Exhibit 1 

Map Depicting Ameren's Power Stations 

and Agency Air Quality Monitoring Stations 

Illinois Environmental Protection Agency, Illinois Annual Air Quality 

Report 2010, including map depicting Agency air quality monitoring 

stations with the locations of the Ameren MPS Group superimposed. 
State of Illinois 

Illinois Environmental Protection Agency 

Annual 

Air uality 

·Report 

Illinois • 2010 

December 2011 
ILLINOIS ANNUAL 

AIR QUALITY REPORT 

2010 

Illinois Environmental Protection Agency 

Bureau of Air 

1021 North Grand Avenue, East 

P.O. Box 19276 

Springfield, IL 62794-9276 

Printed on recycled paper 
2010 

EXECUTIVE SUMMARY 

This report presents a sunnnary of air quality data collected throughout the State of Illinois during 

the calendar year - 2010. Data is presented for the six criteria pollutants (those for which air quality 

standards have been developed- particulate matter (PM 10 and PM2.5), ozone, sulfur dioxide, 

nitrogen dioxide, carbon monoxide, and lead) along with some heavy metals, nitrates, sulfates, 

volatile organic and toxic compounds. Monitoring was conducted at over 80 different site locations 

collecting data from more than 200 instruments. 

In terms of the Air Quality Index (AQI) air quality during 2010 was either good or moderate 91 

percent of the time throughout Illinois. There were no days when air quality in some part of Illinois 

was considered Unhealthy (category Red). This compares with one Unhealthy day in 2009. There 

were 32 days (22 for 8-hour ozone, 9 for PM2.S and 1 for both 8-hour ozone and PM2.5) when air 

quality in some part of Illinois was considered Unhealthy for Sensitive Groups (category Orange). 

This compares with 13 Unhealthy for Sensitive Groups days reported in 2009. Air quality trends 

for the criteria pollutants are continuing to show downward trends or stable trends well below the 

level of the standards. Percentage changes over the ten year period 2001-2010 are as follows: 

Particulate Matter (PM 1 o) 25 percent decrease, Particulate Matter (PM2.5) 24 percent decrease, 

Sulfur Dioxide 43 percent decrease, Nitrogen Dioxide 25 percent decrease, Carbon Monoxide 52 

percent decrease, Lead 33 percent decrease, and Ozone 19 percent decrease. 

Stationary point source emission data has again been included. The data in the report reflects 

information contained in the Emission Inventory System (EIS) as of December 31, 2010. Emission 

estimates are for the calendar year 2010 and are for the pollutants: particulate matter, volatile 

organic material, sulfur dioxide, nitrogen oxides and carbon monoxide. Emission trends of these 

pollutants have been given for the years 1998 to the present. Emissions reported with the Annual 

Emissions Report have been provided starting with 1998 and are currently available through 2009. 

In general there has been a trend toward decreasing emissions over this time period. 
Illinois Annual Air Quality Report 2010 Section 2: Statewide Summary of Air Quality for 2010 

SECTION 2: STATEWIDE SUMMARY OF AIR QUALITY FOR 2010 

OZONE 

Monitoring was conducted at 34 locations 

during at least part of the April-October 

"ozone season" and at least 75 percent data 

capture was obtained at 33 sites. 

No sites recorded hourly concentrations above 

the 0.12 parts per million (ppm) 1-hour 

standard. The highest 1-hour concentration in 

the Chicago area 0.100 ppm at Zion and 

Lemont compared with a high 1-hour value of 

0.118 ppm at Zion in 2009. The highest value 

in the St. Louis Metro East area was 0.115 

ppm recorded at East St. Louis compared with 

a high in 2009 of0.115 ppm at East StLouis. 

Data is also presented to compare with the 8-

hour standard of 0.075 ppm. The appropriate 

statistic for comparison with the 8-hour 

standard is the fourth highest value, which is 

averaged over a three year period. There 

were two sites in Illinois that had a fourth 

high value above 0.075 ppm in 2010 

compared with zero sites in 2009. The 

highest fourth high value was 0.080 ppm at 

Alton. The highest level in the Chicago area 

was 0.078 ppm at Zion. For the three year 

period 2008-2010, no sites had a fourth high 

average above 0.075 ppm (Table B4). 

Figure 1 shows for each year the statewide 

average of each site's highest hourly ozone 

value for the ten year period 2001-2010. The 

graph shows some year-to-year fluctuation 

and a general decreasing 1 0-year trend since 

2002 with high years in 2002 and 2005 and 

low years in 2004, 2008 and 2009. The 

Statewide average for 2010 was 0.087 ppm 

compared with 0.082 ppm in 2009 and 0.082 

ppmin2008. 

Statewide, the total number of 1-hour 

excursion days in 2010 was zero compared 

with zero in 2009 and zero in 2008. 

Figure 1 

Average 1-Hour Ozone Maximum (ppm) 

0.125 

0.075 

0.1 

I I 

I I I 

I 

I i 

I ! 

I 

I I I 

1 I i I ·1 I 

~ I I 

I I 

I 

I 

I 

J I 

I 

0.05 

0 I 02 03 04 05 06 07 08 09 I 0 

Year 

Figure 2 

Average B-Hour Ozone 4th High (ppm) 

0.1 

0.09 

0.08 

0.07 

0.06 

0.05 

01 02 03 04 05 06 07 08 09 10 

Year 

Q 
Illinois Annual Air Quality Report 2010 

Figure 2 shows for each year the statewide 

average of the 4th highest 8-hour ozone value 

for the same period 2001-2010. This trend is 

generally decreasing since 2002 as well. 

Overall, Illinois' weather was above normal 

in terms of meteorological conditions 

favorable to ozone formation and transport 

Statewide. 

August was the most conducive month in 

terms of meteorological conditions Statewide. 

In terms of conducive days, the Chicago area 

and the Metro-East area both had above 

average numbers. 

PARTICULATE MATTER 

Monitoring was conducted at 3 8 sites for 

PM2.5- Valid annual averages were obtained 

for 34 of the 3 8 sites. No sites recorded an 

average above 15.0 ugfm3, the level of the 

annual standard, compared with no sites in 

2009 and one site in 2008. The Statewide 

average of the annual averages was 11.6 

uglm3 in 2010 compared with 10.6 ugfm3 in 

2009 and 11.6 ugfm3 in 2008. Figure 3 

shows the trend of the Statewide annual 

averages for PM2.5 for the period 2001-2010. 

There were 31 exceedances of the revised 24-

hour standard of 35 uglm3 in 2010 compared 

with 16 exceedances in 2009. The Statewide 

peak of 48.1 ug!m3 was recorded at Chicago 

Mayfair Pump Station. The Statewide 

average of the 98th percentile of 24-hour 

averages was 26.9 ugfm3 in 2010 compared 

with 24.3 ugfm3 in 2009 and 27.4 ugfm3 in 

2008. 

In 201 0 there were 1 7 sites monitoring PM 1 ~ 

The Statewide annual average was 23 ug/m 

compared with 20 ugfm3 in 2009 and 22 

ugfm3 in 2008. 

For PM10 the Statewide average of the 

maximum 24-hour averages in 201 0 was 62 

ugfm3 compared with 56 ugfm3 in 2009 and 

62 ugfm3 in 2008. Figure 4 depicts this trend 

for the period 2001-2010. 

1(\ 

Section 2: Statewide Summary of Air Quality for 2010 

No sites exceeded the former primary annual 

standard of 50 uglm3. The highest annual 

average was 32 ugfm3 in Granite City. The 

lowest annual was 17 ugfm3 in Northbrook 

and Nilwood. There were no exceedances of 

the 24-hour primary standard of 150 ug/m3. 

The highest 24-hour average was recorded in 

Granite City with a value of 1 06 ugfm3 

compared with a high 24-hour value of 115 

ugfm3 in Granite City in 2009. 

Figure 3 

Particulate Matter (PM2.5) Annual Trends 

(ug/m3) 

20 

t i I 

I i I 

I I 

I I 15 r I ' I I ' 

10 + t rt 

I 

I I I 5 

0 l ~ ~ ~ l l [ 

01 02 03 04 05 06 07 08 09 10 

Year 

Figure 4 

Particulate Matter (PM10) 24-Hour Trends 

(ug/m3) 

100 

I 

I t 

50 I 

I J 1 I I I 

I l I 

0 ~ ~ ~ 

01 02 03 04 05 06 07 08 09 10 

Year . 

. 
Illinois Annual Air Quality Report 2010 

CARBON MONOXIDE 

There were no exceedances of either the 1-

hour primary standard of 35 ppm or the 8-

hour primary standard of 9 ppm in 2010. The 

highest 1-hour average was 4.3 ppm recorded 

at Chicago Transit Authority. The highest 8-

hour average was 2.0 ppm recorded in 

Maywood. 

Figure 5 shows the trend for the period 2001-

2010 for the statewide average of the 1-hour 

and 8-hour high CO values. The overall trend 

for both averages is downward. The statewide 

average of the 1-hour high was 2.5 ppm in 

2010 compared with 3.3 ppm in 2009. The 

statewide average for the 8-hour high was 1.5 

ppm in 2010 compared with 2.0 ppm in 2009. 

Figure 5 

Carbon Monoxide Trends {ppm) 

a1-hr 

4 

2 

0 

01 02 03 04 05 06 07 08 09 10 

Year 

SULFUR DIOXIDE 

There were 50 exceedances of the new 1-hour 

primary standard of 75 ppb in 2010 compared 

with 68 exceedances in 2009. There were no 

exceedances of the 3-hour secondary standard 

of 500 ppb in 2010. The annual and 24-hour 

primary standards were revoked by USEP A in 

Section 2: Statewide Summary of Air Quality for 2010 

2010. The highest 1-hour average was 331 

ppb recorded in Pekin compared with 352 ppb 

in Pekin in 2009. The .statewide average of the 

1-hour high in 2010 was 75 ppb. This 

compares with 81 ppb in 2009 and 128 ppb in 

2008. The highest 3-hour average of223 ppb 

was recorded in Pekin in 2010 compared with 

265 ppb in Pekin in 2009. There were four 

sites over the primary 1-hr standard of75 ppb 

for the 2008-2010 period compared to six 

sites for the 2007-2009 period (Table B 17). 

Figure 6 

Sulfur Dioxide 24-Hour Trends 

(ppb) 

01 02 03 04 05 06 07 08 09 10 

Year 

Figure 6 shows the statewide trend for the 

maximum 24-hour averages for the period 

2001-2010. The 24-hour average trend has 

been overall downward; however a greater 

degree of year-to-year fluctuations have 

occurred. · The statewide average for 201 0 

was 15 ppb compared with the 2009 average 

of 17 ppb. Statewide 1-hour average 

maximums have also declined. The 2010 

average was 75 ppb compared to 81 ppb in 

2009. 

NITROGEN DIOXIDE 

There were no violations of the annual 

primary standard of 53 ppb recorded in 

Illinois during 2010. The highest annual 
Illinois Annual Air Quality Report 2010 

average of 25 ppb was recorded at Chicago - CTA. The Statewide average for 2010 was 18 

ppb compared with 19 ppb in 2009 and 18 

ppb in 2008. There were no violations of the 

new 1-hour primary standard in 201 0 as well. 

This compares to 15 violations in 2009. 

There were no sites over the 1-hour primary 

standard of 100 ppb for the 2008-2010 period 

compared to one site for the 2007-2009 period 

(Table B20). 

One site operated only during part of the 

ozone season as P AMS. Figure 7 depicts the 

trend of statewide averages from 2001-2010. 

The trend has been generally stable for the 

period ranging from 17 ppb to 25 ppb. There 

have been no violations of the annual standard 

since 1980. 

Figure 7 

Nitrogen Dioxide Annual Trend 

(ppm) 

30 

, I I I I I I I 

I I 25 I i J I I 20 I + I 

' 

+ t I I I 15 I + cr l I 

10 I t I I 

I I 

tt [ 5 I '0 l ~ l l 

01 02 03 04 05 06 07 08 09 10 

Year 

LEAD 

Perhaps the greatest success story in 

controlling criteria pollutants is lead. As a 

direct result of the Federal Motor Vehicle 

Control Program which has required the use 

of unleaded gas in automobiles since 1975, 

lead levels have decreased by more than 90 

percent statewide. Based on new health 

studies the lead standard was revised in 2008 

from a quarterly mean of 1.5 ug/m3 to a 

Section 2: Statewide Summary of Air Quality for 2010 

rolling 3-month maxunum mean of 0.15 

ug/m3. 

There were no violations of the former 

quarterly lead standard of 1.5 ug/m3. There 

were two violations of the new rolling 3-

month maximum mean standard for the 2008 

to 2010 period recorded at Granite City - 15th 

& Madison with a value of 0.42 ug/m3 and 

Chicago Perez with a value of 0.24 ug/m3. 

This compares with a statewide high of 0.28 

ug/m3 for 2007 to 2009 at Granite City 15th & 

Madison. 

Figure 8 

Lead Maximum 3-Month Trend (ug/m3) 

01 02 03 04 05 06 07 08 09 10 

Year 

Figure 8 shows the trend of the statewide 

non-source maximum monthly averages from 

2001-2010. The chart shows a general flat 

trend of ambient lead levels over the last 

several years. In 2010, several source 

oriented monitors were installed and one nonsource monitor was discontinued. Currently, 

not enough data exists for the source oriented 

sites to establish a trend. 

FILTER ANALYSIS RESULTS 

The TSP samples analyzed, in addition to 

lead, for specific metals, sulfates and nitrates. 

Several of the metals analyzed (arsenic, 
Illinois Annual Air Quality Report 2010 

beryllium, cadmium, chromium, manganese, 

and nickel) have known toxic properties. 

Other metals such as iron can be used as 

tracers to help identifY sources of high 

particulate values. Sulfates and nitrates are 

precursors of acid precipitation/deposition 

and add to the understanding of this interregional problem. They are also important 

constituents of the PM2.5 values. There are 

qrrrently no State or Federal ambient air 

quality standards for these parameters. 

The areas with the highest metals 

concentrations in Illinois are generally the 

heavy industrialized areas of the Metro-East 

(Granite City and East St. Louis) and South 

Chicago, especially for iron and manganese. 

The highest 24-hour average for arsenic was 

0.136 ug/m3 measured in Granite City. The 

highest armual average of 0.007 ug/m3 was 

also recorded at Granite City. There were no 

measurable beryllium 24-hour averages 

recorded statewide. Chicago Perez recorded 

·the highest cadmium concentrations with a 

maximum 24-hour average of 0.031 ug!m3. 

The highest armual average of 0.004 ug!m3 

was also recorded at Chicago Perez. The 

highest 24-hour chromium average was 0.066 

ug/m3 recorded at Chicago - Washington. 

Maywood had the highest armual average at 

0.020 ug/m3. The highest iron and 

manganese values were recorded in South 

Chicago and the high traffic areas of 

Maywood. The highest 24-hour average for 

nickel was recorded at Granite City with a 

value of 0.184 ug!m3. The highest armual 

average was in Maywood with an average of 

0.010 ug/m3. For nitrates, the highest 24-

hour average was 33.9 ug/m3 recorded at 

Surmnit. The highest armual average was 5.6 

ug/m3 recorded at Alsip. For sulfates, the 

highest 24-hour average was 18.2 ug/m3 

recorded at Maywood. The highest armual 

average was 7.2 ug!m3 at Chicago -

Washington. In general, metals, nitrate and 

sulfate values were slightly higher in 2010 

than in 2009. 

TOXIC COMPOUNDS 

Section 2: Statewide Summary of Air Quality for 2010 

Sampling for toxic compounds other than 

metals (see Filter Analysis Section) was 

conducted at Northbrook and Schiller Park. 

Most compounds were below the method 

detection limits. The highest compounds 

were toluene, mercury, benzene, and 

formaldehyde. 

PM2.S SPECIATION 

PMz.s samples are also analyzed for numerous 

constituents at 5 sites. The major constituents 

(inorganic elements, anrrnonium, nitrate, 

sulfate, elemental and organic carbon) are 

listed in Table B26. In general, 

approximately 62% is anrrnonium nitrate and 

anrrnonium sulfate, 32% is elemental and 

organic carbon and 6% is inorganic elements. 

1 7 
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--j4752.2.i!8~i8~i3.j~· ii:r,i9~0i~, 

_ _7_q7~_!!,;7.5_:_4?_9~.BII.~_I?Il_.1.Z.l_?!?.~; 

755353.88 _ 4301835.50 _ 171191010 

J~ljP:_._ii:_4~E~.~j~P{ii~ii~PQi 

_73?;3.~_9:.Q9_~_3~~-:J,._?O_·_ 17_CI83_!1!!l~ 

~~~7:4.11; ~~~95._~0 .. 17~~QC!Cl?. 

__, ~a~,¥~~11z:r~~?P""~o_e_~4_, 

27703~. 77: 44~~~-!!9 _}71_67CICI_13_-

'" !00 Milos 
Exhibit 2 

Table 1: Ameren MPS Group Information 

Information provided by Ameren Energy Resources, April 2012, 

including location, permits, pollution control equipment, etc. 
Table 1 

Power Stations and Units Comprising the MPS Group 

(§ 104.204(b)) 

Address Boilers and Sizes Pollution S02 Emissions in Permits issued, issu

Control Rate and TPY application numbers, a

Number of Equipment1 relevant inform

Employees 

Coffeen Power Station (I.D. No. 135803AAA) 

134 CIPS Lane Unit 1 Unit2 OFA3 2011 SOz State O.Qerating Permits: 

Coffeen, Illinois SCR4 emission rate = 

Montgomery nomina13,282 nominal 5,544 ESP5 with 0.003 lb/MMBtu February 13, 2004 

County rmnBtu/hr mmBtu/hr FGC6 App. No. 73020002 2011 S02 mass Unit 1 

156 employees (1965) (1972) emissions= 82.5 

tons February 13, 2004 

App. No. 73020001 

Unit2 

. 

1 all units unless otherwise indicated 

2 Note that listed here are construction pem1it issued in or after 2005 through the present and that during this period, Ameren has been 

construction permits for projects not pertinent to this request for variance. 

3 overfire air 

4 selective catalytic reduction 

5 electrostatic precipitator 

6 flue gas conditioning 

Table 1 - i 
Table 1 

Power Stations and Units Comprising the MPS Group 

(§ 104.204(b)) . 

Address Boilers and Sizes Pollution S02 Emissions in Permits issued, iss

Control Rate and TPY application numbers, 

Number of Equipment1 relevant inform

Employees 

Coffeen Power Station (I.D. No. 135803AAA) 

Construction Permits: 

December 21, 2007 

App. No. 07090069 

New ESP for Unit 2 

December 15, 2006; rev

23,2007 

App. No. 06090019 

New FGD for Unit 1 an

June 22, 2009 

App. No. 06090019 

Revised WFGD System 

handling 

June 22, 2011 

App. No. 11060016 

Fuel Additives System 

Unit2 

March 2, 2012 

App. No. 12020019 

Temporary Mercury Re

Reduction System 

Table I - ii 
Address 

Number of 

Employees 

Table 1 · 

Power Stations and Units Comprising the MPS Group 

(§ 1 04.204(b)) 

Boilers and Sizes Pollution SOz Emissions in Permits issued, issu

Control Rate and TPY application numbers, a

Equipment' relevant inform

Coffeen Power Station (I.D. No. 135803AAA) 

. 

CAAPP Permit: 

September 29, 2005 

App. No. 95090009 Appealed November 3, 2

(PCB 06-064) 

Stayed February 16, 200

Table 1 -iii 
Table 1 

Power Stations and Units Comprising the MPS Group 

(§ 104.204(b)) 

Address Boilers and Sizes Pollution SOz Emissions in Permits issued, iss

Control Rate and TPY application numbers, 

Number of Equipmene relevant infor

Employees 

Duck Creek (I.D. No. 057801AAA) 

17751 North Unit 1 LNB' 2011 SOz State OJ2erating Permit: 

CILCORoad SCR emission rate = Canton, Illinois Nominal3,713 nnnBtu/hr ESP 0.014lb/MMBtu November 13, 1995 

Fulton County FGD8 App. No. 78020006 (1976) 2011 S02 mass 

72 employees emissions= 167 Construction Permits: 

tons 

Nov. 22, 2006; revised 

App. No. 06070049 

New WFGD9 system 

February 16, 2007 

App. No. 06070048 

Boiler project; New ES

7 low NOx burner 

8 flue gas desulfurization (scmbber) 

9 wetFGD 

Table l - iv 
Table 1 

Power Stations and Units Comprising the MPS Group 

(§ 1 04.204(b)) 

Address Boilers and Sizes Pollution S02 Emissions in Permits issued, issu

Control Rate and TPY application numbers, a

Number of Equipment1 relevant inform

Employees 

Duck Creek (I.D. No. 057801AAA) 

. 

May 7, 2007; revised. Ja

App. No. 07030025 

Pilot Air Quality Contro

Aug 15,2011 App. No.11080047 

Canton Fuels Company R

Emission Fuel (REF) Pro

Facility 

CAAPP Permit: 

September 29, 2005 

App. No. 95070025 Appealed November 3, 2

(PCB 06-066) 

Stayed February 16, 200

Table I · v 
Address 

Number of 

Employees 

Table 1 

Power Stations and Units Comprising the MPS Group 

(§ 104.204(b)) 

Boilers and Sizes Pollution S02 Emissions in 

Control Rate and TPY 

Equipment1 

Permits issued, iss

application numbers

relevant infor

E.D. Edwards Power Station (I.D. No. 143805AAG) 

7800 South Unit 1 Unit2 Unit3 LNB 2011 so2 State 0Qerating Permit

CILCO Lane ESP with emission rate = 

Bartonville, nominal nominal nominal FGC 0.45 lb/MMBtu July I, 2004 

Illinois 1,523 3,321 4,594 App. No. 73010724 

Peoria County mmBtu/hr mmBtulhr mmBtulhr NewLNB 2011 so2 mass andOFAon emissions= Construction Permits: 

I 08 employees (1960) (1968 (1972) Unit 3 12,596 tons March 9, 2007 

App. No. 07030026 

LNB and OF A for Uni

August 24, 2008 

App. No. 08080029 

LNB and OFA for Uni

Sorbent Injection Syste

Units 1, 2, 3 

App. No. 08100002 

September 9, 2009 

March 30, 2011 

App. No. 11030003 

Pilot System for HBr in

Control) for Unit 3 

Table l -vi 
Address 

Number of 

Employees 

Table 1 

Power Stations and Units Comprising the MPS Group 

(§ I 04.204(b)) 

Boilers and Sizes Pollution S02 Emissions in 

Control Rate and TPY 

Equipment1 

Permits issued, issu

application numbers, 

relevant inform

E.D. Edwards Power Station (I.D. No. 143805AAG) 

CAAPP Permit: 

September 29, 2005 

App. No. 95070026 Appealed November 3, 

(PCB 06-067) 

Stayed February 16,200

Table I -vii 
Address 

Number of 

Employees 

Table 1 

Power Stations and Units Comprising the MPS Group 

(§ 1 04.204{b)) 

Boilers and Sizes Pollution SOz Emissions in Permits issued, iss

Control Rate and TPY application numbers, 

Equipmene relevant infor

Hutsonville Power Station (I.D. No. 033801AAA) 

15142 East 1900" Unit 5 Unit6 ESP 2011 so2 State OJ2erating Permit: 

Ave. emission rate = 

Hutsonville, norninal695 nomina1695 2.26 lb/MMBtu February 17, 2005 

Illinois mmBtu/hr mmBtu/hr App. No. 73020017 

Crawford County 2011 so2 mass Unit 5 (1952) (1953) emissions= 9,894 

7 employees tons February 17, 2005 App. No. 73020018 

Unit6 

Construction Permits: 

May 14,2006 

App. No. 06040014 

Pilot Evaluation of Fue

S02 and mercury contr

April3, 2008 

App. No. 08030017 

Pilot Evaluation of Wat

PM Control on Unit 5 

Table I - viii 
Address 

Number of 

Employees 

Table 1 

Power Stations and Units Comprising the MPS Group 

(§ 104.204(b)) 

Boilers and Sizes Pollution S02 Emissions in Permits issued, issu

Control Rate and TPY application numbers, a

Equipment1 relevant inform

Hutsonville Power Station (I.D. No. 033801AAA) 

August 18, 2008 

App. No. 08080015 

Pilot OFA Evaluation fo

CAAPP Permit: 

September 29, 2005 

App. No. 95080105 Appealed November 3, 2

(PCB 06-070) 

Stayed February 16, 200

Table I- ix 
Address 

Number of 

Employees 

Table 1 

Power Stations and Units Comprising the MPS Group 

(§ 1 04.204(b)) 

Boilers and Sizes Pollution SOz Emissions in Permits issued, issu

Control Rate and TPY application numbers, 

Equipment' relevant inform

Joppa (I.D. No. 127855AAC) 

21 00 Portland Units 1-6 ESP 2011 SOz State OQerating Permit: 

Road emission rate = 

Joppa, Illinois nomina11,800 mmBtu/hr each OFAon 0.62 lb/MMBtu June 7, 2005 

Massac County Units 1, 3, 5 App. No. 73010757 (Units 1 and 2 1953) and6 2011 S02 mass 

233 employees emiSSIOns= Construction Permits: (Units3 and 4 1954) 26,180 tons 

March 3, 2005 

(Units 5 and 6 1955) App. No. 05020008 

OF A system for Unit 6 

December 5, 2005 

App. No. 05020011 

OF A system for Unit 5 

November 30, 2006 

App. No. 0600057 

OF A system for Unit 3 

October 24, 2007 

App. No. 07090035 

OF A system for Unit 1 

October 31, 2008 

App. No. 08100052 

Table 1 - x 
Address 

Number of 

Employees 

Joppa (I.D. No. 127855AAC) 

Table 1 

Power Stations and Units Comprising the MPS Group 

(§ 104.204(b)) 

Boilers and Sizes Pollution S02 Emissions in Permits issued, issu

Control Rate and TPY application numbers, a

Equipmene relevant inform

OFA system for Unit 4 

March 31, 2006 

App. No. 06020085 

Pilot for Mercury Contro

December 5, 2006, revis

2007 and Aug. 27, 2008 

App. No. 06110002 

Pilot for Mercury Contro

July 18, 2008, revised De

App. No. 08020070 

Sorbent Injection System 

Oct. 20, 2008, revised Ap

App. No. 08090057 

Pilot for SNCR for NOx 

Unit3 

April28, 2010 App. No. 11060053 

Pilot for Injection System 

Control 

June 30, 2011, revised Fe

Table I ·xi 
Address 

Number of 

Employees 

Joppa (I.D. No. 127855AAC) 

Table 1 

Power Stations and Units Comprising the MPS Group 

(§ 104.204(b)) 

Boilers and Sizes Pollution SOz Emissions in Permits issued, issu

Control Rate and TPY application numbers, 

Equipment1 relevant inform

App. No. 11060053 

Additives Injection Sys

CAAPP Permit: 

September 29, 2005 

App. No. 95090120 

Appealed No,vember 3, 

(PCB 06-065) 

Stayed February 16, 200

--- 

Table I - xii 
Address 

Number of 

Employees 

Table 1 

Power Stations and Units Comprising the MPS Group 

(§ 1 04.204(b)) 

Boilers and Sizes Pollution S02 Emissions in Permits issued, issu

Control Rate and TPY application numbers, a

Equipment1 relevant inform

. 

Meredosia Power Station (I.D. No. 137805AAA) 

800 South Units 1 Units 3 Unit 5 ESP 2011 so2 State OQerating Permits: 

Washington Street and2 and4 emission rate = 

Meredosia, Illinois FGC on 0.55 lb/MMBtu May22, 1996 

Morgan County nominal nominal nominal Units 1 -4 App. No. 73020005 

505 505 2,784 2011 SOz mass Unit 1 

10 employees mmBtu/hr mmBtuJln· nnnBtullrr LNB and emissions= 2,747 

FGCon tons May22, 1996 

each each (1957) Unit 5 App. No. 73020009 

Unit 2 

(1945) (1946) 

May22, 1996 

. App. No. 73020008 

Unit 3 

May 22, 1996 

App. No. 73020006 

Unit 4 

July 23, 2003 

App. No. 73020007 

Unit 5 

-

Table 1 - xiii 
Address 

Number of 

Employees 

Table 1 

Power Stations and Units Comprising the MPS Group 

(§ 104.204(b)) 

Boilers and Sizes Pollution 

Control 

Equipment1 

S02 Emissions in 

Rate and TPY 

Permits issued, issu

application numbers, 

relevant inform

Meredosia Power Station (I.D. No. 13 7805AAA) 

Table I - xiv 

Construction Permits: 

July 17, 2008 

App. No. 08050025 

Sorbent Activation Proc

Demonstration Project February 15, 2007 

App. No. 06120072 

FGC System for Boilers 

December I, 2009 

App. No. 08070022 

Sorbent Injection System 

3/Boiler 5 

August 24, 2009 

App. No. 09080018 

Low NOx Burners and 

for Boiler 5 

CAAPP Pennit: 

September 29, 2005 

App. No. 95090010 Appealed November 3, 
. 

Address 

Number of 

Employees 

Table 1 

Power Stations and Units Comprising the MPS Group 

(§ 1 04.204(b)) 

Boilers and Sizes Pollution S02 Emissions in Permits issued, issua

Control Rate and TPY application numbers, a

Equipment1 relevant inform

Meredosia Power Station (I.D. No. 137805AAA) 

(PCB 06-069) 

Stayed February 16, 2006 

Table I - xv 
Address 

Number of 

Employees 

Table 1 

Power Stations and Units Comprising the MPS Group 

(§ I 04.204(b)) 

Boilers and Sizes Pollution S02 Emissions in Permits issued, issu

Control Rate and TPY application numbers, 

Equipment1 relevant inform

Newton Power Station (I.D. No. 079808AAA) 

6725 North 500m Unit 1 Unit2 LNB 2011 S02 State OQerating Permits

Street OFA emission rate = 

Newton, Illinois nominal 5,500 nominal 5,500 ESP with 0.55 lb/MMBtu July 30, 1998 

Jasper County mmBtu!hr mmBtu!hr FGC App. No. 78080036 2011 S02 mass Unit 1 

155 employees (1972) (1975) Primary Air emissions= 

Duct Burners 20,871 tons June 29, 2001 

on Unit 2 App. No. 83020010 

Unit2 

Construction Permits: 

June 8, 2009 

App. No. 09050032 

Pilot Evaluation of Fue

Mercury Control December 1, 2009 

App. No. 08010049 

Sorbent Injection Syste

and2 

December 20, 2010 

App. No. 10070051 

Flue Gas Desulfurizatio

Table 1 - xvi 
Address 

Number of 

Employees 

Table 1 

Power Stations and Units Comprising the MPS Group 

{§ 104.204(b)) 

Boilers and Sizes Pollution S02 Emissions in Permits issued, issu

Control Rate and TPY application numbers, a

Equipme:Ut1 relevant inform

Newton Power Station (I.D. No. 079808AAA) 

Systems for Unit 1 and U

February 25, 2011 

App. No. 08010049 

Revised Sorbent Injectio

Alternative Control Tech

Control for Unit 1 

June 30, 2011 

App. No. 11060023 

Additive Injection System 

Control on Unit 2 

July 28, 2011 

App. No. 11070007 

Fuel Additives System fo

November 28, 2011 

App. No. 11070007 

Fuel Additives for Unit 

CAAPP Permit: 

September 29, 2005 

Table I · xvii 
Address 

Number of 

Employees 

Table 1 

Power Stations and Units Comprising the MPS Group 

(§ 104.204(b)) 

Boilers and Sizes Pollution S02 Emissions in Permits issued, issu

Control RateandTPY application numbers, 

Equipment1 relevant inform

Newton Power Station (I.D. No. 079808AAA) 

App. No. 95090066 Appealed November 3, 

(PCB 06-068) 

Stayed February 16, 20

CH2\lll91307.1 

Table 1 - xviii 
Exhibit 3 

Ne\\'ton Energy Center FGD Project Construction Permit 

Illinois Environmental Protection Agency, Issued to Ameren Energy 

Generating Company (Dec. 20, 201 0). 
ILLINOIS ENVIRONMENTAL PROTECTION AGENCY 

I 021 NORTH GRAND .AVfNUE EAIT, P.O. Box 19506, 5PRINGCIELQ, ILLINOIS 62794-9506- { 217) 782-2113 

217/782-2113 

PERMITTEE 

DouGLAS P. Scon. Dnw T< w 

CONSTRUCTION PERMIT 

NSFS AND NESHAP SOURCE 

Ameren Energy Generating Company 

Attn: !~ichael L. Menne, Vice Presidei!t 

1901 Chouteau -~venue 

St. Louis, Missouri 63103 

APplication No.: 10070051 J.D. No.: 079808k~ 

Appllcant' s Desiqnatlon: NEt..]TONFGD Date Received: July 23'" 2010 

Subject: Addition of Flue Gas Desulfurization Systems 

Date Issued: Decembe~ 20, 2010 

Location: 6725 Nq.rth 500th St;~;eet, Newton, Jasper County 

Permit is hereby granted to the above-designated Permittee to CONSTRUCT 

emission source(s) and/or air pollution control equipment consisting of the 

addition of th'O flue gas desulfurization {FGD) systems, one each for the 

existing Newton steam generating units, Units NB-1 and NB-2, and one dieselfired engine-generate~, as described in the above-referenced application. 

This permit is subject to standard conditions attached hereto and the 

following special conditions: 

Conditions for the Project and Newton Units NB-1 and NB-2 

1.1 Introduction 

a. This permit authorizes the addition of tHo FGD systems, one each 

for UniLs NB-1 and NB-2. The FGD systems are being installed in 

order to ·comply vJi th future environmental requirements. 

b. This permit also authorizes construction of the following 

equipment and facilit:i.es as part of this project: 

• Two new 1nduced draft fans for each unit {four total). 

• P.. single new chimney ~·Ji th separate flues for each unit. 

• A limestone handling facility for the pulverized limestone 

for the FGD systems. 

• ~G. gypsum handling facility for the gypsum material from the 

FGD systems. 

• A diesel engine-generator to provide emergency electrical 

power for the FGD systems. 

1.2 Non-Applicability Provisions 

a. This permit is issued based on ~his project being an emission 

control project that 1.-.rill reduce emissions of sulfur dioxide (S02 ) 

and sulfuric acid mist from Units NB-1 and NB-2 and will not 

increase emissions of other pollutants from these Unitsp 
Page 2 

b. This permit is- issued based on the neitt support equipment and 

facilities associated with the FGD systems, as constrained by the 

limitations and require.rnents in this permit, not being a major 

modification for purposes of the federal PSD rules. This is 

because the increases in emissions of individual PSD poJ.lutants 

from these units are less than the significant emission rates_ set 

in the PSD rules. 

1, 3 Other Applicable Require-ments 

1.4. 

a. This permit does not relax or revise applicable requirements for 

Unj.ts NB-1 and NB-2 and associated control equipment! including 

requirements i-n existing permits for the source, including 

provisions for st0rt..up, malfunction and breakdow-n., recordkeeping, 

and reporting. 

b. This permit does not relieve the Pern-.ittee of the responsibility 

to comply o;.;it~ all Local, State and Federal RegulatiOns that are 

part of the applicable. Illinois State Implementation Plan, as 

well as all other applicable Federal, State and Local 

requiretnents. In particular, this permit does not excuse the 

Permittee from the obligat.ion to undertake further actions at or 

for the source as may be needed to ensure that it would not cause 

or contribute to viola~ions of National P~ient Air Quality 

Standards/ including accepting additional limits on the emissions 

of Unit:s NB-1 and NB-2 and other emission units at the sou!:ce, 

enhancing the operation of the new FGD systems for the Units, 

their existing control equipment, or the control equipment or 

control measures for other emission unit.s at the source to assure 

compliance with such limits 1 and/or enhancing dispersion of 

emissions from the Units and other emission units at the source. 

Control Practices 

a. Each FGD system shal.l be equipped vli th a high efficie...TJ.cy mist 

eliminator to minimize entrained scrubbant carryover. 

b. At .?~ll times, the Permittee shall, to the extent practicable 1 

maintain and operate Units NB-1 ~nd l\!"B-2 with new 1-'GU systems in 

a manner consistent with good air pollution control practice for 

minimizing emissions. 

l.S Emissions Testing Requirements 

a. Within one year (365 days) after the initial startup cf Unit NB-1 

and NB-2 with an FGD system, the emissions of particulate matter, 

both filterable and condensable, from the unit shall be measured 

by an approved testing se-rvl.ce while the unit is operating in the 

maximum load range and other representative o-perating conditions. 

b. The following methods and procedures shall be used for testing of 

emissions, unless another method is approved by the Agency: 
Page 3 

Refer to 40 CFR 60, Appendix A, and 40 CFR Part 51, Appendix H, 

for USEPA test me-thods. 

Location of Sample Points 

Gas Flow & Velocity 

Particulate· Iv!atter 

Condensable Particulate Matter 

USEPA t4e thod 1 

USEPA Method 2 

USEPll. Method 5 

USEPA Method 202 

c. Prior to car_rying out these tests, the Illinois EPA's Regional 

Office ru~d Source Emission Test Specialist shall be notified a 

minimum of 30 days prior to the expected date of these tests and 

further notified a minimum of 5 working days prior to the tests 

of the exact date, time and place of these tests, to enable the 

Agency to witness these tests~ 

d. Three copies of the Final Report(s) for these tests shall be 

submitted to the Illinois EPA within 14 days after the test 

results are compiled and finalized. The following information 

shall be submitted with the results: 

i. The gross power generation and the steam generation rate 

for the unit during the test. 

ii. Significant operating parameters of the FGD system, such as 

absorber pH levelst scrubber slurry density, scrubbant 

circulatlon rate, limestone slurry makeup rate and slurry 

bleed·rate, as measured during the tests. 

iii. 802 emission dat·a during the periods of testing based on 

emission monitoring, and the calculated 802 control 

efficiency on a daily basis. 

iv. Opacity data collected by the continuous opacity monitoring 

systems during each test run and if conditions are suitable 

for such observation, observations of opacity at the stack 

(two 6-minute averages) for each test run. 

1.6 Recordkeeping Requirements 

All records required by this permit shall be retained at a readily 

accessible location at the source for at least three years from the 

date of entry and shall be made available for inspection and copying by 

the Illinois EPA upon request. Any records retained in an electronic 

format {e.g., computer) shall be capable of being retrieved and printed 

on paper during normal source office hours so as to be able to respond 

to ~l Illinois EPA request for records during the course of a source 

ir:.spection. 

1.7 Notifications 

The Permittee shall notify the Illinois EPA in writing within 30 days 

of the initial startup of each FGD system. 
1.8 Reporting Requirement-s 

If there is a deviation from the req-u.irements of this permit, the 

Permittee shall promptly report the deviation to the Illinois EPA. 

Unless otherwise specified, this report shall be subrni~ted with~n 30 

days of the deviation. The report shall describe the deviation 1 the 

probable cause of the deviation, corrective actions chat were taken and 

any actions to prevent future occurrences. 

1. 9 Report./Noti~ications Submittals 

Two copies of all reports and notifications required by this permit 

shall be sent to: 

Illinois :E:nvironmental Protection Agency 

Div~sion of Ai~· Poll'u.tion Control 

Compliance Section (#40) 

P.O. Box 19276 

Springfield, Illinois 62794-9276 

Telephon-e-: 2l7/782-5$11 Fax~ 217/782-6348 

and one copy shall be sent to the Illinois EPArs regional office at the 

following address unless otherwise indicated: 

Illinois Environmental Protection Ag~ncy 

Division of Air Pollution Control 

2009 Nall Street 

Collinsville, Illinois 62234 

'Telephone: 618/346-5120 Fax: 613/346-51.55 

1.10 Authorization for Operation 

a. i. Units NB-1. and NB-2 with FGD systems each may C•perate for 

up t.o one- year under this permit during \'lhich period 

shakeda~1 and emissions testing shall be completed. 

ii. This period of time may be extended by the Illinois EPA for 

up to an additional 365 days upon written request by the 

Permittee as needed to reasonably accorTh:-nadate difficulties 

that are encountered in the shakedo~~ and emissions testing 

of the unit(s) with the new FGD systems. 

b. Following completion of required emissions testing, the Permittee 

is allowed to operate Units NB-l and NB-2 with FGD systems under 

this permit. until the operation of the FGD systems is addressed 

by a CAP.PP permit. 

c. These conditions supersede Standard condition 6. 
Page 5 

Unit-specific Conditions for the New Material Handling Facilities 

2. 0 Introducfion 

The affected facilities for the purpose of these Unit-Specific 

Conditions are the new facility for· h.3:-Ddling limestone for the new FGD 

systems and the neT,, facility for handling the ''gypsum" {sludge or spent 

material) from these FGD systems. 

2.1 Applicable Emission Standards 

a. The Permittee shall not cause or allow the emission of fugitive 

particulate matter {PM) from an affected facility that is visible 

by an observer looking generally toward the zenith (that is 

·looking at the sky directly overhead) from a point beyond the 

property line of the source pursuant to 35 IAC 212.301. 

b. The Permittee shall not cause or allav1 the emission of smoke or 

other PN, with an opacity greater than 30 percent into the 

atmosphere from an·affected facility, pursuant to 35 IAC 

212.123 (a) . 

c. The procesS snission units in the affected facilities shall 

comply With 35 IAC 212~321(a), which provides that no person 

shall cause or allow PM emissions into the atmosphere in any one 

hour period from any new process emission tulit which 1 either 

alone or in combination with the PM emission from all other new 

similar process emission units at a source or premises, exceeds 

the allowable emission rates specified in 35 IAC 212.321(c). 

2.2 Non-Applicability Provisions 

a, This permit is issued based on the affected limestone handling 

facility not being subject to the federal New Source Performance 

Standards {NSPS) for No~metallic Mineral Processing Plants, 40 

CFR 60 Subpart 000, because the facility does not crush or grind 

limestone so that it does not constitute a nonmetallic mineral 

processing plant, as defined by 40 CFR 60.671, for limestone. 

b. This permit is issued based on the affected gypsum handling 

facility not being subject to the NSPS, 40 CFR 60 Suhpart 000 

because it does not crush or grind gypsum, so that it does not 

constitute a nonmetallic mineral processing plant for gypsum. 

2.3 Operational Limitations 

a. The amount of limestone received by the affected limestone 

handling facility shall not exceed 150,000 tons per year. 

Compliance with this limit a..11.d other annual limits set by this 

permit shall be determined from a running total of 12 months o£ 

data, i.e. 1 from the sum of the data for the current month and 

the data for the preceding ~1 months. 
Page 6 

d_ 

i. 

There shall be no visible PM emissions from the 

affected limestone h2ndling facility. 

S. The filters for affected limestone handling facility 

shall have a design outlet loading for PfliJ of no more 

tf1an 0, 02 grains/ scf, as sho\<Jn by the manufacturerr s 

performance specifications for the device or 

representative emission. test data for similar filter 

devices~ 

11. The total -stack emissions of PH ar1d PMlO from the 

limestone silos (bin vent filters) shall both not 

exceed 0.85 tons per year. This limit for PMlO 

e..i11issions 1 and other limits for PM10 emissions set in 

this permit, shall only apply to filterable emissions 

of PHlO, as would be measured in accordance with 35 

I.".C 212 . .lOS (a) . 

2'- Other than stack emissions frOm the lime-stone silos, 

a.s addressed above~ this permit is issued based upon 

negligible emissions of particulate from the affected 

limestone handling facility. For thie purpose, 

emissions of Pt.'! and Pl'-110 from the affected facility~ 

other than from the limestone silos, shall each not 

exceed 0.44 tons per year. 

Gypsum material s~all only be mechanically de-watered, 

i.e., this permit does not authorize thermal drying of the 

material. 

ii. The particulate ernissions from the affected gypsum handling 

facility, including both stack and fugitive emissions 1 

shall not exceed 7.4 and 2.6 tons per year of PM and PMlO; 

respectively. These limits are based on the information in 

the application, including the projected maximum throughput 

of de-watered 101.aterial per year, a nominal 15 percent 

moisture content for de-wat-ered material~ and ap-propriate 

USEPA AP-42 emission factors for handling wet material. 

At all times, the Permittee shall maintain and operate the 

affected limestone and gy-psU.i1'1 handling facilities, inciuding 

associated air pollution control measures 1 in a manner consistent 

with good air pollution control practices for minimizing 

emissions. 

i. A. The transport of limestone on roads at the source 

shall be on paved roads that are maintained in good 

conditiOn to control P!-1 emissions. 

B. The traf.isport of the gypsum on roads at the source 

shall either_ be on paved roads that are: maintained in 
Page 7 

ii. A. 

good condition to control PM emissions or on roads 

that are treated \'lith wet suppression to achieve at 

least a nominal 85 percent control for PM emissions~ 

The PM and Pt-110 emissions from transport of gypsum on 

roads at the source shall not exceed 10.0 and 2.5 

tons/year/ respectively. 

B. This permit is issued based upon negligible emissions 

of particulate from transport of limestone on roads 

at the source. For this purpose, emission£: of Prvr and 

PMlO shall each not exceed 0.44 tons per year. 

2.5 Inspection and Maintenance Re~Airements 

a. Inspections of the affected limestone and gypsum handling 

facilities including emission control measures shall be conducted 

at least once per month when a facility is in operation to 

confirm compliance with the requirements Of this permit. 

b. Maintenance and repair of enclosures, filters, and other control 

measures shall be performed to assure that such measures function 

properly when rnater·ial is being handled. 

c. The Permittee shall maintain records of the above inspections and 

maintenance/repair activity in an operating and maintenance log 

or other records. These records shall contain, at a minimum, the 

date, time and description of the inspections or 

maintenance/repair activities. 

2.6 Opacity Measurements 

Upon written request by the Illinois EPA, the Permittee shall conduct 

opacity observations for operation{s) or unit(s) at the affected 

facilities 1 as specified in the request. These observations shall be 

conducted within 45 calendar days of the date of the request or by the 

date agreed upon by the Illinois EPA, whichever is later. 

2 . 7 Recordkeeping Requirements 

a. For each filter in the affected limestone handling facility, the 

Permittee shall maintain a file containing documentation for 

guarante-ed PH emission rate, in gr/dscf, as provided by the 

supplier of the device. 

b. The Permittee shall maintain operating records for the following 

it~~s for the affected facilities: 

i. Amount of limestone received, tons/month and tons/year. 

ii. Amount of limestone transferred to the FGD systems, 

tons/month and tons/year. 
Page B 

iii. P.inount of gypsum handled, tons/month and tons/year. 

c. The Permittee shall keep records for the implementation of 

fugitive dust control measures on road'lvays used by trucks that 

handle limestone and gy~sum. 

d. The Permittee shall keep the following records related to Pf1 and 

PMlO emissions (tons/month and tons/year} r v.·ith suppo1·ting 

calculations: 

i. Records of stack emissions from the silos at the affected 

limestone handling facility. 

ii. Records of emissions ·from the gypsum handling facility. 

iii. Records of emissions from roadways at the source from 

transport of gypsum. 

2.S The limestone·and gypsum handling facilities may be operated pursuant 

to this construction permit until an operating permit becomes effective 

that addresses operation of these facilities. This condition superse-des 

Standard_Condition 6. 

Unit-Specific Conditions for the Emergency Engine Generator 

3.l Introduction 

one new diesel-fired reciprocating internal combustion engine-generator 

{the affected engine} will be installed at the source to provide 

electricity to the FGD systems on a temporary basis during 

interruptions or outages of the normal power supply. The affected 

engine would also be operated for maintenance and readiness checks. 

3.2 Applicable Emission Standards 

a. i. rrhe affected engine is subject to tlle NSPS for Stationary 

Compression Ignition Internal Combustion Engines, 40 CFR 

60, Subpart IIII. The Permittee must comply \"lith applicable 

requirmoents of the NSPS, 40 CPR 60 Subpart IIII, and 

related requirements of 40 CFR 60, Subpart A, General 

Provisions 1 for the affected engine. 

ii. This permit is issued based on the. affected engine being 

subject to the NSPS requirement for 2010/11 model year and 

later emergency engines with a displacement of less t.han 30 

lit.ers per cylinder so that the engine is subject to and 

shall comply with the applicable e~ission standards in 40 

CFR 89.112 and 89.113, pursuant. to 40 CPR 60.4205(b). 

iii: The Permittee shall operate and maintain the affected 

engine according to the manufacturer's written instructions 
Page Sl 

D. 

or procedures developed by the Permittee that are approved 

by the engine manufacturer, pursuant to 40 CFR 60.421l{a). 

The Permittee shall also meet any applicable requirements 

of 40 CFR Parts 89, 94 and/or 1068 for the affected engine. 

iv~ The Permittee shall use diesel fuel in the affected engine 

that meets the requirements of 40 CFR 80.510, pursuant to 

40 CFR 60.4207. 

v. The Permittee shall demonstrate compliance with the NSPS 

emission standards for the affected engine in accordance 

with 40 CPR 60.4211(c), by purchasing an engine certified 

to the emission standards in.40 CFR 60.4205(b). The 

affected engine must be installed and configured according 

to the manufacturer's specifications. 

vi. The Permittee shall install, operate and maintain a nonresettable hour meter on the affected engine 1 as required 

by 40 CFR 60.4209(a). 

vii. This permit is issued based on the affected engine not 

being equipped with a diesel particulate filterr so that 

the monitoring requirements of the NSPS, 40 CFR 60.4209(b), 

for such devices do not apply. 

L The affected e~gine is subject to the federal National 

Emission Standards for Hazardous Air Pollutants (NESHAP) 

for Stationary Compression Ignition Internal Combustion 

-Engines~ The Permittee must· comply with applicable 

requirements of this NESHAP, 40 CFR 63 Subpart zzzz, and 

related requirements of 40 CFR 63, Subpart A, General 

Provisions, for the affected engine. 

ii. ~~is permit is issued based on the affected engine being 

subject to limited requirements of the NESHAP for emergency 

engines; which consist of the initial notification 

requirements as described in 40 CPR 63.6645(f), because the 

affected engine is a new emergency engine pursuant to 40 

CPR 63.6590(b) (1) (i). 

i. The emission of smoke or other particulate matter from the 

affected engine shall not exceed an opacity greater than 30 

percent, pursuant to 35 IAC 212.123(a) r except as provided 

by 35 IAC 212.124(a) and Conditions 3.2(c) (ii) below. 

ii. Subject to the follO\!I'ing terms and conditions, the 

Permittee is authorized to continue operation of the 

affected engine in violation of the applicable opacity 

standard in 35 IAC 212.123 (a) in the event of a malfunction 

or breakdown of the engine. This authorization is provided 

pursuant to 35 IAC 201.149, 201.161 and 201.262, as the 

Permittee has applied for such authorization in its 
Page 10 

application, generally explaining why such continued 

operatiorr would be required to prevent severe damage to 

equipment, and describing the measures that will be taken 

to minimize emissions from .3..1. .({ malfunctions and breakdowns_ 

A. This authorization only allows such continued 

operation as necessary to provide essential ser~.rice 

or to prevent injury to personnel or severe damage to 

equipment and does not extend to continued operation 

solely for the economic benefit of the Perrnittee. 

B. Upon occurrence of excess emissions due to 

malfunction or breakdm .... n} the Permittee shall as soon 

as pr~cticable restore normal power to the FGD 

systems or complete the shutdovtn of Units NB-l and 

NB-2 or undertake other action so that excess 

ernissions cease~ 

C# The Permittee shall fulfill applicable recordk.eeping 

and reporting requirements of Conditions 3.8[c} ~~d 

3.9. 

D. If the Permittee continues to operate the affected 

engine with excess emissions during malfunction or 

breakdow~ for purposes chat are not related to 

providing emergency power to the FGD systemsi the 

Permittee shall immediately notify the Illinois EPA's 

Regional Office 1 by telephone, facsimile or e-mail 

for each incident in v.rhlch th~ opacity from engine 

exceeds or may have exceeded 30 percent for more than 

one hour (ten 6-minute periods) unless the Permittee 

has begun the shutdo\\lTI of the engine by such time. 

Following this notification to the Illinois EPA of a 

malfunction or breakdown with excess emissions, the 

Permittee shall comply with all reasonable directives 

of the Illinois EPA \·lith ·respect to such incident, 

pursuant to 35 IAC 201.2-63. (Otherwise~ if opacity 

during an incident only exceeds or may have exceeded 

30 percent for less than one hour! the Permittee need 

only report the incident in the periodic cor.1pliance 

report for Units l\'B-1 and l\'B-2.i 

E. This authorization does not relieve t.he Permittee 

from the continuing obligation to minimize excess 

emissiol'lS during malfunction or breakdov..rn 

d. Pursuant to 35 IAC. 214.301, emissions of sulfur dioxide into the 

atmosphere from the affected engine shall not exceed 2,000 ppm. 

3.3 Non-Applicability Provisions 
Page 11 

a. This permit is issued based on the affected engine not being 

subject to the re~uirements of the federal Acid Rain Program 

because it is not a utility unit. (Refer to 40 CFR 72.2 and 

72.6.) Accordingly, electricity generated by the affected engine 

may not be sold to the power grid on a cornrne.rcial basis. 

b. This permit is issued based on the affected engine not being 

subject to the requirements of 35 IAC Part 212 1 Subpart Lr 

because a process weight rate cannot be set, due to the nature of 

such unit, so that these rules cannot reas011.ably be applied, 

pursuant to 35 IAC 212.323. 

3.4 Operational Limitations 

a. The rated output of the affected engine shall not exceed l250 KW. 

b. The affected aDgine sr~ll not be operated for any purpose other 

than emergency operation and maintenru1ce and operational testing, 

pursuant to 40 CFR 60.4211(e). 

c. i. Oper-ation of the affected engine shall not exceed 500 

engine~hours per calendar year, provided, however, that the 

Illinois EPA may authorize temporary operation of the 

engine in excess of 500 hours per year to address 

extraordinary circumstances that require operation of this 

device/ by issu~,ce of a separate State construction permit 

addressing such circumstances. 

ii. The operation of the affected engine for maintenance and 

readiness checks shall be limited to 100 hours per calendar 

year so that the engine qualifies as an emergency engine 

for purposes of the NSPS. 

3.5 Emission Limitations 

a. Emissions from the affected engine shall not exceed the following 

limitations. Compliance with these annual limitations shall be 

determined from a running total of 12 months of data. 

1 

Pollutant Lbs/Hour1 I Tons/Year' 

NO, 18.6 I 4.7 

co 2.8 I 0.7 

The hoUrly limitations for NOx and CO are based on emission 

data from the manufacturer of the engine calculated using 

nameplate capacity of the engine (1,677 HP), which was 

provided in the application. The 502 emission limitation is 

based on fuel sulfur specifications, pursuant to 40 CFR 

so .510 (a) (2). 
Page 12 

The annual limitations are based o-n operation of the. 

affected engine for 500 hours per year at the hourly 

emission rate limit. 

b. This permit· is isSued based on negligible emissions of 802 , PM/PN10 

and VOt·!i fr-om the affected engine. For this purpose, emissions of 

S02 and PM/Pf>110 sha.ll not each e:xceed 0.1 tons/year. Emissions of 

VOM shall not exceed 0.2 tons/year. 

3.6 Opacity Measurements 

b. 

Upon written request by the Illinois EPA~ the Permittee shall 

have the opacity of the exhaust from the affected engine during 

representative operating conditions det.ermined by a qualified 

observer in accordance with USEPA Method 9, as further specified 

below, These observations shall be conducted within 45 calendar 

days of the date of -the request, or on the date the affected 

engine next operates, or by the date agreed upon by the Illinois 

EP.Zi., whichever is latest. 

i. The Permittee shall notify the Illinois EPA at least 7 days 

in advance of tbe date and time of testing 1 in order to 

allow the Illinois EPA to witness testing. This 

notification shall include the name. -and employer of the 

observer(s) and identify any concerns for successful 

completion of observationsr i.e., lack of suitable point 

for proper observation or inability to conduct observations 

under specified operating conditions. 

ii. The Permittee shall promptly notify the Illinois EPA of any 

changes in the date or time of testing. 

The Permittee shall provide a copy of its observer's readings to 

t:.he Tllinois EPA at the time of testing, if Illinois EPA 

personnel are present. 

d. The Permittee shall submit a 'lt!ritten report for these 

observations within 15 days of the date of observ~ation. This 

report shall include: 

~. Date and time of testing. 

ii. Name ruJ..d employer of qualified observer. 

iii. Copy of current certification~ 

iv. Description of observation conditions. 

v. Description of engine operating conditions. 

vi. Raw data. 
Page 13 

vii. Opacity determinations. 

viii. Conclusions. 

3.7 Emission Testing Requirements 

Within 180 days of a written request from t.he Illinois EPA, or the date 

agreed upon by the Illinois EPA, whichever is later, the Permittee 

shall have tests conducted for the affected engine for emissions of NOx, 

CO, PM, and NMHC by an approved independent testing service. These 

tests must be conducted in accordance with the requirements in 40 CFR 

60.4212. 

3.8 Recordkeeping Requirements 

a. The Permittee shall fulfill applicable recordkeeping requirements 

of the :t.JBPS for the affected engine. 

b. The Permittee shall maintain records of the following items for 

the affected engine: 

i. .".. A file containing manufacturer's specifications for 

the affected engine's model year, maximum engine 

capacity, manufacturer's certification of compliance 

with 40 CFR Part 89 or Part 1039 1 and associated 

emission factors~ 

B, Data for the ma.ximu..T!l hourly emission rates {lb/hour) 

from the affected engine, with supporting 

calculations. 

ii ~ .An ope~"'ating log or other operating records, \'fhich shall 

include the following information: 

A. Information for each time the engine is operated, 

with date, time, duration, and purpose (i.e., 

exercise or emergency need)J in accordance with 40 

CPR 60.4214 (b) .. 

B. Information for any incident in which the operation 

of the engine continued during malfunction or 

breakdow"Tl. 1 including: date, time, and duration~· a 

description of the in~ident; whether emissions 

exceeded or may have exceeded any applicable 

standard; a description of the corrective actions 

taken to reduce emissions and the duration of the 

incident; and a description of the preventative 

actions taken. 

iii. A maintenance and repair log or.other records, listing each 

activity performed with date. 
Page 14 

iv. The follo\l'ling operating records: 

A~ Type of fuel used in the affected engine, including 

maximwn sulfur content. 

B. Operating hours of the affected engine {hours/month 

and hours/year) 

v .. Records of NO.x and CO emissions _{tons/month and tons/year} j 

v.rith supporting calculations. 

vi. Records for opacity observations made in accordance with 

· USEPA Method 9 for the 'affected engine· that it conducts or 

that are conducted on its behest by individuals who a~-e 

qualified to make such observations4 For each occasion on 

which such observations are made, these records shall 

include the identity of the observer 1 a description of the 

various observations t~at were made, the observed opacity, 

and copies of the raw data sheets· for thB obse~-vations. 

c_ Pursuant to 35 IAC 201.263, the Permittee shall w~intain the 

following records related to mal".function and break~own of the 

affected engine: 

i. Maintenance and repair log{s) for the affected engine that, 

at a minimum1 address aspects or components of t.he engine 

for which malfunction or breakdo""rn has resulted in excess 

emissions, which shall list the activities performed on 

such aspects or components~ with date and description~ 

ii. Records for each incident vrhen operation of the affected 

engine continued with excess opacity 1 including malfunction 

or breakdown as addressed by Condition 3.2(c) (ii), that, at 

a minimum, include the following information: 

A. Date, time, duration and description of the incident, 

including actions taken to reduce the duration of the 

inci.den.t .. 

B. If opacity exceeded the applicable standard for more 

than 60 minutes _during the incident: 

1. A detailed explanation why continued operation 

of the affected engine was necessary. 

2. The preventative measures that have been or 

will be taken to prevent similar incidents, 

including any repairs to the affecte~ engine 

and associated equipment and any changes to 

operating and maintenance procedures. 
Page 15 

3.9 Reporting Requirements 

a. The Permittee shall fulfill applicable notification and reporting 

requirements of the NSPS and the NESHAP for the affected engine. 

b. If there is 5 deviation from the requirements of this permit for 

the affected engine 1 ·the Permittee shall report the deviation 

with the periodic compliance report for Units NB-1 and NB-2. 

(See also Condition 1. 8.) 

3.10 Authorization for Operation 

The affected engine may be operated pursuant to this construction 

permit until an operating permit becomes effective that addresses this 

engine~ This condition supersedes Standard Condition 6. 

If you have any questions on this permit, please contact Shashi Shah at 

217/782-21l3. 

Edwin C. Bakowski, P.E. 

Manager, Per~it Section 

Division of Air Pollution Control 

ECB: SRS; j ws 

cc: Illinois EPA 1 Region 3 

Date Signed: ~to;ZO!J 
July 1, 1985 

STATE OF ILLINOIS 

ENVIRONMENTAL PROTECTION AGENCY 

DIVISION OF AIR POLLUTION CONTROL 

P. 0. BOX 19508 

SPRINGFIELD, IlLINOIS 62794-9506 

STANDARD CONDITIONS FOR CONSTRUCTION/DEVELOPMENT PERMITS 

ISSUED BY THE ILLINOIS ENVIRONMENTAL PROTECTION AGENCY 

.1 

The Illinois Environmental Protection Act (Illinois Revised Statutes, Chapter 111-112, Section 1039) authorizes the 

Environmental Protection Agency to impose conditions on permits which it issues. 

The following conditions are applicable unless susp·erseded by special condition(s). 

1. Unless this permit has been extended or it has been voided by a newly issued permit, this permit will expire one 

year from the date of issuance, unless a continuous program of construction or development on this project has 

st<:rted by such time. 

2. The construction or development coveted by this permit shall be done in compliance with applicable provisions of 

the Illinois Environmental Protection Act and Regulations adopted by the illinois Pollution Control Board. 

3. There shall be no deviations from the approved plans and specifications unless a written request for modification, 

elong with plans and specifications as required, shall have been submitted to the Agency and a supplemental 

written. permit issued. · 

4. The permittee shall allow any duly authorized agent of the Agency upon the presentation of credentials, at . 

reasonable times: 

a. to enter the permittee's property where actual or potential effluent, emission or noise sources are located or 

where any. activity is to be conducted pursuant to this permit, 

·b. to have access to and to copy any records required to be kept under the terms and conditions of this permit, 

c. to inspect, including during any hours of operation of equipment constructed or operated under this permit, 

such equipment and any equipment required to be kept, used, operated, calibrated and maintained.under this 

permit, 

d. to obtain and remove samples of any discharge or emissions of pollutants, and 

e. to enter and utilize any photographic, recording, testing, monitoring or other equipment for the purpose of 

preserving, testing, monitoring, or recording any· activity, discharge, or emission authorized by this permit. 

5. The issuance of this permit: 

a. shall not be considered as in any manner affecting the title of the premises upon which the permitted 

facilities are to be located, 

b. does not release the permittee from any liability for damage to person·or property caused by or resulting from 

the construction, maintenance, or operation of the proposed facilities, 

c. does not release the permittee from compliance with other applicable statutes and regulations of the United 

States, of the State of Illinois, or with applicable local laws, ordinances and regulations, 

d. does not take into consideration or attest to the structural stability of any units or parts of the project, and 

!!... 532':"0226 

APC 166 Rev. S/99 Printed on Recycled Pi!ipl!r 090-005 
e. in no manner implies or suggests that the Agency (or its officers, agents or employees) assumes any liability, 

directly or indirectly, for any loss due to damage, installation, maintenance, or operation of the proposed 

equipment or facility. 

6. a. Unless a joint construction/operation permit has been issued, a permit for operation shall be obtained from 

the Agency before the equipment covered by this permit is placed into operation. 

b. For purposes of shakedown a'nd testing, unless otherwise specified by a special permit condition, the equip· 

ment covered under this permit may be operated for a period not to exc.eed thirty (30) days. 

7. The Agency·~y file a complaint with the Board for modification, suspension or revocation of a permit; 

I -

a. upon discovery that the permit application contained misrepresentations, misinformation or false statements 

or that all relevant facts were not disclosed, or 

b. uponfinding that any standard or special conditions have been violated, or 

c. upon any violations of the Envirorunen~al Protection Act or any regulation effective thereunder as a result of 

the construction or development authorized by this permit. 
- ••• ~·.--·"'-" , • .._ ...... ·~·~· '-'-''."'"'-'!1 

. BDRE8.U ·oF AIR 

"or assistance in preparin'g a permit· 

lpplication contact the Permit 

iection, 

'· ~llinois Environmental ·Protection,.Agency · Divi-sion of Air .Pollution Control 

Pennit·Seatiou 

· 1.021 N. Graud Ave E. 

· P_,O,Jlc;ri 19SQ6-.: 

.Springfield, Illinois 

Illinois EPA . · 

Region '1- . 

Bureau 6:t; air; FOS 

9511 West·Rarrisou . 

Des.Plaine~. I11fnais.n0016 

847/294-4000 

Illinois EPA 

Region 2· · .. 

5415 North· UniversitY.' 

?eo:da, ILj.inais .61614:; 

309/693-5463,'. 

tiliuois EI'A : 

:egioii 3 

.009 Mall· Street .. 

ollinsV'ille, Illinois 

18/34~..:~i20 

622.3'4 

·' .. 

'· 
Exhibit 4 

Ameren's MPS Opt-In Letter 

Ameren, Letter to Jim Ross, Manager, Division of Air Pollution 

Control, Illinois Environmental Protection Agency 

(December 27, 2007). 
Amere" Energy ReSDurces 

R. Al;sn Kelley 

President & Chief Execurive Officer 

December 27, 2007 

1v1r _ Jim Ross, Manager 

Division of Air Pollution Control 

Bureau of Air 

Illinois Environmental Protection Agency 

1021 North Grand Avenue East 

P. 0. Box !9726 

Springfield, IL 62794-9276 

RE: Illinois Mercury Rule Multi-Pollutant Standard -Notice oflntent 

Dear Mr. Ross: 

One Ameren Plaza 

1!)01 Chouteau Avenue 

PO Box 66149, MC 10 

St. Louis, MO 63166-6149 

314.55f.2849 

3/4.554.3065 fax 

rakelJey@ameren.com 

ln accordance with 35 illinois Administrative Code Part 225 Subpart B Section 225.233 (b), Ameren 

Energy Resources, as authorized .agent for Ameren Energy Generating Company l AmerenEnergy 

Resources Generating Company and Electric Energy Inc., submits this notice of intent that the -o\oYOers 

of the following eligible electric generating units elect to demonstrate compliance with tbe multipo11utant emission limitation as an alternative to the emission standards of Section 225.230. This 

notice of intent is submitted for the fallowing emission units that are eliglble electric generating units 

(EGUs): 

Ameren Energy Generating Campany 

Facility Facility I. D. Emission Unit 

Coffeen !35803AAA 01 

Coffeen 135803AAA 02 

Hutsonville 033801AAA 05 

Hutsonville 033801AAA 06 

Meredosia 137805AAA 01 

Meredosia 137805AAA 02 

Meredosia !37805AAA 03 

Meredosia 137805AAA 04 

Meredosia 137805AAA 05 

Newton 079808AAA I 

Newton 079808AAA 2 

AmerenEnergy Resources Generating Company 

Facility Facility I. D. Emission Unit 

Duck Creek 057801AAA I 

E. D. Edwards 143805AAG 1 

E. D. Edwards 143805AAG 2 

E. D. Edwards 143805AAG 3 
Electric Energy, Inc. 

Facility Facility L D. Emission Unit 

Joppa 127855AAC I 

Joppa 127855AAC 2 

Joppa 127855AAC 3 

Joppa 127855AAC 4 

Joppa 127855AAC 5 

Joppa 127855AAC 6 

The electric generating llllits (EGUs) identified above are eligible to participate as an Multi-Pollutant 

Standard Group for the purpose of delll\lnstrating compliance with the requirements of35 Illinois 

Administrative Code Part225 Subpart B Section 225.233. This notice of intent includes the following 

components as attachments to this submittal: the base emission rates for the EGOs and supporting data; a 

sunnnary of current pollution control equipment installed; and a surrnnary of additional pollution control 

equipment that will likely be installed to comply with the MPS. 

The EGUs identified in this notice of intent have commenc-ed commercial operation on or befOre December 

31, 2004 and constitUte all affected EGUs that were owned by the listed affiliates as of July 1, 2006. 

I am authorized to make this submission on behalf of the owners and operators of the affected unlts for 

which this submission is made. Please contact Steven Wlritworth at (314) 554-4908 if you have any 

questions concerning thjs submittal or if additional information is required. 

Sincerely, 

.{1£127 

President, Ameren Energy Generating Company 

President, AmerenEnergy Resources Generating COmpany 

Director and Chairman, Electric Energy, lac. 

SCW/AEGAERGEEI_ MPSnotice 

Attachments 
rnrr • ., 

Coffee 

le 

Je_ 

. Facility 

Duck Creek 

E. D. Edwards 

E. D. Edwards 

E. D. Edwards 

Facility 

Joppa 

Joppa 

Joppa 

Joppa 

Joppa 

Joppa 

Ameren Energy Resources Company 

Multi-Pollutant Standard Notice oflntent 

Attachment A 

Summary of Existing Pollution Control Equipment 

Ameren Energy Generating Company 

I 

'LD. 

:AA 

t Unit 

ESl 

~Control N< 

_<: ~ "iV"'---"" 

ESJ 

06 ESP 

01 ESP 

I. 02 ESP 

l ,A 03 ESP 

137 04 ESP 

13" 05 ESP LNB 

07l ESP OFA ."NR 

2 ESP OFA!LNB 

AmerenEnergy Resources Generating Company 

Facility]. D . Emission Unit Particulate Control NOxControl 

057801AAA I ESP LNB/SCR 

143&05AAG I ESP LNB 

143805AAG 2 ESP LNB 

143805AAG 3 ESP OFAILNB/SCR 

Electric Energy, Inc. 

Facility L D. EmiSsion Unit hrticulate Control NOx Control 

127855AAC 1 ESP LNB 

127855AAC 2 ESP LNB 

127855AAC 3 ESP LNB 

127855AAC 4 ESP LNB 

127855AAC 5 ESP OFA!LNB 

127855AAC 6 ESP OFAILNB 

802 Control 

802 Omtrol 

FGD 

802 Control 
Ameren Energy Resources Company 

Multi-Pollutant Standard Notice oflntent 

Attachment B 

Base Emission Rate Determination . 
Ameren MPS Base Annual Emission Rate Detennination 

2003 Heat Input 

Company lmmBtu) 

AEGC 158;452,698 

AERGC 63,611,097 

EEl 89,504,514 

AER Illinois 311,568,309 

2004 Heat Input 

Company CmmBtul 

AEGC 171,427,867 

AERGC 70,737,248 

EEl 92,482,478 

AER Illinois 334,647,593 

2005 Heat Input 

Company (mmBtu) 

AEGC 160,864,003 

AERGC 65,569,490 

EEl 86,505,712 

AER lilinois 312,939,205 

Annual Average Heat Input 

Company (mmBtu) 

AEGC 163,581,523 

AERGC 66,639,278 

EEl 89,497,568 

AER lllinois 319,718,369 

MPS Rates 

NOx at 0.11 or 52% of base rate in 2012 

S02 at 0.33 or 44% of base rate in 2013 

S02 at 0.25 or 35% of base rate in 2015 

NOx Rate 

(#/mmBtu) 

0.259 

0.368 

0.129 

0.244 

NOxRate 

f#/mmBtul 

0.249 

0.309 .. 

0.127 

0.224 

NOx Rate 

(#/mmBtu) 

0.253 

0.261 

0.128 

0.235 

NOxRate 

(#/mmBtu) 

0.243 

0.312 

0.128 

0.225. 

%of base rate 

0.117 

NOx 

jtons) 

20,527 

11,690 

5,771 . 

37,988 

NOx 

(tons) 

20,710 

10,897 

5,860 

37,467 

NOx 

(tons) 

18,494 

8,619 

5,524 

32,637 

NOx 

(tons) 

19,910 

10,402 

5,718 

36,031 

S02 Rate 

(#/mmBtul 

1.14 

2.06 

0.54 

1.15 

S02 Rate 

1#/mmBtul 

1.06 

1.47 

0.61 

1.02 

S02 Rate 

(#/mmBtu) 

1.04 

1.22 

0.60 

1.01 

S02 Rate 

(#/mmBtul 

1.08 

1.58 

0.58 

1.04 

% of base rate 

0.46 

0.36 

S02 

[tons) 

90,117 

65,440 

24,026 

179,583 

5021 

(tons) 

90,532 

52,058 

28,Q48 

170,638 

S02 

(tons) 

.83,905 

39,999 

25,963 

149,867 

S02 

(tons) 

88,185 

52,499 

26,012 

166,696 
Ameren MPS Base Seasonal NOx Emission Rate Determination 

2003 Heat Input 

Company {mmBtu) 

AEGC 71,819,229 

AERGC 26,917,427 

EEl 37,416,091 

AER Illinois 136,152,747 

2004 Heat Input 

Companv (mmB!ul 

AEGC 72,205,935 

AERGC 30,512,335 

EEl 30,951,063 

AER Illinois 133,669,333 

2005 Heat Input 

Comp~ny {mmBtul 

AEGC 77,068,042 

AERGC 28,277,603 

EEl 37,004,541 

AER Illinois 142,350,186 

Seasonal Average Heat Input 

Company (mmBtu) 

AEGC 73,697,735 

AERGC 28,569,121 

EEl 35,123,898 

AER Illinois. 137,390,755 . 

MPS Rates 

NOx at 0.11 or 80% of base rate in 2012 

NOx Rate 

{#/mmBtu) 

0.159 

0.255 

0.126 

0.169 

NOx Rate 

(#/mmBtu) 

0.153 

0;180 

0.126 

0.153 

NOxRate 

_(#/mmBtu) 

0.146 

0.170 

0.126 

0.147 

NOx Rate 

(#/mmBtu) 

0.152 

0.200 

0 .. 126 

0.155 

% of base rate 

0.124 

NOx 

(tons) 

5,706 

3,427 

2,359 

11,492 

NOx 

!tonsl 

5,508 

2,750 

1,956 

10,214 

NOx 

(tons) 

5,614 

2,397 

2,328 

10,339 

NOx 

{tons) 

5,609 

2,858 

2,214 

10,682 
p, r;" 

r 

r 

Duck Cree~ 

E. D. 

E. D. 

E. D. 

Facility 

Joppa 

Joppa 

Joppa 

Joppa 

Joppa 

Joppa 

Ameren Energy Resources Company 

Multi-Pollutant Standard Notice oflntent 

Attachment C 

Summary of Likely Future Pollution Control Equipment 

Ameren Energy Generating Company 

[ .Unit N< :Control 

) 

o3: lCI (201: OF A. ."NR 

o3; ACq~UL OF A. ."NR 

137 OJ .. Arlf?OP 

13~ {)2 ACI (2013) 

13~ 03 ACI (2013] 

137RO~AA. ()4 ACI(2013) 

J37RO,AA. 05 ACI (2009) OFAILNB 

079 AC1(2009) OF .A 

079 2 ACI{2009] ur" 

AmerenEnergy Resources Genera-ting Company 

I Unit 'LOlltrOI NC : Contr<>l 

AC1(20 ( 

<OU A<T AC!(20 ( 

.Rn<;AA( ACI(2C OF, 

Electric Energy, Inc. 

Facility I. D, Einissiort Unit Mercury Control NOxControl 

!27855AAC 1 ACI(2009) OFA/LNB 

127855AAC 2 ACI(2009) OFAILNB 

!27855AAC 3 ACI(2009) OFAJLNB 

l27855AAC 4 ACI (2009 OFAJLNB 

JZn55AAC 5 ACI(2009 OFAJLNB 

127855AAC 6 ACI (2009 OFA!LNB 

so~ 

FGD 

. 

FGD 

FGD 

S02 Control 

FGD 

FGD 

802 Control 

FGD 

FGD 

FGD 

FGD 
Exhibit 5 

Affidavit of Gary M. Rygh 
AFJITDA VIT OF GARY M. RYGH 

I. BACKGROUND AND QUALIFICATIONS 

1. My name is Gary M. Rygh. I am employed by Barclays Bank PLC (Barclays) in 

the investment banking division. With over 300 years of history and expertise in banking, 

Barclays operates in over 50 countries and employs over 140,000 people. Barclays provides 

large corporate, government and institutional clients with a full spectrum of solutions to their 

strategic advisory, financing and risk management needs. Barclays is one of the largest financial 

. services providers in the world, and is also engaged in retail banking, credit cards, corporate 

banking, and wealth and investment management. 

2. I am currently a Managing Director in the Global Power and Utility Group. Our 

group is responsible for the corporate finance analysis of, and strategic and capital markets 

transactions related to the utility and power sectors. I have been in the utility, power and energy 

investment banking business for approximately 17 years. I have worked extensively on strategic 

merger and acquisition assignments, debt and equity capital markets transactions, and other 

corporate fmance related assignments in the electric, water and gas utility sectors. I have a 

Bachelors of Science degree in Commerce, with a concentration in Finance from the University 

of Virginia. 

3. The purpose of my testimony is to provide a comprehensive overview of the 

significant challenges faced by the unregulated merchant generation subsidiaries of Ameren 

Corporation (Ameren) and how these challenges have severely limited the ability of those 

subsidiaries to access third party capital for the purposes of continued investment in state and 

federally mandated environmental control equipment. Ameren's unregulated merchant 

generation subsidiaries consist of the subsidiaries of Ameren Energy Resources (AER), including 
Ameren Energy Generating Company (GENCO), AmerenEnergy Resources Generating 

Company, and Electric Energy, Inc. 

ll. THE CURRENT FINANCIAL CONDITION OF AMEREN ENERGY 

RESOURCES AND ITS SUBSIDIARIES 

4. The deteriorating fmancial condition of AER coupled with the continued bearish 

commodity price outlook and uncertain regulatory landscape combine to prevent AER from 

being able to access any meaningful amount of additional third-party capital. Compounding this 

distress is the uncertainty regarding federal environmental regulations as well as the stringent 

state environmental mandates in lllinois that AER must comply with. The lack of flexibility and 

accelerated timeline required by the state of Illinois for the purchase and installation of 

environmental control equipment provides Ameren and AER with little flexibility in managing 

the credit quality, cash flows and the fmancial health of AER and its subsidiaries. Through cost 

reductions and continued investment by Ameren, AER has been able to complete the majority of 

capital expenditures required to comply with both state and likely federal mandates, however the 

excess stringency of the lllinois standards and shorter timeframe required for state compliance 

has hastened the deterioration of the fmancial health of AER. Further, the deterioration in the 

financial health of subsidiaries such as AER and a dire outlook for financial prospects, could 

very well inhibit the motivation of parent companies such as Ameren Corporation to continue 

investing in merchant generation businesses. 

5. AER continues to face significant headwinds that have caused a substantial 

deterioration in credit quality, value to Ameren shareholders and ultimately the ability of AER to 

independently fmance capital expenditures and cash flow shortfalls. AER is a merchant power 

generator with significant exposure to market prices, swings in load demand and commodity 

price volatility. AER' s gross margin is subject to fluctuations in highly volatile wholesale 

2 
energy prices, correlations between power and fuel, and broad macroeconomic supply I demand 

dynamics. Given this market exposure to continued weak natural gas and power prices, 

shrinking margins and increasing environmental obligations, AER's financial health and access 

to capital have both been severely degraded. While the last several years have been difficult for 

AER, the current outlook is no better. Moody's in its report entitled "Low Natural Gas Prices 

Herald Long-Term Changes in US Energy Infrastructure" stated: "Low natural gas prices will 

keep margins and cash flow under pressure for most unregulated power producers-particularly 

for those that generate electricity using coal, nuclear power or hydropower. Historically, power 

producers have used natural gas to meet peak electric demand, which typically determines the 

price at which these companies sell electricity. Low natural gas prices have encouraged gas· 

fired power production in North America, adding to the pressure on coal-fired plants, which face 

increasing environmental restrictions. We expect meaningful increases in fuel switching 

throughout Nonh America, with natural gas plants favored over coal. Most unregulated power 

producers continue to hold a "hunker-down" strategy, conserving capital and liquidity in the 

hope of higher prices for electric power and natural gas. But even though most issuers have 

good cash reserves and undrawn credit facilities, current market conditions might outlast 

liquidity."- April2012 

6. As shown in the Table 1 below, GENCO (AEG), AER's only rated subsidiary, 

has seen its credit rating cut 3 notches by Standard & Poor's (S&P) and 4 notches by Moody's 

Investor Services (Moody's) since 2008. The downgrades have been attributable, in large part, 

to a precipitous decline in net income and cash flow during that time period. AER's net income 

declined by 85% between 2008 and 2011, and a further decline in net income of up to 100% 

from 2008 is expected for 2012. 

3 
-.~ ;. __ ,_ .. ... ,_ . -- ·-

... 1ab~5}<~i~:~il~~~s! :.·":'· .. ·····:: . --.-· . •... ····.·\· ' ·' 

,~. 

. . .. ' . ····· .... ' .. :,,, .. 

2008· 2009 2010 2011 Current 

Forecast 

S&P Rating BBB-1 Stable BBB-1 Stable BBB-1 Stable BBB- I Stable BB-/ 

/Outlook Negative 

Moody's Baa2 I Stable Baa3 I Stable Baa3 I Stable Baa3 I Stable Ba31 

Rating I Negative 

Outlook 

Net Income $352 $247 -$409 $45 $0 

The 2010 net loss includes a $522 million after-tax asset impairment charge. The charge was 

recorded because management concluded that the carrying values of certain merchant generation 

segment assets, including goodwill, intangible assets, and fixed assets, likely would not be 

recoverable. The decline in the estimated value of these assets that led to recognition of the 

impairment charge was driven primarily by a sustained decline in market prices for electricity. 

Excluding the asset impairment charge, 2010 net income would have been $113 million. 

7. AER and its subsidiaries have been some of the worst performing companies in 

their sector due to high reliance on coal fired generation and lack of fuel and market 

diversification. While the total capacity of AER when measured in megawatts is approximately 

70% coal-fired the actual energy production and related gross margin are well over 90% derived 

from its coal fired plants. Moody's also said recently "The ongoing shift in natural gas prices 

reflects a permanent change across the US energy sector, and will make it more difficult for coal 

to compete with natural gas as a power source in the future. A rise in gas-fired power generation 

will not be strong enough to raise natural gas prices on a sustained basis."- April 2012 

4 
8. Taking market share from coal has represented the· marginal demand in the gas 

market for the past four years and will likely play a strong role in setting prices in the next few 

years. We receive many calls from clients who, when looking at spot coal and gas prices, 

wonder why gas is not displacing substantially more coal. After all, it would appear that gasfrred units run at substantially lower utilization rates than their coal counterparts, implying that 

underutilized gas-fired capacity can knock more coal out of the market. Gas prices have been 

falling relative to coal spot prices, especially after considering rail charges for coal, which are 

compounded by distance and strong diesel prices. If one were simply to compare the costs of 

producing a megawatt-hour (Mwh) of power from a coal plant using delivered spot coal prices in 

January 2012 with the cost of producing that same MWh from a gas-frred unit using delivered 

spot Henry Hub prices for the same month, the result would suggest that gas should be idling 

almost all coal. In reality, it is not the most efficient gas-fired unit standing ready to displace the 

least efficient coal-burning plant. The least efficient coal plant seldom operates, whereas the 

more efficient gas-fired units are likely running already. During light load periods (i.e., spring 

and fall) many coal units are idle, requiring gas prices to fall further to displace the cheaper-tooperate coal plants. Likewise, during peak demand periods (i.e., summer and winter), power 

demand may be high enough to require the near-full utilization of gas-burning units, leaving little 

spare capacity with which to displace coal plants. There is a high degree of load dependency 

and, therefore, seasonality to coal displacement. In the market, it is a continuum of gas and 

coal unit efficiencies vying for the marginal MWh. 

9. The biggest driver of coal displacement and, therefore, the inability to source 

capital for investment in coal-fired generation is the cost of coal itself. There is quite a range of 

delivered coal prices in the US, owing to differing contract terms, transportation rates that 

5 
generally vary by distance, and a host of other factors. Transportation costs add considerably to 

the delivered cost of coal. For Powder River Basin (PRB) coal, transportation costs are often 

more than the cost of the coal itself, on a dollar per ton basis. With distance comes more cost, as 

transport is often miles-dependent. Complicating matters is the fact that the bulk of the coal in 

the US is sold under term contracts. PRB coal competes with natural gas at prices of 

$4.00/MMBtu and higher. But at prices below $3.00/MMBtu, natural gas begins to displace 

PRB coal at utilities in the US Midwest, south-central and eastern regions, due to transportation 

costs and available natural gas capacity. AER bums predominately Powder River Basin coal not 

lllinois Basin coal because environmental compliance requires it. 

10. Unregulated power companies are more challenged by steadily increasing 

environmental mandates than their regulated utility peers. These regulations increase the 

operating costs of fossil fueled generation. Unlike regulated utilities, which can recover the costs 

of environmental regulations through authorized rates, unregulated power companies can only 

recover their costs through market driven prices and margins. Among the unregulated power 

companies, firms with coal-fired generating assets are at a significant financial disadvantage 

relative to companies with less carbon-intensive portfolios. Table 2 below demonstrates the 

disadvantage AER as well as coal-based companies like AER are facing. When comparing the 

cost to borrow additional debt capital, represented by the current yields on intermediate term 

bonds, AER and its peers face considerably higher costs even if the capital was available. As 

can been seen in Table 2, merchant generators that are less carbon intensive, including Calpine 

and Exelon Generating, enjoy a significant capital cost advantage. 

6 
,,,, ,,:>c'''' ' ' ' ' A, ,,JableZ:' ',•,,,,,,,,,,, ,c~!~~''•ic;;;f,Ci;,,'':; ,F ;}c:;•/t f ,·;,;; ,;,',,, 

_f, ' '' 

,,, ''• '; .,,,,,,,,,,,,,_,,.,_ ' . ' 

AER Edison Dynegy Calpine Exelon 

Mission Generating 

Yield 10.0% 17.1% 16.9% 6.5% 3.4% 

Credit Ba3/BB- Caa1/B- NRJD B1/BB- Baa1/BBB 

Rating 

III. INVESTOR AND RATING AGENCY ANALYSES OF AER 

11. The increasingly negative view of AER by credit rating agencies, Ameren 

shareholders, current bondholders and equity research analysts not only severely limits AER 

from accessing additional third-party capital but also inhibit Ameren from further investing in 

AER without the risk of severe negative investor reaction that could adversely impact cost and 

access to capital. The credit rating agencies have been very clear that the financial distress being 

experienced by AER and its· subsidiaries will have limited repercussions for Ameren and its 

regulated operations as long Ill' Ameren does not support AER and its subsidiaries through 

capital injections. In effect, the credit rating agencies assume the fmancial health and value of 

AER and its subsidiaries has been so greatly weakened that Ameren has limited incentive to 

invest additional capital in AER, therefore the credit ratings of the unregulated, regulated and 

parent entities are allowed to diverge significantly. 

12. In addition to credit rating agency prohibitions on Ameren' s continued financial 

support of AER and its subsidiaries, shareholders have been very disappointed by the returns 

from the capital already employed in AER and its subsidiaries. There is zero or negative value 

attributable in the current Ameren share price from AER and its subsidiaries despite the 

significant environmental and other investments already made which is a clear indication that 

equity investors have no desire to see Ameren deploy any additional financial resources to its 

7 
unregulated businesses. To illustrate the decline in investor confidence and support for AER it is 

useful to examine the recent trading performance of historically issued GENCO bonds. Table 3 

below highlights the trading prices for the outstanding bonds of GENCO at the beginning of 

2012 versus the current prices. 

GENCO Bond 7.00%-Due 4/2018 6.30%-Due 2/2020 7.95%-Due 6/2032 

Price on 11212012 $104.50 $102.25 $99.50 

Price on 5/112012 $86.63 $82.50 $81.50 

Change Since 1/2/2012 -$17.88 -$19.75 -$18.00 

13. The business conditions for the US unregulated power sector are poor with little 

expectation for near-term improvement. Unlike their regulated utility peers, unregulated power 

companies do not enjoy the benefits of recovery assurance for prudently incurred costs and 

investments. Instead, umegulated power companies can only tum to the markets to generate 

margins. Moreover, many of the factors that influence margin creation and sustained cash flow, 

such as gas commodity prices are beyond the control of Ameren or ·AER management. 

Operating costs are rising, along with capital expenditures. The costs of complying with 

increasingly restrictive environmental mandates are likely to introduce a shift in some generators 

strategic plans, as the differences in operating characteristics, volatility, liquidity requirements 

and capital structure formation among industry players becomes more evident. Additionally, 

umegulated power markets remain subject to political intervention, which appears to be a 

growing risk. These factors are primary drivers of the negative sentiment and outlook debt and 

equity investors have for AER. 

8 
14. Highlighted below in Table 4 and Table 5 below is the current commentary and 

summary conclusions by leading equity analysts that are responsible for providing independent 

guidance to large institutional and retail investors with regards to the power sector. 

-;-,;;_, -· _,-,_; 

-. _,. 

,-; __ _ 

-_,,-. 

''why would ~t~ri invest in Genco?·;j, · '-" ••. ·''''·''' '- ·is --~~:--):" -~.n~-,- ... )i~~{>i'~~~:·:~~r?~~?·'':' -- - ~--· co,•;,:'"·:· :::~~:t~: "YI_edg,not'as~igl{anyvalue to the merchant segment" _ ./', .-. , 

!~~z~=~~,::3~~~~~::~, ''o.uYprim~coricernaboutthe companY remains ,A'!fibfen 's merchant gene~atiod ~~~osura··: · _ -._.· "' . 

~~#~~~~~~~~~1;"'i; )Y;7,.~i; encolll'ilged oy Am_erens' s giq~i~g regulated ~f!~ttuctur~ iny~enen(o,Pj)Ortuhlti~iuid mitigation . effl)rts at Merc,)!ant (cqst con(rols, lower CapE!<),Il:oWever, we beheve shates aq~quately reflect theEPS o_utlook. 

O¥f valua,~ii.ti'.iimge ()f]3~t'33t~hare reflectd"35iSif~e-for the regulated op_I:Iations·a:n!l,~neg~!iYe·$2L3jshare.for ' 

~r~i~WW'- •X' {~'(' ·-. e':f~~~.-> -- --- ;·.;_ G,;,_,:'T't~- - '''!~~J~:.~r~"· --···--- --· ·C:W~:jlij'also_ "IJc~mraged h)' ul'!lated G~pllx disclos~ _ (J;i.i_gher transmi~~<ilt._antl)o,.\'!'.Merchant)Z' . • "- 0_,.., .. <• ::'>:,;-~: ' ' .,,c;:J(-~?:·~;~;~->'""- . --~:c-- - ~--:~_;;;.:-

- ---'~-.'-, 

Table 

-$30 

NA 

-$750 

-$600 -$145 

9 
15. The credit rating agencies, whose views are critical to providers of debt capital, 

not only have a negative view on the credit quality of AER but have also made it abundantly 

clear that further support from the parent Ameren will have negative consequences on the credit 

quality of Ameren and its other subsidiaries. Below are some recent examples that reflect the 

substance of their views. 

Credit Rating Agency Views Regarding Financial Condition, Liquidity, Asset 

Value and Outlook 

"GenCo's margins have steadily declined due to lower demand because of the recession and by an 

increased supply of natural gas from shale gas that have contributed to lower natural gas prices. 

While GenCo continues to manage those areas that it can directly influence, such as reducing 

capital spending, maintaining its hedging program. and reducing its operation and maintenance 

(O&M) costs, sustained weak power prices will pressure its cash flow over the intermediate term. 

Furthermore, the prolonged weakness of the power markets, particularly the flattening of the 

forward curve, reduces the value of GenCo's hedging strategy to protect it from weak power 

prices. While GenCo's three-year hedging strategy provides a degree of price insulation over the 

short term. sustained depressed power prices wouid eventually undermine this credit 

enhancement'". (S&P March 2012) 

~·we view Ameren's recent decision to significantly reduce its environmental capital spending at 

GenCo as prudent from Ameren Corp.'s perspective but believe the reduction adds considerable 

credit risk to GenCo. This decision will provide Ameren management with additional time to 

reevaluate its options and to assess its ability to meet federal and state environmental regulations 

even in the possible absence of a scrubber at Newton. However, the reduction of environmental 

capital spending also suggests management's lack of confidence in the longer-term economic 

sustainability of GenCo's business model. This reinforces our view that Ameren's support for 

GenCo is limited and that it expects GenCo to cover its cash needs as a stand-alone business even 

over the short term'". (S&P March 2012) 

"The downgrade of Ameren Genco's ratings reflects the worsening jino.ncial prospects for this 

predominantly coal-fired generating company as low power prices, higher fuel and transportation 

expenses, and EPA mandated environmental compliance requirements negatively affect the 

company's margins and cash flow generating ability", said Michael G. Haggartjl, Senior Vice 

President. Moody's expects cash flow coverage metrics to continue to exhibit declining trends for 

at least the next two years, with any· improvement in subsequent years highly dependent on a 

recovery in power prices, which may not occur. Last week, Ameren Genco announced drastic 

cutbacks in its environmental compliance expenditure program. specifically related to 

deceleration and possible cancellation of scrubber installation at its Newton plant, which could 

hamper the ability of the company to fully dispatch its merchant generation fleet as early as 2015, 

when Illinois multi-pollutant standards tighten. Although Ameren Genco does not have any longterm debt due until 2018, it may need to finance negative free cash jlow in the interim with 

additional borrowings, the extent of which will depend on whether it decides to again move 

forward with the Newton scrubber project. The company maintains adequate liquidity 

predominantly as a result of a $500 million joint credit facility with the parent company that 

matures in September 2013. Moody's notes that Aineren may not be able to refinance the Ameren 

Genco bank credit facility on an unsecured basis without a parent company guarantee when it 

comes up for renewal next year. Moody's would expect the credit facility renewal to be addressed 

well before the September 2013 maturity date. The negative outlook on the ratings of Ameren 

10 
Genco reflects the low power price environment, the likelihood of further deterioration in 

financial metrics, anticipated weak cash flow generation for the next several years. the lack of a 

viable capacity market in MISO, the high degree of uncertainty regarding the status of the Newton 

scrubber project, and the possibility that the company's generating capability could be 

constrained beginning in 2015." (Moody's March 2012) 

"Without the liquidity provided by the Ameren guaranteed Put Option Agreement and the power 

sales and marketing support provided by Ameren Energy Marketing Company, Ameren Genco 

would exhibit much less financial flexibility in the face of continued low power prices, 

deteriorating financial metrics. environmental capital expenditures, as well as the lack of capacity 

payments in the market in which it operates. The execution of the Put Option Agreement provides 

Ameren Genco critical time for current power market conditions to improve before it decides on 

whether to resume the installation of scrubbers at its Newton power plan~ which it recently 

postponed." (Moody's Apri/2012) 

Credit Rating Agency Statements Regarding the Impact to Ameren of any 

Addition Support of AER or its subsidiaries 

"the reduction of environmental capital spending also suggests management's lack of confidence 

in the longer-term economic sustainability of GenCo's business model. This reinforces our view 

thot Ameren 's support for GenCo is limited and that it expects GenCo to cover its cash needs as a 

stand-a/nne business even over the short term." (S&P March 2012) 

"The downgrade also reflects Moody's view that the Ameren parent company has limited 

flexibility to support its merchant generating business" (Moody's March 2012) 

"Standard & Poor's Ratings Services' ratings on GenCo reflects its stand-alone credit profile with 

limited support from parent Ameren Corp." (S&P Apri/~2012) 

"The negative outlook on GenCo reflects our view that management's support for the merchant 

business is limited. Although Ameren could theoretically support GenCo during a period of 

financial stress, we believe that it would not do so to the detriment of the regulated utilities. As 

·such. we view Ameren 's support of GenCo as very limited and as a basis to separate the ratings." 

(S&P Apri/2012) 

"The affirmation also reflects Moody's view that the parent company has thus jar been unwilling 

to provide additional direct financial support to Ameren Genco. Other than sharing a joint bank 

credit facility and providing parent company counterparty guarantees on behalf of Ameren 

Energy Marketing Company, Ameren has thus jar not provided direct financial support to Ameren 

Genco. This was most recently demonstrated by the significant cutbacks in the Genco's 

environmental compliance expenditures announced last week. To the extent that Ameren does 

provide more material direct financial support or other guarantees to Ameren Genco, the parent's 

fating or rating outlook could be adversely affected." (Moody's March 2012) 

"The reduction from positive to stable rating outlook on Ameren takes into account the continued 

weakness at GenCo and Ameren's willingness to provide cash to shore up GenCo's liquidity." 

(S&P April2012 after the Put Option Agreement was disclosed) 

"The affirmation of the parent company also considers the relatively small contribution of Ameren 

Genco to Ameren's overall cash flow and risk profile compared to its regulated utility 

subsidiaries; and the parent's thus far limited and measured support for Ameren Genco and our 

expectation that it will not provide any material capital contributions or other direct financial 

support to this subsidiary" (Moady's March 2012) 

11 
IV. CONCLUSION 

16. The value destruction experienced by historically invested capital providers 

prohibits the ability to source new capital for AER. Ameren has invested in AER approximately 

$1.0 billion for capital expenditures to comply with environmental regulations .. However, over 

the same time period the value of AER to Ameren shareholders has diminished from what was a 

substantial portion of Arneren's share price to what most analysts estimated as less than zero 

currently. The current GENCO (AEG) bondholders have also experienced multiple credit rating 

downgrades in addition to the value of their bonds declining rapidly in recent months. Given the 

experience of previous investors, the prospects of sourcing additional third-party capital are 

bleak. 

17. Despite the persistent negative outlook and the current inability to source 

necessary third-party capital to complete the installation of environmental control equipment it 

should not be forgotten that while the financial health of AER and its subsidiaries is commodity 

sensitive it is also cyclical. Ameren and its shareholders have invested a significant amount of 

capital in AER over the last several years as the downturn in market conditions worsened. This 

capital could have been invested elsewhere or been used to raise the dividend to shareholders, yet 

the management of Ameren chose to weather increasing market headwinds in the face of 

shrinking support for AER while at the same time making the difficult decisions needed to 

reduce cost. It should not be lost upon those considering this variance that Ameren has invested 

considerable amount of capital to comply with state and federal environmental goals and has 

done so at the expense of short-t.erm shareholder value. When the market begins its inevitable 

recovery, the capital already spent to comply with state and federal environmental mandates will 

12 
allow AER and its facilities to be amongst the best positioned generating assets in the region. 

FURTHER, Affiant sayeth not. 

Subscribed and sworn to before me 

this _,i__ day of May 2012. 

MARGHERITA DeLJUISi-1 

Registration # 01 DE4842124 

l

!'Jew York County, State Jf New York 

1cense Expires 5(/t> ....,cs 

; 7 

13 
Exhibit 6 

Affidvit of Ryan J. Martin 
AFFIDAVIT OF RYAN J. MARTIN 

I. BACKGROUND AND QUALIFICATIONS 

1. My name is Ryan Martin. I am employed by Ameren Services Company as 

an Assistant Treasurer and Manager of Corporate Finance. My business address is One Ameren 

Plaza; 1901 Chouteau Avenue, St. Louis, Missouri, 63103. Ameren Services Company provides 

business and corporate services such as financing to Ameren Corporation and its subsidiary 

companies. 

2. I am responsible for managing . Ameren Corporation and its subsidiary 

companies' short-term and long-term financing activities, including debt and equity issuances 

and credit facility arrangements, monitoring the company's liquidity position and key credit 

metrics, monitoring compliance with our debt agreements, managing relationships with credit 

rating agencies and banks, and monitoring capital markets for key developments, emerging risks, 

and opportunities, among other corporate-finance related activities. I received my Bachelor of 

Business Administration degree, with a concentration in Accountancy, in 1995 from the 

University of Notre Dame. I received my Master of Business Administration degree, with 

concentrations in finance, marketing, and strategy, in 2004 from Northwestern University's 

Kellogg School of Management. 

3. I have over 16 years of experience in various audit, accounting, financial 

reporting, and fmance roles. I began my career in 1995 at Arthur Andersen LLP and worked in 

the firm's Audit and Business Advisory practice for six years. I left Arthur Andersen in 2000 to 

join Career Education Corporation, a Chicago-based public company that owns and operates forprofit, post-secondary schools. At Career Education Corporation, I managed the company's 
accounting and financial reporting functions and at various times was also responsible for 

accounts payable, payroll, and insurance. In 2007, I joined Ameren Services Company as 

Assistant Controller. In that role, I managed the Company's general accounting function and 

plant accounting function and was also responsible for accounting research and policy. In March 

of 2010, I transitioned to the Finance department and into my current position. 

II. AMEREN CORPORATE ORGANIZATION AND FINANCING STRUCTURE 

4. Ameren Corporation is a public utility holding company whose primary assets 

are the common stock of its subsidiaries including Ameren Missouri, Ameren lllinois, and 

Ameren Energy Resources. Appended to my affidavit as Attachment 1 is an organizational chart 

for Ameren Corporation and its principal operating companies. Ameren's subsidiaries are 

separate, independent legal entities with separate businesses, assets, and liabilities. AER consists 

of merchant generating operations including Ameren Energy Generating Company (GENCO), 

AER's only publicly registered and rated company, and Ameren Energy Resources Generating 

Company (AERG). The power generation business is capital intensive, and investments in 

pollution control equipment such as scrubbers for emission control typically cost hundreds of 

millions of dollars. Funding for capital projects can come from a variety of sources, including, 

among others, equity in the form of capital contributions or retained earnings and long or short 

term debt. For state rate-regulated companies such as Ameren Missouri, the costs of capital 

investments are ultimately expected to be recovered from rate payers through rates. In contrast, 

merchant generators such as AER are not assured receipt of state rate-regulated revenue streams 

from a captive customer base. While fixed-price power supply contracts may provide a limited 

degree of fmancial stability for AER, the revenues and profit margins of AER and most other 

merchant generators are based primarily on dynamic and competitive market-driven commodity 

2 
prices for, among other things, power and fuel, which can be highly volatile. Lenders consider 

the relative stability and predictability of revenue streams and cash flows in evaluating a 

company's creditworthiness and establishing borrowing and lending terms that are typically 

specified within a company's bond indentures or credit agreements. Third-party. lenders, 

including bondholders and banks, and credit rating agencies, such as Standard & Poor's and 

Moody's, typically consider, among other things, a projection of future power prices in assessing 

the creditworthiness of a merchant generator borrower as well as investment risk. As set forth in 

. more detail in paragraph 12, market prices for power have decreased dramatically over the last 

three years, which has impacted adversely AER's operating cash flows, its key credit metrics 

and ability to access, through AEG, external short-term and long-term capital markets. 

5. GENCO is a registered company with the Securities and Exchange 

Commission (SEC), and its financials are publicly reported. GENCO's predicament mirrors the 

financial predicament facing all of Ameren's merchant generation segment. As reported in 

Ameren's SEC filings and as noted in the chart below, combined net income for Ameren's 

merchant generation segment (including AERO, GENCO, AER) has dropped precipitously. 

2008 2009 2010 2011 

$352 $247 $ (409)* $ 45 

*The 2010 net loss includes a $522 million after-tax asset impairment charge. The charge was recorded because 

management concluded that the carrying values of certain merchant gen_eration segment assets, including goodwill, 

iotangible assets, and fixed assets, likely would not be recoverable. The decline in the estimated value of these assets that 

led to recognition of the impairment charge was driven primarily by a sustained decline in market prices for electricity. 

Excluding the asset impairment charge, 2010 net income would have been $133 million. 

AER net income is expected to decline significantly once again during 2012, from $45 million in 

2011 to between $0 and $25 million in 2012. Clearly, the depressed levels of AER earnings and 

cash flows, driven primarily by recent and continuing low power prices, are insufficient to fund 

large-scale capital projects such as the installation of scrubbers. 

3 
6. AER has taken a variety of steps during this recent and ongoing period of low 

power prices to conserve its cash and minimize its capital expenditures. In December 2011, 

Meredosia and Hutsonville ceased operations in lieu of the installation of pollution control 

equipment at facilities that are increasingly uneconomical. In addition, actual and forecasted 

cash outlays for GENCO's Newton scrubber project have been reduced dramatically. The pace 

of the Newton scrubber project has been significantly decelerated, and AER's ability to 

ultimately complete the project by 2015 is questionable given chronic unfavorable economic 

conditions. AER has expended considerable sums on pollution control-related projects. In fact, 

AER has spent in excess of one billion dollars on such capital investments, including the 

installation of expensive pollution control equipment at its Duck Creek, Edwards, Coffeen, and 

Newton energy centers. Such equipment includes scrubbers, SCRs and precipitators. AER has 

also constructed landfills and cooling basins and towers at its energy centers, for purposes of 

pollution control and compliance with applicable environmental standards. The long-term 

funding for these investments originated from two primary sources: a $425M unsecured intercompany loan to AER from Ameren Corporation and $825M in unsecured debt publicly issued 

by GENCO and held by bondholders. The maturity dates for these financing instruments range 

from 2014 to 2032, including two public debt issuances coming due in 2018 and 2020. As part 

of the bondholders' efforts to secure their investment and as a condition to financing, restrictive 

covenants within GENCO's bond indenture impact the ability to secure additional debt 

financing from external sources. Those restrictions are described below. 

ill. DEBT COVENANTS IMPACT GENCO'S BORROWING CAPABILITY 

7. Certain covenants within GENCO's bond indenture restrict GENCO's ability 

to incur addition indebtedness from external sources. Specifically, GENCO is prohibited by its 

4 
bond indenture covenants from borrowing additional funds from external, third-party sources if 

its interest coverage ratio is less than a specified minimum (2.5) or its leverage ratio is greater 

than a specified maximum (60%). GENCO's earnings and operating cash flows have been 

adversely affected by changes in the market price for power, which have significantly decreased 

over the last few years. In fact, based on management's projections of future earnings and cash 

flows, which are driven largely by current forward power price assumptions, it is expected that 

by the end of 2012, GENCO's interest coverage ratio will fall below the minimum level required 

for GENCO to incur additional external debt. Therefore, unless power price market conditions 

improve dramatically in the near term, GENCO will not be able to borrow additional funds from 

third-party lenders to finance, among other capitai projects, the installation of scrubbers at 

Newton. Note that AER and AERG are not publicly registered companies, nor are they rated by 

credit rating agencies. Consequently, they have no direct access to public financial markets. 

8. AER, GENCO, and AERG are participants in Ameren's non-state regulated 

utility money pool. In the past, this money pool, under which short-term intercompany loans 

may be available, has served as a source of short-term debt capital for companies within 

Ameren's merchant generation segment. While money pool borrowings are not restricted under 

the terms of GENCO's bond indenture, money pool borrowings are subject to Ameren control, 

and the availability of money pool funds is based on Ameren review of facts and circumstances 

existing at the time of any borrowing request. As addressed in further detail in Mr. Gary Rygh's 

affidavit, given the poor recent financial performance of Ameren's merchant generation segment 

and the bleak financial prospects for the business in light of, among other things, the current 

outlook for future power prices, Ameren has virtually no fmancial motivation to provide 

additional capital to AER In fact, any additional investment or other direct financial support 

5 
provided by Ameren for its merchant generation segment would likely weaken the perceived 

creditworthiness and credit ratings of Ameren. . For these reasons, among others, Ameren 

management expects AER to fund its own operations without additional financial support from 

Ameren and, given the current outlook for the merchant generation business, Ameren is unlikely 

to provide additional debt or equity capital to AER. 

IV. GENCO BOND MATURITIES 

9. As noted above, GENCO has approximately $825 million in long-term public 

bonds outstanding. Approximately $300 million of this debt matures in 2018, and approximately 

$250 million of this debt matures in 2020. Generally, GENCO would plan to refinance these 

bonds in the public market and extend the maturity of the debt. However, if GENCO interest 

coverage ratios do not improve materially by 2018, indenture borrowing restrictions will prohibit 

GENCO from refinancing the 2018 maturity, and the $300 million will have to be repaid to 

bondholders. An inability to repay the bonds when due would constitute an event of default 

under the GENCO bond indenture, which would likely lead to a GENCO bankruptcy. The same 

is true for the 2020 maturity. An inability to refinance or repay the 2020 maturity would likely 

result in a GENCO bankruptcy. Given these pending maturities, a weak financial forecast, and 

covenant provisions that are expected to restrict GENCO's ~ccess to deb capital market, it is 

vitally important that GENCO preserve cash until market prices recover, operating results and 

cash flows improve, and borrowing capacity is restored. Failure to do so could threaten the longterm viability of the business and result substantial losses for all AER stakeholders, including 

both investors and those in the communities in which AER plants operate. 

6 
V. CREDIT RANKING IMPACTS GENCO'S BORROWING · COST AND 

CAPABILITY 

10. Long-term financing of environmental expenditures for Ameren's Illinoisbased merchant generation business segment is dependent in large part on tbe financial 

performance, fmancial outlook, and overall creditworthiness of GENCO. Note that since 

February 28, 2012 and as described in Mr. Gary Rygh's Affidavit, both Moody's and Standard 

and Poor's have downgraded GENCO's senior unsecured credit rating three notches, from 

Baa3/BBB- to Ba3/BB-, largely due to the decline in power prices and the resulting adverse 

impact on recent and expected future interest coverage metrics. Each report outlines, among 

otber things, key challenges GENCO is facing and tbe significant adverse impact of tbose 

challenges on GENCO's credit profile. The summary below shows the relative placement of 

current GENCO senior unsecured credit ratings on tbe credit rating scales used by Standard & 

Poor's and Moody's. 

GENCO's Credit Ratings 

(Standard and Poor's and 

Moody's) 

Standard and Poor's ~oody's 

Senior Unsecured Senior Unsecured 

Credit Ratings Credit Ratings 

AA+ Aal 

AA Aa2 

AA- Aa3 

A+ AI 

A A2 

A3 

BBB+ Baal 

BBB Baa2 

BBB- Baa3 

7 

~ 

!i 

E 

~ 

-" 
11. GENCO's recent rating downgrades have relegated GENCO's credit rating to 

non-investment grade ')unk" status, which adversely impacts financing costs and capital market 

access. The following except from a recent Standard and Poor's credit report (appended hereto 

as Attachment. i) summarizes the market pressures facing the AER's merchant generation 

business. 

"GenCo's fair business risk profile reflects its ultimate dependence on the market 

price of electricity, which has recently sharply declined. GenCo's margins have 

steadily declined due to lower demand because of the recession and by an 

increased supply of natural gas from shale gas that have contributed to lower 

natural gas prices. While GenCo continues to manage those areas that it can 

directly influence, such as reducing capital spending, maintaining its hedging 

program, and reducing its operation and maintenance (O&M) costs, sustained 

weak power prices will pressure its cash flow over the intermediate term. 

Furthermore, the prolonged weakness of the power markets, particularly the 

flattening of the forward curve, reduces the value of GenCo's hedging strategy to 

protect it from weak power prices. While GenCo's three-year hedging strategy 

provides a degree of price insulation over the short term, sustained depressed 

power prices would eventually undermine this credit enhancement. This could 

lead Standard & Poor's to revise GenCo 's business risk profile to "weaR; " 

almost certainly resulting in a ratings downgrade. 

We view Ameren 's recent decision to significantly reduce its environmental 

capital spending at GenCo as prudent from Ameren Corp. 's perspective but 

believe the reduction adds considerable credit risk to GenCo. This decision will 

provide Ameren management with additional time to reevaluate its options and to 

assess its ability to meet federal and state environmental regulations even in the 

possible absence of a ·scrubber at Newton. However, the reduction of 

environmental capital spending also suggests management's lack of confidence in 

the longer-term economic sustainability of GenCo's business model. This 

reinforces our view that Ameren 's support for GenCo is limited and that it expects 

GenCo to cover its cash needs as a stand-alone business even over the short 

term. II 

8 
VI. POWER PRICES CONTINUE TO DECLINE 

12. Power prices are the most significant driver of AER revenues and, along with 

fuel prices, the most significant driver of AER operating margins and cash flows. Power prices 

began a precipitous drop in July 2008, have continued to fall, and are not expected to improve in 

the near to immediate term This drop in power prices, along with an increase in fuel costs, has 

resulted in a sharp decline in AER operating margins and· cash flows available to cover operating 

costs and capital investment. 

Market Prices 

(in millions) 

$50 .--------------------

$45 

$40 

$35 

$30 

$25 

I $20 

-+-$/MWh 

+-------'\-----~--------- (Illinois 

2007 2008 2009 2010 2011 2012 

market 

prices) 

Given AER's inability to source financing from external sources and the lack of motivation for 

Ameren to provide additional financial support, AER operating margins and cash flows represent 

AER's only mechanism for funding both operating activities and capital investment. As noted 

above, AER's operating margins and cash flows are driven primarily by market prices for power. 

If power market prices remain depressed, as expected, internally-generated earnings and cash 

flows will be insufficient to fund major capital projects, including those required for 

9 
environmental compliance. Ameren Corporation, which must balance the credit and lending 

needs of all of its operating companies and deploy capital in an efficient manner, will not t take 

on additional unsecured debt in the absence of a secure revenue stream to support such an 

obligation, nor will it provide to its merchant generation segment additional equity or debt 

capital in the absence of financial prospects that support such an investment. As a result, if the 

power market does not improve, and AER does not receive the variance relief requested, there 

are no viable financing mechanisms to fund the installation of the Newton scrubber, and AER 

would need to resort to extreme operational curtailments to comply with existing standards, 

likely including, but not limited to, the mothballing of units at the Joppa, Edwards, and/or 

Newton energy centers. 

FURTIIER, Affiant sayeth not. 

DATED: 

CH2\2942903 I 

CH2\111521821\04.04.12 

PubfiC 

10 
Attachment 1 
Union Electric Company 

(M0)(100%) 

1901 Chouteau Ave. 

St. Louis, MO 63103 

Ameren Corporation 

1901 Chouteau Avenue 

StLouis, MO 63103 

Ameren Illinois 

Company (IL) (100%) 

300 Liberty St. 

Peoria,IL 61602 

Ameren Services 

Company 

(MO) (100%) 

1901 Chouteau Ave. 

St. Louis, MO 63103 

Ameren Transmission 

Company (MO) (100%) 

1901 Chouteau Ave. 

St. Louis, MO 63103 

Ameren Transmission 

Company of Illinois 

(IL) (100%) 

1901 Chouteau Ave. 

Sl. Louis, MO 63103 

Ameren Energy R

Company, L

(DE) (100%

1901 Chouteau 

St. Louis, MO 6

L 

Amare

Resource

Comp

300 Ub

Peoria

Ameren E

and Servic

(IL) 

1901 Cho

St. Louis

Amere

Marketin

(IL) 

1110 G

St. Louis

Rule 56 

Amere

Generatin

(IL) 

1901 Cho

St. Louis

Electric 

Inc. (I

2100 

R

Joppa, 
Attachment 2 
Research Update: 

AmerenEnergy Generating Co. 

Ratings Lowered And Placed On 

CreditWatch Negative 

Primary Credit Analyst: 

Gabe Grosberg, New York (1)212-438-6043;gabe_grosberg@standardandpoors.com 

Secondary Contact: 

Gerrit Jepsen, CFA, New York (1)212-438-2529;gerritjepsen@standardandpoors.com 

Table Of Contents 

Overview 

Rating Action 

Rationale 

Credit Watch 

Related Criteria And Research 

Ra rings List 

www.standardandpoors.com/ratingsdirect 1 
Research Update: 

AmerenEnergy Generating Co. Ratings Lowered 

And Placed On CreditWatch Negative 

Overview 

• U.S. energy company AmerenEnergy Generating Co. recently disclosed that 

it expects its ability to borrow additional funds from external third 

parties as of March 31, 2013, will be limited. 

• We are lowering our corporate credit and senior unsecured debt ratings on 

ArnerenEnergy Generating to 'BB- 1 from 'BB 1 • 

• We have placed the ratings on CreditWatch with negative implications. 

• The CreditWatch negative placement reflects the 1 in 2 probability that 

we will lower our ratings on the company in the very near term. 

Rating Action 

on March 5, 2012, Standard & Poor's Ratings Services lowered its corporate 

credit and senior unsecured debt ratings on AmerenEnergy Generating Co. 

(GenCo) to 'BB-' from 'BB' and Placed the ratings on CreditWatch with negative 

implications. The •3• recovery rating on GenCo's seni~r unsecured debt, 

indicating expectations of meaningful (50%-70%) recovery in the event of 

payment default, is unchanged. 

Rationale 

We view AmerenEnergy Generating Co.'s (GenCo) recently disclosed projected 

inability to borrow additional funds from third parties as of April 2013 as a 

material ratings constraint. Absent GenCo's ability to borrow from third 

parties, GenCo would most probably not be able to absorb high-impact, 

low-probability events without parental support. Unless management presents a 

very credible plan to avert this scenario, we would revise our assessment of 

GenCo's liquidity to "less than adequate 11 from "adequate" (as our criteria 

define the terms), which would lead to a further downgrade. 

Our 'BB-' corporate credit rating on GenCo is based on its "fair 11 and 

"aggressiv..e" (as our criteria define the terms) business risk and financial 

risk profiles. Additionally, our 'BB-' corporate credit rating on the company 

continues to assume a very limited degree of support from parent Ameren Corp. 

Furthermore, low power prices suggest that Ameren's economic incentive to 

support GenCo is diminishing and thus we may decide to rate GenCo based on its 

stand-alone credit quality. In such a scenario, we would likely lower our 

corporate credit rating on GenCo further. 

GenCo's fair business risk profile reflects its ultimate dependence on the 

market price of electricity, which has recently sharply declined. GenCo's 

Standard & Poors I RatingsDirect on the Global Credit Portal I March 5, 2012 2 
Research Update: AmerenEnergy Generating Co. Ratings Lowered And Placed On Credit Watch Negative 

margins have steadily declined due to lower demand because of the recession 

and by an increased supply of natural gas from shale gas that have contributed 

to lower natural gas prices. While GenCo continues to manage those areas that 

it can directly influence, such as reducing capital spending, maintaining its 

hedging program, and reducing its operation and maintenance {O&M) costs, 

sustained weak power prices will pressure its cash flow over the intermediate 

term. Furthermore, the prolonged weakness of the power markets, particularly 

the flattening of the forward curve, reduces the value of GenCo's hedging 

strategy to protect it from weak power prices. While GenCo 1 s three-year 

hedging strat·egy provides a degree of price insulation over the short term, 

sustained ·depressed pOwer prices would eventually undermine this credit 

enhancement. This could lead Standard & Poor's to revise GenCo's business risk 

profile to "weak, 11 almost certainly resulting in a ratings downgrade. 

We view Ameren's recent decision to significantly reduce its environmental 

capital spending at GenCo as prudent.from Ameren Corp.'s perspective but 

believe the reduction adds considerable credit risk to GenCo. This decision 

will provide Ameren management with additional time to reevaluate its options 

and to as.sess its ability to. meet federal and state environmental regulations 

even in the possible absence of a scrubber at Newton. However, the reduction 

of environmental capital spending also suggests management's lack of 

confidence in the longer-term econornic.sustainability of GenCo's business 

model. This reinforces our view that Ameren•s support for GenCo is limited and 

that it expects GenCo to cover its cash needs as a stand-alone business even 

over the short term. 

GenCo's financial risk profile is aggressive and reflects its stand-alone 

financial risk profile. The aggressive financial risk profile. also reflects 

Standard & Poor's base-case scenario of adjusted funds from operations (FFO) 

to total debt at about 15% and adjusted total debt to total capital at about 

50% over the next 12 months. For the 12 months ending Dec. 31, 2011, adjusted 

FFO to debt was 24.2% or higher than the 22.7% at year-end 2010, adjusted debt 

to EBITDA was 3.0x or slightly better from 3.1x at year-end 2010, and adjusted 

debt to total capital was 48.5% or improved from the 51.4% .at year-end 2010. 

Should power prices continue to remain weak, our stress-case scenario 

indicates that FFO to debt would decline to below 12% and we would revise 

GenCo's financial risk profile to highly leveraged and likely further lower 

our credit rating on GenCo. 

Even with the planned reduction in capital spending, we expect that GenCo's 

discretionary cash flow will turn negative and that it will meet its near-term 

cash needs through its availability under its existing credit facility. 

Liquidity 

While GenCo's liquidity is currently adequate based on our assessment for the 

next 12 months, absent management detailing a credible plan that enhances its 

liquidity position for the period after March 31, 2013, we will revise our 

liquidity assessment to "less than adequate. 11 

www.standardandpoors.com/ratingsdirect 3 
Research Update: AmerenEnergy Generating Co. Ratings Lowered And Placed On Credit Watch Negative 

We base our liquidity assessment on the following factors and assumptions: 

• We expect the company's liquidity sour-ces (including cash, FFO, and 

credit facility availability) over the next 12 months to exceed ·its uses 

by more than 3x. 

• GenCo does not have long-term debt maturities until 2018. 

• Even if FFO declines by 100%, we believe net sources would still be more 

than 1.2x of cash requirements mostly due to the availability on its 

credit facility. 

In our analysis, we assumed liquidity of about $650 million over the next 12 

months, primarily consisting of cash, FFO, and availability under its credit 

facility. GenCo's $500 million credit facility expires in September 2013. We 

estimate the company will use about $200 million over the same period for 

capital spending and working capital needs. 

GenCo's bond indenture includes financial covenants that must be met for GenCo 

to incur additional indebtedness. These financial covenants include a debt to 

capital ratio of no greater than 60% and a minimum interest coverage ratio of 

2.5x. As of Dec. 31, 2011, the debt to capital ratio was 43% and the interest 

coverage ratio was 4.3x. While we expect that the debt to capital ratio will 

be maintained at below SO% over the intermediate term, we expect that the 

interest coverage ratio will drop to about 2.3x in 2013, reflecting weaker 

operating cash flows as a dire.ct result of .weak market power prices. 

Recovery analysis 

GenCo's unsecured notes are rated 'BB- 1 and are on CreditWatch with negative 

implicat~ons. The '3' recovery rating indicates our expectations of meaningful 

(50%-70%) recovery. We will publish a full recovery report on RatingsDirect 

following the release of this report. 

Credit Watch 

The CreditWatch wit.h negative implications is based on the 50% probability 

that we will lower our ratings on GenCo in the very near term. We would lower 

the ratings if we determine that GenCo's liquidity is less than adequate under 

our criteria, if ~e view management's liquidity strategy for the period after 

March 31, 2013, to be insufficient, or if we determine that we should base our 

credit rating on GenCo solely on its stand-alone credit quality, without any 

support from parent Ameren Corp. 

Related Criteria And Research 

• Liquidity Descriptors For Global Corporate Issuers, Sept. 28, 2011 

• Criteria GUidelines For Recovery Ratings On Global Industrials Issuers• 

Speculative-Grade Debt, Aug. 10, 2009 

• Business Risk/Financial Risk Matrix Expanded, May 27, 2009 

Standard & Poors I RatingsDirect on the Global Credit Portal I March 5. 2012 4 
Research Update: AmerenEnergy Generating Co. Ratings Lowered And Placed On Credit Watch Negative 

• Analytical Methodology, April 15, 2008 

• Standard & Poor's Extends Recovery Ratings To Unsecured Speculative-Grade 

Corporate Issues, March 21, 2008 

Ratings List 

Downgraded; CreditWatch Action; Recovery Rating Unchanged 

AmerenEnergy Generating Co. 

Corporate Credit Rating 

Senior Unsecured 

Recovery Rating 

To From 

BE-/Watch Neg/--

BB-/Watch Neg 

3 

BB/Negative/--

BB 

3 

Complete ratings information is available to subscribers of RatingsDirect on 

the Global Credit Portal at www.globalcreditportal.com. All ratings affected 

by this rating action can be found on Standard & Poor•s public Web site at 

www.standardandpoors.com. Use the Ratings search box located in the left 

column. 

www.standardandpoors.com/ratingsdirect 5 
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The McGraw·Hill Companle5 

Standard & Poors 1 RatingsDirect on the Global Credit Portal I March 5, 2012 6 
Exhibit 7 

Affidavit of Steven C. Whitworth 
AFFIDAVIT OF STEVEN C. WHITWORTH 

I. BACKGROUND AND QUALIFICATIONS 

I. My name is Steven C. Whitworth, and I am employed by Ameren Services 

Company as the Manager of Environmental Services. Ameren Services Company provides 

business services to Ameren Corporation's operating companies including Ameren Energy 

Resources ("AER") and its subsidiary companies, Ameren Energy Generating Company 

("GENCO") and Ameren.Energy Resources Company. I have been employed with Ameren since 

1998 following the merger of Central lllinois Public Services Company ·and Union Electric 

Company. During the course of my career I have worked in the environmental air quality and 

permitting arena since 1989. I have been iri my current position with Ameren since 2007. In 

addition to supervising staff personnel, I am responsible for implementing policies and 

procedures relating to environmental compliance. In this capacity, I am responsible for 

representing the Ameren Companies before regulatory and administrative bodies with respect to 

state and federal permitting conditions and regulatory requirements. 

2. In 2006, the State of Illinois adopted regulations pertaining to mercury emissions. 

Thereafter in 2007, the AmerenMPS Group elected to comply with the state's mercury regulation 

by opting into an alternative compliance mechanism called the Multi Pollution Standard (MPS). 

By enrolling in the MPS, sources agreed to specified reductions in NO, and SOx emissions in 

exchange for deferring until2015 compliance with mandatory emission standards. The Ameren 

MPS Group opted all of its twenty-one coal-fired steam generating units located at seven power 

stations throughout the state into the MPS. On a system-wide basis those units are required to 

meet enumerated declining emission rates for NOx and S(h. As set forth more fully in the 

Petition for Variance and the affidavits of Ryan Martin and Gary Rygh, depressed power market 

1 
conditions and the uncertain regulatory climate created by the federal courts rejection and/or 

suspension of federal air quality regulations has combined to make compliance with the SCh 

emission limits of 0.25 and 0.23 pounds per million British thermal units ("lbs!MMBtu") in 

calendar years 2015 and 2017, respectively, under section 225.233(e)(2)(C) of the MPS a 

significant economic hardship. Therefore, on behalf of AER, we are seeking a delay in the 

implementation dates for those rates from 2015 and 2017 to 2020 and 2021, respectively. It is 

important to note that we are not seeking a change to either the NO, limits or the mercury 

requirements. In consideration of this limited time extension and to mitigate the environmental 

impact of the requested variance relief, AER proposes as part of its mitigation plan to 

immediately comply with a more stringent S02 limit than contained in the current rule. 

3. The compliance plan will result in a net environmental benefit as compared to the 

level of reductions required by current MPS requirements should the variance relief not be 

granted. This is because the proposed compliance plan emission rate is set at a level at which 

uncontrolled units at the Meredosia and Hutsonville energy centers will not be able to resume 

operations without additional control technology being installed within the generating system. 

There are no plans to install additional controls at either the Hutsonville or Meredosia energy 

centers and, as a result, an emission reduction from the current level of emissions will be realized 

for the duration of the variance by not operating the units. The current S02 limits required in the 

MPS along with the proposed 802 emission limit that AER proposes as part of its compliance 

plan is set forth below: 

2 
Current Rule S02 System Average Prol!osed Coml!liance Plan S02 System 

Average 

2010-2013: 0.50 lb/MMBtu 

2010-2011: 0.50 lb/MMBtu 

2014: 0.43 lb/MMBtu 

2012-2019: 0.38 lb/MMBtu 

2015-2016: 0.25 lb/MMBtu 

2020: 0.25 lb/MMBtu 

2017+: 0.23 lb/MMBtu 

2021: 0.23 lb/MMBtu 

4. Appended to my testimony as· Attachment 1 are calculations that depict the level 

of S02 emissions expected to occur under the current MPS as compared to projected emissions 

calculated under the compliance plan. In order to equalize the comparison, AER used the same 

average heat input projections as were used to support the 2009 rule revisions to the MPS. Based 

upon those calculations, by implementing a more stringent emission rate in 2012, there is a net 

reduction ofS02 tons as compared to projected emissions under the existing rule resulting in an 

overall environmental benefit. 

Current Rule S02 Projected Emissions 2010 through 2021 = 694,510 tons 

Compliance Plan S02 Limits Projected Emissions 2010 through 2021 = 665,294 tons 

Overall S02 Reduction 2010 through 2021 = 29,217 

tons 

5. I participated in the preparation of the Petition for Variance to the extent it · 

discusses Ameren Services Company and AER. 

6. I have read the Petition for Variance and the facts stated therein with regard to 

AER Illinois fleet information, the detailed compliance plan, environmental impact, and 

compliance with federal law are true and correct to the best of my knowledge and belief. 

3 
FURTHER, Affiant sayeth not. 

Subscribed and sworn to before me 

this I~ day ofMay 1, 2012. 

~ fi, L(f}£hi,AJ 

Notary Public ~, 

f .Dinielle R. M~s· :-.,-:-:-:~ .•ry Public I Notary Seal, State of Mis~ '):.m ,,.rtcrc; ..... n ~ounty 

Co1" •. • " , >027 

My CO'-'· ·"'" " i '"" 7/2112013 

4 
Ameren Energy Resources MP8 Alternative 802 Limits 

Ameren Energy Resources Alternative 502 Limit Comparison to the Current MPS 

Year 

2010 

201 

2012 

2013 

2014 

2015 

2016 

2017 

2018 

2019 

2020 

2021 

Total 

Baseline Heat 

Input •n 

34C ,A.. ?!>' 

\<In AAFi 252 

MPS Baseline 

802 

_Ions 

85,112 

85,112 

85,112 

85,112 

73,196 

42,55Fi 

42,556 

39,151 

39,151 

39,151 

39,151 

39,151 

694,510 

Variance S02 

Tons 

70, i60 

7: 'i39 <;~ QRI': 

56,986 

56,986 

~4 Rfi7 

-3_1._452 

Cumulative 802 

Variance 

Reduced 

Tons 

14,552 

2"/, 125 

fi5,2:i1 

fi3,3'17 

19,5il7 

35. 5· 

70, '2' 

11,223 

,518 

29,217 

29,217 

Note for the "Cumulative S02 Variance Reduced Tons" column, a positive number 

indicates an emission decrease (benefit}. 

Ameren Alternative 802 Emission Limit 
Exhibit 8 

EPA git~es oil companies more time 

to capture emissions from wells 

Juliet Eilperin and Steven Mufson, Washington Post, Apr. 18, 2012. 
~A giVeS ou compames more ttme to capture emtsstons rrom we11s- 1ne wasmngron rost 

Back to previous page 

EPA gives oil companies more time to capture 

emissions from wells 

By Juliet Eilperin and Steven Mufson, Published: April 18 

The Environmental Protection Agency said Wednesday that it will delay requirements for capturing air 

emissions from oil and gas wells until 2015, though in the interim the agency will impose other 

requirements, including gas flaring, that it said would reduce the release of smog-forming and toxic 

chemicals by 90 percent. 

The move represents a victory for firms that use hydraulic fracturing to tap natural gas resources trapped 

in shale rock. The American Petroleum Institute, which has been harshly critical of the Obama 

administration's policies, said EPA's final rules made "constructive changes" from rules the agency proposed 

earlier. 

Half a dozen environmental groups also praised the new regulations, which they said would "result in major 

reductions" of volatile organic compounds (VOCs), toxic benzene and natural gas, or methane, a potent 

contributor to climate change. 

The issue of whether to regulate drilling emissions has become a political football in an election year and 

amid the boom in shale gas drilling over the past three years. 

President Obama has talked about the need to tap shale gas in an environmentally responsible way. The oil 

and gas industry has pressed him to open up federal lands for even more drilling and to keep EPA out of 

fraCking regulation. Environmental groups have urged EPA to step in to prevent water pollution and natural 

gas leaks from pipelines or during drilling that could undermine the climate benefits that gas has over coal. 

Under the Clean Air Act, the EPA has the authority to regulate emissions from the drilling activity. But the 

oil and gas industry has argued that the task should be left in the hands of state regulators. 

Assistant EPA administrator Gina McCarthy said Wednesday that "this is a reasonable step for national 

regulation to try to address." She estimated that there have been 12,000 gas wells drilled using hydraulic 

fracturing. 

McCarthy said the agency delayed requirements for gas capture because of concerns about the availability 

and cost of equipment needed and the worker training needed on that equipment. But she said that the 

gas capture method known as "green completion" is already used for about half the wells drilled and that 

ultimately companies would save money by capturing compounds that can be sold as fuel and chemical 

feedstocks. 

In the meantime, she said, while flaring is wasteful, it would eliminate 90 percent of volatile organic 

compounds. Moreover, flaring natural gas, or methane, breaks down the methane into water and carbon 

dioxide. As a greenhouse gas, methane is more than 20 times more potent than carbon dioxide. 

Howard Feldman, director of regulatory and scientific affairs for the American Petroleum Institute, said the 

changes will "push back" requirements to capture air pollutants at well sites until 2015 but will call for "a 

whole host of" other requirements, including new valves. The agency will phase in over one year a 
r-A gives ou companies more nme 10 capmre emtsswns rrom wells- 1ne vva.snmgLUn rosL 

requirement to put captured gas in storage tanks at well sites, for example. 

"On the whole, we believe EPA has made constructive changes in the rule, which will reduce emissions 

while allowing our member companies to keep producing the oil and gas the country needs," Feldman said 

in an interview. · 

The industry had sought to exempt wells with low emissions from having to capture the volatile organic 

compounds released during hydraulic fracturing, Feldman said, but EPA refused to do so. 

About a month ago, senior oil and gas company executives on the board of API met with Obama senior 

adviser Valerie Jarrett about the hydraulic fracturing proposal and other energy issues. Feldman would not 

speculate on whether the meeting helped shape the new requirements, but he said the industry made 

"cogent and technically-supported arguments for our position" in the course of conversations with White 

House and EPA officials. 

"I hope every place we made those arguments they resonated," he said. 

© The Washington Post Company 
Exhibit 9 

Public Notice of Winning Bidders and Average Prices 
Public Notice of Winning Bidders and Average Prices 

Ameren Illinois Company February 10, 2012 Procurement of 

Standard Energy Products 

February 16, 2012 

On February 10, 2012, Levitan & Associates, as one of the Illinois Power Agency's 

procurement administrators, received bids for the sale of electricity to Ameren Illinois 

Company, in a request for proposals held pursuant to Section 16-111.5(k-5) of the Public 

Utilities Act. This public notice reveals the names of the successful bidders and the load 

weighted average of the winning bid prices. 

The names of the successful bidders for the above-described procurement event 

are as follows: 

Ameren Energy Marketing 

BP Energy Company 

Exelon Generation Company 

lberdrola Renewables 

There were five energy products involved in this procurement, identical except for 

their delivery periods. Each product is a constant around-the-clock (24x7) supply of 

electric energy for each hour of the delivery period. The constant quantity sought under 

this procurement was 650 Megawatts (MWs), in 50 MW increments, in all five delivery 

periods. The total quantities of the bids selected and the average prices of those bids are 

shown in the following table: 

Average Winning Prices and Quantities. 

Period Jun2013- · Jun2014- Jun2015- Jun2016- Jun2017-

May2014 May2015 May2016 May2017 Dec2017 

MW 650 650 200 - -

Hours 8,760 8,760 8,784 8,760 5,137 

MWHs 5,694,000 5,694,000 1,756,800 . - -

Average $29.51 $31.44 $33.62 n/a n/a Price 
Public Notice of Winning Bidders and Average Prices 

CornEd February 10, 2012 Procurement of Standard Energy Products 

February 16, 2012 

On February 10, 2012, NERA Economic Consulting, as one of the Illinois Power 

Agency's procurement administrators, received bids for the sale of electricity to 

Commonwealth Edison Company ("CornEd"), in a request for proposals held pursuant to 

Section 16-111.5(k-5) of the Public Utilities Act. This public notice reveals the names of 

the successful bidders and the. load weighted average of the winning bid prices. 

The names of the successful bidders for the above-described procurement event 

are as follows: 

J.P. Morgan Ventures Energy Corporation 

Morgan Stanley Capital Group Inc. 

Shell Energy North America (US), L.P. 

The only contract sought through this procurement was a constant around-theclock (24x7) supply of electric energy for each hour of the four-year, seven-month period 

from June 1, 2013 through December 31,2017. The constant quantity sought under this 

procurement was 450 Megawatts (MWs), in 50 MW increments. The lowest nine bids 

(adding up to 450 MW) were selected. The average winning bid price was $32.57 per 

Megawatt-hour (MWH). However, the contract calls for an automatic price increase of 

2.5% each June 1. As a result, the effective average price will vary as shown below: 

Effective Average Winning Prices and Quantities. 

Period Jun2013- Jun2014- Jun2015- Jun2016- Jun2017-

May2014 May2015 May2016 May2017 Dec2017 

MW 450 450 450 450 450 

Hours 8,760 8,760 8,784 8,760 5,137 

MWHs 3,942,000 3,942,000 3,952,800 3,942,000 2,311,650 

Average $32.57 $33.39 $34.22 $35.07 $35.95 Price 
Exhibit 10 

Development Strategies Memorandum 

Economic impacts of E.D. Edwards and Joppa Energy Centers of 

Illinois and surrounding market areas, Memorandum to Mike Kearney, 

Manager, Economic Development, Ameren Services from Development 

Strategies (Apr. 19, 2012) 
~DEVELOPMENT STRATEGIES® f guiding effective decisions in 'J real estate, community, and economic development 

Memorandum 

To: Mike Kearney, Manager, Economic Development; Ameren Services 

From: Robert M Lewis, Brian Licari, andY ash Yedavalli 

Date: April19, 2012 

Re: Economic Impacts ofE.D. Edwards and Joppa Energy Centers of lllinois and surrounding market areas 

In April, 2012, Development Strategies (DS) was commissioned to conduct an iudependent analysis of the economic impact that the operations of Ameren Energy Resources (AER) Corporation's E.D. Edwards Energy Center (Peoria County, lllinois) and Joppa Energy Center (Massac County, lllinois) have on the lllinois economy and on their 

respective economic multi-county regions. Development Strategies is pleased to submit this analysis of ti1e direct 

and iudirect economic impacts for each facility. 

Direct economic impacts are ti1e estimated dollars spent by AER at and iu operational support of each of the energy 

center facilities. For the purpose of our analysis, spending iucludes capital expenditures, non-payroll operations expenditures and salaries paid to employees. 

The number of jobs at the E.D. Edwards Energy Center is 110 and there are 235 at the Joppa Energy Center. We 

determined which counties iu the "region" of each plant are home to a large majority of employees and have calculated economic impacts ·within those regions. Four Illinois counties make up the primary economic impact region in 

the case of Edwards, which is home to 97 of its 110 employees. Three counties make up the primary economic 

impact region iu the case of Joppa, which is home to 134 of its 235 employees; additionally, Joppa has 71 of its 235 

employees residing iu the neighboriug state of Kentucky. Because those employees spend the bulk of their iucomes 

not iu lllinois, they are excluded from the impact analysis withiu lllinois. See map "AER: Edwards and Joppa Energy Center Labor Markets" for the local market area boundaries. 

Indirect economic impacts measure the "ripple effect" of wages and expenditures associated with AER's direct 

spending. For instance, plant employees who live in lllinois will spend a large proportion of their earniugs withiu 

the state oflllinois for housing and at local businesses such as retail stores, restaurants, mechanics, and others. Thus, 

each job at an Ameren facility will contribute to additional job support across many sectors iu the community and, 

consequentiy, the state oflllinois. Likewise, much of the non-labor operational spending by each plant is initially 

spent Vlithiu the state, thus supporting additional income and jobs iu the immediately surrounding counties and 

throughout the state. 

To calculate these indirect impacts, multiplier coefficients are applied to the direct impact dollars; these multipliers 

also automatically take into account the amount of "leakage" from the local and state economy because some wages 

and expenditures will be spent outside of the regions in which they are located and possibly even outside the state of 

lllinois. For this reason, multiplier coefficients are finite and, therefore, measureable. 

METHODOLOGY 

The analysis of the direct and iudirect economic impacts of each AER facility relied on spending and workforce infottnation provided by Ameren, and on the U.S. Department of Commerce's Regional Input-Output Multiplier 

System (RIMS-II). RIMS II provides multiplier coefficients for every county iu the United States. These multipliers 

can also be aggregsted for larger regions composed of counties, such as states and, iu this. case, the primary economic impact regions around each energy center. Multiplier coefficients for sub-county geographies are not available. 

The multipliers are determined separately for, and are unique to, each county and region for key economic sectors. 

The RIMS-II multipliers are updated annually by the Bureau of Economic Analysis (BEA). 

10 South Broadway, Suite 1500 • St. LouiS, Missoun 63102 • p 314.421.2800 WWW.DEVELDPMENT-STRATEGIES.COM 
Memorandum on Economic Impacts ofEdwatds and Joppa Energy Centers 

April19, 2012 

The AER analysis focuses on the multi-county regions noted above and on the state as a whole. That is, each facility 

has two economic impact tables associated with it the state and its own region. There are three principal multipliers 

for each sector: 

• Economic Output: This is defined as the total dollat change in the regional or state economy due to direct 

expenditures by AER at each energy center. Economic output is a similar measure as the nation's gross domestic product but, unlike the GDP, it also includes all the intermediate values added during the production process. 

• Earnings: The earnings multiplier measures the added household earnings for the regional and state labor 

force triggered by each energy center's direct spending. 

• Employment: This is defined as the added jobs in the county pet $1,000,000 of direct spending by AER in 

addition to the jobs at the AER facilities. 

Multipliers are provided for various economic sectors. The direct, non-labor, operational spending by each plant 

falls within the Utilities sector; the employee earnings paid by AER fall within the Households sector; capital expenditures fall within the Construction sector. The RIMS-II multipliers for the selected regions are summarized 

below. To calculate the indirect economic impacts: 

• The construction multiplier coefficients for the state and regions are applied to the capital expenditure figures of the 

respective plants, 

• The utilities multiplier coefficients for the state and regions are applied to the llJ!erational expenditures of the respective plants, and 

• The households multiplier coefficients for the state and regions are applied to the en!Jf!loyee conllJ!ensation figures of the 

respective plants. For the purposes of dois analysis, employee compensation includes salary, benefits, and any 

other labor related costs, therefore, the average labor expenditure pet employee does not necessarily refl~ct the 

average wage. 

The respective direct and indirect impacts are then summed to calculate the total indirect impacts. 

Note: We chose.not to include the annual fuel e>.-penditures for each energy center in our analysis. From 2008 to 

2011, Edwards had an average annual fuel expenditure of$4,660,900 in 2012 dollars and Joppa had an average annual fuel expenditure of $8,331,000 in 2012 dollats. Though a small portion these expenditures likely occur within 

lllinois, the vast majority of these e>.-penditures occur outside oflllinois (out of state coal and transportation costs); 

therefore, we are uncomfortable assunoing that tl>e standard RIMS-II multipliers account for dlls scale of immediate 

leakage. Including fuel e>.-penditures in dlls analysis, therefore, could overstate the local and statewide impacts. 

CONCLUSIONS 

DS estimates that each AER Energy Center has the following economic impact on the lllinois economy on the following pages. Each table summarizes Ameren's direct spending at each energy center (top line in d>e table), d>e 

multipliers for lllinois or the market area, the multiplier effects resultiug from Ameren's ·operational spending, and 

the total direct and indirect economic impacts generated. 

DEVELOPMENT STRATEGIES 2 
Memorandum on Economic Impacts of Edwards and Joppa Energy Centers 

April19, 2012 

IMPACTS ON THE STATE OF ILLINOIS 

Table 1: Annual Economic Impact of Ameren's Edwards Energy Center Operations on the State of Illinois 

Annual Average in 2012 Dollars1 

Capital Operating Employee 

Expenditures Expenditures Compensation Total 

Direct Spending $ 16,620,000 $ 15,384,000 $ 12,387,000 $ 44,391,000 

MULTIPLIERS 

Output 2.329 1.502 1.442 0.557 

Earnings 0.7:!.5 0.286 0.397 0.477 

Employment 15.589 4.60:!. 10.422 10.359 

ADDED ECONOMIC IMPACT ON ILLINOIS 

Output $ 38,710,000 $ 23,:!.10,000 $ 17,860,000 $ 79,680,000 

Earnings $ :!.1,870,000 $ 4,390,000 $ 4,910,000 $ 2:!.,:!.70,000 

Indirect Jobs Held by Illinois Residents 260 71 129 460 

TOTAL ECONOMIC IMPACT ON ILLINOIS 

Output (Total Economic Activity) $ 124,071,000 

Earnings $ 33,557,000 

Direct Jobs at Edwards Energy Center 110 

Total Direct and Indirect Jobs at Edwards Energy Center 570 

1

Actuaf operating data from 2008-2011 adjusted to 2012 doflar amounts and averaged 

The top of the table shows the direct e."]Jenditures by Ameren at the Edwards Energy Center totaling approximately 

$44.4 million in 2012. Since all of the employees at this energy center live in Illinois, the employee compensation 

expenditure represents the total labor expenditure at the Edwards Energy Center. Additional results are discussed 

below: 

• The $44.4 million spent by Ameren at Edwards Energy Center triggered an additional $79.7 million in value 

added activity in Illinois, of wltich $21.2 million was household earnings that supported 460 jobs. The multipliers vary for different types of major expenditures shown at the top of the table. 

• The estimated output (economic activity) triggered by Edwards Energy Center's direct operations ($44.4 million) and the added multiplier effects ($79.7 million) were $124.1 million for Illinois. 

• Of that amount, Edwards Energy Center's operations triggered nearly $33.6 million in household earnings for 

workers in Illinois, including $12.4 million in direct compensation for employees and $21.2 million in added 

earnings from the multiplier effects. 

• In total, Edwards Energy Center's operations supported 570 jobs in Illinois, including 110 direct jobs and approximately 460 jobs added through the multiplier effects. 

DEVELOPMENT STRATEGIES 3 
Memorandum on Economic Impacts of Edwards and Joppa Energy Centers 

April19, 2012 

Table 2: Annual Economic Impact of Ameren's Joppa Energy Center Operations on the State of Illinois 

Annual Average in 20i2 Dotlars 1 

capital Operating Employee 

Expenditures Expenditures Compensation 2 Total 

Direct Spending $ 28,205,000 $ 33,551,000 $ 14,895,000 $ 76,651,000 

MULTIPLIERS 

Output 2.329 1.502 1.442 0.557 

Earnings 0.715 0.286 0.397 0.465 

Employment 15.589 4.601 10.422 9.775 

ADDED ECONOMIC IMPACT ON ILLINOIS 

Output $ 65,700,000 $ 50,400,000 $ 21-,470,000 $ 137,570,000 

Earnings $ 20,150,000 $ 9,580,000 $ 5,910,000 $ 35,640,000 

Indirect Jobs Held by Illinois Residents 440 154 155 749 

TOTAL ECONOMIC IMPACT ON ILLINOIS 

Output (Total Economic Activity) $ 214,221,000 

Earnings $ 50,535,000 

Direct Jobs at Joppa Energy Center 164 

Total Dire~t and Indirect Jobs at Joppa Energy Center 913 

1

Actua/ operating data from 2008-2011 adjusted to 2012 dollar amounts and averaged 

2

Estimate based on number of employees who reside in Illinois (164 of 235) and overall average labor expenditure per employee 

The top of the table shows the direct OA-penditures by Ameren at the Joppa Energy Center totaling approximately 

$7 6. 7 million in 2012. Employee compensation is an estimate based on the number of Joppa employees that live in 

illinois (164 of235). Additional results are discussed below: 

• The $76.7 million spent by Ameren at Joppa Energy Center triggered an additional $137.6 million in value added activity in illinois, of which $35.6 million was household earnings that supported 7 49 jobs. The multipliers 

vary for different types of major expenditures shown at the top of the table. 

• The estimated output (economic activity) triggered by Joppa Energy Center's direct operations ($76.7 million) 

and the added multiplier effects ($137.6 million) were $214.2 million for illinois. 

• Of that amount, Joppa Energy Center's operations triggered nearly $50.5 million in household earnings for 

workers in illinois, including $14.9 million in direct compensation for employees and $35.6 million in added 

earnings from the multiplier effects. 

• In total, Joppa Energy Center's operations supported 913 jobs in illinois, including 164 direct jobs and approximately 7 49 jobs added through the multiplier effects. 

DEVELOPMENT STRATEGIES 4 
Memorandum on Economic Impacts of Edwards and Joppa Energy Centers 

April19, 2012 

IMPACTS ON THE RESPECTIVE MULTI-COUNTY REGIONS 

Table 3: Annual Economic Impact of Ameren's Edwards Energy Center Operations on Market Area 

Annual Average in 2012 Dol!ars1 

Gap/tal Operating Employee 

Expenditures Expenditures Compensation" 

Direct Spending $ 16,620,000 $ 15,384,000 $ 10,920,000 $ 

MULTIPLIERS 

Output 1.613 1.220 0.805 

Earnings 0.499 0.205 0.218 

Employment 10.886 2.923 6.193 

ADDED ECONOMIC IMPACT ON MARKET AREA 

Output $ 26,800,000 $ 18,770,000 $ 8,790,000 $ 

Earnings $ 8,290,000 $ 3,160,000 $ 2,380,000 $ 

Indirect Jobs Held by Area Residents 181 45 68 

TOTAL ECONOMIC IMPACT ON MARKET AREA 

Output (Total Economic Activity) $ 

Eamings $ 

Direct Jobs at Edwards Energy Center 

Total Direct and Indirect Jobs at Edwards Energy Center 

1

Actua/ operating data from 2008-2011 adjusted to 2012 dollar amounts and averaged 

Total 

42,924,000 

0.790 

0.322 

6.838 

54,360,000 

13,830,000 

294 

97,284,000 

24,750,000 

97 

391 

2

Estimate based on number of employees who reside in market area (97 of 110) and overall average labor expenditure per employee 

The top of the table shows the direct expenditures by Ameren at the Edwards Energy Center in the market area 

totaling appwximately $42.9 million in 2012. Employee compensation is an estimate based on the number of Edwards employees that live in in the market area (97 of 110). Additional results are discussed below: 

• The $42.9 million spent by Ameren at Edwards Energy Center triggered an additional $54.4 million in value 

added activity in the market area, of which $13.8 million was housel>old earnings that supported 294 jobs. The 

multipliers vary for different types of major expenditures shown at the top of the table. 

• The estimated output (economic activity) triggered by Edwards Energy Center's direct operations ($42.9 million) and the added multiplier effects ($54.4 million) were $97.3 million for the market area. 

• Of that amount, Edwards Energy Center's operations triggered nearly $24.8 million in household earnings for 

workers in the market area, including $10.9 million in direct compensation for employees and $13.8 million in 

added earnings from the multiplier effects. 

• In total, Edwards Energy Center's operations supported 391 jobs in the market area, including 97 direct jobs 

and approximately 294 jobs added tlu:ough the multiplier effects. 

DEVELOPMENT STRATEGiES 5 
Memorandum on Economic Impacts of Edwards and Joppa Energy Centers 

April19, 2012 

Table 4: Annual Economic Impact of Ameren's Joppa Energy Center Operations on Market Area 

Annual Average in 2012 Dollars 1 

. Capital Operating Employee 

Expenditures Expenditures Compensation 2 Total 

Direct Spending $ 28,205,000 $ 33,551,000 $ 12,171,000 $ 73,927,000 

MULTIPLIERS 

Output 1.284 1.111 0.381 0.946 

Earnings 0.330 0.161 0.087 0.213 

Employment 6.881 1.931 2.751 3.955 

ADDED ECONOMIC IMPACT ON MARKET AREA 

Output $ 36,220,000 $ 37,280,000 $ 4,640,000 $ 78,140,000 

Earnings $ 9,290,000 $ 5,390,000 $ 1,060,000 $ 15,740,000 

Indirect Jobs Held by Area Residents 194 65 33 292 

TOTAL ECONOMIC IMPACT ON MARKET AREA 

Output (Total Economic Activity) $ 152,067,000 

Earnings $ 27,911,000 

Direct Jobs at Joppa Energy Center 134 

Total Direct and Indirect Jobs at Joppa Energy Center 426 

1

Actua/ operating data from 2008-201.1 adjusted to 2012 dollar amounts and averaged 

2

Estimate based on number of employees who reside In market area (134 of 235) and overall average labor expenditure per employee 

The top of the table shows the direct expenditures by Ameren at the Joppa Energy Center in the market area totaling approximately $73.9 million in 2012. Employee compensation is an estimate based on the number of Joppa 

employees that live in in the market area (134 of 235). Additional results are discussed below: 

• The $73.9 million spent by Ameren at Joppa Energy Center triggered an additional $78.1 million in value added 

activity in the market area, of which $15.7 million was household earnings that supported 292 jobs. The multipliers vary for different types of major expenditures shown at the top of the table. 

• The estimated output (economic activity) triggered by Joppa Energy Center's direct operations ($73.9 million) 

and the added multiplier effects ($78.1 million) were $152.1 million for the market area. 

• Of that amount, Joppa Energy Center's operations triggered nearly $27.9 million in housel1old earnings for 

workers the market area, including $12.2 million in direct compensation for employees and $15.7 million in 

added earnings from the multiplier effects. 

• In total, Joppa Energy Center's operations supported 426 jobs in the market area, including 134 direct jobs and 

approximately 292 jobs added through the multiplier effects. 

DEVELOPMENT STRATEGtES 6 
'-'-;>-

E.D. Edwards 

Employees by County 

tl' 1-3 

"" 4-11 

~ 12-44 

... ,-.r E. D. Edwards Labor Market 

Joppa Energy Center 

Employees by County 

Q 1-3 

~ 4-11 

~ 12-103 

Joppa Energy Centers Labor Market 

AER: E.D. Edwards & Joppa Energy Centers Labor Markets 

Source: Ameren provided employment counts by work location and county of residence, as of March 1, 2012 

l

"""\ DEVELOPMENTSTRATEGIES' 

!;Llidir·~. e:Het:tke de:r~io,'H! ,r, J r~<;l esta!~;, comm:.~ci:~.-a"~ ec;>r,;eEt•c 1~<?-."E::<:.;>rnef.l 

Apri12012 
Exhibit 11 

Affidavit of Shawn E. Shukar 
AFFIDAVIT OF SHAWN E. SCHUKAR 

I. BACKGROUND AND QUALIFICATIONS 

1. My name is Shawn E. Schukar and I am employed by Ameren Energy 

Marketing as Senior Vice President-Trading & Marketing. Ameren Energy Marketing (AEM) is 

the marketing arm of Ameren Energy Resources and is responsible for all aspects of the selling 

and marketing of power from AER's generating facilities. 

2. I received a Bachelor's degree in Mechanical Engineering from the University 

of Illinois in 1984 and a Master's of Business degree from the University of Illinois in 2001. I 

joined Illinois Power Company ("Illinois Power") in 1984 as a power plant engineer. I 

subsequently held several power plant positions from 1986 through 1996, including positions in 

plant performance management, plant operations management, and plant engineering 

management. In 1996, I became responsible for the generation control function, which included 

the dispatch and short-term energy sales associated with the Illinois Power control area. I was 

responsible for general control, energy trading and energy marketing from 1997 through 1999. I 

then managed the retail pricing and risk management portions of the business from 1999 through 

2000, and transmission operations from 2000 through 200 I. I was responsible for the 

transmission, generati<Jn dispatch and gas control functions at Illinois Power from 2001 through 

2004. In 2004, I became responsible for the Illinois Power field operations and continued with 

that responsibility after Ameren Companies acquisition of Illinois Power Company. Over the last 

several years I have worked for Ameren in a variety of capacities and assumed my current role 

with AEM in November of2011. 
II. DESCRIPTION OF POWER MARKET 

3. AER participates in and sells power into a regional transmission organization 

known as the Midwest Independent Transmission System (MISO). Participants in the MISO 

market include both regulated and unregulated generators. Appended to my Affidavit is a chart 

that depicts average heat rates generating units within the MISO region and including AER's 

energy facilities. For generation units, efficiency is measured in heat rates where a lower heat 

rate indicates more efficient units. As depicted in the chart, the Newton, Joppa, and Edwards 

units are some of the more efficient units in MISO footprint. 

4. In illinois, a customer's electricity costs include both regulated and 

deregulated components. The generation portion of the customer's electricity costs is based on 

competitive market prices while the transmission and distribution or delivery service portion is 

based upon rate-regulated factors. As a deregulated state, Illinois customers have a choice on 

who supplies generation related service. These supplies can originate from any source that can 

be delivered to Illinois. This can includes sources that are in bordering states like Indiana and 

Missouri of from sources that are several states away from Illinois including states like Ohio. 

5. The generation costs typically include energy, capacity, and ancillary services 

costs. In competitive markets these costs are generally determined by supply and demand. Since 

Illinois companies are part of either the P JM or MISO organized electricity markets, energy and 

ancillary service costs are determined based on the offers from available generation sources. 

(Capacity costs are determined by the supply of available generation and the load demands.) The 

marginal costs of the generators are used by marketers such as AEM in determining a unit's offer 

price into the marketplace. 

2 
6. If AER were to mothball generating units, and assuming all other pricing 

variables stay the same or are neutral, removal of such low-cost and efficient units from MISO 

would result in a greater utilization of generating units that are less efficient and have higher 

marginal costs. Mothballing several of AER' s units will cause generation related costs to 

increase, increasing electric costs above what the costs would have been without the 

mothballing. If the units are mothballed the market will need to replace the energy from these 

units with energy from other units that costs more- driving up the costs of energy and ancillary 

services for Illinois customers. In fact, the generation associated with the Newton, Edwards and 

Joppa units in 2011 totaled nearly 20,000,000 megawatt hours (MWh) that will need to be 

replaced by higher cost generation. 

7. In addition the mothball of these units will also decrease the supply of 

available generation which, absent any reductions in load, would tighten the supply demand 

balance and have upward pressure on capacity costs. Thus the mothballing of any of these 

higher efficiency, low cost units from the market will drive up costs for energy, ancillary 

services, and capacity costs which ultimately impacts the cost to consumers in Illinois's 

deregulated markets. 

FURTHER, Affiant sayeth not. 

DATED: 3 Qa;)- . 

3 

Dania lie R. Moskop ··Notary PubliC 

Notary Seal, State of 

MiSSOUri - Jefferson County Commission 11097 45027 

Comn"illlion Expires 7/2112013 
:::::::::::::::::::::::::::;::::::::::::::::::::::;;:::::::: ::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::·.:::::;::;:::::::: ::::::::::::::::::::::·.::::::.·::;;;:::

15,000 

14

'

500 

14,000 +------·-·-·- -·-········ 13,500 

13 000 ___ ,,_, ______ ,_ ---- -------.. ·--··-.. ··- , __ , _____ ,_ ....... ,, _______ --------

' ! 

12 500 +--------- ···-------- ________________ , _______ -----------

' I 

-·--·- - ---- --- ------------·1 

' ! 12,000 --1- M!SO Average: 11,885 -----· --·----- -----............... ___ , ____ ... -............. _ .. ,_ .. __ ,, ___ .... __ .. __ ................... -....... .. ........... . 

i 

11:1 11,500 "t""" 

Edwards 10,495 

11,000 t--·-...... -- ....... 

I Joppa 10,393 "-.... , I 

10,500 ' 1 - •• InTrr 10,000 

9,500 +-· i 9,000 t-- ' ___ , 

8 5Q0 .. ll . . lUlJ..llll__l_lli.ILI . .I-" . .I..LLJ,.LI .. U • ......_.._,_._,____.____.__._,_._L.O .. L.I.o..•.o.a.o..o .. o .. o.u . ._ . ._._.__.,,_..,,_._,,,,,,,_,.,._,_,,_,_, .... ,.,,_,,,,,o._.,_._,._,,_. ...... ..._._ .... o.l 

' Source: FERC Form 1 data for coal-fired plants, Ameren plants per company data. 
Exhibit 12 

Selected Pages of the Technical Support Document for Best 

Available Retrofit Technology IJnder the Regional Haze 

Cover page and Appendix C of the Illinois Environmental Protection 

Agency Technical Support Document containing the MPS, AQPSTR 09-06, 

April 29, 2011. 
TECHNICAL SUPPORT DOCUMENT 

FOR 

BEST AVAILABLE RETROFIT TECHNOLOGY 

UNDER THE REGIONAL HAZE RULE 

AQPSTR 09-06 

April 29, 2011 

ILLINOIS ENVIRONMENTAL PROTECTION AGENCY 

1021 NORTH GRAND A VENUE EAST 

P.O. BOX 19276 

SPRINGFIELD, ILLINOIS 62794-9276 
Appendix C 

Illinois Mercury Rule 

The Illinois EPA is seeking approval from the United States Environmental Protection Agency of the 

following balded provisions of the Illinois Mercury Rule, 35Ill. Adm. Code Part 225, Subpart B: 

Control of Mercury Emissions from Coal-Fired Electric Generating Units, under this submission. 

Please note that the non-balded provisions are included for context: 

Section 225.233 Multi-Pollutant Standards (MPS) 

a) General. 

1) As an alternative to compliance with the emissions standards of Section 

225.230(a), the owner of eligible EGUs may elect for those EGUs to 

demonstrate compliance pursuant to this Section, which establishes control 

requirements and standards for emissions of NO, and S02, as well as for 

emissions of mercury. 

2) For the purpose of this Section, the following requirements apply: 

A) An eligible EGU i~ an EGU that is located in Illino.is and which 

commenced commercial operation on or before December 31, 2004; 

and 

B) Ownership of an eligible EGU is determined based on direct 

ownership, by the holding of a majority interest in a company that 

owns the EGU or EGUs, or by the common ownership of the company 

that owns the EGU, whether through a parent-subsidiary 

relationship, as a sister corporation, or as an affiliated corporation 

with the same parent corporation, provided that the owner has the 

right or authority to submit a CAAPP application on behalf of the 

EGU. 

3) The owner of one or more EGUs electing to demonstrate compliance with 

this Subpart B pursuant to this Section must submit an application for a 

CAAPP permit modification to the Agency, as provided in Section 225.220, 

that includes the information specified in subsection (b) of tb.is Section and 

which clearly states the owner's election to demonstrate compliance pursuant 

to this Section 225.233. 

A) If the owner of one or more EGUs elects to demonstrate compliance 

with this Subpart pursuant to this Section, then all EGUs it owns in 

Illinois as of July 1, 2006, as defined in subsection (a)(2)(B) of this 

Section, must be thereafter subject to the standards and control 

1 
requirements of this Section, except as provided in subsection 

(a)(3)(B). Such EGUs must be referred to as a Multi-Pollutant 

Standard (1\1PS) Group. 

B) Notwithstanding the foregoing, the owner may exclude from an MPS 

Group any EGU scheduled for permanent shutdown that the owner 

so designates in its CAAPP application required to be submitted 

pursuant to subsection (a)(3) of this Section, with compliance for such 

units to be achieved by means of Section 225.235. 

4) When an EGU is subject to the requirements of this Section, the 

requirements apply to all owners or operators of the EGU. 

b) Notice oflntent. 

The owner of one or more EGUs that intends to comply with this Subpart B by 

meanS of this Section must notify the Agency of its intention by December 31, 2007. 

The following information must accompany the notification: 

1) The identification of each EGU that will be complying with this Subpart B by 

means of the multi-pollutant standards contained in this. Section, with 

evidence that the owner has identified all EGUs that it owned in Illinois as of 

July 1, 2006 and which commenced commercial operation on or before 

December 31, 2004; 

2) If an EGU identified in subsection (b )(1) of this Section is also owned or 

operated by a person different than the owner submitting the notice of intent, 

a demonstration that the submitter has the right to commit the EGU or 

authorization from the responsible official for the EGU accepting the 

application; 

3) The Base Emission Rates for the EGUs, with copies of supporting data and 

calculations; 

4) A summary of the current control devices installed and operating on each 

EGU and identification of the additional control devices that will likely be 

needed for the each EGU to comply with emission control requirements of 

this Section, including identification of each EGU in the MPS group that will 

be addressed by subsection (c)(l)(B) of this Section, with information 

showing that the eligibility criteria for this subsection (b) are satisfied; and 

5) Identification of each EGU that is scheduled for permanent shut down, as 

provided by Section 225.235, which will not be part of the MPS Group and 

which will not be demonstrating compliance with this Subpart B pursuant to 

this Section. 

2 
c) Control Technology Requirements for Emissions of Mercury. 

I) Requirements for EGOs in an MPS Group. 

A) For each EGU in an MPS Group other than an EGO that is addressed by 

subsection (c)(! )(B) of this Section for the period beginning July I, 2009 

(or December 31, 2009 for an EGU for which an S02 scmbber or fabric 

filter is being installed to be in operation by December 31, 2009), and 

ending on December 31, 2014 (or such earlier date that the EGU is subject 

to the mercury emission standard in subsection (d)(I) of this Section), the 

owner or operator of the EGU must install, to the extent not already 

installed, and properly operate and maintain one of the following emission 

control devices: 

i) A Halogenated Activated Carbon Injection System, complying 

with the sorbent injection requirements of subsection ( c)(2) of this 

Section, except as may be otherwise provided by subsection (c)(4) 

of this Section, and followed by a Cold-Side Electrostatic 

Precipitator or Fabric Filter; or 

ii) If the boiler frres bituminous coal, a Selective Catalytic Reduction 

(SCR) System and an SOz Scrubber. 

B) An owner of an EGO in an MPS Group has two options under this 

subsection (c). For an MPS Group that contains EGUs smaller than90 

gross MW in capacity, the owner may designate any such EGUs to be not 

subject to subsection ( c)(l )(A) of this Section. Or, for an MPS Group that 

contains EGOs with gross MW capacity of less than 115 MW, the owner 

may designate any such EGUs to be not subject to subsection (c)(l)(A) of 

this Section, provided that the aggregate gross MW capacity of the 

designated EGUs does not exceed 4% of the total gross MW capacity of 

the MPS Group. For any EGU subject to one of these two options, unless 

the EGO is subject to the emission standards in subsection (d)(2) of this 

Section, beginning on January 1, 2013, and continuing until such date that 

the owner or operator of the EGU commits to comply with the mercury 

emission standard in subsection ( d)(2) of this Section, the owner or 

operator of the EGU must install and properly operate and maintain a 

Halogenated Activated Carbon Injection System that complies with the 

sorbent injection requirements of subsection ( c )(2) of this Section, except 

as may be otherwise provided by subsection (c)( 4) of this Section, and 

followed by either a Cold-Side Electrostatic Precipitator or Fabric Filter. 

The use of a properly installed, operated, and maintained Halogenated 

Activated Carbon Injection System that meets the sorbent injection 

requirements of$ubsection (c)(2) of this Section is defined as the 

"principal control technique." 

3 
2) For each EGU for which injection of halogenated activated carbon is required by 

subsection (c)(l) of this Section, the owner or operator of the EGU must inject 

halogenated activated carbon in an optimum manner, which, except as provided in 

subsection (c)(4) of this Section, is defined as all of the following: 

A) The use of an injection system designed for effective absorption of 

mercury, considering the configuration of the EGU and its ductwork; 

B) The injection of halogenated activated carbon manufactured by Alstom, 

Norit, or Sorbent Technologies, Calgon Carbon's FLUEPAC CF Plus, or 

CalgonCarbon's FLUEPAC MC Plus, or the injection of any other 

halogenated activated carbon or sorbent that the owner or operator of the 

EGU has demonstrated to have similar or better effectiveness for control 

of mercury emissions; and 

C) The injection of sorbent at the following mininmm rates, as applicable: 

i) For an EGU firing subbituminous coal, 5.0 lbs per million actual 

cubic feet or, for any cyclone-fired EGU that will install a scrubber 

and baghouse by December 31,2012, and which already meets an 

emission rate of 0.020 lbs mercury/GWh gross electrical output or 

at least 75 percent reduction of input mercury, 2.5 lbs per million · 

actual cubic feet; 

ii) For an EGU firing bituminous coal, 10.0 lbs per million actual 

cubic feet for any cyclone-fired EGU that will install a scrubber 

and baghouse by December 31, 2012, and which already meets an 

emission rate of0.020 lb mercury/GWh gross electrical output or 

at least 75 percent reduction of input mercury, 5.0 lbs per million 

actual cubic feet; 

iii) For an EGU firing a blend of subbituminous and bituminous coal, 

a rate that is the weighted average of the above rates, based on the 

blend of coal being fired; or 

iv) A rate or rates set lower by the Agency, in writing, than the rate 

specified in any of subsections (c)(2)(C)(i), (c)(2)(C)(ii}, or 

(c)(2)(C)(iii) of this Section on a unit-specific basis, provided that 

the owner or operator of the EGU has demonstrated that such rate 

or rates are needed so that carbon injection will not increase 

particulate matter emissions or opacity so as to threaten 

noncompliance with applicable requirements for particulate matter 

or opacity. 

D) For the purposes of subsection (c)(2)(C) of this Section, the flue gas flow 

shall be the gas flow rate in the stack for all units except for those 

4 
equipped with activated carbon injection prior to a hot-side electrostatic 

precipitator; for units equipped with activated carbon injection prior to a 

hot-side electrostatic precipitator, the flue gas flow rate shall be the gas 

flow rate at the inlet to the hot-side electrostatic precipitator, which shall 

be detennined as the stack flow rate adjusted through the use of Charles' 

Law for the differences in gas temperatures in the stack and at the inlet to 

the electrostatic precipitator (Vesp = Vstack x Tesp/Tstock, where V =gas flow 

rate in acf and T = gas temperature in Kelvin or Rankine 

3) The owner or operator of an EGU that seeks to operate an EGU with an activated 

carbon injection rate or rates that are set on a unit-specific basis pursuant to 

subsection ( c )(2)(C)(iv) of this Section must submit an application to the Agency 

. proposing such rate or rates, and must meet the requirements of subsections 

(c)(3)(A) and (c)(3)(B) of this Section, subject to the limitations of subsections 

(c)(3)(C) and (c)(3)(D) ofthis Section: 

A) The application must be submitted as an application for a new or revised 

federally enforceable operating pennit for the EGU, and it must include a 

summary of relevant mercury emission data for the EGU, the unit-specific 

injection rate or rates that are proposed, and detailed information to 

support the proposed injection rate or rates; and 

B) This application must be submitted no later than the date that activated 

carbon must first be injected. For example, the owner or operator of an 

EGU that must inject activated carbon pursuant to subsection ( c)(l)(A) of 

this subsection must apply for unit-specific injection rate or rates by July 

1, 2009. Thereafter, the owner or operator of the EGU may supplement its 

application; and 

C) Any decision of the Agency denying a permit or granting a permit with conditi 

that seta lower injection rate or rates may be appealed to the Board putsuant tc 

Section 39 of the Act; and 

D) The owner or operator of an EGU may operate at the injection rate or rates 

proposed in its application until a final decision is made on the application, 

including a final decision on any appeal to the Board. 

4) Outing any evaluation of the effectiveness of a listed sorbent, an alternative 

sorbent, or other technique to control mercury emissions, the owner or operator of 

an EGU need not comply with the requirements of subsection (c)(2) of this 

Section for any system needed to carry out the evaluation, as further provided as 

follows: 

A) The owner or operator of the EGU must conduct the evaluation in 

accordance with a formal evaluation program submitted to the Agency at 

least 30 days prior to commencement of the evaluation; 

5 
B) The duration and scope of the evaluation may not exceed the duration and 

scope reasonably needed to complete the desired evaluation of the 

alternative control technique, as initially addressed by the owner or 

operator in a support document submitted with the evaluation program; 

C) The owner or operator of the EGU must submit a report to the Agency no 

later than 30 days after the conclusion of the evaluation that describes the 

evaluation conducted and which provides the results of the evaluation; and 

D) If the evaluation of the alternative control technique shows less effective 

control of mercury emissions from the EGU than was achieved with the 

principal control technique, the owner or operator of the EGU must 

resume use of the principal control technique. If the evaluation of the 

alternative control teclmique shows comparable effectiveness to the 

principal control technique, the owner or operator of the EGU may either 

continue to use the alternative control technique in a manner that is at least 

as effective as the principal control technique, or it may resume use of the 

principal control technique. If the evaluation of the alternative control 

technique shows more effective control of mercury emissions than the 

controlteclmique, the owner or operator of the EGU must continue to use 

the alternative control technique in a manner that is more effective than 

the principal control technique, so long as it continues to be subject to this 

subsection (c). 

5) In addition to complying with the applicable recordkeeping and monitoring 

requirements in Sections 225.240 through 225.290, the owner or operator of an 

EGU that elects to comply with this Subpart B by means of this Section must 

also comply with the following additional requirements: 

A) For the first 36 months that injection of sorbent is required, it must 

maintain records of the usage of sorbent, the flue gas flow rate from the 

EGO (and, if the unit is equipped with activated carbon injection prior to a 

hot-side electrostatic precipitator, flue gas temperature at the.inlet ofthe 

hot-side electrostatic precipitator and in the stack), and the sorbent feed 

rate, in pounds per million actual cubic feet of flue, on a weekly average; 

B) After the first 36 months that injection of sorbent is required, it must 

monitor activated sorbent feed rate to the EGU, gas flow rate in the stack, 

and, if the unit is equipped with activated carbon injection prior to a hotside electrostatic precipitator, flue gas temperature at the inlet ofthe hotside electrostatic precipitator and in the stack. It must automatically 

record this data and the sorbent carbon feed rate, in pounds per million 

actual cubic feet of flue gas, on an hourly average; and 

6 
C) If a blend of bituminous and sub bituminous coal is fired in the EGU, it 

must keep records of the amount of each type of coal burned m1d the 

required injection rate for injection of activated carbon, on a weekly basis. 

6) Unti.l June 30,2012, as an alternative to the CEMS or excepted monitoring system 

(sorbent trap system) monitoring, recordkeeping, and reporting requirements in 

Sections 225.240 through 225.290, the owner or operator of an EGU may. elect to 

comply with the emissions testing, monitoring, recordkeeping, and reporting 

requirements in Section 225.239(c), (d), (e), (f)(!) and (2), (h)(2), (i)(3) and (4), 

and U)(l). 

7) In addition to complying with the applicable reporting requirements in Sections 

225.240 through 225.290, the owner or operator of an EGU that elects to comply 

with this Subpart B by means of this Section must also submit quarterly reports 

for the recordkeeping and monitoring conducted pursum1t to subsection (c)( 5) of 

this Section. 

d) Emission Standards for Mercury. 

1) For each EGU in an MPS Group that is not addressed by subsection (c)(l)(B) of 

this Section, beginning January 1, 2015 (or such earlier date when the owner or 

operator of the EGU notifies the Agency that it will comply with these standards) 

and continuing thereafter, the owner or operator of the EGU must comply with 

one of the following standards on a rolling 12-month basis: 

A) An emission standard of0.0080 lb mercury/GWh gross electrical output; 

or 

B) A minimum 90-percent reduction of input mercury. 

2) For each EGU in an MPS Group that has been addressed under subsection 

(c)(l)(B) of this Section, beginning on the date when the owner or operator of the 

EGU notifies the Agency that it will comply with these standards m1d continuing 

thereafter, the owner or operator of the EGU must comply with one of the 

following standards on a rolling 12-month basis: 

A) An emission stm1dard of 0.0080 lb mercury/GWh gross electrical output; 

or 

B) A minimum 90-percent reduction of input mercury. 

3) Compliance with the mercury emission stm1dard or reduction requirement of this 

subsection (d) must be calculated in accordm1ce with Section 225.230(a) or (d), or 

Section 225.232 until December 31, 2013. 

7 
4) Until June 30, 2012, as an alternative to demonstrating compliance with the 

emissions standards in this subsection (d), the owner or operator of an EGU may 

elect to comply with the emissions testing requirements in Section 225.239(a)(4), 

(b), (c), (d), (e), (f), (g), (h), (i), and G) of this Subpart. 

e) Emission Standards for NOx and S02. 

1) NOx Emission Standards. 

A) Beginning in calendar year 2012 and continuing in each calendar 

thereafter, for the EGUs in each MPS Group, the owner and operator 

of the EGUs must comply with an overall NOx annual emission rate of 

no more than O.lllb/million Btu or an emission rate equivalent to 52 

percent of the Base Annual Rate of NO, emissions, whichever is more 

stringent. 

B) Beginning in the 2012 ozone season and continuing in each ozone 

season thereafter, for the EGUs in each MPS Group, the owner and 

operator of the EGUs must comply with an overall NO, seasonal 

emission rate of no more than O.lllb/million Btu or an emission rate 

equivalent to 80 percent of the Base Seasonal Rate of NO, emissions, 

whichever is more stringent. 

2) S02 Emission Standards. 

A) Beginning in calendar year 2013 and continuing in calendar year 

2014, for the EGUs in each MPS Group, the owner and operator of 

the EGUs must comply with an overall S02 annual emission rate of 

0.33 lb/million Btu or a rate equivalent to 44 percent of the Base Rate 

of so2 emissions, whichever is more stringent. 

B) Beginning in calendar year 2015 and continuing in each calendar year 

thereafter, for the EGUs in each MPS Grouping, the owner and 

operator of the EGUs must comply with an overall annual emission 

rate for S02 of 0.25 lbs/million Btu or a rate equivalent to 35 percent· 

of the Base Rate of S02 emissions, whichever is more stringent. 

3) Ameren MPS Group Multi-Pollutant Standard 

A) Notwithstanding the provisions of subsections (e)(l) and (2) of this 

Section, this subsection (e)(3) applies to the Ameren MPS Group as 

described in the notice of intent submitted by Ameren Energy 

Resources in accordance with subsection (b) of this Section. 

B) NO, Emission Standards, 

8 
4) 

f) 

i) Beginning in the 2010 ozone season and continuing in each 

ozone season thereafter, for the EGUs in the Ameren MPS 

Group, the owner and operator of the EGUs must comply with 

an overall NOx seasonal emission rate of no more than 0.11 

lb/million Btu. 

ii) Beginning in calendar year 2010 and continuing in calendar 

year 2011, for the EGUs in the Ameren MPS Group, the owner 

and operator of the EGUs must comply with an overall NOx 

annual emission rate of no more than 0.14 lb/million Btu. 

iii) Beginning in calendar year 2012 and continuing in each 

calendar year thereafter, for the EGUs in the Ameren MPS 

Group, the owner and operator of the EGUs must comply with 

an overall NO, annual emission rate of no more than 0.11 

lb/million Btu. 

C) S02 Emission Standards 

i) Beginning in calendar year 2010 and continuing in each 

calendar year through 2013, for the EGUs in the Ameren MPS 

Group,.the owner and operator of the EGUs must comply with 

an overall SOz annual emission rate of 0.50 lb/million Btu. 

ii) In ca.lcndar year 2{)14, for the EGUs1n the Ameren MPS 

Group, the owner and operator of the EGUs must comply with 

an overall SOz annual emission rate of 0.43 lb/million Btu. 

iii) Beginning in calendar year 2015 and continuing in calendar 

year 2016, for the EGUs in the Ameren MPS Group, the owner 

and operator of the EGUs must comply with an overall SOi 

annual emission rate of 0.25 lb/mi!lion Btu. 

iv) Beginning in calendar year 2017 and continuing in each 

calendar year thereafter, for the EGUs in the Ameren MPS 

Group, the owner and operator of the EGUs must comply with 

an overall SOz annual emission rate of 0.23 lb /million Btu. 

Compliance with the NO, and S02 emission standards must be demonstrated 

in accordance with Sections 225.310, 225.41{), and 225.510. The owner or 

operator ofEGUs must complete the demonstration of compliance before 

March 1 of the following year for annual standards and before November 1 

for seasonal standards, by which date a compliance report must be submitted 

to th.e Agency. 

Requirements for NOx and S02 Allowances. 

9 
1) The owner or operator ofEGUs in an MPS Group must not sell or trade to any 

person or otherwise exchange with or give to anyperson NOx allowances 

allocated to the EGUs in the MPS Group for vintage years 2012 and beyond that· 

would otherwise be available for sale, trade, or exchange as a result of actions 

taken to comply with the standards in subsection (e) of this Section. Such 

allowances that are not retired for compliance must be surrendered to the Agency 

on an annual basis, beginning in calendar year 2013. This provision does not 

apply to the use, sale, exchange, gift, or trade of allowances among the EGUs in 

an. MPS Group. 

2) The owners or operators of EGUs in an MPS Group must not sell or trade to any 

person or otherwise exchange with or give to any person so2 allowances 

allocated to the EGUs in the MPS Group for vintage years 2013 and beyond that 

would otherwise be available for sale or trade as a result of actions taken to 

comply with the standards in subsection (e) of this Section. Such allowances that 

are not retired for compliance, or otherwise surrendered pursuant to a consent 

decree to which the State oflllinois is a paJ.iy, must be surrendered to the Agency 

on an annual basis, beginning in calendar year 2014. This provision does not 

apply to the use, sale, exchange, gift, or trade of allowances aJ.nong the EGUs in 

an MPS Group. 

3) Theprovisions of this subsection (f) do not restrict or inhibit the sale or trading of 

allowaoces that become available from one or more EGUs in aMPS Group as a 

result of holding allowances that represent over-compliance with the NO, or S02 

standard in subsection (e) of this Section, once such a standard becomes effective, 

whether such over-compliance results from control equipment, fuel chaoges, 

changes in the method of operation, unit shut downs, or other reasons. 

4) For purposes of this subsection (f), NOx and S02 allowances meao allowances 

necessary for compliance with Sections 225.310,225.410, or 225.510,40 CFR 

72, or Subparts AA and AAAA of 40 CFR 96, or any future federal NO, or S02 

emissions trading programs that modify or replace these programs. This Section 

· does not prohibit the owner or operator ofEGUs in an MPS Group from 

purchasing or otherwise obtaining allowances from other sources as allowed by 

law for purposes of complying with federal or state requirements, except as 

specifically set forth in this Section. 

5) By March 1, 2010, and continuing each year thereafter, the owner or operator of 

EGUs in an MPS Group must submit a report to the Agency that demonstrates 

compliance with the requirements of this subsection (f) for the previous calendar 

year, and which includes identification of any allowances that have been 

surrendered to the USEP A or to the Agency a11d any allowances that were sold, 

gifted, used, exchanged, or traded because they became available due to overcompliance. All allowances that are required to be surrendered must be 

surrendered by August 31, unless USEPA has not yet deducted the allowances 

10 
from the previous year. A final report must be submitted to the Agency by 

August 31 of each year, verifying that the actions described in the initial report 

have taken place or, if such actions have not taken place, an explanation of all 

changes that have occurred and the reasons for such changes. IfUSEPA has not 

deducted the allowances from the previous year by August 31, the final report will 

be due, and all allowances required to be surrendered must be surrendered, within 

3 0 days after such deduction occurs. 

g) Notwithstanding 35 Ill. Adm. Code 201.146(hhh), until an EGU has complied with 

the applicable emission standards of subsections (d) and (e) of this Section for 12 

months, the owner or operator of the EGU must obtain a construction permit for 

any new or modified air pollution control equipment that it proposes to construct 

for control of emissions of mercury, NO, or S02. 

(Source: Amended at 33 Ill. Reg. 10427, effective June 26, 2009) 

Section 225.291 Combined Pollutant Standard: Purpose 

The purpose of Sections 225.291 through 225.299 (hereinafter referred to as the Combined 

Pollutant Standard ("CPS")) is to allow an alternate means of compliance with the emissions 

standards for mercury in Section 225.230(a) for specified EGUs through permanent shut-down, 

installation of ACI, and the application of pollution control technology for NO., PM, and S02 

emissions that also reduce mercury emissions as a co-benefit and to establish permanent emissions 

standards for those specified EGUs. Unless otherwise provided for in the CPS, owners and 

operators ofthose specified EGUs are not excused from compliance with other applicable 

requirements of Subparts B, C, D, and E. 

(Source: Added at 33 Ill. Reg. 10427, effective June 26, 2009) 

Section 225.292 Applicability of the Combined Pollutant Standard 

a) As an alternative to compliance witb the emissions standards of Section 225.230(a), 

the owner or operator of specified EGUs in the CPS located at Fisk, Crawford, 

Joliet, Powerton, Waukegan, and Will County power plants may elect for all of 

those EGUs as a group to demonstrate compliance pursuant to the CPS, which 

establishes control requirements and emissions standards for NO" PM, S02, and 

mercury. For this purpose, ownership of a specified EGU is determined based on 

direct ownership, by holding a majority interest in a company that owns the EGU or 

EGUs, or by the common ownership of the company that owns the EGU, whether 

through a parent-subsidiary relationship, as a sister corporation, or as an affiliated 

corporation with the same parent corporation, provided that the owner or operator 

has the right or authority to submit a CAAPP application on behalf of the EGU. 

11 
b) A specified EGU is a coal-fired EGU listed in Appendix A, irrespective of any 

subsequent changes in ownership of the EGU or power plant, the operator, unit 

designation, or name of unit. 

c) The owner or operator of each of the specified EGUs electing to demonstrate 

compliance with Section 225.230(a) pursuant to the CPS must submit an application 

for a CAAPP permit modification to the Agency, as provided for in Section 225.220, 

that includes the information specified in Section 225.293 that clearly states the 

owner's or operator's election to demonstrate compliance with Section 225.230(a) 

pursuant to the CPS. 

d) If an owner or operator of one or more specified EGUs elects to demonstrate 

compliance with Section 225.230(a) pursuant to the CPS, then all specified EGUs 

owned or operated in Illinois by the owner or operator as of December 31, 2006, as 

defined in subsection (a) ofthis Section, are thereafter subject to the standards and 

control requirements of the CPS. Such EGUs are referred to as a Combined 

Pollutant Standard (CPS) group. 

e) If an EGU is subject to the requirements of this Section, then the requirements 

apply to all owners and operators of the EGU. 

(Source: Added at 33 Ill. Reg. 10427, effective June 26, 2009) 

Section 225.293 Combined Pollutant Standard: Notice of Intent 

The owner or operator of one or more specified EGUs that intends to comply with Section 

225.230(a) by means of the CPS must notify the Agency of its intention on or before 

December 31, 2007. The following information must accompany the notification: 

a) The identification of each EGU that will be complying with Section 225.230(a) 

pursuant to the CPS, with evidence that the owner or operator has identified all 

specified EGUs that it owned or operated in Jllinois as of December 31, 2006, and 

which commenced commercial operation on or before December 31, 2004; 

b) If an EGU identified in subsection (a) ofthis Section is also owned or operated by a 

person different than the owner or operator submitting the notice of intent, a. 

demonstration that the submitter has the right to commit the EGU or authorization 

from the responsible official for the EGU submitting the application; and 

c) A summary ofthe current control devices installed and operating on each EGU and 

identification of the additional control devices that will likely be needed for each 

EGU to comply with emission control requirements of the CPS. 

(Source: Added at 33 Ill. Reg. l 0427, effective June 26, 2009) 

12 
Section 225.295 Combined Pollutant Standard: Emissions Standards for NO, and S02 

a) Emissions Standards for NO, and Reporting Requirements. 

1) Beginning with calendar year 2012 and continuing in each calendar year 

thereafter, the CPS group, which includes all specified EGUs that have not 

been permanently shut down by December 31 before the applicable calendar 

year, must comply with a CPS group average annual NO, emissions rate of 

no more than O.lllbs/mmBtu. 

2) Beginning with ozone season control period 2012 and continuing in each 

ozone season control period (May 1 through September 30) thereafter, the 

CPS group, which includes all specified EGUs that have not been 

permanently shut down by December 31 before the applicable ozone season, 

must comply with a CPS group average ozone season NO, emissions rate of 

no more than 0.11 lbs/mmBtu. 

3) The owner or operator of the specified EGUs in the CPS group must file, not 

later than one year after startup of any selective SNCR on such EGU, a 

report with the Agency describing the NOx emissions reductions that the 

SNCR has been able to achieve. 

b) Emissions Standards for SOz. Beginning in calendar year 2013 and continuing in 

each calendar year thereafter, the CPS group must comply with the applicable CPS 

group average annual S02 emissions rate listed as follows: 

year lbs/mmBtu 

2013 0.44 

2014 0.41 

2015 0.28 

2016 0.195 

2017 0.15 

2018 0.13 

2019 0.11 

c) Compliance with the NO, and S02 emissions standards must be demonstrated in 

accordance with Sections 225.310, 225.410, and 225.510. The owner or operator of 

the specified EGUs must complete the demonstration of compliance pursuant to 

Section 225.298(c) before March 1 of the following year for annual standards and 

before November 30 of the particular year for ozone season control periods (May 1 

through September 30) standards, by which date a compliance report must be 

submitted to the Agency. [NOTE: This subsection is relying on the compliance requirements 

of the Clean Air Interstate Rule Trading Program under Subparts C, D, and E of Part 225 and will 

need to be amended accordingly when the Transport Rule is promulgated.} 

13 
d) The CPS group average annual S02 emission rate, annual NOx emission rate and 

ozone season NOx emission rates shall be determined as follows: 

n n 

ERav• = :E (S02i or NOxi tonsY:E (Hii) • i=l i=l 

Where: 

ERavg = 

ID· = '• 

so2i = 

NO,i= 

N = 

I = 

average annual or ozone season emission rate in 

lbs/mmBbtu of all EGUs in the CPS group. 

heat input for the annual or ozone control period of each 

EGU, in mmBtu. 

actual annual S02 tons of each EGU in the CPS group. 

actual annual or ozone season NOx tons of each EGU in the 

CPS group. 

number ofEGUs that are in the CPS group.' 

each EGU in the CPS group. 

(Source: Amended at 33 Ill. Reg. 10427, effective June 26, 2009) 

Section 225.296 Combined Pollutant Standard: Control Technology Requirements for NO., S02, 

and .PM Emissions 

a) Control Technology Requirements for NO, and S02• 

1) On or before December 31,2013, the owner or operator must either 

permanently shut down or install and have operational FGD equipment on 

Waukegan 7; 

2) On or before December 31, 2014, the owner or operator must either 

permanently shut down or install and have operational FGD equipment on 

Waukegan 8; 

3) On or before December 31, 2015, the owner or operator must either 

permanently shut down or install and have operational FGD equipment on 

Fisk 19; 

4) If Crawford 7 will be operated after December 31, 2018, and not 

permanently shut down by this date, the owner or operator must: 

A) On or before December 31, 2015, install and have operational SNCR 

or equipment capable of delivering essentially equivalent NO, 

reductions on Crawford 7; and 

14 
B) On or before December 31, 2018, install and have operational FGD 

equipment on Crawford 7; 

5) If Crawford 8 will be operated after December 31, 2017 and not permanently 

shut down by this date, the owner or operator must: 

A) On or before December 31, 2015, install and have operational SNCR 

or equipment capable of delivering essentially equivalent NO, 

emissions reductions on Crawford 8; and 

B) On or before December 31, 2017, install and have operational FGD 

equipment on Crawford 8, 

b) Other Control Technology Requirements for S02. Owners or operators of specified 

EGUs must either permanently shut down or install FGD equipment on each 

specified EGU (except Joliet 5), on or before December 31, 2018, unless an earlier 

date is specified in subsection (a) of this Section. 

c) Control Technology Requirements for PM. The owner or operator of the two 

specified EGUs listed in this subsection that are equipped with a hot-side ESP must 

replace the hot-side ESP with a cold-side ESP, install an appropriately designed 

fabric filter, or permanently shut down the EGU by the dates specified. Hot-side 

ESP means an ESP on a coal-tired boiler that is installed before the boiler's airpreheater where the operating temperature is typically at least 550° F, as 

distinguished from a cold-side ESP that is installed after the air pre-heater where 

the operating temperature is typically no more than 350° F. 

1) Waukegan 7 on or before December 31, 2013; and 

2) Will County 3 on or before December 31, 2015. 

d) Beginning on December 31, 2008, and annually thereafter up to and including December 

31, 2015, the owner or operator of the Fisk power plant must submit in writing to the 

Agency a report on any technology or equipment designed to affect air quality that has 

been considered or explored for the Fisk power plant in the preceding 12 months. This 

report will not obligate the owner or operator to install any equipment described in the 

report. 

e) Notwithstanding 35 Ill. Adm. Code 201.146(hhh), until an EGU has complied with 

the applicable requirements of subsections 225.296(a), (b), and (c), the owner or 

operator ofthe EGUmust obtain a construction permit for any new or modified air 

pollution control equipment that it proposes to construct for control of emissions of 

mercury, NOx. PM, or S02. 

(Source: Added at 33 Ill. Reg. 10427, effective June. 26, 2009) 

15 
225.APPENDIX A Speciiled EGUs for Purposes of the CPS (Midwest Generation's Coal-Fired 

Boilers as of July 1, 2006) 

Plant Permit Boiler Permit designation CPS 

Number Designation 

Crawford 031600AIN 7 Unit 7 Boiler BLRI Crawford 7 

8 Unit 8 Boiler BLR2 Crawford 8 

Fisk 031600AMI 19 Unit 19 Boiler BLR19 Fisk 19 

Joliet 197809AAO 71 Unit 7 Boiler BLR71 Joliet 7 

72 Unit 7 Boiler BLR72 Joliet 7 

81 Unit 8 Boiler BLR81 Joliet 8 

82 Unit 8 Boiler BLR82 Joliet 8 

5 Unit 6.Boiler BLR5 Joliet 6 

Powerton 179801AAA 51 Unit 5 Boiler BLR 51 Powerton5 

52 Unit 5 Boiler BLR 52 PowertonS 

61 Unit 6 Boiler BLR 61 . Powerton 6 

. 62 Unit 6 Boiler BLR 62 PGwerton 6 

Waukegan 097190AAC 17 Unit 6 Boiler BLR17 Waukegan6 

7 Unit 7 Boiler BLR7 Waukegan 7 

8 Unit 8 Boiler BLR8 Waukegan8 

Will County 197810AAK 1 Unit 1 Boiler BLR1 Will County 1 

2 Unit 2 Boiler BLR2 Will County 2 

3 Unit 3 Boiler BLR3 Will County 3 

4 Unit 4 Boiler BLR4 Will County 4 

(Source: Amended at 33 Ill. Reg. 10427, effective Jlm.e 26, 2009) 

16 
Exhibit 13 

Proposed Revisions to Illinois SIP for Regional Haze 

Appro11al and Promulgation of Air Quality Implementation Plans; 

Illinois; Regional Haze; 77 Fed. Reg. 3999 (Jan. 26, 2012). 
[Federal Register Volume 77, Number 17 (Thursday, January 26, 2012)] 

[Proposed Rules] 

[Pages 3966-3975] 

orom the Federal Register Online via the Government Printing Office [www.gpo.gov] 

[FR Doc No: 2012-1606] 

======================================================================= 

~NVIRONMENTAL PROTECTION AGENCY 

lO CFR Part 52 

[EPA-ROS-OAR-2011-0598; FRL-9622-6] 

\pproval and Promulgation of Air Quality Implementation Plans; 

[llinois; Regional Haze 

\GENCY: Environmental Protection Agency (EPA). 

\CTION: Proposed rule. 

3UMMARY: EPA is proposing to approve revisions to the Illinois State 

[mplementation Plan (SIP) addressing regional haze for the first 

lmplementation period. Illinois submitted its regional haze plan on 

June 24, 2011. The Illinois regional haze plan addresses Clean Air Act 

(CAA) section 169B and Regional Haze Rule requirements for states to 

~emedy any existing and prevent future anthropogenic impairment of 

risibility at mandatory Class I areas. EPA is also proposing to approve 

~wo state rules and incorporating two permits into the SIP. 

)ATES: Comments must be received on or before February 27, 2012. 

\DDRESSES: Submit your comments, identified by Docket ID No. EPA-ROS-

)AR-2011-0598, by one of the following methods: 

1. www. regulations. gov: Follow the on-line instructions for 

3ubmitting comments. 

2. Email: blakley.pamela@epa.gov. 

3. Fax: (312) 692-2450. 

4. Mail: Pamela Blakley, Chief, Control Strategies Section, Air 

0 rograms Branch (AR-18J), U.S. Environmental Protection Agency, 77 West 

Jackson Boulevard, Chicago, Illinois 60604. 

5. Hand Delivery: Pamela Blakley, Chief, Control Strategies 

3ection, Air Programs Branch (AR-lBJ), U.S. Environmental Protection 
\gency, 77 West Jackson Boulevard, Chicago, Illinois 60604. Such 

ieliveries are only accepted during the Regional Office normal hours of 

lperation, and special arrangements should be made for deliveries of 

loxed information. The Regional Office official hours of business are 

1onday through Friday, 8:30 a.m. to 4:30p.m., excluding Federal 

wlidays. 

Instructions: Direct your comments to Docket ID No. EPA-R05-0AR-

'011-0598. EPA's policy is that all comments received will be included 

_n the public docket without change and may be made available online at 

IWW.requlations.gov, including any personal information provided, 

mless the comment includes information claimed to be Confidential 

lusiness Information (CBI) or other information whose disclosure is 

:estricted by statute. Do not submit information that you consider to 

le CBI or otherwise protected through www.regulations.gov or email. The 

1ww.regulations.gov Web site is an ''anonymous access'' system, which 

Jeans EPA will not know your identity or contact information unless you 

lrovide it in the body of your comment. If you send an email comment 

iirectly to EPA without going through www.regulations.gov your email 

tddress will be automatically captured and included as part of the 

:omment that is placed in the public docket and made available on the 

:nternet. If you submit an electronic comment, EPA recommends that you 

.nclude your name and other contact information in the body of your 

:omment and with any disk or CD-ROM you submit. If EPA cannot read your 

:omment due to technical difficulties and cannot contact you for 

:larification, EPA may not be able to consider your comment. Electronic 

'iles should avoid the use of special characters, any form of 

'ncryption, and be free of any defects or viruses. For additional 

.nstructions on submitting comments, go to Section I of this document. 

Docket: All documents in the docket are listed in the 

1ww.regulations.gov index. Although listed in the index, some 

.nformation is not publicly available, e.g., CBI or other information 

~ose disclosure is restricted by statute. Certain other material, such 

ts copyrighted material, will be publicly available only in hard copy. 

'ublicly available docket materials are available either electronically 

.n www.regulations.gov or in hard copy at the Environmental Protection 

lgency, Region 5, Air and Radiation Division, 77 West Jackson 

loulevard, Chicago, Illinois 60604. This facility is open from 8:30 

t.m. to 4:30p.m., Monday through 

• [Page 3967]] 

'riday, excluding Federal holidays. We recommend that you telephone 

1att Rau, Environmental Engineer, at (312) 886-6524 before visiting the 

\egion 5 office. 

cOR,FURTHER INFORMATION CONTACT: Matt Rau, Environmental Engineer, 

:ontrol Strategies Section, Air Programs Branch (AR-18J), Environmental 

'rotection Agency, Region 5, 77. West Jackson Boulevard, Chicago, 

lllinois 60604, (312) 886-6524, rau.matthew@epa.gov. 
3UPPLEMENTARY INFORMATION: Throughout this document whenever 

''us,'' or ''our'' is used, we mean EPA. 

fable of Contents 

I. What should I consider as I prepare my comments for EPA? 

II. What is the background for EPA's proposed action? 

III. What are the requirements for regional haze SIPs? 

IV. What is EPA's analysis of Illinois' regional haze plan? 

J. What action is EPA taking? 

JI. Statutory and Executive Order Reviews 

I. What should I consider as I prepare my comments for EPA? 

When submitting comments, remember to: 

we, ' ' 

l. Identify the rulemaking by docket number and other identifying 

Lnformation (subject heading, Federal Register date and page number) 

2. Follow directions--EPA may ask you to respond to specific 

1uestions or organize comments by referencing a Code of Federal 

'egulations (CFR) part or section number. 

3. Explain why you agree or disagree; suggest alternatives and 

3Ubstitute language for your requested changes. 

4. Describe any assumptions and provide any technical information 

lnd/or data that you used. 

5. If you estimate potential costs or burdens, explain how you 

lrrived at your estimate in sufficient detail to allow for it to be 

~eproduced. 

6. Provide specific examples to illustrate your concerns, and 

Juggest alternatives. 

7. Explain your views as clearly as possible, avoiding the use of 

Jrofanity or personal threats. 

B. Make sure to submit your comments by the comment period deadline 

_dentified. 

:I. What is the background for EPA's proposed action? 

\. The Regional Haze Problem 

Regional haze is visibility impairment that is produced by a 

1ultitude of sources and activities located across a broad geographic 

!rea that emit fine particles (PM2.5) (e.g., sulfates, 

1itrates, organic carbon, elemental carbon, and soil dust) and its 

Jrecursors--sulfur dioxide (S02), nitrogen oxides 

(NOX), and in some cases ammonia (NH3) and 

rolatile organic compound (VOCs). Fine particle precursors react in the 

ltmosphere to form fine particulate matter. Aerosol PM2.5 

Lmpairs visibility by scattering and absorbing light. Visibility 

Lmpairment reduces the clarity and distance one can see. 

'M2.5 can also cause serious health effects and mortality in 
tuman~ and contributes to detrimental environmental effects such as 

tcid deposition and eutrophication. 

Data from the existing visibility monitoring network, the 

'Interagency Monitoring of Protected Visual Environments'' (IMPROVE) 

1onitoring network, show that visibility impairment caused by air 

10llution occurs virtually all of the time at most national park and 

rilderness areas. The average visual range, the distance at which an 

1bject is barely discernable, in many Class I areas \1\ in the western 

lnited States is 100-150 kilometers. That is about one-half to two-

:hirds of the visual range that would exist without anthropogenic air 

1ollution. In the eastern and midwestern Class I areas of the United 

:tates, the average visual range is generally less than 30 kilometers, 

>r about one-fifth of the visual range that would exist under estimated 

tatural conditions. 64 FR 35715 (July 1, 1999). 

\1\ Areas designated as mandatory Class I Federal areas consist 

>f national parks exceeding 6000 acres, wilderness areas, and 

tational memorial parks exceeding 5000 acres and all international 

1arks that were in existence on August 7, 1977. 42 U.S.C. 7472(a) 

n accordance with section 169A of the CAA, EPA, in consultation 

rith the Department of Interior, promulgated a list of 156 areas 

rhere visibility is identified as an important value. 44 FR 69122 

November 30, 1979). The extent of a mandatory Class I area includes 

;ubsequent changes in boundaries, such as park expansions. 42 U.S.C. 

'472(a). Although states and tribes may designate as Class I 

tdditional areas which they consider to have visibility as an 

.mportant value, the requirements of the visibility program set 

'orth in section 169A of the CAA apply only to ''mandatory Class I 

"ederal areas.'' Each mandatory Class I Federal area is the 

:esponsibility of a ''Federal Land Manager.'' 42 U.S.C. 7602(i). 

/hen we use the term ''Class I area,'' we mean ''mandatory Class I 

'ederal area. ' ' 

l. Requirements of the Clean Air Act and EPA's Regional Haze Rule 

In section 169A of the 1977 Amendments to the CAA, Congress created 

l program for protecting visibility in the nation's national parks and 

vilderness areas. Th1s section of the CAA establishes as a national 

roal the ''prevention of any future, and the remedying of any existing, 

lmpairment of visibility in mandatory Class I Federal areas which 

lmpairment results from manmade air pollution.'' On December 2, 1980, 

<:FA promulgated regulations to address visibility impairment in Class I 

>reas that is ''reasonably attributable'' to a single source or small 

Jroup of sources known as, ''reasonably attributable visibility 

Lmpairment'' (RAVI). 45 FR 80084. These regulations represented the 

first phase in addressing visibility impairment. EPA deferred action on 

cegional haze that emanates from a variety of sources until monitoring, 

nodeling, and scientific knowledge about the relationships between 
:oollutants and visibility impairment were improved. 

Congress added section 169B to the CAA in 1990 to address regional 

1aze issues. EPA promulgated the Regional Haze Rule (RHR) on July 1, 

1999 (64 FR 35713). The RHR revised the existing visibility regulations 

:o integrate into the regulations provisions addressing regional haze 

Lmpairment and established a comprehensive visibility protection 

)rogram for Class I areas. The requirements for regional haze, found at 

10 CFR 51.308 and 51.309, are included in EPA's visibility protection 

cegulations at 40 CFR 51.300-309. Some of the main elements of the 

cegional haze requirements are summarized in section III. The 

cequirement to submit a regional haze SIP applies to all 50 states, the 

)istrict of Columbia, and the Virgin Islands.\2\ 

\2\ Albuquerque/Bernalillo County, New Mexico must also submit a 

:egional haze SIP to satisfy the section 110 (a) (2) (D) requirements 

lf the CAA for the entire state under the New Mexico Air Quality 

:ontrol Act (section 74-2-4). 

Roles of Agencies in Addressing Regional Haze 

Successful implementation of the regional haze program will require 

_ong-term regional coordination among states, tribal governments, and 

'ederal agencies. Pollution affecting the air quality in Class I areas 

:an be transported over long distances, even hundreds of kilometers. 

~herefore, effectively addressing the problem of visibility impairment 

_n Class I areas means that states need to develop coordinated 

;trategies that take into account the effect of emissions from one 

jurisdiction on the air quality of another state. 

EPA has encouraged the states and tribes to address visibility 

_mpairment from a regional perspective because the pollutants that lead 

:o regional haze can originate from sources located across broad 

jeographic areas. Five regional planning organizations (RPOs) were 

ieveloped to address regional haze and 

[[Page 3968]] 

:elated issues. The RPOs first evaluated technical information to 

letter understand how their states and tribes impact Class I areas 

>cross the country and then pursued the development of regional 

Jtrategies to reduce PM2.5 emissions and other pollutants 

Leading to regional haze. 

The Midwest RPO (MRPO) is a collaborative effort of state 

Jovernments and various Federal agencies established to initiate and 

~oordinate activities associated with the management of regional haze, 

Tisibility, and other air quality issues in the Midwest. The member 

3tates are Illinois, Indiana, Michigan, Ohio, and Wisconsin. 

III. What are the requirements for regional haze SIPs? 
Regional haze SIPs must assure reasonable progress toward the 

1ational goal of achieving natural visibility conditions in Class I 

ireas. Section 169A of the CAA and EPA's implementing regulations 

~equire states to establish long-term strategies for making reasonable 

)regress toward meeting this goal. Plans must also give specific 

lttention to certain stationary sources that were in existence on 

\ugust 7, 1977, but were not in operation before August 7, 1962, and 

mst require those sources to install emission controls reducing 

risibility impairment if appropriate. The specific regional haze SIP 

:equirements are discussed in further detail below. 

\. Determination of Baseline, Natural, and Current Visibility 

:onditions 

The RHR establishes the deciview \3\ (dv) as the principal metric 

lr unit for expressing visibility impairment. This visibility metric 

~xpresses uniform proportional changes in haziness in terms of common 

.ncrements across the entire range of visibility conditions, from 

Jristine to extremely hazy conditions. Visibility expressed in 

!eciviews is determined by using air quality measurements to estimate 

.ight extinction and then transforming the value of light extinction 

tsing a logarithm function. The deciview is a more useful measure for 

:racking progress in improving visibility than light extinction itself 

Jecause each deciview change is an equal incremental change in 

•isibility perceived by the human eye. Most people can detect a change 

n visibility at one deciview. 

\3\ The preamble to the RHR provides additional details about 

:he deciview. 64 FR 35714, 35725 (July 1, 1999). 

The deciview is used in expressing RPGs, defining baseline, 

:urrent, and natural conditions, and tracking changes in visibility. 

~he regional haze SIPs must contain measures that ensure ''reasonable 

Jrogress'' toward the national goal of pieventing and remedying 

•isibility impairment in Class I areas caused by anthropogenic air 

Jollution. The national goal is a return to natural conditions such 

:hat anthropogenic sources of air pollution would no longer impair 

risibility in Class I areas. 

To track changes in visibility over time at each of the 156 Class I 

lreas covered by the visibility program (40 CFR 81.401-437) and as part 

,f the process for determining reasonable progress, states must 

;alculate the degree of existing visibility impairment at each Class I 

lrea at the time of each regional haze SIP submission and at the 

'regress review every five years, midway through each 10-year 

.mplementation period. The RHR requires states with Class I areas 

(Class I states) to determine the degree of impairment in deciviews for 
:he average of the 20 percent least impaired (best) and 20 percent most 

[mpaired (worst) visibility days over a specified time period at each 

Jf its Class I areas. Each state must also develop an estimate of 

1atural visibility conditions for the purpose of comparing progress 

:oward the national goal. Natural visibility is determined by 

ostimating the natural concentrations of pollutants that cause 

Jisibility impairment and then calculating total light extinction based 

Jn those estimates. EPA has provided guidance to states regarding how 

:o calculate baseline, natural, and current visibility conditions in 

iocuments titled, EPA's Guidance for Estimating Natural Visibility 

:onditions Under the Regional Haze Rule, September 2003, (EPA-454/B-03-

]05 located at http://www.epa.gov/ttncaaal/tl/memoranda/rh envcurhr gd.pdf) 

(hereinafter referred to as ''EPA's 2003 Natural Visibility 

;uidance' ') and Guidance for Tracking Progress Under the Regional Haze 

~ule (EPA-454/B-03-004 September 2003 located at http://www.epa.gov/ttncaaal/tl/ 

nemoranda/rh tpurhr gd. pdf) (EPA's 2003 Tracking Progress 

;uidance) . 

For the first regional haze SIP, the ''baseline visibility 

~onditions'' are the starting points for assessing ''current'' 

Jisibility impairment. Baseline visibility conditions represent the 

iegree of visibility impairment for the 20 percent best days and 20 

Jercent worst days for each calendar year from 2000 to 2004, Using 

nonit6ring data for 2000 throUgh 2004, states calculate the average 

iegree of visibility impairment for each Class I area, based on the 

>verage of annual values over the five-year period. The comparison of 

Lnitial baseline visibility conditions to natural visibility conditions 

Lndicates the amount of improvement necessary to attain natural 

risibility, while the future comparison of baseline conditions to the 

:hen current conditions will indicate the amount of progress made. In 

Jeneral, the 2000 to 2004 baseline period is considered the time from 

vhich improvement in visibility is measured. 

3. Determination of Reasonable Progress Goals (RPGs) 

The vehicle for ensuring continuing progress towards achieving the 

1atural visibility goal is the submission of a series of regional haze 

3IPs from the states that establish two distinct RPGs, one for the best 

lays and one for the worst days for every Class I area for each 

>pproximately 10-year implementation period. The RHR does not mandate 

3pecific milestones or rates of progress, but instead calls for states 

:o establish goals that provide for ''reasonable progress'' toward 

>chieving natural visibility conditions. In setting RPGs, Class I 

3tates must provide for an improvement in visibility for the worst days 

Jver the approximately 10-year period of the SIP and ensure no 

iegradation in visibility for the best days. 

Class I states have significant discretion in establishing RPGs, 

Jut are required to consider the following factors established in 

3ection 169A of the CAA and in EPA's RHR at 40 CFR 51.308 (d) (1) (i) (A) 

(1) The costs of compliance; (2) the time necessary for compliance; (3) 
:he energy and non-air quality environmental impacts of compliance; 

1nd, (4) the remaining useful life of any potentially affected sources. 

rhe state must demonstrate in its SIP how these factors are considered 

Jhen selecting the RPGs for the best and worst days for each applicable 

:lass I area. States have considerable flexibility in how they take 

:hese factors into consideration, as noted in EPA's Guidance for 

letting Reasonable Progress Goals Under the Regional Haze Program, 

: ' 'EPA's Reasonable Progress Guidance' '), July 1, _ 2007, memorandum from 

lilliam L. Wehrum, Acting Assistant Administrator for Air and 

'adiation, to EPA Regional Administrators, EPA Regions 1-10 (pp. 4-2, 

;-1). In setting the RPGs, states must also consider the rate of 

1rogress needed to reach natural visibility conditions by 2064 

:·'uniform rate of progress'' or ''glide path' 'I ·and the emissions 

:eduction needed to achieve that rate of progress over the 

tpproximately 10-year period of the SIP. 

• [Page 3969]] 

:n setting RPGs, each Class I state must also consult with potentially 

:ontributing states, i.e. those states that may affect visibility 

_mpairment at the Class I state's areas. 40 CFR 51.308(d)(l)(iv). 

Best Available Retrofit Technology (BART) 

Section 169A of the CAA directs states to evaluate the use of 

:etrofit controls at certain older large stationary sources to address 

•isibility impacts f_rom these sources. Specifically, CAA section 

69A(b) (2) (A) requires states to revise their SIPs to contain such 

1easures as may be necessary to make reasonable progress towards the 

tatural visibility goal including a requirement that certain categories 

1f existing major stationary sources built between 1962 and 1977 

1rocure, install, and operate BART as determined by the state. The set 

1f ''major stationary sources'' potentially subject to BART is listed 

_n CAA section 169A(g) (7). The state can require source-specific BART 

:ontrols, but it also has the flexibility to adopt an alternative such 

ts a trading program as long as the alternative provides greater 

1rogress towards improving visibility than BART. 

On July 6, 2005, EPA published the Guidelines for BART 

leterminations Under the Regional Haze Rule at Appendix Y to 40 CFR 

'art 51 (BART Guidelines) to assist states in determining which of 

:heir sources should be subject to the BART requirements and in 

ietermining appropriate emission limits for each applicable source. A 

ltate must use the approach in the BART Guidelines in making a BART 

ietermination for fossil fuel-fired electric generating units (EGUs) 

Jith total generating capacity in excess of 750 megawatts. States are 

oncouraged, but not required, to follow the BART Guidelines in making 

3ART determinations for other sources. 

States must address all visibility-impairing pollutants emitted by 

> source in the BART determination process. The most significant 

Jisibility impairing pollutants are S02, NOX, and 
?M. EPA has stated that states should use their best judgment in 

)etermining whether VOC or NH3 compounds impair visibility 

Ln Class I areas. 

States may select an exemption threshold value for their BART 

nodeling under the BART Guidelines, below which a BART-eligible source 

vould not be expected to cause or contribute to visibility impairment 

Ln any Class I area. The state must document this exemption threshold 

ralue in the SIP and must state the basis for its selection of that 

ralue. The exemption threshold set by the state should not be higher 

:han 0.5 dv. Any source with emissions that model above the threshold 

ralue would be subject to a BART determination review. The BART 

;uidelines acknowledge varying circumstances affecting different Class 

: areas. States should consider the number of emission sources 

lffecting the Class I areas at issue and the magnitude of the 

.ndividual source's impact. 

The state must identify potential BART sources in its SIP, 

!escribed as ·'BART-eligible sources'' in the RHR, and document its 

lART control determination analyses. In making BART determinations, 

;ection 169A(g) (2) of the CAA requires the state to consider the 

'allowing factors: ( 1) The costs of compliance; ( 2) the energy and nontir quality environmental impacts of compliance; (3) any existing 

lollution control technology in use at the source; (4) the remaining 

tseful life of the source; and, (5) the degree of improvement in 

risibility which may reasonably be anticipated to result from the use 

lf such technology. A regional haze SIP must include source-specific 

lART emission limits and compliance schedules for each source subject 

:o BART. The BART controls must be installed and in operation as 

expeditiously as practicable, but no later than five years after the 

!ate of EPA's approval of the state's regional haze SIP. CAA section 

.69 (g) (4); 40 CFR 51.308 (e) (1) (iv). In addition to what is required by 

:he RHR, general SIP requirements mandate that the SIP must also 

.nclude all regulatory requirements related to monitoring, 

:ecordkeeping, and reporting for the BART controls on the source. 

). Long-Term Strategy 

Consistent with the requirement in section 169A(b) of the CAA that 

;tates include in their regional haze SIP a 10 to 15 year strategy for 

laking reasonable progress, section 51.308 (d) (3) of the RHR requires 

:hat states include a long-term strategy (LTS) in their regional haze 

>IPs. The LTS is the compilation of all control measures a state will 

tse during the implementation period of the specific SIP submittal to 

1eet applicable RPGs. The LTS must include enforceable emissions 

.imitations, compliance schedules, and other measures as necessary to 

tchieve the RPGs for all Class I areas within or affected by emissions 

'rom the state. 40 CFR 51.308 (d) (3). 

When a state's emissions are reasonably anticipated to cause or 

:ontribute to visibility impairment in a Class I area located in 

!nother state, the RHR requires the impacted state to coordinate with 

:he contributing states in order to develop coordinated emissions 
nanagement strategies. 40 CFR 51.308 (d) (3) (i). In such cases, the 

:ontributing state must demonstrate that it has included in its SIP all 

neasures necessary to obtain its share of the emission reductions 

1eeded to meet the RPGs for the Class I area. The RPOs have provided 

:arums for significant interstate consultation, but additional 

:onsultations between states may be required to address interstate 

risibility issues sufficiently. 

States should consider all types of anthropogenic sources of 

risibility impairment in developing their LTS, including stationary, 

1inor, mobile, and area sources. At a minimum, states must describe how 

oach of the following seven factors are taken into account in 

ieveloping their LTS: ( 1) Emission reductions due to ongoing air 

Jollution control programs, including measures to address RAVI; (2) 

1easures to mitigate the impacts of construction activities; ( 3) 

omissions limitations and schedules for compliance to achieve the RPG; 

:4) source retirement and replacement schedules; (5) smoke management 

:echniques for agricultural and forestry management purposes including 

Jlans as currently exist within the state for these purposes; ( 6) 

'nforceability of emissions limitations and control measures; and, (7) 

:he anticipated net effect on visibility due to projected changes in 

Joint, area, and mobile source emissions over the period addressed by 

:he LTS. 40 CFR 51.308(d) (3) (v). 

:. Coordinating Regional Haze and Reasonably Attributable Visibility 

:mpairment Long-Term Strategy 

EPA revised 40 CFR 51.306(c) as part of the RHR regarding the LTS 

:or RAVI to require that the RAVI plan must provide for a periodic 

:eview and SIP revision not less frequently than every three years 

1ntil the date of submission of the state's first plan addressing 

:egional haze visibility impairment in accordance with 40 CFR 51.308(b) 

>nd (c). The state must revise its plan to provide for review and 

:evision of a coordinated LTS for addressing RAVI and regional haze on 

Jr before this date. It must also submit the first such coordinated LTS 

•ith its first regional haze SIP. Future coordinated LTSs, and periodic 

Jrogress reports evaluating progress towards RPGs, must be submitted 

:onsistent with the schedule for SIP submission and periodic progress 

:eports set forth in 40 CFR 51.308(f) and 51.308(g), respectively. 

[[Page 3970]] 

Che periodic review of a state's LTS must report on both regional haze 

>nd RAVI impairment and be submitted to EPA as ·a SIP revision. 

"· Monitoring Strategy and Other Implementation Plan Requirements 

.Section 51.308 (d) (4) of the RHR includes the requirement for a 

nonitoring strategy for measuring, characteriiing, and reporting of 

regional haze visibility impairment that is representative of all 

nandatory Class I Federal areas within the state. The strategy must be 
=oordinated with the monitoring strategy required in section 51.305 for 

~VI. Compliance with this requirement may be met through participation 

Ln the IMPROVE network, meaning that the state reviews and uses 

nonitoring data from the network. The monitoring strategy must also 

Jrovide for additional monitoring sites if the IMPROVE network is not 

3Ufficient to determine whether RPGs will be met. The monitoring 

3trategy is due with .the first regional haze SIP and must be reviewed 

~very five years. 

The SIP must also provide for the following: 

Procedures for using monitoring data and other information 

Ln a state with mandatory Class I areas to determine the contribution 

)f emissions from within the state to regional haze visibility 

Lmpairment at Class I area.s both within and outside of the state; 

Procedures for using monitoring data and other information 

Ln a state with no mandatory Class I areas to determine the 

~ontribution of emissions from within the state to regional haze 

risibility impairment at Class I areas in other states. 

Reporting of all visibility monitoring data to the 

\dministrator at least annually for each Class I area in the state, and 

vhere possible in electronic format; 

A statewide inventory of emissions of pollutants that are 

~easonably anticipated to cause or contribute to visibility impairment 

.n any Class I area. The inventory must include emissions for a 

Jaseline year, emissions for the most recent year with available data, 

!nd future projected emissions. A state must also make a commitment to 

1pdate the inventory periodically; and 

Other elements including reporting, recordkeeping, and 

Jther measures necessary to assess and report on visibility; 

The RHR requires control strategies to cover an initial 

.mplementation period extending to the year 2018 with a comprehensive 

:eassessment and revision of those strategies, as appropriate, every 10 

rears thereafter. Periodic SIP revisions must meet the core 

:equirements of section 51,308(d) with the exception of BART. The 

:equirement to evaluate sources for BART applies only to the first 

:egional haze SIP. Facilities subject to BART must continue to comply 

1ith the BART provisions of section 51.308(e), as noted above. Periodic 

;IP revisions will assure that the statutory requirement of reasonable 

Jrogress will continue to be met. 

,. Consultation With States and Federal Land Managers 

The RHR requires that states consult with Federal Land Managers 

:FLMs) before adopting and submitting their SIPs. 40 CFR 51.308(i). 

;tates must provide FLMs an opportunity for consultation, in person and 

;t least 60 days prior to holding any public hearing on the SIP. This 

:onsultation must include the opportunity for the FLMs to discuss their 

;ssessment of impairment of visibility in any Class I area and to offer 

:ecommendations on the development of the RPGs and on the development 

;nd implementation of strategies to address visibility impairment. 
<urther, a state must include in its SIP a description of how it 

iddressed any comments provided by the FLMs. Finally, a SIP must 

Jrovide procedures for continuing consultation between the state and 

"LMs regarding the state's visibility protection program, including 

ievelopment and review of SIP revisions, five-year progress reports, 

>nd the implementation of other programs having the potential to 

;ontribute to impairment of visibility in Class I areas. 

cV. What is EPA's analysis of Illinois' regional haze plan? 

Illinois submitted its regional haze plan on June 24, 2011, which 

cncluded revisions to the Illinois SIP to address regional haze. 

i. Class I Areas 

States are required to address regional haze affecting Class I 

1reas within a state and in Class I areas outside the state that may be 

1ffected by the state's emissions. 40 CFR 51.308(d). Illinois does not 

1ave any Class I areas within the state. Illinois reviewed technical 

1nalyses conducted by MRPO to determine what Class I areas outside the 

;tate are affected by Illinois emission sources. MRPO conducted both a 

)ack trajectory analysis and modeling to determine the affects of its 

;tates' emissions. The conclusion from the technical analysis is that 

'missions from Illinois sources affect 19 Class I areas. The affected 

:lass I areas are: Sipsey Wilderness Area in Alabama; Caney Creek and 

Jpper Buffalo Wilderness Areas in Arkansas; Mammoth Cave in Kentucky; 

1cadia National Park and Moosehorn Wilderness Area in Maine; Isle 

loyale National Park and Seney Wilderness Area in Michigan; Boundary 

laters Canoe Wilderness Area in Minnesota; Hercules-Glades and Mingo 

lilderness Areas in Missouri; Great Gulf Wilderness Area in New 

lampshire; Brigantine Wilderness Area in New Jersey; Great Smoky 

lountains National Park in North Carolina and Tennessee; Lye Brook 

lilderness Area in Vermont; James River Face Wilderness Area and 

>henandoah National Park in Virginia; and, Dolly Sods/Otter Creek 

lilderness Area in West Virginia. 

l. Baseline, Current, and Natural Conditions 

The RHR requires states with Class I areas to calculate the 

)aseline and natural conditions for their Class I areas. Because 

:llinois does not have any Class I areas, it was not required to 

1ddress the requirements for calculating baseline and natural 

;ondi tions. 

Reasonable Progress Goals 

Class I states must set RPGs that achieve reasonable progress 

~oward achieving natural visibility conditions. Because Illinois does 

10t have any Class I areas, it is not required to establish RPGs. 

Cllinois consulted with affected Class I states to ensure that it 
lchieves its share of the overall emission reductions necessary to 

lchieve the RPGs of Class I areas that it impacts. Illinois's 

:oordination with affected Class I states is discussed under Illinois 

Long Term Strategy, in Section IV. E. 

Illinois included the MRPO technical support document (TSD) in its 

submission. In Section 5 of the TSD, MRPO assessed the reasonable 

Jrogress for regional haze. It first assessed potential control 

neasures using the four factors required to be considered by Class I 

states when selecting the RPGs: the cost of compliance, time needed, 

3nergy and non-air impacts, and remaining useful life of any 

JOtentially affected sources. The cost of compliance factor includes 

:alculating the average cost effectiveness and can include costs to 

1ealth and industry vitality as well as considering the different 

Jisibility effects of different pollutants. The time necessary for 

:ompliance factor considers whether control measures can be implemented 

)y 2018. The third factor, energy and non-air quality impacts, 

:onsiders additional energy consumed by or because of the control 

neasure as well as effects due to waste 

[[Page 3971]] 

Jenerated or water consumption. The final factor, remaining useful 

Life, allows states to consider planned source retirements in 

;alculating costs. 

MRPO also assessed the visibility benefits of existing programs. 

1RPO considered existing on-highway mobile source, off-highway mobile 

;ource, area source, power plant, and other point source programs. MRPO 

1lso included reductions from the Clean Air Interstate Rule (CAIR) in 

.ts analysis, as well from rules adopted by Illinois and included in 

.ts regional haze SIP requiring the control of emissions from EGOs. 

Illinois has a distinctive situation regarding CAIR, insofar as it 

1as adopted state rules that require EGOs to control NOX and 

)02 emissions beyond the control expected from CAIR, even in 

:he absence of CAIR, particularly by 2018 and beyond. Further 

liscussion of these Illinois rules is provided below. The RPGs that 

Jertinent Class I states have adopted are predicated on other 

:ontributing states achieving the EGO emission reductions anticipated 

1nder CAIR. Since Illinois is mandating a greater degree of control 

:han is expected from other states, EPA concludes that Illinois's 

:egional haze plan is expected to provide emission reductions 

:epresenting an appropriate contribution toward meeting the RPGs for 

:he affected Class I areas, irrespective of the status of CAIR and 

.rrespective of the associated issues regarding the adequacy of other 

;tate's plans. For similar reasons, EPA believes that the approvability 

Jf the Illinois plan is also not affected by the status of the 

'ransport Rule, which was promulgated on August 8, 2011 at 76 FR 48208 

1nd stayed on December 30, 2011. 

). Best Available Retrofit Technology 
States are required to submit an implementation plan containing 

omission limitations representing BART and schedules for compliance 

'ith BART for each BART-eligible source that may reasonably be 

>nticipated to cause or contribute to any impairment in a Class I area, 

1nless the State demonstrates that an emissions trading program or 

Jther alternative will achieve greater reasonable progress toward 

1atural visibility conditions. 40 CFR 51.308(e). 

Using the criteria in the BART Guidance at 40 CFR 51.308(e) and 

~ppendix Y, Illinois first identified all of the BART-eligible sources 

1nd assessed whether the BART-eligible sources were subject to BART. 

:llinois initially identified 26 potential BART facilities--11 EGOs, 

'our petroleum refineries, three chemical process plants, two Portland 

:ement plants, two glass fiber processing plants, one lime plant, and 

Jne iron and steel plant. The state further analyzed these facilities 

:o identify those sources subject to BART. Illinois relied on modeling 

:onducted by MRPO using a modeling protocol MRPO developed. MRPO 

:onferred with its states, EPA, and the FLMs in developing its BART 

10deling protocol. EPA guidance says that, ·'any threshold that you use 

'or determining whether a source 'contributes' to visibility impairment 

;hould not be higher than 0.5 dv.'' The Guidelines affirm that states 

tre free to use a lower threshold if the location of a large number of 

\ART-eligible sources in proximity of a Class I area justifies this 

tpproach. Illinois used a contribution threshold of 0.5 dv for 

letermining which sources warrant being subject to BART. Illinois 

:oncluded that the threshold of 0.5 dv was appropriate since its BART-

>ligible sources are located state-wide and no Class I areas are nearby 

:ausing Illinois to correctly conclude that a stricter contribution 

:hreshold is not justified. The modeled impact of these facilities 

.ndicated that 11 sources have at least 0.5 dv impact (98th percentile) 

md thus are subject to BART. The 11 sources determined to be subject 

:o BART are nine EGOs and two petroleum refineries. The other 15 

>otential BART sources were determined not to be subject to BART 

>ecause the analysis showed impacts well below the 0.5 dv contribution 

:hreshold. 

The EGOs subject to BART are: 

Dynegy Midwest Generating--Baldwin Boilers 1, 2, and 3. 

Dominion Kincaid Generation--Boilers 1 and 2. 

Ameren Energy Generating--Coffeen Boilers CB-1 and CB-2. 

Ameren Energy Generating--E.D. Edwards Boilers 2 and 3. 

Ameren Energy Generating--Duck Creek Boiler 1. 

Midwest Generation--Powerton Boilers 51, 52, 61, and 62. 

Midwest Generation--Joliet Boilers 71, 72, 81, and 82. 

Midwest Generation--Will County Boiler 4. 

City Water, Light, and Power--Dallman Boiler 1 and 2. 

City Water, Light, and Power--Lakeside Boiler 8. 

To address mercury emissions from EGOs, Illinois adopted Part 225 

Jf Illinois's air pollution regulations, entitled ''Control of 

:missions from Large Combustion Sources.'' In this rule, Illinois 

Jffered affected utilities two options, one of which imposes stringent 

_imits on mercury emissions alone and the other of which mandates 
Lmplementation of specific mercury control technology in conjunction 

Nith satisfaction of stringent emission limits for S02 and 

~OX. Part 225 includes section 225.233, entitled ''Multi-

"ollutant Standards,'' addressi.ng emissions from facilities owned by 

~eren and Dynegy, and sections 225.293 to 225.299, collectively 

r-eferred to as the Combined Pollutant Standards (CPS), addressing 

=missions from facilities owned by Midwest Generation. In all cases, 

:he utilities have selected the option including mercury control 

:echnology and applicability of the S02 and NOX 

Limits. The emission limits are in the earlier noted sections of the 

state rules, so these S02 and NOX limits are now 

fully enforceable by the state. 

The S02 and NOX emission limits in Part 225 

:ules reflect substantial averaging across units and across facilities. 

"or example, the collective set of facilities in Illinois owned by 

1idwest Generation (as listed in the Part 225 rules) are subject to 

~OX and S02 limits based on annual average 

emissions across all facilities. The limit for NOX emissions 

ls 0.11 pounds per million British Thermal Units (lb/MMBTO) starting in 

2012 and the limits for S02 are 0.15 lb/MMBTU in 2017 and 

J.11 lb/MMBTU starting in 2019. The collective set of Ameren facilities 

ln Illinois, under the Multi-Pollutant Standards (MPS), must meet an 

>nnual average emission limit for NOX of 0.11 lb/MMBTU 

;tarting in 2012 and for S02 of 0.23 lb/MMBTU starting in 

2017. Similar limits under the MPS apply to the Dynegy facilities in 

:llinois. 

EPA believes this degree of averaging is acceptable in this 

~ontext. The limits that Illinois has imposed are sufficiently 

;tringent that the companies have only limited latitude to over control 

>t some facilities in trade for having elevated emissions at other 

'acilities. The facilities owned by each company are sufficiently close 

:o each other, relative to their distances from the nearest Class I 

>reas, that modest shifts in emissions from one facility to another 

;hould have minimal impact on the combined impact on regional haze at 

:he Class I areas. Furthermore, regional haze is evaluated across a 

~onsiderable number of days, e.g., the 20 percent of days with the 

Jorst visibility. Therefore, a limit that allows elevated emissions on 

.ndividual days, so long as other days have lower emissions, should 

;uffice to address the pertinent measures of regional haze. Illinois's 

.imits should also be adequately enforceable since the sources at issue 

ire required to conduct continuous emission monitoring of both 

302 and NOX. 

[[Page 3972]] 

Dynegy has five facilities with 10 units covered by MPS, including 

:he three Dynegy Baldwin units that are subject to BART. Emission 

~eductions required for seven other Dynegy units not subject to BART 

vill allow it meet the MPS reduction requirements. MPS will reduce 
emissions from all Dynegy facilities by 23,831 tons per year (TPY) of 

~OX and 47,347 TPY of S02, as compared to 

emissions in the 2002 base year. 

Ameren has seven facilities with 21 units covered by MPS. This 

Lncludes the subject to BART units: Coffeen units 1 and 2, Duck Creek 

1nit 1, and Edwards units 2 and 3. Ameren has install~d selective 

:atalytic reduction (SCR) for NOX control and wet scrubbers 

:o limit S02 emissions from both Coffeen units. Duck Creek 

1nit 1 is controlled by low NOX burners, SCR, and wet 

3crubbers. Edwards unit 2 will receive an upgraded low NOX 

Jurner and overfire air (OFA) to reduce NOX emissions. 

'dwards unit 3 is already controlled for NOX with low 

'lOX burners·, OFA, and SCR. Ameren plans to install a new 

3crubber and fabric filter at Edwards unit 3. Company-wide reductions 

Erom Ameren EGUs are projected to be 27,896 TPY NOX and 

l31,367 TPY S02 by 2015 and 134,464 TPY of S02 by 

2017. 

Midwest Generating operates six facilities with 19 total units that 

nust comply with CPS, including the Midwest Generation units subject to 

3ART: Powerton units 51, 52, 61, and 62; Joliet units 71, 72, 81, and 

32; and Will County unit 4. The four Powerton units currently have low 

'lOX burners and OFA. Midwest Generation plans to add 

3elective non-catalytic reduction (SNCR) in 2012 to reduce 

'lOX emissions and flue gas desulfurization (FGD) in 2013 to 

:ut S02 emissions. Both control improvements will be .added 

:o all four units. Midwest Generating's Joliet facility currently has 

low NOX burners and OFA on its four BART units. SNCR is 

!Xpected to be added in 2012 to all four BART units. Midwest Generating 

ls also planning to add FGD on units 71, 72, 81, and 82 by 2019. Will 

:ounty unit 4 is currently controlled with low NOX burners 

md OFA. Midwest Generating plans to upgrade the NOX control 

:o SNCR in 2012 and to add FGD control by 2019. CPS will reduce 

'lOX emissions from all Midwest Generating facilities by 

38,155 TPY, while S02 emissions will decrease by 35,465 TPY 

ln 2015, increasing to a 61,194 TPY reduction in 2019. 

A state may opt to implement an alternate measure rather than 

:equiring each subject to BART unit to install, operate, and maintain 

3ART if it demonstrates that the alternate measure will achieve greater 

:easonable progress. The criteria for the assessment if an alternative 

neasure demonstrates greater reasonable progress are provided in 40 CFR 

)1.308 (e) (2). MPS will reduce emissions from both subject to BART and 

1on-BART units at the Ameren and Dynegy facilities. Similarly, CPS will 

require emission reductions from Midwest Generation's subject to BART 

>nd non-BART units. Illinois elected to use MPS and CPS participation 

>S alternative to requiring BART control on each of the Ameren, Dynegy, 

>nd Midwest Generation units subject to BART. Illinois stated that 

Lmplementation of the MPS and CPS emission limits will provide much 

jeeper NOX and S02 reductions than implementing 

3ART on the subject to BART units and thus the alternate will provide 

Jreater reasonable progress. However, Illinois did not provide an 
>nalysis comparing BART for each subject unit to the alternative. 

Illinois compared the emission reductions from MPS and CPS to the 

Jresumptive BART emission levels suggested in EPA's guidance. EPA 

Jenerally requires states to compare the alternative strategy to a 

fully analyzed set of BART limits for the BART-subject units. However, 

Ln this case, the results of such a comparison are clear even without 

Illinois conducting a full BART analysis for these units. The total 

~OX emission reductions due to MPS on Dynegy EGUs are 

Jreater than the base year NOX emissions from Dynegy's 

subject to BART units. Therefore, the emission reductions from MPS are 

Jreater than the maximum possible reductions from the BART units. The 

same is true for S02 emissions for the Dynegy EGUs, the 

~OX emissions from the Ameren EGUs, and the S02 

omissions from the Ameren EGUs. Similarly, the total NOX 

omission reductions from all Midwest Generating are greater than the 

~OX emissions from the BART units and the same for its 

302 emissions. Therefore, even without a full analysis of 

:he precise emission levels that would constitute BART for the BARTsubject units, EPA finds that the Illinois rules, MPS and CPS, are an 

>cceptable BART alternative because the emission reductions are greater 

:han the reductions that could possibly be obtained by only requiring 

3ART at the BART-subject units. 

Three other EGUs, owned by two other utilities Dominion Energy and 

:he City of Springfield's City Water, Light, and Power (CWLP), are not 

:overed by MPS and CPS but have units subject to BART. CWLP is a 

3maller utility with a total generating capacity of less than 750 MW 

>nd Dominion Energy has only one electric generating facility in 

Cllinois such that these utilities do not have the opportunities for 

nulti-plant averaging of emission limits that the larger utilities 

1ave. Rather than adopting an alternative program to address the BART 

~equirements for these two utilities, Illinois is requiring these 

1tilities to meet the BART requirements for the units subject to BART 

>nd establish enforceable emission limits for S02 and 

JOX. CWLP's Dallman and Lakeside plants, along with 

Jominion's Kincaid plant, have units subject to BART. Both utilities 

nust reduce emissions to meet the BART limits. The emission limits for 

)allman units 31 and 32, Lakeside unit 8, and Kincaid units 1 and 2 are 

:ontained in Joint Construction and Operating permits. Illinois 

ovaluated potential controls and what control level the current 

omission controls can achieve in setting the BART emission limits for 

:he CWLP Dallman and Dominion Kincaid units. 

CWLP currently has SCRs and FGD on Dallman units 31 and 32. As of 

2010, CWLP has been operating the SCRs to achieve an annual average 

~OX emission rate of 0.14 lb/MMBTU on both Dallman units, 

:ombined. The annual average NOX emission rate will be 

Limited to 0.12 lb/MMBTU by 2015 and then further decreased to 0.11 lb/ 

1MBTU by 2017 for both units, combined. CWLP will operate the controls 

:o achieve an annual average S02 emissions rate on both 

)allman units, combined, of 0.29 lb/MMBTU by 2012, then reduced to 0.25 

Lb/MMBTU by 2015, and finally to 0.23 lb/MMBTU by 2017. Illinois has 
ietermined these emission limits satisfy BART for both units. CWLP 

Jermanently shut down Lakeside unit 8 in 2009, which is reflected in 

:he permit. 

Dominion's Kincaid facility operates SCRs on its units 1 and 2. The 

Jermit for the Kincaid facility limits NOX emissions to an 

lnnual average of 0.07 lb/MMBTU by March 1, 2013, on both units, 

:ombined. Illinois determined the appropriate S02 control 

;ystem for Kincaid is a dry sorbent injection system along with using 

_ow sulfur coal. Illinois initially gave the Kincaid facility a 

;o2 emission limit of 0.20 lb/MMBTU on both units, but found 

:hat a stricter limit of 0.15 lb/MMBTU can be achieved with the control 

;ystem. Illinois thus set the S02 emission limits for both 

~incaid units, combined, at an annual average emission rate of 0.20 lb/ 

lMBTU by January 1, 2014, and reduced the limit further to an annual 

tverage emission rate of o·.15 lb/MMBTU beginning on January 1, 2017. 

Illinois issued the Joint Construction and Operating permits 

mrsuant to its 

[Page 3973]] 

tuthority in the SIP and submitted the two permits as part of its 

legional Haze plan to be incorporated into the SIP. The permits set 

'ederally enforceable NOX and S02 limits as 

tecessary to meet the Regional Haze requirements of the CAA and 

'ffectively mandate that the utilities to run the SCRs year round and 

'or CWLP to shut down its Lakeside unit 8. 

Two petroleum refineries, the CITGO and Exxon Mobil refineries, 

llso have units subject to BART: the CITGO refinery in Lemont, Illinois 

lnd the Exxon Mobil refinery south of Joliet, Illinois. Both refineries 

1ill be required to reduce emissions by a Federal consent decree 

:esolving an enforcement action brought by EPA against a number of 

:efineries. The consent decrees require the CITGO, Exxon Mobil, and the 

>ther refineries to operate controls at the Best Available Control 

~echnology level. Illinois evaluated the subject-to-BART units at the 

:ITGO and Exxon Mobil refineries. It found that the NOX and 

;o2 emission limits on the subject-to-BART units in the 

:onsent decrees satisfy BART. 

A consent decree between the United States and CITGO Petroleum 

:orporation was entered in the U.S. District Court for the Southern 

listrict of Texas on October 6, 2004 (No. H-04-3883). The consent 

iecree requires the company to operate SCR and a wet scrubbing system 

lt its Fluid Catalytic Cracking Unit (FCCU) that will reduce 

JOX emissions by more than 90 percent and S02 

;missions by 85 percent. The controls on the FCCU will result in a 

~eduction of NOX emissions from 1,065.7 to 106.6 TPY and 

302 emissions from 10,982.5 to 107.9 TPY by 2013. CITGO has 

1lso added a tail gas recovery unit that reduces 302 

;missions from its sulfur train units from 4340.0 to 91.2 TPY, a 98 

Jercent reduction. The emission controls on all units at CITGO's Lemont 

cefinery will reduce NOX emissions by 1,268 TPY and 
302 emissions by 15,123 TPY. 

A consent decree between the United States and Exxon Mobil 

=orporation was entered in the U.S. District Court for the Northern 

Jistrict of Illinois on October 11, 2005 (No. 05-C-5809). The consent 

jecree for Exxon Mobil requires SCR operation on its FCCU in addition 

:o maintenance of the existing wet scrubbing system. The controls on 

:he FCCU result in a 1,636.2 TPY decrease in NOX emissions 

Erom 1,818.0 to 181.8 TPY and a 9,667.7 TPY decrease in S02 

=missions from 9,865.0 to 197.3 TPY. Exxon Mobil also has added a tail 

~as recovery unit on its south sulfur recovery unit. That reduces 

302 emissions by 9,153.8 TPY to 186.8 TPY. The emission 

=ontrols at Exxon Mobil's Joliet refinery will reduce 1,695 TPY 

~ox and 18,821 TPY so2. 

These two consent decrees are Federally enforceable and also 

require that the refineries submit permit applications to Illinois to 

Lncorporate the required emission limits into Federally enforceable air 

)ermits (other than Title V). Therefore, emission limits established by 

:he consent decrees may be relied upon by Illinois for addressing the 

3ART requirement for these facilities. 

Based on modeling, MRPO determined that the visibility impact of 

iirectly emitted particulate matter from the facilities with subject to 

3ART units is minimal. In particular, MRPO assessed the impact of the 

iirectly emitted particulate matter from all facilities potentially 

mbject to BART in the five MRPO states, and found the impact to be 

.ess than 0.5 dv at any Class I area as compared to natural background 

:onditions. Illinois therefore concludes that PM emissions from its 

;ubset of these BART sources have a negligible visibility impact. 

"urthermore, these facilities are already subject to federally 

~nforceable PM emission control requirements mandated by SIP-approved 

;tate particulate matter regulations, so that there is minimal 

lotential for further PM emission reductions. Therefore, based 

larticularly on the substantial existing controls on these facilities-

"abric filters, electrostatic precipitators, and cyclones; and-the 

1inimal benefits of further control, Illinois concluded that BART did 

1ot include further control of PM emissions from these facilities. 

EPA is satisfied with the state's BART determinations. The emission 

.imits that Illinois adopted generally will require state-of-the-art 

'mission controls, not just at the units subject to BART requirements 

JUt also at numerous units that are not subject to BART. The Illinois 

:acilities subject to BART are a long distance from any Class I area 

;uch that, so the geographical redistributions of emissions within 

:llinois do not significantly affect visibility and the benefits of 

llternate control strategies may be judged simply by comparing the net 

~mission reductions .. The MPS and CPS provide emission reduction well in 

~xcess of simply implementing BART on subject units. The reduction ln 

lOX emissions from the Ameren, Dynegy, and Midwest 

;eneration units by 2015 from MPS and CPS is expected to be 89,882 TPY. 

:llinois estimated that simply implementing BART on the subject units 

:rom these entities would yield 32,992 TPY of NOX emission 
ceductions, which is 56,890 TPY less that from MPS and CPS. Illinois 

;stimated that implementing BART on the subject units at Ameren, 

Jynegy, and Midwest Generation facilities would require an 117,252 TPY 

:eduction in S02 emission, but MPS and CPS will require a 

~14,179 TPY S02 reduction by 2015. Thus, Illinois estimated 

:hat its plan will require 96,927 TPY lower S02 emissions 

:han simply requiring BART. EPA believes that Illinois has thereby 

lemonstrated the emission limits on the subject to BART units covered 

>y MPS and CPS satisfy the BART requirements. 

Illinois did not rely on the Clean Air Interstate Rule (CAIR) for 

.ts BART determinations. Illinois is in the CAIR region. However, it 

tsed its state rules, permits, and consent decrees to achieve emission 

·eductions that satisfy BART. This means that Illinois is not reliant 

>n CAIR and, thus, it has avoided the issues of other CAIR region 

:tates that relied on CAIR. For similar reasons, Illinois' satisfaction 

>f regional haze rule requirements is not contingent on the Transport 

cule and thus is not affected by the stay of that rule. 

:. Long-Term Strategy 

Under section 169A(b) (2) of the CAA and 40 CFR 51.308(d), states' 

:egional haze programs must include an LTS for making reasonable 

>regress toward meeting the national visibility goal. Illinois's LTS 

lust address visibility improvement for the Class I areas impacted by 

:llinois sources. Section 51. 30 8 (d) ( 3) requires that Illinois consult 

rith the affected states in order to develop a coordinated emission 

lanagement strategy. A contributing state, such as Illinois, must 

lemonstrate that it has included, in its SIP, all measures necessary to 

>btain its share of the emissions reductions needed to meet the RPGs 

'or the Class I areas affected by Illinois sources. As described in 

:ection III.D. of this proposed rule, the LTS is the compilation of all 

:ontrol measures Illinois will use to meet applicable RPGs. The LTS 

1ust include enforceable emissions limitations, compliance schedules, 

>nd other measures as necessary to achieve the RPGs for all Class I 

>reas affected by Illinois emissions. 

Illinois complied with the consulting requirements by participating 

_n meetings and conference calls with affected Class I states and RPOs 

:o discuss the states' assessments of visibility conditions, analyses 

Jf culpability, and possible measures that could be taken to meet 

risibility goals. Illinois engaged in extensive 

[[Page 3974]] 

:onsultations with other MRPO states, including Indiana, Michigan, 

)hio, and Wisconsin. Illinois also consulted with Arkansas, Kentucky, 

1innesota, Missouri, New Hampshire, New Jersey, and Vermont. As part of 

:he MRPO, Illinois participated in inter-RPO consultation on regional 

1aze. This consultation is detailed in Chapter 9 of the state's.plan. 

O:PA finds that the state's consultation with Class I states satisfies 

>pplicable consultation requirements. 
Illinois's LTS includes the modeling and monitoring results on 

'hich it relied to determine its share of emission reductions necessary 

:o meet the reasonable progress goals of impacted Class I areas. This 

information is provided in Chapter 9 of the Illinois regi9nal haze 

Jlan. Portions of this technical work were provided by MRPO as it 

'orked with other RPOs to provide this information on Class I areas 

JUtside the Midwest. 

At 4 0 CFR 51. 308 (d) ( 3) (v) , the RHR identifies seven factors that a 

state must consider in developing its LTS: (A) Emission reductions due 

:o ongoing programs; (B) measures to mitigate impact from construction; 

(C) emission limits to achieve the RPG; (D) replacement and retirement 

Jf sources; (E) smoke management techniques; (F) Federally enforceable 

omission limits and control measures; and (G) the net effect on 

Jisibility due to projected emission changes over the LTS period. 

rllinois considered the seven factors in developing its LTS. Chapter 8 

)f the Illinois regional haze plan provides a full analysis of each 

:actor. 

Illinois relied on MRPO's modeling and analysis along with its 

'mission information in developing a LTS. Illinois considered the 

:actors set out in 51.308 (d) (3) (v) in developing its LTS. Based on 

:hese factors and the MRPO's technical analysis, in conjunction with 

tPGs that were set by the pertinent Class I states in consultation with 

:llinois and other contributing states, Illinois concludes that 

'xisting control programs, together with the BART controls described 

1bove, address Illinois's impact on Class I areas. This is because the 

:ombination of the existing controls and the BART controls suffice to 

1eet the impacted Class I areas' RPGs by 2018. These existing control 

Jrograms include Federal motor vehicle emission control program, 

~eformulated gasoline, emission limits for area sources of VOCs, Title 

:v, the NOX SIP Call, NOX Reasonable Achievable 

:ontrol Technology, Maximum Achievable Control Technology standards, 

tnd Federal non-road standards for construction equipment and vehicles. 

's discussed in prior sections, implementation of the existing control 

'rograms, supplemented by the control measures in the submission that 

~equire power plant and petroleum refinery emission reductions, will 

:atisfy the LTS requirements because, for reasons discussed above, the 

:xpected emission reductions will meet requirements both to provide for 

iART and to provide emission reductions in Illinois that, in 

:ombination with emission reductions elsewhere, should improve 

·isibility sufficiently for the pertinent Class I areas to meet their 

~PGs. 

Illinois assessed all point sources in the state that emit at least 

,000 TPY of NOX and 802 combined and are more 

:han 100 km from a Class I area to determine if the sources could 

JOtentially affect visibility in a Class I area. The assessment 

allowed EPA guidance in calculating the ratio of emission rate in TPY 

Q) to the distance to the nearest Class I area (d). The exclusions 

tlso followed guidance. Illinois found 15 facilities with a Q/d ratio 

:qual to and greater than 10, EPA's recommended threshold. The results 

>f the Q/d assessment are found in Table 8.1 in the Illinois TSD. 
cllinois found that it expects the implementation of existing control 

1easures will result in emission reductions from the 15 facilities. As 

>uch, Illinois believes that the expected emission reductions will 

~nsure reasonable progress. 

' Monitoring Strategy 

Illinois maintains a monitoring network that provides data to 

tnalyze air quality problems including regional haze. Illinois's 

1onitoring network includes State and Local Air Monitoring Sites 

:sLAMS), Special Purpose Monitors (SPM), Photochemical Assessment 

!onitoring Sites (PAMS), and PM2.5 speciation sites. 

:llinois does not operate any sites under the IMPROVE program, but does 

tave a site in Bondville, Illinois that monitors using the IMPROVE 

Jrocedure method. Illinois is required under 40 CFR 51.308(d) (4) to 

tave procedures for using the monitoring data to determine the 

:ontribution of emissions from within the state to affected Class I 

treas. Illinois developed procedures in conjunction with the MRPO. The 

Jrocedures are detailed in the MRPO TSD. EPA finds that Illinois's 

:egional haze plan meets the monitoring requirements for the RHR and 

:hat Illinois's network of monitoring sites is satisfactory to measure 

tir quality and assess its contribution to regional haze. 

'· Federal Land Manager Consultation 

Illinois was required to consult with the FLMs under 40 CFR 

>1.308(i). Illinois consulted with the FLMs electronically and by· 

:elephone. The FLMs were also included in discussions with Illinois 

luring MRPO conference calls and meetings. A draft regional haze plan 

ras submitted for FLMs comments on August 6, 2009. Illinois then 

Jrovided the FLMs a revised regional haze plan on October 7, 2010 for 

.·eview. That provided the FLMs enough time to comment prior to the 

lecember 6, 2010, public hearing on the regional haze plan. Illinois 

tas included comments from the FLMs in Attachment 9 to its regional 

taze plan, a document providing the comments Illinois received and its 

:esponses. The state has committed to consulting the FLMs on future SIP 

:evisions and progress reports. 

! . Comments 

Illinois took comments on its proposed regional haze plan. It held 

1 public hearing on December 6, 2010. The public comment period ended 

Jn January 5, 2011. Evidence of the public notice and evidence of the 

Jublic hearing were submitted to EPA. 

Illinois's submission includes a document, Attachment 9, which 

>ummarized the comments it received from both the FLMs and from the 

Jublic and provides its responses to the comments. The state revised 

Jortions of its plan based on the comments to correct errors and 

:larify portions that caused confusion. Illinois responded to other 

:ornments without revising its plan. EPA concludes that Illinois has 
3atisfied the requirements from 40 CFR Part 51, Appendix V to provide 

~vidence that it gave public notice, took comments, and that it 

=ompiled and responded to comments. 

J. What action is EPA taking? 

EPA is proposing to approve revisions to the Illinois SIP, 

3Ubmitted on June 24, 2011, addressing regional haze for the first 

Lmplementation period. The revisions address CAA and regional haze rule 

cequirements for states to remedy any existing anthropogenic and 

~revent future impairment of visibility at Class I areas. EPA finds 

=hat Illinois has satisfied all the requirements and, thus, is 

~reposing approval of the regional haze plan. EPA is also proposing to 

>pprove two state rules, MPS and CPS, and incorporating two permits, 

Lssbed to City Water, Light, & Power and to Dominion Energy, into the 

3IP. 

[[Page 3975]] 

JI. Statutory and Executive Order Reviews 

Under the CAA, the Administrator is required to approve a SIP 

3Ubmission that complies with the provisions of the CAA and applicable 

"ederal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a). Thus, in 

:eviewing SIP submissions, EPA's role is to approve state choices, 

)rovided that they meet the criteria of the CAA. Accordingly, this 

1ction merely approves state law as meeting Federal requirements and 

loes not impose additional requirements beyond those imposed by state 

.aw. For that reason, this action: 

Is not a ·"significant regulatory action'' subject to 

~eview by the Office of Management and Budget under Executive Order 

.2866 (58 FR 51735, October 4, 1993); 

Does not impose an information collection burden under the 

Jrovisions of the Paperwork Reduction Act (44 U.S.C. 3501 et seq.); 

Is certified as not having a significant economic impact 

Jn a substantial number of small entities under the Regulatory 

'lexibility Act (5 U.S.C. 601 et seq.); 

Does not contain any unfunded mandate or significantly or 

miquely affect small governments, as described in the Unfunded 

landates Reform Act of 1995 (Pub. L. 104-4); 

Does not have Federalism implications as specified in 

:xecutive Order 13132 (64 FR 43255, August 10, 1999); 

Is not an economically significant regulatory action based 

Jn health or safety risks subject to Executive Order 13045 (62 FR 

.9885, April 23, 1997); 

Is not a significant regulatory action subject to 

:xecutive Order 13211 (66 FR 28355, May 22, 2001); 

Is not subject to requirements of Section 12(d) of the 

Jational Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 
1ote) because application of those requirements would be inconsistent 

;i th the CAA; and 

Does not provide EPA with the discretionary authority to 

>ddress, as appropriate, disproportionate human health or environmental 

~ffects, using practicable and legally permissible methods, under 

executive Order 12898 (59 FR 7629, February 16, 1994). 

In addition, this rule does not have tribal implications as 

;pecified by Executive Order 13175 (65 FR 67249, November 9, 2000), 

Jecause the SIP is not approved to apply in Indian country located in 

:he state, and EPA notes that it will not impose substantial direct 

:osts on tribal governments or preempt tribal law . 

• ist of Subjects in 40 CFR Part 52 

Environmental protection, Air pollution control, Intergovernmental 

·elations, Nitrogen dioxide, Particulate matter, Reporting and 

.·ecordkeeping requirements, Sulfur oxides, Volatile organic compounds. 

Dated: January 17, 2012. 

:usan Hedman, 

~egional Administrator, Region 5. 

FR Doc. 2012-1606 Filed 1-25~12; 8:45 am] 

iiLLING CODE 6560-50-P