·' Electronic Filing -Received, Clerk's Office, 08/20/2012 

BEFORE THE ILLINOIS POLLUTION CONTROL BOARD 

AMEREN ENERGY RESOURCES, 

Petitioner, 

v. 

ILLINOIS ENVIRONMENTAL 

PROTECTION AGENCY, 

Respondent 

) 

) 

} 

) 

) 

) 

) 

) 

) 

) 

PCB 12-126 

(VruiMce-Air) 

NOTICE 

TO: John Tlle!Tiault, Assistant Clerk 

Illinois Pollution Control Board 

James R. Thompson Center 

100 West Rruldolph St., Suite 11-500 

CJ1icago, IL 60601 

Carol Webb 

Hearing Officer 

Illino.is Pollution Control Board 

1021 N. Grand Ave. East 

P.O. Box 19274 

Springfield, IL 62794-9274 

A,-uy Antonio1li 

Renee Cipriano 

Gabriel Rodriguez 

Schiff Hardin LLP 

233 South Wacker Drive 

Suite 6600 

Chicago, !L 60606 

PLEASE TAKE NOTICE that I .have today filed with the Office of the Pollution 

Control Board the POST-HEARING COMlVIENTS OF THE ILLINOIS 

ENVIRONMENTAL PROTECIION AGENCY, a copy of which is herewith served 

upon you. 

DATED: August 20,2012 

1021 North Grand Avenue East 

P.O. Box 19276 

Springfield, Illinois 627.94-9276 

217.782.5544 

217.782.9143 (TDD) 

ILLINOIS ENVIRON1viENTAL 

PROTECTION AGENCY 

By: ~~b'tk::-" Gina Roocaforte 

Assistant Counsel 

Division of Legal Counsel 

THIS FILING IS SUBMITTED 

ON RECYCLED PAPER 

ATIACHMENT __ _ 
Electronic Filing- Received, Clerk's Office, 08/20/2012 

BEFORE THE ILLINOIS POLLUTION CONTROL BOARD 

AMEREN ENERGY RESOURCES, ) 

) 

) 

) 

) 

) 

) 

) 

) 

) 

Petitioner, 

v. 

PCB 12-126 

(Variance-Air) 

ILLINOIS ENVIRONMENTAL 

PROTECTION AGENCY, 

Respondent. 

POST-HEARING COMMENTS OF THE 

ILLINOIS ENVIRONMENTAL PROTECTION AGENCY 

NOW COMES the Illinois Environmental Protection Agency ("Illinois EPA"), by its 

attorney, and respectfully submits its post-hearing comments in the above proceeding. The 

Illinois EPA has reviewed the transcript of the hearing held on August 1, 2012, and responds to 

the information requests as fullows: 

1. As one of the proposed variance conditions on page 11 of AER 's response to the July 6, 

2012 Hearing Officer order, AER indicated it v.vuld be willing to provide progress 

reports on construction activities related to the Newton scrubber by the end of each 

calendar year during the term of the variance to both the Board and the Agency. Would 

Illinois EPA please indicate which address and which contact person such reports should 

be submitted? (Tr. at 54) 

Such reports should be sent to the Illinois EPA as follows: 

lllinois Environmental Protection Agency 

Attn: Ray Pilapil, Manager 

Birreau of Air-Compliance Section 

1021 N. Grand Ave. East 

P.O. Box 19276 

Springfield, IL 62794-9276 

and 

Illinois Environmental Protection Agency 

Attn: Gina Roccaforte, Assistant Counsel 

Division of Legal Counsel-Air Regulatory Unit 

1021 N. Grand Ave. East 

P.O. Box 19276 

Springfield, IL 62794-9276 

._, .. 
2. 

Electronic Filing- Received, Clerk's Office, 08/20/2012 

Question J(b) in the July 25, 2012 Hearing Officer Order asked Ameren to comment on 

the assertion by the Illinois Attorney General's Office that the MPS was not intended to 

be a 12-year averaging period of pollution reduction. Does the Agency have anything to 

add to Ameren 's response and testimony on this issue? (Tr. at 55) 

The Illinois EPA stated, in part, in its Recommendation filed July23, 2012, with 

the Board as follows regarding this issue: 

Furthermore, the J\.1PS was created and designed to achieve significant S02 and 

NOx reductions in exchange for mercury control flexibility in the Illinois Mercury 

Rule. The timing of the J\.1PS reductions was negotiated and the result of the 

consideration of many variables, including Petitioner's ability to install pollution 

control equipment in a timely manner and a desire to achieve the greatest amount 

of reductions within a reasonable amount of time. (Rec. at 21-22) 

The Illinois EPA notes its previous comments on this issue and that a primary 

aspect of the comment by the Office of the Attorney General appears to be in regard to 

Ameren's use of emission reductions to offset any additional increase in emissions. The 

Illinois EPA acknowledged that the use of emission offsets is a normal part of certain 

regillatory processes. 

3. Ameren has requested a response from the Rlinois EPA to Question 2(c) of the Hearing 

Officer Order dated July 25, 2012: "lfthe heat input values are not the same, please 

explain which value is most appropriate for calculations to support a SIP revision. " (Tr. 

at 55-56} 

The Illinois EPA will work with the United States Environmental Protection 

Agency ("USEP A") Region 5 to determine the appropriate year to be used for heat input 

values to support a future SIP revision. It is likely that the original2002 baseline year 

heat input will be used. The Illinois EPA has had preliminary discussions with USEP A 

Region 5 regarding a SIP revision for pending variance requests and no adverse issues 

were identified. Illinois EPA's Regional Haze SIP used the 2002 baseline year in 

accordance with the USEP A memorandum entitled 2002 Base Year Emission Inventory 

SIP Planning: 8-hr Ozone, PM2.5 and Regional Haze Programs, dated November 18, 

2 
Electronic Filing- Received, Clerk's Office, 08/20/2012 

2002, 1 that identifies 2002 aS the emission inventory base year tor the SIP planning 

process. 

DATED: August 20, 2012 

l 021 North Crrand Avenue East 

P. 0. Box 19276 

Sp1ingfield, IL 62794-9276 

2171782-5544 

Respectfully submitted, 

ILLINOIS ENVIRONMENTAL 

PROTECTION AGENCY 

By:~~· Gina Roccaforte 

Assistant Counsel 

Division of Legal Counsel 

THIS FILING IS SUBMITTED 

ON RECYCLED PAPER 

' http:liwv,w.epa.govi\Wchicl!ei oocs/2002hasei:u:ven _102502new. pdf 

3 
.. Electronic Filing- Received, Clerk's Office, 08/20/2012 

STATE OF ILLL"\OIS 

COUNTY OF SANGAMON 

) 

} 

) 

) 

) 

ss 

CERTIFlCATE OF SERVICE 

I, the undersigned, an attorney, state that I have served electronically the attached 

POST-HEARING C0M}.1ENTS OF THE ILLINOIS ENVIRONMEJ\1AL 

PROTECTION AGENCY npon the fullowing person: 

John Therriault, Assistant Clerk 

Illinois Pollution Control Board 

James R. Thompson Center 

100 West Randolph St., Suite 11-500 

Chicago, IL 60601 

and electronically and by mailing tl1em by first-class mail from Springfield, Illinois, ;vith 

sufficient postage affixed to the following persons: 

Carol Webb 

Hearing Officer 

Illinois Po !lution Control Board 

l 021 N. Grand Ave. East 

P.O. Box 19274 

Springfield, IL 62794-9274 

DATED: August 20, 2012 

I 021 North Grand Avenue East 

P.O,Box19276 

Springfield, IL 62794-9276 

217.782..5544 

211-782,9143 (TDD) 

An1y 1\ntoniolli 

Renee Cipriano 

Gabriel Rodrit,'Uez 

Schiff Hardin LLP 

233 South Wacker Drive 

Suite 6600 

Chicago, IL 60606 

1LLINOIS ENVIRONl\IENTAL 

PROTECTION AGENCY, 

Gina 

cJ-; 

Roccafurte 

~--

Assistant Counsel 

Division of Legal Counsel 
., i •· Electronic Filing- Received, Clerk's Office, 8/23/2012 

BEFORE THE ILLINOIS POLLUTION CONTROL BOARD 

AMEREN ENERGY RESOURCES, ) 

) 

) 

) 

} 

) 

) 

) 

) 

} 

Petitioner, 

v. 

ILLINOIS ENVIRONMENTAL 

PROTECTION AGENCY, 

Respondent 

NOTICE OF FILING 

To; ALL PARTIES ON TilE ATTACHED SERVICE UST 

PCB12·126 

(Variance- Air) 

PLEASE TAKE NOTICE that we have today electronically .filed with the Office of the 

Clerk of the illinois Pollution Control Board a MOTION TO FILE INSTANTER and 

PETITIONER'S POST-HEA,..lUNG COMMENT, copie~ of which are herewith served uponyo\L 

Dated: August 23, 2012 

Renee Cipriano 

Gabriel Rodriguez 

Amy Antoniolli 

SCHIFF HARDIN LLP 

233 South Wacker Drive 

Suite 6600 

Chicago, Illinois 60606 

312-258-5500 

Amy Antoniolli 

ATTACHMENT ___ _ 
Electronic Filing" Received, Clerk's Office, 8/23/2012 

CERTIFICATE OF SERVICE 

I, the undersigned, certify that on this 23rd day of August, 2012, I have served 

electronically the attached MOTION TO FILE INSTANTER and PETITIONER'S POSTHEARING COMMENT, upon the following persons: 

John Therriault, Assistrurt Clerk 

Carol Webb, Hearing Offic:er 

Illinois Polluti<m Control Board 

James It Thompson Center 

Suite 11-500 

100 West Randolph 

Chicago, illinois 6060 I 

and electronically and by first class mail, postage affixed, upon: 

Gina Roccaforte 

Assistant Counsel 

Division ofLegal Counsel 

Illinois Environmental Protection Agency 

I 021 North Grand Avenue, East 

P.O. Boxl9276 

Springfield, illinois 62794-9276 

Renee Cipriano 

Gabriel Rodriguez 

Amy Antoniolli 

SCHIFF HARDIN LLP 

233 South Wacker Drive 

Suite6600 

Chicago, Jllinois 60606 

312-258"5500 

\ -~· 
Electronic Filing- Received, Clerk's Office, 8/23/2012 

SERVICE LIST 

(PCB 12-126) 

John Therriault, Assistant Clerk Gina Roccaforte 

Carol Webb, Hearing Officer Assistant Counsel 

Illinois Pollution Control Board Division ofLegal Counsel 

James R. Thompson Center Illinois Environm.ental Protection Agency 

!00 West Randolph Street, Suite 11-.500 1021 North Grand Avenue, East 

Chicago, lliinois 60601 P.O. Box 19276 

therriaj @iQcb.state. il.us Springfield, Illinois 62794-927(/ 
Electronic Filing- Received, Clerk's Office, 8/23/2012 

BEFORE THE ILLINOIS POLLUTION CONTROL BOARD 

AMEREN ENERGY RESOURCES, ) 

) 

) 

) 

) 

) 

) 

) 

) 

) 

Petitioner, 

v. 

PCB 12-126 

(Variance- Air) 

ILLINOIS ENVIRONMENTAL 

PROTECTION AGENCY, 

Respondent. 

MOTION TO FILE INSTANTER 

NOW COMES THE PBTITIONER, AMEREN ENERGY RESOURCES ("AER"), by 

and through its attorneys, SCHIFF HARDIN, LLP, and pursuant to 35111. Adm. Code 101.522, 

and respectfully states as follows: 

L Section !01.522 of the Illinois Pollution Control Board ("Board")'sprocedural 

rules provides: 

The Board or hearing officer, for good cause shown on a motion after 

notice to the opposite party, may extend the time for filing any document 

or doing any act which is required by these rules to be done within a 

limited period, either before or after the expir;:ltion of time. 35 Ill. Aam. 

Code 101.522. 

2. At hearing in this proceeding a member of the Illinois Pollution Control Board 

{"Board''} asked about AER's plan for compliance With the Cross-State Air Pollution Rule 

("CSAI'R"). Hearing Officer Webb set August 10, 2012 as the deadline for filing post-hea-ring 

public comments. AER timely file(! its post~bearing brief on August 15, 2012; 

3. On Augilst 21, 2012, the United .. States Court of Appeals for the D.C. CircJJit 

vacated the CSAPR. 
Electronic Filing- Received, Clerk's Office, 8/23/2012 

4. AER states that because. the vacatur directly relates to a question by a Board 

Member at hearing, AER has shown good cause for an extension of time to file a public 

comment which it files concurrently with this motiOJ:J. 

WHEREFORE, the Petitioner respectfully requests that the Pollution Control Board grant 

this Motion to File Instanter and accept Petitioner's Post-Hearing Comment as timely fiied. 

Dated: August 23, 2DU 

Renee Cipriano 

Gabriel Rodriguez 

AmyAmoniolli 

Schiff Hardin,. LLC 

233 South Wacker Drive, Suite 6600 

Chicago, IL 60606 

Respectf\,illy submitted, 

AMEREN ENERGY RESOURCES, Petitioner. 
Electronic Filing -Received, Clerk's Office, 8/23/2012 

BEFORE THE ILLINOIS POLLUTION CONTROL BOARD 

AMERENENERGY RESOURCES, 

Petitioner, 

v. 

ILLINOIS Em'JRONMENTAL 

PROTECTION AGENCY, 

Respondent. 

) 

) 

) 

) 

) 

) 

) 

) 

) 

) 

PCB 12-126 

(Variance-Air} 

PETITIONER'S POST-HEARING COMMENT 

NOW COMES AMEREN ENERGY RESOURCES ("AER"), by and through its 

attorneys, SCHIFF HARDIN, LLP, and, pursuant to Section. !04.224(d} of the Illinois Pollution 

Control Board's ("Board") procedural rules (35 Ill. Adm. Code 104 .. 220). On August 21,2012, 

the United States Court of Appeal$ f.;>r the D,C. Circuit vacated the Cross-S;ate Air Pollution 

Rule ("CSAPR''}, holding that the United States Environmental Protection Agency ("USEPA") 

exceeded its authority U!Wer the Clean Air Act (''CAA'') by requiring upwind states to reduce 

more pollution than necessary and denying states a post-Rule opportunity to set up their own 

state implementation plans before federally•promulgated Federal Implementation Plans (''FIPs'') 

took effuct. EMEliomer City Gerzetaticm, LP. v. EPJ., et at., No. ll-1302 (D.C. Cir., Aug. 21, 

2012). The coUI! vac<Ued the rule and sent USEPA back to the drawing board to address 

interstate air pollution Under the CAA. 

At hearing, Board Member Zalewski asked "lfCSAPR does go into effect, does Ameren 

have a compliance plan?" (Tr. 41). lti response, in Petitioner's post-hearing brief, Ameren 

Energy Resources ("AER") stated ~[d]etermining AER's CSAPR compliance plan requires a bit 

of forecasting because we can not ):lecessarily l!Sljume that the rule will be upheld in its full and 
Electronic Filing -Received, Clerk's Office, 8/23/2012 

H~aring Brief, pg. 46. Now we knowthe rule has not been upheld in its full ai!d current form. 

With the D.C. Circuit's vacatur of CSAPR several aspects of the CSAPR, including the states' 

emission budgets and emission alloWai!ces for power plants under the US EPA-promulgated FIPs 

will not be part of equivalent federal legislation. Based on the August 21, 2012 decision, it is 

also unclear at this: point when a replacement rule will be promulgated, let alone what it would 

require in terms of emission reductions or when new compliance deadlines would take effect. To 

further answer Board Member Zalewski's question, a compliance plan for CSAPR is no longer 

necessary at this time. 

WHEREFORE, Ameren Energy Resources asks the Illinois Pollution Control Board to 

accept this comment as a supplement to its answer given at bearing and in its post-hearing brief. 

Dated: August23,2012 

Renee Cipriano 

Gabriel Rodriguez 

Amy Antoniolli 

Schiff Hardin, LLC 

233 South Wacker Drive, Suite 6600 

Chicago, IL 606()6 

Respectfully submitted, 

AMEREN ENERGY RESOURCES, Petitioner; 
ILLINOIS POLLUTION CONTROL BOARD

September 20, 2012

AMEREN ENERGY RESOURCES,

Petitioner,

v.

ILLINOIS ENVIRONMENTAL 

PROTECTION AGENCY,

Respondent.

)

)

)

)

)

)

)

)

)

)

 PCB 12-126

 (Variance - Air)

AMY ANTONIOLLI, GABRIEL RODRIGUEZ AND RENEE CIPRIANO, SCHIFF HARDIN 

LLP, APPEARED ON BEHALF OF PETITIONER; AND

GINA ROCCAFORTE, ASSISTANT COUNSEL, APPEARED ON BEHALF OF 

RESPONDENT.

OPINION AND ORDER OF THE BOARD (by J.A. Burke):

Ameren Energy Resources (AER) seeks a variance from the sulfur dioxide (SO2) 

emission rate in the multi-pollutant standard (MPS) rules applicable to the AER MPS Group of 

facilities in Illinois. The AER MPS Group includes the following seven coal-fired electric 

generating plants: Coffeen Energy Center (Montgomery County), Duck Creek Energy Center 

(Fulton County), E.D. Edwards Energy Center (Peoria County), Joppa Energy Center (Massac 

County), Hutsonville Energy Center (Crawford County), Meredosia Energy Center (Morgan 

County), and Newton Energy Center (Jasper County). Pet. at 4-5. AER’s variance petition 

(petition) seeks relief from 35 Ill. Adm. Code 225.233(e)(3)(C)(iii) for five years beginning 

January 1, 2015 and ending December 31, 2019, and relief from 35 Ill. Adm. Code

225.233(e)(3)(C)(iv) for three years and fifteen days, beginning January 1, 2017 and ending 

January 15, 2020. Pet. at 1; AER’s Response to the Board’ First Set of Questions (AER First 

Resp.) at 1.

On July 23, 2012, the Illinois Environmental Protection Agency (Agency) filed its 

“Recommendation” in response to the petition (Agency Response) stating that the Agency 

“neither supports nor objects to the [Board] granting the Petition subject to the terms and 

conditions contained herein.” Agency Resp. at 1. The Agency determined that no 

environmental harm would result if the Board were to grant a variance requiring compliance with 

an overall annual SO2 emission rate of 0.35 lb/mmBtu1 from 2013 through 2019, considering 

that AER has already ceased operation of the Meredosia and Hutsonville stations. Id. at 11. The 

Agency also states that such a variance would be “acceptable” to the Agency. Id. at 7.

 1 “mmBtu” stands for million British thermal units or 1,000,000 Btu.
2

The Board received 2,023 public comments in favor of granting the petition, and 1,072

comments opposed, including several spoken at hearing and many written. The Board 

appreciates the extraordinary time and effort of State and local officials, individual citizens, and 

citizens groups who provided their professional opinions, personal stories, and concerns in this 

matter.

The Environmental Protection Act (Act) gives the Board authority to grant a variance 

from a Board regulation when it finds that compliance with the regulation would impose an 

arbitrary or unreasonable hardship on the petitioner. 415 ILCS 5/35(a) (2010). For the reasons 

set forth below, the Board finds that requiring AER to comply with Section 225.233(e)(3)(C)(iii) 

in 2015 and 2016 and with Section 225.233(e)(3)(C)(iv) starting in 2017 would impose an 

arbitrary or unreasonable hardship. Additionally, the Board finds that the requested variance will 

result in an overall reduction in emissions and therefore has no significant negative impact on the 

public or the environment. The Board also finds that the requested variance is consistent with 

federal law. The Board, therefore, grants the variance subject to certain conditions.

PROCEDURAL BACKGROUND

On May 3, 2012, AER filed a petition for a variance from the overall SO2 annual 

emission rate in the MPS applicable to the seven coal-fired electric generating stations in the 

AER MPS Group. See 35 Ill. Adm. Code 225.233(e)(3)(C)(iii) and (iv). Pet. at 4-5. AER states 

that, as of January 2012, it generates electricity at five of these seven stations, having ceased 

operations at the Meredosia and Hutsonville stations in December, 2011. Id. at 5, Pet. Exh. 6 at 

4. AER seeks relief from Section 225.233(e)(3)(C)(iii) for five years beginning January 1, 2015

and ending December 31, 2019, and relief from Section 225.233(e)(3)(C)(iv) for approximately 

three years, beginning January 1, 2017 and ending January 15, 2020. Pet. at 1; AER First Resp.

at 1.

The Act requires the Agency to provide public notice of a variance petition, including 

notice by publication in a newspaper of general circulation in the county where the facility is 

located, within 14 days after the petition is filed. 415 ILCS 5/37(a); 35 Ill. Adm. Code 104.214. 

AER’s petition was filed on May 3, 2012. Therefore, publication of newspaper notice was 

required by May 17, 2012. The Agency placed newspaper notices in newspapers in each of the 

seven counties where facilities in the AER MPS Group are located on dates between May 10 and 

May 16, 2012. The Agency informed the Board that it also mailed notices of the petition to 

elected officials, consistent with 35 Ill. Adm. Code 104.214(b). Agency Resp. at 3.

The Act requires the Agency to investigate each variance petition and “make a 

recommendation to the Board as to the disposition of the petition.” 415 ILCS 5/37(a); 35 Ill. 

Adm. Code 104.216. On July 23, 2012, the Agency filed a document titled “Recommendation” 

stating that the Agency “neither supports nor objects to the [Board] granting the Petition subject 

to the terms and conditions contained herein.” Agency Resp. at 1. Within 14 days after service 

of an Agency recommendation, the petitioner may file a response to the Agency recommendation 

or an amended petition. 35 Ill. Adm. Code 104.220. AER made no such filing.
3

The Board will hold a hearing on a variance petition (1) if the petitioner requests a 

hearing; (2) if the Agency or any other person files a written objection to the variance within 21 

days after the newspaper notice, together with a written request for hearing; or (3) if the Board, 

in its discretion, concludes that a hearing is advisable. See 415 ILCS 5/37(a); 35 Ill. Adm. Code 

104.224, 104.234. In the petition, AER waived hearing. Pet. at 32. On May 31, 2012, the Board 

received two objections to the petitions, discussed in more detail below: (1) Objection of 

Environmental [sic] Illinois, Environmental Law and Policy Center (ELPC), Natural Resources 

Defense Council, Respiratory Health Association of Metropolitan Chicago (RHA), and Sierra 

Club; and (2) Objection of Environment Illinois, ELPC, RHA, and Sierra Club. However, each 

of these objections expressly stated that they do not request a hearing pursuant to 35 Ill. Adm. 

Code 104.224(c). Nevertheless, based on the filings received, including numerous public 

comments, the Board concluded that a hearing was warranted in this case. See also, infra, p. 6, 

n. 3.

In advance of the hearing, the Board’s hearing officer, Carol Webb, issued two sets of 

questions to AER to clarify points raised in the petition. The hearing officer issued the first set 

of questions on July 6, 2012 and the second set of questions on July 25, 2012. AER filed two 

sets of responses to the hearing officer’s questions on July 30, 2012: AER’s Responses to the 

Illinois Pollution Control Board Technical Unit’s Questions (AER First Resp.); AER’s 

Responses to the Illinois Pollution Control Board Technical Unit’s Second Set of Questions 

(AER Second Resp.).

The Board held the public hearing on August 1, 2012 in Springfield. AER and the 

Agency appeared as participants in the hearing. AER presented testimony from two witnesses. 

In addition to hearing testimony, the Board received 90 oral public comments during the hearing. 

The Board received the transcript of the August 1, 2012 hearing on August 2, 2012. AER filed a 

post-hearing brief (AER Post Br.) on August 15, 2012. IEPA filed a post-hearing brief on 

August 20, 2012. On August 23, 2012, AER filed an additional post-hearing comment (AER 

post comment) and a motion to file the comment instanter.

In addition to the oral public comments received at the hearing, the Board has received 

3,002 written public comments. Two comments were submitted to the Agency and the Agency 

attached the letters to its response. These two comments are substantially similar to public 

comments filed with the Board by the same parties. The deadline for filing public comments 

was August 10, 2012. The Board notes that the number of public participants is greater than the 

3,002 comments received, as some public comments were signed by more than one individual. 

See, e.g., PC#2197 (signed by six individuals), and PC#2648 (signed by 85 individuals). The 

Board received an additional 119 public comments following the close of the public comment 

deadline.2

 2 Public comments 2,995 through 3,005 consist of 2,372 letters urging the Board to deny AER’s 

variance request. In the interests of administrative economy, the Clerk’s Office batched a 

number of identical, late-filed public comments, assigning one number to groups of comments 

with similar text.
4

AER POST-HEARING MOTIONS

On August 15, 2012, along with AER’s post-hearing brief, AER filed a motion for waiver 

of page limitation (Waiver Mot.). AER states it 

cannot adequately address the numerous questions, public comments, both oral 

and written, and the various issues raised in those questions and comments, in the 

50-page limit provided in the Board’s procedural rules. Waiver Mot. at 1.

AER therefore requests that the Board grant it a waiver of the 50-page limitation. Id. at 2. The 

Board did not receive any objections to granting of the motion. The Board has received a total of 

3,005 public comments in this docket. 

On August 23, 2012, AER filed a motion to file instanter (AER Post Mot.) a public 

comment regarding an August 21, 2012 decision of the United States Court of Appeals for the 

D.C. Circuit. AER Post Mot. at 1; see also Petitioner’s Post-Hearing Comment at 1, citing

E.M.E. Homer City Generation, L.P. v. Environmental Protection Agency, et al., No. 11-1302 

(D.C. Circuit, Aug. 21, 2012). The Court’s decision vacated the Cross-State Air Pollution Rule 

(CSAPR) and AER noted that the vacatur “directly relates to a question by a Board member at 

hearing.” Id. at 2.

To ensure a complete record, the Board grants both of AER’s motions.

STATUTORY BASIS FOR ISSUING VARIANCE

A “variance is a temporary exemption from any specified rule, regulation, requirement or 

order of the Board.” See 35 Ill. Adm. Code 104.200(a)(1). Under Title IX of the Act (415 ILCS 

5/35-38), the Board is responsible for granting variances when a petitioner demonstrates that 

immediate compliance with a Board regulation would impose an “arbitrary or unreasonable 

hardship” on petitioner. 415 ILCS 5/35(a). Specifically, the Act provides:

The Board may grant individual variances beyond the limitations prescribed in 

this Act, whenever it is found, upon presentation of adequate proof, that 

compliance with any rule or regulation, requirement or order of the Board would 

impose an arbitrary or unreasonable hardship. However, the Board is not required 

to find that an arbitrary or unreasonable hardship exists exclusively because the 

regulatory standard is under review and costs of compliance are substantial and 

certain. 415 ILCS 5/35(a); see also 35 Ill. Adm. Code 104.200, 104.208, 104.238.

The Board may grant a variance, however, only to the extent consistent with applicable federal 

law. 415 ILCS 5/35. Further, the Board may issue a variance from any regulation with or 

without conditions, and for a period of time not exceeding five years. See 415 ILCS 5/36(a) and 

(b).

The burden of proof is on the petitioner. 415 ILCS 5/37(a); 35 Ill. Adm. Code 

104.200(a)(1), 104.238(a). The petitioner must prove that immediate compliance with Board 
5

regulations would cause an arbitrary or unreasonable hardship that outweighs public interest in 

compliance with the regulations. See Willowbrook Motel v. PCB, 135 Ill. App. 3d 343, 349-50, 

481 N.E.2d 1032, 1036-37 (1st Dist. 1985).

BACKGROUND OF THE MULTI-POLLUTANT STANDARD

In 2005, the United States Environmental Protection Agency (USEPA) promulgated 

regulations requiring reduction of nitrogen oxide (NOx), SO2, and mercury. See 70 Fed. Reg. 

25162 (May 12, 2005); 70 Fed. Reg. 28606 (May 18, 2005). The Agency proposed rules to the 

Board to implement both federal rules. The first rulemaking was Proposed New 35 Ill. Adm.

Code 225 Control of Emissions from Large Combustion Sources (Mercury), R06-25 (Dec. 21, 

2006). This rule amended 35 Ill. Adm. Code Part 225 Subpart A and added Subpart B. The 

second rulemaking was Proposed New Clean Air Interstate Rules (CAIR) SO2, NOx, Annual and 

NOx Ozone Season Trading Programs, 35 Ill. Adm. Code 225, Subparts A, C, D, E, and F, R06-

26 (Aug. 23, 2007).

As a result of these rulemakings, under Part 225 “Control of Emissions from Large 

Combustion Sources,” affected utilities are provided with two compliance options for reducing 

emissions: One option imposes stringent limits on mercury emissions alone and the other option 

requires implementing mercury control technology in conjunction with emission limits for SO2

and NOx. This second option is found at Section 225.233 and is referred to as the MultiPollutant Standard (MPS). 35 Ill. Adm. Code 225.233. On December 27, 2007, AER opted into 

the MPS for the AER MPS Group. Pet. at 12.

In 2008, AER petitioned the Board for a variance from the 2013 and 2014 SO2 emission 

rates (0.33 lb/mmBtu or a rate equivalent to 44% of the Base Rate of SO2 emissions, whichever 

is more stringent) found at Section 225.233(e)(2). Pet. at 6; Ameren Energy Generating Co. et 

al. v. Illinois Environmental Protection Agency, PCB 09-21 (Jan. 22, 2009). The Board denied 

that variance request as not being the proper regulatory relief mechanism. Id. AER then 

participated in the rulemaking captioned Amendments to 35 Ill. Adm. Code 225: Control of 

Emissions from Large Combustion Sources (Mercury Monitoring), R09-10 (June 18, 2009). As 

a result, the Board promulgated a final rule which included adding subsection (3) to Section 

225.233(e), titled “Ameren MPS Group Multi-Pollutant Standard.” Accordingly, Sections 

225.233(e)(3)(C)(iii) and (iv), which are the subject of this variance request, became effective on 

July 15, 2009. Id. at 6-7; Agency Resp. at 5.

The specific rule provisions from which AER now seeks relief are:

Section 225.233 Multi-Pollutant Standard (MPS)

e) Emission Standards for NOx and SO2

. . .

3) Ameren MPS Group Multi-Pollutant Standard
6

. . . 

C) SO2 Emission Standards

. . .

iii) Beginning in calendar year 2015 and continuing in calendar 

year 2016, for the EGUs in the Ameren MPS Group, the owner and 

operator of the EGUs must comply with an overall SO2 annual 

emission rate of 0.25 lb/million Btu.

iv) Beginning in calendar year 2017 and continuing in calendar 

year thereafter, for the EGUs in the Ameren MPS Group, the 

owner and operator of the EGUs must comply with an overall SO2

annual emission rate of 0.23 lb/million Btu.

On June 24, 2011, the Agency submitted a revision to the Illinois State Implementation 

Plan (SIP) addressing regional haze. See 77 Fed. Reg. 3966 (Jan. 26, 2012); Pet. at 29. The 

Illinois regional haze plan addresses Section 169A of the Clean Air Act (CAA) (42 U.S.C. 7491) 

to remedy impairment of visibility in Class I areas such as national parks and wilderness areas. 

77 Fed. Reg. 3966. The Illinois submittal to USEPA included adding Sections 

225.233(e)(3)(C)(iii) and (iv), the subject of this variance petition, to the Illinois SIP. Pet. at 30, 

Exh. 12. On January 26, 2012, USEPA proposed approval of Illinois’ submittal. 77 Fed. Reg. 

3966. As of the date of filing the petition, USEPA had not yet taken final action on this 

proposal. Pet. at 29. On July 6, 2012, during this variance proceeding, USEPA approved the 

Illinois submittal. 77 Fed. Reg. 39943. USEPA granted final approval for Illinois’ Regional 

Haze SIP as proposed by Illinois which means Sections 225.233(e)(3)(C)(iii) and (iv) are part of 

the Illinois SIP effective August 6, 20123

. Id.

AER’S VARIANCE PETITION

AER petitioned the Board for a variance from Section 225.233(e)(3)(C)(iii) and (iv) of 

the MPS seeking additional time to comply with the overall SO2 annual emission rates because:

among other things, declining power market prices have resulted in an insufficient 

cash flow necessary to finance and maintain the construction completion schedule 

of flue gas desulfurization (FGD) equipment at the Newton Energy Center 

(Newton FGD [p]roject) in time to meet those rates. By seeking relief now, 

which is critical from a timing standpoint, AER will conserve cash flow and stave 

off draconian operational measures with the hope that stability will eventually 

return to the marketplace thereby allowing the completion of the Newton FGD 

project. Pet. at 1-2.

 3 Since the MPS is now part of the Illinois SIP, the State of Illinois must hold a public hearing or 

provide the public the opportunity to request a public hearing on this variance request. 40 C.F.R. 

§ 51.102(a).
7

AER states that, contrary to positions advocated by the Citizens Groups, its decision to 

opt-in to the MPS “was not an ‘agreement’ or the ‘functional equivalent of a contract’ . . . but 

rather a decision to be subject to one Illinois regulation as opposed to another.” AER Post Br. at 

6. AER believes that its request “fulfills the purpose of the variance process” and that asking for 

more time to comply “is the responsible thing to do given that [AER]’s compliance plan offsets 

any potential adverse impacts to human health and the environment.” Id.

Corporate Structure

AER is a subsidiary of Ameren Corporation. Affidavit of Ryan J. Martin (Pet. Exh. 6) at 

2. Ameren Corporation is a public utility holding company whose primary assets are the 

common stock of its subsidiaries, including AER, Ameren Missouri and Ameren Illinois. Id. 

Ameren Corporation’s subsidiaries “are separate, independent legal entities with separate 

businesses, assets, and liabilities.” Id. AER consists of merchant generating operations that 

include Ameren Energy Generating Company (GENCO) and Ameren Energy Resources 

Generating Company (AERG). Id. GENCO is AER’s only publicly-registered and rated 

company. Id. GENCO is a registered company with the Securities and Exchange Commission, 

and its financials are publicly reported. Id. at 3.

Illinois deregulated its electricity market in 1997. Pet. at 3, fn. 3. At that time, Ameren 

Corporation’s rate regulated utilities transferred generating facilities formerly owned by Central 

Illinois Public Service Company (CIPS) and Central Illinois Light Company (CILCO) into 

GENCO and AERG. AER owns, respectively, the former CIPS plants (Newton, Coffeen, 

Meredosia and Hutsonville) and the former CILCO plants (Duck Creek, E.D. Edwards). Id. In 

addition, AER owns 80% of the common stock of Electric Energy, Inc., which operates the 

Joppa Energy Center. Id.

Facilities

AER owns seven coal-fired electric generating stations in Illinois. Pet. at 4. These seven 

stations constitute the AER MPS Group and include 21 electric generating units. Pet. at 4, n. 6. 

As of January 2012, AER ceased operation of the Meredosia (Morgan County) and Hutsonville

(Crawford County) stations but generates electricity at the remaining five stations: Coffeen 

(Montgomery County), Duck Creek (Fulton County), E.D. Edwards (Peoria County), Joppa 

(Massac County), and Newton (Jasper County). Pet at 4-5. AER employs approximately 750 

persons at the facilities in the AER MPS Group. Pet. at 6.

The principal emissions at AER’s plants are SO2, NOx, and particulate matter. Pet. at 5. 

The counties where AER plants are located are designated as attainment for all pollutants. Id. 

AER controls SO2 emissions with pollution control equipment, specifically three flue gas 

desulfurization units at the Duck Creek and Coffeen stations, and by using low-sulfur coal or 

blending low sulfur coal with Illinois coal. Id. AER controls NOx emissions using low NOx

burners, over-fired air, selective catalytic reduction systems, and burning combinations of lowsulfur coal. Id. AER controls particulate matter using flue gas conditioning and electrostatic 

precipitators. Id. AER controls mercury emissions using scrubbers and sorbent injection. Id.
8

Relief Requested

In its initial petition, AER seeks a variance from Section 225.233(e)(3)(C)(iii) for five 

years, beginning January 1, 2015 and ending December 31, 2019, and from Section 

225.233(e)(3)(C)(iv) for four years, beginning January 1, 2017 and ending December 31, 2020. 

Pet. at 7. In its response to questions from the Board, AER informs the Board that, after 

discussions with the Agency, AER revises its request to return to compliance with Section 

225.233(e)(3)(C)(iv) regarding the 0.23 lb/mmBtu rate on January 15, 2020, rather than 

December 31, 2020. AER First Resp. at 1, AER Post Br. at 4. The date for return to compliance 

with the 0.25 lb/mmBtu rate will remain January 1, 2020. AER Post Br. at 4.

To meet the current overall SO2 annual emission rates for 2015 and 2016 in Section 

225.233(e)(3)(C)(iii), and for 2017 and beyond in Section 225.233(e)(3)(C)(iv), AER planned to 

install flue gas desulfurization equipment at the Newton station. Id. AER asserts that inadequate 

cash flow and borrowing restrictions make it unable to complete construction. Id. If the 

variance is not granted, AER claims that it “will need to mothball multiple units across [AER’s] 

coal fleet, which may include E.D. Edwards, Joppa, and/or Newton units, so as to comply with 

the MPS overall SO2 annual emission rates until such time as market prices recover to the level 

that the Newton FGD [p]roject is financially viable and installation can be completed.” Pet. at 7-

8. AER believes this to be its “only other viable compliance alternative.” AER Post Br. at 2.

AER seeks this variance well in advance of the 2015 and 2017 compliance deadlines. 

Pet. at 7. AER asserts that the total length of the variance from both requirements “would allow 

for power price market conditions to improve and regulatory certainty at the federal level to 

crystallize.” Pet. at 8. AER argues that this variance does not request a variance exceeding five 

years. Id.

AER does not seek a change to NOx limits or mercury control requirements. Pet. Exh. 7.

Compliance Plan

AER states it has complied with mercury and NOx requirements set forth in the MPS. 

AER Post Br. at 32. AER would further implement a compliance plan that “results in a net 

environmental benefit” and “mitigates the environmental impact represented by extending the 

SO2 compliance dates set forth in the MPS” if the variance is granted. Id.

In its initial petition, AER proposes that the AER MPS Group will meet an overall SO2

annual emission rate of 0.38 lb/mmBtu from 2012 through 2019. Pet. at 9. AER anticipates 

achieving this rate by continuing to not operate at the Hutsonville and Meredosia stations and 

“maximizing FGD performance” at Duck Creek and Coffeen. Id. AER will continue to burn 

low-sulfur coal from the Powder River Basin at the five operating stations. Id. 

In its response to questions from the Board, AER informed the Board that AER has 

revised its proposed compliance plan. AER proposes to return to compliance with the 2015 

overall SO2 annual emission rate on January 1, 2020 and with the 2017 overall SO2 annual rate 
9

by January 15, 2020. AER First Resp. at 1-2. In addition, AER proposes to meet an overall SO2

annual emission rate of 0.35 lb/mmBtu from 2013 through 2019, lowered from 0.38 lb/mmBtu. 

Id. at 1. AER will meet this revised rate by not operating the Hutsonville and Meredosia stations 

during the variance term. Id. at 2. AER will also operate FGD systems at the Duck Creek and 

Coffeen stations at a higher level of control. Id. Specifically, AER will operate the FGD 

systems at a 98%-99% SO2 removal rate rather than 95% which will also require “auxiliary 

power, the increased sizing of equipment, and increased limestone usage.” Id. at 8. AER

estimates that capital expenditures to operate the Duck Creek and Coffeen stations FGD systems 

at 98%-99% will be $5 million in capital costs and $173,337 in annual operating and 

management costs. Id. AER also intends to procure lower-sulfur coal for its operations. AER

Post Br. at 5. AER asserts that, by taking these steps, it will achieve an emission rate of 0.35 

lb/mmBtu. Id. at 5. AER contends that this compliance plan “provides a net environmental 

benefit with respect to SO2 emissions.” Id. at 3.

AER expects to continue construction at Newton to complete the FGD project. Pet. at 9. 

AER has procured “all major equipment components” needed for the Newton FGD project. Id. 

AER “expects to continue” site preparation, foundation work, and duct work fabrication “over 

the next few years.” Id. Field construction “could take approximately 24 months to complete 

once the project ramps back up.” Id. Extending site preparation and construction over several 

years will “position AER for compliance with the 2015 [overall] SO2 annual emission rate by 

January 1, 2020.” Id. AER has incurred $237 million in the Newton FGD project to date. Id. at 

19. By the end of 2012, AER will have spent over 50% of the project cost. Id.

In response to questions from the Board, AER provided additional detail on the 

construction plans for the Newton FGD project. AER has scheduled construction work during 

2012 and 2013. AER First Resp. at 6. During this time, all major equipment will be delivered to 

the site and rough set; AER will also fabricate ductwork and construct the absorber building. Id. 

Engineering design is 65% complete. Id. Engineering design will be completed in 2014. Id. 

AER has budgeted $16 million per year from 2013 to 2016 and greatly increased capital 

expenditures in 2018 and 2019 to complete the Newton FGD project. Pet. at 19; AER First 

Resp. at 6; Tr. at 32; AER Post Br. at 38, 40. 

The Board requested that AER provide an estimated timeline for phases of the 

compliance plan including engineering, site preparation, foundation work, duct work, 

fabrication, field construction activities, startup, and any other significant phases. AER proposes 

instead to provide the Board with progress reports on construction activities. AER First Resp. at 

6. AER states this is because it is difficult to provide a specific and targeted prospective 

schedule beyond the categories of work previously provided to the Board. AER Post Br. at 38. 

AER contends that a specific timeline establishing construction and project milestones cannot be 

provided until an in-service date is fixed. Id. AER states “[o]nce the Company ‘green lights’ the 

project, AER project management and its general contractor Advatech will reestablish a hard and 

fixed schedule that ‘backtracks’ from the service date and takes into account work already 

completed. Id. AER does note that if relief is granted, AER’s current budget projections
10

call for greatly increased capital expenditures commencing in 2018 and 2019 so 

that AER will be in a position to comply with the MPS once the proposed 

variance term expires on January 15, 2020. Id.

AER further states that it is unable to provide a date certain by which AER will know if 

completion of the scrubber project is feasible before the January 15, 2020 deadline. AER Post 

Br. at 40. However, AER contends that its compliance plan is premised on a commitment “that 

meaningful engineering, procurement and construction activities” will continue throughout the 

variance period, committing to spend roughly $16 million per year from 2013 to 2016 with a call 

for greatly increased capital expenditures in 2018 and 2019 to complete the Newton FGD 

project. Pet. at 19; AER First Resp. at 6; Tr. at 32; AER Post Br. at 38, 40.

Arbitrary or Unreasonable Hardship

AER argues that compliance with the 2015 and 2017 overall SO2 annual emission rates in 

the MPS by the current deadlines will impose an arbitrary or unreasonable hardship for AER. 

Pet. at 11. AER states that this hardship was not self-imposed (AER Post Br. at 7), but rather 

that AER is the victim of a “crippling double-whammy.” Pet. at 11. First, Illinois promulgated 

regulations to implement the federal Clean Air Mercury Rule (CAMR) and Clean Air Interstate 

Rule (CAIR). Id. These federal rules were subsequently invalidated while the Illinois MPS 

remained in effect. Id. In the absence of these federal rules, Illinois requirements are more strict 

than surrounding states. Id. Second, Illinois electric generators must fund capital projects such 

as pollution control equipment with revenues rather than captive consumer rates. Id. Illinois’

deregulated electric market also creates a disadvantage for Illinois generators compared to 

competitors in nearby states. Id.

AER states that it did not delay in choosing a plan to comply with the MPS or in deciding 

to seek relief from the Board. AER Post Br. at 7. Rather, AER knew it did not have the cash 

flow to timely complete the Newton FGD project within only a few short months of the sharp 

decline in power prices due to lowest demand in decades because of the recession, the 

exceptionally mild winter, and an increased supply of natural gas. Id.

Regulatory Uncertainty

AER contends that it opted into the MPS in 2007 with the expectation that future federal 

regulatory requirements were imminent. Pet. at 11. AER summarizes the development of 

certain federal air pollution rules and their implementation in Illinois. Pet. at 11-16. In 2005, 

USEPA promulgated regulations requiring reduction of NOx and SO2 emission known as CAIR, 

70 Fed. Reg. 25162 (May 12, 2005) and reduction of mercury emissions known as CAMR, 70 

Fed. Reg. 28606 (May 18, 2005). Both rules applied to coal-fired electric generating units, and 

specifically to AER’s coal-fired electric generating units. Pet. at 11-12. 

The Agency proposed rules to the Board to implement both federal rules. The first 

rulemaking was Proposed New 35 Ill. Adm. Code 225 Control of Emissions from Large 

Combustion Sources (Mercury), R06-25 (Dec. 21, 2006). The second rulemaking was Proposed 

New Clean Air Interstate Rules (CAIR) SO2, NOx, Annual and NOx Ozone Season Trading 
11

Programs, 35 Ill. Adm. Code 225, Subparts A, C, D, E, and F, R06-26 (Aug. 23, 2007). AER

recounts that during these proceedings, AER approached the Agency with a comprehensive 

proposal to address mercury in coordination with other air emission requirements. Pet. at 12. 

These negotiations between AER and the Agency resulted in promulgating Section 225.233 in 

the Board’s R06-25 proceeding. Id. 

Subsequently, in February 2008, a federal court vacated the federal CAMR. Pet. at 13, 

citing State of New Jersey v. Environmental Protection Agency, 517 F.3d 574 (D.C. Cir. 2008). 

Shortly thereafter, a federal appellate court remanded the federal CAIR to the lower court but 

ordered that CAIR remain effective until replaced with a new rule. Pet. at 13, citing North 

Carolina v. Environmental Protection Agency, 550 F.3d 1176 (D.C. Cir. 2008). After these 

decisions, the MPS presented “significantly more confining constraints for Illinois generating 

companies that had opted into the MPS.” Pet. at 13-14. AER states “the impacts of having an 

uneven playing field [then] began revealing themselves.” Pet. at 14.

AER states “these judicial decisions, coupled with pending greenhouse gas emission 

regulations, severe market liquidity conditions, and the near collapse of the banking system first 

presented difficulty for the [AER] MPS Group in 2008.” Pet. at 14. At that time, AER sought 

additional time to comply with the 2013 SO2 overall annual emission rate in the MPS “to avoid 

stranded costs of compliance.” Id. This additional time allowed AER “to make more educated 

and sustainable investment decisions on how to comply with the MPS in light of the regulatory 

uncertainty on both the federal and regional levels.” Id.; see also Ameren Energy Generating 

Co., et al v. IEPA, PCB 09-21 (Jan. 22, 2009); and Amendments to 35 Ill. Adm. Code 225: 

Control of Emissions from Large Combustion Sources (Mercury Monitoring), R09-10 (Jun. 18,

2009).

In August 2011, USEPA adopted CSAPR to replace CAIR. Pet. at 14; 76 Fed. Reg. 

48208 (Aug. 8, 2011). CSAPR was challenged in federal court and the court stayed 

implementation of the rule. Pet. at 14, citing EME Homer City LP v. Environmental Protection 

Agency, No. 11-1302 (D.C. Cir. Dec. 30, 2011). In its petition, AER contends that the fate of 

CSAPR is uncertain and argues that “the very basis of the MPS – that is, an effective and 

permanent federal program – has yet to become a reality.” Pet. at 14. AER argues that it will 

suffer arbitrary and unreasonable hardship if required to comply with the MPS due to the 

uncertainty of whether the CSAPR will be implemented. Id. at 15. AER states that it ceased 

operations at the Hutsonville and Meredosia stations because it faced “deteriorating market 

conditions and compliance with what was anticipated to be an effective CSAPR program in 2012 

compounded by other environmental mandates.” Id. 

AER argues that the federal court order staying implementation of CSAPR has national 

implications, exacerbated in Illinois. Pet. at 15. AER makes two arguments as to why Illinoisspecific MPS requirements cause it an arbitrary or unreasonable hardship.

First, the MPS requires Illinois electric generating units to control NOx and SO2

emissions “even in the absence of a permanent and effective federal emission program like 

CAIR.” Pet. at 15. CSAPR, the replacement for CAIR, was scheduled to take effect on January 

1, 2012 but was stayed. AER concludes that “it is now unknown when or if CSAPR will become 
12

effective.” Id.4

 AER argues that it is arbitrary and unreasonable to require it to comply with the 

MPS if there is no federal program requiring that level of control. Id.

Second, AER argues that Illinois-specific MPS requirements place it at a competitive 

disadvantage with nearby states. Pet. at 16-17. AER asserts that it faces “significant challenges 

that limit their ability to access third party capital to continue to invest in state and federallymandated environmental control equipment.” Id. at 16. AER states that it does not have revenue 

from a captive consumer base to fund environmental compliance costs because it is a “merchant 

generator in an unregulated or consumer choice market.” Id. AER claims that it competes with 

generators in nearby states “that have neither deregulated their energy markets nor invested 

significant capital in environmental pollution control projects.” Id. These companies are able to 

recover compliance costs through rates. Id. AER, as an unregulated power company, is only 

able to recover its costs through market driven prices and margins. Affidavit of Gary M. Rygh 

(Pet. Exh. 5) at 6. Further, AER claims it is at a significant financial disadvantage as a firm with 

coal-fired generating assets compared to companies with less carbon-intensive portfolios. Id. If 

the CSAPR had become effective on January 1, 2012, the CSAPR would have “level[ed] the 

playing field” between Illinois generators and competitors in nearby states. Pet. at 16-17. AER

also states that, in contrast to comments received by the Board, AER did not seek deregulation. 

AER Post Br. at 9. Rather,

it was one of the primary purposes of the [Illinois] Electric Service Customer 

Chose and Rate Relief Law of 1997 to, in fact, incent the utilities to move their 

generating plants into either affiliates or third parties, where they could no longer 

be controlled by the utilities and would, instead, compete in a wholesale power 

market to provide power to retail customers at prices determined by competition.

***

While it is true [AER] was not compelled to effectuate this transfer, there was at 

the time a much greater incentive to do so than . . . portrayed in [the testimony of 

Mr. Rob Kelter on behalf of ELPC]. Id. at 9, 10.

AER claims that retail customers in Illinois are the great beneficiaries of the 1997 law and the 

Illinois Power Agency Act enacted in 2007. AER Post Br. at 12. AER had to provide $185 

million in rate relief to customers “and other payments” as a result of the 2007 legislation. Id. 

AER’s benefit from opting into the MPS was that the compliance date for one aspect of the 

regulation (compliance with the removal efficiency requirement) was delayed from July 2009 to 

January 2015. Id. at 49-50. AER concedes that its intended benefit 

 4 The Board notes that, on August 21, 2012, during the pendency of this action, the United States 

Court of Appeals for the D.C. Circuit issued a ruling vacating CSAPR. E.M.E. Homer City 

Generation, L.P. v. Environmental Protection Agency, et al., No. 11-1302 (D.C. Circuit, Aug. 

21, 2012).
13

was to align the MPS’s NOx and SO2 emission requirements with what AER 

believed to be its control strategy for compliance with then pending CAIR 

regulations. Id. at 51.

AER contends that this intended benefit has not occurred but “substantial and real reductions of 

NOx and SO2 are still occurring.” Id.

Costs of Compliance

AER argues that the costs of compliance with the MPS are substantial and certain. Pet. at 

17. AER had analyzed these costs when the MPS was promulgated. Id. As noted above, the 

MPS was adopted during a proceeding to adopt controls on mercury emissions. Id. at 12. AER

asserts that it “is on track” to meet the mercury emission requirements effective in 2015 which 

was “the driver behind the MPS.” Id. at 17. However, AER claims that compliance with the 

2015 and 2017 [overall] SO2 annual emission rates is “no longer economically reasonable.” Id.

AER identifies various previous expenditures to comply with the MPS. AER installed 

three scrubbers at two plants to control SO2, mercury, and hazardous gas emissions. Pet. at 18. 

AER installed selective catalyst reduction (SCR) equipment to control NOx at three plants. Id. 

AER installed mercury controls. Id. AER spent over $1 billion “on the installation of pollution 

control facilities, including scrubbers, SCRs, landfills, cooling basins and towers, and 

precipitators, at Duck Creek, E.D. Edwards, Coffeen, and Newton, not including the Newton 

FGD [p]roject.” Id. at 18, 21. Specifically, AER has already installed scrubbers on three of its 

generating units at a cost of over $813 million and has started construction of the fourth and fifth 

pollution control facilities (i.e., the Newton FGD project) at a cost of over $237 million. AER

Post Br. at 31. AER also provides a chart that “details the various pollution control devices 

installed at the Coffeen, Duck Creek, E.D. Edwards, Joppa and Newton Energy Centers.” Id. at 

32-36.

AER plans to construct two FGD units at the Newton station. Pet. at 18. The project 

includes constructing a new chimney with separate flues for each unit, new induced draft fans for 

each unit, and gypsum and limestone handling facilities. Id. at 19. AER has obtained a 

construction permit for the project and started “engineering, procurement and construction 

activities.” Id. AER claims that it has spent $237 million to date on the project. Id. Through 

2012, AER will have spent “over 50% of the project cost.” Id. AER has slowed work on the 

project and will not complete it in time to meet the 2015 or 2017 overall SO2 annual emission 

rates. Id. AER intends to proceed with the project in time to comply with the 2015 SO2

emission rate by January 1, 2020 and the 2017 rate by January 15, 2020. Id.; AER First Resp. at 

6.

AER claims that it can no longer fund the Newton FGD project in time to comply with 

the 2015 and 2017 SO2 emission rates. Pet. at 19. Certain covenants within GENCO’s bond 

indenture restrict GENCO’s ability to incur additional indebtedness from external sources. Pet. 

Exh. 6 at 4. AER expects that, by the end of 2012, GENCO’s interest coverage ratio “will fall 

below the minimum level required for GENCO to incur additional external debt.” Id. at 5. 

GENCO “will not be able to borrow additional funds from third-party lenders to finance . . . the 
14

installation of scrubbers at Newton” unless power price market conditions improve dramatically 

in the near term. Id. AER attributes the declining power prices to “the recession, the 

exceptionally mild weather this winter, and an increased supply of natural gas from shale gas.” 

Pet. at 19. As evidence of declining prices, AER states that in 2006 and 2007 the price per 

megawatt hour was approximately $60 and in 2012 the price ranges from $29.50 to $33.60 per 

megawatt hour. Id. at 20. 

Further, as of August 2012, AER’s stock “hovers around $34,” in contrast to its $50 - $54 

asking price at the end of 2007 (AER Post Br. at 12) and AER’s return on equity in 2010 was -

3.9% and in 2011 was 4.3%. Id. at 13. AER states that there is currently uncertainty as to when 

its financial predicament will improve because, as a merchant generator, “[AER] has significant 

exposure to market prices, swings in load demand and commodity price volatility.” Id. 

Declining power prices have reduced operating proceeds and adversely impacted AER’s access 

to short-term and long-term financing. Id. With regards to capital that GENCO currently holds, 

AER states that “it is vitally important that GENCO preserve cash until market prices recover, 

operating results and cash flows improve, and borrowing capacity is restored.” Pet. Exh. 6 at 6. 

This is in part due to an approximate $825 million in long-term public bonds that GENCO 

currently has outstanding. Id. An inability to pay these bonds when due “would likely lead to a 

GENCO bankruptcy.” Id.

Additionally, AER contends that receiving funding from Ameren Corporation is not 

possible because AER as a “merchant business segment must be self-funding and its 

expenditures must be supported by its operating revenues.” Pet. at 22. Ameren Corporation 

cannot assume unsecured debt on behalf of AER without a secure revenue stream to support such 

an obligation. Id. AER has no direct access to public financial markets because it is not a 

publicly-registered company. AER First Resp. at 4. According to AER, “credit rating agencies 

have been very clear” that adverse financial consequences on the ratings of Ameren Corporation 

would result if it were to lend additional monies to AER. Pet. at 22, see also Pet. Exh. 6 at 10-

11. This is due to an “increasing negative view” of AER and its subsidiaries that prevents 

Ameren Corporation from investing in AER without adversely affecting its own credit quality 

and access to capital. AER First Resp. at 4. According to AER, the “credit rating agencies . . . 

have . . . made it abundantly clear that further support from the parent [Ameren Corporation] will 

have negative consequences on the credit quality of [Ameren Corporation] and its other 

subsidiaries.” Pet. Exh. 5 at 10.

AER states that the People’s criticism of Ameren Corporation’s requirements that its 

subsidiaries stand on their own, in terms of maintaining viable cash flow, are unfounded. AER

Post Br. at 14. AER notes that Ameren Corporation owns the common stock of AER and for 

Ameren Corporation to act as an ongoing funding source for AER “that cash flow would have to 

come from an operating unit such as one of the regulated utilities.” Id.

AER, as a merchant power generator, has “significant exposure to market prices, swings 

in load demand and commodity price volatility.” Pet. Exh. 5 at 2. AER’s “financial health and 

access to capital have both been severely degraded.” Id. at 3. This is partially due to low natural 

gas prices which have kept margins and cash flow under pressure for most unregulated power 

producers, including those that generate electricity using coal. Id. Since 2008, GENCO has seen 
15

its credit rating cut three notches by Standard and Poor’s and four notches by Moody’s Investor 

Services. Id. These downgrades, in part, are because of “a precipitous decline in net income and 

cash flow during that time period.” Id. AER states that the prospects of sourcing additional 

third-party capital are “bleak” given the experience of previous investors. Id. at 12. Therefore, 

AER’s operating margins and cash flows “represent AER’s only mechanism for funding both 

operating activities and capital investment. Pet. Exh. 6 at 9. The current depressed levels of 

AER earnings and cash flows “are insufficient to fund large-scale capital projects such as the 

installation of the scrubbers [at Newton].” Id. at 3.

Plant Closures

AER asserts that with no “viable funding mechanism” for the Newton FGD project, 

AER’s “only other compliance alternative” to comply with the overall SO2 annual emission rate 

in the MPS is to close at least two plants, such as Joppa, E.D. Edwards, or Newton. Pet. at 23. 

AER hired consultant Development Strategies to perform an analysis of the economic impact of 

the E.D. Edwards and Joppa stations on Illinois and local economies. Id. at 24, Exh. 10. The 

report concludes that AER puts $44.4 million in the local economy near the E.D. Edwards plant 

and $124,071,000 in the State’s economy due to the plant. Id. The report concludes that AER

puts $76.7 million in the local economy near the Joppa station and $214,221,000 in the State’s 

economy due to the Joppa station. Id. The two plants employ 274 persons and “supported an 

additional 1209 total jobs held by Illinois residents.” Id.

AER claims that closing plants “will indirectly impact Illinois electricity consumers.” 

Pet. at 25. AER sells power into a regional transmission organization known as the Midwest 

Independent Transmission System (MISO). Affidavit of Shawn E. Schukar (Pet. Exh. 11) at 2. 

According to Mr. Schukar, the Newton, Joppa and Edwards plants are among the more efficient 

units in the MISO footprint. Id. This efficiency is measured in heat rates where a lower heat rate 

indicates more efficient units. Id. The closing of these plants would lead to “a greater utilization 

of generating units that are less efficient and have higher marginal costs.” Id. The market would 

need to replace the energy from those units with energy from other units that cost more. Id. As a 

result “there will be less competition in AER’s area, which will negatively affect markets.” Pet. 

at 25. AER concludes that “power prices would likely increase appreciably for consumers.” Id. 

Natural Gas

AER notes that the current economic conditions that it faces “go beyond any price 

declines that were foreseeable when the 1997 law was passed or even when the MPS was 

enacted in 2006.” AER Post Br. at 10. Additionally, the new methods of gas extraction are a 

“game-changing” technology that have “fundamentally altered” the outlook for gas supplies and 

pricing. Id. AER contends that the MPS was premised on the expectation that the power market 

would continue to support the capital expenditures necessary to meet proposed emission rates. 

Id. However, “[m]arket conditions and new technologies and policies that have come about 

since that time were not self-imposed and simply not foreseeable.” Id.
16

Environmental Impact

AER contends that it has “exceeded the legal standard of ‘to minimize the impact,’” and 

has structured the requested variance to “offset the impact resulting in a net environmental 

benefit.” AER Post Br. at 25. AER notes that the Agency concurs with this position. Id.

Sulfur Dioxide

AER claims it has achieved “a steady and significant decline in SO2 emissions across 

[AER’s] fleet--79% since 1990 and 23% over just the last four years.” AER Post Br. at 30. For 

2011, AER stated its overall SO2 emission rate for the AER MPS Group, including the 

Meredosia and Hutsonville stations, was 0.46 lb/mmBtu. Pet. at 5; AER First Resp. at 7. Using 

2011 as a baseline and removing the contributions of the Meredosia and Hutsonville stations, 

AER projects that its overall SO2 annual emission rate in 2012 will be 0.40 lb/mmBtu. AER

First Resp. at 7-8. Section 225.233(e)(3)(C)(i) requires AER to achieve a rate of 0.50 lb/mmBtu

in 2011 and 2012. 35 Ill. Adm. Code 225.233(e)(3)(C)(i).

In Table 1 of its petition, AER presents its estimated SO2 emissions from 2010 through

2021 using the currently required overall SO2 annual emission rates in Section 

225.233(e)(3)(C)(i), (ii), (iii), and (iv). Pet. at 26. AER used a baseline heat input of 

340,446,252 mmBtu/year, which was the input AER used to support its proposed addition of 

Section 225.233(e)(3) in R09-10 in 2009, averaging 2006, 2007, and 2008 data, and includes 

Hutsonville and Meredosia. Pet. Exh. 7 at 3, 5; AER First Resp. at 8-9, fn. 11. In its petition, 

AER estimates that SO2 emissions from the AER MPS Group will total 694,510 tons from 2010 

through 2021 if the variance is not granted and AER complies with the MPS. Pet. at 26. AER

refers to this calculation as its MPS baseline SO2 emissions. Id. In response to questions from 

the Board, AER applied the same rationale to calculate its MPS baseline SO2 emissions from 

2010 through 2020 as 655,359 tons, which is consistent with Table 1 of the petition if emissions 

from 2021 are not included. AER First Resp. at 8-9, Table 2.

As presented in AER’s initial petition Table 1, if the variance is granted allowing AER to 

use an overall SO2 annual emission rate of 0.38 lb/mmBtu from 2012 through 2019, 0.25 

lb/mmBtu in 2020, and 0.23 lb/mmBtu in 2021, AER estimates that it will emit 665,294 tons 

from 2010 to 2021. Pet. at 26. AER also used a heat input of 340,446,252 mmBtu/year, 

multiplied by the proposed variance emission rates to calculate emissions of “variance SO2 tons” 

in Table 1. Pet. at 26; AER Second Resp. at 4. In its initial petition, AER calculates that these 

proposed variance conditions result in 29,217 fewer tons of SO2 emissions from 2010 through

2021 than compliance with the MPS. Pet. at 26. 

AER contends that its proposal for meeting an earlier, more stringent SO2 emission rate 

than what is required by the MPS will result in lower SO2 emissions and a net benefit to Illinois

during the variance. Pet. at 26. Specifically, in its initial petition, AER proposes an overall SO2

annual emission rate of 0.38 lb/mmBtu on a yearly system average (with a 0.55 lb/mmBtu or less 

SO2 coal on non-scrubbed units) from 2012 through 2019, which is lower than what currently is 

required by Section 225.233(e)(3)(C) for 2012, 2013, and 2014 but higher in 2015-2019. Id. at 

26-27. AER asserts that its total SO2 emissions from 2012 through 2021 will be lower if the 
17

variance is granted. Id. at 27. These calculations rely on AER not operating the Hutsonville and 

Meredosia stations through 2021. Id. at 26. 

In AER’s initial petition, AER includes SO2 emissions for past years 2010 and 2011 in 

demonstrating the projected emissions reductions. Pet. at 26, Table 1. The values for 2010 and 

2011 under the column “variance SO2 tons” are 70,560 and 72,539. Id. In response to questions 

from the Board, AER states these values are actual SO2 emissions in 2010 and 2011, 

respectively. AER Second Resp. at 4. In 2010 and 2011, AER’s actual SO2 emissions were less 

than the baseline SO2 tons due to “operation of FGD systems at high efficiencies and other 

operational measures to reduce emissions.” Id. at 4-5. AER included 2010 and 2011 in its 

analysis of the impact of the variance on SO2 emissions “to show the total tons of SO2 reduced 

during the MPS period by the end of the requested variance term.” Id. at 5.

AER subsequently revised its emission calculations resulting from the variance to 

account for its revised proposed SO2 emission rate of 0.35 lb/mmBtu during the years 2013 

through 2019. AER First Resp. at 9. In Table 2, AER used a heat input of 312,003,694 mmBtu 

for years 2012 through 2020 based on historic data from 2006, 2007, and 2008 but eliminating 

the heat inputs for the Meredosia and Hutsonville stations. AER First Resp. at 9, Table 2. Under 

Table 2, if the revised variance request is granted allowing AER to use an overall SO2 annual 

emission rate of 0.35 lb/mmBtu from 2013 through 2019, AER estimates that it will emit 

647,589 tons from 2010 through 2020. Id. AER calculates that the revised proposed variance 

conditions would result in 34,895 fewer tons of SO2 emissions overall by 2020 than compliance 

with the MPS. Id. Using the same data in Table 2, AER provides another assessment of SO2

emissions in Table 4, excluding years 2010 and 2011. AER calculates that from 2012 through 

2020, the revised proposed variance conditions would result in 7,700 fewer tons of SO2

emissions overall by 2020 than compliance with the MPS. AER Second Resp. Table 4.

In AER’s Table 3 and post-hearing brief Exh. 4, AER accounted for “SO2 Reduced Tons” 

based on lower actual emissions in 2010 and 2011 and fewer emissions from not operating 

Hutsonville and Meredosia. To be conservative, AER deducted from the reduced tons twice the 

new emissions from the FutureGen Project as 590 tons SO2 per year before calculating the 

cumulative reductions that would result from the proposed SO2 variance. AER Post Hearing Br. 

at 38-40, Exh. 4.5

 AER then calculates SO2 tons under the variance based on the baseline heat 

input of 340,446,252 mmBtu, resulting in emissions of 691,106 tons of SO2 under the variance 

and representing 60,669 fewer tons of SO2 from 2010 through 2020 than compliance with the 

MPS. AER Post Br. at 38-40, Pet. Exh. 4.

 5 AER explained that FutureGen is a zero emission coal plant project being considered for the 

Meredosia Energy Center, however, the project is years away and would not impact operations at 

Meredosia during the variance period. AER went on to explain that, because emission offsets 

may be required for permitting of the project in the future, the Agency did not want offsets to be 

“double counted” in AER’s calculations of net environmental benefit. AER therefore 

conservatively factored, by deducting from the SO2 reduced tons, two times the projected 

emissions to account for FutureGen project (two times the projected FutureGen SO2 emissions is 

590 tons). AER Post Br. at 29, 39-40.
18

AER commissioned a review of the health effects of SO2 in response to Board questions 

presented at hearing. AER Post Br. at 26; AER Post Br. Exh. 3. This report concludes that 

AER’s emissions under the SO2 variance are lower than the MPS emissions between 2012 and 

2014, and higher from 2015 to 2019. Id. at 27. AER contends that the People, in determining 

excess emissions, have ignored emission reductions that will commence immediately. Id. at 28. 

AER’s report determines that granting the variance “would result in an overall net benefit in 

terms of health effects.” Id. at 43. AER’s report also notes that

simply establishing that a person who has been exposed to SO2 experienced 

bronchoconstriction or a reduced expiratory volume is not proof that the exposure 

caused the effect. This is because in any individual, these effects could have been 

caused by a number of different factors, for example, indoor or outdoor allergens, 

smoking or passive exposure to cigarette smoke, or viral pathogens. Id. (internal 

citations omitted).

AER’s report also refutes the People’s position that additional harm would occur despite the 

overall reduction in tonnage of SO2 emissions over the term of the variance. Id. at 44. Rather, 

AER’s report concludes that there would be fewer adverse health effects overall. Id.

AER also cites a USEPA report prepared in support of the most recent SO2 NAAQS

review which found no causal relationship between long-term exposure to SO2 and asthma, 

bronchitis, or respiratory symptoms. AER Post Br. at 44. AER does note that the report found a 

causal relationship between respiratory morbidity and short-term exposure to SO2, but that these 

associations were very small and questions were raised regarding whether exposure and effect 

were causally associated. Id. In responding to public comments, AER states its report

consistently showed that generalized comments claiming SO2 caused respiratory 

illnesses including asthma relied on studies that either did not show statistically 

significant results or could not isolate the effects associated with SO2 from 

confounding co-pollutants. Id. at 44-45.

These studies further do not control for lifestyle variables or regional disease patterns. AER Post 

Br. at 45. AER’s report also contradicts the People’s position “that any harm done cannot be 

offset through earlier emissions.” Id.

Nitrogen Oxides

AER has achieved “a steady and significant drop in NOx emissions since 1990.” AER

Post Br. at 30. In 2011, the overall NOx emission rate for the AER MPS Group was 0.11 

lb/mmBtu. Pet. at 5. Section 225.233(e)(3)(B)(ii) required AER to achieve a rate of 0.14 

lb/mmBtu. 35 Ill. Adm. Code 225.233(e)(3)(B)(ii). Beginning in 2012, AER is required to 

achieve a rate of 0.11 lb/mmBtu. 35 Ill. Adm. Code 225.233(e)(3)(B)(iii). AER does not seek a 

change to applicable MPS NOx limits. Pet. Exh. 7.
19

Mercury

Starting January 1, 2015, each electric generating unit covered by the MPS must meet an 

emission standard of 0.008 lb mercury/GWh6 gross electrical output. Pet. at 28; 35 Ill. Adm. 

Code 225.233(d)(1). AER does not seek a change to MPS mercury control requirements. Pet. 

Exh. 7.

AER installed activated carbon injection systems on twelve units at four stations to 

control mercury emissions at a capital cost in excess of $20 million. Pet. at 28. AER spends $17 

million in annual operating costs for these systems, including purchasing activated carbon and 

fuel additives. Id. AER has installed four SCRs and three wet flue gas desulfurization systems 

to control mercury, NOx and SO2. Id. AER spent $813 million to install the three wet flue gas 

desulfurization systems and spends approximately $3.5 million in annual operating and 

maintenance costs. Id. AER spent $177 million to install the SCRs and spends approximately 

$3.9 million in annual operating and maintenance costs. Id. 

AER states, “The mercury reductions from AER’s fleet are being achieved three years 

ahead of the compliance deadline set forth in the MPS.” AER Post Hearing Br. at 40. AER

contends that “[e]arlier than anticipated mercury reductions will also provide a benefit to human, 

plant, and animal life impacted by mercury emissions from the [AER] MPS Group fleet.” Pet. 

Exh. 7. 

Greenhouse Gases

AER asserts that it “continues to support research into clean coal technologies, 

voluntarily reduce greenhouse gas emission, and purchase offsets to address climate change.” 

Pet. at 29. AER lists various examples and contends that it “continues to take action to reduce 

greenhouse gases.” Id.

Examined Alternatives

In response to Board questions, AER explains that it evaluated a range of compliance 

alternatives. AER First Resp. at 2; AER Second Resp. at 2. AER notes that the installation of 

two scrubbers at Newton “would reduce emissions by approximately 17,500 tons of SO2,” which 

would result in lower emissions than the 16,000 tons of SO2 AER would need to reduce to 

comply with the 2017 MPS emission rate. AER Post Br. at 15. AER contends that “[n]o other 

commercially available technology produces that level of removal efficiency.” Id. AER

contends that, contrary to positions taken by the People and the Citizens Groups, AER has 

considered all viable alternatives. Id. at 16. AER believes that measures suggested by public 

commenters

are either (a) ineffective because they do not allow AER to achieve compliance 

with the MPS emission standards and/or trigger excessive co-pollutant emissions 

 6 “lb mercury/GWh” stands for pound of mercury per gigawatt hour.
20

and requiring costly additional controls; or (b) would affirmatively worsen AER’s 

financial predicament. Id.

Curtailing Operations

AER considered curtailing generation and determined that curtailing operations is not a 

viable compliance alternative. AER First Resp. at 2; AER Second Resp. at 2-3; Tr. at 22. AER

contends that, although curtailing operations will reduce emissions, fixed operating costs 

essentially remain the same because the units are still operating, and less revenue is generated to 

pay those costs. AER First Resp. at 2. AER concludes that curtailing operations “puts AER as a 

whole in greater financial peril than unit shuttering.” Id. This alternative “puts a greater number 

of jobs at risk” and “does not allow AER to recover financially so that the funding of the 

scrubber can be continued.” Tr. at 22-23.

AER states that it examined the viability of reducing operations at Newton, Edwards and 

Joppa by varying degrees. AER Post Br. at 16. For AER to comply with the MPS SO2 rates, it 

would have to lower capacity factors on such units between 22% and 38%. Id. AER states that 

the result of these tests was a negative cash flow and an inability to fund ongoing operations. Id.

at 17.

Low-Sulfur Coal

As for burning low-sulfur coal, AER notes that the Coffeen and Duck Creek stations have 

wet FGD systems which allow them to burn a range of coals including higher-sulfur coal from 

the Illinois Basin. AER First Resp., n. 2. However, the Newton, Joppa, and E.D. Edwards 

stations burn low-sulfur coal as a compliance mechanism. Id. Although AER initially stated that 

it will “continue to burn low-sulfur coal from the Powder River Basin and manage operations as 

necessary to maintain compliance” (Pet. at 9), AER later committed to the use of ultra low-sulfur 

coal for some stations. AER Post Br. at 25. In order to comply with a SO2 emission rate of 0.35 

lb/mmBtu, AER states it will

limit the use of Illinois Basin coal (roughly 6.2 lb/mmBtu[]) and the higher SO2

content Powder River Basin Coal (roughly 0.8 lb/mmBtu) to the Duck Creek and 

Coffeen Energy Centers. Ultra-low sulfur coal (0.55 lb/mmBtu) will be used at 

the Edwards, Newton and Joppa Energy Centers. AER currently has 17 million 

tons of ultra-low sulfur coal under contract through 2014. AER Post Br. at 25.

Natural Gas

AER performed a screening analysis with respect to the feasibility of natural gas 

conversion of E.D. Edwards and Joppa Energy Centers as a compliance alternative. AER Post 

Br. at 23. AER states, under current market conditions, 

natural gas conversion at Joppa would adversely impact the current capacity 

levels and current operating regime of this facility would be reduced to the point 

where it would operate on a seasonal basis only. Id. at 23-24.
21

The resulting drop in utilization would lead to a reduction in revenue generated to cover fixed 

costs at the facility and across AER’s system, and would result in a reduction in workforce. Id.

Control Equipment

AER states that it continues to implement operational measures to reduce emissions, 

which AER has done “voluntarily at a cost even prior to coming to this Board to ask for relief.” 

AER Post Br. at 17. In response to questions from the Board, AER notes it has revised its 

proposed compliance plan to include operating FGD systems at the Duck Creek and Coffeen 

stations, at a higher level of control. AER First Resp. at 8; AER Second Resp. at 2. Specifically, 

AER will operate the FGD systems at a 99% SO2 removal rate rather than 95% which will also 

require “auxiliary power, the increased sizing of equipment, and increased limestone usage.” 

AER First Resp. at 8. Elsewhere, AER states that the FGD systems will operate with a range of 

98% to 99% removal efficiency. AER Second Resp. at 2. AER estimates that capital 

expenditures to operate FGD systems at 99% will be $5 million in capital costs and $173,337 in 

annual operating and management costs. AER First Resp. at 8. AER states that even with 

maximizing the FGD systems, “compliance margins remain narrow and AER will need to 

employ operational strategies such as low-sulfur coal procurement and generation utilization in 

order to comply with the proposed emission rate.” AER Second Resp. at 2.

AER has also evaluated dry sorbent injection to reduce SO2 emissions. AER Second 

Resp. at 2. AER states that it would be difficult to use sorbent injection as a compliance method 

because removal levels range widely from 10% to 90% and would reduce its effectiveness as a 

compliance alternative. Id. In addition, sorbent injection increased mass loading on electrostatic 

precipitators (ESPs) which may trigger the need for additional controls such as a baghouse to 

control particulate matter. Id. AER already uses activated carbon injection on its non-FGD units 

which adds to mass loading on the ESPs. Id. AER summarizes “to comply with the MPS via 

sorbent injection would entail installation of such controls (and baghouses) at virtually all of 

AER’s uncontrolled units across the system. The cost of such alternative would exceed the cost 

to complete the Newton scrubber.” Id. Further, AER states that the use of dry sorbent injection

would result in a significant increase above threshold levels of PM, “due to the size of the 

existing particulate control equipment and the use of [activated carbon injection (ACI)] for 

mercury control.” AER Post Br. at 19. AER states that neither the People nor the Citizens 

Groups adequately account for the impact that such pollution control technologies would have on 

pollutants other than SO2. Id. AER’s preliminary permitting analysis 

reflects that the use of such materials in the quantities required to comply with the 

2015 and 2017 SO2 emission rates would exceed applicable particulate 

requirements thereby triggering significant additional capital and maintenance 

expenses to address such emission requirements. Id.

To comply with both the SO2 and PM emission limits, AER would need to install additional 

particulate controls such as a fabric filter when using dry sorbent injection. Id. at 22. AER

retained third-party engineering firms to assess the viability of “a host of technologies,” at Joppa 

and Edwards, including the use of dry sorbent injection. AER Post Br. at 15. The cost of 
22

installing dry sorbent injection plus fabric filters at Joppa and Edwards was $433 million and 

$280 million, respectively. Id. This well exceeds the approximate $200 million to $250 million 

needed to complete the Newton FGD project. Id. at 23. AER concludes “there is no cost 

effective or otherwise viable alternative that ‘minimizes the deviation.’” Id.

In response to the People’s comments (PC#2410 at 3), AER differentiated the option of 

dry sorbent injection from dry scrubbers. AER Post Br. at 18. AER explained that dry sorbent 

injection would require relatively minor pieces of equipment to feed the sorbent material into 

ductwork, in addition to controls, such as baghouses, at virtually all of AER’s uncontrolled units 

across the system. Id.; AER Second Resp. at 2. The cost of installing dry sorbent injection plus 

fabric filters at Joppa and Edwards was $433 million and $280 million, respectively, and exceeds 

the costs to complete the Newton FGD project. AER Post Br. at 15, 23. In contrast, AER 

explained that a dry scrubber would require construction of a multi-storied building and spray 

tower. Since dry scrubbers have removal efficiencies in the low 90% range, AER would need to 

install six dry scrubbers at Joppa to achieve the reductions approaching those projected for the 

wet FGD project at Newton. AER estimated costs for installation of dry scrubbers would be 

$460 million, nearly twice the cost of completing the FGD project at Newton. Id. at 18. Further, 

AER notes that installation of dry scrubbers “may be ineffective in addressing hazardous gas 

emissions and, without additional add-on controls, could adversely affect impact particulate 

emissions.” Id.

Compliance with Federal Law

AER contends that the Board may grant the requested variance consistent with federal 

law, and specifically, the Clean Air Act. Pet. at 29. On June 24, 2011, the Agency submitted a 

revision to the Illinois SIP to satisfy Illinois’ obligation under the Clean Air Act to develop a 

Regional Haze SIP. See 77 Fed. Reg. 3966; Pet. at 29, 30. This submittal included adding 

Sections 225.233(e)(3)(C)(iii) and (iv), the subject of this variance petition, to the Illinois SIP. 

Pet. Exh. 12. AER concluded, at the time of its petition, that the proposal was not yet final and it 

was not clear when or if final adoption would occur. Pet. at 29; But see, supra, p. 6, citing 77 

Fed. Reg. 39943 (final USEPA granted effective August 6, 2012).

AER asserts that its requested variance is consistent with federal regional haze 

requirements, including Best Available Retrofit Technology (BART). Pet. at 30-31. In its 

Regional Haze SIP revision submittal, the Agency relies on the MPS to address regional haze 

and argued that Part 225 SO2 emission rates, including the rates applicable to the AER MPS 

Group, provide greater reductions than applying presumptive BART to BART-eligible units. 

Pet. at 30. 

Nevertheless, AER contends that its requested delay in complying with the MPS SO2

emission rates will be consistent with federal BART requirements. Pet. at 30. First, AER claims 

that the Agency concluded that particulate emissions from Illinois BART sources have negligible 

visibility impact using the threshold that a source contributes to reduced visibility if it impairs 

visibility by 0.5 deciviews. Id. Second, AER’s proposed variance does not impact the Agency’s 

BART demonstration in its Regional Haze SIP submittal. Id. at 31. The Agency relied on SO2

emission reductions required under Part 225 by 2015. Id. at 30-31. AER believes the proposed 
23

variance will provide even greater reductions than submitted by the Agency because AER

proposes to reduce its emissions to 0.38 lb/mmBtu beginning in 2012 as opposed to 0.50 

lb/mmBtu through 2013 and 0.43 lb/mmBtu during 2014. Id. at 31. Accordingly, AER’s 

variance will result in lower SO2 emissions than the Agency’s estimates and does not impact the 

state’s BART demonstration. Id. AER contends that, under the variance, emission reductions by 

AER’s energy centers would be even greater by the BART compliance deadline in 2017 than 

would be achieved under the MPS. AER Post Br. at 36.

AER states it will comply with CSAPR when it becomes effective, which it believes to be 

less stringent than the MPS. Pet. at 31. AER contends determining a CSAPR compliance plan 

requires forecasting since it cannot assume that CSAPR will be upheld in its current form. AER 

Post Br. at 46. However, AER notes, based on the substance of the current form of CSAPR, 

AER’s compliance strategy for CSAPR and the MPS overlap. Id. If the second phase of 

CSAPR goes into effect, AER 

anticipates that it would need to implement additional technology measures such as 

completing the Newton scrubber or installation of a sorbent injection system or modify 

the utilization rates at certain units. Id.

AER also states that it will comply with the federal Mercury and Air Toxics Standards (MATS)

which became effective on April 16, 2012. Pet. at 32.

In AER’s August 23, 2012 post-hearing comment, AER noted that the United States 

Court of Appeals for the D.C. Circuit vacated CSAPR in an August 21, 2012 decision and “sent 

USEPA back to the drawing board to address interstate air pollution under the CAA.” AER Post 

Comment at 1. AER states that a compliance plan for CSAPR is “no longer necessary at this 

time.” Id. at 2; see also E.M.E. Homer City Generation, L.P. v. Environmental Protection 

Agency, et al., No. 11-1302 (D.C. Circuit, Aug. 21, 2012).

Suggested Variance Conditions

In response to Board questions, AER proposes that in addition to being subject to an 

overall SO2 annual emission rate of 0.35 lb/mmBtu from 2013 through 2019, AER agrees to the 

following variance conditions:

1. AER agrees not to operate the Hutsonville and Meredosia Energy Centers 

for power generation purposes during the pendency of the variance, except 

that the FutureGen project which is currently proposed for the Meredosia 

Energy Center site is exempt from this restriction.

2. During the term of the variance, AER agrees to file progress reports with 

the Board and the Agency as to the status of construction activities relating 

to the Newton scrubber annually by the end of each calendar year. 

Furthermore, in the event completion of the FGD system become 

infeasible, AER agrees to advise the Board and the Agency of alternative 

plans for compliance during the remaining term of the variance. 
24

AER First Resp. at 11.

AER contends that the People’s suggested two-year variance term 

does not create a sufficient period of economic certainty and AER would have 

little choice but to begin transitioning into mothballing of its uncontrolled units 

and/or plants. This is due to the regulatory structure of the MPS, the anticipated 

construction timeline required prior to the compliance date, and the high level of 

certainty that power markets will not sufficiently return over the next two years 

such that a capital funding option is available. AER Post Br. at 47.

AER requests a five-year term based upon the regulatory structure of the MPS, the control 

strategy and construction timeline needed to comply, and the economic outlook over the next 

several years. AER Post Br. at 47. AER states the current request for relief is also based upon 

the need to synchronize both the construction and financing of the Newton FGD project. Id. at 

48.

AGENCY RESPONSE

The Agency filed a document titled “Recommendation” stating that the Agency “neither 

supports nor objects to the [Board] granting the Petition subject to the terms and conditions 

contained herein.” Agency Resp. at 1. The Agency informs the Board that it “has engaged in 

conversations” with AER and reached “an understanding regarding SO2 emission rates” that 

would be “acceptable” to the Agency. Id. at 7. Specifically, the Agency and AER have agreed 

to an alternative variance proposal where AER commits to complying with an overall SO2 annual 

emission rate of 0.35 lb/mmBtu from January 1, 2013 through December 31, 2019. Id. at 21. 

The Agency states that this alternative compliance proposal satisfies the Agency. Id. An overall

SO2 annual emission rate of 0.35 lb/mmBtu, together with ceasing operations at the Meredosia 

and Hutsonville stations, “would result in a net environmental benefit through 2021 greater than 

initially proposed” in the petition. Id. 

In its response, the Agency stated it had received two written comments, but no requests 

for hearing. The Agency attached to its response the written comments from Michael Unes, State 

Representative, 91st District, and the Office of the Attorney General. Agency Resp. at 3, 

Agency Resp. Exh. 1 and 2. 

Agency Investigation of Facts in the Petition

The Agency summarizes AER’s variance petition and requested relief. Agency Resp. at 

1-2. The Agency recounts AER’s description of its facilities and installation of pollution control 

equipment. Id. at 2, 4, 6. The Agency states that it “has investigated the facts alleged in 

Petitioner’s Petition for Variance.” Id. at 9. The Agency does not affirmatively state whether 

AER’s presented facts are accurate but neither does it point to any errors by AER.
25

Environmental Impact

The Agency confirms that AER has attached to its petition information as to nearby air 

emission monitoring stations. Agency Resp. at 10. The Agency agrees with AER that the seven 

counties where AER facilities are located are designated attainment for all pollutants. Id. at 2. 

The Agency notes that AER has “voluntarily offered to meet an earlier more stringent 

SO2 emissions rate in mitigation resulting in total SO2 mass emissions lower than the projected 

emissions under the current MPS overall SO2 annual emission rates.” Agency Resp. at 10. The 

Agency notes that AER asserts that “by offering to meet this mitigation rate, the total projected 

SO2 emissions from the [AER] MPS Group will be lower than anticipated under the current MPS 

from 2012 through 2021.” Id. The Agency describes AER’s request as offering to meet an 

overall SO2 annual emission rate of 0.38 lb/mmBtu SO2 from 2012 through 2019 which is more 

stringent than the existing 2012 and 2013 rate of 0.50 lb/mmBtu and the 2014 rate of 0.43 

lb/mmBtu. Id. at 10-11. The Agency notes that AER calculated that the variance would result in 

an overall SO2 reduction of 29,217 tons for years 2010 through 2021 compared to the MPS. Id.

at 11.

The Agency informs the Board that it has discussed with AER an alternative variance 

proposal “that will result in a greater decrease in SO2 emission than contained under the MPS.” 

Agency Resp. at 11. The Agency suggests that AER commit to complying with an overall SO2 

annual emission rate of 0.35 lb/mmBtu from 2013 through 2019. Id. at 11. The Agency informs 

the Board that it has evaluated AER’s SO2 emission calculations and agrees that this alternative 

“will result in a greater net environmental benefit.” Id. at 11. Thus, the Agency and AER agree 

that AER’s compliance with an overall SO2 annual emission rate of 0.35 lb/mmBtu yields an 

overall SO2 reduction of 64,964 tons for years 2010 through 2021 as compared to expected SO2

emissions under the MPS. Id. The Agency concludes “the Illinois EPA does not believe that 

any environmental harm will result if the Board were to grant” a variance requiring compliance 

with an overall SO2 annual emission rate of 0.35 lb/mmBtu from 2013 through 2019 together 

with ceasing operation of the Meredosia and Hutsonville stations. Id. The Agency notes that 

projected SO2 emissions under the MPS are 694,510 tons for years 2010 through 2021 using 

2009 heat input and projected SO2 emissions under the alternative variance proposal are 629,547 

tons for the same years. Id. at fn. 11.

In response to Board questions at hearing about the assertion by the Illinois Attorney 

General’s Office that the MPS was not intended to be a 12-year averaging period of pollution 

reduction (PC#249 at 4), the Agency reiterated statements made in its recommendation, stating, 

“The Illinois EPA acknowledged that the use of emission offsets is a normal part of certain 

regulatory processes.” Agency Post Br. at 2. 

In order to provide support for an SIP revision, the Agency stated, 

[the Agency] has had preliminary discussions with USEPA Region 5 regarding a 

SIP revision for pending variance requests and no adverse issues were identified. 

Agency Post Br. at 2. 
26

The Agency stated it will work with USEPA to determine the appropriate years for heat input 

values to support the SIP revision. Since the Agency’s Regional Haze SIP used a 2002 baseline 

year in accordance with USEPA7

, the Agency noted that the SIP revision will likely use the same 

values. Agency Post Br. at 2-3.

Arbitrary or Unreasonable Hardship

The Agency recounts AER’s hardship arguments that “inadequate cash flow and 

restrictions on additional borrowings” preclude completing the installation of FGD units at the 

Newton station. Agency Resp. at 12-14. The Agency notes that AER claims that if the variance 

is not granted, AER will close multiple units which may include units at E.D. Edwards, Joppa, or 

Newton. Id. at 12. 

The Agency notes that Board rules require the Agency to estimate the cost that 

compliance would impose on AER and on others. Agency Resp. at 12, citing 35 Ill. Adm. Code 

104.216(b)(5). The Agency summarizes an analysis attached to AER’s petition which concludes 

that AER puts $44.4 million into the local economy surrounding the E.D. Edwards station and 

that station has a $124,071,000 impact on the Illinois economy annually. Agency Resp. at 16. 

The report also finds that AER puts $76.7 million into the local economy surrounding the Joppa 

station and that station has a $214,221,000 impact on the Illinois economy annually. Id. 

However, the Agency concludes that it “is not able to estimate the costs that compliance would 

impose on [AER]” because AER did not include itemized calculations or supporting data as to 

cost factors. Id. at 17.

Consistency with Federal Law

The Agency summarizes AER’s assertion that the requested variance is consistent with 

federal law and AER’s supporting arguments relating to compliance with BART, CSAPR, and 

MATS. Agency Resp. at 17-18. The Agency concludes that AER “is correct that there is 

currently no authority that precludes granting the instant variance request.” Id. at 19. However, 

the Agency notes that “Illinois must still develop plans to attain and maintain the ozone and 

PM2.5 National Ambient Air Quality Standards” and, “more importantly, must address its impact 

on downwind states pursuant to Section 110(a)(2)(D) of the [Clean Air Act].” Id.

The Agency notes that USEPA approved revisions to the Illinois SIP addressing regional 

haze. Agency Resp. at 19 citing 77 Fed. Reg. 39943 (July 6, 2012). Accordingly, the Agency 

informs the Board that it will submit the variance order, if granted by the Board, for approval as 

a revision to the Illinois SIP. Agency Resp. at 19. The Agency stated the “[Agency] has had 

preliminary discussions with USEPA Region 5 regarding an SIP revision for pending variance 

requests and no adverse issues were identified.” Agency Post Br. at 2.

 7 USEPA memorandum entitled “2002 Base Year Emission Inventory SIP Planning: 8-hr 

Ozone, PM2.5 and Regional Haze Programs”, November 18, 2002 

(http://www.epa.gov/ttn/chief/eidocs/2002baseinven_102502new.pdf). Agency Post Br. at 2-3.
27

Compliance Plan

The Agency recounts AER’s compliance plan as initially proposed in its petition as 

providing: (1) compliance with an overall SO2 annual emission rate of 0.38 lb/mmBtu from 

2012 through 2019; (2) the proposed rate commits AER to ceasing operations at Meredosia and 

Hutsonville; (3) the proposed rate commits AER to maximizing FGD performance at the Duck 

Creek and Coffeen stations; (4) burning low-sulfur coal from the Powder River Basin and 

managing operations as necessary to maintain compliance. Agency Resp. at 19. The Agency 

notes that AER expects to maintain “a continuous program of construction at the Newton Energy 

Center so as to be in a position to have the Newton FGD [p]roject completed and operational to 

meet compliance obligations.” Id. at 20. The Agency states that after discussions with AER, 

AER has agreed to comply with an even lower overall SO2 annual emission rate of 0.35 

lb/mmBtu from January 1, 2013 through December 31, 2019. 8

 Id.

Suggested Variance Conditions

The Agency stated its recommendation was contingent upon AER’s petition “subject to 

the terms and conditions contained herein.” Agency Resp. at 1. These terms consisted of 

requiring compliance with an overall 0.35 lb/mmBtu annual emission rate from January 1, 2013 

through December 31, 2019 and maintained closures of the Meredosia and Hutsonville electric 

generating units through the pendancy of the variance.

AER also proposed providing progress reports on construction activities related to the 

Newton scrubber by the end of each calendar year during the term of the variance to both the 

Board and the Agency. AER First Resp. at 11. In response to Board questions at hearing (Tr. at 

54), the Agency stated such reports should be sent to the Illinois EPA as follows:

Illinois Environmental Protection Agency

Attn: Ray Pilapil, Manager

Bureau of Air-Compliance Section

1021 N. Grand Ave. East

P.O. Box 19276

Springfield, IL 62794-9276

and

Illinois Environmental Protection Agency

Attn: Gina Roccaforte, Assistant Counsel

Division of Legal Counsel-Air Regulatory Unit

1021 N. Grand Ave. East

P.O. Box 19276

Springfield, IL 62794-9276

 8 Ameren requested the beginning of the variance to commence on January 1, 2015. Pet. at 1. 

Ameren revised the proposed variance term to conclude on January 15, 2020. Ameren Second 

Resp. at 5. 
28

Agency Post Br. at 1.

Agency Response and Agency Conclusion

As discussed above, the Agency informs the Board that it has discussed with AER an 

alternative variance proposal where AER commits to complying with an overall SO2 annual 

emission rate of 0.35 lb/mmBtu from January 1, 2013 through December 31, 2019. Agency 

Resp. at 21. The Agency states that this alternative compliance proposal satisfies the Agency. 

Id. The Agency concludes that an overall SO2 annual emission rate of 0.35 lb/mmBtu, together 

with ceasing operations at the Meredosia and Hutsonville stations, “would result in a net 

environmental benefit through 2021 greater than initially proposed” in the petition. Id. 

There is no regulatory requirement that AER’s Meredosia and Hutsonville stations 

remain shut down so granting this variance would ensure that these two stations remain shut 

down during the term of the variance. Agency Resp. at 21. The Agency points out that using 

emission reductions from facility shutdowns to offset emission increases “is an acceptable part of 

the established regulatory process.” Id. The Agency recognizes such reductions to offset 

potential emission increases under other regulatory programs such as New Source Review and 

Prevention of Significant Deterioration permitting programs. Id. Thus, the Agency concludes 

that “the emission reduction offsets that [AER] is seeking to rely on are creditable and 

allowable.” Id.

The Agency also explains key points as to the background of the MPS. Agency Resp. at 

21-22. The Agency notes that the MPS “was created and designed to achieve significant SO2

and NOx reductions in exchange for mercury control flexibility in the Illinois Mercury Rule.” Id.

at 21. The MPS was negotiated in consideration of AER’s “ability to install pollution control 

equipment in a timely manner and a desire to achieve the greatest amount of reductions within a 

reasonable amount of time.” Id. at 22. The Agency specifically states that “the MPS was not 

designed to address the new 2010 1-hour SO2 National Ambient Air Quality Standard, which 

was not proposed at the time the MPS was being negotiated.” Id. 

The Agency also notes that granting the variance under the alternate proposal agreed 

between the Agency and AER will have “no detrimental impact in the ability to rely on the new 

variance-adjusted MPS emission reductions in the Illinois SIPs, as needed.” Agency Resp. at 22.

The Agency concludes that granting the variance imposing an overall SO2 annual 

emission rate of 0.35 lb/mmBtu from January 1, 2013 through December 31, 2019 results in a 

net environmental benefit. Agency Resp. at 22. Further, the Agency “does not believe that any 

environmental harm would result therefrom.” Id.

OBJECTIONS

On May 31, 2012, the Board received two objections to the petitions, as discussed below. 

Environment Illinois, ELPC, Natural Resources Defense Council, Respiratory Health 

Association of Metropolitan Chicago, and Sierra Club (the Citizens Groups) filed an objection 
29

the AER’s petition which the Board clerk docketed as PC#6. The Citizens Groups, except for

Natural Resources Defense Council, filed an additional objection which the Board clerk 

docketed as PC#7. The Citizens Groups also filed a post-hearing comment on August 13, 2012 

(PC#2409).

The Citizens Groups’ Objection (PC#6 and PC#2409)

The Citizens Groups object to granting AER’s variance petition. PC#6 at 1. The 

Citizens Groups make six points, as follows.

First, the Citizens Groups argue that the variance should be denied because AER should 

be required to comply with the MPS which AER itself negotiated. PC#6 at 2. AER “agreed to, 

opted into, and benefitted from the standards it now seeks to undermine.” Id. The Citizens

Groups characterize the MPS as allowing owners “to meet mercury limits less stringent than 

would otherwise be required as long as they meet certain emission standards and technology 

requirements for SO2 and NOx.” Id. Under the MPS, owners opted into the MPS in exchange 

for “the right to delay compliance with numeric or input-based mercury limits until at least 

2015.” Id. The Citizens Groups contend that the MPS mercury control requirements are less 

stringent than the requirements of the Illinois mercury rule which required electric generating 

units to meet the same mercury standards as the MPS six years earlier than the MPS and without 

the compliance option of injecting activated carbon. Id. at 2-3, fn. 4. Thus, granting the variance 

would give AER the benefit of less stringent mercury standards for several years without 

meeting the prescribed SO2 limits which were part of the “laboriously negotiated” deal. Id. at 3-

4. 

The Citizens Groups next argue that, “AER’s agreement with the State and other parties 

to enter into and abide by the MPS is the functional equivalent of a contract.” The Citizens 

Groups cite court cases regarding contract disputes and state that changing market conditions are 

foreseeable and should not excuse AER from fulfilling its commitment. PC#2409 at 23-24, 

citing to Northern Ill. Gas Co. v. Energy Coop., Inc., 122 Ill. App. 3d 940, 952-53 (3d Dist. 

1984); YPI 180 N. LaSalle Owner, LLC, 403 Ill. App. 3d 1; Bank of America, N.A. v. 

Shelbourne Development Group, LLC, No. 09 C 4963, 2011 U.S. Dist. Lexis 21258 (N.D.Ill. 

Mar. 3, 2011).

Second, the Citizens Groups state that AER only suggested two options, the variance or 

the shuttering of multiple generating stations. In so doing, the Citizens Groups argue that AER

failed to address other strategies or a combination of strategies for complying with the MPS: (1)

curtailing power production at AER’s plants with higher SO2 emission rates, (2) using dry 

sorbent injection, (3) using ultra low-sulfur coal, (4) maximizing/optimizing existing scrubbers, 

(5) maximizing operations and capacity at units with scrubbers, (6) natural gas conversions, and 

(7) seeking financing from its parent company to complete installation of scrubbers at its Newton 

plant.” PC#6 at 4, PC#2409 at 11. The Citizens Groups suggest that a combination of strategies 

would at least bring AER closer to the MPS requirements to further reduce emissions during the 

variance period. PC#2409 at 9-10. The Citizens Groups argue that AER must show that these 

other compliance options are not viable in order to demonstrate a hardship. PC#2409 at 9, citing 

Allaert Rendering, 91 Ill. App. 3d at 162 and Willowbrook Motel P’ship, 135 Ill. App. 3d at 349. 
30

As to curtailing power production, the Citizens Groups assert that AER has not presented 

reasons why it could not vary degrees of curtailment at the unscrubbed units or combine 

curtailment with other strategies. PC#2409 at 10. 

With respect to the use of dry sorbent injection, the Citizens Groups note that AER

dismissed this option because variability in removal rates from 10%-90% reduced its 

effectiveness, injection of the dry sorbent would overburden ESPs and require baghouses on all 

units, and costs would be prohibitive. PC#2409 at 12-16. The Citizens Groups cite to AER’s 

dry sorbent injection pilot testing at Joppa, noting that when operators controlled the injection 

rate to achieve 50% SO2 removal, the actual removal rate ranged from 42% to 67%, not 10% to 

90% as AER suggested. PC#2409 at 12-13, PC#2409 Exh. 2. Additionally, the Citizens Groups 

argue that the Joppa pilot test suggests that dry sorbent injection did not impact the operations of

the ESP or necessitate a baghouse. PC#2409 at 14-15. As to costs, the Citizens Groups refer to 

the comments of Kimberly Gray, PhD, who noted, 

perhaps the biggest advantage of dry sorbent injection is lower cost compared to 

wet FGD with dry sorbent injection averaging 10-25% of the cost of wet FGD. 

PC#2409 at 16, PC#2409 Exh. 3. 

The Citizens Groups contend that dry sorbent injection could be installed and operated at a rate 

that would be short of compliance with the MPS but that would not overburden the existing ESPs 

and still provide significant emission reductions during any variance period. PC#2409 at 10-16. 

The Citizens Groups also suggest that the use of ultra low-sulfur coal and natural gas 

conversion, in combination with other strategies, could also achieve significant progress toward 

compliance with the MPS. PC#2409 at 16 -19. The Citizens Groups point out that AER is 

already using low-sulfur coal in Missouri, in combination with other strategies, to meet federal 

SO2 requirements. As to repowering plants with natural gas, the Citizens Groups believe the 

viability of this option has increased over recent years with the fall in natural gas prices. 

PC#2409 at 17-18. 

In terms of financing, the Citizens Groups question AER’s argument that its parent 

company cannot provide funding for the Newton FGD project. PC#6 at 5. The Citizens Groups 

argue that AER has not met its burden to show that this funding is not possible, contending that 

Ameren Corporation “could in principle finance its subsidiary, but has chosen not to for business 

reasons.” Id., PC#2409 at 35. The Citizens Groups offer that the parent corporation has 

“promised to provide a guaranteed $100 million to AER upon the sale of three natural gas 

plants” which may be a possible funding mechanism. PC#6 at 5. 

Third, the Citizens Groups argue that granting AER’s variance request sets a precedent 

for other owners to seek variances which would undo important gains in controlling mercury, 

SO2, and NOx. PC#6 at 6, PC#2409 at 49-50. The Citizens Groups are concerned because 

AER’s justifications for a variance apply to other owners, reasons such as “financial distress due 

to low power demand, higher natural gas supplies, and inability to recuperate costs via rate 

recovery, as well as supposed regulatory uncertainty.” Id. The Citizens Groups predict that 
31

other companies would seek similar variances if AER’s request is granted. PC#6 at 6. In 

addition, the Citizens Groups contend that the Board should deny the variance so that one 

negotiating party in a large-scale multi-party negotiation “does not thwart opportunities to craft 

stronger, widely-supported regulations in the future.” Id. The Citizens Groups claim that many 

of the negotiating parties at that table will have no reason to participate in negotiating future 

complex regulatory schemes if they can be disregarded in bad times. Id.

Fourth, the Citizens Groups contend that AER has not provided a definite compliance 

plan or shown that it will comply with a proposed compliance plan. PC#6 at 7, PC#2409 at 2. 

The Citizens Groups characterize AER’s petition as “not definite” because it requires that power 

prices must improve before investments in SO2 control equipment will be economically feasible, 

which AER itself acknowledges is uncertain. PC#6 at 8, PC#2409 at 2-3. The Citizens Groups 

point to statements in AER’s supporting documents and testimony that prices may never 

increase, which may mean that AER will never be able to comply with the SO2 requirements. Id. 

The Citizens Groups point to Standard & Poor’s ratings showing future power prices will 

quite possibly remain low, and Moody’s ratings finding an improvement in AER’s cash flow 

linked to a “recovery in power prices, which may not occur.” PC#2409 at 5. Should the factors 

not change in the near future, the Citizens Groups suggest the State will be subjected to “a 

revolving door of variance requests.” Id. at 6. The Citizens Groups assert that the Board should 

only grant a variance for a temporary reprieve from regulatory requirements, “rather than a 

mechanism for indefinitely propping up a failed business model.” PC#6 at 9. Additionally, the 

Citizens Groups state that although AER referenced time frames for ongoing construction 

activities, AER has not provided a time schedule for the most important phases of the FGD 

construction. PC#2409 at 6. The Citizens Groups argue that such a vague time schedule does 

not meet the legal standard of a “detailed compliance plan” under the Board’s petition content 

requirements for variances at 35 Ill. Adm. Code 104.204(f). Id.

Fifth, the Citizens Groups argue that AER’s proposed variance will worsen air quality, 

not create any net air quality benefit, and that AER has not presented an honest appraisal of the 

health and environmental impacts. PC#6 at 9, PC#2409 at 36. 

With AER’s claim of a net benefit, the Citizens Groups object to AER using emission 

reductions from closing the Hutsonville and Meredosia plants to mitigate increased emissions 

from delaying compliance with the 2015 and 2017 SO2 emission standards. PC#6 at 9. The 

Citizens Groups argue that it is improper to consider the Hutsonville and Meredosia closures, 

stating that these closures and resulting emission reductions would occur regardless of whether 

the variance is granted because the plants are uneconomical to operate and the shutdowns are 

necessary for lowering the fleet-wide rate to comply with the MPS and a reinstated CSAPR. Id., 

PC#2409 at 41-46.

The Citizens Groups also question AER’s inclusion of 2010 and 2011 emission 

reductions because they pre-date the variance request. PC#6 at 9, PC#2409 at 41-46. The 

Citizens Groups contend that if the air quality impact is properly evaluated, “it is clear that the 

variance will in fact significantly increase harmful SO2 pollution and thereby worsen air quality.” 

Id. The Citizens Groups present what they term as a “corrected” version of AER’s Table 1, 
32

eliminating the emissions reductions AER credited for the shutdowns of Meredosia and 

Hutsonville and the actual emissions during 2010 and 2011 as well as the heat input associated 

with the two shutdown plants. PC#2409 at 38-40. The Citizens Groups claim their revised 

calculations suggest the variance would allow AER to emit 32,760 more tons of SO2 during the 

period of 2012 to 2020, and not result in a net reduction as AER claims. Id. at 38-41.

As to the public health impacts, the Citizens Groups refer to letters signed by health 

professionals in Illinois who cite to the harmful effects of SO2 emissions and voice concern at the 

efforts to weaken the MPS. The health professionals explain that SO2 is a precursor to fine 

particle pollution in the atmosphere. Particulate matter with a diameter less than 2.5 microns, or 

PM2.5, can be transported over long distances and impact populations miles away from the 

source. The health professionals note the link between exposure to PM2.5 and premature 

mortality and cardiovascular effects, stating, 

failure to lower [AER’s SO2 emissions] on the agreed upon schedule would be 

expected to keep rates of asthma attacks and other health problems higher than 

they would be at the agreed upon, lower levels. PC#2409 at 47-48, PC#2409 Exh. 

5, PC#1174, PC#1919. 

From a 2010 National Research Council study9 (PC#1918) referenced by the health 

professionals, the Citizens Groups estimate a cost for damages per ton of SO2, ranging from 

$4,850 (at Newton) to $6,580 (at E.D. Edwards). PC#2409 at 48. The Citizens Groups 

characterized the damages as “externalities associated with local and global air pollution for 

individual coal-fired and gas-fired power plants in the United States.” Id. Based on the Citizens 

Groups estimates that the variance would result in 32,760 more tons of SO2 than compliance 

with the MPS, the Citizens Groups calculate that the variance would result in damages ranging 

from $159 million to $216 million. Id.

Sixth, the Citizens Groups argue that AER’s hardship is self-imposed, and not arbitrary 

or unreasonable as required by the Act. PC#2409 at 7, referring to 415 ILCS 5/35, 37. The 

Citizens Groups contend that the hardship AER now faces is from AER’s own business decisions 

to opt into the MPS and operate their Illinois generating plants through a deregulated entity. 

PC#2409 at 7. The Citizens groups argue that changes in power prices and market conditions 

were foreseeable when AER opted into the MPS. Although AER stated at hearing that the MPS 

was “premised on the expectation that the power market would continue to support costly 

installation of pollution control equipment over the schedule of the MPS”, the Citizens Groups 

argue that AER was aware that opting into the MPS “did not make compliance with the MPS 

contingent on a robust power market.” Id. at 22-23. The Citizens Groups cite to Board cases 

where variances were denied where the petitioner’s hardship was self-imposed or foreseeable. 

Id. at 19-20, citing Marathon Oil Co v. IEPA, PCB 94-27, slip op. at 10-11 (May 16, 1996); 

Ekco Glaco v IEPA, PCB 87-41 (Dec. 17, 1987); Allaert Rendering, Inc. v. IPCB, 91 Ill. App. 3d 

160, 162 (3d Dist. 1980); Willowbrook Motel P’ship v. IPCB, 135. App. 343, 345 (1st Dist. 

1985); IEPA v. Lindgren Foundry Co., PCB 70-1, slip op. at 8-13 (Sept. 25, 1970). 

 9 National Research Council, “Hidden Costs of Energy: Unpriced Consequences of Energy 

Production and Use” (2010).
33

Where AER argues that hardship is also based on “regulatory uncertainty”, the Citizens 

Groups cite to a Board decision to grant a variance in part based on regulatory uncertainty, but 

only under “unique circumstances” where “unprecedented uncertainty exists.” PC#2409 at 24, 

citing ExxonMobil Oil Corp v. IEPA, PCB 11-86, 12-46, slip op. at 30 (Dec. 1, 2011). The 

Citizens Groups argue that the regulatory uncertainty in AER’s case is not comparable to the 

unique circumstances or unprecedented uncertainty in the ExxonMobil case since “it is and has 

been clear to AER that CSAPR is coming soon . . . .” PC#2409 at 24-25. 

Additionally, the Citizens Groups argue that any hardship AER faces is outweighed by 

the benefits AER gained by opting into the MPS and choosing to enter the deregulated market. 

PC#2409 at 26-29. Although AER testified in the R06-25 hearing that the MPS provision would 

be more costly for AER, the Citizens Groups recall that AER stated that the MPS provides 

important financial and operational benefits by allowing companies to spread capital investment 

costs and construction management over a longer period of time. Id. at 27, referring to Proposed 

New Ill. Admin. Code 225 Control of Emissions from Large Combustion Sources, R06-25 (July 

28, 2006). Because of the benefits of opting into the MPS, the Citizens Groups point out that the 

Agency specified in the R06-25 proceeding that the MPS is a “once-in, always-in” provision, 

otherwise companies could opt-out after receiving the benefits of mercury control flexibility. 

PC#2409 at 28-29. As to the benefits of deregulation, the Citizens Groups refer the testimony of 

ELPC’s Mr. Kelter who said, 

[b]y transferring those plants to unregulated affiliates [AER] was able to reap 

benefits from the plants that it would have never earned under traditional 

regulation, and customers were subject to market prices when the freeze ended. 

For many years, [AER]’s decision paid off for the company. PC#2409 at 33, 

citing Tr. at 71.

Although the Citizens Groups object to granting the variance, the Citizens Groups 

suggest that if the Board were to grant the variance, that the Board only do so subject to strict 

conditions and a shorter variance period. PC#2409 at 2, 51-52. The Citizens Groups recommend 

that before the Board grants any variance to AER, AER should better demonstrate its assessment 

of options, including a combination of control strategies that would result in emission reductions 

below the 0.35 lb/mmBtu proposed. The Citizens Groups note that AER’s testimony regarding 

efforts to meet future CSAPR requirements, such as the use of more low-sulfur coal or additional 

sorbent injection, show that AER can do better. Id. at 9, 11, referring to Tr. at 41-42. The 

Citizens Groups believe AER can “[do] it now, pursuant to a variance or the MPS, instead of 

later under CSAPR.” PC#2409 at 11, 51-52. The Citizens Groups also suggest that any grant of 

a variance require AER to provide a detailed description of the work it will perform and a 

binding schedule for completion. Id. at 51. Finally, the Citizens Group suggest the variance 

period be no longer than two years to allow all the parties an opportunity to reassess AER’s 

prospects for future compliance. Id. at 52.
34

The Citizens Groups’ (Except for NRDC) Objection (PC#7)

The Citizens Groups, except for Natural Resources Defense Council, filed an additional 

objection on the same day as the objection detailed above. This additional objection restates, 

nearly verbatim, the first argument outlined above. Accordingly, it is not again summarized 

here.

ILLINOIS ATTORNEY GENERAL’S POSITION (PC#249 AND PCB#2410)

The Illinois Attorney General, on behalf of the People of the State of Illinois (People),

initially stated

the Board should deny the petition for variance filed by [AER] or, in the 

alternative, grant it only with conditions that would minimize the amount of 

excess pollution allowed in the years 2015 through 2019.” PC#249 at 1. 

The People argue that AER has failed to meet its burden of showing that the hardship of 

compliance outweighs harm to the environmental and public health caused by the variance. Id.

Using AER’s SO2 emission calculations in Table 1 of AER’s petition, the People point 

out that if the variance is granted and AER complies with an overall SO2 annual emission rate of 

0.38 lb/mmBtu, AER will increase SO2 emissions between 2015 and 2019 as compared to the 

MPS. PC#249 at 3. The People accuse AER of “gloss[ing] over this pollution increase by 

framing its alternative compliance plan in terms of the cumulative, or overall, number of tons 

that will be emitted from 2010-2021 as compared to what is anticipated under the MPS.” Id. at 

4.

The People argue that “the MPS was not intended to be a 12-year averaging period of 

pollution reduction.” PC#249 at 4. The MPS “was designed to ratchet down emissions of SO2

and other pollutants over a period of time by triggering incremental clean ups of AER’s coal 

fleet.” Id. The People argue that lower SO2 emissions from 2010 to 2014 result from AER 

“having its coal plants dispatched less and less and also from previous business decisions made 

by [AER] to mothball uneconomic units (Hutsonville and Meredosia).” Id. 

The People assert that “SO2 is not a pollutant that should be subjected to a long-term 

averaging analysis because its primary public health impacts occur relatively quickly after being 

released.” PC#249 at 5. Environmental and health impacts from SO2 emissions include shortterm respiratory exposure, formation of particulate matter, and acid rain deposition. Id. The 

People argue that early reductions in SO2 emissions are of little value because “a ton of SO2

avoided in 2010 does not help an asthmatic . . . exposed to emissions in 2018 or the lake that 

receives acid rain pollution in that later year.” Id. 

The People argue that any alleged hardship in complying with the MPS should be 

analyzed by considering “the alternative measures [AER] would have to take assuming its 

preferred compliance plan (scrubbers at Newton) is unavailable.” PC#249 at 6. The People 
35

believe that AER’s inability to obtain financing for the Newton FGD project due to difficult 

economic conditions is not a hardship. Id. 

The People state that AER’s petition presents only one compliance alternative to the 

Newton FGD project which is closing at least two AER plants. PC#249 at 6. 

The People originally suggested the following compliance options: (1) optimizing 

scrubbers to further reduce emissions; (2) other less expensive control technologies; (3) reduce 

production on certain units; (4) other operational management measures. PC#249 at 7.

Following AER’s hearing testimony, the People continue to believe that the information 

provided by AER

is still not sufficient to determine whether various pollution control strategies, 

either alone or in combination with one another, are available to reach compliance 

or to minimize the gap of non-compliance. PC#2410 at 2. 

Should the Board grant the variance, the People believe that the following conditions 

should be added:

• Setting of a revised SO2 emission rate based on additional measures AER might 

take to limit excess pollution,

• The Hutsonville and Meredosia stations remain non-operational,

• Require the use of dry sorbent injection or other dry scrubbing applications as a 

partial if not full compliance measure,

• Require the partial curtailment or derating of certain units to assist with 

compliance,

• Require AER to operate the Duck Creek and Coffeen scrubbers at 98-99% SO2

removal efficiencies,

• If AER continues to procure low-sulfur coal as an operational step to meet 

emission rates, require AER to procure the lowest-sulfur coal available and to 

submit regular verified certifications, and

• Any other conditions as determined by the Board that would minimize deviation 

from the MPS and provide a more proper balance between the hardship to AER

and the harm to public health and the environment that the variance would allow.

PC#2410 at 8. The People make these condition requests in light of comments presented by 

AER. Id. at 5, 6, 7.
36

The People emphasize that AER’s witness testified only that “‘probably’ anywhere from 

one to three plants could ‘very likely’ need to shut down.” PC#2410 at 2. The People also

request that AER be required to submit the details of its evaluation of dry sorbent injection and 

any other dry scrubbing technologies for Board review. Id. at 5. The People do not believe that 

AER has demonstrated that it has thoroughly analyzed the viability of using dry sorbent injection

and any other dry scrubbing technologies in light of these applications being “cheaper, faster 

ways to reduce SO2 emissions.” Id.

The People believe AER should provide evaluation and analysis on unit curtailments or 

deratings because there could be cost effective pollution reductions through partial curtailment 

“that, when combined with other compliance strategies, would bring [AER] closer to complying 

with the MPS.” PC#2410 at 5.

The People further request that the variance be limited to two years with the ability for 

AER to petition for an extension. PC#2410 at 8. The People believe that a two-year variance 

would provide [AER] with the relief it needs now but provide the added benefit of 

allowing the Board and the [Agency] an opportunity for reassessment if, two 

years from now, AER still believes it needs more time under a variance. Id. at 8-

9.

The People further state a number of factors, including a rise in natural gas prices, 

compliance with CSAPR and MATS, economic improvement, weather patterns, price of coal 

and renewable energy policy could lead to an increase in power prices and an improvement in 

AER’s financial position. PC#2410 at 9-10. However, it is not possible to know for sure how all 

of these dynamics will play out. Id. at 10. The People contend a two-year variance

would allow [AER] to maintain the decelerated status of the Newton scrubber 

project and to hold off on making any decisions about placing plants in cold 

standby. But it would also preserve the chance for the Board to keep the MPS on 

track to the fullest extent possible and to keep excess pollution to a minimum. 

PC#2410 at 9.

HEARING

The Board held the public hearing on August 1, 2012 in Springfield. AER and the 

Agency appeared as participants in the hearing. AER presented sworn testimony from two 

witnesses: Michael Menne and Gary Rygh. The Agency did not present any testimony. As a 

public comment, ELPC presented sworn testimony from Robert Kelter. The Board received two

documents as hearing exhibits: Testimony of Michael L. Menne (Exhibit 1); and Comments of 

Robert Kelter, and Ameren Corporation’s Performance Under the Illinois Electric Service 

Customer Choice and Rate Relief Law of 1997 (Exhibit 2). Ninety-five individuals provided 

public comments.
37

Testimony

Michael Menne, Ameren Services Company

Michael Menne is the Vice President of Environmental Services for Ameren Services 

Company, which provides business and administrative service to Ameren Corporation and its 

subsidiaries, including AER. Mr. Menne worked with the Agency on the development of the 

MPS. Tr. at 12-13, Hearing Exh. 1 at 1.

Mr. Menne began by describing AER’s coal-fired power plants in Illinois: Edwards, 

Duck Creek, Meredosia, Coffeen, Newton, Hutsonville, and Joppa. Mr. Menne also spoke of the 

gas-fired turbines in AER’s fleet. Mr. Menne went on to say, “These plants are an integral part 

of the communities in which they’re located . . . .” Tr. at 14-15. 

Mr. Menne then described AER’s progress in reducing emissions across its fleet, showing 

charts depicting the decline in SO2 emissions of 79% since 1990 and 23% over the last four 

years. Mr. Menne emphasized that AER made these reductions despite a significant increase in 

coal utilization within AER’s fleet over the years. Tr. at 15-16, Hearing Exh. 1 at 1-2. The 

charts show historical SO2 emissions for the MPS units declining from approximately 330,000 

short tons in 1990 to 70,000 in 2011, while coal consumption increased from approximately 10 

million tons in 1990 to 17 million tons in 2011. Hearing Exh. 1 at 11. Mr. Menne explained, 

AER has achieved these reductions through a number of investments in pollution 

control equipment and continuing efforts to improve and maximize efficiencies 

and operating performances. Hearing Exh. 1 at 2.

Mr. Menne recounted how AER has spent over $1 billion on pollution control equipment 

for its fleet. In order to meet the MPS, Mr. Menne stated that AER has already spent over $813 

million to install scrubbers on three of its generating units and $237 million to start construction 

on the fourth (Newton). AER has spent over $177 million to install SCR equipment to reduce 

NOx emission at three of its plants, and incurs costs over $7 million each year in operating costs. 

For mercury control, AER has also spent over $20 million installing ACI technology on twelve

units at four plants, with $17 million in operating costs to date. Tr. at 16-17, Hearing Exh. 1 at 3.

Mr. Menne testified that AER has been voluntarily operating its scrubbers at SO2 removal 

efficiencies higher than necessary to meet the current MPS and federal requirements. 

Additionally, Mr. Menne explained that AER is continuing to test and evaluate methods to 

enhance mercury removal. To date, Mr. Menne believes that most of AER’s generating units are 

very close to meeting MATS regulations and Newton Unit 2 already is already meeting the MPS 

mercury control requirements ahead of schedule. Tr. at 17-18, Hearing Exh. 1 at 3.

Mr. Menne emphasized that in proposing the MPS in R06-25, 

[AER] stepped forward on its own with no pressure from the environmental 

groups – the MPS was not a settlement of an enforcement case or adversary 

proceeding. Hearing Exh. 1 at 4, Tr. at 19. 
38

Mr. Menne explained that AER premised the MPS proposal on an expectation that the power 

market would support the costs to comply with the schedule proposed. Tr. at 19, Hearing Exh. 1 

at 4. However, for the scrubber at Newton, Mr. Menne stated, 

[e]ven though AER knew the [economic] forecast was looking grim, AER 

committed the capital dollars to begin the very costly installation for the scrubbers 

in order to be prepared to meet the very stringent 2015 MPS SO2 rate. Tr. at 18-

19, Hearing Exh. at 3-4. 

As construction of the Newton scrubber proceeded, Mr. Menne stated, “the economic climate 

became more troublesome from a financing perspective.” Tr. at 20, Hearing Exh. 1 at 4-5. Mr. 

Menne also explained that AER made a commitment to continue with the project, but to 

decelerate construction activities. Id. 

Mr. Menne explained that, without the financial resources to complete construction of the 

Newton scrubber on schedule, AER evaluated a number of compliance options. These included

curtailment of operations and installation of less expensive pollution control equipment at other 

plants. Tr. at 20-21. Mr. Menne discussed the option of curtailing operations, acknowledging 

that, while it would reduce emissions, AER would still incur the fixed costs associated with 

operating the plant. Id. at 22. With less power produced and less power sold, Mr. Menne said

that curtailment would not allow AER to recover financially so that funding could be achieved to 

complete the Newton scrubber. Id. at 22-23. Mr. Menne testified that curtailment of operations 

would put AER in “a worse position financially than it would if it had to close down plants.” Id.

at 22; see also Hearing Exh. 1 at 5. 

Mr. Menne stated that AER also considered less expensive technologies for reducing SO2

emissions, including scrubbers and sorbent injection. Tr. at 23. For sorbent injection, Mr. 

Menne stated that AER’s evaluation found efficiencies ranging from 10% to 90%. Hearing Exh. 

1 at 6. Mr. Menne explained that such variability would reduce the effectiveness of sorbent 

injection as a compliance alternative. Id. Additionally, AER found that sorbent injection could 

impair performance of the ESPs, unless AER either built bigger ESPs or installed additional 

controls such as a baghouse to control particulate matter. Tr. at 24, Hearing Exh. 1 at 6. When 

considered from a comprehensive approach, Mr. Menne stated that the total cost of sorbent 

injection would exceed that for completion of the Newton scrubber already underway. Id.

In preparing the variance request, Mr. Menne testified that AER considered steps to 

address any environmental impact that might result. Tr. at 24. AER proposed to comply with a 

“mitigation emission rate” during the variance period of 0.38 lb/mmBtu from 2013 through 

2019, which would reduce SO2 emissions earlier in the variance period than required by the 

MPS. Id., Hearing Exh. 1 at 7. Since filing the petition and meeting with the Agency, AER has 

agreed to an even lower SO2 mitigation emission rate of 0.35 lb/mmBtu beginning in 2013 

through 2019. Tr. at 24-26, Hearing Exh. 1 at 6-7, 9. Mr. Menne explained that, to achieve the 

lower rate, AER will need to fully maximize operation of the FGD systems at the Duck Creek 

and Coffeen Energy Centers to removal efficiencies between 98%-99%. Tr. at 25, Hearing Exh. 

1 at 7. Mr. Menne added that AER does not normally operate scrubbers at such high efficiency 
39

removal levels because it degrades the plant and pollution control systems over time. Tr. at 25-

26. Mr. Menne stated that AER will also need to turn to other operational strategies to comply 

with the mitigation emission rate, such as low-sulfur coal procurement and generation utilization. 

Tr. at 26, Hearing Exh. 1 at 7.

As to AER’s compliance plan during the variance period, Mr. Menne stated that AER is 

committed to spending approximately $16 million each year during the variance for the 

continuing work on the Newton scrubber, with more expenditures in the last couple of years of 

the variance. Mr. Menne explained that during the variance period, AER would be continuing to 

install ductwork, complete engineering, and install absorber units. Mr. Menne stated that AER 

would also provide annual updates on costs and activities. Tr. at 32-33. Mr. Menne stated that at 

this time, AER would not be able to predict a last possible date at which point AER would know 

if completion of the Newton FGD would not be accomplished by the January 15, 2020 

compliance date. Tr. at 37-38.

Additionally, Mr. Menne stated that the only way for AER to meet the 0.35 lb/mmBtu 

mitigation emission rate is to not operate the Meredosia and Hutsonville Energy Centers. Mr. 

Menne relayed that the Agency specifically asked AER to commit to not operating the two 

facilities during the variance period. Mr. Menne stressed, “AER’s commitment to keep these 

plans shut down during the pendency of the variance is a real and meaningful commitment with 

consequences.” Tr. at 26-27, Hearing Exh. 1 at 7-8. 

Mr. Menne stated that both energy centers are fully permitted and could be operated. Tr. 

at 26. Had the CSAPR not issued as final with a 2012 initial year of compliance, Mr. Menne 

stated that these two plants would be operating today. Id. at 27. Mr. Menne stated that it is 

because of the requirements to meet air pollution reductions, including the MPS, that these plants 

were shuttered. Tr. at 27-28, 39-40, Hearing Exh. at 7-8. Although CSAPR was stayed by the 

court in the eleventh hour, Mr. Menne stated, “[b]y that time, it was a little late. Everybody was 

gone and things were closed down.” Tr. at 39-40. 

Mr. Menne noted that the Agency’s recommendation explained that offsets for plant 

shutdowns and other commitments are fully creditable and allowed in the established regulatory 

practice for the New Source Review (NSR) and Prevention of Significant Deterioration (PSD) 

programs. Tr. at 27. Furthermore, Mr. Menne stated that emission credits for plant shutdowns 

are a primary part of the federal goal to reduce all forms of emissions nationally from coal-fired 

power plants. Tr. at 28, Hearing Exh. 1 at 8. Mr. Menne stated that if CSAPR were reinstated, 

AER anticipates the need to take additional measures for SO2 reductions, such as use of more 

low-sulfur, or lower-sulfur, coal, additional sorbent injection, or purchase of SO2 allowances, but 

Mr. Menne cautioned, “we don’t know what CSAPR is going to end up being.” Tr. at 41-43.

In terms of the environmental impact, Mr. Menne explained, 

[t]he net environmental benefit comes from the fact that total SO2 emissions are 

lower with this variance in place than originally expected or anticipated over the 

entire MPS compliance period. Tr. at 28-29, Hearing Exh. at 9. 
40

Finally, if the variance is not granted, Mr. Menne explained that AER will likely have to 

shut down one or two or all of the Joppa, Edwards, and Newton plants by 2015 when the lower 

MPS SO2 emission rate takes effect. Tr. at 21.

Gary Rygh, Barclays Capital

Gary Rygh is managing director in the Global Power and Utility group of Barclays 

Capital, covering the power and energy investment banking business. Tr. at 10-11, 44-45. 

Mr. Rygh described how the financial health of GENCO has eroded due to a number of 

factors, including Illinois’ air emission regulations, the drop in natural gas prices, and AER’s 

status as a merchant power generator. Tr. at 45-46. GENCO is AER’s only rated subsidiary. 

Mr. Rygh explained that, as a merchant generator, AER is exposed to market prices, swings in 

load demand, and volatility of commodity pricing. Id. at 46. Mr. Rygh stated that AER is now 

facing shrinking margins in the face of increasing state requirements to invest in capital for 

pollution control equipment; however, AER no longer has access to capital to complete the 

Newton FGD project on time. Tr. at 46-47. Since credit rating agencies view GENCO’s credit 

quality as poor, Ameren Corporation has little incentive to invest additional capital into AER. 

Id. at 47. If Ameren Corporation were to invest in the unregulated merchant subsidiaries, Mr. 

Rygh stated that Ameren Corporation’s own credit and access to capital would be adversely 

impacted. Id. 

Mr. Rygh responded to a suggestion by the Citizens Groups who cited to an earnings call 

where an AER representative referenced a “Put Option Agreement” as a means to provide 

financing. Tr. at 47-48. Mr. Rygh explained, “[t]he Put Option Agreement is essentially an 

agreement between two unregulated subsidiaries for the sale of assets.” Id. at 48. Mr. Rygh 

stated, “[w]hile the Put Option may temporarily stabilize the subsidiary’s liquidity profile, it does 

not provide capital financing for AEG or for the Newton scrubber project.” Id.

As to the statement made by the Citizens Groups that granting the variance would be 

“propping up a failed business model,” Mr. Rygh disagreed, stating, “[c]oal-fired electricity 

generation remains an integral and necessary part of the nation’s energy portfolio.” Tr. at 48. 

Mr. Rygh believes that, once CSAPR or some similar federal legislation becomes law, AER’s 

peers in other states that are not subject to the MPS will be placed on more equal footing. Id. at 

49. Mr. Rygh predicted that when that happens, market prices for electricity will likely rise and 

eventually AER will have access to capital to complete the Newton FGD project. Id. AER has 

already spent over $237 to start construction, and from an investor’s perspective, GENCO wants 

to complete the project. Id.

Robert Kelter, ELPC

Robert Kelter is a Senior Attorney for ELPC and was previously Director of Litigation at 

the Citizens Utility Board (CUB). Tr. at 67. While working at CUB, Mr. Kelter testified that he 

was involved in negotiating and drafting the Electric Service Customer Choice and Rate Relief 

Law of 1997 (1997 law). Id. Mr. Kelter testified regarding the background on the 1997 law and 

his perspective on AER’s variance petition. Id. at 67-68.
41

Mr. Kelter explained that before the 1997 law was passed, the previous regulatory 

framework meant that utilities recovered the costs of building power plants, and investors earned 

a return on their investment. Tr. at 69. Customers paid for upgrades and repairs and received all 

of the benefits, such as the proceeds from the sale of excess power. Id. Utility shareholders 

would not receive these benefits. Id. Mr. Kelter stated that the 1997 law was intended to allow 

utilities to earn unlimited returns in exchange for removing risks from ratepayers. Id.

Mr. Kelter continued that the 1997 law gave customers rate relief, and in turn, gave the 

utilities flexibility to sell their power plants to independent third parties or spin them off as 

unregulated affiliates. Tr. at 68. Mr. Kelter stated that the AER companies transferred the plants 

to their unregulated affiliates. Id. at 70. Mr. Kelter testified, 

[b]y transferring those plants to unregulated affiliates, [AER] was able to reap 

benefits from the plants that it would never have earned under the traditional 

regulation and customers were subject to market prices when the freeze ended. 

Tr. at 71. 

Mr. Kelter stated that as the freeze came to an end in 2006, CUB performed a study showing that 

AER’s stock outperformed the S&P 500 and other utility stocks. Tr. at 71, Hearing Exh. 2. 

Mr. Kelter agrees with AER’s arguments that other utilities in the region are not 

burdened by the Illinois air pollution regulations and that ratepayers in other states do pay the 

costs for compliance. Tr. at 71. But, Mr. Kelter argues that these risks were foreseeable when 

AER transferred the plants. Id. Mr. Kelter adds that while merchant generators are dependent 

on market prices as AER states, AER’s petition does not show its profits and losses over the last 

decade. Id. at 72. Mr. Kelter concluded, 

[AER] benefitted from the market when environmental regulation was more 

relaxed. It now requests relief from environmental regulations that were within 

the realm of reasonable expectation. Tr. at 73.

Public Comments at Hearing

In addition to hearing testimony, the Board received ninety-five oral public comments 

during the hearing. 

Hearing Comments in Support of Granting the Variance

The Board received sixty-three comments in support of granting the variance petition

during the hearing. See Attachment A – Hearing Commenters in Support of Ameren Energy 

Resources Requested Variance. 

Included among these commenters were Senator Gary Forby, 59th District (Tr. at 56); 

Representative Brandon Phelps, 118th District (Id. at 59); and Representative David Reis, 108th 

District (Id. at 63). The Board also received comments from the Mayors of Newton (Id. at 79), 
42

Joppa (Id. at 102), and Metropolis (Id. at 103). The Board received other public comments 

ranging from representatives of the Illinois AFL-CIO (Id. at 76) and the Jasper County Board 

(Id. at 81) to current employees of AER (See, e.g., id. at 131) and residents of the communities 

surrounding the AER plants (See, e.g., id. at 226). The Board also received comments from 

educators including the Jasper County School Board (Id. at 106), Shawnee Community College 

(Id. at 111) and Joppa-Maple Grove School District Unit 38 (Id. at 113); as well as comments 

from business groups including the Economic Development Council for central Illinois (Id. at 

189) and West Central Building Trades (Id. at 122).

In general, the commenters acknowledged the environmental impact currently facing the 

Board. See, e.g. Tr. at 61, 78, 103. However, commenters also focused on the financial impact 

currently faced by AER (see, e.g., id. at 60), and the impact to AER’s employees and 

surrounding areas that would result from the shutdown of plants if the variance is not granted. 

See, e.g., id. at 58 (asking the Board to help “Joppa and the people in southern Illinois to keep 

their jobs”), 62 (noting “the devastating impact economically that [denying AER’s request] 

would have on [Massac County]”), 64 (emphasizing “the serious economic impact of shutting 

down the largest private employer in Jasper County”). Commenters also noted how the “AER 

family of companies . . . pay taxes critical supporting the schools, emergency response systems 

and city governments in dozens of communities across the state.” Id. at 78, see also id. at 102. 

Jasper County Board Member Bill Weber noted that the Newton facility “represents a little over 

51 percent of the total tax revenue for the county” and foresaw “bankruptcy for our county” if 

the Newton plant were to shut down. Id. at 82.

AER employees emphasized their concern for AER’s environmental impact, noting that 

this was a focus for them in their jobs. See, e.g., Tr. at 136, 165, 175, 198, 257. Employees also 

noted the pollution controls that AER has already installed to reach environmental compliance. 

Id. at 212, 233. Bill Miller, an employee at the E.D. Edwards station, noted the “traumatic 

experience” of going through the closing of the Meredosia station and stated that “it’s not 

something that I look forward to going through again.” Id. at 142. Mike Woo, also employed at 

the Edwards Station, emphasized the 

progress I have seen in 40 years and the commitment of three companies to be a 

good steward of the environment and produce electricity needed for economic 

growth in Peoria County and the surrounding tri-county area. Tr. at 154-155.

AER employee Dan Barnett also agreed with AER’s position that granting the variance 

“will lead to a greater overall reduction in SO2 over the life of the agreement.” Tr. at 171, see 

also id. at 206-207. Mike Killebrew, employed at the Edwards station, stated that AER “is the 

most honest company I’ve ever worked for” and that he does not feel AER is misleading its 

employees regarding AER’s variance request. Id. at 174. Commenters also echoed AER’s 

concerns regarding the current economic state of the country and Ameren’s attempts to recover 

from the recession (Id. at 178), as well as the inability to forecast the current energy market. Id.

at 193. Lastly, AER employees raised concerns over losing the source of their income if any of 

the AER stations are to shut down. Id. at 202. 
43

Hearing Comments Opposing Granting the Variance

At hearing, the Board received thirty-two public comments objecting to granting the 

variance petition. See Attachment B – Hearing Commenters Opposing Ameren Energy 

Resources Requested Variance.

A number of environmental groups presented comments at the hearing, including the 

Peoria Families Against Toxic Waste (Tr. at 126), Sierra Club (Id. at 132), ELPC (Id. at 115, 

137, 142, 150), Green Peace in Illinois (Id. at 162), Prairie Rivers Network (Id. at 186), and the 

Heart of Illinois Sierra Club (253). The Board received a comment on behalf of Faith in Place, a 

partnership of 900 religious congregations in Illinois (Id. at 185). The Board also heard 

statements from health professionals and representatives of health groups, including RHA (Id. at 

97), and Dr. Samuel Dorevitch of the University of Illinois in Chicago School of Public Health 

(Id. at 150).

James Gignac, Illinois Attorney General’s Office. James Gignac, an Assistant 

Attorney General, appeared on behalf of the People. Tr. at 84. Mr. Gignac urged the Board to 

ensure that [AER] has taken all the steps that it should to minimize the deviation 

from the [MPS] before [the Board] grants any sort of variance. Id. at 84-85.

Mr. Gignac noted the “heavy burden” on AER to demonstrate that the hardship AER would 

endure by complying with the MPS outweighs the harm to the environment and public health. 

Id. at 86. Mr. Gignac stated the People’s initial concern as “a lack of explanation or 

documentation . . . regarding alternative compliance options.” Id. at 87. Mr. Gignac urged the 

Board to require a “complete analysis from [AER] on the costs and feasibility” of compliance 

alternatives. Id. at 88. Mr. Gignac requested that the Board grant a two year variance because 

granting the full variance now 

would lose that opportunity to see an updated justification for the variance, and 

we would lose the opportunity to revisit the issue and keep the MPS on track to 

the greatest extent possible. Tr. at 92.

Mr. Gignac believes that a two year variance would allow the company to change its compliance 

strategy and approach based on any changes in cash flow conditions. Id. at 91.

The Citizens Groups Objections. The Citizens Groups were represented at hearing by 

members of ELPC (Tr. at 115, 137, 142, 149), Sierra Club (Id. at 132, 233, 253), and RHA (Id.

at 97). 

Brian Urbaszewski, the director of environmental health programs at RHA, stated his 

concerns regarding lung disease such as asthma and chronic obstructive pulmonary disease, (Id.

at 98), and the effects that air pollution from coal power plants have on these and other diseases. 

Id. at 99. Mr. Urbaszewski acknowledges that the 2006 Illinois rule “was stricter than federal 

requirements in place,” but notes that since 2006, national air quality standards have required 

deeper reductions, such as in SO2, and will continue to be tightened. Id. at 100.
44

Faith Bugel, appearing on behalf of ELPC, emphasized that granting the variance does 

not guarantee that the Joppa and E.D. Edwards plants, “old plants that do not have modern 

pollution controls,” will not be shut down. Tr. at 116-117. Ms. Bugel notes the layoffs that have 

already occurred at the Joppa station as “telling” in this regard. Id. at 117. Ms. Bugel also 

believes that denial of the variance request does not guarantee that these plants would be shut 

down, noting AER’s compliance alternatives such as conversion to natural gas, use of ultra lowsulfur coal, optimizing capacity at certain plants, and the use of dry sorbent injection. Id. at 118-

121. Jared Policicchio, also appearing on behalf of ELPC, emphasized statements made relating 

to the 2006 MPS, by then Agency Director Doug Scott testifying in front of the U.S. Congress in 

2009, as well as statements made during the 2006 rulemaking before the Board by AER experts 

testifying on AER’s behalf. Id. at 137-141. Jennifer Cassel read into the record a letter signed 

by eighty-five health professionals opposing AER’s variance request. Id. at 142-146, see also

PC#2648. Lastly, Andrew Armstrong read into the record a comment on behalf of Dr. 

Dorevitch, also opposing the variance request. Id. at 150-153, see also PC#1919.

Terry Grace, representing Sierra Club, states his problem as not being the prospect of 

cleaner energy, but rather with “management decisions that jeopardize everyone’s health, longterm prosperity, and possibly the welfare of [AER]’s workers.” Tr. at 133. Mr. Grace further 

questions AER’s long-term planning responsibility and states that AER “should not be rewarded 

for irresponsible decisions by their management.” Id. at 133-134. Christine Nannicelli, also 

with Sierra Club, noted that AER’s “agreement to reduce air pollution is vital in protecting 

public health and the environment throughout Illinois and the Midwest.” Id. at 234.

Joyce Blumenshine, chair of the Heart of Illinois Sierra Club, stated that she is concerned 

about possible nonattainment in Peoria from additional pollution from the E.D. Edwards and 

Duck Creek stations. Tr. at 254. Ms. Blumenshine contends that the greater Peoria economy 

“would suffer incredibly due to added sulfur and pollution” if the area was forced out of 

attainment, and urged the Board to look at the “greater picture for what other communities have 

at risk.” Id. Ms. Blumenshine believes that AER’s economic statements to be “inadequate and 

self-serving” and raised a concern over AER’s lack of attention given to the health impacts of the 

variance request. Id. at 254-255. Ms. Blumenshine concluded by noting the health concerns 

relating to short-term exposure to SO2 and requested that the Board carefully evaluate this 

position. Id. at 255.

Other Organizations and Individuals. The Board received comments at hearing 

opposing granting AER’s variance request from a number of other organizations and individuals.

These comments emphasized AER’s 2006 MPS agreement and urged the Board to not 

allow AER to alleviate itself of these requirements. See, e.g., Tr. at 156, 169, 171, 191. Edward 

Warden noted that granting the variance “is not fair to . . . other companies who also agreed to 

this time allotted” or “to the people who have to breathe the air that will continue to be as dirty as 

it has been.” Id. at 156-157. Many commenters were also aware of the financial and economic 

implications that AER, and specifically AER’s employees, were facing. Id. at 129, 177, 196. 
45

However, commenters also focused on the health effects of increased levels of SO2, 

contending that granting the variance would result in increased negative health effects 

throughout Illinois. See, e.g., id. at 183, 199, 206. Judy Weimer, a bilateral lung transplant 

recipient, noted that “we need to keep the air clean, if not for my generation, for our children and 

grandchildren.” Id. at 93. Norman Eckstein recalled a friend who lost both parents to lung 

cancer, and while no specific reason was determined, Mr. Eckstein states that the belief is “that 

it’s mostly environmental.” Id. at 94. Brian Sauder, appearing on behalf of Faith in Place, asked 

the Board to deny the variance “for the future health of our generations here in Illinois.” Id. at 

186. Allison Fisher, speaking on behalf of Mary Ellen DeClue, raised a concern that AER “does 

not accept the harm to health and to the environment” caused by coal emissions. Id. at 221.

Commenters also raised concerns about the precedent that would be set regarding other 

companies subject to similar standards if the Board grants AER’s variance request. See, e.g., Tr. 

at 166. Melissa Marks noted that AER was “misleading” its employees “for an industry that’s 

soon to be obsolete.” Id. at 173. Marissa Lieberman-Klein stated that it “is not the job of this 

Board to protect the company’s bottom line.” Id. at 196.

Tracy Cox, appearing on behalf of Peoria Families against Toxic Waste, contends

there have been enough indicators and enough time and enough money that there 

is no reason to grant a variance to [AER] in this matter. Tr. at 126.

Ms. Cox also emphasizes that the environmental protections that AER is being asked to do and 

the disparity with other states “have been in effect for six years.” Id. at 127. Ms. Cox does not 

believe that there is anything new that meets the burden of a unique hardship. Id. Ms. Cox also 

questioned where various sums of money that AER had saved on previously performed costcutting measures had gone. Id. at 128-129.

Edyta Sitko, appearing on behalf of Green Peace Illinois, questioned whether AER would 

simply return in five years requesting another variance. Tr. at 162. Ms. Sitko also raised 

concern that, if AER is granted the variance, “what’s to stop other coal plants in Illinois from 

getting the same thing.” Id. at 164.

Katie Mimnaugh, appearing on behalf of Prairie Rivers Network, noted that AER has not 

demonstrated that installing dry scrubbers is technically infeasible or economically unreasonable. 

Tr. at 187. Ms. Mimnaugh also states that AER has not offered Illinois any environmental 

benefits, and that AER should have been able to anticipate its current position. Id. at 187-188. 

Ms. Mimnaugh echoed previous concerns regarding the precedential value of granting the 

variance, and emphasized that the Board is unable to grant a site-specific law that is inconsistent 

with federal law. Id. at 188-189.
46

FILED PUBLIC COMMENTS

Comments Filed on or before August 10, 2012

In addition to the ninety-five oral public comments during the hearing, the Board 

received 2,886 written public comments prior to the deadline for such comments on August 10, 

2012.10 These public comments have been made available on the Board’s website.

Public Comments in Support of AER’s Variance Request

The Board received 1,864 written public comments in support of granting AER’s 

variance request. These include comments filed by: State Representative David B. Ruis, 108th 

District (PC#2); State Representative Michael Unes, 91st District (PC#3); State Senator Dale A. 

Righter, 55th District (PC#4); and State Representative Brandon W. Phelps, 118th District 

(PC#8). 

The Board received public comments from the Mayors of Newton (PC#1 and PC#146), 

Peoria (PC#139 and PC#150), Metropolis (PC#147), Joppa (PC#310), Effingham (PC#318), East 

Peoria (PC#319), Morton (PC#326) and Palestine (PC#1137). Additionally, the Board received 

public comments in support of granting AER’s variance request from a number of other public 

offices, e.g., the Jasper County Board (PC#5), the Massac County Board of Commissioners 

(PC#313) and the Board of the Village of Palestine (PC#1139).

The Board also received comments in support from organizations (see, e.g., PC#133 from 

Illinois AFL-CIO), businesses (see, e.g., PC#148 from the Outdoor Sportsman’s Lodge), and 

individuals (see, e.g., PC#814), including plant employees (see, e.g., PC#2195).

Commenters generally voiced concerns relating to property taxes received by the AER 

plants (see, e.g., PC#1) and the loss of jobs that would result from closing any of the plants. See, 

e.g., PC#2. Commenters emphasized the difficulty that the current laws place on Illinois 

companies trying to compete with out-of-state energy producers, noting that prices will increase. 

PC#9. Commenters also noted the unpredictable economic climate surrounding AER resulting 

from

a warmer than normal winter, a nationwide economic down turn lasting more than 

four years, a large amount of natural gas availability, due to shale fracturing, 

driving down the price of natural gas, all of which has kept the price [AER] can 

sell [its] power for at an all time low. One or two of these factors may have been 

foreseeable but not all of them coming together at one time. PC#2195 at 2.

The Board also received a number of letters in support of the variance noting that AER 

“simply needs more time to make the costly upgrades” and urging the Board to grant AER’s 

 10 The Board notes that three public comments (PC#1232, PC#2713 and PC#2729) have been 

erroneously included. Additionally, PC#10 and PC#1920 do not support or object granting 

AER’s variance request.
47

variance request so that AER will not have “to jeopardize jobs and livelihoods of Illinois 

residents.” See, e.g., PC#980.

Public Comments Opposing AER’s Variance Request

The Board received 1,017 written public comments opposing granting AER’s variance 

request. These include comments filed by the People (PC#249 and PC#2410) and the Citizens 

Groups (PC#6 and PC#2409). The Board also received comments from environmental groups 

(see, e.g., PC#2194 from Prairie Rivers Network, and PC#2412 from Peoria Families against 

Toxic Waste), medical professionals (see, e.g., PC#1919 and PC#2648), and other concerned 

individuals (see, e.g., PC#11).

The Board received a public comment signed by eighty-five health professionals, 

expressing their support for the MPS and urging the Board “to vote against any action eroding 

MPS standards.” PC#2648 at 1. The health professionals noted the health impacts of SO2, but 

also noted that SO2 and NOx are “precursors to other harmful pollutants such as fine particulate 

matter and ground-level ozone.” Id., see also PC#1919.

Commenters generally noted AER’s previous commitment “to a schedule for reducing its 

SO2 and NOx pollution in return for more time to make its mercury pollution reductions,” 

requesting that the Board hold AER “to the standard passed in 2006.” PC#11. Other 

commenters contend that people in Illinois 

should not now have to suffer from years of extra pollution so that [AER] can 

continue to run old, dirty coal plants without modern pollution controls. PC#151.

Commenters also emphasized that all of the market factors contributing to AER’s 

hardship were foreseeable, and that AER cannot contend that it faces a hardship when it 

expressly agreed with the MPS terms six years ago. PC#2412 at 1.

Comments Filed After August 10, 2012

The Board received 119 public comments following the public comment filing deadline, 

which have been made available on the Board’s website. These included ninety-six comments in 

support of AER’s variance request, and twenty-three comments opposing the request. The Board 

recognizes that public comments 2,995 through 3,005 consist of 2,372 individual letters 

opposing AER’s variance request.

Included in the post-deadline public comments was a one-page letter in support of AER’s 

variance request signed by U.S. Representatives Jerry Costello, John Shimkus and Aaron 

Schock. PC#2643. The Representatives emphasize the “significant hardships” that the MPS 

regulations place on AER’s ability to operate its facilities in Illinois. Id. The Representatives 

urge the Board to approve the variance petition “[g]iven the potential impact to good-paying jobs 

and affordable energy for our constituents.” Id. The Representatives believe that AER “is acting 

in good faith to meet its environmental obligations under the economic circumstances it faces.” 

Id.
48

DISCUSSION

The Act authorizes the Board to grant variances “beyond the limitations prescribed in this 

Act, whenever it is found, upon presentation of adequate proof, that compliance with any rule or 

regulation . . . would impose an arbitrary or unreasonable hardship.” 415 ILCS 5/35(a). AER

seeks relief from the requirements in Sections 225.233(e)(3)(C)(iii) and (iv) to comply with an 

overall SO2 annual emission rate limit of 0.25 lb/mmBtu in 2015 and 2016 and 0.23 lb/mmBtu in 

2017 and thereafter. Pet. at 1. AER requests a variance for five years beginning January 1, 2015 

and ending December 31, 2019 from Section 225.233(e)(3)(C)(iii) for the overall SO2 annual 

emission rate limit of 0.25 lb/mmBtu and a variance for three years and fifteen days beginning 

January 1, 2017 and ending January 15, 2020 from Section 233.255(e)(3)(C)(iv) for the overall 

SO2 annual emission rate limit of 0.23 lb/mmBtu. Pet. at 1; AER First Response at 1.

To obtain a variance, AER must establish that the hardship from denying the variance 

from Sections 225.233(e)(3)(C)(iii) and (iv) “outweighs any injury to the public or the 

environment” from granting the variance. Marathon Oil Co. v. EPA, 242 Ill. App. 3d 200, 206, 

610 N.E.2d 789, 793 (5th Dist. 1993). If AER only shows that compliance will be difficult, “that 

proof alone is an insufficient basis” for granting the variance. Id. Thus, “only if the hardship 

outweighs the injury does the evidence rise to the level of an arbitrary or unreasonable hardship.” 

Id. 

The Board has received a number of public comments raising concern over AER’s 

perceived contract to enter into the MPS. See e.g., PC#2409 at 23-24 (The Citizens Group’s 

state that “AER’s agreement with the State and other parties to enter into and abide by the MPS 

is the functional equivalent of a contract.”). This Board has long held that it does not have the 

authority to enforce contractual agreements, and such disputes are more appropriately brought in 

a court of law. See, e.g., Schilling, et al. v. Hill, et al., PCB 10-100 slip op. at 8-9 (Aug. 4, 

2011). However, Section 104.200(a)(1) of the Board’s regulations defines a variance, in part, as 

“a temporary exemption from any specified rule, regulation, requirement or order of the Board, 

which may be granted by the Board with or without conditions for a period of time not to exceed 

five years. . . .” 35 Ill. Adm. Code 104.200(a)(1); see also 415 ILCS 5/35 (2010). The MPS is a 

Board rule. 35 Ill. Adm. Code 225.233. Therefore, the Board must look at the specific portions 

of the MPS from which AER seeks relief and determine whether AER has met its burden so that 

the request may be granted.

Accordingly, the Board will analyze the injury to the public and the environment from 

granting the requested variance, the hardship to AER from compliance with the rule, and weigh 

the hardship against the injury to determine whether AER has demonstrated that it would suffer 

an arbitrary or unreasonable hardship if the variance is not granted.

As discussed below, the Board finds that AER has adequately addressed its alternatives 

for complying with the current MPS requirements; that AER has demonstrated that the 

requested variance will result in a net benefit to the environment; that AER would suffer an 

arbitrary or unreasonable hardship if forced to comply with the deadlines in Sections 

225.233(e)(3)(C)(iii) and (iv); that granting AER’s petition for variance with conditions in the 
49

order below would be within the State’s current obligation under the Illinois SIP to attain and 

maintain compliance with the National Ambient Air Quality Standards (NAAQS); and that 

granting AER a variance from the rule is consistent with federal law.

Compliance Alternatives

The Citizens Groups and the People state that AER only suggested two compliance 

alternatives, the variance or the shuttering of multiple generating stations. In so doing, the 

Citizens Groups and the People argue that AER failed to address other strategies or a 

combination of strategies for complying with the MPS. PC#2409 at 9-11, PC#2410 at 2. The 

Citizens Groups and the People suggest AER more thoroughly analyze a combination of 

strategies to bring AER closer to compliance with the MPS during the term of the variance, 

including: (1) curtailing power production or derating, (2) using dry sorbent injection, (3) using 

ultra low-sulfur coal, (4) maximizing/optimizing existing scrubbers, and (5) maximizing 

operations and capacity at units with scrubbers. PC#249 at 7, PC#2409 at 11, PC#2410 at 2, 5. 

Additionally, the People also suggest use of dry scrubbers. PC#2410 at 3-5. The Citizens 

Groups also suggest AER more fully address natural gas conversions and seeking financing from 

its parent company to complete the Newton FGD project. PC# 6 at 4, PC#2409 at 11. 

The Board does not agree with the conclusions of the Citizens Groups and the People. 

The Board finds that AER adequately detailed the range of compliance alternatives that AER 

examined in support of its petition. Nothing in this record contradicts AER’s assessment of the 

compliance alternatives set forth below. The Board notes that the Agency response has not 

argued for availability of other compliance technologies, but rather has supported a 0.35 

lb/mmBtu emission rate for AER’s compliance plan. Agency Resp. at 11.

As to the first suggestion to curtail generation, AER acknowledged that this would reduce 

emissions, however, the fixed operating costs would remain essentially the same while less 

revenue would be generated to pay those costs. AER concluded that curtailing generation would 

put jobs at risk, result in a negative cash flow, and not allow AER to recover financially in order 

to fund the Newton FGD project. AER First Resp. at 2; AER Second Resp. at 2-3; Tr. at 22-23. 

Regarding the second alternative of using dry sorbent injection, AER identified two main 

drawbacks: wide-ranging removal efficiencies from 10% to 90% and increased mass loading to 

the ESPs. AER Second Resp. at 2. AER explains that the variability in removal efficiencies 

reduces the effectiveness of dry sorbent injection as a compliance alternative. AER also 

explained that the increased mass loading from the dry sorbent injection to the ESPs would 

potentially trigger the need for bigger ESPs or additional controls, such as baghouses, to control 

particulate matter. AER projected that use of dry sorbent injection to comply with the MPS 

would require installation of dry sorbent injection equipment plus baghouses at virtually all of 

AER’s uncontrolled units across its system. AER Second Resp. at 2, Tr. at 20-24, Hearing Exh. 

1. AER estimated the cost of installing dry sorbent injection plus fabric filters at Joppa and 

Edwards at $433 million and $280 million, respectively, and noted that this would exceed the 

cost to complete the Newton FGD project. AER Post Br. at 15, 23. 
50

As to the third alternative of using ultra low-sulfur coal, AER explains that the Coffeen 

and Duck Creek stations already have wet FGD systems which allow them to burn higher-sulfur 

Illinois Basin coal, while the Newton, Joppa, and Edwards stations use lower-sulfur coal as a 

compliance mechanism. In support of its variance request, AER commits to limit use of the 

higher SO2 content Illinois Basin and Power River Basin coal to just the Duck Creek and 

Coffeen stations, and use ultra low-sulfur coal at the Edwards, Newton, and Joppa stations in 

order to comply with a SO2 emission rate of 0.35 lb/mmBtu. AER First Resp. at fn. 2, AER Post 

Br. at 25.

As to the fourth and fifth alternatives of maximizing and optimizing existing scrubbers 

and operations, AER commits in its filings to support the variance to fully maximize operation of 

the existing FGD systems at the Duck Creek and Coffeen stations at a 98-99% SO2 removal rate 

rather than 95%. AER Second Resp. at 2. AER notes that the scrubbers are not normally 

operated at such high efficiency removal levels because it degrades the plant and pollution 

control systems over time. Tr. at 25-26. AER’s estimates its commitment will require $5 

million in capital costs and $173,337 in annual operation and management costs. AER First 

Resp. at 8. 

As to the People’s suggestion to use dry scrubbers, AER explained that a dry scrubber 

would require construction of a multi-storied building and spray tower. With removal 

efficiencies in the low 90% range, AER estimated six dry scrubbers would be needed at Joppa to 

achieve the reductions approaching those projected for the wet FGD project at Newton. AER

estimated costs for the dry scrubbers at $460 million, nearly twice the cost of completing the 

FGD project at Newton. AER Post Br. at 18. Further, AER notes that installation of dry 

scrubbers “may be ineffective in addressing hazardous gas emissions and, without additional 

add-on controls, could adversely affect impact particulate emissions.” Id.

Regarding the alternative of natural gas conversions, AER considered the feasibility of 

conversions at the Edwards and Joppa stations. AER found that under the current market 

conditions, a natural gas conversion at Joppa would reduce operations to a seasonal basis only 

and lead to reduced revenue and a loss of jobs. AER Post. Br. at 23-24. 

Concerning the issue of seeking financing from the parent company, AER explained that 

as a merchant business, AER must be self-funding and support its expenses through its own 

operating revenues, however, AER’s earnings and cash flows “are insufficient to fund large-scale 

capital projects such as the installation of the scrubbers [at Newton].” Pet. at 22, Pet. Exh. 5 at 3. 

Since AER is not a publicly-registered company, it has no direct access to public financial 

markets. AER First Resp. at 4. 

Additionally, without a secure revenue stream, AER states that its parent company, 

Ameren Corporation, cannot assume unsecured debt on AER’s behalf. Pet. at 22. According to 

AER, the 

credit rating agencies . . . have . . . made it abundantly clear that further support 

from the parent [Ameren Corporation] will have negative consequences on the 
51

credit quality of [Ameren Corporation] and its other subsidiaries. Pet. Exh. 5 at 

10. 

Instead, AER has committed $16 million per year from 2013 to 2016 with greatly increased 

capital expenditures in 2018 and 2019 to complete the Newton FGD project, funds which AER 

states are within its budget. AER will also spend $5 million in capital and $173,337 in annual 

expenses to fully maximize the existing FGD systems at Duck Creek and Coffeen. Pet. at 19; 

AER First Resp. at 6-8, Tr. at 32, AER Post Br. at 38, 40.

AER explains that AER has considered all viable alternatives and determined that the 

installation of two scrubbers at Newton “would reduce emissions by approximately 17,500 tons 

of SO2,” which would result in lower emissions than the 16,000 tons SO2 AER would need to 

reduce to comply with the 2017 MPS emission rate. AER Post Br. at 15-16. Until the Newton 

FGD project is complete, AER will meet the interim compliance emission rates by not operating 

the Hutsonville and Meredosia stations preceding and during the variance term. AER will also 

maximize efficiency of the FGD systems at the Duck Creek and Coffeen stations. AER First 

Resp. at 1-2. AER has also committed to purchasing low-sulfur coal for use at Edwards, 

Newton, and Joppa.

 The Board observes that, in addition to the compliance alternatives AER suggested in its 

petition, AER also examined each of the options suggested by the Citizens Groups and the 

People. AER Post Br. at 15-25. AER found the other options suggested not viable either 

because they would not achieve compliance with the MPS, they would create co-pollutant 

emissions requiring costly additional controls, or they would worsen AER’s financial situation. 

The Board observes that AER’s proposal to complete the Newton FGD project would realize 

emission reductions greater than those required by the 2017 MPS requirements. 

The Board finds that AER has adequately addressed its alternatives for complying with 

the current MPS requirements. Based on the analyses of compliance alternatives by AER, the 

Citizens Groups, and the People, the Board agrees that AER’s chosen alternative to proceed with 

completion of the Newton FGD project, as well as maintain closures of the Hutsonville and 

Meredosia stations and comply with the proposed interim compliance emission rates during the 

variance period is appropriate.

Environmental Impact of Requested Variance

Environmental Net Benefit

AER states that it 

has voluntarily offered to meet an earlier more stringent SO2 emissions rate in 

mitigation resulting in total SO2 mass emissions lower than the projected 

emissions under the current MPS [overall] SO2 annual emission rates, and 

providing a net environmental benefit to the State. Pet. at 26. 
52

The Citizens Groups argue that AER’s proposed variance will worsen air quality and not 

create any net air quality benefit. PC#6 at 9, PC#2409 at 36. The Citizens Groups present what 

they call a “corrected” version of AER’s Table 1, eliminating the emissions reductions AER 

credited for the shutdowns of Meredosia and Hutsonville and the actual emissions during 2010 

and 2011 as well as the heat input associated with the two shutdown plants. PC#2409 at 38-40. 

The Citizens Groups claim their revised calculations suggest the variance would allow AER to 

emit 32,760 more tons of SO2 during the period of 2012 to 2020, and not result in a net reduction 

as AER claims. Id. at 38-41.

In response to the Citizens Groups’ concerns and Board questions regarding calculations 

in AER’s tables, AER responded by providing a new table (Exhibit 4) comparing reductions in 

SO2 emissions under the MPS and the requested variance. To aid in a better review and 

understanding of the information, AER included two columns of additional data and explanatory 

notes. AER Post Br. at 38-39, Exh. 4. Unlike the Citizens Groups’ version of the data, AER 

includes the heat input associated with Meredosia and Hutsonville as well as “SO2 Reduced 

Tons” for not operating these facilities. AER also recognizes the possible increase in emissions 

from the proposed FutureGen Project by conservatively factoring in two times the projected SO2

emissions. This results in “SO2 reduced tons” of 7,699 for years 2012 through 2020. Comparing 

years 2010 through 2020, AER calculated the “Cumulative Reductions in SO2 Variance Tons” 

would reflect a net benefit of 60,669 tons. AER Post Br. 38-40, AER Post Br. Exh. 4.

The Agency has “investigated the facts alleged in Petitioner’s Petition for Variance” as 

required by 35 Ill. Adm. Code 104.216(a). Agency Resp. at 9. The Agency does not disagree 

with AER’s emission calculations, either in the Agency’s response to the initial petition or in any 

response to AER’s later filed Tables 2, 3, 4, or Exhibit 4. The Agency agrees with AER’s 

approach which includes the heat input and reductions associated with Meredosia and 

Hutsonville, explaining, “providing credit for actions (e.g., unit shutdowns) that result in 

emission reductions is an acceptable part of the established regulatory process.” Agency Resp. at 

11, 21. The Agency goes on to explain, 

the Illinois EPA is accustomed to recognizing and allowing such reductions to 

offset potential emission increases under the New Source Review and Prevention 

of Significant Deterioration permitting regulations. Agency Resp. at 21. 

The Agency agrees that AER’s compliance with an emission rate of 0.35 lb/mmBtu from 

January 1, 2013 through December 31, 2019, in conjunction with not operating the Meredosia 

and Hutsonville stations, “would result in a net environmental benefit.” Id. at 21, 22. Further, 

the Agency “does not believe that any environmental harm would result therefrom.” Id. at 22.

The Agency also discusses the variance request within the context of the State’s 

obligations under the Illinois SIP. As discussed above, on July 6, 2012, USEPA approved the 

revisions to the Illinois SIP addressing regional haze. 77 Fed. Reg. 39943 (July 6, 2012). If the 

Board grants the instant variance, the Agency states that it will submit the variance order as a SIP 

revision. Agency Resp. at 19. The Agency states, 
53

[the Agency]’s analysis of the Petition indicates that if such relief is granted under 

the terms and conditions contained herein, there will be no detrimental impact in 

the ability to rely on the new variance-adjusted MPS emission reductions in the 

Illinois SIPs, as needed. Agency Resp. at 22. 

Regarding a future SIP revision that would account for the instant variance, the Agency 

states,“[t]he Illinois EPA has had preliminary discussions with USEPA Region 5 regarding an 

SIP revision for pending variance requests and no adverse issues were identified.” Agency Post 

Br. at 2.

USEPA explained the nature of the regional haze problem and its relationship with SO2

in USEPA’s proposed approval of Illinois’ Regional Haze SIP: 

Regional haze is visibility impairment that is produced by a multitude of sources 

and activities located across a broad geographic area that emit fine particles 

(PM2.5) (e.g., sulfates, nitrates, organic carbon, elemental carbon, and soil dust) 

and its precursors—[SO2], [NOx], and in some cases ammonia (NH3) and volatile 

organic compound (VOCs). Fine particle precursors react in the atmosphere to 

form fine particulate matter. Aerosol PM2.5 impairs visibility by scattering and 

absorbing light. Visibility impairment reduces the clarity and distance one can 

see. PM2.5 can also cause serious health effects and mortality in humans and 

contributes to detrimental environmental effects such as acid deposition and 

eutrophication. 77 Fed. Reg. 3967 (Jan. 2, 2012).

In response to questions regarding the heat input values which would be most appropriate 

for calculations to support a SIP revision, the Agency responded that the original 2002 baseline 

year heat input is likely the value to be used in accordance with an USEPA memorandum on SIP 

Planning. Agency Post Br. at 2. In the notice of proposed approval of the Illinois SIP addressing 

regional haze, USEPA stated, 

[t]he MPS and CPS provide emission reduction well in excess of simply 

implementing BART on subject units . . . Illinois estimated that its plan will 

require 96,927 [tons per year (TPY)] lower SO2 emissions than simply requiring 

BART. [US]EPA believes that Illinois has thereby demonstrated that the 

emission limits on the subject BART units covered by MPS and CPS satisfy the 

BART requirements. 77 Fed. Reg. 3973 (January 26, 2012). 

AER states that the proposed interim SO2 emission rates under the variance would result 

in mass emissions of SO2 even lower than Illinois’ statewide estimates under the current MPS 

requirements by the 2017 BART compliance deadline. AER also points out that the net 

reduction in SO2 emissions continues to 2020 and beyond. AER Second Resp. at 7. AER states, 

“[a]ccordingly, an amendment to the SIP incorporating this variance request would only serve to 

enhance Illinois’ ability to comply with the Clean Air Act and Regional Haze Rule.” AER 

Second Resp. at 8. 
54

As discussed below and considering all of the above points, the Board finds that AER has 

demonstrated that the requested variance will reduce SO2 emissions during the term of the 

variance and result in a net benefit to the environment. 

The Board finds that AER has demonstrated that by complying with an overall SO2

annual emission rate of 0.38 lb/mmBtu in 2012, 0.35 lb/mmBtu in 2013 through 2019, and 0.23 

lb/mmBtu thereafter, together with not operating the Meredosia and Hutsonville stations through 

2020, AER will reduce SO2 emissions as compared to projected emissions under the MPS for the 

same time period. Specifically, AER estimates that it will emit 60,669 tons less SO2 under the 

variance than under the MPS from 2010 through 2020 based on AER’s latest table in Exhibit 4. 

The Board finds that the relevant period for analyzing the environmental impact of the variance 

is 2012 through 2020. The Board finds that subtracting the “SO2 reduced tons” for years 2010 

and 2011 would still result in a net environmental benefit of 33,544 tons11. 

The Board recognizes that AER’s emission estimates show that it will emit more SO2

under the variance than under the MPS in years 2015 through 2019. Specifically, from 2015 

through 2019, the values presented in AER’s Exhibit 4 show that AER will emit 259,395 tons of 

SO2 under the variance compared to 202,565 tons of SO2 under the MPS Baseline. In effect, 

AER will emit 56,830 more tons of SO2 during these years12. However, the Board finds that the 

higher SO2 emissions during the variance period are offset by the reduced SO2 emissions during 

the calendar years of 2012, 2013, 2014 and 2020. Specifically, in 2012, 2013, 2014 and 2020, 

AER’s Exhibit 4 shows that it will emit 192,196 tons of SO2 under the variance compared to 

282,571 tons of SO2 under the MPS, i.e. AER will emit 90,375 fewer tons of SO2 during these 

years13. As noted above, this results in a net benefit to air quality of reducing SO2 emissions by 

33,545 tons from 2012 through 202014.

Health Effects

A number of commenters raised concerns regarding the health impact of granting AER’s 

variance petition, with many public comments citing specifically to personal health issues where 

they or a close friend or family member has suffered from asthma or lung cancer. See e.g., Tr. at 

93, 94, 146-147, 183, 185, 206. The Citizens Groups also raised concerns regarding the health 

impacts of “thousands of tons of additional emissions of SO2 annually between 2015 and 2019 . . 

. .” PC#2409 at 47-48. The Citizens Groups presented letters signed by health professionals in 

Illinois who cite to the harmful effects of SO2 emissions and voice concern at efforts to weaken 

the MPS. The health professionals explain, “[h]igh levels of SO2 and NOx can exacerbate 

respiratory symptoms in at-risk individuals (including children and the elderly), including asthma 

and [Chronic Obstructive Pulmonary Disease (COPD)] attacks.” PC#2409 Exh. 5 at 1. 

 11 60,669 – 14,522 (for 2010) and 12,573 (for 2011) = 33,544 tons

12 (Net Variance SO2 Tons 51,879 x 5 years ) – (MPS Baseline SO2 Tons (42,556 x 2) + (39,151 

x 3)) = 56,830

13 (MPS Baseline SO2 Tons (85,112 x 2) + 73,196 + 39,151) – (Net Variance SO2 Tons 56,986 + 

(51,879 x 2) +34,452 = 90,375

14 90,375 – 56,830 = 33,545 or 60,669 – 14,522 (for 2010) and 12,573 (for 2011) = 33,544 tons
55

Explaining that SO2 is a precursor to PM2.5, the health professionals refer to studies linking 

exposure to PM2.5 and premature mortality and cardiovascular effects. Id. 

Dr. Samuel Dorevitch, a medical doctor and associate professor at the University of 

Illinois at Chicago School of Public Health, stated, “[i]n light of the health impacts of even 

moderate levels of SO2 pollution, and the long term health risks of PM2.5 pollution, failure to 

lower them on the agreed upon schedule would be expected to keep rates of asthma attacks and 

other health problems higher than they would be at the agreed upon, lower levels.” PC#1919 at 

1. 

The People argue that averaging AER’s projected emissions over twelve years does not 

meet the intention of the MPS. The People assert a long-term averaging does not recognize 

health impacts that occur relatively quickly after SO2 is emitted. PC#249 at 5. Therefore, the 

People argue that early reductions in SO2 emissions are of little value because “a ton of SO2

avoided in 2010 does not help an asthmatic . . . exposed to emissions in 2018 . . . .” Id.

In order to respond to questions raised about health effects, AER commissioned a review 

of AER’s variance request and the potential health effects related to SO2 emissions. AER Post 

Br. at 26; AER Post Br. Exh. 3. AER’s report, citing a USEPA report15, found no causal 

relationship between long-term exposure to SO2 and respiratory symptoms. AER Post Br. at 44. 

AER’s report further contends that, while there was a causal relationship found between shortterm SO2 exposure and respiratory symptoms, these findings were small and raised questions 

whether exposure and effect were causally associated. Id. AER’s report further refutes the 

relationship between respiratory symptoms and SO2 exposure by noting that none of these 

studies isolated the effects from SO2 alone nor did they properly account for external factors 

such as smoking or allergens. Id. at 43, 44-45. AER contends that the People, in determining 

excess emissions, have ignored emission reductions that will commence immediately. Id. at 28. 

AER’s report concludes that granting the variance “would result in an overall net benefit in terms 

of health effects.” Id. at 43. The Board finds nothing in the record to undercut this assessment.

As explained above, AER’s emission calculations show a net reduction in SO2 emissions 

under the requested variance resulting in a net benefit to the environment which correlates to a 

net benefit to public health. Emission standards are risk-based standards which consider impacts 

to public health. The Agency agrees with AER’s demonstration of a net environmental benefit, 

and notes that offsetting potential delays in emission decreases through unit shutdowns is an 

acceptable part of the regulatory process. Agency Resp. at 21. The Agency stated, “the emission 

reduction offsets that [AER] is seeking to rely on are creditable and allowable.” Agency Resp. at 

21. The Agency plans to submit the variance order if granted for approval as a SIP revision, 

noting that the interim SO2 emission standards will not result in a detrimental impact in the 

emission reductions in the Illinois SIP. Agency Resp. at 11, 19, 22. After preliminary 

discussions with USEPA Region 5 regarding pending variance requests, the Agency stated that

no adverse issues were identified. Agency Post Br. at 2.

 15 Integrated Science Assessment for Sulfur Oxides-Health Criteria, EPA-600/R-08/047F (Sept. 

2008).
56

Further, the Agency noted, “[t]he MPS was not designed to address the new 2010 1-hour 

SO2 [NAAQS], which was not proposed at the time the MPS was being negotiated.” Agency 

Resp. at 22. The Board notes that the new 1-hour SO2 NAAQS addresses short term exposure 

and sets into motion a requirement for the states to assess attainment. 77 Fed. Reg. 46295 (Aug. 

3, 2012). Based on the record at this time, the Board does not have enough information to 

determine if AER’s variance will interfere with the State’s ability to attain or maintain the new 1-

hour SO2 NAAQS or the proposed PM NAAQS because the MPS and current Illinois SIP do not 

yet address these standards. However, the Board finds that granting AER’s petition for variance 

with the conditions in the order below would be within the State’s current obligation under the 

Illinois SIP to attain and maintain compliance with the NAAQS.

Meredosia and Hutsonville Closures

The Board notes that the above emission projections of 33,545 fewer tons of SO2 under 

the variance than under the MPS use an annual heat input of 340,446,252 mmBtu, which is the 

heat input AER used in 2009 during the R09-10 rulemaking proceeding and includes heat inputs 

for the Meredosia and Hutsonville stations. AER also projected SO2 emissions resulting from 

the variance using an annual heat input of 312,003,694 mmBtu, which does not include heat 

inputs for the now closed Meredosia and Hutsonville stations, of 7,700 fewer tons SO2 under the 

variance than under the MPS. The Board accepts the validity of using these respective heat 

inputs. The Board finds that the requested variance results in a net benefit to air quality, and in 

so doing, has accounted for the SO2 emission reductions resulting from not operating the 

Meredosia and Hutsonville stations from 2012 through 2020. 

The Board is not persuaded by the Citizens Groups’ objection to using emission 

reductions from closing the Meredosia and Hutsonville stations to mitigate emission increases 

under the variance on the grounds that these closures would occur regardless of whether the 

variance is granted. PC#6 at 9; PC#2409 at 41-46. However, the Board agrees with the Agency 

that “providing credit for actions (e.g., unit shutdowns) that result in emission reductions is an 

acceptable part of the regulatory process” and “emission reduction offsets that Petitioner is 

seeking to rely on are creditable and allowable.” Agency Resp. at 21. The Board further echoes

the Agency explanation that the Board and Agency are “accustomed to recognizing and allowing 

such reductions to offset potential emission increases under the New Source Review and 

Prevention of Significant Deterioration permitting regulations.” Id. The Board reminds that it

has recently considered SO2 emission reductions due to unit shutdowns in analyzing the 

environmental impact of a requested variance. See Midwest Generation, LLC – Waukegan 

Generating Station v. IEPA, PCB 12-121, slip op. at 16 (Aug. 23, 2012).

The Board finds it appropriate to account for emission reductions achieved through not 

operating the Meredosia and Hutsonville stations in determining the effect of the variance on 

SO2 emissions. The AER MPS Group includes seven facilities, including Meredosia and 

Hutsonville, and the overall SO2 annual emission rates in the MPS apply to all the facilities in the 

AER MPS Group. It is significant to note the MPS does not restrict the AER MPS Group from 

employing any specific methods to reach the required emission rates. Furthermore, there is no 

current regulatory requirement that these facilities must remain closed so granting this variance 
57

with such a condition would ensure that these two stations remain closed during the term of the 

variance.

Length of Dual Variance Periods

The Board finds initially that, although the total length of the requested combined dual 

variance periods is five years and 15 days, the variance periods do not run afoul of the Act’s 

requirement that the Board may issue a variance for a period not to exceed five years. See 415 

ILCS 5/36(b). AER seeks relief from 35 Ill. Adm. Code 225.233(e)(3)(C)(iii) for five years 

beginning January 1, 2015 and ending December 31, 2019, and relief from 35 Ill. Adm. Code 

225.233(e)(3)(C)(iv) for three years and fifteen days, beginning January 1, 2017 and ending 

January 15, 2020. Pet. at 1; AER First Resp. at 1. 

The Board believes AER accurately points out that

the structure of AER’s requested relief is such that compliance with both the 0.25 

and 0.23 lb/mmBtu SO2 emission standards is separated by two only [sic] weeks 

(December 31, 2019 and January 15, 2020, respectively). That is because the 

control technology needed to achieve both of these rates, is the same – the 

completion of the Newton scrubber. In reality, achievement of one is the 

achievement of the other.” AER Post Br. at 47 (emphasis in original). 

Accordingly, the Board believes that the total length of the combined dual variance periods can 

be kept to 5 years. The Board will grant a variance from two separate regulatory requirements, 

each of which does not exceed five years, and cumulatively covers precisely five years from 

January 1, 2015 through December 31, 2019. As discussed below, the Board has considered 

various issues raised by the petition, AER’s calculations, the Agency’s response, and public 

comments with respect to this period of time.

The Board finds that the relevant period for analyzing the environmental impact of the 

variance is 2012 through 2020. The Board did not include emission estimates from 2010 and 

2011 in finding that the variance will result in an overall reduction of SO2 emissions. AER

includes emission calculations for 2010 and 2011 in its petition, as well as in Tables 1, 2, and 3, 

and explains that it did so “to show the total tons of SO2 reduced during the MPS period by the 

end of the requested variance term.” AER Second Resp. at 5. AER also states that it included

2010 and 2011 “to illustrate that AER would be in the same position or better by the end of the 

variance term than as was projected under the MPS (that is, to make a true comparison, the entire 

period needs to be considered).” AER First Resp. at 10. 

However, the Board finds that 2012 is the appropriate start point because the variance 

will be granted in 2012 and commits AER to complying with a more stringent overall SO2

annual emission rate starting in 2012 of 0.38 lb/mmBtu, decreasing to 0.35 lb/mmBtu in 2013 as 

a prerequisite to the dual variance periods themselves. In addition, AER’s demonstration and the 

variance conditions rely on the shutdown of the Meredosia and Hutsonville stations and these 

facilities ceased operations in December 2011 (Pet. Exh. 6 at 4; AER Post Br. Exh. 4).
58

The Board has included emission estimates for the full calendar year of 2020 in its 

analysis here of the environmental impact of the variance, because the variance requires that 

AER return to compliance with the 0.23 lb/mmBtu overall SO2 annual emission rate in 2020. In 

addition, AER relies on the closure of the Meredosia and Hutsonville stations through 2020 to 

demonstrate that the variance will result in net benefit to the environment. Consequently, the 

Board includes the continued closure of Meredosia and Hutsonville through the end of 2020 as 

one of the conditions of the variance in the order below.

The People criticize AER’s variance request stating that 

the problem with this framework [framing its compliance plan in terms of 

cumulative net emissions from 2010-2021] is that the MPS was not intended to be 

a 12-year averaging period of pollution reduction. PC#249 at 4. 

However, the Agency response explains that the timing of the emission reductions in the 

MPS considered many variables, including AER’s “ability to install pollution control equipment 

in a timely manner and a desire to achieve the greatest amount of reductions within a reasonable 

amount of time.” Agency Resp. at 21-22. For its part, AER disagrees with the Peoples’ 

characterization stating that its petition seeks “to delay the 2015 and 2017 rates such that it can 

complete installation of the pollution control equipment necessary to meet those rates.” AER 

Second Resp. at 8. The Board notes that Section 104.204(g) of its rules requires AER to provide 

“[t]he nature and amount of emissions . . . of the constituent in question if the requested variance 

is granted, compared to that which would result if immediate compliance is required.” AER’s 

Tables 1, 2, 3, and 4 and Exhibit 4 provide this required information in various formats for the 

requested variance term.

The People argue that it is not appropriate to use a “long-term averaging analysis” 

because public health impacts from SO2 occur quickly after being released. PC#249 at 5. In 

other words, the People object to offsetting emission increases in 2015 through 2019 with 

emission decreases in 2010 through 2014. Id. However, the Agency notes that the MPS “was 

not designed to address the new 2010 1-hour SO2 National Ambient Air Quality Standard, which 

was not proposed at the time the MPS was being negotiated.” Agency Resp. at 22. 

As set forth above, the Board finds that it is appropriate to compare estimated SO2

emissions under the MPS to estimated SO2 emissions under the variance for 2012 through 2020 

to determine the environmental impact of granting the variance. See supra at p. 49. Section 

225.233(e)(3)(C) of the MPS, the subject of this variance petition, expressly provides for 

declining overall SO2 annual emission rates over time in four increments from 2010 through 

2017. The variance as granted adjusts the overall SO2 annual emission rate during 2012 through 

2019 and returns the company to compliance with the 2015 and 2017 standards in 2020. 

Although the numerical limits in the variance differ from Section 225.233(e)(3)(C), the Board 

finds that the intent to reduce SO2 emissions by lowering the overall SO2 annual emission rate 

over time is consistent between the variance and the MPS.

The Board rejects the suggestion of the Citizens Groups and the People that the variance 

be limited to two years. PC#2409, PC#2410 at 8. The variance provisions of Section 
59

104.Subpart B require the petitioner’s compliance plan to address achieving full compliance. 

See 35 Ill. Adm. Code 104.204(f)(1). AER’s demonstration shows that full compliance cannot 

be achieved in two years by December 31, 2017. 415 ILCS 5/5(d). While the provisions of 

Section 233.225(e)(3)(C)(iii) cover only the years 2015 and 2016, a variance that only covers 

these two years would not recognize AER’s compliance plan addressing achieving full 

compliance by December 31, 2019. Consequently, the Board finds that the record contains no 

adequate support for shortening the variance period to two years.

In summary, the Board finds that AER has demonstrated that the requested dual variance 

terms to 2020 are reasonable to allow AER to budget money and resources toward completion of 

the Newton FGD project and the costs of additional mitigation measures, including maximizing 

operation of the existing FGDs and purchasing low-sulfur coal during the interim. Further, the 

Board finds that the requested variance is consistent with the Act, which provides that the Board 

may grant a variance from a regulation for a period not to exceed five years. Here, the dual 

variance periods overlap, each one running five years or less, such that the total length of the 

dual variance terms spans precisely five years, commencing January 1, 2015 and ending 

December 31, 2019. 

Mercury Emissions

The Board notes that the Illinois Mercury Rule promulgated in R06-25, specifically 

Section 225.230, provides numerical emission limits for existing EGUs and generally requires 

such units to meet a mercury emission limit of 0.0080 lb/GWh gross electrical output or a 

minimum 90 percent reduction of input mercury by July 1, 2009. 35 Ill. Adm. Code 225.230(a). 

For companies opting in to the MPS, the requirement to meet this same numerical limit is 

extended to January 1, 2015. 35 Ill. Adm. Code 225.233(d)(1). However, during this interim 

period, facilities covered by the MPS are required to operate mercury emission control devices, 

generally either halogenated activated carbon injection systems or selective catalytic reduction 

systems and SO2 scrubbers. 35 Ill. Adm. Code 225.233(c).

The Board finds that there is no impact on mercury emissions attributable to the variance 

request, based on the information discussed below. AER seeks a variance from the overall SO2

annual emission rate in Sections 225.233(e)(3)(c)(iii) and (iv). Granting a variance from 

Sections 225.233(e)(3)(c)(iii) and (iv) has no effect on mercury emissions. AER will continue to 

be subject to mercury control requirements in Section 225.233(c) and will be subject to the 

0.0080 lb/GWh in January 2015 under Section 225.233(d)(1).

Many commenters argue that AER’s variance petition should be denied because AER 

negotiated and opted in to the MPS in order to be subject to less stringent mercury standards in 

exchange for reducing SO2 and NOx emissions. See, e.g., PC#11. By opting in to the MPS, 

commenters allege AER benefitted from delaying compliance with mercury standards until 2015.

In response, AER states, 

[t]he benefit to the company was that the compliance date for one aspect of the 

regulation (compliance with the removal efficiency) was deferred from July 2009 
60

to January 2015. Notably, the obligation to install control technology and to 

inject activated carbon was not deferred. AER Post Br. at 49-50. 

The record demonstrates that AER has installed such mercury control equipment. 

Specifically, AER installed activated carbon injection systems on twelve units at four stations to 

control mercury emissions at a capital cost in excess of $20 million. Pet. at 28. AER spends $17 

million in annual operating costs for these systems. Id. AER installed four SCRs and three FGD 

systems to control mercury as well as NOx and SO2. Id. AER spent $177 million to install the 

SCRs and spends approximately $3.9 million in annual operating and maintenance costs. Pet. at 

28. AER spent $813 million to install the FGD systems and spends approximately $3.5 million 

annually in operating and maintenance costs. Id. AER is continuing to test the equipment to 

achieve more effective control. Pet. at 28, AER Post Br. at 50. At five units, AER has already 

recorded mercury emissions below the 2015 standard, and AER continues to test various control 

methodologies and reagents at nine other units. AER asserts, “[t]he mercury reductions from 

AER’s fleet are being achieved three years ahead of the compliance deadline set forth in the 

MPS. There is no question that the environment in Illinois is benefitting from these early 

reductions.” AER Post Br. at 50.

AER expressly states that it does not seek a change to applicable mercury requirements 

and will comply with the 0.0080 lb/GWh limit by January 1, 2015. Pet. at 28, Pet. Exh. 7 at 2. 

The federal standard under the new MATS program limits mercury emissions to 0.013 lb/GWh 

by 2015 which may be extended under certain circumstances. 77 Fed. Reg. 9304 (Feb. 16, 

2012). AER further points out that the Illinois requirement is stricter than the federal 

requirement. Pet. at 28.

Based on the above, the Board finds grant of the variance has no impact on mercury 

emissions.

Alleged Hardship to AER from Scheduled Compliance

AER asserts that compliance with the 2015 and 2017 overall SO2 annual emission rates in 

Sections 225.233(e)(3)(C)(iii) and (iv) creates an arbitrary or unreasonable hardship on AER. 

Pet. at 4, 11. AER contends that the following events were not foreseen when Sections 

225.233(e)(3)(C)(iii) and (iv) were adopted and therefore impose an undue hardship on AER: 

(a) legal challenges to federal regulations underpinning the MPS; and (b) declining power prices. 

Pet. at 10-11.

Effectiveness of Adopted Federal Regulations Delayed

AER contends that it opted into the MPS in 2007 with the expectation that future federal 

regulatory requirements for its EGUs were imminent. Pet. at 11. Now that these federal rules 

(CAIR, CAMR, and CSAPR) have been challenged, stayed, and remanded in various federal 

court proceedings, AER argues that Illinois-specific MPS requirements cause it an arbitrary and 

unreasonable hardship for two reasons.
61

First, AER asserts that the MPS requires Illinois electric generating units to control NOx

and SO2 emissions “even in the absence of a permanent and effective federal emission program 

like CAIR.” Pet. at 15. CSAPR, the replacement for CAIR, was scheduled to take effect on 

January 1, 2012 but was stayed. AER argues that it is arbitrary and unreasonable to require it to 

comply with the MPS if there is no federal program requiring that level of control. Id.

Second, AER argues that Illinois-specific MPS requirements place it at a competitive 

disadvantage with generators in nearby states. Pet. at 16-17. AER claims that it competes with 

generators in nearby states “that have neither deregulated their energy markets nor invested 

significant capital in environmental pollution control projects.” Id. at 16. These companies are 

able to recover compliance costs through rates but AER does not have revenue from a captive 

consumer base to fund environmental compliance costs. Id. If the CSAPR had become effective

on January 1, 2012, the CSAPR would have “level[ed] the playing field” between Illinois 

generators and competitors in nearby states. Id. at 16-17.

In contrast to commenters opposing grant of the variance, AER states that it did not seek 

deregulation (AER Post Br. at 9) and that its intended benefit from opting in to the MPS has not 

occurred. AER Post Br. at 51. This benefit was the alignment of the MPS’s NOx and SO2

emission requirements with AER’s control strategy for compliance with then-pending CAIR

regulations. Id.

Declining Power Prices

AER had analyzed the costs of compliance with the MPS when the MPS was 

promulgated in 2006. Pet. at 17. AER claims that compliance with the 2015 and 2017 overall 

SO2 annual emission rates is “no longer economically reasonable.” Id.

AER plans to construct two FGD units at the Newton station. Pet. at 18. AER states that 

it has spent $237 million to date on the project. Id. Through 2012, AER will have spent “over 

50% of the project cost.” Id. AER claims that it can no longer fund the Newton FGD project in 

time to comply with the 2015 and 2017 SO2 emission rates. Id. at 19. AER attributes its lack of 

available funds to declining power prices due to “the recession, the exceptionally mild weather 

this winter, and an increased supply of natural gas from shale gas.” Id. AER states that in 2006 

and 2007 the price per megawatt hour was approximately $60 and in 2012 the price ranges from 

$29.50 to $33.60 per megawatt hour. Id. at 20. AER states that “power prices over the next 

three years are not expected to improve to the level to support the installation of the Newton 

FGD [p]roject by either 2015 or 2017.” Id. at 20, citing Pet. Exh. 9.

AER claims that declining power prices have reduced operating proceeds and adversely 

impacted AER’s access to short-term and long-term financing. Pet. at 20. AER states that net 

income for Ameren Energy Generating Company, owner of the Newton station, has dropped by 

over 95% since 2008. Id. citing Pet. Exh. 5. AER claims that it is unable to borrow funds to 

complete the project because its interest rate ratio is expected to fall below the required 

minimum contained in existing debt covenants. Id. at 21-22. AER also contends that it is unable 

to obtain funding from Ameren Corporation. Id. at 22; AER First Resp. at 4-5.
62

AER asserts that with no “viable funding mechanism” for the Newton FGD project, 

AER’s “only other compliance alternative” to comply with the overall SO2 annual emission rate 

in the MPS is to close at least two plants, such as Joppa, E.D. Edwards, or Newton. Pet. at 23. 

AER’s consultant reports that AER puts $44.4 million in the local economy near the E.D. 

Edwards plant and $124,071,000 in the State’s economy due to the plant. Id. at 24. The report 

concludes that AER puts $76.7 million in the local economy near the Joppa station and 

$214,221,000 in the State’s economy due to the Joppa station. Id. The two plants employ 274 

persons and “supported an additional 1209 total jobs held by Illinois residents.” Id.

Weighing Environmental Impact against Hardship to AER

The Board has previously found that the environmental impact of the requested variance 

is a net benefit to air quality. See supra at p. 50. AER has shown that the variance will result in 

a net decrease of 33,545 tons of SO2 emissions from 2012 through 2020. AER will achieve this 

net reduction in emissions by taking credit for the closure of the Meredosia and Hutsonville 

stations, operating FGD equipment at the Coffeen and Duck Creek stations at a higher efficiency

98%-99% SO2 removal rate, and using low-sulfur coal. The Agency agrees that granting a 

variance imposing an overall SO2 annual emission rate of 0.35 lb/mmBtu from January 1, 2013 

through December 31, 2019, together with closing the Meredosia and Hutsonville stations,

results in a net environmental benefit. Agency Resp. at 22. Further, the Agency “does not 

believe that any environmental harm would result therefrom.” Id. Accordingly, the Board is 

persuaded that the overall reduction in SO2 emissions resulting from this variance favors 

granting the variance. 

The People argue that the environmental impact of increased SO2 emissions from 2015 to 

2019 is the environmental impact which should be weighed against the hardship claimed by 

AER. PC#249 at 5. However, as discussed above, the Board has determined that the 

environmental impact of the requested variance from 2012 through 2020 is the impact to be 

weighed against any hardship to AER.

In light of the overall reduction in SO2 emissions from the requested variance, the Board 

considers the alleged hardships to AER from not granting the variance. The public comments 

made at hearing and received by the Board do not persuade the Board to find that AER’s asserted 

hardship is self-imposed. AER contends that the new methods of gas extraction are a “gamechanging” technology that have “fundamentally altered” the outlook for gas supplies and pricing. 

AER Post Br. at 10. This competition has led to a decline in cash flow to the AER MPS Group. 

Id. at 7. None of the commenters opposing granting the variance directly refute this position. 

Instead, they state that market changes should be foreseeable and not excuse AER from meeting 

its MPS requirements. See, e.g., PC#2409 at 24. The Board finds that the hardship is not selfimposed.

In considering hardship, the Board has also taken into account that AER has already 

spent $237 million(nearly 50% of the cost) on the Newton FGD project, and that AER has also 

budgeted $16 million per year from 2013 to 2016 with greatly increased capital expenditures in 

2018 and 2019 to complete the Newton FGD project. Pet. at 19; AER First Resp. at 6; Tr. at 32; 

AER Post Br. at 38, 40. AER has further spent over $813 million to install scrubbers on three of 
63

its generating units, and has provided the Board with a detailed chart outlining the various 

pollution control devices installed at the Coffeen, Duck Creek, E.D. Edwards, Joppa and Newton 

Energy Centers. AER Post Br. at 31-36. In addition, the Board has considered the decline in 

electricity prices from approximately $60 per megawatt hour in 2006 and 2007 to $29.50 to 

$33.60 per megawatt hour for June 2013 through May 2014 and AER’s representation that 

“power prices over the next three years are not expected to improve to the level to support the 

installation of the Newton FGD Project by either 2015 or 2017.” Id. at 20, citing Exh. 9.

The Agency concludes that the revised variance proposal is “acceptable” to the Agency. 

Agency Resp. at 7. Specifically, the Agency and AER have agreed to an alternative variance 

proposal where AER commits to complying with an overall SO2 annual emission rate of 0.35 

lb/mmBtu from January 1, 2013 through December 31, 2019. Id. at 21. The Agency states that 

this revised compliance proposal satisfies the Agency. Id. 

Considering the overall reduction in SO2 emissions during the term of the requested 

variance, the Board finds that requiring AER to comply with the December 31, 2015 deadline in 

Section 225.233(e)(3)(C)(iii) and the December 31, 2017 deadline in Section 

225.233(e)(3)(C)(iv) would impose an arbitrary or unreasonable hardship on AER. 

Consistency with Federal Law

The Board has authority under Section 110 of the Clean Air Act to adopt regulations that 

are part of the State’s plan for implementation, maintenance, and enforcement of air quality 

standards. The variance procedure to grant relief from a Board regulation is consistent with the 

authority granted to the states under Section 110 of the Clean Air Act. The Agency informs the 

Board that it will submit the variance order, if granted by the Board, for approval as a revision to 

the Illinois SIP. Agency Resp. at 19. The Agency states it “has had preliminary discussions with 

USEPA Region 5 regarding an SIP revision for pending variance requests and no adverse issues 

were identified.” Agency Post Br. at 2. The Agency also notes that granting the variance under 

the alternate proposal agreed between the Agency and AER will have “no detrimental impact in 

the ability to rely on the new variance-adjusted MPS emission reductions in the Illinois SIP, as 

needed.” Agency Resp. at 22. Upon reviewing the entire record, the Board finds that granting 

AER’s petition for variance with the conditions in the order below would be within Illinois’ 

current obligation under the Illinois SIP to attain and maintain compliance with the NAAQS. 

The Board, therefore, finds that granting AER a variance from the rule is consistent with federal 

law. 

The Board notes, as AER recognizes, that if federal rules, such as a CAIR or CSAPR

replacement, ultimately go into effect, AER might need to implement additional controls. 

Additionally, the Board notes that USEPA adopted a new primary NAAQS for SO2 of 0.75 ppb 

on June 22, 2010, which became effective on August 23, 2010. 75 Fed. Reg. 35520 (June 22, 

2010). USEPA gave the states until June 3, 2013 to promulgated initial area designations for 

attainment. 77 Fed. Reg. 46295 (August 3, 2012). USEPA stated

any State containing an area designated as nonattainment with respect to the SO2

NAAQS would need to develop for submission to [US]EPA a SIP meeting the 
64

requirements of part D, Title I, of the CAA, providing for attainment by the 

applicable statutory attainment date . . . all components of the SO2 part D SIP 

must be submitted within 18 months of the effective date of an area’s designation 

as nonattainment. 75 Fed. Red. 35577 (June 22, 2010).

Later on June 29, 2012, USEPA also proposed to make revisions to the primary and secondary 

NAAQS for particulate matter (PM2.5 and PM10

16). 77 Fed. Reg. 38890 (June 29, 2012).

Since many rules at the federal level impact State regulations, the new federal rules have 

the potential to trigger related rulemakings on a statewide basis. As a result, the Board notes that 

the regulatory sections from which AER seeks relief might necessarily be amended as a result at 

some point in time. Because AER’s requested dual variance periods would not commence until 

2015 and 2017, this would allow the requested relief to occur farther into the future when 

changes at the State level might be implemented that would impact the sections from which AER 

currently seeks relief. Lastly, any changes to the Board rules will proceed through the 

rulemaking process, and all parties here will have an opportunity at the time to reassess AER’s 

prospects as suggested by the Citizens Groups.

Compliance Plan

For the reasons below, the Board finds that AER’s compliance plan is sufficiently 

definite to support granting the variance.

AER’s Intent to Comply

The Citizens Groups argue that AER’s compliance plan is not definite because of its 

reliance on market conditions and, further, that AER has not shown it will comply with a 

proposed compliance plan. PC#6 at 7, PC#2409 at 2. 

The Board notes that, although the rate of AER’s progress would be dependent on market 

conditions, the dual variance periods would not be. AER would be required to achieve 

compliance with the 0.23 lb/mmBtu and 0.25 lb/mmBtu annual SO2 emission rates starting on

January 1, 2020. Furthermore, the compliance plan explicitly requires AER to meet an annual 

SO2 emission rate of 0.35 lb/mmBtu through 2019. 

The Board notes that AER is committing significant financial resources that AER states 

are already budgeted. AER has already spent $237 million on the Newton FGD project as of 

May 2012, and by the end of 2012, AER will have spent over 50% of the project cost. Pet. at 19. 

AER has budgeted roughly $16 million per year from 2013 to 2016 with greatly increased capital 

expenditures in 2018 and 2019 to complete the Newton FGD project. Pet. at 19; AER First 

Resp. at 6; Tr. at 32; AER Post Br. at 38, 40. AER will also spend $5 million in capital and 

$173,337 in annual expenses to fully maximize the existing FGD systems at Duck Creek and 

Coffeen during the course of the variance. AER First Resp. at 8. Additionally, AER will bear 

 16 Particles generally less than or equal to 2.5 and 10 micrometers in diameter, respectively. 77 

Fed. Red. 38890 (June 29, 2012).
65

lost revenue from the continued closures of Hutsonville and Meredosia, and higher costs for the 

purchase of low-sulfur coal at the Edwards, Newton and Joppa stations. AER adds, 

AER has every incentive to complete the [Newton FGD] project and it cannot 

even begin to recoup its financial investment unless and until the project is 

completed[]. AER Post Br. at 37. 

Newton FGD Project Progress Reports

The Board notes that AER proposed, as a condition of the variance, to provide annual 

progress reports on the status of construction activities relating to the Newton FGD project. 

AER First Resp. at 6. The Board may specify periodic progress reports in granting a variance 

pursuant to 415 ILCS 5/36(b) and has required such reports as a condition of the variance. 

Although AER proposes providing both the Board and the Agency with annual progress reports, 

the Board notes that once a case is closed, providing progress reports to just the Agency instead 

would be more appropriate. The Board will include the requirement for annual progress reports 

to be submitted to the Agency in the conditions of the variance.

Newton FGD Project Time Schedule

The Citizens Groups argue that AER’s compliance plan is not definite because it lacks a 

time schedule for important phases of the Newton FGD project required by 35 Ill. Adm. Code 

104.204(f). PC#2409 at 2-6. 

AER did not submit a detailed compliance plan with its petition. In written questions to 

AER, the Board requested that AER provide an estimated timeline for phases of the compliance 

plan including engineering, site preparation, foundation work, duct work, fabrication, field 

construction activities, startup, and any other significant phases. AER provided general 

information on certain construction activities but no detailed timeline of specific activities. AER 

First Resp. at 6. The Board then asked follow-up questions at the August 1 hearing on the timing 

of activities needed to complete the Newton FGD project. In its post-hearing brief, AER again 

declined to provide a detailed timeline, stating it is difficult to provide a specific and targeted 

prospective schedule beyond the categories of work previously provided to the Board. AER Post 

Br. at 38. AER contends that a specific timeline establishing construction and project milestones 

cannot be provided until an in-service date is fixed. Id. AER states 

[o]nce the Company ‘green lights’ the project, AER project management and its 

general contractor Advatech will reestablish a hard and fixed schedule that 

‘backtracks’ from the service date and takes into account work already 

completed.” Id. 

AER does note if relief is granted, AER’s current budget projections

call for greatly increased capital expenditures commencing in 2018 and 2019 so 

that AER will be in a position to comply with the MPS once the proposed 

variance term expires on January 15, 2020. Id.
66

The Board has extracted from the record the following information as to AER’s 

anticipated timeline for completing the Newton FGD project. AER stated all the major 

equipment components for the Newton FGD project have already been procured. Pet. at 9. AER 

has already scheduled construction work through the end of 2013. AER First Resp. at 6. AER 

stated that engineering design is expected to be complete in 2014. Id. AER stated that work on 

the electrical systems and piping connections will be deferred. Id. AER lists other work that

will be performed during the dual variance period including site preparation and foundation 

work, delivery of major equipment sets that will be rough set into position at the site, ductwork 

that will be fabricated and insulation that will be applied, and the absorber building that will be 

constructed. AER First Resp. at 6, Tr. at 31-32. AER has budgeted $16 million per year from 

2013 to 2016 to complete the Newton FGD project and AER explains “[e]verything that can be 

done on the ground including the construction of the new chimney stack will be performed.” 

AER Post Br. at 38. In 2018 and 2019, AER will need to greatly increase its capital expenditures 

to comply with the MPS by January 2020. Id. When the “project ramps back up,” field 

construction is expected to take 24 months. Pet. at 9. 

The Board agrees with the Citizens Groups that AER has not provided a sufficient 

compliance plan as required by Section 104.204(f) despite several opportunities to do so. AER 

stated that it plans to comply with the overall SO2 annual emission rate under 35 Ill. Adm. Code 

225.233(e)(3)(C)(iii) and (iv) by completing the FGD project at the Newton station by the end of 

the variance period. Pet. at 9. Throughout this proceeding, AER has not indicated that it would 

use any other equipment at any other plant to meet the annual SO2 emission rates. While AER 

provided some information regarding expected dates and timeframes for completing the Newton 

FGD project to achieve compliance, AER did not propose a specific time schedule for 

implementation of all phases of the Newton FGD project. Pet. at 9, AER First Resp. at 6; AER 

Post Br. at 37, 38, 40. The Board finds that AER’s compliance plan must include specific dates 

to demonstrate progress toward achieving compliance with the applicable requirements. Based 

on the information in the record, AER’s estimation that field construction activities could take 

approximately 24 months to complete, and an in-service date of no later than January 1, 2020 for 

the Newton FGD equipment, the Board will assign dates to the elements of AER’s Newton FGD 

project in the variance conditions under the order below. The Board notes that AER may file a 

motion for modification of internal variance compliance dates under 35 Ill. Adm. Code 104.212.

AER states that it is unable to provide a date certain by which AER will know if 

completion of the scrubber project before January 2020 is feasible. Tr. at 32-33; AER Post Br. at 

40. Therefore, AER proposes, “in the event completion of the FGD system become infeasible, 

AER agrees to advise the Board and the Agency of alternative plans for compliance during the 

remaining term of the variance.” AER First Resp. at 11. The Board notes that if AER were to 

develop “alternative plans for compliance,” AER would not be able to amend the instant 

variance but would need to seek new relief.

Additional Variance Conditions

As discussed below, the Board will additionally impose variance conditions agreed to be 

the parties, as outlined in the Board’s order. The Board has previously discussed and rejected 
67

suggestions by the Citizens Groups and the People for inclusion of conditions shortening the 

term of the variance and imposing new compliance plan restrictions, and therefore, these will not 

be repeated here.

AER’s petition did not include proposed language for the variance conditions but 

generally discussed terms that might be included in a Board order, including a requirement to 

comply with an overall SO2 annual emission rate of 0.38 lb/mmBtu through the end of 2019. 

Pet. at 8-9. In response to questions from the Board, AER proposed the following additional 

variance conditions and agreed to comply with an overall SO2 annual emission rate of 0.35 

lb/mmBtu during the variance period:

1. AER agrees not to operate the Hutsonville and Meredosia Energy Centers 

for power generation purposes during the pendency of the variance; except 

that the FutureGen project which is currently proposed for the Meredosia 

Energy Center site is exempt from this restriction.

2. During the term of the variance, AER agrees to file progress reports with 

the Board and the Agency as to the status of construction activities relating 

to the Newton scrubber annually by the end of each calendar year. 

Furthermore, in the event completion of the FGD system become 

infeasible, AER agrees to advise the Board and the Agency of alternative 

plans for compliance during the remaining term of the variance. AER 

First Resp. at 10-11.

The Agency response did not provide specific draft language for the variance conditions.

But, the response finds acceptable imposition of an overall SO2 annual emission rate of 0.35 

lb/mmBtu from 2013 through 2019 in conjunction with requiring the continued closure of the 

Meredosia and Hutsonville stations. 

The Board finds it appropriate to impose conditions to account not only for the interim 

SO2 emission rates, but also for emission reductions achieved through not operating the 

Meredosia and Hutsonville stations in determining the effect of the variance on SO2 emissions 

through 2020 as provided in AER’s demonstration. See AER Post Br. Exh. 4. Furthermore, 

since there is no current regulatory requirement that these facilities must remain closed, the 

Board will impose a condition ensuring that these two stations remain closed through the end of 

2020.

As a condition of the variance, AER has also agreed to provide annual progress reports 

on the status of construction activities relating to the Newton FGD project. In addition, the 

Board has added conditions to the variance presenting a detailed schedule for completion of the 

Newton FGD project. 

The Board will provide conditions to the variance, consistent with this opinion, in the 

order below.
68

CONCLUSION

While the Board today grants AER’s request for variance, the Board is cognizant that this

is AER’s second request for a change in the MPS requirements. AER filed a joint proposal 

during the Board’s R06-25 rulemaking to adopt the MPS and later proposed AER-specific 

revisions to the MPS in the Board’s R09-10 rulemaking. AER has now been given multiple 

opportunities to comply with SO2, NOx and mercury emissions requirements, and to develop a 

compliance plan that AER can implement.

The Board finds that AER has demonstrated that requiring compliance with the overall 

SO2 annual emission rates in Sections 225.233(e)(3)(c)(iii) and (iv) by 2015 and 2017, 

respectively, will impose an arbitrary or unreasonable hardship on AER. AER has committed to 

an overall SO2 annual emission rate of 0.35 lb/mmBtu from 2013 through 2019 in conjunction 

with the continued closure of the Meredosia and Hutsonville stations, increased efficiency of the 

FGD units at the Coffeen and Duck Creek stations, and the use of low-sulfur coal. The Board 

finds this compliance plan is satisfactory, as it results in an overall reduction of SO2 emissions 

from 2012 through 2020, and provides a net benefit to Illinois air quality.

Accordingly, the Board grants AER combined dual variances for the period beginning 

December 31, 2015 until December 31, 2019 from the requirements of 35 Ill. Adm. Code 

225.233(e)(3)(C)(iii) and for the period beginning January 1, 2017 until December 31, 2019 from 

the requirements of 35 Ill. Adm. Code 225.233(e)(3)(C)(iv), subject to the conditions outlined in 

the order below.

ORDER

The Board grants Ameren Energy Resources (AER) combined dual variances for the 

electrical generating units in AER’s multi-pollutant standard (MPS) Group from the applicable 

requirements of 35 Ill. Adm. Code 225.233(e)(3)(C)(iii) for a period beginning January 1, 2015 

through December 31, 2019 and 35 Ill. Adm. Code 255.233(e)(3)(C)(iv) for a period beginning 

January 1, 2017 through December 31, 2019, subject to the following conditions.

1. From the date of this order through December 31, 2012, AER must comply with 

an overall SO2 annual emission rate of 0.38 lb/mmBtu.

2. From January 1, 2013 through December 31, 2019, AER must comply with an 

overall SO2 annual emission rate of 0.35 lb/mmBtu.

3. Beginning January 1, 2020, AER must comply with an overall SO2 annual 

emission rate of 0.23 lb/mmBtu.

4. From the date of this order through December 31, 2020, AER must not operate 

the electrical generating units at Meredosia and Hutsonville Power Stations. The 

FutureGen project at the Meredosia Energy Center is exempt from this restriction.
69

5. Regarding the Flue Gas Desulfurization project at the Newton Power Station (I.D. 

No. 079808AAA) (Newton FGD project):

a. On or before July 1, 2015, AER must complete engineering work on the 

Newton FGD project.

b. On or before December 31, 2017, AER must obtain a new or extended 

construction permit, if needed, for the installation of the FGD equipment 

at the Newton Power station.

c. On or before December 31, 2018, AER must complete construction of the 

absorber building on the Newton FGD project.

d. On or before July 1, 2019, AER must complete steel fabrication of 

ductwork and insulation activities on the Newton FGD project.

e. On or before July 1, 2019, AER must complete installation of electrical 

systems and piping on the Newton FGD project.

f. On or before September 1, 2019, AER must set major equipment 

components into final position on the Newton FGD project.

g. Beginning with calendar year 2012 and continuing through 2019, AER 

must file annual progress reports with the Agency as to the status of 

construction activities relating to the Newton FGD project by the end of 

each calendar year. AER’s annual progress reports must include an 

itemization of activities completed during the year, activities planned to be 

completed in the forthcoming year, progress of the Newton FGD project to 

comply with the timelines specified in this variance, and the estimated inservice date. Annual progress reports must be submitted to :

Illinois Environmental Protection Agency

Attn: Ray Pilapil, Manager

Bureau of Air-Compliance Section

1021 N. Grand Ave. East

P.O. Box 19276

Springfield, IL 62794-9276

and

Illinois Environmental Protection Agency

Attn: Gina Roccaforte, Assistant Counsel

Division of Legal Counsel-Air Regulatory Unit

1021 N. Grand Ave. East

P.O. Box 19276

Springfield, IL 62794-9276
70

IT IS SO ORDERED.

If petitioner chooses to accept this variance, petitioner must, within 45 days after the date of this 

opinion and order, file with the Board and serve on IEPA a certificate of acceptance and 

agreement to be bound by all the terms and conditions of the granted variance. “A variance and 

its conditions are not binding upon the petitioner until the executed certificate is filed with the 

Board and served on the Agency. Failure to timely file the executed certificate with the Board 

and serve the Agency renders the variance void.” 35 Ill. Adm. Code 104.240. The form of the 

certificate follows:
71

CERTIFICATE OF ACCEPTANCE

I (We), __________________________________________, having read the opinion 

and order of the Illinois Pollution Control Board in docket PCB 12-126, dated September 20, 

2012, understand and accept the opinion and order, realizing that this acceptance renders all 

terms and conditions of the variance set forth in that order binding and enforceable. 

Petitioner: AMEREN ENERGY RESOURCES

By: _________________________________ 

Authorized Agent

Title: __________________________________ 

Date: __________________________________ 

Section 41(a) of the Environmental Protection Act provides that final Board orders may 

be appealed directly to the Illinois Appellate Court within 35 days after the Board serves the 

order. 415 ILCS 5/41(a) (2010); see also 35 Ill. Adm. Code 101.300(d)(2), 101.906, 102.706. 

Illinois Supreme Court Rule 335 establishes filing requirements that apply when the Illinois 

Appellate Court, by statute, directly reviews administrative orders. 172 Ill. 2d R. 335. The 

Board’s procedural rules provide that motions for the Board to reconsider or modify its final 

orders may be filed with the Board within 35 days after the order is received. 35 Ill. Adm. Code 

101.520; see also 35 Ill. Adm. Code 101.902, 102.700, 102.702.

I, John Therriault, Assistant Clerk of the Illinois Pollution Control Board, certify that the 

Board adopted the above order on September 20, 2012, by a vote of 4-0.

___________________________________

John Therriault, Assistant Clerk

Illinois Pollution Control Board
Attachment A – Hearing Commenters in Support of 

Ameren Energy Resources Requested Variance

The following list consists of commenters who appeared at the Board’s August 1, 2012 hearing 

in support of Ameren Energy Resources variance request. The commenter’s name appears on 

the left, with the citation to the August 1, 2012 hearing transcript appearing on the right.

Name Transcript Page Number

Senator Gary Forby, 59th District 56

Representative Brandon Phelps, 118th District 59

Representative David Reis, 108th District 63

Tim Drea 76

Mark Bolander, Mayor of Newton 79

Bill Weber, Jasper County Board Member speaking 

 for Brad Mitchell, Chairman of the Board 81

Julie Johnson, Mayor of Joppa 102

Billy McDaniel, Mayor of Metropolis 103

Dan Cox 106

Jean Ellen Boyd 111

Steve Ptacek 113

Kelly Stratemeyer 114

Robert Lawless 122

Paul King 131

Alan Bogardus 134

Bill Miller 141

Roderick Bland 149

Mike Woo 154

Greg Crawford 157

Keith Dollar 161

Prentiss Carter 164

Robert McFarlen 167

Dan Barnett 170

Anthony Robertson 172

Mike Killebrew 174

Mike Norman 178

Lynn Markum 181

Vicky Clark 189

Bill Sheppard 192

Mike Pullen 197

Anthony Jones 201

Jeremy Barnhill 202

John Bower 204

Rick Wolford 206

Rick Myers 207

Roger Kerley 211
2

Bruce Parker 212

Julie Wilke 216

Andy Todd 218

Charles Henderson 219

Larry Millspaugh. 223

Deborah Goodwin 224

Tab Walker 225

Gary Washburn 231

Ed Worthey 231

Andy Bloemer 232

Chris Hankins 236

Gerod Briggs 236

John Marschewski 236

Travis Blake 238

Roland Chapman 238

Kenny Johnson 239

Twyla Harvey 240

Paul Hardiek 240

Roger Bass 241

Larry Quick 242

Lindell Wenthe 245

J. D. Weaver 246

Brad Beisner 249

Skip Moore 251

Mitch Seibert 252

Chris Skates 256

Mike Pierson 258
Attachment B – Hearing Commenters Opposing

Ameren Energy Resources Requested Variance

The following list consists of commenters who appeared at the Board’s August 1, 2012 hearing 

opposing Ameren Energy Resources variance request. The commenter’s name appears on the 

left, with the citation to the August 1, 2012 hearing transcript appearing on the right.

Name Transcript Page Number

James Gignac 84

Judy Weimer 92

Norman Eckstein 94

Bryan Urbaszewski 97

Faith Bugel 115

Tracy Cox 126

Terry Grace 132

Jared Policicchio 137

Jennifer Cassel 142

Andrew Armstrong, on behalf of Dr. Samuel Dorevitch 149

Edward Warden 155

Sandy Carter 158

Edyta Sitko 162

Gabriel Rojkind 165

Simon Wiener 168

Rachel Grannemam 171

Priyanth Manjooran 176

Gloria Fallon 179

Shannon Weigel 182

Brian Sauder 185

Katie Mimnaugh 186

Stephanie Simowski 191

Marissa Lieberman-Klein 195

Amanda Guinn 199

Mayte Guerrero 205

David Jakubiak 209

Seth Johnson 213

Allison Fisher 220

Patty Rykhus 228

Christine Nannicelli 233

Art Meyer 243

Joyce Blumenshine 253
Electronic Filing- Received, Clerk's Office, 10/30/2012 

BEFORE THE ILLINOIS POLLUTION CONTROL BOARD 

AMEREN ENERGY RESOURCES, 

Petitioner, 

v. 

ILLINOIS :&""'¥1RONMENTAL 

PROTECTION AGENCY, 

Respondent. 

) 

) 

) 

) 

) 

) 

) 

) 

) 

) 

PCBl2-U6 

(Varlan~e- Air) 

NOTICE OF FILING 

John Therrlaul4 Assist!lrlt Clerk 

Cart:~l Webb, Hearing Officer 

Illinois Pollution Control Board 

James R. 'Ib:ompson Center 

i 00 West Randolph Street, Sui!,e ll-500 

Chicago, Illi:oois 6060 l 

t.'lcrriaifiillpcb.sll!le. il.us 

l::Webb.!:tsll!.tcJl.us 

Gina Roccaforte 

Assislant Coonsel 

Dh'i!;iono!Legai Counsel 

Illinois Environmental PrQteetion Agency 

1021 North Grand A Vll!'!lle, East 

P.O. Box 19276 

Springfield, Illincis 62794-9276 

PLEASE T.!U<E NOTICE ilia! we have today electronically filed with the Office of the 

Ck:J:k of the illinois Pollation Control Boord a CERTIFICATE OF ACCEPTANCE, c.opiel! cf 

which are herewith served upon you. 

Dated:· October 30, 201.2 

Renee Cipriano 

Gabriel Rodriguez 

Amy Antomolli 

SCHIFF HARDIN LLP 

231! South Wacker Drive 

Swte 6600 

Chicago, Illi:oois 60606 

312-258-5500 

aantomolli@scltiffhardin.com 

~ ~ · AmyC.Antoniolli 

ATTACHMENT 1 (, 
Electronic Filing- Received, Clerk's Office, 10/30/2012 

71 

CERTIFICATE OF AC:CEPTANCE 

LA~ t~ !>" A-jlfl f'#'f~~~' cr-<t~Y P->F jo..t l'.t:(" ~ 

I {We), /"L cl. ~"'1 t.. i"1("J>.if>£ Or' having read the opinion 

and order of the .illinois Pollution Control. Board in docket PCB 12426,. dated September 20; 

2012. understand and accept the opinion and order, real.izing that this acceptance renders all 

terms and conditions of the variance set forth in that order binding and enforceable. 

Petitioner: AMEREN ENERGY RESOWCES 

By~ 

• 

~d.-9 ,r Authorized y Ag ~1f==~-- . t 

.. 

Title: Jl., b' f/o;·J~~+- J? .t•Ji/tYo-t-r/"'l.,:,.,-r7;+~ J,;fi!..V,-ct'J 

Date: /'0.- .)D-/2-.. 

Settion 41( a) of the Environmental Protection Act provides that final Board orders may 

.be appealed directly to the llllnois Appellate Court within 35 days after the Board serveS the 

order. 415 ILCS 5/41(a) (2010); see also 35 ru. Adm. Code 101.300( d)(2), 101.906, 102.706. 

lllin!>is Supreme Court Rule 335 establishes filing requirements that apply when the illinois 

Appellate Court, by Statute, directly reviews administrative orders. 172 ill. 2d R. 335. The 

BOard's procedural roles provide that motions for the Board to reconsider or modify its fmal 

orders may be filed with the Board within 35 days after. the order is received. 35. m. Adm. Code 

101.520; see also 35 TIL Adm. Code 101.902, 102.700, 102.702. 

I,, John Th~rriault, Assistant Clerk of th~ lllinois Pollution Control BOard, certify that the 

BOard adopted the above order on September 20, 2012, by a vote of 4-0. 

~~= 

John Therriault, Assistant Clerk 

illinois Pollutio.n Control Board 
Electronic Filing- Received, Clerk's Office, 10/30/2012 

CERTIFICATE OF SERVICE 

I, the undersigned, certi:fY that on this 30th day of October, 2012, I nave served 

electronically the attached CERTIFICATE OF ACCEPTANCE, upon the following persons: 

John TherriaUlt, Assistant Clerk 

Carol Webb, Hearing Oftieer 

illinois Pollution Control Board 

James R. Thompson Center 

Suite 11-500 

100 West Rlindolph 

Chicago, Dlinois 60601 

tllerriai@,ipgb.s!atejL us 

cwebMilipgb.sweJLu~ 

and electronically and by first class mail, postage affixed, upon: 

Gina Roccaforte 

Assistant Counsel 

Division of Legal Colll1Sel 

llfumls Environmental Ptoteetion Agency 

1021 North Grand Avenue, East 

P.O. Box 19276 

Springfield, Illinois 62794,9276 

Renee Cipriano 

Gabriel RodrigueZ: 

Amy AntonioUi 

SCHIFF HARDlN LLP 

233 South Wacker Drive 

Suite6600 

Chicago, lllinois 60606 

3!2~25.8c:5500 

Mml:m:rlolli~S~;hii:Thardin.com 

. ' . 
2012 

R E G I S T E R ~~~:r~~ental Agencies 

Volume 36, Issue 51 

December 21 , 2012 

_ Pages 17636-18064 

Index Department 

Administrative Code Division 

111 E. Monroe St. 

Springfield, IL 62756 

217-782-7017 

Printed by authority of the State of Illinois. December 2012 - 75 

PUBLISHED BY JESSE WHITE· SECRETARY OF STATE 
 i 

TABLE OF CONTENTS

 December 21, 2012 Volume 36, Issue 51

PROPOSED RULES

CENTRAL MANAGEMENT SERVICES, DEPARTMENT OF 

Extensions of Jurisdiction 

 80 Ill. Adm. Code 305..........................................................................17636 

State of Illinois Dependent Care Assistance Plan 

 80 Ill. Adm. Code 2110........................................................................17640 

State of Illinois Medical Care Assistance Plan 

 80 Ill. Adm. Code 2120........................................................................17646 

Commuter Savings Program 

 80 Ill. Adm. Code 2190........................................................................17658 

The Travel Regulation Council 

 80 Ill. Adm. Code 3000........................................................................17663 

FINANCIAL AND PROFESSIONAL REGULATION, DEPARTMENT OF 

Lending Limits 

 38 Ill. Adm. Code 330..........................................................................17671 

HUMAN RIGHTS, DEPARTMENT OF 

Procedures Applicable to All Agencies 

 44 Ill. Adm. Code 750..........................................................................17686 

OFFICE OF THE AUDITOR GENERAL 

Purchases and Contracts 

 44 Ill. Adm. Code 500..........................................................................17694 

PUBLIC HEALTH, DEPARTMENT OF 

Emergency Medical Services and Trauma Center Code 

 77 Ill. Adm. Code 515..........................................................................17778 

SECRETARY OF STATE 

Commercial Driver Training Schools 

 92 Ill. Adm. Code 1060........................................................................17801 

ADOPTED RULES

BOARD OF HIGHER EDUCATION 

Public Information, Rulemaking, and Organization 

 2 Ill. Adm. Code 5050..........................................................................17847 

Grow Your Own Teacher Grants 

 23 Ill. Adm. Code 1085........................................................................17852 

ILLINOIS COMMERCE COMMISSION 

Obligations of Retail Electric Suppliers 

 83 Ill. Adm. Code 412..........................................................................17886 

STATE BOARD OF EDUCATION 

The 'Grow Your Own' Teacher Education Initiative (Repealer) 

 23 Ill. Adm. Code 60............................................................................17911 

WORKERS' COMPENSATION COMMISSION, ILLINOIS 

Arbitration 
 ii 

 50 Ill. Adm. Code 7030........................................................................17913 

Commission Review Board Procedures 

 50 Ill. Adm. Code 7500.......................................................................17920 

PEREMPTORY RULES

AGRICULTURE, DEPARTMENT OF 

Meat and Poultry Inspection Act 

 8 Ill. Adm. Code 125...........................................................................17930 

OTHER INFORMATION REQUIRED BY LAW TO BE PUBLISHED IN THE 

ILLINOIS REGISTER

IL ENVIRONMENTAL PROTECTION AGENCY 

Notice of Public Information......................................................................17938 

REGULATORY AGENDA

ATTORNEY GENERAL 

Attorney General's Procurement 

 44 Ill. Adm. Code 1300.......................................................................17940 

BOARD OF HIGHER EDUCATION 

Performance Metrics for Budget Recommendations 

 23 Ill. Adm. Code 900.........................................................................17944 

POLLUTION CONTROL BOARD 

General Rules 

 35 Ill. Adm. Code 101.........................................................................17947 

PROPERTY TAX APPEAL BOARD 

Practice and Procedure for Hearings Before the Property Tax Appeal Board 

 86 Ill. Adm. Code 1910.......................................................................18028 

SECOND NOTICES RECEIVED

JOINT COMMITTEE ON ADMINISTRATIVE RULES 

Second Notices Received............................................................................18030 

EXECUTIVE ORDERS AND PROCLAMATIONS

PROCLAMATIONS 

Electoral Proclamation - Constitutional Amendment 

 2012-353..............................................................................................18032 

Electoral Proclamation - Electoral College Electors 

 2012-354..............................................................................................18032 

Electoral Proclamation - Electoral College 

 2012-355..............................................................................................18033 

Electoral Proclamation - Congress, Senators and Representatives 

 2012-356..............................................................................................18036 

Electoral Proclamation - Regional Superintendents of Schools 

 2012-357..............................................................................................18047 

Electoral Proclamation - Trustees of the Prairie Dupont Levee 

and Sanitary District 

 2012-358..............................................................................................18048 

Electoral Proclamation - Judicial Vacancies 

 2012-359..............................................................................................18049 

Electoral Proclamation - Retention 
 ILLINOIS REGISTER 17938

 12 

ENVIRONMENTAL PROTECTION AGENCY 

NOTICE OF PUBLIC INFORMATION 

The Illinois Environmental Protection Agency (Illinois EPA) Bureau of Air is accepting public 

comment on variances granted by the Illinois Pollution Control Board (Board) to Midwest 

Generation, LLC - Waukegan Generating Station (Midwest Generation) and Ameren Energy 

Resources (Ameren) for the purpose of submitting such variances to the United States 

Environmental Protection Agency (USEPA) as a revision to the Illinois State Implementation 

Plan (SIP) under the Clean Air Act (CAA), 42 USC § 7401 et seq. In order for a variance to be 

considered for approval as a revision to the SIP, the State must submit it in accordance with the 

requirements of 40 Code of Federal Regulations (CFR) § 51.104. 

On April 10, 2012, Midwest Generation requested a variance from the provisions of the Illinois 

Combined Pollutant Standard (CPS), 35 Ill. Adm. Code 225.296(a)(l) and (c)(1), for the 12-

month period beginning December 31, 2013, and ending December 31, 2014, thereby allowing 

Midwest Generation an extra year to install pollution controls on Unit 7 at its Waukegan 

Generating Station. Midwest Generation, LLC – Waukegan Generating Station v. Illinois 

Environmental Protection Agency, PCB 12-121. On August 23, 2012, the Board granted the 

variance to Midwest Generation, subject to certain conditions. 

On May 3, 2012, Ameren, with power plants in Montgomery County, Fulton County, Peoria 

County, Massac County, Crawford County, Morgan County, and Jasper County filed a Petition 

for Variance with the Board. Ameren Energy Resources v. Illinois Environmental Protection 

Agency, PCB 12-126. Ameren requested a variance from both the 2015 and 2017 sulfur dioxide 

(SO2) emission rate provisions of the Illinois Multi-Pollutant Standard (MPS), 35 Ill. Adm. Code 

225.233, specifically the SO2 emission standards set forth in Section 225.233(e)(3)(C)(iii) and 

(iv). On September 20, 2012, the Board granted the variance for the electrical generating units in 

Ameren's MPS Group from the applicable requirements of 35 Ill. Adm. Code 

225.233(e)(3)(C)(iii) for a period beginning January 1, 2015, through December 31, 2019, and 

35 Ill. Adm. Code 255.233(e)(3)(C)(iv) for a period beginning January 1, 2017, through 

December 31, 2019, subject to certain conditions. 

The CPS and MPS are a multi-pollutant comprehensive approach to reduce emissions of nitrogen 

oxides, SO2, and mercury. Sections 225.233(e) and 225.296(a) and (c) are approved rules of the 

Illinois SIP. On July 6, 2012, the USEPA approved the Illinois plan submitted to address the 

visibility protection requirements of Section 169A of the CAA, 42 U.S.C. § 7491, and the 

Regional Haze Rule, as codified in 40 CFR § 51.308. See, 77 Federal Register 39943 (July 6, 

2012). The Illinois plan includes Sections 225.233(e) and 225.296(a) and (c). Accordingly, 

since the petitions for variance sought relief from provisions of the CPS and MPS and such relief 

was granted by the Board, the variances must be submitted to the USEPA for approval as a SIP 

revision addressing the visibility requirements under the CAA and the Regional Haze Rule. 
 ILLINOIS REGISTER 17939

 12 

ENVIRONMENTAL PROTECTION AGENCY 

NOTICE OF PUBLIC INFORMATION 

The Illinois EPA will accept written comments from the public. The written comments must be 

postmarked by January 21, 2013, unless a public hearing is requested. Comments and requests 

for hearing should be mailed to: 

Dean Studer, Hearing Officer 

Illinois EPA 

1021 North Grand Avenue East 

P.O. Box 19276 

Springfield, Illinois 62794-9276 

Telephone: 217/558-8280 or TDD: 217/782-9143 

If a timely request for a public hearing is received by January 21, 2013, a public hearing will be 

scheduled through a separate notice and held to receive comments regarding the proposed SIP 

revision. If a public hearing is conducted, the written public comment period will be extended as 

provided for in the separate notice. 

If no request for a public hearing is received by the Illinois EPA by U.S. Mail, carrier mail,

or hand delivered by January 21, 2013, no hearing will be scheduled. Verification of a 

public hearing will be posted on January 28, 2013, on the Illinois EPA's website at 

http://www.epa.state.il.us/public-notices/. Interested persons may also contact Dean Studer, the 

Illinois EPA’s Hearing Officer, at the phone number listed above to inquire as to the status of a 

public hearing. 

Copies of the proposed SIP revision may be viewed by the public on Illinois EPA's website at 

http://www.epa.state.il.us/public-notices/ or during regular business hours (Monday through 

Friday 8:30 a.m. until 4:30 p.m, except for State holidays) at the following Illinois EPA offices: 

1021 North Grand Avenue East, Springfield, Illinois; 9511 W. Harrison St., Des Plaines, Illinois; 

and 2009 Mall Street, Collinsville, Illinois. No walk-in requests for copies of this material will 

be accommodated, unless advance notice is provided. Requests and public inquiries should be 

directed to Dean Studer, the Illinois EPA's Hearing Officer, at the address and phone number 

listed above. 

If a hearing request is received, the hearing will be held in accordance with the provisions of the 

Illinois EPA's "Procedures for Informational and Quasi-Legislative Public Hearings," set forth at 

35 Ill. Adm. Code 164. This notice is intended to satisfy the requirements of Section 110(l) of 

the CAA (42 USC § 7410(l) (public notice for SIP revisions)). 
No Public Hearing Requested 

On December 21,2012, the Illinois Environmental Protection Agency published a Notice of 

Public Information in the Illinois Register noticing a public conunent period on variances 

granted by the Illinois Pollution Control Board to Midwest Generation, LLC- Waukegan 

Generating Station and Ameren Energy Resources tor the pm1Jose of submitting such variances 

to the United States Environmental Protection Agency as a revision to the Illinois Stale 

Implementation Plan under the Clean Air Act. See, 36 Ill. Reg. 17938. Provision was also given 

in the notice for a public hearing to be scheduled in this matter, if a timely request for a public 

hearing was received by January 21, 2013. 

Pursuant to the published notice, the Illinois EPA is required to post verification of a public 

hearing on its website on January 28, 2013. Since no request for a public hearing has been 

received, no hearing will be scheduled. The public comment period has ended, but the Illinois 

EPA will accept any public comments in this matter that have been postmarked on or before 

January 21, 2013. 

~-~ Dated: January 25, 2013 

Dean Studer 

H caring Officer 
February 13, 2013 

Response to Comments Submitted by Sierra Club 

Background 

Illinois EPA received comments on January 19,2013, regarding proposed revisions to the Illinois 

Regional Haze SIP. The c01mnents were in response to proposed revisions to the SIP to reflect 

variances granted to Ameren and Midwest Generation allowing revisions to how the companies 

will be implementing some provisions of the MPS and CPS. 

In general, Sierra Club's c01mnents conflict with the interpretations ofboth Illinois EPA and 

USEPA regarding Regional Haze SIP requirements, as well as the interpretation of the Federal 

Land Managers and others consulted in the original Regional Haze SIP submittal. 

Attached to the January 19 Sierra Club cOJmnents was a document containing older c01mnents 

previously submitted by the Environmental Law and Policy Center ("ELPC"), Little Village 

Enviromnental Justice Organization, National Parks Conservation Association, Respiratory 

Health Association of Metropolitan Chicago, and Sierra Club itself dating back to the COJmnent 

period for the original SIP submittal. These c01mnents were already addressed and rejected by 

USEPA in the original approval oflllinois' Regional Haze SIP. As such, there is little reason to 

rehash each of the previously-submitted individual co1mnents, so the focus of the remainder of 

this response is on the January 19 c01mnents. However, it is first worth noting what USEPA's 

response had to say regarding the previous c01mnents that were submitted that Sierra Club was a 

party to, though they are referred to as co1mnents from.ELPC. The response is taken from 

USEPA's approval of Illinois' alternative plan in the Regional Haze SIP and addresses the 

previously stated concerns regarding the alternative plan: 

ELPC appears to misunderstand the applicable test for alternate strategies for 

addressing BART. In particular, ELPC appears to believe that under the alternative 

approach, Illinois must require BART-level controls at each unit subject to BART. 

In fact, the underlying principle of EPA's guidance on alternative measures is to 

offer states the flexibility to require less control at BART units than BART-level 

control, provided the states provide additional control at non-BART units that more 

than compensates for any degree to which control at BART units falls short of 

BART. Illinois is using precisely this flexibility. Irrespective of the degree to which 

control at individual power plant BART units may be less stringent than the limits 

that for those particular units would be defined as BART, Illinois is requiring 

control across a universe of sources that includes many sources that are not subject 

to BART, thereby providing reductions that under EPA's rules and BART 

guidelines on alternative measures can compensate for any shortfall in control at 

BART units1 

1 77 Fed. Reg. 39945 (July 6, 2012). 
Sierra Club's Further Objections 

In the beginning of Sierra Club's new cmmnents, they claim that "IEPA cannot revise the SIP to 

reflect these variances because these variances are in violation of the Illinois' Regional Haze 

SIP." However, this entire process is taking place because Illinois EPA has proposed revisions to 

the Regional Haze SIP so that the provisions of the variances are included in the SIP. As such, 

Sierra Club's statement is self-contradictory. 

Sierra Club goes on to detail reasons it believes the revisions would not be consistent with 

Regional Haze Rule requirements in 40 CFR 51, as discussed below. 

Sierra Club again objects to Illinois EPA utilizing an altemative emissions reduction plan, as it 

did in the initial SIP submittal, because in order to do so a state is required to meet three criteria: 

Under current regional haze regulations, to utilize an altemative emissions reduction 

program instead of BART, a state must meet several requirements. Crucially, the 

state must "demonstrate that an emissions trading program or other alternative will 

achieve greater reasonable progress [toward natural visibility conditions] than would 

have resulted from the installation and operation of BART at all sources subject to 

BART in the State and covered by the alternative program." 40 C.F.R. § 

51.308(e)(2)(i). Second, a State must require that "all necessary emissions 

reductions take place during the period of the ftrst long-term strategy for regional 

haze." 40 C.F.R. § 51.308(e)(2)(iii). Third, a State must demonstrate that "the 

emissions reductions resulting from the ... alternative measure will be surplus to 

those reductions resulting from measures adopted to meet requirements if the CAA 

as of the baseline date of the SIP." 40 C.F.R. § 51.308(e)(2)(iii). 

Sierra Club claims that revising the SIP to include the variances would mean that (1) Illinois' 

altemative plan would not "achieve greater reasonable progress" toward natural visibility goals, 

and (2) that "all necessary emissions reductions" will not "take place during the period of the first 

long tenn strategy for regional haze." 

The first assertion, that the Illinois plan including the variances will not achieve greater progress 

toward natural visibility goals, was raised in the aforementioned initial co1mnents and was 

dismissed in USEPA's approval of the SIP. Illinois EPA, in technical support documents, 

provided a demonstration that the reductions in S02 and NOx emissions would be far greater 

under the altemative plan than if BART control had been applied to only the units subject to 

BART. The variances in question apply only to S02 reductions, so the remainder of this response 

will be limited to S02. 

Ameren Variance 

Illinois EPA estimated that applying BART to Ameren's subject-to-BART units would result in a 

reduction of69,154 tons ofS02 annually from baseline emissions at the end of the first long-term 

strategy period in 20182. Illinois EPA also estimated that applying a fleet-wide average of0.23 

2 Technical Support Document for Best Available Retrofit Technology Under the Regional Haze Rule, AQPSTR 09-

06, April29, 2011, at 30. 

2 
lbl!runBtu to all Ameren units, per the MPS, would result in a reduction of 134,464 tons ofS02 

annually in 2018 fi-mn baseline emissions. If Illinois' Regional Haze SIP were revised to reflect 

the Ameren variance, Illinois EPA estimates that applying a fleet-wide average of0.35lb/mmBtu 

to all Ameren units would result in a reduction of 115,920 tons ofS02 annually in 2018 from 

baseline emissions. Tins clearly satisfies the criteria that (1) "greater reasonable progress" toward 

natural visibility goals is achieved. 

The above estimates show reductions of194% of the anticipated BART-only reductions in the 

originally-approved alternative plan, and reductions of I 67% compared to BART -only reductions 

when the SIP is revised to reflect the variance in the alternative. This addresses Sierra Club's 

second assertion that (2) the altemative plan including the variance does not ensure that "all 

necessary emissions reductions" will "take place during the period of the first long term strategy 

for regional haze." In fact, the above estimates demonstrate that anticipated reductions in 2018, at 

the end of the first Iong-tenn strategy period, will still be greater than the reductions required by 

BART. While the variance for Ameren delays the fleet-wide average of0.23 lbhrunBtu for three 

years to 2021, "all necessary emissions reductions"- and more- will indeed "take place during 

the period of the first long term strategy for regional haze." Additionally, greater reductions will 

continue after 2021 when the variance ends and will continue in perpetuity thereafter. 

The estimates above are based upon the BART TSD that was included in the initial SIP submittal. 

The smrunary table from that document can seen below in Table I along with an additional two 

columns of that table that show estimates of reductions reflecting the proposed revisions to 

include the variance. The base year in this table is 2002, and estimates are given for reductions 

due to implementing BART control on subject-to-BART units only, reductions from the MPS in 

2018, and the added estimates for reductions from the alternative plan including the variance. 

Figures above are a comparison of Ameren fleet-wide reductions for each scenario totaled at the 

bottom of these colmm1s. 

Midwest Generation Variance 

The variance granted to Midwest Generation, again only addressing S02, does not affect emission 

reductions anticipated in 2018 at the end of the first long-term strategy. Thus, (1) the reductions 

in 2018 in the alternative plan that were approved in the original SIP submittal are unchanged by 

the variance, and (2) these reductions will take place in the first long-tenn strategy period. 

Further, due to the shutdowns of Midwest Generation's Fisk and Crawford units, reductions by 

2018 and over the duration of the first long-tenn strategy period will be much greater than in the 

original approved alternative plan. 

Table 2 was also taken from the BART TSD included in the initial SIP submittal. Again the final 

two columns of the table have been added to show estimates of reductions that reflect the 

proposed revisions to include the variance3 It can be seen in this table that due to the shutdowns 

of the Crawford and Fisk units, there will be additional reductions of34,654 tons per year in 2018 

beyond what were anticipated in the originally submitted alternative plan, providing a total of 

270% of the necessary reductions for BART. 

3 Technical Support Document for Best Available Retrofit Technology Under the Regional Haze Rule, AQPSTR 09-

06, April29, 2011, at 33. 

3 
Updated S02 Estimates 

Table 1. Ameren Estimates from Illinois EPA BART TSD and Reductions Updated for Variance 

-c- Variance Adjusted . Base Year Pres urn tive BART MPS Final .· I· 201a 

. ·· Lbs/ Lbs/ .. 

1000 Tons/Year Lbs/ .·· Tons/Year Lbs/ Tons/Ye'ar 

Plant Unit mmBTU mmBTU Tons mmBTU Reduction mmBTU Reduction mmBTU Reduction 

Coffeen 1 18,570 1.54 14,332 0.15 12,906 0.23 12,163 0.35 11,082 

Coffeen 2 37,545 1.49 27,999 0.15 25,155 0.23 23,653 0.35 21,429 

Duck 

Creek 1 22,635 0.97 11,026 0.15 9,280 0.23 8,375 0.35 7,065 

ED 

Edwards 1 6,417 3.55 11,399 NA NA 0.23 10,652 0.35 10,276 

ED 

Edwards 2 17,222 1.7 14,666 0.15 13,347 0.23 12,658 0.35 11,652 

ED 

Edwards 3 15,972 1.21 9,683 0.15 8.465 0.23 7,826 0.35 6,888 

Hutsonville 5 3,161 4.53 7,163 NA NA 0.23 6,796 0.35 6,610 

Hutsonville 6 3.443 4.53 7,791 NA NA 0.23 7.402 0.35 7,188 

Joooa 1 13,548 0.51 3.441 NA NA 0.23 1,897 0.35 1,070 

Joooa 2 16,258 0.51 4,139 NA NA 0.23 2,276 0.35 1,294 

Jonna 3 15,396 0.51 3,947 NA NA 0.23 2,155 0.35 1,253 

Joppa 4 13.402 0.52 3,488 NA NA 0.23 1,943 0.35 1,143 

Joppa 5 15,094 0.52 3,932 NA NA 0.23 2,189 0.35 1,291 

Joooa 6 16,063 0.52 4,182 NA NA 0.23 2,329 0.35 1,371 

Meredosia 1 1,134 5.02 2,844 NA NA 0.23 2,716 0.35 2,646 

Meredosia 2 1,337 5.02 3,356 NA NA 0.23 3,202 0.35 3,122 

Meredosia 3 1,069 5.04 2,694 NA NA 0.23 2,571 0.35 2,507 

Meredosia 4 1.406 5 3,518 NA NA 0.23 3,353 0.35 3,272 

Meredosia 5 10,810 2.34 12,639 NA NA 0.23 11,405 0.35 10,747 

Newton 1 40,631 0.45 9,046 NA NA 0.23 4.469 0.35 1,936 

Newton 2 38,533 0.46 8,823 NA NA 0.23 4.431 0.35 2,080 

1.099 69,154 134,464 115,920 

4 
Table 2. Midwest Generation Estimates from Illinois EPA BART TSD and Reductions Updated for Variance 

. . · . .... I . Variance Adjusted 

BaseY ear , 'Presum tive BART CPS Final . 2018 

· .. ·. 1000 Lbs/ . 

Lbs/ Tons/Year Lbs/ Tons/Year Lbs/ Tons/Year 

Plant Unit mmBTU mmBTU Tons mmBTU Reduction mmBTU RedUction mmBTU Reduction 

Crawford 7 11,627 0.54 3,142 NA NA 0.11 2,500 0 11,627 

Crawford 8 17,348 0.51 4,453 NA NA 0.11 3,470 0 17,348 

Fisk 19 14,650 0.52 3,843 NA NA 0.11 3,003 0 14,650 

Joliet 29 71 15,034 0.7 5,276 0.15 4,134 0.11 4,435 0.11 4,435 

Joliet 29 72 13,824 0.7 4,828 0.15 3,802 0.11 4,078 0.11 4,078 

Joliet 29 81 15,585 0.68 5,300 0.15 4,130 0.11 4,442 0.11 4,442 

Joliet 29 82 15,403 0.68 5,260 0.15 4,082 0.11 4,390 0.11 4,390 

Joliet 9 5 14,369 0.63 4,559 NA NA 0.11 3,736 0.11 3,736 

Powerton 51 20,936 0.42 4,444 0.15 2,826 0.11 3,245 0.11 3,245 

Powerton 52 21 '137 0.43 4,497 0.15 2,959 0.11 3,382 0.11 3,382 

Powerton 61 18,293 0.43 3,964 0.15 2,561 0.11 2,927 0.11 2,927 

Powerton 62 18,088 0.43 3,909 0.15 2,532 0.11 2,894 0.11 2,894 

Waukegan 17 7,502 0.44 1,642 NA NA 0.11 1,238 0.11 1,238 

Waukeoan 7 16,117 0.47 3,754 NA NA 0.11 2,901 0.11 2,901 

Waukegan 8 21,950 0.49 5,385 NA NA 0.11 4,171 0.11 4,171 

Will 

County 1 9,398 0.42 1,969 NA NA 0.11 1,457 0.11 1,457 

Will 

County 2 8,293 0.39 1,617 NA NA 0.11 1 '161 0.11 1 '161 

Will 

County 3 15,559 0.47 3,636 NA NA 0.11 2,801 0.11 2,801 

Will 

County 4 27,585 0.47 6,462 0.15 4,414 0.11 4,965 0.11 4,965 

0.515 31,440 61,194 95,848 

5 
!SIERRA 

1 CLUB --------

T 0 U!'•n>r 0 Hi 1..12 

January 19, 2013 

VIA Electronic Mail and U.S. Postal Service, First Class Mail 

Dean Studer, Hearing Officer 

Illinois EPA 

1021 North Grand Avenue East 

P.O. Box 19276 

Springfield, Illinois 62794·9276 

dean. studer@illinois. gov 

RE: Revising Illinois State Implementation Plan to Reflect Variances Granted by 

the Illinois Pollution Control Board to Midwest Generation and Ameren 

Dear Mr. Studer, 

On behalf of Sierra Club, I thank you for considering these comments on the 

Illinois Environmental Protection Agency's ("IEP A:') recent proposal to revise the 

Illinois' State Implementation Plan ("SIP") to reflect variances to the Illinois Multi· 

Pollutant Standard ("MPS"), 35 Ill. Adm. Code 225.233, and the Illinois Combined 

Pollutant Standard ("CPS"), 35 Ill. Adm. Code 225.296(a)(l) and (c)(1), granted by 

the Illinois Pollution Control Board to Ameren Energy Resources ("Ameren") and 

Midwest Generation. IEP A cannot revise the SIP to reflect these variances because 

these variances are in violation of the Illinois' Regional Haze SIP. 

In 1999, EPA promulgated the Regional Haze Rule. Regional Haze 

Regulations, 64 Fed. Reg. 35,714 (July 1, 1999). Under that Rule, states are directed 

to submit SIPs containing emissions limitations representing Best Available 

Retrofit Technology ("BART") and schedules for compliance for each BART· eligible 

source that may be anticipated to cause or contribute to any visibility impairment 

in a Class I area. See40 C.F.R. § "51.308(e). 

1 
On June 24, 2011, Illinois submitted a proposed Regional Haze SIP to EPA 

77 Fed. Reg. 3966. In its Proposed SIP, Illinois stated that, based on modeling 

completed by the Midwest Regional Planning Organization ("MRPO"), it determined 

that emissions sources in the state cause or contribute to visibility degradation in 

19 national parks and wilderness areas (defined in the CAA as "Class I areas") .I 

Illinois EPA, Regional Haze State Implementation Plan for Illinois, AQPSTR 10-08 

(May 10, 2011) at 8-12 (hereafter "Illinois Regional Haze SIP"). To comply with the 

BART provisions of the Regional Haze Rule, Illinois evaluated which emissions 

sources within the state cause or contribute to visibility degradation in those Class I 

areas. 

Illinois concluded that 11sources, including 9 Electric Generating Units 

("EGUs"), cause or contribute to visibility degradation and are thus "subject to 

BART." Illinois EPA, Technical Support Document For Best Available Retrofil 

Technology Under the Regional Haze Rule, AQPSTR 09-06 (Apr. 29, 2011) 

(hereafter "Illinois TSD for BART") at 12-22. Instead of evaluating and determining 

BART for all of those sources, Illinois proposed that an "alternative" to BARTostensibly permitted under the Regional Haze Rule- be used for 7 ofthe 9 EGUs. 

Illinois Regional Haze SIP at 19. Specifically, Illinois proposed that the Multi 

Pollutant Standard/Combined Pollutant Standard be relied on in lieu of BART to 

minimize visibility degradation caused or contributed to by those 7 EGUs. Id On 

July 6, 2012, the U.S. Environmental Protection Agency ("U.S. EPA:') approved the 

Illinois plan submitted to address the visibility protection requirements of Section 

169A of the CAA, 42 U.S. C.§ 7491, and the Regional Haze Rule, as codified in 40 

CFR § 51.308. See, 77 Fed. Reg. 39943 (July·6, 2012). 

Under current regional haze regulations, to utilize an alternative emissions 

reduction program instead of BART, a state must meet several requirements. 

Crucially, the state must "demonstrat[e] 2 that an emissions trading program or 

other alternative will achieve greater reasonable progress [toward natural visibility 

conditions] than would have resulted from the installation and operation of BART 

at all sources subject to BART in the State and covered by the alternative program." 

40 C.F.R. § 51.308(e)(2)(i). Second, a State must require that "all necessary 

1 Those 19 national parks and wilderness areas are: Sipsey Wilderness Area, Alabama; Caney Creek 

Wilderness Area, Arkansas; Upper Buffalo Wilderness Area, Arkansas; Mammoth Cave National 

Park, Kentucky; Acadia National Park, Maine; Moosehorn Wilderness Area, Maine; Isle Royale 

National Park, Michigan; Seney Wilderness Area, :Michigan; Boundary Waters Canoe Area 

Wilderness, Minnesota; Voyageurs National Park, Minnesota; Hercules-Glades Wilderness Area, 

:Missouri; lvlingo Wilderness Area, :Missouri; Great Gulf Wilderness Area, New Hampshire; 

Brigantine Wilderness Area, New Jersey; Great Smoky Mountains National Park, Tennessee and 

North Carolina; Lye Brook Wilderness, Vermont; James River Face Wilderness Area, Virginia; 

Shenandoah National Park, Virginia; and Dolly Sods/Otter Creek Wilderness, West Virginia. Illinois 

Regional Haze SIP at 12. 2 A state's determination that an alternative will achieve greater reasonable process than would the installation and 

operation of BART must be based on the clear weight of the evidence. 40 C.F.R. § 51.308(e)(2)(i)(E). 

2 
emissions reductions take place during the period of the first long·term strategy for 

regional haze." 40 C.F.R. § 5L308(e)(2)(iii). Third, a State must demonstrate that 

"the emissions reductions resulting from the ... alternative measure will be surplus 

to those reductions resulting from measures adopted to meet requirements if the 

CAA as of the baseline date of the SIP." 40 C.F.R. § 5L308(e)(2)(iii). 

Revising the SIP to reflect the variances granted by the Illinois Pollution 

Control Board to Ameren and Midwest Gen would mean that the Illinois MPS/CPS 

fails to meet two of the three requirements needed to rely on an alternative to 

BART8 

Fi"rst, the MPS/CPS with the Ameren and Midwest Gen variances will not 

"achieve greater reasonable progress" toward natural visibility conditions than 

would the installation and operation of BART. 40 C.F.R. § 5L308(e)(2)(i). In our 

comments on Illinois' Proposed Regional Haze SIP, Sierra Club noted several 

reasons why the MPS/CPS would not achieve greater reasonable progress toward 

natural visibility conditions than BART.4 Despite all of these reasons why the 

MPS/CPS was more deficient than a BART determination, the U.S. Environmental 

Protection Agency found that the state standards would achieve greater reasonable 

progress because it applied to more facilities than the Regional Haze Rule. It was 

the fact that these non-BART sources were also regulated that allowed the U.S. 

Environmental Protection Agency to find that the state rules provided greater 

reasonable progress. 5 If IEP A were to revise the state SIP to reflect the variances 

granted by the Illinois Pollution Control Board, then it would completely undercut 

EPA's rationale for this finding. For instance, EPA noted that in the case of 

Ameren, three of its power plants meet the criteria for being subject to BART, and 

five coal-fired plants are governed by the sulfur dioxide ("S02") and NOx limits in 

the MPS. 77 Fed. Reg. at 39,943. After the variance, all five coal-fired plants 

governed by the MPS do not have to comply with the 2015 and 2017 sulfur dioxide 

("S02") emission rate provisions of the MPS. The variance, thus, completely 

eliminates the rationale for finding that the MPS/CPS is an acceptable BART 

3 Sierra Club believes that reliance on the 111PS/CPS even before the variances were granted, violated 

the Clean Air Act. See Comments submitted in docket ID No. EP A-R05-0AR-2011·0598. 

4 Sierra Club's Comments on Illinois' Proposed Regional Haze Rule are attached hereto and 

incorporated by reference. 5 77 Fed. Reg. at 39943 Qllinois' submittal includes letters from the affected companies choosing the 

option that includes S02 and NOX emission limits, which pursuant to Illinois' rules establishes 

these limits as enforceable limits. In the case of Midwest Generation, three ofits power plants meet 

the criteria for being subject to BART, and six plants are governed by the S02 and NOX limits in the 

Multi-Pollutant Standards .... In the case of Ameren, three of its power plants meet the criteria for 

being subject to BART, and five coal-fired plants are governed by the S02 and NOX limits in the 

(CPS). In the notice of proposed rulemaking, EPA proposed to conclude that the emission reductions 

from the Cli1PS) and the (CPS) would be greater than the reductions that would 

occur with unit· specific implementation of BART on the subset of these sources that meet the 

criteria for being subject to BART. 

3 
alternative as it will not achieve greater reasonable progress toward natural 

visibility conditions. 

Second, the MPS/CPS with the Ameren and Midwest Gen variances will 

mean that "all necessary emissions reductions" will not "take place during the 

period of the first long·term strategy for regional haze." 40 C.F.R. § 51.308(e)(2)(iiil. 

The period of the first long·term strategy for regional haze ends in 2018. 40 C.F.R. § 

51.308(£). The Ameren variance pushes the already-inadequate emissions 

reductions required by the MPS to three years after that period ends. To revise the 

SIP to reflect this variance would mean that the Illinois' SIP fails to ensure that "all 

necessary emissions reductions take place during the period of the first long·term 

strategy for regional haze." 

In summary, because the standards on which the U.S. Environmental 

Protection Agency relied to find that the state· based standards are an adequate 

alternative to BART would be eliminated if the Ameren and Midwest Gen variances 

were incorporated into the SIP, Illinois must not revise its SIP as it would be in 

violation ofthe Clean Air Act. 

Please do not hesitate to contact undersigned counsel with any questions or 

concerns. 

cc: gina.roccafort.e@illinois.gov 

4 

Sincerely, 

Kristin Henry, Staff Attorney 

Sierra Club 

85 Second Street 

San Francisco, CA 94105 

Phone: (415) 977-5716 

Fax: (415) 977-5793 

kristin.henrv(al,sierraclub. org 
February 27, 2012 

Attention Docket 1D No. EPA-R05-0AR-2011-0598 

Regarding: Approval and Promulgation of Air Quality Implementation Plans; 

Illinois; Regional Haze; 77 Fed. Reg. 3966 (Jan. 26, 2012) 

I. INTRODUCTION 

On behalf of the Environmental Law and Policy Center, Little Village Environmental 

Justice Organization, National Parks Conservation Association, Respiratory Health Association 

of Metropolitan Chicago, and Sierra Club, we thank you for considering these comments on the 

Environmental Protection Agency's recent proposal to approve and promulgate Illinois' 

Regional Haze State Implementation Plan ("SIP"). 

For the reasons explained herein, EPA cannot approve Illinois' Regional Haze SIP. First, 

EPA must reject Illinois' proposal to rely on the Multi-Pollutant Standard/Combined-Pollutant 

Standard ("MPS/CPS") 1 in lieu of BART for numerous sources subject to BART in the state. 

The plain language of the Clean Air Act ("CAA'') requires installation and operation of BART to 

achieve reasonable progress toward meeting the national goal of eliminating visibility 

impairment at Class I areas. See CAA § 169A(b)(2)(A); 42 U.S.C. § 749l(b)(2)(A). Further, 

even if it were legally permissible for EPA to authorize states to rely on alternative programs to 

opt out of BART, the MPS/CPS cannot substitute for BART for several readily apparent reasons: 

• In evaluating the MPS/CPS as an alternative to BART, Illinois was required to make a 

source-specific BART determination for each source subject to BART in the state. 40 

C.F.R. § 51.308(e)(2). Illinois did not do so. 

• Under applicable regulations, alternatives to BART may only be approved if they 

"achieve greater reasonable progress toward natural visibility conditions" than would the 

installation and operation of BART. 40 C.P.R.§ 51.308(e)(2)(i). The MPS/CPS does not 

satisfy that requirement, because 

o BART would require some additional controls at facilities subject to BART,2 

whereas MPS/CPS does not require any additional controls at those sources; 3 

1 35 Ill. Admin. Code§ 225.233, known as the Multi-Pollutant Standard ("MPS"), applies to plants in Illinois owned 

by Ameren and Dynegy. 35 Ill. Admin. Code § 225.293-299, referred to as the Combined Pollutant Standard 

("CPS"), covers Illinois facilities owned by Midwest Generation ("MWG"). 2 See 42 U.S.C. § 7492(g)(2); 40 C.F.R. § 51.308(e)(l)(ii). 3 Although the CPS does contain requirements that MWG install particular types of controls (i.e., activated carbon 

injection, flue gas desulfurization) at certain plants, the CPS contains no equipment requirements at all for the M\VG 

boilers subject to BART. See 35 Ill. Admin. Code §225.293-299. Likewise, the MPS has no control requirements 

for any plants subject to it; however, a consent decree signed by Dynegy, the U.S. EPA, Illinois and other 

intervenors in 2005 requires installation of control equipment at Dynegy's Baldwin plant. See 

http://www.epa.gov/compliance/resources!cases/civil!caa/illinoispower.html. That consent decree is available at 

http://www.epa.gov/compliance/resources/decrees/civil/caa/dmgfinal-cd.pdf (last visited Feb. 21, 20 12). 
o If Illinois perfonned an adequate, source-specific BART analysis for each source 

subject to BART that is covered under the MPS/CPS, Illinois would determine 

that BART would require steeper reductions than MPS/CPS requirements; 

o The MPS/CPS is weaker than even the seven year-old presumptive BART limits, 

because (i) the MPS/CPS's fleetwide average requirements exceed presumptive 

BART in several instances, and MWG and Ameren need not meet even those 

weak requirements at their plants subject to BART; (ii) MPS/CPS emission limits 

are based on a much longer averaging period than presumptive BART limits; and 

(iii) Even presumptive BART, which would be inadequate for each subject-toBART unit in Illinois, would require better control equipment than the equipment 

which Illinois is allowing to be installed at plants subject to BART. 

• Illinois was required, but failed, to ensure that "all necessary emissions reductions take 

place during the period of the first long-term strategy for regional haze." 40 C.F.R. § 

51.308(e) (2)(iii). 

• Governing regulations require that BART alternatives provide emission reductions 

surplus to those resulting from programs implemented to meet other requirements of the 

Clean Air Act. See 40 C.F.R. § 51.308(e)(2)(iv).lt is not clear that the MPS/CPS, which 

may be proposed by Illinois as a mechanism to implement the Transport Rule4 in the 

state, can satisfY this requirement. 

Moreover, the BART determination for Dominion's Kincaid plant- a plant not covered 

by the MPS/CPS- cannot stand, because: (i) Dominion's BART analysis failed to compare 

"apples to apples" in evaluating the emissions reductions that would be achieved by different 

control technologies, leading to the illogical and incorrect conclusion that the least effective 

control technology will result in the greatest decrease in visibility impacts; and (ii) the emission 

limits set as BART for Kincaid are based on a much longer averaging period than BART limits. 

Finally, Illinois' Long-Term Strategy ("LTS") is deficient because Illinois relies heavily 

on the MPS/CPS and the Transport Rule to satisfY the requirement that it include in its SIP "all 

measures necessary to obtain its share of the emission reductions needed to meet the progress 

goal[s]" at Class I areas for which Illinois sources contribute to visibility impairment. Neither 

the MPS/CPS nor the Transport Rule ensure that emissions reductions will be made to help 

achieve reasonable progress goals from two highly-polluting coal plants, Joppa and Marion, 

which are near Class I areas. See 40 C.F.R. § 51.308. These and other issues are discussed in 

further detail below. 

4 See Federal Implementation Plans: Interstate Transport of Fine Particulate Matter and Ozone and Correction of 

SIP approvals, 76 Fed. Reg. 48208 (Aug. II, 2011). 

2 
II. BACKGROUND 

A. The Clean Air Act's Visibility Program: Protecting Public Lands and People 

The Clean Air Act's visibility program requires elimination of visible air pollution at the 

country's national parks, wilderness areas, and other premier public lands, encompassing a total 

of !56 protected public lands that include many of the nation's most iconic vistas. Preservation 

of these views has an obvious and demonstrable intrinsic value; as National Park Service studies 

confinn, visitors' enjoyment of a national park is tied to visibility.5 Preserving visibility also 

helps sustain the healthy tourism industry centered on visits to the nation's iconic landmarks. 

The same National Parks Service surveys demonstrate that visibility conditions affect the amount 

of time and money visitors are willing to spend at national parks.6 In 20 I 0 alone, national parks 

tourism contributed approximately $3 I billion to the United States economy, sustaining over 

250,000 jobs.7 Nevertheless, EPA has recognized that longstanding visibility problems that have 

continued to mar the landscape and obscure views of our most treasured -and economically 

important-landmarks. For example, EPA notes that, "[i]n most of the eastern [National Parks] 

of the United States, the average visual range is less than 20 miles, or about one-fifth of the 

visual range that would exist under estimated natural conditions." 76 Fed. Reg. 82219, 82222. 

While the visibility program primarily seeks to preserve the iconic vistas across the 

country, the program provides important ancillary health benefits as well. Haze-forming 

pollutants, including sulfur dioxide ("S02") and nitrogen oxides (''NOx"), also contribute to 

health problems, meaning that any program that requires controls to target and reduce these 

pollutants will also improve public health. For example, S02 and particulate matter ("PM") are 

associated with serious lung and heart ailments, including premature death, while NOx is a 

precursor to ground level ozone, or smog, which is associated with respiratory diseases, asthma 

attacks, and decreased lung function. In 201 I, there were more than 262 exceedances of the 

EPA's ozone air pollution standard at national parks-the highest number of exceedances since 

2008. Even healthy adults are urged to limit outdoor exercise on days with high ozone. Given 

the overlap between the haze fonning pollutants and health, EPA has estimated that in 2015, 

reductions in S02 and NOx resulting from the Regional Haze Rule will prevent 1,600 premature 

deaths, 2,200 non-fatal heart attacks, 960 hospital admissions, and over 1 million lost school and 

work days, benefits valued at $8.4- $9.8 billion annually. 

B. Visibility Protection Under the Clean Air Act 

Recognizing that manmade haze diminishes visibility and degrades the integrity of many 

of the nation's national parks and wilderness areas, Congress in 1977 amended the Clean Air 

5 National Parks Service, Visibility Effects of Air Pollution: Importance of Visual Air Quality to Visitor 

Experience, http://www.nature.nps.oov/air/AOBasics/visibilitv.cfm (last accessed February 13, 2012). 

6 !d. 

7 Southwick Associates, The Economics Associated with Outdoor Recreation, Natural Resources Consen'ation and 

Historic Preservation in the United States, at 17 (October 10, 2011), available at 

wwv.r.nfwforg/Content/ContentFolders!NationalFishand\VildlifeFoundation/HomePage/ConservationSpotJightsffhe 

EconomicValueofOutdoorRecreation.pdf; United States Department of the Interior, Office of Policy Analysis, The 

Department of the Interior's Economic Contributions, at 9 (June 21, 2011 ), available at 

www .doi.oov/ppa/upload/DO I -Econ-Report-6-21-20 !!.pdf. 

3 
Act, "declar[ing] as a national goal the prevention of any future, and the remedying of any 

existing, impaim1ent of visibility in mandatory class I Federal areas which impairment results 

from manmade air pollution." See 42 U.S.C. § 749l(a)(l), CAA § 169A(a)(l); see also 40 

C.P.R. pt. 81, subpt. D (listing the !56 protected Class I areas, including certain national parks, 

wilderness areas, and national memorial parks, as well as certain intemational parks). Among 

other things, Congress mandated that EPA adopt regulations that would require states to develop 

SIPs containing measures necessary to make reasonable progress toward the national goal of 

improving visibility, including installation and operation of BART at BART-eligible sources8 

that could be reasonably anticipated to cause or contribute to visibility impainnent. 42 U.S.C. § 

749l(a)(4), (b)(2)(A); CAA § 169A(a)(4), (b)(2)(A). 

EPA's visibility program initially focused on controlling plume blight, or visibility 

degradation caused by air pollution reasonably attributable to a source or small group of sources. 

To address plume blight, EPA required installation of BART at sources to which visibility 

impairment at the Class I areas could be reasonably attributed. Thus, under the regulations, 36 

states containing Class I areas were required to determine which existing stationary sources 

should install BART for controlling pollutants that impair visibility. See Visibility Protection for 

Federal Class I Areas, 45 Fed. Reg. 80084, 80086 (Dec. 2, 1980). The Federal Land Managers 

play an important role in assessing the need for BART in this context; if a Federal Land Manager 

certifies to the state that there exists reasonably attributable impairment of visibility in any Class 

I area, at least 6 months prior to the state's SIP submission or revision, the state is required to 

identify and analyze BART for those sources and, where appropriate, require installation BART 

as expeditiously as practicable. See 40 C.F .R. § 51.302(c)(1); I d. § 51.302(c )( 4). This provision 

for addressing reasonably attributable visibility impairment ("RA VI")9 laid the groundwork for 

reaching the national goal or restoring natural visibility. See, e.g., 40 C.P.R.§ 51.302(c)(l); Id. § 

51.302(c)(4). From the outset, however, EPA acknowledged that RA VI BART could only take 

the nation so far toward remedying the visibility problem. Thus, the agency explained that 

widespread, regionally homogenous haze also impaired visibility, but in the original rulemaking 

it deferred action on regional haze until the agency had better monitoring, modeling, and 

scientific knowledge about the relationship between emission of certain pollutants and visibility. 

45 Fed. Reg. at 80086. 

In 1999, EPA expanded the visibility program, promulgating the Regional Haze Rule. 

Regional Haze Regulations, 64 Fed. Reg. 35714 (July 1, 1999). Under that Rule, states are 

directed to submit SIPs containing emissions limitations representing BART and schedules for 

compliance for each BART-eligible source that may be anticipated to cause or contribute to any 

visibility impairment in a Class I area. See 40 C.P.R.§ 51.308(e). BART is determined for each 

source based on a case-by-case analysis. Id. at§ 51.308(e)(l)(ii). Thus, in addition to RA VI 

BART, a source may have to install BART as required to combat regional haze. The EPA 

further elaborated on requirements for determining BART in its BART guidelines, published on 

8 A source is BART -eligible if it is a stationary source within one of 26 enumerated categories, was not in operation 

before August 7, 1962 but was in existence on August 7, 1977, and has the potential to emit 250 tons per year or 

more of any pollutant. 42 U.S.C. § 7491(b)(2)(A), (g)(7); CAA § 169A(b)(2)(A), (g)(7). 9 "Reasonably attributable visibility impairment" is ''visibility impairment that is caused by the emission of air 

pollutants from one, or a small number of sources." 40 C.F .R. § 51.301. Visibility impairment, in turn, is "any 

humanly perceptible change in visibility (light extinction, visual range, contrast, coloration) from that which would 

have existed under natural conditions." Jd. 

4 
July 6, 2005. See Regional Haze Regulations and Guidelines for Best Available Retrofit 

Technology (BART) Determinations, 70 Fed. Reg. 39104 (July 6, 2005) (hereafter "BART 

Guidelines"). 

Implementation of the Regional Haze Rule has been slow since many states fell behind in 

their duty to develop Regional Haze SIPs, triggering EPA's duty to step in and impose federal 

implementation plans ("FIPs"). In response to litigation to force EPA to take action, EPA is now 

in the process of determining whether to approve proposed SIPs and proposing and finalizing 

FIPs around the country. In November 20 I I, EPA agreed that, within one year, it would finalize 

haze pollution clean-up plans for every state, paving the way for clearer (and cleaner) air in 

many national parks and wilderness areas. See Consent Decree, Nat 'l Parks Consen,ation Ass 'n 

v. Jackson, No. I :1 1-cv-01 548(ABJ) (D.D.C. Nov. 9, 201 1). The proposed Illinois Regional 

Haze SIP, at issue in these comments, is one of those plans. 

C. Illinois' Proposed Regional Haze SIP 

On June 24, 2011, Illinois submitted a proposed Regional Haze SIP to EPA. 77 Fed. Reg. 

3966. In its Proposed SIP, Illinois states that, based on modeling completed by the Midwest 

. Regional Planning Organization ("MRPO"), it determined that emissions sources in the state 

cause or contribute to visibility degradation in 19 national parks and wilderness areas (defined in 

the CAA as "Class I areas"). 10 Illinois EPA, Regional Haze State Implementation Plan for 

Illinois, AQPSTR 10-08 (May 10, 2011) at 8-12 (hereafter "Illinois Regional Haze SIP"). To 

comply with the BART provisions of the Regional Haze Rule, Illinois evaluated which emissions 

sources within the state cause or contribute to visibility degradation in those Class I areas. 

Illinois concluded that II sources, including 9 Electric Generating Units ("EGUs"), cause or 

contribute to visibility degradation and are thus "subject to BART." Illinois EPA, Technical 

Support Document For Best Available Retrofit Technology Under the Regional Haze Rule, 

AQPSTR 09-06 (Apr. 29,201 I) (hereafter "Illinois TSD for BART") at 12-22. 

Instead of evaluating and determining BART for all of those sources, Illinois proposed 

that an "alternative" to BART- ostensibly permitted under the Regional Haze Rule- be used for 

7 of the 9 EGUs. Illinois Regional Haze SIP at 19. Specifically, Illinois proposed that the 

MPS/CPS be relied on in lieu of BART to minimize visibility degradation caused or contributed 

to by those 7 EGUs.ld. For the remaining two EGUs, Illinois proposed BART determinations. 

Illinois TSD for BART at 3 I-3 8. 

To comply with the LTS requirements of the CAA, Illinois used a threshold 

determination method included in the BART Guidelines to find that only 15 stationary sources in 

the state must be considered in developing its proposed LTS. Instead of requiring additional 

10 Those 19 national parks and wilderness areas are: Sipsey Wilderness Area, Alabama; Caney Creek Wilderness 

Area, Arkansas; Upper Buffalo Wilderness Area, Arkansas; Mammoth Cave National Park, Kentucky; Acadia 

National Park, Maine; Moosehorn Wilderness Area, Maine; Isle Royale National Park, Michigan; Seney Wilderness 

Area, Michigan; Boundary Waters Canoe Area Wilderness, Minnesota; Voyageurs National Park, Minnesota; 

Hercules-Glades Wilderness Area, Missouri; Mingo Wilderness Area, Missouri; Great Gulf \Vilderness Area, New 

Hampshire; Brigantine Wilderness Area, New Jersey; Great Smoky Mountains National Park, Tennessee and North 

Carolina; Lye Brook Wilderness, Vermont; James River Face Wilderness Area, Virginia; Shenandoah National 

Park, Virginia; and Dolly Sods/Otter Creek Wilderness, West Virginia. Illinois Regional Haze SIP at 12. 

5 
emissions reductions from those sources, however, Illinois claimed that existing or soon-to-beimplemented regulatory programs would require sufficient emissions reductions from those 

sources so as to ensure achievement of reasonable progress goals in impacted Class I areas. 

Illinois Regional Haze SIP at 34. 

For the reasons discussed below, Illinois' Regional Haze SIP is defective and thus may 

not be approved. EPA should disapprove the SIP and instead promulgate a Regional Haze FIP 

for the state to remedy these deficiencies and ensure compliance with all CAA requirements. 

III. ARGUMENT 

A. THE PLAIN LANGUAGE OF THE CLEAN AIR ACT PRECLUDES ALTERNATIVES TO 

BART 

EPA cannot authorize states to rely on alternative programs to opt out of BART. Under 

the Clean Air Act, BART is a mandatory measure that must be implemented to achieve 

reasonable progress toward restoration of natural visibility conditions. Section !69A(b)(2)(A) 

expressly requires states to adopt SIPs that "contain such emission limits, schedules of 

compliance and other measures as may be necessary to make reasonable progress toward 

meeting the national goal ... including" installation and operation of BART at BART-eligible 

sources that emit any air pollutant which may reasonably be anticipated to cause or contribute to 

any impainnent of visibility in any Class I area. See CAA § 169A(b)(2)(A); 42 U.S.C. § 

749!(b)(2)(A) (emphasis added). The only permissible exemption from BART is expressly set 

forth in§ 169A(c). See CAA § 169A(c); 42 U.S.C. § 749l(c). Under§ 169A(c), a source can be 

exempt from BART only if EPA, by rule promulgated with sufficient notice and opportunity for 

public comment, determines that the source does not either by itself or in combination with other 

sources "emit any air pollutant which may reasonably be anticipated to cause or contribute to a 

significant impainnent of visibility in any mandatory clas·s I federal area." CAA § 169A(c)(l); 

42 U.S.C. § 749l(c)(l). Further, EPA cannot exempt a fossil-fuel fired power plant with a 

design capacity of750 megawatts or more, unless the owner or operator of the plant can 

demonstrate that the power plant is located far enough away from the class I areas that it satisfies 

the exemption criteria above. CAA § 169A(c)(2); 42 U.S.C. § 749l(c)(2). Likewise, the 

appropriate Federal Land Manager or managers must agree with the exemption before it can go 

into effect. CAA § 169A(c)(3); 42 U.S.C. § 749l(c)(3). Thus, EPA's authority to exempt 

sources from BART is very narrowly defined. Nowhere in Section 169A did Congress 

contemplate or sanction sweeping alternative programs that would operate in lieu of source 

specific BART. 

In short, there is no statutory authority for EPA regulations that purport to allow for 

reliance on alternative programs in place of BART. See 40 C.F.R. § 51.308(e)(2). Nevertheless, 

the D.C. Circuit Court of Appeals has upheld such regulations, concluding that BART is not 

mandatory but rather one of many available options that EPA and state agencies may impose at 

their discretion to achieve reasonable progress. See Center for Energy & Economic Dev. v. EPA, 

398 F.3d 653 (D.C. Cir. 2005) ("CEED") (holding that§ 169A did not require use ofBART); 

Utility Air Regulat01y Group v. EPA, 471 F.3d 1333, 1340 (D.C. Cir. 2006) ("UARG") (relying 

6 
on CEED for the proposition that "EPA may leave states free to implement BART-alternatives 

so long as those alternatives also ensure reasonable progress"). In so holding, CEED and UARG 

effectively read mandatory BART requirements out of the Clean Air Act. Because these cases 

cannot be reconciled with the plain language of the Clean Air Act, EPA should not rely on them 

to exempt Illinois from implementing BART. 

B. ILLINOIS ILLEGALLY FAILED TO COMPLETE A BART DETERMINATION FOR 

EACH SOURCE SUBJECT TO BART IN THE STATE. 

Even if we assume for the sake of argument that alternatives to BART are permissible 

under the CAA, Illinois has not met the regulatory requirements necessary to approve such 

alternatives. First, Illinois was required, but failed, to make a BART determination for each 

source subject to BART in the state. Pursuant to 40 CFR § 51.308(e )(2), for all alternatives to 

BART that a State proposes, the State "must submit an implementation plan containing the 

following plan elements and include documentation for all required analyses: ... (C) An analysis 

of the best continuous emission control technology available and associated emissions reductions 

achievable for each source within the State subject'to BART and covered by the alternative 

program. . . . [If] the emissions trading program or other alternative measure has been designed 

to meet a requirement other than BART ... the State may determine the best system of 

continuous emission control technology and associated emission reductions for similar types of 

sources within a source category based on both source-specific and category-wide information, 

as appropriate." (emphasis added). 

Illinois' proposed Regional Haze SIP fails to comply with those regulatory requirements. 

Rather than make a BART detennination for each individual source subject to BART that would 

be covered by Illinois' proposed alternative to BART program (namely, the MPS/CPS), Illinois 

simply compared projected emissions reductions from the MPS/CPS to presumptive BART 

emissions. 77 Fed. Reg. at 3972 ("Illinois did not provide an analysis comparing BART for each 

subject unit to the alternative," but rather only "compared the emissions reductions from MPS 

and CPS to the presumptive BART emission levels suggested in EPA's guidance"). In doing so, 

Illinois entirely ignored the regulatory mandate that it determine BART " ... based on both sourcespecific and category wide information .... " 40 C.F.R. § 51.308(e)(2)(C). As EPA made clear in 

its BART Guidelines, presumptive BART levels are not source-specific; rather, they merely 

provide a general baseline for BART that States may- indeed, must- deviate from if a sourcespecific analysis so indicates. See 40 C.F.R. Part 51, Appendix Y; BART Guidelines at 39171 

(presumptive BART limits only apply if no determination made that "an alternative control level 

is justified based on a careful consideration of the statutory factors" for a given source). Because 

Illinois entirely failed to use source-specific information or undertake a comprehensive five 

factor analysis to determine BART, its proposed Regional Haze SIP may not be approved.ll 

11 EPA's conclusion that Illinois need not compare the proposed alternative to BART to a "fully analyzed set of 

BART limits" because the results of such an analysis are "clear even without Illinois conducting a full BART 

analysis for these units," 77 Fed. Reg. 3972, is thus simply legally wrong. 

7 
C. THE MULTI-POLLUTANT STANDARD/COMBINED POLLUTANT STANDARD 

(MPS/CPS) IS NOT AN ACCEPTABLE ALTERNATIVE TO BART. 

Second, Illinois' proposed alternative to BART does not meet regulatory requirements for 

such alternatives. Under current regional haze regulations, to utilize an alternative emissions 

reduction program instead of BART, a state must meet several requirements. Crucially, the state 

must "demonstrat[ e ]

12 that an emissions trading program or other alternative will achieve greater 

reasonable progress [toward natural visibility conditions] than would have resulted from the 

installation and operation of BART at all sources subject to BART in the State and covered by 

the alternative program." 40 C.F.R. § 51.308(e)(2)(i). As discussed above, to do so, the State 

must include "[a]n analysis of the best continuous emission control technology available and 

associated emissions reductions achievable/or each source within the State subject to BART and 

covered by the alternative program." 40 C.F.R. § 51.308(e)(2)(i)(C) (emphasis added). If the 

proposed alternative to BART was "designed to meet a requirement other than BART," the State 

may complete that analysis "based on both source-specific and category-wide information, as 

appropriate." 40 C.F.R. § 51.308(e)(2)(i)(C) (emphasis added). Second, a State must require that 

"all necessary emissions reductions take place during the period of the first long-term strategy 

for regional haze." 40 C.F .R. § 51.308( e )(2)(iii). Third, a State must demonstrate that "the 

emissions reductions resulting from the ... alternative measure will be surplus to those 

reductions resulting from measures adopted to meet requirements if the CAA as of the baseline 

date of the SIP." 40 C.F.R. § 51.308(e)(2)(iii). In this case, Illinois fails to meet any of the three 

requirements necessary for approval of an alternative to BART. 

i. The MPS/CPS Will Not Achieve Greater Reasonable Progress 

Toward Natural Visibility Conditions Than BART 

For several reasons, the MPS/CPS will not "achieve greater reasonable progress toward 

natural visibility conditions" than would the installation and operation of BART. To begin with, 

BART imposes emissions limits on individual sources, which emission limits ensure that each 

individual source that causes or contributes to visibility degradation uses the best available 

controls to minimize its impact to the Class I area(s). See 42 U.S.C. § 7492(g)(2); 40 C.F.R. § 

51.308(e)(l)(ii). The MPS/CPS, in contrast, are fleetwide requirements that impose no specific 

emissions limits on any single plant or emissions source. 77 Fed. Reg. 3971; 35 Ill. Admin. Code 

Part 225. As such, Ameren, MWG and Dynegy can meet MPS/CPS requirements without adding 

any pollution control equipment at sources subject to BART, and without requiring that those 

sources meet BART-level emission limits. 13 Because an appropriate BART determination would 

12 A state's determination that an alternative will achieve greater reasonable process than would the installation and 

operation of BART must be based on the clear weight of the evidence. 40 C.F.R: § 51.308(e)(2)(i)(E). 13 EPA asserts that "[t]he limits that Illinois has imposed are sufficiently stringent that the companies have only 

limited latitude to over control at some facilities in trade for having elevated emissions at other facilities." 77 FR 

3971. EPA provides no basis for this assertion, which is contradicted by the MPS/CPS itself. As discussed 

elsewhere in these comments, the MPS/CPS does not include IDlY control equipment requirements for any of the 

sources subject to BART in Illinois. The MPS/CPS does, in contrast, include specific control equipment 

requirements (i.e., activated carbon injection, flue gas desulfurization) for other covered sources, including MWG's 

Fisk, Crawford, and Waukegan plants, and boiler unit 3 at Will County. See 35 I.A.C. §225.293-299. Since the 

MPS/CPS does mandate specific control requirements at sources not subject to BART, plant owners are constrained 

to make emission reductions at those plants or shut them down. The owners thus have much more "limited latitude" 

8 
require effective emission controls at facilities subject to BART, whereas MPS/CPS does not 

require any additional controls at those specific sources, proper application of BART will ensure 

greater improvements in visibility at affected Class I areas than the MPS/CPS. It is therefore 

illogical and without merit for the state or EPA to suggest, let alone claim, that MPS/CPS would 

achieve greater reasonable progress towards natural visibility conditions than BART. 

Next, Illinois certainly cannot demonstrate that an alternative program would be "better 

than BART" without first properly determining what BART is. Nonetheless, Illinois has not 

properly determined BART for !!!!Y ofthe sources subject to BART that are covered by the 

MPS/CPS. BART determinations must be made on the basis of an up-to-date evaluation of the 

five statutorily-mandated factors, 14 and must take into account source-specific information. See 

42 U.S.C. § 7492(g)(2); 40 CFR § 51.308(e)(2)(C); BART Guidelines at 39171 ("While 

[presumptive S02 BART] may represent current control capabilities, we expect that scrubber 

technology will continue to improve and control costs continue to decline. You should be sure to 

consider the level of control that is currently best achievable at the time that you are conducting 

your BART analysis"). Because presumptive BART limits were established for an entire source 

category and were determined at a particular point in time (2005), they are neither based on 

source-specific infonnation, nor do they represent an up-to-date evaluation of information that 

must be taken into account in determining BART. BART Guidelines at 39171. Thus, a State 

may not rely on presumptive BART limits in lieu of a full, updated, source-specific BART 

analysis for each source subject to BART covered by the alternative program. Illinois, however, 

did just that. 77 Fed. Reg. at 3972. Because Illinois failed to complete a full BART analysis for 

each source subject to BART that is covered under the MPS/CPS, its Regional Haze SIP may not 

be approved. 15 

Moreover, if Illinois had conducted proper, full BART evaluations for sources subject to 

BART that are covered by the MPS/CPS, it almost certainly would have determined that the 

presumptive limits do not represent BART for those sources. Recent BART limits set by EPA 

make clear that the presumptive BART limits (set at . I 5 lb/MMBtu or 95% removal for S02, and 

not to make emissions reductions at those plants, and much greater latitude not to make them at the plants subject to 

BART. Therefore, contrary to EPA's assertion, the MPS/CPS does not ensure that any individual plant will install 

BART-level controls, achieve BART -level emission limits, or achieve "greater reasonable progress" than would 

imposition of BART. 14 BART determinations "shall take into consideration the costs of compliance, the energy and nonair 

quality environmental impacts of compliance, any existing pollution control technology in use at the 

source, the remaining useful life of the source, and the degree of improvement in visibility which may 

reasonably be anticipated to result from the use of such technology." 42 U.S.C. § 7492(g)(2); see also 40 

C.F.R. §51.301. 15 Because Illinois did not complete full, proper BART analyses or make BART determinations based on those 

analyses, it could not- and thus did not- model the visibility impacts that would result from imposition of such 

proper BART limits as compared to the MPS/CPS. What is worse, however, is that Illinois did not even model the 

visibility impacts of its MPS/CPS program as compared to the visibility impacts that would be achieved by 

presumptive BART emission limits. As such, contrary to law, Illinois entirely failed to consider "the degree of 

improvement in visibility which may reasonably be anticipated to result from the use of such technology," 42 U.S.C. 

§ 7492(g)(2)), in evaluating whether the MPS/CPS is "better than BART." Moreover, Illinois' failure to model the 

visibility impacts ofMPS/CPS versus those of BART renders Illinois' claim that MPS/CPS will achieve greater 

reasonable progress than BART utter speculation. A decision by EPA to approve Illinois' Regional Haze SIP in 

reliance on such naked speculation would be arbitrary and capricious. 

9 
at varying levels at and above .I 0 lb/MMBtu for NOx, depending on boiler type and coal type 16), 

are at least 2 to 3 times higher than recent BART requirements. For example, EPA recently set a 

BART limit of0.06lb/MMBtu S02 based on a rolling 30-day average for six coal-fired emission 

units in Oklahoma, 76 Fed. Reg. 81728, 81729 (Dec. 28, 201 !), and a BART limit of0.05 

lb/MMBtu NOxon a 30-day average for 4 coal-fired boiler units in New Mexico. 76 Fed. Reg. 

49 I, 493-97 (Jan. I 5, 20 I!). In contrast, under the MPS/CPS, the fleetwide average 

requirements for 201 i 7 for NO, and S02 emissions are much higher- at .23 lb/MMBtu of S02 

for Ameren plants and . I 5 lb/MMBtu of S02 for MWG plants, and . I I lb/MMBtu of NO, for 

both Ameren and MWG plants- than those recent BART limits. And because these MPS/CPS 

limits are fleetwide average requirements, Ameren and MWG could permissibly keep emissions 

considerably higher than those fleetwide average limits at any given plant, including those 

subject to BART. Thus, if Illinois had conducted proper BART analyses, it is virtually certain 

that it would have detennined that the MPS/CPS is not "better" than BART for subject sources. 

Further, even if it were legally adequate for Illinois to compare its proposed alternative 

program to presumptive BART limits, Illinois still would not have made the required 

demonstration that MPS/CPS is "better than BART." First, fleetwide average requirements for 

2017 for Ameren plants exceed presumptive BART requirements for NOx at one of the three 

plants subject to BART, and far exceed presumptive S02 BART limits at all three Ameren plants 

subject to BART. Illinois Technical Support for BART at 29-30 (compare fleetwide average NO, 

limits of .I 1 lb/MMBtu to presumptive BART NO, limits of .10 for Coffeen plant, and fleetwide 

average S02Iimits of .23 lb/MMBtu to presumptive BART limits of .15 lb/MMBtu). Fleetwide 

average requirements for MWG also exceed presumptive NOx BART limits for the Powerton 

plant. !d. at 32. And again, because these are fleetwide average emission limits, Ameren and 

MWG could pennissibly keep emissions well higher than those limits at any given plant, 

including those plants subject to BART. Because Ameren and MWG's fleetwide average 

requirements under the MPS/CPS exceed presumptive BART in several instances, and because 

Ameren and MWG need not meet even those weak requirements at their plants subject to BART, 

the MPS/CPS is not "better" than presumptive BART limits. See 40 C.F.R. §51.308(e)(3) 

(requiring that alternative measures result in greater emissions reductions than under BART). 

Second, the emission limits required by the MPS/CPS do not ensure greater reasonable 

progress toward natural visibility conditions than would presumptive BART due to the long 

averaging times of those emission limits. Wbile visibility impacts are measured based on a onehour averaging time, the fleetwide average emission limits required by the MPS/CPS are based 

on annual averages. 35 Ill. Admin. Code §§ 225.295 and 225.233. The presumptive BART 

limits, in contrast, are based on 30-day rolling averages. BART Guidelines at 39172. The longer 

the averaging period, the higher emissions may be in any given hour during that averaging 

period. Thus, an emission limit based on annual averages allows for much higher short-term 

emissions- and thus much greater short-term impact on visibility- than would a limit based on 

a 30-day rolling average. Since the emission limits required for the MPS/CPS are not only 

16 BART Guidelines at 39171-72. 17 Because BART must be implemented no later than five years after a State's Regional Haze SIP is approved, 42 

U.S.C. § 749l(b)(2)(A) and (g)(4), assuming the Regional Haze SIP is approved this year (2012), BART 

requirements would be in place by 2017. 

10 
higher than preemptive BART limits, but also are based on a much longer averaging period, the 

MPS/CPS allows for much greater visibility degradation than BART. 

Third, even if the control equipment that Illinois is allowing to be installed at plants 

subject to BART were required by the MPS/CPS, 18 Illinois still could not demonstrate that the 

MPS/CPS is "better" than either presumptive or properly-analyzed BART limits for those 

facilities. In its Regional Haze SIP proposal, Illinois notes that many of the sources subject to 

BART in the state already have installed, or will install, additional S02 and NOx controls. Illinois 

TSD for BART at 25-31. However, much of the control equipment that Ameren and MYG plan 

to install at their facilities falls far short of even presumptive BART requirements. For example, 

while Ameren "is expected to install a new scrubber" 19 at E.D. Edwards unit 3, no such plans are 

in the works for Edwards unit 2. Id. at 28. Without a scrubber, it is virtually certain that Edwards 

unit 2 will not meet even presumptive S02 BART limits, much less S02 limits resulting from a 

full BART analysis for the source."0 Illinois essentially admits as much: "Ameren is relying on 

system-wide reductions required by the MPS to meet BART at Edwards." !d. at 28. 

The controls planned for MWG plants subject to BART also are a far cry from BART 

requirements. For NOx control, MWG "is expected to install selective non-catalytic reduction 

(SNCR)" on all four Powerton units, the four Joliet units subject to BART, and on Will County 

unit 4 by 2012. Illinois TSD for BART at 30-31. SNCR is much less effective at removing NOx 

than is selective catalytic reduction ("SCR"). While SNCR's removal efficiency ranges between 

25 and 50%,21 EPA recognizes the removal efficiency ofSCR as 90%,22 and at least one study 

indicates that SCR achieves an even higher percentage removal.23 Indeed, as noted above, EPA 

recently set a BART limit of0.05 lb/MMBtu for emissions ofNOx on a 30-day average for 4 

coal-fired boiler units in New Mexico, based on the use of SCR. 76 Fed. Reg. at 493-97. 

Moreover, EPA used SCR as the basis for the 7 year-old presumptive NOx limit (of 0.10 

lb/MMBtu) for cyclone boilers. 70 Fed. Reg. 39172. Powerton's four units are all cyclone-type 

boiler units; thus, at a minimum, SCR must be installed on those units to ensure that at least 

BART-level emissions reductions are achieved. Because the CPS lacks a requirement that SCR 

18 As discussed above, the :MPS/CPS contains absolutely no requirements for specific control equipment to be 

installed or operated at any source subject to BART in Illinois. See 35 III. Admin. Code§§ 225.233 and 293-299. 19 We reiterate that, although Illinois may state that a plant owner is "expected" to install a particular type of control 

equipment at a given source, the MPS/CPS includes no source-specific emissions limits or control equipment 

requirements for sources subject to BART. The MPS/CPS, then, would create no penalty if a plant owner were to 

change those "expectations." 

20 See 70 Fed. Reg. 39132 ('~here is ample data to support the determination that the BART presumptive limits 

outlined in today's action are readily achievable by new wet or semi-dry FGD systems across a wide range of coal 

types and sulfur contents based on proven scrubber technologies currently operational in the electric industry"); 

Technical Supp01t Document for the Best Available Retrofit Technology (BART) Notice of Final Rulema/dng: 

Setting BART S02 Limitsfor Electric Gene,rating Units: Control Technology and Cost-Effectiveness (Apr. 2005) at 

15 (included as Appendix A) ("Research conducted by EPA revealed that the pre-existing S02 control systems 

which are typically achieving below 50 percent removal efficiencies are of the dry sorbent injection scrubber type. 

The EPA does not feel that sorbent injection scrubbers reflect current BART for S02 control. ... ") 21 Kevin Dougherty, "Comprehensive NOx Reduction in a Capital Constrained World," MARMA presentation (Jul. 

8, 2009) at slide 6 (included as Appendix B). 22 EPA, Technical Support Document: Methodology for Developing BART NOx Presumptive Limits (June 15, 2005) 

at 13 (included as Appendix C). 23 Institute of Clean Air Companies, White Paper: Selective Catalytic Reduction (SCR) Control of NOx Emissions 

from Fossil Fuel-Fired Electric Power Plants (May 2009) at 7 (included as Appendix D) 

II 
be installed and operated at the MWG sources subject to BART, in particular at Powerton, the 

CPS clearly is not "better" than presumptive BART for NO,. 

For S02 control, MWG is "expected" to install "flue gas desulfurization (FGD) 

equipment" on all four Powerton units by the end of2013, on the four Joliet units subject to 

BART by 2019, and on Will County unit 4 by 2019. The FGD equipment that MWG plans to 

install at Powerton, however, is not wet or dry scrubbers, but rather Dry Sorbent Injection 

(DSI).24 And although MWG does not yet have a penn it for the FGD equipment they "expect" 

to install at Joliet and Will County unit 4 in 2019, it is highly possible that MWG will plan to 

install DSI at those plants as well. But EPA has made it crystal clear that DSI is not BART. In 

its Technical Support document that provides the basis for the presumptive S02 BART limits, 

EPA explained that "[r]esearch conducted by EPA revealed that the pre-existing S02 control 

systems which are typically achieving below 50 percent removal efficiencies are of the dry 

sorbent injection scrubber type. The EPA does not feel that sorbent injection scrubbers reflect 

current BART for S02 control .... "

25 

More recent documents included in Illinois' own SIP submission make clear that DSI is 

far inferior to wet or dry scrubbers. In the BART analysis for Dominion's Kincaid plant, 

Dominion" states that wet scrubbers achieve S02 removal efficiencies of 90 to better than 95% 

on coal-fired boilers, and dry scrubbers (paired with fabric filters) achieve S02 removal 

efficiencies of 80-90%. ENSR, BART analysis for the Kincaid Power Plant (Jan. 2009) at 3-2 

(hereafter "Kincaid BART Analysis"). In contrast, Dominion finds that DSI only achieves S02 

removal efficiencies of 60 to 70%, and that DSI has only achieved 70% removal in certain 

limited tests. !d. at 3-3 - 3-4. The Institute for Clean Air Companies has similarly found that 

DSI systems "typically have removal efficiencies ranging from 50-70%" and that DSI systems 

are "generally applied when lower removal efficiencies are required."27 Because the DSI 

controls that MWG is permitted to install at Powerton, and may install at Joliet and Will County, 

cannot achieve the removal efficiency (95%) or emission limit (.15 lb!MMBtu) required for 

presumptive S02 BART, CPS is not "better than BART," and Illinois cannot demonstrate that 

CPS would achieve greater reasonable progress toward natural visibility conditions than would 

the installation and operation of BART on subject sources. 

Illinois has failed to demonstrate that MPS/CPS will achieve greater reasonable progress 

toward natural visibility conditions than would the installation and operation of BART at subject 

facilities. It will not do so, and therefore may not be relied on as an alternative to BART. 

24 See Construction Permit, Application No. 10120020, Dry Sorbent Injection Systems and ESP Upgrades for Unit 

5, Powerton Generating Station (Feb. 16, 2011) and Construction Permit, Application No. 10120021, Dry Sorbent 

Injection Systems and ESP Upgrades for Unit 6, Powerton Generating Station (Feb. 16, 2011) (included as 

Appendices E and F). 

25 Appendix A, Technical Support Document for the Best Available Retrofit Technology (BART) Notice of Final 

Rulemaf...ing: Setting BART S02Limitsjor Electric Generating Units: Control Technology and Cost-Effectiveness 

(Apr. 2005) at 15 (emphasis added). 26 The BART analysis was prepared by ENSR Corporation for Dominion Energy, Inc. However, to avoid confusion, 

in these comments we refer to the authors of the analysis as "Dominion." 27 "Acid Gas/S02 Control Technologies," available at http://www.icac.com/i4a/pages/index.cfm?pageid-3401 (last 

visited February 17, 2012). 

12 
ii. The MPS/CPS Does Not Require that All Necessary Emissions 

Reductions Take Place During the First Long-Term Strategy for 

Regional Haze. 

In order for an alternative to BART to be approved, a State must require that "all 

necessary emissions reductions take place during the period ofthe first long-term strategy for 

regional haze." 40 C.F.R. § 51.308(e)(2)(iii) (emphasis added). The end of the first long-term 

strategy period for regional haze is 20 I 8. Illinois Regional Haze SIP at 3 I -32. In Illinois, 

however, several requirements of the CPS do not even go into effect until that year or later. For 

example, the CPS does not require that MWG achieve a fleetwide average of .13 Ib/MMBtu S02 

until 2018, or achieve a fleetwide average of .II lb/MMBtu S02 until 2019. 35 Ill. Admin. Code 

§ 225.295(b). Further, MWG is not "expected" to install FGD at the four Joliet boilers and the 

Will County boiler until 2019, one year after the long-term strategy period ends. Illinois TSD for 

BART at 30-31. Because (i) the CPS includes fleetwide requirements that do not take effect until 

at or after the end of the first Iong-tenn strategy period, (ii) the CPS, with only fleetwide average 

requirements, does not ensure that MWG will ever install control equipment on its subject-toBART plants; and (iii) even if the CPS did require MWG to install control equipment on its 

subject to BART plants, MWG does not plan to install FGD on the Joliet and Will County unit 4 

boilers until after the first long-term strategy period ends, Illinois is not requiring that "all 

necessary emissions reductions take place during the period of the first Iong-tenn strategy for 

regional haze." 40 C.F.R. § 51.308(e) (2)(iii) (emphasis added). Thus, the MPS/CPS may not be 

approved as an alternative to BART. 

iii. It Is Not Clear That The Emissions Reductions Resulting from the 

MPS/CPS Will Exceed Those Reductions Resulting from Measures 

Adopted to Meet Requirements of the CAA. 

Another requirement that a State must meet in order to obtain approval to use an 

alternative program instead of BART is to demonstrate that "the emissions reductions resulting 

from the ... alternative measure will be surplus to those reductions resulting from measures 

adopted to meet requirements of the CAA as of the baseline date of the SIP." 40 C.F.R. § 

5!.308(e)(2)(iii). Currently, the MPS/CPS are stand-alone State requirements which are not 

necessary to meet CAA requirements. However, there are substantial indications that Illinois 

will propose to meet the requirements of the Transport Rule using the MPS/CPS. In fact, in an 

article published November 16, 20 I I, Progress Illinois reported that MWG claims that it will 

comply with the Transport Rule based on its compliance with the CPS."8 Although the Transport 

Rule is currently stayed pending appea!,29 it may be upheld before Illinois' Regional Haze SIP is 

approved. If Illinois proposes to comply with the Transport Rule via the MPS/CPS, then any 

emissions reductions resulting from MPS/CPS will not be "surplus to those reductions resulting 

from measures adopted to meet requirements" of the CAA as of the baseline date of the SIP. 

In sum, because (i) Illinois has not demonstrated that the MPS/CPS would achieve 

greater reasonable progress toward natural visibility conditions than would the installation and 

28 See http://orogressillinois.com/quick-hits/content/20 11/11/16/new-epa-rules-target-coal-plant-emissions (last 

visiting Feb. 16, 2012). 29 See http:llepa.•ovlairtransportlpdfs/CourtDecision.pdf (last visited Feb. 16, 2012). 

13 
operation of BART on subject sources; (ii) Illinois is not requiring that "all necessary emissions 

reductions take place during the period of the first long-term strategy for regional haze;" and (iii) 

it is not clear that any emissions reductions resulting from the MPS/CPS will be surplus to 

reductions required by the CAA, the MPS/CPS may not be approved as an alternative to BART. 

Illinois' proposed Regional Haze SIP therefore may not be approved. 

D. THE BART ANALYSIS AND DETERJ\1INA TION FOR DOMINION'S KINCAID PLANT 

IS SEVERELY FLAWED. 

The BART analysis conducted for Dominion's Kincaid plant contains numerous flaws 

which render the BART detennination unlawful. The most egregious of these flaws is 

Dominion's failure to compare "apples to apples" in evaluating S02 control technologies. As 

explained below, because Dominion did not accurately compare the emissions reductions that 

different controls would achieve, the visibility impacts analysis that the company performed 

incorrectly predicts that the least effective control technology will result in the greatest decrease 

in visibility impacts. This illogical and incorrect result cannot be upheld. 

In a BART analysis, EPA mandates that controls be compared on an "apples to apples" 

basis. BART Guidelines at 39166. For that to occur, it is necessary to compare the actual 

emissions reductions a given control technology will produce, assuming all other factors (i.e., 

fuel type, amount, etc.) remain equal. This is so because a BART analysis includes an evaluation 

of the reduction in visibility impacts a control technology will achieve. !d. at 39164. A control 

technology that achieves fewer emission reductions will likely create more visibility impacts, 

while a technology that achieves greater emissions reductions will likely produce less visibility 

impacts. 

As Dominion explains, the sulfur content of the fuel burned at a fossil fuel-fired plant 

determines how much S02 will be created by the combustion process. Kincaid BART Analysis 

at 3-1 ("Sulfur dioxide emissions are generated in fossil-fuel combustion units from the 

oxidation of sulfur present in the fuel.. .. Uncontrolled emissions of S02 are directly related to 

the fuel sulfur content, and not by the firing mechanism, boiler size, or operation"). Logically, 

then, an emissions control technology with greater removal efficiency will necessarily reduce 

S02 emissions more than a technology with a lesser removal efficiency, if the technologies are 

applied to fuels with the same sulfur content. Thus, to correctly compare the S02 emissions 

reduction a given control technology will achieve, a proper BART analysis requires that all 

control technologies be evaluated as applied to fuels with the same sulfur content. 

Dominion did not do that here. Rather, contrary to EPA mandates, Dominion evaluated 

three control technologies by comparing the effectiveness of those technologies as applied to 

fuels with different sulfur content. Dominion evaluated the following "control scenarios": 

• "Case 1: Firing 0.3% sulfur PRB sub-bituminous coal, Dry Sorbent Injection (DSI) with 

Trona capable of achieving an S02 emissions level of .20 lb/MMBtu .... ;" 

• "Case ]a: Firing 0.3% sulfur PRB sub-bituminous coal, enhanced DSI with Trona 

capable of achieving an S02 emissions level of .18 lb/MMBtu (if achievable) ... ;" 

14 
• "Case 2: Firing 0.5% sulfur PRB sub-bituminous coal, Dry Scrubber/Fabric Filter 

(DS/FF) capable of achieving an S02 emissions level of0.15 lb/MMBtu ... ;" and 

• "Case 3: Firing I .62%-sulfur IIJinois Basin bituminous coal, Wet Flue Gas 

Desulfurization (WFGD) capable of achieving an S02 emissions level of0.15 

lb/MMBtu ... " 

Kincaid BART Analysis at ES-1. By comparing the emissions reductions achieved by Wet FGD 

as applied to a fuel with a sulfur content of I .62%, against those achieved by DS/FF as applied to 

a fuel with .5% sulfur, against the emissions reductions achieved by DSI as applied to fuel with a 

sulfur content of .3%, Dominion created an inaccurate, improper comparison of the emissions 

reductions each control technology would achieve. 

To make matters worse, Dominion did so with virtually no justification. Dominion 

provided no basis whatsoever for evaluating DS/FF as applied to PRB coal with .5% sulfur 

content, as opposed to PRB coal with .3% sulfur content. The arbitrary nature of that selection is 

made clear by Dominion's statement that, "[b]ased on historical emissions, the sulfur content of 

the PRB coal generally does not exceed .3% by weight." Kincaid BART Analysis at 2-1 

(emphasis added). And Dominion's explanation of why it evaluated Wet FGD as applied to 

1.62%-sulfur Illinois Basin coal is equally unconvincing. Dominion begins by recognizing that 

Wet FGD has a very high removal efficiency, "ranging from 90% to in excess of95%." !d. at 3-

2. The company then states that those "high S02 control efficiencies would provide Dominion 

with an opportunity to use higher sulfur IIJinois bituminous coal and still meet the presumptive 

BART limit of .15 lb/MMBtu." But as explained above, presumptive BART may not be 

substituted for an up-to-date, source-specific BART analysis. See BART Guidelines, 70 Fed. 

Reg. 39171. Thus; the fact that Wet FGD could achieve the presumptive BART emissions limits 

even as applied to Illinois coal is no excuse for failing to conduct a proper evaluation of Wet 

FGD's effectiveness and of the emissions reductions it could achieve if agplied to ~el with the 

same sulfur content (i.e., the "baseline" fuel with a sulfur content of .3%'0

) as DSI.' 1 

If Dominion had accurately compared the several control technology options on an 

"apples to apples" basis, it undoubtedly would have found that Wet FGD and DS/FF would 

achieve much greater emissions reductions than DSI. Indeed, Dominion itself admits that Wet 

FGD achieves S02removal efficiencies of90 to better than 95% on coal-fired boilers, and that 

DS/FF achieves S02 removal efficiencies of 80-90%. Kincaid BART Analysis at 3-2, 3-3. In 

30 See Kincaid BART Analysis at ES-5, 3-1. 31 Dominion's two other ')ustifications" for evaluating Wet FGD as applied to high sulfur Illinois coal- first, that 

PRB coal "could" be as costly as Illinois Basin coal in the future, equalizing the cost factor of the BART analysis for 

those two types of coal; and second, that using Illinois coal would "improve the Illinois economy," Kincaid BART 

Analysis at 3-2- are similarly useless. As explained above, a BART analysis must first review the effectiveness of 

control alternatives, which requires an "apples to apples" comparison of those alternatives without regard to cost. 

See BART Guidelines at 39164-66. Even if cost were considered as part of a technology's effectiveness in the first 

step of the BART analysis, the fact that PRB coal might, at some future date, cost the same as Illinois coal (which, 

Dominion recognizes, is currently more expensive than PRB coal), is irrelevant because a BART analysis must be 

based on information that is valid at the time of the analysis. See BART Guidelines, 70 Fed. Reg. at 39171. 

Likewise, whether or not use of Illinois coal would "improve the Illinois economy," that is entirely irrelevant to 

determining BART and may not be considered in evaluating the effectiveness of a control technology. 

15 
contrast, Dominion estimates that DSI will achieve a 60% S02 removal efficiency, 32 and 

expresses doubt that even an emissions limit of .18 lb/MMBtu can be achieved using DSI, much 

less a limit of .15 lb/MMBtu. See id. at 3-3 - 3-4 ("Although the lower S02 emission rate [of .18 

lb/MMBtu] is preferred, it may not be achievable, depending on the coal sulfur content and the 

effectiveness of the Trona removal for this specific application.") Necessarily, then, Wet FGD 

and DS/FF will remove more S02 emissions than DSI, and will thus improve visibility more than 

would occur ifDSI is used. 

The reduced impact on visibility resulting from the use of Wet FGD (as compared to 

DS/FF or DSI) would have been clear if Dominion had properly modeled the emission 

reductions achieved by Wet FGD, DS/FF, and DSI as applied to fuel with the same sulfur 

content. But because Dominion modeled only the visibility impacts of those three control 

technologies using the contrived, improper "control scenarios" listed above, Dominion's 

modeling showed, incorrectly, that DSI- the least effective control technology- would produce 

the fewest visibility impacts of the three control types. See Kincaid BART Analysis at ES-2-

ES-3,6-1- 6-3. This illogical and incorrect result may not be relied upon in determining BART. 

A second glaring error in Dominions' BART analysis for S02, which stems in part from 

its failure to compare controls on an "apples to apples" basis, is its flawed cost analysis. The 

cost effectiveness of a control technology must be considered in determining BART. 42 U .S.C. § 

7492(g)(2); 40 C.F.R. §51.301; BART Guidelines at 39166-67. '"[E]ffectiveness' is measured 

in tenus of tons of pollutant emissions removed, while 'cost' is measured in terms of annualized 

control costs." BART Guidelines at 39167. Here, instead of evaluating the effectiveness of each 

control option using the proper technique (comparing annual costs of each control technology to 

the tons ofS02 that the technology would remove each year, id.), Dominion improperly 

compared the annual costs of each technology to the visibility impacts that the company's flawed 

modeling predicted would result from each "control scenario." See Kincaid BART Analysis at 6-

4- 6-5. By doing so, Dominion incorporated into the cost analysis the flawed, "apples-tooranges" calculation of how much S02 each control technology would reduce, rendering the cost 

analysis entirely unreliable. 

Yet another error with Dominion's BART analysis and Illinois EPA's BART 

detennination for Kincaid pertains to the averaging time for the emission limits. Averaging time 

is a critical component of BART emission limits because, as explained above, a longer averaging 

period allows for shorter term emissions spikes which can greatly impact visibility. The BART 

Guidelines specifY that BART limits for EGUs should be based on 30-day averaging periods. 70 

Fed. Reg. at 39172. Because Kincaid is an EGU of greater than 750 MW capacity, presumptive 

BART limits apply unless an updated, source-specific BART analysis establishes that BART for 

that source should vary from those limits. Id. at 39131, 39171. Nonetheless, Illinois determined 

that, beginning in 20 17, BART for S02 at Kincaid is an annual average emission rate of .15 

lb/MMBtu S02. 77 Fed. Reg. at 3972. Neither Illinois nor Dominion provided any reason why 

32 Later in the same BART Analysis, Dominion proclaims that DSI can achieve S02 removal rates of70%. Kincaid 

BART Analysis at 3-5. However, Dominion clearly explairis why it does not believe 70% can be achieved at 

Kincaid (for example, "[e]ffective utilization of Trona will be more difficult for Kincaid's much larger 660 MW 

units .... ). See id. at 3-3. Therefore, in light of Dominion's own explanation, no more than a 60% removal rate can 

be assumed for DSI at Kincaid. 

16 
the S02 emission limits at Kincaid should be based on a less-stringent annual average, rather 

than on the 30-day rolling average mandated by the BART Guidelines. In fact, Dominion 

appears to acknowledge that BART should be based on the 30-day averaging period. See Kincaid 

BART Analysis at 3-3 ("Dominion estimates that for the purposes of BART implementation, 

DSI with Trona injection will be able to achieve an average S02 control of;:o;60% and an S02 

emission rate of .20 lb/MMBtu based upon a 30-day rolling average.") Because an emission rate 

of .15 lb/MMBtu based on an annual average allows spikes in visibility impacts to go 

unaccounted for- and it is precisely these spikes, or the worst days of visibility impainnent that 

BART and the regional haze program more generally are designed to improve- the proposed 

S02 limits for Kincaid do not satisfy BART requirements. 

In summary, because Dominion did not make an "apples to apples" comparison of the 

three control technologies evaluated, did not model the visibility impacts that would be achieved 

by the three control technologies as applied to fuel with the same sulfur content, and prepared a 

flawed cost effectiveness analysis, Dominion's BART analysis is severely flawed. Illinois' 

BART detem1ination for Kincaid, which was made in reliance on that flawed BART analysis and 

which further erred by setting emission limits based on an annual average, rather than the 

required, more stringent 30-day rolling average, thus must be rejected. As such, EPA must 

disapprove Illinois' Regional Haze SIP and, in its stead, implement a FIP that is compliant with 

the CAA and its regulations. 

E. ILLINOIS' LONG-TERM STRATEGY (LTS) IS DEFICIENT. 

Illinois' L TS is deficient because Illinois has failed to demonstrate that it has included in 

its SIP "all measures necessary to obtain its share of the emission reductions needed to meet the 

[Reasonable Progress Goals] for the Class I areas affected by Illinois sources." 77 Fed. Reg. at 

3973. In particular, Illinois has failed to show that it has imposed or will impose enforceable 

emissions limitations on two EGUs- Ameren's Joppa power plant and Southern Illinois Power's 

Marion plant- that are necessary to achieve the RPGs for Class I areas affected by emissions 

from the state. As described further below, two of the primary regulatory mechanisms that 

Illinois relies on to cut emissions from those plants do not, in fact, ensure any emissions 

reductions from those plants at all. Thus, Illinois' Regional Haze SIP fails to meet L TS 

requirements, and must be rejected. 

Under the Regional Haze rules, a state that causes or contributes to visibility impaim1ent 

in Class I areas in other states is required to develop a L TS which "must include enforceable 

emissions limitations, compliance schedules, and other measures as necessary to achieve the 

reasonable progress goals established by States having mandatory Class I Federal areas." 40 

C.F.R. § 51.308(d)(3). Specifically, a contributing state "must demonstrate that it has included 

in its implementation plan all measures necessary to obtain its share of the emission reductions 

needed to meet the progress goal for the area." Id. A contributing state is further required to 

"identify all anthropogenic sources of visibility impaim1ent considered by the State in 

developing its long-term strategy," which should include stationary sources, among others. Id. 

In its proposed Regional Haze SIP, Illinois evaluated sources in the state which emit 

greater than 1000 tons per year of S02, NO,, or the two pollutants combined, and which were 

17 
"not previously evaluated in the subject-to-BART analysis," in order to determine which of those 

sources "potentially affect visibility." Illinois Regional Haze SIP at 32. Adopting a method 

utilized in the BART Guidelines, Illinois calculated a quantity/distance ("Q/D") ratio for 

evaluated sources, with Q representing the emissions rate in tons per year and D representing the 

distance from the evaluated source to a Class I area. !d. Concluding that it could exclude 

emissions sources with a Q/D ratio of less than I 0: I, Illinois found that 15 sources had to be 

considered in developing the state's LTS. !d. at 32-34. Among those sources are Ameren's 

Joppa coal plant, which has a Q/D ratio of274, nearly three times larger than any other evaluated 

source, and Southern Illinois Power Company's Marion coal plant, with a Q/D of91. Illinois did 

not model the visibility impacts ofJoppa, Marion, or any of the 13 other sources with a Q/D ratio 

greater than I 0 (or any of the sources with a Q/D less than I 0, for that matter.). Nor did Illinois 

include in its L TS any new restrictions on emissions from any sources, including those with a 

QID greater than 10. Instead, Illinois claimed that existing or soon-to-be-implemented 

regulatory programs would require sufficient emissions reductions from those 15 sources so as to 

ensure achievement of reasonable progress goals in impacted Class I areas. !d. at 34. In 

particular, Illinois relied on the MPS/CPS and the Transport Rule, along with two other rules (the 

NOx SIP Call and Title IV) as providing emissions reductions from EGUs that ensure that 

reasonable progress goals for impacted Class I areas are met. !d. at 37. 

Illinois' LTS is unacceptable for two reasons. First, Illinois' LTS is unsubstantiated due 

to the state's failure to model the visibility impacts of those sources with a Q/D ratio greater than 

I 0. Absent accurate modeling demonstrating that these sources should be exempt from 

additional emission reductions requirements to help attain reasonable progress goals, Illinois' 

LTS may not be approved. We request that EPA and Illinois revisit whether these sources were 

rightly exempt and whether additional control requirements should be affixed these sources as 

part of a CAA-compliant LTS for the state. 

Second, contrary to Illinois' claims, two of the primary regulatory programs on which it 

relies to provide emissions reductions for the 15 sources with a Q/D ratio greater than 10-

namely, the MPS/CPS and the Transport Rule- do not ensure sufficient emissions reductions at 

plants that contribute to visibility impairment in Class I areas in other states.33 First, the 

MPS/CPS will not ensure sufficient reductions from the highly-polluting Joppa and Marion 

plants. The MPS/CPS does not apply to the Marion plant, which is owned by Southern Illinois 

Power Company. And although Joppa, owned by Ameren, is subject to the MPS, that regulatory 

33 Illinois claims that the most states in which the Class I areas that Illinois sources impact are located told Illinois 

they are on track to meet their reasonable progress goals, and therefore Illinois need not make additional emission 

reductions at its visibility-impacting sources to ensure achievement of those goals. See Illinois Regional Haze SIP at 

41-4 7. However, the assumptions on which some of these states rely in estimating that they will achieve their RPGs 

by 2064 are faulty. For example, states in the VISTAS Regional Planning Organization- where several Class I 

areas impacted by Illinois are located, including Mammoth Cave National Park in Kentucky, Sipsey Wilderness in 

Alabama, and Great Smoky Mountain National Park in Tennessee and North Carolina- assume achievement of 

their RPGs based on controls required by CAIR (which was replaced by the Transport Rule). Id. at 44. As explained 

herein, the Transport Rule is stayed and, even if it goes into effect, it will not ensure that sources that impact 

visibility at Class I areas will reduce their haze-creating emissions. Thus, the VISTAS states' claims that their RPGs 

will be achieved are unreliable, and more emissions reductions beyond those estimated to result from the Transport 

Rule will be needed to meet those goals. As a state that causes or contributes to visibility impairment in Class I 

areas in VISTAS states, Illinois is obligated, but has failed, to take measures sufficient to ensure that it reduces its 

share of emissions necessary to meet RPGs in those areas. 

18 
program does not ensure that emissions reductions will be made at the Joppa plant. As explained 

above, the MPS requires Ameren to achieve fleetwide average emissions limits, but does not 

mandate that Ameren meet those limits by reducing emissions at any specific plant. Ameren 

could, as such, make reductions at the other 6 Ameren coal plants in Illinois without making any 

reductions at Joppa. Because Joppa is a II 00 MW plant that emits 31,487 tons per year ofS02 

and NO,, Illinois Regional Haze SIP at 33, and is within 300 kilometers of the Mingo Wilderness 

Area in Missouri and Mammoth Cave National Park in Kentucky, failure to require additional 

emissions reductions from Joppa puts visibility at both of those Class I areas at risk. 

The Transport Rule also does not ensure emissions reductions at either Joppa or Marion. 

First, it is uncertain whether the Transport Rule will go into effect at all, in light of the fact that it 

has been challenged in court and is currently stayed pending review of those legal challenges. 

See Order, EME Homer City Generation, L.P. v. EPA, No. 11-1302 (D.C. Cir. Dec. 30, 2011). 

Illinois cannot rely on an enjoined regulation that may never take effect to provide emissions 

reductions that the state must make to "obtain its share of the emission reductions needed to meet 

the progress goal[s]" for Class I areas. See 40 C.F.R. § 51.308(d)(3). 

Second, like the MPS/CPS, the Transport Rule does not require emissions reductions at 

particular plants. Under the Transport Rule, emissions allowances are provided to individual 

sources. 76 Fed. Reg. at 48271. Individual sources can meet the Rule's requirements either by 

reducing their emissions down to the level of their budget or by obtaining additional emission 

credits from other sources. While there are some restrictions on trading, intrastate trading, and 

some interstate trading, is still allowed./d at 48271-72. Thus, under the Rule, a source such as 

Joppa or Marion that is within the airshed of multiple Class 1 areas can legally emit above its 

Transport Rule budget by obtaining additional allowances from a source that is far away from 

the Class 1 area. 

Third, Illinois cannot rely on the Transport Rule to reduce visibility impairment in Class I 

areas impacted by pollution from the state because that Rule does not protect against very high 

short-term or seasonal emissions that degrade visibility. Under the Transport Rule, emission 

allowances are issued for a given year, but sources are under no obligation to ration the 

allowances out over the year. Instead, a source such as Joppa or Marion might choose to save its 

allowances for use during the summer ozone period when demand for electricity is at its peak 

and to idle during the rest of the year, failing to reduce emission during the months when Class I 

areas may be most likely to experience the most degradation in visibility. As such, even if the 

Transport Rule resulted in emission reductions from a source such as Joppa or Marion, there is 

no guarantee that those reductions would help ensure achievement of reasonable progress goals 

at Class I areas impacted by Illinois sources. In addition, while EPA has proposed to exempt 

BART sources from source specific BART requirements in reliance on the Transport Rule, 

nothing supplants the state's obligations or precludes it from issuing additional requirements to 

ensure that these non-BART facilities reduce adequate emissions to help ensure the goals of the 

Regional Haze Rule be met. 

In sum, because (i) Illinois relies heavily on the MPS/CPS and the Transport Rule to 

satisfY the requirement that it include in its SIP "all measures necessary to obtain its share of the 

emission reductions needed to meet the progress goal[s]" at Class I areas for which Illinois 

19 
sources contribute to visibility impairment, and (ii) neither the MPS/CPS nor the Transport Rule 

ensure that emissions reductions will be made- or be made at a time that visibility is most 

impacted- from two highly-polluting coal plants, Joppa and Marion, which are near Class I 

areas, Illinois has failed to meet the requirements of 40 C.F.R. § 51.308(d)(3). Illinois' LTS is 

deficient, and therefore its Regional Haze SIP must be disapproved. 

IV. CONCLUSION 

For the reasons stated herein, Illinois' proposed Regional Haze SIP does not comply with 

CAA requirements, and therefore must be rejected. In its place, EPA should promulgate a 

Regional Haze FIP that complies will the CAA and implementing regulations. 

Please do not hesitate to contact undersigned counsel with any questions or concerns. 

20 

Sincerely, 

1(1 

Jennifer L. Cassel 

Staff Attorney 

Environmental Law & Policy Center 

35 E. Wacker Dr., Suite 1600 

Chicago, IL 6060 I 

jcassel@elpc.org 

ph (312) 795-3726 

fax (312) 795-3730