### September 10 , 2009

1 

# 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 int erfere 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 ...”



### I n 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 t he 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

ind ependent ly 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 secti on 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

2 

### 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 inter est. 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 measure s 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 necessa ry 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 EP A's modeling guidance. EPA should also establish performance criteria to insure that the modeling is capturing transport approp r iately.

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. Howe ver, 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. : I n 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) a nd 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 fo r ozone.

We considere d t wo methods , which assume similar approaches for ‘significant contribution to

nonattainment’ and ‘interference with maintenance’ . I n the first method

, a statistical analysis of the year

- to

- year variabili ty 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.

### September 10 , 2009

3 

### 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

t he 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 value s both

exceed the NAAQS

. K ey advantage s of this method are that it accounts for historic variability based on actual monitoring data , and i t uses the NAAQS as the threshold

. For these reasons,

w e recommend this approach be used.

Identifying Upwind States that Significantly Contribute to Nonattainment or Interf ere 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 throug h 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 c onsistent 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 ru lemakings 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)

. I n the Clean Air Interstate Rule (CAIR ), EPA relied on this same threshold for

ozo ne 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

4 

### Implementing a Multi

- Sector Remedy to M e et 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 othe r 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 mechanism s all NOx and SO 2 

### control s 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 SO 2 

### 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

- f ired units ≥25MW. The caps should reflect an analysis of NOx and SO 2 

### 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 SO 2 

### (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 stat e

- 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 state

by

- 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 a nother 18 months for adoption of state rules. Four “layers” of

### September 10 , 2009

5 

### 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 capita l 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 u nderstand 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 performanc e standards go beyond the

r equirements 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 firm ly 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 i dentified 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 SO 2 

### (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 SO 2 

### 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 SO 2 

### 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 formu lated
fuel.

### September 10 , 2009

6 

### 4. Area source strategy, such a s 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 atta inment 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 cost

effective 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 contribu ting states;

**•** 

### Additional c ontrols 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 flexi bility 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 gui dance,
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 mul ti

- 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 co mmensurate 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

evalu ating control measures for the contributing source categories.

### September 10 , 2009

7 

### 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 f or ozone, mobile sources (on

- road and off

- road) are the

dom inant contributors (about 60%), and f or 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

d eal 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 nonat tainment 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, a s 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 ove r the next seve ral 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) we re determined for four future years: 2013, 2014, 2015, and 2017.

### September 10 , 2009

8 

### Four “layers” of control we re 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 capit a l 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 rate s

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

9 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

EGU s reflect the state

- wide average e mission rates not to exceed 0.25 lb/MMBTU for SO2 (annual average) and 0.11 lb/MMBTU for NOx (ozone seasonal average).

To supplement t he r egional 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 scenarios 1 

### :

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

- dail y 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

10 

### 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.

**•** S cenario 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

### September 10 , 2009

11 

### 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 i mplement an appropriate attainment strategy fo r the area of interest. The selection of 4% or more as the definition of a major contributing state was based on available contribution
in formation, 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 success ful 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 are as in achieving the NAAQS

. Specific justification
is summarized below.

T he r egional air quality modeling conducted by the State Collaborative was reviewed to
determine state and source region contribution s . From a regional perspective, the home region
i s 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

### September 10 , 2009

12 Table 4

. Average (%) state

- level contributions for 20

- 30 select monitors

In

State Out

State Total Out

- of

- state Contribution

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

PM2.5

- A nnual

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, concentration

weighted back tr ajectories for a 500 m relea se 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 over

analyzed to yield individual state contributions.

**•** Maryland Department of Environment recently presented a conceptual model of ozone formation and transport in the Northeast ( Maryl and Department of the
Environment, 2009, and N ESCAUM, 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 channele d 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 t he 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. T hese 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

13 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

14 

### • 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 da ta 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 prov ided 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 fr om 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 Ai r 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) bac kground ozone levels (i.e., air entering the LADCO region) were usually about 60

- 70 ppb, (2) these background levels were

low er 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 ai r 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

15 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

16 Table 6 . Areas of interest and contributing states (at dif ferent 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).

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

Dickerso n, 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.

N ESCAUM, 2006, “The Nature of the Ozone Air Quality Problem in the Ozone Transport Region: A Conceptual Description”, prepared for t he OTC by NESCAUM, October 2006.

STI, 2004, “Data Processing and Analysis of Aloft Air Quality Data Collected in the Upper Midwest”, prepared f or 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

- fi red 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 re ported 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 ch anges/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 shutdow n. 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 Analysis 2



### • 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 scru bbers 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 exce ption.

**•** 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 o f 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 be gin 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 meth odology 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 reali stic.

**•** 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 t hose 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 unit

by

- unit basis).

### September 10 , 2009

24 

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

below:

NOx (annual/oz one)

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 constrai nts. 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 dF GD. 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 p otentially accelerated schedule for SCR installations