR, the NO X emission rates for units 3 and 4 are attenuat ed to reflect levels consistent with good operation and combustion efficiency. [Letters: Wisconsin Department of Natural Resources (EPA

- HQ

- OAR

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- 3]
RESPONSE : This comment suggest a budget decrease, not an increase. EPA modeled a 201 2 and 2014 NO X emission rate for Edgewater unit 5 that approximates its current emissions without a SCR. Therefore, once the SCR is installed, the unit will be able to operate at emission levels lower than those projected, suggesting a reduced budget. Ho wever, EPA believes that this is a potential case of emission reductions being captured by one unit that were projected to occur by a different unit (i.e. , Valley facility). Therefore, there is no net impact.FIP Revisions

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33 Comment (D)(5) : Selective Catalytic Reducti on (SCR) and wet scrubber equipment are under construction at Oak Creek units 5 through 8 as required under We Energies' consent decree with EPA. According to We Energies' latest progress report to the Wisconsin PSC, this equipment is on schedule for serv ice on all four units by December 31, 2012. On this basis and because this is the emission requirement deadline under the consent decree, WDNR recommends that emission reductions from SCR and wet scrubber equipment for the Oak Creek plant should not be co nsidered available prior to December 31, 2012. [Letters: Wisconsin Department of Natural Resources (EPA

- HQ

- OAR

- 2009

- 0491

- 4824) p. 3]
RESPONSE : In regards to the South Oak Creek concerns, see response to Integrys Business Support comment above (1.4(B)(1 )). Comment (D)(6) : Regarding the Manitowoc Public Utilities (MPU) unit 9 NO X and SO 2 emission rates (as applied by the IPM model), are significantly different in the remedy run versus emission rates resulting from existing equipment and operations at a current emission rate of 0.26 lbs/ mmBtu . Conversely, the model predicts reducing the NO X emission rate further. The current emission rate is 0.1 lbs/mmBtu with SNCR on the already inherently low emitting fluidized bed boiler. Both the current SO 2 and NO X emission rates should be used in determining emissions from MPU unit 9. [Letters: Wisconsin Department of Natural Resources (EPA

- HQ

- OAR

- 2009

- 0491

- 4824) p. 4]
RESPONSE : While informed by past operation, model projections are not simply replications o f past operation. Market conditions will be different in future years relative to past years, and EPA fully expects some sources to operate differently under these conditions. (E) Commenter requests corrections to the fuel
- switching and SO 2 emission rat e assumptions for Wisconsin units. Comment (E)(1) : Commenter provides a summary table that shows WDNR identified corrections where fuel switching is appropriate by 2012 under the $500/ton threshold. For the Madison Gas and Electric (MGE) owned Blount St reet facility, the IPM remedy run fuel switched to a high sulfur coal fuel. However MGE has committed to fire natural gas in the Blount Street generation units beginning 2012 and after. For JP Madgett unit 1, the IPM model switched to coal with higher su lfur content than that currently under contract. This current coal has an average emission rate of 0.44 lbs/mmBtu. Likewise, IPM switched South Oak Creek to higher sulfur content coal. The recent historic average is 0.46 lbs/mmBtu. No change in SO 2 em ission rate for South Oak Creek is warranted until the committed wet scrubbers come online. The corrected SO 2 emission rates for JP Madgett and South Oak Creek reflect 2010 and 2011 CAMD reported emissions rates. EPA should adopt the corrections summariz ed in Table 3 (as provided in the commenter's letter), to reflect current conditions at the Blount Street, JP Madgett, and South Oak Creek generation units. [Letters: Wisconsin Department of Natural Resources (EPA

- HQ

- OAR

- 2009

- 0491

- 4824) p. 4]FIP Revisions

- RTC Febru ary 7 , 2012 Page 34

34 RESPONSE : See response in section I.3(B) above regarding coal switching and SO 2 emission rate projections. Comment (E)(2) : In applying fuel switching, the EPA analysis assumed wide applicability of ultra

- low sulfur subbituminous coal to several Wisconsin sources (commenter provides a list in Table 4 in their letter). The SO 2 emission rate applied for the ultra

- low sulfur fuel ranges from 0.56 to 0.58 lbs/mmBtu for the affected generation units. However, simply switching to ultra

low sulfur coal does not appear t o meet the cost and feasibility constraints. At best this level of fuel switching is proving challenging. WPL, which operates the Columbia, Edgewater, and Nelson Dewey facilities, currently fires an ultra

- low sulfur coal in the Edgewater Unit 4 boiler. WPL explored obtaining more of this coal from their supplier for firing at their other units 5. In this case the utility was not able to withdraw from their existing contracts for low sulfur coal although the utility also offered to pay an added premium. Further, the supplier is requiring substantially longer contracts for ultra

- low sulfur coal compared to the 2 to 3 year contracts for the normal low sulfur coal. Based on this result, commenter concludes that EPA cannot assume fuel switching is available to those sources they have identified in Table 4 of their letter. [Letters: Wisconsin Department of Natural Resources (EPA

- HQ

- OAR

- 2009

- 0491

- 4824) p. 5]
RESPONSE : See response in section I.3(B) above regarding coal switching and SO 2 emission rate projec tions. Comment (E)(3) : WPL also found that the ultra

- low sulfur coal would cost significantly more than their current low sulfur coal. At least for the Nelson Dewey plant the fuel switch would cost close to $1000/ton of SO 2 reduced compared to the curr ent low sulfur coal currently under contract for that facility. This condition obviously exceeds EPA's threshold for applying fuel switching in 2012. This same cost issue is anticipated for other units currently firing low sulfur fuels. [Letters: Wisco nsin Department of Natural Resources (EPA

- HQ

- OAR

- 2009

- 0491

- 4824) p. 5]
RESPONSE : See response I.3(B) above regarding coal switching and SO 2 emission rate projections. Comment (E)(4) : A feasibility issue for using ultra

- low sulfur fuels is the potential impact to generation heat rates, particularly for small units. For example, the Valley power boilers are designed for high heat release fuels such as bituminous coals. The facility already burns a low sulfur bituminous coal at 0.76 lbs/mmBtu. Switching to a lower sulfur content likely means using a low sulfur subbituminous coal with significantly different heat release characteristics. Because of these identified issues WDNR requests EPA not apply fuel switching and use current SO 2 emission rates found in the CAMD database for the Columbia (pre

- scrubber), Edgewater, and Valley generation units. For generation units at Alma and Nelson Dewey a fuel switch to the low sulfur fuel currently available to each facility is appropriate under the $500/ton cost c eiling. Requested revisions are provided in Table 4 of the commenter's letter. [Letters: Wisconsin Department of Natural Resources (EPA

- HQ

- OAR

- 2009

- 0491

- 4824) p. 5

- 6]FIP Revisions

- RTC Febru ary 7 , 2012 Page 35

35 RESPONSE : First, EPA notes that ther e are no unit level requirements under the Tran sport Rule ; sources are free to comply how they best see fit. Furthermore, with the reductions expected from the Nelson Dewey and Alma fuel switch e s along with the reduced emissions from scrubbers at Genoa U nit 3 and South Oak Creek Facility, the total Wi sconsin SO 2 emissions will likely be below or at the state budget levels. This implies that no fuel switching or reductions may be needed from the remaining units mentioned above. The commenter seems to be interpreting the fuel switching observed in the TR

- Remedy file as a requirement to comply with the state budget. However, this remedy file actually shows Wisconsin outperforming their state budget, with some sources using additional fuel switching to “overcomply” with the state budget and bank allowanc es for future years. (F) EPA should adjust the Wisconsin budget to reflect requested corrections to unit
specific data and assumptions. Comment (F)(1) : The EPA budget corrections in the proposed rule increase SO 2 emissions in 2014 compared to the finali zed CSAPR emission budgets. The NO X emission budget increases in both 2012 and 2014. These budgets assume that the same corrections will be reflected in the ozone season NO X emission budgets. Commenter provides a summary table (Table 7) with the 2012 an d 2014 budgets for both SO 2 and NO X for the finalized CSAPR, the proposed rule, and with their requested corrections (as summarized in Tables 1 through 6). Commenter observes that after incorporating their additional corrections, the SO 2 emission budgets increase in both 2012 and 2014 when compared to EPA's proposed CSAPR budgets. For NO X the emission budget increases for 2012, but is the same as EPA's proposal for 2014. Commenter provides the unit

- by

- unit list of corrections and calculated emissions tha t they proposed as an attachment to their letter (Appendix A). [Letters: Wisconsin Department of Natural Resources (EPA

- HQ

OAR

- 2009

- 0491

- 4824) p. 7]
RESPONSE : EPA has reviewed the comments and final changes to the Wisconsin state budget can be found in the preamble to the final Revisions Rule. EPA notes that many of the commenter’s projections were simply estimates based on past performance of the units. While EPA modeling uses past data to inform its projections, it also relies on comprehensive mar ket and fuel parameters to predict how sources will react to future market and policy conditions. However, EPA does note that the state

- wide projections for Wisconsin are similar to the commenters own projections for most programs in most years. (G) Comm enter recommends that EPA follow a phased approach with respect to the emission budget for Wisconsin. Comment (G)(1) : The CSAPR sets the final emission budget level beginning in 2014. In the case where an additional SCR or scrubber beyond the committed units is identified by IPM remedy runs, EPA cannot reasonably apply the resulting emission reductions until sometime after 2014. Clearly, a sharply accelerated approval and installation schedule is necessary for any newly planned SCR or scrubber to apply before 2015. Further, as evidenced by WPL's Columbia dry scrubber project, even pollution control equipment approved prior to the finalizedFIP Revisions

- RTC Febru ary 7 , 2012 Page 36

36 CSAPR will not be operating until sometime in 2014. In both cases of committed or newly planned control equipment, the most appropriate approach is to incorporate emission reductions beginning in the first full year after operation begins. In addressing the Columbia plant, this approach means SO 2 scrubber reductions are first applied to a 2015 emissions budget and no t in 2014 as currently proposed. This "full year" concept holds true as well for any SCR and scrubber installation which is committed to occur before 2014 in determining CSAPR emission budgets. Commenter provides a table that summarizes their proposed ap proach for phasing in the Wisconsin emission budgets (see Table 8). [Letters: Wisconsin Department of Natural Resources (EPA

- HQ

- OAR

- 2009

- 0491

- 4824) p. 9]
RESPONSE : EPA disagrees with the above comment for two reasons. First, as s ection VII of the f in al Transport Rule p reamble discussed, EPA believes it is feasible to install a scrubber within 30 months. Moreover, completing a scrubber that has already been started (such as the Columbia FGD) within 30 months would be even more feasible. Second, even if the scrubbers were not installed until several months after the beginning of 2014, EPA believes the unit level emissions projected for that unit are a reasonable estimate of how that unit could be expected to emit in the year of the scrubber completion. This a much more reasonable projection than that suggested by commenter of presuming that the scrubber operated the whole year at normal load with no scrubber. Again, EPA reiterates that there are no unit level requirements under the Transport Rule, and many of the sources it projects to comply through control installation may never , in fact , install a scrubber, choosing an alternative compliance option instead. EPA even conducted sensitivity analysis assuming no FGD retrofits occurred in 2014, and foun d that states were still able to meet their 2014 SO 2 emission budgets. While EPA feels that it is highly reasonable to assume an early 2014 start date for these controls, it notes that it is not necessary for the state to comply with its assurance level. Comment (G)(2) : EPA should address appropriate fuel switching to ultra

- low sulfur coal in emission budgets after 2014. By 2015 and after more existing coal contracts will be expired or can potentially be amended. In determining the timing for this opti on EPA needs to clearly show the wide availability of ultralow sulfur fuel and account for coal contract conditions. The time frame also needs to avoid creating artificial market Conditions for ultra

- low sulfur coal in early years before control equipment is online. In any determination this fuel switching must still meet the CSAPR SO 2 cost

- effectiveness ceiling of $2,300/ton or other cost thresholds determined through reconsideration of the rule as applied to Wisconsin. Finally, fuel switching to ultra

- low sulfur coal should not be applied to generation units at any time that will be or have received scrubber controls. [Letters: Wisconsin Department of Natural Resources (EPA

- HQ

- OAR

- 2009

- 0491

- 4824) p. 9]
RESPONSE : See section 6.2(c) of this document , below, for information addressing SO 2 emission rates. Comment (G)(3) : Another factor EPA should consider in phasing requirements is that the same utilities responding to CSAPR emission budgets will be responding to EGU MACT requirements. Under MACT, u tilities will need to reduce emissions at all generating units andFIP Revisions

- RTC Febru ary 7 , 2012 Page 37

37 for different pollutants

— not just at those units which can most effectively meet CSAPR requirements. Because MACT is a unit

- by

- unit requirement, utilities may need to spread resources to smaller and additional units. Whereas under CSAPR utilities would focus installations to large generation sources to obtain the most cost

- effective and largest amount possible of emission reductions by 2014. These two rule compliance pathways seem to fi ght each other to some degree with regards to equipment installations. In fact, the IPM modeling supporting EPA's proposed MACT rule shows that equipment installations will likely be occurring for up to four years or at least through 2015. This analysis demonstrates that utilities will be faced with a complex set of installations and operational decisions for all units through both the initial CSAPR compliance years and into 2015. The utilities should be provided the time frame necessary to achieve both CSAPR and MACT using the most logical and cost

effective installation approach. [Letters: Wisconsin Department of Natural Resources (EPA

HQ

- OAR

- 2009

- 0491

- 4824) p. 9]
RESPONSE : EPA has demonstrated in both rulemakings that utilities will have adequate t ime to install whatever equipment is necessary to comply, taking into account all compliance flexibilities offered under each rule. EPA notes that the commenter has made no demonstration to the contrary

. (H) Comments on the Installation and Operation o f Controls, Fuel Blends, and Emission Rates at Units in Wisconsin.
Comment Columbia Units 1 and 2. Dry FGDs (DFGDs) are planned for both units for the spring of : Errors were made in the parsed files concerning when FGD will be operational at 2014. BC_P_12 correctly assumes that no FGD systems will be operational at Columbia Units 1 and 2 in 2012. In the BC_F_12, however, EPA erroneously includes a dispatchable WFGD system at each unit in 2012. Errors were made in the parsed files for when WFGD and SCR sys tems will be retrofit on Oak Creek Units 5

- 8. Under the terms of an enforceable consent decree, WFGD and SCR systems are planned to be operational at Oak Creek Unit 5 in December 2011 and at Units 6

- 8 in 2012. In BC_P_12 and BC_F_12, EPA erroneously failed to reflect that the WFGD/SCR systems on Units 5 and 6 would be operational in 2012. Errors were made in the parsed files concerning the installation and operation of SCR systems for Valley Units 1 and 2. No SCR retrofits are now planned for Valley in 201 2. In BC_F_12, however, EPA appears to assume erroneously that Valley will be operating SCR systems to reduce NO X emissions from the Valley units. Errors were made in the parsed files concerning installation and operation of SCR systems at the James Madge tt plant. Dairyland has indicated that it plans to install SCR at this plant after 2014. In RC_F_12, however, EPA erroneously assumes that SCR will be installed in 2012.FIP Revisions

- RTC Febru ary 7 , 2012 Page 38

38 Errors were made in the parsed files concerning the installation and operation of an FGD system for Weston Unit 3. The FGD project at Weston Unit 3 is now pending; no definite operational date has been determined. In BC_P_12, EPA correctly assumed that no FGD system would be operational in 2012. In BC_F_12, however, EPA erroneously assumes the existence of a dispatchable WFGD for Weston Unit 3 in 2012. Errors were also made in the parsed files concerning the SO 2 emission rate achievable at Weston Units 1

- 3. The actual SO 2 emission rate that those units achieved in 2010 was 0.56

- 0.57 lbs/ mmB tu . This emission rate is accurately reflected in BC_P_12. In BC_F_12, however, EPA increased the SO 2 rates for Weston Units 1

- 3 to 0.94 lbs/ mmBtu

. Errors were made in the parsed files concerning the blend of fuels for Alma Units 4 and 5. Alma Units 4 and 5 burn a blend of subbituminous/bituminous coal. In both BC_P_12 and BC_F_12, however, EPA erroneously assumes that both units are burning 100% subbituminous coal. Errors were made in the parsed files concerning the NO X rates achievable for Pulliam Units 5

- 8. Separated Overfire Air was installed on Pulliam Units 5

- 8 between 2007 and 2009. This is not reflected in BC_F_12. Errors were made in the parsed files concerning the SO 2 emission rates for Edgewater Units 3

- 5. In BC_F_12, EPA assumes SO 2 emission r ates will be higher than the units’ actual SO 2 emission rates for 2010. [Attachment to UARG comment letter, “J. Marchetti, J. E. Cichanowicz, Initial Identification of Unit Errors in Integrated Planning Model (IPM) Runs (Oct. 7, 2011)” (EPA

- HQ

- OAR

- 2009

- 049 1

- 4823) p. 52

- 53]
RESPONSE : Many of these assumption corrections were addressed in the preamble to this final rulemaking (see section IV.A.(7)). For those where no action was necessary, EPA has explained its reasoning for not making adjustments in its r esponse to Wisconsin stakeholder comments above. (I) Comments Relating to New Units in Wisconsin.
Comment 2011. Under the terms of CSAPR, both units should receive SO 2 allowance allocations from the new unit set

- aside pool. In the final rule, however, EPA erroneously gives Elm : Errors were made in the parsed files for Elm Road Units 1 and 2. Unit 1 began commercial operation in February 2010; Unit 2 began commercial operat ion in February

Road Unit 1 allowances from the main allocation pool instead of from the new unit set

- aside pool. Errors were made in the parsed files for the DTE Stoneman facility, which

– after undergoing new source review

– was repowered in 2010 to use 100% wood biomass renewable fuel. Because the repowered facility began operation af ter January 1, 2010, it should receive substantiallyFIP Revisions

- RTC Febru ary 7 , 2012 Page 39

39 higher SO 2 and NO X allowance allocations from the new unit set

- aside pool. In the final rule, however, EPA erroneously gives the repowered facility allowances from the main allocation pool instead of fro m the new unit set

- aside pool. [Attachment to UARG comment letter, “J. Marchetti, J. E. Cichanowicz, Initial Identification of Unit Errors in Integrated Planning Model (IPM) Runs (Oct. 7, 2011)” (EPA

- HQ

- OAR

- 2009

- 0491

- 4823) p. 53]
RESPONSE : Regarding Elm Road Unit 1, the unit was reported to EPA as starting operation on July 23, 2009 and reported emissions data for that year . T herefore , EPA classified it as an existing unit. EPA treated unit 2 as a new unit as noted by the commenter. Regarding DTE Stone man, changes to the allocation methodology based on repowering and heat input are out side the scope of the revisions proposed and upon which EPA solicited comment . See Section 6.5 , below, of this document for more information. Issue 1.5: New Jersey Mode ling Assumptions
Points Raised: (A) Supports technical corrections proposed for the New Jersey state budget. Comment (A)(1) : In terms of the technical corrections proposed for the New Jersey state budget in general, commenter (PSEG) supports EPA's prop osal to correct the integrated planning model assumptions regarding the installation of pollution control systems for B.L. England Unit 1. As observed in the proposed revisions to the Transport rule, the controls of B.L. England Unit 1 are not actually re quired by New Jersey administrative order until December 2013. Commenter supports EPA's proposal to correct for out of merit dispatch at certain generating facilities in northern New Jersey. This region of the state is located within load pocket, an area where transmission constraints require the dispatch of local generating units, to maintain reliability and voltage support. Also, electric generating facilities in New Jersey support the wielding of power from upstate New York through northern New Jersey into New York City, again requiring out of merit dispatch. These dynamics, which are unique to the region, and make it particularly challenging to develop a reliable forecast of individual unit dispatch decisions. [Letters: Public Service Enterprise Gr oup (PSEG) (EPA

- HQ

- OAR

- 2009

- 0491

- 9003) p. 32

- 33]
RESPONSE : EPA generally agrees with PSEG’s comment. See section IV.A.(6 ) of the preamble to this final Revisions Rule. Comment (A)(2) : While supporting the corrections generally, it appears EPA may hav e underestimated the emissions rate of the B.L. England 1 in accounting for the implications of the installation of the controls contemplated by the order. Specifically, in calculating the revised emission rates for B.L. England Unit 1, EPA has assumed an average SO 2 emissions rate of 2.19 lbs/mmBtu; however, the unit reports to the Clean Air Markets Program database an average SO 2 emissions rate of 2.45 lbs/mmBtu. PSEG respectfully requests that EPA review the emissions rate it used in revising the alloc ation to the sources under the proposed revisions to the TransportFIP Revisions

- RTC Febru ary 7 , 2012 Page 40

40 Rule, and make an adjustment to the proposed allocation if warranted. [Letters: Public Service Enterprise Group (PSEG) (EPA

- HQ

- OAR

- 2009

- 0491

- 4793) p. 3

- 4]
RESPONSE : EPA used an emission rate consistent with the methodology described in the IPM documentation (see the IPM Documentation for the Final Transport Rule; EPA

- HQ

- OAR

- 2009

- 0491

- 4294). There are several reasons why this rate may be different from historic performance, including use of different coal types. For more information, see EPA’s response to comments pertaining to emission rate changes in section 6.2c , below, of this document. (B) Disagrees with EPA’s approach for out
- of
- merit dispatch and off
- setting generation.
Commen t (B)(1) : Commenter (PSEG) agrees with EPA's proposal to correct state allowance allocations based on out

- of

- merit

- dispatch at certain generating facilities in Northern New Jersey, but disagrees with the methodology proposed by EPA to accomplish this corr ection. In offsetting the generation reflected by out

- of

- merit

- order dispatch, EPA has failed to make an appropriate budget adjustment. Northern New Jersey is located within a load

- pocket, an area where transmission constraints often require the dispatch of local generating units to maintain reliability and voltage support. Also, electric generating facilities in New Jersey support the wheeling of power from upstate New York through Northern New Jersey into New York City, again, requiring out

- of

- merit di spatch. These dynamics, which are unique to the region, make it particularly challenging to develop a reliable forecast of individual unit dispatch decisions. PSEG believes these non

economic factors are causing EPA's IPM model to underestimate the utili zation of power plants in Northern New Jersey. A Table 1 is provided that compares the 2010 actual heat input of several power plants in Northern New Jersey with the 2012 projected heat input from the final rule used in calculating the New Jersey state bu dgets. A review of that table reveals that Bergen's projected heat input, for example, is 85 percent below actual 2010 levels. Overall, projected heat input is almost 80 percent below actual 2011 levels. Based on these comparisons, EPA has underestimate d the utilization of generating facilities in Northern New Jersey, and as a result, set an emissions budget that will likely be insufficient to meet the operational needs of generators within the state. The technical correction that EPA proposes adjusting for out

- of

- merit

- dispatch results in a more reasonable estimate of heat input for the six generating facilities. As summarized in Table 2, the revised heat input projection, after adjusting for out

- of

- merit

- dispatch, is 14 percent below actual 2010 level s. This is an improvement over the prior projection; however, after making this adjustment, EPA goes on to assume that the increase in generation reflecting out

- of

- merit

- order dispatch would be offset by decreasing generation at New Jersey combined cycle units. As a result, although EPA proposes to initially add 887 tons to the New Jersey annual NO X budget, EPA then proposes to subtract 775 tons for a net increase of only 112 tons to account for out

- of

merit

- dispatch. We disagree with this proposed metho dology.FIP Revisions

- RTC Febru ary 7 , 2012 Page 41

41 EPA can avoid this inappropriate disparity between projected heat input and projected generation and the values reflected in the allowance allocation under the final rule by eliminating any offset to projected heat input and generation at other Ne w Jersey affected sources. EPA already recognizes that New Jersey is a state that includes a significant load pocket. As such, EPA correctly proposes to upwardly adjust generation at certain units within the state, which would result in increased emissio n allowance allocations to the state. In correcting for load pockets, EPA recognizes that in certain limited instances the IPM model did not consider a unique aspect of a particular generator's operation or the operational constraints that may exist in a particular geographical area. To be perfectly clear, PSEG supports EPA's use of the IPM model and believes that overall EPA got it right. But, in certain instances such as this one, there are limitations that are inherent to any economic forecasting mode l in accounting for activity that does not, on the surface, appear to be economically rational. However, once it is accepted that IPM did not "see" this particular load pocket, this also suggests that total net generation within the state as forecast by I PM was underestimated. Accordingly, it is overly simplistic to suggest that an increase in generation at one New Jersey unit will offset generation at another New Jersey unit on a 1

- to

- 1 basis. Given that New Jersey is a small state, that the IPM did not see the load pocket within the state, and the fact that IPM forecasts a significant decline in overall net generation within the state versus historical levels, the only logical conclusion is that IPM is overestimating electricity imports into New Jersey. As such, the generation from units that ran for reliability purposes with other in

- state units should not be offset through the proposed revisions to the Transport Rule. Or, at a minimum, EPA should take into account the historical data and allow for an overall increase in generation to 2010 levels before considering any offsetting generation that would take back allowance allocations. The IPM’s projections of both heat input and generation at New Jersey’s fossil

- fired units are up to 21 percent below t heir reported 2010 levels. The technical corrections proposed by EPA, after offset adjustments, do almost nothing to correct these differences. However, if EPA removes the deductions made to offset increases associated with out

- of

- merit

- order dispatch of units at the six plants, it would bring the projected totals for New Jersey much closer to their actual 2010 levels. Therefore, EPA should further modify the Transport Rule by increasing the projected output of units at the six plants, which are needed f or reliability, without making a one

- for

- one downward adjustment in the utilization of an in

- state hypothetical natural gas combined

- cycle facility. [Letters: Public Service Enterprise Group (PSEG) (EPA

- HQ

- OAR

- 2009

- 0491

- 4793) p. 4

- 7]
RESPONSE : See sect ion 6.1b of this document, below, for EPA’s description and rationale for the offsetting methodology. EPA notes that it revised the offsetting methodology, as described in the p reamble of the f inal Revisions Rule , which excluded cogeneration units from be ing available for offsetting. This had the impact of decreasing the emissions at offsetting units, which resulted in a larger overall revision to New Jersey’s budgets. For EPA’s response to comments comparing IPM’s heat input to state

- level historic heat input, see section 6.3 , below, of this document.FIP Revisions

- RTC Febru ary 7 , 2012 Page 42

42 Issue 1.6: New York Modeling Assumptions
Points Raised: (A) The allocations erroneously overlooked data for Astoria units from prior to 2009. Comment (A)(1) : The underlying data used to determine the final allocations erroneously overlooked data prior to 2009 for Astoria Generating Station Units 30, 40 and 50 (AGS Units). The root cause of this error was a change in reporting methodology which is detailed below. The AGS Units did, in fact, have subst antial heat input and emissions from 2006

- 2008. The omission of this data has significantly and inappropriately reduced the final allocations provided to these specific units to levels materially below historical emissions. The allocation methodology use s a 5

- year baseline to approximate a unit's normal operating conditions. Reporting changes documented on the CAMD Business System (CBS)' eliminated the heat input and emissions look back for data prior to 2009 in the EPA unit allocation tables, not becaus e the units did not operate, but because they were reported using a different methodology. Previous data utilized by EPA in the initial rulemaking correctly captured the baseline year data for the AGS Units. However, in modeling and data preparation for the final rule, the EPA utilized a different database referenced above which omitted all of the reference data for the baseline years of 2006 through 2008. Commenter notes that the accurate heat input and emissions data for AGS Units for years 2006, 2007, and 2008 were obtained from EPA's Clean Air Markets

- Data and Maps website and provides these data in attached tables. [Letters: Astoria Generating Company (AGC) (EPA

- HQ

- OAR

- 2009

- 0491

- 4758) p. 1

- 2]
RESPONSE : EPA issued a N otice of Data Availability ( NODA) on January 7, 2011 that had the listed heat input for each unit’s baseline years. EPA took comment on these values and incorporated relevant comments regarding corrected heat input values or corrections due to reporting changes into the final Transp ort Rule issued in July of 2011. Astoria Generating Company did not submit the above data at that time, so no changes were made to its values shown in the January NODA. Moreover, the State of New York has the flexibility to allocate allowances as it best sees fit (incorporating or not incorporating the above data) under its State Implementation Plan (SIP). (B) EPA over
- controlled the units at NRG's Huntley and Dunkirk facilities and at Danskammer units 3 and 4 in the modeled remedy case; this error needs to be corrected and the New York budget should be adjusted accordingly. Comment (B)(1) : The range of control efficiencies in EPA's model results indicate a range of 65% to 92% reductions in SO 2 from these units from 2012 base case to 2014 remedy case. Bas ed on information and case study results presented by NRG, commenter (NY DEC) believes that the Huntley and Dunkirk units can realize an SO 2 reduction of approximately 50% when using the Trona and powder

- activated carbon (PAC) injection system that is curr ently installed on those units. NRG has completed a performance test indicating that these technologies reduce emissions of SO 2 by over 55% This test was done when the units were newly installed underFIP Revisions

- RTC Febru ary 7 , 2012 Page 43

43 more ideal conditions, and a conservative estimate of 50% reduction would be a sustainable average over the long term operation of this equipment. Commenter provides additional information related to the case and the supporting presentation in an attachment to their letter. [Letters: New York State Depart ment of Environmental Conservation (EPA

- HQ

- OAR

- 2009

- 0491

- 4788) p. 2]
RESPONSE : EPA intends to increase New York’s 2012 and 2014 annual SO 2 , annual NO X , and ozone
- season NO X budgets , in a separate action, based on comments received on the revisions rule d emonstrating that the East River plant is in an out

- of

- merit

- order dispatch area with conditions likely to necessitate what would otherwise be non

- economic generation

. See Final Revisions Rule State Budgets and New Unit Set

- Asides TSD in the docket to thi s rulemaking. EPA re

- calculated the emissions from this facility with out

- of

- merit

- order dispatch to reflect the input assumption changes. These calculations yield increases to New York’s 2012 and 2014 state budgets for annual SO 2 , annual NO X , and ozone

- season NO X . Commenters also identified two facilities, Dunkirk and Huntley, with existing dry sorbent injection (DSI) technology for which EPA had assumed an SO 2 removal rate of 70 percent but which actually achieves a removal rate of only 53 percent. EPA recalculated the projected emissions for these units based on this revised assumption and is increasing the New York 2012 and 2014 SO 2 budgets accordingly. Comment (B)(2) : Danskammer units 3 and 4 are configured and operated in a manner similar to Huntley and Dunkirk. As part of the plant's strategy to comply with regional haze requirements in 2014, Unit 4 has committed to a BART rate of 0.5 lb SO 2 /mmBtu when co

- firing natural gas with the coal already utilized. Unit 3 is also capable of meeting t he same SO 2 rate. This represents a reduction of approximately 45% from EPA's 2012 base case. The BART analysis determined the cost for these controls to be similar to the cost thresholds used to determine the 2014 SO 2 budgets. It appears that these two units have been incorrectly retrofitted with scrubbers in the 2014 remedy case. The installation of scrubbers is not planned for these units and is unlikely to be consistent with EPA's cost

- effectiveness threshold. If the control level adjustments for t hese units (and the Huntley and Dunkirk units) are incorporated, New York's budget would increase by 5,851 tons SO 2 in 2012 and 8,064 tons SO 2 in 2014. This is appropriate and realistically achievable with the emission controls available/in place at these facilities. Commenter provides a spreadsheet entitled "Summary of NY SO 2 Changes" as an attachment to their letter. [Letters: New York State Department of Environmental Conservation (EPA

- HQ

- OAR

- 2009

- 0491

- 4788) p. 2]
RESPONSE : EPA did not assume advan ced pollution controls at these units as a modeling input. Our economic modeling did suggest that the units would be likely candidates for retrofits in the 2014 TR_Remedy_Final scenario where sources in New York are part of the Transport Rule Group 1 regi on and have a higher economic incentive to reduce their SO 2 emissions to meet the state emission budgets for that year. In this scenario, the Danskammer facilities are part of the nearly 6 GW of projected FGD and 3 GW of projected DSI that EPA anticipate s in response to the SO 2 emission limitations in 2014. However, as EPA noted in the final Transport Rule,FIP Revisions

- RTC Febru ary 7 , 2012 Page 44

44 these particular controls are illustrative unit

- level results from the disaggregation of modeled projections of least

- cost compliance with state budg ets; they do not establish any unit level requirements. There are a variety of compliance options available to sources to lower their emissions as part of the effort to meet a state emission limit. EPA fully expects that some sources will chose complianc e mechanisms other than those modeled by EPA. In fact, EPA even performed a sensitivity in its final Transport Rule analysis (TR_No_FGD_in2014_Scenario_Final) that presumed no FGD were built in 2014. The sources and states were still able to comply with the Transport Rule even in this scenario where no new FGD were assumed to be installed in response to the Transport Rule . Therefore, there is no expectation or requirement that the specific units noted above by the commenter should install any such pollut ion control. (C) EPA should make additional corrections to the proposed rule to account for the required operation of East River cogeneration units. Comment (C)(1) : Con Edison urges EPA to adjust the New York state emissions budgets to account for generati on at its four East River units. EPA is proposing to adjust the New York budgets for SO 2 , annual NO X , and ozone season NO X to take account of operational constraints that necessitate non

- economic generation at ten units in New York. The East River units are subject to similar constraints and must operate to meet demand for steam and electricity in New York City. Inexplicably, EPA failed to include the East River Power Plant units in the list of plants impacted by operational constraints. The list includ es Arthur Kill, Ravenswood, and Astoria units. Unlike these units the East River Power Plant supplies both electricity and steam in Manhattan. The East River Plant is no less critical to the reliability of the electrical system than the units at the list ed plants, and is a fundamental part of the district steam system on a year

- round basis. The IPM predicts zero fuel use for Units 60 and 70 despite the need for electricity and steam from these units and predicts far less fuels use for Units 1 and 2 than necessary for reliability purposes. Con Ed provides a table comparing the average of the three highest years of fuel use for each unit to that predicted by IPM. The total shortfall is about 26 million mmBtu. The errors appear to be due to IPM treating t hese as only electric generating units. In addition IPM uses a much higher SO 2 emission rate for Units 60 and 70 (0.6 lb/mmBtu). Con Ed informed EPA that the proper emission rate was 0.31 lb/mmBtu on oil and 0.0006 lb/mmBtu when burning natural gas. The units burn gas more than 90 percent of the time. EPA should recalculate the proposed emissions budgets and include appropriate heat input for the East River Units. Con Edison proposes that EPA utilize the average of the three highest heat input values f or 2006 through 2010 to represent the level of heat input necessary to meet steam and electric reliability requirements. Heat input should be used instead of heat rate, capacity, and capacity factors to account for the cogeneration status of the units. T his approach also has the benefit of being the same methodology that EPA used to calculate the pro

- rata share of heat inputFIP Revisions

- RTC Febru ary 7 , 2012 Page 45

45 on a statewide basis for budget allocation. Calculations provided in Table 1 of the comments indicate that an additional 107 SO 2 al lowances, 895 annual NO X allowances, and 465 ozone season NO X allowances should be added to the New York emissions budgets.
EPA should not deduct emissions from other units to offset the East River Power Plant heat input. IPM does not account for the ste am provided by cogeneration units, so there is no other "output" that must be balanced against the tons associated with the East River output. EPA's model already significantly underestimated the total heat input needed to provide electric and steam servi ce in New York. [Letters: Consolidated Edison Co. (EPA

- HQ

- OAR

- 2009

- 0491

- 4761) p. 4

- 6]
RESPONSE : EPA has made adjustments to the New York budgets to reflect this comment. See Final Revisions Rule State Budgets and New Unit Set

- Asides TSD. (D) Supports th e proposed revisions with minor additional corrections. Comment (D)(1) : National Grid supports the proposed revisions to the New York budget. EPA has properly adjusted the budget to account for the expected generation from the Long Island and New York C ity units. National Grid will be supporting comments from the Environmental Energy Alliance of New York which recommends some minor budget adjustments to more closely represent emission trends including reductions that have already been made. [Letters: National Grid (EPA

- HQ

- OAR

- 2009

- 0491

- 4809) p. 1]
RESPONSE : See response to Environmental Energy Alliance of New York 1.6(E)(1) below. (E) Further revisions to the New York budgets are required due to EPA's overestimation of cost effective emission control o n New York coal
- fired units. Comment (E)(1) : EEANY appreciates the allowance budget changes included in the October 14 revisions and acknowledges that EPA has made good forward progress in adjusting the NYS Budgets by adding emissions associated with the load and reliability constraints in the New York metropolitan area, including Long Island. However, there is a second step that needs to be taken; namely, the real

- life capability of the control equipment at the State’s large coal plants must be ascribed to those units and the emissions from those sources recalculated. EEANY supports the DEC’s proposed additional allowance budget adjustments because they correct specific instances where the control technology assumptions in IPM were incorrect. However, EEANY recommends further revisions to the NYS Budgets and the budget suggested by the DEC because the IPM estimated emission rates are lower than can be expected for “highly cost effective” reductions based on data not apparent in the modeling data.
The c urrent EPA allocations are, for the most part, lower than what can be reasonably expected because the generic model assumptions over estimate what additional cost

- effective controls are possible at New York units. In order to incorporate site specific con straints it is more appropriate to account for the fact that New York units are implementing control strategies thatFIP Revisions

- RTC Febru ary 7 , 2012 Page 46

46 are cost

- effective to meet the recently revised NO X RACT rules, BART requirements and expected DEC rule

- making that would reduce sulfur

- in

- oil fuel limits to 0.5% sulfur to the extent possible with existing technology and other constraints. The resulting emission rates are called “reasonable” in these comments because further reductions for the CSAPR highly cost effective control cost conser vatively set at $2,300 per ton are unlikely because those programs determined what reasonably available controls were possible at a rate of $5,500 per ton.
The NO X “reasonable” emission rates used the following general assumptions. New York’s revised NO X RACT emission rates are 0.12 for coal

- fired boilers and 0.15 for oil/gas steam boilers are effective in 2014. The minimum annual average NO X emission rate for the last five years was calculated. If the minimum rate was greater than the NO X RACT limit th en the NO X RACT limit was defined as the reasonable rate; otherwise the minimum rate observed was defined as the reasonable rate for these calculations. However, there will likely be units that apply for presumptive alternate NO X RACT rates because even a t the higher $5,500 per ton control costs no reasonably available controls are possible. For example, it is likely that NRG Oswego will apply for alternate rates equal to the minimum rate measured over the last five years. Also note for the purposes of t he budget analysis we have assumed that all units with existing post combustion controls can likely meet the 2014 limit in 2012 and unless otherwise noted the remaining units are assumed to meet the limit in 2014. Furthermore, the NO X rates for the coal

- s team category do not reflect limitations of the SCR technology at AES Somerset and Cayuga, which currently operate as load following units and startup and shutdown much more frequently than in the past. A reasonable allocation must take into account start up, shutdown and non

- SCR operating emissions when the control technology is not available based on vendor recommendations. Load following and cycling of the units during on
- peak and off

- peak periods requires the SCR to be taken out of service to avoid dam age to equipment. Minimum flue gas operating temperatures are required to prevent fouling of the SCR catalyst and downstream equipment, especially air preheaters. Further, as more intermittent assets are introduced to the electric energy grid, the need f or rapid ramp rates and flexible minimum/maximum operating levels on existing base load facilities will become more important to supplement intermittent resources and to maintain system reliability. Based upon the average actual emissions of the last seve ral years that reflect those operating conditions, EEANY proposes an allocation based upon expected unit

- specific alternative NO X RACT emission rates of 0.24 lb. NO X per mmBtu for Somerset, Cayuga 1

– 0.20 and Cayuga 2

– 0.38. The following general assump tions were used to estimate "reasonable" SO 2 emission rates. For units where the minimum SO 2 rate measured over the last five years was less than 0.5 lbs SO 2 per mmBtu, the minimum rate was used. For the remaining sources it is assumed that NY EGUs scoped additional pollution control equipment or operation at coal

- fired power plants to be able to reduce emissions to an equivalent 0.5 lbs. SO 2 per mmBtu in 2014. That assumption is supported because Danskammer recently revised its Title V permit to meet 0.5 as part of its BART commitments. Dunkirk and Huntley have dry sorbent injection technology available that can reduce the SO 2 rate 50% below the 0.8 lbs. SO 2 per mmBtu coal currently purchased. There was a limitation assumed for facilities with FGD techn ology. The limit should not be set lowerFIP Revisions

- RTC Febru ary 7 , 2012 Page 47

47 than 0.20 lb. /mmBtu which is the emission rate proposed in the Utility MACT and is set at the level of the best performing 12% of the generating fleet. One additional aspect of this approach to calculating "reaso nable" emission rates should be kept in mind for the coal

- fired units. Using the minimum rate over the last five years for these calculations assumes that coal with the sulfur content seen in the last five years will still be available and/or cost effecti ve. Because there has been so little pressure on sulfur allowance prices, coal suppliers have provided coal without concern about the sulfur content. That will change when CSAPR is implemented. For example, Dunkirk and Huntley purchase 0.8 lb. SO 2 per m mBtu coal but the observed rates have consistently been below 0.6. With the CSAPR budgets in place low sulfur fuel will command a premium and it is inappropriate to assume that coal with the historical low rates will be cost

- effective.
The reasonable bud gets for NO X increase the New York allocations over the proposed revised budget by 1,991 tons for the annual program and 869 tons for the ozone season. The reasonable 2012 SO 2 budget is higher than the proposed revised budget by 6,144 tons and the reasona ble 2014 SO 2 budget is higher than the proposed revised budget by 11,976 tons. A table is provided with a comparison of the commenter's proposed budget and EPA's proposed budget. An attachment provides individual unit changes. [Letters: Environmental E nergy Alliance of New York (EEANY) (EPA

- HQ

- OAR

- 2009

- 0491

- 4811) p. 4

- 7]
RESPONSE

. : EPA has made the adjustments at the NRG Huntley and Dunkirk facilities to reflect the comments of the New York DEQ that are also referenced in this comment. However, EPA ha s not made the various other general adjustments referenced in this comment. These requested changes are outside the scope of this revisions rule because they constitute a proposal for an entire alternate approach outside the scope of the proposed rule. See sections 6.1b and 6.1c of this document, below, for further information

.FIP Revisions

- RTC Febru ary 7 , 2012 Page 48

48 Issue 1.7: Texas Modeling Assumptions
Points Raised: (A) Supports the proposed corrections to the Texas emissions budgets. Comment (A)(1) : CPS Energy appreciates EPA;'s eff orts to correct its assumptions and revise its Texas emissions budget to reflect the proper application of EPA's methodology established in the final CSAPR, and the underlying assumptions about several CPS Energy units in particular. CPS Energy urges EPA to finalize the proposed corrections before the end of the current year to provide certainty as CPS Energy plans for compliance in the upcoming year. [Letters: CPS Energy (EPA

- HQ

- OAR

- 2009

- 0491

- 4784) p. 1]
RESPONSE : EPA worked quickly to review comments and finalize appropriate adjustments to provide certainty to regulated entities. (B) EPA should confirm that previously requested corrections to Texas' point source NO X emissions have been addressed. Comment (B)(1) : TCEQ in its hearing testimony notes that at proposal, EPA only sought comment on a hypothetical scenario involving increased SO 2 emissions due to Texas switching to higher sulfur coals, not an actual linkage by Texas to a specific monitor. While Texas did point out some flaws in EPA's integ rated planning model data in comments on the original proposal, it is EPA's own mistakes and incorrect assumptions that caused the errors in EPA's SO 2 emission rates from electric generating units in Texas. The EPA made numerous revisions to the emissions inventories and modeling during the original CSAPR rulemaking, which were not clearly explained in the final rule preamble or technical support documents. Texas has still not been able to confirm that EPA has made the requested corrections to the state's point source NO X emissions based on the federally enforceable control measures that are a part of the state implementation plan. This correction is crucial to recognize emission reduction efforts in Texas, and base any modeling and linkage decisions on a ccurate emissions. [Letters: Texas Commission on Environmental Quality (EPA

- HQ

- OAR

- 2009

- 0491

- 9002) p. 21

- 23]
RESPONSE : EPA notes that the revised assumptions in SO 2 emission rates at certain Texas EGUs at issue in this revisions rulemaking would actual ly yield increased projected SO 2 emissions from Texas compared to the analysis conducted in the final Transport Rule showing that Texas significantly contributes to downwind nonattainment of the PM 2.5 NAAQS. In other words, insofar as these “errors” may h ave previously affected the final Transport Rule analysis, they would have resulted in an underestimate of base case Texas emissions; therefore, EPA sustains its conclusion that Texas meets the criteria for inclusion in the annual Transport Rule programs. In regards to NO X rates imposed at the state level, page 72 of the “EPA Documentation Supplement for EPA Base Case v.4.10_FTransport

- Updates for Final Transport Rule” is the section that shows state electric power emission regulations. These include NO X rates for Eastern Texas, Dallas

- Ft. Worth area, and Houston/Galveston.FIP Revisions

- RTC Febru ary 7 , 2012 Page 49

49 Comment (B)(2) : EPA is still significantly over

- predicting point source NO X emissions for Texas in 2012 and 2014 by at least 70,000 tons per year which can lead to faulty conclusion s by the EPA concerning Texas' potential impact on other states. The TCEQ has made multiple attempts in comments on the prior rulemaking and the subsequent NODAs to correct the EPA’s flawed projections on point source NO X emissions in Texas. The TCEQ has even sent complete modeling files for the Houston

- Galveston

- Brazoria (HGB) and Dallas

- Fort Worth (DFW) ozone nonattainment areas to the EPA (Bruce Mason) with the projected NO X emissions from federally enforceable controls measures such as the NO X Mass Emi ssion Cap and Trade (MECT) Program and Chapter 117 rules in DFW. These state control strategies are approved by the EPA as part of the state implementation plan but the EPA is not properly accounting for these federally enforceable control measures in the CSAPR modeling. In the Response to Comments document of the final CSAPR, the EPA indicated that it had made the corrections requested by the TCEQ to incorporate the EPA approved SIP control measures. The TCEQ has been unable to confirm that the EPA has mad e the corrections as was indicated in the Response to Comments. However, the EPA’s projected non

- EGUs point source NO X emissions for 2012 in the final rule are 72,500 tons greater, almost 38%, than the actual 2009 non

- EGUs point source NO X emissions invent ory for Texas. Commenter provides additional discussion and a graph entitled “Texas Point Source Non

- EGU Annual NO X Emission Inventory Trends” to support their point on this issue. [Letters: Texas Commission on Environmental Quality (EPA

- HQ

- OAR

- 2009

- 049 1

- 4782) p. 2 (cvr), p. 12

- 13]
RESPONSE : Annual and ozone

- season NO X EGU emissions projected in EPA’s 2012 base case are less than the emissions actually observed in the most recent year for which there is full data (2010). Although the 2012 base case is not designed to simply reflect the 2010, or other recent year emissions, the fact that EPA’s 2012 base case EGU emission projections for a non

- CAIR scenario are even less than observed in recent history suggest s a conservative prediction (i.e., one that i s more likely to be an under

- prediction that understates the strength of the Texas's contribution linkage to other states, rather than over

- predicting as suggested by the commenter). See Section V of the Final Transport Rule preamble for a discussion of t he air quality and contribution analysis. Furthermore, Chapter 101 and 117 regulations for areas like Dallas

- Fort Worth and Houston

- Galveston (such as the MECT mentioned above) are included in EPA’s modeling and identified in the IPM documentation.
In re sponse to comments on the CSAPR proposal, EPA receiv ed numerous updates to emission inventory data that was used in the CSAPR modeling. EPA incorporated the updated data into the final rule modeling, wherever possible. Among the emission updates received were those from TCEQ. The EPA received ozone season NO X emissions from Texas related to the MECT Program. Upon receipt, the data were re

- formatted and units converted to annual tons prior to its inclusion in EPA’s final rule modeling inventories for 201 2 and 2014. The NO X emissions in the final CSAPR emission inventories match the annualized emission data provided by TCEQ for the specified MECT program stacks. Also, numerous Texas consent decrees were included in the final rule modeling, along with upd ated cement kiln projected emissions for 2012 and 2014. The cumulative impact of these adjustments resulted in 27,000 tons less non

- EGU NO X in TexasFIP Revisions

- RTC Febru ary 7 , 2012 Page 50

50 in 2012 compared to the 2005 CSAPR base case. In addition, annual and ozone

- season NO X EGU emissions proje cted in EPA’s 2012 base case are less than the emissions actually observed in the most recent year for which there is full data (2010). Chapter 101 and 117 regulations for areas like Dallas

- Fort Worth and Houston

- Galveston (such as the MECT mentioned abov e) are included in EPA’s modeling and identified in the IPM documentation. Based on the level of detail of the emission information submitted by TCEQ, it is not possible to fully understand why their emission estimates appear to differ from those modeled by EPA in the final CSAPR rule. But EPA provided detailed information on the 2005, 2012, and 2014 emission inventories during the proposal process and also as part of a NODA. Texas, along with all affected states, had the opportunity to provide alternati ve values for the inventoried sources multiple times during the rule

- making process. Specifically, an emission summary spreadsheet for non

- EGU emission sources larger than 100 tons per year in 2005, 2012, and 2014 was placed in the docke t with the title , “Revised

- Spreadsheet for Sending Future

- Year Emissions Comments for Stationary NonEGU Sources” [EPA

- HQ

- OAR

- 2009

- 0491

- 2525]. Texas could have provided alternate emission data in this spreadsheet for sources in 2005, 2012, or 2014, but no such revisions w ere provided, nor were any complete alternative emission inventories provided. Other states successfully provided comments and revised 2005, 2012 , and/or 2014 emissions using this spreadsheet. The proposal and final emission inventories used for modeling were provided in the docket as EPA

- HQ

- OAR

- 2009

- 0491

- 0059 and EPA

- HQ

- OAR

- 2009

- 0491

- 4228, respectively. These were also provided on EPA’s emissions modeling clearing house web site http://www.epa.go v/ttn/chief/emch/index.html for easier access. Comment (B)(3) : The docket and the EPA’s CSAPR web site do include data files with the 2012 and 2014 projections (identified in the Docket as EPA Docket ID EPA

- HQ

- OAR

- 2009

- 0491

- 4523 and EPA

- HQ

- OAR

- 2009

- 049 1

- 4523). However, these data files appear to only include various adjustments to the future case projected emissions at a site

- wide level and not the total point source emissions inventories. The TCEQ cannot identify the errors in the EPA’s projections wit hout the entire point source data that the EPA is using for the CSAPR modeling being made available. The TCEQ requests that the EPA provide or identify in the docket the specific file or files that contain the total point source NOX emissions inventory for Texas and provide additional opportunity and time for comment via a NODA on the full NOX emissions inventories that the EPA is using for CSAPR modeling

. [Letters: Texas Commission on Environmental Qua lity (EPA

- HQ

- OAR

- 2009

- 0491

- 4782) ]
RESPONSE : The EPA did provide all of the complete emission inventories used in modeling in their entirety in the docket for proposal and final modeling as EPA

- HQ

- OAR

- 2009

- 0491

- 0059 and EPA

- HQ

- OAR

- 2009

- 0491

- 4228, respectively. The inventories were also provided on the emiss ions modeling clearinghouse web

- site: http://www.epa.gov/ttn/chief/emch/index.html . The docket entries that the commenter references are , indeed , only the adjustments made to non

- EGU point sources, but the full data was docketed in another submission. (C) Commenters support the adjustments to the Texas emissions budgets in the Proposal but maintain that they are not sufficient.FIP Revisions

- RTC Febru ary 7 , 2012 Page 51

51 Comment (C)(1) : EPA should adjust the Texas emissions budgets to acc ount for several "must

run" plants requiring non

- economic dispatch on the SPS System. Given the remote location of the SPS system within the Southwest Power Pool, several "out

- of

- merit

- order" or "must

- run" units exist within the SPS system. Commenter pro vides their analysis of the "must

- run" plants on the SPS system as an attachment to their comment letter (Exhibit C) and adds that none of these plants were considered "must

- run" in the modeling EPA conducted under CSAPR. Tables 1, 2.a, and 2.b of Exhibit C identify those units and show their impact on the Texas statewide emissions budgets. SPS urges EPA to include the increased emissions from the units in Tables 2.a and 2.b of Exhibit C in its revisions to the Texas emissions budgets to account for their "must

- run" status. Moreover, in the methodology set forth in the Technical Revision TSD for dealing with out

- of

- merit

- order dispatch under CSAPR, EPA "assume[d] that the additional generation dispatched from [out

- of

- merit

- order] facilities would offset g eneration that would otherwise come from combined cycle units within the state" (see Technical Revision TSD at 46). Because of the unique configuration of the SPS electric system, EPA should not apply a similar assumption to the SPS "must

- run" units descr ibed in Exhibit C, Tables 2.a and 2.b. [Letters: Southwestern Public Service Company (SPS) (EPA

- HQ

- OAR

- 2009

- 0491

- 4752) p. 5]
RESPONSE : EPA reviewed SPS’s comments regarding the units it identified as needing to run out

- of

- merit

- order and plans to revis e the ozone

- season Texas emissions budgets based on information that meets requirements described in proposed revisions [76 FR 63868]. Our rationale for those revisions will be fully explained in that action . See the Final Revisions Rule State Budgets a nd New Unit Set

- Asides TSD in the docket to this rulemaking

. Comment (C)(2) : Commenter (TCEQ) appreciates EPA's efforts in working with companies to correct errors regarding EGUs with SO 2 FGD scrubbers. However, the proposed additional 70,067 tons of SO 2 allowances for the Texas SO 2 emissions budget do not address the TCEQ's concerns regarding the feasibility of such substantial reductions in SO 2 emissions in an unprecedented short period of time (which could endanger the power grid reliability in Texas)

. Even accounting for the SO 2 FGD scrubbers that have recently come on

- line, the TCEQ estimates that approximately 120,000 tons of SO 2 reductions will still be required from Texas EGUs in 2012. The TCEQ still has significant concerns that forcing Texas EG Us to make such significant SO 2 reductions in the unprecedented short compliance schedule mandated by the EPA will leave some Texas coal

- fired EGUs with limited options for compliance and may still endanger Texas electrical power grid reliability. Comment er provides significant additional discussion on this issue and disputes the conclusions related to the benefit of the proposed changes to Luminant’s allocations, their ability to use intrastate trading as a compliance option, and the state budget within A ssistant Administrator Gina McCarthy’s October 17, 2011 letter. Commenter asserts that it is not possible for the cited facilities to achieve sufficient additional reductions and surplus allowances to address the remaining reductions needed by the state a s a whole. Also, it is not expected that any SO 2 allowance trading among the Group 2 states will be sufficient to cover the expected SO 2 reductions necessary in TX to meet the revised SO 2 budget by 2012, despite the proposed delay of the assurance provisi ons and variability limits until 2014.FIP Revisions

- RTC Febru ary 7 , 2012 Page 52

52 [Letters: Texas Commission on Environmental Quality (EPA

- HQ

- OAR

- 2009

- 0491

- 4782) p. 1(cvr); p. 2

- 4]
RESPONSE : EPA’s modeling of cost

- effective compliance for Texas under the Transport Rule programs suggests that th e least

- cost option for many Texas utilities would be to sustain a multi

year trend of switching to lower

- sulfur sub

- bituminous coal. Energy Information Administration (EIA) data shows that Texas lignite

- burning units have significantly increased their le vel of sub

bituminous blending over several years leading to 2010. EPA believes that a switch from lignite to increased blending of sub

- bituminous coal (even fully displacing the lignite) is a technically feasible compliance option that can be accomplishe d at most lignite plants within the time frames available under the Transport Rule. These plants would likely experience reductions in total coal consumption and air pollutant emissions, an increase in boiler efficiency, and an increase in net electrical output. Luminant, and other Texas sources, are not constrained under the Transport Rule to operate with only their initial allocation of allowances and then shut down facilities once initially allocated allowances are consumed. Nor are units constrained to demonstrate compliance prospectively on or before January 1 of each year. Rather, Luminant and all other generators in the program, have until March 1 to demonstrate that they hold allowances equal in amount to the tons of SO 2 and NO X th at th ey emit du ring the annual compliance period , and until December 1 to demonstrate that they hold sufficie nt allowances to cover their NO X emissions during the ozone season compliance period

. Luminant makes its claims based on a compliance strategy that rest s on two mistaken assumptions: (1) That a source may not emit more than its initial allowance allocation; and (2) t hat a source must reduce its emissions to the level of its allowance allocation by January 1

. Their compliance strategy also appears to be based on a fear that markets for Transport Rule allowances may not fully develop. See Declaration o f Sam Napolitano dated October 1 3 , 2011, filed in support of EPA's o pposition to motion filed by the State of Texas, et al., EME Homer City Generation v. US EPA, and consolidated cases, No. 11

- 1302 (D.C. Cir.) which can be found in the docket for this rule making (EPA

- HQ

- OAR

- 2009

- 0491

- 4834 ) , for further discussion and rebuttal of Luminant’s comments on this rulemaking

. Comment (C)(3) : The final CSAPR was based on err oneous assumptions about planned and existing scrubbers at Texas EGUs. EPA proposes to revise Texas’s SO 2 budget because the final CSAPR erroneously assumed that scrubbers exist at three Texas EGUs (W.A. Parish Unit 6 and J.T. Deely Units 1 & 2), and it o verestimated the amount of flue gas that is treated by existing scrubbers at five Texas generating plants (Martin Lake, Monticello, Sandow, W.A. Parish, and Oklaunion). Commenter (Luminant) provides a description of the logic and details behind EPA's prop osed revisions and notes that while EPA is correct to make budget revisions to correct for these clear errors, its proposal understates the amount of revision that is necessary. In particular, in its correction for the three scrubbers that do not exist, E PA assumes an emissions rate of 0.58 lbs/mmBtu, which results in a proposed adjustment of 26,359 tons of SO 2 . However, the emissions rate used by EPA (0.58 lbs/mmBtu) is based on the assumption that these units willFIP Revisions

- RTC Febru ary 7 , 2012 Page 53

53 burn “super

- compliant” Powder River Bas in (“PRB”) coal, which, as Luminant previously documented to EPA, is not possible in the near term and certainly not by the January 1, 2012 compliance start date. A more realistic and achievable emissions rate for these units, based on coal that is actual ly available, is 0.80 lbs/mmBtu. This correction to EPA’s calculation results in a necessary adjustment of 44,609 tons SO 2 as to the three nonexistent scrubbers, not 26,359 tons as proposed. The total revision to Texas’s SO 2 budget to account for all of EPA’s erroneous assumptions about Texas scrubbers should thus be 88,317 tons (an incremental increase of 18,250 tons from what EPA proposes). Commenter adds that EPA is correct to re

- classify Oak Grove Unit 2 as a new unit. In support, commenter provides a copy of their previous comments and other information as Attachments 1, 5 and 6. [Letters: Luminant (EPA

- HQ

- OAR

- 2009

- 0491

- 4818) p. 13

- 15]
RESPONSE : EPA notes that lower sulfur coal is available and coal fired sources in the ERCOT region have had suc cess purchasing and burning such fuels. T hese units are already operating at levels below the 0 .8 lbs/ mmBtu suggested by commenter based on the emission rate data reported by the unit’s themselves in the most recent CAMD data. The rates reported are cons istent and support EPA’s assumption of their access to ultra

- low sulfur coal. Moreover, EPA has received no information from the facility owners themselves validating any of th e claim s submitted by this commenter, who does not own or operate these facilit ies to the best of EPA’s knowledge

. In fact, the facility owner for Deely units commented that they are “planning to use Ultra Low Sulfur coal at the Deely units in 2012”, contradicting claims made by the commenter (see comment EPA

- HQ

- OAR

- 2009

- 0491

- 4784 i n the docket to this rulemaking)

. In regards to the budget adjustment pertaining to the amount of flue gas that is treated by Texas generating plants, see the Final Revisions Rule preamble , section IV.A.(3) and the Final Revisions Rule State Budgets and N ew Unit Set

- Asides TSD for this rulemaking. Comment (C)(4) : Similar to EPA’s error in assuming that certain Texas units would be equipped with scrubbers to control SO 2 in 2012, EPA wrongly assumes that certain Texas units are, or will by 2012 be, equippe d with selective catalytic reductions systems or “SCRs” to control NO X emissions. EPA recognizes its mistake in this regard for other States (i.e., Michigan, Nebraska, Wisconsin, and New Jersey) and increases those States’ NO X budgets accordingly. See Re visions TSD at 4, 5, 16, and 27. The same is true for Texas. The data underlying EPA’s remedy case assumes that five Texas EGUs are equipped with SCRs (i.e., assumes that these units are able to achieve NO X emissions rates of 0.05 lbs./mmBtu, which can o nly be achieved with an SCR). These five units are Limestone Units 1 & 2, San Miguel Unit 1, Pirkey Unit 1, and Welsh Unit 1. Commenter (Luminant) provides supporting data in Attachment 7 to their letter). In reality, these units do not have SCRs, and t heir NO X emissions rates range from 0.18 to 0.20 lbs/mmBtu. Correcting this error in the unit

- level operational information for these units, using the same methodology employed by EPA in the Proposed Revision for other States where this error was identifi ed, results in an increase in the Texas annual NO X budget of approximately 3,619 tons and seasonal NO X budget of 1,956 tons. Commenter provides supporting information in Attachment 8 to their letter). EPA should make these revisions to the Texas NO X budg ets, as it did to the NO X budgets for other States, and, indeed, it would be arbitrary for it to refuse to do so. [Letters: Luminant (EPA

- HQ

- OAR

- 2009

- 0491

- 4818) p. 17

- 18]FIP Revisions

- RTC Febru ary 7 , 2012 Page 54

54 RESPONSE : EPA did not assume SCRs were present at these units in its modeling inp uts (as it did assume SCR was present at the units in other states referenced in the comment above). Rather, some SCR retrofit capacity was collectively projected to be applied to these units to reduce NO X emissions as a response to non

- Transport Rule req uirements or incentives (e.g. , s tate r ule requirements) in the modeling outputs. Moreover, the amount of SCR assumed at these units is not sufficient to achieve the 0 .05 lb/ mmBtu rate claimed by commenter. The TR_final_base_case and TR_final_remedy model ing illustrate much higher assumed emission rates at these units (see http://www.epa.gov/airmarkets/progsregs/epa

- ipm/transport.html ) . The emission rate s , in most cases, approximate reported emission rates at the facilities. For example, the emission rat e modeled at Pirkey is 0 .16 lb/ mmBtu and the actual 2010 NO X rate reported from Pirkey is 0 .16 lb/ mmBtu . Given the consistency of the projected and observed emission rate at the unit, it is not clear why commenter is claiming an inaccuracy at this source. For some of the units, the emission rate is slightly lower than historic emission rates indicating the reductions expected to occur among a collective group of sources in the state in response to legal requirements or incentives. In its IPM Documentatio n Supplement for EPA Ba se Case v.4.10 Ftransport and its Transport Rule IPM Assumptions Response to Comment Technical Support Document , available in the docket for this rulemaking, EPA discussed these type s of retrofits and noted that where they are in res ponse to state rule s or legal requirement s that appl y a singular requirement to a broad coverage of units (i.e. , one emission rate to many sources), the predicted control retrofit may differ from the compliance strategy ultimately chosen by those units. H owever, EPA went on to note that the emissions consequence of those assumptions was valid at the state level as reductions will ensue from some of the covered sources even if it is not those predicted by economic modeling. EPA encourages commenter to look at the emission rate, not the nominal control, modeled for these units and the commenter can confirm that the rate modeled is much higher than 0.05 lb / mmBtu . The overall emissions consequence from the SCR capacity projected at these units is small and va lid given state rule requirements and environmental efforts. Furthermore, EPA disagrees with the notion that this rule somehow requires additional SCRs at units that have not already installed them (as suggested in the petition for reconsideration incorpo rated by reference in Luminant’s comment to which EPA will respond in a separate action ). The NO X reductions finalized in this rule are modest and the state of Texas is already operating under its assurance level, meaning that it could comply with the bud get with no additional NO X reductions if it chose a compliance strategy of allowance purchase. Moreover, the s tate could likely comply with its NO X and ozone season NO X budget levels through simply operating its new generation and operating its existing N O X controls year round. Comment (C)(5) : The final CSAPR is based on the incorrect assumption that Luminant’s Big Brown Unit 1 & 2, Monticello Units 1 & 2, and Martin Lake Units 1, 2, & 3 use, or will use by 2012, 100% super

- compliant western PRB coal (i. e., coal with a sulfur content of 0.58 lbs./mmBtu or less). This is an incorrect assumption. These units currently burn Texas lignite, blended with some western coal of 0.80 lbs/mmBtu, not 0.58 lbs/mmBtu. For several reasons, EPA’s assumption that these units can or will switch to 100% super

- compliant PRB in 2012 as aFIP Revisions

- RTC Febru ary 7 , 2012 Page 55

55 cost

- effective compliance option is not valid. First, the assumption that these units can burn 100% western coal of any variety (and abandon lignite altogether) conflicts with EPA’s own st ated rationale in the final CSAPR. Second, it is inaccurate to assume that these units can blend (even at current blending ratios of lignite to PRB) with super

- compliant PRB coal. Replacing the current western coal used by those units with supercompliant PRB coal for 2012 compliance is unrealistic because all currently

- available supercompliant PRB coal is under contract. Third, as to Martin Lake, EPA’s assumption that the plant can obtain and use 100% PRB coal is incorrect for an additional reason. Comm enter provides (as Attachment 11) an analysis by CANAC Railway Services, Inc., and notes that in order for Martin Lake to use 100% PRB coal, approximately 12.6 million tons would be required to be delivered to the plant annually. To correct this error in the fuel usage data for Martin Lake, EPA should increase Texas’s SO 2 budget by an additional 7,546 tons. Commenter provides significant additional discussion on each of these three points and provides supporting documentation in Attachments 1, 2, and 11 o f their letter. [Letters: Luminant (EPA

- HQ

- OAR

- 2009

- 0491

- 4818) p. 19

- 22]
RESPONSE : T he emission rate s reported at unscrubbed coal plants in Texas support the assumption that the uncontrolled emission rates assumed in EPA modeling are achievable in the state and that t here is demonstrated delivery and consumption of super

- compliant low sulfur coal by coal facilities in Texas. Luminant has not demonstrated sufficiently that it was impossible for their facilities to contract or receive this coal. See section 6.1c of this document , below, for information addressing SO 2 emission rates. Furthermore, EPA believes for any mine

- mouth lignite unit there could be a need for additional coal handling systems and improvements to any existing rail spur serving th e site in order to receive large trainloads of sub

- bituminous coal in lieu of the lignite currently delivered from nearby mining operations. However, it also understand s that, except for the coal handling systems, any unit designed to burn a low rank coal like lignite can burn higher rank sub

bituminous coal with only a few relatively minor changes to the boiler and its related systems. This is because a lignite unit is in almost all respects "over

- designed" for the requirements of a higher rank coal. For a switch from lignite to sub

- bituminous, the primary boiler improvement needed might only be the simple addition of modern "intelligent sootblowing" systems to manage the effects of "ash reflectivity" in the boiler furnace and convection pass with sub

bitu minous. EPA believes that with such relatively minor boiler improvements , a switch from lignite to sub

- bituminous should result in no derating of electrical output, improved boiler efficiency, and reduced stack emissions. Comment (C)(6) : The unit

- level operational information used in the final CSAPR for Luminant’s Sandow Unit 4 contains a material error. EPA’s modeling assumes that Sandow Unit 4 operates at an annual capacity factor of 0.25 (i.e., that it runs only 25% of the year) because presumably EP A erroneously assumed that the lignite coal that is mined onsite to fuel the unit will no longer be available given that the Sandow Mine was reaching the end of its life. This assumption is incorrect. Although the Sandow Mine has ceased production, the T hree Oaks Mine was developed and permitted years ago to take its place in supplying local lignite to the unit. That mine is presently operating and in fact supplied the unit with over 2.6 million tons ofFIP Revisions

- RTC Febru ary 7 , 2012 Page 56

56 lignite in 2010 and is projected to provide fuel fo r the Sandow generating units well into the future. EPA is aware of this replacement mine, and, in fact, the agency provided comments on the Environmental Impact Statement for the Three Oaks Mine during its permitting process for the mine. Commenter (Lum inant) provides supporting documentation on this as Attachment 13 of their letter. EPA should make revisions for this incorrect assumption for Sandow Unit 4 that would reflect its current capacity factor (approximately 92%) and thus its higher emissions i n the remedy case. According to Luminant’s calculations, in order to reflect the unit’s actual operations, it is necessary to increase Texas’s SO 2 budget by 11,967 tons, its annual NO X budget by 1,721 tons, and its seasonal NO X budget by 514 tons. [Lette rs: Luminant (EPA

- HQ

- OAR

2009

- 0491

- 4818) p. 22]
RESPONSE : The commenter mistakenly presumes that EPA “assumes” capacity factors in its IPM modeling. In fact, EPA makes no assumptions regarding any facility’s level of utilization; instead, EPA conducts IPM modeling in order to project least

- cost operation of the power sector and consider associated parameters of interest, such as the state

- level EGU emission projections that form the basis for state budgets under the Transport Rule programs. EPA includ es in its IPM modeling a highly detailed and peer reviewed coal supply network, among other variables in the model that are relevant to projected fleet operations to meet electricity demand. One key variable in the modeling of economic dispatch is the hea t rate of the unit, since heat rate directly impacts how often it is economic to operate the unit. The Sandow unit referenced in this comment is one of the two most inefficient units in the Texas lignite fleet as measured by the unit heat rate. This diff erence between the Sandow unit and other lignite units is reflected in the heat rate data used as inputs to IPM modeling and influences the capacity factor projected for the Sandow unit compared to other units in Texas. EPA disagrees with the commenter’s assertion that historic capacity factors would be, in and of themselves, an appropriate basis for a state budget revision under the Transport Rule programs; this approach, if taken to its logical conclusion, would suggest that all units would indefinitely sustain their operating behavior regardless of a host of variables that change over time and are accounted for in IPM modeling projections. Comment (C)(7) : According to Luminant’s review of the individual unit heat input data used in the CSAPR remedy cas e, EPA has erroneously assumed that six coal

- fired boilers in Texas (at five units) co

- fire with biomass

— thus overstating the emissions reductions that can be achieved by Texas sources at EPA’s cost thresholds and underestimating the Texas SO 2 budget. Thi s error exists for Gibbons Creek 1, Oklaunion 1, San Miguel 1, Sandow 4, and Sandow 5A and 5B. For these units, the sum of the coal heat inputs for each of these units does not equal the total heat input used in the modeling, indicating that EPA’s model a ttributes some other type of fuel to make up the difference at each unit. A review of the un

- delimited text “rpe” file indicates that this other fuel type used in the modeling is biomass (the fuel code “ZB1” is used to indicate biomass). However, none of these units (two of them are Luminant’s units) has the permit authorization, the transportation infrastructure, or the fuel feeding mechanism to co

- fire biomass. These units should have been modeled as burning coal only, not biomass. EPA should account for this error and recalculate the emissions for these units using coal only and increase the TexasFIP Revisions

- RTC Febru ary 7 , 2012 Page 57

57 SO 2 budget accordingly. According to Luminant’s estimate, this would increase the Texas SO 2 budget by about 300 tons. [Letters: Luminant (EPA

- HQ

- OAR

- 2009

- 0491

- 4818) p. 23]
RESPONSE : See Response to American Electric Power (EPA

- HQ

- OAR

- 2009

- 0491

- 4737) p. 7

- 8; American Electric Power (EPA

- HQ

- OAR

- 2009

- 0491

- 9000) p. 51

- 52 in section I.8(e) below. Comment (C)(8) : Commenter (Luminant) agrees with EPA’s asses sment that the proposed increases to Texas’s emissions budgets will not affect downwind air quality in any meaningful way and certainly will not cause Texas emissions to contribute significantly to nonattainment or interfere with maintenance of air quality standards in any State downwind of Texas. Commenter provides additional discussion on this issue, noting that given the minuscule impact that the addition of 70,067 tons of SO 2 to Texas’s budget has on the modeling of Texas’s downwind impact, the additio nal revisions recommended by Luminant in these comments will also have no meaningful impact and certainly will not cause Texas to approach the “significant contribution” thresholds set by EPA. [Letters: Luminant (EPA

- HQ

- OAR

- 2009

- 0491

- 4818) p. 24

- 25]
RES PONSE : In the pre a mble of the final Transport Rule (76 FR 48208, August 8, 2011, see 48214, 48240), EPA identifies Texas as a state that significantly contributes to and/ or interferes with maintenance of the annual PM 2.5 NAAQS in another state. On page 4 8237, EPA describes and justifies its use of a threshold of one percent of the NAAQS to help identify states that may, or may not, be significantly contributing or interfering with maintenance of a NAAQS in another state. On page 48257 EPA classifies Texa s as a “Group 2” state for SO 2 control, indicating that its significant contribution and/or interference with maintenance is eliminated at the $500/ton level of emission reductions in 2014. Following the analysis in the final revisions rule (see the pream ble as well as the Final Revisions Rule Significant Contribution Assessment TSD in the docket to this rulemaking ), EPA affirms that Texas is appropriately classified as a “Group 2” state and that its significant contribution and/ or interference with mainte nance is eliminated at the $500/ton level of emission reductions in 2014 (evaluated at the level of the emissions resulting from the final revisions rule). The commenter mischaracterizes the definition of significant contribution under the Transport Rule. In keeping with the methodology EPA developed in the Transport Rule as previously promulgated, and as applied to all states covered by the rule, EPA is quantifying Texas’s significant contribution and interference with maintenance as the emission reducti ons available at the cost thresholds selected in the final Transport Rule multifactor analysis. This revisions rule makes a technical adjustment to the quantification of emission reductions available at that cost threshold (which is administratively achie ved by the proper quantification of the state budgets under the Transport Rule programs). The commenter’s assertion that there exist somehow additional emissions, beyond the state’s revised assurance level, that are still inferior to its “significant cont ribution” represents a fundamental misunderstanding of how EPA has defined significant contribution under the Transport Rule (which is actually defined to be equivalent to the state’s assurance level). The commenter has failed to demonstrate that its addi tional requested revisions are founded on any technical inability to achieve the relevant emission reductions at or below the relevant cost threshold informing the quantification of the Texas state budgets. As such, EPA believes it hasFIP Revisions

- RTC Febru ary 7 , 2012 Page 58

58 properly quantified the assurance levels for Texas (inclusive of the revisions finalized in this rule) and it is therefore illogical to claim that EPA could allow even greater emissions from Texas that “ will not cause Texas to approach the “significant contribution” threshol ds set by EPA ,” as the revised assurance levels themselves are an expression of the significant contribution that must be eliminated. (D) EPA's reliability analysis is flawed and the Agency significantly overestimates ERCOT generation capacity.
Comment (D)(1) : EPA's analysis entitled "Resource Adequacy and Reliability in the IPM Projections for the Transport Rule TSD" was not available at rule proposal and includes significant errors regarding generation capacity within ERCOT, the largest grid operator within Texas. The EPA overestimates ERCOT's generation capacity by nearly 20,000 megawatts, leading to faulty conclusions about the impact of the CSAPR on the ERCOT system. ERCOT’s analysis of the CSAPR indicates that the rule will place electric reliabil ity in the ERCOT system at risk. ERCOT considered three different scenarios in their analysis and each scenario resulted in reductions in capacity in peak and off

- peak months. During summer 2011, Texas set new records for power demand during a record heat wave. ERCOT’s analysis indicated that if the CSAPR had been in effect in 2011, then ERCOT would have experienced rotating outages, i.e., rolling blackouts, in August. Problems with the CSAPR compliance timeline was another key point from ERCOT’s study, in which ERCOT commented “...the CSAPR implementation date does not provide ERCOT and its resource owners a meaningful window for taking steps to avoid the loss of thousands of megawatts of capacity, and the attendant risks of outages for Texas power users.” ER COT’s report on the final CSAPR, entitled Impacts of the Cross

- State Air Pollution Rule on the ERCOT System , is available at http://www.ercot.com/news/presentations/

. [Letters: Texas Commission on Environmental Quality (EPA

- HQ

- OAR

- 2009

- 0491

- 9002) p. 23; Texas Commission on Environmental Quality (EPA

- HQ

- OAR

- 2009

- 0491

- 4782) p. 7]
RESPONSE : The letters cited in this comment maintain EPA failed to consider units that ERCOT considers mothballed in developing the database for IPM analysis. EPA uses the Natio nal Electric Energy Data System (NEEDS) to determine existing capacity in each model region. The NEEDS data show 92 GW of capacity in ERCOT. EPA made this information public and made any corrections to these data in comments on the proposed rule.
EPA recognizes that wind is a variable resource for power generation, and our modeling of CSAPR, in fact, takes this reality into account in a very detailed manner to simulate future generation from wind turbines. EPA’s power sector modeling utilizes capacity factors for wind generators that reflect both wind class (ranging from class 1 to class 7) and geographic region, and are explicitly designed to represent how often the wind blows to support power generation at different locations. EPA worked with the U. S. Department of Energy’s (DOE) National Renewable Energy Laboratory (NREL) on a complete update of the wind resource assumptions for use in EPA Base Case v.4.10. The result is a complete representation of the potential onshore, offshore (shallow and deep ) wind generating capacity (in MW) broken into four cost classes in each IPM model region.FIP Revisions

- RTC Febru ary 7 , 2012 Page 59

59 To represent intermittent renewable generating sources like wind and solar, EPA’s IPM modeling (including the modeling used for the Transport Rule development) uses generation profiles which specify hourly generation patterns for a representative day in winter and summer. Each eligible model region is provided with a distinct set of winter and summer generation profiles for wind, solar thermal, and solar photovoltaic plants, such that projected generation from intermittent renewable sources would reflect the frequency that those resources are actually available in that region. For CSAPR modeling, EPA derived its capacity factor assumptions for wind generation from th e Energy Information Administration’s (EIA) Annual Energy Outlook (AEO) 2010 and the data are shown in Table 4

- 20, Table 4

- 21, and Table 4

- 22 of the IPM documentation on EPA’s website. 1 The letter also raises the concern that IPM included plants that we re no longer operating or indefinitely out of service. It is difficult to determine which plants are being referenced; however, a previously released ERCOT report mentions 2.5 GW of mothballed (i.e., indefinitely out of service) plants that Texas does not include among capacity resources. If these plants were removed from the capacity in the IPM reserve margin calculation, and if a lower capacity credit were assumed for wind generators, the Texas reserve estimated from IPM would be 17.4%, which exceeds ER COT’s reserve margin planning target of 13.75%. Therefore, even if we revised our projections to eliminate this capacity, our modeling would still find that Texas can maintain adequate capacity reserves to meet its planning reserve margin target while com plying with the Transport Rule . Given this margin and the inherent market

- based flexibility of the regulation, the Transport Rule does not threaten electric reliability in Texas. EPA therefore believes that the IPM projections are based on reasonable cap acity estimates for the ERCOT system, even if the specific concerns cited by Texas were accepted. Moreover, these changes would not have required any modifications to the Texas emissions budgets. Comment (D)(2) : EPA's reliability analysis continues to s uffer from factual errors and methodological flaws in its calculation of existing generating capacity in the ERCOT region, and has significantly overstated existing generating capacity. EPA has overstated the amount of generation available in future years by more than 14 GW by including generating plants that have been retired or mothballed and by failing to adjust wind generation capacity to account for the fact that wind is variable and often does not blow during times of peak energy use. Commenter prov ides additional discussion to support their assertion on this issue. [Letters: Public Utility Commission of Texas (EPA

- HQ

- OAR

- 2009

- 0491

- 4800) p. 4

- 5]
RESPONSE : See response to last comment, 1.7(D)(1), above. (E) Commenter believes that the emissions allowances granted under the CSAPR FIP to several of its electric generating units in Texas should be adjusted with the other proposed revisions to the rule.

1 http://www.epa.gov/airmarkets/progsregs/epa

- ipm/docs/v410/Chapter4.pdfFIP Revisions

- RTC Febru ary 7 , 2012 Page 60

60 Comment (E)(1) : Allowances granted to Topaz’s Barney M. Davis and Laredo Energy Centers should b e adjusted to account for repowering projects during the relevant years under the CSAPR FIP’s emissions allocation method. In recent years, Topaz has completed substantial capital improvements to increase efficiency and reduce air emissions through repowe ring projects at each of its three Texas plants. Each of these projects involved replacing less

- efficient, higher

- emitting oil

- fired boilers with higher

- efficiency, lower

- emitting combined

- cycle gas

- fired turbines. Commenter (Topaz Power) provides signif icant additional discussion to describe the timing and sequence of these capital improvements and how they affected the operation and start

- up of each unit and asserts that despite the clearly

- stated objective of CSAPR, the repowered units at the Laredo, B arney M. Davis, and Nueces Bay Energy Centers operated by Topaz have been granted emissions allocations under the CSAPR FIP based only on heat input and emissions data from after completion of the repowering projects, without regard to the units’ past oper ating history. Commenter provides a reproduction of EPA's allocation spreadsheet as Attachment 1 and describes how the data in that file does not contain any heat input or emissions data for years before the repowering projects were completed, adding that these data are readily accessible within EPA’s CAMD database. Commenter provides a spreadsheet as Attachment 2 that contains the emissions and heat rate data from 2003

- 2008, as obtained from the CAMD database, for Barney M. Davis Unit 2 and Laredo Units 1, 2, and 3. EPA should correct the allowance allocations to the repowered units at the Barney M. Davis and Laredo Energy Centers to account for operations during years both prior to and following the repowering projects. [Letters: Topaz Power Group (EP A

- HQ

- OAR

- 2009

- 0491

- 4755) p. 2

- 5]
RESPONSE : Changes to the allocation methodology are out side the scope of revisions proposed and upon which EPA solicited comment . See Section 6.5, below, for more information. Comment (E)(2) : The allowance allocations under the CSAPR FIP should not turn on whether the units affected by the project were given new unit names or retained the same unit names. Commenter (Topaz) recognizes that the repowering projects for which they are requesting an allocations adjustment w ere not one

- for

- one turbine replacements. At the Barney M. Davis Energy Center, one existing boiler was replaced with two new turbines, and at the Laredo Energy Center, three existing boilers were replaced with two new turbines and both were repowered wit h differently named units. However, the fact remains that the new units at these plants were the products of repowering projects that served to reduce emissions at existing units in a manner that CSAPR’s allocation method is intended to consider. In this regard, the projects are similar to the repowering project described by the City of Tallahassee in comments on CSAPR. See U.S. EPA, Transport Rule Primary Response to Comments, Docket No. EPA

- HQ

- OAR

- 2009

- 0491 at 2,648

- 49 (June 2011). EPA responded that repowered units reporting as the same unit “would continue to receive the same allocation as prior to repowering.” Id. at 2,649. As such, EPA should correct the CSAPR allocation spreadsheet to assign past emissions and heat input data from Barney M. Dav is Unit 2 to the current Barney M. Davis Unit 3, assign past emissions from Laredo Units 1 and 2 to the current Laredo Unit 4, and assign past emissions from Laredo Unit 3 to the current Laredo Unit 5. [Letters: Topaz Power Group (EPA

- HQ

- OAR

- 2009

- 0491

- 47 55) p. 2

- 5]FIP Revisions

- RTC Febru ary 7 , 2012 Page 61

61 RESPONSE : Changes to the allocation methodology are out side the scope of revisions proposed and upon which EPA solicited comment

. See Section 6.5, below, for more information. Comment (E)(3) : EPA should correct emissions and heat rate dat a and resulting allocations for the Barney M. Davis and Nueces Bay Energy Centers to account for partial

- year 2010 operation (i.e., corrected to reflect the operation of those units both before and after repowering). Such an allocation would be most consi stent with the allocation methodology in the CSAPR FIP and its underlying principles. The year

- 2010 heat input and emissions data for these units must also be corrected to reflect representative annual operations. The repowering projects at the Barney M. Davis Energy Center and the Nueces Bay Energy Center were both completed during 2010, and the newly

- repowered units did not operate at representative capacity levels for the full calendar year. Commenter provides significant additional discussion on this issue and describes the schedule for certification and commercial availability (i.e., February and March 2010, respectively). During 2010, the two repowered units at the Barney M. Davis Energy Center were utilized at only 37.9% capacity and the two repow ered units at the Nueces Bay plant were utilized at only 42.8% capacity. However, the allocations granted to these units correspond to their actual emissions during 2010 alone. The emissions allocations for Barney M. Davis Units 3 and 4 and Nueces Bay Units 8 and 9 should be adjusted to reflect a full year’s operation at representative heat input and emissions numbers. Commenter provides requested revisions in a table and notes that EPA has already taken similar steps to correct the allocations for sim ilarly

situated units. [Letters: Topaz Power Group (EPA

- HQ

- OAR

- 2009

- 0491

- 4755) p. 5

- 7]
RESPONSE : Changes to the allocation methodology are out side the scope of revisions proposed and upon which EPA solicited comment

. See Section 6.5, below, for more i nformation. (F) Commenters express concerns regarding the methodology EPA has proposed in order to adjust the SO 2 allowances granted to Texas. Comment (F)(1) : Sierra Club and EDF have approximately 30,000 and 17,000 members, respectively, residing in Texas and in downwind states such as Arkansas, Louisiana, and Oklahoma, who are impacted by air pollution from Texas sources. Many of these members live and recreate in areas impacted by SO 2 pollution and the fine particle pollution to which it contributes. T he proposed increase to the Texas SO 2 budget is not based on the most accurate data and as a result is larger than is appropriate. An excessive SO 2 budget for Texas would likely result in unnecessarily high Texas emissions with adverse effects on our memb ers in Texas and downwind states. The largest beneficiary of this excessive adjustment would be Luminant, the state’s largest and dirtiest generator, which will receive allowances equal to approximately one
- third of Texas’s SO 2 budget and therefore will r eceive approximately one

- third of any budget adjustment made by EPA. [Letters: EDF, NRDC and Sierra Club (EPA

- HQ

- OAR

- 2009

- 0491

- 4822) p. 1

- 3]
RESPONSE : See the preamble, section IV.A(3), of the final Revisions Rule

.FIP Revisions

- RTC Febru ary 7 , 2012 Page 62

62 Comment (F)(2) : Table 4 of the TS D addendum for the final rule reflects the fact that EPA assumed the scrubber efficiency rates reported on EIA Form 860, which asks for the “design” parameters for a scrubber (reflecting the maximum performance expected under normal operating conditions). Thus, in certain circumstances, the “design” efficiency reported on Form 860 does not necessarily reflect the actual performance of the scrubber. The actual performance data is reported to EIA by the generators on Form 923, and varies from year to year. The Form 923 data for the plants at issue here reflects the lower SO 2 removal efficiencies resulting from less

- than

- optimal performance, and the fact that not all the flue gas is being routed through the scrubber before it reaches the atmosphere. Comment ers provide significant additional discussion on this issue, including tables that include emissions and budget data for multiple scenarios, including Table 1

- Calculation to Determine Texas SO 2 Budget Revision

- Assuming 2007 SO 2 Removal Rates at FGD; Ta ble 2

- Calculation to Determine Texas SO 2 Budget Revision

- Assuming 2009 SO 2 Removal Rates at FGD; and Table 3

- Calculation to Determine Texas SO 2 Budget Revision

- Assuming Design SO 2 Removal Rates at FGD and Percent Flue Gas Entering FGD. These table s show that had EPA used the Form 923 data from either 2007 or 2009, the calculations would have resulted in significantly lower projected emissions for these four Luminant units and significantly lower adjustments to the SO 2 budget for Texas as a whole. Commenter asserts that if EPA decides to move forward with adjusting Texas’ SO 2 budget, they recommend that EPA finalize revisions that take into consideration the design capabilities of the scrubber, as used in the final rule, and adjust the calculation t o consider the amount of flue gas actually entering the scrubber. Recalculating the SO 2 budget adjustment for Texas using a more appropriate measure of scrubber performance will help ensure Texas’ SO 2 pollution does not continue to contribute to downwind attainment problems. [Letters: EDF, NRDC and Sierra Club (EPA

- HQ

- OAR

- 2009

- 0491

- 4822) p. 2

- 7]
RESPONSE : EPA based its scrubber assumptions in the final Transport Rule on EIA form 860 which provides information on the capability (i.e., "design" parameter s under normal operating conditions) of scrubbers, as opposed to actual historical performance data. At that time, EPA assumed that 100 percent of flue gas was treated at all scrubbers. EPA responded to comments in the final Transport R ule defending the appropriateness of this metric as opposed to other measures (e.g. , historic performance). In the proposed revisions rule, when EPA tried to address the concern raised by facilities in Texas that , due to stack configurations , 100 percent of the flue gas wa s not being treated by the scrubber , and the assumption that this had a significan t impact on the state budget, EPA deviated from the approach taken in the final Transport Rule by basing the scrubber removal efficiency on historic performance.
Commenter s pointed out the inconsistency with the approach used in the final Transport Rule, and suggested several options for identifying a removal value to make adjustment s for those units that was more consistent with the approach used for other scrubbed units i n the final Transport R ule

. In this final revisions rule, EPA recognizes the inconsistency in using a removal rate from the 2008 EIA form 923 for Texas in the revisions proposal, as opposed to scrubber capability from EIA form 860, and corrects for that inconsistency by taking into account scrubber capability dataFIP Revisions

- RTC Febru ary 7 , 2012 Page 63

63 from EIA form 860 in this final notice. Consistent with this final approach for the units in Texas and with the final Transport R ule, EPA intends to appl y this approach in responding to a comm ent EPA received for the revisions rule proposal to address flue gas bypass for units in Indiana. See the preamble, section IV.A(3), of the final Revisions Rule

. (G) To the extent that EPA refuses to reconsider and stay the final CSAPR as it applies to Te xas, EPA should finalize the Proposed Revisions to the Texas SO 2 and NO X budgets before the January 1, 2012 compliance start date. Comment (G)(1) : EPA should not have included Texas in the final CSAPR at all because Texas sources are not contributing to “nonattainment” to the only downwind monitor (Madison County, Illinois) to which Texas is linked. Commenter provides significant additional discussion on this issue, including a summary of their arguments previously submitted as part of their request for reconsideration. However, if EPA refuses to exclude Texas, then the proposed revisions should be finalized expeditiously. EPA's proposed adjustments are well

- supported by the record and should be finalized and implemented immediately. [Letters: Luminan t (EPA

- HQ

- OAR

- 2009

- 0491

- 4818) p. 9

- 13]
RESPONSE : In the preamble of the final Transport Rule (76 FR 48208, August 8, 2011, see pages 48214, 48240), EPA identifies Texas as a state that significantly contributes to or interferes with maintenance of the a nnual PM 2.5 NAAQS in another state. On page 48237, EPA describes and justifies its use of a threshold of one percent of the NAAQS, to help identify states that may, or may not, be significantly contributing and/ or interfering with maintenance of a NAAQS i n another state. On page 48257 EPA classifies Texas as a “Group 2” state for SO 2 control, indicating that its significant contribution or interference with maintenance is eliminated at the $500/ton level of emission reductions in 2014. Following the anal ysis in the final revisions rule (see the preamble as well as the Final Revisions Rule Significant Contribution Assessment TSD), EPA affirms that Texas is appropriately classified as a “Group 2” state and that its significant contribution or interference w ith maintenance is eliminated at the $500/ton level of emission reductions in 2014 (evaluated at the level of the emissions resulting from the final revisions rule). In the proposed Transport Rule (see preamble section IV, 75 FR 45210, August 2, 2010) EP A outlined its proposed methodology for the definition and elimination of significant contribution and interference with maintenance. In the Alternative Significant Contribution Approaches TSD from the proposed Transport Rule, EPA described a number of al ternative approaches that were examined as well as identified limitations. In section VI of the preamble for the final Transport Rule (as well as in other sections of the preamble), EPA describes the approach to define significant contribution and interfe rence with maintenance (see 76 FR 48208, August 8, 2011). In sections VI.A, VI.D and VI.G of the preamble, EPA describes its rationale for using both cost and air quality factors and its justification for using a uniform cost. Commenters on the proposed Transport Rule (EPA

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64 to how EPA could overcome the challenges that prevented the Agency from constructing a rule utilizing an alternative basis for defining and eliminating significant contribution a nd interference with maintenance. (H) The final CSAPR incorrectly allocates allowances to cogeneration units in Texas. Comment (H)(1) : The final CSAPR incorrectly allocates annual SO 2 , annual NO X , and seasonal NO X allowances to cogeneration units in Texas that are not regulated by the rule. The result of these erroneous allocations to unregulated units is that there are fewer allowances available and allocated to existing EGUs that are covered by the rule. Specifically, under the final CSAPR, cogeneration units are not covered units if they do not supply “in 2005 or any calendar year thereafter more than one

- third of the unit’s potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale.” 40 C .F.R. §§ 97.404(b)(1); 97.504(b)(1); 97.704(b)(1). The final CSAPR, however, allocates allowances to at least fifteen cogeneration units in Texas that do not provide one

- third of their power (or 219,000 MWh) to the grid. Commenter (Luminant) notes that t hese units and the allowances that were incorrectly allocated to them are detailed in Attachment 9 of their letter. This error involves a substantial number of allowances; 3,121 annual NO X , 1,389 seasonal NO X , and 152 SO 2 allowances. It is Luminant’s und erstanding that EPA is aware of this error and has gathered information from operators of these units confirming that they are not covered by the rule. The error is also confirmed by ERCOT’s Capacity Demand Reserve report, which does not include these cog eneration units in the universe of units dispatched to provide power to the grid. Commenter also provides supporting information in Attachment 10 of their letter, and notes that the revision should be implemented by January 1, 2012 to ensure that the erro r does not carry over to future compliance years and to avoid the situation where increasingly fewer allowances revert back to existing sources from the new unit set

- aside every compliance year. [Letters: Luminant (EPA

- HQ

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- 4818) p. 18

- 19]
R ESPONSE : The inclusion of a unit on the list of allocations does not constitute a determination that the unit is subject to the Transport Rule. Qualification for exemption can be determined through an applicability determination. A potentially exempted entity can request a determination of applicability at any time. Criteria for applicability are described in the p reamble s ection VII.B of the f inal Transport Rule (76 FR 48208, August 8, 2011). The formal applicability determination process provisions c an be found at 40 CFR 97.404(c), 504(c), 604(c), and 704(c). (I) EPA has not provided a supply
- side analysis supporting the technical feasibility for the large number of coal
- fired EGUs switching to low
- sulfur coal. Comment (I)(1) : The EPA’s analysis in S ection 7 of the final Regulatory Impact Analysis (RIA) of the CSAPR discusses switching to low

- sulfur as a compliance option and the potential increase in the use of low

- sulfur coal as a result of the rule. However, the EPA did not analyze whether the low

- sulfur coal producing regions are capable of meeting the demand. Furthermore, some of the EPA analysis in the RIA regarding coal use appears contradictory and inconsistentFIP Revisions

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65 with Energy Information Administration data and recent market analyses. Table 7

- 9 of the RIA projects approximately a 100 million ton increase in 2012 of what the EPA designates as very low

- sulfur coal (less than 0.8 lb/mmBtu) but Table 7

- 15 only indicates a 21 million ton increase in the western coal region where these low

- sulfur grades of coal are produced. Powder River Basin (PRB) subbituminous coal is the predominant western low

- sulfur coal and 90% of PRB coal is produced in Wyoming. The EPA has also not given appropriate consideration to issues such as contractual obligations, infras tructure needs, technical considerations, and employment impacts associated with an EGU switching to low

- sulfur coal. In response to the comments and concerns received in response to the 2010 proposal of CSAPR, EPA merely added a cost factor to its IPM mo deling “to capture the potential cost burden of deratings that might accompany switching to a very low sulfur subbituminous coal or coal blend.” The EPA did not provide an analysis of the feasibility issues raised by comments or even explain and justify th e factor it applied to the IPM modeling. These factors directly affect the feasibility of companies complying with the requirements of CSAPR and must be considered by the EPA. The EPA has also not given appropriate consideration to issues such as contract ual obligations, infrastructure needs, technical considerations, and employment impacts associated with an EGU switching to low

- sulfur coal. Commenter provides additional discussion on this issue and asserts that since the EPA relied specifically on fuel switching to low

- sulfur coal as a justification for short

- term reductions in SO 2 emissions, the impacts to the coal mining industry are self

- evident and much more detailed analysis is necessary. [Letters: Texas Commission on Environmental Quality (EPA

- H Q

- OAR

- 2009

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- 4782) p. 6

- 7]
RESPONSE : In regard to the RIA tables 7

- 9 and 7

- 15, the commenter is comparing apples to oranges. Table 7

- 9 pertains only to consumption in the Transport Rule regions covered for PM. Table 7

- 15 is coal production at the na tional level. In regards to low sulfur coal availability, EPA’s power sector modeling ( http://www.epa.gov/airmarkets/progsregs/epa

ipm/transport.html ) , which supported the Transport Rule analysis, already projects consumption of low

- sulfur coal in 2012 (4 15 million tons) to be lower than production of low

- sulfur coal in 2010 (423 million tons). Low sulfur sub

- bituminous coal can be further subdivided into relatively “lower” low sulfur coal (sulfur content below 0.8 lbs/mmBtu) and relatively “higher” low s ulfur coal (sulfur content above 0.8 lbs/mmBtu). EIA data from 2010 demonstrates that U.S. production of low sulfur sub

- bituminous coal is skewed toward production of coal in the former category. See the Declaration of Sam Napolitano, dated December 1, 2 011, filed in support of EPA's Consolidated Opposition, EME Homer City Generation v. US EPA, and consolidated cases No. 11

- 1302 (D.C. Cir.), which can be found in the docket for this rulemaking (EPA

- HQ

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- 2009

- 0491

- 4834 ). EIA data demonstrates that 339 m illion tons of “lower” low sulfur sub

- bituminous coal with sulfur content lower than 0.8 lbs/mmBtu were produced in 2010, and 84 million tons of “higher” low

- sulfur sub

- bituminous coal with sulfur content higher than 0.8 lbs/mmBtu were produced in that sa me year. The coal supply curves that are implemented in EPA modeling were reviewed independently by industry experts and were available for two rounds of public review during the Transport Rule development process in 2010. Finally, s ee section 6.2(c) of this document , below, for information addressing SO 2 emission rates. (J) Comments on Operation, Emissions, and Controls at Texas UnitsFIP Revisions

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66 Comment : Errors were made in the parsed IPM files for operation of the FGD system at Gibbons Creek. Reflecting the fac t that TMPA has announced plans to bring the FGD system back into operation in 2012, BC_P_12 correctly showed that the FGD system would, indeed, become operational in 2012. The FGD, however, does not appear in the BC_F_12 file. (The FGD appears in RC_F_12, suggesting that EPA now erroneously believes that the system will not be operational in 2012 but will only be “in the pipeline” at that time.) Errors were made in the parsed IPM files for the operation of an FGD system at Deely. The Deely FGD is not expe cted to be in operation until 2013 (although plans for FGD installation could be affected by the CPS announcement early this year that Deely is to be retired in 2018). BC_P_12 properly reflects that no FGD system will be installed at Deely in 2012. In BC_F _12 and RC_F_12, however, EPA erroneously assumes that the FGD system will be dispatchable/operational in 2012. Errors were made in the parsed IPM files for W.A. Parish 6. There are now no plans to have WFGD technology operational on Parish Unit 6 by 2012 . This was accurately reflected in BC_P_12 (where Parish Unit 6 is not identified as having WFGD technology). In both BC_F_12 and RC_F_12, however, a dispatchable WFGD erroneously appears on Unit 6. Errors were made in the parsed IPM files concerning the operation of gas

- fired units that have been retired and cannot be brought back on

- line. Specifically, the following units have been retired and cannot be brought back into service: Bryan (50 MW); CE Newman (41 MW); Colin (153 MW); Laredo Units 1

- 3 (a total of 171 MW); Leon Creek (120 MW); Mountain Creek Units 2 and 3 (a total of 100 MW); North Lake Units 1

- 3 (a total of 715 MW); North Texas Unit 3 (38 MW); and WB Tuttle Units 1, 3 and 4 (a total of 304 MW). In both the BC_P_12 and BC_F_12, however, EPA erro neously assumes that these numerous gas

- fired units can be made operational in 2012. Errors were made in the parsed IPM files concerning the operation of and emissions from San Miguel Unit 1, which is operated by San Miguel Electric Cooperative. San Migue l Unit 1 is a 391 MW base load unit with annual heat input between 32 and 35 TBtu; it provides least cost electricity to its members. The unit burns lignite coal with a sulfur content of 2.72% (2009) and a heat content of 5,280 Btu/lb (2009). This translat es into an uncontrolled SO 2 emission rate of 10.3 lbs/ mmBtu , but by operating its WFGD system with an actual removal efficiency of 93.8% (based on 2009 data), the unit is able to meet an SO 2 emission rate of 0.64 lb/ mmBtu

– which is almost identical to wha t is shown in 2010 data concerning the unit’s operations (the data show that the unit achieved an SO 2 emission rate of 0.63 lbs/ mmBtu in 2010). In BC_P_12, EPA erroneously showed the unit as operating on a seasonal basis only and erroneously showed that th e unit was capable of achieving an SO 2 emission rate of 0.15 lbs/ mmBtu

.FIP Revisions

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67 In comments on the PTR, San Miguel Electric Cooperative provided data to correct those mistaken assumptions. EPA, however, did not correct these errors in BC_F_12 and RC_F_12. Rather, in those IPM runs in support of CSAPR, EPA continues to assume (erroneously) that San Miguel Unit 1 operates only on a seasonal basis and that it is capable of meeting an emission rate even lower than that in BC_P_12 (i.e., in BC_F_12, EPA assumes Unit 1 c an meet an SO 2 limit of 0.13 lbs/ mmBtu rather than the 0.63 lbs/ mmBtu SO 2 emission rate that the unit has been demonstrated to achieve). Similar to the case of San Miguel Unit 1, EPA has made errors in the parsed IPM files concerning the operation of and emissions from Sandow Unit 4. Sandow Unit 4 operates year

- round, not seasonally. The unit burns 4.0 lbs/ mmBtu lignite coal (from a nearby mine), but by operating an FGD system with 75.2% removal efficiency, it is possible for Sandow Unit 4 to achieve an SO 2 emission rate of 0.99 lbs/ mmBtu . In BC_F_12, EPA erroneously assumes that Sandow Unit 4 would operate only seasonally (not year

- round) and that the unit would be able to achieve an SO 2 emission rate as low as 0.18 lbs/ mmBtu (which translates into a 95.5% removal efficiency, which is not the removal efficiency for Sandow 4). Errors were made in the parsed IPM files concerning the coals which can be burned at Big Brown Units 1 and 2; Martin Lake Units 1, 2, and 3; and Monticello Units 1 and 2. Those units burn a blended lignite/subbituminous coal; they are not designed to burn 100% subbituminous coal and, indeed, combustion of 100% subbituminous coal at those units would require boiler component replacements (which could not be installed by January 1, 2012) or a derate. In BC_P_12, EPA erroneously assumed that these units would be able to burn a 100% subbituminous coal. In response to comments, BC_F_12 correctly reflects that these units are burning a blended lignite/subbituminous coal. However, in the IPM R emedy Case run (RC_F_12), EPA erroneously returned to assuming that all these units could burn 100% subbituminous coal. Errors were made in the parsed IPM file concerning the SO 2 emission rate that can be achieved by Monticello Unit 3. The 2009 and 2010 S O 2 emission rates for Monticello Unit 3 are 0.51 lbs/ mmBtu and 0.66 lbs/ mmBtu , respectively. EPA, however, erroneously assumed in BC_P_12 that Monticello Unit 3 would achieve an SO 2 emission rate of 0.19 lbs/ mmBtu and even more erroneously assumed in BC_F_ 12 that Monticello Unit 3 would achieve an SO 2 emission rate of 0.08 lbs/ mmBtu

. [Attachment to UARG comment letter, “J. Marchetti, J. E. Cichanowicz, Initial Identification of Unit Errors in Integrated Planning Model (IPM) Runs (Oct. 7, 2011)” (EPA

- HQ

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- 2009

- 0491

- 4823) p. 50

- 51]
RESPONSE : In regard to the Gibbons Creek FGD, EPA did not assume it would operate in base case 2012 or 2014 as a dispatchable FGD as it would not have an economic incentive to be dispatched. This is consistent with recent emiss ion rates observed at the unit as reported to CAMD Data and Maps. However, the commenter is incorrect in suggesting EPA believes the system will not have an operational FGD in 2012. EPA models an FGD as in place andFIP Revisions

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68 operating in both 2012 and 2014 in the RC_F_12 and RC_F_14 based on the Transport Rule

based economic incentive to operate it In regard to Deely and Parish scrubbers, the responses above explain that EPA adjust the Texas state SO 2 budget to reflect the assumption that no FGD is present at th ese units

. In regard to the San Miguel and Sandow comment , EPA notes that the projected remedy scenario is not binding for a particular source, but simply an economic projection that the source may or may not replicate. In regard to the Bryan, CE Newman, Collin Laredo, Mountain Creek, North Texas , and WB Turtle units referenced by commenter, these units were not assumed to operate in the 2012 Base Case for the f inal Transport Rule. Leon Creek and North Lake were modeled as operating and generated about 3 40 GWh (or 0 .1%) of the state’s generation in the base case. If they are not available for utilization in 2012, then they would likely be replaced by generation with higher SO 2 emissions (these units have zero SO 2 emissions), which would only increase the strength of the linkage between Texas emissions and downwind nonattainment or maintenance issues. The state is well above its target reserve margin in the 2012 base case. The assumed operation of the FGD at this unit is evidenced by the 0 .06 lb/ mmBtu em ission rate observed at the unit in the 2012 remedy modeling. Many of these other unit level issues (e.g., Big Brown, Martin Lake, Monticello) are addressed in response s to comment s submitted by the facility owner (L uminant ) above, the p reambles to these rulemakings, and the Response to Comment Documents for the f inal Transport Rule. See section 6.1c of this document , below, for information addressing SO 2 emission rates. (K) Comments Relating to New Units in Texas
Comment : Errors were made in the parsed IPM files concerning the allocations for Spruce Unit 2 and Oak Grove Unit 2. Both units entered commercial operation after January 1, 2010 and thus should be receiving their allocations from the new unit set

- aside pool. Instead, EPA has incorrectly determ ined both Spruce 2 and Oak Grove 2 are existing units and should receive their allocations from the main allocation pool. Errors were made in the parsed IPM files through the exclusion entirely of new gas
- fired generation. Specifically, there are 16 units of gas

- fired generation that entered commercial operation in 2010 but are not included as new units (or otherwise) in the IPM files. [Attachment to UARG comment letter, “J. Marchetti, J. E. Cichanowicz, Initial Identification of Unit Errors in Integrated P lanning Model (IPM) Runs (Oct. 7, 2011)” (EPA

HQ

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- 4823) p. 51

- 52]
Comment : EPA is proposing to address errors in the CSAPR unit allowance allocation files, in which Oak Grove Unit 2 was receiving allowance allocations from the main allocation pool even though (as pointed out by the October 2011 Report), Oak Grove Unit 2 entered commercial operation after January 1, 2010, and thus should be receiving its allocations from the new unit set

- aside. EPA is proposing to correct this error by assignin g Oak Grove Unit 2 to the new unit set

- aside. [Unit Errors in the Integrated Planning Model (IPM) Runs for the Final Cross

- State Air Pollution Rule (CSAPR): A Comparison of Errors Addressed by EPA’s Proposed Revisions to CSAPR and Errors Identified by Rulem aking Participants (Nov. 28, 2011)” (EPA

- HQ

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- 4823) p. 4]FIP Revisions

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69 RESPONSE : Regarding Oak Grove Unit 2, the commenter acknowledges that a technical revision is proposed and is finalized by this rulemaking. Regarding Spruce Unit 2, the unit was repor ted as commercially operational on November 22, 2009 and classified as an existing unit. Regarding the 16 new gas

- fired units, qualification for inclusion under the rule can be determined through an applicability determination. A potentially regulated en tity can request a determination of applicability from EPA at any time. If the unit is determined to be subject to the FIP and it has not been allocated allowances, then it can be allocated allowances from the state's new unit set

- aside. Criteria for appl icability are described in the preamble s ection VII.B of the final Transport Rule (76 FR 48208, August 8, 2011). The formal applicability determination process provisions can be found at 40 CFR 97.404(c), 504(c), 604(c), and 704(c). The commenter did not provide any specific data on the units, so no further revision can be made in this action

. Issue 1.8: Other States/Unit Operational Issues
Points Raised: (A) Additional corrections are required to provide additional allowances for units that provide anci llary services necessary to support grid stability and reliability. Comment (A)(1) : Commenter (AEP) notes that they have a number of units within their system that EPA projects will not run within the 2012 IPM policy case. EPA should provide additional allowances for these 22 AEP units, which are utilized for spinning reserves, voltage support, black start capability, and other ancillary services necessary to support grid stability and reliability. AEP provides additional discussion as well as unit

- spec ific information as an attachment to their comment letter (and adds that the information provided should be treated as Confidential Business Information). AEP EGUs dispatch into two distinct regions, SPP and PJM and has provided (in their CBI hard copy on ly attachments) the "must

- run" conditions for AEP's units in these two systems. Due to the need to operate these units to address reliability

- related issues, the IPM model output of ZERO operation for these units is not a reasonable prediction of future a ctual operation or emissions, and substantially understates actual historic operation of these units. Also, since AEP acts as a balancing authority and needs to maintain capacity and reserves to meet load obligations, any of the AEP SPP units may be commi tted to the day

- ahead capacity market and run real time to meet load and reserves. In some cases, these units may be a more economical alternative than other options and in other cases they may be the only option available to maintain reserves and meet tr ansfer limitations between PSO and SWEPCO. AEP provides an estimate of expected unit operation in 2012 based on the models AEP commonly uses to project future system operations, to develop fuel forecasts, and for internal budgeting purposes. Using EPA em ission factors for NO X and AEP projections for SO 2 emission rates, AEP projects total emissions for the units in question and provides the resulting state

- specific budget adjustments for the affected states (i.e., the projected emission totals should be ad ded back into the respective state emissions budgets as technical corrections). [Letters: AmericanFIP Revisions

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70 Electric Power (EPA

- HQ

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- 2009

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- 4737) p. 3

- 5; American Electric Power (EPA

- HQ

OAR

- 2009

- 0491

- 9000) p. 51]
RESPONSE : EPA has revised the relevant stat e budgets in response to these concerns. See the Final Revisions Rule State Budget s and New Unit Set

- Asides TSD. (B) Supports allowance increases in Louisiana and other states to account for non
economic generation in out
- of
- merit
- order dispatch areas but o pposes any automatic downward correction to offset previously established generation and emissions levels as a result of these changes. Comment (B)(1) : A downward adjustment is not a logical extension of the technical revision. For example, the IPM Ente rgy model region covers five separate states, including Louisiana. EPA has demonstrated in the policy case that this region is a net importer of power. While EPA needs to account for the out

- of

- merit

- order dispatch of existing units in each state, they c annot assume that other generation in the same state will be displaced. Even with the generation and heat input corrections, EPA is still projecting that Louisiana will produce significantly less electricity than historical levels. Based on EPA's policy case (which shows that Louisiana's generation in 2012 was 27% below the level of generation in 2010), one cannot infer that the power supplied from the corrected unit's non

- economic dispatch is in fact displacing generation from natural gas combined cycle units within the state of Louisiana. Due to the complexity of grid interconnections and the localized transfer limitations within the grid, it is impossible to determine where displaced generation is coming from on a state

- by

- state basis. This downward c orrection to the state budgets should be eliminated within the final state budget determinations for all states. EPA should correct the state budgets to account for real

- world reliability needs without making adjustments that have no basis in fact. [Lett ers: American Electric Power (EPA

- HQ

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- 0491

- 4737) p. 3]
RESPONSE : For an explanation of EPA’s methodology and rationale for offsetting revisions that increase generation at units, see section 6.1b, below, of this document. (C) Additional budge t changes are required to reflect the infeasibility of LNB controls based on timing issues and control costs. Comment (C)(1) : EPA assumes that a significant number of LNB installations could occur by 2012 within the CSAPR policy case and estimates signif icant reductions in seasonal and annual NO X relative to the base case. However, completing the assumed number of LNB installations is technically infeasible due to permitting issues, equipment availability, and construction scheduling issues. These conce rns are exacerbated for states included within the supplemental proposal (not yet finalized). As such, a technical correction is needed to adjust state budgets upwards to reflect that these projects cannot be feasibly completed by the 2012 deadlines. Als o, the installation of LNB equipment on certain units represents a cost far in excess of the cost

effectiveness thresholds used to establish the state

- level budgets. New low NO X burners at AEP's Northeastern Units 3 to 4 in Oklahoma have a levelized cost removal that's greater thanFIP Revisions

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71 $1,800 per ton. The high cost and timing issues indicate that this project should not have been included in the policy case. If EPA finalizes the supplemental proposal, the emission reductions associated with these retrofits ( 1,749 tons seasonal NO X ) should be added back into the Oklahoma budget. This adjustment would reflect the infeasibility of installing new controls and the excessive cost of those controls compared to the cost thresholds in the final rule. [Letters: Amer ican Electric Power (EPA

- HQ

- OAR

- 2009

- 0491

- 4737) p. 6

- 7; American Electric Power (EPA

- HQ

- OAR

- 2009

- 0491

- 9000) p. 51]
RESPONSE : See the Supplemental Final Rule (76 FR 80760, December 27, 2011) regarding the Oklahoma state budget in 2012. EPA increased the 2012 Oklahoma budget between the proposed and final supplemental rulemaking to account for no LNB being installed in 2012. The Response to Comment document for that rulemaking also addressed the cost issues raised above. Comment (C)(2) : EPA apparently assumes that Georgia Power’s Plant Kraft installs low NO X burners by January 1, 2012 to lower the NO X emission rate from 0.63 lb/mmBtu in the base case to 0.27 lb/mmBtu in the remedy case. As explained in more detail in UARG’s petition for reconsideration , low NO X burner installations cannot occur by 2012. Additionally, a simple burner retrofit would not likely achieve the 0.27 lb/mmBtu emission rate. Any control strategy would have to be more aggressive and the retrofit would likely take even longer. [ Letters: Southern Company (EPA

- HQ

- OAR

- 2009

- 0491

- 4744) p. 13]
RESPONSE : See s ection VII of the f inal Transport Rule preamble (76 FR 48208, August 8, 2011) for a discussion of the feasibility of LNB installation and 2012 compliance. Moreover, EPA notes t here is no unit

- level requirement that the facility install such combustion control devices in 2012. (D) EPA should adjust in
- service dates for projected FGD or dry sorbent injection installations. Comment (D)(1) : EPA needs to adjust the assumed in ser vice dates for FGD or dry sorbent injection in the 2014 policy case. A number of AEP units are projected to be retrofit with either FGD or DSI in the 2014 policy case but this is not technically feasible. AEP has not received the necessary regulatory app rovals for any of the projects, which is a prerequisite to the detailed engineering and procurement steps that precede construction. In addition, AEP has no operational experience using DSI for SO 2 reductions and the U.S. power industry as a whole has lit tle experience using this technology to achieve emission reductions of the magnitude assumed in the IPM modeling. None of the AEP units identified in the IPM runs are currently anticipated to be equipped with DSI technology. Without unit

- specific testin g and technology validation, EPA has not made a sufficient record to justify including DSI as a universally available solution. AEP provides tables that summarize specific revisions that EPA should incorporate with respect to both FGD and DSI corrections. [Letters: American Electric Power (EPA

- HQ

- OAR

- 2009

- 0491

- 4737) p. 10

- 11; American Electric Power (EPA

- HQ

- OAR

- 2009

- 0491

- 9000) p. 52]FIP Revisions

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72 RESPONSE : EPA’s IPM analysis of the final Transport Rule scenario predicted a modest 6 GW of FGD and 3 GW installation of DSI in 2014 in response to the economic incentives created for Group 1 states under the Transport Rule. Section VII of the final Transport Rule p reamble and the Response to Comment document for that rulemaking in the docket address the feasibility of F GD installation. Moreover, the Transport Rule places no individual emission reduction requirements on units. Regardless of whether EPA’s economic modeling predicts a particular retrofit at a given unit, that unit is by no means expected or required to ma ke that retrofit. There are multiple compliance options available to each unit under the Transport Rule due to the flexibility of the rule being administered as an allowance trading program. EPA even conducted sensitivity analysis demonstrating that stat es could comply with the 2014 Transport Rule emission caps without any incremental FGD retrofit. (E) EPA should correct the emission rates and allocations for units wrongly assumed to burn biomass. Comment (E)(1) : EPA should correct the emission rates and allocations for 33 AEP units wrongly assumed to burn biomass in 2012. Specifically, AEP recommends that a technical correction be made to the state budgets based on the use of biomass within certain coal

- fired facilities (i.e., Cardinal 3, Clifty Cree d 1

- 6, Clinch River 1

- 3, Conesville 3, Glen Lyn 5

- 6, Kammer 1

- 3, Kanawha River 1

- 2, Muskingum River 3

- 5, Oklaunion, Sporn 1

- 4, Rockport 1

- 2, Tanners Creek 1

- 4, and Beckjord 6 all have some "missing" coal heat input which is described by EPA as "other fuel" ). This "other fuel" in most cases is biomass. None of these units have a reliable source of biomass fuel and have not been permitted to burn biomass by the state regulatory authorities, nor have they implemented any physical improvements to allow proper handling of these materials. AEP provides a table showing the incremental allocations that should be made to eliminate the emission reductions associated with the use of biomass at these units, amounting to 11,536 tons SO 2 emissions that should be reesta blished in state budgets for the 2012

- 2013 compliance years. AEP also concludes that based on IPM's projected total biomass use at coal

- fired units of 240 TBtu, up to 47,000 tons of SO 2 should be restored to state budgets based on these erroneous assumpti ons. [Letters: American Electric Power (EPA

- HQ

OAR

- 2009

- 0491

- 4737) p. 7

- 8; American Electric Power (EPA

- HQ

- OAR

- 2009

- 0491

- 9000) p. 51

- 52]
RESPONSE : Commenters themselves have noted that it is not impossible for them to burn biomass, but rather that th ey have not done so in the past or have not previously modified any permits accordingly. Such arguments do not prevent the limited biomass consumption modeled in IPM from representing a feasible option among a portfolio of options available to coal

- fired units for managing emissions under the Transport Rule programs. 2

2 A limit of biomass co

- firing is expressed in EPA IPM v.4.10 model as a maximum of 10% of the facility level power output (not to exceed 50 M W) that can be sustained by biomass. See Section 5.3 of the IPM documentation for a more complete discussion of biomass co

- firing. EPA notes that lengthy documentation in trade press and power engineering journals demonstrate that biomass co

- firingFIP Revisions

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73 in coal

- fired boilers is an available, commercially proven technology. 3 More importantly, EPA notes that the Transport Rule provides the flexibility, through its trading mechanism, for sources to comply with the rule requirements through a variety of strategies. There are no source

specific requirements for biomass consumpti on. Therefore, if a unit operator feels that biomass co
- firing is not a cost

- effective emission reduction strategy for that given unit, the operator is entirely free not to do so. EPA’s modeling projections demonstrate that there are multiple low cost co mpliance strategies available to every unit that do not require increased biomass utilization. Moreover, there is very little predicted co

- firing biomass driven by the Transport Rule. Most of the co

- firing biomass projected is a predicted compliance str ategy for sources to deal with collective Renewable Portfolio Standards. Therefore, if sources elect a less intensive co

- firing RPS compliance strategy than that predicted by EPA, the co

- firing generation would be replaced by other forms of non

- fossil gen eration, not simply by more coal generation as suggested by many commenters. Because the substituted generation would not have corresponding SO 2 or NO X emissions, there would be no basis for a budget adjustment as suggested by commenter. Section 3.9 and Appendix 3.6 of EPA’s IPM Documentation explain how IPM modeling relies on AEOs 2010 assumptions regarding Renewable Portfolio Standards. Comment (E)(2) : It appears from the “rpe” file in the record that hundreds of coal

- fired units (in addition to tho se commenter (Luminant) identifies in Texas) are also modeled as co

- firing biomass, and thus the impact to SO 2 budgets across all CSAPR States is much greater than just the impact to Texas. It is not possible during the short comment period for the Propos ed Revision for a third

- party like Luminant to extract the pertinent data from the “rpe” file to determine how much biomass is erroneously attributed to units in all of the CSAPR States. Other commenters have raised this issue for their particular States (e.g., Southern Company). Luminant evaluated the remedy parsed file and identified 64 coal

- fired units in SO 2 Group 2 that had a higher total heat input than coal heat input, indicating that biomass was added to their fuel mix by EPA’s model and the total generation attributed to biomass was 4,677 GWh, 4.8% of the total heat input for these units. If these units do not actually burn biomass, this is a substantial error in EPA’s remedy case calculations, meeting even EPA’s arbitrary threshold for a “materi al” error. EPA should not assume that biomass co

- firing is a fuel choice for all coal

- fired power plants, when clearly that is not the reality. Rather, EPA should only attribute biomass to units

3 http://38.96.246.204/cneaf/solar.renewables/page/rea_data/table1_9.html http://www.americancoalcouncil.org/displaycommon.c fm?an=1&subarticlenbr=162 http://www.et.byu.edu/~tom/classes/733/Biomass/biomass

- cofiring.pdf http://www.globalbioenergy.org/fileadmin/user_upload/gbep/docs/2010_events/7th_TF_Sustaina bility__The_Hague__17_19_March_2010/20100318_Amer_Presentation_GBEP_Dele gation.pdf http://www.eia.gov/oiaf/analysispaper/biomass/ http://www.fs.fed.us/ccrc/topics/urban

- forests/docs/Biopower_Assessment.pdf http://www1.eere.energy.gov/femp/pdfs/fta_biomass_cofiring.pdfFIP Revisions

- RTC Febru ary 7 , 2012 Page 74

74 that have permit approval to burn biomass, an adequate supp ly of such fuel, and some historical practice of using this alternative fuel. After identifying such units, EPA should adjust its modeling and revise each State’s SO 2 budget accordingly. [Letters: Luminant (EPA

- HQ

- OAR

2009

- 0491

- 4818) p. 23

- 24]
RESPONSE : See Response in section 1 .8(E)(1) above. (F) EPA should correct errors in the final rule with regard to fuel switching assumptions, which has led to flawed allocations and/or state budgets. Comment (F)(1) : In its hearing testimony, AEP states that v ery low sulfur fuel is only available from a selected number of mines in Wyoming and Montana. The 20 percent production increase in the 2012 policy case is not technically feasible. EPA needs to correct its projection of the amount of fuel switching that can occur by 2012. [Letters: American Electric Power (EPA

- HQ

OAR

- 2009

- 0491

- 9000) p. 52]
RESPONSE: EPA’s IPM modeling, which supported the Transport Rule analysis, already projects consumption of low

- sulfur coal in 2012 (415 million tons) to be lower t han production of low

- sulfur coal in 2010 (423 million tons). AEP’s assertion that EPA wrongly assumed that mines supplying very low sulfur coal could increase output quickly is incorrect. EPA’s Transport Rule modeling projects lower use of low

- sulfur co al in 2012 compared to 2010 production. Low sulfur sub

- bituminous coal can be further subdivided into relatively “lower” low sulfur coal (sulfur content below 0.08 lbs/mmBtu) and relatively “higher” low sulfur coal (sulfur content above 0.08 lbs/mmBtu). EIA data from 2010 demonstrates that U.S. production of low sulfur sub

- bituminous coal is skewed toward production of coal in the former category. EIA data demonstrates that 339 million tons of “lower” low sulfur sub

- bituminous coal with sulfur content lo wer than 0.08 lbs/mmBtu were produced in 2010, and 84 million tons of “higher” low

- sulfur sub

- bituminous coal with sulfur content higher than 0.08 lbs/mmBtu were produced in that same year. The coal supply curves that are implemented in EPA modeling were reviewed independently by industry experts and were available for two rounds of public review during the Transport Rule development process in 2010. See also response to UARG comment letter, “J. Marchetti, J. E. Cichanowicz, Initial Identification of Un it Errors in Integrated Planning Model (IPM) Runs in section 1.3 above regarding coal switching and SO 2 emission rate projections. Comment (F)(2) : EPA has made erroneous assumptions about fuel switching in the final rule. These errors alone potentially impact Georgia’s SO 2 budget by 50% in 2012 and must be corrected. In the proposed technical adjustments, EPA acknowledged that IPM did not dispatch certain must

- run units in the way that they must operate, resulting in sometimes significantly skewed gener ation projections and state emission budgets. Similarly, with respect to the erroneous coal

- switching, IPM dispatches several units to run in a way that they cannot. Said another way, IPM fails to dispatch several units in the way that they must operate

– on the coal that the company has already purchased and committed to. Georgia’s budget is significantlyFIP Revisions

- RTC Febru ary 7 , 2012 Page 75

75 flawed and unrealistic due to this error. Several Georgia Power units are switched to a very low sulfur bituminous coal in 2012, despite the fact tha t they were already majority committed to coal contracts when the proposed rule came out (which Southern called to the Agency’s attention in its comments on the proposed rule and NODAs) and fully committed by the time the final rule came out. These units “must run” on the purchased coal, not the very low sulfur bituminous coal EPA models. In addition, some units have constraints on the sulfur level in the coal related to ESP operation. Whether IPM fails to dispatch a unit because it did not recognize “mu st run” constraints or whether IPM fails to dispatch a unit on the committed coal, the impact is the same. In both cases, the emissions are drastically underestimated. Southern Co. provides significant additional discussion on this issue and provides sev eral specific reasons why Georgia Power's fourteen unscrubbed units will not and cannot switch to the very low sulfur bituminous coal that EPA assumes, including: 1) there is simply not enough of the assumed coal available in 2012 and 2013; 2) the coal is not available at the prices EPA assumes (i.e., $54/ton, despite the fact that it is being exported at prices over $230/ton); 3) even if available, the fourteen units would not be able to switch to the assumed coal for less than $500/ton SO 2 (IPM erroneous ly assumes that the coal is available at 25% of market price and artificially inflates the number of tons that would be removed); and 4) the units at Plant Branch and Yates Units 2, 3, 4, and 5 cannot burn this particular coal type without opacity issues ( they must consider the impacts on ESP performance when the fuel sulfur content drops below about 1%). Southern Company concludes that EPA's modeled coal switches for Georgia are an absurd projection and they undermine the credibility of the IPM. [Letters : Southern Company (EPA

- HQ

- OAR

- 2009

- 0491

- 4744) p. 9

- 12]
RESPONSE : See response to in section 1 .3 above regarding coal switching and SO 2 emission rate projections. Comment (F)(3) : Xcel Energy and others previously asked that EPA recognize and reward pr oactive emissions reductions under programs like the MERP through early reduction credit, which would reward states and companies (like NSPM) that have taken on the burden of early emissions reductions and encourage other states and companies to follow sui t. In the final CSAPR, EPA responded to this request by using historic heat input from 2006 to 2010 as the basis for individual unit allowance allocations, capped by maximum historic emissions between 2003 and 2010. Thus, any plant that has reduced its e missions through emission controls or fuel switching during the baseline period would receive an allocation undiminished by its recent emission reductions, which rewarded some plants but denied plants like High Bridge and Riverside (which were converted fr om coal to natural gas combined cycle technology) the benefits of this allocation methodology. EPA dramatically limited the High Bridge and Riverside allowance allocations by basing them solely on the plants’ post

- conversion heat input and then capping th e allowances at the plants’ maximum post

- conversion emissions. The post

conversion emissions were much lower than the pre

- conversion emissions because they reflected only gas

- fired operation as opposed to coal

- fired operation. However, the conversions we re accomplished during EPA’s selected baseline period and, as a result there were years with pre

conversion heat input and emissions data during EPA’s baseline period. This allocation methodology, which ignored the pre

- conversion emissions and heat input data, awarded High Bridge and Riverside no credit for the enormous reductions in emissions due to the conversionFIP Revisions

- RTC Febru ary 7 , 2012 Page 76

76 from coal to natural gas. Commenter provides additional discussion and requests that EPA recalculate the allocations using the pre

- conversion heat input and emissions for those plants. [Letters: Northern States Power Company, MN (NSPM) (EPA

- HQ

- OAR

- 2009

- 0491

- 4751) p. 1

- 3]
RESPONSE : EPA considers units that are entirely replacing pre

- existing units to be a different unit. The pre

- existing uni ts are considered retired, and EPA does not allocate allowances to units that were retired at the time of Transport Rule finalization. Additionally, changes to the allocation methodology are out side the scope of the revisions proposed and upon which EPA s olicited comment (76 FR 63860) . See Section 6.5 , below , for more information. Comment (F)(4) : Commenter recommends a technical correction to the Indiana state budget to restore missing coal heat input that was assumed to be other fuel

- biomass in IPM. The 2012 final remedy case for Clifty Creeks Units 1

- 6, as well as numerous other AEP plants have some "missing" coal heat input which is described by EPA as other fuel. The Clifty Creek units currently have no reliable source of biomass fuel, nor have t he units been permitted to burn biomass by Indiana. In addition there have been no physical changes to allow proper handling of these materials. A table is provided with the incremental changes in unit allocations. While they cannot positively assert t hat biomass cannot be utilized, they have not pursued this and instead already installed SCRs on 5 of the 6 units, and are in the process of installing wet FGD systems on all 6 units. The FGD systems are 60% complete, but will not be complete in time to m eet the 2012 compliance date. Accordingly, commenter asks that the Clifty Creek unit emissions be restored to the Indiana state budget along with any other applicable emissions based on similar erroneous concerns. [Letters: Ohio Valley Electric Corporat ion and Indiana Kentucky E (EPA

- HQ

- OAR

- 2009

- 0491

- 4794) p. 3

- 4]
RESPONSE : EPA did not model FGD operating at Clifty Creek in 2012. It only projects it to be online and operating in the 2014 Transport Rule scenario. In regard to the biomass issue, see r esponse to American Electric Power in section 1 .8(E)(1) above. Comment (F)(5) : Alter analyzing EPA's Integrated Planning Mode] ("IPM") runs for Homer City Station, the commenter believes that it is clear that EPA made incorrect assumptions about the faci lity's ability to switch to low

- sulfur coal and to use biomass, and hence miscalculated the reductions that are feasible by 2012. If EPA overestimated the emission reductions that can be achieved at the Homer City facility by 2012, it must have under calc ulated Pennsylvania's Phase I SO; budget. EPA`s IPM modeling of Homer City was flawed in the in the following respects. EPA's base case assumptions regarding the SO 2 content of coal utilized at Homer City Station Units 1

- 3 greatly understate the SO 2 cont ent of coal actually consumed at the facility. In calculating this average facility rate, EPA's base case assumes use of 2.34 lb/mmBtu SO 2 content coal at Homer City Units I and 2 and 4.23 lb/mmBtu SO 2 content coal at the Unit 3. EPA's base case assumpti ons, however, contrast starkly with actual coal deliveries at Homer City. In 2010, for example, the actual SD; content of coal used at Homer City Units I and 2 varied from aFIP Revisions

- RTC Febru ary 7 , 2012 Page 77

77 minimum 2.73 lb/mmBtu to a maximum of 3.46 lb/mmBtu with an average SO 2 content of 3.11 lb/mmBtu. This represents an average SO 2 content more than 32% greater than EPA's modeled base case even after coal deliveries to Homer City have been washed to reduce SO 2 content prior to combustion. EPA's modeling errors are not confined to one aberrant year of coal consumption. Between 2006 to 2009, minimum SO 2 content for Homer City Units 1 and 2 ranged from 2.57 lb/mmBtu to 3.19 lb/mmBtu, and had an average annual SO 2 content (for both units) of between 2.91 lb/mmBtu and 2.88 lb/mmBtu. In t he same years, the average annual SO 2 content of fuel used at Unit 3 ranged from a low of 4.4 to 4.88 lb/mmBtu. Thus, over the last four years contained in EPA's base case analysis, the actual SO 2 content of fuel consumed at all units at Homer City was al ways above the SO 2 content contained in EPA's modeling. Errors in EPA's base case modeling carry over with regard to EPA's IPM projections of Homer City's operations after the constraints imposed by CSAPR. Commenter goes on to describe facility coal use in relation to the projections in the same detail. They end by also pointing out that the facility has not burned biomass in the past nor have they conducted tests of the combustion of biomass, while EPA has projected that biomass can replace 2% of coal b ased electric generation at Homer City. EPA's modeled use of biomass at Homer City is without foundation. EPA should address its overestimation of the SO 2 reductions that can be achieved at Homer City, and reassess its model assumptions and recalculate s tate emission budgets and individual unit allocations accordingly. [Letters: Homer City Owner Lessors LLC (EPA

- HQ

OAR

- 2009

- 0491

- 4816) p. 3

- 6]
RESPONSE : See section 6.2(c) of this document , below, for information addressing SO 2 emission rates. As rega rd s biomass consumption, see response in section 1 .8(E)(1) above. (G) The existing blending ratios for coal
- fired units should be retained as a basis for calculating state budgets during the 2012 and 2013 compliance years. Comment (G)(1) : Several units within Indiana in which AEP has an ownership interest, Clifty Creek units 1

- 6 and Rockport units 1

- 2 are projected to use 100% subbituminous coal in the 2012 policy case, but this is based on an erroneous assumption. These units have historically burned coal blends that include just 75% and 85% subbituminous coals, respectively. Additionally, Cardinal unit 3 is projected to use 100% PRB coal but its current maximum blend ratio is 20%. The existing blending ratios should be retained for 2012 and 2013 st ate budget calculations given existing coal supply contracts, safety considerations that arise with higher ratios of low sulfur coal and other operational limitations that may impede higher blending ratios. [Letters: American Electric Power (EPA

- HQ

- OAR

- 2 009

- 0491

- 4737) p. 9]
RESPONSE : See section 6.1c , below , of this document for information addressing SO 2 emission rates.FIP Revisions

- RTC Febru ary 7 , 2012 Page 78

78 Comment (G)(2) : In addition to incorrect blends of subbituminous coal being projected for the Rockport units 1

- 2, Clifty Creek units 1

- 6 (IN) and Cardinal unit 3 (OH), these also projected to use very low sulfur subbituminous coal in the 2012 policy case for 100% of their coal use. This coal is only produced from a select number of mines in WY and MT and AEP questions whether the assu mption in the 2012 policy case showing a 20% increase in production is technically feasible. A more reasonable technical assumption is that units could only rely on this very low

sulfur subbituminous coal in 2012 to the extent they have used it historical ly, due to production, contractual and transportation issues. AEP refers to their previous comments on this issue (AEP Request for Reconsideration and Stay, pp. 13

- 16; October 3, 2011) and provides a table with the approximate 2011 use of very low sulfur coal at the aforementioned units as well as recommended changes to emission budgets based on the very limited availability of this very low sulfur fuel (and their recommendation to keep the blend ratios at historic levels). AEP recommends that EPA follow similar logic for the rest of the U.S. and assume that incremental fuel switching to very low sulfur coals could not occur by 2012. AEP adds that according to IPM data, the policy case assumes an additional 694 TBtu of very low sulfur subbituminous coal c ould be produced by next year and delivered for use at generating stations all over the region and given that significant increases in production of this coal cannot occur by next year, it is likely that a much broader range of low sulfur subbituminous coa ls will be used. [Letters: American Electric Power (EPA

- HQ

- OAR

- 2009

- 0491

- 4737) p. 9

- 10; Ohio Valley Electric Corporation and Indiana Kentucky E (EPA

- HQ

- OAR

- 2009

- 0491

- 4794) p. 4

- 5]
RESPONSE : See response above to American Electric Power in section 1.8(E )(1). (H) The state budgets are based on significant errors in EPA's Base Case assumptions. Comment (H)(1) : Many assumptions and errors in the base case model runs (i.e., 2012 and 2014 without CAIR or CSAPR) dramatically reduce the Agency’s starting po int for making emission reductions and thereby directly reduce the state budgets. Commenter (Southern Co.) notes that most of these errors are not new and that they have commented previously on the errors, which affected the base case projections. Specif ically, Southern commented on: (i) errors in pollution control installation dates; (ii) premature unit retirements; (iii) an erroneous biomass fuel switch assumption; and (iv) an assumed substantial drop in projected fossil fuel generation and fossil fuel heat input. EPA neither fixed these errors nor responded to these comments. Commenter provides significant additional discussion on these issues, including details on which units are affected and the changes that need to be made, and references their pre viously submitted comments on these issues (submitted in October 2010 and provided for reference as Attachment B). The comments on errors in pollution control installation dates pertain to the following Georgia Power units: Branch Units 1, 2, and 4; Yates Units 6 and 7; and Scherer Unit 1 (these units will have SCRs and FGDs installed when required by Georgia's Multi

- Pollutant Rule, which is well after EPA's assumed date of January 1, 2014). In addition, commenter notes that EPA added an SCR to Crist Unit 6 with a start

- up date in 2012, but that SCR is not "Dispatchable"

- it is operated year

- round. The comments on premature unit retirements refer to Georgia Power's Plant McDonough Unit 1 which will retire on April 30, 2012 (not January 1, 2012 as EPA ass umes). The incorrect biomass conversion issue pertains to Georgia Power'sFIP Revisions

- RTC Febru ary 7 , 2012 Page 79

79 Plant Mitchell Unit 3, which will not convert from coal to biomass until late 2015 (not January 1, 2012 as EPA assumes) due to uncertainty surrounding EPA's Industrial Boiler MACT. Commenter also reiterates their comments on incorrect fuel assumptions for Georgia Power's Plant Yates Units 6 and 7 and Plant McIntosh Unit 1 (actual 2010 rates were more than twice as high as EPA has assumed since the Agency incorrectly identified these units as subject to NSPS Subpart D). Finally, substantial changes in generation and heat input are required for units in Georgia , Mississippi, and Florida (see subsequent summary and discussion in Sections 2.1 and 2.2). [Letters: Southern Company (EPA

- HQ

- OAR

- 2009

- 0491

- 4744) p. 4

- 9]
RESPONSE : In regard to the pollution control installation dates, EPA explained i n the final Transport Rule its intent to capture “reductions that occur due to state rules, consent decrees, and other planned changes in gene ration patterns that occur after 2012, but during or prior to 2014” in the 2014 state budgets (76 FR 48261). Commenters on the revisions rule noted that EPA inadvertently included pollution control installation requirements from a Georgia state rule whose deadlines at certain units actually extend beyond 2014. To correct the alignment of the Georgia 2014 state budgets with the requirements for affected units in Georgia to install controls by the state rule’s deadlines, EPA intends to increase Georgia’s 20 14 state budgets in a separate action

. See the Final Revisions Rule State Budgets and Ne w Unit Set

- Asides TSD in the docket to this rulemaking. In regard to unit level retirements, EPA does not take partial year operation into account. See r esponse to Am erican Electric Power ( (EPA

- HQ

- OAR

- 2009

- 0491

- 4737) p. 7

- 8; (EPA

- HQ

- OAR

- 2009

- 0491

- 9000) p. 51

- 52 ) in section 1 .8(E)(1), above, in regard to the biomass issue. As to the fourth issue raised above, regional demand in IPM modeling is based off AEO projection s as described in the IPM documentation. In regard to comments directed to coal switching, please see section 6.2.c , below , a s well as the Declaration of Sam Napolitano dated October 13, 2011, filed in support of EPA's opposition to motion filed by the St ate of Texas, et al., EME Homer City Generation v. US EPA, and consolidated cases, No. 11

- 1302 (D.C. Cir.) which can be found in the docket for this rulemaking , for additional discussion. Comment (H)(2) : The final budgets are based on significant unexpla ined reductions in generation and heat input, particularly in Georgia, Mississippi, and Florida between the proposed and final rule. Ozone season heat input in the 2012 base case for the CSAPR

- affected units shows a decrease in Georgia, Mississippi, and F lorida compared to 2010 actual heat inputs. Although Alabama’s total generation is projected to slightly increase approximately 5%, the other states drop dramatically, as much as 39% in Mississippi. The projected reductions are inconsistent with historic al data and are unusual even in absolute terms. Commenter references their comments previously submitted in response to EPA's first NODA and asserts that EPA has not adequately responded to those comments. Commenter provides actual total megawatt hours g enerated from 2001 to 2010, which demonstrates that generation increases each year except during 2008 and 2009. EPA erroneous reductions in projected heat input cut the state budgets and resulting allowance allocations making state by state compliance exc eedingly difficult. Commenter provides significant additional discussion (including specific percentages and heat input assumptions) that reiterates their concerns on this issue and asserts that if the Agency decides to continue to rely on these assumptio ns, it must document the reasons for that decision. [Letters: Southern Company (EPA

- HQ

- OAR

- 2009

- 0491

- 4744) p. 6

- 9]FIP Revisions

- RTC Febru ary 7 , 2012 Page 80

80 RESPONSE : EPA conducted this revisions rulemaking process to address technical information provided by stakeholders and commenters demons trating where EPA’s quantification of state budgets under the Transport Rule was inconsistent with immediate

- term post

- combustion control configurations or non

- economic operational constraints at specific units subject to the rule’s emission reduction prog rams. EPA notes that this specific comment fails to indicate any such technical concerns at covered sources in the states referenced. The IPM load growth is derived from data from the AEO 2010 load factors and estimated energy demand projections (as des cribed in Chapter 3.2.2 of the IPM v.4.10 Documentation) , an authoritative source within the energy modeling community. The EIA data incorporates assumptions about short

- and long

- term growth and macroeconomics, yielding a growth rate that evolves over tim e to reflect economic recovery and growth (IPM Documentation section 2.3.5; EPA

- HQ

- OAR

- 2009

- 0491

- 4294)

. The model dispatched generation to meet this demand, subject to the other constraints of the model. EPA disagrees that the state budgets will make co mpliance exceedingly difficult. Compared to their 2011 ozone season emissions and incorporating all of the revisions described in the “Final Revisions Rule State Budgets and New Unit Set

- Asides TSD,” Florida would need to reduce its emissions less than 4 percent , Mississippi less than 8 percent , and Georgia already emitted significantly less than their 2012 budget in 2011. In terms of SO 2 , Georgia’s 2011 emissions were only 10 percent above its 2012 budget. Comment (H)(3) : As part of WPSC’s analysis of the rule, the 2012 base case SO 2 results from all of the Cross

- State Rule states were compared with 2010 actual emissions from those states. This simple analysis helps to gauge the accuracy of EPA's IPM base case modeling and to determine whether base ca se errors were pervasive. A table with the results is included in the comment, and show that EPA's projected base case SO 2 emissions in 2012 are not even reasonably close to actual 2010 emissions in many states. These results also show that EPA's IPM bas e case model determined that total SO 2 emissions from all of the states would be approximately 7.4 million tons in 2012, when actual SO 2 emissions in those states in 2010 were 4.7 million tons. While it is possible that this huge discrepancy between EPA's modeled base case and reality is based on EPA's assumption that no CAIR

- related controls will run in 2012, it seems more likely that the wide disparity is in fact due to significant data errors (as it is in Wisconsin). [Letters: Integrys Business Suppor t (EPA

- HQ

- OAR

- 2009

- 0491

- 4757) p. 4

- 5]
RESPONSE : This analysis outlined by commenter illustrates a misunderstanding of what the base case is intended to capture. The base case is not designed to reflect 2010 values : 2010 was a year in which the Clean Ai r Interstate Rule (CAIR) was in place. As described in the preamble, EPA’s base case assumes in the baseline that CAIR is not in effect . Therefore, comparing the two as described in the comment above is comparing apples and oranges. (I) IPM does not ad equately address the concept of reliability, which is treated in a cursory, and largely economic, fashion.FIP Revisions

- RTC Febru ary 7 , 2012 Page 81

81 Comment (I)(1) : The IPM focuses on the economics associated with moving power between regions. In fact, the IPM assumes a perfect transmission wor ld once power passes through known regional "bottlenecks." Even assuming that the IPM's assumptions regarding regional transmission capacity are correct (which they are not), intraregional and more local constraints play an even greater role in relation t o reliability and deliverability. The IPM ignores local transmission constraints and "must run" generation. The utility industry has a saying: "Transmission is built with generation in mind." Generally speaking, generation is built as close as practicab le to the load it will serve. Transmission then runs from the generation to the load. The farther away load is from generation the more costly and difficult it becomes to reliably deliver electricity to load. The farther electricity must travel from its generation the greater the need for higher voltage transmission. At certain distances, "line losses" become unacceptable, and electricity cannot be reliably delivered. Well

- placed generation improves the overall operational efficiency and reliability of the transmission system. [Letters: Mississippi Public Service Commission (EPA

- HQ

- OAR

- 2009

- 0491

- 4746) p. 2

- 3]
RESPONSE : EPA believes it has appropriately considered both regional transmission limits and the cost (in the form of losses and transmission fees) of long distance transmission in arriving at state budgets. In view of the inherent flexibility of the allowance trading process at the state and regional level, these limitations on electricity transmission in the modeling, coupled with limits on r eserve margins in each region, ensure that the emissions budgets developed for this rule from the modeling are reasonable. Moreover, EPA recognizes that specific, local transmission conditions can impact immediate

- term generation dispatch and has made man y related targeted changes in state budgets when adequate information has been presented on the record on constraints or operating conditions. However, this comment does not contain adequate specific information to make such modifications and consequently does not require any action related to revisions. (J) EPA should accept and consider all comments that identify credible unit
- level technical errors regardless of their level of impact to a state's budget. Comment (J)(1) : Corrections should be made regardl ess of whether or not they will have a 1 percent state budget impact or whether the errors occurred in the 2012 or 2014 assumptions. The sum of various errors, whether large or small budget impacts, often led to state budgets that do not reflect real

- life expectations. EPA cannot arbitrarily set boundaries for correcting errors. If the error exists, then it must be corrected. The state budgets are based on significant errors in EPA's Base Case and Remedy Case assumptions. Commenter (Southern Co.) provi des specific comments that summarize all the errors that must be corrected, not just those that fall in EPA’s arbitrary categories. [Letters: Southern Company (EPA

- HQ

- OAR

- 2009

- 0491

- 4744) p. 3

- 4] Comment (J)(2) : Commenters do not agree with EPA that tec hnical corrections resulting in changes in a state’s budget that are less than 1 percent are not material. At a minimum, the determination of what changes might or might not be material must consider the size of a state’s budget, and cannot be based solel y on an arbitrary percentage. Commenters provide examples toFIP Revisions

- RTC Febru ary 7 , 2012 Page 82

82 illustrate this point. A 1 percent change in New Jersey’s 2012 SO 2 budget of 5,600 tons is 56 tons, while a 1 percent change in the 2012 SO 2 budget for Indiana is 2,854 tons. While 56 tons mig ht not be material, 2,854 tons most certainly is material, which is why applying an across the board threshold based solely on an arbitrary percentage is not appropriate. Instead of setting an arbitrary 1 percent threshold, EPA should accept and consider all comments that identify credible unit

- level technical errors regardless of their level of impact to a state’s budget. One commenter (UARG) adds that EPA's approach also ignores the possibility that there may be several unit

level errors in a single sta te of less than 1 percent each that, when combined, implicate more than 1 percent of the state budget. Commenter provides (as an attachment to their letter) a supplemental analysis completed by James Marchetti Inc. (JMI) that shows a broad range of errors and concludes that cumulatively, these errors could affect a large fraction of the state budget. Commenter provides additional discussion and examples of how this issue could lead to inaccuracies and asserts that EPA must accept and consider comments on all unit

- level errors and should defer the compliance dates until these problems are resolved. [Letters: Duke Energy (EPA

- HQ

- OAR

- 2009

- 0491

- 4768) p. 2; Utility Air Regulatory Group (EPA

- HQ

- OAR

- 2009

- 0491

- 4823) p. 7

- 9] Comment (J)(3) : There is no basis f or EPA's decision to limit comments to only those concerning a "material" impact which EPA defines as "at least 1 percent different from that budget's value" as calculated in the final rule. Defining a material impact is inconsistent with past EPA practic e, and EPA does not give any justification for the 1% material impact level which it considers on unit level or group of units under one entity. Apparently EPA has not given any thought about the impact of multiple errors. While a single unit may not mee t EPA's arbitrary 1% level, the combination of errors in a given state may far exceed this arbitrary limit. Also, this material impact stands in contradiction to EPA's stated collective contribution approach used in the previous NO X SIP Call and CAIR. In these rules EPA contends that you cannot ignore emissions from an individual source if by itself it may be insignificant, but must consider the collective contribution from all insignificant sources as the combined impact could be significant. EPA must c onsider submittals for corrections no matter how small as the collective contribution could have a significant impact on a state budget. [Letters: Ameren (EPA

- HQ

- OAR

- 2009

- 0491

- 4802); Luminant (EPA

- HQ

- OAR

- 2009

- 0491

- 4818) p. 16

- 17] Comment (J)(4) : EPA p roposes to accept unit

- level operational information which results in a change greater than 1% difference from the finalized CSAPR emission budget. The explanation of this approach in the rule making notice leads WDNR to believe that EPA is only consideri ng each correction individually for whether the resulting change is greater than the 1% threshold. That approach does not have merit. EPA should accept all changes which meet the aforementioned criteria and methodology used in determining significant con tribution under the finalized CSAPR. Obviously a number of corrections can yield a total change in the emission budgets greater than 1%. An example specific to Wisconsin is the faulty assumption of fuel switching from the current low sulfur fuel to ultra

- low sulfur fuels over multiple units. For one generation unit the resulting emission budget increase is likely less than 1% of the emission budget. However, correcting the fuel switch assumption over multiple units will have a largerFIP Revisions

- RTC Febru ary 7 , 2012 Page 83

83 impact. [Letters: Wisconsin Department of Natural Resources (EPA

- HQ

- OAR

- 2009

- 0491

- 4824) p. 7

- 8] Comment (J)(5) : Commenters support EPA's proposal to make technical corrections, but does not believe that the submissions should be limited to those that have material impac t on the budget. EPA completely ignores the fact that while an individual unit may not have a material impact, the cumulative effect of all units in a state with such new information quite possibly could have a material impact on the state's budget. EPA should consider the information submitted by all affected sources before determining whether the new information will be used to recalculate a state budget. Also EPA did not provide any justification or explanation for the 1% materiality threshold. Comme nters request an explanation why EPA decided to impose a materiality threshold, and/or justify the choice of 1%. [Letters: Lafayette Utility Systems (EPA

HQ

- OAR

- 2009

- 0491

- 4807) p. 20; Louisiana Chemical Association (LCA) (EPA

- HQ

- OAR

2009

- 0491

- 4803) p. 17] Comment (J)(6) : The 1% difference in state emission budgets that EPA is using to define materials impact is arbitrary and biased against states with larger budgets. The EPA should not be limiting the scope of comments on the proposed state budgets b y imposing an arbitrary 1% threshold of the state’s current budget for determining what the EPA considers to be material impact to the budget. The EPA has made significant errors in setting state budgets and, in the case of Texas, denied the state the opp ortunity to comment on that state budget until this proposed rulemaking. The 1% threshold also biases the public comment process in this rulemaking. The 1% threshold is even more biased against smaller companies within a state with a larger budget that als o has large corporations that control a greater percent of the total generation fleet within that state. For smaller utility owners, the 1% threshold could be a large percent of the EGU’s total emissions or possibly even exceed the emissions, thereby makin g it impossible for them to meet the EPA’s material impact threshold in their comments. [Letters: Texas Commission on Environmental Quality (EPA

- HQ

- OAR

- 2009

- 0491

- 4782) p. 2(cvr), p. 5]
RESPONSE : EPA considered all comments submitted and did not limit i ts review to those with an impact greater than 1 percent. (K) EPA should correct erroneous assumptions regarding NO X emission rates. Comment (K)(1) : Gulf Power Company’s operations are heavily penalized by the proposed NO X emission rates in the remedy case runs for 2012 and 2014. Commenter (Southern Co.) provides a table summarizing the unrealistic NO X emission rates that EPA has assumed for Gulf Power's Plant Crist Units 4 & 5 and Plant Smith Unit 1, all of which have SNCR, and for Plant Scholz Units 1 & 2. Commenter also notes that EPA has underestimated the overall emission rates and tons for Gulf Power’s system and provides a summary table comparing actual emissions and NO X rates with allocations and the corresponding EPA assumptions for the Remedy Cas e. Commenter notes specifically that under EPA’s final rule, Gulf Power’s annual allocation is 56% smaller than its actual 2010 emissions and that EPA models Gulf Power’s units to operate at aFIP Revisions

- RTC Febru ary 7 , 2012 Page 84

84 36% lower NO X emissions rate on average. [Letters: Southern Company (EPA

- HQ

- OAR

- 2009

- 0491

- 4744) p. 12]
RESPONSE : The controlled NO X base rate modeled for these units is very consistent with the emission rates reported by the units themselves. However, the controlled NO X policy rate for these units is adjusted do wnward as a result of combustion control (e.g. , LNB) upgrades or installation that would be considered economic at the cost thresholds modeled in the remedy scenario. The rates modeled are reflective of what other similarly

- configured units are achieving when installing such controls. Therefore, the rates modeled are derived, but different, from the historic rates observed at the units as noted by commenter. However, the change is not accidental (as assumed by commenter) but intentional and explained in section VII of the final Transport Rule preamble and the IPM v.4.10 documentation. Furthermore, the commenter ’ s notion that its allocations should cover its historic emission levels illustrates a misunderstanding of EPA’s FIP allocation methodology

— whic h is fully documented and explained in the final Transport Rule preamble (see 76 FR 48284, August 8, 2011 ) . Also, see section 6.2(b) of this document , below, for information addressing NO X emission rates. (L) Commenters provide control equipment and other m odeling corrections for Georgia units, and request changes to Georgia SO 2 and NO X budgets. Comment (L)(1) : The final CSAPR incorrectly assumes that Plant Scherer Unit 1, 60% owned by Oglethorpe Power, will have "dispatchable" SCR and FGD post

- combustion pollution control equipment installed on the unit by January 1, 2012. Georgia law requires the phased installation of specified post

- combustion control equipment. For Plant Scheyer Unit 1, installation and operation of SCR and FGD is required by December 31, 2014. Since installation and operation are not required until December 31, 2014, EPA should not have assumed the existence and operation of the SCR and FGD control for the 2014 modeling. EPA assumed the controls were operational on January 1, 2014. EPA should therefore adjust the 2014 SO 2 and NO X budgets for Georgia by the requisite amount to reflect that the Schere Unit 1 SCR and FGD systems are not required to be operational until December 31, 2014. [Letters: Oglethorpe Power (EPA

- HQ

OAR

- 2009

- 0 491

- 4749) p. 2]
RESPONSE : In the final Transport Rule, EPA explained its intent to capture “reductions that occur due to state rules, consent decrees, and other planned changes in generation patterns that occur after 2012, but during or prior to 2014” i n the 2014 state budgets (76 FR 48261). Commenters on the revisions rule noted that EPA inadvertently included pollution control installation requirements from a Georgia state rule whose deadlines at certain units actually extend beyond 2014. To correct the alignment of the Georgia 2014 state budgets with the requirements for affected units in Georgia to install controls by the state rule’s deadlines, EPA is increasing Georgia’s 2014 state budgets of SO 2 , annual NO X , and ozone

- season NO X . See the Final R evisions Rule State Budgets and New Unit Set

- Asides TSD in the docket for this rulemaking.FIP Revisions

- RTC Febru ary 7 , 2012 Page 85

85 Comment(L)(2) : MEAG objects to the shortfall of SO 2 emission allowances for Georgia and MEAG's facilities in the final Transport Rule, and EPA should initiate a su bsequent rulemaking to restore Georgia's 2012 SO 2 budget and unit level allocations to the levels in the August 2010 proposal and January 2011 NODA, respectively. The final Transport Rule established a 2012 SO 2 emission budget for Georgia of 158,527 tons, while the August 2010 proposal had established a 233,260 ton budget. At minimum EPA's modeling errors mandate the revision of Georgia’s 2012 SO 2 emission budget to the extent that is necessary to grant an allocation to MEAG of additional 2012 SO 2 emissio n allowances as addressed in MEAG’s Request for Partial Reconsideration (October 6, 2011); attached as supporting documentation. The final Transport Rule dramatically reduced Georgia’s 2012 SO 2 emission budget by greater than 30% from the proposed Transp ort Rule budget, and MEAG’s allocation of such allowances by roughly the same percentage. As a result, MEAG will face a significant SO 2 emission allowance shortfall in 2012 that will irreparably and adversely affect MEAG, the Municipalities, and the citiz en consumers and ratepayers that rely on MEAG. This reduction apparently rests on erroneous modeling and data assumptions, including EPA’s failure to fully and appropriately account for all aspects of Georgia’s Multipollutant Control Rule, particularly fo r compliance year 2012. From MEAG’s ongoing review of the modeling assumptions and data underlying the final Transport Rule, which EPA did not make available until after the final rule’s promulgation, it is clear that there are many discrepancies in the A gency’s assumptions. For example, the final Transport Rule erroneously assumes that Plant Scherer Unit Nos. 1 and 2, in which MEAG has ownership interests, will operate as of January 1, 2012 with “dispatchable scrubber” post

combustion pollution control e quipment. In reality, flue gas desulfurization (“FGD”) controls are currently under construction at Plant Scherer Unit No. 2 and are scheduled for commercial operation in 2013, in advance of the December 31, 2013 deadline imposed by the MPCR. See Ga. Com p. R. & Regs. 391

- 3

- .02(2)(sss)(9)(ii). Similarly, FGD controls are currently under construction at Plant Scherer Unit No. 1 and are scheduled for commercial operation by the MPCR’s December 31, 2014 deadline. See id. 391

- 3

- .02(2)(sss)(11)(iii). EPA’s e rroneous unit

specific assumptions for Plant Scherer Unit Nos. 1 and 2 related to the MPCR may very well have reduced the 2012 allocation of SO 2 allowances to such units. Further, the 2012 Base Case incorrectly assumes that Plant Scherer Unit Nos. 1 and 2 , which are Subpart D New Source Performance Standard (“NSPS”) units, switch from the historic use of 100% sub

- bituminous coal to partial use of higher

- sulfur and costlier bituminous coal. Likewise, the 2012 Base Case erroneously assumes that Plant Wansle y Unit Nos. 1 and 2, which already use FGD systems, nearly triple their sulfur dioxide lb/mmBtu emission rates (e.g., because of a switch to higher sulfur coal or because of less efficient SO 2 removal by the FGD systems) compared with such units’ 2010 actu al emission rates. Also, the 2012 Base and Remedy Cases erroneously show MEAG’s well

- controlled NSPS and scrubbed units all operating less in 2012 than in 2010. The above

- described errors may have significantly reduced the allocation of SO 2FIP Revisions

- RTC Febru ary 7 , 2012 Page 86

86 emission allo wances to MEAG units. MEAG notes that the State of Georgia has also pointed out other incorrect data assumptions and modeling errors affecting the State’s 2012 and 2014 Transport Rule budgets in its October 5, 2011 Petition for Reconsideration and Stay of the Cross

State Air Pollution Rule. [Letters: Municipal Electric Authority of GA (MEAG) (EPA

- HQ

OAR

- 2009

- 0491

- 4753) p. 1

- 3]
RESPONSE : EPA did not assume 2012 operation, or dispatch, of controls at those plants referenced by commenters. Post combustio n controls were assumed for some of those units in 2014 in the final Transport Rule, but EPA intends to modify that assumption in a separate action

. See the Final Revisions Rule State Budgets and New Unit Set

- Asides TSD in the docket to this rulemaking

. In regard to coal switching in the base case, the base case is not simply meant to reflect historic operation. It reflects a scenario in which there is no CAIR. In this scenario, there are different economic incentives influencing coal choice. See respo nse to UARG in section 1.3(B) above regarding coal switching and SO 2 emission rate projections. Comment (L)(3) : EPD’s comments on U.S. EPA’s Proposed Transport Rule and Proposed SIP Disapproval Rule showed there were significant errors in the Proposed Tr ansport Rule as it applied to Georgia: (1) the projected SO 2 emissions from EGUs used by U.S. EPA in its modeling (552,007 tons) were over twice the projected emissions used by EPD for its SIP analyses (232,952 tons) and (2) U.S. EPA’s modeling included th e installation of controls on a number of units in 2014 instead of 2015, as required by Georgia’s “Multipollutant Rule”, Ga. Comp. R. & Regs r. 391

- 3

- 1

- .02(2)(sss)7(ii), 8(i). In its Petition for Reconsideration and Stay on CSAPR (“Petition”), Georgia rei terated (and provided detailed examples) that the final Cross

State Air Pollution Rule still contains significant errors for units in Georgia. Specifically, Georgia’s Petition shows that projected SO 2 emissions from EGUs used by U.S. EPA in its modeling f or CSAPR (406,279 tons) are one and one

- half times higher than EPD’s projected emissions (232,952 tons). See Petition at 10

- 11. In addition, the Petition shows that U.S. EPA’s modeling of future SO 2 and NO X emissions from EGUs contains a number of errors , including the installation of controls on a number of units in 2014 instead of 2015, which result in material understatements in Georgia’s budgets. Id. at 11

- 14. Lastly, the Petition shows that in its modeling, U.S. EPA took into account emission reduc tions achieved by the installation of controls in the future required by Georgia’s Multipollutant Rule, but gave $0 credit against CSAPR’s remedy cost thresholds of $500 per ton, thereby requiring EGUs in Georgia to “over

reduce” emissions and penalizing t he State for enacting a state rule. Id. at 27

- 28. EPD provides a copy of their petition and other previous submittals to the Transport Rule docket as supporting documentation. [Letters: Georgia Environmental Protection Division (EPD) (EPA

- HQ

- OAR

2009

- 0491

- 4756) p. 1

- 2]
RESPONSE : In the final Transport Rule, EPA explained its intent to capture “reductions that occur due to state rules, consent decrees, and other planned changes in generation patterns that occur after 2012, but during or prior to 2014” in the 2014 state budgets (76 FR 48261). Commenters on the revisions rule noted that EPA inadvertently included pollution control installation requirements from a Georgia state rule whose deadlines at certain units actually extend beyond 2014. To correc t the alignment of the Georgia 2014 state budgets with theFIP Revisions

- RTC Febru ary 7 , 2012 Page 87

87 requirements for affected units in Georgia to install controls by the state rule’s deadlines, EPA plans, in a separate action, to increas e Georgia’s 2014 state budgets for SO 2 , annual NO X , and ozon e
- season NO X . See the Final Revisions Rule State Budgets and New Unit Set

- Aside TSD in the docket to this rulemaking. See the final Transport Rule Preamble for a discussion of EPA’s IPM Base Case modeling. (M) Commenters request that EPA correct data ( e.g., fuel use, assumed control technologies) that impact allocations to specific units, and adjust the allocations and state budgets accordingly. Comment (M)(1) : The New Ulm Public Utilities facility Gas Turbine #7 should be subject to the CSAPR, since it operated during the baseline years, and should receive allocations. Commenter notes that the unit is 26 MW and that the turbine is not subject to the Acid Rain Rule since the provisions at 40 CFR Section 72.6 (b)(1) specify that a simple combustion tur bine that commenced commercial operation before November 15, 1990 is not an affected unit under the program and Gas Turbine #7 is a 1979 Pratt and Whitney FT4

- 3C simple cycle combustion turbine. The CSAPR supporting technical information does not give any data for the NUPU Gas Turbine #7 even though the facility operated in the relevant baseline period. EPA may have overlooked this unit because it is not subject to the Acid Rain Rule. Commenter provides the amount of fuel burned in the past and the corre sponding heat input, and requests that EPA consider providing allocations to this unit. [Letters: City of New Ulm, MN (EPA

- HQ

- OAR

2009

- 0491

- 4740) p. 1

- 2]
RESPONSE : A potentially regulated entity can request a determination of applicability from EPA at any time. If EPA determines that the unit is subject to the FIP and it has not been allocated allowances, then it can be allocated allowances from the state's new unit set

- aside. Criteria for applicability are described in the preamble s ection VII.B of t he f inal Transport Rule. The formal applicability determination process provisions can be found at 40 CFR 97.404(c), 504(c), 604(c), and 704(c). Comment (M)(2) : Commenter (IL EPA) recommends that assumptions used in the CSAPR analysis to determine Illin ois' budget be revised, specifically for City Water, Light and Power's Dallman Unit 4 (ORIS plant code 963, CAMD Unit ID 4). Dallman Unit 4 commenced commercial operation on May 11, 2009, and because this is prior to January 1, 2010, it is considered to b e an existing unit under CSAPR. The allowances allocated to Dallman unit 4 are based on heat input for just a single year (2010) and the operations of the unit during that year are not representative of expected normal future operations. In particular, i n Dallman Unit 4's first full year of operation (i.e., 2010) it experienced problems with water circulating pumps which forced City Water, Light and Power to operate the unit at a substantially reduced capacity factor for much of that year. City Water, Li ght and Power previously requested that this unit be allocated 993 and 447 allowances per year for the annual SO 2 and NO X control programs, respectively (and 186 allowances for the ozone season NO X control program) beginning in 2012 and each year thereafte r. IL EPA supports this request, particularly since the allowancesFIP Revisions

- RTC Febru ary 7 , 2012 Page 88

88 requested are consistent with the SO 2 and NO X emission rates of 0.12 and 0.055 lb/mmBtu, respectively. [Letters: Illinois EPA (EPA

- HQ

- OAR

- 2009

- 0491

- 4738) p. 1

- 2]
RESPONSE : The state of Illinois has the flexibility to allocate allowances to units how it best sees fit beginning in 2013. EPA’s allocation methodology and heat input data used to allocate allowances under the FIP are out side the scope of the revisions proposed and upon which EPA solicited comment [76 FR 63868]

. Comment (M)(3) : Commenters provide additional corrections for Illinois facility, and questions the Illinois SO 2 Budget. IPM WebReady_ParsedFile_T_Remedy_Final_2014.xls shows the installation of Dry Sorbent Injection (DSI) for SO 2 control for the Joppa Generating Station (ID 887_B_1

- 7). EPA assumed 57% SO 2 reduction from the application of DSI. While the Joppa Generating Station has tested DSI for SO 2 and Hg control, the facility has no plans to install this control technology by 2013. Significant modifications to the current ESP or installation of other particulate matter control devices would be required to avoid exceeding Illinois particulate limits for this facility as well as triggering PSD regulations. PSD wo uld require the installation of BACT for particulate matter. Installation of these additional control devices makes the use of DSI impractical from both a functional and monetary perspective. EPA should increase Joppa's 2014 SO 2 allocation back to 2012 levels and adjust the Illinois state wide allocations appropriately. [Letters: Ameren (EPA

- HQ

- OAR

- 2009

- 0491

- 4802) p. 2; Electric Energy, Inc. (EEI) (EPA

- HQ

- OAR

- 2009

- 0491

- 4748) p. 2]
RESPONSE : Some controls are predicted in EPA modeling as a response to s tate r ule requirements that impose tonnage or rate limit requirements collectively on units. Although, the sources covered by such requirements may ultimately choose a different compliance strategy, EPA believes the emission reductions modeled are valid at the state level for which they are used as it reflects reductions legally mandated across a group of sources. For instance, the Illinois s tate r ule imposes emission rate limitations for which specific groups of covered entities must collectively compl y. At the aggregate (i.e. , state budget) level, it does not matter whether the reduction comes from source A or source B. What matters is that the reductions ultimately will occur within the state. Comment (M)(4) : EPA should address incorrect heat inpu t and emissions data for certain North Carolina sources. Two new renewable energy facilities (CPI USA

- Roxboro and CPI USA

Southport) were provided allowances under the final CSAPR annual allocation methodology based on seasonal heat input data. Additiona lly, the emissions data used by EPA to calculate the facilities' allocations are incorrect. Because of these errors, the Roxboro and Southport facilities in NC received allocations far lower than what would have resulted had EPA used the correct annual he at input and emissions data. NCDAQ urges EPA to consider the correct heat input and emissions as submitted by CPI USA's Counsel on September 30, 2011. [Letters: North Carolina Department of Environment and Natural Re (EPA

- HQ

- OAR

- 2009

- 0491

- 4776) p. 2]FIP Revisions

- RTC Febru ary 7 , 2012 Page 89

89 R ESPONSE : Changes to allocation methodology are out side the scope of revisions proposed and upon which EPA solicited comment . The allocation methodology is described in preamble s ection VII.D of the f inal Transport Rule (76 FR 48208, August 8, 2011).
Co mment (M)(5) : EPA should remove the SCR designation for Bay Shore Unit 4 (OH) and correct the NO X budget allocations for the state of Ohio. EPA should also revise and re

- allocate the emission allowance allocations under the FIP rule since EPA's NO X budge t for Ohio is erroneous. EPA’s rush to finalize the CSAPR and the FIP rulemakings without accurate and quality assured underlying data has produced flawed regulations. FirstEnergy (FE) notes that they submitted comments to the CATR docket on October 1, 2 010 and the Notice of Data Availability (NODA I) docket, on October 15, 2010, pointing out that EPA erroneously assumed Bay Shore Unit 4 has or will have a scrubber to control SO 2 emissions. While EPA eliminated the Bay Shore Unit 4 scrubber assumption in its final rulemaking, it erroneously assumed an SCR in place of the scrubber. FE adds that they did not have the opportunity to correct EPA’s error because the SCR designation for Bay Shore Unit 4 first appeared in the technical support documentation for the final CSAPR. As supporting documentation, FE provides a copy of their comments (dated October 15, 2010) that were submitted in response to the NODA. [Letters: First Energy Corporation (EPA

- HQ

- OAR

- 2009

- 0491

- 4741) p. 1

- 2, Att. 1]
RESPONSE : EPA is i ncreasing Ohio’s 2012 and 2014 annual SO 2 , annual NO X , and ozone

season NO X budgets to account for operational constraints at two plants, Conesville and Muskingum River, based on comments received on the revisions rule. The commenter provided information showing that these plants were in out

- of

- merit

- order dispatch areas with conditions likely to necessitate what would otherwise be non

- economic generation.
EPA re

- calculated the emissions from these two plants with non

- economic generation to reflect the in put assumption changes. EPA is finalizing additional adjustments to Ohio’s 2012 and 2014 annual and ozone

- season NO X budgets to correct an erroneous assumption of an SCR at Bayshore 4. There is no SCR planned or under construction at this facility. Th is results in increases to the state’s annual and ozone season NO X budgets. See Final Revisions Rule State Budgets and New Unit Set

- Asides TSD in the docket for this rulemaking. Comment (M)(6) : Commenter (SC DHEC) notes that Duke Energy notified EPA on October 3, 2011 of errors in the IPM data for the W.S. Lee Plant. The CSAPR modeling assumed that W.S. Lee was equipped with wet scrubbers, though no such scrubbers exist at this plant. These errors may have skewed all of the allocations to South Carolin a sources subject to the CSAPR. Correcting these, and other, errors, will improve IPM's correspondence with real world conditions, and enhance the effectiveness of the rule. [Letters: South Carolina DHEC (EPA

HQ

- OAR

- 2009

- 0491

- 4742) p. 2]
EPA should co rrect several errors in the data used to set SO 2 budgets and subsequently the unit

level SO 2 allowance allocations for South Carolina. Commenter (Duke) notes that this is the firstFIP Revisions

- RTC Febru ary 7 , 2012 Page 90

90 opportunity that they have had to comment on these technical errors becaus e each appeared for the first time in the final rule. In both the TR_Remedy_Final_2012 and TR_Remedy_Final_2014 IPM parsed files, W S Lee units 1, 2, and 3 are shown to each be equipped with a dispatchable wet scrubber. EPA’s definition of a dispatchable scrubber means the scrubber either exists or is planned to be on line prior to 2012, but is not required to operate. The only decision the model is making with regard to a dispatchable scrubber is whether to operate the control. Based on the fact that t he above referenced IPM parsed files show these units being modeled with an SO 2 emission rate of 0.25 lbs/mmBtu, it is clear the model is operating the control because this emission rate is not achievable without a scrubber. The problem is that none of th ese units are currently equipped with a scrubber, nor are scrubbers planned for any of these units, so designating these units as having dispatchable scrubbers is clearly an error. Dispatchable scrubbers on these units appeared for the first time in the f inal Transport Rule. Commenter provides additional discussion and references specific files in order to describe how the IPM modeling for the proposed Transport Rule (including previous iterations of NEEDS) does not show a scrubber for any of these units in either 2012 or 2014. The modeling assumption that W S Lee units 1, 2 and 3 are either currently equipped with a scrubber or will be equipped with a scrubber by 2012 is clearly an error. EPA should remove the scrubber from each of these units and make the appropriate adjustments to the South Carolina SO 2 budget, assurance level, and unit level allocations using the same methodology EPA outlined in its Technical Revisions to State Budgets and New Unit Set

- Asides document for other units that were incorre ctly modeled with scrubbers. Based on that methodology, the SO 2 emission rate that should be applied to each of the W S Lee units, calculated from the TR_Base_Case_Final IPM run for 2012, is 1.47 lbs/mmBtu. [Letters: Duke Energy (EPA

- HQ

- OAR

- 2009

- 0491

- 47 68) p. 2

- 3]
RESPONSE : The South Carolina 2012 and 2014 SO 2 budget has been adjusted to reflect no FGD at this facility. See Final Revisions Rule State Budgets and New Unit Set

- Asides TSD in the docket for this rulemaking. Comment (M)(7) : EPA should correct several errors in the data used to set SO 2 budgets and subsequently the unit

- level SO 2 allowance allocations for Indiana. Commenter (Duke) notes that this is the first opportunity they have had to comment on the following technical errors because each appeared for the first time in the final rule. The IPM modeling incorrectly incorporates dry scrubbers on R. Gallagher Units 2 and 4 in the final Transport Rule. The NEEDSv410_FTransport.xls file indicates that both these scrubbers came on line in 2011, each at 85% efficiency, resulting in the units being modeled with a 0.31 lbs/mmBtu SO 2 emission rate. Neither of these units is currently equipped with a dry scrubber, nor is a dry scrubber planned for either of these units, so designating these uni ts as having dry scrubbers is clearly an error. Dry scrubbers on these units appeared for the first time in the final Transport Rule. The IPM modeling for the proposed Transport Rule (ParsedFile_TR_SB_Intrastate_Trading) does not show a dry scrubber for either unit in 2012 or 2014. In addition, neither the NEEDSv3.02 database nor the NEEDSv4.10 database that EPA put out for public comment on September 1, 2010, indicated dry scrubbers for either of these units. Both units are operating under a NSR settle ment agreement, approved in early 2010, that limits their SO 2 emission rate to 0.80FIP Revisions

- RTC Febru ary 7 , 2012 Page 91

91 lbs/mmBtu on a 30

- day rolling average, and both units employ dry sorbent injection technology, not a dry scrubber. Dry sorbent injection technology is less effective than a dry scrubber at reducing SO 2 . The modeling assumption that R Gallagher units 2 and 4 are equipped with a dry scrubber is clearly an error. EPA should remove the dry scrubbers from these units, apply a 0.80 lbs/mmBtu emission rate, and make the appropri ate adjustments to the Indiana SO 2 budget, assurance level, and unit level allocations. [Letters: Duke Energy (EPA

- HQ

- OAR

- 2009

- 0491

- 4768) p. 4

- 8]
EPA should correct several errors in the data used to set SO 2 budgets and subsequently the unit

level SO 2 a llowance allocations for Indiana. Commenter (Duke) notes that this is the first opportunity they have had to comment on the following technical errors because each appeared for the first time in the final rule. The SO 2 control efficiency of the Gibson un it 5 wet scrubber was inappropriately changed in the final transport rule from 85% to 95%. In both the NEEDSv3.02 database and the NEEDSv4.10 database that EPA put out for public comment on September 1, 2010, the Gibson unit 5 scrubber was appropriately s hown at 85% efficiency. In the proposed Transport Rule EPA switched Gibson 5 to a 1.4 lb sulfur coal that along with the 85% scrubber efficiency produced a 0.21 lbs/mmBtu SO 2 emission rate. Duke Energy commented that the unit was not capable of burning a 1.4 lb sulfur coal without costly equipment upgrades that couldn’t be completed by 2012. In the final Transport Rule EPA appropriately increased the sulfur content of the coal assigned to Gibson unit 5 to 4.2 lb sulfur, but then arbitrarily increased the unit’s scrubber efficiency from 85% to 95%, as reflected in the NEEDSv410_FTransport.xls file. The combination of the higher sulfur content coal and higher efficiency produce the same 0.21 lbs/mmBtu SO 2 emission rate that was modeled as part of the propo sed Transport Rule. Commenter provides additional technical discussion to describe why the Gibson unit 5 scrubber is not capable of achieving 95% removal efficiency based on its initial design, noting that the typical SO 2 removal achieved by the original scrubber was 80%. In 2007 the absorbers were upgraded to increase SO 2 removal and improve reliability at a cost of $40M. Commenter provides additional technical discussion to describe the upgrade and notes that consistent 85% removal can now be achieved with DBA. The upgrade improved the overall performance but missed the >90% SO 2 removal goal and there are still reliability problems since the absorbers are too short and there is not enough distance between the slurry nozzles and the mist eliminators so the mist eliminators continue to plug. Thus additional slurry headers can’t be added to increase SO 2 removal. The slurry header arrangement is such that most of the slurry drains into the reaction tank at one end which causes pH variations across the rea ction tank and reduced SO 2 removal. Due to various physical constraints it is impractical to correct these problems. The only option to get the scrubber to 95% would be a total replacement, which obviously couldn’t be achieved by 2012 or 2014. Commenter asserts that the assignment of 95% efficiency to the Gibson unit 5 scrubber is clearly an error and requests that EPA changes the efficiency of the Gibson unit 5 scrubber back to 85% while maintaining the same coal sulfur content assigned to the unit in t he final Transport Rule. EPA should make the appropriate adjustments to the Indiana SO 2 budget, assurance level, and unit level allocations accordingly. Commenter provides significant additional discussion to support their request including a comparison of how this change is similar to those proposed by EPA for scrubber removal rates for a number of units in Texas and a description of the scrubber efficiency reported in EIA formFIP Revisions

- RTC Febru ary 7 , 2012 Page 92

92 923 and their correction of that efficiency with EIA. [Letters: Duke Energy (EPA

- HQ

- OAR

2009

- 0491

- 4768) p. 4

- 8]
RESPONSE : EPA has adjusted Indiana’s 2012 and 2014 SO 2 Budgets to reflect DSI technology at the Gallagher units and a lower SO 2 removal rate at Gibson Unit 5. See Final Revisions Rule State Budgets and New Unit Set

- A sides TSD in the docket to this rulemaking. Comment (M)(10) : EPA should correct several incorrect modeling assumptions for units in Maryland, and increase the allocations for the units. Commenter (Constellation) identifies several incorrect unit

- specifi c modeling assumptions that could affect the SO 2 budgets. For H. A. Wagner units 2 and 3 (ORIS 1554), the inputs to the IPM runs include an assumptions that the units will be burning subbituminous coal in 2012 and beyond, which results in predicted emissi on rates of 0.53 lb/mmBtu for both units. Constellation has test burned subbituminous coal in the units, however, the tests indicated that subbituminous coal could not be burned at Wagner due to operational and safety concerns. Also the modeling assumes permit rates of 0.36 and 0.32 lb/mmBtu for units 2 and 3 respectively. Maryland regulations limit the units to burning coal with a maximum sulfur content of 1% (about 1.6 lbs/mmBtu). Wagner 2 and 3 currently and are expected to burn low sulfur bituminous coal with maximum emissions of 1.2 lbs/mmBtu. For C.P. Crane (ORIS 1552) the IPM modeling for units 1 and 2 assumes permit rates of 0.38 and 0.3 lbs per mmBtu. Maryland regulations limit the units to 3.5 lbs/mmBtu. [Letters: Constellation Energy (EPA

- HQ

- OAR

- 2009

- 0491

- 4769) p. 3]
RESPONSE : First, EPA notes that Maryland’s 2010 emissions were already compliant with its 2012 Transport Rule SO 2 budget for 2012, supporting the notion that the compliance capability modeled for the state in 2012 is entirely reasonable given the state ’ s ability to operate at this level. Regarding these particular units, EPA does not assume a 0 .53 lb/ mmBtu rate as claimed by commenter and it does not assume the 0 .38 and 0 .3 lb/ mmBtu rate limits for Craine claimed by commenter ( s ee NEEDSv.4.10 FTransport and TR_Base_Case_Final available in the d ocket to this rulemaking and on the website). Some coal switching is projected as economic, but by no means required at any individual unit. Furthermore, as illustrated by the state e missions and budget levels given above, no major changes are necessary for the state of Maryland’s coal consumption patterns given that they have already demonstrated an ability to reach compliant levels. See section 6.2(c) , below, of this document for in formation addressing SO 2 emission rates. Comment (M)(11) : The remedy 2014 NO X control case in the Final Rule analysis erroneously assumed SCR emission control devices would be operational on the three Westar JEC generating units. Under the JEC Consent D ecree, only one SCR at JEC is required, and it is not required to be online until December 31, 2014, which means the NO X reductions at JEC assumed in the IPM are not actually required until 2015 or later. Kansas’ 2014 NO X annual and ozone season projected emissions should be revised to reflect the absence of any JEC SCRs in 2014. Westar calculated a revised emission rate to account for the lack of any SCRs at JEC in 2014, using, instead, JEC’s emission limits set by 2014 Kansas Regional Haze emission requ irements. Westar’s calculations of 2014 NO X annual and 2014 NO X ozone season revisions are shown inFIP Revisions

- RTC Febru ary 7 , 2012 Page 93

93 Table 5

- 1 and Table 5

- 2, respectively . The revisions result in a 5,110 ton increase for the Kansas 2014 NO X annual budget, and a 2,238 ton increase for t he Kansas 2014 NO X ozone season budget. These changes are also reflected in the results shown in Tables 2

- 3 and 2

- 4 of the comment letter. [Letters: Westar Energy (EPA

- HQ

- OAR

- 2009

- 0491

- 4777) p. 8

- 9]
RESPONSE : EPA has adjusted the Kansas 2014 annual NO X budget to reflect the removal of the 2015 rate limit requirement. See the Final Revisions Rule State Budgets and New Unit Set

Asides TSD in the docket to this rulemaking. Comment (M)(12) : In their Petition for Reconsideration, Northern States Power no tified EPA that in final allowance allocation, the Riverside and High Bridge plants were characterized on the basis of their emissions only after they were converted to natural gas plants, even though they operated as coal plants during part of the time pe riod EPA used to develop the allowance allocations. As a result, NSP is not receiving credit under CSAPR for the early actions it has taken through unit repowerings to reduce emissions from coal power plants. This result may have occurred because these u nits were assigned different unit numbers when the conversion from coal to natural gas generation took place. EPA's response to comments to the CSAPR rule appears to indicate that its intent is to account for emission reductions that occurred due to repow erings (see Transport Rule RTC at 2649). EPA should review and reevaluate the application of its methodology with respect to Northern State Power's Riverside and High Bridge facilities, taking into account the early actions taken by the utility that resul ted in significant, cost effective emission reductions. It is important that the Agency's methodology not penalize the early actions taken by Northern States Power when it repowered two aging coal plants, actions that produced air quality outcomes consist ent with the goals of the new CSAPR standards. [Letters: Isaak Walton League of America (EPA

- HQ

- OAR

- 2009

- 0491

- 4798) p. 1

- 2]
RESPONSE : EPA considers units that are entirely replacing pre

- existing units to be a different unit. The pre

- existing units are considered retired, and EPA does not allocate allowances to units that were retired at the time of Transport Rule finalization. Additionally, changes to the allocation methodology are out side the scope of the revisions proposed and upon which EPA solicit ed comment (76 FR 63860) . See Section 6.5 , below , for more information. (N) Additional revisions are necessary to prevent blackouts in a transmission constrained area. Comment (N)(1) : The BPU system includes a large service area in and around Kansas City, KS where transmission capability is inadequate to provide reliable supply to the electric load without relying entirely on BPU’s generation units (Quindaro 1 and CT 2) that are located inside this service area. Transmission constraints surrounding t his load pocket make it very difficult, if not impossible, to import power without increasing the risk of blackouts throughout the pocket. As a result, BPU must depend on its Quindaro 1 and CT 2 units to provide virtually all the electricity within this a rea. The Final Rule emission allowances will not permit these two units to generate power throughout the year, thus forcing BPU to rely on imported power (assuming it can beFIP Revisions

- RTC Febru ary 7 , 2012 Page 94

94 found) for these transmission constrained customers continually for a substantia l portion of the year. Importing power will significantly increase the potential for blackouts. To avoid this problem, BPU requests additional Kansas allowances that would permit Quindaro 1 and CT2 to generate enough electricity throughout the year to se rve customer load within the load pocket. BPU’s system is roughly divided in two with one half served by a 161 kV line and the other half served by a 69 kV line. The 69 kV line portion of BPU serves approximately half of BPU’s residential and industrial load, and, because it is transmission constrained, this portion depends almost entirely on Quindaro 1 and CT 2 for generation to serve the load within its area. Power can only be brought into the area served by the 69 kV line by passing over BPU’s 161 kV line. It is largely impracticable to import power from BPU’s 161 kV line to its 69 kV line because the bus facilities at the point of transfer overload if more than a minimal amount of electricity is transferred between the lines. Whenever a more than mi nimal amount of power is transferred, the increased chance of an overload leads to a stronger possibility for cascading blackouts over the entire 69 kV line service area. As Quindaro 1 and CT 2 are located within the 69 kV line service area, their generat ion moves directly to this line, thereby avoiding overload problems. At the Final Rule emission allowances, BPU will be forced to shut down Quindaro 1 and CT 2 sometime in mid

- May 2012 and, if it can obtain power from outside sources, transfer that import ed power over the 161 kV line into the 69 kV service area. Such large, continuous transfers of electricity over the connecting bus between the lines will increase substantially the possibility of overload and resulting blackouts. This operational constra int justifies a revision in the allowance for Quindaro 1 and CT 2 as part of an increase to the Kansas State Budget. Increasing the allowance to these two units offers the best means to assure reliable service to BPU’s customers located within this transm ission constrained service area. BPU requests that EPA revise the Kansas budget allowances to provide sufficient allowances to Quindaro 1 and to CT 2 to enable them to provide the necessary electricity to serve BPU’s customers in the 69 kV service area th roughout the year. BPU estimates that the following additional allowances would be needed for the units’ 2012 and 2014 allowance budgets. [Letters: Kansas City Board of Public Utilities (EPA

- HQ

- OAR

- 2009

- 0491

- 4779) p. 6

- 8]
RESPONSE : EPA has made adjust ments to the Kansas budgets to reflect this comment. See Final Revisions Rule State Budgets and New Unit Set

- Asides TSD. EPA only made adjustments for Quindaro 1 and not CT2, because KC BPU indicated that C 2 was used only in cases where Quindaro 1 was d own. EPA also notes that the resulting revisions to the Kansas budgets, which indirectly revise KC BPU’s allocation, reflect the incremental emissions from operating Quindaro 1 more. (O) Additional operational constraints necessitating non
- economic dispa tch that are not accounted for in final CSAPR.FIP Revisions

- RTC Febru ary 7 , 2012 Page 95

95 Comment (O)(1) : KCP&L has identified unit

- specific operational constraints not accounted for in the final CSAPR whose inclusion may warrant revisions in state budgets, with associated revisions to the state assurance levels and unit

- level allocations for existing units. KCP&L is submitting additional unit

- level operational information that would have a material impact on the calculation of CSAPR state budgets (with associated impacts on corresponding assuran ce levels and unit

- level allocations for existing units). See 76 Fed. Reg. at 63868. Operational requirements necessitating non

- economic generation occur at KCP&L’s combustion turbine peaking units because of transmission congestion. These units include KCP&L’s Hawthorn 6

- 9, Northeast Station 11

- 18, Lake Road 5, Greenwood 1

- 4, Ralph Green 3, and South Harper 1

- 3 in Missouri and West Gardner 1

- 4 and Osawatomie 1 in Kansas. Each of these units was required to generate for reasons other than the regional e conomic sale of electricity which most often was transmission congestion management. KCP&L estimates during the ozone season and during the calendar year that such non

- economic generation is necessitated from these units about 20 percent of the time in 20 10. Consistent with a similar request granted in the Proposed Revisions to the Transport Rule, See 76 Fed. Reg. at 63868, KCP&L requests additional allowances for these units to account for the necessitated non

- economic generation in an amount of 15 ozon e season NO X and 30 annual NO X . These additional allowances are material and significant to KCP&L operations where we have very limited alternate compliance options. [Letters: Kansas City Power and Light Company (EPA

- HQ

- OAR

- 2009

- 0491

- 4804, 4826) p. 4

- 5]
RESPONSE : EPA reviewed KCP&L comments regarding the units it identified as needing to run out

- of

- merit

- order and made revisions to the Missouri units as appropriate (see the F inal Revisions Rule State Budgets and New Unit Set

- Asides TSD in the docket to this rulemaking). EPA notes that the commenter’s requested revisions for the units identified with out

- of

- merit

order dispatch, even in the commenter’s own estimation, amount to very marginal quantities of emissions. Furthermore, EPA did not make revisi ons with regard to the units in Kansas. A s explained in the Final Revisions Rule State Budgets and New Unit Set

- Asides TSD in the docket to this rulemaking, EPA bases any budget revision related to out

- of

- merit

- order dispatch units on the net impact on pr ojected emissions of revising assumptions concerning immediate

- term unit operation, including the subtraction of emissions from offset generation. EPA found that these requested revisions would yield a net impact on Kansas state budgets that would have ro unded to zero; as a result, EPA found that no revision was necessary for Kansas state budgets with regard to these units identified by this commenter as having out

- of

- merit

- order dispatch in Kansas. Additionally, units in Kansas are not currently covered under the Transport Rule ozone season program (see 76 FR 80760, December 27, 2011). (P) The proposed modifications of state budgets and unit allocations eliminate local reliability concerns and no other modifications should be made unless necessary and material.FIP Revisions

- RTC Febru ary 7 , 2012 Page 96

96 Comment (P)(1) : Exelon supports EPA making modifications to state emission budgets to correct the limited number of technical errors identified by stakeholders related to EPA''s IPM model input assumptions and output results. The proposed rev isions should eliminated the over

stated concerns with the Rule's impacts on local reliability by adjusting state budgets and unit allocations to provide additional allowances to units that will need to run uneconomically to supply VARS or otherwise to pr omote reliability of transmission. The proposed revisions provide the fourth opportunity for the electric generation industry to comment on technical correction issues. Absent extraordinary circumstances, no further technical adjustments should be make. Market participants need to know the final state emission budgets in order to plan and to develop capital and operating budgets. The need for certainty drives Exelon's support for EPA's proposal that no additional changes should be made in response to an y comments submitted during this public comment period unless the changes are shown to be necessary and to exceed a "material impact." A commenter must show that the adjustment is absolutely necessary to correct a clear model input error or to allow an un economic plant to run sufficiently to assure local reliability of transmission. Because CSAPR is a cap

- and

- trade program and because budgets include variability limits, most adjustments can be readily accommodated without modifying unit allocations or sta te budgets at all. Exelon agrees with EPA's proposal that no additional adjustment in budgets should be made unless the required increase for an individual state at issue is greater than one percent of the state's emission budget.
Also Exelon notes that the criticisms leveled at the overall structure of CSAPR and the methodology that EPA used to develop unit and state budgets are unsupported and unwarranted. These criticisms have been set forth in petitions for reconsideration, motions for a stay of CSAP R and comments already submitted on the Rule. In particular, criticisms directed at EPA's IPM model and its use for deriving budgets are unwarranted and are founded upon a fundamental misunderstanding of models, modeling, and their limitations. These cri ticisms are particularly unwarranted in light of the fact that the state budget modifications in the Proposed Revisions are designed, in part, to address the limited instances in which the IPM model did not consider a unique aspect of a particular generati ng unit's operation that could not be easily modeled in IPM. Models like IPM are powerful tools to predict the behavior of complex systems. Due to limitations of time, computing power and information available for model inputs, any model's representation of a complex system must be simplified. Thus, no model of a complex system can be accurate in all cases. Indeed, a model that duplicates reality and meets the very strict 95% confidence level used in scientific studies to determine statistical significa nce will, by definition, not generate accurate predictions in five out of 100 instances. Models are frequently deemed scientifically reliable at lower significance levels. EPA's IPM model performs well to predict the relationship between allowance prices and how this will affect decisions to operate emissions equipment and the decisions whether to dispatch electricity to cleaner gas

- fired units or units with emissions controls rather than uncontrolled or less controlled intermediate and baseline units. I n fact, the IPM model is the best tool available for this purpose. Because the IPM model is based on dispatching units based on least costFIP Revisions

- RTC Febru ary 7 , 2012 Page 97

97 system price [which includes energy and capacity prices], it does not reflect all of the complexities of the transmi ssion system at a micro scale, including situations where dispatch of un
- economic units may be necessary during a limited number of hours each year. Budgets for those un

- economic units may need to be adjusted outside of the model based on the particular f

acts presented. Regardless, because CSAPR is a cap and trade program, 100% accuracy in state budget and unit allocations of free allowances is both unnecessary and poor policy. Marginal model inaccuracies can go both ways and can both under and over pred ict available reductions and prices. A unit which may be awarded too few allowances can go into the market and purchase allowances. The owner of a unit awarded too many allowances is unlikely to submit comments suggesting that its allocation be reduced. Thus likely over awarded allowances for some units will generate additional liquidity. In fact ex ante concerns about budgets have frequently resulted in budgets too high to drive needed or even any reduction, and to date a cap and trade system has never had an initial cap that has generated prices significantly exceeding those originally modeled. [Letters: Exelon (EPA

- HQ

- OAR

- 2009

- 0491

- 4810) p. 9

- 10, 35

- 38]
RESPONSE : EPA thanks the commenter for its submission. (Q) EPA's proposed revisions fail to ad dress many of the previously identified errors. Comment (Q)(1) : Commenter (UARG) notes that they asked James Marchetti Inc. (JMI) to determine whether EPA’s proposed corrections resolve the unit

- level errors that the October 2011 JMI Analysis had identif ied for sources in five "overlap" states (i.e., Florida, Louisiana, Michigan, Texas, and Wisconsin). Commenter provides JMI’s findings as Attachment II to their comment letter. In this report, JMI finds that although EPA’s Proposed Revisions identify and appear to correct some of the unit

- level errors identified in the October 2011 JMI Analysis, the Proposed Revisions fail to address many of the previously identified errors in the five states. Furthermore, the Proposed Revisions fail to address any of th e unit

- specific errors that JMI identified in the three other states evaluated in the October 2011 JMI Analysis (Georgia, Kansas, and Ohio), and the Proposed Revisions fail to address unit

- specific errors that likely were made with respect to a large numbe r of units in states covered by the Cross

- State Rule that JMI did not have time to evaluate. Commenter expresses concern that any additional corrections EPA does make apparently will not be promulgated in final form until after the start of the initial co mpliance periods on January 1, 2012, and asserts that EPA should correct all unit

- level errors before the start of the initial compliance periods under the rule. [Letters: Utility Air Regulatory Group (EPA

- HQ

- OAR

- 2009

- 0491

- 4823) p. 4

- 7]
RESPONSE : EPA is finalizing changes for Georgia, Kansas, and Ohio in this rulemaking. It has evaluated all comments and identified and finalized changes where appropriate. This response to comment document explains where comments were accepted. In the case that they were not ac cepted, the response addresses unit specific or general reasons for that outcome. See section 6.2(b) of this document , below, for information addressing NO X emission rates. See section 6.2(c) of this document , below, for information addressing SO 2 emission rates. See theFIP Revisions

- RTC Febru ary 7 , 2012 Page 98

98 Final Revisions Rule State Budgets and New Unit Set

- Asides TSD in the docket to this rulemaking. Issue 1.9: Georgia Modeling Assumptions
Comment : The state of Georgia has a progressive air pollution rule, called the Georgia Multipollutant Rule (GaMPR), that requires the installation of SCR and Wet Flue Gas Desulfurization (WFGD) technology on major power plants. IPM has several errors in regard to the schedule of retrofits required by the GaMPR that affect Georgia’s state bu dget. Errors were made in the parsed IPM files concerning when WFGD systems would be required by the GaMPR at Plant Scherer. The correct information is that Scherer Unit 3 now has a non

- dispatchable WFGD; and retrofits of WFGD systems on Units 4, 2 and 1 are required by the GaMPR, respectively, on December 31 of 2012, 2013, and 2014. Data in the parsed files for the PTR’s Base Case run for 2012 indicate two WFGDs committed between 2010 and 2011 on Scherer 3 and 4, and no FGDs on Scherer 1 and 2. CSAPR’s Ba se and Remedy Case runs for 2012

– BC_F_12 and RC_F_12

– assume a retrofit of WFGD for only Unit 4 by 2012; however, since the retrofit of this WFGD is not required by the GaMPR to be complete until December 31, 2012, the Base and Remedy Case runs for 2012 should not reflect WFGD on Unit 4. CSAPR’s Base and Remedy Case runs for 2012

– BC_F_12 and RC_F_12

– incorrectly assume WFGD retrofits for Units 1 and 2 by 2012. Finally, CSAPR’s Base and Remedy Case runs for 2014

– BC_F_14 and RC_F_14

– incorrectly assu me a WFGD retrofit for Unit 1 by 2014. As the WFGD for this unit is not required before January 1, 2015, IPM modeling should not assume this retrofit until 2015. Errors were made in the parsed IPM files concerning when SCR modules would be required by the GaMPR at Plant Scherer. The correct information is that SCR has already been retrofit on Scherer Unit 3 and that retrofits of SCR systems are required by the GaMPR on Scherer Units 4, 2, and 1 on December 31, of 2012, 2013, and 2014. The BC_P_12 run corre ctly assumed that the SCR retrofit on Scherer Unit 3 would be complete by 2012 but incorrectly assumed that the Unit 4 SCR would be complete in 2012. Because the SCR retrofit for Unit 4 is not required to be complete until December 31, 2012, IPM modeling s hould not reflect SCR on Unit 4 until 2013. CSAPR’s Base and Remedy Case runs for 2012

– BC_F_12 and RC_F_12

– correctly assume a retrofit of SCR for only unit 3 by 2012. CSAPR’s Base and Remedy Case runs for 2012

– BC_F_12 and RC_F_12

– incorrectly assume a SCR retrofit for Unit 2 by 2012. Finally, CSAPR’s Base and Remedy Case runs for 2014

– BC_F_14 and RC_F_14 incorrectly assume SCR retrofit for Unit 1 by 2014. As the SCR for this unit is not required to be complete until December 31, 2014, IPM modeling should not assume this retrofit until 2015. Errors have also been made concerning if and when FGD and SCR systems willFIP Revisions

- RTC Febru ary 7 , 2012 Page 99

99 be required by the GaMPR at Harlee Branch and Yates. In BC_F_14, however, EPA has incorrectly assumed FGD and SCR systems will be instal led on all four Harlee Branch Units by January 1, 2014. Similarly, FGD and SCR installations at Yates Units 6 and 7 are not required until June 1, 2015, but in BC_F_14, EPA has incorrectly assumed that FGD and SCR systems will be installed at Yates Units 6 and 7 by 2014. Errors were made in the SO 2 emission rates used for the four Harlee Branch units. The correct information is that each of the four Harlee Branch units has an actual emission rate of 1.8 lbs/ mmBtu , as reported in the CEMS Data Base. In both BC_P_12 and BC_F_12, EPA used SO 2 emission rates of 4.2 lbs/ mmBtu for the four Harlee Branch units. In its October 2010 comments on the PTR, Southern Company pointed out these errors. In the final CSAPR, however, EPA did not correct these emission rate err ors. As a result of these errors, emission rates for the Harlee Branch units were almost twice as high as the units’ actual emission rates. Large errors in emissions can result in erroneous calculations as to the state’s significant contribution to nonatta inment in downwind states and can result in errors in calculating the level of the state’s emission budgets. Errors were also made in the SO 2 emission rates used by EPA for Kraft Units 1

- 3 and Yates Units 2

- 5. The actual SO 2 emission rate for the Kraft Uni ts 1

- 3 is 1.53 lbs/ mmBtu ; the actual emission rate for Yates Units 2

- 5 is 2.1 lbs/ mmBtu . In the BC_F_12 run, however, EPA assumed that the SO 2 emission rates for all of these units would be about 4.3 lbs/ mmBtu

. Errors were made about how long it would tak e certain coal

- fired units in Georgia to be able to switch from burning higher sulfur bituminous coal to a lower sulfur bituminous coal. In its October 2010 comments on the PTR, Southern Company explained that it can switch from burning higher to lower sul fur bituminous coals at Harlee Branch Units 1

- 4, Kraft Units 1

- 3, and Yates Units 2

- 5; however, it will take at least 1 to 2 years for the fuel switching to begin, plus another 3 to 5 years for existing contracts to expire, thus allowing a 100% fuel switch . In its IPM runs, though, EPA has incorrectly assumed that fuel switching at all these units can be accomplished by January 1, 2012. Errors have been made in the modeling of McDonough Units 1 and 2. Those two units are to be retired in April of 2012 and then replaced by two 850 MW combined cycle units which will begin operation in the first half of 2012.[footnote: The third block of the McDonough combined cycle facility (850 MW) is expected to be in operation by January 1, 2013. In BC_P_12, EPA correctly assumed that McDonough Units 1 and 2 would continue operating. EPA inappropriately “retired” those units in its BC_F_12 run and also failed to include in its BC_F_12 run the two new combined cycle units that will begin operating in 2012. [Attachment to UA RG comment letter, “J. Marchetti, J. E. Cichanowicz, Initial Identification of Unit Errors in Integrated Planning Model (IPM) Runs (Oct. 7, 2011)” (EPA

- HQ

- OAR

- 2009

- 0491

- 4823) p. 44

- 45]FIP Revisions

- RTC Febru ary 7 , 2012 Page 100

100 RESPONSE : In the final Transport Rule, EPA explained its intent to ca pture “reductions that occur due to state rules, consent decrees, and other planned changes in generation patterns that occur after 2012, but during or prior to 2014” in the 2014 state budgets (76 FR 48261). Commenters on the revisions rule noted that EPA inadvertently included pollution control installation requirements from a Georgia state rule whose deadlines at certain units actually extend beyond 2014. To correct the alignment of the Georgia 2014 state budgets with the requirements for affected units in Georgia to install controls by the state rule’s deadlines, EPA is increasing Georgia’s 2014 state budgets. See the Final Revisions Rule State budgets and New Unit Set

- Asides TSD in the docket to this rulemaking. Also, see response to UARG comment let ter in section 1 .3 above regarding coal switching and SO 2 emission rate projections. The commenter’s criticism with regards to the precise retirement dates of the McDonough units is misguided, as EPA is not attempting to project EGU emissions on a daily b asis. Instead, EPA’s IPM modeling in support of the Transport Rule programs is designed to provide reasonable estimates of future

- year EGU emissions at the state level over the course of the two time periods regulated under the rule

– an annual control pe riod and an ozone

- season control period. It is not necessary to create a daily

- specific input assumption structure in order for the model to provide reasonable seasonal and annual emission projections at the state level; moreover, EPA is not administering the Transport Rule programs to regulate daily or even monthly emission levels, but is instead offering substantial compliance flexibility that allows sources to account for their emissions over many months at a time and subject to an overarching limitatio n on state

- wide emissions (rather than any unit

- specific requirements). Issue 1.10: Kansas Modeling Assumptions
Comment : In its BC_P_12 run, EPA made errors in the NO X and SO 2 emission rates that it used to evaluate the downwind impacts of EGUs in Kans as. In the case of NO X emissions, EPA greatly over

- estimated NO X emissions at many plants, including at Jeffery 1

- 3, LaCygne 1, Quindaro 2, and Nearman 1. In their October 2010 rulemaking comments, Westar, KCP&L, and KCBPU pointed out the errors, and EPA a ppears to have addressed most such errors in the runs associated with the final CSAPR. (As a result of the corrections of many of the errors related to NO X emission rates in BC_P_12, the state’s total 2012 NO X emissions were reduced from 70,700 tons (in BC _P_12) to 37,100 tons (in BC_F_12).) However, there seem to be errors with regard to EPA’s assumptions about SO 2 emission rates at Kansas power plants. Thus, as set forth in the following table, in BC_F_12, the SO 2 emission rates for many Kansas units rem ain extremely high relative to their actual SO 2 emission rates in 2010.
Unit BC_F_12 SO 2 Rate Actual SO 2 Rate in 2010 Quindaro 2 0.94 lbs/ mmBtu 0.59 lbs/ mmBtu Nearman Creek 1 0.94 lbs/ mmBtu 0.63 lbs/ mmBtu Holcomb 0.29 lbs/ mmBtu 0.12 lbs/ mm Btu LaCygne 2 0.94 lbs/ mmBtu 0.68 lbs/ mmBtuFIP Revisions

- RTC Febru ary 7 , 2012 Page 101

101 Lawrence 3 1.26 lbs/ mmBtu 0.62 lbs/ mmBtu Lawrence 4 0.40 lbs/ mmBtu 0.06 lbs/ mmBtu Lawrence 5 0.71 lbs/ mmBtu 0.12 lbs/ mmBtu Tecumseh 9 1.22 lbs/ mmBtu 0.60 lbs/ mmBtu Tecumseh 10 1.21 lbs/ mmBtu 0.63 lbs/ mmBtu As a consequence of assuming that SO 2 emission rates will be so high, EPA concludes that in 2012, the state’s total emissions of SO 2 will be 68,000 tons, rather than 45,200 tons. Use of the higher emission rates then translates into a st ate

- wide emission rate of 0.39, which is significantly greater than the actual state

- wide emission rate of 0.23. [Attachment to UARG comment letter, “J. Marchetti, J. E. Cichanowicz, Initial Identification of Unit Errors in Integrated Planning Model (IPM) Runs (Oct. 7, 2011)” (EPA

- HQ

- OAR

- 2009

- 0491

- 4823) p. 46]
RESPONSE : The 2012 Base Case SO 2 emission rates are not intended to simply reflect 2010 SO 2 emission rates. As described in the f inal Transport Rule preamble, the base case scenario reflects one in which CAIR is not in place. In 2010, CAIR was in place. Therefore, comparing 2010 historic emissions to 2012 base case emission projection s is comparing apples to oranges. See response to UARG comment letter in section 1 .3 above regarding coal switchin g and SO 2 emission rate projections. Issue 1.11: Ohio Modeling Assumptions
Comment : Errors were made in the parsed IPM files for Conesville 3. Consistent with the enforceable terms of a consent decree, American Electric Power has committed to retiring C onesville Unit 3 or switching it to natural gas by the end of 2012. In BC_F_12 and RC_F_12, EPA properly reflects that Unit 3 will be operating as a coal

- fired unit throughout 2012. EPA, however, has failed to take into account that Unit 3 will not be oper ating as a coal

- fired unit after 2012. Thus, in BC_F_2014, EPA mistakenly assumes that Conesville Unit 3 will still be operating as a coal

- fired unit. Errors were made in the parsed IPM files for Conesville Units 5 and 6. Because the FGD systems were upgr aded in 2009 and are now operating at 97% removal efficiencies, the appropriate SO 2 emission rate for those units is 0.16 lbs/ mmBtu (the result of removing 97 percent of the SO 2 emissions produced by burning coal with an emission rate of 6.5 lbs/ mmBtu of S O 2 ). In BC_P_12, EPA erroneously used an SO 2 emission rate that was too low (0.07 lbs/ mmBtu ). In BC_F_12, EPA over

- corrected and now is using an SO 2 emission rate that is too high (0.39 lbs/ mmBtu rather than 0.16 lbs/ mmBtu ). Errors were made in the parsed IPM files for the Richard Gorsuch Power Plant. Consistent with the enforceable terms of a consent decree, American Municipal Power permanently shut down all four boilers at Gorsuch on November 11, 2010, thus renderingFIP Revisions

- RTC Febru ary 7 , 2012 Page 102

102 them incapable of combusting coal or producing steam. This information is not reflected in BC_P_12, BC_F_12, or BC_F_14. Errors were made in the parsed IPM files for Bay Shore Unit 4. FirstEnergy now has no plans to install SCR technology on Bay Shore Unit 4. EPA accurately reflects this in BC_P_12, which indicates that no SCR has been installed on Bay Shore Unit 4. In BC_F_12, however, EPA mistakenly shows that an SCR system will be installed on Bay Shore Unit 4 in 2012. Errors were made in the parsed IPM files concerning the mix of coals being burned at Eastlake Units 1

- 5. The 2010 fuel blends for the Eastlake units are as follows: (i) Eastlake 1

- 3 is 90% subbituminous/10% bituminous coal; (ii) Eastlake 4 is 100% subbituminous coal; and (iii) Eastlake 5 is a 50/50 subbituminous /bituminous blend. EPA has incorrectly characterized the coals being burned at Eastlake 1

- 5. In BC_P_12, EPA had all Eastlake units burning bituminous coals, which is incorrect. In BC_F_12, EPA shifted the Eastlake units to blended coals, but included the wrong blend s. Specifically, in BC_F_12, EPA mistakenly has the Eastlake units burning a 20% subbituminous/80% bituminous coal blend, instead of the above

- listed blends for each Eastlake unit.
The above

- listed errors in the blends of coals being burned at Eastlake Un its 1

- 5 led to additional errors being made in the parsed IPM files concerning the SO 2 emission rates for those five units. The 2010 SO 2 emission rates for the Eastlake units are as follows: Eastlake 1

- 1.19 lbs/ mmBtu ; Eastlake 2

- 1.35 lbs/ mmBtu ; Eastlak e 3

- 1.41 lbs/ mmBtu ; Eastlake 4

- 0.77 lbs/ mmBtu ; and Eastlake 5

- 1.99 lbs/ mmBtu . In BC_F_12, however, EPA assumed that the SO 2 emission rates for each of the Eastlake units would be 3.6 lbs/ mmBtu . As a result of EPA’s using these erroneously high emissi on rates, there is a significant overestimation of 2012 SO 2 emissions from Eastlake Units 1

- 5: predicted SO 2 emissions in 2012 are almost 152,000 tons, which is almost 91,000 tons above the plant’s actual SO 2 emissions in 2010. Errors were made in the par sed IPM files concerning the SO 2 emission rates for Sammis Units 1

- 7. The 2011 SO 2 emission rate for Sammis Units 1

- 3 is 0.09 lbs/ mmBtu

. In BC_P_12, EPA failed to reflect accurately the controls that had been installed at these three units. Although EPA co rrected those erroneous technological assumptions in BC_F_12, EPA still fails in that final IPM run to reflect the actual SO 2 emission rates being achieved at Sammis Units 1

- 3. Specifically, in BC_F_12, EPA assumes that those three units will have an SO 2 e mission rate of 1.1 lbs/ mmBtu (which is required by an enforceable consent decree) when in fact those units are routinely achieving an emission rate of 0.09 lbs/ mmBtu . In addition, Sammis Units 5, 6 and 7 share a common FGD system and are achieving a commo n SO 2 emission rate of 0.07 lbs/ mmBtu . In BC_F_12, however, EPA erroneously assumes that these three units will, respectively, achieve SO 2 emission rates of 0.18, 0.13 and 0.13 lbs/ mmBtu . All three should be listed as achieving the same SO 2 emission rate, which

– based on the most recent data

– is 0.07 lbs/ mmBtu

.FIP Revisions

- RTC Febru ary 7 , 2012 Page 103

103 [Attachment to UARG comment letter, “J. Marchetti, J. E. Cichanowicz, Initial Identification of Unit Errors in Integrated Planning Model (IPM) Runs (Oct. 7, 2011)” (EPA

- HQ

- OAR

- 2009

- 0491

- 4823) p. 48

- 50]
RESPONSE : Commenter appears to be operating under the mistaken assumption that 2012 base case and policy case emission rates should reflect 2010 levels. However, as clearly described in the Transport Rule preamble, they are different scenarios in wh ich units would have different economic incentives and different potential emission rates. See section 6.2(b) of this document , below, for information addressing NO X emission rates. See section 6.2(c) of this document , below, for information addressing S O 2 emission rates. In regard to the Conesville 2014 issue, the comment has no bearing on 2012 modeling of contribution , since it is a 2014 issue. Any such adjustment to account for this retirement would only result in a downward adjustment to the state’s 2014 budget and a more stringent compliance scenario. However, EPA does not feel this is necessary as the action is driven by a consent decree whose caps are still collectively honored in the 2014 modeling, regardless of which units the reductions come f rom. The same applies for Conesville 5 and 6.FIP Revisions

- RTC Febru ary 7 , 2012 Page 104

104 2. New Unit Set
- Asides
Issue 2.1: Arkansas New Units Set
- Asides
Points Raised: (A) Additional new units need to be included in the set
- aside. Comment (A)(1) : EPA needs to adjust the new source set asid e to provide allowances for the operation of the John W. Turk, Jr. power plant. The Turk plant should be included in the NEEDS database, and the new set aside adjusted to eight percent. The 600 MW Turk plant is currently under construction, over 70% comp lete and is scheduled to come online in late 2012. This plant represents a known planned unit which was incorrectly omitted from NEEDS and subsequently the new source set aside calculation. [Letters: American Electric Power (EPA

HQ

- OAR

- 2009

- 0491

- 4737) p. 5; American Electric Power (EPA

- HQ

- OAR

- 2009

- 0491

- 9000) p. 51]
RESPONSE : EPA revise d the ozone

- season new unit set

- aside in Arkansas . See the preamble to this final Revisions Rule and also the Final Revisions Rule State Budgets and New Unit Set

Aside s TSD in the docket to this rulemaking.FIP Revisions

- RTC Febru ary 7 , 2012 Page 105

105 Issue 2.2: Texas New Unit Set
- Asides
Points Raised: (A) The new SPS generation unit, Jones Unit 3, should receive emissions allowances from the Texas New Unit Set
- Aside. Comment (A)(1) : Jones Unit 3 commenced co mmercial operation on June 30, 2011, and is therefore classified as a "new unit" under the CSAPR FIP. Consistent with this classification, Jones Unit 3 did not receive existing unit allocations. According to the new unit allocations methodology, Jones Un it 3 should be granted emissions allowances from the Texas New Unit Set

- Aside, which EPA expects to complete by August 1, 2012. Commenter (SPS) notes that their review of the National Electric Energy Data System ("NEEDS") database shows that Jones Unit 3 is not expressly listed in that database. The NEEDS database includes an entry for "SPPS TX Combustion Turbine," with the Unique Id number "82940_C_1," that appears to account for the new Jones Unit 3.6 (Jones Units 1 and 2, two older units at the Jones S tation, are specifically listed in the NEEDS database.) However, because there is not an express listing for Jones Unit 3 in the NEEDS database, SPS urges EPA to ensure that Jones Unit 3 will not ultimately be omitted from the 2012 New Unit allowance allo cation. [Letters: Southwestern Public Service Company (SPS) (EPA

- HQ

- OAR

- 2009

- 0491

- 4752) p. 5

- 6]
RESPONSE : In the IPM file “WebReady_ParsedFile_TR Base Case Final_2012,” SPPS TX Combustion Turbine (Unique Id 82940_C_1) is listed, corresponding to Jones Unit 3. The unit is also included as a planned unit in the 2020 parsed IPM file. Therefore, this unit was included as a planned unit in the calculation of the Texas new unit set

- aside, which will be available to the unit as described in s ection VII.D of the f inal Transport Rule.FIP Revisions

- RTC Febru ary 7 , 2012 Page 106

106 Issue 2.3: Other Set
- Aside Issues
Points Raised: (A) EPA should identify sources in North Carolina that have responded to the Renewable Energy Portfolio Standard and provide allocations for those sources under the new unit set - as ide. Comment (A)(1) : While generation from these units does not correspond to new demand, there has been a shift in native load generation in response to NC's environmental goals. In designing its program in response to CSAPR, North Carolina will take into consideration the overall state goals and decide how best to meet the overall CSAPR allocations. [Letters: North Carolina Department of Environment and Natural Re (EPA

- HQ

- OAR

- 2009

- 0491

- 4776) p. 2]
RESPONSE : The impacts of state

- level renewable po rtfolio standards on generation are accounted for in the IPM Base Case. For details on how these policies are represented in IPM, refer to Chapter 3 in the Documentation for EPA Base Case v.4.10

- Using the Integrated Planning Model. Additionally, chan ges to allocation methodology are outside the scope of this rulemaking. The allocation methodology is described in preamble section VII.D of the final Transport Rule (s ee 76 FR 637860, 63868). Further, the comment does not specify immediate

- term unit

- spe cific operational constraints nor does it specify immediate binding operational requirements on specific units that require out

- of

- merit

- order dispatch , which were the technical bases for which revisions were being considered in this rulemaking, as explain ed in this rule’s proposal

. Finally, s tates may take individual state goals into account when allocating allowances through the State Implementation Plan (SIP). States are free to allocate to sources how they see most appropriate by submitting a SIP. (B) E PA should have provided SO 2 allowance allocations to Elm Road Units 1 and 2 in Wisconsin from the new unit set
- aside. Comment (B)(1) : Errors were made in the parsed files for Elm Road Units 1 and 2. Unit 1 began commercial operation in February 2010; Un it 2 began commercial operation in February 2011. Under the terms of CSAPR, both units should receive SO 2 allowance allocations from the new unit set

- aside pool. In the final rule, however, EPA erroneously gives Elm Road Unit 1 allowances from the main a llocation pool instead of from the new unit set

- aside pool. (See also Issue 1.4). [Letters: We Energies (EPA

- HQ

- OAR

- 2009

- 0491

- 4781) p. 5

- 6]
RESPONSE : Regarding Elm Road Unit 1, the unit was reported to EPA as starting operation on July 23, 2009 and re ported emissions data for that year, conforming to an existing unit. Commenter has not demonstrated why this data is void or provided sufficient information to demonstrate that their commercial operation data ended up occurring later than they reported.FIP Revisions

- RTC Febru ary 7 , 2012 Page 107

107 However, EPA notes that s tates have the flexibility to allocate allowances to sources through a SIP at the level , and using the methodol ogy, they deem most appropriate. EPA treated Unit 2 as a new unit , as noted by the commenter. (C) Repowered boilers shoul d have been reclassified as new units. Comment (C)(1) : It is DTE Stoneman’s position that the repowered renewable energy plant that underwent New Source Review permitting and resulted in fuel switching to wood biomass with low sulfur content and installa tion of SNCR and OFA as BACT for NO X control, be afforded sufficient allowances to cover 100% of its projected emissions (provided in table) or significantly increase its allowance allocation under the current approach by relying on projected heat input. The basis for this petition, besides the severe economic hardship that the current EPA approach will impose on the facility, are the errors we identified in EPA’s application of the allowance allocation methodology and include: 1) Classification of the un its as “existing” versus “new”; 2) Erroneous inputs (e.g. projected actual emissions for 2012 and 2014) to the IPM model under the current approach; 3) Emissions Reductions already achieved through New Source Review consistent with intent of the CSAPR rule ; and 4) If classified as “existing,” EPA should not rely on historical heat input from the facility as this data does not reflect future plans for plant operation. It should rely on projected heat input. The facility consists of two 340 mmBtu/hr rated b oilers serving through cross connected steam headers, 33 MW, and 18 MW generators. Emissions are through a common stack. The two units were originally built in 1949 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 d own 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 August 2010 period while the units were permanently di sabled by removal of the lower half of each unit and replacing boiler tubes. The units were replaced by new stoker grate units to enable combustion of wood biomass. The units underwent New Source Review permitting which required as BACT the installation of add

- on emission controls for NO X including SNCR and OFA. The conversion of the plant from coal to wood biomass provided significant reduction in SO 2 emissions due to the low sulfur content of wood biomass. These new stoker grate units started the comm issioning process on July 28, 2010 and began commercial operation on October 8, 2010. Since commercial operation began after January 1, 2010 the units should receive allowances from the new unit set aside and not be allocated allowances as existing units. [Letters: DTE Stoneman LLC (EPA

- HQ

- OAR

- 2009

- 0491

- 4783) p. 2

- 3]
RESPONSE : Changes to the allocation methodology are out side the scope of revisions proposed and for which EPA solicited comment . See section 6.5, below, for more information.FIP Revisions

- RTC Febru ary 7 , 2012 Page 108

108 (D) Tennessee new unit annual SO 2 set - aside allocations are in error. Comment (D)(1) : EPA states in the preamble discussion that the new unit set aside [for the SO 2 Group 1 Program] for the state of Tennessee would increase in 2013, 2018, 2019, and each year thereaft er, by 8,460, 3,173 and 5,225 tons respectively. We wish to bring a couple of discrepancies to EPA' attention. First, the increase in the new unit set aside for 2019 and each year thereafter would be 8,398 tons, not 5,225 tons, since these increases shou ld match the reduction in existing unit allocations to maintain the total Tennessee CASPR allocation level. Second, the set asides provided in this preamble discussion do not match those provided in the tables under Section 97.610 of the revised proposal on pages 63876 and 63,877. EPA should correct these discrepancies if it does not abandon the unit level allocation approach TVA requested with respect to their consent decree comments. [Letters: Tennessee Valley Authority (TVA) (EPA

- HQ

- OAR

- 2009

- 0491

- 479 2) p. 3]
RESPONSE : The tables represent the new unit set aside as defined in the Transport Rule. While EPA is not altering the new unit set aside for Tennessee, any allowances that are not reallocated under this rulemaking are transferred to the new uni t set aside. EPA is adjusting the application of the consent decree annual tonnage limits (ATL) so that any adjustments to the annual tonnage limits after 2017 do not alter allowance allocations. Therefore, the 2018 and 2019 adjustments are no longer appl icable. (E) EPA should reduce the Louisiana new unit set aside. Comment (E)(1) : Commenters request that EPA revise the Louisiana new unit set aside from 3% to 2%, and redistribute the remaining 1% to existing EGUs. The only new units that have commenced o peration since January 1, 2010, were the two J. Lamar Stall units 6A and 6B at the Arsenal Hill power station (ORIS 1416). Ozone season NO X emissions were 46.4 tons in 2010 and 57.3 tons in 2011. The 2011 ozone season represents a full year of normal ope ration, and emissions are much less than 1% of the state budget. In the preamble to the final rule, EPA discusses when a new unit set aside was increased above 2%. A new unit set aside is increased above 2% only if EPA has knowledge that additional know are units are coming online between January 1, 2010 and 2012. Because the Washington Parish Energy Center is not a known unit coming online during this period (partially built, non

operational, no current PSD permit), EPA should not have increased the set aside and any allocations set aside for Washington Parish Energy Center should be added back to the state's ozone season budget. [Letters: Lafayette Utility Systems (EPA

- HQ

- OAR

- 2009

- 0491

- 4807) p. 18

- 19; Louisiana Chemical Association (LCA) (EPA

- HQ

- OAR

- 2 009

- 0491

- 4803) p. 15

- 16]
RESPONSE : EPA plan s to revise the ozone

- season new unit set

- aside in Louisiana in a separate action, based on comments that EPA solicited (76 FR 63860) . See Final Revisions Rule State Budgets and New Unit Set

- Asides TSD in the d ocket to this rulemaking.FIP Revisions

- RTC Febru ary 7 , 2012 Page 109

109 (F) The basis for the new unit set aside for Indian lands in Louisiana should be identified. Comment (F)(1) : EPA set aside 18 tons as a new unit set aside for Indian lands. Commenters are not aware of any proposed projects on In dian lands. The basis for this set aside should be discussed and made available for public comment or EPA should eliminate this set aside. [Letters: Lafayette Utility Systems (EPA

- HQ

- OAR

- 2009

- 0491

- 4807) p. 19; Louisiana Chemical Association (LCA) (EPA

- H Q

- OAR

- 2009

- 0491

- 4803) p. 16]
RESPONSE : The methodology for calculation of Indian country new unit set

- asides is provided in the final Transport Rule s ection VII.D. As described in this methodology, the number of allowances included in the Indian country new unit set

- aside is not dependent on the existence of proposed projects. EPA in fact made the basis for Indian country new unit set

- asides public and available for comment as part of the Transport Rule allowance allocation NODA issued in January, 2011 (76 FR 1109, January 7, 2011), and the Agency reviewed all comments submitted on that topic before finalizing the establishment of Indian country new unit set

- asides in the final Transport Rule signed in July, 2011. (G) EPA should address specific errors related to Missouri’s new unit set
- aside. Comment (G)(1) : KCP&L requests increased new unit set

- aside allowances for SO 2 , ozone season NO X , and annual NO X because the final CSAPR calculation of the new unit set

- aside erroneously omitted Iatan Unit 2’s pr ojected emissions. This request is similar to the request granted to Arkansas’s Plum Point Unit 1 in the Proposed Revisions to Transport Rule. See 76 Fed. Reg. at 63864. It appears from the Technical Support Documents associated with the final CSAPR tha t only one new unit in Missouri was modeled by EPA. The NEEDSv4.10 FTransport file indicates a SPPN_MO_Coal Steam unit with 300 MW capacity which appears to be the John Twitty Unit 2, formerly Southwest Power Station Unit 2. KCP&L requests that EPA incre ase Missouri’s SO 2 , ozone season NO X , and annual NO X budget to include an increased new unit set

- aside. EPA should increase the portion of that budget dedicated to the new unit set aside. In the CSAPR, EPA had determined a 3 percent new unit set

- aside fo r ozone season NO X and annual NO X in Missouri. Both of those values should be changed to 6 percent. In the CSAPR, EPA had determined a 2 percent new unit set

- aside for SO 2 in Missouri. This value should be changed to 3 percent. The revision is consiste nt with the new unit set

- aside methodology described in the CSAPR. The 2 percent allocation should be maintained for future “planned” new units in Missouri. See 76 Fed. Reg. at 48291. The updated values simply reflect the revised classification of one u nit to be treated as a new unit for purposes of unit

- level allowance allocation. This unit, Iatan Unit 2, commenced commercial operation on or after January 1, 2010, and therefore would be considered a new unit under the final CSAPR’s unit

- level allocatio n methodology (See 76 Fed. Reg. at 48290); however, the final CSAPR erroneously omitted this unit’s projected emissions from the calculation of Missouri’s SO 2 , ozone season NO X , and annual NO X budget new unit set

- aside. Including this unit’s projected emi ssions in the calculation would yield a revised new unit set

- aside of 3 percent for SO2and 6 percent for ozoneFIP Revisions

- RTC Febru ary 7 , 2012 Page 110

110 season NO X and annual NO X of Missouri’s budget instead of the previous 2 percent and 3 percent values for the respective new unit set

- asides. Th is change should be made for both Phase 1 compliance commencing in 2012 and Phase 2 compliance commencing in 2014. [Letters: Kansas City Power and Light Company (EPA

- HQ

- OAR

- 2009

- 0491

- 4804, 4826) p. 3

- 4]
RESPONSE : EPA is revising the Missouri new unit set

- asides. See the Final Revisions Rule State Budgets and New Unit Set

- Asides TSD in the docket to this rulemaking. Comment (G)(2) : City Utilities (CU) believes that EPA erred in establishing the Missouri CSAPR budgets for sulfur dioxide ( SO 2 ), annual nitrogen dioxide ( NO X ), and seasonal NO X , by failing to account for two new units that commenced operation in the state this year. This error was compounded by a failure to provide adequate allowances in the New Unit Set Aside (NUSA) pools, leaving the st ate with a dramatic shortage to cover future generating needs. These new units were repeatedly identified to EPA, by CU, The Missouri Department of Natural Resources, and others, during the public comment period on the original rule and subsequent comment s on at least two Notices of Data Availability. However, the record appears to indicate that corrections made to the Missouri database actually compounded rather than resolved the erroneous listings. These errors are similar if not exactly equivalent, to errors recognized for at least one other state (Arkansas) and for which correction is proposed in the current regulatory action. Unfortunately, EPA has not proposed a similar adjustment to correct Missouri errors. CU firmly believes that these same corr ections are justified for the state of Missouri and that these corrections should properly be completed as part of the current effort to correct misallocations. In the docket for the July 2010 proposed rule, EPA included a spreadsheet entitled the Nationa l Electric Energy Database System, version 3.02 (NEEDS v3.02). This exhaustive record detailed the inputs to EPA's energy demand model and included 425 electric generating units in the state of Missouri. One of these, identified as 82710, was a generic 1 ,150 MW coal

- fired unit, expected to come on line later in 2010. Several commenters to the proposed Transport Rule (as CSAPR was termed at that time), most notably the Missouri Department of Natural Resources pointed out that there were actually two new u nits under construction in Missouri, our John Twitty Energy Center (formerly Southwest Power Station) Unit 2 in Greene County and the Iatan Energy Center Unit 2, owned by Great Plains Energy and others, and located in Platte County. Together, these two un its total 1,150 MW (300MW at Twitty 2; 850 MW at Iatan 2)

- the total shown for the generic "placeholder" unit 82710 in NEEDS v3.02. However, these two units have different unit heat rates, air pollution control devices, and permitted emission rates, rend ering the conflation of these two units into a single 1,150 MW placeholder unworkable for the purposes of EPA's model. In response, EPA appears to attempt a correction to this Missouri issue when they revised the database to version 4.10. However, rathe r than split the new Missouri generation into two distinctly permitted units, EPA substituted a new placeholder, identified as 82934, listed only as 300 MW of coal

- fired capacity. In effect, this acknowledges the construction of Twitty Unit 2 but omits Ia tan Unit 2 from further consideration. Moreover, the regimen of control devices andFIP Revisions

- RTC Febru ary 7 , 2012 Page 111

111 permit limits shown for placeholder unit 82934 appear to be specific for the larger Iatan unit rather than the 300 MW Twitty unit. Although these two new units have the l owest emission rates in the state, the modeled result based on the flawed final NEEDS v4.10 inputs dramatically understate their expected annual emissions. The solution is that Missouri's allowance budget should be increased to account for the two new uni ts in the state. EPA has proposed to make a very similar change to the Arkansas budget, based on a similar oversight concerning the Plum Point Energy Center, but has not proposed to amend the Missouri budget. CU provides estimates of the required increas e in the Missouri Phase 1 and Phase 2 budgets. [Letters: City Utilities Springfield Missouri (EPA

- HQ

- OAR

- 2009

- 0491

- 4814) p. 1

- 3]
RESPONSE : EPA is revising the Missouri new unit set

- asides. See the Final Revisions Rule State Budgets and New Unit Set

- A sides TSD in the docket to this rulemaking. Comment (G)(3) : By overlooking the two new Missouri units

- or at least the larger of them

- in determining Missouri's NUSA pool, EPA violated its stated protocol and therefore under

assigned allowances to that pool. EPA neglected to increase the NUSA for SO 2 above the minimum 2%, despite the fact that two new "planned" units (i.e., those already under construction and which would enter service prior to January 1, 2012) were repeatedly pointed out by commenters . In the case of annual and seasonal NO X , the NUSA level was set at 3%, only one small notch above the minimum level, apparently to account for one and only one of the planned units

- and the smaller one at that. In the proposed amendments of October 14, EPA recognized a similar error for the state of Arkansas and revised the state NUSA to 5% on the basis of only one overlooked unit. Accordingly, we feel that the Missouri NUSA should be increased to the maximum 6% to account for two "planned" units in th e state. iv. Suggested Alternative language Using EPA's own test, the NUSA for Missouri should be increased to 3% of the state budget for annual SO 2 , 6% for annual NO X , and 6% for seasonal NO X . Combined with the increased budgets implemented above, this would result in NUSA absolute levels provided in a table in the comment letter. CU recognizes that EPA did not ask for Missouri

- specific revisions as part of the October 14 proposed amendments to the CSAPR program. Nonetheless, the corrections requested herein are justified, necessary, and identical in nature to proposed changes for a neighboring state. It would be unconscionable for the Agency to correct the erroneous record regarding Arkansas, yet refuse to do the same for Missouri. [Letters: City Ut ilities Springfield Missouri (EPA

- HQ

- OAR

- 2009

- 0491

- 4814) p. 3

- 5]
RESPONSE : EPA is revising the Missouri new unit set

- asides. See the Final Revisions Rule State Budgets and New Unit Set

- Asides TSD in the docket to this rulemaking. (H) EPA should addre ss specific errors related to Tennessee’s new unit set
- aside.FIP Revisions

- RTC Febru ary 7 , 2012 Page 112

112 Comment (H)(1) : There is a discrepancy in how the new unit set aside for Tennessee would increase for Tennessee if the proposal were finalized and Table 2 which shows no increase. The proposed rule states that, if the additional constraint is finalized as proposed, the new unit SO 2 set aside for Tennessee would increase in 2013, 2018, 2019, and each year thereafter, by 8,460, 3,173, and 5,225 tons respectively. However, the new unit set aside in the proposed rule (Table 1) shows no increase from that in the August 8, 2011, final rule (Table 2). It is 2,963 tons in both cases. [Letters: Tennessee Department of Environment and Conservation (EPA

- HQ

- OAR

2009

- 0491

- 4750) p. 2 of Attachment; Tenne ssee Valley Authority (TVA) (EPA

- HQ

- OAR

- 2009

- 0491

- 4792) p. 3]
RESPONSE : The tables represent the new unit set

- aside as defined in the Transport Rule. While EPA is not altering the new unit set aside for Tennessee, any allowances that are not reallocated under this rulemaking are transferred to the new unit set aside. As a result, when these allowances are transferred, the new unit set aside in Tennessee will have additional allowances. EPA is adjusting the application of the consent decree annual tonna ge limits so that any adjustments to the annual tonnage limits after 2017 do not alter allowance allocations. Therefore, the 2018 and 2019 adjustments are no longer applicable. (I) The request from NCDAQ for additional allocation under the NC FIP due to generation required by the State’s REPS should be rejected. Comment (I)(1) : Commenters question NCDAQ’s request for additional allocations to be allocated to NC emissions sources under the NC FIP due to generation required by the State’s Renewable Ener gy Portfolio Standard (REPS). NCDAQ “suggests that EPA consider identifying sources in NC that have responded to the REPS and provide allocations for those sources under the new unit set
- aside” which should be rejected both as a matter of the intended pol icy of CSAPR and because the NCDAQ comments are not within the parameters EPA established in their request for comments. Commenters cite to the Federal Register notice (76 FR 63860) and assert that NCDAQ does not include the required “data that demonstrat e why the unit in question is required to generate in the immediate term for reasons other than the regional economic sale of electricity” and does not provide an explanation as to how increased output in response to the State’s REPS is “non
- economic gener ation” as required by the comment parameters. Increased generation at sources in response to the NC REPS is actually guaranteed by law to be economic. The REPS requires an electric utility to “establish the least cost mix of demand reduction and generati on measures that meet the electricity needs of its customers.” By law, investor owned public utilities (IOUs) may recover their reasonable and prudent incremental costs of REPS compliance in excess of traditional production costs, up to the level of per
- a ccount cost caps, in the form of a rider added to their customer rates. While it is true that IOUs must produce a certain amount of electricity from non
- traditional sources to satisfy the REPS, the law was specifically designed so that the production woul d remain economic forFIP Revisions

- RTC Febru ary 7 , 2012 Page 113

113 the IOUs and labeling this generation as “non
- economic” is a gross misclassification. Aside from small investments in solar in accordance with a mandatory set
- aside, NC utilities intend to use biomass and landfill gas to fulfill most of their REPS requirement. The increased use of these combustion sources to meet the REPS will not make an appreciable difference in air quality and may actually have a detrimental effect. Providing additional allocations to NC’s new unit set aside for these increases does not appear to be consistent with the goal of CSAPR or in the best interest of states’ air quality. Increased allocations will allow utilities to gain additional credits from increased production at combustion sources at existing facil ities. The fact that the fuel used has been determined to satisfy the REPS requirement should not exempt them from meeting the NO X , SO 2 and PM requirements allotted to each state. In fact, not counting increased production at a retrofitted facility towar d the existing allowances in the FIPs may provide an extra incentive to the utilities to fulfill the REPS in this manner, rather than investing in clean, emissions
- free renewables to satisfy the REPS. [Letters: Appalachian Voices, North Carolina Conser vation Network, North Carolina League of Conservation Voters, and Southern Environmental Law Center (EPA
- HQ
- OAR
- 2009
- 0491
- 4862) p. 1
- 3]
RESPONSE : The impacts of state

- level renewable portfolio standards on generation are accounted for in the IPM Base Ca se. For details on how these policies are represented in IPM, refer to Chapter 3 in the Documentation for EPA Base Case v.4.10

- Using the Integrated Planning Model.FIP Revisions

- RTC Febru ary 7 , 2012 Page 114

114 3. Consent Decrees
- Allowance Allocations
Points Raised: (A) Disagrees with EPA's propo sal to impose additional constraints on specific units covered by consent decrees. Comment (A)(1) : EPA proposes to add a constraint on Transport Rule unit

- level SO 2 and NO X allowance allocations to reflect the maximum allowable emissions at the units aff ected by existing utility consent decrees which contain annual tonnage limits, and require the surrender or restrict trading of Transport Rule allowances allocated in excess of annual tonnage limits. The proposed constraint would affect unit

- level alloca tions to 82 units in Alabama, Indiana, Kansas, Kentucky, Ohio, and Tennessee. Tennessee is a signatory to an enforceable Consent Decree with the Tennessee Valley Authority (State of Alabama et.al. v. TVA, Civil Action No. 3:11

- cv
- 00170, filed April 14, 20 11, approved June 30,2011). The Federal Facilities Compliance Agreement (FFCA) signed by EPA and TVA contains similar provisions to the consent decree and would be similarly impacted. The Consent Decree and FFCA include specific provisions requiring the surrender of excess NO X and SO 2 allowances that are not required to meet Federal or State Clean Air Act requirement for the TVA system in the calendar year. However, the Consent Decree does not require the surrender of surplus allowances from specific fac ilities and units, but allows TVA the discretion to choose specific facilities for allowance surrender. Tennessee believes the proposed CSAPR constraint could be harmful for the following reasons: The system

- wide cape and the negotiated flexibility for i ndividual units was an essential provision of the consent decree, and Tennessee believes a final agreement would have been more difficult and perhaps impossible without this flexibility. The proposed constraint does not alter the Consent Decree, but does limit the discretion that would have been allowed under the Consent Decree. By fundamentally altering the manner in which TVA would be required to comply with an obligation in the Consent Decree, this could be argued as a modification that would require a greement of all the Consent Decree parties. Paragraph 84 of the Consent Decree increases the system

- wide annual tonnage limits for SO 2 in 2013 and 2014 if one or more nuclear units are shut down due to forced outages or safety concerns. EPA's proposed c hanges would practically negate this provision, because it would not change allocations under the transport rule for a higher system

- wide cap under this contingency. EPA''s final Transport Rule allowed States to submit SIP revisions that allocate allowanc es for the 2013 control period to units that commenced operation before January 1, 2010. States were required to provide notification to EPA within 70 days of publication of the final rule, if the State intends to submit State

- specific 2013 allocations. Tennessee elected, based on the original provisions of the rule, to accept the FIP allocations in lieu of SIP submittal, and asserts that theFIP Revisions

- RTC Febru ary 7 , 2012 Page 115

115 October 17, 2011 deadline did not provide sufficient time for affected States to review and act upon the October 1 4, 2011 proposal package. Tennessee would have considered adoption of State

- specific allocations for 2013. EPA's decision to initiate rulemaking so quickly after the Consent Decree was finalized is troubling. The Consent Decree was finalized on June 30, 2011. The proposed rule was signed on October 6, 2011. While EPA is not bound by such an agreement in perpetuity (since changing air quality standards or other concerns may require new rules that go beyond existing agreements), the short time period bet ween the Consent Decree and proposed rule suggests EPA needs to better harmonize the actions of the Clean Air Markets Division and the Office of Enforcement and Compliance Assurance. Finally, EPA's proposed changes could undermine the EPA's ability to con duct future negotiations. The proposed changes, if finalized, could give the impression that EPA did not negotiate in good faith. It was clear in the negotiation of the Consent Decree that allowances would be surrendered, and there could have been

- but importantly was not

- a more specific methodology described for how the allowances would be surrendered. [Letters: Tennessee Department of Environment and Conservation (EPA

- HQ

- OAR

- 2009

- 0491

- 4750) p. 1

- 2 of Attachment]
RESPONSE : EPA disagrees with the c omment that the adjustment of unit

- level allocations can be viewed as a modification to the terms of the consent decree. The new constraint on unit

- level allocations, as adopted in the final rule, does not alter any obligations, timelines, or other requir ements of the consent decrees. Most of the consent decrees addressed by this rule, including the TVA consent decree, define the SO 2 and/or NO X allowances covered by the consent decree allowance surrender provisions as allowances issued in any emission tra ding or marketable permit program under the CAA and/or a SIP. None of the consent decrees is premised on any particular allocation methodology or distribution of unit

- level allocations being employed in the applicable trading programs. Moreover, the con sent decrees do not, and cannot, preclude any particular allocation methodology or distribution from being implemented in future trading programs. The TVA consent decree, like all of the consent decrees at issue in this rulemaking, contains a provision th at clearly obligates TVA to comply with any other federal laws or regulations, such as the Transport Rule, regardless of the actions otherwise permitted under the consent decree: 199. This Consent Agreement is not a permit. Compliance with the terms of this Consent Agreement does not guarantee compliance with any applicable federal, state, and/or local laws and/or regulations. The emission limitations set forth herein do not relieve TVA from any obligation to comply with other state and federal require ments under the Act, including TVA’s obligation to satisfy any modeling requirements set forth in the Act.FIP Revisions

- RTC Febru ary 7 , 2012 Page 116

116 Consent Decree, ECF No. 15, June 30, 2011, Alabama v. Tennessee Valley Authority , Case No. 3:11cv170 (E.D. Tenn.). The TVA consent decree clearly d oes not supplant TVA’s obligation to comply with the requirements of the Transport Rule, nor was the consent decree intended to in any way limit the EPA’s authority to implement future regulations. Furthermore, at the time that the TVA consent decree was executed by the parties, the Transport Rule had already been proposed, and TVA therefore had notice that its federal regulatory obligations were subject to change in the near future. EPA further disagrees that the adoption of a constraint on unit

- level allocations (and TVA allocations, in particular) based on consent decree annual tonnage limits (ATLs) reduces the flexibility that the TVA consent decree allows for compliance in any significant way. EPA’s approach does not prevent TVA from balancing em issions among its units in three different states. TVA remains free to comply with the terms of the consent decree in any manner it sees fit, including an approach that would result in more emissions in one state than the allowances that are allocated to units in that state. That two of the states in which TVA units are located (Tennessee and Kentucky) are in the Transport Rule SO 2 Group 1 trading program and one (Alabama) is in the Transport Rule SO 2 Group 2 trading program does not alter this fact. Fir st, the fact that TVA’s units are divided between two trading groups is not new to this revisions rule. The two trading groups were established in the final Transport Rule. Although EPA is reducing the number of allowances generally allocated to the TVA units in these states, the division of the units between Group 1 and Group 2 remains unchanged. Second, t o the extent EPA’s approach results in a different distribution of allowances among the states or between units in these two SO 2 trading programs than would result from unadjusted allocations and the surrender under TVA’s consent decree of some of the allocated allowances, TVA acknowledged that its ability to transfer allowances from its units in one state in a Transport Rule trading program to its unit s in another state in the same Transport Rule trading program is not limited by this rule. See “Conference Call Between TVA and EPA to Discuss TVA Comments on Proposed Revisions to FIP Allocations Based on TVA Consent Decree,” concerning a conference cal l between TVA and EPA on December 15, 2011 in the docket to this rulemaking (Docket No. EPA

- HQ

- OAR

- 2009

- 0491). In addition, because all existing units in Tennessee are subject to either the constraint on historical emissions or the constraint on consent decree annual tonnage limits, the unallocated allowances in Tennessee will be directed to the state's new unit set aside as a result of the revisions made in this final rule. At the end of the calendar year, any allowances remaining in the new unit set as ide are distributed to existing units in proportion to those units' allocations, as explained in the final Transport Rule (76 FR 48208). There are currently no known permit applications for new coal

- units to start operation in 2013 in Tennessee. Therefor e, because TVA units received over 99 percent of Tennessee's 2013 SO 2 allowance allocations, nearly all of the allowances in the new unit set aside, including both the original new unit set aside of 2 percent of the state’s budget and those allowances adde d to the new unit set aside as a result of both the constraint on historical emissions and the consent decree constraint, will be distributed back toFIP Revisions

- RTC Febru ary 7 , 2012 Page 117

117 TVA. Thus, given Tennessee’s unique situation, the total allowances distributed to TVA in Tennessee will not be significantly changed for 2013. EPA agrees that the maximum ATL (rather than the ATL applicable in the absence of certain contingencies, such as a nuclear unit shutdown in the case of TVA’s consent decree) allowed under the consent decree should be used to adjust allocations to units covered by the decree. This approach avoids the situation where systems might have emission levels that are permissible under the consent decree but higher than the units’ allowance allocations, which had been reduced solely as a result of the consent decree constraint. However, any ATL changes due to shutdowns, controls, or retirements that are required by certain dates or that have already been implemented, are included in the assumptions for selecting and apportioni ng the ATL. Consequently, EPA is adopting, in the final rule revision, a constraint on TVA’s unit

- level allocations based on the least stringent ATL under TVA’s CD, i.e., the ATL applicable in the event of a shutdown of a TVA nuclear electric generation u nit that is greater than 120 days in calendar year 2012, 2013, or 2014. TVA’s total SO 2 annual allocation under the final revised rule will be therefore greater than the allocation under the proposed revised rule in 2013. Regarding the timing of the prop osed revisions and the deadline for a state to notify EPA of their intent to allocate 2013 allowances, in deciding whether to issue allowances to sources or give state's additional time to submit allowances, EPA has to balance many considerations, includin g the sources’ interest in receiving allocated allowances quickly. EPA proceeded to allocate allowances under the FIPs as soon as the deadline passed for a state to submit notice that they intended to allocate allowances for 2013 unless we had received su ch a notice from a state. Allowances were therefore issued to sources in Tennessee on October 25, 2011. The commenter’s letter is dated November 22, 2011, several weeks after the allowances were allocated in Tennessee. We do not see any justification, b ased on this comment, for withdrawing previously allocated allowances. Moreover, the commenters fail to explain why the proposed or final rule revisions (and the revisions with regard to Tennessee in particular) would affect the state’s consideration of whether to submit to EPA the state’s 2013 allowance allocations for existing units. As explained above, the TVA units in Tennessee are likely to regain most of the allowances that are being added to the new unit set aside as a result of the consent decre e constraint when the new unit set aside is distributed to sources in the state at the end of 2013. Finally, the proposed rule was signed and widely disseminated on October 6, 2011, 11 days before the deadline for a state to submit notice of its intent t o allocate 2013 allowances. If a state wished to have more time to consider establishing allowance allocations for 2013, the state could have submitted a notice of intent to provide such allocations and still subsequently decided not to submit 2013 alloca tions to EPA. States that did not submit a notice of intent with respect to the 2013 allocations still have the opportunity to submit allocations for 2014 and beyond.FIP Revisions

- RTC Febru ary 7 , 2012 Page 118

118 Comment (A)(2) : EPA states in its proposal that the unit level allowance allocations u nder the Transport Rule FIPs did not properly account for provisions in those Consent Decrees that effectively require the surrender or restrict the trading of excess Transport Rule allowances. See 76 Fed. Reg. 63,860, 63,868 (October 14, 2011) Accordingl y, EPA has proposed adding a constraint on the unit level allocations designed to reflect its calculation of the maximum allowable emissions at the units affected by existing utility consent decrees which contain annual tonnage limits and require the surre nder or restrict trading of Transport Rule allowances allocated in excess of annual tonnage limits. TVA strongly objects to this proposal and asks that EPA not do this or, alternatively, to restructure it as suggested below. Contrary to EPA's assertion, id. at 63,869, this proposal will effectively modify to varying degrees consent decree provisions that companies bargained with EPA to obtain. If EPA does this, it would be using its rulemaking authority to undo or compromise provisions in agreements whic h it negotiated. This is questionable policy, raises good faith questions, and should and will make companies wary of negotiating settlements of disputes in the future. While EPA may establish general rules which incidentally affect earlier negotiated se ttlement agreements, this proposal is not a general rule as it specifically targets companies which have settlement agreements with EPA. Indeed, according to EPA’s analysis, only six companies, including TVA, would be affected. TVA notes that courts have held that federal agencies are liable to companies for damages resulting from the enactment of specific, as opposed to general, legislation by Congress that breaches existing agreements with federal entities. They go on to reference a number of cases in support of their assertion, and go on to point out that EPA’s proposal here is not a response forced by subsequently enacted federal legislation. Rather, this would be the conscious decision and action of the federal entity that negotiated the provisions being undermined or negated. It calls into question EPA’s good faith and fair dealing. EPA's agreement with TVA exemplifies the problems with this proposal and the potential harm that can result to EPA’s settlement negotiating partners. Under Paragraph 88 of the EPA

- TVA agreement, the SO 2 system wide cap negotiated by the two agencies can be increased if TVA must shut down one or more of its nuclear units for more than 120 days within any of the calendar years 2012, 2013, or 2014. The agreement provides for increasing the SO 2 caps for these calendar years by 10,000 tons, 5,482 tons and 5,893 tons respectively in the event of a shutdown. Removing this flexibility from the agreement could result in TVA incurring a monetary loss of $6 million to $10 millio n for each of these calendar years, assuming an SO 2 allowance price of $1,000 per ton of SO 2 emitted. In the mid

- 1980's, safety concerns led to the shutdown of all of TVA's nuclear units, requiring TVA to rely more on its fossil units to meet demands on i ts electric system. This provision was very important to TVA in light of this history and EPA's proposal here would nullify it. The proposal also would compromise the flexibility TVA has under the compliance agreement and CSAPR as originally promulgated to surrender any excess CSAPR allowances over the agreement's tonnage limitations from units of TVA's choosing rather than surrendering theFIP Revisions

- RTC Febru ary 7 , 2012 Page 119

119 excess on an EPA

- prorated basis across the TVA fleet. This loss of flexibility is compounded because TVA operates a ffected units in multiple states (Alabama, Kentucky, and Tennessee). Two of these States (Kentucky and Tennessee) are in Group 1 under CASPR while the third (Alabama) is in Group 2. Allowances cannot be traded or transferred between the two trading group s. Under CSAPR as originally promulgated and the compliance agreement, TVA could balance the operation of its units to more fully utilize the allowances allocated to it. Under the proposal, its ability to do this is compromised. EPA's proposal reduces T VA's CSAPR allocations for 2013, 2018, 2019, and each year thereafter on the basis that the tonnage limitations in the agreement for these calendar years are less than the original CSAPR allocations. However, any such future reductions in allocations (and especially those reductions in the distant years

- 2018 and beyond) fail to contend with future elections made by TVA to retire certain units. While such retirements would likely result in TVA's CSAPR allocations dropping below the tonnage limitations of the agreement, the allocation scheme put into effect by EPA's current proposal will continue to exact the surrender of allowances. We urge EPA to not proceed with this aspect of its October 14 proposal. Alternatively, EPA could allow owners with Consent Decrees (or Federal Facility Compliance Agreements) to submit a report within 45 days of the end of the control period that provides an accounting of the allowances that would be surrendered by the owner consistent with its obligations under the Consent D ecree. These surrendered allowances could then be redistributed by EPA to other existing facilities or new source set asides prior to the true

- up dates. [Letters: Tennessee Valley Authority (TVA) (EPA

- HQ

- OAR

- 2009

- 0491

- 4792) p. 1

- 3]
RESPONSE: See the r esponse to comment 3(A)(1), above. For the purpose of allocating allowances under the Transport Rule, EPA will use the CD ATL that becomes effective in 2017 for the years 2017 and beyond for units subject to an existing CD ATL. EPA is taking this approac h in the final revised rule, even though TVA’s CD includes a lower CD ATL starting in 2018, for the following reasons:

● The TVA CD is unique in that it is the only CD used to adjust allocations that includes an ATL that changes after 2017. The application of the post

- 2017 ATL is affected by unit

retirement decisions that TVA may make in the future. As a result, it is difficult for EPA to determine a reasonable allocation constraint for control periods after 2017.
● With regard to allocations for 2017 and l ater, Tennessee, Kentucky, and Alabama will have the opportunity, if they wish, to submit SIPs and establish alternate allocation methods. This approach affects only TVA’s SO 2 allocations, increasing the ir 2018 and 2019 allocations, assuming that Tennesse e, Kentucky, and Alabama do not file SIPs to establish alternate allocation methods in the interim period.FIP Revisions

- RTC Febru ary 7 , 2012 Page 120

120 Regarding the proposal to allow owners with consent decrees to specify from which units allowances are surrendered, EPA does not believe that this s uggested alternative approach is workable. This approach would result in a significant amount of allowances being allocated at the end of the control period for which they were allocated, rather than before the control period, as generally provided in the Transport Rule trading programs. Reducing the amount of allowances allocated in a state which would be available for trading during the control period would interfere with the operation of the allowance markets and the ability of sources to engage in trad ing in order to comply with the requirement to hold allowances covering the sources’ emissions. (B) Supports EPA's proposal to limit allocations based on limits established in Consent Decrees, but the analysis conducted in support of the Transport Rule failed to include these limits. Comment (B)(1) : In at least one circumstance, the appropriate limits were not included in the analysis. For example, the Colbert Plant in AL (ORIS 47, Units 1 through 5) are listed in the Consent Decree TSD as limited to a total of 19,445 tons of SO 2 by 2013. However, in EPA's analysis of the 2014 remedy case, these same units are predicted to emit over 45,000 tons. Even with EPA's subsequent reduction of the potential allocation to these units, allowing these excess emi ssions in the modeling analysis result in over 25,000 tons of excess SO 2 allowances in Alabama's budget. EPA should reassess the remedy case results against the consent decree annual tonnage limits and modify state budgets as appropriate. [Letters: New York State Department of Environmental Conservation (EPA

- HQ

- OAR

- 2009

- 0491

- 4788) p. 3]
RESPONSE : EPA’s IPM remedy analysis correctly imposes no emission tonnage limit on the Colbert Plant e missions based on the consent decree. The consent decree has coll ective tonnage limits for TVA (that greatly exceed 45,000 tons), but does not have a tonnage limitation specific to the Colbert Plant. Therefore, the modeling projection is entirely within reason. As to the plant’s allocation limit , as described in the c onsent decree TSD, this does not reflect a binding emission limit on the plant but rather is a mechanism for ensuring that the TVA allocation does not collectively exceed its consent decree cap and thereby retire excess allowances as a consequence

– in eff ect reducing the state budget. However, TVA sources are free to trade allowance within their Group in a manner that allows them to comply with the collective tonnage caps in the manner they best see fit. (C) EPA should limit unit allocations to any maxim um emission level contained in a permit or other enforceable instrument, not just federal consent decrees as proposed. Comment (C)(1) : This would prevent a facility from receiving an allowance windfall in the allocation process. The Iatan facility in MO is a good example of EPA's over

- allocating to a specific unit. Iatan Unit 1 installed both SO 2 and NO X controls which came on

- line in 2009. SO 2 emissions from this unit went from over 15,000 tons in 2008 to 152 tons in 2009. Using the limits contained in the permit (8,100 mmBtu/hr and 0.1 lb/mmBtu) provides a maximum emission of about 3,550 tons per year. EPA's final allocation provides more than 14,000 tons inFIP Revisions

- RTC Febru ary 7 , 2012 Page 121

121 2012 and 11,000 in 2014 for this unit. [Letters: New York State Department of Environmenta l Conservation (EPA

- HQ

- OAR

- 2009

- 0491

- 4788) p. 3

- 4]
RESPONSE : See s ection VII of the f inal Transport Rule p reamble in the docket to this rulemaking for a description of the allocation methodology (76 FR 48284, August 8, 2011)

. The only aspect of the allo cation methodology that was the part of this rulemaking was the addition of the consent decree constraint. The remainder of the allocation methodology , as laid out in the Final Transport Rule Preamble, is out side the scope of revisions proposed and upon w hich EPA solicited comment

. (D) EPA misinterpreted the JEC Consent Decree that requires compliance with the NO X annual tonnage limit at the end of 2015, not the beginning of 2014. Comment (D)(1) : Table 6 of the document entitled “Assessment of the Imp act of Consent Decree Annual Tonnage Limits on CSAPR Allocations” lists Westar’s annual tonnage limit (ATL) for SO 2 as 6,600 (2012 through 2016) and for NO X as 12,400 for 2014 and 2015 decreasing to 9,600 tons in 2016. The NO X ATL is based on a misinterpr etation of the JEC Consent Decree related to the NO X ATL. By December 31, 2012, Westar must decide between two options: it can install a second SCR at JEC and accept individual unit

- specific emission rates or it can install a single SCR with a NO X plant

- w ide 30

- day rolling average emission rate. If Westar decides to install one SCR, it must be installed and operational no later than December 31, 2014 under ¶ 58 of the Consent Decree, which states “Westar shall...achieve, maintain and comply with a Plant

- Wid e 12

- Month Rolling Tonnage limitation for NO X at JEC of 9,600 tons by December 31, 2014.” Similarly, if Westar decides to install a second SCR, Paragraph 59 states the compliance date for the Plant

- Wide 12

- Month Rolling Tonnage Limitation of 12,400 is Dec ember 31, 2014 and for the Plant

- Wide 12

- Month Rolling Tonnage Limitation of 9,600 is December 31, 2016. In all these cases compliance does not apply retroactively to the 12

- month period preceding these dates, but rather, to the 12

- month period after the identified dates. This prospective compliance timetable is specified in Paragraph 177, which states “For purpose of determining compliance with any Plant

- Wide 12

- Month Rolling Tonnage limit in this Consent Decree, such limit shall apply prospectively from the specified date on which the 12 month period begins. For example, if Westar must comply with a Plant

- Wide 12

- Month Rolling Tonnage limit on June 1, 2010, compliance with the limit will first be determined 12 months after June 1, 2010.” The prospecti ve treatment under Paragraph 177 means compliance with the 12,400 ton limitation begins on December 31, 2015 and for the 9,600 ton limitation begins on December 31, 2017. Based on the proper interpretation of the JEC Consent Decree, Table 6 should be upda ted as provided in a table in the comment letter. It is also important to note that the Final Rule NO X emissions from JEC beginning in 2012 and continuing in subsequent years are not only less than the ATLs allowed by the JEC Consent decree, but also the Final Rule’s more restrictive limits are imposed four to five years earlier than the timetable agreed upon by the good faith negotiations between Westar and EPA that is memorialized in the Consent Decree. [Letters: Westar Energy (EPA

- HQ

- OAR

- 2009

- 0491

- 477 7) p. 11

- 12]FIP Revisions

- RTC Febru ary 7 , 2012 Page 122

122 RESPONSE : For the purpose of determining the impact of the CD ATLs on Transport Rule NO X allocations for Westar Energy, EPA has adjusted the timeframe of the NO X CD ATLs from 2014 to 2015 and 2016 to 2017, respectively. However, as stated i n the TSD, the calendar

- year application of the CD ATL does not constitute an interpretation of the CD for any other purpose, and EPA is not adopting in this rulemaking any interpretation of Westar Energy’s CD. (E) Annual tonnage limitations in a consent decree should not be used as a basis for reallocating CSAPR allocations to other sources in a state. Comment (E)(1) : EPA appropriately decided not to further reallocate CSAPR based upon consent decree 30 day rolling average emission limits. Hoosier Ene rgy agrees with EPA that this approach should not be used to reallocate allowances because: 1) the approach is based upon a mistaken interpretation of the Hoosier Consent Decree; and 2) such a reallocation would have a dramatic impact on the Hoosier syste m which depends on over

- controlling at Merom to free allowances for Ratts. The Hoosier Consent Decree is system

- wide, not plant specific. SO 2 and NO X annual allowance restrictions and surrenders under the Consent Decree are based on annual tonnage limita tions for the entire system. Hoosier must be able to use the Merom CSAPR allowances that are freed up by controlling the Merom units for the Ratts units. Any additional reductions in the system allocations will seriously curtail the operation of the Ratt s units with a potentially dramatic impact on the Hoosier System. In fact, without SO 2 allowances from Merom, the Ratts station would only be able to generate electricity 15% of the time which amounts to a de facto closure of the plant based on SO 2 allowa nce allocation. EPA should clarify that the SO 2 and NO X allowance surrender requirements in consent decrees will not apply to annual CSAPR allowances because under any analysis it is clear that there will be no surplus CSAPR allowances. Allowance surrend er provisions under CSAPR where the development of a market is precarious at best is not in the best interest of EPA or the utilities with consent decrees. The market will be very short particularly in Group 1 states that are coal dependent like Indiana. This clarification will allow companies who chose to settle instead of litigate NSR claims, to trade CSAPR allowances and gain benefit for any early installation of controls and emissions reductions under the NSR consent decrees. [Letters: Hoosier Elect ric Cooperative (EPA

- HQ

- OAR

- 2009

- 0491

- 4785) p. 1

- 5]
RESPONSE : EPA is adjusting allowance allocations to align them with the consent decree (CD) annual tonnage limits (ATLs) in order to minimize the impact of CD allowance surrender provisions on state tra ding budgets. As stated in the preamble of the proposed revisions, EPA is not adjusting allocations based on the emission rate provisions in the CDs. Regarding the comment to clarify allowance surrender requirements, the language in the allowance surrend er provisions and the associated definitions in each CD determine what types of allowances are subject to surrender under that CD. Most of the CDs addressed by this ruleFIP Revisions

- RTC Febru ary 7 , 2012 Page 123

123 revision (including the Hoosier CD) define the SO 2 and/or NO X allowances covered by t he CD allowance surrender provisions as allowances issued in any emission trading or marketable permit program under the CAA and/or a SIP. EPA cannot unilaterally reinterpret or rewrite the terms of these CDs to exclude the CSAPR allowances from the allow ance surrender requirements. In this final rule revision, EPA is adjusting some units’ allocations in order to align the allocations with the CD ATLs , reduce the amount of allowances otherwise required to be surrendered under the CDs involved and th e consequent reduction in allowances available for trading and compliance, and, in this way, minimize the impact on the state trading budgets involved. Comment (E)(2) : Any NO X allowance restrictions in the EKPC Consent Decree should not be used as a basi s for reallocating CSAPR NO X allocations from EKPC to other Kentucky sources. EPA correctly determined that no reallocations are appropriate for SO 2 , but EPA inappropriately compared EKPC system annual unit NO X allocations and determined that there would not be any excess NO X allowances that need to be reallocated. This is inconsistent with the Consent Decree because: 1) The EKPC Consent Decree clearly was not intended to apply to future annual NO X allowances because at the time it was negotiated the onl y NO X allowances were ozone season allowances; and 2) The EKPC Consent Decree only restricts the use of NO X allowances. It does not require the surrender of NO X allowances. The Consent Decree clearly allows NO X allowances to be banked under any interpret ation of the scope of its allowance provisions. The commenter goes on to support these two points and concludes that the Consent Decree cannot be a basis for reallocating CSAPR NO X allowances from EKPC based on the rationally EPA advances in the proposed rule and CD TSD. EPA should also clarify that the EKPC Consent Decree does not restrict trading of annual CSAPR NO X allowances. [Letters: East Kentucky Power Cooperative (EKPC) (EPA

- HQ

- OAR

- 2009

- 0491

- 4806) p. 5

- 7]
RESPONSE : The commenter raises a quest ion of legal interpretation of the EKPC CD, which is outside the scope of the Transport Rule revision notice of proposed rule and the scope of this rulemaking. EPA did not propose, and is not finalizing, in this rule revision any reduction of EKPC’s NO X a nnual allowance allocation. EKPC’s NO X consent decree (CD) annual tonnage limit (ATL) was greater than the system

- wide allocation, and so EPA did not revise EKPC’s NO X annual allowance allocation. Therefore, EPA is not taking any final action with respec t to EKPC. Solely for the purpose of analyzing the impacts of the CD ATL, EPA used the broadest possible interpretation of the EKPC CD. However, as stated in the TSD, this is not an interpretation of the CD for any other purpose, and EPA is not adopting in this rulemaking any interpretation of the EKPC CD. (F) Proposal timing requires that State time period for Notification to Submit a SIP should be extended.FIP Revisions

- RTC Febru ary 7 , 2012 Page 124

124 Comment (F)(1) : The CSAPR Rule finalized by EPA on August 8, 2011 provided States the opport unity to submit SIP revisions that allocate allowances for the 2013 control period to supplant allowances in the FIP. States were required to provide notification to EPA by October 17, 2011 (70 days from publication of the rule) if the State intended to s ubmit State

- specific 2013 allocations. EPA's recent proposal to revise CSAPR, published in the Federal Register a mere 3 days prior to the October 17, 2011 deadline, makes it necessary to provide States an extension to submit this notification. Specifica lly, with respect to the changes proposed by EPA to reflect the maximum tonnage limitations of Consent Decrees in six States (Alabama, Indiana Kansas, Kentucky, Ohio and Tennessee), EPA should provide those six States at least 70 days from the date of publ ication in the federal register of a revised CASPR to submit the SIP notification. [Letters: Tennessee Valley Authority (TVA) (EPA

- HQ

- OAR

- 2009

- 0491

- 4792) p. 4]
RESPONSE : Regarding the timing of the proposed revisions and the deadline for a state to not ify EPA of their intent to allocate 2013 allowances, in deciding whether to issue allowances to sources or give state's additional time to submit allowances, EPA has to balance many considerations, including the sources’ interest in receiving allocated all owances quickly. EPA proceeded to allocate allowances under the FIPs as soon as the deadline passed for a state to submit notice that they intended to allocate allowances for 2013 unless we had received such a notice from a state. Allowances were therefo re issued to sources in Tennessee on October 25, 2011. The commenter’s letter is dated November 28, 2011, several weeks after the allowances were allocated in Tennessee. We do not see any justification, based on this comment, for withdrawing previously a llocated allowances. Moreover, the commenters fail to explain why the proposed or final rule revisions (and the revisions with regard to Tennessee in particular) would affect the state’s consideration of whether to submit to EPA the state’s 2013 allowan ce allocations for existing units. As explained above, the TVA units in Tennessee are likely to regain most of the allowances that are being added to the new unit set aside as a result of the consent decree constraint when the new unit set aside is distri buted to sources in the state at the end of 2013. Finally, the proposed rule was signed and widely disseminated on October 6, 2011, 11 days before the deadline for a state to submit notice of its intent to allocate 2013 allowances. If a state wished to have more time to consider establishing allowance allocations for 2013, the state could have submitted a notice of intent to provide such allocations and still subsequently decided not to submit 2013 allocations to EPA. States that did not submit a notic e of intent with respect to the 2013 allocations still have the opportunity to submit allocations for 2014 and beyond. (G) Supports EPA’s proposed revisions to units covered by existing consent decrees. Comment (G)(1) : Commenter supports EPA’s incorporatio n of the emission reduction requirements of existing utility consent decrees. EPA now recognizes that the unit

- level allowance allocations under the CSAPR did not properly account for provisions in those consent decrees that effectively require the surren der of “excess” CSAPR allowances. As a result, CSAPR allowance allocations to certain units reduced the availability of some of thoseFIP Revisions

- RTC Febru ary 7 , 2012 Page 125

125 allowances to other sources in the state. EPA should finalize revisions of CSAPR unit

- level allocations for the specific units subject to these consent decrees. These revisions would not alter the state budgets but would have the effect of increasing the number of allowances within the budget that are available for compliance purposes and that would not otherwise be availa ble without this proposed change to the allocation of allowances. [Letters: Kansas City Power and Light Company (EPA

- HQ

- OAR

- 2009

- 0491

- 4804, 4826) p. 2

- 3]
RESPONSE : EPA appreciates the supportive comments.FIP Revisions

- RTC Febru ary 7 , 2012 Page 126

126 4. Assurance Penalty Provisions
Issue 4.1: G eneral Support/Opposition to Assurance Provisions Deferral
Points Raised: (A) Supports EPA's proposal to defer the effective date of the assurance penalty provisions, but argues that it may not fully address liquidity issues and that EPA should consider de laying implementation beyond 2014. Comment (A)(1) : Deferring implementation of the assurance provisions until the 2014 CY will help improve allowance market liquidity, which is essential given the short time frame from the final rule to the 2012 complian ce period. However, the need for market liquidity will persist beyond the 2012

- 2013 compliance periods, and will be most important to assure that SO 2 emission reductions can be implemented in a cost

- effective fashion in the Group 1 states. Therefore, the assurance provisions should be further delayed or substantially modified in 2014 and beyond. Commenter (AEP) adds that along with the benefit that deferring implementation will have on improving allowance market liquidity, the additional time will allow sources to meet real world engineering, design and construction schedules for pollution controls for this regulation and any other new regulations governing the electric utility generator source category. Allowing a delay in the assurance provision is ess ential given the short time frame requiring sources to comply with the final rule in 2012. In prior comments to the proposed rule and subsequent NODAs, AEP provided actual timelines for engineering and constructing pollution control necessitated by this r ule. In summary, the timeframe for an SCR is 42 months and an FGD is 52 months. While the construction of pollution control equipment is occurring, the electric generating capacity will have to come from high emitting sources. As such, AEP recommends an extension of the assurance provision delay to 2016. [Letters: American Electric Power (EPA

- HQ

- OAR

- 2009

- 0491

- 4737) p. 2, 11

- 12]
RESPONSE : EPA is finalizing the delay of the assurance provisions until 2014. See preamble section IV.C. for more details. Comment (A)(2) : Commenter supports EPA’s proposal to delay implementation of the assurance provisions but encourages EPA to leave CAIR in place while it takes the time to revise the rule to address numerous errors. [Letters: Southern Company (EPA

- HQ

- OA R

- 2009

- 0491

- 4744) p. 2

- 3, 13]
RESPONSE : In July 2008, the Court in. North Carolina v. EPA, 531 F.3d 896 (D.C. Cir.2008), modified on rehearing, North Carolina v. EPA, 550 F.3d 1176, 1178 (D.C. Cir. 2008) instructed EPA to replace CAIR as expeditiously as possible. Thereafter, the U.S. Court of Appeals for the District of Columbia Circuit in EME Homer City Generation, L.P. v. EPA , No. 11

- 1302 and consolidated cases stayed the Transport Rule, but in doing so, stated that EPA “... is expected to continue admi nistering the Clean Air Interstate Rule pending the court’s resolution ofFIP Revisions

- RTC Febru ary 7 , 2012 Page 127

127 [challenges to the Transport Rule].” EPA is finalizing the delay of the assurance provisions until 2014. See preamble section IV.C of this final rulemaking for more details.
Com ment (A)(3) : Even with the Proposal, the CSAPR allowance markets are still narrow and have numerous constraints beyond the assurance provisions. The Proposal would delay a single market constraint, but a two

- year delay in the assurance provisions cannot be expected to overcome these fundamental market design constraints. Moreover, given the stringency of the Clean Air Act enforcement provisions as EPA would apply them to CSAPR, there is a strong incentive for utilities to save their allowances for future compliance. CSAPR allowance trades continue to occur infrequently and in very small lots (less than 100 tons). In contrast, in 2012, SPS would need to purchase roughly 21,000 tons of allowances for SO 2 , and 6,000 tons for annual NO X and 2,500 tons for s easonal NO X . The illiquidity of the market is exacerbated by the 2012 compliance date for CSAPR. In order to create a pool of reasonably priced allowances for sale, a significant portion of covered power plant owners must over

- control their plants and of fer their excess allowances on the market. While this market condition may occur over time, installing new emission controls to free up allowances for sale usually takes several years. CSAPR gave the industry a mere five months to reduce its emissions

- not nearly enough time for SPS or other companies to reduce their emissions sufficiently to create a robust allowance trading program. Commenter provides additional discussion, noting that the delay in the applicability of the assurance provisions would b e an improvement but is unlikely to result in a substantially more rapid development of an allowance market. [Letters: Southwestern Public Service Company (SPS) (EPA

- HQ

- OAR

- 2009

- 0491

- 4752) p. 6

- 7]
RESPONSE : EPA is finalizing the delay of the assurance provisions until 2014. See section IV.C in the preamble to this final rule. Comment (A)(4) : Con Edison supports EPA's proposal to postpone the implementation of the assurance penalty provisions from 2012 to 2014, but remains concerned that postponing un til 2014 will not be sufficient. The large decrease in Group 1 SO 2 budget in 2014 risks a similar chill to trading activity, particularly if allowance prices are higher than EPA's modeled values during the first two years of the program. Further in late 2013 and early 2014, the impending assurance penalty provisions will lead utilities to bank allowances or "artificially constrain...operational plans to not exceed initially allocated allowances [and] the volume of early trading activity might be unnecessa rily constrained " (76 FR 63871). Con Edison therefore recommends that the EPA either extend the applicable date to 2016 instead of 2014, or develop a safety valve in the final rule that allows for the postponement of the assurance penalty provision for S O 2 compliance in the fourth quarter of 2013 if the forward market price of SO 2 allowances for 2014 is more than twice the value modeled by EPA. [Letters: Consolidated Edison Co. (EPA

- HQ

- OAR

- 2009

- 0491

- 4761) p. 3]
RESPONSE : The implementation of a safet y valve is outside the scope of the revisions proposed and upon which EPA solicited comment . EPA is finalizing the delay of the assurance provisions until 2014. See section IV.C of the preamble to this final rule.FIP Revisions

- RTC Febru ary 7 , 2012 Page 12 8

128 Comment (A)(5) : Commenters support the EPA’s proposal to extend the start date for these assurance provisions to 2014, but requests that the Agency consider an additional one year extension, to 2015. One additional year would allow all market participants the ability to effectively evaluate th eir compliance plans with a three year implementation period consistent with the minimum needed to make physical investments in control technologies. This extension will likely force credit market prices to levels comparable to the marginal compliance cos t of controls, and help to minimize additional scarcity and uncertainty premiums already apparent in early market trades. [Letters: Lafayette Utility Systems (EPA

- HQ

- OAR

- 2009

- 0491

- 4807) p. 19

- 20; Louisiana Chemical Association (LCA) (EPA

- HQ

- OAR

- 2009

- 0491

- 4803) p. 16

- 17; Louisiana Public Service Commission (EPA

- HQ

- OAR

- 2009

- 0491

- 4799) p. 4

- 5]
RESPONSE : EPA is finalizing the delay of the assurance provisions until 2014. See section IV.C of the preamble to this final rule. Comment (A)(6) : TVA supports th e postponement of the effective date, but further recommend that the effective date be postponed to match the presumed initial compliance date in the Utility MACT rule. A longer postponement not only further advances the liquidity and price accessibility goals that animated EPA in the first place to defer the effective date. It also better aligns the compliance dates for the CSAPR and Utility MACT Rules. Several control technologies promoted by the two rules (wet FGD, Dry FGD and DSI) are effective in re ducing the emissions of both a primary CSAPR pollutant ( SO 2 ) as well as a primary Hazardous Air Pollution group of pollutants (acid gases). The additional time would assist in the development of robust allowance markets as the marketplace would have taken into account different strategies that result in cost effective emission reductions. [Letters: Tennessee Valley Authority (TVA) (EPA

- HQ

- OAR

- 2009

- 0491

- 4792) p. 3

- 3]
RESPONSE : There is no requirement to align the Transport Rule and MATS compliance date s and EPA does not believe it would be reasonable to do so. MATS was still in development at the time the final Transport Rule was finalized, making it infeasible to marry the Transport Rule’s compliance deadlines to those of MATS. Additionally, MATS and the Transport Rule result from different authorities under the Clean Air Act that require EPA to act. Furthermore, EPA believes that extending the delay of the assurance provisions beyond 2014 would not provide assurances of states eliminating their sign ificant contribution to nonattainment or interference with maintenance. EPA is finalizing the delay of the assurance provisions until 2014. See section IV.C of the preamble to this final rule. Comment (A)(7) : Commenter strongly supports EPA's proposal t o defer the effective date of the assurance provisions, but asks EPA to reconsider whether such provisions are even necessary beginning in 2014 given the likely impacts of the emission budgets and the impact of the EGU

MACT. Because most of the CSAPR stat es have already participated in emission trading programs that require substantial reductions, and sources are otherwise taking steps to achieve further reductions consistent with CSAPR, a more flexible method can be used to satisfy theFIP Revisions

- RTC Febru ary 7 , 2012 Page 129

129 statutory mandate a nd preserve cost savings associated with a robust interstate trading system. They also point out that they were on track with scrubber installations for the proposed Transport Rule, but their scrubbers will not be installed in time to meet the reduced bud gets in the final rule for 2012. [Letters: Ohio Valley Electric Corporation and Indiana Kentucky E (EPA

- HQ

- OAR

2009

- 0491

- 4794) p. 1

- 2]
RESPONSE : EPA is finalizing the delay of the assurance provisions until 2014. See section IV.C of the preamble to t his final rule. Comment (A)(8) : EEANY supports EPA’s efforts to encourage a robust allowance market. As noted, EEANY strongly endorses the revision that postpones the assurance penalty until 2014. Furthermore, EEANY recommends that EPA continue to moni tor the CSAPR allowance markets because of continuing uncertainties in the CSAPR allowance program. Even though cap and trade programs have been functioning well for the last 15 years, there are significant differences (described further in Technical Sect ion 3) in this program that supports the delay of the assurance penalty until 2014 but also suggests continued monitoring is appropriate. If there are indications of a less than robust allowance market, the assurance penalty should be delayed even longer. Possible indicators of a poorly functioning allowance market include, but are not limited to, a) allowance prices at the 2012 or 2013 compliance deadline are more than 50% higher than those prices projected by EPA modeling, b) units have been or are unab le to operate due to a shortage of allowances in the secondary market, or, c) sources cannot acquire allowances at the compliance deadline. EEANY in Technical Section 3 of their comments expands on this, noting that The CASPR rule has an ambitious impleme ntation schedule that currently does not include provisions for a transition period, similar to those included in earlier cap and trade programs. Analysis of the New York situation suggests that dependency on a generic model’s estimated unit

- specific cont rol implementation capabilities probably over

- estimates the ability of sources to reduce emissions to meet the start date of the program. Those concerns would be alleviated if CSAPR included provisions to ease into the program. In previous programs banki ng and early reduction options provided early benefits and flexibility for sources to comply with the rule and implement the control strategies necessary for long

- term compliance. In both CAIR and the NO X SIP Call, EPA wisely permitted the use of allowanc es from previous programs for compliance. This transition was not included in CSAPR. The presumption that the allowance trading market will be robust and efficient is another concern. Previous cap and trade programs calculated budgets differently than C SAPR. In CSAPR the projected margin between emissions and allowances will be tight because “highly cost effective” emission reductions were calculated for each unit. This limits the ability of any source to over

- control and cost

- effectively generate exce ss allowances suggesting that there will not be a large surplus of allowances available to sources that need them for compliance. While on one hand EPA’s penalty provisions discourage interstate allowance trading, within each state budget the unit allocati ons are determined by historical operations, not historicalFIP Revisions

- RTC Febru ary 7 , 2012 Page 130

130 emissions. EEANY has supported this method of allocation in the past, and continues to support it as the most equitable method for distributing allowances among generators in the State. Also, th is approach is consistent with applicable judicial precedent. However, EEANY recognizes that this allocation methodology has consequences for the subsequent allowance market. One potential outcome of such an approach is that more trades will be focused w ithin each state, leading to an increase in transaction costs stemming from decreased allowances availability. Even though EPA cap and trade programs have been in place since 1995, because much of the previous trading was done within company systems and t he margins were not as tight, there is not as much experience with trading as a compliance option as one might expect at first blush. Lastly, there are also reasons why companies with surpluses might not trade, e.g., due to uncertainties in a regulated en vironment or future requirements. As a result, the presumption that the allowance market will be robust and efficient could be unfounded. [Letters: Environmental Energy Alliance of New York (EEANY) (EPA

- HQ

- OAR

2009

- 0491

- 4811) p. 3, 9

- 10]
RESPONSE : As explained in the preamble for this rule, one reason for delaying the assurance provisions is to ease the transition from CAIR to CSAPR. The use of allowances from previous trading programs was addressed in the final Transport Rule and is outside the scope of th e revisions proposed and upon which EPA solicited comment

. EPA is finalizing the delay of the assurance provisions until 2014. See section IV.C of the preamble to this final rule. (B) Supports EPA's proposal to defer the effective date of the as surance penalty provisions, but argues that EPA should consider implementing substantial revisions to the provisions. Comment (B)(1) : One way to address the continued need for market liquidity would be to recognize that as the overall state budgets decre ase, the variability percentage provides a smaller and smaller absolute amount of variability, one that may not be adequate on an ongoing basis. As the budgets decrease, it is far more likely that higher

- emitting units will perform load following duty rat her than being dispatched as baseload units. Thus, a pure percentage basis will not reflect the realities of the available resources. AEP suggests that the assurance provisions be increased, particularly for Group 1 SO 2 states, so that the number of allo wances available to address variability remains constant. As high emitting units will likely be marginal units for dispatch and operation under CSAPR, any forced outages on non

- or low

- emitting units or uptick in natural gas prices will likely force incre ased generation from these units, which could result in a dramatic emission increase. As such, AEP recommends the variability limits remain at a constant volume based on the 2012 state budgets and previously established percentages. [Letters: American E lectric Power (EPA

- HQ

- OAR

- 2009

- 0491

- 4737) p. 12

- 13]
RESPONSE : The size of the variability limits was addressed in the final Transport Rule and is outside the scope of th e revisions proposed and upon which EPA solicited comment

.FIP Revisions

- RTC Febru ary 7 , 2012 Page 131

131 EPA is finalizing the del ay of the assurance provisions until 2014. See section IV.C of the preamble to this final rule. Comment (B)(2) : Commenter (We Energies) supports EPA's proposal to amend the effective date of the assurance penalty provisions to make them effective beginn ing in 2014 instead of 2012, for the reasons EPA states and since this deferral would mitigate potential assurance penalties that We Energies could incur during the early years of CSPAR due to its need to operate units located in a transmission

- constrained area. However, EPA should consider an exemption from assurance penalties that would apply beyond 2014 for units in transmission

constrained areas that need to operate to ensure stability of the transmission grid. Alternatively, EPA could provide a limit ed exemption to the assurance penalty provisions for generating units that participate in a company's system

- wide and multi

- state emission reduction program, which would allow a utility that operates plants in different states to implement a compliance pla n that would allow emission trading within its fleet of covered units without the risk of exceeding state assurance levels. Commenter asserts that as finalized, CSAPR creates real and significant risk for electric system reliability in the Upper Peninsula because insufficient allowances have been allocated to support the necessary levels of generation from these units, and that allowances allocated to sources in the State of Michigan are not sufficient to enable the state to avoid compliance concerns with its assurance obligations. Commenter provides significant additional discussion on this issue including a description of the units at Presque Isle Power Plant, the reliance on these units to meet the potential demand for electricity in the Upper Peninsula and ensure grid stability and electric system reliability, and why the available compliance options that could be used to make up for allowance shortages (i.e., curtailing operations, installing controls, or purchasing allowances on the open market) are n ot viable. [Letters: We Energies (EPA

- HQ

- OAR

- 2009

- 0491

- 4781) p. 3

- 5]
RESPONSE : EPA is finalizing the delay of the assurance provisions until 2014. See section IV.C of the preamble to this final rule. EPA responds to We Eneregies’ comments on Presque Isle in section 1.3 (A)(1) of this document. Comment (B)(3) : CSAPR's allowance allocation scheme has created significant obstacles for the Homer City Generation Facility to finance the pollution controls that are necessary to comply with the Phase II SO 2 limits and no maintain operational viability until such equipment can be installed. The problems are two

- fold. First, Homer City simply has not been allocated sufficient allowances to allow it to maintain normal operations during the transition from Ph ase I to Phase II. Second, and most pertinent to EPA's proposed revisions, CSAPR's allowance allocation scheme is likely to result in a lack of liquidity in the allowance market during Phase I. lf allowances are not available, or at least not at a fair pr ice, Homer City will likely be forced to significantly curtail operations since it has been allocated less than one

- fifth of the allowances it needs to maintain normal operations. Less operation means less dispatch, which in turn could jeopardize scrubber financing and result in job losses and electricity rate increases for millions of consumers.FIP Revisions

- RTC Febru ary 7 , 2012 Page 132

132 Thus, the Homer City OLs strongly support EPA's proposal to amend the assurance penalty provisions to make them effective January 1, 2014 instead of 2012. A de ferral of the penalty provisions likely would improve liquidity of the SO; allowance market during Phase I and ease the transition CAlR to CSAPR Phase 1 which EPA itself acknowledges is critical. Because the Phase I state budgets are likely to be met rega rdless of assurance penalty provisions, the deferral of allowance penalties until Phase II would not jeopardize any of the public health or environmental benefits. Moreover, because CSAPR reduces Group 1 state budgets by 371,000 allowances more than what the agency determined necessary for states to meet their CAA section 110(a)(2](D] obligations, there is significant "head room" under the rule for interstate trading during Phase I. Although the Homer City OLs support EPA's proposed delay of the assurance provisions, this revision alone will not adequately address allowance market liquidity since it does not eliminate the perverse incentive created by the rule for entities long on allowances to hoard them. The Homer City OLs believe that market liquidity can be improved further if during a tight market, participants have the "safety valve" option of borrowing Phase II vintage allowances for use during Phase I. [Letters: Homer City Owner Lessors LLC (EPA

- HQ

- OAR

- 2009

- 0491

- 4816) p. 2

- 3]
RESPONSE : EPA is f inalizing the delay of the assurance provisions until 2014. See section IV.C of the preamble to this final rule. (C) Instead of deferring the effective date of the assurance penalty provisions, EPA should consider eliminating the provisions altogether. Comment (C)(1) : Commenter (AEP) strongly supports EPA's proposal to defer the effective date of the assurance provisions to 2014, but asks that EPA also reconsider whether such provisions are necessary given (1) the progress made in reducing emissions con tributing to transport under CAIR; (2) the likely impacts of the emission budgets developed by EPA for the final CSAPR (as adjusted by the corrections in the proposed rule and as suggested herein); and (3) the likely future impact of the final electric gen erating unit maximum achievable control technology rule (EGU

- MACT Rule). The restraint on interstate trading imposed by the assurance provisions makes the CSAPR more difficult to administer and enforce, and ignores the historic evidence that cost

- effectiv e reductions made to comply with a multi

- state regional trading program effectively remedy long

- range transport issues. As demonstrated by modeling submitted by MOG and work performed by UARG, the emissions reductions achieved or to be achieved under CAIR would have been sufficient to accomplish the air quality objectives associated with the CSAPR. And every state has made some contribution to the progress that has already been made, as evidenced by the controls incorporated into the IPM model runs. Thus , although the state

- by

- state reductions may not precisely match the modeled contributions, EPA would have satisfied its duty under section 110(a)(2)(D)(i)(I) to "promulgat[e] a rule that achieves something measurable toward the goal of prohibiting sources 'within the State' from contributing to nonattainment or interfering with maintenance 'in any other State.'" [Letters: American Electric Power (EPA

- HQ

- OAR

- 2009

- 0491

- 4737) p. 2, 11

- 12]FIP Revisions

- RTC Febru ary 7 , 2012 Page 133

133 RESPONSE : In this final rule, EPA is finalizing the delay of the as surance provisions until 2014. See section IV.C of the preamble to this final rule. (D) Supports EPA's decision to defer the effective date of the assurance penalty provisions. Comment (D)(1) : Commenters support EPA's decision to defer the effective d ate of the assurance penalty provisions until January 1, 2014 and generally agree that this proposal will promote the development of allowance market liquidity as the program gets underway. This will smooth the transition from CAIR to the Transport rule p rograms, while ensuring that necessary emission reductions are occurring within the states that are contributing to non

- attainment. Some (EEI, Oglethorpe) note that delaying will allow the Transport Rule allowance trading market to develop, promote liquid ity and accessibility of price information in allowance markets for the CSAPR, and provide additional time for utilities to install emission control equipment while remaining in compliance by purchasing allowances without interstate trading restrictions. One commenter (Alliant) notes that in light of the stringent emissions reductions of this rule in 2014, they believe that measures to support the development of a robust market are critical for helping affected sources mitigate compliance risk and reduce c ost impacts of this program in the long term. Some commenters (San Miguel, FEPC, Progress) add that while the 2014 date provides some additional limited flexibility in complying with the rule, the revision is only a small step in the right direction and n ot nearly enough to resolve their concerns with the rule. A number of other commenters also note that it will be helpful in light of the uncertainty in the state and unit level allocations as EPA finalizes budgets, and states decide whether to take over t he allocation of the CSAPR allowances. One commenter (National Grid) noted that other trading programs included the use of a small auctions or the carryover of allowances, provisions which are not included in CSAPR. A small independent power producer not ed that they are at a disadvantage compared to large utilities that have an opportunity to aggregate and trade internally, and also the punitive aspects of the assurance provisions would contribute to market uncertainty (CPI USA North Carolina). [Letters: Alliant Energy (EPA

- HQ

- OAR

- 2009

- 0491

- 4762) p. 3; Ameren (EPA

HQ

- OAR

- 2009

- 0491

- 4802) p. 1; CPI USA North Carolina LLC (EPA

- HQ

- OAR

- 2009

- 0491

- 4813) p. 1

- 2; CPS Energy (EPA

- HQ

- OAR

- 2009

- 0491

- 4784) p. 1; Constellation Energy (EPA

HQ

- OAR

- 2009

- 0491

- 4769) p. 2

- 3; Electric Energy, Inc. (EEI) (EPA

- HQ

- OAR

- 2009

- 0491

- 4748) p. 1; Entergy (EPA

- HQ

- OAR

- 2009

- 0491

- 4820) p. 6; Florida Electric Power Coordinating Group, Inc. (EPA

- HQ

- OAR

- 2009

- 0491

- 4772) p. 8; Fox Energy Company LLC (EPA

- HQ

- OAR

2009

- 0491

- 4815) p. 5; Kansas Ci ty Power and Light Company (EPA

- HQ

- OAR

- 2009

- 0491

- 4804, 4826) p. 2; Michigan Department of Environmental Quality (MDEQ) (EPA

- HQ

- OAR

2009

- 0491

- 4859) p. 1; National Grid (EPA

- HQ

- OAR

- 2009

- 0491

- 4809) p. 2; Oglethorpe Power (EPA

- HQ

- OAR

- 2009

- 0491

- 4749) p. 2

- 3; P rogress Energy (EPA

- HQ

- OAR

- 2009

- 0491

- 4771) p. 1; Public Service Enterprise Group (PSEG) (EPA

- HQ

- OAR

- 2009

- 0491

- 4793) p. 8; Public Service Enterprise Group (PSEG) (EPA

- HQ

- OAR

- 2009

- 0491

- 9003) p. 33; San Miguel Electric Cooperative (EPA

- HQ

- OAR

- 2009

- 0491

- 4766) p. 1]
RESPONSE : EPA is finalizing the delay of the assurance provisions until 2014. See section IV.C of the preamble to this final rule.FIP Revisions

- RTC Febru ary 7 , 2012 Page 134

134 Comment (D)(2) : Commenter (PA DEP) supports EPA's proposed Transport Rule revision which changes the effective da te of the "assurance penalty" provisions to 2014, as proposed in August 2010. The DEP agrees that change in the final rule should promote "market liquidity" during the transition from the CAIR to Transport Rule market

- based programs. EPA calls this a "li mited postponement" of the assurance penalty provisions but this is really not a "postponement" but a return to the provisions outlined in the proposed rule. Because CAIR and Acid Rain Program allowances cannot be used to comply with the Transport Rule be ginning 2012, the DEP believes that the proposed amendment to the assurance penalty provisions is necessary and should not have an environmental effect. EPA based the 2012

- 2013 budgets on existing or already planned controls. EPA's analysis indicated tha t there is a high level of certainty that emission reductions in 2012 and 2013 would occur within individual states, and that it was thus unlikely that states would exceed their assurance levels in any case. The assurance penalty provisions, therefore, in those years could only serve as a drag on trading without air quality benefit. [Letters: Pennsylvania Department of Environmental Protection (EPA

- HQ

- OAR

- 2009

- 0491

- 4773) p. 4]
RESPONSE : EPA is finalizing the delay of the assurance provisions until 201 4. See section IV.C of the preamble to this final rule. Comment (D)(3) : Commenter (CWLP) agrees with EPA's proposal to amend the assurance penalty provisions for the reasons EPA states. CWLP had earlier commented on the proposed Transport Rule that in choosing 2012 and 2014 as the targeted compliance dates, the compliance schedule appears to be unreasonable and unrealistic, as well as potentially harmful to an already weakened economy. This is especially true as it applies to the Springfield community, since in the final rule, Dahlman Unit 4 was allocated allowances that do not reflect its normal operation. Further, Midwest Ozone Group (MOG) modeling and air quality analysis shows that the air quality objectives of the Transport Rule could be achieved without the implementation of any controls beyond the CAIR rule and other controls already required. [Letters: City Water, Light and Power (EPA

- HQ

- OAR

- 2009

- 0491

- 4764) p. 2]
RESPONSE : EPA is finalizing the delay of the assurance provisions until 2014. See section IV.C of the preamble to this final rule. Comment (D)(4) : Commenters generally support the proposed revisions, but do not provide additional discussion. [Letters: American Electric Power (EPA

- HQ

- OAR

- 2009

- 0491

- 9000) p. 50; South Carolina DHEC (EPA

- HQ

- OAR

- 2009

- 0491

- 4742) p. 3]
RESPONSE : EPA is finalizing the delay of the assurance provisions until 2014. See section IV.C of the preamble to this final rule. Comment (D)(5) : Commenters support EPA’s proposal to amend the effective date of the assurance provisions under the CSAPR to make them effective beginning January 1, 2014, instead of January 1, 2012. Given the fact that EPA believes that a two year postponement of theFIP Revisions

- RTC Febru ary 7 , 2012 Page 135

135 effective date of the assurance penalty provisions will not interfere w ith the air quality objectives of the program, the only thing that imposing the assurance provisions beginning in 2012 would accomplish is make an already stringent and costly program needlessly more stringent and more costly. Commenters agree with EPA th at the proposed limited postponement of the effectiveness of the assurance provisions is justified in order to smooth the transition from CAIR to CSAPR. Deferring the effective date of the assurance provisions until the compliance periods beginning in 201 4 will also mitigate uncertainty created by the fact that most if not all state budgets and associated unit

- level allocations remain in flux until EPA completes this rulemaking. [Letters: Dominion Resources Services (EPA

- HQ

- OAR

- 2009

- 0491

- 4790) p. 2; Duke Energy (EPA

- HQ

OAR

- 2009

- 0491

- 4768) p. 8; Utility Air Regulatory Group (EPA

- HQ

- OAR

- 2009

- 0491

- 4823) p. 3]
RESPONSE : EPA is finalizing the delay of the assurance provisions until 2014. See section IV.C of the preamble to this final rule. Comment (D)(6) : Commenter (NRG) endorses the revision to delay implementation of the assurance provisions until 2014. CSAPR creates new emission markets for Group 1 SO 2 , Group 2 SO 2 , Annual NO X and Ozone Season NO X . Compliance requires planning and emission reductions in uncharted emission markets especially where many power plants were not granted enough allowances to meet historical emissions. Past cap and trade programs provided transition in the form of early action credits, time for implementation of compliance s trategies, or the use of allowances from already existing programs. The CSAPR assurance provisions can assess significant financial penalties without a transition. It is a challenge for power plants to make reductions, adjust outage schedules, or change commitments to provide electricity before the start date. In addition, determining the number of needed allowances is difficult as the variability trigger depends on the state emissions and is beyond the control of any single company. Commenter believes this delay addresses these issues and will: 1) not impact the intent of the regulation; 2) provide a sufficient transition from existing to new regulations; and 3) allow nascent emission markets to develop and gain liquidity. [Letters: NRG Energy (EPA

- H Q

OAR

- 2009

- 0491

- 4796)]
RESPONSE : EPA is finalizing the delay of the assurance provisions until 2014. See section IV.C of the preamble to this final rule. Comment (D)(7) : Delaying the CSAPR assurance penalty measure to 2014 or later is a prudent step for a number of reasons. Several Wisconsin utilities with projected shortfalls in allowances versus their 2010 and 2011 operations have submitted requests to the Wisconsin Public Service Commission for recovering costs related to CAPR compliance. In thei r submittals these utilities have indicated that primary compliance mechanisms for 2012 is purchasing of allowances and/or curtailing operations coupled with purchasing electricity. EPA inaccurately assumed under the finalized CSAPR that Wisconsin could e ffectively meet emission budgets under a restricted emissions trading program. In actuality, the finalized CSAPR set several conditions which will likely require higher levels of out

- of

- state trading than that allowed under the restricted trading program. Commenter provides significant additional discussion on this issue to describe theFIP Revisions

- RTC Febru ary 7 , 2012 Page 136

136 multiple reasons why additional trading is needed, including: 1) the CSAPR allowance distribution leaves some utilities with more allowances and some utilities fewer allo wances than the individual source emission levels used in calculating the emissions budgets (which forces utilities to trade emissions or curtail generation beyond that assumed in setting the budgets); 2) due to electric demand and uncontrollable emissions in any one year, utilities can and will generate more electricity than predicted and as such, without control options available in the early CSAPR years, they are likely to trade more emissions than expected (and EPA cannot expect that all excess allowanc es generated in Wisconsin will be available to Wisconsin utilities with allowance deficits); and 3) based on reasonable installation schedules, scrubber and SCR equipment planned as a result of the CSAPR finalized emission budgets will not be fully availab le until sometime after 2014 (and utilities will be seeing a reduction in allowances in 2014 but as yet may still not have the necessary equipment in place to meet the requirements. [Letters: Wisconsin Department of Natural Resources (EPA

- HQ

- OAR

- 2009

- 049 1

- 4824) p. 8

- 9]
RESPONSE : EPA is finalizing the delay of the assurance provisions until 2014. See section IV.C of the preamble to this final rule. Comment (D)(8) : In addition to expressing support for the deferral of the assurance penalty provisions, commenter (UARG) notes that the variability limits included in the Cross

- State Rule represent a significant improvement over the variability limit provisions in the proposed rule. In the Cross

- State Rule, EPA set one

- year variability limits as uniform per centages of each state’s budget representing the highest measured historic variability of annual heat input by EGUs between 2000 and 2010 among the states covered by the rule. The final rule’s approach on this issue provides greater transparency, and is m ore reasonable and straightforward, than the proposed rule’s approach, which would have included both one

- year and three

- year rolling variability limits set as the greater of 10 percent of the state’s budget or an absolute tonnage amount. The size of, and the approach to setting, the variability limits as determined in the final rule are not issues that EPA has reopened for comment in these proposed revisions, and UARG urges EPA not to revise the variability limits to make them smaller or to make the appro ach to calculating them less transparent. [Letters: Utility Air Regulatory Group (EPA

- HQ

- OAR

- 2009

- 0491

- 4823) p. 4]
RESPONSE : EPA is finalizing the delay of the assurance provisions until 2014. See section IV.C of the preamble to this final rule.
Comm ent (D)(9) : The development of robust allowance markets is essential to the successful implementation of the CSAPR trading programs. The ability of many covered sources to comply with CSAPR in 2012 will hinge on the availability of allowances. EPA inten tionally designed state emissions budgets to be stringent, in order to force covered sources to operate more efficient units and any existing controls, and the majority of sources will not be able to install highly

- effective emissions controls before the b eginning of the first compliance period in January 2012. As a result, sources that cannot achieve the required emissions reductions through redispatch of their units or the operation of existing controls will need to purchase allowances in order to mainta in current generation levels and comply with the rule. Although eliminating theFIP Revisions

- RTC Febru ary 7 , 2012 Page 137

137 threat of assurance penalties does not itself increase the number of allowances allocated under CSAPR, it may increase the number of allowances that are offered for sale. Com menter (Class of '85) provides additional discussion on this issue and agrees with EPA that postponing implementation of the assurance penalty provisions will not result in harm to the environment since CSAPR will achieve the same level of emissions reduct ions in 2012 regardless of whether the assurance penalty provisions are implemented. [Letters: Class of '85 (EPA

- HQ

- OAR

- 2009

- 0491

- 4821) p. 1

- 3]
RESPONSE : EPA is finalizing the delay of the assurance provisions until 2014. See section IV.C of the prea mble to this final rule. (E) Delaying the assurance provision does not alleviate reliability concerns. Comment (E)(1) : Even with the proposed revisions to the final rule, the substantial cuts in NO X emissions allocation to the states in the seasonal NO X program will likely prevent a viable intrastate or interstate trading market from becoming a reality. Even with the revisions, Mississippi's budget suffers a 23% reduction compared to Mississippi's actual 2010 NO X emissions. A trading market will not e xist inside Mississippi. Mississippi utilities will not likely be able to purchase allowances from utilities in other states due to the severity of the budget reductions in those states. For seasonal NO X emissions, 13 states still face budget reductions ranging from 0.70% to 49%, with an average of 13.9% for the affected states. A comparison of the state budgets under the proposed revisions to actual 2010 seasonal NO X emissions illustrates the severity of the cuts. Total 2010 seasonal NO X emissions for states under the rule were 585,566 tons while the 2012 total budget is 506,378 tons (a 13.5% reduction). Regardless of when the assurance provision is set to begin, there is simply not enough liquidity for a viable market to exist in May 2012. The reduce d allocation budgets in the final rule leave no options for Mississippi utilities to comply by May 2012 in a cost

- effective manner. Mississippi utilities will likely be forced to reduce their generating capacity during the summer of 2012 thereby degrading the reliability of the power system. For this reason, and others previously expressed, commenters request that the Administrator reconsider and stay implementation of the Final Rule. [Letters: Mississippi Public Service Commission (EPA

- HQ

- OAR

- 2009

- 0491

- 4746) p. 4; South Mississippi Electric Power Association (EPA

- HQ

- OAR

- 2009

- 0491

- 4763) p. 3]
RESPONSE : The commenter’s claim that utilities will not be able to purchase allowances due to state budgets below current emission levels is not supported by the successful record of other cap
- and

- trade programs. Previous programs such as the Acid Rain Program and NO X Budget Trading Program have concurrently reduced emissions and sustained liquid trading markets. EPA is finalizing the delay of the assurance provi sions until 2014. See section IV.C of the preamble to this final rule. EPA will respond to petitions for reconsideration separately. (F) Assurance provisions should be delayed until 2017 for non
- CAIR states. Comment (F)(1) : The proposed revision to d elay until 2014 moves in the right direction, but does not go far enough insofar as Nebraska utilities are concerned. Nebraska did not participateFIP Revisions

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138 in the NO X SIP Call, and was not subject to the Clean Air Interstate Rule. It is patently unfair to expect non
- CAIR stat utilities to comply with the same provisions as CAIR state utilities that have had years to prepare. NPPD requests that the assurance penalty provision become effective on January 1, 2017 for states which were not subject to CAIR. It is imp ortant to note that the court in North Carolina v EPA did not set any hard and fast deadlines for the EPA. The court's statement that EPA must decide whether 2015 or earlier is as expeditious as practical relates to nonattainment with the 1997 PM2.5 NAAQS . However, Nebraska is alleged to have interfered with maintenance at two sites in Milwaukee, Wisconsin, which were designated in non

- attainment with the 2006 PM2.5 NAAQS. Thus the North Carolina decision is not on point as to the deadline for the Wiscon sin monitoring receptors. The Clean Air Act provides that the deadline for attainment for the Milwaukee sites is December 14, 2014, unless a five year extension is granted. Given that the Clean Air Act allows an extension of the compliance deadline for N ebraska to 2019, EPA should find no impediments to extending the Nebraska deadline to 2017. No harm will come as the Milwaukee monitoring sites are now in attainment. [Letters: Nebraska Public Power District (NPPD) (EPA

- HQ

- OAR

- 2009

- 0491

- 4754) p. 2

- 3]
RESPONSE : EPA is finalizing the delay of the assurance provisions until 2014. See section IV.C of the preamble to this final rule. (G) EPA should not defer the penalty provisions since it would hinder timely compliance with the new ozone NAAQS.
Comm ent (G)(1) : Commenter does not provide additional discussion on this issue. [Letters: Maryland Department of Environment (EPA

- HQ

- OAR

- 2009

- 0491

- 4812) p. 3]
RESPONSE : As described in the preamble of the final Transport Rule (FR 76, page 48218), with res pect to ozone, this rule and the revisions rule focus on the removal of significant contribution and interference with maintenance of the 1997 ozone NAAQS, and not with the 2008 ozone NAAQS. EPA is finalizing the delay of the assurance provisions until 20 14. See section IV.C of the preamble to this final rule. (H) Supports EPA's proposal to delay the effective date of the assurance penalty provisions, but it does not solve the bigger problem of lack of allowances during the first years of the trading pro gram. Comment (H)(1) : Commenter generally supports EPA's proposed change to the assurance penalty provisions of the CSAPR, but it does not solve the biggest problem which is a lack of emission allowances to purchase during the first years of the trading program. Even with the provisions delayed until 2014 there will be a major shortage of emission allowances to purchase. For instance under the ozone season NO X trading program there is a nationwide budget of 620,499 allowances to cover 704,992 average NO X emissions (2008

- 2010 period). This yields a deficit of 84,493 allowances. Also, the penalties for not holding sufficient allowance remainFIP Revisions

- RTC Febru ary 7 , 2012 Page 139

139 excessively high. Shortage is due to the fact that the effective date of CSAPR does not allow ample time to insta ll emission controls. For this reason, CSAPR should be delayed it its entirety for at least two years so that EGU operators can have additional time to install controls. [Letters: Arkansas Electric Cooperative (EPA

- HQ

- OAR

- 2009

- 0491

- 4791) p. 1

- 2]
RESPON SE : EPA is finalizing the delay of the assurance provisions until 2014. As explained in section IV.C of the preamble to this final rule , we do not believe there is a shortage of allowances

. Comment (H)(2) : Consumers Energy believes that the CSAPR, even if it were to be modified with the proposed changes, remains seriously flawed. EPA should accept, analyze, and respond to all comments identifying errors in the CSAPR. Then, EPA should adjust its modeling to account for those errors. EPA should defer t he start of the first compliance periods until the state budgets and unit

- level allocations have been revised and put in final form. In any event, EPA should promptly make final its proposal to defer the effective date of the assurance provisions under th e CSAPR until 2014. [Letters: Consumers Energy (EPA

- HQ

- OAR

- 2009

- 0491

- 4808) p. 7]
RESPONSE : EPA is addressing all identified corrections . See the Final Revisions Rule State Budgets and New Unit Set

- Asides TSD in the docket to this rulemaking . EPA is f inalizing the delay of the assurance provisions until 2014. See section IV.C of the preamble to this final rule.

(I) The Proposed Rule is not supported by the record and the Court has already concluded that implementation of 110(a)(2)(D)(i)(I) is unlawf ul. EPA has presented no reasoned basis for (and should not adopt) this amendment. Comment (I)(1) : Commenter (NC Attorney General) provides a description of the D.C. Circuit's opinion on interstate trading and EPA's response to that decision in the form of the CSAPR. To address the Court's opinion, in the July 2010 proposed CSAPR, EPA proposed to curb interstate trading. After EPA assigned to each State a budget, EPA then inflated that budget to account for year
- to

- year variability in emissions. This budget

- plus

- variability amount was termed the State's assurance level. However, under the proposed CSAPR, the restrictions on interstate trading would have been completely unenforceable in the near term. Commenter provides additional description of the s equence of decisions noting that EPA's proposal to allow unrestricted interstate trading in 2012 and 2013 did not withstand scrutiny. In the Proposed Rule, EPA indicates that it intends to revert to its original position and prohibit any enforcement of th e curbs on interstate trading in 2012 and 2013. That is, EPA proposes to allow unrestricted interstate trading in the first two years of CSAPR. Despite EPA‘s new justification, this path remains as unlawful today as it was when EPA first put it on the ta ble in July 2010. As such, the Proposed Rule violates 110(a)(2)(D)(i)(I) as interpreted by the D.C. Circuit in "North Carolina." Commenter provides additional discussion (and their previous comments submitted on October 1, 2010 on this issue as Attachmen t 1) and cites numerous portions of the "North Carolina" decision as well as portions of the Proposed Rule to support their assertion on this issue, andFIP Revisions

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140 concludes that the inescapable conclusion from "North Carolina" is that without the assurance provision s in 2012 and 2013, the program is unlawful. EPA attempts to justify its change of position by claiming that stakeholders have informed it that imposing assurance provisions in 2012 and 2013 would restrict market activity and make the transition to CSAPR somewhat rocky. Whatever the merits of this claim, it has no support in the statute. Nowhere does the statute permit concerns about market economics to allow upwind sources to shirk their statutory obligations, even temporarily. EPA cannot deny that the assurance levels draw the line between lawful and unlawful emissions in every year, including 2012 and 2013. EPA‘s rationale for allowing sources to ignore this line, no matter how well

- intended or well

- reasoned and for no matter how brief a period, is o utside the scope of Congress‘ plan. [Letters: North Carolina Attorney General (EPA

- HQ

- OAR

- 2009

- 0491

- 4825) p. 1

- 8]
RESPONSE : EPA disagrees with commenter’s argument that delaying the assurance provisions until 2014 is unlawful under section 110(a)(2)(D) (i)(I) and inconsistent with the D.C. Circuit’s opinion in North Carolina . The Court’s mandate that EPA must “promulgat[e] a rule that achieves something measurable toward the goal of prohibiting sources “within the State” from contributing to nonattainme nt or interfering with maintenance “in any other state,”” 531 F.3d at 907, is more than satisfied by th e Transport Rule as revised by th is action. As explained in the preamble, EPA determined that the assurance provisions did not need to be in place befor e 2014 and that it is reasonable to delay their implementation to facilitate the transition from the Clean Air Interstate Rule (CAIR), which currently remains in place due to the stay of the Transport Rule, and the Transport Rule. T he existence of the ass urance provisions in 2014 and beyond will affect the decisions of EGU owners and operators in the preceding years as well since EGU owners and operators can reasonably be expected to take 2014 compliance requirements into account when making key decisions that affect emission rates and total emissions. Furthermore, as explained in the preamble, EPA has demonstrated, using the most recent data and modeling, that in 2012 and 2013 the rule will result in emission reductions that cause each participating state to emit below the level of the applicable assurance levels , thereby ensuring elimination of all emissions identified in the rule as significantly contributing to downwind nonattainment or interfering with maintenance . It is thus reasonable for the agency to ease the transition from CAIR to CSAPR by taking this step. Comment (I)(2) : Data from EPA's CAMD completely undermines EPA's stated justification for the Proposed Rule. In the FR notice, EPA states that amending the effective date of the assurance pr ovisions would ease the transition from CAIR to the Transport Rule, promote market liquidity, and allow for flexible compliance strategies (76 FR 63871). However, EPA's own statements since then undercut that justification, as do intervening facts. In th e litigation that has ensued over CSAPR, EPA has had to respond to a number of stay requests directed to the same federal appeals court that decided North Carolina. Some of those motions are grounded, at least in part, on the complaint that sources at a g iven plant or in a certain geographic region will not be allocated sufficient allowances to cover their emissions. The arguments thus assume, implicitly or explicitly, that the allowance markets will not be adequately liquid to allow for the purchase, at a reasonable price, of allowances from other sources to make up the differences. Commenter observes that EPA‘s position on these arguments is that they are factually inaccurate. That is,FIP Revisions

- RTC Febru ary 7 , 2012 Page 141

141 EPA asserts that allowance markets are sufficiently liquid to rende r them a perfectly viable compliance option. Commenter provides several references as examples (in the context of Louisiana v. EPA, Wisc. Pub. Serv. Corp. v. EPA, and EME Homer City Generation L.P. v. EPA (provided as Attachment 2)) and cites verbatim sev eral statements made by CAMD Director Sam Napolitano, adding that he clearly subscribes to the view that the markets do not lack liquidity or price information, making them a useful compliance option in 2012, 2013 and beyond. Commenter adds that on Novemb er 17, 2011 First Energy successfully completed the auction to which Mr. Napolitano referred and announced plans to hold a second auction no later than April 30, 2012 (supporting documentation is provided as Attachment 3). In addition, Exelon has already sold $750,000 of 2012 NO X allowances (supporting documentation is provided as Attachment 4). The detailed observations and conclusions of Mr. Napolitano along with facts on the ground, completely undermine EPA's basis for proposing to eliminate all enforc ement of the assurance provisions in 2012 and 2013. [Letters: North Carolina Attorney General (EPA

- HQ

OAR

- 2009

- 0491

- 4825) p. 8

- 12]
RESPONSE : Commenter correctly observed that, prior to the D.C. Circuit’s order staying the rule on December 30, 2011, a number of trades occurred in the Transport Rule markets. In litigation preceding the court’s stay, EPA acknowledged that these trades were happening and argued that the existence of these early trades tended to contradict litigants’ claims that no allowan ces would be available for trading at all. These statements , however, do not “completely undermine” EPA’s conclusion that delaying the effect of the assurance provisions in the very near term would help ease the transition from CAIR to CSAPR and would ass ist the growth and development of the markets under the Transport Rule’s trading programs. As explained in the preamble, the development of the trading regime into a robust, mature market is inherently dependent on the confidence of participating stakehol ders. Because the state assurance levels promulgated in the Transport Rule w ill be met even absent the assurance provisions in 2012 and 2013, neutralizing this potential obstacle to the development of the Transport Rule markets is a reasonable action.
Co mment (I)(3) : The Proposed Rule is not supported by the record and is therefore arbitrary, capricious, and unlawful. Commenter (NC Attorney General) cites to 76 FR 63871 where EPA states that "there is a high level of certainty that the state assurance l evels will not be exceeded in 2012 and 2013." Because, according to EPA, the unit emissions allocations should be close to the unit's actual levels for the 2012 and 2013, there should be relatively few allowances traded. The very nature of how EPA calcul ated the 2012

- 13 budgets is the culprit if the markets do not develop in the early years, not stakeholders' concern about "uncertainty over how each state will transition" from CAIR to CSAPR (76 FR 63870). It is irrational for EPA to handcuff enforcement of the budgets on the ground that there is a "high level of certainty" that enforcement will not be necessary. First, a "high level of certainty" itself indicates that EPA is not entirely certain that the assurance levels will not be exceeded. Second, EP A's "level of certainty" is based on EPA‘s own body of technical work. Although this work was extensive, it is by no means infallible, especially when the question is one of the predictions of future compliance behavior. Commenter notes that EPA original ly asserted in the CSAPR proposal that it had a "high level of certainty" that all States would comply with their assurance levels inFIP Revisions

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142 2012 and 2013 (75 FR 45306) and provides significant additional discussion on this issue and concludes that EPA cannot rat ionally dispense with the only enforcement tool it has regarding the 2012 and 2013 budgets simply based on its technical record, which EPA itself already asserts is faulty. [Letters: North Carolina Attorney General (EPA

- HQ

- OAR

- 2009

- 0491

- 4825) p. 12

- 15]
R ESPONSE : EPA has based its decision to delay the assurance provisions on its technical analysis and record. It is notable that the commenter does not actually indicate any specific outstanding errors in the record and analysis, and it is not arbitrary and capricious for the agency to base its decisions on its own technical analysis and record. The commenter has had ample opportunity, during the notice and comment period for the Transport Rule, subsequent notices of data availability, the supplemental rulem aking, and this current rulemaking, to indicate actual deficiencies in EPA’s technical analysis, if it believes that the agency should not base its decisions on that technical analysis. In addition, EPA’s conclusion that all states will meet their assuranc e levels, even without the assurance provisions, does not suggest that no trading between individual sources will occur. Commenter’s argument that “there should be relatively few allowances to trade” is not supported by any analysis of cost

- effective comp liance with the Transport Rule, and it ignores the fact that the rule imposes no limitation on the degree to which sources may trade allowances with other sources within the same state . There is no basis for the commenter’s presumption that sources within a given state would not desire to minimize their compliance costs by accessing a liquid allowance trading market that allows the state to meet its obligation while minimizing costs across the covered sources within that state. It is therefore reasonable for EPA to consider the potential impact on trading markets associated with immediate implementation of the assurance provisions. EPA concluded that the introduction of the assurance provisions at the immediate outset of the program could inhibit early tra nsaction behavior as sources transitioned from CAIR to the Transport Rule programs, and such inhibition could delay the efficient development of the overall Transport Rule allowance markets, thereby potentially impairing the ability of sources to trade all owances even with other sources located in their own states. Finally, there is nothing to support commenter’s apparent conclusion that trading at the source level would lead to the state’s emissions exceeding the state assurance level, and EPA’s technical analysis shows that it will not. Comment (I)(4) : EPA asserts that it "did not disavow the proposal's rationale for starting the assurance provisions in 2014" (76 FR 63871). In the CSAPR proposal, EPA set forth four justifications for freeing sources fr om any enforcement of the budgets in 2012 and 2013. In its previous comments, North Carolina explained exactly why each justification was arbitrary and could not support EPA's proposed rule. EPA never responded on point because it properly abandoned its unlawful proposal. To the extent that EPA now relies on any previous rationale that it "did not disavow," North Carolina again submits that EPA's reasoning is faulty, for the reasons previously stated. Commenter cites to their previously submitted commen ts (provided as Attachment 1) at p. 26

- 30. [Letters: North Carolina Attorney General (EPA

- HQ

- OAR

- 2009

- 0491

- 4825) p. 15]FIP Revisions

- RTC Febru ary 7 , 2012 Page 143

143 RESPONSE : In their original submission of October 1, 2010, which commenter has resubmitted, commenter first disagreed that EPA’s “h igh level of certainty” that reductions would occur was sufficient to support its decision to delay the assurance provisions. As detailed in the preamble and in the three responses provided above, EPA’s position is based on new and careful analysis of the most recent data and modeling. Further, the imposition of the assurance provisions in 2014 will impact sources’ compliance planning in preceding years as well. Based on its analysis, EPA has determined that the EGU emissions in each state have virtually no chance of exceeding the applicable state assurance levels. Regarding commenter’s second point, EPA has reasonably chosen to delay the assurance provisions under the rationale outlined in the preamble. EPA could have chosen to implement the assurance provisions for 2012 and 2013 in order to provide additional assurance that the budgets would be met, but that does not mean it was required to do so . EPA is in accord with commenter that 2012 and 2013 would be no different from years that follow in that s tates must eliminate emissions identified as significantly contributing to nonattainment and interfering with maintenance in all years . As explained in the preamble, EPA believes, based on the most recent data and its analysis, that states will not exceed their assurance levels even in the absence of the assurance provisions. It is therefore reasonable for EPA to take the challenge of the transition from CAIR to CSAPR into consideration in its decision to delay the assurance provisions. EPA disagrees wit h commenter’s suggestion that EPA should not need to take into consideration compliance flexibility for sources during this transition period. EPA has not based the design of the Transport Rule programs on any individual source’s projected emissions under the program; for example, EPA bases initial unit

- level allowance allocations on historic heat input, not on projected unit

- level emissions, and units have the flexibility under these programs to determine their own cost

- effective level of emissions subjec t to the overarching state

- level emission reduction requirement. Therefore, individual sources may still require flexibility in compliance options (including access to a well

developed allowance market) even though EPA is confident in its assertion that s tates will not exceed their assurance levels. Comment (I)(5) : The Proposed Rule violates the anti

- backsliding provision of 110(l). The Proposed Rule would amend the current implementation plans. Section 110(l) of the Act provides that EPA "shall not approve a revision of a plan if the revision would interfere with any applicable requirement concerning attainment and reasonable further progress (as defined in section 171), or any other applicable requirement of this Act". The Proposed Rule is a revis ion to the States' existing plans. EPA is barred from promulgating the Proposed Rule if the rule would "interfere with any applicable requirement concerning attainment and reasonable further progress... or any other applicable requirement of this Act." C ommenter (NC Attorney General) refers to Ky. Res. Council, Inc. v. EPA (467 F.3d 986, 994 (6th Cir. 2006)), noting that Section 110(l) requires EPA to reject any revision that would "interfere with attainment" and that EPA's reference to "artificial" in th eir statement that the effect of the revision would be to counteract sources "artificially constrain[ing] 2012 operational plans" is unclear (76 FR 63871). However, what is clear is that EPA expects that these revisions would foster less constrained opera tions in 2012 (i.e., sources would emit more). Commenter provides additional discussion and concludes that these revisions will, at least in some locations, lead to increases in ambient PM2.5 and ozone levels in nonattaining areas at or near the attainmen t deadlines and therefore violate the anti

-FIP Revisions

- RTC Febru ary 7 , 2012 Page 144

144 backsliding provision of §110(l). [Letters: North Carolina Attorney General (EPA

- HQ

- OAR

2009

- 0491

- 4825) p. 16

- 17]
RESPONSE : EPA also rejects the assertion in North Carolina’s comments that delaying the effect iveness of the assurance provisions until 2014 violates CAA section 110(l). Section 110(l) states that each implementation plan revision “submitted by a [s]tate” must be adopted by the state “after reasonable notice and public hearing.” 42 U.S.C. 7410(l) . This section further states that EPA “shall not approve a revision of a plan if the revision would interfere with any applicable requirement concerning attainment and reasonable further progress. . . or any other applicable requirement of” the CAA. 42 U.S.C. 7410(l). According to North Carolina, this statutory provision bars EPA from dela ying the effectiveness of the assurance provisions in the Transport Rule FIPs because this delay “will, at least in some locations, lead to” increased emissions in som e nonattainment or maintenance areas. It is not clear whether section 110(l) applies to this rule, given that the section, on its face, addresses revisions to implementation plans submitted by states and approved by EPA. 42 U.S.C. 7410(l). Even assuming that it does, EPA has concluded, based on the record, that pursuant to this action, total EGU emissions in each state will be below the state assurance level and each state will eliminat e the significant contribution and interference with maintenance iden tified in the final Transport Rule . Therefore, this rule will not interfere with attainment or maintenance of the NAAQS, or any other applicable requirement of the CAA

. Commenter has failed to show otherwise. On the contrary, commenter has simply specul ated that the lack of assurance provisions in the first two years of the rule’s implementation will result in more emissions in “some locations” than if the assurance provisions were in effect , and that these emissions will increase ambient pollutant level s in areas with nonattainment or maintenance problems. However, commenter has failed to identify any such “locations” and any such nonattainment/maintenance problem areas, much less provided any support (beyond its bare assertion) that these emission incr eases and ambient effects would occur. (J) The assurance provisions should not be delayed by more than one year if at all. Comment (J)(1) : The assurance provisions should not be delayed by more than one year if at all. Falling allowance prices and in creased trading suggest that the delay is unnecessary, and delay beyond 2013 creates a risk of there being insufficient constraints to assure eliminations of all states significant contributions. Rather than postponing the assurance provisions for a secon d year, a small auction could be held, if necessary to address any liquidity concerns for 2013. EPA could hold back a small percentage of the allowances that it would otherwise populate in existing units' compliance accounts, and auction these allowances. EPA would model the auction on the auction provided by Title IV of the Clean Air Act, and would withhold 2.8% of the allowances for each unit's budget for the auction. Individual unit and state budgets would remain the same for the purposes of assurance provisions, but units would simply receive 2.8% fewer free allowances. The auction would be a single round, uniform price, sealed bid auction with the proceeds of the auction flowing back to the source owners that contributed the allowances.FIP Revisions

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145 If concerns about the market persist despite freeing up of allowances by new equipment, retirements, banking, and the use of an auction, EPA could initiate a second rulemaking proceeding to delay the effectiveness of the assurance provisions for a second year. There is no reason to believe such a delay is necessary. [Letters: Exelon (EPA

- HQ

- OAR

- 2009

- 0491

- 4810) p. 25

- 30]
RESPONSE : EPA is finalizing the delay of the assurance provisions until 2014. See section IV.C of the preamble to this final rule for more detail s explaining EPA’s decision. (K) Supports EPA's decision to defer the effective date of the assurance penalty provisions, but adds that January 1, 2014 should also be established as the compliance deadline for the mandated emissions reductions. Comment ( K)(1) : Commenter (Luminant) references the OMB report and describes OMB's concerns with EPA's decision to accelerate the assurance provisions to 2012. Commenter supports EPA’s decision to now reinstate the 2014 effective date for the assurance provisions

. However, the OMB report also expressed concerns about the ability of sources to meet the January 1, 2012 compliance deadline, given the substantial changes made by EPA to the final CSAPR, and EPA should address those concerns as well by staying and dela ying the January 1, 2012 start date. There is no basis or requirement in the Clean Air Act for a January 1, 2012 effective date for the assurance provisions or for the January 1, 2012 compliance start date for upwind emissions reductions. Commenter provi des additional discussion on this issue and references its judicial filings and request for reconsideration and stay in support of their position on this issue. Even if the assurance date is pushed back, emissions generated by an EGU after January 1, 2012 , count against the EGU’s emissions budget that goes into effect on January 1, 2012, and the EGU must ultimately have enough allowances to cover those emissions. Further, by leaving the January 1, 2012 compliance start date in place, the constraints on al lowance trading caused by EPA’s short compliance start date and its failure to allocate sufficient allowances (unprecedented in prior similar rulemakings) continue to exist. [Letters: Luminant (EPA

- HQ

- OAR

- 2009

- 0491

- 4818) p. 25

- 28]
RESPONSE : Compliance deadlines have been addressed in the final Transport Rule and are outside the scope of the revisions proposed and upon which EPA solicited comment (76 FR 63860) . EPA is finalizing the delay of the assurance provisions until 2014. See section IV.C of the p reamble to this final rule. Issue 4.2: Impact of Assurance Penalty Provisions on Allowance Market Liquidity
Points Raised: (A) Proposed multi
- year delay in the start of the assurance provision is not necessary to address market liquidity. Comment (A)(1) : Exelon in its hearing testimony and written comments note that with regard to the development of emission allowance markets and liquidities in the early years, they believeFIP Revisions

- RTC Febru ary 7 , 2012 Page 146

146 that the sooner the proposed rule process is concluded, the better. Exelon agrees with all of EPA's proposed budget revisions. However, they do not believe that the proposed multi year delay in the start of the assurance provision is necessary to address market liquidity. The issue of liquidity is a Year 1 issue that should only be addressed, if at all, by accommodations in 2012. EPA should not delay the assurance provision implementation by more than one year. The assurance provision construct is a necessary element of the CSAPR, implemented to respond to the Court's 2008 North Ca rolina decision. It's a critical element of what makes CSAPR different from CAIR, and it's a necessary component of the final rule. Any concerns regarding liquidity in 2013 would better be addressed by an auction modeled on the Acid Rain SO 2 auction pro gram of a small percentage of 2013 allowances. A one year delay of the assurance provisions followed by an auction would better assure compliance with the Court's mandate than would a two year delay.
Also in its written comment Exelon notes that without the assurance provisions, CSAPR does not look much different than CAIR. Delaying the assurance provisions makes it possible that excess emissions reductions in one state could allow emissions to increase in a second state beyond those modeled, raising the possibility that the second state's significant contribution will not be eliminated. While a one year delay may be justifiable based on EPA's modeling of reductions available in 2012, this is less the case for a two year delay of the assurance provisions . As time elapses beyond the period on which EPA's modeling is based, the greater the likelihood becomes of a state exceeding its budgets. With each passing year comes the installation of new controls, retirement of older non

- economic plants, and shifts in generation. These changes could affect allowance prices and, therefore, the market's allocation of reductions among the states, allowing potential significant contribution to develop or re

- develop in some states. The same factor also makes a two year delay unnecessary. New control equipment, new low emissions generating capacity, and retirements in 2012 and 2013 will increase liquidity. Controls do not need to be in place by January 1, 2013 to impact liquidity. The operation of new control equipment even during the last month of 2013 can make additional allowances available for sale during all of 2013. Since the proposed revisions were signed on October 6, 2011, the industry has already seen progress toward development of a robust allowance market. Exelon has already sold allowances that it will create, in part, by operating previously idled control equipment. Exelon has seen bid

ask spreads close and prices decline as regulatory certainty increases. On October 24, First Energy Solutions announced an auction of allowances for 2012 and 2013 in mid

- November. They conducted their auction on November 17, 2011, and announced that four of the six products offered cleared above our minimum prices. This demonstrates the effectiveness and liquidity of th e CSAPR market. The minimum prices charged were $200 for Group 1 SO 2 and $800 for both NO X products. First Energy announced it would conduct another auction no later than April 30,2012. These auctions support the conclusion that additional allowances wi ll comeFIP Revisions

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147 onto the market as regulatory certainty increases. [Letters: Exelon (EPA

- HQ

- OAR

- 2009

- 0491

- 4810) p. 25

- 30; Exelon Corporation (EPA

- HQ

- OAR

- 2009

- 0491

- 9004) p. 42

- 43]
RESPONSE : Allowance auctions have been addressed in the final Transport Rule and are outside the scope of the revisions proposed and upon which EPA solicited comment (76 FR 63860) . EPA is finalizing the delay of the assurance provisions until 2014. See section IV.C of the preamble to this final rule. (B) The delay in the assurance prov isions will not promote the development of the allowance market. Comment (B)(1) : EPA’s Proposal would delay the implementation of the assurance provisions until 2014. Commenters support this proposal because it gives added compliance flexibility. Howev er, they disagree with EPA’s assertion that this will promote the development of the allowance market or ensure liquidity. One commenter (Integrys) notes that it will have the opposite effect in that the proposal would likely increase the demand for allow ances (more buyers based on penalty elimination), but does nothing for the supply of allowances. EPA did not allocate sufficient allowances or allow enough time before Cross

- State Rule implementation to allow a true market to develop. In order for a mark et to develop, there must be sufficient time for the installation of controls by those for whom it makes economic sense, thus freeing up allowances for sale to those without an economic control option. There will be a significant allowance shortfall in th e beginning of the program, and even those facilities with excess allowances are likely to bank them for their own future use rather than sell them, especially in SO 2 Group 1, for which the cap drops sharply in 2014. [Letters: Integrys Business Support ( EPA

- HQ

- OAR

- 2009

- 0491

- 4757) p. 5; Wisconsin Industrial Ratepayer Group (EPA

- HQ

- OAR

2009

- 0491

- 4789) p. 2]
RESPONSE : Compliance deadlines have been addressed in the final Transport Rule and are outside the scope of the revisions proposed and upon which EPA solicited comments (76 FR 63860) . EPA is finalizing the delay of the assurance provisions until 2014. See section IV.C of the preamble to this final rule. (C) Despite the proposed delay of the assurance provisions and variability limits until 2014, timing issues and regulatory uncertainty will preclude a sufficient level of SO 2 allowance trading. Comment (C)(1) : EPA's own actions are an impediment to the development of the emission trading markets that EPA claims will address companies' concerns. The re peated rulemakings and changes to the CSAPR program create significant uncertainty in the regulated community and discourages market development. EPA's assumption that an emissions banking and trading market can develop within the unprecedented and unreas onable compliance timeline that the EPA is mandating by requiring huge SO 2 reductions in some states by next year is flawed. Additional time must be provided for the trading market to develop after the regulated community has greater certainty about their regulatory requirements and their compliance plans.FIP Revisions

- RTC Febru ary 7 , 2012 Page 148

148 The EPA’s intent for delaying the assurance provisions until 2014 is to encourage trading in the initial two years of the CSAPR program. However, Texas is still limited to trading with Group 2 states, w hich still does not appear to be a viable trading market for SO 2 allowances sufficient to address Texas’ concerns. While the TCEQ has limited information about the compliance plans of EGUs in other Group 2 states, by extrapolating SO 2 emissions data for 20 11 from the EPA’s Acid Rain Program, it appears that some of the Group 2 states might have a marginal surplus in 2012 and some are expected to have a deficit. However, even excluding Texas’ expected 120,000 additional tons of reductions needed next year, t he remaining Group 2 states are expected to have a net deficit in allowances. Additionally, any marginal surplus in some of the Group 2 states is not expected to be sufficient to cover the necessary SO 2 reductions required of Texas. [Letters: Texas Commi ssion on Environmental Quality (EPA

- HQ

- OAR

- 2009

- 0491

- 4782) p. 1

- 2(cvr), p. 4]
RESPONSE : EPA is finalizing the delay of the assurance provisions until 2014. As explained in section IV.C of the preamble to this final rule , we do not believe there will be an allowance shortfall. (D) Simply removing the assurance penalty provisions is not enough to ensure the development of liquid trading markets. Comment (D)(1) : Even if EPA finalizes the proposed budget revisions and delays implementation of the assurance p enalty provisions until 2014, it is unlikely that in 2012 there will be sufficient seasonal NO X allowances to cover demand in most states. In support of their assertion, commenter (Entergy) provides state

- specific budget and allowance numbers in Table 2 o f their letter. For most states, the proposed seasonal NO X budgets still are significantly below actual 2010 emissions. Under the Proposed Rule, there is a seasonal NO X allowance deficit of 81,037 tons, compared to 2010 emissions, assuming that all sourc es that are anticipated to have excess allowances enter the market. It is unlikely that the limited number of sources with positive margins can increase control efficiency enough to generate a meaningful number of additional allowances in 2012. Thus, giv en the stringency of the emissions caps, it is highly unlikely that allowance purchases will be a cost

- effective compliance option in 2012. Commenter provides additional discussion noting that EPA should delay implementation of the entire CSAPR program un til 2014, instead of just the assurance penalty provisions, to give at least some affected sources sufficient time to install pollution controls. [Letters: Entergy (EPA

HQ

- OAR

- 2009

- 0491

- 4820) p. 6

- 7]
RESPONSE : EPA is finalizing the delay of the assuran ce provisions until 2014. See section IV.C of the preamble to this final rule. (E) EPA should incorporate a borrow
- forward option to increase liquidity in the CSAPR allowance market during Phase I. Comment (E)(1) : Although the Homer City OLs support EPA's proposed delay of the assurance provisions, this revision alone will not adequately address allowance market liquidity since itFIP Revisions

- RTC Febru ary 7 , 2012 Page 149

149 does not eliminate the perverse incentive created by the rule for entities long on allowances to hoard them. The Homer City OL s believe that market liquidity can be improved further if during a tight market, participants have the "safety valve" option of borrowing Phase II vintage allowances for use during Phase I. To ensure consistency with CSAPR's goals and purposes and to add ress the Clean Air Act's "good neighbor" provision, use of the borrow

- forward option could be conditioned on the following: 1) Only facilities that commit to install state

- of

- the

- art pollution control equipment by a date certain and pursuant to specified milestones would be eligible to borrow forward; 2) Eligible entities cannot borrow forward unless they use (as opposed to sell) all their Phase I allowances; and 3) Any Phase Il allowances used during Phase I must be discounted by 10% (i.e., 1 Phase II all owance equal to 0.9 Phase I allowance) and permanently retired. From a policy perspective, the borrow forward option would provide additional liquidity to the SO; allowance market during the crucial transition between CAIR and CSAPR and between CSAPR Phas e I and CSAPR Phase ll. The option would recognize that it is difficult to predict all the implications of the abrupt shift from CAIR allowances to CSAPR allowances and how the regulated community will react to the removal of CAIR allowances from existing accounts and the uncertainty of the Utility MACT rule. In addition, and perhaps more importantly, the borrow

- forward option would promote market discipline by making it less likely that EGUs with excess allowances in Phase 1 would act to withhold such al lowances from the market. Importantly, a borrow forward option would not compromise any of the rule's public health benefits or run afoul of North Carolina v. EPA, because it would not adjust the Phase II 2014 deadline or emission caps that drive the bene fits. In fact, this option would result in even greater longer

- term air

- quality benefits, because it requires the discounting of any Phase II allowances used during the Phase I transition years and would lower Phase II allocations to facilities that util ize this compliance option. [Letters: Homer City Owner Lessors LLC (EPA

- HQ

- OAR

- 2009

- 0491

- 4816) p. 2

- 3]
RESPONSE : Borrowing future allowances is outside the scope of the revisions proposed and upon which EPA solicited comments (76 FR 63860) . EPA is fi nalizing the delay of the assurance provisions until 2014. See section IV.C of the preamble to this final rule. Issue 4.3: Other Assurance Penalty Issues
Points Raised: (A) EPA should retain a two phased trigger assessment and the higher variability limi ts of the assurance provisions. Comment (A)(1) : Commenter also supports EPA's retention of the two phased approach in assessing whether the assurance provisions would apply. In addition we support the retention of the variability limits established in t he final rule (18% of annual SO 2 and NO X budgets, and 21% of the ozone season budgets). This coupled with the two year suspension of assurance provisionsFIP Revisions

- RTC Febru ary 7 , 2012 Page 150

150 will provide much needed flexibility in both short and long term. [Letters: Dominion Resources Serv ices (EPA

- HQ

- OAR

- 2009

- 0491

- 4790) p. 2]
RESPONSE : EPA is finalizing the delay of the assurance provisions until 2014. See section IV.C of the preamble to this final rule.FIP Revisions

- RTC Febru ary 7 , 2012 Page 151

151 5. General Comments Issue 5.1: General Support for Proposed Rule Revisions
Poi nts Raised: (A) Supports CSAPR and EPA's proposed limited technical revisions. Comment (A)(1) : Commenters note that they generally support the rule since it is a sound, achievable market based program that will deliver strong public health protections. So me commenters (e.g., Sierra Club) cite to statistics that support the public health benefits of the rule. Some commenters also note that EPA's proposed revisions accomplish important technical adjustments that will promote the development of allowance mar ket liquidity and smooth the transition from the Clean Air Interstate Rule known as CAIR programs, to the cross state rule in 2012 and nothing more. Commenters also assert that any delay in the implementation of the cross state air rule would not only be contrary to law; it would be detrimental to the public's health and environment, and would also be inequitable to those utilities that have made the investments in clean energy, installed emissions controls and closed uneconomic coal plants. [Letters: C alpine Corporation (EPA

- HQ

- OAR

- 2009

- 0491

- 4817) p. 2; Clean Air Task Force (EPA

- HQ

- OAR

- 2009

- 0491

- 9008) p. 47; Environmental Law and Policy Center (EPA

- HQ

- OAR

2009

- 0491

- 9006) p. 24

- 25; NRG Energy (EPA

- HQ

- OAR

- 2009

- 0491

- 4796) p. 1; Sierra Club (EPA

- HQ

- OAR

- 200 9

- 0491

- 9007) p. 35

- 36]
RESPONSE : EPA is finalizing the proposed state budget revisions. See section IV of the preamble to this final rule. Comment (A)(2) : EPA's proposal addresses discrepancies in unit

- specific modeling assumptions that affect the pr oper calculation of Transport Rule state budgets and assurance levels, and revises allowance allocations to specific units covered by certain consent decrees that restrict the use of those allowances. These important technical fixes allow the Transport Ru le to eliminate significant contribution and interference with maintenance from upwind areas and address deficiencies in the original analysis that created reliability concerns through the underestimation of generation in NY. The analysis in the final rul e did not properly constrain transmission in NY or quantify the impact of local reliability rules. The proposed revisions to the rule better address the non

- economic and out

- of

- merit order dispatch that is necessary to meet local electricity demand and ma intain a reliable electric system in NY. [Letters: New York State Department of Environmental Conservation (EPA

- HQ

- OAR

- 2009

- 0491

- 4788) p. 1]
RESPONSE : EPA is finalizing the proposed state budget revisions and assurance provision delay. See section IV of the preamble to this final rule. Comment (A)(3) : Commenter generally supports the proposed modifications to the rule, most notably the suspension of the implementation of assurance provisions from 2012 to 2014 and the additional allowances EPA is pro viding due to technical errors. These changes will provideFIP Revisions

- RTC Febru ary 7 , 2012 Page 152

152 affected sources much needed flexibility to meet the rule requirements in 2012. [Letters: Dominion Resources Services (EPA

- HQ

- OAR

- 2009

- 0491

- 4790) p. 1]
RESPONSE : EPA is finalizing the proposed state budget revisions and assurance provision delay. See section IV of the preamble to this final rule. (B) Supports timely implementation of the Transport Rule as proposed, as rule addresses the requirements of the Court, can be met within the compliance deadlines, and provides emission reductions essential to required air quality goals. Comment (B)(1) : Commenter (PSEG) supports the timely implementation of the Transport rule, because of the important air quality benefits. The rule addresses the requ irements of the Court and the technical corrections proposed by EPA further strengthen the rule. EPA should move forward with its technical corrections and implementation schedule. The electric power industry can meet the emissions reductions within the time lines called for by the Transport Rule, which are essential to meet air quality goals required by the Clean Air Act. [Letters: Public Service Enterprise Group (PSEG) (EPA

- HQ

- OAR

- 2009

- 0491

- 4793) p. 1

- 2; Public Service Enterprise Group (PSEG) (EPA

- HQ

- OAR

- 2009

- 0491

- 9003) p. 31] Comment (B)(2) : Exelon commends EPA for its continued commitment to implement CSAPR on January 1, 2012. For nearly a decade, investment in the electric industry has been stifled by environmental regulatory uncertainty. As suc h, EPA should finalize these regulations on a timely basis to help inform industry investments. Implementation of CSAPR beginning on January 1, 2012, is essential both to provide industry with desperately needed investment and regulatory certainty, and to achieve the large economic, environmental and health benefits that will flow from CSAPR. Currently, power plants are operating in an environment with little incentive for progress. Allowance prices under CAIR, which the Court of Appeals found unlawful b ut allowed to remain in force until EPA promulgated an appropriately protective replacement, have fallen so low that they do not create a sufficient incentive to run existing available emission control equipment. If allowance prices are too low, units tha t lack emission controls, such as some of those owned by EME Homer City Generation, L.P. in Pennsylvania and by Luminant Generation Company, LLC in Texas, can charge a lower price for electricity than companies who operate emission controls. In that case, the market reduces the dispatch of units that operate controls or causes units with controls to shut the controls off. CSAPR is essential to assure that companies will operate existing pollution control equipment on generating units and to encourage both the timely retrofit of uncontrolled units and investment in new low or zero pollution technology. Indeed, the anticipation of CSAPR and the Toxics Rule were important factors in guiding Exelon’s business and environmental strategy and its decision in Dec ember 2010 to embark on a multi

- billion dollar investment program to expand zero pollution generation capacity while closing older, less controlled fossil fuel

- fired plants.FIP Revisions

- RTC Febru ary 7 , 2012 Page 153

153 The focus of the Proposed Revisions is therefore correctly limited to the very na rrow proposed technical revisions to the Rule and to consideration of options to improve allowance market liquidity at the commencement of the CSAPR program. [Letters: Exelon Corporation (EPA

HQ

- OAR

- 2009

- 0491

- 9004) p. 38] Comment (B)(3) : The emissions reductions targets are achievable simply by optimizing the use of existing emissions controls and switching to cleaner forms of coal and use of natural gas. Many plants with dispatchable pollution controls do not operate them at full removal efficiency or even at all since it is more profitable to run the plants without operating these controls and because a minority of power plant operators are taking advantage of ongoing regulatory uncertainty and continued low CAIR allowance pricing. CSAPR will put an end to this practice. In addition, CSAPR will not threaten electric reliability and the will be no shortage of electricity to meet demand. The cost impacts of the rule are modest and are dwarfed by the overwhelming health care savings that EPA has calcul ated. Market costs are already lower than what EPA estimated. SO 2 allowances that EPA expected will sell for approximately $1,000 per ton in Group 1 states, are already selling for less than 900. Commenter provides additional discussion in support of th e rule and agrees with EPA's RIA that the CSAPR will have less than a one to two percent impact on retail electric rates. [Letters: Exelon (EPA

- HQ

- OAR

- 2009

- 0491

- 4810) p. 1

- 9; Exelon Corporation (EPA

- HQ

- OAR

- 2009

- 0491

- 9004) p. 38

- 40]
RESPONSE : EPA is fin alizing the proposed state budget revisions and assurance provision delay. See section IV of the preamble to this final rule. Comment (B)(4) : Very deep, additional reductions of NO X in upwind states are necessary for Maryland to attain the new ozone sta ndard. States like Maryland that have moved ahead proactively to control power plants and other sources in those states are being penalized for trying to clean the air and they are depending on EPA to use the Transport Rule and other authorities like the MACT requirements to level the playing field. Multiple FGDs, SCRs and other pollution control equipment at EGUs can be installed in a relatively short, 2 to 3 year time frame. In a period of just under 3 years, Maryland's 9 coal fired power plant units i nstalled 6 FGDs, 2 baghouses, 2 hydrated lime injection systems, 3 SCRs, 6 SNCRs and 6 powder activated carbon injection systems. Commenter (MDE) also asks EPA to move ahead quickly with stricter national rules for boilers, cement kilns, mobile sources, m arine engines, locomotives , and next round of EGU controls. These 6 source sectors represent about 75% of the NO X that is left to regulate. [Letters: Maryland Department of Environment (EPA

- HQ

OAR

- 2009

- 0491

- 4812) p. 2

- 3]
RESPONSE : As described in the preamble of the final Transport Rule (76 FR 48218), with respect to ozone, this rule and the revisions rule focus on the removal of significant contribution and interference with maintenance of the 1997 ozone NAAQS, and not with the 2008 ozone NAAQS. Cons equently, that portion of the comment is out

- of

- scope. EPA recognizes the commenters efforts to apply emission controls in their state, and appreciates their support for potential new emission rules.FIP Revisions

- RTC Febru ary 7 , 2012 Page 154

154 Comment (B)(5) : The CSAPR is a much

- needed, long

- over due public health safeguard. Even with the proposed adjustments to the final rule, CSAPR will have profound positive effects on our nation’s health and well

- being. As adjusted, this rule will still considerably reduce power plant emissions that travel ac ross state lines and contribute to ground level ozone and fine particle pollution. EPA should move forward as promptly as possible and should reject requests by industry for further delay of the rule’s effective dates, including the assurance penalty prov isions. [Letters: EDF, NRDC and Sierra Club (EPA

- HQ

- OAR

- 2009

- 0491

- 4822) p. 1

- 2]
RESPONSE : EPA is finalizing the proposed state budget revisions and assurance provision delay. See section IV of the preamble to this final rule. Comment (B)(6) : Exelon comments that requiring compliance beginning on January 1, 2012, will not jeopardize the reliability of the electric system. EPA properly calculated state budgets for 2012 and 2013 based on optimizing controls already in place or scheduled to be operation al by January 1, 2012 and some dispatch switching. Comparisons of 2010 physical emissions of states with 2012 state emission budgets significantly over state the percentage reductions that will be required in 2012 when existing underutilized pollution con trol equipment that was not operated at full removal potential in 2010 is considered. Claims that allowances will not be available for trading are unfounded. Exelon references it' s comments on the proposed CSAPR and report by M.J. Bradley and Associates and the Analysis Group showing that CSAPR would not have an adverse impact on reliability. They also reference the Charles Rivers Associates report reaching the same conclusion. Since that time, three additional reports, House testimony, and the results of the most recent PJM capacity auction (referenced more fully in the comment letter) have all reconfirmed and lent further support to EPA's conclusion that compliance with CSAPR as well as other proposed regulations affecting the electric generation indu stry will not impair grid reliability. Exelon goes on to comment in more detail on the referenced reports, EEI modeling results, and additional independent reports by the Bipartisan Policy Center and Congressional Research Service. Exelon concludes that reliability risk claims have been round refuted by objective analysis and are so contrary to the facts that those seeking to prolong the life of uneconomic coal plants now claim CSAPR will adversely impact local (emphasized) reliability. Even without the proposed revisions these claims are unfounded. They are based on the completely unwarranted assumptions that the initial allocation of free unit allowances act as a permit limitation and that units will be forced to curtail operations because there will b e no allowance trading. These assumptions are contrary to the actual Rule which allows trading and includes generous variability limits, all previous experience under cap and trade programs, and the actual trading that has already occurred and is expandin g. Thus neither the budget modifications nor the delay in assurance provisions proposed by EPA is necessary to assure reliability because additional allowances and increased liquidity could beFIP Revisions

- RTC Febru ary 7 , 2012 Page 155

155 created by switching dispatch to controlled and gas

- fired unit s at a slightly higher cost per ton. [Letters: Exelon (EPA

- HQ

- OAR

- 2009

- 0491

- 4810) p. 11

- 25]
RESPONSE : Compliance deadlines were addressed in the final Transport Rule and are outside the scope of the revisions proposed and upon which EPA solicited comme nts

. EPA is finalizing the proposed state budget revisions and assurance provision delay. See section IV of the preamble to this final rule. (C) Supports EPA's technical corrections to unit level information used to project emissions and develop state budg ets. Comment (C)(1) : EPA's correction of technical errors in the development of the state emission budgets for the final CSAPR provide greater flexibility in designing and implementing cost

effective measures to comply with the increased emission reducti on obligations in the rule. EPA's corrections also address some of the concerns that have been expressed concerning the lack of liquidity in the emissions trading markets and potential reliability issues that arise from not correctly incorporating localiz ed transmission constraints and other important limitations on the operation of the electricity grid in the compliance models used to develop the state budgets. [Letters: American Electric Power (EPA

- HQ

- OAR

- 2009

- 0491

- 4737) p. 1] Comment (C)(2) : The corrections to adjust for emissions controls not in

- service, incorrect control removal efficiency, unit unavailable for option, new units in

- service and units needed to support grid operation are all necessary corrections to the final rule. Commenter (AEP) s upports the corrections identified in the proposed rule, but also provides additional suggested corrections (which are summarized in subsequent sections of this report). [Letters: American Electric Power (EPA

- HQ

- OAR

- 2009

- 0491

- 4737) p. 1] Comment (C)(3) : AEP testified that it appreciates EPA's effort to correct technical deficiencies in the development of state emission budgets for the final Transport rule. The proposed corrections more accurately represent projected emission levels achievable in 2012

. [Letters: American Electric Power (EPA

- HQ

- OAR

- 2009

- 0491

- 9000) p. 50]
RESPONSE : EPA is finalizing the proposed state budget revisions and assurance provision delay. See section IV of the preamble to this final rule. Comment (C)(4) : Regarding the Fl orida specific data that EPA used to develop the rule, the FCG notes that they submitted detailed comments or information in that regard on September 30th (identifying several errors in the NO X emission rates and the Florida specific demand growth rate) a dding that they appreciate the inclusion of those issues in the proposal and will submit more detailed comments on those and other issues by November 28th. FCG in its hearing testimony also stated that it continues to research possible other areas that ca used under allocation for Florida including: EPA's apparent failure to account for certain must run units, units that are dispatched for non

- economic reasons; the non

- deployment of certain very efficient and low emitting units; the underutilization of cer tain units and the low state wide heat input;FIP Revisions

- RTC Febru ary 7 , 2012 Page 156

156 EPA's assumption that certain SCR NO X controls are dispatchable (when they may not be); and EPA's apparent failure to account for transmission constraints between units, between FERC regions. Detailed comments submitted on these issues are summarized in subsequent sections of this comment summary document. [Letters: Florida Electric Power Coordinating Group (EPA

HQ

- OAR

- 2009

- 0491

- 9001) p. 16]
RESPONSE : EPA has responding to the specific issues that FCG raised in other sections of this document, with the many of those responses appearing in section 1.1, which compiles comments on modeling topics related to Florida. Comment (C)(5) : Exelon Corporation in hearing testimony and written comment notes that the foc us of the proposed rule is rightly limited to technical corrections to the CSAPR, and consideration of the options to improve allowance market liquidity in the program's early years. This proposal provides the electric generation industry the fourth oppor tunity to file public comments related to technical corrections. Exelon support the agency's view that additional changes suggested during this public comment period should be subjected to a material impact threshold equal to no less than one percent of t he state's emission budget. The inherent flexibility of the allowance trading mechanism available under CSAPR will be more than adequate to address any perceived discrepancies below this threshold. [Letters: Exelon (EPA

HQ

- OAR

- 2009

- 0491

- 4810) p. 1, 5

- 8 ; Exelon Corporation (EPA

- HQ

- OAR

- 2009

- 0491

- 9004) p. 42]
RESPONSE : EPA is finalizing the proposed state budget revisions and assurance provision delay. See section IV of the preamble to this final rule. Comment (C)(6) : Commenter (LPSC) supports the tec hnical revisions to the CSAPR including those allocating an additional 4,201 tons of seasonal NO X allowances to Louisiana’s EGUs. However, commenter adds that their support for these specific changes should not be interpreted as a retreat or modification of positions they have taken previously and submitted in prior Transport Rule comments. [Letters: Louisiana Public Service Commission (EPA

- HQ

- OAR

2009

- 0491

- 4799) p. 1]
RESPONSE : EPA is finalizing the proposed state budget revisions and assurance provi sion delay. See section IV of the preamble to this final rule. Comment (C)(7) : Commenters generally support the proposed revisions, but do not provide additional discussion. [Letters: CPI USA North Carolina LLC (EPA

- HQ

- OAR

- 2009

- 0491

- 4813) p. 1

- 2; Sou th Carolina DHEC (EPA

- HQ

- OAR

- 2009

- 0491

- 4742) p. 3]
RESPONSE : EPA is finalizing the proposed state budget revisions and assurance provision delay. See section IV of the preamble to this final rule. Comment (C)(8) : EEI commends both EPA’s effort to addr ess errors in its unit

- level assumptions and EPA’s recognition that other errors exist (as demonstrated by the fact that theFIP Revisions

- RTC Febru ary 7 , 2012 Page 157

157 Agency is accepting comments identifying additional unit

- level errors). 76 Fed. Reg. 63868. EEI member companies will be submitti ng individually separate comments related to potential errors in unit

- specific modeling assumptions. EEI defers to our members’ expertise in those areas. EEI asks EPA to consider all comments that may be submitted by EEI member companies on unit

- level errors and asks EPA to consider the cumulative impact of any identified errors on state

- level budgets and set

- asides. [Letters: Edison Electric Institute (EPA

- HQ

- OAR

- 2009

- 0491

- 4795) p. 4]
RESPONSE : EPA is finalizing the proposed state budget revisions a nd assurance provision delay. See section IV of the preamble to this final rule. EPA plans to address additional revisions that were brought to EPA’s attention through comments , as specified in 76 FR 63860

. See the Final Revisions Rule State Budgets and New Unit Set

- Asides TSD in the docket of this rulemaking

. (D) EPA is commended for its commitment to implementing the rule by January 1, 2012. Comment (D)(1) : Exelon commends EPA for its commitment to implementing the rule on January 1, 2012. There is no justification for any further delay. The deadlines for states to attain the '97 ozone and PM 2.5 NAAQS have already passed, and states have failed to submit adequate SIPs. The D.C. Circuit in the 2008 North Carolina decision invalidated CAIR because in part its 2015 compliance date was too late to support the Clean Air Act's 2010 attainment dates. Delaying the start of the CSAPR beyond 2012 would be illegal. Using EPA's federal implementation plan authority is not only the right thing to do, it is the only thing to do. [Letters: Exelon Corporation (EPA

- HQ

- OAR

- 2009

- 0491

- 9004) p. 41]
RESPONSE : As the Court directed in the North Carolina decision, EPA has been working to replace the CAIR rule as expeditiously as practicable. It should be noted, howev er, that the U.S. Court of Appeals for the District of Columbia Circuit in EME Homer City Generation, L.P. v. EPA , No. 11

- 1302 and consolidated cases stayed the Transport Rule, but in doing so, stated that EPA “ ... is expected to continue administering the Clean Air Interstate Rule pending the court’s resolution of [challenges to the Transport Rule]. (E) Supports EPA’s decision that there is no need to impose the assurance penalty provisions during the first two years of the program. Comment (E)(1) : EEI gene rally supports EPA’s proposal to amend the effective date of the assurance penalty provisions to make them effective beginning January 1, 2014, instead of January 1, 2012. See 76 Fed. Reg. 63870. Most EEI members believe that an extension of two or more years is appropriate, while there is also limited support for an extension of less than two years. [Letters: Edison Electric Institute (EPA

- HQ

- OAR

- 2009

- 0491

- 4795) p. 2]
RESPONSE : EPA is finalizing the assurance provision delay to 2014. See section IV. C of the preamble to this final rule.FIP Revisions

- RTC Febru ary 7 , 2012 Page 158

158 Comment (E)(2) : KCP&L supports EPA’s proposal to amend the effective date of the assurance provisions under the CSAPR to make them effective beginning January 1, 2014, instead of January 1, 2012. See 76 Fed. Reg. at 63870. Electric generating units regulated under the rule face substantial uncertainty when the first compliance periods begin because, although the rule is “final,” state budgets and unit

- level allocations under the rule remain in flux. Deferring the e ffective date of the assurance provisions until the compliance periods beginning in 2014 will mitigate a significant additional category of uncertainty and provide a measure of badly needed flexibility for regulated entities during the first two compliance periods under this extraordinarily demanding and stringent rule. [Letters: Kansas City Power and Light Company (EPA

- HQ

OAR

- 2009

- 0491

- 4804, 4826) p. 2]
RESPONSE : EPA is finalizing the assurance provision delay to 2014. See section IV of the preamble to this final rule. (F) Supports EPA's incorporation of the emission reduction requirements of existing utility consent decrees. Comment (F)(1) : EPA should finalize revisions of CSAPR unit

- level allocations for the specific units subject to these consent d ecrees. These revisions would not alter the state budgets but would have the effect of increasing the number of allowances within the budget that are available for compliance purposes and that would not otherwise be available without this proposed change to the allocation of allowances. [Letters: Kansas City Power and Light Company (EPA

- HQ

OAR

- 2009

- 0491

- 4804, 4826) p. 3]
RESPONSE : EPA has worked as expeditiously as practicable to finalize the Revisions Rule.FIP Revisions

- RTC Febru ary 7 , 2012 Page 159

159 Issue 5.2: General Opposition to Proposed Rule Revisions
Points Raised: (A) Commenters support certain components of the Proposed Rule, but assert that the revisions are inadequate since they create further uncertainty and do not address concerns related to specific unit corrections, economic impac ts, compliance schedules, and/or electric reliability. Comment (A)(1) : Even with the proposed budget corrections and delay in assurance provisions, the substantial required reductions may be infeasible given the compliance schedule. Despite additional a llowances proposed for the Texas budget and recent SO 2 scrubber start ups, substantial SO 2 reductions will still be needed for the 2012 control period. EPA is publicly claiming that the rule would not be implemented until March 1, 2013, which is misleadin g since it is the allowance transfer deadline for the annual NO X and SO 2 programs. With the 2012 deadline, companies must reduce their SO 2 emissions early enough in the year to avoid running out of allowances mid

- year and being forced to shut down. Compa nies are unlikely to gamble compliance on SO 2 allowances becoming available at the end of the 2012 control period. Also, EPA's intent for delaying the assurance provisions until 2014 is to encourage trading in the initial two years of the CSAPR program bu t Texas is still limited to trading with Group 2 states, which still does not appear to be a viable trading market for SO 2 allowances sufficient to address Texas concerns. Companies will have only a matter of months to achieve the large reductions in SO 2 emissions that EPA is mandating with the CSAPR, which leaves some companies with limited options for compliance. [Letters: Texas Commission on Environmental Quality (EPA

- HQ

- OAR

2009

- 0491

- 4782) p. 2(cvr), p. 5

- 6); Texas Commission on Environmental Qualit y (EPA

- HQ

OAR

- 2009

- 0491

- 9002) p. 18

- 20]
RESPONSE : The compliance schedule has been addressed in the record to this rulemaking (s ee section VII .C of the preamble to the final Transport Rule and the r esponse to c omments for the final Transport Rule in the docket to this rulemaking ) and is outside the scope of revisions proposed and upon which EPA solicited comments . Regarding the development of viable allowance trading markets, see the preamble to this final revisions rule, section IV.C. Regarding the De cember 1 allowance transfer deadline for the ozone season and March 1 allowance transfer deadline for the annual NO X and SO 2 programs, EPA’s intention was to clarify for sources that allowances may still be bought and sold up until December 1 and March 1 f or the ozone

- season and annual trading programs, respectively. Comment (A)(2) : Commenter (PUC

- TX) provides a summary of EPA projections and analysis related to the CSAPR's impact on electric reliability and asserts that there are a number of fundamental flaws, noting that they (and others) have described these flaws in filings with EPA and the D.C. Circuit Court and in meetings with top EPA officials. EPA has failed to address these flaws in its proposed revisions to the rule. Commenter provides signifi cant additional discussion on several specific concerns, including: 1) EPA has underestimated the amount of generation that will be retired or derated as a result of the various rules (and EPA's analysisFIP Revisions

- RTC Febru ary 7 , 2012 Page 160

160 conflicts with studies completed by ERCOT and other s; with the ERCOT study showing that CSAPR will lead to the retirement or derating of 1,200 to 6,000 MW of generation in the ERCOT region); 2) EPA has significantly overstated existing generating capacity in the ERCOT region (i.e., EPA has overstated the a mount of generation available in future years by more than 14 GW by including generating plants that have been retired or mothballed and by failing to adjust wind generation capacity to account for the fact that wind is variable and often does not blow dur ing times of peak energy use; 3) EPA has ignored the effects of local transmission constraints when considering the impact of generating plant retirements on electric reliability; and 4) EPA has underestimated the time needed to plan, permit, and construct the significant amount of new generation and transmission that will be required to compensate for the retirements caused by the various rules. Commenter's letter includes detailed discussion and description of the ERCOT data and analyses; the time neces sary for environmental permitting, planning and construction; local transmission constraints; and the impact of extreme weather on electricity demand. Commenter concludes that EPA should delay the implementation of CSAPR so that all the various problems w ith the rule may be resolved. [Letters: Public Utility Commission of Texas (EPA

- HQ

- OAR

- 2009

- 0491

- 4800) p. 1

- 9]
RESPONSE : See responses to Issue 1.7(D) on Texas Modeling Assumptions and Reliability. Comment (A)(3) : Even with the proposed changes, CSAP R remains seriously flawed and must be further modified to effectuate the intent of the Clean Air Act and protect the ratepayers throughout the proposed CSAPR region. Commenter (Consumers Energy) welcomes EPA’s recognition that the final CSAPR is flawed. EPA’s proposed changes to the CSAPR constitute an appropriate first step toward remedying significant flaws in the rule. But as UARG point out in great detail, more changes are necessary to correct errors in unit

- level assumptions used for modeling the C SAPR. EPA has proposed very modest increases to the allowance budgets for the State of Michigan and has proposed to amend the effective date of the CSAPR assurance provisions to January 1, 2014 instead of January 1, 2012. Neither the increased allocation s nor the amended date for the assurance provisions afford our Company any significant relief. Commenter provides additional discussion, including a description of its Balanced Energy Initiative which considered compliance with CAIR and CAMR. They note t hat in order to have any possibility of achieving compliance by CSAPR’s 2012 compliance dates, the only options are to burn higher blends of western coal and/or reduce operation of the lower cost coal units since they currently have long term contracts in place to purchase eastern coal that will have be modified or broken, which may incur penalties. Operating these units at reduced loads can result in inefficiencies that result in increases of pollutant emissions. Commenter also describes actions required to achieve compliance by the deadline and various impediments, noting that Consumers Energy could not prudently start implementation of a revised spending plan based only on the earlier proposal that evolved into the final CSAPR. EPA should: 1) accept, analyze, and respond to all comments identifying errors in the CSAPR; 2) adjust its modeling to account for those errors; 3) defer the start of the first compliance periods until the state budgets and unit

level allocations have been revised and put in fin al form; and 4) promptly make final its proposal to defer the effective date of the assurance provisions under the CSAPR until 2014. [Letters: Consumers Energy (EPA

- HQ

- OAR

- 2009

- 0491

- 4808) p. 2

- 7]FIP Revisions

- RTC Febru ary 7 , 2012 Page 161

161 RESPONSE : See the preamble to the final revisions rule an d the TSD called “Final Revisions Rule State Budgets and Ne w Unit Set

- Asides” in the docket to this rulemaking regarding revisions and assurance provisions. Discussions of EPA’s modeling are found in the preamble to the proposed and final Transport Rule i n the docket to this rulemaking and are outside the scope of the revisions proposed and upon which EPA solicited comment

. Comment (A)(4) : EPA's proposal as a whole is part of an inadequate piecemeal approach, is far too limited, and does not include the necessary technical corrections for certain units. EPA’s proposed decision to provide additional emission allowances to certain states in response to incorrect or incomplete data is a step in the right direction toward correcting the flaws embedded in the final Cross

- State rule. The proposal, however, is far too limited and does not include any technical corrections for Southern Company’s units. It is obvious that additional changes will be necessary before this rule can be properly implemented, yet sour ces will not know the final changes until very near or after the compliance date. This is untenable. Instead of once again updating the rule in a piecemeal approach, EPA should reconsider the rule in its entirety, allowing the public an opportunity to co mment on all the corrections, and not make changes in isolation. [Letters: Southern Company (EPA

- HQ

- OAR

- 2009

- 0491

- 4744) p. 2]
RESPONSE : This comment is outside the scope of the revisions proposed and upon which EPA solicited comment (76 FR 63860). EPA will respond to requests for reconsideration separately from this action. Comment (A)(5) : If the emissions budgets for Texas set out for the first time in the final CSAPR (budgets that EPA now concedes in the Proposed Revision are based on erroneous ass umptions) go into effect as scheduled on January 1, 2012, Luminant will idle two generating plants on January 1, 2012, and ultimately need to close three lignite mines, resulting in the loss of hundreds of jobs and severe harm to the rural communities that depend on those operations. Luminant must also spend hundreds of millions of dollars (an expense that it cannot pass along to ratepayers) to comply with the flawed emissions budgets adopted in the CSAPR. The Proposed Revision, if expeditiously finalized and implemented prior to the January 1, 2012 compliance start date, might reduce some of these adverse effects on Luminant’s operations, but it would not eliminate the irreparable harm Luminant will suffer. In order to fully address the harm to Luminant and other Texas stakeholders from EPA’s errors in assumptions, data, and methodologies, EPA must immediately stay the final CSAPR as it applies to Texas and correct the fundamental errors and flaws that led to Texas’s inclusion in the annual programs, as f ully set out in Luminant’s reconsideration request (which commenter (Luminant) discusses further in Section III of their comment letter). If EPA follows through on its proposal to ignore Luminant’s reconsideration request, and refuses to reconsider the fu ndamental flaws in EPA’s CSAPR methodology, EPA should, at a minimum, make additional revisions to the Texas emissions budgets to account for additional unit

- level errors that EPA has not addressed in the Proposed Revision and make those adjustments effect ive immediately. [Letters: Luminant (EPA

- HQ

- OAR

- 2009

- 0491

- 4818) p. 8

- 9]
RESPONSE : EPA will respond to requests for reconsideration separately from this action.FIP Revisions

- RTC Febru ary 7 , 2012 Page 162

162 (B) The proposed revisions adjust the budgets even higher than those established in the final Transport Rule, which were already too high. Comment (B)(1) : EPA is now adjusting the NO X budgets even higher than those set in the final Transport Rule, which commenter (MDE) believes are already too high. Understanding that corrections may be justifie d, Maryland continues to be overcome by transported air pollution. In addition, EPA stated in the proposed Technical Revisions that it is "...seeking that all relevant information that may support similar revisions be submitted in full by the comment dead line on this rulemaking, such that the Agency may consider whether a subsequent and timely rulemaking should address any further revisions to the final Transport Rule state budgets." As EPA receives and accepts comments suggesting technical revisions to t he NO X and SO 2 caps, Maryland continues to be negatively affected by transported air pollution. Commenter emphasizes the importance of EPA analyzing the results of any and all future technical revisions and adjustments that it may wish to make as a result of information submitted during the comment period for this proposed rule

-- prior to finalizing such revisions. This is necessary to ensure that the final state budgets eliminate significant contribution to nonattainment areas and interference with mainte nance areas. [Letters: Maryland Department of Environment (EPA

- HQ

- OAR

- 2009

- 0491

- 4812) p. 2]
RESPONSE : As described in the Preamble to the final Transport Rule (76 FR 48208), states included in the program are eliminating their significant contribution and interference with maintenance with other states (also see pages 48210 and 48256 in the Transport Rule preamble for additional information about selected states and the 1997 ozone NAAQS). In the proposed revisions rule, EPA has estimated the air qual ity impacts of the SO 2 emission changes (see the Significant Contribution Assessment Technical Support Document, EPA

- HQ

- OAR

- 2009

- 0491

- 4690, for details). EPA also assessed the proposed annual and ozone

- season NO X emission changes, noting that the changes are only a small proportion of each state’s total emissions. In the final rule, EPA has similarly assessed the finalized emission changes (see the Final Revisions Rule Significant Contribution Assessment TSD for details), finding that for SO 2 , the changes in the budgets and the resulting estimated air quality impacts would not substantially affect the air quality portion of the multifactor test, and would not affect EPA’s conclusions from the final Transport Rule identifying $500/ton and $2,300/ton as the appropriate SO 2 cost thresholds for “Group 2 ” and “Group 1 ” states , respectively . Furthermore, for the annual and ozone

- season NO X budget revisions, EPA again notes that the changes are only a small proportion of each state’s total emissions.FIP Revisions

- RTC Febru ary 7 , 2012 Page 163

163 Issue 5.3: Miscellaneous Issues
Points Raised: (A) Commenter appreciates EPA's efforts to improve the CSAPR, but notes that the Agency's inaction on implementation guidance could hinder the effectiveness of the rule. Comment (A)(1) : SC DHEC and other state and loc al permitting agencies have been requesting guidance from EPA on how to address the non

- electricity generating units subject to the NO X SIP Call, EGU permit conditions, and state implementation plans. EPA has not provided this guidance, and commenter note s that they are making decisions now on the applicable permits. [Letters: South Carolina DHEC (EPA

- HQ

- OAR

- 2009

- 0491

- 4742) p. 2

- 3]
RESPONSE : EPA is working closely with states on implementation of the rule and has provided guidance and questions and a nswers on our web site, as well as model rules for SIP development to the Regions. See the following web page: http://www.epa.gov/crossstaterule/faqs.html. (B) In its proposed revisions, EPA seriously misrepresents the Cross
- State Rule’s compliance dates. Comment (C)(1) : Perhaps aware of the effect its errors will have on compliance with the Cross

State Rule, EPA in the Proposed Revisions seriously misrepresents the rule’s compliance dates. EPA asserts in the preamble to the Proposed Revisions that the “f irst compliance deadlines” under the Cross

- State Rule are not January 2012 and May 2012, but are actually the first allowance accounting (or “true

- up”) dates for the allowance trading programs, i.e., December 1, 2012, for the 2012 ozone

- season NO X program , and March 1, 2013, for the 2012 annual NO X and SO 2 programs. (76 FR 63870

- 63872). This revisionist characterization of the rule’s compliance deadlines is plainly incorrect and is expressly contradicted by the description EPA gave of the compliance dead lines when it promulgated the final rule (see 76 FR 48277). [Letters: Utility Air Regulatory Group (EPA

- HQ

- OAR

- 2009

- 0491

- 4823) p. 9

- 10]
RESPONSE : EPA’s intention was to clarify for sources that allowances may still be bought and sold up until December 1 and March 1 for the ozone

- season and annual trading programs, respectively. Issue 5.4: Out of Scope Issues
Points Raised: (A) EPA should stay or withdraw the Transport Rule to ensure that it is technically sound, meets the requirements of the CAA, and allows adequate time for public comment on all substantive changes to the rule.FIP Revisions

- RTC Febru ary 7 , 2012 Page 164

164 Comment (A)(1) : EPA identified 15 coal

- fired units in Nebraska as being subject to the TR. EPA had errors on the identification of existing post

- combustion controls on four of these 15 units. This means that EPA had significant technical errors on more than 25 percent of the coal

fired units in Nebraska. As such, the entire basis for the TR is in question with the likelihood that there are numerous errors throughout EPA's d ata gathering, analysis, and modeling efforts that went into development of this rule. EPA should stay or withdraw the TR in order to review and correct the data and methodology used to develop the rule to ensure that it is technically sound. [Letters: Omaha Public Power District (EPA

- HQ

- OAR

- 2009

- 0491

- 4747) p. 4, 6]
RESPONSE : EPA is increasing the Nebraska budgets. See the preamble for the final Revisions Rule regarding corrections to Nebraska’s budget as well as the Final Revisions Rule State Budge ts and New Unit Set

- Asides TSD in the docket to this rulemaking. The methodology EPA used to develop the Transport Rule is outside the scope of revisions proposed and upon which EPA solicited comment (76 FR 63860)

. Comment (A)(2) : The changes made to the final Transport Rule were significant as compared to what was put forth in the proposed rule. While EPA claims that stakeholders should have deduced that state budgets would decrease significantly, there is no justification for these claims. The last NOD A that EPA released prior to issuance of the final rule was on January 7, 2011, which provided information on two alternate allowance allocation methods and provided the unit

- level allowance allocations under those methods. The total Nebraska allowance al locations that EPA provided under those methods were the same as what was identified in the original TR proposal from July 2010. Commenter provides additional discussion, noting that with major changes made at the last minute, EPA should delay implementat ion of the rule for at least two years to allow sufficient time for implementation and to avoid economic hardship and disruption to the nation's power supply. [Letters: Omaha Public Power District (EPA

- HQ

- OAR

- 2009

- 0491

- 4747) p. 4, 6]
RESPONSE : These i ssues

— public comment opportunity and power supply disruptions

— have already been addressed in the final Transport Rule record and are outside the scope of th e revisions proposed and upon which EPA solicited comment

. Comment (A)(3) : EPA has assumed tha t most coal

- fired units without SO 2 emission controls in the western portion of the TR states will switch to use of the lowest sulfur coal in the PRB area. EPA's spreadsheet titled "WebReady_ParsedFile_TR_Remedy_Final_2012.xlsx" indicates that 147 units ( in IL, IN, IA, KS, MI, MO, NE, OH, TN, TX, and WI) have an assumed SO 2 emission rate in this range. EPA should conduct an analysis demonstrating that the PRB mines can supply this type of coal to all of these units. If insufficient supply is an issue, th en state budgets will likely need to be adjusted to reflect this reality. If this type of study cannot be conducted, then EPA should increase the Nebraska state SO 2 budget to reflect use of a more reasonable mix of low sulfur PRB coal. [Letters: Omaha P ublic Power District (EPA

- HQ

- OAR

- 2009

- 0491

- 4747) p. 5

- 6]FIP Revisions

- RTC Febru ary 7 , 2012 Page 165

165 RESPONSE : IPM modeling has already been addressed in the Transport Rule record and is outside the scope of the revisions proposed and upon which EPA solicited comment. Comment (A)(4) : Nebraska was not subject to CAIR and there was no prior impetus for Nebraska utilities to consider significant expenditures and unit modifications to comply with the TR. With the major changes to the final TR, there is simply not enough time for Nebraska utilities to respond to the rule in the most cost

- effective manner for their rate

- payers. While EPA gave states at least 3.5 years to comply with CAIR, Nebraska is given less than six months to comply with the TR. As such, the compliance year should be revised to 20 14. [Letters: Omaha Public Power District (EPA

- HQ

- OAR

- 2009

- 0491

- 4747) p. 5

- 6]
RESPONSE : Compliance deadlines have already been addressed in the final Transport Rule record and are outside the scope of the revisions proposed and upon which EPA solicited comment

. Comment (A)(5) : Commenter (Southern Co.) strongly supports EPA’s proposal to delay the implementation of the rule’s assurance provisions, but questions the need to start the rule in 2012 at all. The Clean Air Interstate Rule (CAIR) remains in place and is achieving real, tangible air quality improvements, including air quality that already attains the targeted ozone and PM

- 2.5 air quality standards at all of the ozone and PM2.5 air quality monitors that Alabama, Florida, Georgia, and Mississipp i were purportedly affecting and that brought them under the rule in the first place. The rush to implement the program in 2012 is perplexing given that many of the benefits projected by EPA’s “remedy case” to occur in 2014 appear to have already been ach ieved under CAIR. Commenter refers to their "Petition for Reconsideration and Stay" at 32

- 40 (which they provide as Exhibit A). EPA should leave CAIR in place while it takes the time to revise this rule, and if the Agency does not stay the rule, then it should postpone the effectiveness of the rule's assurance provisions and revise the relevant state budgets and unit level allocations based on the errors and flawed assumptions summarized by Southern Company and others. [See related discussion under Issue s 2.10 and 5.1.] [Letters: Southern Company (EPA

- HQ

- OAR

- 2009

- 0491

- 4744) p. 2

- 3, 13]
RESPONSE : Compliance deadlines have already been addressed in the final Transport Rule record and are outside the scope of the revisions proposed and upon which EPA so licited comment

. Petitions for reconsideration will be addressed separately from this rulemaking. Comment (A)(6) : Commenter (SPS) notes that the 2012 compliance date does not provide them with an opportunity to install the extensive suite of emission co ntrols necessary to reduce emissions to the level of allowance allocation provided to them. Moreover, the 2012 compliance date leaves little time for a liquid allowance market to develop. As a result, they have no choice but to prepare a "system flip" op erating plan. Under such a plan, SPS would dramatically reduce the operation of its base load coal plants and commit to running its aging peaking and intermediate gas plants around the clock. This approach exposes SPS’s customers to a substantially incre ased risk of electric system reliability problems and an enormous increase in customer energy costs. Commenter provides additional discussion and cites to their comments previously submitted in SPS' Initial and Supplemental Petitions for Reconsideration a nd RequestFIP Revisions

- RTC Febru ary 7 , 2012 Page 166

166 for Stay of the CSAPR. [Letters: Southwestern Public Service Company (SPS) (EPA

- HQ

- OAR

2009

- 0491

- 4752) p. 2] RESPONSE : EPA has made revisions in response to this comment. See the preamble for the final Revisions Rule regarding corrections to Nebraska’s budget as well as the Final Revisions Rule State Budgets and New Unit Set

- Asides TSD in the docket to this rulemaking. Comment (A)(7) : The small number of errors identified in the Proposal with respect to Texas resulted in massive adjustment s to the Texas annual SO 2 budget, as well as smaller adjustments to the state’s annual and ozone

- season NO X budgets. Similarly significant errors were identified in other states. The errors in Texas’s emissions budget related to two factors. First, in C SAPR, EPA inaccurately characterized the existing pollution control equipment installed on certain Texas plants. Relying on information it gleaned only from a review of public databases and trade publications, EPA made several bad assumptions regarding th e emission control configuration and operation of several large Texas plants (76 FR 63864). These errors alone resulted in Texas receiving approximately 70,000 fewer SO 2 allowances than was appropriate under EPA’s allocation methodology. [See related dis cussion in Section 2.7.] [Letters: Southwestern Public Service Company (SPS) (EPA

- HQ

- OAR

- 2009

- 0491

- 4752) p. 3]
RESPONSE : EPA has made revisions in response to this comment. See the preamble for the final Revisions Rule regarding corrections to Nebrask a’s budget as well as the Final Revisions Rule State Budgets and New Unit Set

- Asides TSD in the docket to this rulemaking. Comment (A)(8) : EPA failed to assure that IPM properly accounted for "out

- of

- merit

- order dispatch areas." In out

- of

- merit

- order di spatch areas, units "are frequently dispatched out of regional economic order as a result of short

- run limitations on the ability to meet local electricity demand with generation from outside the area." (76 FR 63867). The Proposal recognizes that CSAPR f ailed to properly account for out

- of

- merit

- order dispatch areas and addresses some of these errors by proposing to increase Texas’s annual and ozone

- season NO X budgets by 1,375 tons each. This error demonstrates the inability of IPM to properly model the electric power system. Commenter provides additional discussion and notes that they highlighted and described this flaw in detail their petitions for reconsideration. [Letters: Southwestern Public Service Company (SPS) (EPA

- HQ

- OAR

- 2009

- 0491

- 4752) p. 3

- 4 ]
RESPONSE : Comments on IPM are outside the scope of the revisions proposed and upon which EPA solicited comment

. Information on the use of IPM to inform the Transport Rule, including previous notice and comment, is available in the final Transport Rule docket. EPA is finalizing revisions relevant to out

- of

- merit

- order dispatch in Texas . See also the Final Revisions Rule State Budgets and New Unit Set

- Asides TSD. Comment (A)(9) : IPM fails to consider "must

- run" units that must operate for reliability or voltage support reasons, and there are significant flaws in the IPM modeling as it relates to transmission: (1) its failure to use current transmission flow information; (2) its failure to incorporate the impacts on transfer capability arising from re duced fossil generation under CSAPR; and (3) its assumption that utilities such as SPS can access any available generationFIP Revisions

- RTC Febru ary 7 , 2012 Page 167

167 within their region without any transmission constraints and t hat any power imported into the region can freely flow where it is need ed. Commenter notes that they described these issues in detail in their petitions (attached to their comment as Exhibit B at 14

- 16) and asserts that EPA’s Proposal does not address these problems. [Letters: Southwestern Public Service Company (SPS) (EPA

- HQ

- OAR

- 2009

- 0491

- 4752) p. 4]
RESPONSE : EPA has included revisions to state budgets related to the technical information this commenter submitted regarding immediate

- term out

- of

- merit

- order dispatch at certain units in Texas

. See the Final Revisions Rul e State Budgets and New Unit Set

- Asides TSD in the docket for this rulemaking. Comment (A)(10) : EPA's across the board "rush to judgment" in not just the final Transport Rule but many other rulemakings is causing it to make scientific and technical error s. Many of EPA's now admitted errors deal in an area in which many observers have already noted it has very little expertise and has done too little analysis or consultation with experts regarding electricity market dispatch/local grid security issues. F or example, EPA now realizes that it missed "out

- of

- merit" dispatch situations in New Jersey, New York's Long Island, Louisiana and Texas, as well as missing New York Independent System Operator N

- I

- I Contingency arid Minimum Oil Burn Rules issues. EPA ev en missed the fact that a nuclear power plant in Florida was scheduled to be off

- line for a year. Commenter provides additional discussion and examples of errors in this and other rules and expresses serious concern about the technical framework of the fi nal Transport Rule that now requires a last

- minute rulemaking to correct serious technical errors discovered only after the promulgation of the final rule. [Letters: Pennsylvania Department of Environmental Protection (EPA

- HQ

- OAR

- 2009

- 0491

- 4773) p. 1

- 2]
RESPONSE : See the preamble to the final Revisions Rule and the Final Revisions Rule State Budgets and New Unit Set

- Asides TSD in the docket to this rulemaking. Comment (A)(11) : Sources in Pennsylvania currently operate under Pennsylvania's Clean Air In terstate Rule (CAIR) SIP, and as such, there was no urgency for EPA to impose Transport Rule FIPS for 2012 and 2013, as those FIPS may achieve little more than the current CAIR SIPs in terms of emission reductions. EPA could have left CAIR in place until 2014, when state budgets are set to decrease under the Transport Rule. This would have given states time to develop and submit SIP revisions and thereby retain control over sources within their borders. [Letters: Pennsylvania Department of Environmental Protection (EPA

- HQ

- OAR

- 2009

- 0491

- 4773) p. 4]
RESPONSE : This comment is outside the scope of the revisions proposed and upon which EPA solicited comment. However, EPA’s authority for the Transport Rule FIPs and the timing of the rule have been discussed in the proposal and final Transport Rule and the final Transport Rule response to comments document in the docket to this rulemaking. It should be noted, however, that the U.S. Court of Appeals for the District of Columbia Circuit in EME Homer City Gener ation, L.P. v. EPA , No. 11

- 1302 and consolidated cases stayed the Transport Rule, but in doing so, stated that EPA “ ... is expected to continue administering the Clean Air Interstate Rule pending the court’s resolution of [challenges to the Transport Rule].FIP Revisions

- RTC Febru ary 7 , 2012 Page 168

168 Comment (A)(12) : The proposed changes will not be sufficient to remedy all of the potential technical problems raised regarding the final Transport Rule. EPA's lack of transparency in the final rule development has contributed to these concerns as af fected sources were not provided opportunity to provide informed comment given the numerous datasets and alternative regulatory approaches proposed in this docket. Therefore, it was not possible to anticipate the application of data provided to the EPA, a s the relevance of such information was not apparent until the final rule was promulgated. This request was made by Alliant Energy as well as numerous other parties as part of the original comments filed for this docket. It is not too late to allow for p ublic comment on the methodologies and allocation approaches. While Alliant Energy is committed to complying with the Transport Rule, it believes the rule flaws must be addressed. EPA should reconsider the rule, and revise the effective date and allow th e CAIR program to proceed for the 2012 calendar year. This approach is preferred over further legal challenges and is responsive to the numerous petitions for reconsideration. Furthermore, EPA should provide complete datasets that are self

- explanatory or provide workshops or webinars that explain the underlying application of the data in the complex models used for this rule. For example modeling assumptions for fuel switching are not apparent in the rule documentation. Similarly clarification is needed on EPA['s application of existing as well as future air pollution controls modeled to demonstrate achievable emissions reductions without retirements or re

- dispatch. EPA has modeled a theoretical solution, but has not sufficiently demonstrated that this solution can be implemented without risks to reliability or whether there is sufficient transmission support. [Letters: Alliant Energy (EPA

- HQ

- OAR

- 2009

- 0491

- 4762) p. 2

- 3]
RESPONSE : This comment is outside the scope of the revisions proposed and upon wh ich EPA solicited comment. However, EPA’s data, approach, methodology, and models have all be addressed in the proposal and final Transport Rule and the final Transport Rule response to comments document in the docket to this rulemaking. Comment (A)(13) : The implementation of the CSAPR will cause irreparable harm to Texas businesses and consumers by reducing overall energy production and crippling the operations of rural electric cooperatives and mining facilities, which are major employers in rural Texa s. CSAPR will also decrease electricity reliability, which could negatively impact businesses and consumers at a time when they desperately need stability for jobs and economic growth. Commenter makes the following assertions (but does not provide any ad ditional discussion on these issues): Texas should not be included in the program; faulty monitoring by EPA arbitrarily places unfair and unachievable emission reductions on the state; program implementation deadlines are inconsistent and unreasonable; an d thorough economic impact analyses should be conducted before the rule is implemented. [Letters: Texas Department of Agriculture (EPA

HQ

- OAR

- 2009

- 0491

- 4819) p. 1]
RESPONSE : See responses to Issue 1.7(D) on Texas Modeling Assumptions and Reliability.FIP Revisions

- RTC Febru ary 7 , 2012 Page 169

169 Comment (A)(14) : The Gulf Coast Lignite Coalition states that EPA has failed to address the majority of concerns of its members voiced in comments on the August 2011 rule. The revision does not serve as a replacement to a stay or delay of the rule. In o rder to address root causes of the rule errors, primarily late inclusion of Texas in the annual programs and the methodology for Texas' inclusion a stay period and detailed review is required. The revised CSAPR still poses a significant threat to coal

- fir ed generation in Texas and other states. The commenter goes on to note errors and concerns identified in their Petition for Reconsideration which they also attached. [Letters: Gulf Coast Lignite Coalition (EPA

- HQ

- OAR

- 2009

- 0491

- 4805) p. 1

- 2]
RESPONSE : This comment is outside the scope of the revisions proposed and upon which EPA solicited comment. EPA will address petitions for reconsideration separately from this action.

(B) EPA should provide the regulated community sufficient detail and opportunit y to comment on the IPM and its application to ensure that the model is appropriate and that it is appropriately applied. Comment (B)(1) : EPA’s unprecedented use of the proprietary Integrated Planning Model (“IPM”) to model every significant source in th e country produces results that appear to inappropriately reward some sources with allowances over others, and the results cannot be independently substantiated or verified. Use of a proprietary model is not appropriate for this purpose as it deprives the public and regulated community of the opportunity to independently evaluate the inner workings of the model and ensure that it is accurate, precise and robust enough to perform this enormous task. Likewise, the public and regulated community cannot tell whether the questionable IPM output is the result of an error in a modeling assumptions or algorithm, or if the model itself inappropriately amplifies irregularities in the input database, as previously mentioned. Publishing the NODA I, NODA II, NODA III and now the Notice of Proposed Rulemaking (NPRM), to correct the model inputs, compounds the confusion in understanding all aspects of the IPM model outputs. [Letters: First Energy Corporation (EPA

HQ

- OAR

- 2009

- 0491

- 4741) p. 2]
RESPONSE : This comment i s outside the scope of the revisions proposed and upon which EPA solicited comment. However, information on the use of IPM to inform the Transport Rule, including previous notice and comment, has been discussed in the proposal and final Transport Rule and the final Transport Rule response to comments document i n the docket to this rulemaking. The commenter’s assertion that EPA’s use of IPM “inappropriately reward[s] some sources with allowances over others” is incorrect; as explained in the final Transpor t Rule, EPA based unit

- level allowance allocations on historic heat input and emissions data, not on IPM unit

level modeling projections. (C) EPA has not provided adequate notice or meaningful opportunity to comment on Texas' inclusion in CSAPR, and there are still numerous errors and problems with EPA's proposed rule that need to be addressed.FIP Revisions

- RTC Febru ary 7 , 2012 Page 170

170 Comment (C)(1) : There has been a lack of adequate notice or meaningful opportunity to comment on Texas' inclusion in CSAPR and there was no significant linkage by Texas for PM 2.5 to any monitor of the rule proposal. Yet a significant Texas linkage was made for PM 2.5 to the Granite City, Illinois monitor in the final rule. At proposal, EPA only sought comment on a hypothetical scenario involving increased SO 2 e missions due to Texas switching to higher sulfur coals, not an actual linkage by Texas to a specific monitor. While Texas did point out some flaws in EPA's IPM data in comments on the original proposal, it is EPA's own mistakes and incorrect assumptions t hat caused the errors in EPA's SO 2 emission rates from electric generating units in Texas. Commenters provides significant additional discussion and assert that the adjusted emissions do not justify inclusion of Texas in the rule for PM 2.5 since the stat e's emissions have not been shown to contribute significantly to non

- attainment in or interference with maintenance by any other state. EPA made numerous revisions to the emissions inventories and modeling during the original CSAPR rulemaking, which were not clearly explained in the final rule preamble or technical support documents. One commenter (TCEQ) notes that Texas has still not been able to confirm that EPA has made the requested corrections to the state's point source NO X emissions based on the fe derally enforceable control measures that are a part of the state implementation plan, which is crucial to recognize emission reduction efforts in Texas, and base any modeling and linkage decisions on accurate emissions. This commenter also asserts that t he EPA has failed to adequately assess the full economic impacts of CSAPR on Texas and that implementation of the rule puts at risk the reliability of the electric grid and the economic future of power generation and those dependent on affordable and relia ble electricity. The additional allowances that EPA is proposing to add to the Texas budget for SO 2 are not sufficient to address the short term impacts to reliability. In a subsequent letter, this commenter notes that the North American Electric Reliabi lity Corporation (NERC) issued its 2011 Long

- Term Reliability Assessment report on November 28, 2011 and that the report encompasses an evaluation of CSAPR which reinforces TCEQ comments on both the current proposal and on the original CSAPR rulemaking (pa rticularly their conclusion that EPA has not properly evaluated the impacts of CSAPR and other EPA regulations on the Texas electrical power system and has not provided adequate implementation time). Commenter provides the relevant excerpts of the NERC re port as an attachment to their letter. Another commenter (Luminant) cites to the revisions in allocations to their units as well as to their previous comments (including their petition for reconsideration submitted on August 5, 2011). EPA's proposed rev isions only partially address some of the errors raised in Luminant's request and otherwise proposes to ignore most of the errors and all of the fundamental flaws that Luminant identified in the final CSAPR. [Letters: Luminant (EPA

- HQ

- OAR

- 2009

- 0491

- 4818) p. 4

- 8; Texas Commission on Environmental Quality (EPA

- HQ

- OAR

- 2009

- 0491

- 4782) p. 1(cvr), p. 1

- 2, 8; Texas Commission on Environmental Quality (EPA

- HQ

- OAR

- 2009

- 0491

- 9002) p. 20

- 22]
RESPONSE : See responses to Issue 1.7(D) on Texas Modeling Assumptions and Reliability. Comment (C)(2) : San Miguel explains in detail in its Petition for Reconsideration the numerous issues in the finalized CSAPR. The vast majority of these issues remain after this revision. First, issuing a limited revision of the rule does not resolve the serious notice issue resulting from Texas’ inclusion in the annual SO 2 and NO X programs in the final rulemaking. EPA hasFIP Revisions

- RTC Febru ary 7 , 2012 Page 171

171 provided no additional time to address the procedural notice issue or the significant substantive issues in the rule, choosing instead to maintain the January 1, 2012 compliance date. This is despite the fact that the extremely short compliance period is not mandated by U.S. Court of Appeals for the D.C. Circuit’s decision in North Carolina v. EPA1 and despite evidence demonstrating that the short compliance period could result in serious harm to electric reliability and significant increases to electricity cost. [Letters: San Miguel Electric Cooperative (EPA

HQ

- OAR

- 2009

- 0491

- 4766) p. 1

- 2]
RESPONSE : This comment is o utside the scope of the revisions proposed and upon which EPA solicited comment. However, EPA has addressed compliance and timing issues in the proposal and final Transport Rule and final Transport Rule response to comments document in the docket tot his rulemaking. EPA will address petitions for reconsideration separately from this action. Comment (C)(3) : The EPA’s reliability assessment of the CSAPR is flawed for multiple reasons; however, the fundamental reasons are the EPA’s over

- reliance on IPM and attempting to evaluate electrical system reliability from a broad macro

- scale approach. The EPA does not have the necessary tools and expertise to properly evaluate the impact of its actions on electrical system reliability. The same mistakes were made in the EPA’s reliability assessment of the recent Utility National Emission Standards for Hazardous Air Pollutants rulemaking proposal. Local public utility commissions and system operators have much more detailed information and experience regarding the loc al issues and challenges within the local system and the EPA should be taking advantage of their expertise. Provisions are needed in the rules to provide a safety mechanism to help ensure that electrical system reliability is not endangered by the CSAPR. For example, an emergency pool of allowances surplus to the state budget could be provided to the local system operator organization to help address emergencies such as those experienced by ERCOT during summer 2011. Emergency allowances would be restricted to use only on an emergency basis if electrical system reliability is in jeopardy as determined by the system operator and only by the specific EGU within that state that the system operator determines needs the allowances.. [Letters: Texas Commission o n Environmental Quality (EPA

- HQ

- OAR

2009

- 0491

- 4782) p. 8]
RESPONSE : This comment is outside the scope of the revisions proposed and upon which EPA solicited comment. However, information on the use of IPM to inform the Transport Rule, including previou s notice and comment, has been discussed in the proposal and final Transport Rule and the final Transport Rule response to comments document in the docket to this rulemaking. (D) Final SO 2 and NO X budgets are significantly less than proposed and EPA has not provided the basis for the reduction, opportunity to comment, or time to install control equipment to meet reduced allocations. Comment (D)(1) : In EPA 's proposed SO 2 allocation published in September 2010, the drop from 2012 to 2014 allocation for I llinois was 27%, which is close to the drop required by CAIR. However, the 2014 final transport allocation for Illinois dropped by 47% from the 2012FIP Revisions

- RTC Febru ary 7 , 2012 Page 172

172 allocation. This additional 20% drop is an unreasonably large drop in allocations with compliance require d in a very short time period. EPA provided no explanation for the significant change between the proposed and final allocations, and also did not allow public comments on the new allocation. The Transport Rule was finalized on August 8, 2011. This leav es less than two and one half years to design and build a scrubber to meet the 2014 compliance date. EEI believes the timeline to design, bid, permit, build, and start up a scrubber to be much longer than this. Financing in today's environment will also be difficult. EPA should delay implementation of the Transport rule until clear peer reviewed explanations are made on how state and unit allocations were determined, and affected sources are given opportunity to provide comments. [Letters: Electric Ene rgy, Inc. (EEI) (EPA

- HQ

- OAR

- 2009

- 0491

- 4748) p. 1

- 2] Comment D(2) : In EPA's proposed Transport Rule, Illinois was allocated 54,359 annual NO X allowances and 22,863 ozone seasons NO X allowances. In the Final Transport Rule, Illinois was only allocated 44 ,042 annual and 19,511 ozone season NO X allowances. This is a drop of 19% for the annual NO X allocation, and 15% for ozone season allocation between the proposed and final rule. EEI had similar reductions on our unit allocations.
EEI had assumed that th ey would receive allowances very close to our ozone and annual NO X emissions. Because of the short implementation due date (January 1, 2012), EEI is unable to evaluate, design, build, permit, and start up any pollution control device and will be required to purchase a significant amount of allowances to cover emissions. EPA provided no explanation for the significant change in proposed and final Illinois allocations, and did not allow public comment. EPA should delay implementation of the Transport rule until clear peer reviewed explanations are made on how state and unit allocations were determined, and affected sources given the opportunity to provide comments. [Letters: Electric Energy, Inc. (EEI) (EPA

- HQ

OAR

- 2009

- 0491

- 4748) p. 2

- 3] Comment (D)(3) : While EPA has increased some state allocations based on discovered technical errors, and EPA is accepting comment on these changes, it has not explained why emissions from the original proposed CSAPR are significantly different in the final rule. For ex ample 2012

- 2013 annual NO X emissions from both Missouri and Illinois dropped 9.2% (15.5% 2014) and 14.6% respectively from the proposal to final rule. EPA has made major changes to the state level allocations and has not given proper notice and opportunit y to comment. EPA needs to supply supporting information for these adjustments between the proposed and final CSAPR and allow for proper notice and comment. [Letters: Ameren (EPA

- HQ

- OAR

- 2009

- 0491

- 4802) p. 2] Comment (D)(4) : Commenter is unable to recr eate or understand the allocation assumptions that led EPA to drastically reduce Hoosier's Ratts allocations. Allocations are 23% below the lowest allocations previously proposed for 2012 and 11% below the lowest proposed for 2014. There is no clear expl anation in EPA's TSDs or spreadsheets. Specifically the 0.30 lb/mmBtu SO 2FIP Revisions

- RTC Febru ary 7 , 2012 Page 173

173 emission rate must assume fuel switching or pollution control not required by the NSR consent decree, existing permits, or any new rule. [Letters: Hoosier Electric Cooperative (EP A

- HQ

OAR

- 2009

- 0491

- 4785) p. 4]
RESPONSE : These comments are outside the scope of the revisions proposed and upon which EPA solicited comment . However, EPA notes that some of the above commenters are confusing budgets with existing unit allocations. I n some cases the budgets were not reduced by the magnitude suggested by commenter, rather the n ew u nit s et

- a side increased for the state meaning that fewer of the total allowance s were allocated to existing units and more were held for new units. In regard s to the broader claim about adequate notice and a state's ability to comply with budgets that are smaller in the final rule than proposed, commenters should see the Declaration of Sam Napolitano, dated December 1, 2011, filed in support of EPA's Consolida ted Opposition, EME Homer City Generation v. US EPA, and consolidated cases No. 11

- 1302 (D.C. Cir.) and Section I.C of the EPA Consolidated Opposition to Remaining Motions for Stay Pending Judicial Re view of EPA's Transport Rule, filed in EME Homer City Ge neration v. US EPA, and consolidated cases , No. 11

- 1302 (D.C. Cir.) which can be found in the docket for this rulemaking , which states the following: "Many of the stay motions assert that EPA failed to give adequate notice of the emission budgets in the f inal rule because those budgets changed from the proposal. As we have explained in our responses to other stay motions, EPA provided adequate notice because it identified in the proposal the methodology it would use to establish the budgets and provided o pportunities to comment on the changes to the model and data being used. See, e.g., EPA Opp. to NE Mot.,document 1335231, at 7

- 9. The changes in budgets from the proposal to the final rule are in large part the result of information provided in comments, and thus the final rule is a logical outgrowth of the proposal. As this Court has held, a final rule may permissibly differ from the proposal if it is a “logical outgrowth” of the proposal “where the agency gave adequate notice of the procedures it inten ded to use, the criteria by which it intended to select data, and the range of alternative sources of data it was considering.” Am. Coke & Coal Chems.Inst. v. EPA, 452 F.3d 930, 939 (D.C. Cir. 2006). The budgets under the rule represent each State’s emiss ions in an average year after implementation of reductions needed to eliminate emissions that significantly contribute to nonattainment or interfere with maintenance in other States. 76 Fed. Reg. at 48,260. To identify the necessary reductions, EPA used an air

- quality

- based analysis to identify appropriate cost thresholds and the Integrated Planning Model (“IPM”) to predict NOx and SO2 emissions from electric generating units in each State after implementing controls at those cost thresholds. 76 Fed. Reg. at 48,255

- 61. The change in the budgets between the proposed and final rules is due primarily to modifications EPA made to the IPM to make it more accurate, including addressing public input suggesting that certain IPM updates were needed. Id. at 48,260

. EPA provided an opportunity to comment on the revisions to the model through a Notice of Data Availability (“NODA”) that stated that EPA had made changes in the IPM, that detailed documentation of the changes was available in the docket (and on

- line), a nd that requestedFIP Revisions

- RTC Febru ary 7 , 2012 Page 174

174 comment on the changes. 75 Fed. Reg.53,613, 53,614 (Sept. 1, 2010). The NODA also stated that updated information concerning the generating units included in the IPM was available for comment in the docket, and that, in running the IPM, EPA would use data from 2009, rather than the 2007 data used in the proposal, and EPA identified the data that would be used. Id. at 53,614

- 15. EPA explained that these changes would “more accurately portray the unit level control installations that have occurred at power plants during the past several years.” Id. The NODA also explained that these changes to the IPM could impact the final rule by “[c]hanging cost and emission projections used in the multi

- factor test to determine the amount of emissions that represent significant contribution,” id. at 53,614, which determines the State budgets. Thus, through the NODAs, EPA gave notice that the final rule budgets would differ from those in the proposal and provided an opportunity to comment on the methodo logy and data used in developing the final budgets." (E) EPA failed to adequately assess the economic impacts of CSAPR, which will increase electricity prices and negatively impact the economy. Comment (E)(1) : The CSAPR puts at risk the economic future of power generation, and those dependent on affordable electricity in Texas and places vulnerable citizens at significant health and safety risk. The potential loss of electricity to state offices, schools, prisons, etcetera, would directly impact state resources and the ability of the state to provide services. Texas' inclusion was not adequately noticed as a part of the rule proposal. The EPA failed to adequately assess the economic impacts of CSAPR on Texas. The EPA's analysis entitled "Resource Ade quacy and Reliability in the IPM Projections for the Transport Rule TSD" was not available at rule proposal and includes significant errors regarding generation capacity within ERCOT, the largest grid operator within Texas. The EPA overestimates ERCOT's generation capacity by nearly 20,000 megawatts. [Letters: Texas Commission on Environmental Quality (EPA

- HQ

- OAR

2009

- 0491

- 9002) p. 22

- 23]
RESPONSE : These comments are outside the scope of the revisions proposed and upon which EPA solicited comment. Ho wever, analysis of the economic impacts of the final Transport Rule is provided in Chapter 8 of the Regulatory Impact Analysis for the final Transport Rule and in the docket for this rulemaking [EPA

- HQ

- OAR

- 2009

- 0491

- 4193]. Comment (E)(2) : The CSAPR will increase the price of electricity in Texas and thereby negatively impact residential consumers and energy

- intensive businesses and the jobs they create. EPA has vastly understated the cost impact of the CSAPR. Although the cost impacts of the CSAPR are m ore difficult to determine in ERCOT's competitive market because generation plant owners must attempt to recover their costs through higher market prices, the costs will likely be substantial. Commenter provides significant additional discussion in suppor t of their assertion, including data and conclusions from Southwest Power Pool (SPS), AEP subsidiary Southwestern Electric Power Co., Luminant, and San Miguel Electric Cooperative regarding the potential increase in rates due to implementation of the Trans port Rule. [Letters: Public Utility Commission of Texas (EPA

- HQ

- OAR

- 2009

- 0491

- 4800) p. 7

- 9]FIP Revisions

- RTC Febru ary 7 , 2012 Page 175

175 RESPONSE : These comments are outside the scope of the revisions proposed and upon which EPA solicited comment. However, analysis of the economic impacts of the final Transport Rule is provided in Chapter 8 of the Regulatory Impact Analysis for the final Transport Rule and in the docket for this rulemaking [EPA

- HQ

- OAR

- 2009

- 0491

- 4193]. (F) Proposes modification to the methodology for determining variability limi ts for small states. Comment (F)(1) : PSEG commented in its hearing testimony that it would propose in its written comments, a modification to the methodology for determining the variability limits for small states beginning in 2014. [Letters: Public Se rvice Enterprise Group (PSEG) (EPA

- HQ

- OAR

2009

- 0491

- 9003) p. 33]
RESPONSE : This comment is outside the scope of the revisions proposed and upon which EPA solicited comment. However, variability limits are discussed in the final Transport Rule preamble (section VI) and the response to comment document for the final Transport Rule, in the docket to this rulemaking. Comment (F)(2) : In the proposed Transport Rule, EPA recognized that smaller states with fewer affected units could face difficulties if the assurance penalty provisions were based only on percentages. As a result, EPA proposed that the variability of state budgets for smaller states subject to the Transport Rule would be calculated based on absolute tonnage limits. EPA appropriately recogniz ed that this distinct approach for calculating variability levels for smaller states would ensure that each state is allowed adequate variability, while limiting the absolute amount of emissions allowed. However, in promulgating the final Transport Rule, EPA disregarded the approach proposed in the proposed rule, and instead established a single, fixed percentage for variability applicable to all covered states. In the context of correcting other technical errors through the pending Proposed Rule, EPA sho uld revise the Transport Rule to establish the variability levels for smaller budget states based on an absolute tonnage limit. A standard percentage

- based variability limit, in particular one that reflects the emissions variability of a large state with dozens of base

- load, load

- following and peaking plants, resulting in a smaller range of emissions in percentage terms over time, serves only to reduce the operational flexibility of the states with fewer plants subject to the Transport Rule. As EPA reason ed in the proposed Transport Rule, a dual approach that is based both on percentage and tonnage variations addresses the difficulties that smaller states would face under a percentage

only approach. As illustrated in a supplied chart, a switch to a percen tage

- only approach adversely affects the operational flexibilities of generating companies in just three states

– New York, Maryland and New Jersey

– while increasing the flexibility of companies in all other states covered under the program. Of these thr ee states, New Jersey has the smallest allowance budget under the Transport Rule. As a result, New Jersey is severely affected by EPA’s current approach of basing all affected states’ variability limits on a percentage of the state’s budget. New Jersey’sFIP Revisions

- RTC Febru ary 7 , 2012 Page 176

176 variability limit for the annual NO X program was reduced the most

– from 42 percent under the proposed rule to 18 percent under the Transport Rule. Three other small states

– Delaware, Massachusetts, and Connecticut

– that would have seen even steeper de clines are no longer subject to the Transport Rule. A number of additional issues, which can raise the volatility of overall emission levels and are unique to New Jersey, make the percentage

- only approach particularly onerous for the state. New Jersey in cludes transmission

- constrained zones that often require many high

- emitting peaking units to be run, especially in the summer, to maintain reliability. Combustion turbines comprise a relatively significant rate of total state generation (almost 30 percent of the total state generating capacity). Unlike predictable base load units which operate most of the time regardless of weather conditions, theses peaking units are highly dependent on the weather. New Jersey is also often subject to gas curtailments w hen supplies are needed for residential and commercial heating during cold winter months. This forces certain dual fuel units to run on oil, which may result in higher emissions. [Letters: Public Service Enterprise Group (PSEG) (EPA

HQ

- OAR

- 2009

- 0491

- 47 93) p. 8

- 10]
RESPONSE : EPA is adjusting New Jersey’s annual and ozone season NO X budgets and SO 2 budget in 2012 and 2014. See the preamble to the final Revisions Rule and the TSD called Final Revisions Rule State Budgets and New Unit Set

- Asides in the d ocket for this rulemaking. (G) EPA's TSD for the Proposed Supplemental Rule stated that onroad vehicle emissions were “primarily based on the publicly released 12/21/2009 version of the Motor Vehicle Emissions Simulator (MOVES2010).” However, Trinity Consul tants was unable to replicate EPA’s mobile source emissions using the publicly available information for MOVES2010. Comment (G)(1) : Commenter notes that after the close of the comment period on the Proposal (i.e., Supplemental rule covering Oklahoma and other states), they have continued to review new information that was not previously available from EPA concerning its modeling for CSAPR. The new information suggests that EPA deviated from its own default datasets and protocols for vehicle emissions mod eling, which had the effect of increasing modeled emissions. This is one reason that would explain why EPA’s modeling results for maintenance

- interference sites are out of step with actual, real

- world conditions. Commenter notes that upon further corresp ondence with EPA after the close of the comment period, Trinity Consultants learned that different datasets need to be used in lieu of the publicly available database for MOVES2010 in order to duplicate EPA’s mobile source emissions in CSAPR. Trinity furt her identified that EPA adjusted the MOVES2010 inventory output after processing by converting the model output into emissions per vehicle mile traveled (“VMT”) and then applied data from a separate VMT database. This is different from the approach explai ned in the TSD. The actual VMT information used by EPA to project Allegan County, Michigan as a maintenance interference location apparently has not been made available for public review and comment. Commenter provides significant additional discussion w ith regard to the problems with EPA's modeling assumptions and its impact on Oklahoma and requests that EPA reconsider its inclusion ofFIP Revisions

- RTC Febru ary 7 , 2012 Page 177

177 Oklahoma in the CSAPR. [Letters: Oklahoma Utilities Group (EPA

- HQ

- OAR

- 2009

- 0491

- 4739) p. 1

- 4, Att. 1]
RESPONSE : This comment is outside the scope of the revisions proposed and upon which EPA solicited comment (76 FR 63860). However, these comments have been addressed in the record. S ee the final s upplemental rule (76 FR 80760, December 27, 2011) and the response to co mments document for that rulemaking in the docket. (H) EPA's FIP first approach for 2012 and 2103 violates the Clean Air Act's Mandate of Cooperative Federalism and has no substantial environmental or health gain. Comment (H)(1) : EPA has very likely overst epped its legal boundaries under the cooperative

federalism mandates of, among other provisions of the Clean Air Act (CAA), 42 U.S.C. §§ 7407(a), 7401 (a)(3), and 7410(c). These CAA provisions and court cases as well, mandate a state action first approach . EPA's transgression is evident for the years 2012 and 2013, where the EPA has adopted what has been called the "FIP first approach" which has illegally commandeered the States' role under the cooperative federalism mandates of the CAA. EPA will not acc ept SIP revisions for the 2012 control periods, and most states cannot realistically submit SIPs in time for the 2013 compliance periods. PA DEP has reserved the right to submit a SIP revision by April 1, 2012, and is examining all options available under state law to expedite the rulemaking and SIP development process in order to allocate 2013 Transport Rule allowances. The Transport Rule FIPs promulgated by EPA with a January 1, 2012, compliance date usurp states' rights by depriving states of any oppor tunity to regulate directly sources within their own borders. EPA's highly questionable "FIP first" approach for 2012 and 2013 is especially troublesome in that EPA has not specifically quantified any environmental or health benefits for 2012 and 2013. [ Letters: Pennsylvania Department of Environmental Protection (EPA

- HQ

OAR

- 2009

- 0491

- 4773) p. 3

- 4]
RESPONSE : This comment is outside the scope of the revisions proposed and upon which EPA solicited comment. However, EPA’s authority has been discussed th roughout the Transport Rule process in the proposal and the final rules and in the final Transport Rule response to comments document in the docket to this rulemaking (EPA

- HQ

- OAR

- 2009

- 0491). (I) Waste coal
- fired power plants should not be subject to the Tran sport Rule. Comment (I)(1) : This group of EGUs that EPA included in the final Transport Rule should not be subject to the rule because these sources do not contribute significantly to nonattainment of the national ambient air quality standards or interfe re with maintenance in downwind areas. These units produce environmental benefits from the clean

- up of waste coal piles. In the proposed preamble for the Utility MACT Rule, EPA acknowledges that special consideration is warranted for units that burn coal refuse because of their unique environmental benefits. EPA also already recognizes that Circulating Fluidized Bed (CFB) technology ensures that the units are inherently cleaner than most EGUs. CFB units are among the units used to set the MACT floor for coal

- fired EGUs with the exception of hydrogen chloride. They are also among theFIP Revisions

- RTC Febru ary 7 , 2012 Page 178

178 units with lowest mercury emissions. They should be excluded from the Transport Rule because the add

- on controls EPA considers cost effective for pulverized

- coal fired unit s are not cost

effective for waste coal

- fired units. Commenter (PA DEP) provides significant additional discussion on this issue and asserts that the waste coal units should be treated similarly to non

EGUs, which EPA has excluded. Commenter also notes t hat should EPA decide not to exclude these units, EPA should increase Pennsylvania's S02 budgets by the amount needed to be consistent with their historic emission rates; these allocations would reflect the consideration of (that is, the lack of) cost

- effe ctive controls. Commenter provides a method for how EPA should allocate the number of allowances to the units (and provides unit

- specific information in Table 1 of their letter and within Enclosure 1 as an attachment to their letter). [Letters: Pennsylv ania Department of Environmental Protection (EPA

- HQ

- OAR

- 2009

- 0491

- 4773) p. 6

- 8]
RESPONSE : This comment is outside the scope of the revisions proposed and upon which EPA solicited comment. See the preamble for the final Transport Rule and the response to comments document for the final Transport Rule in the docket to this rulemaking for information on waste coal units. (J) EPA should amend the Transport Rule to allow the owners and operators of non
EGUs to buy and surrender NO X allowances. Comment (J)(1 ) : Under the two predecessor trading programs, the NO X SIP Call and CAIR programs, certain non

- EGUs could opt

- into the program or buy and surrender NO X allowances for compliance with other emission limitation programs. Pennsylvania's SIP

- approved air qua lity regulations authorize the use of this market

- based compliance option for small sources of NO x in the five

- county Philadelphia ozone nonattainment area that were not subject to either trading program (namely certain boilers, stationary combustion turb ines, and stationary internal combustion engines) and for large stationary internal combustion engines and cement kilns that are subject to the NO X SIP Call. Commenter (PA DEP) requests that EPA amend the Transport Rule to continue to allow for the surren der of NO X allowances for these units to avoid a disruption of this cost

- effective method of compliance. The impact on the Transport Rule will be insignificant. [Letters: Pennsylvania Department of Environmental Protection (EPA

- HQ

- OAR

2009

- 0491

- 4773) p . 9]
RESPONSE : This comment is out side the scope of revisions proposed and upon which EPA solicited comment. This issue has been addressed in the preamble to the proposal and final Transport Rule actions as well as in the response to comments for the Tr ansport Rule. (K) Significant errors persist in the EPA base case and remedy runs for Wisconsin. Comment (K)(1) : EPA used the unit

- level 2012 base case emission estimates in its air quality model (i.e., CAMx) to determine Wisconsin's contribution level s to downwind nonattainment and maintenance receptors, and ultimately to decide whether Wisconsin should be included in the annual SO 2 and NO X programs. EPA used the results of the 2012 and 2014 remedy modeling runs to determine Wisconsin's state allowanc e budgets in 2012 and 2014, respectively.FIP Revisions

- RTC Febru ary 7 , 2012 Page 179

179 However, EPA has made a number of significant factual errors in both its 2012 base case and its 2012 and 2014 remedy runs. Commenter (Integrys) notes that EPA relied on specific unit level data sets for determini ng base case emissions in 2012 and setting Wisconsin's 2012 and 2014 state budgets (Docket IDs: EPA

- HQOAR

- 2009

- 0491

- 4420, 4431, and 4440) and that it appears EPA assumed SO 2 emissions rates in its 2012 base case for Wisconsin that are completely inaccurate for the following units: Alma 4 & 5, Columbia 1 & 2 Edgewater 3

- 5, Genoa 1, Manitowoc 9, Nelson Dewey 1

- 2, South Oak Creek 5

- 6 and Weston 1

- 3. EPA's 2012 base case assumes that CAIR is not in place but that does not explain EPA's erroneous emission rates for these units. Other units in the base case also have inaccuracies as well that taken in total result in a substantial overstatement of Wisconsin's SO 2 emissions in the 2012 base case. Commenter provides as an attachment, a list of the various units in Wisconsin comparing EPA's 2012 base case emission rate with the actual emission rates in 2010, and notes that these errors overestimated Wisconsin's SO 2 base case emissions in 2012 by approximately 24,000 tons (or 22%). It appears EPA used these data t o determine whether to include Wisconsin in the annual SO 2 program. Given these errors and the small size of Wisconsin's contributions to downwind receptors, EPA should reconsider the state's inclusion in the annual SO 2 program and should stay the final r ule with regard to Wisconsin. [Letters: Integrys Business Support (EPA

- HQ

- OAR

2009

- 0491

- 4757) p. 2

- 4]
RESPONSE : EPA’s methodology for identifying significant contribution to downwind nonattainment and/or maintenance is outside the scope of the revision s proposed and upon which EPA solicited comment. EPA has responded to similar comments in the final Transport Rule preamble and response to comments document in the docket to this rulemaking. (L) EPA should use the same baseline calculation for coal uni ts converted to natural gas combined cycle that it uses for coal plant upgrades. Comment (L)(1) : In 2002, Northern States Power (NSP) voluntarily proposed a plan to reduce emissions at three Twin Cities area coal

- fired power plants. NSP replaced existin g coal fired boilers with natural gas combined cycle units at two plants (High Bridge and Riverside). NSP also installed state of the art emission controls at the A.S. King coal fired plant. These projects began in 2005 and were completed in 2009.
While the A.S. King coal plant is rewarded for its emissions reductions, the two coal plants converted to natural gas combined cycle are penalized. The allowance caps are currently calculated based on the plant's maximum post

- conversion emissions. These level s were only achieved after an investment of one billion dollars and years of work. If the allowance cap calculation is not changed, NSP, other utilities, and rate payers will have little incentive to be early adopters or pursue such forward looking collab orations. The Minnesota Chamber supports NSP's request that EPA use the same baseline calculation for coal units converted to natural gas combined cycle as it uses for coal plant upgrades. [Letters: Minnesota Chamber of Commerce (EPA

- HQ

- OAR

- 2009

- 0491

- 47 59) p. 2]FIP Revisions

- RTC Febru ary 7 , 2012 Page 180

180 RESPONSE : EPA considers units that are entirely replacing pre

- existing units to be a different unit. The pre

- existing units are considered retired, and EPA does not allocate allowances to units that were retired at the time of Transport Rule f inalization. Additionally, changes to the allocation methodology are out side the scope of the revisions proposed and upon which EPA solicited comment . See Section 6.5, below, for more information. (M) IPM is not a reliable model and should not be used to de termine future year utilization and emissions. Comment (M)(1) : Commenter provides specific information and comments on why IPM modeling results are inaccurate (see related discussion under Section 1.2) noting that comparisons between the projections and actual data indicate that the model does not mimic what would happen in the market absent the proposed standards (as it should). While it may have its purposes, IPM is not a reliable model for determining future year utilization and emissions and should not be used to determine unit level allocations or state emission budgets. EPA should find a different method to make future year projections and determine allocations and budgets. [Letters: Mississippi Department of Environmental Quality (EPA

- HQ

- OAR

- 20 09

- 0491

- 4786) p. 2]
RESPONSE : Comments regarding the IPM model are out side the scope of revisions proposed and upon which EPA solicited comment, but have been addressed elsewhere in the record. See the preamble to the final Transport Rule and the respon se to comments document for the final Transport Rule in the docket to this rulemaking. Comment (M)(2) : EPA’s IPM projected heat input differs significantly from 2010 actuals for Westar as well from any realistic 2012 projections. The under

- estimation of heat input is partially due to an under

- estimation of heat input for units projected by IPM to be in operation in 2012 and partially due to excluding heat input values for several Westar’s units identified as “withdrawn as uneconomic” (previously named as “early retirement”). The Final Rule IPM projects that Westar’s total2 2012 remedy case heat inputs will be 245,821,509 mmBtu/yr and 107,689,567MBtu/ozone season. The annual projections represent approximately an 8% decrease as compared to Westar’s 2010 actual heat input and the ozone season projection represents an 11% decrease compared to Westar’s 2010 actual ozone season heat input. Based on an average NO X 2010 emission rate of 0.2 lb/mmBtu, aligning the IPM 2012 projections with 2010 actuals would r esult in approximately 2,000 additional NO X annual allowances to the 2012 Kansas budget and 1,300 additional 2012 NO X ozone season allowances. Similar increases in the 2014 Kansas budgets would be expected if the IPM projections were aligned with 2010 act uals. The Southwest Power Pool (SPP) has indicated that the heat input projected by the IPM model for the state of Kansas will not be sufficient to assure grid reliability for the 2012 summer peak period. [Letters: Westar Energy (EPA

- HQ

- OAR

- 2009

- 0491

- 47 77) p. 7

- 8]
RESPONSE : As noted at 76 FR 63868, EPA was encouraging comments on modeling input assumptions. However, the above comment does not provide any relevant information on what input assumptions are incorrect, rather notes that for a subset of un its modeled , the outputFIP Revisions

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181 projections are different from their own predictions for the units ’ operation. EPA notes that the Transport Rule is a t rading p rogram without unit level operational requirements, and sources are free to operate at levels predicted by commenter. See the Declaration of Sam Napolitano, dated December 1, 2011, filed in support of EPA's Consolidated Opposition, EME Homer City Generation v. US EPA, and consolidated cases No. 11

- 1302 (D.C. Cir.) , which can be found in the docket for this rulemaking, paragraphs 58

- 61, for a response regarding the SPP statements. Comment (M)(3) : In the Final Rule, the IPM projected for the total BPU1 2012 remedy case heat input of 25.00 TBtu/yr and 10.67 TBtu/ozone season. Those values do not comport with BPU’s 2010 actuals or any realistic 2012 projections; the IPM heat input values are approximately 24% lower than BPU’s 2010 annual heat input and 28% lower than the ozone season heat input. It appears that the IPM under

- estimation results from a combinat ion of projecting lower heat inputs for 2012 operational units and of excluding BPU units from evaluation under the heading “withdrawn as uneconomic” (previously titled “early retirement”). Trinity calculated what additional 2012 allowances would result i f a more realistic heat input were used. Starting from the remedy 2012 NO X emission rates for Nearman Unit 1 and Quindaro Units 1 and 2, Trinity substituted the 2010 actual heat input in lieu of the IPM projections (including the 2010 actual emission rate for Nearman CT4 for which IPM assigned a zero emissions level). These changes would result in 1,247 additional NO X annual allowances and 584 additional NO X ozone season allowances to the 2012 Kansas budget. Similar changes would apply for the 2014 Kansa s budget. The full calculations are shown in Tables 2 and 3 of the comment letter.
For SO 2 , Trinity started with the 2012 base case adjusted for an emission rate of 0.937 lb/mmBtu, which as discussed above (Table 1 and accompanying text) reflects the emi ssions that can be achieved at $500/ton cost threshold, and for BPU’s CT4 2010 actual emission rate (in lieu of the zero emissions for CT4 projected by the IPM). As shown on Table 4, the heat input increase and revised emissions rates together suggest tha t an additional 7,857 SO 2 allowances be included in a revised Kansas budget. Trinity also calculated what revisions should be made in Kansas’ 2014 State budgets, using the same approach as described above for the 2012 Budget revisions. The 2014 results a re shown in Tables 5 and 6. A summary of all the proposed revisions to the Kansas State Budgets based on these changes to the emission levels for BPU’s units is shown in Table 7. [Letters: Kansas City Board of Public Utilities (EPA

- HQ

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- 4779 ) p. 3

- 6]
RESPONSE : See the preamble to final Revisions Rule and the TSD c alled “Final Revisions Rule Sta t e Budgets and New Unit Set

- Asides.” (N) The CSAPR does not provide adequate time for all affected sources to comply with the requirements.
Comment (N)(1) : The final rule only gave Nebraska and its utilities 6 months to comply and while the proposal will provide additional NO X allowances, the final allowances will not beFIP Revisions

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182 known until 2012. Utilities in Nebraska are at a distinct disadvantage to have the control equipment required by CSAPR installed for 2012. All NE power utilities are publically owned and all significant expenditures must be approved and funding must be procured through an open public procurement process. Also, the timeframe does no t account for the time it would take to issue permits for the equipment at these facilities. [Letters: Nebraska Department of Environmental Quality (EPA

- HQ

- OAR

- 2009

- 0491

- 4780) p. 2]
RESPONSE : This comment is outside the scope of the revisions proposed and upon which EPA solicited comment. However, EPA has addressed compliance timing in the preamble to the final Transport Rule and the final Transport Rule response to comments document in the docket to this rulemaking. Comment (N)(2) : The Final Rule do es not provide sufficient time for Westar (and other Kansas utilities) to meet the proposed emission reductions and an extension of the deadlines is not only necessary but also equitable in light of Westar's history of good faith and diligent efforts to me et its CAA obligations. In February 2008, Westar entered into a Regional Haze Agreement with the Kansas Department of Health and Environment (KDHE) establishing a timeline for the installation of NO X , SO 2 , and PM emission control equipment across its ent ire operating fleet. KDHE worked closely with all stakeholders (EPA, affected states and Westar) prior to finalization of this Agreement to establish a plan for expeditious completion of these projects to meet the Agreement's NO X and SO 2 emission limitati on no later than January 1, 2014. As part of its good faith efforts to carry out the Agreement's terms, Westar, prior to finalization of the Agreement and knowing the long lead times necessary to complete the installation of the control equipment, began t he designing, procuring and installing of the emission control equipment to ensure compliance with the Agreement's NO X and SO 2 emission limitations by January 1, 2014. Similarly, Westar, in good faith, entered into a Consent Decree in March 2010 with EPA to settle claims alleging violations at Jeffrey Energy Center ("JEC"). The Consent Decree requires the installation of an SCR prior to the end of 2014 with an option, to be exercised by the end of 2012, to install a second SCR by the end of 2016 as one me ans to comply with the NO X emission obligations of the Consent Decree In recognition of the long lead time for designing, procuring and installing an SCR, EPA agreed to a more than four year timetable for the installation of the first SCR and over six year s for the installation of the possible second SCR. Likewise, the Consent Decree did not require Westar to meet the first NO X conditions, utilizing low NO X burners ("LNB"), until the end of 2011, or approximately 20 months after entry of the Consent Decree. Westar has actively undertaken emission control fleet

- wide upgrades and additions prior to the conception and finalization of the Final Rule. Westar's existing agreements ensure that all the emission controls required to meet the Final and Supplemental Proposed Rule for Kansas will be in place at Westar's Energy Centers by 2015. The Final Rule needs to reflect "real world" timelines for pollution control equipment design, procurement and installation. [Letters: Westar Energy (EPA

- HQ

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- 2009

- 0491

- 477 7) p. 2

- 3]
RESPONSE : This comment is outside the scope of the revisions proposed and upon which EPA solicited comment, however, compliance timing has been addressed elsewhere in the record. SeeFIP Revisions

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183 the preamble to the final transport Rule and the response t o comments document for the final Transport Rule in the docket to this rulemaking. (O) The revised transport rule proposal fails to adjust the allocation of allowances for newer "existing units." Comment (O)(1) : CWLP disagrees with EPA's proposed Revised T ransport Rule, because it does not adjust the method for allocating allowances to newer "existing" units like Dallman Unit 4. Accordingly CWLP requests that as part of its revisions, EPA revise its method of allocation for newer existing units (i.e., unit s that commenced operation after January 1, 2008) to avoid short

- changing units like Dallman Unit 4. In 2009, CWLP began commercial operation of Dallman Unit 4. The methodology for allocating allowances for existing units unreasonably under allocates al lowances because the allowances are based on maximum emissions for just a single year (2010), when operations of the unit were not representative of expected normal future operations. Dallman Unit 4 was still in its shakedown period for much of 2010, and also experienced problems with it water circulating pumps which force CWLP to operate the unit at a substantially reduced capacity factor. The under allocation was also a surprise as an earlier version of the rule's allocation methodology treated the unit as a new unit, subject to Illinois' New Unit Set Aside pool which uses an allocation methodology that accounts for the types of operation limitations experienced by the unit. In CWLP's Petition for Reconsideration, CWLP identified methods, such as alloca ting based on a reasonable projection of 2012 emissions that would have treated units like Dallman Unit 4 more fairly. Using that method would result in the unit being allocated 993 and 447 annual allowances for SO 2 and NO X , and 186 ozone season NO X allo wances. As EPA noted in the preamble to its proposed revisions, technical fixes to the final CSAPR can yet be made while still maintaining the rule's ability to achieve the reductions intended. [Letters: City Water, Light and Power (EPA

- HQ

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- 2009

- 049 1

- 4764) p. 2

- 3]
RESPONSE : This comment is outside the scope of the revisions proposed and upon which EPA solicited comment. However, EPA’s allocation methodology is described in p reamble s ection VII.D of the f inal Transport Rule and in the final Transpo rt Rule response to comments document in the docket to this rulemaking. Comment (O)(2) : DTE Stoneman should receive significantly higher allowances than currently provided. The intent of the rule and allowance allocation approach EPA took is not to pena lize units for choosing cleaner fuels or installing pollution controls. DTE Stoneman converted the plant to 100% wood biomass, reduced fuel sulfur content and installed SNCR and OFA as BACT for NO X control. Wood biomass is a cleaner burning fuel than coa l, which resulted in significantly reduced SO2emission rate. It also installed SNCR and overfire air as add

- on emission controls to reduce NO X emissions. With the fuel conversion, the use of SNCR and overfired air, the current EPA approach in allocating allowances provided DTE Stoneman veryFIP Revisions

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184 little to cover future emissions. DTE Stoneman previously fulfilled the intent of the rule by converting to biomass and now is being asked to buy a significant number of allowances and retrofit with additional polluti on controls that are not economical and likely not technically feasible. DTE Stoneman should receive significantly higher allowances than currently provided. The allocation method EPA chose for the final CSAPR consists of the use of historical heat inp ut to allocate allowances instead of projected heat input. Though this approach may make sense for units that have not undergone reconstruction during the look back period, it is not a logical way to appropriately allocate allowances for DTE Stoneman.
Th e plant was unfairly penalized for converting the plant from 100% coal to 100% Biomass and for installing SNCR and OFA. The reconstruction occurred between April 2009 and July 2010, during the baseline period. Prior to the reconstruction, the facility di d not operate often combusting coal (capacity factors in the 3% to 17% range). EPA should allocate based on DTE Stoneman’s projected emissions using limited operation data from 2010 and extrapolating for a full year operation and projected capacity factor rather than using the highest 3

- yr average between 2006 and 2010 which is not representative of the biomass plant we currently have and future operating conditions. Due to the extraordinary reasons listed above, DTE Stoneman should receive a significant increase in the allocated allowances to be consistent with the intent of the rule and not cause severe economic hardship to this renewable energy facility. [Letters: DTE Stoneman LLC (EPA

- HQ

- OAR

- 2009

- 0491

- 4783) p. 3

- 4]
RESPONSE : This comment is outside the scope of the revisions proposed and upon which EPA solicited comment. See Section 6.5, below, for more information. Comment (O)(3) : In addition to the corrections already proposed, EPA should correct the allocations for J.K. Spruce 2 ("Spruce 2"). The allowances granted to Spruce 2 under the CSAPR Federal Implementation Plan ("FIP") are not based on representative operating data for the unit, which only became operational in November 2009 and was not operated at full capacity in 2010. As a new, s tate

- of

- the

- art plant, CPS Energy expects that Spruce 2 will provide critical base load supply in the long term. It is therefore important that Spruce 2 be accurately characterized under CSAPR and its operation not be dependent on system trading or SO; ma rket forces. Accordingly, CPS Energy requests that EPA correct the allowance allocations granted to Spruce 2 to levels that reflect normal operations of the unit on an annual basis. Previously, CPS Energy filed a petition for reconsideration of the final CSAPR to address this issue] A copy of that petition for reconsideration is attached, and CPS Energy believes that the currently proposed revisions to CSAPR present a suitable opportunity to correct the allocations granted to Spruce 2. After roughly 50 m onths of construction, start

- up of Spruce 2 occurred in November 2009, just before the January 1, 2010 date that separates "existing units" from "new units" under the CSAPR FIP. Even following its commercial availability to ERCOT on May 28, 2010, Spruce 2 was not available to be operated, and did not operate, at full capacity during 2010 due toFIP Revisions

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185 additional work associated with the full commissioning of the new unit. In total, Spruce 2 ran at only 52.7 percent capacity between April and December 2010, the m onths after which CPS Energy began submitting quality

- assured emissions data for Spruce 2 to the Clean Air Markets Division (CAMD). Under the CSAPR PIP, Spruce 2 was classified as an existing unit and granted 158 annual SO 2 allowances, 560 annual NO X allo wances, and 455 ozone season NO X allowances. These allowances, which under the CSAPR FIP, are based on a single, partial year of operation at less than full capacity, are not representative of normal annual operations and are not consistent with the prin ciples that govern EPA's allocation method in the CSAPR PIP. CPS Energy did not report heat inputs and emissions data to CAMD dining the first three months of 2010 because the CEMS were not yet certified, and the unit was idled for nearly three months bet ween September and December 2010 for work and repairs associated with the initial commissioning of the unit. As a result, the 2010 emissions and heat input data does not come anywhere close to the level that CPS Energy would expect Spruce 2 to achieve in a full year of normal operations. Because Spruce 2's allocations were capped by the unit's actual emissions solely from its partial

- year operations during 2010, Spruce 2 will not be granted any additional allowances if the proposed revisions to the Texas statewide budgets are finalized as proposed. CPS Energy requests that the allowance allocations be corrected to reflect normal operation. CPS Energy believes the permitted annual SO 2 and NO X emissions reflect normal operation, and should be the allocatio n. At a minimum allowances would alternatively be based on the months of June, July, or August 2010 which provide a period of representative operation. [Letters: CPS Energy (EPA

- HQ

OAR

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- 4784) p. 3

- 5]
RESPONSE : This comment is outside the sco pe of the revisions proposed and upon which EPA solicited comment. See Section 6.5, below, for more information. Comment (O)(4) : The allocation of allowances under the CSAPR for EKPC's Spurlock Unit 4 was inappropriately reduced based on the start

- up da te. When operating normally Spurlock Unit 4 averages a monthly heat input of 1,851,818 mmBtu with an estimated annual heat input over 22 million mmBtu. EPA, however, underestimated heat input at Spurlock Unit 4 by nearly 25%. The reason is that EPA fail ed to account for the fact that Unit 4 did not come online until the second quarter of 2009 in its averaging calculations. Additionally EPA mad e improper assumptions about Units 4's historic emissions that severely limited the final allocation by more tha n 200% below its initial heat input basis. Spurlock Unit 4 was not online prior to 2009. EPA's consideration of heat input was arbitrary because Unit 4 was not fully operational for all of 2009. EPA's use of 2010 emissions to constrain the allocation wa s also in error. Although 2010 was the only year for which the unit had a full year of emissions data, a single year of emissions data cannot appropriately capture the inherent variability in a unit's emissions from year to year. Equally important the un it had no emissions for nearly 20% of the 24 month period EPA looked at for determining a unit's maximum historic emissions.FIP Revisions

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186 EKPC raised the allowance under allocation in its formal comments to the proposed rule, but EPA did not address the comments in it s final rule. EKPC determined allowances using the heat input methodology EPA proposes but without utilizing a maximum historic emissions factor since no such factor is available for the unit. Instead, EKPC used monthly average heat input for 2010, exclu ding September and October when the unit was off line a significant amount due to unit outage, to arrive at an average monthly heat input of 1,851,816 mmBtu. As a result, a fair allocation based on EPA methodology used for Spurlock Unit 3 would have been 1,724 annual SO 2 allowances for 2012 and 2014, and NO X annual allowances for 2012 and 2014 should be 2,122 and 1,752 tons respectively. This allocation is more representative of normal operation and comparable to similar CSAPR units. [Letters: East Kent ucky Power Cooperative (EKPC) (EPA

- HQ

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- 2009

- 0491

- 4806) p. 3

- 5]
RESPONSE : This comment is outside the scope of the revisions proposed and upon which EPA solicited comment (76 FR 63860)

. In addition allocation issues have no bearing on a state’s budget . In fact, states have the flexibility to adjust allocations as they see fit through their SIPs. See Section 6.5, below, for more information. (P) EPA's method of group classification is faulty. Comment (P)(1) : The EPA must reevaluate whether Texas shoul d be considered as a Group 1 or a Group 2 state in the SO 2 CSAPR program. The EPA should also consider whether the group classifications for the SO 2 program are potentially biased for some states or if the group classifications are even necessary. The ju stification that EPA used for the group classifications and the restriction that limits states to trading within their group classification are arbitrary and faulty. Some Group 2 states are being forced to make more reductions faster than some Group 1 sta tes, while some Group 1 states may already meet their final 2014 Group 1 SO 2 budgets this year. EPA has erred in classifying Texas as a Group 2 state and has erred in the group classification of other states. EPA should abandon the group classification a nd should provide all states additional time to make the required reductions. Commenter asserts that EPA’s request for comment on including Texas as a Group 2 state in the original proposal of the rule is founded on conclusions derived from the EPA’s faul ty projected emissions data. Commenter provides significant additional discussion on this issue including graphs illustrating the CSAPR Group 1 and Group 2 state SO 2 reductions from 2010 on a tons per year and percent basis and a detailed critique of EPA’ s rationale for the classifications. [Letters: Texas Commission on Environmental Quality (EPA

- HQ

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- 2009

- 0491

- 4782) p. 2 (cvr), p. 8

- 11]
RESPONSE : This comment is outside the scope of the revisions proposed and upon which EPA solicited comment. See t he final Transport Rule docket for further information on the classification of states in the sulfur dioxide program. (Q) EPA’s revision also does not resolve the questionable fact basis for Texas’ inclusion in the annual SO 2 and NO X programs in the first pl ace, and underlying problems with EPA's budget methodology.FIP Revisions

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187 Comment (Q)(1) : EPA’s revision also does not resolve the questionable fact basis for Texas’ inclusion in the annual SO 2 and NO X programs in the first place. The revision does not provide any ad ditional analyses, nor does it provide an updated methodology, supporting Texas’ inclusion in these programs. There is no attempt to resolve the fundamental flaws and potential errors in relying upon one monitor in Madison County, Illinois to include Texa s in the annual SO 2 and NO X programs. In addition, EPA has not addressed that the Madison County area has been found to be in compliance with the annual PM2.5 NAAQS,2 and to the degree that the Madison County monitor may show elevated levels of PM2.5, thi s is likely caused by a nearby steel mill. Providing a small increase to Texas’ SO 2 budget, and an extremely small increase to Texas’ NO X budget, does not correct EPA’s underlying methodology in assigning emissions budgets. These budgets have placed disp roportionately high emissions reduction requirements in relation to Texas’ alleged impact and in relation to the reductions required in other states’ emissions budgets. EPA is imposing these budgets, all while proceeding directly to a FIP and bypassing st ates’ rights under the CAA to take the lead in reducing its emissions through a SIP. With regard to the individual unit allocations for San Miguel, EPA’s proposed addition of allowances does not change San Miguel’s compliance strategy. EPA provided an ad ditional 1640 tons of SO 2 for the annual program and only 24 additional tons of NO X tons during the ozone season. The increase for NO X for the annual program is even lower at only 16 tons. These allocations do not reflect the actual operations at the San Miguel facility and do not provide any additional compliance flexibility or alternatives for San Miguel’s compliance strategy, which is a violation of the Federal Clean Air Act § 110. Ultimately, in the best case scenario under the rule, the electric coo peratives relying on San Miguel’s electricity, and their consumers, will be burdened with elevated electricity costs. For many of these cooperatives’ rural electricity customers, which operate companies and farms on small margins or live with tight budget s, these increased electricity costs could be devastating. In the worst case scenario, as predicted by the Electric Reliability Council of Texas (ERCOT), there may not be sufficient electricity on the grid statewide during peak

- demand periods due to the e ffects of CSAPR. The consequences would be rolling blackouts. [Letters: San Miguel Electric Cooperative (EPA

- HQ

OAR

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- 4766) p. 2

- 3]
RESPONSE : This comment is outside the scope of the revisions proposed and upon which EPA solicited comment. Se e the final Transport Rule docket for further information on findings of states’ significant contribution. (R) EPA's proposal does not address CSAPR's fundamental flaws. Comment (R)(1) : The limited corrections proposed do not satisfy commenters concerns wi th the rule. As explained in the Florida Electric Power Coordinating Group's Petition for Reconsideration and Stay, EPA erroneously included Florida in the CSAPR, substantially underallocated allowances to Florida, required Florida EGUs to provide a dispr oportionately large reduction in emissions, failed to allow for state implementation prior to federal implementation, failed to adequately cover the rule impacts, and failed to account for the Houston area's attainment deadline of 2019. The commenter also describes concerns with respect to 1) EPA not allowing Florida to codify existing emissions reductions; 2) Florida's NO XFIP Revisions

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188 budget fails to allow for economic recovery and growth; and 3) EPA must re

- run its modeling to address identified errors given the ext ent of errors and sensitivity of the model to changes in inputs. [Letters: Florida Electric Power Coordinating Group, Inc. (EPA

- HQ

- OAR

- 2009

- 0491

- 4772) p. 1

- 3; Progress Energy (EPA

- HQ

- OAR

- 2009

- 0491

- 4771) p. 2

- 3]
RESPONSE : This comment is outside the sco pe of the revisions proposed and upon which EPA solicited comment (76 FR 63860) . See the final Transport Rule docket for further information on these issues. Comment (R)(2) : As detailed in comments on the proposed rule, petition for stay, and petition f

or review and subsequent motions filed with the U.S. Court of Appeals for the District of Columbia the commenter has numerous concerns with the CSARP, and none of these are addressed by the proposed revisions. The proposed revisions do not fully redress t he penalty imposed on sources like EME Homer City, which acted in good faith to comply with CAIR. EME Homer City scheduled installation of millions of dollars of additional control technology for CAIR only to find itself forced to pay its competitors addi tional hundreds of millions of dollars (for no meaningful emissions reductions) because EPA changed the requirements midstream and provided an impossible compliance deadline. Commenter also notes that the proposed revisions do not redress the rule's costs which produce no meaningful public benefit. The significant costs of retrofits will be exacerbated by unjustified costs to many facilities resulting from EPA's allowance allocation methodology. These costs will ultimately be passed on to ratepayers. Th e rule allocates emission allowances between existing units during Phase I in a way that amounts to a redistribution of wealth without meaningful environmental benefit. Commenter provides additional discussion on these points. [Letters: EME Homer City G eneration (EPA

- HQ

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- 2009

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- 4778) p. 1

- 4]
RESPONSE : This comment is outside the scope of the revisions proposed and upon which EPA solicited comment. See the final Transport Rule docket for further information on these issues. Also refer to the Re gulatory Impact Analysis for the final Transport Rule [EPA

- HQ

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- 4193] for a benefit analysis and an analysis of the costs of the rule. Comment (R)(3) : Commenter (LPSC) continues to firmly assert that CSAPR, in both its current and potentially revised form, is based upon a large number of fatally flawed modeling assumptions and methodologies that improperly include Louisiana as a state subject to regulation, overstate the opportunities for emissions reductions in Louisiana, force the state to b ecome increasingly more reliant on imported energy and allowances from neighboring regions, and will likely lead to a number of significant reliability

- related impacts on electricity service in Louisiana. As such, CSAPR, with or without the technical revis ions, is arbitrary and capricious and should be reconsidered by the EPA or overturned by the Court. Further, EPA’s justifications for the proposed technical revisions, which are all related to a failure to account for real

- world dispatch constraints that differ from those used to develop the Louisiana’s budget and the EGU

specific allowance allocations, validates the commenter’s positions regarding CSAPR’s flaws. [Letters: Louisiana Public Service Commission (EPA

- HQ

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- 2009

- 0491

- 4799) p. 1]FIP Revisions

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189 RESPONSE : This comment is outside the scope of the revisions proposed and upon which EPA solicited comment. See the final Transport Rule docket for further information related to these issues. (S) EPA assumed unrealistic emission rates in the final rule and supplemen tal proposal. Comment (S)(1) : In the Final and Supplemental Proposed Rules, EPA assumed unrealistic NO X emission rates for Westar’s generating units in 2012 and 2014. Westar has analyzed the types of add

- on controls that would be needed to reduce the 20 10 emissions rates from its generating units to meet the stringent 2012 and 2014 emission rates inherent in the Final and Supplemental Proposed Rule for Kansas. To meet these stringent NO X emission rates, Westar would need to install add

- on controls consi sting of LNB, separated overfired air (“SOFA”), and Selective Noncatalytic reduction (“SNCR”). As discussed in Section 1, Westar has already begun to install add

- on controls required by the Agreement and Consent Decree, but these planned add

- on controls, which must become operational by 2015, will not be in place soon enough to meet the NO X emission rates within the required compliance timeline set by the Final Rule. In accordance with the JEC Consent Decree, in 2012 Westar will begin utilizing LNB and SO FA to meet the required NO X emission limitations of 0.180 lb/mmBtu on each unit. In accordance with the terms of its Regional Haze Agreement, Westar will begin installing LNB and SOFA on: Lawrence Energy Center (“LEC”) Units 4 and 5 in 2012 and Unit 3 in 2013; on Tecumseh Energy Center (“TEC”) Unit 10 in 2013; and on La Cygne Energy Center (“La Cygne”) Unit 2 in 2013. The addition of LNB and SOFA will not, however, be sufficient for these units to meet the Final Rule’s NO X emission rates. In 2014, Westar must begin complying with its Regional Haze Agreement NO X limitations at JEC, LEC and TEC, and in 2015 must begin compliance at La Cygne. Westar calculated adjusted emissions for 2012 and 2014, utilizing Westar’s obligations under existing agreements as appropriate and the IPM base case emission rates when no specific emission limitation is effective. Westar requests the emissions for each unit be adjusted to account for “real world” timelines for control equipment installation.
Westar’s calculations of 2012 NO X annual and NO X ozone season revisions are shown in Tables 2

- 1 and Table 2

- 2 of its comment letter. The 2014 NO X annual and NO X ozone season revisions are shown in Table 2

- 3 and 2

- 4 of the comment. The revisions result in a 6,340 ton increase fo r the Kansas 2012 NO X annual budget, a 2,779 ton increase for the Kansas 2012 NO X ozone season budget, a 5,693 ton increase for the Kansas 2014 NO X annual budget and a 2,487 ton increase for the Kansas 2014 NO X ozone season budget. [Letters: Westar Energ y (EPA

- HQ

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- 0491

- 4777) p. 3

- 6]
RESPONSE : In the final Transport Rule, EPA explained its intent to capture “reductions that occur due to state rules, consent decrees, and other planned changes in generation patterns that occur after 2012, but duri ng or prior to 2014” in the 2014 state budgets (76 FR 48261). Commenters on the revisions rule noted that EPA inadvertently included an emission rate requirement from a consent decree affecting a Kansas facility whose deadline actually extends beyond 2014 . To correct the alignment of the Kansas 2014 state budget with the requirementsFIP Revisions

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190 for affected units in Kansas to meet the emission rate limitation by the consent decree’s deadlines, EPA is increasing the Kansas 2014 annual NO X budget. See the Final Revis ions Rule State Budgets and New Unit Set

- Asides TSD in the docket to this rulemaking. Comments on the final supplemental proposed rules are outside the scope of proposed revisions for which EPA solicited comments. (T) The cost of compliance exceeds $500 per ton of emission reduced. Comment (T)(1) : In the Final Rule, “EPA determined that $500/ton for annual and ozone NO X was the appropriate cost threshold for this rule.” 76 FR 48208, 48250 (Aug. 8, 2011). Westar has analyzed what controls would be needed to reduce the 2010 emissions rates for its generating units to meet the reduced 2012 emission rates inherent in the Final and Supplemental Proposed Rule for Kansas. To reduce the 2010 emission rates to the Final and Supplemental Proposed Rule rates would require the addition of LNB, SOFA, and SNCR. Westar then calculated the annualized cost (depreciation plus O&M costs) of the additional controls as compared to the estimated NO X reduction (tons/year) to determine a cost per ton. The actual costs to Westa r would be multiples higher than EPA’s proposed $500/ton cost: ranging from a low of $1,063/ton to a high of $3,418/ton. Westar requests that the Kansas NO X annual and ozone season 2012 and 2014 budgets be revised to reflect the emissions that can be achi eved at the $500/ton cost set in the Final Rules. The adjustment calculations contained in Section 2 reflect what emissions can be achieved at the $500/ton cost. [Letters: Westar Energy (EPA

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- 4777) p. 7]
RESPONSE : This comment is outs ide the scope of proposed revisions for which EPA solicited comments. See the final Transport Ru le preamble se ction VI for further information related to the cost curve analysis for the rule. Comment (T)(2) : The Final Rule used a cost analysis to dete rmine what emission reductions could be achieved. For SO 2 reductions, a $500/ton cost curve was established: “In all modeling, the 2012 cost per ton threshold was held constant at $500/ton as EPA believes that this cost threshold captures all emission red uctions feasible in 2012.” 76 FR 48208, 48251/3 (Aug. 8, 2011). BPU analyzed what the cost/ton at its Nearman and Quindaro EGUs would be to reduce SO 2 emissions from their current levels to the Final Rule’s levels using DSI control technology. See 76 FR at 48283/2 (“DSI is a relatively low capital cost technology that readily can be installed in the time frame available for compliance”). BPU’s analysis showed that, although DSI has relatively low capital costs, the annual costs for T rona and byproduct d isposal are relatively high. As a result, the cost effectiveness of this approach (expressed as cost per ton of emissions removed) was high: for Nearman, the cost/ton is $2,680, for Quindaro 1, the cost/ton is $2,953, and for Quindaro 2, the cost/ton is $ 2,725. As these estimates are all several multiples higher than the $500/ton used in the Final Rule, BPU asked Trinity Consultants, Inc. (“Trinity”) to calculate the SO 2 emissions for BPU’s units at the $500/ton cost threshold. BPU requests that the Kans as SO 2 annual 2012 and 2014 allowances beFIP Revisions

- RTC Febru ary 7 , 2012 Page 191

191 increased by the difference between the feasible emission reductions at $500/ton and emission levels set in the Final Rule that can be achieved only at a substantially higher cost effectiveness price. Table 1 in t he comment letter shows Trinity’s calculation of the allowances to be added to the Kansas budget under this revision. [Letters: Kansas City Board of Public Utilities (EPA

HQ

- OAR

- 2009

- 0491

- 4779) p. 2]
RESPONSE : This comment is outside the scope of the r evisions proposed and upon which EPA solicited comment. See the final Transport Rule preamble Section VI for further information related to the cost curve analysis for the rule. The commenter’s calculations are invalid because they appear to calculate un it

- specific marginal costs of specific emission reduction strategies (such as DSI installation) which are in no way mandated by the Transport Rule programs. The commenter’s calculations ignore the fact that the Transport Rule programs allow sources to con sider all available cost

- effective emission reduction strategies, including the purchase of allowances that would be priced at the market

- wide marginal cost of abatement (across all sources covered by the programs). The commenter has not made any demonstr ation regarding the broader cost of abatement under this program accounting for all covered sources and the state budgets; as such, the commenter has not offered any technical information displacing the detailed analyses EPA conducted in the final Transpor t Rule. (U) EPA’s data and modeling in support of the Transport Rule is flawed. Comment (U)(1) : Commenter (LPSC) notes that their support for the specific changes in the proposed rule should not be interpreted as a retreat or modification of the positions taken in their Request for Reconsideration filed on October 5, 2011, nor Louisiana’s Petition for Review before the Court of Appeals for the District of Columbia filed on October 7, 2011. Commenter continues to firmly assert that CSAPR, in both its curren t and potentially revised form, is based upon a large number of fatally flawed modeling assumptions. [Letters: Louisiana Public Service Commission (EPA

- HQ

- OAR

- 2009

- 0491

- 4799) p. 1

- 2]
RESPONSE : This comment is outside the scope of the revisions proposed and upon which EPA solicited comment. See the final Transport Rule docket for further information related to these issues. Comment (U)(2) : Commenter (KY DAQ) notes that many of the downwind nonattainment and maintenance areas linked to Kentucky and oth er states have already attained the applicable NAAQS and requests that EPA consider this fact in making revisions to the final rule. Commenter provides 2008

- 2010 PM2.5 monitoring data as an attachment to their letter, noting that only one downwind monitor (42

- 003

- 0064) with complete data is still indicating nonattainment for the annual and 24

- hour PM2.5 standards. However, this monitor is located in Allegheny County, Pennsylvania, which includes Pittsburgh and is most likely impacted significantly by loca l emissions. [Letters: Kentucky Division for Air Quality (EPA

- HQ

- OAR

2009

- 0491

- 4797) p. 1]FIP Revisions

- RTC Febru ary 7 , 2012 Page 19 2

192 RESPONSE : This comment is outside the scope of the revisions proposed and upon which EPA solicited comment. However, see the preamble for the final Transport R ule (76 FR 48230). EPA also notes that for a number of the receptors listed in the appendix of Kentucky's comments (showing 2008 through 2010 air quality values for receptors to which Kentucky is linked), the annual mean or the annual 98th percent values, individually, are above the air quality level of the NAAQS. For other sites, there was substantial year

- to

- year variation in air quality. These facts are suggestive and supportive of EPA's analysis identifying these areas as nonattainment and/or "mainte nance" areas, necessitating additional emission reductions under the Transport Rule. Comment (U)(3) : Commenter (KY DAQ) notes that their comments submitted previously (October 2010 and January 2011) are still applicable and provides those comments as an attachment to their letter. Those comments raise a number of issues; namely, they request specific corrections with respect to allocations and state budgets, note the lack of SIP guidance available to states, emphasize the need to follow principles outlin ed by the Southeastern States Air Resource Managers, Inc. (SESARM), request that the most recent ambient air quality data be used, and question whether the reductions assumed for Kentucky are actually achievable. [Letters: Kentucky Division for Air Quali ty (EPA

- HQ

- OAR

- 2009

- 0491

- 4797) p. 1]
RESPONSE : These issues are outside the scope of the revisions proposed and upon which EPA solicited comment. Furthermore, see the final preamble and the final Transport Rule Primary Response to Comment document (EPA

- HQ

- OAR

- 2009

- 0491

- 4513) in the docket to this rulemaking for responses to individual comments previously provided. (V) EPA's proposal does not eliminate the need for reconsideration and stay. Comment (V)(1) : EPA's proposal does not address or otherwise reme dy the unlawfulness of CSAPR. While there is some merit in the proposal, the fact that EPA itself has now acknowledged that the final rule contains many errors that affected numerous states supports the need for reconsideration and stay. [Letters: Wisco nsin Industrial Ratepayer Group (EPA

- HQ

OAR

- 2009

- 0491

- 4789) p. 2]
RESPONSE : This comment is outside the scope of the revisions proposed and upon which EPA solicited comment. (W) Nebraska does not significantly impact any nonattainment or maintenance are as in downwind states and as such, should not be subject to the Transport Rule. Comment (W)(1) : EPA's own modeling shows that Nebraska is in the TR program due to a maximum 24

- hr PM2.5 impact of 0.53 ug/m3 at a receptor in Wisconsin, while EPA has establ ished by rule that an impact of less than 1.2 ug/m3 is not considered significant (40 CFR 52.21(k)(2)). EPA should have modified the final rule to remove Nebraska in order to stay consistent with their basic significance criteria established in the PSD re gulations. [Letters: Omaha Public Power District (EPA

- HQ

- OAR

- 2009

- 0491

- 4747) p. 3]FIP Revisions

- RTC Febru ary 7 , 2012 Page 193

193 RESPONSE : This comment is outside the scope of the revisions proposed and upon which EPA solicited comment. However, in the preamble of the final Transport Rule (76 FR 48237) EPA describes and justifies its use of a threshold of one percent of the NAAQS, to help identify states that may, or may not, be significantly contributing to and/or interfering with maintenance of a NAAQS in another state. Also on page 48237 of th e final Transport Rule preamble, EPA restates why the thresholds under the Transport Rule are different from the significant impact levels referred to by the commenter. (X) EPA should consider how the North Carolina Renewable Energy Portfolio Standard w ill impact the allowance allocations under the FIP for both 2012 and 2013. Comment (X)(1) : It is expected that many of the smaller EGUs in North Carolina have already, or will, convert their fossil

- fuel fired units to renewable fuels and as a result will substantially increase their load in order to meet the REPS goals. This increase in load is in direct response to NC law and was not considered by the EPA in allocating the future year allowances under the CSAPR, which established allocations based on a pre
- REPS time period when many of these facilities had lower demand for their fossil

- fuel generated power. The REPS has spurred considerable development of renewable energy from entrepreneurial companies thus providing needed jobs in NC. As the REPS requ irements increase over time, the EPA failure to account for this shift in load (evidenced by the allocations to these smaller EGUs) becomes more pronounced and could frustrate and even threaten the ability of NC to meet these important goals. [Letters: N

orth Carolina Department of Environment and Natural Re (EPA

- HQ

- OAR

- 2009

- 0491

- 4776) p. ]2
RESPONSE : The impacts of state

- level renewable portfolio standards on generation are accounted for in the IPM Base Case. For details on how these policies are repre sented in IPM, refer to Chapter 3 in the Documentation for EPA Base Case v.4.10

- Using the Integrated Planning Model. Additionally, changes to allocation methodology are outside the scope of the revisions proposed and upon which EPA solicited comment. However, EPA’s allocation methodology is described in preamble section VII.D of the final Transport Rule preamble

. The comment also does not specify immediate binding operational requirements on specific units that require out

- of

- merit

order dispatch.
C omment (X)(2) : CPI NC urges EPA to address allocations for existing facilities that have been converted for the purpose of generating renewable energy. North Carolina's renewable portfolio standard establishes a mandatory compliance level of at least 3% of retail electric sales commencing in 2012, it is likely that this transition to renewable energy would have had a material impact on North Carolina's state budget if EPA had properly accounted for the RPS program in the Transport Rule. CPI NC provided E PA with historic and projected heat input data showing that generation of renewable energy under the RPS would result in an increase in overall heat input at the facilities.FIP Revisions

- RTC Febru ary 7 , 2012 Page 194

194 As an alternative to adjusting the state budget to accommodate the transition to renewable energy, CPI NC urges EPA to allow converted energy facilities to access the new unit set asides for NO X and SO 2 . The facilities (and other similar sources retrofitted during the baseline period) fall into a gap between existing sources and new s ources. Because EPA has limited the new source category to units commencing operations on or after January 1, 2010, any facility retrofitted for the purpose of generating renewable energy would suffer a disadvantage to units commencing operation in 2010 o r later. CPI NC recommends EPA establish an intermediate category of converted renewable energy facilities that meet the following requirements: 1) Substantial investment in retrofitting during the baseline period to accommodate renewable fuel (at least 50% of book value); 2) as a result of the retrofit, facility combusts 50% or more renewable fuel on an annual heat input basis; 3) renewable fuel is not a fossil fuel or solid waste; 4) fuel qualifies as renewable under RPS; 5) facility has received all RP S regulatory approvals and is generating renewable energy certifications; and 6) allocations from new unit set aside are only available for increased load attributable to renewable generation, and no additional allocations for non

- renewable fuel components

. This approach would first align the Transport Rule with support for renewable energy. Second it would provide an equitable portion of the new unit set aside to investment in renewable generation otherwise disregarded. Third, it would not require an in crease in the budget for any state. Finally it would not require EPA to adjust allocations for any existing source. [Letters: CPI USA North Carolina LLC (EPA

- HQ

- OAR

- 2009

- 0491

- 4813) p. 3

- 4]
RESPONSE : The impacts of state

- level renewable portfolio stand ards on generation are accounted for in the IPM Base Case. For details on how these policies are represented in IPM, refer to Chapter 3 in the Documentation for EPA Base Case v.4.10

- Using the Integrated Planning Model. Additionally, changes to allocati on methodology are outside the scope of revisions proposed and upon which EPA solicited comment. However, EPA’s allocation methodology is described in preamble section VII.D. of the final Transport Rule. The comment also does not specify immediate binding operational requirements on specific units that require out

- of

- merit

- order dispatch. (Y) EPA did not provide adequate notice and comment for the inclusion of Louisiana in the CSAPR where based on a wholly new methodology. Comment (Y)(1) : Commenters no te that EPA concluded in the preamble to the final rule that Louisiana met the first criteria for inclusion (linkage), but not the second criteria (cost effectiveness). Despite this, instead of concluding that Louisiana should not be subject to the final rule, EPA engaged in post hoc justification for including Louisiana in the NO X ozone season program. EPA indicated that it must include Louisiana, because if it did not there would be projected leakage of emissions because generation would move Louisiana from CSAPR states. EPA did not provide any basis for the presumed leakage, and this methodology for inclusion was never made available for public comment. Commenters request EPA stay the finalFIP Revisions

- RTC Febru ary 7 , 2012 Page 195

195 CSAPR and take public comment on Louisiana's inclusion. [Let ters: Lafayette Utility Systems (EPA

- HQ

- OAR

- 2009

- 0491

- 4807) p. 6

- 7; Louisiana Chemical Association (LCA) (EPA

- HQ

OAR

- 2009

- 0491

- 4803) p. 6

- 7]
RESPONSE : This comment is outside the scope of revisions proposed and upon which EPA solicited comment. (Z) Requests increased flexibility with regards to allowances between Group 1 and 2 States and the use of future allowances in early years. Comment (Z)(1) : KCP&L operate electric generating units in both Kansas and Missouri. The final rule designated Kansas as an SO 2 Group 2 state and Missouri as an SO 2 Group 1 state. KCP&L’s La Cygne Generating Station stack is located in Kansas approximately 2 miles from the Missouri border. Obviously, the air shed is the same with such close proximity. Consistent with the Proposed Revisions to the Transport Rule goal “to promote the development of allowance market liquidity as these revisions are finalized, thereby smoothing the transition from the Clean Air Interstate Rule (CAIR) programs to the Transport Rule programs in 2012”, KCP&L requests EPA finalize the revisions to allow the use of SO 2 Group 1 allowances for compliance in SO 2 Group 2 states. This should be allowed because Group 1 states are subject to greater SO 2 reduction stringency than Group 2 states. See 7 6 Fed. Reg. at 48212. At a minimum, this request should be allowed for electric generating utilities where their system spans across both Group 1 and Group 2 states as is the case with KCP&L.. Similarly, KCP&L requests EPA finalize the revisions to allow the use of the next five years of allowances for compliance in an earlier year. KCP&L seeks this to provide for the additional flexibility to install emission controls that are underway but will not yet be operational in the coming years. For example, a t KCP&L’s La Cygne Generating Station we have commenced construction of an SCR, scrubbers, and baghouses for compliance with the Regional Haze Rule requirements. The emission controls will not be fully operational until 2015. Currently, the La Cygne Gene rating Station is short about 25% of the required allowances for SO 2 , ozone season NO X , and annual NO X for 2012 and 2013. After 2015 when the emission controls are fully operational, the Station will have excess allowances. EPA should provide the additio nal flexibility to use these future allowances for compliance in early years to facilitate the implementation of the CSAPR. [Letters: Kansas City Power and Light Company (EPA

- HQ

OAR

- 2009

- 0491

- 4804, 4826) p. 5

- 6]
RESPONSE : This comment is outside the sc ope of the revisions proposed and upon which EPA solicited comment. See the final Transport Rule docket for further information related to these issues. (AA) EPA should initiate a SIP Call for reduced and modified CSAPR NO X Budgets necessary to achieve the 2008 Ozone NAAQS.FIP Revisions

- RTC Febru ary 7 , 2012 Page 196

196 Comment (AA)(1) : Exelon comments that establishing CSAPR phase 2 budgets immediately is both required by law and necessary for sound industry planning, and reference Assistant Administrator Gina McCarthy's September 22, 2011 memora ndum to Regional Air Division Directors regarding the deadline for interstate transport SIPs implementing the 2008 ozone season standard. The Court in North Carolina held that, when establishing cap and trade program deadlines, EPA must establish a deadli ne that will enable downwind states to achieve attainment as expeditiously as practicable and no later than the mandatory date for achieving compliance. Establishing a revised program and completing a rulemaking for a SIP call is clearly practicable befor e the end of 2012 and is therefore required under the Court's reasoning. Initiating a SIP call now would also give states the first ch ance to develop and submit SIPs t hemselves. Also in response to previous comments EPA stated that it would propose a rul e to address transport with respect to the reconsidered 2008 ozone NAAQS as expeditiously as possible after reconsideration is complete. Exelon also comments that establishing budgets for 2015 is essential for sound electric industry planning They point to the Utility Air Toxic Rule, and the need to already begin initial compliance planning for that rule, which could be impacted or impact NO X control decisions. [Letters: Exelon (EPA

- HQ

- OAR

- 2009

- 0491

- 4810) p. 38

- 40]
RESPONSE : This comment is outside th e scope of the revisions proposed and upon which EPA solicited comment. (BB) CSAPR will not have a significant impact on consumer prices. Comment (BB)(1) : CSAPR 's cost impacts are modest and dwarfed by the overwhelming health care savings. Claims that CSAPR will cause increases in electricity rates that will adversely affect the economy lack foundation. Contrary to some claims that EPA has sandbagged the costs, market costs are already lower than EPA estimated. SO 2 allowance that EPA expected would s ell for $1,000/ton sell for $500/ton or less. Because the cost of compliance is less than EPA projected, the impact on power prices will be lower, suggesting that the impact on retail prices will be no greater than, and likely even less than, the 1

- 2% pre dicted by the RIA. Exelon goes on to provide the results of their analysis of the combined impact of CSAPR and the MACT standard in its service areas (Chicago and Philadelphia). The results were that generation rates in 2015 will be less than 2010 on an inflation adjusted basis due in large part to the decline in natural gas prices. [Letters: Exelon (EPA

- HQ

- OAR

- 2009

- 0491

- 4810) p. 30

- 35]
RESPONSE : This comment is outside the scope of revisions proposed and upon which EPA solicited comment. See the fin al Transport Rule docket for further information on these issues. Refer to the Regulatory Impact Analysis for the final Transport Rule [EPA

- HQ

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- 2009

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- 4193] for a benefit analysis and an analysis of the costs of the rule. (CC) IPM statewide heat i nputs for New York must be adjusted upward. Comment (CC)(1) : In addition to the facility controls issues, IPM improperly forecasts electric dispatch in New York. EEANY appreciates the cooperation between the EPA and NYSDEC toFIP Revisions

- RTC Febru ary 7 , 2012 Page 197

197 resolve specific dispatch i ssues, as outlined in the NOPR and Technical Support Documents (TSDs). Those dispatch changes go a long way to correcting the operational differences between IPM heat input projections and historical operations. However, the fact remains that the IPM tot al state projected heat input is approximately 24% less than the average of the last three years. Such a reduction in heat input is not likely in such a short time frame. While EEANY recognizes that the EPA does not have the resources to rerun the IPM mo del, our recommended adjustment to the NYS budget, based on more realistic control technology assumptions, will compensate for this. [Letters: Environmental Energy Alliance of New York (EEANY) (EPA

- HQ

- OAR

- 2009

- 0491

- 4811) p. 3, 8]
RESPONSE : See section 6.3 of this document , below, for EPA’s response to comments comparing state

- level heat input in IPM to historic data. EPA notes that it reviewed comments pertaining to controls and out

- of

- merit

- order dispatch at specific units and made revisions when the information provided met the requirements described in the proposed revisions [76 FR 63868]. (DD) Reliance upon historical operating data significantly under
- predicts current unit dispatch. Comment (DD)(1) : In the case of Fox Energy, reliance upon his toric operating data significantly under predicts current unit dispatch as the baseline period did not reflect normal dispatch conditions. For the first two years of the baseline period (2006

- 2007), the units were coming out of initial startup (and the un its changed ownership due to bankruptcy of the original developer). The remainder of the baseline corresponded with the 2008

- 2010 recession from which power demand in Wisconsin is slowly recovering. For these reasons the baseline period capacity factor o f 11% substantially under predicts the 2011 factor of 29%. Under current conditions the units are dispatched roughly 2.5 times as frequently as anticipated when EPA developed the unit level emissions allocations and that the heat input to allocate allowan ces to Fox Energy should again have been 2.5 times greater than used. If anything a capacity factor of 29% likely underestimates the future operations of the facility due to the Utility MACT and CSAPR. If the Fox Energy units are not allocated additional annual and ozone season NO X (and to a lesser extent SO 2 ) allowances it is not clear that the additional dispatch of the units anticipated by the CSAPR will be possible. There are three potential options to make up for an allowance shortfall: 1) curtail operations; 2) purchase allowances; or 3) install emission controls. None of the three are viable for Fox Energy. Curtailment of operations would undercut the ability to use the cleaner burning Fox Energy units. Given the doubt that a liquid market for allowances will develop in Wisconsin over the next 12 months due to the gap in allowances and historic emissions it is uncertain whether sufficient allowances will be available to cover the short fall. Finally the units already utilize BACT. We request E PA recognize due to factors unique to the in

- service date for the units, as well as the effects of the recession, the baseline period is not representative of normal unit operation. To remedy we ask EPA to allocate additional allowances to Fox Energy cons istent with a heat input equivalent of 29% capacity factor. This would result in the allocation of 116 annual and 79FIP Revisions

- RTC Febru ary 7 , 2012 Page 198

198 ozone seasons NO X allowances, and 6 annual SO 2 allowances. [Letters: Fox Energy Company LLC (EPA

- HQ

- OAR

- 2009

- 0491

- 4815) p. 1

- 4]
RESPONS E : These comments are outside the scope of the revisions proposed and upon which EPA solicited comments. However, EPA issued a N otice of Data Availability (NODA) on January 7, 2011 that had the listed heat input for each unit’s baseline years. EPA took comment on these values and incorporated relevant comments regarding corrected heat input values or corrections due to reporting changes into the final Transport Rule issued in July of 2011. See the preamble for the final Transport Rule and the final Tran sport Rule response to comments document in the docket for this rulemaking. (EE) EPA should reconsider its decision to include Louisiana, Mississippi, and Arkansas in the CSAPR. Comment (EE)(1) : There is no basis for including Louisiana, Mississippi, an d Arkansas in CSAPR. EPA found no cost

- effective emissions reduction available in these states but justified including them in CSAPR based on EPA’s fears that interstate shifts in electricity generation from covered states to Mississippi, Louisiana, and A rkansas would result in “emissions leakage” and increase these states’ actual contribution to downwind pollution in the Houston/Galveston and Baton Rouge areas (see 76 FR 48263). EPA’s concerns are unfounded. Actual emissions data from the Houston/Galves ton area indicates that it achieved attainment with the 1997 ozone NAAQS in 2009 and remained in attainment in 2010. Commenter refers to their Petition for Reconsideration (at 10) in this regard. Further, only last week EPA finalized approval of Louisian a’s request to designate the Baton Rouge area to attainment for the 1997 8

- hour ozone standard. Commenter cites to EPA's press release on this issue dated November 15, 2011 and asserts that EPA should exclude Louisiana, Mississippi, and Arkansas from CSA PR. [Letters: Entergy (EPA

- HQ

- OAR

- 2009

- 0491

- 4820) p. 8]
RESPONSE : This comment is outside the scope of the revisions proposed and upon which EPA solicited comment. However, see the final Transport Rule docket for further information on findings of sta tes’ significant contribution. (FF) Nebraska has not been provided adequate time to submit a partial SIP to re
- allocate state allowances. Comment (FF)(1) : The rule requires states that are submitting SIP revisions to re

- allocate allowances to submit th e revision by April 2, 2012 in order for the allowances to be effective for 2013. However, NE utilities will not know their final allowances until the final revisions to CSAPR is issued in the FR, which depending on comments received may not be until Janu ary or February 2012. This will not provide NE with sufficient time to prepare and submit a SIP revision. [Letters: Nebraska Department of Environmental Quality (EPA

- HQ

- OAR

- 2009

- 0491

- 4780) p. 2]FIP Revisions

- RTC Febru ary 7 , 2012 Page 199

199 RESPONSE : This comment is outside the scope of the revi sions proposed and upon which EPA solicited comment. However, EPA is working closely with states on implementation of the rule and has provided guidance and questions and answers on our web site, as well as model rules for SIP development to the Regions. See the following web page: http://www.epa.gov/crossstaterule/faqs.html. (GG) There are errors in the EPA’s Significant Contribution Tables. Comment (GG)(1) : In the Excel spreadsheet document, Annual PM25 AQAT_rev, Docket ID EPA

- HQ

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- 2009

- 0491

- 4691, there appear to be errors. Specifically, on the worksheet "estimated contribs and DVs," it appears that not all columns were sorted on the same sort key, and/or that some formulas refer to other worksheets that were sorted differently. This results in cal culated average and maximum design values on the "estimated contribs and DVs" spreadsheet that are inconsistent with Tables 2 and 3 of the October 2011 version of the Significant Contribution Assessment Technical Support Document (TSD). The tables in the T SD appear correct. While the TCEQ has no new concerns about the EPA's methodology used in implementation of the significant contribution analysis using the Air Quality Assessment Tool, the discovery of this error does raise questions about the possibility that other, possibly more significant errors lie buried within the spreadsheets. [Letters: Texas Commission on Environmental Quality (EPA

- HQ

- OAR

- 2009

- 0491

- 4782) p. 13]
RESPONSE : Tables 2 and 3 in the Significant Contribution Assessment Technical Suppo rt Document (EPA

- HQ

- OAR

- 2009

- 0491

- 4690) from the proposed revisions rule are sorted in order of decreasing Maximum 2012 base case design value. However, the “estimated contribs and DVs” worksheet and the related worksheets for the various AQAT estimates ( e.g., worksheet “500 CT”) are sorted in order of decreasing Average 2012 base case design value (see the worksheets in the Annual PM25 AQAT_rev, Docket ID EPA

- HQ

- OAR

- 2009

- 0491

- 4691). The site

- by

- site estimates from both sources match up, when sorted accor ding to the same key. Also, note that an additional row is present in the “estimated contribs and DVs” worksheet and the related worksheets for the various AQAT estimates (e.g., worksheet “500 CT”), relative to the “Annual AMMS” worksheet. Thus, a cell f rom row 4 in the “estimated contribs and DVs” worksheet would reference row 3 in the “Annual AMMS” worksheet. The formulas for the cells in the “estimated contribs and DVs” correctly refer to the appropriate cells in the other worksheets. (HH) Commenters refer to comments they have previously submitted in the context of the Transport Rule. Comment (HH)(1) : Commenters refer to their October 2010 comments submitted in response to the proposed Transport Rule and/or their comments submitted in January 2011 in response to the Notice of Data Availability (NODA), noting that they are still relevant in the context of this latest proposed rulemaking. [ Letters: Kentucky Division for Air Quality (EPA

- HQ

- OAR

- 2009

- 0491

- 4797) p. 1; Consolidated Edison Co. (EPA

- HQ

- O AR

- 2009

- 0491

- 4761) p. 1, Attachment A; Luminant (EPA

- HQ

- OAR

- 2009

- 0491

- 4818) p. 13

- 15, Attachments 1, 5, & 6; North CarolinaFIP Revisions

- RTC Febru ary 7 , 2012 Page 200

200 Attorney General (EPA

- HQ

- OAR

- 2009

- 0491

- 4825) p. 1

- 8, Attachment 1; Southern Company (EPA

- HQ

- OAR

- 2009

- 0491

- 4744) p. 4

- 9, Attachment B ; Louisiana Public Service Commission (EPA

- HQ

- OAR

- 2009

- 0491

- 4799) p. 1

- 2; Constellation Energy (EPA

- HQ

- OAR

- 2009

- 0491

- 4769) p. 2; Dominion Resources Services (EPA

- HQ

- OAR

- 2009

- 0491

- 4790) p. 1; Environmental Energy Alliance of New York (EEANY) (EPA

- HQ

- OAR

- 200 9

- 0491

- 4811) p. 1; Edison Electric Institute (EPA

- HQ

- OAR

- 2009

- 0491

- 4795) p. 2

- 3; East Kentucky Power Cooperative (EKPC) (EPA

- HQ

- OAR

- 2009

- 0491

- 4806) Exhibit A; First Energy Corporation (EPA

- HQ

- OAR

- 2009

- 0491

- 4741) Att. 1; Omaha Public Power District (EPA

- H Q

- OAR

- 2009

- 0491

- 4747) p. 3; Utility Air Regulatory Group (EPA

- HQ

- OAR

- 2009

- 0491

- 4823) p. 2, 4, 8; We Energies (EPA

- HQ

OAR

- 2009

- 0491

- 4781) p. 2]
RESPONSE : EPA has responded to previously submitted comments in the context of the final Transport Rule (76 FR 48208). Comment (HH)(2) : Commenters refer to their petition for reconsideration and/or stay submitted in the context of the Transport Rule. [ Letters: Consolidated Edison Co. (EPA

- HQ

- OAR

- 2009

- 0491

- 4761) p. 2, Attachment B; American Electric Power (EPA

- HQ

- OAR

- 2009

- 0491

- 4737) p. 9

- 10; Entergy (EPA

- HQ

- OAR

- 2009

- 0491

- 4820) p. 2

- 4,8, Exhibit J; Nebraska Public Power District (NPPD) (EPA

- HQ

- OAR

- 2009

- 0491

- 4754) p. 1

- 2; Integrys Business Support (EPA

- HQ

OAR

- 2009

- 0491

- 4757) p. 2

- 4; Southern Company (EPA

- HQ

- OAR

- 2 009

- 0491

- 4744) p. 2

- 3, 13, Exhibit A; Municipal Electric Authority of GA (MEAG) (EPA

- HQ

- OAR

- 2009

- 0491

- 4753) p. 1

- 3; Georgia Environmental Protection Division (EPD) (EPA

- HQ

- OAR

- 2009

- 0491

- 4756) p. 1

- 2; Isaak Walton League of America (EPA

- HQ

- OAR

- 2009

- 0491

- 4798) p. 1

- 2 (refers to Northern States Power petition); Southwestern Public Service Company (SPS) (EPA

- HQ

- OAR

- 2009

- 0491

- 4752) p. 2; Gulf Coast Lignite Coalition (EPA

- HQ

- OAR

- 2009

- 0491

- 4805) p. 1

- 2; Luminant (EPA

- HQ

- OAR

- 2009

- 0491

- 4818) p. 4

- 8; San Miguel E lectric Cooperative (EPA

- HQ

- OAR

2009

- 0491

- 4766) p. 1

- 2; City Water, Light and Power (EPA

- HQ

- OAR

- 2009

- 0491

- 4764) p. 2

- 3; CPS Energy (EPA

- HQ

- OAR

- 2009

- 0491

- 4784) p. 3

- 5; Florida Electric Power Coordinating Group, Inc. (EPA

- HQ

- OAR

- 2009

- 0491

- 4772) p. 1

- 3; EME Homer City Generation (EPA

- HQ

OAR

- 2009

- 0491

- 4778) p. 1

- 4; Louisiana Public Service Commission (EPA

- HQ

- OAR

- 2009

- 0491

- 4799) p. 1

- 2 ]; ARRIPPA (EPA

- HQ

- OAR

- 2009

- 0491

- 4765) p. 3; CPI USA North Carolina LLC (EPA

- HQ

- OAR

- 2009

- 0491

- 4813) p. Att. 1; DTE Stoneman L LC (EPA

- HQ

- OAR

- 2009

- 0491

- 4783) p. 3; Homer City Owner Lessors LLC (EPA

- HQ

- OAR

- 2009

- 0491

- 4816) p. 2; Lafayette Utility Systems (EPA

- HQ

- OAR

- 2009

- 0491

- 4807) p. 9; Mississippi Public Service Commission (EPA

- HQ

- OAR

- 2009

- 0491

- 4746) p. 1; Nebraska Department of Environmental Quality (EPA

- HQ

- OAR

- 2009

- 0491

- 4780) p. 1; Northern States Power Company, MN (NSPM) (EPA

- HQ

- OAR

- 2009

- 0491

- 4751) p. 1, Att. 1; Progress Energy (EPA

- HQ

- OAR

- 2009

- 0491

- 4771) p. 2; Topaz Power Group (EPA

- HQ

- OAR

- 2009

- 0491

- 4755) p. 2; Utility Air Reg ulatory Group (EPA

- HQ

- OAR

- 2009

- 0491

- 4823) p. 2, 5, 9, Att.1; We Energies (EPA

- HQ

- OAR

- 2009

- 0491

- 4781) p. 2; Wisconsin Industrial Ratepayer Group (EPA

- HQ

- OAR

- 2009

- 0491

- 4789) p. 2]
RESPONSE : The process for responding to a petition for reconsideration or stay is distinct from the process for responding to comments received in a rulemaking and EPA could not, in this action, grant the relief requested in the petitions. Many of the commenters did not point to aFIP Revisions

- RTC Febru ary 7 , 2012 Page 201

201 particular portion of the petition for reconsid eration and/or stay or to a particular substantive issue they believe is relevant to this rulemaking. Except as specifically noted in response to comments, above, EPA is not addressing information in the referenced petitions in this rulemaking.
SECTION 6 . General Responses
- Other Issues of Concern 6.1) General Explanation of OMOD and Offset Methodologies, including why/how we are offsetting increased generation a) General OMOD Method description: Some commenters (including LPSC and MDEQ) questioned the m ethodology used for determining the amount of out

- of

- merit

- order dispatch generation to add. Some commenters, like LPSC, wrote that a historic average of heat input should be used for units that run for non

- economic reasons.
RESPONSE : EPA disagrees with this suggested approach. For the revisions rules, EPA quantified only the amount of expected immediate

- term future generation from a unit most likely to be driven by non

- economic reasons (specifically, reasons not captured in IPM’s least

- cost dispatch mod eling). These units’ historic operations may have been influenced by regional dispatch economics, which the final Transport Rule’s IPM modeling already considered in projecting future unit dispatch (and therefore projected emissions). EPA believes that it s approach in these revisions rules was appropriately designed to isolate and quantify likely immediate

- term future generation from units for reasons not already captured in prior IPM projections informing Transport Rule budgets. A pure substitution of mo deling projections with historic operating data would, if taken to its logical conclusion across the fleet, yield a future identical to the past, which would defeat the purpose of seeking least

- cost, incremental emission reductions from the power sector in future years. b) Offsetting method Several commenters (including PSEG, LDEQ, LUS, and LCA) provided comments regarding the “offsetting” of increased generation at units due to revisions related to out

- of

- merit

- order dispatch. This offsetting consists of di splacing an equal amount of generation from in

- state combined

- cycle units as was added for out

- of

- merit

- order dispatch reasons
. RESPONSE : EPA is offsetting the additional generation to ensure that the Transport Rule emission projections are consistent with a balance between projected electricity supply and demand. Therefore, increased generation at certain units affected by these revisions must be offset by decreasing generation elsewhere in the previous projections. EPA chose to offset increased gene ration at units with revised operation with generation previously projected to occur at natural gas combined cycle units in the affected state, because these units are often at the margin in electricity supply. EPA believes this approach is reasonable as it maintains the balance between electricity supply and demand while minimizing the offsetting of state budget increases related to the revised operation of units identified by commenters, because combined cycle units tend to have the lowest emission rates of all fossil

- fired units.FIP Revisions

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202 6.2) Comments on Heat Rates, NO X Emission Rates, and SO 2 Emission Rates a) Heat Rates Some commenters (including Entergy) wrote that they believed alternative heat rates should be used for their units, since they believed tho se heat rates were more representative of the units’ operation.
RESPONSE : EPA used a consistent, rational methodology for determining heat rates (see IPM Documentation section 3.8; EPA

- HQ

- OAR

- 2009

- 0491

- 4294). This approach was open for public comment d uring the proposal of the Transport Rule. Using the alternative rates that commenters provided would make the treatment of those units inconsistent with the underlying methodology in IPM. b) Comments on NO X Emission Rates
RESPONSE : See Section 2 “ NO X R ates” in EPA’s Documentation Supplement for EPA Base Case v.4.10_FTransport

– Updates for Final Transport Rule (“Documentation” in the docket to this rulemaking ), released in July of 2011 and available on EPA’s website and in the Transport Rule Docket. Th e NO X rates modeled are based on historic NO X rates reported to EPA by sources themselves in 2009. In most cases, the NO X rate modeled for a unit is the 2009 emission rate itself (without any adjustment). In some cases, the 2009 emission rate is modified to reflect year round operation of a control, future state rule requirement, Low NO X Burner (LNB) installation or an individual or collective emission rate/tonnage requirement imposed by a consent decree. EPA disagrees with commenters’ arguments that NO X rates derived from reported data in 2009 should not be used for emission projections on the basis that they are not sufficiently “representative” emission rates for certain units. The 2009 NO X rates (that served as input assumptions to EPA’s power secto r modeling for the Transport Rule) are derived from reported annual emissions and heat input at each unit in the data set; as such, they reflect an average emission rate outcome spanning EGU operations over that entire year. None of these commenters demon strated why these units would be incapable of achieving an average emission rate in the future that they were shown to achieve on average in previously reported data over a similar timeframe. EPA used 2009 data as it was the most recent emission rate data available at the time of Transport Rule promulgation and constituted the best available data to understand the performance capability of individual units.
For commenters who note that the NO X emission rate in the unit

- level outputs from the Transport Ru le modeling projections is different from that observed in 2009, Section 2 of the IPM Documentation Supplement (noted above) describes how and when the 2009 NO X rates were modified to better reflect the sources’ emission rates in a future year under differ ent policy scenarios. In EPA’s modeling projections of the Transport Rule’s emission reduction requirements for annual and ozone

- season NO X , sources in covered states that did not alreadyFIP Revisions

- RTC Febru ary 7 , 2012 Page 203

203 have a LNB shift to a lower NO X emission rate to reflect the additi on of combustion controls. In other cases, the modeled emission rate is lower than the 2009 reported emission rate in order to reflect increased operation of a control that was not fully utilized in 2009. Finally, a lower emission rate may be indicative of a compliance strategy that is predicted to be most economic to comply with a state rule or other legal requirement (e.g. a collective cap or rate limit for a set of units). In these cases, the sources may chose to respond with a different compliance st rategy than that predicted by EPA, but the emissions consequences are still valid as such reductions are necessary from a source within the set of units to comply with the legal requirements. EPA notes that the vast majority of states are already complyin g with their 2012 and 2014 assurance levels under for annual NO X and ozone

- season NO X under the program, supporting the notion that the NO X emission rates assumptions used in EPA’s modeling are broadly accurate and representative of the power sector fleet. Furthermore, for commenters who note that their unit will not or has no plans to reduce their emission rate to that depicted in EPA’s TR_Final_Remedy scenario, they are under no obligation or requirement to do so. The flexibility of the trading mechani sm on which the Transport Rule relies provides the flexibility for source to use a variety of compliance strategies. Therefore, any source can continue to operate at its current emission rate and still comply with the Rule requirements. EPA does not expe ct and nor does the rule require every unit to operate precisely in the manner that is shown when IPM modeling projections are disaggregated to the unit level. c) Comments on SO 2 Emission Rates
RESPONSE : See Section 4 “Coal Switching

– Bituminous to S ubbituminous” and 5 “Restrictions on Coal Choice in 2012” in EPA’s Documentation Supplement for EPA Base Case v.4.10_FTransport

– Updates for Final Transport Rule, released in July of 2011 and available on EPA’s website and in the Transport Rule Docket. A dditionally, see Section VII.C.2 of the Final Transport Rule preamble for a discussion of coal switching for SO 2 compliance in 2012 and 2014. In addition to this, EPA reiterates two points regarding coal switching at particular units. First, the Transpo rt Rule places no individual emission reduction requirements on units. Regardless of whether EPA’s economic modeling predicts a particular coal switch at a given unit, that unit is by no means expected or required to make that coal switch. There are mult iple compliance options available to each unit under the Transport Rule due to the flexibility of the rule being administered as an allowance trading program. EPA’s modeling projections demonstrate that regional shifts in coal consumption from higher

- sulf ur to lower

- sulfur coal are a reasonable and cost

- effective compliance response to the increased economic incentive under the Transport Rule programs to mitigate SO 2 emissions. The unit level projections, however, in no way dictate any individual unit’s a llowable emissions in the program and the sources have the flexibility to operate in a manner different from EPA’s modeling results for that unit when the projections are disaggregated to the unit level.FIP Revisions

- RTC Febru ary 7 , 2012 Page 204

204 EPA disagrees with commenters’ arguments that indiv idual units’ historic, current, or alleged future coal procurement patterns impose a necessary or sufficient condition for revising state budgets under the Transport Rule programs. As thoroughly demonstrated in the above

referenced modeling documentation, which itself was subject both to peer review and multiple rounds of public notice and comment in the development of the Transport Rule, EPA’s modeling of projected power sector emissions relied on a highly detailed coal supply network that can reliably an d cost

- effectively support the emission reductions required by the Transport Rule programs. Furthermore, EPA’s projections of cost

- effective coal

- switching for Transport Rule reductions fall well within the flexibility of utilities to contract for supply as the program is implemented. In particular, according to EIA data, only 55 percent of the coal delivered to power plants in June of 2010 remained under contact beyond January 2011. In contrast, the IPM modeling projects that only 5 percent of the coal consumption of higher

- sulfur coal in the base case switches to lower

- sulfur categories in the policy case in 2012. Moreover, even the coal supply classified by EIA as under “purchase order or contract” is not necessarily etched in stone, as such contracts can include terms for adjustment. Nevertheless, these data show that the level of coal

- switching shown in EPA projections supporting Transport Rule emission reductions is well below the percentage of coal most recently reported as subject to contracts or purchase orders. 6.3) Comments Comparing State

- Level Heat Inputs in IPM to Historic Data Several commenters (including MPSC, UARG, PSEG, and FCG) made comparisons between statewide historic levels of heat input and IPM projections as a basis for request ing a larger state budget.
RESPONSE : EPA finds these comparisons flawed for multiple reasons, including: ( 1) that it is electricity, not heat input, that is the relevant metric, as more efficient units can produce the same amount of electricity with les s heat input compared to less efficient units, and the IPM model projections show that more efficient units can be run as part of a least

- cost dispatch strategy to achieve cost

- effective emission reductions; ( 2) such heat input comparisons, typically made only for units subject to EPA’s programs, ignore the ability of projected least

- cost generation from units not covered by the Transport Rule, including nuclear and renewable sources, as well as fossil

- fired units less than 25 MW, to meet electricity demand ; and ( 3) comparison to historic performance can be misleading since the projected generation patterns include the impact of the Transport Rule, which was not in effect in 2010. 6.4) Comments Comparing Unit Level Allocations to Projected Emissions
Sever al commenters (including FCG, LUS, and LEPA) submitted comments requesting revisions to their unit

- level allocations or relevant state budgets because they argued that specific units would receive initial allocations representing fewer tons than what the p lant had either emitted historically or was expected to emit in the future by the commenter.FIP Revisions

- RTC Febru ary 7 , 2012 Page 205

205 RESPONSE : As described in the preamble to the final revisions rule and in the Final Revisions Rule State Budgets and New Unit Set Asides TSD in the docket to th is rulemaking , EPA made revisions to state budgets where the commenter provided adequate unit

- level operational information as requested in the proposed revisions rules (76 FR 63868). However, EPA disagrees with commenters who argued for any revision base d on a given unit allegedly receiving inadequate allowances through its initial allowance allocation. As explained in the final Transport Rule, EPA did not base unit

- level allowance allocations on unit

- level projected emissions; instead, EPA quantified un it

- level allowance allocations based on a combination of historic heat input and historic emissions at each unit. The revisions rule is not intended to revise the historic data sets on which unit

- level allowance allocations are based; as such, these comme nts are irrelevant to this rulemaking. 6.5) Comments on allocation methodology, with information on unit operating status and heat input Several commenters (including Topaz Power Group, DTE Stoneman LLC, Northern States Power Company, CPS Energy, and UARG) submitted comments on the allocation methodology as it related to unit operating status and, in some cases, heat input.
RESPONSE : Changes to allocation methodology are out side the scope of the revisions proposed and upon which EPA solicited comm ent . The allocation methodology is described in p reamble s ection VII.D of the f inal Transport Rule. Comments on the use of historic heat input to determine allowance allocation are also out side the scope of the revisions proposed and upon which EPA soli cited comment . EPA issued a notice of Data Availability (NODA) on January 7, 2011 that had the listed heat input for each unit’s baseline years. EPA took comment on these values and incorporated relevant comments regarding corrected heat input values or corrections due to reporting changes into the final Transport Rule issued in July of 2011. If a commenter has a concern about a unit’s operating status under the rule, this can be determined through an applicability determination. A potentially regulated entity can request a determination of applicability from EPA at any time. Criteria for applicability are described in the p reamble s ection VII.B of the f inal Transport Rule. The formal applicability determination process provisions can be found at 40 CFR 97.404(c), 504(c), 604(c), and 704(c).