## Exhibit 1

Map Depicting Ameren's Power Stations and Agency Air Quality Monitoring Stations

Illinois Environmental Protection Agency, Illinois AnnualAir 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 ofAir 1021 North Grand Avenue, East P.O. Box 19276 Springfield, IL 62794-9276

Printed on recycledpaper2010 EXECUTIVE SUMMARY

This report presents a sunnnary ofair quality data collected throughout the State ofIllinois during the calendaryear

- 2010. Data is presented for the six criteria pollutants (those for which air quality standards have been developed- particulate matter (PM10 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 ofthe Air Quality Index (AQI) air quality during 2010 was either good or moderate 91 percent ofthe time throughout Illinois. There were no days when air quality in some part ofIllinois

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 ofIllinois 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 belowthe level ofthe standards. Percentage changes over the ten year period 2001-2010 are as follows: Particulate Matter (PM1o) 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 inthe report reflects information contained in the Emission Inventory System (EIS) as ofDecember 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 ofthese 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 10-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 0I 02 03 04 05 06 07 08 09 I0

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

QIllinois Annual Air Quality Report 2010

Figure 2 

### shows for each year the statewide average ofthe 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 ofmeteorological 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 ofthe 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 PM1**~** 

### 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 ofAir 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 106 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 

# J

# 1

50 

### I I 

### 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

SULFURDIOXIDE


### There were 50 exceedances ofthe new 1-hour primary standard of 75 ppb in 2010 compared with 68 exceedances in 2009. There were no exceedances ofthe 3-hour secondary standard of 500 ppb in 2010. The annual and 24-hour primary standards were revoked by USEPA 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 ofthe 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 B17).

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 annualIllinois 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 ofthe
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 PAMS. 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 ofthe 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 

# l**~** 

# l 

# l '0 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

## Statewide Air Monitoring Site Locations

ID

__



### '

__5

..'_

. 6' 7 NAME Alsip**~!llage; !;>_~ra_ge** _**~~ro_r~**..**HEal_~** !'J_e_P.art_m_ej1_t

__**_B~U_E** ls_!_a_n_d**~~-~~-n~~~~-** HS.**Br!!~wood_Com~ ~1?-~~in_te_n_!IIC:'O_** **-~-~-ry ~~o~~**  l;l,_s

.__**~Ci-~.f?JEf'A ~~.i!'O~** __

Ci_<:,Em**U~_erty** S_ch_o_o!_ Des**Pl~ine~_Reg!o_na!_p_f_fice_** B_uilding J'l!l'in_ t,ars_e_11**Ju_~l£r.I::!:S,_** ElginMcKinley**~~ool_** Evanston**Wate~ Pumpin~**  St:stion**J~l~-~~i~~~~!l- El~~~** **~t-~ry ~ct,-~,;~** **X():JOR~** .....YS_OgRD.**fll~** ..**t::C?~E** 439028.14 4613506.98 170310001 3B9528,1<1:_4626729.16**_l?D_~_D_~l7.**

. .**~-~15-!!~ -~-s~~~~~m**  __**l.?.IB:~~o~~ _4Q_Q.1~-~l-** **~-6:4_!1~_?_,~~** P!:'IJ!P.!J:.**39]'~0~**_ _¥751!:Q,15**17111~1 43753~2-~-~33~_z7p_** **l?Q_31~~-~ 437~2.17**  _46_34984.05 179316005·**_4~85_4_~.5~ ."!~?~79?-_86_** **!?~~l~p7_**

-.**~9~§!~06 -~~_§g1_?:_~~** **1:?E_~D_O_D5**

394074.74_ 4656154.53 1708900[)3_**~~-,~~ -~§85_7** **-~~- ..l?~~?OQ~** 

---**~_§_8~-~- 4~7~~]:_0** _**_p~7:!fl01:** Joliet Water Plant West ·_____**!D~?~Q,~_i ~~-!J9_]:I~?(J(J_-?** 

_**~m~~t_!E~-~~~~~__':_ _.!--'~l~** **N1oJton.~rber~~Uil1_ Lyo!ls_.'I~~ns.~.i~Y!Il_~g_oo__lj~l**  _

_ _**l_v1a\':W_(J_O~ ~_O_!l_J;1~V-~I'!!.~~[)_r:l~~--~~~tf'!frf1** _

_ 12_

_**--~!I'.~.PI:I~--~--~!Tl!:'!~.~-III!~J.n~~~n-~~** _**}B.~ r.rl_~~o-~~-~~~.Q!_.>t_o:~<:!_S.CI_l!~~ui!dlng**  19

..**M~~~e.~hi~!l-!!!~1!!~-rl-'!·5,** ZO**Nap"~[le_~[!y_Hall** 21**N~rthbroo~.INa.ter** Plant

_**~~-- S~~ill!'_r** **~ark** I EPA**T~!Je!r .~:** **~!l~.f!"IJ~§_~_v~_s.Qel!l.~-t~_ri'_?_oh_~o_J** __**2~_ __vva.uk_~~-~** **~o::>~F!re_5~_tio~** 25

_____**Z_i_<:l_f'l_~-ITI~~g~~ .2~_;**  ..**~!:!~~o** __**c_a_ry~~!!~-** __ P:_

_**Cbi~go _c_e~rna.~** **P.':'!"~_5t~tf~_n -~**  _**--~!_~1;~~-0~!:fl-~D** ___ . Z9**chi_sagc_>J.~~<!i~_e_V\I~t~~-~!~_nt**

_**q.~C>l~0..9".A .B!l!~~ing_**  C_hi_"!go**So~t_hW~~er_F)I~!)_<m** Plar:t**S.hi.~~~c_>.'!_t~!§l~**..**~oJ!~-~~-~~~!'-** _**Chi.~g[) SJ!_ri.ngl'ile_~d** **~ump S~ation** 

--**f~i~gc_>J:~ft_lj~_ ~!_~go** **_Un!','e~sJt\1.~-~hi_~ag[) q,i~gc** ..**w~.sh_l!'gtl:ln** _H_-S._ ChJcago**_f\.'lal'_fa)r_~!l[fli'**..**S~ti.on _l!l:l!:lo:I.VJ_I!_e_~_CI_!_m_~t~~~tjc_>!'** **_4_1;:52:8-~- 4613~0.~~~3**  __**:1_,79?_!_160~** 4}_D891l_2fi**--~~~5-~2,!1~ _1]_04~60.0:1,_** **~73 97** **._~i_ <!§_3_~i~,4l3**  __**nt!3_~6_3** • 454702.37 4622802.04 170311XB2**4?~.~s:.i~jj-li'!62_l:i-_:~,?_o.:~i~O-' 44!J0!:!3.8_B_/IJ:i40~54_}~**  __**:1_71!~~:;'** ·**-4?_4~!J::,Qq .:t§~s.?::.~** **J?.~3_1~1l_Q3 _45Q_D~~[)9_**  4§_26?.?£:.¥ .•**!?~3l_Q064,** 455116,70 4615183.98 170310022

-**4~?_85_9,3~**__**4_6~2_1~,';'1'! ]_,70_~;tODg** **-~~2~??~63**..**~~-~~-C!P- .:l.?~lll~[)~l**  40 Carbondale Mainten;mD< Building**31Y.J28B.8~,~l,77?B~** _00.**_]_,70J71l_[)~**

_ 4:1__**S:hal)lp~ign ~oo~~r_T._** **'!Y~_sh~(~it.~n~~~-~~**..ntary

__ 5o:h_ccl**3.95~~-~**..**_444?,2Z~_5_!l_** :Q019_00?4.**42.~** Decatur IEPA TrsJier**----~~5~9._~**__**¥14?6!1.00_1~001_3.'** !l?

_ . __**~~ng_!l~~- r::_~-n~LJ.':'~i~rf-!.5.:** **3~sp~:t_1~43~5?~9_,_0.~~1JI?4~1D_OJ,** 44**Ho!:IS_~fl.B~_I.dy;j!J.~)~e_2_:_1~P_A:rr'!lle!** _**.~7!J5~2--~~~!I·~-Il_ P,t2_7_1l_[)()~;** **~--­ -~,**  4_:?**:~L**... ;49.**~o_ .s~_**  .52;_**_5_~­ -~-----**  ?S_'_**~56** 57_

"62

__ !i3_ 64.**~5; _6~** 

_ 67_,_ :6a_: 

### " 70 n**7~L.** K!'_igl)_t P_r:airie**T~_w<:J~hi!J ~!YII_iU.e** **~o!!~~~e~!_.C~b_le!** TV**M?un~ Ca~_el_pivisio_n_~treet** **Ru~_J ~a~~-'.1:!.** **c_o_~ll!Y ?.~u1;~.!'f!i_~!e** **-~"-'!tOO** 1**J:'!il.~oo__I!!EPA _Tra_\~** **~~­ J:lo~!l\_a_!_IS!-,!** **P~-y~i<:~ll. ~l'!.nt** **_,,gle~-~Y !.~-~-T~!Ieor_**  Peo.ria

__City O_f!lD<_BuJI ding

__**£'~.~!~ Fi_~** **.~!<'!)~n_ ~**  "**_p_~o__r:Ia ~f!l_I)'.~!,~L~** **B-lJ.il~_ing.**

_**.P.~~~.'~ .Heigh~_I!,S·.-**  Lov_es**.~ar~_Maple El_e_m.,~tary**  S_ch_'?91_ Rockford C1ty Hall
_5pringlil_e_ld**-~ewag~_**Trealm!'.nt**~I**ant

_**Spri_n~e:_l_d !'_ub!!~** **~e_al_th ~~reh_o_use!** **Sp~_i'!_!@~-~ J!lin_'?_is_A!l"~~c-~~ll~** **~'!-ilding_**

_**S'!"anse_a_vji~-~ ~aill_~e.tl.~n_ce**  Building Barto.nvill_e Pump**-~tat\on -~oo_~tu~** **~~~-[[er**..**M_~pl ~_t(J~** **_C~t!'P!.II.~r. !'_l_a~t**  _ _Per!'• §e.rnen_!:ary sq.ool

__**~c~f_or~_J._l\_ub_!!J ~l_l_d** **~'!'Pil"-\'_**

_Sterling ?_allk**M~~~!"'JI,cc_i~ic** ALt_on fiar_a_**J!~rtc_>n _Eiell!e_n_ta_ry_:S:~o_o_l**  East5t.**Louis_R~>.P~_:r~~J~_r: -~d':':':ar~_svj)l."-** **-~A~ !!~11!'-.r** **t;r.al1.\~e.£i!y_fi!"': s_;~tion** **-~­** Granite**_t;_ity_~ir Pr~~u.cts** **~!'~~_l_slanl!fl._r:~':_n_a_i:** -" South Rouna_**G~d~_s~~o_ol**

_**~O.~_d_ f!!y_e_r_~!~B_<:_Tr~~t"'!)!'n.t.!'l~n~** **_Je~s~y~U-~ l)l[n.!}"':'l1i~~** _1--I.S. Quincy**J_o~n** Woo_d**_C~m~~~ity** C[)[lege**<:i~~jt~- ~!.tv** **~**..**_t~~-~_\'_~~d!~l**__ Springflleld Blandco B!!ilding _**3_57_4.Bfot_?~,4~s:t77~0[)_:1_7()65[)QO~ :?-_4~~~2~~** **;'129[)59~_pq**_**__!?l~l_,ll.~.**

__432:'4_Lo_o._**4_~Dlnoo**_**_17;!B5o~ol**

_**.-~~?-~_-.Q.6** __:!:_:Z_5_?;!12,-DO_**].~.B?_!l!J_1_**

_**~8-~-~-!18._3~-~9B,5q** }7P,7Dg_02

.**~?~~37,~-~ _44.~?2!;Q.s.o** _ EJ.P2_Q93

_**3~B~L~~-~~ll}lQ_1?~~~~0]** 281616.22' 4508336.50 171430037

-**=2_z5_22~~¥--.~~~:9~:~-~?.;7~~-­**

..**PS.~~-~-~**__**4_?QS_?~_s,,~o 2-?~~~~3!>~** **-~7_970BB _4~_~73~_9.59**  __**1?~~()02~-**

- ..**:?-B)._6J~:~**..**~~f3~3:-?0. _17~'!3-~9-~'** **~~2~~~1- _'!fi¥~8_!.~'** **1~!20_!13 -~~8_11.J2.46B!:_6~~-o_** **,1~_0_1:1**

.278158.03. 44{18840.50_**:17~~~6 _27]_1,~§-_53~** **~-13??~::5.~- P.~€1-~~D_'** **_27~.-z~a.po**__**4;4g~~'~_q_p1f51D_IJ~2 ~73~12._59** **.4W_~~2.50 .~?~~7_00_08** **z:o~o-~_2,Q~** __**4_~6~-~-B o~.** **_g:1_~~1**

.27651S.Oq_; 4S036_7_4¥l _17:143q_llO 333988.(1(.- 4414303.00' 171150110

_**ifb.4~9;Eg_~~i3~_4,_oo=·i71.4322J2" ¥5~!!_.00-** **46~39~!!_,[_(1_ 1?~_10~0** 

,**3P_4:1_1l·9~ _1§7~3_!.(!0_** **!?_~~o. 2750B<~,.oo** ....**~29822.ClQ ,1,:n.,~so~10**  71"?73_1.9.4**:.~~-D:?I.~D!JQ**...**1?!_~~0-~9**_

_**7473?~__,_5§-'--4_308<!~B.~_ ~,7.!!'J~qa_**  ·

-**_?~?~~,-~9' ~2??_55~,~** **1716.~00~0.**

-**~?_5]!0~~-.4~11~,1!0.):?_1_~~**

748727.63: 42:87873.00 171l!l10D7**--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.Table1PowerStationsandUnitsComprisingtheMPSGroup(§104.204(b))AddressBoilersandSizesPollutionS02EmissionsinPermitsissued,issuancedates,ControlRateandTPYapplicationnumbers,andanyotherNumberofEquipment1relevantinformation2EmployeesCoffeenPowerStation(I.D.No.135803AAA)134CIPSLaneUnit1Unit2OFA32011SOzStateO.QeratingPermits:Coffeen,IllinoisSCR4emissionrate=Montgomerynomina13,282nominal5,544ESP5with0.003lb/MMBtuFebruary13,2004CountyrmnBtu/hrmmBtu/hrFGC6App. No.730200022011S02massUnit1156employees(1965)(1972)emissions=82.5tonsFebruary13,2004App. No.73020001Unit2.1allunitsunlessotherwiseindicated2Notethatlistedhereareconstructionpem1itissuedinorafter2005throughthepresentandthatduring thisperiod,Amerenhasbeenissuedotherconstructionpermitsforprojectsnotpertinenttothisrequestforvariance.3overfireair4selectivecatalyticreduction5electrostaticprecipitator6fluegasconditioningTable1 -iTable1PowerStationsandUnitsComprisingtheMPSGroup(§104.204(b)).AddressBoilersandSizesPollutionS02EmissionsinPermitsissued,issuancedates,ControlRateandTPYapplicationnumbers,andanyotherNumberofEquipment1relevantinformation2EmployeesCoffeenPowerStation(I.D.No.135803AAA)ConstructionPermits:December21,2007App.No.07090069NewESPforUnit2December15,2006;revisedOctober.23,2007App.No.06090019NewFGDforUnit1andUnit2June22,2009App.No.06090019RevisedWFGDSystem-LimestonehandlingJune22,2011App.No.11060016FuelAdditivesSystemforUnit1andUnit2March2,2012App.No.12020019TemporaryMercuryRe-EmissionReductionSystemTableI -iiAddressNumberofEmployeesTable1·PowerStationsandUnitsComprisingtheMPSGroup(§104.204(b))BoilersandSizesPollutionSOzEmissionsinPermitsissued,issuancedates,ControlRateandTPYapplicationnumbers,andanyotherEquipment'relevantinformation2CoffeenPowerStation(I.D.No.135803AAA).CAAPPPermit:September29,2005App.No.95090009AppealedNovember3,2005(PCB06-064)StayedFebruary16,2006Table1-iiiTable1PowerStationsandUnitsComprisingtheMPSGroup(§104.204(b))AddressBoilersandSizesPollutionSOzEmissionsinPermitsissued,issuancedates,ControlRateandTPYapplicationnumbers,andanyotherNumberofEquipmenerelevantinformation2EmployeesDuckCreek(I.D.No.057801AAA)17751NorthUnit1LNB'2011SOzStateOJ2eratingPermit:CILCORoadSCRemissionrate=Canton,IllinoisNominal3,713nnnBtu/hrESP0.014lb/MMBtuNovember13,1995FultonCountyFGD8App.No.78020006(1976)2011S02mass72employeesemissions=167ConstructionPermits:-tonsNov.22,2006;revisedMay23,2008App.No.06070049NewWFGD9systemFebruary16,2007App.No.06070048Boilerproject;NewESP7lowNOxburner8fluegasdesulfurization(scmbber)9wetFGDTablel -iv'Table1PowerStationsandUnitsComprisingtheMPSGroup(§104.204(b))AddressBoilersandSizesPollutionS02EmissionsinPermitsissued,issuancedates,ControlRateandTPYapplicationnumbers,andanyotherNumberofEquipment1relevantinformation2EmployeesDuckCreek(I.D.No.057801AAA).May7,2007;revised.January31,2008App.No.07030025PilotAirQualityControlSystemAug15,2011App.No.11080047CantonFuelsCompanyReducedEmissionFuel(REF)ProductionFacilityCAAPPPermit:September29,2005App.No.95070025AppealedNovember3,2005(PCB06-066)StayedFebruary16,2006TableI·vAddressNumberofEmployeesTable1PowerStationsandUnitsComprisingtheMPSGroup(§104.204(b))BoilersandSizesPollutionS02EmissionsinControlRateandTPYEquipment1Permitsissued,issuancedates,applicationnumbers,andanyotherrelevantinformation2E.D.EdwardsPowerStation(I.D.No.143805AAG)7800SouthUnit1Unit2Unit3LNB2011so2State0QeratingPermit:CILCOLaneESPwithemissionrate=Bartonville,nominalnominalnominalFGC0.45lb/MMBtuJulyI,2004Illinois1,5233,3214,594App. No.73010724PeoriaCountymmBtu/hrmmBtulhrmmBtulhrNewLNB2011so2massandOFAonemissions=ConstructionPermits:I08employees(1960)(1968(1972)Unit312,596tonsMarch9,2007App. No.07030026LNBandOFAforUnit3August24,2008App. No.08080029LNBandOFAforUnit2SorbentInjectionSystemUnits1,2,3App. No.08100002September9,2009March30,2011App.No.11030003PilotSystemforHBrinjection(HgControl)forUnit3Tablel-viAddressNumberofEmployeesTable1PowerStationsandUnitsComprisingtheMPSGroup(§I04.204(b))BoilersandSizesPollutionS02EmissionsinControlRateandTPYEquipment1Permitsissued,issuancedates,applicationnumbers,andanyotherrelevantinformation2E.D.EdwardsPowerStation(I.D.No.143805AAG)CAAPPPermit:September29,2005App.No.95070026AppealedNovember3,2005(PCB06-067)StayedFebruary16,2006TableI-viiAddressNumberofEmployeesTable1PowerStationsandUnitsComprisingtheMPSGroup(§104.204{b))BoilersandSizesPollutionSOzEmissionsinPermitsissued,issuancedates,ControlRateandTPYapplicationnumbers,andanyotherEquipmenerelevantinformation2HutsonvillePowerStation(I.D.No.033801AAA)15142East1900"Unit5Unit6ESP2011so2StateOJ2eratingPermit:Ave.emissionrate=Hutsonville,norninal695nomina16952.26lb/MMBtuFebruary17,2005IllinoismmBtu/hrmmBtu/hrApp. No.73020017CrawfordCounty2011so2massUnit5(1952)(1953)emissions=9,8947employeestonsFebruary17,2005App. No.73020018Unit6ConstructionPermits:May14,2006App.No.06040014PilotEvaluationofFuelAdditivesforS02andmercurycontrolApril3,2008App.No.08030017PilotEvaluationofWaterInjectionforPMControlonUnit5TableI -viiiAddressNumberofEmployeesTable1PowerStationsandUnitsComprisingtheMPSGroup(§104.204(b))BoilersandSizesPollutionS02EmissionsinPermitsissued,issuancedates,ControlRateandTPYapplicationnumbers,andanyotherEquipment1relevantinformation2HutsonvillePowerStation(I.D.No.033801AAA)August18,2008App. No.08080015PilotOFAEvaluationforUnits5and6CAAPPPermit:September29,2005App. No.95080105AppealedNovember3,2005(PCB06-070)StayedFebruary16,2006TableI-ixAddressNumberofEmployeesTable1PowerStationsandUnitsComprisingtheMPSGroup(§104.204(b))BoilersandSizesPollutionSOzEmissionsinPermitsissued,issuancedates,ControlRateandTPYapplicationnumbers,andanyotherEquipment'relevantinformation2Joppa(I.D.No.127855AAC)2100PortlandUnits1-6ESP2011SOzStateOQeratingPermit:Roademissionrate=Joppa,Illinoisnomina11,800mmBtu/hreachOFAon0.62lb/MMBtuJune7,2005MassacCountyUnits1,3,5App. No.73010757(Units1and21953)and62011S02mass233employeesemiSSIOns=ConstructionPermits:(Units3and41954)26,180tonsMarch3,2005(Units5and61955)App.No.05020008OFAsystemforUnit6December5,2005App.No.05020011OFAsystemforUnit5November30,2006App. No.0600057OFAsystemforUnit3October24,2007App. No.07090035OFAsystemforUnit1October31,2008App.No.08100052Table1 - xAddressNumberofEmployeesJoppa(I.D.No.127855AAC)Table1PowerStationsandUnitsComprisingtheMPSGroup(§104.204(b))BoilersandSizesPollutionS02EmissionsinPermitsissued,issuancedates,ControlRateandTPYapplicationnumbers,andanyotherEquipmenerelevantinformation2OFAsystemforUnit4March31,2006App.No.06020085PilotforMercuryControlDecember5,2006,revisedOct.30,2007andAug.27,2008App.No.06110002PilotforMercuryControlJuly18,2008,revisedDec.1,2009App.No.08020070SorbentInjectionSystemOct.20,2008,revisedApril21,2009App.No.08090057PilotforSNCRforNOxControlforUnit3April28,2010App.No.11060053PilotforInjectionSystemforS02ControlJune30,2011,revisedFeb.24,2012TableI·xiAddressNumberofEmployeesJoppa(I.D.No.127855AAC)Table1PowerStationsandUnitsComprisingtheMPSGroup(§104.204(b))BoilersandSizesPollutionSOzEmissionsinPermitsissued,issuancedates,ControlRateandTPYapplicationnumbers,andanyotherEquipment1relevantinformation2App.No.11060053AdditivesInjectionSystemCAAPPPermit:September29,2005App.No.95090120AppealedNo,vember3,2005(PCB06-065)StayedFebruary16,2006----TableI-xiiAddressNumberofEmployeesTable1PowerStationsandUnitsComprisingtheMPSGroup(§104.204(b))BoilersandSizesPollutionS02EmissionsinPermitsissued,issuancedates,ControlRateandTPYapplicationnumbers,andanyotherEquipment1relevantinformation2.MeredosiaPowerStation(I.D.No.137805AAA)800SouthUnits1Units3Unit5ESP2011so2StateOQeratingPermits:WashingtonStreetand2 and4emissionrate=Meredosia,IllinoisFGCon0.55lb/MMBtuMay22,1996MorganCountynominalnominalnominalUnits1-4App.No.730200055055052,7842011SOzmassUnit110employeesmmBtu/hrmmBtuJln·nnnBtullrrLNBandemissions=2,747FGContonsMay22,1996eacheach(1957)Unit5App. No.73020009Unit2(1945) (1946)May22,1996.App.No.73020008Unit3May22,1996App.No.73020006Unit4July23,2003App. No.73020007Unit5-Table1 -xiiiAddressNumberofEmployeesTable1PowerStationsandUnitsComprisingtheMPSGroup(§104.204(b))BoilersandSizesPollutionControlEquipment1S02EmissionsinRateandTPYPermitsissued,issuancedates,applicationnumbers,andanyotherrelevantinformation2MeredosiaPowerStation(I.D.No.137805AAA)TableI -xivConstructionPermits:July17,2008App.No.08050025SorbentActivationProcessDemonstrationProjectFebruary15,2007App.No.06120072FGCSystemforBoilersI,2,3and4DecemberI,2009App.No.08070022SorbentInjectionSystemforUnit3/Boiler5August24,2009App.No.09080018LowNOxBurnersandOFASystemforBoiler5CAAPPPennit:September29,2005App.No.95090010AppealedNovember3,2005.AddressNumberofEmployeesTable1PowerStationsandUnitsComprisingtheMPSGroup(§104.204(b))BoilersandSizesPollutionS02EmissionsinPermitsissued,issuancedates,ControlRateandTPYapplicationnumbers,andanyotherEquipment1relevantinformation2MeredosiaPowerStation(I.D.No.137805AAA)(PCB06-069)StayedFebruary16,2006TableI-xvAddressNumberofEmployeesTable1PowerStationsandUnitsComprisingtheMPSGroup(§I04.204(b))BoilersandSizesPollutionS02EmissionsinPermitsissued,issuancedates,ControlRateandTPYapplicationnumbers,andanyotherEquipment1relevantinformation2NewtonPowerStation(I.D.No.079808AAA)6725North500mUnit1Unit2LNB2011S02StateOQeratingPermits:StreetOFAemissionrate=Newton,Illinoisnominal5,500nominal5,500ESPwith0.55lb/MMBtuJuly30,1998JasperCountymmBtu!hrmmBtu!hrFGCApp.No.780800362011S02massUnit1155employees(1972)(1975)PrimaryAiremissions=DuctBurners20,871tonsJune29,2001onUnit2App.No.83020010Unit2ConstructionPermits:June8,2009App.No.09050032PilotEvaluationofFuelAdditivesforMercuryControlDecember1,2009App.No.08010049SorbentInjectionSystemsforUnits1and2December20,2010App.No.10070051FlueGasDesulfurization(FGD)Table1 -xviAddressNumberofEmployeesTable1PowerStationsandUnitsComprisingtheMPSGroup{§104.204(b))BoilersandSizesPollutionS02EmissionsinPermitsissued,issuancedates,ControlRateandTPYapplicationnumbers,andanyotherEquipme:Ut1relevantinformation2NewtonPowerStation(I.D.No.079808AAA)SystemsforUnit1andUnit2February25,2011App. No.08010049RevisedSorbentInjectionSystemandAlternativeControlTechnologyforHgControlforUnit1June30,2011App.No.11060023AdditiveInjectionSystemforMercuryControlonUnit2July28,2011App. No.11070007FuelAdditivesSystemforUnit1November28,2011App. No.11070007FuelAdditivesforUnit1andUnit2CAAPPPermit:September29,2005TableI·xvii'.AddressNumberofEmployeesTable1PowerStationsandUnitsComprisingtheMPSGroup(§104.204(b))BoilersandSizesPollutionS02EmissionsinPermitsissued,issuancedates,ControlRateandTPYapplicationnumbers,andanyotherEquipment1relevantinformation2NewtonPowerStation(I.D.No.079808AAA)App.No.95090066AppealedNovember3,2005(PCB06-068)StayedFebruary16,2006CH2\lll91307.1Table1 -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 UnitspPage 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 t4ethod 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 inPage 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-1 10 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 instructionsPage 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 itsPage 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 ProvisionsPage 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/Hour 1 

### 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 50 2 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/PN 10 and VOt·!i fr-om the affected engine. For this purpose, emissions of S02 and PM/Pf>1 10 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 minimum 1 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!JJuly 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 ofissuance, 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 donein 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 writtenrequest 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. activityis 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 ofequipment constructed or operated under this permit, such equipment and any equipmentrequired to be kept, used, operated, calibrated and maintained.under this permit,

d. to obtain and remove samples of any discharge or emissions ofpollutants, 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 orresulting from the construction, maintenance, or operation of the proposed facilities,

c. does not release the permittee from compliance with other applicable statutes and regulations ofthe 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 090-005e. 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 containedmisrepresentations, 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 ofthe**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 & ChiefExecurive Officer

December 27, 2007

1v1r

_ Jim Ross, Manager Division ofAir Pollution Control Bureau ofAir 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 EnergyResources, as authorized .agent for Ameren Energy Generating Companyl AmerenEnergy Resources Generating Company and Electric Energy Inc., submits this notice ofintent that the -o\oYOers ofthe following eligible electric generating units elect to demonstrate compliancewith tbe multipo11utant emission limitation as an alternative to the emission standards ofSection 225.230. This notice ofintent is submitted for the fallowing emissionunits 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 3Electric 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 anMulti-Pollutant Standard Group for the purpose ofdelll\lnstrating compliance with the requirements of35 Illinois Administrative Code Part225 Subpart B Section 225.233. This notice ofintent includes the following components as attachments to this submittal: the base emission rates for the EGOs and supporting data; a sunnnary ofcurrent pollution control equipmentinstalled; and a surrnnary ofadditional pollution control equipmentthatwill likelybe installed to complywith the MPS.

TheEGUs identified in this notice ofintent have commenc-ed commercial operation on or befOre December 31, 2004 and constitUte all affected EGUs that were owned by the listed affiliates as ofJuly 1, 2006.

I am authorized to make this submission on behalfofthe owners and operators ofthe affectedunlts for which this submission is made. Please contact Steven Wlritworth at (314) 554-4908 ifyou have any questions concerning thjs submittal or ifadditional 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

Attachmentsrnrr •., 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 ofExisting Pollution Control Equipment

Ameren Energy Generating Company

'LD. t Unit**~Control** N<

# ~ I :AA _<: ESl 

### "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 AttachmentB Base Emission RateDetermination

.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.

%ofbase 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 26,012 166,696Ameren 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 10,682p, 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 ofLikely Future Pollution Control Equipment

Ameren Energy Generating Company

[ .Unit N< :Control )
o3: lCI (201: OFA. ."NR o3;**ACq~UL** OFA. ."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

### AFJITDAVIT 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 ofthe 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

ofVirginia.

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 ofthe subsidiaries ofAmeren 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 offlexibility 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 ofAER 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 andcashflow underpressure for most unregulatedpowerproducers-particularly
for those that generate electricity using coal, nuclearpower or hydropower. Historically, power producers have used natural gas to meetpeak electric demand, which typically determines the
price at which these companies sell electricity. Low natural gas prices have encouraged gas· firedpowerproduction in NorthAmerica, adding to thepressure on coal-firedplants, whichface

increasing environmental restrictions. We expect meaningful increases in fuel switching
throughout Nonh America, with natural gas plantsfavored over coal. Most unregulatedpower producers continue to hold a "hunker-down" strategy, conserving capital and liquidity in the
hope ofhigher pricesfor 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 RatingI 

### Negative Outlook
NetIncome 

### $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 ofcertain 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 ofthe
impairment charge was driven primarily bya 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 apermanent change across the US energy sector, and will make it more difficult for coal

to compete with natural gas as apower source in the future. A rise in gas-firedpower generation

will notbe strong enough to raise natural gasprices 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) ofpower 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 ofgas-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 ofthe 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 offossil 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.



### 814. 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.

-;-,;;_, -· _,-,_;

-. _,. ,-;

__ _-_,,-. ''whywould

### ~t~ri investin Genco?·;j, · '-" ••. ·''''·''' '- 

# ·is**--~~:--):" -~.n~-,-**  

# ...**)i~~{>i'~~~:·:~~r?~~?·'':'** -- -

### ~--· co,•;,:'"·:·

### :::~~:t~:**"YI_edg,not'as~igl{anyvalue** to the merchant segment"

_./', .-. ,

# !~~z~=~~,::3~~~~~::~,**''o.uYprim~coricernaboutthe**companYremains ,A'!fibfen

## 's merchant**gene~atiod ~~~osura··:**  · _ -._.· "'

.

# ~~#~~~~~~~~~1;"'i;**)Y;7,.~i;** encolll'ilgedoy 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** theregulated**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

915. 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 oftheir 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 gasfrom 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 weakpowerprices willpressure its cashflow over the intermediate term. Furthermore, the prolonged weakness ofthe power markets, particularly the flattening ofthe forward curve, reduces the value ofGenCo's hedging strategy to protect itfrom 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** viewAmeren's recent decision to significantly reduce its environmental capital spending at GenCo as prudentfrom 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 ofenvironmental capital spending also suggests management's lack ofconfidence in the longer-term economic sustainability ofGenCo's business model. This reinforces our view that Ameren's supportfor 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 lowpowerprices, higher fuel and transportation expenses, and EPA mandated environmental compliance requirements negatively affect the company's margins and cashflow generating ability", said Michael G. Haggartjl, Senior Vice President. Moody's expects cashflow coverage metrics to continue to exhibit declining trendsfor 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 tofully dispatch its merchant generationfleet 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 ofa $500 million joint creditfacility with the parent company that matures in September 2013. Moody's notes that Aineren may not be able to refinance the Ameren Genco bank creditfacility on an unsecured basis without a parent company guarantee when it
comes upfor 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

10Genco reflects the low power price environment, the likelihood of further deterioration in financial metrics, anticipated weak cashflow generationfor the next several years. the lack ofa 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, deterioratingfinancial 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 Agreementprovides Ameren Genco critical timefor currentpower market conditions to improve before itdecides on whether to resume the installation ofscrubbers 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 ofAER or its subsidiaries

"the reduction ofenvironmental capital spending also suggests management's lack ofconfidence in the longer-term economic sustainability ofGenCo's business model. This reinforces our view thotAmeren '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 creditprofile with limited support from parentAmeren Corp." (S&P**Apri/~2012)** "The negative outlook on GenCo reflects our view that management's supportfor 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 ofthe regulated utilities. As ·such. we viewAmeren's support ofGenCo 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 thusjar been unwilling to provide additional directfinancial support to Ameren Genco. Other than sharing ajoint bank creditfacility and providing parent company counterparty guarantees on behalf ofAmeren Energy Marketing Company, Ameren has thusjar notprovideddirect 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 directfinancial support or other guarantees to Ameren Genco, the parent's fating or rating outlook could be adversely affected." (Moody's March 2012)

"The reductionfrom positive to stable rating outlook onAmeren 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 OptionAgreement 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 thusfar limited and measured supportfor Ameren Genco and our expectation that it will notprovide any material capital contributions or other directfinancial 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 oftheir 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 spentto 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 ofMay 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 ofCorporate 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 ofManagement.

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

of2010, 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 ofdollars. 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 offuture power prices in assessing

the creditworthiness ofa 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 ofcertain merchant gen_eration segment assets, including goodwill, iotangible assets, and fixed assets, likely would not be recoverable. The decline in the estimated value ofthese assets that led to recognition ofthe impairment charge was driven primarily by a sustained decline in market prices for electricity. Excluding the asset impairment charge, 2010 net incomewould 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 ofAER 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 ofscrubbers.



### 3

### 6. AER has taken a variety ofsteps during this recent and ongoing period oflow

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 ofexpensive 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

ofthe 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 fewyears. In fact, based on management's projections offuture earnings and cash
flows, which are driven largely by current forward power price assumptions, 

### it is expected that
by the end of2012, 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 ofmoney pool funds is based on Ameren review offacts and circumstances
existing at the time ofany borrowing request. As addressed in further detail in Mr. 

### Gary Rygh's
affidavit, given the poor recent financial performance ofAmeren'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

5provided 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 ofthis 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 

### inthe communities inwhich 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'sfair business riskprofile 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 ofthe recession and by 

### an increased supply ofnatural gasfrom 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 ofthe power markets, particularly the flattening of theforward curve, reduces the value of GenCo's hedging strategy to protect itfrom weakpower 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 provideAmeren 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 thatAmeren '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 ofAER revenues and, along with

fuel prices, the most significant driver ofAER 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 ofmotivation 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 ofall ofits 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 offinancial prospects that support such an investment. As a result, ifthe

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 1UnionElectricCompany(M0)(100%)1901ChouteauAve.St.Louis,MO63103AmerenCorporation1901ChouteauAvenueStLouis,MO63103AmerenIllinoisCompany(IL)(100%)300LibertySt.Peoria,IL61602AmerenServicesCompany(MO)(100%)1901ChouteauAve.St.Louis,MO63103AmerenTransmissionCompany(MO)(100%)1901ChouteauAve.St.Louis,MO63103AmerenTransmissionCompanyofIllinois(IL)(100%)1901ChouteauAve.Sl.Louis,MO63103AmerenEnergyResourcesCompany,LLC(DE)(100%)1901ChouteauAve.St.Louis,MO63103LAmarenEnergyResourcesGeneratingCompany(IL)300UbertyStreetPeoria,IL61602AmerenEnergyFuelsandServicesCompany(IL)(100%)1901ChouteauAve.St.Louis.MO63103AmerenEnergyMarketingCompany(IL)(100%)1110Gratiot51.St.Louis,MO63103Rule56•EnergyAmerenEnergyGeneratingCompany(IL)(100%)1901ChouteauAve.St.Louis,MO63103IElectricEnergy,Inc.(IL)(BO%)2100PortlandRoadJoppa,IL62953

### 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
Rarings 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 2Research Update: AmerenEnergy Generating Co. Ratings Lowered AndPlaced On CreditWatch 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 3Research Update: AmerenEnergy Generating Co. Ratings LoweredAndPlaced On CreditWatch 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 4Research Update: AmerenEnergy Generating Co. Ratings Lowered And Placed On CreditWatch 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 5Copyright© 2012 by Standard &Poor's Financial Services UC. All rights reserved.

No content (including ratings, credit-related analyses and data. model. software or other application or output therefrom) or any partthereof (Content) may be modified,
reverse engineered, reproduced or**di~ributed** in any form by any means, or stored in a database or retrieval system, without the prior written permission ofStandard &Poor's Financial Services LLC or its affiliates (collectively. S&P). The Content shall notbe used for any unlawful or unauthorized purposes. S&P and any third-party providers, as well
as.their directors, officers, shareholders, employees or agents {collectively S&P Parties) do not guarantee the accuracy, completeness, timeliness or availability ofthe Content. S&P Parties are nat responsible for any errors or omissions (negligent or otherwise), regardless ofthe cause, for the results obtained from the use ofthe Gontent. or for the security or maintenance of any data input by the user. The Content is provided on an "as is" basis. S&P PARTiES DISCLAIM ANY AND All EXPRESS OR IMPLIED WARRANTIES, INCLUDING, BUT NOT LIMITED TO, ANY WARRANTIES OF MERCHANTABILITY OR FITNESS FOR A PARTiCULAR PURPOSE OR USE, FREEDOM FROM BUGS, SOFTWARE ERRORS OR DEFECTS, THATTHE CONTENTS FUNCTIONING Will BE UNINTERRUPTED, OR THATTHE CONTENT Will OPERATE WITH ANY SOFTWARE OR HARDWARE CONFIGURATION. in no event shall S&P Parties be liable to any party for any direct, indirect incidental, exemplary. compensatory, ptmitive, special or consequential damages, costs, expenses, legal fees, or losses (Including, without limitation. lost income or lost profits and opportunity costs or losses caused by negligence) in connection with any use ofthe Content even if advised'ofthe possibility of such damages.

Credit-related and other analyses, including ratings. and statements in the Content are statements of opinion as ofthe date they are expressed and not statements offact. S&P's opinions, analyses, and rating acknowledgment decisions (described below) are not recommendations to purchase, hold. or selt any securities orto make any investment decisions, and do not address the suitability ofany security. S&P assumes no obligation to update the Content following publication in any form or format. The Content should not be rened on and ·Is not a substitutefor the skill, judgment and experience ofthe user, its-management, employees, advisors and/or clients when making investment and other business dec-isions. S&P does not act as a fiduciary or an investment advisor except where registered as such. While S&P has obtained information from
sources it believes to be reliable, S&P does not pertorm an audit and undertakes no duty ofdue diligence or independent verification of any information it receives.

To the extent that regulatory authorities allow a rating agency to acknowledge in one jurisdiction a rating issued in anotherjurisdiction for certain regulatory purposes, S&P

reserves the right to assign, withdraw, or suspend slJch acknowledgement at anytime and in its sole discretion. S&P Parties disclaim any duty whatsoever arising olJt ofthe assignment withdrawal, or suspension of an acknowledgment as well as any liability for any damage alleged to have been suffered on accountthereof.

S&P keeps certain activities of its business units separate from each other in orderto preserve the independence and objectivity oftheir respective activities. As a result certain business units of S&P may have information that is not available to other S&P business units. S&P has established policies and procedures to maintain the confidentiality ofcertain nonpublic information received in connection with each analytical process. ·
S&P may receive compensation for its ratings and certain analyses, normally from issuers or underwriters of securities or from obligors. S&P reserves the right to disseminate its opinions and analyses. S&P's public ratings and analyses are made available on its Web sites. www.standardandpoors.com {free ofcharge), and www.ratingsdirect.com and www.globaltreditportal.com (subscription), and may be distributed through other means. including via S&P publications and**third~party** redistributors. Additional information about our ratings fees is available at 'N'N'W.standardandpoors.com/usratingsfees.

The McGraw·Hill Companle5

Standard & Poors 1RatingsDirect 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 ofmy 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 ofIllinois 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 ofits 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 ofRyan 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 ofthis 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 inthe 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 ofemissions will be realized

for the 

### duration ofthe 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 setforth below:

2

### CurrentRule 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

ofS02 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 S02Reduction 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 ofmy knowledge and belief.



### 3FURTHER, 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

4Ameren 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 emissionsfrom 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 stepfor 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 ar-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 andAverage PricesPublic 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 ofthe 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 ofthe 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 PricePublic Notice ofWinning 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



# 'Jreal estate, community, and economic development



## Memorandum

To: Mike Kearney, Manager, EconomicDevelopment; Ameren Services
From: Robert M Lewis, Brian Licari, andYash Yedavalli
Date: April19, 2012
Re: Economic Impacts ofE.D. Edwards andJoppa Energy Centers oflllinois and surrounding market areas

In April, 2012, Development Strategies (DS) was commissioned to conduct an iudependent analysis ofthe economic impactthat the operations ofAmeren Energy Resources (AER) Corporation's E.D. Edwards Energy Center (Peoria County, lllinois) andJoppaEnergy Center (Massac County, lllinois) have on the lllinois economy and ontheir respective economic multi-county regions. Development Strategies is pleased to submit this analysis ofti1e direct andiudirecteconomicimpacts for each facility.

Direct economic impacts are ti1e estimated dollars spent byAER at and iu operational support ofeach ofthe energy center facilities. For the purpose ofour analysis, spendingiucludes capital expenditures, non-payroll operations expenditures and salaries paid to employees.

The number ofjobs at the E.D. Edwards Energy Center is 110 and there are 235 at theJoppaEnergy Center. We determined which counties iu the "region" ofeach plant are home to a large majority ofemployees and have calculated economic impacts ·within those regions. Four Illinois counties make up the primary economic impact region in the case ofEdwards, which is home to 97 ofits 110 employees. Three counties make up theprimary economic impactregion iu the case of Joppa, which is home to 134 ofits 235 employees; additionally,Joppa has 71 ofits 235 employees residingiu the neighboriug state ofKentucky. Because those employees spend the bulk oftheir iucomes notiu lllinois, they are excluded from the impact analysis withiu lllinois. See map "AER: Edwards andJoppaEnergy Center LaborMarkets" for the local market area boundaries.

Indirect economic impacts measure the "ripple effect" ofwages and expenditures associated with AER's direct spending. Forinstance, plant employees who live in lllinois will spend a large proportion oftheir 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 additionaljob support across many sectors iu the community and, consequentiy, the state oflllinois. Likewise, much ofthe non-labor operational spending by each plantis initially spentVlithiu the state, thus supporting additional income andjobs iu the immediately surrounding counties and throughout the state.

To calculate these indirectimpacts, 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 somewages and expenditures will be spent outside ofthe 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 ofthe direct and iudirect economic impacts ofeach AER facility relied on spending andworkforce infottnation provided byAmeren, and on the U.S. Department ofCommerce's Regional Input-OutputMultiplier System (RIMS-II). RIMS IIprovides multiplier coefficients for every county iuthe United States. These multipliers

can also be aggregsted for larger regions composed ofcounties, such as states and, iu this. case, the primary economic impactregions around each energy center. Multiplier coefficients for sub-county geographies are not available. Themultipliers are determined separately for, and are unique to, each county and region for key economic sectors. TheRIMS-II multipliers are updated annually by the Bureau ofEconomicAnalysis (BEA).

10 South Broadway, Suite 1500 • St. LouiS, Missoun 63102 • p 314.421.2800 WWW.DEVELDPMENT-STRATEGIES.COMMemorandum on Economic Impacts ofEdwatds andJoppa Energy Centers April19, 2012

TheAER analysis focuses on the multi-countyregions noted above and on the state as a whole. Thatis, each facility has two economic impact tables associated with it the state and its own region. There are three principalmultipliers 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 outputis a similar measure as the nation's gross domestic productbut, 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 addedjobs in the county pet $1,000,000 ofdirect spending byAERin addition to the jobs at theAERfacilities.
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 byAER fall within the Households sector; capital expenditures fall within the Construction sector. TheRIMS-II multipliers for the selected regions are summarized below. To calculate the indirect economic impacts:

• The construction multiplier coefficients for the state andregions are applied to the capitalexpenditure figures ofthe respective plants,

• The utilities multiplier coefficients for the state and regions are applied to the llJ!erational expenditures ofthe respective plants, and

• The households multiplier coefficients for the state andregions are applied to the en!Jf!loyee conllJ!ensation figures ofthe respective plants. For the purposes ofdois analysis, employee compensation includes salary, benefits, and any otherlabor related costs, therefore, the average labor expenditure pet employee does notnecessarily**refl~ct** the average wage.

Therespective direct andindirect impacts are then summedto calculate the total indirectimpacts.

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 andJoppahad an average annual fuel expenditure of $8,331,000 in 2012 dollats. Though a smallportion these expenditures likely occur within lllinois, the vastmajority ofthese e>.-penditures occur outside oflllinois (out ofstate coal and transportation costs); therefore, we are uncomfortable assunoing that tl>e standard RIMS-II multipliers account for dlls scale ofimmediate leakage. Including fuel e>.-penditures in dlls analysis, therefore, could overstate thelocal and statewide impacts.

CONCLUSIONS
DS estimates that each AEREnergy 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 andindirect economic impacts generated.

DEVELOPMENT STRATEGIES 2Memorandum on Economic Impacts ofEdwards andJoppaEnergy Centers April19, 2012

IMPACTS ONTHE STATE OF ILLINOIS

Table 1: Annual Economic Impact of Ameren's Edwards Energy Center Operations on the State of Illinois

Annual Average in 2012 Dollars 1 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

1Actuaf operating data from 2008-2011 adjustedto 2012 doflar amounts and averaged

The top ofthe table shows the direct e."]Jenditures byAmeren at theEdwards Energy Center totaling approximately $44.4 millionin 2012. Since all ofthe employees at this energy center live in Illinois, the employee compensation expenditure represents the total labor expenditure at theEdwards Energy Center. Additionalresults are discussed below:

• The $44.4 million spent byAmeren at Edwards Energy Center triggered an additional $79.7 million in value added activity in Illinois, ofwltich $21.2 million was household earnings that supported 460 jobs. Themultipliers vary for different types ofmajor expenditures shown at the top ofthe table.

• The estimated output (economic activity) triggeredbyEdwards Energy Center's direct operations ($44.4 million) and the addedmultiplier effects ($79.7 million) were $124.1 million for Illinois.

• Ofthat amount, Edwards Energy Center's operations triggered nearly $33.6 million inhousehold 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 directjobs and approximately 460 jobs addedthrough the multiplier effects.

DEVELOPMENT STRATEGIES 3Memorandum on Economic Impacts ofEdwards andJoppaEnergy 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

1Actua/ operating data from 2008-2011 adjusted to 2012 dollaramounts andaveraged

2Estimate based on number ofemployees who reside in Illinois (164 of235) and overall average labor expenditure peremployee

The top ofthe table shows the direct OA-penditures byAmeren at theJoppa Energy Center totaling approximately $76.7 million in 2012. Employee compensation is an estimate based onthe number ofJoppa employees that live in illinois (164 of235). Additional results are discussed below:

• The $76.7 million spent byAmeren atJoppa Energy Centertriggered an additional $137.6 million in value added activity in illinois, ofwhich $35.6 million was household earnings that supported 749 jobs. The multipliers vary for different types ofmajor expenditures shown at the top ofthe table.

• The estimated output (economic activity) triggered byJoppa Energy Center's direct operations ($76.7 million) and the added multiplier effects ($137.6 million) were $214.2 million for illinois.

• Ofthat amount,JoppaEnergy 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 directjobs and approximately 749 jobs added through the multiplier effects.

DEVELOPMENT STRATEGIES 4Memorandum on Economic Impacts ofEdwards andJoppaEnergy Centers April19, 2012

IMPACTS ONTHE RESPECTIVE MULTI-COUNTYREGIONS

Table 3: Annual Economic Impact of Ameren's Edwards Energy Center Operations on Market Area

Annual Average in 2012 Dol!ars 1 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

1Actua/ operating data from 2008-2011 adjusted to 2012 dollaramounts andaveraged 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

2Estimate based on number of employees who reside in market area (97 of 110) and overall average labor expenditure peremployee

The top ofthe table shows the direct expenditures byAmeren 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 ofEdwards employees thatlive inin the market area (97 of 110). Additionalresults are discussed below:

• The $42.9 million spentbyAmeren at Edwards Energy Center triggered an additional $54.4 million invalue added activity in the market area, ofwhich $13.8 million was housel>old earnings that supported 294jobs. The multipliers vary for different types ofmajor expenditures shown at the top ofthe table.

• The estimated output (economic activity) triggeredbyEdwards Energy Center's direct operations ($42.9 million) and the added multiplier effects ($54.4 million) were $97.3 million for the market area.

• Ofthat amount, Edwards Energy Center's operations triggered nearly $24.8 million inhousehold 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 directjobs and approximately 294jobs added tlu:ough the multiplier effects.

DEVELOPMENT STRATEGiES 5Memorandum onEconomic Impacts ofEdwards andJoppa 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

1Actua/ operating data from 2008-201.1 adjusted to 2012 dollar amounts and averaged

2Estimate based on number ofemployees who reside In market area (134 of 235) and overall average labor expenditure per employee

The top ofthe table shows the direct expenditures byAmeren at theJoppaEnergy Center in the market area totaling approximately $73.9 million in 2012. Employee compensationis an estimate based on the number of Joppa employees thatlive in in the market area (134 of235). Additional results are discussedbelow:

• The $73.9 million spentbyAmeren atJoppa Energy Center triggered an additional $78.1 million in value added activity in the market area, ofwhich $15.7 million was household earnings that supported 292jobs. Themultipliers vary for different types ofmajor expenditures shown at the top ofthe table.

• The estimated output (economic activity) triggered byJoppa Energy Center's direct operations ($73.9 million) and the added multiplier effects ($78.1 million) were $152.1 million for the market area.

• Ofthat amount,JoppaEnergy Center's operations triggered nearly $27.9 million inhousel1old earnings for workers the market area, including $12.2 million in direct compensation for employees and $15.7 millionin added earnings from the multiplier effects.

• In total,Joppa Energy Center's operations supported 426 jobs in the market area, including 134 directjobs and approximately 292jobs addedthrough 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 ofAmeren Energy Resources and is responsible for all aspects ofthe selling

and marketing ofpower 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 ofIllinois 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 ofthe 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 ofIllinois 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 ofthe more efficient units in MISO footprint.

4. In illinois, a customer's electricity costs include both regulated and
deregulated components. The generation portion ofthe 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 offrom 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 PJM 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 ofavailable generation and the load demands.) The
marginal costs ofthe generators are used by marketers such as AEM in determining a unit's offer
price into the marketplace.

26. 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 ofenergy 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 Danialie R. Moskop ··Notary PubliC Notary Seal, State of MiSSOUri

- Jefferson County

Commission 1109745027 Comn"illlion Expires 7/2112013:::::::::::::::::::::::::::;::::::::::::::::::::::;;::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::·.:::::;::;::::::::::::::::::::::::::::::·.::::::.·::;;;:::·:::::;::;:::.:····....:::;:····15,00014'50014,000+------·-·-·--·-········13,50013000___,,_,______,_-----------..·--··-..··-,__,_____,_.......,,_______--------' !12500+---------···--------________________,_______-----------'I-·--·---------------------·1'!12,000--1-M!SOAverage:11,885-----·--·----------...............___,____...-............._..,_..__,,___....__..__...................-.....................i11:111,500"t"""Edwards10,49511,000t--·-......--.......IJoppa10,393"-....,I1-••InTrr10,500'10,0009,500+-·i'9,000t--___,85Q0..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:FERCForm1dataforcoal-firedplants,Amerenplantspercompanydata.V4Ameren

### 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 AVENUE EAST P.O. BOX 19276 SPRINGFIELD, ILLINOIS 62794-9276Appendix C

Illinois Mercury Rule

The Illinois EPA is seeking approval from the United States Environmental ProtectionAgency of the following baldedprovisions of the Illinois Mercury Rule, 35Ill. Adm. Code Part 225, Subpart B: Control of Mercury Emissions from Coal-FiredElectric 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 ofSection 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 ofNO, and S02, as well as for emissions ofmercury.
2) For the purpose ofthis 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 ofa majority interest in a company that

owns the EGU or EGUs, or bythe common ownership ofthe 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 behalfofthe 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) oftb.is Section and which clearly states the owner's election to demonstrate compliance pursuant to this Section 225.233.
A) 

### Ifthe owner ofone or more EGUs elects to demonstrate compliance with this Subpart pursuant to this Section, then all EGUs it owns in Illinois as ofJuly 1, 2006, as defined in subsection (a)(2)(B) ofthis Section, must be thereafter subject to the standards and control

1

### requirements ofthis 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) ofthis Section, with compliance for such units to be achieved by means of Section 225.235.
4) When an EGU is subject to the requirements ofthis Section, the requirements apply to all owners or operators ofthe EGU.
b) Notice oflntent.

The owner ofone or more EGUs that intends to comply with this Subpart B by meanS ofthis Section must notify the Agency ofits intention byDecember 31, 2007. The following information must accompany the notification:
1) The identification of each EGU thatwill be complying with this Subpart B 

### by
means ofthe 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) ofthis Section is also owned or operated by a person different than the owner submitting the notice ofintent,
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 ofthe current control devices installed and operating on each EGU and identification ofthe 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) ofthis 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 ofthe MPS Group and which will not be demonstrating compliance with this Subpart B pursuant to this Section.

2c) Control Technology Requirements for Emissions ofMercury.
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) ofthis Section for the period beginning July I, 2009 (or December 31, 2009 for an EGU for which an S02 scmbber orfabric 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) ofthis Section), the

owner or operator ofthe EGU must install, to the extent not already installed, and properly operate and maintain one ofthe following emission control devices:
i) A Halogenated Activated Carbon Injection System, complying with the sorbent injection requirements ofsubsection ( c)(2) ofthis Section, except as may be otherwise provided by subsection (c)(4) ofthis Section, and followed by a Cold-Side Electrostatic Precipitator or Fabric Filter; or
ii) Ifthe boiler frres bituminous coal, a Selective Catalytic Reduction (SCR) System and an SOz Scrubber.
B) An owner ofan 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) ofthis Section. Or, for an MPS Group that contains EGOs with gross MW capacity ofless 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 ofthe designated EGUs does not exceed4% ofthe total gross MW capacity of the MPS Group. For any EGU subject to one ofthese two options, unless the EGO is subject to the emission standards in subsection (d)(2) ofthis Section, beginning on January 1, 2013, and continuing until such date that the owner or operator ofthe EGU commits to comply with the mercury emission standard in subsection (d)(2) ofthis Section, the owner or operator ofthe EGU must install and properly operate and maintain a Halogenated Activated CarbonInjection System that complies with the sorbent injection requirements ofsubsection ( c)(2) ofthis Section, except
as may be otherwiseprovided by subsection (c)(4) ofthis Section, and followed by either a Cold-Side Electrostatic Precipitator or Fabric Filter. The use ofa properly installed, operated, and maintained Halogenated Activated Carbon Injection System that meets the sorbent injection requirements of$ubsection (c)(2) ofthis Section is defined as the "principal control technique."

32) For each EGU for which injection ofhalogenated activated carbon is required by subsection (c)(l) ofthis Section, the owner or operator ofthe EGU must inject halogenated activated carbon in an optimum manner, which, except as provided in subsection (c)(4) ofthis Section, is defined as all ofthe following:
A) The use ofan injection system designed for effective absorption of mercury, considering the configuration ofthe EGU and its ductwork;
B) The injection ofhalogenated activated carbon manufactured by Alstom, Norit, or Sorbent Technologies, Calgon Carbon's FLUEPAC CF Plus, or CalgonCarbon's FLUEPAC MC Plus, or the injection ofany other halogenated activated carbon or sorbent that the owner or operator ofthe EGU has demonstrated to have similar or better effectiveness for control ofmercury 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 byDecember 31,2012, and which already meets an emission rate of0.020 lbs mercury/GWh gross electrical output or at least 75 percent reduction ofinput 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 ofinput mercury, 5.0 lbs per million actual cubic feet;
iii) For an EGU firing a blend ofsubbituminous and bituminous coal,

a rate that is the weighted average ofthe above rates, based on the blend ofcoal 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) ofthis Section on a unit-specific basis, provided that the owner or operator ofthe 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) ofthis Section, the flue gas flow shall be the gas flow rate inthe stack for all units except for those

4equipped 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 ofCharles' 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 acfand T = gas temperature in Kelvin or Rankine
3) The owner or operator ofan 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) ofthis Section must submit an application to the Agency

. proposing such rate or rates, and must meet the requirements ofsubsections (c)(3)(A) and (c)(3)(B) ofthis Section, subject to the limitations ofsubsections (c)(3)(C) and (c)(3)(D) ofthis Section:
A) The application must be submitted as an application for a new orrevised federally enforceable operating pennit for the EGU, and it must include a summary ofrelevant 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 ofthe EGU may supplement its application; and
C) Any decision ofthe Agency denying a permit or granting a permit with conditi that seta lower injectionrate or rates may be appealed to the Board putsuanttc Section 39 ofthe Act; and
D) The owner or operator ofan 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 ofthe 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 withthe requirements of subsection (c)(2) ofthis Section for any system needed to carry out the evaluation, as further provided as follows:
A) The owner or operator ofthe EGU must conduct the evaluation in accordance with a formal evaluation program submitted to the Agency at least 30 days prior to commencement ofthe evaluation;

5B) The duration and scope ofthe evaluation may not exceed the duration and scope reasonably needed to complete the desired evaluation ofthe 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 ofthe EGU must submit a report to the Agency no later than 30 days after the conclusion ofthe evaluation that describes the evaluation conducted and which provides the results ofthe evaluation; and
D) Ifthe evaluation ofthe alternative control technique shows less effective control ofmercury emissions from the EGU than was achieved with the principal control technique, the owner or operator ofthe EGU must
resume use ofthe principal control technique. Ifthe evaluation ofthe alternative control teclmique shows comparable effectiveness to the principal control technique, the owner or operator ofthe 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 ofthe principal control technique. Ifthe evaluation ofthe alternative control technique shows more effective control ofmercury emissions thanthe controlteclmique, the owner or operator ofthe 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 ofan EGU that elects to comply with this Subpart B by means ofthis Sectionmust also comply with the following additional requirements:
A) For the first 36 months that injection ofsorbent is required, it must maintain records ofthe usage ofsorbent, the fluegas flow rate from the EGO (and, ifthe 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 inthe stack), and the sorbent feed rate, in pounds per million actual cubic feet offlue, on a weekly average;
B) After the first 36 months that injection ofsorbent is required, it must monitor activated sorbent feed rate to the EGU, gas flow rate inthe stack, and, ifthe unit is equipped with activated carbon injection prior to a hotside electrostatic precipitator, flue gas temperature at the inlet ofthe hotside electrostatic precipitator and inthe stack. It must automatically record this data and the sorbent carbon feed rate, in pounds per million actual cubic feet offlue gas, on an hourly average; and

6C) Ifa blend ofbituminous and subbituminous coal is fired in the EGU, it must keep records ofthe amount ofeach type ofcoal burned m1d the required injection rate for injection ofactivated 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 ofan 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 ofan EGU that elects to comply with this Subpart B by means ofthis 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 ofthe EGU notifies the Agency that 

### it will comply with these standards) and continuing thereafter, the owner or operator ofthe EGU must comply with

one ofthe 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 ofinput mercury.
2) For each EGU in an MPS Group that has been addressed under subsection (c)(l)(B) ofthis Section, beginning onthe date when the owner or operator ofthe EGU notifies the Agency that it will comply with these standards m1d continuing thereafter, the owner or operator ofthe EGU must comply with one ofthe following standards on a rolling 12-month basis:
A) An emission stm1dard of0.0080 lb mercury/GWh gross electrical output;
or
B) A minimum 90-percent reduction ofinput mercury.
3) Compliance with the mercury emission stm1dard or reduction requirement ofthis subsection (d) must be calculated in accordm1ce with Section 225.230(a) or (d), or Section 225.232 until December 31, 2013.



### 74) Until June 30, 2012, as an alternative to demonstrating compliance with the emissions standards inthis subsection (d), the owner or operator ofan 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) ofthis 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 ofthe 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 ofthe Base Annual Rate ofNO, 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 ofthe EGUs must comply with an overall NO, seasonal emission rate ofno more than O.lllb/million Btu or an emission rate equivalent to 80 

### percent ofthe Base Seasonal Rate ofNO, emissions, whichever is 

### more stringent.
2) 

### S02 

### Emission Standards.
A) Beginning in 

### calendaryear 2013 

### and continuing in calendaryear 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 ofthe Base Rate of

## so2 emissions, whichever is more stringent.
B) Beginning in calendaryear 2015 

### and continuing in 

### each calendar year thereafter, for the EGUs in each MPS Grouping, the owner and operator ofthe EGUs must comply with an overall annual emission rate for S02 

### of0.25 

### lbs/million Btu or a rate equivalent to 35 percent· ofthe Base Rate ofS02 

### 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) 

### ofthis Section.
B) NO, Emission Standards,

84)

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 ofthe EGUs must comply with an overall NOx annual emission rate ofno 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 ofthe EGUs must comply with
an overall NO, annual emission rate ofno more than 0.11 

### lb/million Btu.
C) S02 

### Emission Standards

i) 

### Beginning in calendar year 2010 

### and continuing in each calendaryear through 2013, 

### for the EGUs in the Ameren MPS Group,.the owner and operator ofthe EGUs must comply with
an overall SOz annual emission rate of0.50 

### 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 of0.43 

### lb/million Btu.
iii) Beginning in calendaryear 2015 

### and continuing in calendar year 2016, 

### for the EGUs in the Ameren MPS Group, the owner and operator ofthe EGUs must comply with an overall 

### SOi annual emission rate of0.25 

### lb/mi!lion Btu.
iv) Beginning in calendaryear 2017 

### and continuing in each calendar year thereafter, for the EGUs in the Ameren MPS Group, the owner and operator ofthe 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 ofthe 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.

91) The owner or operator ofEGUs in an MPS Group must not sell or trade to any person orotherwise exchange with or give to anyperson 

### NOx allowances allocated to the EGUs inthe MPS Group for vintage years 2012 and beyond that· would otherwise be available for sale, trade, or exchange as a result ofactions taken to comply with the standards in subsection (e) ofthis 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 ofallowances among the EGUs in

an. MPS Group.


### 2) The owners or operators ofEGUs 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 ofactions taken to comply with the standards in subsection (e) ofthis 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 ofallowances aJ.nong the EGUs in
an MPS Group.
3) Theprovisions ofthis 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 ofholding allowances that represent over-compliance with the 

### NO, or S02 standard in subsection (e) ofthis Section, once such a standard becomes effective, whether such over-compliance results from control equipment, fuel chaoges, changes in the method ofoperation, unit shut downs, or other reasons.
4) For purposes ofthis 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 ofcomplying 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 ofthis subsection (f) for the previous calendar year, and which includes identification ofany allowances that have been surrendered to the USEPA 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 

### ofeach year, verifying that the actions described in the initial report have taken place or, if such actions have not taken place, an explanation ofall 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 30 days after such deduction occurs. g) Notwithstanding 35 Ill. Adm. Code 201.146(hhh), until an EGU has complied with the applicable emission standards ofsubsections (d) and (e) ofthis Section for 12 months, the owner or operator ofthe EGU must obtain a construction permit for any new or modified air pollution control equipment that it proposes to construct for control ofemissions ofmercury, NO, or S02.
(Source: Amended at 33 Ill. 

### Reg. 10427, effective June 26, 2009)

Section 225.291 Combined Pollutant Standard: Purpose

The purpose ofSections 225.291 through 225.299 (hereinafter referred to as the Combined PollutantStandard ("CPS")) is to allow an alternatemeans ofcompliance with the emissions standards for mercury in Section 225.230(a) for specified EGUs through permanent shut-down, installation ofACI, and the application ofpollution 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 ofSubparts B, C, D, and E.
(Source: Added at 33 Ill. 

### Reg. 10427, effective June 26, 2009)

Section 225.292 Applicability ofthe Combined Pollutant Standard
a) As an alternativeto compliance witb the emissions standards ofSection 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 ofthe 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 behalfofthe EGU.

11

### b) A specified EGU is a coal-fired EGU listed in Appendix A, irrespective of any subsequent changes in ownership ofthe EGU or power plant, the operator, unit designation, or name ofunit.
c) The owner or operator ofeach 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 ofDecember 31, 2006, as defined in 

### subsection (a) ofthis Section, are thereafter subject to the standards and control requirements ofthe CPS. Such EGUs are referred to as a Combined Pollutant Standard (CPS) group. e) If

### an EGU is subject to the requirements ofthis Section, then the requirements apply to all owners and operators ofthe EGU.
(Source: Added at 33 Ill. Reg. 10427, 

### effective June 26, 2009)



### Section 225.293 Combined Pollutant Standard: Notice ofIntent

The owner or operator ofone or more specified EGUs that intends to comply with Section 225.230(a) by means ofthe CPS must notify the Agency ofits 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 ofDecember 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 ofthe additional control devices thatwill likely be needed for each EGU to comply with emission control requirements ofthe CPS.
(Source: Added at 33 Ill. Reg. l 0427, 

### effective June 26, 2009)

12Section 225.295 Combined Pollutant Standard: Emissions Standards for NO, and S02 a) Emissions Standards for NO, and Reporting Requirements.
1) Beginning with calendaryear 2012 and continuing in each calendaryear 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) Beginningwith 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 ofthe specified EGUs in the CPS group must file, not later than one year after startup ofany 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 calendaryear 2013 and continuing in each calendaryear 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 ofcompliance pursuant to Section 225.298(c) before March 1 ofthe following year for annual standards and before November 30 ofthe particularyear 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 ofthe Clean Air Interstate Rule Trading Program under Subparts C, D, and E ofPart 225 and will need to be amended accordingly when the Transport Rule is promulgated.}

13

### d) The CPS group average annual S02emission rate, annualNOx 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 ofall EGUs in the CPS group. heat input for the annual or ozone control period ofeach EGU, in mmBtu. actual annual S02tons ofeach EGU in the CPS group. actual annual or ozone season NOx tons ofeach 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 ofdelivering 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 ofdelivering 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) ofthis Section.
c) Control Technology Requirements for PM. The owner or operator ofthe 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-heaterwhere 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 ofthe 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 inthe 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)



### 15225.APPENDIX A Speciiled EGUs for Purposes ofthe CPS (Midwest Generation's Coal-Fired Boilers as ofJuly 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

Appro11alandPromulgation of Air Quality Implementation Plans; Illinois; RegionalHaze; 

### 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 emissionsnanagement 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 ;onditions.

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 itlchieves 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 TechnologyStates 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 mandatesLmplementation 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 reduceemissions 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 hasietermined 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 and302 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 emissionceductions, 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 40 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. 2721ote) because application of those requirements would be inconsistent

;ith 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