ILLINOIS POLLUTION CONTROL BOARD

December 10, 2008

4 IN THE MATTER OF:

)

6 NITROGEN OXIDES EMISSIONS ) R08-19

7 FROM VARIOUS SOURCE

)

8 CATEGORIES: AMENDMENTS TO )

9 35 ILL. ADM. CODE PARTS 211 )

10 AND 217

)

REPORT OF PROCEEDINGS HAD at the

13 hearing held before the ILLINOIS POLLUTION

14 CONTROL BOARD held on December 10, 2008, at

15 9:30 o'clock a.m., The Thompson Center, Chicago,

16 Illinois.

1 A P P E A R A N C E S:

3 MEMBERS PRESENT:

4 TIMOTHY FOX, Chairman

5 ANAD RAO, Member

6 MR. JOHNSON, Member

8 HODGE DWYER ZEMAN

9 BY: MS. KATHERINE D. HODGE

10 3150 Roland Avenue

11 Post Office Box 5776

12 Springfield, Illinois 62705-5776

13 (217) 523-4900

MR. FOX: We are back. We recessed

2 yesterday afternoon approximately 4:30, and are

3 here at about 9:00 o'clock on Wednesday,

4 December 10th, to resume the hearing in R08-19.

As was the case yesterday, I've

6 left at the door to this room a sheet on anyone

7 who has not pre-filed testimony can indicate that

8 they would like to offer testimony of their own

9 after we have completed the questions based on the

10 testimony that was pre-filed for this hearing. We

11 did have a gentleman on the basis of signing that

12 sheet to offer a comment at the conclusion of that

13 pre-filed testimony. I don't see that he's here

14 yet this morning, but certainly we can accommodate

15 what I suspect will be a brief comment at the

16 conclusion of the questions.

Having mentioned that routine

18 housekeeping matter, Ms. Hodge, you had provided

19 to me yesterday copies of the pre-filed testimony

20 of both Mr. Siebenberger and Mr. Stapper. Was

21 there a motion that you wanted to make in regard

22 to those?

MS. HODGE: Yes, this is Katherine

24 Hodge with the law firm of Hodge Dwyer Zeman, here

1 for United States Steel Corporation, and, yes, I

2 would ask, Mr. Fox, to please admit the copies of

3 the pre-filed testimony as exhibits as received.

MR. FOX: Very well. Those wil be

5 for Mr. Siebenberger hearing No. 10 and No. 11.

6 Is there any objection to the motion to admit

7 those two separate pre-filed testimony as those

8 exhibit numbers? Neither seeing or hearing any,

9 they would be marked as indicated in the case of

10 Siebenberger No. 10, and Stapper No. 11, into the

11 record.

If you are prepared to begin with

13 perhaps a brief summary or statement, why don't we

14 have the court reporter swear in both gentlemen at

15 once and go ahead and proceed. We can move them

16 in seamlessly through it.

MS. HODGE: I'm going to ask that

18 all three of these gentlemen be sworn in.

(Whereupon the witnesses were

sworn, after which the

following proceedings were

had:)

MS. HODGE: Like I said, this is

24 Katherine Hodge with Hodge Dwyer Zeman on behalf

1 of United States Steel Corporation, in particular

2 the Granite City Works in Granite City, Illinois.

3 My witnesses today are Mr. Larry Siebenberger, who

4 is the manager of environmental control at Granite

5 City Works and Mr. Blake Stapper, who is with URS

6 Corporation. Mr. Stapper has been involved in

7 evaluating the technical feasibility and economic

8 reasonableness of implementing NOx controlled

9 technology at URS --

As I said, Mr. Blake Stapper is

11 with the URS Corporation, and he's been involved

12 in evaluating the technical feasibility and

13 economic reasonableness of implementing NOx

14 controls at the Granite City Works.

Also present with us today is Mr. Bob

16 Ribbing. Mr. Ribbing is with the environmental

17 quality control department at Granite City Works,

18 and Mr. Ken Hagg to my right. And Mr. Hagg is

19 also with URS Corporation, and he does not have

20 any prepared testimony today, but he will be

21 available to assist in answering questions.

Also present is Monica Rios, who is an

23 associate with my firm. Mr. Siebenberg and

24 Mr. Stapper would like to make brief statements

1 for the record today, and then would be happy to

2 answer any questions regarding their pre-filed

3 testimony. And before we go to that, I do want to

4 thank the Board today for the opportunity to be

5 here, and also to let the Board know that United

6 States Steel Corporation has been working with the

7 Agency for more than a year now on some of the

8 proposed controls. So we appreciate the

9 opportunity to work with them, and we still have a

10 few issues outstanding and we're offering

11 testimony to that. Mr. Siebenberg?

MR. SIEBENBERGER: Good morning. My

13 name is Larry Siebenberger. I'm manager of

14 environmental control at Greater City Works at

15 U.S. Steel's Granite City Works in Granite City,

16 Illinois. I'm here today on behalf of U.S. Steel

17 to discuss Granite City Works' unique situation in

18 meeting the emission limits proposed by the

19 Agency. My testimony provides a summary of the

20 operations of Granite City Works, briefly

21 describes recent improvements at Granite City

22 Works and explains the impact of the proposed rule

23 on Granite City Works.

Granite City Works currently has 12

1 boilers. Number 1 through 10 boiler are planned

2 to be shut down in the future, and a new COGEN

3 boiler, which is under construction, will be

4 brought on line. Granite City Works also operates

5 four slab reheat furnaces. The proposed limits

6 applicable to 11 and 12 boiler, as well as reheat

7 furnaces 1 through 4 do not take into

8 consideration the unique characteristics of the

9 units in Granite City Works' operations. As

10 discussed in more detail in my testimony and the

11 testimony of U.S. Steel's consultant, Mr. Blake

12 Stapper of URS, Granite City Works' boilers

13 combustion mixed fuels which consists of blast

14 furnace gas, which is a relatively low NOx fuel,

15 natural gas and coke oven gas. Based on URS's

16 evaluation, the proper feasible control technology

17 for the boilers 11 and 12 is through gas

18 recirculation.

In terms of reheat furnaces

20 impacted by the rule, low NOx burners are

21 currently being installed, and Illinois EPA has

22 agreed such inflation is RACT. Based on its

23 evaluation of control technologies and Granite

24 City Works' unique circumstances, U.S. Steel is

1 proposing alternative limits for boilers 11 and 12

2 and the reheat furnaces. Blake Stapper and I are

3 happy to discuss the alternative to the limits

4 with you.

On behalf of U.S. Steel I would

6 like to discuss the Agency's proposed, May 1, 2001

7 compliance date. My testimony provides greater

8 detail on this issue, but I want to emphasize that

9 U.S. Steel cannot meet the deadline proposed by

10 the Agency. U.S. Steel will need 18 months from

11 the effective date of the Rule to complete

12 engineering, obtain permits, receive capital

13 approval, purchase, procure and install the

14 controls. The proposed compliance date is

15 therefore not achievable for U.S. Steel.

In addition, there are two final

17 issues that I would like to briefly comment on.

18 First, for U.S. Steel, environmental stewardship

19 is a core value. It influences how the company

20 conducts business. U.S. Steel recognizes that

21 manufacturing steel is a resource intense

22 operation that has an impact on future

23 generations. The company is committed to

24 continually improving its environmental and

1 resource management, as well as maintaining

2 compliance with environmental laws and

3 regulations.

Secondly, as you may know, last

5 week U.S. Steel announced that it was laying off

6 3500 workers and idling or effectively shutting

7 down three facilities, including Granite City

8 Works. At Granite City Works only the Coke

9 batteries and boilers will continue to operate at

10 reduced levels. At this time we are uncertain how

11 long the temporary idling will last, but it will

12 likely continue until market conditions begin to

13 improve. We are evaluating the impact of the

14 idling on Granite City Works' time frame to comply

15 with the Agency's proposal. I want to thank the

16 Board for the opportunity to testify today, and I

17 request that the Board seriously consider U.S.

18 Steel's proposed limits for its boilers and

19 furnaces as well as consider U.S. Steel's request

20 that the compliance date be revised. I'm happy to

21 answer any questions regarding my testimony.

MR. FOX: Thank you,

23 Mr. Siebenberger.

MR. SIEBENBERGER: Ms. Hodge, does

1 Mr. Stapper also have some remarks?

MS. HODGE: Yes, he does.

MR. STAPPER: Good morning. I'm

Blake Stapper. I'm a principle

engineer for URS Corporation, and I'm

registered as a professional engineer in the

state of Texas. URS is one of the world's

largest engineering design and construction

firms with over 55,000 employees and over

300 offices in 30 countries. URS was

retained by U.S. Steel to evaluate potential

NOx controlled technologies for the boilers

and reheat furnaces at the Granite City

Works located in Granite City, Illinois.

URS evaluated several options for boilers 11

and 12 and determined that flue gas

recirculation or FGR, in conjunction with

the existing burners was the optimum

NOx controls for boilers 11 and 12. As

discussed in more detail in my testimony,

since the existing boilers on 11 and 12

already burn a significant amount of blast

furnace gas, the introduction of FGR should

not cause any combustion problems or impact

boiler efficiency. URS also determined that

replacement of the burners on boilers 11 and

12 and selective noncatalytic reduction or

SNCR were not viable options for controlling

NOx. Because of the specialized fuel

requirements and mixtures utilized at steel

plants, many low NOx burners are not

designed for blast furnace gas. In

addition, boiler 11 is a corner fired unit,

so installing wall mounted low NOx burners

would require a complete rebuild of the

boiler.

My testimony also discusses in

detail why SNCR is not a technically

feasible option at the Granite City Works

facility. Because of problems associated

with ammonia slip and the characteristics of

boilers 11 and 12, such as varying steam

loads and fuel blends, SNCR would not

provide optimum control of NOx emissions.

I thank the Board for allowing

me to testify today, and I welcome any

questions on my any of my testimony.

MS. FOX: Mrs. Hodge, are we

prepared to go to questions to the

witnesses?

MS. HODGE: Yes, we are.

MR. FOX: Very good. Why don't we

dive right into those. If there is anyone

who has a question and identify themselves

for the court reporter, that would be

greatly appreciated. Please go ahead.

MS. VETTERHOFFER: I'm Dana

Vetterhoffer, assistant counsel with the

Illinois EPA. Mr. Siebenberger, on page 2

of your testimony you state that

13 undesulphurized Coke oven gas contains

14 hydrogencyanide, which contributes to nitrogen

15 during the promotion process. Does this mean that

16 the results in NOx emission rate is higher when

17 unsulphurized gas is burned than when desulfurized

18 gas is used?

MR. SIEBENBERGER: Yes, that's what

20 it refers to.

MS. VETTERHOFFER: Would you say

22 then that undesulpherized Coke oven gas is your

23 worst case fuel with respect to NOx emissions?

MR. SIEBENBERGER: Yes.

MS. VETTERHOFFER: And how is Coke

2 oven gas desulfurized?

MR. SIEBENBERGER: Well, we are

4 currently installing a desulfurization unit and

5 Coke byproducts unit. The Coke oven gas produced

6 there will go through a mean scrubber which will

7 scrub out hydrosulfide, hydrocyanide and carbon

8 dioxide.

MS. VETTERHOFFER: Does your permit

10 require that the desulfurization process be used

11 continuously?

MR. SIEBENBERGER: Yes, other than

13 when it's down for maintenance.

MS. VETTERHOFFER: Is there a limit

15 in your permit as to the length of time the

16 desulfurization can be shut down in a given year

17 for maintenance?

MR. SIEBENBERGER: Yes, the limit in

19 the permit is 35 days.

MS. VETTERHOFFER: When do you

21 expect construction of the desulfurization system

22 to be completed?

MR. SIEBENBERGER: Currently we are

24 anticipating having the desulf facility finished

1 by mid-2009. That's obviously subject to change

2 if business conditions cannot support that.

MS. VETTERHOFFER: Would you say

4 that when the desulfurization system has been

5 constructed, that Coke oven gas will be

6 desulfurized most of the time?

MR. SIEBENBERGER: Yes, other than

8 when the system is down for maintenance.

MS. VETTERHOFFER: How many weeks or

10 months per year do you estimate?

MR. SIEBENBERGER: Thirty-five days.

MS. BASSI: Does desulfurization

13 affect NOx emissions?

MR. SIEBENBERGER: Yes.

MS. BASSI: How so?

MR. SIEBENBERGER: The primary

17 purpose of the desulf is obviously to take

18 hydrosulfide out of the gas, but it also removes

19 hydrogencyanide from the Coke oven gas, which

20 reduces the fuel bound nitrogen which produces NOx

21 in addition to the thermal NOx that's generated --

22 the hydrogen cyanide adds additional NOx to

23 emission generation.

MS. VETTERHOFFER: On page 6 of your

1 testimony, does the emission limit you propose for

2 boilers 11 and 12 assume that the Coke oven gas is

3 desulfurized, undesulfurized or a combination of

4 the two?

MR. SIEBENBERGER: It assumes a

6 combination of the two. We assume that all of the

7 time the facility is operating on desulfurized

8 gas, except for the 35 days that the

9 desulfurization is down for maintenance.

MS. VETTERHOFFER: On page 6 again,

11 if your proposed limit of .113 lbs/MMBtu for

12 boilers 1 and 12 takes into account a worst case

13 kind of mixed use fuels. Have you examined an

14 emission case for a best case, expected case or

15 any other case?

MR. SIEBENBERGER: Well, I guess in

17 the way of a little background, we produce two

18 byproduct fuels, Coke oven gas and blast furnace

19 gas. Blast furnace gas, as I mentioned, is a low

20 oven NOx fuel. Coke oven gas is a higher NOx

21 fuel, and is affected whether it is desulfurized

22 or not. It is our desire to combust as much of

23 our byproduct fuels as we can in lieu of purchased

24 fuels, in this case natural gas. So we have to

1 maintain the ability in our facilities to burn as

2 much of the byproduct fuels as we can to displace

3 natural gas. In the case of boilers, we typically

4 burn natural gas, blast furnace gas and Coke oven

5 gas. The condition that is changing is with the

6 new COGEN facility coming on line. The COGEN

7 facility is only capable of burning blast furnace

8 gas and a small amount of natural gas. So the

9 COGEN is replacing boilers 1 through 10, which

10 burn natural gas, blast furnace gas and Coke oven

11 gas. So when the COGEN comes on-line and the

12 boiler 1 is repaired now, we will now have

13 additional Coke oven gas which we will have to

14 combust and hopefully not flare, but combust it in

15 lieu of combusted fuels. So when we say worst

16 case, what we attempted to do was take into

17 account providing a limit that is based on the

18 amount of Coke oven gas that we need to burn 11

19 and 12, taken into account the additional Coke

20 oven gas that is available and allowing for the

21 fact that depending on which facilities downstream

22 are running or not running, gas may become

23 available. And then when those sources start

24 running again, it may be consuming there. We have

1 to have the flexibility of producing gas

2 throughout the system. I know Rob Kaleel. We've

3 worked with him in the past on developing an SO2

4 desulf that we have. In doing so, it was

5 recognized that in setting the amount of Coke oven

6 gas limits on our facilities that we consume it

7 on, we have to recognize the fact that -- we have

8 to be able to move this fuel around to the

9 different facilities based on which facilities are

10 operating at the time. So that drives the maximum

11 amount that we set, and the Coke oven gas really

12 drives the worst case NOx fuel for 1 and 3.

(At which point a brief recess

was taken, after which the

following proceedings were

had:)

MR. FOX: Mr. Siebenberger, I think

18 you had wrapped up one response question from

19 Ms. Vetterhoffer. Should we go back to her? We

20 can certainly go back to her if she's ready for

21 another follow-up question and another question.

MS. VETTERHOFFER: So just to

23 clarify, you only examined worst case because you

24 wanted to maximize flexibility?

MR. SIEBENBERGER: Correct. I mean,

2 we have to have our limit based on worst case

3 scenario for using Coke oven gas in order to allow

4 us to maintain flexibility to move the gas around

5 the facilities.

MS. VETTERHOFFER: Can you just

7 briefly explain what the percentages in your worst

8 case blend, how much of that is Coke oven gas? Is

9 that explained in one of your exhibits?

MR. SEINDENBERGER: It's Exhibit A.

MS. VETTERHOFFER: What would you

12 expect NOx emissions to be for boilers 11 and 12

13 if only desulfurized oven gases were used in

14 combination with the gas recirculation recommended

15 by your consultant?

MR. SIEBENBERGER: I don't currently

17 have that determination, and we would have to make

18 that determination and submit it, would be happy

19 to submit it.

MS. VETTERHOFFER: Would you be

21 willing to provide that?

MR. SIEBENBERGER: Yes.

MS. VETTERHOFFER: Are boilers 11

24 and 12 fitted with any NOx controls currently?

MR. SIEBENBERGER: No.

MS. VETTERHOFFER: On page 6 of your

3 testimony you state because of the unique

4 characteristics of boilers 11 and 12, specifically

5 varying mixes of desulfurized and nondesulfurized

6 Coke oven gas in combination with blast furnace

7 gas and natural gas, that the only NOx control

8 option is flue gas recirculation. Why couldn't

9 low NOx be used possibly in conjunction with the

10 FGR?

MR. SIEBENBERGER: I would have to

12 defer to Blake Stapper in this case. I'm not a

13 combustion expert. That's why we retained him.

MR. STAPPER: Low NOx burners are

15 generally circular burners designed for wall-fired

16 applications. So a corner-fired boiler, such as

17 boiler 11, you would have to rebuild the boiler to

18 take the burners out of the corners and put them

19 into a wall. So from that aspect it's certainly

20 not reasonably available as it applies to that

21 boiler. For boiler 12, it is a wall-fired boiler

22 with circular burners, but the reality is that low

23 NOx burner development has primarily targeted

24 natural gas fired sources, and that's simply a

1 market reality. There is a larger market for

2 natural gas fired low NOx burners, and so that's

3 where the vendors have put their research efforts.

4 There are very few applications in the United

5 States where blast furnace gas and Coke oven gas

6 are being fired, and those different fuels would

7 not be -- it would not be possible to operate

8 those in a conventional low NOx burner. You would

9 have to have something that is custom designed for

10 the application, which currently does not exist.

11 And when I say that it's not possible to fire

12 those fuels in a low NOx burner, I'm not saying

13 that it's not possible to get low NOx performance.

14 I'm saying you would be in danger of a

15 catastrophic failure, an explosion, if you tried

16 to burn those gases in a commercially available

17 low NOx burner.

MS. VETTERHOFFER: Don't refineries,

19 however, use low NOx burners?

MR. STAPPER: Refineries use low NOx

21 burners to burn either natural gas or refinery

22 gas. Refinery gas is primarily composed of -- you

23 can consider it as being a mixture of hydrogen and

24 what is essentially natural gas, and refinery gas

1 is -- there is a better opportunity to safely

2 control the combustion of refinery gas in a low

3 NOx burner. The blast furnace gas and the Coke

4 oven gas are very different than what a refinery

5 is firing in their low NOx burners.

MS. VETTERHOFFER: Have you selected

7 a supplier for the FGR?

MR. SIEBENBERGER: No.

MS. VETTERHOFFER: Exhibits A and B

10 to your testimony, Mr. Siebenberger, appear to

11 have been prepared by your consultant URS; is that

12 correct?

MR. SIEBENBERGER: Yes, with my

14 input.

MS. VETTERHOFFER: Can I direct

16 questions toward you and then decide if

17 Mr. Stapper might be better to answer them?

MR. SIEBENBERGER: Yes.

MS. VETTERHOFFER: In Exhibit A you

20 provided emission production calculations for

21 boilers 11 and 12 on page 2 under "Normal

22 Operations." Can you just walk us through your

23 calculations?

MR. SIEBENBERGER: Yes. What

1 Exhibit A attempts to do is present the

2 assumptions that we used to develop the proposed

3 average emission and absorb .113 BTU for 11 and 12

4 boilers, and there were three distinct operating

5 conditions that were considered. The first being

6 what we called normal operations. Normal

7 operations is based on the operation of both blast

8 furnaces at the facility and providing a maximum

9 amount of blast furnace gas availability. So

10 during this metal when we're running both blast

11 furnaces, we produce the maximum amount of blast

12 furnace gas and we attempt to consume as much of

13 that as we can. In considering that, what we did

14 in our calculation was, we determined both on an

15 ozone and annual basis, when we are on a

16 two-furnace operation, there are still times when

17 maintenance is required on one furnace, and we

18 have to take one or the other furnace down for

19 maintenance. So we determine the number of days

20 that one blast furnace or the other would be down.

21 When a blast furnace goes down -- and we'll cover

22 that under the second scenario later -- it's a

23 changed condition as far as our fuels. So we took

24 the time when both blast furnaces are running, and

1 we assumed a fuel mix for the 11 and 12 boiler of

2 25 percent natural gas, 35 blast oven gas and

3 40 percent Coke oven gas, and we assume that the

4 boilers would be running at full load since we are

5 operating both furnace and need the steam for the

6 hot blast turbulance for the furnaces. We also

7 used the controlled emission rates based on flue

8 gas recirculation for natural gas of .084. For

9 blast furnace gas .0288 and Coke oven gas .44,

10 and, again, this is desulfurized Coke oven gas.

11 And essentially that's the basis for determining

12 the emissions from under normal operations.

MS. VETTERHOFFER: Is the fuel mix,

14 is that the worst case mix that you referred to

15 previously?

MR. SIEBENBERGER: Yes, what we did

17 was, again, we have to preserve the ability to

18 burn Coke oven gas on the 11 and 12 boiler, and

19 particularly with 1 through 10 going down and the

20 COGEN going on, we are going to have more Coke

21 oven gas available to us than under that scenario

22 we currently have. So we have to have the ability

23 to burn Coke oven gas on the 11 and 12 boiler.

MS. VETTERHOFFER: And how are the

1 emission rates that you list there using FGR

2 estimated?

MR. SIEBENBERGER: They were based

4 on URS's evaluation.

MS. VETTERHOFFER: And, again, I

6 think you addressed this earlier. You haven't

7 examined an emission rate for a best case or

8 expected case; is that correct?

MR. SIEBENBERGER: Correct.

MS. VETTERHOFFER: And I think you

11 already answered this as well, but I'm going to go

12 ahead and ask it just in case, but for the normal

13 operations calculation, did you assume a mixture

14 of desulferized and nondesulferized Coke oven gas

15 or only desulferized Coke oven gas?

MR. SIEBENBERGER: Both actually.

17 We assumed desulfurized Coke oven gas, except for

18 he 35-day period that the desulf would be down for

19 maintenance.

MS. VETTERHOFFER: Do you know if

21 the fuel mix percentages represent heat input or

22 volumetric rates?

MR. SIEBENBERGER: Yes, it's heat

24 input.

MS. VETTERHOFFER: Do you have any

2 historical data regarding how much Coke oven gas

3 is burned in boilers 11 and 12?

MR. SIEBENBERGER: Yes.

MS. VETTERHOFFER: Would you be able

6 to provide that data to the Agency?

MR. SIEBENBERGER: Sure.

MS. VETTERHOFFER: On average how

9 much Coke oven gas has been used in the boilers

10 just historically?

MR. SIEBENBERGER: My memory is, and

12 it's been a while since I've looked at this, but I

13 think we've approached the 40 percent Coke oven

14 gas usage on the boilers at one time or another in

15 the past. Again, we will have a changed condition

16 now where because of boilers 1 through 10 going

17 down, we will have more Coke oven gas available.

MS. VETTERHOFFER: Do you have any

19 estimate of how much you think that will change?

MR. SIEBENBERGER: No, I do not.

MS. VETTERHOFFER: Will the

22 operation of the new ovens at the Sun Coke project

23 increase the availability of Coke oven gas in the

24 future or are those the ones you were just

1 referencing?

MR. SIEBENBERGER: No, actually the

3 installation of the COGEN boiler, which will burn

4 blast furnace gas and natural gas, takes the place

5 of boilers 1 through 10, our existing boilers.

6 The shutting down of 1 through 10, which burn

7 natural gas, blast furnace gas and Coke oven gas

8 will create an additional amount of Coke oven gas

9 available at our facility for combusting.

MS. VETTERHOFFER: Regarding the

11 emission rates for each fuel shown on Exhibit A

12 under normal operations, are these the guaranteed

13 emission rates from the company supplying the FGR?

MR. SIEBENBERGER: No, they are not.

MS. VETTERHOFFER: I have kind of

16 the same question for page 3 of Exhibit A under

17 Coke oven gas scrubber maintenance mode. Could

18 you briefly explain those calculations?

MR. SIEBENBERGER: Yes. As I said

20 earlier, the emission rates that we used are based

21 on combusting Coke oven gas, desulfurized Coke

22 oven gas, except for our 35 days of the year. So

23 what we did was, we determined, based on 35 days

24 of combusting undesulfurized Coke oven gas what

1 the NOx emissions would be for the nondesulfurized

2 Coke oven gas, and we compared that to what the

3 emissions would be to burning desulfurized Coke

4 oven gas. And we basically identified the net

5 increase above burning desulfurized Coke oven gas

6 for those periods, and that was identified in our

7 calculation and was determined to represent about

8 14-1/2 tons of additional NOx per year when we are

9 consuming the nondesulpherized Coke oven gas

10 versus sulfurized Coke oven gas. So we just

11 identified incremental increases in emissions from

12 that period.

MS. VETTERHOFFER: And how did you

14 arrive at the base line NOx rates for the natural

15 gas, blast furnace gas and Coke oven gas?

MR. SIEBENBERGER: I think in the

17 formatting of our attachment, we probably should

18 have had that paragraph under the results column.

19 Because all we're doing here, it's really not

20 relevant to the scrubber down determination. All

21 we are doing here is stating for the purposes of

22 the table below what the current emission rates

23 are based on what IEPA uses in their inventory and

24 what we have used for historical data in the past.

1 So these are just what we are using as our current

2 emission rates for these fuels.

MS. VETTERHOFFER: Why does the

4 natural gas emission rate go up, not just the Coke

5 oven gas rate?

MR. SIEBENBERGER: Is that in

7 referring to the emission factors?

MS. VETTERHOFFER: Comparing the

9 normal operations versus the Coke oven gas

10 scrubber maintenance mode.

MR. SIEBENBERGER: Oh, good point.

12 I meant to mention that.

Actually, we used the normal

14 operation blend when we determined the difference

15 in the net increase from burning desulfurized

16 versus nondesulfurized gas. There is a correction

17 to our attachment. The Coke oven gas that we show

18 here is at 60 percent. Actually it's at 40

19 percent. So it should match up with the blend

20 that we have, the mix that we have identified on

21 page 2 for our normal operation.

MS. VETTERHOFFER: Does URS have

23 anything in writing regarding these calculations

24 or how they came up with them that they can share

1 with us?

MR. SIEBENBERGER: URS did an

3 evaluation and provided that information to us.

MS. VETTERHOFFER: Is that something

5 that you can provide us?

MR. SIEBENBERGER: Yes, I believe

7 so.

MS. VETTERHOFFER: Thank you.

MR. RAO: Would it be possible to

10 provide it into the record so everybody else has

11 it?

MR. SIEBENBERGER: Sure, I assume

13 so.

MS. VETTERHOFFER: On page 7 your

15 testimony does the emission limit you propose for

16 the reheat furnaces assume that the Coke oven gas

17 is desulfurized or undesulfurized or a

18 combination?

MR. SIEBENBERGER: Basically the

20 same is for the boilers. We have assumed that

21 desulfurized Coke oven gas is used at all times,

22 except for the 35 day period that the desulph

23 facility is down for maintenance.

MS. VETTERHOFFER: What would you

1 expect NOx emissions to be for the reheat furnaces

2 if only desulfurized Coke oven gas were used in

3 combination with the low NOx configuration now

4 being installed?

MR. SIEBENBERGER: We would have to

6 make that determination. I don't currently have

7 it, but we can make that determination. We'll

8 submit it.

MS. VETTERHOFFER: On page 7 of your

10 testimony you state that you have proposed an

11 emission rate of .189 pound per MMBTU for the

12 reheat furnaces based on specific fuel mixes. Is

13 this source case mix as well?

MR. SIEBENBERGER: Yes.

MS. VETTERHOFFER: And similar to

16 what I asked for the boilers, did you examine any

17 other case, best case, any other case?

MR. SIEBENBERG: No.

MS. VETTERHOFFER: For the furnaces,

20 do you know what percentage on a heat input base,

21 how much Coke oven gas was used, what the

22 percentages are for the different gases used?

MR. SIEBENBERG: For the assumptions

24 of our calculations, is that what you are asking?

MS. VETTERHOFFER: Yes.

MR. SIEBENBERGER: Yes. The

3 percentage for heat input for furnace number one,

4 for Coke oven gas, was 32 percent. For number two

5 furnace, it was 32 percent. For number three

6 furnace, it was 72 percent, and for number four

7 furnace it was 70 percent.

MS. VETTERHOFFER: And the rest is

9 from natural gas, is that correct?

MR. SIEBENBERGER: Correct.

MS. VETTERHOFFER: Is there any way

12 we can obtain a copy of the technical proposal

13 from Bloom for the burners on the reheat furnaces?

MR. SIEBENBERGER: I assume so. I

15 don't know if there's -- I'd have to ask our

16 engineering department. I don't know of an issue

17 with it.

MS. HODGE: We'll check on it.

MR. SIEBENBERGER: If there's no

20 issue with it.

MS. VETTERHOFFER: Does the sum of

22 the Coke oven gas used on boilers 11 and 12, plus

23 that used on the other furnaces exceed the amount

24 that the facility produces?

THE WITNESS: Yes, it would.

MS. VETTERHOFFER: By how much?

MR. SIEBENBERGER: I'd have to

4 determine that. I don't know off the top of my

5 head. Again, the reason for that is, we have to

6 have the flexibility when the hot strip doesn't

7 run continually. So there are times when the hot

8 strip is down, and so Coke oven gas that would be

9 consumed on a hot strip, would become available to

10 burn more on the boilers if we chose to do that.

11 Ultimately all the Coke oven gas is going to be

12 consumed, whether we burn it on the boilers, the

13 refurnaces, if we don't burn it there, it's going

14 to be flared. So the amount of Coke oven gas

15 combusted in the facility doesn't change. It just

16 gets moved around from facility to facility based

17 on their operations.

MS. VETTERHOFFER: Do you think

19 that's reasonable since they are annual and

20 seasonal limits?

MR. SIEBENBERGER: Well, I think we

22 have to have that ability, yes.

MS. VETTERHOFFER: On page 3 of your

24 testimony you state that slab reheat furnaces are

1 heated by Coke oven gas and natural gas. Do you

2 know what the uncontrolled NOx rates are for these

3 furnaces?

MR. SIEBENBERGER: I'm sorry, would

5 you repeat that?

MS. VETTERHOFFER: Sure. On page 3

7 of your testimony you state that slab reheat

8 furnaces are heated by Coke oven gas and natural

9 gas. Do you know what the uncontrolled NOx rates

10 are for these furnaces?

MR. SIEBENBERGER: I would have

12 to -- I'm sure we do. I don't right at this

13 moment. I would have to find that, what the

14 emission rates were that we used.

MS. VETTERHOFFER: Do you blend the

16 gases before combustion?

MR. SIEBENBERGER: On furnaces -- my

18 understanding is on furnaces 1, 2 and 3, which are

19 of similar design, we provide Coke oven gas to

20 certain zones and certain burners, and it is

21 burned solely on those burners. You either have

22 Coke oven gas or natural gas on those burners.

23 And the remaining burners burn natural gas. The

24 number four furnace we actually burn the Coke oven

1 gas into the natural gas mix that goes to the

2 furnace in total.

MS. VETTERHOFFER: On page 1 of

4 Exhibit B, the NOx rate shown for furnaces number

5 three and 4 are higher than for furnaces number 1

6 and 2. Can you explain why there is a difference?

MR. SIEBENBERGER: Well, two reasons

8 that I can think of off the top of my head. The

9 percent Coke oven gas that we used on 3 and 4 is

10 higher than what we assumed on furnaces 1 and 2.

11 In addition to that, I think on number four,

12 because of its different design, it may also have

13 a higher NOx emission rate than 1, 2 and 3.

MS. VETTERHOFFER: With regard to

15 Exhibit B, would the estimate of NOx emission

16 reductions for the slab furnaces, their ozone

17 season emission rates shown on Exhibits 1 and 2,

18 are these provided by the burner manufacturer?

MR. SIEBENBERGER: Yes.

MS. VETTERHOFFER: Are they

21 guaranteed values or expected values?

MR. SIEBENBERGER: It is my

23 understanding that these are guaranteed values.

MS. VETTERHOFFER: With regard to

1 the table on page 2 of 2 of Exhibit B, are the

2 emission rates simply an average of the emission

3 rates from the table on page 1?

MR. SIEBENBERGER: Correct.

MS. VETTERHOFFER: Have you

6 discussed the appropriate emission limit for this

7 process with the Illinois EPA prior to this

8 hearing?

MR. SIEBENBERGER: Yes, we have.

MS. VETTERHOFFER: Are you willing

11 to continue to work with the Agency on this issue?

MR. SIEBENBERGER: Yes, we are.

MS. VETTERHOFFER: On page 7 of your

14 testimony you state that it would take at least

15 18 months from the date that the final rule is

16 promulgated to achieve installation of controls.

17 If the Board were to adopt a compliance date 18

18 months after the effective date of approval, would

19 that be acceptable from your perspective?

MR. SIEBENBERGER: I think so. I

21 guess the one caveat I have to put in is with the

22 recent changes in business conditions, as I stated

23 in my opening statement, we don't know whether

24 that's going to affect our ability to spend

1 capital. So we could do it if business conditions

2 are normal and will allow us to provide the

3 capital to do it. But if the conditions

4 deteriorate to the point where we couldn't, well,

5 then that would be affected.

MS. VETTERHOFFER: That's all the

7 questions I had for you Mr. Siebenberger. Thank

8 you.

MR. FOX: Did you have questions for

10 Mr. Stapper or otherwise for U.S. Steel?

MS. VETTERHOFFER: I do.

MR. FOX: Before we go on to those,

13 I suspect we can do that very quickly, were there

14 other participants who had questions based on

15 Mr. Siebenberger's prior filed testimony? Seeing

16 none, Ms. Vetterhoffer, if you want to go ahead

17 with the questions that you refer to, go ahead.

MS. VETTERHOFFER: Mr. Stapper, you

19 testified on page 2 of your testimony that Abb

20 Combustion Engineering built boiler 1 and Riley

21 built number 12. Does Abb Combustion Engineering

22 currently go by the name of Alstom?

MR. STRAPPER: I believe so.

MS. VETTERHOFFER: And does Riley

1 now go by the name of Babcock Power?

MR. STRAPPER: Yes.

MS. VETTERHOFFER: Did you contact

4 either of these companies to seek their opinion on

5 how to reduce NOx boilers?

MR. STRAPPER: No.

MS. VETTERHOFFER: Why didn't you

8 contact them?

MR. STRAPPER: Both those firms are

10 primarily, their business is new boilers. They

11 are less active in the burner retrofit market. I

12 think Combustion Engineering is now actually a

13 North American Company. North American does

14 supply some low NOx burners, but they have a very

15 small market niche. Again, Ulstom and Babcock

16 Power in the current marketplace, in the utility

17 industry, there is sufficient or more than

18 sufficient business for these companies to go

19 after every opportunity, and so they are primarily

20 focused on the utility industry right now because

21 that's, like URS, is a profitable market sector

22 for them.

MS. VETTERHOFFER: And did you say

24 that both of those companies supplied NOx control

1 equipment?

MR. STRAPPER: Yes.

MS. VETTERHOFFER: Besides Ulstom

4 how many companies have supplied corner fired

5 boilers in the United States, if you know?

MR. STRAPPER: Combustion

7 Engineering is the firm that I think has supplied

8 the vast majority of corner fired burners in the

9 United States.

MS. VETTERHOFFER: And wouldn't that

11 make that company uniquely qualified to evaluate

12 unit 11?

MR. STRAPPER: No, not necessarily.

14 Combustion Engineering's, like I say, their

15 primary focus is to supply new equipment. And

16 they will supply that equipment and make

17 guarantees about how that equipment will perform.

18 They are not in the business of extracting the

19 greatest possible benefit from that equipment,

20 only for meeting their guarantees. And so

21 Combustion Engineering does not have as much

22 experience in the burner retrofit market in the

23 industrial boiler sector as, for instance, URS

24 does.

MS. VETTERHOFFER: And what about

2 boiler 12. Since Riley or Babcock Power supplies

3 NOx control equipment, wouldn't it make sense to

4 contact them for input?

MR. STRAPPER: Our participation in

6 this business over the years didn't require us to

7 contact them to know that there are no low NOx

8 burners available for that application.

MS. VETTERHOFFER: Are there any low

10 NOx burners that you believe could be installed on

11 boiler number 12.

MR. STRAPPER: No, Dan -- let me

13 expound on that answer. There are no low NOx

14 burners that could be safely installed on boiler

15 12 to burn blast furnace gas and Coke oven gas.

MS. VETTERHOFFER: Did you contact

17 any burner suppliers to see if they could supply

18 low NOx burners that could be used on these

19 boilers?

MR. STRAPPER: No, we did not. URS

21 is involved in the burner retrofit business. To

22 the extent that we have a current database of what

23 is available in the marketplace, and we look at a

24 variety of vendors and a variety of technologies

1 and that experience base allows us to operate

2 without contacting the vendors for every

3 application.

MS. VETTERHOFFER: Will URS manage

5 the construction of this project?

MR. STRAPPER: That has not yet been

7 determined. I would say likely not.

MS. VETTERHOFFER: Since you were

9 unsure, you probably don't know. Do you know who

10 will be overseeing the construction of this

11 project?

MR. STRAPPER: No.

MS. VETTERHOFFER: On page 3 of your

14 testimony you state that an FGR addition to the

15 existing burners was elected as the optimum NOx

16 control technology. How do you define optimum and

17 how is it optimized?

MR. STRAPPER: I would define as the

19 optimum solution in that it provides the most

20 benefit in terms of NOx reduction with the lowest

21 cost and the highest margin of safety.

MS. VETTERHOFFER: In this

23 optimization did URS consider the Agency's NOx

24 draft emission?

MS. STAPPER: Yes.

MS. VETTERHOFFER: Were the Agency

3 limits considered in the optimization?

MR. STRAPPER: When URS approaches

5 one of these projects, there's always a target

6 emission level that is regulatory driven, that is

7 our objective in developing a cost effective

8 solution. However, there are instances such as

9 boilers 11 and 12 where the specifics of the

10 application don't allow them to readily achieve

11 the target emission rate.

MS. VETTERHOFFER: Is any kind of

13 optimization analysis written down on paper or any

14 document?

MR. STRAPPER: Yes.

MS. VETTERHOFFER: Would you be able

17 to provide the Agency a copy of that or enter it

18 in the record?

MR. STRAPPER: We have provided that

20 to U.S. Steel. It's their document.

MS. VETTERHOFFER: Would U.S. Steel

22 be willing to provide that document?

MR. SIEBENBERGER: Yes.

MS. VETTERHOFFER: Thank you. You

1 mention on page 4 of your testimony that another

2 factor that makes FGR an ideal NOx technology for

3 the Granite City Works boilers if the amount of

4 FGR added can easily be controlled based on the

5 measured fraction of natural gas, Coke oven gas

6 and blast furnace gas used, allowing NOx

7 controlled to be maximized when firing natural gas

8 or Coke oven gas, but not causing flammability

9 issue when firing blast furnace gas. This implies

10 that the boiler had or will have the ability to

11 track the amount of each fuel being fired for FGR

12 control. Is that correct?

MR. STRAPPER: As part of the

14 retrofit, the instrumentation may have to be

15 upgraded, but the control system would have that

16 capability, yes.

MS. VETTERHOFFER: Does that mean

18 that FGR can be continuously controlled and

19 adjusted based on the fuel mix at the time?

MR. STRAPPER: Yes.

MS. VETTERHOFFER: And this would

22 provide good furnace combustion control and good

23 NOx emission control, correct?

MR. STRAPPER: Yes.

MS. VETTERHOFFER: And that's a

2 benefit of FGR, is that right?

MR. STRAPPER: Yes.

MS. VETTERHOFFER: You then mention

5 that on page 6 of your testimony that boilers 11

6 and 12 are not good candidates for NGCR

7 application as their operating characteristics are

8 not consistent with the characteristics with the

9 operating characteristics required for NGCR are

10 not appropriate for those two boilers. You then

11 state on page 7 that variations in heating values

12 and nitrogen makes the NOx emissions and furnace

13 temperatures fluctuate which makes NGCR untenable;

14 is that correct?

MR. STRAPPER: Yes.

MS. VETTERHOFF: You previously

17 testified however that you are able to monitor

18 fuel input to provide good combustion control and

19 good NOx emission controls. Wouldn't these same

20 capabilities make NGCR available control options

21 as well?

MR. STRAPPER: No.

MS. VETTERHOFFER: Can you explain

24 why?

MR. STRAPPER: There are a number of

2 factors that affect SNCR applicability that where,

3 with flue gas recirculation, if you have the right

4 amount of flue gas mixed in with the combustion

5 air, you can control the peak flame temperature

6 and control your NOx emissions. That is

7 essentially the only driving factor in flue gas

8 recirculation performance. In an SNCR system you

9 have to match up the ammonia or uria molecule that

10 you are injecting with a NOx molecule in the gas.

11 So it has to do with knowing how much NOx is there

12 and knowing where it's located in the duct. In a

13 boiler, especially like the ones at Granite City

14 where there are multiple fuels introduced that

15 have different NOx generating characteristics,

16 there's stratification of the NOx in the duct. So

17 you can think of it as the NOx generated by the

18 Coke oven gas might follow a different path

19 through the boiler than the NOx formed by the

20 natural gas. If you think of the boiler cross

21 section as a doorway, there might be more NOx at

22 head level than there is at foot level, and that

23 will change as the fuel blend changes. And so

24 your ammonia injection grid, which is distributing

1 ammonia across that duct, is really not capable of

2 understanding how that distribution across the

3 duct varies and it's not capable of following it.

4 That's one aspect. Another aspect of SNCR

5 applicability is temperature. You need to be in

6 the right temperature window for the right amount

7 of time in order for those reactions to occur.

8 Because unlike combustion reactions, which are

9 very fast, the SNCR reactions are relatively slow.

10 And in the boiler as the load changes, that

11 temperature window moves. So you can imagine at

12 the highest load, immediately at the furnace exit,

13 a boiler essentially consists of a fire box and

14 then ducts that have tubes in them where heat is

15 recovered, that ideal injection temperature is

16 probably right at the exit of the furnace. Maybe

17 2000 degrees. However at lower loads, that

18 temperature at that furnace exit is going to be

19 lower. And you are not going to achieve the same

20 amount of reduction. It's even conceivable that

21 the ideal temperature at maximum load is somewhere

22 beyond the furnace exit, somewhere within the duct

23 that's filled with heat recovery tubes. And,

24 again, that temperature window is going to move.

1 So if you have a fixed ammonia injection grid and

2 you have your temperature window, your optimum

3 temperature window moving with load, and also the

4 NOx, the mass of NOx that you are trying to

5 control is changing, both with load and with fuel

6 blend, and then you also have the NOx cross

7 section changing with fuel blend, it's virtually

8 an impossible control scenario. What you end up

9 with is if you have too much ammonia at a given

10 point for the amount of NOx that's present, that

11 ammonia will go through unreacted and you'll have

12 ammonia slip. If you don't have enough ammonia at

13 the point where the NOx is, then there's unreduced

14 NOx and the NOx will be emitted. It is

15 conceivable that in the particular application,

16 the installation of an SNCR could result in higher

17 emissions than the base level or baseline.

MS. VETTERHOFFER: If you just

19 explain the changes of using SNCR, but isn't it

20 true that SNCR has been installed successfully on

21 industrial boilers?

MR. STRAPPER: Yes, but not all

23 boilers and not all boilers have the same

24 configuration as we see at Granite City. Not all

1 boilers are in the same service. Some are base

2 loaded, whereas others like at Granite City follow

3 load and have significant load variations. And

4 fuel types among different boilers vary, and there

5 are some fuels that are more consistent that would

6 lend themselves better to SNCR and there are also

7 I would say for a typical SNCR application, there

8 are not multiple fuels being fired of such a

9 variety of composition.

MS. VETTERHOFFER: Has SNCR been

11 installed, however, on multi-fueled industrial

12 boilers before?

MR. STRAPPER: I'm aware of boilers

14 in the forest products industry that burn

15 combinations of natural gas and wood products

16 where SNCR is installed. I am not aware of any

17 SNCR applications on boilers firing a combination

18 of natural gas, blast furnace gas and Coke oven

19 gas.

MS. VETTERHOFFER: How many SNCR

21 systems has URS recently designed or supplied?

MR. STRAPPER: URS is not in the

23 business of evaluating NOx controlled technologies

24 to develop cost effective solutions for our

1 clients' needs. One of the reasons we are not in

2 the SNCR business is it's not a large business,

3 and for us it's not a profitable business. We're

4 capable of doing it. We chose not to.

MS. VETTERHOFFER: According to

6 information provided by Midwest Generation, a

7 company named Fuel Tech has supplied 450 SNCR

8 systems. Have you ever heard of Fuel Tech?

MR. STRAPPER: Yes, Fuel Tech is the

10 industry leader in supplying SNCR systems.

MS. VETTERHOFFER: The information

12 provided by Midwest Generation indicates that a

13 hundred of those SNCR systems were utility; that

14 implies that the majority of systems, roughly 350

15 are industrial, correct?

MR. STAPPER: If that's what their

17 data says. If you need to me to do the math, I

18 would agree, yes.

MS. VETTERHOFFER: Thank you. Have

20 you contacted Fuel Tech regarding control options

21 for boilers 11 and 12?

MR. STRAPPER: No. We and our staff

23 are fully capable of understanding SNCR

24 applications, where they will work and where they

1 won't work without contacting Fuel Tech. The

2 other thing that you have to understand in the

3 business that we do, in working with these vendors

4 who supply these control technologies, we do

5 hundreds of these studies; BACT analyses, RACT

6 analyses, and every one of them you need to

7 develop cost information for that particular

8 application. After you call a vendor about a

9 dozen times to give you cost information on an

10 application that your client is not going to be

11 buying because you are just getting that

12 information to complete your study, the vendor

13 doesn't answer the phone anymore. The vendor

14 doesn't go and spend a week designing the system

15 for something that they know they are never going

16 to do. So we have to rely on our experience and

17 our data base to come up with those analyses.

MS. VETTERHOFFER: Were you aware

19 that Fuel Tech's headquarters are in Illinois?

MR. STRAPPER: I was not aware of

21 that.

MR. JOHNSON: Mr. Strapper, it is

23 then and both pre-filed and today that the flue

24 gas recirculation is a more effective NOx

1 reduction method in this instance at the Granite

2 City plant than SNCR would be?

MR. STRAPPER: Yes, for this

4 particular application.

MR. JOHNSON: And what about cost?

6 Based upon your experience, is the FGR system

7 cheaper to put in than SNCR and operate?

MR. STRAPPER: It's cheaper and it

9 will result in lower emissions.

MS. VETTERHOFFER: I don't have any

11 further questions. Thank you, Mr. Stapper.

MR. FOX: Are there, from other

13 participants here beyond the Agency, are there any

14 other questions either for Mr. Stapper or

15 Mr. Seibenberger before we move on?

MS. HODGE: I do have just a

17 follow-up question for Mr. Stapper, and this is in

18 follow-up to some questions of the Agency

19 yesterday, and it's dealing with page 27 and 28 in

20 the technical support document, and I believe the

21 Agency had been asking some questions of, I think

22 it was of Mr. Dunn of Conico Phillips about the

23 Todd rapid mix burner. And in some conversations

24 last night we learned that URS is very familiar

1 with this, and I would just ask Mr. Stapper to

2 offer a few comments on this situation.

MR. STRAPPER: Is that okay for the

4 benefit of the Board?

MR. FOX: Yes, please go ahead.

MR. STRAPPER: The materials shown

7 for the lean pre-mix or the ultra low NOx burners

8 in the document in question on page -- I guess it

9 is page 27 -- refers to the Todd Rapid mix burner.

10 It shows data for the installation at Morning

11 Star. URS actually owns the rapid mix burner

12 technology. We hold two patents for the rapid mix

13 burner, and we license that technology to John

14 Zincs, which markets or previously marketed under

15 the brand name of Todd Combustion. Recently John

16 Zinc's sister company purchased Cohen Company.

17 Cohen now offers the rapid mix burner in this

18 particular application, and the QLA burner that's

19 referenced in these materials is no longer offered

20 because the rapid mix burner is superior in

21 performance. The rapid mix burner is a technology

22 that was developed in the early 1990's. There are

23 almost 300 of them currently in service. The

24 oldest one dating back to 1994. All have been

1 guaranteed and have met 9 ppm, which is .01

2 lbs/MMBtus. With the exception of two recent ones

3 we have developed a new generation of the burner

4 that's a 5 ppm version, and we've applied for a

5 patent on that technology. So URS understands

6 this burner extremely well, and URS benefits from

7 the sales of this burner.

Unfortunately the rapid mix

9 burner only works in a very narrow niche of

10 industrial boiler applications. It only works on

11 wall-fired, natural gas-fired industrial boilers

12 with one or two burners. It won't work for on

13 refinery gas. It won't work on corner fired

14 units, and it won't work on wall-fired units that

15 have more than two burners. And it would be

16 wonderful if we could apply it to all these

17 boilers because we'd sell thousands of these

18 instead of hundreds, but the reality is, this

19 technology, like many other technologies, is a

20 snapshot for a particular application and cannot

21 be applied with a broad brush to the entire

22 population of gas fired industrial boilers. And

23 in fact our agreement with John Zinc states that

24 if they have a request from a customer to apply

1 this on a unit that is not firing natural gas,

2 they have to come to URS and ask if it's possible

3 to apply it in that situation. So the reason I

4 would like to bring this up is there are the --

5 even though this is a wonderful technology and for

6 its application it works as advertised, there are

7 many applications, such as the boilers at Wood

8 River where this technology is simply not

9 feasible. And so I think it's important to

10 remember in reviewing documents such as this, and

11 this is a wonderful document in terms of

12 describing these technologies and how they work

13 and what the potential of these technologies are,

14 but there are always limitations to those

15 technologies and being aware of those limitations

16 is an important part of applying these limits to

17 these boilers.

MS. HODGE: Thank you, Mr. Stapper.

MR. FOX: Any further questions,

20 Ms. Hodge?

MS. HODGE: No, that's all we have.

MR. FOX: Were there any additional

23 questions from the other participants?

MS. VETTERHOFFER: I just had a

1 couple follow-ups. The rapid mix burner is

2 ultra-low NOx.

MR. STRAPPER: Yes.

MS. VETTERHOFFER: It is not a

5 simple stage air low NOx burner, is it?

MR. STAPPER: No.

MS. VETTERHOFFER: Just one second.

8 Does the Illinois EPA require the use of this

9 technology at the Wood River refinery?

MR. STRAPPER: The rapid mix.

MR. STRAPPER: Not that I am aware

12 of.

MR. FOX: Any additional questions

14 on the part of the participants? We have been

15 under way for quite a while. Why don't we take a

16 break and reconvene here at 10:30 and we can start

17 again with the questions from Midwest Generation.

(Whereupon a brief recess was

taken, after which the

following proceedings were

had:)

MR. FOX: When we broke for a short

23 time, we had, I believe, wrapped up the questions

24 based on the pre-filed testimony of Mr.

1 Siebenberger and Mr. Stapper on behalf of U.S.

2 Steel. Was I correct that in fact we had

3 exhausted those? There were no further questions?

4 I'm not seeing any indication that there are.

5 That brings us to the point in the agreed order at

6 which it's time for the testimony of Mr. Wanninger

7 and Mr. Miller on behalf of Midwest Generation.

8 In advance of their testimony, their questions

9 based on that testimony, Ms. Bassi was kind enough

10 to provide copies of pre-filed testimony of

11 Mr. Miller, of the pre-filed testimony of

12 Mr. Wanninger and also Mr. Wanninger has a graph

13 included on page 7, which was not apparently as

14 clear as it might have been and might have been

15 difficult in some of the copies. This was merely

16 a reproduction of that, with the expectation that

17 the type was a little clearer.

Ms. Bassi, I think you indicated

19 you supplied copies to all the attorneys who were

20 here today?

MS. BASSI: I would like to move

22 that these be admitted as separate exhibits,

23 please?

MR. FOX: Very well. And that would

1 be, Ms. Bassi, for Mr. Miller's pre-filed

2 testimony hearing Exhibit No. 12, for

3 Mr. Wanninger's testimony, Exhibit No. 13, and in

4 case of the graph that we have just been referring

5 to, Exhibit No. 14. Is there any objection to the

6 admission of those three exhibits numbered in that

7 way? Neither seeing nor hearing, Ms. Bassi, they

8 will be marked and admitted according to those

9 numbers.

MS. BASSI: Thank you.

MR. FOX: Surely. You had mentioned

12 that you had Mr. Miller and Mr. Wanninger both

13 interested in offering a brief summary or

14 introduction. Why don't we begin by having the

15 two sworn in just to take care of that and we can

16 proceed to those two summaries in whichever order

17 you wish your witnesses to be.

MS. BASSI: Good morning. My name

19 is Kathleen Bassi. I'm with Schiff Harden, LLP,

20 here in Chicago, and with me to my far left is Tom

21 Bell, who is also an associate with our firm. We

22 are here on behalf of Midwest Generation today,

23 and Scott Miller to my right and Kent Wanninger to

24 my left will be presenting brief summaries of

1 their pre-filed written testimony, and then we'll

2 be available for questions. And I request that

3 the Agency or whoever just address the questions

4 to Midwest Generation and the appropriate witness

5 will respond. Thank you.

MR. MILLER: Midwest Generation

7 appreciates the opportunity to present testimony

8 in this proceeding. My name is Scott Miller,

9 S-C-O-T-T, M-I-L-L-E-R. I'm responsible for

10 managing the air quality programs at Midwest

11 Generation and have been in the power generation

12 business since 1978. The rule as proposed

13 contends to exempt units subject to the combined

14 pollutant standard or CPS as we have heard before.

15 Currently subpart F, 225 from this rule. Midwest

16 Generation has opted into the CPS. As a result if

17 the Board exempts the amendments to subpart M

18 offered by IEPA at the October 14th hearing

19 Midwest Generation would be exempt from this rule.

20 However, Midwest Generation does not believe it is

21 prudent for it to ignore the emission limitation

22 included in a rule for solid fuel electric

23 generating units. IEPA must have believed that

24 some limit was necessary, even though all each

1 impacted by this rule has opted into the EPS or

2 the multi-pollutant standard. That being the case

3 Midwest Generation believes it is necessary to

4 address the proposed limit. Midwest Generation

5 supports the testimony given by Dave Kolalz and EK

6 Herner on behalf of IER relative to the

7 appropriateness of subpart M. Based upon analysis

8 provided IER, Midwest Generation agrees that

9 subpart M is not necessary and should be deleted

10 from the rule. As proposed, subpart M exceeds

11 IEPA's definition of RACT as discussed in more

12 detail in Mr. Wanningers' written testimony.

In the alternative, Midwest

14 Generation suggests that the rate that is the

15 basis for the NOx codified in Illinois 217 subpart

16 W of the Board's Rules, 0.15 lbs/mmBtu is a more

17 appropriate emission rate for solid BTUs than the

18 proposed rate of 0.09 lbs/mmBtu. Even at

19 0.15 lbs/mmBtu is potentially more stringent than

20 a NOx SIP Call (sic) to a plant because each plant

21 would have to achieve that rate without reliance

22 on indudstry streams (sic).

Finally, if the Board believes

24 that subpart M must remain in the rule, Midwest

1 Generation supports the amendments offered by IEPA

2 at the October 14th hearing, and urges the Board

3 to substitute that language in addition to

4 changing the emission limit in Section 217.344(a)

5 to 10.15 lbs/mmBtu. Thank you.

MR. FOX: Thank you, Mr. Miller.

MR. WANNINGER: Good morning. My

8 name is Kent Wanninger, W-A-N-N-I-N-G-E-R. I am a

9 director in environmental controls and strategy at

10 Midwest Generation. I have worked in the

11 operation in the electric power industry since

12 1975. My written testimony was submitted to the

13 Board on November 25, 2008. I do need to correct

14 the table on page 6 of the written testimony

15 listing Midwest Generation's units that are

16 subject to this proposed rule. That table does

17 not include two small cyclone boilers, units 1 and

18 2 of the Will County Station. These boilers are

19 scheduled to be shut down at the end of 2010 as a

20 part of a combined pollutant strategy. The

21 emission rates are similar to those of Joliet 6

22 and the other cyclone boilers and the Midwest

23 Generation's Chicago area fleet. As stated in my

24 testimony, Midwest Generation believes that the

1 rate of .09 lbs/mmBtu proposed for solid fuel

2 electric generating units in Section 217 is not

3 RACT, at least at Midwest Generation's units.

4 Midwest Generation is the only company subject to

5 subpart M in the Chicagoland area. Midwest

6 Generation's units with the exception of Joliet 6

7 and Will County 1 and 2 have low NOx emission

8 rates, though none of these can achieve a

9 0.09 pounds with per million BTU rate. IEPA

10 proposed that rate of .09 can be achieved through

11 the application of selective noncatalyte reduction

12 equipment, or SNCR, which according to the IEPA

13 would achieve around 30 percent reduction from

14 baseline levels. However, Midwest Generation's

15 baseline NOx levels are very low, much lower than

16 that included in the IEPA's analysis, where the

17 reference .4 to a .5 lbs/mmBtu baseline.

Midwest Generation has obtained

19 a proposal for the installation of SNCR at one of

20 our tangentially fired units, Will County 4,

21 that's included in the testimony. Based on that

22 proposal, a 30-percent reduction is not

23 achievable. This is the proposal that is attached

24 to my written testimony. The rate of reduction

1 that was proposed by Fuel Tech, the SNCR vendor is

2 a target of 15 percent, which I would point out is

3 not even a guaranteed level of reduction. A

4 reduction of 15 percent is not sufficient for our

5 units to comply with the limit of .09. Therefore

6 in order to comply with this limit, Midwest Gen

7 would have to install selective catalytic

8 reduction or SCR equipment on its Chicago area

9 plants. SCR's are considerably more costly than

10 SNCR'S. Even if the board were to agree that

11 Midwest Generation was RACT and Midwest Generation

12 asserts it was not, it would not be possible for

13 Midwest Generation to comply by the compliance

14 date proposed in this rule. Despite IEPA's

15 testimony to the contrary, our experience is that

16 it takes at least 42 to 48 months for us to plan,

17 finance, permit and install an SCR. Because

18 Midwest Generation's rates are already so low,

19 reducing the rates further to comply with the rate

20 of .09 lbs/mmBtu would cost in the range of 7,000

21 to 32,000 per ton, well in excess of the 2500, the

22 $3,000 per ton identified in the Agency as RACT.

23 I might add that the $7,000 ton number is for our

24 high NOx Joliet unit, which is a higher NOx rate.

There has been a significant

2 run-up in the costs in all areas of construction,

3 including pollution control equipment in recent

4 years. This is illustrated on page 7 of my

5 testimony by the HIS Sarah curve. That's the

6 attachment that was handed out in the larger scale

7 and easier to read. It shows a significant run-up

8 in capital costs for new pollution control

9 equipment in the power sector, particularly in the

10 last two or three years. As an example of that

11 run-up, Wisconsin Power and Light and Webco just

12 recently filed a joint application with the public

13 service commission of Wisconsin to spend 53.9

14 million or $405 a kilowatt on a retrofit of SCR at

15 the Edgewater unit five in Sheboygan, Wisconsin.

16 The proposed rule at least as applied to BUT's is

17 not RACT. Thank you.

MR. FOX: Thank you, Mr. Wanninger.

19 That concludes, of course, the two sets of

20 introductory remarks. And we would be ready, I

21 presume, for questions. Is there anyone who has

22 questions to pose to either of the witnesses for

23 Midwest Generation?

MR. ROCCAFORTE: I'm Gina

1 Roccaforte, assistant counsel on behalf of the

2 Illinois EPA. Good morning.

Has Midwest Generation notified

4 the Agency of its intent to comply with the

5 combined pollutant standard?

MR. MILLER: Yes.

MS. ROCCAFORTE: Isn't it true that

8 this proposed rule making does not apply to coal

9 fired boilers that are complying with the

10 multi-pollutant standards or combined pollutant

11 standards?

MR. MILLER: If the changes are made

13 to the language that we suggested -- if the

14 changes are amended that we recommended and the

15 Agency responded during the question and answer

16 session during the last testimony, we would not be

17 impacted.

MS. ROCCAFORTE: Are you aware that

19 there is currently before the Board docketed as

20 R-9-10 a rule making proposal to incorporate the

21 provisions of the combine pollutant standard

22 within the Illinois Mercury Rule due to the

23 vacature of the Clean Air Interstate Rule. And

24 given --

MS. BASSI: Could I ask for a

2 clarification of that question? You said that

3 R-O9-10 is incorporating the CPS because of the

4 vacature of the CAIR, C-A-I-R?

MS. ROCCAFORTE: I believe that was

6 one of the Agency's reasons for amending the rule,

7 proposing to amend the rule.

MS. BASSI: Okay.

MS. ROCCAFORTE: In addition to

10 addressing monitoring provisions and other

11 provisions.

MS. BASSI: Thank you.

MR. MILLER: Yes.

MS. ROCCAFORTE: Given the NOx and

15 SO2 emissions in the Chicago area, does it seem

16 reasonable that other industries be required to

17 reduce such emissions as well?

MS. BASSI: I'm going to object to

19 that. You are asking them to give you their

20 personal opinions or Midwest Generation's opinion

21 about what should apply to other industries, and

22 that is not within the scope of their expertise at

23 all.

MS. ROCCAFORTE: I'm just trying to

1 ask if the burn --

MS. BASSI: This is a policy question

3 that the Agency has to decide. It's not a policy

4 question that Midwest Generation should be

5 addressing.

MR. FOX: Anything further

7 Ms. Roccaforte.

MS. ROCCAFORTE: Yes, I have some

9 more questions.

MS. ROCCAFORTE: On page 4 of

11 Mr. Wanninger's testimony, you describe the costs

12 of SCR and you provide a figure called the I H I C

13 ERA power capital cost index. There are two lines

14 and just to clarify we would use the lower of the

15 two lines on that figure, the overall without

16 nuclear, is that correct?

MR. WANNINGER: That figure was to

18 demonstrate the trend in the industry for capital

19 costs for all industry going up. The trend shows

20 that there is a variable between different

21 industries, but there is definitely a trend in

22 that direction driving up costs across the

23 industry.

MS. BASSI: And to clarify, this is

1 Exhibit 14 that we handed out?

MR. FOX: Correct, Ms. Bassi?

MR. WANNINGER: It's not just the

4 power industry or the fossil industry experiencing

5 cost run-ups. In fact, if you look at the

6 website, you'll find there's one for petrochemical

7 refineries following the same general trend.

MS. ROCCAFORTE: In using this to

9 project costs, would you escalate costs based upon

10 a factor of the index?

MR. WANNINGER: It's more

12 complicated than that. We've done some initial

13 cost estimates in 2005. We updated some of those

14 numbers in 2006. We saw a significant run-up in

15 that one-year period. From that point on I would

16 take these costs and say they are continuing to

17 increase to 2009.

MS. ROCCAFORTE: So is it correct

19 that if you had a cost of a project in the year

20 2000 and wanted to know how much it would cost in

21 2007, you would multiply the 2000 cost by 171 and

22 divide it by 100, is that correct?

MR. WANNINGER: 182 I think it is.

MS. ROCCAFORTE: For 2007?

MR. WANNINGER: Oh, I'm sorry, 2007,

2 yes. That would be a simplified way of doing it,

3 yes. If you have a cost estimate that's more site

4 specific and more recent, you would apply the

5 appropriate correction to get you in the ballpark.

6 But the idea of this draft or the intent of this

7 draft was to indicate that there was a significant

8 cost increase going on with power prices, and that

9 you need to be aware of that when looking at

10 today's prices versus even three or four years

11 ago.

MS. ROCCAFORTE: So is it correct

13 that when someone makes a projection of a project

14 going into the future, say in 2011, he or she

15 would have to assume some sort of escalation

16 factor since this figure only provides historical

17 information?

MR. WANNINGER: That's correct.

MS. ROCCAFORTE: Is it possible that

20 someone who had a project for 2011 might just

21 extrapolate the line on this figure out to 2011?

MR. WANNINGER: That's a -- it would

23 be dangerous to do that, trying to predict the

24 future. Anyone that would be developing a project

1 cost, would be going at a much greater detail and

2 to cost escalators, what other reasons for it.

3 Also as costs, as a project is designed, equipment

4 is ordered in this four-year window, some of that

5 equipment is ordered in year two, year three, year

6 four, so those costs would be escalated throughout

7 that full four-year period. But really what you'd

8 be looking at is what other drivers would continue

9 this rise or might taper off. And it's a much

10 more indepth review. There are consultants out

11 there that do those types of forecasts. They look

12 at market trends. And it has to be worldwide

13 market trends. A lot of this cost run-up is

14 believed to be caused by the huge growth in China

15 where they are building a power plant a week.

16 India is building power plants, driving up the

17 demand for raw materials. So you really have to

18 have an understanding of what the worldwide

19 markets are doing to project how these costs are

20 going to go up.

MS. ROCCAFORTE: So it wouldn't be

22 until 2011 that he or she would know what that

23 extrapolaiton was, correct?

MR. WANNINGER: Yes, that's true.

1 That's a fair statement. It's always difficult to

2 predict the future. If I could, I'd be rich.

MS. ROCCAFORTE: Would it be fair to

4 say that building a real SCR or other project,

5 would you know for sure what it costs before it is

6 done?

MR. WANNINGER: It depends on the

8 level of -- if you've gone on for bids for the

9 equipment and you got firm bid prices, as you

10 start bidding on major pieces of equipment, those

11 costs become more firm. And typically those are

12 done long before the project is completed.

MS. ROCCAFORTE: Is it fair to say

14 though that there is a certain degree of

15 uncertainty until the project is completed?

MR. WANNINGER: As I said, until you

17 get firm bids on every piece of equipment and the

18 construction is final, as you move towards getting

19 firm bids, the level of uncertainty goes down.

20 And typically you will see contingencies reduced

21 once that level of uncertainty goes away.

22 Normally you cover that, try to anyway.

MS. ROCCAFORTE: So depending how

24 close reality reaches the projection costs, might

1 be under-predicted or over-predicted?

MR. WANNINGER: It could be, yes.

MS. ROCCAFORTE: I notice that the

4 data here on this figure only goes through the

5 first quarter of 2008. Do you have a more recent

6 figure?

MR. WANNINGER: No, that's the most

8 recent we have. I've had other chemical engineer

9 index. There's some others out there trending the

10 same thing, but they only went through 2007.

MS. ROCCAFORTE: Are the escalation

12 of construction costs strongly impacted by

13 escalation of steel and other commodity

14 construction materials used to build power plants?

MR. WANNINGER: That's one of the

16 confluences. Labor, availability of labor, which

17 drives, is driven by what's happening in the

18 marketplace. There are a number of factors, but,

19 yes, definitely commodities, steel, concrete,

20 copper, all those different commodities. I'm sure

21 you are familiar with what's going on with the

22 economy today?

MR. WANNINGER: Yes.

MR. ROCCAFORTE: Are you aware there

1 has been a drop in commodity prices including

2 steel over the last few months?

MR. WANNINGER: I've seen some

4 prices tapering off. We've tracked that because

5 we are in the process of engineering some NCRs,

6 and we are constantly trying to track where the

7 prices are going. Right now I believe our

8 procurement groups feel that at best it's going to

9 slow down at this rate of climb that it's curved.

MS. BASSI: Could I do a follow-up

11 question here, please?

MR. FOX: Please go ahead,

13 Ms. Bassi.

MS. BASSI: Does the idling of

15 plants such as the Granite City Steel Works have

16 an affect on what's going to happen to steel

17 prices in your estimation?

MR. WANNINGER: That's a good

19 question because one of the things we've seen, and

20 we have a procurement consultant that we've hired

21 specifically to track commodity prices, and

22 they've indicated that because of the slow down in

23 the economy, prior to that, there was a lot of

24 capacity addition to meet this demand for these

1 particular commodities, metals, copper in

2 particular, a lot of that capacity that was

3 planned to meet this future growth has been

4 canceled or postponed. So whether or not that,

5 you know, the question then comes in, if you kept

6 building that capacity, yes, I would expect

7 pricing to continue to drop. But once the

8 industry reacts and they back off on that extra

9 capacity, I think our experts think that it's

10 going to tend to stabilize it, but not bring the

11 prices down. Also what we found, too, is that

12 typically when the raw materials do start coming

13 down, the finished products take a year or two lag

14 before we see them respond to that.

MS. ROCCAFORTE: I have some Bureau

16 of Labor statistics here from the U.S. Department

17 of Labor. I'd like to move that they be

18 introduced as an exhibit.

MR. FOX: Thank you. That would be

20 great.

MS. BASSI: Do we have an extra copy

22 we can look at?

MS. ROCCAFORTE: I don't. I

24 apologize for that.

MR. FOX: If you have a single copy

2 now, and, Ms. Bassi, you'd like to examine it now,

3 we could deal at the conclusion of admitting it as

4 an exhibit.

MS. ROCCAFORTE: Would you be

6 surprised if these statistics demonstrated a

7 decline in the price of various metal and metal

8 products, hot rolled bars, plates and structural

9 shapes?

MR. WANNINGER: I think in short

11 term, I think there has been some decline, yes.

MS. ROCCAFORTE: Going back to

13 Exhibit 14, say someone made a projection of a

14 cost of a project out to 2011 and extrapolated

15 this line as if it were ever increasing out to

16 2011, but it actually dropped off, wouldn't that

17 mean that they likely over-estimated the cost?

MR. WANNINGER: Yes, I would say so,

19 hindsight is always 20-20.

MS. ROCCAFORTE: On page 8 of your

21 testimony you describe projected costs at Midwest

22 Generations Powerton Station and at Wisconsin

23 Light and Power's Edgewater station.

MR. WANNINGER: Yes.

MS. ROCCAFORTE: What is the

2 start-up date?

MR. WANNINGER: In time for the CPS

4 agreement, 2012, January 1st.

MS. ROCCAFORTE: Have you started

6 construction on it?

MR. WANNINGER: We are in the

8 engineering phase right now.

MS. ROCCAFORTE: Would it be fair to

10 say that you really won't know the final cost of

11 the Powerton SCR until the plant it completed?

MR. WANNINGER: Without absolute

13 certainty, we won't know, that's correct. As far

14 as using the data on page 7, again, that is

15 historical, that is reflecting that cost estimates

16 of just three or four years ago and need to be

17 taken into the right context. The costs have

18 continued to go up. As far as projecting those

19 feature costs, as I said earlier, it would be,

20 probably dangerous to say that this rate of

21 increase is going to continue.

MS. ROCCAFORTE: So your estimate

23 could be high or low?

MR. WANNINGER: If you follow that

1 increase. I am not saying we follow that

2 increase. In fact, in my analysis of our 2005 and

3 2006 numbers, I do not use that beyond the time

4 frame of 2008. We had a much more conservative

5 increase than we expect in the future years, but

6 we do not see it dropping.

MS. ROCCAFORTE: How did you project

8 the cost using this index for the year 2012?

MR. WANNINGER: For?

MS. ROCCAFORTE: For the Powerton?

MR. WANNINGER: We had a $240

12 kilowatt number that was updated in 2006. In that

13 period of time there was about a 30 percent

14 increase in the numbers from, based on the SERA

15 report, then we reduced the forecast rate to I

16 think a number of three percent per annum, which

17 right now we would have said a higher number two

18 months ago, but again, with the change in the

19 economy. And, again, when is that going to turn

20 around? That gets us in the ballpark of the price

21 that we just saw in this recent Edgewater

22 announcement of an SCR.

MS. ROCCAFORTE: Do you know the

24 plan to start the update for that Edgewater SCR?

MR. WANNINGER: It's in their

2 report. I can't remember. I think it's the end

3 of 2011 or somewhere like that. In this time

4 frame, 2012, somewhere around there.

MS. ROCCAFORTE: So if costs do drop

6 over the next few years as they have in the next

7 few months, doesn't that increase the chance that

8 your projected costs for the Powerton SCR and

9 Edgewater's SCR may be high?

MR. WANNINGER: As I said, we do not

11 expect the rates to go up like they have

12 historically. We are expecting something much

13 slower of an increase. Labor is a big part of the

14 costs of a plant. Typically over half the costs.

15 And labor rates are not going down. Union labor

16 rates are what they are. They are going -- they

17 are negotiating increases every year. So those

18 costs will not go down. And depending on the --

19 one of the problems we are running into is

20 manpower. We're coming up into a period in this

21 time frame where a large part of the construction

22 work force is retiring, and there are not a lot of

23 people getting into the building trades, and

24 because of that and the competition for labor with

1 the steel industry, with the refinery industry,

2 with other utilities in the region, we have what

3 we thought travelers -- we bring them in over the

4 country to staff our major outages. Those people

5 get paid premiums to come in. So we see the labor

6 is definitely not going down. If anything, it's

7 getting tighter. Materials we think, it's a short

8 thing to decline. If the economy recovers, we

9 don't think it's going to continue to drop.

MS. ROCCAFORTE: Do you have a sense

11 of what it will cost Midwest Generation to comply

12 with the NOx and SO2 requirements of the combined

13 pollutant standards?

MS. BASSI: Can I ask how that's

15 defined to NOx RACT?

MS. ROCCAFORTE: Discussing cost

17 compliance options to comply with NOx RACT.

MR. WANNINGER: I don't have the

19 number at my fingertips, and part of the issue is

20 variable because as you are aware of probably the

21 CPS agreement had some options for early

22 retirement versus retrofit. We haven't made those

23 decisions yet. So I don't know how in the future

24 years what units will be retrofitted or retired.

1 I think if, you know, if you look at our 10-K

2 there were some figures of what we said and beyond

3 that I can't say. I'm not familiar with what's in

4 there off the top of my head.

MS. ROCCAFORTE: And will Midwest

6 Generation be making substantial reduction of NOx

7 in complying with the pollutant standards?

MR. WANNINGER: Yes.

MS. ROCCAFORTE: I have nothing

10 further.

MS. BASSI: I have a couple

12 follow-ups. Can SCR be installed at each of the

13 Chicago plants for between $2500 to $3,000 a ton?

MR. WANNINGER: I really haven't run

15 the calculation. I was more focused on the

16 ability to get down to .09, which according to our

17 Fuel Tech proposal says they can't get there.

18 They can't get close, which is one of the things

19 that we did include in the testimony. One of the

20 things we found in talking to field techs. And of

21 course the amount of reduction affects whether or

22 not it gets TIF on a dollar per ton basis. The

23 denominator is how many tons you remove. 30

24 percent reduction would get more reduction than 15

1 percent. And one of the things they've told us is

2 they never worked on a unit with this low a NOx

3 rate. They have indicated that 15 percent is

4 their target. In fact when we first solicited

5 their input, they said 10 to 15 percent was more

6 likely. As you can see, they only gave us a

7 target. They didn't give us a guarantee.

MS. BASSI: Is that for SNCR?

MR. WANNINGER: For SNCR, yes.

MS. BASSI: Okay. So the cost of

11 SCR, is it the case that the cost of SCR would be

12 considerably more than the cost of SNCR?

MR. WANNINGER: Oh, yes, definitely.

MS. BASSI: Would the cost of SCR at

15 the Fisk Station for example fall in the range of

16 $2500 to $3,000 a ton for NOx removal?

THE WITNESS: No, not even close.

MS. BASSI: How many units are there

19 at Fisk?

MR. WANNINGER: One.

MS. BASSI: That would be the worst

22 case?

MR. WANNINGER: Yes.

MS. BASSI: A better case might be

1 one of the other stations would it fall into the

2 range of $2500 to $3000 per ton?

MR. WANNINGER: No, it wouldn't.

MS. BASSI: Are you aware of that

5 news, all the news talks about the unemployment

6 rate increasing?

MR. WANNINGER: Yes.

MS. BASSI: With the unemployment

9 rate increasing, would this have an affect on the

10 availability of construction workers for your

11 industry?

MR. WANNINGER: You know,

13 construction workers are a trained work force.

14 Various building trades, apprentice programs, they

15 have to go through and they are fairly lengthy in

16 terms of years. Plus you have to attract that

17 work force to the construction industry. Then

18 construction industry is typically a very vagabond

19 type work force. And not a lot people like to be

20 moving around for eight weeks, twelve weeks to go

21 to Iowa for eight weeks or twelve weeks. They

22 tend to be a specialized group. Not everyone is

23 going to want to go into that business. And even

24 if they did, they would have to go through a

1 significant amount of training.

MS. BASSI: That's all I have.

MR. FOX: Did the Agency, Ms.

4 Roccaforte, have any additional questions?

MS. ROCCAFORTE: Has Midwest

6 Generation conducted an analysis to determine

7 whether SCR is required on all of its units?

MR. WANNINGER: Conducted an

9 analysis?

MS. ROCCAFORTE: Whether SCR would

11 be required?

MR. WANNINGER: Would be, we

13 conducted a cost estimate for technology or I'm

14 not sure -- well to reach the .09 rate, yes, we

15 feel SNCR is insufficient, and if we had to get

16 there we believe we would have to go with an SCR.

MS. ROCCAFORTE: On all units?

MR. WANNINGER: We do it plantwide

19 so you might be able to do one unit at a plant, at

20 a two-unit plant. Because our emission rates are

21 fairly low, even if you overcomply with one unit,

22 but even with that, the dollar per ton numbers are

23 still well above the $3,000 range.

MS. ROCCAFORTE: Are you aware of

1 any other tangential units operating in Illinois

2 at or below the 0.09 pound per MMBTU unit with

3 only combustion controls?

MS. BASSI: Do you mean this as

5 EGU's?

MR. WANNINGER: I'm aware that

7 Baldwin III has a very good NOx rate in the .09-

8 .1 pound range, yes.

MS. BASSI: Why is that?

MR. WANNINGER: What I've looked at,

11 there are several reasons why this appears to be

12 the case. One is the age of the unit. Baldwin

13 III is a 600 megawatt unit. It's a newer unit

14 from CE now Alstom. It's a single furnace design,

15 which is a much more open furnace design that

16 leads to better low NOx firing, better staging

17 with their state of the art, what they call TFS

18 2000 system. That's low NOx burners. Our units

19 are probably roughly ten-year old or vintage,

20 which are older CE units. They are typically twin

21 furnace set-ups. They are not the big open

22 furnace, which tends to concentrate heat more and

23 heat creates NOx. We have retrofitted all of our

24 units with the TFS 2000. So we put the state of

1 the art technology that Alstom provides. I might

2 add they have a NFLCS I, II, III and the top of

3 the line is the TFS 2000. We have retrofitted our

4 units with that. I think it's the size of the

5 unit and the age of the unit, it doesn't allow it

6 to get to those levels. If you look at some of

7 the other units on the Dynagy (sic) system that

8 owns Baldwin, you will see that some of the units

9 do not get down to that level. Another reason is

10 if you look at how Baldwin III is dispatched, in

11 the southern part of the state, that is in the

12 Midwest ISO (phonetic). In the northern part of

13 the state we're dispatched through PJM. So we

14 dispatch in different, independent, system

15 operations. In the northern part of the state

16 we're heavily nuclear base loaded. So our fossil

17 units cycle load daily, and we also regulate load,

18 meaning as you turn the light switch on, somebody

19 has to crank up a load another half a megawatt or

20 something. Hopefully not a half a megawatt.

21 Somebody has to raise the load to cover that

22 because we don't have storage capacity so, it's

23 just a comment on it. So we end up regulating

24 loads and cycling loads with our units here in

1 Northern Illinois.

In southern Illinois there's

3 only one nuclear unit, Clinton. It's a small

4 unit, a single unit. And the rest of it is base

5 loaded with coal. And of course your large coal,

6 such as your Baldwin's, units 1, 2 and 3 are the

7 units that become base loaded. When you are --

8 base loaded -- and it's a long introduction -- but

9 when you are base loaded, those units, if you look

10 at their dispatch, you will see that they spend

11 the vast majority of their time at full load.

12 Very rarely do they even come down to low load,

13 and you don't see the constant load swinging that

14 you see on our units to try and regulate voltage

15 control. As a result, you are able to tune NOx

16 much more precisely when things aren't moving.

17 The analogy is your car. If you take it up to

18 65 miles an hour and put it on cruise control,

19 versus if you accelerate 75 to 55 down to 55,

20 where do you get the better gas mileage? Steady

21 state. You are able to fine tune everything.

22 Baldwin is that type of operation. In fact, I ran

23 some curves, and I don't know if these -- I took

24 information off the part 75 CEM data base and I

1 don't know --

MS. BASSI: Where is the part 75 CEM

3 data base located?

MR. WANNINGER: It's in the USEPA

5 website.

MS. BASSI: And do you have an

7 address for it?

MR. WANNINGER: Scott could provide

9 it I'm sure. What I plotted was load versus time

10 and I took a month, the month of July 2007. And

11 you can see it sits at full load almost all the

12 time on Baldwin. Then I compared it to one of our

13 units, a Joliet unit. Now, the megawatts on the

14 side is, one boiler, our unit having a twin

15 boiler. So that's why it's half a unit, but the

16 trend is the same. You can see the seesaw motion

17 of the data. And that seesaw motion makes it very

18 difficult to control NOx. When you are constantly

19 ramping load, what you have to do is you have to

20 over-fire to raise load, to build up pressure to

21 raise load, you under-fire to drop load, and when

22 you do that, you always add air a little bit more

23 of the fuel in order to avoid getting fuel rich.

24 So it makes it much more difficult to control NOx.

1 Again, Baldwin is the flat line where it virtually

2 sits at full load. That's a month's worth of

3 data. Those are the two main reasons. There may

4 be some other tweaks that have been done. I know

5 they installed a neuro net to optimize their

6 control.

MS. BASSI: What is a neuro net?

MR. WANNINGER: A neuro net is an

9 artificial intelligent system that evaluates a

10 plethora of operating parameters and tries to

11 optimize every damper and every control linkage

12 that you have to control combustion and optimize

13 NOx. They sit there constantly learning, and then

14 they eventually come back and say, I figured out

15 that by operating these dampers in this

16 arrangement -- and we are talking a hundred

17 dampers -- maybe that can be tweaked between all

18 the corners and all the elevations of coal

19 dampers, coal burner nozzle tilts, coal burner

20 over air, separate over air, show there is a lot

21 of adjustments that can be made. And this thing

22 can sit there and continuously relearn and

23 optimize to the tenth degree.

We've tried neuro nets on our

1 system, on a T-fired unit, and what we found is

2 that the systems need to have steady state

3 operation to really optimize. They stopped

4 learning when the unit stops ramping, and they

5 don't stop learning until it stops ramping for so

6 many minutes. We never stopped long enough for it

7 to learn. So they've been able to -- that's

8 probably more information than I needed to say.

MR. FOX: The record is richer.

10 Ms. Bassi, you had handed me, and I believe you

11 notified me a copy of them, as well to the Agency

12 two documents, one regarding the Baldwin III, one

13 regarding Joliet 71 boiler that, I believe,

14 Mr. Wanninger from a USEPA source. Did you have a

15 motion for that or any other?

MS. BASSI: What I propose to do is

17 take those back from you or you can keep those,

18 but to submit these to the docket and propose

19 that, they be admitted as an exhibit. And what I

20 will also provide when I submit it to the docket

21 is the EPA address, you know, to give it a

22 citation.

MR. FOX: And that would help to

24 make it clearer. I will agree that makes a great

1 deal of sense. The Agency had a chance to look at

2 it, if not, obtain a copy of this.

MS. BASSI: If you could close the

4 record in that fashion.

MR. FOX: Did you indicate that?

MS. BASSI: I was going to scan them

7 into my PDF system so I can have them. He can

8 send me new ones. So would this be admitted as

9 Exhibit 15, is that what it is?

MR. FOX: The next two would be 15

11 and 16.

MS. BASSI: Those would be separate?

MR. FOX: I think it would be

14 helpful because they deal with two separate

15 numbers.

MS. BASSI: And which did you want

17 to be which?

MR. FOX: Why don't we make Baldwin

19 the first, out of alphabetical order if nothing

20 else.

MS. BASSI: And what about

22 Ms. Roccaforte, the Bureau of Statistics?

MR. FOX: That was my next question.

24 Let me see, Ms. Roccaforte, did you or anyone else

1 from the Agency have any further questions for

2 Midwest Generation?

MS. ROCCAFORTE: No.

MR. FOX: Then Ms. Roccaforte,

5 Ms. Bassi has lead me right to the issue, I think

6 you said they were Bureau of Labor Statistics

7 data, and you had shared those I'm sure with

8 Ms. Bassi and Mr. Wanninger. Did you have a

9 motion with regard to those?

MS. ROCCAFORTE: Yes, I'd like to

11 move these charts be admitted as exhibits.

MR. FOX: Why don't I identify them?

13 I'm trying to distinguish the two of these so they

14 can be submitted separately. Can you eliminate

15 that for me in any way?

MS. ROCCAFORTE: One states Scrap

17 Metal and the other one lists out the finished

18 product.

MR. FOX: The one that refers to the

20 item "Hot rolled bars, plates and structural

21 shapes," would be then admitted as No. 17. And

22 that is a single-page document, and just in the

23 interest of clarifying that, no. 18 then would be

24 then, as you referred to it, that is the two-page

1 document. And, Ms. Roccaforte, forgive me if I've

2 forgotten, did you have a specific motion that

3 you'd offer or did you wish to do so now?

MS. ROCCAFORTE: I did it, yes.

MR. FOX: You made it. My memory is

6 lapsing. Was there any objection to admitting

7 these two documents from the Bureau of Labor

8 Statistics as Exhibits Number 17, 18? Neither

9 hearing nor seeing any, they will be marked and

10 admitted in that fashion.

Did the Agency have any further

12 questions for Midwest Generation?

MS. ROCCAFORTE: No.

MR. FOX: Very well, that wraps up,

15 I believe, any questions for the witnesses by

16 Midwest Generation and concludes the questions

17 based on the five sets of pre-filed testimony that

18 the Board received on November 25th in this

19 docket.

We did have, as I mentioned, I

21 think, at the conclusion of the day yesterday, a

22 single person who indicated that wished to

23 testify, but I think you clarified that you wished

24 to make a public comment to the board that would

1 be unsworn. I think Mr. Urbaszewski that you

2 wished to make a comment to the board unsworn.

3 We've come to a point, if you are prepared, it's

4 probably most appropriate to do that.

MR. URBASZEWSKI: My name is Brian

6 Urbaszewski. I'm the director of Environmental

7 Health Programs for the Respiratory Health

8 Association of Metropolitan Chicago.

I want to say thanks for allowing me to

10 speak. We advocate on behalf of the hundreds of

11 thousands of people in Illinois who live with lung

12 disease every day. We do educational programs in

13 schools. We support medical research. And we

14 advocate for clean air. We've been working on

15 lung health issues in the metropolitan Chicago

16 area since 1906.

I first wanted to state that

18 setting good RACT and RACTM limits is critical for

19 public health. We agree with IEPA that strong NOx

20 limits from the affected categories are needed to

21 reduce both Ozone and PM2.5. I also wanted to

22 reiterate that standards are getting tighter and

23 we will still have nonattainment issues going

24 forward. While it appears that the Agency may

1 apply for redesignation with the 0.08/8hr ozone

2 standard in the near future, the state is now

3 facing a new tighter ozone standard and the

4 current nonattainment areas are expected to be

5 designated as nonattainment areas with the new

6 standard as well. Also, the Agency has also been

7 notified by USEPA that final NAAs for the 2006

8 PM2.5 NAAQS will occur on or before December 18th.

Not only has the federal

10 government stated that the current PM2.5 NAAs are

11 not expected to meet this tighter, though still

12 inadequate standard, but that two additional areas

13 in the state, Rock Island and Massac County, will

14 also likely be classified as NAAs.

Even the new standards are

16 inadequate. It is important features in the news

17 coming out just yesterday and today in the

18 Philadelphia Enquirer. It is important to note

19 that the USEPA has essentially ignored the advice

20 of its own experts in setting NAAQS for both ozone

21 and PM2.5. By this I mean for Ozone, the new

22 standard 0.075 is higher than the range of

23 0.06-0.07 that was recommended by Agency's own

24 advisor. Likewise, the annual 15um is higher than

1 the 13-14 um recommended by its advisors. It was

2 complained loudly that the advice given over the

3 past years based on medical and scientific

4 evidence is being ignored. Likely current reviews

5 will result in tighter standards that will be

6 adopted by the EPA under an Obama Administration,

7 if tighter standards are not adopted through legal

8 action first.

Based on the preponderance of

10 medical evidence and expert scientific opinion, we

11 continue to believe the levels of the new

12 standards are insufficient, do not comply with the

13 requirements of the Clean Air Act to provide a

14 reasonable margin of safety when setting NAAQS.

While the State has made

16 progress in lowering ozone levels, and credit is

17 deserved for implementing regulations and programs

18 that have helped achieve these lower levels, it

19 must also be noted that the region has also

20 benefited from unusually cool summer weather in

21 2006 and 2008 that greatly diminished ground level

22 ozone formation.

I'm referring to this because

24 people have been mentioning that we are close to

1 achieving ozone standards. Mr. Tom Skilling noted

2 in the 8/13/08 Chicago Tribune, "There have been

3 only 162 days 90 degrees or warmer at Midway

4 Airport over the period from 2000 to 2008. That's

5 by far the fewest 90-degree temperatures in the

6 opening nine years of any decade on record here

7 since 1930."

This summer's highest reading to

9 date was just 91 degrees in August. That's

10 unusual. Since 1928, only one year, 2000, has

11 failed to record a higher warm season temperature

12 by August 13th. Other than one 95 degree day in

13 September 2008, there were no days higher than 91

14 degrees this year at Midway Airport. Only 10 days

15 were recorded at 90 degrees or above. In 2006

16 only 16 such days were recorded. This is compared

17 to 21 in 2007 and 35 in 2005. The long-term

18 average is nearly 24 days per year reaching 90

19 degrees or above.

In regards to Midwest

21 Generation's written testimony, Midwest Generation

22 says it believes it can meet 0.15 lbs/MMBtu at all

23 of its plants, and in fact is at or near this

24 level in several cases. It also claims that it

1 doesn't believe 0.09 is RACT. They claim that

2 since their emissions are already low, SNCR can

3 only get a 15 percent reduction. Likewise they

4 claim SCR is too expensive.

We think that due to worldwide

6 economic conditions and falling prices for labor

7 and materials, that the Company has vastly

8 overstated the cost per ton of removing NOx from

9 potentially affected plants in the Chicago

10 metropolitan area. We would strongly encourage

11 the Agency and the Board to consider the strictest

12 possible emission limits at the plants, which

13 remain among the single largest source of NOx in

14 the metropolitan area.

Although we have concerns about

16 the legality of claiming that CAIR fulfills, or

17 the Illinois rules designed to fulfil the

18 requirements of CAIR/CAMR fulfill the requirements

19 for RACT/RACM, we support the Agency's efforts to

20 reduce NOx from various sources in Illinois as

21 proposed in the rule. Time is of the essence.

22 Because of health damage from high ozone and PM2.5

23 levels is ongoing, we encourage the Board to move

24 forward as quickly as possible to implement the

1 Agency's proposal.

MR. FOX: Thank you,

3 Mr. Urbaszewski, for your comment in this

4 proceeding. Is there any additional person who

5 wishes to offer a comment? Seeing no indication

6 that there is, we can move on then to some of the

7 housekeeping details.

The first of which is that we do

9 have to address the issue of an Economic Impact

10 Study. Since 1998 section 27(b) of the

11 Environmental Protection Act has required that the

12 Board request that the department now known as the

13 Department of Commerce and Economic Opportunity

14 conduct an Economic Impact Study of proposed rules

15 before the Board adopts them. The Board then must

16 make either the impact study, Economic Impact

17 Study or the Department's explanation for not

18 conducting and make one available to the public at

19 least 20 days before a public hearing. In a

20 letter dated June 6, 2008, which is listed on the

21 Board's clerk's office on line under this docket

22 number R08-19, the Board requested that the

23 Department conduct an Economic Impact Study on

24 this rule making proposal. To date the Board has

1 received nothing from the Department responding to

2 that request, and my question is to the

3 applicants, as to whether anyone would like to

4 offer testimony regarding the request from the

5 Board to the Department of Commerce and Economic

6 Opportunity at this time? Seeing none, we will

7 move on then.

And specifically we've come to

9 the point where we can address the issue of the

10 third hearing that was raised at the very

11 beginning of the hearing yesterday. Ms.

12 Roccaforte, I think I remember your comment

13 accurately, but please correct me if I'm not. The

14 Agency was not opposed to scheduling a third

15 hearing in this docket, and we will see if that

16 continues to be the Agency's position at this

17 point.

MS. ROCCAFORTE: Yes, that's

19 correct.

MR. FOX: Do any of the other

21 participants wish to?

MS. BASSI: May we go off the record

23 for just a moment.

(Whereupon, a discussion was

had off the record.)

MR. FOX: Ms. Bassi, did you wish to

4 offer any further comment on that issue?

MS. BASSI: I was just raising a

6 question of whether because this rule is limited

7 to the two nonattainment areas, if one hearing has

8 to be held in a nonattainment area as opposed to

9 Springfield where it was held before. I was just

10 raising the question.

MR. FOX: Just so I may deal with

12 that and move on, do any of the other participants

13 wish to be heard on the issue of a third hearing?

14 Seeing that there is certainly no strenuous

15 objection, I believe to conducting a third

16 hearing, it's my intent specifically to issue a

17 hearing officer order that would schedule one and

18 what I would like to do, again, Madam court

19 reporter, is go off the record for a moment to

20 discuss the procedural details of when we will

21 have that.

(Whereupon an off the record

discussion was had.)

MR. FOX: We will continue this

1 hearing to a date February 3, 2009, at a location

2 to be determined. Please check the website for

3 further information.

(End of proceedings.)

100

1 STATE OF ILLINOIS )

) SS.

2 COUNTY OF COOK )

I, DENISE ANDRAS, being a Certified

5 Shorthand Reporter doing business in the City of

6 Des Plaines, Illinois, County of Cook, certify

7 that I reported in shorthand the proceedings had

8 at the foregoing hearing of the above-entitled

9 cause. And I certify that the foregoing is a true

10 and correct transcript of all my shorthand notes

11 so taken as aforesaid and contains all the

12 proceedings had at the said meeting of the

13 above-entitled cause.

___________________________

DENISE ANDRAS, CSR

CSR NO. 084-0003437