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DOCKET NUMBER EPA-HQ-OAR-2009-0491

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, 2012
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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 Assumptions

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 Support for Proposed Rule Revisions

Issue 5.2: General Opposition to Proposed Rule Revisions

Issue 5.3: Miscellaneous Issues

Issue 5.4: Out of Scope Issues
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1. Unit-Specific Modeling Assumptions

Issue 1.1: Florida Modeling Assumptions

Points Raised:

(A) Commenter questions increase in Florida ozone season NOX budget without 

modeling to demonstrate it will not cause NAAQS violations. 

Comment (A)(1)

[Letters: Lakeland Electric (EPA-HQ-OAR-2009-0491-4770) p. 1-2]

: EPA is proposing to allocate Florida utilities with 819 additional ozone season 

allowances for 2012 and 2013 through this proposal 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 contribution 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 significant 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 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 of 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 for this rulemaking).

(B) Progress Energy's Crystal River nuclear unit 3 will be on extended repair 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 Energy 
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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 allocate 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 allocated an additional 819 tons for both 2012 and 2014. [Letters: Florida Electric 

Power Coordinating Group, Inc. (EPA-HQ-OAR-2009-0491-4772) p. 7-8; Progress Energy 

(EPA-HQ-OAR-2009-0491-4771) p. 1]

RESPONSE: See section IV of the preamble to the final Revisions Rule (76 FR 48208, August 

8, 2011), where EPA responded to this comment.

(C) There are significant errors in EPA's unit-level NOX emission rate assumptions for a 

number of Florida units.

Comment (C)(1): As the Florida Electric Power Coordinating Group (FCG) noted in its 

September 30, 2011, letter to EPA, there are significant errors in EPA's unit level NOX emission 

rate assumptions for a number of Florida units. Several of EPA’s NOX rate inputs to the model 

are off by as much as 100% and are clearly unachievable and erroneous. The corrected NOX

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 levels. The result of these corrections when conservatively using EPA's projected heat 

input is an increase of 3,423 tons of ozone season NOX emissions from EPA's base case 

projections. EPA should review carefully the FCG corrections, re-run the modeling if necessary, 

and accordingly increase Florida's 2012 and 2014 ozone season NOX 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-HQ-OAR-2009-0491-4772) p. 

5-6; Progress Energy (EPA-HQ-OAR-2009-0491-4771) p. 3]

RESPONSE: See section 6.2(b) of this document for information addressing NOX emission 

rates. A look at recent historic data submitted by Florida sources themselves illustrate the 

commenter misunderstands the compliance picture for the State of Florida and the significance 

of the impact that the NOX 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 NOX, 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 reasonableness of EPA’s assumed NOX emission rates applied to projected ozone-season 

NOX emissions for Florida under the Transport Rule program. 
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Comment (C)(2): Commenter (FCG) provides supplemental comments to clarify and updates 

their previously submitted 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 

Florida 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 represents 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 facility 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 ozoneseason NOX 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. (EPAHQ-OAR-2009-0491-4860) p. 1-2, Attachments – all pgs]

RESPONSE: This response addresses both the comment of FCG and the next comment of 

Progress 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 developing state budgets, 

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 uses 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.) 
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Data from the EIA confirms that the 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 power 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 capacity 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 additional 170 

tons per day of NOX emissions. [Letters: Progress Energy (EPA-HQ-OAR-2009-0491-4771) p. 

3]

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 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 1.41 billion cubic feet per 

day without even accounting for the needs 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 NOX emission 

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 NOX emissions. Because this is scattered across 

the state it is appropriate to utilize average emission rates, rather than unit specific rates Further 
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0.1 lb/mmBtu is a conservative estimate for an average NOX emission rate for the natural gas 

fired generation being replaced given most natural gas fired generation emits NOX 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 NOX per day 

in a worst-case scenario (i.e., 1,457,940 mmBtus and 0.3 lb NOX/mmBtu). There is no constraint 

in EPA's IPM model that addresses this scenario, and it is imperative 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 NOX ozone season allowances for 2012 and 2014. 

[Letters: Florida Electric Power Coordinating Group, Inc. (EPA-HQ-OAR-2009-0491-4772) p. 

6-7]

RESPONSE: See response to comments 1.1(C)(1) and (2) above.

(E) EPA fails to account for transmission line import constraints, and must increase 

Florida's ozone season NOX budget 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 Reliability 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 transmission 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 imported. 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 be 

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 NOX budget.

The additional ozone season NOX emissions can be estimated based on available capacity 

weighted 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 the most base 

generating capacity, available capacity weighted averages are biased towards units with the most 
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generating capacity after already generating some baseline amount. In this case, the available 

capacity weighted FRCC region average heat and emission 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 capacity 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 toward 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 NOX to meet demand. Thus EPA must increase 

Florida's ozone season NOX budget by 4,240 allowances to account for this EPA modeling error. 

[Letters: Florida Electric Power Coordinating Group, Inc. (EPA-HQ-OAR-2009-0491-4772) p. 

4-5]

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. This 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 derived 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 NOX emissions and NOX 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 NOX 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 NOX 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 NOX emissions from 94,000 tons in BC_P_12 to 41,700 tons in BC_F_12. EPA 
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did this by reducing heat input by almost 150 TBtu and making some adjustments to emission 

rates, as shown in the following table.

Scenario Heat Input (TBtu) Seasonal NOX (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 NOX emissions, EPA may have incorrectly 

modeled 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 those SCRequipped 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 NOX

will come from coal-fired EGUs. In fact, however, in 2010, only 56.6% of the state’s ozone 

season NOX 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 seasonal NOX emissions than are really occurring and 

this, in turn, has resulted in EPA’s predicting that EGU NOX emissions from Florida sources will

have higher impacts on ozone season concentrations downwind than are actually occurring.

In addition, errors were made in the parsed IPM files concerning the NOX 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 

operational full time and is designed to reduce NOX (and is reducing NOX) 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 NOX 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 historically 

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-HQ-OAR-2009-

0491-4823) p. 43-44]

RESPONSE: See response to comment 1.1(C)(1) above regarding general application of historic 

NOX 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 final Transport Rule preamble 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 sufficient to cover the O&M cost of operating the 

control. Furthermore, the alleged discrepancies regarding “dispatchable” SCR operation in the 
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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 predicting that EGU NOX

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 Transport 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 Transport 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 of 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 for this rulemaking).

(G) Must-run requirements 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 NOX. 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 must 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 

Lansing 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-HQ-OAR-2009-0491-4772) p. 6]

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 

operational requirement that FCG describes. (see 

“WebReady_ParsedFile_TR_Remedy_Final_2012,” EPA-HQ-OAR-2009-0491-4431)
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Issue 1.2: Louisiana and Mississippi Modeling Assumptions

Points Raised:

(A) EPA's proposed revisions in IPM to account for local constraints 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 NOX 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 actual 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 address reliability and local transmission constraints. [Letters: Mississippi Public 

Service Commission (EPA-HQ-OAR-2009-0491-4746) p. 1-2]

RESPONSE: EPA reviewed the comments and information submitted by Entergy, the operator 

of those units, which resulted in the revisions to the Mississippi budget described in the preamble 

for the final Revisions Rule. Entergy specifically identified the level of generation required for 

voltage support and grid stability; some historic generation from these units may have been 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 more 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 NOX emissions by 

approximately 70% from the actual 2010 ozone season emissions, correlating 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 capacity 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 in 2010, continue to run as needed, and are projected to 

operate at capacity factors important to system operations and reliability in 2012. However, EPA 
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has offered no revisions to SMEPA's units. Commenters provide additional discussion on these 

facilities, 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 required 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 should accurately reflect the importance and role of 

local generation. [Letters: Mississippi Public Service Commission (EPA-HQ-OAR-2009-0491-

4746) p. 2-4; South Mississippi Electric Power Association (EPA-HQ-OAR-2009-0491-4763) p. 

2-3]

RESPONSE: EPA considered 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 described by MPSC and SMEPA (see 

“WebReady_ParsedFile_TR_REmedy_Final_2012,” EPA-HQ-OAR-2009-0491-4431). The 

analysis also found the one unit at plant Moselle was subject to out-of-merit-order dispatch to 

provide voltage support and regulation as described by 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 method 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 NOX emission budgets 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 result 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 of 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-HQ-OAR-2009-0491-4786) p. 1]

RESPONSE: Revisions to the operation of units in Mississippi that are being finalized in the 

final Revisions Rule, based on information that meets requirements described in proposed 

revisions [76 FR 63868], can be found in the preamble and in the TSD called, Final Revisions 

Rule State Budgets and New Unit Set-Asides. For EPA’s response to comments on the rationale 
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behind the out-of-merit-order dispatch generation revisions, see section 6.1a, below, 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 utilities. 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 has been historically 

committed (e.g., IPM 2006 estimates are 130 trillion BTU and 12,940 tons NOX for ozone 

season 2010 but the actual data reported to CAMD are 205 trillion BTU and 16,089 tons NOX) 

and that the IPM Base Case models should reflect the operation 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

RESPONSE: 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 dispatched 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-run 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 emissions budget and the calculated net change reflects a "material 

impact," EPA should take the necessary steps to adjust the emissions budget so that these "mustrun" units may operate without penalty. In recalculating Louisiana's NOX 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 identify 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 brownouts that the revision to the rule is intended to avoid. [Letters: Louisiana Department of 

Environmental Quality (EPA-HQ-OAR-2009-0491-4787) p. 1]
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RESPONSE: EPA reviewed comments related to units dispatched out-of-merit-order that met 

the requirements described in the proposed revisions [76 FR 63868]. Revisions to units in 

Louisiana that EPA is finalizing are in the final 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 the 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 NOX 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 net 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 frequency 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 

revisions 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 level 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 reliability in what EPA has already recognized as a 

uniquely constrained geographic region. If EPA proceeds with this rule, the Agency should reconsider its position on this issue, particularly during the critical 2012-2014 transition period and 

grant additional 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-merit-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 Napolitano 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 made 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. 
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(E) Supports the increased allocations for must-run units, but there should be no offset 

or a reduced offset 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 constraints 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 the 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 PURPA 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 unless 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. All 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 the 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-OAR-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 outof-merit-order dispatch generation, see section 6.1b, below, in this document. EPA agrees that 

given the operating characteristics of cogeneration units, they should not be used for offsetting 

under this approach and has adjusted its method accordingly, as described in the preamble 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 regulated electric utility and serves Louisiana exclusively. 

Cleco Power operates four power plants with 3,843 MW of nameplate capacity. On September 
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7, 2011, Cleco Power issued a Request for Proposals for Contractual Resources to Meet the 

CSAPR Beginning in May 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 

and 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 NOX 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 Association (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/site574.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 consider 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 the 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 

NOX emissions. LUS requests that EPA increase the ozone season NOX 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]

Comment (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 CSAPR. 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]
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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 supported (see the preamble for the final 

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 ozone 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 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-HQOAR-2009-0491-4834); paragraphs 58-61.) and did not find the analysis a credible basis for 

making 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. 

Comment (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 Rodemacher 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 Rodemacher 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 they intend to supply their own native load with 

limited NOX ozone season allowances. As such, LEPA must rely on its own generation fleet, 

which is now limited by available NOX allowances. CSAPR has changed market conditions and 

made economic purchases unavailable, 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 LEPA to 

increase the level of generation from their fleet to well above historical amounts. As such, 

LEPA will need 345 additional NOX ozone season allowances to provide affordable power. 

[Letters: Louisiana Energy and Power Authority (EPA-HQ-OAR-2009-0491-4864) p. 1-2]
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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 limit 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 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 11, 13-

20). 

(H) EPA should correct the assumptions made in its IPM modeling and re-run the model 

for Louisiana, Mississippi, 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 

Arkansas) 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 it 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 found 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 Company 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 reductions, 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 

correcting 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 inadequate 
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state emissions budgets threaten to undermine 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 the 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 Data 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 finalization 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 

programs 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 states 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 include 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 

displaced 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 cycle 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 their 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’ 

emissions 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 to account for noneconomic 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. 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 
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pertaining to heat rate and emission rate changes, please see section 6.2a and 6.2b, below, in this 

document. 

(I) Comments on Dispatch of Units in Louisiana

Comment (I)(1)

are subject to dispatch by the Southwest Power Pool, and LUS has historically operated

: Errors were made in the parsed IPM files concerning the operation of – and 

NOX 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 Bonin 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 have 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 NOX emissions from – Louisiana Electric & Power Authority’s (LEPA’s) Houma

and Morgan City EGUs. 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 assumptions, the heat inputs

for Louisiana sources and ozone season NOX 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 NOX (tons)

BC_P_12 224.9 21,200

BC_F_12 235.1 13,400

CEMS_2010 336.1 23,200
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[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 gas-fired units as non-economic/out-of-merit units

: In evaluating projected NOX 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 constraints 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 NOX emissions from those sources are significantly below what is

expected in 2012. Some 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 Revisions, 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 the 

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 allowance 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 final Transport Rule.

While the Marchetti report attached to UARG’s comments 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 to 
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run to provide voltage support 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 Rule 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 leastcost 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 by 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. 
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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 penalties 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 costeffectively 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 Energies’ 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 allowances to cover the emissions the unit 

actually produces. Moreover, local reliability conditions are recognized in allocating 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 reliability uses.

Additionally, EPA reviewed the information provided by We 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 sufficiently in the IPM analysis 

of the final Transport Rule [“WebReady_ParsedFile_TR_Remedy_Final_2012,” EPA-HQ-OAR2009-0491-4431] such that EPA’s previous projections are consistent with the information 

provided by the commenter to satisfy this plant’s minimum 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 systems

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

installed 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 – by
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2012. BC_F_12, however, erroneously assumes that WFGDs will be installed on all four

units at Monroe 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 operation at Monroe 2.

In the PTR, errors were also made in the parsed IPM files concerning the SO2

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 BC_P_12, EPA

made some corrections to take fuel blending into account, but the SO2 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 are burning

100% subbituminous coal.

Rulemaking comments also pointed out errors made by EPA (in BC_P_12)

concerning the SO2 and NOX emission rates for Trenton Channel Units 16-19 and 9A. In

BC_F_12, however, EPA continues to use unrealistically low SO2 and NOX emission

rates for these units.

Errors were also made as to the NOX and SO2 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-NOX burners and overfire air (LNB/OFA) and that Unit 2’s NOX

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 noted in BC_F_12 that Unit 2 is not

equipped with LNB/OFA, but failed to correct the NOX emission rate for Unit 2. Thus

BC_F_12 erroneously uses a NOX 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 SO2 emission rate for Eckert Unit 2. Although (as pointed out in

rulemaking comments) the SO2 emission rate for Eckert Unit 2 (as reflected in actual SO2

emissions data for the plant) is about 0.53 lbs/mmBtu, EPA continued – in BC_F_12 – to

use an SO2 emission rate of 0.94 lbs/mmBtu. A similar SO2 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 SO2 emission rate of 0.94 lbs/mmBtu for Erickson 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-OAR-2009-

0491-4823) p. 47-48]

RESPONSE: As noted in the final Transport Rule TSD on Significant Contribution and the 

preamble for the final Revisions Rule, appropriate budget adjustments have been made to reflect 

the timing on control installation at the Monroe Power Plant. In regards to NOX emission rates, 

see section 6.2b, below, of this document. In regards to SO2 emission rates, see section 6.2c, 

below, of this document. For SO2 emission rates, EPA notes that, like NOX emission rates, that 
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the future emission rate values projected take into account 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 through 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 

NOX budget (e.g., to correct the assumption that OPPD's Nebraska City Station Unit 1 

is equipped with SCR (since this unit 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 SO2 emissions of approximately 256 tons per year, reflecting an 

SO2 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 SO2 emissions of 2,300.7 tons and heat input of approximately 5,689,332 mmBtu. This 

calculates to a SO2 emissions rate of approximately 0.81 lb/mmBtu, which indicates use of low 

sulfur PRB coal without scrubber controls. As such, the SO2 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 SO2 budget (a 3% increase). [Letters: Omaha Public Power District (EPA-HQOAR-2009-0491-4747) p. 1-2]

RESPONSE: EPA is finalizing revisions to the Nebraska 2012 and 2014 SO2 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 SO2 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 SO2

budgets 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 

SO2 emission rate for these two units was assumed to be 0.06 lb/mmBtu, but should be 0.08 
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lb/mmBtu (i.e., the lowest SO2 emission rate that EPA assumed for any units firing 

subbituminous coal equipped with dry scrubbers). These changes would increase the Nebraska 

state SO2 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 Nebraska state SO2 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 of assumptions that went into determining the 

Nebraska state NOX 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, including 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 NOX budgets should 

go into effect in 2014, not 2012. [Letters: Omaha Public Power District (EPA-HQ-OAR-2009-

0491-4747) 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 Transport Rule 

provides flexibility of an emissions 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 final Transport Rule discusses the timing and feasibility of 

Low NOX 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 regulations or economic drivers outside of the Transport Rule. EPA also notes 

that the state is already operating at levels less than its NOX assurance level and close to the state 

budget. The level of current emissions in the state illustrates 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 SO2 control. This unit has no SO2 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 for 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 

SO2 and NOX are lower (by 6,287 and 1,771 tons/yr respectively) than the EGU emissions EPA 

claimed it modeled as part of its 2014 Remedy Case. The proposed revised emissions allocations 
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for Nebraska do not account for these errors, and EPA should correct these errors and revise the 

Nebraska allocations accordingly. [Letters: Nebraska Public Power District (NPPD) (EPA-HQOAR-2009-0491-4754) 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 SO2 controls in place by January 1, 2012, but in fact those units are subject 

to a consent decree that does not require such controls until December of 2012. This data error, 

if corrected, would raise Wisconsin’s state budget of SO2 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 identify additional errors in the 2012 and 2014 remedy files for 

Wisconsin that EPA has not yet corrected. [Letters: Intergys Business Support (EPA-HQ-OAR2009-0491-4757) p. 2-4]

RESPONSE: This comment simply points 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 

2012, EPA is only showing retrofits on two units as operating for the entire year. For example, 

2010 SO2 emissions for the facility were approximately 12,000 tons. In spite of four units 

gaining controls at the facility during 2012, EPA is only forecasting 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 for 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 choose given the flexibility of the trading program 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 being planned to be online in 2012, the controls are 
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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 State 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 SO2 in 2012, but WPSC's total SO2 allowance allocation under the 

rule in 2012 is 16,137 (increased to 16,303 under the proposed revision), which means its 

assurance cap will be 19,042 tons of SO2 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 subject 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-HQ-OAR-2009-0491-4757) p. 2-4]

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 flexibility 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 

the 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 flexibility 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 NOX program also require adjustment of the Wisconsin ozone-season NOX

state budgets. In other words, Wisconsin and WPSC should receive additional allowances under 

the ozone-season NOX program for the same reasons that additional allowances will be allocated 

to these sources for the annual SO2 and NOX 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 NOX 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 the Wisconsin budgets, EPA notes that the state is 

already operating at or below its budget level for annual and ozone-season NOX. For SO2, no 
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additional advanced pollution 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 SO2 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 themselves, bring the state’s emissions below the state 

assurance level and possibly below the state budget for SO2.

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 supply 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 recent 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 

operation 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 operation 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 based 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 operation, 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 actually 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-HQOAR-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. Therefore, these units are included in the final 

IPM remedy run. The commenter is likely assuming that the only units included are in the run 
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are those listed in the parsed results. However, this is a misconception. The parsed results do 

not show all units, 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 

questioned.

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 revisions 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 likely 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 provided 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; Absorber, 

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-2009- 0491-4762) p. 4]

RESPONSE: EPA does not assume the scrubber at Lansing Unit 4 is installed 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 multifactor 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, whereas 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 occur, 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 already 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_12 
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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 for 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 NOX 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 SO2 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 

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 reflect these late changes 

to the underlying data and related rule assumptions. [Letters: We Energies (EPA-HQ-OAR2009-0491-4781) 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 

requirements. 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, because 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 

Edgewater 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 unit 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 budgets. 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 still assuming SO2 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 not 
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reflect SO2 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 units. Further, in developing 

Wisconsin NOX 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 NOX emissions under CSAPR. 

Therefore, assuming SCRs at Valley is incorrect. WDNR recommends that emission budgets 

through 2014 reflect the current NOX 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 state 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 NOX RACT emission requirements starting May 1, 2013. WPL originally 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 in-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 NOX emission rate data for all Edgewater units in Table 

2 of their letter. Commenter observes that after the SCR, the NOX emission rates for units 3 and 

4 are attenuated to reflect levels consistent with good operation and combustion efficiency. 

[Letters: Wisconsin Department of Natural Resources (EPA-HQ-OAR-2009-0491-4824) p. 2-3]

RESPONSE: This comment suggest a budget decrease, not an increase. EPA modeled a 2012 

and 2014 NOX 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. However, 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.
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Comment (D)(5): Selective Catalytic Reduction (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 service 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 

considered 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 NOX and SO2

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 NOX 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 SO2 and NOX 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 of 

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 SO2 emission rate 

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 Street 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 sulfur 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 

emission rate for South Oak Creek is warranted until the committed wet scrubbers come online. 

The corrected SO2 emission rates for JP Madgett and South Oak Creek reflect 2010 and 2011 

CAMD reported emissions rates. EPA should adopt the corrections summarized 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]
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RESPONSE: See response in section I.3(B) above regarding coal switching and SO2 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 SO2 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 ultralow sulfur coal does not appear to 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 SO2 emission 

rate projections.

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 current 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: Wisconsin Department of Natural Resources (EPA-HQ-OAR-2009-0491-4824) 

p. 5]

RESPONSE: See response I.3(B) above regarding coal switching and SO2 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 

SO2 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 ceiling. 

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]
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RESPONSE: First, EPA notes that there are no unit level requirements under the Transport 

Rule; sources are free to comply how they best see fit. Furthermore, with the reductions 

expected from the Nelson Dewey and Alma fuel switches along with the reduced emissions from 

scrubbers at Genoa Unit 3 and South Oak Creek Facility, the total Wisconsin SO2 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 allowances for future years.

(F) EPA should adjust the Wisconsin budget to reflect requested corrections to unitspecific data and assumptions.

Comment (F)(1): The EPA budget corrections in the proposed rule increase SO2 emissions in 

2014 compared to the finalized CSAPR emission budgets. The NOX emission budget increases 

in both 2012 and 2014. These budgets assume that the same corrections will be reflected in the 

ozone season NOX emission budgets. Commenter provides a summary table (Table 7) with the 

2012 and 2014 budgets for both SO2 and NOX 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 SO2 emission budgets increase in both 

2012 and 2014 when compared to EPA's proposed CSAPR budgets. For NOX 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 that they proposed as an attachment to 

their letter (Appendix A). [Letters: Wisconsin Department of Natural Resources (EPA-HQOAR-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 market 

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) Commenter 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 finalized 
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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 SO2 scrubber reductions are first applied to a 2015 emissions budget and not 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 approach 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 section VII of 

the final Transport Rule preamble 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 found that states 

were still able to meet their 2014 SO2 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 option 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 SO2 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 SO2

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, utilities will need to reduce emissions at all generating units and 
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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 fight 

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 costeffective installation approach. [Letters: Wisconsin Department of Natural Resources (EPAHQ-OAR-2009-0491-4824) p. 9]

RESPONSE: EPA has demonstrated in both rulemakings that utilities will have adequate time 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 of 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 systems 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

2012. In BC_F_12, however, EPA appears to assume erroneously that Valley will be

operating SCR systems to reduce NOX emissions from the Valley units.

Errors were made in the parsed files concerning installation and operation of SCR

systems at the James Madgett 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.
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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 SO2 emission rate achievable at

Weston Units 1-3. The actual SO2 emission rate that those units achieved in 2010 was

0.56-0.57 lbs/mmBtu. This emission rate is accurately reflected in BC_P_12. In

BC_F_12, however, EPA increased the SO2 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 NOX 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 SO2 emission rates for

Edgewater Units 3-5. In BC_F_12, EPA assumes SO2 emission rates will be higher than

the units’ actual SO2 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-

0491-4823) 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 response to Wisconsin stakeholder comments 

above.

(I) Comments Relating to New Units in Wisconsin.

Comment

2011. Under the terms of CSAPR, both units should receive SO2 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 operation 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 after January 1, 2010, it should receive substantially 
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higher SO2 and NOX 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 from 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. Therefore, EPA classified it as an 

existing unit. EPA treated unit 2 as a new unit as noted by the commenter. Regarding DTE 

Stoneman, changes to the allocation methodology based on repowering and heat input are 

outside 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 Modeling 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 proposal 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 required 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 Group (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 have 

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 SO2 emissions rate of 2.19 

lbs/mmBtu; however, the unit reports to the Clean Air Markets Program database an average SO2

emissions rate of 2.45 lbs/mmBtu. PSEG respectfully requests that EPA review the emissions 

rate it used in revising the allocation to the sources under the proposed revisions to the Transport 
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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.

Comment (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 correction. 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 

dispatch. 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 noneconomic factors are causing EPA's IPM model to underestimate the utilization 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 budgets. 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 underestimated 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 levels. 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 NOX budget, 

EPA then proposes to subtract 775 tons for a net increase of only 112 tons to account for out-ofmerit-dispatch. We disagree with this proposed methodology.
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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 New 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 emission 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 model 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 IPM 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 their 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 for 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 section 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 preamble of the final Revisions Rule, which excluded cogeneration units from being 

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. 
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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 substantial 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 uses 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 because 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 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. 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 SO2 from these units from 2012 base case to 2014 remedy case. 

Based on information and case study results presented by NRG, commenter (NY DEC) believes 

that the Huntley and Dunkirk units can realize an SO2 reduction of approximately 50% when 

using the Trona and powder-activated carbon (PAC) injection system that is currently installed 

on those units. NRG has completed a performance test indicating that these technologies reduce 

emissions of SO2 by over 55% This test was done when the units were newly installed under 
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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 Department of Environmental Conservation (EPA-HQ-OAR-2009-

0491-4788) p. 2]

RESPONSE: EPA intends to increase New York’s 2012 and 2014 annual SO2, annual NOX, and 

ozone-season NOX budgets, in a separate action, based on comments received on the revisions 

rule demonstrating 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 this 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 SO2, annual NOX, and ozone-season NOX. 

Commenters also identified two facilities, Dunkirk and Huntley, with existing dry sorbent 

injection (DSI) technology for which EPA had assumed an SO2 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 SO2 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 SO2/mmBtu when co-firing natural gas 

with the coal already utilized. Unit 3 is also capable of meeting the same SO2 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 SO2 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 these units (and the Huntley and Dunkirk units) are incorporated, New York's 

budget would increase by 5,851 tons SO2 in 2012 and 8,064 tons SO2 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 SO2 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 advanced 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 region and have a higher economic incentive to reduce their SO2 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 anticipates in response 

to the SO2 emission limitations in 2014. However, as EPA noted in the final Transport Rule, 
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these particular controls are illustrative unit-level results from the disaggregation of modeled 

projections of least-cost compliance with state budgets; 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 compliance 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 pollution 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 generation at its four East River units. EPA is proposing to adjust the New York 

budgets for SO2, annual NOX, and ozone season NOX 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 includes 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 

listed 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 these as only electric generating units. In addition 

IPM uses a much higher SO2 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 for 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. This approach also has the 

benefit of being the same methodology that EPA used to calculate the pro-rata share of heat input 
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on a statewide basis for budget allocation. Calculations provided in Table 1 of the comments 

indicate that an additional 107 SO2 allowances, 895 annual NOX allowances, and 465 ozone 

season NOX 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 steam 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 service 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 the 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 City 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 on 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 current 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 constraints it is more 

appropriate to account for the fact that New York units are implementing control strategies that 
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are cost-effective to meet the recently revised NOX 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 conservatively 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 NOX “reasonable” emission rates used the following general assumptions. New York’s 

revised NOX 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 NOX emission rate for the last five 

years was calculated. If the minimum rate was greater than the NOX RACT limit then the NOX

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 NOX RACT rates because even at 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 the 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 NOX rates for the coal-steam 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 startup, 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 damage 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 for 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 several years that reflect those operating conditions, EEANY 

proposes an allocation based upon expected unit-specific alternative NOX RACT emission rates 

of 0.24 lb. NOX per mmBtu for Somerset, Cayuga 1 – 0.20 and Cayuga 2 – 0.38.

The following general assumptions were used to estimate "reasonable"SO2 emission rates. For 

units where the minimum SO2 rate measured over the last five years was less than 0.5 lbs SO2

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. SO2 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 SO2 rate 50% below the 0.8 lbs. SO2 per mmBtu coal currently purchased. There 

was a limitation assumed for facilities with FGD technology. The limit should not be set lower 
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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 "reasonable" 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 effective. 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. SO2

per mmBtu 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 budgets for NOX 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 SO2 budget is higher than the proposed revised budget by 6,144 tons and the reasonable 

2014 SO2 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 Energy 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 has 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. 
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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 efforts 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 

NOX 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 SO2 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 integrated 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 SO2

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 NOX

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 accurate emissions. [Letters: Texas 

Commission on Environmental Quality (EPA-HQ-OAR-2009-0491-9002) p. 21-23]

RESPONSE: EPA notes that the revised assumptions in SO2 emission rates at certain Texas 

EGUs at issue in this revisions rulemaking would actually yield increased projected SO2

emissions from Texas compared to the analysis conducted in the final Transport Rule showing 

that Texas significantly contributes to downwind nonattainment of the PM2.5 NAAQS. In other 

words, insofar as these “errors” may have 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 NOX 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 NOX

rates for Eastern Texas, Dallas-Ft. Worth area, and Houston/Galveston.
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Comment (B)(2): EPA is still significantly over-predicting point source NOX emissions for 

Texas in 2012 and 2014 by at least 70,000 tons per year which can lead to faulty conclusions 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 NOX 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 NOX emissions from federally 

enforceable controls measures such as the NOX Mass Emission 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 made the corrections as was indicated in the Response to Comments. However, 

the EPA’s projected non-EGUs point source NOX emissions for 2012 in the final rule are 72,500 

tons greater, almost 38%, than the actual 2009 non-EGUs point source NOX emissions inventory 

for Texas. Commenter provides additional discussion and a graph entitled “Texas Point Source 

Non-EGU Annual NOX Emission Inventory Trends” to support their point on this issue. 

[Letters: Texas Commission on Environmental Quality (EPA-HQ-OAR-2009-0491-4782) p. 2 

(cvr), p. 12-13]

RESPONSE: Annual and ozone-season NOX 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 suggests a conservative prediction (i.e., one 

that is 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 the 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 response to comments on the CSAPR proposal, EPA received 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 NOX 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 2012 and 2014. The NOX 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 updated cement kiln projected emissions for 2012 and 2014. 

The cumulative impact of these adjustments resulted in 27,000 tons less non-EGU NOX in Texas 
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in 2012 compared to the 2005 CSAPR base case. In addition, annual and ozone-season NOX

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). 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.

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 alternative 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 docket 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 were 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.gov/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-2009-0491-4523). 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 without 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 Quality (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 

emissions 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.
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Comment (C)(1): EPA should adjust the Texas emissions budgets to account for several "mustrun" 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 provides 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 generation 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 described 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 revise 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 and 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 SO2 FGD scrubbers. However, the proposed additional 

70,067 tons of SO2 allowances for the Texas SO2 emissions budget do not address the TCEQ's 

concerns regarding the feasibility of such substantial reductions in SO2 emissions in an 

unprecedented short period of time (which could endanger the power grid reliability in Texas). 

Even accounting for the SO2 FGD scrubbers that have recently come on-line, the TCEQ 

estimates that approximately 120,000 tons of SO2 reductions will still be required from Texas 

EGUs in 2012. The TCEQ still has significant concerns that forcing Texas EGUs to make such 

significant SO2 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. Commenter 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 Assistant 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 as a 

whole. Also, it is not expected that any SO2 allowance trading among the Group 2 states will be 

sufficient to cover the expected SO2 reductions necessary in TX to meet the revised SO2 budget 

by 2012, despite the proposed delay of the assurance provisions and variability limits until 2014. 
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[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 the least-cost option for many Texas utilities would be to sustain a multiyear trend of switching to lower-sulfur sub-bituminous coal. Energy Information Administration 

(EIA) data shows that Texas lignite-burning units have significantly increased their level of subbituminous 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 accomplished 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 SO2 and 

NOX that they emit during the annual compliance period, and until December 1 to demonstrate 

that they hold sufficient allowances to cover their NOX emissions during the ozone season 

compliance period.

Luminant makes its claims based on a compliance strategy that rests on two mistaken 

assumptions: (1) That a source may not emit more than its initial allowance allocation; and (2) 

that 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 of Sam Napolitano dated October 13, 2011, 

filed in support of EPA's opposition 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 rulemaking (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 erroneous assumptions about planned and 

existing scrubbers at Texas EGUs. EPA proposes to revise Texas’s SO2 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 overestimated 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 

proposed 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, EPA assumes an emissions rate of 0.58 

lbs/mmBtu, which results in a proposed adjustment of 26,359 tons of SO2. However, the 

emissions rate used by EPA (0.58 lbs/mmBtu) is based on the assumption that these units will 
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burn “super-compliant” Powder River Basin (“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 actually available, is 0.80 lbs/mmBtu. This correction to EPA’s calculation results in 

a necessary adjustment of 44,609 tons SO2 as to the three nonexistent scrubbers, not 26,359 tons 

as proposed. The total revision to Texas’s SO2 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 success purchasing and burning such fuels. These 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 

consistent 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 the

claims submitted by this commenter, who does not own or operate these facilities 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 in 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 New 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 SO2 in 2012, EPA wrongly assumes that certain Texas units are, or will 

by 2012 be, equipped with selective catalytic reductions systems or “SCRs” to control NOX

emissions. EPA recognizes its mistake in this regard for other States (i.e., Michigan, Nebraska, 

Wisconsin, and New Jersey) and increases those States’ NOX budgets accordingly. See 

Revisions 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 NOX emissions rates of 0.05 lbs./mmBtu, which can only 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 their NOX 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 identified, results in an increase in the Texas annual NOX budget of approximately 

3,619 tons and seasonal NOX budget of 1,956 tons. Commenter provides supporting information 

in Attachment 8 to their letter). EPA should make these revisions to the Texas NOX budgets, as 

it did to the NOX 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]
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RESPONSE: EPA did not assume SCRs were present at these units in its modeling inputs (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 NOX emissions as a response to non-Transport Rule requirements or incentives (e.g., state 

rule 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 modeling illustrate much higher assumed emission 

rates at these units (see http://www.epa.gov/airmarkets/progsregs/epa-ipm/transport.html). The 

emission rates, in most cases, approximate reported emission rates at the facilities. For example, 

the emission rate modeled at Pirkey is 0.16 lb/mmBtu and the actual 2010 NOX 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 Documentation Supplement for EPA Base 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 types of retrofits and 

noted that where they are in response to state rules or legal requirements that apply 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. 

However, 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 valid 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 

incorporated by reference in Luminant’s comment to which EPA will respond in a separate 

action). The NOX 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 budget with no 

additional NOX reductions if it chose a compliance strategy of allowance purchase. Moreover, 

the state could likely comply with its NOX and ozone season NOX budget levels through simply 

operating its new generation and operating its existing NOX 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 a 
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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 

stated 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. Commenter 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 SO2

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 of 

their letter. [Letters: Luminant (EPA-HQ-OAR-2009-0491-4818) p. 19-22]

RESPONSE: The emission rates 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 there 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 SO2 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 the 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 understands that, except for the coal handling 

systems, any unit designed to burn a low rank coal like lignite can burn higher rank subbituminous 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 subbituminous. 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 EPA 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 Three 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 of 
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lignite in 2010 and is projected to provide fuel for 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 (Luminant) 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 in the 

remedy case. According to Luminant’s calculations, in order to reflect the unit’s actual 

operations, it is necessary to increase Texas’s SO2 budget by 11,967 tons, its annual NOX budget 

by 1,721 tons, and its seasonal NOX budget by 514 tons. [Letters: Luminant (EPA-HQ-OAR2009-0491- 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 includes 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 heat 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 difference 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 case, 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 SO2 budget. This 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 attributes 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 Texas 
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SO2 budget accordingly. According to Luminant’s estimate, this would increase the Texas SO2

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 assessment 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 SO2 to Texas’s budget has on the modeling of Texas’s downwind 

impact, the additional 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]

RESPONSE: In the preamble 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 PM2.5 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 or interfering with maintenance of a NAAQS in another 

state. On page 48257 EPA classifies Texas as a “Group 2” state for SO2 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 

preamble 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 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). 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 reductions 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 

achieved 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 contribution” 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 additional 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 has 
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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” thresholds 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 reliability 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.” ERCOT’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 

National 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.
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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 the 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 were 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 ERCOT’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 complying 

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 capacity 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 suffer 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 provides 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.pdf
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Comment (E)(1): Allowances granted to Topaz’s Barney M. Davis and Laredo Energy Centers 

should be 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 repowering 

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 significant 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, Barney 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 operating 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 (EPA-HQ-OAR-2009-0491-4755) p. 2-5]

RESPONSE: Changes to the allocation methodology are outside 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 were 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 with 

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. Davis 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-2009-0491-4755) p. 

2-5]
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RESPONSE: Changes to the allocation methodology are outside 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 data 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 consistent 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 repowered 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 similarlysituated units. [Letters: Topaz Power Group (EPA-HQ-OAR-2009-0491-4755) p. 5-7]

RESPONSE: Changes to the allocation methodology are outside the scope of revisions proposed 

and upon which EPA solicited comment. See Section 6.5, below, for more information.

(F) Commenters express concerns regarding the methodology EPA has proposed in order 

to adjust the SO2 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 SO2 pollution and the fine particle pollution to which it 

contributes. The proposed increase to the Texas SO2 budget is not based on the most accurate 

data and as a result is larger than is appropriate. An excessive SO2 budget for Texas would 

likely result in unnecessarily high Texas emissions with adverse effects on our members 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 SO2 budget and therefore will receive 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.
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Comment (F)(2): Table 4 of the TSD 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 SO2 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. Commenters 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 SO2 Budget Revision - Assuming 2007 SO2

Removal Rates at FGD; Table 2 - Calculation to Determine Texas SO2 Budget Revision -

Assuming 2009 SO2 Removal Rates at FGD; and Table 3 - Calculation to Determine Texas SO2

Budget Revision - Assuming Design SO2 Removal Rates at FGD and Percent Flue Gas Entering 

FGD. These tables 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 SO2 budget for Texas as a whole. 

Commenter asserts that if EPA decides to move forward with adjusting Texas’ SO2 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 to consider the amount of flue gas 

actually entering the scrubber. Recalculating the SO2 budget adjustment for Texas using a more 

appropriate measure of scrubber performance will help ensure Texas’ SO2 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" parameters 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 Rule 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 was not being treated by the scrubber, and the assumption that this had a significant 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. 

Commenters pointed out the inconsistency with the approach used in the final Transport Rule,

and suggested several options for identifying a removal value to make adjustments for those 

units that was more consistent with the approach used for other scrubbed units in the final 

Transport Rule. 

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 data 
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from EIA form 860 in this final notice. Consistent with this final approach for the units in Texas 

and with the final Transport Rule, EPA intends to apply this approach in responding to a 

comment 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 

Texas, EPA should finalize the Proposed Revisions to the Texas SO2 and NOX 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: Luminant (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 annual PM2.5 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 in another state. On page 48257 EPA classifies Texas as a “Group 2” state for SO2

control, indicating that its significant contribution 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 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 with 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) EPA 

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 alternative 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 interference 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-HQ-OAR-2009-0491-4513) did not provide any suggestions as 
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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 and 

interference with maintenance.

(H) The final CSAPR incorrectly allocates allowances to cogeneration units in Texas.

Comment (H)(1): The final CSAPR incorrectly allocates annual SO2, annual NOX, and seasonal 

NOX 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 these 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 NOX, 1,389 seasonal NOX, and 152 SO2

allowances. It is Luminant’s understanding 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 cogeneration 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 error 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-OAR-2009-0491-4818) p. 18-19]

RESPONSE: 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 

preamble section 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).

(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 Section 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 inconsistent 
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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, infrastructure 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 modeling “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 the 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 contractual 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 SO2 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-HQ-OAR-2009-0491-4782) 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 national level. In regards to low sulfur coal availability, 

EPA’s power sector modeling (http://www.epa.gov/airmarkets/progsregs/epaipm/transport.html), which supported the Transport Rule analysis, already projects consumption 

of low-sulfur coal in 2012 (415 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 sulfur 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, 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

(EPA-HQ-OAR-2009-0491-4834). EIA data demonstrates that 339 million 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 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. Finally, see 

section 6.2(c) of this document, below, for information addressing SO2 emission rates.

(J) Comments on Operation, Emissions, and Controls at Texas Units
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Comment: Errors were made in the parsed IPM files for operation of the FGD system at

Gibbons Creek. Reflecting the fact 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 expected 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

erroneously 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 Miguel 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 

translates into an uncontrolled SO2 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 SO2 emission rate of 0.64 lb/mmBtu – which is almost

identical to what is shown in 2010 data concerning the unit’s operations (the data show

that the unit achieved an SO2 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 the unit was capable of achieving an SO2 emission rate of 0.15 lbs/mmBtu.
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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 can meet an SO2 limit of 0.13 lbs/mmBtu rather than the 0.63

lbs/mmBtu SO2 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 SO2 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 SO2 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 Remedy 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 SO2 emission rate that

can be achieved by Monticello Unit 3. The 2009 and 2010 SO2 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 SO2 emission

rate of 0.19 lbs/mmBtu and even more erroneously assumed in BC_F_12 that Monticello

Unit 3 would achieve an SO2 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-OAR-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 emission 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 and 
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operating in both 2012 and 2014 in the RC_F_12 and RC_F_14 based on the Transport Rulebased economic incentive to operate it In regard to Deely and Parish scrubbers, the responses 

above explain that EPA adjust the Texas state SO2 budget to reflect the assumption that no FGD 

is present at these 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 final Transport Rule. Leon 

Creek and North Lake were modeled as operating and generated about 340 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 SO2 emissions (these units have zero SO2

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 emission 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 responses to 

comments submitted by the facility owner (Luminant) above, the preambles to these 

rulemakings, and the Response to Comment Documents for the final Transport Rule. See section 

6.1c of this document, below, for information addressing SO2 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 determined 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 Planning Model (IPM) Runs (Oct. 7, 2011)” (EPAHQ-OAR-2009-0491-4823) 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 assigning 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 Rulemaking Participants (Nov. 28, 2011)” (EPA-HQ-OAR-2009-0491-4823) p. 4]
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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 

reported 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 entity 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 applicability are described in the preamble section 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 ancillary 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-specific 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 only 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 actual 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 committed 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 transfer 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 emission factors for NOX and AEP projections for SO2 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 added 

back into the respective state emissions budgets as technical corrections). [Letters: American 
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Electric Power (EPA-HQ-OAR-2009-0491-4737) p. 3-5; American Electric Power (EPA-HQOAR-2009-0491-9000) p. 51]

RESPONSE: EPA has revised the relevant state budgets in response to these concerns. See the

Final Revisions Rule State Budgets and New Unit Set-Asides TSD.

(B) Supports allowance increases in Louisiana and other states to account for noneconomic generation in out-of-merit-order dispatch areas but opposes 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 Entergy 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 cannot 

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 

correction 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. [Letters: American Electric Power 

(EPA-HQ- OAR-2009-0491-4737) 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 budget 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 significant reductions in seasonal and annual 

NOX 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 concerns 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. Also, 

the installation of LNB equipment on certain units represents a cost far in excess of the costeffectiveness thresholds used to establish the state-level budgets. New low NOX burners at 

AEP's Northeastern Units 3 to 4 in Oklahoma have a levelized cost removal that's greater than 
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$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 NOX) 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: 

American 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 NOX

burners by January 1, 2012 to lower the NOX 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 NOX 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 section VII of the final Transport Rule preamble (76 FR 48208, August 8, 

2011) for a discussion of the feasibility of LNB installation and 2012 compliance. Moreover, 

EPA notes there 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 service 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 approvals 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 SO2 reductions and the U.S. power industry as a whole has 

little 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 testing 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]
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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 preamble and 

the Response to Comment document for that rulemaking in the docket address the feasibility of 

FGD 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 make 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 states 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 Creed 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 SO2 emissions that should be reestablished 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 SO2 should be restored to state 

budgets based on these erroneous assumptions. [Letters: American Electric Power (EPA-HQOAR-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 they 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 MW) 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-firing 
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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 sourcespecific requirements for biomass consumption. 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 compliance 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 strategy 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 generation, not simply by more coal generation as suggested by 

many commenters. Because the substituted generation would not have corresponding SO2 or 

NOX 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 those commenter (Luminant) identifies in Texas) are also modeled as co-firing 

biomass, and thus the impact to SO2 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 Proposed 

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 SO2 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 “material” 

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.cfm?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_Delegation.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.pdf
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that have permit approval to burn biomass, an adequate supply 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 SO2 budget accordingly. [Letters: Luminant (EPA-HQ-OAR2009-0491-4818) 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 very 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-HQOAR-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 than 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 coal 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 lower 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 Unit Errors in Integrated Planning Model (IPM) Runs in section 1.3 above 

regarding coal switching and SO2 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 SO2 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 generation 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 significantly 
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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 that 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 “must 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 several 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 SO2 (IPM erroneously 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 SO2 emission 

rate projections.

Comment (F)(3): Xcel Energy and others previously asked that EPA recognize and reward 

proactive 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 suit. 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 emissions 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 from 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 the allowances at the plants’ maximum post-conversion emissions. The postconversion 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 were 

accomplished during EPA’s selected baseline period and, as a result there were years with preconversion 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 conversion 
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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 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 outside the scope of the revisions proposed and upon which EPA 

solicited 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 the 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 that 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 meet 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 Corporation 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 

response 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 facility'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 calculated 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 SO2 content of coal utilized at Homer City Station 

Units 1-3 greatly understate the SO2 content of coal actually consumed at the facility. In 

calculating this average facility rate, EPA's base case assumes use of 2.34 lb/mmBtu SO2 content 

coal at Homer City Units I and 2 and 4.23 lb/mmBtu SO2 content coal at the Unit 3. EPA's base 

case assumptions, 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 a 
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minimum 2.73 lb/mmBtu to a maximum of 3.46 lb/mmBtu with an average SO2 content of 3.11 

lb/mmBtu. This represents an average SO2 content more than 32% greater than EPA's modeled 

base case even after coal deliveries to Homer City have been washed to reduce SO2 content prior 

to combustion.

EPA's modeling errors are not confined to one aberrant year of coal consumption. Between 2006 

to 2009, minimum SO2 content for Homer City Units 1 and 2 ranged from 2.57 lb/mmBtu to 3.19 

lb/mmBtu, and had an average annual SO2 content (for both units) of between 2.91 lb/mmBtu 

and 2.88 lb/mmBtu. In the same years, the average annual SO2 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 SO2 content of fuel consumed at all units at Homer City was 

always above the SO2 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 based 

electric generation at Homer City. EPA's modeled use of biomass at Homer City is without 

foundation. EPA should address its overestimation of the SO2 reductions that can be achieved at 

Homer City, and reassess its model assumptions and recalculate state emission budgets and 

individual unit allocations accordingly. [Letters: Homer City Owner Lessors LLC (EPA-HQOAR-2009- 0491-4816) p. 3-6]

RESPONSE: See section 6.2(c) of this document, below, for information addressing SO2

emission rates. As regards 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 state 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-2009-0491-4737) p. 9]

RESPONSE: See section 6.1c, below, of this document for information addressing SO2 emission 

rates.
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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 assumption 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 lowsulfur subbituminous coal in 2012 to the extent they have used it historically, 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 

could 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 coals 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 point 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. Specifically, 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 previously 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 assumes). The incorrect biomass conversion issue pertains to Georgia Power's 
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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 in the final 

Transport Rule 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 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 2014 state budgets 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 unit level retirements, EPA does not take partial year operation 

into account. See response to American 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 projections as described in the IPM documentation. In regard to comments directed to 

coal switching, please see section 6.2.c, below, as well as the Declaration of Sam Napolitano 

dated October 13, 2011, filed in support of EPA's opposition 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 rulemaking, for additional discussion.

Comment (H)(2): The final budgets are based on significant unexplained 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 Florida 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 historical 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 

generated 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 exceedingly 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 assumptions, it must document the reasons for that decision. 

[Letters: Southern Company (EPA-HQ-OAR-2009-0491-4744) p. 6-9]
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RESPONSE: EPA conducted this revisions rulemaking process to address technical information 

provided by stakeholders and commenters demonstrating 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 programs. 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 described 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 time 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 compliance 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 SO2, 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 SO2 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 case errors were pervasive. A table with the results is included in the 

comment, and show that EPA's projected base case SO2 emissions in 2012 are not even 

reasonably close to actual 2010 emissions in many states. These results also show that EPA's 

IPM base case model determined that total SO2 emissions from all of the states would be 

approximately 7.4 million tons in 2012, when actual SO2 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 Support (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 Air 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 adequately address the concept of reliability, which is treated in a 

cursory, and largely economic, fashion.
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Comment (I)(1): The IPM focuses on the economics associated with moving power between 

regions. In fact, the IPM assumes a perfect transmission world 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 to 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 practicable 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 reserve 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 many 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 regardless 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.) provides 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 technical 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 solely on an arbitrary percentage. Commenters provide examples to 
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illustrate this point. A 1 percent change in New Jersey’s 2012 SO2 budget of 5,600 tons is 56 

tons, while a 1 percent change in the 2012 SO2 budget for Indiana is 2,854 tons. While 56 tons 

might 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 unitlevel errors in a single state 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 for 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 practice, 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 meet 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 NOX 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 consider 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 proposes 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 considering 

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 contribution 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 larger 
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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 impact 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. Commenters request an explanation why EPA decided to impose a 

materiality threshold, and/or justify the choice of 1%. [Letters: Lafayette Utility Systems (EPAHQ-OAR- 2009-0491-4807) p. 20; Louisiana Chemical Association (LCA) (EPA-HQ-OAR2009-0491- 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 by 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 opportunity 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 also 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 making 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 its review to those with 

an impact greater than 1 percent.

(K) EPA should correct erroneous assumptions regarding NOX emission rates.

Comment (K)(1): Gulf Power Company’s operations are heavily penalized by the proposed NOX

emission rates in the remedy case runs for 2012 and 2014. Commenter (Southern Co.) provides 

a table summarizing the unrealistic NOX 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 

NOX rates with allocations and the corresponding EPA assumptions for the Remedy Case. 

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 a 
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36% lower NOX emissions rate on average. [Letters: Southern Company (EPA-HQ-OAR-2009-

0491-4744) p. 12]

RESPONSE: The controlled NOX base rate modeled for these units is very consistent with the 

emission rates reported by the units themselves. However, the controlled NOX policy rate for 

these units is adjusted downward 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 — which 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 NOX emission rates.

(L) Commenters provide control equipment and other modeling corrections for Georgia 

units, and request changes to Georgia SO2 and NOX 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 SO2 and NOX 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-HQOAR-2009-0491-4749) 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” 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 of SO2, annual NOX, and ozone-season NOX. See the 

Final Revisions Rule State Budgets and New Unit Set-Asides TSD in the docket for this 

rulemaking.
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Comment(L)(2): MEAG objects to the shortfall of SO2 emission allowances for Georgia and 

MEAG's facilities in the final Transport Rule, and EPA should initiate a subsequent rulemaking 

to restore Georgia's 2012 SO2 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 

SO2 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 SO2 emission 

budget to the extent that is necessary to grant an allocation to MEAG of additional 2012 SO2

emission 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 SO2 emission budget by greater 

than 30% from the proposed Transport Rule budget, and MEAG’s allocation of such allowances 

by roughly the same percentage. As a result, MEAG will face a significant SO2 emission 

allowance shortfall in 2012 that will irreparably and adversely affect MEAG, the Municipalities, 

and the citizen 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 for 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 Agency’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” postcombustion pollution control equipment. 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. Comp. 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 erroneous unitspecific assumptions for Plant Scherer Unit Nos. 1 and 2 related to the MPCR may very well 

have reduced the 2012 allocation of SO2 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 Wansley 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 SO2 removal by the FGD systems) 

compared with such units’ 2010 actual 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 SO2
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emission allowances 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 CrossState Air Pollution Rule. [Letters: Municipal Electric Authority of GA (MEAG) (EPA-HQOAR-2009-0491-4753) p. 1-3]

RESPONSE: EPA did not assume 2012 operation, or dispatch, of controls at those plants 

referenced by commenters. Post combustion 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 response to UARG in section 

1.3(B) above regarding coal switching and SO2 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 Transport Rule as it 

applied to Georgia: (1) the projected SO2 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 the 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 reiterated (and provided detailed examples) that the final CrossState Air Pollution Rule still contains significant errors for units in Georgia. Specifically, 

Georgia’s Petition shows that projected SO2 emissions from EGUs used by U.S. EPA in its 

modeling for 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 SO2 and NOX 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 reductions 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 “overreduce” emissions and penalizing the 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-OAR2009-0491-4756) 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 correct the alignment of the Georgia 2014 state budgets with the 
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requirements for affected units in Georgia to install controls by the state rule’s deadlines, EPA 

plans, in a separate action, to increase Georgia’s 2014 state budgets for SO2, annual NOX, and 

ozone-season NOX. 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 turbine 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 corresponding heat input, and requests that EPA 

consider providing allocations to this unit. [Letters: City of New Ulm, MN (EPA-HQ-OAR2009-0491-4740) 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 section VII.B of the final 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 Illinois' 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 be 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, in 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, Light and Power previously requested that this unit be 

allocated 993 and 447 allowances per year for the annual SO2 and NOX control programs, 

respectively (and 186 allowances for the ozone season NOX control program) beginning in 2012 

and each year thereafter. IL EPA supports this request, particularly since the allowances 
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requested are consistent with the SO2 and NOX 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 outside 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 SO2 Budget. IPM WebReady_ParsedFile_T_Remedy_Final_2014.xls shows the 

installation of Dry Sorbent Injection (DSI) for SO2 control for the Joppa Generating Station (ID 

887_B_1-7). EPA assumed 57% SO2 reduction from the application of DSI. While the Joppa 

Generating Station has tested DSI for SO2 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 would 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 SO2 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 state rule 

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 

state rule imposes emission rate limitations for which specific groups of covered entities must 

collectively comply. 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 input and emissions data for certain North 

Carolina sources. Two new renewable energy facilities (CPI USA-Roxboro and CPI USASouthport) were provided allowances under the final CSAPR annual allocation methodology 

based on seasonal heat input data. Additionally, 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 heat 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]
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RESPONSE: Changes to allocation methodology are outside the scope of revisions proposed 

and upon which EPA solicited comment. The allocation methodology is described in preamble 

section VII.D of the final Transport Rule (76 FR 48208, August 8, 2011). 

Comment (M)(5): EPA should remove the SCR designation for Bay Shore Unit 4 (OH) and 

correct the NOX 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 NOX budget 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, 2010 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 SO2 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 increasing Ohio’s 2012 and 2014 annual SO2, annual NOX, and ozoneseason NOX 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 input assumption changes. 

EPA is finalizing additional adjustments to Ohio’s 2012 and 2014 annual and ozone-season NOX

budgets to correct an erroneous assumption of an SCR at Bayshore 4. There is no SCR planned 

or under construction at this facility. This results in increases to the state’s annual and ozone 

season NOX 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 Carolina 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 (EPAHQ-OAR- 2009-0491-4742) p. 2]

EPA should correct several errors in the data used to set SO2 budgets and subsequently the unitlevel SO2 allowance allocations for South Carolina. Commenter (Duke) notes that this is the first 
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opportunity that they have had to comment on these technical errors because 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 the above referenced IPM parsed files show these 

units being modeled with an SO2 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 these 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 final 

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 SO2 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 incorrectly modeled with scrubbers. Based on that methodology, the SO2 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-2009-0491-4768) p. 2-

3]

RESPONSE: The South Carolina 2012 and 2014 SO2 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 SO2 budgets and 

subsequently the unit-level SO2 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 SO2 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 units 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 

settlement agreement, approved in early 2010, that limits their SO2 emission rate to 0.80 
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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 SO2. 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 appropriate adjustments to the Indiana SO2 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 SO2 budgets and subsequently the unitlevel SO2 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 SO2 control efficiency of the Gibson unit 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 shown 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 SO2 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 SO2 emission rate that was modeled as part of the 

proposed 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 SO2 removal achieved by the original scrubber was 80%. In 2007 

the absorbers were upgraded to increase SO2 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% SO2 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 SO2 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 reaction tank and 

reduced SO2 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 the final Transport Rule. EPA should make the appropriate 

adjustments to the Indiana SO2 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 form 
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923 and their correction of that efficiency with EIA. [Letters: Duke Energy (EPA-HQ-OAR2009-0491-4768) p. 4-8]

RESPONSE: EPA has adjusted Indiana’s 2012 and 2014 SO2 Budgets to reflect DSI technology 

at the Gallagher units and a lower SO2 removal rate at Gibson Unit 5. See Final Revisions Rule 

State Budgets and New Unit Set-Asides 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-specific modeling assumptions that could affect the SO2 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 

emission 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 SO2 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 (see NEEDSv.4.10 FTransport and TR_Base_Case_Final available in the docket 

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 emissions 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 information addressing SO2 emission 

rates.

Comment (M)(11): The remedy 2014 NOX 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 Decree, only one SCR at JEC is required, and it is not required to 

be online until December 31, 2014, which means the NOX reductions at JEC assumed in the IPM 

are not actually required until 2015 or later. Kansas’ 2014 NOX 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 requirements. 

Westar’s calculations of 2014 NOX annual and 2014 NOX ozone season revisions are shown in 
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Table 5-1 and Table 5-2, respectively . The revisions result in a 5,110 ton increase for the 

Kansas 2014 NOX annual budget, and a 2,238 ton increase for the Kansas 2014 NOX 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 NOX budget to reflect the removal of 

the 2015 rate limit requirement. See the Final Revisions Rule State Budgets and New Unit SetAsides TSD in the docket to this rulemaking.

Comment (M)(12): In their Petition for Reconsideration, Northern States Power notified 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 period 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 units 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 

repowerings (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 resulted 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 consistent 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 outside the scope of the revisions proposed and upon which EPA 

solicited 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 this 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 area. 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 be 
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found) for these transmission constrained customers continually for a substantial 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 serve 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 minimal 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 generation 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 

imported 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 constraint 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 transmission 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 throughout 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 adjustments 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 down. 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 dispatch that are not 

accounted for in final CSAPR.
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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 assurance 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 economic 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 2010.

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 ozone season NOX and 30 annual 

NOX. 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 Final 

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-meritorder dispatch, even in the commenter’s own estimation, amount to very marginal quantities of 

emissions. Furthermore, EPA did not make revisions with regard to the units in Kansas. As 

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 projected 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 rounded 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.
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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 revisions should eliminated the overstated 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 promote 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 any 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 uneconomic 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 state 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 

CSAPR 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 criticisms 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 generating 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 significance 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. In fact, the IPM model is the best tool available 

for this purpose. Because the IPM model is based on dispatching units based on least cost 
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system price [which includes energy and capacity prices], it does not reflect all of the 

complexities of the transmission 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 

facts 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 predict 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 address 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 identified 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 the 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 number 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 

compliance 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 accepted, the response addresses unit specific or general reasons for that outcome. See 

section 6.2(b) of this document, below, for information addressing NOX emission rates. See 

section 6.2(c) of this document, below, for information addressing SO2 emission rates. See the 
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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

budget.

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 Base 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 assume 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 correctly 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 should 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 will
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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 installed 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 SO2 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 SO2 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 errors. 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 nonattainment in downwind states

and can result in errors in calculating the level of the state’s emission budgets. Errors

were also made in the SO2 emission rates used by EPA for Kraft Units 1-3 and Yates

Units 2-5. The actual SO2 emission rate for the Kraft Units 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 SO2 emission rates for all of these units would be about 4.3

lbs/mmBtu.

Errors were made about how long it would take 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 sulfur 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 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. 44-45]
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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 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 

letter in section 1.3 above regarding coal switching and SO2 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 basis. 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 period 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 limitation 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 NOX and SO2 emission rates that it

used to evaluate the downwind impacts of EGUs in Kansas. In the case of NOX

emissions, EPA greatly over-estimated NOX 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 appears 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 NOX emission rates in BC_P_12,

the state’s total 2012 NOX 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 SO2

emission rates at Kansas power plants. Thus, as set forth in the following table, in

BC_F_12, the SO2 emission rates for many Kansas units remain extremely high relative

to their actual SO2 emission rates in 2010.

Unit BC_F_12 SO2 Rate Actual SO2 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/mmBtu

LaCygne 2 0.94 lbs/mmBtu 0.68 lbs/mmBtu
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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 SO2 emission rates will be so high, EPA

concludes that in 2012, the state’s total emissions of SO2 will be 68,000 tons, rather than

45,200 tons. Use of the higher emission rates then translates into a state-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 SO2 emission rates are not intended to simply reflect 2010 

SO2 emission rates. As described in the final 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 projections is comparing apples to oranges. 

See response to UARG comment letter in section 1.3 above regarding coal switching and SO2

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 Conesville 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

operating 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 upgraded in 2009 and are now operating at 97% removal

efficiencies, the appropriate SO2 emission rate for those units is 0.16 lbs/mmBtu (the

result of removing 97 percent of the SO2 emissions produced by burning coal with an

emission rate of 6.5 lbs/mmBtu of SO2). In BC_P_12, EPA erroneously used an SO2

emission rate that was too low (0.07 lbs/mmBtu). In BC_F_12, EPA over-corrected and

now is using an SO2 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 rendering
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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 blends.

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 Units 1-5

led to additional errors being made in the parsed IPM files concerning the SO2 emission

rates for those five units. The 2010 SO2 emission rates for the Eastlake units are as

follows: Eastlake 1 - 1.19 lbs/mmBtu; Eastlake 2 - 1.35 lbs/mmBtu; Eastlake 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 SO2 emission rates for each of the Eastlake units would

be 3.6 lbs/mmBtu. As a result of EPA’s using these erroneously high emission rates,

there is a significant overestimation of 2012 SO2 emissions from Eastlake Units 1-5:

predicted SO2 emissions in 2012 are almost 152,000 tons, which is almost 91,000 tons

above the plant’s actual SO2 emissions in 2010.

Errors were made in the parsed IPM files concerning the SO2 emission rates for

Sammis Units 1-7. The 2011 SO2 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 corrected those erroneous technological assumptions in

BC_F_12, EPA still fails in that final IPM run to reflect the actual SO2 emission rates

being achieved at Sammis Units 1-3. Specifically, in BC_F_12, EPA assumes that those

three units will have an SO2 emission 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 common SO2 emission rate of 0.07 lbs/mmBtu. In BC_F_12,

however, EPA erroneously assumes that these three units will, respectively, achieve SO2

emission rates of 0.18, 0.13 and 0.13 lbs/mmBtu. All three should be listed as achieving

the same SO2 emission rate, which – based on the most recent data – is 0.07 lbs/mmBtu.
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[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 which units would have different 

economic incentives and different potential emission rates. See section 6.2(b) of this document, 

below, for information addressing NOX emission rates. See section 6.2(c) of this document, 

below, for information addressing SO2 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 from. The same applies for 

Conesville 5 and 6. 
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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 aside 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% complete 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 (EPAHQ-OAR-2009- 0491-4737) p. 5; American Electric Power (EPA-HQ-OAR-2009-0491-9000) p. 

51]

RESPONSE: EPA revised 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 SetAsides TSD in the docket to this rulemaking. 
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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 commercial 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 Unit 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 Station, 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 allocation. [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 section VII.D of the final Transport Rule.
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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-aside. 

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 portfolio 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, changes 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 (see

76 FR 637860, 63868). Further, the comment does not specify immediate-term unit-specific 

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 explained in this rule’s proposal.

Finally, states 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) EPA should have provided SO2 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; Unit 2 began commercial operation in February 

2011. Under the terms of CSAPR, both units should receive SO2 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 allocation 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 reported 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. 
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However, EPA notes that states have the flexibility to allocate allowances to sources through a 

SIP at the level, and using the methodology, they deem most appropriate. EPA treated Unit 2 as 

a new unit, as noted by the commenter.

(C) Repowered boilers should 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 installation of SNCR and OFA as BACT for NOX 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 units 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 boilers 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 down 

the remaining coal pile in preparation for the conversion from coal to wood biomass firing. The 

remaining coal pile was depleted in March 2009. The facility was shut down during the March 

2009 to August 2010 period while the units were permanently disabled 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 NOX including SNCR 

and OFA. The conversion of the plant from coal to wood biomass provided significant reduction 

in SO2 emissions due to the low sulfur content of wood biomass.

These new stoker grate units started the commissioning 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 outside the scope of revisions 

proposed and for which EPA solicited comment. See section 6.5, below, for more information.
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(D) Tennessee new unit annual SO2 set-aside allocations are in error.

Comment (D)(1): EPA states in the preamble discussion that the new unit set aside [for the SO2

Group 1 Program] for the state of Tennessee would increase in 2013, 2018, 2019, and each year 

thereafter, 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 should 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-2009-0491-4792) 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.

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 applicable.

(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 operation since January 1, 2010, were the two J. Lamar Stall units 6A and 6B at the 

Arsenal Hill power station (ORIS 1416). Ozone season NOX emissions were 46.4 tons in 2010 

and 57.3 tons in 2011. The 2011 ozone season represents a full year of normal operation, 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, nonoperational, 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-2009-0491-4803) p. 15-16]

RESPONSE: EPA plans 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 docket to this rulemaking.
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(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 Indian 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-HQ-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 section 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 SO2, ozone 

season NOX, and annual NOX because the final CSAPR calculation of the new unit set-aside 

erroneously omitted Iatan Unit 2’s projected 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 that 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 increase Missouri’s SO2, 

ozone season NOX, and annual NOX 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 for ozone season NOX and annual NOX 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 SO2 in Missouri. This value should be changed to 

3 percent. The revision is consistent 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 unit 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 

allocation methodology (See 76 Fed. Reg. at 48290); however, the final CSAPR erroneously 

omitted this unit’s projected emissions from the calculation of Missouri’s SO2, ozone season 

NOX, and annual NOX budget new unit set-aside. Including this unit’s projected emissions in the 

calculation would yield a revised new unit set-aside of 3 percent for SO2and 6 percent for ozone 
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season NOX and annual NOX of Missouri’s budget instead of the previous 2 percent and 3 

percent values for the respective new unit set-asides. This 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 (SO2), annual nitrogen dioxide (NOX), and seasonal NOX, 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 state 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 

comments 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 corrections 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 National 

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 units 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 units 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, 

rendering 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, rather 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 Iatan Unit 2 from further consideration. Moreover, the regimen of control devices and 
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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 lowest 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 

units 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 increase 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-Asides 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 underassigned allowances to that pool. EPA neglected to increase the NUSA for SO2 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 NOX, 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 the 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 SO2, 

6% for annual NOX, and 6% for seasonal NOX. 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 Utilities 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 address specific errors related to Tennessee’s new unit set-aside.
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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 SO2

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-OAR2009-0491- 4750) p. 2 of Attachment; Tennessee 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 tonnage 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 Energy 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 policy 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 demonstrate 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 generation” 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 

generation 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-account 

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 would remain economic for 
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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 facilities. The fact that the fuel used has been determined to satisfy the 

REPS requirement should not exempt them from meeting the NOX, SO2 and PM 

requirements allotted to each state. In fact, not counting increased production at a 

retrofitted facility toward 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 Conservation 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 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.
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3. Consent Decrees - Allowance Allocations

Points Raised:

(A) Disagrees with EPA's proposal 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 SO2 and NOX

allowance allocations to reflect the maximum allowable emissions at the units affected 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 allocations 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, 2011, 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 

NOX and SO2 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 facilities 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 individual 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 agreement of all the Consent Decree parties. 

Paragraph 84 of the Consent Decree increases the system-wide annual tonnage limits for SO2 in 

2013 and 2014 if one or more nuclear units are shut down due to forced outages or safety 

concerns. EPA's proposed changes 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 allowances 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 the 
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October 17, 2011 deadline did not provide sufficient time for affected States to review and act 

upon the October 14, 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 between 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 conduct 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 comment 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 

requirements of the consent decrees. Most of the consent decrees addressed by this rule, 

including the TVA consent decree, define the SO2 and/or NOX allowances covered by the 

consent decree allowance surrender provisions as allowances issued in any emission trading 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 consent 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 

that 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 requirements 

under the Act, including TVA’s obligation to satisfy any modeling requirements set forth 

in the Act.
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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 does 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 emissions 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 SO2 Group 1 trading program and 

one (Alabama) is in the Transport Rule SO2 Group 2 trading program does not alter this fact. 

First, 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, to the extent 

EPA’s approach results in a different distribution of allowances among the states or between 

units in these two SO2 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 units 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 call 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 aside 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. Therefore, because TVA 

units received over 99 percent of Tennessee's 2013 SO2 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 added 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 to 
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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 apportioning 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 unit that is greater than 120 days in 

calendar year 2012, 2013, or 2014. TVA’s total SO2 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 proposed 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, including 

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 such 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, based 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 decree 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 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 notice of intent with respect to the 

2013 allocations still have the opportunity to submit allocations for 2014 and beyond.
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Comment (A)(2): EPA states in its proposal that the unit level allowance allocations under 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) Accordingly, 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 surrender 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 which 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 settlement 

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 SO2 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 SO2 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 million for each of these calendar years, assuming an SO2

allowance price of $1,000 per ton of SO2 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 its 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 the 
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excess on an EPA-prorated basis across the TVA fleet. This loss of flexibility is compounded 

because TVA operates affected 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 

groups. 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 TVA'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 Decree. 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 response 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 approach 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 unitretirement 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 later, 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 SO2 allocations, increasing their 2018 and 2019 allocations, 

assuming that Tennessee, Kentucky, and Alabama do not file SIPs to establish alternate 

allocation methods in the interim period.
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Regarding the proposal to allow owners with consent decrees to specify from which units 

allowances are surrendered, EPA does not believe that this suggested 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 trading 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 SO2 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 

emissions in the modeling analysis result in over 25,000 tons of excess SO2 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 emissions based on the consent decree. The consent decree has collective 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 consent 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 effect 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 maximum 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 SO2 and NOX controls which came on-line in 2009. 

SO2 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 in 
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2012 and 11,000 in 2014 for this unit. [Letters: New York State Department of Environmental 

Conservation (EPA-HQ-OAR-2009-0491-4788) p. 3-4]

RESPONSE: See section VII of the final Transport Rule preamble in the docket to this 

rulemaking for a description of the allocation methodology (76 FR 48284, August 8, 2011). The 

only aspect of the allocation 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 outside the scope of revisions proposed and upon which EPA 

solicited comment. 

(D) EPA misinterpreted the JEC Consent Decree that requires compliance with the 

NOX 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 Impact of Consent 

Decree Annual Tonnage Limits on CSAPR Allocations” lists Westar’s annual tonnage limit 

(ATL) for SO2 as 6,600 (2012 through 2016) and for NOX as 12,400 for 2014 and 2015 

decreasing to 9,600 tons in 2016. The NOX ATL is based on a misinterpretation of the JEC 

Consent Decree related to the NOX 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 NOX plant-wide 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-Wide 12-Month Rolling Tonnage limitation for NOX 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 

December 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 prospective 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 updated as 

provided in a table in the comment letter. It is also important to note that the Final Rule NOX

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-2009-0491-4777) p. 11-12]
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RESPONSE: For the purpose of determining the impact of the CD ATLs on Transport Rule 

NOX allocations for Westar Energy, EPA has adjusted the timeframe of the NOX CD ATLs from 

2014 to 2015 and 2016 to 2017, respectively. However, as stated in 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 Energy 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 system which depends on over-controlling at Merom to free 

allowances for Ratts.

The Hoosier Consent Decree is system-wide, not plant specific. SO2 and NOX annual allowance 

restrictions and surrenders under the Consent Decree are based on annual tonnage limitations 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 Ratts units with a potentially dramatic 

impact on the Hoosier System. In fact, without SO2 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 SO2 allowance allocation.

EPA should clarify that the SO2 and NOX 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 surrender 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 Electric 

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 trading 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 surrender 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 rule 
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revision (including the Hoosier CD) define the SO2 and/or NOX allowances covered by the 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 allowance 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 the 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 NOX allowance restrictions in the EKPC Consent Decree should not be 

used as a basis for reallocating CSAPR NOX allocations from EKPC to other Kentucky sources. 

EPA correctly determined that no reallocations are appropriate for SO2, but EPA inappropriately 

compared EKPC system annual unit NOX allocations and determined that there would not be any 

excess NOX 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 NOX

allowances because at the time it was negotiated the only NOX allowances were ozone season 

allowances; and 2) The EKPC Consent Decree only restricts the use of NOX allowances. It does 

not require the surrender of NOX allowances. The Consent Decree clearly allows NOX

allowances to be banked under any interpretation 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 NOX 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 NOX allowances. [Letters: East Kentucky 

Power Cooperative (EKPC) (EPA-HQ-OAR-2009-0491-4806) p. 5-7]

RESPONSE: The commenter raises a question 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 NOX annual allowance allocation. EKPC’s NOX consent decree (CD) annual tonnage 

limit (ATL) was greater than the system-wide allocation, and so EPA did not revise EKPC’s 

NOX annual allowance allocation. Therefore, EPA is not taking any final action with respect 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.
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Comment (F)(1): The CSAPR Rule finalized by EPA on August 8, 2011 provided States the 

opportunity 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 submit 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. Specifically, 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 publication 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 

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, including 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 such a 

notice from a state. Allowances were therefore 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 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 decree 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 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 notice 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 incorporation 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 surrender of “excess” CSAPR allowances. As a result, 

CSAPR allowance allocations to certain units reduced the availability of some of those 
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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 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. 2-3]

RESPONSE: EPA appreciates the supportive comments.
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4. Assurance Penalty Provisions

Issue 4.1: General 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 

delaying 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 compliance period. However, the need for market liquidity will persist 

beyond the 2012-2013 compliance periods, and will be most important to assure that SO2

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 essential 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 rule. 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-OAR-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 administering the Clean Air Interstate Rule pending the court’s resolution of 
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[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. 

Comment (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 SO2, and 6,000 tons for 

annual NOX and 2,500 tons for seasonal NOX. 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 offer 

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 be 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 until 

2014 will not be sufficient. The large decrease in Group 1 SO2 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 unnecessarily 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 SO2 compliance in the fourth quarter of 2013 if the forward market price of SO2 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 safety 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.
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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 their 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 cost 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 the 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 reducing 

the emissions of both a primary CSAPR pollutant (SO2) 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 dates 

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 significant 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 to 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 EGUMACT. Because most of the CSAPR states 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 the 
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statutory mandate and 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 budgets in the final rule 

for 2012. [Letters: Ohio Valley Electric Corporation and Indiana Kentucky E (EPA-HQ-OAR2009-0491-4794) p. 1-2]

RESPONSE: EPA is finalizing the delay of the assurance provisions until 2014. See section 

IV.C of the preamble to this 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 monitor 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 Section 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 unable 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 implementation 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 

control 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 banking 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 NOX SIP Call, EPA wisely permitted the use of allowances 

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 CSAPR. 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 excess 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 allocations are determined by historical operations, not historical 
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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, 

this 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 within 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 the 

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 environment 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-OAR2009-0491-4811) 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 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.

(B) Supports EPA's proposal to defer the effective date of the assurance 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 decrease, 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 rather 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 SO2 states, so that the number of allowances 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 increased 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 Electric 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 the revisions proposed and upon which EPA solicited comment.
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EPA is finalizing the delay 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 beginning 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 transmissionconstrained areas that need to operate to ensure stability of the transmission grid. Alternatively, 

EPA could provide a limited 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 plan 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 not 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 SO2 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 Phase 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 price, 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. 
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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 deferral 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 regardless 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 finalizing 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 contributing 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 generating 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-effective 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]
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RESPONSE: In this final rule, EPA is finalizing the delay of the assurance 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 date 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 programs, 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 liquidity 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 cost 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 not 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 the 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 noted 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 (EPAHQ- 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 (EPAHQ-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-OAR2009-0491- 4815) p. 5; Kansas City Power and Light Company (EPA-HQ-OAR-2009-0491-

4804, 4826) p. 2; Michigan Department of Environmental Quality (MDEQ) (EPA-HQ-OAR2009-0491-4859) p. 1; National Grid (EPA-HQ-OAR-2009-0491-4809) p. 2; Oglethorpe Power 

(EPA-HQ-OAR-2009- 0491-4749) p. 2-3; Progress 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.
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Comment (D)(2): Commenter (PA DEP) supports EPA's proposed Transport Rule revision 

which changes the effective date 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 

"limited 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 beginning 

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 that 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 2014. 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 the 
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effective date of the assurance penalty provisions will not interfere with 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 that 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 2014 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-HQOAR-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 SO2, Group 

2 SO2, Annual NOX and Ozone Season NOX. 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 strategies, 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-HQOAR-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 their 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 effectively 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 the 
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multiple reasons why additional trading is needed, including: 1) the CSAPR allowance 

distribution leaves some utilities with more allowances and some utilities fewer allowances 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 allowances 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 

available 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-2009-0491-4824) 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 percentages 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 more 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 approach 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.

Comment (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 intentionally 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 beginning 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 maintain current generation levels and comply with the rule. Although eliminating the 
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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. Commenter (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 reductions 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 preamble 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 NOX

emissions allocation to the states in the seasonal NOX 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 NOX

emissions. A trading market will not exist 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 NOX 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 NOX emissions illustrates 

the severity of the cuts. Total 2010 seasonal NOX 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 reduced 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 NOX Budget 

Trading Program have concurrently reduced emissions and sustained liquid trading markets. 

EPA is finalizing the delay of the assurance provisions 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 delay until 2014 moves in the right direction, but 

does not go far enough insofar as Nebraska utilities are concerned. Nebraska did not participate 
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in the NOX 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 important 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 Wisconsin 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 Nebraska 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.

Comment (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 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. EPA is finalizing the delay of the assurance provisions until 2014. 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 program.

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 NOX trading program there is a nationwide budget of 

620,499 allowances to cover 704,992 average NOX emissions (2008-2010 period). This yields a 

deficit of 84,493 allowances. Also, the penalties for not holding sufficient allowance remain 
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excessively high. Shortage is due to the fact that the effective date of CSAPR does not allow 

ample time to install 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]

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 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 the 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 the 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 finalizing 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 unlawful. 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 sequence 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 the 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 table 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 Attachment 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, and 
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concludes that the inescapable conclusion from "North Carolina" is that without the assurance 

provisions 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 outside 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 nonattainment or interfering with maintenance “in any other state,”” 531 F.3d at 

907, is more than satisfied by the Transport Rule as revised by this action. As explained in the 

preamble, EPA determined that the assurance provisions did not need to be in place before 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. The existence of the assurance 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 provisions 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 the 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 given 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, 
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EPA asserts that allowance markets are sufficiently liquid to render 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 several 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 November 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 NOX 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 enforcement of the 

assurance provisions in 2012 and 2013. [Letters: North Carolina Attorney General (EPA-HQOAR-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 

allowances 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 assist 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 stakeholders. Because the state assurance levels 

promulgated in the Transport Rule will 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.

Comment (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 levels 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 calculated 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, EPA'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 originally asserted in the CSAPR proposal 

that it had a "high level of certainty" that all States would comply with their assurance levels in 
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2012 and 2013 (75 FR 45306) and provides significant additional discussion on this issue and 

concludes that EPA cannot rationally 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]

RESPONSE: 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 rulemaking, 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 

assurance 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 compliance 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 transaction 

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 allowances 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 from 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 comments (provided as 

Attachment 1) at p. 26-30. [Letters: North Carolina Attorney General (EPA-HQ-OAR-2009-

0491-4825) p. 15]
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RESPONSE: In their original submission of October 1, 2010, which commenter has 

resubmitted, commenter first disagreed that EPA’s “high 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 states 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 with 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 subject to the overarching state-level emission reduction requirement. Therefore, 

individual sources may still require flexibility in compliance options (including access to a welldeveloped allowance market) even though EPA is confident in its assertion that states 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 revision 

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." Commenter (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 their 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 operations 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 attainment deadlines and therefore violate the anti-
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backsliding provision of §110(l). [Letters: North Carolina Attorney General (EPA-HQ- OAR2009-0491-4825) p. 16-17]

RESPONSE: EPA also rejects the assertion in North Carolina’s comments that delaying the 

effectiveness 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 delaying 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 some 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 eliminate the significant 

contribution and interference with maintenance identified 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 speculated 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 levels 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 increases 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 increased 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 second 

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.
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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 details 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 delaying 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 provides 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 allowance 

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 preamble 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 believe 
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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 Carolina 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 SO2 auction program 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 bidask 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 the CSAPR market. The minimum prices charged were $200 for Group 1 SO2 and 

$800 for both NOX products. First Energy announced it would conduct another auction no later 

than April 30,2012. These auctions support the conclusion that additional allowances will come 
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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 provisions 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. 

However, 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 allowances (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 market 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 the 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 

SO2 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-OAR2009-0491-4789) 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 SO2

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 repeated 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 unreasonable compliance timeline that the 

EPA is mandating by requiring huge SO2 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. 
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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, which still does not appear to be a viable trading market for SO2 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 SO2 emissions data for 2011 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, the 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 SO2 reductions required of 

Texas. [Letters: Texas Commission 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 penalty provisions until 2014, it is unlikely that in 2012 there 

will be sufficient seasonal NOX allowances to cover demand in most states. In support of their 

assertion, commenter (Entergy) provides state-specific budget and allowance numbers in Table 2 

of their letter. For most states, the proposed seasonal NOX budgets still are significantly below 

actual 2010 emissions. Under the Proposed Rule, there is a seasonal NOX allowance deficit of 

81,037 tons, compared to 2010 emissions, assuming that all sources 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, given 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 until 2014, instead of just the assurance penalty provisions, to give at 

least some affected sources sufficient time to install pollution controls. [Letters: Entergy (EPAHQ-OAR-2009-0491-4820) p. 6-7]

RESPONSE: EPA is finalizing the delay of the assurance 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 it 
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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. To ensure consistency with CSAPR's goals and purposes and 

to address 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 allowance 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 Phase 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 allowances 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 benefits. 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 

utilize 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 finalizing 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 limits 

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 the final rule (18% of annual SO2 and NOX budgets, and 21% 

of the ozone season budgets). This coupled with the two year suspension of assurance provisions 
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will provide much needed flexibility in both short and long term. [Letters: Dominion Resources 

Services (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.
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5. General Comments

Issue 5.1: General Support for Proposed Rule Revisions

Points 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. Some 

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 market 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: Calpine 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-OAR2009-0491-9006) p. 24-25; NRG Energy (EPA-HQ-OAR-2009-0491-4796) p. 1; Sierra Club 

(EPA-HQ-OAR-2009- 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 proper 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 Rule 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 rule 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 maintain 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 providing due to technical errors. These changes will provide 
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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 requirements 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 such, 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 but 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 that 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 December 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.
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The focus of the Proposed Revisions is therefore correctly limited to the very narrow 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 (EPAHQ-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 calculated. Market costs are already lower than what EPA 

estimated. SO2 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 the 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 finalizing 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 NOX in upwind states are necessary for 

Maryland to attain the new ozone standard. 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 installed 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, marine engines, 

locomotives, and next round of EGU controls. These 6 source sectors represent about 75% of 

the NOX that is left to regulate. [Letters: Maryland Department of Environment (EPA-HQOAR-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. Consequently, 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.
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Comment (B)(5): The CSAPR is a much-needed, long-overdue 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 across 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 

provisions. [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 operational 

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 control 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 industry 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 be 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 expanding.

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 be 
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created by switching dispatch to controlled and gas-fired units 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 comments. 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 budgets.

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 costeffective measures to comply with the increased emission reduction 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 localized 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) supports 

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 Florida 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 NOX emission rates and the Florida specific demand 

growth rate) adding 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 caused 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 certain units and the low state wide heat input; 
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EPA's assumption that certain SCR NOX 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 (EPAHQ-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 

focus 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 opportunity 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 the 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 (EPAHQ-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 technical revisions to the CSAPR including 

those allocating an additional 4,201 tons of seasonal NOX 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-OAR2009-0491- 4799) 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 (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; South 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 address errors in its unit-level 

assumptions and EPA’s recognition that other errors exist (as demonstrated by the fact that the 
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Agency is accepting comments identifying additional unit-level errors). 76 Fed. Reg. 63868. 

EEI member companies will be submitting 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 and 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, however, 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 generally 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.
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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 

effective 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-HQOAR-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 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 available without this proposed change 

to the allocation of allowances. [Letters: Kansas City Power and Light Company (EPA-HQOAR-2009-0491-4804, 4826) p. 3]

RESPONSE: EPA has worked as expeditiously as practicable to finalize the Revisions Rule.
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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 impacts, 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 allowances proposed for the Texas budget and recent SO2 scrubber start ups, 

substantial SO2 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 misleading since 

it is the allowance transfer deadline for the annual NOX and SO2 programs. With the 2012 

deadline, companies must reduce their SO2 emissions early enough in the year to avoid running 

out of allowances mid-year and being forced to shut down. Companies are unlikely to gamble 

compliance on SO2 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 but Texas is still limited to trading with Group 2 states, which 

still does not appear to be a viable trading market for SO2 allowances sufficient to address Texas 

concerns. Companies will have only a matter of months to achieve the large reductions in SO2

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-OAR2009- 0491-4782) p. 2(cvr), p. 5-6); Texas Commission on Environmental Quality (EPA-HQOAR-2009-0491- 9002) p. 18-20]

RESPONSE: The compliance schedule has been addressed in the record to this rulemaking (see 

section VII.C of the preamble to the final Transport Rule and the response to comments 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 December 1 allowance transfer deadline for the ozone season and March 1 allowance transfer 

deadline for the annual NOX and SO2 programs, 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.

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 significant 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 analysis 
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conflicts with studies completed by ERCOT and others; 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 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; 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 necessary 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 with 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, CSAPR 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 CSAPR. 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 allocations 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 that 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 unitlevel allocations have been revised and put in final 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]
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RESPONSE: See the preamble to the final revisions rule and the TSD called “Final Revisions 

Rule State Budgets and New 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 in 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 sources 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 comment 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 assumptions) 

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 fully 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 fundamental 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 effective immediately. [Letters: Luminant 

(EPA-HQ-OAR-2009-0491-4818) p. 8-9]

RESPONSE: EPA will respond to requests for reconsideration separately from this action.
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(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 NOX budgets even higher than those set in the final 

Transport Rule, which commenter (MDE) believes are already too high. Understanding that 

corrections may be justified, 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 deadline 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 the NOX and SO2 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 

maintenance 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 quality impacts of the SO2 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 NOX 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 SO2, 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 SO2 cost thresholds for 

“Group 2” and “Group 1” states, respectively. Furthermore, for the annual and ozone-season 

NOX budget revisions, EPA again notes that the changes are only a small proportion of each 

state’s total emissions.
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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 local permitting agencies have been requesting 

guidance from EPA on how to address the non-electricity generating units subject to the NOX

SIP Call, EGU permit conditions, and state implementation plans. EPA has not provided this 

guidance, and commenter notes 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 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.

(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 CrossState Rule, EPA in the Proposed Revisions seriously misrepresents the rule’s compliance dates. 

EPA asserts in the preamble to the Proposed Revisions that the “first 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 NOX program, and March 1, 2013, for the 2012 annual NOX

and SO2 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 deadlines 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.
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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 coalfired 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 data 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 

Budgets 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 NODA 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 allocations 

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 implementation 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 issues — public comment opportunity and power supply disruptions —

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)(3): EPA has assumed that most coal-fired units without SO2 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 SO2 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, then 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 SO2 budget to reflect use of a more reasonable mix of 

low sulfur PRB coal. [Letters: Omaha Public Power District (EPA-HQ-OAR-2009-0491-4747) 

p. 5-6]
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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 2014. [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 Mississippi 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 

achieved 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 Issues 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 solicited 

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 controls 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" operating 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 increased 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 and Request 
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for Stay of the CSAPR. [Letters: Southwestern Public Service Company (SPS) (EPA-HQ-OAR2009-0491-4752) 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 adjustments to the Texas annual SO2 budget, as well as smaller adjustments 

to the state’s annual and ozone-season NOX budgets. Similarly significant errors were identified 

in other states. The errors in Texas’s emissions budget related to two factors. First, in CSAPR, 

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 the emission control 

configuration and operation of several large Texas plants (76 FR 63864). These errors alone 

resulted in Texas receiving approximately 70,000 fewer SO2 allowances than was appropriate 

under EPA’s allocation methodology. [See related discussion 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 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)(8): EPA failed to assure that IPM properly accounted for "out-of-merit-order 

dispatch areas." In out-of-merit-order dispatch 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 failed 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 NOX 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 reduced fossil generation under 

CSAPR; and (3) its assumption that utilities such as SPS can access any available generation 
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within their region without any transmission constraints and that any power imported into the 

region can freely flow where it is needed. 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 Rule 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 errors. 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. For 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 even 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 final 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 

Interstate 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 

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].
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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 affected 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, as 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 public 

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 the 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 which 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 Texas. 

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 additional 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; and thorough economic impact analyses should be 

conducted before the rule is implemented. [Letters: Texas Department of Agriculture (EPAHQ-OAR-2009-0491-4819) p. 1]

RESPONSE: See responses to Issue 1.7(D) on Texas Modeling Assumptions and Reliability.
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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 order 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-fired 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 opportunity 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 the 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 (EPAHQ-OAR-2009- 0491-4741) p. 2]

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 previous 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. 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 Transport Rule, EPA 

based unit-level allowance allocations on historic heat input and emissions data, not on IPM unitlevel 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.
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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 SO2 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 IPM data in comments on the original proposal, it is EPA's own mistakes and 

incorrect assumptions that caused the errors in EPA's SO2 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 state'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 NOX emissions based on the federally 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 the 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 reliable electricity. The 

additional allowances that EPA is proposing to add to the Texas budget for SO2 are not sufficient 

to address the short term impacts to reliability. In a subsequent letter, this commenter notes that 

the North American Electric Reliability 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 (particularly 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 report 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 revisions 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 SO2 and NOX programs in the final rulemaking. EPA has 
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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 (EPAHQ-OAR-2009-0491-4766) p. 1-2]

RESPONSE: This comment is outside 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 local 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 on Environmental Quality (EPA-HQ-OAR2009-0491-4782) 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 previous 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 SO2 and NOX 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 SO2 allocation published in September 2010, the drop 

from 2012 to 2014 allocation for Illinois was 27%, which is close to the drop required by CAIR. 

However, the 2014 final transport allocation for Illinois dropped by 47% from the 2012 
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allocation. This additional 20% drop is an unreasonably large drop in allocations with 

compliance required 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 leaves 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 Energy, 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 NOX

allowances and 22,863 ozone seasons NOX allowances. In the Final Transport Rule, Illinois was 

only allocated 44,042 annual and 19,511 ozone season NOX allowances. This is a drop of 19% 

for the annual NOX 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 they would receive allowances very close to our ozone and annual NOX

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-HQOAR-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 example 

2012-2013 annual NOX 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 opportunity 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 recreate 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 explanation in EPA's TSDs or spreadsheets. Specifically the 0.30 lb/mmBtu SO2
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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 (EPA-HQOAR-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. In some cases the budgets were not reduced by the 

magnitude suggested by commenter, rather the new unit set-aside increased for the state meaning 

that fewer of the total allowances were allocated to existing units and more were held for new 

units. In regards 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 Consolidated 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 

Review of EPA's Transport Rule, filed in 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 states the following: "Many of the stay motions assert that EPA failed to give 

adequate notice of the emission budgets in the final 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 opportunities 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 intended 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 emissions 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), and that requested 
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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 methodology 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 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. [Letters: Texas Commission on Environmental Quality (EPA-HQ-OAR2009- 0491-9002) p. 22-23]

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].

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 more 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 support 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 Transport Rule. [Letters: Public Utility 

Commission of Texas (EPA-HQ-OAR-2009-0491-4800) p. 7-9]
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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 limits 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 Service Enterprise Group (PSEG) (EPA-HQ-OAR2009- 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 recognized 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 should 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 

reasoned 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 percentageonly approach.

As illustrated in a supplied chart, a switch to a percentage-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 three 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’s
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variability limit for the annual NOX 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 declines 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 includes 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 when 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) (EPAHQ-OAR-2009- 0491-4793) p. 8-10]

RESPONSE: EPA is adjusting New Jersey’s annual and ozone season NOX budgets and SO2

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 docket 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 Consultants 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 modeling, 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 correspondence 

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 further 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 explained 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 with regard to the problems with EPA's modeling 

assumptions and its impact on Oklahoma and requests that EPA reconsider its inclusion of 
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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. 

See the final supplemental rule (76 FR 80760, December 27, 2011) and the response to 

comments 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 overstepped its legal boundaries under the cooperativefederalism 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 accept 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 opportunity 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-HQOAR-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 throughout 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 Transport 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 interfere 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 the 
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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 units are not costeffective 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 nonEGUs, which EPA has excluded. Commenter also notes that 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-effective 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: Pennsylvania 

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 nonEGUs to buy and surrender NOX allowances.

Comment (J)(1): Under the two predecessor trading programs, the NOX SIP Call and CAIR 

programs, certain non-EGUs could opt-into the program or buy and surrender NOX allowances 

for compliance with other emission limitation programs. Pennsylvania's SIP-approved air 

quality 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 turbines, and stationary internal 

combustion engines) and for large stationary internal combustion engines and cement kilns that 

are subject to the NOX SIP Call. Commenter (PA DEP) requests that EPA amend the Transport 

Rule to continue to allow for the surrender of NOX 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-OAR2009-0491- 4773) p. 9]

RESPONSE: This comment is outside 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 Transport 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 levels to downwind nonattainment 

and maintenance receptors, and ultimately to decide whether Wisconsin should be included in 

the annual SO2 and NOX programs. EPA used the results of the 2012 and 2014 remedy modeling 

runs to determine Wisconsin's state allowance budgets in 2012 and 2014, respectively. 
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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 determining 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 SO2 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 SO2 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 SO2 base case emissions in 2012 by approximately 24,000 tons (or 

22%). It appears EPA used these data to determine whether to include Wisconsin in the annual 

SO2 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 SO2 program and should stay 

the final rule with regard to Wisconsin. [Letters: Integrys Business Support (EPA-HQ-OAR2009-0491-4757) p. 2-4]

RESPONSE: EPA’s methodology for identifying significant contribution to downwind 

nonattainment and/or maintenance is outside the scope of the revisions 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 units 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 existing 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 levels 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 collaborations. 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-2009-0491-4759) p. 2]
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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 outside 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 determine 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-2009-

0491-4786) p. 2]

RESPONSE: Comments regarding the IPM model are outside 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 response 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 NOX 2010 emission rate of 0.2 lb/mmBtu, aligning the IPM 2012 projections with 

2010 actuals would result in approximately 2,000 additional NOX annual allowances to the 2012 

Kansas budget and 1,300 additional 2012 NOX ozone season allowances. Similar increases in 

the 2014 Kansas budgets would be expected if the IPM projections were aligned with 2010 

actuals. 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-2009-0491-4777) 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 units modeled, the output 
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projections are different from their own predictions for the units’ operation. EPA notes that the 

Transport Rule is a trading program 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 combination 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 if a more realistic heat input 

were used. Starting from the remedy 2012 NOX 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 NOX annual allowances 

and 584 additional NOX ozone season allowances to the 2012 Kansas budget. Similar changes 

would apply for the 2014 Kansas budget. The full calculations are shown in Tables 2 and 3 of 

the comment letter.

For SO2, 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 emissions 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 that an additional 7,857 SO2 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 are 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-OAR-2009-

0491-4779) p. 3-6]

RESPONSE: See the preamble to final Revisions Rule and the TSD called “Final Revisions 

Rule State 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 NOX allowances, the final allowances will not be 
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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 not 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 does 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 meet 

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 NOX, SO2, and PM emission control equipment across its entire 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 NOX and SO2 emission limitation 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 the designing, procuring and installing of the emission control equipment to 

ensure compliance with the Agreement's NOX and SO2 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 means to comply with the NOX 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 years for the installation of the possible second SCR. Likewise, the 

Consent Decree did not require Westar to meet the first NOX conditions, utilizing low NOX

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-OAR-2009-0491- 4777) 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. See 
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the preamble to the final transport Rule and the response to 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 Transport 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., units 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 allowances 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 allocating 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 SO2 and NOX , and 186 ozone season NOX allowances. 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-OAR-2009-0491-4764) 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 preamble section 

VII.D of the final Transport Rule and in the final Transport 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 penalize 

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 NOX control. Wood biomass is a cleaner burning fuel than coal, which resulted in 

significantly reduced SO2emission rate. It also installed SNCR and overfire air as add-on 

emission controls to reduce NOX emissions. With the fuel conversion, the use of SNCR and 

overfired air, the current EPA approach in allocating allowances provided DTE Stoneman very 
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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 pollution 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 input 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.

The 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 did 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, state-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; market 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 months 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 to 
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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 months 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 SO2

allowances, 560 annual NOX allowances, and 455 ozone season NOX 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 principles 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 between 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 SO2 and NOX emissions reflect normal operation, and should be the allocation. 

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-HQOAR-2009-0491-4784) p. 3-5]

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)(4): The allocation of allowances under the CSAPR for EKPC's Spurlock Unit 4 

was inappropriately reduced based on the start-up date. 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 failed to account for the fact that Unit 4 did not come online until the 

second quarter of 2009 in its averaging calculations. Additionally EPA made improper 

assumptions about Units 4's historic emissions that severely limited the final allocation by more 

than 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 was 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 unit had no emissions for nearly 20% of the 24 month period 

EPA looked at for determining a unit's maximum historic emissions.
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EKPC raised the allowance under allocation in its formal comments to the proposed rule, but 

EPA did not address the comments in its 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, excluding 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 

SO2 allowances for 2012 and 2014, and NOX 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 Kentucky Power Cooperative (EKPC) 

(EPA-HQ-OAR-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 should be considered as a Group 1 or 

a Group 2 state in the SO2 CSAPR program. The EPA should also consider whether the group 

classifications for the SO2 program are potentially biased for some states or if the group 

classifications are even necessary. The justification 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 

states, while some Group 1 states may already meet their final 2014 Group 1 SO2 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 and 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 faulty projected emissions data. Commenter provides 

significant additional discussion on this issue including graphs illustrating the CSAPR Group 1 

and Group 2 state SO2 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-OAR-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 the 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 SO2 and NOX programs in the first place, and underlying problems with 

EPA's budget methodology.
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Comment (Q)(1): EPA’s revision also does not resolve the questionable fact basis for Texas’ 

inclusion in the annual SO2 and NOX programs in the first place. The revision does not provide 

any additional 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 Texas in the annual 

SO2 and NOX 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, this is likely caused by a nearby 

steel mill. Providing a small increase to Texas’ SO2 budget, and an extremely small increase to 

Texas’ NOX budget, does not correct EPA’s underlying methodology in assigning emissions 

budgets. These budgets have placed disproportionately 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 states’ 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 additional 

1640 tons of SO2 for the annual program and only 24 additional tons of NOX tons during the 

ozone season. The increase for NOX 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 cooperatives 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 budgets, 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 effects of CSAPR. The 

consequences would be rolling blackouts. [Letters: San Miguel Electric Cooperative (EPA-HQOAR-2009-0491-4766) p. 2-3]

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 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 with 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 disproportionately 

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 NOX
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budget fails to allow for economic recovery and growth; and 3) EPA must re-run its modeling to 

address identified errors given the extent 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 scope 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 

for 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 the 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 additional 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. The 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 

Generation (EPA-HQ-OAR- 2009-0491-4778) 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 Regulatory Impact Analysis for the final Transport Rule [EPA-HQ-OAR-2009-

0491-4193] 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 

become 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 revisions, 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 EGUspecific allowance allocations, validates the commenter’s positions regarding CSAPR’s flaws. 

[Letters: Louisiana Public Service Commission (EPA-HQ-OAR-2009-0491-4799) p. 1]
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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 supplemental proposal.

Comment (S)(1): In the Final and Supplemental Proposed Rules, EPA assumed unrealistic NOX

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 2010 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 NOX emission rates, Westar would need to 

install add-on controls consisting 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 

NOX 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 SOFA 

to meet the required NOX 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 NOX emission rates. In 2014, Westar must begin complying with its Regional 

Haze Agreement NOX 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 NOX annual and NOX ozone season revisions are shown in Tables 

2-1 and Table 2-2 of its comment letter. The 2014 NOX annual and NOX ozone season revisions 

are shown in Table 2-3 and 2-4 of the comment. The revisions result in a 6,340 ton increase for 

the Kansas 2012 NOX annual budget, a 2,779 ton increase for the Kansas 2012 NOX ozone 

season budget, a 5,693 ton increase for the Kansas 2014 NOX annual budget and a 2,487 ton 

increase for the Kansas 2014 NOX ozone season budget. [Letters: Westar Energy (EPA-HQOAR-2009- 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 during 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 requirements 
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for affected units in Kansas to meet the emission rate limitation by the consent decree’s 

deadlines, EPA is increasing the Kansas 2014 annual NOX budget. See the Final Revisions 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 NOX

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 NOX reduction (tons/year) to determine a cost per ton. The actual costs to Westar 

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 NOX annual and ozone season 2012 and 2014 budgets be revised 

to reflect the emissions that can be achieved 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-HQ-OAR-2009-0491-4777) p. 7]

RESPONSE: This comment is outside the scope of proposed revisions for which EPA solicited 

comments. See the final Transport Rule preamble section VI for further information related to 

the cost curve analysis for the rule. 

Comment (T)(2): The Final Rule used a cost analysis to determine what emission reductions 

could be achieved. For SO2 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 reductions 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 

SO2 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 Trona and byproduct disposal 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 SO2 emissions for BPU’s units at the 

$500/ton cost threshold. BPU requests that the Kansas SO2 annual 2012 and 2014 allowances be 
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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 the 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 (EPAHQ-OAR-2009-0491-4779) p. 2]

RESPONSE: This comment is outside the scope of the revisions 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 unit-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 

consider 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 demonstration 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 Transport 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 current 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 other 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 local emissions. [Letters: Kentucky Division for Air Quality (EPA-HQ-OAR2009-0491-4797) p. 1]
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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 Rule (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 

"maintenance" 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 outlined 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 Quality (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 remedy 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: Wisconsin Industrial Ratepayer Group (EPA-HQOAR-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 areas 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 

established 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 regulations. [Letters: 

Omaha Public Power District (EPA-HQ-OAR-2009-0491-4747) p. 3]
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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 the 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 

will 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 requirements 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: 

North 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 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 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-meritorder dispatch.

Comment (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 EPA 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. 
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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 NOX and SO2. The facilities (and other similar sources retrofitted during the baseline period) 

fall into a gap between existing sources and new sources. 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 or 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 RPS 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 increase 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 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, changes to allocation 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 note 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 NOX 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 final 
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CSAPR and take public comment on Louisiana's inclusion. [Letters: Lafayette Utility Systems 

(EPA-HQ- OAR-2009-0491-4807) p. 6-7; Louisiana Chemical Association (LCA) (EPA-HQOAR-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 SO2 Group 2 state and Missouri as an SO2 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 SO2 Group 1 allowances for 

compliance in SO2 Group 2 states. This should be allowed because Group 1 states are subject to 

greater SO2 reduction stringency than Group 2 states. See 76 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, at 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 Generating Station is short about 25% of the required allowances for SO2, ozone season 

NOX, and annual NOX for 2012 and 2013. After 2015 when the emission controls are fully 

operational, the Station will have excess allowances. EPA should provide the additional 

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-HQOAR-2009-0491-4804, 4826) p. 5-6]

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. 

(AA) EPA should initiate a SIP Call for reduced and modified CSAPR NOX Budgets 

necessary to achieve the 2008 Ozone NAAQS.
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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 memorandum 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 deadline 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 before the end of 2012 and is therefore required under the Court's reasoning. 

Initiating a SIP call now would also give states the first chance to develop and submit SIPs 

themselves. Also in response to previous comments EPA stated that it would propose a rule 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 NOX control decisions. 

[Letters: Exelon (EPA-HQ-OAR-2009-0491-4810) p. 38-40]

RESPONSE: This comment is outside the 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. SO2 allowance that EPA expected 

would sell 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% predicted 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 final Transport Rule docket for further information on these issues. 

Refer to the Regulatory Impact Analysis for the final Transport Rule [EPA-HQ-OAR-2009-

0491-4193] for a benefit analysis and an analysis of the costs of the rule.

(CC) IPM statewide heat inputs 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 to 
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resolve specific dispatch issues, 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 

total 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 model, 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 historic 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 units 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 

of 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 allowances 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 NOX (and to a lesser extent SO2) 

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 EPA 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 consistent with a heat input 

equivalent of 29% capacity factor. This would result in the allocation of 116 annual and 79 
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ozone seasons NOX allowances, and 6 annual SO2 allowances. [Letters: Fox Energy Company 

LLC (EPA-HQ-OAR-2009-0491-4815) p. 1-4]

RESPONSE: These comments are outside the scope of the revisions proposed and upon which 

EPA solicited comments. However, 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. See the 

preamble for the final Transport Rule and the final Transport 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, and 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 Arkansas 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/Galveston 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 

Louisiana’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 CSAPR. [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 states’ 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 the 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 January 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]
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RESPONSE: This comment is outside the scope of the revisions 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-OAR-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 

calculated 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 TSD 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 Support 

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 according 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 from 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-OAR-2009-0491-4761) p. 1, Attachment 

A; Luminant (EPA-HQ-OAR-2009-0491-4818) p. 13-15, Attachments 1, 5, & 6; North Carolina 
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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-2009-0491- 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-HQ-OAR-2009-0491-4747) p. 3; Utility 

Air Regulatory Group (EPA-HQ-OAR-2009- 0491-4823) p. 2, 4, 8; We Energies (EPA-HQOAR-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-HQOAR-2009-0491-4757) p. 2-4; Southern Company (EPA-HQ-OAR-2009-0491-4744) 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 Electric Cooperative (EPA-HQ-OAR2009-0491-4766) 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-HQOAR- 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 LLC (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 Regulatory 

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 a 
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particular portion of the petition for reconsideration 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 methodology 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 modeling). 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 its 

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 modeling 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 displacing 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 generation 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. 
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6.2) Comments on Heat Rates, NOX Emission Rates, and SO2 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 those 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 during 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 NOX Emission Rates

RESPONSE: See Section 2 “NOX Rates” 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. The NOX rates modeled are based on historic NOX rates reported to EPA by 

sources themselves in 2009. In most cases, the NOX 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 NOX Burner (LNB) 

installation or an individual or collective emission rate/tonnage requirement imposed by a 

consent decree. 

EPA disagrees with commenters’ arguments that NOX 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 NOX rates (that served as input 

assumptions to EPA’s power sector 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 demonstrated 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 NOX emission rate in the unit-level outputs from the 

Transport Rule modeling projections is different from that observed in 2009, Section 2 of the 

IPM Documentation Supplement (noted above) describes how and when the 2009 NOX rates 

were modified to better reflect the sources’ emission rates in a future year under different policy 

scenarios. In EPA’s modeling projections of the Transport Rule’s emission reduction 

requirements for annual and ozone-season NOX, sources in covered states that did not already 
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have a LNB shift to a lower NOX emission rate to reflect the addition 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 strategy 

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 complying with their 2012 and 2014 

assurance levels under for annual NOX and ozone-season NOX under the program, supporting the 

notion that the NOX 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 mechanism 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 

expect 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 SO2 Emission Rates

RESPONSE: See Section 4 “Coal Switching – Bituminous to Subbituminous” 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. Additionally, see Section VII.C.2 of the Final 

Transport Rule preamble for a discussion of coal switching for SO2 compliance in 2012 and 

2014.

In addition to this, EPA reiterates two points regarding coal switching at particular units.

First, the Transport 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 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’s modeling projections 

demonstrate that regional shifts in coal consumption from higher-sulfur to lower-sulfur coal are a 

reasonable and cost-effective compliance response to the increased economic incentive under the 

Transport Rule programs to mitigate SO2 emissions. The unit level projections, however, in no 

way dictate any individual unit’s allowable 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.
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EPA disagrees with commenters’ arguments that individual 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 abovereferenced 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 and 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 requesting 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 less 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 

Several 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 plant had either emitted 

historically or was expected to emit in the future by the commenter. 
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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 this 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 based 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 unit-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 

comments 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 outside the scope of the revisions proposed 

and upon which EPA solicited comment. The allocation methodology is described in preamble 

section VII.D of the final Transport Rule. 

Comments on the use of historic heat input to determine allowance allocation are also outside the 

scope of the revisions proposed and upon which EPA solicited 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 preamble section VII.B of the final Transport Rule. The formal applicability determination 

process provisions can be found at 40 CFR 97.404(c), 504(c), 604(c), and 704(c).