BEFORE THE ILLINOIS POLLUTION CONTROL BOARD 

ILLINOIS POWER HOLDINGS, LLC and ) 

AMERENENERGY MEDINA VALLEY ) 

COGEN, LLC; ) 

) 

Petitioners, ) 

) 

AMEREN ENERGY ) 

RESOURCES, LLC ) 

) PCB No. 13-

Co-Petitioner, ) (Variance- Air) 

) 

v. ) 

) 

ILLINOIS ENVIRONMENTAL ) 

PROTECTION AGENCY, ) 

) 

Respondent. ) 

APPEARANCE 

I, Amy Antoniolli, hereby file my appearance in this proceeding on behalf of Petitioner, 

AMERENENERGY MEDINA VALLEY COGEN, LLC, and Co-Petitioner, AMEREN 

ENERGY RESOURCES, LLC. 

Dated: July 19, 2013 

/] 

~£~~) ' " 

SCHIFF HARDIN, LLP 

233 South Wacker Drive, Suite 6600 

Chicago, illinois 60606 

(312) 258-5550 

Fax: (312) 258-5600 

ATTACHMENT __ , __ 
BEFORE THE ILLINOIS POLLUTION CONTROL BOARD 

ILLINOIS POWER HOLDINGS, LLC and ) 

AMERENENERGY MEDINA VALLEY ) 

COGEN, LLC; ) 

AMEREN ENERGY 

RESOURCES, LLC 

Petitioners, 

Co-Petitioner, 

v. 

ILLINOIS ENVIRONMENTAL 

PROTECTION AGENCY, 

Respondent. 

) 

) 

) 

) 

) 

) 

) 

) 

) 

) 

) 

) 

) 

) 

PCB No. 13-

(V ariance - Air) 

APPEARANCE 

I, Renee Cipriano, hereby file my appearance in this proceeding on behalf of Petitioner, 

AMERENENERGY MEDINA VALLEY COGEN, LLC, and Co-Petitioner, AMEREN 

ENERGY RESOURCES, LLC. 

Dated: July 19, 2013 

' 

Renee Ciprian 

SCIDFF HARDIN, LLP 

233 South Wacker Drive, Suite 6600 

Chicago, Illinois 60606 

(312) 258-5550 

Fax: (312) 258-5600 
BEFORE THE ILLINOIS POLLUTION CONTROL BOARD 

ILUNOIS POWER HOLDINGS, LLC and ) 

AMERENENERGY MEDINA VALLEY ) 

COGEN, LLC; ) 

) 

Petitioners, ) 

) 

AMEREN ENERGY ) 

RESOURCES, LLC ) 

) PCB No. 13-

Co-Petitioner, ) (Variance- Air) 

) 

v. ) 

) 

ILLINOIS ENVIRONMENTAL ) 

PROTECTION AGENCY, ) 

) 

Respondent. ) 

APPEARANCE 

I, William D. Ingersoll, hereby file my appearance in this proceeding on behalf of 

Petitioner, ILLINOIS POWER HOLDINGS, LLC. 

#L,""-~ William D. Ingersoll '-" 

Dated: July 19, 2013 

BROWN, HAY & STEPHENS, LLP 

205 S. Fifth Street, Suite 700 

P.O. Box 2459 

Springfield, IL 62705-2459 

(217) 544-8491 

Fax: (217) 241-3111 
BEFORE THE ILLINOIS POLLUTION CONTROL BOARD 

ILLINOIS POWER HOLDINGS, LLC and ) 

AMERENENERGY MEDINA VALLEY ) 

COGEN,LLC; ) 

) 

Petitioners, ) 

) 

AMEREN ENERGY ) 

RESOURCES, LLC ) 

) PCB No. 13-

Co-Petitioner, ) (Vmiance- Air) 

) 

v. ) 

) 

ILLINOIS ENVIRONMENTAL ) 

PROTECTION AGENCY, ) 

) 

Respondent. ) 

APPEARANCE 

I, Claire A. Manning, hereby file my appearance in this proceeding on behalf of 

Petitioner, ILLINOIS POWER HOLDINGS, LLC. 

Dated: July 19, 2013 

Claire A. Manning 

BROWN, HAY & STEP 

205 S. Fifth Street, Suite 700 

P.O. Box 2459 

Springfield, IL 62705-2459 

(217) 544-8491 

Fax: (217) 241-3111 
CERTIFICATE OF SERVICE 

I, the undersigned, certify that on tllis 19th day of July, 2013, I have served electronically the 

attached PETITION FOR V AlliANCE, and APPEARANCES OF CLAIRE A. MANNING, 

WILLIAM D. INGERSOLL, RENEE CIPRIANO, AND AMY ANTONIOLLI, upon the following 

persons: 

John The1riault, Assistant Clerk 

illinois Pollution Control Board 

James R. Thompson Center 

Suite 11-500 

100 West Randolph 

Chicago, illinois 60601 

and by first class mail, postage affiXed upon: 

Division of Legal Counsel 

illinois Environmental Protection Agency 

1021 North Grand Avenue, East 

P.O. Box 19276 

Springfield, illinois 62794-9276 

BROWN, HAY & STEPHENS, LLP 

Claire A. Manning 

William D. Ingersoll 

205 S. Fifth Street, Suite 700 

P.O. Box 2459 

Springfield, IL 62705-2459 

(217) 544-8491 

Fax: (217) 241-3111 

SCHIFF HARDIN, LLP 

Renee Cipriano 

Amy Antoniolli 

233 South Wacker Drive, Suite 6600 

Chicago, Illinois 6Q606 

(312) 258-5550 

Fax: (312) 258-5600 
BEFORE THE ILLINOIS POLLUTION CONTROL BOARD 

ILLINOIS POWER HOLDINGS, LLC and ) 

AMERENENERGY MEDINA VALLEY ) 

COGEN, LLC; ) 

AMEREN ENERGY 

RESOURCES, LLC 

Petitioners, 

Co-Petitioner, 

v. 

ILLINOIS ENVIRONMENTAL 

PROTECTION AGENCY, 

Respondent. 

) 

) 

) 

) 

) 

) 

) 

) 

) 

) 

) 

) 

) 

) 

PCB No. 13-

(Variance- Air) 

NOTICE OF FILING 

To: ALL PARTIES ON THE ATTACI-IED SERVICE LIST 

Please take notice that today we have electronically filed with the Office of the Clerk of the 

illinois Pollution Control Board a PETITION FOR VARIANCE, and the APPEARANCE 01? 

CLAIRE A. MANNING, WILLIAM D. INGERSOLL, RENEE CIPRIANO, AND AMY 

Dated: July 19, 2013 

BROWN, HAY & STEPHENS, LLP 

Claire A. Manning 

William D. Ingersoll 

205 S. Fifth Street, Suite 700 

P.O. Box 2459 

Springfield, IL 62705-2459 

(217) 544-8491 

Fax: (217)241-3111 

SCHIFF HARDIN, LLP 

Renee Cipriano 

Amy Antoniolli 

233 South Wacker Drive, Suite 6600 

Chicago, Illinois 60606 

(312) 258-5550 

Fax: (312) 258-5600 
Electronic Filing- Recived, Clerk's Office: 07/22/2013 

**PCB 14-10** 

BEFORE THE ILLINOIS POLLUTION CONTROL BOARD 

ILLINOIS POWER HOLDINGS, LLC and ) 

AMERENENERGY MEDINA VALLEY ) 

COGEN, LLC; ) 

) 

Petitioners, ) 

) 

AMEREN ENERGY ) 

RESOURCES, LLC ) 

) PCB No. 14-10 

Co-Petitioner, ) (Variance- Air) 

) 

V. ) 

) 

ILLINOIS ENVIRONMENTAL ) 

PROTECTION AGENCY, ) 

) 

Respondent. ) 

PETITION FOR VARIANCE 

NOW COME PETITIONERS ILLINOIS POWER HOLDINGS, LLC ("IPH") and 

AMERENENERGY MEDINA VALLEY COGEN, LLC ("Medina Valley") (collectively, 

"Petitioners") and, along with AMEREN ENERGY RESOURCES, LLC ("AER"), ("CoPetitioner"), and pursuant to Sections 35 and 37 of the Illinois Environmental Protection Act 

("Act"), 415 ILCS 5/35, 37, and 35 Ill. Adm. Code Part 104, Subpart B, respectfully request that 

the Illinois Pollution Control Board ("Board") grant Petitioners dual variances from the sulfur 

dioxide ("SOz") annual emission rates provided for in 35 Ill. Adm. Code 225.233(e)(3)(C)(iii) 

and (iv), 1 the Illinois Multi-Pollutant Standard ("MPS") applicable specifically to the fleet of 

seven coal-fired power plants that are together the entities subject to this rule ("MPS Group" or 

"Ameren MPS Group"). 

1 Hereinafter, citations to the Board's regulations will be by section number only. 
Electronic Filing- Recived, Clerk's Office: 07/22/2013 

**PCB 14-1 0** 

The timing of this Petition is necessary in order to allow a seamless regulatory transition 

in concert with a planned change in ownership of the MPS Group from the current owner, CoPetitioner AER, to the new owners, Petitioners IPH and Medina Valley. 

I. PROCEDURAL BACKGROUND 

On May 5, 2012, AER filed a Petition for Variance with the Board and, on September 20, 

2012, the Board granted AER the relief requested. Ameren Energy Resources v. Illinois 

Environmental Protection Agency ("AER v. !EPA" or "PCB 12-126"), PCB 12-126 (Sept. 20, 

2012). The September 20, 2012, Opinion and Order ("Variance Opinion") in that proceeding 

informs this Petition, which involves the same facilities, the same regulations, and the same 

requested relief. 2 

The PCB 12-126 vanance involved alternative emJsswn rates for S02 from those 

promulgated in Sections 225.233(e)(3)(C)(iii) and (iv) of the Board's rules, known as the 

Ameren MPS Group Multi-Pollutant Standard ("Ameren MPS Rule"). 35 Ill. Adm. Code 

225.233(e)(3)(C)(iii) and 225.233(e)(3)(C)(iv). The Ameren MPS Rule is a system-wide rule 

applicable to a discreet group of seven coal-fired power plants, specifically: Coffeen Energy 

Center (Montgomery County); Duck Creek Energy Center (Fulton County); E.D. Edwards 

Energy Center (Peoria County); Newton Energy Center (Jasper County); Joppa Energy Center 

(Massac County); Hutsonville Energy Center (Crawford County) and Meredosia Energy Center 

(Morgan County). Variance Opinion, at 1. The Board granted relief from Section 

225.233(e)(3)(C)(iii)3 for five years beginning January 1, 2015, and ending December 31, 2019, 

2 The Petitioners request that the Board take administrative notice of its record in PCB 12-126. 3 Section 225.233(e)(3)(C)(iii) reads: "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 S02 annual 

emission rate of 0.25 lb/million Btu." 
BEFORE THE ILLINOIS POLLUTION CONTROL BOARD 

ILLINOIS POWER HOLDINGS, LLC and ) 

AMERENENERGY MEDINA VALLEY ) 

COGEN, LLC; ) 

AMEREN ENERGY 

RESOURCES, LLC 

Petitioners, 

Co-Petitioner, 

V. 

ILLINOIS ENVIRONMENTAL 

PROTECTION AGENCY, 

Respondent. 

) 

) 

) 

) 

) 

) 

) 

) 

) 

) 

) 

) 

) 

) 

RECEIVED 

Division of Legal Counsel 

JUL 2 4 2ou 

Environmental Protection 

Agency 

PCB No. 14-10 

(Variance - Air) 

PETITION FOR VARIANCE 

NOW COME PETITIONERS ILLINOIS POWER HOLDINGS, LLC ("IPH") and 

AMERENENERGY MEDINA VALLEY COGEN, LLC ("Medina Valley") (collectively, 

"Petitioners") and, along with AMEREN ENERGY RESOURCES, LLC ("AER"), ("CoPetitioner"), and pursuant to Sections 35 and 37 of the Illinois Environmental Protection Act 

("Act"), 415 ILCS 5/35, 37, and 35 Ill. Adm. Code Part 104, Subpart B, respectfully request that 

the Illinois Pollution Control Board ("Board") grant Petitioners dual variances from the sulfur 

dioxide ("S02") annual emission rates provided for in 35 Ill. Adm. Code 225.233(e)(3)(C)(iii) 

and (iv), 1 the Illinois Multi-Pollutant Standard ("MPS") applicable specifically to the fleet of 

seven coal-fired power plants that are together the entities subj ect to this rule ("MPS Group" or 

"Ameren MPS Group"). 

1 Hereinafter, citations to the Board's regulations will be by section number only. 

1 
The timing of this Petition is necessary in order to allow a seamless regulatory transition 

_:-"" • '""/ *: r a •H 1"'"1- ----s ..,._.:% 

in concert with''a 'planned :ehM\ge in ownership of the MPS Group from the current owner, Co-

·- <: .. -:Jt> ' 1 ;~ ~- \ jPetitioner AER, to the new owners, Petitioners IPH and Medina Valley. 

I. PROCEDURAL BACKGROUND 

-,-:' 

On MayS, ~?'H' AER filed a Petition for Variance with the Board and, on September 20, 

2012, the Board granted AER the relief requested. Ameren Energy Resources v. Illinois 

Environmental Protection Agency ("AER v. !EPA" or "PCB 12-126"), PCB 12-126 (Sept. 20, 

2012). The September 20, 2012, Opinion and Order ("Variance Opinion") in that proceeding 

informs this Petition, which involves the same facilities, the same regulations, and the same 

requested relief. 2 

The PCB 12-126 variance involved alternative emission rates for S02 from those 

promulgated in Sections 225.233(e)(3)(C)(iii) and (iv) of the Board's rules, known as the 

Ameren MPS Group Multi-Pollutant Standard ("Ameren MPS Rule"). 35 Ill. Adm. Code 

225.233(e)(3)(C)(iii) and 225.233(e)(3)(C)(iv). The Ameren MPS Rule is a system-wide rule 

applicable to a discreet group of seven coal-fired power plants, specifically: Coffeen Energy 

Center (Montgomery County); Duck Creek Energy Center (Fulton County); E.D. Edwards 

Energy Center (Peoria County); Newton Energy Center (Jasper County); Joppa Energy Center 

(Massac County); Hutsonville Energy Center (Crawford County) and Meredosia Energy Center 

(Morgan County). Variance Opinion, at I. The Board granted relief from Section 

225.233(e)(3)(C)(iii)3 for five years beginning January 1, 2015, and ending December 31, 2019, 

2 The Petitioners request that the Board take administrative notice of its record in PCB 12-126. 3 Section 225.233( e )(3)(C)(iii) reads: "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 SOz annual 

emission rate of 0.25 lb/million Btu." 

2 
and relief from Section 225.233(e)(3)(C)(iv)4 for three years, beginning January I, 2017, and 

ending December 31, 2019, making both variances expire simultaneously on January 1, 2020. 

Without this relief, the Ameren MPS Rule would have required the plants to achieve a systemwide (all seven plants) annual S02 emission limit of 0.25 pounds per million Btu ("lb/mmBtu") 

beginning in 2015 and 0.23 lb/mmBtu beginning in 2017. !d. at 7. In accordance with Section 

35(a) of the Act, the Board found that immediate compliance with the 2015 and 2017 S02 annual 

emission rates would have posed an arbitrary or unreasonable hardship. 5 !d. at 68. 

In its compliance plan in PCB 12-126, AER voluntarily committed to make earlier S02 

emission reductions than otherwise required by the Ameren MPS Rule during the years 2012 

through 2014. !d. Subsequent to discussions with the Illinois Environmental Protection Agency 

("the Agency" or "IEPA"), AER committed to, and the Board's Order imposed, mitigation S02 

annual emission rates to be met during the variance term. !d. The Board-ordered compliance plan 

also required AER not to operate the generating units at two of the plants from 2012 through 

2020, and set certain milestones and reporting dates related to the constmction of the flue gas 

desulfurization ("FGD") project at the Newton Energy Center ("Newton scmbber" or "Newton 

FGD project"). Id. at 68-69. 

The Board found that AER had demonstrated that requiring compliance with the MPS 

overall SOz annual emission rates by 2015 and 2017 would impose an unreasonable hardship on 

AER and on September 20,2012, granted the requested relief. !d. at 68. In granting the relief, the 

Board also determined that the earlier, more stringent S02 annual emission rates provided for in 

the compliance plan would result in a net benefit to Illinois air quality. !d. 

4 Section 225.233(e)(3)(C)(iv) reads: "Beginning in calendar year 2017 and continuing in each calendar year 

thereafter, for the EGUs in the Ameren MPS Group, the owner and operator of the EGUs must comply with an 

overall S02 annual emission rate of0.23 lb/mmBtu." 

5 A hearing was held in PCB 12-126 on August I, 2012, and the Board received over 3,000 public comments, both 

oral and written, in that proceeding. See Variance Opinion, at 2. 

3 
Subsequent to the Variance Opinion and due to the continued volatility of the merchant 

generating business, historically low power prices and a bleak financial outlook, Ameren 

Corporation ("Ameren"), AER's parent company, made a fundamental business decision to exit 

the merchant generating business. Exhibit 1, Affidavit of Martin Lyons ("Ex. I, Lyons Affidavit"), 

~6. Thereafter, Ameren entered into a Transaction Agreement ("Agreement") with IPH, an 

indirect subsidiary of Dynegy Inc. ("Dynegy"), dated March 14, 2013. Exhibit 2, Affidavit of 

Mario E. Alonso ("Ex. 2, Alonso Affidavit'), ~7. The Agreement was negotiated and carefully 

crafted to change ownership of the MPS Group and secure the variance relief and concomitant 

compliance obligations deemed appropriate by the Board in PCB 12-126. !d. ~~7, 8; Ex. I, 

Lyons Affidavit, ~9. In connection with the closing of the transaction, Ameren will initiate a 

reorganization of AER, which creates "New AER" for the acceptance of the active generating 

facilities of the MPS Group (Coffeen, Duck Creek, E.D. Edwards, Joppa, Newton) which will 

then be acquired by IPH. 6 Ex. 2, Alonso Affidavit, ~7; Ex. I, Lyons Affidavit, ~9. IPH will then 

acquire New AER and the five active generating plants. Ex. 2, Alonso Affidavit, ~4. The facilities 

required to remain shuttered under the Order in PCB 12-126 (Meredosia and Hutsonville) will be 

acquired by Petitioner Medina Valley, an indirect subsidiary of Ameren. Ex. 1, Lyons Affidavit 

~~9, 15. 

On May 2, 2013, in order to effectuate the transaction, IPH and AER filed a joint Motion 

to Reopen the Docket and Substitute Parties in PCB 12-126 ("Motion"). On June 6, 2013, the 

Board issued an Order denying the Motion which nonetheless stated: 

IPH may file a variance petition consistent with Section 104.202(a) of the Board's 

regulations, or may make any other appropriate filing concerning the facilities 

consistent with this order. 

6 In accordance with the Agreement, once the transaction closes, IPH will rename the acquired entity to remove all 

references to "Ameren" from its organization documents and representation materials. 

4 
PCB 12-126, slip op. at p. 11 (Jun. 6, 2013) ("Board Order on Motion"). 

As a result of the Board's discussion in the Board Order on Motion, Petitioners and CoPetitioner wish to address preliminarily two aspects of this Petition for relief. First, Petitioners 

wish to make clear that any petition for relief from the Ameren MPS Rule must include an 

analysis of all seven plants and not only the five plants to be acquired by IPH. This is because all 

seven plants remain part of the MPS Group regardless of ownership. Second, this Petition for 

relief is timely and includes all necessary parties. 

A. The Regulatory History and Framework of the Underlying MPS Regulations 

Requires that any Variance Address all Seven Facilities That Comprise the 

MPS Group. 

In its analysis of this variance request, the Board must consider the electrical generating 

units ("EGUs") located at all seven plants in the MPS Group. Accordingly, this Petition seeks 

relief applicable to all seven plants, and is supported by an analysis of the factors based on all 

seven plants as any variance requesting relief from the MPS Rule should. 

As a principal foundation of the MPS, the MPS applies fleet-wide and, once an owner or 

operator opts its EGU fleet into the MPS as an identified MPS group, those EGUs remain 

permanently part of that MPS group for regulatory purposes even if one or more of the EGUs are 

subsequently sold to a new owner. The Board must analyze, as it did for AER's request, how the 

variance will apply to all seven facilities in the MPS Group, not just those five that will be 

owned by IPH. This is so for three reasons. 

First, the EGUs at all seven facilities must permanently remain part of the MPS Group for 

regulatmy purposes because the Board relied on system-wide information in promulgating the 

Ameren MPS Group emission rates. The original MPS, found at Section 225.233, became 

effective on Janumy 5, 2007. In the Matter of Proposed New 35 Ill. Adm. Code 225 Control of 

Emissions fi'om Large Combustion Sources (Mercwy), R06-25 (Dec. 21, 2006). Sections 

5 
225.233(e)(3)(C)(iii) and (iv) were added to the MPS on June 18, 2009, and became effective 

July 15, 2009. 7 In the Matter of Proposed Amendments to 35 Ill. Adm. Code 225: Control of 

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

promulgated, the MPS delayed compliance with the mercury emission standards from July I, 

2009, to January I, 2015, but required compliance with stringent system-wide emission rates for 

nitrogen oxides ("NOx") and S02• Ameren opted all twenty-one steam electric generating units 

at seven plants into the MPS on December 27, 2007, 8 and has since been required to meet 

progressively declining emission rates for NOx and S02, as well as to meet interim requirements 

for controlling mercury emissions before January I, 2015. The MPS allows the MPS Group to 

average compliance across all EGUs in the system, thus enabling AER to over-comply at some 

units for the benefit of other units. 

In the initial MPS analysis, the Illinois Environmental Protection Agency ("IEP A" or 

"Agency") employed a method relying on data from the EGUs at all seven facilities to calculate 

an average heat input based on the three highest years between 2000 and 2007. 9 In the 2009 

revisions to the MPS, AER used the same Agency methodology, but included calendar year 2008 

to calculate the average heat input of 340,446,252 lb/mmBtu for the Ameren MPS Group. PCB 

12-126, AER's Responses to the Illinois Pollution Control Board Technical Unit's Questions, 8-

9 (July 30, 2012) (citing Mercury Monitoring, R09-10, Testimony of Michael L. Menne on 

Behalf of Ameren Companies, 15 (Feb. 2, 2009)). In both cases, the MPS rates were developed 

by relying on data from all seven facilities. 

7 The 2009 amendments added a section entitled "Ameren MPS Group Multi-Pollutant Standard," the 2015 S02 

annual emission rate of 0.25 lb/mmBtu and the 2017 SO? annual emission rate of 0.23 lb/mmBhL 

8 PCB 12-126, Petition, Ex. 4 (filed May 3, 2012). - 9 PCB 12-126, Petition, Ex. 4, Attach. B (filed May 3, 2012) (relying on years 2003,2004, and 2005). 

6 
T 

During the variance proceeding, the Agency supported the approach of considering the 

closures of Hutsonville and Meredosia in calculating emissions reductions (i.e., using a baseline 

heat input that includes Meredosia and Hutsonville), noting that "providing credit for actions 

(e.g., unit shutdowns) that result in emission reductions is an acceptable part of the established 

regulatory process." PCB 12-126, Recommendation, 21 (filed July 23, 2012). The Variance 

Opinion in PCB 12-126 affirmed the appropriateness of this approach. Again, the variance rates 

are founded on data from all seven facilities used to assess environmental impact and establish 

system-wide S02 and NOx emission rates for the MPS Group. 

As the owner of the units at the Newton, E.D. Edwards, Coffeen, Joppa, and Duck Creek 

Energy Centers, Petitioner IPH will be required to comply with the requirements currently 

applicable to the MPS Group. As the owner of Hutsonville and Meredosia, Petitioner Medina 

Valley will be required to keep those facilities shuttered during the term of the requested 

variance. In other words, the units at all seven of the Energy Centers that comprise the MPS 

Group will remain part of the same group and subject to the same emission rates even though 

ownership has changed. In fact, this regulatory construct will continue beyond the variance 

period. 

Second, the EGU s at all seven facilities must be analyzed together because the language 

of Section 225.233(a) plainly states that the MPS applies to all owners or operators ofEGUs that 

make up an MPS group. 35 Ill. Adm. Code 225.233(a). Section 225.233(a) further provides the 

general requirements for opting into the MPS in lieu of complying with the otherwise applicable 

emissions standards. !d. This provision contains what has been referred to as the "once in, always 

in" language, which states, "all EGUs [the owner] owns in Illinois as of July 1, 2006, ... must be 

thereafter subject to the standards and control requirements of this Section .... " Id. (emphasis 

7 
added). The same Section further states: "When an EGU is subject to the requirements of this 

Section, the requirements apply to all owners or operators of the EGU." !d. (emphasis added). 

This latter statement clearly anticipates that there could be multiple owners and/or operators of 

the EGUs included in an MPS group. Once part of an MPS group, the plain language of Section 

225.233(a) applies the MPS requirements to all owners of that EGU, including future owners. 

The regulation is not ambiguous. See Lee v. John Deere Ins. Co., 208 Ill. 2d 38, 43 (2003) 

(explaining the plain language of a statute or regulation is the best indicator of its intended 

meaning). 

Third, Agency testimony during the underlying rulemaking supports the conclusion that 

the seven facilities in the MPS Group must be considered together for regulatory purposes even 

if sold or transferred. It was well-established through Agency testimony during the promulgation 

of the MPS that it was the Agency's intent that once a unit becomes subject to the MPS 

regulations as part of an MPS group, that unit remains part of that group even if sold or 

transferred to another owner. The clear intent of structuring the MPS in such fashion is to keep 

the units that comprise an MPS group together for purposes of regulating annual emissions of 

S02, NOx, and mercury, as well as ozone season emissions of NOx. As one of the chief 

architects of the MPS, the Agency explained its position at hearing during the original mercury 

mlemaking, stating that once an owner or operator opts into the MPS, the MPS emission rates 

apply fleet-wide-even if one or more tmits are sold. When posed with a hypothetical involving 

the sale of some but not all units in an MPS group, Mr. Jim Ross, Bureau of Air Division of Air 

Pollution Control Manager, and Mr. Chris Romaine, Bureau of Air Manager of the Construction 

Unit in the Permit Section, both on behalf of the Agency, maintained that the "system-wide" 

average applicable to an MPS group would continue to apply to the same units even if some 

8 
were owned by a new company. The Agency witnesses further explained that compliance would 

need to be accounted for in the sale of units. 

MR. ROSS: What happens if a non-MPS company purchases EGUs that 

are subject to the MPS after July I, 2006? We did not contemplate that 

occurrence. The new owner, however, would be responsible for compliance of the 

units. And if the new owner is not using the MPS, then the units have to comply 

with the non-MPS provisions. 

MS. BASSI: I'm sorry. Did you just say that the MPS units would have to 

stay in the MPS but the non-MPS units would not? 

MR. ROMAINE: I believe so, yes. There's nothing, as this rule is drafted, 

that would say somebody purchasing a unit out of the multi-pollutant standard 

group would then be excused from compliance requirements of the multipollutant standards. It wouldn't necessarily trigger compliance with the multipollutant standard because they haven't opted in before, but that obligation would 

apply to units that have accepted that option. 

* * * 

MR. ZABEL: My hypothetical would be that assuming Ameren opts in 

and for whatever reason decides to sell its Coffeen plant to the Northern Indiana 

Public Service Company, how do you enforce a system-wide average when 

somebody just dropped out of the system? 

MR. ROMAINE: Actually, I think that's the easier part of it. It's simply as 

a group of the Ameren units that Ameren still owns plus at the Coffeen unit 

because the appropriate owners must comply with a particular emission rate. So 

the particular aspect, there are some things like allowances because there could be 

over-compliance from Coffeen separate from over-compliance of other units. 

Hopefully, when Ameren entered into such an agreement, it would work out those 

details to avoid the need for litigation to resolve how those matters should be 

handled. 

MR. ZABEL: Well, assuming in that hypothetical, that for whatever 

reason Ameren makes a mistake and emits too much sulfur, you're going to sue 

Northern Indiana Public Service? Let's assume it happened at Newton, which 

Ameren still owns, or three of their plants, however you like. Who gets sued? 

MR. ROMAINE: Good question. Who do you sue? 

MR. ZABEL: That's why I asked it. 

MR. ROMAINE: Obviously there's complications that this type of 

anangement would pose in a particular circumstance. Obviously that makes sale 

of units more complicated if Ameren would ever elect to do that. 

9 
MR. ZABEL: Thank you. 

Mercury, R06-25, Aug. 15 (am) Tr., 344-47 (Aug. 15, 2006). While the Agency, in its testimony, 

did not detail exactly how companies were to ensure compliance with the MPS rates after some, 

but not all, of the units in an MPS group are sold, the testimony is clear that the Agency expects 

compliance from the entirety of the MPS group as originally formulated by the Agency and AER 

in 2007. Accordingly, the Petitioners and Co-Petitioner must, as they have, address regulatory 

and compliance obligations in their transaction agreements. Therefore, in considering any 

request for relief from the Ameren MPS Rule, the Board must include in its analysis all seven 

facilities which comprise the Ameren MPS Group, as a whole, as it did in PCB 12-126, 

regardless of who owns the facilities. 

In keeping with the plain language of the regulation and the Agency's stated "once in, 

always in" intent of the MPS, IPH and Ameren have entered into an agreement for the sale of 

five of the seven facilities that comprise the MPS Group while taking special care to account for 

the continued compliance with the MPS emission rates of the units at all seven of the Energy 

Centers. Likewise, any analysis of the variance requested in this Petition must consider the EGUs 

at all seven of the facilities, regardless of ownership. This is how the Agency intended the MPS 

regulations to operate and it is based on the framework used to develop the original as well as 

current Ameren MPS Rule emission rates. Further, the Board adopted this system-wide 

regulatory approach, as is evident from the plain language of the rule. 

B. The Request is Timely and The Petitioners and Co-Petitioner Are All 

Necessary Parties. 

The Petitioners and Co-Petitioner meet the criteria for who may file a petition for 

variance. Section 104.202(a) is entitled "Who May File" and states "[a]ny person seeking a 

variance from any rule or regulation, requirement or order of the Board that would otherwise be 

10 
applicable to that person may file a variance petition." 35 Ill. Adm. Code 104.202(a) (emphasis 

added). Consistent with the Board Order on Motion, the Petitioners and Co-Petitioner are here 

prepared to demonstrate, on this record, that denial of the requested relief will present an 

arbitrary or unreasonable hardship that outweighs any adverse impact to the environment. Upon 

closing of the transaction, the Ameren MPS Rule will otherwise be applicable to both IPH and 

Medina Valley together unless a variance is granted and, accordingly, each is a proper Petitioner. 

As the current owner of the MPS Group, with a direct and substantial interest in this proceeding, 

AER is a proper Co-Petitioner. 

The proposed Order included herein has been crafted to create the obligations and secure 

the same relief as that found appropriate for the MPS Group in PCB 12-126. As to IPH, the 

proposed Order (a) grants the same relief as that secured by AER as it relates to the five plants it 

will own; and (b) sets forth compliance conditions that ensure ultimate compliance with the 

Ameren MPS Rule by the MPS Group and achieves environmental protection. As to Medina 

Valley (as well as to IPH), the proposed Order provides that the shuttering of Hutsonville and 

Meredosia is an enforceable obligation. 

The Petitioners here are the entities that will own and control the facilities that comprise 

the MPS Group. They are the persons to whom the Ameren MPS Rule for the MPS Group would 

"otherwise be applicable," as stated in Section 104.202(a). It is imperative that the Board provide 

regulatmy certainty to the new owners of the MPS Group without requiring existing ownership 

as a prerequisite. Nothing in the Act, or the Board's rules, requires, mandates, or justifies a 

different result. 

In the Board's Order on Motion, the Board relied primarily on an interim order in 

Ensign-Bickford Company v.IEPA, PCB 02-159 (April3, 2003). In denying IPH and AER's 

11 
joint motion to reopen the docket and substitute parties, the Board quoted the following 

portion of the interim order in Ensign-Bickford: 

[ t ]he Board's procedural rules do not provide for a third party to seek a 

variance or have a variance transferred on Dyno Nobel's behalf. If in fact 

the ... closing occurs, consistent with Section 104.202(a), Dyno Nobel may 

file a variance petition or other appropriate filing concerning this facility. 

PCB 12-126, Board Order on Motion, at 10-11. The quoted excerpt of the interim order is, 

however, immediately preceded in the original Ensign-Bickford text by the statement: 

"Although EBCo asks that the variance be transferred to Dyno Nobel Inc., Dyno Nobel is 

not a party to the motion." Ensign-Bicliford, PCB 02-159, slip op. at 2. Read in its entirety, 

the select paragraph of the Board's interim order in Ensign-Bicliford clearly denied the 

request to transfer because the future owner, Dyno Nobel, was not a party to the motion. 

This conclusion is further evidenced by the Board's statement that a third party cannot have 

a variance transferred on another party's behalf as well as the subsequent reference to 

Section I 04.202(a) (the Board's procedural rules for variance proceedings specifying "Who 

May File"). !d. In contrast to Ensign-Bickford, all the necessary parties are parties to this 

Petition for Variance. 

The Board's single statement that Dyno Nobel may file a variance petition if closing 

occurs is dicta, petitioner-specific and respectfully should be read in full context. 

Importantly, dicta does not have precedential value. Further, this single statement without 

full context does not prevent Dyno Nobel or any other petitioner from filing a petition for 

variance before it becomes the owner of a facility. In denying the request to transfer 

variance relief because the company was not a party to the motion, the Board invited Dyno 

Nobel to file a petition for variance after closing (which was scheduled 30 days from the 

date of the order), and it did not find that the company could not or should not do so before 

12 
closing. !d. There is simply no foundation for reading the Ensign-Bickford interim order to 

mean that Dyno Nobel or any other petitioner could not seek a variance prior to owning the 

facility. 10 

The Board has a long history of reading the Act and its procedural rules in a manner that 

provides the regulated community with the certainty it needs, as well as providing appropriate 

relief where justified and allowed pursuant to the Act-relief such as that which the MPS Group 

Petitioners seek here. See Allied Chern. Corp. & Inverness Mining Co. v. IEP A, PCB 80-92 

Order (May I, 1980); Opinion and Order (June 12, 1980). There, the Board granted relief to 

Inverness, who filed for a variance petition prior to its intended purchase of two mines in 

Southern Illinois (Hardin County) from Allied Chemical Corporation. The variance was granted 

because the Board found: "At the time this petition was filed [Allied] was in the process of 

selling these operations to Inverness. The parties agree and the Board finds that Inverness would 

suffer substantially the same arbitrary and unreasonable hardship if variances similar to those 

granted Allied were not granted. The previous Opinions in PCB 77-203 and PCB 79-149 are 

incorporated by reference." !d. 

Here, the variance granted in PCB 12-126 applies to the same MPS Group facilities that 

are the subject of this Petition and concerns the same specific regulatory framework relevant to 

that MPS Group. That relief is an essential term of the transaction and, as set forth below, is as 

10 Given other Board cases, see Allied Chem. Cmp. & Inverness Mining Co., PCB 80-92 Order (May 1, 1980); 

Opinion and Order (June 12, 1980), the Board should not rely upon the dicta in the Ensign-Bickford interim 

order as precedent to exclude a variance petition prior to closing. See Exelon Cmp. v. Dep 't of Revenue, 234 Ill. 

2d 266 (2009) (quoting United States v. Crawley. 837 F.2d 291, 292 (7th Cir.l988)) ("A dictum is 'any statement 

made by a court for use in argument, illustration, analogy or suggestion. It is a remark, an aside, concerning some 

mle of law or legal proposition that is not necessarily essential to the decision and lacks the authority of 

adjudication."'); Cates v. Cates, 156 Ill. 2d 80, 76 (1993) ("The term 'dictum' is generally used as an abbreviation of 

obiter dictum, which means a remark or opinion uttered by the way. Such an expression or opinion as a general rule 

is not binding as authority or precedent within the stare decisis rule."). 

13 
relevant to IPH as it is to AER and the same arbitrary and unreasonable hardship results to IPH if 

the relief is not granted. 

Moreover, the Board has previously granted variances as to multiple petitioners 

concerning future compliance dates such as those relevant here where, as here, petitioners 

established that such regulatory relief is warranted because the hardship of immediate 

compliance outweighs any injury to the environment. See Ill. Petroleum Marketers Ass 'n. v. 

!EPA, PCB 95-3 (May 4, 1995) (granting 157 gas stations in the Chicago nonattainment area an 

extension of the compliance date otherwise required for implementation of Stage II Vapor 

Recovery systems). 

II. REGULATION FROM WIDCH VARIANCE IS SOUGHT 

A. The Petitioners Seek Temporary Relief from the 2015 and 2017 S02 Annual 

Emission Rates of the Ameren MPS Rule. 

The Petitioners jointly seek relief from Section 225.233(e)(3)(C)(iii) and (iv) of the 

Ameren MPS Rule. As explained, this regulatory provision was created specifically for the 

seven coal-fired power plants in the MPS Group that are the subject of this Petition. Section 

225.233(e) states in relevant part: 

e) Emission Standards for NOx and S02• 

*** 

3) Ameren MPS Group Multi-Pollutant Standard 

*** 

C) S02 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 S02 annual emission rate of 0.25 lb/million Btu. 

iv) Beginning in calendar year 2017 and continuing in each 

14 
calendar year thereafter, for the EGUs in the Ameren MPS 

Group, the owner and operator of the EGUs must comply 

with an overall S02 annual emission rate of 0.23 lb/million 

Btu. 

The original MPS became effective on January 5, 2007. Mercury, R06-25, (Dec. 21, 

2006). Sections 225.233(e)(3)(C)(iii) and (iv) were added to the MPS on June 18, 2009, and 

became effective July 15,2009. R09-10 (June 18, 2009). 

Consistent with Section 35(a) of the Act, in PCB 12-126, the Board found adequate proof 

that compliance with the Ameren MPS Rule would impose an arbitrary or unreasonable 

hardship. In doing so, the Board effectuated the balance the Act requires, by finding that the 

hardship caused by a denial of such request "outweighs any injury to the public or the 

environment." PCB 12-126, at 48 (citing Marathon Oil Co. v. EPA, 242 Ill. App. 3d 200, 206 

(5th Dist. 1993)). Although not required to so find, the Board also concluded that the PCB 12-

126 variance "will result in a net benefit to the environment." PCB 12-126, at 48, 51-56, 58, 68. 

Utilizing the framework the Board established in that proceeding, relative to the very 

same MPS Group relevant here, as well as the same relevant regulation, this Petition seeks the 

identical relief. This Petition does take into account current economic, market, and regulatory 

conditions, even though those conditions are materially the same as existed at the time of the 

filing of PCB 12-126 on May 3, 2012. 

The variance relief in PCB 12-126 was granted on September 20, 2012, prospectively, 

since it was not triggered simultaneously with the date of the Board's final opinion and order. 

Variance Opinion, at 68-69. Instead, the variance set a new S02 emission rate during the years of 

2015 through 2019 in lieu of compliance with Sections 225.233(e)(3)(C)(iii) and 

225.233(e)(3)(C)(iv). !d. Fmiher, the compliance plan imposed more stringent interim S02 

emission rates during the years of2012 through 2014. !d. Here, the Petitioners seek, and justify, 

15 
that same relief. This variance request is, likewise, prospective and must be so that regulatory 

obligations and commitments under any order will be seamless and certain for the Board and the 

transacting parties. 

The relief granted in PCB 12-126 was deemed to be justified in order to allow for market 

conditions to improve prior to completing the Newton FGD project as scheduled, without any 

concomitant increase in total S02 emissions. At the end of the variance period, compliance with 

the Ameren MPS Rule, as written, will be achieved. This variance request, likewise, would allow 

for market conditions to improve prior to completing the Newton FGD project as scheduled, 

without any concomitant increase in total S02 emissions, and achieve compliance with the 

Ameren MPS Rule, as written, beginning in 2020. 

B. Each of the Dual Variances Does Not Exceed Five Years. 

The Petitioners seek relief from Section 225.233(e)(3)(C)(iii) for five years beginning 

January I, 2015, and ending December 31, 2019, and relief from Section 225.233(e)(3)(C)(iv) 

for three years, beginning January I, 2017, and ending December 31, 2019. In PCB 12-126, the 

Board previously granted AER this exact relief, for the very same seven power plants in the MPS 

Group that are the subject of this Petition, which are the sole subjects of Section 

225.233(e)(3)(C). See PCB 12-126. 

III. THE MPS GROUP FLEET INFORMATION AND NATURE OF ACTIVITY 

A. The MPS Group Includes Seven Illinois Coal-Fired Energy Centers. 

The seven coal-fired power plants that constitute the MPS Group, and which are the 

subject of this variance request, are all located in Central and Southern Illinois. See Exhibit 3, 

Map ofMPS Group ("Ex. 3, Map of MPS Group"). Exhibit 3 shows the location of these plants 

16 
and the air monitoring stations maintained by IEP A that are near them. 11 These seven Energy 

Centers are located in Montgomery County (Coffeen); Fulton County (Duck Creek); Jasper 

County (Newton); Peoria County (E.D. Edwards); Massac County (Joppa); Crawford County 

(Hutsonville); and Morgan County (Meredosia). As of the filing of this Petition, electricity 

continues to be generated at five of these facilities, since AER committed in PCB I 2-I 26 to 

cease operation of the electric generating units at Meredosia and Hutsonville during the term of 

the granted variance. All of the counties are currently designated attainment for all pollutants. 12 

B. The Fleet Operates Pollution Control Equipment to Minimize Emissions of 

S02 and Other Constituents. 

The principal emissions at the MPS Group power plants are S02, NOx, and particulate 

matter ("PM"). The MPS Group power plants generally control S02 emissions with pollution 

control equipment at several facilities as well as through the use of low sulfur coal, including 

blending low sulfur coal with Illinois coal that contains higher levels of sulfur. In particular, 

three scrubbers (a.k.a. "FGD units") are in service at the Duck Creek and Coffeen Energy 

Centers. NOx emissions are generally controlled by selective catalytic reduction systems 

("SCRs"), low NOx burners ("LNB"), over-fired air ("OFA"), and burning various 

combinations of low sulfur coal. PM IS generally controlled through the use of flue gas 

11 Exhibit 3, which consists of selected pages of the Agency's Illinois Annual Air Quality Report 20 II, includes 

a copy of the map at page 34, depicting the locations of the air quality monitoring stations with the locations of 

MPS Group superimposed. See http://www.epa.state.il.us/air/air-quality-report/2011/air-quality-report-2011.pdf. 

12 See United States Environmental Protection Agency ("USEPA") Green Book Nonattainment Areas for 

criteria Pollutants (2012)(listing national attainment and nonattainment designations) available at 

http://www.epa.gov/oar/oaqps/greenbk/. However, US EPA is considering the inclusion of a portion of Peoria 

County, which would include E.D. Edwards Energy Center, as a designated nonattainment area with respect to 

the one-hour S02 National Ambient Air Quality Standard ("NAAQS"). As explained later in this Petition, 

Ameren has filed a comment in USEPA Docket QA-OAR-2012-0233 objecting to such inclusion, which is 

attached hereto and incorporated herein as Exhibit 4 ("Ex. 4, Ameren Comment in Docket QA-OAR-2012-

0233"). 

17 
conditioning and electrostatic precipitators ("ESPs"). Mercury emissions are controlled through 

the use of scrubbers and sorbent injection technologies. 

In 2012, the MPS Group achieved an overall NOx annual emission rate ofO.ll lb/mmBtu 

and an overall S02 annual emission rate of 0.36 lb/mmBtu. Exhibit 5, MPS Group 2012 

Emissions Data ("Ex. 5, MPS Group Emissions Data"). The addresses of the seven Energy 

Centers, their IEP A identification numbers, permit application numbers, and other pertinent 

information regarding their output, pollution control equipment, and S02 emissions are provided 

in Exhibit 6, attached to this Petition ("Ex. 6, MPS Group information"). 

C. The Facilities Provide A Significant Economic Benefit to the State of Illinois. 

The operating Energy Centers are of significant economic benefit to the State of Illinois 

and its workforce, accounting for an estimated total economic impact on Illinois of 

approximately $1.5 billion annually and approximately 6,200 total direct and indirect jobs. 

The direct and indirect economic impacts have been analyzed by Development Strategies 

and are provided here as Exhibit 7, Group Exhibit of Five Memoranda ("Ex. 7, Group Exhibit"). 

Direct impacts include money spent on capital expenditures, operating costs, and salaries; 

indirect impacts include the multiplier effect of those dollars being spent in the community at 

local businesses for goods and services. See below table (Table A): 

Table A 

Coffeen Duck Creek Newton E.D. Joppa TOTAL 

Edwards ECONOMIC 

IMPACT 

Output 

(Total $534,944,000 $307,429,000 $288,339,000 $108,118,000 $193,530,000 $1,432,360,000 Economic 

Activity) 

Earnings $123,228,000 $66,590,000 $288,339,000 $29,941,000 $46,007,000 $554,105,000 

Direct Jobs 161 65 142 Ill 125 604 at the Energy 

18 
Centerr" 

Total Direc 

and Indirect 2,481 1,325 1,292 471 725 6,294 

Jobs 

If relief is not granted, and the transaction fails to close, Ameren will need to pursue other 

options. See Ex. 1, Lyons Affidavit 'i[l6. Ameren's stated intention to exit the merchant generation 

business to better focus on its core regulated business, inevitably means that AER will no longer 

be in a position to ensure the operation of these plants. Ameren would continue to explore exit 

possibilities which could include sale of the assets, the restructuring of debt and equity in AEG, 

or some combination thereof. !d. While it is difficult to predict the outcome of Ameren's exit 

strategy, there is no reason to believe that any other potential buyer will be willing to acquire the 

plants without this variance, unless the buyer intended to close one or more of the Energy 

Centers. Under a restructuring scenario, control and operation of the merchant business would be 

dependent on negotiation with bondholders thereby creating uncertainty for employees, 

suppliers, and local communities. !d. IPH, with a continuation of the variance relief granted to 

AER, represents the best path forward for the continued operation of those facilities in a manner 

that achieves ultimate compliance with the Ameren MPS Rule. !d. As the Board is well aware 

from the public comments and testimony during AER's PCB 12-126 variance proceeding, the 

Energy Centers are an integral part of the Southern and Central Illinois economy. Granting the 

Petitioners the requested variance relief represents the best alternative for the merchant business 

as it struggles through very distressed and uncertain economic and power market conditions. 

13 Table A only reflects employees who reside in Illinois. Some of the Energy Centers employ personnel from 

neighboring states. The total direct jobs at the Energy Centers are as follows: Coffeen 162 employees; Duck Creek 

66 employees; E.D. Edwards Ill employees; Joppa 176 employees; Newton 143 employees. Ex. 7, Group Exhibit. 

19 
D. Prior Variance Relief. 

The key relevant prior variance is the one granted by the Board in PCB 12-126. In 

petitioning for that variance, AER explained that it had never previously received variances of 

similar relief; however, it detailed variances previously received by it and other Ameren 

affiliated companies in other contexts. See PCB 12-126, AER Pet., at 6, 8. Medina Valley has not 

been the subject of any prior variance relief. 

As IPH is a new entity, it has sought no previous variance relief. Dynegy Midwest 

Generation ("DMG"), a separate Dynegy affiliate, sought and received a variance in Dynegy 

Midwest Generation v. !EPA, PCB 09-048. There, the Board granted a temporary nine-month 

deferral in implementation of mercury emission controls at Baldwin Unit 3 (Randolph County), 

while beginning mercury controls six months early on Havana Unit 6 (Mason County) and 

Hennepin Unit 2 (Putnam County). The PCB 09-048 variance resulted in an overall net reduction 

of 41.7 pounds of mercury emissions. 

DMG has previously obtained 45-day provisional variance relief from the Board on 

unrelated matters, such as effluent discharge limitations. See PCB 03-027 and PCB 03-234. 

Finally, DMG has a variance petition pending before the Board related to the S02 allowance 

restrictions under the MPS rule. See Dynegy Midwest Generation v. !EPA, PCB 12-135 (seeking 

a variance from 35 Ill. Adm. Code 225.233(±)(2)). 

IV. DETAILED DESCRIPTION OF COMPLIANCE PLAN 

A. Petitioners' Compliance Plan Will Achieve Compliance with All of the Terms 

of the Variance Opinion in PCB 12-126. 

As an integral part of its Compliance Plan accompanying this variance request, and in 

mitigation of the relief requested, the Petitioners propose that the MPS Group will meet an 

overall S02 aruma! mitigation emission rate of0.35lb/mmBhl through 2019. Committing to this 

20 
S02 annual mitigation emission rate in the Compliance Plan will impose significant operational 

restrictions on the Petitioners. The proposed rate will effectively commit Petitioner IPH to (a) 

maximize FGD performance at the Duck Creek and Coffeen Energy Centers, (b) continue to 

burn low sulfur coal (0.55 lbs sulfur/mmBtu) from the Powder River Basin at the E.D. Edwards, 

Joppa and Newton Energy Centers, and (c) manage generation as necessary to maintain 

compliance. The coal and performance commitments are discussed in more detail below. 

Fmiher, in order to meet the proposed mitigation emission rate, Petitioner Medina Valley also 

will commit to the continued cessation of operations of the electrical generating units at the 

Hutsonville and Meredosia Energy Centers through December 31, 2020, with the exception of 

the FutureGen project at the Meredosia Energy Center. That obligation is formalized in the 

proposed Order, making the commitment to maintain cessation of operations at Hutsonville and 

Meredosia an enforceable condition as to both IPH and Medina Valley, and as consistent with 

the enforcement approach ofiEPA as to the MPS Group. 

Further, Petitioner IPH will maintain a continuous program of construction at the Newton 

Energy Center, on the existing schedule set forth in the Variance Opinion, so as to be in a 

position to have the Newton FGD project completed and operational to meet compliance 

obligations. All major equipment components required to complete the Newton FGD project 

have been procured. Engineering design will continue through 2014. Field construction work 

will be staged so as to facilitate future construction sequencing. Ductwork and insulation 

activities will occur, the absorber building will be constmcted, and electrical systems and piping 

connections will be completed. Proceeding in this manner will position the Petitioners for 

compliance with the Ameren MPS Rule's final overall S02 annual emission rate (0.23 

lb/mmBtu) beginning in 2020, with the installation and operation of the Newton FGDs. 

21 
The Petitioners request a three-year variance from Section 225.233(e)(3)(C)(iv) to 

comply with the final overall S02 annual emission rate. As the Board determined in the prior 

proceeding, a shorter variance is not feasible because it would not allow sufficient time for 

financially viable completion of the Newton FGDs. The requested variance term also will allow 

Petitioners to properly stage and stagger the in-service date of each of the two Newton FGDs and 

to ensure that the FGD project achieves the expected S02 reductions. Petitioner IPH has 

analyzed all of the commitments made by AER in the prior proceeding, and has agreed to 

assume each and every commitment. As AER pointed out in its various filings with the Board in 

PCB 12-126, these obligations are not insubstantial. In sum, they are as follows: 

(i) From January I, 2013 to December 31, 2019, IPH will comply with an overall 

S02 annual emission rate of 0.35 lb/mmBtu. 

(ii) Beginning January I, 2020, IPH will comply with an overall S02 annual emission 

rate of 0.23 lb/mmBtu. 

(iii) With respect to the EGUs at the Meredosia and Hutsonville Energy Centers, the 

Petitioners will ensure that the EGUs will not be operated through December 31, 

2020 (one year beyond the entire term of the variance relief), with the exception 

of the FutureGen project at Meredosia Energy Center. 

(iv) With regard to the FGD project at the Newton Energy Center, IPH will comply 

with the obligations set forth in the PCB 12-126 variance, including all 

constmction milestone commitments and repmting obligations. 

1. IPH Will Continue to Use Low Sulfur Coal. 

As indicated above, agreeing to a mitigation emission rate during the variance term 

requires operational commitments above and beyond what is cunently required by law. AER 

22 
committed to limiting the use of higher sulfur coal to the Duck Creek and Coffeen Energy 

Centers, both of which have wet FGD systems, and to using low sulfur Powder River Basin 

("PRB") coal (0.55 lb/mmBtu) at the E.D. Edwards, Newton, and Joppa Energy Centers. 

Variance Opinion, at 50. By agreeing to the same S02 mitigation emission rate during the 

requested variance term, IPH will also be required to limit the use of high sulfur coal to the Duck 

Creek and Coffeen Energy Centers and use low sulfur coal at the E.D. Edwards, Newton, and 

Joppa Energy Centers. See Exhibit 8, Affidavit of Daniel P. Thompson ("Ex. 8, Thompson 

Affidavit), ~14. In fact, as a result of the transaction, IPH's acquired operating subsidiaries will 

inherit and be bound by the low sulfur coal purchase contracts that AER has already signed for 

coal purchases in 2013,2014,2015, 2016, and 2017. !d. 

Furthermore, in order to meet the requested variance's 0.35 lb/mmBtu S02 annual 

mitigation emissions rate, IPH anticipates the potential to purchase even lower sulfur coal than 

included in AER's commitment for Newton, E.D. Edwards and Joppa. !d.~~ 14, 28. Based on 

DMG's coal purchasing experience, IPH understands that 0.50 lb/mmBtu sulfur PRB coal is 

available from one supplier. !d. ~15. While IPH is committed to the 0.55 lb/mmBtu low sulfur 

coal contracts entered by AER for 2013-2017 as well as to using 0.55 lb/mmBtu low sulfur coal 

at Newton, E.D. Edwards and Joppa during the term of the variance, IPI-I anticipates potentially 

purchasing certain quantities of even lower sulfur coal, consistent with availability, perfom1ance 

risk, price, and the MPS Group's emission performance. !d. 

2. IPH Will Continue to Optimize Scrubber Performance. 

IPI-I also will operate the existing FGD systems at the Duck Creek and Coffeen Energy 

Centers at a 98-99 percent S02 removal rate. !d. ~24. While achieving and maintaining 98-99 

percent S02 removal is challenging, IPI-I is confident that it can operate the Duck Creek and 

23 
Coffeen Energy Centers at those removal efficiencies. Indeed, such efficiencies will be required 

(and are budgeted) in order to meet the mitigation emission rate presented as part of its 

Compliance Plan. 

B. Costs to Achieve Compliance Are Staggering. 

The costs required to achieve compliance with the MPS are staggering. Specifically, 

compliance with the MPS Group 2015 S02 annual emission rate (0.25 lb/mmBtu) as it exists 

without the variance will require the near immediate shut down of the E.D. Edwards and Joppa 

Energy Centers. !d. -,r12; Ex. 2 Alonso Affidavit, -,r8. As further explained below, such shutdown 

will have a devastating impact on the local economies and materially undermine the State's 

struggling economy. As the Board found in its Variance Opinion, the shutdown ofE.D. Edwards 

and Joppa would adversely impact 274 direct jobs, 1,374 indirect jobs, over $121 million per 

year in the local economies near the two plants, and over $338 million per year in the State's 

economy. 

To date, AER has spent over $1 billion in capital expenditures to comply with its MPS 

Group environmental obligations. Variance Opinion, at 62-63; Pet. 17, 18; Tr., at 16; Post 

Hearing Brief, at 31. That includes installation of S02 scrubbers on three units at a cost of over 

$813 million, installation of SCR systems to reduce NOx emissions at three plants at a cost of 

over $177 million, and installation of activated carbon injection ("ACI") teclmology on 12 units 

at a cost of over $20 million. Variance Opinion, at 13. In addition, AER has spent over $7 

million annually in operating costs for the SCRs and a total of about $17 million for operation of 

the ACI systems. !d. at 17. 

Total costs of construction for the two FGD units at the Newton Energy Center are 

estimated to be approximately $500 million. Ex. 8, Thompson Affidavit, -,r2s. Approximately one 

24 
half of the total costs have been spent to date. !d. In accordance with the construction milestones 

in the proposed variance order, IPH has budgeted $18 million in annual expenditures through 

2017 with the remainder of total estimated spending scheduled for 2018 and 2019 to complete 

construction of the Newton FGDs and achieve compliance at the end of the variance period. !d. 

In addition, for the five Energy Centers, IPH estimates several million dollars in average annual 

Operations and Maintenance ("O&M") expenditures through 2019 to comply with the MPS NOx 

and mercury emission limits. !d. 

Without the variance, IPH's compliance with the MPS Rule 2015 S02 emission rate 

would require virtually immediate completion of the Newton FGD project which, at this time, 

given the variance relief afforded AER, and the anticipated construction schedule contained in 

that variance, is virtually impossible. !d. ~13. Moreover, upon closing IPH simply will not have 

the financial resources to cover such immediate construction expenditures. Ex. 2, Alonso 

Affidavit, ~24. Thus, the Board's endorsement of a multi-year (2015-2019) construction schedule 

in PCB 12-126 is quite relevant to this Petition. 

V. ARBITRARY OR UNREASONABLE HARDSHIP 

The very same hardship factors recognized by the Board in its Variance Opinion, decided 

less than ten months ago, are also relevant here. Given current conditions, those factors are even 

more onerous and immediate. 

A. Regulatory Uncertainty Still Exists at the Federal Level and Illinois Stands 

Alone. 

As the Board recognized in its Variance Opinion, the Ameren MPS Rnle was developed 

with the belief that federal regulations related to the MPS Group were imminent. Variance 

Opinion, at 5. Yet, the expected federal regulations have not materialized, and Illinois stands 

25 
alone in its stringent MPS requirements, putting the MPS Group at a disadvantage to its 

competitors. !d. at 10. None of that changes under the new ownership. 

In May 2005, USEPA promulgated the Clean Air Mercury Rule ("CAMR") that 

established a cap on mercury emissions from coal-fired EGUs serving generators with nameplate 

capacity greater than 25 megawatts. 70 Fed. Reg. 28606 (May 18, 2005). However, in February 

2008, the United States. Court of Appeals for the District of Columbia vacated CAMR. New 

Jersey v. EPA, 517 F .3d 574, 583 (D.C. Cir. 2008). 14 

Also in May 2005, USEPA promulgated the Clean Air Interstate Rule ("CAIR"), which 

required reductions of S02 and NOx to address interstate ozone and fine particulate matter 

("PM2.s") pollution. 70 Fed. Reg. 25162 (May 12, 2005). CAIR established a cap on emissions of 

S02 and NOx for coal-fired EGUs. !d. But, in July 2008, the D.C. Circuit Court of Appeals 

vacated CAIR. See North Carolina v. EPA, 531 F.3d 896, 929-30 (D.C. Cir. 2008). Later, upon 

request of USEPA, the court remanded CAIR without vacatur and ordered CAIR to remain 

effective until USEPA replaced it with a new rule. See North Carolina v. EPA, 550 F.3d 1176, 

1777-78 (D.C. Cir. 2008). 

In an attempt to promulgate a replacement rule for CAIR, USEPA adopted the CrossState Air Pollution Rule ("CSAPR") in 2011. 76 Fed. Reg. 48208 (Aug. 8, 2011). The mle was 

designed to reduce annual and seasonal S02 and NOx emissions from EGUs in upwind states to 

areas in downwind states. !d. at 48349. The D.C. Circuit Court of Appeals also vacated this mle 

in August 2012. EPA v. EME Homer City, 696 F.3d 7 (D.C. Cir. 2012), cert. granted, 2013 WL 

1283840 (June 24, 2013). On June 24, 2013, the United States Supreme Court issued certiorari 

and will review the decision vacating CSAPR next term. !d. This recent development puts in 

14 The US EPA subsequently adopted the Mercmy and Air Taxies Standards ("MATS") to control EGU emissions, 

77 Fed. Reg. 9304 (Feb. 16, 2012), but that rule is currently being appealed to the District of Columbia Circuit Comt 

of Appeals. See White Stallion Energy Ctr., LLC v. EPA, No. 232200 (D.C. Cir., Feb. 16, 2012). 

26 
play more directly the uncertainty coal-fired power generators face as they await both how the 

Supreme Court will rule and whether USEP A will continue to move forward on developing a 

CAIR/CSAPR replacement yet again. 

The uncertainty involving the future applicability of any federal rule to control the 

interstate transport of air pollution is further compounded by President Obama's Climate Action 

Plan announced on June 25, 2013. 15 The Presidential Memorandum, issued together with the 

President's Climate Action Plan, directs USEP A to issue final carbon pollution reduction 

standards for existing power plants "no later than" the ambitious deadline of June I, 2015. 16 

Indeed, in no uncertain terms, President Obama has made power plant carbon pollution reduction 

a top priority of this Administration. How this action may specifically implicate the five 

operating Energy Centers in the MPS Group is, at this point, anyone's guess. While the 

Presidential Memorandum states that USEP A must ensure that carbon standards are developed 

and implemented in a manner "consistent with the continued provision of reliable and affordable 

electric power for consumers and businesses," 17 no one yet knows how USEPA will interpret its 

mandate to set new carbon pollution standards. 

Given the uncertainty and lack of detail surrounding federal regulatory initiatives and 

structures, including the President's climate change mandate, planning for the future regulatory 

compliance is now even more complex for merchant generators, as such regulatory uncertainty 

complicates decision-making and negatively impacts markets and power prices. The Board's 

denial of this variance request would only complicate these matters further. Until the federal 

regulatory obligations are sufficiently clear, it is even more imperative that the State of Illinois, 

15 Exec. Office of the President, The President's Climate Action Plan (June 2013). 

16 The White House, Office of the Press Secretary, Memorandum for the Administrator of the Environmental 

Protection Agency, Subject: Power Sector Carbon Pollution Standards (June 25, 2013). 78 Fed. Reg. 39535 (July I, 

2013). 

17 !d. at §I(c)(v). 

27 
through the Board, stay on the course that the Board found appropriate in PCB 12-126; if 

changes requiring plant closures occur at the federal level, those changes will be implemented 

nation-wide, in a manner that does not unfairly implicate Illinois merchant generation. 

B. Due To An Unforeseen Sequence of Events, Illinois Power Generators 

Operate At An Economic Disadvantage Compared to Competitors In 

Surrounding States. 

The hardship the Ameren MPS Group now faces was not foreseeable. While the impact 

of the CSAPR stay has been felt nationally, it has been felt acutely in Illinois where the MPS 

imposes a uniquely structured emission program in a state that has also experienced drastic 

changes in power prices and market conditions in the very recent past. This series of events 

makes compliance with the emission rates at issue an arbitrary and unreasonable hardship for any 

owner of the MPS Group. 

The Illinois General Assembly adopted the Electric Service Customer Choice and Rate 

Relief Law of 1997. See 220 ILCS 5/16-101. One of the primary purposes of this law was to 

incent the Illinois utilities to transfer 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. The 1997 law created an expeditious process for transferring generating plants that 

was available for a limited amount of time (the mandatory transition period). As a result of the 

legislature's deregulation of Illinois' energy markets in 1997, Illinois generators cannot recover 

the costs of capital projects, including those relating to environmental mandates, through captive 

consumer rates. Rather, merchant power companies' investment decisions such as the installation 

of pollution control equipment are based on the ability to recoup such expenditures from 

expected future market prices for power. 

28 
The deregulated market does not alone create the hardship that the MPS Group now 

faces. It is well-recognized that in promulgating the MPS rule in 2006, Illinois adopted emission 

reduction requirements significantly more stringent than other states-with the unintended 

consequence of putting the Illinois merchant generation business at a substantial disadvantage to 

its out-of-state competitors. Those mandates, however, were adopted in anticipation of federal 

mandates-which, as explained below, have been subsequently vacated, remanded or are 

currently on appeal. Meanwhile, Illinois' MPS regulations are now among the strictest in the 

nation; quite simply, other neighboring states have not adopted state air regulations in advance of 

a federal mandate. 18 

Since the MPS was adopted in 2006, economic conditions have fallen beyond any price 

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

enacted in 2006. The new methods of gas extraction are a "game-changing" technology that have 

fundamentally altered the outlook for gas supplies and pricing. The general recessionary 

economic conditions have also depressed the demand for power and, therefore, power prices. 

Further, mandatory requirements that certain percentages of the total retail electric supply come 

from renewable resources, enacted in Illinois in 2007, have also reduced the demand for power 

from traditional sources, and consequently prices. In sum, the MPS was premised on the 

expectation that the power market would continue to support the capital expenditures necessary 

to meet the proposed emission rates. Today, however, market prices for power cannot support 

the necessary capital expenditures to complete the Newton FGD project in time to meet the MPS 

18 For example, Indiana, Kentucky, Missouri, Iowa, and Ohio have no mercury emission mles. Wisconsin requires 

that large coal-fired EGUs apply control technology to reduce mercury emissions 90 percent by January 1, 2015, or 

comply with a multi-pollutant option that achieves 90 percent mercury reduction by January I, 2021. Wis. Adm. 

Code, Dept. of Natural Res., NR 446 et seq. Michigan requires mercury reductions from coal-fired EGUs by January 

I, 2015, or achieve 75 percent reduction under a multi-pollutant option. Mich. Adm. Code, Part 15, R 336.2501 et 

seq. Minnesota requires 90 percent mercury reduction by 2015 from the State's three largest electric power plants; 

remaining facilities must reduce mercury emissions 70-90 percent by 2025. Minn. Stat. §115A.932 et seq. 

Moreover, none of our neighboring states have as stringent 802 standards as in the Illinois MPS. 

29 
2015 and 2017 S02 emission rates. Market conditions and new technologies and policies that 

have come about since that time were not self-imposed and simply not foreseeable. It is the 

convergence of these factors that amount to the arbitrary and umeasonable hardship that any 

owner of the MPS Group now faces. 

Generators in neighboring states who have not had to make such emJsswn control 

equipment investments or are able to recover such costs through the consumer rate base are able 

to offer their power into the marketplace, including the Illinois marketplace, without any such 

cost considerations. Also, as Illinois proceeded towards deregulation, regional transmission 

organizations formed through which power generators were more easily and efficiently able to 

sell power across state lines. As a result, AER now competes with generators in several nearby 

states that have neither deregulated their energy markets nor invested significant capital in 

environmental pollution control projects to address stringent state requirements. Thus, when 

Illinois requires merchant generators to install controls not required of companies in surrounding 

states, or by the federal government, at a time when the Illinois economy is abysmal, 19 the Board 

must engage in a responsible cost-benefit analysis, as the legislature has provided for in Section 

35(a) of the Act. 

C. Hardship Caused by Plant Closures. 

Unless Petitioners receive the requested variance relief, plant closures are inevitable. It is 

for this reason that the Petition has been filed now. 20 If the Board does not allow the Petitioners 

the MPS variance relief it deemed appropriate as to AER, for the very same MPS Group, and 

19 See Sarah Burnett, Illinois Credit Rating: State's Worst In Nation Costing Tax Payers Millions, Huffington Post, 

June 25, 2013, available at http://www.huffingtonpost.com/2013/06/25/illinois-credit-rating-st_n_3496264.html. 20 A Board decision requiring this variance petition to be filed after IPH acquires ownership of the plants, without 

any review of the appropriateness of the requested relief pursuant to Section 35(a) and this Petition, would inject a 

great and unnecessaty uncertainty regarding the continued viability and operation of the Energy Centers. As stated 

in Section I.B above, such result is not legally required and any policy interpretation otherwise is tantamount to a 

detem1ination that, in Illinois, corporations cannot transact with certainty as to existing Illinois regulatory 

obligations. 

30 
IPH nonetheless moves forward with the transaction, IPH' s only compliance option would be to 

shut down a combination of Energy Centers by January 1, 2015. Ex. 2, Alonso Affidavit, ~8. 

Given depressed power prices that have existed over the past several years and which will 

continue for several more years, compliance with the MPS 2015 and 2017 overall S02 annual 

emission rates in Sections 225.233(e)(3)(C)(iii) and (iv) is not achievable without the shutdown 

of Energy Centers, in this case the E.D. Edwards and Joppa Energy Centers. Assuming the 

transaction closes, IPH and Ameren anticipate closing on the transaction in the fourth quarter of 

2013. !d. IPH will not have the financial resources required to complete installation of the 

Newton FGDs at that time; in any event, even if the needed financial resources were available 

(which they are not), the Newton FGDs could not, absent the variance, now be completed in time 

to avoid shutting down the E.D. Edwards and Joppa Energy Centers. !d. ~~8, 20. 

Should the IPH transaction not close, Ameren would continue to explore exit 

possibilities, which could include the sale of assets, the restructuring of debt and equity in 

GENCO, or some combination thereof. Ex. 1, Lyons Affidavit, ~16. As previously noted, under a 

restructuring scenario, control and operation of the merchant business would be dependent on 

negotiations with the GENCO bondholders and, ultimately, the result of such restmcturing 

proceedings thereby creating uncertainty for employees, suppliers and local communities. 

Ameren has no reason to believe that any other potential buyer would be willing to acquire the 

Energy Centers without the variance, unless such buyer intended to close one or more plants. !d. 

IPH, with a continuation of the variance relief granted to AER, represents the best path forward 

for the continued operation of the Energy Centers and in a manner that achieves ultimate 

compliance with the Ameren MPS Rule. 

31 
The shutdown of the E.D. Edwards and Joppa Energy Centers would, as previously 

considered by the Board in PCB 12-126, adversely affect 274 direct jobs, 1,374 indirect jobs, 

over $121 million per year in the local economies near the two plants, and over $338 million per 

year in the State's economy. Variance Opinion, at 62. In short, the economic impact of shutting 

down the E.D. Edwards and Joppa Energy Centers would devastate their local communities and 

materially undermine the State's struggling economy. The shuttering of these plants will create 

an arbitrary or umeasonable hardship on IPH, the local economies served by those facilities and, 

more generally, the State's economy. See, for example, the public comments made by local and 

state officials and others at the Board's hearing in PCB 12-126, held less than one year ago, 

about the E.D. Edwards, Joppa and Newton Energy Centers: 

Senator Gary Forby (Tr., at 57-59) 

Sen. Forby discussed the Joppa Power Plant. While he recognized it needs some 

improvements, he stated that the issues before the Board in that proceeding were "all 

about jobs" which is the main thing the State of Illinois, especially southern Illinois, 

needs. He wants southern Illinois to "stay a part of Illinois" and keep its economic 

development going. He is just asking for their "fair share." 

Representative Brandon Phelps (Tr., at 59-62) 

Rep. Phelps' comments focused on the Joppa Power Plant, also in his district. As 

Chairman of the Honse Public Utilities Committee, he recognized that the government 

and private sectors are facing a huge financial crisis. He explained that Joppa provides 

164 well-paying jobs for southern Illinois which, when compared to Chicago 

demographics, is the equivalent to 10,000 jobs in southern Illinois. Economics must 

factor into Illinois' environmental regulations and pollution control because these rules 

were adopted assuming that federal rules would soon follow their adoption. While he 

recognized the commitment of the power companies to reduce emissions, he 

recommended that compliance be deferred to a later date given the current economic 

situation. 

Representative David Reis (Tr., at 63-66) 

The Newton Plant, which is located in his district, is the largest private employer in 

Jasper County. The plant employees 155 people and losing those jobs would crush Jasper 

County's economy and the local school system. Those 155 jobs in a county of less than 

10,000 people equates to losing 41,800 jobs in Chicago (pop. 2.7 million). 

32 
Rep. Reis stated that the United States emissions are only a "thimble of water in the 

pond" and that unilateral American reductions in greenhouse gases and S02 will have a 

negligible impact on atmospheric conditions worldwide. He believes it is not 

unreasonable to give the Newton plant the time requested to come into compliance. 

Speaking for the people of Jasper County, he stated that they don't have big organizations 

representing them, or lobbyists or lawyers, just themselves and their concern for their 

community, schools, and jobs. 

Mayor Mark Bolander of Newton (Tr., at 79-81) 

Newton has an annual economic impact on the state, in direct spending, of$71.5 million; 

total economic activity, over $231 million; direct jobs at plant 158; and total direct and 

indirect jobs 978. The $71.5 million in direct spending triggers an additional $141.6 

million in value added activity in Illinois, of which $40.5 million was household earning 

that supported 820 jobs. The $213 million in total economic activity triggers nearly $56.9 

million in household earnings for Illinois workers including $16.4 million in direct 

compensation and $40.5 million in added eamings from the multiplier effects. 

For the labor market, the Newton plant provides a direct spending of $67.5 million; total 

economic activity of$154.3 million; direct jobs of 120; and total direct and indirect 553 

jobs in Newton's labor market. The $67.6 million in direct spending triggered an 

additional $86.7 million in value added activity in the market area ($22.7 million was 

household eamings, supporting 433 jobs). The $153.4 million of total economic activity 

supported $35.1 million in household eamings for the market area including $12.4 

million in direct compensation for employees, and $22.7 million in added eamings. 

Jasper County Board Member Bill Webber (Tr., at 81-84) 

The Newton Energy Center recently gave a $7 million check to the Jasper County 

treasurer, for the payment of local taxes which support the schools, the community 

college district, the library board, fire department district, the county, the extension 

service and various other govemment services. It represents a little over 51% of the total 

tax revenue for the county. 

Mayor Billy McDaniel of Metropolis (Tr., at 103-106) 

There are 235 well-paying jobs at the Joppa plant-well above the average income in the 

area. The plant pays about $800,000 a year in property taxes and real estate taxes. The 

plant and its employees spend hundreds of thousands of dollars on vendors in the city. 

Jasper County School Board Superintendent Dan Cox (Tr., at 106-108) 

The Newton Energy Center represents 60% of the local tax revenues for Jasper County 

Schools, which translates into $4 million per year to the school district. 

Jean Ellen Boyd from Shawnee Community College (Tr., at 111-112) 

The property taxes from the Joppa facility provide $86,000 per year to the college. 

33 
Vicky Clark President of Economic Development Council for Central Illinois (Tr., 

at 189-191) 

The E.D. Edwards Energy Center provides 110 jobs in Bartonville. The wages generated 

from those jobs create an additional 450 jobs through spending in the local economy. 

Closing of Edwards would result in a loss of over $124 million annually to the local 

economy. 

Bill Sheppard from Joppa Plant (Tr., at 192-195) 

In 2011, there were approximately 150,000 man-hours of building trade/crafts man hours 

worked at Joppa. The Joppa plant spent $116 million per year over the last five years 

with Illinois vendors and suppliers. 

D. Poor Market Conditions for the Power Generation Industry Continue to 

Contribute to an Arbitrary and Unreasonable Hardship. 

Due to AER' s limited financial resources caused by depressed power prices and poor 

economic conditions over the past several years and its inability to obtain external financing, IPH 

will not be able to fund completion of the Newton FGDs in time to comply with either the 2015 

or 2017 MPS S02 annual emission rates. Ex. 2, Alonso Affidavit, ~24. Nor is adequate funding 

available to implement any other feasible MPS compliance alternatives available to IPH as 

demonstrated in Section VI. These financial considerations lead to an inevitable conclusion that, 

without the variance, the plant closures discussed above will occur-causing a significant 

hardship to the Petitioners, employees who work at the Energy Centers, the local communities 

the Energy Centers support, and the State of Illinois. Moreover, the same financial considerations 

the Board addressed in PCB 12-126 as it relates to hardship continue to be equally relevant here. 

1. Power Prices/Market Conditions Remain Depressed and Are Not Expected 

to Begin Gradual Recovery Until 2015. 

Construction of the Newton FGD in time to meet the existing MPS is an impossibility 

both in terms of construction timeframe and required financial resources. Because IPH will not 

acquire ownership of the Acquired Plants until late 2013 and because construction activities 

needed to install the Newton FGDs are expected to take up to 24 months, IPH could not 

complete construction of the Newton FGDs in time to comply with the MPS 2015 overall S02 

34 

' 
£'. 

annual emission rate, even if IPH were financially able to ramp up construction immediately 

upon acquiring ownership, which it is not. Ex. 8, Thompson Affidavit, ,; 12. The lack of financial 

resources needed to complete installation of the Newton FGDs in order to meet the MPS is the 

direct result of severely depressed power prices which are expected to continue for the next 

several years. Ex. 2, Alonso Affidavit, ,;,;11, 20, 23, 24. As a merchant generator, the source of 

revenues for IPH21 is the sale of electricity; thus, IPH is largely dependent on the commodity 

price of electricity. Id. ,;11. As relevant to the Energy Centers, power prices declined from 

approximately $60 per megawatt hour in 2006-2007 to approximately $29.50 to $33.50 per 

megawatt hour in 2012. See Variance Opinion, at 63; Ex. 2, Alonso Affidavit, ,;11. The steep 

decline in power prices is largely due to the combination of excess natural gas supplies resulting 

from increasing unconventional natural gas production from shale deposits, which has resulted in 

low natural gas prices, and lower demand resulting from poor overall economic conditions. See 

Variance Opinion, at 62 (recognizing AER's contentions that the new methods of gas extraction 

are a "game changing" technology that have "fundamentally altered" the outlook for gas supplies 

and pricing); see also Exhibit 9, Affidavit of George W Bilicic ("Ex. 9, Bilicic Affidavit"), ,;6. 

Power prices remain depressed today, currently at approximately $31.85 per megawatt 

hour. Ex. 2, Alonso Affidavit, ,;11. Current forecasts by independent market observers and 

financial analysts expect power prices to remain depressed for the next several years. Ex. 9, 

Bilicic Affidavit, ,;6. Objective market expectations for the next several years are that power 

prices will remain depressed and natural gas prices will remain at distressed levels. See below 

Table B: 

21 As a holding company, !PH will conduct substantially all of its business operations through its subsidiary New 

AER, as acquired from Ameren, and New AER's subsidiaries, including Ameren Energy Generating Company 

("GENCO"), AmerenEnergy Resources Generating Company ("AERO"), Ameren Energy marketing Company 

("Ameren Marketing"), Electric Energy, Inc., and Midwest Electric Power, Inc. See Ex. 2, Alonso Affidavit, 1\6. 

35 
Table B 

Ex. 2, Alonso Affidavit, ~11. These forecasts of future power prices suggest that earnings 

pressure at IPH (or New AER as referred to by Mr. Bilicic) will continue in the near term. Ex. 9, 

Bilicic Affidavit, ~6 (citing Moody's Unregulated Utility & Power Companies: Still No Sign of 

Recovery (Feb. 6, 20 13)). Other source data reflects slightly different price forecasts than those 

reflected in Table B, but confirms the same basic trend. I d. ~6 (citing SNL, prices as of 

7/5/2013). 

2. IPH Will Not Have Sufficient Financial Resources to Comply with the MPS 

2015 and 2017 S02 Compliance Deadlines. 

With power prices reiiJaining depressed, IPH will continue to face the continuing 

financial pressures that AER faced at the time of its variance petition. I d.; Ex. 2, Alonso 

Affidavit, ~~13, 14. These depressed power prices have severely eroded operating margins of the 

Energy Centers in the MPS Group and will continue to limit the ability of the Energy Centers to 

generate cash flow for the next several years. Ex. 2, Alonso Affidavit, ~24. Without those 

operating margins, IPH will not have the cash flow from power sales to fund large scale capital 

expenditures needed to comply with the MPS, such as completion of the Newton FGDs. Id. 

The power industry is a cyclical commodity business with significant price volatility 

requiring considerable investment requirements. As such, it is imperative to build and maintain a 

balance sheet with manageable debt supported by a multi-faceted liquidity program to support 

daily operations. Importantly, IPH will sell power primarily into the regional electricity market 

36 
known as "MISO" (the Midcontinent Independent System Operator, Inc.). Participants in MISO 

include both regulated utilities and merchant generators. Id. ~II. As previously discussed, 

merchant generators like IPH do not have a regulated consumer rate base, meaning that 

environmental or other compliance costs cannot be recovered by rates from captive consumers. 

Instead, to cover their costs of doing business, merchant generators rely primarily on revenues 

obtained from selling power in the competitive wholesale electricity market. Id. Thus, as a 

merchant generator, IPH and the Energy Centers will face significant exposure to market prices, 

swings in load demand, and commodity price volatility. Id. ~13. 

Furthermore, as previously discussed, because the Energy Centers are at the mercy of the 

marketplace, they are more challenged by Illinois' stringent environmental mandates than (a) 

merchant generators in neighboring states that are not required to invest in capital intensive 

pollution controls and (b) regulated utilities that can recover compliance costs through customer 

rates; thus, they are at a competitive disadvantage. Ex. 9, Bilicic Affidavit, ~7; Ex. 2, Alonso 

Affidavit, ~13. With depressed power prices, merchant generators, such as IPH, cannot easily, if 

at all, generate sufficient cash flows to fund large-scale capital projects. Ex. 2, Alonso Affidavit, 

~24. 

AER does not currently have, and as a result IPH will not at closing have, the financial 

resources to complete construction of the Newton FGDs or otherwise comply with the MPS. !d. 

~~20, 24. The above market factors are compounded by the fact that AER's financial outlook, 

credit profile and access to third-party capital have weakened further since AER received the 

variance, as a result of persistently low power prices and ongoing uncettainty regarding federal 

environmental regulations. Ex. 9, Bilicic Affidavit, ~8 ("Since receiving the Variance Relief, 

AER's financial outlook has worsened, as market expectations of power prices have not 

37 
improved, but, in fact, have deteriorated further beyond the 2014 time horizon,") (footnote 

omitted). 

Further, AER's recurring net income declined from $359 million in 2008 to $41 million 

in 2011 with net income losses of $415 million in 2010 and $396 million in 2012. !d. In addition 

in the first quarter of 2013, AER had a $151 million net income loss. Ex. 2, Alonso Affidavit, 

'i[l4. 

Moreover GENCO, AER's largest subsidiary and the owner of the Newton Energy 

Center, has approximately $825 million in long-term public bond debt outstanding, with 

approximately $300 million of this debt maturing in 2018 and $250 million maturing in 2020. 

GENCO's existing debt requires approximately $59 million in annual interest payments. !d. 

Notably, the credit rating of GENCO has been cut by 4 and 3 notches by Standard & Poor's 

("S&P") and Moody's, respectively, since AER was granted the variance. Ex. 9, Bilicic Affidavit, 

'i[8. GENCO "has less than adequate liquidity" and "poor standing in the credit markets." Ex. 2, 

Alonso Affidavit, 'i[l4 (quoting S&P, Research Update: Ameren Energy Generating Co. Ratings 

Lowered to 'CCC+' On Weak Power Prices; Outlook Negative (Feb. 8, 2013)). 

GENCO will continue to be responsible for repayment of its $825 million debt, including 

the annual $59 million interest payment obligation, after being acquired by IPH. !d. Given 

depressed power prices, GENCO's existing debt and the significant capital expenditure needed 

to complete the Newton FGDs, maintaining liquidity for GENCO is at a premium. In sum, IPH 

will in the near tem1 face almost the identical balance sheet challenges as those currently faced 

by AER. 

More specifically, at closing, IPH will have approximately $220 million in cash. !d. 'i[20. 

Of that $220 million, approximately $203 million will be at GENCO and approximately $17 

38 
million will be at AERG/ Ameren Marketing. !d. The proceeds from exercising the put option (a 

minimum of $133 million) are part of the approximate $203 million in cash that GENCO will 

have when acquired by IPH. 22 IPH will utilize the vast majority (depending largely on the 

volatility of commodity markets) of this $220 million in cash available at closing over the next 

several years to fund operations, potential losses, pay interest, and provide some working capital 

and credit support needed to keep the businesses running day-to-day in the prevailing 

challenging market conditions. !d. Moreover, two years after closing, IPH will need the financial 

resources to replace its existing credit support from Ameren, which, if replaced today, would use 

up a significant amount of the $220 million in cash available at closing. !d. As a result, the 

approximate $220 million in cash on hand at IPH upon closing will not be available to fund 

completion of the Newton FGDs or make any other MPS compliance alternatives feasible. !d. 

~21. 

In addition to the cash on hand at closing discussed above, IPH will have approximately 

$160 million in net working capital at closing. !d. ~22. This $160 million, however, is necessary 

for day-to-day capital business expenses: fuel inventory; materials/supplies (e.g., spare parts), 

etc. !d. Thus, the $160 million in net working capital at closing will not be available to fund 

completion of the Newton FGDs or make any other MPS compliance alternatives feasible. 

IPH expects that, at closing, it will have sufficient liquidity to meet anticipated operating 

obligations, including sufficient funds to (a) continue constmction of the Newton FGDs in 

accordance with the requested Compliance Plan; (b) maximize the existing FGD systems at 

22 As explained in PCB 12-126, the Put Option Agreement was designed as a mechanism to provide cash liquidity to 

GENCO by selling its three natural gas fired power plants (Elgin, Gibson City and Grand Tower). Depending on the 

results of the sale process of the put assets, the total cash available for GENCO at closing could be higher than $203 

million (i.e., the amount that includes the minimum $133 million resulting from GENCO having exercised the put 

option in March 2013). Any additional proceeds would be used for GENCO operating needs. Notably, the sale of the 

three natural gas plants also means that GENCO no longer can derive cash flow from those plants. 

39 
Duck Creek and Coffeen; and (c) utilize low sulfur coal at Newton, Edwards and Joppa. It is not 

feasible over the next several years to simultaneously have adequate liquidity necessary to 

continue operating the Energy Centers and also spend hundreds of millions on capital 

investments to accelerate installation of the Newton FGD project, install alternative air pollution 

controls or otherwise comply with the MPS without the requested variance relief. Ex. 2, Alonso 

Affidavit, ~~25, 27. 

IPH will continue to face financial challenges over the next several years. In fact, given 

depressed power prices and the volatile nature of the merchant energy business, the approximate 

$220 million in cash available at closing would not be sufficient to fund IPH' s operations over 

the next several years without the approximate $60 million in annual cost-based operational 

synergies that Dynegy, IPH's ultimate parent company, estimates it will realize in the transaction 

by 2015. !d. ~25. The synergies will result from gross margin and cost improvements at IPH 

based on the successful implementation of Dynegy programs addressing, among others, 

reduction in forced outage rates, fuel and rail procurement practices, and vendor optimization, 

and the combination of Dynegy's engineering, maintenance, and outage planning expertise. !d. 

Implementation ofDynegy's PRIDE initiative (Producing Results through Innovation by Dynegy 

Employees) at IPH is also expected to result in significant margin and cost improvements, as it 

has at Dynegy over the past two years, by continuously improving performance wherever 

possible based on the advice of its employees. !d. ~25. 

Importantly, IPH does expect that the gradual recovery of power prices (anticipated to 

begin after April 2015) will provide IPH with sufficient cash flow and liquidity to ramp up and 

complete construction of the Newton FGDs by year end 2019. !d. ~23. Dynegy has made clear in 

its public statements that it believes power prices will begin to recover when compliance with the 

40 
federal Mercury and Air Toxics Standards ("MATS") tightens supply as environmentally 

noncompliant or uneconomic generation units in the Midwest continue to retire. 23 !d. MATS 

generally requires compliance beginning in April2015, but one and two year extensions of the 

compliance deadline are allowed in certain circumstances. As publicly stated, Dynegy expects 

IPH will not generate free cash flow until2015.Z4 !d. ~24. 

However, free cash flow in 2015 by IPH does not mean that IPH would have sufficient 

liquidity or financial resources in 2015 to spend the significant capital needed to complete 

construction of the Newton FGDs in time to meet the 2015 and 2017 MPS emission rates. !d. 

The recovery of power prices will not be immediate in 2015, nor will market recovery in 2015 be 

sufficient to generate the cash flow and liquidity needed to accelerate completion of the Newton 

FGDs in time to meet the MPS. !d. Rather, the recovery of power prices and associated 

generation of positive cash flows is expected to occur gradually over time. !d. Thus, the five-year 

term of the requested variance is critical to allowing adequate time for both recovery of power 

prices and for IPH to accumulate the significant financial resources needed to comply at the end 

of the variance period. !d. In short, IPH will not have the financial resources to complete the 

Newton FGD project or otherwise meet the MPS 2015 and 2017 compliance deadlines without 

the variance. !d. 

3. IPH Cannot Currently Obtain Financing From External Third Party 

Lenders. 

Due to the distressed power market in which the Energy Centers operate and AER' s 

deteriorated balance sheet at closing, IPH will not be able to secure financing from external third 

23 See a/sa Dynegy Inc. Form 8-K (Mar. 14, 2013), Ex. 99.2 at 2 (available at www.dynegy.com/investorrelations/sec-filings); DYN-Q4 2012 Dynegy Inc. Earnings Conference Call (Mar. 14, 2013), Tr., at 17 ("in a postMATS compliance world, [Dynegy] certainly expect[s] higher capacity payments, higher power prices"). 

24 DYN-Q4 2012 Dynegy Inc. Earnings Conference Call (Mar. 14, 2013), Tr., at 10 (Dynegy "expect[s] the 

[Ameren-IPH] transaction to be accretive to adjusted EBITDA in 2014 and free cash flow in 2015 .... "). 

41 
party lenders. Ex. 2, Alonso Affidavit, ~15. Before entering the Agreement, Dynegy approached 

several financial institutions to inquire about the possibility of obtaining a credit facility to 

support IPH. !d. Given the low cash flow profile, negligible lien capacity of the Energy Centers, 

existing debt, and weak credit profile of the businesses, the financial institutions contacted 

replied that they would not extend a credit facility. !d. 

As noted above, GENCO holds approximately $825 million in long-term public bond 

obligations, debts that GENCO will continue to owe after being acquired by IPH. !d. ~14. 

Approximately $300 million of this debt matures in 2018, and approximately $250 million of the 

debt matures in 2020. !d. GENCO's failure to repay the bonds when due would constitute a 

default under the GENCO bond indenture, which would likely lead to a GENCO bankruptcy. !d. 

While IPH generally would seek to refinance those bonds in the public market at some point in 

the future in order to extend the maturity dates, covenants in GENCO's bond indenture restrict 

GENCO's ability to incur additional indebtedness from external sources if GENCO's interest 

coverage ratio is less than 2.5 or its leverage ratio is greater than a specified maximum. !d. ~16. 

During the first quarter of 2013, GENCO's interest coverage ratio fell to a level less than the 

specified minimum level required for external borrowings. Ex. 9, Silicic Affidavit, ~10. Due to 

the decline in GENCO's earnings and operating cash flows resulting from depressed power 

prices, GENCO's interest coverage ratio is expected to remain less than this minimum level 

through at least 2015. Id. As a result, until power prices recover post 2015, GENCO's ability to 

borrow additional fi.mds from external, third-party sources is restricted. !d. Moreover, given 

GENCO's poor financials, even after GENCO regains its ability to borrow external funds, 

refinancing may not be possible as a practical matter due to onerous terms imposed by external 

lenders. Ex. 2, Alonso Affidavit, ~16. 

42 
In addition, because IPH, New AER and AERG are not and will not be publicly 

registered companies and will not be rated by the credit rating agencies, they will have limited 

financing options. Id.~l5. 

If GENCO's interest coverage ratios do not improve significantly by the debt maturity 

dates, GENCO would have to repay its outstanding debts ($300 million in 20 18; $250 million in 

2020) to the bondholders. Id.~14. Given these looming significant debt maturities and the 

continuing financial challenges, including depressed power prices, it is critical that IPH, 

including GENCO, preserve and accumulate cash until power market prices recover, operating 

results improve, cash flows increase, and the ability to obtain external lender financing returns. 

That will not be possible under IPH without the requested variance relief. 

4. Dynegy Cannot Support the Capital Needs of IPH. 

As Dynegy has publicly communicated to its investors, IPH and the Energy Centers must 

succeed on their own financially, without support for major capital projects coming from the 

ultimate parent or affiliated companies. Ex. 2, Alonso Affidavit, ~~5, 13, 18. This is no different 

than the situation presented to the Board by AER (and Ameren) in PCB 12-126. The same credit 

pressures that prevented Ameren from financially supporting the Energy Centers at the time of 

the PCB 12-126 petition impose similar constraints on Dynegy as IPH' s ultimate parent 

company. Indeed, the credit pressures and overall financial pressures on Dynegy are, in fact, 

worse. 25 

As solely a merchant generation company without any regulated rate-based subsidiaries, 

Dynegy has had to face several years of economic challenges caused by depressed power pricing 

25 In granting the variance in PCB 12-126, the Board did not accept arguments that Ameren, as AER's ultimate 

parent company, must financially support AER's MPS compliance efforts. That same conclusion should apply to 

IPH's request for variance relief, particularly given that Ameren has a stronger credit rating than Dynegy. Ex. 9, 

Bilicic Affidavit, ~12. 

43 
and a weakened national economy. !d. ~26. In fact, Dynegy filed for Chapter II bankruptcy 

protection in July 2012. !d. While successfully emerging from bankruptcy in October 2012, 

Dynegy continues to face near-term economic challenges posed by depressed power prices. !d. 

For example, Dynegy reported operating losses of $104 million for the fourth quarter of 20 12 

and $142 million for the first quarter of 2013. !d. Thus, in a very real sense, while Dynegy 

expects power pricing and market conditions to improve over the longer-term beginning in 2015, 

Dynegy is not a "deep pocket" with limitless funds that could now or in the next several years be 

made available to IPH to complete construction of the Newton FGDs sooner than the proposed 

variance conditions. !d. 

More importantly, Dynegy cannot integrate IPH into the Dynegy capital structure without 

severe adverse consequences that would imperil its financial future. !d. ~17. As part of its due 

diligence process prior to entering the Agreement, Dynegy contacted the credit rating agencies 

(Moody's and S&P) to understand the credit rating implications, if any, of the transaction on 

Dynegy. !d. Both credit rating agencies clearly indicated that the transaction would negatively 

affect Dynegy's credit rating if IPH were integrated into the Dynegy financial structure or if 

Dynegy were to provide financial support to IPH, other than limited amounts of working capital. 

!d. Having only recently emerged from bankruptcy in October 2012, Dynegy cannot take actions 

that would downgrade its credit rating. !d. A downgrade would mean less favorable terms and 

conditions for Dynegy's financing (e.g., increased interest rates for borrowing, more restrictive 

covenants) and loss of investor confidence, which would ultimately jeopardize Dynegy's balance 

sheet and liquidity. !d. ~18. Simply stated, Dynegy will not-and, in effect, cam10t-endanger its 

balance sheet or its credit rating by integrating IPH into the Dynegy capital structure. !d. 

44 
In April2013, Dynegy completed a refinancing in which it again made clear to the credit 

rating agencies, as well as to equity and debt investors, that IPH would not be integrated into the 

Dynegy capital structure. !d. While the new refinancing agreement itself would allow Dynegy to 

invest certain amounts in its subsidiaries, including IPH, Dynegy cannot inject those funds into 

IPH without risking its credit rating and credibility-something Dynegy cannot do. !d. ~19. 

Consistent with Dynegy's need to protect its financial soundness and its commitments to 

the credit rating agencies and investors concerning the IPH transaction, Dynegy, if it is needed, 

may provide very limited financial support to IPH for the sole purpose of providing necessary 

working capital needed to maintain day-to-day operations of the businesses. !d. ~25. As was the 

case at the time of the Variance Opinion, under IPH ownership the Energy Centers still must be 

economically viable on their own and operate as independent, self-sustaining and self-funding 

businesses. !d. ~~5, 13. Moreover, given the potential adverse reaction of the credit rating 

agencies, equity investors and debt investors were Dynegy to provide financial support, 

affiliation of the Energy Centers (or their operating companies) with Dynegy will not improve 

their financial outlook or their ability to fund environmental-related expenditures on a more 

accelerated timeframe. Ex. 9, Bilicic Affidavit, ~15. In short, the various challenges faced by 

IPH are the same, if not worse, than those faced by AER when it was granted the variance. See 

id. ~14. The rationale for the variance remains unchanged-it will continue to play a critical role 

in allowing IPH to manage its liquidity and credit quality in the midst of a currently 

challenged merchant generation operating environment. !d. 

Given depressed power prices over the past several years which are expected to remain 

depressed for several more and given the overall financial challenges that result, economic 

viability for the plants is only possible with the relief requested in the Petition. 

45 
E. The Petitioners' Hardship is Not Self-Imposed. 

The Board's regulations at issue here, the Ameren MPS Rule, has been promulgated to 

apply system-wide: to all seven plants in the MPS Group. The IEPA recognizes the regulatory 

basis and structure of that system-wide approach. The transaction negotiated by Ameren and IPH 

also recognizes that regulatory structure and responsibly tries to implement it as part of the 

transaction. Ex. 2, Alonso Affidavit, ~ 8. Thus, any argument that the Board should dismiss this 

Petition based upon a line of Board cases finding the hardship to be "self-imposed" is simply 

wrong. The cases in which the Board denied variance relief by finding the hardship was "selfimposed" present factual scenarios much different than that presented here. The inquiry the 

Board engages in to determine a self-imposed hardship is whether the company seeking relief is 

in a quagmire of its own making, due to lack of diligence or despite knowledge of requirements. 

Consider, for example, the following cases where the Board denied variance relief because it 

found that the claimed hardship was self-imposed: 

• Ecko Glaco v. !EPA, PCB 87-41 (Dec. 17, 1987). Company, that was in a poor 

financial position due to procrastination and poor business decisions, exhibited 

continuous unwillingness to commit to a compliance plan; 

• Skyway Realty v. !EPA, PCB 75-249 (Sept. 18, 1975). Company sought relief 

after proceeding with a construction project with full knowledge of the 

regulations; 

• City of Ottawa v. !EPA, PCB 86-165 (Jan. 22, 1987). City claims to be unaware of 

existing regulations; 

• Marathon Oil Co. v. !EPA, PCB 95-150 (May 16, 1996). Variance denied because 

of company's faulty decision-making. 

46 
See also Copley Mem '/Hasp., Inc. v. City of Aurora, 99 Ill. App. 3d 217, 222, 425 N.E.2d 493 

(2d Dis!. 1981) (suing for zoning change following purchase and assuming property with the 

restrictions). 

The circumstances warranting denial of variance relief due to a finding the hardship was 

self-imposed simply do not exist here. !PH's relief is not requested because of lack of due 

diligence. For the Board to hold that this variance is not warranted because the claimed hardship 

would be self-imposed would be tantamount to ruling that a business could not contract for, and 

achieve through the Board's processes, a variance relief for the same exact facilities, pursuant to 

the same exact regulatory provisions, that the current owner had achieved under virtually the 

same circumstances. Such result is inconsistent with the Board's statutory responsibility to 

provide regulatory relief where warranted, and such a result would be inconsistent with prior 

Board rulings. See Allied Chem. Corp. & Inverness Mining Co., PCB 80-92 Order (May 1, 

1980); Opinion and Order (June 12, 1980). 

Quite simply, IPH is not before this Board requesting vanance relief due to faulty 

decision-making or lack of knowledge of the requirements. In fact, IPH is demonstrating sound 

decision-making and knowledge of the requirements by acknowledging the need for the 

continuation of variance relief to provide the best path forward for the operating plants before the 

transaction is completed. The Petitioners have exhibited through the structure of the transaction, 

and this Petition, a full understanding of the regulatory construct of the MPS and the obligations 

that result, as well as the need to substantiate the request for relief instead of appearing before the 

Board, after-the-fact, assuming the Board would provide the lifeboat. The hardship faced by the 

plants is anything but self-imposed. 

47 
VI. COMPLIANCE ALTERNATIVES 

Petitioners have performed an independent analysis of compliance alternatives, consistent 

with the Board's procedural rule at Section 104.204(e) which requires that a variance petitioner 

provide a description of the efforts that would be necessary to achieve immediate compliance 

(here, with the existing MPS rule) and a discussion of the compliance alternatives. 

The range of those alternative compliance options and the issues related to the 

consideration afforded them by AER in PCB 12-126 still exist today, and are relevant to this 

Petition. Ex. 8, Thompson Affidavit, ~12. During the PCB 12-126 variance proceeding, which 

concluded less than one year ago, the Board fully vetted a variety of suggested compliance 

alternatives and concluded that: "AER adequately detailed the range of compliance alternatives 

that AER examined in support of its petition." Variance Opinion, at 49. The costs and 

technological limits prevailing at the time of the Board's opinion in September 2012 have not 

changed in any material way. IPH's own projections show that it remains the case that, 

notwithstanding the IPH acquisition, completing construction of the Newton FGD project 

remains the most prudent and cost effective control technology that can be used to achieve 

ultimate compliance with the MPS. Ex. 8, Thompson Affidavit, ~11. 

A. Curtailing Plant Operations Is Not Economically Feasible. 

As explained above, to meet the MPS 2015 S02 emission rate without the variance, IPH 

would need to shut down a combination of the Newton, Joppa and E.D. Edwards Energy Centers. 

!d. ~12. A curtailment of operations by piecemeal shutdowns of specific units at various Energy 

Centers does not make sense economically, since the fixed costs would be the same while 

revenue would be less- defeating the ability of IPH to gamer the final necessary financial 

resources to complete the Newton FGDs and meet the strict emission standards required at the 

48 
end of the variance period. !d. Curtailing operations at any of the five Energy Centers as a 

compliance strategy would prevent the plants from generating sufficient funds to sustain their 

operations and obligations. !d. Such curtailment would mean reduced sales of electricity, less 

revenue generated, and less funds to run the business and cover fixed operating costs. !d. IPH's 

analysis indicates meeting the 2015 MPS S02 emission rate with all five operating Energy 

Centers continuing to operate would effectively require Newton, E.D. Edwards and Joppa to 

limit each of their respective generation to approximately one-third of its capacity. !d. Given 

their fixed costs, such a limit on generation would eliminate any potential ability of these Energy 

Centers to generate positive cash flows going forward. !d. 

While it would be infeasible for IPH to curtail operations of specific units on a temporary 

basis to meet the MPS, IPH expects that during the term of its requested reliefE.D. Edwards Unit 

I will be permanently retired. !d. ~27. In December 2012, Ameren filed a request with the MISO 

to retire E.D. Edwards Unit I effective December 31, 2012. Id. MISO's analysis determined the 

unit was needed for reliability purposes until such time as numerous transmission system 

reinforcements were put into service in order to mitigate thermal and voltage issues. !d. MISO 

filed an unexecuted System Support Resource ("SSR") Agreement, pursuant to attachment Y -I 

of MISO's tariff, with the Federal Energy Regulatory Commission ("FERC") on July II, 2013 

(the "July 11 SSR Filing"). !d. The maximum term of an SSR Agreement is twelve months and 

the July 11 SSR Filing covers the 2013 calendar year, however an SSR Agreement can be 

renewed and continue subject to an aruma! review of mitigation alternatives. !d. As noted in the 

July II SSR Filing, MISO expects that E.D. Edwards I will continue as an SSR unit until all of 

the required transmission system reinforcements are implemented in December 2016, though 

newly available alternatives will be sought in considering the mmual review of the SSR 

49 
Agreement. Therefore, annual renewal of the SSR Agreement seems likely. !d. Thus, IPH cannot 

commit to retiring E.D. Edwards Unit I by a date certain, but based on MISO information 

currently available, IPH does expect that E.D. Edwards Unit 1 will be retired before the end of 

the requested variance term. !d. 

B. Alternative Control Technologies. 

IPH also has reviewed the availability of alternative control technologies and agrees with 

AER's prior conclusion, which the Board endorsed in its Variance Opinion, that these 

technologies are infeasible because they would cost more than the Newton FGD project. !d. ~16. 

At hearing in PCB 12-126, some participants asserted that dry sorbent injection ("DSI") would 

be an appropriate and economically feasible technology to reduce S02 at the Joppa and E.D. 

Edwards Energy Centers. Tr., at 119, 120. The overall cost ofDSI as applied to the Joppa and/or 

E.D. Edwards Energy Centers makes it infeasible as a compliance alternative. Ex. 8, Thompson 

Affidavit, ~17. Based upon its analysis of DSI at other coal-fired plants, IPH estimates that the 

capital cost of installing DSI alone would be in the range of $60 million at Joppa (all six units) 

and $30 million at E.D. Edwards (Units 2 and 3). !d. IPH will not have the sufficient liquidity to 

fund any such large-scale projects over the next several years. Ex. 2, Alonso Affidavit, ~20. 

Further, as AER demonstrated in its Post Hearing Brief and reaffirmed here, the capital 

costs of installing DSI at Joppa and/or E.D. Edwards would not be limited to the DSI technology 

only. Ex. 8, Thompson Affidavit,~~ 17-18. Because of the size of the existing particulate control 

equipment and the use of ACI for mercury control at E.D. Edwards and Joppa, the use of DSI 

would result in a significant increase in PM emissions necessitating installation of PM control 

technologies (e.g., baghouses). !d. Thus, the real expected capital cost of installing DSI at Joppa 

would be approximately $433 million and approximately $280 million at E.D. Edwards (Units 2 

50 
and 3). !d. See also Post Hearing Brief, at 15 (citing 2011 URS report and attaching a cost table 

therein as Post Hearing Brief, Exhibit 1 ). 

Moreover, the annual O&M expense of DSI is significant. Ex. 8, Thompson Affidavit, 

~18. As AER demonstrated, the estimated annual cost of dry sorbent ranges from $15 million to 

$44 million depending upon the type of material used and the location of injection (before or 

after the air heater). See Post Hearing Brief, at 20 (citing 2010 report completed by the Shaw 

Group, Post Hearing Brief, Exhibit 2). Those estimated O&M costs cited by AER are consistent 

with IPH's analysis ofDSI O&M expenses. Ex. 8, Thompson Affidavit, ~18. The impact ofDSI 

annual O&M costs is even more pronounced given the cash flow challenges the Energy Centers 

face. !d. IPH will not have the sufficient liquidity to fund any such large-scale projects over the 

next several years. Ex. 2, Alonso Affidavit, ~20. Thus, IPH concludes that, as the Board 

determined in the AER variance proceeding, it is economically infeasible to employ DSI 

technology at Joppa or E.D. Edwards, especially when construction of the Newton FGD project 

is already underway. 

C. Conversion to Natural Gas is Economically Infeasible. 

The Board also examined AER's analysis of converting to natural gas at E.D. Edwards 

and Joppa. Variance Opinion, at 50. In PCB 12-126, the Board accepted AER's conclusion that 

conversion to natural gas did not represent a viable compliance alternative because, quoting from 

AER's Post Hearing Brief, at 23-24: "under current market conditions, a natural gas conversion 

at Joppa would reduce operations to a season basis only and lead to reduced revenue and a loss of 

jobs." !d. 

IPH has also considered firing natural gas as a means to comply with the MPS. Natural 

gas pipelines are not currently connected to the E.D. Edwards or Newton Energy Centers. Ex. 8, 

51 
Thompson Affidavit, ~19. The cost of constructing natural gas pipelines to either facility would 

be cost prohibitive. !d. An initial estimate of the cost to bring a natural gas supply pipeline to 

E.D. Edwards is $100 million and $70 million to Newton. Further, the additional capital 

expenditures needed to convert the coal-fired boilers at E.D. Edwards or Newton to natural gas 

firing are expected to be significant. In the absence of detailed, site-specific natural gas 

conversion engineering studies at E.D. Edwards or Newton, based on reported industry trade 

literature and case studies involving natural gas conversion of existing coal-fired boilers, the cost 

of converting each plant would be expected to be tens of millions of dollars, if not more. !d. 

(identifYing cost range of $50 to $75/kW by referencing F.J. Binkiewicz Jr. et al., Babcock & 

Wilcox, Natural Gas Conversions of Existing Coal-Fired Boilers (2010)). 26 In addition, 

converting the Newton units to natural gas firing in lieu of completing construction of the 

Newton FGDs also would waste the several hundred million spent, to date, on the Newton FGD 

project. Accordingly, conversion to gas is not feasible and is cost prohibitive. Id. 

Moreover, natural gas firing at Newton or E.D. Edwards would not be a cost-effective 

compliance alternative because dispatch on natural gas is more expensive than on coal, with the 

result that natural gas firing would result in significantly lower production by the plant, and, thus, 

generate lower revenues needed for the recovery of fixed operating costs and capital 

expenditures. Id. ~20. Based on current power market conditions in Illinois, production costs 

related to fuel are roughly $20-$25/MWh on PRB coal and would be roughly $40/MWh on 

natural gas. Id. Based on MISO published clearing prices in 2012, power prices at, for example, 

the Newton busbar averaged in excess of $22/MWh during 76 percent of the on-peak days while 

only two percent on the on-peak day averages exceeded $40/MWh. !d. In other words, Newton 

26Available at www.babcock.com/librwylpdj!MS-14.pdf 

52 
fired on natural gas during 2012 would have been dispatched approximately only two percent of 

the time. Jd. Thus, IPH concludes that it is infeasible to convert E.D. Edwards or Newton to 

natural gas. !d. 

Further, IPH concludes that, for several reasons, converting Joppa to natural gas would be 

cost prohibitive and not economically feasible. Jd.~21. First, an order of magnitude cost estimate 

to convert the relevant Joppa units to natural gas ranges from $25 million (i.e., convert to 50 

percent capacity on natural gas) to $38 million (i.e., convert to 100 percent capacity on natural 

gas), with an additional estimated $4.5 million in capital expenditures needed for gas supply 

pipeline and equipment improvements. !d. ~21. Second, natural gas firing at Joppa would not be 

a cost effective compliance alternative because, as discussed in the paragraph above, dispatch on 

natural gas is more expensive than on coal, with the result that natural gas firing would result in 

lower production at Joppa and, thus, generate lower revenues, revenues needed for the recovery 

of fixed operating costs and capital expenditures. !d. Finally, as determined by the Board in 

AER's variance proceeding, conversion of Joppa to natural gas firing would reduce the plant's 

operations to a seasonal basis only, thereby resulting in reduced revenues and, ultimately, a loss 

of jobs. Variance Opinion, at 21, 50. IPH will not have the sufficient liquidity to fund any such 

large-scale capital projects over the next several years. Ex. 2, Alonso Affidavit, ~20. 

In evaluating all potential compliance options, IPH also considered that two units at 

Joppa (Units 1 and 4) have the physical capability to co-fire natural gas up to approximately 45 

percent of heat input at full load. !d. ~22. Based on DMG's experience with analyzing natural 

gas co-firing as an option to reduce 802 emissions at its coal-fired plants in Illinois, IPH 

concludes that natural gas co-firing at these two Joppa units, even at levels less than 45 percent, 

is not cost effective. Jd. Because dispatch on natural gas is more expensive, natural gas co-firing 

53 
would result in lower production and, thus, generate lower revenues for the recovery of fixed 

operating costs and capital expenditures. !d. The key factor for sustained use of natural gas cofiring is the price differential between natural gas and coal. !d. 

Based on current market conditions, production costs related to fuel are roughly 

$20/MWh to $25/MWh on PRB coal and would be roughly $40/MWh on natural gas. !d. In 

general, it would only be cost effective to co-fire natural gas if natural gas prices approached 

$2.50/mmBtu. !d. Thus, even at the historically low natural gas prices in recent times, natural gas 

co-firing does not make economic sense. !d. Accordingly, IPH concludes that natural gas cofiring at Joppa Units 1 and 4, while technically possible, is not a cost effective compliance 

alternative, nor would it achieve compliance with the MPS overall S02 emission rates. !d. 

Thus, IPH concludes that, as the Board determined in the AER variance proceeding, it is 

economically infeasible to convert E.D. Edwards, Newton or Joppa to natural gas, especially 

when construction of the Newton FGD project is already underway. Ex. 8, Thompson Affidavit, 

~~19-22. 

VII. ENVIRONMENTAL IMPACT 

A. Any Adverse Environmental Impact From the Variance Does Not Outweigh 

the Arbitrary or Unreasonable Hardship oflmmediate Compliance. 

The appropriate standard the Board must employ in any analysis of any variance, as the 

legislature has provided in Section 35(a) of the Act, is one of arbitrary and unreasonable 

hardship: 

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 arbitrwy or unreasonable hardship. 

415 ILCS 5/35(a) (emphasis added). 

54 
In order to make that finding, a great body of case law requires that the Board weigh any 

such hardship against any adverse impact to the environment. In a variance proceeding, a 

petitioner must demonstrate that the hardship resulting from a denial would "outweigh any injury 

to the public or the environment" from granting the relief. Marathon Oil Co. v. EPA, 242 Ill. 

App. 3d 200, 206, 610 N.E.2d 789, 793 (5th Dist. 1993). The Board has previously found an 

arbitrary and unreasonable hardship would result where technically and economically feasible 

means of compliance have not been identified despite diligent efforts by the petitioner. Mobil Oil 

Co. v. !EPA, PCB 86-45, slip op. at 6 (Aug. 14, 1986). The Board has granted variance relief on 

many occasions after finding the variance would cause minimal or no adverse environmental 

impact. Vi!!. of Princeville v. !EPA, PCB 93-227, slip op. at 4 (Jan. 20, 1994); Vills. of Granville 

& Mark v. !EPA, PCB 93-163, slip op. at 3 (Nov. 4, 1993): Amerock Corp. v. !EPA, PCB 92-

120, slip op. at 2-3 (Feb. 4, 1993); City of Galva v. !EPA, PCB 89-131, slip op. at 2 (Dec. 20, 

1989). The Board has even granted variance relief after finding an adverse environmental impact 

based on a showing that the impact was "not great" and did not outweigh the "huge cost of 

compliance." Shell Oil Co. v. !EPA, PCB 83-24, slip op. at 2 (Mar. 21, 1984). 

Although Section 35(a) of the Act does not require that the Board find a "net benefit to 

the environment" as a condition precedent to granting relief, and no court has interpreted the Act 

as requiring such net benefit, AER's compliance plan in PCB 12-126 relative to the MPS Group 

in fact so provided. Variance Opinion, at 48, 51-56, 58, 68. Given that the Petitioners here seek 

to implement that compliance plan pursuant to identical variance relief, for the identical MPS 

Group, conceming the identical regulatory framework, little more than one year later, the Board 

should again recognize the net benefit to the environment that will be achieved by the MPS 

Group subject to this variance. That the Petitioners here will be the new owners of the MPS 

55 
Group should be of no consequence in the Board's analysis of environmental impact in this 

variance proceeding. 

B. IPHillynegy is Committed to Environmental Protection in Illinois. 

Dynegy, through other wholly owned subsidiaries, such as DMG and Dynegy Kendall 

Energy, LLC, has historically enjoyed a meaningful presence in Illinois since its February 2000 

acquisition of Illinova Corporation (i.e., the fossil fuel-fired electric generating assets of Illinois 

Power Company), which formed the basis of DMG's current generating fleet. Ex. 8, Thompson 

Affidavit, ~6. As IPH's parent company, Dynegy is very cognizant of its environmental impact in 

Illinois and has taken proactive steps to minimize its imprint.27 !d. ~8. Through its subsidiaries, 

Dynegy owns and operates five coal and natural gas-fired power generation facilities in Illinois, 

with the capacity of producing approximately 4,200 MW of reliable, low cost energy for wholesale 

customers. !d. ~6. DMG's generating assets include four operating coal-fired electric generating 

stations located in Southern Illinois: the Baldwin Energy Complex (Randolph County), the 

Havana Power Station (Mason County), the Hennepin Power Station (Putnam County), and the 

Wood River Power Station (Madison County). !d. ~7. In November 2011, DMG permanently 

retired a fifth coal-fired power plant, the Vermilion Power Station (Vermilion County). I d. 

Through its subsidiaries, Dynegy employs approximately 600 full-time employees m 

Illinois, employing approximately 550 persons at its Illinois power stations and approximately 50 

persons at its corporate office located in O'Fallon, Illinois. !d. The economic impact ofDynegy's 

operations in Illinois and in the affected local Illinois communities is significant. Id. For 

27 For example, Dynegy has been involved in carbon sequestration efforts, with tree-planting projects covering more 

than 45,000 acres in a portion of the Shawnee National Forest. The Lower Mississippi River Valley reforestation 

project is registered under the Verified Carbon Standard and was the first United States forest carbon offset project 

to receive this certification. Dynegy has also donated 1,100 acres along the Middle Fork Vennilion River to the 

Illinois Department of Natural Resources and has sponsored activities preserving lj200 acres afforests in Illinois. 

Each year, these trees will sequester increasing levels of carbon dioxide. Ex. 8, Thompson Affidavit, ~[9. 

56 
example, in 2012 Dynegy's direct investments in Illinois (i.e., maintenance, capital, and taxes) 

totaled approximately $261 million. !d. 

Dynegy and its subsidiaries have a strong commitment to safe and environmentally 

responsible operations in Illinois. !d. ~8. DMG has invested approximately $1 billion in air 

pollution controls at its Illinois facilities (including installation of FGDs, activated carbon 

injection systems, and/or baghouses on select generating units) to comply with the Illinois 

Mercury Rule, including the MPS, and DMG's Consent Decree.28 !d. Dynegy is very familiar 

and experienced with the Illinois MPS requirements. !d. DMG's five coal-fired stations elected 

into the MPS in 2007 (i.e., the DMG MPS Group) and Dynegy's environmental support group 

staff was directly involved in the MPS rulemakings. !d. DMG has met its MPS limits. !d. Indeed, 

DMG met the MPS's mercury emission rate limit at all but one of its MPS generating units three 

years earlier than the required January 1, 2015 deadline. !d. Combined with DMG's statewide 

conversion to low sulfur coal, the company's environmental efforts in Illinois have reduced 

emissions of NOx, S02 and mercury, as well as particulate matter and other emissions. Since 

1998, emissions levels from DMG have dropped almost 90 percent. 29 !d. 

C. Description of Environmental Impacts. 

Pursuant to Section 104.204(g) of the Board's procedural rules, a petitioner for variance 

must describe the environmental impact of the activity. 

28 United States v. Illinois Power Co., No. 99-CV-833-MJR (S.D. Ill.) (Consent Decree entered May 27, 2005) (a 

copy of the Consent Decree as originally entered is available at: 

http://www.epa.gov/compliance/resources/decrees/civil/caa/dmgfinal-cd.pdf). 

29 DMG's Baldwin and Havana facilities have installed and are operating dry FGD systems for the control of S02 

emissions, and ESPs and baghouses for the control of particulate emissions. DMG's Hennepin facility has ESPs and 

baghouses for the control of particulate matter. The baghouses at DMG's facilities also control hazardous air 

pollutants in particulate form, such as most metals. ACI or mercury oxidation systems for the control of mercury 

emissions have been installed and are operating on all ofDMG's coal-fired capacity. SCR technology to control 

NOx emissions has been installed and is operational at Havana and two units at Baldwin. See Ex. 8, Thompson 

Affidavit, ~8. 

57 
1. The nature and amount of emissions if the variance is granted compared to 

that which would result if immediate compliance is required. 

Section 104.204(g)(l) requires the Petitioners to discuss, as relevant, the nature and 

amount of emissions that will be released if the variance is granted, compared to that which 

would result if immediate compliance is required. As the Petitioners have demonstrated, without 

the variance, immediate compliance (compliance with the 2015 and 2017 MPS S02 emission 

rates) is simply not achievable, absent further plant closures. Ex. 2, Alonso Affidavit, ~8; Ex. 8, 

Thompson Affidavit, ~13. The Ameren-IPH transaction has been carefully crafted to allow for the 

operation of the plants in a manner that achieves compliance with the Ameren MPS Rule. Ex. 2, 

Alonso Affidavit, ~8. Dynegy, the ultimate parent of IPH, has a history of achieving compliance 

with MPS rules in Illinois. Ex. 8, Thompson Affidavit, ~8. IPH, with a continuation of the 

variance relief granted to AER, represents the best path forward for the continued operation of 

the Energy Centers in a manner that achieves ultimate compliance with the Ameren MPS Rule. 

Ex. I, Lyons Affidavit, ~16. 

Neither Section 35(a) of the Act nor Section 104.204(g) of the Board's rules requires, in 

justifying the variance, that emissions be less than they would be if immediate compliance is 

required. Indeed, such result is generally not the case and, indeed, rather somewhat of a 

juxtaposition. Nonetheless, because AER agreed to mitigation rates in advance of a prospective 

compliance date, such was achieved in PCB 12-126. That benefit will continue with the 

extension of the variance to the new owners of the MPS Group, as the Petitioners here propose 

the same compliance plan. 

The Petitioners have demonstrated this net environmental benefit by both estimating the 

tons of S02 emissions reduced from 2010 through 2020 (Table I) and from 2013 through 2020 

(Table 2), Exhibit I 0. Both Tables demonstrate over the relevant period, fewer tons of S02 will 

58 
be emitted into the air by the end of the variance term than would be under the Ameren MPS 

Rule. 

Table 1 shows a net environmental benefit of 74,303 fewer tons of S02 emitted. 30 Exhibit 

11, Affidavit of Aric D. Diericx ("Ex. 11, Diericx Affidavit"), ~6. It is critical to view the overall 

reductions during the time period from 2010 through 2020. This time period illustrates what 

would have been allowed under the Ameren MPS Rule and compares those emissions with those 

from the MPS Group factoring in: (1) actual emissions; (2) the mitigation rates from the 2012 

variance (same as those in the requested relief); and (3) the shuttering of Hutsonville and 

Meredosia. Table 1 shows the actual S02 emissions for 2010,2011, and 2012. !d. The actual tons 

ofS02 emitted during 2012 were even less than projected in PCB 12-126. !d. All of these factors 

have resulted in benefits to human health and the environment not otherwise required under the 

MPS. Further, the requested relief includes a provision to not operate the electric generating units 

at Hutsonville and Meredosia through December 31, 2020, thereby providing a benefit through 

the end of2020. 31 

Even if the Board were to look only at the years in the requested relief that IPH and 

Medina Valley are scheduled to take ownership of the MPS Group-the time period from 2013 

through 2020-in analyzing the environmental impact of the variance, Table 2 shows the MPS 

30 Over the period 2012-2020, Table I reflects a 47,178 net reduction in S02 emissions for the MPS Group, a 13,633 

ton increase in net reductions compared to the Variance Opinion, which recognized a net reduction of 33,545 tons. 

Variance Opinion, at 54. The increase in net reductions reflects that actual S02 emissions from the MPS Group in 

2012 were less than had been projected in PCB 12-126 and that FutureGen 2.0 project (to be constructed at the 

Meredosia Energy Center) S02 emissions are not included for 2013-2016 because the FutureGen 2.0 project is not 

expected to begin operations until September 2017. Ex. II, Diericx Affidavit, ~6. 31 In keeping with the "once in, always in" intent of the MPS that was previously endorsed by both !EPA and the 

Board in PCB 12-126 (!EPA Recommendation, at 21; Variance Opinion, at 54), the cumulative S02 reduction in 

both Tables is based on a baseline heat input that reflects the cessation of operations at the Hutsonville and 

Meredosia plants through 2020. In analyzing environmental impact, the Board has considered emission reductions 

not exclusively attributable to a particular individual petitioner in a particular variance proceeding. ExxonMobil Oil 

Corp. v. !EPA, PCB 11-86, 12-46 (Dec. I, 2011) (considering the significant environmental benefit ofNOx 

reductions achieved through the installation of selective catalytic reduction that was installed under a consent 

decree). Thus, in this MPS variance context, the Board should consider the "benefit" provided by the entire MPS 

Group and not only as it relates to one isolated petitioner. 

59 
Group will achieve a net environmental benefit of 7,748 fewer tons of S02 if the variance is 

granted compared to current the Ameren MPS Rule requirements. ld. ~7. Under either scenario, 

a net environmental benefit exists. ld. ~8. Certainly, both Tables demonstrate that no adverse 

environmental impact exists to outweigh the hardships associated with plant closures. 

2. Qualitative and Quantitative Impact on Human Health and the 

Environment. 

In order to ensure that the Board is informed as to any adverse impacts to human health 

and the environment, Section 104.204(g)(2) of the Board's rules requires that variance 

petitioners discuss, as relevant, such potential impacts in the variance petition. In PCB 12-126, 

AER provided the Board with a letter from toxicology experts from AECOM. Post Hearing 

Brief, Ex. 3. The Petitioners here have again commissioned AECOM to review this variance 

request, and provide the Board with a toxicologist's perspective on the Petition. The AECOM 

Memorandum is attached as Exhibit 12, AECOM Memorandum ("Ex. 12, AECOM 

Memorandum"). 

As AECOM concludes, "there would be no adverse impact as a result of implementing 

the requested variance and proposed compliance plan, in fact, a net environmental benefit would 

be realized." !d. In reaching this conclusion, the AECOM Memorandum not only provides 

infonnation directly related to the variance request (an analysis of the impact of the requested 

variance, a discussion of the health effects information available regarding exposure to S02, and 

potential implications from S02 emissions at issue), it also provides an overview of the Clean Air 

Act's National Ambient Air Quality Standards ("NAAQS"), a summary of S02 emissions in the 

United States and Illinois, and a discussion of the variance request as it may be related to the 

USEPA December 2012 revision of the NAAQS for annual PM2.s (airborne particulate matter of 

2.5 micrometer in diameter and smaller). Given the earlier reductions in S02 emissions that have 

60 
already occurred and the commitment to adhere to the mitigation rate granted in PCB 12-126, the 

requested variance will result in an overall benefit to human health and the environment 

compared to the potential of the existing Ameren MPS Rule. !d. The AECOM Report 

demonstrates there will be fewer adverse health effects overall over the term of the variance. !d. 

The earlier, more stringent mitigation rates provide a benefit to human health and the 

environment. Indeed, in terms of the appropriate Board query, there will be no adverse impacts 

to the environment that outweigh the impacts from plant closures and other identified hardships. 

3. Impacts of Discharge of Contaminants on Human, Plant and Animal Life. 

Section 104.204(g)(l) of the Board's rules requires that variance petitioners discuss, as 

relevant, discharge impacts to human, plant and animal life in the variance petition. Again, the 

AECOM Memorandum is relevant to this inquiry and is provided for the Board's analysis of this 

Petition. !d. Again, the proposed mitigation rate imposes significant restriction on how 

Petitioners IPH and Medina Valley must manage the MPS Group once the companies acquire 

ownership. In order to comply with the proposed compliance plan, including the mitigation rate 

that will apply during the term of the variance, Petitioners IPH and Medina Valley must 

implement specific measures that will minimize the impact of the variance on human, plant and 

animal life. !d. Petitioner IPH must operate the scrubbers at Duck Creek and Coffeen to optimize 

performance levels and procure low sulfur PRB coal on an ongoing basis to be used at the E.D. 

Edwards, Joppa and Newton facilities. !d. Petitioner Medina Valley must maintain the 

Hutsonville and Meredosia Energy Centers shuttered through the end of the variance term. !d. 

D. Probable Further Emission Reductions Through IPH Performance. 

Fmihermore, for several reasons, the Petitioners expect that the MPS Group will achieve 

even more S02 emissions reductions during the term of the requested variance period than the 

61 
reductions identified in Tables I and 2. Ex. I 0. First, based on MISO information currently 

available, Petitioner IPH expects that E.D. Edwards Unit I will be retired before the end of the 

requested variance term. The Tables do not reflect the expected retirement of E.D. Edwards Unit 

I given that the retirement date for the unit rests with MISO and is beyond IPH's control.32 Ex. 

8, Thompson Affidavit, ~27. Second, IPH anticipates that, in order to meet the 0.35 lb/mmBtu 

overall S02 annual mitigation emission rate, it may, at times, use even lower sulfur coal than 

included in AER's commitment for Newton, E.D. Edwards and Joppa. Jd. ~28. Tables 1 and 2 do 

not account for IPH's expectation that lower than 0.55 lb/mmBtu sulfur coal may be used to 

some extent at these three Energy Centers, based on availability, performance risk, price, and 

MPS Group emission performance. See Ex. II, Diericx Affidavit, ~~6, 7, 8. Third, the Tables do 

not reflect the expected reduction in S02 emissions that will occur in 2019 due to the extended 

unit outages at Newton that will be required to complete the installation of the two FGDs and the 

fact that the FGDs will, in all likelihood, be installed in series (i.e., after FGD installation is 

completed on one unit, the second FGD would be installed on the second unit), meaning that one 

of the FGDs will most likely be operating for a portion of calendar year 2019. Ex. 8, Thompson 

Affidavit, ~29. While these expected emission reductions cannot at this point be reasonably 

quantified, the Board should be aware that such will likely occur, especially in the later years of 

the variance. 

E. The Requested Variance Will Cause No Additional Environmental Impacts. 

The requested variance relief addresses only S02 emissions and would not impact 

emissions of other pollutants from the MPS Group. The MPS Group cunently complies and 

will continue to comply with the applicable MPS mercury and NOx emission limitations under 

32 The retirement of Edwards Unit 1 would reduce "Net Variance S02 Tons", as identified in Table 1 and Table 2, 

by approximately 2,000 tons per year beginning in the first full year the unit is retired. Ex. 8, Thompson Affidavit, 

~27. 

62 
the new ownership. Ex. 6, MPS Group Information (identifYing pollution control equipment 

installed and operating at the MPS Group facilities). AER has spent over $20 million installing 

ACI technology on twelve units at four plants, with $17 million in operating costs to date. 

Variance Opinion, at 37 (citing Tr., at 16-17, Hearing Ex. I at 3). In fact, the Board found in 

PCB 12-126 that "[t]here is no question that the environment in Illinois is benefitting from these 

early [mercury] reductions." !d. at 60. 

AER has taken additional steps since the date of the Variance Opinion to reduce 

mercury emissions from the fleet beyond what is required by the MPS. Exhibit 13, Affidavit of 

Steven C. Whitworth ("Ex. 13, Whitworth Affidavit"), ~4. AER early elected five EGUs to meet 

the 0.008 lb/GWh mercury emission limit in 2013 a year to a year and a half earlier than the 

January I, 2015 date required under the mle (35 Ill. Adm. Code 225.233(d)(l)): Coffeen Units 

1 and 2 beginning Febmary I, 2013, Newton Units I and 2 beginning April!, 2013, and E.D. 

Edwards Unit 3, beginning July I, 2013. Also, Duck Creek and Joppa Units 1 through 6 have 

qualified as "Low Mass Emitting" units by demonstrating that potential mercury emissions are 

de minimis ( <29 lbs/year). !d. 

Moreover, IPH ownership will bring with it the environmental compliance experience of 

Dynegy. As stated above, Dynegy has a solid history of positive environmental compliance in 

Illinois. Since 1998, emissions levels from DMG have dropped almost 90 percent. Ex. 8, 

Thompson Affidavit, ~8. 

In addition, cross media impacts are not an issue. See Ex. 12, AECOM Memorandum. 

63 
VIII. CONSISTENCY WITH FEDERAL LAW 

The Board may grant the variance consistent with federal law and, specifically, with the 

Clean Air Act, 42 U.S.C. 7401 et seq. The requested variance is consistent with current federal 

law. 

A. The Terms of the Requested Variance Will Not Jeopardize Illinois' BART 

Compliance Demonstration. 

In 2012, USEPA approved revisions to the Illinois state implementation plan ("SIP") to 

address regional haze. 77 Fed. Reg. 39943 (July 6, 2012). USEPA regulations mandate that 

regional haze plans include emission limitations representing Best Available Retrofit Technology 

("BART") for each BART-eligible source. 40 C.F.R. § 51.308(e). BART is defined as: an 

emission limitation based on the degree of reduction achievable through the application of the 

best system of continuous emission reduction for each pollutant which is emitted by an existing 

stationary facility. 40 C.F.R. § 51.301. 

USEPA approved relevant sections of the MPS and Illinois Combined Pollutant 

Standards ("CPS"), and two permits, and incorporated them into the SIP as satisfying BART 

requirements for the affected Illinois power plants and refineries. USEP A noted in response to 

public comments that Illinois' plan would achieve greater reasonable progress (i.e., meaning 

greater emissions reductions) and greater visibility protection by the BART compliance deadline 

(in 20 17) than the application of BART on BART -subject units. 

When compared to emissions reductions pursuant to the MPS, this variance will impart 

even greater emissions reductions by the BART compliance deadline in 2017. Accordingly, a 

SIP amendment incorporating this variance would only serve to enhance Illinois' ability to 

comply with the Clean Air Act's regional haze mles. 

64 
" 

B. The MPS Group Could Comply with CSAPR. 

While CSAPR is not yet, and may never be, effective, Petitioners point out that the 

CSAPR is not as onerous as the MPS, because while the MPS imposes stringent emission rates, 

CSAPR is based on mass emissions. Also, the CSAPR is a cap-and-trade program that would 

allow compliance to be achieved through the purchase of emission allowances while the MPS 

does not. The anticipated cost of buying allowances pursuant to the CSAPR is not expected to be 

as financially challenging to Petitioners as installing the pollution control technology in the 

current time frame required to meet current MPS emission rates. 

C. MPS Group Must Also Comply with MATS. 

In response to the vacatur of the CAMR in 2008, USEP A adopted national emissions 

standards for hazardous air pollutants from coal and oil-fired EGUs in February 2012, known as 

the Mercury and Air Toxic Standards ("MATS"). 77 Fed. Reg. 9304 (Feb. 16, 2012). For coalfired EGUs, MATS sets emission limits for mercury, PM, hydrogen chloride, and trace metals 

and also establishes alternative numeric emissions limits. The rule requires compliance by April 

16, 2015, and in certain circumstances, allows an additional one or two years to achieve 

compliance. IPH will comply with the MATS at each of the five operating Energy Centers 

through the use of a combination of existing FGD systems, sorbent injection technologies and 

ESPs. 

D. Compliance with NAAQS 

The variance relief requested by IPH is consistent with the NAAQS and the Illinois SIP, 

see Variance Opinion, at 63, including two recent federal rulemaking developments, one 

involving the NAAQS for PM25, the other involving the one-hour S02 NAAQS. 

65 
First, in December 2012, USEPA adopted a revised primary annual PM25 NAAQS. 78 

Fed. Reg. 3086 (Jan. 15, 2013) (effective Mar. 18, 2013). In accordance with Clean Air Act 

section 1 07( d)(l ), US EPA anticipates promulgating initial PM2.5 nonattainment area 

designations by December 12, 201433 The USEPA intends to classifY all initially designated 

PM2.5 nonattainment areas as "moderate," meaning that, in accordance with Clean Air Act 

section 188(c), designated PM2.5 nonattainment areas will not be required to achieve attainment 

until six years after the designation, i.e., December 2020. 34 Notably, the MPS does not establish 

emission limits for particulate matter or PM2.5, and none of the Energy Centers are located in an 

area that USEPA has preliminarily identified as exceeding the revised primary annual PM2.5 

NAAQS. 35 The AECOM Memorandum further concludes that there is no evidence to suggest 

that the Energy Centers are contributing to elevated PM25 concentrations or, in the case of the 

Coffeen and Newton Energy Centers, concentrations in excess of the NAAQS. Ex. 12, AECOM 

Memorandum, Attachment 2, at 5. Moreover, the requested variance relief would end 

December 31, 2019, almost one year before the anticipated PM2.5 attainment deadline. Thus, the 

requested variance relief would not be inconsistent with Illinois' PM2.5 NAAQS obligations. 

Second, in 2010, USEPA adopted a new primary one-hour 802 NAAQS. 75 Fed. Reg. 

35520 (June 22, 2010). The USEPA had intended to make final its initial one-hour S02 

NAAQS nonattainment area designations in June 2013, but has not yet taken such action. In 

accordance with Clean Air Act section 192, states with areas designated nonattainment for the 

one-hour 802 NAAQS have five years from the date of designation to achieve attainment. 

33 USEPA Memorandum, From: Gina McCarthy, Assistant Administrator, To: Regional Administrators, Regions 1-

10, Subject: Initial Area Designations for the 2012 Revised Primary Annual Fine Particulate National Ambient Air 

Quality Standard, 2-3,9 (April 16, 2013). 34 !d. at 6-7. 35 USEPA, Summmy of2009-2011 PM2.

5 Design Values & Map showing counties with sites violating the annual 

PM2.5 air quality standard for 2009-2011 (2012) available at http://www.epa.gov/airquality/ particle 

pollution/designations/20 12standards/techinfo.htm. 

66 
Subsequent to the Board's issuance of the variance m PCB 12-126, USEPA 

recommended to Illinois that Hollis Township in Peoria County, Illinois, the location of the 

E.D. Edwards Energy Center, be designated as nonattainment with the one-hour S02 NAAQS. 

AER has disputed that recommended designation. Ex. 4, Ameren Comment in Docket QAOAR-2012-0233. While the outcome of the designation recommendation concerning the Hollis 

Township area remains uncertain, Petitioner IPH recognizes that the requested variance relief 

would not exempt E.D. Edwards from compliance with any federal Clean Air Act requirements 

adopted in the future, including Illinois regulations, if any, needed to implement SIP obligations 

concerning the one-hour S02 NAAQS. 

IX. RELEVANT PERMITS 

As required by 35 Ill. Adm. Code 104.204(i), relevant permits are listed in Exhibit 6, 

MPS Group Information. Additionally, the Newton FGD construction permit is included as 

Exhibit 14. 

X. AFFIDAVITS OF FACTS CONTAINED IN PETITION 

As required by 35 Ill. Adm. Code 1 04.204(m), affidavits from the following individuals 

are attached to this Petition as Exhibits: 

• Ex. 1 - Martin J Lyons, Ameren, Executive Vice President and Chief Financial 

Officer 

• Ex. 2 -Mario E. Alonso, IPH, Vice President Strategic Development 

• Ex. 8 - Daniel P. Thompson, IPH, Vice President 

• Ex. 9 - George W. Bilicic, Lazard Freres & Co. LLC, Managing Director and Vice 

Chairman ofinvestment Banking 

• Ex. 11 - Aric D. Diericx, Dynegy Operating Company, Senior Director -

Environmental Compliance 

• Ex. 13 - Steven C. Whitworth, Ameren Services Company, Director of 

Environmental Services 

67 
XI. REQUEST FOR HEARING 

Should the Board decide to hold a hearing in this matter, Petitioners respectfully request 

that any hearing take place in Springfield, Illinois, due to its proximate location to the affected 

facilities, as soon as practicable. As time is of the essence in this matter given the pending 

financial considerations underlying the planned transaction, Petitioners also respectfully request 

that the Board act on this Petition within 120 days as required by the Act, and that any hearing 

be consistent with Board procedures as utilized in PCB 12-126. 

XII. PROPOSED VARIANCE ORDER AND CONDITIONS 

Petitioners recommend the same conditions as provided in the Variance Opinion, but only 

revised to reflect the applicability to the new owners of the MPS Group and the more current 

operable dates and to be conditioned to reflect its effectiveness upon closing of the transaction. 

This will allow all facilities in the MPS Group to remain bound together in the same regulatory 

framework as envisioned by the Board in the regulatory proceedings that created the MPS Rule 

applicable to the MPS Group. Therefore, Petitioners respectfully recommend the following 

variance Order and conditions: 

The Board grants Petitioners, ILLINOIS POWER HOLDINGS, LLC and 

AMERENENERGY MEDINA VALLEY COG EN, LLC, combined dual variances for the 

electrical generating units in the Ameren 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 begitming January I, 2017 through December 31, 2019, subject to the following 

conditions: 

68 

A " 
' ' ' 

1. If at any time Illinois Power Holdings, LLC (IPH) acquires ownership or control 

of the five operating power stations in the Ameren MPS Group, IPH must assure 

compliance with Condition 2 of this Order and must comply with an overall S02 

annual emission rate of 0.35 lb/mmBtu through December 31, 2019, and 

beginning January 1, 2020, must comply with an overall S02 annual emission rate 

of0.23 lb/mmBtu. 

2. At any time AmerenEnergy Medina Valley Cogen, LLC acquires ownership or 

control of the Meredosia and Hutsonville Power Stations, it shall not operate the 

electrical generating units at those plants until after December 31, 2020. The 

FutureGen project at the Meredosia Energy Center is exempt from this restriction. 

3. Regarding the Flue Gas Desulfurization project at the Newton Power Station (I.D. 

No. 079808AAA) (Newton FGD project), at the time IPH acquires ownership or 

control of the Newton Power Station: 

a. On or before July 1, 2015, IPH must complete engineering work on the 

Newton FGD project. 

b. On or before December 31, 2017, IPH 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, IPH must complete construction of the 

absorber building on the Newton FGD project. 

d. On or before July 1, 2019, IPH must complete steel fabrication of 

ductwork and insulation activities on the Newton FGD project. 

e. On or before July 1, 2019, IPH must complete installation of electrical 

systems and piping on the Newton FGD project. 

f. On or before September 1, 2019, IPH must set major equipment 

components into final position on the Newton FGD project. 

g. Beginning with calendar year 2013 and continuing through 2019, aruma! 

progress reports must be filed with the Agency as to the status of 

construction activities relating to the Newton FGD project by the end of 

each calendar year. These aruma! 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 

69 
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 62794-927 6 

WHEREFORE, for the reasons set forth above, Petitioners ILLINOIS POWER 

HOLDINGS, LLC, and AMERENENERGY MEDINA VALLEY COGEN, LLC, and CoPetitioner AMEREN ENERGY RESOURCES, LLC, respectfully request that the Board grant 

the requested variance from the requirement that the seven affected MPS Group facilities comply 

with a system-wide S02 annual emission rate of0.25lb/mmBtu for the period from January I, 

2015, through December 31, 2019, and from the requirement that they comply with a systemwide S02 annual emission rate of0.23 lb/mmBtu for the period from January I, 2017 through 

December 31,2019. 

70 
Respectfully submitted, 

ILLINOIS POWER HOLDINGS, LLC 

BROWN, HAY & STEPHENS, LLP 

Claire A. Manning 

William D. Ingersoll 

205 S. Fifth Street, Suite 700 

P.O. Box 2459 

Springfield, IL 62705-2459 

(217) 544-8491 

Fax: (217)241-3111 

cmanning@bhslaw.com 

wingersoll@bhslaw.com 

AMEREN ENERGY RESOURCES, LLC 

and AMERENENERGY MEDINA 

VALLEY CO EN, LLC 

71 

SCHIFF HARDIN, LLP 

Renee Cipriano 

Amy Antoniolli 

233 South Wacker Drive, Suite 6600 

Chicago, Illinois 60606 

312-258-5550 

Fax: 312-258-5600 

rcipriano@schiffhardin.com 

aantoniolli(ci).schiffhardin.com