September 10, 2009

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Supporting Materials

LADCO Recommendations to EPA on a CAIR Replacement Rule

The purpose of this document is to review LADCO’s recommendations to EPA on a CAIR 

replacement rule, along with the rationale and any supporting materials.

Introduction

Section 110(a)(2)(D) requires SIPs to...

“... contain adequate provisions – (i) prohibiting...any source or other type of emissions 

activity within the State from emitting any air pollutant in amounts which will –

(I) contribute significantly to nonattainment in, or interfere with maintenance by, any 

other State with respect to any (NAAQS)..., or

(II) interfere with measures required to be included in the applicable implementation 

plan for any other State under part C to prevent significant deterioration of air quality 

or to protect visibility...”

In its decision, the U.S. Court of Appeals for the D.C. Circuit rejected EPA’s approach in CAIR in 

which it gave “interfere with maintenance” much the same meaning as “contribute significantly 

to nonattainment”. The Court discussed the problem of areas struggling to meet the National 

Ambient Air Quality Standards (NAAQS) – i.e., areas which “could fall back into nonattainment 

because of the historic variability” in their air quality levels. It is, therefore, necessary for EPA to 

independently address the “contribute significantly to nonattainment” and “interfere with 

measures” provisions of section 110(a)(2)(D).

To ease the administrative (and technical) burden, LADCO recommends that a necessary first 

step in addressing significant contribution and interference with maintenance is to identify the 

downwind areas of interest. (Note: LADCO’s recommended test is broad enough to consider 

“historic variability”, as instructed by the Court.) For those areas, a threshold level is proposed 

to determine which upwind states need to be considered for emission reductions. A 2-part, 

multi-sector process is then recommended to meet Clean Air Act requirements.

In summary, a 3-step approach is proposed to address the transport requirements of section 

110(a)(2)(D): 

(1) identify areas of interest; 

(2) identify upwind states which contribute significantly to nonattainment or interfere 

with maintenance in these areas, and 

(3) implement a multi-sector approach, as necessary, to provide an appropriate remedy 

to meet Clean Air Act requirements.
September 10, 2009

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Identifying Areas of Interest

LADCO Recommendation

A. While the requirements of Section 110(a)(2)(D) apply to all areas, most attention should be 

given to those areas not meeting or struggling to maintain the NAAQS. These "areas of 

interest" should be identified using monitoring and modeling data. 

:

B. Specifically, these are areas with both base monitored design values and future modeled 

design values above the applicable NAAQS should be designated as areas of interest. The 

monitored design values are based on the maximum design value from the periods 2003-

2005 through the most recent three-year period, and the future modeled values are based 

on future year modeling which reflects legally enforceable control measures and a 

conservative model attainment test - i.e., use of maximum design values rather than 

average design values.

1. The use of maximum design values and a conservative model attainment test are 

intended to account for historic variability, which is necessary to ensure maintenance. 

An alternative means of accounting for historic variability is to conduct a statistical 

analysis of the year-to-year variation in meteorology. 

2. Requiring a more conservative model attainment test will necessitate a change in EPA's 

modeling guidance. EPA should also establish performance criteria to insure that the 

modeling is capturing transport appropriately.

3. EPA's approach in CAIR also reflects a "monitored and modeled" test to identify areas 

of interest.

Discussion

EPA was challenged by the State of North Carolina on its test to identify areas of interest. North 

Carolina argued that EPA’s test should address areas that are currently monitoring 

nonattainment. The Court found that EPA’s approach in CAIR was identical to its approach in 

the NOx SIP call and that EPA’s approach was reasonable. It denied North Carolina’s petition 

on this issue. As such, LADCO recommends that EPA continue to use a modeled plus 

monitored test to identify areas of interest. However, the test will need to deal with both areas 

not meeting and those struggling to maintain the air quality standards. In particular, as 

instructed by the Court, the test will need to account for historic variability in air quality levels. 

: In the Clean Air Interstate Rule (CAIR), EPA relied on a “modeled plus monitored” 

test to identify the areas of interest. Specifically, a county had to have both a measured design 

value for the most recent period of available ambient data (i.e., 2001-2003) and a modeled 

value for the 2010 base case above the air quality standard to qualify “as the downwind 

receptors for determining which upwind States make a significant contribution” in downwind 

States. EPA identified 62 counties for PM2.5 and 40 counties for ozone.

We considered two methods, which assume similar approaches for ‘significant contribution to 

nonattainment’ and ‘interference with maintenance’. In the first method, a statistical analysis of 

the year-to-year variability in meteorology was conducted using the method developed by Cox 

and Chu (1993). Under this method, a threshold value slightly below the NAAQS could be used 

to address maintenance. 
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A second method to address maintenance uses the year-to-year variability already reflected in 

the ambient measurements. Under this method, areas of interest would be identified based on 

the monitoring data for the highest of the last three 3-year periods and the future year modeled 

values (based on the highest of the three 3-year periods included in the modeled attainment 

test, rather than the average of these three periods, which is what EPA’s modeling guidelines 

currently recommend). An area would be on the list if the monitored and modeled values both 

exceed the NAAQS. Key advantages of this method are that it accounts for historic variability 

based on actual monitoring data, and it uses the NAAQS as the threshold. For these reasons, 

we recommend this approach be used.

Identifying Upwind States that Significantly Contribute to Nonattainment or Interfere with 

Maintenance

A. An upwind state significantly contributes to nonattainment or interferes with maintenance in 

a downwind area of interest if its total impact from all source sectors equals or exceeds 1% 

of the applicable NAAQS.

LADCO Recommendation:

B. Individual state contributions should be determined through a weight-of-evidence approach, 

including source apportionment modeling 

C. Use of 1% of the NAAQS as the significance threshold is consistent with EPA's approach in 

CAIR. 

Discussion:

EPA was challenged by the State of North Carolina on its significance threshold for PM2.5, 

including its rounding to 0.2 ug/m3. The Court found that EPA’s approach was reasonable and 

denied North Carolina’s petition on this issue. As such, LADCO recommends that EPA continue 

to rely on significance values consistent with its prior rulemakings. Given that the ozone and 

PM2.5 standards have changed since these rulemakings, a reasonable approach would be to 

assume a specific percentage of the NAAQS as the significance threshold. Taken as a whole, 

the prior rulemakings suggest a value on the order of 1 – 1.5% of the NAAQS. For simplicity, 

we recommend a value of 1% of the NAAQS for a state to be deemed significant and included 

in the applicability of a CAIR replacement rule. 

In the NOx SIP Call, EPA assumed a significance threshold for ozone of 2 ppb, 

which represented about 1.5% of the 1-hour ozone standard and 2.5% of the 8-hour standard 

(1997 version). In the Clean Air Interstate Rule (CAIR), EPA relied on this same threshold for 

ozone and assumed a significance threshold for PM2.5 initially based on 1% of the 15 ug/m3 

annual standard. EPA subsequently rounded this value to 0.2 ug/m3, which is 1.3% of the 

NAAQS.
September 10, 2009

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Implementing a Multi-Sector Remedy to Meet Clean Air Act Requirements

A two-part process is recommended consisting of: (A) a national/regional control program 

adopted by EPA for electrical generating units (EGUs) and additional federal control measures 

for other sectors, and (B) state-led efforts to develop, adopt, and implement federally 

enforceable plans for each area of interest that is not expected to attain the standards even 

after implementation of the national/regional program. 

LADCO Recommendation:

A. National/Regional Control Program

A significantly contributing state (i.e., a state which contributes at least 1% to a downwind 

area of interest) must comply with the national/regional control program described below.

1. EGU point source strategy (applicable to units > 25 MW)

In adopting a CAIR replacement rule, EPA should:

(a) make federally enforceable through appropriate mechanisms all NOx and SO2

controls to comply with the original CAIR Phase I program;

(b) make federally enforceable through appropriate mechanisms optimization by no later 

than early 2014 of existing NOx and SO2 controls;

(c) make federally enforceable through appropriate mechanisms application by 2015 of 

low capital cost NOx controls; 

(d) establish statewide emission caps by no later than 2017 for all fossil fuel-fired units 

≥25MW. The caps should reflect an analysis of NOx and SO2 controls on coal-fired 

units ≥ 100 MW which, in combination with the three measures above, will achieve 

rates that are not expected to exceed 0.25 lb/MMBTU for SO2 (annual average for all

units ≥25 MW) and 0.11 lb/MMBTU for NOx (ozone seasonal and annual average for 

all units ≥25 MW) and which will result in lower rates in some states. Previously 

banked emissions under the Title IV or CAIR programs shall not be used to comply 

with the state-wide emission caps; and

(e) to the fullest extent allowed under the Clean Air Act, EPA should work with the states 

to establish regional emissions caps with full emissions trading to replace the caps 

currently applicable under CAIR.

We believe that regional emissions caps for any earlier year (e.g., 2015) should not 

be established, either in addition to or in lieu of a 2017 cap. We conducted a stateby-state analysis of what level of EGU control for NOx and SO2 is achievable over 

the next several years. A fundamental assumption in our analysis is a July 2012 

start date for the planning, engineering, and construction of any new NOx and SO2 

controls. This date reflects a January 2011 promulgation date for a CAIR 

replacement rule and another 18 months for adoption of state rules. Four “layers” of 
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control were considered: (1) all NOx and SO2 controls to comply with the original 

CAIR Phase I program, (2) optimization of existing NOx and SO2 controls by 2014, 

(3) application of low capital cost NOx controls (e.g., combustion modifications) by 

2015, and (4) installation of new NOx and SO2 controls (e.g., SCRs for NOx and 

FGDs for SO2) by 2017. We believe that the first three measures identified above 

are all that can be done by 2015.

We understand that EPA is considering a hybrid approach in its CAIR replacement 

rule involving regional emissions trading and unit-specific performance standards 

(cite: July 9, 2009, testimony by Regina McCarthy before the Subcommittee on 

Clean Air and Nuclear Safety, Committee on Environment and Public Works, U.S. 

Senate). As noted above, we strongly support and encourage EPA to include 

regional emissions trading to the fullest extent allowed under the Clean Air Act.

We believe, however, that unit-specific performance standards go beyond the 

requirements of section 110 and the scope of a CAIR replacement rule; inhibit 

trading; and that performance standards with a near-term compliance timeframe, 

such as 2017, are not practical for all EGUs. Although we firmly believe that is not 

appropriate to include performance standards in a CAIR replacement rule, if EPA 

decides to consider including performance standards, then EPA should work with the 

states to take into account the basis and timing of the requirements identified above, 

cost effectiveness, site specific factors (such as space limitations) and the pollution 

control equipment already in place on the existing fleet of EGUs. Specifically, on this 

last point, we believe that EPA should not require replacement or repowering of units 

or control systems that are sound technology and operating at a reasonable 

effectiveness.

2. Non-EGU point source strategy

a. EPA should identify and prioritize other categories of point sources with major 

emissions of NOx and/or SO2 (e.g., cement plants) based on a review of available 

emissions inventories and other information, such as source apportionment studies.

b. For the non-EGU point sources, EPA should identify and evaluate control options for 

reducing NOx and/or SO2 emissions. The evaluation should consider the 

technological, engineering, and economic feasibility of each control option.

c. At a minimum, EPA should evaluate the technological, engineering, and 

implementation feasibility, and cost-effectiveness of controlling SO2 and NOx 

emissions from industrial, commercial, and institutional boilers > 100 MMBTU/hour.

3. Mobile source strategy, such as new engine standards for on-highway and off-highway 

vehicles and equipment, and a single consistent environmentally-sensitive formulated 

fuel.
September 10, 2009

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4. Area source strategy, such as new federal standards for consumer products and 

architectural, industrial and maintenance coatings as originally promised by EPA in 

2007.

B. State- Led Attainment Planning 

We recommend the use of a state-led attainment planning process concurrent with 

developing the transport SIP to address areas of interest that are not expected to attain after 

implementation of the national/regional control program. The advantages of this state-led 

planning effort include:

• A one-size-fits-all federal solution cannot provide the most appropriate and costeffective solution for each area; 

• Attainment planning is more effective and more likely to succeed if it is done on a 

non-attainment area basis with a key subset of contributing states;

• Additional controls are identified where they are needed; and 

• States maintain their responsibility under the Clean Air Act to establish state 

implementation plans.

A major contributing state (i.e., a state which contributes at least 4% to a downwind area of 

interest that is not expected to attain after implementation of the national/regional program) 

must also either:

1. In conjunction with other major contributing states, develop, adopt, and implement an 

appropriate attainment strategy for the area of interest, as follows: 

a. An upwind state’s responsibility for achieving air quality benefits in a downwind area 

should be commensurate with the magnitude of the upwind state’s contribution to the 

downwind air quality problem.

b. To facilitate flexibility in developing control programs and reduce control costs, state 

planning efforts should accommodate interstate emissions trading to the fullest 

extent allowed by the Clean Air Act.

c. Photochemical modeling, performed in accordance with EPA modeling guidance, 

should be conducted to determine the amount of emission reduction needed to 

provide for attainment and the relative contributions of the participating states and 

source sectors, and to assess candidate control measures.

2. In the event that the multi-state planning effort is unsuccessful, then each 4% state may 

still be able to satisfy its section 110(a)(2)(D) obligation if it can demonstrate to EPA that 

it has emission reductions measures for significantly contributing source categories that 

are commensurate with a Reasonably Available Control Measure analysis for the 

affected area. These measures should be determined by first identifying key pollutants 

and source categories that contribute to the air quality problem, and then identifying and 

evaluating control measures for the contributing source categories. 
September 10, 2009

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Discussion:

Regional air quality modeling conducted by the State Collaborative demonstrates the need for a 

multi-sector approach (“Regional Modeling for the Eastern U.S.: Technical Support Document”, 

July 9, 2009). This modeling shows for ozone, mobile sources (on-road and off-road) are the 

dominant contributors (about 60%), and for PM2.5, point, area, and mobile sources are all 

important contributors – see Figure 1. Thus, a complete remedy to section 110(a)(2)(D) must 

deal with EGUs and other important source sectors.

A 2-part, multi-sector process is recommended consisting of: (1) a national/regional 

control program adopted by EPA for EGUs and additional federal control measures for other 

sectors, and (2) state-led efforts to develop, adopt, and implement appropriate attainment plans 

for each nonattainment and maintenance area of interest. 

Figure 1. Source sector contributions for ozone PM2.5-annual, and PM2.5-daily based on 20-30 

select (high concentration) monitors 

National/Regional Control Program: A key part of the recommended national/regional control 

program covers EGUs, which, as seen in Figure 2, contribute about 10% (on average) for ozone 

and 20% (on average) for PM2.5. The LADCO States examined the level of EGU control for 

NOx and SO2 that is achievable over the next several years – see, for example, Attachment I. 

A fundamental assumption in the LADCO analysis is a July 2012 start date for the planning, 

engineering, and construction of any new NOx and SO2 controls. This date reflects a January 

2011 promulgation date for a CAIR replacement rule and another 18 months for adoption of 

state rules.

Achievable state-wide average NOx and SO2 emission rates (annual average) were determined 

for four future years: 2013, 2014, 2015, and 2017. 
September 10, 2009

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Four “layers” of control were considered on a plant-by-plant basis:

1. Current “in the pipeline” controls pursuant to CAIR Phase I; state rules; state permits; 

or Consent Decrees

2. By 2014, optimization of existing NOx and SO2 controls to achieve 90% (SCRs) and 

95% or more (FGDs) reduction, respectively 

3. By 2015, application of low capital cost NOx controls (e.g., combustion modifications) 

4. By 2017, installation of new NOx and SO2 controls (e.g., SCRs for NOx and FGDs 

for SO2) on units > 100 MW to support state-wide average emissions rates

Based on this plant-level, unit-level analysis of coal-fired units, the LADCO States identified the 

following achievable annual average emission rates: 

Table 1. Results of LADCO analysis of achievable emission rates (lb/MMBTU)

NOx

Year Illinois Indiana Michigan Ohio Wisconsin

2008 0.23 0.305 0.29 0.36 0.21

2013 0.11-0.12 0.297 0.18 0.24 0.13

2014 0.11-0.12 0.171 0.15 0.18 0.12

2015 0.11-0.12 0.165 0.13 0.17 0.10

2017 0.11-0.12 0.114 0.11 0.12 0.09

SO2

Year Illinois Indiana Michigan Ohio Wisconsin

2008 0.50 0.93 0.91 1.09 0.57

2013 0.24-0.44 0.67 0.58 0.75 0.39

2014 0.20-0.43 0.66 0.45 0.65 0.39

2015 0.19-0.28 0.66 0.37 0.65 0.25

2017 0.15-0.23 0.25 0.25 0.256 0.16

It should be noted that the analysis is based on coal-fired units. Consideration of all units (coal, 

oil, gas, and biomass) will result in emission rates slightly below those indicated above. The 

number of post-combustion controls assumed in this analysis is provided in Table 2. The total 

amount of mega-wattage controlled in each state is on the order of 80-90%.
September 10, 2009

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Table 2. Number of controls assumed in LADCO analysis of achievable emission rates

NOx SO2

SCR SNCR ALL FGD

IL IN MI OH WI IL IN MI OH WI IL IN MI OH WI IL IN MI OH WI

2008 23 3 19 1 4 0 15 1 17 27 3 34 2 6 23 2 16 1

2013 23 7 25 5 7 0 11 8 32 30 7 36 13 20 29 7 25 6

2014 23 12 26 5 7 0 11 8 34 30 12 37 13 29 29 12 33 6

2015 23 17 27 5 17 0 11 15 36 40 17 38 20 35 29 17 33 6

2017 32 25 34 8 17 0 14 15 36 49 27 48 23 37 48 27 56 13

Note: IL and OH numbers reflect number of units controlled, and IN and WI numbers reflect number of 

installations (which may cover multiple units)

Based on the above analysis, the LADCO States recommend the federal control program for 

EGUs reflect the state-wide average emission rates not to exceed 0.25 lb/MMBTU for SO2 

(annual average) and 0.11 lb/MMBTU for NOx (ozone seasonal average).

To supplement the regional air quality modeling conducted by the State Collaborative (see 

“Regional Modeling for the Eastern U.S.: Technical Support Document”, July 9, 2009), LADCO 

conducted modeling for two additional EGU control scenarios1

:

 NOx SO2

(lb/MMBTU) (lb/MMBTU)

Scenario E (2018) 0.125 0.25

Scenario E2 (2018) 0.11 0.25

The average improvement in air quality concentrations for the EGU scenarios (for 2018) is as 

follows:

Table 3. Domainwide average change in air quality concentrations between EGU scenarios

PM-annual PM-daily Ozone

C v. E C v. E2 C v. E C v. E2 C v. E C v. E2

NE 0.7 0.8 1.2 1.2 1.6 2.0

MW 1.1 1.1 1.3 1.4 1.8 1.8

SE 0.9 0.9 1.1 1.1 2.0 2.2

Domain 0.9 0.9 1.1 1.1 1.7 1.8

 1 The base control scenario, which reflects all existing (“on the books”) controls (including all legally 

enforceable EGU controls and all planned EGU controls pursuant to CAIR, as identified by EPA), is 

referred to as Scenario C.
September 10, 2009

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The amount of improvement varies spatially, as shown in Figure 2. Based on these results, two 

key findings should be noted:

• Scenario E2, which is consistent with the LADCO proposal for EGUs in the

national/regional strategy, provides considerable air quality benefit.

• Scenario E2 provides similar air quality benefit compared to other EGU control 

strategies considered in the regional air quality modeling. 

Figure 2. Change in PM2.5-annual, 

PM2.5-daily, and ozone concentrations, 

Scenario E2 v. Scenario C
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State-led Planning: A major contributing state (i.e., a state which contributes at least 4% to a 

downwind area of interest) must, in conjunction with other major contributing states, develop, 

adopt, and implement an appropriate attainment strategy for the area of interest. The selection 

of 4% or more as the definition of a major contributing state was based on available contribution 

information, which showed: (1) a 4% threshold is sufficient to capture most of the total impact at 

key monitoring sites in eastern nonattainment areas, and (2) a 4% threshold results in a 

manageable number of states, which is important for a successful planning process, yet 

includes the necessary states specific to each residual nonattainment area. These focused, 

manageable state-led planning efforts will produce air quality benefits farther downwind as well, 

assisting farther downwind nonattainment areas in achieving the NAAQS. Specific justification 

is summarized below.

The regional air quality modeling conducted by the State Collaborative was reviewed to 

determine state and source region contributions. From a regional perspective, the home region 

is the dominant contributor – see Figure 3. From an individual state perspective, states with a 

4% or more contribution make-up a large portion (70-80%) of the total concentration in the 

areas of interest – see Table 4.

Figure 3. Source region contributions for ozone PM2.5-annual, and PM2.5-daily based on 20-30 

select (high concentration) monitors
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Table 4. Average (%) state-level contributions for 20-30 select monitors

InStateOutState Total Out-of-state Contribution

1% 2% 3% 4% 5% 1% 2% 3% 4% 5%

PM2.5-Annual

2005 40 60 94 86 77 71 67 89 75 58 50 42

2012 43 57 94 85 77 72 68 89 72 58 49 42

PM2.5-Daily

2005 38 62 95 89 83 78 75 91 82 71 63 57

2012 43 57 95 90 83 78 74 91 81 70 60 52

Ozone

2005 25 75 93 83 76 69 64 90 77 66 57 50

2012 26 74 92 84 78 71 66 93 78 68 59 52

Additional information on which states are important contributors to nonattainment problems is 

available from analyses of measurement data:

• Back trajectory analyses were generated by LADCO based on 2003 ozone air quality 

data for select locations in the eastern half of the U.S. Example results are 

presented in Figure 4. These contour plots are based on 72-hour, concentrationweighted back trajectories for a 500 m release height and noon start time. Upwind 

areas most associated with higher concentrations reflect darker red shading. 

Consistent with the modeling, higher concentrations are associated with the home 

states and nearby neighboring states (e.g., for Chicago, important upwind areas 

include IL, IN, and MO; and for Baltimore, MD, PA, VA, WV, and OH). Note, the 

plots are meant to be more qualitative than quantitative, and should not be overanalyzed to yield individual state contributions.

• Maryland Department of Environment recently presented a conceptual model of 

ozone formation and transport in the Northeast (Maryland Department of the 

Environment, 2009, and NESCAUM, 2006). The conceptual model identifies multiple 

transport features, including long-range transport (from sources to the south and 

west of the OTR), regional-scale transport within the OTR from channeled flows in 

nocturnal low-level jets, and local-scale transport along coastal shores due to sea 

and lake breezes. Evidence of an aloft ozone reservoir is based on aloft aircraft 

measurements and higher altitude monitoring sites. An educated estimated of the 

relative impacts for Baltimore suggests 30-40% from westerly transport, 10-20% from 

southerly nocturnal low-level jets, 10-20% from city-to-city local transport, and 10-

20% local. These estimates generally agree with the regional modeling-based 

source apportionment, which ascribes 30-40% from states to the west (mostly, VA, 

WV, and PA), 20-30% from MD, 5-10% from states to the south, and 20% from 

background.
September 10, 2009

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Figure 4. Contour plots of back trajectories for high concentration days for Chicago (upper left), Boston (upper right, Baltimore (lower 

left), and Richmond (lower right)

Note: the plots are meant to be more qualitative than quantitative and do not reflect specific individual state contributions.
September 10, 2009

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• Preliminary analysis of aircraft data during the August 2003 blackout period in the 

Northeast was conducted by the University of Maryland (Marufu, et al, 2004). 

Comparison of aircraft spirals over central PA on August 15, 2003 and August 4, 

2002 indicate aloft ozone about 50% lower and surface ozone about 38 ppb lower. 

The limited nature of this analysis (e.g., comparison of only two days) suggests the 

need for a more rigorous analysis. LADCO intends to examine further this event by 

conducting ambient data analyses (e.g., back trajectories) and applying a regional air 

quality model. Source apportionment methods (trajectory-based and model-based) 

will be used to determine the relative source sector contributions. The results of this 

analysis will be provided to EPA later this year. We believe this analysis will provide 

useful information on the effect of a large reduction in EGU emissions on air quality 

concentrations, and on the model’s ability to simulate transport in the eastern U.S.

• Over a period from 1987 to 2003, LADCO sponsored the collection of aloft (aircraft) 

data for ozone, ozone precursors, and PM chemical species (2002-2003 only). An 

overview of the data, along with limited analyses, is presented in “Data Processing 

and Analysis of Aloft Air Quality Data Collected in the Upper Midwest”, prepared for 

LADCO by Sonoma Technology, Inc.., August 5, 2004. Based on a case study 

analysis of the August 13-20, 2003, period, which included the blackout event noted 

above, key findings included: (1) background ozone levels (i.e., air entering the 

LADCO region) were usually about 60-70 ppb, (2) these background levels were 

lower than those observed in the 1991 LMOS field program when boundary 

conditions were about 70-100 ppb during episodes, and (3) local contributions were 

generally on the order of 20-40 ppb (and as high as 60 ppb). Furthermore the report 

stated that “it is not clear from this analysis whether the shutdown of power plants 

had any influence on air quality in the Midwest.”

The regional air quality modeling conducted by the State Collaborative was also reviewed to 

determine which states contribute at different threshold levels – 1%, 2%, 3%, 4%, and 5% of the 

NAAQS. Tables 5 – 7 summarize the states which contribute to the areas of interest for PM2.5-

annual, PM2.5-daily, and ozone. (Note, Table 8 includes a representative set of ozone areas of 

interest relative to the 75 ppb NAAQS.) The tables show that the number of 4% or more states 

is generally on the order of 3-4, while the number 1% or more states is 10-15. This shows that 

a threshold on the order of 4% will provide for a manageable number of states, which is 

important for a successful planning effort.
September 10, 2009

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Table 5. Areas of interest and contributing states (at different thresholds) for PM2.5-annual

>0.15 ug/m3 >0.30 >0.45 >0.60 >0.75

Southeast

* Atlanta, GA IN, OH, AL, GA. 

SC, NC, TN, KY

AL, GA, SC, TN AL, GA GA GA

* Macon, GA (M) IN, OH, AL, GA, 

FL, SC, NC, TN, 

KY, VA

AL, GA, SC, NC GA GA GA

Midwest

* Cleveland, OH IL, IN, MI, OH, WI, 

KY, WV, PA, NY, 

CAN

IL, IN, MI, OH, WV, 

PA, CAN

IN, MI, OH, PA, 

CAN

MI, OH, PA, CAN MI, OH, PA, CAN

* Detroit, MI IL, IN, MI, OH, WI, 

IA, MN, MO, KY, 

WV, PA, NY, CAN

IL, IN, MI, OH, WI, 

PA, CAN

IL, IN, MI, OH, 

CAN

IN, MI, OH, CAN MI, OH, CAN

* Granite City, IL IL, IN, OH, MI, WI, 

IA, MN, MO, TN, 

KY

IL, IN, MI, IA, MO IL, IN, MO IL, MO IL, MO

* Cincinnati, OH (M) IL, IN, MI, OH, WI, 

IA, MO, TN, KY, 

WV, PA, CAN

IL, IN, MI, OH, KY IL, IN, MI, OH, KY IN,OH, KY IN, OH, KY

* Chicago, IL (M) IL, IN, MI. OH, WI, 

IA, MN, MO, KY, 

CAN

IL, IN, MI, OH, WI, 

IA, MO

IL, IN, MI, WI IL, IN, MI, WI IL, IN, MI, WI

* Indianapolis, IN (M) IL, IN, MI. OH, WI, 

IA, MN, MO, TN, 

WV, PA, KY, CAN

IL, IN, MI, OH, WI, 

MO, KY

IL, IN, MI, OH, KY IL, IN, MI, OH, KY IL, IN, OH

Northeast

* Liberty-Clairton, PA IL, IN, MI, OH, WI, 

KY, WV, VA, PA, 

NY,CAN

IN, OH, MI, KY, 

WV, PA, CAN

MI, OH, WV, PA OH, WV, PA OH, WV, PA

* New York, NY OH, MI, VA, MD, 

PA, NY, NJ, CT/RI, 

MA, CAN

PA, NY, NJ, CAN PA, NY, NJ PA, NY, NJ PA, NY, NJ
September 10, 2009

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Table 6. Areas of interest and contributing states (at different thresholds) for PM2.5-daily

>0.35 ug/m3 >0.75 >1.05 >1.5 >1.75

Southeast

* Birmingham, AL 

(M)

IN, OH, GA, SC, 

NC, TN, KY, VA, 

WV, PA, NY

IN, OH, GA, TN, 

KY, VA, WV, PA

OH, GA, TN, KY, 

WV, PA

OH, GA, TN, KY, 

WV, PA

OH, GA, KY, WV, 

PA

Midwest

* Chicago, IL IL, IN, MI. OH, WI, 

IA, MO, KY, PA, 

CAN

IL, IN, MI, OH, WI, 

IA, MO, KY

IL, IN, MI, OH, WI, 

MO

IL, IN, MI IL, IN, MI

* Cleveland, OH IL, IN, MI, OH, WI, 

KY, WV, PA, NY, 

CAN

IN, MI, OH, PA, 

NY, CAN

IN, MI, OH, PA, 

CAN

MI, OH, PA, CAN MI, OH, PA, CAN

* Detroit, MI IL, IN, MI. OH, WI, 

IA, MO,TN, KY, 

WV, PA, NY, CAN

IL, IN, MI, OH, KY, 

PA, CAN

IL, IN, MI, OH, KY, 

CAN

IL, IN, MI, OH, 

CAN

IN, MI, OH, CAN

* Milwaukee, WI IL, IN, MI, OH, WI, 

IA, MN, MO, KY, 

CAN

IL, IN, MI, WI, IA, 

MN, MO

IL, IN, MI, WI IL, IN, MI, WI IL, WI

* Green Bay, WI IL, IN, MI, OH, WI, 

IA, MN, MO, KY, 

CAN

IL, IN, MI, WI, IA, 

MN, MO

IL, IN, MI, WI, IA, 

MN, MO

IL, MI, WI, IA IL, MI, WI, IA

* Granite City, IL (M) IL, IN, OH, MI. WI, 

IA, MN, ND, MO, 

PA, CAN

IL, IN, OH, MI, WI, 

IA, MN, MO

IL, IN, OH, MI, IA, 

MO

IL, MO IL, MO

* Muscatine, IA (M) IL, IN, OH, MI, WI, 

IA, MN, ND. WV. 

PA, CAN

IL, IN, MI, OH, WI, 

IA, MN, MO

IL, IN, MI, WI, IA, 

MN, MO

IL, IN, MI, WI, IA, 

MN

IL, IN, MI, WI, IA, 

MN

Northeast

* Baltimore, MD IN, OH, NC, VA, 

WV, MD, DE, PA, 

NY, NJ, KY, CT/RI, 

MA, CAN

OH, VA, WV, MD, 

PA, NY, NJ

VA, MD, PA, NY, 

NJ 

VA, MD, PA, NY VA, MD, PA

* Lancaster, PA IN, MI, OH, NC, 

VA, WV, MD, DE, 

PA, NY, NJ, CT/RI, 

MA, CAN

OH, VA, MD, PA, 

NY, NJ

VA, MD, PA, NY, 

NJ

VA, MD, PA, NY, 

NJ

MD, PA, NY

* Liberty-Clairton, PA IL, IN, MI, OH, KY, 

WV, PA, NY, VA,

MD, CAN

IN, MI, OH, KY, 

WV, PA, NY

OH, KY, WV, PA OH, WV, PA OH, WV, PA

* New York, NY IN, MI, OH, VA, 

WV, MD, PA, NY, 

NJ, MA, CT/RI, DE, 

NC, CAN

OH, VA, MD, PA, 

NY, NJ, MA, CT/RI

PA, NY, NJ PA, NY, NJ PA, NY, NJ
September 10, 2009

17

Table 7. Areas of interest and contributing states (at different thresholds) for ozone

>0.85 ppb >1.70 >2.55 >3.40 >4.25

Southeast

* Atlanta, GA AL, MS, GA, FL, 

SC, NC, TN, KY, 

VA

AL, GA, SC, NC, 

TN

AL, GA, SC, TN AL, GA AL, GA

* Charlotte, NC IN, OH, AL, GA, 

SC, NC, TN, KY, 

VA. WV

SC, NC, TN, KY, 

VA

SC, NC, TN, VA SC, NC, TN, VA SC, NC

Midwest

* Chicago, IL 

(Kenosha, WI)

IL, IN, OH, MI, WI, 

MO, KY, WV, 

CAN

IL, IN, MI, OH, WI, 

MO, KY, CAN

IL, IN, MI, OH, WI, 

MO, KY

IL, IN, MI, WI, MO IL, IN

* Holland, MI IL, IN, OH, MI, WI, 

IA, MO, TN, KY, 

PA, CAN

IL, IN, OH, MI, WI, 

MO

IL, IN, MI, WI, MO IL, IN, MI, WI, MO IL, IN, MI, MO

* St. Louis, MO IL, IN, OH, MI, 

MO, MS, KY, TN, 

IA

IL, IN, OH, MO, 

TN, KY

IL, IN, MO, KY IL, IN, MO IL, MO

* Cleveland, OH IL, IN, OH, MI, 

MO, TN, KY, VA, 

WV, PA, NY, CAN

IL, IN, OH, MI, 

KY, PA, CAN

IL, IN, OH, MI, 

KY, PA, CAN

IN, OH, MI, KY, 

PA, CAN

IN, OH, MI, PA

* Cincinnati, OH

 (Campbell, KY)

IL, IN, MI, OH, 

MO, TN, KY WV, 

PA, CAN

IL, IN, OH, MO, 

TN, KY

IL, IN, OH, TN, KY OH, KY OH, KY

* Sheboygan, WI IL, IN, OH, MI, WI, 

MO, TN, KY, VA, 

WV, PA, CAN

IL, IN, OH MI, WI, 

MO, KY

IL, IN, OH, MI, WI, 

MO, KY

IL, IN, MI, WI IL, IN, WI

Northeast

* Washington, DC IN, OH, MI, NC, 

KY, VA, WV, MD, 

PA, NJ, NY, CAN

OH, NC, VA, WV, 

MD, PA, NY

OH, VA, WV, MD, 

PA

OH, VA, MD, PA VA, MD, PA

* Baltimore, MD IN, OH, MI, NC, 

TN, KY, VA, 

WWV, MO, PA, 

NJ, NY, CAN

OH, KY, VA, WV, 

MD, PA, NY

OH, VA, WV, MD, 

PA

VA, WV, MD, PA VA, MD, PA

* Philadelphia, PA IL, IN, OH, MI, 

NC, KY, VA, WV, 

MD, DE, PA, NJ, 

NY, CAN

OH, VA, MD, WV, 

PA, NJ, NY, CAN

MD, DE, PA, NJ, 

NY

NY, PA, NJ NY, PA, NJ

* Springfield, MA OH, NC, KY, VA, 

WV, MD, PA, NJ, 

NY, CT/RI, MA, 

CAN

OH, NC, VA, MD, 

PA, NJ, NY, 

CT/RI, MA, CAN

MD, VA, PA, NJ, 

NY, CT/RI, MA

VA, PA, NJ, NY, 

CT/RI, MA

PA, NJ, NY, 

CT/RI, MA

* Greater 

Connecticut

OH, NC, KY, VA, 

WV, MD, PA, NJ, 

NY, CT/RI, MA, 

CAN

OH, NC, VA, MD, 

PA, NJ, NY, 

CT/RI, CAN

VA, NC, PA, NJ, 

NY, CT/RI

VA, PA, NJ, NY, 

CT/RI

PA, NJ, NY, CT/RI 

* New York, NY

 (Danbury, CT)

IN, OH, NC, KY, 

VA, WV, MD, PA, 

NJ, NY, CT/RI, 

CAN

OH, NC, VA, MD, 

PA, NJ, NY, 

CT/RI, CAN

VA, PA, NJ, NY, 

CT/RI

VA, PA, NJ, NY, 

CT/RI

PA, NJ, NY, CT/RI 
September 10, 2009

18

References

Cox, W.M. and S.H.Chu, 1993, “Meteorologically Adjusted Ozone Trends in Urban Areas: A 

Probabilistic Approach”, Atmospheric Environment 27B(4):424-434 (1993).

Marufu, L.T., B.F. Taubman, B. Bloomer, C.A. Piety, B.G. Doddridge, J.W. Sther, and R.R. 

Dickerson, 2004, “The 2003 North American electrical blackout: An accidental experiment in 

atmospheric chemistry”, Geophysical Research Letters, Vol, 31, L13106, 2004.

Maryland Department of the Environment, 2009, “Where does the air pollution in the OTR come 

from and what do we need to do to fix it?”, PowerPoint presentation from the June 9 and 10, 

2009 Annual OTC Meeting.

“Regional Modeling for the Eastern U.S.: Technical Support Document”, July 9, 2009, State 

Collaborative Modeling Workgroup.

NESCAUM, 2006, “The Nature of the Ozone Air Quality Problem in the Ozone Transport 

Region: A Conceptual Description”, prepared for the OTC by NESCAUM, October 2006.

STI, 2004, “Data Processing and Analysis of Aloft Air Quality Data Collected in the Upper 

Midwest”, prepared for LADCO by Sonoma Technology, Inc.., August 5, 2004
September 10, 2009

19

Attachment I

State-Level Analysis of Achievable EGU Emission Rates in the LADCO Region

Illinois – see State of Illinois’ Multi-Pollutant Standard/Combined Pollutant Standard (Illinois 

Mercury Rule, 35 Ill. Adm. Code Part 225)

Indiana – copy attached

Michigan

Ohio – copy attached

Wisconsin – copy attached
September 10, 2009

20

Indiana Analysis

SO2

1. Incorporated changes/controls that occurred or are projected to occur between the baseline 

year and the year 2013. Due to the timing of the controls that were installed between the years 

2005 and the year 2008, 2005 was chosen the base year for analysis to capture the effect of 

controls installed. One power plant is projected to switch to IGCC and three coal-fired units are 

projected to shutdown. During this time, interval scrubbers were installed on several units and 

the scrubbers on several units were upgraded. Several more controls are projected to be 

installed.

2. By the year 2015, several pre-2005 with reported efficiencies less than 95% were assumed to 

be upgraded to 95%.

3. By the year 2017, new scrubbers were installed on units in order of their capacities and 

emissions. Units >100 MW were considered for installation and an efficiency equal to 95% or a

floor rate equal to 0.06 lb/MMBtu was assumed. The projected emission rates are given below:

Year Emission rate (lb/MMBtu)

2005 1.31

2006 1.27

2007 1.08

2008 0.93

2013 0.67

2015 0.68

2017 0.25 

NOx

1. Incorporated changes/controls that occurred or are projected to occur between the baseline 

year and the year 2013. The year 2008 was chosen as the base year for analysis. One power 

plant is projected to switch to IGCC and three coal-fired units are projected to shutdown. 

SNCRs are projected to be installed on three units.

2. In the year 2014, existing post-combustion controls were assumed to begin year round 

operation. Emission rates equal to 0.25 lb/MMBtu for SNCRs and 0.06 lb/MMBtu were 

assumed. 

3. In the year 2015, low capital cost controls were applied. SNCRs were considered for units 

<200 MW at an efficiency equal to 35% or at a floor rate equal to 0.25 lb/MMBtu. Controls were 

installed on units in order of their capacities and emissions. 

4. In the year 2017, SCRs on units >200 MW at a control efficiency equal to 90% or at a floor 

emission rate equal to 0.06 lb/MMBtu were applied. Controls were installed on units in order of 

their capacities and emissions. The projected emissions are given below: 
September 10, 2009

21

 

Year Emission rate (lb/MMBtu)

2008 0.305

2013 0.297

2014 0.171

2015 0.165

2017 0.114
September 10, 2009

22

Ohio Analysis2

• Incorporated reductions in rates based upon in the pipes controls that are locked in by 

the companies based on company provided schedule.

SO2

o If consent decree required retire, retrofit or repower in the future we assumed a 

retrofit level of control would be applied.

• Incorporated additional control requirements for units where the company has not 

indicated future control:

o Required scrubbers installed by 2017.

o Required optimization by 2014 if it was to meet 95% or by 2017 if it was to 

achieve greater than 95% efficiency based on 2008 base year.

• Required continuous operation for all controls upon installation or by 2015-2017 

(assessed on unit-by-unit basis).

• Applied rates of 0.20 for scrubbers which would equate to approximately 97+% control 

for higher sulfur coals or 95% control for blends.

o This rate was still applied to sources currently controlled whose baseline rates 

were below 0.20 in 2008 to provide a safety margin so that coal use would not be 

limited.

o This rate was also applied to sources currently controlled whose baseline rates 

were above 0.20 in 2008 but we had reason to believe optimization is realistic. 

See next bullet for exception.

• Applied rates of 0.25 to known high sulfur units based upon factors such as: company 

indications of continuing to use high sulfur coals, recently installed scrubbers, company 

indications of 95% efficiencies during 2007 and 2008, etc.

• Applied rates of 0.30 to two small units currently controlled (120 MW each) with known 

higher rates.

• Did not require control on the following units based upon size and fuel use 

characteristics. However, required these sources to maintain use of lower S coal/blends 

or begin use of lower S coal/blends. This was a unit-by-unit analysis of 2008 base year 

rates, S content used and company indications of future coal use:

o Four units at 100 MW and below – no changes.

 2 This identifies the methodology that was used to arrive at interim and final 2017 rates. Use of 

terminology such as “required” does not imply these exact strategies and cutoffs will be used to 

implement said rates.
September 10, 2009

23

NOx

• Incorporated reductions in rates based upon in the pipes controls that are locked in by 

the companies based on company provided schedule.

o If consent decree required retire, retrofit or repower in the future we assumed a 

retrofit level of control would be applied.

• Incorporated additional control requirements for units where the company has not 

indicated future control:

o Required SCR or SNCR installed by 2017.

 SCR required for sources roughly greater than 250 MW. Assumed a 0.08 

rate could be achieved (assessed on unit-by-unit basis).

• This rate was still applied to sources currently controlled whose 

baseline rates were below 0.08 in 2008 to provide a safety margin.

• This rate was also applied to sources currently controlled whose 

baseline rates were above 0.09 in 2008 but we had reason to 

believe optimization is realistic. 

• This required some sources to upgrade from SNCR to SCR.

 SNCR required for sources roughly between 130 and 250 MW. Assumed 

50% reduction in rate over base year. Rates ranged from 0.11 to 0.25 

(higher end rare).

• Required low NOx burners by 2015 for those missing regardless of size (assumed 30% 

reduction over base year).

• Required optimization by 2014 of existing controls where it appeared realistic (assessed 

on unit-by-unit basis).

• Required continuous operation for all controls upon installation or by 2015-2017 

(assessed on unit-by-unit basis).

• Did not require SCR or SNCR on units roughly at 150 MW or below (assessed on unitby-unit basis).
September 10, 2009

24

The following rates achieved applying the above, through the requested years, is outlined 

below:

NOx 

(annual/ozone)

Year Illinois Indiana Michigan Ohio Wisconsin

2008 0.36/0.19

2013 0.24/0.17

2014 0.18/0.16

2015 0.17/0.16

2017 0.12/0.115

SO2

Year Illinois Indiana Michigan Ohio Wisconsin

2008 1.09

2013 0.75

2014 0.65

2015 0.65

2017 0.256

The table below summarizes the number of controls assumed over time:

2008 2013 2014 2015 2017

#

total MW 

controlled

% total 

MW #

total MW 

controlled

% total 

MW #

total MW 

controlled

% total 

MW #

total MW 

controlled

% total 

MW #

total MW 

controlled

% total 

MW

SCR 19 11274 51% 25 13751 63% 26 14422 66% 27 14731 67% 34 17173 78%

SNCR 15 4335 20% 11 2823 13% 11 2823 13% 11 2823 13% 14 2737 12%

FGD 16 10049 46% 25 12636 58% 33 15261 70% 33 15261 70% 56 20933 95%
September 10, 2009

25

Wisconsin Analysis

SOx (lbs/mmBtu)

2008 2013 2014 2015 2017 2017

Existing In Pipeline

Improve 

existing 

controls

Controls 

without major 

investment

With available 

FGD High Control

State Average (approved CAs) 0.57 0.39 0.39 0.25 0.16 0.16

Large Utilities

2013 Base (approved CAs) 0.23 - 0.93 0.12 - 0.77 0.12 - 0.77 0.12 - 0.77 0.12 - 0.26 0.12 - 0.26

2013 Base (w/ pending CAs) 0.26 - 0.77 0.12 - 0.59 0.12 - 0.59 0.12 - 0.43 0.06 - 0.16 0.03 - 0.07

Small Utilities

2013 Base (approved CAs) 0.41 - 2.18 0.00 - 0.53 0.00 - 0.53 0.00 - 0.17 0.00 - 0.17 0.00 - 0.17

notes

1) Dry FGD (95% efficiency) control assumed for many utilities, due to small unit sizes at plant sites and/or timing constraints. 

2) This is a "best case" analysis using FGD technology. Alternative controls - such as lime injection or substituting more low-sulfur coal - may be 

used in practice at some utilities in order to avoid deep controls, but still be below 0.25 #/MMBtu.

NOx (lbs/mmBtu)

2008 2013 2014 2015 2017 2017

Existing In Pipeline

Improve 

existing 

controls

Controls 

without major 

investment

With available 

SCR High Control*

State Average (approved CAs) 0.21 0.13 0.12 0.10 0.09 0.07

Large Utilities

2013 Base (approved CAs) 0.13 - 0.36 0.08 - 0.24 0.08 - 0.24 0.08 - 0.14 0.08 - 0.10 0.06 - 0.09

2013 Base (pending CAs) / Possible 0.13 - 0.36 0.08 - 0.15 0.07 - 0.15 0.07 - 0.13 0.07 - 0.09 0.05 - 0.06

Small Utilities 0.19 - 0.55 0.06 - 0.25 0.06 - 0.25 0.06 - 0.2 0.06 - 0.2 0.06 - 0.2
September 10, 2009

26

notes

1) "CA" - Certificate of Authorization

2) Controls without major investment include combustion modifications, LNBs, and SNCR

3) The 2015 control levels reflect the WeEnergies consent decree, NOx RACT, and approved CAs for major controls.

4) The schedule for installing SCRs is built around the schedule for installing dFGDs.

5) Accommodating an SCR installation in the needed timeframe may require altering the schedule for a major 

outage which occurs every 5 to 10 years. An SCR tie-in usually requires major outage as it impacts existing 

ductwork in typically restricted space as compared to dFGD.

6) The default control for SCR is 0.06 lbs/mmbtu to reflect average accounting for less efficient operation during winter to 

prevent ammonium sulfate buildup.

7) "*" - Reflects pushing SCR control to 90% control on a year-round basis

8) "Possible" - This case addresses a potentially accelerated schedule for SCR installations