IN THE MATTER OF

:

)

PROPOSED NEW 35 ILL. ADM. CODE 225

)

CONTROL OF EMISSIONS FROM

)

LARGE COMBUSTION SOURCES (MERCURY) )

NOTICE

TO :

Dorothy Gunn

Clerk

Illinois Pollution Control Board

James R. Thompson Center

100 West Randolph St., Suite 11-500

Chicago, IL 60601-3218

SEE ATTACHED SERVICE LIST

PLEAST TAKE NOTICE that I have today filed with the Office of the Clerk of the

Illinois Pollution control Board the POST-HEARING COMMENTS OF THE ILLINOIS

ENVIRONMENTAL PROTECTION AGENCY a copy of which is herewith served upon you

DATED: July 28, 2006

Illinois Environmental Protection Agency

1021 North Grand Avenue East

P.O. Box 19276

Springfield, Illinois 62794-927

BEFORE THE ILLINOIS POLLUTION CONTROL BOARD

RECEIVED

CLERK'S OFFICE

JUL 3 1 2006

R06-25

STATE OF

ILLINOIS

Pollution Control Board

(Rulemaking - Air)

ILLINO

VIRONMENTAL

PRO

N

olm J .

Managing Attorney

Air Regulatory Unit

Division of Legal Counsel

---

BEFORE THE ILLINOIS POLLUTION CONTROLBOARD RECEIVED

CLERK'S OFFICE

IN THE MATTER OF :

)

JUL 3 1 2006

R06-25

TE

PROPOSED NEW 35 ILL. ADM. CODE 225

)

(RulemakingATAE

OF ILLINOIS

ion Control Board

CONTROL OF EMISSIONS FROM

)

LARGE COMBUSTION SOURCES (MERCURY) )

POST-HEARING COMMENTS OF THE ILLINOIS ENVIRONMENTAL

PROTECTION AGENCY

NOW COMES the ILLINOIS ENVIRONMENTAL PROTECTION AGENCY (Illinois

EPA), by one of its attorneys, John . J. Kim, and hereby submits comments in the above

rulemaking proceeding. The Illinois EPA appreciates the efforts of the Illinois Pollution Control

Board (Board) in this rulemaking regarding the request to add 35 Ill. Adm. Code Part 225 to

control mercury emissions from coal-fired electric generating unties . Though the Illinois EPA

responded to most every issue raised at the first hearing in this matter on the record during those

proceedings, some outstanding issues remain to be addressed in these post-hearing comments

.

RESPONSES TO QUESTIONS RAISED DURING THE JUNE 12, 2006 HEARING

Question :

Directed to James E. Staudt, Ph.D., CFA question 59 a,b,c from Ameren

:

With reference to page 156 of the technical support document,

a. by unit, what are the coal types (bituminous, sub-bituminous) you are

assuming IL units will be burning in 2009?

b.

by unit, what are the 2009/10 control configuration (S02, NOx and PM

controls) you are assuming?

c .

What is the level of co-benefits are you assuming for the 2009/10 control

configurations (in pounds) and the removal efficiencies of these control

configurations?

Answer:

Response from James E. Staudt, Ph.D., CFA :

In response to questions 59 a, b, c, I stated at the hearing that I would

provide a table that includes my assumptions from the TSD . Since preparing the

TSD, my understanding of the configuration of some of the plants has changed

.

Therefore I am presenting two tables - one that shows what was assumed in the

original TSD and the other is based upon my more current understanding . In the

more recent one I show the calculated cobenefit in ounces as well as percentage

.

For the few unscrubbed bituminous units (except for Meredosia), I assumed that

90% removal or 0.008 lb/GWhr was achievable through a combination of

1

---

cobenefit (around 30-50%) and sorbent injection (additional 85% removal) . I

assumed no cobenefit mercury removal for any of the PRB fired units, except

Baldwin. It is likely that some significant cobenefit removals are achieved at

some of these units . This will have the effect of lowering the cost or increasing

the amount of mercury removed from the estimates shown here

.

2

---

IT

3

Owner

Plant Name

Unit #

oal

Post-

omb NO

FGD

PM

Co-benefit % Comments

I

lUCK CREEK

t

IT CI

et FGD

old-side ESP

0% or 0.008

-NEWTON

C e~ one

None

old-side ESP

EWTON

one

one

old-side ESP

E D EDWARDS

1

one

None

old-side ESP

E D EDWARDS

one

one

Cold-side ESP

•

0 EDWARDS

IT

+

one

old-side ESP

0%

OFFEEN

IT

one

old-side ESP

0%

OFFEEN ~

~~P

one

old-side ESP

0%

UTSONVILLE

IT

one

one

old-side ESP

0%

UTSONVILLE

6

IT

one

one

old-side ESP

0%

EREDOSIA

~,~-~

one

one

Id-side ESP

EREDOSIA

IT

one

one

old-side ESP

0%

MEREDOSIA

one

one

old-side ESP

EREDOSIA

04

C

::

one

one

old-side ESP

It -~ EREDOSIA

one

one

old-side ESP

PALLMAN

IT C~

et FGD

old-side ESP

0% or 0.008

~DALLMAN

IT

et FGD

old-side ESP

0% or 0.008

DALLMAN

IT

L~

et FGD

old-side ESP

0 % or 0.008

Dynegy

:ALDW IN

old-side ESP

.0%

o add

which reduces sorbent injection rate

.

to IL

obenefit

fit based on Dynegy presentation

to IL

PA

ynegy

:ALDWIN

~

.

:SCR

one

old-side ESP

0%

Dynegy

BALDWIN

:SUB

one

one

old-side ESP

0%

Dynegy

HAVANA

one

of-side ESP

o add FF, TOXECON assumed

Dynegy

ENNEPIN

1

C

::

one

one

old-side ESP

Dynegy

HENNEPIN ::None

one

old-side ESP

ynegy

ERMILION

1

BIT

None

one

old-side ESP

o add FF, TOXECON assumed

ynegy

ERMILION

i

IT

one

one

old-side ESP

Dynegy

ODD RIVER

one

None

old-side ESP

Dynegy

DOD RIVER

SUB

one

one

old-side ESP

oppa

OPPA STEAM

one

one

old-side ESP

oppa

OPPA STEAM :

one

None

old-side ESP

---

4

oppa

JOPPA STEAM

one

None

old-side ESP

J

=Ci

SUB

one

one

old-side ESP

J

5

C c~ one

None

old-side ESP

J

one

one

old-side ESP

1

one

old

~~

one

Cold

M

BIT

et FGD

Id

0 /o

or 0.008

Marion

123

IT

'

~

one

Fabric Filter

% or 0.008

Midwest

1

C t

one

one

old-side ESP

2

SUB

one

one

old-side ESP

J

1

C e~ one

one

old-side ESP

J

2

C e~ one

one

old-side ESP

5

C:None

None

old-side ESP

C

C c~

one

one

old-side ESP

C

one

d-side ESP

4

e~

one

one

old-side ESP

SUB

one

None

old-side ESP

Midwest

one

one

old-side ESP

Midwest

one

None

old-side ESP

AUKEGAN

UB

TOXECON assumed

Midwest

NAUKEGAN

~

.

:

I

one

one

old-side ESP

ILL COUNTY

1

us

one

None

old-side ESP

I

ILL COUNTY

UB

one

old-side ESP

R

TOXECON assumed

Midwest

None

Midwest

19

+

---

5

to i uts to revisea cost es tmate

Owner

Plant Name

Unit #

Post-

omb NOx

FGD

PM

o-

benefit %

Comments

~ •

UCK

CREEK

BIT

SCR

et FGD

0% or

.008

2,278

EWTON

1

one

one

old-side ESP

0

•

EWTON i~

one

one

old-side ESP

0

E D EDWARDS

C e~

one

one

old-side ESP

0

s "- -

E D EDWARDS 7~

one

None

old-side ESP

0

I• -E D EDWARDS

one

old-side ESP

0

OFFEEN

a

IT

None

old-side ESP

0%

744

OFFEEN

a

IT

None

old-side ESP

0%

1,307

•

UTSONVILLE

None

0

n in

etn

oto

is used

switch

tup

PRB coal as high S coal

I•HUTSONVILLE

6

one

None

old-side ESP

0

EREDOSIA

01

BIT

0

%

11

Expected to use TTBS. Use TTBS injection

ates

~MEREDOSIA

I

IT

one

None

old-side ESP

0%

10

EREDOSIA

I

IT

one

one

old-side ESP

0%

19

I•

-

m

MEREDOSIA

04

IT

one

one

old-side ESP

0%

20

!~MEREDOSIA

M'

:

one

one

old-side ESP

0

~IALLMAN

BIT

et FGD

old-side ESP

0%

646

'~DALLMAN

IT

et FGD

old-side ESP

0%

631

.~DALLMAN

a

IT

e,

et FGD

old-side ESP

0%

1,383

Dynegy

BALDWIN

t

C

e~

-

:

None

old-side ESP

0%

5,951

o add FF in 2010, TOXECON assumed

Dynegy

BALDWIN

one

old-side ESP

0%

5,767

o add FF in 2011, TOXECON assumed

Dynegy

BALDWIN

~C,31-:

one

None

old-side ESP

0%

6,409

o add FF in 2012, TOXECON assumed

Dynegy

AVANA

one

of-side ESP

0

o add FF in 2012, TOXECON assumed

Dynegy

HENNEPIN

1

C '

.None

one

old-side ESP

0

Dynegy

ENNEPIN

~C eul

one

one

old-side ESP

0

Dynegy

ERMILION

IT

None

one

old-side ESP

0%

158

o add FF and SI in 2007, TOXECON assumed

Dynegy

ERMILION

i

BIT

one

None

old-side ESP

0%

239

o add FF and SI in 2007, TOXECON assumed

Dynegy

ODD RIVER

=C

eJ

None

None

Cold-side ESP

0

Dynegy

ODD RIVER

SUB

one

one

old-side ESP

0

oppa

OPPA STEAM

1

one

one

old-side ESP

0

---

6

Joppa

JOPPA STEAM

2

SUB

one

None

Cold-side ESP

0

0

Joppa

JOPPA STEAM

3

SUB

None

None

Cold-side ESP

0

0

Joppa

JOPPA STEAM

4

SUB

None

None

Cold-side ESP

0

0

Joppa

JOPPA STEAM

5

SUB

None

None

Cold-side ESP

3

0

Joppa

JOPPA STEAM

3

SUB

None

None

Cold-side ESP

3

0

Kincaid

KINCAID

1

SUB

SCR

None

Cold

0

0

Kincaid

KINCAID

2

SUB

SCR

None

Cold

3

0

Marion

MARION

4

BIT

SCR

Wet FGD

Cold

90%

1,478

Marion

MARION

123

BIT

CFB-SNCR

None

Fabric Filter

90%

973

Midwest

JOLIET 29

71

SUB

None

None

Cold-side ESP

3

0

Midwest

JOLIET 29

72

SUB

None

None

Cold-side ESP

J

0

Midwest

JOLIET 29

81

SUB

None

None

Cold-side ESP

3

0

Midwest

JOLIET 29

82

SUB

None

None

Cold-side ESP

3

0

Midwest

JOLIET 9

5

SUB

None

None

old-side ESP

3

0

Midwest

CRAWFORD

7

SUB

None

None

old-side ESP

3

0

Midwest

CRAWFORD

8

SUB

None

None

old-side ESP

3

0

Midwest

POWERTON

51

SUB

None

None

old-side ESP

3

0

Midwest

POWERTON

52

SUB

None

None

old-side ESP

J

0

Midwest

POWERTON

61

SUB

None

None

old-side ESP

0

0

Midwest

POWERTON

62

SUB

None

None

old-side ESP

0

0

Midwest

WAUKEGAN

17

SUB

None

None

Cold-side ESP

0

0

Midwest

WAUKEGAN

7

SUB

None

None

Hot-side ESP

3

0

TOXECON assumed

Midwest

WAUKEGAN

8

SUB

None

None

Cold-side ESP

0

0

Midwest

WILL COUNTY

1

SUB

None

None

Cold-side ESP

0

Midwest

WILL COUNTY

2

SUB

None

None

Cold-side ESP

3

0

Midwest

WILL COUNTY

3

SUB

None

None

Hot-side ESP

3

0

OXECON assumed

Midwest

'WILL COUNTY

4

SUB

None

None

Cold-side ESP

3

0

Midwest

FISK

19

SUB

None

None

Cold-side ESP

3

0

---

Question :

What revisions would be made to Dr. Staudt's cost estimates after the information

provided in the hearing?

Answer :

Response from James E. Staudt, Ph.D., CFA:

I have also prepared revised Tables 8 .7, 8.9, and 8 .10 that incorporates the

following revisions

.

•

Revisions based upon my understanding of the coal types

•

Revisions/Corrections of fly ash costs shown in the original tables in

the TSD

•

Revisions to sorbent injection rates due to revised coal types and understanding

of the configurations

•

Revisions/Corrections of sorbent costs assuming that the four Meredosia units

use the TTBE

In addition, as requested in the hearing, I have prepared a cost for additional

fly ash expense associated with operating the Baldwin units with cold-side ESP's

during 2009-2012 and some additional cost for installing the Havana fabric filter

earlier than 2012

.

As shown in the revised Table 8 .7, the costs are close to what was originally

estimated, albeit, slightly higher due to the higher cost of sorbent assumed

.

Importantly, the difference in annual costs between the IL rule and CAMR are in

the same range as originally stated in the TSD - about $36 million. Including the

additional costs described for Baldwin and Havana associated with the timing of

the fabric filters, the annualized cost differential between the IL Rule and CAMR

remains below $40 million for the years 2009-2012

.

Table 8.7 Estimated Cost for IL Utilities of Complying with IL Mercury Rule and with

2010 CAMR

7

Cost

Units

IL Rule

2010

CAMR

Capital Cost

$1000

$75,135

$33,558

Annualized Capital Cost (14% CRF)

$1000

$10,519

$4,698

Annual Sorbent Cost

$1000

$46,374

$19,838

Annual Ash Disposal Cost

$1000

$13,461

$10,041

Annualized TOXECON O&M

(excluding sorbent)

$1000

$425

$0

Total Annual Cost

$1000

$70,779

$34,577

Ounces Hg removed *

1000 ounces

124**

90

Cost per oz Hg removed *

$/ounce

$572**

$385

Cost per lb Hg removed *

$/Ib

$9,158 **

$6,161

NOTE: columns may not add due to rounding

*No credit is taking for Hg reductions from cobenefits (-28,000 oz) because these would happen regardless of IL rule or

CAMR

** This is estimated from 90% removal. As described in Revised Table 8 .9, expected removal is higher than shown here

and therefore expected cost per ounce or pound is actually lower

---

Revised Table 8.9

Owner

Plant Name

ethnology

ost,

Sorbent

OXECON

sh

sfimated

1000

ost

&M

isposal,

nnual Coal

1000/ r

1000

se (1000 tons)

Hg reduced

g Output

Hg reduced,

Hg Output

z/yr

or/yr

az/yr

oLyr

meren

2,278

253

2,278

253

me en

6,394

710

6,608

497

meren

6,254

695

6,463

486

meren

1,295

144

1,338

101

Ameren

2,618

291

2,705

204

DEDWAI2DS

$903

1,211

387

3,603

248

230

436

4,052

538

60

556

681

76

704

53

Ameren

EREDOSIA

$78~

14

4

33**

~~

31

3

32

•'

58'

6

60"

4

$78

27

7

63**

2 07

231

2,147

162

64

72

646

631

70

631

DALLMAN

obenefit

154

1,383

744

6,917

721

6,704

801

7,451

381

3,542

88

822

280

2,601

53

49

80

74

Dyneg

OODA[VER

$283

$30

$

$12

35

1,010

112

1,044

7

Dynegy

WOOD RIVER

$93

$1,06

$

1,048

3,017

335

3,117

235

oppa

OPPA STEAM

$458

$802

$

81

2,360

262

2,439

18

oppa

OPPA STEAM

$458

$802

81

2,345

261

2,423

182

8

---

9

18

Joppa

OPPA STEAM

$458

$802

$0

1

822

2,36 .

263

2 4 5

Joppa

OPPA S LAM

$458

$822

$0

$1

8 2

2.424

269

2,505

89

Joppa

OPPA STEAM

$458

$852

$0

351

875

2,5

•

280

2,603

196

195'

Joppa

OPPA STEAM

SI

$458

$852

$0

$1

86

•

2,503

278

2 586

Kincaid

INCAID

$1,650

$1,808

$1'

$e

1,824

5,252

58

5,427

408

Kincaid

KINCAID

S1

$ ,651

$216

•

$0

$1

2,122

6,111

679

6,314

75

Marion

ARION

obenefi

$1

$1

$

$1

642

1 78

164

1 78

164

Canon

ARION

obenefi

$0

$1

$

$1

42

973

08

973

108

Midwest

OLIET 29

$825

$723

$0

1

76

2,20

245

1

172

M d est

OLIET 29

$825

$8

$

$

2,703

300

2,793

211

dwest

OLIET 29

S1

$825

$90

$

$

2,758

306'

2,85

215

Mid es

OLIET 29

$825

$90

$

$

2,758

306

2,8

21,

1

Mid est

OL ET 9

S1

$900

$1,578

$

2 62

0

4,089

454

4,225

3181

id e

RA FORD

$598

$66

$0

$825

2,175

242

2,248

169

Midwest

RAWFORD

1

$895

$1,02

$

$

3,223

358

3,331

251

idwest

I-OWERTON

~~

$1,46

$0

1

1,52

.

486

4,522

Mid es

OWERTON

$1,

6

$1,371

$0

$

1

18

4,085

454

4,221

318

Mid est

0 ERTON

$1,1

$1 371

$

1418

4,085

454

4,221

318

Mid es

0

ERTON

$1,116

$1,345

$

1393

4,01

4

4

5

312

id est

AUKEGAN

$303

$398

$0

63

44

1,28

143

2

10

id es

AUKEGA

OXECON

19,68

$53

24

$

1,10

3,185

35

3 8b

35

d est

WAUKEGAN

$888

$1,20

$

$

1,21

3,504

389

3,621

73

idwest

ILLCOUNTY

~~

$257

$

~

~~

824

92

851

64

id es

ILLCOUNTY

*1

$46

$302

$

343

988

110

1,02

7

Mid es

ILL COUNTY

OXECON

$179

40

$183

$

858

2 7

275

2 47

27

Md es

ILLCOUNTY

$1 495

$1,638

$

$

1,653

4 6

529

492

3

idwest

1ISK

$935

11

$0

11

99

2,86

319

2,964

223

otal

1

1

$75,13

$46,374

$425

$13,461

53,95

15 ,65

16,851

156,27

12,230

* Over 90% overall removal has been shown, particularly on PRB fired units, at injection rates of about 3 lb/MMacf . Nearly all of the unscrubbed units in IL fire PRB coal. As a result,

lightly better than 90% removal is expected at the costs shown here .

"* Because Meredosta 1-4 are using high sulfur coal at this time and are not - as far as I know -planning to change coals, 90% removal at these small units may not be achieved.

owever, because of their small size and limited use, they have little impact on the overall mercury removal state-wide .

-"Baldwin is already reportedly achieving 80% removal of mercury. There is a good chance that with the addition of a fabric filter the Baldwin units will achieve adequate removal

ithout any sorbent. Therefore, this cost may go to zero

.

**** For 2009-2012 Baldwin and Havana will likely have additional costs since the fabric filters will not be installed prior to 2009 . Fabric filters at Baldwin, Havana and Vermillion

lore installed due to Consent Decree, as is Sl at Vermillion . Capital cost offabric filters is not attributed to IL rule, but sorbent injection is in the case of Baldwin and Havana .

---

10

AC

I, t1 K auIc V,1 V

Plant Name

apathy

w

ethnology

ost, $1000

OXECON

&M

sh

isposal,

1000

stima

s

all Coal Us

1000 tons

reduced

8

u pu

EDEDWARDS ~~

$34

$~-

1,007

432

D EDWARDS

281

1

$

90

2,03

873

Ameren

EDEDWARDS

361

~~

1,211

2,712

1 62

•

OFFEEN

~

$

$

968

w

OFFEEN

61

~~

1,702

3,05

30

•

HUTSONVILLE

UL

90

$

13

233

m

,

E

0

1

I

t

EREDOSIA

31

C

1

61

MEREDOSIA

31

C

1

$

Ameren

EREDOSIA

31

C

38

C

122

EREDOSIA

721

1,61

692

~aALLMAN

87.5

obenefit

C

281

64

72

CWLP

IIALLMAN

8

obenefit

C

I

$$

$0

274

631

1

IIALLMAN

207

obenefit

C

I

$

1

60

1,383

C

Dynegy

ENNEPIN !I

$

$625

61

265

Dynegy

HENNEPIN

231,

$

874

1,95

Dynegy

ERMILION**

OXECON

C

$

1

20

53

Dynegy

ERMILION**

10

OXECON

C

$

1

311-1

Dynegy

DOD RIVER

113s~

$

II

351

~~

Dynegy

OOD RIVER

~I

C

$

$

1,048

•

1 00

oppa

OPPA STEAM

183.

$

IC

787

Joppa

PPA STEAM

18

I

$458

$334

$1

814

1,82'

78

1

oppa

OPPA STEAM

183

1

$458

$334

I

$2,'11

822

1,8 0

789

oppa

OPPA STEAM

183

1

$45

$342

$I

I

842

1,885

808

oppa

OPPA STEAM

183

$

$1

$1

I

875

1

2,799

oppa

OPPA STEAM

183

$

1

I

I

86'

1

2,781

---

11

IKincaid

KINCAID

661

$1,651

$753

1

$

1824

4,085

1,75

incatd

INCAID

66 SI

$1,65

$904

1

2,122

4,753

2037

anon

MARION

2

obenefit

$

$0

$

1

642

1,478

16

Marion

ARION

obenefit

$

$

$

$0

422

973

108

Midwest

OLIET 29 ~C

$825

$301

$

76

2,20

245

Midwest

OLIET 29

I i

$825

$36

$

1

93

2,703

30

idwest

OLIET 29

$825

$377

$

$

958

2,758

30

idwest

JOLIET 29

--

1

$377

$

1

958

2,758

30

idwest

OLIET 9

36111

[

$657

$

$2,625

1,42

4,08

Midwest

RAWFORD

'

I

$598

$278

$

$825

755

2,175®

idwest

RAWFORD ~~

$895

$425

$5a

3,223

Midwest

IOWERTON

446.5Ct

$1,11

$611

$

2

1,52~-M

idwest

POWERTON

446.5~~

$571

$

$0

1,418

4,085

idwest

POWERTON

446.L

$1,11

$571

$

1,418

4,085

idwest

IOWERTON

446.5

$1,11

$561

$

$0

1,393

4,012

idwest

121

$

0

$

SI

E

1 427

idwest~~

$

$5

1,10

idwest

355

$

I

$

5

1,217

3 89

Midwest

ILL COUNTY

5C~

$47

$107

$

$191

* 1

9

Midwest

ILL COUNTY

~~

$46

$

$0

343

988

idwest

FISK ~~

$9357

S

11

99

2,86

o al

$3355

$19,83

$1

$ 0,04

53,85

17 79

50,27

*Baldwin is already reportedly achieving 80% removal of mercury . There is a good chance that with the addition of a fabric filter the Baldwin units will

rchieve adequate removal without any sorbent. Therefore, this cost may go to zero .

* For 2009-2012 Baldwin and Havana will likely have additional costs since the fabric filters will not be installed prior to 2009

. Fabric filters at

ialdwin, Havana and Vermillion are installed due to Consent Decree, as is Slat Vermillion. Capital cost offabric filters is not attributed to IL rule, but

orbent injection is in the case of Baldwin and Havana .

---

Baldwin and Havana

During the hearing it was pointed out that the costs of fly ash disposal would be

higher than what was shown for the Baldwin plant due to the installation of a fabric

filter after the 2009 start date for the IL rule . As a result, this plant would not fully

realize the benefits of a TOXECON system until the fabric filters were installed

.

For Baldwin, the costs associated with additional ash disposal costs (in $1000's)

for each year can be estimated. The table below shows estimated costs assuming that

the differential costs are $25/ton for ash that was sold and must be disposed of as a

result of sorbent injection . However, according to Table 8 .8 of the TSD, which

shows that Baldwin is able to dispose of fly ash in ash ponds at little or no cost, the

$25/ton cost for disposal of ash used is probably very high . The actual cost is likely a

small fraction of what is estimated at $25/ton, and is likely to be closer to what is

shown for the estimated costs using only the lost revenue from Table 8 .8. Since this

estimate assumes that the fabric filters are installed on the last day of the year, and

they are likely to be installed prior to that, these costs are the highest that they can be

.

Therefore, I expect that these estimates of ash disposal cost for these years are very

high. After 2012, these costs would not apply since the TOXECON systems would

be installed. For these years, sorbent costs would also be higher since they would be

injecting upstream of an ESP instead of a fabric filter . And, the additional cost of

sorbent over what is shown in revised Table 8 .9 is shown below .

The Havana unit would have to install their fabric filter early since the proposed

rule does not provide a TTBE for units with a hot-side ESP. As a result, they would

incur an additional cost associated with early installation . This would be equal to a

cost of capital times the installed cost . At 488 MW, if the cost of the fabric filter is

$60/kw, the cost of a fabric filter would be about $29 million . At a 5.69% annual

yield (current 5 year AAA corporate yield, per Bloomberg on 7/12/06), this is an

annual cost of $1 .66 million for the years 2009-2012 (actually, $0 .83 million in 2009

since it's half a year). Although Dynegy probably uses a higher cost of capital than

AAA bond yields when it builds a power plant or buys one, it is customary for

corporations to match the cost of capital to the risk of a project. In this case Dynegy

would simply be performing an environmental project a few years earlier, which does

not bear nearly the same risk as a project that has far more business risk . Moreover,

the cost of capital effects would actually be mitigated by the effects of escalation of

labor and material. In fact, there would be a net financial benefit to performing the

project earlier if material and labor escalation is at a higher rate than the cost of

capital .

12

Estimated fly ash cos s

2009 (half year)

2010

2011

2012

at $25/ton, $1000

1,263

2,525

1,680

840

at cost of lost fly ash revenue from Table 8.8, $1000

6

11

7

4

Estimated additional sorbent costs

at $0.90/lb, $1,000

205

410

273

137

---

Further Amendment/Clarification to Hearing testimony from James E . Staudt,

Ph.D., CFA :

During the hearing I was questioned on my contribution to an article

published in Environmental Science and Technology titled "Control of Mercury

Emissions from Coal-Fired Electric Utility Boilers" coauthored with Ravi

Srivastava, Nick Hutson, Blair Martin and Frank Princiotta of US EPA . At the

time of the hearing I did not properly recall when I contributed to this article

.

Since the hearing, I have had the opportunity to check the timing of my work on

this. This article originates from work I performed for US EPA in late 2004 . US

EPA used this work in its White Paper entitled "Control of Mercury Emissions

from Coal Fired Electric Utility Boilers : An Update" issued on February 18,

2005 by US EPA's Office of Research and Development that is referenced in the

TSD. The material in this White Paper as well as work by others at US EPA was

subsequently used to form a basis of the Environmental Science and Technology

journal article that was entered into evidence . That the article took until spring of

2006 to get published probably reflects the slow process of integrating other

peoples work, the slow process of getting an article published in a prestigious

journal and the slow process of getting such an article through US EPA

administrative review on such a sensitive issue as mercury. For this reason, I

believe that the article does not accurately reflect the current state of technology,

which has advanced rapidly in the time since 2004 when I originally did the work

for US EPA .

To be clear, my work with US EPA is specifically limited to technology and

cost studies. Any conclusions of a policy nature in the White Paper or in the

journal article, such as regarding the timing of availability of technology for

complying with regulations, better reflect the official policy position of the US

EPA than my opinion. The section of the journal article "Outlook for technology

availability" clearly states that the opinions expressed regarding technology

availability are those of US EPA . These statements in the article that I coauthored

are correct statements because they are, in fact, US EPA's official policy position .

Whether I agree or disagree with US EPA's policy position is another matter. It

is my opinion that the US EPA positions in the Environmental Science and

Technology article regarding technology availability should not be taken to mean

that technology is not yet available for the applications we are discussing in

Illinois, although technology may or may not currently be available for other

applications. It is my opinion that the technology is available as described in the

TSD and as I have described in my other testimony .

Question

:

What is the average daily flow from all NPDES permits?

Answer :

Based on our information, the average daily flow from all NPDES permittees is

21,140 million gallons per day. This includes cooling water flows from power

plants (they intake river water, run it past hot equipment and then discharge it

back to the river) which are very voluminous

.

13

---

ADDITIONAL DOCUMENTS REQUESTED DURING THE JUNE12, 2006 HEARING

Attachment 1

:

Scope of Work Proportion from ICF Contract

Attachment 2

:

Scope of Work Proportion from Richard Ayres' Contract

Attachment 3

:

Scope of Work Proportion from Gerald Keeler's Contract

Attachment 4

:

Control Configuration Inspections at Illinois Coal-Fired Power Plants -

2006 (provided to the Board as complete copies and redacted copies for

the public record)

Attachment 5

:

Illinois Environmental Protection Agency comments to the U . S .

Environmental Protection Agency regarding Proposed National Emission

Standards for Hazardous Air Pollutants ; and in the Alternative, Proposed

Standards of Performance for New and Existing Stationary Sources

:

Electric Utility Steam Generating Untis, Proposed Rule; Propose Rule (69

Federal Register 4652, January 30, 2004) ("Proposal") and Supplemental

Notice for the Proposal (69 Federal Register 2397, March 16, 2004)

Attachment 6

:

IPM modeling data (Compact Disk, provided only to Board and Counsel

for: Ameren, Dynegy, Midwest Generation, Kincaid, Chicago Legal

Clinic, and Environmental Law and Policy Center)

Attachment 7 :

"Blood and Hair Mercury Levels in Young Children and Women of

Childbearing Age --- United States 1999"

Attachment 8

:

Dated: July 28, 2006

Illinois Environmental Protection Agency

1021 North Grand Avenue East

P.O. Box 19276

Springfield, Illinois 62794-9276

Prairie State comments to the Illinois Environmental Protection Agency

on the Temporary Technology Based Extension - Beginning with email

from Dianna Tickner to Laurel Kroack

Respectfully submitted,

0Ae

~ 110

B ,

E. Matoesi

Assistant Counsel

Division of Legal Counsel

14

---

STATE OF ILLINOIS

)

COUNTY OF SANGAMON

)

SS

CERTIFICATE OF SERVICE

I, the undersigned, an attorney, state that I have served the attached POST-HEARING

COMMENTS OF THE ILLINOIS ENVIRONMENTAL PROTECTION AGENCY upon the

person to whom it is directed, by placing a copy in an envelope addressed to :

Dorothy Gunn, Clerk

Illinois Pollution Control Board

James R. Thompson Center

100 West Randolph St., Suite 11-500

Chicago, IL 60601-3218

(Overnight Mail)

SEE ATTACHED SERVICE LIST

(First Class Mail)

and mailing it Springfield, Illinois, with sufficient postage affixed, as indicated above

.

DATED: July 28, 2006

Illinois Environmental Protection Agency

1021 North Grand Avenue East

P.O. Box 19276

Springfield, Illinois 62794-9276

ILLINOIS ENVIRONMENTAL

PROTECTION AGENCY

Byx~

Charles E atoesian

Assistant Counsel

Division of Legal Counsel

---

Marie Tipsord

Hearing Officer

Illinois Pollution Control Board

James R. Thompson Center

100 West Randolph St., Suite 11-500

Chicago, IL 60601-3218

Bill S. Forcade

Katherine M . Rahill

Jenner & Block LLP

One IBM Plaza

Chicago, IL 60611

S. David Farris

Environmental, Health and Safety

Manager

Office of Public Utilities

City of Springfield

201 East Lake Shore Drive

Springfield, IL 62757

Keith I. Harley

Chicago Legal Clinic

205 West Monroe Street, 4th Floor

Chicago, IL 60606

Katherine D. Hodge

N. LaDonna Driver

Hodge Dwyer Zeman

3150 Roland Avenue

Post Office Box 5776

Springfield, IL 62705-5776

Bruce Nilles

Attorney

Sierra Club

122 W. Washington Ave., Suite 830

Madison, WI 53703

Dianna Tickner

Prairie State Generating Company, LLC

701 Market Street

Suite 781

St. Louis, MO 63101

SERVICE LIST 06-25

James T. Harrington

David L. Rieser

Jeremy R. Hojnicki

McGuire Woods LLP

77 West Wacker, Suite 4100

Chicago, IL 60601

William A. Murray

Special Assistant Corporation Counsel

Office of Public Utilities

800 East Monroe

Springfield, IL 62757

Faith E. Bugel

Howard A. Lemer

Meleah Geertsma

Environmental Law and Policy Center

35 East Wacker Drive

Suite 1300

Chicago, IL 60601

Christopher W. Newcomb

Karaganis, White & Magel, Ltd .

414 North Orleans Street

Suite 810

Chicago, IL 60610

Kathleen C . Bassi

Sheldon A. Zabel

Stephen J. Bonebrake

Joshua R. More

Glenna L . Gilbert

Schiff Hardin LLP

6600 Sears Tower

233 South Wacker Drive

Chicago, IL 60606

James W. Ingram

Senior Corporate Counsel

Dynegy Midwest Generation, Inc.

1000 Louisiana, Suite 5800

Houston, TX 77002

---

Mike Koerber

Executive Director

Lake Michigan Air Directors Consortium/

Midwest Regional Planning Organization

2250 East Devon Avenue, Suite 250

Des Plaines, Illinois 60018

Jim Ross

Division of Air Pollution Control, Bureau of Air

Illinois EPA

P.0. Box 19276,

1021 N. Grand Ave ., East,

Springfield, IL 62794-9276

Re: Request for Proposal: Illinois EPA Modeling of Mercury Rule

Dear Mike and Jim

:

ICF is pleased to provide the Lake Michigan Air Directors Consortium (LADCO) with the attached

proposal for providing additional modeling and other work in support of the Illinois Mercury Rule

. The

scope

of

work outlined here is based on the Illinois EPA's (IEPA) scope outlined in a memo dated

1/26/06 and a conversation between ICF and Illinois EPA on February 1, 2006 .

Task I Modify NEEDS and 3 IPM runs and Supporting Parsings

Illinois EPA would like to make additional modifications to the VISTAS/LADCO case in order to

incorporate new information on specific unit characterizations . IEPA has already forwarded those

changes to ICF for review . ICF will discuss any issues related to the date with IEPA and incorporate the

changes as appropriate. In addition, IEPA would like to incorporate new mercury control technology data

.

Once this new information is incorporated, Illinois EPA requires three new IPM runs

:

•

A. Abase case run based on the modified VISTAS/LADCO case without CAIR or CAMR in

place, but including Title IV and NOx SIP Call requirements

.

•

B. A Base Case Run with CAIR and CAMR in place

.

•

C. A Policy run with the CAIR in place, the Illinois Mercury Rule (specified in your email of

February 1) for Illinois plants, and CAMR for non-Illinois plants

.

We will provide you with run specs for your review and approval before implementing these runs . Full

implementation, QA/QC for the first

of

these runs could be completed by February 27. We would expect

to complete the third run By March 3 . Summary data will be developed to report on the impacts of the

CAIR mercury rule in isolation (Run C vs . Run A) as well as the incremental impacts

of

the Illinois rule

(Run C vs. R run B). The total impacts

of

the Illinois Rule would be a cost comparison of Run C vs . Run

A

.

This proposal contains Confidential Business Information that shall not be disclosed and shall not be duplicated, used or disclosed

-- in whole or

in part

-- for any purpose other than to evaluate this proposal

ICF

CONSULTING

February 17, 2006

---

M. Koerher/J. Ross

February 17, 2006

Page 2 of 4

Task 2: Parsing of Runs Expanded IPM Run Data and Other Cost Information for LADCO

(Item 1-4)

In support of its work, LADCO would like some additional information on cost and other impacts. We

have budgeted for three runs, three years each (9 parsings) . These will be completed by March 8

Key information to be provided in addition to the parsed results would be the impacts on costs per kWh of

the Illinois rule. We will provide information on the change in average production cost per kWh for

Illinois due to the rule as well as the change in the marginal cost of production (i .e ., the IPM wholesale

energy price). Impacts of coal plants (retirements and retrofits) and emissions data will also be provided

We will also provide impacts on costs from the Illinois Rule vs. the CAMR Rule (Run C vs. Run B) in

terms of average and marginal cost per kWh. The other indicators -- $/month to the different consuming

sectors will require some discussion with IEPA. As we have indicated, IPM provides forecast at the

wholesale level, and therefore forecast wholesale marginal power prices

. In order to estimate retail price

impacts we could (1) apply the tool that EPA uses to produce these estimates at the regional (the MANO

region) average level for all sectors, or (2) implement a simpler approach to get at retail sectors . Option I

could be implemented for this work, but the result will not have any sectoral detail, and will be based on

the current EPA tool. There is insufficient time to update this tool to more recent data

(i .e ., AEO 2006) .

Option 2 will require some estimate of the total expenditures at the average household or establishment

level, and an estimate of the relationship between changes in wholesale prices and retail rates

(e.g.,

wholesale prices represent x percent of retail ; or all marginal prices will be added to a base forecast) .

Other questions related to impacts on health benefits, jobs, pollution control industry, and the economy at

large is something we could potentially assist you with, but not within the timeframe that you require

.

Therefore, we have not included this in the current scope

.

Task 3. Reduced Permits for RENEE Set Aside

This run is a simple reduction in the available NOx allowances under the CAIR rule for Illinois units . This

run would be done off of the existing VISTAS/LADCO CAIR/CAMR run (LADCO IL _BC_02e) with

revised CAIR annual and summer NOx caps and the NOx allowance supplementary pool . The NOx caps

and the NOx allowance supplementary pool will he adjusted to reflect a retirement of 30% of the IL NOx

budget. As we understand, this run would not need to be parsed and state level outputs will be provided

.

This run would be completed by February 24

.

Task 4 Reporting

You have asked for an executive level summary that highlights and explains the summary results in

addition to a more lengthy report . We envision a report with an executive summary of 3-5 pages

addressing key issues such as the cost of the mercury rule (with CAIR/CAMR for the rest of the nation)

vs. the CAIR/CAMR, the implications of the rule for key system indicators identified

(e.g ., retirements,

generation, rates, coal consumption) with a focus on Illinois results . The focus would be on the difference

between the Illinois rule vs. the CAIR/CAMR. The goal would be to hit the highlights of the findings

.

The remainder of the report would provide more in depth results . We would expect this to be a 20 to 30-

page report that goes into more depth into the modeling platform, the inputs, outputs, and results, with the

focus on explaining the impacts of the Illinois rule . The expected audience would be someone u

this proposal contains Confidential Business Information that shall not be disclosed and shall not he duplicated, used or disclosed

-- in whole or

in pan-- for any purpose other than to evaluate this proposal

---

M. Koerber/.J. Ross

February 17, 2006

Page 3 of 4

unfamiliar with the modeling and therefore, the need for more detailed discussion of findings and

explanation of the results . We would develop a draft report by March 8 . W e would feed you preliminary

background material as we develop it so you have some time to absorb and process it . However, the first

full draft of a report you would see would be March 8h. I have not budgeted for revisions beyond that

first draft .

This proposal contains Confidential Business Information that shall not be disclosed and shall not be duplicated, used or disclosed - in whole or

in part .- for any purpose other than to evaluate this proposal

---

M. Koerber/J. Ross

February 17, 2006

Page 4 of 4

Next Steps

Please call if you have questions . If you would like to proceed, you may sign the attached form in

duplicate and return it to my attention. We look forward to working with the LADCO and Illinois EPA on

this project .

Sincerely,

Juanita M. Haydel

Senior Vice President

I hereby authorize ICF Consulting to proceed according to the scope of work described above.

Accepted (including Attachments A and B) for

Accepted for

Lake Michigan Air Directors Consortium

ICF Resources, LLC

Signature :

Signature

Printed Name

:

Printed Name:

Title:

Title :

Date :

Date:

This proposal contains Confidential Business Information that shall not be disclosed and shall not be duplicated, used or disclosed --in whole or

in part-. for any purpose other than to evaluate this proposal

---

IN

low SIN"

I mn ummuto PIMI,

0 VIC'N

A-,rc

-miq,,

11c ,

Mmml,

FPA, Rwow,-l Air 1t

v himi Wanc pows immlAwc mo .

I

ioi;'mh~ Wleil

IIIIIS

lmd the

( b~ ;i Revn,~F

tntaiioi Mctmraltduni set Gnat tb

o!

aw,

",

:IS

no

WK of 9, "Mmi WQMC pmd 'w

lNkwvd pfv~rrim,'6tal lrakk

tote, Ayle, .%,U lx-p Rm appi

do IM,,,

,

;s chat, with

a, Av, hdkd v- i Al X 1) Age; m

I

'moll

r

,l

tfiali"lo

m all POW1 Wiv edam[

it raf%n+. .cl& ;, of if"-akN fox, Ihr mcnAtc

;a da

ac, of 1 Af Wk) Mr On Mims

Irm

may u.

pn' ule acmeo! to .M )(,

-0 a-nd 9' quml1wr Santa

---

---

';dr

swleil

W aw,%l lfw llbul;8 ta

shed in 6e ulxwnvar(%

ts

Dwc,4~q~

Cmywo

Cllbuois LPA')

t

Smamul-sSmkm

tuallmi

Ofthe

wovpc orwoex in axpaukW, such atfidi(joiofl

wcit1k,

will no-? he govri'm

by tht, tours and cbfldkion 1100 Agman"a unless mutwilly agreed othienvise

PXCCar!

u provided

nk

SCO)ftll riot IbisAgrrvrncw, Ayrnq'kevim wild be de med

w

Ow limn

thus

A" hats mulzrud its,

in cur angaganimt kster

of *th

stub ad

xrovid

ii

t

Im

Arcs wx}srttkv; to

xtiol:1 with the

dl

bo

LADCO nn l it

INJA~YY~01

.

---

February 16, 2006

Gerald Keeler, Ph .D

.

Professor, Environmental Health Sciences

Professor, Atmospheric, Oceanic and Space Sciences

University of Michigan

1530 SPH I

109 South Observatory

Ann Arbor, Michigan 48109-2029

Dear Gerald

:

On behalf of the Lake Michigan Air Directors Consortium (LADCO), I wish to award you

a contract to provide technical support for the State of Illinois

in developing a rule for

controlling mercury emissions from power plants

.

Specific support shall include the

following activities, as directed by the State of Illinois (or LADCO) :

•

preparation and review of technical documents

;

•

participation in stakeholder meetings, as needed ;

•

testimony at hearings

;

•

technical assistance to key staff; and

•

other technical support agreed to by you and Illinois (or LADCO) .

---

Control Configuration Inspections at Illinois Coal-Fired Power Plants

- 2006

---

TABLE OF CONTENTS

#1 - Midwest Generation (Fisk)

1

#2-Midwest Generation (Crawford)

4

Addendum

6

#3 - Midwest Generation (Waukegan)

24

#4 - Midwest Generation (Powerton)

27

#5 - Midwest Generation (Will County)

32

#6 - Midwest Generation (Joliet)

37

#7 - Ameren Energy Generating (Hutsonville)

40

#8 - Ameren Energy Generating (Newton)

42

#9 - Ameren Energy Generating (Coffeen)

44

#10 - Ameren Energy Generating (Meredosia)

47

#11 - Ameren Energy Resources (Duck Creek)

51

#12 -Ameren Energy Resources (Edwards)

53

#13 - Dynegy Midwest Generation (Wood River)

57

#14 - Dynegy Midwest Generation (Havana)

59

#15 - Dynegy Midwest Generation (Hennepin)

62

#16 - Dynegy Midwest Generation (Vermilion)

66

#17 - Dynegy Midwest Generation (Baldwin)

70

#18 - Kincaid Generation (Kincaid)

72

#19 -Electric Energy (Joppa)

75

#20 - City of Springfield (CWI,P)

81

#21 - Southern Illinois Power (Marion)

85

---

2

.

so

3

injection

A pilot SO3 injection project was undertaken in autumn

2004

and abandoned in spring of

2005

.

Midwest Generation official claimed it had no quantifiable results . Another said it

had "mixed results .

.. but they didn't see an impact ." The goal of the project was to reduce

the resistivity of PRB coal . The pipes and headers were abandoned in place. These are

located at the

7"'

floor at approximately the 116-foot elevation . Gaseous SO3 was injected at

the economizer. The S03 generation process was located at ground level

.

Fisk also constructed a polymer injection system, which introduced liquid polymer into the

ducts after the preheater and upstream of the ESP . The polymer injection system included a

header pipe and four spray nozzles installed per duct (16 altogether.) The polymer was

supposed to combine with and agglomerate particles in the flue gas to facilitate collection by

the ESP. This was done in the time period around

2000 .

The project was discontinued as the

injections accumulated in the ducts producing a series of "stalagmites ." The header system

and injection ports are still in place

.

2

.

Flue gas conditioning

No direct flue gas conditioning s performed. Sodium carbonate, anhydrous is added to the

coal at the mine to achieve

3.25-3 .75

wt%. The sodium is added to decrease resistivity of the

fly ash. Wt % sodium is provided in the quarterly coal analysis reports

.

Other Information

Fisk Unit 19 is a

3,379

mmBtu/hr electric generating unit consisting of two boilers, a

superheater boiler (or "furnace") and a reheat boiler (furnace) . This arrangement is known as

a "dual furnace." They are basically identical except for the arrangement of tubes in the

fireboxes. Each furnace cannot be run separately

.

Low sulfur Powder River Basin coal is utilized to achieve sulfur dioxide limits . Unit 19

utilizes low NO, burners and overfire air for NO, control

.

The ESPs are considered "cold side" since they are located after the preheaters

.

2

---

This is a view of the west ESP at Fisk with breeching exiting the ESP and entering the stack. (In

the background is the bottom of the Sears tower.) The air preheaters are inside the large building

to the right. The preheaters are about 4 feet from the wall at about the same elevation as the

ESP. The section of dark transition before the silver ESP pictured and the building is about 25

feet long. It probably houses perforated plates which distribute air into the ESP in a laminar type

flow. Total distance of ductwork from exit of preheater to ESP is about 29-35 feet

.

3

---

2

.

S0 3 inecttQn

The facility does not use S03 injection

.

3

.

Flue gas conditioning

No direct flue gas conditioning is performed . Sodium carbonate, anhydrous is added to the coal

at the mine to achieve 3 .25-3.75 wt%. The sodium is added to decrease resistivity of the fly ash

.

Wt % sodium is provided in the quarterly coal analysis reports

.

4

.

Other Information

Crawford Unit 7 is a 216 MW electric generating unit consisting of two boilers, a superheater

boiler (or "furnace") and a reheat boiler (furnace) . This arrangement is known as a "dual

furnace." They are basically identical except for the arrangement of tubes in the fire box . Each

furnace cannot be run separately . The superheater furnace supplies high pressure steam to the

high pressure turbine, the steam is then routed to the reheat furnace . The turbine on the reheat

furnace operates at a lower pressure and utilizes a condenser to extract remaining energy from

the steam

.

Low sulfur Powder River Basin coal is utilized to achieve sulfur dioxide limits . Unit 7 utilizes

low NO, burners and overfire air for NO, control

.

The ESPs are considered "cold side" since they are located after the preheaters

.

ESP collection area is given in what is called "specific collection area," the units of which are

ft2/acfm. The design flow rate (acfm) was not given . The specific collection areas (for units 7

and 8) were taken from stack test reports . Originally the SCA was given as 118 .3 and it was

suggested by Midwest Generation that to get the individual SCA per ESP to divide the number

by two

.

A further note about the ducts : There did not appear to be any obvious large open areas near the

superheater duct. At low elevations, there is a considerable amount of electrical equipment to

the west. At slightly higher elevations, a number of prominent vessels for the feedwater system

are placed close to the duct . Then the wall of the building runs adjacent to the duct on the west

side of it. On the east side, there is not much room between the down coming duct (hot gas to

the air preheater) and the outgoing duct . At one elevation, there did appear to be a large "patch"

placed into the side, approximately 25 feet by 6 foot tall section may have been welded into

place (see photo.) There is also a steel beam truss section which could support a pad at this

approximate 77-foot elevation. We did not see any convenient places in which large equipment

(baghouses/ storage silos) could be easily placed. The reheat furnace duct had an adjacent

approximately 400 sq foot area open to the East and some windows were within 20 feet east

.

5

---

Date :

May 16, 2005

To

: Ed Bakowski

From: Joe Kotas

RE :

Mercury VIP

SCA CORRECTION

Source

:

I .D

.

#

:

Address

:

Contact/Title

Phone/Fax

:

Inspector(s)

:

ADDENDUM

Midwest Generation,

LLC ;

Crawford Generating Station

031600

AIN

3501

S

.

Pulaski Road ;

Chicago,

IL

60623-4987

Luke

Ford/EH&S

Specialist, John

Kennedy/Station

Director

;

David

Gladem/Production Manager

773-650-5489

Ice Kotas

and Emilio Salis

Following an inquiry,

further information was gathered concerning

the

specific collection area

("SCA")

of the ESPs

at Crawford Unit 7 . The SCA for

Crawford unit 7 was originally given as 59 .15 in the report dated 05/06/06

.

The correct SCA (as provided by contacts at Midwest Generation) for Crawford

Unit #7 is 118 .3 ft'/kacfm . Please adjust your records accordingly

.

6

---

The facility does not use S03 injection

.

3

.

Flue gas conditioning

No direct flue gas conditioning is performed . Sodium is added at the mine as stated above (which

is true for all Midwest Generation plants in the Chicago area .)

4 .

Other Information

Crawford Unit 8 is a nominal 326 MW electrical generating unit consisting of a dual furnace

arrangement connected to a single stack .

Low Sulfur Powder River Basin coal is utilized to achieve sulfur dioxide limits . Unit 8 utilizes

low NO, burners and overfire air for NO, control

.

The ESPs are considered "cold side" since they are located after the preheaters

.

The preheaters are of a "Ljungstrom" design. They consist of cylindrical metal drums with fins

.

The axis of rotation is between the inlet (cold) and outlet (hot) air streams. The unit rotates to

allow the preheated fins to come in contact with the incoming combustion air . The temperature

of the flue gas is 600-700 degrees F entering the preheater and 300 degrees F out

.

Attachments

a .

Photos. (Midwest Generation Crawford Generating Station photos)

b .

Side view schematic Crawford 7. (Crawford block)

8

---

\]iJwt~4(imn(,ojoo(`r./«!^)!(~(0cr2\~!l~~t~(ioA

iH!h0()/\~~~

OAT JAW,

YhoN~kv

AV

OfCnawford

powti

,

p

Ian( looking south,

Unit 7 h~ mc, elect

I

prC60iaiclf

(~S'Y\)nVth(I 00f a' V1 an onne and white SUQCd stack The bI(&umek }siUU&'

0

---

2

.

S03 injection

The facility does not use S03 injection in any of the boilers

.

3

.

Flue gas conditioning

No flue gas conditioning is utilized

.

4 .

Other Information

This facility is an electric-powered generating station with two units, 5 and 6, each consisting of

two crushed coal-fired boilers controlled by ESP units and a turbine-driven generator . Unit 5

covers boilers number 51 and 52 and Unit 6 covers boilers number 61 and 62. The ductworks for

all these boilers are identical. Each boiler has a nominal capacity of 4116 mmBtulhr each and are

served by a single shared stack . NOx emissions are controlled by low-NOx overfire air systems

and the PM emissions are controlled by ESP. Generators for units 5 and 6 are permitted for 851

MW and 846 MW, respectively.

Coal is received by rail into a car dumper and coal crushers and then moved by conveyor to the

stockpile or surge bins . From the surge bins, coal is fed by a conveyor to the conditioners and

then to the silos. All sources, including the fly ash bins; with uncontrolled emission rates greater

than the allowable rate are controlled by bag houses . The coal silo for unit 5 also has a wet dust

extractor system and there are dry logger systems on the traveling tripper car and at some tripper

room transfer points . Other sources are an auxiliary oil-fired boiler for facility heating and start-

up steam for units 5 and 6, several insignificant storage tanks, a gasoline dispensing station, coal

storage pile, and roadways

.

Emissions Unit Information

In addition, the facility supplied flow diagram of the boilers operation

.

31

Emission

Unit

Description

Emission Control

Equipment

Unit 5

Boiler BLR 51

Babcock and Wilcox Dual Cyclone fired

Nominal 4116 nunBtulhr (1973)

Low

NOx, Overfire Au and

ESP

Unit 5

Boiler BLR 52

Babcock and Wilcox Dual Cyclone fired

Nominal 4116 mmBtulhr (1973)

Low NOx, Overfire Air and

ESP

Unit 6

Boiler BLR 61

Babcock and Wilcox Dual Cyclone fired

Nominal 4116 nunBtulhr (1976)

Low NOx, Overfre Air and

ESP

Unit 6

Boiler BLR 62

Babcock and Wilcox Dual Cyclone fired

Nominal 4116 mmBtulhr (1976)

Low

NOx, Overfire Air and

ESP

---

3

.

Flue gas eonditionini

No other flue gas conditioning is utilized

.

4

.

Other Information

Low sulfur coal is utilized . All boilers incorporate low NOx technology and over-fired air

.

35

---

2 .

An SO, flue gas conditioning system has been installed on Units I and 2

A 3,000 molten

sulfur tank supplies sulfur that is used to make S0 2 for both units . The SO, is forced into SO,

and put into the flue gas . With a letter dated August 2, 2001, Steve Whitworth notified the

Agency that the flue gas conditioning system for Unit 1 was placed into service on July

16,

2001 and released to operations on July 17, 2001 The flue gas conditioning system for Unit 2

was placed in service on July 10, 2001 and released to operations on July 13, 2001

.

During

the inspection, both units were operating and the S0

3 injection rate for Units 1 and 2 was 9ppm

and 10ppm, respectively. The facility burns Powder River Basin coal and East Hornsby Coal

.

The SO, injection system is used for both

.

3

.

No other flue gas conditioning is performed

.

4

.

The coal-fired boilers are designated as Unit 1 (CB-1) and Unit 2 (CB-2) . They have a steam

production capacity of 2.5 million pounds per hour and 4 .159 million pounds per hour,

respectively. Both are Babcox and Wilcox subcritical cyclone-fired units

.

Unit #1 and Unit #2

have overfire air systems for reducing NOx emissions. According to an email from the facility

dated May 16, 2002, "full utilization of the overfire air systems on Unit #1 and Unit #2 was not

realized until late in 2001 and early 2002"

The overfire air systems did not have full capability

until the fine grind crushers were installed. The overfire air systems operate all year

.

The facility installed selective catalytic reduction (SCR) systems on both units

. The

manufacturer will not guarantee the catalyst in the SCR during ozone season while burning

low

sulfur coal. The SCR mixes ammonia with the exhaust gas

.

It is located before the precipitator

on the hot side. There are two 50,000 gallon anhydrous ammonia tanks for supplying the SCR

units. The SCR system operates May through September

.

It needs to operate at about 800

degrees Fahrenheit for optimum performance The SCR on Unit #2 initially started up on April

9, 2002. The SCR on Unit #1 was in service May 1, 2003 .

46

---

2 .

The facility performs SO, injection on Boiler #5 . Boiler #5 (unit 3) is a 220 MW coal-fired

boiler equipped with a low NOx burner system . It has an electrostatic precipitator and a

sulfur dioxide monitor . The boiler is burning Powder River Basin coal which contains low

sulfur. A flue gas conditioning system was installed on boiler #5

.

It was needed for

burning the low sulfur coal . The flue gas conditioning system burns molten sulfur

making S02 .

The system oxidizes the SO2 into SO3

. The S0 3 is put into the flue gas

which lowers the resistivity of the fly ash making it easier for the precipitator to collect

.

The system was place in service on March 22, 2003 and was operating reliably April 14,

2003. During the inspection, SO, was being injected at a rate of 7 .98 ppm

. The system

has the capability of injecting SO 3 at a rate of 6 to 14 ppm .

3. Flue gas conditioning is also performed on Boiler #4 . A non-sulfur liquid conditioning

agent called Arkay is used. The facility was issued a construction permit (#06010047)

on February 16, 2006 to do a "pilot evaluation of an alternative flue gas conditioning

agent" on Boilers #1-5 . The facility has immediate plans to install the Arkay flue gas

conditioning systems on Boilers #1-3 after receiving the construction permits

. They plan

to make the Arkay system on Boiler #4 a permanent system and no longer a "pilot

evaluation"

.

4. The Meredosia power station has a total of six boilers divided into four units

. There are

two coal-fired boilers (#1 and #2) with a generating capacity of 32 MW each

. There are

also two coal-fired boilers (#3 and #4) with a generating capacity of 30 MW each

. The

boilers #1-#4 have a common stack . The units are equipped with S02, NOx, and

opacity monitors. Boiler #5 (unit 3) is a 220 MW coal-fired boiler

equipped with a low NOx

horner system. It has an electrostatic precpitatoi Boiler #5 has a separate stack

.

50

---

This facility is an electric generating station with one boiler, a pulverized coal, wall fired

boiler rated at 3,713 million BTU per hour or about 400 MW

.

For NOx control there are low NOx burners on the boiler and a SCR system with

ammonia injection. Particulates are controlled by two parallel, cold side, ESP's with flue

gas conditioning by means of SO3 injection. Sulfur dioxides are controlled by a

limestone wet scrubber system

.

The S03 injection system was just started up in March 2006. The proper permits were

obtained. The coal presently being used can be described as a medium sulfur content

coal of up to 2%. This amount is high enough to continue to require the use of the wet

scrubber for SO 2 control, but low enough to require flue conditioning with S03 injection

for proper ESP performance . The ESP's were designed for use with high sulfur coal,

but with the lower sulfur coal, SO 3 needs to be injected to modify the resistivity of the

flyash particles for proper ESP operation

.

The current scrubber is reaching the end of its life . The company is currently

investigating whether rebuilding the scrubber or replacing the scrubber is most

economic. If the scrubber system needs to be shutdown while a new one is built or

rebuilt, then low sulfur will be temporarily used to meet the SO 2 emission limits

.

The SCR was put into service in about June 2003 and presently operates from May

through September, the ozone season . New rules may require year round operation by

2009. The SCR system produces a little SO 3 so the S03 injection system is operated at

a reduced rate in proportion to the amount from the SCR to maintain about 10 ppm of

SO3 in the flue gas

.

The duct between the air heater and the ESP's is about 212 feet long but is not in a

straight line. The single duct connection at the pre-heater is 14 x 25 feet (352 sq . ft.)

and it splits into two sections, one for each ESP . Each connection to the ESP's is 7 x

33 feet (464 sq . ft.) The specific collection area (both ESP's combined) is 291

.

Rizwan Syed and Wayne Kahila, both from the Peoria Regional Office, did this

inspection

.

cc

:

W.Kahila

R.Syed

ID: 057 801 AAA

52

---

Sulfur dioxide is controlled by burning coal with the proper sulfur content. The average

S02 emissions from all three boilers are limited to 4.71 lbs. S02/million BTU. Any one

boiler may have up to 6.6 lbs. S0 2/million BTU as long as the overall average is not

exceeded . Also, on a plant wide basis, the 24-hour average for SO2 emissions shall not

exceed 34,613 lbs. SO2/hour. Reports of coal analyses have been submitted to the

Agency in a timely manner. Quarterly reports of the sulfur dioxide monitoring have

been submitted in a timely manner

.

Unit 1

:

The ESP is a cold side one . The duct from the air pre-heater to the ESP is a twin duct

.

Each section is 7 x 20 feet (274 sq

.

ft .)

at the outlet of the pre-heater and 16 x 34 feet

(1088 sq . ft.) at the inlet to the ESP. The total duct length is about 61 feet ; however,

this is not a straight line distance . There are many curves and angles in this length of

duct. The equipment is tightly squeezed together

.

The ESP specific collection area is 138

.

The only flue gas conditioning is S0 3 injection. Elemental sulfur is burned to make S02

and a catalyst converts the SO 2 into SO3

. The injection averages about 10 ppm of 50 3 .

The SO3 system is necessary for the ESP to work properly with low sulfur coal since the

ESP was designed to operate with high sulfur coal

.

Unit 2

:

The ESP is a cold side one . The duct from the air pre-heater to the ESP is a twin duct

leaving the pre-heater but is combined into a single inlet at the ESP. Each section is 11

x 28 feet (612 sq

.

ft .)

at the outlet of the pre-heater and 27 x 74 feet (1968 sq

.

ft .)

at the

inlet to the ESP. The total duct length is about 46 feet; however, this is not a straight

line distance. There are many curves and angles in this length of duct . The equipment

is tightly squeezed together

.

The ESP specific collection area is 170

.

The only flue gas conditioning is S03 injection. Elemental sulfur is burned to make S0 2

and a catalyst converts the SO 2 into SO 3

. The injection averages about 8 ppm of SO 3 .

The SO3 system is necessary for the ESP to work properly with low sulfur coal since the

ESP was designed to operate with high sulfur coal

.

Unit 3

:

The ESP is a cold side one . The duct from the air pre-heater to the ESP is a twin duct

.

Each section is 12 x 29 feet (638 sq

.

ft .)

at the outlet of the pre-heater and 32 x 49 feet

(3056 sq

.

ft.)

at the inlet to the ESP . The total duct length is about 31 feet ; however,

this is not a straight line distance . There are many curves and angles in this length of

duct. The equipment is tightly squeezed together

55

---

The ESP specific collection area is 178

.

The only flue gas conditioning is S03 injection and SCR system . Elemental sulfur is

burned to make S02 and a catalyst converts the S0 2 into 503 . The injection averages

about 12 ppm of SO3 . The S03 system is necessary for the ESP to work properly with

low sulfur coal since the ESP was designed to operate with high sulfur coal

.

Unit 3 also has a SCR system with ammonia injection . Data from the catalyst

manufacturer indicates that the catalyst in the SCR converts about 1 % of the entering

SO2 into SO3 . The rate of the S0 3 injection system is adjusted to account for the S03

from the SCR system so that the total S03 is about 12 ppm. Presently the SCR system

operates only during the ozone season, which is May through September. It may go to

year round operation in 2009 .

Rizwan Syed and Wayne Kahila, both of the Peoria Regional Office, did this inspection

.

cc

:

W.Kahila

R.Syed

ID: 143 805 AAG

56

---

Emissions Unit Information

61

1 iiu swn

Emission Control

1 )nit

Descriptioi

gwpment

Ito.ilei 9

Babcock& Wilcox It3diant

Overfire Air System, Lo

Coal-Fired Boiler

NOx burners, In-duct

447 MW Nominal Rating (1975)

Selective Catalytic

(pulverized coal wall fired)

Reduction System and ESP

with Flue Gas Conditioning

---

2

.

S03 injection

The facility does not use S03 injection in the boiler

.

3

.

Flue gas conditioning

The facility does use flue gas conditioning and is done between the boiler and the agglomerator

.

The flue gas additive used is manufactured by ADA and is sodium based and ADA proprietary

.

4 .

Other Information

The Havana Power Station is located on the Illinois River approximately one mile south of

Havana, Illinois. The facility has six major fossil-fuel-fired generating units, which are

essentially divided into two parts

.

The original plant was the first generating station built by Illinois Power . Station construction

planning began in 1944 with the five units coming on-line between 1947 and 1950 . These

original units are steam powered by eight # 6 fuel-oil-fired boilers . # 2 fuel oil is used to ignite

the # 6 fuel oil . All eight boilers are connected to a common steam header that supplies the five

turbine generators, each rated at 48 MW . All eight boilers are connected to

a

common exhaust

header, which in turn is connected to three exhaust stacks

.

The second plant houses Havana Unit # 6 (Boiler # 9), which is rated at approximately 490 MW

and is fired with low-sulfur pulverized coal and is wall fired . Construction began on this unit in

1975, and the unit came on-line in 1979 . Coal is transported to the station either by barge or rail

car where it is unloaded, stored, crushed, elevated to the coal silos in the Unit # 6 building,

pulverized, and blown into the boiler for combustion . Upgrades to the existing coal handling and

processing system, including a new crusher, new fly ash transport and loadout systems, flue gas

conditioning system and a temporary portable coal conveying system were made and the new

coal crusher and associated conveyors began operation on January 9, 2005 and achieved

maximum production rates on February 1, 2005 . The temporary portable coal conveying system

was removed once the main conveyors began operation . Exhaust gases from the boiler pass

through an electrostatic precipitator to remove fly ash and then pass through a selective catalytic

reduction (SCR) unit to control NOx emissions. The facility is installing a agglomerator

between the boiler and the ESP which is hot side . The agglomerator has a series of charge plates

to collect small particles to attract to each other and assist in enhancing the efficiency of the ESP

.

The agglomerator by itself is not an emission source or a control equipment . According to the

Dynegy staff, the Agency's office in Springfield was notified about this installation . From the

SCR, the exhaust gas flows through the air heater then up the stack Prior to installation

of

the

SCR over-fire air fans were installed and began operation on March 03, 2003 to provide some

NOx control. The SCR system began operation on August 04, 2003 . The boiler has started

burning low-sulfur sub bituminous coal in place of low-sulfur bituminous coal on January 19,

2005

.

Presently, about 12 startups of Unit # 6 occur per year . Dynegy has changed the station's

operating status to a base load unit. Prior to the change, about 150 startups per year occurs ed

60

---

Contact: Jim Dodson

Phone: 815-339-9212

Contact: John Augspols

Phone : 815-339-9218

Contact: Michelle Chestnut

Phone: 217-872-2367

Cell : 217-714-4794

#15-Dynegy Midwest Generation (Hennepin)

Division of Air Pollution Control - Field Operations Section

Special Inspection Memorandum

Date : May 4, 2006 (revised)

To: E . Bakowski

From : J. Krolak & W. Kahila

Source: Dynegy Midwest Generation, Inc .

Address : R.R.1, Box 200A, Hennepin, IL 61327

Title: Plant Manager

Fax :

Title: Environmental Coordinator

Fax : 815-339-2772

Title: Environmental Specialist (Decatur)

Fax : 217-876-7475

ID# 155 010 AAA

Dynegy Midwest Gen

.

Field Inspection Report

Date of Inspection : April 28,2006

Last Inspection : not relevant

ID : 155 010 AAA

RID: 203

County : Putnam

SIC: 4911

Description: This facility is a coal-fired electric generating station that now burns

western sub-bituminous low-sulfur coal to meet federal acid-rain prevention

requirements. Dynegy Midwest is the successor (for fossil-fuel power generation) to

Illinois Power Company

.

62

---

2

SO ,_19iection

Dynegy's Hennepin Station burns only low-sulfur Powder River Basin (PRB) coal, and uses S0

3

injection after the air heater exhaust to enable the ESPs to function properly . The sulfur use rate and

resultant SO3 concentration are not directly measured ; the optimum concentration is dependant on exhaust

gas parameters and is determined by observing the ESP power levels and the plume opacity and

appearance. Inadequate SO, results in excess emissions and opacity, while a slightly bluish plume

indicates too much SO,

3

.

Flue gas conditioning

No other flue gas conditioning is utilized beyond the furnace NO, controls

.

4

.

Other Information

The station is located in an agricultural/ industrial area within the corporate limits of Hennepin in Putnam

County, and is an electric utility . The two coal- or natural gas-fired units at this station are capable of

generating a total of about 316 megawatts . No other commercial generating units are located here

.

Under Board Regulations, the station's combined SO, emission limit is 17,05olbs/hr due to the 264foot

stack height. Burning PRB coal, actual emissions do not approach this limit

.

The station is located on the south bank of the Illinois River, and coal is delivered to the site by barges

.

Construction of Unit I was begun about 1950, followed by the larger Unit 2 about 1956

. Due to the lack

of space at the site, the ESPs for both units are located above the respective ID fans, with the common

stack between them. Unit 2's ESP is located higher above the ID fans to allow space for the larger

ductwork and breeching underneath it

.

When considering how to reduce sulfur emissions to meet acid rain restrictions, the owner (formerly

Illinois Power Company) determined that it was not economically feasible to install additional flue-gas

control systems such as scrubbers, or to increase the size of the ESPs . The only means left was the use of

low-sulfur coal and SO 3 injection

.

It is apparent that emission control systems requiring enlarged or additional structures could not be fitted

between the furnaces and the river . Lateral expansion might be accommodated, probably at a considerable

expense .

The Unit 2 ESP was refurbished in 2003, as described in Dynegy's letter of January 29, 2003 to Don

Sutton of the Agency. The Collection Plate Area and SCA information on form 260-CAAPP, page 164 of

the original CAAPP application submitted in September 1995, is no longer correct

. Information received

from Dynegy on May 4, 2006 states that the collection plate area is now 109,200sq ft, and the Specific

collector Area (SCA) is 125 .5

.

CC: Dean Hayden

Wayne Kahila

65

---

3_SO3lnigction ;

The facility presently utilizes S() 3 injection, however, the system may or may not be utilized in

conjunction with new mercury/PM baghouse control

.

4. Flu Gas Conditioning

:

The plant previously tried flue gas conditioning when using high sulfur coal. The boilers have

been switched to Powder River Basin coal (PRB) and this system will no longer be used

.

5. General Boiler Description :

3.2 Unit #1 Boiler with ESP and low NOX combination system

Dynegy has two Combustion Engineering tangentially fired pulverized coal boilers (Units #1 and #2)

.

Unit #1 has a maximum rated capacity of 84 MW (785 mmbtu/hr) . Each Unit has 4 pulverizers and 16

burners . Each pulverizer feeds 4 burners that are located at each comer of the boiler . The pulverized coal

is injected at four levels of the boiler. Each pulverizer corresponds to a different height at which coal is

injected into the boiler. The emissions from each unit are exhausted through an electrostatic precipitator

and then through a common stack

.

Electrostatic Precipitators (ESP) control the particulate matter emissions from the boilers . The ESP for

Unit #1 is a Buell with 4 sections (4 TRs) . The ESPs uses a hammer /anvil type rapper to remove

particulate matter from the plates. Particulate matter emissions from Unit I are limited to 0 .12 lhs/mmbtu

per 35 111. Adm. Code 212 .203(b) .

Sulfur dioxide (SO,) emissions from Units #1 are uncontrolled . S02 emissions are limited to 8 .5

Ib/rmnbtu by 35 111 Adm. Code 214.184. In addition, SO2 emissions trout both units #1 and #2 are limited

to 16,805 lbs/hr by permit special condition . Construction permit PN05030030 was granted 4/6/05 to

install new SO, gas conditioning system for ESP unit to bum low-sulfur coal (PRB) and reduce PM and

SO, emissions . S03 concentration in the flue gas will be approximately 20 ppm as needed by volume

.

Carbon monoxide emissions from the boilers are subject to 35 Ill . Adm- Code 216.121 (200 ppm

corrected to 50 percent excess air)

.

Dynegy has SO,, NOX, C0 2, flow and opacity continuous emissions monitors (CEM/COM) located in

the stack. Dynegy installed these monitors because of the Acid Rain regulations, 40 CPR Part 75

.

However, Dynegy is required by permit special condition to submit quarterly reports of excess opacity

and SO 2

.

Unit #1 and its ESP are permitted in CAAPP operating permit 95090050 and state operating permit

73020064 .

3.3 Unit #2 Boiler with ESP and low NOX combination system

Dynegy has two Combustion Engineering tangentially fired pulverized coal boilers (Units #1 and #2)

.

Unit #2 has a maximum rated capacity of 113 MW (1,167 mmbtu/hr) . Fach Unit has 4 pulverizers and 16

burners. Each pulverzer feeds 4 bunicr.s that are located at each corner of the boiler_ The pulverized coal

is injected at four levels of the boiler Each pulverizer corresponds to a different height at which coal is

68

---

injected into the boiler. Unit #2 is equipped with low NOx burners, installed in 1993 . The burners take a

portion of the airflow that is injected into the bottom and injects the air above the highest burner . The

emissions from each unit are exhausted through an electrostatic precipitator and then through a common

stack

Electrostatic precipitators (ESP) control the particulate matter emissions from the boilers . The ESP for

Unit #2 the ESP is a Western-Precipitation with 10 sections (5 TR=s) . The ESPs uses a hammer/anvil type

rapper to remove particulate matter from the plates

.

Particulate matter emissions from Unit 2 are limited to 0 .1 lbs/mmbtu per 35 111. Adm. Code 212 .202

.

Sulfur dioxide (SO2 ) emissions from Unit #2 are uncontrolled. SO2 emissions are limited to 8 .5 lb/mmbtu

by 35 111. Adm. Code 214.184. In addition, SO2 emissions from both units #1 and #2 are limited to 16,805

lbs/hr by permit special condition . Construction permit PN05030030 was granted 4/6/05 to install new

SO, gas conditioning systems for ESP unit to bum low-sulfur coal (PRB) and reduce PM and SO 2

emissions. SO, concentration in the flue gas will be approximately 20 ppm as needed by volume

.

Carbon monoxide emissions from the boilers are subject to 35 Ill . Adm. Code 216 .121 (200 ppm

corrected to 50 percent excess air)

.

Dynegy has SO 2

, NOX, CO2 , flow and opacity continuous emissions monitors (CEM/COM) located in

the stack. Dynegy installed these monitors because of the Acid Rain regulations, 40 CFR Part 75

.

However, Dynegy is required by permit special condition to submit quarterly reports of excess opacity

and SO, .

Unit #2 and its ESP are permitted in CAAPP operating permit 95090050 and state operating permit

73020063/construction permit PN05030030

.

6. The information concerning ductwork dimensions was received from Dynegy personnel (Rick Dieriex)

and is not listed or documented in any permit application or official Dynegy drawing. The actual layout of

the new construction of mercury baghouse, associated ductwork, and auxiliary equipment may not be as

presented by FOS in this document . The drawings are not to scale

.

69

---

i18-Kincaid Generation (Kincaid)

TIER

I INSPECTION MEMORANDUM

Date

May 2, 2006

Date of Inspection

:

Marl,

2006

To

:

E Bakow-ki

From

:

E

.

Kierbach

I .D . )$

:

021814AAB

R/D

204

Source

Kincaid Generation,

L .L .C

.

Address

:

PO Box 260 : 4 miles west of Kincaid Rt . 104 Kincaid,

II 62540

Contact/Title Ann Singh, PE/Sr . Environmental Compliance Engineer

Phone

:

217-237-4311 x 2291 /

217 -237-5519

inspector(s) : Steve Youngbiut/Ernie Kierbach

Purpose

:

Coal fired powerpiant equ4ment

verification/clarification

1

.

Block Diagram

The block diagram depicts boilers unit 1 and 2 along with ductwork and

controls

.

Unit I boiler is equipped with over fire air for NOx reduction . The unit

exhausts to an ammonia injection selective catalytic reduction system (SCR)

.

From the SCR exhaust travels thru an air heater to an electrostatic

precipitator (ESP) . The ESP has two main compartments each with a specific

collection area (SCA) of 327 .5 . From the ESP the exhaust travels to a common

stack

Unit 2 boiler is equipped with over fire air for NOx reduction . The unit

exhausts to an ammonia injection selective catalytic reduction system (SCR)

.

From the SCR exhaust travels thru an air heater to an electrostatic

precipitator

(ESP)

.

The ESP has two main compartments each with a specific

collection area (SCA) of 327-5 . From the ESP the exhaust travels to a common

stack

.

In either configuration the estimated distance from the air heater discharge

to the ESP is 325 feet . There would appear to be ample room for add on

control in this section of ductwork

.

72

---

2

.

S0_3

injection

The

facility

does not use

S03 injection. A S03

injection has never been used

at

the

facility

.

3

.

Flue gasconditioning

No flue gas conditioning

is utilized

.

4

.

other

Information

Kincaid Generation utilizes two coal-fired boilers

in conjunction with steam

turbine generators

to generate electricity

.

Electricity generated by Kincaid

Generation

is sold on the "grid" . Coal combusted at this facility is low

sulfur Powder River Basin coal

(Black Thunder, North Antelope,

and Antelope)

.

The facility,

in general,

consists

of coal receiving/storage, coal

processing/crushing systems, a water treatment plant,

an auxiliary boiler,

and two coal-fired units each controlled by an SCR and electrostatic

precipitator

(ESP)

vented to a common stack

.

Each boiler is also equipped with an over

fire

air system

(OFA)

to reduce

emissions

of

NO, to aid in complying with the Acid Rain Program requirements

of

40 CFR 76

.

In general, this is

accomplished by reducing airflow

(oxygen)

in

the furnace region resulting

in a reduction of NO, formation

.

Additionally,

the facility has installed a selective catalytic reduction

(SCR) system to each unit . The SCR taps in at the economizer exit and vents

to the air heater . The air heater section then vents to the ESP . The SCR

systems provide NO„ reductions during the ozone season . The SCR systems will

utilize ammonia as a reducing agent to convert nitrogen oxide emissions from

the combustion process to nitrogen and water

.

Steam from each boiler is fed to a turbine set . A turbine set consists of

one high-pressure turbine, one intermediate-pressure turbine, and two low-

pressure turbines . The turbine sets are connected to generators that

complete the conversion of chemical energy to electric power

.

Emissions Unit

Information

74

Unit

Manufacturer

Firing Type

Design Heat

Ipput

Control

Equipment

Date

Constructed

Unit

1

Babcock & Wilcox

Cyclone

6,634 mmbtu/hr

OFA,

SCR,

ESP

1967

Unit

2

Babcock & Wilcox

Cyclone

6,406 mmbtu/hr

OFA,

SCR,

ESP

1968

Aux

Unit

Babcock & Wilcox

-

165 mmbtu/hr

-

1984

---

#19-Electric Energy (Joppa)

ILLINOIS ENVIRONMENTALPROTECTION AGENCY

Division of Air Pollution Control--Field Operations Section

TIER I1 MEMORANDUM

Contact/Title: Bruce Parker, Environment Engineer

FY06 Workplan Inspection. Also witnessed RATA

.

Description

:

Electric Energy's

- Joppa Generating Station, located near Joppa, Illinois consists of six coal-

fired generating units, which supply electricity for the U .S. DOE - Paducah, Kentucky uranium

enrichment facility, as well as supply the grid . The facility is a CAAPP source

.

Units 1-6 are all Combustion Engineering pulverized coal-fired units rated at 181 MW (1653

mmbtu/hr) capacity. The units started operation between 1953 and 1955. The units are each

equipped with Research

- Cottrell 5 section (3 TR's) ESP's installed in 1971 and 1972 . The

ESP's were upgraded in 1993-94 to handle particulate emission from western coal . The units are

vented through three 525' stacks, two units per stack. Continuous emission monitoring

equipment was installed at the station, as per 1990 Clean Air Act amendment

.

The station receives western coal by rail from the Powder River Basin in Wyoming with less

than 1% sulfur- The facility burns approximately 4 .6x

106 tons of coal per year

.

Following is a summary of station design data

75

Date :

February 27, 2006

Date of Inspection: February 9, 2006

To

:

Ed Bakowski, FOS Manager

Last Insp . Date: February 15, 2005

From :

Scott Arnold, FOS

1.D.#: 127 855 AAC

RID: 304

County: Massac

SIC: 4911

Source :

Address :

Electric Energy, Inc

.

Joppa Steam Station, 2100 Portland Rd ., Joppa, IL 62953

Phone :

618/543-7531, Ext . : 458

Fax :

618/543-7420

Purpose.

Unit

MW

MMBTtV/}g

"I'y3)e

Age

Equ-iment

Age

Height

1

181

1053

( C-I/, 11-C

1953

R-C, ESP

1971

525

2

181

1653

C-E,P-C

1953

R-C, ESP

1972

3

181

1653

C-F,P-C

1954

R-C, ESP

1972

525

4

181

1653

( :_F, 11-C

1954

R-C, ESP

1972

5

181

1653

C-F, P-C

1955

R-C, ESP

1972

525

6

181

1653

C-F, P-C

1955

R-C, P.SP

1972

---

Electric Energy, Inc

.

ID# 127 855 AAC

February 27, 2006

Page 2

The station's SO2 limit is 38,865 lb/hr. based on a 3-hour block average .

Findings

I arrived at Electric Energy, Inc. at roughly 10:25 a.m. on the date of inspection . I met with

Bruce Parker, Environmental Engineer, and Mike Mercer, Chemist . We began the inspection

with a walk through of the facility. On this day, a gas RATA was being finished up on the SO,,

NO, and CO2 monitors on all three stacks . They were presently on stack #3, units #5 and #6 .

Unit #6 was operating at roughly 180 MW . Unit #5 was in start up running at about 100 MW

.

After Unit #5 reached 180 MW, stack #3 would undergo its' RATA . The RATAs on stacks #1

and #2 were done yesterday with both operating at 360 MW . All the boilers operate at about 180

MW or high load normally, and there are two units vented to each stack

.

The RATA was finished yesterday on stacks #1 and #2, Unit #1 and #2 and Units #3 and #4

.

The RATA was being done by G .E. Mostardi Platt. The stack testing crew chief was Greg Rock .

Mr. Rock told me they were doing Methods 6C, 7E and 3A for SO„ NO, and

C02, respectively

.

Mr. Rock said they were using a dilution extraction system for testing, since Electric Energy,

Inc. has the same type CEM system . They were sampling 3 pts ., 7 minutes/pt . For 21 minute

RATA runs. They were using a Teflon probe. They were doing a minimum of 9 runs on each

stack at high load, which is also normal operating conditions

.

We next checked out the coal handling system . I observed the dumping of a train. I noted little,

if any, opacity. Ron Thompson, the coal-handling supervisor stated that the coal being dumped

on this day was going to storage . The #25 stacker was the only one operating. Stackers #23 and

#24 were down at this time. I noted opacity in the 5% range from the #25 slacker. I noted no

other VE from the storage area or coal piles

.

We proceeded to the control room. All units were operating at full load or about 180 MW each,

except the #5 unit which was operating at 100 MW and in start up mode . I asked for an received

a copy of the CEM data for each stack (attached)

.

We returned to the office and Mr. Parker provided me with a copy of the "used oil disposal log"

(copy) and the "used oil" analysis (copy in general file) .

I next asked for coal burned in 2005 (attached). I also asked if any chemical waste had been

burned in 2005. Mr. Parker stated there had. There is a chemical waste quantity and analysis in

the company's general file . They burned roughly 15,000 gallons of chemical cleaning waste in

2005

.

76

---

Electric Energy, Inc

.

ID# 127 855 AAC

February 27, 2006

Page 3

Finally, I asked for and received a copy of 2004 and 2005 emissions (attached)

.

This completed this inspection. Recommendations will be made

.

SAA:jkb/233x/02-28-06

cc :

BOA/Marion

Electric Energy, Inc

.

77

---

Electric Energy, Inc

.

ID# 127 855 AAC

February 27, 2006

Page 4

Conclusions & Recommendations

The company appears to be in compliance with Agency regulations . Also, I photographed all

three stacks. There is no equipment after the ESP and before the stack . All three ESPs are cold

side ESP's

.

SAA:jkb/233a/02-28-06

cc :

BOA-Marion

78

---

is

a

dry

fly ash handling system

.

This system

is controlled by a baghouse

designated as LS BA

-

the Hytem has not been opetated tot several years

.

The Dallman station consists of coal receiving/storage, coal

processing/crushing

:yctem, and three coal-fired boilers (units 31, 32, and

33) . Units 31 and 32

are rack controlled by a separate ESP (EP 31 and EP 32,

respectively) then by a common flue gas desulfurization (FGD) system venting

to a common stack. Exhaust from Unit 33 is first vented to an ESP (EP 33)

then to a FGD system_ From the FGD system the exhaust is directed to the

Unit 33 stack . Additionally, the facility has installed selective catalytic

reduction systems (SCR) to each of the three Dallman Units

.

The FGD systems are used to remove sulfur dioxide from the boiler exhaust

.

Limestone received at the Dallman station is crushed using ball mills . From

the ball mills the crushed limestone is mixed with

water creating slurry

.

The slurry is misted through the boilers exhaust via spray towers . Pumps at

the bottom of the spray

towers move the spent slurry to a settling tank

.

Settled material is pumped to a de-watering station . In the de-watering

stage a rotating vacuum drum is used to pick up the by product (gypsum)

. As

the drum rotates an edge is used to scrape the gypsum from the drum . The de

watered gypsum is conveyed to a temporary storage

area prior to off-site

distribution . The cement and agricultural industries currently use this

material

.

The dry ash handling

located at the Lakeside Station is not currently

utilized . Ash from the slag tank of each unit is dropped to a slag tank

hopper that feeds to a grinder . The ground ash is sluiced to separate

settling ponds located north of the Spaulding Dam . After the ash has settled

the materiall is distributed off-site for use in the construction industry as

backfill or as a component in the manufacturing of roofing materials

.

Currently fly ash and bottom ash are not separated

.

Three diesel generators are located just south of the Lakeside Station

.

These generators were Added to the facility for the purpose of black start

capability (back up power for the stations) . Initial operation began in June

of 2002

.

Emissions Unit Information

In addition, the fa

Y

applied drawings of the exhaust systems

.

84

Unit

Manufacturer

Firing Type

Design Heat

input (Output)

Control

Date of

Equipment Construction

Unit

7

Babcock & VUIco-x

Cyclone

415 mmBtu/hr

(33

MW)

EPLS

1959

Unit

8

Babcock & Wilcox

Cyclone

415 mmBtu/hr

(33

MW)

EPLS

1964

Unit 31

Babcock &

I

Cyclone

882 mmBtu/hr

(88 MW)EP31/FGD/SCR

1967

Unit 32

Babcock & Wilcow

Cyclone

882 mmBtu/hr

(88 MW)EP32/FGD/SCR

1971

Unit 33Combustion Enginee.tog Pulverized2,120

mmBtu/hr

(192 MW)EP33/FGD/SCR

1975

---

ILLINOIS ENVIRONMENTAL PROTECTION AGENCY

-Gt f

1021

NORTH GRAND AVENUE EAST,

P.O. Box 19276,

SPRINGFIELD, ILLINOIS

62794-9276, 217-782-3397

JAMES R . THOMPSON CENTER, 100 WEST RANDOLPH, SUITE

11-300,

CHICAGO,

IL 60601, 312-814-6026

,

ROD

R

.

BLAGOJEVICH, GOVERNOR

RENEE CIPRIANO, DIRECTOR

N

P

~l-d

•3

-

Oy

(217) 782-3397

(217) 782-9143 TDD

April 22, 2004

EPA Docket Center (Air Docket)

U. S. Environmental Protection Agency West

Mail Code 6102T

Room B-108

1200 Pennsylvania Ave, NW

Washington, DC 20460

Attn: Docket ID No. OAR-2002-0056

Re: Proposed National Emission Standards for Hazardous Air Pollutants ; and, in the

Alternative, Proposed Standards of Performance for New and Existing Stationary Sources :

Electric Utility Steam Generating Units, Proposed Rule ; Proposed Rule (69

Federal

Register

4652, January 30, 2004) ("Proposal") and Supplemental Notice for the Proposal

(69

Federal Register

2397, March 16, 2004)

Ladies and Gentlemen : -

The Illinois Environmental Protection Agency (Illinois EPA) appreciates this opportunity to

comment on the U.S. Environmental Protection Agency's (U.S

. EPA's) "Proposed National

Emission Standards for Hazardous Air Pollutants; and, in the Alternative, Proposed Standards of

Performance for New and Existing Stationary Sources : Electric Utility Steam Generating Units

;

Proposed Rule" referred to herein as the "Mercury Proposal" and the Supplemental Notice to the

Mercury Proposal, referred to as "Supplemental Notice." These comments supplement the

testimony that I presented on behalf of the Illinois EPA at the public hearing held in Chicago on

February 26, 2004

.

We have stated publicly that Illinois is very committed to substantially reducing mercury in the

environment, and the State is aggressively encouraging clean-coal technology that will allow

Illinois' abundant coal reserves to be used in the most environmentally responsible manner . The

proposals as set forth in the January 30, 2004 and March 16, 2004,

Federal Registers will

impede these efforts

.

ROCKFORD-4302 North Main Street, Rockford, IL 61103-(815) 987-7760

DES PLANES-9511 W. Harrison St., Des Plaines, IL 60016-(847) 294-4000

ELaN-595 South State, Elgin, IL 60123

- (847) 608-3131

•

PEORIA-5415 N. University St., Peoria, IL 61614-(309) 693-5463

BUREAU OF LAND -PEORIA-7620 N . University St., Peoria, IL 61614-(309) 693-5462

•

CHAMPAIGN-2125 South First Street, Champaign, IL 61820- (217) 278-5800

SPRINGFIELD-4500 S. Sixth Street Rd., Springfield, IL 62706-(217) 786-6892

•

COLLINSVILLE-2009 Mail Street, Collinsviile, IL 62234 - (618) 346-5120

MARION-2309 W. Main St., Suite 116, Marion, IL 62959-(618) 993-7200

---

In brief, our comments on the Mercury Proposal will focus on the following : 1) Mercury is a

highly toxic pollutant that needs to be regulated; 2) Mercury must be regulated under the Clean

Air Act (CAA) section 112(d), Maximum Available Control Technology (MACT) standard

;

3)

Under section 112(d), the mercury limits must be more stringent than set forth in the proposals

;

4)

The final rule must be fuel neutral, without favoring coal from any particular region of the

country; 5) Emissions trading of mercury allowances is not appropriate unless each affected unit

involved in a trade can demonstrate that mercury hot spots are prevented ; and

6)

Mercury

emissions can and should occur by

2010,

and section

112

of the Clean Air Act has sufficient

provisions to accommodate this timeframe. Attached please find Illinois EPA's specific

comments on the proposal .

Coal-fired power plants are a major source of air pollutants, but their pollution can be

significantly reduced using cost-effective technology that is available now, and which will be

improved even further in the next few years. Further reductions will reap tremendous benefits in

terms of environmental protection . It is imperative that U.S. EPA promulgate rules that will set

the tone and direction for the power plant emission reductions that are long overdue and put the

Nation on a path to better protect the health of our citizens and its future generations . To shirk

its responsibility in this matter would have devastating consequences that will not be able to be

fully compensated through State action alone

.

If you have any questions regarding our comments, please contact Laurel L. Kroack, Manager of

the Division of Air Pollution Control at

(217) 524-7636

.

Renee Cipriano

Director

Attachment

cc: Bharat Mathur

Acting Regional Administrator

U .S. EPA Region V

2

---

Comments of the Illinois EPA on the Mercury Proposal

Environmental Concerns

Mercury is a highly toxic, persistent, bioaccumulative pollutant that can cause long lasting health

problems. It is especially harmfid to unborn babies, where exposure can result in a number of

neurological deficiencies, including delayed developmental milestones, reduced test scores and

cerebral palsy. A National Research Council study commissioned by Congress and published in

2000 estimated that each year about 60,000 children born in the United States could have

neurological problems because they were exposed to mercury before birth

.

The high levels of mercury found in fish that populate the waters of our State are also of great

concern to us. Mercury contamination is wjdespread throughout Illinois, causing fish

consumption advisories to be issued for every waterbody in the State . Illinois is counting on a

strong federal mercury reduction program to help us achieve the goal of reducing the amount of

mercury deposited into waterbodies in the State . U.S. EPA's proposed rule is unlikely to realize

either sufficient reductions or reductions in a timely enough manner to protect our citizens

.

The Clean Water Act requires States to identify impaired waters, to determine what reductions in

loading need to occur to restore water quality (i .e., develop a Total Maximum Daily Load or

TMDL) and to develop and implement plans to accomplish that restoration . When fish from a

waterbody are so contaminated with mercury that we must advise our citizens to limit their

consumption of fish or face an increased risk of adverse health consequences, that waterbody

must be listed as impaired . Under the Clean Water Act, States are expected to have clean-up

plans (TMDLs) in place and working by 2015 to address impaired waterbodies . To achieve this

goal, substantial reductions in ambient mercury levels and mercury deposition must be initiated

in 2010. We believe it is only prudent, sensible public policy that this proposal should also

address our obligations under the Clean Water Act

.

Moreover, a strong mercury control program would provide significant co-benefits for sulfur

dioxide and nitrogen oxide reductions, both of which are important in attaining the fine

particulate matter and 8-hour ozone National Ambient Air Quality Standards (NAAQS) . We

encourage U.S. EPA to require substantial mercury control by 2010, when most ozone and fine

particulate nonattainment areas are required to reach attainment under the Clean Air Act

.

Coal-fired electrical generating units (EGUs) represent the largest domestic source of mercury

emissions, as well as the largest source of emissions of nitrogen oxides and sulfur dioxide . In

order to mitigate the significant health impacts of mercury, sulfur dioxide, and nitrogen oxides,

and meet our obligations under the federal Clean Air Act and Clean Water Act, wee urge U.S

.

EPA to adopt a more stringent rule that reduces mercury emissions from coal-fired EGUs to the

greatest possible extent and within the timeframes states are required to address program

compliance under these federal statutes

.

---

Rulemaking Approach

Although U.S. EPA attempts to justify how it can properly regulate mercury emissions from

EGUs under either sections 111(d) or 112(n) of the Clean Air Act, Illinois EPA believes that

those units must be regulated under section 112(d)

.

U.S. EPA chooses to interpret part of the language in section 112(n), requiring U .S. EPA to

evaluate "alternative control strategies," to justify an approach to regulation of hazardous air

pollutants (HAPs) from EGUs other than a listing under section 112(c), standard setting under

section 112(d), and compliance deadlines established under section 112(g) . U.S. EPA does not

provide legislative history

or

case law that would support such an approach or interpretation

.

Nothing in section 112(n) indicates any intent of Congress to allow U .S. EPA to regulate

emissions of hazardous air pollutants (as opposed to other air contaminants) from EGUs

under any other section than 112, nor does the language in section 112(n) evince any

intent of Congress to allow U.S.EPA to exempt EGUs from the multiple requirements of

other subsections of section 112 . Indeed, if Congress had intended to give U.S. EPA that

authority, it could have done so when it drafted section 112(n)

.

Moreover, regulation under section 111(d) would be inconsistent with the structure of the Clean

Air Act itself, i.e., section 112 for the regulation of hazardous air pollutants, sections 108 to 110

for the regulation of sources as necessary to attain a NAAQS, and section 111 to set standards of

performance for new stationary sources

.

Also, regulation of emissions of hazardous air pollutants from EGUs under section 111(4) would

be inconsistent with U .S. EPA's previous findings . Pursuant to section 112(n) of the CAA,

U .S. EPA was required to study the hazards to public health that result from the emissions of

EGUs and to provide a -report to Congress . If the section 112(n) study and report to Congress

found that regulation of these sources were necessary and appropriate, U .S. EPA is then required

to regulate under section 112. This proposal essentially proposes to rescind the findings U .S .

EPA reported to Congress, which concluded that controlling emissions of hazardous air

pollutants from EGUs are necessary under section 112 . Instead, U.S. EPA now proposes to

change to a section 111 finding that it is only "appropriate" to control emissions from these

sources. After negating its own conclusion, U.S. EPA then, without resubmitting the report to

Congress, has proposed rules pursuant to the authority of section 111, and in the form of a

trading program. To regulate EGUs under a section other than section 112, U .S. EPA would be

required to delist EGUs under section 112(c). U .S. EPA has not undertaken this process, and

cannot, in light of their own report to Congress, do so by claiming they erred in listing under

section l 12(c) initially .

Finally, U .S. EPA's conclusions that it erred in listing EGUs under section 112(c) cannot be

supported by its actions in regards to the proposed maximum achievable control technology

(MACT) standards for industrial boilers "National Emission Standards for Hazardous Air

Pollutants for Industrial Commercial/Institutional Boilers and Process Heaters" (40 CFR part 63,

subpart DDDD) ("Industrial Boiler MACT") . In the Industrial Boiler MACT, U .S. EPA

2

---

proposes to regulate mercury, nickel and other HAPS from these sources, based on a finding that

exposure to these HAPS have adverse health impacts, even though they emit these HAPS in

smaller quantities than EGUs

.

We do not believe that the rule proposed by U .S. EPA for the control of mercury emissions from

E

GUs tinder section 111(d) or 112(n) complies with the requirements of the Clean Air Act

.

Although U.S. EPA constructs an elaborate interpretation that allows it to promulgate a trading

program under sections 1 11(d) and 112(n), neither section provides specific authority for

promulgating a trading program . Sections 111(b)(1)(B) and (d) and section 112(d) require U.S

.

EPA to promulgate either a "performance standard" or an "emissions standard ." A performance

standard as defined by section 11 I(a)(1) of the CAA means an emissions standard that reflects

the "best system of reduction." And, an "emissions standard" under section 112(d)(2) is required

to reflect "the maximum degree of reduction that is achievable" (MACT). A trading program

does not, by its very structure, require a source to achieve any

particular level of emissions

reduction. U.S. EPA asserts that a cap and trade program is the best system of reduction because

it provides incentives to sources to make early reductions and to go beyond compliance

.

However, the safety valve and banking features without flow control of the proposed trading

program negate the very incentives of a market-based program . For these and other reasons

discussed more thoroughly below, we believe that the appropriate and legally required approach

for regulating mercury is under section 112(d) of the CAA that requires USEPA to set an

emissions standard that each unit would be required to comply with based on MACT, and each

EGU would then be required to meet that standard

.

We are also very concerned that other important section 112 requirements will be avoided under

a section 1 1 1(d) approach . As noted in a publication of the Washington, D.C. law firm of

VanNess Feldman entitled "EPA's December 15, 2003 Proposed Rule to Regulate Mercury

Emissions from Electric Utilities : Summary and Analysis"

:

Also of importance is that the alternative cap-and-trade option (under either

sections 112 or 111) would include the removal of the electric utility steam

generating units from the section 112(c) list. Such an action would shield the

affected utility boilers from the more prescriptive MACT standard-setting process

related to MACT floors, regulation of all HAPs, the form of standards, and unit

specific compliance obligations. In addition, such an action would spare electric

utilities from further regulation under section 112, specifically additional

tightening of the MACT standards under section 112(d)(6) or residual risk

standards under-section 112(1), eight years after promulgation of the initial MACT

standard .

We are concerned that the timeline in the Proposal is too long, and controls must be required

much more quickly. U.S. EPA gives insufficient support for its extended compliance deadline of

2018, which it has acknowledged, based on the elements of the trading program, could extend to

2025 or 2030. Based on the Florida Everglades experience in which stringent controls were

applied to incineration sources in the 1990's, resulting in a steep decline in fish tissue levels of

mercury within less than a decade, we can conclude that the quicker we start a reduction

3

---

program, the quicker the risk to our citizens can be reduced . A 2018 compliance date under the

section 111(d) proposal would be far, too late for Illinois to use the federal mercury rule

as

part of

a plan to restore an impaired waterbody under the Clean Water Act. And, we would be looking

at 2028 before substantial fish tissue reductions could occur in the best of cases. That's 25 years

before a current public health risk even begins to resolve, and that's too long

.

Under section 112(g), the compliance deadline would be three years after the rule adoption,

likely in 2007 . There is evidence that requiring strict levels of reduction by 2007 would be very

difficult, if not impossible, for all EGUs to meet and still ensure electric reliability . However, we

believe that mercury reductions can and should be required under the timeframes allowed for by

section 112(g), and the final compliance date should be no later than 2010 . Although this date is

three years beyond the date specified under section 112(g)(3)(A), sufficient authority under

section 112 exists to extend this date. The U.S. EPA Administrator, or a State with an approved

program under Title V of the Clean Air Act, may extend the compliance date by one year under

section 112(g)(3)(A)

if

the additional period is necessary for the installation of controls. Under

section 112(g)(4), the President may exempt any stationary source from compliance with any

standard for a period of not more than two years, which period may be extended, if the

technology to implement the standard is not available, and if it is in the national security interest

to extend the date

.

Also as discussed more thoroughly below, we believe that the limits should be much tighter than

those proposed by U .S. EPA and the rule should be fuel neutral, i.e ., it should not set different

reduction levels based on coal type .

Mercury Emission Limits

We believe that for existing coal-fired EGUs an input-based (or input-based equivalent) limit of

two pounds per trillion British Thermal Units (lb/TBTU's) or a reduction of 80% should be the

MACT standard. This limit should be adopted and required within

a

timeframe that is legally

allowed for under section 112 of the CAA. Various studies, including a U .S. EPA report

"Control of Mercury Emissions from Coal-Fired Electric Utility Boilers," which was posted on

U.S. EPA's website on February 27, 2004, indicate that these levels of control have been

achieved and are projected to be achievable for the types of units and types of coal utilized

.

Indeed, if the MACT had been properly set as an average of the best performing 12% of EGUs,

the MACT standard would have been set at 2.0 lbs/TBTU

.

In setting the MACT floor, U.S. EPA looked at emission test results from approximately 80

EGUs. However, there were not enough units tested nor enough test runs to completely rely on

this data. While it may be appropriate to apply a statistical analysis to generate a confidence

level when working with less than an ideal set of data, the statistical analyses used by .U .S. EPA

cannot be completely determined or replicated by Illinois . From what Illinois EPA staff have

been able to determine, the data have been selected to reflect the worst-case scenario, and then

some. This approach is fundamentally inconsistent with MACT standard setting under

section 112(d) which is technology-forcing--hence the requirement that the MACT floor be

based on the best performing 12% of sources

.

4

---

U.S. EPA has recommended that under section 11 I (d) new EGUs that burn bituminous coals

achieve a 94% removal efficiency for mercury. The recommended efficiencies for sources

burning sub-bituminous and lignite coals are 74% and 68%, respectively

.

We recommend that new EGUs should be required to reduce mercury emissions by 90%

regardless of fuel type. U .S. EPA determined that the average of the best 12% of 411 plants was

94% control and the average of the best 12% of the select 80 test runs was 93%. Notably,

Illinois EPA has recently issued a construction permit for one coal-fired power plant and has

proposed to issue a construction permit for another coal-fired power plant . At this point in time,

Illinois EPA has found that the permittees have not been able to obtain performance guarantees

from equipment manufactures at levels above 90% removal at this time .

The State and local Agency stakeholders, as well as the equipment manufacturers, as part of the

October 2002 FACA report, recommend that 90% removal efficiency was appropriate based on

their review of pilot plant and large unit testing of new technologies

.

Also, various studies, including a U .S. EPA report "Control of Mercury Emissions from Coal-

Fired Electric Utility Boilers," which was posted on U .S. EPA's website on February 27, 2004,

indicate that these levels of control have been achieved and are projected as achievable in 2010

across all types of units and types of coal

.

Rule Should Be Fuel Neutral

We urge U.S. EPA to adopt a rule that treats all types of coal equally in setting the standards for

mercury and that requires state-of-the-art control equipment . While the overarching goal of this

proposed environmental control program is to greatly reduce the emissions of hazardous

mercury, the proposed levels for sub-bituminous and lignite coals would require no, or very

minimal, mercury reduction from EGUs burning these coals . In fact, U.S. EPA's own contractor

(RTI International) has been quoted as admitting that the proposed rule would necessitate

installation of control equipment at 78% of the EGUs using bituminous coal, while only 29% of

the EGUs burning sub-bituminous coal and 21% of those burning lignite coals would have to add

controls. We also note that U .S. EPA's proposed approach in this proposal to require less

mercury reduction from lignite and sub-bituminous coals is counter to the recommendations of

its own working group for this issue that met from August 2001 through March 2003 under the

Federal Advisory Committee Act (FACA). Moreover, we do not believe the approach that

distinguishes between coal rank is either legal or technically supportable . Sections I I I and 112

limit U .S. EPA's authority when developing regulations for a source category to simply

distinguishing between the classes, types, and sizes of boilers, or, in other words, they are

allowed to make a technical distinction . As has already been discussed, an EGU can burn both

the sub-bituminous or bituminous coal with minimal or no change to the boiler . In addition, as

some states have found, mercury emissions from sub-bituminous coal decreases with the

blending of it with bituminous coal . If U.S. EPA's proposal was fuel neutral, users of sub-

bituminous coal may have an incentive to blend with bituminous coal . A similar blending has

taken place for years with respect to the Acid Rain and NOx Trading Programs, where users of

primarily bituminous coal are blending sub-bituminous coal to meet more stringent NOx and

SO2 emission limits

.

5

---

Moreover, there does not appear to be a technological issue to prevent EGUs that burn

bituminous coal from switching to or blending sub-bituminous coal. Therefore, the proposal

provides an incentive that could result in an overall increase in current mercury levels within the

State . As illustration, the estimate of 2 .99 tons of mercury attributed to the State of Illinois did

not account for blending/mixing of coal types and coal switching that resulted in a substantial

increase in the use of sub-bituminous coals that has occurred since the implementation of the

Acid Rain program. As such, Illinois' mercury emissions from EGUs.are approximately 25%

higher than U.S. EPA's estimate. With different mercury emission standards for each type of

coal, companies will likely continue to experiment with different coal blend scenarios which

could further delay the reduction of mercury to the environment : Furthermore, Illinois' mercury

emissions could actually increase as EGUs take advantage of less stringent emission limits if

they were to switch from bituminous to sub-bituminous coal

.

This rulemaking should not provide a justification for power plants that choose to use lignite or

sub-bituminous coals to continue to pollute . The provisions of the Clean Air Act and U .S. EPA

implementing regulations are basically fuel neutral . Although we note that some minimal attempt

was made in the Clean Air Act Title IV Acid Rain program to give relief for EGUs in states that

relied more heavily on high-sulfur bituminous coals, the Acid Rain program still had an

extremely deleterious effect on bituminous eastern and Mid-western coal industry, although it

achieved significant environmental gains. The U.S. EPA mercury reduction rule must also

provide a fuel neutral approach to reducing the emissions of mercury

.

This approach to fuel neutrality is evidenced by U .S. EPA's recently proposed, but not yet

published, Industrial Boiler MACT, which does not distinguish between coal ranks . (40 CFR

part 63, subpart DDDD)

The U.S. EPA should establish a fuel neutral approach for mercury reductions that achieves

environmental gain without creating additional economic distortions in the coal market . We urge

U .S. EPA to recognize the importance of adopting standards that will result in real reductions of

mercury to the environment without unfairly pitting the regions of the country against each other

.

We strongly oppose the proposed approach in reducing mercury emissions from utility boilers

based on coal types . The mercury proposal should be uniform for all fuel types nationwide,

consistent with the Clean Air Act's policy of fuel neutrality . We urge U.S. EPA to revise the

Proposal, as it appears to indirectly promote certain coal fuel types

.

Determining Compliance

Under the Mercury Proposal, a company could elect to blend coals from different types and

ranks as a means to achieve compliance with the rule. Although, U .S. EPA discussed the

possibility of blending different coal ranks (69 Fed. Reg. 4674), there is no industry-wide

uniform blending procedures. In fact, sources may adopt irregular blending frequencies due to

their own economic situation, the coal quality of their supplies, or to achieve their own

optimization goals. The determination of the weighted mercury allowable emissions limit would

then become a case-by-case compliance determination for most, if not all, EGUs. We believe

this lack of specificity by U.S. EPA will lead to an inaccurate accounting of mercury emissions

r

---

and may well lead to an increase of uncontrolled mercury emissions to the atmosphere . For the

aforementioned reasons, determining or verifying compliance could be a very cumbersome

procedure. States would face extreme difficulty in enforcing such a rule . Again, Illinois

supports a fuel neutral rule

.

Technical Issues

As stated previously, we found it very difficult to assess the statistical analyses that were used as

the basis for setting the MACT floor values based on the information provided in the Federal

Registers and in the various supporting materials

.

Our concerns regarding the analyses that were used to set the MACT floor include the following

:

1) It has not been established that the best performing 12% of sources were selected to establish

the MACT floor; 2) Since the testing of emissions units was not random, we cannot be sure that

the data used to set the MACT floor properly represents the variability of the mercury emissions

;

3) Only one test per unit does not seem sufficient to use as the basis in setting the MACT floor

;

4) We cannot tell which emissions variables are most sensitive in determining the MACT floor

;

and what the model indicated when variability was accounted for; 5) We question why a hot side

electro-static precipitator (HESP) was selected as one of the best-controlled sources for setting

the MACT floor for sub-bituminous coal; and 6) There was inadequate justification for not

examining more control technologies/options in setting the MACT for new sources . These

concerns add further to the lack of confidence in the MACT levels values that USEPA has

proposed

.

Other Hazardous Air Pollutants

We also urge U.S. EPA to take steps to move forward with emissions standards for all non-

mercury HAPs that are emitted from EGUs . In its December 2000 "Notice of Regulatory finding

for Emissions of HAPs from EGUs", U .S. EPA indicated that a significant number of the 189

HAPs included in the section 112(b) list are being emitted by coal and oil fired utility units

. In

fact, in the final utility report ("Study of Hazardous Air Pollutant Emissions from Electric Utility

Steam Generating Units, Final Report to. Congress, Volume I", referenced as "Utility Report to

Congress") containing the study on exposure and risk assessment from a number of HAPs from

EGUs, U .S. EPA estimated that in addition to mercury and nickel, as much as 143,000 tons of

hydrogen chloride (HCL), 20,000 tons of hydrogen fluoride and an appreciable tonnage of heavy

metals such as arsenic (61 tons), chromium (73 tons), lead (75 tons), acrolein (25 tons) and

manganese (164 tons) were emitted to the atmosphere in 19900 from these units . The same report

predicted that these HAP emissions would increase during the period of 1990 to 2010

.

The Utility Report to Congress recommended that a risk assessment analysis be performed on

emissions from coal combustion for the following HAPs : acrolein, arsenic, beryllium, cadmium,

chromium, dioxin/furans, radionucleides, hydrogen chloride (HCL), hydrogen fluoride (HF),

and

lead. Heavy metals like arsenic, nickel, chromium and cadmium are the heavy metals

prioritized for further risk assessment because of the higher potential concern for carcinogenic

effects. Also recommended for further assessment were hydrogen chloride, hydrogen fluoride

---

and acrolein because these HAPs are of greatest potential concern for public_ health due to short-

term exposure

.

Although the preliminary screenings indicate that cancer risks are not high, our concern is based

on the fact that U.S. EPA could not eliminate these heavy metals as posing no risk to public

health. We believe that U.S. EPA should include emission standards for acid gases, other HAPs

(notably arsenic, cadmium, chromium, and lead) and organics (dioxin) for the very same reasons

these heavy metals and HAPs were selected as priorities for further risk assessment, i .e., due to

their significant level of emissions, persistency in the environment, tendency to bioaccumulate

and potential health threat due to short term exposures . Such standards have been adopted in

recent Industrial Boiler MACT and MACT standards for municipal solid waste combustors .

Treating EGUs the same as industrial boilers is clearly appropriate and scientifically supportable

.

Emissions Trading

Illinois has been recognized as a leader in the area of emissions trading, and based

on our

experience with a number of emissions trading programs for criteria pollutants, we provided

supportive comments to U .S. EPA on their proposed interstate trading program as part of the

recent Interstate Air Quality Rule (IAQR) proposal . We are very concerned, however, that the

proposed emissions trading program for mercury would cause or perpetuate continued fish

consumption advisories for our waterbodies . Because of these concerns, we urge U.S. EPA to

refrain from including an emissions trading program in its national mercury reduction strategy

for electric generating units, unless EGUs wishing to trade can demonstrate that they do not

cause or allow continuation of a mercury "hot spot," or U .S. EPA otherwise ensures that a

protective base level of mercury reduction from each unit is achieved, and trading only occurs

above this protective limit .

Without strict mercury reduction limits, emissions trading could result in an undetected localized

mercury "hot spot" due to an EGU that elects not to reduce its emissions . Unlike NAAQS for

criteria pollutants (i .e., particulates, nitrogen dioxide, sulfur dioxide, ozone and lead), there are

no NAAQS for mercury that must be maintained to protect against localized atmospheric loading

and deposition. Furthermore, the number of ambient mercury monitors is very,

very

small

compared to the criteria pollutant-monitoring program throughout the Nation. In Illinois, for

example, we are fortunate to have one continuous mercury monitor ; many States do not have

any. Our air-monitoring network is therefore not adequate to detect a localized ambient mercury

"hot spot ."

We have particular concerns about the water quality in our local rivers and streams in the

Midwest, and even greater concerns about mercury levels in the Lake Michigan . High levels of

mercury deposited in our State's waterways have accumulated in fish tissue, resulting in the

issuance of advisories to restrict consumption of predator fish caught from Illinois' lakes and

streams. A soon to be published study, "Modeling the Atmospheric Transport and Deposition of

Mercury to the Great Lakes,"(to be published in "Environmental Research") shows that Midwest

EGUs are substantial contributors to mercury in the Great Lakes . A three-year study of

precipitation samples collected in Indiana and analyzed by the U .S. Geological Survey has

concluded that the mercury concentration in the precipitation is significantly influenced by

8

---

nearby mercury emitting sources. (Risch, Martin, U .S. Geological Survey, Briefing for Indiana

Department of Environmental Management Mercury Workgroup, "Atmospheric Deposition of

Mercury in Indiana and Nearby Emission Sources", April 2004.) Local sources must achieve

reductions

.

In addition to Illinois' general concerns with a trading program, there are two particular

provisions of the U .S. EPA proposal that further exacerbate our concerns for "hot spots." The

first is the "safety valve" provision that enables sources to buy additional allowances from a

future allocation at a price that is preset in the rule. The proposed rule allows borrowing with no

interest or penalty, requiring only a reduction in the State's mercury budget for fiiture years

.

(See 69 Fed. Reg. 12445, proposed section 60.4143.) A safety valve provision is counter to a

market-based approach to reducing emissions . A local mercury "hot spot" could be the result of

applying the "safety valve" to a particular plant or group of plants

.

The second provision of concern is the one for banking as proposed in section 60.4135. It allows

unlimited banking with no flow control . Such a provision will allow sources that may easily

comply with the "limits" set for 2010 to bank allowances for 8 years and to push the final

compliance date out at least another decade. The federal NOx SIP Call Trading Program

avoided this result by adopting a flow control provision that makes older allowances less

valuable. Such a mechanism is even more appropriate for this progam, where "hot spots" could

appear .

Illinois has these additional concerns about the Supplemental Notice to the U .S. EPA proposal

.

First, it did not include any proposed language for a section 112(n) trading program . Such a

program could be fundamentally different in structure than a program promulgated pursuant to

section 111 . As proposed in the Supplemental Proposal, under section 111 states are given

flexibility over allocation issues as long as they meet their budgets, and so long as they meet

certain parameters,

-but similar authority is not specified under a section 112(n) approach

.

Moreover, it is unclear, given the mandate under section 11 I(b)(1)(B) that U.S. EPA is required

to regulate new sources, how U.S. EPA can require states to regulate "new" EGUs under

section 111(d), because this section requires states to regulate "existing" sources . Illinois prefers

that if there is a trading program promulgated, it would have the authority to develop its own

system for allowance allocation, flow control, banking, and other trading issues

.

Second, the Supplemental Notice provides no State budgets for 2010, nor does it indicate when

such budgets would be promulgated by U .S. EPA. This is a critical piece of a program, as the

State would be required to promulgate rules no later than 2007

.

We ask that U.S. EPA not incorporate mercury emissions trading within its national mercury

reduction program, and in the alternative, that such a trading program be carefully designed so

that U.S. EPA can insure protection of our waters .

Program Consistency

We urge U .S. EPA to make every effort to ensure consistency, especially with respect to

compliance deadlines, between the various federal air quality programs, including the mercury

9

---

reduction program, the Interstate Air Quality Rule (IAQR), the Regional .Haze program, and the

NAAQS attainment dates. While it is clear that additional reductions from EGUs are warranted

and achievable, we must take all available steps to provide the electric power industry with a

reasonable degree of certainty regarding future regulatory requirements, especially the timing of

these requirements . The industry must be given the opportunity to plan for the most cost-

effective set of compliance options

.

Conclusion

It is disappointing that U.S. EPA is not proposing the kind of strong federal mercury reduction

program that will result in comparable, reliable, equitable and sufficient reductions to allow

States to minimize the risk to their citizens and fulfill their obligations under the Clean Air and

Clean Water Acts. U.S. EPA has ultimate statutory responsibility, along with the State of

Illinois, for assuring that water quality standards are achieved and impaired waters are restored in

a timely manner. If the Mercury Proposal is promulgated as proposed under other section 111(d)

or 112(n), Illinois is concerned that the significant adverse health impacts from mercury would

continue into the next several decades, and we will be unable to provide reasonable assurance

(under the Clean Water Act TMDL vile) that water quality standards will be achieved . Instead,

U.S. EPA will be looking to us for a better demonstration of reasonable assurance, and we will

ultimately need to develop state-level requirements to solve what is

a

national-scale water quality

problem

.

We strongly urge U.S. EPA to establish a mercury reduction program through a MACT standard

under section 112(d) and to adopt a fuel neutral program as mandated by the Clean Air Act . We

urge a strict program, which results in a mercury limit for all existing coal-fired units of 2

lb/TBTU or an 80% reduction in 2010. New sources should be required to reduce emissions by

90% .

h:\kk\Docket ID No Draf.dl-4-04.doc

10

---

EPA Dockets

- Submit Comment Results

About

EDOCKET

EPA Dockets

Contact

Us

EPA

Home

> EPA

Dockets >

-Submit Comment Results

Submit Comment Results

View Open

Dockets

EPA

Home

I

Submit

Comments

04-22-2004 18:29:07 EST

Search

Submit Comment Results

1J

Your Comment with Title "Illinois EPA Comments on the Mercury Proposal" was Received

.

The Identifier Assigned is "OAR-2002-0056-1967" .

Please note that it may take between 24 and 72 hours for the EDOCKET staff to process

your comment before it is available publicly through EDOCKET . You can use the identifier

noted above to find your comment (document) through the Quick or Advanced Search pages

when it is available . An Electronic File was Attached to this Submission

.

Return to Submit Item Search

I Contact Us

Search

Last updated on Thursday,

April

22nd, 2004

URL : http://cascade.epa.gov/RightSite/dk_public submit comment

results.htm

Page I of I

U.S. Environmental Protection Agency

Quick

Advanced

User

Help

Agreement

http://cascade.epa.gov/16WSite/dk_publi c

su

mit7OTflfl ent resujts:htm-- 4/2212004

---

Blood and Hair Mercury Levels in Young Children and Women of Childbearing Age

--

CDC

j CDC Home

;Searrh

(t;ezttfi Topics A-2

Weekly

March

02, 2001150(08) ;140-3

Page 1 of 4

Blood and Hair Mercury Levels in Young Childi

and Women of Childbearing Age --- United Stati

1999

Mercury (Hg), a heavy metal, is widespread and persistent in the environment. Exposure to hazardous I

cause permanent neurologic and kidney impairment (1--3) . Elemental or inorganic Hg released into the

becomes methylated in the environment where it accumulates in animal tissues and increases in concen

through the food chain. The U .S. population primarily is exposed to methylmercury by eating fish. Met

exposures to women of childbearing age are of great concern because a fetus is highly susceptible to ad

This report presents preliminary estimates of blood and hair Hg levels from the 1999 National Health ai

Examination Survey (NHANES 1999) and compares them with a recent toxicologic review by the Nati,

Research Council (NRC). The findings suggest that Hg levels in young children and women of childbe~

generally are below those considered hazardous . These preliminary estimates show that approximately

women have Hg levels within one tenth of potentially hazardous levels indicating a narrow margin of s

:

some women and supporting efforts to reduce methylmercury exposure

.

CDC's NHANES is a continuous survey of the health and nutritional status of the U .S. civilian, noninst

:

population with each year of data constituting a representative population sample . A household intervie

physical examination were conducted for each survey participant . During the physical examination, blo

collected by venipuncture for all persons aged >1 year and hair samples, consisting of approximately 1(

were cut from the occipital position of the head of children aged 1--5 years and women aged 16--49 yet

blood specimens were analyzed for total Hg and inorganic Hg for children aged 1--5 years and women

years by automated cold vapor atomic absorption spectrophotometry in CDC's trace elements laborator

detection limit was 0 .2 parts per billion (ppb) for total Hg and 0 .4 ppb for inorganic Hg (4) . Hairs of 0 .(

cm) closest to the scalp (approximately 1 month's growth) were analyzed for total Hg concentration usii

atomic fluorescence spectroscopy (5)

. The limit of detection for total Hg in hair varied by analytic batcl

maximum limit of detection (0.1 parts per million [ppm]) was used in these analyses . Blood Hg levels b

limit of detection were assigned a value equal to the detection limit divided by the square root of two fo

of geometric mean values .

The geometric mean total blood Hg concentration for all women aged 16--49 years and children aged 1

1 .2 ppb and 0.3 ppb, respectively; the 90th percentile of blood Hg for women and children was 6 .2 ppb

respectively (Table 1) . Almost all inorganic Hg levels were undetectable ; therefore, these measures indi

methylmercury levels. The 90th percentile of hair Hg for women and children was 1 .4 ppm and 0.4 ppn

respectively. Geometric mean values were not calculated for hair Hg values

.

Reported by: Center for Food Safety and Applied Nutrition, Food and Drug Administration . US Enviro

Protection Agency. National Energy Technology Laboratory, Dept of Energy . National Marine Fisherii

file://C:\Documents%20and%20Settings\epauser\My%20Documents\Mercury\Exhibits\B1

.

.

.

6/30/2006

---

Blood and Hair Mercury Levels in Young Children and Women of Childbearing Age

---

.

.

Page 2 of4

Laboratory, National Oceanic and Atmospheric Administration . National Center for Health Statistics;,

Center for Environmental Health, CDC .

Editorial Note :

The NHANES 1999 blood and hair Hg data are the first nationally representative human tissue measure

:

population's exposure to Hg. Previous estimates of methylmercury exposure in the general population v

exposure models using fish tissue Hg concentrations and dietary recall survey data (1) . The NRC reviec

guidance to the Environmental Protection Agency (EPA) for developing an exposure reference dose for

methylmercury

(i .e., an estimated daily exposure that probably is free of risk for adverse effects over th

person's life) (3). The NRC report recommended statistical modeling of results from an epidemiologic s

conducted in the Faroe Islands near Iceland, where methylmercury exposures are high because of the la

of seafood eaten by the local population . Results of this study were used to calculate a benchmark dose

estimate of a methylmercury exposure in utero associated with an increase in the prevalence of abnorm

:

cognitive function tests in children. The lower 95% confidence limit of the BMD (BMDL*) was recom

:

calculate the EPA reference dose. The NRC committee recommended a BMDL of 58 ppb Hg in cord bI

(corresponding to 12 ppm Hg in maternal hair) (3) . In the NHANES 1999 sample, there were no measu

blood values >58 ppb or hair values >12 ppm. A margin-of-exposure analysis (i .e., an evaluation of the

BMDL to estimated population exposure levels) showed ratios of <l0 when comparing BMDL with NI

estimates of the 90th percentile for blood and hair Hg levels in women of childbearing age

. Margin-of-c

measures of this magnitude indicate a narrow margin of safety (3) and suggest that efforts aimed at deci

human exposure to methylmercury should continue

.

The findings in this study are subject to at least three limitations . First, the ratio of Hg in cord and mates

uncertain. The NRC committee summarized some studies that suggest that cord blood values may be 2(

higher than corresponding maternal blood levels . However, other studies suggest that the ratio is closer

therefore, the NHANES values may not be directly comparable to BMDL recommended by NRC . Seen

NHANES cannot provide estimates of Hg exposure in certain highly exposed groups (e.g., subsistence

and others who eat large amounts of fish). Published data from studies of highly exposed U .S. populatic

that some persons attain Hg tissue levels above BMDL (1). Third, the sample size of NHANES 1999 w

the 1999 survey was conducted in only 12 locations . More data are needed to confirm these findings

.

The long-term strategy for reducing exposure to Hg is to lower concentrations of Hg in fish by limiting

into the atmosphere from burning mercury-containing fuel and waste and from other industrial processt

basis of data from EPA's National Toxics Inventory, air emissions of Hg decreased approximately 21

-1996, largely because of regulations for waste incineration (7). EPA expects this trend to continue as n

implemented for waste incineration and chlorine production facilities and are developed for electric poi

(8, 9). Fish is high in protein and nutrients and low in saturated fatty acids and cholesterol and should be

an important part of the diet . The short-term strategy to reduce Hg exposure is to eat fish with low Hg b

avoid or to moderate intake of fish with high Hg levels. State-based fish advisories and bans identify fis

contaminated by Hg and their locations and provide safety advice

(http://www.eva.gov/ost/fisht ) . The I

Drug Administration advises that pregnant women and those who may become pregnant should not eat

swordfish, king mackerel, and tile fish known to contain elevated levels of methylmercury. Information

atht//www.fda.gov/bbs/topics/ANSWERS/2001/advisory.html t

.

U.S. population estimates of Hg tissue levels by race/ethnicity, region, and fish consumption will becon

after 2 additional years of NHANES data collection . NHANES will provide the opportunity to measure

levels and to monitor the effectiveness of continuing efforts to reduce methylmercury exposure in the L

population

.

f le ://C:\Documents%20and%20Settings\epauser\My%20Documents\Mercury\Exhibits\Bl

. . . 6/30/2006

---

Blood and Hair Mercury Levels in Young Children and Women of Childbearing Age

---

Page 3 of 4

References

1. Environmental Protection Agency. Mercury study report to Congress . Washington, DC : Office

o1

Planning and Standards and Office of Research and Development, Environmental Protection Age

December 1997 .

2. Agency for Toxic Substances and Disease Registries . Toxicological profile for mercury (update)

.

Georgia: Agency for Toxic Substances and Disease Registries, US Department of Health and Hu

:

Services, March 1999 .

3. National Academy of Sciences. Toxicologic effects of methylmercury. Washington, DC: Nationa

Council, 2000

.

4. Chen HP, Paschal DC, Miller DT, Morrow J. Determination of total and inorganic mercury in wI

on-line digestion with flow injection . Atomic Spectroscopy 1998;19:176--9

.

5. Pellizzari ED, Fernando R, Cramer GM, Meaburn GM, Bangerter K . Analysis of mercury in hair

Region V population. J Expo Anal Environ Epidemiol 1999 ;9:393--401 .

6. Budtz-Jorgensen E, Grandjean P, Keiding N, White RF, Weihe P . Benchmark dose calculations c

methylmercury-associated neurobehavioral deficits . Toxicol Lett 2000;112--113 :193--9 .

7. Environmental Protection Agency . National toxics inventory. Washington, DC: Office of Air Qu

;

Planning and Standards, Environmental Protection Agency, 2000 .

8. Environmental Protection Agency and Environment Canada . Mercury sources and regulations : di

1999 update. Binational toxics strategy . Environmental Protection Agency and Environment Can

November 1999 .

9. Environmental Protection Agency . Regulatory finding on the emissions of hazardous air pollutan

electric utility steam generating units. Federal Register 2000;65:79825--31 .

*A BMD of 85 ppb Hg in cord blood or 17 ppm Hg in maternal hair was estimated to result in an increase in the proportion

scores on the Boston Naming Test for children exposed in utero from an estimated background prevalence of 5% to a preval

(6)

. BMDL recommended by NRC is the lower 95% confidence bound of the BMD

.

I References to sites of nonCDC organizations on the World-Wide Web are provided as a service to

MMWR

readers and do

imply endorsement of these organizations or their programs by CDC or the U .S. Department of Health and Human Services

.

responsible for the content of pages found at these sites

.

Table 1

file://C:\Documents%20and%20Settings\epauser\My%20Documents\Mercury\Exhibits\Bl

.

.. 6/30/2006

---

brood and Hair mercury Levels in Young Children and Women of Childbearing Age

TABLE 1 . Selected percentiles and geometric means of blood and hair meri

(Hg) concentrations for children aged 1-5 years and women aged 16-49 ye

.

National Health and Nutrition Examination Survey, United States, 1999

Geometric

Selected percentiles (95% Cl")

* Confidence interval

.

Parts per billion

.

' Limit of detection

.

a Parts permillion

.

" Notcalculated. Proportion cLODtoo high tobevalid

.

Return_

to

top

. .

Disclaimer

All

MMWR

HTML versions of articles are electronic conversions from ASCII text into HTML . This cony'

resulted in character translation or format errors in the HTML version . Users should not rely on this HTML document, but a

the electronic PDF version and/or the original

MMWR

paper copy for the official text, figures, and tables . An original paper

issue can be obtained from the Superintendent of Documents, U.S. Government Printing Office (GPO), Washington, DC 20

telephone: (202) 512-1800. Contact GPO for current prices

.

**Questions or messages regarding errors in formatting should be addressed to mmwrq crcdc.gov .

Page converted: 3/1/2001

HOME

I

ABOUTMMWR

I MMWRSEARCH

I

DOWNLOADS

(

RSS_

I CONTACT

POLICY

I

DISCLAIMER

I

ACCESSIBILITY

1A?fl .

KALT1lltll

. PtiOPL10"

Morbidity and Mortality Weekly Report

Centers for Disease Control and Prevention

1600 Clifton Rd, MailStop K-95, Atlanta, GA 30333

.

USA

This page last reviewed 5/2/01

Page 4 of 4

`'Dcartment

of

Hgalth

,and Human Services

filed/C:\Documents%20and%20Settings\epauser\My%2ODocuments\Mercury\Exhibits\BI

.

.

.

6/30/2006

10th

25th

50th

75th

<LOCH

<LOD

0 .2

(0 .2-0 .3)

0 .5

(0.4-0 .8)

1

0 .2

(0.1-0 .3)

0 .5

(0.4-0 .7)

1 .2

(0.8-1 .6)

2 .7

(1 .8-4 .5)

6

<LOD

<LOD

¢LOD

0 .2

(0.1-0 .4)

0

<LOD

<LOD

0 .2

(0 .2-0 .3)

0,5

(0.4-0 .8)

1

No. mean

(95%CI)

RioodHgr

Children

248

0 .3

(0.2-0 .4)

Women

679

1 .2

(0.9-1 .6)

Hair Hg¶

Children

338

**

Women

702

-

---

Peabodq

Laurel,

Just wanted to letyou know that the Temporary Technology Based Extension is very helpful in addressing

the Prairie State Generating Station concerns . We just have a few comments/clarifications for your

consideration

.

Thanks

.

Dianna

IL Mercury reg Temporary Technology Based ext proposal 3-21 .06_ doc

/~ Iv

~GVr~wi

Dianna Tickner

To

"Laurel Kroack" <Laurel.Kroack@epa .state .il.us>

03/23/2006 04:54 PM

cc

Colin M . Kelly/STL/Peabody@PeabodyEnergy

bcc

Subject Technology Extension for Mercury

---

i

Overview :

To qualify for the Temporary Technology-Based Extension (TTBE), a source must meet

the specific criteria identified in the rule . The most significant criterion is use of an

appropriate configuration of control devices for effective control of mercury emissions,

given the type of coal being fired and the control devices already installed on the unit .

(Refer to Tables 1 and 2.) For existing units, the specified configuration is generally use

of activated carbon injection for control of mercury emissions along with an appropriate

particulate matter control device to assure the effectiveness of carbon injection . In

addition, during Phase 1 of the program, existing units equipped with an appropriate

suite of control devices for effective control of mercury emissions by co-benefit would be

eligible for an extension . For a new unit, the specified configurations for an extension

require use of activated carbon for control of mercury emissions along with use of

appropriate control devices to minimize emissions by co-benefit .

There needs to be an express waiver durinq the extension. For example, "If the

applicant demonstrates compliance with the five criteria

specified under "Contents of a

Request," the mercury standards would not apply or the deadline for compliance would

be extended so lonq as the criterion for the extension are met-

Process :

A source must submit a timely application for a temporary technology-based extension,

containing information showing that the relevant criteria for such an extension are met

.

If the application shows that all relevant criteria are met, i .e., the application is not found

to be incomplete within a nominal period of time, the source can rely on the extension

until the Agency takes final action on the application

. (We believe "the nominal period of

time "for aqency review of the application must be defined ie, 30 days)

The Illinois EPA will conduct a technical review to determine whether an extension is

given or to establish whether any unit-specific requirements should accompany the

extension too assure that the source undertakes optimization measures as required by

criterion 3 and that state-of-the-art mercury control be applied as required by criterion 5

.

There is no opportunity for public participation in the process by which an extension

becomes effective

.

Timing and Duration

The temporary technology-based extension would be available through December

2018, that is, through Phase 1 and up to the first five years of Phase 2 of the mercury

control program . A source would have to submit its application for an extension to the

OVERVIEW OF POSSIBLE PROVISIONS FOR A

TEMPORARY TECHNOLOGY-BASED EXTENSION (TTBEI

3/23+/2006

1

---

Illinois EPA no later than three months before compliance needs to be demonstrated

.

Accordingly, an application for an extension for an existing unit must be submitted by no

later than March 31, 2010 for Phase 1 of the mercury control program, and by no later

than September 30, 2012 for Phase 2 of the program

. What happens if the source has

done evervthinq after extension period and still doesn't meet the limits?

If a source obtains an extension for a unit for Phase 1 of the program, the source must

reapply for the extension for Phase 2 . The source must also reapply for the extension if

there will be a change in the control device configuration of the unit and the source

plans to change its practices for control of mercury emissions based on the change to

the control device configuration

.

Contents of a Request

A request for a temporary technology-based extension for a unit must include information

showing that the applicable criteria for such an extension are met for the unit, as follows

:

1 . The owner or operator of the unit submits a formal request for the extension that : 1)

Explains why an extension is being requested : 2) Describes the measures that have

been taken for control of mercury emissions ; 3) Provides a detailed discussion of the

factors that currently prevent more effective control of the mercury emissions of the

unit, with a summary of relevant mercury emission data for the unit ; and 4) Includes a

copy of the current action plan describing the measures that will be taken during the

term of the extension to improve control of mercury emissions

.

2. The configuration of control devices on the unit is one that qualifies for an extension,

as listed in Table 1 or 2, and the activated carbon injection system, if one is required,

has been properly installed . An alternative sorbent may be used in place of the

halogenated activated carbon if the source demonstrates that the alternative sorbent

either: 1) Has at least the same effectiveness for control of mercury as halogenated

activated carbon; or 2) Will be used in a manner to provide equal or better

effectiveness for control of mercury as would be achieved with halogenated

activated carbon .

3. For a unit for which injection of halogenated activated carbon is required, injection is

occurring at optimal rate(s) . For this purpose, a source must either inject

halogenated activated carbon at a rate of at least 3 and 10 pounds per million cubic

feet of actual exhaust for units fired on sub-bituminous and bituminous coal,

respectively, or at rate(s) that reflect the maximum practicable degree of mercury

removal, based upon a unit-specific evaluation of the relationship between the

injection rate and the removal of mercury, to identify the injection rate at which

increased usage of halogenated activated carbon no longer provides proportionate

improvements in mercury removal

.

4. The owner or operator of the unit has an action plan identifying specific measures

that will be taken during the term of the extension to improve control of the mercury

emissions from the unit. This plan shall address measures such as evaluation of

2

---

alternative forms or sources of activated carbon, changes to the injection system,

changes to operation of the unit that affect the effectiveness of mercury absorption

and collection, changes to the particulate matter control device to improve the

performance of, and changes to other emission control devices

. For each measure

contained in the plan, the plan shall provide a detailed description of the specific

actions that are planned, the reason that the measure is being pursued and the

range of improvement in control of mercury that is expected, and the factors that

affect the timing for carrying out the measure, with the current schedule for the

measure .

5. The owner or operator of a unit utilizing halogenated activated carbon injection

(ACI)

must include a demonstration that halogenated ACI remains the state-of-the-art for

mercury control. If new developments in ACI occur that demonstrate a higher level

of mercury control (e.g., use of more effective sorbents), or if other mercury control

technologies develop that remove mercury at a cost similar to the cost of

halogenated ACI in 2006 dollars, the owner or operator must agree to utilize the

more effective means of ACI or other control technology within a reasonable time

frame.The provision "if other mercury control technoloqies develop" causes us

concern that it could be a continual movinq tarqet and cause qreat concern with the

projects lenders that they could potentially be exposed to hundreds of millions of

costs for retrofit if oriqinal technology does not work to the requlation level . If this

provision is intended just for different sorbents or chemical additives that is

acceptable . However, a requirement to install totally new hardware technologV, for

example if it were determined somethinq like Powerspan was state of the art,

it

miqht be impossible to incorporate that technoloqy into the desiqn once the plant is

constructed with Table 2 required technologV . The costs for the new hardware miqht

be similar, but millions would have already been invested in the original approved

technology increasinq the plants cost dramatically. We recommend removinq

"demonstration of state of the art mercury control" and references to "other mercury

control technoloqies" unless there is further clarification on limitations

.

Consequences of Obtaining an Extension

Sources that obtain a temporary technology-based extension for a unit would have to

continue to operate the unit in accordance with the technology-based criteria that were

the basis of the extension, including implementing an action plan for the unit for the

period of time that extension is in place . Units operating under an extension could not

be included in any compliance demonstrations involving multiple units

. When a source

determines that a unit can comply with the applicable emissions standards for mercury,

the source would notify the Illinois EPA that it is terminating the extension for the unit

.

Thereafter, the source would no longer be required to implement an action plan for the

unit and the unit could be included in compliance demonstrations involving multiple units

in subsequent months

.

A source that is operating a unit under a temporary technology based extension would

be required to submit annual reports describing the activities that are conducted for the

unit to further improve control of mercury emissions, including significant measures that

3

---

were taken during the past year, significant activities that are planned for the current

year, and any changes to the action plans for the unit, with explanation

.

4

---

Table 1 : Required Configuration of Control Devices for Existing Units

5

Primary Type

of Coal

Phase of

Program

Minimum

Control Configuration

Subbituminous

Available for

Both Phase 1

and Phase 2

Cold-side Electrostatic Precipitator or Fabric Filter

and Injection of Halogenated Activated Carbon

Bituminous

Available for

Both Phase 1

and Phase 2

Cold-side Electrostatic Precipitator or Fabric Filter

and Injection of Halogenated Activated Carbon

Available for

Phase 1 only

Selective Catalytic Reduction (SCR) System (located

prior to the particulate matter control device) and S02

Scrubber

Fluidized Bed Boiler: Selective Non-Catalytic Reduction

(SNCR) System and Fabric Filter

---

Table 2 : Required Configuration of Control Devices for New Units

6

Primary

Type

of Coal

Minimum

Control Configuration

Subbituminous

Pulverized Coal Boiler: SCR, SO2 Control Device,

Fabric Filter, and Injection of Halogenated Activated

Carbon

Fluidized Bed Boiler: SNCR, Supplemental SO2

Control System, Fabric Filter and Injection of

Halogenated Activated Carbon

Bituminous

Pulverized Coal Boiler: SCR, High-efficiency PM

Control Device (i.e ., subject to a limit of no more than

0.015 lb/million Btu, as measured by USEPA Method

5), SO2 Scrubber, and Injection of Halogenated

Activated Carbon

Fluidized Bed Boiler: SNCR, Supplemental SO2

Control System, Fabric Filter and Injection of

Halogenated Activated Carbon

Unit Firing Fuel Gas Produced by Coal Gasification:

Processing of the Raw Fuel Gas prior to Combustion

With Systems for PM and Sulfur Removal and with

Activated Carbon for Removal of Mercury

.