Exhibit No. Name/Citation Description 

1 Ex. 1 Lyons Affidavit Affidavit of Martin J. Lyons 

2 Ex. 2 Alonso Affidavit Affidavit of Mario E. 

Alonso 

3 Ex. 3 Illinois Annual Air Quality 

Report 2011—location of 

plants and air monitoring 

stations 

4 Ex. 4 Ameren’s comment in 

USEPA Docket QA-OAR2012-0233 

5 Ex. 5 MPS Group Emission 

Data 

MPS Group 2012 Emission 

Data 

6 Ex. 6 MPS Group Information Addresses, IEPA ID 

numbers, permit application 

numbers, and other info of 7 

Energy Centers 

7 Ex. 7 Group Exhibit Group Exhibit of Five 

Memoranda provided by 

Development Strategies 

8 Ex. 8 Thompson Affidavit Affidavit of Daniel P. 

Thompson 

9 Ex. 9 Bilicic Affidavit Affidavit of George W. 

Bilicic 

10 Ex. 10 Table 1 & Table 2 Table 1 & Table 2 Ameren 

MPS Group Variance SO2 

Limit Comparison to the 

Current MPS 

11 Ex. 11 Diericx Affidavit Affidavit of Aric D. Diericx 

12 Ex. 12AECOM Memorandum Health Effects Report 

provided by AECOM 

13 Ex. 13 Whitworth Affidavit Affidavit of Steven C. 

Whitworth 

14 Ex. 14 Newton FGD Construction 

Permit 
EXHIBIT 1

AFFIDAVIT OF MARTIN J. LYONS 
TESTIMONY OF MARTIN J. LYONS 

I. BACKGROUND AND QUALIFICATIONS 

1. My name is Martin J. Lyons, Jr. I am employed by Ameren Corporation 

("Ameren") as Executive Vice President and Chief Financial Officer. My business address is 

1901 Chouteau A venue, St. Louis, Missouri, 63103. I am responsible for corporate planning, 

business and commodity risk management, internal audit, treasury, tax, investor relations, 

accounting and financial reporting. I received my Bachelor of Science in Business 

Administration degree, with a major in Accountancy, from St. Louis University. I received my 

Master of Business Administration degree from Washington University in St. Louis. I was 

named to my current position in 2009. 

2. Before joining Ameren, I served as a partner in PricewaterhouseCoopers LLP's 

St. Louis office providing auditing services to companies in a variety of industries. In 2001, I 

joined Ameren Corporation as the Controller. I was named Vice President and Controller in 

2003 and in 2008 became Senior Vice President and Chief Accounting Officer. 

II. AMEREN CORPORATION'S DECISION TO EXIT MERCHANT 

GENERATION BUSINESS 

3. Ameren is a public utility holding company whose primary assets are the common 

stock of its subsidiaries, including Ameren Missouri, Ameren Illinois, Ameren Transmission 

Company and Ameren Energy Resources ("AER"). Ameren's subsidiaries are separate, 

independent legal entities with separate businesses, assets, and liabilities. Dividends to Ameren 

stockholders depend on distributions made to it from its subsidiaries. Ameren's core business and 

source of earnings is its utility operations (rate-regulated natural gas delivery, rate- regulated 

transmission and rate-regulated generation and delivery). AER has not made a distribution to 

Ameren since 2009. 
4. AER's financial prospects have been increasingly dire. A depressed power price 

market, increasing fuel and transportation costs, Midwest economic malaise, and burdensome 

interest costs associated with AER long-term debt, including debt obligations of AER subsidiary 

Ameren Energy Generating Company ("AEG" or "GENCO"), have all contributed to AER's 

poor financial performance. AER's net income plummeted from $238 million in 2009 to$ (396) 

million in 2012 and cash flow from operations for AER over this same period dropped 44% from 

$339 million in 2009 to $191 million in 2012. Net income for GENC0 1

, the owner of the 

Newton Energy Center and a Securities and Exchange Commission (SEC) registrant, plummeted 

from $162 million in 2009 to $(40) million in 2012, as summarized below: 

Year Ended December 31, 

2009 2010 2011 2012 

Net income/(loss) in millions $ 162 $ (36) $ 45 $ (40) 

5. In addition, cash flow from operations over this same period dropped 45%, from 

$253 million in 2009 to $139 million in 2012. The erosion of income and cash flows has had a 

direct and adverse impact on GENCO's creditworthiness and ability to fund capital investment. 

Over the last fourteen months, credit rating agencies (Standard & Poor's, Moody's and Fitch) 

have downgraded the ratings of GENCO's bonds several notches, such that they are now deep 

within 'junk" status, indicating increasing uncertainty as to whether or not GENCO will be able 

to meet its ongoing debt obligations2

. The chart below summarizes credit rating actions since 

2009. 

1 AER subsidiary and AmerenEnergy Resources Generating (AERG) are not publicly registered companies. 

GENCO's financial predicament, however, is reflective of AER and AERG's financial status. 2 Investment grade ratings are 888- and above (8aa3 Moody's) while 88+ (8al Moody's) and below are 

considered speculative investments. GENCO's bond ratings fall within the speculative or "junk" category. Fitch 

defines "CC" and "CCC" ratings as follows: CCC: "Default is a real possibility"; CC: "Default of some kind is 

2 
Ameren Energy Generating Company Rate Changes 

(January 2009-June 2013) 

Fitch Moody's S&P 

Unsecured Issuer Unsecured Issuer Unsecured Issuer Rating Change 

As of 01/01/09 BBB+ BBB+ Baa3 NR BBB- BBB07/30/10 BBB BBB Downgrade 

03/01/11 Ba1 NR Downgrade 

05/23/11 BB+ BB+ Downgrade 

01/27/12 BB- BB- Downgrade 

02/28/12 BB BB Downgrade 

02/29/12 Ba2 NR Downgrade 

03/05/12 BB- BB- Downgrade 

04/12/12 Ba3 NR Downgrade 

11/26/12 B+ B Downgrade 

12/21/12 B+ B- B B- Downgrade 

01/10/13 B2 NR Downgrade 

01/28/13 CCC- cc Downgrade 

02/08/13 CCC+ CCC+ Downgrade 

03/14/13 B3 NR Downgrade 

6. Under generally accepted accounting standards3

, all entities must perform 

impairment assessments when events and circumstances suggest that the value of an asset (or 

group of assets) has declined such that its carrying costs may not be recoverable. For example, a 

dramatic change in market conditions could trigger a requirement to perform an impairment 

assessment. If the carrying cost or book value exceeds the undiscounted future cash flows of the 

asset(s), an impairment charge must be recognized in the company's financial statements. On 

December 30, 2011, the United States D.C. Circuit Court of Appeals issued a stay ofUSEPA's 

Cross-State Air Pollution Rule "CSAPR".4 Following the stay, in early 2012 natural gas prices 

declined sharply. As a result ofthese events, Ameren performed an impairment evaluation of its 

merchant generation assets. Upon conclusion of such evaluation, impairment charges of $628 

probable." Moody's defines a "8" rating as follows: "Obligations rated 8 are considered speculative and subject to 

high credit risk." Genco's rating is the lowest within the category. Standard & Poor's defines a "CCC" rating as 

follows: "Currently vulnerable and dependent on favorable business, financial and economic conditions to meet 

financial commitments". All of the ratings indicate the dire financial situation of Genco. 3 Accounting Standards Codification (ASC) 360 Property, Plant and Equipment. 4 The Court ultimately vacated the CSAPR in its entirety. 

3 
million pre-tax were recorded in the first quarter of2012 to reduce the book value of AERG's 

Duck Creek to its estimated fair market value. However, under applicable accounting guidance, 

the estimated undiscounted future cash flows of the remainder of the merchant assets retained 

sufficient value at the time of the assessment to avoid impairment charges. See Note 17 -

Impairment and Other Charges, Ameren Corporation 2012 Form 10k. As 2012 progressed, 

however, market conditions and outlook for the business continued to erode, forcing Ameren to 

make a fundamental decision regarding its business operations. The volatility and bleak outlook 

for earnings and cash flow from the merchant segment threatened to impede Ameren's ability to 

focus on and invest in its core rate-regulated operations. Accordingly, in a Form 8K filed on 

December 20, 2012, with the SEC, Ameren announced its intent to exit the merchant generation 

business and affirmed that "a change in circumstances had occurred regarding its expected 

duration of ownership of its Merchant Generation business segment's energy centers" and that 

cash flows would be insufficient to recover the total carrying value of the energy centers. As a 

consequence, and under applicable accounting guidance, Ameren recorded an impairment charge 

of $1.95 billion related to its merchant business segment indicating their value had deteriorated 

well below the cost of these assets reflected on Ameren's books. The specific method of exit was 

not identified, but the options cited in Ameren's 2012 10K included either sale of all or parts of 

Ameren's merchant generation business or the restructuring of all or a portion of Ameren's 

equity position in GENCO. 

7. Prior to Ameren's decision to exit its merchant business, Ameren had taken 

several measures to preserve liquidity and manage its credit profile with the goal of weathering 

the power market downturn. Specifically, AER reduced capital and operating & maintenance 

4 
expenditures, divested select non-coal generating plants, and established an internal "Put Option" 

mechanism to provide CENCO with emergency standby liquidity. 

III. Divestiture of AER Business Segment to Dynegy (IPH) 

8. Shortly after that public announcement, Dynegy, Inc. ("Dynegy") contacted 

Ameren regarding the potential acquisition of the AER merchant generating business segment. 

Dynegy owns and operates through two if its subsidiaries coal and natural gas fired power plants 

in Illinois. Due to its Illinois presence and its ownership of a variety of merchant generation 

assets throughout the country, Dynegy was viewed as a strategic buyer for the AER assets. 

(During the summer and fall of2012, other firms expressed interest in the merchant business, but 

those discussions did not culminate in a viable transaction for Ameren.) 

9. By agreement dated March 14, 2013, Ameren agreed to convey to Illinois Power 

Holdings, LLC (IPH), an indirect subsidiary ofDynegy, its equity interest in AER (once 

reorganized). AER, through its various operating subsidiaries (AERG, AEG, EEl), owns the 

following coal-fired energy centers: Joppa, Edwards, Newton, Coffeen, Duck Creek, Meredosia 

and Hutsonville. However, not all assets and liabilities of AER are part of the IPH transaction. 

As directly relevant to the variance, Ameren will initiate a reorganization of AER by moving the 

five operating energy centers (Joppa, Edwards, Newton, Coffeen, and Duck Creek) into a 

subsidiary of AER ("New AER"). The reorganized company is referred to as "new AER" in the 

Transaction Agreement and is the entity that IPH will be acquiring. In addition, the shuttered 

energy centers, Meredosia and Hutsonville, will be transferred from AER but to an existing 

indirect subsidiary of Ameren, AmerenEnergy Medina Valley Cogen LLC ("Medina Valley") so 

that Ameren can continue to manage ongoing environmental responsibilities for these plants. 

5 
After closing occurs, the reorganized company acquired by IPH will be renamed and will no 

longer operate under the name of "Ameren" or any other similarly derived name. 

10. The Put Option Agreement described in testimony and during the public hearing 

in PCB 12-126 has been modified and exercised by GENCO. As the Board may recall from the 

testimony of Gary Rygh (Barclay's Capital) and Ryan Martin (Ameren) in PCB 12-126, the Put 

Option Agreement was designed as a mechanism to provide cash liquidity to GENCO. Based on 

GENCO's current and expected liquidity position, the GENCO Board of Directors determined 

exercising the Put Option was in the best interest of GENCO. In essence, GENCO agreed to 

transfer ownership of the Elgin, Gibson City and Grand Tower natural gas plants in exchange for 

an irrevocable commitment that, upon exercise of the Put Option, the remittance of $100 million 

would immediately be made by Ameren to GENCO indirectly through a cash infusion into 

AERG. GENCO would subsequently receive additional funds to the extent appraised values of 

the three natural gas plants was determined to be greater than $1OOM. As part of the negotiations 

with Dynegy, Ameren and GENCO agreed to modify the Put Option Agreement and substituted 

Medina Valley in place of AERG as a party to that agreement. GENCO has exercised the 

option, and Ameren, through Median Valley, has remitted $100 million to GENCO. Following 

approval from FERC, ownership of the three natural gas facilities will be transferred from AEG 

to Medina Valley. The gas plant facilities are being marketed and will be sold by Medina Valley 

as soon as practicable. The Put Option proceeds represent GENCO's primary source of reserve 

liquidity, since it no longer has access to third party external financing, and can be used to 

support the volatile short-term working capital and cash needs associated with continued 

operation ofthe GENCO energy centers, including funding operations and potential losses and to 

6 
pay interest. Copies of the Put Option Agreements and Amendments thereto are appended to my 

testimony. 

IV. WORKING CAPITAL REQUIREMENTS OF THE AER MERCHANT BUSINESS 

11. On-going operations of AER require relatively large amounts of working capital. 

Specifically, the marketing activity associated with AER's generation business necessitates the 

availability of working capital sufficient to support the settlement of fuel purchases, power 

purchase and sale transactions, and any related credit assurance required under agreements with 

trading partners. The overall timing of all cash receipts and payments impacts ongoing working 

capital and cash needs. These needs varied by up to $75 million in 2012 on a daily basis within 

any month. Through short-term inter-company loans, Ameren Corporation extended capital to 

AER (including GENCO) to cover cash obligations until the settlement of power sale 

transactions permitted such proceeds to be remitted back to the parent company. The average 

daily amount of short-term debt extended to AER during the year ended March 31, 2013 was $80 

million. The largest daily debt balance during this period was $132 million. 

12. Ameren has historically provided credit and cash collateral support for AER's 

business. As of March 31, 2013, this support totaled $223 million of credit guarantees and $31 

million of cash collateral support. In its December 20, 2012 announcement, Ameren indicated it 

planned to reduce and ultimately eliminate this support. Due to its weak financial state, AER 

and its subsidiaries may be required to provide cash collateral to support its ongoing business. 

Without a bank credit facility, parental credit support, or the ability to obtain debt from external 

sources, such cash collateral, would have to be funded with on-hand cash balances. 

13. Future AER operations and cash needs may vary depending upon a variety of 

factors including the following: cash collateral requirements for new or existing contracts, the 

7 
future price of electricity, the dispatch of the generation stations, the price of fuel, changes in 

fuel inventory levels, future operations and maintenance expenses and capital expenditure 

requirements. Accordingly, while the cash position of GENCO has benefitted from the exercise 

of the Put Option, such proceeds must be reserved by GENCO to provide adequate ongoing 

liquidity and manage short-term cash volatility. The funds are not available to fund significant 

capital investment, including the completion ofthe Newton FGD. The use of GENCO's primary 

liquidity source to fund long-term projects that do not generate additional revenues would be 

financially imprudent and could threaten GENCO's ability to continue as a going concern. 

14. Assuring adequate liquidity is a challenge for AER and GENCO due a number of 

factors described previously in the testimony of Gary Rygh (Barclay's Capital) and Ryan Martin 

(Ameren) and noted by the Board in PCB 12-126. GENCO cannot secure its own independent 

source of additional liquidity due to restrictions in certain bond indenture covenants. Outside of 

specific borrowing restrictions, liquidity for unregulated generation companies continues to be 

very limited and, if available at all, expensive given declining business conditions and operating 

results. Note that under IPH ownership, GENCO would continue to be subject to the indenture 

provisions that currently restrict its ability to secure third party financing or pay dividends. 

V. COMPLIANCE OBLIGATIONS UNDER BOARD ORDER (PCB 12-126) 

15. As indicated above, to facilitate the transaction, Ameren will reorganize AER to 

segregate the assets to be conveyed from those to be retained by Ameren through Medina Valley. 

Along with the natural gas plants identified above, and just prior to the closing of the IPH 

transaction, as noted above, ownership ofthe Hutsonville and Meredosia energy centers will be 

transferred to Medina Valley. I am the Executive Vice President and Chief Financial Officer of 

Medina Valley and a member of its Board of Managers. I can confirm and represent that under 

8 
the current AER variance (PCB 12-126) and in the event the Board grants IPH's proposed 

request for variance, neither Hutsonville nor Meredosia will operate its generating units, 

consistent with the Board's Order in PCB 12-126. 

16. Should the Board deny the pending request for variance relief presented to the 

Board by IPH and Medina Valley, AER would continue to comply with the Board's Order in 

PCB 12-126. I simply wish to reiterate that Ameren is committed to exiting the merchant 

generation business in an orderly fashion so as to focus on its core utility operations. Ameren 

does not foresee a circumstance under which it would continue to own and operate merchant 

generating assets in Illinois. Should the IPH transaction not close, Ameren would continue to 

explore exit possibilities, which could include the sale of assets, the restructuring of debt and 

equity in GENCO, or some combination thereof. Under a restructuring scenario, control and 

operation of the merchant business would be dependent on negotiations with the GENCO 

bondholders and, ultimately, the result of such restructuring proceedings thereby creating 

uncertainty for employees, suppliers and local communities. In Ameren's view, the conveyance 

of the merchant business to IPH represents the best path forward for the continued operation of 

the energy center facilities which are an integral part of the Southern and Central Illinois 

economy. Dynegy already has a significant operating presence in Illinois and is well-positioned 

through its subsidiaries to achieve the necessary economies of scale required to operate these 

energy centers during uncertain and distressed power market conditions. We have no reason to 

believe that any other potential buyer would be willing to acquire the energy centers without the 

variance, unless such buyer intended to close one or more plants. 

FURTHER, Affiant sayeth not. 

9 
DATED: +----- /JY~/;3 _ _ TJ 

Subsc )}ed and swore to before me 

this l.t'""day of July, 2013 

42853-0000 

CH2\12852130.2 

in J. L ns, Jr. 

Title: Executive Vice President and Chief 

Financial Officer 

Debby Anzalone - Notary Public . Notary Seal, State of 

Mlssou~ - ~t. louis County Com~1~s1on #1 0435722 

My CommiSSion Expires 512312014 

10 
EXHIBIT 2

AFFIDAVIT OF MARIO E. ALONSO 
AFFIDAVIT OF MARIO E. ALONSO 

I. BACKGROUND AND QUALIFICATIONS 

1. My name is Mario E. Alonso and I am the Vice President Strategic Development 

for Dynegy Inc. ("Dynegy"). I also am a member ofDynegy's Executive Management Team and 

am Vice President Strategic Development for Tllinois Power Holdings, LLC ("IPH"), a wholly 

owned, indirect subsidiary of Dynegy. My business address is 601 Travis Street, Suite 1400, 

Houston, Texas 77002. I provide this affidavit in support of the Petition for Variance filed by 

IPH, AmerenEnergy Medina Valley Cogen, L.L.C. ("Medina Valley"), and Ameren Energy 

Resources, LLC ("AER") ("Petition"). I make this affidavit based on personal knowledge or on 

knowledge I have obtained through inquiry of individuals employed by Dynegy or its affiliates. 

2. As Dynegy's Vice President Strategic Development, I am responsible for leading 

Dynegy's strategic planning and corporate deve1opment activities, including long-term strategic 

planning and mergers and acquisitions. Prior to taking on this role in July 2012, I served as 

Dynegy' s Treasurer from August 2011 to July 2012. I previously served as Vice President, 

Mergers and Acquisitions from 2008-201 1 and held various other key roles in Mergers and 

Acquisitions and Treasury at Dynegy from 2001 to 2008. Prior to joining Dynegy in 2001, I 

worked as an associate with Enron Corporation. I received my undergraduate business degree 

from the University of Virginia in 1993 with a major in finance. I received my MBA from the 

University of Virginia in 1999. 

3. I am familiar with the planned transaction between IPH and Ameren Corporation 

C'Ameren'} I have read and am familiar with the September 20, 2012 Opinion and Order by the 

Illinois Pollution Control Board (the "Board" or "IPCB"), PCB 12-126, granting AER variance 
relief from the sulfur dioxide ("S02") emission rates in the multi-pollutant standard ("MPS") rules 

applicable to the Ameren MPS Group. 

D. ILLINOIS POWER HOLDINGS, LLC 

4. TPH is a Delaware limited liability company owned directly by Illinois Power 

Holdings II, LLC, a Delaware limited liability company ("Holdi_ngs II"). Holdings II is a directly 

wholly owned subsidiary of Dynegy. IPH is a non-recourse entity formed with the purpose of 

acquiring the equity interest in Ameren's merchant utilities (as further discussed below), 

pursuant to the Transaction Agreement, dated March 14, 2013, between Ameren and IPH (the 

"Transaction Agreement"). As of the date of this affidavit, IPH does not own any assets or conduct 

any business in the state of illinois. 

5. No entity in Dynegy's corporate structure, outside of Holdings II and Dynegy, 

holds any direct or indirect interest in IPH and IPH maintains corporate separateness from 

Dynegy and Dynegy' s existing subsidiaries. A core pillar of the transaction is that the Acquired 

Merchant Utilities (as defined below) must be economically viable on their own and be 

independent, self-sustaining, self-funding businesses. Attached Affidavit Exhibit 1 is a 

simplified corporate organization diagram for Dynegy Inc. as would exist upon closing of the 

transaction, including IPH's position as a parent company of the Acquired Merchant Utilities. 

Each ofDynegy's subsidiaries is an independent legal entity with separate assets and liabilities. 

6. FoUowing closing under the Transaction Agreement, IPH will own all of 

Ameren's interest in Ameren Energy Generating Company ("GENCO", also referred to as 

··AEG"), AmerenEnergy Resources Generating Company ("AERG"), Arneren Energy Marketing 

Company ("Ameren Marketing"), Electric Energy, Inc. ("EEl"), and Midwest Electric Power, 

Inc. ("MEPI") (GENCO, AERG, Ameren Marketing, EEl, and MEPI, collectively, the 

2 
"Acquired Merchant Utilities"). IPH and each of the Acquired Merchant Utilities will maintain 

corporate separateness from all ofDynegy's current legal entities. 

III. THE ACQUISITION OF NEW AER 

7. The transaction between IPH and Ameren is functionally a straightforward sale of 

equity interests in the company owning the generating assets. At the closing of the transaction 

and after a reorganization of AER that, to IPH's understanding, Arneren intends to undertake 

prior to closing (the reorganized company is referred to in the Transaction Agreement as "New 

AER"), Ameren will transfer 100 percent of its equity interest in New AER to IPH with the 

result that IPH will acquire all of Ameren' s interests in the Acquired Merchant Utilities and the 

operating generating facilities they bold at closing, specifically the: (i) Coffeen Plant (located in 

Coffeen, Illinois), (ii) Duck Creek Plant (located in Canton, Illinois), (iii) E.D. Edwards Plant 

(located in Bartonville, Illinois), (iv) Newton Power Plant (located in Newton, Illinois), and (v) 

Joppa Generating Station (located in Joppa, Illinois) (collectively, the "Acquired Plants"). 

8. The closing of the transaction is expected to occur during the fourth quarter of 

2013. IPH' s obligation to close is subject to two specific conditions relevant to the Petition. The 

first is the transfer to IPH, or such other legally binding approval by the Board which has the 

effect of making applicable immediately after closing of the transaction to IPH, of the variance 

relief, Docket PCB 12-126, granted by the Board on September 20, 2012 to AER (the "Variance 

Relief') without material change. The second is the successful transfer of the Grand Tower, 

Gibson City and Elgin natural gas-fired energy centers (collectively, the "Put Assets") to 

Petitioner Medina Valley. IPH insisted its obligations to close the acquisition from Arneren be 

conditioned upon the applicability of variance relief after the transaction because the Acquired 

Plants will simply not be financially viable without the relief from the MPS rules applicable to 

3 
the Ameren MPS Group. If the variance relief from the MPS .rules requested in the Petition is 

not granted, and IPH nonetheless moves forward with the transaction, IPH's only option to 

comply with the MPS would be to shut down a combination of the Newton, E.D. Edwards and 

Joppa Energy Centers by January 1, 2015. In IPH's analysis, the E.D. Edwards and Joppa 

Energy Centers would be shut down by January 1, 2015. 

IV. WITHOUT THE REQUESTED VARIANCE RELIEF, COMPLIANCE WITH 

THE 2015 AND 2017 MPS OVERALL S02 ANNUAL EMISSION RATES 

WOULD IMPOSE AN UNREASONABLE SIGNIFICANT HARDSHIP ON IPH 

9. Compliance with the Ameren MPS Group Multi-Pollutant Standard rule's 2015 

and 201 7 overall S02 annual emission rates would impose an arbitrary and unreasonable 

hardship on IPH as the owner of the Acquired! Merchant Utilities. The hardship derives from 

two key factors: continuing significant federal regulatory uncertainty and historically depressed 

power prices. As a result of these intertwined factors, IPH and the Acquired Merchant Utilities 

will simply not be financially viable to comply with the MPS without the requested variance 

relief. 

10. First, USEPA has not announced formal plans or a timeline for developing a valid 

replacement rule for the Cross State Air Pollution Rule ("CSAPR"). While the United States 

Supreme Court recently decided to review the appellate court's decision vacating CSAPR, the 

future ofCSAPR remains uncertain. President Obama's recent announcement directing USEPA 

to develop carbon standards for existing power plants creates additional regulatory uncertainty 

for long-term planning involving the Acquired Merchant Utilities and the Acquired Plants. 

Importantly, in the absence of an effective federal S02 and NOx program that "levels the playing 

field" among competitors in the electric generation market, the Illinois-specific MPS 

4 
requirements continue to place the Acquired Merchant Utilities and the Acquired Plants at a 

competitive disadvantage with electric generators in nearby states that have not deregulated their 

energy markets (and, thus, in contrast to the Acquired Plants, are able to recover environmental 

costs through revenues from a captive rate base) and have not required electric generators to 

significantly reduce S02 and NOx emissions. 

11. Second, based on information provided by an independent third-party reporting 

service 1 and as shown in the table below, power prices remain depressed and are not expected to 

improve over the next several years. As a merchant generator, the source of revenues for IPH 

and the Acquired Merchant Utilities is the sale of electricity; thus, IPH and Acquired Merchant 

Utilities are largely dependent on the commodity price of electricity. The table below 

summarizes future expected natural gas and power prices as of late June 2013. The prices in the 

table below represent hub pricing for natural gas and power in the Midcontinent Independent 

System Operator ("MISO") region, where the Acquired Plants are located and sell almost all of 

their power.2 MISO participants include both regulated utilities and merchant generators. For 

purposes of comparison, in 2006-2007, the power price relevant to the Acquired Plants was 

approximately $60 per megawatt hour,3 and the natural gas price was approximately $6.70 per 

mmBtu.

4 The data clearly shows objective market expectations that for the next several years 

power prices will remain depressed and natural gas prices will remain at distressed levels. 

1 SunGard Kiodex LLC (Kiodex). Kiodex surveys a variety of market sources in creating its daily market 

assessments and, therefore, generates a reliable unbiased market expectation. 

2 ln table column "2013", June 28,2013 power prices represent the balance of2013 and June 28 gas prices include 

August to December 2013. Power prices are around the clock (A TC) prices. 

3 See AER v. JEPA, PCB 12-126, Opinion and Order, 61 (Sept. 20, 20 12). 

4 Average Chicago Citygate price over the 2006-2007 period, based on information reported by Platts Gas Daily. 

5 
MISO Gas Price 2013 2014 2015 2016 2017 

($/mmBtu) 

6/28/20 13 $3.70 $3.96 $4.17 $4.37 $4.61 

MISO Power Price 2013 2014 2015 2016 2017 

($!MWhr) 

6/28/2013 $3 1.85 $30.67 $3 1.78 $33.14 $34.47 

12. IPH has analyzed several financing alternatives, including self-funding, third 

party financing and financing through its parent company, Dynegy, in each case as described 

below. No viable funding mecharusm exists for IPH to complete the Newton flue gas 

desulfurization ("FGD, ) project or otherwise meet the MPS 2015 and 2017 compliance 

deadlines. 

13. IPH and the Acquired Merchant Utilities, as AER under Ameren, must be selffunding and support their own expenses through their own operating revenues. Under IPH, the 

Acquired Merchant Utilities will remain in the merchant power generation market without a rate 

base, meaning that environmental or other compliance costs cannot be recovered by rates from 

captive consumers. IPH and the Acquired Merchant Utilities will face significant exposure to 

market prices, swings in load demand, and commodity price volatility; and power prices remain 

at historically depressed levels. 

14. In acquiring New AER, IPH will inherit the near tenn balance sheet challenges 

currently faced by AER. In the first quarter of 2013, AER had a $151 million net income loss, 

which follows its $396 million net income loss in 2012.5 As stated in a recent Standard & Poor's 

update, GENCO, AER's largest subsidiary, "has less than adequate liquidity" and "poor standing 

s Dynegy Inc., Prospectus, SEC Form 4248(3) filed June 5, 2013, Annex A: Financial Statements Relating to AER. 

6 
in the credit markets".6 Notably, GENCO has approximately $825 million in long-term public 

bond debt outstanding, with approximately $300 million of this debt maturing in 2018 and $250 

million maturing in 2020. GENCO's existing debt requires approximately $59 million in annual 

interest payments. 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. After IPH 

acquires New AER and its subsidiary GENCO, GENCO will continue to be responsible for 

repayment of that $825 million debt, including the annual $59 million interest payment 

obligation. Given depressed power prices, GENCO's existing debt and the significant capital 

expenditure needed to complete the Newton FGDs, New AER will not have the financial 

resources or liquidity at closing to complete construction of the Newton FGDs to comply with 

the MPS rule's 2015 and 2017 system-wide S02 annual emission rate limits. 

15. Third party external financing also is not available to IPH or the Acquired 

Merchant Utilities. Neither IPH nor its subsidiaries will likely be able to access credit markets to 

obtain third-party financing due to the distressed power market in which the Acquired Merchant 

Utilities operate. Indeed, prior to entering the Transaction Agreement, Dynegy approached 

several financial institutions to inquire about the possibility of obtaining a credit facility to 

support the Acquired Plants once transferred to IPH. Given the low cash flow profile, negligible 

lien capacity of the assets, existing debt and weak credit profile of the Acquired Merchant 

Utilities, the financial institutions contacted replied that they would not extend a credit facility. 

In addition, because IPH, New AER and AERG (as with AER and AERO currently) will not be 

6 Standard & Poor's, Research Update: Ameren Energy Generating Co. Ratings Lowered to 'CCC+ ' On Weak 

Power Prices; Outlook Negative, at 2, 3 (Feb. 8, 2013). 

7 
publicly registered companies and will not be rated by the credit rating agencies, they will have 

limited financing options. 

16. Moreover, GENCO is currently prohibited by its debt covenants from obtaining 

external financing. While IPH generally would seek to refinance GENCO's existing $825 

million bond obligation 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. As GENCO disclosed in a recent filing 

with the U.S. Securities and Exchange Commission ("SEC"), during the first quarter of 2013, 

GENCO's interest coverage ratio fell to a level less than the specified minimum level required 

for external borrowings. Further, as also disclosed in GENCO's SEC filing, due to the decline in 

GENCO's earnings and operating cash flow·s resulting from depressed power prices, GENCO's 

interest coverage ratio is expected to remain less than this minimum level through at least 2015. 

As a result, GENCO's ability to borrow additional funds from external, third-party sources is 

restricted. Moreover, given GENCO's poor financial health, even after GENCO regains the 

ability under its existing debt agreements to borrow external funds, refinancing may not be 

possible as a practical matter due to the onerous terms that likely would be imposed by external 

lenders. 

17. Finally, credit pressures prevent Dynegy from financially supporting IPH and the 

Acquired Merchant Utilities. As part of its diligence process prior to entering the Transaction 

Agreement, Dynegy contacted the credit rating agencies (Moody's and Standard & Poor's) to 

understand the transaction's implications, if any, on Dynegy's credit rating. Both credit rating 

8 
agencies agreed that, as structured, the transaction was a credit neutral event because of the nonrecourse nature of IPH. However, the credit rating agencies made clear that the transaction 

would have a negative effect on the credit rating of Dynegy if the acquired entities were to be 

absorbed into the Dynegy capital structure or if Dynegy were to provide financial support to the 

Acquired Merchant Utilities other than limited amounts of working capital. 

18. A downgrade in Dynegy's credit rating would mean less favorable terms and 

conditions for Dynegy's financing (e.g., increased interest rates for borrowing, more restrictive 

covenants) and loss of investor confidence, ultimately jeopardizing Dynegy's balance sheet and 

liquidity. In fact, Dynegy very recently completed a refinancing, in which Dynegy made clear to 

the rating agencies and equity and debt investors that IPH would be non-recourse to the Dynegy 

balance sheet. Today, Dynegy is recognized as having a good balance sheet within the industry 

and, thus, is able to obtain the benefits of this, as demonstrated by the recent favorable 

refinancing. Simply stated, Dynegy will not -- and, in effect, cannot -- endanger its balance sheet 

or its credit rating by integrating IPH and the Acquired Merchant Utilities into the Dynegy 

capital structure. Thus, Dynegy has publicly communicated to investors that the Acquired 

Merchant Utilities must stand on their own fmancially. Confidence from its investor base (both 

debt and equity) is key to Dynegy's future success and Dynegy cannot, without jeopardizing 

Dynegy's financial future, backtrack on its commitment to the non-recourse nature of IPH, 

particularly in the context that Dynegy emerged from bankruptcy in late 2012 through which it 

was able to restructure its balance sheet. 

19. While Dynegy's new refinancing agreement would allow Dynegy to make certain 

investments in its subsidiaries, including IPH, Dynegy cannot invest funds under the refinancing 

9 
agreement in IPH without risking its credit rating. Nor could Dynegy invest funds under the 

refinancing agreement in IPH without risking its credibility with investors. Moreover, because 

Dynegy must balance the investment needs of all of its current and future subsidiaries, Dynegy 

could not commit funds under the refmancing agreement to the extent needed to complete the 

Newton FGDs, even if doing so would not imperil Dynegy's credit rating and credibiljty. 

20. Upon closing of the transaction, IPH and the Acquired Merchant Utilities will not 

have sufficient liquidity to fund the immediate or accelerated installation of the Newton FGD 

project or other large environmental capital projects. At closing, IPH, New AER and its 

consolidated subsidiaries will have approximate ly $220 million in cash, 7 of which $203 million 

will be at GENCO and approximately $17 million at AERG/Ameren Marketing. Depending on 

the results of the sale process of the Put Assets, the total cash figure at closing for GENCO could 

be higher. However, depending largely on volatile commodity markets, the majority of this 

approximate $220 million in cash available at c losing will be utilized over the next several years 

to fund operations/potential losses, pay interest, and provide some working capital and credit 

support. Moreover, in two years when Ameren' s obligation under the Transaction Agreement to 

provide credit support to New AER terminates, New AER will need to replace its credit support, 

which may be a significant amount. In fact, if the existing credit support were to be replaced 

today, a substantial amount of the $220 million in cash available at closing would be used up. 

21. While the exercise of the put option has infused additional capital into GENCO, 

the proceeds from exercising the put option (a minimum of $133 million) are part of the 

approximately $220 million in cash that New AER and its subsidiaries will have at closing. 

7 The approximate nature of the $220 million amount reflects uncertainty regarding certain real estate sales. 

Depending on the outcome of those real estate sales, the cash at closing may be up to approximately $226 million. 

10 
However, as explained above, this cash is needed to fund operations/losses and pay interest at 

GENCO over the next several years, and there are no excess funds to accelerate installation of 

the Newton FGD project or make any other MPS compliance alternatives feasible. In addition, 

this cash would also be used for purposes of replacing New AER's credit support in two years. 

22. At closing, New AER and its consolidated subsidiaries also will have 

approximately $160 million in net working capital. This does not, however, mean that the 

Acquired Merchant Utilities will have an incremental $160 million of liquidity to spend above 

the approximate $220 million in cash available at closing. This $160 million of net working 

capital is tied up in the business as the typical capital required to simply run the business day to 

day and maintain appropriate fuel (coal) inventory and materials/supplies (e.g., spare parts). In 

fact, the majority of this $160 million net working capital is for maintaining adequate levels of 

fuel inventory and materials/supplies. 

23. Importantly, IPH expects that the gradual recovery of power prices (anticipated to 

begin after April 20 15) will provide New AER with sufficient cash t1ow and liquidity to 

complete construction of the Newton FGDs by year end 2019. Dynegy has made clear in its 

public statements that it believes power prices will begin to recover when compliance with the 

federal Mercury and Air Toxics Standards ("MATS") tightens supply as environmentally 

noncompliant or uneconomic generation units in the Midwest continue to retire. The MATS 

compliance deadline is April 16, 20 15, but the rule allows electricity generating units to obtain 

one-year, and in some cases two-year, extensions of the compliance deadline. 

24. As publicly stated, Dynegy expects New AER will not generate free cash t1ow 

until 2015. However, free cash flow in 2015 by New AER does not mean that New AER would 

have sufficient liquidity or financial resources in 2015 to spend the significant capital needed to 

II 
complete construction of the Newton FGDs or otherwise comply with the MPS. The recovery of 

power prices will not be immediate in 2015, nor will market recovery in 2015 be sufficient to 

generate the cash flow and liquidity needed to accelerate completion of the Newton FGDs in 

time to meet the 2017 MPS overall S02 annual emission limit. Rather, IPH expects the recovery 

of power prices and associated generation of positive cash flows to occur gradually over time. 

Thus, the five-year term of the requested variance is critical to allowing adequate time for both 

recovery of power prices and New AER and its subsidiaries to accumulate the significant 

financial resources needed to fund completion of the Newton FGDs, while at same time meeting 

their existing debt obligations, operating costs and credit support requirements. 

25. In evaluating the contemplated transaction, Dynegy's position has always been 

that, given the depressed commodity markets and volatile nature of the merchant energy 

business, at the closing of the transaction, New AER must have sufficient liquidity for the next 

several years to meet its needs of funding operations/potential losses, paying interest, and 

providing some working capital and credit support. Furthermore, without the approximate $60 

million in annual operational synergies that Dynegy estimates it will realize in this transaction by 

2015, the approximate $220 million in cash at closing would not be sufficient to fund operations 

over the next several years. Those synergies will result from gross margin and cost 

improvements at New AER based on the successful implementation of Dynegy programs 

addressing, among others, reduction in forced outage rates to improve in-market availability, fuel 

and rail procurement practices, vendor optimization, and the combination of Dynegy's 

engineering, maintenance, and outage planning expertise. Implementation of Dynegy's PRIDE 

initiative (Producing Results through Innovation by Dynegy Employees) at New AER is also 

12 
expected to result in significant margin and cost improvements, as it has at Dynegy over the past 

two years, by continuously improving performance wherever possible based on the advice of our 

employees, the experts who see these opportunities first-hand. Both the upfront cash at closing 

and the synergies are required to provide comfort that the business will have the necessary 

liquidity over the next several years, particularly given the volatile nature of the markets. Simply 

stated, it is not feasible over the next several years to simultaneously have adequate liquidity 

necessary to continue operating the Acquired Plants and also spend hundreds of millions on 

capital investments to accelerate installation of the Newton FGD project, install alternative air 

pollution controls or otherwise comply with the MPS without the requested variance relief. 

Consistent with Dynegy's need to protect its credit rating and the commitments Dynegy has 

made to the credit rating agencies, as well as to Dynegy's creditors and investors, that IPH would 

not be integrated into Dynegy's capital structure, financial support from Dynegy to IPH, if any, 

will be limited in amount and targeted only to providing necessary working capital support. This 

limited support will not be for the purposes of making capital investments at the Acquired Plants 

(e.g , pollution controls, equipment replacements) and, in any event, would only be a small 

fraction of the significant capital needed for a large scale capital project such as the Newton FGD 

project. As part of the Transaction Agreement, Dynegy also has provided a $25 million 

guarantee to Ameren for two years after closing for certain pre-closing payments of IPH and 

certain post-closing indemnification and reimbursement obligations of IPH. That guarantee is 

not available for making capital investments at the Acquired Plants and, again, in any event 

would not be sufficient to fund completion of the Newton FGD project. 

13 
26. Finally, as solely a merchant generation company without any regulated ratebased subsidiaries, Dynegy has had to face several years of economic challenges caused by 

depressed power pricing and a weakened national economy. Dynegy filed for Chapter 11 

bankruptcy protection in July 2012 and, while successfully emerging from bankruptcy in 

October 2012, Dynegy continues to face near-term economic challenges posed by depressed 

power prices. For example, Dynegy reported operating losses of $104 million for the fourth 

quarter of 2012 and $142 million for the first quarter of 2013. Thus, in a very real sense, while 

Dynegy expects power pricing and market conditions to improve gradually over the longer-term 

beginning in 2015, Dynegy is not a "deep pocket" with limitless funds that could now or in the 

next several years be made available to IPH to complete construction of the Newton FGDs. 

27. In short, at closing, IPH and the Acquired Merchant Utilities are expected to have 

sufficient liquidity and collateral support to meet expected operating obligations, including 

sufficient funds to continue construction of the Newton FGD project in accordance with the 

schedule in the requested variance relief, as well as to maximize the existing FGD systems at 

Duck Creek and Coffeen and utilize low sulfur coal at the other Acquired Plants. IPH and the 

Acquired Merchant Utilities will not, however, have sufficient funds to meet the MPS 

requirements without the requested variance relief or to accelerate installation of the Newton 

FGD project. 

14 
V. CONCLUSION 

28. I have read the Petition and the facts stated therein with regard to subject matters 

of this affidavit are true and correct to the best of my knowledge and belief. 

FURTHER, Affiant sayeth not. 

DATED:~ It ;).1)/3 

Subscribed and swore to before me 

this rct ay of July, 2013 

Notary 

~;3 Public {[~ 

Mario E. Alonso 

15 
EXHIBIT 3

MAP DEPICTING LOCATIONS OF ENERGY CENTERS AND IPEA AIR QUALITY 

MONITORING STATIONS 

Illinois Environmental Protection Agency, Illinois Annual Air Quality Report (2011) (including 

map depicting Agency air quality monitoring stations with the locations of the Ameren MPS 

Group superimposed). 
State of Illinois

Illinois Environmental Protection Agency

November 2012

Annual Air Quality Report

Illinois



2011
 

 

ILLINOIS ANNUAL 

AIR QUALITY REPORT 

2011

Illinois Environmental Protection Agency 

Bureau of Air 

1021 North Grand Avenue, East 

P.O. Box 19276 

Springfield, IL 62794-9276 

Printed on recycled paper 
ix

2011

EXECUTIVE SUMMARY 

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

the calendar year - 2011. Data is presented for the six criteria pollutants (those for which air quality 

standards have been developed - particulate matter (PM10 and PM2.5), ozone, sulfur dioxide, 

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

volatile organic and toxic compounds. Monitoring was conducted at 75 different site locations 

collecting data from more than 170 instruments. 

In terms of the Air Quality Index (AQI) air quality during 2011 was either good or moderate 92

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

was considered Unhealthy (category Red). This compares with zero Unhealthy days in 2010. 

There were 31 days (25 for 8-hour ozone, 4 for PM2.5 and 2 for both 8-hour ozone and PM2.5) when 

air quality in some part of Illinois was considered Unhealthy for Sensitive Groups (category 

Orange). This compares with 32 Unhealthy for Sensitive Groups days reported in 2010. Air quality 

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

the level of the standards. Percentage changes over the ten year period 2002 – 2011 are as follows: 

24-hour Particulate Matter (PM10) 15 percent decrease, annual Particulate Matter (PM2.5) 20 percent 

decrease, 1-hour Sulfur Dioxide 47 percent decrease, annual Nitrogen Dioxide 29 percent decrease, 

8-hour Carbon Monoxide 48 percent decrease, Lead 33 percent decrease, and 8-hour Ozone 5 

percent decrease. 

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

information contained in the Emission Inventory System (EIS) as of December 31, 2011. Emission 

estimates are for the calendar year 2011 and are for the pollutants: particulate matter, volatile 

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

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

Emissions Report have been provided starting with 1998 and are currently available through 2010. 

In general there has been a trend toward decreasing emissions over this time period. 
Illinois Annual Air Quality Report 2011 Section 2: Statewide Summary of Air Quality for 2011 

9

SECTION 2: STATEWIDE SUMMARY OF AIR QUALITY FOR 2011 

OZONE 

Monitoring was conducted at 34 locations 

during at least part of the April-October 

"ozone season" and at least 75 percent data 

capture was obtained at 34 sites. 

Two sites recorded hourly concentrations 

above the former 0.12 parts per million (ppm) 

1-hour standard. University of Chicago 

recorded the highest 1-hour concentration of 

0.139 ppm followed by Zion with a 

concentration of 0.126 ppm. This compares 

with the highest concentration of 0.100 ppm 

in 2010 at both Lemont and Zion. The highest 

value in the St. Louis Metro East area was 

0.109 ppm recorded at Jerseyville compared 

with a high in 2010 of 0.115 ppm at East St. 

Louis. 

Data is also presented to compare with the 8-

hour standard of 0.075 ppm. The appropriate 

statistic for comparison with the 8-hour 

standard is the fourth highest value, which is 

averaged over a three year period. There 

were 11 sites in Illinois that had a fourth high 

value above 0.075 ppm in 2011 compared 

with two sites in 2010. The highest fourth 

high value was 0.081 ppm at both Maryville 

and Wood River. The highest level in the 

Chicago area was 0.079 ppm at the South 

Water Filtration Plant. For the three year 

period 2009 – 2011, two sites had a fourth 

high average above 0.075 ppm (Table B4). 

Figure 1 shows for each year the statewide 

average of each site’s highest hourly ozone 

value for the ten year period 2002-2011. The 

graph shows some year-to-year fluctuation 

with high years in 2002 and 2005 and low 

years in 2004, 2008 and 2009. The statewide 

average for 2011 was 0.097 ppm compared 

with 0.087 ppm in 2010 and 0.082 ppm in 

2009.

Statewide, the total number of 1-hour 

excursion days in 2011 was two compared 

with zero in 2010 and zero in 2009. 

Figure 2 shows for each year the statewide 

average of the 4th highest 8-hour ozone value 

for the same period 2002-2011. The 

statewide average for 2011 was 0.082 ppm 

0.05

0.075

0.1

0.125

02 03 04 05 06 07 08 09 10 11

Year

Figure 1

Average 1-Hour Ozone Maximum (ppm)

0.05

0.06

0.07

0.08

0.09

0.1

02 03 04 05 06 07 08 09 10 11

Year

Figure 2

Average 8-Hour Ozone 4th High (ppm)
Illinois Annual Air Quality Report 2011 Section 2: Statewide Summary of Air Quality for 2011 

10

compared with 0.069 ppm in 2010 and 0.064 

in 2009. 

Overall, Illinois’ weather was much above 

normal in terms of meteorological conditions 

favorable to ozone formation and transport 

statewide. 

July was the most conducive month in terms 

of meteorological conditions statewide. In 

terms of conducive days, the Chicago area 

and the Metro-East area both had much above 

average numbers. 

PARTICULATE MATTER 

Monitoring was conducted at 34 sites for 

PM2.5. Valid annual averages were obtained 

for 32 of the 34 sites. No sites recorded an 

average above 15.0 ug/m3, the level of the 

annual standard, compared with zero sites in 

2010 and zero sites in 2009. The Statewide 

average of the annual averages was 11.2 

ug/m3in 2011 compared with 11.6 ug/m3 in 

2010 and 10.6 ug/m3 in 2009. Figure 3 shows 

the trend of the Statewide annual averages for 

PM2.5 for the period 2002-2011. There were 6 

exceedances of the 24-hour standard of 35 

ug/m3 in 2011 compared with 31 exceedances 

in 2010. The Statewide peak of 39.9 ug/m3

was recorded at Chicago Mayfair Pump 

Station. The Statewide average of the 98th 

percentile of 24-hour averages was 25.5 

ug/m3in 2011 compared with 26.9 ug/m3 in 

2010 and 24.3 ug/m3in 2009. 

In 2011 there were 5 sites monitoring PM10.

The Statewide annual average was 23 ug/m3

compared with 23 ug/m3in 2010 and 20 

ug/m3in 2009.

For PM10 the Statewide average of the 

maximum 24-hour averages in 2011 was 69 

ug/m3 compared with 62 ug/m3 in 2010 and 

56 ug/m3 in 2009. Figure 4 depicts this trend 

for the period 2002-2011.

No sites exceeded the former primary annual 

standard of 50 ug/m3. The highest annual 

average was 31 ug/m3 in Granite City. The 

lowest annual was 13 ug/m3 in Northbrook. 

There were no exceedances of the 24-hour 

primary standard of 150 ug/m3. The highest 

24-hour average was recorded in Lyons 

Township with a value of 92 ug/m3compared 

with a high 24-hour value of 106 ug/m3in 

Granite City in 2010. 

0

5

10

15

20

02 03 04 05 06 07 08 09 10 11

Year

Figure 3

Particulate Matter (PM2.5) Annual Trends 

(ug/m3)

0

50

100

02 03 04 05 06 07 08 09 10 11

Year

Figure 4

Particulate Matter (PM10) 24-Hour Trends 

(ug/m3)
Illinois Annual Air Quality Report 2011 Section 2: Statewide Summary of Air Quality for 2011 

11

CARBON MONOXIDE 

There were no exceedances of either the 1-

hour primary standard of 35 ppm or the 8-

hour primary standard of 9 ppm in 2011. The 

highest 1-hour average was 3.3 ppm recorded 

at Chicago Transit Authority. The highest 8-

hour average was 2.0 ppm recorded in 

Maywood and Peoria. 

Figure 5 shows the trend for the period 2002-

2011 for the statewide average of the 1-hour 

and 8-hour high CO values. The overall trend 

for both averages is downward. The statewide 

average of the 1-hour high was 2.3 ppm in 

2011 compared with 2.5 ppm in 2010. The 

statewide average for the 8-hour high was 1.5 

ppm in 2011 compared with 1.5 ppm in 2010. 

SULFUR DIOXIDE 

There were 42 exceedances of the new 1-hour 

primary standard of 75 ppb in 2011 compared 

with 50 exceedances in 2010. There were no 

exceedances of the 3-hour secondary standard 

of 500 ppb in 2011. The annual and 24-hour 

primary standards were revoked by USEPA in 

2010. The highest 1-hour average was 262 

ppb recorded in Pekin compared with 331 ppb 

in Pekin in 2010. The statewide average of the 

1-hour high in 2011 was 63 ppb. This 

compares with 75 ppb in 2010 and 81 ppb in 

2009. The highest 3-hour average of 176 ppb 

was recorded in Pekin in 2011 compared with 

223 ppb in Pekin in 2010. There were two 

sites over the primary 1-hr standard of 75 ppb 

for the 2009-2011 period compared to four 

sites for the 2008-2010 period (Table B17). 

Figure 6 shows the statewide trend for the 

maximum 24-hour averages for the period 

2002-2011. The 24-hour average trend has 

been overall downward; however a greater 

degree of year-to-year fluctuations have 

occurred. The statewide average for 2011 

was 15 ppb compared with the 2010 average 

of 15 ppb. Statewide 1-hour average 

maximums have also declined. The 2011 

average was 63 ppb compared to 75 ppb in 

2010.

0

2

4

6

02 03 04 05 06 07 08 09 10 11

Year

Figure 5

Carbon Monoxide Trends (ppm)

1-hr

8-hr

0

10

20

30

40

50

02 03 04 05 06 07 08 09 10 11

Year

Figure 6

Sulfur Dioxide 24-Hour Trends

(ppb)
Illinois Annual Air Quality Report 2011 Section 2: Statewide Summary of Air Quality for 2011 

12

NITROGEN DIOXIDE 

There were no violations of the annual 

primary standard of 53 ppb recorded in 

Illinois during 2011. The highest annual 

average of 23 ppb was recorded at Schiller 

Park. The Statewide average for 2011 was 16 

ppb compared with 18 ppb in 2010 and 19 

ppb in 2009. There were no violations of the 

new 1-hour primary standard in 2011 as well. 

This compares to zero violations in 2010. 

There were no sites over the 1-hour primary 

standard of 100 ppb for the 2009-2011 period 

compared to zero sites for the 2008-2010 

period (Table B20). 

One site operated only during part of the 

ozone season as PAMS. Figure 7 depicts the 

trend of statewide averages from 2002-2011. 

The trend has been generally stable for the 

period ranging from 16 ppb to 24 ppb. There 

have been no violations of the annual standard 

since 1980. 

LEAD

Perhaps the greatest success story in 

controlling criteria pollutants is lead. As a 

direct result of the Federal Motor Vehicle 

Control Program which has required the use 

of unleaded gas in automobiles since 1975, 

lead levels have decreased by more than 90 

percent statewide. Based on new health 

studies the lead standard was revised in 2008 

from a quarterly mean of 1.5 ug/m3 to a 

rolling 3-month maximum mean of 0.15 

ug/m3.

There were no violations of the former 

quarterly lead standard of 1.5 ug/m3. There 

were three violations of the new rolling 3-

month maximum mean standard for the 2009 

to 2011 period. Violoations were recorded at 

Granite City - 15th & Madison with a value of 

0.42 ug/m3, Chicago Perez with a value of 

0.29 ug/m3 and Decatur Mueller with a value 

of 0.20 ug/m3. This compares with a 

statewide high of 0.42 ug/m3for 2008 to 2010 

at Granite City 15th & Madison. 

Figure 8 shows the trend of the statewide 

non-source maximum monthly averages from 

2002-2011. The chart shows a general flat 

trend of ambient lead levels over the last 

several years. In 2010, several source 

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

not enough data exists for the source oriented 

sites to establish a trend. However, the 

statewide average for all sites was 0.08 ug/m3

in 2011 compared to 0.12 ug/m3

in 2010. 

0

5

10

15

20

25

30

02 03 04 05 06 07 08 09 10 11

Year

Figure 7

Nitrogen Dioxide Annual Trend

(ppm)

0

0.01

0.02

0.03

0.04

0.05

0.06

02 03 04 05 06 07 08 09 10 11

Year

Figure 8

Lead Maximum 3-Month Trend (ug/m3)
Illinois Annual Air Quality Report 2011 Section 2: Statewide Summary of Air Quality for 2011 

13

FILTER ANALYSIS RESULTS 

The TSP samples analyzed, in addition to 

lead, for specific metals, sulfates and nitrates. 

Several of the metals analyzed (arsenic, 

beryllium, cadmium, chromium, manganese, 

and nickel) have known toxic properties. 

Other metals such as iron can be used as 

tracers to help identify sources of high 

particulate values. Sulfates and nitrates are 

precursors of acid precipitation/deposition 

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

constituents of the PM2.5 values. There are 

currently no State or Federal ambient air 

quality standards for these parameters. 

The areas with the highest metals 

concentrations in Illinois are generally the 

heavy industrialized areas of the Metro-East 

(Granite City and East St. Louis) and South 

Chicago, especially for iron and manganese. 

The highest 24-hour average for arsenic was 

0.464 ug/m3 measured in Granite City. The 

highest annual average of 0.011 ug/m3 was 

also recorded at Granite City. There were no 

measurable beryllium 24-hour averages 

recorded statewide. Chicago Perez recorded 

the highest cadmium concentrations with a 

maximum 24-hour average of 0.022 ug/m3.

The highest annual average of 0.002 ug/m3

was also recorded at Chicago - Washington. 

The highest 24-hour chromium average was 

0.092 ug/m3 recorded at Maywood. Maywood 

had the highest annual average at 0.023 

ug/m3. The highest iron and manganese 

values were recorded in South Chicago and 

the high traffic areas of Maywood. The 

highest 24-hour average for nickel was 

recorded at Maywood with a value of 0.016 

ug/m3. The highest annual average was in 

Maywood with an average of 0.008 ug/m3. 

For nitrates, the highest 24-hour average was 

34.0 ug/m3 recorded at Chicago - 

Washington. The highest annual average was 

4.1 ug/m3 recorded at Maywood, Cermak and 

Chicago – Washington. For sulfates, the 

highest 24-hour average was 17.7 ug/m3

recorded at Maywood. The highest annual 

average was 7.5 ug/m3at Chicago - 

Washington. In general, metals, nitrate and 

sulfate values were slightly higher in 2011

than in 2010.

TOXIC COMPOUNDS 

Sampling for toxic compounds other than 

metals (see Filter Analysis Section) was 

conducted at Northbrook and Schiller Park. 

Most compounds were below the method 

detection limits. The highest compounds 

were toluene, mercury, benzene, acrolein and 

formaldehyde. 

PM2.5 SPECIATION 

PM2.5 samples are also analyzed for numerous 

constituents at 5 sites. The major constituents 

(inorganic elements, ammonium, nitrate, 

sulfate, elemental and organic carbon) are 

listed in Table B26. In general, 

approximately 62% is ammonium nitrate and 

ammonium sulfate, 32% is elemental and 

organic carbon and 6% is inorganic elements. 
34

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Statewide Air Monitoring Site Locations

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LEE

PIKE

WILL

COOK

OGLE

MCLEAN

LASALLE

KNOX

HENRY

ADAMS

IROQUOIS

FULTON

BUREAU

WAYNE

SHELBY

KANE

FORD

EDGAR

CLAY

LAKE

LOGAN

PEORIA

LIVINGSTON

FAYETTE

CHAMPAIGN

HANCOCK

MACOUPIN

PIATT

COLES

VERMILION

MADISON

MACON

DEKALB

WHITE

MASON

CASS

POPE

SANGAMON

CLARK

ST. CLAIR

JASPER

MARION

PERRY

GREENE

MERCER

BOND

JACKSON

CHRISTIAN

UNION

MORGAN

WARREN

WHITESIDE

TAZEWELL

MCHENRY

KANKAKEE

CLINTON

JO DAVIESS

RANDOLPH

SALINE

JEFFERSON

JERSEY

DEWITT

GRUNDY

CARROLL

MONTGOMERY

WOODFORD

MONROE

STARK

MCDONOUGH

STEPHENSON

DOUGLAS

FRANKLIN

DUPAGE

WASHINGTON

SCHUYLER

BROWN

EFFINGHAM

CRAWFORD

SCOTT

JOHNSON

MENARD

MARSHALL

RICHLAND

WILLIAMSON

LAWRENCE

KENDALL

ROCK ISLAND

PULASKI MASSAC

HARDIN

PUTNAM

WINNEBAGO

HAMILTON

BOONE

MOULTRIE

GALLATIN

HENDERSON

CALHOUN

WABASH

CUMBERLAND

EDWARDS

ALEXANDER

5554

ID NAME XCO O RD YCO O RD AQ S CO DE

1 Quincy John Wood Community College 642227.44 4419695.50 170010007

2 Champaign 394297.22 4442244.68 170190006

3 Thomasboro 398939.77 4455622.22 170190007

4 Bondville SWS Climate Station 382927.63 4434458.00 170191001

5 Alsip Village Garage 439028.14 4613506.98 170310001

6 Chicago Washington H.S. 455116.70 4615183.98 170310022

7 Chicago Cermak Pump Station 446450.82 4635956.70 170310026

8 Chicago South Water Filtration Plant 454702.37 4622802.04 170310032

9 Chicago Mayfair Pump Station 437859.32 4646216.44 170310052

1 0 Chicago Springfield Pump Station 440063.88 4640354.22 170310057

1 1 Chicago CTA Building 447307.81 4636384.48 170310063

1 2 Chicago University of Chicago 450011.00 4626726.33 170310064

1 3 Chicago Jardine Water Plant 449590.78 4638386.72 170310072

1 4 Chicago Comm ED 440680.96 4622421.39 170310075

1 5 Perez Elementary School 445348.00 4633988.00 170310110

1 6 Chicago Taft H.S. 434390.00 4648367.48 170311003

1 7 Lyons Township Village Hall 430877.97 4628036.70 170311016

1 8 Lemont IEPA Trailer 417538.46 4613403.03 170311601

1 9 Blue Island Eisenhower H.S. 442015.58 4612496.03 170312001

2 0 Schiller Park IEPA Trailer 427390.48 4646283.31 170313103

2 1 Summit Graves Elementary School 433134.91 4626002.30 170313301

2 2 Cicero IEPA Trailer 437539.20 4633977.22 170314002

2 3 Des Plaines Regional Office Building 428543.56 4656797.86 170314007

2 4 Northbrook Water Plant 433953.24 4665668.78 170314201

2 5 Maywood 1500 Maybrook Drive Platform 431442.48 4635917.35 170316003

2 6 Maywood Comm ED Maintenance 431199.07 4635910.07 170316004

2 7 Cicero Liberty School 437852.27 4634984.05 170316005

2 8 Maywood 4th District Court Building 431466.96 4635994.08 170316006

2 9 Evanston Water Pumping Station 444223.82 4656857.88 170317002

3 0 Naperville City Hall 404209.07 4625007.66 170434002

3 1 Lisle Morton Arboretum 410890.26 4629582.92 170436001

3 2 Effingham Central Junior H.S. 366000.19 4325369.00 170491001

3 3 Knight Prairie Township 357489.72 4216177.00 170650002

3 4 Jerseyville Illini Junior H.S. 731349.00 4332451.50 170831001

3 5 Elgin McKinley School 394074.74 4656164.53 170890003

3 6 Elgin Larsen Junior H.S. 394651.06 4656017.29 170890005

3 7 Aurora Health Department 389528.14 4626729.16 170890007

3 8 Zion Camp Logan 433408.66 4702013.37 170971007

3 9 Oglesby IEPA Trailer 328401.31 4573311.00 170990007

4 0 Cary Grove H.S. 397480.49 4675110.16 171110001

4 1 Normal ISU Physical Plant 330837.53 4487250.50 171132003

4 2 Decatur IEPA Trailer 335319.94 4414769.00 171150013

4 3 Decatur Mueller 333988.00 4414303.00 171150110

4 4 Nilwood IEPA Trailer 258043.88 4364498.50 171170002

4 5 Alton Clara Barton Elementary School 747358.56 4308458.00 171190008

4 6 Granite City Air Products 747522.88 4286713.50 171190010

4 7 Granite City Gateway Medical 748300.44 4287426.50 171190024

4 8 Granite City Fire Station 1 748727.63 4287873.00 171191007

4 9 Maryville Southwest Cable TV 242682.59 4290595.00 171191009

5 0 South Roxana Grade School 755353.88 4301836.50 171191010

5 1 Edwardsville RAPS Trailer 757101.44 4298007.00 171192007

5 2 Alton SIU Dental Clinic 747734.94 4309900.00 171192009

5 3 Wood River Water Treatment Plant 751122.13 4305295.00 171193007

5 4 Peoria Fire Station 8 279707.38 4507329.50 171430024

5 5 Peoria Commercial Building 279203.50 4508748.50 171430036

5 6 Peoria City Office Building 281616.22 4508336.50 171430037

5 7 Bartonville Pump Station 276515.00 4503674.00 171430110

5 8 Mapleton Caterpillar Plant 267429.00 4493834.00 171430210

5 9 Peoria Heights H.S. 281679.94 4513723.50 171431001

6 0 Houston Baldwin Site 2 - IEPA Trailer 255745.52 4229049.50 171570001

6 1 Rock Island Arsenal 707169.75 4598886.00 171613002

6 2 East St. Louis RAPS Trailer 747238.69 4277551.00 171630010

6 3 Springfield Sewage Treatment Plant 278158.03 4408840.50 171670006

6 4 Springfield Federal Building 273312.59 4408832.50 171670008

6 5 Springfield Illinois Agriculture Building 273728.00 4412449.00 171670012

6 6 Springfield Illinois Building 274003.78 4412395.53 171670014

6 7 Pekin Fire Station 3 275274.31 4492892.00 171790004

6 8 Mount Carmel Division Street 432441.06 4250177.00 171850001

6 9 Sterling Sauk Medical Clinic 275084.00 4629822.00 171950110

7 0 Joliet Pershing Elementary School 406854.40 4597853.20 171971002

7 1 Braidwood Comm ED Maintenance 400173.37 4564033.85 171971011

7 2 Rockford City Hall 327811.72 4681606.50 172010011

7 3 Rockford Winnebago County Health Department 327392.16 4681107.00 172010013

7 4 Rockford J. Rubin and Company 327440.00 4678637.00 172010110

7 5 Loves Park Maple Elementary School 332121.41 4688981.00 172012003
EXHIBIT 4

USEPA DOCKET QA-OAR-2012-0233 

Ameren Comment in Docket QA-OAR-2012-0233 
~ WAmeren Ameren Services 

::::::::::::::::::::::::;::::::::::::::;::::::::::::::::::::::::;:::::::::::::::::::::::::::::::::::::::::;::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: 

March 15, 2013 

United States Environmental Protection Agency 

Air Docket 

Attention Docket ID No. EPA-HQ-OAR-2012-0233 

Mail Code 6102T 

1200 Pennsylvania Ave., NW 

Washington, DC 20460 

Dear Sirs, 

Ameren appreciates the opportunity to comment on the US EPA recommendations for the Pekin, IL S02 

nonattainment area. Ameren Corporation ("Ameren") is based in St. Louis, MO, and through its operating 

companies serves 2.4 million electric and nearly one million natural gas customers across a 64,000-square-mile 

area in Illinois and Missouri. Ameren companies' net generating capacity is more than 16,400 megawatts. Our 

power plants use a variety of fuels to generate electricity-principally coal, nuclear, hydro and natural gas. 

Specifically Ameren disagrees with the inclusion of the Hollis Township in Peoria County to the Pekin, IL S02 

non-attainment area for the following reasons: 

1) The Pekin area map displayed in Figure 2 of the Illinois EPA's technical support documene shows that 

the Hollis Township (in particular the Ameren Edwards Energy Center) is located almost directly north 

of the exceeding Pekin S02 monitor. Figure 3 in that same document shows the wind rose for the 

nearby Peoria Regional Airport. This figure indicates that winds from the north account for less than 5% 

of total direction occurrences. US EPA makes the following statement in their response to the Illinois 

technical support document: 

"The wind rose provided by Illinois suggests that winds come most frequently from the south, 

and somewhat frequently from the northwest, but winds come from all directions with sufficient 

frequency to suggest that meteorology is not a significant factor in defining this nonattainment 

area."

2 

This statement is misleading. With such a low percentage of winds from the north the probability of 

facilities located north of the exceeding monitor having a significant impact is expected to be low. 

2) Figure 4 of the Illinois technical support document1 shows the pollution rose for the years 2008-2010. 

This figure shows that over 90% of the occurrences of hours with S02 > 75 ppb occurred for wind 

directions from the West to Southwest. The remaining hours with S02 > 75 ppb occurred for wind 

directions from the East to South-Southwest. Figure 1 below and Attachment I shows a more detailed 

picture of this pollutant rose.

3 This figure uses data from the Tazewell county S02 monitor and 

meteorology from the Greater Peoria Regional Airport (see Attachment 1). The enhanced pollutant rose 

1 Technical Support Document: Recommended AttainmenVNonattainment Designations in Illinois for the 201 0 Revised Primary 1-Hour S02 

National Ambient Air Quality Standard (AQPSTR 11-02); June 2, 2011 

2 Draft Technical Support Document Illinois Area Designations For the 2010 S02 Primary National Ambient Air Quality Standard; US EPA 

February 2013. 3 See references in Attachment I for data sources 

·~·····~·~······ ·· ·····~·~················· ···~-·- ·-········ ....... ..... ......................... . • o 0 o o I rIp~'' o po o 0 •• poo roo o -~ o I o o o 0 I I 0 I. 1 . 0 •• t 0 I. I •• .................................................. :::::: : :~ :;:::: :::::::: :;:::: ;:: :: ~=: ::: ::~ ::~ :: ~: ·········· ........... ....................... . ............................................. •••••••• ~- ..... .... ..... .... ......... ·-· ............ . 0 •• o p 0 oo or 0 pO 0 I 0 0 o I o o lo- 0 I& oa ~· lo-o • 0 • • o o 0 • I 0°' 

. . . ~ ...... ' ............................................... .. ···--····· .............................. . 1901 Chouteau Avenue 

PO Box 66149, MC 602 St. Louis, MO 63166-6149 Ameren.com 
03/15/2013 1:54:00 PM Page 2 of 3 

shown in Figure 1 demonstrates that for the 3 year period 2008~201 0 there were no contributions from 

facilities located north of the Tazewell county monitor for measured S02 1evels greater than or equal to 

75 ppb. Actually over 99% of the measured S02 levels 75 ppb or larger occurred for winds from the 

South-Southeast to West-Northwest. The majority of these occurred with winds from the West and 

West-Southwest. 

3) Further evaluation of Figure 1 (as well as the detailed hourly data in Attachment I) indicates that the 

meteorology associated with elevated S02 levels was occurring a majority of the time with wind speeds 

greater than 10 mph. These relatively high wind speeds can cause plumes from relatively short stacks 

to experience significant downwash. Such stacks exist just west of the Tazewell county S02 monitor. 

4) US EPA in its response to Illinois' analysis for designating the Pekin, IL area nonattainment insinuates 

that just because there is a significant S02 emitting source north of the monitor that it automatically 

contributes to the higher levels monitored. This assumption is false based on the analysis described 

above. In addition as US EPA surely knows that the level of emissions emitted is not the only factor 

that should be considered. US EPA needs to consider the actual location of the source relative to the 

monitor and area's meteorology (as discussed above); the sources stack height; sources stack flow and 

temperature; and the sources other relevant operating characteristics. It is presumptuous of US EPA to 

assume that a source that emits S02 automatically contributes to the exceedances measured without 

considering all relevant information. 

80.00% 

70.00% 

60.00% 

50.00% 

40.00% 

30.00% 

20.00% 

10.00% 

0.00% 

Figure 1 

502 Pollutant Rose 2008-2010 

Tazwell Monitor (17-179-0004} 

502 Levels >= 75 ppb 

-- -

• >- 15 mph 

10 15 mph 

• 5·10 mph 

ao 5 mph 

Based on this analysis and Illinois EPA's analysis the facilities located north of the Tazewell monitor did not 

contribute to any of the measured exceedances of the one hour S02 standard in Tazewell County. US EPA has 

not sufficiently demonstrated that Hollis Township, Peoria County should be included in the Pekin, IL S02 

nonattainment area and thus Hollis Township should be removed from US EPA's recommendation. 
03/15/2013 1:54:00 PM Page 3 of 3 

If you have any questions please don't hesitate to contact me at 314-544-2089. 

Sincerely, 

ZIJ~~ Kenneth Anderson 

Managing Supervisor - Air Quality Management 

Attachment 
Attachment I 

Hourly S02 Data from the Tazewell Monitor and 

Wind Data from the Peoria Airport for 

Measured S02 Levels >= 75 ppb 

2008-2010 
502 and Wind Data for Tazewell Area 2008 

Wind 

Wind Speed Direction 

Date Hour S02 (ppb) (mph) (deg) 

12/27/2008 21:00 277 5 200 

11/08/2008 0:00 260 17 260 

12/28/2008 0:00 256 18 260 

05/02/2008 18:00 243 15 260 

12/27/2008 23:00 231 24 270 

11/08/2008 2:00 229 14 260 

12/28/2008 3:00 225 15 260 

12/28/2008 2:00 211 20 260 

11/07/2008 23:00 207 14 260 

14 260 

17 260 

12/28/2008 1:00 205 18 260 

12/28/2008 6:00 181 13 260 

11/07/2008 22:00 165 15 270 

12/27/2008 22:00 164 15 270 

22 270 

12/28/2008 4:00 164 11 250 

21 270 

04/12/2008 5:00 160 11 270 

03/25/2008 15:00 155 20 280 

05/03/2008 8:00 155 20 260 

03/25/2008 16:00 143 15 270 

04/12/2008 4:00 143 11 250 

04/12/2008 2:00 142 15 260 

16 260 

05/03/2008 9:00 140 20 270 

11/08/2008 1:00 136 14 260 

04/26/2008 8:00 119 16 250 

15 260 

16 250 

12/29/2008 11:00 119 14 270 

10/02/2008 14:00 118 11 260 

01/17/2008 22:00 117 10 260 

04/26/2008 13:00 115 18 280 

04/07/2008 12:00 114 16 270 

03/21/2008 13:00 112 11 220 

12/02/2008 1:00 112 8 250 

9 260 

12/28/2008 7:00 111 9 270 
01/17/2008 21

:00 110 11 260 

14 260 

10/02/2008 15:00 109 7 280 

11/08/2008 

9:00 105 20 270 

04/26/2008 

5:00 103 14 270 

04/07/2008 11

:00 102 14 290 

01/17/2008 16

:00 100 15 270 

04/12/2008 1:00 97 16 260 

04/26/2008 10:00 96 15 260 

04/12/2008 

6:00 95 16 280 

04/26/2008 

7:00 90 15 250 

20 260 

12/02/2008 

2:00 90 8 260 

7 260 

8 260 

03/25/2008 14

:00 89 22 260 

04/26/2008 11:00 87 15 260 

11/07/2008 18

:00 86 13 250 

12/28/2008 

5:00 85 5 230 

04/26/2008 12

:00 81 18 270 

04/26/2008 9:00 80 15 240 

05/04/2008 16

:00 80 9 260 

12/28/2008 

8:00 80 15 260 

11/10/2008 12:00 79 0 0 

06/28/2008 16:00 78 14 290 

03/26/2008 12

:00 77 3 VR 

04/12/2008 

3:00 77 11 250 

06/28/2008 11:00 77 10 250 

10/02/2008 16:00 77 7 280 

05/02/2008 19

:00 76 10 250 

11/08/2008 4:00 76 13 260 
S02 and Wind Data for Tazewell Area 2009 

Wind 

Wind Speed Direction 

Date Hour S02 (ppb) (mph) (deg) 

03/31/2009 17:00 352 22 260 

12/09/2009 7:00 282 28 260 

28 260 

22 260 

26 260 

10/23/2009 16:00 263 14 250 

14 260 

12/09/2009 9:00 262 25 260 

29 260 

29 260 

26 260 

29 270 

12/09/2009 8:00 252 29 260 

30 260 

28 260 

31 260 

26 260 

10/23/2009 17:00 235 14 260 

13 260 

15 260 

11 260 

10 270 

10 270 

10/30/2009 23:00 233 18 260 

13 260 

04/30/2009 10:00 231 17 280 

14 280 

12/28/2009 2:00 230 10 260 

05/21/2009 11:00 229 15 210 

08/20/2009 15:00 202 16 270 

12/09/2009 10:00 198 31 270 

28 260 

24 280 

03/31/2009 18:00 197 15 250 

03/10/2009 18:00 193 20 290 

14 290 

10/31/2009 3:00 187 15 250 

10/31/2009 2:00 183 15 260 
03/08/2009 14:00 181 31 270 

08/20/2009 17

:00 175 7 250 

10/31/2009 

0:00 173 14 250 

13 280 

01/17/2009 15

:00 171 18 290 

12/28/2009 

4:00 170 10 260 

11 270 

04/30/2009 14

:00 169 14 270 

11 260 

11 250 

04/30/2009 9:00 

163 18 280 

18 270 

17 260 

15 260 

06/01/2009 11:00 161 8 250 

05/21/2009 10

:00 160 17 260 

10/31/2009 

7:00 160 13 260 

08/20/2009 14

:00 155 17 240 

12/03/2009 21

:00 155 13 260 

10/03/2009 

3:00 154 10 260 

11 250 

11 250 

12/27/2009 23

:00 151 11 270 

11 260 

10/31/2009 5:00 149 8 260 

05/30/2009 14

:00 148 5 290 

10/31/2009 

4:00 147 13 260 

05/29/2009 11

:00 146 3 VR 

03/08/2009 13

:00 144 28 280 

05/31/2009 11

:00 144 3 160 

03/24/2009 21:00 144 11 250 

10/23/2009 15

:00 142 14 260 

15 260 

13 250 

05/14/2009 11

:00 142 13 280 

10/06/2009 16

:00 141 18 270 

10/03/2009 

5:00 140 10 260 

10 260 

08/20/2009 16

:00 139 14 250 

12/10/2009 12

:00 138 18 260 

12/09/2009 6:00 138 25 260 

25 260 

23 260 
12/10/2009 

6:00 138 14 270 

10/23/2009 14

:00 137 13 260 

13 250 

11 250 

06/09/2009 12

:00 137 0 0 

10/24/2009 10:00 137 9 270 

06/01/2009 12:00 134 11 280 

12/28/2009 

3:00 134 11 260 

10/24/2009 12

:00 133 10 280 

10/02/2009 21

:00 130 14 240 

15 250 

10/31/2009 

1:00 129 13 270 

14 270 

10/30/2009 22

:00 129 25 260 

21 260 

08/20/2009 13:00 127 18 240 

10/03/2009 

4:00 127 10 250 

10 260 

05/29/2009 10

:00 126 5 280 

03/31/2009 16

:00 125 26 270 

10/03/2009 

8:00 125 14 250 

06/28/2009 23

:00 125 6 260 

10/03/2009 11

:00 123 8 260 

9 250 

06/01/2009 15

:00 120 8 270 

10/24/2009 13

:00 119 10 250 

04/08/2009 10

:00 119 9 290 

06/05/2009 

9:00 118 8 230 

11/25/2009 19:00 118 10 270 

08/21/2009 12

:00 113 13 270 

10/31/2009 8:00 113 14 280 

14 270 

12/09/2009 13

:00 112 20 270 

28 270 

11/25/2009 11:00 112 14 280 

11 260 

14 270 

05/31/2009 12

:00 112 6 VR 

10/23/2009 20

:00 112 17 270 

10 270 

10 260 

12/10/2009 23

:00 110 7 260 

05/30/2009 12

:00 109 13 250 
12/10/2009 21

:00 108 13 270 

05/10/2009 14:00 107 13 310 

08/21/2009 11

:00 107 8 260 

14 260 

04/25/2009 15

:00 105 8 260 

05/30/2009 11:00 105 13 260 

10/06/2009 14

:00 104 17 280 

10/30/2009 20

:00 103 15 250 

03/25/2009 12:00 102 11 240 

12/10/2009 7:00 102 13 260 

12/28/2009 

1:00 101 11 260 

03/25/2009 14

:00 100 13 250 

05/11/2009 

9:00 99 5 VR 

10/04/2009 14:00 98 5 260 

10/24/2009 11

:00 98 14 260 

9 280 

05/21/2009 13

:00 97 9 240 

11/04/2009 11

:00 97 10 270 

06/19/2009 10

:00 97 18 250 

03/25/2009 10

:00 97 15 250 

16 260 

14 260 

15 260 

02/07/2009 13:00 96 13 250 

03/08/2009 15:00 95 29 270 

05/23/2009 8:00 95 0 0 

06/01/2009 10

:00 95 9 240 

03/25/2009 11:00 94 10 260 

12/04/2009 9:00 94 11 260 

05/14/2009 10

:00 94 13 260 

12/10/2009 22

:00 93 10 270 

11/25/2009 18

:00 91 10 260 

11 260 

04/30/2009 13:00 91 11 270 

04/25/2009 14:00 91 6 270 

05/14/2009 12

:00 91 13 260 

11/25/2009 13

:00 90 16 270 

06/20/2009 14

:00 90 9 260 

10/23/2009 18

:00 89 14 260 

15 280 

12/28/2009 0:00 87 13 260 

12/03/2009 17

:00 85 10 260 

07/31/2009 13

:00 85 7 280 
12/03/2009 20:00 85 11 260 

12/10/2009 13

:00 84 14 280 

07/15/2009 12

:00 84 11 290 

06/09/2009 13

:00 83 6 280 

05/29/2009 12

:00 83 5 250 

10/23/2009 21

:00 83 14 270 

14 260 

11 280 

06/05/2009 12

:00 82 8 240 

03/25/2009 15:00 80 11 250 

11 280 

05/21/2009 

9:00 80 11 260 

12/11/2009 

0:00 80 7 260 

10/06/2009 15

:00 79 16 270 

04/01/2009 13

:00 79 16 270 

06/01/2009 19

:00 79 0 0 

11/04/2009 10

:00 79 10 270 

03/25/2009 

1:00 79 3 210 

04/09/2009 10

:00 78 0 0 

11/25/2009 21

:00 78 15 280 

12/26/2009 21

:00 78 10 260 

10 270 

05/27/2009 11

:00 77 11 270 

11/03/2009 12:00 76 5 230 

07/31/2009 10

:00 76 10 280 

06/05/2009 17

:00 75 9 240 

05/29/2009 

9:00 75 5 300 
S02 and Wind Data for Tazewell Area 2010 

Wind 

Wind Speed Direction 

Date Hour S02 (ppb) (mph) (deg) 

05/13/2010 15:00 331 21 250 

06/02/2010 8:00 254 10 260 

01/25/2010 11:00 241 16 270 

09/07/2010 9:00 228 15 260 

09/07/2010 11:00 224 20 260 

10/27/2010 13:00 220 22 250 

09/07/2010 10:00 217 21 260 

09/07/2010 14:00 210 15 270 

09/07/2010 12:00 202 24 260 

10/20/2010 16:00 198 9 250 

10/20/2010 14:00 196 18 260 

09/07/2010 13:00 195 20 260 

05/13/2010 14:00 190 14 260 

04/07/2010 14:00 179 14 260 

01/25/2010 12:00 178 17 280 

17 260 

16 270 

21 270 

22 270 

17 280 

17 270 

17 260 

03/18/2010 13:00 177 9 240 

01/24/2010 12:00 174 10 250 

11 270 

10/20/2010 15:00 173 13 270 

10/30/2010 13:00 172 16 260 

04/21/2010 20:00 170 10 260 

11/13/2010 23:00 167 15 270 

01/24/2010 11:00 161 11 270 

10/14/2010 12:00 160 8 260 

11/13/2010 18:00 151 17 250 

01/25/2010 6:00 150 11 260 

10 250 

11/30/2010 8:00 149 13 260 

13 260 

15 260 

14 260 
10/20/2010 13

:00 145 17 260 

11/13/2010 20:00 144 21 270 

11/30/2010 

6:00 144 13 260 

11/26/2010 

7:00 138 10 260 

11/30/2010 12

:00 137 16 270 

11/26/2010 

2:00 134 6 240 

04/15/2010 11

:00 134 16 250 

10/20/2010 17:00 127 7 250 

11/30/2010 10

:00 125 16 270 

11/14/2010 3:00 122 10 260 

11/13/2010 19:00 122 20 270 

10/14/2010 14

:00 120 13 260 

03/11/2010 20

:00 117 9 250 

11/26/2010 

8:00 116 13 270 

04/15/2010 12

:00 116 15 230 

06/19/2010 13

:00 115 7 290 

11/13/2010 21

:00 114 13 260 

02/19/2010 11

:00 114 3 190 

11/30/2010 

5:00 114 15 270 

11 260 

11/30/2010 11

:00 114 20 270 

11/30/2010 

2:00 113 20 270 

14 270 

11/26/2010 14

:00 111 15 260 

10/26/2010 15:00 111 17 250 

09/12/2010 13:00 110 14 250 

04/21/2010 15:00 109 0 0 

03/19/2010 12

:00 108 14 250 

10/14/2010 13:00 108 14 280 

03/23/2010 14

:00 108 15 210 

10/27/2010 12

:00 107 21 250 

07/28/2010 13

:00 107 13 260 

05/11/2010 12

:00 106 15 270 

10/20/2010 12

:00 105 13 270 

11/14/2010 13:00 104 13 240 

05/09/2010 12

:00 104 7 VR 

04/03/2010 11

:00 102 14 290 

09/16/2010 

6:00 102 13 260 

11 260 

11 260 

13 260 

11/13/2010 17

:00 102 17 250 

12/31/2010 23:00 99 20 260 
10/06/2010 15:00 98 13 260 

05/09/2010 14:00 97 3 VR 

05/13/2010 16:00 97 16 270 

10/01/2010 13:00 97 6 300 

04/15/2010 13:00 97 15 230 

10/27/2010 16:00 96 22 270 

11/30/2010 14:00 95 21 270 

11/30/2010 9:00 95 13 250 

07/28/2010 12:00 94 13 250 

09/12/2010 11:00 92 9 280 

01/25/2010 10:00 91 13 260 

14 250 

13 260 

12/31/2010 22:00 91 16 260 

02/03/2010 12:00 89 3 170 

01/17/2010 1:00 89 3 10 

5 40 

5 20 

3 20 

0 0 

12/11/2010 20:00 88 13 250 

06/27/2010 14:00 87 13 280 

06/27/2010 13:00 87 15 260 

01/24/2010 13:00 86 13 280 

05/03/2010 14:00 86 13 280 

03/11/2010 15:00 82 15 240 

12/11/2010 19:00 81 14 270 

03/19/2010 13:00 81 13 240 

05/03/2010 17:00 81 10 280 

06/19/2010 14:00 80 11 260 

10/30/2010 14:00 77 11 250 

02/19/2010 10:00 77 0 0 

01/25/2010 5:00 77 10 260 

11/30/2010 7:00 77 14 260 

02/23/2010 14:00 75 9 270 

05/14/2010 10:00 75 10 260 

11/30/2010 4:00 75 21 270 

11/30/2010 3:00 75 13 270 

Note: 

1. Zero for wind speed/direction indicates calm 
2. Multiple wind speed/direction readings indicate more than one reading was taken for 

that hour because of changing conditions. 

3. VR- variable 

4. S02 data from US EPA AirData- Tazewell monitor (ID: 17-179-0004) Pekin, IL 

5. Wind Speed/Direction data from NOAA- Quality Controlled Local Climatological Data 

(QCLC) Greater Peoria Regional Airport- Station 10: 14842/PIA 
EXHIBIT 5

MPS GROUP 2012 EMISSION DATA 
~ 

Ameren 

Michael L. Menne 

Vice President 

Environmental Services 

Ameren Services 

T 314.554.2816 

F 314.554.4182 

mmenne@ameren.com 

. I, ooo ················-·-·······················--·-······························································· OIO 0 0 ••• ot •,,,, o oo o o o•o oo 0 0 0 0 o o oo o, o o• ooo,,, o o o Oo o o o o o •••• o oo o• o o o o ooooo o o o, o • o o o o•l oo o o o o o •• • o • o o o o o ooo • ·

I ····· o o •• o • ························ •• • • • • • •I• • • •'' o' 0' 0 ' ' o ·ooo' ··························- 0 0 0 0 oo 0 'oo 0"' '''" ''' '' •• • ... 0 ·······················"············································ '' • 0 ' 0 •••• • • 0 ° 0 ''' ' ' ' • 0 '' ''' 0 0 ° 00 I 0 0 0 0 ° 0 0'' 0 ' 0•'' 0 • ~ .. ,,' • 'oo'' oo 0 ' oo 

February 6, 2013 

CERTIFIED MAIL 7009 0820 0001 4250 1690 

Mr. Jim Ross, Manager 

Division of Air Pollution Control 

Bureau of Air 

Illinois Environmental Protection Agency 

1021 North Grand Avenue East 

P. 0 . Box 19726 

Springfield, IL 62794-9276 

RE: Illinois Multi-Pollutant Standard- Annual Emission Rate Report for 2012 

Dear Mr. Ross: 

In accordance with 35 Illinois Administrative Code Part 225 Subpart B Section 225.233(e)(4), Ameren 

Energy Resources, as authorized agent for Ameren Energy Generating Company, Ameren Energy 

Resources Generating Company and Electric Energy Inc., submits this Annual Emission Rate Report for 

2012. This report encompasses the electric generating units that are members of Ameren's MultiPollutant Standard (MPS) group as contained in Ameren's "Notice of Intent" dated December 27, 2007. 

Below is a list of the units contained in Ameren's MPS group: 

Ameren Energy Generating Company 

Facility Facility I. D. Emission Unit 

Coffeen 135803AAA 01 

Coffeen 135803AAA 02 

Hutsonville 033801AAA 05 

Hutsonville 033801AAA 06 

Meredosia 137805AAA 01 

Meredosia 137805AAA 02 

Meredosia 137805AAA 03 

Meredosia 137805AAA 04 

Meredosia 137805AAA 05 

Newton 079808AAA 1 

Newton 079808AAA 2 

Ameren Energy Resources Generating Company 

Facility 

Duck Creek 

E. D. Edwards 

E. D. Edwards 

E. D. Edwards 

0 ~- o 0 04 o o o o 4 •• o o ••, 0 .. I ... 0 o o .. I .... o 0 Po• o t ~ f -~ ~ •• • o '1 roo o o ol 0 0 0 0 "0 I o I 0 10 I I 0. I 0 I 0 I ... 0 4 I 4 I oo ''I o 0 o 0 I • 0 o o 0 0 ° o o o 

0 04 ... oO o 0 0 o o o 0, o 0. •O •1 0 0 I~ I 0 I 0 0 0 0 I"' o o o o o •• ••• o o o 1 oo o o oo * o o• oo o o 0 0 t 0 0 0 ~-I o o o o 0 I o I 0 o I 0 o I I I 4 I 0 I .. I •• I 4 0 0 I 0 0 o o 

0 0 0 ... 0 o 0 0 0 0 I •1 0 I 0 0 0 0 pI o 0 p 0 001 o 0 0 0 0 00 0 oO oo -~ oOo o o 0 o4 o4 o o o o o o oo 0 o • • •• o• o o I o oo o 0 0 oo 00 o o o 0 o PO 0 ° I P ' PI I 0 0 0 0 0 I 0 0 0 I 

............................................................................................. , ................ . ::::::~::::::::::::::::::::::;::~:~:::::::::::::::::::::::::::::::;:::::::::::::::::::::;:::::~::::::~:::; 

Facility I. D. 

057801AAA 

143805AAG 

143805AAG 

143805AAG 

1901 Chouteau Avenue 

PO Box 66149, MC 602 

Emission Unit 

1 

1 

2 

3 

St. Louis, MO 63166-6149 Ameren.com 
Electric Energy, Inc. 

Facility Facili_ty I. D. Emission Unit 

Joppa 127855AAC 1 

Joppa 127855AAC 2 

JQQQ_a 127855AAC 3 

Joppa 127855AAC 4 

JopQ_a 127855AAC 5 

Joppa 127855AAC 6 

Section 225.233(e)(3)(B)(iii) requires the Ameren MPS Group comply with an overall NOx annual 

emission rate of no more than 0.11 #/mmBtu. Ameren's MPS Group achieved an overall NOx annual 

emission rate of 0.11 #/mmBtu for 2012. Unit specific emission data is included in Attachment 1. 

By order of the Illinois Pollution Control Board (I PCB) on September 20, 2012(PCB-12-126, Variance-Air) 

for 2012 the Ameren MPS Group must comply with an overall S02 annual emission rate of no more than 

0.38 #/mmBtu. Ameren's MPS Group achieved an overall S02 annual emission rate of 0.36 #/mmBtu for 

2012. Unit specific emission data is included in Attachment 2. 

Please contact Donald Schuh at (314) 554-2658 if you have any questions concerning this submittal or if 

additional information is required. 

I certify under penalty of law that this document and all attachments were prepared under my direction or 

supervision in accordance with a system designed to assure that qualified personnel properly gather and 

evaluate the information submitted. Based on my inquiry of the person or persons directly responsible for 

gathering the information, the information submitted is, to the best of my knowledge and belief, true, 

accurate, and complete. I am aware that there are significant penalties for submitting false information, 

including the possibility of fine and imprisonment for knowing violations. 

Sincerely, 

~/~~~ Michael l. Menne 

Attachments 
bee: M. L. Menne 

S. C. Whitworth 

M. T. Curtis 

K. J. Kersting 

K. J. Anderson 

M. J. Hutcheson 

R. H. LaPlaca 

B. Parker 

D. H. Schuh 

R. L. Robertson 

S. C. Hughes 

File: AQ 5.6.2 
Attachment 1 

Multi-Pollutant Standard Demonstration of Compliance 

2012 NOx Annual Emission Rates 

Required by 351AC 225 Subpart 8 Section 225.233(e)(4) 

Ameren Energy Generating Company 

Facility Emission Point NOx Heat Input NOx Emission Rate 

ttonsl tmmBtul t#/mmBtul 

Coffeen 01 703 19,425,264 0.072 

Coffeen 02 1,270 34,734,221 0.073 

Hutsonville 05 0 0 0.000 

Hutsonville 06 0 0 0.000 

Meredosia CS0001 (01, 02, 03, 04) 0 0 0.000 

Meredosia 05 0 0 0.000 

Newton 1 1,946 35,688,036 0.109 

Newton 2 1,057 20,336,868 0.104 

Ameren Energy Resources Generating Company 

Facility Emission Point NOx Heat Input NOx Emission Rate 

(tons) CmmBtu) (#/mmBtu) 

Duck Creek 1 1,247 25,219,961 0.099 

ED Edwards CS0001 (1, 2) 2,698 25,327,583 0.213 

ED Edwards 3 611 18,872,502 0.065 

Electric Energy, Inc. 

Facility Emission Point NOx Heat Input NOx Emission Rate 

(tons) tmmBtul (#/mmBtul 

Joppa Steam CS1 (1, 2) 1,532 25,030,782 0.122 

Joppa Steam CS2 (3, 4) 1,261 23,650,130 0.107 

Joppa Steam CS3 (5, 6) 1,272 22,902,466 0.111 

Ameren MPS Weighted Average I 13,5981 251 ,187,813 0.108 

Ameren MPS Group Mull-Pollutant Standard Per 225.233(e)(3)(B)(iii) 0.114 

Note: Emissions data monitored and reported in accordance with 40 CFR Part 75. 

February 1, 2013 
Attachment 2 

Multi-Pollutant Standard Demonstration of Compliance 

2012 S02 Annual Emission Rates 

Required by 351AC 225 Subpart 8 Section 225.233(e)(4) 

Ameren Energy Generating Company 

Facility Emission Point 802 Heat Input 802 Emission Rate 

(tonsl CmmBtu) (#/mmBtu) 

Coffeen 01 43 19,425,264 0.00 

Coffeen 02 60 34,734,221 0.00 

Hutsonville 05 0 0 0.00 

Hutsonville 06 0 0 0.00 

Meredosia CS0001 (01 , 02, 03, 04) 0 0 0.00 

Meredosia 05 0 0 0.00 

Newton 1 10,538 35,688,036 0.59 

Newton 2 5,982 20,336,866 0.59 

Ameren Energy Resources Generating Company 

Facility Emission Point 802 Heat Input 802 Emission Rate 

ftonsl {mmBtul f#/mmBtul 

Duck Creek 1 296 25,219,961 0.02 

ED Edwards CS0001 (1 , 2) 6,845 25,327,583 0.54 

ED Edwards 3 4,958 18,872,502 0.53 

Electric Energy, Inc. 

Facility Emission Point S02 Heat Input S02 Emission Rate 

(tons) CmmBtul C#/mmBtu) 

Joppa Steam CS1 (1 , 2) 5,924 25,030,782 0.47 

Joppa Steam CS2 (3, 4) 5,734 23,650,130 0.48 

Joppa Steam CS3 (5, 6) 5,333 22,902,466 0.47 

Ameren MPS Weighted Average I 45,7121 251,187,813 0.36 

Ameren MPS Group Mult~Pollutant Standard Per September 20, 20121PCB Order 0.38 

Note: Emissions data monitored and reported in accordance with 40 CFR Part 75. 

February 1, 2013 
Michaell. Menne 

Vice President 

Environmental Services 

Ameren Services 

T 314.554.2816 

F 314.554.4182 

mlmenne@ameren.com 

'o o t o H, o 1 1 0 o •• o , 0 0 •o o o o, 0 o ••••• , , , "eo 4 10 I o o o o I o " " o o o o o ot o •• o o o o o ~ o o o o o o o •• t ~ o o 0 o o ~ o o o o t •• o o o 0 • o oo o too • ••••• • • •• o • too o o o • 0 o o o o •• • o o o o o., o o o oo o o o o o o o o o •0 oo o o o o I •• 0 • • 0 t • • •~ 0 • •• • • o • oo •• •• •• o• • • oo • • o • • o o o " • o t o o • o 0 too o o o "" Oo o o 0 0 

....................................................................... ' ........................................................................................................................................................... . 

October 29, 2012 

CERTIFIED MAIL 7004 2890 0003 6374 3693 

Mr. Jim Ross, Manager 

Division of Air Pollution Control 

Bureau of Air 

Illinois Environmental Protection Agency 

1021 North Grand Avenue East 

P. 0. Box 19726 

Springfield, IL 62794-9276 

RE: Illinois Mercury Rule Multi-Pollutant Standard- Seasonal Report for 2012 

Dear Mr. Ross: 

In accordance with 35 Illinois Administrative Code Part 225 Subpart B Section 225.233(e)(4), Ameren 

Energy Resources, as authorized agent for Ameren Energy Generating Company, Ameren Energy 

Resources Generating Company and Electric Energy Inc., submits this seasonal 2012 compliance report. 

This report encompasses the electric generating units that are members of Ameren's Multi-Pollutant 

Standard (MPS) group as contained in Ameren's "Notice of Intent" dated December 27, 2007. Below is a 

list of the units contained in Ameren's MPS group: 

Ameren Energy Generating Company 

Facility Facility_ I. D. Emission Unit 

Coffeen 135803AAA 01 

Coffeen 135803AAA 02 

Hutsonville 033801AAA 05 

Hutsonville 033801AAA 06 

Meredosia 137805AAA 01 

Meredosia 137805AAA 02 

Meredosia 137805AAA 03 

Meredosia 137805AAA 04 

Meredosia 137805AAA 05 

Newton 079808AAA 1 

Newton 079808AAA 2 

Ameren Energy Resources Generating Company 

Facility 

Duck Creek 

E. D. Edwards 

E. D. Edwards 

E. D. Edwards 

1• , ., ••, 1 ~~ • o •••• o o oooo ~ o•o• ro r~ o ••~• o o o ••• o o• o o •• o o oot' lo ~ • ••• ••; •~ ~- •• • • o ,, oo o o o o oo o o o o o o oo •• o o • o • r• oo • 

; :::::: :::::: ::::: ~:.: :; : :::::: ::::: =~:: ~::: ::::;:::::: ~:::: ~::::::::: ::::::::::: ~: :: :::::: :: ::::::: :: :: ~ 

···

o o 0 ·01 ·····0 ~- ·o ·0 0 0 ········· ooo o o o o ·fO ·oO ··-0 0 0 0 o 0 0 0 ···-·-... ··o, -o 0 ·-·o• -o 0 o 0 0 0 0 o 0 -································ oo o 0 o 01 o o o I o o o; o 0 • o o o oo oo ·o • o o o o I 0 o o 0 I ······················· 0 00 0 0 o 0 I 0 I 0 I 0 0 o 0 0 ······.0 00 

··· I 

I 00 0 o 0 0 0 o 0 I 0 0 0 o o 0 I 0 0 I I 0 0 0 I 0 I 0 I 0 o 0 I • o .. , 0 0 0 .. 0 0 I • I • I • • o 0 • •• • • • • • •~ • • •• • • • • • • • •• • • ~ • • • 0 • • o. •• ••. I o 0. 0 ~ • • ~ ' 

Facility I. D. 

057801AAA 

143805AAG 

143805AAG 

143805AAG 

1901 Chouteau Avenue 

PO Box 66149, MC 602 

Emission Unit 

1 

1 

2 

3 

St. louis, MO 63166-6149 Ameren.com 
Electric Energy, Inc. 

Facility Facility I. D. Emission Unit 

Joppa 127855AAC 1 

Joppa 127855AAC 2 

Joppa 127855AAC 3 

Joppa 127855AAC 4 

Joppa 127855AAC 5 

Joppa 127855AAC 6 

Section 225.233(e)(3)(B)(i) requires the Ameren MPS Group comply with an overall NOx seasonal 

emission rate of no more than 0.11 #/mmBtu. Ameren's MPS Group achieved an overall NOx seasonal 

emission rate of 0.109 #/mmBtu for the 2012 ozone season. Unit specific emission data is included in 

Attachment 1. 

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

which this submission is made. Please contact Donald Schuh at (314) 554-2658 if you have any 

questions concerning this submittal or if additional information is required. 

Sincerely, 

~JJ£9y~ Michael L. Menne 

Attachment 
Attachment 1 

Multi-Pollutant Standard Demonstration of Compliance 

2012 NOx Ozone Season Emission Rates 

Required by 35 lAC 225 Subpart B Section 225.233(e)(4) 

Ameren Energy Generating Company 

Facility Emission Point NOx Heat Input NOx Emission Rate 

(tons\ CmmBtul {#/mmBtul 

Coffeen 01 290 8,589,844 0.068 

Coffeen 02 547 14,158,471 0.077 

Hutsonville 05 0 0 0.000 

Hutsonville 06 0 0 0.000 

Meredosia CS0001 {01, 02, 03, 04) 0 0 0.000 

Meredosia 05 0 0 0.000 

Newton 1 886 16,004,071 0.111 

Newton 2 481 9,035,849 0.106 

Ameren Energy Resources Generating Company 

Facility Emission Point NOx Heat Input NOx Emission Rate 

(tons) (mmBtu) (#/mmBtu) 

Duck Creek 1 531 10,020,339 0.106 

ED Edwards CS0001 {1 , 2) 1131 10,913,845 0.207 

ED Edwards 3 240 7,875,766 0.061 

Electric Energy, Inc. 

Facility Emission Point NOx Heat Input NOx Emission Rate 

Ctonsl CmmBtul f#lmmBtul 

Joppa Steam CS1 (1, 2) 618 10,102,220 0.122 

Joppa Steam CS2 {3, 4) 474 9,057,909 0.105 

Joppa Steam CS3 (5, 6) 516 9,043,370 0.114 

Ameren MPS Weighted Average I 57141 104,801 ,684 0.109 

Ameren MPS Group Mult-Pollutant Standard Per 225.233(e)(3)(B)(i) 0.114 

Note: Emissions data monitored and reported in accordance with 40 CFR Part 75. 

October 25, 2011 
bee: M. Curtis 

S. C. Whitworth 

K. J. Anderson 

B. Parker 

S. C. Hughes 

File: AQ 5.6. 1 
EXHIBIT 6

MPS GROUP INFORMATION 

(§104.204(b)) 

General Information Responsive to 35 Ill. Adm. Code 104.204(b): Addresses; Boiler and Sizes; 

Pollution Control Equipment; SO2 Emissions; Permits. 
Exhibit 6 

Ameren MPS Group Information 

(§ 104.204(b)) 

Address Boilers and Sizes Pollution 

Control 

Equipment1

SO2 Emissions in 

Rate and TPY 

Permits issue

application num

relevant 

Coffeen Energy Center (I.D. No. 135803AAA) 134 CIPS Lane Coffeen, Illinois Montgomery County 

Unit 1 Nominal 3,282 mmBtu/hr (1965) 

Unit 2 nominal 5,544 mmBtu/hr (1972) 

OFA3SCR4

ESP5 with 

FGC6FGD7Mercury Controls 

2012 SO2emission rate = 0.004 lb/MMBtu 2012 SO2 mass emissions = 103 tons 

State Operating PFebruary 13, 2004 App. No. 730200Unit 1 February 13, 2004 App. No. 730200Unit 2 

1 All units unless otherwise indicated. 2 Note that listed here are construction permit issued in or after 2005 through the present and that during this period, Ameren h

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

3 Overfire Air 4 Selective Catalytic Reduction 5 Electrostatic Precipitator 6 Flue Gas Conditioning 7 Flue Gas Desulfurization (scrubber) 

Exhibit 6 - 1 
Exhibit 6 

Ameren MPS Group Information 

(§ 104.204(b)) 

Address Boilers and Sizes Pollution 

Control 

Equipment1

SO2 Emissions in 

Rate and TPY 

Permits issue

application num

relevant 

Coffeen Energy Center (I.D. No. 135803AAA) 

Exhibit 6 - 2 

Construction PermDecember 21, 200App. No. 070900New ESP for UniDecember 15, 20023, 2007 App. No. 060900New FGD for UnJune 22, 2009 App. No. 060900Revised WFGD SHandling June 22, 2011 App. No. 110600Fuel Additives SyUnit 2 March 2, 2012; reApp. No. 120200Temporary MercuReduction System 
Exhibit 6 

Ameren MPS Group Information 

(§ 104.204(b)) 

Address Boilers and Sizes Pollution 

Control 

Equipment1

SO2 Emissions in 

Rate and TPY 

Permits issue

application num

relevant 

Coffeen Energy Center (I.D. No. 135803AAA) 

October 30, 2012 App No 1207004Permanent Steag System CAAPP Permit: 

September 29, 20App. No. 950900Appealed Novem(PCB 06-064) Stayed February 1Partial Stay SepteReissued permit wSeptember 20, 20September 20, 20

Exhibit 6 - 3 
Exhibit 6 

Ameren MPS Group Information 

(§ 104.204(b)) 

Address Boilers and Sizes Pollution 

Control 

Equipment1 

SO2 Emissions in 

Rate and TPY 

Permits issue

application num

relevant 

Duck Creek Energy Center (I.D. No. 057801AAA) 17751 North CILCO Road Canton, Illinois Fulton County 

Unit 1 Nominal 3,713 mmBtu/hr (1976) 

LNB8SCR ESP FGD Mercury Controls 

2012 SO2

emission rate = 0.02 lb/MMBtu 2012 SO2 mass emissions = 296 tons 

State Operating PNovember 13, 19App. No. 7802000Construction PermNovember 22, 202008 App. No. 0607004New WFGD9 sysFebruary 16, 2007 App. No. 0607004Boiler project; NeMay 7, 2007; reviApp. No. 0703002Pilot Air Quality 

8 Low NOx Burner 9 Wet FGD 

Exhibit 6 - 4 
Exhibit 6 

Ameren MPS Group Information 

(§ 104.204(b)) 

Address Boilers and Sizes Pollution 

Control 

Equipment1 

SO2 Emissions in 

Rate and TPY 

Permits issue

application num

relevant 

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

August 15, 2011 App. No. 1108004Canton Fuels ComEmission Fuel (RFacility May 8, 2013 App. No. 1304004Pilot Testing of FCAAPP Permit: September 29, 20App. No. 9507002Appealed Novem(PCB 06-066) Stayed February 1

Exhibit 6 - 5 
Exhibit 6 

Ameren MPS Group Information 

(§ 104.204(b)) 

Address Boilers and Sizes Pollution 

Control 

Equipment1 

SO2 Emissions in 

Rate and TPY 

Permits issue

application num

relevant 

E.D. Edwards Energy Center (I.D. No. 143805AAG) 7800 South CILCO Lane Bartonville, Illinois Peoria County 

Unit 1 Nominal 1,523 mmBtu/hr (1960) 

Unit 2 Nominal 3,321 mmBtu/hr(1968 

Unit 3 Nominal 4,594 mmBtu/hr(1972) 

LNB ESP with FGC OFA on Unit 2 New LNB and OFA + SCR on Unit 3 Sorbent Injection 

2012 SO2

emission rate = 0.53 lb/MMBtu 2012 SO2 mass emissions = 11,803 tons 

State Operating P

July 1, 2004 App. No. 730107Construction PerMarch 9, 2007 App. No. 070300LNB and OFA foAugust 24, 2008 App. No. 080800LNB and OFA foSeptember 9, 200App. No. 081000Sorbent Injection 2, 3 March 30, 2011 App. No. 110300Pilot System for (Mercury Contro

Exhibit 6 - 6 
Exhibit 6 

Ameren MPS Group Information 

(§ 104.204(b)) 

Address Boilers and Sizes Pollution 

Control 

Equipment1 

SO2 Emissions in 

Rate and TPY 

Permits issue

application num

relevant 

E.D. Edwards Energy Center (I.D. No. 143805AAG) 

CAAPP Permit: September 29, 20App. No. 950700Appealed Novem(PCB 06-067) Stayed February 

Exhibit 6 - 7 
Exhibit 6 

Ameren MPS Group Information 

(§ 104.204(b)) 

Address Boilers and Sizes Pollution 

Control 

Equipment1 

SO2 Emissions in 

Rate and TPY 

Permits issue

application num

relevant 

Hutsonville Energy Center (I.D. No. 033801AAA) 15142 East 1900th

Ave. Hutsonville, Illinois Crawford County 

Unit 5 Nominal 695 mmBtu/hr (1952) 

Unit 6 Nominal 695 mmBtu/hr (1953) 

ESP 2012 SO2

emission rate = 0.00 lb/MMBtu 2012 SO2 mass emissions = 0 tons

State Operating P

February 17, 200App. No. 730200Unit 5 February 17, 200App. No. 730200Unit 6 Construction Perm

May 14, 2006 App. No. 060400Pilot Evaluation oSO2 and mercury 

April 3, 2008 App. No. 080300Pilot Evaluation oPM Control on U

Exhibit 6 - 8 
Exhibit 6 

Ameren MPS Group Information 

(§ 104.204(b)) 

Address Boilers and Sizes Pollution 

Control 

Equipment1 

SO2 Emissions in 

Rate and TPY 

Permits issue

application num

relevant 

Hutsonville Energy Center (I.D. No. 033801AAA) 

August 18, 2008 App. No. 080800Pilot OFA EvaluaCAAPP Permit: September 29, 20App. No. 950801Appealed Novem(PCB 06-070) Stayed February 

Exhibit 6 - 9 
Exhibit 6 

Ameren MPS Group Information 

(§ 104.204(b)) 

Address Boilers and Sizes Pollution 

Control 

Equipment1 

SO2 Emissions in 

Rate and TPY 

Permits issue

application num

relevant 

Joppa Energy Center (I.D. No. 127855AAC) 2100 Portland Road Joppa, Illinois Massac County 

Units 1-6 Nominal 1,800 mmBtu/hr each (Units 1 and 2 1953) (Units 3 and 4 1954) (Units 5 and 6 1955) 

ESP OFA on Units 1, 3, 4, 5 and 6 Sorbent Injection 

2012 SO2emission rate = 0.48 lb/MMBtu 2012 SO2 mass emissions = 16,991 tons 

State Operating PJune 7, 2005 App. No. 7301075Construction PermMarch 3, 2005 App. No. 0502000OFA system for UDecember 5, 2005 App. No. 050200OFA system for UNovember 30, 20App. No. 0600057 OFA system for UOctober 24, 2007 App. No. 0709003OFA system for U

Exhibit 6 - 10 
Exhibit 6 

Ameren MPS Group Information 

(§ 104.204(b)) 

Address Boilers and Sizes Pollution 

Control 

Equipment1 

SO2 Emissions in 

Rate and TPY 

Permits issue

application num

relevant 

Joppa Energy Center (I.D. No. 127855AAC) 

October 31, 2008 App. No. 0810005OFA system for UMarch 31, 2006 App. No. 060200Pilot for Mercury December 5, 20062007 and August App. No. 0611000Pilot for Mercury July 18, 2008; rev2009 App. No. 0802007Sorbent Injection October 20, 20082009 App. No. 0809005Pilot for SNCR foUnit 3 

Exhibit 6 - 11 
Exhibit 6 

Ameren MPS Group Information 

(§ 104.204(b)) 

Address Boilers and Sizes Pollution 

Control 

Equipment1 

SO2 Emissions in 

Rate and TPY 

Permits issue

application num

relevant 

Joppa Energy Center (I.D. No. 127855AAC) 

April 28, 2010 App. No. 1106005Pilot for Injection Control June 30, 2011; rev2012 App. No. 1106005Additives InjectioCAAPP Permit: September 29, 20App. No. 9509012Appealed Novem(PCB 06-065) Stayed February 1

Exhibit 6 - 12 
Exhibit 6 

Ameren MPS Group Information 

(§ 104.204(b)) 

Address Boilers and Sizes Pollution 

Control 

Equipment1

SO2 Emissions in 

Rate and TPY 

Permits issue

application num

relevant 

Meredosia Energy Center (I.D. No. 137805AAA) 800 South Washington Street Meredosia, Illinois Morgan County 

Units 1 and 2 Nominal 505 mmBtu/hr each (1945) 

Units 3 and 4 Nominal 505 mmBtu/hreach (1946) 

Unit 5 Nominal 2,784 mmBtu/hr(1957) 

ESP FGC on Units 1-4 LNB, FGC and Sorbent Injection on Unit 5 

2012 SO2

emission rate = 0.0 lb/MMBtu 2012 SO2 mass emissions = 0 tons 

State Operating P

May 22, 1996 App. No. 730200Unit 1 May 22, 1996 App. No. 730200Unit 2 May 22, 1996 App. No. 730200Unit 3 May 22, 1996 App. No. 730200Unit 4 July 23, 2003 App. No. 730200Unit 5 

Exhibit 6 - 13 
Exhibit 6 

Ameren MPS Group Information 

(§ 104.204(b)) 

Address Boilers and Sizes Pollution 

Control 

Equipment1

SO2 Emissions in 

Rate and TPY 

Permits issue

application num

relevant 

Meredosia Energy Center (I.D. No. 137805AAA) 

Construction PermJuly 17, 2008 App. No. 080500Sorbent ActivatioDemonstration PrFebruary 15, 2007 App. No. 061200FGC System for BDecember 1, 2009 App. No. 080700Sorbent Injection 3/Boiler 5 August 24, 2009 App. No. 090800Low NOx Burnerfor Boiler 5 

Exhibit 6 - 14 
Exhibit 6 

Ameren MPS Group Information 

(§ 104.204(b)) 

Address Boilers and Sizes Pollution 

Control 

Equipment1

SO2 Emissions in 

Rate and TPY 

Permits issue

application num

relevant 

Meredosia Energy Center (I.D. No. 137805AAA) 

CAAPP Permit: 

September 29, 20App. No. 950900Appealed Novem(PCB 06-069) Stayed February 1

Exhibit 6 - 15 
Exhibit 6 

Ameren MPS Group Information 

(§ 104.204(b)) 

Address Boilers and Sizes Pollution 

Control 

Equipment1 

SO2 Emissions in 

Rate and TPY 

Permits issue

application num

relevant 

Newton Energy Center (I.D. No. 079808AAA) 6725 North 500th

Street Newton, Illinois 

Unit 1 Nominal 5,500 mmBtu/hr (1972) 

Unit 2 Nominal 5,500 mmBtu/hr (1975) 

LNB OFA ESP with FGC Sorbent Injection 

2012 SO2

emission rate = 0.59 lb/MMBtu 2012 SO2 mass emissions = 16,520 tons 

State Operating P

July 30, 1998 App. No. 780800Unit 1 June 29, 2001 App. No. 830200Unit 2 Construction Perm

June 8, 2009 App. No. 090500Pilot Evaluation oMercury Control December 1, 200App. No. 080100Sorbent Injection and 2 

Exhibit 6 - 16 
Exhibit 6 

Ameren MPS Group Information 

(§ 104.204(b)) 

Address Boilers and Sizes Pollution 

Control 

Equipment1 

SO2 Emissions in 

Rate and TPY 

Permits issue

application num

relevant 

Newton Energy Center (I.D. No. 079808AAA) 

December 20, 20App. No. 100700Flue Gas DesulfuSystems for Unit February 25, 201App. No. 080100Revised Sorbent Alternative ContrControl for Unit June 30, 2011 App. No. 110600Additive Injection Control on Unit 2 July 28, 2011 App. No. 110700Fuel Additives SyNovember 28, 20App. No. 110700Fuel Additives fo

Exhibit 6 - 17 
Exhibit 6 

Ameren MPS Group Information 

(§ 104.204(b)) 

Exhibit 6 - 18 

Address Boilers and Sizes Pollution 

Control 

Equipment1 

SO2 Emissions in 

Rate and TPY 

Permits issue

application num

relevant 

Newton Energy Center (I.D. No. 079808AAA) 

CAAPP Permit: September 29, 20App. No. 950900Appealed Novem(PCB 06-068) Stayed February 
EXHIBIT 7

ECONOMIC IMPACT: DEVELOPMENT STRATEGIES MEMORANDA

Five Memoranda Providing Economic Data and Analysis Specific to the five operating Energy 

Centers in the Ameren MPS Group. 
DEVELOPMENT STRATEGIES® 

guiding effective decisions in 

real estate, community, and economic development 

10 South Broadway, Suite 1500  St. Louis, Missouri 63102  p 314.421.2800 WWW.DEVELOPMENT-STRATEGIES.COM

Memorandum

To: Daniel P. Thompson, Vice President, Illinois Power Holdings, LLC 

From: Robert Lewis, Brian Licari, and Yash Yedavalli 

Date: July 12, 2013 

Re: Economic Impacts of Coffeen Energy Center of Illinois and Surrounding Labor Market Area 

In April, 2012, Development Strategies (DS) was commissioned by Ameren Energy Resources Corporation (AER) 

to conduct an independent analysis of the economic impact that the operations of AER’s Coffeen Energy Center 

(Montgomery County) have on the Illinois economy and on its respective multi-county economic region. Development Strategies has since been commissioned by Illinois Power Holdings to update this analysis with the latest 

available data as of July, 2013, from both AER/Ameren Services and appropriate state and federal economic data 

sources. Development Strategies is pleased to submit this analysis of the direct and indirect economic impacts for 

this facility. 

Direct economic impacts are the estimated dollars spent by AER at and in operational support of the energy center facility. For the purpose of this analysis, spending includes capital expenditures, non-payroll operations expenditures, and salaries paid to employees. 

There are 162 total jobs at the Coffeen Energy Center, 161 of whom live in Illinois. We determined which counties 

in the “region” of the energy center are home to a large majority of those employees and this determined the facility’s primary economic impact region for our impact analysis. We then calculated economic impacts within that impact region. Four Illinois counties make up the primary economic impact region in the case of Coffeen, which is

home to 113 of its 162 employees. See accompanying map “AER: Coffeen Energy Center Labor Market Area” for 

the local labor market area boundaries. 

Indirect economic impacts measure the “ripple effect” of wages and expenditures associated with AER’s direct 

spending. For instance, Coffeen employees who live in Illinois will spend a large proportion of their earnings within 

the state of Illinois for housing and at local businesses such as retail stores, restaurants, mechanics, and others. Thus, 

each job at Coffeen will contribute to additional job support across many sectors in the community and, consequently, the state of Illinois. Likewise, much of the non-labor operational spending by the energy center is initially 

spent within the state, thus supporting additional income and jobs in the immediately surrounding counties and 

throughout the state. 

To calculate these indirect impacts, multiplier coefficients are applied to the direct impact dollars; these multipliers 

also automatically take into account the amount of “leakage” from the local and state economies because some wages and expenditures will be spent outside of the regions in which they are initiated. For this reason, multiplier coefficients are finite and, therefore, measureable. 

METHODOLOGY 

The analysis of the direct and indirect economic impacts of the Coffeen Energy Center relied on spending and 

workforce information provided by AER, and on the U.S. Department of Commerce’s Regional Input-Output Multiplier System (RIMS-II). RIMS-II provides multiplier coefficients for every county in the United States. These multipliers can also be aggregated for larger regions composed of counties, such as states and, in this case, the primary 

economic impact region around the energy center. Multiplier coefficients for sub-county geographies are not available. The multipliers are determined separately for, and are unique to, each county and region for key economic sectors. The RIMS-II multipliers are updated annually by the Bureau of Economic Analysis (BEA). 
Memorandum on Economic Impacts of Coffeen Energy Center 

July 12, 2013 

DEVELOPMENT STRATEGIES 2

The economic impact analysis focuses on the multi-county region noted above and on the state as a whole. That is, 

the Coffeen Energy Center has two economic impact tables associated with it: the state and its own primary economic impact region. There are three principal multipliers for each sector: 

 Economic Output: This is defined as the total dollar change in the regional or state economy due to direct 

expenditures by AER at the energy center. Economic output is a similar measure as the nation’s gross domestic 

product but, unlike the GDP, it also includes all the intermediate values added during the production process. 

 Earnings: The earnings multiplier measures the added household earnings for the regional and state labor 

force triggered by AER’s direct spending at the energy center. 

 Employment: This is defined as the added jobs in the county per $1,000,000 of direct spending by AER in 

addition to the jobs at the energy center.1

Multipliers are provided for various economic sectors. The direct, non-labor, operational spending by AER at the 

energy center falls within the Utilities sector; the employee earnings paid by AER fall within the Households sector; 

and capital expenditures fall within the Construction sector. The RIMS-II multipliers for the selected regions are 

summarized below. To calculate the indirect economic impacts: 

 The construction multiplier coefficients for the state and region are applied to the capital expenditure figures of the 

energy center, 

 The utilities multiplier coefficients for the state and region are applied to the operational expenditures of the energy 

center, and 

 The households multiplier coefficients for the state and region are applied to the employee compensation figures of the 

energy center. Employee compensation is calculated by applying the average labor expenditure to the number 

of workers who reside in the state and region. For the purposes of this analysis, employee compensation includes salary, benefits, and any other labor related costs; therefore, the average labor expenditure per employee 

does not necessarily reflect the average wage. 

 DS estimated a weighted fuel multiplier based on the mining (except oil and gas), truck transportation, and rail transportation multipliers. Approximately 20 percent of the fuel cost was for transportation; therefore, the fuel multiplier 

was weighted accordingly.2

 

The respective direct and indirect impacts are then summed to calculate the total indirect impacts. 

CONCLUSIONS 

DS estimates that the Coffeen Energy Center has an economic impact on the Illinois economy and its primary economic impact region as shown on the following tables. Each table summarizes AER’s direct spending at the Coffeen Energy Center (top line in the table), the multipliers for Illinois or the market area, the multiplier effects resulting from AER’s operational spending, and the total direct and indirect economic impacts generated. 

 

1

The multipliers derived from U.S. Department of Labor data, however, are based on 2008 economic activity and data. So the model used in 

this report inflates the million dollars from 2008, or jobs per $1,081,940 in 2013 dollars, using the Consumer Price Index (CPI). 

2 A portion of AER’s coal comes from out-of-state sources, but since this study focuses on the impacts within the state of Illinois, only the 

expenditures for Illinois-sourced coal were considered. The Coffeen Energy Center uses Illinois-sourced coal; therefore, the impacts of these 

fuel expenditures were included in the state-wide analysis. A small portion of Coffeen’s Illinois-sourced coal comes from within its impact region; therefore, the fuel expenditures from Crown Mine in Macoupin County were considered for the economic impact region analysis.
Memorandum on Economic Impacts of Coffeen Energy Center 

July 12, 2013 

DEVELOPMENT STRATEGIES 3

IMPACTS ON THE STATE OF ILLINOIS

The top of the table shows the direct expenditures by AER at the Coffeen Energy Center averaging approximately 

$170.1 million per year from 2008 to 2012 in 2013 dollars. Employee compensation is an estimate based on the 

number of Coffeen employees that live in Illinois (161 of 162). Additional results are discussed below: 

 The $170.1 million spent by AER at Coffeen Energy Center triggered an additional $364.8 million in value added activity in Illinois, of which $106.9 million was household earnings that another supported 2,320 jobs. 

 The estimated total output (economic activity) triggered by Coffeen Energy Center’s direct operations ($170.1

million) and the added multiplier effects ($364.8 million) were $534.9 million for the Illinois economy. 

 Of that amount, Coffeen Energy Center’s operations triggered nearly $123.2 million in household earnings for 

workers in Illinois, including $16.3 million in direct compensation for employees and $106.9 million in added 

earnings from the multiplier effects. 

 In total, Coffeen Energy Center’s operations supported and annual average of 2,481 jobs for Illinois residents, 

including 161 direct jobs and approximately 2,320 jobs added through the multiplier effects. 

Fuel Expenditures

Capital

Expenditures

Operating 

Expenditures

Employee 

Compensation 2Total

Direct Spending $ 5,001,000 $ 128,878,000 $ 19,922,000 $ 16,336,000 $ 170,137,000

MULTIPLIERS

Output 2.2263 2.3293 1.5022 1.4416 2.1442

Household Earnings 0.5273 0.7145 0.2856 0.3968 0.6283

Employment3

 10.5826 15.5885 4.6006 10.4217 13.6361

ADDED ECONOMIC IMPACT ON ILLINOIS

Output $ 11,134,000 $ 300,196,000 $ 29,927,000 $ 23,550,000 $ 364,807,000

Household Earnings $ 2,637,000 $ 92,083,000 $ 5,690,000 $ 6,482,000 $ 106,892,000

Indirect Jobs Held by Illinois Residents 5 0 2,010 9 0 170 2,320

TOTAL ECONOMIC IMPACT ON ILLINOIS

Output (Total Economic Activity) $ 534,944,000

Household Earnings $ 123,228,000

 161

 2,481

3 E mployment multiplier represents jobs per $1 million in expenditures. Since the original RIMS-II multiplier is based on 2008 economic data, the 

employment multiplier presented in this table have been adjusted to jobs per $1 million in 2013 dollars using the CPI, or jobs per $1,081,940.

Annual Economic Impact of AER's Coffeen Energy Center Operations on the State of Illinois

Total Direct and Indirect Jobs at Coffeen Energy Center

1 Actual operating data from 2008-2012 adjusted to 2013 dollar amounts using the Consumer Price Index (CPI) and averaged.

2 Estimate based on number of employees who reside in Illinois (161 of 162) and overall average labor expenditure per employee.

Annual Average i n 2013 Dol l ars 1

Direct Jobs at Coffeen Energy Center (Illinois residents)
Memorandum on Economic Impacts of Coffeen Energy Center 

July 12, 2013 

DEVELOPMENT STRATEGIES 4

IMPACTS ON THE MULTI-COUNTY REGION

The top of the table shows that the direct expenditures by AER at the Coffeen Energy Center in the market area 

averaged approximately $160.5 million per year from 2008 to 2012 in 2013 dollars. This is less than for the state as a 

whole because employees outside of the market area are excluded. Employee compensation is an estimate based on 

the number of Coffeen employees that live in the labor market area (113 of 162). Additional results are discussed 

below: 

 The $160.5 million spent by AER at Coffeen Energy Center triggered an additional $228.0 million in value added activity in the market area, of which $67.6 million was household earnings that supported 1,400 jobs. The 

multipliers vary for different types of major expenditures shown at the top of the table. 

 The estimated total output (economic activity) triggered by Coffeen Energy Center’s direct operations ($160.5

million) and the added multiplier effects ($228.0 million) were $388.5 million for the market area. 

 Of that amount, Coffeen Energy Center’s operations triggered nearly $79.1 million in household earnings for 

other workers in the market area, including $11.5 million in direct compensation for employees and $79.1 million in added earnings from the multiplier effects. 

 In total, Coffeen Energy Center’s operations supported an annual average of1,513 jobs for residents of the 

market area, including 113 direct jobs and approximately 1,400 jobs added through the multiplier effects. 

Fuel Expenditures

Capital

Expenditures

Operating 

Expenditures

Employee 

Compensation 2Total

Direct Spending $ 273,000 $ 128,878,000 $ 19,922,000 $ 11,466,000 $ 160,539,000

MULTIPLIERS

Output 1.4367 1.4958 1.3635 0.6683 1.4202

Household Earnings 0.3328 0.4634 0.2920 0.1711 0.4210

Employment3

 5.6576 9.8700 3.8628 4.5419 8.7206

ADDED ECONOMIC IMPACT ON MARKET AREA

Output $ 392,000 $ 192,776,000 $ 27,164,000 $ 7,663,000 $ 227,995,000

Household Earnings $ 91,000 $ 59,722,000 $ 5,817,000 $ 1,962,000 $ 67,592,000

Indirect Jobs Held by Market Area Residents - 1,270 8 0 5 0 1,400

TOTAL ECONOMIC IMPACT ON MARKET AREA

Output (Total Economic Activity) $ 388,534,000

Household Earnings $ 79,058,000

 113

 1,513

3 E mployment multiplier represents jobs per $1 million in expenditures. Since the original RIMS-II multiplier is based on 2008 economic data, the employment 

multiplier presented in this table have been adjusted to jobs per $1 million in 2013 dollars using the CPI, or jobs per $1,081,940.

Direct Jobs at Coffeen Energy Center (market area residents)

Annual Economic Impact of AER's Coffeen Energy Center Operations on Labor Market Area

Total Direct and Indirect Jobs at Coffeen Energy Center

1 Actual operating data from 2008 to 2012 adjusted to 2013 dollar amounts using the Consumer Price Index (CPI) and averaged.

2 Estimate based on number of employees who reside in labor market area (113 of 162) and overall average labor expenditure per employee.

Annual Average i n 2013 Dol l ars 1
AER Headquarters

Duck Creek Energy Center

45%

6%

Newton Energy Center

12%

6%

6%

Missouri

Iowa

Indiana

Kentucky

Wisconsin

Michigan

Elgin Energy Center

Gibson City Energy Center

Joppa Energy Center

Grand Tower Energy Center

E.D. Edwards Energy Center

Will

Pike

Lee

Cook

Ogle

McLean

La Salle

Iroquois

Fulton

Knox

Henry

Adams

Bureau

Shelby

Livingston

Wayne

Edgar

Ford

Vermilion

Clay

Logan

Kane

Fayette

Peoria

Hancock

Piatt

Macoupin

Clark

Lake

Champaign

Macon

Madison

Coles

DeKalb

Marion

Mason

St. Clair

White

Sangamon

Mercer

Christian

Perry

Tazewell

Morgan

Warren

Jackson

Greene

Clinton

Whiteside

Jasper

Cass

Union Pope

Bond

Kankakee

Carroll

McHenry

Jefferson

Randolph

Saline

Montgomery

Grundy

Jo Daviess

Woodford

Jersey

De Witt

Franklin

Monroe

Stark

Douglas

Schuyler

McDonough

Washington

Hamilton

Crawford Effingham

Stephenson

Brown

Scott

Marshall

Winnebago

Kendall

Moultrie

Gallatin

Boone

Johnson

Williamson

DuPage

Richland

Menard

Lawrence

Rock Island

Cumberland

Hardin

Wabash

Henderson

Calhoun

Pulaski Massac

Edwards

Alexander

Putnam

AER: Coffeen Labor Market Areas

F

0 25 50

Miles

July 2013

! AER Energy Centers

Cofeen Market Area

Coffeen Employees by County

1 - 3

4 - 7

8 - 72

Source: Ameren provided employment counts by work location and county of residence, as of June 26, 2013

Coffeen Energy Center
DEVELOPMENT STRATEGIES® 

guiding effective decisions in 

real estate, community, and economic development 

10 South Broadway, Suite 1500  St. Louis, Missouri 63102  p 314.421.2800 WWW.DEVELOPMENT-STRATEGIES.COM

Memorandum

To: Daniel P. Thompson, Vice President, Illinois Power Holdings, LLC 

From: Robert Lewis, Brian Licari, and Yash Yedavalli 

Date: July 12, 2013 

Re: Economic Impacts of Duck Creek Energy Center of Illinois and Surrounding Labor Market Area 

In April, 2012, Development Strategies (DS) was commissioned by Ameren Energy Resources Corporation (AER) 

to conduct an independent analysis of the economic impact that the operations of AER’s Duck Creek Energy Center (Jasper County) have on the Illinois economy and on its respective multi-county economic region. Development 

Strategies has since been commissioned by Illinois Power Holdings to update this analysis with the latest available 

data as of July, 2013, from both AER/Ameren Services and appropriate state and federal economic data sources. 

Development Strategies is pleased to submit this analysis of the direct and indirect economic impacts for this facility. 

Direct economic impacts are the estimated dollars spent by AER at and in operational support of the energy center facility. For the purpose of this analysis, spending includes capital expenditures, non-payroll operations expenditures, and salaries paid to employees. 

There are 66 total jobs at the Duck Creek Energy Center, 65 of whom live in Illinois. We determined which counties in the “region” of the energy center are home to a large majority of those employees and this determined the 

facility’s primary economic impact region for our impact analysis. We then calculated economic impacts within that 

impact region. Three Illinois counties make up the primary economic impact region in the case of Duck Creek, 

which is home to 52 of its 66 employees. See accompanying map “AER: Duck Creek Energy Center Labor Market 

Area” for the local labor market area boundaries. 

Indirect economic impacts measure the “ripple effect” of wages and expenditures associated with AER’s direct 

spending. For instance, Duck Creek employees who live in Illinois will spend a large proportion of their earnings 

within the state of Illinois for housing and at local businesses such as retail stores, restaurants, mechanics, and others. 

Thus, each job at Duck Creek will contribute to additional job support across many sectors in the community and, 

consequently, the state of Illinois. Likewise, much of the non-labor operational spending by the energy center is 

initially spent within the state, thus supporting additional income and jobs in the immediately surrounding counties 

and throughout the state. 

To calculate these indirect impacts, multiplier coefficients are applied to the direct impact dollars; these multipliers 

also automatically take into account the amount of “leakage” from the local and state economies because some wages and expenditures will be spent outside of the regions in which they are initiated. For this reason, multiplier coefficients are finite and, therefore, measureable. 

METHODOLOGY 

The analysis of the direct and indirect economic impacts of the Duck Creek Energy Center relied on spending and 

workforce information provided by AER, and on the U.S. Department of Commerce’s Regional Input-Output Multiplier System (RIMS-II). RIMS-II provides multiplier coefficients for every county in the United States. These multipliers can also be aggregated for larger regions composed of counties, such as states and, in this case, the primary 

economic impact region around the energy center. Multiplier coefficients for sub-county geographies are not available. The multipliers are determined separately for, and are unique to, each county and region for key economic sectors. The RIMS-II multipliers are updated annually by the Bureau of Economic Analysis (BEA). 
Memorandum on Economic Impacts of Duck Creek Energy Center 

July 12, 2013 

DEVELOPMENT STRATEGIES 2

The economic impact analysis focuses on the multi-county region noted above and on the state as a whole. That is, 

the Duck Creek Energy Center has two economic impact tables associated with it: the state and its own primary 

economic impact region. There are three principal multipliers for each sector: 

 Economic Output: This is defined as the total dollar change in the regional or state economy due to direct 

expenditures by AER at the energy center. Economic output is a similar measure as the nation’s gross domestic 

product but, unlike the GDP, it also includes all the intermediate values added during the production process. 

 Earnings: The earnings multiplier measures the added household earnings for the regional and state labor 

force triggered by AER’s direct spending at the energy center. 

 Employment: This is defined as the added jobs in the county per $1,000,000 of direct spending by AER in 

addition to the jobs at the energy center.1

Multipliers are provided for various economic sectors. The direct, non-labor, operational spending by AER at the 

energy center falls within the Utilities sector; the employee earnings paid by AER fall within the Households sector; 

and capital expenditures fall within the Construction sector. The RIMS-II multipliers for the selected regions are 

summarized below. To calculate the indirect economic impacts: 

 The construction multiplier coefficients for the state and region are applied to the capital expenditure figures of the 

energy center, 

 The utilities multiplier coefficients for the state and region are applied to the operational expenditures of the energy 

center, and 

 The households multiplier coefficients for the state and region are applied to the employee compensation figures of the 

energy center. Employee compensation is calculated by applying the average labor expenditure to the number 

of workers who reside in the state and region. For the purposes of this analysis, employee compensation includes salary, benefits, and any other labor related costs; therefore, the average labor expenditure per employee 

does not necessarily reflect the average wage. 

 DS estimated a weighted fuel multiplier based on the mining (except oil and gas), truck transportation, and rail transportation multipliers. Approximately 20 percent of the fuel cost was for transportation; therefore, the fuel multiplier 

was weighted accordingly.2

 

The respective direct and indirect impacts are then summed to calculate the total indirect impacts. 

CONCLUSIONS 

DS estimates that the Duck Creek Energy Center has an economic impact on the Illinois economy and its primary 

economic impact region as shown on the following tables. Each table summarizes AER’s direct spending at the

Duck Creek Energy Center (top line in the table), the multipliers for Illinois or the market area, the multiplier effects 

resulting from AER’s operational spending, and the total direct and indirect economic impacts generated. 

 

1

The multipliers derived from U.S. Department of Labor data, however, are based on 2008 economic activity and data. So the model used in 

this report inflates the million dollars from 2008, or jobs per $1,081,940 in 2013 dollars, using the Consumer Price Index (CPI). 

2 A portion of AER’s coal comes from out-of-state sources, but since this study focuses on the impacts within the state of Illinois, only the 

expenditures for Illinois-sourced coal were considered. The Duck Creek Energy Center uses Illinois-sourced coal; therefore, the impacts of 

these fuel expenditures were included in the state-wide analysis. Duck Creek’s Illinois-sourced coal does not come from within its impact region; therefore, the fuel expenditures are not considered for the regional analysis.
Memorandum on Economic Impacts of Duck Creek Energy Center 

July 12, 2013 

DEVELOPMENT STRATEGIES 3

IMPACTS ON THE STATE OF ILLINOIS

The top of the table shows the direct expenditures by AER at the Duck Creek Energy Center averaging approximately $97.8 million per year from 2008 to 2012 in 2013 dollars. Employee compensation is an estimate based on 

the number of Duck Creek employees that live in Illinois (65 of 66). Additional results are discussed below: 

 The $97.8 million spent by AER at Duck Creek Energy Center triggered an additional $209.7 million in value 

added activity in Illinois, of which $58.9 million was household earnings that supported another 1,260 jobs. 

 The estimated total output (economic activity) triggered by Duck Creek Energy Center’s direct operations 

($97.8 million) and the added multiplier effects ($209.7 million) were $307.4 million for the Illinois economy. 

 Of that amount, Duck Creek Energy Center’s operations triggered nearly $66.6 million in household earnings 

for workers in Illinois, including $7.7 million in direct compensation for employees and $58.9 million in added 

earnings from the multiplier effects. 

 In total, Duck Creek Energy Center’s operations supported 1,325 jobs for Illinois residents, including 65 direct 

jobs and approximately 1,260 jobs added through the multiplier effects. 

Fuel Expenditures

Capital

Expenditures

Operating 

Expenditures

Employee 

Compensation 2Total

Direct Spending $ 19,883,000 $ 59,091,000 $ 11,123,000 $ 7,666,000 $ 97,763,000

MULTIPLIERS

Output 2.2263 2.3293 1.5022 1.4416 2.1446

Household Earnings 0.5273 0.7145 0.2856 0.3968 0.6027

Employment3

 10.5826 15.5885 4.6006 10.4217 12.8883

ADDED ECONOMIC IMPACT ON ILLINOIS

Output $ 44,265,000 $ 137,641,000 $ 16,709,000 $ 11,051,000 $ 209,666,000

Household Earnings $ 10,484,000 $ 42,221,000 $ 3,177,000 $ 3,042,000 $ 58,924,000

Indirect Jobs Held by Illinois Residents 210 920 5 0 8 0 1,260

TOTAL ECONOMIC IMPACT ON ILLINOIS

Output (Total Economic Activity) $ 307,429,000

Household Earnings $ 66,590,000

 6 5

 1,325

3 E mployment multiplier represents jobs per $1 million in expenditures. Since the original RIMS-II multiplier is based on 2008 economic data, the 

employment multipliers presented in this table have been adjusted to jobs per $1 million in 2013 dollars using the CPI, or jobs per $1,081,940.

Annual Economic Impact of AER's Duck Creek Energy Center Operations on the State of Illinois

Total Direct and Indirect Jobs at Duck Creek Energy Center

1 Actual operating data from 2008-2012 adjusted to 2013 dollar amounts using the Consumer Price Index (CPI) and averaged.

2 Estimate based on number of employees who reside in Illinois (65 of 66) and overall average labor expenditure per employee.

Annual Average i n 2013 Dol l ars 1

Direct Jobs at Duck Creek Energy Center (Illinois residents)
Memorandum on Economic Impacts of Duck Creek Energy Center 

July 12, 2013 

DEVELOPMENT STRATEGIES 4

IMPACTS ON THE MULTI-COUNTY REGION

The top of the table shows that the direct expenditures by AER at the Duck Creek Energy Center in the market area 

averaged approximately $76.3 million per year from 2008 to 2012 in 2013 dollars. This is less than for the state as a 

whole because employees outside of the market area are excluded. Employee compensation is an estimate based on 

the number of Duck Creek employees that live in the labor market area (52 of 66). Additional results are discussed 

below: 

 The $76.3 million spent by AER at Duck Creek Energy Center triggered an additional $113.9 million in value 

added activity in the market area, of which $32.7 million was household earnings that supported 710 jobs. The 

multipliers vary for different types of major expenditures shown at the top of the table. 

 The estimated total output (economic activity) triggered by Duck Creek Energy Center’s direct operations 

($76.3 million) and the added multiplier effects ($113.9 million) were $190.2 million for the market area. 

 Of that amount, Duck Creek Energy Center’s operations triggered nearly $38.8 million in household earnings 

for other workers in the market area, including $6.1 million in direct compensation for employees and $32.7

million in added earnings from the multiplier effects. 

 In total, Duck Creek Energy Center’s operations supported an annual average of 762 jobs for residents of the 

market area, including 52 direct jobs and approximately 710 jobs added through the multiplier effects. 

Capital

Expenditures

Operating 

Expenditures

Employee 

Compensation 2Total

Direct Spending $ 59,091,000 $ 11,123,000 $ 6,132,000 $ 76,346,000

MULTIPLIERS

Output 1.613 1.218 0.813 1.491

Household Earnings 0.492 0.199 0.218 0.428

Employment3

 10.758 2.847 6.219 9.300

ADDED ECONOMIC IMPACT ON MARKET AREA

Output $ 95,332,000 $ 13,542,000 $ 4,985,000 $ 113,859,000

Household Earnings $ 29,096,000 $ 2,217,000 $ 1,337,000 $ 32,650,000

Indirect Jobs Held by Market Area Residents 640 3 0 4 0 710

TOTAL ECONOMIC IMPACT ON MARKET AREA

Output (Total Economic Activity) $ 190,205,000

Household Earnings $ 38,782,000

 5 2

 762

3

E mployment multiplier represents jobs per $1 million in expenditures. Since the original RIMS-II multiplier is based on 2008 economic 

data, the employment multiplier presented in this table have been adjusted to jobs per $1 million in 2013 dollars using the CPI, or jobs 

per $1,081,940.

Direct Jobs at Duck Creek Energy Center (market area residents)

Annual Economic Impact of AER's Duck Creek Energy Center Operations on Labor Market Area

Annual Average i n 2013 Dol l ars 1

Total Direct and Indirect Jobs at Duck Creek Energy Center

1 Actual operating data from 2008 to 2012 adjusted to 2013 dollar amounts using the Consumer Price Index (CPI) and averaged.

2 Estimate based on number of employees who reside in labor market area (52 of 66) and overall average labor expenditure per employee.
AER Headquarters

Coffeen Energy Center

20%

43%

17%

Newton Energy Center

Missouri

Iowa

Indiana

Kentucky

Wisconsin

Michigan

Elgin Energy Center

Gibson City Energy Center

Joppa Energy Center

Grand Tower Energy Center

E.D. Edwards Energy Center

Will

Pike

Lee

Cook

Ogle

McLean

La Salle

Iroquois

Fulton

Knox

Henry

Adams

Bureau

Shelby

Livingston

Wayne

Edgar

Ford

Vermilion

Clay

Logan

Kane

Fayette

Peoria

Hancock

Piatt

Macoupin

Clark

Lake

Champaign

Macon

Madison

Coles

DeKalb

Marion

Mason

St. Clair

White

Sangamon

Mercer

Christian

Perry

Tazewell

Morgan

Warren

Jackson

Greene

Clinton

Whiteside

Jasper

Cass

Union Pope

Bond

Kankakee

Carroll

McHenry

Jefferson

Randolph

Saline

Montgomery

Grundy

Jo Daviess

Woodford

Jersey

De Witt

Franklin

Monroe

Stark

Douglas

Schuyler

McDonough

Washington

Hamilton

Crawford Effingham

Stephenson

Brown

Scott

Marshall

Winnebago

Kendall

Moultrie

Gallatin

Boone

Johnson

Williamson

DuPage

Richland

Menard

Lawrence

Rock Island

Cumberland

Hardin

Wabash

Henderson

Calhoun

Pulaski Massac

Edwards

Alexander

Putnam

AER: Duck Creek Labor Market Areas

F

0 25 50

Miles

July 2013

! Ameren Energy Centers

Duck Creek Market Area

Duck Creek Employees by County

1 Or Less

2 - 11

12 - 28

Source: Ameren provided employment counts by work location and county of residence, as of June 26, 2013

Duck Creek Energy Center
DEVELOPMENT STRATEGIES® 

guiding effective decisions in 

real estate, community, and economic development 

10 South Broadway, Suite 1500  St. Louis, Missouri 63102  p 314.421.2800 WWW.DEVELOPMENT-STRATEGIES.COM

Memorandum

To: Daniel P. Thompson, Vice President, Illinois Power Holdings, LLC 

From: Robert Lewis, Brian Licari, and Yash Yedavalli 

Date: July 12, 2013 

Re: Economic Impacts of E.D. Edwards Energy Center of Illinois and Surrounding Labor Market Area 

In April, 2012, Development Strategies (DS) was commissioned by Ameren Energy Resources Corporation (AER) 

to conduct an independent analysis of the economic impact that the operations of AER’s E.D. Edwards Energy 

Center (Peoria County) have on the Illinois economy and on its respective multi-county economic region. Development Strategies has since been commissioned by Illinois Power Holdings to update this analysis with the latest 

available data as of July, 2013, from both AER/Ameren Services and appropriate state and federal economic data 

sources. Development Strategies is pleased to submit this analysis of the direct and indirect economic impacts for 

this facility. 

Direct economic impacts are the estimated dollars spent by AER at and in operational support of the energy center facility. For the purpose of this analysis, spending includes capital expenditures, non-payroll operations expenditures, and salaries paid to employees. 

There are 111 total jobs at the E.D. Edwards Energy Center, all of whom live in Illinois. We determined which 

counties in the “region” of the energy center are home to a large majority of those employees and this determined 

the facility’s primary economic impact region for our impact analysis. We then calculated economic impacts within 

that impact region. Three Illinois counties make up the primary economic impact region in the case of Edwards, 

which is home to 95 of its 111 employees. See accompanying map “AER: E.D. Edwards Energy Center Labor 

Market Area” for the local labor market area boundaries. 

Indirect economic impacts measure the “ripple effect” of wages and expenditures associated with AER’s direct 

spending. For instance, Edwards employees who live in Illinois will spend a large proportion of their earnings within the state of Illinois for housing and at local businesses such as retail stores, restaurants, mechanics, and others. 

Thus, each job at Edwards will contribute to additional job support across many sectors in the community and, consequently, the state of Illinois. Likewise, much of the non-labor operational spending by the energy center is initially 

spent within the state, thus supporting additional income and jobs in the immediately surrounding counties and 

throughout the state. 

To calculate these indirect impacts, multiplier coefficients are applied to the direct impact dollars; these multipliers 

also automatically take into account the amount of “leakage” from the local and state economies because some wages and expenditures will be spent outside of the regions in which they are initiated. For this reason, multiplier coefficients are finite and, therefore, measureable. 

METHODOLOGY 

The analysis of the direct and indirect economic impacts of the E.D. Edwards Energy Center relied on spending and 

workforce information provided by AER, and on the U.S. Department of Commerce’s Regional Input-Output Multiplier System (RIMS-II). RIMS-II provides multiplier coefficients for every county in the United States. These multipliers can also be aggregated for larger regions composed of counties, such as states and, in this case, the primary 

economic impact region around the energy center. Multiplier coefficients for sub-county geographies are not available. The multipliers are determined separately for, and are unique to, each county and region for key economic sectors. The RIMS-II multipliers are updated annually by the Bureau of Economic Analysis (BEA). 
Memorandum on Economic Impacts of E.D. Edwards Energy Center 

July 12, 2013 

DEVELOPMENT STRATEGIES 2

The economic impact analysis focuses on the multi-county region noted above and on the state as a whole. That is, 

the E.D. Edwards Energy Center has two economic impact tables associated with it: the state and its own primary 

economic impact region. There are three principal multipliers for each sector: 

 Economic Output: This is defined as the total dollar change in the regional or state economy due to direct 

expenditures by AER at the energy center. Economic output is a similar measure as the nation’s gross domestic 

product but, unlike the GDP, it also includes all the intermediate values added during the production process. 

 Earnings: The earnings multiplier measures the added household earnings for the regional and state labor 

force triggered by AER’s direct spending at the energy center. 

 Employment: This is defined as the added jobs in the county per $1,000,000 of direct spending by AER in 

addition to the jobs at the energy center.1

Multipliers are provided for various economic sectors. The direct, non-labor, operational spending by AER at the 

energy center falls within the Utilities sector; the employee earnings paid by AER fall within the Households sector; 

and capital expenditures fall within the Construction sector. The RIMS-II multipliers for the selected regions are 

summarized below. To calculate the indirect economic impacts: 

 The construction multiplier coefficients for the state and region are applied to the capital expenditure figures of the 

energy center, 

 The utilities multiplier coefficients for the state and region are applied to the operational expenditures of the energy 

center, and 

 The households multiplier coefficients for the state and region are applied to the employee compensation figures of the 

energy center. Employee compensation is calculated by applying the average labor expenditure to the number 

of workers who reside in the state and region. For the purposes of this analysis, employee compensation includes salary, benefits, and any other labor related costs; therefore, the average labor expenditure per employee 

does not necessarily reflect the average wage. 

The respective direct and indirect impacts are then summed to calculate the total indirect impacts. 

Note: Fuel expenditures for coal were not considered for this analysis. AER’s coal comes from in-state and out-ofstate sources. In the case of Edwards Energy Center, all of its coal comes from out-of-state sources. Since this 

study focuses on the impacts within the state of Illinois, only the expenditures for Illinois-sourced coal should be 

considered. Though a small portion of Edwards’s fuel expenditures likely occur within Illinois (e.g. transportation 

costs), the vast majority of these expenditures occur outside of Illinois; therefore, we are uncomfortable assuming 

that the standard RIMS-II multipliers account for this scale of immediate leakage. Including fuel expenditures in this 

analysis, therefore, could overstate the local and statewide impacts. 

CONCLUSIONS 

DS estimates that the Edwards Energy Center has an economic impact on the Illinois economy and its primary economic impact region as shown on the following tables. Each table summarizes AER’s direct spending at the Edwards Energy Center (top line in the table), the multipliers for Illinois or the market area, the multiplier effects resulting from AER’s operational spending, and the total direct and indirect economic impacts generated. 

 

1

The multipliers derived from U.S. Department of Labor data, however, are based on 2008 economic activity and data. So the model used in 

this report inflates the million dollars from 2008, or jobs per $1,081,940 in 2013 dollars, using the Consumer Price Index (CPI). 
Memorandum on Economic Impacts of E.D. Edwards Energy Center 

July 12, 2013 

DEVELOPMENT STRATEGIES 3

IMPACTS ON THE STATE OF ILLINOIS

The top of the table shows the direct expenditures by AER at the E.D. Edwards Energy Center averaging approximately $39.2 million per year from 2008 to 2012 in 2013 dollars. Employee compensation is the total labor cost at 

the energy center since all of the employees live in Illinois. Additional results are discussed below: 

 The $39.2 million spent by AER at E.D. Edwards Energy Center triggered an additional $68.9 million in value 

added activity in Illinois, of which $18.0 million was household earnings that another supported 360 jobs. 

 The estimated total output (economic activity) triggered by E.D. Edwards Energy Center’s direct operations 

($39.2million) and the added multiplier effects ($68.9 million) were $108.1 million for the Illinois economy. 

 Of that amount, E.D. Edwards Energy Center’s operations triggered nearly $29.9 million in household earnings 

for workers in Illinois, including $11.9 million in direct compensation for employees and $18.0 million in added 

earnings from the multiplier effects. 

 In total, E.D. Edwards Energy Center’s operations supported 471 jobs for Illinois residents, including 111 direct 

jobs and approximately 360 jobs added through the multiplier effects. 

Capital

Expenditures

Operating 

Expenditures

Employee 

Compensation 2Total

Direct Spending $ 12,864,000 $ 14,488,000 $ 11,893,000 $ 39,245,000

MULTIPLIERS

Output 2.3293 1.5022 1.4416 1.7549

Household Earnings 0.7145 0.2856 0.3968 0.4599

Employment3

 14.4079 4.2522 9.6324 9.1731

ADDED ECONOMIC IMPACT ON ILLINOIS

Output $ 29,964,000 $ 21,764,000 $ 17,145,000 $ 68,873,000

Household Earnings $ 9,191,000 $ 4,138,000 $ 4,719,000 $ 18,048,000

Indirect Jobs Held by Illinois Residents 190 6 0 110 360

TOTAL ECONOMIC IMPACT ON ILLINOIS

Output (Total Economic Activity) $ 108,118,000

Household Earnings $ 29,941,000

 111

 471

3

E mployment multiplier represents jobs per $1 million in expenditures. Since the original RIMS-II multiplier is based on 2008 economic 

data, the employment multipliers presented in this table have been adjusted to jobs per $1 million in 2013 dollars using the CPI, or jobs 

per $1,081,940.

Direct Jobs at Edwards Energy Center (Illinois residents)

Annual Economic Impact of AER's Edwards Energy Center Operations on the State of Illinois

Annual Average i n 2013 Dol l ars 1

Total Direct and Indirect Jobs at Edwards Energy Center

1 Actual operating data from 2008-2012 adjusted to 2013 dollar amounts using the Consumer Price Index (CPI) and averaged.

2 All of the employees at Edwards Energy Center live in the state of Illinois (111 total).
Memorandum on Economic Impacts of E.D. Edwards Energy Center 

July 12, 2013 

DEVELOPMENT STRATEGIES 4

IMPACTS ON THE MULTI-COUNTY REGION

The top of the table shows that the direct expenditures by AER at the E.D. Edwards Energy Center in the market 

area averaged approximately $37.5 million per year from 2008 to 2012 in 2013 dollars. This is less than for the state 

as a whole because employees living outside of the market area are excluded. Employee compensation is an estimate based on the number of Edwards employees that live in the labor market area (95 of 111). Additional results 

are discussed below: 

 The $37.5 million spent by AER at E.D. Edwards Energy Center triggered an additional $46.6 million in value 

added activity in the market area, of which $11.6 million was household earnings that supported 240 jobs. The 

multipliers vary for different types of major expenditures shown at the top of the table. 

 The estimated total output (economic activity) triggered by E.D. Edwards Energy Center’s direct operations 

($37.5 million) and the added multiplier effects ($46.6 million) were $84.1 million for the market area. 

 Of that amount, E.D. Edwards Energy Center’s operations triggered nearly $21.8 million in household earnings 

for other workers in the market area, including $10.2 million in direct compensation for employees and $11.6 

million in added earnings from the multiplier effects. 

 In total, E.D. Edwards Energy Center’s operations supported an annual average of 335 jobs for residents of the 

market area, including 95 direct jobs and approximately 240 jobs added through the multiplier effects. 

Capital

Expenditures

Operating 

Expenditures

Employee 

Compensation 2

Total

Direct Spending $ 12,864,000 $ 14,488,000 $ 10,179,000 $ 37,531,000

MULTIPLIERS

Output 1.6128 1.2198 0.8047 1.2419

Household Earnings 0.4988 0.2052 0.2175 0.3092

Employment3

10.8857 2.9230 6.1929 6.3947

ADDED ECONOMIC IMPACT ON MARKET AREA

Output $ 20,747,000 $ 17,672,000 $ 8,191,000 $ 46,610,000

Household Earnings $ 6,417,000 $ 2,973,000 $ 2,214,000 $ 11,604,000

Indirect Jobs Held by Area Residents 140 4 0 6 0 240

TOTAL ECONOMIC IMPACT ON MARKET AREA

Output (Total Economic Activity) $ 84,141,000

Household Earnings $ 21,783,000

 9 5

 335

3 E mployment multiplier represents jobs per $1 million in expenditures. Since the original RIMS-II multiplier is based on 2008 economic data, 

the employment multiplier presented in this table have been adjusted to jobs per $1 million in 2013 dollars using the CPI, or jobs per 

$1,081,940.

Direct Jobs at Edwards Energy Center (market area residents)

2Estimate based on number of employees who reside in market area (95 of 111) and overall average labor expenditure per employee.

Annual Economic Impact of AER's Edwards Energy Center Operations on Market Area

Annual Average i n 2013 Dol l ars 1

Total Direct and Indirect Jobs at Edwards Energy Center

1 Actual operating data from 2008-2012 adjusted to 2013 dollar amounts using the Consumer Price Index (CPI) and averaged.
AER Headquarters

Duck Creek Energy Center

Coffeen Energy Center

Newton Energy Center

Grand Tower Energy Center

30%

4%

43%

9%

Missouri

Iowa

Indiana

Kentucky

Wisconsin

Michigan

Elgin Energy Center

Gibson City Energy Center

Joppa Energy Center

Will

Pike

Lee

Cook

Ogle

McLean

La Salle

Iroquois

Fulton

Knox

Henry

Adams

Bureau

Shelby

Livingston

Wayne

Edgar

Ford

Vermilion

Clay

Logan

Kane

Fayette

Peoria

Hancock

Piatt

Macoupin

Clark

Lake

Champaign

Macon

Madison

Coles

DeKalb

Marion

Mason

St. Clair

White

Sangamon

Mercer

Christian

Perry

Tazewell

Morgan

Warren

Jackson

Greene

Clinton

Whiteside

Jasper

Cass

Union Pope

Bond

Kankakee

Carroll

McHenry

Jefferson

Randolph

Saline

Montgomery

Grundy

Jo Daviess

Woodford

Jersey

De Witt

Franklin

Monroe

Stark

Douglas

Schuyler

McDonough

Washington

Hamilton

Crawford Effingham

Stephenson

Brown

Scott

Marshall

Winnebago

Kendall

Moultrie

Gallatin

Boone

Johnson

Williamson

DuPage

Richland

Menard

Lawrence

Rock Island

Cumberland

Hardin

Wabash

Henderson

Calhoun

Pulaski Massac

Edwards

Alexander

Putnam

AER: E.D. Edwards Labor Market Areas

F

0 25 50

Miles

July 2013

! AER Energy Centers

E.D. Edwards Labor Market

Edwards_13

1 - 3

4 - 10

11 - 48

Source: Ameren provided employment counts by work location and county of residence, as of June 26, 2013

E.D. Edwards Energy Center
DEVELOPMENT STRATEGIES® 

guiding effective decisions in 

real estate, community, and economic development 

10 South Broadway, Suite 1500  St. Louis, Missouri 63102  p 314.421.2800 WWW.DEVELOPMENT-STRATEGIES.COM

Memorandum

To: Daniel P. Thompson, Vice President, Illinois Power Holdings, LLC 

From: Robert Lewis, Brian Licari, and Yash Yedavalli 

Date: July 12, 2013 

Re: Economic Impacts of Joppa Energy Center of Illinois and Surrounding Labor Market Area 

In April, 2012, Development Strategies (DS) was commissioned by Ameren Energy Resources Corporation (AER) 

to conduct an independent analysis of the economic impact that the operations of AER’s Joppa Energy Center 

(Massac County) have on the Illinois economy and on its respective multi-county economic region. Development 

Strategies has since been commissioned by Illinois Power Holdings to update this analysis with the latest available 

data as of July, 2013, from both AER/Ameren Services and appropriate state and federal economic data sources. 

Development Strategies is pleased to submit this analysis of the direct and indirect economic impacts for this facility. 

Direct economic impacts are the estimated dollars spent by AER at and in operational support of the energy center facility. For the purpose of this analysis, spending includes capital expenditures, non-payroll operations expenditures, and salaries paid to employees. 

There are 176 total jobs at the Joppa Energy Center, 125 of whom live in Illinois. We determined which counties in 

the “region” of the energy center are home to a large majority of those employees and this determined the facility’s 

primary economic impact region for our impact analysis. We then calculated economic impacts within that impact 

region. Three Illinois counties make up the primary economic impact region in the case of Joppa, which is home to 

109 of its 143 employees; additionally, Joppa has 51 of its 176 employees residing in the neighboring state of Kentucky See accompanying map “AER: Joppa Energy Center Labor Market Area” for the local labor market area 

boundaries. 

Indirect economic impacts measure the “ripple effect” of wages and expenditures associated with AER’s direct 

spending. For instance, Joppa employees who live in Illinois will spend a large proportion of their earnings within 

the state of Illinois for housing and at local businesses such as retail stores, restaurants, mechanics, and others. Thus, 

each job at Joppa will contribute to additional job support across many sectors in the community and, consequently, 

the state of Illinois. Likewise, much of the non-labor operational spending by the energy center is initially spent 

within the state, thus supporting additional income and jobs in the immediately surrounding counties and throughout the state. 

To calculate these indirect impacts, multiplier coefficients are applied to the direct impact dollars; these multipliers 

also automatically take into account the amount of “leakage” from the local and state economies because some wages and expenditures will be spent outside of the regions in which they are initiated. For this reason, multiplier coefficients are finite and, therefore, measureable. 

METHODOLOGY 

The analysis of the direct and indirect economic impacts of the Joppa Energy Center relied on spending and workforce information provided by AER, and on the U.S. Department of Commerce’s Regional Input-Output Multiplier 

System (RIMS-II). RIMS-II provides multiplier coefficients for every county in the United States. These multipliers 

can also be aggregated for larger regions composed of counties, such as states and, in this case, the primary economic impact region around the energy center. Multiplier coefficients for sub-county geographies are not available. The 

multipliers are determined separately for, and are unique to, each county and region for key economic sectors. The 

RIMS-II multipliers are updated annually by the Bureau of Economic Analysis (BEA). 
Memorandum on Economic Impacts of Joppa Energy Center 

July 12, 2013 

DEVELOPMENT STRATEGIES 2

The economic impact analysis focuses on the multi-county region noted above and on the state as a whole. That is, 

the Joppa Energy Center has two economic impact tables associated with it: the state and its own primary economic 

impact region. There are three principal multipliers for each sector: 

 Economic Output: This is defined as the total dollar change in the regional or state economy due to direct 

expenditures by AER at the energy center. Economic output is a similar measure as the nation’s gross domestic 

product but, unlike the GDP, it also includes all the intermediate values added during the production process. 

 Earnings: The earnings multiplier measures the added household earnings for the regional and state labor 

force triggered by AER’s direct spending at the energy center. 

 Employment: This is defined as the added jobs in the county per $1,000,000 of direct spending by AER in 

addition to the jobs at the energy center.1

Multipliers are provided for various economic sectors. The direct, non-labor, operational spending by AER at the 

energy center falls within the Utilities sector; the employee earnings paid by AER fall within the Households sector; 

and capital expenditures fall within the Construction sector. The RIMS-II multipliers for the selected regions are 

summarized below. To calculate the indirect economic impacts: 

 The construction multiplier coefficients for the state and region are applied to the capital expenditure figures of the 

energy center, 

 The utilities multiplier coefficients for the state and region are applied to the operational expenditures of the energy 

center, and 

 The households multiplier coefficients for the state and region are applied to the employee compensation figures of the 

energy center. Employee compensation is calculated by applying the average labor expenditure to the number 

of workers who reside in the state and region. For the purposes of this analysis, employee compensation includes salary, benefits, and any other labor related costs; therefore, the average labor expenditure per employee 

does not necessarily reflect the average wage. 

The respective direct and indirect impacts are then summed to calculate the total indirect impacts. 

Note: Fuel expenditures for coal were not considered for this analysis. AER’s coal comes from in-state and out-ofstate sources. In the case of Joppa Energy Center, all of its coal comes from out-of-state sources. Since this study 

focuses on the impacts within the state of Illinois, only the expenditures for Illinois-sourced coal should be considered. Though a small portion of Joppa’s fuel expenditures likely occur within Illinois (e.g. transportation costs), the 

vast majority of these expenditures occur outside of Illinois; therefore, we are uncomfortable assuming that the 

standard RIMS-II multipliers account for this scale of immediate leakage. Including fuel expenditures in this analysis, therefore, could overstate the local and statewide impacts. 

CONCLUSIONS 

DS estimates that the Joppa Energy Center has an economic impact on the Illinois economy and its primary economic impact region as shown on the following tables. Each table summarizes AER’s direct spending at the Joppa 

Energy Center (top line in the table), the multipliers for Illinois or the market area, the multiplier effects resulting 

from AER’s operational spending, and the total direct and indirect economic impacts generated. 

 

1

The multipliers derived from U.S. Department of Labor data, however, are based on 2008 economic activity and data. So the model used in 

this report inflates the million dollars from 2008, or jobs per $1,081,940 in 2013 dollars, using the Consumer Price Index (CPI). 
Memorandum on Economic Impacts of Joppa Energy Center 

July 12, 2013 

DEVELOPMENT STRATEGIES 3

IMPACTS ON THE STATE OF ILLINOIS

The top of the table shows the direct expenditures by AER at the Joppa Energy Center averaging approximately 

$70.3 million per year from 2008 to 2012 in 2013 dollars. Employee compensation is an estimate based on the 

number of Joppa employees that live in Illinois (125 of 176). Additional results are discussed below: 

 The $70.3 million spent by AER at Joppa Energy Center triggered an additional $123.2 million in value added 

activity in Illinois, of which $31.3 million was household earnings that another supported 600 jobs. 

 The estimated total output (economic activity) triggered by Joppa Energy Center’s direct operations ($70.3 million) and the added multiplier effects ($123.2 million) were $193.5 million for the Illinois economy. 

 Of that amount, Joppa Energy Center’s operations triggered nearly $46.0 million in household earnings for 

workers in Illinois, including $14.7 million in direct compensation for employees and $31.3 million in added 

earnings from the multiplier effects. 

 In total, Joppa Energy Center’s operations supported 725 jobs for Illinois residents, including 125 direct jobs 

and approximately 600 jobs added through the multiplier effects. 

Capital

Expenditures

Operating 

Expenditures

Employee 

Compensation 2Total

Direct Spending $ 22,380,000 $ 33,226,000 $ 14,696,000 $ 70,302,000

MULTIPLIERS

Output 2.3293 1.5022 1.4416 1.7528

Household Earnings 0.7145 0.2856 0.3968 0.4454

Employment3

 14.4079 4.2522 9.6324 8.5346

ADDED ECONOMIC IMPACT ON ILLINOIS

Output $ 52,130,000 $ 49,912,000 $ 21,186,000 $ 123,228,000

Household Earnings $ 15,991,000 $ 9,489,000 $ 5,831,000 $ 31,311,000

Indirect Jobs Held by Illinois Residents 320 140 140 600

TOTAL ECONOMIC IMPACT ON ILLINOIS

Output (Total Economic Activity) $ 193,530,000

Household Earnings $ 46,007,000

 125

 725

3

E mployment multiplier represents jobs per $1 million in expenditures. Since the original RIMS-II multiplier is based on 2008 

economic data, the employment multipliers presented in this table have been adjusted to jobs per $1 million in 2013 dollars using the 

CPI, or jobs per $1,081,940.

Direct Jobs at Joppa Energy Center (Illinois residents)

2 Estimate based on number of employees who reside in Illinois (125 of 176) and overall average labor expenditure per employee

Annual Economic Impact of AER's Joppa Energy Center Operations on the State of Illinois

Annual Average i n 2013 Dol l ars 1

Total Direct and Indirect Jobs at Joppa Energy Center

1 Actual operating data from 2008-2012 adjusted to 2013 dollar amounts using the Consumer Price Index (CPI) and averaged.
Memorandum on Economic Impacts of Joppa Energy Center 

July 12, 2013 

DEVELOPMENT STRATEGIES 4

IMPACTS ON THE MULTI-COUNTY REGION

The top of the table shows that the direct expenditures by AER at the Joppa Energy Center in the market area averaged approximately $67.4 million per year from 2008 to 2012 in 2013 dollars. This is less than for the state as a 

whole because employees outside of the market area are excluded. Employee compensation is an estimate based on 

the number of Joppa employees that live in the labor market area (100 of 176). Additional results are discussed below: 

 The $67.4 million spent by AER at Joppa Energy Center triggered an additional $70.1 million in value added 

activity in the market area, of which $13.7 million was household earnings that supported 240 jobs. The multipliers vary for different types of major expenditures shown at the top of the table. 

 The estimated total output (economic activity) triggered by Joppa Energy Center’s direct operations ($67.4 million) and the added multiplier effects ($70.1 million) were $137.5 million for the market area. 

 Of that amount, Joppa Energy Center’s operations triggered nearly $25.5 million in household earnings for other workers in the market area, including $11.8 million in direct compensation for employees and $13.7 million in 

added earnings from the multiplier effects. 

 In total, Joppa Energy Center’s operations supported an annual average of 340 jobs for residents of the market 

area, including 100 direct jobs and approximately 240 jobs added through the multiplier effects. 

Capital

Expenditures

Operating 

Expenditures

Employee 

Compensation 2Total

Direct Spending $ 22,380,000 $ 33,226,000 $ 11,757,000 $ 67,363,000

MULTIPLIERS

Output 1.2842 1.1111 0.3814 1.0412

Household Earnings 0.3295 0.1606 0.0867 0.2038

Employment3

 6.8812 1.9310 2.7508 3.5628

ADDED ECONOMIC IMPACT ON MARKET AREA

Output $ 28,740,000 $ 36,917,000 $ 4,484,000 $ 70,141,000

Household Earnings $ 7,374,000 $ 5,336,000 $ 1,019,000 $ 13,729,000

Indirect Jobs Held by Area Residents 150 6 0 3 0 240

TOTAL ECONOMIC IMPACT ON MARKET AREA

Output (Total Economic Activity) $ 137,504,000

Household Earnings $ 25,486,000

 100

 340

3

E mployment multiplier represents jobs per $1 million in expenditures. Since the original RIMS-II multiplier is based on 2008 economic 

data, the employment multiplier presented in this table have been adjusted to jobs per $1 million in 2013 dollars using the CPI, or jobs per 

$1,081,940.

Direct Jobs at Joppa Energy Center (market area residents)

2

Estimate based on number of employees who reside in market area (100 of 176) and overall average labor expenditure per employee.

Annual Economic Impact of AER's Joppa Energy Center Operations on Market Area

Annual Average i n 2013 Dol l ars 1

Total Direct and Indirect Jobs at Joppa Energy Center

1

Actual operating data from 2008-2012 adjusted to 2013 dollar amounts and averaged.
AER Headquarters

Duck Creek Energy Center

Coffeen Energy Center

Newton Energy Center

Duck Creek Energy Center

Grand Tower Energy Center

Missouri

Iowa

Indiana

Kentucky

Wisconsin

Michigan

Elgin Energy Center

Gibson City Energy Center

0.6% 3.4%

2.8%

3.4%

3.4% 5.7%

0.6% 5.7% 45.5%

Will

Pike

Lee

Cook

Ogle

McLean

La Salle

Iroquois

Fulton

Knox

Henry

Adams

Bureau

Shelby

Livingston

Wayne

Edgar

Ford

Vermilion

Clay

Logan

Kane

Fayette

Peoria

Hancock

Piatt

Macoupin

Clark

Lake

Champaign

Macon

Madison

Coles

DeKalb

Marion

Mason

St. Clair

White

Sangamon

Mercer

Christian

Perry

Tazewell

Morgan

Warren

Jackson

Greene

Clinton

Whiteside

Jasper

Cass

Pope

Bond

Kankakee

Carroll

McHenry

Jefferson

Randolph

Saline

Montgomery

Grundy

Jo Daviess

Woodford

Jersey

De Witt

Franklin

Monroe

Stark

Douglas

Schuyler

McDonough

Washington

Hamilton

Crawford Effingham

Stephenson

Brown

Scott

Marshall

Winnebago

Kendall

Moultrie

Gallatin

Boone

Johnson

DuPage

Richland

Menard

Lawrence

Rock Island

Cumberland

Hardin

Wabash

Union

Williamson

Henderson

Calhoun

Massac

Pulaski

Edwards

Alexander

Putnam

AER: Joppa Labor Market Areas

F

0 25 50

Miles

July 2013

! AER Energy Centers

Joppa Energy Centers Labor Market

Joppa Employees by County

1 - 3

4 - 9

10 - 80

Source: Ameren provided employment counts by work location and county of residence, as of June 26, 2013

Joppa Energy Center
DEVELOPMENT STRATEGIES® 

guiding effective decisions in 

real estate, community, and economic development 

10 South Broadway, Suite 1500  St. Louis, Missouri 63102  p 314.421.2800 WWW.DEVELOPMENT-STRATEGIES.COM

Memorandum

To: Daniel P. Thompson, Vice President, Illinois Power Holdings, LLC 

From: Robert Lewis, Brian Licari, and Yash Yedavalli 

Date: July 12, 2013 

Re: Economic Impacts of Newton Energy Center of Illinois and Surrounding Labor Market Area 

In April, 2012, Development Strategies (DS) was commissioned by Ameren Energy Resources Corporation (AER) 

to conduct an independent analysis of the economic impact that the operations of AER’s Newton Energy Center 

(Jasper County) have on the Illinois economy and on its respective multi-county economic region. Development 

Strategies has since been commissioned by Illinois Power Holdings to update this analysis with the latest available 

data as of July, 2013, from both AER/Ameren Services and appropriate state and federal economic data sources. 

Development Strategies is pleased to submit this analysis of the direct and indirect economic impacts for this facility. 

Direct economic impacts are the estimated dollars spent by AER at and in operational support of the energy center facility. For the purpose of this analysis, spending includes capital expenditures, non-payroll operations expenditures, and salaries paid to employees. 

There are 143 total jobs at the Newton Energy Center, 142 of whom live in Illinois. We determined which counties 

in the “region” of the energy center are home to a large majority of those employees and this determined the facility’s primary economic impact region for our impact analysis. We then calculated economic impacts within that impact region. Three Illinois counties make up the primary economic impact region in the case of Newton, which is

home to 109 of its 143 employees. See accompanying map “AER: Newton Energy Center Labor Market Area” for 

the local labor market area boundaries. 

Indirect economic impacts measure the “ripple effect” of wages and expenditures associated with AER’s direct 

spending. For instance, Newton employees who live in Illinois will spend a large proportion of their earnings within 

the state of Illinois for housing and at local businesses such as retail stores, restaurants, mechanics, and others. Thus, 

each job at Newton will contribute to additional job support across many sectors in the community and, consequently, the state of Illinois. Likewise, much of the non-labor operational spending by the energy center is initially 

spent within the state, thus supporting additional income and jobs in the immediately surrounding counties and 

throughout the state. 

To calculate these indirect impacts, multiplier coefficients are applied to the direct impact dollars; these multipliers 

also automatically take into account the amount of “leakage” from the local and state economies because some wages and expenditures will be spent outside of the regions in which they are initiated. For this reason, multiplier coefficients are finite and, therefore, measureable. 

METHODOLOGY 

The analysis of the direct and indirect economic impacts of the Newton Energy Center relied on spending and 

workforce information provided by AER, and on the U.S. Department of Commerce’s Regional Input-Output Multiplier System (RIMS-II). RIMS-II provides multiplier coefficients for every county in the United States. These multipliers can also be aggregated for larger regions composed of counties, such as states and, in this case, the primary 

economic impact region around the energy center. Multiplier coefficients for sub-county geographies are not available. The multipliers are determined separately for, and are unique to, each county and region for key economic sectors. The RIMS-II multipliers are updated annually by the Bureau of Economic Analysis (BEA). 
Memorandum on Economic Impacts of Newton Energy Center 

July 12, 2013 

DEVELOPMENT STRATEGIES 2

The economic impact analysis focuses on the multi-county region noted above and on the state as a whole. That is, 

the Newton Energy Center has two economic impact tables associated with it: the state and its own primary economic impact region. There are three principal multipliers for each sector: 

 Economic Output: This is defined as the total dollar change in the regional or state economy due to direct 

expenditures by AER at the energy center. Economic output is a similar measure as the nation’s gross domestic 

product but, unlike the GDP, it also includes all the intermediate values added during the production process. 

 Earnings: The earnings multiplier measures the added household earnings for the regional and state labor 

force triggered by AER’s direct spending at the energy center. 

 Employment: This is defined as the added jobs in the county per $1,000,000 of direct spending by AER in 

addition to the jobs at the energy center.1

Multipliers are provided for various economic sectors. The direct, non-labor, operational spending by AER at the 

energy center falls within the Utilities sector; the employee earnings paid by AER fall within the Households sector; 

and capital expenditures fall within the Construction sector. The RIMS-II multipliers for the selected regions are 

summarized below. To calculate the indirect economic impacts: 

 The construction multiplier coefficients for the state and region are applied to the capital expenditure figures of the 

energy center, 

 The utilities multiplier coefficients for the state and region are applied to the operational expenditures of the energy 

center, and 

 The households multiplier coefficients for the state and region are applied to the employee compensation figures of the 

energy center. Employee compensation is calculated by applying the average labor expenditure to the number 

of workers who reside in the state and region. For the purposes of this analysis, employee compensation includes salary, benefits, and any other labor related costs; therefore, the average labor expenditure per employee 

does not necessarily reflect the average wage. 

The respective direct and indirect impacts are then summed to calculate the total indirect impacts. 

Note: Fuel expenditures for coal were not considered for this analysis. AER’s coal comes from in-state and out-ofstate sources. In the case of Newton Energy Center, all of its coal comes from out-of-state sources. Since this study 

focuses on the impacts within the state of Illinois, only the expenditures for Illinois-sourced coal should be considered. Though a small portion of Newton’s fuel expenditures likely occur within Illinois (e.g. transportation costs), 

the vast majority of these expenditures occur outside of Illinois; therefore, we are uncomfortable assuming that the 

standard RIMS-II multipliers account for this scale of immediate leakage. Including fuel expenditures in this analysis, therefore, could overstate the local and statewide impacts. 

CONCLUSIONS 

DS estimates that the Newton Energy Center has an economic impact on the Illinois economy and its primary economic impact region as shown on the following tables. Each table summarizes AER’s direct spending at the Newton Energy Center (top line in the table), the multipliers for Illinois or the market area, the multiplier effects resulting 

from AER’s operational spending, and the total direct and indirect economic impacts generated. 

 

1

The multipliers derived from U.S. Department of Labor data, however, are based on 2008 economic activity and data. So the model used in 

this report inflates the million dollars from 2008, or jobs per $1,081,940 in 2013 dollars, using the Consumer Price Index (CPI). 
Memorandum on Economic Impacts of Newton Energy Center 

July 12, 2013 

DEVELOPMENT STRATEGIES 3

IMPACTS ON THE STATE OF ILLINOIS

The top of the table shows the direct expenditures by AER at the Newton Energy Center averaging approximately 

$93.9 million per year from 2008 to 2012 in 2013 dollars. Employee compensation is an estimate based on the 

number of Newton employees that live in Illinois (142 of 143). Additional results are discussed below: 

 The $93.9 million spent by AER at Newton Energy Center triggered an additional $194.4 million in value added 

activity in Illinois, of which $56.7 million was household earnings that another supported 1,150 jobs. 

 The estimated total output (economic activity) triggered by Newton Energy Center’s direct operations ($93.9

million) and the added multiplier effects ($194.4 million) were $288.3 million for the Illinois economy. 

 Of that amount, Newton Energy Center’s operations triggered nearly $72.4 million in household earnings for 

workers in Illinois, including $15.6 million in direct compensation for employees and $56.7 million in added 

earnings from the multiplier effects. 

 In total, Newton Energy Center’s operations supported 1,292 jobs for Illinois residents, including 142 direct 

jobs and approximately 1,150 jobs added through the multiplier effects. 

Capital

Expenditures

Operating 

Expenditures

Employee 

Compensation 2Total

Direct Spending $ 65,705,000 $ 12,553,000 $ 15,636,000 $ 93,894,000

MULTIPLIERS

Output 2.3293 1.5022 1.4416 2.0709

Household Earnings 0.7145 0.2856 0.3968 0.6042

Employment3

 14.4079 4.2522 9.6324 12.2479

ADDED ECONOMIC IMPACT ON ILLINOIS

Output $ 153,047,000 $ 18,857,000 $ 22,541,000 $ 194,445,000

Household Earnings $ 46,946,000 $ 3,585,000 $ 6,204,000 $ 56,735,000

Indirect Jobs Held by Illinois Residents 950 5 0 150 1,150

TOTAL ECONOMIC IMPACT ON ILLINOIS

Output (Total Economic Activity) $ 288,339,000

Household Earnings $ 72,371,000

 142

 1,292

3

E mployment multiplier represents jobs per $1 million in expenditures. Since the original RIMS-II multiplier is based on 2008 

economic data, the employment multipliers presented in this table have been adjusted to jobs per $1 million in 2013 dollars using the 

CPI, or jobs per $1,081,940.

Annual Economic Impact of AER's Newton Energy Center Operations on the State of Illinois

Annual Average i n 2013 Dol l ars 1

Total Direct and Indirect Jobs at Newton Energy Center

1 Actual operating data from 2008 to 2012 adjusted to 2013 dollar amounts using the Consumer Price Index (CPI) and averaged.

2 Estimate based on number of employees who reside in Illinois (142 of 143) and overall average labor expenditure per employee.

Direct Jobs at Newton Energy Center (Illinois residents)
Memorandum on Economic Impacts of Newton Energy Center 

July 12, 2013 

DEVELOPMENT STRATEGIES 4

IMPACTS ON THE MULTI-COUNTY REGION

The top of the table shows that the direct expenditures by AER at the Newton Energy Center in the market area 

averaged approximately $90.3 million per year from 2008 to 2012 in 2013 dollars. This is less than for the state as a 

whole because employees outside of the market area are excluded. Employee compensation is an estimate based on 

the number of Newton employees that live in the labor market area (109 of 143). Additional results are discussed 

below: 

 The $90.3 million spent by AER at Newton Energy Center triggered an additional $120.9 million in value added 

activity in the market area, of which $32.4 million was household earnings that supported 630 jobs. The multipliers vary for different types of major expenditures shown at the top of the table. 

 The estimated total output (economic activity) triggered by Newton Energy Center’s direct operations ($90.3

million) and the added multiplier effects ($120.9 million) were $211.2 million for the market area. 

 Of that amount, Newton Energy Center’s operations triggered nearly $44.4 million in household earnings for 

other workers in the market area, including $12.0 million in direct compensation for employees and $32.4 million in added earnings from the multiplier effects. 

 In total, Newton Energy Center’s operations supported an annual average of 739 jobs for residents of the market area, including 109 direct jobs and approximately 630 jobs added through the multiplier effects. 

Capital

Expenditures

Operating 

Expenditures

Employee 

Compensation 2Total

Direct Spending $ 65,705,000 $ 12,553,000 $ 12,002,000 $ 90,260,000

MULTIPLIERS

Output 1.4919 1.2710 0.5804 1.3400

Household Earnings 0.4231 0.2295 0.1442 0.3591

Employment3

 8.3442 2.7410 3.8597 6.9798

ADDED ECONOMIC IMPACT ON MARKET AREA

Output $ 98,025,000 $ 15,955,000 $ 6,966,000 $ 120,946,000

Household Earnings $ 27,800,000 $ 2,881,000 $ 1,731,000 $ 32,412,000

Indirect Jobs Held by Market Area Residents 550 3 0 5 0 630

TOTAL ECONOMIC IMPACT ON MARKET AREA

Output (Total Economic Activity) $ 211,206,000

Household Earnings $ 44,414,000

 109

 739

3

E mployment multiplier represents jobs per $1 million in expenditures. Since the original RIMS-II multiplier is based on 2008 economic 

data, the employment multipliers presented in this table have been adjusted to jobs per $1 million in 2013 dollars using the CPI, or jobs 

per $1,081,940.

Annual Economic Impact of AER's Newton Energy Center Operations on Labor Market Area

Annual Average i n 2013 Dol l ars 1

Total Direct and Indirect Jobs at Newton Energy Center

1 Actual operating data from 2008 to 2012 adjusted to 2013 dollar amounts using the CPI and averaged.

2 Estimate based on number of employees who reside in labor market area (109 of 143) and overall average labor expenditure per employee.

Direct Jobs at Newton Energy Center (market area residents)
AER Headquarters

Duck Creek Energy Center

Coffeen Energy Center

20% 46% 12%

Newton Energy Center

Missouri

Iowa

Indiana

Kentucky

Wisconsin

Michigan

Elgin Energy Center

Gibson City Energy Center

Joppa Energy Center

Grand Tower Energy Center

E.D. Edwards Energy Center

Will

Pike

Lee

Cook

Ogle

McLean

La Salle

Iroquois

Fulton

Knox

Henry

Adams

Bureau

Shelby

Livingston

Wayne

Edgar

Ford

Vermilion

Clay

Logan

Kane

Fayette

Peoria

Hancock

Piatt

Macoupin

Clark

Lake

Champaign

Macon

Madison

Coles

DeKalb

Marion

Mason

St. Clair

White

Sangamon

Mercer

Christian

Perry

Tazewell

Morgan

Warren

Jackson

Greene

Clinton

Whiteside

Jasper

Cass

Union Pope

Bond

Kankakee

Carroll

McHenry

Jefferson

Randolph

Saline

Montgomery

Grundy

Jo Daviess

Woodford

Jersey

De Witt

Franklin

Monroe

Stark

Douglas

Schuyler

McDonough

Washington

Hamilton

Crawford Effingham

Stephenson

Brown

Scott

Marshall

Winnebago

Kendall

Moultrie

Gallatin

Boone

Johnson

Williamson

DuPage

Richland

Menard

Lawrence

Rock Island

Cumberland

Hardin

Wabash

Henderson

Calhoun

Pulaski Massac

Edwards

Alexander

Putnam

AER: Newton Labor Market Areas

F

0 25 50

Miles

July 2013

! AER Energy Centers

Newton Market Areas

Newton Employees by County

1 - 3

4 - 16

17 - 64

Source: Ameren provided employment counts by work location and county of residence, as of June 26, 2013
EXHIBIT 8

AFFIDAVIT OF DANIEL P. THOMPSON 
AFFIDAVIT OF DANIEL P. THOMPSON 

I. BACKGROUND AND QUALIFICATIONS 

1. My name is Daniel P. Thompson. I am Vice President and General Manager for 

Dynegy Midwest Generation, LLC ("DMG"), an indirect, wholly owned subsidiary of Dynegy 

Inc. ("Dynegy"). J also serve as Vice President of Illinois Power Holdings, LLC ("IPH"), which 

is also an indirect, wholly owned subsidiary of Dynegy. My business address is 604 Pierce 

Blvd., O'Fallon, lllinois, 62269. I provide this affidavit in support of the Petition for Variance 

filed by IPH, AmerenEnergy Medina Valley Cogen, L.L.C. ("Medina Valley") and Ameren 

Energy Resources, LLC ("AER") ("Petition"). I make this affidavit based on personal 

knowledge or on knowledge I have obtained through inquiry of individuals employed by Dynegy 

or its affiliates. 

2. As Vice President of DMG, I am responsible for the safe and efficient operation 

of Dynegy's coal-fired electric generating fleet in Illinois. My responsibilities include oversight 

of environmental compliance at Dynegy's Illinois coal fleet. 

3. Prior to my current position with Dynegy, I served as Dynegy's Vice President of 

Operations, West Region from 2007 to late 2011 ; Vice President, Northeast Operations (New 

York) from 2001 to 2007; and Vice President, Engineering for Generation from 1999 to 2001. 

Prior to that, l had worked for Illinois Power since 1987 in numerous capacities, including the 

Manager of the Vermilion and Hennepin Stations; Operations Supervisor at Baldwin Station, 

Plant Manager at Havana Station; Manager of Nuclear Training at Clinton Nuclear Station and 

Manager of Nuclear Engineering. Prior to joining Illinois Power, I was Maintenance Manager 

for Pfizer, Inc. at its Minerals and Pigments Division in East St. Louis, Illinois from 1980 to 

1982 and the Maintenance Superintendent for the Allis Chalmers Coal Gasification R&D 
Facility at East Alton, Illinois from 1982 to 1987. I graduated in 1975 from the United States 

Naval Academy, subsequently completed Naval Nuclear Power School and then served as a 

Nuclear Propulsion/Surface Warfare Officer aboard the USS Long Beach (CNG-9) until 1980. I 

hold an MBA from Southern Illinois University Edwardsville (1984). 

4. I am familiar with the contemplated transaction between IPH and Ameren 

Corporation ("Ameren") and led Dynegy's due diligence efforts on operations-related issues for 

the transaction. I have read and am familiar with the September 20, 2012 Opinion and Order 

C'Order") by the illinois Pollution Control Board ("Board"), Docket PCB 12-126, granting AER 

variance relief from the sulfur dioxide ("S02") annual emission rates in the multi-pollutant standard 

(''MPS") rules applicable to the Ameren MPS Group. 

D. DYNEGY'S PRESENCE AND EXPERIENCE IN ILLINOIS 

5. Dynegy is a holding company that conducts substantially all of its business 

operations through its subsidiaries. Dynegy's primary business is the production and sale of 

electric energy, capacity and ancillary services on a wholesale basis to Regional Transmission 

Organizations ("RTOs"), Independent System Operators ("ISOs"), integrated utilities, electric 

cooperatives, municipalities and other energy companies in the Midwest, Northeast and West 

Coast regions of the U.S. Dynegy's power generation portfolio consists of twelve operating 

power plants in six states totaling approximately 9,800 megawatts ("MW") of baseload, 

intermediate and peaking generation fueled by a mix of coal, fuel oil and natural gas. 

6. Through its subsidiaries Dynegy Midwest Generation, LLC ("DMG") and 

Dynegy Kendall Energy, LLC, Dynegy owns and operates five coal and natural gas-fired power 

generation facilities in illinois, with the capacity of producing approximately 4,200 MW of reliable, 

low cost energy for wholesale customers. Dynegy has had a strong and meaningful presence in the 

2 
State of Illinois since its February 2000 acquisition of Illinova Corporation (i.e., the fossil fuelfired electric generating assets of Illinois Power Company), which formed the basis of DMG's 

current generating fleet in illinois. In 2004, Dynegy sold the Illinois Power Company regulated 

energy delivery business to Ameren Corporation, but retained the generating assets. 

7. DMG's generating assets include four operating coal-fired electric generating 

stations located in southern Illinois: the Baldwin Energy Complex in Randolph County, the 

Havana Power Station in Mason County, the Hennepin Power Station in Putnam County, and the 

Wood River Power Station in Madison County. In November 2011, DMG permanently retired a 

fifth coal-fired power plant, the Vermilion Power Station, located in Vermilion County. Through 

its subsidiaries operating in Illinois, Dynegy has approximately 600 full-time employees 

statewide, employing approximately 550 persons at its Illinois power stations and approximately 

50 persons at its corporate office located in O'Fallon, Illinois. The economic impact of 

Dynegy's operations in Illinois and in the affected local Illinois communities is significant. For 

example, in 2012, through its subsidiaries, Dynegy's direct investments in Illinois (i. e., 

maintenance, capital, and taxes) totaled approximately $261 million. 

8. Dynegy and its subsidiaries have a strong commitment to safe and 

environmentally responsible operations in Illinois. DMG has invested approximately $1 billion 

in air pollution controls at its Illinois facilities (including installation of flue gas desulfurization, 

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.1 Since 1998, 

DMG's fleet has reduced its aggregate annual emissions by almost 90 percent. Dynegy is very 

familiar and experienced with the Illinois MPS requirements. DMG's five coal-frred stations 

1 United States. v. Jllinois Power Co., No. 99-CV-833-MJR (S.D. Ill.) (Consent Decree entered May 27, 2005) (a 

copy of the Consent Decree as originally entered is available at: 

http://www.epa.gov/compliance/resources/decrees/civilfcaa/dmgfinal-cd.pdf. 

3 
elected into the MPS in 2007 (i.e., the DMG MPS Group) and Dynegy's environmental support 

group staff was directly involved in the MPS rulemakings. DMG has met its MPS limits. 

Indeed, DMG met the MPS's mercury emission rate limit at all but one of its MPS generating 

units three years earlier than the required January 1, 2015 deadline. 

9. Dynegy also has been involved in carbon sequestration efforts, with tree-planting 

projects covering more than 45,000 acres in a portion of the Shawnee National Forest. The 

Lower Mississippi River Valley reforestation project is registered under the Verified Carbon 

Standard and was the first U.S. forest carbon offset project to receive this certification. Dynegy 

has also donated 1,1 00 acres along the Middle Fork Vermilion River to the Illinois Department 

of Natural Resources and has sponsored activities preserving 1,200 acres of forests in Illinois. 

Each year, these trees will sequester increasing levels of carbon dioxide. Dynegy also reuses 

coal ash produced at its Illinois coal-fired generating facilities through agreements with cement 

manufacturers that incorporate the material into cement products, helping to reduce carbon 

dioxide emissions from the cement manufacturing process. 

ID. TRANSACTION AGREEMENT WITH AMEREN 

10. On March 14, 2013, IPH entered a Transaction Agreement with Ameren to 

acquire the equity interest in Ameren's merchant utilities businesses (collectively, the "Acquired 

Merchant Utilities"). Upon closing of the transaction, IPH will own the Acquired Merchant 

Utilities, which own and operate five operating coal-fired electric energy generating centers in 

central and southern Illinois -- specifically the Duck Creek Energy Center in Fulton County, the 

Coffeen Energy Center in Montgomery County, the E.D. Edwards Energy Center in Peoria 

County, the Newton Energy Center in Jasper County, and the Joppa Energy Center in Massac 

County (the five operating energy centers, collectively, the "Acquired Plants"). Under the 

4 
Transaction Agreement, the shuttered Hutsonville and Meredosia power plants will remain with 

Petitioner Medina Valley, a subsidiary of Ameren, and will not be acquired by IPH. Closing on 

the Transaction Agreement is expected to occur in the fourth quarter of2013. Given Dynegy's 

experience in Illinois, IPH's acquisition of the Acquired Merchant Utilities will position the 

businesses and the Acquired Plants to move forward with a company committed to lllinois and 

with a history of providing environmentally sound, safe, affordable, and reliable power in 

Dlinois. 

IV. WITHOUT THE REQUESTED VARIANCE RELIEF COMPLIANCE WITH 

THE MPS WOULD IMPOSE UNREASONABLE HARDSHIP ON IPH 

11. IPH has analyzed its options to meet the Ameren MPS Group Multi-Pollutant 

Standard rule 2015 and 20 17 overall S02 annual emission rates and concluded that its only 

compliance alternative not involving shutdown of some combination of the Acquired Plants is to 

follow through on AER's chosen compliance plan to meet the Ameren MPS Group system-wide 

S02 emission rate limits, namely by installing and operating a flue gas desulfurization ("FGD") 

system on each unit at the Newton Energy Center. 

12. Because IPH will not acquire ownership of the Acquired Plants until late 2013 

and because construction activities needed to install the Newton FGDs are expected to take up to 

24 months, IPH could not complete construction of the Newton FGDs in time to comply with the 

MPS 2015 overall S02 annual emission rate, even if IPH were financially able to ramp up 

construction immediately upon acquiring ownership (which, as explained in the Affidavit of 

Mario E. Alonso, will not be possible). Thus, without the requested variance relief, IPH's only 

option to comply with the MPS would be to shut down a combination of the Newton, E.D. 

Edwards and Joppa Energy Centers by January 1, 2015. In IPH's analysis, without the requested 

variance relief, E.D. Edwards and Joppa would be shut down by January 1, 2015 to meet the 

5 
MPS. Moreover, without the requested variance relief, even after shutting down the E.D. 

Edwards and Joppa Energy Centers by 2015, the remaining three operating energy centers 

(Coffeen, Duck Creek, and Newton) would not meet the 2017 MPS overall S02 annual emission 

rate without operational curtailments or implementation of other S02 emission reduction 

measures at Newton, as IPH likely would not complete construction of the Newton FGDs given 

the significant remaining capital expense of doing so. As discussed below, there are no other 

viable compliance alternatives. 

A. Compliance Alternatives 

1. Curtailment of Operations 

13. Curtailment of operations (i.e. , derates, seasonal operations, etc.) to meet the MPS 

overall S02 annual emission rate limits would not be economically feasible because less power 

would be generated, resulting in less revenues to run the business and cover fixed operating 

costs. In other words, curtailing operations at the Acquired Plants as a compliance strategy 

would prevent the plants from generating sufficient funds to sustain their operations and 

obligations. More specifically, IPH's analysis indicates that in order to meet the 2015 MPS 

overall S02 emissions limit with all five plants remaining in operation would effectively require 

each of the Newton, E.D. Edwards and Joppa energy centers to limit its respective generation to 

approximately one-third of its capacity. Given their significant fixed costs, such a limit on 

generation would eliminate the ability of these energy centers to generate positive cash flows 

going forward and result in their shutdown. For the same reason, seasonal operation of the 

Newton, E.D. Edwards and Joppa stations would be infeasible. 

6 
ii. Low Sulfur Coal 

14. IPH will continue to honor AER's prior commitment to limit the use of higher 

sulfur coal to the Duck Creek and Coffeen stations (both of which utilize wet FGD systems) and 

to use low sulfur Powder River Basin ("PRB") coal (i.e., 0.55 lbs sulfur/mrnBtu) at the E.D. 

Edwards, Newton and Joppa stations. In fact, IPH, through the Acquired Merchant Utilities, will 

inherit the binding 0.55 lb/mmBtu low sulfur coal purchase contracts AER already has in place 

for 2013-2017. More specifically, IPH understands that AER is already contracted for the 

majority of its expected coal supply needs in 2013 and 2014, approximately one-half of its 

expected coal supply needs in 2015 and 2016, and approximately one quarter of its coal supply 

needs in 2017. Those contracts could not be breached without material penalties. 

15. Based on DMG's coal purchasing experience, IPH understands that 0.50 

lb/mrnBtu sulfur PRB coal is available from one coal supplier. Ongoing dependence for coal 

from a single supplier may materially increase contracted prices by I 0 percent or more above 

current market prices and would expose IPH to production and performance specific risks. ln 

completing coal purchasing to meet its fuel inventory needs in 2013-2017 (i.e., purchasing coal 

to supplement the quantities for which AER has already entered binding contracts), 2018 and 

2019, IPH anticipates that it may need to purchase certain quantities of coal with a sulfur content 

lower than 0.55 lb/mmBtu to ensure compliance with the variance's so2 mitigation emissions 

limit. However, JPH does not at this time know the precise quantities of such coal (i.e. , sulfur 

content lower than 0.55 lb/mmBtu) that may be needed for compliance, as that will depend on 

actual S02 emissions performance of the Acquired Plants in future years. Moreover, given the 

material increased risks associated with relying on a single supplier of such coal and the financial 

liquidity challenges that the Acquired Plants will face, IPH cannot now commit to purchasing 

7 
only coal with sulfur content lower than 0.55 lb/mmBtu for the currently uncontracted coal 

supply needs of the Newton, E.D. Edwards and Joppa stations during the requested variance 

period. As stated above, IPH will commit to using low sulfur PRB coal with a sulfur content not 

to exceed 0.55 lb/mmBtu at the E.D. Edwards, Newton and Joppa stations during the term of the 

requested variance. 

iii. Alternative Control Technologies 

16. IPH also has independently reviewed the availability of alternative S02 emission 

control technologies and reaches the same conclusion that AER did, as approved by the Board's 

prior grant of the AER variance, that these technologies are infeasible because they would cost 

more than the Newton FGD project. The costs and technological limits prevailing at the time of 

the Board's Order in September 2012 have not changed in any material way. Thus, there are no 

other cost-effective control technologies that IPH could used at the Acquired Plants to achieve 

compliance with the MPS. 

17. Specifically with regard to dry sorbent injection ("DSI") technology as a potential 

compliance alternative, the overall cost of DSI as applied to the Joppa and/or E.D. Edwards 

energy centers renders DSI infeasible. Based upon IPH's analysis of DSI at other coal-fired 

plants, IPH estimates that the capital cost of installing DSI would alone be in the range of $60 

million at Joppa (all six units) and $30 million at E.D. Edwards (Units 2 and 3). These are order 

of magnitude estimates based on DMG's experience, as IPH has not performed a site-specific 

engineering analysis of DSI at either facility. As explained in the Affidavit of Mario E. Alonso, 

IPH will not have sufficient liquidity to fund any such large-scale capital projects over the next 

several years. Importantly, however, as AER demonstrated in obtaining its variance, the capital 

costs of installing DSI at Joppa and/or E.D. Edwards would not be limited only to the DSI 

8 
technology. Because of the size of the existing particulate control equipment and the injection of 

activated carbon to control mercury emissions at E.D. Edwards and Joppa, the additional use of 

DSI would result in a significant increase in particulate matter ("PM") emissions, necessitating 

installation of PM control technologies (e.g., baghouses, significant upgrades to the existing 

ESPs). Thus, the real expected capital cost of installing DSI would be materially higher, 

approximately $433 million at Joppa and approximately $280 million at E.D. Edwards (Units 2 

and 3), as identified in AER's Post-Hearing Brief (p.15) (PCB 12-126) (filed Aug. 15, 2012), 

which cites to a 201 1 URS engineering report and attaches a cost table from the URS report as 

Post-Hearing Brief, Exhibit 1. 

18. The annual operation and maintenance ("O&M") expense of DSI also is itself 

significant. As AER demonstrated, the estimated annual cost of dry sorbent ranges from $15 

million to $44 million depending upon the type of material used and the location of injection 

(before or after the air heater). See PCB 12-126, Petitioner's Post-Hearing Brief, 20-21 (citing 

2010 report completed by the Shaw Group (Post-Hearing Brief, Exhibit 2)). Those estimated 

O&M costs cited by AER are consistent with DMG's analysis of DSI O&M costs at other coalfired plants. In addition, use of DSI would result in O&M expenses associated with the disposal 

of the reacted DSI materiaL Those costs would not be insignificant. The impact of DSI annual 

O&M costs is even more pronounced given the liquidity challenges the Acquired Plants will 

face. 

iv. Natural Gas 

19. IPH also has considered firing natural gas as a means to comply with the MPS. 

Natural gas pipelines are not currently interconnected to E.D. Edwards or Newton. The cost of 

constructing natural gas pipelines to either facility would be cost prohibitive. Based on 

9 
preliminary analysis by AER, an order of magnitude estimate of the cost to develop natural gas 

supply to E.D. Edwards is $100 million and the cost to develop natural gas supply to Newton is 

$70 million. Further, the additional capital expenditures needed to convert the coal- fued boilers 

at E.D. Edwards or Newton to natural gas firing are expected to be significant. In the absence of 

detailed site-specific natural gas conversion engineering studies at E.D. Edwards or Newton, 

based on reported industry trade literature and case studies involving natural gas conversion of 

existing coal-fired boilers, the cost of converting each plant would be expected to be tens of 

millions of dollars, if not more. See, e.g, Babcock & Wilcox, Natural Gas Conversions of 

Existing Coal-Fired Boilers, White Paper MS-14 (20 10) (identifying cost range of $50 to 

$75/kW). 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 dollars aheady 

spent on the Newton FGDs. 

20. Moreover, natural gas firing at Newton or E.D. Edwards would not be a costeffective compliance alternative because dispatch on natural gas is more expensive than on coal, 

with the result that natural gas firing would result in significantly lower production by the plant 

and, thus, generate lower revenues needed for the recovery of fixed operating costs and capital 

expenditures. Based on current power market conditions in Illinois, production costs related to 

fuel are roughly $20-$25 per megawatt hour ("$/MWh") on PRB coal and would be roughly 

$40/MWh on natural gas. Based on MISO published clearing prices in 2012, power prices at, for 

example, the Newton busbar averaged in excess of $22.00/MWh during 76 percent of the onpeak days while only of two percent of the on-peak day averages exceeded $40.00/MWh. In 

other words, Newton fired on natural gas during 2012 would have been dispatched 

approximately only two percent of the time. Thus, IPH concludes that it is infeasible to convert 

10 
E.D. Edwards or Newton to natural gas. 

21. Further, IPH concludes that, for several reasons, converting Joppa to natural gas 

would be cost prohibitive and not economically feasible. First, based on preliminary analysis by 

AER, an order of magnitude cost estimate to convert the relevant Joppa units to natural gas 

ranges from $25 million (i.e., convert to 50 percent capacity on natural gas) to $38 million (i.e., 

convert to 1 00 percent capacity on natural gas), with an additional estimated $4.5 million in 

capital expenditures needed for gas supply pipeline and equipment improvements. As explained 

in the Affidavit of Mario E. Alonso, IPH will not have sufficient liquidity to fund any such largescale capital projects over the next several years. Second, as discussed in the following 

paragraph, natural gas firing at Joppa would not be a cost-effective compliance alternative 

because dispatch on natural gas is more expensive than on coal, with the result that natural gas 

firing would result in lower production at Joppa and, thus, generate lower revenues needed for 

the recovery of fixed operating costs and capital expenditures. Finally, as determined by the 

Board in AER's variance proceeding, conversion of Joppa to natural gas firing would reduce the 

plant's operations to a seasonal basis only, thereby resulting in reduced revenues and, ultimately, 

a loss of jobs. Thus, IPH concludes that, as the Board determined in the AER variance 

proceeding, it is infeasible to convert Joppa to natural gas. 

22. IPH understands that two units at Joppa (Units 1 and 4) have the physical 

capability to co-fire natural gas up to approximately 45 percent of heat input at full load. Based 

on DMG's experience with analyzing natural gas co-firing as an option to reduce S02 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. Because dispatch on natural gas is 

more expensive than dispatch on coal, natural gas co-firing would result in lower production and, 

11 
thus, generate lower revenues for the recovery of fixed operating costs and capital expenditures. 

The key factor for sustained use of natural gas co-firing is the price differential between natural 

gas and coal. As mentioned above, based on current market conditions, production costs related 

to fuel are roughly $20 - $25/MWh on PRB coal and would be roughly $40/MWh on natural gas. 

In general, it would only be cost effective to co-fire natural gas if natural gas prices approached 

$2.50/mmBtu. Thus, even at the historically low natural gas prices in recent times, natural gas 

co-firing does not make economic sense. Accordingly, IPH concludes that natural gas co-firing 

at Joppa Units 1 and 4, while technically possible, is not a cost-effective compliance alternative, 

nor would it achieve compliance with the MPS overall S02 emission rate limits. 

V. IPH's COMPLIANCE PLAN UNDER THE REQUESTED VARIANCE RELIEF 

23. IPH will keep intact the seven-plant Ameren MPS Group, including the shutdown 

Hutsonville and Meredosia plants, through the requested variance period. Even though IPH will 

not acquire the shuttered Hutsonville and Meredosia plants, IPH understands that these two 

shutdown plants must remain in the Ameren MPS Group for MPS compliance determination 

purposes, including MPS reporting. In addition, as provided in the Petitioners' proposed 

variance order, IPH will assume responsibility for ensuring that the shuttered electrical 

generating units at the Hutsonville and Meredosia plants remain shuttered through December 31, 

2020. Petitioner Medina Valley, who will acquire the Hutsonville and Meredosia plants, also has 

independently committed not to operate the electrical generating units at Hutsonville and 

Meredosia through December 31,2020. As in AER's existing variance, the requirement to keep 

the electrical generating units at Meredosia shuttered through December 31, 2020 would exempt 

the FutureGen project. 

12 
24. IPH will meet an overall S02 mitigation emission rate of 0.35 lb/mmBtu for each 

year from 2013 through December 31, 2019, and 0.23 lb/mmBtu annually thereafter (i. e., the 

same overall SOz annual mitigation emission rate and final MPS SOz emission rate at the 

Acquired Plants that AER committed to by accepting the Order). IPH will honor AER's prior 

commitment to limit the use of higher sulfur coal to the Duck Creek and Coffeen stations and to 

use low sulfur coal (i.e., 0.55 lbs sulfur/mmBtu) at the E.D. Edwards, Newton and Joppa stations 

during the variance term. IPH also will honor AER's commitment to maximize operation of the 

existing FGD systems at the Duck Creek and Coffeen stations at a 98-99 percent S02 removal 

rate during the variance term. Finally, IPH will continue the construction of the Newton FGD 

project and comply with the Newton FGD project construction milestones and reporting 

requirements as set forth in the Petitioners' proposed variance order (i.e. , the same Newton FGD 

project construction milestones and reporting requirements that AER committed to by accepting 

the Order). 

25. TPH estimates that total costs of construction for the two FGD units at the Newton 

energy center are approximately $500 million. Approximately one-half of the total costs have 

been spent to date. In accordance with the construction milestones in the proposed variance 

order, IPH has budgeted $18 million in annual expenditures through 2017 to continue 

construction of the Newton FGDs, with the remainder of the total estimated spend scheduled for 

2018 and 2019 to complete the Newton FGDs. In addition, several million dollars in annual 

O&M expenses will be required to comply with the MPS NOx and mercury emission limits at the 

Acquired Plants. 

13 
VI. THE PROPOSED VARIANCE ORDER WILL HAVE NO ADVERSE 

ENVIRONMENTAL IMPACT AND WILL REDUCE OVERALL SOz 

EMISSIONS 

26. The proposed variance would reduce overall S02 emissions compared to the S02 

reductions achieved by compliance with the Ameren MPS Group Multi-Pollutant Standard rule. 

As identified in the Affidavit of Aric D. Diericx, the proposed variance will result in a net 

reduction of 74,303 tons of S02 over the period 2010-2020 and a net reduction of 7,778 tons of 

so2 over the period 2013-2020. 

27. IPH anticipates that additional overall net reductions will occur for one or more of 

several reasons. First, IPH expects that during the term of its requested reliefE.D. Edwards Unit 

1 will be permanently retired. In December 2012, AmerenEnergy Generating Resources 

Company ("AERG") filed a request with the Midcontinent Independent System Operator, Inc. 

C'MISO"), the regional transmission organization, to retire E.D. Edwards Unit 1 effective 

December 31, 2012. MISO then informed AERG that MISO' s reliability analysis indicated the 

unit was needed for reliability purposes and that continued service of E.D. Edwards Unit 1 as a 

System Support Resource ("SSR") unit would be required. MISO determined that E.D. Edwards 

Unit 1 would be needed for reliability purposes until such time as numerous transmission system 

reinforcements were put into service in order to mitigate thermal and voltage issues. 

Accordingly, effective January 1, 2013, AERG was required to continue to run E.D. Edwards 

Unit l. MISO filed an unexecuted SSR Agreement, pursuant to attachment Y-1 of MISO's 

tariff, with the Federal Energy Regulatory Commission ("FERC") on July 11, 2013 (the "July 11 

SSR Filing"). The maximum term of an SSR Agreement is twelve months and the July 11 SSR 

Filing covers the 2013 calendar year, however an SSR Agreement can be renewed and continue 

subject to an annual review of mitigation alternatives. As noted in the July 11 SSR Filing, MISO 

14 
expects that E.D. Edwards Unit 1 will continue as an SSR unit until all of the required 

transmission system reinforcements are implemented in December 2016, though newly available 

alternatives will be sought in considering the annual review of the SSR Agreement. Therefore, 

annual renewal of the SSR Agreement seems likely. The ultimate retirement date of E.D. 

Edwards Unit 1 is subject to MISO approval, which is beyond IPH's control. Thus, IPH cannot 

commit to retiring E.D. Edwards Unit 1 by a date certain. However, based on information 

currently available from MISO, IPH does expect that E.D. Edwards Unit 1 will be retired before 

the end of the requested variance term. With respect to the net reductions identified above, the 

retirement of E.D. Edwards Unit 1 is expected to reduce S02 emissions by approximately 2,000 

tons per year beginning in the first full year the unit is retired. 

28. Second, as explained above, IPH anticipates that it may at times purchase certain 

quantities of even lower sulfur coal than included in AER's commitment for Newton, E.D. 

Edwards and Joppa, depending on S02 emissions performance of the Acquired Plants. While 

IPH cannot commit to purchasing lower than 0.55 lb/mrnBtu sulfur coal for the currently 

uncontracted coal supply needs ofNewton, E.D. Edwards and Joppa during the variance period 

given the material increased risks associated with relying on a single supplier of such coal and 

the financial liquidity challenges that the energy centers will face, IPH anticipates that any such 

purchases of lower than 0.55 lb/mmBtu sulfur coal would achieve additional reductions beyond 

those identified. 

29. Third, the net reductions identified above do not reflect the expected reductions in 

S02 emissions that will occur in 2019 due to installation of the two FGDs at Newton. That is, the 

reductions identified above do not reflect that extended unit outages at Newton that will be 

required to install the FGDs, during which time the respective unit will not emit SOz. In 

15 
addition, the net reductions identified above do not reflect that the FGDs would, in all likelihood, 

be installed in series (i.e., after FGD installation is completed on one Newton unit, the second 

FGD would be installed on the second Newton unit), meaning that at least one of the FGDs 

would be operating for a portion of calendar year 2019. 

30. Finally, IPH will meet the applicable MPS NOx and mercury emission rate limits 

at the Acquired Plants. IPH also will comply with the federal Mercury and Air Toxics Standards 

("MATS") at the Acquired Plants. Cross-media impacts resulting from the proposed variance 

will remain a non-issue, as they were for the AER variance. 

VII. IPH'S VARIANCE REQUEST IS CONSISTENT WITH ILLINOIS SIP 

OBLIGATIONS AND FEDERAL LAW 

31. Granting the petition with the conditions imposed by the proposed variance order 

would be within Illinois' current obligations under the Illinois state implementation plan ("SIP") 

to attain and maintain compliance with the National Ambient Air Quality Standards ("NAAQS") 

and, therefore, would be consistent with federal law. 

32. IPH understands that the requested variance relief would not exempt the Acquired 

Plants from compliance with federal requirements. Thus, if new requirements are adopted under 

the federal Clean Air Act in the future, additional controls might need to be implemented at an 

Acquired Plant(s). 

16 
Vfil. CONCLUSION 

33. I have read the Petition and the facts stated therein with regard to the subject 

matters of this affidavit are true and correct to the best of my knowledge and belief. 

FURTHER, Affiant sayeth not. 

DATED: ?t \ IS l d:c>).3 

~IIIIIIIIIIIIHI ,,;.t·~ 'NIIIIIIIIIIIIIIII, 

~ "OFFICIAL SEAL" ~ 

§ LAUREN A. SCHMIERBACH : ~ NOTARY PUBLIC--3TATE OF IWNOIS ~ 

~ MY COMMISSION EXPIRES MAlt 16,2014 i ,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,/. 

17 
EXHIBIT 9

AFFIDAVIT OF GEORGE W. BILICIC 
AFFIDA VlT OF GEORGE W. BIUCIC 

I. BACKGROUND AND QUALIFICATIONS 

1. My name is George Bilicic. I am employed by Lazard Freres & Co. LLC 

("Lazard" or the "Firm") in the Financial Advisory practice. Lazard is an independent 

fmancial advisory and asset management finn. With over 160 years of history, Lazard, 

together with its affiliates, operates in 26 countries and employs approximately 2,500 people. 

Lazard's Financial Advisory practice provides advice to corporate, institutional, government, 

sovereign and individual clients on a broad array of strategic and frnancial matters. 

2. I am currently a Managing Director and Vice Chairman of Investment Banking 

at Lazard, and head the Finn's global efforts in Power, Energy and Infrastructure. I serve as a 

member of the Firm's Investment Banking Committee and Deputy Chairman Committee. 1 

have worked extensively on a variety of transactional, strategic and financial advisory 

assignments in the power, utility, alternative energy and infrastructure sectors for over 20 

years. I have a B.A. from DeSales University and a J.D. from Georgetown University Law 

Center. 

3. In my testimony, 1 will refer to the following: Ameren Corporation ("Ameren"); 

Ameren Energy Resources Company ("AER"); a newly formed limited liability company that 

is a direct wholly owned subsidiary of AER (''New AER" or the "Company"); each of the (i) 

Coffeen Plant, (ii) Duck Creek Plant, (iii) E.D. Edwards Plant, (iv) Newton Power Plant, and 

(v) Joppa Generating Station (collectively, the "Acquired Plants"); each of the (i) Ameren 

Energy Generating Company ("GENCO"), (ii) AmerenEnergy Resources Generating 

Company, (iii) Ameren Energy Marketing Company, (iv) Electric Energy, Inc., and (v) 

Midwest Electric Power, Inc. (collectively, the "Ameren Merchant Utilities"); and each of the 

(i) Grand Tower Energy Center, (ii) Gibson City Energy Center and (iii) Elgin Energy Center 
(collectively, the "Put Assets"). 

4. The purpose of my testimony is to provide an overview of the financial and 

market challenges that I believe New AER will likely face following its sale to Dynegy Inc.'s 

("Dynegy's") wholly-owned subsidiary illinois Power Holdings, LLC ("lPH"). The challenges 

IPH and New AER wiJl likely face are very similar to the challenges cited in the September 

20, 2012 Opinion and Order by the Illinois Pollution Control Board granting AER variance 

relief, Docket PCB 12-126, from the sulfur dioxide emission rate in the multi-pollutant 

standard ("MPS") rules ("Variance Relief'). My testimony will also describe how, as was the 

case with AER under Ameren, these challenges are expected to limit New AER's ability to 

access third-party capital for investment in state- and federally-mandated environmental 

control equipment (or otherwise) on economic terms supportable by New AER's financial 

condition, if at all. 

II. THE EXPECTED FINANCIAL CONDITION OF NEW AER 

5. AER's financial outlook, credit profile and access to third-party capital have 

weakened further since AER received the Variance Relief, as a result of persistently low 

power prices and ongoing uncertainty regarding federal environmental regulations. Ameren 

specifically cited its "analysis of the current and projected future financial condition of [AER], 

including the need to fund GENCO debt maturities" as one of its chief motivations for exiting 

the merchant generation business in December 2012. 1 Similarly, as described below, New 

AER's financial condition outlook is expected to be challenged. Thus, the variance relief 

requested by IPH will continue to play a critical role in allowing New AER to manage its 

liquidity and credit quality in the midst of a currently challenged merchant generation 

1 Ameren Form 8-K filing (December 20, 20 12). 

2 
operating environment. 

6. AER continues to face a persistently low power price environment that has 

impaired its credit profile and its ability to fund capital expenditures and cash flow shortfalls. 

As a merchant generator, AER's earnings and cash flow exhibit significant volatility and are 

materially impacted by changes in the relationship between fuel and power prices. The decline 

and ongoing weakness in power prices has pressured the earnings of AER's primarily coalfired generation fleet, impairing AER's financial health and access to third-party capital on 

economic terms supportable by AER's financial condition. Forecasts of future power prices 

suggest that AER's cash flow are expected to remain under pressure through at least 2016. 

Moody's Investor Services ("Moody's") recently stated: 

"Energy prices for power continue to trade at depressed levels owing in large 

part to low natural gas prices. Gas prices, which once lifted the overall price of 

power, have declined significantly over the past several years. While natural gas 

prices have recovered somewhat from a low in 2012, they are expected to remain 

depressed for the foreseeable future due to market fundamentals driven by the 

glut of shale gas supply .... Outside of ERCOT, most of the deregulated markets 

have significant surplus capacity. . .. To have shortages, another round of 

widespread shutdowns would be required, involving many gigawatts of large 

coal or nuclear plant capacity. This scenario is unlikely to occur unless the price 

of gas fa1ls further on a sustained basis or there is a marked shift in the economic 

calculus of power plant owners. Demand growth is also not expected to be 

helpful in closing the surplus gap any time soon."2 

While power prices in all markets have been negatively affected by low natural gas prices, 

certain regions have fared worse on a relative basis. Energy and capacity prices in MISO, for 

example, have been particularly depressed, given an oversupply of low-marginal-cost 

2 Moody's, "Unregulated Utility & Power Companies: Still No Sign of Recovery'' (February 6, 2013). 

3 
generation. Moody's, in the same report, stated: 

"The downturn [for merchant generators] is most severe in the MISO and upstate 

New York regions. MISO and upstate New York have very low capacity prices 

as well as low energy prices, because these regions are dominated by coal and 

nuclear generation and, in upstate New York, significant hydropower. 

Companies most concentrated in these regions include Oynegy and Ameren 

GENCO." 

Specifically, as of July 5, 2013, forward market power prices for the Indiana Hub (located in 

MISO), the relevant liquid trading hub for the majority of the Acquired Plants, are projected to 

be $32.76/MWh, $31.64/MWh, $32.62/MWh and $34.59/MWh in 2013, 2014, 2015 and 

2016, respectively, which suggests that AER's cash flow are expected to remain under 

pressure through at least 2016.3 Similarly, equity analyst Steve Fleishman of Wolfe Trahan 

suggested that the outlook for power and natural gas prices is unlikely to improve in the near 

term: 

"We see limited upside potential for power and natural gas prices in the near 

term since key structural changes in these markets do not come until 2015 or 

beyond. In power, there will be some shutdowns over this period to implement 

EPA rules and also some regions, such as Texas, are already tight. For the most 

part, however, power markets should have ample supply. More importantly, 

power demand shows little sign of turning and may even contract in certain 

regions. For natural gas, there will likely be ebbs and flows in pricing due to 

weather and coal-to-gas switching, but forward prices likely stay range bound in 

the $3.50 - $4.50 area until the new structural demand forces kick in. Even when 

demand ultimately drives prices above this trading range, we do not expect 

natural gas to rise above $5.00 - $6.00 long term, given the vast supply of shale 

3 SNL, prices as of7/5/2013. 

4 
gas in the United States."4 

7. AER's credit profile bas been further challenged by the ongoing uncertainty 

regarding potential federally-mandated environmental regulations. Incremental expenditures 

stemming from the potential federal regulation of greenhouse gasses and coal combustion 

residuals, for example, could further exacerbate AER's currently weak liquidity profile. 

Unregulated power companies are generally more challenged by increasingly stringent 

environmental mandates than the.ir regulated utility peers. Environmental regulations increase 

the operating costs of all fossil generation. However, while regulated power companies are 

able to recover the costs of environmental regulations through authorized rates, unregulated 

power companies recover their costs through market driven prices and earnings. 

8. As shown in Table 1 below, GENCO, AER's only rated subsidiary, has seen its 

credit rating cut 7 notches by both Standard & Poor's ("S&P") and Moody's since 2008. The 

downgrades appear to be attributable to a decline in net income and cash flow during that time 

period, among other factors. AER's net income declined from $359 million in 2008 to ($396) 

in 2012. GENCO's credit rating has been cut 4 and 3 notches by S&P and Moody's, 

respectively, since AER was granted the Variance Relief. 

4 Steve Fleishman (Wolfe Trahan), "Utilities and Power: Income But Little Growth; Patience on Power" (March 

13, 2013). 

5 
TABLEl($fNMILLIONS) 

2008 2009 2010 2011 2012 2013 

S&P Rating BBB-/Stable BBB-/Stable BBB- BBB- B-IStable CCC+/ 

/Outlook /Negative /Negative Negative 

Moody's 

Rating Baa2/Stable Baa3/Stable Baa3/ Baa3/Stable Ba3/Negat1ve B3/ Negative 

!Outlook Stable 

Net 

lncomei(Loss) $359 $238 ($415) $41 ($396) NA 

The challenged financial outlook for AER (and, accordingly, New AER) is further evidenced 

by the trading performance of the GENCO bond prices (Table 2), which were trading 

relatively close to par at the time AER was granted the Variance Relief. GENCO bond prices 

traded down significantly following Ameren's announcement on December 20, 2012 that it 

planned to exit the merchant generation business, and still trade well below par, which I 

believe reflects the understanding that Dynegy will not provide liquidity support, investor 

concern regarding the long-term financial health of New AER, and the attendant effect of such 

concern on the Company's ability to access the capital markets in order to refinance the 

GENCO debt at maturity, among other factors. 

TABLE2 

7.00%-Due 4/2018 6.30%- Due 212020 7.95%-Due 612032 

Price on 9120/2012 $97.19 $89.69 $91.56 

Price on 1212 112012 $75.44 $75.31 $74.06 

Price on 3/ 1312013 $55.69 $52.56 $53.19 

Price on 3115/2013 $75.81 $71.19 $71.56 

Price on 7/512013 $81.81 $75.8.1 $76.06 

9. With Ameren retaining the Put Assets, nearly 100 percent of New AER's energy 

6 
production and gross margin will be derived from coal-fired generation facilities. Moody's 

recently stated: 

"Falling natural gas prices have had the most dramatic impact on the operating 

cash flow of coal and nuclear generation. As the price of natural gas falls, it 

drives down the energy price of power. For a natural gas plant, there is a 

corresponding fall in its fuel cost, which is also based on price of natural gas. But 

for coal and nuclear plants, there has not been much of a decline for delivered 

price of coal or processed uranium. To make matters worse, coal and nuclear 

plants also have a much higher fixed operating cost on a $/kW basis than gas 

plants. . . . Though they are both heavily impacted by low natural gas prices, 

nuclear plants generally fare better than coal plants because their all-in 

production cost tends to be lower and they have much less burden in terms of 

environmental compliance costs." 5 

10. Ameren specifically cited AER's challenged financial condition as one of its 

chief motivations for exiting the merchant generation business: 

"Ameren's Merchant Generation business segment and GENCO have 

experienced decreasing earnings and cash flows from operating activities over 

the past few years, including the current year, as margins have declined 

principally as a result of weaker power prices. In addition, environmental 

regulations have resulted in significant investment requirements over the same 

timeframe. . . . Ameren has sought to have its Merchant Generation business 

segment and GENCO fund their operations internally and not rely on financing 

from Ameren. ln December 2012, Ameren determined that it intends to, and it is 

probable that it will, exit its Merchant Generation business segment before the 

end of the previously estimated useful lives of that business segment's long-lived 

assets. This determination resulted from Ameren's analysis of the current and 

projected future financial condition of its Merchant Generation business 

segment, including the need to fund GENCO debt maturities beginning in 

5 Moody's, "Unregulated Utility & Power Companies: Still No Sign of Recovery" (February 6, 20 13). 

7 
2018."6 

Prior to its decision to divest its merchant generation business, Ameren had taken several 

measures to preserve liquidity and manage its credit profile with the goal of weathering the 

power market downturn. Specifically, Ameren reduced operating and maintenance capital 

expenditures, divested selected generating plants, and established an internal plant "put" 

mechanism to provide GENCO with an emergency standby liquidity. Despite these measures, 

Ameren appears to have ultimately determined that market conditions were not improving 

quickly enough to allow AER to fund its cash needs and near-term GENCO debt maturities 

($300 million in 2018; $250 million in 2020) without parent support. 

In fact, given the debt incurrence covenant under the terms of its current bond indenture, and 

its weakened financial condition and outlook, GENCO is currently contractually prohibited 

from incurring any additional debt financing. In its lQ 2013 10-Q, Ameren stated: 

"During the first quarter of 2013, Genco's interest coverage ratio fell to a value 

less than the specified minimum level required for external borrowings, and we 

expect the ratio to remain less than this minimum level through at least 2015. As 

a result, Genco's ability to borrow additional funds from external third-party 

sources is restricted." 

11. Upon closing of the transaction, IPH, New AER and its consolidated 

subsidiaries will have approximately $220 million in cash, a majority of which will be utilized 

over the next several years to fund operations, pay interest and provide some working capital 

and credit support.7 This suggests that, at closing, !PH would not have the ability to fund the 

remainder of the approximately $500 million projected by IPH for the installation of the 

Newton FGD project. Similarly, Dynegy has concluded that both the upfront cash at closing of 

6 Ameren Form 8-K filing (December 20, 20 12). 

1 See Affidavit of Mario E. Alonso (paragraph 20). 

8 
the transaction and the synergies that Dynegy projects following the transaction are required to 

provide comfort that the business will have the necessary liquidity over the next several years 

and adequate liquidity will not exist over the next several years to simultaneously continue 

operating the Acquired Plants and also spend hundreds of millions on capital investments to 

accelerate installation of the Newton FGD project. 8 

Likewise, Dynegy has stated that New AER's affiliation with Dynegy will not improve the 

Company's ability to fund environmental-related expenditures, whether via Dynegy parent 

equity contributions or enhanced access to third-party capital: 

"IPH and the Acquired Merchant Utilities, as AER under Ameren, must be selffunding and support their own expenses through their own operating revenues." 9 

Dynegy has publicly committed to its investors and bondholders that New AER will need to 

be self-sufficient. That commitment was made clear by Dynegy CEO Bob Flexon on a March 

14,2013 investor call: 

"The acquisition of AER is being accomplished through a newly created 

subsidiary of Dynegy, IPH, which will be a ring-fenced non-recourse subsidiary 

. . . that will observe corporate separateness formalities. In structuring the 

transaction, we established and followed these principles: IPH must stand on its 

own and be a viable self-sustaining business; Dynegy cannot and will not put its 

balance sheet at risk; and there is no intent, no plans and no reason to engage in 

any type of financial restructuring of Genco's public debt." 

Feedback received by Dynegy from credit rating agencies suggests that the agencies would 

likely view any Dynegy provision of financial support to New AER negatively: 

"As part of its diligence process prior to entering the Transaction Agreement, 

Dynegy contacted the credit rating agencies (Moody's and Standard & Poor's) to 

8 See Affidavit of Mario E. Alonso (paragraph 25). 9 See Affidavit of Mario E. Alonso (paragraph 13). 

9 
understand the transaction's implications, if any, on Dynegy's credit rating. Both 

credit rating agencies agreed that, as structured, the transaction was a credit 

neutral event because of the non-recourse nature of IPH. However, the credit 

rating agencies made clear that the transaction would have a negative effect on 

the credit rating of Dynegy if the acquired entities were to be absorbed into the 

Dynegy capital structure or if Dynegy were to provide financial support to the 

Acquired Merchant Utilities other than limited amounts of working capital. " 10 

Thus, given (a) the inability of IPH to fund the remainder of the approximately $500 million 

Newton FGD project with cash on the balance sheet of New AER and its consolidated 

subsidiaries at transaction close; (b) Dynegy' s conclusion that both (i) the up front cash at 

closing of the transaction and (ii) the synergies that Dynegy projects over the next several 

years following the transaction are required to provide comfort that the business will have the 

necessary liquidity over the next several years; (c) Dynegy's conclusion that adequate liquidity 

will not exist over the next several years to simultaneously continue operating the Acquired 

Plants and also spend hundreds of millions on capital investments to accelerate installation of 

the Newton FGD project, it appears that New AER will not be able to meet the MPS 

requirements without the requested variance relief, or to accelerate installation of the 

remainder of the approximately $500 million Newton FGD project. ln addition, given (a) the 

public commitments Dynegy has made to its equity investors in respect of not placing its 

balance sheet at risk by providing capital to New AER; and (b) commentary of credit rating 

agencies in respect of Dynegy potentially providing capital to New AER, as described below, 

it appears that for Dynegy to operate New AER absent the requested variance relief and to 

provide capital to New AER, other than limited amounts of working capital, would adversely 

affect Dynegy's own access to capital (e.g., a credit rating downgrade could materially 

10 See Affidavit of Mario E. Alonso (paragraph 17). 

10 
increase Dynegy's cost of capital). 

t 2. Moreover, even if Dynegy were to provide financial support to New AER, its 

current credit ratings suggest that it has less financial flexibility than Ameren had at the time 

the Variance Relief was granted. Dynegy is currently rated B (S&P) and B2 (Moody's), while 

Ameren benefited from significantly stronger investment-grade credit ratings of BBB- (S&P) 

and Baa3 (Moody's) at the time the Variance Relief was granted. 

III. INVESTOR AND RATING AGENCY ANALYSES OF NEW AER 

13. Highlighted below is the current commentary of certain equity analysts that are 

responsible for providing independent guidance to large institutional and retail investors 

regarding the power sector. In their commentary, equity analysts highlight New AER's 

challenged cash flow profile, but note the limited potential downside for Dynegy shareholders, 

given the non-recourse nature of the transaction. 

"The debt assumed is non-recourse back to Dynegy and does not directly 

deteriorate Oynegy's preexisting liquidity or capital structure. . . . Our analysis 

presumes current forward power prices and a $1/kW-month capacity price. 

Under these conditions, we believe the [New AER] portfolio will not likely be 

free cash flow positive on an unhedged basis in 2015, which is a more 

conservative outlook than Dynegy's guidance." - Citi, 3/15/2013 

"[The] acquisition yields little equity value, as we expect restructuring to 

continue. Consistent with the structuring of NRG and GenOn's transaction, the 

deal will be done at a non-recourse subsidiary .... We believe the Genco 

subsidiary (Joppa, Newton, Coffeen) does not have equity value net of its debt, 

and believe the fact that Ameren would transact its non-encumbered assets 

(Edwards, Duck Creek) for nothing is suggestive of limited underlying value in 

those assets, net of liabilities, which includes coal ash ponds (which has recently 

attracted some attention) .... We estimate the portfolio in aggregate continues to 

11 
generate cash losses; we anticipate the Company will continue to use its existing 

liquidity to fund these losses."- UBS, 311 4/2013 

The equity analyst commentary suggests that the Acquired Plants may have negative equity 

value, even with the benefit of the requested variance relief. As such, any investment to meet 

the MPS requirements without the requested variance relief, or to accelerate installation of the 

remainder of the approximately $500 million Newton FGD project, would likely be viewed as 

uneconomic and imprudent by investors. 

14. The credit rating agencies, whose v1ews are taken into consideration by 

investors in debt securities and lenders, have taken an increasingly negative view on the credit 

quality of AER since the time it received the MPS Variance Relief because of ongoing 

deterioration of power market conditions. Given the expectation that Oynegy will not provide 

additional funds to New AER, the agencies have also made clear that they have not penalized 

Dynegy's credit rating. Below are samplings of credit rating agency commentary following the 

announcement oflPH's agreement to acquire New AER: 

Credit Rating Agency Statements Regarding the Outlook for New AER 

"The negative outlook reflects our base case scenario that Genco's financial 

measures and profit margins will meaningfu11y deteriorate over the next few 

years because of continued weak power prices. These trends could result in 

lower ratings during the next 12 months and, absent a reversal of price trends, 

could lead to a payment default or debt restructuring .... Genco's ' vulnerable' 

business risk profile reflects its dependence on the commodity price of 

electricity, its competitive position in its markets, and its reliance on a 

meaningful improvement to power prices to fully meet its financial obligations. 

. . . Over the next year, we expect that expiring higher-priced hedges will 

continue to be replaced by lower market prices. While we expect that 

management may continue to identify further cost reduction opportunities, the 

12 
business risk profile and operating results will continue to be pressured by 

continued weak electricity prices and the company's Midwest location, which 

lacks a robust capacity market. ... Genco has ' less than adequate liquidity', 

reflecting the following qualitative factors and assumptions: the Company lacks 

a core bank relationship and essentially relies on its ability to generate cash, cash 

on hand, and its asset put option as its sole sources of liquidity; the Company has 

a poor standing in the credit markets as demonstrated by the Company's debt, 

which is trading with a yield to maturity of about 20%; in our view, the 

Company would not be able to withstand a material low probability event, such 

as a prolonged plant outage." - S&P, 3/28/20 13 

Credit Rating Agency Statements Regarding Dynegy Support of New AER 

"ln March, Dynegy secured an agreement to acquire the AER merchant assets 

and operations from Ameren, with the closing planned by the end of 2013. We 

have not factored any cash flow from AER into our analysis. Dynegy will hold 

the acquired assets as a ring-fenced subsidiary, to shield Dynegy from risk 

associated with them. We do not expect Dynegy to fmancially support the 

acquired assets over the next two years, since Ameren is essentially providing 

deal liquidity to get them through the next few years of likely depressed power 

prices." - S&P, 4/2/20 13 

IV. CONCLUSION 

15. AER's financial outlook and credit profile have weakened further since AER 

received the Variance Relief-T believe this is a result of persistently low power prices and 

ongoing uncertainty regarding federal environmental regulations. Accordingly, the prospects 

of sourcing additional third-party capital on economic terms supportable by New AER's 

financial condition, if at all, are likely to remain challenged. In fact, Dynegy was unable to 

obtain a debt facility at New AER on economic terms coincident with the transaction, "given 

the low cash flow profile [of the Ameren Merchant Utilities}, negligible lien capacity of the 

13 
assets, existing debt and weak credit profile. " 11 Importantly, based on Dynegy analysis, both 

the upfront cash at closing of the AER transaction and the synergies that it projects following 

the transaction are required to provide comfort that the business will have the necessary 

liquidity over the next several years, particularly given the volatile nature of the markets. 

Dynegy has stated, therefore, that it is not feasible over the next several years to 

simultaneously have adequate liquidity necessary to continue operating the Acquired Plants 

and also spend hundreds of millions on capital investments to accelerate installation of the 

Newton FGD project, install air pollution controls or otherwise comply with the MPS without 

the requested variance relief. Moreover, given the potential adverse reaction of the credit 

rating agencies, investors and bondholders were Dynegy to provide financial support to IPH or 

New AER, New AER's affiliation with Dynegy will not improve New AER's financial 

outlook or its ability to fund environmental-related expenditures on a more accelerated 

timeframe. In short, I believe that the various challenges faced by New AER are likely the 

same, if not worse, than those faced by AER when it was granted the Variance Relief. The 

rationale for IPH's requested variance relief remains the same as for the Variance Relief.- it 

will continue to play a critical role in allowing the Company to manage its liquidity and credit 

quality in the midst of a currently challenged merchant generation operating environment. 

11 See Affidavit of Mario E. Alonso (paragraph 15). 

14 
FURTHER, Affiant sayeth not. 

IRENE M. MONTERO 

Notary Public, State of New Yor1< 

No. 01M06270607 

Qualified in Queens County 

Commission El!pires October22, 2016 

15 
EXHIBIT 10

ENVIRONMENTAL IMPACT: TABLE 1 & TABLE 2
Table 1 

Year

Baseline Heat 

Input

MMBtu

MPS SO2 Rate

lb/MMBtu

MPS Baseline 

SO2 

Tons

Variance SO2 

Rate

lb/MMBtu

Variance SO2 

Tons

Actual SO2 

Emissions

SO2 Reduced

Tons (1)

2010 340,446,252 0.50 85,112 0.50 85,112 70,560 14,552 2011 340,446,252 0.50 85,112 0.50 85,112 72,538 12,574 2012 340,446,252 0.50 85,112 0.38 64,685 45,712 18,973 2013 340,446,252 0.50 85,112 0.35 59,578 8,289 2014 340,446,252 0.43 73,196 0.35 59,578 8,289 2015 340,446,252 0.25 42,556 0.35 59,578 8,289 2016 340,446,252 0.25 42,556 0.35 59,578 8,289 2017 340,446,252 0.23 39,151 0.35 59,578 7,699 2018 340,446,252 0.23 39,151 0.35 59,578 7,699 2019 340,446,252 0.23 39,151 0.35 59,578 7,699 2020 340,446,252 0.23 39,151 0.23 39,151 7,699 Total 655,359 691,106 110,050 

Note for the "Cumulative Reductions in SO2 Variance Tons" column, a positive number indicates an emission decrease (benefit).

Ameren MPS Group Variance SO2 Limit Comparison to the Current MPS

(1) Tons shown for 2010, 2011 and 2012 are based on actual SO2 emissions. Tons shown for 2013-2020 are based on not operating Hutsonville an

2016 do not include any SO2 emissions for FutureGen 2.0 because FutureGen 2.0 is not scheduled to begin operations until mid-2017. For 2017-20two times (1.8) worst-case potential SO2 emissions from FutureGen 2.0.

Exhibit 10 - 1
Table 2

Year

Baseline Heat 

Input

MMBtu

MPS SO2 Rate

lb/MMBtu

MPS Baseline 

SO2 

Tons

Variance SO2 

Rate

lb/MMBtu

Variance SO2 

Tons

Actual SO2 

Emissions

SO2 Reduced

Tons (1)

2013 340,446,252 0.50 85,112 0.35 59,578 8,289 2014 340,446,252 0.43 73,196 0.35 59,578 8,289 2015 340,446,252 0.25 42,556 0.35 59,578 8,289 2016 340,446,252 0.25 42,556 0.35 59,578 8,289 2017 340,446,252 0.23 39,151 0.35 59,578 7,699 2018 340,446,252 0.23 39,151 0.35 59,578 7,699 2019 340,446,252 0.23 39,151 0.35 59,578 7,699 2020 340,446,252 0.23 39,151 0.23 39,151 7,699 Total 400,024 456,198 63,952 

Note for the "Cumulative SO2 Variance Reduced Tons" column, a positive number indicates an emission decrease (benefit).

Ameren MPS Group Variance SO2 Limit Comparison to the Current MPS

(1) Reduced tons shown for 2013-2020 are based on not operating Hutsonville and Meredosia. Reduced tons in 2017-2020 are less nearly two timeemissions from FutureGen 2.0. Tons shown for 2013-2016 do not include any SO2 emissions for FutureGen 2.0 because FutureGen 2.0 is not sched2017. 

Exhibit 10 - 2
EXHIBIT 11

AFFIDAVIT OF ARIC D. DIERICX 
AFFIDAVIT OF ARIC D. DIERICX 

I. Background and Qualifications 

1. My name is Aric D. Diericx. I am the Senior Director - Environmental 

Compliance for Dynegy Operating Company. Dynegy Operating Company, an affiliate of 

Dynegy Inc. ("Dynegy"), provides business services to Dynegy's operating subsidiaries, 

including Illinois Power Holdings, LLC ("IPH"), Dynegy Midwest Generation, LLC ("DMG"), 

and Dynegy KendaJl Energy, LLC. My business address is 604 Pierce Blvd., O' Fallon, Illinois, 

62269. 

2. I have been employed with Dynegy in my current position or similar 

environmental compliance positions for the past 13 years. Prior to that and beginning in 1979, I 

was employed by Illinois Power Company and worked in its environmental department. In 

February 2000, Dynegy acquired Illinova Corporation, the fossil fuel-fired electric generating 

assets of lllinois Power Company. I received a Bachelor of Science degree in Meteorology from 

Northern Illinois University in 1979. 

3. As Senior Director - Environmental Compliance, my responsibilities include 

oversight of permitting, regulatory and policy development, and compliance for air, water, waste 

and other environmental matters at DMG's coal-fired power plants in lllinois, as weU as 

Dynegy's power plants in other states. My duties include supervising environmental staff 

personnel, representing Dynegy before environmental regulatory agencies and governmentaJ 

authorities, and developing and implementing environrnentaJ compliance strategies. More 

specifically, I am responsible for DMG's compliance efforts regarding the Illinois multipollutant standard ("MPS") rule by the DMG MPS Group, which consists of five coaJ-fired 
power plants (i.e., ten electrical generating units) that elected into the MPS in 2007. 1 I was 

directly involved in the 2006 and 2009 lllinois rulemaking proceedings concerning development 

of the MPS rule. 

4. I am familiar with the contemplated transaction between IPH and Ameren 

Corporation ("Ameren"), having led Dynegy's environmental due diligence efforts for the 

transaction. I provide this affidavit in support of the Petition for Variance filed by IPH, 

AmerenEnergy Medina Valley Cogen, L.L.C. and Ameren Energy Resources, LLC ("AER") 

("Petition for Variance"). I make this affidavit based on personal knowledge or on knowledge I 

have obtained through inquiry of individuals employed by Dynegy or its affiliates. 

II. The Proposed Variance's Compliance Plan Will Reduce Overall S02 Emissions 

5. The Petition for Variance includes as Exhibit 10 two tables-- Table 1 and Table 2 

-- that identify the sulfur dioxide ("S02") emissions, in tons, that are expected to occur from the 

seven-plant AER MPS Group under the current Ameren MPS Group Multi-Pollutant Standard 

rule (i.e., 35 Ill. Admin Code 225.233(e)(3)) as compared to the projected S02 emissions under 

the compliance plan set forth in the Petition for Variance. The two tables are based on the 

format and content of the emissions table used by AER in its variance petition proceeding, PCB 

12-126, Petitioner's Post-Hearing Brief, Exhibit 4 (referred to as Table 3 in the Post-Hearing 

Brief) (filed Aug. 15, 2012). 

6. Table 1 identifies S02 emissions for the seven-plant AER MPS Group for the 

period 2010 through 2020. Table 1 reflects two updates to the emissions table used by AER in 

PCB 12-126. First, Table 1 includes the AER MPS Group's actual S02 emissions for calendar 

1 Jn 201 1, DMG retired the Vermilion Power Station and its two coal-fired generating units. 

2 
year 2012, as reported by AER. The actual tons of S02 emitted during 2012 by the AER MPS 

Group were less than projected in the emissions table used by AER in PCB 12-126. Second, 

Table 1 does not include S02 emissions in years 2013 through 2016 from the FutureGen 2.0 

project, which is planned for development at the Meredosia facility, because, based on 

information provided by Ameren Services Company, the FutureGen 2.0 project is not expected 

to begin operations until September 2017. With these two updates, as identified in Table 1, the 

compliance plan set forth in the Petition for Variance will result in a net reduction of 74,303 tons 

of S02 over the period 2010-2020. Furthennore, over the period 2012-2020, Table 1 identifies a 

4 7' 178 ton net reduction in so2 emissions. 

7. Table 2 identifies S02 emissions for the seven-plant AER MPS Group for the 

period 2013 through 2020. As identified in Table 2, the compliance plan set forth in the Petition 

for Variance will result in a net reduction of 7, 778 tons of S02 over the period 2013-2020. 

8. Accordingly, Tables 1 and 2 each show that the compliance plan in the Petition 

for Variance would result in a net overall reduction of S02 emissions by achieving additional 

tons of S02 emissions reduction as compared to the tons of S02 emissions reductions that would 

result from compliance with the current Ameren MPS Group Multi-Pollutant Standard rule. 

9. I have read the Petition for Variance and the facts stated therein concerning the 

compliance plan, environmental impact, compliance with federal and Illinois law, and DMG's 

environmt!ntal compliance activities are hue and correct to the best of my knowledge and belief. 

3 
FURTHER, Affiant sayeth not. 

DATED: 

Subscribed and swo~ 

before me this \ -:f ay 

of July, 2013. -

4 

~,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,~ 

~ ''OFFICIAL SEAL" ~ 

i LAUREN R. SCHMIERBACH ~ ~ NOTARY PUBLIC-STATE OF IlliNOIS ~ ~ MY COMMISSION EXPIRES MAR. 16, 2014 : ~,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,~ 
EXHIBIT 12

ENVIRONMENTAL IMPACT: AECOM MEMORANDUM
 AECOM 978-905-2100 tel 

250 Apollo Drive 978-905-2100 fax 

 Chelmsford, MA 10824 

Memorandum 

To Illinois Power Holdings 

AmerenEnergy Medina Valley Cogen 

Ameren Energy Resources 

 Page 1 

 

Subject Health Effects Evaluation of Request for Variance from the Illinois Sulfur Dioxide 

Multi-Pollutant Standard by Illinois Power Holdings, AmerenEnergy Medina Valley 

Cogen, and Ameren Energy Resources 

From Lisa JN Bradley, Ph.D., DABT 

Date July 18, 2013 

 

The purpose of this memorandum is to provide a toxicologist’s perspective on the joint Petition for 

Variance sought by Illinois Power Holdings, LLC (IPH) and AmerenEnergy Medina Valley Cogen, 

LLC (Medina Valley) (collectively, “the Petitioners”), along with Ameren Energy Resources, LLC 

(AER) as a Co-Petitioner. The information in this memorandum builds upon the variance from the 

Illinois Sulfur Dioxide (SO2) Multi-Pollutant Standard (MPS) sought by AER and granted by the 

Illinois Pollution Control Board on September 20, 2012. The commitments made by AER in the 

original variance proceeding are proposed, in this variance request, to be continued by IPH and 

Medina Valley. The variance is from the 2015 and 2017 MPS SO2 emission rate provisions 

applicable to the seven plants that are referred to as the Ameren MPS Group (Duck Creek, Coffeen, 

E.D. Edwards, Newton, Joppa, Meredosia, and Hutsonville). 

In March 2013, IPH and Ameren Corporation announced that they had entered an agreement under 

which IPH would acquire AER. When the sale is completed, IPH will control the Duck Creek, 

Coffeen, E.D. Edwards, Newton and Joppa power plants, while Medina Valley will control the 

Meredosia and Hutsonville power plants, which are shuttered. 

The evaluation concludes that there would be no adverse impact as a result of implementing the 

requested variance and proposed compliance plan, in fact, a net environmental benefit would be 

realized. In support of this conclusion, this memorandum provides: an overview of the Clean Air 

Act’s National Ambient Air Quality Standards (NAAQS) and a summary of SO2 emissions in the 

U.S. and Illinois; an analysis of the impact of the requested variance; and a discussion of the health 

effects information available regarding exposure to SO2. A discussion of the variance request as it 

may relate to the U.S. Environmental Protection Agency (USEPA) revision in December 2012 of the 

NAAQS for annual PM2.5 (airborne particulate matter of 2.5 micrometers in diameter and smaller) 

is also included. 
AECOM 2

THE CLEAN AIR ACT AND NAAQS 

The Clean Air Act (CAA) was originally passed in 1963, and in 1970 was amended to identify 

pollutants that may reasonably be anticipated to endanger public health and welfare and to issue air 

quality standards for them. SO2 and PM were included in the original constituents identified as a 

“criteria pollutant” and USEPA issued NAAQS in 1971 that have been updated periodically since 

then. The primary NAAQS are to protect public health, and the secondary NAAQS are to protect 

the public welfare, including animals, crops, visibility, and buildings. The current NAAQS for SO2 

and PM are shown in Table 1, below. 

Table 1. NAAQS for SO2 and PM 

Pollutant 

 [final rule cite] 

Primary/ 

Secondary 

Averaging 

Time Level Form 

 Sulfur Dioxide 

[75 FR 35520, Jun 22, 

2010] 

[38 FR 25678, Sept 14, 

1973] 

primary 1-hour 75 ppb (a) 

99th percentile of 1-hour daily 

maximum concentrations, 

averaged over 3 years 

 secondary 3-hour 0.5 ppm Not to be exceeded more than 

once per year 

Particle Pollution 

[78 FR 3086, 

January 15, 

2013] 

 

PM 2.5

primary Annual 12 μg/m3 annual mean, averaged over 3 

years 

secondary Annual 15μg/m3 annual mean, averaged over 3 

years 

primary and 

secondary 24-hour 35 μg/m3 98th percentile, averaged over 3 

years 

PM10

primary and 

secondary 24-hour 150 μg/m3

Not to be exceeded more than 

once per year on average over 3 

years 

(a) Final rule signed June 2, 2010. The 1971 annual and 24-hour SO2 standards were revoked in that same 

rulemaking. However, these standards remain in effect until one year after an area is designated for the 2010 

standard, except in areas designated nonattainment for the 1971 standards, where the 1971 standards remain 

in effect until implementation plans to attain or maintain the 2010 standard are approved. 

Source: USEPA. 2012. National Ambient Air Quality Standards (NAAQS). Retrieved July, 17, 2013, from: 

http://www.epa.gov/air/criteria.html. 

Title IV, the Acid Rain Program, of the Clean Air Act Amendments was enacted in 1990 and 

requires reductions in both SO2 and nitrogen oxides (NOx) emissions from the electric power 

industry. Since 1990, emissions of SO2 (and NOx) from the electric power sector have decreased 

dramatically, this at a time when the use of coal in the U.S. by the electric power sector has been 

increasing. Figure 1, below, graphically illustrates these dramatic changes for the U.S. (US EIA, 

2012). Figure 2 shows the trend in SO2 emissions in Illinois in recent years, and Figure 3 shows 

the trends in ambient air concentrations of SO2 for Illinois, including the decrease in SO2 

concentrations since 2008 (IEPA, 2012). 
AECOM 3

Figure 1. Coal Consumption, and SO2 and Nitrogen Oxides Emissions Over Time 

Figure 2. SO2 Emissions Trends (1000s of Tons/Year), Illinois 
AECOM 4

Figure 3. SO2 24-hour Trends (ppb), Illinois 

THE MPS AND THE REQUESTED VARIANCE 

Specifics of the Requested Variance 

The MPS specifies a 0.5 lb/MMBtu SO2 emission rate until 2014 when the required emission rate is 

decreased to 0.43 lb/MMBtu, followed by a decrease to 0.25 lb/MMBtu in 2015. Under the MPS, 

the SO2 emission rate is further decreased to 0.23 lb/MMBtu in 2017. The requested variance for 

the seven power plants in the Ameren MPS Group (as defined above) seeks relief from meeting the 

0.25 lb/MMBtu SO2 emission rate required by the provisions of the MPS beginning in 2015 and the 

0.23 lb/MMBtu emission rate that is required beginning in 2017. The commitments made by AER in 

the original variance proceeding are proposed, in this variance request, to be continued by IPH and 

Medina Valley. Specifically, IPH and Medina Valley are proposing a mitigation emission rate of 0.35 

lb/MMBtu for the MPS Group that would take effect in 2013, which means that a more stringent 

SO2 emissions limitation will be in effect in 2013 and 2014 than would be otherwise in effect under 

the MPS rule. The MPS Group would comply with the 0.35 lb/MMBtu mitigation emission rate from 

2013 through 2019, with the 2017 MPS emission rate of 0.23 lb/MMBtu being met beginning in 

2020. Table 2 provides the comparison of MPS Group SO2 emissions under the provisions of the 

MPS rule and the requested variance, and these are shown graphically in Figure 4. 
AECOM 5

Table 2. The Ameren MPS Group Variance SO2 Limit Comparison to the Current MPS, 2013-

2020 

Year 

Baseline 

Heat Input 

MMBtu 

MPS SO2 

Rate 

lb/MMBtu 

MPS 

Baseline 

SO2 

Tons 

Variance 

SO2 Rate

lb/MMBtu 

Variance 

SO2 

Tons 

Actual SO2 

Emissions 

SO2 

Reduced 

Tons (1) 

Net 

Variance

 SO2 

Tons 

Cumulative 

Reductions 

in 

 SO2 

Variance 

Tons 

2013 340,446,252 0.50 85,112 0.35 59,578 8,289 51,289 33,822 

2014 340,446,252 0.43 73,196 0.35 59,578 8,289 51,289 55,729 

2015 340,446,252 0.25 42,556 0.35 59,578 8,289 51,289 46,996 

2016 340,446,252 0.25 42,556 0.35 59,578 8,289 51,289 38,263 

2017 340,446,252 0.23 39,151 0.35 59,578 7,699 51,879 25,535 

2018 340,446,252 0.23 39,151 0.35 59,578 7,699 51,879 12,807 

2019 340,446,252 0.23 39,151 0.35 59,578 7,699 51,879 79 

2020 340,446,252 0.23 39,151 0.23 39,151 7,699 31,452 7,778 

Total 400,024 456,198 63,952 392,246 7,778 

Note for the "Cumulative SO2 Variance Reduced Tons" column, a positive number indicates an emission decrease (benefit). 

(1) Reduced tons shown for 2013-2020 are based on not operating Hutsonville and Meredosia. Reduced tons in 

2017-2020 are less nearly two times (1.8) worst-case potential SO2 emissions from FutureGen 2.0. Tons shown 

for 2013-2016 do not include any SO2 emissions for FutureGen 2.0 because FutureGen 2.0 is not scheduled to 

begin operations until mid-2017. 

Figure 4. The Ameren MPS Group Variance SO2 Limit Comparison to the Current MPS, 2013-

2020 

The blue line in Figure 4 represents the MPS Group’s baseline SO2 emissions under the MPS rule 

and the black line represents projected SO2 emissions under the requested variance and 

compliance plan. As can be seen in the figure, SO2 emissions under the requested variance are 

considerably lower than the MPS emissions in 2013 and 2014 and are slightly higher in 2015 

through 2019. However, the area representing the difference between the MPS and variance SO2 

emissions from 2013 to 2014 is larger than the area between the MPS and variance SO2 emissions 

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

SO2 Emissions (tons)

Year

Ameren MPS Group Variance SO2 Limit Comparison to the Current MPS

Allowable Emissions Based on MPS  Rate Total Future Emissions Based on Ameren MPS Group Variance Rate

Net difference over time between SO2

emissions based on the  Ameren MPS Group

variance rate and SO2 emissions based on the

MPS baseline rate is a decrease by  74,303 tons.
AECOM 6

in 2015 through 2019. Therefore, there is an overall net improvement (i.e., decline) in SO2 

emissions under the requested variance. 

It should be noted that since 2010 these power plants have voluntarily operated at lower SO2 

emission rates than allowable under the MPS, demonstrating a commitment to reducing emissions. 

If the reduced SO2 emissions starting in 2010 are taken into consideration, the positive difference 

between variance SO2 emissions and those allowable under the MPS is even larger (see Table 3 

and Figure 5, below). 

Table 3. The Ameren MPS Group Variance SO2 Limit Comparison to the Current MPS, 2010-

2020 

Year

Baseline Heat 

Input 

MMBtu

MPS 

SO2 

Rate 

lb/M

MBtu

MPS 

Baseline 

SO2 

Tons

Variance 

SO2 Rate

lb/MMBtu

Variance 

SO2 

Tons

Actual SO2 

Emissions 

SO2 

Reduced 

Tons (1) 

Net 

Variance

 SO2 

Tons 

Cumulative

Reductions 

in 

 SO2 

Variance 

Tons 

2010 340,446,252 0.50 85,112 0.50 85,112 70,560 14,552 70,560 14,552 

2011 340,446,252 0.50 85,112 0.50 85,112 72,538 12,574 72,538 27,125 

2012 340,446,252 0.50 85,112 0.38 64,685 45,712 18,973 45,712 66,525 

2013 340,446,252 0.50 85,112 0.35 59,578 8,289 51,289 100,347 

2014 340,446,252 0.43 73,196 0.35 59,578 8,289 51,289 122,254 

2015 340,446,252 0.25 42,556 0.35 59,578 8,289 51,289 113,521 

2016 340,446,252 0.25 42,556 0.35 59,578 8,289 51,289 104,787 

2017 340,446,252 0.23 39,151 0.35 59,578 7,699 51,879 92,060 

2018 340,446,252 0.23 39,151 0.35 59,578 7,699 51,879 79,332 

2019 340,446,252 0.23 39,151 0.35 59,578 7,699 51,879 66,604 

2020 340,446,252 0.23 39,151 0.23 39,151 7,699 31,452 74,303 

Total 655,359 691,106 110,050 581,056 74,303 

Note for the "Cumulative Reductions in SO2 Variance Tons" column, a positive number indicates an emission decrease 

(benefit). 

(1) Tons shown for 2010, 2011 and 2012 are based on actual SO2 emissions. Tons shown for 2013-2020 are based on not 

operating Hutsonville and Meredosia. Tons shown for 2013-2016 do not include any SO2 emissions for FutureGen 2.0 

because FutureGen 2.0 is not scheduled to begin operations until mid-2017. For 2017-2020, reduced tons are less nearly 

two times (1.8) worst-case potential SO2 emissions from FutureGen 2.0. 

Figure 5. The Ameren MPS Group Variance SO2 Limit Comparison to the Current MPS, 2010-

2020 

0

20,000

40,000

60,000

80,000

100,000

2013 2014 2015 2016 2017 2018 2019 2020

SO2 Emissions (tons)

Year

Ameren MPS Group Variance SO2 Limit Comparison to the Current MPS

Allowable Emissions Based on MPS  Rate Total Future Emissions Based on Ameren MPS Group Variance Rate

Net difference over time between SO2

emissions based on the  Ameren MPS Group

variance rate and SO2 emissions based on the

MPS baseline rate is a decrease by 7,778 tons.
AECOM 7

Lack of Adverse Impact of the Variance 

Over the course of the entire period 2013-2020, the total tons of SO2 reduced in the atmosphere 

will be greater if the requested variance is granted than if it is not. The source of reduction in SO2 

emissions attributable to granting the variance period is two-fold: 1) the MPS Group will emit less 

SO2 via a mitigation emissions rate representing a 19% to 30% reduction in the MPS allowable 

SO2 emissions rate through 2014; and 2) the Hutsonville and Meredosia coal-fired power plants will 

remain shuttered through 2020, which will result in less coal being burned and less SO2 being 

emitted. 

Based on the emissions mitigation commitments in the requested variance, granting the variance 

request would not result in an adverse impact and, in fact, would result in an overall net health 

benefit.

THE POTENTIAL FOR ADVERSE HEALTH EFFECTS FROM SO2 

While concerns about potential health effects associated with exposure to SO2 are understandable, 

there are misconceptions about what the scientific research is telling us. From controlled studies 

with human subjects, there appears to be a continuous spectrum of sensitivity to SO2, with some 

people being completely unaffected by concentrations that lead to severe bronchoconstriction in 

others. Asthmatics are particularly sensitive to the effects of SO2 and the effects are enhanced if 

sufficient amounts of SO2 reach the lower regions of the lungs, which is more likely to occur during 

mouth breathing (as opposed to breathing through the nose) and exercise. Maximum effects of 

SO2 occur within a few minutes and continued exposure does not typically increase the response 

and the effects are generally short-lived and completely reversible (WHO, 2006). 

However, more studies than not have failed to find statistically significant associations between 

long-term and short-term SO2 concentrations and adverse health outcomes on an epidemiological 

basis, indicating that the apparent associations found in the laboratory may well be due to other 

factors in an environmental setting. In fact, USEPA has concluded that there is not a causal 

relationship between long-term SO2 exposure and respiratory effects or mortality (USEPA, 2008). 

While USEPA has concluded that the results of clinical studies in which humans are exposed to 

SO2 concentrations much higher than those found in ambient air support a causal relationship 

between respiratory morbidity and short-term exposure to SO2, nine of the 10 primary epidemiology 

studies attempting to correlate short-term exposure to asthma-related emergency room visits or 

hospitalizations relied upon by USEPA found either no association or very small positive 

associations. USEPA further concludes that the evidence on short-term SO2 exposure is only 

suggestive of a causal relationship with mortality (USEPA, 2008). Therefore, although there is a 

public perception of a correlation between SO2 and health effects, when the studies providing the 

underlying support for such declarations are more closely examined, it becomes clear that the 

association between SO2 exposure and respiratory health effects and mortality is not a scientific 

certainty. 

Asthma Prevalence in the U.S. 

Asthma is the health effect most commonly cited as associated with SO2 exposure, and there is 

public concern about rise in asthma in the U.S. population. However, there are many theories 

about the rise in asthma over the past 30 years, and exposure to outdoor pollution is probably the 

least plausible explanation given that the air quality in Illinois (IEPA, 2012) and the nation as a 

whole, specifically with respect to SO2 emissions, has improved dramatically during the same time 

period over which asthma prevalence has increased. 
AECOM 8

This theory of causality cannot be supported when the dramatic decreases in SO2 emissions in the 

U.S. by the electric power sector is compared to asthma prevalence data. As shown in Figure 6, 

below, asthma prevalence increased from 1980 through 1996 (MMWR, 2007). Less dramatic 

increases have occurred from 2001 through 2010 (CDC, 2012), as shown in Figure 7 below. 

Figure 6. Asthma Prevalence 1980 - 1996 

Figure 7. Asthma Prevalence 2001 - 2010 

NOTES: Asthma prevalence refers to percentage of people who have ever been diagnosed with asthma and still have 

asthma. Data are age adjusted to the 2000 U.S. standard population. SOURCE: CDC/NCHS, National Health Interview 

Survey. 
AECOM 9

Thus, the perceived connection between the rising prevalence of asthma in the U.S. is not borne 

out by the dramatic decreases in SO2 emissions over the same time period. The distribution of 

asthma in other countries also fails to implicate SO2 or other pollutants as an aggravating factor. 

Some of the highest asthma mortality rates occur in Australia and New Zealand, which have 

excellent air quality. Asthma is more prevalent in rural areas of the Scottish highlands, which have 

some of the lowest ozone concentrations in the world, than in more urban and polluted parts of the 

United Kingdom, according to a recent report (Friebele, 1996). 

Changes in the diagnostic coding of asthma and survey questions in self-reporting asthma 

questionnaires over the last 30 years have likely altered the diagnosis of asthma cases and caused 

changes in prevalence and incidence statistics. The International Classification of Diseases (ICD) 

provided by the World Health Organization (WHO) was revised in 1978 (9th revision) and 1990 

(10th revision) resulting in a change to the coding of asthma. In the ICD 8, a patient with “asthmatic 

bronchitis” would have been coded under bronchitis, while in ICD 9 this same person would be 

coded under asthma (Marcus and Braman, 2010). One study that analyzed asthma patient records 

found an increase in patients with an asthma classification that had a history of smoking in the 

1980s versus the 1970s. The cause of this difference was attributed to the change in classification 

of asthmatic bronchitis from a bronchitis heading to an asthma heading, resulting in asthmatic 

bronchitis patients now falling under the umbrella of asthma in the 1980s (Marcus and Braman, 

2010). This change in coding may also influence the validity of epidemiology studies that look at 

hospital emergency room (ER) visits for asthma as potential indicators of an association between 

ambient pollutant concentrations and respiratory effects over years during which changes in the 

asthma definition has changed. 

A large source of asthma surveillance data is compiled by the National Center for Health Statistics 

of the Centers for Disease Control and Prevention (CDC) under the National Health Interview 

Survey (NHIS). The NHIS questions used to evaluate asthma prevalence changed in 1997 and 

2001, resulting in three separate types of questions that could impact asthma prevalence estimates 

from 1980 to 1996, 1997 to 2000, and 2001 to the present (National Heart and Lung Institute; 

www.nhlbi.nih.gov/health/prof/lung/asthma/surveil.htm). These changes prevent comparisons of 

reported asthma rates from 1980 to 1997 to the more recent data set from 1997 to 2001 and from 

2001 to 2010, and illustrate the potential variability in reported asthma prevalence depending on 

how asthma questions are phrased, and what sort of asthma information is requested (lifetime 

incidence versus episodes in the past 12 months, for example). Thus the prevalence graphs above 

a provided for two time periods. 

The increase in asthma cases may also be partially explained by factors relating to changes in 

healthcare access and physician perceptions. The diagnosis of asthma may have become more 

likely than a similar diagnosis of bronchitis or chronic obstructive pulmonary disease (COPD) 

among patients with similar symptoms. One study looked at healthcare data from Manitoba, 

Canada from 1980-1990 and found a statistically significant increase in asthma diagnosis above 

background increases found for other diseases with similar symptoms over that time period 

(Manfreda et al., 1993). The study attributes some of the increase to an increase in the likelihood of 

asthma diagnoses. 

Another factor that may have contributed to the apparent increase in childhood asthma prevalence 

is that children spend much more time indoors today than they did 30 years ago. In addition to 

contributing to the development of asthma, exposure to various indoor air irritants can also 

exacerbate asthma symptoms. Cat, cockroach, and house mite dust allergens have all been 

causally linked to exacerbation of asthma symptoms in sensitive individuals, and environmental 
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tobacco smoke exposure has also been causally linked to exacerbation of asthma symptoms in 

young children (Institute of Medicine, 2000). 

Therefore, the suggestion that SO2 emissions are significant contributors to the rise in reported 

asthma cases (and other diseases) is not supported by evidence in the literature. 

Long-term Health Evaluation 

Despite the calculations demonstrating an overall reduction in the tonnage of SO2 emissions over 

the variance period (see Tables 2 and 3 and Figures 4 and 5 above), there is the concern that 

potential harm could occur during the period of the increase in emissions that would be allowed 

between the years of 2015 and 2019 under the requested variance. 

While looking exclusively at the MPS Group plants there could, theoretically, be additional adverse 

health outcomes between the years of 2015 and 2019, those theoretical health effects will be offset 

by fewer theoretical adverse health outcomes in the years of 2013 and 2014. Specifically, because 

the magnitude of the emission reductions during 2013 and 2014 is greater than the increased SO2 

emissions that will occur between 2015 and 2019, there are fewer adverse health effects overall. In 

addition, because the requested variance and proposed compliance plan include the commitment to 

keep the Hutsonville and Meredosia power plants shutdown, the requested variance will ensure a 

reduction in emissions of other pollutants that otherwise would be allowed under the MPS. 

Therefore, the health benefits of approving the requested variance outweigh the potential for 

adverse health effects, resulting in an overall health benefit, when the entire period of the requested 

variance taken into account. Assuming that one accepts that the SO2 emissions pose a health 

threat, the requested variance represents a tradeoff between greater reductions in health effects in 

2013 and 2014 in exchange for smaller reductions in health effects between the years of 2015 and 

2019. 

It is important to note that the above discussion is predicated on the assumption that the C-R 

(concentration-response) relationships reported in early epidemiological studies indicate causal 

relationships between the SO2 exposures and adverse health effects. However, in most studies 

that have examined the potential for confounding by other co-pollutants (particulates, ozone, 

nitrogen oxides), the small associations observed between ambient SO2 concentrations and 

adverse health outcomes usually become null when two-pollutant models are used, indicating that 

the associations are stronger for the other pollutants or that there is no association with SO2 

(USEPA, 2008; USEPA, 2009; Goodman et al., 2010). [See also the discussion below on 

particulate matter.] As a result, more studies than not have failed to find statistically significant 

associations between long-term and short-term SO2 concentrations and adverse health outcomes. 

According to the USEPA’s own Integrated Science Assessment (ISA, USEPA, 2008) prepared in 

support of the most recent SO2 NAAQS review, “Overall, the epidemiologic studies do not provide 

sufficient evidence to infer a causal relationship between long-term exposure to SO2 and asthma, 

bronchitis, or respiratory symptoms”. The USEPA ISA also concluded that “The available 

epidemiologic evidence on the effect of long-term exposure to SO2 on mortality is inadequate to 

infer a causal relationship at this time” (USEPA, 2008). 

The USEPA ISA does conclude that “the human clinical, epidemiologic, and animal toxicological 

data are sufficient to conclude that there is a causal relationship between respiratory morbidity and 

short-term exposure to SO2” and that “The evidence is suggestive of a causal relationship between 

short-term exposure to SO2 and mortality”. However, of the 10 primary epidemiology studies 

attempting to correlate short-term (daily) SO2 exposures to adverse health outcomes relied upon by 

USEPA, nine found either no association or very small positive associations between daily SO2 

concentrations and asthma-related emergency room visits or hospitalizations. Among the studies 
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for which weak positive associations were observed, conclusions were either: 1) based only on 

results from single-pollutant models (i.e., multiple pollutant models were not used, which are applied 

to determine confounding by co-pollutants); or 2) based on results from single-pollutant models that 

were not statistically significant in two-pollutant models. 

Statistical significance is key to determining if exposure and effect are causally associated. 

Determining whether the effect is isolated, independent, or secondary to a known effect of exposure 

is also important because these types of effects may be the result of other factors not related to the 

exposure of interest (Goodman et al., 2010). Isolated effects occur in only a few test subjects and 

independent effects are those which occur in the absence of other effects expected via the same 

mechanism of action. The fact that these effects occur inconsistently and lack biological plausibility 

is an indication that they are more likely due to another factor or measurement error rather than 

exposure related. A test of statistical significance helps determine whether effects are caused by 

the exposure under study. These tests compare differences between exposed and non-exposed 

groups of test subjects as opposed to evaluating effects in independent individuals. If the difference 

between exposed and non-exposed groups is not statistically significant, the exposure is either 

insufficient to cause the effect under study or the study is not sufficiently powered, most likely due to 

having too few test subjects. 

Only one of the 10 epidemiological studies (NYSDOH, 2006) correlating daily SO2 concentrations 

to adverse health outcomes relied upon by USEPA in the latest NAAQS review found a marginally 

statistically significant association with increased SO2 levels in both single-and two-pollutant 

models. However, the authors of that one study acknowledged that correlations between copollutants made these results difficult to interpret. 

Short-term Health Evaluation 

Concern has been raised previously that the long-term cumulative SO2 reductions do nothing to 

help communities with short-term pollution impacts and it is those short-term impacts that happen to 

children and the elderly population across the state. However, it is not correct that cumulative SO2 

reductions do nothing to abate short-term pollutant impacts. Long-term concentrations are not 

completely independent of short-term concentrations of the same pollutant. In fact, USEPA has 

performed extensive evaluations to determine relationships between short-term and longer-term 

concentrations of various pollutants and has on occasion set a longer-term standard to limit the 

relative frequency with which shorter-term exposures will exceed a particular level. In addition, 

USEPA’s screening modeling guidance indicates that for a point source it can be assumed that the 

maximum daily average concentration is 0.4 of the maximum 1-hour and that the maximum annual 

concentration is 0.08 of the max 1-hr (http://www.colorado.gov/airquality/permits/screen.pdf). From 

this we can infer 24-hour to annual ratio of 0.4/0.08 = 5. Thus, it is widely accepted that long-term 

and short-term concentrations are related to one another. For this reason, the overall net reduction 

in SO2 provided by the requested variance in comparison to the MPS rule is also expected to have 

an effect on reducing short-term exposures over the variance time period. 

SO2 Levels 

Concern has also been expressed previously that high levels of SO2 (and NOx) can exacerbate 

respiratory systems in at-risk individuals (e.g., children, the elderly), including asthma and COPD 

attacks. The operative words regarding this concern are “high levels.” There are many controlled 

human studies that have exposed healthy and asthmatic test populations to SO2 and that have 

measured small lung function decrements in the asthmatic population, particularly at higher than 

normal exertion levels. However, most fail to show a statistically significant response, and even in 

asthmatics (a sensitive subpopulation), responses are only seen at high concentrations on the order 
AECOM 12

of 250 ppb (715 μg/m3) over a 10 minute period (WHO, 2006). Peak exposures in the range of 

4,000 ppb (11,440 μg/m3) to 5,000 ppb (14,330 μg/m3) are required for reductions in mean lung 

function in normal (non-asthmatic) individuals at rest. No significant changes in group mean lung 

function in healthy individuals have been seen below short-term exposures of 1000 ppb (2860 

μg/m3), even with exercise (WHO, 2006). 

To put the SO2 concentrations above into context, according to the Illinois EPA 2011 Air Quality 

Report (IEPA, 2012), the statewide average 24-hour SO2 concentration for 2011 was 39 μg/m3 (15 

ppb) and was the same in 2010, and 45 μg/m3 (17 ppb) in 2009. The statewide average 1-hour 

high in 2011 was 165 μg/m3 (63 ppb), compared with 197 μg/m3 (75 ppb) in 2010, 212 μg/m3 (81 

ppb) in 2009 and 335 μg/m3 (128 ppb) in 2008. Therefore, not only have the air concentrations 

monitored in Illinois been well below levels demonstrated to cause respiratory effects in healthy and 

asthmatic individuals, there has been an overall downward trend in SO2 concentrations in the state 

(corresponding to the national data). See Figures 1, 2 and 3 above. 

In the original variance proceeding, reference was made to a 2010 study conducted by the National 

Research Council (NRC) that indicated that annual health related damages from particulate, SO2 

and NO2 cost $62 billion in 2005 alone. The concentration-response (C-R) relationship used in the 

NRC Health Impact Assessment (HIA) to estimate damages associated with SO2-related hospital 

admissions was from a study conducted by Sheppard et al. (1999). However, this study, like most 

SO2 epidemiology studies, failed to find an association between ambient SO2 concentrations and 

asthma-related hospital admissions, as was clearly acknowledged by the authors. 

The C-R function is a key component of HIAs because it is this function that allows the effect of 

interest to be linked in a quantitative way to incremental changes in concentrations by assuming a 

response continuum. However, C-R relationships are calculated for all pollutants and health 

endpoints examined in a scientific study by the authors, even for those pollutant-health effect 

pairings that are determined through statistics not to be associated with the exposure of interest. 

Therefore, it is up to those conducting the HIA (individuals other than the scientific study authors) to 

choose appropriate C-R relationships for use in modeling. It is disconcerting that the NRC study 

would use a C-R function from a study in which the ambient SO2 concentrations and asthmarelated hospital admissions were determined not to be correlated and casts doubt on the validity of 

the entire NRC report. This is a clear example of how findings published in the scientific literature 

are often misinterpreted and inadvertently or intentionally misused. 

Epidemiological Studies 

Concerns have been raised previously that research demonstrates that even moderate levels of 

SO2 are associated with bronchospasm. Indeed, in the original variance proceeding reference was 

made to the USEPA’s ISA (USEPA, 2008) to support the assertion that epidemiologic studies have 

observed respiratory effects in areas where the SO2 concentration was below the regulatory level in 

place at the time. However, the evidence of respiratory effects below the 24-hour NAAQS 

referenced in the ISA comes entirely from epidemiological studies. To put this finding into context, it 

is important to understand what epidemiological studies can and cannot do. 

Observational epidemiological studies attempt to determine which factors are associated with 

diseases (risk factors) and which factors may protect people or animals against disease (protective 

factors). However, epidemiological studies cannot prove that a specific risk factor actually causes 

the disease being studied. This is because epidemiological studies cannot control for, nor can they 

necessarily identify, all of the factors that may influence a health outcome. Therefore, they are 

plagued with issues of confounding. For example, if coffee drinkers were more likely to also be 

cigarette smokers, and a study was conducted to explore potential associations between coffee 
AECOM 13

drinking and lung cancer, without taking the smoking habits of the coffee drinkers into account, 

smoking would be a confounder and the results may seem to show that coffee drinking increases 

the risk of lung cancer. 

Epidemiological evidence can only show that a risk factor is or is not associated (correlated) with a 

higher incidence of disease in the population exposed to that risk factor. The higher the correlation, 

the more certain the association; but causation cannot be proven in these studies. Therefore, the 

fact that there may be studies showing that hospital admissions or emergency room visits were 

increased in an area where short-term SO2 concentrations were below the NAAQS does not 

necessarily mean that the SO2 concentrations caused the increase in hospital admissions. 

Studies that use population level data, such as respiratory hospital admissions or emergency room 

visits obtained from databases without collecting any data on the individuals involved, are prone to 

what is known as “ecologic fallacy.” This occurs when a correlation observed at the population level 

is assumed to apply at the individual level. Without information on whether the correlations were 

statistically significant and whether co-pollutants and other intervening variables were properly 

controlled for, it is not possible to know what the implications of the findings are or if the statement 

even accurately characterizes the findings. 

Thus, while USEPA’s ISA may have noted that epidemiologic studies observed respiratory effects in 

areas where the SO2 concentration was below the regulatory level in place at the time, the 

respiratory effects were not necessarily due to SO2 exposure. This is discussed in more detail 

below. 

Particulate Matter 

Epidemiological data do indicate that particulate matter is a stronger causal agent for mortality and 

morbidity (i.e., effects other than mortality) than gaseous SO2, and gaseous SO2 is usually found in 

association with particulate matter, as SO2 is a precursor for fine sulfate particles. The original 

scientific health data on particulates, both PM10 (airborne particulate matter of 10 micrometers in 

diameter and smaller data) and PM2.5 only measured the total amount of PM, and certain adverse 

health effects are correlated with total PM, whether measured as PM10 or PM2.5. 

However, the scientific and regulatory communities understood that PM can have many different 

sources, and many different compositions. The National Academy of Sciences, National Research 

Council report (NRC, 2004) states: “The current NAAQS for PM is both size and mass-based and 

implicitly assumes that all particles of a given size have the same toxicity per unit mass, irrespective 

of chemical composition. In the committee’s judgment, this mass-based NAAQS greatly 

oversimplifies complex biological phenomena.” 

Thus, recent studies have focused on speciating the types of PM present in ambient air, and these 

studies indicate that the sulfate component of PM2.5 is not associated with adverse health effects; 

instead, indications are that carbonaceous forms of PM2.5 (black carbon, elemental carbon, such 

as emitted from diesel engines or the combustion of residual oils) are the critical health 

determinants. 

However, recent epidemiological studies have not shown a correlation between adverse health 

effects and ambient SO2, or its particulate product, sulfate. 

 Metzger et al. (2004) demonstrated that 1-hr SO2 and 24-hr PM2.5 from sulfates were not 

associated with hospital emergency room visits for cardiovascular disease symptoms in a 
AECOM 14

study of 31 hospitals in the Atlanta area. Associations were shown for NO2, CO, PM2.5, 

organic carbon, elemental carbon, and oxygenated hydrocarbons. 

 Schwartz et al. (2005) demonstrated that there were no associations between heart rate 

variability (HRV), an indicator of potential cardiovascular complications, and ambient SO2 

or NO2 in a group of elderly residents in Boston, nor for secondary PM. Total PM2.5 was 

correlated with adverse HRV values, but black carbon, a traffic-related component of 

PM2.5, had the strongest correlation with adverse HRV values. The remaining secondary 

PM had a weak association with one adverse indicator. 

 Jerrett et al. (2005) studied health outcomes in 51 cities originally evaluated by the 

American Cancer Society (ACS). Relative Risks (RR) for sulfate [PM2.5 component] 

exhibit a large decline from the 1980s to the 1990s. In contrast, PM2.5 RRs follow the 

opposite pattern, with larger RRs later in the 1990s. The authors state that “The reduction 

in sulfate RR may have resulted from air quality improvements that occurred through the 

1980s and 1990s in response to the acid rain control program. PM2.5 concentrations also 

declined in many places, but toxic mobile sources are now the largest contributors to PM in 

urban areas. This may account for the heightened RR of mortality associated with PM2.5 in 

the 1990s.” 

 Reiss et al. (2007) reviewed the “Evidence of Health Impacts of Sulfate- and NitrateContaining Particles in Ambient Air.” They conclude: “In total, the epidemiologic and 

toxicologic evidence provide little or no support for a causal association of PM sulfate and 

health risk at ambient concentrations.” There is general consensus that SO2 is unlikely to 

be causally associated with mortality. Where adverse outcomes are associated with SO2, 

they indicate that SO2 may be a surrogate for some other exposure. 

 Black carbon, an indicator of traffic emissions, is consistently associated with adverse 

health outcomes in the studies where speciation of the components of PM2.5 is conducted. 

Interestingly, where PM2.5 and the sulfate component are measured, but black carbon is 

not measured, the secondary sulfate component of PM2.5 will track with adverse health 

effects; this is considered to be a phenomenon of “transference” of health associations from 

a poorly or measured parameter to one that is well measured. However, where SO2 and/or 

sulfate (the PM2.5 component) are measured, significant adverse health outcome 

associations are rarely demonstrated (Grahame, 2009). 

Attachment 2 provides an evaluation of PM2.5 measurements in the vicinity of the MPS Group 

power plants. The results indicate that there is no evidence to suggest that the power plants are 

contributing to elevated PM2.5 concentrations. PM2.5 concentration trends are decreasing at the 

monitoring locations, and this trend is expected to continue, and there is no reason to conclude that 

the requested variance will adversely impact these results. 

Health-Outcome Predictive Tools 

Concerns have also been raised based on reported statistics for deaths associated with emissions 

from specific power plants, including, statistics from the Power Plant Impact Estimator Software 

Tool located at http://www.catf.us/resources/publications/view/138 and its accompanying report 

entitled, “Toll from Coal: An Updated Assessment of Death and Disease from America’s Dirtiest 

Energy Source.” This study was commissioned by the Clean Air Task Force (CATF, 2010). The 

underlying assumptions used in deriving these statistics are not particularly transparent, even upon 

examination of the technical support document for the estimator tool and Toll from Coal report (Abt, 

2010). However, one thing noted is that the C-R relationship for SO2 exposure and asthma-related 
AECOM 15

hospital admissions used in the tool was from a study (Sheppard et al., 1999) that failed to find an 

association between ambient SO2 concentrations and asthma-related hospital admissions (a 

shortcoming noted for the NRC report discussed above). Although these types of evaluations are 

becoming increasingly more common, use of these C-R relationships are subject to significant 

uncertainty related to their generalizability and accuracy. One thing is certain, C-R relationships 

from studies that fail to establish an association between the exposure and effect of concern should 

not be extrapolated to other situations in the hopes of providing accurate predictions of adverse 

health outcomes. The other comments made above about C-R relationships and their use apply 

here as well. 

Public Perceptions 

The public debate on air pollution coupled with the sensationalized air pollution health stories in the 

media have created the appearance that harm from air pollution is much greater and more certain 

than suggested by the underlying scientific evidence. According to Dr. Joel Schwartz (2006), 

whose work on the relationship between respiratory hospital admissions and ambient air pollutants 

is amongst some of the most highly cited and who is one of the premier authors of many 

epidemiological studies that have been relied upon by USEPA in establishing and re-evaluating the 

NAAQS, “the incentives in air pollution health research encourage risk exaggeration...Through 

exaggeration, omission of contrary evidence, and lack of context, regulators, activists, and even 

many health scientists misrepresent the results of air pollution health studies and the overall weight 

of the evidence from the research literature” (Schwartz, 2006). Dr. Schwartz’ work is cited across 

multiple fields, including Clinical Medicine, Environment & Ecology, Biology & Biochemistry, and 

Pharmacology & Toxicology. http://www.esi-topics.com/airpoll/interviews/JoelSchwartz.html 

Attached is a copy of “Air Pollution and Health: Do Popular Portrayals Reflect the Scientific 

Evidence?” by Dr. Joel Schwartz, which provides several case studies aimed at demonstrating that 

misinformation about air pollution is a pervasive problem. The Schwartz (2006) article 

demonstrates why it is so important for those involved in evaluating and setting health policy to look 

deeper than the summaries of studies provided by other governmental agencies, health scientists in 

press conferences, and activists in hearings. 

CONCLUSION 

There is no question that very high levels of pollution can kill, as occurred during the “London Fog” 

of 1952, when soot and SO2 were at levels orders of magnitude higher than those experienced in 

developed countries today and visibility was less than 20 feet. However, claims that low levels of 

pollutants cause death is based on observational studies, many of which have not controlled for copollutants and lifestyle variables and usually do not contemplate regional disease patterns that have 

nothing to do with air pollution. It is noteworthy that researchers have been unable to evoke 

adverse health outcomes in animals with SO2 concentrations anywhere near as low as those found 

in ambient air today. And the preponderance of the evidence from a variety of epidemiological 

studies indicates, as noted above, where SO2 and/or sulfate (the PM2.5 component) are measured, 

significant adverse health outcome associations are rarely demonstrated (Grahame, 2009). 
AECOM 16

More specifically related to the requested variance that is the direct subject of this Memorandum, 

this evaluation concludes that there would be no adverse impact as a result of implementing the 

requested variance and, in fact, a net environmental benefit would be realized. 

Sincerely, 

Lisa JN Bradley, Ph.D., DABT 

Vice President and Senior Toxicologist 

Enclosures: 

 Attachment 1. References 

Attachment 2. Regional Evaluation of PM2.5 

Attachment 3. Schwartz, J. 2006. Air Pollution and Health: Do Popular Portrayals Reflect 

the Scientific Evidence? American Enterprises Institute for Public Policy 

Research. Environmental Policy Outlook, No. 2. 

Attachment 4: Resume for Lisa JN Bradley, Ph.D., DABT 
AECOM 17

Attachment 1: References 
AECOM 18

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CATF. 2010. Toll from Coal: An Updated Assessment of Death and Disease from America’s 

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CDC. 2012. Trends in Asthma Prevalence, Health Care Use, and Mortality in the United States, 

2001–2010. National Center for Health Statistics Data Brief No. 94. Centers for Disease 

Control and Prevention (CDC), U.S. Department Of Health And Human Services. May 

2012. 

Friebele, E. 1996. The attack of Asthma. Environ Health Persp., 104: 22-25. 

Goodman, J.E., Dodge, D.G., and Bailey, L.A. 2010. A framework for assessing causality and 

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Grahame, TJ. 2009. Does improved exposure information for PM2.5 constituents explain differing 

results among epidemiological studies? Inhalation Toxicology, April 2009; 21(5);381-393. 

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Institute of Medicine. 2000. Clearing the Air: Asthma and Indoor Air Exposures. National Academy 

Press. Executive Summary. http://www.nap.edu/openbook.php?isbn=0309064961. 

Jerrett, M., K.B. Newbold, R.T. Burnett, G. Thurston, R. Lall, C.A. Pope III, R.M.P. De Luca, M. 

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Manfreda, J., Becker, A. B., Wang, P. Z., Roos, L. L., and Anthonisen, N. R.. (1993). Trends in 

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Metzger, K.B., P.E. Tolbert, M. Klein, J.L. Peel, W.D. Flanders, K. Todd, J.A. Mulholland, P.B. 

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MMWR. 2007. National Surveillance for Asthma --- United States, 1980—2004. Center for 

Disease Control. Morbidity and Mortality Weekly Report, October 19, 2007 / 56(SS08);1-

14;18-54. 

NRC. 2004. Research Priorities for Airborne Particulate Matter: IV: Continuing Research 

Progress. National Research Council. National Academy of Sciences, Washington, D.C. 
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NYSDOH. 2006. April. New York State, Dept. of Health. A study of ambient air contaminants and 

asthma in New York City. Part A: a comparison of ambient air quality in the Bronx and 

Manhattan. Part B: air contaminants and emergency department visits for asthma in the 

Bronx and Manhattan (Final). Report to Agency for Toxic Substances and Disease Registry 

(ATSDR); New York State, Energy Research and Development Authority. NTIS PB2006-

113523, July, 260p. http://www.nyserda.ny.gov/en/Publications/Research-andDevelopment/ Environmental/ EMEP- Publications/~/media/Files/Publications/ 

Research/Environmental/ EMEP/Report%2006 _02_web.ashx 

Reiss, R., E.L. Anderson, C.E. Cross, G. Hidy, D. Hoel, R. McClellan, and S. Moolgavkar.2007. 

Evidence of Health Impacts of Sulfate- and Nitrate-Containing Particles in Ambient Air. 

Inhalation Toxicology, 19:419–449, 2007. 

Schwartz, J., A. Litonjua, H. Suh, M. Verrier, A. Zanobetti, M. Syring, B. Nearing, R. Verrier, P. 

Stone, G. MacCallum, F.E. Speizer, and D.R. Gold. 2005. Traffic related pollution and 

heart rate variability in a panel of elderly subjects. Thorax 60:455–461. 

Schwartz, J. 2006. Air Pollution and Health: Do Popular Portrayals Reflect the Scientific Evidence? 

American Enterprises Institute for Public Policy Research. Environmental Policy Outlook, 

No. 2. www.aei.org. 

Sheppard, L., D. Levey, G. Norris, T.V. Larson, and J.Q. Koenig. 1999. Effects of Ambient Air 

Pollution on Nonelderly Asthma Hospital Admissions in Seattle, Washington, 1987-1994. 

Epidemiology, 10(1). January 1999. 

USEPA. 2008. Integrated Science Assessment for Sulfur Oxides-Health Criteria. EPA-600/R08/047F. September. 

USEPA. 2009. Risk and Exposure Assessment to Support the Review of the SO2 Primary 

National Ambient Air Quality Standards: Final Report. EPA-452/R-09-007. July. 

US EIA. 2012. Annual Energy Review. Energy Information Administration. 

http://www.eia.gov/totalenergy/data/annual/ 

WHO. 2006. Air Quality Guidelines, Global Update 2005. Particulate Matter, ozone, nitrogen 

dioxide and sulfur dioxide. World Health Organization Regional Office for Europe. 
AECOM 20

Attachment 2: Regional PM2.5 Evaluation 

 
AECOM 978.905.2100 tel 

250 Apollo Drive 978.905.2101 fax 

Chelmsford, MA 01824-3627 

Memorandum 

To Lisa Bradley Page 1 

CC Carlos Szembek, Bob Paine 

Subject Ambient PM2.5 Concentrations – Ameren Power Plants, Illinois 

From Brian Stormwind 

Date July 10, 2013 

Review of PM2.5 Monitoring Data in the Vicinity of the Ameren Power Plants to be Purchased 

by Illinois Power Holdings (IPH) 

Figure 1 shows the location of the power plants and closest and most representative PM2.5 ambient 

air quality monitors relative to each plant. The proximity, surrounding land use (e.g., rural or urban) 

and prevailing wind direction were considered in selecting representative monitors, although 

monitors in all directions were reviewed for consideration. For facilities with a lack of nearby 

monitors, distant monitors that were not necessarily representative of the facility locations were 

included for reference. The monitors with respect to each power plant are reviewed below. 

The source of the PM2.5 monitoring data is U.S. EPA’s AirData website1. The AirData site provides 

annual summaries of measured concentrations from state-run ambient air quality monitors including 

the design concentrations used to evaluate the monitor results relative to the National Ambient Air 

Quality Standards (NAAQS). 

The PM2.5 NAAQS are as follows: 

x 24-hour = 35 μg/m3; design value is the 3-year average of the 98th percentile daily 

concentration. 

x Annual = 12 μg/m3; design value is the 3-year average of the annual mean concentration. 

Discussion of Individual Power Plants and Surrounding PM2.5 Ambient Air Monitors 

E.D. Edwards and Duck Creek 

Due to the proximity of the E.D. Edwards and Duck Creek power plants, the monitors for these 

have been grouped together. No representative monitors for these facilities were found north of the 

nearest monitor at Peoria (Figure 1). The prevailing wind pattern for both these facilities is shown 

in Figure 2, with wind primarily from the south. 

 

1

 http://www.epa.gov/airdata/ad_rep_mon.html 
AECOM 2

The E.D. Edwards power plant is located in Bartonville, IL in Peoria County. The closest PM2.5

monitors relative to the E.D. Edwards plant are located in Peoria, IL, 13 km to the northeast; in 

Normal, IL, 57 km to the east southeast; Springfield, IL, 86 km to the south and Decatur, IL, 103 km 

to the south-southeast. Further out (and upwind) from E.D. Edwards are the Keokuk, IA monitor, 

148 km to the west and the Quincy, IL monitor 148 km to the southwest. The most recent 3 years 

of data and corresponding design values for these monitor stations are summarized in Table 1. 

The monitoring data indicate compliance with the NAAQS and a likely decreasing trend as 2012 

data were consistently lower than 2011. The trend of decreasing PM2.5 concentrations is expected 

due to consistent reductions in precursor emissions, as noted by EPA in their June 2013 trends 

update available at http://www.epa.gov/ttnchie1/trends/. 

The Duck Creek power plant is located east-southeast of St. David, IL in Fulton County. The 

closest PM2.5 monitors relative to the Duck Creek facility are located in Peoria, IL, 42 km to the 

northeast; Springfield, IL, 77 km to the south-southeast; Normal, IL, 84 km to the east; Decatur, IL 

112 km to the southeast; Keokuk, IA, 121 km to the west; and in Quincy, IL, 132 km to the westsouthwest. The most recent 3 years of data and corresponding design values for the monitor 

stations are summarized in Table 1. The monitoring data indicate compliance with the NAAQS 

and, similar to the monitors surrounding the E.D. Edwards plant, a likely trend for decreased 

concentrations as the 2012 data were consistently lower than the previous two years. 

Table 1: PM2.5 Monitor Concentrations – E.D. Edwards and Duck Creek Power Plants 

Monitor Ave. Period Ranking 

Design Concentrations (μg/m3

) NAAQS 

(μg/m3

2010 2011 2012 3-yr Ave ) 

Peoria, IL 

ID 17-143-0037 

24-hour 98th % 26.0 27.7 20.7 24.8 35 

Annual Highest 11.5 11.7 9.8 11.0 12 

Springfield, IL 

ID 17-167-0012 

24-hour 98th % 24.2 27.8 20.0 24.0 35 

Annual Highest 11.5 10.7 9.5 10.6 12 

Normal, IL 

ID 17-113-2003 

24-hour 98th % 25.0 25.8 21.3 24.0 35 

Annual Highest 10.6 10.7 9.3 10.2 12 

Decatur, IL 

ID 17-115-0013 

24-hour 98th % 22.1 25.5 18.1 21.9 35 

Annual Highest 12.2 11.6 10.0 11.3 12 

Keokuk, IA 

ID 19-111-0008 

24-hour 98th % 30.4 23.9 22.7 25.7 35 

Annual Highest 11.8 11.3 10.9 11.3 12 

Quincy, IL 

ID 17-001-0007 

24-hour 98th % 22.6 24.6 20.8 22.7 35 

Annual Highest 10.5 10.4 9.5 10.1 12 

Coffeen 

The Coffeen power plant is located in Coffeen, IL in Montgomery County. The closest PM2.5

monitors relative to the Coffeen plant are located in Wood River, IL, 65 km west southwest; Alton, 

IL 68 km to the southwest; and Granite City, IL, 75 km to the southwest. The most recent 3 years 

of data and corresponding design values for these monitor stations are summarized in Table 2. 

The monitoring data for Wood River and Alton indicate a large margin of compliance with the 24-

hour NAAQS, while annual concentrations are slightly below the revised annual NAAQS of 12 

μg/m3. The Granite City monitor shows compliance for the 24-hour NAAQS, but exceeds the new 

annual NAAQS. However, the annual averages at this location are decreasing year by year, and 

the Granite City monitor is in an urban setting and likely most significantly influenced by local 

commercial/industry and vehicular emissions. As indicated by climatological data from Springfield, 

IL (Figure 3), Coffeen is predominately downwind of all three monitors; i.e., winds in the region are 

predominantly from the southerly and southwesterly sectors. The closest downwind monitors 
AECOM 3

relative to the Coffeen plant are located in Springfield (~90 km NNW) and Decatur (~100 km NNE). 

The monitored concentrations for these stations are below the annual NAAQS. 

Table 2: PM2.5 Monitor Concentrations – Coffeen Power Plant 

Monitor Ave. Period Ranking 

Design Concentrations (μg/m3) NAAQS 

(μg/m3

2010 2011 2012 3-yr Ave ) 

Wood River, IL 

ID 17-119-3007 

24-hour 98th % 22.1 28.6 23.2 24.6 35 

Annual Highest 12.0 12.4 10.6 11.7 12 

Alton, IL 

ID 17-119-2009 

24-hour 98th % 25.0 23.9 23.6 24.2 35 

Annual Highest 13.3 11.6 10.6 11.8 12 

Granite City, IL 

ID 17-119-0024 

24-hour 98th % 28.6 30.6 23.7 27.6 35 

Annual Highest 14.6 14.3 13.1 14.0 12 

Springfield, IL 

ID 17-167-0012 

24-hour 98th % 24.2 27.8 20.0 24.0 35 

Annual Highest 11.5 10.7 9.5 10.6 12 

Decatur, IL 

ID 17-115-0013 

24-hour 98th % 22.1 25.5 18.1 21.9 35 

Annual Highest 12.2 11.6 10.0 11.3 12 

Newton 

The Newton power plant is located in Newton, IL in Jasper County. The closest PM2.5 monitors 

relative to the Newton plant are located at the Purdue Agricultural Farm near Vincennes, IN, 72 km 

to the east southeast; co-located monitors in Terre Haute, IN, 96 km to the northeast and Knight 

Prairie, IL, 99 km to the south-southwest. The most recent 3 years of data and corresponding 

design values for these monitor stations are summarized in Table 3. 

All monitors indicate a large margin of compliance with the 24-hour NAAQS. The Purdue and Terra 

Haute #1 annual concentrations are just below the annual NAAQS, while Terra Haute #2 exceeds 

the new annual NAAQS. The Purdue monitored concentrations are likely influenced by local 

farming activities. The Terre Haute monitors are located in an urban area and the higher 

concentrations are likely a result of local commercial/industrial activities and vehicular traffic. Note 

that although regional wind patterns (Figure 3) suggest potential transport of emissions from the 

Newton power plant toward Terra Haute, the power plant, which is almost 100 km away, is too far 

to have a significant contribution to the Terre Haute monitored concentrations. 
AECOM 4

Table 3: PM2.5 Monitor Concentrations – Newton Power Plant

Monitor Ave. Period Ranking 

Design Concentrations (μg/m3) NAAQS 

(μg/m3

2010 2011 2012 3-yr Ave ) 

Purdue 

ID 18-083-0004 

24-hour 98th % 27.6 26.7 23.1(1) 25.8 35 

Annual Highest 12.3 11.4 11.4(1) 11.7 12 

Terre Haute, IN 

ID 18-167-0018 (POC1) 

24-hour 98th % 29.2 26.5 24.1 26.6 35 

Annual Highest 13.0 12.4 10.4 11.9 12 

Terre Haute, IN 

ID 18-167-0018 (POC2) 

24-hour 98th % 31.0 33.6 26.2 30.3 35 

Annual Highest 13.4 13.8 11.6 12.9 12 

Knight Prairie 

ID 17-065-0002 

24-hour 98th % 25.3 20.6 15.7 20.5 35 

Annual Highest 11.3 10.1 8.4 9.9 12 

(1) Data listed for 2009. Monitor discontinued after 2011.

Joppa 

The Joppa power plant is located in Joppa, IL in Massac County on the border with Kentucky. The 

regional wind pattern for south-southeastern IL is best represented by the 30-year wind rose from 

Evansville, IN airport (Figure 4) that shows both strong northwest and southerly flow in the area. 

The closest PM2.5 monitors relative to the Joppa plant are located in Paducah, KY, 25 km to the 

southeast and in Knight Prairie, IL, 98 km to the north-northeast. No other representative monitors 

were found within 125 km of the Joppa plant. Given the wind pattern for the region shown in Figure 

4, the Joppa plant lines up reasonably well with the Paducah (northwest flow) and the Knight Prairie 

monitors (southerly flow). The most recent 3 years of data and corresponding design values for 

both monitor stations are summarized in Table 4. The monitoring data indicate a large margin of 

compliance with the NAAQS and a likely decreasing trend as the data for each year is lower than 

the data for previous year. 

Table 4: PM2.5 Monitor Concentrations – Joppa Power Plant

Monitor Ave. Period Ranking 

Design Concentrations (μg/m3

) NAAQS 

(μg/m3

2010 2011 2012 3-yr Ave ) 

Paducah, KY 

ID 21-145-1004 

24-hour 98th % 25.0 23.2 19.3 22.5 35 

Annual Highest 11.4 10.4 9.9 10.6 12 

Knight Prairie 

ID 17-065-0002 

24-hour 98th % 25.3 20.6 15.7 20.5 35 

Annual Highest 11.3 10.1 8.4 9.9 12
AECOM 5

Conclusions 

Based on a review of available monitoring data in the vicinity of the Ameren power plants, there is 

no evidence to suggest that the stations are contributing to elevated PM2.5 concentrations or, in the 

case of the Coffeen and Newton facilities, concentrations in excess of the NAAQS. It is important 

to note that the 2012 24-hour and annual PM2.5 concentrations for all the monitors listed (with the 

sole exception of the Purdue monitor which was discontinued after 2011) are consistently lower 

than the 2011 year values indicating a potential regional downward trend. This trend is expected 

due to downward trends in precursor emissions of SO2 and NOx. 

Sincerely yours, 

Brian Stormwind 

brian.stormwind@aecom.com
AECOM 6

Figure 1 Location of Power Plant Facilities and Noted PM2.5 Ambient Air Monitors. The power plants are noted with the red 

markers; the ambient air monitors are noted with the yellow markers. 
AECOM 7

Figure 2 30-year Climatological Wind Rose for Peoria Airport, IL2

 

 

2

 http://www.isws.illinois.edu/atmos/statecli/roses/pia_rose_13.pdf 
AECOM 8

Figure 3 30-year Climatological Wind Rose, Springfield Airport3

 

3

Source: http://www.isws.illinois.edu/atmos/statecli/roses/spi_rose_13.pdf 
AECOM 9

Figure 4 30-year Climatological Wind Rose for Evansville Airport, IN4

 

4

 http://www.isws.illinois.edu/atmos/statecli/roses/eva_rose_13.pdf 

WIND ROSE PLOT 

Station #93817- EVANSVILLE/DRESS REGIONAL ARP, IN 

MODELER 

Wind Speed (Knots) 

> 21 DISPLAY 

17 .21 Wind Speed 

11-16 AVG. WIND SPEED 

7- 10 7.60 Knots 

4. 6 ORIENTATlON 

Direction 1· 3 (blowing from) 

- -- :~ORr

I 

I 

I 

I 

I 

---- -~- ----

I 

:SOUTH 

------- ------

DATE 

10/7/2004 

UNIT 

Knots 

CALM WINDS 

12.24% 

PLOT YEAR-DATE-TIME 

Jan 1 -Dec 31 

Midnight - 11 PM 

' ' ' ' \ 

\ 

a" 

' ' ' 

' ' 

\ 

\ 

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' ' ' ' ' ' ' ' ' 

\ 

\ 

\ 

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I 

I I I 

----- L -------L ------- 1 1 1 EAST I 

' ' ' ' ' 

COMPANY NAME 

I I 

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' ' 

' ' ' 

' ' 

' ' ' ' 

Illinois State Climatologist Office 

COMMENTS 

1961-1990 Annual Average 

PROJECT/PLOT NO. 

' ' 

' ' ' 

' ' 
AECOM 21

Attachment 3: Schwartz, J. 2006. 

Air Pollution and Health: Do Popular Portrayals Reflect the Scientific 

Evidence? American Enterprises Institute for Public Policy Research. 

Environmental Policy Outlook, No. 2. 

 
In a nationwide survey in 2004, 85 percent of

Americans rated air pollution as a “very serious”

or “somewhat serious” problem, with similar

results for state surveys.1 In a recent Gallup Poll,

78 percent of Americans said they worry about

air pollution “a fair amount” or “a great deal.”2

Public fear of air pollution is understandable,

because most popular information about air pollution is indeed alarming. 

Activist groups regularly issue reports with scary

titles such as Danger in the Air; Death, Disease and

Dirty Power; Highway Health Hazards; Plagued by

Pollution; and Children at Risk.

3 Health researchers

often issue alarming summaries of their research as

well. Recent press-release headlines from health

research institutes include “Smog May Cause Lifelong Lung Deficits,” “Link Strengthened between

Lung Cancer, Heart Deaths and Tiny Particles of

Soot,” “USC Study Shows Air Pollution May

Trigger Asthma in Young Athletes,” and “Traffic

Exhaust Poisons Home Air.”4

Regulators declare “code orange” and “code

red” alerts on days when air pollution is predicted to exceed federal health standards. And

news stories on air pollution often feature 

menacing headlines such as “Air Pollution’s

Threat Proving Worse than Believed,” “Don’t

Breathe Deeply,” “Study Finds Smog Raises

Death Rate,” “State’s Air Is among Nation’s

Most Toxic,” and “Asthma Risk for Children

Soars with High Ozone Levels.”5 

Headlines like these might be warranted if they

accurately reflected the weight of the scientific

evidence. But they do not. Through exaggeration,

omission of contrary evidence, and lack of context, regulators, activists, and even many health

scientists misrepresent the results of air pollution

health studies and the overall weight of the evidence from the research literature. They create

the appearance that harm from air pollution is

much greater and more certain than suggested by

the underlying evidence.

Journalists are the final line of defense between

the public and the proponents of air pollution

health scares. Unfortunately, the majority of media

air pollution health stories are sensationalized

exaggerations of air pollution’s risks.

Through several case studies, this essay shows

that misinformation on air pollution and health is 

a pervasive problem. As a result, public fear of air

pollution is out of all proportion to the minor risks

posed by current, historically low air pollution levels.

Air Pollution and Health: Do Popular Portrayals Reflect

the Scientific Evidence?

By Joel Schwartz

Environmentalists, regulators, health scientists, and journalists are the main purveyors of information on air

pollution health risks. Unfortunately, these groups create the appearance that harm from air pollution is much

greater and more certain than suggested by the underlying evidence. The incentives in air pollution health

research encourage risk exaggeration, because information purveyors depend on public fear to maintain their

funding and influence. Investigative reporters are in the best position to assess how the political economy of environmental health research affects the production and portrayal of the evidence. Public debate on air pollution

will continue to proceed from false premises until journalists take up this challenge.

Environmental Policy Outlook

1150 Seventeenth Street, N.W., Washington, D.C. 20036 202.862.5800 www.aei.org

No. 2, 2006

Joel Schwartz (jschwartz@aei.org) is a visiting fellow at AEI.
False Alarm on Asthma and Air Pollution

Beginning in 1993, the California Air Resources Board

(CARB) funded the Children’s Health Study (CHS).

Researchers from the University of Southern California

(USC) tracked several thousand California children living in twelve communities with air pollution ranging

from near-background to the worst in the nation.

At a joint press conference in 2002, the USC

researchers and CARB managers reported

that children who played three or more

team sports were more than three times 

as likely to develop asthma if they lived 

in the six highest-ozone communities in

the study, when compared with the six

lowest-ozone communities.6 They also

claimed the study’s results applied to cities

across the United States.

Ironically, the CHS asthma study actually showed just the opposite. While

higher ozone was associated with a greater

risk of developing asthma for children

who played three or more team sports (8

percent of children in the study), higher

ozone was associated with a 30 percent

lower risk of developing asthma in the full

sample of children in the study.7 While

this fact was discussed in a journal article

on the study, it was not mentioned at the

press conference.8

Higher levels of other pollutants,

including nitrogen dioxide and particulate matter

(PM10), were also associated with a lower asthma risk.9

Also mentioned in the journal article, but not at the

press conference, was that when the researchers divided

the twelve communities in three groups of four (rather

than two groups of six), the association of ozone with

increased asthma prevalence in child athletes applied

only to the four communities in the highest ozone

group and not to the medium-ozone group.

The assertion that the study is relevant for other parts

of the country was also false. The four high-ozone areas

in the study averaged 89 days per year exceeding the federal eight-hour ozone standard and 59 days per year

exceeding the one-hour standard during 1994–1997, the

years used to assess pollution exposure in the study.10 No

area of the United States, outside of a few parts of California, has ever had ozone levels this high even for a single year, much less for several years running.

In fact, by the time of its release in February 2002,

the study no longer applied even in the southern California areas where it was performed. Eight-hour ozone

exceedances had declined 55 percent, and one-hour

exceedances had declined 78 percent in the interim. By

2002, communities that were “high-ozone” areas during

the study had become “medium-ozone” areas, for which

ozone had no effect on asthma risk.

At the press conference releasing the CHS asthma

results, the chairman of the Air

Resources Board claimed: “This study

illustrates the need not to retreat but to

continue pushing forward in our efforts

to strengthen air pollution regulations.”11

But if anything, the CHS asthma study

showed that current standards already

include a large safety margin. Ozone was

not associated with a change in asthma

risk in the medium-ozone areas of the

study. Yet these areas exceeded federal

ozone standards by large margins—an

average of 41 eight-hour exceedance days

per year and 17 one-hour exceedances.

False information on the CHS asthma

results was not limited just to CARB officials or USC scientists. Health experts

from around the country misinterpreted

the study’s results. For example, on the

day the study was released, a professor at

the State University of New York at

Stony Brook, who has since become the

American Lung Association’s medical director, claimed:

“This is not just a Southern California problem. There

are communities across the nation that have high

ozone.”12 According to the Houston Chronicle, Houston

asthma specialists said the study showed that “Houston

[should] step up its efforts to implement a state plan to

reduce ozone.”13 The director of the pediatric asthma

program at the University of California at Davis claimed

“Sacramento is a very high ozone area, so this [the CHS

asthma study] is going to be very relevant to us.”14

Not only were all of these nominal experts wrong

about whether the study is relevant to actual ozone levels

in the United States, all of them completely missed the

fact that ozone and other air pollutants were associated

with an overall lower risk of developing asthma.

In a recent commentary on air pollution and asthma

in the Journal of the American Medical Association, two

prominent air pollution health researchers claimed:

- 2 -

Through exaggeration,

omission of contrary

evidence, and lack of

context, regulators,

activists, and even

many health scientists

misrepresent the

results of air pollution

health studies and the

overall weight of the

evidence from the

research literature.
“Some evidence suggests that air pollution may have

contributed to the increasing prevalence of asthma.”15

The “evidence” they cite is the CHS asthma study.

Journalists also often act as cheerleaders for air pollution alarmists when reporting on air pollution and

health. For example, a recent editorial headline in the

Sacramento Bee declared “Smog and Asthma: The

Link—and Threat—Are Real.”16 The Bee’s source for

this claim? Once again, the CHS asthma study.

Much Ado about Very Little

The Children’s Health Study also suggests that even the

highest air pollution levels in the nation are having little or no effect on children’s lung development. But

once again, the scientists involved in the study obscured

that fact.

After following more than 1,700 children from ages

ten to eighteen (years 1993 to 2001), CHS scientists

reported that there was no association between ozone

and lung-function growth.17 This is despite the fact that

the twelve communities in the study ranged from zero

to more than 120 eight-hour ozone exceedance days 

per year, and zero to more than 70 one-hour ozone

exceedance days per year during the study period.18

Once again, no area outside California has ever had

anywhere near this frequency of elevated ozone, even

for a single year, so we can conclude that ozone is not

causing any reduction in children’s lung capacity. This

has not stopped environmental groups from claiming

otherwise. For example, in Impacts of Ozone on Our

Health, the Carolinas Clean Air Coalition claims:

“Children have a 10 percent decrease in lung function

growth when they grow up in more polluted air.”19

The Children’s Health Study also suggests that fine

particular matter (PM2.5) is causing little or no longterm harm to lung growth. Unlike ozone, PM2.5 actually

was associated with a small effect on lung development.

Annual-average PM2.5 levels ranged from about 6 to 32

micrograms per cubic meter (μg/m3) in the twelve communities in the study.20 Across this range, PM2.5 was

associated with about a 2 percent decrease in forced

expiratory volume in one second (FEV1) and a 1.3 percent decrease in force vital capacity (FVC), both measures of lung capacity.

But even this small effect drastically inflates the

apparent importance of the results. First, no location

outside of the CHS communities has PM2.5 levels anywhere near 32 μg/m3. In fact, outside California there is

not a single area with PM2.5 above 21 μg/m3. And by

the time the study was published in 2004, even the

highest PM2.5 area in California was at 25 μg/m3.

It is also worth noting that the children in the CHS

were already ten years old when they entered the study

in 1993 and had therefore been breathing the evenhigher air pollutant levels extant during the 1980s in

southern California. For example, Riverside averaged

about 48 μg/m3 PM2.5 during the 1980s, or about 50

percent greater than the highest PM2.5 level measured

during the CHS years.21 If it were really these higher

1980s PM2.5 levels that caused the lung-function

declines, then the current worst PM2.5 in the country

would be causing about a 1 percent decrease in FEV1

and a 0.5 percent decrease in FVC. Thus, taking the

CHS results at face value, ozone is having no effect on

children’s lung development anywhere in the United

States. PM2.5 is having virtually no effect.

Nevertheless, the USC researchers’ press release on

the study created an unwarranted appearance of serious

harm. Titled “Smog May Cause Lifelong Lung Deficits,”

the press release asserted: “By age 18, the lungs of many

children who grow up in smoggy areas are underdeveloped and will likely never recover.”22 The National

Institutes of Health (NIH) also misled the public about

the study’s findings and relevance. The director of the

National Institute of Environmental Health Sciences

claimed the study “shows that current levels of air pollution have adverse effects on lung development in

children.”23

Furthermore, although the study is relevant only to a

few areas of California with uniquely high air pollution

levels, by asserting that it applies to all “smoggy areas”

and to “current levels of air pollution,” NIH and USC

created the false impression that the study applies to

much of the United States.

The scientists were able to create these false impressions, because the journal article on the study, which

was published in the prestigious New England Journal of

Medicine (NEJM), does not explicitly reveal the magnitude of the percentage change in children’s lung capacity. Instead, readers have to be vigilant enough to realize

that the percentage change can be calculated by combining information found in three different places in

the article.24 It is odd that a study whose main outcome

measure is changes in lung capacity never actually states

the percentage change explicitly.

The researchers reported a different outcome measure in their NEJM paper: the percent of children in

- 3 -
each community with a lung capacity of less than 80

percent of the “predicted” value for their age.25 Between

the least and most polluted communities, PM2.5 was

associated with nearly a five-fold increase in this percentage, from about 1.6 percent of children in the 

lowest-PM2.5 community, up to about 7.9 percent in the

highest-PM2.5 community.

This seems like a large effect, but it is not. What is

going on is that the 2 percent average decline in lung

function in the highest-PM2.5 community relative to the

lowest meant a shift of some children who were at, say,

80 or 81 percent of “predicted” lung

capacity for their age, down to maybe 78

or 79 percent. Because lung-capacity

scores have a bell-curve distribution, and

few children have low lung capacity, there

are many more children slightly above 80

percent than slightly below 80 percent. A

small shift in average lung-capacity scores

therefore results in a large change in the

fraction of children scoring below a given

cutoff level.26

Reporting that even the highest air pollution levels in the country were associated with only a 2 percent decrease in

lung capacity would not have caused

much alarm. This probably explains why

that number is nowhere to be found in the

NEJM report or the press releases on it.

NIH took advantage of this omission

in its press release, which begins: “Children who live in

polluted communities are five times more likely to have

clinically low lung function—less than 80 percent of

the lung function expected for their age.”27 Note how

this statement creates the appearance of a decline of

more than 20 percent in average lung function by leading readers to tacitly make the incorrect assumption

that all children would be at 100 percent if there were

no air pollution.

This is exactly the mistake environmentalists have

made in promoting the study. For example, the American

Lung Association’s (ALA) State of the Air 2005 report

claims the “average drop in lung function was 20 percent

below what was expected for the child’s age.”28 The

Carolinas Clean Air Coalition made a similar error.29

The ALA clearly did not understand the study’s

results. But NIH and the USC researchers created the

confusion. The editors and peer reviewers at the New

England Journal of Medicine also bear responsibility for

not requiring that its article on the study explicitly state

the percentage change in lung capacity associated with

air pollution. 

Monkey Business 

A University of California at Davis press release begins

“Primate Research Shows Link between Ozone Pollution, Asthma.”30 The press release goes on to claim the

ozone exposures in the study “mimic the effect of exposure to occasional ozone smog—for example as it occurs

in the Sacramento area.”

In fact, the ozone exposures in the

study were far higher than the actual

ozone levels in American air—including

the air in Sacramento. The monkeys

were exposed to 0.5 parts per million

(ppm) ozone for eight hours a day for five

days in a row, followed by nine days of

clean air. This cycle was repeated eight

times. To give you an idea of the magnitude of these ozone exposures, during the

last thirty years only one site in the U.S.

has ever exceeded 0.5 ppm ozone for

even one hour, and that happened in

1976. Today, the worst site in the United

States never reaches even 0.25 ppm for

one hour, and the average site never

reaches 0.11 ppm.

Despite the real-world irrelevance of

this study, environmental activists cite it to support

claims that ozone is causing permanent lung damage in

people. For example, under the headline “Lung Development of Young Monkeys Drastically Changed when

Exposed to Ozone Pollution,” the American Lung Association concludes, “This study presents data suggesting

that the changes caused by ozone pollution are longlasting, and maybe even permanent.”31

Some reporters also failed to compare ozone levels

in the study to real-world ozone levels. For example,

according to the Modesto Bee, “Monkeys were exposed

to air contaminated with ozone, mimicking the smog

in the [Central] valley.”32 But even more nuanced stories still took an alarmist tack. For example, the Sacramento Bee explicitly compared ozone levels in the

Sacramento region with the far higher ozone levels

used in the study.33 But you have to go halfway into

the 1,100-word story to find this information. The story’s headline—“Study Suggests Asthma Culprit; Young

- 4 -

Scientists, regulators,

and environmentalists

have ignored these

weaknesses and

continue to make

believe these spurious

statistical correlations

are telling us

something real about

the effects of low-level

air pollution.
Lungs Exposed to Ozone Seem More Prone to Problems

with Development”—leaves no doubt that readers are

supposed to conclude that ozone is causing Americans

to develop asthma.

Of Mice and Men

By far the most serious health claim about air pollution

is that it kills tens of thousands of Americans each year,

mainly due to exposure to PM2.5. There is no question

that high levels of air pollution can kill. About 4,000

Londoners died during the infamous five-day “London

Fog” of December 1952, when soot and sulfur dioxide

soared to levels tens of times greater than the highest

levels experienced in developed countries today, and

visibility dropped to less than 20 feet.34

However, current fears center on whether today’s

comparatively low levels of air pollution are also deadly.

An embarrassment for proponents of low-level air pollution as a cause of death is that the evidence is almost

solely circumstantial, being based on statistical studies

reporting small correlations between long- or short-term

air pollution levels and risk of dying. These “observational” studies are not based on randomized trials, but on

non-random data that inherently suffer from confounding by non-pollution factors with much larger effects on

health than the purported effects of air pollution.

Observational studies could be taken more seriously

if they were supported by evidence from randomized,

controlled studies that eliminate the possibility of confounding by non-pollution factors. Such studies cannot, of course, be done with people, but they can be

done with animals. However, researchers have been

unable to kill animals with air pollution at levels anywhere near as low as the levels found in ambient air.

As a recent review of particulate matter toxicology

concluded:

It remains the case that no form of ambient PM—

other than viruses, bacteria, and biochemical

antigens—has been shown, experimentally or

clinically, to cause disease or death at concentrations remotely close to U.S. ambient levels.35

This seemingly changed in December 2005 when 

the Journal of the American Medical Association (JAMA)

published the results of a study that claimed PM2.5 at

current ambient levels is increasing Americans’ risk of

developing heart disease. The study exposed mice to 

85 μg/m3 of PM2.5 concentrated from ambient air for six

hours per day for six months, or about one-fourth of a

typical mouse life span.36

Mice fed a high-fat diet and exposed to PM2.5 had

more than a 50 percent greater rate of atherosclerosis

(as measured by arterial plaque area) and other signs of

heart disease, when compared with a control group that

was fed a high-fat diet, but not exposed to PM2.5. PM2.5

was associated with greater atherosclerosis in mice on a

low-fat diet as well, but the effect was not statistically

significant.

NIH highlighted the study with a press release that

begins: “Test results with laboratory mice show a direct

cause-and-effect link between exposure to fine particle

air pollution and the development of atherosclerosis . . .

[The study] may explain why people who live in highly

polluted areas have a higher risk of heart disease.”37

The study caused a minor media sensation, with both

journalists and health experts claiming the study provides strong evidence that PM2.5 is causing serious harm

to human beings.38

Despite the enthusiastic reception, there is much less

here than meets the eye. The mice used in the study

were genetically engineered in ways that make them

unrepresentative of even real-world mice, much less of

humans. The mice were designed to lack the gene for

apolipoprotein E (ApoE), a key substance for fat and

cholesterol metabolism. As a result, these ApoE “knockout” mice have blood cholesterol levels 5 to 6 times

greater than normal mice when fed regular rat chow.

ApoE knockout mice have 14 times the cholesterol of

normal mice when both are fed a high-fat diet.39

These are stupendous cholesterol levels. For comparison, medical authorities define “high cholesterol” as a

serum cholesterol level greater than 240 milligrams per

deciliter (mg/dl), which is about 20 percent greater than

the average cholesterol level in American men.40 Only

one in 50 American men exceeds 1.5 times the U.S.

average, and only one in 500 exceeds twice the average.41

The very reason for using such grossly unrealistic

mice to study PM2.5 is that PM2.5 does not kill regular

mice or other animals at PM concentrations relevant

to real-world human exposures. For that matter, PM2.5

did not actually kill the high-cholesterol mice in the

study either.

NIH downplayed the vast gulf between the genetically engineered mice and normal mice, stating only

that they were “genetically programmed to develop atherosclerosis at a higher-than-normal rate.” This is a bit

- 5 -
like doing a study on people who weigh 500 pounds and

referring to them merely as “overweight.”

If you build a house out of cards, you would expect

even a gentle breeze to knock it down. But this does not

tell you much about the ability of a real house to withstand a gentle breeze. Likewise, if you design an artificial

mouse that cannot regulate its fat or cholesterol levels, it

is not surprising that even a minor environmental insult

can cause it some health problems. But this does not tell

you much about the effects of low-level air pollution

levels on regular mice or on people.

Unfortunately, news articles on the study failed to

provide the context that would show that study has little real-world relevance. A Nexis search turned up ten

news reports on the study. Seven did not even mention

that the mice had been genetically engineered, leaving

the impression that real-world PM2.5 levels caused heart

disease in normal mice.

Three other news outlets followed NIH’s lead, creating the impression that the mice in the study were

merely analogous to people with a higher-than-average

risk of heart disease. For example, according to the Los

Angeles Times, the mice were “bred to be susceptible to

developing heart disease.”42

NIH and the study authors also misled reporters

about the relevance of the PM2.5 doses to real-world

PM2.5 levels. According to NIH, “The fine particle

[PM2.5] concentrations used in the study were well

within the range of concentrations found in the air

around major metropolitan areas.” The press release also

quotes one of the study’s authors saying that “the average exposure over the course of the study was 15 micrograms per cubic meter, which is typical of the particle

concentrations that urban area residents would be

exposed to, and well below the federal air quality standard of 65 μg/m3 over a 24-hour period.”43

In fact, the PM2.5 levels in the study were nothing

like real-world PM2.5 levels. The mice were exposed to

PM2.5 at 85 μg/m3 for six hours in a row during five days

of each week, and filtered air the rest of the time. Over

the six-month study period, this does indeed average

out to about 15 μg/m3, the level of the federal PM2.5

annual standard. But in the real world, areas that average 15 μg/m3 of PM2.5 over a year rarely approach shortterm PM2.5 levels of 85 μg/m3.

For example, in the mouse study, the mice spent the

equivalent of 1,560 hours per year breathing 85 μg/m3

PM2.5 (30 hours per week times 52 weeks per year). 

In contrast, Modesto California averaged 16 μg/m3

of PM2.5 over the past year, but spent only 80 hours 

at 85 μg/m3 or above.44 Furthermore, 40 percent of

those high-PM2.5 hours occurred between 11 p.m. and 

6 a.m., when most people are in bed. There were only

420 hours when Modesto exceeded even 50 μg/m3

of PM2.5.

Even areas with the highest PM2.5 levels in the

country have far fewer hours of high PM2.5 than were

used in the mouse study. For example, Riverside California averaged 27 μg/m3 PM2.5 over the past year, but had

only 135 hours at or above 85 μg/m3, and 1,055 hours

above 50 μg/m3.

Health effects depend not only on the average dose,

but on the acute dose. For example, you could take 2

aspirins 4 times per day, or you could take 8 all at once

each day. Either way, your average dose is 8 aspirins per

day. But you are more likely to suffer ill effects if you

take the aspirins all at once. The mice received an

analogously unrealistic daily PM2.5 exposure. NIH and

the scientists involved in the study then created the

false appearance that this unrealistic exposure schedule

has some relevance to the real world.

There is nothing wrong with the JAMA mouse study

in principle. It shows that when you take a mouse specially designed to have unrealistically stupendous cholesterol levels, feed it a high-fat diet, and repeatedly

expose it to unrealistically high acute levels of PM2.5,

that PM2.5 increases the extent of heart disease. The

problem arose when the study’s proponents claimed that

this has something to do with PM2.5 risks faced by

human beings.

You can now find a summary of the study on NIH’s

website. Its title? “Particulate Air Pollution and a High

Fat Diet: A Potentially Deadly Combination.”45

Sins of Omission

At the March meeting of the California Air Resources

Board, staff members gave a detailed presentation on

Jerrett et al. (2005)—a new epidemiological study of

the Los Angeles region that reported a stronger link

between PM2.5 and mortality than suggested in previous

research regulators have used to support tougher PM2.5

standards.46 What CARB’s staff did not tell its board is

that right around the same time that Jerrett et al. was

published, another study of PM2.5 risks in California by

Enstrom (2005) concluded that PM2.5 was having no

effect on mortality.47 Several California papers, including the Los Angeles Times, covered the alarming findings

- 6 -
of Jerrett et al. But none covered the benign results

reported by Enstrom.

This is a typical pattern. Studies that report harm

from air pollution receive a great deal of attention from

regulators, environmentalists, and journalists. Studies

finding no harm from air pollution are ignored. As a

result, claims of harm from air pollution appear more

consistent and robust than suggested by the actual

weight of the evidence.

The American Lung Association’s

website includes an area called Medical

Journal Watch, which summarizes hundreds of air pollution health studies.48 But

the site omits studies that do not report

any harm from air pollution. For example, the site does not include any studies

by Fred Lipfert, Suresh Moolgavkar,

Richard Smith, Gary Koop, William

Keatinge, or James Enstrom—all of

whom have provided evidence against a

connection between low-level air pollution and risk of death.49

The ALA also excludes specific studies

and portions of studies that fail to find any

harm from air pollution. For example,

Medical Journal Watch does not mention

Gong et al. (2003) and Holgate et al.

(2003), which found little or no adverse

health effects in human volunteers who

breathed high levels of PM2.5 and diesel

soot, respectively.50 The ALA does summarize the CHS findings on children’s

lung capacity discussed earlier, but does

not mention that the study found that

even the highest ozone levels in the

country had no effect on lung growth.

Three studies have used CHS data to

assess whether ozone is associated with

increases in school absences. One study

reported an increase.51 Two reported no effect.52 The

ALA mentions only the first study on Medical Journal

Watch. CARB likewise cites only the first study in its

review of California’s ozone standard.53

Coal-fired power plants have been one of environmentalists’ premier targets during the last several years. In

reports such as Danger in the Air; Death, Disease and Dirty

Power; Power to Kill; Children at Risk; and many more,

environmental groups claim that particulate pollution

from power plants is killing thousands of Americans

each year.54 The Bush administration, a constant target

of environmental groups for supposedly “gutting” power

plant pollution requirements, last year adopted the

Clean Air Interstate Rule (CAIR).55 CAIR requires

that power plants reduce their sulfur dioxide emissions

by more than 70 percent below current levels.56 Some

sulfur dioxide is converted to ammonium sulfate in the

atmosphere, and this is the main form of PM2.5 from

power plants. EPA claims these PM2.5

reductions will prevent 17,000 premature

deaths each year.57

There is just one problem: ammonium

sulfate is not toxic, even at levels many

times those ever found in ambient air.58 In

fact, ammonium sulfate is used as an inert

control—that is, a compound not expected

to have any health effects—in studies of

the health effects of acidic aerosols.59 If

ammonium sulfate is not toxic, then the

campaign against PM2.5 from power plants

is based on a false premise.

Last year CARB adopted a tougher

ozone standard for California.60 To justify

the tougher standard, CARB prepared a

detailed report summarizing ozone health

effects research. The report analyzes hundreds of health studies in nearly 1,000

pages, but fails to mention a study reporting that higher ozone was associated with a

lower rate of hospital visits in California’s

Central Valley.61 CARB was certainly

aware of the existence of this study,

because CARB funded and published it.

EPA also failed to mention the study in its

latest review of the federal ozone standard.62

EPA based its annual PM2.5 standard

mainly on the American Cancer Society

(ACS) study, which followed more than

500,000 Americans in fifty cities from 1982

to 1989 and looked for correlations between PM2.5 levels

and risk of death.63 The most recent ACS report covered

the period from 1982 to 1998 and reported that each

10 μg/m3 increase in long-term PM2.5 levels is associated with a 4 percent increase in risk of death.64

The validity of epidemiological studies, such as the

ACS study, depends on the assumption that correlations

between air pollution and health outcomes represent

genuine causal relationships. The implicit assumption is

that after researchers have controlled for non-pollution

- 7 -

Environmental groups

want to increase

support for ever more

stringent regulations,

maintain and enhance

their control over

other people’s lives,

and bring in the

donations that support

their activism.

Regulators want to

show the success of

their efforts to reduce

air pollution, but they

also want to justify the

need to preserve or

expand their powers

and budgets. 
health factors like income or smoking, any residual correlation between air pollution and health represents a

genuine causal linkage. Experience has shown that this

assumption is false.

For example, a reanalysis of the ACS data showed

that the apparent PM2.5-mortality link was spurious.

According to sensitivity analyses of the ACS data,

PM2.5 apparently kills men, but not women; those with

no more than a high school degree, but not those with

at least some college; and those who said they were

moderately active, but not the very active or the sedentary.65 Results like these are biologically implausible and

suggest a failure to adequately control for confounding

by non-pollution factors.

When migration rates into and out of various cities

over time were added to the statistical model relating

PM2.5 and risk of death, the apparent effect of PM2.5

disappeared.66 Cities that lost population during the

1980s—Midwest “rust belt” cities—also had higher

PM2.5 levels. People left these cities, which were in economic decline, in search of work in more economically

dynamic parts of the country. But people who work and

have the wherewithal to migrate also tend to be healthier than the average person. Hence, what appeared to

be an effect of PM2.5 was actually the result of differential migration. Migration was just one of several confounding factors that diminished or erased the apparent

harm from PM2.5, but that were not accounted for by

the ACS researchers.

This problem of spurious air pollution risk estimates

is not limited to the ACS study, but is endemic to air

pollution epidemiology and to epidemiology in general.67 Nevertheless, scientists, regulators, and environmentalists have ignored these weaknesses and continue

to make believe these spurious statistical correlations

are telling us something real about the effects of lowlevel air pollution.

The Politics of Air Pollution Health Science

Most public information on air pollution and health

comes from environmental activists, regulators, and

health researchers. As these case studies show, their

claims of harm from current, historically low air pollution levels are at best exaggerations and at worst fabrications. The result is unwarranted public fear, and

continued support for ever more costly regulatory

requirements that deliver little or no benefit in

exchange for their high costs.

Regulators, environmentalists, and scientists enjoy

substantial credibility with the public and the press. But

like other interest groups, their goals often do not coincide with the interests of the vast majority of Americans. Environmental groups want to increase support for

ever more stringent regulations, maintain and enhance

their control over other people’s lives, and bring in the

donations that support their activism. Regulators want

to show the success of their efforts to reduce air pollution, but they also want to justify the need to preserve

or expand their powers and budgets. Maintaining a climate of crisis and pessimism meets these institutional

goals, but at the expense of encouraging people to exaggerate the risks they face.

While it is not surprising that activists and regulators

exaggerate air pollution risks, they would not be taken

as seriously without scientific authority to back them

up. The credibility of science and scientists flows from

the power of scientific methods to uncover truths about

the world, and from the perceived objectivity of scientists themselves. As the case studies above show, trust in

scientific authority is often misplaced.

Scientific and medical research does have checks

and balances that are absent from more explicitly

political endeavors. Environmental health research

nevertheless suffers from its own set of pressures that

militate against evenhanded inquiry and dispassionate

analysis and presentation of evidence. Studies that

report harm from air pollution are more likely to be

published than studies that do not. Regulatory agencies, whose power and budgets depend on the perception that air pollution is a serious health problem, are

also major funders of the research intended to demonstrate the severity of the problem. Scientists who

believe air pollution is a serious health threat and who

report larger health effects are more likely to attract

research funding. It is not a big leap to conclude that

there is a great deal of selection bias in who does environmental health research, what questions they ask,

and how they report their results.

Journalists should be acting as a check on air pollution misinformation, but they are not. Media outlets

face their own pressures to sensationalize stories. Good

news does not sell newspapers or attract viewers. As a

result, journalists and editors are more likely to cover

studies claiming harm from air pollution, and to pass

along these claims with little or no critical review.

True, few journalists have the expertise to evaluate

the technical merits of specific studies. But continuing

- 8 -
to rely on scientific authority will only perpetuate the

problem of risk exaggeration. Among the major

providers of public information on environmental risks,

investigative reporters are in the best position to assess

how the political economy of environmental health

research affects the production and portrayal of scientific evidence. It would be a breath of fresh air if journalists and editors took up this challenge.

AEI editor Scott R. Palmer worked with Mr. Schwartz to edit and

produce this Environmental Policy Outlook.

Notes

1. The Environmental Deficit: Survey on American Attitudes 

on the Environment (New Haven, CT: Yale Center for Environmental Law and Policy, May 2004), available at www.yale.edu/

forestry/downloads/yale_poll_globalwarming.pdf. For similar

results in state surveys, see Recent Texas Statewide Survey Findings

Prepared for Public Citizen and the Seed Coalition (Alexandria,

VA: American Viewpoint, 2002); New York Conservation 

Education Fund, Key Findings of a Statewide Survey of New York

State Residents on Environmental Issues (New York: New York

League of Conservation Voters, 2001); Sprawl: New Jerseyans

Dislike the Problems, and the Solutions (New Brunswick, NJ:

Newark Star-Ledger/Eagleton-Rutgers, September 29, 2002),

available at http://slerp.rutgers.edu/retrieve.php?id=138-6; and

M. Baldassare, PPIC Statewide Survey: Special Survey on Californians and the Environment (San Francisco: Public Policy Institute of California, July 2004).

2. Water Pollution Tops Americans’ Environmental Concerns

(Washington, D.C.: Gallup Poll, April 21, 2006), available at

http://poll.gallup.com/content/Default.aspx?ci=22492&

VERSION=p.

3. Death, Disease and Dirty Power: Mortality and Health

Damage Due to Air Pollution from Power Plants (Boston:

Clean Air Task Force, October 2000), available at www.

cleartheair.org/fact/mortality/mortalitylowres.pdf; Our Children at Risk (Washington, D.C.: Natural Resources Defense

Council, November 1997), available at www.nrdc.org/

health/kids/ocar/ocarinx.asp; Children at Risk: How Air Pollution from Power Plants Threatens the Health of America’s Children (Boston: Physicians for Social Responsibility, May 2002),

available at www.cleartheair.org/fact/children/children_at_

risk.pdf; Danger in the Air (Washington, D.C.: Public Interest Research Group [PIRG], August 2003); Plagued by Pollution (Washington, D.C.: PIRG, January 2006), available at

http://cleanairnow.org/pdfs/plaugedbypollution.pdf; and

Highway Health Hazards (Washington, D.C.: Sierra Club,

July 2004), available at www.sierraclub.org/sprawl/report04_

highwayhealth/report.pdf.

4. Johns Hopkins School of Public Health News Center,

“Traffic Exhaust Poisons Home Air,” news release, August 31,

1999, available at www.jhsph.edu/PublicHealthNews/Press_

Releases/PR_1999/traffic_exhaust.html; A. Di Rado, “USC

Study Shows Air Pollution May Trigger Asthma in Young

Athletes,” news release, February 1, 2002, available at www.usc.

edu/hsc/info/pr/1vol8/803/air.html; A. Di Rado, “Smog May

Cause Lifelong Lung Deficits,” University of Southern California, September 8, 2004, available at www.usc.edu/uscnews/

stories/10495.html; and National Institutes of Health (NIH),

“Link Strengthened between Lung Cancer, Heart Deaths and

Tiny Particles of Soot,” March 5, 2002, available at www.niehs.

nih.gov/oc/news/lchlink.htm.

5. T. Avril, “Air Pollution’s Threat Proving Worse than

Believed,” Philadelphia Inquirer, November 17, 2004; M. Cone,

“State’s Air Is among Nation’s Most Toxic,” Los Angeles Times,

March 22, 2006, available at www.latimes.com/news/

printedition/la-me-cancer22mar22,1,7087336.story; M. Cone,

“Study Finds Smog Raises Death Rate,” Los Angeles Times,

November 17, 2004; T. Freemantle, “Asthma Risk for Children

Soars with High Ozone Levels—Study,” Houston Chronicle,

February 1, 2002; and T. Webber, “Don’t Breathe Deeply,”

Indianapolis Star, June 23, 2005.

6. California Air Resources Board, “Study Links Air Pollution and Asthma,” news release, January 31, 2002, available at

www.arb.ca.gov/newsrel/nr013102.htm.

7. The risk of developing asthma was 30 percent lower based

on one-hour ozone levels and was statistically significant. Asthma

risk was 20 percent lower based on eight-hour ozone levels and

was just a hair short of statistical significance. (The top of the 

95 percent confidence interval for relative risk was 1.0. Anything

less than that would have been statistically significant.)

8. The journal article is R. McConnell, K. T. Berhane, F.

Gilliland et al., “Asthma in Exercising Children Exposed to

Ozone: A Cohort Study,” Lancet 359 (2002): 386–91.

9. Once again the risk was 20 percent lower and was just

barely short of statistical significance.

10. Pollution monitoring data from the Children’s Health

Study were provided by CARB’s staff.

11. California Air Resources Board, “Study Links Air Pollution and Asthma,” news release, January 31, 2002, available at

www.arb.ca.gov/newsrel/nr013102.htm.

12. Dr. Norman Edelman, quoted in S. Borenstein, “Air

Pollution Is a Cause of Asthma, Study Contends,” Philadelphia

Inquirer, February 1, 2002.

13. T. Freemantle, “Asthma Risk for Children Soars with

High Ozone Levels—Study.”

- 9 -
14. In fact, even the worst areas of Sacramento never average more than a few days per year exceeding the one-hour

ozone standard and 20 or so days per year exceeding the 

eight-hour standard—ozone levels typical of the “mediumozone” CHS communities, in which there was no relationship

between air pollution and asthma risk. Dr. Jesse Joad, quoted in

C. Bowman, “Asthma’s Toll: A New Study Links Children’s

Sports Activities in Smoggy Areas to the Illness,” Sacramento

Bee, February 1, 2002.

15. G. D. Thurston and D. V. Bates, “Air Pollution as an

Underappreciated Cause of Asthma Symptoms,” Journal of the

American Medical Association 290 (2003): 1915–17.

16. “Smog and Asthma: The Link—and Threat—Are

Real,” Sacramento Bee, May 6, 2003.

17. W. J. Gauderman, E. Avol, F. Gilliland et al., “The

Effect of Air Pollution on Lung Development from 10 to 18

Years of Age,” New England Journal of Medicine 351 (2004):

1057–67.

18. The CHS study set up special-purpose monitors to

measure pollution levels in the communities where the

study was performed. CARB staff provided data from these

monitors.

19. Impacts of Ozone on Our Health (Charlotte, NC: Carolinas Clean Air Coalition, undated), available at http://003af56.

netsolhost.com/air_basics_ozone_impact.htm.

20. Based on research by CARB staff, these values have

been adjusted upward by 13.6 percent to make them comparable with PM2.5 levels determined by the Federal Reference

Method, which has been used nationwide since 1999 for

determining compliance with federal PM2.5 standards. See N.

Motallebi, J. Taylor, A. Clinton, B. E. Croes et al., “Particulate Matter in California: Part 1—Intercomparison of Several

PM2.5, PM10-2.5, and PM10 Monitoring Networks,” Journal of

the Air & Waste Management Association 53 (2003): 1509–16.

21. Based on IPN data for Riverside collected in the early

1980s, and PM2.5 data collected by CARB in 1988 and 1989

and retrieved from CARB’s 2006 Air Pollution Data CD,

www.arb.ca.gov/aqd/aqdcd/aqdcd.htm. Once again, I have corrected these values for the change in measurement methods.

22. Di Rado, “Smog May Cause Lifelong Lung Deficits.”

23. Dr. Kenneth Olden, quoted in NIH, “New Research

Shows Air Pollution Can Reduce Children’s Lung Function,”

news release, September 9, 2004, www.nih.gov/news/pr/

sep2004/niehs-08a.htm.

24. Here’s how: First, note from table 3 of the NEJM article

that PM2.5 was associated with a 79.7 milliliter (ml) reduction

in FEV1 between the least and most polluted community. Then

from table 2, note that at eighteen years of age average FEV1

was 3,332 ml for girls and 4,464 ml for boys. Given that there

were 876 girls and 883 boys in the study (p. 1,059, column 1),

the weighted average FEV1 for the study population was 3,900

ml. The percentage decline is then 79.7/3,900 = 0.02 or 2 percent. A similar calculation can be done to show that the average decline in FVC was 1.3 percent. Gauderman, Avol,

Gilliland et al., “The Effect of Air Pollution on Lung Development from 10 to 18 Years of Age.”

25. The researchers used a regression model to create this

“predicted” value.

26. This is assuming the “predicted” lung capacity values are

valid. The NEJM paper provides few details on the model or

the underlying distribution of lung-function test scores by community. Thus, another problem with this outcome measure is

that it depends on something that was not actually measured!

27. NIH, “New Research Shows Air Pollution Can Reduce

Children’s Lung Function.”

28. American Lung Association, State of the Air 2005

(Washington, D.C.: May 2005), 60.

29. N. Bryant, “What Air Quality Problem?” Charlotte

Observer, September 1, 2005, available at www.charlotte.com/

mld/charlotte/news/opinion/12530112.htm?BMIDS=13194.

30. A. Fell, “Primate Research Shows Link between Ozone

Pollution, Asthma,” U.C.-Davis news release, October 13, 2000,

available at www.dateline.ucdavis.edu/101300/DL_asthma.html.

31. Recent Scientific Findings on Health Effects of Air Pollution

and Diesel Exhaust (Oakland, CA: American Lung Association

of California, 2003), available at www.californialung.org/

spotlight/cleanair03_research.html.

32. Melanie Turner, “Kids Focus of Air Quality Study

Researcher Looking for Link Between Ozone, Asthma in

Youth,” Modesto Bee, May 11, 2001.

33. Edie Lau, “Study Suggests Asthma Culprit; Young Lungs

Exposed to Ozone Seem More Prone to Problems with Development,” Sacramento Bee, April 15, 2001.

34. I. M. Goklany, Clearing the Air: The Real Story of the War

on Air Pollution (Washington, D.C.: Cato Institute, 1999).

35. L. C. Green and S. R. Armstrong, “Particulate Matter in

Ambient Air and Mortality: Toxicologic Perspectives,” Regulatory Toxicology and Pharmacology 38 (2003): 326–35.

36. Q. Sun, A. Wang, X. Jin et al., “Long-Term Air Pollution Exposure and Acceleration of Atherosclerosis and Vascular Inflammation in an Animal Model,” Journal of the American

Medical Association 294 (2005): 3003–10.

37. NIH, “Air Pollution, High-Fat Diet Cause Atherosclerosis in Laboratory Mice,” news release, December 22, 2005,

available at www.nih.gov/news/pr/dec2005/niehs-22.htm.

38. Newspapers carrying articles on the study included the

Los Angeles Times, Houston Chronicle, Philadelphia Inquirer, and

several others.

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39. A. S. Plump, J. D. Smith, T. Hayek et al., “Severe

Hypercholesterolemia and Atherosclerosis in Apolipoprotein

E-Deficient Mice Created by Homologous Recombination in

Es Cells,” Cell 71 (1992): 343–53; and S. H. Zhang, R. L. Reddick, J. A. Piedrahita et al., “Spontaneous Hypercholesterolemia and Arterial Lesions in Mice Lacking Apolipoprotein

E,” Science 258 (1992): 468–71.

40. See table 70 in National Center for Health Statistics,

Health, United States, 2005 (Hyattsville, MD: U.S. Department

of Health and Human Services, 2005), available at

www.cdc.gov/nchs/data/hus/hus05.pdf#070.

41. Based on National Health and Nutrition Examination

Survey (NHANES) data on 4,090 adult men collected from

1999–2002. Data were downloaded from www.cdc.gov/nchs/

nhanes.htm.

42. M. Bustillo and M. Cone, “EPA Issues New Plan to

Limit Soot; Critics Say the Revised Standard Is Too Weak

to Properly Protect the Public from Health Dangers Caused

by Breathing Particulates,” Los Angeles Times, December 21,

2005.

43. NIH, “Air Pollution, High-Fat Diet Cause Atherosclerosis in Laboratory Mice.”

44. Hourly PM2.5 data were downloaded from CARB at

www.arb.ca.gov/aqmis2/paqdselect.php.

45. M. Lippmann, L. C. Chen, and S. Rajagopalan, “Particulate Air Pollution and a High Fat Diet: A Potentially

Deadly Combination,” NIH, available at www.niehs.nih.

gov/dert/profiles/hilites/2005/pm-diet.htm.

46. Stronger Relationship between Particulate Matter (PM) and

Premature Death (Sacramento: California Air Resources Board,

March 23, 2006), available at ftp://ftp.arb.ca.gov/carbis/board/

books/2006/032306/06-3-1pres.pdf. This presentation was based

on the results of M. Jerrett, R. T. Burnett, R. Ma et al., “Spatial

Analysis of Air Pollution and Mortality in Los Angeles,” Epidemiology 16 (2005): 727–36.

47. J. E. Enstrom, “Fine Particulate Air Pollution and Total

Mortality among Elderly Californians, 1973–2002,” Inhalation

Toxicology 17 (2005): 803–16.

48. American Lung Association, “Clean Air Standards,”

Medical Journal Watch, available at www.cleanairstandards.

org/listing/journalWatch.

49. Based on a search of the Medical Journal Watch website

on April 6, 2006.

50. H. Gong Jr., W. S. Linn, C. Sioutas et al., “Controlled

Exposures of Healthy and Asthmatic Volunteers to Concentrated Ambient Fine Particles in Los Angeles,” Inhalation Toxicology 15 (2003): 305–25; S. T. Holgate, T. Sandstrom, A. J.

Frew et al., “Health Effects of Acute Exposure to Air Pollution.

Part I: Healthy and Asthmatic Subjects Exposed to Diesel

Exhaust,” Research Report/Health Effects Institute (2003): 1–30,

discussions 51–67.

51. F. D. Gilliland, K. Berhane, E. B. Rappaport et al.,

“The Effects of Ambient Air Pollution on School Absenteeism Due to Respiratory Illnesses,” Epidemiology 12 (2001):

43–54.

52. K. Berhane and D. C. Thomas, “A Two-Stage Model for

Multiple Time Series Data of Counts,” Biostatistics 3 (2002):

21–32; and V. Rondeau, K. Berhane, and D. C. Thomas, “A

Three-Level Model for Binary Time-Series Data: The Effects of

Air Pollution on School Absences in the Southern California

Children’s Health Study,” Statistics in Medicine 24 (2005):

1103–15.

53. Review of the California Ambient Air Quality Standard for

Ozone (Sacramento: California Air Resources Board, March

2005), available at www.arb.ca.gov/research/aaqs/ozone-rs/

ozone-final/ozone-final.htm; J. Schwartz, “Rethinking the 

California Air Resources Board’s Ozone Standards” (working

paper, AEI, Washington, D.C., September 2005), www.aei.org/

publication23145.

54. Death, Disease and Dirty Power, Clean Air Task Force;

Power to Kill: Death and Disease from Power Plants Charged with

Violating the Clean Air Act (Boston: Clean Air Task Force, July

2001); Children at Risk: How Air Pollution from Power Plants

Threatens the Health of America’s Children, Physicians for Social

Responsibility; Danger in the Air, PIRG.

55. Environmental Protection Agency (EPA), “Clean Air

Interstate Rule,” available at www.epa.gov/cair/.

56. “Clean Air Interstate Rule: Charts and Table,” EPA,

available at www.epa.gov/cair/charts.html.

57. Clean Air Interstate Rule (CAIR): Reducing Power Plant

Emissions for Cleaner Air, Healthier People, and a Strong America

(Washington, D.C.: EPA, March 2005), available at www.epa.

gov/cair/charts_files/cair_final_presentation.pdf.

58. L. C. Green and S. R. Armstrong, “Particulate Matter in

Ambient Air and Mortality: Toxicologic Perspectives”; M. A.

Sackner, D. Ford, and R. Fernandez, “Effect of Sulfate Aerosols

on Cardiopulmonary Function of Normal Humans,” American

Review of Respiratory Disease 115 (1977): 240; and M. J. Utell,

P. E. Morrow, D. M. Speers et al., “Airway Responses to Sulfate

and Sulfuric Acid Aerosols in Asthmatics. An ExposureResponse Relationship,” American Review of Respiratory Disease

128 (1983): 444–50.

59. J. Q. Koenig, K. Dumler, V. Rebolledo et al., “Respiratory Effects of Inhaled Sulfuric Acid on Senior Asthmatics and

Nonasthmatics,” Archives of Environmental Health 48 (1993):

171–75.

60. Review of the California Ambient Air Quality Standard for

Ozone, CARB.

- 11 -
61. J. Schwartz, “Rethinking the California Air Resources

Board’s Ozone Standards”; S. F. van den Eeden, C. P. Quesenberry, J. Shan et al., Particulate Air Pollution and Morbidity in

the California Central Valley: A High Particulate Pollution Region

(Sacramento: CARB, July 2002).

62. Air Quality Criteria for Ozone and Related Photochemical

Oxidants (Second External Review Draft) Volumes I-III (Washington, D.C.: EPA, August 2005), available at www.epa.gov/

ttn/naaqs/standards/ozone/s_o3_cr_cd.html.

63. C. A. Pope III, M. J. Thun, M. M. Namboodiri et al.,

“Particulate Air Pollution as a Predictor of Mortality in a

Prospective Study of U.S. Adults,” American Journal of Respiratory and Critical Care Medicine 151 (1995): 669–74.

64. C. A. Pope III, R. T. Burnett, M. J. Thun et al., “Lung

Cancer, Cardiopulmonary Mortality, and Long-Term Exposure

to Fine Particulate Air Pollution,” Journal of the American Medical Association 287 (2002): 1132–41.

65. D. Krewski, R. T. Burnett, M. S. Goldberg et al.,

Reanalysis of the Harvard Six Cities Study and the American

Cancer Society Study of Particulate Air Pollution and Mortality

(Cambridge, MA: Health Effects Institute, July 2000); Pope,

Burnett, Thun et al., “Lung Cancer, Cardiopulmonary 

Mortality.”

66. Ibid.

67. J. P. Ioannidis, “Why Most Published Research Findings

Are False,” PLoS Medicine 2 (2005): e124; W. R. Keatinge and

G. C. Donaldson, “Heat Acclimatization and Sunshine Cause

False Indications of Mortality Due to Ozone,” Environmental

Research 100 (2006): 387–93; G. Koop and L. Tole, “Measuring

the Health Effects of Air Pollution: To What Extent Can We

Really Say That People Are Dying from Bad Air?” Journal of

Environmental Economics and Management 47 (2004): 30–54; T.

Lumley and L. Sheppard, “Time Series Analyses of Air Pollution and Health: Straining at Gnats and Swallowing Camels?”

Epidemiology 14 (2003): 13–14; S. H. Moolgavkar, “A Review

and Critique of the EPA’s Rationale for a Fine Particle Standard,” Regulatory Toxicology and Pharmacology 42 (2005): 123–44;

G. D. Smith, “Reflections on the Limitations to Epidemiology,”

Journal of Clinical Epidemiology 54 (2001): 325–31; G. Taubes,

“Epidemiology Faces Its Limits,” Science 269 (1995): 164–69.

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#20036 May 2, 2006
AECOM 22

Attachment 4: Resume for Lisa JN Bradley, Ph.D., DABT 
AECOM LJN Bradley Resume Chelmsford, MA 

 Environment 

 July 2013 

Page 1 of 13 

Lisa J. N. Bradley, Ph.D., DABT 

Vice President and Senior Toxicologist 

Professional History 

AECOM (formerly ENSR) 

Massachusetts Institute of 

Technology 

University of Idaho 

Education 

PhD (Toxicology) Massachusetts 

Institute of Technology, 1991 

BS (Zoology) University of Idaho, 

1983 

BS (Chemistry) University of Idaho, 

1983 

Years of Experience 25 

Technical Specialties 

Toxicology 

Risk Assessment 

Environmental Communication 

Regulatory Negotiation 

Site Strategy Development 

Professional Affiliations 

Diplomate, American Board of 

Toxicology, 1994 

Society of Toxicology 

Phi Beta Kappa 

Dr. Lisa Bradley is a Senior Toxicologist/Risk Assessor and Vice President 

with AECOM. She has a Ph.D. in toxicology from the Massachusetts 

Institute of Technology. She has 25 years of experience in risk assessment 

and toxicology, and is certified by the American Board of Toxicology. She 

has managed risk assessments for hazardous waste sites in many EPA 

Regions, and under many state programs. Dr. Bradley has also served as 

an advisor on strategic risk assessment issues for clients in the natural gas, 

utility, and railroad industries. She has developed the risk assessment 

approach for a large multi-site program for a railroad client, for a national 

steel client, and developed and managed the risk evaluation component of 

a large multi-site, multi-state federal program for a natural gas client. Dr. 

Bradley is experienced in public speaking and environmental 

communications, and she has published articles in peer reviewed scientific 

journals based on both her laboratory and risk assessment work. Dr. 

Bradley is the global risk practice technical lead for AECOM. She is the 

manager and technical lead for AECOM’s coal combustion product (CCP) 

initiative and was recently elected to the Executive Committee of the 

American Coal Ash Association. 

Experience 

A. Representative Superfund Experience 

Pines Area of Investigation, Indiana, USEPA Region 5. Serving as project 

manager for a multi-disciplinary team conducting the Remedial 

Investigation/Feasibility Study for the Respondents of an Administrative 

Order on Consent (AOC) being administered under the Superfund Alternative 

program in USEPA Region 5. The AOC addresses the placement of coal 

combustion by-products (CCBs) within a local permitted landfill and allegedly 

used as fill in other locations within the Area of investigation. Activities to 

date include agency negotiations on the AOC and scope of work; submission 

of a Site Management Strategy document, and subsequent approval by the 
AECOM LJN Bradley Resume Chelmsford, MA 

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Agency; submittal of the RI/FS Work Plan (including a Field Sampling Plan, 

Human Health and Ecological Risk Assessment Work Plans, HASP, QAPP, 

and a Quality Management Plan), and subsequent approval by the agency; 

submission of additional Sampling and Analysis Plans; and communications 

activities (including a website – www.pinesupdate.com - and regular mailings 

of information updates to the community). Regular communications with the 

agency is also a cornerstone of the project. As the site covers not a facility, 

but a town and surrounding area, executing access agreements with the land 

owners for sampling and well installation was a critical task. Four rounds of 

sampling and analysis have been successfully completed. The Final RI 

Report has been approved, and the Human Health Risk Assessment Report 

and the Ecological Risk Assessment Report have been approved and the 

Draft Feasibility Study has been submitted to the agency. Approved project 

documents to date are available on USEPA’s website: 

http://www.epa.gov/region5/sites/pines/index.htm. 

Aurora Energy, Fairbanks, AK. Providing consulting services for an EPA 

HRS scoring investigation of the coal-fired power plant. Activities have 

included fact sheet preparation, frequently asked questions and answers, 

document review, strategy development, and risk-based evaluation of 

detailed coal and coal ash data sets for the facility. 

Delaware Sand & Gravel Remedial Trust, Delaware, USEPA Region 3. A 

human health risk assessment (HHRA) focusing on evaluation of the vapor 

intrusion exposure pathway was performed for the PRPs at a former drum 

disposal area to evaluate the effectiveness of a Bioremediation System 

installed as a result of an EPA Superfund Record of Decision Amendment. A 

tiered vapor intrusion assessment was performed consistent with USEPA 

guidance using groundwater and then soil gas data. It was successfully 

concluded, with acceptance from EPA Region 3, that no unacceptable risk to 

human health was posed to occupants of on-site buildings via the vapor 

intrusion inhalation pathway. 

Solutia, Inc., Human Health Risk Assessment, Sauget Area 1, Illinois, 

USEPA Region 5. Prepared a human health risk assessment work plan to 

follow Superfund guidelines for several abandoned landfill areas and areas 

downgradient of the landfills. The work plan was accepted by U.S. EPA 

Region V. A comprehensive human health risk assessment was prepared 

that evaluated the former land fill areas as well as local residential areas, a 

creek, and a borrow pit lake. A total of 64 receptor and area scenarios were 

quantitatively evaluated. Supporting risk modeling included indoor and 

outdoor air from subsurface soil and groundwater. Activities included site 

visits, meetings with personnel from USEPA Region 5 and their contractors, 

and preparations of responses to comments and document revisions. The 

human health risk assessment has been accepted by the agency, and the 

results have been used to guide the feasibility study and remedy selection. 

Constituents of interest included PCBs in ditch sediments. The final report is 

available on EPA’s website: 

http://www.epa.gov/region5/cleanup/saugetarea1/pdfs/

sauget1_deadcreek_final_remedy_200604.pdf 
AECOM LJN Bradley Resume Chelmsford, MA 

 Environment 

 July 2013 

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Sauget Area 2 Sites Group, Human Health Risk Assessment, Illinois, 

USEPA Region 5. Serving as the senior human health risk assessment 

manager for a multi-party PRP group. Prepared a human health risk 

assessment work plan to follow Superfund guidelines for a set of sites that 

include abandoned landfill areas. Conducted the multi-receptor, multipathway human health risk assessment, including vapor intrusion modeling 

for both indoor and outdoor air for the multiple multi-acre sites within the 

project area. Activities included a site visit, meetings and negotiations with 

USEPA Region 5 and their contractors, and preparation of responses to 

comments.

Columbia Gas Transmission, Strategic Risk Assessment Advisor, West 

Virginia, USEPA Region 3. Served as strategic risk assessment advisor to a 

multi-site, ten-state AOC with U.S. EPA Region III to assess environmental 

conditions along their pipeline system in the Mid-Atlantic States. Provided 

strategic risk assessment advice and technical support on the design and 

implementation of the program, and developed a programmatic approach to 

the evaluation of risk across the program. Was responsible for: review of 

other contractor reports, development of a common strategy for TPH and 

mercury to be used across the program, review and summary of risk 

assessment regulations and guidance for each of the states (Ohio, 

Pennsylvania, West Virginia, Virginia, Kentucky, North Carolina, Delaware, 

New Jersey, Maryland, New York, and Louisiana), conducted risk 

assessments, provided critical review of individual site characterization 

reports prepared by other contractors, and provided support in negotiations 

and meetings with regulators. Additional constituents of interest include 

PCBs, arsenic, and PAHs. 

Tippecanoe Landfill, Human Health Risk Assessment, Indiana, USEPA 

Region 5. Conducted agency negotiations (U.S. EPA Region V) concerning 

the human health risk assessment for a Superfund site. Because arsenic 

concentrations in groundwater were of concern to the agency, researched 

and reviewed the toxicological information available for arsenic, and prepared 

a literature review and evaluation of the dose-response values developed by 

the U.S. EPA for arsenic. 

Industri-Plex CERCLA Site, Risk Assessment Review and Strategy for 

PRP Group, Massachusetts, USEPA Region 1. Provided risk assessment 

review and strategy for PRP group, and developed risk assessment work 

plan to address surface water and groundwater exposure pathways. 

Tennessee Valley Authority, Human Health Risk Assessment, 

Tennessee, USEPA Region 4. Prepared human health risk assessment 

and developed target cleanup levels for an abandoned battery manufacturing 

site. Primary constituent was lead and both child and adult lead models were 

used in the evaluation. 

Confidential Client, Human Health Risk Assessment, New Jersey, 

USEPA Region 5. Conducted a human health risk assessment for a school 

district's baseball fields located adjacent to a potential Superfund site. Report 
AECOM LJN Bradley Resume Chelmsford, MA 

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 July 2013 

Page 4 of 13 

was prepared for community distribution, and results presented at a public 

meeting. 

Motco Superfund Site, Review of AIC for Volatile Organics, Texas, 

USEPA Region 6. Reviewed U.S. EPA-developed acute inhalation criteria 

(AIC) for volatile organics. Developed a consistent and scientificallydefensible methodology for AIC development, and applied this methodology 

to provide alternative AICs for use at the site. 

Brio Site Task Force, Texas, USEPA Region 6. Developed acute 

inhalation criteria for use in a remedial program for benzene, 1,1-

dichloroethane, 1,2-dichloroethane, ethyl benzene, methylene chloride, 

styrene, toluene, 1,1,1-trichloroethane, 1,1,2-trichloroethane, and vinyl 

chloride. 

B. Representative RCRA Experience 

Solutia, Inc., Human Health Risk Assessment Oversight for the J.F. 

Queeny Facility, St. Louis, Missouri. Provided oversight for the human 

health risk assessment prepared for the facility under an order with USEPA 

Region 6. The risk assessment is designed to meet the requirements of both 

USEPA and the State of Missouri Risk-Based Corrective Action Program. 

Solutia, Inc., Human Health Risk Assessment for the W.G. Krummrich 

Facility, Sauget, Illinois, USEPA Region 5. Developed the human health 

risk assessment workplan and report for the RCRA Sampling Plan for 

Solutia's W.G. Krummrich Facility. The workplan was designed to permit 

evaluation of the "Human Exposures Environmental Indicator" as well as 

human health risk. Used risk assessment and data visualization to identify 

extent of areas for remediation such that total site risk would not exceed 

target risk levels once remediation is complete. Also used the risk 

assessment to identify remedial treatment objectives for soils and 

groundwater. Target chemicals included PCBs and chlorinated compounds. 

U.S. Steel, Human Health Risk Assessment, Gary, Indiana, USEPA 

Region 5. Developed the RCRA RFI Human Health Risk Assessment 

Workplan for the U.S. Steel Gary Works. Activities included response to 

regulatory comments on previous reports, site visits, review of reports 

generated both by USS and by local groups about the facility and its 

environs, development of the risk-related portions of the facility-wide RCRA 

RFI workplan, in addition to the HHRA workplan, and agency negotiation. 

Participated in strategy development for and preparation of the human health 

sections of the Sampling and Analysis Plans for each of the Solid Waste 

Management Areas being addressed at Gary Works under RCRA (13 in 

total). Managed and prepared the human health risk evaluation of perimeter 

groundwater data. Work included conducting a two tiered well-by-well 

screening (55 wells total). The first tier comparison was to generic and 

readily available standards, and the second tier took into account background 

and dilution into receiving water bodies, and evaluated construction worker 

and indoor air scenarios. 
AECOM LJN Bradley Resume Chelmsford, MA 

 Environment 

 July 2013 

Page 5 of 13 

U.S. Steel, Human Health Risk Assessment, Fairless Hills, 

Pennsylvania, USEPA Region 3. Prepared the human health risk 

evaluation under RCRA Corrective Action for a parcel of property to be 

leased by U.S. Steel at Fairless Works. The work was conducted to satisfy 

Pennsylvania Department of Environmental Protection (PADEP) 

requirements under the Pennsylvania Act 2 program, as well as USEPA 

Region 3 requirements. Activities included site visit, meetings and 

presentations to both agencies, as well as preparation of memoranda and 

reports. Included in the evaluation was a sensitivity analysis of the 

parameters used to evaluate a construction worker scenario; site-specific 

parameters, parameters from the scientific literature, and parameters 

provided by the agency were evaluated. 

U.S. Steel, Human Health Risk Assessment, Fairfield, Alabama, USEPA 

Region 4. Developed the RCRA RFI Human Health Risk Assessment 

Workplan for the U.S. Steel Fairfield Works under USEPA Region 4 and 

Alabama Department of Environmental Management (ADEM) requirements. 

Activities included site visits, preparation of strategy, review of the full RFI 

workplan to ensure consistency with risk objectives, and preparation of 

responses to agency comments. Work included a detailed evaluation of 

USEPA’s current and proposed adult soil ingestion rates. 

Hartford Working Group, Hartford Hydrocarbon Plume Site, Hartford, 

Illinois, USEPA Region 5. Provided toxicology and risk assessment 

services to the PRP group for the Hartford Hydrocarbon Plume site in 

Hartford, IL. Provided review of indoor air screening levels developed by the 

Agencies for benzene, butane, isopentane, trimethylbenzene and other 

petroleum-related constituents used in vapor intrusion evaluations. 

C. Representative Risk Assessment Experience Under Other 

Programs 

NiSource, Risk Assessment Issues, Columbus, Ohio. Serving as the 

human health risk assessment expert for NiSource’s environmental 

programs. Have addressed issues related to PCBs (including conducting 

employee informational meetings), MGP-related constituents (benzene, 

PAHs), radon, and mercury. 

Confidential Utility. Have provided PCB expert support for issues related to 

PCBs in natural gas pipeline systems and potential residential and 

commercial exposures. 

Bureau of Land Management, Environmental Impact Statement, 

Western States. Developed human health risk assessment to evaluate five 

pesticides proposed for use in BLM vegetation treatment programs. Risk 

assessment uses standard USEPA Office of Pesticide Policy risk 

assessment methods and includes use of the AgDRIFT model to evaluate 

off-site spray drift and deposition, and transport models to evaluate surface 

water impacts. Worker, public and Native American subsistence receptors 

were evaluated. Work has included interagency scoping meetings. Report 
AECOM LJN Bradley Resume Chelmsford, MA 

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 July 2013 

Page 6 of 13 

available at: http://www.blm.gov/wo/st/en/prog/more/veg_eis.html. 2007. 

Bureau of Land Management, Environmental Impact Statement, 

Western States. Conducting human health risk assessment for additional 

pesticides for the BLM vegetation treatment programs following the protocol 

developed for the 2007 BLM Vegetation EIS. 

Confidential Client, Indiana. Evaluated groundwater and soil gas data for 

vapor intrusive to indoor air using the USEPA version of the Johnson and 

Ettinger model. Used the Johnson (2002) sensitivity analysis method to 

ensure that critical model parameters were within acceptable/realistic ranges. 

Provided deposition testimony and testimony in a court hearing on both the 

vapor intrusion pathway risk assessment and the toxicology of benzene. 

U.S. Steel, Development of a Standardized Risk Evaluation Guidance 

Manual, Pennsylvania. Worked in conjunction with another firm and USS 

personnel to develop a standardized Risk Evaluation Guidance Manual for 

USS. The manual addresses important issues in human health and 

ecological risk assessment, provides background for the issues, USS 

strategy to address the issues, and examples of standard language and 

references to be used in future USS reports. The manual will allow for more 

cost-effective and consistent risk evaluations to be conducted for USS 

facilities and sites. 

U.S. Steel, Review and Comment on Indiana's RISC Program, Indiana. 

Reviewed several draft versions of Indiana's "Risk Integrated System for 

Closure" guidance, and submitted comments to the agency. Detailed 

comments were provided on the following topics: construction worker soil 

ingestion rate, soil saturation limit, arbitrary caps for metals concentrations in 

soil. Have also prepared comments on Indiana's draft groundwater policy 

and The User's Guide that details how the RISC program will be applied to 

RCRA sites under state authority. 

U.S. Steel, Human Health Risk Assessment, Fairfield, Alabama. 

Conducted a human health risk evaluation for a parcel of property to be 

leased by U.S. Steel at Fairfield Works. Activities included evaluation of a 

construction worker scenario, and use of the Johnson & Ettinger and ASTM 

models to evaluate indoor and outdoor air. 

West Virginia Manufacturer’s Association, West Virginia. Worked with 

the WVMA on a committee to review and provide language to the West 

Virginia Department of Environmental Protection in development of their 

tiered site closure guidance. 

Indiana Department of Environmental Management, Indiana. Served on 

an IDEM committee to review and provide language in the development of 

revisions to the "Risk Integrated System for Closure" guidance. 

D. Representative Toxicology Experience 

Utility Solid Waste Activities Group (USWAG), Washington, DC. 

Reviewed and developed comments on the risk assessment aspects of 
AECOM LJN Bradley Resume Chelmsford, MA 

 Environment 

 July 2013 

Page 7 of 13 

USEPA’s June 2010 proposed rulemaking for the disposal of coal 

combustion residuals (CCRs). Comments focused on a critique of the 

USEPA’s updated human health and ecological risk assessment, a critique of 

the USEPA’s fugitive dust model report, and a critique of USEPA’s proposed 

listing of CCRs as a hazardous waste under RCRA Subtitle C. 

Utility Solid Waste Activities Group (USWAG), Washington, DC. 

Reviewed and developed comments on the USEPA’s risk assessment for 

coal combustion wastes. The risk assessment was released in 2007, and 

comments were submitted under USWAG cover in January 2008. AECOM 

addressed all aspects of the risk assessment including human health, 

ecological risk and fate and transport. Provided oral comments during a 

national teleconference. 

Utility Solid Waste Activities Group (USWAG), Washington, DC. 

Developed information sheet on “What is Coal Ash” for use by the USWAG 

membership for community relations. 

Electric Power Research Institute, Palo Alto, CA. Developed the report 

“Comparison of Risks for Leachate from Coal Combustion Product Landfills 

and Impoundments with Risks for Leachate from Municipal Solid Waste 

Landfill Facilities,” EPRI Report Number 1020555, available at www.epri.com. 

Prairie State Energy Campus, Washington County, IL. Provided 

presentation to county board on coal ash composition and health risk issues. 

We Energies, Milwaukee, WI. Reviewed the basis of the state and USEPA 

screening levels and toxicity values for molybdenum, and demonstrated the 

over-conservatism used in their derivation. Provided the review to the state 

agency, and developed a fact sheet on molybdenum in groundwater for 

communications with a local community. 

We Energies, Milwaukee, WI. Reviewed the basis of the state screening 

levels and toxicity values for aluminum as part of review of the Wisconsin 

Department of Natural Resources proposed groundwater standards under 

NR 140. Provided testimony for a board hearing, and met with the state 

regulators, and demonstrated the over-conservatism used in their derivation. 

Ameren UE, St. Louis, MO. Developed a human health and ecological risk 

assessment to support the regulatory closure under the state agency of a 

former ash impoundment located along a major river at the Hutsonville, IL 

Power Station. Boron and molybdenum were constituents of interest. 

Pathways evaluated in the risk assessment included use of groundwater for 

irrigation purposes and the migration of groundwater to the river and potential 

impact on the benthic community. Work included negotiation meeting with 

the local agency. 

Ameren UE, St. Louis, MO. Serving as an expert for a landfill siting project 

in Missouri, for issues related to exposure, toxicity and risk assessment. 

Provided public testimony at a county board meeting as well as written 

comments that have been submitted into the record. 
AECOM LJN Bradley Resume Chelmsford, MA 

 Environment 

 July 2013 

Page 8 of 13 

Ameren UE, St. Louis, MO. Providing toxicology and risk assessment 

support for various coal ash related projects in Illinois and Missouri. 

AES, New York. Provided expert testimony on the lack of human health 

effects of ammonia in groundwater associated with coal ash landfills. 

Developed expert opinion, reviewed and critiqued opposing opinions, and 

testified at hearing. 

AES, Puerto Rico. Provided review and synthesis of data associated with a 

beneficial use product, AGREMAXTM manufactured by AES Puerto Rico 

using bottom ash and fly ash from the coal-fired power plant. Specifically, 

evaluation of data on metals content, leaching of metals, and radionuclides 

were shown not to pose a human health or environmental risk based on the 

beneficial uses of AGREMAXTM. Testified on AES behalf at a Puerto Rican 

Senate subcommittee hearing on coal ash issues. 

South Carolina Electric & Gas, Columbia, SC. Provided presentation 

materials for use in a landfill siting and zoning process. Materials addressed 

the comparison of arsenic and other metals and radionuclides in coal ash and 

in our natural environment, and background levels of arsenic in foods and 

background levels of exposure to radioactivity in our natural environment. 

Utility Solid Waste Activities Group (USWAG), Washington, DC. 

Provided oversight of comments developed on the proposed listing of 

naphthalene as a carcinogen by the National Toxicology Program, and on the 

USEPA’s childhood cancer document. 

Electric Power Research Institute, California. Worked with another ENSR 

toxicologist to develop a critique of the benzo(a)pyrene toxicity value 

developed by the United Kingdom for their Contaminated Lands program. 

Confidential Natural Gas Client, Toxicity Assessment, Ohio. Provided 

toxicity assessment of cleaning compounds proposed for use in the 

decommissioning of a natural gas pipeline laid on the bed of a reservoir that 

serves as the primary drinking water source for a community. Demonstrated 

that even should a catastrophic release of cleaning fluid and/or PCBs occur, 

human and ecological health would not be adversely affected and that 

concentrations at the drinking water intake would be much lower than healthbased values or detection limits. 

Confidential Client, Toxicology Review, Indiana. Provided a review of the 

toxicology and potential carcinogenicity of two structurally similar proprietary 

industrial chemicals. Used recent data on the nongenotoxic/cytotoxic 

mechanism of action of a class of potential carcinogens to demonstrate that a 

safe level for worker exposure exists. 

U.S. Environmental Protection Agency, Literature Review. Developed a 

strategy for evaluating absorption data in the literature and applied it to the 

development of absorption adjustment factors for oral and dermal exposures 

to soil and water for 5 metals of concern at hazardous waste sites (arsenic, 

cadmium, chromium III, chromium VI, inorganic mercury, organic mercury, 
AECOM LJN Bradley Resume Chelmsford, MA 

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 July 2013 

Page 9 of 13 

and nickel) based on a thorough review of the literature. 

Georgia Pacific, Literature Review, Georgia. Reviewed literature and 

summarized the current scientific knowledge of the endogenous synthesis of 

halogenated compounds in humans. 

E. Representative MGP Experience 

Natural Gas Company, Risk Assessment Advisor, Ohio. Serving as 

strategic risk assessment advisor to the manager of MGP sites. Work 

includes conducting risk assessments for MGP sites under various state 

programs, evaluation of program-wide vapor intrusion data, regulatory 

negotiations, environmental communications, and employee meetings. 

Natural Gas Company, Former MGP Site Advisor, Wisconsin. Have 

reviewed remediation plans and fenceline monitoring plans, gave 

presentation at public meetings discussing the air monitoring plan, and have 

reviewed fenceline monitoring data for a remediation project. 

Energy Company, Former MGP Site Review, Rhode Island. Provided 

senior review of an air monitoring program and identified where flexibility can 

be used in the development of fenceline air monitoring standards. 

Village of Oak Park, Former MGP Site Advisor, Illinois. Provided senior 

review of remediation plans, and fenceline monitoring plans, and provided air 

monitoring data evaluation. Was involved in regulatory meetings, 

negotiations, and presentations to the Village council, including public 

meetings concerning air monitoring aspects of the project. 

Committees 

Leader of AECOM’s Risk Assessment Technical Practice Group including 

practitioners internationally within AECOM with specialties in human health 

and ecological risk assessment and other supporting disciplines. 

Leader of AECOM’s Coal Combustion Product (CCP) Initiative; responsible 

for following regulatory developments, and keeping AECOM staff and clients 

updated on the issues. 

Elected member of the American Coal Ash Association (ACAA) Executive 

Committee, and member of the Government Relations Committee, and the 

Women’s Leadership Forum. 

Publications and Presentations 

“Coal Ash Material Safety: A Health Risk-Based Evaluation of USGS Coal 

Ash Data from Five US Power Plants.” LJN Bradley. Poster presented at the 

Society of Toxicology Annual meeting, March 2013, San Antonio, TX. 

Abstract 2211, The Toxicologist, Volume 132, Issue 1. Available at: 

www.toxci.osfordjournals.org. 
AECOM LJN Bradley Resume Chelmsford, MA 

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Page 10 of 13 

“Key Decisions in Establishing National Ambient Air Quality Standards.” L 

Fraiser and LJN Bradley. Poster presented at the Society of Toxicology 

Annual meeting, March 2013, San Antonio, TX. Abstract 1567, The 

Toxicologist, Volume 132, Issue 1. Available at: 

www.toxci.osfordjournals.org. 

“Coal Ash Material Safety: A Health Risk-Based Evaluation.” LJN Bradley. 

American Coal, Issue 2, 2012. Available at: www.americancoalonlime.com. 

“Coal Ash Material Safety: A Health Risk-Based Evaluation of USGS Coal 

Ash Data from Five US Power Plants.” LJN Bradley. Ash at Work, Issue 1, 

2012. Available at: www.acaa-usa.org. 

“Health Hazards and Risk Issues: Sorting Fact from Fear.” Invited 

presentation at the Coal Combustion Products Utilization & Management: A 

Practical Workshop. Lexington, KY. October 9-10, 2012. 

“Is this Risk for Real? Putting Risk Results into Context.” Invited 

presentation at the Midwest Energy Association meeting, Minneapolis, MN. 

September 2012. 

“Coal Ash Material Safety: A Health Risk-Based Evaluation of USGS Coal 

Ash Data from Five US Power Plants.” American Coal Ash Association 

Summer Meeting, Portsmouth, VA. June 2012. 

“Coal Ash Material Safety: A Health Risk-Based Evaluation of USGS Coal 

Ash Data from Five US Power Plants.” June 2012. Report prepared for the 

American Coal Ash Association. Available at: www.acaa-usa.org. 

“Coal Ash Material Safety: A Health Risk-Based Evaluation of USGS Coal 

Ash Data from Five US Power Plants.” Press Conference, National Press 

Club, Washington, DC. June 6, 2012. 

“Health Risk of CCPs: Is Coal Ash Toxic?” Presentation at the South 

Carolina SWANA Meeting. Myrtle Beach, SC, May 2012. 

“Health Risk of CCPs: Is Coal Ash Toxic?” Presentation at Electric Power 

2012. Baltimore, MD, May 2012. 

“Hexavalent Chromium in Perspective” Presentation and invited Chair – 

Human Health Risk Panel, MGP 2012, Chicago, IL, March 29, 2012. 

“Health Risk of CCPs.” Invited presentation at the Coal Ash Consortium, 

Scottsdale, AZ, March 28, 2012. 

“Health Risk of CCPs.” Presented at the EUCI conference on CCR 

Management: Impacts of Regulations and Technological Advances. , 

Nashville, TN, February 28-29, 2012. 

“Coal Ash in Context: Separating Science from Sound Bites As Regulatory 
AECOM LJN Bradley Resume Chelmsford, MA 

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 July 2013 

Page 11 of 13 

and News Media Debates Continue.” LJN Bradley and J Ward. Ash at 

Work, Issue 1, 2011. Available at www.acaa-usa.org. 

“Management of Coal Ash Disposal and Household Trash – Do They Need to 

be Different?” LJN Bradley. Energeia, Volume 22, No. 4, 2011. Available at: 

http://www.caer.uky.edu/energeia/enerhome.shtml. 

Bradley, L.J.N., “Comparison of Risks for Leachate from Coal Combustion 

Product Landfills and Impoundments with Risks for Leachate from Municipal 

Solid Waste Landfill Facilities.” EPRI Report Number 1020555, available at 

www.epri.com. 

“Risk Assessment: How the EPA Looks at Coal Combustion Products.” 

Presented at the ACAA Fall meeting, Indianapolis, IN, September 27, 2011. 

“Risk assessment: An overview of how the U.S. Environmental Protection 

Agency looks at coal combustion residuals.” Presented at the American 

Chemical Society meeting in Denver, CO, August 28, 2011. 

“Is Coal Ash Toxic?” Keynote Presentation at the World of Coal Ash May 10-

12, 2011, and invited presentation at The Coal Institute/NCCI meeting July 

11, 2011. 

“Potential Effect of Proposed Coal Combustion Residuals Regulation and 

Alternative Leach Testing on Beneficial Reuse.” World of Coal Ash May 10-

12, 2011. 

“Comparison of Risks for Leachate from Coal Combustion Product Landfills 

and Impoundments with Risks for Leachate from Municipal Solid Waste 

Landfill Facilities.” World of Coal Ash May 10-12, 2011, and poster at Society 

of Toxicology March 6-10, 2011. 

“Overview of Coal Ash Regulatory Issues.” NCASI Northern Regional 

Meeting May 18-19, 2011. 

“Perspectives on Health Risks Associated with Beneficial Re‐Use of 

Byproducts of Coal Combustion.” McIlvaine Hot Topic Hour. April 28, 2011. 

”Risk Assessment: How the EPA Looks at Coal Combustion Products.” EUCI 

March 13-14, 2011. 

 “Risk Assessment: How the EPA Looks at Coal Combustion Products.” 

Presented at the EUCI conference on Future of Coal Combustion Products 

(CCPs): Regulatory, Legal, Technical, and New Markets, March 2011, 

Denver, CO. 

“Development of a Realistic Risk Assessment Conceptual Site Model for an 

Urban River Sediment Site.” B. Ruffle, L. Bradley, K. Durocher, and L. 

Fraiser. Battelle Sediment Conference February 7-10, 2011. 

Press Conference with ACAA (American Coal Ash Association) , October 27, 
AECOM LJN Bradley Resume Chelmsford, MA 

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Page 12 of 13 

2010, Knoxville, TN. 

“USEPA’s Proposed rule for Coal Combustion Residual (CCRs): Beneficial 

Use Aspects.” Keynote address given at the June 2010 meeting of the 

American Coal Ash Association, Baltimore, MD. Bradley, L.J.N, and A. Ellis. 

 “Overview of a CCP Site Investigation Conducted Under the Superfund 

Alternative Program.” Presented at the ACAA spring meeting, March 2010, 

Nashville, TN. 

 “Coal Ash Business Planning and Management: Addressing Risks and 

Liabilities in a Changing Regulatory Environment.” Workshop presented at 

the EUCI Conference on the Future of Coal Combustion Products, March 

2010, Houston, TX. L.J.N. Bradley, J. Trast, J. Matus,, and A. Kier. 

“PAHs and Dioxins Not Present in Fly Ash at Levels of Concern.” World of 

Coal Ash, May 2009 and Society of Toxicology, March 2009. 

Bradley, L.J.N., G.M. Fent, and S.W. Casteel. “In Vivo Bioavailability of 

Arsenic in Coal Combustion By-Products.” Poster presented at the Society of 

Toxicology 2008 annual meeting in Seattle, WA. 

Bradley, L.J.N., K. Sullivan, and M. Garcia. “Background Levels of Benzene 

in Indoor and Outdoor Air.” Paper presented at the Gas Technology 

Institute’s Natural Gas Technologies II Conference, Phoenix, Arizona. 

February, 2004 

Bradley, L.J.N., and K.A. Sullivan. "Risk-Based Action Levels for 

Remediation Project Fence-Line Air Monitoring Programs." The Toxicologist. 

72(S-1): 395. March, 2003 

Bradley, L.J.N., and M. Gerath. "Generic Risk and Fate Analysis for Mercury 

at Natural Gas Meters." Paper presented at the December 1998 Society for 

Risk Analysis Annual Meeting, Phoenix, AZ. 

Bradley, L.J.N., K.B. Lemieux, M.C. Garcia, A.H. Parsons, and D.E. Rabbe. 

"Comparison of Concentrations of Selected Metals and Organics in Fish 

Tissue and Sediment in the Grand River, Ohio, and the Southern Lake Erie 

Drainage Basin." Human and Ecological Risk Assessment 4(1):57-74 

(1998). 

Bradley, L.J.N. "TPH Analyses Provide Means of Direct Assessment of 

Diesel Releases." Paper presented at the October, 1997, Contaminated Soils 

Conference, Amherst, MA. 

Bradley, L.J.N. "Risk Assessment of Hazardous Air Pollutants in Arizona." 

Paper presented at the December, 1996 Society for Risk Analysis Annual 

Meeting, New Orleans, LA. 

Bradley, L.J.N. "Cost-Effective Use of Tiered Approaches in Risk 

Assessment." Paper presented at the October, 1996 Annual Conference on 
AECOM LJN Bradley Resume Chelmsford, MA 

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Page 13 of 13 

Contaminated Soils, Amherst, MA. 

Bradley, L.J.N. "Role of Risk Assessment in Environmental Management." 

Invited paper presented at the West Virginia Manufacturers Association 

Environmental Compliance Conference, May, 1996, Charleston, WV. 

Bradley, L.J.N. "New Toxicology Data for Chloroform: Implications for the 

Pulp and Paper Industry." Proceedings of the 1996 Environmental 

Conference of the Technical Association of the Pulp and Paper Industry. Vol 

1, pp. 13-16 (1996). 

Bradley, L.J.N. "Ingested Arsenic - Are the Taiwanese Data Appropriate for 

Risk Assessment in the U.S." Paper presented at the December, 1994, 

Society of Risk Analysis Conference, Baltimore, MD. 

Magee, B.H., and L.J.N. Bradley. "Absorption Adjustment Factors for Use in 

Risk Assessment." Proceedings of the International Congress on the Health 

Effects of Hazardous Waste. (1994). 

Bradley, L.J.N., B.H. Magee, and S.L. Allen. "Background Levels of 

Polycyclic Aromatic Hydrocarbons and Selected Metals in New England 

Urban Soils." J. Soil Contam. 3(4):349-361. (1994). 

Magee, B.H., L.J.N. Bradley, E.L. Butler, A. Dasinger, J. Grabowski. "RiskBased Target Clean-Up Levels for TPH in Soils." In: Hydrocarbon 

Contaminated Soils. Vol. 3. pp. 303-319. Edited by P.T. Kostecki and E.J. 

Calabrese. 1993. 

Bradley, L.J.N. "Human Health Risk Assessment Workshop." Presented at 

the September, 1992, Hydrocarbon Contaminated Soils Conference, 

Amherst, MA. 
EXHIBIT 13

AFFIDAVIT OF STEVEN C. WHITWORTH 
AFFIDAVIT OF STEVEN C. WHITWORTH 

I. BACKGROUND AND QUALIFICATIONS 

1. My name is Steven C. Whitworth, and I am employed by Ameren Services 

Company as the Director of Environmental Services. Ameren Services Company provides 

business services to Ameren Corporation's operating companies including Ameren Energy 

Resources ("AER") and its subsidiary companies, Ameren Energy Generating Company 

("GENCO") and AmerenEnergy Resources Company. I have been employed with Ameren 

Services Company since 1998 following the merger of Central Illinois Public Services Company 

and Union Electric Company. During the course of my career I have worked in the 

environmental air quality and permitting arena since 1989. I have been in my current position 

since 2007. In addition to supervising staff personnel, I am responsible for implementing 

policies and procedures relating to environmental compliance. In this capacity, I am responsible 

for representing the Ameren Companies before regulatory and administrative bodies with respect 

to state and federal permitting conditions and regulatory requirements. 

II. MERCURY EMISSIONS REDUCTIONS 

2. In 2006, the State of Illinois adopted regulations pertaining to mercury emissions. 

Thereafter in 2007, the Ameren MPS Group elected to comply with the state's mercury 

regulation by opting into an alternative compliance mechanism called the Multi Pollution 

Standard ("MPS"). By enrolling in the MPS, sources agreed to specified reductions in NOx and 

S02 emissions in exchange for deferring until 2015 compliance with mandatory emission 

standards. The Ameren MPS Group opted all of its twenty-one coal-fired steam generating units 

located at seven power stations throughout the state into the MPS. On a system-wide basis those 

units are required to meet enumerated declining emission rates for NOx and S02• 

' ' 
3. AER sought to delay the implementation dates for two of the S02 annual emission 

rates of the MPS. Specifically, AER sought a variance from the Illinois Pollution Control Board 

("Board") to defer compliance with the MPS 2015 S02 annual emission rate of 0.25 pounds per 

million British thermal units ("lbs/mmBtu"), and the 2017 S02 annual emission rate of 0.23 

lbs/mmBtu. 35 Ill. Adm. Code 225.233(e)(3)(C)(iii) and (iv). It is important to note that AER 

did not seek a change to either the NOx limits or the mercury requirements. 

4. The Board granted AER a variance on September 20, 2012. The Board-issued 

variance also did not grant any changes to the MPS NOx emission limits or mercury 

requirements. AER has taken additional steps since the date of the Board opinion and order to 

reduce mercury emissions from the fleet beyond what is required by the MPS. AER early 

elected five EGUs to meet the 0.008 lb/GWh mercury emission limit in 2013. Those EGUs 

include: Coffeen Units 1 and 2 beginning February 1, 2013, Newton Units 1 and 2 beginning 

April 1, 2013, and E.D. Edwards Unit 3, beginning July 1, 2013. Moreover, Duck Creek and 

Joppa Units 1 through 6 have qualified as "Low Mass Emitting" units by demonstrating that 

potential mercury emissions are de minimis ( <29 lbs/year). 

5. AER's voluntary early mercury reductions resulted in compliance with the MPS 

requirements (35 Ill. Adm. Code 225.233(d)(1)) a year to a year and a half earlier than the 

January 1, 2015 date required under the rule. 

Further affiant sayeth not. 

Steven C. Whitworth 

Subscribed and sworn to before me 

~ this~ day of July, 2013. 
EXHIBIT 14

NEWTON FGD CONSTRUCTION PERMIT 
ILLINOIS ENVIRONMENTAL PROTECTION AGENCY 

1021 NORTH GRAND AvENue EAST, P.O. Box 19506, SPRINGFIELO, IlliNOIS 62794-9506- ( 21 7) 782-2113 

PAT QUINN, CovEgNoK DOUGLAS P. SCOTT. DIRE< T< >R 

2 17/782-2113 

PERMITTEE 

CONSTRUCTION PERMIT 

NSPS AND NESHAP SOURCE 

Ameren Energy Generating Company 

Attn: Michael L. Menne, Vice President 

1901 Chouteau Avenue 

St. Louis, Missouri 63103 

Application No.: 10070051 I. D. No.: 079808AAA 

Applicant's Designation: NEWTONFGD Date Received: July 23, 2010 

Subject: Addition of Flue Gas Desulfurization Systems 

Date Issued: December 20, 2010 

Location : 6725 North SOOth Street, Newton, Jasper County 

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

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

addition of two flue gas desulfurization {FGD) systems, one each for the 

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

This permit is subject to standard conditions attached hereto and the 

following special conditions: 

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

1.1 Introduction 

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

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

order to comply with future environmental requirements. 

b. This permit also authorizes construction of the following 

equipment and facilities as part of this project: 

• Two new induced draft fans for each unit (four total) . 

• A single new chimney with separate flues for each unit . 

• A limestone handling facility for the pulverized limestone 

for the FGD systems. 

• A gypsum handling facility for the gypsum material from the 

FGD systems. 

• A diesel engine-generator to provide emergency electrical 

power for the FGD systems. 

1 . 2 Non-Applicability Provisions 

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

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

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

increase emissions of other pollutants from these Units. 

PRINTED ON RECYCLED PAPER 
Page 2 

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

facilities associated with the FGD systems, as constrained by the 

limitations and requirements in this permit, not being a major 

modification for purposes of the federal PSD rules. This is 

because the increases in emissions of individual PSD pollutants 

from these units are less than the significant emission rates set 

in the PSD rules. 

1.3 Other Applicable Requirements 

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

Units NB-1 and NB-2 and associated control equipment, including 

requirements in existing permits for the source, including 

provisions for stC~:rtup , malfunction and breakdown, recordkeeping, 

and reporting . 

b. This permit does not relieve the Permittee of the responsibility 

to comply with all Local, State and Federal Regulations that are 

part of the applicable Illinois State Implementation Plan, as 

well as all other applicable Federal, State and Local 

requirements. In particular, this permit does not excuse the 

Permittee from the obligation to undertake further actions at or 

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

or contribute to violations of National Ambient Air Quality 

Standards, including accepting additional limits on the emissions 

of Units NB-1 and NB-2 and other emission units at the source, 

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

their existing control equipment, or the control equipment or 

control measures for other emission units at the source to assure 

compliance with such limits, and/or enhancing dispersion of 

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

1.4. Control Practices 

a. Each FGD system shall be equipped with a high efficiency mist 

eliminator to minimize entrained scrubbant carryover. 

b. At all times, the Permittee shall, to the extent practicable, 

maintain and operate Units NB-1 and NB-2 with new C'Gl> systems in 

a manner consistent with good air pollution control practice for 

minimizing emissions. 

1.5 Emissions Testing Requirements 

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

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

both filterable and condensable, from the unit shall be measured 

by an approved testing service while the unit is operating in the 

maximum load range and other representative operating conditions. 

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

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

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

for USEPA test methods. 

Location of Sample Points 

Gas Flow & Velocity 

Particulate Matter 

Condensable Particulate Matter 

USEPA Method 1 

USEPA Method 2 

USEPA Method 5 

USEPA Method 202 

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

Office and Source Emission Test Specialist shall be notified a 

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

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

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

Agency to witness these tests. 

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

submitted to the Illinois EPA within 14 days after the test 

results are compiled and finalized. The following information 

shall be submitted with the results: 

i. The gross power generation and the steam generation rate 

for the unit during the test. 

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

absorber pH levels, scrubber slurry density, scrubbant 

circulation rate, limestone slurry makeup rate and slurry 

bleed rate, as measured during the tests. 

iii. S02 emission data during the periods of testing based on 

emission monitoring, and the calculated S02 control 

efficiency on a daily basis. 

iv. Opacity data collected by the continuous opacity monitoring 

systems during each test run and if conditions are suitable 

for such observation, observations of opacity at the stack 

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

1.6 Recordkeeping Requirements 

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

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

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

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

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

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

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

inspection. 

1.7 Notifications 

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

of the initial startup of each FGD system. 
Page 4 

1.8 Reporting Requirements 

If there is a deviation from the requirements of this permit, the 

Permittee shall promptly report the deviation to the Illinois EPA. 

Unless otherwise specified, this report shall be submitted within 30 

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

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

any actions to prevent future occurrences. 

1 . 9 Report/Notifications Submittals 

Two copies of all reports and notifications required by this permit 

shall be sent to: 

Illinois Environmental Protection Agency 

Division of Air Pollution Control 

Compliance Section (#40) 

P.O. Box 19276 

Springfield, Illinois 62794-9276 

Telephone: 217/782-5811 Fax: 217/782-6348 

and one copy shall be sent to the Illinois EPA's regional office at the 

following address unless otherwise indicated: 

Illinois Environmental Protection Agency 

Division of Air Pollution Control 

2009 Mall Street 

Collinsville, Illinois 62234 

Telephone: 618/ 346-5120 Fax: 618/346-5155 

1.10 Authorization for Operation 

a. i. Units NB-1 and NB-2 with FGD systems each may operate for 

up to one year under this permit during which period 

shakedown and emissions testing shall be completed. 

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

up to an additional 365 days upon written request by the 

Permittee as needed to reasonably accommodate difficulties 

that are encountered in the shakedown and emissions testing 

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

b . Following completion of required emissions t e sting, the Permittee 

is allowed to operate Units NB-1 and NB-2 with FGD systems under 

this permit until the operation of the FGD systems is addressed 

by a CAAPP permit. 

c. These conditions supersede Standard Condition 6. 
Page 5 

Unit-specific Conditions for the New Material Handling Facilities 

2.0 Introduct"ion 

The affected facilities for the purpose of these Unit-Specific 

Conditions are the new facility for handling limestone for the new FGD 

systems and the new facility for handling the "gypsum" (sludge or spent 

material) from these FGD systems. 

2.1 Applicable Emission Standards 

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

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

by an observer looking generally toward the zenith (that is 

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

property line of the source pursuant to 35 IAC 212.301. 

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

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

atmosphere from an affected facility, pursuant to 35 IAC 

212 .123 (a) . 

c. The process emission units in the affected facilities shall 

comply with 35 IAC 212.321(a), which provides that no person 

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

hour period from any new process emission unit which, either 

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

similar process emission units at a source or premises, exceeds 

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

2.2 Non-Applicability Provisions 

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

facility not being subject to the federal New Source Performance 

Standards (NSPS} for Nonmetallic Mineral Processing Plants, 40 

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

limestone so that it does not constitute a nonmetallic mineral 

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

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

facility not being subject to the NSPS, 40 CFR 60 Subpart ooo 

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

constitute a nonmetallic mineral processing plant for gypsum. 

2.3 Operational Limitations 

a. The amount of limestone received by the affected limestone 

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

Compliance with this limit and other annual limits set by this 

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

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

the data for the preceding 11 months. 
Page 6 

2.4 a. 

b. 

i . 

i i. 

i. 

A. There shall be no visible PM emissions from the 

affected limestone handling facility. 

B. The filters for affected limestone handling facility 

shall have a design outlet loading for PM of no more 

than 0.02 grains/scf, as shown by the manufacturer's 

performance specifications for the device or 

representative emission test data for similar filter 

devices. 

A. The total stack emissions of PM and PMlO from the 

limestone silos (bin vent filters) shall both not 

exceed 0.85 tons per year. This limi.t for PMlO 

emissions, and other limits for PMlO emissions set in 

this permit, shall only apply to filterable emissions 

of PMlO, as would be measured in accordance with 35 

IAC 212.108(a). 

B . Other than stack emissions from the limestone silos, 

as addressed above, this permit is issued based upon 

negligible emissions of particulate from the affected 

limestone handling facility. For this purpose, 

emissions of PM and PMlO from the affected facility, 

other than from the limestone silos, shall each not 

exceed 0.44 tons per year. 

Gypsum material shall only be mechanically de-watered, 

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

material. 

ii. The particulate emissions from the affected gypsum handling 

facility, including both stack and fugitive emissions, 

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

respectively. These limits are based on the information in 

the application, including the projected maximum throughput 

of de-watered material per year, a nominal 15 percent 

moisture content for de-watered material, and appropriate 

USEPA AP-42 emission factors for handling wet material. 

c. At all times, the Permittee shall maintain and operate the 

affected limestone and gypsum handling facilities, including 

associated air pollution control measures, in a manner consistent 

with good air pollution control practices for minimizing 

emissions. 

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

shall be on paved roads that are maintained in good 

condition to control PM emissions. 

B. The transport of the gypsum on roads at the source 

shall either be on paved roads that are maintained in 
Page 7 

ii. A. 

good condition to control PM emissions or on roads 

that are treated with wet suppression to achieve at 

least a nominal 85 percent control for PM emissions. 

The PM and PM10 emissions from transport of gypsum on 

roads at the source shall not exceed 10.0 and 2.5 

tons/year, respectively. 

B. This permit is issued based upon negligible emissions 

of particulate from transport of limestone on roads 

at the source. For this purpose, emissions of PM and 

PMlO shall each not exceed 0.44 tons per year. 

2.5 Inspection and Maintenance Requirements 

a. Inspections of the affected limestone and gypsum handling 

facilities including emission control measures shall be conducted 

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

confirm compliance with the requirements of this permit. 

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

measures shall be performed to assure that such measures function 

properly when material is being handled. 

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

maintenance/repair activity in an operating and maintenance log 

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

date, time and description of the inspections or 

maintenance/repair activities. 

2.6 Opacity Measurements 

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

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

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

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

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

2.7 Recordkeeping Requirements 

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

Permittee shall maintain a file containing documentation for 

guaranteed PM emission rate, in gr/dscf, as provided by the 

supplier of the device. 

b. The Permittee shall maintain operating records for the following 

items for the affected facilities: 

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

ii. Amount of limestone transferred to the FGD systems, 

tons/month and tons/year. 
Page 8 

iii. Amount of gypsum handled, tons/month and tons/year. 

c. The Permittee shall keep records for the implementation of 

fugitive dust control measures on roadways used by trucks that 

handle limestone and gypsum. 

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

PMlO emissions (tons/month and tons/year), with supporting 

calculations: 

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

limestone handling facility. 

ii. Records of emissions from the gypsum handling facility. 

iii. Records of emissions from roadways at the source from 

transport of gypsum. 

2.8 The limestone and gypsum handling facilities may be operated pursuant 

to this construction permit until an operating permit becomes effective 

that addresses operation of these facilities. This condition supersedes 

Standard Condition 6. 

Unit-Specific Conditions for the Emergency Engine Generator 

3.1 Introduction 

One new diesel-fired reciprocating internal combustion engine-generator 

(the affected engine) will be installed at the source to provide 

electricity to the FGD systems on a temporary basis during 

interruptions or outages of the normal power supply. The affected 

engine would also be operated for maintenance and readiness checks. 

3.2 Applicable Emission Standards 

a. i. The affected engine is subject to the NSPS for Stationary 

Compression Ignition Internal Combustion Engines, 40 CFR 

60, Subpart IIII. The Permittee must comply with applicable 

requirements of the NSPS, 40 CFR 60 Subpart IIII, and 

related requirements of 40 CFR 60, Subpart A, General 

Provisions, for the affected engine. 

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

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

later emergency engines with a displacement of less than 30 

liters per cylinder so that the engine is subject to and 

shall comply with the applicable emission standards in 40 

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

iii. The Permittee shall operate and maintain the affected 

engine according to the manufacturer's written instructions 
Page 9 

b. 

c. 

or procedures developed by the Permittee that are approved 

by the engine manufacturer, pursuant to 40 CFR 60.4211{a). 

The Permittee shall also meet any applicable requirements 

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

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

that meets the requirements of 40 CFR 80.510, pursuant to 

40 CFR 60.4207. 

v. The Permittee shall demonstrate compliance with the NSPS 

emission standards for the affected engine in accordance 

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

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

affected engine must be installed and configured according 

to the manufacturer's specifications. 

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

by 40 CFR 60.4209(a}. 

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

being equipped with a diesel particulate filter, so that 

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

for such devices do not apply. 

i. The affected engine is subject to the federal National 

Emission Standards for Hazardous Air Pollutants (NESHAP) 

for Stationary Compression Ignition Internal Combustion 

Engines. The Permittee must comply with applicable 

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

related requirements of 40 CFR 63, Subpart A, General 

Provisions, for the affected engine. 

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

subject to limited requirements of the NESHAP for emergency 

engines, which consist of the initial notification 

requirements as described in 40 CFR 63.6645{f}, because the 

affected engine is a new emergency engine pursuant to 40 

CFR 63 . 6590(b) (1) (i). 

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

affected engine shall not exceed an opacity greater than 30 

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

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

ii. Subject to the following terms and conditions, the 

Permittee is authorized to continue operation of the 

affected engine in violation of the applicable opacity 

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

or breakdown of the engine. This authorization is provided 

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

Permittee has applied for such authorization in its 
Page 10 

application, generally explaining why such continued 

operation would be required to prevent severe damage to 

equipment, and describing the measures that will be taken 

to minimize emissions from any malfunctions and breakdowns. 

A. This authorization only allows such continued 

operation as necessary to provide essential service 

or to prevent injury to personnel or severe damage to 

equipment and does not extend to continued operation 

solely for the economic benefit of the Permittee. 

B. Upon occurrence of excess emissions due to 

malfunction or breakdown, the Permittee shall as soon 

as pr~cticable restore normal power to the FGD 

systems or complete the shutdown of Units NB-1 and 

NB-2 or undertake other action so that excess 

emissions cease. 

C. The Permittee shall fulfill applicable recordkeeping 

and reporting requirements of Conditions 3.8(c) and 

3. 9 . 

D. If the Permittee continues to operate the affected 

engine with excess emissions during malfunction or 

breakdown for purposes that are not related to 

providing emergency power to the FGD systems, the 

Permittee shall immediately notify the Illinois EPA's 

Regional Office, by telephone, facsimile or e-mail 

for each incident in which the opacity from engine 

exceeds or may have exceeded 30 percent for more than 

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

has begun the shutdown of the engine by such time. 

Following this notification to the Illinois EPA of a 

malfunction or breakdown with excess emissions, the 

Permittee shall comply with all reasonable directives 

of the Illinois EPA with respect to such incident, 

pursuant to 35 IAC 201.263. (Otherwise, if opacity 

during an incident only exceeds or may have exceeded 

30 percent for less than one hour, the Permittee need 

only report the incident in the periodic compliance 

report for Units NB-1 and NB-2.) 

E. This authorization does not relieve the Permittee 

from the continuing obligation to minimize excess 

emissions during malfunction or breakdown 

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

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

3.3 Non-Applicability Provisions 
Page 11 

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

subject to the requirements of the federal Acid Rain Program 

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

72.6.) Accordingly, electricity generated by the affected engine 

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

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

subject to the requirements of 35 IAC Part 212, Subpart L, 

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

such unit, so that these rules cannot reasonably be applied, 

pursuant to 35 IAC 212.323. 

3.4 Operational Limitations 

a. The rated output of the affected engine shall not exceed 1250 KW. 

b. The affected engine shall not be operated for any purpose other 

than emergency operation and maintenance and operational testing, 

pursuant to 40 CFR 60.4211(e). 

c. i. Operation of the affected engine shall not exceed 500 

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

Illinois EPA may authorize temporary operation of the 

engine in excess of 500 hours per year to address 

extraordinary circumstances that require operation of this 

device, by issuance of a separate State construction permit 

addressing such circumstances. 

ii. The operation of the affected engine for maintenance and 

readiness checks shall be limited to 100 hours per calendar 

year so that the engine qualifies as an emergency engine 

for purposes of the NSPS. 

3.5 Emission Limitations 

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

limitations. Compliance with these annual limitations shall be 

determined from a running total of 12 months of data. 

Pollutant Lbs/Hour1 Tons/Year2 

NO'- 18.6 4.7 

co 2.8 0.7 

The hourly limitations for NOx and CO are based on emission 

data from the manufacturer of the engine calculated using 

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

provided in the application. The S02 emission limitation is 

based on fuel sulfur specifications, pursuant to 40 CFR 

80.510 (a) (2). 
Page 12 

b. 

The annual limitations are based on operation of the. 

affected engine for 500 hours per year at the hourly 

emission rate limit. 

This permit is issued based on negligible emissions 

and VOM from the affected engine. For this purpose, 

802 and PM/PM10 shall not each exceed 0.1 tons/year. 

VOM shall not exceed 0.2 tons/year. 

of 802 , PM/PM10 

emissions of 

Emissions of 

3.6 Opacity Measurements 

a. Upon written request by the Illinois EPA, the Permittee shall 

have the opacity of the exhaust from the affected engine during 

representative operating conditions determined by a qualified 

observer in accordance with USEPA Method 9, as further specified 

below. These observations shall be conducted within 45 calendar 

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

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

EPA, whichever is latest. 

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

in advance of the date and time of testing, in order to 

allow the Illinois EPA to witness testing. This 

notification shall include the name and employer of the 

observer(s) and identify any concerns for successful 

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

for proper observation or inability to conduct observations 

under specified operating conditions. 

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

changes in the date or time of testing. 

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

the Illinois EPA at the time of testing, if Illinois EPA 

personnel are present. 

d . The Permittee shall submit a written report for these 

observations within 15 days of the date of observation. This 

report shall include: 

i. Date and time of testing. 

ii. Name and employer of qualified observer. 

iii. Copy of current certification. 

iv. Description of observation conditions. 

v. Description of engine operating conditions. 

vi. Raw data . 
Page 13 

vii. Opacity determinations. 

viii. Conclusions. 

3.7 Emission Testing Requirements 

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

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

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

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

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

60.4212. 

3.8 Recordkeeping Requirements 

a. The Permittee shall fulfill applicable recordkeeping requirements 

of the NSPS for the affected engine. 

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

the affected engine: 

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

the affected engine's model year, maximum engine 

capacity, manufacturer's certification of compliance 

with 40 CFR Part 89 or Part 1039, and associated 

emission factors. 

B. Data for the maximum hourly emission rates {lb/hour) 

from the affected engine, with supporting 

calculations. 

ii. An operating log or other operating records, which shall 

include the following information: 

A. Information for each time the engine is operated, 

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

exercise or emergency need), in accordance with 40 

CFR 60.4214{b). 

B. Information for any incident in which the operation 

of the engine continued during malfunction or 

breakdown, including: date, time, and duration; a 

description of the incident; whether emissions 

exceeded or may have exceeded any applicable 

standard; a description of the corrective actions 

taken to reduce emissions and the duration of the 

incident; and a description of the preventative 

actions taken. 

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

activity performed with date. 
Page 14 

iv. The following operating records: 

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

maximum sulfur content. 

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

and hours/year) . 

v. Records of NO~ and CO emissions {tons/month and tons/year), 

with supporting calculations. 

vi. Records for opacity observations made in accordance with 

USEPA Method 9 for the affected engine that it conducts or 

that are conducted on its behest by individuals who are 

qualified to make such observations. For each occasion on 

which such observations are made, these records shall 

include the identity of the observer, a description of the 

various observations that were made, the observed opacity, 

and copies of the raw data sheets for the observations. 

c . Pursuant to 35 IAC 201.263, the Permittee shall maintain the 

following records related to malfunction and breakdown of the 

affected engine: 

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

at a minimum, address aspects or components of the engine 

for which malfunction or breakdown has resulted in excess 

emissions, which shall list the activities performed on 

such aspects or components, with date and description. 

ii. Records for each incident when operation of the affected 

engine continued with excess opacity, including malfunction 

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

a minimum, include the following information: 

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

including actions taken to reduce the duration of the 

inci.dent. 

B. If opacity exceeded the applicable standard for more 

than 60 minutes during the incident: 

1. A detailed explanation why continued operation 

of the affected engine was necessary. 

2. The preventative measures that have been or 

will be taken to prevent similar incidents, 

including any repairs to the affected engine 

and associated equipment and any changes to 

operating and maintenance procedures. 
- • • 1' 

Page 15 

3.9 Reporting Requirements 

a. The Permittee shall fulfill applicable notification and reporting 

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

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

the affected engine, the Permittee shall report the deviation 

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

(See also Condition 1.8.) 

3 . 10 Authorization for Operation 

The affected engine may be operated pursuant to this construction 

permit until an operating permit becomes effective that addresses this 

engine. This condition supersedes Standard Condition 6. 

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

217/782-2113. 

Edwin C. Bakowski, P.E. 

Manager, Permit Section 

Division of Air Pollution Control 

ECB: SRS: jws 

cc: Illinois EPA, Region 3 

,, 

Date Signed: 
July 1, 1985 

STATE OF ILLINOIS 

ENVIRONMENTAL PROTECTION AGENCY 

DIVISION OF AIR POLLUTION CONTROL 

P. 0. BOX 19506 

SPRINGFIELD, ILLINOIS 62794-9505 

STANDARD CONDITIONS FOR CONSTRUCTION/DEVELOPMENT PERMITS 

ISSUED BY THE ILLINOIS ENVIRONMENTAL PROTECTION 'AGENCY 

.L 

The Illinois Environmental Protection Act (Illinois Revised Statutes, Chapter 111-1/2, Section 1039) authorizes the 

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

The following conditions are applicable unless susperseded by special condition(s). 

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

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

st~rted by such time. 

. ' 

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

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

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

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

written permit issued. · . ·· 

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

reasonable times: 

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

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

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

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

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

permit, · 

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

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

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

5. The issuance of this permit: 

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

facilities are to be locateC.l, 

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

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

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

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

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

!L 532.,.0226 

APC 166 Rev. 5/99 Printed on Recycled Pllper 090-00S 
e. in no manner implies or suggests that the Agency (or ita officers, agents or employees) assumes any liability, 

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

equipment or facility. · 

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

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

b. For purposes of shakedown a·nd testing, unless otherwise specified by a special permit condition, the equipment covered under· this permit may be operated for a period not to ex~eed thirty (30) days. 

7. The Agency may file a complaint with the Board for modification, suspension or revocation of a permit: 

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

or that all relevant facts were not disclosed, or 

b. upon finding that any standard or spechil conditions h~ve been violated, or 

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

the construction or development authorized by this permit. 
..... ~~- .. .... ...,, •• u ... t~ ''"- '1\lo.tl L-V l "" "-' ll IIVr..IIVI 

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Por 'assistance in preparin'g a permit· 

·a'pp1ication contact the Permit 

Section! 

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

Permit ·Ser:.tion · 

· 1.021 N. Grand Ave E. 

· P.=-O~n9x· 19506· .: .. _ ·: ~ 

.Springfield, Illinois . 62794-9506 · 

Illinois EP.A · · 

Region '1· Bureau 6~ air.; FOS 

9511 West·Harrison . ·Des. Plaines, Illinois .. 60016 

847/294-4000 

Illinois EPA 

Region 2· · . . 5415. North · UniversitJ. 

.Peoria, Illinois .61614:. · J 309/693-5463' . . . ' 

IJlinois EPA : 

Region 3 

2009 Mall· Street . . 

Collinsville, Illinois 

6l8/34f}...:ji20 

6223'4 

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