P.1 

OAR Box 1865 

Prepped by Charmelle Mathews 

Document Number: 

71) IV-J-14 

Docket Number: 

A-83-27 

Printed 12/3/2008 9:15:30 AM Sheet 71 of 105 
P.2 

* % dbo 

COUNCIL OF INDUSTRIAL BOILER OWNERS 

A-83-27 IV-J-14 

PRESIDENT Novembe r 25 , 198 6 

William B mm 

Mrs. Wendy Lee Gramm 

Administrator 

Info. & Regulatory Affairs 

Office of Management & Budget 

Old Executive Office Bldg., Rm. 246 

17th & Pennsylvania Ave., NW 

Washington, DC 20503 

Dear Mrs. Gramm: 

We read with great interest your comments to the Environmental 

Protection Agency on the proposed NSPS for SO2 emissions from 

industrial boilers. Your questioning of the applicability of 

the percent reduction to industrial units is the central issue 

of this entire proceeding. 

In addition, CIBO has endorsed several other points raised in 

your letter, including the need for a performance type standard; the excessive incremental costs of the proposal, and the 

grossly understated annualized costs of the proposal due to 

use of an incorrect baseline. 

We urge you to consider one other very crucial and basic fact, 

namely the replacement nature of the current new boiler market. 

Several surveys, including our own, confirm that approximately 

80% of new units are installed not because additional steam 

capacity is needed but because it is economic to replace an 

old boiler with a new unit. It follows, therefore, that a 

standard which is overly stringent, and too costly, will dampen 

this process with severe consequences not only for boiler manufacturers, but more importantly for the public; because retention of these older boilers has an unfortunate environmental 

result as well. 

Since many of these units burn high sulfur residual oils, 

their replacement, even by new coal-burning boilers, will 

actually result in reduced SO2 emissions; therefore, their 

prolonged service means a continuance of these emissions. 

This fact was documented by a 1984 CIBO survey and several 

case histories in the docket. Please note Appendix C of the 

enclosed National Coal Council report on this subject, and the 

5817 Burke Centre Parkway. Burke. Virginia 22015 • (703) 250-9042 
P.3 

Mrs. Wendy Lee Gramm - 2 - November 25, 1986 

comments of ESI of Tennessee, attached. 

Taking this critical factor into account gives a startling 

contrast in the environmental outcome: 30,390 tons SO2 

removed, in the EPA case, vs 87,250 tons removed, using the 

CIBO recommendation and scenario. In other words, we believe 

our recommendation will actually result in three times the 

SO2 removed, at a fraction of the cost, and will result in a 

modernization of our aging industrial steam plant. This is 

further confirmed by the attached table from our comments, 

"Total SO2 Emissions in 1991." 

We would appreciate your review and consideration of these 

facts and their impact on the NSPS development process. 

Sincerely, 

/William B. Marx ' 

WBM:ag 

Enclosures 

cc: Randall E. Davis 
P.4 

TABLE I 

TOTAL S02 EMISSIONS IN 1991 

NUMBER BOILERS ANALYZED 

NUMBER NEW BOILERS 

(TONS/YEAR) 

PROJECTED BASELINE EMISSIONS 

NUMBER REPLACEMENT BOILERS 

NUMBER EXPANSION BOILERS14 

11/ 

REPLACEMENT BOILER EMISSIONS 11/ 

EXPANSION BOILER EMISSIONS15 

TOTAL EMISSIONS 

TONS REMOVED 

PERCENT REMOVED 

EPA 

250 11/ 

50 

159,800 

-0-

50 

127,840 

1,570 

129,410 

30,390 

19% 

CJBQ 

250 

250 

159,800 

200 

50 

58,040 

14,510 

72,550 

87,250 

55% 

DIFFERENCE 

200 

200 

-0-

69,800 

12,940 

56,860 

58,450 

36PTS. 

EMISSIONS REDUCTION 

RATIO, CIBO/EPA — — 2.9x 

11/ The EPA 510 boiler estimate has been disregarded as wholly 

unrealistic. However, as explained above, even if one accepts the 

unrealistic 510 boiler estimate, a similar result occurs. 

11/ Based on 80% new boilers for replacement; 20% for expansion. 

11/ Based on: EPA-90% removal; CIBO-55% removal. 

- 23 -
P.5 

Report on 

Industrial Boiler 

New Source 

Performance 

Standards 

GERALD BLACKMORE, Chairman 

Coal Policy Committee 

WILLIAM B. MARX, Leader 

NSPS Work Group 

JUNE 1986 

THE NATIONAL COAL COUNCIL 
Table of Contents 

P.6 

Executive Summary 1 

Introduction 3 

Chapter 1: Background 5 

Importance of Industrial Steam 5 

Energy Efficiency 5 

Industrial Energy Conservation and Its Impact on the Industrial 

Boiler Market 5 

Difference Between Industrial and Utility Boilers 6 

Chapter 2: EPA's Industrial Boiler NSPS Proposal 7 

Synopsis of Draft EPA NSPS for Coal-Fired Industrial Boilers 7 

Background 7 

Economic Analysis of EPA's Draft NSPS for SO: Emissions Control 

for Coal-Fired Industrial Boilers 8 

Deficiencies in cost estimates; Disproportionate Costs Imposed 

by Draft NSPS 8 

Fuel Switching 8 

Chapter 3: Need to Encourage Innovative Fuels and Technologies: 

e.g. Fluidized Bed Boilers 13 

Chapter 4: Other Considerations 15 

Importance of Coal to National Security 15 

The Need to Protect U.S. Industry's Competitive Position in 

International Markets 15 

Industrial Projects: Delay or Abandonment 15 

Chapter 5: Comparison of Various Control Strategies 17 

Chapter 6: Conclusions 19 

Chapter 7: Recommendations 21 

Bibliography 23 

Appendices 25 

Appendix A: Other Legal Provisions 27 

VII 
VIII 

Appendix B: Scrubber Technologies and Costs 29 

B1 Advent of Commercial Scrubbing Technology .. 29 

B2 Summary of Scrubbing Cost Survey 30 

B3 Flue gas desulfurization data, Case Histories 

"A" through "H" 31 

Appendix C: Letter to Fred L. Porter from William B. Marx 

dated July 30, 1985 regarding CIBO (Boiler) 

"Expansion Replacement Survey," and 

Attachments 53 

Appendix D: Letter to William B. Marx from R.N. Mosher dated 

April 11, 1986 63 

Appendix E: Letter to William B. Marx from Joseph B. 

Landwehr dated February 6, 1986 and 

Attachment 65 

Appendix F: Letter to William B. Marx from Karl F. Held dated 

September 19, 1983 and Attachment 69 

Appendix G: Comments of the Coal Policy Committee on 

Industrial Boiler NSPS Draft Report, April 22, 

1986 73 

Appendix H: Comments of the Coal Policy Committee on 

Industrial Boiler NSPS Draft Report, May 1986 75 

Appendix 1: Letter from B.R. Brown to the Secretary of Energy, 

dated December 19, 1985; the Secretary of 

Energy's response to Mr. Brown's letter, dated 

Januarvl3, 1986 77 

Appendix J: Description of The National Coal Council and The 

National Coal Council Membership Roster 79 

Appendix K: The National Coal Council Coal Policy Committee 

Membership Roster and the Industrial Boiler NSPS 

Work Group 83 
P.8 

PUBLIC HEARING 

SEPTEMBER 4, 1986 

ENVIRONMENTAL PROTECTION AGENCY 

40 CFR PART 60 

AIR POLLUTION; STANDARDS OF PERFORMANCE FOR NEW SOURCE 

INDUSTRIAL, COMMERCIAL, INSTITUTIONAL STEAM GENERATING UNITS 

STATEMENT BY: William L. Reeves 

President 

ESI, Inc. of Tennessee 
P.9 

TABL E O F CONTENT S 

PAGE 

COMMENTS AND EXECUTIVE SUMMARY 1 

CASE STUDIES 6 

Liggett & Myers Case Study 6 

American Fructose Case Study 9 

OPERATING & MAINTENANCE COST 13 

Calculation Data; Operating and Maintenance Cost 

When Using Wet or Dry Scrubbing Systems 13 

Liggett & Myers; Operating and Maintenance Cost 

Calculations 14 

American Fructose; Operating and Maintenance Cost 

Calculations 18 

EXHIBITS 22 

Exhibit 1: Liggett & Myers Economic Summary ... . 22 

New 90,000 PPH Coal Fired System 

Without Scrubber 22 

Exhibit 2: Liggett & Myers Economic Summary ... . 25 

New 90,000 PPH Coal Fired System 

With Dry Scrubber 25 

Exhibit 3: Liggett & Myers Economic Summary ... . 28 

New 90,000 PPH Coal Fired System 

With Wet Scrubber 28 

Exhibit 4: American Fructose Economic Summary .. . 31 

New 150,000 PPH Coal Fired System 

Without Scrubber 31 

Exhibit 5: American Fructose Economic Summary .. . 34 

New 150,000 PPH Coal Fired System 

With Dry Scrubber 34 

Exhibit 6: American Fructose Economic Summary .. . 37 

New 150,000 PPH Coal Fired System 

With Wet Scrubber 37 
P.10 

COMMENTS AND EXECUTIVE SUMMARY 

I am William L. Reeves, President of ESI, Inc. of Tennessee 

located in Atlanta, Georgia. I appreciate this opportunity to 

present ESI's views on the proposed New Source Performance 

Standards for Industrial Steam Generating Units. 

ESI, Inc. of Tennessee is a design engineering and construction 

firm which specializes in the turnkey design and construction of 

energy related projects. Over our eight year history, the 

primary thrust of our business has been the solid fuel fired conversion of industrial steam generating systems firing natural gas 

and No. 6 oil to primarily coal firing. These projects have all 

been in the 10-250 MMBTU/hour input range. We have worked primarily in the industrial sector and have in operation over 30 

major installations for many Fortune 500 companies. All of the 

systems which we have installed to date have complied in every 

respect with all local, State and Federal regulations regarding 

emission compliance. ESI recognizes its obligation to work 

jointly with the industrial marketplace to install clean, efficient steam generating systems which provide economic benefit to 

the industrial client without compromising our joint obligation 

to be responsible corporate citizens by maintaining a clean and 

healthy environment. 

In the eight years that ESI has been in business, we have seen 

significant evolution of the requirements for air pollution 

control equipment for new solid fuel fired installations. Up 

until this time, we believe that all previous regulations have 

been a reasonable compromise between its effect on the industrial 

consumer relative to capital and operating costs for emission 

compliance equipment and the anticipated improvements in the air 

quality. However, we feel that the new proposed NSPS regulation 

for sulfur dioxide emission compliance is totally unreasonable. 

- 1-
P.11 

Requiring every installation to achieve a 90% reduction in sulfur 

dioxide emissions, regardless of the sulfur content of the fuel 

to be used, is a knock-out blow to industry's endeavor to put our 

national energy policy on more solid ground through the utilization of our nation's most plentiful fossil fuel resource. Should 

these regulations be passed into law in their present form, it 

will have a devastating effect upon future industrial conversion 

to coal fired steam generating systems. These effects will be 

felt not only economically, but will ultimately result in poorer 

air quality, thus defeating the original intent of the regulations. 

In recent years, ESI has converted several industrial clients to 

coal fired steam generating systems, replacing existing No. 6 oil 

fired systems. In each and every case, after discussion with the 

client, we are quite certain that all of these projects would 

have been defeated because of economic nonfeasibility had they 

been required to comply with this mandatory SO2 reduction 

legislation. We have cited two specific examples in this document. The first example is a 90,000 pph coal fired system 

installed for Liggett & Myers Tobacco Company in Durham, North 

Carolina, which commenced operation in March 1984. The second 

example is a 150,000 pph coal fired system for American Fructose 

in Decatur, Alabama, which has just commenced operation in July 

1986. In these two examples we have demonstrated the resultant 

economic impact had either wet or dry scrubbing systems been 

required for either of these two installations. A summary of the 

results of these two case studies is shown on the following page. 

-2-
P.12 

LIGGETT & MYERS 

As Dry Wet 

Installed Scrubber Scrubber 

Capital Cost ($000) 2,900 3,750 3,550 

Annual O&M Cost (S000)1 164 244 319 

Investment Payback (Yr) 3.5 4.2 4.3 

Return on Investment (%) 25 19 17 

S02 Emissions (T/Yr) 281 74 28 

S02 Removal Cost ($/T)3 3504 792 840 

AMERICAN FRUCTOSE 

As Dry Wet 

Installed Scrubber Scrubber 

Capital Cost ($000) 5,350 6,650 6,320 

Annual O&M Cost ($000)1 255 500 891 

Investment Payback (Yr) 2.5 3.1 3.3 

Return on Investment (%) 38 29 26 

S02 Emissions (T/Yr) 1,410 4232 141 

S02 Removal Cost ($/T)3 -

 4 365 569 

1) These figures are additional costs above the previous base 

costs for the gas/oil fired systems. 

2) This system is only capable of 70% reduction which does not 

comply with proposed standards. 

3) This cost includes the annuity requirement for capital 

recovery at 8% over a 30 year life. 

4) This figure was calculated by comparing the availability of 

higher sulfur coals and their respective cost differential to 

the coal being burned. In the case of American Fructose, 

higher sulfur coals are available for the same price. 

-3-

L 
P.13 

We have included specific client contacts which have verified 

that neither of these projects would have gone forward had 

compliance with the current NSPS regulations for 90% sulfur 

reduction been required. We have also documented the fact that 

in both cases, had these projects been defeated and the client 

continued to burn oil, there would have been a significant 

deterioration of the air quality through increased sulfur dioxide 

emissions. These figures are consistent with the findings of two 

separate Federal Government sponsored studies, both of which 

independently concluded that S02 emissions from industrial 

sources have been decreased by as much as 46% between 1973-1983 

under current environmental control regulations. 

The obvious reluctance by industrial steam generators to install 

either wet or dry flue gas S02 scrubbing systems goes much deeper 

than a superficial economic evaluation. In the 100-250 

MMBTU/hour input size range, U.S. industry has demonstrated that 

it is not ready to install arguably proven and unreliable flue 

gas S02 scrubbing systems. These systems have an absolutely 

horrifying track record with regard to availability and reliability. Their performance to date has certainly been well below the 

98% plus level which industry has come to expect and demand from 

utility equipment. No coal fired boiler system that ESI has 

installed would have still gone ahead if a wet or dry scrubbing 

system was the only alternative to S02 emission compliance. 

Furthermore, industry as a whole has little more faith in 

fluidized bed combustion units than wet and dry scrubbers. Here 

again, the track record of availability and reliability has not 

yet come up to industrial expectation standards. It is for this 

reason that mandatory implementation of these technologies by all 

prospective coal conversion candidates would have a devastating 

negative effect upon the sorely needed upgrading of the 

industrial producers' steam generating units. 

-4-
In summary, ESI, Inc. of Tennessee is opposed to the portion of 

the NSPS regulations regarding the requirement for 90% sulfur 

dioxide reduction regardless of the sulfur content of the fuel. 

We feel that, as was the intent of the Clean Air Act and PSD 

review, the economic impact of proposed environmental control 

regulations should be considered when setting forth required 

sulfur dioxide emission controls. We believe it is much more 

prudent to set a specific maximum sulfur dioxide emission level 

and let industry use whatever resources and technology are 

available to it to achieve this emission level. In lieu of the 

insignificant contribution to the "acid rain" problem by the 

industrial steam producer, we believe this to be an extremely 

reasonable request. Numerous data has been generated to prove 

that less than 1.5% of the total sulfur dioxide emissions cone 

from industrial sources. 

Furthermore, we believe that if this legislation is enacted in 

its present form, it will deal an even more severe blow to companies such as ESI. For the past three years we have maintained 

an annual sales volume of roughly $12 million in design and 

construction projects. Had these projects been required to conform with these proposed NSPS S02 reduction regulations, ESI 

would have very likely performed less than 10% of that business 

volume. If this legislation is passed, we can immediately expect 

this magnitude of sales volume erosion. ESI will be required to 

perform a major restructuring of its business or become 

insolvent. We believe that ESI serves a useful purpose in our 

economy because we are helping the industrial producer become 

more independent from an energy standpoint, fulfilling the goals 

of our National Energy Policy. 

MISC.BR/NSPS 

-5-
P.15 

CASE STUDIES 

LIGGETT t. MYERS 

In February of 1983, ESI, Inc. of Tennessee began a project for 

Liggett & Myers Tobacco Company at their downtown Durham, North 

Carolina facility. This project was the design and construction 

of a new coal fired steam plant addition which would be capable 

of producing low pressure steam for present and future satisfaction of all process steam and space heat requirements. In addition, this system had the future capability of being retrofitted 

for electrical cogeneration. Liggett & Myers at that time was 

utilizing three existing No. 6 oil fired boilers for these 

requirements. The sole motivation for this conversion to coal 

fired stea- was the return on investment generated by the differential fueling costs between stoker coal and No. 6 oil. This 

facility has never had the ability to burn natural gas. 

This new coal fired system was a complete stand-alone plant consisting of a high pressure design, 90,000 pph boiler utilizing a 

rear ash discharge chain grate stoker for the firing equipment. 

Because of the relatively low emissions from this type of stoker, 

the system was permitted using only a mechanical multicyclone 

sidestream baghouse system as the method of particulate emission 

control. Nitrous oxide emissions were controlled by the firing 

equipment and the sulfur dioxide emissions were controlled by 

burning less than 1% sulfur coal. The existing boilers at that 

time were burning No. 6 oil. with a sulfur content of 2.1%. At 

the time of the conversion, the annual energy consumption of this 

facility was 351,000 MMBTU with a projected annual growth of 1%. 

This new facility was put into operation in March of 1984 and has 

been operating continuously since that time. 

The project cost for this facility at that time was $2,900,000 

and, as can be seen in Exhibit 1, yielded an estimated 3.5 year 

-6-
P.16 

payback on the capital investment with a projected 25% rate of 

return. At the time this investment decision was made, this 

project was marginally in excess of Liggett & Myers' parent 

company's required hurdle rate for capital projects. This boiler 

has a maximum rated input of 108.5 MMBTU/hour and as such, if it 

were being considered today, this installation would fall under 

the restrictions of the new proposed NSPS regulations for boilers 

between 100-250 MMBTU/hour. It is absolutely certain that if 

Liggett & Myers at the time of construction would have had to 

comply with the proposed NSPS regulations relative to sulfur 

dioxide removal, this entire project would not have been 

constructed because of the additional capital and operating cost 

effect on the return on investment. Exhibits 2 and 3 indicate 

the effects of these costs on the project economics. The additional capital costs required for the dry and wet scrubbing 

systems have been estimated at $850,000 and $650,000, respectively. In either case, had either the dry scrubbing system 

which is not capable of 90% reduction, or the wet scrubbing 

system been required, the project would not have gone forward. 

The resultant nonfeasibility of this project, had it been subject 

to these rigid NSPS regulations for sulfur dioxide removal, can 

be verified by talking with Mr. Ken Daber of Liggett & Myers at 

919-683-8948. 

The effect of these regulations on this project would have had a 

significant overall negative effect on the local air quality as 

well as the economy. As previously stated, at the time of 

Liggett & Myers' installation of this new system, their current 

annual fuel usage was 351,000 MMBTU with an annual projected 

growth of 1%. Assuming that no growth was experienced, the maximum annual actual sulfur dioxide emissions using the permitted 

maximum 1% sulfur coal has been as follows: 

- 7-
P.17 

351,000 MMBTU It Coal 0.01 »S

 2 *so2 Ton 

Yr 12,500 BTU II Coal

 X II S X 2,000 I 

= 281 Tons of Sulfur Dioxide per Year 

Previously, the existing No. 6 oil fired boilers were burning a 

2.1% sulfur oil, even though they were actually permitted to burn 

a higher sulfur content oil. Therefore, their actual annual 

sulfur dioxide emissions, if they had continued this operation as 

opposed to switching to coal, would have been as follows: 

351,000 MMBTU 1# Oil 0.021 #S

 2 *S02 Ton 

Yr 18,000 BTU

 X 1# Oil X 1 IS 2,000 # 

= 410 Tons of Sulfur Dioxide per Year 

Therefore, the actual sulfur dioxide emissions in the downtown 

Durham area have been decreased by a minimum of 129 tons per year 

for the last 2-1/2 years, or a total of 323 tons. 

In addition, over this same time period, over 35,100 tons of 

regionally mined coal have been consumed instead of over 

5,850,000 gallons of primarily foreign produced oil. Over 

$3,000,000 of equipment and services have been inserted into the 

economy which, after you apply the cascade effect, have resulted 

in several million dollars of contribution to the Gross National 

Product. Also, the foreign trade deficit might well have been 

decreased. 

Had Liggett & Myers been required to limit sulfur dioxide 

emissions to a specific level, such as for example 1.6 t/MMBTU, 

rather than to achieve a specific percentage reduction regardless 

of the fuel sulfur content, a slightly lower sulfur coal would 

very likely have been found as a possible supply for this new 

facility with only a very slight impact on fuel cost. In this 

case, the project would still have gone forward and the stated 

benefits would still have been realized. 

- 8-
P.18 

AMERICAN FRUCTOSE 

In April of 1985, ESI, Inc. of Tennessee began a project for The 

American Fructose Company at their Decatur, Alabama facility. 

This project was the design and construction of a new coal fired 

steam plant addition which would be capable of producing low 

pressure steam for satisfaction of all process steam and space 

heat requirements. In addition, this system had the future capability of being retrofitted for electrical cogeneration. 

American Fructose at that time was utilizing two existing natural 

gas and No. 6 oil fired boilers for these requirements. The sole 

motivation for this conversion to coal fired steam was the return 

on investment generated by the differential fueling costs between 

stoker coal and natural gas or No. 6 oil. 

This new coal fired system was a complete stand-alone plant consisting of a high pressure design, 150,000 pph boiler utilizing a 

front ash discharge traveling grate spreader stoker for the 

firing equipment. The system was permitted using a full size 

pulse jet fabric filter collector for the particulate clean-up 

equipment. The required particulate emission compliance rate was 

0.05 #/MMBTU. Nitrous oxide emissions were to be controlled by 

the firing equipment and the sulfur dioxide emissions were to be 

controlled by burning less than 1.5% sulfur coal. The existing 

boilers at that time were burning No. 6 oil with a sulfur content 

of 3.0% maximum. This project was rather unique because all of 

the residual heat in the oil fired flue gas was being used in the 

animal feed byproduct dryer. The new system required maintaining 

the baghouse exit flue gas temperature at 400°F so that the new 

coal fired flue gas could also be used in this drying system. 

The feed dryer exhaust gas goes to a low energy wet scrubber and 

then up a 140-foot fiberglass stack. There is no reagent added 

to the existing wet scrubber in an effort to eliminate sulfur 

dioxide emissions. At the time of the conversion, the annual 

-9-
P.19 

/ 

t 

energy consumption of this facility was approximately 1,260,000 

MMBTU. This new facility was put into operation in July, 1986 

and has been operating continuously since that time. 

The project cost for this facility at the time it was sold was 

$5,350,000 and, as can be seen in Exhibit 4, yielded an estimated 

2.5 year payback on the capital investment with a projected 38% 

rate of return. Again, at the time this investment decision was 

made, this project was marginally in excess of American 

Fructose's parent company's required hurdle rate for capital 

projects. This boiler has a maximum rated input of 180 

MMBTU/hour and as such, if it were being considered today, this 

installation would fall under the restrictions of the new proposed NSPS regulations for boilers between 100-250 MMBTU/hour. 

It is absolutely certain that if American Fructose at the time of 

construction would have had to comply with the proposed NSPS 

regulations relative to sulfur dioxide removal, this entire 

project would not have been constructed because of the additional 

capital and operating cost effect on the return on investment. 

Exhibits 5 and 6 indicate the effects of these costs on the 

project economics. The additional capital costs required for the 

dry and wet scrubbing systems have been estimated at $1,300,000 

and $970,000, respectively. In either case, had either the dry 

scrubbing system which is not capable of 90% reduction, or the 

wet scrubbing system been required, the project would not have 

gone forward. The resultant nonfeasibility of this project, had 

it been subject to these rigid NSPS regulations for sulfur 

dioxide removal, can be verified by talking with Mr. Jack Mehok 

of American Fructose at 219-659-2000. 

Again, as was demonstrated in the case with Liggett & Myers, the 

effect of these regulations on this project would have had a 

significant overall negative effect on the local air quality as 

well as the economy. This installation is currently burning coal 

-10-
with a sulfur level of 1.4%. The annual actual sulfur dioxide 

emissions using 1.4% sulfur coal will be as follows: 

1,260,000 MMBTU II Coal 0.014 IS

 2 fso 2 Ton 

Yr 12,500 BTU 1# Coal 1# S 2,000 * 

= 1,410 Tons of Sulfur Dioxide per Year 

Previously, the existing boilers had been burning maximum 3.0% 

sulfur No. 6 oil. They were actually permitted to run both 

100,000 pph boilers at full capacity using 3.0% sulfur No. 6 oil. 

The actual annual sulfur dioxide emissions, if they had continued 

this operation as opposed to switching to coal, would have been 

as follows: 

1,260,000 MMBTU „ 1# Oil „ 0.030 #S

 2 *s 0 2 „ Ton 

X — : z-z-z— X Yr 18,000 BTU * 1# Oil 1 #S 2,000 # 

= 2,100 Tons of Sulfur Dioxide per Year 

Therefore, through this coal fired conversion, the actual annual 

sulfur dioxide emissions in the Decatur, Alabama area have been 

decreased by a minimum of 690 tons per year. 

Here again, for every year this new steam plant operates, over 

50,400 tons of regionally mined coal will be consumed instead of 

8,400,000 gallons of primarily foreign produced oil. Over 

$5,500,000 of equipment and services have been inserted into the 

economy which again, after you apply the cascade effect, will 

result in the addition of several million dollars of contribution 

to the Gross National Product. Here again, the foreign trade 

deficit has been decreased. 

Had American Fructose been required to limit sulfur dioxide 

emissions to a specific level, such as for example 1.6 #/MMBTU, 

rather than to achieve a specific percentage reduction regardless 

of the fuel sulfur content, a slightly lower sulfur coal would 

very likely have been found as a possible supply for this new 

-11-
P.21 

facility with only a very slight impact on fuel cost. In this 

case, the project would still have gone forward and the stated 

benefits would still have been realized. 

MISC.BR/NSPS 

-12-
P.22 

OPERATING & MAINTENANCE COST 

Calculation Data for Increased Operating and Maintenance 

Cost When Using Wet or Dry Scrubbing Systems 

Assumptions: 

1. Dry flue gas scrubbing system (lime) data: 

A. Water consumption = 0.30 gpm/1,000 cfm 

B. Water cost = $1.25/1,000 gal 

C. Pumping HP = 1.4 HP/1,000 cfm 

D. Lime consumption = 1.4 tons/ton S02 removed 

E. Lime cost = $70/ton 

F. Byproduct disposal cost = $20/ton S02 removed 

G. System pressure drop = 14 in. w.g. 

H. Annual maintenance cost = 3% of capital cost 

2. Ket flue gas scrubbing system (soda ash) data: 

A. Water consumption = 0.5 gpm/1,000 cfm 

B. Water cost = $1.25/1,000 gal 

C. Pumping HP = 1.25 HP/1,000 cfm 

D. Soda ash consumption = 1.8 tons/ton S02 removed 

E. Soda ash cost = $180/ton 

F. Byproduct disposal cost = $80/ton S02 removed 

G. System pressure drop = 12 in. w.g. 

H. Annual maintenance cost = 3% of capital cost 

MISC.BR/NSPS 

-13-
P.23 

LIGGETT «, MYERS 

Dry and Wet Scrubber Operating and Maintenance 

Cost Calculations 

Assumptions: 

1. Full load gas flow = 40,000 ACFM £ 350°F. 

2. Fan power and flow calculations will consider 50% of 

this volume (20,000 ACFM) to account for additional 

excess air at approximate 1/3 average load. 

3. Power cost = $0.045/KWH. 

4. Operating hours = 8,400 hours/year. 

5. ID fan efficiency at average load = 65%. 

6. Current sidestream system pressure drop = 4.0" w.g. 

7. Electrical motor efficiency = 90% and power factor = 

85%. 

Case I = Dry Scrubber with Lime Reagent: 

1. Additional water cost 

20,000 ACFM x ^^ Q g ^ = 6.0 GPM 

6.0 GPM x i^g^HR x 60_MIN x T _ $ f e 2 5 _ = $3f730/y R 

2. Reagent cost 

For 70% reduction, the S02 removed equals 0.70 x 281 

tons/year = 197 tons S02/year. 

197 Tons S02 1.4 Tons Lime $70 _ $1 9 300/ v 

YR

 X Ton S02 X ToT $19,300/YR 

3. Byproduct disposal cost 

197 Tons S02 <?0 

YR " X T#S ^ - 53,940/YR 

-14-
P.24 

4. Additional electrical cost 

a) Pumping HP 

20,000 ACFM x ^QOVCF M = 28 HP 

b. ID fan HP 

20,000 CFM x (14.0 - 4.0) In. W.G. A0 u n 

6,356 x 65% " 4 8 H P 

c) Total additional cost 

7 6 Hj> 8,400 HR 0.7 46 KW $0.045 

HR YR HP x 0.90 EFF x 0.85 PF KWH 

= $28,000/YR 

5. Additional maintenance cost 

The additional maintenance cost equals 3% of the differential capital cost which is estimated to be 

$850,000. Therefore, it is equal to: 

$850,000 x 0.03 = $25,000/YR 

Therefore, in summary, the additional electrical, maintenance, and operating costs associated with the dry 

scrubbing system would be as follows: 

Cost Without Cost With 

Item Scrubber Scrubber 

Electrical $50,400 $78,400 

Maintenance 43,500 69,000 

Operating 70,000 97,000 

These figures are all considered as additional costs above 

and beyond the base cost for the oil fired system. 

Exhibit 2 reflects these changes in the capital, electrical, 

maintenance, and operating costs compared to the original 

costs as shown in Exhibit 1. 

-15-
P.25 

Case II * Ket Scrubber with Soda Ash Reagent: 

1. Additional water cost 

20.00 0 ACFM x 1%ji 0

G

ff! M - 10 GPM 

10 G M „ BMOOZHR x eo ^ x _ | K 2 | _ . S6>300/yR , 

2. Reagent cost 

For 90% reduction, the S02 removed equals 0.90 x 281 

tons/year = 253 tons S02/year. 

253 Tons SQ2 1.8 Tons SA $180 _ S8 2 u00/V R 

YR

 X ~ Ton S02 X ToTT " >82,000/YR 

3. Byproduct disposal cost 

253 Tons S02 con 

YR " X ToT = 520,200/YR 

4. Additional electrical cost 

a) Pumping HP 

20,000 CFM x x^o5o CFM

 = 25 H P 

b. From Case I, additional ID fan HP = 48 HP 

c) Total additional electrical cost 

73 HP_ 8,400 HPv 0.74 6 KW $0.045 

HR

 X YR HP x 0.90 EFF x 0.85 PF KWH 

= $26,900/YR 

5. Additional maintenance cost 

The additional maintenance cost equals 3% of the differential capital cost which is estimated to be 

$650,000. Therefore, it is equal to: 

$650,000 x 0.03 = $19,500/YR 

Therefore, in summary, the additional electrical, maintenance, and operating costs associated with the wet 

scrubbing system would be as follows: 

-16-
P.26 

Cost Without Cost With 

Item Scrubber Scrubber 

Electrical $50,400 $ 77,300 

Maintenance 43,500 63,000 

Operating 70,000 178,500 

Exhibit 3 reflects those changes in the capital, electrical, 

maintenance, and operating costs as compared to the original 

costs as shown in Exhibit 1. 

MISC.BR/NSPS 

-17-
P.27 

AMERICAN FRUCTOSE 

Dry and Wet Scrubber Operating and Maintenance 

Cost Calculations 

Assumptions: 

1. Full load gas flow = 66,000 ACFM @ 350°F. 

2. Fan power and flow calculations will consider 56,000 

ACFM to account for 10% additional excess air at the 

average load of 120,000 pph. 

3. Power cost = $0.045/KWH. 

4. Operating hours = 8,400 hours/year. 

5. ID fan efficiency at average load = 68%. 

6. Current baghouse system pressure drop = 4.0" w.g. 

7. Electrical motor efficiency = 90% and power factor = 

85%. 

Case I = Dry Scrubber with Lime Reagent: 

1. Additional water cost 

56,000 ACFM x ^QQ Q CF'M

 = 16, 8 GP M 

16.0 CPM x laiOO^HR x 60 ^ x T _|^5 _ . $10 _600/y R 

2. Reagent cost 

For 70% reduction, the SO2 removed equals 0.70 x 1,410 

tons/year = 987 tons S02/year. 

987 Tons S02 1.4 Tons Lime $70 _ sg , 700/V R 

YR

 X " Ton S02 X To"n" ~ 596,700/YR 

3. Byproduct disposal cost 

987 Tons SO2 S20 

YR ' X T&TToi = 519,700/YR 

-18-
P.28 

4. Additional electrical cost 

a) Pumping HP 

56,000 ACFM x ^o^F M

 = 7 8 H P 

b. ID fan HP 

56,000 CFM x (14.0 - 4.0) In. W.G. ,,, U D 

6,356 x 65% " 13 6 H P 

c) Total additional cost 

214 HP 8,400 HR 0.746 KW $0.045 

HR YR HP x 0.90 EFF x 0.85 PF KWH 

= $78,900/YR 

5. Additional maintenance cost 

The additional maintenance cost equals 3% of the differential capital cost which is estimated to be 

$1,300,000. Therefore, it is equal to: 

$1,300,000 x 0.03 = $39,000/YR 

Therefore, in summary, the additional electrical, maintenance, and operating costs associated with the dry 

scrubbing system would be as follows: 

Cost Without Cost With 

Item Scrubber Scrubber 

Electrical $ 75,600 $154,500 

Maintenance 79,500 118,500 

Operating 100,000 227,000 

These figures are all considered as additional costs above 

and beyond the base cost for the oil fired system. 

Exhibit 5 reflects these changes in the capital, electrical, 

maintenance, and operating costs compared to the original 

costs as shown in Exhibit 4. 

-19-
P.29 

Case II = Wet Scrubber with Soda Ash Reagent: 

1. Additional water cost 

56,00 0 ACFM x 1°ooOGCFM

 = 2 B GP M 

2 8 GP M x JUiOO ^ x 60 ^ x T _$K2S K r

 . sl7 , 600/y R 

2. Reagent cost 

For 90% reduction, the SO2 removed equals 0.90 x 1,410 

tons/year = 1,270 tons S02/year. 

3 . Byproduc t disposa l cost 

1,27 0 Tons S0 2 CPQ 

~ YR " X T§H = $102,000/YR 

4 . Additiona l electrica l cost 

a ) Pumping HP 

56f 0 0 0 CFM x ^ 0 U U g PM = 70 HP 

b . From Cas e I , additiona l ID fan HP = 136 HP 

c ) Tota l additiona l electrica l cost 

206 HP_ 8,400 HR 0.746 KW $0.04 5 

HR

 X YR HP X 0.9 0 EFF x 0.8 5 PF KWH 

= $75,900/YR 

5 . Additiona l maintenanc e cost 

The additional maintenance cost equals 3% of the differential capital cost which is estimated to be 

$970,000. Therefore, it is equal to: 

$970,000 x 0.03 = $29,100/YR 

Therefore, in summary, the additional electrical, maintenance, and operating costs associated with the wet 

scrubbing system would be as follows: 

-20-
P.30 

Cost Without Cost With 

Item Scrubber Scrubber 

Electrical $ 75,600 $151,500 

Maintenance 79,500 108,600 

Operating 100,000 630,600 

Exhibit 6 reflects those changes in the capital, electrical, 

maintenance, and operating costs as compared to the original 

costs as shown in Exhibit 4. 

MISC.BR/NSPS 

-21-
P.31 

EXECUTIVE. sUMMAKY 

f-r eper e/d ro r 

EXHicI T l LIGGETT fc MYERS 

NEW 90,OC" TFH :C<AL FIRED SYSTEM WllHuOl ©CRUBBfcR 

09-01-19o j 

Fue l Eavin^b Ne-t Cash Flow 

•i>e.t ;t : (» > 

1 l,0:-i,66 3 640,so y 

2 l,0r/,2i V 7o7,20 4 

3 1,17*4,632 787,666 

•i i,Z57,el O 82*4, 1S6 

3 1,3*6,«402 663,27 V 

Payfcarl< o-f Initia l In.tBtxent : J. 5 Year s 

Aftt-la X ri*fO»«?r'y Ct 

7

c'.a l Ir.vestn.cr.t: 3. ' Year s 

retur n or. iiwoit.T.s.it: 25 % 

l-.'c-t Prtttri t Vilu e 

(c;«_cunt* d a t 10.0%): «3,242,76 7 

Tota l Capita l C=st: *2,900,00 0 

by 

ESI IMC. OK TENf4t3SEE 

811C Livingsto n Cour t 

Marietta , Ct-rgi * 3006 7 

inO^i 427-620 0 

-22 -
ECONOMIC ANALYSIS 

EXHIBI T 1 LIGOEII k MYERS 

NEW 90,OC'C FFH COAL FIRED SYSTEM WITHOUT SCRUbBER 

P.32 

'his e>:-ial/«ia is -for a c.cal system that is to replace an oil system. 

3 i 1 Coal 

L b s Steam pe r Ho-.' 

I ." " V 6 a S. tr 

the n 

r'r.r.ual C^trati i g i-our i 

'Jrir t as e 

the n 

33350 33360 

:.0 % far 30 yr& 1.0% fo r 30 yri 

C O X fcr O yr * 0.0 % -for O yri 

G40u 

0.0 % -for O yr 

0. 0% -far 0 y n 

6*00 

U.OV. fo r O yr s 

O. 0% fo r O yr s 

Averag e Utilizatio n 

roi 11r Eff iiisncy 

100% 

3u.0% 

1002 

100% 

80.0 % 

1002 

Oi1 Mo.<2,4,6) 

'ri ce/gal 

C !/ M C = sts 

Electric& l 

Mai nteiianc e 

Operilor s 

*0.7500 

*0 

*0 

SO 

12500 BTUs/lb 

S52.0 0 Price/ton 

•50400 

•43SOO 

S7OO0O 

0 k M Inflation rale 6.0% 

1 natal 1 a Iion per ioi 14 months 

Fuel ir.flAtio--- rate 

da-i-19 installation 0.0% 0.0% 

then 6.0% for 5 yrs 6.0% for 5 yrs 

and 0.0% for 25 yrs 0.0% for 2o yrs 

Federal ta>: rate*. 46. C^ 

Federal tax credit: 10.0% 

St£te tax rate: 6.0% 

State ta.-. credit: O.O'* 

Depr<ci±tlcn period: S yrs 

Ve-p-- ec i at i on method: ACRS 5-year 

Lean period*. C >r& 

Loan inter tit rate: 0 % 

Equity i rte;-est rate: 12 % 

Eqi.:*.>• capital: * 29OO000 

Capital cost: « 27OOO00 

Cp»ratir.g life: 30 yr% 

rifeccjnt .ate: IC % 

Electrical power rate: * 0 /kwh 

Turti'.: v.Ater rate: 30 lb stm/kwh 

Electricity price inflation rate 

then 

0.0% for O yri 

0.0% for 0 yri 

-23-
P.33 

EXMII11 I L1KET1 t ITERS 

HL. 90,000 PPh COAL Ut£J iWlM llTMOUl fcCMltt 

Ettlii'.tt First Tear Coamtplioi I Cotti 

Aniiil Oil ttrmiptio»: 2,J3»,9^0 g«l 

tt K.73C-9 pr j*i : 81,734,902.80 

Anrii) Fat; Cc:tJ«pli»r: (>&ita:i) ICO I tirrg) Irci colli 

;j,C:? ton it IC2.0C *»r U«: 8730,039.54 

C:it cl :j^!»3rftU: Fkti: 10.00 

4730,039.34 

.t-ln fLG* AWljI j 

CoifiKiis oi Ait»r-»'..vi F^tii (thousands ol Jollirs) 

Tl*.'* 

les'.illi':;; 1 2 3 4 £ 6-1C 11-20 21-30 

Pro-i:» Cost « 290C.0C1 

Lei-. *ro:»t<i C.0J 

I»»t. P*r>:4 :«t. ( COC! 

S»t C Ci! Ccs'.s 1T54.5C U73.S0 2011.44 215.3.45 2305.4B 11877.89 25604.35 28233.13 

ri-^:tf< S>=ti» fi.\ Ccsti 730.G- 7ol.5i 834.74 895.84 939.08 4941.20 10631.41 11763.78 

:-rrtt» ; <l*:,-::i'. ; COC O.OC 0.00 COC COO 0.00 0.00 0.00 

c

. l l :».RJ S 10H.34 1077.22 il.--t.i3 !257.bl 1346.40 4936.68 14952.94 16517.35 

MliliiBi l 3 fc * U!.?S 173.73 184.16 193.21 296.92 1236.41 38e8.83 4923.48 

Sepr i-iatiir 411.21 404.10 5.*9.55 5:8.35 378.35 0.00 0.00 0.00 

U.ufA ceo O.OC COO 0.00 0.00 0.00 0.00 9.00 

FrtU : li'.Cmt 4<i7.7! 317.3s 411.97 483.64 360.93 370C27 110S4.il 9388.B7 

S'.tlt It.ii 19.04 24.72 29.03 33.64 342.02 463.05 373.33 

r Mfi i 193.39 137.24 17E.14 209.22 242.33 2464.10 4792.77 4146.23 

T»: CraliU ' 29C0C 

fat f»r^.;i («:•;. '.».| 227.26 161.10 2K.U 245.H 284.73 2(93.46 3624.30 4867.31 

Ui sty-..A:o- 413.23 iCi.li 3/8.33 373.33 378.35 0.00 0.00 0.00 

9il.:l Loai Pa>r« '. CO: O.J) O.OC COO 9.00 O.OC 0.00 0.00 

U1::\ E*ll> M I 2C7.•?: 

fc* Cr.f F'w I 2919.191 

640.31 757.29 787.47 124.16 143.28 2893.44 3426.30 4847.31 

-24 -
P.34 

EXECUTIVE SUMMARY 

F r epar ed For 

EXMITIT 2 LIGGETT t- MYERS 

ME1; 90, CCC '•"'H COAL FIRED SYSTEM WITH DRY SCRUBBER 

09-01-19£,6 

Fuel Savings Net Cash Flow 

Year («) i*> 

1 1,024,863 659,289 

2 1,097,219 811,366 

3 1,174,682 825,254 

4 1,257,615 858,926 

5 1,346,402 895,191 

Payback cf Initial Investment: 4.2 Years 

Avt*~-tax Recover/ of 

Total Investment: 4.2 Years 

Retv.rr. ot. Investment: IV* % 

Net P: c-sent. Value 

(discoantei at 10.0%): *2,029,293 

"eta: Capital Cost: 43,750,000 

by 

ESI INC. OF TENNESSEE 

311C Livingston Court 

Marietta, Georgia 30067 

(404) 427-6200 

-25-
P.35 

ECONOMIC ANALYSIS 

EXHIBIT 2 LIGGETT 4. MYERS 

N EW 90, COO F'PH CCAL FIRED SYSTEM WITH DRY SCRUBBER 

TV. il l.-.sl is ? c • a cca l %, ste m thi t is to replac e a n oi l system , 

O i 1 Coal 

L*-'« £ttr.-» ptrr Hour 

Incr eei« 

tl.en 

33360 33360 

1.0% for 30 yrs 1.0% for 30 yrs 

0.0% for 0 yrs 0.0% for 0 yrs 

A-.iv.is.' Cpe;-ating Hours 3400 U400 

Increase O.C". for 0 yrs 0.0% fc:- 0 yrs 

tr.Ph 0.0% fcr 0 yrs O.OX fcr 0 yrs 

Average L' til ir at ion 

Boiler Efficiency 

STUs/Lt :t(:M 

Oil No. < 2,4,6! 

Pr ice/gal 

0 ti M Cost s 

Electr ical 

M a i Tt t «• r. a n c e 

Ope r atcc s 

6 .O* 

14 

»0 

D C 

100% 

80.C% 

1002 

6 

750C 

*0 

*0 

eo 

-tr.s 

100% 

80.0 % 

1002 

12500 BTUs/lb 

S52.00 Price/ton 

•78400 

*69000 

*97000 

0 t: M In- Istioi: rrfte 

Installation period 

Fuel inflation rate 

during installation 0.0% 0.0% 

ther. 6.0% for 5 yrs 6.0% for 5 yrs 

ar.d 0.0% for 25 yrs 0.0% for 2b yrs 

Federal tax rate: 46.0 % 

Federal tax credit: 10.0% 

State tax rate: 6.0% 

State ta~ credit: 0.0% 

Depreciation period: 5 yrs 

Depreciation nethc-d: ACR3 5-year 

Lour. p»rir»i: 0 yrs 

Loan i'iter est »ate: 0 % 

E:;\>ity i r, tr-r*«=. t rate: 12 % 

ET^.'t/ capita!: « 3750000 

Ciplia! cost: « 375OO00 

"•pf- atlrg life: 30 yrs 

Discount rate: IO % 

Electrical power rate: » O /kwh 

Turbine ttater rate: 30 lb stm/kwh 

Electricity price inflation rate 0.0% for O yri 

then 0.0% for O yri 

-26-
P.36 

EXrilir. 2 UWtTI k RrEtl 

IfU 90,000 PFh CU- Kiu.1 iTSIEN allH it; SCtt'ltf 

Sst'.-w'.ti First Tta* ConiuipU;* k CoiU 

»r.-.:il Oil C---.ik«c*ior.: 2,339,87t i*. 

at 8-.73X pi: ja.: 81,7:4,U2.SJ 

Areca: Fat! Coimip'.io.: (»ii.jii3 1*; *> t.-fj) 4rca coal) 

•.•",::" U; s al i:i.C: ;tr Un ; 4730,039.34 

::,'. ;J :.;;:i:*:.'.i: r»r!: M.OO 

*730,C39.!s 

CASH FLR AKm-Ti!" 

Cupariion si Altt.'tativt 'atls lU-itaats oi f:lla:il 

tars 

o:tjl:.ii:n 1 2 3 4 3 6-10 11-20 21-30 

frz.tti Cost « 375CO0! 

Icir, °-c:t»2i 0.00 

I-i!*. Ptrici >'.. I 0.301 

fas 3: 0:1 Csi'.s 1734.90 1875.89 2011.44 2133.45 23C5.48 11877.89 23604.35 2fa?83.i: 

Process *>itn F«t! Celts 730.04 781.38 834.76 39CB4 939.0s 4941.20 10651.41 11763.Tt 

tttt't.rt elect- irlty 0.00 O.CO O.uO 0.00 J.CC O.OC 0.00 O.OC 

Fot) Sn-.^i 1924.Hi 19*7.22 1174.43 1257.6! 1346.49 6~36.48 14952.94 14517.J5 

««:ti:-s! 9 t f 144.40 235.06 I*-!.61 291.C9 3C6.33 1643.48 3769.01 10331.42 

•i;r;::iti;- 33«.:-8 733.73 743.12 743.12 743.12 0.00 0.00 0.80 

l(.ttr»;t CCC O.OC 0.00 COO 0.00 0.00 0.00 O.OC 

•rttti :<.:Mt 246.0? 54.40 131.93 218.41 289.73 3093.00 9183.93 4183.92 

Ta.fi payablt 

Statt 14.77 3.26 9.12 13.10 17.33 305.56 551.04 371.16 

Ftatral 196.41 23.52 45.70 94.44 123.28 2202.21 3971.13 2474.7* 

Tat Crrfiti 373.00 

Itt Earslaj* Ufttr tail 124.91 27.32 77.13 110.86 147.07 2585.21 4441.74 3139.98 

kU StaractaMsa 334.36 783.75 743.12 748.12 748.12 0.00 0.00 0.00 

•flic* toa-. »a;M*t 0.00 0.00 0.00 0.90 0.00 0.00 0.00 8.00 

5t<u't Equity Itt I 270.3!) 

fet Cat*. Flow I '445.311 

439.29 811.37 125.25 858.99 893.19 2583.21 4441.74 3139.98 

-27 -
P.37 

EXECUTIVE SUMMARY 

Prepared For 

EXHIBIT 3 LIGGETT 8* MYERS 

NEW 90,OOO PPH CCAL PIRED SYSTEM WITH WET SCRUBBER 

09-01-1986 

Fuel Savings Net Cash Flow 

Year <*) (*) 

1 1,024,863 607,491 

2 1,097,219 750,752 

3 1, 174,692 763, 174 

4 1,257,615 794,362 

5 1,346,402 827,666 

Paybac k of Initia l I r vestment : 4. 3 Year s 

AUfr -tax Recovc--/ of 

Toti". Investment: 4.3 Years 

R^t.v'.-. on Investment: 17 % 

Not P'»jeit Value 

(discounte d a t 10.0%) : $1,520,20 1 

Tota l Capita l Cost : «3, 550,00 0 

by 

ESI INC. OF TENNESSEE 

811C Livingsto n Cour t 

Marietta , Georgi a 3006 7 

(404 ) 427-620 0 

-28 -
P.38 

ECONOMIC ANALYSIS 

EXHIBIT 3 LIGGETT k MYERS 

NEW 90,000 F=H COAL FIRED SYSTEM WITH WET SCKUfaBtR 

This ar*l>sis is for a coal system that is to replace an oil system. 

Ci l Coal 

L bs Steam per Hou." 33360 33360 

Ir.cre-se 1.0% for 30 yrs 1.0% fo.* 30 yrs 

the.-; C.0 % for 0 yrs. 0.0 % for O yrs 

Ar.r.ual Operatin g Hour s £<00 8400 

Ir.-rrease C.0% for 0 yrs 0.0% for 0 yrs 

tr*n O.G% -for 0 >rs O.O'J, -tor 0 ,r* 

Average Vt i 1 i :»•. lor, 100% 100% 

Teller CH;:i*r,c> C0.C% 30.OV. 

*?TllD/'..b rteair. 1002 1002 

OiI Nc.(2,4,£) 6 12500 8TUs/ib 

Price/gal *0.750O *52.0C Price/ton 

0 f < M C c -. t s 

Sl.vctr ical *0 «77300 

Me.ir. ter-ance *"-> «6300 0 

Opei ators *0 *17dS00 

C ^ K* Inflation r«t«? 6.0% 

Iii'sllition period 14 months 

ruc-1 Inflation rate 

iu'ing installation 0.0% 0.0% 

tl tn 6.C% for 5 yrs 6.0% for £ yrs 

ind 0.0% for 25 yrs O.O".; for 2S yrs 

Tc.leral tax rate: 4o.C% State tax rate". 6.0% 

Pcde'al tax credit: 10.0% State ti., credit: 0.0% 

Dsp:*ec i at i cn period*. tZ yrs 

Depreciation T>et'-.cd: ACRS 5-year 

Lr^r p^ri-d' O ; .- s 

Lean ir-'.i-rts*. :ate: 0 % 

rr-.lt,' 1-trrest rate: 12 X 

Fr.uity capital: « 3550000 

Capital cost: * 3550000 

Cptratirg life: 30 yrs 

Discount rate: 10 % 

Flectrical potter rate: • 0 /kwr. 

Turbine Mater rate: 30 lb stir./kwh 

Electricity price inflation rate 0.0% for 0 yrs 

then 0.0% for 0 yrs 

-29-
P.39 

EXHIBIT 3 LIS8ETT I ITEIS 

HcV 90,0-30 FPH COAi FIREI STSILH VITM NET KtUIJO 

Ei'tuttC First Tta- Csiinp'.ior. i CaiU 

•.Mia* Oil Cstfbtp'.ior.: I.339.E7C ja! 

tl K.73W pt' j*i : 81,734,902.80 

>"i»: FJI I C:r.t-jip'.iai.: lastuair.) 13) \ t»t:jj froa caal) 

14,239 Xt'% it «2.0C ptr toa: 87:0,035.34 

Ccit :f :-o;Ui«:.lil 7a»:: 40.00 

•730,039.36 

CASH FLOW MULT3IS 

Ccipariaor. or Alttrt.iliv* Fae'.i (taoasanii of 4:'.iar») 

Ytaxi 

lestallatiM 1 2 3 4 5 e-10 11-20 2i-.i 

Pr:j»ct C:»t < 3350.00: 

Ira-. Fr::tt<i O.CO 

lest. ?tri;l ;•*. I COO! 

Sas cr Til Tcj'.i 1714.?C 137:.80 2011.44 2113.43 2305.48 11877.89 25404.35 232*3.13 

Prep:?;* S;ilti f.i\ frsti 733.04 781.53 836.76 3*3.84 939.03 4941.20 10631.41 H7o5.7S 

5*>va'»! r!»:'-::l'.y S.JO O.CO 0.00 O.OC 0.00 0.00 0.00 COO 

F:t! S.vitji 

Miitiona! "i H 

ItprK-itJon 

I*t»r*=' 

Prtti ' ',t.Ztmt 

Tai?t pa/at:* 

Statf 

r

tl>rtl 

Tax Credits 

II*'. Carairp tilttr 

Hi Jtp'tclilica 

8*4a:t lea* Pa;ii»t 

Ste-i:*. !qo'.*7 let 1 

Itt Cask FlM ( 

353.00 

tail 

254.98) 

3431 .08) 

1024.84 

sie.ee 

333.88 

coo 

200.19 

12.01 

84.54 

101.42 

SOS.8! 

0.00 

:o97.:i 

337.53 

741.93 

COv 

17.34 

1.C4 

7.50 

•.to 

741.95 

0.00 

1174.68 

3Se.2J 

703.22 

0.00 

108.23 

4.50 

44.31 

34.95 

708.22 

O.M 

1237.61 

379.70 

7-.-8.22 

0.00 

149.49 

10.13 

72.38 

•4.14 

708.22 

1.00 

1344.43 

402.48 

706.22 

0.00 

235.70 

14.14 

101.92 

119.44 

708.22 

0.00 

4934.48 

2404.93 

0.00 

0.00 

4331.75 

271.91 

1939.53 

2300.32 

1.00 

0.80 

14952.94 

7323.21 

0.00 

0.00 

7427.73 

445.46 

3211.75 

3770.32 

0.00 

0.00 

14317.33 

13474.30 

0.00 

0.00 

3C40.84 

182.43 

1314.64 

1343.53 

0.00 

0.00 

407.49 750.75 743.17 794.34 127.87 2300.32 3770.32 1543.53 

-30 -
P.40 

EXHCoTiVE. SUJ'iMAFVr 

~-r epa r c-J Fur 

L: : -ii: : T 4 Ar-!rr*:cAN FRUCTOSE 

N^'W i5::/.o : cr-_ TIRE D SYSTEM WITHOUT SCRUBBER 

09-01-1936 

Tu*'. c.».ir>.gs Net Cash Flow 

rev; {$.' (*) 

1 3,OC?,8S? 1,7 73,724 

2 3.190.4G3 2,032,803 

3 3, 3'-1,911 J, Orb, 716 

4 3,t>b-J,£.:o 2,190,935 

5 :,7r9,9i= 2,290,911 

Pi/jis:: ; c-f I .-t i I i a 1 Ir.vEstatut : 2. 5 Years 

f.f.t- 1 -'. u... i\?ccv?f y CT 

Total I:-. vestment: 2. 5 Year s 

r

.-=.'\-.--:-Ti ci . Ir. N/astr/.snt: 3 8 % 

Ms*. r*r ?i*r. t Valu e 

(c:3:3j:i'.« d a t 10.0%) : *ll,851,27 i 

Tnttl Capital Coat: *5,350,000 

by 

ESI INC. OF TENNESSEE 

SllC Livingston Court 

Mi.- ietla, Georgia 30067 

(4C4) 427-6200 

-31-
P.41 

ECONOMIC ANALYSIS 

EXHIBIT 4 AMERICAN FRUCTOSE 

NEW 150,000 COAL FIRED SYSTEM W1THGUT SCRUEBEK 

Tris analysis is for a coal system that is to replace an oil system. 

Oil Coal 

Lbs Steam pe>- Hour 

I n r r -? a s -

the n 

Vu.Ur l Operatin g Hcu* . 

Increas e 

the n 

Averag e L't i 1 i r at : or. 

Bo'. le r Efficienc y 

?

TU«s."..b ^tearr. 

Oi T Mo. (2,4,6) 

Prize/ga1 

O t- M Costs 

El metrical 

Mai r.tet.anc e 

Ope- ate- s 

1 IcOOO 

0.0* for 0 >)*« 

0.0% for 0 yr* 

0 

0 

6 

. 0% 

. c% 

. ot. 

16 

G40C 

fc- 0 •/.-

fo:- O yr 

1 cor. 

3 0. C-% 

1004 

6 

*0.6500 

*0 

so 

*o 

months 

s 

s 

115000 

0.0% for 0 yrs 

C.0% for O yrs 

3400 

0.0% for 0 yrs 

0.0& for 0 /rs 

100% 

83.0% 

1004 

12500 BTJs/lb 

*48.00 Hrice/ton 

*75600 

*79500 

SIOOOOO 

O tx M Inflation r*te 

Installation pe led 

Fuel I:-.*! at ion rate 

iuriog irstallation 0.0% 0.0% 

then 6.0% for 5 yrs 6.0% for 5 yrs 

end 0.0% for 25 yrs 0.0% for 25 yrs 

Federal tax rate: 46.0% 

Federal tax credit: 2C.C% 

State ta.-. rate: 

State tax credit: 

6.0% 

0.0% 

Depreciattcr period: Z /re 

Depreciation met'-rid: ACRS 5-year 

Loar. tmtr: i-?.'. 0 yrs 

l.r.r\r. ir.tr,re><it rate: 0 % 

Faulty 

Equity 

errst rate*. IC *X 

cap i tal : 0000 

Capital cost: * 5350000 

Ope ratify life-: 30 yrs 

Discount *»».*: 10 % 

FTlectr i.-ctl power rate: • 0 /kwh 

Turbine water rate: 30 lb stm/kwh 

Electricity price inflation rate 

then 

0.0% for O yrs 

0.0% for O yrs 

-32-
P.42 

IXMI1T 4 MllICAJi FRUCTOSE 

%l. ISO.OvO C3AL FIREI STSTEH «H4XT URUIZO 

Ettiiitttf >ira*. Ttar Co«tui;tlon t Coiti 

luti ) Oi! Conutpttsa: i,0Ei,2*3 3«i 

«• «C.i:X pi- ja!1. »3,:53,430.K 

A'-ual Fitl C?r.*iBp',ic--. :muiit>9 1*0 \ II-J ; lroo> coal) 

iS,74f ta - i'. »-'{.:: ;•: tea: tl,243,WO.82 

CoO. :f •»»;>'.,wital F«i : *0.00 

•2,243,540.32 

Zr.iH RCW hNALYSIS 

Coaparitor. cf Alttr-.a'.ivt Full* (Itoutanis of iollartl 

Tiara 

'..i.n.ii. , i-IO 11-20 21-30 

Preje:*. Csst ( S350.C-3: 

..it °ro:ttl» CCO 

last. ?tM:« !•'•• ( :.-:•:» 

U. ar C:l tis'.i 

Frap;jtd S.-stta Fwl Joiti 

?#».»at«i tW:'.ricity 

5253.43 53i3.64 5702.75 6236.52 6432.33 33.eI.o7 66323.34 46323.3'-

•243.54 237-. IS 2S2CM 2672.05 2232.42 Hlal.0 * i»3:4.19 22324.I? 

0.3; CCO 3.30 ;. A COO O.OC 0.00 O.CC 

Fjt: .-ivir.31 

-*:'..\:.:'*: : 

latita t 

::•:•/.£» 31?C.iJ 3381.91 3584.83 3759.52 18995.So 37999.16 37-95.16 

2SM0 270.41 2S£.£3 3C3.83 322.06 1924.40 4021.38 10763.74 

762.38 !!ie.!3 1067.32 1067.32 1067.32 O.CO 0.00 0.00 

COO O.-JO 0.00 COO COO COC 0.00 O.OC 

•rf.i:- '.Kit 

Ta-K ?•/**'* 

S'.itt 

Fi8i:»l 

Tax Credits 33I.00 

1592.41 lcOi.93 2027.9s 2213.i 2410.53 17075.18 31*77.57 27215.42 

:\f.'m- 133.1? 121.63 132.cZ 144.63 1024.51 1918.63 1432.93 

SJ1.32 779.15 376.39 957.19 1042.31 7383.31 1*427.10 11767.95 

*4tt Eini-o* ii-ttr tai' 1C11.3S 914.66 1029.39 1123.44 1223.39 8447.34 14231.82 13814.33 

Mt mt;-tz:..V.m~ 762.33 1118.15 1067.32 1047.32 1047.32 0.00 0.00 O.OC 

U.nzt I w taywX O.OC 0.00 COi O.OC 0.00 0.00 0.00 0.00 

UfmZ. tj.\\j 1st I 367.23) 

Stt Cat> He I 3132.73) 

1773.72 2032.81 2094.72 2190.99 2250.91 8447.34 14231.82 13814.33 

-33 -
- ' 4 

EXECUTIVE SUMMARY 

Pr epar ed For 

EX:-!:B:T Z AMIFICAN FRUCTCSE 

NEW 150,000 C3AL FIRED SYSTEM WITH DRY SCRUS5ER 

C?-01-19S£ 

".ic! crvi.igs Net Cash Flew 

'. 3,009,829 1,740,630 

2 3, .' ?C, ^23 2,034,£23 

3 7,311,911 2,084,743 

4 3,590,626 2,170,633 

*5 3,7r9,91£ 2,261,675 

Pf.;ba:i. C T tr.itial Investment: 3.1 Years 

A F *.«•' - t i">:: Recover> OT 

Total I r.-. estxent: 3.1 Years 

F.otur n cr Z r. ves tir.*?rit : 29 % 

Net P»ei«-rit Value 

Cdit-oui.ted at 10.0%).' Sb,963, 140 

Total Capital Cost: *6,650,000 

by 

ESI IMC. OF TENNESSEE 

81 IC Livingston Court 

Marietta, Georg:*. 3O067 

(404) 427-6200 

-34-

P.43 

/ 

./ 
P.44 

ECONOMIC ANALYSI S 

EXHIBI T 5 AMERICAN FRUCTOSE 

MEW 150 , OTC COAL FIF.ED SYSTEM WI'»H DRY SCRUBBER 

T M c ari)l>f.l a I s foi- 4 coa l wy&tein tha t i s t o replac e a n oi l system , 

O i l Coa l 

l b s St**:.* pi.r Hou r 11500 0 1 1500 0 

I;v;-Das e 0.0 % fo r 0 yr s 0.07 . fo r O yr s 

the.'i 0.0 % fc r 0 >r s 0.0 % ior 0 yr s 

Annua l 0pe-*tt,i g Hou- i £40 0 S40 0 

Zr.cte-s.zc: 0 . OV. fc r 0 yr s 0.0 % fo r O yr s 

the . 0.0 % -for 0 yr s 0.O % fo r 0 >r » 

A.trsj e 'Jt i l :raticr . 100% 100 % 

Eoila ' Efficienc y 30 . Ct. b3.0 % 

J'UJ.'L^ - ?te*:r> 100 4 100 4 

C i - No.(2,4,6 : 6 1250 0 BlUs/l b 

Fr -re/ga l $0.650 0 «4d.O 0 Frict/to n 

0 fc M 1-~*_-

«"U: 4.r-:;8 l * 0 * 15450 0 

Maintenanc e * 0 *1165O 0 

Operator s SO *22700 0 

n tc r: I . f ictio- i ral e c.0 % 

Irsta l 1 a t i or. perio d 1 6 mcr.ti. s 

F.i.:-1 '. .-. f 1 a t i r. r. r s, t «e 

^u-i-. g it tta l la t :cr. 0.0 % 0.0 % 

tr;er. 6.0 % fc r 5 y r a 6.0 % fo r 5 yr s 

anC 0.0 % fo r 2 5 yr s 0.0 % fo r 2 5 yr s 

Fsic-a l ta x rate : 46.0 % Stat e ta x rate : 6.0 % 

Fc??-a l ta x credit : 10.0 % Stat e ta x credit : 0.0 % 

Depreciatio n period : 5 yr s 

T3»r.r t r j a t i cn xetl-od : ACR3 5-yea r 

L c --. r. p e r i c i '. 0 y r s 

'..can i-teres t rate : 0 % 

Equit y 1-. ter»s t rate : 1 0 % 

•Equit y capital : * 6650O0 O 

Capita l cost : * 665COOO 

Op yr a t ir g life* . 3 0 yr s 

Discoun t rrt» : 1 0 % 

Electrica l ptz-mtr rate : « 0 /kw h 

Turbin e wate r rate : 3 0 l b stm/kvi h 

Electricit y pric e inflatio n rat e 0.0 % fo r 0 yr s 

the n 0.0 % fo r O yr s 

-35 -
P.45 

'i *• 

t 

a, 

l 

' 4 

E'(!«i*.*4

 r irt t Tftr CoAiuastioa 

Actual Oil Cmuiptloa 

•t 

1 dil l 

•0.6300 

•.052, 

AiMal Fttl Coasiipti;:.'. .an^siaj ; 

« » * 

Ccsp 

I-.ta'.la'.iif. 

P-:jt:t C:st ( fSSCOOi 

i:i:.

 0 -;:M4 I COO 

!r.»*. tttizi Itt . ' 0.031 

Sas ar 0:'. Cos's 

P*:;:t?< Sritti

 c.t\ Ccst; 

Ct*r*i*.?* ?lsctTi*:l v 

Fstl *t-.i« i 

A4(?i*.:3-il Si r 

lt;r;;!ati: ' 

U'.i-ait 

Prtti* !*tct» 

T i m ja.-ai't 

S'.itt 

Ftft'tl 

Tat CrH't i 44!.OC 

•to*.

 r ani:j i fa-'tir tu ' 

Mi 3t;rtcia*.i3r 

Hi:: ! lar. F«,i*rt 

eti-:ct E^it ; Ir.t ! 454.48: 

fat tat* Fl a t £441.48! 

.m , . » 

'J »il . • -

- t • 

» • >• -r r 

irisoa at 

1 

a.-*'. I' 

22*7.34 

COO 

30:9.59 

5CC.0-3 

?-i:.o3 

COO 

1362.2i 

93.74 

4*,!.S2 

793.01 

94:.«: 

COC 

1740.43 

I - — <. 

•..:-\.a\ F 

20v aai 

3-3 ". *.».»/ 

*.- '.it: 

mt'.: 

IEV 1SO.0C4:,:;;,<:c:i 

froi coail 

•2,243,543.S2 

•0.00 

12,243,343.82 

CASH FLCW AhALY'IS 

Alltrsatift FjtiS 

2 

3568.64 

2373.IJ 

0.00 

3190."3 

531.OS 

1389.35 

0.00 

1270.63 

76.24 

349.42 

£44.97 

i:e9.ss 

0.33 

2914.12 

(tkojiast'i at 

Yuri 

3 

3902.75 

2I23.84 

COO 

32el.rl 

iii.63 

1326.67 

3.8-3 

1491.44 

*T.6J 

14S.:6 

rss.o* 

1324.67 

0.00 

2084.74 

36-

4 

5256.92 

2672.05 

0.00 

3354.53 

393.51 

1326.67 

O.OC 

1442.64 

?9.:b 

"15.93 

643.9a 

1326.47 

COO 

2170.43 

EXMllli 3 AMIIIIM * itMmal 

> 3341 rlki l 6ua « 1 

iolian) 

3 

4632.33 

2312.42 

O.irj 

3799.92 

431.24 

1326.47 

0.00 

1842.00 

110.32 

796.48 

935.00 

1324.47 

8.0C 

2261.41 

4-10 

33141.47 

14162.C9 

0.00 

18999.58 

3771.85 

0.00 

0.00 

15227.73 

913.44 

4584.47 

7729.59 

0.00 

0.00 

7729.3? 

.,h Ui aLt 

11-20 

46323.34 

28324.19 

COO 

37999.16 

11832.40 

0.00 

0.00 

24194.74 

1571.81 

11327.48 

13297.46 

0.00 

0.80 

13297.48 

•USaEfl 

21-30 

66323.34 

2Ki24.1» 

0.00 

37999.16 

21136.30 

0.00 

8.00 

14842.86 

1011.77 

7291.34 

8359.3? 

0.00 

0.00 

8S59.S? 
P.46 

* » 

EXECUTIV E SU'-tHAfcY 

Prepare d Fo r 

r£:c*-::BiT 6 AMERICA N FRUCTOS E 

NEW 150,^00 FPH CIAL FIRED SYSTEM WITH WET 6CRUBBER 

09-Ci-l?3e 

Fuel '"a\/ir:gs '..*. Cash Flow 

•t=!-r i.f, <*) 

1 3,0C?,3S9 1,519,156 

2 3,190,-83 1,790,644 

T 3,731,911 1,329,495 

4 3,5EC4,£26 1,902,014 

Z 3,7*9,916 l,978,e85 

Pa>b«cU of Initial Investment: 3.w Years 

AfU.-tax Recovery ot 

Total In.estme.-it: 3.3 Years 

Retv.r r. cn Investn:e:. t: 26 % 

Net Present Value 

<discounted at 10.0%J: »5,840,993 

Tctal Capital Cost: $6,320,000 

by 

ESI IMC. OF TENNESSEE 

eiiC Livingston Court 

Marietta, Georgia 30067 

<404) 427-6200 

-37-
/ '• * » 

ECONOMIC ANALYSIS 

EXHIBIT 6 AMEF.ICAW FfxUCTOSE 

NEW 150,OCO rFH CLAL FIRED SYSTEM WITH WET SCRUBBER 

P.47 

'I- is € r: l >«. i • ''_> fcr a oa i system that is to replace an oil system. 

Oil Coal 

mmtz. Steam per Hour 

I r.cr ease 

then 

115000 

0.0% for O yrs 

0.0% for 0 yir* 

115000 

v.0% for 0 yrs 

j. 0".i fo: 0 yrs 

Annual Operating Hou. 

Ir..: r ease 

t> a\. 

0400 

0.C7. tor 0 yr< 

0. 07. ?JI 0 yr) 

6400 

0.0% for 0 yrs 

0.0% for O yrs 

"..erag e L't i 3 i sa t i or 

rsile - E'ficier.c / 

?"'Jr./Lb 5tta-,i 

100% 

SO. 0% 

•004 

100% 

83.0% 

1004 

Oil Mo.(2,4,6) 

Price/gal 

C L M Costs 

Electrical 

Mai r.tenance 

0\z e-at ors 

49.0.6500 

* 0 

* 0 

SO 

1250 0 BfUs/l b 

S48.0 0 Fries/tor . 

4*151500 

S10860 0 

S63O6O0 

C . ml /• 

16 Months 

C t K Ir.f 1 At ion -at s 

Irsta l U t i c perio d 

F..rrl ir.f I a t ion rat e 

du-i-vg installation 0.0% 

then 6.0% for 5 yrs 

and 0.0% tor 25 /vs 

0.0% 

6.0% for 5 yr! 

0.0% for 25 yri 

Federal tax rate 

F?d?ral tax cred 

46.0% State tax rate*. 6.0% 

t: 10.0% State tax credit: O.0% 

rept eciat ion period: 5 yri 

Deprec i at i on .v.ethod : ACRS 5-

Lc=v:i p*~icd: /' 

Lc&r. .er est "ate: 0 % 

Equity interest rate: 10 % 

Equity capital: • 6320000 

Capital cost: * 6320000 

Operating life: 30 yrs 

Discount *ate: 10 % 

Electrical power rate: % 0 /kwh 

Turbine water rate: 30 lb stm.'kwh 

Electricity price inflation rate 

then 

0.0% for O yrs 

0.0% for 0 yrs 

-38-
fe. \ 

. , EXHIBIT 4 AflEIItAN FIUCTOSE 

\ •/ . » » NCI. 150,000 PPH COAL flK I aTSIEJI VlTH KT SCIUIIEJ 

Ettiai'.ti First Tiar Contuftatleri I Caita 

Aitm) Oil CaiiaiMi": B,0S2,200 sal 

al tO.£300 err jal: 43,253,4:0.00 

A-.ni.al fatl Car.tii;'.>o-: lanaiiaj 103 5 titrjjr froa coal) 

46,740 tcu at tif.00 par toa: •2l242,34Ca2 

Cut mi Su^>u-ntal Fatl: SCOO 

•2,243,343.52 

CASH FIOV r\Wtlv.Zl. 

C:i;i-ii:? :< Altt.-ratUt F.tls (tkouiasia af t:liar»> 

. 'Mta 

Pr:jt:t Cut ! 

'.cr. P.- ;:»#<» 

'.Mt. Ptfli j If.*. • 

Sat at Ci! Cos'.! 

Prapc*ti Systta Fn! 

6*it*at?4 «lt:iri:it7 

Fit! Saviojs 

Aiditicra' CI R 

Stprtc:atlas 

lattriit 

.laticr. 

6320.001 

0.00 

0.001 

IcVs 

Ttarj 

4 5 4-10 11-20 21-30 

3253.43 5113.64 5702.75 6236.92 6432.33 33141.47 44323.34 46323.34 

22'3.S4 237S.I5 2320.84 2472.09 2832.42 14162.09 2S324.19 283/4.19 

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 

3009.39 3190.48 3361.91 3384.83 3799.92 18999.58 37999.14 37999.14 

890.70 944.14 1000.79 1040.64 1124.49 4719.18 21024.79 37452.20 

900.40 I320.es 1260.64 1260.84 1260.S4 0.00 0.00 0.00 

0.03 O.OC 0.00 0.00 0.00 0.00 0.00 8.00 

Pritax !atn« 1218.59 925.46 1120.28 1243.13 1414.39 12280.40 14974.37 344.94 

Tarn payafclt 

Sr.it t 73.12 55.53 67.22 75.79 84.82 734.82 1018.46 20.82 

tcatrtl 326.92 400.17 434.41 S4s.i9 411.47 5310.05 7339.72 150.02 

Ta» Orrtits 432.00 

•ft Ear i i 19a laf.f tail 618.Sc 449.76 S4E.6S 441.17 718.04 4233.53 8414.19 174.12 

ttit Stprttla'.ia- 900.43 1320.18 1240.64 1260.84 1240.84 8.00 0.00 O.K 

UiizK l:a-. Pay-t.t 8.03 0.03 0.00 0.00 8.00 0.80 0.00 8.00 

D»*-.:t Evil; lot ( 413.83) 

Utt Cai* F!o« t 4121.831 

1319.16 1790.44 1829.49 1902.81 1978.88 4233.53 1414.19 174.12 

-39-