1

SNPR Response to Comments Document

December 2011

I. Determination of Significant Contribution to Nonattainment of Ozone NAAQS

1. General 

(A)Commenter generally questions the validity of EPA’s conclusion regarding the six 

States determined to significantly contribute to nonattainment in downwind States 

and covered in this SNPR, especially based on the Allegan, MI receptor.

Comment: Why were States that did not significantly impact a non-compliance monitor 

included in this rulemaking? The goal of the rulemaking is to ensure that all monitor locations 

are in attainment by 2014. Including States that only showed a significant impact on a 

maintenance monitor is excessive and does nothing to accomplish the goal. [Oklahoma 

Municipal Power Authority (OMPA) (EPA-HQ-OAR-2009-0491-4573), p. 2]

RESPONSE: The comment is outside the scope of the SNPR because it addresses issues that 

were within the scope of the request for comments in the proposed Transport Rule but not in the 

SNPR. While EPA is not reconsidering or reopening the issue, we note that the issue was 

previously addressed in the final Transport Rule, section V.C.2, 76 FR 48227, August 8, 2011

and that the North Carolina v. EPA opinion requires EPA to give independent meaning to the 

interfere with maintenance prong of section 110(a)(2)(D)(i)(I). Further, EPA notes that the 

commenter incorrectly describes the objective of the Transport Rule.

Comment: PSO and AEP respectfully submit that the data included in the proposal does not 

support EPA's conclusion that emissions from EGU sources in Oklahoma significantly contribute 

to the projected maintenance issues at the Allegan County, Michigan monitor, or that further 

reductions in NOX emissions from these sources will address the modeled maintenance issue. 

The monitor in question has already attained the 1997 ozone standard, and EPA's modeling 

erroneously predicts a maintenance issue at this location. Moreover, even if the modeled values 

were accurate, they are the result of a well understood phenomenon resulting from rush-hour 

mobile source emissions in the Chicago area and no additional reductions in Oklahoma will aid 

in maintaining the standard. [Public Service Company of Oklahoma (EPA-HQ-OAR-2009-0491-

4600), p. 2-3.]

RESPONSE: EPA’s methodology for identifying nonattainment and maintenance receptors is 

based on using modeling to project measured air quality for specific monitors, not on the 

designation status of an area as explained in section III.D of the preamble to the final 

supplemental. EPA believes this approach is appropriate for reasons explained in section V.C.2 

of the preamble to the final Transport Rule. 76 FR 48230, August 8, 2011. 

The commenter claims that ozone at the Allegan County monitor is the result of rush-hour 

mobile source emissions in Chicago and no additional reductions in Oklahoma will aid in 

maintaining the standard. However, the commenter provides not analyses or references to 
2

substantiate this claim. EPA’s CAMx source apportionment modeling shows that 10 states 

(including Oklahoma) contribute above the 1% of the ozone NAAQS threshold to Allegan 

County. EPA’s modeling does show that the largest ozone contribution is from Illinois. But that 

does not change the fact that 9 other states interfere with maintenance in Allegan County and it 

does not alleviate the need for those states, including Oklahoma, to eliminate their interference 

with maintenance. Further, the North Carolina v. EPA opinion requires EPA to give 

independent meaning to the interfere with maintenance prong of section 110(a)(2)(D)(i)(I).

Comment: EPA's decision to use the CSAPR program as the basis for further NOX reductions in 

Oklahoma is not sound for all of the reasons presented in previous comments submitted on the 

proposed Transport Rule by AEP, the Utility Air Regulatory Group (UARG). The Edison 

Electric Institute (EEI), the Midwest Ozone Group (MOG) and ignores the substantial additional 

reductions already required to be made under the Regional Haze SIP developed by Oklahoma, 

and proposed to be approved by EP A in a notice earlier this year. The reductions required under 

the Regional Haze SIP will more than adequately address any contribution of NOX emissions by

Oklahoma sources to the Allegan County, MI monitor. [Public Service Company of Oklahoma 

(EPA-HQ-OAR-2009-0491-4600), p. 2-3.]

RESPONSE: EPA’s methodology for identifying nonattainment and maintenance receptors is 

based on using modeling to project measured air quality for specific monitors, not on the 

designation status of an area as explained in section III.D of the preamble to the final 

supplemental. EPA believes this approach is appropriate for reasons explained in section V.C.2 

of the preamble to the final Transport Rule, 76 FR 48230, August 8, 2011. Additional responses 

on the MOG modeling data are also contained in section V.C.2. Responses to CAIR-related 

baseline comments are in section V.B. of the preamble to the final Transport Rule, 76 FR 48223, 

August 8, 2011. EPA disagrees with the comment that the Regional Haze SIP will more than 

adequately address any contribution of NOX emissions by Oklahoma sources to the Allegan 

County, Michigan monitor. EPA agrees that the regional haze SIP requirements will require 

reductions in NOX emissions from several EGUs in Oklahoma, and EPA expects to issue a final 

approval of those regional haze NOX requirements by December 31, 2011. Those required 

reductions, however, have compliance dates five years after EPA’s SIP approval — that is, late 

2016. This time period is much later than 2012. Accordingly, those requirements would not 

have affected EPA’s 2012 base case inventory for Oklahoma, nor would they have affected 

EPA’s determination of whether Oklahoma’s contribution was sufficient for inclusion under the 

Transport Rule. 

Comment: EPA's application of its CSAPR modeling methodology to the state of Oklahoma 

requires the entire state (along with 3 other states in this supplemental notice of proposed 

rulemaking (SNPR) (Iowa, Wisconsin and Kansas)) to significantly reduce, at significant total 

cost, EGU emissions of NOX during the ozone season to address a modeled maintenance issue. 

The area in question is a single county (Allegan County) in Michigan. The county is located in 

western Michigan in an area directly East across Lake Michigan from the Chicago/Milwaukee 

metro areas. It is important to note that the monitors in the area show the county to be in 

attainment. The modeling data developed by the Midwest Ozone Group (MOG) and its 

Industrial Modeling Coalition, used in conjunction with ambient air quality data collected by 
3

USEPA, show that not only are transport criteria met by the existing CAIR program, the 

requirements of which are still in effect and under which significant emissions reductions have 

been achieved and continue, but full compliance with the NAAQS targeted by this rulemaking 

are satisfied for this county. [Public Service Company of Oklahoma (EPA-HQ-OAR-2009-0491-

4600), p. 2-3.]

RESPONSE: EPA’s methodology for identifying nonattainment and maintenance receptors is 

based on using modeling to project measured air quality for specific monitors, not on the 

designation status of an area as explained in section III.D of the preamble to the final 

supplemental. EPA believes this approach is appropriate for reasons explained in section V.C.2 

of the preamble to the final Transport Rule, 76 FR 48230, August 8, 2011. Additional responses 

on the MOG modeling data are contained in section V.C.2 of the preamble to the final Transport 

Rule, 76 FR 48230, August 8, 2011. The comment suggesting that the transport criteria are met 

by the existing CAIR program is outside the scope of issues we requested comment on in this 

SNPR, ignores the fact that this rule is to replace, not supplement the CAIR, and was responded 

to in the record for the final Transport Rule. Responses to CAIR-related baseline comments are 

in section V.B. of the preamble to the final Transport Rule, 76 FR 48223, August 8, 2011. 

Responses to comments on current air quality in Allegan County are in section III.D of the final 

supplemental rule preamble.

Comment: The reductions required in the six states are significant. The proposed 2012 

Oklahoma budget 21,835 tons is 56% lower than the total of the highest emissions for each unit 

during 2006 through 2010, and 42% lower than the total 2010 emissions for the applicable units 

in the state. For PSO plants operating in Oklahoma, the allocations would require these facilities 

to reduce emissions by 65% from their maximum annual during 2006 through 2010, and 52% 

below their 2010 emissions. Of these units, only two are coal combustion units with the 

remaining being natural gas. PSO and AEP have developed plans and a schedule to install 

additional NOX controls on many of these units. However, those controls are scheduled to be 

phased in over several years. Based on our experience of installing controls for NOX emissions 

over the past several years, there would not be enough time to complete installation of all of 

these controls by the 2012 ozone season, even if expedited delivery and installation were 

feasible. [Public Service Company of Oklahoma (EPA-HQ-OAR-2009-0491-4600), p. 2-3]

RESPONSE: EPA made a number of adjustments between proposal and final that affect the 

size of the Oklahoma budget. See the preamble to this final rule, section III.B.iv, for an 

explanation of how the final budget was calculated. In calculating the 2012 budget, EPA did not 

assume NOX combustion control installations or upgrades in 2012. Sources will be able to phase 

in those controls as the above comment suggests.

Comment: PSO does not believe that the timelines and stringent budgets within this Proposed 

Supplemental Transport Rule are justified by the minimal maintenance impact predicted by the 

model and the total costs of imposed reductions, especially considering the number of 

states/units affected only because of this one receptor. [Public Service Company of Oklahoma 

(EPA-HQ-OAR-2009-0491-4600), p. 2-3]. Given that the model predicts that this single 

receptor still attains the ozone air quality standard but is marginally approaching levels that 
4

suggest additional reductions will assure maintenance of the standard, and that the integrity of 

the modeling results is uncertain as discussed below, it is excessive to require such significant 

reductions at such a significant cost. The cost to achieve this projected 0.1 ppb reduction is not 

justified. In addition, the short compliance timeframe imposes greater costs to expedite 

construction schedules than accounted for in EPA's estimate. Oklahoma should not be included 

in the CSAPR program. Public Service Company of Oklahoma (EPA-HQ-OAR-2009-0491-

4600), p. 2-3]

RESPONSE: See preamble section III.D of this final rule for discussion of EPA’s justification 

for inclusion of the Allegan site as a receptor, including discussion of how recent air quality

monitoring reinforces EPA’s position. As noted in this preamble discussion, a very large 

proportion of ozone at the Allegan receptor is caused by upwind state contributions. 

Accordingly, it is especially important for such a location to ensure that upwind states are 

meeting the requirements of section 110(a)(2)(D)(i).

EPA finds that Oklahoma clearly contributes to this ozone problem receptor. Oklahoma 

contributes more than 2 ppb, which is more than twice the threshold. 

EPA finds the costs imposed by the rule to be modest in comparison to the types of controls 

routinely in place elsewhere. For example, for Oklahoma EPA predicts, at most, additional low 

NOX burner (LNB) installations on certain facilities. Such technologies, and more stringent 

controls such as selective catalytic reduction (SCR), have routinely been in place for states in the 

areas of the eastern United States which contribute to downwind state ozone nonattainment. One 

illustration of the degree of SCR installation may be seen by comparing 2008 and 2009 annual 

NOX emissions. Because CAIR essentially required SCR installations to operate year round, 

which were not required to operate year-round in 2008, nearly one million tons of NOX was 

reduced between 2008 and 2009. EPA finds the costs of LNB controls that may result from the 

rule’s inclusion of Oklahoma to be very reasonable.

EPA has considered the commenter concerns with respect to the compliance schedule. In the 

final rule, EPA is setting the Oklahoma 2012 ozone season NOX budget at a level that reflects 

emission reductions achievable through actions (such as some changes in generation unit 

dispatch) that do not include additional LNB installations or significant changes in dispatch of 

certain oil/gas units. EPA is setting the Oklahoma ozone season NOX budget for 2013 and 

beyond at the level that was proposed in the SNPR, i.e., to reflect NOX levels achievable with 

additional LNB installations that can be completed before the 2013 ozone season without 

necessitating the shutdown of units during the summer peak demand period in 2012. 

Comment: USEPA has failed to completely examine its own record relating to the Allegan 

County ozone monitor (260030005). In examining the emission inventory from the proposed 

rule to the new modeling supporting the final rule, the emission inventories offer several 

alternative perspectives on why this monitor has suddenly changed from a monitor that was not 

of interest to a monitor that is now classified as Maintenance. These alternatives clearly show 

that this monitor should not be used to include additional states in the CSAPR program. [Public 

Service Company of Oklahoma (EPA-HQ-OAR-2009-0491-4600), p. 4-6.]
5

RESPONSE: EPA disagrees with the comment. EPA has carefully examined the information 

regarding the Allegan County ozone monitor and explained the relevance of this information in 

Section III.D of the preamble to the final supplemental rulemaking.

Comment: First, the states that are shown to contribute to the monitor based on the 2012 source 

apportionment modeling should be considered. These states can be grouped roughly as follows: 

Lake Michigan States Michigan, Indiana, Illinois, Wisconsin

Intermediate Range States -Iowa, Kansas, Missouri

Long Range States -Arkansas, Oklahoma, Texas

When the NOX inventories in the Lake Michigan and Intermediate Range States are examined 

based on the information in the Technical Support Documents for both the Proposed and Final

Modeling, the total NOX inventories for these states have changed very little (2,683,513 Tons vs. 

2,684,457 Tons). The state level changes are shown in a table (see Table 1 of the comment 

letter) for these states.

This state level analysis shows that while significant decreases in the EGU portion of the 

inventory occur in all of the Lake Michigan and intermediate range states, the total NOX

inventory decreases by less, or increases. The contributions of other source categories from 

these nearer states therefore play a far more significant role in any projected maintenance for the 

Allegan County monitor. 

Past studies that USEPA modeling staff is aware of (as at least two of them were participants in 

various of these studies), determined that two of the critical states for driving ozone levels in 

western Michigan are Illinois and Wisconsin. For those two states, the total NO" inventory

increases while the EGU contribution decreases by some 34,728 tons between the cases. This 

clearly shows that other source categories are growing the inventory by some 97,699 tons. Many

of these other source categories also generate organic emissions concurrently with the NOX

emissions, which then reacts in the atmosphere over Lake Michigan to become ozone. This 

ozone then blows on shore in Western Michigan giving the elevated readings observed. 

Taking this one step further, if the four Lake Michigan States are considered, the numbers 

become an increase in total NOX of 16,316, but a decrease in EGU NOX of 150,850 tons, giving 

a total increase in NO" for all non-EGU sources of 167,166 tons. The inventory changes in just 

these four key states impacting the Allegan County monitoring site suggest that the VOC/NOX

ratio in the Lake Michigan area has been significantly shifted toward VOC's between the 

Proposal and Final Modeling. Since these changes have occurred in areas known to contribute to 

elevated ozone levels in Western Michigan, this strongly suggests that local, non-EGU sources 

are the cause of the increase modeled at the Allegan County monitor. With the reduced emission 

inventories of the EGU Sector in relation to the total NOX inventory, addressing the maintenance 

issues at the Allegan County monitor is being wrongly placed on the shoulders of EGUs and 

USEPA must perform more detailed source apportionment modeling that is able to identify

responsible source categories as well as states. In addition, this modeling must be extended to 
6

the 2014 Remedy Case, at a minimum, to properly demonstrate that the remedy USEPA is 

attempting to impose will actually achieve the predicted reductions. [Public Service Company of 

Oklahoma (EPA-HQ-OAR-2009-0491-4600), p. 4-6.]

RESPONSE: The comment is outside the scope of the SNPR to the extent it is suggesting EPA 

should make changes to the methodology used to quantify a state’s significant contribution. 

EPA addressed numerous comments regarding this methodology in the final Transport Rule and 

did not reopen this methodology for comment in the SNPR. . 

EPA agrees that there were numerous emissions updates, including updates to both the EGU and 

non-EGU components of the inventory between the proposal and the final rule. Some 

components of the emissions inventory increased and some decreased. In some cases EGU 

emissions went down between proposal and final. EPA agrees that, in general, mobile source 

emissions went up, due to the availability of updates to the mobile source emissions model 

(MOVES). EPA also agrees that changes to NOX and VOC emissions in the inventories used for 

air quality modeling could change the VOC/NOX ratio and thereby change projected ozone 

concentrations and contributions. In this regard, EPA reran CAMx for the final rule using the 

updated emissions inventories in order to explicitly account for any chemistry affects from the 

net changes in emissions. As a result of the updated modeling, the Allegan receptor went from a 

level that was slightly below the NAAQS in the proposal modeling to a level that was slightly 

above the NAAQS (for maintenance) in the final rule modeling. Therefore, the Allegan county

monitor became a maintenance receptor for the final rule analysis. This receptor was treated in 

the same way as every other potential nonattainment and/or maintenance receptor. EPA believes 

that the Allegan county receptor is a valid maintenance receptor and that it is not identified as a 

receptor due to any errors in the modeling or the calculation of future design values (see also 

responses to comments on current air quality in Allegan County are in section III.D. of the final 

supplemental rule preamble).

The commenter says that EPA’s approach to addressing the maintenance issues at the Allegan 

County monitor is being wrongly placed on the shoulders of EGUs and EPA must perform more 

detailed source apportionment modeling that is able to identify responsible source categories as 

well as states. The comment questions EPA’s approach that considers the collective contribution 

from all anthropogenic source categories of NOX (i.e., including both EGU and non-EGU 

emissions) from each upwind state along with cost in determining the amount of significant 

contribution. The commenter suggests an approach that is based on air quality contributions 

from individual sectors. This comment represents a broad challenge to EPA’s approach of 

considering cost and collective contribution. The identification of EGU emission reductions by

EPA in the remedy analysis was based on a determination that, at the cost thresholds selected 

under the final Transport Rule, the power sector offers the most cost-effective emission 

reductions to reduce a state’s significant contribution to nonattainment or interference with 

maintenance. Information on EPA’s decision to include cost as part of the analysis is provided 

in the final Transport Rule preamble.
7

Comment: USEPA redesignated Allegan County to attainment in 2009. In 2010, the monitor 

had a three year average value of 74 ppb and for the period including through 7/21/2011 a three 

year average of 77 ppb. As discussed in previous comments on the Transport Rule, the Midwest 

Ozone Group (MOG) supplied new modeling based on the use of a 2008 base year. That 

modeling does not indicate that the Allegan County monitor would be out of attainment with the 

84 ppb standard in any of the cases. The MOG modeling shows this monitor at roughly 81 ppb 

in the base year, 76 ppb in 2014, and 73 ppb in 2018 with CAIR level reductions (which did not 

include Oklahoma) and other rules in place. The actual monitor three-year average values are 

much more consistent with the 2008 values modeled by MOG and much less consistent with the 

values being generated by USEPA using the 2005 base year. We therefore continue to believe 

that USEPA has incorrectly used 2005 for the base year of its analysis and should re-perform its 

modeling using a base year of 2008. [Public Service Company of Oklahoma (EPA-HQ-OAR2009-0491-4600), p. 6.]

RESPONSE: The comment is outside the scope of the SNPR because issues concerning the 

base case were within the scope of the request for comments in the proposed Transport Rule but 

not in the SNPR. While EPA is not reconsidering or reopening the issue, we note that the issue 

was addressed in the final Transport Rule, section V.B, 76 FR 48223-48224. Additional 

information is available in section III.D of the preamble to the final supplemental rulemaking.

Comment: In 2008 the U.S. Court of Appeals for the D.C. Circuit found the Clean Air Interstate 

Rule (CAIR) to be “fundamentally flawed,” initially vacating and remanding it to EPA See North 

Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008). However some months later in December, the 

D.C. Circuit Court of Appeals remanded the CAIR without vacatur, North Carolina v. EPA, 550 

F.3d 1176 (D.C. Cir. 2008), instead, leaving CAIR in place until EPA cured the flaws in CAIR. 

Therefore CAIR is a viable rule and utilities must currently comply with the stringent nitrogen 

oxide (NOX) and sulfur dioxide (SO2) limits prescribed by the rule.

During the last half of the previous decade utilities have installed and continue to install 

equipment to control NOX to meet the requirements of CAIR. In Ameren’s case we have 

installed add-on controls including Selective Catalytic Reduction (SCR) and combustion controls 

including low NOX burners and over-fire air systems on Ameren's fleet of coal plants. Ameren 

has also been a pioneer in enhancing the use of combustion controls in addition to low NOX

burners, such as over fire air and combustion optimization systems to achieve cost effective 

reduction in NOX emissions. Installation of these controls began in the 1990s to enable Ameren 

to comply with the Acid Rain Program, state implementation plans and the NOX Budget Trading 

Programs and continued into the subsequent years to achieve regional reductions for the CAIR 

program.

EPA has assumed as part of its regulatory analysis that the CAIR program is not in place and that 

affected sources are not complying with the rules. This assumption is in error. By not including 

compliance with CAIR in its assumptions, the EPA analyses have over stated the impact of these 

sources prior to the imposition of the proposed inclusion of these six states into the ozone season 

control period of the CSAPR. This assumption completely invalidates EPA’s analyses and the 

results produced. EPA should redo the analyses assuming that CAIR is fully in place and the 
8

affected sources are complying with the regulations. EPA should view CAIR as the valid control 

program that it is and allow sources to smoothly transition to the future rules to be promulgated 

in a more reasonable time frame, just as was done between the NOX SIP Call trading program 

and the CAIR. [Ameren Corporation (EPA-HQ-OAR-2009-0491-4596), p. 2.]

RESPONSE: The comment is outside the scope of the SNPR because it addresses issues that 

were within the scope of the request for comments in the proposed Transport Rule but not in the 

SNPR. The comment also ignores the fact that the Transport Rule replaces, and does not simply

supplement, the CAIR. While EPA is not reconsidering or reopening the issue, we note that the 

issue was previously addressed in the final Transport Rule, sections V.B and V.C, 76 FR 48223-

48236, August 8, 2011. 

(B) Commenter supports generally EPA’s supplementary proposal.

Comment: The Sierra Club commends the EPA for recognizing the important role of interstate 

air pollution in the non-attainment and interference with maintenance of National Ambient Air 

Quality Standards (“NAAQS”), and its efforts to address the issue in the proposed rule. The 

Sierra Club is the oldest and largest grassroots environmental group, with over 1.3 million 

members. Sierra Club members live, work, attend school, travel and recreate in areas adversely 

by power plant emissions. Our members enjoy and are entitled to the benefits of natural 

resources that are adversely affected by interstate air pollution, including air, water and soil; 

forests and cropland; parks, wilderness areas and other green space; and flora and fauna. Our 

membership and their families include sensitive populations such as asthmatics, the elderly and 

children who are at elevated risk for deleterious health effects posed by power plant emissions.

Sierra Club supports EPA’s proposal to include six states in the cross-state rule’s ozone season 

NOX program: Iowa, Kansas, Michigan, Missouri, Oklahoma and Wisconsin. Using the 

methodologies and modeling previously available for public comment, EPA identified two 

additional counties that are having trouble maintaining the 1997 ozone standards: Allegan 

County, MI and Harford County, MD. EPA found that Iowa, Kansas, Missouri, Oklahoma and 

Wisconsin significantly contribute to Allegan County’s maintenance problem and Michigan 

significantly contributes to the maintenance problem in Harford County. EPA’s proposal 

includes NOX emissions budgets for all the covered units in the six states. The NOX emissions at 

issue, and the ozone it forms, causes significant harm to public health and the environment.

As EPA explains in the proposed rule, there has been ample time and stakeholder process for 

public comment on all aspects of modeling and methodology. EPA made all the relevant 

background data available for public comment previously in connection with the proposed 

transport rule. Reopening public comment on methodology and modeling would serve only to 

delay emissions reductions that are long overdue. The six affected states had incentive to review 

that proposal closely because it included all six states in at least one of the rule’s trading 

programs.

All states that are included in the proposed rule significantly contribute to ozone maintenance in 

other states. Although Sierra Club continues to maintain that EPA’s threshold should be lower, 
9

EPA used 1 percent of the NAAQS as the threshold for determining which states to include in 

this rule. For the 1997 8-hour ozone NAAQS of 0.08 ppm, the contribution threshold is 0.0008 

ppm (0.8 ppb). All states that contribute .8 ppb or above to a nonattainment or maintenance 

receptor are included in the rule for ozone season. Most of the six states contribute much more. 

For Allegan County, MI, Oklahoma contributes over three times that threshold at 2.8 ppb. 

Missouri contributes even more at 4.8, Wisconsin 2.2 ppb, Kansas 1 ppb and Iowa .9 ppb. The 

numbers show why it is vital that every contributing state do its fair share of reductions. If only

the few largest state contributors were responsible for reductions, the air quality standards could 

not be achieved. The sum of all the many small contributors forms a substantial portion of the 

total. For Harford County, only 42% of the total contribution is captured if a 5% threshold is 

used (4 ppb). Using a 1% threshold captures 81% of the total contribution to exceedances. For 

Allegan County, only 72% of the total is captured with a 5% threshold, while 92% is captured 

with a 1% threshold. [Sierra Club (EPA-HQ-OAR-2009-0491-4587), p. 1-2.]

RESPONSE: EPA concurs with the comments that issues concerning modeling and 

methodology should not be reopened, because adequate opportunity for public comment was 

already provided on these matters, and the comments supporting the inclusion of Iowa, 

Michigan, Missouri, Oklahoma and Wisconsin in the Transport Rule ozone season NOX

program. As explained in the preamble to this final rule, EPA is not finalizing a FIP for Kansas 

at this time for the reasons provided in section III.C.

Comment: In brief, we support EPA’s conclusion that these six states significantly contribute to 

nonattainment and interference with maintenance of the 1997 ozone NAAQS, as well as EPA’s 

application of the CSAPR remedial program to power plants in those states. Given EPA’s 

analysis and methodology employed in CSAPR, and the emission inventories for those and other 

states, we do not think EPA could come to a different conclusion, either as a policy or legal 

matter.

Specifically, we find no error in EPA’s application of CSAPR methodologies with respect to the 

significant contribution of Iowa, Kansas, Michigan, Missouri, Oklahoma, or Wisconsin to 

nonattainment and interference with maintenance of the 1997 ozone NAAQS in downwind 

states. Furthermore, we support the Agency’s decision not to reopen issues related to its overall 

methodology employed in CSAPR. Clearly, EPA’s decision is final with respect to the 

contribution of 20 other eastern states to ozone nonattainment and maintenance problems in 

downwind states, and to the establishment of emissions budgets and related FIP provisions for 

power plants in those states. As a matter of law and policy, EPA is required to apply the same 

methodologies to the six states addressed by the SNPR. Thus, we support EPA’s ozone season 

budgets and allocation of allowances to covered power plants in those states. [Clean Air Task 

Force, et al. (EPA-HQ-OAR-2009-0491-4588), p. 2.]

RESPONSE: EPA concurs with the comments supporting the inclusion of Iowa, Michigan, 

Missouri, Oklahoma and Wisconsin in the Transport Rule ozone season NOX program and the 

comments that issues concerning modeling and methodology should not be reopened, because 

adequate opportunity for public comment was already provided on these matters. As explained 
10

in the preamble to this final rule, EPA is not finalizing a FIP for Kansas at this time for the 

reasons provided in section III.C.

2. Iowa

A. Commenter supports EPA’s decision to include Iowa in the ozone season NOX

program. 

Comment: Based on the ozone levels in Iowa this year, as monitored by the statewide SLAMS 

network and reported by the State Hygienic Lab and in light of EPA’s upcoming change in the 

ozone NAAQS, Iowa’s inclusion in the supplement is entirely warranted. [Iowa Environmental 

Council (EPA-HQ-OAR-2009-0491-4572), p. 1.]

RESPONSE: EPA concurs with the comment supporting the inclusion of Iowa in the Transport 

Rule ozone season NOX program. Iowa is included in the Transport Rule ozone season NOX

program because of the contributions from NOX emissions in Iowa to the downwind maintenance

receptor in Allegan County, MI. Reductions in ozone season NOX emissions in Iowa from 

implementation of the Transport Rule will help reduce ozone concentrations within Iowa in 

addition to reducing ozone in downwind states.

B. EPA’s approach improperly includes Iowa.

Comment: The final Transport Rule elaborates extensively on EPA’s justification for not 

utilizing an updated emissions baseline to reflect reductions that have been made under the 

provisions of CAIR, attempting to draw a distinction regarding the enforceability or perceived 

lack thereof based on CAIR’s legal status because “unlike most regulatory requirements, the 

emission limitations contained in CAIR are only temporary.” EPA’s distinction is disingenuous. 

Certainly, EPA would not have hesitated to utilize its enforcement authority against a facility

that did not hold a sufficient number of emission allowances under CAIR. Controls were 

installed and are operated and emission limits imposed under state-issued permits that are 

federally enforceable, yet, EPA has not made it clear what, if any, controls are reflected in its 

modeling. Further, EPA takes the position that any costs associated with emission reductions 

already implemented are considered “sunk costs” and are not included in projected costs to 

comply with the Transport Rule’s requirements. Neither the emission reductions achieved to 

date nor the costs with achieving those emissions reductions are invisible. [MidAmerican 

Energy Company (EPA-HQ-OAR-2009-0491-4597), p. 3.]

RESPONSE: The comment is outside the scope of the SNPR because issues concerning the 

legal status of CAIR were within the scope of the request for comments in the proposed 

Transport Rule but not in the SNPR. While EPA is not reconsidering or reopening the issue, we 

note that the issue was previously addressed in the final Transport Rule, sections V.B and V.C,

76 FR 48223-48236, August 8, 2011.

Comment: Emissions of NOX in Iowa have declined substantially by virtue of the requirements 

imposed under CAIR; those emission reductions have a cost associated with them. As EPA 

recognized in the final Transport Rule, “ultimately we believe the electric power industry will 
11

pass along most of the costs of the rule to consumers, so that the costs of the rule will largely fall 

on the consumers of electricity.” It is critical that in making its determination to impose another 

layer of regulation on sources (and, most importantly, electricity consumers) in Iowa for 

allegedly making a less than 1 part per billion impact on an ozone monitor in Michigan that is in 

attainment of the ozone standard, EPA recognize both the emissions reduction efforts and cost 

impacts imposed on the citizens of Iowa. [MidAmerican Energy Company (EPA-HQ-OAR2009-0491-4597), p. 3.]

RESPONSE: EPA used the best practices available to estimate the future costs and benefits of 

this action and found that the emission reductions implemented under this rulemaking, combined 

with the reductions of the final Cross-State Rule, provide annual net benefits starting in 2014 

valued between $120 to $280 billion (2007$, 3% discount rate). The quantified PM2.5 and ozone 

health benefits within Iowa alone are valued between $790 million and $1.9 billion (2007$, 3% 

discount rate). To put the benefits in Iowa in context, EPA estimates that the total social costs of 

the entire rule, across all states, is $810 million (2007$, 3% discount rate). EPA also chose to 

finalize interstate trading programs as the remedy for the emission reductions to provide for the 

most cost-effective implementation of any emission controls. See section VII in the preamble to 

the final Transport Rule, 76 FR 48271, August 8, 2011.

Comment: The Allegan County, Michigan ozone monitor has been in operation, collecting data, 

since 1992. On May 12, 2010, prior to the issuance of the proposed Transport Rule on July 6, 

2010, the Michigan Department of Natural Resources & Environment (“DNRE”) submitted a 

request to EPA to redesignate Allegan County to attainment of the 0.08 parts per million 8-hour 

ozone National Ambient Air Quality Standard, to change the legal status of the areas from 

nonattainment to attainment, and to approve the maintenance plan as a revision to the Michigan 

State Implementation Plan. The DNRE’s request included a maintenance plan consistent with 

Clean Air Act Section 175A which demonstrated an attainment year inventory for 2008, an 

interim year inventory for 2018, and a projected maintenance inventory for 2021 under which the 

2021 inventories for VOC and NOX remained below attainment year 2008 emissions levels. 

The DNRE noted that “continuing reductions in ozone precursor emissions will be realized from 

fleet turnover, Maximum Achievable Control Technology (“MACT”) standards for hazardous air 

pollutants and federal diesel emissions programs.” In addition to Michigan’s regulations 

requiring less volatile consumer and commercial products, the DNRE noted that:

“Due to the legal uncertainty of the Clean Air Interstate Rule (CAIR) future year NOX 

reductions, a conservative 2018 and 2021 inventory was prepared without the NOX 

reductions assumed from CAIR for the two subject sources in this county.”(emphasis 

supplied) 

EPA approved Michigan’s request to redesignate the Allegan County, Michigan nonattainment 

area to attainment for the 1997 8-hour ozone standard on September 24, 2010 (See 75 Fed. 

Register 58315), prior to issuance of the final Transport Rule. EPA’s redesignation and approval 

of Michigan’s maintenance plan, assuming no underlying reductions from sources in Allegan 

County, or from upwind states under the Transport Rule is contrary to EPA’s assertion that NOX

emissions from sources in Iowa interfere with maintenance of the ozone standard in Allegan 
12

County, Michigan. MEC believes EPA has incorrectly included Iowa in the Transport Rule’s 

ozone season NOX reduction requirements.

In addition, EPA should reject arguments that Iowa and other states should be included in the 

NOX ozone season reduction requirements because lower ozone standards may be promulgated 

in the future. First, 0.08 parts per million is the existing 8-hour ozone National Ambient Air 

Quality Standard, and that is the standard which must be met today. Second, if the standard is 

ultimately lowered, there is no certainty that Allegan County, Michigan wouldn’t still be in 

compliance, as ozone levels in the area continue to trend downward. [MidAmerican Energy

Company (EPA-HQ-OAR-2009-0491-4597), p. 3-4.]

RESPONSE: See section III.D of the preamble to the final supplemental; and the preamble (76 

FR 48230) and Transport Rule Primary Response to Comments document in the docket to this 

rulemaking [EPA-HQ-OAR-2009-0491-4513]. This issue was discussed in the preamble to the 

NOX SIP Call (see 63 FR 57375, October 27, 1998, footnote 25), and the U.S. Court of Appeals 

for the D.C. Circuit’s decision in Michigan v. EPA, 213 F.3d 663 (2000), further supports the 

position that determinations of significant contribution or interference with maintenance under 

CAA section 110(a)(2)(D)(i)(I) should not be based on an area’s attainment designation. Also, 

under the Clean Air Act statutory structure, section 110(a)(2)(D)(i)(I) SIPs are due 3 years from 

promulgation of a NAAQS, and the statute allows designations to be done, in some cases, as late 

as 3 years after promulgation of a new NAAQS. This statutory structure suggests that 

designations are not relevant to the analysis of what is required to satisfy section 

110(a)(2)(D)(i)(I). Finally, this rule addresses significant contribution with respect to the 1997 

ozone standard only, and the requirements of the rule are necessary to address emissions that 

significantly contribute or interfere with maintenance of that standard. The commenter, 

however, misstates the level of the existing 8-hour ozone National Ambient Air Quality

Standard, which is 0.075 ppm.

3. Kansas

(A)Commenter(s) dispute EPA’s findings that Kansas significantly interferes with the 

Allegan, MI receptor.

Comment: Commenters first note the inadequate opportunity to comment on this issue, and 

assert that EPA is committing reversible error in not providing adequate opportunity to comment. 

No prior notice was given that Kansas interfered with a receptor in Allegan County, MI; 

previously, Kansas was linked for interference with maintenance only with a receptor in Dallas, 

TX. See Proposed Air Transport Rule, 76 FR 45210, 45269 (Aug. 2, 2010). No explanation was 

given in the SNPR for the change or for how the model shifted from a receptor south of Kansas 

to one north of Kansas in the interim. As Allegan MI was newly identified in the SPNR, 

commenter, who is with other Kansas utilities engaging Trinity Consultants, Inc. to review the 

EPA data and modeling, had no prior notice that this would be the area of concern, nor had 

Trinity had a prior opportunity to consider "whether there are errors in the Agency's application 

of the Transport Rule methodologies with respect to Kansas's significant contribution to 
13

nonattainment and interference of the 1997 ozone NAAQS" in Allegan County, MI. 76 FR at 

40665/2. [Westar Energy (EPA-HQ-OAR-2009-0491-4583), p. 1-3; Kansas City Board of Public 

Utilities (EPA-HQ-OAR-2009-0491-4585), p. 1-3.]

RESPONSE: The comment is outside the scope of the SNPR to the extent it seeks to challenge 

the methodology selected for quantifying significant contribution and interference with 

maintenance. EPA provided ample opportunity to comment on this methodology in response to 

the proposed Transport Rule. While EPA is not reconsidering or reopening the issue in the 

SNPR, we note that our methodologies were documented in the preambles for the proposed rule 

and final rule and the proposal and final rule Air Quality Modeling TSDs. There was ample 

opportunity to comment on these methods based on information provided in the proposed 

Transport Rule, three subsequent NODAs, and the additional opportunity to comment on the 

conclusion in the proposed SNPR. Further, EPA disagrees that the opportunity to comment on 

the linkage between Kansas and Allegan County was inadequate. The purpose of the SNPR was 

to provide notice of, and an opportunity to comment on, the linkage to Allegan (and Harford 

County, MD) that was identified in finalizing the Transport Rule. See the preamble, section 

III.C., of the final supplemental rule for the status of Kansas. 

Comment: In an August 19, 2011 email denying requests for extension of time to file comments 

in this matter, EPA stated: "The supplemental proposal and all of the key supporting 

documentation and model results were posted on our website on July 7, 2011 and the SNPR was 

formally published in the Federal Register on July 20, 2011." This statement is not true. Trinity

determined after initially reviewing the information posted on EPA's website that only emissions 

data were available, and not the actual CAMx model input and output files. Those files contain 

key supporting documentation for the proposed results. After contacting EPA Staff to obtain the 

files, Trinity sent on August 2 via overnight mail four 2-TB hard drives for EPA to upload the 

previously-unavailable files. This process was finally completed on August 11, when Trinity

received the uploaded files. August 11 thus is the date on which key supporting documentation 

was actually made available to Trinity. Once the files were received, Trinity began the weekslong process of transferring the data to Trinity's computers, performing necessary model runs 

using the newly available data, and processing results. Until those steps are completed, Trinity 

will not be in a position to determine whether EPA made any errors with respect to the claimed 

interference by Kansas in Allegan, MI. [Westar Energy (EPA-HQ-OAR-2009-0491-4583), p. 1-

3; Kansas City Board of Public Utilities (EPA-HQ-OAR-2009-0491-4585), p. 1-3.]

RESPONSE: Air quality modeling input and output files developed by EPA for the final 

Transport Rule were available in the docket on the date of signature of the final rule (see docket 

item EPA-HQ-OAR-2009-0491-4228, "Final Transport Rule Air Quality Modeling Data 

Drives"). This docket item provides instructions on how to obtain electronic copies of the final 

Transport Rule modeling input and output files. The material that was available for instant 

access online was sufficient to understand the application of the modeling in order to provide 

meaningful comment. The modeling code is available as a public resource in concert with the 

substantive material presented for immediate consumption and review online. Additionally, all 

of this material was available in the docket office as of the day of signature and prior to 

publication in the Federal Register. Also, a commenter submitted a follow-up analysis 
14

pertaining to certain modeling input files by Trinity Consultants that came in after the close of 

the 60-day comment period. These comments are responded to in section 6 (B), below.

Comment: As of the filing of the comments, Trinity has not had enough time to complete that 

process, which is critical to determining whether the SNPR modeling erred, and how such errors 

affected the final results. This precludes commenter from filing meaningful comments because 

of the limited nature of the topics (whether errors in the modeling occurred) allowed to be 

addressed at this time. A complete analysis of the actual CAMx model input and output files is 

needed to address matters of central relevance to the SNPR, and to show errors that would 

increase the likelihood that the current SNPR must be significantly changed. EPA's denial of an 

extension prevents the filing of meaningful analysis and comments that could invalidate any rule 

that results from the SPNR, and thus constitutes reversible error. [Westar Energy (EPA-HQOAR-2009-0491-4583), p. 1-3; Kansas City Board of Public Utilities (EPA-HQ-OAR-2009-

0491-4585), p. 1-3.]

RESPONSE: Our methodologies were documented in the preambles for the proposed rule and 

final rule and the proposal and final rule Air Quality Modeling TSDs. There was ample 

opportunity to comment on these methods based on information provided in the proposed rule. 

Comment: Trinity's initial assessment of the SNPR modeling suggests several areas that could 

uncover errors in the final results after full examination and analysis. In this regard, the projected 

maximum ozone concentration at the Allegan receptor was 85.1 ppb, or 0.1 ppb over the 

threshold of 85 ppb for a maintenance site. Previously, EPA projected that the concentration at 

the Allegan receptor was 84.7 ppb. The increased projected concentration between the Proposed 

Rule and the SNPR would seem to suggest that Kansas EGU emission projections increased 

since the prior projections were made. Yet, that is not the case; instead, Kansas EGU projected 

emissions dropped and other Kansas sources were projected to have higher emissions. Certainly, 

this calls into question whether Kansas EGU emissions should be considered to be the cause of 

interference at the Allegan MI receptor. [Westar Energy (EPA-HQ-OAR-2009-0491-4583), p. 1-

3; Kansas City Board of Public Utilities (EPA-HQ-OAR-2009-0491-4585), p. 1-3.]

RESPONSE: While EPA is not reconsidering or reopening the issue, we note that in both the 

Transport Rule proposal and final rule, CAMx photochemical modeling for the 2012 “no CAIR” 

base case was used to determine nonattainment and maintenance receptors. The final rule 

modeling was updated based on comments from the proposal. There were numerous emissions 

updates, including updates to both the EGU and non-EGU components of the inventory. The 

commenter is correct that in some cases EGU emissions went down between proposal and final. 

In general mobile source emissions went up, due to the availability of updates to the mobile 

source emissions model (MOVES). EPA ran CAMx for the final rule and followed the proposed 

rule methodology for determining nonattainment and maintenance receptors and contributions 

from upwind states. The Allegan receptor went from a level that was slightly below the NAAQS 

in the proposal modeling to a level that was slightly above the NAAQS (for maintenance) in the 

final rule modeling. Specifically, in the final rule modeling, ozone at the Allegan receptor was 

projected to be 85.1 ppb which is 0.2 ppb above the NAAQS (projected maximum design values 

of 85 ppb and higher are indicative of a maintenance problem). Therefore, the Allegan county 

monitor became a maintenance receptor for the final rule analysis. This receptor was treated in 
15

the same way as every other potential nonattainment and/or maintenance receptor. EPA believes 

that the Allegan county receptor is a valid maintenance receptor and is not identified as a 

receptor due to any errors in the modeling or the calculation of future design values. The 

modeling system was updated and the receptor was found to have a maintenance problem in 

2012. The methodology for the Transport Rule identifies the most cost-effective emission 

reductions available from upwind states, which are not necessarily from whichever sector may be 

the largest absolute contributor of emissions at any specific receptor. All upwind state NOX

emissions (including EGU, non-EGU point sources, and mobile sources) are tracked collectively

to determine state-level downwind ozone contributions. The contribution modeling was used to 

identify states with an ozone contribution that was at least 1% of the NAAQS. The identification 

of EGU emission reductions in the remedy analysis was based on a determination that, at the cost 

thresholds selected under the final Transport Rule, the power sector offers the most cost-effective 

emission reductions to reduce a state’s significant contribution to nonattainment or interference 

with maintenance. 

Comment: Further, the 0.1 ppb differential between the maintenance threshold and the projected 

concentration at Allegan heightens the possibility that any error could dramatically change the 

results. One problem with EPA's approach involves its reliance on linear modeling to represent 

nonlinear photochemistry for ozone and secondary PM formation. Linear modeling does not 

account for limiting factors that act differently in various emissions scenarios. A related concern 

involves the use of a latter version (5.3 versus 5.01) of the CAMx modeling program for SNPR 

purposes. Different chemical parameter values are found in the two versions, with a possible key

difference related to changed chemical reactivity values. What effect changes in these values, 

which are used to estimate the projected rates of ozone and PM species formation, had in the 

final results were not discussed in the SNPR. Because there simply has not been enough time 

since receipt of the previously unavailable files, Trinity has not yet been able to determine what 

effects these changes had on the results or whether they adequately represent the complex 

photochemistry involved in quantifying pollutant concentrations.

It appears also that the SNPR modeling also is biased in favor of attributing emissions to 

anthropogenic, rather than to biogenic, sources. This bias does not reasonably represent the 

source contributions at receptors, and fails to account for the limiting factor among the 

photochemical reactions when attributing source contributions to ozone formation. The SNPR 

modeling does not take into consideration the ozone formation conditions present near large 

water bodies, such as Lake Michigan where the Allegan MI receptor is located, which differ 

from those at other areas, and thus unless factored into the model, may lead to erroneous results. 

These preliminary assessments of some possible areas of concern in the modeling suggest areas 

that could produce erroneous results. Because an extension was not granted, commenter does not 

have a full analysis from Trinity that would determine whether these and possibly other problems 

have led to erroneous results. Commenter reserves its right to submit supplemental comments 

into the docket that more fully explain the potential errors raised by any such concerns after 

Trinity has had adequate time to conduct a full analysis of the model using the recently obtained 

data files. [Westar Energy (EPA-HQ-OAR-2009-0491-4583), p. 3-4; Kansas City Board of 

Public Utilities (EPA-HQ-OAR-2009-0491-4585), p. 3-4.]
16

RESPONSE: These comments question our use of CAMx as the modeling tool for the 

Transport Rule and our choice of the source apportionment technique for ozone. Our 

methodologies were documented in the preambles for the proposed rule and final rule and the 

proposal and final rule Air Quality Modeling TSDs. There was ample opportunity to comment 

on these methods based on information provided in the proposed rule. The focus of the CSAPR 

transport analysis for ozone was on the contribution to ozone at downwind receptors resulting 

from emissions of NOX from anthropogenic sources in upwind states irrespective of whether the 

anthropogenic NOX formed ozone through reactions with anthropogenic VOC or biogenic VOC. 

For this purpose, the APCA ozone source apportionment technique was used for the proposed 

and final rule modeling because this technique allocates ozone formed from anthropogenic NOX

reacting with either anthropogenic or biogenic VOC to the sources of anthropogenic NOX. 

Ozone formed from reactions of biogenic VOC and biogenic NOX are allocated not includes as 

part of the state contributions in the CSAPR modeling. The commenter claims that only the 

portion of the ozone formed from the reaction of anthropogenic NOX with biogenic VOC under 

“NOX limited” conditions should be allocated to the anthropogenic NOX and that ozone formed 

under “VOC limited” conditions should be allocated to biogenic sources. Specifically, the 

commenter suggests that we should have used an alternative technique (OSAT) which splits the 

ozone from anthropogenic NOX plus biogenic VOC to the biogenic sources and anthropogenic 

sources based on assumptions as to whether the ozone is formed under NOX-limited or VOClimited regimes. EPA disagrees with this comment because even when the amount of ozone is 

limited about the amount of biogenic VOC, the ozone is still formed by reactions with 

anthropogenic NOX. We did not get any comments on the proposed rule that said that we should 

have used OSAT. In addition, the commenter contends that EPA’s approach relied on a linear 

model. This is not correct since the chemical mechanism in CAMx includes non-linear 

chemistry associated with the formation of ozone and secondary PM2.5 species concentrations. 

The rationale for changes in the chemical parameter file in CAMx v5.3 versus v5.0 are 

documented in the CAMx v5.3 User’s Guide (docket item EPA-HQ-OAR-2009-0491-4380). 

This document clearly states the users should not “mix and match” a version of CAMx with a 

different version of the chemical parameter file, as suggested by the commenter. Rather, the 

chemical parameter files specified in the user’s guide for CAMx v5.3, as applied by EPA, should 

be used when running CAMx v5.3. The commenter contends that the SNPR modeling does not 

take into consideration the ozone formation conditions present near large water bodies, such as 

Lake Michigan where the Allegan, MI receptor is located. However, the commenter provides no 

information to support this contention. In fact, EPA’s CAMx air quality modeling and the MM5 meteorological modeling used to provide weather inputs to CAMx do include Lake Michigan 

(and other large bodies of water) in terms of the thermodynamic effects and differential 

deposition properties of these bodies of water on pollutant concentrations. EPA compared the 

CAMx ozone predictions for Allegan County to monitored data and found that the model 

predictions closely replicate observations, adding confidence to EPA’s model predictions for this 

location (see Appendix A of EPA-HQ-OAR-2009-0491-4140, "Air Quality Modeling Final Rule 

Technical Support Document").

4. Michigan

No comments received on this issue.
17

5. Missouri

(A) EPA’s supplementary proposal does not require full elimination of Missouri’s 

significant contribution.

Comment: Finally, Sierra Club notes that the cross state rule does not eliminate each of these 

states’ significant contribution to downwind ozone nonattainment and/or interference with 

maintenance. The Act requires EPA to promulgate FIPs for states that contain inadequate 

provisions “prohibiting...any source or other type of emissions activity within the State from 

emitting any air pollutant in amounts which will contribute significantly to nonattainment in, or 

interfere with maintenance by, any other State with respect to any such national primary or 

secondary ambient air quality standard...”. Nonetheless, EPA confesses in the Preamble to 

proposed rule that it has not satisfied this obligation for all of the states covered by the final 

rule’s ozone program, including, Missouri. EPA expressly explains that “[t]he one state 

addressed in the supplemental proposal for which EPA’s analysis identifies reductions that are 

necessary but may not be sufficient to satisfy section 110(a)(2)(D)(i)(I) with respect to the 1997 

ozone NAAQS is Missouri.” For this reason, the cross state rule and proposed supplement will 

not fully satisfy EPA’s 110(a)(2)(D)(i)(I) FIP duty. EPA must require additional reductions in 

ozone forming emissions that are sufficient to eliminate Missouri’s significant contribution to 

ozone nonattainment and/or interference with maintenance in the States to which it is linked. 

[Sierra Club (EPA-HQ-OAR-2009-0491-4587), p. 3.]

RESPONSE: EPA has noted that the Transport Rule FIP may not fully address Missouri’s 

obligations under section 110(a)(2)(D)(i)(I) with regard to the 1997 ozone NAAQS. The final 

rule states that further analysis is needed to determine if these FIPs do fully satisfy section 

110(a)(2)(D)(i)(I) or if additional reductions are needed. The FIP for Missouri makes 

measureable progress toward satisfying the requirements of section 110(a)(2)(D)(i)(I) with 

respect to the 1997 ozone NAAQS. To the extent that significant contribution to nonattainment 

and/or interference with maintenance is not entirely eliminated, EPA will address these instances 

in a future action. For more information, see sections IV.C (76 FR 48218), VI.A (76 FR 48246), 

and VI.D (76 FR 48263, August 8, 2011) within the preamble of the final Transport Rule, and 

see section IV of the Transport Rule Primary Response to Comments document [EPA-HQ-OAR2009-0491-4513].

(B) EPA is using databases that are out of date and do not represent current air 

quality.

Comment: EPA Should Use a More Recent Base Year Than 2005. EPA has used inventory and 

meteorological data that is not representative of current conditions. Inventories and meteorology

are available for 2008. Currently the Lake Michigan Air Directors Consortium (LADCO) is 

performing modeling with both 2007 and 2008 emissions and meteorological data. In addition 

the Midwest Ozone Group has performed modeling (see comments submitted by the Midwest 

Ozone Group, October 1, 2010 to the original proposed rule (75 Fed. Reg. 45210-45465 (August 

2, 2010)) that shows a totally different picture than that portrayed by EPA’s modeling. EPA’s 
18

reliance on non-current data produces results that are not reflective of today's environment and 

should not be relied upon as the basis of such a far reaching rule. EPA should redo its analysis 

with more recent and relevant data. In the case of Missouri's contribution to the maintenance and 

nonattainment monitors the July 11, 2011 Federal Register notice sites 3 monitors; Harris 

County, TX, Brazoria County, TX and Allegan County, MI.

● Harris and Brazoria, TX Counties - Both of these counties are located in the Houston 

metropolitan area; the most populous city in Texas surrounded by many large VOC and 

NOX sources from refineries, mobile sources, power stations and one of the largest ports 

in the US. Missouri's contribution to these monitors is 1 ppb ozone or less or 

approximately 0.2 ppb ozone over the 1% arbitrary threshold (0.8 ppb) EPA has chosen. 

EPA in its current analysis is using 2005 base case emissions that are significantly higher 

than those of later years. Commenter provides table developed by the Midwest Ozone 

Group using EPA compiled emissions data compares Missouri statewide NOX emissions 

from 1999 to 2009. Using the information presented in that table, if EPA would have 

chosen 2008 as its base year the NOX inventory for Missouri would have dropped by

129,580 tons. This would lead to a similarly large drop in EPA 2012 and 2014 projected 

emissions. Clearly this large of a reduction in NOX emissions would significantly lower 

Missouri's impact on these Texas monitors to the point of no significance.

● Allegan County, MI monitor – This county according to EPAs designation in the 

modeling performed is considered a maintenance monitor since its maximum 2012 ozone 

design value is 85.1 ppb ozone; 0.2 ppb over the threshold for an attaining county. 

According to EPAs modeling Missouri significantly contributes to this monitor. However 

this significant contribution is based on the projected 2005 emissions inventory. 

Commenter provides table developed by the Midwest Ozone Group using EPA compiled 

emissions data compares Michigan statewide NOX emissions from 1999 to 2009. Using 

the information presented in that table, if EPA would have chosen 2008 as its base year 

the NOX inventory for Michigan would have dropped by 95,775 tons. This would lead to 

a similarly large drop in EPA 2012 and 2014 projected emissions. Clearly this large 

reduction in Michigan NOX emissions (as well as those in Missouri) would have lowered 

the Allegan County monitor to an ozone level much below the significance threshold of 

84.9 ppb ozone.

Clearly if EPA would have chosen a more recent and relevant base emissions case that was 

reflective of current NOX emissions Missouri's impact on these 3 monitors would be 

insignificant. EPA needs to revisit this analysis using more current data sets that reflect actual air 

quality. [Ameren Corporation (EPA-HQ-OAR-2009-0491-4596), p. 4-7.]

RESPONSE: The comment about the base case is outside the scope of the SNPR because it 

addresses issues that were within the scope of the request for comments in the proposed 

Transport Rule but not in the SNPR. While EPA is not reconsidering or reopening the issue, we 

note that EPA took comment on the rationale for selecting 2005 as the base year and the use of 

monitoring data for the period 2003 through 2007 as the starting point for projecting ozone and 

PM2.5 concentrations in 2012 and 2014 in the Transport Rule proposal. Also see the Transport 

Rule Primary Response to Comments document in the docket to this rulemaking [EPA-HQ-
19

OAR-2009-0491-4513] on the use of 2005 as the base year and the use of 2003 through 2007 

monitoring data.

Comment: Current 2007-2009 8-hour ozone design values show major inconsistencies with the 

results of EPA’s analysis for the CSAPR. Commenter provides a table that shows a comparison 

of 2003-2009 8-hour ozone design values and EPA’s 2014 remedy case for selected monitors in 

Kansas and Missouri. As is evident from the table all of these monitors have current design 

values that are already lower than what EPA predicts for its 2014 remedy case. EPA by

overestimating the impact of states on downwind nonattainment and maintenance areas will tend

to increase the level of control perceived to be required to meet the desired goals. This will lead 

to the installation controls that in reality may not be needed. EPA’s base case selection and 

control assumptions are fatally flawed and need be re-analyzed using a more recent and relevant 

information. [Ameren Corporation (EPA-HQ-OAR-2009-0491-4596), p. 7-8.]

RESPONSE: This comment is outside the scope of the SNPR because it addresses issues that 

were within the scope of the request for comments in the proposed Transport Rule but not in the 

SNPR. While EPA is not reconsidering or reopening the issue, we note that EPA took comment 

on the rationale for selecting 2005 as the base year and the use of monitoring data for the period 

2003 through 2007 as the starting point for projecting ozone and PM2.5 concentrations in 2012 

and 2014 in the Transport Rule proposal. Also see the Transport Rule Primary Response to 

Comments document in the docket to this rulemaking (EPA-HQ-OAR-2009-0491-4513) on the 

use of 2005 as the base year and the use of 2003 through 2007 monitoring data. 

In response to the assertion that EPA overestimates the impact of states on downwind 

nonattainment and maintenance and thus increases the level of control perceived to be required 

to meet the desired goals, EPA refutes this notion on two grounds. First, EPA does not overstate 

the emission impacts from individual sources. It is very clearly described in the preamble 

section V.B of the program. Because the rule is substitution, not incremental, for CAIR, it 

cannot assume CAIR in its base case and any assertions that its base case overstates emissions 

because of its failure to reflect CAIR-driven reductions ignores this important component of the 

Court’s decision in North Carolina. On the second notion that it overstates the control required 

in the state, EPA also disagrees. The first controls that would be operated in a state would be 

those already in place (and in some cases already operating). Therefore, in many states the 

difference between the base case and the policy case emissions is not the installation of 

additional controls, but simply the operation of existing controls. The commenter’s generation 

portfolio is primarily located in Missouri and Illinois. EPA does not anticipate any new controls 

in these states in response to Transport Rule. In fact, for many of the programs in these states, 

the state is already emitting at levels less than their 2012 budget level, suggesting no additional 

reductions/controls are required from current levels. Where this is not the case, EPA modeling 

may be capturing additional reductions that are on the way because of state rules (as is the case 

with Illinois and its multi-pollutant rule requirements in 2012). Finally, any additional 

reductions that are driven by the Transport Rule (through fuel switching or other means) are 

reductions that are incremental to current levels and are necessary to eliminate that state’s 

significant contribution.
20

6. Oklahoma

(A)Commenter generally opposes inclusion of Oklahoma.

Comment: The inclusion of the new states in the ozone transport rule is another example of why 

EPA is getting beat up by the politicians and people who are in the know. As an environmental 

professional for 35 years I’ve always said EPA is its own worst enemy. You lose the trust of the 

people, and it’s a matter of time. In this case, the EPA is working against the State of OK 

because OK is causing a violation in one county in MI. Great model! [EST Inc. (EPA-HQ-OAR2009-0491-4570), p. 1]

Several individuals in Oklahoma similarly stated that they question the logic that Oklahoma's 

emissions could, in fact, have an impact on one single county in Michigan, and that this 

implausible notion is being used as the basis for including their state in these proposed rules. 

These commenters recommend that EPA should stop and consider the impact the proposed rule 

would have on PSC of Oklahoma and its generation fleet, and not include Oklahoma in the

Transport Rule. [Individual email comments (EPA-HQ-OAR-2009-0491-4608 through 4618), p. 

1]

RESPONSE: As explained in the preamble to the final supplemental rule, EPA is obligated 

under its Clean Air Act authority to protect human health and welfare. Using the notice and 

comment process, EPA is finalizing the supplemental rule based on our conclusions and taking 

into account public comments. The rule will help reduce ozone season NOX emissions that 

expose hundreds of million Americans to harmful health impacts from ozone pollution. EPA’s 

methodology for identifying nonattainment and maintenance receptors is based on modeled 

projections of measured air quality at specific monitors, not on the designation status of an area. 

EPA believes this approach is appropriate for the reasons explained in section V.C.2 of the 

preamble to the final Transport Rule. 76 FR 48230, August 8, 2011. Further, the North 

Carolina v. EPA opinion requires EPA to give independent meaning to the interfere with 

maintenance prong of section 110(a)(2)(D)(i)(I).

(B) EPA lacks a reasonable basis for concluding that Oklahoma significantly 

interferes with maintenance of the 1997 Ozone NAAQS in Michigan.

Comment: In the 2010 Proposed Transport Rule, EPA linked sources in Oklahoma with 

significant impacts in a nonattainment area in Tarrant County, Texas. The emission reductions 

required of Oklahoma in the 2010 Proposed Rule were not significant and did not require costly 

controls or the shut-down of units. In the Supplemental Proposal, EPA now abandons its claim of 

significant impacts in Texas and for the first time asserts that Oklahoma interferes with 

maintenance of the 1997 ozone NAAQS based exclusively on a newly-identified ozone 

maintenance receptor in Allegan County, Michigan. This new claim is not only based on a new 

wind direction, but also would require a 40% reduction from actual emissions in approximately

six months time. The maintenance area in question is roughly 700 miles from most of the 

affected EGUs in Oklahoma, and the area does not have a nonattainment problem.
21

Some of the commenters note that EPA's determination that it is necessary to regulate Oklahoma 

under CSAPR is arbitrary and capricious. EPA is proposing to include Oklahoma in the ozoneseason NOX program based solely on its projected significant contribution to or interference with 

maintenance of the ozone NAAQS in Allegan County, Michigan. Allegan County currently is in 

attainment. EPA is proposing to include Oklahoma in the ozone-season NOX program not 

because emissions from Oklahoma are causing any nonattainment problems, but because EPA's 

models predict that ambient ozone concentration in Allegan County will increase to 85.1 parts 

per billion ("ppb"), just 0.1 ppb above the 1997 ozone NAAQS. See 62 Fed. Reg. 38,856 (July

18, 1997).

EPA's decision to subject Oklahoma to regulation under CSAPR solely based on predicted 

increase in ozone of just 0.1 ppb is not supportable. The CAMx model is highly variable and will 

produce significantly different results based on relatively small changes in the underlying 

emissions inventory and other modeling assumptions. The emissions inventory data relied on by 

EPA contain a significant number of errors and, thus, raise concerns regarding the validity of 

EPA's modeling results. Additionally, the model relied on by EPA has a significant degree of 

uncertainty when used to predict future emissions. According to EPA's technical support 

documents, the predicted increase in ozone in Allegan County during the ozone season has 

degree of uncertainty of -3.0 to +3.6 percent of the normalized mean bias. The predicted 

exceedance of 0.1 ppb is well within the range of potential uncertainty and is not sufficient 

justification for subjecting Oklahoma EGUs to extremely burdensome and costly regulatory 

requirements. [Oklahoma Gas & Electric Company (OGE) (EPA-HQ-OAR-2009-0491-4590), 

p. 5; Oklahoma Utility Group (EPA-HQ-OAR-2009-0491-4591), p. 3-4; Public Service 

Company of Oklahoma (EPA-HQ-OAR-2009-0491-4600), p. 6-7; Western Farmers Electric 

Cooperative (EPA-HQ-OAR-2009-0491-4589), p. 6-7; Grand River Dam Authority ("GRDA") 

(EPA-HQ-OAR-2009-0491-4586), p. 3-4.]

RESPONSE: In response to comments on the proposed Transport Rule, EPA made numerous 

updates to the emission inventories used for the final rule modeling. As a result of all of the 

updates made to the modeling platform, the maximum 2012 ozone design value at the Allegan 

receptor went from 84.7 ppb (i.e., a level that was slightly below the NAAQS) in the proposal 

modeling to 85.1 ppb (i.e., a level that was slightly above the NAAQS) in the final rule 

modeling. This relatively small increase in ozone concentration between the proposal modeling 

and final rule modeling of 0.4 ppb is not “highly variable,” as is contended by the commenter. 

The Allegan county monitor was treated in the same way as every other nonattainment and/or 

maintenance receptor. EPA believes that the Allegan county receptor is a valid maintenance 

receptor and is not identified as a receptor due to any errors in the modeling or the calculation of 

future design values. As described in the Transport Rule Response to Comments document, 

EPA believes that it is inappropriate to use model performance results, such as normalized mean 

bias, as a quantitative indicator of model uncertainty in part because the modeling results are 

used in a relative sense to project measured concentrations to 2012 and 2014. In other words, 

EPA is not basing the Transport Rule purely on air quality modeling output, but on an 

application of that modeling output to real observed air quality data at the relevant sites. A 2002 
22

report by the National Research Council (Estimating the Public Health Benefits of Proposed Air 

Pollution Regulations) states that the accuracy of modeling is increased when the model 

predictions for a recent base period and a future time period are used in a relative sense as 

scaling (or response) factors to “calibrate” observed pollutant levels from the recent base period. 

The report states that, “This approach may help reduce the bias introduced by modeling errors 

and, therefore, may be more accurate than using model results directly (absolute values) to 

estimate future pollutant levels.” Thus, it is not appropriate to simply use base year model 

performance results as a quantitative measure or gauge of the uncertainty in the air quality 

modeling process.

Comment: Even assuming that EPA can include Oklahoma in the CSAPR based solely on 

modeled impacts, commenters are concerned about several uncertainties in EPA's modeling that 

need to be addressed in order to reasonably evaluate whether the Allegan County monitor 

represents a maintenance issue for the ozone NAAQS. A report on these uncertainties was 

prepared by Trinity Consultants and is included with various comment letters as Attachment A.

First, EPA's modeling overstates mobile source emissions by failing to account for new 

corporate average fuel economy standards and greenhouse gas emission standards for mobile 

sources. The latest version of the Motor Vehicle Emission Simulator was not used in EPA's 

modeling and typically predicts less VOC emissions compared to the version used by EPA for 

CSAPR. Second, EPA used different chemical parameters in the CAMx for the Supplemental 

Proposal than for the 2010 Proposed Rule. This change in chemistry is not explained. Third, the 

location of the Allegan County monitor near the banks of Lake Michigan creates cause for 

concern that EPA's model may not adequately address certain unique aspects of near-water 

chemistry or atmospheric conditions.

Other of the Oklahoma utility commenters referenced the following key findings from the 

Trinity Consultants report:

 Comparing the CSAPR to the proposed Transport Rule, NOX and VOC emissions were 

noticeably less. Considering that Allegan County was not identified as a non-attainment or 

maintenance concern in the proposed Transport Rule, EGUs do not appear to be the 

primary source category impacting Allegan County. Therefore, EGU s should not be 

required to make aggressive and disproportionate NOX reductions of 60% when other 

sources are having a more significant impact. 

 Mobile source emissions increased from those predicted in the proposed Transport Rule. 

EPA did not apply the most recent available version of MOVES for predicting the mobile 

emission impact. The newer version would likely project lower emissions from mobile 

sources which may show Allegan County to not be above the maintenance threshold.

 EPA changed the CAMx version used between the proposed Transport Rule and the 

CSAPR. The two versions of CAMx have different chemical parameters and represent a 

potentially significant change in methodology results. These changes may be enough to 

cause Allegan County to have been reclassified and a change in methodology this 

significant should not be made without the opportunity for public comment or adequate 

explanation of the impact of the differences. 
23

 EPA may have overestimated the anthropogenic contribution of NOX and VOC emissions. 

As a result, the costly controls imposed by CSAPR may not produce the reduced impact to 

Allegan County predicted. EPA should use the Ozone Source Apportionment Technology 

(OSAT) for CAMx and reevaluate the impacts to properly account for the limiting 

photochemical factors. 

 The Allegan County location has unique characteristics that may cause the modeling not to 

be representative of actual impacts. The effects of its proximity to Lake Michigan suggests 

that the impacts are more likely to be from more local sources that from such distances as 

Oklahoma sources.

Since the Allegan County receptor exceeds EPA's threshold for being a maintenance receptor by 

just 0.1 ppb, failure to account for these uncertainties in the modeling could significantly impact 

EPA's conclusion in the Supplemental Proposal. EPA should address these uncertainties before 

including Oklahoma in the CSAPR based on modeled impacts in Allegan County, Michigan. 

One commenter adds that they believe that the model has other errors that tend to overstate 

source emissions and the corresponding modeled impacts in Allegan County. Commenter 

reserves the right to supplement these comments if additional errors are identified. [Oklahoma 

Gas & Electric Company (OGE) (EPA-HQ-OAR-2009-0491-4590), p. 5; Oklahoma Utility

Group (EPA-HQ-OAR-2009-0491-4591), p. 3-4; Public Service Company of Oklahoma (EPAHQ-OAR-2009-0491-4600), p. 6-7; Western Farmers Electric Cooperative (EPA-HQ-OAR2009-0491-4589), p. 6-7; Grand River Dam Authority ("GRDA") (EPA-HQ-OAR-2009-0491-

4586), p. 3-4.]

In comments submitted in mid-November well after the close of the public comment period, 

some of these commenters provided further comment on this issue and attached a follow-up 

study from Trinity Consultants. The commenters note that EPA, in its Technical Support 

Document (“TSD”) for the Proposal, 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. 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.

These commenters state that Oklahoma is included in the Proposal based solely on a link to a 

projected future maintenance problem in Allegan County. If EPA had used the publicly

available default options for vehicle emissions in MOVES2010 as described in its TSD, Trinity’s 

analysis shows that the vehicle emissions contributed to Allegan County from upwind states 

would be roughly five percent less than what EPA actually modeled. Furthermore, because EPA 

predicts in the Proposal that future ozone concentrations in Allegan County will be just slightly
24

above the ozone standard (by just 0.1 ppb), this difference in vehicle emissions could affect 

whether or not Allegan County has a projected maintenance problem under CSAPR.

These commenters continue by stating that in other rulemaking actions unrelated to CSAPR, 

EPA has designated Allegan County as an attainment area for ozone based on actual, real-world 

monitoring data. EPA also approved a revision to the Michigan State Implementation Plan 

(“SIP”) that will maintain compliance with the 1997 8-hour ozone standard through 2021 in 

Allegan County. The SIP does not require emission reductions from out-of-state sources to 

maintain attainment. It is only in CSAPR modeling that EPA projects a future maintenance 

problem for Allegan County, and even there only by a very slight margin. If EPA were to utilize 

the public information as stated in the TSD for the vehicle emission modeling, we believe that 

the CSAPR modeling for Allegan County would show future attainment with the ozone standard 

consistent with actual monitoring data and the Michigan maintenance SIP for that area.

The commenters conclude by arguing that EPA’s authority to impose emission reduction 

requirements based on modeling is limited in important respects. A complete analytic defense of 

a model’s application is required in each case, and EPA must consider real-world data to ensure 

that modeled predictions are reasonable and accurate. Where real-world data contradict a model, 

EPA must address with reasonable analysis the discrepancies between its model and the actual 

data. Based on Trinity’s analysis, the commenters argue that it is not appropriate for EPA to 

issue a final rule without addressing the discrepancies noted and explaining why they deviated 

from the approach set forth in the TSD. EPA should also reconsider other aspects of the 

modeling, such as using maximum design values to identify maintenance sites, even though EPA 

guidance seems to call for the use of average design values in attainment modeling. [AES Shady

Point et al. (EPA-HQ-OAR-2009-0491-4739), p. 1-3 and attachment]

RESPONSE: These comments include questions about our use of CAMx as the modeling tool 

for the Transport Rule and our choice of the source apportionment technique for ozone. Our air 

quality modeling methodologies were documented in the preambles for the proposed rule and 

final rule and the proposal and final rule Air Quality Modeling TSDs. There was ample 

opportunity to comment on these methods based on information provided in the proposed rule. 

The focus of the CSAPR transport analysis for ozone was on the contribution to ozone at 

downwind receptors resulting from emissions of NOX from anthropogenic sources in upwind 

states irrespective of whether the anthropogenic NOX formed ozone through reactions with 

anthropogenic VOC or biogenic VOC. For this purpose, the APCA ozone source apportionment 

technique was used for the proposed and final rule modeling because this technique allocates 

ozone formed from anthropogenic NOX reacting with either anthropogenic or biogenic VOC to 

the sources of anthropogenic NOX. Ozone formed from reactions of biogenic VOC and biogenic 

NOX are allocated not includes as part of the state contributions in the CSAPR modeling. The 

commenter claims that only the portion of the ozone formed from the reaction of anthropogenic 

NOX with biogenic VOC under “NOX limited” conditions should be allocated to the 

anthropogenic NOX and that ozone formed under “VOC limited” conditions should be allocated 

to biogenic sources. Specifically, the commenter suggests that we should have used an 

alternative technique (OSAT) which splits the ozone from anthropogenic NOX plus biogenic 

VOC to the biogenic sources and anthropogenic sources based on assumptions as to whether the 
25

ozone is formed under NOX-limited or VOC-limited regimes. EPA disagrees with this comment 

because even when the amount of ozone is limited about the amount of biogenic VOC, the ozone 

is still formed by reactions with anthropogenic NOX. We did not get any comments on the 

proposed rule that said that we should have used OSAT. The rationale for changes in the 

chemical parameter file in CAMx v5.3 versus v5.0 are documented in the CAMx v5.3 User’s 

Guide (docket item EPA-HQ-OAR-2009-0491-4380). This document clearly states the users 

should not “mix and match” a version of CAMx with a different version of the chemical 

parameter file, as suggested by the commenter. Rather, the chemical parameter files specified in 

the user’s guide for CAMx v5.3, as applied by EPA, should be used when running CAMx v5.3. 

The commenter contends that the SNPR modeling does not take into consideration the ozone 

formation conditions present near large water bodies, such as Lake Michigan where the Allegan, 

MI receptor is located. However, the commenter provides no information to support this 

contention. In fact, EPA’s CAMx air quality modeling and the MM-5 meteorological modeling 

used to provide weather inputs to CAMx do include Lake Michigan (and other large bodies of 

water) in terms of the thermodynamic effects and differential deposition properties of these 

bodies of water on pollutant concentrations. EPA compared the CAMx ozone predictions for 

Allegan County to monitored data and found that the model predictions closely replicate 

observations, adding confidence to EPA’s model predictions for this location (see Appendix A of 

EPA-HQ-OAR-2009-0491-4140, "Air Quality Modeling Final Rule Technical Support 

Document"). The response to the commenter’s claims about the mobile emissions used in EPA’s 

air quality modeling are provided below.

Comment: In comments submitted by AES Shady Point above, they claim that EPA did not 

apply the most recent available version of MOVES for predicting the mobile emission impact

and that the newer version would likely project lower emissions from mobile sources which may

show Allegan County to not be above the maintenance threshold. On November 11, after the 

close of the public comment period, further comment was provided on the modeled mobile 

source emissions along with a study from Trinity Consultants. In the November 11 submittal, 

the commenters note that in the Emissions Inventory Technical Support Document (“TSD”) for 

the final rule, EPA stated that onroad vehicle emissions were “primarily based on the publicly

released December 21, 2009 version of the Motor Vehicle Emissions Simulator (MOVES2010).” 

However, the commenters claim that Trinity Consultants was unable to replicate EPA’s mobile 

source emissions using the publicly available information for MOVES2010. 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.

These commenters state that Oklahoma is included in the proposal based solely on a link to a 

projected future maintenance problem in Allegan County. If EPA had used the publicly

available default options for vehicle emissions in MOVES2010 as described in its TSD, Trinity’s 

analysis shows that the vehicle emissions contributed to Allegan County from upwind states 
26

would be roughly five percent less than what EPA actually modeled. Furthermore, because EPA 

predicts in the proposal that future ozone concentrations in Allegan County will be just slightly

above the ozone standard (by just 0.1 ppb), this difference in vehicle emissions could affect 

whether or not Allegan County has a projected maintenance problem under CSAPR.

If EPA were to utilize the public information as stated in the TSD for the vehicle emission 

modeling, the commenters believe that the CSAPR modeling for Allegan County would show 

future attainment with the ozone standard consistent with actual monitoring data and the 

Michigan maintenance SIP for that area.

Based on Trinity’s analysis, the commenters argue that it is not appropriate for EPA to issue a 

final rule without addressing the discrepancies noted and explaining why they deviated from the 

approach set forth in the TSD. [AES Shady Point et al. (EPA-HQ-OAR-2009-0491-4739), p. 1-3

and attachment]

RESPONSE: The calculation of onroad mobile emissions involves the use of the MOVES 

model code along with several input data sets. The inputs include a “database” with information 

for calculating emissions factors, vehicle miles travelled (VMT) data, and meteorological data. 

For the final Transport Rule, EPA used the MOVES2010 code that was released to the public on 

12/21/2009 (i.e., December 2009 release). In addition to the MOVES code, this release also 

included several default data sets that could be used as inputs for running MOVES. In general, 

the defaults are provided for users who do not have more appropriate, representative data for 

their particular application. There is no requirement to use the default data sets when running the 

MOVES model. As described in the Emissions Inventory Technical Support Document (TSD) 

and summarized below, EPA did not use all of the default data sets that came with the December 

2009 release for creating onroad mobile emissions for the final Transport Rule. The commenter 

misinterpreted the TSD and incorrectly assumed that EPA used all the default data sets that were 

included with the December 2009 release of MOVES. The TSD says that we primarily used 

MOVES 2010 to compute onroad emissions, but clearly states that we did not use all of the 

default data provided with the December release. Instead, we strove to use the best available 

data at the time of the modeling as input to MOVES. 

For the final Transport Rule modeling, EPA did not use the default “database” that came with the 

December release. Rather, we used the “database” created and released publicly in May 2010. 

As noted by the commenter, the December 2009 database contains errors that were subsequently 

corrected in the May 2010 version, and therefore EPA did not use the December 2009 version 

for the final Transport Rule Modeling.

For 2005, the TSD states that, “The onroad emissions were primarily based on the publicly

released 12/21/2009 version of the Motor Vehicle Emissions Simulator (MOVES2010) 

(http://www.epa.gov/otaq/models/moves/). MOVES was run with a state/month aggregation 

using county-average fuels for each state, state/month-average temperatures, and national default 

vehicle age distributions. 2005 Vehicle Miles Travelled (VMT), consistent with the 2005v2 NEI, 

were used.” For 2012, the TSD states “The onroad emissions were primarily based on the 2010 

version of the Motor Vehicle Emissions Simulator (MOVES2010) – the same version as was 
27

used for 2005... Vehicle Miles Travelled (VMT) were projected using growth rates from the 

Department of Energy’s AEO2009.” The TSD states that we used state-month specific 2005 

meteorology, not the default climatology that was included with the December 2009 release. The 

TSD also states that we used 2005 VMT from the 2005v2 NEI for our 2005 modeling, and that 

VMT based on DOE AEO2009 was used for our future year modeling. These are clearly not the 

default datasets that were included in the December 2009 release. Thus, EPA disagrees with the 

commenter’s assertion that the TSD does not provide adequate documentation on the 

meteorological data, VMT, and VMT growth rates EPA used for the final Transport Rule. With 

a base year of 1999, the default VMT is known to not properly reflect different growth rates in 

different states – even with a year as close to 1999 as 2005. The 2005 and 2012 state-specific 

VMT used by EPA provide a more appropriate representation of VMT for these years versus 

using the default 1999-based VMT data provided with MOVES. Since mobile source emissions 

of NOX and VOC are sensitivity to temperature, the use by EPA of 2005 meteorology, rather 

than climatological data, provides for greater consistency with the 2005 meteorology used to 

drive the air quality model. Thus, we believe that the onroad emissions developed for the final 

Transport Rule using MOVES 2010 with the May 2010 database and other inputs developed by 

EPA, as described in the TSD, provide a credible projection of onroad emissions for use in the 

Transport Rule air quality modeling. 

The commenter also ran the MOVES model using the “database” and other default inputs that 

came with the December release and found that using these default data produced onroad mobile 

NOX and VOC emissions that were lower than those generated by EPA. EPA disagrees with the 

commenter that onroad mobile emissions using the December 2009 defaults, which contain 

known errors, should be used for the Transport Rule modeling.

The onroad mobile emissions EPA created and used for the final Transport Rule were provided 

as state totals in the TSD and as county totals in files in the docket. Thus, the commenter had 

ample opportunity to review the actual emissions data used by EPA. The commenter requested 

and received from EPA the version of the “database” and other inputs that EPA used for 

calculating onroad mobile source emissions for the final rule. With these inputs, the commenter 

was able to successfully replicate EPA’s onroad mobile emissions. The commenter did not 

provide comments saying that EPA had made any errors in the application of these data.

Comment: In addition, the analysis provided by Trinity Consultants suggests that EPA's model 

tends to overstate the contribution of Oklahoma sources to ozone formation in Allegan County.

Commenters are concerned that the drastic emissions reduction required for Oklahoma in the 

Supplemental Proposal goes beyond what is required to address Oklahoma's impact. EPA also 

should consider that NOX emissions predicted for all source groups in Oklahoma, other than 

mobile sources, were lower in the modeling for the Supplemental Proposal than in the modeling 

for the 2010 Proposed Transport Rule. EGUs showed a decrease of 20,493 tons per year of 

NOX, while NOX emissions from mobile sources increased by 21,344 tons per year. Oklahoma 

showed an overall increase in VOC emissions in the modeling for the Supplemental Proposal 

compared to the 2010 Proposed Rule, but this VOC emissions increase is attributable to an 

increase in modeled emissions from mobile and non-point sources rather than EGUs. All told, 

these changes indicate that EGUs are not the likely cause of the newly identified maintenance 
28

issue in EPA's modeling for Allegan County, Michigan. EGUs in Oklahoma should not be held 

responsible for remedying an increase in emissions from other types of sources. [Oklahoma Gas 

& Electric Company (OGE) (EPA-HQ-OAR-2009-0491-4590), p. 6; Oklahoma Utility Group 

(EPA-HQ-OAR-2009-0491-4591), p. 4.]

RESPONSE: The comment concerning overstating the contribution of Oklahoma sources to 

ozone in Allegan County is outside the scope of the SNPR because it addresses modeling and 

inventory issues that were within the scope of the request for comments in the proposed 

Transport Rule but not in the SNPR. While EPA is not reconsidering or reopening the issue, we 

note that in both the Transport Rule proposal and final rule, CAMx photochemical modeling for 

the 2012 “no CAIR” base case was used to determine nonattainment and maintenance receptors. 

The final rule modeling was updated based on comments from the proposal. There were 

numerous emission updates, including updates to both the EGU and non-EGU components of the 

inventory. 

Comment: Furthermore, commenters question EPA's authority to include Oklahoma in the 

Supplemental Proposal based solely on modeled impacts in Allegan County, which is in 

attainment with the applicable ozone NAAQS. As noted, EPA is predicting possible impacts in 

Allegan County from Oklahoma sources based on its use of the CAMx. EPA's use of this 

computer-modeling approach is overly conservative and tends to exaggerate the impact of source 

emissions on air quality. EPA's modeling, at most, establishes a tenuous link to a predicted 

problem in Michigan, but does not establish that Oklahoma sources actually "contribute 

significantly to nonattainment, or interfere with maintenance of NAAQS," as contemplated by

the CAA. EPA oversteps the bounds of its authority by proposing to impose stringent 

requirements on Oklahoma sources to address an issue that does not exist in the real world.

[Oklahoma Gas & Electric Company (OGE) (EPA-HQ-OAR-2009-0491-4590), p. 6; Oklahoma 

Utility Group (EPA-HQ-OAR-2009-0491-4591), p. 4.]

RESPONSE: The comment is outside the scope of the SNPR because it addresses EPA’s 

authority and modeling issues that were within the scope of the request for comments in the 

proposed Transport Rule but not in the SNPR. While EPA is not reconsidering or reopening 

these issues, we refer the commenter to section IV.A of the final Transport Rule for a discussion 

of EPA’s authority, as well as section III.D of the preamble to the final supplemental rule for a 

discussion of the Allegan County, MI receptor. Additionally, in response to comments on the 

proposed rule, EPA performed a trajectory analysis to examine the upwind transport patterns on 

days with measured exceedances at the Transport Rule nonattainment and maintenance sites (see 

docket item EPA-HQ-OAR-2009-0491-4360). EPA’s trajectory analysis included backward 

trajectories from Allegan County for multiple times on exceedance days at Allegan not only for 

2005, but also for other years during the period 2003 through 2007. This analysis shows 

multiple days when air crosses portions of Oklahoma within three days of passing over Allegan 

County on days when an exceedance was measured at the Allegan County monitor in 2005 and 

on several days in the other years examined. EPA believes that the trajectory analysis 

corroborates the air quality contribution modeling which links emissions in Oklahoma to the 

ozone maintenance problem in Allegan County.
29

Comment: AES Shady Point believes there are significant technical flaws in the modeling and 

allocation process. In general terms, the need for significant reductions in Oklahoma for the 

maintenance of attainment in Allegan County, Michigan, which is over 900 miles from the AES 

Shady Point facility, does not make logical sense because Allegan County is directly across Lake 

Michigan from the Chicago/Milwaukee airshed. The emissions from that airshed (and Gary, IN 

and St. Louis, MO) would seem to dwarf any contribution from several hundred miles further 

away in Oklahoma. Modeling by Midwest Ozone Group does not indicate that Allegan County is 

expected to have attainment maintenance issues. The fact that Allegan County, Michigan 

already is in attainment with the NAAQS supports the exclusion of Oklahoma in the proposed 

rule. There is not an immediate non-attainment issue that needs to be addressed. It is 

appropriate to allow an orderly process and period to achieve compliance with a rule that is 

intended solely for maintenance of current attainment. [AES Shady Point (EPA-HQ-OAR-2009-

0491-4595), p. 5.]

RESPONSE: EPA’s methodology for identifying nonattainment and maintenance receptors is 

based on modeled projections of measured air quality at specific monitors, not on the designation 

status of an area. EPA believes this approach is appropriate for the reasons explained in section 

V.C.2 of the preamble to the final CSAPR. 76 FR 48230, August 8, 2011. EPA does not believe 

it would be appropriate to rely on the designation status of an area. The statute does not require 

EPA to do so. In fact, the statutory requirement that section 110(a)(2)(D)(i)(I) SIPs be 

submitted within 3 years of promulgation or revision of a NAAQS would make it difficult to do 

so, suggesting that Congress did not intend section 110(a)(2)(D)(i)(I) SIPs to be linked in any

way to designation status. Further, even areas that have never been in nonattainment or that have 

been re-designated to attainment (including those where the majority of pollution comes from 

out of state) continue to be at risk for falling into nonattainment due to the impact of emissions 

from upwind states. We therefore disagree with the commenter and continue to believe that 

Allegan was appropriately determined to be a maintenance receptor. See Section III.D of the 

preamble to the final supplemental.

Furthermore, the Transport Rule CAMx source apportionment modeling shows that 10 states 

(including Oklahoma) contribute above the 1% of the ozone NAAQS threshold to Allegan 

County. As would be expected, the largest ozone contribution is from Illinois. But that does not 

change the fact that 9 other states interfere with maintenance in Allegan County and it does not 

alleviate the need for those states to eliminate their interference with maintenance. Further, the 

North Carolina v. EPA opinion requires EPA to give independent meaning to the interfere with 

maintenance prong of section 110(a)(2)(D)(i)(I).

Comment: In addition to the Trinity Consultant's evaluation of the modeling methodology, 

AEP/PSO found a specific apparent error in the IPM TR Base Case Final results. PSO operates a 

combined cycle at its Northeastern Power Station. Units 1A and 1B are combustion turbines 

equipped with heat recovery steam generators that provide steam to the original Unit 1 turbine. 

The Unit 1 boiler has not operated since about 1999. Although the NEEDS v4.1 database does 

not include the Unit 1 boiler as an emission source, EPA's IPM file shows Unit 1 as emitting 

0.0789 Mton of NOX in the 2012 Base Case. This raises the question whether EPA has double 

counted Units 1A and 1B's emissions and whether EPA has accurately quantified emissions in 
30

the IPM projections. [Public Service Company of Oklahoma (EPA-HQ-OAR-2009-0491-4600), 

p. 7 plus attachment.]

RESPONSE: EPA did not double count units 1A and 1B emissions in its base case modeling. 

Double counting would suggest a number that was higher than historic levels. However, EPA’s 

base case modeling shows total ozone-season emissions for the Northeastern combined cycle 

facility of approximately 102 tons, where as the 2010 emission levels were approximately 145 

tons. EPA uses the three units as reported in EIA 860 by the source owner. The units are 

modeled as two combustion turbines and one steam turbine, as supported by the commenter. 

The model accounts for unit level emissions by taking the facility level emissions and 

distributing them among the three units. The steam turbine is dependent on the combustion 

turbines for operation, therefore, emissions from the facility are spread across all three units 

proportional to their generation. A failure to do so would suggest a unit that could generate 

electricity without any associated fuel use related to that generation. In reality, these emissions 

(the 79 tons referenced by commenter) would still occur, but would be emitted from the other 

two units at the facility. However, IPM attributes the emissions to the steam turbine to 

appropriately capture the economics. If this was not the case, and the model could generate 

electricity from a steam turbine without any corresponding emissions, then it would dispatch 

steam turbines as economic before the combustion turbines – a sequence that is not possible. In 

short, the facility level emissions are correctly captured at the Northeaster unit noted above and 

there is no double counting as speculated by the commenter. 

Comment: AEP PSO did an analysis of air parcel back trajectories for days in 2005 when ozone 

exceeded 80 ppb at the Allegan monitoring site. Their analysis identified two “elevated ozone 

days where the winds were originating far to the south of the Lake Michigan region showing a 

reasonable possibility of Oklahoma emissions participating in ozone formation that impacts the 

Allegan County region”. The commenter claims that this “calls into question the accuracy of the 

meteorological fields being used by USEPA as they relate to the transport from elevated sources 

in the Oklahoma region and the potential benefits of NOX emissions reductions from elevated 

sources in Oklahoma in reducing ozone at the Allegan County monitor in a meaningful fashion”. 

This work is included in an attachment to this letter titled "USEPA's Analysis of the Allegan 

County Ozone Monitor Is Incomplete and Does Not Demonstrate a Connection to the CSAPR 

Remedy Proposed in the SNPR". [Public Service Company of Oklahoma (EPA-HQ-OAR-2009-

0491-4600), p. 7 plus attachment.]

RESPONSE: In response to comments on the proposed rule, EPA performed a trajectory

analysis to examine the upwind transport patterns on days with measured exceedances at the 

Transport Rule nonattainment and maintenance sites (see docket item EPA-HQ-OAR-2009-

0491-4360). EPA’s trajectory analysis was more extensive than the analysis performed by AEP 

PSO in that EPA’s analysis included backward trajectories from Allegan County for multiple 

times on exceedance days at Allegan not only for 2005 but also for other years during the period 

2003 through 2007. In general, backward trajectory analyses are intended to show the upstream 

pathway followed by air that arrives over a particular location at a particular time. In EPA’s 

trajectory analysis we examined the airflow pathways within 3 days of when air crossed Allegan 

County on each day that an exceedance was measured at the Allegan County monitor. EPA’s 
31

trajectory analysis shows that air crossed over portions of Oklahoma within three days before

passing over Allegan County on several of the days when an exceedance was measured at the 

Allegan County monitor. EPA believes that the trajectory analysis corroborates the air quality

contribution modeling which links emissions in Oklahoma to the ozone maintenance problem in 

Allegan County.

Comment: Under the EPA's Supplemental Proposal, the State of Oklahoma is being required to 

significantly reduce emissions of NOX during the ozone season for the maintenance of a single 

county in Michigan (Allegan County). The county in question is hundreds of miles away from 

Oklahoma, and modeling data shows that Allegan County, Michigan, is not expected to have 

attainment maintenance issues and, in fact, is already in attainment with the NAAQS targeted by

the proposed rulemaking. It does not make sense for the EPA to require significant reductions in 

Oklahoma for attainment in Allegan County, Michigan, in an area directly across Lake Michigan 

from the Chicago/Milwaukee airshed (and also the Gary, Indiana, and St Louis, Missouri, 

airsheds), where these areas would be far greater contributors to nonattainment in Allegan

County, Michigan, than any contribution from Oklahoma. In addition, the fact that Allegan 

County, Michigan, is already in attainment, as shown by modeling, supports the exclusion of 

Oklahoma in the Supplemental Proposal rulemaking. [Oklahoma Attorney General (EPA-HQOAR-2009-0491-4592), p. 8.]

RESPONSE: EPA’s methodology for identifying nonattainment and maintenance receptors is 

based on modeled projections of measured air quality at specific monitors, not on the designation 

status of an area. EPA believes this approach is appropriate for the reasons explained in section 

V.C.2 of the preamble to the final CSAPR. 76 FR 48230, August 8, 2011. EPA does not believe 

it would be appropriate to rely on the designation status of an area. The statute does not require 

EPA to do so. In fact, the statutory requirement that 110(a)(2)(D)(i)(I) SIPs be submitted within 

3 years of promulgation or revision of a NAAQS would make it difficult to do so, suggesting that 

Congress did not intend 110(a)(2)(D)(i)(I) SIPs to be linked in any way to designation status. 

Further, even areas that have never been in nonattainment or that have been re-designated to 

attainment (including those where the majority of pollution comes from out of state) continue to 

be at risk for falling into nonattainment due to the impact of emissions from upwind states. We 

therefore disagree with the commenter and continue to believe that Allegan was appropriately 

determined to be a maintenance receptor. See Section III.D of the preamble to the final 

supplemental.

Furthermore, the Transport Rule CAMx source apportionment modeling shows that 10 states 

(including Oklahoma) contribute above the 1% of the ozone NAAQS threshold to Allegan 

County. As would be expected, the largest ozone contribution is from Illinois. But that does not 

change the fact that 9 other states interfere with maintenance in Allegan County and it does not 

alleviate the need for those states to eliminate their interference with maintenance. Further, the 

North Carolina v. EPA opinion requires EPA to give independent meaning to the interfere with 

maintenance prong of section 110(a)(2)(D)(i)(I).

Comment: The DEQ does not believe that the conclusion that Oklahoma significantly impacts 

the air quality in Allegan County, Michigan is accurate. The modeling conducted by EPA 
32

alleged that the NOX sources in the state of Oklahoma interfere with maintenance of the ozone 

standard for Allegan County, Michigan. Allegan Co. was designated attainment of the ozone 

standard on July 20, 2010, and is now a maintenance area. The design values for Allegan Co. for 

the years 2005, 2006, 2007, 2008, 2009, and 2010 are 89, 88, 93, 86, 81, and 74 ppb 

respectively. It is apparent that the emission reductions obtained from the CAIR sources have 

helped to lower recent design values to well below the standard, and that Allegan County’s 

maintenance of the standard is not threatened (even the modeled value of 85.1 in the CSAPR was 

just over the standard). If EPA were to update their base case to the year 2008 or later, Allegan 

Co. would model attainment with no threat to their maintenance status in a normal weather year. 

The monitor in Allegan County is the only monitor projected to be above the standard that EPA 

identified Oklahoma as impacting; therefore, if Allegan County is in attainment of the standard, 

then Oklahoma can and should be completely removed from the rule. It is DEQ’s belief that the 

conclusion that Oklahoma emissions impact Michigan is false. [Oklahoma Department of 

Environmental Quality (EPA-HQ-OAR-2009-0491-4593), p. 1-2.]

RESPONSE: See section III.D of the preamble for the final supplemental regarding Allegan 

County. The comments on CAIR, modeling, and the base case are outside the scope of the 

SNPR because they address issues that were within the scope of the request for comments in the 

proposed Transport Rule, but not in the SNPR. While EPA is not reconsidering or reopening 

these issues, we note that these issues were previously addressed in sections V.C.2 (76 FR 

48230, August 8, 2011) and V.B (76 FR 48223, August 8, 2011) of the preamble to the final 

Transport Rule. 

Comment: It is important to note that Oklahoma is currently being included for its alleged 

impact on one county in the entire United States. Commonsense suggests that carbon emissions 

in Oklahoma are not dictating the air quality of Allegan County, Michigan, while somehow 

having little or no impact on states with which we share a border. Without additional and 

conclusive scientific data, I reject the EPA’s conclusions in this instance, which I believe call 

into question the overall validity of its study and modeling data. I strongly advocate that further 

scientific and empirical modeling is necessary to truly determine if Oklahoma is impacting any 

area of the country in relation to air quality. I am asking today that the EPA revisit this 

important issue to ensure that it is using proven science and techniques to make an informed 

decision on this issue. [Governor, State of Oklahoma (EPA-HQ-OAR-2009-0491-4594), p. 1.]

RESPONSE: See section III.D of the preamble to the final supplemental. Regarding the 

comment on carbon emissions, the Transport Rule does not regulate carbon emissions. 

Regarding comments on the validity of EPA’s modeling, the comment is outside the scope of the 

SNPR because it addresses issues that were within the scope of the request for comments in the 

proposed Transport Rule but not in the SNPR. While EPA is not reconsidering or reopening the 

issue, we note that our methodologies were documented in the preambles for the proposed rule 

and final rule and the proposal and final rule Air Quality Modeling Technical Support 

Documents. See EPA-HQ-OAR-2009-0491-4372, "Air Quality Modeling Final Rule Technical 

Support Document". There was ample opportunity to comment on these methods based on 

information provided in the proposed rule.
33

Comment: Since its promulgation in 2005, CAIR has achieved significant emissions reductions. 

For the purpose of determining the base case (i.e., the analytical baseline emissions scenario), 

EPA arbitrarily assumed that CAIR is not in effect. EPA claims that it is required to do so 

because if it "were to consider all reductions associated with CAIR in the 'base case,' the baseline 

emissions would not adequately reflect the true 2012 baseline in each state." 76 Fed. Reg. at 

48,223. EPA incorrectly assumes that pre-CAIR emission levels represent the emissions that 

"would occur in each state in 2012 if the Transport Rule did not require any reductions in that 

state." Id. EPA's reasoning is arbitrary because it lacks a "rational relationship to the real world." 

See, e.g., Appalachian Power Co. v. EPA, 249 F.3d 1032, 1053 (D.C. Cir. 2001) (citing 

Chemical Mfrs. Ass'n v. EPA, 28 F.3d 1259, 1265 (D.C. Cir. 1994» ("While courts routinely 

defer to agency modeling of complex phenomena, model assumptions must have a 'rational 

relationship' to the real world."); Columbia Falls Aluminum Co. v. EPA, 139 F.3d 914, 923 (D.C. 

Cir. 1998) ("An agency's use of a model is arbitrary if that model bears no rational relationship to 

the reality it purports to represent.") (internal quotations omitted).

In light of the numerous regulatory developments since 2005 and the billions of dollars invested 

in installing controls at EGUs, it is unreasonable for EPA to assume that all of the EGUs 

currently subject to CAIR would instantly stop operating these controls on January 1, 2012. The 

D.C. Circuit in North Carolina remanded without vacatur the federal CAIR program; it did not 

in any way invalidate state regulations implementing CAIR. Since 2005, EPA has set 

significantly more stringent NAAQS for Ozone, SO2, NOX, and PM. Many states have become 

dependent on the emissions reductions achieved by their CAIR programs to attain or maintain 

these newly promulgated, and more stringent, NAAQS within their own borders. EPA cannot 

assume that these states will forgo these reductions simply because the federal mandate to 

implement CAIR expires.

It is far more rational for EPA to acknowledge the emissions reductions achieved by CAIR. 

EPA cannot simply assume that pre-CAIR emission levels are an appropriate base case without 

first determining whether states will continue to require CAIR reductions. The U.S. Court of 

Appeals remanded CAIR without vacatur and has consistently declined to set a deadline for EPA 

to replace CAIR. See North Carolina v. EPA, 550 F.3d 1176 (D.C. Cir. 2008) (remanding 

without vacating CAIR); Order, North Carolina v. EPA, No. 09-1316 (D.C. Cir. Feb 2, 2010) 

(denying request for writ of mandamus ordering EPA to issue proposed rule). Nothing requires 

EPA to discount emissions reductions achieved by CAIR.

Failing to account for CAIR undermines the ability of EPA's model to accurately determine 

whether states significantly contribute to nonattainment or maintenance of the NAAQS. 

Michigan is a CAIR state and Allegan County currently is in attainment of the 1997 ozone 

NAAQS. In 2010, the Holland monitor, located in Allegan, Michigan, had a three-year average 

of 74 ppb. If EPA used this actual data, which reflects CAIR reductions, its modeling would 

show that Allegan, Michigan would remain in attainment. See Docket No. EPA-HQ2009-0491-

2809 (Comments Submitted by the Midwest Ozone Group). Modeling submitted by the Midwest 

Ozone Group in response to the 2010 Proposal shows that if EPA considered CAIR, and other 

rules currently in place, ambient air quality at the Holland monitor would be approximately 81 

ppb in the base year, 9 76 ppb in 2014, and 73 ppb in 2018. See id. There simply is no rational 
34

basis for EPA's determination that Oklahoma will significantly contribute to nonattainment or 

interference with the 1997 ozone NAAQS in Allegan County, Michigan. [Western Farmers 

Electric Cooperative (EPA-HQ-OAR-2009-0491-4589), p. 6-7; Grand River Dam Authority 

("GRDA") (EPA-HQ-OAR-2009-0491-4586), p. 4-5.]

RESPONSE: The comment is outside the scope of the SNPR because it addresses issues that 

were within the scope of the request for comments in the proposed Transport Rule but not in the 

SNPR. While EPA is not reconsidering or reopening the issue, we note that EPA took comment 

on the rationale for selecting 2005 as the base year and the use of monitoring data for the period 

2003 through 2007 as the starting point for projecting ozone and PM2.5 concentrations in 2012 

and 2014 in the Transport Rule proposal. See section V.B of the final Transport Rule preamble. 

Also see section IV.A of the Transport Rule Primary Response to Comments document in the 

docket to this rulemaking [EPA-HQ-OAR-2009-0491-4513].

7. Wisconsin

No comments received on this issue.

II. FIPs (use of ozone season NOX program in Transport Rule as FIP) 

1. General

(A) EPA lacks authority to promulgate the proposed FIP.

Comment: For the reasons discussed in detail in its comments on the Proposed Transport Rule, 

UARG opposes EPA’s imposition of FIPs establishing ozone-season NOX emission reduction 

requirements in these states without first giving the states adequate time and opportunity to 

develop and submit state implementation plans (“SIPs”) implementing section 110(a)(2)(D)(i) of 

the Clean Air Act (“CAA”). See Docket ID No. EPA-HQ-OAR-2009-0491-2756.1, at 19-26 

(Oct. 1, 2010). For example, UARG notes that, even assuming for the sake of argument that, as 

EPA asserts, CAA section 110(a)(2)(D) “requires all states, within 3 years of promulgation of a 

new or revised NAAQS, to submit SIPs that prohibit certain emissions of air pollutants because 

of the impact they would have on air quality in other states,” 76 Fed. Reg. at 40664 -- an 

assertion that ignores that the 3-year SIP submission deadline appears only in CAA section 

110(a)(1), which explicitly applies to SIPs that “provide[] for implementation, maintenance, and 

enforcement” of NAAQS “within,” not outside, the state that submits the SIP -- that is no basis 

for EPA’s imposition of FIPs in this rule. As UARG notes in its comments, any schedule for 

submission of section 110(a)(2)(D)(i) SIPs for the 1997 NAAQS should be restarted “upon 

EPA’s promulgation of a valid final rule” replacing the currently effective Clean Air Interstate 

Rule.5 Docket ID No. EPA-HQ-OAR-2009-0491-2756.1, at 26. [Utility Air Regulatory Group 

(EPA-HQ-OAR-2009-0491-4598), p. 2-3.]

RESPONSE: The comment is outside the scope of this action because it questions the legality

of using a FIP, not whether the Transport Rule FIPs are the appropriate method for addressing 

the emissions. While EPA is not reconsidering or reopening the issue, we note that the legality

question was previously addressed in section IV.A of the preamble to the final Transport Rule.

2. Iowa
35

No comments received on this issue.

3. Kansas

No comments received on this issue.

4. Michigan

(A)Commenter disagrees with use of the FIP and the associated timeframe.

Comment: Within the proposed rules, the U.S. Environmental Protection Agency (EPA) again 

indicated their decision to use the final Transport Rule program's federal implementation plans 

(FIPs) to address the emissions in these six states. Once again, and as also stated in our original 

comments to the August 2, 2010, Federal Register, "Federal Implementation Plans to Reduce 

Interstate Transport of Fine

Particulate Matter and Ozone," and comments to the January 7, 2011 Federal Register, "Notice 

of Data Availability for Federal Implementation Plans to Reduce Interstate Transport of Fine 

Particulate Matter and Ozone," one of the MDEQ's most critical concerns is "the implementation 

timing for the proposed Interstate Transport Rules, where Phase One begins in 2012 and Phase 

Two in 2014. The MDEQ continues to believe the shortened timeline for implementation of the 

Transport Rule has adverse impacts on the states and sources affected." The MDEQ requests the 

implementation of the FIP be delayed a minimum of 18 months, until states can finalize an 

approvable state implementation plan (SIP) to effectively replace the FIP requirements. 

[Michigan Department of Environmental Quality (EPA-HQ-OAR-2009-0491-4606), p. 1.]

RESPONSE: The comment is outside the scope of the SNPR because it addresses issues that 

were within the scope of the request for comments in the proposed Transport Rule, but not in the 

SNPR. While EPA is not reconsidering or reopening these issues we note that the issues were 

previously addressed in sections VII.C and section X of the preamble to the final Transport Rule, 

as well as in the Transport Rule Primary Response to Comments document in the docket to this 

rulemaking [EPA-HQ-OAR-2009-0491-4513]. Additionally, questions regarding the legality of 

using a FIP were addressed in the preamble. 

5. Missouri

No comments received on this issue.

6. Oklahoma

(A) EPA lacks authority to promulgate the proposed FIP for Oklahoma.

Comment: The proposed FIP for Oklahoma is premature and inconsistent with the structure of 

CAA. In the Supplemental Proposal, EPA claims that it has authority to include Oklahoma in 

the CSAPR by virtue of the Agency's general finding on April 25, 2005 that all 50 states, 
36

including Oklahoma, failed to submit State Implementation Plans ("SIPs") to address the 

requirements of CAA Section 110(a)(2)(D)(i) with respect to the 1997 ozone NAAQS. In a 

Technical Support Document ("TSD") for the Supplemental Proposal, EPA says that it "has not, 

subsequent to that date, received or approved a SIP revision to correct the deficiency" for 

Oklahoma. Commenters disagree with EPA's characterization of the status of Oklahoma's SIP. 

First, EPA's claim misrepresents the status of Oklahoma's SIP and ignores subsequent actions 

taken by Oklahoma to implement the good neighbor requirements. It also ignores the reality that 

EPA only in this proposal gave Oklahoma any notice about the putative contribution to Allegan 

County's prospective and/or projected nonattainment. It would have been impossible for 

Oklahoma to have taken steps previously to ensure that it is meeting its good neighbor 

obligations because EPA had never identified the potential problem which Oklahoma must 

address.

Also, contrary to EPA's assertion in the TSD, Oklahoma submitted an interstate transport SIP on 

May 1, 2007 to address the requirements of CAA Section 110(a)(2)(D)(i). In the 2007 SIP, the 

State informed EPA as follows:

“As required by Section 110(a)(2)(D)(i) of the Clean Air Act, the State of Oklahoma 

submits to the USEPA that it has met the requirements for the 8-hour ozone and PM2.5

National Ambient Air Quality Standards ("NAAQS") and does not significantly

contribute to nonattainment or interfere with maintenance of the NAAQS in another 

State.”

On December 5, 2007, the State supplemented its interstate transport SIP with additional 

assessments and also provided EPA with the following certification regarding the adequacy of its 

SIP under CAA Section 110(a)(1) and (2):

“We have evaluated our existing SIP for implementation of the 1997 8-hour ozone 

NAAQS to determine if it includes all the requirements in Section 110(a)(1) and (2) of 

the CAA and is consistent with the guidance provided to the Regional Air Division 

Directors from William T. Harnett, Director, Air Quality Policy Division on October 

2,2007. We conclude and certify that our SIP does meet these requirements.”

The guidance referred to in this certification is an EPA memorandum titled "Guidance on SIP 

Elements Required Under Sections 110(a)(1) and (2) for the 1997 8-hour Ozone and PM2.5

National Ambient Air Quality Standards." The memorandum lists the basic elements that EPA 

thinks should be part of a SIP and also says, "To the extent that existing SIPs for ozone and 

particulate matter already meet these requirements, States need only certify that fact to [EPA]."

Consistent with EPA's guidance, Oklahoma certified in 2007 that the State's Interstate Transport 

SIP met all of the requirements of CAA Section 110(a)(l) and (2), which includes the interstate 

transport requirements related to NAAQS under CAA Section 110(a)(2)(D)(i)(I). Since then, 

EPA has not approved or disapproved of the State's conclusion in 2007 that its SIP meets the 

requirements of CAA Section 110(a)(2)(D)(i)(I) related to the 1997 8-hour ozone NAAQS. EPA 

has approved certain portions of the Oklahoma SIP relating to Prevention of Significant 
37

Deterioration ("PSD") requirements and has also issued a proposal to partially approve and 

partially disapprove other specific portions related to visibility.

EPA is now proposing to move directly to imposing a Federal Implementation Plan ("FIP"), 

eliminating the State's opportunity to receive notice of, and correct, a perceived deficiency in the

2007 SIP submittal as it relates to the requirements of CAA section 110(a)(2)(D)(i)(I). The EPA 

does not have authority under the CAA to proceed with implementing a FIP prior to approving or 

disapproving the State's 1997 SIP as it relates to the requirements of CAA section 

110(a)(2)(D)(i)(I). The CAA requires the EPA to act on a SIP revision within 12 months of 

having received a completed submission (such SIP submissions are deemed complete after 6 

months unless EPA makes a finding otherwise) see CAA section 110 (k)(l)(B), (k)(2). When a 

State submits a SIP, the CAA allows EPA to issue a FIP within 2 years after the Administrator

disapproves the SIP in whole or part. Also, the CAA gives the EPA the authority to issue a FIP 

within two years after finding that a State failed to submit a SIP, or submitted a SIP that was 

found to be incomplete. However, the authority to issue a FIP expires two years after EPA issues 

a finding of failure to submit a SIP. The EPA has missed that two year deadline here and 

therefore, lacks authority under the CAA to issue the proposed FIP. Furthermore, where a State 

submits a SIP after the issuance of a deficiency finding by the Administrator, the EPA must act 

on the SIP submittal before issuing a FIP.

Pursuant to 42 U.S.C. § 7410(c)(l)(B):

(1) The Administrator shall promulgate a Federal implementation plan at any time within 

2 years after the Administrator –

(A) finds that a State has failed to make a required submission or finds that the plan or 

plan revision submitted by the State does not satisfy the minimum criteria established 

under subsection(k)(l)(A) of this section, or

(B) disapproves a State implementation plan submission in whole or part, unless the State 

corrects the deficiency, and the Administrator approves the plan or plan revision, before 

the Administrator promulgates such Federal implementation plan.

In this Supplemental Proposal, the EPA has not followed the CAA mandate requiring that prior 

to promulgating a FIP, the EPA must find that a State has failed to make a required submission, 

or find that the plan or plan revision submitted by the State does not satisfy minimum criteria, or 

must disapprove a SIP submission in whole or part. As set forth above, the EPA has not taken 

any action in regards to the May 1, 2007, Interstate Transport SIP that addressed the 

requirements of CAA 1l0(a)(2)(D)(i). In addition, the EPA has not taken action to approve or 

disapprove the December 2007 State of Oklahoma SIP revision and certification that was 

submitted pursuant to an October 2007, EPA guidance document. In that submission, Oklahoma 

certified (following the dictates in the EPA Guidance Document) in December 2007 that 

Oklahoma's Interstate Transport SIP met all the requirements of CAA section 11O(a)(I) and (2), 

which includes CAA section 110(a)(2)(D)(i)(I). Therefore, the EPA does not have the authority 

under the CAA to issue the FIP it is proposing in this Supplemental Rule under the CSAP 
38

Program. [Oklahoma Attorney General (EPA-HQ-OAR-2009-0491-4592), p. 3-6; Oklahoma 

Gas & Electric Company (OGE) (EPA-HQ-OAR-2009-0491-4590), p. 3-5; AES Shady Point 

(EPA-HQ-OAR-2009-0491-4595), p. 3-4; Western Farmers Electric Cooperative (EPA-HQOAR-2009-0491-4589), p. 5-6.]

RESPONSE: For the reasons explained in section IV.C.2 of the preamble to the final Transport 

Rule (76 FR 48208, August 8, 2011) and in the TSD entitled “Status of CAA 110(a)(2)(D)(i)(I) 

SIPs Supplemental Rule” TSD (December 2011), EPA has the legal obligation to promulgate all 

of the FIPs in this rule. This conclusion is based on the plain language of the Clean Air Act as 

applied to the specific circumstances of each state. 

Section 110(c)(1) of the Act requires EPA to promulgate FIPs within two years after finding that 

a state has failed to make a required SIP submission or disapproving a SIP. Specifically, section 

110(c)(1) states that the Administrator shall promulgate a Federal Implementation Plan within 

two years after the Administrator "(A) finds that a State has failed to make a required submission 

or finds that the plan or plan revision submitted by the State does not satisfy the minimum 

criteria established under subsection (k)(1)(A) of this section or (B) disapproves a State 

implementation plan submission in whole or in part." 42 U.S.C. § 7410 (c)(1)(A) & (B). EPA is 

relieved of the obligation to promulgate a FIP only if the state corrects the deficiency and EPA 

approves the SIP before promulgating a FIP. 42 U.S.C. § 7410(c)(1). The Act does not create 

any exceptions to this rule. EPA has not approved a SIP for Oklahoma that addresses this 

requirement; rather, EPA has proposed to disapprove Oklahoma’s SIP submittal that addresses 

110(a)(2)(D)(i)(I). EPA is promulgating FIPs only in those circumstances where the Clean Air 

Act explicitly provides that it shall do so. 

The commenter does not identify any provision that would give EPA authority to alter the 

deadlines established in the statute or delay implementation of the Transport Rule as requested. 

In this case, the Act explicitly provides that the SIP submission deadline runs from the date of 

promulgation or revision of a NAAQS and the FIP clock starts when EPA finds that a state has 

failed to make a required SIP submission or EPA disapproves a SIP submission.

Nothing in the Act requires EPA, where it has already made findings of failure to submit or 

disapproved SIP submissions, to promulgate a SIP Call to give the states another opportunity to 

promulgate a SIP before promulgating a FIP. Section 110(a)(2)(D)(i)(I) SIP submittals are due 3 

years after promulgation or revision of a NAAQS. See 42 U.S.C. § 7410(a)(1). Thus, 

110(a)(2)(D)(i)(I) SIPs for the 1997 ozone NAAQS were due in 2000. While the statute gives 

EPA authority to prescribe a shorter period of time for states to make SIP submissions, it does 

not give EPA authority to extend the 3-year deadline established by statute. See 42 U.S.C. § 

7410(a)(1). Moreover, there is no requirement that EPA promulgate a rule or issue guidance 

regarding the specific requirements of section 110(a)(2)(D)(i)(I) in advance of the SIP submittal 

deadline.

The plain language of section 110(c)(1) of the Act provides that EPA shall promulgate a FIP at 

any time within 2 years after the Administrator finds that a state has failed to make a required 

submission or after disapproving a state implementation plan submission in whole or part, unless 
39

the state corrects the deficiency, and the Administrator approves the plan or plan revision, before 

the promulgation of a FIP. See 42 U.S.C. § 7410(c)(1). Far more than 2 years has now elapsed 

since EPA first made these findings with respect to the 1997 ozone and 1997 PM2.5 NAAQS. 

There is nothing in the plain language reading of the Act that says that EPA’s obligation 

“expires” at the end of the 2 years.

Finally, nothing in the Act requires EPA, where it has already made findings of failure to submit 

or disapproved SIP submissions, to promulgate a SIP Call to give the states another opportunity

to promulgate a SIP before promulgating a FIP. Section 110(a)(2)(D)(i)(I) SIP submittals are 

due 3 years after promulgation or revision of a NAAQS. See 42 U.S.C. § 7410(a)(1). While the 

statute gives EPA authority to prescribe a shorter period of time for states to make SIP 

submissions, it does not give EPA authority to extend the 3-year deadline established by statute. 

See 42 U.S.C. § 7410(a)(1).

Comment: The EPA's Supplemental Rule Proposal for Oklahoma under the CSAP Program 

intrudes upon the role generally left to the States under the CAA. In Train v. Natural Resources 

Defense Council, Inc., 421 U.S. 60 (1975), the United States Supreme Court found that although 

the CAA plainly charges the EPA with the responsibility for setting the national ambient air 

quality standards, the Act, just as plainly, relegates the EPA to a secondary role in the process of 

determining and enforcing the specific, source-by-source emission limitations that are necessary

if the national standards are to be met. According to the Court, the Act gives the agency no 

authority to question the wisdom of a State's choice of emission limitations if they are part of a 

plan that satisfies the standards of section 110(a)(2), and the agency may devise and promulgate 

a specific plan of its own only if a State fails to submit an implementation plan that satisfies 

those standards. To this point, the Court stated: "So long as the ultimate effect of a State's choice 

of emission limitations is compliance with the national standards for ambient air, the State is at 

liberty to adopt whatever mix of emission limitations it deems best suited to its particular 

situation." Id. at 79.

The CAA then "establishes a partnership between EPA and the states for the attainment and 

maintenance of national air quality goals." See Natural Res. Def Council, Inc. v. Browner, 57 

F.3d 1122, 1123 (D.C. Cir. 1995). "Air pollution prevention ... at its source is the primary 

responsibility of States and local governments...." 42 U.S.C. § 7401(a)(3). Congress "carefully

balanced State and national interests by providing for a fair and open process in which State and 

local governments, and the people they represent, will be free to carry out the reasoned weighing 

of environmental and economic goals and needs."

In the current Supplemental Proposal, the EPA is proposing a FIP in Oklahoma regarding 

summertime NOX reductions under the CSAP ozone-season control program. The EPA is 

proposing to promulgate this FIP despite the fact that Oklahoma has submitted a SIP that meets 

the requirements of the CAA and despite the fact that EPA has not taken any action on 

Oklahoma's SIP, as required in the CAA. Such action by the EPA is an impermissible intrusion 

upon the authority reserved to Oklahoma and exceeds the authority granted to the EPA under the 

CAA.
40

Another commenter makes similar arguments, citing the same case law. The commenter also 

notes that The Act expressly allocated to states the initial responsibility for determining the 

manner in which air quality standards are to be achieved. Train v. Natural Resources Defense 

Counsel, 421 U.S. 60,64 (1975). EPA "may devise and promulgate a specific plan of its own 

only if a State fails to submit an implementation plan which satisfies those standards." 

Commonwealth of Virginia, 108 F.3d at 1482. The CAA is an experiment in federalism "and the 

EPA may not run roughshod over the procedural prerogatives that the Act has reserved to the 

states ... " Id at 1408 (internal citation omitted). [Oklahoma Attorney General (EPA-HQ-OAR2009-0491-4592), p. 6-8; Western Farmers Electric Cooperative (EPA-HQ-OAR-2009-0491-

4589), p. 4.]

RESPONSE: For the reasons explained in section IV.C.2 of the preamble to the final Transport 

Rule (76 FR 48208, August 8, 2011) and in the TSD entitled “Status of CAA 110(a)(2)(D)(i)(I) 

SIPs Supplemental Rule” TSD (December 2011), EPA has the legal obligation to promulgate all 

of the FIPs in this rule. This conclusion is based on the plain language of the Clean Air Act as 

applied to the specific circumstances of each state. 

Section 110(c)(1) of the Act requires EPA to promulgate FIPs within two years after finding that 

a state has failed to make a required SIP submission or disapproving a SIP. Specifically, section 

110(c)(1) states that the Administrator shall promulgate a Federal Implementation Plan within 

two years after the Administrator "(A) finds that a State has failed to make a required submission 

or finds that the plan or plan revision submitted by the State does not satisfy the minimum 

criteria established under subsection (k)(1)(A) of this section or (B) disapproves a State 

implementation plan submission in whole or in part." 42 U.S.C. § 7410 (c)(1)(A) & (B). EPA is 

relieved of the obligation to promulgate a FIP only if the state corrects the deficiency and EPA 

approves the SIP before promulgating a FIP. 42 U.S.C. § 7410(c)(1). The Act does not create 

any exceptions to this rule. EPA has not approved a SIP for Oklahoma that addresses this 

requirement; rather, EPA has proposed to disapprove Oklahoma’s SIP submittal that addresses 

110(a)(2)(D)(i)(I). EPA is promulgating FIPs only in those circumstances where the Clean Air 

Act explicitly provides that it shall do so. 

EPA has considered the specific circumstances of each state in determining whether it has an 

obligation to promulgate a FIP for that state with respect to a particular NAAQS. More detailed 

information regarding Oklahoma-specific actions taken by EPA and the status of its 

110(a)(2)(D)(i)(I) SIP appears in the TSD entitled, Status of CAA 110(a)(2)(D)(i)(I) SIPs 

Supplemental Rule TSD (December 2011). The TSD explains the current status of the 

Oklahoma 110(a)(2)(D)(i)(I) SIP.

Further, the cases cited by the commenter do not support the commenter's conclusion that it is 

improper for EPA to promulgate the FIPs in this rule. The cases discussing the system of 

cooperative federalism established by the Clean Air Act explain both the primary role given to 

states with regard to the protection of air quality and EPA’s obligation to promulgate federal 

plans “if a State fails to submit an implementation plan which satisfies [the standards of 

110(a)(2)]”. Train, 421 U.S. at 79. 
41

Comment: Commenter incorporates by reference comments filed by Oklahoma Gas and Electric 

and Western Farmers Electric Cooperative. [Oklahoma Utility Group (EPA-HQ-OAR-2009-

0491-4591), p. 3.]

RESPONSE: See above responses in this section.

7. Wisconsin

No comments received on this issue.

III. Ozone Season NOX Emission Budgets 

3.1. General

No comments received on this issue.

3.2 Iowa

No comments received on this issue.

3.3 Kansas

(A) Commenters(s) raise issues with the budgets established for Kansas.

Comment: The allowances allocated to sources in these rules are severely short for the SO2 and 

NOX programs. This presents difficult compliance challenges for Empire District as well as other 

sources in Kansas that have either maintained compliance with previous rules via banked or 

purchased allowances and have not previously been subject to the Clean Air Interstate Rule and 

subsequently do not have the needed controls installed. 

Empire District compared 2010 SO2 actual emissions with the 2012 SO2 allowance allocations 

and the initial analysis shows that SO2 Group 1 allocations will be approximately 600,000 tons 

short and SO2 Group 2, of which the state of Kansas belongs, allocations will be short 

approximately 300,000 tons. Since it is apparent there will be a shortage of SO2 allowances in 

2012 available to purchase for compliance, it is critical that sources have more time to install the 

controls needed to comply with the CSAPR and supplemental rule to the CSAPR. 

According to the technical supporting document for Final Transport Rule analysis in EPA’s 

application of the Integrated Planning Model, Appendix 3-3 New Source Review settlements in 

Base Case v 4.10_F Transport (05-16-11), the state of Kansas SO2 budgets were developed 

without considering the allowance restrictions contained in the consent agreement for Westar’s 

Jeffrey Energy Center. Because of the consent agreement restrictions there will be approximately

13,700 SO2 allowances unavailable for trading. This egregious error severely restricts Kansas 
42

utilities ability to comply with the CSAPR via the SO2 allowance trading program and represents 

approximately 34 percent of the total state SO2 budget. 

Empire District questions how many other consent agreements were ignored or erroneously

missed. Furthermore, what is the true number of total allowances available across Group 1 and 

Group 2 if EPA considers all consent agreements in its respective state budgets? This is a serious 

issue that must be addressed prior to the commencement of the CSAPR going into effect in 

January 2012. [Empire District Electric Company (EPA-HQ-OAR-2009-0491-4581), p. 2]

RESPONSE: These comments are outside the scope of this rulemaking. EPA is addressing the 

role of consent decrees in unit-level allowance allocation in a separate rulemaking. See 

Revisions to Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate 

Matter and Ozone, 76 FR 63860, October 14, 2011. 

3.4 Michigan

No comments received on this issue.

3.5 Missouri

No comments received on this issue.

3.6 Oklahoma

(A) EPA's Supplemental Proposal requires an overly drastic reduction in ozone 

season NOX emissions for commenter and the State of Oklahoma generally.

Comment: EPA's Supplemental Proposal marks a significant change in the Agency's treatment 

of Oklahoma compared to the 2010 Proposed interstate Transport Rule, and also would require a 

drastic reduction in the State's actual ozone season NOX emissions. Commenter include a table 

that summarizes the differences between the ozone season NOX emissions budget for Oklahoma 

in the Supplemental Proposal, the same budget in the 2010 Proposed Rule, and the State's actual 

NOX emissions from EGUs during the 2010 ozone season.

As shown in the table, the Supplemental Proposal assigns to Oklahoma a statewide ozone season 

NOX emissions budget of just 21,835 tons per year, which represents a reduction of more than 

15,000 tons (roughly 41%) from the state's budget in the 2010 Proposed Transport Rule. 

Compared to 2010 actual emissions, this budget requires a reduction of more than 13,000 tons 

(37%) statewide. The budget proposed for Oklahoma is inadequate because EPA relies on a 

collection of flawed assumptions about unit shutdowns and curtailments. For example, OG&E's 

Mustang units are allocated no allowances and are therefore assumed to retire. OG&E does not 

expect shutdown of these units to be feasible while still meeting consumer demand.

For OG&E's units, the total emission reduction required under the Proposal would be roughly

6,000 tons or 38.6% percent less than actual 2010 emissions and 6,800 tons or 41.5% percent 

less than the allowances provided to OG&E's units under the 2010 Proposed Rule. Certain 
43

OG&E units would bear the bulk of this impact. As an example, OG&E's Muskogee and Sooner 

units (the base load units of OG&E's generation) are assumed to achieve a 50% reduction in NO, 

emissions during the ozone season. Simply put, this would mean that these base load units could 

only run during 50% of the ozone season, which is the hot period in Oklahoma. Based on the 

demand for recent operations, OG&E believes that these reductions are not feasible.

EPA claims that the drastic reductions in ozone season NOX emissions called for by the 

Supplemental Proposal can be achieved by installing emission controls, or by purchasing 

allowances to cover emissions. It is not realistic, however, to expect EGUs to install controls 

prior to the proposed compliance deadline of May I, 2012. Nor has EPA accounted for the 

likelihood of allowance shortfalls in light of the drastic emission reductions that EGUs would be 

required to achieve by May 2012. Furthermore, as discussed in more detail in Section IV, the 

compliance schedule may not allow enough time for OG&E to purchase power to replace what 

would be lost through curtailments. [Oklahoma Gas & Electric Company (OGE) (EPA-HQOAR-2009-0491-4590), p. 6-8; Oklahoma Utility Group (EPA-HQ-OAR-2009-0491-4591), p. 

5.]

RESPONSE: See the preamble to this final rule, section III.B.iv. and section III.E.

Comment: Oklahoma’s ozone-season NOX budget is unreasonably low. In the proposed 

rulemaking for the Transport Rule (published in the Federal Register on August 2, 2010), the 

ozone-season NOX budget for the state of Oklahoma was set at 37,087 tons (Table IV.E-2 of the 

preamble to the proposed rule, 75 FR 45291). In the SNPR, the ozone-season NOX budget for 

the state of Oklahoma was set at 21,835 tons (Table I.C-1 of the SNPR, 76 FR 40666). Between 

the issuance of the proposed rule in 2010 and the issuance of the SNPR in 2011, EPA reduced 

the state budget by 41.1%. In the proposed rule, the state budgets were set using a process that 

started with a baseline developed using the Integrated Planning Model (IPM), based on historic 

emissions data and projections about future growth in demand for electricity. After setting the 

emissions baseline, EPA used an air quality assessment tool (AQAT) and cost curves to 

determine the amount of NOX reduction that would be required to comply with the “good 

neighbor” requirements of the Clean Air Act. Using this method, EPA set the state ozone-season 

NOX budget at 37,087 tons for Oklahoma. Despite some concerns about some aspects of the 

process, we believed the state budget established in the proposed rule to be fair and achievable. 

In the final rule and in the SNPR, EPA made a radical and previously unannounced departure 

from the previous method. In the preamble for the final rule, EPA stated that, based on 

emissions inventory data for 2009, they were changing the ozone-season emissions baseline. In

the final rule, EPA acknowledged this change, but did not provide a clear description of the 

process. Was the new baseline based almost exclusively on the 2009 emissions inventory data? 

Did the EPA take into consideration the reduced demand associated with the recession as 

mentioned in section IV? How much did the IPM analysis performed previously factor into the 

new state budgets? The criteria used to set the new baseline remain unclear. We believe this 

change in methodology fails to meet the standards for prudent rulemaking and that, by failing to 

re-propose the rule and accept comments on this aspect of the rule, EPA has acted in an arbitrary

and capricious manner. [Oklahoma Department of Environmental Quality (EPA-HQ-OAR2009-0491-4593), p. 5-6.]
44

RESPONSE: First, EPA has finalized in this action an ozone-season NOX budget for the state 

of Oklahoma that is significantly larger than the budget in the proposed Supplemental 

rulemaking. This higher budget for 2012 addresses the commenter’s concerns about compliance 

with the 2012 proposed budget. In regards to questions about 2009 data informing the baseline, 

the 2009 data was one of several variables that influenced the final rule emissions baseline for 

2012. For instance, lower natural gas prices are another variable that were updated that would 

also impact the baseline between proposal and final. EPA did consider the recessionary impact 

of 2009 on emissions levels. We did not use emission levels in our modeling, only emission 

rates — which are minimally impacted by any recessionary impacts.

Comment: The Oklahoma emission budget is not based on accurate data and operational 

assumptions. EPA may not impose requirements on sources or states without authorization by

Congress through the CAA. See, e.g., Michigan v. EPA, 268 F.3d 1075, 1081 (D.C. Cir. 2001) 

("It is axiomatic that an administrative agency's power to promulgate legislative regulations is 

limited to the authority delegated by Congress.") (quoting Bowen v. Georgetown Univ. Hosp., 

488 U.S. 204, 208 (1988». EPA has not demonstrated that the severely restrictive budget 

proposed for Oklahoma would achieve only those emissions reductions required by Section 110 

of the Act. Emissions reductions beyond what is required to eliminate significant contribution to 

downwind nonattainment are an abuse of EPA discretion and in excess of the Agency's authority

under the Act. 

The unit-specific data and operational assumptions relied on by EPA to establish the

State emissions budget contains numerous inaccuracies. Comments on the 2010 Proposal 

submitted by the Oklahoma Department of Environmental Quality ("ODEQ") identified a 

significant number of errors in EPA's Integrated Planning Model ("IPM") files. See Docket No. 

EPA-HQ-OAR-2009-049I -2662. ("The IPM model run results are very erratic, retiring both coal 

and natural gas facilities that have no plans to retire, increasing and decreasing electricity 

production at various facilities, and adding solar power to Oklahoma when none has been

planned.") Similarly, WFEC notified EPA that the IPM files contained no heat input data for 

units 4, 5, and 6 at its Anadarko facility. See Docket No. EPA-HQ-OAR-2009-0491-2642. The 

heat input of EGUs within a state play a crucial role in EPA's methodology for establishing the 

state's emissions budget. EPA's failure to correct these errors "bespeaks a 'let them eat cake' 

attitude that ill-becomes an administrative agency whose obligation to the public it serves is 

discharged if only it avoids being arbitrary and capricious." Chemical Mfrs. Ass'n v. EPA, 28 

F.3d at 1266. The emissions budget for the State of Oklahoma cannot accurately reflect 

emissions reductions necessary to eliminate only those emissions that significantly contribute to 

downwind pollution because it is not based on the most accurate data available to the Agency.

EPA cannot impose emissions reductions beyond those required to address Oklahoma's 

significant contribution to downwind pollution. In North Carolina v. EPA, the D.C. Circuit 

rejected EPA's attempt to require some states "to exceed the mark" in reducing upwind emissions 

because the Act gave "EPA no authority to force an upwind state to share the burden of reducing 

other upwind states' emissions." 531 F.3d 896, 921. Because the state budgets at issue in North 

Carolina "shifted the burden of emissions reductions," the Court invalidated the budgets as 
45

arbitrary and capricious. Id In CSAPR, EPA claims that the methodology used to set state 

emissions budgets evaluates only cost and state-specific contributions to downwind pollution. 76 

Fed. Reg. 48,211-12. EPA completely disregards the fact that any methodology would produce 

inaccurate emissions budgets if fed inaccurate data and assumptions. Because the emissions 

budget proposed for Oklahoma is based on inaccurate data, modeling and assumptions, there is 

every reason to believe that it too "exceeds the mark." [Western Farmers Electric Cooperative 

(EPA-HQ-OAR-2009-0491-4589), p. 9-10.]

RESPONSE: Regarding the “solar” issue, EPA is not aware of any projected new solar in the 

IPM outputs, and the commenter does not specify what solar in the IPM outputs they are 

referring to. There are only 7.5 MW of Oklahoma solar generating capacity (or about 0.03% of 

more than 20,000 MW of total Oklahoma generating capacity) in the NEEDS input files,

reflecting what is reported to be recently installed Southern Great Plains Commercial Solar. 

However, this appears to already exist and the source did not comment on its existence when 

depicted in the proposed modeling, so this is unlikely what commenter is addressing. Moreover, 

the relative size of these existing solar units would not have any meaningful impact on emissions 

modeled at the state level. In regards to IPM projections of unit level heat input, they are just 

that – projections of what would likely be the least-cost response to the state budget or cost 

threshold modeled. EPA was very clear about how IPM does not reflect how the unit may

ultimately decide to operate. CSAPR is not a unit-level control program and the allocations are 

not based on its projections. Therefore, the projection has no bearing on how the unit chooses to 

operate. The commenter’s suggestion that simply substituting historic data from a period when a 

source was not subject to an ozone season emission reductions program for a period when it is 

subject to an emission reductions program is not reasonable and fundamentally inconsistent with 

the notion of emission reductions.

In regards to the viability of the state budget in 2012, this final rule addresses those concerns by 

increasing the budget to a level where no combustion controls are assumed.

(B) There are errors in EPA’s methodology as applied to calculation of Oklahoma’s 

budget.

Comment: DEQ’s analysis of the application of EPA’s methodologies for determining state 

budgets and allocations to individual units demonstrates clear errors were made in determining 

Oklahoma’s allowances. By changing the method of calculation for the state allowance budgets 

from using the IPM modeling to a reliance on 2009 emissions inventory data, EPA made a 

number of errors that have resulted in assigning an ozone-season NOX allowance budget for the 

State of Oklahoma which is lower than is warranted. The Excel spreadsheet titled “Proposed 

CSAPR Unit Level Allocations under the SNPR and Underlying Data” provides baseline data 

used to calculate the state budgets. A number of units are listed in the spreadsheet, because they

will be subject to the Cross-State Air Pollution Rule even though they are not currently subject to 

the Acid Rain Program (ARP). These units do not report emissions to the Clean Air Markets 

Division (CAMD), and their emissions are not included in the CAMD database. EPA obtained 

some historical emissions data for these units, and those data are included in the spreadsheet. 

However, for the years 2008, 2009, and 2010, many of these units appear in the table as having 
46

zero emissions for the ozone season. The absence of any emissions data for these units has the 

effect of lowering the baseline from which EPA set the state budget. The agency provides a in 

the comment letter to provide a comparison of EPA and DEQ data for the total emissions from 

all subject units for the 2008 through 2010 ozone seasons.

Two key observations are noteworthy: (1) due to the recession, the 2009 ozone season 

represented an anomalously low year for ozone-season emissions and (2) the failure to capture 

year-to-year trends in emissions from units not subject to the ARP yielded a state budget baseline 

that is nearly 3,000 tons too low. In addition, we calculate that utilities operating in Oklahoma 

will need to retrofit 43 individual combustion units with low-NOX burners to comply with the 

requirements of the new rule. This number is substantially larger than the 30 units in a four-state 

area predicted in EPA’s TSD, “Installation Timing for Low NOX Burners (LNB).” To remedy 

these failings, we recommend that EPA increase the state ozone-season NOX allowance budget 

by 1,500 tons and that the compliance date for units operating in Oklahoma be pushed back to 

the 2015 ozone season. 

We believe that our request for this increase in the state budget is justified for four reasons: (1) 

the 2009 emissions estimate data are unrepresentative due to the recession, (2) the failure to 

include non-ARP sources in the budget baseline lead to a baseline nearly 3,000 tons below actual 

values, (3) assuming a 50% control efficiency for low-NOX burners applied to a baseline 

elevated by 3,000 tons would yield an additional 1,500 tons of allowances for the state budget, 

and (4) this increase in the budget still retains over 90% of the reductions from the initial 

proposal. We believe the fourth point to be particularly salient, and we would ask EPA to use 

their AQAT to determine whether, with a state ozone-season NOX budget of 23,335 tons, 

Oklahoma would be expected to make a significant contribution to the ozone levels in Allegan 

Co., Michigan. [Oklahoma Department of Environmental Quality (EPA-HQ-OAR-2009-0491-

4593), p. 3-4.]

RESPONSE: The 2012 state budget has been increased. See section III.B.iv and section III.E. 

in the preamble of the final rule. EPA has finalized an ozone-season NOX budget for the state of 

Oklahoma that is significantly larger than the budget in the proposed Supplemental. This higher 

budget for 2012 addresses the commenter’s concerns about compliance with the 2012 proposed 

budget. In regards to questions about 2009 data informing the baseline, the 2009 data was one of 

several variables that influenced the final rule emissions baseline for 2012. For instance, lower 

natural gas prices are another variable that were updated that would also impact the baseline 

between proposal and final. EPA did consider the recessionary impact of 2009 on emissions 

levels. We did not use emissions levels in our modeling, only emission rates — which are 

minimally impacted by any recessionary impacts.

3.7 Wisconsin

No comments received on this issue.

IV. Proposed Unit-Level Ozone Season NOX Allowance Allocations (data inputs & new 

unit set-asides)
47

4.1 General

No comments received on this issue.

4.2 Iowa

No comments received on this issue.

4.3 Kansas

No comments received on this issue.

4.4 Michigan

(A) Commenter disagrees with set-aside for Indian Country in Michigan.

Comment: The MDEQ believes that the proposed new unit set-asides of 26 allowances for 2012 

and 25 allowances for 2014 are not necessary and should be returned to the allocation pools for 

the electric generating units main allowances. At this time and into the foreseeable future, the 

MDEQ is not aware of any proposed power plant installations on Michigan tribal lands.

In addition, the EPA has indicated that even if a state received federal approval for a SIP, the 

EPA will continue to allocate allowances to Indian Country units.

The MDEQ believes it is more appropriate for states to have the ability to process any new 

source requests and allowance determinations for the entire state, including tribal lands, rather 

than having a split allocation system once the state's SIP is approved. [Michigan Department of 

Environmental Quality (EPA-HQ-OAR-2009-0491-4606), p. 1-2.]

RESPONSE: EPA retains administration of new unit set-asides designated for Indian country

because EPA, rather than the states, has the authority and responsibility of administering the 

Transport Rule with regard to new units that locate in Indian country. Under the FIP, any

allowances from the Indian country new unit set-aside that are not allocated in a given control 

period are redistributed to the state’s new unit set-aside for allocation to new units not in Indian 

country. Any allowances not allocated from the state’s new unit set-aside are redistributed to 

existing units, which are not in Indian country. Under a SIP, the state may determine how 

unallocated allowances in the Indian country set-aside are to be allocated within the state. For 

details, see section VII.D.2.e of the preamble of the final Transport Rule and see section XX.D 

of the Transport Rule Primary Response to Comments document [EPA-HQ-OAR-2009-0491-

4513].

4.5 Missouri

No comments received on this issue.
48

4.6 Oklahoma

(A) Commenter(s) state that facility-specific allowance allocations are based on flawed 

and/or incomplete data.

Comment: The data used in the proposed allowance allocations in the NODA for the proposed 

rule and supporting technical information are in error. The allowance allocations in the Technical 

Support Documents are based on flawed and incomplete historical data and emissions level 

model inputs. These errors were identified in previous comments regarding this rulemaking by 

the AES Corporation, but have thus far not been corrected.

The NOX allocations provided for the AES Shady Point facility do not reflect historical actual 

NOX emissions. As indicated in the Unit Allocation Table in the Administrative Record, the 

source of the NOX data for AES Shady Point is Energy Information Administration (EIA) data. 

However, in years 2005 - 2006, for the AES Shady Point facility, despite non zero data entry

entries for heat input, data entries for NOX emissions were omitted, and apparently treated as 

zero within the allocation methodology.

This omission must be a clerical error since it cannot be assumed that the facility generated heat 

without generating NOX. The facility was unquestionably in existence and operating at the time. 

More specifically, the State of Oklahoma authorized NOX emissions for this facility (Permit 

Number) and included AES Shady Point facility emissions in its State Implementation Plan (SIP) 

emissions inventory. For example, for calendar year 2009, the facility reported a total of 1315.7 

tons NOX (2009 Point Source Emissions, ODEQ, August 22, 2011, 

http://www.deq.state.ok.us/AQDnew/emissions/index.htm). Based on an engineering review 

utilizing actual facility NOX emission data (in place of the omitted data) and the proposed 

USEPA methodology, these data omissions appear to yield erroneously low NOX allocations. A 

copy of these engineering calculations including proposed corrected NOX allocations are 

attached.

AES asks that the above clerical error be corrected and the facility's actual emissions be 

recognized in the allocation methodology. If the clerical error is not corrected AES will be 

significantly and unfairly impacted. While NOX emissions from other company's facilities would 

be recognized-the NOX emissions from AES would not-resulting in a significant competitive 

disadvantage to AES. Such an unfair application of the law would appear to be both arbitrary 

and capricious, and a Federal due process violation. [AES Shady Point (EPA-HQ-OAR-2009-

0491-4580), p. 1.]

RESPONSE: The AES Shady Point facility’s historic data has been updated in this final 

rulemaking to reflect the data submitted during the comment period and described above. The 

final unit level allocations reflect these updates and can be seen in the allocation Technical 

Support Document, “Final Unit-Level Ozone Season NOX Allowance Allocations to Existing 

Units in 5 States: Supplemental Final Rule,” in the docket to this rulemaking.
49

4.7 Wisconsin

No comments received on this issue.

V. Other In-Scope Issues 

5.1 Implementation Issues (e.g., timing for installation of controls)

A. Commenter supports EPA’s compliance timetable.

Comment: Sierra Club also supports EPA’s proposal to implement the NOX emissions 

reductions on the same schedule for the 20 other states subject to the transport rule. Each state 

has been well aware that it could be subject to ozone season NOX emission requirements. Four 

of the states were subject to the ozone season NOX requirements in the Clean Air Interstate Rule, 

and three were subject to 2010 cross state proposal.

Another compelling reason why these six states must start making reductions immediately is that 

the proposed cross state rule only aims to achieve compliance with 1997 ozone standard of .08 

ppm. The standard was decreased in 2008 to .075 ppm and EPA has proposed to lower the 

standard even further to .06 to .07 ppm. Indeed, Sierra Club’s position continues to be that the 

transport rule, and this supplement, is deficient because it fails to prevent significant contribution 

to nonattainment of 2008 ozone NAAQs. [Sierra Club (EPA-HQ-OAR-2009-0491-4587), p. 2-

3.]

RESPONSE: EPA concurs with the comments supporting the application of the same schedule 

under the Transport Rule ozone season NOX program to Iowa, Michigan, Missouri, Oklahoma,

and Wisconsin as to other states. To the extent the comment addresses the 2008 Ozone NAAQS, 

the comment is outside the scope of this rulemaking, which addresses the 1997 ozone NAAQS.

Comment: We also support EPA’s proposal to implement the ozone season NOX emission 

requirements for the six states subject to the SNPR (including SIP submissions) on the same 

schedule as those requirements for the 20 other states subject thereto, that is, beginning May 1, 

2012. Those six states and power plants located therein should be able to meet this schedule, as 

each state has been subject to (or on notice that it could be subject to) ozone season NOX

emission requirements. Of the six states subject to the SNPR, four (Iowa, Michigan, Missouri 

and Wisconsin) were subject to the ozone season NOX requirements in the Clean Air Interstate 

Rule (“CAIR,” which CSAPR replaces), while three (Kansas, Michigan, and Oklahoma) were 

subject to the 2010 CSAPR proposal. [Clean Air Task Force, et al. (EPA-HQ-OAR-2009-0491-

4588), p. 3.]

RESPONSE: EPA concurs with the comments supporting the application of the same schedule 

under the Transport Rule ozone season NOX program to Iowa, Michigan, Missouri, Oklahoma,

and Wisconsin as to other states. 
50

B. Commenter(s) questions the feasibility and/or validity of the compliance deadline.

Comment: How does EPA expect the States to comply with this rule by the 2012 compliance 

date? In the Fact Sheet for the Cross-State Air Pollution Rule, EPA notes that “This action 

builds on more than fifteen years of progress...” The six States in the Supplemental Rule will 

have approximately 6 months to prepare and implement a method of compliance. [Oklahoma 

Municipal Power Authority (OMPA) (EPA-HQ-OAR-2009-0491-4573), p. 2.]

RESPONSE: See the preamble of final Transport Rule, section VII.C and the "Transport Rule 

Engineering Feasibility Response to Comments" document in the docket to this rulemaking 

(Docket ID No. EPA–HQ–OAR–2009–0491). The Transport Rule does not apply unit-specific 

requirements, thus provides flexibility for compliance across units with various control 

capacities. While the NOX ozone season program begins in May 2012, sources have until 

September 30, 2012 to achieve emission reductions and can purchase allowances to cover 

emissions until December 1, 2012 when they have to comply by holding allowances sufficient to 

cover their ozone season NOX emissions.

Comment: Empire District believes the short time frame whereby affected sources must comply 

with the provisions of both the final CSAPR as well as the proposed supplemental rule to the 

CSAPR is not realistic. Affected sources are allowed less than five months to comply with the 

annual NOX and SO2 emissions requirements in the final CSAPR and allowed less than nine 

months ( to comply with the ozone season NOX emission requirements in the proposed 

supplemental rule to the CSAPR. 

In the proposed Transport Rule Empire District commented that during a 2010 study of our 

Asbury facility to determine the Air Quality Control Systems (ACQS) needed for the future, 

including a scrubber, that the actual projected timeline from project planning to project 

completion is approximately 60 months. Using this as an example, it will take more time than 

allowed for by these rules for sources to install the controls that will be required for compliance. 

[Empire District Electric Company (EPA-HQ-OAR-2009-0491-4581), p. 1.]

RESPONSE: See the preamble of final Transport Rule, section VII.C.2 and the "Transport Rule 

Engineering Feasibility Response to Comments" document in the docket to this rulemaking 

(Docket ID No. EPA–HQ–OAR–2009–0491). The Transport Rule does not apply unit-specific 

requirements, thus provides flexibility for compliance across units with various control 

capacities.

Comment: EPA indicates that it expects to finalize this rulemaking on or before November 1, 

2011 which allows for only a six-month lead time prior to the 2012 ozone season which 

commences on May 1, 2012. See 76 Fed. Reg. 40667, Section I(E). KCP&L has coal-fired units 

that are part of what EPA describes as the “vast majority of covered sources already have 

combustion controls installed”, but also has units that are part of the “small number of sources 

will need to install combustion controls to comply”. Id. KCP&L does not concur that for this 

later group of sources it is “practical” to install combustion controls to achieve compliance 

“within the time period” allowed. Id. 
51

Installation of these combustion controls on KCP&L’s coal-fired units is a time-consuming, 

expensive process. Steps in this process include: initial design, development of project 

specifications, procurement (identification of bidders, solicitation, review of bids, and contract 

negotiations), permitting including in some cases New Source Review Presentation of significant 

Deterioration permits, regulatory approvals, obtaining financing, final design, mobilization of the 

needed workforce, construction, process tie-ins and process startup testing. These activities 

cannot commence until a final rule is issued and the compliance requirements known. KCP&L

believes several of these steps alone can exceed six months much less all the steps in total. 

[Kansas City Power & Light (EPA-HQ-OAR-2009-0491-4584), p. 2.]

RESPONSE: See the preamble of final supplemental rule, section III.B.iv. Also see the 

preamble to the final Transport Rule, section VII.C.2 and the "Transport Rule Engineering 

Feasibility Response to Comments" document in the docket to this rulemaking (Docket ID No. 

EPA–HQ–OAR–2009–0491). The Transport Rule does not apply unit-specific requirements, 

thus provides flexibility for compliance across units with various control capacities.

Comment: In the Supplemental Proposal, EPA says that it expects to finalize a rule for 

Oklahoma and the other five states on or before November 1, 2011, which would allow 

approximately six months of lead time before the start of the 2012 ozone season. EPA claims 

that only "a small number" of sources would need to install combustion controls in order to 

comply with the CSAPR, and that this small number of required installations can be achieved in 

just six months.

EPA's assumptions are incorrect for Oklahoma and the surrounding region. To comply with the 

Supplemental Proposal (without considering other EPA rulemakings on air emissions), one 

commenter anticipates that it would need to install Low NOX Burners ("LNBs") on all five of its 

coal-fired units, which represent a significant portion of the generating capacity in Oklahoma. 

Another utility group commenter states broadly that it will need to install controls on many of its 

affected units. EPA itself estimates that LNBs will need to be installed on 30 coal-fired boilers, 

mostly in Oklahoma and surrounding states. In Oklahoma alone, EPA assumes that LNBs will be 

responsible for 9,900 tons of ozone season NO, emission reductions in Oklahoma during 2012. 

Commenters therefore disagree with EPA's notion that LNB retrofits will impact a "small 

number" of units in the region.

Furthermore, it will not be possible to procure, permit, and install the necessary controls on these 

units before May of 2012. Some commenters estimate that it will need roughly three years from 

the date of an appropriate final rule before the required controls could be operational on the 

appropriate units. Overall, this process requires project scoping, budgeting, engineering and 

design, bidding, permitting, outage planning, equipment fabrication, delivery, and installation.

One utility group commenter estimates that it will need somewhere between 2 1⁄2 to 3 years, 

before the required controls can be installed and are functionally operational. This is typical for 

this kind of installation of air emission controls. It will take 12-18 months to bid and acquire the 

necessary equipment. Assuming permits and regulatory approvals can be obtained 
52

simultaneously with this procurement process, the timing to apply for and receive the required 

permits and approvals will require approximately 12-18 months. Another 12-18 months of 

construction time may be needed once equipment, permits and approvals are available for the 

controls to be operational. In some instances the controls may require additional tuning over a 

period of four (4) to six (6) months to achieve the designed reductions. Overall, this process 

requires project scoping, budgeting, engineering and design, bidding, permitting, outage 

planning, equipment fabrication, delivery, and installation. While not included in this estimate, 

another timing requirement will be to schedule and determine how the units will be allowed to be 

taken off-line for the installation – whether during scheduled outages or if other timing involved 

with the SPP approval. This comprehensive planning and schedule coordination will require 

additional time and may prevent the controls being installed as quickly as they might without 

these important considerations for electricity reliability on the grid.

Another commenter states that it is estimated that affected units would need 12-18 months to 

acquire the necessary equipment and permits, and that it is estimated that 21 months of 

construction time would be necessary once equipment and permits are available.

EPA's two anecdotal instances of LNB installations in Texas and Georgia from the two page 

TSD for this rulemaking do not support a six-month schedule for installing LNBs on 

commenters’ units. Two commenters note that as an initial matter, the "similar schedule" 

mentioned in the TSD for the Southern Company units was actually eight months, not six. 

Furthermore, these examples do not account for the entire process leading up to operation. 

Specification, selection, procurement, and permitting are not discussed in one or both examples. 

Optimization is also not taken into account. Reliant Energy, for example, installed LNBs in May

but then spent through September tuning the controls to achieve performance guarantees.

One of the commenters notes that unit-specific characteristics distinguish EPA's two examples 

from its units. The document cited for Reliant Energy mentions additional boiler modifications 

that would be required when burning Powder River Basin coal, which commenter uses in its 

units. For the Southern Company units, the retrofit system consisted of burners only and did not 

require the design or installation of overfire air systems, as would commenter's units. The 

examples were 1990-2001 retrofits, whereas commenter would need to install controls under 

different circumstances and at a time when contractor and equipment availability will be at a 

premium. Commenter also differs from EPA's two examples in that it will need to proceed on its 

units in phases for demand reliability reasons. For all these reasons, EPA has no basis for setting 

a compliance schedule based on two isolated examples that are not comparable to LNB 

installation schedules for EGUs in Oklahoma.

Some commenters also noted in conjunction with these examples cited by EPA that, contrary to 

those examples, it is infeasible for WFEC to install controls by May 1, 2012 that will be 

necessary to achieve the emissions reductions required by the proposed unit-specific allowance 

allocation for its units. Under the Proposal, WFEC must reduce its overall emissions by 30 

percent. Installation of dry low NOX burners on Anadarko units 4, 5, and 6 is the quickest and 

most cost effective way for WFEC to achieve the required reductions through controls. EPA 

makes the unfounded assumption in its technical support documents that low NOX burners can 
53

be purchased, installed, and tuned within 6 months. EPA's assumption is based on vendor papers 

developed as marketing tools. These papers are not an unbiased technical assessment 

representative of industry practices. EPA cannot rely on promotional materials to determine the 

feasibility of installing controls. 

WFEC has solicited bids for low NOX burners from several vendors. Simply obtaining the 

equipment will take WFEC between 12 and 18 months. After WFEC obtains the necessary

equipment, there are numerous other factors that will further delay installation of the controls. 

First, WFEC must obtain approval from Southwest Power Pool ("SPP") before it takes the units 

offline for an extended outage (it will take approximately six to eight weeks to install the low 

NOX burners at each unit). SPP has members in nine states; eight of those states are affected by 

either CSAPR or the Proposal. EGUs in each of these states also will need to install controls. 

Second, WFEC must undertake extended outages during shoulder seasons. Due to increased 

demand, it cannot shut down a unit for a significant amount of time during the winter and 

summer months. Finally, WFEC must obtain the necessary permits before it begins installation 

of the low NOX burners. The permitting process can take between 12 and 24 months, depending 

on the potential affect of the proposed project on emissions. Even if WFEC beings the process of 

obtaining the necessary equipment and permits now, it would be impossible for the company to 

install controls by the compliance deadline for the first ozone-season NOX trading program.

Another commenter (GRDA) stated that it must reduce its overall NOX emissions by over 50 

percent. Installation of low NOX burners with over fire air and computerized combustion controls 

is the most expedient and technically established method for GRDA. To implement such a 

customized solution requires substantially more time than the six (6) months allowed by the 

Proposal. GRDA has carefully studied EPA's explanation of its decision to allow Oklahoma 

utilities only six (6) months to implement multiple and complex NOX reduction projects, and it is 

apparent EPA's six month allowance is unreasonable, and not consistent with EPA's own 

statement of facts. For example, EPA expressly acknowledges on page 48281 of the published 

rule that "historical projects suggest a more typical schedule would be 12 to 16 months for the 

contractors' portion of the work. A plant owner's project planning and procurement work in 

advance of a contract award would typically involve several additional months." The coal fired 

units in Oklahoma are the primary and most reliable base load providers of electricity. Of these, 

nine units totaling over 4,000 megawatts will require design and installation of customized low 

NOX burner systems. The installation and startup time for such systems is a minimum of several 

months, and electric system needs would necessitate that all nine Oklahoma units be scheduled 

between March 20 - May 1, 2012. Successfully mobilizing the necessary experienced engineers 

and technicians for installation and successful startup would be in grave doubt. Industry

experience has clearly shown that tuning of new low NOX systems often takes several months. 

GRDA has consulted with a highly experienced engineering firm (Black & Veatch), and also 

obtained preliminary conceptual proposals from vendors of low NOX burner systems. Based on 

these consultations, an achievable and prompt implementation schedule for customized and 

effective low NOX burner systems in Oklahoma (and GRDA) needs to include a number of 

elements totaling 36 months as outlined in a full detailed list in the commenter’s letter.
54

Another commenter states that it will need roughly three years from the date of an appropriate 

final rule before the required controls can be installed and operation. This amount of time is 

typical for the kind of work required, and other EGUs are likely to be in a similar position. 

Therefore, in addition to revising the Supplemental Proposal to set forth a reasonable degree of 

emission reductions, the Agency should allow no less than three years from the date of a final 

rule for sources to comply. [Oklahoma Gas & Electric Company (OGE) (EPA-HQ-OAR-2009-

0491-4590), p. 8-9; Oklahoma Utility Group (EPA-HQ-OAR-2009-0491-4591), p. 6-7; AES 

Shady Point (EPA-HQ-OAR-2009-0491-4595), p. 5; Western Farmers Electric Cooperative 

(EPA-HQ-OAR-2009-0491-4589), p. 10-11; Grand River Dam Authority ("GRDA") (EPA-HQOAR-2009-0491-4586), p. 6-8.]

RESPONSE: See the preamble of final supplemental rule, section III.B.iv. Also see the 

preamble to the final Transport Rule, section VII.C.2 and the "Transport Rule Engineering 

Feasibility Response to Comments" document in the docket to this rulemaking (Docket ID No. 

EPA–HQ–OAR–2009–0491). The Transport Rule does not apply unit-specific requirements, 

thus provides flexibility for compliance across units with various control capacities.

Comment: EPA's claim of two (2) low NOX burner projects requiring only six (6) months is 

incorrectly assessed and should not be utilized for the following reasons:

● In the case cited by EPA (subscript 62) by Riley Power, this project only included low 

NOX burners, and was specifically implemented without the use of overfire air (OFA) or 

burner sizing changes. The actual NOX emissions attained after this example project was 

only a pitiful .36 lb/MMBtu. In the case of GRDA, this .36 level is already surpassed and 

GRDA must achieve a reduction to approximately 0.16 lb/MMBtu to meet Proposal 

allowances. Clearly, much more sophisticated, and customized, burner technology 

systems will be needed than this EPA example. Lastly, this "paper" cited by EPA was 

obviously written by the vendor as a sales promotional tool. This "paper" should not be 

relied on by EPA as representing an independent and impartial assessment of the facts, 

and a basis for issuing enforceable regulations.

● In the case cited by EPA (subscript 63) by Foster Wheeler, this "paper" is again 

obviously a sales promotional tool, and should not be relied on by EPA as representing an 

independent and impartial assessment of the facts, and a primary basis for establishing 

enforceable regulations. The paper claims 16 weeks to engineer and fabricate low NOX

burners, and 7 weeks to install them. However, no facts are presented that demonstrated 

the project only took six months total and no mention was made of how this base load 

unit was scheduled for its nearly two month outage. In addition, the paper states "The 

system was fully operational in May of 2000 and was tuned by September to consistently

achieve a NOX performance guarantee". This statement positively shows an additional 

four months were needed to actually get burners to work properly, which is not unusual 

for low NOX systems. The "paper" states the design was simply copied from a similar 

Foster Wheeler design and it is therefore clear the engineering time was minimal. The 

paper states the burners were for tangential style burners which are known to be easier to 

achieve results than those at GRDA. Clearly, this case does not warrant EPA establishing 
55

a six (6) month implementation regulation for the Oklahoma base load coal units. [Grand 

River Dam Authority ("GRDA") (EPA-HQ-OAR-2009-0491-4586), p. 6-7.]

RESPONSE: EPA is not basing this final rule’s 2012 state budget for Oklahoma on the 

installation of new combustion controls by that control period. See the preamble of final 

supplemental rule, section III.B.iv. Also see the preamble to the final Transport Rule, section 

VII.C.2 and the "Transport Rule Engineering Feasibility Response to Comments" document in 

the docket to this rulemaking (Docket ID No. EPA–HQ–OAR–2009–0491). The Transport Rule 

does not apply unit-specific requirements, thus provides flexibility for compliance across units 

with various control capacities. In addition, sources in four of the states covered by this final 

rule (Iowa, Michigan, Missouri, and Wisconsin) are already covered by the final Transport 

Rule’s annual NOX program, which was finalized almost a year in advance of the 2012 ozone 

season; these sources should have already begun implementing any desired NOX combustion 

controls well before finalization of this rule.

Comment: EPA'S referenced Technical Support Document (TSD) "Installation Timing for Low 

NOX Burners (LNB)” states that EPA "analyzed" the installation of NOX burners on 30 boilers in 

the four affected states that are not in CAIR, with Oklahoma being one of these four states. This 

TSD is defective in several aspects. First of all, the TSD assumes the proposal will be finalized 

in June 2011 and burner modifications will be performed during fall of 2011 and spring of 2012. 

However, the Proposal final rule is now planned for October 2011. The TSD was not updated to 

consider this four month delay of the rule. No implementation of low NOX burners can be done 

in the fall of 2011 which means all 30 boilers must be modified in the spring of 2012. These 30 

boilers are the primary base load electric generators for the involved utilities. In particular, taking 

out the affected boilers in Oklahoma, Kansas and Nebraska at the same time would be 

irresponsible and threatens public safety and health. EPA could have learned this with a few 

simple phone calls, but no evidence is included this was done. EPA has apparently instead relied 

on a single telephone discussion with a vendor, and two sales promotion "papers" issued by

vendors. No apparent effort was made to obtain independent and non-biased assessment from a 

competent engineering firm. There is no evidence that EPA contacted utilities, the Southwest 

Power Pool or NERC. As such, EPA has failed to meet its required consideration of such impacts 

on the electric energy system. Secondly, the referenced paper by Foster Wheeler contains no 

statement the entire project was done in a total of six months. In fact, the paper admits that 

tuning to meet burner guarantees took four months (during the critical summer months). Thirdly, 

both referenced examples were clearly non-typical situations where minimal boiler modifications 

and engineering was performed. EPA should not base their rule making on such non-typical 

examples. Fourthly, EPA's overly "aggressive" six month schedule will prevent GRDA and other 

Oklahoma utilities from obtaining competitive and fair pricing, and is therefore not in the public 

interest. Vendors will be able to charge exorbitant prices, overtime and support fees. GRDA's 

ability to negotiate NOX performance guarantees will be impaired and this is not in the public 

interest.

In summary, GRDA strongly objects to the six (6) month implementation and requests EPA to 

utilize the 36 month implementation schedule described earlier. [Grand River Dam Authority 

("GRDA") (EPA-HQ-OAR-2009-0491-4586), p. 7-8.]
56

RESPONSE: EPA is not basing this final rule’s 2012 state ozone season budget for Oklahoma 

on the installation of new combustion controls by that control period. See the preamble of final 

supplemental rule, section III.B.iv. Also see the preamble to the final Transport Rule, section 

VII.C.2 and the "Transport Rule Engineering Feasibility Response to Comments" document in 

the docket to this rulemaking (Docket ID No. EPA–HQ–OAR–2009–0491). The Transport Rule 

does not apply unit-specific requirements, thus provides flexibility for compliance across units 

with various control capacities.

Comment: Even if EPA retains the allowance budget that is currently proposed for Oklahoma, 

an initial compliance deadline of May 1, 2012 is not reasonable and must be revised. The 

Agency should allow no less than three years for utilities to evaluate generating options, obtain 

allowances, arrange for the purchase of replacement power where possible, and install controls to 

achieve the actual emission reductions that will drive the trading program in Oklahoma.

Commenters state that a compliance schedule of three years is especially appropriate in light of 

the fact that Oklahoma was not included in CAIR and has relatively tenuous modeled impacts 

compared to other states. As evidenced by the shifts in EPA's modeling and emission budgets for 

Oklahoma over the years, affected sources in the State have faced significant uncertainty

regarding whether, and to what extent, they would be subject to interstate transport requirements. 

This uncertainty translated into Oklahoma sources having less notice of the requirements than 

sources in other states.

One of the commenters also argues that EPA should consider that capital expenditures for 

environmental controls cannot be included in customer rates until state regulatory agencies 

authorize cost recovery. The commenter notes that controls were not going to be necessary for its 

units based on the 2010 Proposed Rule. As a final alternative, if EPA retains the allowance 

budget and the May 1, 2012 deadline in the Supplemental Proposal, EPA should at the very least 

delay application of the assurance provisions until 2014 so that interstate trading can provide 

more allowances to Oklahoma EGUs while the markets for instate allowances develop. 

Otherwise, if faced with inadequate lead time for installing controls and a shortfall of emission 

allowances, commenter and other electric utilities would be forced to curtail operations to avoid 

noncompliance with CSAPR. As noted, the commenter's coal-fired units could need to curtail 

operations by roughly 50% during the ozone season, compared to their operations in 2010, if 

sufficient allowances are not available. EPA has not provided an adequate assessment of the 

impacts on electric reliability from this level of curtailment. [Oklahoma Gas & Electric 

Company (OGE) (EPA-HQ-OAR-2009-0491-4590), p. 10; Oklahoma Utility Group (EPA-HQOAR-2009-0491-4591), p. 7.]

RESPONSE: EPA has proposed to adjust the effective date of the Transport Rule assurance 

provisions in a separate rulemaking (see 76 FR 63860, October 14, 2011). EPA believes that this 

final rule’s 2012 state budget for Oklahoma represents feasible emission reductions in that 

timeframe (see section III.B.iv of the preamble to this final rule). The Transport Rule does not 

apply unit-specific requirements, thus provides flexibility for compliance across units with 

various control capacities. See comments in other areas of this Response to Comment document 
57

regarding EPA’s assessment of current and future market liquidity and allowance availability

based on current reports from the market place.

Comment: The timeline for compliance with the rule’s requirements is not realistic. The final 

rule (published in the Federal Register on August 8, 2011) establishes a compliance schedule for 

both the PM-2.5 and ozone portions of the rule that makes sense only for those states that were 

previously covered by the Clean Air Interstate Rule (CAIR). The final CAIR was published in 

March of 2005, allowing utilities owning or operating units subject to the rule years to come into 

compliance with the cap-and-trade system set up by the rule. Key components of any successful 

market-based program include (1) sending clear signals to the market regarding the number of 

allowances which will be issued and (2) allowing the companies owning and operating units 

subject to the rule sufficient time to plan for future needs. DEQ recognizes that the vacatur and 

associated holding by the Court of Appeals for the District of Columbia Circuit put the EPA in a 

position which necessitated that EPA set the compliance date for states already covered by CAIR 

such that there would be no gap between compliance with CAIR and compliance with CSAPR. 

DEQ appreciates that this was needed to retain the reductions in emissions associated with the 

installation of new controls and other changes required by CAIR. A seamless transition from 

CAIR to CSAPR makes sense for facilities located in those states; however there is no similar 

justification for the short time period between the issuance of the final rule and the requirements 

for compliance for states like Oklahoma that were not part of CAIR. Based on the state budgets 

announced in the Proposed Transport rule, it appeared that EPA was taking those concerns into 

account by establishing budgets that could realistically be achieved by the non-CAIR states in 

general and Oklahoma in particular.

However, if the SNPR is finalized by the target date of October 1, 2011, that will only allow 

utilities seven months to plan, acquire capital, design, and install the control systems that will be 

required to allow those units to operate in compliance with the rule. Even the EPA’s own 

Technical Support Document (TSD), “Installation Timing for Low NOX Burners,” (issued July

2010), assumes that there are only 30 boilers located in the four states not already covered by 

CAIR and that utilities would be able to install low NOX burners on those boilers if EPA was 

able to finalize the rule by June 2011. EPA has missed that target. The rule covering the six 

states (including Oklahoma) will not likely be finalized until October of 2011; therefore, even 

EPA’s own documents show the false premises upon which the assumption of a smooth 

transition to compliance with CSAPR were constructed.

For Oklahoma utilities who were first excluded from CAIR and then led to believe based on the 

allowances in the proposed Transport Rule that compliance could reasonably be achieved, seven 

months is not enough time to accomplish the required measures based on the new timeline and 

new allowances in the SNPR. First, before installation can even begin, utilities will have to have 

the capital expenditures approved, get designs in place, and obtain the required permits. If PSD is 

triggered, permit issuance could possibly take 9-12 months, 3-6 months if PSD is not triggered. 

Secondly, Oklahoma utilities must obtain permission from the Southwest Power Pool to 

undertake the substantial downtimes that will be required to install control equipment (upwards 

of 40-50 days). Based on power demand and the short timeline, brown-outs could very likely 

occur.
58

The pace and aggressiveness of these environmental regulations should be adjusted to reflect and 

consider the overall risk to the bulk power system. EPA, FERC, DOE, and state utility

regulators, both together and separately, should employ the array of tools at their disposal to 

moderate reliability impacts, including, among other things, granting required extensions to 

install emission controls. [Oklahoma Department of Environmental Quality (EPA-HQ-OAR2009-0491-4593), p. 2-3.]

RESPONSE: See the preamble of final supplemental rule, section III.B.iv. Also see the 

preamble to the final Transport Rule, section VII.C.2 and the "Transport Rule Engineering 

Feasibility Response to Comments" document in the docket to this rulemaking (Docket ID No. 

EPA–HQ–OAR–2009–0491). The Transport Rule does not apply unit-specific requirements, 

thus provides flexibility for compliance across units with various control capacities.

Comment: Agency commenter calculates that utilities operating in Oklahoma will need to 

retrofit 43 individual combustion units with low-NOX burners to comply with the requirements 

of the new rule. This number is substantially larger than the 30 units in a four-state area predicted 

in EPA’s TSD, “Installation Timing for Low NOX Burners (LNB).” To remedy these failings, 

agency recommends that the compliance date for units operating in Oklahoma be pushed back to 

the 2015 ozone season. We believe that our request for a minimum of a three-year extension of 

the compliance date is justified for four reasons: (1) that is the minimum time necessary between 

issuance of the final rule (which will set the allowance budget) and the time the utilities will need 

to be able to plan for compliance with the rule – this is an essential component of any marketbased approach, (2) the failure of the EPA to abide by the assumptions identified in their own 

TSD regarding the time required to install low-NOX burners, (3) the large number of units (43) 

that will need to be retrofitted in Oklahoma and the burden that will place on engineers, 

equipment suppliers, and the utilities, and (4) the need to allow for utilities to apply for PSD 

permits as well as the time required to evaluate and draft the permits and that needed for the 

public and EPA to review them. [Oklahoma Department of Environmental Quality (EPA-HQOAR-2009-0491-4593), p. 4-5.]

RESPONSE: See the preamble of final supplemental rulemaking, section III.B.iv. Also see the 

preamble to the final Transport Rule, section VII.C.2 and the "Transport Rule Engineering 

Feasibility Response to Comments" document in the docket to this rulemaking (Docket ID No. 

EPA–HQ–OAR–2009–0491). The Transport Rule does not apply unit-specific requirements, 

thus provides flexibility for compliance across units with various control capacities.

Comment: Should the EPA proceed with this rule making I would request that Oklahoma be 

granted a more reasonable implementation timeline. Because we are so close to the effective 

date, it will be impossible for Oklahoma sources to comply and be fitted in time with the 

appropriate emission controls, which require custom design, engineering, and installation 

specific to each source. With an unrealistic implementation timeline such as the one proposed, 

the reliability of electrical generation in the state of Oklahoma and the livelihood of many

Oklahomans is at stake. [Governor, State of Oklahoma (EPA-HQ-OAR-2009-0491-4594), p. 1.]
59

RESPONSE: See the preamble of final supplemental rulemaking, section III.B.iv. In addition, 

note that the Transport Rule does not apply unit-specific requirements, thus provides flexibility

for compliance across units with various control capacities.

Comment: Our preliminary review of the proposed rule and the supporting documentation 

brings us to the same conclusion for both the final rule and the proposed supplemental rule, 

which is there is insufficient time for Kansas utilities to comply with either rule. Of the 28 states 

that will be subject to the Cross State Air Pollution rule (CSAPR) starting in 2012, all but three 

were subject to the Clean Air Interstate Rule (CAIR) prior to CSAPR. The three non-CAIR states 

are Kansas, Nebraska, and Oklahoma. CAIR states have had several years to prepare plans, 

obtain construction permits, and commence or complete construction of projects to reduce 

emission of nitrogen oxides and sulfur dioxide. Until very recently, Kansas and the other nonCAIR states have shared uncertainty with respect to interstate transport and future control 

requirements. Kansas finds itself at a disadvantage, when compared to the CAIR states, when 

faced with a 2012 compliance deadline. In section VII C. 2. of the CSAPR preamble (76 FR 

48279), EPA states:

"In 2012, the industry will largely meet the rule's NOX requirements by: Operating an 

extensive existing set of combustion and post-combustion controls on fossil fuel-fired

generators; dispatching lower emitting units more often; and installing and operating a 

limited amount of relatively simple NOX pollution controls in states not previously

subject to CAIR."

EPA acknowledges that utilities in non-CAIR states likely will need to install "relatively simple 

NOX pollution controls," such as low-NOX burners and overfire air, to meet the state emissions 

budget for 2012. EPA further posted a NOX cost threshold of$500 per ton for states under the 

Cross-State Air Pollution Rule. Installing combustion NOX pollution controls is not a simple task 

and cannot be completed in the six months time frame the proposed rule would allow. We have 

current real world costs for installation of such controls and they are higher than the $500 cost 

threshold. The rush for Kansas utilities to comply with a 2012 deadline will result in increased 

costs and the potential for stranded investments resulting from interim measures or "temporary

fixes." For a utility to install low NOX burners, a prevention of significant deterioration (PSD) 

permit generally will be required due to an increase in carbon monoxide emissions. The PSD 

construction permitting process alone would normally take more than five months. It is highly 

unlikely that Kansas utilities will be able to install controls and meet the state's emissions budget 

for 2012.

Many Kansas facilities are in the planning stages for installation of additional controls to be 

completed between 2012 and 2015, and have received permits or have applications in process. 

Emission reductions from approved projects now underway and in 2012 will reduce over 14,000 

tons of NOX and 18,133 tons of SO2. Once these controls are in place, the State of Kansas 

should be able to meet the assurance levels established in the Cross State Rule. Kansas needs the 

time for these plans to be put in place to comply with the proposed rule. We believe that the 

assumptions made by EPA in terms of cost of compliance and ability to complete pollution 

control projects in time for the 2012 ozone season are fundamentally flawed and therefore do not 
60

accurately reflect the actual impacts the proposed rule will have on the Kansas economy. We 

formally request that EPA provide the State of Kansas and its affected utilities two additional 

years to comply with the provisions of the proposed supplemental Cross-State Air Pollution 

Rule. [Kansas Department of Health & Environment (EPA-HQ-OAR-2009-0491-4582), p. 2.]

RESPONSE: See the preamble of final supplemental rule, section III.C regarding the status of 

Kansas in the final rule. Also see the preamble for the final Transport Rule, section VII.C.2 and 

the "Transport Rule Engineering Feasibility Response to Comments" document in the docket to 

this rulemaking (Docket ID No. EPA–HQ–OAR–2009–0491) regarding timing and feasibility of 

controls installation. Note that the Transport Rule does not apply unit-specific requirements, 

thus provides flexibility for compliance across units with various control capacities.

Comment: PSO and AEP believe that if these states are required to reduce emissions, the level 

of reductions and the schedule for the emission reductions can and should be relaxed. There is no 

immediate need associated with potential health impacts since the Michigan County at issue is 

already in attainment and predicted to remain in attainment. This clearly illustrates that there is 

no need to rush the emission reductions EPA proposed for 2012. The proposed time schedule for 

emission reductions will greatly impact the availability of existing generating sources in these 

states by requiring controls be added prior to the 2012 ozone season. Very few units will be able 

to install controls in order to comply with the 2012 ozone season and generation may not be 

available during high demand periods. Given the uncertain availability of NOX allowances and 

the compliance risk associated with utilizing allowances above the assurance level, sources will 

likely curtail operation to achieve compliance. The result could be either insufficient generating 

capacity to meet load demands during peak summer conditions and/or much higher prices for 

power purchases during these periods which will significantly impact customer costs. We are 

also uncertain of the availability and price of NOX allowances for the 2012 ozone season. We 

expect the State as a whole to require allowances greater than the 21% assurance level above the 

state budget which will add an undue burden on the rate payers of Oklahoma. By extending the 

compliance dates by 2-years or more, the industry would have time to properly plan and install 

any needed controls in Oklahoma and other states. [Public Service Company of Oklahoma 

(EPA-HQ-OAR-2009-0491-4600), p. 3-4.]

RESPONSE: See section III.B.iv in the preamble to the final supplemental rule. Also, see the 

preamble of final Transport Rule, section VII.C.2 and the "Transport Rule Engineering 

Feasibility Response to Comments" document in the docket to this rulemaking (Docket ID No. 

EPA–HQ–OAR–2009–0491). Note in addition that the Transport Rule does not apply unitspecific requirements, thus provides flexibility for compliance across units with various control 

capacities.

(C) Commenter(s) disagree with statement that ability to purchase allowances helps 

address concerns over compliance timetable.

Comment: EPA recognizes in the Supplemental Proposal that some sources will need more than 

six months to procure, permit and install combustion controls. In this situation, EPA says that 

sources may comply through the purchase of additional allowances. Commenters have not been 
61

able to identify how sufficient allowances could be available in Oklahoma while still allowing 

EGUs to meet consumer demand. They believe there will be a shortfall of allowances, especially

during the 2012 ozone season. With no system of information available with which to discern 

allowances and their pricing, commenters assert that more time is needed before the start of 

CSAPR in order to appropriately manage the supply (and cost) of allowances available for 

purchase.

Table A in the comments shows that a reduction of close to 13,000 tons, or roughly 40%, from 

actual 2010 state-wide NO, emissions would be needed in order to make sufficient in-state 

allowances available to EGUs in Oklahoma. The group of commenters represents roughly 80% 

of the generating capacity in the State of Oklahoma and, as noted, will be unable to install 

controls by May 2012. The group of commenters would need to purchase roughly 16,000 tons of 

ozone season NOX allowances prior to that date. One of the commenters states that it will have 

to purchase up to 6,000 allowances, mostly from EGUs that make up the other 50% of the State's 

generating capacity. Those other units, however, would themselves be required to reduce (or 

obtain allowances for) an additional 7,000 tons or so of NOX emissions. Because many of these 

units will be unable to reduce emissions in less than six months time, there is not likely to be a 

sufficient supply of in-state allowances available for purchase in the early days of CSAPR in 

Oklahoma.

Moreover, even if some units reduce emissions in 2012, they could choose to bank rather than 

sell their allowances in light of EPA's stated intent to promulgate further interstate transport 

requirements in the future. Allowances that are available for purchase are likely to be at a 

premium price. While commenters agree that allowance banking is a cost-effective and 

important feature of any emissions trading program, EPA should recognize that banking also can 

lead to an allowance shortfall (and high prices) at the beginning of a trading program when 

drastic emission reductions are required without sufficient time to install controls, and further, 

unspecified reductions are likely to be required in the future.

Interstate trading will be of limited use to commenters and other utilities that must obtain 

thousands of allowances at the start of the CSAPR program, if EPA applies the assurance 

provisions starting in 2012. The assurance provisions would mean that interstate trading could 

provide no more than 4,585 tons of ozone season NOX allowances (i.e. the variability limit) to 

EGUs in Oklahoma during 2012, or else penalties would be imposed on the State and its sources. 

One of the commenters notes that it alone will require more allowances than interstate trading 

could provide.

Given the lack of sufficient allowances, EPA should revise the Supplemental Proposal to allow a 

reasonable allowance budget. Once a reasonable budget is established, utilities will need at least 

three years from the date of a final rule to comply, which is the amount of time needed to install 

controls for achieving actual emission reductions. One of the commenters notes here, echoing 

similar remarks summarized above, that EPA should at the very least delay application of the 

assurance provisions until 2014 so that interstate trading can provide more allowances to 

Oklahoma EGUs while the markets for instate allowances develop. Otherwise, if faced with 

inadequate lead time for installing controls and a shortfall of emission allowances, commenter 
62

would be forced to curtail operations to avoid noncompliance with CSAPR. EPA has not 

provided an adequate assessment of the impacts on electric reliability from this level of 

curtailment. [Oklahoma Gas & Electric Company (OGE) (EPA-HQ-OAR-2009-0491-4590), p. 

9-10; Oklahoma Utility Group (EPA-HQ-OAR-2009-0491-4591), p. 7.]

RESPONSE: Market liquidity is already developing in the Transport Rule (TR) emission 

markets, including in the ozone season NOX market relevant to this rule. Facilities have been 

trading allowances since EPA formally recorded 2012 Transport Rule allowances into designated 

facility accounts on October 18, 2011. In fact, several trades of Transport Rule allowances took 

place prior to the formal distribution of allowances. Initial transactions have been followed by

further trades and options contracts in all of the trading programs.

Further, on Thursday, November 17, 2011, First Energy held a successful auction of a minimum 

of a 100,000 SO2 allowances, 50,000 each from 2012 and 2013 markets, along with an 

undisclosed amount of annual and ozone season NOX allowances. This auction is a significant 

injection of liquidity into the market by a single entity, further indicating that a sufficient 

numbers of allowances will be available to meet the needs of sources. They are planning to hold 

another auction on April 30, 2012.1

Market liquidity has developed rapidly in all of the previous emission trading programs that EPA 

has implemented, including the Acid Rain Trading Program, the NOX SIP Call, the NOX Budget 

Program, and most recently CAIR, the predecessor to the Transport Rule. In both CAIR and the 

Transport Rule, individual units have the flexibility to supplement their own allowance 

allocations with the acquisition from the marketplace of any additional allowances needed to 

cover emissions under the Transport Rule programs. Healthy markets for the CAIR annual NOX, 

CAIR ozone-season NOX, and Acid Rain (SO2) program allowances have been in existence for 

many years and delivered compliance costs below EPA’s estimates. Further, as mentioned, 

trades have already taken place for allowances in the seasonal NOX market and other TR markets 

in anticipation of program implementation. Also see “Sam Napolitano Omnibus Declaration” in 

the docket to this final rulemaking.

EPA is addressing the timing of the assurance provisions in a separate rulemaking (76 FR 63860, 

October 14, 2011).

Comment: EPA says in the Supplemental Proposal that individual sources may comply through 

the purchase of additional allowances in the event that it takes a particular source more than six 

(6) months to install combustion controls. EPA fails to acknowledge the potential for allowance 

shortfalls, especially leading up to the proposed 2012 compliance deadline. EPA allowance 

allocation shows that a 37.5% reduction in actual state-wide NOX emissions are needed for 

sufficient in-state allowances to be available. EPA has not suggested any means for achieving 

this sort of reduction in the few short months before the beginning of the 2012 ozone season.

 

1

First Energy. FirstEnergy Successfully Concludes Emission Allowance Auction. Press release. November 18, 2011. Available 

on the Internet at <http://www.fescsaprauction.info/Portals/0/Documents/News/2011-11-

18%20FES%20Successfully%20Concludes%20Emission%20Allowance%20Auction.pdf>.
63

Interstate trading is limited by assurance provisions that restrict EGU emissions within each state 

to the state's budget plus the variability limit. The number representing a state's budget + 

variability limit is referred to as the "assurance level." For Oklahoma, the assurance level in 2012 

for ozone season NOX from EGUs is 21,835 (budget) + 4,585 (variability limit) = 26,420. The 

purchase of allowances by individual sources cannot authorize the state to go above 26,420 tons 

of ozone season NOX emissions. Otherwise, penalties will be imposed on the state and its 

sources. Note that EPA originally proposed to apply the assurance provisions starting in 2014, 

but the final rule implements the provisions starting in 2012. Commenters favor a 2014 start date 

for assurance provisions.

If faced with inadequate lead time for installing controls and a shortfall of emission allowances, 

utilities would be forced to shut down some units or curtail their operation to avoid 

noncompliance with CSAP program requirements. If curtailment becomes necessary for CSAP 

compliance, the only other alternative to serve customers is to purchase power from out-of state 

generators. It is unknown if sufficient additional generating capacity will be available from units

within the Southwest Power Pool. Additionally power which is available to be supplied by the 

Southwest Power Pool would increase NOX emissions in the generating state as well. [AES 

Shady Point (EPA-HQ-OAR-2009-0491-4595), p. 5-6.]

RESPONSE: Market liquidity is already developing in the Transport Rule (TR) emission 

markets, including in the ozone season NOX market relevant to this rule. Facilities have been 

trading allowances since EPA formally recorded 2012 Transport Rule allowances into designated 

facility accounts on October 18, 2011. In fact, several trades of Transport Rule allowances took 

place prior to the formal distribution of allowances. Initial transactions have been followed by

further trades and options contracts in all of the trading programs.

Further, on Thursday, November 17, 2011, First Energy held a successful auction of a minimum 

of a 100,000 SO2 allowances, 50,000 each from 2012 and 2013 markets, along with an 

undisclosed amount of annual and ozone season NOX allowances. This auction is a significant 

injection of liquidity into the market by a single entity, further indicating that a sufficient 

numbers of allowances will be available to meet the needs of sources. They are planning to hold 

another auction on April 30, 2012.2

Market liquidity has developed rapidly in all of the previous emission trading programs that EPA 

has implemented, including the Acid Rain Trading Program, the NOX SIP Call, the NOX Budget 

Program, and most recently CAIR, the predecessor to the Transport Rule. In both CAIR and the 

Transport Rule, individual units have the flexibility to supplement their own allowance 

allocations with the acquisition from the marketplace of any additional allowances needed to 

cover emissions under the Transport Rule programs. Healthy markets for the CAIR annual NOX, 

CAIR ozone-season NOX, and Acid Rain (SO2) program allowances have been in existence for 

many years and delivered compliance costs below EPA’s estimates. Further, as mentioned, 

 

2

First Energy. FirstEnergy Successfully Concludes Emission Allowance Auction. Press release. November 18, 2011. Available 

on the Internet at <http://www.fescsaprauction.info/Portals/0/Documents/News/2011-11-

18%20FES%20Successfully%20Concludes%20Emission%20Allowance%20Auction.pdf>.
64

trades have already taken place for allowances in the seasonal NOX market and other TR markets 

in anticipation of program implementation.

EPA is addressing the timing of the assurance provisions in a separate rulemaking (76 FR 63860, 

October 14, 2011.

Comment: It is equally infeasible for WFEC to comply with the required emissions reduction by

purchasing allowances. EPA anticipates that EGUs that cannot install controls by the compliance 

deadline will avoid violating the regulatory program by purchasing allowances. However, EPA's 

expectations for the liquidity of the allowance market are greatly inflated. ODEQ analyzed the 

state emissions budget information provided by EPA in its technical support documents for 

CSAPR and determined that, of the 26 states included in the ozone season NOX trading program, 

only five states are predicted to have excess allowances. See ODEQ Analysis, Attached. None of 

these states are in the SPP. The remaining states are expected to have allowance shortfalls that 

range between 4.5 and 42 percent. ld.

Accordingly, the Proposal would place WFEC in the untenable position of having to choose 

between violating the requirements of the program or derating or shutting down units. Derating 

or shutting down units would jeopardize WFEC's ability to fulfill its contractual obligation to 

supply power to the cooperatives it serves and ultimately to their retail, residential, commercial 

and industrial consumers. WFEC currently relies on some bilateral and market purchases to 

satisfy its obligations. If WFEC is forced to derate its EGUs to avoid violating CSAPR, it will 

need to significantly increase its power purchases. WFEC is concerned that if the Proposal is 

finalized, it will be unable to purchase sufficient power to cover the shortfall in generation. Eight 

of the nine states in the SPP are affected by either CSAPR or the Proposal and, thus, are unlikely 

to generate excess power for sale. Derating or shutting down units also would pose a significant 

risk to the public health and welfare. The cooperatives served by WFEC do not have access to 

other sources of power. If WFEC cannot respond to demand, the rural areas served by the 

cooperatives will experience potentially dangerous brownouts and blackouts. 16 WFEC urges 

EPA to seek additional information from SPP regarding the potential affect of the Proposal on 

reliability before issuing a final rule. 

GRDA has studied the NOX allowances for EGU's under the Proposal and is deeply concerned 

that sufficient NOX allowance will not be available in 2012 and that Oklahoma utilities will be 

gouged exorbitant millions of dollars to purchase allowances from eastern utilities which have 

had ample opportunity to accumulate such NOX allowances. To force Oklahoma utilities like 

GRDA to transfer many millions of dollars of wealth is patently unfair and serves no 

environmental benefit. GRDA estimates that its public power customers will express great 

outrage if such a wealth transfer was forced on them. Again, GRDA urges EPA to reconsider the 

Proposal schedule and allow a minimum of 36 months for implementation by Oklahoma EGU's. 

[Grand River Dam Authority ("GRDA") (EPA-HQ-OAR-2009-0491-4586), p. 5-6]

RESPONSE: Market liquidity is already developing in the Transport Rule (TR) emission 

markets, including in the ozone season NOX market relevant to this rule. Facilities have been 

trading allowances since EPA formally recorded 2012 Transport Rule allowances into designated 
65

facility accounts on October 18, 2011. In fact, several trades of Transport Rule allowances took 

place prior to the formal distribution of allowances. Initial transactions have been followed by

further trades and options contracts in all of the trading programs.

Further, on Thursday, November 17, 2011, First Energy held a successful auction of a minimum 

of a 100,000 SO2 allowances, 50,000 each from 2012 and 2013 markets, along with an 

undisclosed amount of annual and ozone season NOX allowances. This auction is a significant 

injection of liquidity into the market by a single entity, further indicating that a sufficient 

numbers of allowances will be available to meet the needs of sources. They are planning to hold 

another auction on April 30, 2012.3

Market liquidity has developed rapidly in all of the previous emission trading programs that EPA 

has implemented, including the Acid Rain Trading Program, the NOX SIP Call, the NOX Budget 

Program, and most recently CAIR, the predecessor to the Transport Rule. In both CAIR and the 

Transport Rule, individual units have the flexibility to supplement their own allowance 

allocations with the acquisition from the marketplace of any additional allowances needed to 

cover emissions under the Transport Rule programs. Healthy markets for the CAIR annual NOX, 

CAIR ozone-season NOX, and Acid Rain (SO2) program allowances have been in existence for 

many years and delivered compliance costs below EPA’s estimates. Further, as mentioned, 

trades have already taken place for allowances in the seasonal NOX market and other TR markets 

in anticipation of program implementation.

EPA is addressing the timing of the assurance provisions in a separate rulemaking (76 FR 63860, 

October 14, 2011.

Comment: EPA indicates that, “Individual sources may comply through other measures (such as 

purchasing additional allowances) in the event that it takes a particular source more than six 

months for installation of a given combustion control.” See 76 Fed. Reg. 40668, Section I(E). 

KCP&L does not agree with this statement. For example, KCP&L operates the La Cygne 

Generating Station in Kansas. This Station is the only coal-fired units operated by KCP&L in 

Kansas. The proposed 2012 ozone season allowance allocation shortfall is substantially greater 

than the Station’s share of the Kansas variability limit. So even if KCP&L was able to procure 

allowances to cover its shortfall at the Station, it would be exceeding its share of the Kansas 

variability limit. This puts KCP&L at risk of a significant penalty if the state exceeds it 

assurance level even though KCP&L La Cygne Generating Station had allowances to cover its 

emissions. See 76 Fed. Reg. 48296. This risk of penalty illustrates that EPA’s statement that the 

sources may purchase additional allowances is not a viable option to comply with our allowance 

shortfall at the Station. [Kansas City Power & Light (EPA-HQ-OAR-2009-0491-4584), p. 2-3.]

RESPONSE: EPA is not finalizing the FIP for Kansas at this time. See the preamble to the 

final supplemental, section III.C, for a discussion on Kansas’ current status.

 

3

First Energy. FirstEnergy Successfully Concludes Emission Allowance Auction. Press release. November 18, 2011. Available 

on the Internet at <http://www.fescsaprauction.info/Portals/0/Documents/News/2011-11-

18%20FES%20Successfully%20Concludes%20Emission%20Allowance%20Auction.pdf>.
66

(D) The rule presents reliability concerns.

Comment: In order to provide electrical service to our customers Empire District must maintain 

system reliability. Considering the severe shortage of allowances that will be available for 

purchase in 2012, sources that do not receive sufficient allocations permitting them to operate 

normally must install pollution control equipment. And given the fact that sources will not have 

enough time to install the proper pollution control equipment before January 1, 2012, to meet 

customer electrical demand will be forced to de-rate the unit(s) in order to comply with these 

rules. This will have an effect on system reliability. [Empire District Electric Company (EPAHQ-OAR-2009-0491-4581), p. 2.]

RESPONSE: EPA rejects the commenter’s assertion that there will be no allowances available 

to purchase in 2012. As explained above, ample evidence already exists that viable allowance 

markets for Transport Rule compliance are already developing and trading has already begun. 

Furthermore, sources have the benefit of accessing the allowance market not just ahead of the 

commencement of the programs, but also over the entire time horizon ahead of the allowance 

transfer deadlines by which sources must demonstrate compliance (December 1, 2012 for the 

2012 ozone season and March 1, 2013 for the annual programs in 2012). As a result, the 

Transport Rule offers substantial unit-level flexibility that will allow sources to continue to meet 

whatever obligations they may have concerning electric reliability. See also “Sam Napolitano 

Omnibus Declaration” in the docket to this rulemaking.

Comment: The Attorney General is also concerned about the effect of compliance upon the 

availability of electricity and the reliability of the grid in this region. To the knowledge of the 

Attorney General, there has been no complete or formal electric reliability assessment in 

cooperation with FERC for the CSAP Program, either alone or in combination with EPA's other 

proposed rules. FERC's informal analysis regarding the CSAP Program indicates that over 80 

gigawatts of coal-fired generation may be retired in response to EPA regulations. Instead of 

obtaining a complete reliability assessment from FERC, EPA instead relied upon emission 

projections and analyses developed using its Integrated Planning Model ("IPM"). However, a 

major limitation of the IPM model is that it assumes adequate transmission capacity exists to 

deliver any resource located in, or transferred to, the region in question and thereby fails to 

accurately evaluate impacts on reliability resulting from EPA programs such as CSAP, or 

combinations of EPA programs. The Attorney General is concerned that deficiencies in the IPM 

modeling could result in a shortage of replacement purchased power during the times in which 

either generating units are down or usage is curtailed due to efforts to comply with CSAP or 

other EPA rules. Electricity shortages could also result from the inability of utilities to timely

obtain needed permits and control equipment. Oklahoma electric utilities doubt that they can take 

the measures required to attain compliance with CSAP Rules within the six-month time frame 

currently allowed by EPA. Instead, they estimate needing twelve to eighteen months to acquire 

all necessary permits and equipment is given, with a total of twenty-one months estimated for the 

controls to be operational. Failure to obtain needed permits and control equipment by May 2012 

would result in the utilities' de-rating its non-compliant generating units to a point necessary to 

comply with ozone standards, meaning each of those units would be operating at far less than its 

rated capacity. As a result, uncertainty currently exists regarding the availability and price of 
67

purchased power, even assuming adequate transmission capabilities, due to the widespread 

imposition of CSAP requirements across many states. [Oklahoma Attorney General (EPA-HQOAR-2009-0491-4592), p. 2-3.]

RESPONSE: The commenter erroneously attributes “FERC’s informal analysis” of 80 GW of 

potential retirements to the Transport Rule, while in reality the commenter is citing a preliminary

FERC estimate that was based on a wide spectrum of several regulations, many of which had not 

even been proposed, and about which FERC made highly conservative assumptions about 

stringency of required controls that were not borne out by the rules as they were subsequently 

proposed. FERC’s own chairman has emphasized that FERC staff had to make assumptions 

about EPA regulations before they were proposed and that these regulations have changed , has 

characterized this document as only “an adequate back-of-the-envelope first assessment” and has 

stated that it “cannot be relied on to determine specific effects on system reliability. Therefore, it 

is “inadequate to use as a basis for decision making.” 4 EPA disagrees with the commenter’s 

unsupported allegation that its analysis, included in the final Transport Rule, “fails to accurately 

evaluate impacts on reliability.” EPA’s modeling includes interregional transmission limitations 

based on parameters published by the North American Electric Reliability Corporation, and 

those modeling assumptions were subject to public comment in the Transport Rule proposal as 

well as that rule’s IPM NODA. As explained in section III.B.iv of this rule’s preamble, as well 

as in the Determination of State Budgets for the Final Ozone Season Supplemental of the 

Transport Rule” TSD in the docket to this final rule, EPA has carefully examined the feasibility

of emission reductions required for Oklahoma under this final rule, and EPA’s analyses show 

that the Transport Rule does not threaten the availability or reliability of electricity for 

Oklahoma’s citizens.

(E) A more complete electric reliability assessment is needed for Oklahoma and the 

surrounding region.

Comment: EPA has yet to provide an appropriate electric reliability assessment for the CSAPR 

and EPA's other rulemaking initiatives for the electric power sector. Requiring compliance with 

the Supplemental Proposal by May 2012 without a more complete assessment of reliability

would create an unacceptable risk, especially if 2012 brings weather patterns similar to those 

experienced in Oklahoma this year. Commenters’ generating resources are currently operating at 

maximum capacity to meet consumer demands during a record-breaking heat wave. A more 

complete reliability assessment is critically important to evaluate whether Oklahoma EGUs 

could meet these kinds of demands if curtailments were required as a result of EPA rules.

According to the Federal Electric Reliability Commission ("FERC"), "the appropriate vehicles 

for addressing the impact on electric reliability of the EPA rules in detail are the planning 

processes used by utilities to identify and plan for the infrastructure and resources they will need 

to meet future needs." The processes FERC is referring to are implemented by regional planning 

authorities, including the Southwest Power Pool ("SPP") for the States of Arkansas, Kansas, 

 

4 Testimony of Chairman Jon Wellinghoff, Federal Energy Regulatory Commission, Before the House 

Subcommittee on Energy and Power of the Committee on Energy and Commerce United States House of 

Representatives, September 14, 2011.
68

Louisiana, Mississippi, Missouri, Nebraska, New Mexico, Oklahoma, and Texas. EPA should 

coordinate with FERC and the SPP to prepare a more complete electric reliability assessment for 

the implementation of CSAPR and other major EPA rulemakings in Oklahoma.

In response to comments submitted on the final CSAPR, EPA claims that it has "been in contact" 

with many of the regional planning authorities concerning the impact of CSAPR on electric 

reliability. EPA does not elaborate on its consultations with the SPP or other regional authorities, 

but instead relies on the fact that regional authorities "have not filed comments or expressed 

concerns over reliability in the record for this rule. . . . EPA's response misses the point. 

Numerous entities have expressed concern over the lack of a complete assessment of electric 

reliability impacts from EPA rules, especially during the early years of CSAPR. The way to 

obtain a complete assessment is for EPA to prepare one in consultation with FERC and the 

regional authorities. It is not sufficient for EPA to point to a lack of comments from these entities 

in the official record.

Rather than performing a complete reliability assessment, EPA claims that the flexibility allowed 

by an interstate trading program structure will inherently promote electric reliability, and that 

"basic reliability requirements are already incorporated into the analysis" of its IPM. With 

respect to the structure of CSAPR, allowance trading alone will not ensure electric reliability in 

Oklahoma during the initial phase of the CSAPR for the reasons discussed previously in 

commenters’ letters. Rather, unit curtailments are possible on a scale that could impact electric 

reliability, if sufficient replacement power is not available for purchase and transmission into and 

within the State. Commenters are concerned that the IPM does not sufficiently account for 

restrictions on purchase power availability and transmission capabilities.

In particular, the IPM sets certain limits on the ability to transfer power between model regions 

using the bulk power transmission system. One of the commenters recently performed a Linear 

First Contingency Incremental Transfer Capability Single Transfer Analysis to determine the 

deliverability of a resource in another region and found that the capacity from that resource was 

not deliverable, even though the capacity studied was less than the Joint Capacity and Energy 

Limit used by the IPM. Furthermore, the IPM's inter-regional limits were determined from the 

2004 NERC Reliability Assessments, which were performed at a time when energy sales in 

Oklahoma were 7% less than in 2010.

The IPM also assumes that, within each model region, "adequate transmission capacity exists to 

deliver any resources located in, or transferred to, the region. . . This is a major limitation on the 

model's ability to accurately evaluate impacts on electric reliability in Oklahoma from major 

federal rules like the CSAPR. While the IPM can determine that a given region could meet 

reserve requirements with imported resources, it performs no assessment of the reliable delivery

of the needed capacity. Regarding the legacy systems of its members in the 2010 State of the 

Market Report, the SPP stated that "[w]hile these systems may be functionally sufficient for their 

respective areas, they may not be sufficient for macro transfers across the region." Also, of the 

20 most congested flowgates identified by the SPP in the July 2011 Monthly State of the Market 

Report, 18 were within the SPP region as designated in the IPM.
69

EPA should consider that purchasing replacement power of this magnitude may require OG&E 

to go through a competitive procurement bid process pursuant to the Oklahoma Corporation 

Commission ("OCC") electric utility rules and also may require OCC approval. Depending on 

the complexity of the issues involved and the timelines prescribed by OCC rules, this process 

could require one year or more to complete, which could frustrate commenters' ability to arrange 

for replacement power if needed during the 2012 ozone season. Commenters are also concerned 

that an increase in demand for purchase power of this magnitude could impact the electricity 

prices during 2012.

Finally, the IPM does not substitute for an operational study of the generation capacity that 

would be available in the SPP during the ozone season if the Supplemental Proposal is finalized. 

The assumptions made in the IPM tend to overestimate unit availability, and commenters are 

concerned that EPA has not adequately evaluated how the Supplemental Proposal would impact 

the ability to meet peak loads on a month-to-month basis during the summer time. In addition, 

while it is theoretically possible that generation capacity might be available within the region, it 

is also necessary to consider potential limitations in gas supply and transportation deliverability 

to ensure that fuel switching from coal to natural gas can be accomplished, along with the costs.

These are select examples of commenters’ concerns about the IPM as a means of evaluating 

electric reliability for the Supplemental Proposal, especially during the 2012 ozone season. More 

time is needed to review the model's assumptions and incorporate additional considerations 

related to generation capacity and transmission in the SPP. It will not be possible to prepare a 

sufficient assessment in time for compliance by May 2012. Furthermore, requiring compliance 

by that date without an appropriate assessment would create an unacceptable risk to electric 

reliability.

Commenter AES Shady Point raises some of the same concerns in its comments. [Oklahoma 

Gas & Electric Company (OGE) (EPA-HQ-OAR-2009-0491-4590), p. 11-13; Oklahoma Utility

Group (EPA-HQ-OAR-2009-0491-4591), p. 8-10; AES Shady Point (EPA-HQ-OAR-2009-

0491-4595), p. 6-7.]

RESPONSE: As the commenters note in quoting FERC, utility planning processes are the 

appropriate vehicle for addressing the impact on reliability of EPA rules. EPA has been 

working with RTOs, utilities, state commissions, and other appropriate entities in developing this 

rule, and others, and will continue working with these agencies as the rules are finalized and 

implemented. EPA considers all rules that are in effect when it evaluates each proposal, so that 

the cumulative impact of rules are evaluated as they are put into effect. EPA evaluates all 

comments that are filed on each proposed rule in finalizing the rule. 

EPA believes the limitations on inter-regional power transfers used in IPM are appropriate; these 

limits are evaluated and modified when information is provided that is sufficient to update these 

limits. Broad references, such as those in these comments, do not provide sufficient information 

to update these limits. Although the commenters’ information that sales in Oklahoma are 7% 

higher today than they were in 2010 is relevant to the determination of resource adequacy, IPM 

already captures these impacts through its use of reserve margin requirements.
70

EPA believes commenters are wrong to dismiss the flexibility of the rule and then claim 

reliability problems. The rule’s inherent flexibility permits all utilities many alternatives to 

comply with the requirements of the rule: to purchase allowances from the market, to choose the 

best units to dispatch, to change fuel supply, or to import power from other regions. These 

comments provide no substantive reasons why these alternatives – either singly or in 

combination – are not viable ways of meeting the rule’s requirements.

With respect to comments on the operational limitation of the IPM model, IPM is not intended to 

be a model of operating capability within a region, nor does it need to be for the purposes used in 

developing the rule. IPM is an economic model of the operation of the overall power system in 

the lower 48 states; it projects generation and emissions in each region to meet electricity

demand using engineering, environmental, and economic information on generating units and 

information on the inter-regional transmission grid. The rule does not set operating requirements 

on individual units and provides operators of units the flexibility to choose how units should be 

operated. IPM models the loads in each region using a load curve that represents the amount of 

load that must be served at each load level; load levels are designed to reflect key operational 

peak, intermediate, and baseload conditions, thus capturing differing monthly load levels where 

these are important for operation of the system. The model also contains a detailed 

representation of the natural gas pipeline system, and incorporated the cost of increased supply 

of natural gas and additional pipeline capacity in deciding whether fuel switching is the best 

economic choice. EPA has developed a balanced set of data on unit availabilities to accurately 

represent plant availabilities in the IPM modeling: coal unit availabilities are based on historical 

data used by the Energy Information Administration, and other availabilities for other types of 

units are based on the GADS data (see IPM Documentation in the docket to this rulemaking).

5.2 Statutory and Executive Order Reviews (e.g., ICR)

(A) Commenter questions how the health benefits of this rule were determined.

Comment: How does EPA justify/calculate the numerous health benefits to this rule? Limiting 

emissions from any source will of course provide health benefits; however, the numbers being 

issued with this rule seem to have no basis in fact. They appear to be based on estimations such 

as number of cases, severity of cases, and costs associated with treatment. Using those 

estimations to build a case to justify the action does not seem fair to the States that will pay the 

actual costs for estimated benefits. [Oklahoma Municipal Power Authority (OMPA) (EPA-HQOAR-2009-0491-4573), p. 2.]

RESPONSE: The comment is outside the scope of the SNPR because it addresses issues that 

were within the scope of the request for comments in the proposed Transport Rule but not in the 

SNPR. While EPA is not reconsidering or reopening the issue, we note that the issue was 

previously addressed in section VIII.C of the preamble for the final Transport Rule and in 

chapter 5 of the final Transport Rule Regulatory Impact Analysis, in the docket for this 

rulemaking.
71

(B) Rule does not take into consideration inability of independent power 

producers to recover compliance costs.

Comment: Additionally and most importantly, the FIP does not take into consideration that the 

AES Shady Point facility, as a contracted independent power producer under long term contracts, 

does not currently have mechanisms in place to recoup the implementation costs of this rule. 

This lack of a cost sharing mechanism unfairly penalizes independent power producers, and 

thereby jeopardizing facility profitability, economic viability, regional grid stability, and 

employment of 90 workers, not including trickling economic impacts. [AES Shady Point (EPAHQ-OAR-2009-0491-4580), p. 1-2.]

RESPONSE: The comment is outside the scope of the SNPR because it addresses issues that 

were within the scope of the request for comments in the proposed Transport Rule but not in the 

SNPR. While EPA is not reconsidering or reopening the issue, we note that the issue was 

previously addressed in the under the subject of long term contracts in the final Transport Rule 

RTC. See section V.D.2.a., Applicability/Opt-in Units in the Transport Rule Primary Response 

to Comments for more details.

(C) Commenter questions finding of no significant or unique impacts on small 

governments.

Comment: BPU questions EPA's finding that "[n]either the final Transport Rule nor the 

provisions in this SNPR have regulatory requirements that might significantly or uniquely affect 

small governments." 76 FR at 40669/1. BPU, an administrative agency of the Unified 

Government of Wyandotte County/Kansas City, Kansas, operates an electric utility on a not-forprofit basis for the benefit of approximately 65,000 residential, commercial, and industrial 

customers in Wyandotte County/Kansas City, Kansas. The final Transport Rule and the SNPR 

will significantly affect BPU by requiring it to spend substantial sums of money to comply with 

these rules. Raising those amounts through bonds, as BPU must do, places additional burdens on 

the regulatory and political process. Moreover, the final Transport Rule and the SNPR require 

instantaneous results in comparison to the amount of time needed to obtain bond financing thus 

significantly affecting the ability of a small government to timely react to such requirements 

without facing the possibility of enforcement of the new rules against BPU. Finally, any

increased costs related to new emission controls required by the rule will strain the finances of all 

BPU's customers, which include the county, the city and their citizens. [Kansas City Board of 

Public Utilities (EPA-HQ-OAR-2009-0491-4585), p. 4-5.]

RESPONSE: As already stated, EPA believes that no unfunded mandates have been created by

the Transport Rule program inclusive of this supplemental rule. This comment does not provide 

evidence to demonstrate that this rule uniquely affects small governments or that the magnitude 

of the impact should be considered “significant.” EPA has not changed its finding based on the 

fact that most of the costs are to be incurred by the private sector. In the economic analysis for 

this rule, EPA’s projected impacts on electricity prices are small—around 1% on average 

nationwide. See Chapter 8 of the RIA for more on economic impacts.
72

(D) The cost of compliance creates a substantial burden upon consumers and may affect 

the availability of electricity and the reliability of transmission within the region.

Comment: The Attorney General is concerned about the cost of compliance for utilities within 

Oklahoma and the effect those costs will have on consumers when they are inevitably transferred 

to ratepayers. The cost of compliance for just the two largest electric utilities in Oklahoma is 

estimated to be approximately $150 million. Those costs, when combined with the substantial 

costs of compliance with other EPA mandates and proposed rules create an unprecedented 

burden upon the electric energy consumers of Oklahoma. The EPA should be mindful of the fact 

that electricity consumers are not only paying the cost of compliance with its rules, they are also 

responsible for additional costs mandated by other entities for transmission development, 

demand-side management and energy efficiency programs, renewable energy programs, etc. 

[Oklahoma Attorney General (EPA-HQ-OAR-2009-0491-4592), p. 2.]

RESPONSE: EPA’s projected impacts on electricity prices are small—around 1% on average 

nationwide. These are the incremental rate increases attributable to compliance with the 

Transport Rule. The total retail electricity prices forecasted by EPA do take into account nonTransport Rule variables such as those cited above. EPA appreciates the comment and believes 

its modeling exemplifies its awareness of the millions of variables factored into electricity prices. 

See Chapter 8 of the RIA in the docket of this rulemaking for more on economic impacts.

(E) Commenter believes that EPA has failed to consider costs and impacts properly n 

applying the rule to Iowa.

Comment: The 2012 and 2014 base case modeling runs conducted to determine, among other 

things, NOX emissions in Iowa and their purported interference with the maintenance of the 1997 

8-hour ozone standard in Allegan County, Michigan utilized NOX values from IPM that did not 

account for the Utility HAPs MACT or the Boiler MACT, both of which will serve to lower 

emissions nationwide through the installation of controls or shutdown of facilities. Utilization of 

old base case data that fails to consider the real emission reductions achieved by the CAIR (as 

discussed above) and the emission reductions that will be achieved by the MACT standards, 

MEC does not believe EPA has, in this instance, achieved the requirements of Executive Order 

13563 of January 18, 2011, to “tailor its regulations to impose the least burden on society, 

consistent with obtaining regulatory objectives, taking into account, among other things, and to 

the extent practicable, the costs of cumulative regulations” in requiring ozone season NOX

reductions from Iowa sources. [MidAmerican Energy Company (EPA-HQ-OAR-2009-0491-

4597), p. 4.]

RESPONSE: The comment is outside the scope of the SNPR because it addresses issues that 

were within the scope of the request for comments in the proposed Transport Rule but not in the 

SNPR. While EPA is not reconsidering or reopening the issue, we note that the issue regarding 

the baseline was previously addressed in the preamble to the final Transport Rule, section VI. 

Also see the Regulatory Impact Assessment for the final Transport Rule in the docket to this 

rulemaking.
73

Comment: EPA is quick to point out that since Iowa and other states subject to the supplemental 

notice provisions are already subject to other requirements to reduce NOX emissions under the 

final Transport Rule, there are, effectively, no additional costs to comply with the ozone season 

requirements. EPA’s proposed allocation of seasonal NOX allowances is insufficient to cover 

Iowa’s compliance burdens without additional controls, leaving Iowa sources with a choice to 

spend money on controls or in the purchase of allowances. Further, there are incremental 

administrative costs associated with maintaining compliance under the ozone season NOX

reduction requirements, both from a reporting and allowance management perspective. EPA’s 

analysis fails to account for these incremental costs (as it does for the so-called “sunk costs” 

associated with compliance with the legally enforceable requirements of CAIR); MEC believes 

that the EPA should be required to inform the public in general, and MEC’s customers, of the 

full costs associated with reducing emissions in Michigan at an ozone monitoring station that 

indicates the county is in attainment of the standard. [MidAmerican Energy Company (EPAHQ-OAR-2009-0491-4597), p. 4-5.]

RESPONSE: While EPA is not reconsidering or reopening the issue, we note that the issue 

regarding the treatment of CAIR was previously addressed in section V.B of the preamble of 

Federal Implementation Plans: Interstate Transport of Fine Particulate Matter and Ozone and 

Correction of SIP Approvals (EPA–HQ–OAR–2009–0491) and Transport Rule Primary

Response to Comments (EPA-HQ-OAR-2009-0491-4513) Section IV.A. In regards to the 

assertion that Iowa will need to install additional controls or purchase additional allowances, the 

commenter has not provided significant evidence of that. For instance, the 2010 ozone-season 

emissions in Iowa were 17,179 tons; the preliminary 2011 emissions for ozone-season NOX in 

Iowa are 17,179 tons, and their 2012 budget is 16,532 tons. If Iowa continues to lower emissions 

at the rate it has been, its 2012 emissions will be well below its 2012 budget (meaning the state 

will likely have a surplus of allowances, not a shortage). EPA does not anticipate any additional 

controls or allowance purchase for the state. In fact, EPA modeling projects the state to be a 

seller of allowances in 2012. As for the incremental cost of operating controls that would not 

otherwise operate in the base case, that type of cost is captured in EPA’s analysis. Additionally, 

the $1.6 billion in capital cost already sunk into controls for CAIR is also cited in EPA’s rollout 

of the final Transport Rule. In regards to any administrative or reporting cost, these are not 

reflected in the model, as they are negligible.

(F) EPA’s cost thresholds do not support retrofit environmental controls.

Comment: EPA's analysis suggests that additional combustion controls can be added to many 

units within Oklahoma in 2012 at or below the cost effective threshold of $500/ton of seasonal 

NOX. However, based on the data contained within the IPM v4.10 documentation and the 

NEEDs input file, the cost of some of the projected controls exceeds the cost-effective threshold. 

As an example, Northeastern unit 3 is projected to change from a NOX rate of 0.382 lb/MMBtu 

in the base case to a NOX rate 0.251 lb/MMBtu in the policy case. According to EPA 

documentation this project would cost almost $13 million and remove approximately 860 tons of 

NOX per year. Using the retrofit capital charge rate of 11.3%, this project would effectively cost 

more than $1,600 per ton, before even consideration of O&M impacts. Therefore, it is unclear 

why this project would be selected in the policy case. There appears to be a fundamental 
74

discrepancy with the IPM model logic surrounding control cost-effectiveness. [Public Service 

Company of Oklahoma (EPA-HQ-OAR-2009-0491-4600), p. 4.]

RESPONSE: The commenter does not provide its underlying calculations for the $13 million in 

capital cost referenced in the comment. EPA’s calculations reveal a much smaller number for 

total capital cost and $/ton figures. It appears that the commenter may have erred by reflecting 

the total capital cost of “LNC3” controls in its assessment. However, the only cost incurred to 

achieve incremental tonnage reductions noted above are the incremental cost of upgrading 

combustion controls from LNC1 to LNC3 figures. Table 5-5 of EPA’s IPMv4.10 documentation 

provides the capital cost and scaling factor assumption necessary to calculate the upgrade cost at 

this particular unit. Therefore, EPA believes that the reductions can be made cost-effectively and 

that the commenter has misinterpreted EPA data in forming its capital cost projection. EPA 

believes that the capital costs postulated by the commenter are drastically overstated. However, 

even if one were to assume that all the commenter’s calculations are correct, their observation 

should be of no surprise. The EPA remedy modeling that the commenter is referencing projects 

an ozone season allowance price that exceeds $1600/ton in future years, which would make the 

upgrade decision for the Northeastern 3 unit economic even at the conservative parameters 

assumed in the comment. Finally, the commenter assumes that the emissions avoided are 860 

tons annually (as shown in 2012). However, this does not take into account the ability of the unit 

to increase utilization in future years and thus generate even more emission reductions thereby

further lowering the $/ton cost of the control upgrade. Finally, in this IPM remedy scenario, the 

state emissions are less than the budget. That is, EPA does not assume that this control is part of 

necessary emission reductions to reach the budget level, but rather part of a strategy that allows 

the state to outperform its budget (emit less than its budget). There are no source specific 

requirements that the unit install any controls under Transport Rule. Moreover, in this 

rulemaking, EPA has removed any such assumption that these controls are installed in 2012 in 

Oklahoma. 

5.3 Miscellaneous Issues

(A) Several commenters claimed that EPA has not provided a valid opportunity for public 

review and comment of the supplemental proposal. [Note: RESPONSE at end of this set of 

comments]

Comment: Commenters who submitted follow-up comments had earlier submitted requests for 

an extension of time to submit comments based on the size of the rulemaking record and the late 

date by which the input and output files were provided for CAMx modeling used to support the 

Supplementary Proposal. [AES Shady Point (EPA-HQ-OAR-2009-0491-4578), Oklahoma Gas 

& Electric Company (EPA-HQ-OAR-2009-0491-4577), Westar Energy (EPA-HQ-OAR-2009-

0491-4575).]

Comment: For the reasons set forth in earlier extension request letters, commenters request that 

EPA extend the applicable comment period to provide sufficient time for commenter to 

thoroughly review and further inform its comments on this important proposal. The need for 

additional time is especially compelling for Oklahoma sources. As mentioned above, Oklahoma 

was not previously included in CAIR, and whether or not Oklahoma would be included in any
75

interstate transport rule, and the basis for such inclusion, has been a moving target. EPA included 

Oklahoma in its 2010 Proposed Transport Rule on the basis that sources within the State 

contributed to nonattainment with NAAQS in Tarrant County, Texas, with those allowances and 

actual emissions not requiring that any control equipment be installed. EPA now proposes to 

include Oklahoma based on modeled impacts in Allegan County, Michigan, and also proposes to 

require a nearly 40% reduction in emissions in a six month period.

Oklahoma's purported connection to Allegan County, Michigan is based on new modeling data. 

The CAMx input and output files for this modeling were not available online like other technical 

support documents, and it took more than a week to receive the 8 TB of data once requested. 

Additionally, it can take weeks to re-run the same CAMx model runs that EPA completed in 

support of the CSAPR and the 42 day comment period is not enough time to allow a thorough 

review. Given the nature of this data and the tenuous link between Oklahoma and Allegan 

County purportedly established by it, it is important that commenters be provided additional time 

in which to conduct an in-depth analysis of the methodology used by EPA as the basis for 

including Oklahoma in the Supplemental Proposal. The 42 days that EPA allows for public 

comment is not enough.

Furthermore, the comment period allowed by EPA is inconsistent with Executive Order 13563, 

which was signed by the President on January 18, 2011, as well as with other recent rulemakings 

by EPA. Executive Order 13563 (Improving Regulation and Regulatory Review), provides that in 

order to facilitate public participation in the regulatory process, "each agency shall afford the 

public a meaningful opportunity to comment ... with a comment period that should generally be 

at least 60 days." Although EPA followed this mandate in other rulemakings that also required 

time-intensive review, such as the 2010 Proposed Transport Rule and the Utility MACT, EPA 

inexplicably fails to do the same here. Commenters request that EPA reconsider its August 19, 

2011 decision not to extend the comment period for the Supplemental Proposal.

Commenter AES Shady Point raises some of the same concerns in its comments. [Oklahoma 

Gas & Electric Company (OGE) (EPA-HQ-OAR-2009-0491-4590), p. 13; Oklahoma Utility

Group (EPA-HQ-OAR-2009-0491-4591), p. 10-11; AES Shady Point (EPA-HQ-OAR-2009-

0491-4595), p. 7.]

Comment: EPA has failed to provide an adequate notice and opportunity for public comment on 

the Proposal. The Administrative Procedures Act ("APA") requires the EPA to provide notice of 

a proposed rulemaking "adequate to afford interested parties a reasonable opportunity to 

participate in the rulemaking process." Florida Power & Light Co. v. United States, 846 F.2d 

765, 771 (D.C.Cir. 1988); SENATE JUDICIARY COMMITTEE, ADMINISTRATIVE 

PROCEDURE ACT, S. REP., No. 752, 77th Cong., 1st Sess. 14 (1945) ("Agency notice must be 

sufficient to fairly apprise interested parties of the issues involved, so that they may present 

responsive data or argument relating thereto."). This requirement serves both (1) "to reintroduce 

public participation and fairness to affected parties after governmental authority has been 

delegated to unrepresentative agencies"; and (2) to assure that the "agency will have before it the 

facts and information relevant to a particular administrative problem." National Ass'n of Home 

Health Agencies v. Schweiker, 690 F.2d 932, 949 (D.C. Cir. 1982); see also, MCI 
76

Telecommunications Corp. v. FCC, 57 F.3d 1136, 1141 (D.C. Cir. 1995) (same). The Proposal 

does not provide potentially affected parties with sufficient opportunity to understand and 

respond to the data and highly technical modeling utilized by EPA and, thus, does not satisfy the 

notice and comment requirements of the APA.

The Proposal does not provide affected source with sufficient notice and opportunity to 

comment. The Proposal is just eight pages long and does not have its own technical support 

documents. EPA directs sources to the preamble and the technical support documents associated 

with CSAPR See 76 Fed. Reg. at 40,666. Sources affected by the Proposal do not have a similar 

short-cut available for parsing through the relevant information and developing responsive data 

and arguments. CSAPR covers 27 states and establishes four different trading programs. The 

amount of information underlying the rule is voluminous. The CSAPR preamble is 146 pages 

long and has over 147 technical support documents. EPA has made no effort to organize the 

CSAPR materials in a way that clearly identifies information relevant to the Proposal. 

Additionally, the Proposal itself lacks any meaningful explanation of EPA's significant 

contribution analyses, state emissions budget determination, or allowance allocation calculation. 

EPA's cursory treatment of the Proposal undermines "the values of public participation, fairness, 

and informed agency decision making that the notice-and-comment process is designed to 

foster." City of Idaho Falls v. FERC, 629 F.3d 222,229 (D.C. Cir. 2011).

The comment period for the Proposal is too short for affected sources and states to verify the 

accuracy of the data and analyses relied on by EPA. To develop meaningful comments on the 

Proposal, affected sources faced the daunting tasks of (1) locating and verifying the data EPA 

attributes to their EGUs; (2) understanding the complicated methodology used by EPA to 

determine unit-specific emissions allowances; (3) determining whether EPA correctly calculated 

the number of allowances to be allocated to their EGUs; (4) understanding the complicated 

methodology used by EPA to calculate state emissions budgets; (5) locating all the relevant 

information for EGUs in the state of interest and determining whether EPA correctly calculated 

the state emissions budget; and (6) understanding the highly technical model used by EPA to 

determine that the state of interest significantly contributes to downwind pollution. Even with the 

assistance of expert consultants, it is impossible to complete all analyses necessary to fully

address the Proposal in the 43-day comment period.

EPA's failure to provide a reasonable comment period is inconsistent with Executive Order 

13563. The order requires EPA to "afford the public a meaningful opportunity to comment" on 

proposed rules, "with a comment period that should generally be at least 60 days." 7'6 Fed. Reg. 

3,821 (Jan. 21, 2011). EPA has had nearly three years since the decision in North Carolina to 

develop the Proposal. It expects the general- public and affected sources, which are far less 

equipped than EPA to conduct technical analyses and air quality modeling, to develop comments 

in just 43 days. Given the scope of the technical analysis required, that timeframe is clearly 

insufficient and not in accordance with the mandate of Executive Order 13563 to allow for 

meaningful public comment. [Western Farmers Electric Cooperative (EPA-HQ-OAR-2009-

0491-4589), p. 12-13.]
77

Comment: EPA set a 30-day comment period ending August 22, 2011. Despite EPA's efforts to 

post everything related to this rule on the EPA website, key decisions and assumptions made in 

the rulemaking, particularly changes from proposed to final, have not been readily accessible. 

Although the emissions data are available in the docket, the modeling input and output files are 

not. As late as a month after signing the rule, information is still being posted to the website. The 

technical and supporting documentation for the final and proposed rules is over 132,000 pages. 

Parsing how and why Kansas fits into the proposed rule has been an extremely difficult task for 

KDHE staff. In the proposed rule, Kansas is linked only to maintenance of the ozone standard in 

Allegan County, Michigan. The proposed rule is the first opportunity for KDHE to review the 

technical information supporting Kansas' significant contribution to Allegan County. A complete 

analysis of these data will take more time than the current comment period allows. KDHE 

requests an extension of time to file a more complete set of comments from the currently set date 

of August 22, 2011 to October 1, 2011. [Kansas Department of Health & Environment (EPAHQ-OAR-2009-0491-4582), p. 1-2.]

RESPONSE: EPA disagrees with the commenters for the following reasons. Section 307(d)(5) 

of the CAA requires the Administrator to give an opportunity for written or oral comments. The 

Act does not specify the length of time, other than the record must be open 30 days after holding 

public hearings - with which EPA has complied. There was no request for a public hearing on 

the Supplemental Notice of Proposed Rulemaking (SNPR).

EPA posted the signed version of the Proposed Transport Rule to the web when it was signed on 

July 6, 2010. The proposal was published in the Federal Register on August 2, 2010, and the 

public comment period closed on October 1, 2010. This provided a 60 day comment period (and 

also provided 90 days of public notice from the date posted to the web).

EPA posted the signed version of the first Transport Rule Notice of Data Availability (NODA) 

addressing its power sector model (IPM) to the web when it was signed on August 25, 2010.

The first NODA was published in the Federal Register on September 1, 2010, and the public 

comment period closed on October 15, 2010. This provided a 45 day comment period (or 52 

days from the date posted to the web). EPA posted the signed version of the second Transport 

Rule NODA (addressing emissions inventories) to the web when it was published in the Federal 

Register on October 27, 2010. The public comment period closed on November 26, 2010, which 

provided a 30 day comment period. EPA posted the signed version of the third Transport Rule 

NODA (allocations and related matters) to the web when it was signed on December 30, 2010.

The third NODA was published in the Federal Register on January 7, 2011. The public comment 

period closed on February 7, 2011, which provided a 30 day comment period (or 38 days from 

the date posted to the web). EPA posted the signed version of the Supplemental Notice of 

Proposed Rulemaking to the web when it was signed on July 6, 2011. The SNPR was published 

in the Federal Register on July 11, 2011. The public comment period closed on August 22, 

2011, which provided a 6 week comment period from publication in the Federal Register (and 47 

days from availability of the proposal on the web).
78

Given the timeframe EPA provided to the public for submission of comments, and indicative of 

the fact that the Agency received several thousand substantive comments, commenters did, in 

fact, have a reasonable opportunity to submit their comments for consideration.

A. Commenter states broadly that for all of the various reasons in the comments, EPA has 

acted arbitrarily and capriciously in the rulemaking as it affects Oklahoma.

Comment: While DEQ is in support of reducing NOX emissions in Oklahoma, it is our belief 

that the implementation of this rule in this manner undermines the credibility of the EPA and that 

this particular rulemaking has crossed the line between prudent rulemaking and practices that can 

only be characterized as arbitrary and capricious. We believe that the best way forward would be 

for the EPA to remove the State of Oklahoma from the states included in the CSAPR.

DEQ wishes to express its support for emission reductions in the state of Oklahoma. 

Unfortunately, it appears that compliance with the heavily reduced emission budget and the tight 

timeline will be extremely difficult, if not impossible for Oklahoma utilities. EPA has acted in a 

manner that is arbitrary and capricious in: (1) changing the methodology used to set state 

allowance budgets without allowing public comment, (2) failing to make those procedures clear 

and unambiguous in a timely manner, and (3) delaying the final rulemaking which will set state 

ozone-season budgets for the six states (including Oklahoma) covered by the Supplemental 

Notice of Proposed Rulemaking (SNPR). This is particularly burdensome for utilities operating 

units located in the state of Oklahoma. In fact, Oklahoma is the only state covered by the SNPR 

that has no requirements whatsoever in the CSAPR as finalized on August 8, 2011. EPA’s 

actions have jeopardized the market-based benefits of the rule by failing to issue clear and 

unambiguous signals regarding the allowances that will be allocated on a unit-by-unit basis and 

by holding the potentially subject units hostage to another proposed rulemaking. As of the date 

these comments were prepared (August 22, 2011), utilities operating units located in Oklahoma 

do not know whether those units will be subject to the rule at all and, if they are subject, how 

many allowances each unit will be issued for the 2012 ozone season beginning in May of that 

year.

After the issuance of the proposed rule in 2010, many Oklahoma utilities pointed out 

inconsistencies in the IPM assumptions and problems with specific allocations, but, in general, 

the utilities expected to be able to comply with the rule. All of these assumptions were upended 

this summer and, based on the changes between 2010 and 2011, it would be imprudent for the 

utilities to assume consistency between the SNPR and whatever will be included in the rule when 

it is finalized this fall. We believe that the best way to remedy these problems would be for the 

EPA to remove the State of Oklahoma from this version of the CSAPR altogether. We 

acknowledge that we may well need to be included in a future extension of CSAPR in a future 

rulemaking. If and when that occurs, it is essential that EPA provide sufficient time between the 

publication of the final rule and the beginning of the compliance period to allow utilities 

operating subject units to adapt to the new requirements. By failing to provide that time, EPA 

undercuts its credibility and makes it more difficult for states to defend rules which, if 

implemented properly, would provide substantial benefits to our citizens. 
79

DEQ respectfully requests that EPA exclude Oklahoma from the rule altogether, but requests that 

at the very least, EPA increase the state ozone-season NOX allowance budget by 1,500 tons and 

that the compliance date for units operating in Oklahoma be pushed back to the 2015 ozone 

season. [Oklahoma Department of Environmental Quality (EPA-HQ-OAR-2009-0491-4593), p. 

5-7.]

RESPONSE: EPA disagrees with the commenter for the following reasons. Section 307(d)(5) 

of the CAA requires the Administrator to give an opportunity for written or oral comments. The 

Act does not specify the length of time, other than the record must be open 30 days after holding 

public hearings - with which EPA has complied. There was no request for a public hearing on 

the Supplemental Notice of Proposed Rulemaking (SNPR).

EPA posted the signed version of the Proposed Transport Rule to the web when it was signed on 

July 6, 2010. The proposal was published in the Federal Register on August 2, 2010, and the 

public comment period closed on October 1, 2010. This provided a 60 day comment period (and 

also provided 90 days of public notice from the date posted to the web).

EPA posted the signed version of the first Transport Rule Notice of Data Availability (NODA) 

addressing its power sector model (IPM) to the web when it was signed on August 25, 2010.

The first NODA was published in the Federal Register on September 1, 2010, and the public 

comment period closed on October 15, 2010. This provided a 45 day comment period (or 52 

days from the date posted to the web). EPA posted the signed version of the second Transport 

Rule NODA (addressing emissions inventories) to the web when it was published in the Federal 

Register on October 27, 2010. The public comment period closed on November 26, 2010, which 

provided a 30 day comment period. EPA posted the signed version of the third Transport Rule 

NODA (allocations and related matters) to the web when it was signed on December 30, 2010.

The third NODA was published in the Federal Register on January 7, 2011. The public comment 

period closed on February 7, 2011, which provided a 30 day comment period (or 38 days from 

the date posted to the web). EPA posted the signed version of the Supplemental Notice of 

Proposed Rulemaking to the web when it was signed on July 6, 2011. The SNPR was published 

in the Federal Register on July 11, 2011. The public comment period closed on August 22, 

2011, which provided a 6 week comment period from publication in the Federal Register (and 47 

days from availability of the proposal on the web).

Given the timeframe EPA provided to the public for submission of comments, and indicative of 

the fact that the Agency received several thousand substantive comments, commenters did, in 

fact, have a reasonable opportunity to submit their comments for consideration.

See section III.B.iv of the preamble to this final rule regarding the Oklahoma budget. EPA has 

considered the comment concerns with respect to the compliance schedule. In the final rule, 

EPA is setting the Oklahoma 2012 ozone season NOX budget at a level that reflects emission 

reductions achievable through actions (such as changes in generation unit dispatch) that do not 

include additional LNB installations. EPA is setting the Oklahoma ozone season NOX budget 

for 2013 and beyond at the level that was proposed, i.e., to reflect NOX levels achievable with 
80

additional LNB installations that can be completed before the 2013 ozone season without 

necessitating the shutdown of units during the summer peak demand period in 2012. 

(C) EPA’s refusal to consider data is improper.

Comment: EPA’s supplemental notice of proposed rulemaking seeks to limit the scope of 

public input, nothing that: 

EPA is not taking comment on any aspect of the final Transport Rule, including any 

aspect of the methodology used to identify receptors for nonattainment; the methodology

used to identify receptors for maintenance; the methodology used to identify any specific 

state’s significant contribution and interference with maintenance; the methodologies 

used to establish state budgets, variability limits, and state assurance levels; or the 

methodologies used to allocate allowances to existing units, to establish new unit setasides and Indian country new unit set-asides, or to allocate allowances in these setasides. 

EPA’s refusal to take comment on these issues is premised on its theory that “EPA provided an 

adequate opportunity for public comment on all of these issues during the comment period for 

the proposed Transport Rule and during the comment periods for the associated Notices of Data 

Availability.” MEC respectfully disagrees that EPA has provided an adequate opportunity for 

public comment on the issue of the methodology used to identify receptors for maintenance. 

EPA’s previous proposal to include “all six states in at least one of the Transport Rule trading

programs” does not (and in this case, cannot) mean that entities impacted by this supplemental 

notice had the same opportunity to review the potential impacts at a receptor that EPA itself 

admits was not identified or included in the July 6, 2010, proposed rule. [MidAmerican Energy

Company (EPA-HQ-OAR-2009-0491-4597), p. 2.]

RESPONSE: EPA disagrees with the commenter for the following reasons. Section 307(d)(5) 

of the CAA requires the Administrator to give an opportunity for written or oral comments. The 

Act does not specify the length of time, other than the record must be open 30 days after holding 

public hearings - with which EPA has complied. There was no request for a public hearing on 

the Supplemental Notice of Proposed Rulemaking (SNPR).

EPA posted the signed version of the Proposed Transport Rule to the web when it was signed on 

July 6, 2010. The proposal was published in the Federal Register on August 2, 2010, and the 

public comment period closed on October 1, 2010. This provided a 60 day comment period (and 

also provided 90 days of public notice from the date posted to the web).

EPA posted the signed version of the first Transport Rule Notice of Data Availability (NODA) 

addressing its power sector model (IPM) to the web when it was signed on August 25, 2010.

The first NODA was published in the Federal Register on September 1, 2010, and the public 

comment period closed on October 15, 2010. This provided a 45 day comment period (or 52 

days from the date posted to the web). EPA posted the signed version of the second Transport 

Rule NODA (addressing emissions inventories) to the web when it was published in the Federal 
81

Register on October 27, 2010. The public comment period closed on November 26, 2010, which 

provided a 30 day comment period. EPA posted the signed version of the third Transport Rule 

NODA (allocations and related matters) to the web when it was signed on December 30, 2010.

The third NODA was published in the Federal Register on January 7, 2011. The public comment 

period closed on February 7, 2011, which provided a 30 day comment period (or 38 days from 

the date posted to the web). EPA posted the signed version of the Supplemental Notice of 

Proposed Rulemaking to the web when it was signed on July 6, 2011. The SNPR was published 

in the Federal Register on July 11, 2011. The public comment period closed on August 22, 

2011, which provided a 6 week comment period from publication in the Federal Register (and 47 

days from availability of the proposal on the web).

Given the timeframe EPA provided to the public for submission of comments, and indicative of 

the fact that the Agency received several thousand substantive comments, commenters did, in 

fact, have a reasonable opportunity to submit their comments for consideration.

6. Out of Scope Comments

1. Significant Contribution Methods

A. Commenter requests additional clarification on the data used to determine that Oklahoma is a 

significant contributor to downwind ozone nonattainment. 

1. How were the wind patterns developed? For example, there are numerous monitoring 

locations between Oklahoma and Michigan (including large metropolitan areas such as 

Kansas City and St. Louis). None of these monitors showed a significant contribution from 

Oklahoma. [Oklahoma Municipal Power Authority (OMPA) (EPA-HQ-OAR-2009-0491-

4573), p. 2.]

RESPONSE: The model meteorological estimates from MM-5 used as inputs for CAMx are 

described in EPA-HQ-OAR-2009-0491-4140, the "Air Quality Modeling Final Rule Technical 

Support Document." Furthermore, examining the state-by-state ozone contribution estimates 

from the 2012 base case air quality modeling for the final rule, Oklahoma clearly contributes at 

or above the 1% contribution threshold to a number of monitor-receptors in downwind states 

(e.g., Texas, Missouri, Indiana, Illinois, and Michigan) (see the “Contributions of 8-hour ozone, 

annual PM2.5, and 24-hour PM2.5 from each state to each monitoring site” excel workbook 

accessible on the EPA transport rule website for the contributions. This is part of EPA-HQOAR-2009-0491-4228 in the docket to this rule). However, with the exception of the Allegan, 

Michigan receptor, these monitors were modeled not to have nonattainment and/or maintenance 

issues. Thus, they were not further used to examine significant contribution and/or interference 

with maintenance in the Transport Rule.

Comment: Have there been any third party evaluations of the results of the CAMx model? The 

results of this model will subject the State of Oklahoma, cities within the state, and businesses to 

numerous requirements costing billions of dollars. The results of this model need to be verified. 

[Oklahoma Municipal Power Authority (OMPA) (EPA-HQ-OAR-2009-0491-4573), p. 2.]
82

RESPONSE: There have been a number of third party evaluations of CAMx model predictions. 

Several of these are listed below. Additional information on the development and use of CAMx 

can be found on the web site: www.camx.com.

(1) Tesche, T. W.; Morris, R.; Tonnesen, G.; McNally, D.; Boylan, J.; Brewer, P.,

CMAQ/CAMx annual 2002 performance evaluation over the eastern US. Atmospheric

Environment 2006, 40(26), 4906-4919.

(2) Hogrefe, G., Civeroio, K.L., Hao, W., Ku, J-Y., Zalewsky, E.E., and Sistla, G., Rethinking 

the Assessment of Photochemical Modeling Systems in Air Quality Planning Applications. Air 

& Waste Management Assoc., 58:1086-1099, 2008.

(3) Implementation of State-of-Science PM Modules into the PMCAMx Photochemical Grid 

Model.R.E. Morris, G. Yarwood, C. Emery, Spyros Pandis, and F. Lurmann. Presented at the 

96th Annual Conference and Exhibition of the A&WMA, San Diego, California (June 2003).

(4) Arunachalam, S. Peer Review of Source Apportionment Tools in CAMx and CMAQ, EP-D07-102. University of North Carolina, Institute for the Environment, August 2009.

2. Budget/Variability/Assurance Methods

No comments received on this issue.

3. Allocation Methods

No comments received on this issue.

4. Emission Inventories

A. Commenter asserts that the types of sources affected by the SNPR should be expanded 

so that the burden of precursor emissions reduction is more widely shared. 

1. The Midwest has numerous Title V stationary sources that rely on coal-generated heat for 

process boilers. Notable among these are grain handling and processing facilities, of which 

there are several in Iowa. For Iowa and other Midwestern states, the focus on fossil fuel-fired 

energy facilities is too narrow. One major source, a value-added grain products facility, is 

proposing to increase the stack height of a main stack in order to solve local problems. 

However, the NOX and volatile organics from this source will continue to blow downwind, 

barring upgrades to NOX controls under other rules and the current SIP call for Muscatine. 

[Iowa Environmental Council (EPA-HQ-OAR-2009-0491-4572), p. 2.]

RESPONSE: This issue is beyond the scope of the Supplemental rulemaking.

Although the cost curves presented in the Transport Rule only included EGU reductions, EPA 

also assessed the cost of NOX emission reductions available for source categories other than 

EGUs in the rulemaking. This assessment for the Transport Rule concluded that there are little 
83

or no reductions available from non-EGUs sources, such as those noted by the commenter, at

costs lower than the $500/ton threshold for NOX. 

5. Kansas Proposed SIP Call

No comments received on this issue.

6. Other Out of Scope Comments

A. Commenter expresses concern that the SNPR does not include Nebraska and South 

Dakota for ozone season NOX emissions. 

At the current 75 ppb standard, Iowa does not have any nonattainment areas for ozone, which is 

the primary driver for the rule and the Supplemental Action. However, a 65 ppb standard could 

mean nonattainment in several Iowa cities, and an even lower standard of 60 ppb would put 

much of the state in nonattainment. Clearly Iowa’s own upwind air shed plays a role in the 

State’s ozone levels, and these may become problematic when the new NAAQS standard comes 

into play—as it should, given the health benefits. [Iowa Environmental Council (EPA-HQ-OAR2009-0491-4572), p. 1-2.]

RESPONSE: The Transport Rule and the SNPR address ozone transport under the 1997 ozone 

standard. These comments regarding transport to areas at potential 60 or 65 ppb standards are 

thus beyond the scope of the rule.

B. Commenter expresses concern that the SNPR does not anticipate or address scenarios 

associated with a revised 8-hour NAAQS for ozone. 

1. EPA’s online materials (fact sheets, presentations) do not make mention of any scenarios 

under a revised eight-hour NAAQS. And yet these clearly are factors in determining ozone 

nonattainment. It is likely that many more downwind counties than the ones shown in the 

presentation at http://www.epa.gov/airtransport/pdfs/CSAPRPresentation.pdf will be affected 

by nonattainment designations once the NAAQS is changed. [Iowa Environmental Council 

(EPA-HQ-OAR-2009-0491-4572), p. 2.]

RESPONSE: The Transport Rule and the SNPR address ozone nonattainment and maintenance 

for the 1997 ozone standards. Because revised NAAQS are beyond the scope of this rulemaking, 

and because the levels of the NAAQS under these revisions are not yet known, it would not be 

appropriate to include consideration of them in our online materials for this rule. Other 

communications materials will address ozone attainment under subsequent standards. For 

example, EPA will be developing online materials for area designations under the 2008 ozone 

standard of 75 ppb. 

(C) EPA’s opportunity for comment should allow for changes in coverage in the other 

direction (adding states). 
84

(1) Finally, we note that EPA’s SNPR provides opportunity for comment for changes in 

coverage of the rule only in one direction. In particular, opportunity for comment is provided 

with respect to states linked to downwind monitors showing nonattainment and maintenance 

problems in the revised analysis for CSAPR that were not so linked in the prior analysis in the 

August 2010 proposed rule, but not for the reverse. That is, EPA has not provided an opportunity

for interested persons to challenge the removal of a state from the rule’s requirements as 

proposed last August on the grounds that the downwind monitors to which those states were then 

linked did not evidence nonattainment and maintenance problems in the revised CSAPR 

analysis. We believe that EPA should adopt an even-handed approach to changes in requirements 

of the rule resulting from revised analyses, both with respect to subjecting additional states to the 

rule and to removing states from coverage of the rule. While we are not requesting that EPA 

reopen this rulemaking solely to address this issue, we do request the Agency to consider this 

issue of fundamental fairness in future rulemakings (or in further iterations of this one). [Clean 

Air Task Force, et al. (EPA-HQ-OAR-2009-0491-4588), p. 3.]

RESPONSE: Comment noted and appreciated. EPA will take this comment into consideration 

in future rulemakings.