Wolverine Power Supply Cooperative, Inc. 

RESPONSE TO COMMENTS DOCUMENT 

June 29, 2011 

PERMIT No. 317-07 

Rick Snyder, Governor 

Air Quality Division 

Michigan Department of Environmental Quality 

INTERNET: http://www.michigan.gov/air 

G. Vinson Hellwig, Chief 

Air Quality Division 

Constitution Hall, 3rd Floor 

525 West Allegan Street

P.O. Box 30260 

Lansing, Michigan 48909-7760 

Phone: (517) 373-7023 

Fax: (517) 373-1265
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 1 of 140 

June 29, 2011 

Table of Contents 

Section Page 

Public Participation Process ................................................................................................................ 3

Summary of Comments Resulting in Changes to the Permit...............................................................4

Summary of Significant Comments.................................................................................................... 17

A. Alternatives Analysis .................................................................................................................... 17

B. MEPA/Rule 901............................................................................................................................ 22

C. Public Health and Environment Concerns....................................................................................26

1. Comments on Environmental Justice Concerns ...........................................................................41

D. Dispersion Modeling..................................................................................................................... 43

E. Maximum Achievable Control Technology (MACT) Review......................................................... 53

F. Best Available Control Technology (BACT) Review .....................................................................71

1. IGCC ............................................................................................................................................. 71

2. Clean Fuels................................................................................................................................... 72

3. Opacity.......................................................................................................................................... 80

4. PM2.5............................................................................................................................................ 80

5. PM10............................................................................................................................................. 82

6. NOx............................................................................................................................................... 84

7. SO2............................................................................................................................................... 87

8. CO/VOC......................................................................................................................................... 93

9. Greenhouse Gases (GHG) ........................................................................................................... 95

G. Material Handling ....................................................................................................................... 114

H. Ancillary Equipment.................................................................................................................... 118

I. Control Equipment ....................................................................................................................... 120

J. Start-up and Shut-down Emissions............................................................................................. 121

K. Annual Emissions....................................................................................................................... 122
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L. Monitoring ................................................................................................................................... 125

M. Compliance Testing ................................................................................................................... 128

N. Enforcement ............................................................................................................................... 129

O. Rules and Regulations ............................................................................................................... 131

P. Malfunction Abatement Plan (MAP) ...........................................................................................132

Q. Emergencies and Safety Concerns............................................................................................133

R. Public Participation Process....................................................................................................... 134

S. Miscellaneous............................................................................................................................. 136

T. Other Comments Received – Not Regulated by the AQD..........................................................140
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I. PUBLIC PARTICIPATION PROCESS 

Wolverine Power Supply Cooperative, Inc’s (Wolverine) Permit to Install application No. 

317-07 is for the proposed installation and operation of a 600 megawatt (MW) (net) solid 

fuel-fired power plant, which will be located in the existing Carmeuse quarry (formerly 

Oglebay Norton) property, directly south of Rogers City, Michigan. The public 

participation process involved providing information for public review including fact 

sheets, technical summaries, proposed permit terms and conditions; several public 

comment periods, informational meetings, and public hearings were held; and the 

receipt of written and verbal public comments on staff’s analysis of the application and 

the proposed permit. 

On September 23, 2008, copies of the Notice of Air Pollution Comment Period and 

Public Hearing, the Fact Sheet, the Technical Summary, and the draft terms and 

conditions were placed on the Internet at the Michigan Department of Environmental 

Quality (MDEQ), Air Quality Division’s (AQD) Home Page 

(http://www.michigan.gov/deq). Also, the AQD mailed postcards to persons who had 

previously expressed interest and had provided a complete mailing or email address. In 

addition, a notice announcing each Public Comment Period, Public Informational 

Meeting, and Public Hearing was placed in The Alpena News and the Presque Isle 

Advance. The notice provided pertinent information regarding the proposed action; the 

locations of available information; a telephone number to request additional information; 

the date, time, and location of the Public Informational Meeting and Public Hearing; the 

closing date of the Public Comment Period; and the address where written comments 

were being received. 

Since October 1, 2008, two (2) panel informational sessions and five (5) public hearings 

have been held regarding the Permit to Install application for the proposed project. 

On May 21, 2010, the MDEQ denied the Permit to Install application, due to a failure to 

demonstrate need for the proposed facility. Wolverine Power challenged that decision 

and in the Order dated January 28, 2011, the Missaukee County Circuit Court ruled that 

the alleged lack of need for the proposed project alone, separate from air quality 

concerns, was not a legal basis to deny the application. The court remanded it back to 

the MDEQ for further consideration and requiring them to make a decision. This 

informational meeting and hearing are in response to that remand, taking into account 

new regulations that became effective since the denial action. These regulations are the 

new 1-hour National Ambient Air Quality Standards for nitrogen dioxide and sulfur 

dioxide and the requirement to provide a BACT demonstration for greenhouse gases. 

Approximately 4500 written comments were received during the Public Comment 

Periods and the hearings. 

The remainder of this document is a listing of the significant comments received during 

the public comment period and hearing regarding the proposed permit and the 

Department’s response. The first section discusses the comments received that 

resulted in changes to the final permit terms and conditions and the basis for each 
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change. The last section discusses the Department’s response to all other significant 

comments that did not result in changes to the final permit. 

This Response to Comments document fulfills the requirements specified in 

40 CFR 124.17. 

II. SUMMARY OF COMMENTS RESULTING IN CHANGES TO THE PERMIT 

There are a significant number of changes to the permit. Many of the changes address 

issues raised in the public comments. Other changes were made because of modifications 

to the applicable rules and regulations or by MDEQ to clarify enforceability of the applicable 

requirements. Some permit condition changes are simply corrections of unintentional errors. 

Except for the first few changes listed, the changes listed on the following pages will follow 

the order of conditions in the permit within each grouping. Condition changes made in 

response to comments are identified, and the section of this document where a more 

detailed response can be located is listed for each of those changes. 

Common Abbreviations / Acronyms 

Changes:

Page 3: MDEQ added the following abbreviations: SC = Special Condition; 

and PM2.5 = PM less than or equal to a nominal 2.5 micrometers, in diameter 

Page 3: MDEQ changed the following abbreviation: PM10 = PM less than or equal to a 

nominal 10 micrometers, in diameter 

General Conditions 

Changes:

Page 4: MDEQ revised General Condition No. 5 due to a 2007 rule change. General 

Condition 5 now reads: 

 “The terms and conditions of this Permit to Install shall apply to any person or legal 

 entity that now or hereafter owns or operates the process or process equipment at 

 the location authorized by this Permit to Install. If the new owner or operator submits

 a written request to the Department pursuant to R 336.1219 and the Department 

 approves the request, this permit will be amended to reflect the change of ownership 

 or operational control. The request must include all of the information required by 

 subrules (1)(a), (b), and (c) of R 336.1219 and shall be sent to the District 

 Supervisor, Air Quality Division, Michigan Department of Environmental Quality.

(R336.1219)”

Special Conditions 

Entire Document Changes:

Pages 8 - 52: MDEQ removed all footnotes in the Emission Limit tables for each emission 

unit and insert language, “Test protocol will specify averaging time”, in the appropriate cell 

under the Time Period/Operating Scenario column within the table. 

Pages 34 - 52: MDEQ removed all footnotes in the Emission Limit tables for each emission 

unit and insert language, “...calculated on a dry gas basis”, in the appropriate cell under the 

Limit column within the table. 
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Pages 8 - 52: MDEQ added PM 2.5 BACT limits. Emission limits were added for PM2.5 to 

all emission units which have PM10 limits. 

Pages 1 – 53: MDEQ change applicable requirement of R 336.1299(e) to R 336.1299(2)(b). 

There was an error throughout the entire document referencing the applicable requirement 

for adoption of standards by reference for federal MACT requirements. 

Pages 1 – 53: MDEQ added the following applicable requirements to each emission units 

requirement for a Malfunction Abatement Plan (MAP): R 336.1331, R 336.1910, 

R 336.1911, R 336.2803, R 336.2804, R 336.2810, 40 CFR 52.21 (c), (d), & (j) 

EUAUXBOILER 

Condition Change: 

Page 8: (Emission Limit Column for SC I.2, 1.3, and 1.6) MDEQ changed “lb/hr” to “pph”, to 

keep consistency throughout the document. Both units refer to the same meaning of pounds 

per hour. 

Condition Change: 

Page 8: (SC I.8) MDEQ defined HCl as “Hydrogen Chloride” in the Emission Limit Table, 

Pollutant column. 

Comment:

Particulate matter limits for EUAUXBOILER does not include condensable fraction. Draft 

permit does not include complete particulate matter BACT limits for EUAUXBOILER. 

Response: 

Potential particulate matter, of all forms, from the distillate oil-fired equipment is expected to 

be very low, since the equipment will have limited use. However, PM2.5 emission limits 

representing BACT have been added to the auxiliary boiler. 

Condition Change: 

Page 8: (Added SC I.4 and Renumbered Emission Limit Table) MDEQ added a PM2.5 

emission limit representing BACT for EUAUXBOILER. 

Comment: 

Proposed EUAUXBOILER BACT emission limits for PM, PM10, NOx, CO, VOC and HCL 

exclude periods of startup and shutdown; permit does not define startup and shutdown, or 

contain recordkeeping or reporting requirements for startup and shutdown. 

Response:

MDEQ agrees with the commenter, that BACT emission limits should not be excluded during 

periods of startup and shutdown. Also, the MDEQ agrees with the commenter that the draft 

permit does not define startup and shutdown. However, MDEQ does not believe it is 

necessary to define startup and shutdown when there is not a way to measure continuous 

heat input to the boiler. When the boiler emissions were reviewed it was determined that 

BACT, for a small boiler (less than 100 MMBtu/hr) burning ultra low sulfur fuel and limited 

operation, did not include continuous emission monitors which would measure heat input. 

Therefore, MDEQ changed previously proposed lb/MMBtu limits to lb/hour limits based on 
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the maximum heat input of EUAUXBOILER and deleted all exclusions for startups and 

shutdowns from the limits. MDEQ also added a special condition which minimizes emissions 

during startup and shutdown. 

Condition Change: 

Page 8: (SC I.1 through I.8) MDEQ changed previously proposed lb/MMBtu emission limits 

to lb/hr limits for PM, VOC, and HCL. The limits for the pollutants were changed as follows: 

Pollutant Current Limit 

(lb/MMBtu) 

Proposed Limit 

(lb/hr) 

PM 0.0015 0.11 

VOC 0.0042 0.30 

HCL 0.0007 0.050 

Condition Change: 

Page 9: (Added SC III.4) MDEQ added a special condition to the Process/Operational 

Restrictions to minimize excess emissions during startup and shutdown. The condition reads 

as follows: 

 “The permittee shall not operate EUAUXBOILER unless an acceptable plan that 

 describes how emissions will be minimized during all startups and shutdowns has 

 been submitted to the AQD District Supervisor. The plan shall incorporate 

 procedures recommended by the equipment manufacturer as well as incorporating 

 standard industry practices and good combustion control. (R 336.1911, R 336.1912, 

 R 336.2802, 40 CFR 52.21)” 

Comment: 

The proposed EUAUXBOILER emission limits do not contain limits for sulfur dioxide. There 

should also be appropriate monitoring, recordkeeping and reporting requirements. 

Response: 

The proposed draft permit does not include emission limits for sulfur dioxide. However, it 

does include material limits for the sulfur content in the fuel, required by the NSPS. Also, 

there are monitoring and recordkeeping requirements for fuel supplier certification records. 

When the auxiliary boiler emissions were reviewed it was determined that BACT, for a small 

boiler (less than 100 MMBtu/hr) burning fuel oil with a low sulfur content and limited 

operation, was to limit only the sulfur content of the fuel since that is a limit which is more 

enforceable as practical manner. The fuel oil company is required to do an analysis of the 

fuel and to certify it. This allows more frequent monitoring and recordkeeping of the fuel 

which is burned. 

Condition Change: 

Page 9: (SC II.1) MDEQ deleted from the beginning of SC II.1: “After the year 2010”. That 

statement refers to the sulfur content in the fuel if the boiler were to be operating before the 

year 2010. 

Condition Change: 

Page 11: (Added SC IX.1) MDEQ added special condition to ensure the permittee follows all 

federal New Source Performance Standards. The condition reads as follows: 

 
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 “The permittee shall comply with all provisions of the federal Standards of 

 Performance for New Stationary Sources as specified in 40 CFR Part 60 Subparts A 

 and Dc, as they apply to EUAUXBOILER. (40 CFR Part 60 Subparts A & Dc)”

EUEMGGEN 

Comment:

The particulate matter limits for EUEMGGEN does not include condensable fraction. Draft 

permit does not include complete particulate matter BACT limits for EUEMGGEN. 

Response: 

Potential particulate matter, of all forms, from the distillate oil-fired equipment is expected to 

be very low, since the equipment will have limited use. However, PM10 and PM2.5 emission 

limits, which include the condensable fraction, representing BACT have been added to the 

emergency generator. 

Condition Change: 

Page12: (Renumbered Emission Limits and Added SC I.2, I.3, 1.8, and 1.9) MDEQ added 

PM10 and PM2.5 emission limits representing BACT for EUEMGGEN. 

Condition Change: 

Page 13: (SC II.1) MDEQ deleted reference to the sulfur content of diesel fuel used prior to 

October 2010. The condition now reads as follows: 

 “The permittee shall only burn diesel fuel, in EUEMGGEN, with a maximum sulfur 

 content of 15 ppm per gallon, and a minimum centane index of 40; or a maximum 

 aromatic content of 35 percent by volume. (40 CFR 60.4207(b))” 

Comment: 

Proposed draft conditions for EUEMGGEN do not define startup and shutdown, or contain 

recordkeeping or reporting requirements for startup and shutdown. 

Response: 

MDEQ agrees emissions should be minimized during startup and shutdown. However, 

MDEQ does not believe it is necessary to define startup and shutdown when there is not a 

way to measure continuous heat input to the generator. Emergency generators are 

expected to run no more than 500 hours per year which includes startup and shutdown. 

Condition Change: 

Page 14: (Added SC III.6) MDEQ added a special condition to the Process/Operational 

Restrictions to minimize excess emissions during startup and shutdown. The condition reads 

as follows: 

 “The permittee shall not operate EUEMGGEN unless an acceptable plan that 

 describes how emissions will be minimized during all startups and shutdowns has 

 been submitted to the AQD District Supervisor. The plan shall incorporate 

 procedures recommended by the equipment manufacturer as well as 

 incorporating standard industry practices and good combustion control. (R 336.1911, 

 R 336.1912, R 336.2802, 40 CFR 52.21)” 
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Condition Change: 

Page 15: (Added SC IX.1) MDEQ added a special condition to ensure the permittee follows 

all federal New Source Performance Standards. The condition reads as follows: 

 “The permittee shall comply with all provisions of the federal Standards of 

 Performance for New Stationary Sources as specified in 40 CFR Part 60 Subparts A 

 and IIII, as they apply to EUEMGGEN. (40 CFR Part 60 Subparts A & IIII)” 

Condition Change: 

Page 15: (Added SC IX.2) MDEQ added a special condition to ensure the permittee follows 

all National Emission Standards for Hazardous Air Pollutants. The condition reads as 

follows: 

 “The permittee shall comply with all provisions of the National Emission Standards 

 for Hazardous Air Pollutants, as specified in 40 CFR, Part 63, Subpart A and Subpart 

 ZZZZ, for Stationary Reciprocating Internal Combustion Engines, as they apply to 

 EUEMGGEN. (40 CFR, Part 63, Subparts A and ZZZZ)” 

EUFIREPUMP 

Comment:

The particulate matter limits for EUFIREPUMP does not include condensable fraction. The 

draft permit does not include complete particulate matter BACT limits for EUFIREPUMP. 

Response: 

Potential particulate matter, of all forms, from the distillate oil-fired equipment is expected to 

be very low, since the equipment will have limited use. However, PM10 and PM2.5 emission 

limits, which include the condensable fraction, representing BACT have been added to the 

emission limit table for EUFIREPUMP. 

Condition Change: 

Page16: (Added SC l.2 and 1.3 and Renumbered Emission Limit Table) MDEQ added a 

PM10 and PM2.5 emission limit representing BACT for EUFIREPUMP. 

Condition Change: 

Page 16: (SC II.1) MDEQ deleted reference to the sulfur content of diesel fuel used prior to 

October 2010. The condition now reads as follows: 

 “The permittee shall only burn diesel fuel, in EUFIREPUMP, with a maximum sulfur 

 content of 15 ppm per gallon, and a minimum centane index of 40; or a maximum 

 aromatic content of 35 percent by volume. (40 CFR 60.4207(b))” 

Comment: 

The proposed draft conditions for EUFIREPUMP do not define startup and shutdown, or 

contain recordkeeping or reporting requirements for startup and shutdown.

Response: 

MDEQ agrees emissions should be minimized during startup and shutdown. However, 

MDEQ does not believe it is necessary to define startup and shutdown when there is not a 
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way to measure continuous heat input to the engine fire pump. Emergency fire pumps are 

expected to run no more than 500 hours per year which includes startup and shutdown. 

Condition Change: 

Page 17: (Added SC III.6) MDEQ added a special condition to the Process/Operational 

Restrictions to minimize excess emissions during startup and shutdown. The condition reads 

as follows: 

 “The permittee shall not operate EUFIREPUMP unless an acceptable plan that 

 describes how emissions will be minimized during all startups and shutdowns has 

 been submitted to the AQD District Supervisor. The plan shall incorporate 

 procedures recommended by the equipment manufacturer as well as incorporating 

 standard industry practices and good combustion control. (R 336.1911, R 336.1912, 

 R 336.2802, 40 CFR 52.21)”

Condition Change: 

Page 18: (Added SC IX.1) MDEQ added special condition to ensure the permittee follows all 

federal New Source Performance Standards. The condition reads as follows: 

 “The permittee shall comply with all provisions of the federal Standards of 

 Performance for New Stationary Sources as specified in 40 CFR Part 60 Subparts A 

 and IIII, as they apply to EUFIREPUMP. (40 CFR Part 60 Subparts A & IIII)”

EUBLACKSTART 

Comment:

Particulate matter limits for EUBLACKSTART does not include condensable fraction. Draft 

permit does not include complete particulate matter BACT limits for EUBLACKSTART. 

Response: 

Potential particulate matter, of all forms, from the distillate oil-fired equipment is expected to 

be very low, since the equipment will have limited use. However, PM10 and PM2.5 emission 

limits, which include the condensable fraction, representing BACT have been added to the 

emission limit table for EUBLACKSTART. 

Condition Change: 

Page 19: (Added SC I.2 and I.3 and Renumbered Emission Limit Table) MDEQ added a 

PM10 and PM2.5 emission limits representing BACT for EUBLACKSTART. 

Condition Change: 

Page 20: (Changed SC II.1) MDEQ deleted from the beginning of SC II.1: “After the year 

2010”. That statement refers to the sulfur content in the fuel if the equipment were to be 

operating before the year 2010. 

Comment: 

The proposed draft conditions for EUBLACKSTART do not define startup and shutdown, or 

contain recordkeeping or reporting requirements for startup and shutdown.
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Response: 

MDEQ agrees emissions should be minimized during startup and shutdown. However, 

MDEQ does not believe it is necessary to define startup and shutdown when there is not a 

way to measure continuous heat input to the black start turbine. Emergency turbines are 

expected to run no more than 500 hours per year which includes startup and shutdown. 

Condition Change: 

Page 20: (Added SC III.4) MDEQ added a special condition to the Process/Operational 

Restrictions to minimize excess emissions during startup and shutdown. The condition reads 

as follows: 

 

 “The permittee shall not operate EUBLACKSTART unless an acceptable plan that 

 describes how emissions will be minimized during all startups and shutdowns has 

 been submitted to the AQD District Supervisor. The plan shall incorporate 

 procedures recommended by the equipment manufacturer as well as incorporating 

 standard industry practices and good combustion control. (R 336.1911, R 336.1912, 

 R 336.2802, 40 CFR 52.21)”

Condition Change: 

Page 22: (Added SC IX.1) MDEQ added special condition to ensure the permittee follows all 

federal New Source Performance Standards. The condition reads as follows: 

 “The permittee shall comply with all provisions of the federal Standards of 

 Performance for New Stationary Sources as specified in 40 CFR Part 60 Subparts A 

 and KKKK, as they apply to EUBLACKSTART. (40 CFR Part 60 Subparts A & 

 KKKK)”

FGCFB Emission Limits 

Condition Change: 

Page 26: (Limit Column of SC I.10 and I.16) MDEQ deleted “excluding periods of startup and 

shutdown” from the New Source Performance Standard (NSPS) which should be met at all 

times. 

Condition Change: 

Page 26: (Underlying Applicable Requirement Column of SC I.18) MDEQ added 

R 336.1299(2)(b), to ensure the requirement for MACT is met during periods of startup and 

shutdown for VOC. 

Comment: 

The proposed draft conditions include conflicting limits for the same load levels, when only 

the lower limit arguably may constitute BACT. Also, a late submittal of a startup, shutdown 

plan violates the CAA requirements. 

Response: 

Based on the comments received the MDEQ removed intermediate load conditions from the 

permit. The MDEQ believes that Wolverine did not provide adequate information to 

substantiate the necessity for such limits and that the limits appeared to allow Wolverine to 

operate in a malfunction state of operation without calling it a malfunction. The startup, 

shutdown, and malfunction plans will be submitted to the district supervisor before operation 
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of the plant. Since the plan is required by the permit but not part of the permit, it allows the 

district supervisor to require the permittee to quickly make changes to the MAP if it fails to 

address a malfunction. 

Condition Change: 

Pages 25 -27: MDEQ removed intermediate load special conditions for NOx, CO, SO2, and 

VOC. As a result, all emission limits were renumbered in the Emission Limit Table. 

Condition Change: 

Page 27: (SC I.22) MDEQ added a more restrictive emission limit for Hydrogen Fluoride 

(HF), 0.00014 lb/MMBtu heat input, replaces previous proposed limit of 0.00030 lb/MMBtu 

heat input. This change is made in response to a comment. A detailed response can be 

found in the “Maximum Achievable Control Technology (MACT) Review” Section of this 

document. 

Condition Change: 

Page 27: (SC I.25 Footnote 1) MDEQ changed “CEMs” to “CERMs” and added the 

language “as defined in 40 CFR Part 98 for non-CO2e GHGs”. Change was made for 

enhanced emissions monitoring. CEMs measures concentration of the flue gases and 

CERMs measures the concentration plus the flow of the flue gas to monitor the emission 

rate. The footnote now reads as follows: 

 “1

Emissions shall be calculated based on CO2 CERMS data and fuel factors for nonCO2 GHGs, as defined in 40 CFR Part 98.” 

FGCFB Material Limits

Condition Change: 

Pages 27, 28: (SC II.1) MDEQ changed No. 2 fuel oil to ultra low diesel fuel based on the 

NSPS requirements of other diesel fueled equipment at the proposed facility which requires 

the use of this type of fuel. Therefore, ultra low sulfur diesel fuel will be available at the site. 

Also, deleted previous SC II.6 since the condition is now covered by SC II.1. 

FGCFB Process/Operational Restrictions

Condition Change: 

Page 29: (Added SC III.1) MDEQ added an additional requirement to the start-up provisions 

of each boiler in SC III.1 to ensure both boilers are not starting up at the same time. This 

qualifier is necessary to ensure protection of the NAAQS. The condition reads as follows: 

 “The permittee shall not operate both EUCFB1 and EUCFB2 simultaneously anytime 

during a start-up operation. Start-up operations for each boiler included in FGCFB shall 

not exceed 24 hours. Shutdown operations for each boiler included in FGCFB shall not 

exceed 8 hours. FGCFB shall not exceed 12 cold start-ups and shutdowns for each 

boiler in a 12-month time period. Start-up is defined as the period of time from initiation 

of combustion firing until the unit reaches steady state operation (i.e. minimum of 50% 

load). Cold start-up is defined as a start-up after 48 or more hours following the last fuel 

input to the boiler. Shutdown is defined as that period of time from the initial lowering of 

the boiler output below 50% of the maximum heat input, until the point at which the 

combustion process has stopped and the bed material fluidizing air has been 

discontinued. (R 336.2810, 40 CFR 52.21(j))” 
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Condition Change: 

Page 29: (Added SC III.5) MDEQ added a special condition to the Process/Operational 

Restrictions to minimize excess emissions during startup and shutdown. The condition reads 

as follows: 

 “The permittee shall not operate FGCFB unless an acceptable plan that describes 

 how emissions will be minimized during all startups and shutdowns has been 

 submitted to the AQD District Supervisor. The plan shall incorporate procedures 

 recommended by the equipment manufacturer as well as incorporating standard 

 industry practices and good combustion control. (R 336.1911, R 336.1912, 

 R 336.2802, 40 CFR 52.21)”

FGCFB Design/Equipment Parameters

Condition Change: 

Page 27, 28: (SC IV.1 and IV.2) MDEQ changed the special conditions by adding 

parenthesis around “spray dryer absorber”. The condition reads as follows: 

 “The permittee shall not operate EUCFB1 unless the selective non-catalytic reduction 

 system (SNCR), pulse jet fabric filter with polyphenylene sulfide bags, polishing 

 scrubber (spray dryer absorber), and sorbent injection system is installed, 

 maintained, and operated in a satisfactory manner. Satisfactory manner includes 

 operating and maintaining each control device in accordance with an approved 

 malfunction abatement plan (MAP) for EUCFB1 as required in Process/Operational 

 Restriction SC III.2. (R 336.1225, R 336.1299(2)(b), R 336.1901, R 336.1910, 

 R 336.2810, 40 CFR 52.21(j))”

FGCFB Monitoring/Recordkeeping 

Condition Change: 

Page 31: (SC VI.4) MDEQ changed the special condition by adding the word “volumetric” to 

the exhaust gas flow rate. It now reads as follows: 

“The permittee shall install, calibrate, maintain and operate in a satisfactory manner a 

device to monitor and record the exhaust gas volumetric flow rate from each boiler 

included in FGCFB on a continuous basis. The monitor shall be operated in 

accordance with procedures outlined in Appendix B attached and in 

40 CFR 60.49Da(m). (R 336.2810, 40 CFR 52.21(j), 40 CFR 60.49Da)” 

Condition Change: 

Page 30, 31: (from draft dated 9/9/2008, deleted SC VI.11, 12, 13, 14, and 15) MDEQ 

deleted previous draft recordkeeping requirements for VOC, Pb, H2SO4, HCl and As, since 

it is not necessary to calculate monthly emissions for those pollutants. The emission limits 

require stack testing to verify emission rate, not to determine an annual average. Records of 

stack test results are required to be kept in SC VI.12. 

Condition Change: 

Page 32: (SC VI.12) MDEQ added subparts e, f, and g to specify necessary record keeping 

ensuring compliance with all applicable requirements of the permit. Also, all applicable 
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requirement numbers were added to the special condition. Special condition VI.12 now 

reads as follows: 

 

“The permittee shall maintain records for FGCFB for information necessary for all 

notifications and reports as specified in these special conditions as well as that 

information necessary to demonstrate compliance with the emission limits of this 

permit. This information shall include, but shall not be limited to, the following: 

a) Compliance tests and any testing required under 40 CFR Subpart Da or the 

conditions of this permit 

b) Monitoring data 

c) Heat input calculations 

d) Fuel analysis including identification, type, heating value (Btu/lb), and the 

amounts of all fuels combusted in FGCFB on a daily average basis 

e) Total gigawatt-hours of energy produced on a monthly basis 

f) Records of the duration of all times FGCFB is operated under startup or 

shutdown conditions as defined in SC III.1 

g) All records required by 40 CFR§60.7 and §60.52a 

h) All calculations necessary to demonstrate compliance with the limits contained in 

this permit, or the reporting requirements contained in Appendix C of this permit. 

All of the above information shall be stored in a format acceptable to the Air Quality 

Division, shall be maintained for a period of at least five years, and shall be 

consistent with the requirements of 40 CFR 60.7(f). (R 336.1205(1)(a), R 336.1225, 

R 336.1228, R 336.1229(2)(b), R 336.1299(2)(b), R 336.1301, R 336.1331, 

R 336.1401, R 336.1702(a), R 336.1901, R 336.1912, R 336.2802(4), R 336.2803, 

R 336.2804, R 336.2810, 40 CFR 52.21(a)(2), 40 CFR 52.21(c),(d), & (j), 

40 CFR 60.42Da, 40 CFR 60.7(f))” 

FGCFB Reporting

Condition Change:

Page 31: (SC VII.1) MDEQ added the underlying applicable requirement of 

“40 CFR 60.51Da(a)” to the condition. The condition refers to Appendix C-1 reporting which 

is required by 40 CFR 60.51Da(a) in addition to 40 CFR 60.51Da(b). 

FGCFB Other Requirements 

Condition Change: 

Page 33: (Added SC IX.3 and changed the old SC IX.3 to SC IX.4) MDEQ added special 

condition to ensure the permittee follows all federal New Source Performance Standards. 

The condition reads as follows: 

 “The permittee shall comply with all provisions of the federal Standards of 

 Performance for New Stationary Sources as specified in 40 CFR Part 60 Subparts A 

 and Da, as they apply to FGCFB. (40 CFR Part 60 Subparts A & Da)” 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 14 of 140 

June 29, 2011 

Material Handling Operations 

Condition Change: 

Page 45, 48, and 50: (Added SC IX.1 and deleted condition from Process Operational 

Limits) MDEQ added special condition to ensure the permittee follows all federal New 

Source Performance Standards. The condition reads as follows: 

 “The permittee shall comply with all provisions of the federal Standards of 

 Performance for New Stationary Sources as specified in 40 CFR Part 60 Subparts A 

 and Y, as they apply to (EMISSION UNIT ID). (40 CFR Part 60 Subparts A & Y)” 

Comment:

With regard to the fuel crusher (EUFUELCRUSHER) for PM and PM10, the draft conditions 

reference General Condition 13 which states that Michigan may require performance testing 

for emission control. However, Subpart Y 40 CFR 60.252(c) references 40 CFR 60.8 which 

requires performance testing within 180 days of start up and a written report to be submitted. 

The draft permit should be amended to reflect the federal requirements found at 

40 CFR 60.252(c). 

Response: 

EUSOLIDFUELHANDLING, EUFUELCRUSHER, and EUFUELSILO are all subject to NSPS 

Y and the proposed permit reflects that applicability. However the requirement for 

mandatory visible emission testing under NSPS Y was not included in the draft permit. The 

requirement was added to the special conditions. 

Condition Change: 

Page 45, 48, and 50: (Added SC V.1) MDEQ added the requirement for permittee to 

conduct visible emissions tests for emission units EUSOLIDFUELHANDLING, 

EUFUELCRUSHER, and EUFUELSILO. Special Condition reads as follows: 

“Within 180 days after initial start-up of (EMISSION UNIT ID), the permittee shall 

conduct visible emissions tests from (EMISSION UNIT ID) by testing at owner's 

expense, in accordance with federal Standards of Performance for New Stationary 

Sources 40 CFR Part 60 Subparts A and Y. No less than 60 days prior to testing, the 

permittee shall submit a complete test plan to the AQD. The AQD must approve the 

final plan prior to testing. Verification of emission rates includes the submittal of a 

complete report of the test results to the AQD within 60 days following the last date of 

the test. (40 CFR Part 60 Subparts A & Y)” 

Comment: 

The permit is not practically enforceable because it relies on a yet-to-be completed 

Malfunction Abatement Plan (MAP) and Fugitive Emissions Control Plan (FECP) and 

because the permit does not include the contents of the MAP and FECP. The MAP violates 

the public participation requirements for PSD because it will not be completed until after the 

permit is issued. The FECP violates the public participation requirements for PSD permits 

because it does not have to be completed until 180 days after initial start-up of the covered 

equipment. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 15 of 140 

June 29, 2011 

Response: 

The requirements of the MAP and the FECP are incorporated into the permit and are not 

separate, unenforceable provisions. For example, Special Condition III.2 for EULIMESTONE 

states that Wolverine shall not operate EULIMESTONE unless an MAP as described in Rule 

911(2) is implemented and maintained. Similarly, Special Condition III.1 for EULIMESTONE 

states the FECP shall be implemented, and maintained. 

 

The documents published for public comment included a preliminary MAP. The preliminary 

MAP provides a template for the MAP requirements and identifies the plan components, 

including equipment to be inspected, inspection frequency, spare parts inventory, and 

remedial actions to be undertaken if a malfunction occurs. The preliminary MAP also 

explains that the final information as to such components cannot be defined until the 

equipment vendors are selected and the facility design has progressed to a point that allows 

definition. 

The documents published for public comment also include a preliminary FECP. As stated in 

that document, the requirements in the FECP may be changed once the actual equipment is 

selected and installed. For example, the preliminary FECP states that fly ash in storage silos 

shall be transferred onto haul trucks using a wet ash unloading system to minimize fugitive 

dust. Additional requirements (including how that system will operate to keep the ash wet) 

will be incorporated into the FECP after the wet ash unloading system is selected and 

installed. 

It is not technically feasible to develop the final requirements of the MAP and the FECP as 

part of the pre-construction review because they are dependent on facility-specific, as-built 

site conditions. The opportunity the public was given to comment on the preliminary MAP 

and FECP satisfies the public participation requirements for PSD permits. 

Condition Change: 

Pages 34 through 53: (SC III.1) As part of this comment review, MDEQ modified the 

previous language for requiring a fugitive dust control program from EULIMESTONE, 

EULIMESTONEPREP, EUBEDASH, EUFLYASH, EUSOLIDFUELHANDLING, 

EUFUELCRUSHER, and EUFUELSILO. 

The revised Special Condition III.1 now reads as follows: 

“Within 180 days of initial start-up of (EMISSION UNIT ID) the permittee shall submit 

to the AQD District Supervisor a program for continuous fugitive emissions control for 

all material handling operations. The program shall be reviewed and approved by 

the AQD District Supervisor and is implemented and maintained. If at any time the 

fugitive dust control program fails to address or inadequately addresses an event that 

meets the characteristics of a revision or update, the permittee shall amend the 

fugitive dust control program within 45 days after such an event occurs. The 

permittee shall also amend the fugitive dust control program within 45 days, if new 

equipment is installed or upon request from the District Supervisor. The permittee 

shall submit the fugitive dust control program and any amendments to the fugitive 

dust control program to the AQD District Supervisor for review and approval. If the 

AQD does not notify the permittee within 90 days of submittal, the fugitive dust 

control program or amended fugitive dust control program shall be considered 

approved. Until an amended plan is approved, the permittee shall implement 

corrective procedures or operational changes to achieve compliance with all 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 16 of 140 

June 29, 2011 

applicable emission limits. (R 336.1371, R 336.1901, R 336.2803, R 336.2804, 

R 336.2810, 40 CFR 52.21 (c), (d), & (j))” 

Condition Change: 

Pages 34 through 53: (SC III.2) As part of the comment review, MDEQ added language 

requiring a malfunction abatement plan (MAP) from EULIMESTONE, EULIMESTONEPREP, 

EUBEDASH, EUFLYASH, EUSOLIDFUELHANDLING, EUFUELCRUSHER, and 

EUFUELSILO. The Special Condition III.2 reads as follows: 

“The permittee shall not operate (EMISSION UNIT) unless a malfunction abatement 

plan (MAP) as described in Rule 911(2) is implemented and maintained. If at any 

time the MAP fails to address or inadequately addresses an event that meets the 

characteristics of a malfunction, the permittee shall amend the MAP within 45 days 

after such an event occurs. The permittee shall also amend the MAP within 45 days, 

if new equipment is installed or upon request from the District Supervisor. The 

permittee shall submit the MAP and any amendments to the MAP to the AQD District 

Supervisor for review and approval. If the AQD does not notify the permittee within 

90 days of submittal, the MAP or amended MAP shall be considered approved. Until 

an amended plan is approved, the permittee shall implement corrective procedures 

or operational changes to achieve compliance with all applicable emission limits.

(R 336.1331, R 336.1910, R 336.1911, R 336.2803, R 336.2804, R 336.2810, 

40 CFR 52.21 (c), (d), & (j))” 

Condition Change: 

Pages 34 through 53: (SC IV.1) As part of the comment review, special conditions requiring 

the installation, operation and maintenance of emissions control equipment were moved from 

the “Process/Operational Restriction(s)” section to the “Design/Equipment Parameter(s)” 

section. This occurred in the following Emission Units: EULIMESTONE; 

EULIMESTONEPREP; EUBEDASH; EUFLYASH; EUSOLIDFUELHANDLING; 

EUFUELCRUSHER; and EUFUELSILO. The special condition reads as follows: 

“The permittee shall not operate (specific portion of EMISSION UNIT) unless the 

(specific control equipment) is installed and/or implemented, maintained and 

operated in a satisfactory manner. Satisfactory manner includes operating and 

maintaining each control device in accordance with a malfunction abatement plan 

(MAP), as required by Special Condition III.2. (R 336.1901, R 336.1910, R 336.1911, 

R 336.2803, R 336.2804, R 336.2810, 40 CFR 52.21 (c), (d) & (j))”

Condition Change: 

Pages 33 through 53: (SC IX.1) As part of the comment review, special conditions 

referencing general compliance for an applicable New Source Performance Standard 

(NSPS) were moved from the “Process/Operational Restriction(s)” section to the “Other 

Requirement(s)” section. This occurred in the following Emission Units: EULIMESTONE; 

EULIMESTONEPREP; EUSOLIDFUELHANDLING; EUFUELCRUSHER; and EUFUELSILO. 

The special condition reads as follows: 

 “The permittee shall comply with all provisions of the federal Standards of 

 Performance for New Stationary Sources as specified in 40 CFR Part 60 Subparts A 

 and (SUBPART), as they apply to (EMISSION UNIT). (40 CFR Part 60 Subparts 

 A & (SUBPART))” 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 17 of 140 

June 29, 2011 

Condition Change: 

Pages 33 through 53: MDEQ made changes to the permit underlying applicable 

requirements (UAR). Specifically, removal of 40 CFR 52.21(c) & (d) and MAPC 

Rules 336.2803, and 336.2804 from any allowable opacity limitations from emission units 

EULIMESTONE, EULIMESTONEPREP, EUBEDASH, EUFLYASH, 

EUSOLIDFUELHANDLING, EUFUELCRUSHER, and EUFUELSILO. This particular change 

was due to the recognition that opacity limits are neither subject to the PSD increment 

analysis nor any NAAQS demonstration. 

Condition Change: 

Pages 46 through 52: The previously listed UAR for Opacity Limits was changed from 

40 CFR 60.252(c) to 40 CFR 60.254 for the following emission units: 

EUSOLIDFUELHANDLING, EUFUELCRUSHER, and EUFUELSILO. During the comment 

review, the Federal EPA promulgated a revised NSPS Y and the appropriate UAR citation 

was changed. 

Condition Change: 

Pages 34 and 37: MDEQ changed the opacity limit from 10% to 7% for drop and transfer 

points in EULIMESTONE and EULIMESTONEPREP. During the comment review, the 

federal EPA promulgated revisions to the Standards of Performance for Non-metallic Mineral 

Processing Plants (NSPS OOO), which lowered the opacity emission limitations for drop and 

transfer points from 10% to 7%. 

 

III. SUMMARY OF COMMENTS 

A. Alternative Analysis

Comment: 

Wolverine has not satisfied the burden of demonstrating a need for or lack of a feasible and 

prudent cleaner alternative to the proposed coal plant. In very general terms, the filing fails 

to demonstrate there are not feasible and prudent alternatives. Issuance of the permit based 

on Wolverines' submittal would be arbitrary and capricious. 

Response: 

On June 12, 2009, in response to a request from MDEQ, Wolverine submitted an Electric 

Generation Alternatives Analysis ("EGAA"). The EGAA addressed both coal burning 

alternate technologies and non-coal burning alternative technologies. The MDEQ 

determined that, from a cost of electricity standpoint, the proposed facility represents the 

least expensive technology to implement and the alternative technologies presented in the 

EGAA are either not viable or are substantially more expensive. 

In response to the question of demonstrating need, the MDEQ originally denied the air permit 

to install on May 21, 2010. Key in that denial was a determination from the Michigan Public 

Service Commission (MPSC) that the applicant had failed to demonstrate a need for the 

additional power as part of its EGAA. Wolverine challenged this decision and in its Opinion 

and Order dated January 28, 2011 in Case No. 10-7686-CE, the Missaukee County Circuit 

Court ruled that the alleged lack of need for the proposed facility alone, separate from air 

quality concerns, is not a legal basis to deny the permit application. The court concluded 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 18 of 140 

June 29, 2011 

that the state overstepped its authority, and gave the state 60 days to re-review the 

application. 

Before providing a more detailed rationale regarding the MDEQ review of the alternatives 

analysis, it is appropriate to provide a background on the requirements for performing an 

analysis of alternative electricity generating technologies. 

Specific regulatory guidance on performing an alternative analysis for new facilities locating 

in attainment areas are not provided for in existing federal or state environmental rules. The 

basis for an alternatives analysis is contained is Section 165(a)(2) of the Clean Air Act. That 

provision states that no major emitting facility on which construction is commenced after 

August 7, 1977, may be constructed in an attainment area unless, among other things: 

...the proposed permit has been subject to a review in accordance with this 

section, the required analysis has been conducted in accordance with regulations 

promulgated by the Administrator, and a public hearing has been held with the 

opportunity for interested persons including representatives of the Administrator to 

appear and submit written or oral presentation on the air quality impact of such 

source, alternatives thereto, control technology requirements, and other 

appropriate considerations; [Emphasis added] 

This provision has been interpreted by the United States Environmental Protection Agency 

(EPA) Environmental Appeals Board to require a permitting agency to respond to comments 

raised during public comment regarding alternatives to a proposed facility, and to give the 

agency the discretion as to how to conduct this review. 

Language similar to that in Section 165(a)(2) is contained in Rule 1817(2)(e) of the Michigan 

Air Pollution Rules. The rule requires the MDEQ to do several things after receiving a 

technically complete permit application, including: 

Provide opportunity for a public hearing for interested persons to appear and submit 

written or oral comments on the air quality impact of the major source, alternatives 

to it, the control technology required, and other appropriate considerations. 

[Emphasis added] 

As previously stated, on June 2, 2009, the MDEQ requested that Wolverine provide an 

analysis of alternatives in response to public comment received on the draft air permit to 

install. The EGAA was submitted by Wolverine addressing comments received on 

alternatives to the proposed facility. 

In cooperation with the MPSC, the EGAA was reviewed with regard to alternatives. 

Although, the MPSC concluded that ‘the coal-fired generating plant is one alternative out of 

a range of alternatives that may be used to fill the projected capacity need’, costs 

associated with the alternatives were reviewed and deemed prohibitive. The MPSC 

suggested that alternatives such as energy efficiency and renewable resources may be 

used. 

The EGAA evaluated a number of different alternative technologies. In very general terms 

these alternatives can be grouped into two categories: coal burning technologies and noncoal burning alternative technologies. For coal burning technologies a number of coal 

burning technologies were evaluated and costs of implementing the technologies were 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 19 of 140 

June 29, 2011 

estimated in the EGAA. The coal burning technologies considered included Advanced 

Supercritical Pulverized Coal, Subcritical Pulverized Coal, Subcritical Circulating Fluidized 

Bed, Integrated Gasification combined Cycle and Ultra Supercritical Pulverized Coal. The 

non-coal burning technologies considered included natural gas combined cycle, natural gas 

combustion turbine, on-shore wind, off-shore wind, small wind, small biomass – wood, solar 

photovoltaic, hydroelectric, nuclear, geothermal, and landfill gas. 

The MDEQ reviewed the assumptions and methodology used by Wolverine in arriving at the 

costs of the various technologies. The MDEQ determined the costs of the alternatives to the 

proposed facility are substantially more expensive than the proposed facility itself and are 

cost prohibitive. In addition, some of the technologies are not available (e.g. geothermal) or 

have limited availability (e.g. combined heat and power, pumped storage). 

Comment: 

Even looking just at coal-fired generation, there are feasible and prudent alternatives 

available for achieving lower environmental impacts than the proposed coal plants, such as 

IGCC. 

Response: 

Coal-burning technologies other than CFB boilers are available, as discussed in a previous 

response. MDEQ evaluated these technologies during the permit review process, including 

IGCC. Other existing coal combustion technologies are not designed to burn the multiple 

fuels that Wolverine is proposing to use. Wolverine, as a part of their alternatives analysis, 

evaluated the cost of these alternate coal firing alternatives and made the determination that 

the chosen technology is the most cost effective for the variety of fuels they are proposing to 

use. MDEQ concurred with this determination. 

In regards to IGCC, the applicant provided additional information as a part of the best 

available control technology (BACT) review. The MDEQ rejected IGCC from further analysis 

as it was determined to be cost prohibitive under this control technology review. The MDEQ 

has similarly rejected IGCC as cost prohibitive for purpose of the analysis under Section 

165(a)(2) of the Clean Air Act and Rule 1817(2)(e) of Michigan's Air Pollution Control Rules. 

Comment: 

The public has not been provided the full opportunity for meaningful public participation 

required by the Clean Air Act and state regulations. The public has not been given the 

opportunity to review the alternatives analysis and needs analysis provided by Wolverine. 

 Response: 

Neither Section 165(a)(2) of the Clean Air Act nor Rule 187(2)(e) of Michigan's Air Pollution 

Control Rules require additional public comment. Nevertheless, the MDEQ, in order to 

provide the public with all pertinent issues relating to the evaluation of the permit, announced 

a 30-day public comment period. This comment period was announced on the MDEQ 

website (see http://www.deq.state.mi.us/aps/cwerp.shtml). This public comment period was 

scheduled concurrently with the public hearing announced by the MPSC public comment 

period. All information related to the EGAA was made publicly available during this public 

notice period either on the MDEQ website or via the MPSC e-docket. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 20 of 140 

June 29, 2011 

Comment: 

The EGAA fails to recognize that it is possible to construct nothing and still meet Michigan’s 

foreseeable generation requirements. 

Response: 

This comment is directed at the issue of whether there is a need for the facility. In its

Opinion and Order dated January 28, 2011 in Case No. 10-7686-CE, the Missaukee County 

Circuit Court ruled that the alleged lack of need for the proposed facility alone, separate from 

air quality concerns, is not a legal basis to deny the permit application. 

Comment: 

Wolverine assumed an estimated cost for wind power that is at least 1.5 times higher than 

national averages and recent estimates. 

Response: 

Many of the factors that are used to estimate the costs of electrical generation are volatile 

and in a constant state of flux. Wolverine estimated the cost of power generated by a wind 

farm would be about 11.1 cents/kWh1

. Since a wind farm alone is not suitable for baseload 

need, this cost includes a natural gas simple-cycle technology for those intermittent times 

that the wind is not blowing. Assuming that the assertion made by the commenter is correct, 

if the cost for wind power was adjusted downwards, the national average cost for wind power 

would equate to approximately 7.4 cents/kWh, which is the same cost of the chosen CFB 

boiler technology firing petroleum coke/PRB/Biomass Blend.2

 Also, consideration would 

need to be given to the amount of land required for a wind farm. For every 1 MW of power 

there needs to be at least 50 acres of land available. Therefore, to achieve a 600 MW 

capacity there would need to be at least 50 square miles of land available. 

Comment: 

Section 165(a)(2) of the Clean Air Act, which requires as part of the permitting for a 

proposed major source that the public be provided the opportunity to submit testimony 

on the “air quality impacts of such source, alternatives thereto, control technology 

requirements, and other appropriate considerations.” As the agency is required to 

respond to comments submitted by the public, MDEQ must substantively address the 

alternatives issues raised in these and other public comments. In addition, this language 

has long been interpreted to grant a permitting authority broad discretion to evaluate 

need, consider alternatives (including the “no build” alternative), conduct or require 

additional analyses, and impose permit conditions beyond the baseline requirements of 

BACT in order to protect air quality. In re Prairie State Generating Co., PSD Appeal No. 

05-05, quoting U.S. EPA Draft NSR Manual, 1990 (“NSR Manual”), MDEQ may consider 

a no-build option under Section 165(a)(2) of the Act, which provides MDEQ with the 

authority to deny a PSD permit based on policy considerations related to CO2.17 While 

Section 165(a)(2) is designed primarily to ensure that the public’s participation rights are 

 

1

 See “Wolverine Power Cooperative Electric Generation Alternatives Analysis for the proposed Permit to Install 

(PTI) No. 317-07 For Circulating Fluidized Bed Coal Boilers at Rogers City, Michigan, Docket Number: U16000, 

Staff Report to the Michigan Department of Environmental Quality, Page 36. 2

 See “Wolverine Power Cooperative Electric Generation Alternatives Analysis for the proposed Permit to Install 

(PTI) No. 317-07 For Circulating Fluidized Bed Coal Boilers at Rogers City, Michigan, Docket Number: U16000, 

Staff Report to the Michigan Department of Environmental Quality, Page 39. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 21 of 140 

June 29, 2011 

meaningful, MDEQ is not limited to issues raised by the public, but instead may consider 

or require alternatives, evaluations of need, and additional permit conditions on its own.

Response:

As previously stated, discretion is granted to the reviewing authority as to how to 

respond to comments raised on alternatives. This position is supported in the Prairie 

State case cited by the commenter. The MDEQ requested Wolverine address the 

question of alternatives raised during public comment and Wolverine responded with 

submittal of the EGAA. Wolverine, as a part of their alternatives analysis, evaluated the 

cost of coal firing alternatives and made the determination that the chosen technology is the 

most cost effective for the variety of fuels they are proposing to use. MDEQ concurred with 

this determination. As to the question of need or a ‘no build’ option, in its Opinion and Order 

dated January 28, 2011 in Case No. 10-7686-CE, the Missaukee County Circuit Court ruled 

that the alleged lack of need for the proposed facility alone, separate from air quality 

concerns, is not a legal basis to deny the permit application. 

Comment: 

We are sorry to see MDEQ misapplying the 28th Circuit Court ruling of Jan. 28. That ruling 

turns entirely on a failure by the MDNRE PTI denial letter to specifically tie questions about 

“need” to concerns about air quality – a tie that is plain in the administrative record, but not 

explicitly stated in the letter. In fact the ruling concedes that if the denial letter had taken that 

one final and obvious step, both it and the MDEQ decision to deny would have passed legal 

muster. So the decision to exclude from these new hearings further consideration of “need” 

and, much more to the legal and practical point, of the ready availability of cleaner 

alternatives for meeting future base load requirements, ignores what the circuit court ruling 

and federal and state laws actually say. 

Response: 

At the time of the May 21, 2010 denial, MDEQ had determined that the proposal by 

Wolverine met all applicable air quality rules and regulations with the exception of failing to 

demonstrate need. Therefore, it is incorrect to say that the MDEQ is misapplying the Circuit 

Court ruling. In its Opinion and Order dated January 28, 2011 in Case No. 10-7686-CE, the 

Missaukee County Circuit Court ruled that the alleged lack of need for the proposed facility 

alone, separate from air quality concerns, is not a legal basis to deny the permit application. 

MDEQ has evaluated the proposal and has determined that the project meets all applicable 

state and federal air quality requirements.

Comment: 

The analysis of need is very closely tied to a requirement for alternatives analysis. That 

requirement for an alternative analysis exists both under the Federal Clean Air Act as well as 

state pollution law and regulations. And that requires the state to choose a no-build scenario. 

Response: 

The MDEQ requested Wolverine address the question of alternatives raised during 

public comment and Wolverine responded with submittal of the EGAA. Wolverine, as a 

part of their alternatives analysis, evaluated the cost of coal firing alternatives and made the 

determination that the chosen technology is the most cost effective for the variety of fuels 

they are proposing to use. MDEQ concurred with this determination. As to the question of 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 22 of 140 

June 29, 2011 

need or a ‘no build’ option, in its Opinion and Order dated January 28, 2011 in Case No. 

10-7686-CE, the Missaukee County Circuit Court ruled that the alleged lack of need for the 

proposed facility alone, separate from air quality concerns, is not a legal basis to deny the 

permit application. 

B. MEPA/Rule 901

Comment: 

The emission of carbon dioxide (CO2) and other greenhouse gases (GHGs) from the 

proposed facility will pollute, impair and destroy natural resources by exacerbating climate 

change. The impacts on public health and the environment from climate change are severe 

and widespread. Section 1705(a)(2) of MEPA requires that the MDEQ deny the permit 

application if there is a feasible and prudent alternative that would avoid or minimize the 

effect on climate change from the proposed facility. 

Response: 

The focus of the Michigan Environmental Protection Act (MEPA) is on the conduct of the 

permit applicant as opposed to emissions from other facilities.3

 Section 1705(2) of MEPA 

states: 

In administrative, licensing, or other proceedings, and in any judicial review of such a 

proceeding, the alleged pollution, impairment, or destruction of the air, water or other 

natural resources, or the public trust in these resources, shall be determined, and 

conduct shall not be authorized or approved that has or is likely to have such an effect if 

there is a feasible and prudent alternative consistent with the reasonable requirements of 

the public health, safety, and welfare. [MCL 324.1705(2)]. 

Before reaching the question of whether there is a feasible and prudent alternative to a 

permit applicant's conduct under Section 1705(2) of MEPA, the MDEQ is to determine 

whether the conduct has or is likely to have the effect of polluting, impairing, or destroying 

natural resources. If the MDEQ concludes the conduct has or is likely to have that effect, the 

conduct shall not be authorized if there is a feasible and prudent alternative consistent with 

the reasonable requirements of the public health, safety, and welfare. If, however, the 

MDEQ determines the applicant's conduct does not have or is not likely to have that effect, it 

is unnecessary to analyze whether a feasible and prudent alternative exists. 

Not all environmental impacts from human activities pollute, impair, or destroy natural 

resources. As the Michigan Supreme Court has observed, "virtually all human activities can 

be found to adversely impact natural resources in some way or other. The real question 

before us is when does such impact rise to the level of impairment or destruction?"4

 

Whether the emissions from a facility rise to the level of pollution, impairment, or destruction 

of natural resources is determined based on the particular facts of the facility's operations 

and its impacts. The factors to examine include whether the natural resources involved are 

rare, unique, or endangered and whether the natural resources impacted are easily 

replaceable.5

 

 

3

 See Preserve the Dunes, Inc v MDEQ, 471 Mich 508, 514; 684 NW2d 847 (2004). 

4

 West Michigan Envt'l Action Council v Natural Resources Comm'n, 405 Mich 741, 760; 275 NW2d 538 (1979). 

5

 Nemeth v Abonmarche Development Inc, 457 Mich 16, 31-36; 574 NW2d 641 (1998). 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 23 of 140 

June 29, 2011 

Climate change is caused by changes in atmospheric concentrations of GHGs and aerosols, 

as well as changes in land cover and solar radiation. Global emissions of GHGs from human 

activities have increased since pre-industrial times, with an increase of 70% from 1970 to 

2004.6

 

According to the Intergovernmental Panel on Climate Change, CO2 is the most important 

anthropogenic GHG. Annual emissions of CO2 from global anthropogenic activities 

increased by approximately 80% between 1970 and 2004.7

 Once GHGs (including CO2) are 

emitted from anthropogenic activities anywhere around the world, they become well mixed 

globally in the atmosphere and remain in the atmosphere for decades to centuries.8

 

GHG emissions from the proposed facility will not rise to the level of pollution, impairment or 

destruction under MEPA. The available information indicates that the current and future 

adverse effects of climate change (such as more frequent heat waves, increased drought, 

sea level rise, and more intense storms) are very likely caused by GHG emissions from 

anthropogenic activities globally over the course of past decades and centuries.9

 Adverse 

effects that are projected to occur in the future will not be caused by the GHGs emitted from 

the proposed facility. Since the incremental contribution to climate change from GHGs 

emitted by the facility does not have and is not likely to have the effect of polluting, impairing 

or destroying natural resources, no analysis of alternatives under MEPA is required. 

 

Two commenters submitted a Petition to Intervene pursuant to Section 1705(1) of MEPA. 

Like the comments they submitted on the draft permit, they allege that GHGs from the facility 

will exacerbate climate change and that the MDEQ must deny the permit under 

Section 1705(a)(2). This response addresses the comments on the draft permit and the 

Petition to Intervene. 

Comment: 

MEPA requires the MDEQ to adopt more stringent pollution standards than those required by 

the CAA and Part 55 if Wolverines’ actions have or are likely to have the effect of polluting, 

impairing, or destroying natural resources. Air pollutant emissions from the proposed facility 

-- even if they complied with the CAA and Part 55 -- will adversely impact public health, air 

quality, water quality and vegetation. 

In addition, the facility will result in negative impacts from coal mining and associated 

transportation, water withdrawals, water discharges, and waste disposal. These impacts 

constitute pollution, impairment, or destruction of natural resources under MEPA. 

Response: 

The permit requirements developed pursuant to the CAA and Part 55, Air Pollution Control, 

of the Natural Resources and Environmental Protection Act, 1994 PA 451, as amended 

(NREPA), to address air emissions are protective of public health and the environment. Air 

emissions from the facility do not constitute pollution, impairment, or destruction of natural 

resources under MEPA. 

 

6

 Intergovernmental Panel on Climate Change, Climate Change: 2007, Synthesis Report, Summary for Policy 

Makers, at 5 (Nov. 17, 2007). 

7

 See id. 

8

 74 Fed Reg 18,886, 18,888 (April 24, 2009). 

9

 See IPCC Synthesis Report, at 5; 74 Fed Reg at 18,888. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 24 of 140 

June 29, 2011 

Wolverine must comply with all applicable pollution standards regarding environmental 

media other than air. The commenters provide no information to show that the impacts to 

such other media will rise to the level of pollution, impairment, or destruction when the facility 

is operating pursuant to the applicable pollution standards. In addition, it is noted that some 

of the activities listed by the commenter (e.g. coal mining and the associated transportation) 

take place outside of the State of Michigan. MEPA would not apply to those activities. 

Comment: 

MEPA requires the MDEQ to thoroughly evaluate alternatives to the facility. If a permit is 

issued, MEPA requires that the emission limits not be based on the "worst case" fuels 

proposed by Wolverine. Instead, the emission limits must be based on less polluting 

alternatives (such as natural gas, biomass, and/or lower sulfur coals). 

Response: 

As stated previously, Section 1705(2) of MEPA provides that alternatives are evaluated in 

licensing proceedings if it is determined that the proposed conduct has or is likely to have the 

effect of polluting, impairing, or destroying natural resources. The facility will not have that 

effect. MEPA does not, therefore, require an evaluation of feasible and prudent alternatives. 

Comment: 

Rule 901 requires consideration of cleaner alternatives and limits on GHG emissions. 

Response: 

Rule 901 states: 

“Notwithstanding the provisions of any other department rule, a person shall not 

cause or permit the emission of an air contaminant or water vapor in quantities that 

cause, alone or in reaction with other air contaminants, either of the following: 

(a) Injurious effects to human health or safety, animal life, plant life or significant 

economic value, or property. 

(b) Unreasonable interference with the comfortable enjoyment of life and property.” 

The air contaminants emitted from the proposed facility, including GHG, will not have either 

of the effects identified in Rule 901. Wolverine is required to comply with the permit 

requirements developed pursuant to Part 55 and the CAA to ensure protection of public 

health and the environment. GHG emissions have been addressed under the BACT review 

and appropriate limits have been added to the permits. Additional information can be found 

under the BACT Section of this document. 

Comment: 

Section 165(a)(2) of the CAA, 42 USC 7475(a)(2), requires a thorough evaluation of the 

need for, and cleaner alternatives to, the proposed facility. That evaluation must consider 

environmental impacts from the facility, energy need, alternatives in addition to a no-build 

option, and measures to avoid or minimize environmental impacts (including impacts from 

GHG emissions). 

In addition, Section 165(a)(2) provides authority to the MDEQ to deny a permit application 

based on the relative environmental impacts of the proposed facility and cleaner alternatives 

and to impose permit conditions beyond those required to satisfy BACT. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 25 of 140 

June 29, 2011 

 

The available information demonstrates that the proposed facility is not needed. Whatever 

need exists can be met through the use of cleaner alternatives. 

Response: 

Section 165(a)(2) states that no major emitting facility may be constructed in an area that is 

in attainment with the NAAQS unless a public hearing has been held on the proposed permit 

and an opportunity provided for interested persons to submit presentations on the air quality 

impact of the source and "alternatives thereto." 

The MDEQ has analyzed alternatives to the proposed facility pursuant to Section 165(a)(2), 

including less polluting alternatives. Alternatives to the facility are addressed elsewhere in 

this document. 

Comment: 

Section 165(a)(4) of the CAA, 42 USC 7475(a)(2), requires the consideration of collateral 

environmental impacts as part of step 4 of a BACT analysis. 

Response: 

The MDEQ analyzed collateral environmental impacts as part of its BACT analysis. 

Comment: 

The proposed facility will emit significant amounts of hazardous air pollutants. An evaluation 

of cleaner alternatives is therefore required under MEPA and Rule 901. 

Response: 

The permit restricts the emission of hazardous air pollutants pursuant to the requirements of 

Michigan's air toxics rules and the CAA to ensure they are protective of public health and the 

environment. The emissions that Wolverine is authorized to emit do not rise to the level of 

pollution, impairment or destruction of natural resources under MEPA, nor do they result in 

the effects listed in Rule 901. 

Comment: 

PM2.5 NAAQS is inadequate to protect public health and the environment. MEPA and 

Rule 901 require emissions limits beyond those needed to meet the PM2.5 NAAQS. 

Response:

A PM2.5 NAAQS modeling analysis was performed taking into account all emissions at the 

proposed facility; along with other sources in the area expected to contribute to the NAAQS 

impact. Modeling demonstrated that emissions of PM2.5 comply with the NAAQS. The 

proposed facility’s emissions do not cause or contribute to exceedence of the NAAQS for 

PM2.5 within the meaning of the Clean Air Act and Part 55. 

This analysis demonstrates the PM2.5 emissions from the facility do not rise to the level of 

pollution, impairment, or destruction of natural resources under MEPA. It further 

demonstrates that the PM2.5 emissions do not result in the effects listed in Rule 901. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 26 of 140 

June 29, 2011 

MDEQ relies upon the NAAQS for PM2.5 as the appropriate health protection benchmark for 

the assessment of the proposed facility. Attainment of the primary NAAQS is presumptively 

protective of the public health. On that basis, MDEQ has concluded that the emissions of 

PM from the proposed facility will not have an adverse impact on public health. 

On December 18, 2006, EPA revised the NAAQS for PM2.5 to levels required to protect the 

public health with an adequate margin of safety. On February 24, 2009, the U.S. Court of 

Appeals for the District of Columbia Circuit granted a petition for review and remanded to 

EPA for reconsideration the primary annual NAAQS and the secondary NAAQS for PM2.5. 

The PM2.5 NAAQS were not vacated by the court, and the court did not find that the primary 

annual NAAQS was inadequately protective of the public health. The court found that EPA’s 

failure to explain adequately why the primary annual level of 15 ug/m3 is sufficient to protect 

public health was in principle a curable defect. EPA is currently in the process of 

re-evaluating the PM2.5 NAAQS, as a matter of routine updating and assessment of the 

relevant studies and in response to the court’s remand. 

The MDEQ has not concluded that the PM2.5 NAAQS are inadequate standards for public 

health protection or that Rule 901 should be applied to require further reductions in allowable 

facility impacts of PM2.5. The PM2.5 emissions from the proposed facility do not cause the 

adverse effects listed in Rule 901 and do not rise to the level of pollution, impairment, or 

destruction of natural resources under MEPA. 

Comment: 

The emission of criteria air pollutants will pollute, impair and destroy natural resources. More 

specifically, negative impacts to human health from the emission of criteria pollutants may 

occur at levels below the NAAQS established by EPA as shown by the Senate Report that 

accompanied the 1977 amendments to the CAA. MEPA and Rule 901 therefore require an 

evaluation of cleaner alternatives. 

Response: 

The commenter mistakenly interpreted the Senate Report. The Senate Report emphasizes 

that the NAAQS are insufficient to protect public health and welfare and explains that 

Congress added the PSD program to the CAA in 1977 to achieve air quality better than the 

NAAQS. The permit for the proposed facility ensures that Wolverines' operations will meet 

the requirements of both the NAAQS and the PSD program. Further, in 1977 the Senate 

Report did not address PM2.5 emissions. 

C. Public Health and Environment Concerns 

Comment: 

The Fact Sheet for the draft permit states: “Only a fraction of the mercury emitted may 

deposit locally. The remainder undergoes long-range transport where it disperses and may 

still deposit, but at lesser levels of impact than occurs locally.” The statement shows an error 

in the assumptions MDEQ used to evaluate the risks from mercury emitted by the proposed 

facility. Recent studies (e.g., the Steubenville, Ohio study by Keeler et al.) have shown that 

the majority of mercury deposition occurs locally and is from coal plants. As a result, 

MDEQ’s assumptions regarding local deposition are without foundation and contradicted by 

the most recent studies on the subject. MDEQ’s flawed assumptions regarding local 

deposition underestimate the impact the proposed facility will have on local water bodies 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 27 of 140 

June 29, 2011 

and, in turn, the health impacts to local tribal populations dependent upon local water bodies 

for subsistence fishing. 

Response: 

The statement the commenter quotes from the Fact Sheet was intended to dispel any 

misconception that all of the emitted mercury will deposit in the local watersheds. While wetand dry-weather deposition processes can be expected to cause some local mercury 

deposition (e.g., within a few kilometers of the source), most mercury emissions will travel 

greater distances and disperse over larger areas. 

The MDEQ did not underestimate the risks from the facility's mercury emissions. To the 

contrary, the impact assessment used extremely conservative assumptions to overestimate 

the likely impact from the mercury emissions and analyze whether that overstated impact did 

not pose an unacceptable risk to public health or the environment. One of the assumptions 

concerned the extent to which the mercury emissions are deposited near the facility. 

The local deposition impact of mercury air emissions is highly dependent on the form 

(speciation) of mercury. In its 1997 Mercury Study Report to Congress, EPA estimates that 

small, medium and large coal-fired boilers emit 50% elemental mercury, 30% divalent 

mercury vapor, and 20% divalent particle-bound mercury (“50:30:20” speciation profile). 

Local deposition of elemental mercury is expected to be negligible; it enters the “global 

cycle”. Divalent mercury is expected to deposit in greater quantities closer to the emission 

source compared to elemental mercury. Divalent mercury vapor (also known as reactive 

gaseous mercury or “RGM”) is expected to deposit closer to the source than divalent 

particle-bound mercury. The risk assessment performed for the proposed facility used the 

extremely conservative assumption that the mercury emissions consist of 100% RGM. In 

other words, the risk assessment used a worst-case approach regarding the form of mercury 

emitted to maximize the calculation regarding local deposition and ensure that such 

deposition was not understated. Based on the impacts using this and other conservative 

assumptions that overestimate the likely risks from the facility, the MDEQ nevertheless 

determined the mercury emissions from the facility are not anticipated to be harmful to the 

public health. 

The assumptions in the impact assessment are not inconsistent with the findings of the 

Steubenville, Ohio study. That study evaluated mercury deposition at a monitoring station, 

rather than evaluating the dispersion and deposition pattern of mercury from any particular 

emission source. It does not identify the form of mercury emitted from regional coal-fired 

boilers or the fraction of emitted mercury from those boilers that deposited locally versus the 

fraction that did not. Here, the impact assessment used a worst-case approach to local 

deposition due to mercury speciation by assuming that 100% of the mercury emitted from the 

proposed facility is RGM. 

Comment:

MDEQ only modeled deposition to four inland lakes. Deposition to Lake Huron was 

completely disregarded. MDEQ’s assessment ignored both the degree to which Lake Huron 

would be impacted by the proposed coal plant and also the important role Lake Huron plays 

in tribal subsistence fishing. What criteria were used to evaluate the deposition radius for 

mercury since elemental mercury travels thousands of miles? 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 28 of 140 

June 29, 2011 

Response:

MDEQ determined it would be appropriate to conduct an assessment of the potential 

deposition impacts of the mercury emissions from the proposed Wolverine Power facility. 

The purpose of the mercury impact assessment is to characterize the potential long-term 

impacts to fish mercury levels in the lakes likely to be the most impacted and that may 

reasonably be assumed to have fish populations that can support recreational sport fishing. 

This is an appropriate approach. The most useful risk assessment approach is to 

characterize the incremental impacts from the facility's mercury emissions to the fisheries 

that are expected to be the most affected. If the risk assessment establishes that the 

incremental impact at the most affected fisheries does not pose an unacceptable risk to 

public health from eating fish, then the incremental impact at lesser affected fisheries will 

similarly not pose an unacceptable risk. 

Selecting the fisheries most affected by mercury deposition from the proposed facility is 

guided by several key considerations. The proximity of the water body and watershed to the 

source is an important factor, since deposition rates are generally greater near the facility. 

The prevailing wind directions are also important, since varying wind directions determine the 

direction of movement of the mercury in the air emissions. The size (area) of the water body 

and watershed is another important factor to evaluate deposition impacts from the 

background concentration of mercury in the atmosphere and from the mercury emitted by the 

facility. Additionally, the background fish mercury level can be an important consideration 

when such data are available and show that the background fish mercury level is already 

approaching or exceeding a level of concern. 

In the case of the mercury impact assessment for the proposed facility, the MDEQ 

determined that four nearby inland lakes to the east and southeast of the proposed facility 

could support recreational fisheries and would be the most impacted fisheries. The 

assessment estimated that the background fish mercury level is between 0.24 and 0.30 

mg/kg at the four inland lakes (depending on the combination of assumptions used). The 

greatest incremental impact is 0.007 mg/kg at the most impacted water body (Swan Lake). 

The cumulative mercury level in fish at the most impacted water body is less than the fish 

advisory trigger level of 0.5 mg/kg and less than the value of 0.35 mg/kg the MDEQ uses to 

determine if waters are in attainment with the designated use of fish consumption under Part 

31 of NREPA. 

An assessment of Lake Huron would not be an appropriate focus for the study; because 

Lake Huron is expected have a lower incremental impact than the four selected lakes. Lake 

Huron is a very large body of water, with an area of approximately 59,600 km2 and a 

drainage area of approximately 134,100 km2. There is a significant background mercury 

atmospheric deposition loading in the region (approximately 14 to 19 ug per m2 per year, 

which equates to approximately 6,000 to 8,000 lb/yr to the Lake Huron watershed). If all of 

the facility's permitted emissions of mercury (47 lb/yr) were conservatively assumed to 

deposit in the Lake Huron watershed, the incremental depositional impact would constitute 

only 0.6% to 0.8% of the background loading. Furthermore, the incremental impact of the 

facility relative to the background rate for Lake Huron is not reasonably expected to be as 

great as it is for the inland lakes near the source that were selected for the assessment. The 

potential impact of the facility's emissions to Lake Huron and other fisheries not included in 

the assessment will be no greater than the impact estimated for the four inland lakes 

included in the assessment. Lake Huron fish mercury levels are not currently elevated 

based on the MDEQ-Water Bureau designation of attainment status for surface waters. The 

commenter has not provided any information that would cause MDEQ to question the 

mercury impact assessment. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 29 of 140 

June 29, 2011 

Comment:

MDEQ ignored all the data on subsistence fishing by tribes in Michigan and considered only 

much lower levels of fish consumption. The level of protection MDEQ incorporated in its 

modeling is not reflective of tribal subsistence fishing and is that of an angler who only eats 

one fish meal every two weeks. MDEQ thereby violated its Rule 228 requirements. 

Response:

Rules 228 and 229(b) of Michigan's Air Pollution Control Rules authorize the MDEQ to 

conduct toxicological assessments using relevant scientific information to ensure the 

allowable mercury emissions from a proposed facility are protective of human health. The 

factors and variables the MDEQ uses in performing the assessments are based on the 

circumstances specific to the facility being evaluated. 

With regard to fish consumption rate, EPA has considered the range of fish consumption 

rates from survey data, including data regarding “subsistence” fish consumption, and 

recommended using a rate of 15 g/day for the purposes of developing chemical-specific 

water quality standards and pollutant discharge limits for the Great Lakes region.10 EPA 

determined that this rate was reasonable and provided adequate protection, while 

acknowledging that some portion of the population will consume greater than 15 g/day. The 

consumption rate of 15 g/day is approximately the average rate for the subpopulation of 

regional sport anglers and their families for the consumption of regional sport-caught fish. 

This value also approximates the 90th percentile for the entire regional population. 

Subsequently, the MDEQ Water Bureau promulgated Rule 1057 under Part 31 of NREPA 

which incorporates a fish consumption rate of 15 g/day for calculating human noncancer and 

cancer values to develop water quality standards and pollutant discharge limits. Rule 1057 

also states: “Human health values may be modified on a site-specific basis to be more or 

less stringent to reflect local environmental conditions or local human exposure.” This rule 

authorizes the use of a fish consumption rate other than 15 g/day based on site-specific 

information. 

In this case, the four inland lakes evaluated in the mercury impact assessment are privately 

owned lakes. They have no public access. The commenter has not provided any sitespecific information showing that these or other nearby lakes are used for tribal subsistence 

fishing. MDEQ determined that, for the four inland lakes that are the most impacted fisheries 

and evaluated in the mercury impact assessment, 15 g/day is an appropriate fish 

consumption rate for purposes of evaluating the impact of mercury deposition from the 

proposed facility. 

The risk assessment provided estimates of a 0.24 to 0.3 ppm background mercury level in 

fish in the lakes evaluated, and an estimate of 0.001 to 0.007 ppm incremental impact due to 

the facility long-term deposition impacts. Thus, the incremental impact is approximately 0.3 

to 3% of the background level. This estimate applies regardless of the assumed fish 

consumption rate. Therefore, if a person is assumed to consume fish at a higher 

(e.g., subsistence) rate, their mercury exposure would still be reasonably anticipated to be 

predominantly due to the background fish mercury level, not the incremental impact. 

 

10 Water Quality Guidance for the Great Lakes System, 40 CFR Part 132. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 30 of 140 

June 29, 2011 

Comment:

The cumulative risk assessment for the proposed facility does not meet the requirements of 

Rule 901, as it fails to follow guidelines recommended by EPA and the National Academies 

of Science and thus underestimates cumulative risk. 

Response:

The cumulative risk assessment the MDEQ performed to evaluate non-cancer and cancer 

effects of emitted toxic air contaminants followed USEPA and MDEQ-AQD guidance. The 

MDEQ adopted a conservative approach in which all toxic air contaminants from the 

proposed facility with an impact equal to or greater than one percent of the relevant health 

based screening level were assumed to act additively. The MDEQ calculated the hazard 

quotient (HQ) for each such toxic air contaminant. The HQs for the noncarcinogenic toxic air 

contaminants were then summed to calculate a total hazard index. As a conservative 

screening-level step, the MDEQ calculated the total hazard index for noncarcinogens by 

summing the hazard quotients of all the individual air contaminants examined regardless of 

whether they impact the same organ or have the same effect.11 Based on its analysis, the 

MDEQ correctly determined that the cumulative cancer and noncancer risks from the 

proposed facility do not pose an unacceptable risk to public health. 

The commenters cited two different reports by the National Academies of Science (NAS). In 

the first of these (“Phthalates and Cumulative Risk Assessment: The Task Ahead”), the NAS 

recommended that cumulative risk assessment should evaluate exposures to combinations 

of substances which have the same toxic effects, regardless of whether or not their 

mechanisms of action have been shown to be the same. MDEQ agrees with that 

recommendation. In the particular case of the cumulative risk assessment for the proposed 

facility, MDEQ took an even more conservative approach for noncancer cumulative risk 

assessment by combining all substances additively, whether they had the same toxic effects 

or not. The second cited NAS report (Science and Decisions: Advancing Risk Assessment) 

provided general recommendations to EPA for ways to improve cumulative risk assessments 

in the future, while noting the complexity of considering many factors simultaneously and 

recognizing the need for simplified risk assessment tools for screening-level risk 

assessments. The MDEQ's cumulative risk assessment for the proposed facility was an 

appropriate screening-level approach utilizing current EPA guidance. 

 

Additional information concerning the cumulative risk assessment is contained in the 

administrative record in the Human Health Risk Assessment Scope for the Wolverine Clean 

Energy Venture, dated August 11, 2008, and in the Addendum: Wolverine Clean Energy 

Venture (WCEV) Mercury Risk Assessment and Cumulative Risk Assessment, dated 

September 17, 2008.12 

Comment:

The draft permit will allow significant emissions of carcinogenic toxics that pose an 

unacceptable cancer risk to Michigan residents. 

 

11 The hazard quotient (HQ) for a substance is calculated by dividing the maximum ambient air impact by the 

applicable health based screening level. A hazard quotient of less than one indicates that emissions of the toxic 

air contaminant are expected to be safe. 

12 As discussed in the Human Health Risk Assessment, the background level of air toxics in the area around the 

proposed facility is not significant. The background cumulative HI is less than one for respiratory and neurological 

effects based on the background level of air toxics in Presque Isle County. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 31 of 140 

June 29, 2011 

Response:

The predicted emissions and ambient air impacts of all carcinogenic air toxics comply with 

the applicable health-based screening levels established pursuant to Michigan's Air Pollution 

Control Rules. There are no unacceptable cancer risks to Michigan residents associated 

with the proposed facility. 

Comment:

Scientific consensus exists that serious health impacts from PM2.5 occur at levels below the 

current NAAQS. The MDEQ cannot rely on compliance with PM2.5 NAAQS to satisfy its 

Rule 901 obligations, as Rule 901 applies regardless of other regulations. Indeed, MDEQ 

required a Rule 901 analysis of lead, a criteria pollutant for which full PSD analysis may be 

required, even though the facility did not trigger PSD for lead. Also, MEPA requires a 

comparison of PM2.5 impacts to health protective levels, not the 2006 NAAQS which have 

been remanded to EPA. The health impact analysis did not include the existing incidences 

of cardiovascular and cardiopulmonary disorders present in area residents that increase risk 

from particulate matter emissions. 

Response:

In 2006, EPA revised the NAAQS for particulate matter to levels required to protect the 

public health with an adequate margin of safety. As discussed elsewhere in this document, 

the ambient air near the proposed facility is in attainment with the PM2.5 NAAQS and would 

remain in attainment after conservative (i.e., high-end) potential impacts of the facility are 

taken into account. 

In establishing the revised PM2.5 NAAQS, EPA considered many comments, including those 

from the Clean Air Scientific Advisory Committee (CASAC). Correspondence from CASAC 

to EPA (September 29, 2006) indicated agreement with the setting of the 24-hour NAAQS at 

a level of 35 ug/m3, but reiterated their recommendation that the annual primary PM2.5 

NAAQS should be decreased from 15 ug/m3 to 13-14 ug/m3

. The MDEQ has not concluded 

that the PM2.5 NAAQS are inadequate standards for public health protection or that 

Rule 901 should be applied to require further reductions in allowable facility impacts of 

PM2.5. However, the potential impacts of the facility plus the impacts from other sources 

and background levels result in a maximum ambient air annual PM2.5 level of approximately 

11 ug/m3

. That concentration is below the CASAC recommended range of 13-14 ug/m3. 

Regardless of the applicability of Rule 901 or MEPA to PM2.5 emissions, the PM2.5 

emissions from the proposed facility do not cause the adverse effects listed in Rule 901 and 

do not rise to the level of pollution, impairment, or destruction of natural resources under 

MEPA. 

EPA is currently in the process of re-evaluating the PM NAAQS, as a matter of routine 

updating and assessment of the relevant studies and in response to the remand by the U.S. 

Court of Appeals for the D.C. Circuit. EPA is currently reevaluating the PM2.5 NAAQS. The 

MDEQ will ensure that future proposed facilities, like the facility proposed by Wolverine 

Power, do not cause or contribute to an exceedence of the NAAQS. 

Comment:

The facility will be a source of pollutants that cause cancer, birth defects, and other serious 

health problems at low levels of exposure. It will also emit persistent toxic pollutants that will 

contaminate the environment and will increase health burdens and accompanying social and 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 32 of 140 

June 29, 2011 

economic burdens. The MDEQ’s analysis estimates five cancer cases will be caused by the 

facility's operations, and that is too high. 

Response:

The MDEQ did not estimate that five cancer cases will be caused by the facility's operations. 

In the air toxics cumulative cancer risk assessment, the MDEQ estimated a plausible upper 

bound cumulative inhalation cancer risk of approximately five in one million for hypothetical 

individuals located at the point of maximum ambient air impact continuously for 70 years. 

The emissions and impacts will comply with all applicable regulations that are designed to 

ensure an adequate level of protection for the environment and public health. 

Comment:

The State should undertake a full analysis of the harm that may result from emissions from 

the proposed facility, including effects on the local population. The potential increase in 

harmful effects may occur across the State and in other areas where the emissions from the 

facility will travel have not been described or considered by the MDEQ. The MDEQ chose 

not to comprehensively evaluate the impacts of the proposed plant on Lake Huron or on 

many other water bodies in the region. The proposed permitted arsenic emissions could 

result in thousands of cancer cases, occurring over a period extending long into the future, 

based on the EPA cancer potency value and assuming there is no wasted dose. Arsenic 

emissions and modeling did not take into consideration existing arsenic contamination 

(including all sources of arsenic emission), assess adsorption rates, or incorporate new 

arsenic health effects information into an integrated source-receptor and exposure 

assessment. 

Response:

The predicted emissions and ambient air impacts of air toxics comply with Michigan's Air 

Pollution Control Rules. The arsenic and other air toxics emissions are approvable because 

the maximum modeled ambient air impacts do not exceed the health protective screening 

levels established by the MDEQ. In addition, the cumulative risk assessment and mercury 

impact assessment further establish that the emissions are not anticipated to be harmful to 

public health. 

The MDEQ analyzed the maximum ambient air impacts from the proposed facility and 

compared them to the applicable health based screening levels. The maximum modeled 

ambient air impacts occur relatively close to the proposed facility. At greater distances, the 

emissions are more dispersed, the ambient air impacts reduced, and the potential risks also 

meet the applicable requirements. The MDEQ's analysis demonstrates that the impacts at 

Lake Huron and other water bodies in the region meet the applicable screening levels. 

Similarly, the cumulative risk assessment and the mercury impact assessment show that the 

emissions from the proposed facility at all water bodies, including Lake Huron, do not pose 

an unacceptable risk. 

With regard to arsenic, the MDEQ's analysis of carcinogenic air contaminants included an 

assessment of the cancer risks from inhaling arsenic emitted from the proposed facility. 

Based on the applicable requirements in Michigan's Air Pollution Control Rules, the analysis 

established there is not an unacceptable inhalation risk. 

In addition, arsenic has a low potential for environmental accumulation through deposition 

and indirect pathways of exposure (such as children eating soil containing arsenic). EPA's 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 33 of 140 

June 29, 2011 

(1998) Utility Air Toxics Report to Congress included an assessment of the risks from 

deposition and indirect exposure pathways for air toxics emissions from 426 coal-fired 

utilities. The agency's analysis examined local and long-range impacts for individual facilities 

as well as cumulative impacts. For arsenic, EPA analyzed deposition and indirect exposure 

for four model facilities and found cancer risk estimates of 4 in 10 million to 1 in 10,000 (for 

the pica child, i.e., a child that is assumed to ingest significant quantities of soil). 

Background exposures were estimated to dominate the exposures and risks in all scenarios. 

The findings of the EPA study reinforce the MDEQ's conclusion that, due to the low risks to 

human health and the environment from deposition and indirect exposure to arsenic, a 

separate study to analyze the risks associated with arsenic deposition and indirect exposure 

was neither required nor appropriate. The commenters did not provided any specific 

information to show that such a study would alter the permit decision-making process. 

Comment:

A full exposure assessment, taking into consideration susceptible populations and important 

natural resources, has not been adequately carried out, leading to substantial 

underestimation of the harm that would be caused. A comprehensive cumulative risk 

assessment of human health impacts was not performed. Examples of incomplete 

evaluation include mercury transport and bioaccumulation, soil and plant contamination, 

carcinogen contamination of waterways, high fish consumption rates, children with asthma 

and other respiratory disorders, elderly residents, cumulative neurological impacts, endocrine 

disruptors, and impacts to fisheries. The addition of ANY neurotoxic heavy metal is harmful 

to those women and their children with mercury levels posing health risks. 

Response:

The MDEQ disagrees that the risk assessment was too narrowly focused. The MDEQ 

utilized health-based screening levels for air toxics, NAAQS for criteria pollutants, and a 

multi-pathway risk assessment for mercury and lead. The MDEQ also utilized U.S.EPA 

guidance for the cumulative risk assessment. 

The MDEQ performed a cumulative risk assessment for both carcinogenic and 

noncarcinogenic toxic air contaminants. The scope of the assessment was broad and used 

conservative assumptions to ensure that the cumulative risks were not underestimated. 

Among other things, the MDEQ used the maximum ambient air impacts and calculated a 

total hazard index of noncarcinogenic toxic air contaminants regardless of whether they 

impact the same organ or have the same effect. Even with these extremely conservative 

assumptions, the MDEQ determined that the cumulative risks from the emission of toxic air 

contaminants do not pose an unacceptable risk to human health. The commenter has not 

provided any specific information to show the risk assessment underestimates the harm from 

the proposed facility. 

Comment:

The coal ash can contain mercury and other heavy metals, and all landfills leak eventually. 

MDEQ has not addressed these concerns adequately. Our health and our children’s health 

is at stake. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 34 of 140 

June 29, 2011 

Response:

The regulatory review and permitting of Wolverine’s potential disposal of coal ash in a landfill 

is not within the bounds of the MDEQ’s assessment of the permit to install application for air 

emissions, and thus was not part of the review of this permit application. 

Comment:

Minor or catastrophic system failures or human errors, and probabilistic risk, should have 

been assessed in order to account for potentially increased acute and chronic health risks 

and contamination of natural resources. 

Response:

Part 55 and its rules do not require such assessment methods as part of the MDEQ's air 

toxics analysis. The permit requires Wolverine to implement a malfunction abatement plan 

to prevent, detect, and correct malfunctions or equipment failures resulting in emissions 

exceeding any applicable emissions limit. 

Comment:

Using brominated compounds to control mercury emissions trades one carcinogen for 

another. The EPA took bromine off the market because Bromo-Seltzer killed people. The 

State of Michigan has not answered questions as to how much bromine is going in, how 

much is going in the landfill and how much is going in the air. 

 

Response: 

Bromine is a naturally occurring element, present in soils at a few ppm and in seawater at 

approximately 65 milligrams per liter. Bromine is used in the manufacture of many products. 

Although breathing high concentrations of bromine (e.g., 1 ppm) can be very irritating, 

bromine is less toxic than chlorine and the acceptable occupational exposure level is 0.1 

ppm (approximately 654 micrograms per cubic meter). 

Bromo-Seltzer was in a class of tranquilizers called bromides, which were used as a pain 

reliever and sedative for heartburn, upset stomach, or acid indigestion; they were withdrawn 

from the American market in 1975 due to their chronic toxicity. The therapeutic dose of 

bromide was reportedly about 3-5 grams, and repeated doses can accumulate because the 

body’s elimination half-life is 9-12 days. Although occasional usage may have been safe, 

repeated doses as low as 0.5 -1 grams per day resulted in a risk of chronic toxic effects 

(neurological and gastrointestinal effects, and skin rash). 

Neither bromine nor mercury are inhalation carcinogens. The use of activated carbon 

injection for mercury emission control by WCEV, which may potentially include brominated 

activated carbon, was considered by MDEQ and not found to pose a significant concern for 

potential bromine emissions. The majority of the bromine would be anticipated to remain 

bound in the activated carbon and appear in the flyash. Any bromine that may off-gas and 

appear in the air emissions would be expected to have a very low ambient air impact below 

that which could pose a threat of irritancy or other adverse effects. 

Comment:

Presque Isle and surrounding counties have the highest per capita cancer rates in the State. 

It seems that most deaths in the area are caused by cancer. Information from the Detroit 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 35 of 140 

June 29, 2011 

News (detnews.com) indicates that the 2001-2005 cancer incidence rates per 100,000 

people for Presque Isle County (512.9), Alpena County (499.7) and Montmorency County 

(565.9) are higher than the Michigan rate of 499.4 or the U.S. overall rate of 468.2. 

Response: 

Nationally, about 1 in 3 people will have cancer in their lifetime, therefore, cancer incidence 

rates appear to be high to citizens everywhere. The cancer incidence statistics provided by 

the commenter indicates that the source of the data was the National Cancer Institute (NCI). 

The NCI website (http://www.cancer.gov/statistics) provides cancer incidence statistics for 

each state, but not for individual counties. Therefore, the data presented by the Detroit 

News cannot be readily evaluated using the NCI website. However, the cancer statistics for 

each county in Michigan are available at the Michigan Department of Community Health 

(MDCH) website (www.michigan.gov/mdch; select “Statistics and Reports”), and these data 

are somewhat more recent than the NCI data cited by the Detroit News. MDEQ asked 

MDCH to review the data. They reported that the 1985 – 2007 cancer incidence rates for 

Presque Isle and Alpena Counties fluctuate above and below the State rate and do not 

indicate higher mortality than the State rate. The Montmorency County cancer incidence 

rate has been higher than the State rate fairly consistently, for reasons that are not 

understood but which may involve reporting problems. 

The WCEV project emissions were evaluated for potential lifetime cumulative cancer risk. 

The point of maximum ambient air impact from the emissions was associated with a potential 

risk level of 5 in one million over a lifetime of continuous exposure. This is not considered to 

be an unacceptable incremental cancer risk under Part 55 of NREPA. 

Comment:

What are the mercury deposition estimates for Swan Lake and the Swan River downstream? 

Is bioaccumulation considered? 

Response:

The MDEQ evaluated mercury deposition and bioaccumulation impact to the Swan Lake 

watershed, resulting in facility deposition impact estimates of 0.22 grams per year to the lake 

and 9.06 grams per year to the watershed. The modeling also utilized an estimated 

background (not due to the facility) deposition rate of 6.53 grams per year to the lake and 

591.79 grams per year to the watershed. 

Comment:

Has the shifting wind direction from onshore to offshore been accounted for in the fallout 

pattern? 

Response:

The air dispersion and impact assessment utilized meteorological data that accounted for all 

conditions of wind direction, and the mercury deposition impact assessment was based on 

the dispersion modeling results. 

Comment:

How will calm wind conditions and calm wind precipitation events affect the fallout pattern 

from the stack plume? 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 36 of 140 

June 29, 2011 

Response:

Horizontal dispersion is slowed by calm wind conditions. Precipitation acts to strip many 

contaminants out of the air and deposit them. 

Comment:

Concerning mercury deposition locally and downwind, why aren’t ranges used instead of 

averages? 

Response:

Long-term accumulated mercury deposition impacts are the focus of the risk assessment, 

because mercury is persistent and bioaccumulative and has cumulative impacts within 

watersheds. Therefore, the MDEQ analyzed the impacts on water bodies and watersheds 

based on three years of meteorological data. It is unclear what additional useful information, 

if any, would be gained by utilizing ranges of impacts over time or spatial dimensions. 

Comment:

The revised permit application dated January 10, 2008, states on page 7-4: “The MMREM 

results conservatively indicate that the mercury concentrations in fish fillets from mature fish 

could increase from 0.83% to 1.25% in the target lakes.” That is a 50.6% increase. Also, 

what happened to that forecast in the September 12, 2008 revision of the Rule 228 Analysis 

for Mercury Emissions? 

Response:

As stated in the revised permit application, the range of estimated increases in mercury 

concentration in fish fillets is the estimated incremental increase in fish fillets due to mercury 

emitted from the proposed facility alone. Contrary to the commenters' suggestion, the 

percentage difference between the upper and lower end of that range (50.6%) does not 

represent the total increase in mercury concentration in fish fillets. The final revision to the 

risk assessment (September 12, 2008) included updated meteorological data (2005-2007) 

and a corrected mercury emission rate. For the four lakes evaluated, the final revision 

identifies an incremental increase of between 0.83% and 1.67% of the estimated background 

fish mercury level of 0.24 mg/kg. 

Comment:

Michigan does not have a baseline of amounts of mercury in the environment; fish data are 

inadequate and much is missing. Mercury removed from coal burning emissions is only 

moved to other places. 

Response:

Although there are gaps in the available fish mercury data, there is a substantial amount of 

environmental mercury information available that the MDEQ has compiled in several reports. 

For example, data on fish contaminant monitoring, including mercury, are compiled in MDEQ 

annual reports (http://www.michigan.gov/deq/0,1607,7-135-3313_3686_3728-32393--

,00.html), and form the basis for fish consumption advisories from the Michigan Department 

of Community Health (http://www.michigan.gov/mdch/0,1607,7-132-54783_54784_54785---

,00.html). The MDEQ Mercury Strategy Staff Report is available at 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 37 of 140 

June 29, 2011 

http://www.michigan.gov/deq/0,1607,7-135--184041--,00.html. Since mercury is an 

element, it cannot be destroyed. However, capturing and removing it from air emissions for 

disposal is an effective method for preventing release to the environment. 

Comment:

The mercury impact assessment uses incorrect average surrogate fish values of 0.24 ppm 

(for Lake Esau) and 0.30 ppm (for Grand Lake). Fish mercury data exist for Swan Lake and 

Swan River (1986 chinook data) that indicate higher levels than those in the surrogate lakes 

(6/10 fish were 0.5 ppm or above). Also, the mercury assessment did not include many 

other lakes in the area. 

In addition, the mercury impact assessment underestimated the local deposition of mercury. 

The Hubbard Brook Research Foundation of New Hampshire says that the average coal 

burning power plant has 40% reactive gaseous mercury, while the mercury assessment 

assumed 100% or 30%. DEQ assumed a dry deposition rate equivalent to the wet 

deposition rate, while the Hubbard Brook Research Foundation states that northeastern 

states have dry deposition ranging from 50% to 70% in forested areas. 

Further, using data from Pellston for background atmospheric deposition of mercury is 

questionable because Pellston is in western Michigan while Rogers City is in eastern 

Michigan, which could affect the wet / dry patterns. It is also questionable why MDEQ 

suggested the use of a background deposition rate of 17.2 micrograms per square meter on 

land and water, while also modeling with an assumption of a significantly higher background 

deposition rate on land. Some other alternative combinations of modeling assumptions 

could have been used but were not, which would have more appropriately been worst-case. 

Response:

The MDEQ did not use incorrect surrogate fish mercury values. Staff provided to the 

commenter the available fish mercury data for Lake Huron and inland waters. Included in 

that database were the 1986 Swan River Chinook salmon data (n = 10, arithmetic average = 

0.447 ppm). Those fish were not resident to Swan Lake, but were collected in the fall of the 

year in Swan River. More recent Chinook salmon mercury data for Lake Huron indicate 

average levels of about 0.1 to 0.2 ppm, although the data have not been compiled for easy 

accessibility. The Lake Huron fish mercury data indicate attainment with all designated uses, 

according to MDEQ-Water Resources Division, i.e., they do not trigger nonattainment status 

designation under the Clean Water Act. The mercury risk assessment was appropriate and 

sufficient to demonstrate that the potential facility impacts would be acceptably low and are 

permissible. 

Comment:

Are existing contaminants of concern and criteria pollutants in soils in the community 

considered in the assessment and how? 

Response:

In the case of lead, the risk assessment used a multipathway approach. This included 

estimates of exposure due to existing (background) levels of lead in topsoil, among other 

exposure pathways. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 38 of 140 

June 29, 2011 

Comment:

Neither the applicant nor the MDEQ has modeled how many people will die, be hospitalized, 

require emergency room care or will become sick because of this new facility. The modeling 

does not reflect the real consequence of issuing a permit to this facility, which will be 

increased hospitalizations and decreased quality of life. 

Response:

The regulatory requirements of the permitting process ensure public health protection. The 

requirements include meeting the National Ambient Air Quality Standards and maximum 

allowable increases for criteria air pollutants, and satisfying the MDEQ air toxics rules for 

toxic air pollutants. These requirements are designed to safeguard the public health. 

Further, the extensive risk assessments that have been performed demonstrate that the 

emissions from the proposed facility do not pose an unacceptable risk to the public health. 

In addition, the commenter has not provided any modeling to suggest that emissions from 

the proposed facility pose an unacceptable risk. 

Comment:

This particular shoreline is known for being home to a number of species protected by the 

Endangered Species Act. Any environmental impact study must determine how protected 

species will be impacted by any disruption of their habitat. 

Response:

There is no regulatory requirement for that type of assessment. The Endangered Species 

Act is implemented at the federal government. In the case of Michigan’s air permit program, 

Michigan is operating under an approved State Implementation Plan, which does not 

incorporate a review under the Endangered Species Act. 

Comment:

MDEQ has not taken the economic burden and health burden of the people now and into the 

future into equal consideration. 

Response:

MDEQ has accounted for public health concerns associated with the potential future 

operation of the facility. Part 55 and the Clean Air Act do not require an analysis of the 

economic effects of the proposed facility. 

Comment:

Pollution from coal fired power plants in Michigan has a deadly health effect on Michigan 

citizens. It is forecast that pollution from Michigan coal plants will be responsible for the 

following health impacts in the state in the year 2010 alone: 981 deaths, 1000 hospital 

admissions, 1700 heart attacks, 700 cases of chronic bronchitis, 115 lung cancer deaths, 

1500 emergency room visits, hundreds of thousands of lost work and school days, impacting 

the productivity of the state. Wolverine proposes to add particle pollution, SO2 and NOx 

pollution for the next 50 years. Allowing this additional pollution from the Wolverine plant will 

worsen the health threat already posed by pollution from coal plants and other sources in the 

state. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 39 of 140 

June 29, 2011 

Response:

The commenter describes estimates of health impacts throughout the state that may be 

associated with criteria pollutant emissions from existing coal-fired power plants rather than 

the proposed facility. The MDEQ analyzed the public health impacts of criteria pollutant 

emissions from the proposed facility alone and in combination with the existing air 

contaminants in the atmosphere and determined that the facility's emissions meet all 

applicable federal and state requirements, including those designed to protect the public 

health. 

The MDEQ has confidence that the extensive regulatory requirements of the permitting 

process ensure sufficient public health protection. These requirements include the NAAQS 

for criteria pollutants and the MDEQ air toxics rules for the toxic air pollutants, both of which 

are designed to provide sufficient public health safeguards. The risk assessments that have 

been performed for the facility’s emissions do not suggest a significant public health threat. 

Comment:

The proposed plant’s warm water discharge and pollutants would affect water quality, fish, 

and aquatic species and habitats of Michigan’s waters. 

Response:

These concerns are not part of the MDEQ review of the permit to install application for air 

emissions. They are addressed as part of Wolverine’s permitting process for surface water 

discharge. 

Comment:

Michigan’s mercury standards in fish have not been modernized. The federal EPA and FDA 

have set trigger levels of 0.3 ppm. Minnesota, Maine, and Canada have set levels of 0.2 

ppm. Michigan trails at a much less sensitive trigger level for mercury in fish. The MDCH 

advisory trigger levels are only protective for sport fishermen. The new May 2007 protocol 

for uniform Great Lakes Sport Fish Consumption Advisory limits start at 0.058 ppm and 

advise no consumption at 0.95 ppm. 

Response:

The mercury impact assessment cited both the MDEQ fish mercury value for determining 

attainment with water quality standards (0.35 mg/kg), and the Michigan Department of 

Community Health consumption advisory trigger level (0.5 mg/kg). The MDEQ value of 0.35 

mg/kg is current. The MDCH is in the process of re-evaluating their fish consumption 

advisory trigger levels, but changes have not been made. The mercury impact assessment 

demonstrates that mercury level in fish fillets at the location of greatest impact is below both 

the MDEQ and MDCH levels. Mercury emissions from the proposed facility do not pose an 

unacceptable risk to public health. 

Comment:

The modeling for mercury impact builds on a mathematical base of three lakes, all with no 

fish mercury data. The surrogate figure from Lake Esau is 0.24 ppm. This number is not an 

average or median of the Lake Esau data. Where did it come from? 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 40 of 140 

June 29, 2011 

Response:

The sample of ten smallmouth bass from Lake Esau in 2003 had a mean mercury 

concentration of 0.207 mg/kg with a 95% upper confidence limit (UCL) of 0.24 mg/kg. The 

95% UCL value was used preferentially as a surrogate value for the lakes of interest in the 

evaluation, rather than the mean, in order to better ensure that the actual levels in the lakes 

of interest would not be underestimated. This step adds conservatism to the mercury 

incremental impact assessment for the lakes of interest (i.e., it results in higher estimates of 

the potential impact of the Wolverine Power mercury emissions than would be derived if the 

mean value were used). 

Comment: 

The application and risk assessment materials make no mention of Naturally Occurring 

Radioactive Material (NORM), which could be present in the coke, and could occur at levels 

harmful to human health, particularly for workers at the proposed facility. 

Response:

There was no evidence of any amount of radium in the fuel sampling analysis done for 

petcoke. 

Comment:

The T-BACT analysis under Rule 224 and Rule 225’s health-based TAC screening analysis 

for the Draft Permit are inadequate to demonstrate protection of public health because they 

rely on AP-42 emission factors and are not clearly based on the contents of petroleum coke 

that will be burned at the facility. 

Response:

MDEQ disagrees with the commenter. A health-based TAC analysis (R 336.1225) was 

performed and based on data used in AP-42, FIRE and from the Louisiana Cleco 

Corporation application, in which the facility was permitted to burn 100% petcoke. FIRE 

does not contain any emission factors for boilers firing pet coke, therefore the Cleco 

emission factors, which were greater than the FIRE emission factors for coal, were used to 

be conservative in the TAC analysis. Emission limits were added to the permit for those 

TACs that did not initially meet the recommended health based screening levels. The 

requirement for T-BACT (R 336.1224(1)) did not apply to this project because the project 

was subject to 112(g) MACT review (R 336.1224(2)). 

Comment:

Can Wolverine assure local citizens that the clean water and air will be kept clean during the 

power plants lifetime? 

Response:

There were no unacceptable concerns identified during the review of the application for this 

project. Worst case emissions were assessed and predicted impacts were below regulatory 

threshold levels. 

This permit is limited to the activities at the source as they pertain to air emissions. 

Therefore, water related impacts were not evaluated in this permit application. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 41 of 140 

June 29, 2011 

Comment: 

The permit conditions do not specify fuel quality and testing requirements. In particular, 

trace metals and other hazardous chemicals in coke are highly variable, depending on what 

type of crude the coke came from. Thus, the health risk analyses for mercury, lead and 

other contaminants are inherently flawed, since they do not assume the full range of possible 

contaminants in the coke. At a minimum, coke should be analyzed prior to shipment, to 

ensure that contaminant levels are not above those assumed in the risk assessment. It is 

not protective of human health and the environment to rely on “end of pipe” metrics for these 

dangerous contaminants. 

Response:

Special condition VI.12 of FGCFB requires the permittee to maintain records of fuel analysis. 

1. Comments on Environmental Justice Concerns 

Comment: 

In 2007, Governor Granholm signed Executive Directive No. 2007-23, “Promoting 

Environmental Justice” (EJ Directive). The EJ Directive calls upon the MDEQ to develop and 

implement an environmental justice plan for Michigan, with the goals of identifying and 

preventing discriminatory public health and environmental effects of state laws, regulations, 

policies, and activities. Permitting of the proposed facility will have disproportionately 

harmful impacts on tribal public health and the environment. As such, MDEQ’s permitting 

action under state laws and regulations should have considered the differing and 

disproportionate impacts on tribes but it did not. 

In particular, the Human Health Risk Assessment (HHRA) did not evaluate the impacts of 

mercury and other emissions from the proposed facility on subsistence fishers. Subsistence 

fishing is a reality of tribal life and prevalent in tribal communities. The MDEQ failed to 

consider the disproportionate impact on subsistence fishers in tribal communities. In addition 

to increased pollution to waters where tribal members fish, other expected impacts include 

increased pollution affecting plant species of importance to tribes and particulate matter 

impacts on air quality disproportionately impacting on tribe members’ health. 

Response: 

The applicable legal requirements were applied equally to all groups. The extent and scope 

of the risk assessment was consistent with the environmental justice principle of preventing 

disparate adverse impacts to protected groups. The MDEQ applied a greatly expanded 

public outreach, education and comment process for this permit application consistent with 

the environmental justice principle of providing opportunities for enhanced public 

participation. 

With regard to methylmercury exposure via local fish consumption, concerns for higher rates 

of local fish consumption, including subsistence fishing, were also addressed in the risk 

assessment because the characterization of the incremental impact to fish mercury levels is 

applicable to any fish consumption rate. This is discussed in more detail in response to a 

comment regarding mercury emission and exposure concerns. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 42 of 140 

June 29, 2011 

Comment:

Is the applicant required to conduct an Environmental Justice analysis? Is there state or 

federal law requiring an Environmental Justice analysis by the applicant? 

Response:

There is no requirement for the applicant to perform an environmental justice analysis. The 

Air Quality Division strives to protect the health and welfare of all citizens of the State of 

Michigan equally. In addition, the state and federal air quality standards that have been 

established are designed to be protective for all segments of society, including the most 

sensitive. Therefore, the Air Quality Division has not attempted to determine the economic 

or racial demographics of the area, but has determined that the permit, as approved, will 

meet all applicable air quality standards. 

Comment:

The State’s Environmental Justice Plan that was finalized in December 2010 includes the 

use of the EPA’s Strategic Enforcement Adjustment Tool (EJSEAT). EJSEAT uses 18 

criteria to rank census tracts on a scale of 1 to 10, with a ranking of 1-3 indicating a relatively 

high priority for evaluation of environmental justice concerns. Rogers City has a ranking of 

“4”, and the Rogers City area will unnecessarily be pushed over the edge into a high priority 

area of concern for public health if WCEV is approved and constructed. 

Response: 

The MDEQ’s “Environmental Justice Plan” was finalized on Dec. 17, 2010

(http://www.michigan.gov/deq/0,1607,7-135-3306_51662---,00.html). The Plan presents the 

EPA’s EJSEAT method as a screening approach to identify “potential environmental justice 

areas of concern”. The report (page 9) states that for projects that require public outreach, 

enhanced public outreach activities will be implemented when the proposed project is 

located within one mile of a level 1, 2, or 3 potential environmental justice area of concern as 

identified by EPA’s EJSEAT method. A map of Michigan showing the EJSEAT ranking of 

areas is provided in Attachment 6 of the report. The WCEV facility and the impacted area 

evaluated in the risk assessment are in EJSEAT priority areas 4 and 7. Therefore, this area 

is not currently located in a potential EJ area of concern, and the commenter did not provide 

any specific information to show that the WCEV facility would result in a higher ranking in the 

EJSEAT scoring system. Even if it could be assumed that the WCEV operation could result 

in an increase in the area’s EJSEAT ranking, the ranking is only a screening approach to 

identify potential environmental justice areas of concern, not for determining when and where 

disparate impacts exist. An EJSEAT ranking of 1-3 would indicate a priority area for 

employing enhanced public outreach activities and for providing assurance that adverse 

disparate impacts would not occur. Regardless of the EJSEAT ranking of the WCEV area, 

the MDEQ has applied heightened public outreach efforts and conducted an extensive risk 

characterization to ensure that the facility will not have adverse public health impacts, 

consistent with EJ principles. 

Comment: 

The proposed facility would generate significant amounts of particulate matter, most notably 

PM2.5, which will impose an unwarranted and unacceptable health burden on the tribal 

communities in the vicinity. Pollutants that trigger asthma attacks impose a disproportionate 

burden on tribal communities. According to the Centers for Disease Control, the asthma rate 

among Native Americans is more than 50% higher than the rate among the rest of the 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 43 of 140 

June 29, 2011 

population. According to the study, published in Morbidity and Mortality Weekly Report, 

based on a 2002 survey, 11.6% of Native Americans said they suffered from asthma. This 

was significantly higher than the national average of 7.5%, and much higher than every other 

single racial or ethnic group. The draft permit, permit supporting materials, and application 

contain no consideration of the differing and unequal public health impact that tribal 

communities would bear as a result of the particulate matter pollution from the plant. 

Response: 

MDEQ has obtained and reviewed the study report that was apparently described by the 

commenter (http://www.cdc.gov/mmwr/preview/mmwrhtml/mm5307a1.htm). MDEQ relies 

upon the NAAQS for PM as the appropriate health protection benchmark for the assessment 

of the proposed facility. Attainment of the primary NAAQS is presumptively protective of the 

public health. On that basis, MDEQ has concluded that the emissions of PM from the 

proposed facility will not have an adverse impact on public health, including asthma 

prevalence among Native Americans. We are not aware of any other specific information 

that the facility emissions would aggravate asthma in the community. 

D. Dispersion Modeling 

Comment: 

MDEQ violated the Clean Air Act by granting a waiver of preconstruction monitoring 

requirements. The Act requires that preconstruction monitoring be conducted specifically for 

the purpose of PSD permitting and does not allow monitoring data gathered for a different 

purpose to be substituted. Waiver of on-site preconstruction monitoring is unjustified when 

Wolverine has stated its intent to conduct on-site monitoring for PM10 and PM2.5. In 

addition, the existing, off-site monitoring data is not representative of the air quality in the 

area of the proposed project based on monitor location, quality of the data, and currentness 

of the data. 

Response: 

Part 55, the Act and their regulations do not require the use of on-site preconstruction 

ambient air quality data gathered for the sole purpose of determining whether the proposed 

facility will exceed the NAAQS or PSD increments. 40 CFR part 51, appendix W provides 

that regional site monitors may be used to determine background concentrations near an 

isolated single source (such as the proposed facility) if there are no monitors located in the 

vicinity of the facility and additional requirements are satisfied. Rule 299(2)(d) of the 

Michigan Air Pollution Control Rules adopts by reference the standards in 40 CFR part 51, 

appendix W. 

The commenters seek to invalidate these provisions in 40 CFR part 51, appendix W. A 

challenge to a nationally applicable regulation must be filed in the U.S. Court of Appeals for 

the District of Columbia, not in this permit proceeding. The MDEQ does not have the 

authority to invalidate 40 CFR Part 51, appendix W. 

On July 27, 2007, the MDEQ granted Wolverine's request for a waiver from on-site 

preconstruction monitoring and approved the use monitoring data for sulfur dioxide, carbon 

monoxide, nitrogen dioxide, PM10 and PM2.5. Wolverine proposed to perform on-site 

monitoring for PM10 and PM2.5 and requested the use of regional monitoring data to provide 

information for PM10 and PM2.5 in case of problems with the onsite monitoring it elected to 

perform. As discussed in a separate response, Wolverine did not complete its monitoring for 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 44 of 140 

June 29, 2011 

PM10 and PM.2.5 due to technical problems and budgetary reasons. Regional site monitors 

may be used if, among other things, there are no monitors located in the vicinity of the 

source, regardless of an applicant's intent to perform on-site monitoring. 

The MDEQ granted Wolverine's waiver request because the regional monitoring data are 

representative of the ambient air quality in the vicinity of the proposed facility. The MDEQ 

considered monitor location, quality of the data, and currentness of the data in granting the 

waiver request. 

Data from regional monitor locations are sufficient to be substituted for site-specific data 

when 1) the data are representative of the subject area (i.e., the location(s) of maximum 

concentration increase from the proposed facility, the location(s) of the maximum air 

pollutant concentration from existing sources, and the location(s) of maximum pollutant 

concentration based on existing sources and the proposed facility), or 2) are likely more 

conservative than the subject area because it was collected in an area prone to higher 

concentrations (i.e., urban areas). 

The ambient air quality monitor located in Missaukee County collected data for SO2 and CO 

from 2002 through 2003 and NO2 data during 2000. This data is representative of the 

subject area in Rogers City because prevailing southwest winds transport similar regional 

background concentrations to Rogers City. Data for SO2 and CO collected in 2005 from a 

monitor located at the Seney National Wildlife Refuge (a rural location at a near latitude and 

upwind of the proposed facility) demonstrate that the Missaukee County data are 

representative of, or more conservative than, the ambient air quality of the subject area. 

Although only one year of monitoring data is required, it is MDEQ’s preferred practice to 

review the most recent three years of data from the most representative monitor and use the 

most conservative value recorded from that monitoring location as representative of the 

regional background. In rare cases, the most representative data may come from a monitor 

that has been recently decommissioned. If the most recent data from that monitor are not 

within the most recent 3-year window but are more likely to be representative than existing 

monitors from other locations, the older data may be considered for use. The factors to 

consider include: 1) whether any new significant sources of emissions have been added 

since the monitor was decommissioned, and 2) whether existing monitors from other 

locations, during the same period, show that those monitors are less representative than the 

recently decommissioned monitor. Both factors are satisfied in this case. Data from 

Missaukee County were therefore used in the determination of SO2, NO2, and CO 

background concentrations. 

In addition, data for NO2 collected during 2005 and 2006 from a monitor in Two Rivers, 

Wisconsin (also a rural, upwind location at a near latitude) confirmed that the Missaukee 

County NO2 data are both current and conservative. The NO2 data from the Two Rivers 

monitor shows a lower average annual NO2 concentration than the Missaukee County data. 

Data for PM10 collected from a monitor in Flint (an upwind urban location) may be 

substituted for site specific data because they are likely more conservative than the subject 

area. The data were collected in 2004, 2005, and 2006, and were therefore current when 

the MDEQ granted Wolverine's waiver request. 

The data from the regional monitors were collected pursuant to EPA's Ambient Monitoring 

Guidelines for PSD. Determination of background data for PM2.5 is discussed in a separate 

response. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 45 of 140 

June 29, 2011 

MDEQ disagrees that data from the existing monitoring network cannot be considered as 

representative. 

Comment: 

The modeling analysis uses inappropriate meteorological data lacking the characteristics, 

detail and quality assurance required for modern modeling applications. The reliance on 

data from the Presque Isle airstrip is unacceptable for air dispersion modeling because it is 

not site specific and omits periods of calm. 

Response: 

The MDEQ allowed the applicant to use meteorology data from the National Weather 

Service (NWS) collection monitor at the Presque Isle County airport. This NWS monitor site 

is located within one mile of the proposed facility and resides within the near-field AERMOD 

modeling grid. Therefore, MDEQ disagrees with the commenters that this data should not be 

considered as “on-site” data. EPA guidance allows an applicant to use as little as one year 

of on-site meteorology data for required modeling demonstrations. However, MDEQ 

requested the applicant use all three years of available data from this monitoring site to 

increase the reliability of predicted impacts. 

The commenters suggest that observational data collected at NWS sites are inadequate due 

to instrument exposure, location, and resolution and, thus, should not be used for air quality 

modeling studies. The siting criteria for instrument exposure, resolution, and accuracy are 

required to adhere to the standards outlined in the Federal Meteorological Handbook No. 1. 

The observational data collected from NWS stations contain necessary information that is 

routinely used in modeling, climate evaluations and real time meteorological conditions for 

the aviation industry. The collected data are input into complex NWS numerical forecast 

models which serve as a tool for the development of daily weather forecasts and are 

accurate and reliable. 

The commenters state that aircraft takeoff and landings alter the reliability of the airstrip data. 

MDEQ disagrees as this airport is comprised of a single, seldom-used runway used by small, 

non-commercial aircraft. The infrequent landings, takeoffs and idling by such aircraft do not 

result in the data being unrepresentative of the area surrounding the proposed facility. 

The commenters also state that NWS data are inadequate for air dispersion modeling 

purposes. Part of the commenter’s rationale stems from the fact that reported NWS hourly 

data at the Presque Isle airstrip are derived from 2-minute averages taken within the last 

10-minutes of every hour rather than a complete hourly average. This practice provides a 

“snapshot” image of the atmosphere for diagnostic forecasting and aviation purposes. 

40 CFR part 51 appendix W, (the Guideline on Air Quality Models) authorizes the use of 

such data from NWS reporting stations (Section 8.3.1.2). Appendix W has been adopted by 

reference in Rule 299(2)(d) of the Michigan Air Pollution Control Rules. 

The commenters also refer to the number of “calm” wind conditions contained within the 

NWS data as justification for invalidating modeling results. While it is true that when the 

NWS monitoring network was converted to the Automated Surface Observing System 

(ASOS) in the mid-1990’s, they revised the definition of “calm” as wind speeds less than 3 

knots. This policy decision resulted in annual data sets containing more reported calm hours 

than when data were manually collected. With this knowledge, EPA’s AERMOD 
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Implementation Work Group (AIWG) performed a study to determine if the increased 

frequency of calm winds in the ASOS data significantly altered the outcome of modeled 

impacts. The results of this analysis were introduced during a national EPA modeler’s 

workshop (Denver, June 10-12, 2008). The conclusion of the AIWG workgroup was that any 

perceived shortcomings of the data did not result in any unacceptable bias, and the use of 

standard ASOS data was acceptable for air dispersion modeling purposes. As a result, 

MDEQ disagrees that any additional on-site meteorological monitoring is required. 

Comment: 

The Applicant and MDEQ relied on illegal and dated draft thresholds to avoid a full Class I 

increment analysis. 

Response: 

Wolverine must demonstrate that emissions from the proposed facility will not cause or 

contribute to air pollution in excess of a PSD increment. Not all emissions cause or 

contribute to an exceedance. Insignificant, i.e., de minimis, emissions are permissible. The 

courts have determined that the permitting authority has discretionary authority under the 

Clean Air Act to exempt de minimis circumstances from review when the burdens of 

regulation yield a gain of trivial or no value. 

MDEQ has determined that emissions from the proposed facility will not cause or contribute 

to an exceedance of a PSD increment or NAAQS if they are below the Class I significant 

impact levels (SILs) proposed by EPA in 1996. The SILs are numerical values that represent 

thresholds of insignificant impacts from the proposed facility. Sources whose contributions to 

ambient concentrations in Class I areas are below such de minimis levels do not cause or 

contribute to a PSD increment exceedance, do not have a significant impact, and are not 

required to perform a comprehensive PSD increment analysis. A full Class I air quality 

analysis is not required when impacts are less than the applicable SILs. 

Comment: 

A full increment analysis is likely to show violations of, among other things, the Class I 

24-hour SO2 increment. 

Response: 

As discussed in response to the previous comment, an impact does not cause or contribute 

to an increment violation if the impact is less than the applicable SIL. Additional factors also 

make it exceedingly unlikely that proposed SO2 emissions from the proposed facility will 

cause an increment violation to a Class I area. 

First, southeast winds would be needed to transport Wolverine emissions to Seney. 

Statistical wind roses from the Presque Isle County Airport show that winds from this 

direction are among the lowest percentage winds traveling over the Rogers City area. 

Second, all Class I impact analyses and addendums were provided to the Federal Land 

Manager for review and approval. The Federal Land Manager for this project, Ms. Jill 

Webster (U.S. Fish and Wildlife Service) agreed that no violations are likely to occur: “A 

Class I modeling analysis was performed in support of the Prevention of Significant 

Deterioration (PSD) application submitted by Wolverine. This analysis assessed the impact 

to the Seney NWR due to the project. We have reviewed this modeling analysis and the 
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PSD application. Based on the information provided to us, we do not believe that the project 

will adversely impact visibility or air quality related values at Seney.” (e-mail from Jill Webster 

(USFWS) to William Campbell, ENSR, April 11, 2008). As such, MDEQ disagrees that a 

Class I increment violation is likely to occur. 

Comment: 

The Federal Land Manager failed to fully evaluate impacts on AQRVs. 

Response: 

The applicant is responsible for providing the appropriate Federal Land Manager with all air 

quality and visibility impact analyses for review and approval. Copies of the original permit 

application, visibility analyses, and all subsequent addendums pertaining to Class I impacts 

were provided to the Federal Land Manager agent, Ms. Jill Webster of the U.S. Fish and 

Wildlife Service. As discussed in the previous comment response, Ms. Webster approved all 

analyses and agreed that no violations are likely to occur: “A Class I modeling analysis was 

performed in support of the Prevention of Significant Deterioration (PSD) application 

submitted by Wolverine. This analysis assessed the impact to the Seney NWR due to the 

project. We have reviewed this modeling analysis and the PSD application. Based on the 

information provided to us, we do not believe that the project will adversely impact visibility or 

air quality related values at Seney.” (e-mail from Jill Webster (USFWS) to William Campbell, 

ENSR, April 11, 2008) 

While MDEQ was not responsible for approving this portion of the analysis, the agency was 

provided with copies of the correspondence between the applicant and the Federal Land 

Manager. 

Comment: 

Class II NAAQS and Increments – SO2, NO2, VOC, PM10; The modeling fails to take into 

account the impact of the quarry’s west wall on modeled concentrations. 

Response: 

The AERMOD modeling demonstration for all pollutants included terrain heights at all 

receptors. As such, the modeling did not fail to take into account the terrain heights along 

the quarry west wall. 

Additionally, the CFB boiler 450 stack height of 450 feet is significantly higher than the 50-80 

foot high west wall of the quarry. As such, it is unlikely that the west wall would have any 

accumulating or channeling effect upon the buoyant plume, even during light wind episodes. 

Any such effect was taken into account in the modeling by including terrain heights with each 

receptor. 

Comment: 

The modeling fails to measure total impacts from the quarry, proposed coal plant and other 

sources at receptors located on quarry property owned by Oglebay-Norton. 

Response: 

The air over secured property is considered “non-ambient” relative to that facility’s emissions 

and is excluded during the modeling analysis. As such, a separate run was made for “quarry 

only emissions” which excluded the receptors within the quarry’s airspace as non-ambient 
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but included all ambient receptors outside of the quarry airspace. The impacts from quarry 

emissions on receptors within the quarry's secured property were therefore correctly 

excluded from the modeling analysis. The analysis of impacts from non-quarry sources (i.e., 

Wolverine plus non-quarry offsite sources) correctly considered the quarry airspace as 

ambient air and included receptor impacts within the quarry airspace. To determine an 

overall impact from all sources, the maximum impacts from each of the runs were added 

together, regardless of the time and location of each run’s maximum impact. By adding the 

maximum impacts from multiple modeling runs, this is approach is more protective of air 

quality than a single run that merges all emissions together. 

It would have been difficult, but technically possible, to merge the two runs into a single, 

combined run and then manually subtract out impacts resulting from quarry emissions at 

quarry receptors. Post-processing software would have been needed to look at the each 

emission source’s contribution to each receptor on a day-by-day basis. The developed 

software would have to identify if a receptor was located within the quarry’s airspace, and if 

so, subtract the quarry’s contribution leaving only the non-quarry contributions. However, 

since adding the maximum impacts from each run is a more conservative approach to 

evaluating NAAQS and PSD increment compliance than a single, combined run, the analysis 

is acceptable if the sum of the maximums is lower than the applicable NAAQS and PSD 

increment. 

As such, MDEQ disagrees that impacts from quarry emissions within the quarry’s airspace 

should have been included in the modeling analysis 

Comment: 

MDEQ and the Applicant used inappropriately low background levels for NAAQS modeling. 

Response: 

As discussed in response to a previous comment, the MDEQ has the authority to use 

regional monitors, if no other monitors are in the vicinity. 40 CFR part 51, appendix W 

(Guideline on Air Quality Models) Section 8.2.2(c). The commenters claim the regional 

monitor data should not be used because the applicant initially proposed to perform its own 

particulate monitoring. 

Prior to receiving the monitoring waiver, the applicant proposed a plan for particulate 

monitoring in the case the waiver request was denied. Once the waiver was granted, the 

applicant was not obliged to continue with its proposed monitoring. However, the applicant 

chose to proceed with its independent monitoring plan for PM10 and PM2.5. The applicant 

ran a PM10 monitor for six months, submitted the data to the EPA and MDEQ, and did not 

(contrary to the commenters' suggestion) try to hide incriminating data. The PM10 

monitoring program was discontinued for budgetary reasons and because results were not 

significantly different than the MDEQ monitor chosen for regional background. 

The PM2.5 monitor experienced a host of technical difficulties including a lightening strike in 

early July 2007 which destroyed the monitor after three months of operation. With the 

reported difficulties, questionable quality data, and short span of data, that data were never 

submitted to EPA. Since PM2.5 modeling was not required at the time, the applicant chose 

to discontinue PM2.5 monitoring. With the short time span of monitoring (three months for 

PM2.5 and six months for PM10), there was not sufficient data to qualify for background use. 

Additionally, since the PM10 results closely resembled the chosen MDEQ regional monitor, 
Wolverine Power Supply Cooperative, Inc. 

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there was no compelling reason to override the regional monitor as representative. 

Additional explanation regarding the use of regional monitoring data is provided in response 

to a previous comment. 

Comment: 

The modeling inappropriately used annual average emissions to estimate short-term 

impacts, thus significantly underestimating short-term impacts. 

Response: 

All short-term modeling from proposed Wolverine sources were based on the worst-case, 

short-term emissions scenario. For all pollutants which had a short-term threshold, the same 

short-term emission rate was also used for long-term impacts. Emissions reporting 

requirements do not include maximum single day emissions or maximum hour emissions. 

For those offsite sources (i.e. quarry and other non-Wolverine emission sources), the only 

available data reported to the State are tons per year (tpy) and hours of operation. Offsite 

short-term emissions are derived by dividing annual emissions by the total annual hours of 

operation. 

Comment: 

The modeling is based on inappropriately low lb/hour figure for NOX from the black start 

generator that does not correspond to the draft permit limits on the black start generator. 

Response: 

Although the maximum unrestricted hourly NOx emission rate for the black start generator is 

86.4 lbs/hour, black start generator emissions are limited by a permit condition that restricts 

operation of the generator to 500 hours per 12-month rolling time period. The modeled NOx 

emission rate was “annualized” based on operation of the generator as restricted by the 

permit. The annualized NOx emission rate was derived per the following: 86.4 lb/hours x 

500 operating hours/year / 8760 total hours/year = 4.9 lbs/hour. The modeling is therefore 

based on the correct annualized lbs/hour emissions for NOx from the black start generator. 

Comment: 

The increment analysis must include emissions during startup and shutdown. 

Response: 

The increment and NAAQS analyses were based on the proposed pound per hour limits in 

the draft permit, which include emissions during startup and shutdown. 

Comment: 

The increment analysis omits emissions from haul trucks at receptors on the Carmeuse 

property. 

Response: 

New haul truck emissions, resulting from the proposed facility, were included in the 

increment analysis. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

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June 29, 2011 

Comment: 

The increment analysis omits mobile source combustion emissions from trucks and barges. 

Response: 

By administrative rule, emissions that come directly from mobile sources such as motor 

vehicles or vessels, are excluded from the increment analysis. Pursuant to Rule 1811 of the 

Michigan Air Pollution Control Rules, Wolverine must demonstrate that the allowable 

emission increases from the proposed facility, in conjunction with all other applicable 

emission increases or reduction, including "secondary emissions," shall not cause or 

contribute to an exceedance of the PSD increments. Rule 1801(pp) defines secondary 

emissions and excludes "any emissions which come directly from a mobile source, such as 

emissions from the tailpipe of a motor vehicle, from a train, or from a vessel." Emissions 

from trucks and barges were correctly excluded from the increment analysis. 

Comment: 

Combustion emissions from increased truck and barge traffic must be included in the air 

quality component of the additional impacts analysis. 

Response: 

Similar to the previous comment, the commenter wishes to expand existing broad 

regulations to include vehicle combustion emissions. The commenter uses broad definitions 

contained in State and Federal guidance to suggest that because vehicle combustion 

emissions are not specifically excluded (other than Michigan Rule 212), inclusion is 

mandated. As answered in the previous comment, emissions from trucks and barges were 

correctly excluded from the increment analysis. 

Comment: 

The Permit is based impermissibly on the illegal and unsupported use of PM10 as a 

surrogate for PM2.5 in the modeling demonstration. 

Response: 

Although not required by federal or state law, Wolverine Power Supply Cooperative, Inc. has 

requested that the MDEQ, rather than use PM10 as a surrogate for PM2.5, include an 

emission limit in the permit that reflects the best available control technology (BACT) for 

PM2.5. Wolverine submitted a “top-down” BACT assessment for PM2.5. It also submitted a 

complete air quality analysis that includes a modeling demonstration showing that emissions 

from the proposed facility will not exceed the national ambient air quality standards for 

PM2.5. The air quality analysis further shows that PM2.5 emissions will not exceed final 

NAAQS thresholds nor the increments for PM2.5 as proposed by EPA. 

Comment: 

The Applicant did not conduct site-specific preconstruction monitoring for PM2.5. 

Response: 

As explained in a previous response, the applicant applied for and received a waiver from 

preconstruction monitoring. EPA regulations, specifically 40 CFR 51, Appendix W, Section 

8.2.2(c), states that “If there are no monitors located in the vicinity of the source, a “regional 

site” may be used to determine background. A “regional site” is one that is located away from 
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Response to Comments Document 

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the area of interest but is impacted by similar natural and distant man-made sources.” 

Representative data are not always determined by which monitor is closest to the subject 

area. Although not required at the time of the applicant’s waiver request, PM2.5 background 

data were included in the original supplied data inventory. That data was collected from the 

Alpena monitor, approximately 45 kilometers southeast of Rogers City. When the applicant 

provided notice to MDEQ that they intended to go forward and perform PM2.5 modeling, a 

more detailed review was conducted to determine the most representative PM2.5 data. It 

was determined that the Alpena data was likely not the most representative regional data 

because it was over five years old and from a low percentage upwind direction. Although 

further in distance, approximately 140 kilometers from the proposed facility, the Missaukee 

County monitor was determined to be more representative of the Rogers City regional 

background because 1) the data was current; and 2) the monitor was a predominant upwind 

direction (southwest). 

Prior to receiving the waiver, the applicant made plans to monitor for PM10 and PM2.5. 

Although the granted waiver ultimately negated the necessity for onsite particulate 

monitoring, the applicant still independently installed PM10 and PM2.5 monitors. As 

discussed in response to a prior comment, the PM10 monitor ran for six months and the data 

posted to the EPA network for ambient monitoring data. The PM2.5 monitor experienced a 

host of technical difficulties and was ultimately destroyed by lightening after three months of 

monitoring and was not continued. 

As stated previously, the commenters seek to invalidate the provisions in 40 CFR Part 51, 

Appendix W that authorize the use of regional site monitors. The commenters' effort to 

challenge such nationally applicable regulations must be filed in the U.S. Court of Appeals 

for the District of Columbia, not in this permit proceeding. The MDEQ does not have the 

authority to invalidate these provisions. 

Comment: 

The Applicant’s late-submitted PM2.5 modeling contains numerous omissions and errors 

that, if corrected, would result in violations of the PM2.5 NAAQS and increments. The 

Applicant failed to base the background concentrations from preconstruction monitoring data 

and instead used an inappropriately low background concentration for PM2.5 based on 

non-representative regional site monitors. 

Response: 

The Applicant voluntarily performed dispersion modeling for PM2.5. As discussed above, 

the Applicant used background ambient air quality data from a monitor in Missaukee County 

because the data are representative of ambient air quality at the proposed facility after taking 

into account monitor location, quality of the data and currentness of the data. MDEQ has 

reviewed the dispersion modeling analysis for PM2.5, and it demonstrates that emissions 

from the proposed facility will not result in an exceedance of the NAAQS for PM2.5. The 

analysis further shows that PM2.5 emissions will not exceed the increments for PM2.5 as 

proposed by EPA. 

In addition, the Applicant applied for and lawfully received a waiver from site-specific 

preconstruction monitoring pursuant to 40 CFR 52.21, Appendix W. 
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Response to Comments Document 

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June 29, 2011 

Comment: 

The Applicant completely omitted secondary emissions. 

Response: 

EPA currently recommends that only primary PM2.5 emissions be included in NSR 

modeling. This is because of two primary reasons: First, the current near-field models for 

NSR (i.e. AERMOD) are simple Gaussian dispersion models and cannot do the chemistry 

required for secondary emissions. The continental and regional models, which include 

chemistry, are not designed for single source applications. If permitted, these sources will be 

included in the regional models for regional SIP analyses. Additionally, PM2.5 secondary 

chemistry is complex and can require hours, days, or weeks to form particulates. As such, 

the reactions occur far outside the near-field grid of the available NSR models. 

Comment: 

The Applicant used an inappropriate radius of impact. 

Response: 

The receptor grid for PM2.5 is the same as for the PM10 analysis. The applicant performed 

a “Significant Impact Analysis” for PM10 to determine the maximum distance to a significant 

impact receptor. As discussed in response to a previous comment, a facility does not cause 

or contribute to a NAAQS or increment violation where its emissions have an insignificant 

impact. It is therefore appropriate to exclude receptors outside the distance of the maximum 

significant impact receptor. Since primary PM2.5 is a subset of PM10, the significant impact 

radius can be no greater than the radius for PM10. Secondary PM2.5 emissions are not 

included in the air quality analysis. The Applicant omitted combined impacts from the 

Proposed Coal Plant and quarry at receptors on O-N quarry property. The air over secured 

property is considered “non-ambient” relative to that facility’s emissions. The impacts from 

quarry emissions on receptors within the quarry's secured property were correctly excluded 

from the modeling analysis. 

Comment:

MDEQ’s re-analysis also fails to show protection of the NAAQS and increments. 

Response: 

The commenters accuse MDEQ of “modeling away” a predicted violation of the PM2.5 

because the agency reviewed the applicant’s submitted air quality analysis and revised 

calculations that overestimated the impacts of emissions. The role of the agency is to 

determine whether the legal requirements for a proposed facility have been satisfied. In 

fulfilling that role and reviewing a permit application, the MDEQ may appropriately revise 

errors in the applicant's analysis. 

In the instance of preliminary modeling PM2.5 for 24-hour NAAQS compliance 

(September 30, 2008), the MDEQ modified some of the supplied input parameters to be 

consistent with previous PM10 modeling and performed further analysis to evaluate the 

applicant's claim of compliance. The applicant was notified that the agency modified some 

of the supplied information and was performing additional analysis. MDEQ’s additional 

analysis involved combining the separate runs together, at the maximum impact receptors, to 

determine if the overall maximum combined impacts achieved NAAQS compliance to the 

satisfaction of the agency. In the final submitted PM2.5 analysis (July 29, 2009), the 
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June 29, 2011 

applicant provided the rationale for their original emission factors, which was accepted and 

used by the MDEQ for the final NAAQS and increment results. 

The final 24-hour PM2.5 NAAQS impact, with 2005-2008 background, was 31.5 ug/m3, less 

than the threshold of 35 ug/m3. The final 24-hour PM2.5 increment impact was 7.8 ug/m3, 

less than EPA’s proposed threshold of 9 ug/m3. Annual impacts for both NAAQS and 

proposed increment were less than 80% of the thresholds. 

Comment: 

The NAAQS for PM2.5 promulgated by EPA are inadequate to protect public health, and 

Rule 901 requires comparison of PM2.5 modeling impacts to levels that are truly protective. 

Response: 

EPA set the primary NAAQS for PM2.5 to protect the public health, including the health of 

sensitive populations such as, children, the elderly, and people with asthma. It set the 

secondary PM2.5 NAAQS to protect the public welfare, including crops, trees and buildings. 

MDEQ promulgated the Part 18 rules of the Air Pollution Control Rules to ensure that new 

major emitting facilities in areas that have attained the NAAQS do not cause or contribute to 

a violation of these standards. 

Unlike the NAAQS that protect the public health and public welfare generally and take into 

account emissions from diverse mobile and stationary sources, Rule 901 addresses the 

impact of emissions from an individual facility. It prohibits a person from emitting an air 

contaminant that causes injurious effects to human health or safety, animal life, plant life of 

significant economic value, or property; or which causes unreasonable interference with the 

comfortable enjoyment of life and property. It does not authorize the establishment of 

ambient air quality standards to protect the public health at concentrations below the NAAQS 

set by EPA, nor does it authorize emission limits to achieve any such standards. 

E. Maximum Achievable Control Technology (MACT) Review 

Comment: 

The permit does not contain terms and conditions requiring maximum achievable control 

technology (MACT) for mercury and other hazardous air pollutants (HAPs). 

Response: 

A case-by-case MACT analysis was performed for mercury and all other HAPs. The Public 

Participation Documents for Wolverine Power Supply Cooperative, Inc., Permit Application 

Number 317-07 contains a “Notice of Maximum Achievable Control Technology (MACT) 

Approval.” The MDEQ performed the case-by-case MACT analysis pursuant to the federal 

regulations that implement Section 112(g) of the Clean Air Act, 40 CFR §§ 63.40 to 63.44 

and 63.50 to 63.56, that are adopted by reference in Rule 336.1299(2)(b) of Michigan's Air 

Pollution Control Rules. 

Comment: 

The Draft Permit purports to meet MACT requirements for the Proposed Coal Plant’s HAPs, 

but it does not. The Draft Permit is deficient because the MACT determination fails to 
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Response to Comments Document 

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June 29, 2011 

establish an emission limit for each HAP the Proposed Coal Plant would emit, including but 

not limited to dioxins, radionuclides and cyanide. These HAPs are ignored. 

Response: 

The permit contains emission limits for each HAP that will be emitted by the emission units at 

the proposed facility to which the MACT requirements apply: the two CFB boilers and the 

auxiliary boiler. Dioxins are organic HAPs. Dioxins are included in the VOC emission limit 

that is a surrogate for organic HAPs. Radionuclides are emitted in the form of particulate 

and are covered under the PM emission limit as a surrogate. Cyanides are inorganic HAPs 

along with HCl and HF, and are listed in the Study of Hazardous Air Pollutant Emissions from 

Electric Utility Steam Generating Units, Final Report to Congress.13 HCl and HF are the 

surrogates for acid/inorganic HAPs which includes cyanides. 

Comment: 

The MACT limit set in the draft permit for mercury does not meet stringent MACT standards. 

None of the limits are based on proper “MACT floor” analyses, nor did MDEQ undertake any 

beyond-the-floor investigation, as required. Once the MDEQ revises its MACT 

determination by performing a complete assessment of the Proposed Coal Plant’s likely 

HAPs and establishing real MACT limits for those HAPs, the MDEQ must then take a new 

look at the Project’s Best Available Control Technology (BACT) limits since the MACT limits 

for the various surrogates are based on the BACT limits. 

Response: 

MDEQ disagrees with this comment. As described in the Public Participation Documents for 

Wolverine Power Supply Cooperative, Inc., Permit Application Number 317-07, the MACT 

floors were identified and beyond-the-floor investigation was performed for each. The best 

controlled similar source(s) for all MACT limits was identified after extensive research 

through all available sources of information (relevant proposed regulations, EPA - TTN 

RACT/BACT/LAER Clearinghouse (RBLC), permitting activities in other states, literature, 

etc.) and included surveying emission limits and test results. 

Each MACT emission limit was analyzed using the appropriate procedures to meet MACT. 

The MACT emission limits are not based on a BACT analysis for the limits. In some cases, 

the MACT limit which is considered a more stringent requirement has lowered BACT limits 

for those pollutants which are surrogates and PSD/criteria pollutants. This happened with 

hydrogen fluoride (HF) which is one of the surrogates for acid/inorganic HAPs and volatile 

organic compounds (VOCs) which is the surrogate for organic HAPs. The original proposed 

BACT emission limit for HF was 0.0017 lb/MMBtu. The MACT determination resulted in 

lowering this limit to 0.0003 lb/MMBtu. For VOCs, the original proposed BACT emission limit 

was 0.0035 lb/MMBtu and the MACT determination resulted in 0.0030 lb/MMBtu. 

Comment: 

The Draft Permit does not include adequate MACT limits for each and every hazardous air 

pollutant that will be emitted by the Proposed Coal Plant. The Act requires that emission 

limits be established for each and every HAP that a facility will emit. The U.S. EPA has 

identified 67 different HAPs that are emitted by coal-fired power plants. The draft permit fails 

to do so by omitting entirely several HAPs from the list of relevant HAPs, as well as 

 

13 Study of Hazardous Air Pollutant Emissions from Electric Utility Steam Generating Units – Final Report to Congress, 

EPA-453/R-98-004a, February 1998, Volume 2, Table A-1. 
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June 29, 2011 

inappropriately grouping HAPs together and using surrogates in place of limits on the HAPs 

themselves. The MACT approval, specifically lists the following HAPs scattered throughout 

the text: mercury; the “acid/inorganic HAPs” HCl and HF; the “metal (particulate) HAPs” 

antimony, arsenic, beryllium, cadmium, chromium, lead, manganese, nickel, and selenium; 

and unnamed “organic HAPs.” Absent any specific list beyond these HAPs, this list serves as 

the only guide to the covered HAPs. 

EPA’s report to Congress lists numerous additional HAPs that are not included in the WCEV 

MACT analysis. For example, the analysis makes no mention of dioxins (“priority” HAPs 

identified by EPA), radionuclides, or cyanide, nor include any discussion of whether and how 

these pollutants are covered within the HAP categories defined or why such HAPs should be 

excluded, with appropriate technical support. 

Response: 

The permit establishes emission limits for each HAP the proposed facility will emit. The PM 

emission limit is the surrogate for metal HAPs. The VOC emission limit is the surrogate for 

organic HAPs, and HCl and HF are the surrogates for acid/inorganic HAPs. 

The application covers all regulated pollutants that will be emitted by the facility. A complete 

list is in the Public Participation Documents for Wolverine Power Supply Cooperative, Inc., 

Permit Application Number 317-07, Appendix 2, Table – Toxic Air Contaminant Impacts – 

TAC / HAP. Table 1 below identifies the HAPs in three groupings: non-mercury metal 

(particulate) HAPs, acid/inorganic HAPs, and organic HAPs. 

TABLE 1 

HAP HAP Grouping 

Mercury Mercury 

Hydrogen chloride 

Hydrogen fluoride 

Cyanide 

Acid/inorganic HAPs 

Antimony 

Arsenic 

Beryllium 

Cadmium 

Chromium, total 

Chromium, hexavalent 

Cobalt 

Lead 

Manganese 

Nickel 

Phosphorus14

Selenium 

Non-mercury metal (particulate) HAPs 

Acetaldehyde 

Acetophenone 

Acrolein 

Benzene 

Organic HAPs 

 

14 Study of Hazardous Air Pollutant Emissions from Electric Utility Steam Generating Units – Final Report 

to Congress, EPA-453/R-98-004a, February 1998, Volume 2, Table A-1. 
Wolverine Power Supply Cooperative, Inc. 

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June 29, 2011 

HAP HAP Grouping 

Benzyl chloride 

Bromoform 

Methyl bromide 

1,3-Butadiene 

Carbon disulfide 

Chlorobenzene 

Chloroform 

Cumene 

1,4-Dichlorobenzene15

Methylene chloride 

Dimethyl sulfate 

2,4-Dinitrotoluene 

Ethylbenzene 

Ethyl chloride 

Ethylene dibromide 

1,2-Dichloroethane 

Formaldehyde 

Hexane 

Isophorone 

Methyl chloride 

Methyl hydrazine 

Methyl methacrylate 

Methyl tert butyl ether 

Phenol 

Propionaldehyde 

Styrene 

Tetrachloroethylene 

Toluene 

Vinyl acetate 

Xylenes 

alpha-Chloroacetophenone 

2-Methylnaphthalene3

5-Methyl chrysene 

Acenaphthene 

Acenaphthylene 

Anthracene 

Benzo(a)anthracene3

Benzo(a)pyrene 

Benzo(b)fluoranthene3

Benzo(b,j,k)fluoranthene3

Benzo(g,h,i)perylene 

Benzo(k)fluoranthene3

Biphenyl 

Chrysene3

Organic HAPs (cont.) 

 

15 Study of Hazardous Air Pollutant Emissions from Electric Utility Steam Generating Units – Final Report 

to Congress, EPA-453/R-98-004a, February 1998, Volume 2, Table A-4. 
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June 29, 2011 

HAP HAP Grouping 

Dibenzo(a,h)anthracene3

Fluoranthene 

Fluorene 

Indeno(1,2,3-cd)pyrene 

Naphthalene 

Phenanthrene 

Pyrene 

Total Dioxin/Furan 

Methyl ethyl ketone (delisted 12-15-05) 

Methyl chloroform 

1,1,2-trichloroethane3

Bis(2-ethylhexyl) phthalate 

Carbon tetrachloride3

Dibutyl phthalate3

Hexachlorobenzene3

Methyl iodine3

Methyl isobutyl ketone3

n-nitrosodimethylamine3

Cresols3

Perylene3

Pentachlorophenol3

Phthalic anhydride3

Quinoline3

Trans-1,3-dichloropropene3

Trichloroethylene3

Vinylidene chloride3

1-methylnaphthalene3

2-chloronaphthalene3

Organic HAPs (cont.) 

Dioxins are organic HAPs. Radionuclides are covered under the surrogate PM emission 

limit. Cyanides and its chemical forms are inorganic, and are covered under the HCl and HF 

surrogacy for acid/inorganic HAPs. All HAP emissions that the boilers are expected to emit 

are appropriately covered in the permit application and limited in the draft permit. 

Comment: 

The MACT analysis is based on inappropriate grouping of HAPs and the use of inappropriate 

surrogates for each group. The Draft Permit only contains direct MACT limits for mercury, 

hydrogen chloride, and hydrogen fluoride. In addition, the MDEQ treated groups of HAPs 

together and set limits on surrogate pollutants as MACT for each group. In sum, MDEQ 

considers and purportedly includes limits on four categories of HAPs: mercury, metallic 

HAPs, organic HAPs, and inorganic HAPs. This approach both fails to set limits for all HAPs 

and unjustifiably uses surrogates for others. 

Response: 

Links and relationships were established between each surrogate and its respective group of 

HAPs. As discussed in more detail below, each of the surrogate emission limits satisfy the 

legal standard for using a surrogate pollutant for a group of HAPs: (1) the HAPs are 

invariably present in the surrogate pollutant; (2) the control technology for the surrogate 
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pollutant indiscriminately captures the HAPs along with the surrogate pollutant; and (3) the 

control for the surrogate pollutant is the only means by which facilities achieve reductions in 

emissions of the HAPs. NDRC v EPA, 353 F3d 976, 984 (DC Cir 2004); National Lime Ass'n 

v EPA, 233 F3d 625, 639 (DC Cir 2000). 

As also discussed below, the surrogate emission limits satisfy the MACT requirements 

because they are not less stringent than the emission control achieved in practice by the 

best controlled similar source and they reflect the maximum degree of reduction in emissions 

that the MDEQ, taking into consideration the cost of achieving such emission reductions and 

any non-air quality health and environmental impacts and energy requirements, has 

determined is achievable by the proposed facility. 

Comment: 

An emission limit for filterable particulate matter is not a proper surrogate for non-mercury 

metallic HAPs because it does not satisfy the legal standard for using a surrogate pollutant 

for a group of HAPs. First, HAP metals are not invariably present in particulate matter at the 

inlet to the fabric filter because some HAP metals (such as arsenic and selenium) are 

present as gases at that location. Second, particulate controls for coal plants do not 

indiscriminately capture HAP metals because they do not capture HAP metals at the same 

rate as other particulates and, instead, favor larger, non-metallic HAP-laden particles. Fabric 

filters allow most of the metallic HAPs (which exist primarily in smaller particles) to escape. 

Third, facilities achieve reductions in HAP metal emissions by means other than PM control 

such as switching fuels. In addition, switching fuels would decrease HAP metal emissions 

without a corresponding reduction in PM emissions. 

Response: 

The use of PM as a surrogate for non-mercury metal (particulate) HAPs is reasonable based 

on the criteria established by the U.S. Court of Appeals for the D.C. Circuit: (1) non-mercury 

metal HAPs are invariably present in PM; (2) PM control technology indiscriminately captures 

non-mercury metal HAPs along with other particulates; and (3) PM control is the only means 

by which facilities achieve reductions in non-mercury metal HAP emissions. National Lime, 

233 F3d at 639; Sierra Club, 353 F3d at 984. 

First, PM generated by coal-fired combustion units invariably contains metal HAPs. 

Bituminous and subbituminous coals can contain antimony, arsenic, beryllium, cadmium, 

chromium, cobalt, lead, manganese, nickel, and selenium.16 These metal HAPs are 

released when coal is combusted. In elemental form, most of these metal HAPs have boiling 

points greater than 1,000oF. The exceptions are lead with a boiling point of approximately 

620oF and selenium with a boiling point of approximately 420oF.17 The exhaust gas 

temperatures in the fabric filter will be approximately 200oF. At these temperatures, metal 

HAPs will be solid and in a particulate form that can be removed from the exhaust gases 

prior to discharge out of the stack. Research on bituminous and subbituminous coals has 

shown that trace metallic element concentrations in the fly ash fraction exist in both PM <2.5 

μm and PM >2.5 μm. Measurements of PM from fabric filters indicate collection efficiencies 

of greater than 99% for particulates with diameters of 0.02 to 10 μm. For the bituminous and 

 

16 Study of Hazardous Air Pollutant Emissions from Electric Utility Steam Generating units – Final Report to Congress, 

EPA-453/R-98-004a, February 1998, Volume 2, Table A-1. 

17 CRC Handbook of Chemistry and Physics, 53rd Edition, 1972-1973. 
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subbituminous coals analyzed, 4 to 7% of the particulate matter from fabric filters was <2.5 

μm while the remainder was >2.5 μm.18 

Second, the PM control required by the proposed permit (a fabric filter) indiscriminately 

captures non-mercury metal HAPs along with other particulates, regardless of whether the 

fabric filter does not capture PM and some non-mercury metal HAPs at the same rate. 

When the fabric filter removes PM, non-mercury metal and particulate HAPs are also 

removed. 

Third, the commenter does not identify any similar sources that, by switching fuels, achieve 

reductions in non-mercury metal HAPs emissions without a corresponding reduction in PM 

emissions. Similarly, the MDEQ has not identified any such sources. PM is the only means 

by which similar sources achieve reductions in the emission of non-mercury metal HAPs, 

regardless of the potential variability of non-mercury metal HAPs in different fuels. The 

criteria for the reasonable use of PM as a surrogate for non-mercury metal HAPs is satisfied. 

U.S. EPA has used filterable PM as a surrogate for non-mercury metal HAPs from various 

source categories, including glass manufacturing facilities, chemical manufacturing areas, 

and mineral wool production facilities. 72 Fed Reg 73,180 (Dec. 26, 2007); 72 Fed 

Reg 38,884 (July 16, 2007); 64 Fed Reg 29,491 (June 1, 1999).19 Other states have used 

filterable PM as a surrogate for HAP metal emissions in their case-by-case MACT 

determinations.20 

Comment: 

MDEQ’s proposal to group together all organic HAPs from the Proposed Coal Plant and use 

VOCs as a surrogate is unsupported and VOC is not a proper surrogate for the organic 

HAPs group. There is no explanation of whether or how the “organic HAPs” grouping is 

appropriate. In fact, the behavior of the various organic HAP compounds are dissimilar in 

terms of, for example, how some are formed and their fate after leaving the boiler. There are 

also different classes of organic HAPs (volatile, semi-volatile, and particulate compounds) 

that behave differently during combustion. In addition, VOC control does not indiscriminately 

capture organic HAPs, and facilities achieve reductions in organic HAP emissions by means 

other than VOC control. VOC cannot be a surrogate for HAPs. 

Response:

VOCs are an appropriate surrogate for organic HAPs based on the three-part legal standard 

for surrogates. First, all organic HAPs from the proposed facility are invariably present as 

VOCs. As explained in the Public Participation Documents, organic HAPs are a subset of 

VOCs and are produced during the combustion of coal. Second, organic HAPs and VOCs 

are produced as a result of incomplete combustion. Good combustion practices that 

promote complete combustion of coal in the boiler is an effective pollution control measure 

 

18 Comparison of Particle Size Distributions and Elemental Partitioning from the Combustion of Pulverized Coal and 

Residual Fuel Oil, Journal of the Air & Waste Management Association, Volume 50, August 2000, pp. 1532 – 1544. 19 EPA also used filterable PM as a surrogate for HAP metals in its MACT standard for Industrial/Commercial/Institutional 

Boilers and Process Heaters. 69 Fed Reg 59,218 (Sept. 13, 2004). Although the standard was vacated by U.S. Court of 

Appeals for the D.C. Circuit, the court's ruling was not based on the use of filterable PM as a surrogate. 489 F3d 1250 

(DC Cir 2007). 

20 See e.g., Georgia Dept. of Nat. Res., Environmental Protection Division, Notice of MACT Approval for Longleaf Energy 

Associates, LLC (June 2009); South Carolina Dept. of Health and Env. Control, Bureau of Air Quality, Final Determination 

and Final Notice of MACT Approval for Santee Cooper Pee Dee Generating Station (Dec 16, 2008).
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for VOCs and indiscriminately captures both VOCs and organic HAPs. Third, similar sources 

do not use means other than good combustion practices to control organic HAPs. 

Comment: 

There are pollution-control methods that would reduce the Proposed Coal Plant’s organic 

HAP emissions without producing a corresponding reduction in the plant’s VOC or CO 

emissions. Combustion optimization will increase some organic HAPs, reduce some organic 

HAPs, and have no effect on other organic HAPs. Other VOC controls, such as substituting 

alternative fuels (natural gas, or distillate oil) would reduce organic HAPs at a far higher rate 

than they would reduce carbon monoxide. 

Response:

The MDEQ has not identified any similar facilities that employ such other means and the 

commenter has not identified any such facilities. Other similar facilities use good combustion 

practices to reduce organic HAP emission regardless of the type of fuel combusted. 

 

Comment: 

The Draft Permit proposes to require as a surrogate a VOC limit that is subject to only 

periodic (annual) stack testing. Such stack testing is further evidence that VOC is an 

improper surrogate because, measured occasionally, VOC emissions lack the necessary 

indiscriminating correlation with organic HAP emissions. Organic HAPs that are caused by 

incomplete combustion can be produced in large quantities during short "hot spot," 

incomplete-combustion events, such as burner malfunction, startups and shutdowns. 

Infrequent stack testing likely occurs outside of these periods and fails to capture the organic 

HAP emissions during these "hot spot" events. The periodic testing further demonstrates 

that VOCs are not an appropriate surrogate for organic HAP emissions. 

Response:

Periodic stack testing of VOC emissions is only one permit requirement to ensure good 

combustion practices. CO is formed as a result of incomplete combustion of a hydrocarbon 

fuel. The permit requires that Wolverine demonstrate good combustion control by 

continuous monitoring of CO emissions. Continuous monitoring of CO emissions is used to, 

among other things, reduce the air to fuel ratio to ensure the maximum combustion of fuel, 

which in turn ensures minimum VOC emissions, including organic HAPs. In addition, 

continuous monitoring of CO assures minimization of organic HAP emissions at all times. 

Comment: 

VOC cannot be used as a surrogate for organic HAPs because the MDEQ has not shown 

that more specific, tailored limits for organic HAPs are not feasible. The applicant should be 

required to set limits upfront on individual HAPs and organic HAP subgroups and conduct 

post-construction testing (particularly for cyanide and dioxins) and revise limits as 

appropriate. 

Response:

The feasibility of limits tailored to organic HAPs is not the legal standard for determining 

whether it is reasonable to use a surrogate emission limit for a group of HAPs. As discussed 

previously, the U.S. Court of Appeals for the D.C. Circuit has established a three-part legal 
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standard for using surrogates. The MDEQ has satisfied that standard in using VOCs as a 

surrogate for organic HAPs. 

The VOC emission limit is the surrogate limit for organic HAPs. Post-construction testing is 

required to demonstrate compliance with that limit. Given the lack of individual limits for 

each organic HAP, stack testing for individual organic HAPs is not required. The individual 

HAPs that will be emitted from the proposed facility and that are included in the organic 

HAPs group are listed in Table 1. 

Comment: 

Any surrogate MACT limit for VOC must be based on a short-term average, on the order of 

one hour. Compliance with periodic stack tests of VOC, as is currently required by the 

permit, will not protect against very high organic HAP emissions that can occur over short 

periods. 

Response:

The averaging time is defined by the test protocol as required by Rule 1003(5) of Michigan's 

Air Pollution Control Rules. That rule states: “Minimum sample time shall be 60 minutes, 

which may be continuous or a combination of shorter sampling periods for sources that 

operate in a cyclic manner.” Compliance with the VOC emission limit will therefore be based 

on a short-term average. As for “very high organic HAP emissions that can occur over short 

periods,” spikes in organic HAP emissions will be minimized because good combustion will 

be monitored continuously through CO emissions. 

Comment: 

For acid/inorganic HAPs and HCl/HF as surrogates, MDEQ must confirm whether cyanides 

are considered as part of the inorganic HAPs group or some other group/surrogate. If 

cyanides are not considered as part of any of the groups, MDEQ must address this omission 

before issuing a revised permit. 

Response:

Cyanides are considered inorganic compounds. The surrogates for cyanides are HCl and 

HF. Cyanides will be controlled using the same reduction techniques used for HCl and HF, 

and reduction in HCl and HF emissions will be indicative of reductions in cyanides. 

Comment: 

MDEQ failed to properly assess the MACT floor for each HAP. The permit limits do not 

constitute MACT, as they are not based on the emissions achieved in practice by the best 

controlled similar source. Neither Wolverine nor the MDEQ has correctly identified the “best 

controlled similar source” for each of the HAPs emitted by the WCEV. MDEQ inappropriately 

narrowed the universe of “similar source,” resulting in MACT limits impermissibly based on 

the Applicant’s preferred configurations and control strategy for meeting BACT requirements. 

Response:

"Similar source" is defined in both the federal regulations and Michigan's Air Pollution Control 

Rules as "A stationary source or process that has comparable emissions and is structurally 

similar in design and capacity to a constructed or reconstructed major source such that the 
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source could be controlled using the same control technology." 40 CFR 63.41; 2008 AACS, 

Rule 299(2)(b). 

The MDEQ identified the best controlled similar source for all MACT limits after extensive 

research. The MDEQ's review included a thorough search of emission limits and test 

results, EPA's TTN RACT/BACT/LAER Clearinghouse (RBLC), proposed regulations, and 

literature. Information from over 70 power plants, including PC boilers and CFB boilers, was 

surveyed in the MACT determination. As discussed below, the MDEQ correctly established 

MACT limits for the HAPs to be emitted from the proposed facility. 

Comment: 

The MDEQ does not “make a reasonable estimate of the performance” of the bestcontrolled unit in the appropriate category, but references only a select few other power 

plants for all of the HAPs in question. While several plants are addressed for mercury alone, 

the only comparison for all the other HAPs (albeit with regard to inappropriate surrogates) 

appears to have been the JEA Northside plant in Florida. This limited citation and failure to 

compare sources in the determination itself is insufficient to set MACT. In other words, the 

agency started with the applicant’s proposed boiler and the fuel selected by the applicant for 

the mercury MACT analysis (notably only one of the many fuels the boiler will be capable of 

burning) and eliminated any sources that did not fit that exact configuration. This narrowing is 

arbitrary and capricious. 

Response:

Information from over 70 power plants was surveyed for best controlled similar sources and 

used in the MACT determination. Four sources were highlighted as best for a number of 

different HAPs. A large source pool of information was developed to compare sources for 

the MACT determination that was sufficient. 

PC boilers burning bituminous and subbituminous coal, and petroleum coke (not an “exact 

configuration”) were not omitted or eliminated from the MACT determination. For the 

mercury emission limit and other MACT limits, all possible fuel combinations had to be 

evaluated and the emission limit assessed for continuous compliance under all operating 

scenarios. This is not a “narrowing” that “is arbitrary and capricious,” but a broad analysis to 

derive an emission limit. 

Comment: 

The MACT limit may not be based on the worst case fuel for each HAP or group of HAPs. 

MACT requires a limit reflecting the maximum degree of reduction in emissions, where 

“process changes” and “substitution of materials” must be considered as control options. 

Using a different fuel qualifies as a process change and/or substitution of materials. Where, 

as here, a source is entirely capable of burning a range of fuels, it is wholly inappropriate to 

base MACT on the worst possible fuel for each HAP or group of HAPs. 

Response:

The CFB boilers are designed and capable of burning a range of different fuels. The type 

and amount of fuel combusted in the CFB boilers is closely tied to availability (e.g., 

transportation, cost, growing seasons, etc.). In addition, the permitted operation of the units 

is for a blend or variety of fuels to be fired at any given time. The MACT determination was 
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based on the maximum achievable control for the types of fuels proposed to be combusted 

while maintaining fuel flexibility as a practical consideration. 

Comment: 

It is appropriate to set separate MACT limits for each fuel – i.e., PRB coal, Illinois bituminous 

coal, pet coke, and biomass. 

Response:

Setting separate limits was evaluated and deemed impractical for CFB boilers designed for 

fuel flexibility. Also, setting a limit specific to each fuel type may not result in additional 

reductions in HAPs because the type of fuel that will be combusted in the boiler will be 

determined based on availability. 

Comment: 

MDEQ also improperly selected purportedly appropriate control technologies based on the 

Applicant’s proposal, and calculated emissions limits based on the expected performance of 

these technologies. While control methods and technologies are part of the MACT analysis, 

the MACT floor is not set by reference to particular technologies. The MDEQ must base its 

limits on the actual emissions of the best controlled existing source. 

Response:

The MDEQ based its MACT floor determinations on the actual emissions (i.e., data from test 

results) for each best controlled similar source. In addition, the MACT emission limits need 

to account for variability in fuels and corresponding performance in the pollution controls to 

assure the emission limit represented by the best controlled similar source can be achieved 

consistently. To ensure the MACT emission limits are based on realistic operation rather 

than solely on test results from stack tests performed under optimum conditions, the MDEQ 

used safety factors in calculating the limits. The safety factors take into account the fuel 

characteristics and variability in the anticipated performance of the pollution controls for 

mercury and the HAP surrogates. Also, if test data does not fully represent the source or is 

very scarce, safety factors are adjusted to account for the quality and quantity of data used 

to establish the MACT emission limit. Safety factors are calculated based on the statistical 

variability of the data available. 

Comment: 

The MDEQ’s proposed MACT limit for non-mercury metallic HAP is a filterable PM10 

emission limit of 0.010 lb/MMBtu, based on an unspecified averaging time to be determined 

later in a test protocol. Even if all of the other portions of the analysis were acceptable, the 

lack of averaging time renders this MACT determination deficient. 

Response:

The averaging time is defined by the test protocol as required by R 336.2003. Specifically, 

“Minimum sample time shall be 60 minutes, which may be continuous or a combination of 

shorter sampling periods for sources that operate in a cyclic manner.” This meets the 

requirements of the NSR Manual for a “reasonable averaging time in order to be 

enforceable.” 
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Comment: 

The proposed limit of 0.010 lb/MMBtu is greater than the MACT floor. A stack test at Santee 

Cooper’s Cross Unit 3 showed filterable PM10 emissions of 0.0099 lb/MMBtu in January 

2008. As the PPD notes, even the highest PM emission level from JEA Northside, Unit 1 

while burning 75% petroleum coke and 25% coal (a blend very close to that identified by 

Wolverine as its “design fuel”), 0.0091 lb/MMBtu, is below the proposed MACT limit for 

Wolverine. The PM10 MACT floor should be no greater than 0.006 lb/MMBtu, based on a 

3-hour average, or roughly 40% lower than the limit proposed by the MDEQ as MACT. 

Response:

The proposed limit and the test results of 0.0099 lb/MMBtu and 0.0091 lb/MMBtu are within 

the range of the test method accuracy and are basically similar numbers. The emission limit 

is stringent but not so stringent that it can not be achieved continuously. This was 

determined based on the fact that JEA Northside for example has emission tests 

demonstrating lower particulate emission rates under a variety of operating conditions as 

evidence that the emission limit can be achieved on a continuous basis. The commenter’s 

proposed limit of 0.006 lb/MMBtu does not contain an acceptable factor of safety that would 

assure continuous compliance. 

Comment: 

The lowest BACT limits for CO of 0.15 lb/MMBtu (based on a 30-day average) and a VOC 

limit of 0.003 (based on an unspecified test protocol) are inappropriate for MACT. 

Response:

CO is not proposed as a surrogate for organic HAPs, therefore the CO emission limit was not 

part of the MACT determination. The VOC limit is the surrogate for organic HAPs, and the 

test protocol will be specified and approved because the draft permit requires submission of 

an approvable test plan before compliance testing. 

The proposed VOC limit of 0.003 lb/MMBtu could have been explained better. VOC 

emissions from combustion sources are related to the organic content of the fuels 

combusted and good combustion practices. VOC emissions are uncontrolled and can 

fluctuate widely, therefore making it difficult to assess an emission limit. Typically, the 

organic content of subbituminous coal is higher than bituminous coal, and petroleum coke 

has a lower organic content than coal. The highest organic content fuel that Wolverine is 

proposing to combust is the biomass. Data is limited for VOC emissions from all of the fuels 

that Wolverine is proposing to combust. Decisions on the VOC emission limit for Wolverine 

were mainly based on the performance of JEA Northside which combusts bituminous coal 

and petroleum coke, two of the lower organic content fuels. The two CFB boilers at JEA 

Northside had measured VOC emissions of approximately 0.0014 lb/MMBtu when 

combusting a blend of 90% petroleum coke/10 % coal. This emission rate was higher than 

the VOC emission rate of 0.00025 lb/MMBtu measured when combusting a blend of 70% 

petroleum coke/30 % coal. The blend of 70% petroleum coke/30 % coal should contain a 

higher organic content, and in theory result in higher VOC emissions. In contrast, when 

combusting 100% coal, unit #1 had VOC emissions of 0.0023 lb/MMBtu measured at 104% 

of allowed process rate and unit #2 had VOC emissions of 0.000016 lb/MMBtu measured at 

92% of allowed process rate. Since VOC emissions were unpredictable and based on lower 

organic content fuels, a conservative 0.003 lb/MMBtu was assessed for the VOC emission 

limit which represents a 30% factor of safety over JEA Northside’s highest VOC test while 

combusting coal. 
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June 29, 2011 

Comment: 

The MDEQ has proposed an HCl limit of 0.0011 lb/MMBtu, with an unspecified averaging 

time. The lack of an averaging time makes this a deficient and unenforceable permit limit. 

Also, for the purpose of setting the HCl limit, Illinois bituminous coals was considered to be 

the appropriate fuel, despite the fact that it is intended to be a secondary fuel used when pet 

coke and PRB are limited due to market conditions. This was done simply to obtain the 

highest limit possible, as Illinois bituminous coal contains the highest chlorine content of the 

considered fuels. The fuel on which the limit is based thus has little relationship to how the 

Proposed Coal Plant will actually operate, making the limit a sham. 

Response:

The averaging time is defined by the test protocol as required by R 336.2003. Specifically, 

“Minimum sample time shall be 60 minutes, which may be continuous or a combination of 

shorter sampling periods for sources that operate in a cyclic manner.” The limit is sufficient 

and enforceable. The limit of 0.0011 lb/MMBtu encompasses the fact that CFB boilers are 

designed and capable of burning a range of different fuels. The type and amount of fuel 

proposed to be combusted in the CFB boilers are closely tied to availability (e.g., 

transportation, cost, growing seasons, etc.) In addition, the intended operation of the units is 

for a blend of fuels to be fired at any given time. The MACT determination was based on the 

maximum achievable control for the types of fuels proposed to be combusted while 

maintaining fuel flexibility as a practical consideration not “simply to obtain the highest limit 

possible.” 

Comment: 

The HCl and HF limits appear to be based on specific controls with no proof as to the basis 

for the 95% control claim. No design details for the controls are provided that would support 

such a removal efficiency. While such efficiencies are possible, the relevant design 

parameters should be specified. 

Response:

The 95% is based on the best conceptual design for the specific control strategy that is 

required via permit condition. The engineering design and design-to-build drawings have not 

been completed for the source so specific design details are not available. 

Comment: 

The MACT floor should be the lowest limit that is achievable regardless of fuel, as fuel 

selection is one of the controls for HAPs (“process changes,” “design,” and “substitution of 

materials” are pollution-reduction methods that must be assessed as part of a MACT 

determination). Other states have performed MACT analyses for similar sources and 

concluded that MACT is much lower than inferred here for the Proposed Coal Plant. 

Kentucky established a MACT limit for hydrogen chloride of 0.000825 lb/MMBtu in October 

2002 for a bituminous coal fired pulverized coal fired boiler. 

Response:

Determination of the MACT floor has to take into account fuel. For example, acid gas 

emissions from the combustion of natural gas are different from acid gas emissions due to 

coal combustion. What is being combusted is very important in a MACT determination for a 
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combustion source. The statement that “the MACT floor should be the lowest limit that is 

achievable regardless of fuel” is incorrect and would lead to an unenforceable limit. 

Thoroughbred Generating Station, in Kentucky, will have a wet FGD and wet ESP, and is not 

strictly speaking a similar source. Since these units are not operating, the HCl emission limit 

of 0.000825 lb/MMBtu has not been achieved in practice. 

Comment: 

Stack testing indicates that similar sources routinely achieve lower hydrogen chloride 

emissions. The Gilbert Unit 3 circulating fluidized bed boiler achieved a hydrogen chloride 

emission level of less than 0.000056 lb/MMBtu while burning bituminous coal. The U.S. 

Department of Energy measured hydrogen chloride emissions from 16 different coal burning 

boilers, including with and without various control options, such as reburn, low NOX burners 

and selective noncatalytic reduction. This study demonstrated that several of the facilities 

emitted lesser amounts of hydrogen chloride than proposed here, over a decade later, as 

MACT. These include Springerville (less than 0.000176 lb/MMBtu), Yates (0.000742 

lb/MMBtu), Bailly (0.00102 lb/MMBtu), Burger using SNCR (0.00077 lb/MMBtu), Arapahoe 

uncontrolled (0.000630 lb/MMBtu), Arapahoe using SNCR (0.000720 lb/MMBtu), and 

Shawnee using lime injection with fabric filters (less than 0.000073 lb/MMBtu). 

Response:

Testing results for HCl emissions from sources that could be identified as similar to 

Wolverine’s CFB boilers are limited. And, stack test results represent limited data and may 

not demonstrate the variability of chlorine in coal and the variability of operating conditions. 

The testing information listed by the commenter does not establish that these are similar 

sources or that the HCl emissions are consistently achieved in practice. Gilbert, Unit 3 

combusts a run-of-mine eastern bituminous which is not similar to any fuel Wolverine is 

proposing to combust. Gilbert is not a similar source based on fuel. 

Stack testing is a measure of performance, but the MACT emission limit should not be set at 

the lowest single test result ever achieved by a best controlled similar source, and when 

working with small sets of source test data to assess an emission limit, an appropriate safety 

factor needs to be assessed. 

Based on available information, it appears that the MACT emission limit for HCl for 

Wolverine’s two proposed CFB boilers is appropriate without being too overly conservative. 

Comment: 

The MDEQ has proposed an HF limit of 0.0003 lb/MMBtu, with an unspecified averaging 

time. The lack of an averaging time makes this a deficient and unenforceable permit limit. As 

with HCl, Illinois bituminous coals was considered to be the appropriate fuel. Again as with 

HCl, this selection was made simply to obtain the highest limit possible and has little direct 

relationship to how the Proposed Coal Plant will actually operate. 

Response:

The averaging time is defined by the test protocol as required by R 336.2003. Specifically, 

“Minimum sample time shall be 60 minutes, which may be continuous or a combination of 

shorter sampling periods for sources that operate in a cyclic manner.” The limit is sufficient 
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and enforceable. The HF limit encompasses the fact that CFB boilers are designed and 

capable of burning a range of different fuels. The type and amount of fuel proposed to be 

combusted in the CFB boilers are closely tied to availability (e.g., transportation, cost, 

growing seasons, etc.) In addition, the intended operation of the units is for a blend of fuels 

to be fired at any given time. The MACT determination was based on the maximum 

achievable control for the types of fuels proposed to be combusted while maintaining fuel 

flexibility as a practical consideration not “simply to obtain the highest limit possible.” 

Comment: 

The MACT floor should be the lowest limit that is achievable regardless of fuel, as fuel 

selection is one of the controls for HAPs. Other states have performed MACT analyses for 

similar sources and concluded that MACT for HF is much lower than Wolverine’s HF limit. 

West Virginia issued a permit for the Longview facility, two CFB boilers that will burn 

bituminous coal, with a hydrogen fluoride limit of 0.00001 lb/MMBtu. 

Response:

Determination of the MACT floor has to take into account fuel. For example, acid gas 

emissions from the combustion of natural gas are totally different from acid gas emissions 

due to coal combustion. What is being combusted is very important in a MACT 

determination for a combustion source. 

Also, Longview is a proposed pulverized coal-fired boiler not two CFB boilers. The plant has 

not been built, and therefore the HF emission limit has not been demonstrated as achieved 

in practice nor is the source considered similar to Wolverine’s proposed CFB boilers. 

Comment: 

Stack testing indicates that similar sources routinely achieve lower hydrogen fluoride 

emissions. The Gilbert Unit 3 circulating fluidized bed boiler achieved a hydrogen fluoride 

emission level of less than 0.000056 lb/MMBtu while burning bituminous coal. The JEA 

Northside circulating fluidized bed boilers tested at less than 0.0000309 lb/MMBtu while 

burning 100% Pittsburgh 8 coal; at 0.0000169 lb/MMBtu while burning a 50:50 blend of coke 

and Pittsburgh 8 coal; at 0.00004582 lb/MMBtu while burning 100% Illinois 6 coal; and at 

less than 0.0000053 lb/MMBtu while burning a blend of 80% coke and 20% Pittsburgh 8 

coal. 

Further, the U.S. Department of Energy measured hydrogen fluoride emissions from 16 

different coal burning boilers, including with and without various control options, such as gas 

reburn, low NOX burners and selective noncatalytic reduction. This study demonstrated that 

several of the facilities emitted lesser amounts of hydrogen fluoride than proposed here, over 

a decade later, as MACT. These include Springerville (<0.000092 lb/MMBtu), Yates 

(0.000122 lb/MMBtu), Nelson Dewey (0.000067 lb/MMBtu), Burger using SNCR (0.000039 

lb/MMBtu), and Shawnee using lime injection with fabric filters (<0.000023 lb/MMBtu).

Response:

The testing information from the U.S. Department of Energy listed by the commenter does 

not establish that these are similar sources or that the HF emissions are consistently 

achieved in practice. Gilbert, Unit 3 combusts a run-of-mine eastern bituminous which is not 

similar to any fuel Wolverine is proposing to combust. Gilbert is not a similar source based 

on fuel. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 68 of 140 

June 29, 2011 

Stack testing is a measure of performance, but the MACT emission limit should not be set at 

the lowest single test result ever achieved by a best controlled similar source, and when 

working with small sets of source test data to assess an emission limit, an appropriate safety 

factor needs to be assessed. 

As for the proposed HF emission limit, the stack testing results from JEA Northside were 

revisited. Again, emission limits should not be set at the lowest single stack testing result 

ever achieved, and JEA Northside has had higher emissions of HF. Unit #2 had HF 

emissions measured at 0.261 lb/hr (equivalent to 0.00010 lb/MMBtu) while combusting 100% 

petroleum coke, and while combusting 100% coal, HF emissions were measured at 0.290 

lb/hr (equivalent to 0.00011 lb/MMBtu). It is appropriate to lower the proposed HF emission 

limit for Wolverine’s CFB boilers to 0.00014 lb/MMBtu which provides a 30% factor of safety. 

Comment: 

The MDEQ established the MACT limit for mercury as 0.0077 lb/GW-hr on an annual 

average basis, using the mercury content of PRB coal. This limit is equivalent to 0.882 

lb/TBtu, in terms of heat input. 

The one glaring flaw in the calculated limit relates to the use of PRB coal as the basis. The 

WCEV is expected to use as its fuel up to 70% pet coke, a fuel with very low mercury 

content. WCEV has every incentive to use as much pet coke as allowed under the permit 

given the far lower cost of pet coke as compared to other fuels. However, the mercury limit 

assumes that, on an annual basis, PRB coal will be used at all times. It is clear that the 

mercury limit is significantly over-estimated. As discussed earlier, without conceding that the 

MACT limit must be set on the cleanest fuel for mercury, separate mercury limits at least 

should be developed for each proposed fuel. The annual average mercury limit should then 

reflect the actual proportion of fuels used and their respective limits. 

Response:

As stated earlier, CFB boilers are designed and capable of burning a range of different fuels. 

The type and amount of fuel proposed to be combusted in the CFB boilers are closely tied to 

availability (e.g., transportation, cost, growing seasons, etc.) In addition, the intended 

operation of the units is for a blend of fuels to be fired at any given time. The MACT 

determination was based on the maximum achievable control for the types of fuels proposed 

to be combusted while maintaining fuel flexibility as a practical consideration. There is no 

“glaring flaw” in the use of PRB coal as the basis of the mercury emission limit. Mercury 

emissions from the combustion of PRB coal are expected to be the hardest to capture and 

control, and are dependent on the effectiveness of the sorbent injection system. Wolverine’s 

CFB boilers were evaluated to combust up to 100% PRB/subbituminous coal. Setting 

separate limits was evaluated and deemed impractical for CFB boilers designed for fuel 

flexibility. Also, setting a limit specific to each fuel type may not result in additional 

reductions in HAPs because the type of fuel that will be combusted in the boilers will be 

determined based on availability. 

Comment: 

If a more thorough analysis had been conducted by the MDEQ, it would have discovered that 

the best controlled similar source to the Proposed Coal Plant is the Reliant Energy Seward 

unit, a CFB boiler whose mercury emissions have been tested at 0.03 lb/TBtu. At this rate, 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

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June 29, 2011 

each of the proposed coal plant units would have a mercury emission rate of approximately 

0.8 lb/year, instead of the proposed 23.4 lb/yr, a limit that is approximately 29 times greater. 

In addition, several permits have been issued with lower mercury MACT limits. Utah issued a 

permit in October 2004 to Intermountain Power Generating Station for Unit 3. This 950-MW 

pulverized coal-fired boiler will burn subbituminous/bituminous coal. The Intermountain 

permit contains a mercury MACT limit of 0.006 lb/GW-hr. This is 22% lower than the limit 

proposed by MDEQ. Virginia issued a permit in June 2008 to Virginia Electric and Power 

Company for two CFB boilers (Dominion Wise County) with a combined output of 668 MW. 

These boilers would burn coal and waste coal. The permit contains a mercury MACT limit of 

0.000088 lb/GW-hr (0.09 lb/TBtu), or several degrees of magnitude lower than the proposed 

MACT limit here. 

Response:

Seward combusts a waste bituminous coal that Wolverine is not proposing to combust. 

Therefore, the Reliant Energy Seward unit is not a similar source. The mercury permit limits 

for Virginia Electric and Power Company, Dominion were based in part on Seward because 

the Virginia units will be combusting a bituminous coal refuse (gob) and was considered 

similar to Seward by the permitting agency. 

Intermountain Power, Unit 3 is not operating. The mercury emission limits for Intermountain 

Power (converted to GW) are 0.006 lb/GW-hr per 12-month rolling average for bituminous 

coal and 0.020 lb/GW-hr per 12-month rolling average for subbituminous coal. The emission 

limit for subbituminous coal is higher than the emission limit assessed for Wolverine’s CFB 

boilers. 

Comment: 

Having failed to properly identify the MACT floors, the MDEQ analysis also omits proper 

beyond-the-floor MACT analyses, as well as the information that would be used in its 

preparation. This total omission of a required component of the MACT analysis, see 

40 C.F.R. § 63.43(d)(2), itself is grounds for invalidating the MACT limits. 

Response:

The MDEQ disagrees with this comment. Emission controls and limits beyond what is 

achieved in practice by the best controlled similar source were reviewed for HAPs. For 

example, oxidation catalyst control technology (as well as EMx-SCONOX) for organic HAPs, 

wet ESP for acid gases and metal HAPs, and demonstration technologies such as electrocatalytic oxidation (ECOTM) for mercury were reviewed and found to be either not cost 

effective, technically feasible, demonstrated in practice, and/or available for application to a 

utility-size CFB boiler. 

The beyond-the-floor analysis is not complex for this project. The CFB boilers have the best 

control to meet the MACT floor. There are not any control options that the MDEQ is aware of 

that are cost effective, technically feasible, demonstrated in practice and/or available for 

application on a utility-size boiler to set a MACT emission limit based on a beyond-the-floor 

control technology. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 70 of 140 

June 29, 2011 

Comment: 

The beyond-the-floor analysis for mercury is lacking. Although brominated activated carbon 

injection is proposed, no details on this control are provided. At a minimum, the following 

information must be supplied to support a beyond-the-floor MACT analysis: 

• design basis mercury content of each fuel that is proposed; 

• uncontrolled mercury emission rate; 

• design basis of the activated carbon system, including control efficiency and basis of the 

carbon injection rate used in the cost analysis; 

Without this information, it is unclear if the proposed 93% reduction rate is MACT. In our 

opinion, 99% mercury control has been achieved and is achievable for the subject units 

using brominated activated carbon, the ReACT technology, or other technologies that are 

currently available.

Response:

The design basis for the mercury content of the fuels is 12.6 lb Hg/TBtu. The uncontrolled 

mercury emission rate for each CFB boiler is 0.038 lbs/hr. The design basis for the sorbent 

injection system is 93% control and the sorbent injection rate will be dependent on the 

mercury loading into the system which can be variable. As for 99% mercury control, whether 

that can be achieved on a continuous basis under all operating conditions is the question. 

Brominated activated carbon is a mature technology that is commercially available. The 

same cannot be said for the ReACT technology nor any other technology for mercury 

control, since they are still in the development stages. 

Comment: 

The alleged MACT limits are not enforceable. Setting aside the improper use of surrogates, 

the surrogate limits themselves fail in numerous ways to meet enforceability requirements, 

as discussed elsewhere in these comments. Limits that are not enforceable are not MACT. 

Response:

The permit contains emission limits for HAPs, and testing, monitoring, and record keeping 

requirements to demonstrate compliance with the emission limits. This makes the MACT 

limits enforceable. 

Comment: 

The mercury controls proposed by the MDEQ do not meet the requirements of the Clean Air 

Act because MDEQ did not do a sufficient MACT analysis, and arbitrarily and without reason 

rejected lower mercury limits that other plants are proposing to meet. 

Response:

The MDEQ disagrees. Operational Memorandum No. 15, “Procedure for Processing Permit 

Applications Subject to Federal Clean Air Act Section 112(g)” establishes guidelines for 

processing a permit application for a case-by-case MACT determination. The process of 

determining what is maximum achievable control technology for a source is called a 

case-by-case MACT determination, and the implementation regulations are adopted by 

reference in Rule 336.1299(2)(b). 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 71 of 140 

June 29, 2011 

Comment: 

Since your previous permitting action on the proposed Wolverine facility, please be aware 

that the EPA recently proposed the National Emissions Standards for Hazardous Air 

Pollutants from Coal-and Oil-Fired Electric Utility Steam Generating Units and Standards of 

Performance for Fossil-Fuel Fired Electric Utility, Industrial-Commercial Institutional, and 

Small Industrial-Commercial-Institutional Steam Generating (see 76 FR 24976; 

May 3, 2011). Please ensure that any applicable requirements are reflected in a permit. 

Response: 

The rule has only been proposed and is not final yet. MDEQ does not put proposed rule 

requirements in PTI’s because the rule may change and then the permit would need to be 

modified. Also, as stated above, MDEQ properly applied a case-by-case MACT 

determination. 

F. Best Available Control Technology (BACT) Review 

1. Integrated Gasification Combined Cycle (IGCC) 

Comment:

CFB boilers do not achieve emission levels comparable to IGCC. When compared to IGCC, 

CFB boilers come in worse across the board for numerous pollutants. For example, CFB 

boilers and IGCC do not achieve comparable NOx emissions rates. CFB boiler permit levels 

for NOx have generally been in the 0.07 to 0.08 lb/MMBtu range. In contrast, expected NOx 

emissions levels for recently proposed IGCC plants averaged 0.039 lb/MMBtu. NOX levels 

from IGCC, therefore, are upwards of 45% lower than CFB boilers. IGCC facilities are 

similarly lower in SO2 emissions, with 30-day averages at nearly half that proposed for the 

present CFB boilers (0.033 lb/MMBtu for IGCC versus 0.06 lb/MMBtu for the Proposed Coal 

Plant). PM10 emissions from IGCC also are significantly lower than for the Proposed Coal 

Plant. 

Response:

The MDEQ required an evaluation of IGCC as part of the BACT analysis for the proposed 

facility. On February 25, 2008, Wolverine submitted to MDEQ additional information to 

supplement the permit application for the IGCC BACT analysis pursuant to the agency’s 

information request of February 14, 2008. Based on the MDEQ’s review of Wolverine’s 

submittal, and the comments received, the MDEQ determined that the cost of IGCC is 

excessive (approximately $26,000 per ton of emissions removed for the criteria pollutants) 

and that IGCC is not BACT for the proposed facility. 

The BACT analysis considered the total annualized costs for IGCC versus the CFB boilers in 

calculating the costs per ton of criteria pollutants removed. The high cost of IGCC is due in 

part to the substantial difference in the costs of engineering, procurement and construction 

(EPC) between IGCC and the proposed. Wolverine identified a 37.2% higher EPC cost (i.e., 

a premium) for a 600 MW IGCC to generate the electricity Wolverine seeks. 

In responding to the emission rates that can be achieved by an IGCC facility, MDEQ concurs 

that for certain pollutants, an IGCC facility would emit at a lower rate. However, this does not 

alter the overall MDEQ conclusion that IGCC is cost prohibitive. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

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June 29, 2011 

It is worth noting that in comparing emissions and costs of similar facilities, such as those 

presented by the commenter, the facilities, although permitted, have not been constructed. 

No verification of emission rates through stack testing has occurred. In addition, the two 

known operating IGCC facilities in this country located at Wabash, Indiana and Polk Unit 1, 

Tampa, Florida, both had large portions federally funded by the Department of Energy 

(DOE). A comparative evaluation of costing techniques is not reflective of true costs of the 

project. 

In summary, the MDEQ reviewed the detailed IGCC analysis submitted by Wolverine and 

accurately concluded that IGCC is cost prohibitive in terms of the cost to remove a ton of 

criteria pollutants. 

2. Clean Fuels 

Comment::

MDEQ and the applicant failed to consider clean fuels and low sulfur coal in the BACT 

analyses. A permittee cannot avoid lower emission limits achievable with cleaner fuels 

based on its desire for “fuel flexibility”. The applicant and MDEQ may only justify rejecting 

the top control (cleanest fuel) on other environmental grounds in a proper collateral impacts 

analysis, including quantification of impacts to the extent possible. The boiler is not limited to 

the dirtiest fuels but rather it is capable of burning a range of fuels, including those that 

release comparatively less pollution. 

Response:

In the original application, Wolverine submitted a Fuel Supply and Fuel Selection Study 

dated November 2007 as prepared by Burns and Roe Enterprises which was performed to 

identify fuels that would be appropriate for the WCEV project. In response to public 

comment and at the request of the MDEQ, Wolverine submitted additional information on 

their evaluation of clean fuels. This document titled ‘Fuel BACT Review’ is dated 

June 22, 2009. The Fuel BACT Review supports the fuel selection by Wolverine as 

representing BACT. 

Because the chosen CFB boiler technology is designed to burn multiple fuels, it is 

appropriate for MDEQ to evaluate Wolverine’s request to use up to 70% pet coke to blend 

with western PRB coal, while reserving the ability to utilize 100% PRB, ILB coal, or 20% 

biomass with 80% PRB. It is also appropriate for MDEQ to evaluate other, ‘cleaner,’ fuels as 

well. In making this evaluation, MDEQ accepted the approach by Wolverine to start with a 

base case of the chosen boiler and control technology, comparing other ‘cleaner’ fuels 

against the selected fuels. 

The Fuel BACT Review identified the fuel options, including ‘cleaner’ fuels, available to the 

WCEV project and how the availability of such fuels is related to the transportation resources 

available to the site as well as the emission unit under consideration. The emissions 

characteristics and available control technology are dependent on the boiler type. Therefore, 

in addition to considering fuel type, the CFB boiler technology itself must be taken into 

account. The decision on which generating technology to select was based on 

considerations such as the desired generating capacity, planned use of the capacity in 

meeting load, fuel type, transportation, transmission, and water and raw material resource 

availability. Wolverine selected a CFB boiler which can best accommodate western 

sub-bituminous coal (Powder River Basin), eastern bituminous coal (Illinois Basin), central 
Wolverine Power Supply Cooperative, Inc. 

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bituminous coal (Central Appalachia & Northern Appalachia), western bituminous coal 

(Western Canada), pet coke, and biomass. Other fuels, such as natural gas, fuel oil, and 

biomass used as primary fuels, may require significant boiler modification and/or new boiler 

design. 

Of the coals under consideration for use in a CFB boiler, the average coal prices were 

compared by region, taking into account availability, long term stability, and transportation 

costs, and the more economic coals were chosen. The remaining coals were put through a 

coal/ash characterization and were screened using critical fuel characteristics including; fuel 

heating value, sulfur content, ash content, chlorine content, ash fusion temperature, sodium 

in ash, and mercury in coal. The fuels meeting the necessary criteria were: PRB, Illinois 

Basin, pet coke, and biomass. Wolverine has proposed to burn western (PRB) 

sub-bituminous coal with a blend of up to 70% petroleum coke as its primary fuel, and ILB as 

a secondary fuel. The project’s location within a limestone quarry greatly diminishes the cost 

impact of using high sulfur fuels because the limestone is very inexpensive, readily available, 

and can be used as a reagent to capture SO2 in the CFB boiler furnace. According to the 

Fuel Supply and Fuel Selection Study, burning 100% PRB coal or ILB coal are also both 

available options and are technically feasible. 

It is generally known that the cost of coal is related to the heat content in the coal, i. e., the 

greater the heat content, such as in eastern coal, the more costly the price of this coal. Heat 

content is the amount of energy that can be generated from a fuel and is reported as MMBtu. 

Wolverine has stated that there is no business advantage to use eastern coal, as pet coke 

and western coal delivered costs are less expensive at $1.32 per MMBtu and $1.91 per 

MMBtu, respectively. Eastern coal has a delivered cost of $2.17 per MMBtu. The fuel user 

(Wolverine) can mitigate the risks of unforeseen circumstances in the chosen fuel supply by 

using fuel flexibility/blending. Examples of such a circumstance would be a rail disruption or 

mine strike which reduce or interrupt supply. The proposed blend of up to 70% pet coke 

blended with PRB allows Wolverine to mitigate price fluctuations and maintain supply and 

transportation reliability. Limiting a base load facility to a single fuel supply source is a risk 

both from a financial and reliability perspective. 

Wolverine conducted the Fuel BACT Review taking into consideration the add-on control 

equipment selected as BACT. BACT for this project includes the inherent CFB boiler control 

and polishing scrubber for SO2, SNCR for NOx, a baghouse for PM10, the polishing 

scrubber and baghouse for PM2.5, and good combustion control for CO and VOC. A 

pollutant by pollutant review was then conducted to determine if a cleaner fuel would be 

considered BACT. Costs of fuel switching were considered as compared to the base case or 

in terms of burning western (PRB) sub-bituminous coal with a blend of up to 70% petroleum 

coke. 

The sulfur content of the fuel is directly related to SO2 generation which is the dominant 

pollutant in terms of fuel choice. The PRB coal is known to have lower sulfur content than 

other coals. The typical sulfur content of PRB coal ranges from 0.2 – 1.0%, while ILB ranges 

from 1.0% to 3.0%. While the sulfur content of pet coke is higher than coal, ranging from 

4.0% to 7.0%, it is not necessarily a poor choice of fuel. Pet coke burned in a CFB boiler 

with the inherent control via the limestone bed along with the add-on polishing scrubber, 

results in similar outlet SO2 emissions as other boilers burning coal. The CFB boiler design 

provides an inherent control as the limestone bed reacts with the sulfur in fuel to provide a 

removal efficiency of up to 80%. In general, pet coke has a lower ash content (<0.5%), lower 

moisture content (8-10%) and lower volatiles (8-10%) than coal, resulting in a much higher 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

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June 29, 2011 

heat content, on the order of 14,000 Btu/lb. In comparison, the heat content of PRB ranges 

from 8,500 to 9,500 Btu/lb. A higher heat content results in less pet coke needed to achieve 

the same energy level. 

The sulfur content of biomass varies, depending of the type of wood, from 0.01% to 0.10%. 

The boiler is limited in the amount of biomass it can burn. According to the Fuel BACT 

Review “Biomass combustion is limited by the amount of biomass in the region and the fuel 

characteristics of the biomass. It has been determined that a maximum of 20% of the boiler 

heat input can be provided by biomass.” In addition, biomass has the lowest heat content of 

the fuels considered resulting in more biomass burned to achieve the same amount of 

energy as coal or pet coke. The heat content of biomass ranges from 4,000 to 7,000 Btu/lb, 

depending on the moisture content. Biomass with a higher moisture content can affect flame 

stability in the boiler and could lead to increased CO emissions. A balance of fuels will 

assure consistent characteristics in the boiler. The chosen fuel blends will meet the 0.05 lb 

SO2 per MMBtu, based on an annual average and 0.06 lb SO2 MMBtu 30 day rolling 

average, limits identified as BACT. 

NOx emissions result from both fuel bound nitrogen as well as a result of combustion (i.e. 

thermal NOx). NOx formation is related to temperature. Because a CFB boiler operates at a 

lower combustion temperature than more traditional boilers, thermal NOx formation is less 

significant, making fuel NOx the dominant contributor. Of the fuels reviewed, the Fuel BACT 

Review concluded that with the inherent limitations of the SNCR system (i.e. ammonia slip), 

no fuel identified for review provides an advantage over another in terms of NOx formation or 

control. 

The Fuel BACT Review concluded that PM10 and PM2.5 emissions are not affected by the 

fuel choice as it has been defined by Wolverine. Emission differences between coal types, 

pet coke and biomass are not significant as they will be controlled by the baghouse which is 

designed to remove in excess of 99% of the particulate that passes through, independent of 

the inlet loading. 

CO and VOC are products of combustion, formed when fuels are not combusted completely. 

BACT for CO and VOC is good combustion. CO may be impacted by use of biomass as 

wood has higher moisture content and driving this moisture off may affect boiler temperature, 

thereby increasing CO. A well operated boiler will maintain the temperature in the CFB 

boiler to optimize combustion. Biomass has benefits as a clean fuel in that it has a lower 

sulfur and mercury content and is a renewable resource. However, the boiler is limited in the 

amount of biomass it can burn based on concerns over being able to support its use on a 

sustainable basis. 

The MDEQ also evaluated use of natural gas as a fuel. Natural gas use was addressed in 

the Fuel Supply and Fuel Selection Study as well as in the Electric Generating Alternatives 

Analysis (EGAA), dated June 8, 2009. Natural gas was not pursued as a viable fuel for 

long-term energy production due to the price volatility. The price of natural gas is referenced 

in the EGAA. The following table is an excerpt from the EGAA comparing natural gas costs 

to PRB and pet coke. As the data supports, natural gas is at least 5 times greater in price 

than coal. In addition to the fuel volatility, when assessing costs for a natural gas plant, the 

addition of a natural gas pipeline to bring suitable natural gas quantities for base load 

generation to the Rogers City site must be factored in. It would be cost prohibitive to 

construct the necessary infrastructure to get natural gas to the plant site. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

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June 29, 2011 

Wolverine Screening Curve Fuel Cost Input ($/MMBtu) 

Fuel Low Fuel Cost High Fuel Cost 

Natural Gas $6.15 $13.40 

PRB Coal 1.20 4.56 

Petroleum Coke 1.00 4.00 

Based on these considerations, MDEQ has determined that burning western (PRB) 

sub-bituminous coal with a blend of up to 70% petroleum coke as primary fuel, and ILB as a 

secondary fuel provides "fuel flexibility to manage fuel supply risks" and is a reasonable 

consideration in the BACT process. 

Comment:

Including BACT limits based on the cleanest fuel or combination of fuels proposed by the 

applicant is not redefining the source. The proposed plant is specifically designed to burn a 

range of fuels, including low sulfur PRB sub bituminous coal, higher sulfur Illinois bituminous 

coal, very high sulfur pet coke, and low sulfur biomass. Basing BACT limits on the cleanest 

fuel or combination of fuels proposed by the applicant is not redefining the source. 

Response:

Given the design of the boiler and furnace, Wolverine determined that the CFB boiler could 

accommodate, with little or no modification to the burner configuration, western 

sub-bituminous coal (Powder River Basin), eastern bituminous coal (Illinois Basin), central 

bituminous coal (Central Appalachia & Northern Appalachia), western bituminous coal 

(Western Canada), pet coke, and biomass. The Fuel BACT Review addressed these fuels 

and concluded which fuels represent BACT. Other fuels, such as natural gas or biomass 

used as primary fuels, may require significant boiler modification and/or new boiler design. 

The MDEQ concurs with the Fuel BACT Review submitted by Wolverine in selecting to burn 

western (PRB) sub-bituminous coal with a blend of up to 70% petroleum coke as its primary 

fuel and ILB as a secondary fuel. 

Comment:

The claim that Wolverine could not burn clean fuels rings hollow. CFB boilers are capable of 

burning a wide range of sulfur content fuels. 

Response:

MDEQ agrees with the statement that CFB boilers are capable of burning a wide range of 

fuels. In fact, Wolverine has proposed to burn western (PRB) sub-bituminous coal with a 

blend of up to 70% petroleum coke as its primary fuel and ILB as a secondary fuel. The CFB 

boiler is also being designed to burn up to 20% biomass. The issue of clean fuels was 

addressed in the June 9, 2009 Fuel BACT Review and Appendix 2, Fuel Supply and Fuel 

Selection Study. MDEQ concurs with the conclusions drawn by Wolverine that the selected 

fuel mix represents BACT. 

Comment:

Fuel choice is relevant to BACT for several regulated NSR pollutants. The applicant rejects 

the lowest permitted SO2 emissions rates from the AES-Puerto Rico & NEVCO Sevier plants 

on the basis that neither is designed to utilize pet coke. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 76 of 140 

June 29, 2011 

Response:

MDEQ reviewed both AES Puerto Rico and NEVCO Sevier as part of the permit review and 

concluded that emission limits established as BACT for these two facilities were not 

comparable to the Wolverine proposal. Both AES Puerto Rico and NEVCO Sevier proposed 

to burn low sulfur coal. Wolverine proposed to burn western (PRB) sub-bituminous coal (a 

low sulfur coal) with a blend of up to 70% petroleum coke as its primary fuel, and ILB as a 

secondary fuel. A CFB boiler can accommodate many different fuels. As stated in the AES 

permit, permit values identified in the AES permit were based on the ‘environmentally 

worst-case coal’ allowed by the permit, which in this case was 1% sulfur coal. In the case of 

Wolverine, permit values were also based on the ‘environmentally worst-case fuel’ which in 

the case of Wolverine was pet coke. Neither AES Puerto Rico nor NEVCO Sevier is 

permitted to burn pet coke or higher sulfur coal. 

Fuel selection is critical to establishing emission limits. Wolverine has demonstrated through 

the Fuel BACT Review that their selected fuel blend of western (PRB) sub-bituminous coal 

with a blend of up to 70% petroleum coke as its primary fuel and ILB as a secondary fuel 

represents BACT. A BACT analysis evaluates multiple criteria, including costs, to determine 

the appropriate emissions control strategy for the proposed project. Costs of burning a lower 

sulfur fuel or fuel blend were compared incrementally against the Wolverine selected fuel 

blend and determined to be excessive. 

The cost per year of burning PRB (alone), Biomass/PRB blend, or IB alone were compared 

to the Wolverine selected fuel blend and determined the difference, respectively, as follows: 

$7,414,697; $17,676,785; and $15,546,348. 

The MDEQ concurs with the Fuel BACT Review submitted by Wolverine in selecting to burn 

western (PRB) sub-bituminous coal with a blend of up to 70% petroleum coke as its primary 

fuel and ILB as a secondary fuel. 

For comparison purposes, the emission limits for the AES Puerto Rico and NEVCO Sevier 

facilities are identified below: 

Pollutant Wolverine AES Puerto Rico JEA Northside NEVCO Sevier 

SO2 0.06 (30-day), 

0.05(12month), 

303 pph (24-hr) 

0.022 (3-hr) 0.15 (30 day), 

0.20 (24-hr) 

0.022 (30-day), 

0.05 (24-hr) 

NOx 0.07 (30-day), 

281.1 pph (24-hr) 

0.10 (24-hr) 0.09 (30-day) 0.1 (24-hour) 

H2SO4 0.003 (24-hr) 0.0024 (24-hr) 1.1 pph 0.0024 (24-hr) 

PM 0.010 0.015 (24-hr) 0.011 0.0154** (24-hr) 
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June 29, 2011 

PM10 0.026, 

78.8 pph 

0.015 (24-hr) 0.011 ** 0.0154** (24-hr) 

CO 0.15 (30-day), 

744 pph (24-hr) 

0.10 (8-hr) 0.22 (24-hr) 0.115 (1-hr) 

All limits are in units of lb/MMBtu, unless otherwise noted. 

**Limit is listed in the permit as PM/PM10. 

Comment:

The BACT limits for sulfuric acid mist (SAM) and PM2.5 must consider use of low sulfur 

fuels. 

Response:

Both SAM and PM2.5 were subject to a BACT review. The issue of low sulfur fuels was 

addressed by Wolverine in the Fuel BACT Review. After a thorough top-down BACT review, 

taking into account ‘clean’ fuels, SAM and PM2.5 limits as proposed in the Wolverine permit 

are 0.003 lb/MMBtu and 0.024 lb/MMBtu, respectively. The MDEQ concurs with the Fuel 

BACT Review submitted by Wolverine in selecting to burn western (PRB) sub-bituminous 

coal with a blend of up to 70% petroleum coke as its primary fuel and ILB as a secondary 

fuel. 

Comment:

The amount of particulate matter and NOx are also dependent on the fuel source. 

Combustion of biomass generally results in lower PM and NOx emissions than coal. 

Response:

As for the use of biomass in establishing particulate and NOx limits, the amount of particulate 

and NOx emissions from biomass use is dependent on the type of biomass. A decrease in 

NOx based on a lower operating temperature may result in an increase in CO. Particulate 

may or may not decrease with use of biomass. In any case, the BACT limits established for 

NOx and particulate are appropriate and are in line with similar facilities burning a similar fuel 

combination. After a thorough top-down BACT review, taking into account ‘clean’ fuels, 

particulate and NOx limits as proposed in the Wolverine permit are 0.010 lb/MMBtu (PM10 

limit is 0.026) and 0.07 lb/MMBtu, respectively. The MDEQ concurs with the Fuel BACT 

Review submitted by Wolverine in selecting to burn western (PRB) sub-bituminous coal with 

a blend of up to 70% petroleum coke as its primary fuel and ILB as a secondary fuel. 

Comment:

Throughout the draft permit, the applicant emphasizes fuel flexibility as a benefit of CFB 

boiler technology. The prospect of a more diverse fuel stream brings responsibility to 

thoroughly characterize the additional potential emissions profiles and their impacts on 

human health and natural resources. This responsibility was not met in the draft permit. 

Until a comprehensive analysis of all possible emissions profiles is provided, the draft permit 

must be considered incomplete. 

Response:

All fuel streams were evaluated and to be conservative (as to not exceed any regulation 

standards) pollutants showing the highest emissions were evaluated and compared to all 
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state and federal regulations. Impacts on human health were thoroughly reviewed and 

results of the MDEQ analysis can be found in Section C. Public Health and Environmental 

Concerns. 

Comment:

No where in the document is the term “biomass” specifically defined. Any wood waste 

should be prohibited that has been painted or chemically treated. 

Response:

Biomass is defined in the permit, special condition II.3, Material Limits for FGCFB, and does 

not include materials from building construction or demolition. Painted or chemically treated 

would is also prohibited. Biomass is defined as non-chemically treated wood and wood 

residue, bark, or any derivative fuel or residue thereof, in any form, including but not limited 

to sawdust, sander dust, wood chips, scraps, slabs, millings, shavings, processed pellets 

made from wood or other forest residues, switch grass, and other similar fuels. 

Comment: 

MDEQ failed to evaluate emissions from biomass fuel hauling. A thorough analysis of 

emissions from biomass freight operations must be conducted. Key parameters in the 

analysis should include quantities of various biomass feed stocks consumed, and average 

duration and number of truck trips needed to deliver it to the plant. Until a comprehensive 

analysis of all possible emissions profiles is provided, the draft permit must be considered 

incomplete. 

Response:

Emissions from the use of biomass as a fuel have been evaluated as part of this application 

review. Roadways and associated truck traffic emissions are covered by the Fugitive 

Emissions Control Plan (FECP). Due to the variable nature of the biomass fuel industry it is 

not known at this time if WCEV will be processing biomass prior to combustion or receiving 

pre-processed biomass. Off-site freight operations are beyond the regulatory authority of 

the air permit evaluation. 

Comment:

The BACT analysis is deficient because it did not consider the impact of fuel choice on start 

up and shut down emissions. BACT during start up and shut down should require the 

maximum amount of biomass feasible and an accompanying reduction in low sulfur coal. 

Response:

Fuels were considered in the BACT analysis for periods of startup and shutdown and limits 

were appropriately established. Depending on the nature (i.e. cold start, warm start) and 

duration of the startup, NOx and SO2 can be significantly higher during start up and shut 

down than during normal operation. The SO2 and NOx control equipment requires stable 

boiler conditions for effective operation. Effective operation of the SNCR to control NOx 

emissions requires stable flue gas flows and temperatures greater than 1,500°F to ensure 

that the injected ammonia reacts with the NOx in the flue gas. Otherwise, ammonia slip can 

occur which can contribute to additional particulate emissions. Effective operation of the 

polishing scrubber to control SO2 emissions, is much the same. Ensuring the proper bed 

temperature, mixing, availability of bed lime for SO2 absorption, and operation of the spray 
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dryer absorber (SDA) for SO2 control can all affect higher than normal SO2 emissions. 

Therefore because the control equipment is not fully operational during startup #2 fuel oil 

with 0.05% sulfur, low sulfur coal, and/or biomass will be utilized in the CFB boilers. NOx 

and SO2 are inherently lower in those fuels as opposed to the PRB coal and pet coke. After 

the boiler(s) reaches about 40% load, and the control equipment is operating effectively, then 

PRB coal and pet coke will begin to be added. 

This scenario was determined by MDEQ to represent BACT and BACT emission limits were 

appropriately set to account for periods of start up and shut down. 

Comment: 

As part of the BACT determination, Wolverine must consider the collateral impacts from fuel 

choice including the volume of ash that will be produced, the amount that will be sold for 

reuse, the amount that will require landfill disposal including disposal costs, as well as the 

expected content of the ash. 

Response:

In the Fuel BACT Review analysis, Wolverine addressed the volume of ash, disposal of the 

ash, and the cost of disposal. MDEQ reviewed this analysis and determined it to be 

acceptable. 

Comment: 

Has anyone considered blending anthracite coal with bituminous coal? 

Response:

Blending anthracite coal with bituminous coal was not considered for this project. 

Comment: 

What is petroleum coke? What is the benefits of its use? What are the risks? Mercury, 

acids, particulates, HAPs, and other emissions based on 100% sub bituminous, 100% Illinois 

coal, and up to 70% pet coke, 20% biomass, need further consideration. Examples given at 

other facilities burning pet coke show increased emissions over coal for several pollutants. 

Given that substantial dirty tar sand oil is presently being refined at locations on the Great 

Lakes, it should be presumed that pet coke waste from this heavy oil would be even more 

contaminated, especially with sulfur and heavy metals. 

Response:

Petroleum coke, often referred to as pet coke, which is defined as a solid derived from oil 

refinery coker units or other cracking (breaking long chain hydrocarbons into short ones) 

processes. This by-product once disposed of in landfills, is now used in the cement industry 

and utility plants as fuel and raw materials. There are many benefits to using petroleum coke 

as a fuel. It makes a good source of fuel because less fuel is needed on a pound of fuel per 

million Btu basis as compared to coal. Other benefits include, low ash content, lower cost 

per ton, and lower mercury content, as compared to coal. The low ash content means there 

are less emissions of particulate matter. There are no risks to using petroleum coke, 

although one disadvantage is it contains a high sulfur content, as compared to coal. 

However, with the proper add-on control technology to control SO2 emissions, like those that 

Wolverine has proposed, it is still a good source of fuel for a relatively low price compared 
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with coal. The source of petroleum coke that Wolverine is proposing has not yet been 

determined. All petroleum coke emissions evaluated were based on the Louisiana Cleco 

Corporation application, in which the facility was permitted to burn 100% petroleum coke. 

Comment: 

How can Wolverine use up to 70% pet coke as a fuel, when they do not have a local permit 

to burn pet coke? 

Response:

The state requirements contained in the air permit to install are based on state regulations 

the facility must meet. Those requirements are separate from any local requirements such 

as zoning or special use permits. 

Comment: 

Commenter requests that for MDEQ to make public all data used to justify the economic 

decisions that are contained in this permit. Show the math where there are economic 

decisions used to drive environmental decisions within this permit. 

Response:

All supporting information used in reviewing the permit application is contained in the permit 

file and is available by the Freedom of Information Act, including the economic analysis in 

the BACT review. In addition, Wolverine’s submittals were made available on the MDEQ 

AQD website at http://www.deq.state.mi.us/aps/downloads/permits/cfpp/cfpp.htm. 

3. Opacity 

Comment:

The draft permit does not contain a BACT limit for opacity from the boiler. 

Response:

The draft permit contains a limit of 10 percent, based on a 6-minute average, except one 

6-minute average per hour of not more than 20 percent. MDEQ considers this BACT. 

4. PM2.5 

Comment: 

The MDEQ's application of EPA's surrogate policy for PM10 does not satisfy the legal 

requirements of the CAA for PM2.5. PM2.5 is a regulated new source review pollutant that 

the proposed facility will emit in significant amounts. The MDEQ must therefore establish 

BACT emission limits for PM2.5. 

Even if the PM10 surrogate policy is lawful, it is no longer appropriate because the technical 

difficulties on which it is based (PM2.5 monitoring, emissions estimation and modeling) have 

been resolved. 

Response:

A PM2.5 BACT analysis was submitted by Wolverine on September 30, 2008 and additional 

supporting information was submitted on June 22, July 27 and July 29 of 2009. Wolverine 
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also submitted an air quality analysis that includes a modeling demonstration showing that 

emissions from the proposed facility will not exceed the NAAQS or PSD increments for 

PM2.5. MDEQ held a public comment period from August 18, 2009 through September 17, 

2009 with an informational meeting and hearing held on September 17, 2009 to incorporate 

the PM2.5 BACT limits, stack testing, and monitoring requirements into the draft permit. 

Comment:

The late submitted PM2.5 BACT analysis supplement is flawed in numerous ways. 

 

 1) The analysis does not discuss the baghouse design basis and membrane bag 

 technology in sufficient detail in order to determine the removal efficiency. 

 

 2) The analysis only considered a wet ESP and a fabric filter baghouse as control 

 technologies. The analysis should of included other options to reduce PM2.5 

 emission such as an “Advanced Hybrid Particulate Collector” (AHPC) system. 

 

3) The analysis should be more like the Highwood Generating Station BACT 

 analysis where they considered various types of control technologies 

individually and in combination with each other. 

 

 4) Test data from the Manitowoc Public Utilities facility is achieving a PM10 level of 

0.0210 lb/MMBtu as BACT for PM2.5. This limit is less than half the limit Wolverine is 

proposing as BACT for PM2.5. 

Response:

MDEQ disagrees with the above comments. 

The additional information Wolverine submitted on July 27, 2009 gives a thorough 

explanation of the filterable and condensable portions of the PM2.5 emission rate proposed 

from the CFB boilers. Since reliable emissions information on PM2.5 is still limited, it is 

difficult to determine what the removal efficiency will be. Although some vendors have 

provided estimates, it is still not known how reliable the data is. Therefore, Wolverine took a 

conservative approach in which they assumed that approximately 80% of filterable PM10 (or 

0.008 lb/MMBtu) best represented the expected filterable PM2.5 emissions. For the 

condensable portion of PM2.5, Wolverine assumed that it would be equally proportional to 

PM10 condensable emissions (or 0.016 lb/MMBtu). 

Wolverine considered many control technologies in their BACT review, as the record 

demonstrates. The commenter listed several technologies related to ESP technologies that 

have not been demonstrated in practice. (Table 1 in the July 27, 2009 submittal discusses 

where the various technologies can be found in the record.) MDEQ recognizes the 

technologies listed by the commenter. However, these technologies were deemed to be 

infeasible since it is not clear what effect (those technologies) would have on acid gases and 

mercury. WESP, ESP, fabric filter baghouse with membrane bags, and fabric filter baghouse 

with felted polyphenylene sulfide (PPS) bags were evaluated as the top controls for PM2.5. 

The commenter references the Otter Tail Power’s Big Stone plant in South Dakota where the 

AHPC system was used for a retrofit project. That AHPC system failed and was replaced 

with a pulse jet baghouse. 
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Wolverine did evaluate particulate control technologies in combination with other particulate 

control devices, as did the Highwood Generating Facility. The record reflects a cost 

analysis, done by Wolverine, in series for a polishing scrubber, baghouse, and wet ESP. 

After an iteration of such an analysis, it was found that as the additional control technologies 

are added to the series and the removal efficiency approaches zero, the cost is beyond 

economical. Also note, the Highwood analysis, determined that the source would install a 

FGD (polishing scrubber) followed by a fabric filter baghouse for BACT of PM2.5 but does 

not establish a BACT emission limit. 

The Manitowoc Public Utilities CFB boiler has a limit of 0.03 lb/MMBtu for total particulate. 

Stack test results for one day, while firing coal only, demonstrated the following emission 

rates: PM total = 0.0120, PM condensable = 0.0092, and calculated PM Filterable = (0.012 – 

0.0092) = 0.0028. The stack test data does not demonstrate that there was a Method 202 

for PM filterable done. AQD disagrees that this one stack test for PM should be used as a 

basis for setting a limit for PM2.5. The stack test was done for PM total and PM 

condensables, only. There was no test done for PM2.5, and therefore the MDEQ believes 

that setting a limit based only on PM condensable does not provide enough supporting data 

to demonstrate such a limit would be achievable.

5. PM10 

Comment:

First, the limit on PM10 fails to include condensable particulate matter. A BACT limit on PM 

must include the condensable portion. While MDEQ claims the PM10 limit includes both 

filterable and condensable PM, the limit is not accompanied by any testing requirements that 

include the condensable portion. Rather, compliance with the limit is determined only by 

stack test. The PM10 BACT limit must be based on a test method like Method 202 that 

includes the condensable portion. 

Response:

Particulate matter (PM) is defined by MDEQ, Air Pollution Control Rule 336.1116(c), 

“Particulate matter” means any air contaminant existing as a finely divided liquid or solid, 

other than uncombined water, as measured by a reference test specified in R 336.2004(5) or 

by an equivalent or alternative method. This means that determinations of particulate 

emission rates for stationary sources shall be conducted as specified in the following 

reference test methods: 5, 5B, 5C, 5D, 5E, or an acceptable alternative method. Acceptable 

test methods measure filterable particulate emissions. 

PM10 is defined by MDEQ, Air Pollution Control Rule 336.1116(k), "PM10" means 

particulate matter that has an aerodynamic diameter less than or equal to a nominal 10 

micrometers, as measured by a reference test specified in 40 C.F.R. Part 51, Appendix M. 

The reference test methods include 201 (filterable) and 202 (condensable). Acceptable test 

methods measure filterable particulate and condensable particulate to determine PM10 

emissions. 

Both PM and PM10 are required to be measured to show compliance with the emission limits 

in the permit. In order to establish uniform requirements to help ensure proper test methods 

and procedures are used for the compliance demonstration, a complete test plan is required 

to be submitted to the appropriate AQD district office and the Technical Programs Unit in 
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Lansing, at least 60 days prior to the scheduled test date. A complete submittal will minimize 

the possibility of a test rejection as a result of improper sampling or data collection methods. 

Testing shall be performed in strict accordance with the procedures specified in 

40 CFR Part 60 (Standards of Performance for New Stationary Sources, Appendix A, as 

amended), Part 61 (NESHAP, Appendix B), and Part 51 (Requirements for Preparation, 

Adoption, and Submittal of Implementation Plans, Appendix M); and the MDEQ Rules, 

Part 10, Intermittent Testing and Sampling. Any variations in the sampling or analytical 

procedures must be described in the test plan and receive approval from the AQD prior to 

testing. If state or federal test methods are not available for the pollutants of concern, or the 

nature of the test site makes it impractical to use them, other methods may be proposed as 

necessary. 

Comment:

The Draft Permit proposes as BACT for PM and PM10, through the use of a fabric filter, the 

following emission limits: 0.010 lb/MMBtu for PM and 0.026 lb/MMBtu for PM10. This is not 

BACT for the PM. 

BACT is 0.0088 lb/MMBtu for total PM emissions. Pennsylvania issued a PSD permit in 

April 1995 to the Northampton Generating Company with a total PM10 limit of 

0.0088 lb/MMBtu. This facility burns anthracite culm in a 1,146 MMBtu/hr circulating 

fluidized bed boiler. Compliance testing in February 2001 reported total PM10 emissions of 

0.0045 lb/MMBtu. The permit limit and the compliance tests for Northampton have been 

rejected by other permitting agencies in the past due to those agencies’ confusion as to 

whether the 0.0088 lb/MMBtu Northampton permit limit includes condensable PM. The 

confusion appears to stem from the fact that the Northampton permit requires testing by 

“Method 5.” USEPA Method 5 tests only for filterable particulate matter. However, the 

“Method 5” referred to in the Pennsylvania DEQ Permit for Northampton refers to 

Pennsylvania Method 5, which includes both front half and some condensable (backhalf) 

emissions (i.e., both filterable and condensable PM). The Pennsylvania permit and 

compliance tests for Northampton included condensable fraction PM in the backhalf of the 

control train. 

A test at the JEA facility, conducted by Black & Veatch for the Department of Energy, 

measured filterable PM emissions of 0.004 lb/MMBtu. This is significantly lower than the 

proposed 0.010 lb/MMBtu for PM and 0.026 lb/MMBtu for PM10. 

Response:

MDEQ disagrees with the commenter. MDEQ reviewed Wolverine’s BACT analysis and 

determined that BACT for the CFB boilers was 0.010 lb/MMBtu for PM, 0.026 lb/MMBtu and 

78.8 pph for PM10. 

The stack test for Northampton Generating Company was reviewed by the MDEQ-AQD 

Technical Programs Unit, and determined to be incorrect for measurement of PM10 

emissions. Instead of drying and weighing the impingers to get back half condensable PM, 

they filtered the impinger liquid and only dried and weighed the filter. The majority of the 

condensable PM would be dissolved in the impinger liquid and run through the filter. 

Northampton did not find any condensable PM when testing the anthracite coal boiler and 

the reported total PM10 emissions of 0.0045 lb/MMBtu is bias low. This test data does not 

support setting a limit for PM10 that is lower than proposed since the test method did not 

measure condensables appropriately. 
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PM emission tests for the JEA facility have varied up to as high as 0.0091 lb/MMBtu filterable 

PM in November 2002, while burning 75% petroleum coke and 25% coal (a blend very close 

to that identified by Wolverine as its “design fuel”). JEA Northside has demonstrated lower 

particulate emission rates under a variety of operating conditions. It has also demonstrated 

that a limit of 0.004 lb/MMBtu can not be achieved continuously using the same monitoring 

methods that Wolverine will be using. The proposed PM BACT limit of 0.010 lb/MMBtu 

contains an acceptable factor of safety that would assure continuous compliance. 

Comment:

The PM limit is not BACT because compliance is not measured by a continuous emission 

monitoring system for PM (“PM CEMS”). The method of determining compliance is a critical 

part of a permit limit, which impacts the stringency of the limit. Here, the Draft Permit requires 

that compliance with the PM/PM10 limit be demonstrated by stack testing and continuous 

opacity monitoring. The permit for Spurlock Unit 4 requires that PM CEMs be used to 

demonstrate compliance with the PM (filterable) BACT limit. The record contains no 

information showing why PM CEMs cannot be used to demonstrate compliance at the 

Proposed Coal Plant. 

Response:

Currently, a PM CEMS is not required by any federal or state regulation. Wolverine has 

proposed to demonstrate compliance with the PM BACT limit through periodic stack testing, 

and a continuous opacity monitoring system (COMS). A COMS indicates the presence of 

particulate matter, and will provide an indication of continuous satisfactory operation of the 

boilers when an opacity of less than 10 percent is met. A COMS is also allowed as a 

compliance provision per 40 C.F.R. 60, Subpart Da to monitor the performance of a fabric 

filter operated to comply with the applicable PM emission limit. A COMS is an acceptable 

monitoring system on a PSD permit. 

6. NOx 

Comment: 

The MDEQ notes that SCR can control NOx emissions by 80-90% efficiency. This 

underestimates the efficiency. Recent SCRs, designed for high-dust (located upstream of 

the particulate control device) coal boiler applications routinely achieve greater than 90% 

NOx reduction. 

Response:

MDEQ agrees that SCRs, can likely reach efficiencies greater than 90% for NOx reduction. 

However, maintaining that efficiency is not usually practical from a cost standpoint. Also, the 

MDEQ is not aware of any CFB boilers with SCR control that have demonstrated greater 

than 90% and the commenter did not give any examples of such sources. 

Comment: 

Due to numerous errors in assessing selective catalytic reduction (“SCR”) and selective 

non-catalytic reduction (“SNCR”), MDEQ failed to base BACT on the top control technology. 

In conducting its BACT analysis, Wolverine evaluated several NOx control approaches, as 

summarized in the MDEQ Fact Sheet. These included staged combustion techniques, flue 
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gas recirculation, SCONOxTM, gas reburn, SNCR and SCR. The discussion of SCR is 

deficient and the rejection of SCR is without basis: the analysis of the technical feasibility of 

upstream SCR is flawed, while the analysis of the economic feasibility of downstream SCR 

contains improper data and assumptions. Finally, the control technology—SNCR—and NOx 

limit selected is not BACT. 

MDEQ erred in dismissing the technical feasibility of upstream SCR in a “high dust” setting. 

In addition, MDEQ made the statement that SCRs have not been demonstrated to be 

technically feasible on CFB boilers, and Wolverine’s assertion that SCR has “never been 

installed on a CFB boiler in a high dust location”, are both inapplicable to the BACT 

discussion and patently untrue. 

Response:

Using the top-down BACT approach per EPA’s DRAFT New Source Review Workshop 

Manual (October 1990), SCR was identified as the top control option for NOx. However, the 

BACT analysis takes into account energy, environmental, and economic impacts and other 

costs to determine if the maximum degree of reduction is achievable for a source. The 

technical feasibility and the cost of an SCR for a CFB boiler was thoroughly investigated. 

Documents published by EPA, EPA/452/B-02-001 and EPA-452/F-03-032, do support the 

claim that using SCRs in high dust locations will result in fouling of the catalyst. Therefore, 

MDEQ did find that the location of a SCR in high dust locations to be technically infeasible. 

MDEQ believes the use of SNCR is BACT for NOx and was determined using the top-down 

BACT approach. As determined in the Sierra Club vs. Western Greenbrier Co-Generation, 

LLC, (Appeal # 06-03-AQS) the permittee was not required to innovate or to push technology 

beyond what is available and applicable. EPA’s DRAFT New Source Review Workshop 

Manual (October 1990), page B.18, states that in determining the technical feasibility of 

"available" control technologies: 

“[a] source would not be required to experience extended time delays or resource 

penalties to allow research to be conducted on a new technique. Neither is it 

expected that an applicant would be required to experience extended trials to learn 

how to apply a technology on a totally new or dissimilar source type." 

Wolverine initially submitted SNCR with tail-end cold-side (located after PM and sulfur 

removal equipment) SCR, however they excluded SCR saying it was not feasible. The AQD 

disagreed and asked Wolverine for an additional analysis based on tail-end SCR without 

SNCR, in December 2007. Wolverine provided supplemental information supporting tail-end 

SCR as not cost effective. The cost effectiveness of this control technology was 

approximately $20,100 per ton (for both boilers uncontrolled emissions), which was 

considered cost prohibitive. An SCR located after other control equipment requires the flue 

gas to be reheated for proper operation and NOx removal efficiency which increases the 

costs associated with this option. 

Comment: 

Operation of SCR also will result in reductions in dioxins. The Proposed Coal Plant is subject 

to MACT for dioxins. The current MACT limits fail to control dioxins adequately. An SCR is 

one technology that can be used to establish more appropriate MACT limits. Therefore, the 
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cost effectiveness of SCR must be credited with reduction of dioxins, a result not seen with 

SNCR. 

Response:

This source is not subject to MACT limits. The proposed project is subject to 112(g), which 

effectively evaluated all Hazardous Air Pollutants (HAP). 

Comment: 

The control technology analysis of SNCR is faulty. MDEQ cited permits that have to meet 

limits at all load conditions, unlike Wolverine. 

MDEQ ‘s analysis of other facilities NOx emissions is disingenuous. They noted several 

facilities that had NOx emissions of 0.07 lb/MMBtu, the MDEQ does not include that these 

permits require the limit to be met at all load ranges. 

There are several other existing coal fired CFB boilers that have NOx limits lower than 0.07 

lb/MMBtu, such as BMC Thomas Oil facility, Cogeneration National Corporation facility and 

Corn Products facility. A top-down BACT analysis must assume that the proposed 

Wolverine CFB boilers can achieve this same level of control. 

In addition, limits representing LAER are presumptively appropriate BACT limits. 

Specifically, NOx LAER limits in other states show that 0.033 lb/MMBtu (24-hr average) is an 

achievable limit. Unless the LAER level of control can be rejected as not technically feasible, 

not cost effective, or due to unusual collateral impacts at the permitted site, LAER must be 

established as BACT. LAER for NOx control from the proposed CFB boilers is at least as low 

as 0.033 lb/MMBtu over a 24-hour averaging period, which is required by the Dallas-Forth 

Worth State Implementation Plan for coal-fired boilers. 

Moreover, BACT analyses cannot be restricted to existing limits. Instead, BACT must 

represent the best achievable control, which includes the control achieved by unit operating 

well below their respective limits. A number of coal fired CFB boilers are achieving lower 

NOx emission rates than the 0.07 lb/MMBtu limit proposed in the Draft Permit, even with 

periods of startup and shutdown included (from data taken in 2003). Because these similar 

units already achieve a lower NOx emission rate—0.043 lb/MMBtu and lower—BACT is 

assumed to be at least as low as 0.043 lb/MMBtu. 

Wolverine rejected the use of SCR achieving 75% control in the “tailend” configuration based 

on an estimated cost effectiveness of $20,100 per ton reduced. The cost recently estimated 

by the Wisconsin Department of Natural Resources when determining the cost effectiveness 

of a tail-end SCR on a 300 MW coal, petroleum coke and biomass fired boiler that is 

essentially the identical boiler to the two proposed for Wolverine was $10,647. In addition to 

Wolverine and MDEQ’s failure to justify the extraordinarily high cost estimates for an SCR, 

MDEQ also prejudiced the cost-effectiveness analysis. 

Response:

In the permits cited by MDEQ, the EKPC Spurlock Unit 3 and 4, does require the limit to be 

met under all load conditions, however, the permit also has an optimizational period, which if 

they can not meet 0.07 lb/MMBtu within the 18 month period, they can adjust the limit 

upward as much as 0.10 lb/MMBtu. However, the second permit cited by MDEQ, Southern 

Montana Highwood Station permit has the following emission limits for NOx: 
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Except during periods of start-up and shutdown, NOx emissions from the CFB boiler 

stack shall not exceed the following: 

 a. 0.10 lb/MMBtu based on a 1-hour average 

 b. 0.09 lb/MMBtu based on a 24-hour average and 

 c. 0.07 lb/MMBtu based on a rolling 30-day average 

Since the intermediate loads have been removed from the Wolverine permit (see “Section II. 

Summary of Comments Resulting In Changes to the Permit”, of this document) Wolverine 

will be required to meet the NOx emission limit of 0.07 lb/MMBtu, based on a 30 day rolling 

average, at all loads. This limit is the same or lower than the plants listed above. 

In the June 2009 additional information submittal, the applicant provides CEMs data 

measured from 3 similar operating power plants. This information supports 0.07 lb/MMBtu 

with a SNCR for NOx control as BACT for the proposed Wolverine boilers. The data was 

obtained from AES Warrior Run Unit 1 (bituminous coal-fired unit), Schiller Unit 3 (wood-fired 

unit), and JEA Northside Units 1A and 2A (petcoke-fired units). 

Wolverine is not subject to LAER. As stated above, the record supports 0.07 lb/MMBtu with 

a SNCR for NOx control as BACT. 

The Commenter also lists several power plants, including some of those that Wolverine 

provided information on, that the commenter states are achieving lower NOx emission rates 

than 0.07 lb/MMBtu. Although this may be true at one instantaneous point in time, the data 

shown in the comment is for the lowest emission rate achieved one time; it does not consider 

the standard deviation of the data. The standard deviation would demonstrate that those 

power plants are not continuously achieving the lowest rate possible all the time. 

Lastly, the commenter refers to the cost recently estimated by the Wisconsin Department of 

Natural Resources for the Nelson Dewey plant expansion which was for one 300 MW CFB 

boiler. The cost of 20,100 per ton reduced estimated by Wolverine was for two 300 MW CFB 

boilers. Therefore, the cost for each boiler controlled by a tail-end SCR would be $10,050 

per ton reduced, which is less than that cost rejected by Wisconsin. 

7. SO2 

Comment: 

MDEQ does not propose limits reflecting the maximum degree of reduction as shown by 

permits issued to and/or the performance of other facilities. As noted by Wolverine and the 

MDEQ itself, the AES Puerto Rico facility in Guayama, Puerto Rico, received a PSD permit 

for two coal-fired CFB boilers (~225 MW/each) that contains the following SO2 BACT limits 

applicable to each CFB boiler: 

• 9 ppmdv @ 9% oxygen; 

 • 0.022 lb/MMBtu; or 

 • 54.1 lb/hour, whichever is more stringent on a three hour basis. 

These limits are lower than the proposed BACT limit for Wolverine. Furthermore, this facility 

was tested in October 2002. Unit 1 achieved 0.00037 lb/MMBtu SO2 emissions. Unit 2 

achieved 0.0013 lb/MMBtu SO2 emission. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 88 of 140 

June 29, 2011 

Similarly, the NEVCO-Sevier facility received a PSD permit for a 270 MW coal-fired CFB 

boiler with a BACT limit for SO2 of 0.05 lb/MMBtu over 24 hours and 0.022 lb/MMBtu on a 30 

day rolling average. These limits include periods of startup, shutdown and malfunction. 

Other coal-fired CFB boiler facilities in California have also received BACT limits much lower 

than 0.05 lb/MMBtu for SO2: 

• Pyropower Corp. received a SO2 limit of 0.039 lb/MMBtu for a 49.9 MW coal fired 

CFB boiler in 1986 

• BMCP (Thomas Oil) received an SO2 limit of 0.039 lb/MMBtu (96% control) for a 

coal fired CFB boiler in 1986 

• Cogeneration National Corp. received an SO2 limit of 95% control for two coal fired 

CFB boilers in 1985 

However, MDEQ fails to mention these permits at all, let alone explain why they can be 

rejected as a basis for BACT at the Proposed Coal Plant. Nothing in the permit record 

suggests any reason why the WCEV cannot achieve at least 0.022 lb SO2/MMBtu on a 24 

hour average, which is the limit for AES Puerto Rico. In fact, nothing indicates why the 

WCEV cannot achieve 0.0013 lb SO2/MMBtu, which AES Puerto Rico achieved in practice. 

Therefore, BACT for SO2 emissions from the Proposed Coal Plant is 0.0013 lb/MMBtu, or 

lower. 

Additionally, the JEA Northside facility in Florida conducted an emission test in summer 

2002, while firing high sulfur coal in its 300 MW CFB boilers, and achieved 0.0-0.04 

lb/MMBtu SO2 emissions. Northside uses a spray dry absorber (dry FGD), similar to the 

proposal at WCEV. The design specifications required 85% removal of SO2 in the CFB 

boiler, and another 89.5% SO2 removal in the dry FGD. While this is not as low as the AES 

Puerto Rico emission rates, it is significantly lower than the limits proposed for the WCEV. 

This further demonstrates that the proposed permits are too high to constitute BACT. 

Response:

There were many facilities with CFB coal-fired boilers reviewed. However, during the BACT 

review, facilities that best represented Wolverine were used to establish BACT. The criteria 

used was similarity in the unit characteristics, primary and secondary fuels, permit limit, type 

of pollution control equipment and the level of emissions emitted from the operating plant. 

The commenter listed several facilities that Wolverine did not mention: Pyropower Corp, 

BMCP, and Cogeneration National Corp. Those CFB boilers were less than 50 MW which is 

not a comparable size unit. Also mentioned by the commenter was the Nevco Sevier Power 

Company which is comparable in size. However, this plant was proposed with the use of 

low sulfur coal and did not have any stack test data results. The last facility mentioned was 

the AES Puerto Rico facility which uses coal and petcoke with a maximum of 1% sulfur 

content. Stack test results provided by the commenter, demonstrated lowest emission rate 

achieved one time; it does not consider the standard deviation of the data and should not be 

used to set the BACT emission limit. AES Puerto Rico CEMS data demonstrated an 

exceedence of the 0.022 lb/MMBtu BACT limit. 

MDEQ agrees with Wolverine that the best representative facilities are JEA Northside, 

Florida and Reliant Energy Seward Power Plant, Pennsylvania. These facilities are similar in 

all characteristics to the proposed Wolverine facility. Additionally, the CEMs data collected in 

2007 and 2008 was used to demonstrate that 0.06 lb/MMBtu is BACT for the proposed CFB 

boilers at Wolverine. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 89 of 140 

June 29, 2011 

*June 22, 2009 submittal: Wolverine submitted additional information (which AECOM 

collected and processed) that included two years of hourly CEMs data (2007 & 2008) from 

the Reliant Energy Seward Plant and JEA Northside for comparison to the WCEV units 

proposed. Based on that data it was concluded that the Seward Plant achieves about 93% 

overall SO2 control and JEA Northside achieves about 97% overall SO2 control. Compared 

to WCEV with a proposed SO2 limit of 0.05 lb/MMBtu the overall control efficiency should be 

greater than 98%. 

The following calculation if provided to demonstrate how the control efficiencies were 

derived: 

Petcoke/PRB Blend = 2.97lb/MMBtu (from application submittal Appendix 2, Table 4.2) 

CFB 80%: 2.97 lb/MMBtu x (1-0.80) = 0.5940 lb/MMBtu (SO2 coming out of CFB) 

Scrubber 91.5%: 0.5960 lb/MMBtu x (1-0.915) = 0.050 lb/MMBtu (12 month averaging 

period) 

Overall (CFB + scrubber): 2.97 lb/MMBtu x (1-0.98) = 0.0594 lb/MMBtu 

Comment: 

There should be a percent reduction or separate BACT limits for each type of fuel that 

Wolverine plans to burn. If not, the facility could use lower sulfur petroleum coke or PRB 

coal, or other coals with lower sulfur and operate their SO2 controls at lower control 

efficiencies than established as BACT. 

Response:

The MDEQ ranked by control efficiency the feasible control alternatives for sulfur dioxide 

emissions pursuant to the Clean Air Act, Part 55 and EPA guidance. Site-specific and 

process-specific variables such as the sulfur content of the fuel were taken into account. 

When the concentration of SO2 in the flue gases entering the polishing dry scrubber is high 

(from burning fuel with a high sulfur content), the control efficiency of the polishing dry 

scrubber is higher than when the SO2 concentration is lower. The SO2 emission limit is 

dependent on both the sulfur content of the fuel and the control efficiency of the polishing dry 

scrubber. 

Similarly, the clean fuels and control effectiveness components of a BACT analysis are 

closely linked. The commenter asserts that BACT requires the use of cleaner fuels for SO2

(in the form of lower sulfur-content coal), and that BACT (at JEA Northside) requires 85% 

removal of SO2 in the CFB boiler, and another 89.5% SO2 removal in the dry FGD. 

For the maximum sulfur content in the fuel proposed, a greater than 98% control efficiency 

overall (80% from the CFB boiler and 91.5% from the polishing scrubber) is necessary to 

meet the emission limit 0.05 lb/MMBtu annually. MDEQ agrees that the emission limit may 

be met through use of a lower sulfur content fuel than the maximum design value, and as a 

practical matter, the actual fuel used will not always contain the maximum allowable sulfur 

content. As can be seen in the analysis of the examples cited by the commenter (presented 

below), a 99% control efficiency is achieved at power plants burning high sulfur content fuel. 

The same level of control efficiency is not achievable when the concentration of the pollutant 

in the flue gases entering the scrubber is lower.

Also, BACT for SO2 is an emission limit, based on control efficiency, which is applicable at all 

times. The MDEQ correctly determined that the dry polishing scrubber can consistently 

achieve 98% control efficiency at an inlet concentration of 2.97 lb SO2/MMBtu and that an 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 90 of 140 

June 29, 2011 

SO2 emission limit of 0.05 lb/MMBtu annually (0.06 lb/MMBtu 30-day rolling average) is 

BACT. 

Comment: 

Rejection of wet flue gas desulfurization (WFGD) was improper due to inappropriate 

technical and unsupported economic assumptions in the BACT determination. The MDEQ 

provided the following analysis to justify its refusal to require wet Flue Gas Desulfurization 

scrubber technology (wet FGD): 

 “No known WFGD systems have been installed or demonstrated in practice 

downstream of a CFB boiler. Their percent removal efficiency can range anywhere from 52 

to 98% and have high capital and operating costs because of the large consumption of 

water. This control option is frequently used on pulverized coal boilers, and involves the use 

of a spray absorber tower to contact the flue gas with water/lime slurry sprayed from the top 

of the tower. Although this control technology has not been used with a CFB boiler, 

Wolverine considered it technically feasible and included an economic evaluation for 

application with the proposed CFB boilers. This evaluation yields a cost of $11,000 per ton of 

SO2 controlled. Wet flue gas desulfurization is not an economically viable control option.” 

MDEQ must clarify whether it accepted Wolverine’s position that WFGD is technically 

feasible. Assuming that the above quote means that MDEQ rejected WFGD on economic 

grounds only, we include comments on technical issues as well, both because these issues 

impact the cost effectiveness outcome and to correct errors and misconceptions in the 

record. 

Response:

Even though MDEQ could not find a CFB boiler with a WFGD system that has been installed 

or demonstrated in practice, the MDEQ believed it could be feasible. Therefore, a top-down 

BACT analysis was performed including WFGD. 

Comment: 

MDEQ erred in citing 80-90% control from WFGD, as wet FGDs can, by themselves, 

achieve, and have achieved, equal to or greater than 99% removal of SO2. 

Response:

MDEQ cited 52 to 98% as the removal efficiency for a WFGD. The range includes all 

scrubbers, wet and dry. This range was taken from the Air Pollution Control Technology 

Fact Sheet, document EPA-452/F-03-034. Also stated in that document, the highest removal 

efficiencies are achieved by wet scrubbers, greater than 90%, and dry scrubbers, typically 

less than 80%. Although, newer technology of dry scrubber designs are capable of 90% or 

more control efficiencies. Based on data that Wolverine provided on June 22, 2009 for 

additional BACT information, Seward and JEA Northside units achieved SO2 control 

efficiencies of 93% and 97%, respectively, using dry FGD. 

Comment:

MDEQ accepted the Applicant’s economic feasibility argument, thereby failing to include 

specific information on the WFGD design or designs being considered and relying on 

unsupported assertions provided by the Applicant. Nor did MDEQ explain its rejection of 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 91 of 140 

June 29, 2011 

WFGD as economically unjustified based on a cost per ton figure of $11,000. These errors 

undermine the economic feasibility analysis. 

As an initial matter, there are many different types of WFGD, as opposed to DAQ’s 

misleading description of it as consisting of “...a spray absorber tower...” Costs (both capital 

and operating), as well as operating efficiencies can differ between the various designs. 

Since WFGD was correctly deemed to be technically feasible, various designs of WFGD 

should have been considered with regards to cost before they were rejected. MDEQ also 

accepted Wolverine’s cost analysis of WFGD, which concluded that it would cost $11,000 

per ton of SO2 controlled. The cost analysis did not contain vendor design and related cost. 

It relied on numerous assumptions that could not be verified and that do not appear to be 

supported. Since it did not consider a proper (i.e., 99%) removal efficiency, the cost analysis 

underestimated the tons of SO2 removal, thereby providing an erroneously high value of the 

cost-effectiveness. For example, simply by considering a 99% removal efficiency as opposed 

to 98%, and keeping all other assumptions the same, the cost effectiveness should have 

been $5,500 per ton of SO2 removed, which is well within the acceptable range for 

costeffectiveness. 

Further, it is not clear why the $11,000 per ton of cost-effectiveness that was calculated by 

Wolverine should not be deemed to be cost-effective. It is Wolverine’s obligation to show that 

this cost is not “cost-effective” compared to the cost of controlling SO2 elsewhere. “The 

top-down approach places the burden of proof on the applicant to justify why the proposed 

source is unable to apply the best technology available.” 

Additionally, MDEQ must state for the record what the cut-off for cost-effectiveness is and 

why. Without this support, DAQ’s rejection is arbitrary and the limit is not BACT. The basis 

for a BACT determination must always be set forth in the public record. 

Response:

MDEQ disagrees with this comment. First, Wolverine did use a control efficiency of 99% in 

the cost analysis for the WFGD system. Second, two similar sources, Southern Montana 

Electric Generating (Highwood Station) and Virginia City Hybrid Energy Center both did cost 

analysis for a WFGD system and the following was determined: Highwood Station cost 

equaled $27,365/ton SO2 controlled which did include the cost of water; and Hybrid Energy 

Center cost equaled $8,100/ton SO2 controlled (did not include cost of water), both were 

considered too costly. Based on that information MDEQ determined that $11,000/ton SO2 

controlled was also too costly. 

Comment:

Putting aside the improper rejection of WFGD, MDEQ also erred by failing to require 

submission of any specific information as to the polishing scrubber technology that Wolverine 

is proposing to use. This omission is improper; indeed, it abdicates the DAQ’s core 

responsibility to specify the “technology that is ...the most economical and cost effective” as 

the basis of its BACT limit. Different polishing scrubbers can achieve different levels of 

control. It is not possible to divorce the SO2 control efficiency from the technology that will 

provide for SO2 reduction. Requesting this flexibility simply means that Wolverine wants to 

achieve a target, predetermined SO2 emissions level which was not arrived at based on 

what the best technology can achieve. The omission of information regarding the polishing 

scrubber technology proves that the top-down BACT analysis process was not properly 

followed. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 92 of 140 

June 29, 2011 

Response:

MDEQ disagrees with the commenter. As stated above, MDEQ is aware that different 

polishing scrubbers can achieve different levels of control. In determining BACT (an 

emission limit) for SO2 Wolverine used an aggressive yet achievable control efficiency of 

98% overall (CFB boiler and dry polishing scrubber) to calculate the SO2 controlled emission 

rate. As compared to Seward and JEA Northside, these units have achieved SO2 control 

efficiencies of 93% and 97%, respectively, using a dry polishing scrubber. Therefore, MDEQ 

believes that the SO2 emissions level was based on what the best technology can achieve. 

The following calculation if provided to demonstrate the control efficiencies used: 

Petcoke/PRB Blend = 2.97lb/MMBtu (from application submittal Appendix 2, Tables 4.2) 

CFB 80% : 2.97 lb/MMBtu (1-0.80) = 0.5940 lb/MMBtu (SO2 coming out of CFB) 

Scrubber 91.5%: 0.5960 lb/MMBtu (1-0.915) = 0.050 lb/MMBtu (12 month averaging 

period) 

Overall (CFB + scrubber): 2.97 lb/MMBtu (1-0.98) = 0.0594 lb/MMBtu 

Comment:

In addition to the improper rejection of wet FGD, Wolverine did not properly analyze other 

technologies for SO2 removal. For example, 90% removal across the a dry scrubber was 

evaluated as BACT in the South Heart Power Plant permit application, with an inlet SO2 

concentration to the spray dry absorber of 0.392 lb/MMBtu. In the Gascoyne 175 MW permit 

application, the applicant assumed that the spray dry absorber would remove 89.1% of the 

SO2 emissions with an inlet SO2 emission rate of 0.348 lb/MMBtu. There is ample indication 

in PSD permit applications that spray dry absorbers can achieve at least 90% SO2 removal 

even with low sulfur coals. Indeed, as found by EPA in its review of the New Source 

Performance Standards for coal-fired electric utility boilers, a spray dryer/absorber can 

generally achieve greater than 90% SO2 removal. Wolverine should, at a minimum, 

accordingly, evaluate an SO2 BACT limit that reflects at least 90% SO2 removal across the 

spray dry absorber. Coupled with a 90% removal in the boiler, for an inlet SO2 level of 3.0 

lb/MMBtu, the outlet emission limit would be 0.03 lb/MMBtu. This limit would be lower still at 

lower inlet SO2 levels. Wolverine also failed to evaluate the maximum degree of SO2 

reduction achievable with other technologies, such as circulating dry scrubbers. For 

example, the Mustang Power Company plans to use a circulating dry scrubber at its 

proposed New Mexico power plant, and it has indicated SO2 removal of 97% can be 

achieved. The applicant must evaluate the maximum degree of SO2 emission reduction that 

can be achieved across a circulating dry scrubber in its SO2 BACT analysis. 

Response:

Wolverine did evaluate the emission based on the maximum degree of SO2 reduction 

achievable from the inherent scrubbing of the CFB boiler furnace and the dry polishing 

scrubber. Again, as stated above, the following calculations are provided to demonstrate 

how the emission limits were derived: 

Petcoke/PRB Blend = 2.97lb/MMBtu (from application submittal Appendix 2, Tables 4.2) 

CFB 80%: 2.97 lb/MMBtu (1-0.80) = 0.5940 lb/MMBtu (SO2 coming out of CFB) 

Scrubber 91.5%: 0.5960 lb/MMBtu (1-0.915) = 0.050 lb/MMBtu (12 month averaging period) 

Overall (CFB + scrubber): 2.97 lb/MMBtu (1-0.98) = 0.06 lb/MMBtu 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 93 of 140 

June 29, 2011 

8. CO/VOC 

Comment: 

The permit fails to include the requirement for good combustion control as part of BACT for 

CO and VOC while concluding that good combustion control is BACT. Good combustion 

control is the BACT limit that Wolverine suggests for CO and VOC, and the method that 

MDEQ acknowledges for CO (although never includes in the permit). The permit ultimately 

does not incorporate or require good combustion control as a permit operating or other 

requirement. Identifying good combustion control as BACT, and then not including, it 

violates BACT requirements. 

Response:

The permit does require good combustion control, and it is incorporated in the emission limits 

for CO and VOC. CO and VOC are formed as a result of incomplete combustion of a 

hydrocarbon fuel. The permit requires that Wolverine demonstrate good combustion control 

through continuous monitoring of CO emissions. Continuous monitoring of CO emissions is 

used to, among other things, reduce the air to fuel ratio to ensure the maximum combustion 

of fuel, which in turn ensures compliance with the CO and VOC emission limits.

Comment: 

The Draft Permit does not contain a BACT limit for VOC. The VOC BACT limit of 0.003 

lb/MMBtu is higher than BACT limits for VOC at other similar sources. Provide justification 

why a limit of 0.0024 (both Santee Cooper, South Carolina and Louisville Gas & Electric 

Trimble County, Kentucky power plants) cannot be achieved, including an analysis of the 

energy, environmental, and economic impacts of available control technologies. 

Response:

The proposed limit of 0.003 lb/MMBtu could have been explained better. VOC emissions 

from combustion sources are related to the organic content of the fuels combusted and good 

combustion practices. VOC emissions are not controlled by an add-on control device and 

can fluctuate widely, therefore making it difficult to assess an emission limit. Typically, the 

organic content of subbituminous coal is higher than bituminous coal, and petroleum coke 

has a lower organic content than coal. The highest organic content fuel that Wolverine is 

proposing to combust is the biomass. Data is limited for VOC emissions from all of the fuels 

that Wolverine is proposing to combust. Decisions on the VOC emission limit for Wolverine 

were mainly based on the performance of JEA Northside which combusts bituminous coal 

and petroleum coke, two of the lower organic content fuels. The two CFB boilers at JEA 

Northside had measured VOC emissions of approximately 0.0014 lb/MMBtu when 

combusting a blend of 90% petroleum coke/10 % coal. This emission rate was higher than 

the VOC emission rate of 0.00025 lb/MMBtu measured when combusting a blend of 70% 

petroleum coke/30 % coal. The blend of 70% petroleum coke/30 % coal should contain a 

higher organic content, and in theory result in higher VOC emissions. In contrast, when 

combusting 100% coal, unit #1 had VOC emissions of 0.0023 lb/MMBtu measured at 104% 

of allowed process rate and unit #2 had VOC emissions of 0.000016 lb/MMBtu measured at 

92% of allowed process rate. Since VOC emissions were unpredictable and based on lower 

organic content fuels, a conservative 0.003 lb/MMBtu was assessed for the VOC emission 

limit which represents a 30% factor of safety over JEA Northside’s highest VOC test while 

combusting coal. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 94 of 140 

June 29, 2011 

The limit of 0.0024 lb/MMBtu (both Santee Cooper, South Carolina and Louisville Gas & 

Electric Trimble County, Kentucky power plants) can be achieved when combusting 

bituminous coal. Santee Cooper Cross, South Carolina combusts similar fuels to JEA 

Northside. Santee Cooper Cross has demonstrated compliance with the VOC limit of 0.0024 

lb/MMBtu, but the MDEQ had more extensive emission data for JEA Northside from 2002 to 

2008. The performance of JEA Northside indicates that the VOC emission limit of 0.003 

lb/MMBtu is conservative without being too generous. Louisville Gas & Electric, Trimble 

County has not been built yet so no further evaluation was completed on this unit. 

A complete analysis of the energy, environmental, and economic impacts of available VOC 

control technologies did not have to be performed per the top-down BACT process. 

Wolverine evaluated two options for VOC control: oxidation catalyst and good combustion 

control. The oxidation catalyst was found to be not technically feasible for a coal-fired boiler. 

Good combustion control was found to be the most effective control option, and therefore, 

selected as BACT. 

Comment: 

The Draft Permit does not contain a BACT limit for CO. The BACT limit of 0.15 lb/MMBtu for 

CO is higher than BACT limits for CO at other similar sources. 

Response:

For other similar boilers, CO emission limits of 0.10 lb/MMBtu, 0.11 lb/MMBtu, and up to 0.15 

lb/MMBtu were reviewed. CO emissions from boilers are a function of oxygen availability 

(excess air), flame temperature, residence time, combustion zone design, and turbulence. 

CO emissions like VOC emissions are controlled by good combustion and can fluctuate 

widely, therefore making it difficult to assess an emission limit. The CO emission limit of 0.15 

lb/MMBtu is conservative without being too generous.

Comment: 

For CO, the commenter reviewed a large number of permits and stack tests to determine the 

lowest carbon monoxide emission rate that has been achieved in practice at a similar source. 

A quick review indicates that the CFB boilers located at the Cedar Bay facility in Florida 

routinely achieve a lower carbon monoxide emission rate than proposed. Fifteen stack tests 

conducted between 2003 and 2008 demonstrate that Cedar Bay achieved a carbon 

monoxide emission rate of 0.05 lb/MMBtu based on a 3-hour average. Similarly low CO 

levels have been achieved at other circulating fluidized bed boilers. These include JEA 

Northside circulating fluidized bed boiler, where detailed performance tests were conducted 

for a range of fuels and at loads of from 40% to 100%. The CO limit is no greater than 0.05 

lb/MMBtu based on a 3-hour average, the highest reported CO value over the period 2003 to 

2008. This is one-third of the value (0.15 

lb/MMBtu) proposed by MDEQ as the BACT for CO, notwithstanding the leniency afforded 

by MDEQ’s longer averaging time (i.e., 30 days). 

Response:

The monitoring method for the CFB boilers is a CO CEMS. The monitoring method allows 

averaging over a longer period of time for a potentially lower CO emission limit. The stack 

testing results listed by the commenter demonstrate performance for short time frames 

during stable operation. CO emissions can fluctuate during load shifts and fuel switching, 

and since the monitoring will measure continuous operation, the emission limit of 0.15 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 95 of 140 

June 29, 2011 

lb/MMBtu was assessed to include a factor of safety. Continuous compliance with a CO limit 

no greater than 0.05 lb/MMBtu has not been demonstrated as achievable. Likewise, a 

3-hour averaging period for CO emissions is not necessary and potentially too restrictive. 

 

Comment: 

Several proposed emission limits require compliance on a 30-day rolling average basis. 

Several similar permits used for comparison in the permit application contain a 3-hour 

average or 24-hour rolling average. Explain why a shorter compliance time is not feasible for 

this source. 

Response:

A shorter compliance time is feasible for this source. However, the monitoring method 

selected for the CFB boilers is a CO CEMS. The monitoring method allows averaging over a 

longer period of time, and therefore, the selection of a lower CO emission limit. The longer 

averaging time allows for averaging of lower emissions with higher emissions over more 

emission data. Better performance (good combustion) can be maximized, and fluctuations 

in CO emissions minimized. A lower CO emission limit means lower CO emissions over the 

lifetime of the CFB boilers. 

Comment: 

It has been determined that state-of-the-art combustion techniques and proper and efficient 

combustion practices represent BACT for toxic air contaminants. Explain in full what this 

means. 

Response:

Best Available Control Technology for Toxics (T-BACT) refers to any chemical or compound 

emitted to the air other than criteria pollutants (CO, VOC, NOx, PM, PM10, PM2.5, Sox, and 

lead). Toxic air pollution in Michigan is controlled under two sets of regulation: (1) state 

administrative rules and (2) the federal Clean Air Act, as amended. According to Michigan’s 

Rules all known substances can be regulated as toxic air contaminants (TAC), except some 

substances which have been specifically excluded because they are regulated elsewhere or 

are considered relatively non-toxic. MDEQ reviewed the amount of TAC emissions the 

facility could possibly emit after the best controls are installed. Wolverine is required to limit 

TAC emissions to amounts at or below screening levels which protect the public health. 

State-of-the-art combustion techniques; such as oxygen availability (excess air), flame 

temperature, residence time, combustion zone design, and turbulence; aid in complete 

combustion in the CFB boilers which minimize TAC emissions. State-of-the-art combustion 

techniques have been considered T-BACT to minimize TAC emissions on many similar 

projects. 

9. Greenhouse Gases (GHG) 

Comment: 

Circulating Fluidized Bed (CFB) boilers have a significantly greater greenhouse gas impact 

than Pulverized Coal (PC) boilers, even when burning biomass. Perhaps most egregiously, 

not only do CFB boilers emit more NOx and other criteria pollutants than controlled PC 

boilers and (Intergrated Gasification Combined Cycle) IGCC plants, but CFB boilers pose a 

very serious additional environmental and health concern: CFB boilers emit more 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 96 of 140 

June 29, 2011 

greenhouse gases than PC boilers on a carbon-equivalent basis. While CFB boilers emit 

less CO2 than PC boilers, they emit more nitrous oxide than PC boilers. N2O is a potent 

greenhouse gas, with almost 300 times the greenhouse gas impact of CO2. Thus, 

comparatively, supposedly “clean” CFB boilers emit approximately 15% more global warming 

pollutants than PC boilers. 

Petroleum coke, a fuel burned in CFB boilers, also increases the amount of greenhouse 

gases from combustion. 

Response:

On a lb/MW-hr basis, greenhouse gas emissions from both CFB and PC boilers are very 

similar. As reported in the (Electric Generating Alternative Analysis) EGAA, NOx emissions 

and CO2 emissions from a subcritical CFB boiler are superior to subcritical PC boiler 

technology. Supercritical PC boilers are estimated to emit about 30% less NOx than the 

proposed CFB boilers. This amount is approximately 0.02 lb/MW-hr. However, even if the 

proposed facility were to operate at full capacity for an entire year, and all of the NOx 

generated from operating at full capacity were assumed to be N20, the total greenhouse gas 

contribution from the additional NOx emissions is only about 0.3% of the total allowable 

annual CO2e emissions.21 

In addition, emissions of other pollutants, such as hydrochloric acid, lead, hydrofluoric acid, 

and mercury, are higher for PC boiler versus CFB boiler technology. MDEQ has discretion 

to consider the priority of the varying pollutants emitted from a facility taking into 

consideration other State initiatives. Michigan has a statewide mercury reduction initiative, 

and toxics and health-based rules that limit emissions of these pollutants. Whenever a 

health-based standard exists, it will almost always be rated a higher priority than a nonhealth based standard. In the proposed Wolverine CFB boiler project, the emissions of 

these pollutants are considered a higher priority than greenhouse gases currently are. Thus, 

MDEQ disagrees with the commenter that PC boiler technology is preferable to CFB boiler 

technology. 

It is a common misconception that CFB boilers emit 15-20% more N2O than PC boiler 

technology. This is because early sampling methods yielded incorrect results due to errors 

inherent in the sampling methods in use. “In the turn of the 1990s nitrous oxide (N2O) was 

measured usually by non-continuous methods, such as bag sampling followed by an 

analysis with gas chromatography (GC). This method, however, was prone to errors. It was 

noticed that too high N2O concentrations were determined in bag samples because NO, 

SO2 and H2O formed N2O as an artifact. Therefore, based on these measurements, wrong 

conclusions were drawn about nitrous oxide emissions.”22

It was later determined that, “CFB boilers inherently operate at lower temperatures and have 

lower NOX emissions than pulverized coal boilers, but can emit some N2O. Cell burners 

(manufactured in 1950s and 1960s) rapidly mix pulverized coal and combustion air resulting 

in highly turbulent and efficient combustion, but NOX emissions are high, typically 1.0 to 1.8 

lb/mmBTU.”23 Uncontrolled emissions of NOx are lower for a CFB boiler than a PC boiler 

because the combustion temperature of a CFB boiler (1544 - 1652°F) is much lower than a 

 

21 {[(0.02 #/Mw-hr)x(8760 hrs/yr)/(2000 #/ton)*310] / 6,024,107 tons CO2e allowed/yr} * 100% = 0.3% 22 Non-CO2 greenhouse gas emissions from boilers and industrial processes, pgs 26-27, Tsupari, E, et al, VTT 

Research Notes 2321, ESPOO 2005 

23 NOx Emissions Produced with Combustion of Powder River Basin Coal in a Utility Boiler, pg 19, WRI-97-R033, 

Nordin, John S and Merriam, Norman W., April 1997, US Department of Energy Office of Fossil Energy 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 97 of 140 

June 29, 2011 

PC boiler (2462 - 2732°F) which results in lower NOx formation. (NOx present in flue gas 

generally comes from two sources: the oxidation of nitrogen compounds in the fuel (fuel 

NOx) and the reaction between the nitrogen and oxygen in the combustion air (thermal 

NOx). With low temperature and staged combustion, the oxidation of fuel nitrogen is 

suppressed resulting in very low NOx emissions). Additional control of NOx in the proposed 

Wolverine CFB boilers are provided by selective non-catalytic reduction (SNCR), which can 

control NOx with efficiencies up to 75%. For a PC boiler, add-on control of NOx can be 

provided by selective catalytic reduction (SCR) systems. SCR is a post combustion system 

that can reduce NOx emissions at 85 to 90% efficiency. However, the higher efficiency of 

SCR control on a PC boiler does not mean that overall emissions of N2O will be significantly 

lower than for CFB boiler. Thus MDEQ disagrees that CFB boilers emit 15% more 

greenhouse gases than PC boiler technology. 

Petroleum coke (petcoke) is proposed as one of the fuels in the feedstock mix. On a pounds 

per ton basis, petcoke does create more greenhouse gases than other fuels. However, it 

also has a higher heating value, so less needs to be combusted to generate the same 

amount of energy as other fuels. For example, to get the same amount of energy you get 

from combusting one pound of petroleum coke, you would need to combust almost 1.5 

pounds of sub-bituminous coal and about 1.6 pounds of dry wood (green wood would be 

considerably higher). The tables below provide information regarding the emissions of 

individual greenhouse gases in a variety of units, and a comparison of greenhouse gas 

emissions from the different fuels proposed in the project, based on heating value of the fuel. 

It is clear from this data that CO2 is by far the largest greenhouse gas emitted from 

combustion of any of the fuels proposed by Wolverine, even when Global Warming 

Potentials are applied to the individual greenhouse gases. 

GHG emissions in #/mmBTU – proposed Wolverine project 

Fuel Type CO2 (#/mmBTU) CH4 (#/mmBTU) N2O (#/mmBTU) 

Subbituminous coal 213 (97.02 kg) 0.024 (0.011 kg) 0.004 (0.0016 kg) 

Coke 225 (102.04) 0.024 (0.011) 0.004 (0.0016) 

Wood/Wood 

Residuals 

206.4 (93.8) 0.07 (0.032) 0.009 (0.0042) 

GHG emissions in #/ton fuel – proposed Wolverine project 

Fuel Type CO2 (#/ton fuel) CH4 (#/ton fuel) N2O (#/ton fuel) 

Subbituminous coal 3682 (1674 kg) 0.042 (0.019 kg) 0.061 (0.028 kg) 

Coke 5567 (2531) 0.60 (0.27) 0.087 (0.040) 

Wood/Wood 

Residuals 

3174 (1443) 1.08 (0.49) 0.14 (0.065) 

GHG emissions from combustion by % (based on #/ton) – proposed Wolverine project 

Fuel Type CO2 CH4 N2O 

Subbituminous coal 99.98 0.001 0.016 

Coke 99.99 0.01 0.002 

Wood/Wood 

Residuals 

99.96 0.03 0.004 

GHG emissions from combustion by % (based on #/ton), with GWP’s applied – proposed 

Wolverine project 

Fuel Type CO2 (#/mmBTU) CH4 (#/mmBTU) N2O (#/mmBTU) 

Subbituminous coal 99.5 0.024 0.49 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

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Coke 99.3 0.22 0.48 

Wood/Wood 

Residuals 

97.96 0.70 1.34 

GHG emissions from combustion by % (based on #/ton) - EPA data 

Fuel Type CO2 

(#/ton fuel) 

HHV 

(mmBTU/ton) 

Fuel Needed 

to equal HHV 

value of coke 

Total CO2 

emissions to 

equal HHV of coke

Coke 5579 24.8 1 5579 

Subbituminous 

coal 

3689 17.25 1.44 5304 

Ag Biomass 2149 8.25 3 6447 

Wood/Wood 

Residuals (dry) 

3180 15.38 1.61 5128 

Thus, MDEQ disagrees with the commenter that PC boiler technology is preferable to CFB 

boiler technology. 

Comment: 

The “redefining the source” rationale does not apply in the present case. Wolverine 

eliminated multiple available technologies, including natural gas combined cycle, pulverized 

coal, super critical CFB boilers, Integrated Coal Gasification Combined Cycle, and biomass 

gasification, as control options by stating “they would constitute ‘redesign’ or ‘reconfiguration’ 

of the project.” GHG Permit Appl. at 1-2. The “redefining the source” rationale does not apply 

to options that would reduce pollution while redesigning or reconfiguring the project. Rather, 

it permits the agency to exercise limited discretion to omit options that would fundamentally 

“redefine the source”. MDEQ applies redefining the source too broadly. 

Response: 

MDEQ disagrees with the commenter. The “redefining the source” question is been 

discussed in the NSR Workshop Manual (page B.13) and evaluated by the courts in a 

number of documents. These documents indicate that an applicant is not required to 

evaluate cleaner fuels in the BACT analysis, but should evaluate cleaner forms the selected 

fuel source for the project. Other court decisions have clarified that an applicant is not 

required to evaluate fuels that would fundamentally change the scope of the project.24 In 

other court decisions, it was determined that the question of redesign of a facility to achieve 

reduced emissions is the kind of judgment which should be left to the Permitting Agency.25 

MDEQ, as the permitting authority, has appropriately applied its discretion in applying the 

redefining the source rationale. 

Comment: 

Site specific criteria are not a valid reason for excluding control options. As MDEQ points 

out, elimination of control technologies must be for reasons such as “not technically or 

economically feasible or that energy, environmental, or economic impacts are unfavorable.” 

If MDEQ were trying to invoke the collateral impacts exception here, it failed to do so. An 

alternative clean fuel may only be rejected for the single additional reason of when “using 

 

24 Old Dominion, 3 E.A.D. 779 (1992) 25 Sierra Club v. EPA, 499 F.3d 653, 655-6, on appeal of the EAB’s Prairie State decision, and Hawaiian 

Commercial & Sugar Company, 4 E.A.D. 95 (1992) 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

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June 29, 2011 

another type of fuel would be inconsistent with the fundamental purpose of the facility.” 

Consequently, since consideration of clean fuels is required as part of the BACT analysis, 

the applicant and MDEQ were required to consider natural gas. 

Response: 

Site specific criteria were not used to exclude control options. However, site specific criteria 

did make the selected control options and boiler design more attractive than other controls 

and designs considered in the BACT analysis. For example, by locating the CFB boilers in 

this specific limestone quarry, a ready source of limestone is available for SOx control, presoftened water is available for cooling, an on-site ash disposal site is available, and a dock is 

available for delivery of fuel. 

The consideration of clean fuels in the BACT analysis only requires consideration of cleaner 

forms of the fuel being proposed. This is clearly explained in the October 1990 draft NSR 

Workshop Manual. Since Wolverine has designed a plant that will burn petcoke, Powder 

River Basin coal, and biomass, MDEQ may consider cleaner forms of these fuels. 

Consideration of natural gas is beyond the scope of the BACT requirements. However, it 

was considered as part of the alternatives analysis. 

Comment:

Wolverine also rejected the use of 100% biomass combustion, stating that a 100% biomass 

CFB boiler is limited to 50 MW in size which does not meet the needs of the project. The 

use of 100% biomass as fuel in a fluidized bed combustor greater than 50 MW, however, has 

been demonstrated as technologically feasible and was therefore unreasonably rejected as a 

control option for the WCEV project. Since May of 2010, a Foster Wheeler 385 MW 

circulating fluidized-bed combustor has been operating for Kaukaan Voima Oy in Finland 

firing 100% biomass. The power plant is fueled by bark, branches, tops, stumps, small wood 

and peat. 

Response: 

MDEQ disagrees that the Kaukaan Voima Oy CFB boiler has the ability to provide similar 

electrical output to the proposed Wolverine CFB boiler using only biomass. The Kaukaan 

Voima Oy CFB boiler plant can provide 125 MW of electricity, 110 MW (thermal basis) of 

district heat, and 150 MW (thermal basis) of process steam. The actual electrical output is 

only 125MW, which is approximately 35% of the capacity of the CFB boilers proposed by 

Wolverine, which can provide 350 MW (each) of electricity. 

Comment:

Wolverine also did not evaluate the use of torrefaction to prepare the biomass to reduce the 

cost of transportation and fuel handling. 

Response:

Torrefaction is the process of heating the raw biomass to drive off water and volatiles. The 

remaining material is a charcoal or bio-coal, and can be used in the combustion process 

along with coal and other fuels. The advantage of torrefaction is that the final product has 

about 30% more energy per unit of mass, and transportation costs per unit of energy 

decrease. However, about 10% of the original energy in the biomass is lost due to the 

volatile materials being driven off in the torgas. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

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June 29, 2011 

Torrection was not reviewed during the GHG BACT review. However, it should be noted that 

torrefaction does not come without its own production costs and environmental penalty. Fuel 

must be burned to create the heat needed for the torrefaction process. The biomass would 

have emissions of greenhouse gases along with other pollutants such as volatile organic 

compounds. So, even though there may be savings from lower transportation costs or better 

fuel handling characteristics, the burning of a bio-coal is not necessarily a cleaner form of 

biomass, and the same or higher amount of greenhouse gases may be emitted through the 

course of the process. 

MDEQ does not believe that consideration of torrefaction would have changed the outcome 

of the GHG BACT analysis. 

Comment:

While both the applicant and MDEQ have relied upon site-specific criteria as if they define 

the source, these site specific criteria do not rise to the level of being a fundamental purpose 

of the project. The purpose of this project, generating electricity, would still be achieved if the 

project location, combustion technology and fuels were changed to generate significant 

reductions in GHG emissions. 

Response:

MDEQ disagrees that the ability to take advantage of site-specific attributes were a 

fundamental purpose of the project. While it is true that site-specific criteria do not define the 

fundamental purpose of the project, the selection of the appropriate combustion process 

does impact the analysis and outcome of the decision. Site-specific attributes are one of the 

many considerations that may have an affect on the selection of the process employed and 

the control strategy. For example, site-specific attributes may make one control strategy 

more cost effective or a combustion process alternative more feasible. The site specific 

factors were just one element that influenced Wolverine’s selection and MDEQ support of a 

CFB boiler. 

Comment:

Although scientists have now thoroughly debunked the long-standing myth that biomass 

combustion is “carbon neutral,” industry proponents and project applicants continue to seek 

special treatment for biomass projects based on the dangerously false contention that 

biogenic greenhouse gas emissions do not affect the climate. The company and the State 

simply assume, but never actually demonstrate, that biomass combustion should be 

considered carbon neutral. 

The GHG BACT Determination “considers” biomass combustion to be “carbon neutral.” The 

weight of current scientific work compels the opposite conclusion. 

The GHG BACT Determination claims that “the implementation of a sustainability 

standard”—specifically one derived from Michigan law defining “sustainably managed 

forests”—is “the key to documenting the carbon neutrality” of fuels. Yet the document fails to 

demonstrate that any of the referenced sustainable forestry certification methods even 

considers the atmospheric impact of biomass combustion, much less establishes “carbon 

neutrality.” This assumption, however, relies on a simplistic, inventory-based accounting 

approach that ignores both real carbon dynamics and the legal requirements of the Clean Air 

Act. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 101 of 140 

June 29, 2011 

Response:

In March 2011 EPA published the Guidance for Determining Best Available Control 

Technology for Reducing Carbon Dioxide Emissions From Bioenergy Production. This 

document provides a general discussion regarding biomass as an overall net carbon sink, 

and discusses how CO2 emissions participate in a global carbon cycle through 

photosynthesis, which is a form of terrestrial sequestration. In this document, EPA states 

that averaged over the years 1990-2008, the United States has been a net sink of 841 

teragrams of CO2e per year (about 12% of the average gross emissions). EPA further 

states that this net carbon sink is expected to continue, if not increase, through 2020.26 

While combustion of biomass may or may not be carbon neutral, MDEQ follows EPA 

guidance and treats CO2 emissions from biomass as a net carbon sink, and therefore 

preferable to combustion of fossil fuels. 

Comment:

Since the March 16, 2011 GHG BACT determination has been prepared and submitted well 

after the application, it can be concluded that many of the project design considerations 

including project location, combustion technology and fuels were chosen with no 

consideration to minimizing GHG emissions. Further, since the project and permit remained 

virtually unchanged after the GHG BACT analysis, the BACT analysis appears to have come 

to the predetermined conclusion that the project and permit as written were BACT for GHGs 

instead of the BACT analysis driving the pollution controls and emissions limits for the 

project. 

Response:

MDEQ strongly disagrees with this comment. Since the original BACT analysis was 

performed more than a year before the GHG BACT was required, it may seem that the 

conclusions were predetermined. However, this was not the case. 

It is important to remember that the GHG BACT analysis submitted by Wolverine on March 

16, 2011, is a supplement to the original BACT analysis for the conventional criteria 

pollutants. After considering the information in the original application, the original BACT 

analysis concluded that the CFB boiler as proposed was the best design choice. With the 

addition of the regulation of GHGs, the question becomes; does the regulation of GHGs 

change the original conclusion? It is clear that some technologies, such as IGCC, offer an 

attractive option for capturing CO2. However, the ability to capture CO2 becomes a less 

attractive feature without the ability to sequester it. In their March 2011 PSD and Title V 

Permitting Guidance for Greenhouse Gases document, EPA found that while CCS is a 

promising technology, there are numerous reasons to eliminate it because it is technically 

infeasible at this time. During our review of the GHG BACT supplement, MDEQ concluded 

that this was the case for the Wolverine project. 

Next, we determined if any of the other technologies offered any advantages that would 

reduce GHG emissions significantly enough to outweigh the conclusions of the original 

analysis. Again, MDEQ concluded that the other technologies did not provide overwhelming 

evidence that would necessitate a redesign of the proposed facility. 

 

26 Guidance for Determining Best Available Control Technology for reducing Carbon Dioxide Emissions from 

Bioenergy Production, March 2011, USEPA, pg 7 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 102 of 140 

June 29, 2011 

This left evaluation of the existing proposed CFB boiler design with respect to reduction of 

greenhouse gas emissions. MDEQ determined that energy efficiency, and a requirement for 

use of a renewable energy in the form of biomass in the fuel mix, was BACT for GHGs. 

Thus, while conclusions reached in the original BACT analysis may influence the results of 

the GHG BACT analysis, the GHG BACT was performed independently. 

Comment:

The GHG BACT Determination fails to follow several of the steps recommended by EPA for 

a top-down BACT analysis and thus fails to ensure that the determination adequately 

addresses all relevant regulatory and statutory requirements. The document also fails to 

support conclusions reached at several of these steps with facts or data in the record. 

Response:

Guidance from EPA states that, “...EPA has not established the top-down BACT process as 

a binding requirement through rule. Thus permitting agencies that implement an 

EPA-approved PSD permitting program contained in their State Implementation Plans (SIPs) 

may use another process for determining BACT in permits they issue, including BACT for 

GHGs, so long as that process (and each BACT determination made through that process) 

complies with the relevant statutory and regulatory requirements.”27 Although MDEQ 

typically follows the top-down process, it is not unusual to combine steps when appropriate. 

Because the GHG BACT analysis was a supplement to the original BACT analysis submitted 

by Wolverine, a modified process was used to evaluate the supplemental information. 

However, all steps required in the top-down review process were included by MDEQ in the 

modified analysis. 

Comment:

IGCC is a technology that can lower control costs of CO2 emissions because the CO2 in the 

syngas can be removed prior to combustion. MDEQ and Wolverine failed to include IGCC in 

the full BACT analysis eliminated it prior to Step 1. MDEQ did do a cost analysis of IGCC 

within the earlier BACT analysis for other criteria pollutants. However, the omission of GHGs 

from the list of reduced pollutants fails both to attribute some of the cost of the plant to 

control of these harmful pollutants and to spread the cost of controlling other pollutants 

across GHG reductions. Had IGCC been included in the cost-effectiveness analysis for GHG 

controls, step 3 of the BACT analysis, the favorable costs for GHG reductions coupled with 

greater cost effectiveness for other pollutants would have produced a significantly different 

overall picture of IGCC. MDEQ was arbitrary and capricious in failing to analyze BACT for 

GHGs with IGCC with CCS as a control option. 

Response:

It is clear that some technologies, such as IGCC, offer an attractive option for capturing CO2. 

However, the second step is sequestration. The ability to capture CO2 becomes a less 

attractive design feature without the ability to sequester it. In their March 2011 PSD and Title 

V Permitting Guidance for Greenhouse Gases document, EPA found that while CCS is a 

promising technology, there are numerous reasons to eliminate it in the BACT analysis 

because it is technically infeasible at this time. During our review of the GHG BACT 

supplement, MDEQ concluded that this was the case for the proposed Wolverine project. 

 

27 PSD and Title V Permitting Guidance for Greenhouse Gases, March 2011, USEPA, pg 19
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 103 of 140 

June 29, 2011 

Comment:

Wolverine and MDEQ should have looked beyond Wolverine’s DOE project as the basis for 

its cost estimates for using CCS to control GHGs. As explained elsewhere in these 

comments, IGCC technology should have been considered for the plant, instead of solely 

CFB boiler technology. 

Response:

In addition to the many technical hurdles to overcome, current information suggests that the 

cost structure for CCS is very high. However, there is very little information available on the 

cost structure for CCS, which is why we elected to evaluate the CCS option with the 

Wolverine-DOE grant proposal information. Based on the information in the proposal, 

MDEQ found that to sequester even 5-6% of the total exhaust would cost approximately 

$128 per ton. Considering the large number of tons of greenhouse gases produced through 

the combustion process, MDEQ determined that CCS was not cost effective. 

Comment:

The BACT analysis submitted by Wolverine and the BACT review conducted by MDEQ are 

further inadequate because they improperly dismiss CCS as BACT for controlling emissions 

of CO2 from the facility. Wolverine and MDEQ err in claiming that CCS is not an “available” 

technology for BACT purposes. Second, Wolverine and MDEQ make an unsupported and 

flawed argument that CCS is not economically feasible. 

Response:

MDEQ did not claim that CCS was not an available option. MDEQ is well aware that EPA 

considers CCS an available technology.28 However, EPA also indicates in this document 

that while CCS is a promising technology, there are numerous reasons to eliminate it as 

technically infeasible at this time, recognizing that the significant logistical hurdles presented 

by CCS technology sets it apart from other conventional forms of pollution control equipment. 

Off-site land acquisition, funding, and liability for long term storage were all cited in the EPA 

guidance document as making CCS prohibitive at this time. Thus, MDEQ eliminated CCS in 

Step 3 of the BACT analysis for these reasons. 

Comment:

An example of a recent permit for a supercritical plant is that issued for a new unit at the 

Trimble County Generating Station. AEP Southwestern Electric Power Company recently 

obtained a permit to build a 600 MW ultra-supercritical unit in Arkansas. In addition, 

ultra-supercritical units have been permitted and in use overseas. MDEQ shows the 

randomness of its BACT process: the agency required IGCC to be considered in the BACT 

analyses for the supercritical PC boiler plant proposed by Consumer’s Energy and the 

subcritical CFB boiler proposed here, but did not require Wolverine to consider SPC in its 

BACT analysis for the subcritical CFB boiler. MDEQ must explain why IGCC is an 

alternative to supercritical PC boiler and the Wolverine subcritical CFB boiler for criteria 

pollutants, but supercritical PC boiler is not an alternative to the proposed plant for GHGs. 

Ultra-supercritical PC boiler also should be considered in the GHG BACT analysis. 

 

28 PSD and Title V Permitting Guidance for Greenhouse Gases, USEPA, March 2011 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 104 of 140 

June 29, 2011 

Response:

Pulverized coal (PC) boiler technologies (subcritical, supercritical, and ultra-supercritical) 

were eliminated in Step 2 of the BACT analysis because they do not have the demonstrated 

ability to utilize the mixture of fuels proposed by Wolverine. Although PC boiler technology is 

capable of burning biomass, special handling is required when biomass exceeds about 3% 

of the fuel mix due to physical limitations of the pulverizer. (Wolverine Power Cooperative 

Electric Generation Alternatives Analysis – Volume 1, Appendix A-2, June 8, 2009, pg 17) 

In addition, PC boiler technology would not take advantage of site-specific characteristics to 

the extent that CFB boiler technology does. CFB boiler allows direct addition of limestone in 

the boiler feed for sulfur control. PC boiler technology would require wet flue gas 

desulfurization, and which would create a new wastewater stream that would have to be 

collected and treated. 

Furthermore, greenhouse gas emissions are within about 3% of each other for these 

technologies while emissions of lead, hydrochloric acid, hydrofluoric acid, and mercury all 

increase with PC boiler technology. 

Therefore, the MDEQ has determined that there is no significant advantage to PC boiler 

technology that would outweigh the benefits derived by selecting CFB boiler. 

Comment:

Given the requirement to conduct BACT for greenhouse gases as well as criteria pollutants, 

MDEQ should have considered a supercritical CFB boiler in its BACT analysis. MDEQ 

references the supercritical CFB boiler constructed in 2009 for the Łagisza Power 

Plant in Poland, but states that “there is limited information on the performance of the unit” 

and dismisses this as a “developing technology.” In March, 2010, Foster Wheeler concluded 

that: “After operating over 4000 hours, it can be stated that initial operation experience of the 

Łagisza boiler has been excellent.” Due to the success of the Łagisza CFB boiler, Foster 

Wheeler is moving forward to design an 800 MW supercritical steam CFB boiler. The 

Łagisza supercritical CFB boiler has operated successfully for over 1 and half years. 

Wolverine concludes both facilities have a similar heat rate but dismisses supercritical CFB 

boilers as not being demonstrated as capable of operating with biomass fuels. However, 

Foster Wheeler itself indicates that supercritical CFB boilers can fire up to 20% biomass, the 

percentage proposed by Wolverine. MDEQ and Wolverine were required to conduct a more 

thorough BACT analysis of the availability and feasibility of this technology and may not 

arbitrarily dismiss it as developing because the designs for the Wolverine plant call for a 

subcritical CFB boiler. 

Response:

While supercritical CFB boiler technology shows great promise, after only 6 months of 

operation we believe it is premature to require supercritical CFB boiler technology as BACT 

over subcritical technology, which has a very long and successful history. There is been 

very little information available regarding operation of the Lagisza CFB boiler other than 

Foster Wheeler’s literature. Based on an information search via the internet, it appears that 

the Lagisza CFB boiler is still under-going fine tuning and has yet to undergo stack testing to 

verify vendor guarantees. “After fine tuning of controls and optimization of the boiler 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 105 of 140 

June 29, 2011 

performance, a 720 h trial operation will begin followed by plant takeover and start of the 

commercial operation.”29 

While emission results are available in the Foster Wheeler literature, the background data, 

testing methods, and verification of data, are not provided in any of the literature we were 

able to find. At this point it is not even clear if fuels other than European bituminous coals 

have been used in the boiler and if so, in what ratios. 

Nor is it clear if the technology will continue to perform at such high reported efficiencies over 

time. With the exception of a few news articles reporting on the new technology, almost all 

of the available information has been provided by the vendor, Foster Wheeler. However, this 

information does not provide any information that allows an independent party to verify the 

reported efficiency of the unit. 

In addition, since the unit has only been in operation for about a year and a half, 

maintenance and reliability have yet to be proven. However, the sub-critical CFB boiler 

technology proposed by Wolverine is well proven with the technology, fuel mix, and air 

quality control strategies proposed. Wolverine is staking the future of the company on this 

proposed facility, and cannot be expected to risk the viability of their company with a 

technology that is still being verified by the vendor. 

For these reasons, supercritical CFB boiler is currently considered a developing technology 

by the MDEQ. 

Comment:

The GHG BACT Determination lists “biogenic fuel augmentation” among the “possible 

control technologies” identified for the Project, but does not explain why this technology is 

even appropriate for identification at Step 1 of the BACT analysis. The purpose of Step 1 is 

to identify “inherently lower emitting processes/practices,” add-on controls, and combinations 

thereof. The GHG BACT analysis does not demonstrate that biomass combustion is 

“inherently” lower-emitting. Indeed, biomass combustion can result in more greenhouse gas 

emissions per unit of energy produced than either coal or natural gas. 

Response:

MDEQ believes it is appropriate to include biogenic fuel augmentation as an available 

technology. While it is true that biomass may emit more greenhouse gas on a heat input 

basis, it is also considered a renewable and “carbon neutral” fuel. Selection of biomass as 

BACT is supported in of the March 2011 Guidance For Determining Best Available Control 

Technology For reducing Carbon Dioxide Emissions From Bioenergy Production. On page 

29 of that document, EPA states “...[forest] residuals that would otherwise decompose in a 

10-15 year time frame, the net carbon cycle impact of this biomass fuel is expected to be 

negligible. Thus for a feedstock composed of such residue material, the costs of applying 

strategies to reduce emissions from the facility do not appear justified at this time because 

the carbon dioxide emissions from the individual facility would not be increasing atmospheric 

impacts above the business as usual case.” EPA further states “...EPA believes the energy 

and economic benefits of this fuel is sufficient at this time to justify selecting biomass fuel as 

BACT for greenhouse gases without further control.” 

 

29 Utility CFB goes “Supercritical” – Foster Wheeler’s Lagisza 460 MWe Operating Experience and 600-800 MWe 

Designs, James Utt, Arto Hotta, Stephen Goidich, August 19-21, 2009, pg 11, 

http://www.fwc.com/publications/tech_papers/files/TP_CFB_09_12.pdf
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 106 of 140 

June 29, 2011 

MDEQ concurs with EPA guidance, and included biogenic fuel augmentation as an available 

technology in Step 1 of the BACT analysis. 

Comment:

The GHG BACT Determination’s discussion of the technical feasibility of burning biomass as 

BACT begins not with any technical analysis, but rather with a survey of federal and state 

policy provisions that favor biomass energy generation. These policy judgments have no 

place in a BACT analysis. 

Response:

MDEQ disagrees with this comment. Selection of biomass as BACT is supported in of the 

March 2011 Guidance For Determining Best Available Control Technology For reducing 

Carbon Dioxide Emissions From Bioenergy Production. On page 27 of this document EPA 

states, “Renewable fuels policies, which in some cases provide incentives for the substitution 

of renewable fuels for fossil fuels, have not traditionally been part of the BACT energy 

impacts analysis. However, consideration of renewable energy policies could become part of 

the BACT analysis, especially if state policies mandate the replacement of fossil fuel with 

biogenic fuel. In addition to numerous federal programs, as of February 2011, states have 

some kind of state-level financial or conservation incentive program that includes biomass 

production and almost as many states have rules, regulations or policies that promote 

bioenergy use.” 

EPA further states that “...where a bioenergy facility is projected to provide the energy and 

economic benefits described above in accordance with existing federal or state policies 

promoting utilization of biomass for energy production, these considerations may justify 

selecting the option of exclusively using a biomass fuel as BACT for biogenic CO2 emissions 

from a bioenergy facility.” 

Clearly, the EPA guidance supports permitting agencies factoring federal and state policies 

into the BACT determination for biomass. MDEQ concurs with this approach and factored 

this into the evaluation process. 

Comment:

The GHG BACT Determination also fails to provide any meaningful discussion of the 

environmental impacts of co-firing with biomass. The GHG BACT Determination fails to 

answer even the most basic questions: what is the environmental effect of collecting and 

burning biomass from areas within 75 miles of the Project? What are the effects at a 5% 

co-firing rate, as opposed to a 20% co-firing rate? What is the effect (on soils, water quality, 

and habitat) of removing logging residuals and burning them, rather than leaving them in the 

forest? The MTU Report provides no actual evidence for concluding that every acre of 

“herbaceous open land” or other “open lands” is, in fact, “abandoned agricultural land.” Nor 

does the MTU Report provide any support for its conclusion that energy crop conversion will 

be beneficial for biodiversity. 

Response:

The MTU Report estimates that Wolverine would require approximately 168,105 dry tons of 

biomass per year to provide 5% feedstock, and 672,418 dry tons biomass per year to 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 107 of 140 

June 29, 2011 

provide 20% of the total feedstock.30 MTU also estimates that the “... ‘unused’ portion of 

annual removals, comprised of logging residues that are normally left on-site and ‘other’ 

removals, such as road and right-of-way clearing and thinning treatments”, would provide 

approximately 220,000 dry tons of biomass, or about 7%, annually, assuming a 65% 

recovery rate of this material.31 As described in the report, this estimate considered only the 

currently unused portion of biomass residues as material that is available to Wolverine within 

a 75-mile radius of the proposed facility. In addition, collecting this material will reduce 

emissions generated by decay of this organic material. 

MTU also found that Michigan Forests are currently growing more wood than is removed 

through timbering and natural mortality. Currently, average harvest levels in Michigan’s 

northern lower peninsula are about 1/3 of current growth. If this additional existing biomass 

growth were used, co-firing at more than 20% biomass would be feasible in a supply radius 

of 50-miles.32 

While MTU acknowledges that sufficient information is not available to draw strong 

conclusions, they were able to use various governmental databases and the knowledge of 

local county extension and USDA staff to develop recommendations. Available herbaceous 

open land was estimated using “...data from the USDA Forest Service, Forest Inventory and 

Analysis Program (FIA)(Miles 2007) and the agricultural and open-land based using data 

from the State of Michigan’s IFMAP (Integrated Forest Monitoring, Assessment and 

Prescription) program (MI DNR 2006).”33 Through personal communications with county 

extension and USDA personnel, MTU learned that much of the land identified as herbaceous 

open-land is actually abandoned farm land.34 

The study looked at both available unused forest residuals and other removals (such as 

brush clearing), and development of a sustainable biomass feedstock through dedicated 

energy crops. MTU estimates that there are an additional 980,000 dry tons per year of 

biomass that could be made available through development of a dedicated energy crop 

program.35 This is more than sufficient to support a 20% biomass feedstock. 

Thus MDEQ has determined that the MTU report findings support the conclusions reached in 

the GHG BACT review with respect to biomass sustainability and supply. 

Comment:

The GHG BACT Determination concludes that co-firing with 5% biomass will reduce CO2e 

emissions by 4.7%. GHG BACT Determination at 3-13. Nowhere does the document explain 

how this figure was calculated. Nor does the MTU Report contain any data to substantiate 

 

30 Biomass Co-Firing for the Wolverine Clean Energy Venture, Michigan Technological University, January 30, 

2008, page 2 

31 Biomass Co-Firing for the Wolverine Clean Energy Venture, Michigan Technological University, January 30, 

2008, page 7 

32 Biomass Co-Firing for the Wolverine Clean Energy Venture, Michigan Technological University, January 30, 

2008, page iii 

33 Biomass Co-Firing for the Wolverine Clean Energy Venture, Michigan Technological University, January 30, 

2008, pg 6 

34 Biomass Co-Firing for the Wolverine Clean Energy Venture, Michigan Technological University, January 30, 

2008, page 6 

35 Biomass Co-Firing for the Wolverine Clean Energy Venture, Michigan Technological University, January 30, 

2008, page 8 
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Response to Comments Document 

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June 29, 2011 

this claim. As a result, the GHG BACT Determination lacks any support for its ultimate 

conclusion that co-firing with 5% biomass should be considered BACT. 

Table 1 of the Supplemental Update seems to include CO2 emissions from biomass in the 

Project total of 5,878,168 tpy CO2e from the CFB boilers. The GHG BACT Determination 

states that all proposed BACT measures, including biomass co-firing at 5% and energy 

efficiency measures, will result in a 4.7% reduction in CO2e emissions. The document 

proposes to enforce a 5,722,000 tpy “cap” on CO2 emissions through “continuous emissions 

monitors at the CFB boiler stack.” The proposed cap would result in a reduction of only 

156,168 tpy CO2e from the CFB boilers. A 4.7% reduction in CO2e emissions from the CFB 

boilers, however, should be 276,274 tpy. 

Response:

The Wolverine BACT submittal indicates that through co-firing using 5% biomass in the fuel 

feedstock, implementing energy efficiency measures, and following the manufacturer’s 

guidance for proper operation of equipment, the net result is a reduction of greenhouse gas 

emissions attributable to fossil fuels is approximately 4.7%. However, because greenhouse 

gas emissions reductions attributable to energy efficiency and following manufacturer’s 

guidance are not easily quantifiable, the actual reductions are expected to be slightly higher 

than estimated because this figure was calculated using only greenhouse gas emissions 

from fossil fuels that would be eliminated through the use of biomass. 

The Wolverine BACT submittal calculates that at a 5% biomass feedstock rate, 284,000 tons 

of CO2e emissions from fossil fuels will be avoided. The report also discusses a 5,722,000 

ton per year cap on CO2e emissions from the boiler. 

4.7% = [(284,000 + 5,722,000) / (5,722,000)] * 100% 

Note that these values were not used in the AQD review due to a miscalculation of the total 

CO2e emissions from the proposed facility in the Wolverine BACT submittal. This error was 

later corrected, but the reduction in CO2e emissions from fossil fuels was not recalculated. 

Comment:

It is not clear how this “cap” will be enforced. The GHG BACT Determination proposes to 

measure the cap “with continuous emission monitors at the CFB boiler stack,” which will 

necessarily capture biomass CO2 emissions as well. 

 

Response:

The proposed deferral of CO2 from biogenic sources is not final at this time. Therefore the 

greenhouse gases from biomass combustion are not exempt from regulation and must be 

counted when determining compliance with the proposed emission limit. MDEQ has 

proposed conditions in the permit that account for all greenhouse gas emissions. 

Comment:

The Biomass Study fails to account for the greenhouse effects of burning standing timber, 

which will include N2O and other compounds which are far more potent greenhouse gases 

than CO2. It does not account for the short-term reduction in sequestration caused by 

increased harvesting and burning of wood with currently sequestered and subsequently 

released carbon, nor the N2O emissions from burning wood. The greenhouse effects of 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

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June 29, 2011 

other gases, such as N2O, which are released by burning wood, are released from CFB 

boilers, and are many times more potent than CO2. The analysis must include amounts and 

multipliers of these more potent greenhouse gases. 

Response:

Higher GWP greenhouse gases were included in the analysis. Greenhouse gases with 

higher Global Warming Potentials (GWP), such as methane (CH4) and nitrous oxide (N2O), 

were evaluated as part of the review process to determine their contribution to the total 

CO2e. Using CO2e allows us to compare greenhouse gases with different GWP, (e.g. 1 ton 

of N2O is equivalent to 310 tons of CO2). Thus one ton of N2O equals 310 tons of CO2e. 

However, even though N2O has a much higher GWP than CO2, the total N2O emissions 

from the CFB boilers account for less than 0.5% of the total CO2e emissions (GWP applied). 

Thus, the effects of higher GWP greenhouse gases such as methane and N2O were 

considered by MDEQ in the analysis. 

Comment:

Minimizing CO2 emissions in the next few years is critically important to meeting climate 

targets, even if some of all of that CO2 might in theory be reabsorbed from the atmosphere 

in the decades or centuries to come. 

Response:

Existing rules regulating greenhouse gas emissions do not take the effects of climate change 

into consideration. EPA specifically provides guidance contrary to this effort, “As a general 

matter, GHG emissions contribute to global warming and other climate changes that result in 

impacts on the environment and society. However, due to the global scope of the problem, 

climate change modeling and evaluations of risks and impacts of GHG emissions currently is 

typically conducted for changes in emissions orders of magnitude larger than the emissions 

from individual projects that might be analyzed in PSD permit reviews. Quantifying these 

exact impacts attributable to the specific GHG source obtaining a permit in specific places is 

not currently possible with climate change modeling. Given these considerations, an 

assessment of the potential increase or decrease in the overall level of GHG emissions from 

a source would serve as the more appropriate and credible metric for assessing the relative 

environmental impact of a given control strategy.”36 

Comment:

The GHG BACT Determination fails in its most basic task: providing an assessment of the 

relative cost-effectiveness of burning biomass. Indeed, neither the GHG BACT Determination 

nor the MTU Report quantify the cost of control for combustion of biomass at 5% of the fuel 

mix (the proposed BACT measure). 

Response:

Step 4 of the BACT analysis is to evaluate the most cost effective control strategies, and 

Step 5 is to select BACT. No cost analysis was required for the following reasons: 

- Selection of biomass co-firing with the primary fuel meets existing state policies 

promoting utilization of biomass for energy production, thereby reducing carbon 

emissions from fossil fuels. 

 

36 (PSD and Title V Permitting Guidance for Greenhouse Gases, USEPA, March 2011, pgs 41-42) 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

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June 29, 2011 

- Co-firing 5% biomass with the primary fuel would not significantly reduce the 

efficiency of the boiler even when using biomass with higher moisture contents. 

- The MTU study found that at a recovery rate of 65%, 220,000 dry tons per year of 

existing forest residuals are available within a 75 mile radius of the proposed facility. 

This is more than sufficient to meet the 5% biomass requirement in the permit. 

- The cost of using biomass is offset by the reduction in costs associated with petcoke 

and PRB coal. 

Based on these factors, MDEQ believes that a minimum of 5% biomass in the fuel feedstock 

is both technically feasible and cost effective. 

Comment:

The discussion of potential energy efficiency measures in the GHG BACT Determination is 

underdeveloped and fails to follow EPA guidance. Indeed, the discussion does not even 

identify which specific efficiency measures are being proposed. The document thus provides 

no basis for determining which energy efficiency measures are available and applicable to 

this Project. 

Response:

The concept behind incorporating energy efficiency measures into the draft permit for the 

proposed facility is that when the plant is operated as efficiently as possible, the power 

needed to operate the plant is reduced, thereby reducing overall fuel consumption and 

emissions of greenhouse gases. 

Energy efficiency measures are largely determined during the design of the plant during 

planning and engineering phases. The general efficiency of the proposed plant is evaluated 

as part of the BACT process. Specific energy efficiency measures are determined during 

final design of the plant and during development of operational practices. Because 

Wolverine is not at the final design stage, it is technically infeasible to identify specific energy 

efficiency measures that will be employed in the final design because the measures selected 

will be dependent on facility-specific, as-built site conditions. Therefore, energy efficiency 

measures can only be identified in the permit in a general sense at this time. 

However, MDEQ has included language in the proposed permit that specifies that during the 

design phase of the project, Wolverine shall incorporate energy efficient equipment wherever 

practical in the design of each boiler included in FGCFB. Specifically, MDEQ has required 

that the design of each boiler, at a minimum, shall specify that all motors over 100 

horsepower shall be variable speed, all air pollution control devices shall be operated at the 

minimum pressure drop required to maintain compliance with permit limits and conditions, 

thermal performance of all heat transfer components at the facility, including structures, shall 

be designed to maximize energy efficiency, and energy efficiency shall be optimized, where 

practical, for all fans, motors and other equipment necessary to operate each boiler and 

support systems.37 

MDEQ has also included language in the proposed permit to address energy efficiency 

through an Energy Efficiency Management Plan (EEMP). This is a living document and is 

intended to influence not only design and operation of the facility when it is initially 

constructed, but also to incorporate changes once experience is gained through on-going 

 

37 Wolverine Power Supply Draft Permit to Install No. 317-07, FGCFB, IV.4 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

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June 29, 2011 

operation of the facility. Permit conditions requiring the source to address a concern prior to 

construction is common practice for other similar situations, such as Malfunction Abatement 

Plans (MAP) and Fugitive Emission Control Plans (FECP), and provides the State with 

continued oversight of the project for specific purposes even after permit issuance. 

In their March 2011 PSD and Title V Permitting Guidance for Greenhouse Gases (pg 21), 

EPA also recommends performance benchmarking as a method to assess energy 

efficiency.38 Plant energy benchmarking is the process of comparing the energy 

performance of one site against itself over time or against the range of performance of the 

industry, and is typically done at the whole facility level to account for differences in 

technology, operating practices, and operating conditions.39 Since the Wolverine CFB 

boilers have not yet been constructed or operated, performance benchmarking is of limited 

use at this time. 

EPA also recommends the use of output based limits when numerous small energy savings 

methods are employed in the design and operation of a facility.40 MDEQ has included an 

output based limit of 2.1 lb/KW-hr on a gross output basis. This limit is intended to not only 

include energy efficient design and work practices in the proposed plant, but also to require 

them to maintain a high level of energy efficiency throughout the life of the facility. 

Comment:

The GHG BACT Determination fails to provide any meaningful evaluation of the 

cost-effectiveness related to proposed energy efficiency control measures. Promising 

“consideration of plant thermal component efficiency” in the design process is no substitute 

for identifying proposed efficiency measures and evaluating their economic, energy, and 

environmental impacts. Nor is an assurance that the Project operator will follow 

manufacturers’ O&M guidelines a meaningful control measure, unless the Project operator 

had been planning to violate these guidelines as a matter of course before identifying this 

approach. In short, the Step 4 analysis of energy efficiency ignores virtually every component 

of a defensible BACT determination. 

Response:

The response to the prior question discussed evaluation of energy efficiency measures and 

the EEMP in detail. As explained in that response, it is technically infeasible to identify or 

evaluate specific energy efficiency measures that will be employed in the final design 

because the measures selected will be dependent on facility-specific, as-built site conditions. 

We have included language in the draft permit indicating that the operator follow 

manufacturer’s guidelines as a control measure because the engines, fans, and other 

equipment necessary to operate the CFB boiler may be operated under various conditions. 

There will also be guidelines on how to operate and maintain the equipment to achieve the 

most efficient operation for the desired electrical output. Thus the proposed language was 

not included in the draft permit because we believe the operator intended to operate the CFB 

boilers inconsistent with best operating practices. 

 

38 PSD and Title V Permitting Guidance for Greenhouse Gases, USEPA, March 2011, pg 21 39 Available and Emerging Technologies for Reducing Greenhouse Gas Emissions From Industrial, Commercial, 

and Institutional Boilers, October 2010, USEPA, pg 25 40 PSD and Title V Permitting Guidance for Greenhouse Gases, March 2011, pg 22 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

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June 29, 2011 

Comment:

The Applicant has not shown that equally effective greenhouse gas controls cost only $8/ton. 

In fact, the Applicant has not provided enough information on the control- and 

cost-effectiveness of other proposed BACT measures (biomass and energy efficiency) to 

even enable a relative comparison. The short-cut attempted in the GHG BACT Determination 

does not even attempt to comply with the requirements for this step of the BACT analysis. 

Response:

There is very little, if any, reliable data regarding a cost effective level for greenhouse gas 

control costs. EPA makes this clear by stating, “...given that there is little history of BACT 

analyses for GHG at this time, there is not a wealth of GHG cost effectiveness data from 

prior permitting actions for a permitting authority to review and rely upon when determining 

what cost level is considered acceptable for GHG BACT.”41 

In their March 16, 2011 GHG BACT Supplement submittal, the applicant attempted to 

develop a cost effectiveness basis for GHGs by making comparisons between the 

greenhouse gas applicability threshold established in the Tailoring Rule and the average 

control cost effectiveness threshold of approximately $8,000 per ton for a criteria pollutant.42 

Using this information, Wolverine assumed that EPA was attempting to equate 100,000 tons 

of CO2 to the 100 tons per year threshold for major sources defined in one of the 28 source 

categories in the PSD rules, and thus establish an $8 per ton control cost threshold for 

GHGs. This cost effectiveness threshold was not used in the AQD evaluation of the GHG 

BACT Supplement. 

EPA also suggests that for the economic analysis, “...it may be appropriate in some cases to 

assess the cost effectiveness of a control option in a less detailed quantitative (or even 

qualitative) manner... As with all evaluations of economics, a permitting authority should 

explain its decisions in a well-documented permitting record.”43 

As MDEQ evaluated the GHG BACT Supplement submitted by Wolverine for each step of 

the BACT process, all of the various control options dropped out for reasons other than 

economics, and by Step 4 of the process, we were left with only energy efficiency and 

biomass augmentation. Since the applicant was willing to accept conditions requiring both of 

these options under BACT, MDEQ elected to observe EPA’s guidance, and there was no 

need to perform an economic evaluation. 

Comment:

A thorough assessment of biomass availability must look at not simply how much forest 

growth occurs within the procurement area, but how much is actually available for purchase. 

Without considering any competing proposals, Wolverine’s conclusion that there are unused 

logging residues of 220,000 dry tons per year which are available and sufficient to meet 

Wolverine’s co-firing requirements are suspect. 

According to the MTU Report, the Project will require 168,105 dry tons per year of biomass 

to sustain a 5% co-firing rate. The MTU Report concludes that 177,591 dry tons per year of 

logging residues, and 41,510 dry tons per year of “other removals” (“road and right-of-way 

 

41 PSD and Title V Permitting Guidance for Greenhouse Gases, USEPA, March 2011, pg 43 42 (Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, Federal Register, Vol. 75, 

No. 106, published June 30, 2010) 

43 PSD and Title V Permitting Guidance for Greenhouse Gases, USEPA, March 2011, pg 42 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

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June 29, 2011 

clearing and thinning treatments”), are available within the “bioshed,” defined as a 75-mile 

straight-line radius around the Project. However, the MTU Report does not provide any 

analysis of the cost of transportation of logging residues and “other removals” over these 

distances. The MTU Report thus does not establish that enough residues and “other 

removals” exist within an economically feasible transport radius of the Project to support 

even a 5% co-firing rate. Finally, the MTU Report fails even to mention or analyze competing 

demand for biomass feedstocks in the same bioshed. 

Response:

The MTU study developed the 220,000 dry tons per year of available biomass using the 

USDA Timber Products Output database (USDA FIA-TPO 2006) and assumed an availability 

rate of 65%. As the report explains, this estimate is based on the “... ‘unused’ portion of 

annual removals, comprised of logging residues that are normally left on-site and ‘other’ 

removals, such as road and right-of-way clearing and thinning treatments.”44 As described in 

the report, this estimate considered only the currently unused portion of biomass residues as 

material that is available to Wolverine. Estimating future additional demand for these unused 

residues would be pure conjecture. 

However, the MTU study looked at both available unused forest residuals and other 

removals (such as brush clearing), and development of a sustainable biomass feedstock 

through dedicated energy crops. MTU estimates that there are an additional 980,000 dry 

tons per year of biomass that could be made available through development of a dedicated 

energy crop program.45 

Comment:

MDEQ’s calculation of the “parasitic load” of energy, and corresponding costs, required for 

CCS is also flawed. MDEQ claims that the “parasitic load” of energy required to power GHG 

capture at the Wolverine facility would “reduce the net generating capacity of the proposed 

CFB boiler by a minimum of 20%,” and thus would require additional output from the 

proposed design to achieve the desired energy production, generating additional emissions 

and additional costs to control those emissions. But a recent study shows that the energy 

penalty (parasitic load) of using MEA for carbon capture at a 500 MW plant is just less than 

20%, while the penalty of using H3-1 at the same sized plant is approximately 16%. Thus, 

the “parasitic load” required for capture should be estimated to be 20% or less, and costs 

should be estimated accordingly. 

Response:

There are no known full scale commercial CCS operations available to evaluate actual 

performance data on at this time. Therefore, all estimates are theoretical, or developed 

through pilot scale tests. 

In the GHG BACT analysis, 20% was used as a lower limit because our research found such 

a wide range of estimates of the parasitic load from a variety of sources. One report from the 

Department of Energy estimates the parasitic load of a full CCS system at over 47%.46 

Another source indicates, “...parasitic energy requirement can range from around 25% for 

 

44 Biomass Co-Firing for the Wolverine Clean Energy Venture, January 30, 2008, pg 7 45 Biomass Co-Firing for the Wolverine Clean Energy Venture, January 30, 2008, pg 8 46 Existing Plants, Emissions and Capture - Setting CO2 Program Goals, Appendix C-5, April 20, 2009, 

DOE/NETL-2009/1366 
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Response to Comments Document 

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post-combustion capture at a high efficiency ultra-supercritical coal plant up to over 37% for 

a typical subcritical plant”47 

The example cited in the comment was part of a Department of Energy network of seven 

Regional Carbon Sequestration Partnerships (RCSPs) that were created to develop the 

technology, infrastructure, and regulations to implement large-scale CO2 sequestration in 

different regions and geologic formations within the Nation. The estimates of parasitic loads 

in the comment reflect the results of a Stage 1 capture trial, and do not include costs 

associated with sequestration, which can substantially increase both parasitic load and cost 

of control. In addition, because this is still a pilot study, there may be additional costs to 

scaling it to a full commercial operation, such as the costs of long term corrosion impacts. In 

addition, the presentation cited by the commenter as the source for the parasitic load 

estimates contains only conclusions of the study and does not provide the data used to 

develop these conclusions. 

Thus MDEQ disagrees that the review was flawed. 

Comment:

Wolverine BACT analysis contains the same deficiency that USEPA identified in its recent 

comments on the GHG Analysis for the Pacificorp Lake Side Power Plant: a failure to 

establish permit emission limits as PSD BACT for GHG emissions. The Wolverine BACT 

analysis also contains the same deficiencies that USEPA identified in its recent comments 

on the WE Energies Biomass Fueled Cogeneration Facility in Rothschild, Wisconsin. In 

those comments, USEPA specified that a GHG carbon dioxide equivalent in units of 

lbs/MWh be established as a BACT limit, the limit needed to be specific to the operating 

conditions, and the limit needed to specify whether it includes startup and shutdown periods. 

Response:

The proposed Wolverine permit contains a limit of 2.1 lb CO2e/KW-hr (gross output) that 

applies at all times, including startup and shutdown. 

G. Material Handling

Comment: 

The draft permit failed to incorporate a BACT analysis including covering storage piles. 

Response: 

MDEQ requested additional information from WCEV regarding the covered storage pile 

issue. WCEV submitted follow-up information on June 22, 2009 which addressed the 

covered storage pile comment. That information showed a cost per controlled ton of 

particulate matter to exceed $4.4 million dollars; that value exceeds acceptable BACT cost 

parameters. Any emissions generated from uncovered storage piles would be fugitive in 

nature. Fugitive emissions – defined under MAPCR 336.1106(l) as those emissions which 

could not reasonably pass through a stack, chimney, vent, or other functionally equivalent 

opening – meet the technological limitation standard included in the BACT definition and are 

 

47 Cost Analysis of Carbon Capture and Storage for the Latrobe Valley, February 28, 2010, Charles Kolstad and 

Daniel Young, Bren School of Environmental Science and Management, University of California, Santa Barbara, 

California) 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

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subject to work practice and operation standards as BACT. The Fugitive Emissions Control 

Plan itself is the work practice standard necessary to satisfy BACT. 

Comment: 

Reliance on opacity, in place of numeric emission limits; fails to include enforceable BACT 

limits for haul roads. The comment further identifies the lack of any other haul roads in the 

draft permit to be in violation of BACT. 

Response: 

Haul road activities are subject to the requirements of the FECP. That plan requires, among 

other things, that unpaved travel surfaces be controlled by the application of water, 

sweeping, vacuuming, or other acceptable dust control method on a frequency sufficient to 

meet the visible emission opacity standard of five percent opacity. BACT is satisfied by the 

implementation of the FECP as a work process standard. There is no practical method to 

quantify emissions from haul roads. Therefore, a mass limit would be unenforceable. 

Comment: 

The PM10 modeling for the 24 hour PM10 NAAQS analysis and the increment analysis is 

based on unsupported and artificially low emission estimates for the O-N Mineral operations. 

This comment further identifies specific equipment inputs used in these modeling analyses 

as not representing worst-case emissions. 

Response: 

MDEQ disagrees with this comment. Commenter is correct that the PM10 modeling analysis 

must meet a worst case emissions standard meaning that the inputs for the computer 

modeling must reflect the highest level of air contaminant emitted from the modeled process. 

However the worst case standard must also reflect any controlling permit requirements for 

that equipment as well. Emissions calculations from the neighboring O-N Minerals operation 

are based on information taken from both MAERS emissions inventory and the current 

Permit to Install (PTI) 31-02A issued to the O-N facility. Calculated values from MAERS 

utilize high levels of control efficiencies. PTI 31-02A requires (among other requirements) 

that most of the limestone processing equipment operate within a building enclosure and 

emit no visible emissions from the operation. Other equipment and operations at the facility, 

including truck traffic and storage piles, are subject to a 5% opacity requirement and 

operational requirement from the facility’s Fugitive Dust Control Plan. Proper operation of 

the required control equipment in PTI 31-02A would reflect a high degree of control 

efficiency. Worst case emissions must represent operation of the equipment under the terms 

of a lawfully issued PTI and cannot be based upon non-compliant operating conditions. 

Because the modeling inputs represent the upper end of allowable emissions from a lawfully 

permitted facility they correctly represent “worst-case” emissions. 

Comment: 

The PM10 modeling for the 24 hour PM10 MAAQS analysis and the Increment analysis is 

based on unsupported and artificially low emission estimates at the proposed coal plant. 

Commenter further identifies the assumed values for moisture content, wind speed, and 

control efficiencies as violating the “worst-case emissions” standard. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

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June 29, 2011 

Response: 

As discussed above, commenter is correct that the PM10 modeling analysis must meet a 

worst case emissions standard meaning that the inputs for the computer modeling must 

reflect the highest level of air contaminant emitted from the modeled process. However the 

worst case standard must also reflect any controlling permit requirements for that equipment 

as well. Permit conditions, including the FECP, require control of generated emissions. 

Assuming constant moisture content is an acceptable procedure when utilizing the AP-42 

equations and emission factors. The assumed values used in this application fall within the 

acceptable range. Wind data was reviewed by AQD staff and deemed acceptable for this 

exercise. The permit conditions, including requirements for operating specific control 

equipment and operational requirements in the FECP, for this facility reflect high levels of 

control efficiency for material handling operations. Worst case emissions must represent 

operation of the equipment under the terms of a lawfully issued PTI and not be based upon 

non-compliant operating conditions. 

Comment: 

The PM10 modeling is based on an inappropriate and unjustified emissions figure for PM10 

from haul roads. In particular, commenter cites the use of AP-42 emission factors found in 

Chapter 13 for silt content as too low and not reflective of worst case-emissions. 

Response: 

AQD staff reviewed the haul road emissions and assumptions contained within the 

application and concluded that those calculations are acceptable. Important to remember is 

that worst case emissions must represent operation of the equipment under the terms of a 

lawfully issued PTI and cannot be based upon non-compliant operating conditions. The haul 

roads are subject to both Special Conditions requiring an opacity limit of 5 % or less and the 

terms of a FECP, which requires wet sweeping for paved roads and wet/chemical 

suppression of dust for unpaved roads in order to meet required opacity limits. As these 

opacity requirements are quite stringent, the use of low silt content for emissions calculations 

is justified. 

Comment: 

It appears that Wolverine failed to include emission rates for the physical working of the 

storage piles in the PM10 modeling analysis. This must be done to accurately account for 

emissions. 

Response: 

Wolverine accounted for emissions from roadways, wind erosion and pile loading activities 

from the storage piles. Emissions associated with the physical working of the pile were not 

accounted for. This number is expected to be a minimal influence on the PM10 modeling 

analysis and not affect the results in a manner which violates the NAAQS or increment 

consumption from this facility. As a reference, Consumers Energy’s recent permit for a 

larger facility calculated emissions from a storage pile as 0.18 lbs PM10 per hour. Those 

values extrapolated over the worst case operating scenario of 24 hrs/day and 7 days/week 

result in less then 0.8 tons of emissions per 12-month rolling time frame. 

 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

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June 29, 2011 

Comment: 

A comment was received stating that “For EULIMESTONE, proposed permit does not 

include an operational limit on the maximum annual throughput of limestone. Limit is needed 

to substantiate several calculations such as the efficiency of the fabric filter and the wind 

erosion emissions calculation, which are based on the amount of limestone supply and 

usage/day.” 

Response: 

There are no underlying regulations requiring fabric filter efficiency and wind erosion 

calculations. As this proposed project is at a facility which is a source category designated 

through rulemaking under Section 302(j) of the CAA, fugitive emissions must be analyzed as 

part of the PSD-BACT review. The special conditions for EULIMESTONE include opacity 

limits, a requirement to install fabric filter control on collected exhaust streams, opacity 

monitoring requirements, and a requirement to implement a Fugitive Dust Control Plan upon 

operation of the equipment. All of these requirements fulfill BACT requirements. Opacity 

limits are specifically included in the definition of BACT. An emission limit of 0.00016 lbs PM 

per 1000 lbs of dry exhaust gas representing fabric filter control of the material handling 

exhaust stream is BACT for processes of this nature. Fugitive emissions – defined under 

MAPCR 336.1106(l) as those emissions which could not reasonably pass through a stack, 

chimney, vent, or other functionally equivalent opening – meet the technological limitation 

standard included in the BACT definition and are subject to work practice and operation 

standards as BACT. The Fugitive Dust Emission Control Plan itself is the work practice 

standard necessary to satisfy BACT. 

Comment:

Is it true that Wolverine will have the largest fuel pile with no dust suppression? 

Response:

No, the proposed draft permit requires fuel piles to use dust suppression. More specific 

details of when and how often to use dust suppression will be developed in the Fugitive 

Emissions Control Plan (FECP) before the facility starts accepting fuels. 

Comment:

The Permit only contains an opacity limit for roads in the section on limestone handling and 

thus fails to include enforceable BACT limits for truck traffic on all roads at the plant. 

Response: 

The AQD included the particulate emissions from the increased truck traffic on all the 

roadways on the facility when it evaluated total particulate emissions from the facility. The 

evaluation showed that the total particulate emissions from the facility are not expected to 

violate state and federal standards. In addition, the facility will have to comply with the 

FECP, which is authorized under the MDEQ State Rules 336.1371 and 336.1372. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

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H. Ancillary Equipment

Comment: 

Proposed EUAUXBOILER emission limits are in lb/MMBtu. It is unclear how the source will 

demonstrate continuous compliance as the monitoring associated with these requirements is 

stack testing every 5 years. Explain how the source will demonstrate compliance, or 

incorporate into the permit additional monitoring and reporting requirements. 

Response:

There is no continuous emissions monitoring required for the auxiliary boiler since the 

operating time will be limited. Required record keeping of fuel certifications and hours of 

operation along with stack testing to verify emission limits will be required to ensure 

compliance. 

Comment:

For EUEMGGEN the proposed emission limits table does not include limits for SO2 and 

VOC. Please add, with appropriate monitoring, recordkeeping and reporting to the permit. 

Response:

The proposed draft permit for the EUEMGGEN emission unit does not include limits for sulfur 

dioxide. However it does include limits for the sulfur content in the fuel, monitoring and 

recordkeeping of fuel supplier certification records and hours of operation limit. When the 

emergency generator emissions were reviewed it was determined that BACT for an 

emergency generator (operating less than 500 hours per year burning fuel oil with a low 

sulfur content) was to limit only the sulfur content of the fuel since that is a limit which is more 

enforceable as practical manner. The fuel oil company is required to do an analysis of the 

fuel and to certify it. This allows more frequent monitoring and recordkeeping of the fuel that 

is burned. 

The VOC emissions were evaluated to be about one ton per year for this size of a generator. 

Since hours of operation are limited, and the generator is operated with good combustion 

control techniques, it was determined that a VOC limit would not add any additional 

protection to health and the environment. 

Comment: 

For EUFIREPUMP, the proposed emission limits table does not include limits for CO, SO2, 

and VOC. Please add, with appropriate monitoring, recordkeeping and reporting to the 

permit. 

Response:

The proposed draft permit for the EUFIREPUMP emission unit does not include limits for 

SO2, CO, or VOC. However, it does include limits for the sulfur content in the fuel, 

monitoring and recordkeeping of fuel supplier certification records and hours of operation 

limit. When the fire pump emissions were reviewed, it was determined that BACT for a fire 

pump (operating less than 500 hours per year burning fuel oil with a low sulfur content) was 

to limit only the sulfur content of the fuel since that is a limit which is more enforceable as 

practical manner. The fuel oil company is required to do an analysis of the fuel and to certify 

it. This allows more frequent monitoring and recordkeeping of the fuel which is burned. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

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June 29, 2011 

The CO and VOC emissions were evaluated to be about a half ton per year each. Since the 

hours of operation are limited and the generator is operated with good combustion control 

techniques, it was determined that a CO and VOC limit would not add any additional 

protection to our health and environment. 

Comment: 

For EUBLACKSTART, the proposed emission limits table does not include VOC limits. 

Please add, with appropriate monitoring, recordkeeping and reporting to the permit. 

Response:

The VOC emissions were evaluated to be about one ton per year. Since the hours of 

operation are limited and the generator is operated with good combustion control techniques, 

it was determined that a VOC limit would not add any additional protection to health and the 

environment. 

Comment: 

For FGCOOLINGTWR, the proposed permit does not include PM emission limits. Please 

add, with appropriate monitoring, recordkeeping and reporting to the permit. 

Response:

The cooling towers emissions are minimal and BACT was considered to be the use of drift 

eliminators with a maximum drift rate of 0.0005 percent or less. The RBLC was reviewed 

and shows a number of entries of cooling towers at power generation facilities. The RBLC 

entries indicate a range of 0.001% to 0.0005% drift loss for MP10 emissions. 

Comment: 

Some cooling towers use algecides to control the formation of algae and molds. This could 

be a source that has not been considered and could emit VOC emissions. 

Response:

To the extent algae growth does occur in the cooling towers it will be controlled by the 

addition of an oxidizing biocide. Oxidizing biocides typically consist of chlorine and bromine 

compounds. These oxidizing biocides do not contain VOCs and do not form VOCs as a part 

of the oxidizing reactions. Usage of oxidizing biocides depends on the type of oxidizing 

biocide used, specific conditions and the level of fouling. There are a number of oxidizing 

biocides which do not contain VOCs on the MDEQ-Surface Water Quality Division’s (SWQD) 

“Water Treatment Additives with the Rule 57(2) Minimum Toxicity Data Base for Aquatic Life” 

list. Wolverine has stated that they will follow the MDEQ-SWQD guidelines regarding toxicity 

of water treatment additives as appropriate. 

As stated on page 5-49 of the original application all VOC-related RBLC entries were for 

cooling towers at refineries. At refineries, the cooling towers would be serving equipment in 

VOC service (equipment that processes, transfers, or contains a VOC or mixture of VOCs), 

such as cracking towers and distillation columns which would have a potential of leaking 

VOC into the cooling media. AP-42, Section 5.1, lists a VOC emission factor specifically for 

refinery cooling towers due to hydrocarbon leaks into the cooling water system. On the other 

hand the AP-42, Section 13.4, provides a methodology for calculating PM emissions only 

from cooling towers in general. The cooling towers at WCEV will not be serving any 
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Response to Comments Document 

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equipment in VOC service. As a result, there is no basis to expect that VOCs will leak into 

the cooling water system and result in VOC emissions from the cooling towers at WCEV. 

Comment:

Is there any chlorine or other chemicals in the water vapor plume from the cooling towers 

and has this been studied? 

Response:

Trace amounts of chlorine will be added to the cooling tower water to reduce algae growth 

on the tower equipment. Water evaporating from the tower will be mostly pure, except for the 

small presence of dissolved solids, which will exit the tower in particulate form. The tower’s 

high efficiency drift eliminators will reduce these particulate emissions greatly. Technical 

studies on the fate of chlorine in cooling towers verify that the majority is consumed in 

reactions that kill the bacteria in the water and only insignificant amounts will be emitted to 

the air. 

Comment:

Several comments were received regarding the use of water in the cooling towers and the 

effect that draining so much water from Lake Huron will have on the lake level. Why does 

the steam need to be discharged to the air instead of used in a cogeneration process? 

Response:

The WCEV facility has been proposed to receive water, for the cooling towers from a portion 

of that which the Carmeuse quarry currently discharges into the creek running through the 

quarry property. Also, the facility has been designed to have zero liquid discharge (ZLD), 

which means there will not be any water discharged into Lake Huron. It will all be 

re-circulated back into the system. 

Any steam generated is used in the process of generating electricity. The water going into 

the atmosphere is water vapor that results from evaporation from cooling the hot water prior 

to returning it to the system for recirculation. This is done to re-circulate the water 

continuously back into the system. 

I. Control Equipment

Comment:

What securities/backups are required for emission control equipment failures? Will the 

emission control equipment be on at all times? What will happen if emission levels rise 

above the limit level? Will the boilers be required to shutdown, if that occurs? 

Response:

The purpose of the malfunction abatement plan is to prevent failures from occurring by 

implementing a schedule for maintenance on all control equipment. 

FGCFB special conditions IV.1 and IV.2 of the draft permit requires the permittee to operate 

the boilers at all times with the control devices listed. If for some reason, there is a 

malfunction of any of the control devices, then the appropriate actions as required in the 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

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June 29, 2011 

malfunction abatement plan (MAP) will be required to be implemented and could result in 

shutdown of the boiler(s). 

Comment:

Why do you consider this proposed plant to be “clean” coal technology? 

Response:

MDEQ has not labeled the proposed plant to be ‘clean’ coal technology. However, Clean 

Coal Technology is defined in the Michigan Department of Environmental Quality, Air Quality 

Division, Pollution Control Rule 336.2801(h) as any technology, including technologies 

applied at the pre-combustion, combustion, or post-combustion stage, at a new or existing 

facility which will achieve significant reductions in air emissions of sulfur dioxide or oxides of 

nitrogen associated with the utilization of coal in the generation of electricity, or process 

steam which was not in widespread use as of November 15, 1990. The control equipment 

that WCEV has proposed to use are selective non-catalytic reduction (SNCR) to control NOx 

emissions, limestone injection into the CFB boiler and polishing scrubber to control SO2 

emissions, sorbent injection to control mercury emissions and fabric filter baghouse to 

remove particulates. 

Comment:

Commenter asked if the NOx control for this facility is via an SNCR? What is an SNCR? 

Response:

Yes, the CFB boilers will use a selective non-catalytic reduction (SNCR) system for NOx 

control. In an SNCR system, a reagent (ammonia or urea) is injected into the flue gas in the 

furnace of the boiler within an appropriate temperature window. The reagent reacts to 

reduce NOx into nitrogen and water. 

J. Start-up and Shut-down Emissions

Comment:

Why does a base load facility need so many hours to start-up and shutdown? 

Response:

The facility is permitted to operate continuously. However, there are expected times that the 

facility will need to shutdown for maintenance. It is also likely that the facility may encounter 

some occasional unexpected shutdowns. The duration of each startup and shutdown as well 

as emission estimates associated with unsteady state operation were compared to the 

manufacturer’s data and information from similar sources and found to be acceptable. In 

addition, the increase in emissions during startup and shutdown conditions was included in 

the modeling analysis and maximum impacts are still below the federal health standards. 

The company is also required to submit a plan that describes how emissions will be 

minimized during startup and shutdown conditions before operation of the equipment is 

allowed. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

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June 29, 2011 

Comment:

The Draft Permit erroneously exempts Wolverine from NOx and CO BACT limits during 

periods of startup, shutdown, and maintenance.

Response:

The commenter’s claim that the draft permit exempts startup/shutdown operations from 

BACT limitations is incorrect. The permit contains BACT emission limits for NOx and CO in 

units of pounds per hour that are applicable each hour the boiler operates, including periods 

of startup and shutdown. When measuring the NOx concentration in parts per million (ppm) 

with a continuous emission monitor system (CEMs), a false high indication for NOx occurs 

when very low CO2 concentrations are measured. This data is used to calculate NOx in 

pounds per million Btu (lb/MMBtu) emission rates during startup and shutdown operation. 

The NOx emission rate equations are found in Method 19, Equation 19-7 of 40 CFR Part 60, 

Appendix A and Formula F-6 in Section 3.2 of 40 CFR Part 75, Appendix F. Mathematically, 

the last term in the equation causes the lb/MMBtu emission rate calculation to approach 

infinity as the measured diluent value approaches a value representative of zero heat input 

(i.e. 0.0 % when CO2 is the monitored diluent). Thus, during periods of boiler startup and 

shutdown when the heat input and CO2 concentrations are low (or high as would be the case 

if O2 were being measured), the NOx lb/MMBtu emission rates become artificially inflated. 

This is also the reason why the New Source Performance Standards (NSPS) for NOx 

emission limit utility boilers, namely, 40 CFR Part 60, Subparts A and Da, Section 

60.48Da(c), does not apply during periods of boiler startup, shutdown or malfunction. This 

same response also applies to CO emissions. 

K. Annual Emissions

Comment: 

Will the individual emissions of the Wolverine plant be less than or more than existing coal 

plants in Michigan? In what relationship? 

Response:

Size for size, the proposed coal plant will emit less emissions than existing coal plants as a 

result of the best available control technologies that have been proposed. 

Comment: 

On September 18th, 2008, at a Presque Isle County Planning Commission meeting, Lee 

Sprague stated that “the MDEQ has not licensed a coal plant since 1984, they do not have 

the experience and expertise on hand to deal with even one permit, and they are bombarded 

with five of them.” Is that true? 

Response:

The MDEQ disagrees with the commenter. Even though there has not been a “new” coal 

plant permit issued in recent years, the AQD has had many permit applications for 

modifications at existing plants that has required us to keep up to date with what is 

happening around the nation with new and modified applications. The AQD participates on 

monthly calls with EPA Region 5 to discuss technologies, current rule revisions, new rules, 

recent court actions, BACT analyses, test methods, and policies. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 123 of 140 

June 29, 2011 

Comment: 

The generating capacity of Wolverine Power would be 600 megawatt, and the proposed 

generating capacity of Consumers Energy in Bay City would be 930 megawatt. Why is 

Wolverines plant proposing it would emit 820 pounds more of nitrogen oxide into the air than 

the Consumers Energy plant and Wolverine is 330 MW less capacity? 

Response:

It is not clear what limits the commenter is referring to. Consumers Energy has a permit limit 

of 409.5 pounds per hour and Wolverine is proposing 281.1 pounds per hour, for NOx. 

Comment:

Where and when has a plant of this size been permitted and are emissions data on record? 

Does it use like fuel? 

Response:

There are a number of comparable existing plants with available emissions data. Information 

on the units was gathered including the unit characteristics, primary and secondary fuels, the 

permit date, the permit limits, the type of pollution control equipment and the level of 

emissions. The most similar CFB boilers (with the same type of controls) are Units 1 and 2 

at JEA Northside Generating Facility located in Jacksonville, Florida. They are permitted to 

use coal and pet coke as fuel in the boilers, as Wolverine is proposing. The following table 

compares the JEA Northside facility with that of Wolverine. 

 

Pollutant Wolverine JEA Northside 

SO2 0.06 lb/MMBtu (30-day), 

0.05 lb/MMBtu (12month), 

303 pph (24-hr) 

0.15 lb/MMBtu (30 day), 

0.20 lb/MMBtu (24-hr) 

NOx 0.07 lb/MMBtu (30-day), 

281.1 pph (24-hr) 

0.09 lb/MMBtu (30-day) 

H2SO4 0.003 lb/MMBtu (24-hr) 1.1 pph 

PM 0.010 lb/MMBtu 0.011 lb/MMBtu 

PM10 0.026 lb/MMBtu, 

78.8 pph 

0.011 lb/MMBtu ** 

PM2.5 0.024 lb/MMBtu, 

72.7 pph excluding su/sd, 

54.5 pph during su/sd 

No limit 

CO 0.15 lb/MMBtu (30-day), 

744 pph (24-hr) 

0.22 lb/MMBtu (24-hr) 

**Limit is listed in the permit as PM/PM10. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 124 of 140 

June 29, 2011 

Comment: 

There were some incorrect emissions in the MDEQ Fact Sheet. They were as follows: VOCs 

were incorrectly calculated using the proposed pound per hour VOC limit of 17.8 rather than 

the intermediate load limit of 0.0066 lb/MMBTU. The lb/MMBtu limit effectively and 

enforceably limits the maximum VOC emissions from the CFB boilers to 122.6 tons/year. 

The current proposed limit is 33.3 tons/year less than the value listed in the Fact Sheet. 

PM10 allowed emission was not updated in the Fact Sheet to reflect the final proposed 

PM10 limit of 0.026 lb/MMBtu. This PM10 limit was adjusted during the permit application 

review process based on the 112(g) analysis for the CFB boilers. As a result of this change, 

the allowed PM10 emissions from the CFB boilers were reduced from 717.0 tons/year to 

690.1 tons/year. This limit is 26.9 tons/year less than the number listed in the Fact Sheet. 

Response:

MDEQ has taken note of the discrepancy. However, as noted earlier, pages 3 -10, 

intermediate load limits are being removed from the permit. 

Comment: 

There are currently 88 operating coal-fired power plants in Michigan emitting 2,488 pounds 

of mercury, 91 million tons of Carbon Dioxide, and 300,000 tons of Sulfur Dioxide annually. 

Additional annual emissions from 8 new coal plants include: 232 pounds of Mercury, 13 

million tons (or more) of Carbon Dioxide, 6776 tons of Sulfur Dioxide, and 2463 tons of 

additional particulate matter (soot). 

Response:

MDEQ disagrees with the commenter. The MDEQ Mercury Strategy Staff Report in 2008 

reported 21 plants. There have not been any new coal-fired power plants issued since the 

report was released. The report can be downloaded at: 

http://www.michigan.gov/documents/deq/MDEQ_MSWG_FinalReportJan2008.pdf_222

256_7.pdf. The source of the commenter’s information was not provided for MDEQ to 

determine the correctness of the figures. 

Comment: 

There are several contaminants emitted such as HCl, HF, and the presence of chlorine in the 

fuel oil for startups that could indicate formation of dioxins. Combination with 20% wood 

waste also could contribute to dioxin emissions. There is no discussion or determination of 

whether control of dioxins should be considered. Wood waste should also be prohibited that 

has been painted or chemically treated. 

Response:

Dioxin formation is a by-product created during incineration, uncontrolled burning, and in 

some industrial processes. Just as combustion allows for formation of dioxins it also can 

destroy dioxins. The proper combustion temperature, combustion time, turbulence, and then 

quickly cooling the combustion gases minimizes the presence of certain metals known to 

promote dioxin formation. Wolverine will use good combustion control practices in the CFB 

boilers to minimize dioxins. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 125 of 140 

June 29, 2011 

Comment: 

When looking at real-world operations, CFB boilers do not emit less NOx than PC boilers. In 

fact, the opposite is the case. This is true whether one looks at uncontrolled emissions or 

controlled emissions. 

Response: 

Commenter did not provide any specific examples. NOx present in flue gas is a result of two 

sources: the oxidation of nitrogen compounds in the fuel (fuel NOx) and the reaction among 

nitrogen and oxygen in the combustion air (thermal NOx). CFB boiler combustion is a newer 

technology that provides greater fuel flexibility and more efficient heat transfer. The 

combustion temperature of a CFB boiler is a few hundred degrees lower than a PC boiler 

which favors lower NOx formation because the oxidation of the nitrogen in the fuel is 

suppressed. 

Comment: 

Emission limits for NOx, CO, SO2, and VOC in the proposed draft permit differ from that 

proposed in the application. 

Response:

The Fact Sheet states that during the permit review process, the permittee submitted new 

information requesting different emission limits. The emissions limits, as presented in the 

draft permit for public review, reflect the most current information used in the application 

review. The MDEQ reviewed all emission limits and determined they meet all state and 

federal regulations. 

L. Monitoring

Comment

The draft permit does not require PM CEMs, making the alleged BACT and MACT limits 

unenforceable. 

Response: 

A PM CEMS measures filterable PM only. The limits in the permit for particulate matter 

include both filterable and condensable particulate. 

Comment:

How will compliance with the emission limits in the permit be demonstrated? 

Response:

There are several ways in which emissions from a process may be monitored: stack 

sampling, continuous emissions monitors (CEMS), and continuous opacity monitoring 

(COMS). 

Periodic stack tests are a required part of the annual Relative Accuracy Test Audits of the 

Continuous Emission Monitoring Systems at the facility. The stack testing requirements of 

the Permit to Install will also be included in a Renewable Operating Permit which the facility 
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Response to Comments Document 

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June 29, 2011 

must obtain. Also, General Condition No. 13 provides for additional stack testing not 

specifically included in the permit. 

For air emissions, the act of sample collection involves the use of specialized equipment 

operated over an extended time period (usually three one-hour samples). Many process and 

control equipment variables must also be monitored during the stack test because of their 

possible effects on the air emissions. These may include fuel mixture content, steam output, 

startup/shutdown conditions, exhaust gas variables (moisture content, temperature, flow 

rate), and control equipment operating parameters. This sampling process provides a 

“snapshot” of the process emissions under known operating conditions. Three collected 

samples are then analyzed for each pollutant. 

One objective of stack testing is to identify pollutant emission rates at “worst case” operating 

conditions. Operating parameters for the stack test are delineated in the stack test plan. 

Another objective is to identify measurable process and control system operating parameters 

which can be used to conclude that a process is operating within the allowed emission limits. 

For many small facilities of various types, a single stack test is conducted upon issuance of a 

Permit to Install. For many major sources of air emissions, stack testing is repeated every 

five years under a Renewable Operating Permit. 

In addition to stack testing, Continuous Emission Monitoring Systems for NOx, CO, SO2, and 

exhaust gas oxygen content are required. Also, a Continuous Opacity Monitoring System 

(opacity indicates the presence of particulate matter) is required. These systems provide an 

indication of efficient and proper operation of the process, which means that emissions of all 

pollutants are reduced. 

All records from stack testing and CEM systems must be kept on site for five years to 

demonstrate compliance with emission limits during site inspections from the district office. 

Comment:

Where are the stack emission controls located on/in the stack? 

Response:

It is unclear what the commenter is asking. There will be continuous emission monitoring 

(CEM) devices and continuous opacity monitoring (COM) device which are typically located 

after the control equipment and before the stack. These devices continuously monitor the 

amount of pollutants in the exhaust gases before the exhaust leaves the stack. There will be 

CEM devices for Nitrogen Oxide (NOx), Sulfur dioxide (SO2), and mercury. The COM will 

continuously monitor opacity coming from the stack. 

There will also be pollutant emission controls, usually referred to as “control equipment” for 

NOx, sulfur dioxide SO2, and mercury. The NOx control equipment proposed is selective 

non-catalytic reduction (SNCR), it will be located after the CFB boiler and will reduce NOx 

emissions in the exhaust gases; to control SO2 emissions, limestone injection will occur in 

the CFB boiler and a polishing scrubber will follow the SNCR; sorbent injection system to 

control mercury emissions will follow the polishing scrubber; and a fabric filter baghouse to 

remove particulates will follow the sorbent injection system. 
Wolverine Power Supply Cooperative, Inc. 

Response to Comments Document 

Page 127 of 140 

June 29, 2011 

Comment: 

The consultant for Wolverine commented that an inadvertent error was made when 

formatting the proposed permit for public comment. During permit development, the MDEQ 

had language for Special Conditions relating to a schedule for the installation and operation 

of continuous emission monitoring (CEM) and emission testing of the new CFB boilers which 

provided, “Within 90 days of commencing commercial operation, as defined in 40 CFR 72.2, 

but no later than 12 months after commencement of initial startup of each boiler included in 

FGCFB.” That language remains in proposed conditions VI.6, 8, 9, and 11 -16. However, it 

has been omitted from proposed conditions V. 3 – 9 and replaced with a requirement to 

conduct stack testing “within 180 days after commencement of initial startup...” 

Response:

The MDEQ disagrees with commenter. The draft special conditions were reviewed and 

accepted by Wolverine before the comment period. MDEQ will leave the language as it was 

proposed during the comment period. 

Comment:

Will the plant personnel be qualified or certified to perform the modification, installation, 

periodic maintenance, corrective maintenance, and routine calibrations of the monitoring 

devices? What standards/criteria are used in the certification? Who certifies the technician? 

Response:

Generally when continuous emission monitoring devices are installed at a facility, plant 

personnel will operate and maintain the monitors. The monitors are required to be calibrated 

on a daily basis, so it is usually plant personnel who are assigned the calibration and 

maintenance functions. Plant personnel are trained in the operation and maintenance of the 

continuous emission monitors. 

With regard to standards used in the certification of the monitors, the EPA has published 

performance specifications which must be followed in the certification of the monitors. These 

standards must be used in the installation and operation of the monitors. 

In addition to the daily calibration of the monitors, the monitors are required to have 

calibration gas audits (CGAs) on a quarterly basis, and have relative accuracy test audits 

(RATAs) on an annual basis. The MDEQ participates in the RATAs and also reviews 

maintenance logs on the monitors. 

The specific requirements for the installation calibration and maintenance of the continuous 

emission monitors are contained in special condition numbers VI.2 and VI.3 for the CFB 

boilers. 

Comment:

How can we trust a company to do self monitoring? 

Response:

The facility is a major source of emissions and is required to obtain a Renewable Operating 

Permit (ROP). The ROP requires the company to certify that they are in compliance with the 

terms and conditions of their permit semi-annually. Self monitoring is therefore not 

discretionary. The company will show compliance with their emission limitations through the 

use of continuous emission monitors, recordkeeping, and material analysis. Continuous 
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June 29, 2011 

emission monitors are subject to federal requirements which require calibration as well as 

certification that the continuous emission monitors are calibrated and working properly. 

MDEQ staff will review this information and will verify that calibrations are done correctly by 

doing their own on site calibrations. 

Records for emissions and process parameters will be stored and retained for at least five 

years and is shared with AQD. AQD has the ability to perform an independent analysis of 

the facility at any time. 

The responsible official of any facility which has an ROP, can be criminally prosecuted, if the 

responsible official falsified information, or violated the terms and conditions of the operating 

permit. 

Comment:

Who is to monitor the control system to ensure the proper operation and maintenance? Will 

the monitoring be continuous and will records be kept on file? 

Response:

The company will be required to develop a preventative maintenance plan for the control 

system which includes the manufacturer’s recommended guidelines. The AQD is 

responsible for approving this plan and overseeing its implementation. The company cannot 

operate the equipment until the plan is approved. The approved plan will be kept on file at 

the AQD Gaylord District Office and at the facility. When the AQD district personnel go to 

the facility for an inspection the company will be required to allow the AQD to view any 

records needed. 

M. Compliance Testing

Comment:

Why is Wolverine allowed to choose their own stack testers? Shouldn’t the DEQ do the 

testing? 

Response:

Due to the large volume of testing required to analyze the air contaminants potentially being 

emitted from facilities all over Michigan, the MDEQ does not perform emissions testing. It is 

the responsibility of the owner of the facility to contract a certified tester and conduct and pay 

for emissions testing. However, the AQD’s Technical Programs Unit reserves the right to 

witness the testing and thoroughly reviews test methods and reports before approving or 

denying results submitted by the tester. 

Comment:

The testing requirements in the draft permit are written in a very vague way referring to 

Appendix A and/or a test plan submitted to the AQD. You should spell out exactly what test 

method you’re going to require to be used. 

Response: 

The testing condition requires that a complete test plan be submitted 30 days prior to testing. 

The final plan must be approved by the AQD prior to testing. The testing methods are 
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June 29, 2011 

proposed in the test plan, since the methods could change before the stack test is 

performed. If AQD does not agree with the test methods proposed then the permittee runs 

the risk of performing an unacceptable compliance test. This type of mistake is costly for the 

permittee, as they will still be expected to perform the compliance test with an approved 

method. 

Comment: 

The draft permit omits averaging times for numerous pollutant limits. Provisions allowing 

later determinations as to test protocols, time periods, and operating scenarios are not 

practically enforceable. 

Response: 

AQD permits normally do not contain averaging times for pollutant limits that will 

demonstrate compliance through stack testing. The test plan is required to be submitted 30 

days prior to testing which will specify the test protocols, time periods (averaging times), and 

operating scenarios. This allows flexibility to choose the optimum and best methods. 

Comment:

There are no provisions for future stack tests for toxic air contaminants. There is much 

uncertainty concerning the actual emission of toxic air contaminants. Testing for these 

pollutants must be performed before a permit is issued and annually thereafter. Testing 

must be conducted under worst case operating conditions. There is no monitoring for all 

pollutants emitted from the stack, so MDEQ doesn’t know what’s coming out of the stack. 

Response:

As a part of the application review, AQD staff evaluated the generation, and potential 

emission, of toxic air contaminants. This evaluation included multiple fuels and fuel blends. 

The applicable regulations governing this review are; MAPCRs 336.1224 through 336.1232, 

and certain standards promulgated under Section 112 of the Clean Air Act. Individual toxic 

air contaminants testing/monitoring requirements were included as required by the applicable 

regulations. In some circumstances similar toxic air contaminants were grouped under a 

surrogate limit designed for compliance with the applicable regulations. All inclusive toxic air 

contaminants testing/monitoring requirements are not required under any of the applicable 

regulations. 

N. Enforcement

Comment:

What process will be in place to ensure that the facility will not go above the allowed 

emissions? In the future if and when new information changes standards, how will 

enforcement change? 

Response:

Changes will be addressed as the regulations dictate. Often there is a lead time allowed to 

implement new standards to allow for design and construction. Emission monitoring using 

Continuous Emission Monitors (CEMs), site inspections, and the Malfunction Abatement 

Plan (MAP) will all provide a way to measure compliance with allowed emissions. Also, 
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June 29, 2011 

public reporting of emission concerns is an important part of compliance, as it alerts the AQD 

to investigate problems. 

A MAP must include the following components as described in Rule 336.1911: a 

preventative maintenance program to minimize equipment malfunctions or failures, identify 

the process and emissions control equipment operating variables that will be monitored to 

detect a malfunction, and description of the corrective activities, methods, and/or operational 

changes to quickly restore normal operating conditions. 

Comment:

How many times has a MDEQ permitted coal-fired power plant violated its air permit? Be 

specific with numbers and types of violations. How does violator correct air permit 

violations? Do they clean environment or pay a fine? 

Response: 

Air Quality Division (AQD) Field Section staff are located in eight district offices and two field 

offices. Additional investigatory and compliance support responsibilities are assigned to staff 

in the central Lansing office. Together, each year these AQD staff are responsible for 

conducting approximately 1,000 source inspections, investigating over 1,000 citizen 

complaints of air pollution, quality reviewing and assuring approximately 2,000 emission 

inventory reports, and sending out in excess of 500 Violation Notices. These AQD staff are 

responsible for evaluating the adequacy of the compliance programs to assure and maintain 

compliance, conducting oversite of over 200 stack tests and 750 in-stack monitors, resolving 

cited violations, and handling issuance, renewals and modifications for over 500 Title V 

Permits. 

When, as a result of compliance assurance and source inspections, a violation is identified, 

staff advise the source of the violation, which is documented in a violation notice (previously 

identified as letters of violation). The AQD requires the source to take corrective action to 

resolve the violation and implement a corrective action plan identifying how the source will 

take preventative action to avoid repeating the cited violation. 

The AQD reviews the magnitude, gravity, and frequency of each violation to determine if 

formal administrative action should be implemented to reflect and make enforceable the 

corrective action and enhance compliance assurance. Such an enforceable corrective action 

plan may be implemented promptly at the source, may be implemented and made 

enforceable under terms of the air use permit and/or may be implemented through an 

enforcement document such as an administrative order. 

If a violation is deemed significant, the source is contacted by AQD’s enforcement staff and a 

meeting is convened to discuss the cited violation and formalize a legally enforceable 

corrective action plan which is state and federally enforceable. In such an enforcement 

document a corrective action is required to be implemented, a settlement amount is required, 

and future violations may be subject to monetary sanctions. 

The authority to assure compliance begins at the federal government through the USEPA. 

The USEPA has delegated to the state both the requirement and the authority to write air 

use permits and enforce the federal Clean Air Act Amendments (Act) requirements under the 

Natural Resources and Environmental Protection Act, Part 55 (Part 55) and the Rules 

promulgated under the Act. The Act and the Rules are incorporated into the State 
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Implementation Plan (SIP), which has been approved by the USEPA. Additional federal 

requirements have been conditionally delegated to the State. The State, through Part 55, 

has authority to issue permits, to enter orders, and to collect fines and penalties to assure 

compliance is attained and maintained, to preserve the health, safety and welfare of the 

citizens as well as the natural resources. 

Comment:

The draft permit provisions that reference actions, steps, content or requirements contained 

in documents that fall outside of the permit are not enforceable. The specific stated concern 

is two permit references to compliance with manufacturers’ specifications. Draft Permit 

EUEMGGEN SC III.1 and EUFIREPUMP SC III.1. 

Response: 

The conditions that reference manufacturers’ specifications are from the federal New Source 

Performance Standards (NSPS). One of the underlying applicable requirements for the 

special condition is 40 CFR 60.4206 which clearly states that “Owners and operators of 

stationary CI ICE must operate and maintain stationary CI ICE that achieve the emission 

standards as required in §§60.4204 and 60.4205 according to the manufacturer's written 

instructions or procedures developed by the owner or operator that are approved by the 

engine manufacturer, over the entire life of the engine.” 

Comment:

The word “satisfactory” is too subjective to be practically enforceable. The draft permit must 

be rewritten to delete all instances in which the term “satisfactory” is used. 

Response: 

The term “satisfactory” is used to allow for flexibility among different facilities. The MDEQ 

district inspector will review source records and the manner in which they are kept, to ensure 

the records are demonstrating compliance with the special conditions in the permit. 

Comment:

A reference to operation of the turbine generator EUBLACKSTART emission unit with good 

pollution control practices is vague and unenforceable. 

Response: 

The condition that references good pollution control practices is from the federal New Source 

Performance Standards (NSPS). One of the underlying applicable requirements for the 

special condition is 40 CFR 60.4333 which clearly states in the NSPS that “You must operate 

and maintain your stationary combustion turbine, air pollution control equipment, and 

monitoring equipment in a manner consistent with good air pollution control practices for 

minimizing emissions at all times including during startup, shutdown, and malfunction.” 

O. Rules and Regulations

Comment: 

Emission limit requirement for the CFB boilers is missing for 40 CFR Part 60, Subpart Da 

which requires a 95% SO2 emissions reduction based on a 30 day rolling average. 
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Response:

This requirement is an “OR” requirement. The regulation states that the emission unit must 

comply with 40 CFR 60.43Da(i)(1)(i) OR 40 CFR 60.43Da(i)(1)(ii). The draft permit requires 

compliance with 40CFR 60.43Da(i)(1)(i), which is that SO2 must be less than 1.4 lb/MW-hr, 

as determined on a 30-day rolling average. 

Comment: 

How do the air quality regulations for power plants in Michigan compare with those of other 

states, particularly with those adjacent states? 

Response:

All states must follow the federal rules and regulations which are consistent across states 

and their own state rules. Those regulations are Prevention of Significant Deterioration 

(PSD), New Source Performance Standards (NSPS), National Emission Standards for 

Hazardous Air Pollutants (NESHAP), and Maximum Achievable Control Technology (MACT). 

All states have their own rules which are similar and cannot be any less stringent than 

federal rules and regulations. 

P. Malfunction Abatement Plan (MAP)

Comment:

The condition requiring a malfunction abatement plan (MAP) also allows changes in the 

malfunction abatement plan (MAP) with the approval of the district supervisor. This allows 

the DEQ to make important changes to the permit without informing the public. 

Response:

Changes in the MAP allow for flexibility and quick response to modifications in the operation 

of the plant which do not meet the definition of modification and therefore do not require a 

permit or public comment. 

 

Comment:

The draft permit references a yet-to-be-developed malfunction abatement plan (MAP) and 

fugitive emissions control program (FECP) without specifying the contents of these. 

Consequently, the conditions referencing the MAP and FECP are not enforceable and violate 

the requirements of the CAA. 

Response: 

The MDEQ accurately informed the public during the public hearings and correctly 

referenced development of a MAP and FECP to be working documents referenced from 

within the permit but which can be fine tuned subsequently. It is standard practice to attach 

MAP and FECP documents to permits to allow inspectors and district supervisors to require 

additional modifications of these working documents once a facility is constructed, and 

during the time that it continues to operate thereafter. It is in the public and environment’s 

best interests to retain these documents as references within the permit and the specifics of 

the MAP and FECP to be fine tuned over time to reflect changes in roadway maintenance 

and dust control techniques, equipment degradation and process refinements to assure 

protective measures are implemented and maintained in the best fashion. R 336.1911 
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(“Rule 911”) was most recently updated in March 2002, and has been part of the State 

Implementation Plan approved Rules since at least January 1980. R 336.1911(2) identifies 

in detail the minimum requirements of an acceptable MAP, which must be present before 

approval and with which it may practically enforceable.

Q. Emergencies and Safety Concerns

Comment:

Who should I contact to report a pollution emergency? 

Response:

In addition to your local police and fire departments, you may call the Pollution Emergency 

Alert System (PEAS) at 1-800-292-4706. This telephone number is operated by MDEQ and 

is staffed 24 hours per day. Information received by the PEAS operator is quickly forwarded 

to the appropriate agencies. 

Comment:

What types of accidental releases does the air-use permit address? 

Response:

A facility is required to comply with all permit conditions, including emission limits, at all 

times. General Condition No. 7 requires the facility to notify the District Supervisor, AQD, of 

abnormal conditions or malfunctions resulting in certain types of emissions in excess of a 

standard or limitation lasting more than one hour. This condition places an additional burden 

on the facility to investigate and self-report malfunctions that cause excess emissions. 

Specifically, the facility is required to give the AQD a written summary of the actions taken to 

correct and prevent recurring malfunctions. These actions become a part of the facility’s 

preventive maintenance and malfunction abatement plan. 

Comment:

What is being done to address accidental releases? 

Response:

The federal Clean Air Act requires that many facilities file risk management plans (RMPs) 

with the U.S. Environmental Protection Agency (U.S. EPA) and work with the local 

emergency planning committee to ensure response plans are in place in the event of an 

emergency. Local governments and local emergency response entities, such as fire and 

police departments, have primary responsibility for first response during emergencies. 

MDEQ works with the primary responders in a support role during emergencies. The 

company has developed an emergency preparedness plan with local officials, which must be 

continuously maintained and updated annually, and has a RMP on file with the U.S. EPA. 

Air-use permits ensure that worst-case air emissions from process operations meet the 

appropriate air pollution control requirements and health protective limits. AQD’s primary 

responsibility is to ensure that a facility complies with all applicable control technology and 

health standards. Permit conditions require that a facility properly install, operate, and 

maintain production and control equipment and require monitoring and recordkeeping of 

critical parameters to ensure that proper equipment operation is maintained. Also, permit 
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conditions require the installation of specific safety devices and require the periodic 

inspection of equipment for wear and deterioration. Once a permit has been issued, AQD 

makes periodic inspections and/or requires periodic stack testing to determine whether or not 

the facility is operating in compliance with its air-use permit. The draft permit conditions for 

this specific modified process include various monitoring, recordkeeping, reporting, and 

equipment/operational requirements in order to ensure compliance with emission limits. 

When violations are found, AQD takes enforcement action and makes certain they are 

addressed and corrections made promptly. 

R. Public Participation Process 

Comment: 

How soon after the end of the comment period will the AQD make a finding and issue a 

permit to install and operate? 

Response:

Any action on the proposed permit by MDEQ will occur after sufficient time to review and 

address all comments received during the comment period. Recognizing that the magnitude 

of this application far exceeds the average application this will likely be a lengthy process. 

Previously identified interested parties will receive notice of a final action. 

Comment: 

There is no ability of the public to have input on the adequacy of proposed pollution controls. 

Response:

The primary purpose of the public comment period is to allow the public an opportunity to 

review the proposed project and provide input. Further, MDEQ posted all permit applicant 

submittals on the internet to better provide the public an opportunity to review all information 

and provide input. 

Comment: 

The notice of hearing does not mention the release of mercury from the proposed plant nor 

does it take into consideration cumulative impacts to human health from the combination of 

pollutants to be released. 

Response:

The notice of hearing is only required by the Natural Resources and Environmental 

Protection Act, Act 451 of 1994, Part 55, Section 5511(3)(b) to include criteria pollutants that 

have been determined to increase significantly and the air impacts associated with the 

increase. Mercury is not a criteria pollutant so it was not listed in the notice of hearing. 

However, mercury, the air impacts and the detailed review the MDEQ did was included in the 

Public Participation Documents for Wolverine Power Supply Cooperative, Inc., Permit 

Application Number 317-07. 
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Comment:

Quoting your own documents (MDEQ’s), “It has been preliminarily determined that the 

proposed installation of the facility will not violate any of the department’s rules nor the 

national ambient air quality standards.” What is the point of the public hearing? 

Response:

The permit conditions reflect the rules and laws that the facility must operate under. The 

draft permit itself is the preliminary determination. The purpose of the public participation 

process is to obtain input on the preliminary determination from all affected parties, including 

the applicant and general public. This helps the decision-maker to make a more informed 

final decision on the permit application. 

Comment: 

Residents of Ontario should be asked for their approval of the new coal plant, since 

emissions will affect them too. 

Response:

The following recipients received the draft permit to install and they were copied on the letter 

to Wolverine referencing when the public comment period for the proposed PSD source 

would begin: Mayor Beach Hall, City of Rogers City; Ms. Susan Rhode, Presque Isle County 

Clerk; Honorable Laurel Broten, Ontario Misnistry of the Environment; Mr. Mike Moroney, 

Ontario Ministry of the Environment; Ms. Pamela Blakley, U.S. Environmental Protection 

Agency, Region 5; Ms. Laura Cossa, U.S. Environmental Protection Agency, Region 5; Mr. 

Jim Warner, Minnesota Pollution Control; Mr. Jeff Hanson, Wisconsin Bureau of Air 

Management; Ms. Laurel Kroack, Illinois EPA; Mr. Steve Blaser, Office of Air Quality IDEM; 

Mr. Robert Hodanbosi, Ohio EPA; Ms. Joyce E. Epps, Pennsylvania Bureau of Air Quality 

Control; Mr. David Shaw, New York Department of Environmental Conservation; Mr. John 

Bunyak, Isle Royale National Park Federal Land Manager Isle Royale National Park 

Superintendant; Ms. Sandra Silva, Seney National Wildlife Refuge Federal Land Manager; 

Seney National Wildlife Refuge Manager; and Ms. Janis Denman, MDEQ. Anyone is 

allowed to make comments on the proposed new plant during the comment period. The 

approval or denial of a draft permit to install is not based on a popularity vote, but rather 

information supporting state and federal regulations. 

Comment:

Concern was expressed that a single non-elected official has the power to approve a permit. 

Response:

Previous to Executive Order 1991-31, air use permits have been approved by the Air 

Pollution Control Commission. The Air Pollution Control Commission had been given the 

authority to approve air use permits. Executive Order 1991-31, which was signed by 

Governor John Engler on November 8, 1991, abolished the Air Pollution Control Commission 

and assigned their responsibilities to the Director of the Department of Natural Resources. 

Included in that transfer of responsibility was the approval of air use permits. Executive 

Order 1995-18, signed by Governor John Engler on July 31, 1995, created the MDEQ. The 

Air Quality Division was moved to the MDEQ. The powers of the director of the DNR as they 

related to approval of environmental permits were transferred to the Director of the MDEQ or 

the Director’s delegated decision maker. Approval of permits is being done in accordance 

with these executive orders, which prescribe that one individual has the authority to approve 
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a permit. Even though one person is responsible for approving the permit, the technical 

review is still the same, and the permit has the same opportunity for public review and input 

that existed with the Air Pollution Control Commission. 

Comment:

How can the decision be appealed? 

Response:

Any person may appeal the permit decision as specified in the Natural Resources and 

Environmental Protection Act, Act 451 of 1994, Section 5505(8), which states: 

Any person may appeal the issuance or denial by the department of a permit to install, a 

general permit, or a permit to operate authorized in rules promulgated under subsection (6), 

for a new source in accordance with section 631 of the revised judicature act of 1961, Act 

No. 236 of the Public Acts of 1961, being section 600.631 of the Michigan Compiled Laws. 

Petitions for review shall be the exclusive means to obtain judicial review of such a permit 

and shall be filed within 90 days after the final permit action, except that a petition may be 

filed after that deadline only if the petition is based solely on grounds arising after the 

deadline for judicial review. Such a petition shall be filed no later than 90 days after the new 

grounds for review arise. Appeals of permit actions for existing sources shall be in 

accordance with section 5506(14). 

In addition, any person may file an action in a court of competent jurisdiction on a permit or 

consent order. 

S. Miscellaneous 

Comment:

Will Wolverine be able to commence construction based on this permit? 

Response:

Yes, if the permit to install is approved then Wolverine will be able to commence 

construction. 

Comment:

Has anyone from the DEQ that is involved in this permit visited the proposed site? 

Response:

Yes. All AQD staff that attended the hearing visited the proposed site. In addition, the AQD 

Gaylord District Office Inspector responsible for inspecting the facility is familiar with the area 

and the site. 

Comment:

What is the AQD required to know about the surrounding property use and what is their 

procedure for gathering and evaluating this information? 
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Response:

The location of any facility is an issue addressed by local government through the planning 

and zoning processes. The Air Quality Division does not control the selection of sites for 

industrial facilities nor does it have jurisdiction over local zoning issues. Site selection is 

done by the permit applicant. A site assessment is conducted by Air Quality Division staff as 

a part of the permit review process and air pollution impacts are reviewed. 

Comment:

Does the State prefer or encourage the redevelopment of industrial land rather than to 

industrialize and take out of production agricultural land? Is the State persuaded by specialinterest groups to make this decision? 

Response:

As a regulatory agency, the Air Quality Division cannot exercise non-technical discretion in 

the issuance of air use permits. The permit review process is a technical review of the 

proposed air pollution source and issuance of the permit is based solely on expected 

compliance with all applicable state and federal rules and regulations. 

Comment:

Shouldn’t the residents have a right to decide if this plant should go here? 

Response:

There is no legal mechanism which allows for popular votes on such proposals. Both the 

state and federal air pollution control laws are established by the legislative process and any 

changes to the regulations must go through this process. These laws are in place to protect 

public health and welfare. The role of the AQD is to implement the laws. 

Comment:

Consideration of this permit should not be made until a popular vote is taken. The majority of 

the people believe the emissions from the plant will cause unreasonable interference with the 

comfortable enjoyment of life and property as stated in General Condition No. 6 of the draft 

permit terms and conditions. 

Response:

There is no legal mechanism which allows for popular votes on such proposals. Both the 

state and federal air pollution control laws are established by the legislative process and any 

changes to the regulations must go through this process. The role of the AQD is to 

implement the laws. 

General Condition No. 6 of the final permit specifically states that operation of the proposed 

process shall comply with Rule 901. Rule 901 states, in part, that “a person shall not cause 

or permit the emission of an air contaminant or water vapor in quantities that cause, alone or 

in reaction with other air contaminants...injurious effects to human health or safety...or 

unreasonable interference with the comfortable enjoyment of life and property.” AQD staff 

takes into account the ability of a process to comply with Rule 901 as a part of the permit 

review and will not recommend approval of any application that they believe will not be able 

to comply with the Department’s Rules for Air Pollution Control, including Rule 901. 

However, if a violation of Rule 901 should occur after the new process has commenced 
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operation, the final permit includes sufficient terms and conditions to allow the AQD to 

enforce this rule and address any such problems in the community. 

Comment:

A decision on the permit should be delayed until the people have a chance to accept or 

reject the location of the plant. 

Response:

The location of any facility is an issue addressed by local government through the planning 

and zoning processes. The Air Quality Division does not control the selection of sites for 

industrial facilities nor does it have jurisdiction over local zoning issues. Site selection is 

done by the permit applicant. The issuance of a Permit to Install by the AQD does not 

guarantee local site approval. A site assessment is conducted by Air Quality Division staff as 

a part of the permit review process and air pollution impacts are reviewed. 

Comment:

Comments were received on the location of the plant near residential properties and tax 

breaks that the company may receive. 

Response:

The location of any facility and taxing issues are subjects best addressed by local 

government through the planning and zoning processes. The Air Quality Division does not 

control the selection of sites for industrial facilities nor does it have jurisdiction over local 

zoning and taxing issues. Site selection is done by the permit applicant. The issuance of a 

Permit to Install by the AQD does not guarantee local site approval. A site assessment is 

conducted by Air Quality Division staff as a part of the permit review process and air pollution 

impacts are reviewed. 

Comment:

Is the electricity generating plant warranted for this area or is it directly attributable to the 

deregulation of the power generating industry? 

Response:

The AQD does not have authority to determine whether or not a type of industry is warranted 

for a specific area. The air permitting process involves a thorough review of the proposal 

and its impacts on the environment including whether or not the emissions will comply with 

state and federal health standards. Emissions from the plant will meet the NAAQS and the 

AQD health-based screening levels. 

Comment:

The company should be required to provide salary for an MDEQ employee to monitor the 

record keeping and plant operation on a 24-hour basis. 

Response:

There is no state or federal law that requires a facility to provide staff on a 24-hour basis to 

monitor plant operation. An AQD inspector is specifically assigned to inspect the equipment, 

review the records that the permit requires the facility to keep, and review the annual 
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emissions reports that the facility is required to submit. The facility is also required to submit 

test protocols and test results to the AQD for review and approval. 

Comment:

Since the facility will be located in close proximity of so many people, they should be held to 

higher and broader standards than what smaller industry is held to. 

Response:

All processes that have the potential to emit an air contaminant are required to comply with 

all applicable state and federal rules and regulations. Most air pollution control laws are 

based on the amount of emissions from the process. As a result, larger facilities are often 

subject to more regulations that are often quite stringent. Such is the case with Wolverine. 

In addition, all facilities that go through the permit review process must comply with national 

health standards and the AQD health-based screening levels regardless of the location. 

Maximum impacts from the facility are below all applicable health standards. 

Comment:

Can the DEQ and the people of the State of Michigan trust the company to follow regulations 

and do the required reporting? 

Response:

The AQD cannot recommend a permit for approval if it is determined that the proposal 

cannot comply with all applicable state and federal rules and regulations. The company’s 

proposed installation was reviewed and compared to other similar sources throughout the 

nation. Any information that seems unreasonable or inadequate is questioned and 

challenged. The permit is written using the best available and most updated data on the 

proposed source. Emission levels are compared with levels from similar sources throughout 

the United States and with actual test data to determine if they are reasonable and can be 

achieved. If the Permit to Install is violated, the regulations allow for AQD staff to take 

enforcement action against a facility. 

Comment:

Would AQD staff allow this facility in their neighborhood? 

Response:

Like most citizens, AQD staff places a high priority on residing and raising their families in a 

healthy environment. We share the concerns voiced by impacted residents, and we apply 

the air pollution control laws to help ensure public health protection. We are all exposed to 

air pollutants to some degree. From what we do know about the emissions and health risks 

associated with such facilities, we ensure that the allowed emissions do not pose 

unacceptable health risks, as required under the law. There are many aspects beyond 

effects on air quality that would be issues in siting this type of facility in a neighborhood. 

These include things that are not within AQD’s jurisdiction such as effects on property 

values, noise, traffic, etc. All of these are reasonable concerns that most people would want 

answered and addressed. The answers to these questions would obviously impact anyone’s 

response as to whether or not they would accept an industry in their neighborhood. While 

these are important issues, the permit under review by the Air Quality Division is meant to 

address the aspect of effects on ambient air quality. AQD staff is required to make sure that 
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all permits issued by the State comply with all applicable state and federal regulations. 

These regulations are designed to protect human health and the environment. The decision 

as to whether to approve or disapprove an air permit application in any neighborhood, 

regardless of location, would depend on whether or not the proposed facility would comply 

with all such applicable air regulations. 

T. Other Comments Received – Not Regulated by the AQD

Comment:

When and where will other environmental issues such as water, heavy metals, fuel storage, 

etc. be addressed? 

How can you not mandate a Water Quality permit first, although the plant will likely use 

billions of gallons of water, perhaps much of it dewatering water of questionable quality form 

the quarry or perhaps, mostly from Lake Huron. 

Response: 

The proposed permit is for the prescribed purpose of assuring compliance with 

Part 55 of 1994 PA 451 only. General Condition 9 of the proposed permit specifically states 

that “Approval of this permit does not obviate the necessity of obtaining such permits or 

approvals from other units of government as required by law.” Wolverine has stated that the 

plant is being designed for zero discharge and that a NPDES (National Pollutant Discharge 

Elimination System (NPDES) permit, will not be required. Wolverine has also stated that a 

timely permit application for ash disposal will be made to the MDEQ when required for plant 

operation. The air permit application addresses permitting requirements for fuel storage and 

handling. With the possible exception of storm water discharge permitting, Wolverine has 

again stated that a timely permit application for a storm water discharge permit will be made, 

if necessary, to the MDEQ when required for plant operation. 

Comment: 

Petroleum coke results in especially high amounts of ash compared to coal, in the range of 

twice as much fly ash and 65 percent more bottom ash. 

Response:

This activity is not within the regulatory authority of this permit. Solid waste disposal is 

subject to separate permitting. This permit is limited to the activities at the source as they 

pertain to air emissions, which the emissions and impacts from the proposed facility were 

evaluated and determined to comply with all applicable regulations which are designed to 

ensure an adequate level of protection for the environment and public health. 

Prepared by: Melissa Byrnes, Robert Sills, Matthew Hall, Julie Brunner, Jim Haywood, 

and Mary Ann Dolehanty