### BEFORETHEILLINOIS POLLUTIONCONTROLBOARD

ILLINOIS POWER HOLDINGS, LLC and ) AMERENENERGY MEDINA VALLEY ) COGEN, LLC; ) ) 

### Petitioners, ) ) 

### AMERENENERGY ) RESOURCES,LLC ) ) PCB No. 13- Co-Petitioner, ) (Variance- Air) 

### ) 

### v. ) ) 

### ILLINOIS ENVIRONMENTAL ) PROTECTIONAGENCY, ) 

### ) Respondent. )

APPEARANCE I, AmyAntoniolli,herebyfile myappearanceinthisproceedingonbehalfofPetitioner, AMERENENERGYMEDINAVALLEYCOGEN, LLC, andCo-Petitioner, AMEREN ENERGYRESOURCES, LLC.

Dated: July 19, 2013 

# /] ' 

# "**~£~~)** SCHIFFHARDIN,LLP 233 SouthWackerDrive, 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; )

AMERENENERGY RESOURCES, LLC Petitioners,

Co-Petitioner,


### v. ILLINOIS ENVIRONMENTAL PROTECTION AGENCY, Respondent. ) ) ) ) ) ) ) ) ) ) ) ) ) 

### ) PCB No. 13- (Variance

- Air)



### APPEARANCE I, Renee Cipriano, hereby file myappearanceinthis proceedingonbehalfofPetitioner, AMERENENERGYMEDINAVALLEYCOGEN,LLC, and Co-Petitioner, AMEREN ENERGYRESOURCES, LLC.

Dated: July 19, 2013 ' Renee Ciprian 

### SCIDFF HARDIN, LLP 233 SouthWackerDrive, Suite 6600 Chicago, Illinois 60606 (312) 258-5550 Fax: (312) 258-5600BEFORETHE 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 ) PROTECTIONAGENCY, ) ) Respondent. )

APPEARANCE I, William D. Ingersoll,herebyfile my appearancein thisproceedingonbehalfof Petitioner, ILLINOIS POWERHOLDINGS, LLC.

# #L,""-~ WilliamD. Ingersoll '-"

Dated: July 19, 2013 BROWN, HAY & STEPHENS, LLP 205 S. Fifth Street, Suite 700 P.O. Box2459 Springfield, IL 62705-2459 (217) 544-8491 Fax: (217) 241-3111BEFORETHE ILLINOIS POLLUTION CONTROLBOARD

ILLINOIS POWER HOLDINGS, LLC and ) AMERENENERGY MEDINA VALLEY ) COGEN,LLC; ) ) Petitioners, 

### ) ) AMERENENERGY ) RESOURCES, LLC ) ) PCBNo. 13- Co-Petitioner, ) (Vmiance-Air) ) v. ) ) ILLINOIS ENVIRONMENTAL ) PROTECTIONAGENCY, ) ) Respondent. )

APPEARANCE I, Claire A. Manning, herebyfile myappearanceinthisproceedingonbehalfof Petitioner, ILLINOIS POWERHOLDINGS, LLC.

Dated: July 19, 2013 ClaireA. Manning BROWN,HAY& STEP 205 S. FifthStreet, Suite700 P.O. Box2459 Springfield, IL 62705-2459 (217) 544-8491 Fax: (217) 241-3111CERTIFICATE OFSERVICE I, theundersigned, certifythatontllis 19thday ofJuly, 2013, Ihave servedelectronicallythe attachedPETITIONFORVAlliANCE, andAPPEARANCES OF CLAIREA. MANNING, WILLIAMD. INGERSOLL, RENEE CIPRIANO,AND AMYANTONIOLLI,uponthefollowing persons: JohnThe1riault, AssistantClerk illinoisPollutionControlBoard James R. Thompson Center Suite 11-500 100WestRandolph Chicago, illinois 60601 andbyfirst classmail, postage affiXedupon: DivisionofLegal Counsel illinoisEnvironmentalProtectionAgency 1021 NorthGrandAvenue, East P.O. Box 19276 Springfield, illinois 62794-9276



### BROWN,HAY& STEPHENS, LLP Claire

### A. Manning WilliamD. Ingersoll 205 S. Fifth Street, Suite700 P.O. Box2459 Springfield,

### IL 62705-2459 (217) 544-8491 Fax: (217) 241-3111 SCHIFFHARDIN, LLP Renee Cipriano AmyAntoniolli 233 SouthWackerDrive, Suite 6600 Chicago, Illinois

### 6Q606 (312) 258-5550 Fax: (312) 258-5600BEFORETHEILLINOIS POLLUTION CONTROLBOARD

ILLINOIS POWER HOLDINGS, LLC and ) AMERENENERGY MEDINA VALLEY ) COGEN, LLC; )

AMERENENERGY RESOURCES, LLC Petitioners,

Co-Petitioner,


### v. ILLINOIS ENVIRONMENTAL PROTECTIONAGENCY, Respondent. ) 

### ) ) 

### ) ) 

### ) ) 

### ) ) ) ) ) ) ) PCB No. 13- (Variance- Air)

NOTICEOFFILING To: ALL PARTIES ONTHEATTACI-IED SERVICELIST Pleasetakenoticethattoday wehave electronically filed withthe Office ofthe Clerkofthe illinois PollutionControlBoardaPETITIONFORVARIANCE, andtheAPPEARANCE 01? CLAIREA. MANNING,WILLIAMD.INGERSOLL,RENEE CIPRIANO,ANDAMY

Dated: July 19, 2013 BROWN, HAY & STEPHENS,LLP ClaireA. Manning WilliamD. Ingersoll 205 S. Fifth Street, Suite700 P.O. Box 2459 Springfield, IL62705-2459 (217) 544-8491 Fax: (217)241-3111 SCHIFFHARDIN, LLP Renee Cipriano AmyAntoniolli 233 SouthWackerDrive, 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 ) PROTECTIONAGENCY, ) ) Respondent. )

PETITIONFORVARIANCE 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 ofthe 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 "AmerenMPS Group").

1Hereinafter, 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 ofthis Petition is necessary in order to allow a seamless regulatory transition in concert with a planned change in ownership ofthe MPS Group from the current owner, CoPetitionerAER, to the new owners, Petitioners IPH andMedina Valley. I. PROCEDURAL BACKGROUND OnMay 5, 2012, AERfiled a Petitionfor Variance with the Boardand, on September20, 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 requestedrelief.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 requestthat the Board take administrative notice ofits record in PCB 12-126. 3 Section 225.233(e)(3)(C)(iii) reads: "Beginningin calendaryear2015 and continuing in calendaryear2016, for the EGUs in the Ameren MPS Group, the owner and operator ofthe EGUs mustcomplywith an overall S02 annual emission rate of0.25 lb/million Btu."BEFORE THE ILLINOIS POLLUTION CONTROLBOARD

ILLINOIS POWER HOLDINGS, LLC and ) AMERENENERGY MEDINA VALLEY ) COGEN,LLC; )

AMEREN ENERGY RESOURCES, LLC Petitioners,

Co-Petitioner, V. ILLINOIS ENVIRONMENTAL PROTECTIONAGENCY, Respondent. ) ) ) ) ) ) ) ) ) ) ) ) ) ) 

# RECEIVED Division of Legal Counsel 

### JUL 24 

### 2ou 

## Environmental Protection 

## Agency

PCB No. 14-10 (Variance

- Air)

PETITION FORVARIANCE 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 ofthe Illinois Environmental Protection Act ("Act"), 415 ILCS 5/35, 37, and 35 Ill. Adm. Code Part 104, SubpartB, respectfully requestthat 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-firedpowerplants that are together the ent ities subject to this rule ("MPS Group" or "AmerenMPS Group").

1Hereinafter, citations to the Board's regulations will be by section number onl y. 1The timing ofthis 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 ofthe MPS Group from the current owner, Co-



### ·- <:..-:Jt> ' 1**;~ ~-**  \ jPetitionerAER, to the new owners, Petitioners IPH andMedina Valley. I. PROCEDURAL BACKGROUND -,-:' On MayS,**~?'H'** AERfiled aPetitionfor Variance with the Board and, onSeptember20, 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 ofits record in PCB 12-126. 3 Section 225.233(e)(3)(C)(iii) reads: "Beginning in calendaryear2015 and continuing in calendaryear2016, for the EGUs in the Ameren MPS Group, the ownerand operatorofthe EGUs must comply with an overall SOz annual emissionrate of0.25 lb/millionBtu." 2and relieffrom 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 S02emission limit of0.25 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) ofthe Act, the Boardfound that immediate compliance with the 2015 and 2017 S02 annual emissionrates would have posed an arbitrary orunreasonablehardship.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 emissionrates to bemetduring the variance term. !d. The Board-orderedcomplianceplan also required AER not to operate the generating units at two ofthe plants from 2012 through 2020, and set certain milestones and reporting dates related to the constmction ofthe 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 September20,2012, granted therequestedrelief. !d. at 68. Ingranting the relief, the Board also determined that the earlier, more stringent S02 annual emission rates provided for in the complianceplan would result in anetbenefitto Illinois air quality. !d.

4 Section 225.233(e)(3)(C)(iv) reads: "Beginningin calendaryear 2017 and continuing in each calendaryear thereafter, for the EGUs in the Ameren MPS Group, the owner and operatorofthe EGUs must comply with an overall S02 annual emission rate of0.23 lb/mmBtu." 5A hearingwas held inPCB 12-126 on August I, 2012, and the Board received over3,000 public comments, both oral and written, in that proceeding. See Variance Opinion, at 2. 3Subsequent to the Variance Opinion and due to the continued volatility ofthe 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 generatingbusiness. Exhibit 1,Affidavitof Martin Lyons ("Ex. I,LyonsAffidavit"),**~6.** Thereafter, Ameren entered into a Transaction Agreement ("Agreement") with IPH, an indirect subsidiary ofDynegy 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 ofthe MPS Group and secure the variance reliefand 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 ofAER, which creates "New AER" for the acceptance ofthe active generating facilities ofthe MPS Group (Coffeen, Duck Creek, E.D. Edwards, Joppa, Newton) which will then be acquired by IPH. 6 Ex. 2,AlonsoAffidavit,**~7;** Ex. I, LyonsAffidavit,**~9.** IPH will then acquire New AERand the five active generatingplants. Ex. 2,AlonsoAffidavit,**~4.** The facilities required to remain shutteredunder the Order inPCB 12-126 (Meredosia and Hutsonville) willbe acquired by Petitioner Medina Valley, an indirect subsidiary ofAmeren. Ex. 1, LyonsAffidavit**~~9,** 15. OnMay 2, 2013, in order to effectuate the transaction, IPH and AER filed ajointMotion to Reopen the Docket and Substitute Parties in PCB 12-126 ("Motion"). On June 6, 2013, the Boardissued an Orderdenying the Motion which nonetheless stated: IPH may file avariance petitionconsistentwith Section 104.202(a) ofthe 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. 4PCB 12-126, slip op. atp. 11 (Jun. 6, 2013) ("Board Order onMotion"). As a result ofthe Board's discussion in the Board Order on Motion, Petitioners and CoPetitioner wish to address preliminarily two aspects ofthis Petition for relief. First, Petitioners wish to make clear that any petition for relief from the Ameren MPS Rule must include an analysis ofall sevenplants and not only the five plants to be acquired by IPH. This is because all

seven plants remain part ofthe MPS Group regardless ofownership. Second, this Petition for reliefis timely and includes all necessary parties. A. TheRegulatory History andFrameworkofthe UnderlyingMPSRegulations Requires that any Variance Address all Seven Facilities That Comprise the MPS Group. Inits analysis ofthis variance request, the Board must consider the electrical generating units ("EGUs") located at all seven plants in the MPS Group. Accordingly, this Petition seeks reliefapplicable to all seven plants, and is supported by an analysis ofthe factors based on all

sevenplants as any variance requesting relieffrom the MPS Rule should. As a principal foundation ofthe 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 permanentlypart ofthat MPS group for regulatory purposes even ifone or more ofthe EGUs are subsequently sold to anew owner. The Boardmust 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 ownedby IPH. This is so for three reasons. First, the EGUs at all seven facilities mustpermanentlyremain part ofthe 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 ofProposedNew 35 Ill. Adm. Code 225 Control of Emissions fi'om Large Combustion Sources (Mercwy), R06-25 (Dec. 21, 2006). Sections 5225.233(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 ofProposedAmendments to 35 Ill. Adm. Code 225: Control of Emissionsfrom 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, butrequired 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 emissionrates 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 thebenefit ofotherunits. In the initial MPS analysis, the Illinois Environmental Protection Agency ("IEPA" 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, AERused the same Agency methodology, butincluded calendaryear 2008 to calculate the average heat input of340,446,252 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 BehalfofAmeren Companies, 15 (Feb. 2, 2009)). In both cases, the MPS rates were developed byrelying on data from all sevenfacilities.

7 The 2009 amendments added a section entitled "Ameren MPS Group Multi-Pollutant Standard," the 2015 S02 annual emission rate of0.25 lb/mmBtu and the 2017 SO? annual emission rate of0.23 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 onyears 2003,2004, and 2005). 

### 6T During the variance proceeding, the Agency supported the approach ofconsidering the closures ofHutsonville 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 ofthe established regulatory process." PCB 12-126, Recommendation, 21 (filed July 23, 2012). The Variance Opinion in PCB 12-126 affirmed the appropriateness ofthis approach. Again, the variance rates

are founded on data from all seven facilities used to assess environmental impact and establish system-wide S02 andNOx emissionrates for the MPS Group. As the owner ofthe 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 ofHutsonville 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 ofthe Energy Centers that comprise the MPS Group will remain part ofthe 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 EGUs at all seven facilities must be analyzed togetherbecause the language ofSection 225.233(a) plainly states that the MPS applies to all owners or operators ofEGUsthat 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 ofcomplying with the otherwise applicable emissions standards. !d. This provision contains what has beenreferred to as the "once in, always in" language, which states, "allEGUs [the owner] owns in Illinois as of July 1, 2006,

...mustbe thereafter subject to the standards and control requirements ofthis Section

...." Id. (emphasis



### 7added). The same Section further states: "When an EGU is subject to the requirements ofthis 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 ofan MPS group, the plain language ofSection 225.233(a) applies the MPS requirements to all owners ofthat 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 ifsold or transferred. Itwas 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 ofstructuring the MPS in such fashion is to keep the units that comprise an MPS group together for purposes ofregulating annual emissions of S02, NOx, and mercury, as well as ozone season emissions of NOx. As one of the chief architects ofthe 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 ifone or more tmits are sold. When posed with a hypothetical involving the sale ofsome but not all units in an MPS group, Mr. Jim Ross, Bureau ofAir Division ofAir Pollution Control Manager, and Mr. Chris Romaine, Bureau ofAir Manager ofthe 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

8were owned by a new company. The Agency witnesses further explained that compliance would need to be accounted for inthe sale ofunits. MR. ROSS: What happens ifa 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, wouldbe responsible for compliance ofthe units. And ifthe new owner is not using the MPS, then the units have to comply with the non-MPS provisions. MS. BASSI: I'm sorry. Didyoujust say that the MPS units would have to stay in theMPS butthe non-MPS units would not? MR. ROMAINE: Ibelieve so, yes. There's nothing, as this rule is drafted, that would say somebody purchasing a unit out ofthe multi-pollutant standard group would then be excused from compliance requirements of the multipollutant standards. It wouldn't necessarily trigger compliance with the multipollutant standardbecause they haven't opted in before, butthat 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 somebodyjustdropped out ofthe system? MR. ROMAINE: Actually, Ithinkthat'sthe easierpart ofit. 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, whenAmeren 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, orthree oftheirplants, howeveryou like. Who gets sued? MR. ROMAINE: Good question. Who do you sue? MR. ZABEL: That'swhy I asked it. MR. ROMAINE: Obviously there's complications that this type of anangement would pose in a particular circumstance. Obviously that makes sale ofunits more complicatedifAmeren would ever electto do that. 9MR. ZABEL: Thankyou. 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, ofthe units in anMPS group are sold, the testimony is clear that the Agency expects compliance from the entirety ofthe MPS group as originallyformulated bythe 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 relieffrom 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 ofwho owns the facilities. In keeping with the plain language ofthe regulation and the Agency's stated "once in, always in" intent ofthe MPS, IPH and Ameren have entered into an agreement for the sale of five ofthe seven facilities that comprise the MPS Group while taking special care to account for the continued compliance with the MPS emission rates ofthe units at all seven ofthe Energy Centers. Likewise, any analysis ofthe variance requested in this Petitionmust consider the EGUs at all seven ofthe facilities, regardless ofownership. 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 plainlanguage ofthe rule. B. The Request is Timely and The Petitioners and Co-Petitioner Are All NecessaryParties. 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 orregulation, requirement or order ofthe Board that wouldotherwise be
10applicable 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 orunreasonable hardship that outweighs any adverse impact to the environment. Upon closing ofthe transaction, the Ameren MPS Rule will otherwise be applicable to both IPH and MedinaValley togetherunless a variance is granted and, accordingly, each is aproperPetitioner. As the current owner ofthe MPS Group, with a direct and substantial interest in this proceeding, AERis aproper Co-Petitioner. The proposed Order includedherein 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 reliefas that securedbyAERas 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 ofHutsonville and Meredosiais 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 whomthe AmerenMPS Rule for the MPS Group would "otherwisebe applicable," as stated in Section 104.202(a). Itis imperative that the Boardprovide regulatmy certainty to the new owners ofthe MPS Group without requiring existing ownership

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



### 11joint motion to reopen the docket and substitute parties, the Board quoted the following portionofthe interimorderinEnsign-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 orother appropriate filing concerningthis facility. PCB 12-126, Board Order on Motion, at 10-11. The quoted excerpt ofthe 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 evidencedby the Board's statementthat a thirdparty cannot have

a variance transferred on another party's behalf as well as the subsequent reference to Section I04.202(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 ifclosing

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 reliefbecause 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 ofthe order), and it did not find that the company could not or should not do so before
12closing. !d. There is simply no foundation for reading the Ensign-Bickfordinterim order to

meanthat DynoNobel or any other petitioner could not seek a variance priorto owning the facility. 10 The Board has a long history ofreading the Act and its procedural rules in a mannerthat provides the regulated community with the certainty it needs, as well as providing appropriate reliefwherejustified and allowedpursuantto the Act-reliefsuch 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 reliefto 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 ifvariances similar to those granted Allied were not granted. The previous Opinions in PCB 77-203 and PCB 79-149 are incorporatedbyreference."!d. Here, the variance granted in PCB 12-126 applies to the same MPS Group facilities that

are the subject ofthis Petition and concerns the same specific regulatory framework relevant to that MPS Group. That reliefis an essential term ofthe transaction and, as set forth below, is as

10 Given otherBoard cases, seeAlliedChem. Cmp. & InvernessMining Co., PCB 80-92 Order (May 1, 1980); Opinion and Order (June 12, 1980), the Board should not rely uponthe dicta in theEnsign-Bickfordinterim order as precedent to exclude a variance petition prior to closing. SeeExelon Cmp. v. Dep 'tof Revenue, 234 Ill. 2d 266 (2009) (quoting UnitedStates v. Crawley. 837 F.2d 291, 292 (7th Cir.l988)) ("A dictum is 'anystatement made byacourt foruse in argument, illustration, analogy orsuggestion. Itis aremark, an aside, concerning some mleoflaw or legal proposition thatis 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 generallyused as an abbreviation of obiterdictum, which means aremark oropinionuttered by the way. Such an expression oropinion as ageneral rule is notbinding as authority orprecedentwithin thestaredecisis rule."). 13relevant to IPH as it is to AERand the same arbitrary andunreasonable hardship results to IPH if the reliefis 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 FROMWIDCHVARIANCE IS SOUGHT A. The Petitioners Seek Temporary Relieffrom the 2015 and 2017 S02 Annual Emission Rates ofthe Ameren MPS Rule. The Petitioners jointly seek relief from Section 225.233(e)(3)(C)(iii) and (iv) ofthe 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 ofthis Petition. Section 225.233(e) states inrelevantpart: e) Emission Standards forNOx and S02• 

### *** 3) AmerenMPS Group Multi-Pollutant Standard 

### *** C) S02 Emission Standards 

### *** iii) Beginningin calendaryear2015 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 emissionrate of0.25 lb/million Btu. iv) Beginning in calendar year 2017 and continuing in each
14calendar year thereafter, for the EGUs in the Ameren MPS Group, the owner and operator ofthe EGUs must comply with an overall S02annual emissionrate of0.23 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 becameeffectiveJuly 15,2009. R09-10 (June 18, 2009). Consistent with Section 35(a) ofthe Act, in PCB 12-126, the Boardfound 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 "willresult in anetbenefitto the environment." PCB 12-126, at48, 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 ofthe filing ofPCB 12-126 onMay 3, 2012. The variance reliefin PCB 12-126 was granted on September 20, 2012, prospectively, since it was not triggered simultaneously with the date ofthe Board's final opinion and order. Variance Opinion, at 68-69. Instead, the variance set anew 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 emissionrates during the years of2012 through 2014. !d. Here, the Petitioners seek, andjustify, 15that 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 andthe transacting parties. The reliefgranted in PCB 12-126 was deemed to bejustifiedin orderto 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 ofthe variance period, compliance with the AmerenMPS Rule, as written, willbe 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 AmerenMPS Rule, as written, beginningin 2020. B. Each ofthe DualVariances 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 relieffrom Section 225.233(e)(3)(C)(iv) for three years, beginning January I, 2017, and ending December 31, 2019. In PCB 12-126, the Boardpreviously granted AERthis exactrelief, for the very same sevenpowerplants 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. TheMPS Group Includes Seven Illinois Coal-Fired Energy Centers. The seven coal-fired power plants that constitute the MPS Group, and which are the subject ofthis 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 ofthese plants

16and the air monitoring stations maintained by IEPA 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 ofthese facilities, since AER committed in PCB I2-I26 to

cease operation ofthe electric generating units at Meredosia and Hutsonville during the term of the grantedvariance. All ofthe counties are currently designated attainment for allpollutants. 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 oflow sulfur coal, including blending low sulfur coal with Illinois coal that contains higher levels ofsulfur. 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 ofselected pages ofthe Agency'sIllinoisAnnualAir Quality Report20II, includes a copy ofthe map at page 34, depicting the locations ofthe 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, USEPA is considering the inclusion ofa portion ofPeoria County, which would include E.D. Edwards Energy Center, as a designatednonattainment area with respect to the one-hour S02 National Ambient Air Quality Standard ("NAAQS"). As explained later in this Petition, Amerenhas filed a comment in USEPA Docket QA-OAR-2012-0233 objectingto such inclusion, which is attached hereto and incorporatedherein as Exhibit4 ("Ex. 4,Ameren Comment inDocket QA-OAR-2012- 0233"). 17conditioning and electrostatic precipitators ("ESPs"). Mercury emissions are controlledthrough the use ofscrubbers and sorbentinjectiontechnologies. In 2012, the MPS Group achieved anoverallNOx annual emissionrate 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 IEPA identification numbers, permit application numbers, and other pertinent informationregarding their output, pollution control equipment, and S02 emissions are provided inExhibit 6, attached to this Petition ("Ex. 6, MPS Group information"). C. TheFacilities ProvideA SignificantEconomic Benefitto the State ofIllinois. The operating Energy Centers are ofsignificant economic benefit to the State ofIllinois and its workforce, accounting for an estimated total economic impact on Illinois of approximately $1.5 billion annually and approximately 6,200 total directand indirectjobs. The direct and indirect economic impacts have been analyzedby Development Strategies and are providedhere 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 ofthose dollars being spent in the community at localbusinesses for goods and services. Seebelowtable (TableA): TableA 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 18Centerr" Total Direc and Indirect 2,481 1,325 1,292 471 725 6,294 Jobs Ifreliefis not granted, and the transaction fails to close, Ameren will needto pursue other options. See Ex. 1, LyonsAffidavit'i[l6. Ameren's stated intentionto exitthe merchant generation business to better focus on its core regulatedbusiness, inevitably means that AERwill no longer be in a position to ensure the operation ofthese plants. Ameren would continue to explore exit possibilities which could include sale ofthe assets, the restructuring ofdebt and equity in AEG,

or some combination thereof. !d. While it is difficult to predict the outcome ofAmeren's exit strategy, there is no reason to believe that any otherpotentialbuyerwill be willing to acquire the plants without this variance, unless the buyer intended to close one or more of the Energy Centers. Under arestructuring scenario, control and operation ofthe merchantbusiness would be dependent on negotiation with bondholders thereby creating uncertainty for employees, suppliers, and local communities. !d. IPH, with a continuation ofthe variance reliefgranted to AER, represents the bestpath forward for the continued operation ofthose 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 ofthe Southern and Central Illinois economy. Granting the Petitioners the requested variance reliefrepresents the best alternative for the merchant business

as it struggles through very distressed and uncertain economic andpowermarket conditions.

13 Table A only reflects employees who reside in Illinois. Some of the Energy Centers employ personnel from neighboring states. The total directjobs 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, GroupExhibit. 19D. 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 othercontexts. See PCB 12-126, AERPet., at 6, 8. MedinaValley has not been the subject ofanypriorvariance 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 ofmercury 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). ThePCB 09-048 variance resulted in an overall net reduction of41.7 pounds ofmercury 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 DynegyMidwest Generation v. !EPA, PCB 12-135 (seeking

avariance from 35 Ill.Adm. Code 225.233(±)(2)). IV. DETAILED DESCRIPTION OF COMPLIANCE PLAN A. Petitioners' Compliance Plan Will Achieve Compliance with All ofthe Terms ofthe Variance Opinion in PCB 12-126. As an integral part ofits 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 emissionrate of0.35lb/mmBhlthrough 2019. Committing to this 20S02 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 sulfurcoal (0.55 lbs sulfur/mmBtu) from the PowderRiverBasin 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 ofoperations at Hutsonville and Meredosia an enforceable condition as to both IPH and Medina Valley, and as consistent with the enforcement approach ofiEPA as to theMPS Group. Further, Petitioner IPH will maintain a continuousprogram ofconstruction atthe 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 absorberbuilding 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 ofthe NewtonFGDs.

21The 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 ofthe Newton FGDs. The requested variance term also will allow Petitioners to properly stage and staggerthe in-service date ofeach ofthe two NewtonFGDs 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 AERpointed out inits 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 emissionrate of0.35 lb/mmBtu. (ii) Beginning January I, 2020, IPH will comply with an overall S02 annual emission rate of0.23 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 ofthe variance relief), with the exception ofthe FutureGenproject atMeredosiaEnergy 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 constmctionmilestone commitments andrepmting obligations. 1. IPHWill Continueto Use Low SulfurCoal. 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

22committed to limiting the use of higher sulfur coal to the Duck Creek and Coffeen Energy Centers, both ofwhich 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 requestedvariance term, IPH will also berequiredto limitthe use ofhigh 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 ofthe 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 in2013,2014,2015, 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 enteredby 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 ofthe variance, IPI-I anticipates potentially purchasing certain quantities ofeven lower sulfur coal, consistent with availability, perfom1ance risk, price, and the MPS Group's emissionperformance. !d. 2. IPH Will Continue to Optimize ScrubberPerformance. 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

23Coffeen 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 ComplianceAre 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 ofthe E.D. Edwards and Joppa Energy Centers. !d. -,r12; Ex. 2AlonsoAffidavit, -,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 Boardfound in its Variance Opinion, the shutdown ofE.D. Edwards and Joppa would adversely impact 274 directjobs, 1,374 indirectjobs, 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 ofS02 scrubbers on three units at a cost ofover $813 million, installation ofSCR systems to reduce NOx emissions at three plants at a cost of

over $177 million, and installation ofactivated 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 atotal ofabout $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

24halfofthe total costs have been spent to date. !d. In accordance with the constructionmilestones in the proposed variance order, IPH has budgeted $18 million in annual expenditures through 2017 with the remainder oftotal estimated spending scheduled for 2018 and 2019 to complete construction ofthe Newton FGDs and achieve compliance at the end ofthe variance period. !d. In addition, for the five Energy Centers, IPH estimates several million dollars in average annual Operations andMaintenance ("O&M") expenditures through 2019 to comply with the MPS NOx and mercury emissionlimits. !d. Without the variance, IPH's compliance with the MPS Rule 2015 S02 emission rate would require virtually immediate completion ofthe Newton FGD project which, at this time, given the variance reliefafforded 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 ofamulti-year (2015-2019) construction schedule inPCB 12-126 is quiterelevant to this Petition. V. ARBITRARY ORUNREASONABLE HARDSHIP The very samehardship factors recognizedby 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

25alone in its stringent MPS requirements, putting the MPS Group at a disadvantage to its competitors. !d. at 10. None ofthat changes underthe 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 ofAppeals 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 inupwind states to

areas in downwind states. !d. at 48349. The D.C. Circuit Court ofAppeals also vacated this mle inAugust 2012. EPA v. EMEHomer 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 TheUSEPA subsequently adopted the Mercmy and AirTaxies Standards ("MATS") to control EGU emissions, 77 Fed. Reg. 9304 (Feb. 16, 2012), but thatrule is currentlybeing appealed to the DistrictofColumbia Circuit Comt ofAppeals. See White Stallion Energy Ctr., LLCv. EPA, No. 232200 (D.C. Cir., Feb. 16, 2012). 26play more directly the uncertainty coal-fired power generators face as they await both how the Supreme Court will rule and whether USEPA will continue to move forward on developing a CAIR/CSAPRreplacementyetagain. The uncertainty involving the future applicability of any federal rule to control the interstate transport ofairpollution is further compoundedby 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 USEPA to issue final carbon pollution reduction standards for existing power plants "no later than" the ambitious deadline ofJune I, 2015. 16 Indeed, inno uncertainterms, President Obamahas made powerplantcarbonpollutionreduction

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 USEPA must ensure that carbon standards are developed and implemented in a manner "consistentwiththe continuedprovision ofreliable and affordable electricpower for consumers and businesses," 17 no oneyet knows howUSEPA will interpret its mandateto setnewcarbonpollution 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 ofthis variance request would only complicate these matters further. Until the federal regulatory obligations are sufficiently clear, it is even more imperative that the State ofIllinois,

15 Exec. Officeofthe President, ThePresident's ClimateAction Plan (June 2013). 16 The White House, Office ofthe Press Secretary, Memorandum for the Administrator ofthe 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). 27through 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 amannerthat does notunfairly 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 ofthe 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 compliancewith the emissionrates at issue an arbitrary andunreasonable hardship for any
owner ofthe MPS Group. The Illinois General Assembly adopted the Electric Service Customer Choice and Rate ReliefLaw of 1997. See 220 ILCS 5/16-101. One ofthe primary purposes ofthis 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 oftime (the mandatory transition period). As a result ofthe legislature's deregulation ofIllinois' energy markets in 1997, Illinois generators cannot recover the costs ofcapitalprojects, including those relatingto environmentalmandates, through captive

consumerrates. Rather, merchantpower companies' investment decisions such as the installation of pollution control equipment are based on the ability to recoup such expenditures from expectedfuture marketprices for power.



### 28The deregulated market does not alone create the hardship that the MPS Group now faces. Itis 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 ofputtingthe Illinois merchant generationbusiness at a substantial disadvantage to its out-of-state competitors. Those mandates, however, were adopted in anticipation offederal 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, otherneighboring states have not adopted state airregulations 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 ofgas 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 certainpercentages ofthe 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 theNewton FGD project in time to meet the MPS

18 Forexample, Indiana, Kentucky, Missouri, Iowa, and Ohio have no mercury emissionmles. Wisconsin requires that large coal-fired EGUs apply control technology to reduce mercuryemissions 90 percentbyJanuary 1, 2015, or complywith amulti-pollutantoption that achieves 90 percent mercuryreductionbyJanuary I, 2021. Wis. Adm. Code, Dept. ofNatural Res., NR446 etseq. Michigan requires mercuryreductions from coal-fired EGUs byJanuary I, 2015, or achieve 75 percentreduction under amulti-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 largestelectric powerplants; remaining facilities must reduce mercury emissions 70-90 percentby2025. Minn. Stat. §115A.932 etseq. Moreover, none ofourneighboring states have as stringent 802 standards as in the Illinois MPS. 292015 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 ofthese factors that amount to the arbitrary and umeasonable hardship that any

owner ofthe MPS Group now faces. Generators 

### in neighboring states who have not had to make such emJsswn control equipment investments orare able to recover such costs through the consumerrate 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 ofcompanies in surrounding states, orby the federal government, at atime 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) ofthe Act. C. Hardship Caused byPlant Closures. Unless Petitioners receive the requested variance relief, plant closures are inevitable. Itis for this reason that the Petition has been filed now.20 Ifthe Board does not allow the Petitioners the MPS variance reliefit deemed appropriate as to AER, for the very same MPS Group, and

19 See Sarah Burnett,Illinois CreditRating: State's WorstIn Nation Costing Tax PayersMillions, Huffington Post, June 25, 2013, available athttp://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 ofthe plants, without any review ofthe appropriateness ofthe requested reliefpursuant to Section 35(a) and this Petition, would inject a great and unnecessaty uncertainty regarding the continued viability and operation ofthe 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. 30IPH nonetheless moves forward with the transaction, IPH's only compliance option would be to shut down a combination ofEnergy 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 ifthe needed financial resources were available (which they are not), the NewtonFGDs could not, absent the variance, nowbe completedin time to avoid shutting down the E.D. Edwards and JoppaEnergy 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 combinationthereof. Ex. 1, LyonsAffidavit,**~16.** As previously noted, under a restructuring scenario, control and operation ofthe 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 suchbuyer intended to close one or more plants. !d. IPH, with a continuation ofthe variance reliefgranted to AER, represents the best path forward for the continued operation of the Energy Centers and in a manner that achieves ultimate compliance with theAmerenMPS Rule.

31The shutdown of the E.D. Edwards and Joppa Energy Centers would, as previously considered by the Board in PCB 12-126, adversely affect 274 directjobs, 1,374 indirectjobs,

over $121 million per yearin 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 ofshutting down the E.D. Edwards and Joppa Energy Centers would devastate their local communities and materially undermine the State's struggling economy. The shuttering ofthese plants will create

an arbitrary or umeasonable hardship on IPH, the local economies servedby 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 andNewtonEnergy Centers:
Senator GaryForby (Tr., at57-59) 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 isjustasking for their "fair share." Representative BrandonPhelps (Tr., at59-62) Rep. Phelps' comments focused on the Joppa Power Plant, also in his district. As Chairman ofthe 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 thosejobs would crush Jasper County's economy and the local school system. Those 155jobs in a county ofless than 10,000 people equates to losing 41,800jobs in Chicago (pop. 2.7 million).

32Rep. Reis stated that the United States emissions are only a "thimble ofwater 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 ofJasper County, he statedthatthey don'thave big organizations representing them, or lobbyists or lawyers, just themselves and their concern for their community, schools, andjobs. MayorMarkBolanderofNewton (Tr., at79-81) Newton has an annual economic impact onthe state, in direct spending, of$71.5 million; total economic activity, over $231 million; directjobs 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 inIllinois, ofwhich $40.5 million was household earning that supported 820jobs. The $213 million in total economic activitytriggers 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 themultiplier effects. Forthe labormarket, the Newtonplantprovides a direct spending of$67.5 million; total economic activity of$154.3 million; directjobs 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 oftotal economic activity supported $35.1 million in household eamings for the market area including $12.4 million indirect compensationfor employees, and $22.7 million in added eamings. JasperCountyBoardMemberBillWebber(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. Itrepresents a little over 51% ofthe total tax revenue for the county. MayorBillyMcDaniel ofMetropolis (Tr., at 103-106) There are 235 well-payingjobs at the Joppa plant-wellabove 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 ofthousands ofdollars on vendors inthe city. JasperCounty SchoolBoardSuperintendentDanCox (Tr., at 106-108) The Newton Energy Center represents 60% ofthe local tax revenues for Jasper County Schools, which translates into $4 million peryearto the school district. JeanEllenBoyd from Shawnee CommunityCollege (Tr., at 111-112) The propertytaxes from the Joppa facility provide $86,000 peryearto the college.

33Vicky Clark President ofEconomic Development Council for Central Illinois (Tr., at 189-191) The E.D. Edwards Energy Centerprovides 110jobs in Bartonville. The wages generated from those jobs create an additional 450 jobs through spending in the local economy. Closing ofEdwards would result in a loss of over $124 million annually to the local economy. Bill Sheppardfrom JoppaPlant (Tr., at 192-195) In2011, there were approximately 150,000 man-hours ofbuilding 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 Contributeto an Arbitrary andUnreasonableHardship. Due to AER's limited financial resources caused by depressed power prices and poor economic conditions overthe past several years andits inability to obtainexternalfinancing, IPH will not be able to fund completion ofthe Newton FGDs in time to comply with either the 2015

or 2017 MPS S02 annual emission rates. Ex. 2, AlonsoAffidavit,**~24.** Nor is adequate funding available to implement any other feasible MPS compliance alternatives available to IPH as demonstrated in SectionVI. 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, andthe State ofIllinois. Moreover, the same financial considerations the Boardaddressed in PCB 12-126 as itrelates to hardship continueto beequallyrelevanthere. 1. Power Prices/Market Conditions Remain Depressed and Are Not Expected to Begin GradualRecoveryUntil 2015. Construction ofthe Newton FGD in time to meet the existing MPS is an impossibility both in terms ofconstruction 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 ofthe Newton FGDs in time to comply with the MPS 2015 overall S02 34 

### '£'.

annual emission rate, even ifIPH were financially able to ramp up construction immediately upon acquiring ownership, which it is not. Ex. 8, ThompsonAffidavit, ,; 12. The lack offinancial

resources needed to complete installation ofthe 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 ofelectricity; 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 powerprices is largely due to the combination ofexcess 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 ofgas extraction

are a "game changing"technology that have "fundamentally altered" the outlookfor gas supplies and pricing); seealso Exhibit 9,Affidavitof George W Bilicic ("Ex. 9,BilicicAffidavit"), ,;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 ofits 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,AlonsoAffidavit, 1\6. 35TableB

Ex. 2, Alonso Affidavit,**~11.** These forecasts of future power prices suggest that earnings pressure at IPH (orNew AER as referred to byMr. Bilicic) will continue in the near term. Ex. 9, BilicicAffidavit,**~6** (citing Moody's Unregulated Utility & Power Companies: StillNo Sign of Recovery (Feb. 6, 2013)). 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 S02ComplianceDeadlines. With power prices reiiJaining depressed, IPH will continue to face the continuing financial pressures that AER faced at the time of its variance petition. Id.; Ex. 2, Alonso Affidavit,**~~13,** 14. These depressed powerprices have severely eroded operating margins ofthe Energy Centers in the MPS Group and will continue to limit the ability ofthe 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 ofthe Newton FGDs. Id. The power industry is a cyclical commodity business with significant price volatility requiring considerable investmentrequirements. 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 36known 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 ofdoing 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 marketprices, swings in load demand, and commodityprice volatility. Id.**~13.** Furthermore, as previously discussed, because the Energy Centers are at the mercy ofthe 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, AlonsoAffidavit,**~24.** AER does not currently have, and as a result IPH will not at closing have, the financial

resources to complete construction ofthe 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 ofpersistently 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

37improved, 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 of2013, AER had a $151 million net income loss. Ex. 2, AlonsoAffidavit, '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 ofthis 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 ofGENCO has been cut by 4 and 3 notches by Standard & Poor's ("S&P") and Moody's, respectively, since AERwas grantedthe variance. Ex. 9, BilicicAffidavit, 'i[8. GENCO "has less than adequate liquidity" and "poor standing in the credit markets." Ex. 2, AlonsoAffidavit, 'i[l4 (quoting S&P, Research Update: Ameren Energy Generating Co. Ratings Loweredto 'CCC+' On WeakPowerPrices; OutlookNegative (Feb. 8, 2013)). GENCO will continue to be responsible for repayment ofits $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 byAER. More specifically, at closing, IPH will have approximately $220 million in cash. !d. 'i[20. Ofthat $220 million, approximately $203 million will be at GENCO and approximately $17

38million will be at AERG/Ameren Marketing. !d. The proceeds from exercising the put option (a minimum of$133 million) are part ofthe 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 ofcommodity markets) ofthis $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, ifreplaced today, woulduse 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 ofthe Newton FGDs or make any other MPS compliance alternatives feasible. !d.**~21.** Inaddition 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 ofthe Newton FGDs or make any otherMPS 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 OptionAgreement was designed as amechanism to provide cash liquidity to GENCO by selling its three natural gas fired powerplants (Elgin, Gibson City and GrandTower). Depending on the results ofthe sale process oftheputassets, the total cash available for GENCO at closing couldbehigherthan $203 million (i.e., the amountthat includes the minimum $133 million resulting from GENCO having exercised the put option in March2013). Anyadditional proceeds would beused for GENCO operating needs. Notably, the sale ofthe three natural gas plants also means that GENCO no longer can derive cash flow from those plants. 

### 39Duck Creek and Coffeen; and (c) utilize low sulfur coal atNewton, Edwards and Joppa. Itis 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 ofthe 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 powerprices and the volatile nature ofthe merchant energybusiness, 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'sultimate 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 ofDynegy's engineering, maintenance, and outage planning expertise. !d. Implementation ofDynegy'sPRIDE initiative (Producing Results through Innovationby 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 possiblebased onthe advice ofits employees. !d.**~25.** Importantly, IPH does expect that the gradual recovery ofpower prices (anticipated to begin after April 2015) will provide IPH with sufficient cash flow and liquidity to ramp up and complete construction ofthe Newton FGDs by year end 2019. !d.**~23.** Dynegy has made clearin its public statements thatitbelievespowerprices will begin to recover when compliance with the



### 40federal 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 ofthe 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 ofthe Newton FGDs in time to meet the 2015 and 2017 MPS emission rates. !d. The recovery ofpowerprices will notbe immediate in 2015, norwill marketrecovery in 2015 be sufficientto generate the cash flow and liquidity needed to accelerate completion ofthe Newton FGDs in time to meet the MPS. !d. Rather, the recovery of power prices and associated generation ofpositive cashflows is expected to occurgradually overtime. !d. Thus, the five-year term ofthe requested variance is critical to allowing adequate time for both recovery ofpower prices and for IPH to accumulate the significant financial resources needed to comply at the end ofthe 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 atwww.dynegy.com/investorrelations/sec-filings); DYN-Q4 2012 Dynegy Inc. Earnings Conference Call (Mar. 14, 2013), Tr., at 17 ("inapostMATS complianceworld, [Dynegy] certainlyexpect[s] highercapacitypayments, higherpowerprices"). 24 DYN-Q42012 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

...."). 41party lenders. Ex. 2, AlonsoAffidavit,**~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 ofthe Energy Centers, existing debt, and weak credit profile of the businesses, the financial institutions contacted replied that they would not extend a creditfacility. !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 ofthis debt matures in 2018, and approximately $250 million ofthe 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 of2013, GENCO's interest coverage ratio fell to a level less than the specified minimum level required for external borrowings. Ex. 9, SilicicAffidavit,**~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 powerprices 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,AlonsoAffidavit,**~16.**

42In 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.** IfGENCO's interest coverage ratios do not improve significantly by the debt maturity dates, GENCO would have to repay its outstanding debts ($300 million in 2018; $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. Thatwill notbepossible underIPH without therequestedvariance relief. 4. Dynegy CannotSupportthe CapitalNeeds ofIPH. As Dynegyhas publicly communicatedto 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, AlonsoAffidavit,**~~5,** 13, 18. This is no different than the situation presented to the Boardby 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 severalyears ofeconomic challenges caused by depressedpowerpricing

25 In granting the variance in PCB 12-126, the Board did not accept arguments thatAmeren, as AER's ultimate parent company, mustfinancially supportAER's MPS compliance efforts. That same conclusion should apply to IPH's requestfor variance relief, particularly given that Ameren has astrongercreditrating than Dynegy. Ex. 9, BilicicAffidavit,**~12.** 

### 43and 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 of20 12 and $142 million for the first quarter of 2013. !d. Thus, in a very real sense, while Dynegy expects powerpricing and marketconditions to improve overthe longer-termbeginning in 2015, Dynegy is not a "deeppocket"with limitless funds that could now orinthe next severalyears be made available to IPH to complete construction ofthe Newton FGDs sooner than the proposed variance conditions.!d. More importantly, Dynegycannotintegrate IPH into theDynegy capital structure without

severe adverse consequences that would imperil its financial future. !d.**~17.** As part ofits 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 ifIPH were integrated into the Dynegy financial structure or if Dynegy were to provide financial supportto IPH, otherthan limited amounts ofworking capital. !d. Having onlyrecently emerged from bankruptcy in October2012, Dynegy cannottake 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 ofinvestorconfidence, which wouldultimatelyjeopardizeDynegy'sbalance sheet and liquidity. !d.**~18.** Simply stated, Dynegywill not-and, ineffect, cam10t-endangerits balance sheetorits creditratingbyintegratingIPH into the Dynegy capital structure.!d.

44InApril2013, 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 notbe integratedinto the Dynegy capital structure. !d. While the newrefinancing agreement itselfwould allow Dynegy to invest certain amounts in its subsidiaries, including IPH, Dynegy cannot inject those funds into IPH withoutrisking its creditrating and credibility-somethingDynegy cannot do. !d.**~19.** Consistent with Dynegy's needto protect its financial soundness and its commitments to the credit rating agencies and investors concerning the IPH transaction, Dynegy, ifit is needed, may provide very limited financial support to IPH for the sole purpose ofproviding necessary working capital needed to maintain day-to-day operations ofthe businesses. !d.**~25.** As was the

case at the time ofthe 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 ofthe 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, BilicicAffidavit,**~15.** In short, the various challenges faced by IPH are the same, ifnot worse, than those faced by AERwhen it was granted the variance. See id.**~14.** The rationale for the varianceremains unchanged-itwill continueto play a critical role in allowing IPH to manage its liquidity and credit quality in the midst of a currently challengedmerchant 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 thereliefrequested inthe Petition.

45E. ThePetitioners' Hardship is NotSelf-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 ofthat system-wide approach. The transaction negotiatedbyAmeren and IPH also recognizes that regulatory structure and responsibly tries to implement it as part of the transaction. Ex. 2, AlonsoAffidavit,**~** 8. Thus, any argument that the Board should dismiss this Petition based upon a line ofBoard cases finding the hardship to be "self-imposed" is simply wrong. The cases in which the Board denied variance reliefby finding the hardship was "selfimposed" present factual scenarios much different than that presented here. The inquiry the Board engages into determine a self-imposed hardship is whether the company seeking reliefis in a quagmire ofits own making, due to lack ofdiligence or despite knowledge ofrequirements. Consider, for example, the following cases where the Board denied variance reliefbecause it found that the claimedhardship 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 committo a complianceplan;

• 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 beunaware of existingregulations;

• Marathon Oil Co. v. !EPA, PCB 95-150 (May 16, 1996). Variance denied because ofcompany's faulty decision-making.

46See 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 ofvariance reliefdue 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. Forthe Boardto hold that this variance is notwarranted 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 relieffor 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 reliefwhere 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 ofknowledge ofthe requirements. In fact, IPH is demonstrating sound decision-making and knowledge of the requirements by acknowledging the need for the continuation ofvariancereliefto provide thebestpath forward for the operatingplants before the transaction is completed. The Petitioners have exhibited through the structure ofthe transaction, and this Petition, a full understanding ofthe regulatory construct ofthe MPS and the obligations thatresult, as well as theneed to substantiatethe request for reliefinstead ofappearing before the Board, after-the-fact, assuming the Board would provide the lifeboat. The hardship faced by the plants is anything but self-imposed.

47VI. COMPLIANCE ALTERNATIVES Petitioners have performed an independent analysis ofcompliance alternatives, consistent with the Board's procedural rule at Section 104.204(e) which requires that a variance petitioner provide a description ofthe efforts that would be necessary to achieve immediate compliance (here, with the existing MPS rule) and adiscussion ofthe 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 ofcompliance alternatives that AER examined in support of its petition." Variance Opinion, at 49. The costs and technological limits prevailing at the time ofthe 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, ThompsonAffidavit,**~11.** A. CurtailingPlant Operations Is NotEconomicallyFeasible. As explained above, to meet the MPS 2015 S02 emission rate without the variance, IPH would need to shut down acombination ofthe Newton, Joppa and E.D. Edwards Energy Centers. !d.**~12.** A curtailment ofoperations by piecemeal shutdowns ofspecific 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

48end 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 oftheir respective generation to approximately one-third of its capacity. !d. Given their fixed costs, such a limit on generation would eliminate any potential ability ofthese Energy Centers to generatepositive cash flows going forward. !d. While it would be infeasible for IPH to curtail operations ofspecificunits on atemporary basisto meet the MPS, IPHexpects that during the term ofits requested reliefE.D. Edwards Unit I will be permanently retired. !d.**~27.** In December 2012, Ameren filed arequest 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 ofMISO's tariff, with the Federal Energy Regulatory Commission ("FERC") on July II, 2013 (the "July 11 SSR Filing"). !d. The maximum term ofan 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 ofmitigation alternatives. !d. As noted in the July II SSR Filing, MISO expects that E.D. Edwards I will continue as an SSRunit 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



### 49Agreement. Therefore, annual renewal ofthe SSRAgreement 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 1will be retired before the end of the requestedvariance term. !d. B. Alternative ControlTechnologies. IPH also has reviewed the availability ofalternative 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 costmore than the NewtonFGDproject. !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 ofDSI at other coal-fired plants, IPH estimates that the capital cost ofinstalling 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 sufficientliquidity to fund any such large-scaleprojects overthe next several years. Ex. 2,AlonsoAffidavit,**~20.** Further, as AER demonstrated in its Post Hearing Briefand reaffirmed here, the capital costs ofinstalling DSI atJoppa and/or E.D. Edwards would not belimited to the DSI technology only. Ex. 8, Thompson**Affidavit,~~** 17-18. Because ofthe size ofthe existing particulate control equipment and the use ofACI for mercury control at E.D. Edwards and Joppa, the use ofDSI would result in a significant increase in PM emissions necessitating installation ofPM control technologies (e.g., baghouses). !d. Thus, the real expected capital cost ofinstalling DSI at Joppa wouldbe approximately $433 million and approximately $280 million at E.D. Edwards (Units 2



### 50and 3). !d. See also Post Hearing Brief, at 15 (citing 2011 URS report and attaching a cost table therein as PostHearingBrief, Exhibit 1 ). Moreover, the annual O&M expense ofDSI is significant. Ex. 8, Thompson Affidavit,**~18.** As AER demonstrated, the estimated annual cost ofdry sorbent ranges from $15 million to $44 million depending upon the type ofmaterial used and the location ofinjection (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 citedby 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 ofthe Newton FGD project is alreadyunderway. C. Conversion to NaturalGas is EconomicallyInfeasible. The Board also examined AER's analysis ofconverting to natural gas at E.D. Edwards and Joppa. Variance Opinion, at 50. In PCB 12-126, the Board accepted AER's conclusion that conversionto natural gas did not represent aviable compliance alternative because, quoting from AER's Post Hearing Brief, at 23-24: "under current market conditions, a natural gas conversion at Joppawould reduce operations to a season basis only and lead to reduced revenue and aloss 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 orNewtonEnergy Centers. Ex. 8,

51ThompsonAffidavit,**~19.** The cost ofconstructing natural gas pipelines to either facility would be cost prohibitive. !d. An initial estimate ofthe 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 ofexisting coal-firedboilers, the cost ofconverting each plant would be expected to be tens ofmillions ofdollars, ifnot 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, conversionto gas is not feasible and is costprohibitive. 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 wouldresult in significantly lowerproductionbythe 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 Newtonbusbar averaged in excess of$22/MWh during 76 percent ofthe on-peak days while only two percent on the on-peak day averages exceeded $40/MWh. !d. In other words, Newton

26

Availableatwww.babcock.com/librwylpdj!MS-14.pdf

52fired 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 severalreasons, convertingJoppa to natural gas would be costprohibitive and not economically feasible.**Jd.~21.** First, an order ofmagnitude 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 atJoppa would not be

a cost effective compliance alternativebecause, 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 ofJoppa to natural gas firing would reduce the plant's operations to a seasonal basis only, thereby resulting in reduced revenues and, ultimately, a loss ofjobs. Variance Opinion, at 21, 50. IPH will not have the sufficient liquidity to fund any such large-scale capitalprojects overthe next severalyears. Ex. 2,AlonsoAffidavit,**~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 ofheat 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

53would result in lower production and, thus, generate lower revenues for the recovery offixed operating costs and capital expenditures. !d. The key factor for sustained use ofnatural gas cofiring is the price differential betweennatural 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 ifnatural gas prices approached $2.50/mmBtu. !d. Thus, even atthe 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, norwould it achieve compliance withtheMPS overall S02 emissionrates. !d. Thus, IPH concludes that, as the Board determined in the AERvariance proceeding, it is economically infeasible to convert E.D. Edwards, Newton or Joppa to natural gas, especially when construction ofthe Newton FGD project is already underway. Ex. 8, Thompson Affidavit,**~~19-22.** VII. ENVIRONMENTALIMPACT A. Any Adverse Environmental Impact From the Variance Does Not Outweigh theArbitrary orUnreasonableHardship oflmmediateCompliance. The appropriate standard the Board must employ in any analysis ofany 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 ororderof the Boardwould impose an arbitrwy orunreasonable hardship. 415 ILCS 5/35(a) (emphasis added).

54Inorderto make that finding, a greatbody ofcase law requires that the Board weigh any such hardship against any adverse impact to the environment. In a variance proceeding, a petitionermustdemonstrate thatthe 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 ofcompliancehave notbeenidentified despite diligent efforts bythe petitioner. Mobil Oil Co. v. !EPA, PCB 86-45, slip op. at 6 (Aug. 14, 1986). The Board has granted variance reliefon many occasions after finding the variance would cause minimal or no adverse environmental impact. Vi!!. of Princeville v. !EPA, PCB 93-227, slip op. at4 (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 ofGalva v. !EPA, PCB 89-131, slip op. at 2 (Dec. 20, 1989). The Boardhas even grantedvariance reliefafter 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) ofthe Act does not require that the Board find a "net benefit to the environment" as a conditionprecedentto granting relief, and no courthas interpreted the Act

as requiring such netbenefit, 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 ofthe MPS

55Group should be ofno consequence in the Board's analysis of environmental impact in this varianceproceeding. B. IPHillynegy is Committedto EnvironmentalProtectionin 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 ofIllinova Corporation (i.e., the fossil fuel-fired electric generating assets ofIllinois Power Company), which formed the basis ofDMG's current generating fleet. Ex. 8, Thompson Affidavit,**~6.** As IPH's parent company, Dynegy is very cognizant ofits 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 ofproducing approximately 4,200 MW ofreliable, 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 afifth coal-firedpowerplant, the Vermilion Power Station (Vermilion County). Id. Through its subsidiaries, Dynegy employs approximately 600 full-time employees m Illinois, employing approximately 550 persons atits Illinois powerstations and approximately 50 persons at its corporate office located in O'Fallon, Illinois. !d. Theeconomicimpact 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 aportion ofthe ShawneeNational Forest. The LowerMississippi River Valley reforestation project is registered underthe Verified Carbon Standard and was the first United States forest carbon offsetproject to receive this certification. Dynegyhas also donated 1,100 acres along the Middle Fork Vennilion River to the Illinois DepartmentofNatural Resources and has sponsored activities preserving lj200 acres afforests in Illinois. Each year, these trees will sequester increasing levels ofcarbon dioxide. Ex. 8, ThompsonAffidavit,**~[9.** 

### 56example, 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 staffwas 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 ofits 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 ofNOx, S02 and mercury, as well as particulate matter and other emissions. Since 1998, emissions levels from DMGhave dropped almost 90 percent. 29 !d. C. Description ofEnvironmentalImpacts. Pursuant to Section 104.204(g) ofthe Board's procedural rules, a petitioner for variance must describe the environmentalimpact ofthe activity.

28 UnitedStates v. Illinois Power Co., No. 99-CV-833-MJR(S.D. Ill.) (ConsentDecree entered May27, 2005) (a copy ofthe ConsentDecreeas originally entered is available at: http://www.epa.gov/compliance/resources/decrees/civil/caa/dmgfinal-cd.pdf). 29 DMG'sBaldwinand Havanafacilities have installed and are operating dryFGD systems for the control ofS02 emissions, and ESPs and baghouses for the control ofparticulate emissions. DMG'sHennepin facility has ESPs and baghouses for the control ofparticulate matter. Thebaghouses atDMG's facilities also control hazardous air pollutants in particulate form, such as mostmetals. ACI ormercury oxidation systems for the control ofmercury 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 atBaldwin. See Ex. 8, Thompson Affidavit,**~8.** 571. The nature and amount ofemissions ifthe variance is granted compared to that which would result ifimmediate 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 ifimmediate 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, AlonsoAffidavit,**~8;** Ex. 8, ThompsonAffidavit,**~13.** The Ameren-IPH transactionhas been carefully crafted to allow for the operation ofthe plants in amanner that achieves compliance with the Ameren MPS Rule. Ex. 2, AlonsoAffidavit,**~8.** Dynegy, the ultimate parent ofIPH, has a history ofachieving compliance with MPS rules in Illinois. Ex. 

### 8, Thompson Affidavit,**~8.** IPH, with a continuation of the variance reliefgranted 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,LyonsAffidavit,**~16.** Neither Section 35(a) ofthe Act nor Section 104.204(g) ofthe Board's rules requires, in justifying the variance, that emissions be less than they would be ifimmediate 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 ofa prospective compliance date, such was achieved in PCB 12-126. That benefit will continue with the extension ofthe variance to the new owners ofthe MPS Group, as the Petitioners here propose the same complianceplan. The Petitioners have demonstrated this net environmental benefit by both estimating the tons ofS02 emissions reduced from 2010 through 2020 (Table I) and from 2013 through 2020 (Table 2), Exhibit I0. Both Tables demonstrate over the relevant period, fewer tons ofS02will 

### 58be emitted into the air by the end ofthe variance term than would be under the Ameren MPS Rule. Table 1shows anet environmentalbenefit of74,303 fewer tons ofS02emitted.30 Exhibit 11,Affidavit of AricD. Diericx ("Ex. 11, DiericxAffidavit"),**~6.** Itis 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 AmerenMPS 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 1shows the actual S02 emissions for 2010,2011, and2012. !d. The actual tons ofS02emitted during 2012 were even less than projected in PCB 12-126. !d. All ofthese factors have resulted in benefits to human health and the environment not otherwise required under the MPS. Further, the requested reliefincludes aprovisionto not operatethe electric generatingunits at Hutsonville and Meredosia through December 31, 2020, thereby providing a benefit through the end of2020. 31 Even ifthe Board were to look only at the years in the requested reliefthat IPH and Medina Valley are scheduled to take ownership ofthe MPS Group-the time period from 2013 through 2020-in analyzing the environmental impact ofthe variance, Table 2 shows the MPS

30 Overthe period 2012-2020, Table I reflects a 47,178 netreduction in S02emissions for the MPS Group, a 13,633 ton increase in net reductions compared to the Variance Opinion, which recognized anet reduction of33,545 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) S02emissions are not included for 2013-2016 because the FutureGen 2.0 project is not expected to begin operations until September2017. Ex. II,DiericxAffidavit,**~6.** 31 Inkeeping with the "oncein, always in" intentofthe MPS thatwas previously endorsedbyboth !EPAand the Board in PCB 12-126 (!EPA Recommendation, at 21; Variance Opinion, at 54), thecumulative S02reduction in both Tables is based on abaseline heat input that reflects the cessation ofoperations atthe Hutsonville and Meredosia plants through 2020. In analyzing environmental impact, the Board has considered emission reductions notexclusively attributable to aparticular individual petitionerin aparticularvariance proceeding. ExxonMobil Oil Corp. v. !EPA, PCB 11-86, 12-46 (Dec. I, 2011) (considering the significantenvironmental benefitofNOx reductions achieved through the installation ofselective catalytic reduction that was installed underaconsent decree). Thus, in this MPS variance context, the Board should consider the "benefit"providedbythe entire MPS Group and notonly as it relates to one isolated petitioner. 

### 59Group will achieve a net environmental benefit of7,748 fewer tons of S02 ifthe 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 outweighthe hardships associatedwith 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 ofimplementing the requested variance and proposed complianceplan, in fact, anetenvironmentalbenefit would be realized." !d. In reaching this conclusion, the AECOM Memorandum not only provides infonnation directly related to the variance request (an analysis ofthe impact ofthe requested variance, a discussion ofthe health effects information available regarding exposure to S02, and potentialimplicationsfrom S02 emissions at issue), it also provides an overview ofthe CleanAir Act's National Ambient Air Quality Standards ("NAAQS"), a summary ofS02 emissions in the United States and Illinois, and a discussion ofthe variance request as it may be related to the USEPA December 2012 revision ofthe NAAQS for annual PM2.s (airborne particulate matter of 2.5 micrometer in diameter and smaller). Given the earlierreductions in S02 emissions that have 60already occurred and the commitmentto adhere to the mitigationrate 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 ofthe variance. !d. The earlier, more stringent mitigation rates provide a benefit to human health and the environment. Indeed, in terms ofthe appropriate Board query, there will be no adverse impacts to the environmentthat outweigh the impacts from plant closures and otheridentifiedhardships. 3. Impacts ofDischarge ofContaminants on Human, Plant and Animal Life. Section 104.204(g)(l) ofthe 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 ofthis 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 ofthe variance on human, plant and animal life. !d. PetitionerIPH must operate the scrubbers atDuck 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 shutteredthrough the end ofthe variance term. !d. D. Probable FurtherEmission Reductions Through IPH Performance. Fmihermore, for several reasons, the Petitioners expectthat the MPS Group will achieve

even more S02 emissions reductions during the term ofthe requested variance period than the

61reductions 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 ofthe requested variance term. The Tables do notreflect the expectedretirement ofE.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 includedin AER's commitmentforNewton, E.D. Edwards andJoppa.

### Jd.**~28.** Tables 1and 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,DiericxAffidavit,**~~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 atNewtonthatwill be required to complete the installation ofthe 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 secondFGD wouldbe installed on the secondunit), meaning that one ofthe FGDs will most likely be operating for a portion ofcalendaryear 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. TheRequestedVarianceWill Cause No AdditionalEnvironmentalImpacts. The requested variance relief addresses only S02 emissions and would not impact emissions ofother 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 ofEdwards 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.** 

### 62the new ownership. Ex. 6, MPS Group Information (identifYing pollution control equipment installed and operating at the MPS Group facilities). AERhas 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 questionthat the environmentin Illinois is benefittingfrom 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 requiredby the MPS. Exhibit 13,Affidavit of Steven C. Whitworth ("Ex. 13, Whitworth Affidavit"),**~4.** AERearly elected five EGUs to meet the 0.008 lb/GWh mercury emission limit in 2013 a year to a year and a halfearlier 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 "LowMass Emitting" units by demonstrating that potential mercury emissions are de minimis (<29 lbs/year). !d. Moreover, IPH ownership will bring with itthe environmental compliance experience of Dynegy. As stated above, Dynegy has a solid history ofpositive environmental compliance in Illinois. Since 1998, emissions levels from DMG have dropped almost 90 percent. Ex. 8, ThompsonAffidavit,**~8.** In addition, cross mediaimpacts are not an issue. See Ex. 12,AECOMMemorandum.

63VIII. CONSISTENCY WITHFEDERAL LAW The Board may grant the variance consistent with federal law and, specifically, with the Clean Air Act, 42 U.S.C. 7401 etseq. The requested variance is consistent with current federal law. A. The Terms of the Requested Variance Will Not Jeopardize Illinois' BART ComplianceDemonstration. 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 limitationsrepresenting BestAvailable 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 ofreduction achievable through the application ofthe best system ofcontinuous emission reduction for each pollutant which is emitted by an existing stationaryfacility. 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. USEPA 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 2017) than the application ofBART onBART-subjectunits. 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 withthe Clean AirAct'sregional 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 ofemission allowances while the MPS does not. The anticipated cost ofbuying allowances pursuantto the CSAPR is not expectedto be

as financially challenging to Petitioners as installing the pollution control technology in the currenttime frame required to meetcurrentMPS emissionrates. C. MPS Group Must Also Comply with MATS. In response to the vacatur ofthe CAMR in 2008, USEPA 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 ofa combination ofexisting FGD systems, sorbent injection technologies and ESPs. D. Compliancewith NAAQS The variance reliefrequestedbyIPH is consistent with the NAAQS and the Illinois SIP,

see Variance Opinion, at 63, including two recent federal rulemaking developments, one involvingtheNAAQS for PM25, the otherinvolving the one-hour S02 NAAQS.

65First, 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), USEPA 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 afterthe designation, i.e., December2020. 34 Notably, the MPS does not establish emissionlimits for particulatematter orPM2 .5, and none ofthe 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 ofthe Coffeen andNewton Energy Centers, concentrations in excess oftheNAAQS. Ex. 12,AECOM Memorandum, Attachment 2, at 5. Moreover, the requested variance relief would end December 31, 2019, almost one yearbefore the anticipated PM2 .5 attainment deadline. Thus, the requestedvariance reliefwouldnotbe inconsistent with Illinois' PM2 .5NAAQS obligations. Second, in 2010, USEPA adopted a new primary one-hour 802NAAQS. 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 802NAAQS have five years from the date ofdesignation to achieve attainment.

33 USEPA Memorandum, From: Gina McCarthy, AssistantAdministrator, To: Regional Administrators, Regions 1- 10, Subject: Initial Area Designations for the 2012 Revised PrimaryAnnual Fine ParticulateNational AmbientAir Quality Standard, 2-3,9 (April 16, 2013). 34 !d. at 6-7. 35 USEPA, Summmy of2009-2011 PM2.5Design Values & Map showingcountieswith sites violating the annual PM2.5 airquality standard for 2009-2011 (2012) availableathttp://www.epa.gov/airquality/ particle pollution/designations/2012standards/techinfo.htm. 66Subsequent 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 ofthe 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 ofthe designation recommendation concerningthe Hollis Township area remains uncertain, Petitioner IPH recognizes that the requested variance relief would notexemptE.D. Edwards from compliance with any federal CleanAir Actrequirements adopted in the future, includingIllinois regulations, ifany, neededto implement SIP obligations concerningthe one-hour S02NAAQS. 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 OFFACTS 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 -MarioE. Alonso, IPH, Vice President Strategic Development • Ex. 8

-DanielP. Thompson, IPH, Vice President • Ex. 9

- George W. Bilicic, Lazard Freres & Co. LLC, Managing Director and Vice Chairman ofinvestmentBanking • Ex. 11

- Aric D. Diericx, Dynegy Operating Company, Senior Director

- Environmental Compliance • Ex. 13

- Steven C. Whitworth, Ameren Services Company, Director of Environmental Services



### 67XI. REQUEST FOR HEARING Should the Board decide to hold ahearing 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 ofthe essence in this matter given the pending financial considerations underlying the plannedtransaction, Petitioners also respectfully request that the Board act on this Petition within 120 days as required by the Act, and that any hearing beconsistent with Boardprocedures as utilized inPCB 12-126. XII. PROPOSED VARIANCE ORDERAND CONDITIONS Petitionersrecommend the same conditions as provided inthe Variance Opinion, but only revised to reflect the applicability to the new owners ofthe MPS Group and the more current operable dates and to be conditioned to reflect its effectiveness upon closing ofthe 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 Orderand conditions: The Board grants Petitioners, ILLINOIS POWER HOLDINGS, LLC and AMERENENERGY MEDINA VALLEY COGEN, 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. Ifat any time Illinois Power Holdings, LLC (IPH) acquires ownership or control ofthe five operating power stations in the Ameren MPS Group, IPH must assure compliance with Condition 2 ofthis Order and must comply with an overall S02 annual emission rate of 0.35 lb/mmBtu through December 31, 2019, and beginningJanuary 1, 2020, must comply with an overall S02 annual emissionrate of0.23 lb/mmBtu. 2. At any time AmerenEnergy Medina Valley Cogen, LLC acquires ownership or control ofthe Meredosia and Hutsonville Power Stations, it shall not operate the electrical generating units at those plants until after December 31, 2020. The FutureGenproject atthe MeredosiaEnergy Centeris exemptfrom this restriction. 3. Regarding the Flue Gas Desulfurizationproject at the Newton Power Station (I.D. No. 079808AAA) (Newton FGD project), at the time IPH acquires ownership or control ofthe 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, ifneeded, for the installation ofthe FGD equipment atthe NewtonPower Station.

c. On or before December 31, 2018, IPH must complete construction ofthe absorberbuilding onthe Newton FGD project. d. On or before July 1, 2019, IPH must complete steel fabrication of ductworkand 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 NewtonFGD 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 ofactivities completed during the year, activities plannedto be completedin the forthcoming year, progress ofthe NewtonFGD projectto comply with the timelines specified in this variance, and the estimated inservice date. Annual progressreports mustbe submittedto: Illinois Environmental ProtectionAgency Attn: Ray Pilapil, Manager 

### 69BureauofAir-Compliance Section 1021 N. Grand Ave. East P.O. Box 19276 Springfield, IL 62794-9276 and Illinois EnvironmentalProtectionAgency Attn: GinaRoccaforte, Assistant Counsel Division ofLegal Counsel-AirRegulatoryUnit 1021 N. Grand Ave. East P.O. Box 19276 Springfield, IL 62794-9276 WHEREFORE, for the reasons setforth above, PetitionersILLINOIS POWER HOLDINGS, LLC, andAMERENENERGYMEDINAVALLEY COGEN,LLC, and CoPetitionerAMERENENERGYRESOURCES, LLC,respectfully request that the Boardgrant therequested variance from the requirement thatthe seven affectedMPS Group facilities comply with a system-wide S02 annual emissionrate of0.25lb/mmBtufor the period from January I, 2015, through December 31, 2019, andfrom the requirementthat they comply with a systemwide S02 annual emissionrate of0.23 lb/mmBtufor the period from January 

### I, 2017 through December31,2019.

70

### Respectfully submitted, 

### ILLINOIS POWERHOLDINGS, LLC

BROWN, HAY & 

### STEPHENS, LLP Claire A. 

### Manning WilliamD. Ingersoll 205 S. Fifth Street, Suite 700 P.O. Box2459 Springfield,IL 62705-2459 (217) 544-8491 Fax: (217)241-3111 cmanning@bhslaw.com wingersoll@bhslaw.com 

### AMEREN ENERGY RESOURCES, LLC and AMERENENERGYMEDINA VALLEY CO EN, LLC

71

### SCHIFF HARDIN, LLP Renee Cipriano Amy Antoniolli 233 SouthWacker Drive, Suite 6600 Chicago, Illinois 60606 312-258-5550 Fax: 312-258-5600 rcipriano@schiffhardin.com aantoniolli(ci).schiffhardin.com