Mr. Cole Anderson

WDEQIAQD

Herschler Building

122 W. 25th Street

Cheyenne, Wyoming 82002

RE: BART Conference Call

Alstom Reports

Dear Cole.

- Gener.al ~Chem/eal

June 9, 2010 GREEN RIVER SODA ASH OPERATIONS

P.O. Box 551

GREEN RIVER, WYOMING 82935.0551

(307)-875-3350

Attached are two copies of the correspondence from Alstom as a result of their

visit to the plant to tune C and D Boilers in February 20 IO. They were not attached to the

letter we submitted dated May 27, 2010. A copy was also submitted to Tony Hoyt in

Lander. If you have any questions, please contact me at (307) 872-3445.

;i~CerelY, A () n ·W'1-..~ Michael J. Dah\.

Supr.-Environmental Engineering

CC: Tony Hoyt
Page 1 of!

Dahl, Mike

From: Johler, Paul N.

Sent: Monday, March 15, 2010 12:11 PM

To: Pitts, Randy; Braman, Vic

Cc: Dahl, Mike

Subject: FW: General Chem, Green River: NOx system evaiuation

Randy and Vic,

Here is the response from Art Adams with Alstom giving the reasoning for their recommendation to now go with a

Secondary Over Fire Air (SOFA) system instead of the originally proposed Low NOx Burner (LNB) system. I have more

notes from our conversations and if you are interested in more details or if you have any other questions.

Thanks,

Paul.

From: arthur.adams@power.alstom.com [rnailto:arthur.adams@power.alstom.comj

Sent: Monday, March 15, 2010 11:38 AM

To: Johler, Paul N.

Cc: rnichael.taber@power.alstom.com; jeff.edwards@power.alstom.com; c1iff,oconnell@power.alstom.com

Subject: General Chern, Green River: NOx system evaluation

This is my response to your request on the issue of burner only modifications (our LNCFS P2) versus a SOFA system

(LNCFS 111). Let me know if this is sufficient for your needs. Also, just a reminder from our phone conversation today, you

may wish to try ciosing down the coal air dampers into the 30% open range to see it's impacts on NOx. This test would

be run with the more desirable NOx settings aiready established during the NOx tuning that gave the 0.40 - 0.42 results

on boiler "C",

General Chemical operations, in conjunction with Alstom TS, has completed a baseline evaluation/optimization tuning

effort to establish baseline NOx emissions, Boiler "C" was able to reduce full load NOx from an as found conditionof 0.52

ibs/MBtu down to the 0.40 - 0.42 range. "0" boiler reduction was slightly less going from 0.54Ibs/MBtu down to the 0.45 -

0.46 range after optimization. The proposed Wyoming NOx limit for General Chemical is 0,32 Ibs/MBtu. Alstom has

previously discussed the possibility of using it's patented LNCFS P2 system to reduce NOx. This system historically has

been able to achieve a 10 - 25% reduction in NOx from baseline conditions. The larger reduction capability took into

account tuning optimization which has been completed at Gen Chem, Because of the new optimized baseline, Alstom

wouid predict only an additional 10% reduction or less with the LNCFS P2 hardware. This would not meet the proposed

Wyoming regulation for NOx.

Alstom would recommend an LNCFS III system to meet the target of 0.32 Ibs/MBtu. The LNCFS III is essentially a

separated overfire air (SOFA) system. There would be 4 SOFA registers with 2 located on each boiler sidewall above the

main windbox elevation. Air for the SOFA Is obtained from the secondary air duct upstream of the main windboxes. The

main windbox nozzle tips would be downsized to account for secondary air that is re-distributed to the SOFA registers.

Re-sizing the air nozzle tips is designed to maintain nozzle tip exit velocity's for proper mixing of air and fuel.

CONFIDENTIALITY: This e-mail and any attachments are confidential and may be privileged. If you are not a named

recipient, please notify the sender immediately and do not disclose the contents to another person, use it for any purpose

or store or copy the information in any medium.
Power

Boiler & Environmental Plant Services

March 5, 2010

General Chemical

Mr. Paul Johler

P.O. Box 551

Green River, WY 82935

Re: Units 'C' & '0'

Orignal CE C/N

NOx Optimization Tuning

Attention: Mr. Paul Johler

Dear Paul:

I arrived on site Tuesday February 16, 2010 for MSHA training then began

optimizing NOx on both C and 0 power boilers the following day.

The current NOx limit is 0.7 Ibs/mBTU and the new limit that takes effect in 2011

will be 0.32 Ibs/mBTU. Currently the boilers are reported to operate in the 0.5 to

-------Q,6-llilsfmB+lJ-range-.-+he~G!.-1il0iler2s-0riginal-design-rating-is-4QQ,QQQ-11il8fhr'---­

steam flow and has 2 elevations of pulverized coal. The '0' boiler's original rating

is 600,000 Ibs/hr steam flow and has 3 elevations of pulverized coal.

The plan was to optimize the firing to achieve the lowest NOx for both boilers.

This will give Alstom a base to develop a proposal for retrofitting the boilers to

achieve the new NOx limits of 0.32 Ibs/mBTU.

The windbox dampers are controlled on an elevation basis, remote manual from

the control room. There is no automatic function for either of the auxiliary or fuel

air dampers. The OFA dampers are adjusted locally at the windbox.

The SCAH's are no longer in service so the Ljungstrom air inlet temperatures are

the ambient indoor temperature at the F.D. fan.

The mill feed rate in tons/hr is based on the rpm of a CE Volumetric feeder. The

coal is not weighed as the scales have been out of service for many years.

Except for the low load performance data the boilers were being operated at their

typical daily load demand. They operate near the design MCR on a daily basis

Boiler &Environmental Plant Services Division

Parts & Technical Services 223266th Drive SE Phone: 425.487.0839

Department Bothell. WA 98021 cliff.oconnell@power.alstom.com
General Chemical - Units 'C' & '0' page 2

except for occasional restrictions due to process steam demand or for equipment

being out of service due to problems. .

For reference, the 02 analyzers for both boilers are located after the generating

bank about 3 feet above the centerline of the lower drum, midway between the

lower drum and the rear wall. The 'C' analyzer is on the left side of the boiler.

The '0' boiler analyzer is located on the right side. The analyzers are 'wet' type.

The LOI values on 2-18-10 was 2.5% for the 'C' boiler and 0.75% on the '0'

boiler. Typically they run about 1.5 %or less on LOI. Additional LOI data has

been requested.

The boiler corners are referenced as 1 through 4, with corner 1 in the left/front

and counting clockwise around the boiler.

'C' Boiler

During the tuning the 'A' mill hot air damper was 100% open and the 'B' hot air

damper was about 45% open. The local damper drive indicators were similar for

the 'B' mill but the 'A' mill local indicator said the damper was 'closed'. The mills

were loaded the same so it may be something with the hot air dampers inside the

duct as was discussed with Earl Grange. I recommend that the dampers and the

drives be checked out and calibrations verified during the next maintenance

outage.

An 'as found' performance data was taken before any changes were made to the

boiler. Initially I biased the mills so that the 'B' mill ran a lower coal feed than the

'A'. This was the configuration for the first 5 sets of performance data. Biasing

the mills on this boiler didn't have any noticeable effect.

The OFA dampers have been set at 50% open prior to testing. I opened all of

the dampers to 100% except for corner #2. The corner #2 drive arm slips on the

damper shaft and we could not get the damper to move. This drive arm should

be repaired during the next maintenance outage. Opening the OFA dampers

100% did not significantly affect the NOx.

The OFA dampers have local manual tilt drives. Unfortunately these do not

move. All data was taken with the OFA tilts as shown below. Recommend

repairing these during your next scheduled maintenance outage.

'c" OFASETTING

CORNER

1 Horizontal

2 10 dearees UP

3 Horizontal

4 10 dearees UP

The sootblowers were not blown during the testing but the IK's and the APH

blower were blown during lunch break each day.
General Chemical - Units 'C' & 'D' page 3

I adjusted the windbox dampers to put more air through the 'BB' auxiliary air (top

air) elevation. Opening this up significantly lowered the NOx from a range of

0,48 to 0.52 Ibs/mBTU down to a range of 0.37 to 0.41 Ibs/mBTU.

When putting more air into the 'BB' elevation the windbox/furnace differential

pressure decreases. In order to increase this I closed down on the bottom

auxiliary elevation 'AA'. This immediately resulted in a darker furnace bottom. It

also prevents the operators from observing the conditions in the bottom of the

furnace. Therefore the 'AA' elevation was opened up until the bottom of the

furnace was visible but not as much as before the changes. Later it showed that

this resulted in the f1yash getting increasingly darker than normal. When we went

back to the original setup the NOx value increased as expected and the flyash

also become lighter in color.

'D' Boiler

The corner OFA dampers were found in the following settings, where the range is

oto 5 with 5 being wide open.

'0' OFA SETTING

CORNER

1 3

2 31/2

3 5

4 31/2

Later the dampers were opened and the OFA dampers were set as shown

below:-When+left-the-site-the-dampers-were-still-at-these-settingsi-o-.-------

'D' OFASETTING

CORNER

1 4

2 41/2

3 5

4 5

When putting in more air into the top auxiliary elevation 'CC' the effect wasn't as

noticeable as observed on the 'c' boiler. It is speculated that the elevations may

be partially blocked and therefore opening them doesn't change the airflow very

much.

Later after the OFA dampers were opened and the windboxllfurnace differential

pressure was increased from 3" w.g. to 4.5" w.g., no significant change here

either. The best results were when the O2 lowered back down.

The OFA tilts on this boiler as found:
General Chemical· Units 'C' & '0'

10'- OFASETTING

CORNER

1 5 dearees UP

2 10 demees UP

3 10 dearees UP

4 10 dearees UP

Then they were changes as follows:

-'0' OFASETTING

CORNER

1 10 dearees UP

2 10 dearees UP

3 15 dearees UP

4 20 dearees UP

page 4

It wasn't possible to change the tilts very much. And therefore no significant

change in the NOx was observed. Recommend repairing the OFA tilts and

dampers during the next maintenance outage.

Exhauster setup

In reviewing the data the mill exhauster discharge pressures for any given mill

never changed. The reading was taken from the analog pressure gauges in the

control room and I was told that that those indications are dampened. They

appear to be low so I inqUired how the exhauster inlet damper is setup. In order

to get the maximum discharge pressure it is recommended to adjust the inlet

damper as stated below. This information that is directly out of the instruction

.--_. -----manIJals-f0r-these-b0i1eFs,~.----------------- _

It is recommended to run clean airflow tests on all pulverizers. Due to the use of

ceramics and also because no clean air test has been performed in a long time.

If the airflows were higher than necessary then this could result in the NOx

increasing.

EXHAUSTER INLET DAMPER Operation

The following procedure shall be used when setting up the exhauster inlet damper.

Minimum Exhauster Inlet Damper Setting (INITIAL)

1. Set the exhauster inlet damper so that it opens 100 percent at 100 percent stroke of its drive

unit.

2. Determine the clean air exhauster discharge pressure with the mili set up per the clean

airflow test procedure.

3. For tangential fired units determine the damper setting which gives a clean air exhauster

discharge pressure equal to 70 percent of the value obtained in Step 2 above.
General Chemical· Units 'C' &'OJ page 5

4. The setting obtained in Step 3 is the temporary minimum exhauster inlet damper setting and

should be established as a minimum with a temporary mechanical stop. The damper drive

control unit should be temporarily stroked between this minimum and 100 percent open.

5. There should be a straight line relationship between feeder speed and exhauster inlet

damper position, as feeder speed is increased from minimum to maximum and damper

position moves from minimum to maximum.

Minimum Exhauster Inlet Damper Setting (FINAL)

1. Determine the exhauster discharge pressure available with the miii loaded to its design

capacity and exhauster discharge damper is 100 percent open.

2. For tangential fired units compute 60 percent of the value obtained in Step 1 above.

3. Set the final exhauster inlet damper minimum to give the discharge pressure from Step 2

while operating the feeder at its minimum position. Permanently fix the mechanical stop.

4. Make finai control adjustment between minimum and fuii open. This should be a straight-line

reiationship between feeder speed and exhauster damper position. This should result in 100

percent airflow at 100 percent feeder speed and a somewhat lower airflow at minimum feeder

speed. This resuits in the Optimum Air Flow Curve.

If you have any questions about performing a clean air flow test or setting up the

exhauster inlet damper please ask. It was a pleasure working at your plant and

everyone was extremely helpful during the testing.

Sincerely yours

---- ~--------------eliff-e!eonnell---------~-­

Consulting Engineer

Technical Services
Reviewer . _''-''!:-', _

Copy to:

CynthiJl _ D.E. _

File: __15>8'D7

May 27, 2010

GREEN RIVER SODA ASH OPERATIONS

P.O. Box 551

GREEN RIVER, WYOMING 82935-0551

(307)-875-3350

Mr. Chad Schlichtemeier

WDEQ/AQD

Herschler Building

122 W. 25th Street

Cheyenne, Wyoming 82002

RE: Conference Call 5/12/10

BART Permit

Dear Chad:

The Division and General Chemical held a conference call regarding BART

Permit 6046, General Chemical is responding to the items addressed in the meeting.

In October 2009, General Chemical established a target limit for C and D Boilers

by artificially lowering the compliance limit alarm in the Powerhouse Control Room

from 0,7 Lbs. NOx/MMBTU to 0.60 Lbs. NOx/MMBTU limit. This was done to

motivate the operators to make adjustments to the boilers and reduce the NOx as much as

possible. C Boiler was operating between 0.53 and 0.60 and D Boiler was operating

between 0.54 and 0.60 during this time period. In the time period of December 2009

tluough mid-Febmary, General Chemical began making adjustments to air and oxygen

levels to lower the NOx even further, prior to contracting Alstom for boiler ttming.

During this time, C Boiler was operating between 0.42 and 0.53 and D Boiler was __

opeliting between 0.50 and 0.59.-Alstom began boiler tuning on Febmary 17,2010 for a

week. Numerous adjustments to a variety of parameters were made on both boilers to

minimize NOx. Since that time, C Boiler has operated in the range of 0.44 to 0.53 and D

Boiler in the range of 0.51 to 0.55. The tuning exercise demonstrated that the boilers

were operating at an efficiency greater than Alstom expected, which led them to conclude

that LNB would not provide a substantial improvement to NOx control or reductions to

meet 0.32 Lbs.lMMBTU. Alstom's correspondence to General Chemical is attached.

As we noted in the meeting, C Boiler was more responsive to tuning than D

Boiler and a more significant reduction was achieved. Based upon tuning efforts and

recommendations provided by Alstom, General Chemical proposes interim limits of .53

and .55 Lbs. NOx per MMBTU for C and D Boilers respectively, utilizing a 30-day

rolling average. In addition, we are working to get Alstom or Storm to the plant during

the upcoming boiler outages to inspect, adjust and make as many repairs to the boilers

noted during their boiler inspection as time allows.
Regarding permit limits, General Chemical is committed to the installation of

SOPA with the option to install an equivalent technology that will meet 0.28 Lbs.

NOjMMBTU based on a 3D-day rolling average. C Boiler installation would take place

in 2014 and D Boiler in 2015. Engineering work must be completed by the manufacturer

prior to receiving a guarantee for the 0.28 Lb.lMMBTU NOx•

If you have any questions regmding this response, please contact Mike Dahl at

(307) 872-3445.

Sincerely,

e~M'Ir:f 4 i'lf

Randy Pitts

Plant Manager

-----.--
Power

Boiler & Environmental Plant Services

March 5, 2010

General Chemical

Mr. Paul Johler

P.O. Box 551

Green River, WY 82935

Re: Units 'C' & '0'

Orignal CE C/N

NOx Optimization Tuning

Attention: Mr. Paul Johler

Dear Paul:

I arrived on site Tuesday February 16, 2010 for MSHA training then began

optimizing NOx on both C and 0 power boilers the following day.

The current NOx limit is 0.7 Ibs/mBTU and the new limit that takes effect in 2011

will be 0.32 Ibs/mBTU. Currently the boilers are reported to operate in the 0.5 to

0.6 Ibs/mBTU range. The 'C' boiler's original design rating is 400,000 Ibs/hr

----- steam-f1ow-and-has-2-elevations-of-pulverized_coal._Tbe-'D-'-b.ojler~s_ori.ginaL[ating _

is 600,000 Ibs/hr steam flow and has 3 elevations of pulverized coal.

The plan was to optimize the firing to achieve the lowest NOx for both boilers.

This will give Alstom a base to develop a proposal for retrofitting the boilers to

achieve the new NOx limits of 0.32 Ibs/mBTU.

The wind box dampers are controlled on an elevation basis, remote manual from

the control room. There is no automatic function for either of the auxiliary or fuel

air dampers, The OFA dampers are adjusted locally at the windbox.

The SCAH's are no longer in service so the Ljungstrom air inlet temperatures are

the ambient indoor temperature at the F.D. fan.

The mill feed rate in tons/hr is based on the rpm of a CE Volumetric feeder. The

coal is not weighed as the scales have been out of service for many years.

Except for the low load performance data the boilers were being operated at their

typical daily load demand. They operate near the design MCR on a daily basis

Boiler & Environmental Plant Services Division

Parts & Technical Services 22326 6ffi Drive SE Phone: 425.487,0839

Department Bothell. WA 98021 c1iff,occnnell@power,alslom,com
General Chemical - Units 'C' & '0' page 2

except for occasional restrictions due to process steam demand or for equipment

being out of service due to problems.

For reference, the 02 analyzers for both boilers are located after the generating

bank about 3 feet above the centerline of the lower drum, midway between the

lower drum and the rear wall. The 'C' analyzer is on the left side of the boiler.

The '0' boiler analyzer is located on the right side. The analyzers are 'wet' type.

The LOI values on 2-18-10 was 2.5% for the 'c' boiler and 0.75% on the '0'

boiler. Typically they run about 1.5 %or less on LOI. Additional LOI data has

been requested.

The boiler corners are referenced as 1 through 4, with corner 1 in the lefUfront

and counting clockwise around the boiler.

'C' Boiler

During the tuning the 'A' mill hot air damper was 100% open and the 'B' hot air

damper was about 45% open. The local damper drive indicators were similar for

the 'B' mill but the 'A' mill local indicator said the damper was 'closed'. The mills

were loaded the same so it may be something with the hot air dampers inside the

duct as was discussed with Earl Grange. I recommend that the dampers and the

drives be checked out and calibrations verified during the next maintenance

outage.

An 'as found' performance data was taken before any changes were made to the

boiler. Initially I biased the mills so that the 'B' mill ran a lower coal feed than the

'A'. This was the configuration for the first 5 sets of performance data. Biasing

the mills on this boiler didn't have any noticeable effect.

--1=heGFAaampers-have-been-set-at-5Q%-open-prior-to-testing~l-opened-all-of-­

the dampers to 100% except for corner #2. The corner #2 drive arm slips on the

damper shaft and we could not get the damper to move. This drive arm should

be repaired during the next maintenance outage. Opening the OFA dampers

100% did not significantly affect the NOx.

The OFA dampers have local manual tilt drives. Unfortunately these do not

move. All data was taken with the OFA tilts as shown below. Recommend

repairing these during your next scheduled maintenance outage.

Ie" OFA SETTING

CORNER

1 Horizontal

2 10 degrees UP

3 Horizontal

4 10 degrees UP

The sootblowers were not blown during the testing but the IK's and the APH

blower were blown during lunch break each day.
General Chemical· Units 'C' & 'D' page 3

I adjusted the windbox dampers to put more air through the 'BB' auxiliary air (top

air) elevation. Opening this up significantly lowered the NOx from a range of

0.48 to 0.52 Ibs/mBTU down to a range of 0.37 to 0.41 Ibs/mBTU.

When putting more air into the 'BB' elevation the windboxlfurnace differential

pressure decreases. In order to increase this I closed down on the bottom

auxiliary elevation 'AA'. This immediately resulted in a darker furnace bottom. It

also prevents the operators from observing the conditions in the bottom of the

furnace. Therefore the 'AA' elevation was opened up until the bottom of the

furnace was visible but not as much as before the changes. Later it showed that

this resulted in the flyash getting increasingly darker than normal. When we went

back to the original setup the NOx value increased as expected and the flyash

also become lighter in color.

'D' Boiler

The corner OFA dampers were found in the following settings, where the range is

oto 5 with 5 being wide open.

'0' OFASETTING

CORNER

1 3

2 31/2

3 5

4 31/2

Later the dampers were opened and the OFA dampers were set as shown

below. When I left the site the dampers were still at these settings. _.~-

- ------_._---~-

'0' OFA SETTING

CORNER

1 4

2 41/2

3 5

4 5

When putting in more air into the top auxiliary elevation 'CC' the effect wasn't as

noticeable as observed on the 'C' boiler. It is speculated that the elevations may

be partially blocked and therefore opening them doesn't change the airflow very

much.

Later after the OFA dampers were opened and the windboxllfurnace differential

pressure was increased from 3" w.g. to 4.5" w.g., no significant change here

either. The best results were when the O2 lowered back down.

The OFA tilts on this boiler as found:
General Chemical - Units 'C' & '0'

lOP OFA SETTING

CORNER

1 5 de!lrees UP

2 10 de!lrees UP

3 10 degrees UP

4 10 de!lrees UP

Then they were changes as follows:

"0' OFASETTING

CORNER

1 10 dearees up

2 10 dearees UP

3 15 dearees UP

4 20 degrees up

page 4

It wasn't possible to change the tilts very much. And therefore no significant

change in the NOx was observed. Recommend repairing the OFA tilts and

dampers during the next maintenance outage.

Exhauster setup

In reviewing the data the mill exhauster discharge pressures for any given mill

never changed. The reading was taken from the analog pressure gauges in the

control room and I was told that that those indications are dampened. They

appear to be low so I inquired how the exhauster inlet damper is setup. In order

to get the maximum discharge pressure it is recommended to adjust the inlet

damper as stated below. This information that is directly out of the instruction

manuals for these boilers.

It is recommended to run clean airflow tests on all pulverizers. Due to the use of

ceramics and also because no clean air test has been performed in a long time.

If the airflows were higher than necessary then this could result in the NOx

increasing.

EXHAUSTER INLET DAMPER Operation

The following procedure shall be used when setting up the exhauster inlet damper.

Minimum Exhauster Inlet Damper Setting (INITIAL)

1. Set the exhauster inlet damper so that it opens 100 percent at 100 percent stroke of its drive

unit.

2. Determine the clean air exhauster discharge pressure with the mill set up per the clean

airflow test procedure.

3. For tangential fired units determine the damper setting which gives a clean air exhauster

discharge pressure equal to 70 percent of the value obtained in Step 2 above.
General Chemical· Units 'C' & 'D' page 5

4. The setting obtained in Step 3 is the temporary minimum exhauster inlet damper setting and

should be established as a minimum with a temporary mechanical stop. The damper drive

control unit should be temporarily stroked between this minimum and 100 percent open.

5. There should be a straight line relationship between feeder speed and exhauster inlet

damper position, as feeder speed is increased from minimum to maximum and damper

position moves from minimum to maximum.

Minimum Exhauster Inlet Damper Setting (FINAL)

1. Determine the exhauster discharge pressure available with the mill loaded to its design

capacity and exhauster discharge damper is 100 percent open.

2. For tangential fired units compute 60 percent of the value obtained in Step 1 above.

3. Set the finai exhauster inlet damper minimum to give the discharge pressure from Step 2

while operating the feeder at its minimum position. Permanentiy fix the mechanical stop.

4. Make final control adjustment between minimum and full open. This should be a straight-line

relationship between feeder speed and exhauster damper position. This should result in 100

percent airflow at 100 percent feeder speed and a somewhat lower airflow at minimum feeder

speed. This results in the Optimum Air Flow Curve.

If you have any questions about performing a clean air flow test or setting up the

exhauster inlet damper please ask. It was a pleasure working at your plant and

everyone was extremely helpful during the testing.

Sincerely yours

Cliff O'Connell

Gonstllting-Engineer

Technical Services
I

Date: 3-5-2010 I

TEST As Found 1 2 I

I 3 4 5 6 7 8 9 10

DATE 2/18/10 2/18/10 2/18110j 2/18/10 2/18/10 2/18/10 2/19/10 2/19/10 2/19/10 2/19/10 2/22/10

TIME 7:53AM 9:04 AM 9:55 AM 1:10 PM 2:30 PM 3:00 PM 9:35AM 10:23AM 11:19AM 2:15 PM 10:15 PM

C Boiler

Steam Flow k#/hr 380.027 379.288 382.219 376.238 384.881 382.037 381.112 390.212 380.012 380.344 303.321 I

FWFlow% 74 74 74 73 75 74 74 76 74 74 59

FW Flow k#/hr NA NA NA INA NA NA NA NA NA NA 296.103

Drum Press psig 656 656 656 655 650 657 654 659 654 647 633 I

FW Press psig 880 878 884 879 881 878 888 882 882 878 885 I

SH Out Temp F 743 735 735, 740 732 736 728 732 725 731 735

FWTemp F 252 252 252 253 253 251 252 252 252 252 251

I

02 % boiler outlet 3.2 3.2 3.3 3.0 3.2 3.2 3.1 3.2 3.2 3.1 5.0

WB Press in. WG 4.2 4.0 40 4.5 3.7 3.9 4.0 4.5 3.5 3.4 2.9 I

Fum Press in. WG -0.5 -0.5 -0.5 -0.5 -0.5 -0.5 -0.6 -0.4 -0.6 -0.6 -0.6 I

S02 #/mBTU 1.09 1.17 1.19 1.25 1.26 1.28 1.36 1.35 1.31 1.26 1.14

S02 ppm NA NA NA INA NA NA 509.00 515.00 501.00 490.00 394.00

CO ppm 0.73 0.61 0.83 0.83 0.83 0.83 0.55 0.55 0.55 0.83 0.28 I

02 CEMS % 6.5 6.4 6.3 6.0 5.9 6.1 6.2 6.1 6.4 6.3 7.6 I

NOx #/mBTU 0.52 0.52 0.50 0.41 0.42 0.42 0.48 0.46 0.40 0.43 0.47 I

NOx ppm 286 251 253, 202 212 215 242 240 202 207 210

Opacity % 18.90 18.90 18.5ID 15.30 22.39 14.60 18.79 17.07 15.08 16.79 18.30

1- Windbox dampers %

OFA 50 50 * - 50 -- -- 50 50 50 I

BB top aux air 80 80 8ID, 50 60 60 60 45 55 45 55

B coal 80 80 8ID, 80 80 80 80 80 80 80 87

AB aux air 75 75 75, 75 75 75 70 70 70 90 90

A coal 75 75 75, 75 75 75 75 75 75 75 80

AA bottom aux air 55 55 55 80 65 60 60 60 60 60 65

I

APH In Temp F 92 93 95 96 97 96 90 90 91 98 83 I

APH OutTemp F 510 516 518 520 523 524 513 513 519 525 494 I

APH Gas In Temp F 620 623 625 620 626 629 625 629 631 625 593 I

APH Gas Out Temp F 354 359 36ID 360 364 364 356 356 361 364 338
I

!

A Mill Disc. Press in.WG 7.0 7.0 7.q 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0

A Mill out Temp F 145 140 140 141 139 139 143 143 142 139 144

A Mill Amp 64 72 74 73 73 74 65 67 66 74 53

A Mill feed rate % 56 64 64 61 61 63 57 56 53 61 41

A Mill Flow Tons/hr 13.1 14.3 14.3 13.8 13.9 14.1 13.2 13.0 12.6 13.9 10.7

A Mill Hot Air Damper % 100 100 100 100 100 100 100 100 100 100 86

I

B Mill Disc. Press. In.WG 6.5 6.5 6.5 6.6 6.4 6.4 6.2 6.2 6.2 6.2 6.2 I

B Mill out Temp F 149 149 149 149 150 149 149 149 150 150 53

BMiliAmp 64 57 57[ 57 57 57 65 67 66 56 31

B Mill feed rate % 49 38 36 38 38 39 52 53 51 39 9

B Mill Flow Tons/hr 11.93 10.19 989 10.07 10.19 10.38 12.4 12.6 12.3 10.4 62.0

B Mill Hot Air Damper % 50 42 49 42 46 43 42 42 42 54 54 I

FD Damper % 84 81 82, 82 78 80 81 91 80 73 62

FDfan RPM 3839 3839 3839, 3839 3844 3840 3842 3840 3839 3840 3839

ID Damper % 63 63 64, 61 61 64 61 68 65 59 44

IDfan RPM 3925 3925 3925 3925 3925 3925 3925 3923 3925 3925 3924

I

,

FD fan disc Press in.WG 9.5 9.5 9.5 9.7 9.5 9.5 9.7 9.7 9.3 8.5 7.0 , Ljung AH Air in inWG 9.5 9.5 9.5 9.7 , 9.5 9.5 9.7 9.7 9.3 8.5 7.0

Ljung AH Air in in.WG 5.0 5.0 4.5 5.5 4.5 4.5 4.8 5.0 4.8 3.5 3.2 , Tubular AH Air out in.WG 4.1 4.1 3.9 5.0 3.8 3.8 3.7 4.1 3.2 2.8 2.2

Tubular AH Gas in in.WG NA NA NA INA NA NA NA NA NA NA NA

Tubular AH Gas out in.WG -4.3 -4.2 -4.2 -4.0 -4.0 -4.0 -4.0 -4.1 -4.2 -4.4 -3.2

Ljung AH Gas in in.WG NA NA NA INA NA NA NA NA NA NA NA

Ljung AH Gas out in.WG -10.0 -10.0 -10.G -9.5 -9.7 -9.7 -9.5 -10.0 -10.0 -10.0 -7.5

!

ID fan disc. Press. in.WG -0.15 -0.15 -0.15 -0.15 -0.15 -0.15 -0.15 -0.15 -0.15 -0.15 -0.15

Barometric Press. mm Hg na na na I na na na 607.9 607.9 607.9 607.9 608.0

• Corner 1 is 100% open whiie other 3 corners are 50% open.

/\A Corner 2 is 50% open while other 3 corners are 100% o~en

... Corner 2 is 50% open whiie other 3 corners are 100% closed

I
AECOM

AECOM Environment

1601 Prospect Parkway, Fort Collins, Colorado 80525

T 970.493.8878 F 970.493.0213 www.aecom.com

December 12, 2008

Mr. Cole Anderson

Air Quality Engineer

Wyoming Department of Environmental Quality

Air Quality Divison

Herschler Building

122 West 25th Street

Cheyenne, WY 82002·

RE: Revised BART Analysis for the Green River Works (AP-6046)

Dear Mr. Schlichtemeler:

On the behalf of our client, General Chemical, and in response to your letter of November 4,2008,

AECOM is submitting the enclosed Revised Best Available Retrofit Technology (BART) Analysis Report

for the Green River Works. This revision incorporates your requested evaluation of Low NO, Burners

with Separated Overfire Air, which reduces emissions to the levels specified in the Division's BART

analysis.

If you have any questions regarding this submittal, please contact Dr. Bruce Macdonald at

(970) 530-3500.

Regards,

"1:(t<:~t{

Mi6naelze5ell~~----- .. \.-.

Senior Program Manager

Air Resources

michael.zebell@aecom.com

AECOM Environment

J)~~~~_._. ----'·Bruce C. Macdonald, Ph.D.

Vice President

Regional Air Quality Practice Leader

bruce.macdonald@aecom.com
Prepared for:

General Chemical Soda Ash Partners

Green River, Wyoming

Response to Comments for the BART

Analysis - General Chemical Green

River Works

AECOM Environment

Decem ber 2008

Document No.: 02999-022

AECOM
Prepared for:

General Chemical Soda Ash Partners

Green River, Wyoming

Response to Comments for the BART

Analysis - General Chemical Green

River Works

Prepared By: Micha~1 Zebell, PE "

Reviewed By: Bruce MacDonald

AECOM Environment

December 2008

Document No,: 02999·022

AECOM
Contents

1.0 Introduction 1·1

2.0 Summary of Previous BART Work 2·1

3.0 Consideration of Emission Control Alternatives 3·1

3,1 NOx Combustion Controls """ " ", ..",,,.. , ,,,,,,,, ,,.,, ,.. ',, ,,,., ,,,,,,..",,,,,,., 3·1

3,1 ,1 NOx Control Tech nical Feasibility"",,,," "".." , " '""""" '...",,,,,,,",,".." "",". 3-1

4.0 Emission Reductions for BART Cost Evaluation 4·1

4.1 Actual Annual Emissions Baseline , ,.." ".., ",,,,,, .. ,,,,,,,, ,,,,,..,'..,,..,,, 4·1

4.2 Effectiveness and Economic Analysis of NOx Emission Control Alternatives """" ,,,..,,,, ,.. ,.. .4·1

4,2.1 Costs for Boiler C NOx,,,... ,, , ,, ,,,,, ,,,..,,, ..,'......,,, ..,,,.,,........,,,' "" ,,, ,,4·2

4,2.2 Boiler D NO, ,,, , ,,,,,,' .. ,,,.,, ,,,,,,, ,,.,,,," ,,.,, ,,.,,, ,,, .. ,,,,,."."."." " 4-2

5.0 Selection of Control Scenarios 5·3

5,1 Control Options Modeling Emission Rates" , ""..,.." "" ",..",,, ,,, ,,, " 5-3

5,2 Control Scenario Options for Evaluation " .."" """ ".".." , , , ,.. , " ,.. 5-5

6.0 Selection of the Best Alternative for BART Control 6·1

6,1 Summary of Results "",..,,, .... ,,,.........,.......,...." .... , ,,, , ,,,,,,,'.. ,, ,,, ..,'"' ,.."." ,,., 6-1

6,2 Annualized Cost for Implementing Control versus Decrease in Visibility ImpairmenL.." , ,6·1

List of Appendices

Appendix A Cost Analyses for BART Control Options

Appendix B Cost Quote from Aistom Power

J:\200012999-022-Gen_Chem-BART\Final BART

Reporl\Gen Chem BART Response Dec-12,doc

December 2008
List of Tabtes

Table 4-1

Table 4-2 .

Table 4-3

Table 5-1

Table 5-2

Table 6-1

Baseline Annual Average Emissions for 2001-2003 .4-1

Cost Evaluation of NOxcontrols for Boiler C 4-2

Cost Evaluation of NOxcontrols for Boiler D .4-2

Emission Rates for Visibility Evaluation for LNB and LNB+SPFA 5-3

Visibility Modeling Results 5-4

Tabulation of Visibility Improvement at Jim Bridger Wilderness Area and Annual Costs for Each

Control Option 6-1

J:\2000\2999-022-Gen_Cllem-BART\Final BART

Report\Gen Chern BART Response Dec-12.doc

ii December 2008
1.0 Introduction

Federal regulations under 40 Code of Federal Regulations (CFR) 51 Appendix Y provide guidance and

regulatory authority for conducting a visibility impairment analysis for designated eligible sources. The

regulations are provided in Wyoming Air Quaiity Standards and Regulations, Chapter 6, Section 9. The

program requires the application of Best Available Retrofit Technology (BART) to those existing eligible

sources in order to help meet the targets for visibility improvement at designated Class I areas. The Wyoming

Department of Environmental Quality (WDEQ) identified two coal-fired boilers, Boilers C and D, at the General

Chemical facility in Green River, Wyoming, (General Chemical- Green River) as two BART-eligible emission

units.

The Wyoming BART program requires that BART-eligible sources perform a site-specific BART analysis

including a control technology review and CALPUFF modeling to assess the visibility impact of the emission

units. General Chemical- Green River conducted a BART review and provided a report to WDEQ (BART

Analysis for the General Chemical Green River Works, March 2007). The conclusion of that report is that

installation of Low NO, Burners (LNB) represents BART for Boilers C and D. WDEQ made a draft

determination for public review based on the information submitted by General Chemical- Green River, and

received comments on the draft determination. In response to those comments, WDEQ requests that General

Chemical evaluate additional state-of-the-art control levels achievable through application of LNB with

separated over-fire air (LNB+SOFA) to reduce emissions below the levels specified in the original BART

determination.

This report documents the application of LNB and LNB+SOFA as representing BART for Boilers C and D at

General Chemical- Green River using updated additional information from the March 2007 analysis. The NO,

control technologies evaluated in the original BART determination included both post-combustion controls and

combustion controls as follows:

• Post-Combustion Controls

Selective catalytic reduction (SCR);

Selective non-catalytic reduction (SNCR);

• Combustion Controls:

LNB; and

LNB+SOFA.

In the March 2007 report the post-combustion controls were determined to be too costly relative to the amount

of emission control and visibility impact improvement gained (benefits) through application of those

technologies. Of the two combustion control techniques evaluated in the original BART determination, LNB

+SOFA was shown to be too costly relative to the benefits; however, this conclusion was not clearly

communicated and this response to comments is designed to ciarify that conclusion. In addition, the costs of

LNB and LNB+SOFA have been revised from the originai report based on additional information from Alstom

Power Systems.

1-1 December 200B
2.0 Summary of Previous BART Work

The follow'lng is a brief summary of the March 2007 BART report submitted by General Chemical- Green

River and subsequent WDEQ review and draft BART determination. There are no near-term limitations on the

useful life of Boiler C and D. These units, along with the other non-BART eligible gas-fired boiler provide

on-site steam and electric power for mining and ore processing operations. The boiler house containing all

three boilers is located within a compact area at the facility. Boilers C and D are tangentially fired using low

sulfur bituminous coal. Boiler C has a totai heat rate input of 534 million British Thermal Units per hour

(MMBtu/hr) and Boiler D is rated at 880 MMBtu/hr. Given the limited area at the site, coal is received ready for

firing, without on site long-term storage, pre-sizing, or coal biending. Both boilers are equipped with in-line

pulverizers that prepare the coal for direct introduction into the combustion zone. Particulate emissions from

both boilers are controlled by separate hot-side electrostatic precipitators (ESP) which vent through

independent stacks that penetrate and extend above the boiler house roof.

The facility is currently operating under an operating permit number 30-123-1 issued by the WDEQ. The

emission limits for the units are as follows:

Particulate Matter (PM)

Oxides of Nitrogen (NOxl

Sulfur Dioxide (S02)

0.10 Ib/MMBtu

0.7Ib/MMBtu

1.2 Ib/MMBtu

Both units are subject to Wyoming Air Quality Standards and Regulations (WAQSR) Chapter 5, Section 2 and

40 CFR Part 60 Subpart D - Standards of Performance for Fossil-Fuel Fired Steam Generators. Both units are

eqUipped with continuous emission monitoring systems (CEMS) for NOxand S02 emissions, and data are

maintained in pounds-per-MMBtu (lb/MMBtu) for each hour recorded. Periodic monitoring via Method 5

(40 CFR 60 Appendix A) source testing is conducted to demonstrate compliance with the PM limits, and a

Compliance Assurance Monitoring (CAM) plan has been proposed for demonstrating continuous compliance

with the PM limits.

The BART Air Modeling Protocol issued by WDEQ in September, 2006 defines visibility impairing baseline

emissions as the maximum-24'hour aellfaleni'lssi6n rates-foftfieyears20Ql through2003.-T-heseemissTons

represent a realistic depiction of anticipated annual emissions for the source. These baseline emissions were

used in the original report as the basis for estimating annual emission reductions for the various control

technologies evaluated and determining the annualized costs to achieve those reductions. The baseiine

analysis showed that the permit limits were representative of the maximum 24-hour actual emissions for the

purposes of the BART analysis. The facility used the permit limits as representative of maximum emissions for

the per'lod from 2001-2003 and as the basis for determining baseline (pre-BART) em'lssion rates. The original

BART determination concluded that BART for General Chemical- Green River is controlling NO, emissions

from the baseline emission rate of 0.7 to 0.49 Ib/MMBtu.

2-1 December 2008
3.0 Consideration of Emission Control Alternatives

The following is a description of the LNB and LNB+SOFA NO, control systems under consideration. The level

of boiler work required to install each of these systems varies significantly. Installation of LNB is a matter of

changing the existing burners and replacing them with burners with a different configuration in the same

space. Installation of LNB+SOFA requires extensive modification of the boiler windbox where new air ports

are installed, air supply provided, and operator interface control provided.

3.1 NOx Combustion Controls

Based on review of the literature and discussions with vendors, two levels of combustion modifications and low

NO,burners have been identified as available for retrofit of tangentially fired boilers equipped like those at

General Chemical- Green River. The combustion controls and the level of control provided are as follows:

• LNB for an additional 10 to 30 percent control; and

• LNB+SOFA for an additional 25 to 45 percent control.

Due to the small size, age, and design of the Combustion Engineering boilers at General Chemical- Green

River, as well as the NOx controls already in place, the retrofit of low NOx combustion control options is

practically limited to the two options noted above and described below.

The low NOxburner market is a mature and cost-competitive business. A variety of manufacturers have

developed competitive LNB and LNB+SOFA systems. In a retrofit application, the applicability of various

product offerings and site-specific cost factors vary from boiler to boiler. For the purpose of this analysis, the

analysis included obtaining data from Alstom Power Systems.

A desktop study was conducted to evaluate the alternative levels of control, feasibility, emission reduction

potential, and costs associated with installing NOx controls of Boilers C and D. Alstom's LNCFSTM_P2 system

(LNB) represents advancement in coal combustion technology for tangentiaily fired units. The system was

developed to offer the advantages of significant NOx reduction through simple nozzle tip replacement. There

are three main components to the LNCFSTM_P2 system; the P2 coal nozzle tip and vaned close coupled

overfire air, and concElntricfiring system"i! nozzle tips.

Alstom's LNCFSTM Level II (LNB+SOFA) is a more aggressive NOx reduction firing system which also could

be retrofitted to the General Chemical- Green River boilers. The system utilizes the same general

components described for LNCFSTM P2 system above, with the addition of a new SOFA System. The SOFA

system employs a staged combustion process that diverts secondary air from the main windbox and injects it

into the furnace above the main firing zone. This staged combustion process is one of the first principles of

aggressive NOx reduction. The air is introduced into the furnace through a dedicated SOFA windbox mounted

above the main wlndbox. Typically, the SOFA windboxes are corner-mounted, but this can vary based upon

the particular geometry of the boiler and local interferences.

3.1.1 NOx Control Technical Feasibility

Both of the two NOx control technolog'les described above are technically feasible and are evaluated further in

the following sections.

3-1 December 2008
4.0 Emission Reductions for BART Cost Evaluation

4.1 Actual Annual Emissions Baseline

The estimated reduction in emissions from the annual baseline is used to evaluate the potential costs and

benefits of each technically feasible retrofit technology. While the visibility analysis uses the potential 24-hour

allowable emissions for NOx, the BART cost evaluation is based on actual annual emissions for 2001 through

2003. The annual NOx emissions are used as reported for the three years and is shown in Table 4·1.

Table 4-1 Baseline Annual Average Emissions for 2001-2003

Data provided in ton/year

Pollutant Year C Boiler D Boiler

NO, 2001 1015.9 1436.2

2002 1147.2 1441.9

2003 1009.2 1527.1

Average 1057.4 1468.4

4.2 Effectiveness and Economic Analysis of NOx Emission Control Alternatives

Detailed cost data for NOxcontrol are included in Appendix A. A cost quotation form Alstom Power Systems

is included in Appendix B. The data include assumed components of capital and operating costs, as shown

in each table. Aside from the standard capital and operating costs, there are addWonal costs associated with

modifications to existing units at this site. These are the costs for replacement energy to provide steam and

electricity when the existing units are being modified, the costs of lost production (fractional revenue stream)

and the costs for demolition of existing structures and reconstruction within or near the existing units. This

analysis assumes that lost production revenue would not be included in the cost of installation. The lost

revenue wouid be based on the marg'lnal return (sales minus costs) for product, but market conditions dictate

the magnitUde of this cost, and with this uncertaintyit is notincludedhere.

For operating while one of the units is down for instailation of a new control device, the faciiity would use the

natural gas fired E-boiler. The E-boiier can generate up to 350,000 Ibs/hour of steam, while the C and D

boiiers generate up to 400,000 and 660,000 Ibs/hour of stearn, respect'lvely. The E-boiier has a heat input

rating of 490 MMBtu/hour, the C boiler has a heat input rating of 534 MMBtu/hour and the D boiler has a heat

input rating of 880 MMBtu/hour. The E-boiler can therefore replace only a portion of the C and D boiler steam

demand.

Replacement energy costs during downt'lme are accounted for by assuming that retrofits would be made for

each boiler at different times. The cost analyses assume natural gas costs of $10/MMBtu for operation of the

natural gas fired boiler (Boiler E) and coal costs of $2/MMBtu for a cost differential of $8/MMBtu. Therefore the

cost of the replacement steam is $94,000 per day (490 MMBtu/hr X $8/MMBtu X 24 hr/day) for either unit. The

downtime associated with Installation of each system is assumed to be 1-week beyond the normal turnaround

t'lme for LNB and 5-weeks beyond the normal turnaround t'lme for LNB + SOFA.

The replaced energy cost for these periods would apply to each of the Installed systems. At $94,000 per day,

the cost is approXimately $658,000 for the LNB options and $3,290,000 for the LNB + SOFA option. The

estimate is based on a 20 year period at 7 percent interest.

4-1 December 2008
Alstom's review of the current design and operation indicates that a substantial level of boiler refurbishing and

tun'lng could lead to improved pre-controi NOx emissions above those tabulated for the 2001-2003 time period.

Based on an engineering review, Alstom estimates that the pre-control NOxlevels could be brought down to

0040 Ib/MMBtu ahead of the installation of the revised burner design. This value is used to determine the

expected emission limits associated wHh each of the optional designs.

4.2.1 Costs for Boiler C NOx

The Alstom LNCFS P2 (LNB) option is expected to reduce NOxemissions by about 20 percent to

0.32Ib/MMBtu. This equates to an annual reduction from baseline emissions of about 419 tons per year (tpy),

at an estimated cost of $480 per ton (Appendix A). The Alstom LNCFS Level 2 (LNB+SOFA) option is

expected to reduce NOxemissions to about 0.28 Ib/MMBtu. This equates to an annual reduction from baseline

emissions of 512 tpy, at an estimated annualized cost of $1,640 per ton (Appendix A).

Table 4-2 summarizes the total cost, annualized costs and incremental cost per ton of each evaluated NOx

combustion control technology.

Table 4-2 Cost Evaluation of NOxcontrols for Boiler C

Control NO, Controlled Cost Effectiveness Incremental

Technology (tpy) Annualized Cost ($) ($/ton) Cost ($/ton)

LNB 419 $202,000 $480

LNB+ SOFA 512 $838,000 $1,640 $6,800

4.2.2 Boiler D NO,

The Alstom LNCFS P2 (LNB) option is expected to reduce NOxemissions to about 0.32 Ib/MMBtu. This

equates to an annual reduction from baseline emissions of about 582 tpy, at an estimated cost of $360 per ton

(Appendix A). The Aistom LNCFS Level 2 (LNB+SOFA) option is expected to reduce NOxemissions to about

0.28Ib/MMBtu. This equates to an annual reduction from baseline emissions of 737 tpy, at an estimated

annualized cost of $1,420 per ton (Appendix A).

Table 4-3 summarizes the total cost, annuali<:ed costs and Incrementai cost perton ofeach evaluated NOx

combustion control technology.

Table 4-3 Cost Evaluation of NOxcontrols for Boiler D

Control NO, Controlled Cost Effectiveness Incremental

Technology (tpy) Annualized Cost ($) ($/ton) Cost ($/ton)

LNB 582 $211,000 $360

LNB + SOFA 737 $1,047,000 $1,420 5,420

4-2 December 2008
5.0 Selection of Control Scenarios

5.1 Control Options Modeling Emission Rates

Visibility impacts were evaluated with modeling based on the maximum 24-hour NOxemission rate. For

evaluating visibility improvement as a result of installing the BART options, the first step is to identify the level

of improvement in the 24-hour maximum emissions, from the baseline to the proposed new limits. Table 5-1

lists each control option, as applied to each unit for separate NOxcontrols. The controlled emission rate used

for modeling are also listed and are based on achieving an emission rate of 0.32 Ib/MMBtu for LNB and

0.28 Ib/MMBtu for LNB+SOFA and the maximum rated heat input capacity of the boilers.

Table 5-1 Emission Rates for Visibility Evaluation for LNB and LNB+SPFA

Baseline Peak 24·hour Future Peak 24-hour

Unit Control Option Emission (Ib/hour) Emission (Ib/hour)

C LNB 376 171

C LNB + SOFA 376 150

D LNB 616 282

D LNB + SOFA 616 246

The baseline modeling visibility impact was determined for each modeling year for each of the above control

option installed on both boilers.

In accord with BART gUidance, the CALPUFF Method 6 modeling setup was used to evaluate results of

impacts on v'lsibility at the nearby Class I areas. Impacts were assessed at the Jim Bridger Wilderness Area

and at the Fitzpatrick Wilderness Area. In all cases, the maximum impacts are at the Jim Bridger Wilderness

Area. Results of the modeling for each of these scenarios are provided in Table 5-2, showing the maximum

impact for each year for the baseline analysis and the impact for each scenario for the worst case year (2001).

The table lists the results for the Base Case for each of the three modeling years, using the percent change

based on the 20 percent cleanest days at each of the Class I areas;--

Results for the Base Case show the maximum impacts BART impacts are evaluated on the reported 8th

highest impact for each of the 3 years. The results showed that the maximum number of days with impacts

above 5 percent and 10 percent at the Jim Bridger Wilderness Area occurred in 2001. The impacts for that

year have formed the basis for evaluating each of the options.

5-3

December 2008
Table 5-2 Visibility Modeling Results

.::.:., L, ,

2001 2002 2003

Days> than Days> than Days> than

Class I 0.5 dv 1.0 dv MAXdv 8th Highest dv 0.5 dv 1.0 dv MAXdv 8th Highest dv 0.5 dv 1.0 dv MAXdv 8th Highest dv

Area D Sext D Bext D Bext D Bert o Sext D Bert D Sext D Bert D Bert D Bert Sext D Sext

Method 6, 20% Best Days Background,

Base Case Emissions

Bridger Wilderness 21 6 2.19 0.841 16 2 1.70 0.72 16 5 2.46 0.967

Fitzpatrick Wilderness 8 2 1.77 0.502 7 2 1.81 0.469 10 0 0.79 0.591

Method 6, 20% Best Days Background, LNB+SOFA

Bridger Wilderness 10 3 1.53 0.60 -- -- -- -- -- -- -- --

Fitzpatrick Wilderness 5 1 1.25 0.37 -- -- -- -- -- -- -- --

Method 6, 20% Best Days Background, LNB •

Bridger Wilderness 10 3 1.60 0.62 -- -- -- -- -- -- -- --

Fitzpatrick Wilderness 5 1 1.30 0.39 ,

-- -- -- -- -- -- -- --

5-4

December 2008
5.2 Control Scenario Options for Evaluation

The Control Scenario options for visibility impact modeling and economic analysis must consider a reasonable

combination of equipment and control options. The evaluation of the visibility improvement due to the BART

options was conducted by grouping the choices in order of increasing controls for individual pollutants and for

combinations of control technologies as follows:

Base Case: No additional controls;

Option 1: LNB; and

Option 2: LNB+SOFA

For this consideration, the optional controls were applied to each boiler for each option. The combination of the

modeling results and the economic analyses are provided in Chapter 6.

5-5

December 2008
6.0 Selection of the Best Alternative for BART Control

6,1 Summary of Results

The selection of BART controls Is based on the annualized costs for controis and the extent of improvement in

visibil'ityat Class I areas, For this analysis the improvement is based on impacts at the Jim Bridger Wilderness

Area only, and is based on the 98th percentile impact at that area, Table 6-1 provides the calculated

improvement in visibility for each control option, taken from the results in Table 5-2, The improvement is based

on the added cost and increased control for the next option (Case 1 over the Base Case, and Case 2 over

Case 1, respectively). The cost associated with each of the controls is also provided in Table 5-2,

summarized from the data provided in Appendix A cost analyses.

Table 6-1 Tabulation of Visibility Improvement at Jim Bridger Wilderness Area and Annual Costs

for Each Control Option

Modeled dV Delta dV Annualized CQst

($1,000)

Case Max Impact 8th-highest Max 8th Highest NO, PerdV

Base 2.19 0.84

1 - LNB 1.60 0.62 0,59 0.22 $413,000 $1,877

2-LNB+SOFA 1.53 0,60 om 0,02 $1,885,000 $94,250

The caicuiated annualized cost for visibility improvement for each of the control options is also provided in that

table, based on the combined data for 2001. The results are given in thousands of doliars for a delta deciview

(threshold of perceptibility) improvement. The results of modeling for other years for the baseline and BART

options are provided separateiy in the computer modeling archive,

6.2 Annualized Cost for Implementing Control versus Decrease in Visibility

Impairment

BART Controls are selected based on the estimated cost for applying those controis and on the expected

visibility improvement that would result from both LNB and LNB+SOFA, The retrofit of LNB is determined to

represent BART for Boilers C and D at the General Chemical- Green River, This conclusion is based on

technical Viability, degree of deciview improvement that can be achieved, and the cost effectiveness in dollars

per deciview improvement of the Control Scenario options evaluated.

6-1 December 2008
Appendix A

Cost Analyses for BART Control Options

December 2008
Table A-1

Boiler Data Sheet

General Chemical - Green River, WY

--Control of Peak

LNB LNB+SOFA

Ib/hr @ 0.32 ib/hr @ 0.32

Unillnformation Ib/MMBtu Ib/MMBtu

Boiler C

Year Built 1973

Manufacturer Combustion Engineering

Rating 534 MMBtu/hr

400 klb/h r Steam

Fuel Low-Sulfur Bitum'lnous Coal

Firing Tangentially Fired

Air Pollution Control Hot-Side ESP

Soda Ash Coal Conditioning

NOx Emissions 376 Ib/hr Maximum 171 150

0,50 Ib/MMBtu Average

267 Ib/hr Average

1057 TPY Average

1147 TPY Max (2001-2003)

Exhaust Temperature 320 of

Boiler D

Year Built 1975

Manufacturer Combustion Engineering

Rating 880 MMBtu/hr

660 klb/hr Steam

Fuei Low-Sulfur Bituminous Coal

Firing Tangentially Fired

Air Pollution Control Hot-Side ESP

Soda Ash Coal Conditioning

NOx Emissions 616 Ib/hr Mf!)<imunL 282. I 246

0,47 Ib/MMBtu Average •

415 Ib/hr Average

1468 TPY Average

1527 TPY Max (2001-2003)

Exhaust Temperature 320 of
Table A-2

Combustion Modifications and Low NOx Burners

Boiler C

1 BasIc equipment for Aistom options are from Aistom Power budgetary costs of S170,000 for LNCFS P2 and $1,800/MMBtulhr for

LNCFS Level 2.

2 Total installed costs for Aistom options are based on low NOx burner factors from "Best Available Retrofit Technology Engineering

Analysis", Midwest RPO, March 30, 2005lhat ind'icaies total costs are 2.65 times basic equ'lpment.

Alstom Alstom LNCFS

LNCFS P2 Level 2 Basis

(LNB) (LNB+SOFA)

Capital Cost

Basic Equipment $ 175,000 $ 961,200 Note 1

Total Installed Cost not $ 463,750 $ 2,547,180 Note 2 Includin[J Lost Revenue

Lost Revenue $ 658,000 $ 3,290,000

Total Installed Cost $ 1,121,750 $ 5,837,180 Includinq Lost Revenue

Annual Costs, S/yr

Increased Carbon Loss $ $ 40,000 Possible 50% increase for LNCFS Level 2 IfLoss on lonition) .

Operatlnq Labor $ 32,850 $ 32,850 1 hrlshift at $30/hr

Supervisor $ 4,928 $ 4,928 15% of ooeratin[J labor· Note 3

Maintenance Labor $ 8,974 $ 46,697 0.8% of total installed cost· Note 4

Maintenance Materials $ 13,461 $ 70,046 1.2% of total installed cost Note 4

Overhead $ 36,128 $ 92,713 60% of oper, maint. & supv labor + maint. mtl

costs· Note 3

Prooertv Tax $ · $ · 1% of total installed costs· Note 3

Insurance $ · $ · 2% of total installed costs· Note 3

Administration $ · $ · 2% of total installed costs· Note 3

Cap'ital Recoverv $ 105,893 $ 551,030 7%, 20 years· Note 3

Total Annual Cost $ 202,000 $ 838,000

Cost Effectiveness

NOx Emissions before Base on historic average emission rate for

1,167 1,167 2001,2002, and 2003 and maximum rated Control, ton/yr heatTripLit cifb6rrer. - -_.. -

After Control Emissions, 748 655 Based on information from Alstom

ton/vr

Emission Reduction, ton/yr 419 512

Cost Effectiveness, $/ton 480 1,640

Incremental Cost $ 636,000

Incremental NOx Reduction,

ton/Yr 94

Incremental Cost

Effectiveness, $/ton 6,800 .

3 "8est Available Retrofit Technology Engineering Analysis", Midwest RPO, March 30, 2005,

4 8ased on EPA's CUECQST program.

5 EPA Air pollution Control Cosl Manual, Sixth Edition, Section 4, Pages 1·3 and 1-25. EPAJ452/8-002-001. January 2002.
Table A-3

Combustion Modifications and Low NOx Burners

Boiler D

1 BaSIC equipment for Aistom options are from AIs10m PO'ller budgetary costs of $200,000 for LNCFS P2 and $1 ,aOOfMMBtu/hr lor

LNCFS Level 2.

2 Total installed costs for A!stom options are based on low NOx burner factors from "Best Available Retrofit Technology Engineering

Analysis", Midwest RPO, March '30, 2005 that 'Indicates total costs are 2.65 times basic equipment. This factor accounts for e

Alstom Alstom LNCFS

LNCFS P2 Level 2 Basis

(LNB) (LNB+SOFA)

Capital Cost

Basic Equipment $ 200,000 $ 1,584,000 Note 1

Total Installed Cost not Note 2

Includinq Lost Revenue $ 530,000 $ 4,197,600

Lost Revenue $ 658,000 $ 3,290,000

Total Installed Cost $ 1,188,000 $ 7,487,600 Includinq Lost Revenue

Annual Costs, $/vr

Increased Carbon Loss $ $ 40,000 Possible 50% increase for LNCFS Level 2

Loss on Iqnition)

Operat'lnq Labor $ 32,850 $ 32,850 1 hr/shift at $30/hr

Supervisor $ 4,928 $ 4,928 15% of ooeratina labor - Note 3

Maintenance Labor $ 9,504 $ 59,901 0,8% of total installed cost - Note 4

Maintenance Materials $ 14,256 $ 89,851 1.2% of total Installed cost Note 4

Overhead $ 36,923 $ 112,518 60% of oper, maint. & supv labor + maint. mtl

costs - Note 3

Propertv Tax $ - $ - 1% of total installed costs - Note 3

Insurance $ - $ - 2% of total installed costs - Note 3

Adm inistration $ - $ - 2% of total installed costs - Note 3

Capital Recoverv $ 112,147 $ 706,829 7%, 20 vears - Note 3

Total Annual Cost $ 211,000 $ 1,047,000

Cost Effectiveness

NOx Emissions before Base on historic average em'lssion rate for

. Control, ton/yr 1,816 1,BJI3. 200L~Q02, and 21tOa and maximum rated

heat innut of boiler.

After Control Emiss'lons, 1,233 1,079 Based on information from Alstom

ton/vr

Emission Reduction, ton/vr 582 737

Cost Effectiveness, $/ton 360 1,420

Incremental Cost $ 836,000

Incremental NOx Reduction,

ton/vr 154

Incremental Cost

Effectiveness, $/ton 5,420 , ,

3 "Best Available Retrofit Technology Engineering Analysis", Midwest RPO, March 30, 2005.

4 Based on EPA's CUECOST program.

5 EPA Air Pollution Control Cost Manual. Sixth Edition, Section 4, Pages 1-3 and 1-25. EPA/4521B-002-001. January 2002.
Appendix B

Cost Quote from Alstom Power

D~cerr.ber 2008
I

POWER SYSTEMS

ENERGY AND ENVIRONMENT SYSTEMS

Boiter f<etrofits, Willdsor Operations

ALSTOM Powel h:.

2000 Day HIli Road

Vv'indsol; CT 060'35

':"1;'1 (B50) 2BS-90S2

Fax: (aw) 285./.301,

October 3, 2008

Mr. Mike Dahl

General Chemical Corporation

Green River Works

PO Box 551

Green River, WY 82935

Subject: General Chemical- Green River Works, Boilers C & D

Low NOx Concentric Firing System (LNCFSTM) P2 Modification

Alstom Contract Numbers 22072 & 21173 / Alstom Submittal No. 43033880

Dear Mr. Dahl:

Alstom's Boiler Retrofits Windsor, CT Operations (the Company) is pleased to present General

Chemical Corporation (the Purchaser) the attached budget submittal and budgetary estimate for an

Low NOx Concentric Firing System (LNCFSTM) P2 Low NOx modification. The proposed

materials are intended for use at the Purchaser's Green River Works, boilers C and D. The boilers

are further identified as the Company's Original Contract No. 22072 and 21173.

The LNCFSTM P2 system utilizes a VCCOFATM nozzle tip to maximize close-coupled overfire air

capacity. This offer does not require any coalptpemodifications: --- - - -

The Company's budgetalY estimate for the combustion system modifications is listed on the

attached page. This estimate includes engineering services to design all required materials, material

fabrication, equipment arrangement drawings, instruction manuals, and material delivery to the site.

Budgetary pricing for Technical Services Supervision can be included upon your request.

If you should have any questions or need additional inf0l11lation, please feel free to call me at

(860) 285-9989.

Sincerely,

Michael Taber

Business Development

Boiler Retrofits Windsor Operations

cc: Michael Zebell

Jeff Edwards
Mr. Mike Dahl

October 3, 2008

ATTACHMENT

BUDGETARY PRICING

LNCFSTM P2 System

BOILERC

The Company's budgetary estimate for the proposed LNCFSTM P2 system, as described in the

submittal document, is:

One Hundred Seventy-Five Thousand Dollars

$175,000.00

BOILERD

The Company's budgetary estimate for the proposed LNCFSTM P2 system, as described in the

submittal document, is:

Two Hundred Thousand Dollars

$200,000.00

The abovc estimate does not include installation, technical services, or additional burner nozzle

tip weld overlay material.

Note:

This budget submittal gives a preliminmy indication of the basis of which the scope of work

described herein can be provided, and does not constitute afirm price, offer or commitment as to

such scope. In particular, any prices, delivery times or performance figures provided in this

budget submittal are given without commitment and without regard to terms and conditions.

This budget price has been prepared with only the minimum technical investigation to determine

the feasibility ofthe requirements, if any, that your organization provided to ours. To this end,

we look forward to disclissing the content ofthis submittal and, when appropriate, providing a

more formal offer. At that time, we can review and comment to YOlir organization's terms and

conditions or we will reference Olir standard terms and conditions or a previolisly agreed upon

set ofterms with your organization that may be appropriate for this project. This letterforms an

integral part ofthis submittal.
/J Budget Submit/a! To:

General Chemical Corporation

Green River Works

Unit C and D

For:

Advanced Combustion System

Changes

October 3, 2008 Submittal Number 43033880

Copyright 2008 ALSTOM Power Inc.

Al! Rights Reserved
The information contained in this Submittal is considered to be of a confidential and proprietary

nature, the rights to which belong to ALSTOM Power Inc. (Alstom/the Company), and are

protected under the copyright and trade secret laws. This information is being furnished to the

Purchaser to enable the Purchaser to evaluate the Company's Submittal. If a Contract is awarded

to the Company based on this Submittal, then the information is to be included in whole or in part

in the Contract. Neither this Submittal nor any information contained therein, nor any proprietary

inf01111ation furnished pursuant thereto, shall be disclosed to others, or used for any pUlpose other

than that set forth above, without the prior written approval of the Company. The Company may

seek to obtain patent coverage on aspects of the Company's offering as described in this Submittal.
Submittal Number 43033880

TABLE OF CmHENTS

I.! INTENT 1

1.2 UNIT DESCRIPTION I

2.1 MATER1ALS AND SERVICES LISTING 1

2.1.1 Low NOx Concentric Firing System (LNCFSTM) P2 I

3.1 TECHNICAL DISCUSSION 2

3.1.1 LNCFSTM P2 Modification 2

3.1.2 Windbox Technical Details 3

3.2 F1ELD SERVICE SUPPORT 5

3.3 ITEMS/WORKNOT 1NCLUDED 8

3.4 TERM1NATIONP01NTS · 8

4.1 PERFORMANCE PREDICTIONS FOR UNITS C AND D 9

4.2 SCHEDULE 9

4.3 SHIPMENT 9

4.4 TAXES 10

4.5 CONDITIONS OF SALE 10

APPENDIX

A.l ORGAN1ZATIONAL CHART OF PROPOSED PERSONNEL 1

A.2 QUALITY ASSURANCE "."' , 2

A.3 TOTAL PROJECT MANAGEMENT.. .4

General Cltemical COIporalion

Gadsden Sleam PlanI, Unil No.1

Table ofCon/enls
Submittal Number 43033880

l.l INTENT

Alstom's Boiler Retrofits Windsor, CT Operations (Alstom/the Company) proposes to

furnish General Chemical Corporation (Jthe Purchaser) the material and services outlined

in this Budget Submittal to provide a Low NOx Firing System. This submittal includes an

offer for an LNCFSTM P2 modification. The materials are intended for the Purchaser's

Green River Works, Units C and D. The boilers are further identified as the Company's

Contract Numbers 22072 & 21173.

The Company has been asked to quote an LNCFSTM P2 modification for NOx reduction.

Peak NOx is listed as 0.68 and 0.83 IbIMBhl, respectively for each unit. Given the western

coal and vintage of these units, the NOx would be expected to be significantly lower than

these rates. Discussions with ENSR indicate NOx may achmlly be closer to 0.5 ib/MBhl,

but this has not been confirnled. The stated target for the NOx reduction system is 0.49

ib/MBh!.

1.2 UNIT DESCRIPTION

There are two units at Green River Works to be modified. Boiler C is rated for 400 klb/hr

steamflow, and Boiler D is rated for 600 klb/hr. Both are fixed-T VU-40 units, boiler C

with two (2) elevations of coal, and boiler D with three (3) elevations of coal. Intennediate

aux compartments contain two (2) flame scanners. There is a single manual tilting

CCOFA above the top end air compartment on both units.

2.1 '\1ATERIALS AND SERVICES LISTING

2.1.1 Low NOx Concentric Firing System (LNCFSD') P2

The following is a listing of the major equipment included within the scope of the

Low NOx Concentric Firing System (LNCFSTM) P2 Modification.

BOILERC

Item Quantitv

1. Eight (8)

2. Four (4)

3. Eight (8)

Geneml Chemical COl1Jomtion

Green Ri,'er 'Yorks, Boiler C and D

Description

Coal nozzles with round-to-square transition P2 nozzle

exit, fabricated from 309 stainless steel

Fixed CFSTM nozzle tips, fabricated from 309 stainless

steel

VCCOFA nozzlc tips, fabricated ll'om 309 stainless steel

Page 1
Submittal Number 43033880

4. As Required Drawings and instruction manuals to incorporate the

above cquipment

BOILERD

1.

2.

3.

4.

Twelve (12)

Eight (8)

Eight (8)

As Required

Coal nozzles with round-to-square transition P2 nozzle

exit, fabricated from 309 stainless steel

Fixed CFSTM nozzle tip fabricated from 309 stainless

steel

VCCOFA nozzle tips fabricated from 309 stainless steel

Drawings and instruction manuals to incorporate the

above equipment

3.1 TECHNICAL DISCUSSION

3.1.1 LNCFST>' P2 Modification

Alstom proposes a Low NOx Concentric Firing System (LNCFSTM) P2

modification for General Chemical's Green River Works, Boilers C and D. The

advanced design of the P2 Low NOx system was derived through tcsting

comprehensive full-scale combustion in Alstom's Power Plant Laboratories.

The P2 Low NOx system, developed by Alstom, represents advancement in coal

combustion for tangential firing. The system was developed to offer the

advantages of NOx emissions reduetion-through-modified nozzle-tips. The P2 coal

nozzle tip is part of an advanced in-windbox low NOx firing system that includes

Vaned Close-Coupled Overfire Air (VCCOFAfM), as well as optimized

intermediate air compartments. (See Figure 1.) The system requires modifications

that includc replacement of intermediate air tips and top end air nozzle tips.

The Company predicts that a 10 - 30% NOx reduction can be achieved with the

LNCFsn, P2 modification. This NOx reduction range is a function of how the unit

is currently operated to control NOx. Additional NOx reductions of 50% or greater

can be achieved with a separated overfire air (SOFA) system.

The Company plans to re-tip the main windbox with its patented LNCFST>I P2

modification. Since this is a fixed-T windbox, the coal nozzle will be replaced with

a new coal nozzle. This includes the !lange connection to the coal pipe and a

General Chemical C01])()/'{/tion

Grecn Ril'er Works, Boiler C and D

Page 2
t\l Submittal Number 43033880

Figure I - P2 Coal Nozzle Tip

modified nozzle exit. The nozzle exit will go from a round-to-square design and

incorporate the center bluff wedges of the P2 coal tip. (Refer to Figure 1 for a

Wide Range Coal Nozzle (WRCN) tip design.)

The intenllediate aux air elevations will contain a new fixed CFSTM nozzle tip with

scanner ports. Both the top end air and CCOFATM air compartments will be

modified with the VCCOFATM nozzle tip. The VCCOFATM nozzle tip has a tlxed

position, which eliminates the use of the manual tilt drive. No changes will be

made to the bottom end air nozzle tip.

An additional review of the damper box in each compartmcnt will be made, to

determine if the damperarea-needs-to be resi2edto-maintain a-reasonable control

range. Downsizing the damper box will simply require welding one or more of the

existing blades closed. All nozzle tips will be manufactured from 309 stainless

steel.

3.1.2 Windbox Technical Details

Coal Compartments

The coal compartments will be equipped with P2 coal nozzle tips and new support

plates. A total of eight (8) coal nozzles will be supplied for Boiler C and twelve

(12) coal nozzles for Boiler D. The P2 coal nozzle tips have been designed to

improve coal combustion occurring in the near-nozzle region of the boiler, which

helps in NOx reduction.

General Chemical Corporation

Green River lVorks, Boiler C and D

Page 3
t\ Submittal Number 43033880

Optional P2 Coal Nozzle Tip Weld Overlay

Alstom's optional weld overlay includes coverage of the leading edges of the

splitter plates, including the notched areas of the splitter plates, with overlay. The

optional weld overlay design was incorporated to extend the life of the coal nozzle.

Many Western coals have high silica and alumina content in their ash and exhibit

higher erosion potential. Sub-bituminous coals require higher coal throughput and

increase their erosion potential. This option can be priced upon request.

Vaned Close-Coupled Overfire Air

The VCCOFATM system is installed in the top most air compartment of the main

windbox - top end air compartment. (See Figure 2 and 3.) The existing air nozzle

tip plates are removed, and a set of fixed vanes is installed into this compartment to

optimize the amount and injection angle ofthe close-coupled air.

Figure 2 - VCCOFA 10" Compartment Figure 3 - VCCOFA 12" COll1partl11ellt

Concentric Firing System (CFST")

Redistribution of the secondary air to achieve maximum NOx reduction is critical.

This is accomplished by replacing the existing auxiliary air tips with the

Company's Concentric Firing System (CFSTM) offset air tips. A typical CFSTM

nozzle tip is illustrated in Figure 4. The CFSTM offset air tip directs a pOliion ofthe

secondary air closer to the furnace walls relative to the firing angle of the fuel

nozzles.

Under Low NOx firing conditions with staged air, a rcducing atmosphere can exist

near the furnace walls. An increase in furnace slagging can be the result of this

rcducing atmosphere. CFSHt aids in the control of slagging by promoting an

oxidizing atmosphere in these areas. The CFSTM offset air tip directs a portion of

General Chemical Corporation

Green Rh'er Works, Boiler C and D

Page 4
Submittal Number 43033880

Figure 4 - CFsn, Air Nozzle Tip

the secondary air closer to the furnace walls relative to the firing angle of the fuel

nozzles. The CFSTM angle is detern1ined for each boiler based on fuels fired and

fi.lrnace geometry.

An additional benefit of reducing NOx may be realized with CFSTM air. The

auxiliary air that is directed away from the [,leI stream prevents the fuel jet from

entraining this air; thereby, reducing the combustion stoichiometry during

volatilization and the initial stages of char combustion. This results in a very fuel

rich primary flame, while maintaining-oxidizing eonditions-alongthe furnace walls

and enhancing overall mixing in the fireball. All new adjustable yaw CFSTM air

nozzle tips will be a one-piece design, fabricated using 309 stainless steel.

3.2 FIELD SERVICE SUPPORT

It is recommended that the above modifications (installation, set-up, and initial start-up) be

supervised by the Company's representative to ensure a successful and trouble free retrofit.

The Company can provide a Service Engineer (SE) to offer field technical support to the

Purchaser as requested during the project. The SE can perform an array of activities prior

to, during, and following the outage, as an advisor to the Purchaser. These services can bc

provided on a per diem basis, at the rate prevailing at the time of servicc, as requested by

thc Purchaser.

General Chemical CO/1)()ration

Green River Works, Boiler C and D

PageS
Submittal Number 43033880

The following are typical activities that could be perfonned:

Pre-Outage Activities

The designated lead service engineer could begin project activities, which include but are

not limited to the following:

• Travel to site

• Inspect "as-received" burner equipment to review for potential problems and

equipment shortages

• Perfonn pre-outage walkdowns to identify overlooked interference's and unit

peculiarities

• Attend pre-outage meeting with the Purchaser and Constmetion for introductory and

technical support/consultation reasons

Ontage Activities

During the outage the lead engineer would:

• Perform detailed windbox and burner inspections to identify areas, which could

necessitate additional unanticipated work.

• Provide detailed inspection and checkout of windbox, nozzles, tips, linkages and pins

during and upon completion of installation.

• Stroke main bUl11er tilts to ensure full travel is achieved without undue strain.

• Check out Main Windbox dampers and stroke.

• Check out and start up ignitors and scanners (if applicable)

• Provide general boiler outage support andinspectiOlLas time avails._

• Provide technical service and direction to the Purchaser during the installation and cold

commission phases of the project.

• Perform detailed inspection and check out of all other material and equipment provided

by the Company under this scope offering.

Note: Boiler and Environmental Plant Services division of ALSTOM Power Inc. Technical

Services Engineer ("Representative") shall act in an advisory capacity to Purchaser's

personnel during the scheduled time period. Such Representative is not authorized to

supervise operations or other business activities nor is the Representative authorized to

operate any machinery or equipment. The responsibilities of the Representative are

limited to advising and consulting in accordance with the provisions of the

Submittal/contract. Nothing herein shall relieve the Purchaser or its other contractors from

the rcsponsibility for dimensional accuracy, quality or worlQ11anship, or asscmbly, erection

and operation of equipment. The Representativc shall have no rcsponsibility for inspection

General Chemical C0I1}()ration

Green River Works, Boiler C {/lId D

Page 6
Submittal Number 43033880

services which may be required by local, state, federal, or independent regulatory agencies

or boards.

Post-Outage Activities

Post-outage activities consist of start-up support, and tuning support. Staffed with one

qualified Service Engineer, the Company would:

o During initial fires conduct clean airflow checks on all mills looking for system

resistance and ensuring proper mill airflow.

o Assist the purchaser with testing and setting coal fineness on the pulverizers. Fineness

must be set in order to tune the units.

o Burner equipment unit tuning to meet contract objectives at high, mid and low load.

o Once the unit tuning bas been completed, the Lead Service Engineer would prepare "as

marked up" prints and close out reports.

Alstom has not included any temporary test equipment for measuring NOx and CO and

assumes the customer will provide this data through pennanent instmments or CEM.

Note: Safe operation of tbe unit is the responsibility of the Purchaser, under all

circumstances.

TUNING CRITERIA

The following criteria are recommended to bc provided by the Purchaser to support tuning:

o A consistent specified coal supply is required for the duration of the observation and

tuning period.

o Fly ash sampling is required for the tuning phase during each test.

o Fineness tests are required prior to tuning. Additionally, recent clean airflow test data

should be available. Fineness test equipment and ports are assumed to be available

fr0111 the purchascr.

o Existing plant O2 monitors are calibrated and accurate.

o Existing plant stack monitor for NOx and CO is available, calibrated and accurate.

• Main burner tilts are to be operable within the full tilt range.

• Secondary air damper drives are to be operablc with a full one hundred percent (100%)

stroke.

• Plant personnel support will be rcquircd to work with the control system in

reconfiguration of parameters, as required.

Unit "scasoning" will bc required to determine accurate unit perfol1nance. One (l) week is

estimated but is dependent on fuel characteristics.

General Chemical COl1Joration Page 7

Green River Works, Boiler C and D
Submittal Number 43033880

3.3 ITEMS/WORK NOT INCLUDED

The following items are not included in the scope of this Submittal and are to be supplied

by the Purchaser:

• Installation of Equipment

• Casing and insulation removal, and installation. Asbestos abatement, ifrequired.

• All control system modifications

• Performance Testing

• Electrical wiring and conduit

• Stmctural steel or modifications to the existing structural steel is not included in this

offering, except for new suppOli steel required to support Company supplied

equipment.

• Relocation of existing piping, cable trays, ducts, sootblowers and observation doors, if

required.

• New ductwork systems and modifications to the existing ductwork systems, except for

windboxes

• Pulverizer modifications

• Ignitors or scanners and any associatcd repairs or upgrades (if applicable)

• Coal piping modifications required to restore system back to original design

3.4 TERMINATION POINTS

The termination points for this offering are as follows:

Windbox Modification Components

Materials to replace existing windbox, as shown in the materials list.

Control Svstem

SAMA logic drawing will be supplied.

All control system modifications are to be by the Purchaser or their control vendor. This

includes system hardware, engineering, and programming. The Company will provide

control system logic design for secondary air control.

General Chemical COl1JOra!ion

Green River Works, Boiler C and D

Page 8
Submittal Number 43033880

4.1 PERFORNIANCE PREDICTIONS FOR UNITS C AND D

Following the completion of the installation of the proposed equipment, the Company is

predicting the following at 100% MCR:

Emissions Prediction

LNCFST>I P2 System:

Nitrogen Oxides, Ib/MBtu: 10 - 30% reduction from baseline

4.2 SCHEDULE

Based upon current engineering and production schedules, the Company anticipates that

the material andlor equipment described in this Submittal could be shipped out to the

jobsite thirty (30) weeks after the receipt of an acceptable purchase order.

This lead-time for material delivery does not include actual shipping time ·from the

manufacturing point to the specified destination, or additional time which may be required

for approval of drawings, plans, and specifications by the Purchaser.

AlTangement drawings for the main windbox modifications will be submitted to the

Purchaser approximately sixteen (16) weeks after the receipt of an acceptable purchase

order. Preliminary installation drawings may be available for review upon Purchaser's

request.

4.3 SHIPMENT

The material andlor equipment described in this Submittal are quoted FOB. destination

with freight prepaid and included to the jobsitc or nearest rail unloading facility.

The prepaid freight charges included in the Submittal price are based on standard rail or

truck transportation and routing as designated by the Company. Should the Purchaser

request expeditious or special shipping, all additional charges resulting therefrom will be

added to the Purchaser's account.

Switching, unloading and extra handling chargcs are not included In the Company's

quotcd price and, if incurred, will be added to the Purchaser's account.

General Chemical CO/poratio/l Page 9

Green River Works, Boiler C and D
Submittal Number 43033880

4.4 TAXES

The Purchaser will pay all sales, use, value added, excise and other taxes which may bc

levied or assessed in connection with the transfer of the material or equipment furnished by

the Company (including such taxes which are levied or assessed in connection with such

material or equipment which the Company obtains for use in performing the services), or

in connection with the perfonnance of the services, or in cOlmection with this Submittal or

any resultant Contract or the Company's performance under this Submittal or any resultant

Contract. The Company's price does not include any such taxes. lfthe Company pays any

such taxes, the Purchaser will reimburse the Company promptly upon receipt of the billing

invoice. The Purchaser will provide the Company with any exemption certificates and

other relevant documents in sufficient time to claim any tax exemptions in association with

this Submittal or any resultant Contract but in all events will be supplied prior to shipment

of material. This article shall prevail over any conflicting or inconsistent provisions

contained elsewhere in the documents comprising the Contract regarding taxes.

4.5 CONDITIONS OF SALE

The Standard Tenns and Conditions of Sale - Domestic, located in the Appendix of this

Submittal, shall govern this Submittal and any order resulting therefrom.

General Chemical CO/poration

Green Riper fVorks, Boilcr C alld D

Page 1()
APPENDIX
Submittal Number 43033880

A.I ORGANIZATIONAL CHART OF PROPOSED PERSONNEL

1- Paul Greni~

Project MWlager

Windsor, CT

-'-""'1

Rich LaFJesh i

Design Engi1leer ! --~--'

TimGr

Desigll G

Barbara Lane

Planl1er/Seller/uler

Charlie Hart

Fie{(J Service Support '"_'_··'·_,."••• '··'e •__,_••,••

General Chemical Corporation

Green River Works, Boiler C amI f)

App-l
Submittal Number 43033880

A.2 QUALITY ASSURANCE

ALSTOM was ISO 9001 certified by the American Society of Mechanical Engineers

(ASME) in November 1994 and later recertified by Hartford Steam Boiler Registration

Services in July 2000 and June 2003. Our current ISO 900 I certificate is with Lloyds

Register Quality Assurance (LRQA) based upon their review of ALSTOM in November

2005. It is valid until November 30, 2008. ALSTOM's ISO 9001 Quality System is

documented in a Quality Systems Manual, which is supported by common quality

procedures and departmental work instructions. A copy of this Quality System Manual

and our cUtTent ISO Certificate can be provided upon request.

It is the Company's policy to have and maintain manuals of procedures and operations

which will be followed to assure that a product within the Company's scope of supply will

be engineered, designed, and fabricated to meet or exceed the applicable Codes, Purchaser

specifications and relevant Company standards. The following is a synopsis of the overall

quality program.

• The Company's Quality Assurance Department reviews the Submittal and Contract

requirements upon request and advises the appropriate department of any special

requirements. Concerned departments will initiate the appropriate steps to assure the

capacity and capability of the Company to comply with all contractual obligations.

This review wiIl determine the nature and extent of the involvement of the Company's

Quality Assurance Depmiment.

• It is the responsibility of the Company's Quality Assurance Department to audit the

Product Design and Design Graphics Departments to assure that the unit design is

completed in accordance with established procedures, using current, applicable

Standards and Codes.

• All items are ordcred from qualified suppliers. Suppliers are approved by the

Company's Quality Assurance and Supply Management Department. This qualifying

procedure is delineated in a Company procedure.

• The Company's procurement order system is the official medium for authorizing

material to be purchased and work to be performed in its shops and its suppliers'

shops. Appropriate tests, checks, and inspections are spccified to assure the quality of

purchased and manufactured items.

• When deemcd appropriate, manufacturing processes cmployed by the Company and

suppliers' shops, follow travelers, or similar shop documents that accompany the work

and indicate applicable specifications, procedures, and techniques. This traveler is

also the established document to be signed-off on by the operator, foreman, inspector,

and Non-Dcstructive Examination (NDE) pcrsonnel when appropriate. All work is

performcd by welders, NDE persollnel, and inspcetors qualified in accordance with

applicable Codcs and procedures.

General Chemical Corporatioll

Green Ri1'er Works, Boiler C alld D

App-2
9

""" Submit/al Number 43033880

• Fabrication of all items is accomplished to provide equipment confom1ing to the

engineering drawings and specifications, and to present a quality workmanship

appearance. All NOE required by the applicable ASME Code is performed, and the

results are made available to the Authorized Inspector. Additional NDE for Company

or supplier quality control purposes is perfol111ed on some product fom1s and on

specific weldments, in accordance with Company standards or by contractual

agreement.

• Inspection of the manufacturing operations is the responsibility of the individual plant

Quality Assurance Department. Surveillance over the suppliers' work is the

responsibility of the Company's Quality Assurance Department.

• The details of the quality program utilized (including references to test procedures,

techniques, and associated Company standards) are contained in the Company's

Quality Assurance Manual, the Fossil Engineering Quality Assurance Manual, and the

Quality Assurance Manuals of the Company's manufacturing facilities and suppliers'

facilities. The test procedures, instmctions, and associated Company standards are

considered proprietary and are available for the Purchaser's review at the Company's

and its snppliers' facilities.

Gelleral Chemical C011J01'lIIioll

Greell River Works, Boiler C alld D

App·3
Submittal Number 43033880

AJ TOTAL PROJECT MANAGEMENT

An individual Project Manager coordinates and directs the project effort throughout

engineering, procurement, fabrication, delivery, installation, commissioning, start-up,

performance testing and final close-out.

The Company works on a team basis with the Purchaser. Focused, integrated teams,

comprised of both Purchaser and Company personnel, are formed. Each Project Team

includes a Purchaser Project Manager, a Company Project Manager, and Specialists in the

areas of engineering, procurement, installation, and commissioning. This winning team

ensures that the high standards of both the Company and the Purchaser are maintained and

that all available resources are utilized to the Purchaser's best advantage. The Project

Team has a mutual goal- the successful completion of the project. Figure 5 illustrates the

Project Team, while Figure 6 depicts the major events demonstrating the integration of the

Project Team into a project-focused entity.

INTEGRATED PROJECT TEAM

Purchaser'.s

IL- Purchasor Company - Plannert Scheduler

ProJGct Toom Project Projecl

Manager Manager

f- Prolect Englnoor

,- - Purchasing

Man-egGr

- Inslallallon SQrvlCQS

Power Plant field Service

laboratorIal Support

Balance of Plant "- Designer

Figure 5 - Il1tegrated Projeet Team

General Cllelllica! Corporation

Green River Works, Boiler C and D

App-4
Submittal Number 43033880

PROJECT EXECUTION

® MonulOcfI.J'~ I (lndol,fpplno I

,

,

Shop I'r•. ,,- "~~9'l

~.'Il'"I' AP\'llQvlli

PIO,<IiIC'1

cllvllfes A(etp.lonc'

nn,jlnl,,1"'>01 1--+ (le~'J1!

/

I

Orde,

A.,..<Ird

Acllvltles

'"Ptl1!lId

(jC~\l1r I- Purchas40H

Company A

Pmi",d

D.~tjoP""ffl .--)0- .-

®~_.

OI;~ ..

1'1IY,llOU

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Figure 6 - Project Execution

The Integrated Project Team is focused on the end product. This allows all team members

to interact and promote the success ofthejJroject. InlloyatiQl) is_CllCQUraged to support the

project goaL Innovation in one function, such as design, may greatly enhance

manufacruring of a project. Under the Project Team concept, each function or piece of a

project is designed to enhance the project goaL

Utilizing the Total Project Management approach allows both the Purchaser and the

Company to optimize resources to meet the shared commitment. Eliminating duplication

of efforis within both organizations can reduce use of resources, The participants become

partners in an effort to produce the desircd end result.

The Project Manager provides single point contact for both the Purchaser and the

Company, Thc single point contact affords resolution of all issues both internally and

externally. Questions of a legal, technical, contractual, schcduling, financial, quality

control, design, performance, installation, or commissioning nature arc properly directcd

and addressed. Project Team members are provided with timely, accurate and coherent

feedback and responses to questions and concerns.

General Cllelllical Corporation

Green Ril'er Works, Boiler C alld D

App-5
Submittal Number 43033880

All team members receive accurate feedback on how their performance is affecting the

overall project. The Project Manager cultivates team spirit. The Project Team members

understand the requirements of the desircd result and are encouraged to fulfill the overall

project requirements,

The Project Manager is supported by a strong organization providing experienced

assistance and support for scheduling, legal, financial and technical advice, If required,

additional Project Management personnel can offer direction and support to a project.

Total Project Management does not rely solely upon the experience, skills, and availability

of one person within the Company,

The Company and the Purchaser share a clear and common goal - supplied equipment, in

operation, performing as required, by the agreed upon date, When numerous contractors

carry out a project, the only entity that retains ownership or accountability for the final

product is the Purchaser. Individual contractors will have met their commitment when

their part of the project is complete, Although "Engineering Complete" is an important

milestone in any project, if the individual contractor's engineering effort has not supported

and been integrated into the fabrication, installation, start-up or performance of the final

product, the end result may not meet the Purchaser's requirements and expectations,

The overall quality of the final product is within the control of the integrated Project Team,

Quality control and quality assurance of the many components and functions of the

project's scope are enhanced when commitment to the successful completion of the project

is the goal of the Project Team, Decisions are based on what is best for the entire project,

not on what may be enough to meet the contractual requirements of individual components

or functions,

Gel1eral Chemical C0I1JOratiol1

Greel1 River Works, Boiler C al1d D

App- 6
Submittal Number 43033880

(Goods and Services) - Domestic/Rev: OSi!2'()5

ALSTOM Power Inc.

STANDARD TERMS AND CO:'<DITlO:-;S OF SALE

ARTICLE 1. Oefinitinns.

1.1 The words '",ve", "our", "ours", and "us" mean the Seller.

1.2 The words "you", "your", and yours" mC'dn the Purchaser.

1.3 The word "Agreement" means the agreement under which we provide you \vtlh goods, equipment and/or services, and includes these Standard

Terms and Conditions of Sale and all documents expressly incorporated by reference und all attachments.

1A The word "Goods" means the goods or eqllipment which we will provide to you under the Agreement.

1.5 The word "Services" means installation, simi-up, training, supervision, engineering. andlor other services which we will provide to you under

the Agreement.

1.6 The word "Affiliate" means any entity which controls or is controlled by or is under coml11on control with us.

ARTICLE 2, Duration ofSubmittalj Effect.

2, I We may withdraw any Submittal at any time until we receive yom written acceptance,

2,2 If we do not receive your written acceptance within 60 days of the date of any Submittal, that Submittal will expire and be void, unless

otherwise stated in the Submittal,

2,3 Any changes which you wish to make to any Submittal must be expressly accepted by us in writing; othenvise those changes will be void,

2.4 We expressly reject any provisions elsewhere in the Agreement which conflict with these Standard Ten1lS and Conditions of Sale,

ARTICLE 3, Shipment and Deliverv.

3.1 We will deliver the Goods F,O,B. points of shipment or as stated in the Agreement. This will be the only delivery which we are required to

make to you. Title and risk of loss will pass to you when we make this delivety,

ARTICLE 4. Termination and Caucellation.

4,1 You may not terminate or cancel the Agreement except by giving us written notice.

4,2 If you te1111inate or cancel, you must pay us for our costs of labor, material, engineering, administration, and overhead incuned up to the date

we receive your notice, and demobilization costs, together with a reasonable profit on these costs. These costs include any tel111ination or

cancellation charges from our vendors, If you request, we will provide you with documentation in support of these costs,

4.3 IfyoLl fail to make any payment to us when due, and ifyoll do not make such payment within seven days of our giving you notice that you are

in default ofyoUl' obligation to make such payment, we sha11 have the right to cancel the Agreement.

ARTICLE 5. Dehw,

5, I We will not be in default and we \vill not be liable to you for loss or d:ll11age Wl1ich results from delay or failure to perfonn any of ou)'

obligations, if this delay or failure is caused by one or more cirCLImstances beyond our reasonable control ('Torce Majeure"), \vhether or not

existing or foreseeable on the date of the Agreement.

5,2 Force tVlajeure includes, without limitation, acts of God, war, acts of the public enemy, civil disorder. riot, sabotage, governmental action or

law or regulation, strikes, work slowdowns, or labor shortage or other labor problems, fire, nood, emthquake, severe weather, health and

safety considerations, embargoes, transportation sh0l1age or delay, fuel or material sh0l1age, failure of petfonnance by a vendor or

subcontractor, and your failure to give timely approval and comment to documents or otherwise perf011l1 YOllr obligations,

5.3 Our time ofperfonnance will be extended by the length of any delay caused by Force Majeure plus a reasonable time to reSume our nOnllal

operations.

5.4 If a delay results from Force Majeure, we will cxcrcisereasonable efforts to minimize the delay; provided; that we will have no obligation to

subcontract work or to work at over-time rates or otherwise incur additional costs and expenses,

5.5 If we are ready to ship, but shipment is delayed through no fault of aliI'S, then the date on which we are ready to ship will be regarded as the

date ofshipment and delivery for all plllvoses, including payment. You will be responsible for the costs \Ind risks ofstorage und handling and

risk of loss commencing with that date,

5.6 You will reimburse us for all extra costs and expenses which we incnr (i) as a result of:my delay which you cause, and (ii) for om reasonable

efforts to mitigate any delay caused by Force Majeure.

ARTICLE 6. Limited WlIrranh'.

6,1 We warrunt to you tll:1t the Goods will be delivered free from defects in material and workmanship,

6.2 If you discover a defect in material or workmanship during the Warranty Period (set forth below), yOLl must give us written notice within 10

(bys. We will, Elt our option, eithcr deliver to you a l'eplae~11lent part, F.O,B, point of ~hipment, and installation ther~of shall be your

t'csponsibility. or repair the defect in place or elsewhere on a straight-time basis, You will provide work area, utilities, access and egress to

enable us to perforll1otll' obligations under this Section 6.2,

6.3 We warrant to you that the Services, ifany. will be perf0l111ed in a good and wOI'kmanlike manner. If within the Wammty Period you discov'er

thElt any p0l1ion of the Services was not performcd in a good and workmanlike l1l[lnncr, yOll must give us notice within 10 days of your

discovery and we will pelform again that P0l1iotl of the Services,

6A The WalTilnty Period as to Goods will expirc 12 months from the date of delivery, The WillTanty Period as to Services will expire 12 months

from the date of completion of the Services.

SI<lIIdard Terms & emu/iliu!lS - D(!me.~lic

Celleral Chemical C0'1JOratioll

Creell River Works, Boiler C and D

Page j d3

App- 7
Submittal Number 43033880

6.5 We \vill have no obligations to you under Sections 6.1,6.2 and 6.3 if:

[i) you fail to operate or maintain the Goods in accordance with generally appro\'ed induslly practice: or

IIi) you fail to operate or maintain the Goods in accordance with instnlctions from LIS; or

(iii) you fail to give us written notice within 10 days of your discon~ry of a defect; or

(iv) the Goods have been altered or repaired by someone other than us; or

IV) the Goods have been in:imlled by someone other than us, and the installation is not done in accordance with our inSlnlctions.

6.6 We warrant to yOll that <It delivery, the Goods will be free of any liens or encLlmbrances. Ifthere are any such liens or encumbrances, we will

cause them to be discharged promptly after you have notified us of their existence.

6.7 We make no guaranty or \valTanty of the perfonnance of the Goous except as may be expressly identified as a Performance Guarantee

elsewhere in the Agreement. Any other data and infon1lation pertaining to perf0l111anCe of the Goods, wllether stated in the Agreement or

elscwbere, are for purposes of illustration or estimate only, and are not guaranteed.

6.8 THE EXPRESS WARRANTIES WE MAKE TO YOU IN THIS ARTICLE 6 AND THE PERFORMANCE GUARANTEE, IF ANY,

REFERRED TO IN SECTION 6.7 ARE THE ONLY WARRANTIES AND GUARANTEES WE WILL MAKE. THERE ARE NO OTHER

WARRANTIES OR GGARANTEES. WHETHER STATUTORY, ORAL, WRITTEN, EXPRESS, OR IMPLIED. IN PARTICULAR,

THERE ARE NO IMPLIED WARRANTIES OF MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE. THERE ARE

NO STATUTORY, ORAL. OR IMPLIED CONDITIONS. THERE ARE NO IMPLIED WARRANTIES AGAINST REDHIBITORY

DEFECTS, VICES, OR DEFECTS, HIDDEN OR OTHERWISE.

6.9 The remedies we provide to you in Sections 6,2, 6.3, and 6,6 and the remedies we expressly provide in connection with the Perfonnance

Guanmtee, if any, as referred to in Section 6.7 are, the only remedies you will have in th: event of a breach of warranty or Perfommnce

Guarantee.

ARTICLE 7. Limitation of Lillbilih·.

7.1 For purposes of thIS Alticle 7, the \vords "we", "our", "ours", and "us" mean the Seller and its Affiliates, and their employees, agents,

subcontractors, and suppliers,

7,2 Our liability to you under the Agreement or under any cause of action relating to the subject matter of the Agreement, whether based on

contract, ,valTanty (including warranty against redhibitory defects or vices). tort (including negligence), strict liability, profeSSional liability,

indemnity, contribution, or othenvise, will not exceed the base price of the Goods and Services.

7.3 We will not be liable to you under the Agreement or under any cause of action relating to the snbject matter of the Agreement whether based

on contract, walTanty (including warranty against redhibitory defects or vices), tOli (including negligence), strict liability. professional

liability, indemnity, contributIon, or othenvise, for loss of profits or revenue or business opportunity, loss by reason of shutdown of YOllT

facilities or inability to operate your facilities at full capacity, cost of obtaining other means for performing the function of the Goods,

increased cost of Goods or Services outside of our scope of work, costs of replacement power or capital, claims of your customers, or

incidental or consequential damages of any nature.

7.4 \Ve will not be liable to you for any loss or damage relating to any pOltion or component of the Goods or Services which you sustain after the

expiration ofthe WalTallty Period pertaining to such portion or component of the Goods or Services.

7.5 You will have waived your right to sue liS at lrl\v or in equity under the Agreement or under flny caUse of action relating to the subject matter

of th~ Agreem~nl unless you commcnce your suit within one year from the date on which you sustain the loss or damage which is the subject

ofvour suit.

7.6 Th~ provisions of this Attic1e 7 shall prevail over any inconsistent provisions elsewhere in the Agreement.

ARTICLE 8. Permits: Environmental and SafL'tv Responsibilities.

8.1 YOll wil1 (at your expense) obtain and maintain in force all permits and approvals necessary for the installntion and operation of the Goods and

the pcliormance ofthe Services,-and the disposal of\vaste products.

8.2 lfyoll fail to perf0n11 your obligations undcr Section 8, 1 or ifyoll fail to do the following:

(i) oper~ltc the Goods in complIance with <Ill applicable Irl\vs, mles, regulations, permits, and approvals, and with llperating instmctions

(including safety-related instmctions) which we issue from time to time:

(ii) dispose of any waste products in compliance with ajl rlpplicable laws, 11l1es. regulations. pemlits and approvals;

(iii) in operating the Goods and disposing of the waste products, avoid contribu(mg to air or water pollution or any condition which is

haZell'dolls to health; then you will indemnify us and hold us harmless and defend us at your expense from any claim. suit, or liability or

penalty which may result from stIch failure, and yOIl \vaive any immunity from this indemnity obligation which Illcty be conferred by

workers compensation laws.

,\RTICLE 9. Taxes.

9.l The Agreement price shall include, and we shall pay. all taxes and assessments for unemployment insurance, workers' compensation, social

sccmity ctnd disability benefits, and other taxcs which are based upon Ihe compens:llion pCliJ to persons employed by us or our subcontractors

for the performance of any Sen'ices under the Agreement.

9.2 The Agreement price shall include all applicable foreign, kderal, state and local income, duties, cxcise, and similar taxes payable with respect

to this Agreement pursll<lnt to laws or regulations in effect on the fiJ"st day of our Sttblllittalo The price excludes all Dlher dllttes, cxcise. or

simibr t<\xes assessed by allY govelllmental body or agency with respect to the Goods and ServiceS, induding increases in the ctl1lount of any

tax or duty due to changes in laws or rcgulations. which become cft"\:ctive after the first date of om Submittctl. lfwe aJ"c required to pay. or if

you are required to withhold any tax or duty not included in the price of the Goods and Sen'ic~, then the amount ofstich tax shall be paid to tiS

by you in addition to the prices provi{led herein.

S(aJld,wd Ter/1/s & Condilirms - Domestic

Genera! Chemica! Corporation

Green River Works, Boiler C and D

Poge 2 of3

App- 8
Submittal Number 43033880

9.3 YOll will payor reimburse us all sales. use, and other similar taxes. which may be levied or assessed in connection \vitll the transfer of the

Goods and Services furnished by us. Our price does not indude any such tax.es. You will provide us with any exemption cel1ificates and

other relevant documents in stlfficicnt time to claim any lax exemptions associated with this Agreement, but in all events will be supplied prior

to shipment of ll1utefial. Additional taxes along with associated interest find penalties assessed to liS by govemment authorities for denied

exemption shall be your responsibil ity.

9.4 The tirm price shall include or, if pricing is non-firm, we \vill invoice you for, and we shall pay, all sales, use, and other similar taxes,

associated with lools. rentals, and cotlsumables utilized dming erection or installation, or for the perfolmance of any other Services under the

Agreement.

ARTICLE 10. Patents.

10.1 \Ve will defend you !lgainst any suit which claims that the Goods infringe any united States or Canadian patent. We will satisfy any judgment

for damages entered against you in such suit. [I' sllch judgment enjoins yOll from using the Goods. then \ve shall at our option:

(i) obtain for you the right to continue using the Goods; or

(ii) eliminate the infringement by replacing or modifying all or part of the Goods; or

(iii) take back the Goods and refund 10 you all payments on the price which we have received. In this event, neither you nor \ve will have any

claim against the other under the Agreement or adsing out of the subject matter of the Agreement.

10.2 We \vill have no obligation under this Article 10 if you fail to notify us promptly of any claim or suit for infringement or if yOll fail to

cooperate with lIS in conducting the defense, or if infringement results from:

(i) lise ofthe Goods except in accordance with our instlUctiolls to YOll~ or

(ii) any change made to the Goods after we make delivery or made at yOul' request~ or

(iii) any portion of the Goods made pursuant to your design.

10.3 The remedies which we provide to you in this Article 10 are the only remedies yoll will have in the event of any infringement claim.

ARTICLE t I. Changes.

11.1 We will not make changes in the Goods or Services unless yOll and we have executed a written Change Order for such change.

11.2 The Change Order will include a price adjustment for any added costs or the change plus a reasonable profit.

11.3 If the change impairs our ability to satisfy OLlr obligations to you, including meeting delivery schedules and any Pelformance Guarantees, the

Change Order will include appropriate modifications to the Agreement.

11.4 If after the earlier of either (i) the date of the Submittal on which the Agreement is based or (ii) the date of the Agreement, new or revised

governmental or code requirements shall require a change in the Goods or Services, the chan~e \vill be the subject of a Change Order pursuant

to this Article II.

ARTICLE 12. Confidentiality; Use of Drawings.

12.1 You acknowledge that the infonnation which we submit to you in connection with any Submittal or this Agreement includes our confidential

and proprietmy infonmltion, both ofa technical and commercial nature.

12.2 You will not disclose our confidential and proprietary infommtion to third parties without our prior written consent.

12.3 You will not pennit any thil·d pal1y to fabricate components oflhe Goods from our druwings. YOll will indemnify us and hold us harmless and

defend us from any claim. suit, or liability based on personal injury (inclnding death) or property damage related to any component of the

Goods \vhich is fabricated by a third patty without our prior \vdttcn consent.

12.4 The Goods may contain software and related instl1lctions lind other materials which we and our suppliers have provided. Your use thereof

shall be subject to license conditions and other restrictions which we or our suppliers may impose as required to maintain confidentiality.

J2.5 You represent to LIS that you have the right to disclose to us any drawings or other infon11atiol1 which you provide to us under the Agreement,

without condition.

ART[CLE-13;,gEO Compliance.

13.1 We shall at all times comply with the requirements ofExecutiye Order 11246.

ARTICLE 14. End User,

1.:1-.1 If you are not the End l)ser of the Goods or Services. then you will use your best efforts to obwin the End L.:ser's conse-nt to be bOllnd to us by

the provisions of Article 6, Article 7, and Article 8 ("End User Consent").

14.2 IfyoLl do not obtain such End User Consent, then you shall indemnify tIS and our Affiliates and our a~ents, employees, subcontractors, and

suppliers tl'om any liability, cost, loss or expense for which we would not ha\·e been liable or from which wc wonld have been indemnified if

you had obtained the End User Consent.

ARTICLE 15. Entire ,-\ lfrcement.

15,1 The Agreement contains thc entire understanding between yOll Hnd us, und supersedes any prior oral and written understAndings between you

and us concerning the Goods and Services, including any document which is not expressly incOlvorated by reference into this Agreement.

YOli ackno\vledge that you are not relying on any representation not expressly contained ill the Agreement.

15.2 No modification to the Agreement will be effective unless in wl"iting duly executed by you and us.

15.3 The Agreement is binding on the parties aml their respective successors and assigns.

ARTiCLE 16, Invnlidit\'.

16.1 If a final decision of a COl\lt of competent jurisdiction holds invalid a portion of any sentence of this Agreement, or a sentence of any section

of this Agn.::el11ent, or a section of lIny Article, or any At·tiele of this Agreemcnt, the remainder of such sclltence or section or Article or this

Agreement, as the case Illay be, shall be valid.

ARTICLE 17. Governing Law.

17.1 The Agreement will be governed by and construed aecording to the laws of the State ofConnecticut. L'.S.A.

S/ilI/d,ml Terms & COi/ditirJl/s- Domestic

General Chemical Corporation

Green River Works, Boiler C and D

Page 3 on

App- 9
AECOM Env'lfonment

www.aecom.com

About AECOM Environment

Evolving to better serve global clients, AECOM has

formed AECOM Environment-a new global business

line that utilizes the environmental management

resources of ENSR, Earth Tech, STS and Metcalf &

Eddy. With over 4200 staff worldwide in 20 countries,

AECOM Environment is one of five new giobally

integrated business lines of AECOM (AECOM Water,

AECOM Transportation, AECOM Design, AECOM

Energy and Power). As AECOM Environment, we can

offer clients broader and deeper environmental health

and safety services with greater technicai expertise

across greater geographies-closer to sites and

facilities. Plus, we can deliver more value by leveraging

the full resources of AECOM's worldwide staff of 41,000

people in 450 offices. Our commitment to the success of

your projects and your organization is our top priority, as

we harness the global capabilities of AECOM.

Contact AECOM Environment

Asia: +603,7725.0380

Australia: +61.2.8484.8999

Europe: +39.02.3180.771

Latin America: +55.21.3526.8160

North America: +1,800.722.2440

Global: AskEnvironment@aecom.com

AECOM

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