i

Air Pollution Control

40 CFR 52.21(i)

Prevention of Significant Deterioration Permit to Construct

Final Statement of Basis

for Permit No. PSD-OU-0002-04.00

August 30, 2007

Deseret Power Electric Cooperative

Bonanza Power Plant, Waste Coal Fired Unit

Uintah & Ouray Reservation

Uintah County, Utah

In accordance with requirements at 40 CFR 124.7, the Region 8 office of the U.S.

Environmental Protection Agency (EPA) has prepared this Statement of Basis describing the

issuance of a Prevention of Significant Deterioration (PSD) permit to Deseret Power Electric

Cooperative. This Statement of Basis discusses the background and analysis for the PSD permit

for construction of a new Waste Coal Fired Unit (WCFU) at Deseret Power’s Bonanza power

plant, and presents information that is germane to this permit action.
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Table of Contents

I. Introduction.................................................................................... 1

II. Authority....................................................................................... 3

III. Public Notice, Comment, Hearings and Appeals......................................... 4

IV. Project Description ........................................................................... 6

A. Location............................................................................... 6

B. Existing Facility and PSD Permitting History................................... 6

C. Company Contacts .................................................................. 7

D. Process Description................................................................. 7

E. Waste Coal Characteristics ........................................................ 9

F. Waste Coal Versus Run-of-Mine or Washed Coal as Potential Fuel......... 9

G. Coal, Limestone and Ash Handling .............................................. 11

1. Coal .......................................................................... 11

2. Limestone ................................................................... 11

3. Ash ........................................................................... 12

H. Proposed Emission Control Techniques .......................................... 12

1. CFB boiler .................................................................. 12

2. Emergency generator ....................................................... 12

3. Coal, limestone and ash handling......................................... 12

4. Particulate emissions from cooling tower............................... 13

I. Potential to Emit..................................................................... 14

1. Controlled (with BACT applied) ......................................... 14

2. Uncontrolled ................................................................ 15

J. Proposed Emission Monitoring Techniques ..................................... 16

1. CFB boiler .................................................................. 16

2. Emergency generator ...................................................... 16

3. Materials hndling system baghouses..................................... 16

4. Non-point source (i.e., fugitive ) PM/PM10 emissions................. 17

V. Description of this Permitting Action ...................................................... 18

A. Purpose................................................................................ 18

B. PSD Applicability.................................................................... 18

C. Application Submittals and Addendums.......................................... 18

VI. Best Available Control Technology Analysis ............................................ 22

A. Approach Used in BACT Analysis................................................ 22

B. PSD BACT Emission Limits Apply at All Times............................... 23

C. Pollutants Subject to BACT for this Project..................................... 24
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D. Alternative Coal (Clean Fuels) for BACT....................................... 25

1. Alternative coal from Deserado mine.................................... 25

2. Alternative coal from other mines........................................ 29

3. Proposed fuel restrictions at CFB boiler................................. 34

a. Fuel during startup................................................. 34

b. Fuel during emergencies when waste coal is not available... 34

c. Fuel other than during startup or emergencies................. 34

E. Supercritical Boiler Technology for BACT...................................... 39

F. IGCC not Within Scope of BACT Analysis for this Project.................. 41

G. BACT for NOx Emissions from CFB Boiler.................................... 42

1. Step 1: Identify Potential Control Technologies........................ 42

2. Step 2: Eliminate Technically Infeasible Options..................... 47

a. Selective Catalytic Reduction.................................... 47

b. Selective Non-Catalytic Reduction.............................. 48

c. Non-Thermal Plasma Reactor.................................... 48

d. Carbon Injection in Combustion Chamber..................... 48

3. Step 3: Rank Remaining Control Technologies

by Control Effectiveness................................................... 48

4. Step 4: Evaluate Economic, Environmental and Energy Impacts... 49

a. Selective Catalytic Reduction.................................... 49

b. Selective Non-Catalytic Reduction.............................. 51

5. Step 5 - Proposed NOx BACT for CFB Boiler.......................... 51

6. Comparison to applicable NSPS emission standard.................... 58

7. Proposed compliance monitoring approach............................. 59

H. BACT for PM/PM10 Filterable Emissions from CFB Boiler................... 60

1. Step 1: Identify Potential Control Technologies........................ 60

2. Step 2: Eliminate Technically Infeasible Options...................... 60

a. Fabric Filtration.................................................... 60

b. Electrostatic Precipitation ........................................ 61

3. Step 3: Rank Remaining Control Technologies

by Control Effectiveness.......................................... 61

4. Step 4: Evaluate Economic, Environmental and Energy Impacts.... 62

5. Step 5: Proposed PM/PM10 Filterable BACT for CFB Boiler ....... 62

6. Comparison to applicable NSPS emission standard.................... 66

7. Proposed compliance monitoring approach............................. 66
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I. BACT for PM/PM10 Condensible Emissions from CFB Boiler.............. 69

1. Step 1: Identify Potential Control Technologies........................ 69

2. Step 2: Eliminate Technically Infeasible Options...................... 69

a. Alkali (limestone) injection + fabric filter baghouse.......... 70

b. Dry SO2 scrubbing + fabric filter baghouse..................... 70

c. Alkali injection + dry SO2 scrubbing + fabric filter

baghouse............................................................. 70

d. Alkali injection + wet SO2 scrubbing + fabric filter

baghouse............................................................ 70

e. Addition of wet electrostatic precipitation

to option c above ................................................... 71

3. Step 3: Rank Remaining Control Technologies

by Control Effectiveness.......................................... 72

4. Step 4: Evaluate Economic, Environmental and Energy Impacts..... 72

5. Step 5: Proposed PM/PM10 Condensible BACT for CFB Boiler .... 74

6. Comparison to applicable NSPS emission standard.................... 84

7. Proposed compliance monitoring approach............................. 84

J. BACT for CO Emissions from CFB Boiler ...................................... 85

1. Step 1: Identify Potential Control Technologies........................ 85

2. Step 2: Eliminate Technically Infeasible Options...................... 85

a. Catalytic Oxidation................................................. 85

b. Combustion Controls............................................... 86

3. Step 3: Rank Remaining Control Technologies

by Control Effectiveness.......................................... 86

4. Step 4: Evaluate Economic, Environmental and Energy Impacts.... 86

5. Step 5: Proposed CO BACT for CFB Boiler ........................... 86

6. Comparison to applicable NSPS emission standard.................... 89

7. Proposed compliance monitoring approach............................. 89

K. BACT for SO2 Emissions from CFB Boiler ..................................... 91

1. Step 1: Identify Potential Control Technologies........................ 91

2. Step 2: Eliminate Technically Infeasible Options...................... 91

a. Limestone Injection................................................ 91

b. Dry Scrubbing....................................................... 92

(i) Spray dry absorber......................................... 92

(ii) Circulating dry scrubber.................................. 92

(iii) Hydrated ash reinjection.................................. 93

(iv) Dry sorbent injection...................................... 93

c. Wet Scrubbing...................................................... 93

3. Step 3: Rank Remaining Control Technologies

by Control Effectiveness.......................................... 94

4. Step 4: Evaluate Economic, Environmental and Energy Impacts.... 94
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5. Step 5: Proposed SO2 BACT for CFB Boiler........................... 96

6. Comparison to applicable NSPS emission standard.................... 107

7. Proposed compliance monitoring approach............................. 108

L. BACT for Sulfuric Acid (H2SO4) Emissions from CFB Boiler................. 109

1. Step 1: Identify Potential Control Technologies........................ 109

2. Step 2: Eliminate Technically Infeasible Options...................... 109

3. Step 3: Rank Remaining Control Technologies

by Control Effectiveness.......................................... 109

4. Step 4: Evaluate Economic, Environmental and Energy Impacts.... 110

5. Step 5: Proposed H2SO4 BACT for CFB Boiler........................ 110

6. Comparison to applicable NSPS emission standard................... 114

7. Proposed compliance monitoring approach............................. 114

M. BACT for NOx Emissions from Emergency Generator......................... 116

1. Step 1: Identify Potential Control Technologies ....................... 116

2. Step 2: Eliminate Technically Infeasible Options...................... 116

a. Injection Timing Retardation...................................... 116

b. Lean Burn Combustion ............................................ 117

c. Catalytic Oxidation................................................. 117

3. Step 3: Rank Remaining Control Technologies

by Control Effectiveness ......................................... 118

4. Step 4: Evaluate Economic, Environmental and Energy Impacts.... 118

5. Step 5: Proposed NOx BACT for Emergency Generator ............. 119

6. Proposed compliance monitoring approach............................. 119

N. BACT for PM/PM10 Emissions from Emergency Generator.................. 121

1. Step 1: Identify Potential Control Technologies........................ 121

2. Step 2: Eliminate Technically Infeasible Options ...................... 121

a. Positive Crankcase Ventilation ................................... 121

b. Add-on Controls .................................................... 121

c. Combustion of Clean (Low-Sulfur) Fuel)....................... 121

d. Good Combustion Practices ...................................... 122

3. Step 3: Rank Remaining Control Technologies

by Control Effectiveness.......................................... 122

4. Step 4: Evaluate Economic, Environmental and Energy Impacts.... 122

5. Step 5: Proposed PM/PM10 BACT for Emergency Generator........ 122

6. Proposed compliance monitoring approach............................. 123

O. BACT for CO Emissions from Emergency Generator .......................... 125

1. Step 1: Identify Potential Control Technologies........................ 125

2. Step 2: Eliminate Technically Infeasible Options....................... 125

a. Oxidation Catalyst.................................................. 125
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b. Good Combustion Practices ...................................... 125

3. Step 3: Rank Remaining Control Technologies

by Control Effectiveness.......................................... 125

4. Step 4: Evaluate Economic, Environmental and Energy Impacts.... 125

5. Step 5: Proposed CO BACT for Emergency Generator............... 125

6. Proposed compliance monitoring approach............................. 126

P. BACT for SO2 Emissions from Emergency Generator ......................... 128

1. Step 1: Identify Potential Control Technologies........................ 128

2. Step 2: Eliminate Technically Infeasible Options ...................... 128

3. Step 3: Rank Remaining Control Technologies

by Control Effectiveness.......................................... 128

4. Step 4: Evaluate Economic, Environmental and Energy Impacts.... 128

5. Step 5: Proposed SO2 BACT for Emergency Generator............... 128

6. Proposed compliance monitoring approach............................. 129

Q. BACT for PM/PM10 Point Source Emissions from Materials Handling ..... 130

1. Step 1: Identify Potential Control Technologies ....................... 130

a. Fabric filters......................................................... 130

(i) Baghouses .................................................. 130

(ii) Vent filters.................................................. 130

b. Cyclones............................................................. 130

c. Water sprays ........................................................ 130

2. Step 2: Eliminate Technically Infeasible Options....................... 130

3. Step 3: Rank Remaining Control Technologies

by Control Effectiveness.......................................... 130

4. Step 4: Evaluate Economic, Environmental and Energy Impacts.... 131

5. Step 5: Proposed BACT for PM/PM10 Point Source Emissions

from Materials Handling....................... ................... 131

6. Proposed compliance monitoring approach............................. 133

7. Comparison to applicable NSPS emission standard.................... 136

R. BACT for PM/PM10 Non-Point Source Emissions from Materials Hdlg..... 137

1. Step 1: Identify Potential Control Technologies........................ 137

2. Step 2: Eliminate Technically Infeasible Options...................... 137

3. Step 3: Rank Remaining Control Technologies

by Control Effectiveness .......................................... 137

4. Step 4: Evaluate Economic, Environmental and Energy Impacts.... 137

5. Step 5: Proposed BACT for PM/PM10 Non-Point Source

Emissions from Materials Handling ............................ 138

6. Proposed compliance monitoring approach............................. 138
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S. BACT for PM/PM10 Emissions from Cooling Tower ........................... 139

1. Step 1: Identify Potential Control Technologies........................ 139

2. Step 2: Eliminate Technically Infeasible Options...................... 139

3. Step 3: Rank Remaining Control Technologies

by Control Effectiveness.......................................... 139

4. Step 4: Evaluate Economic, Environmental and Energy Impacts.... 139

5. Step 5: Proposed PM/PM10 BACT for Cooling Tower................ 139

6. Proposed compliance monitoring approach............................. 141

VII. Applicability/Non-applicability of Other Federal Requirements....................... 142

A. New Source Performance Standards.............................................. 142

B. Acid Rain Program.................................................................. 145

1. Permitting.................................................................... 145

2. SO2 allowances.............................................................. 145

3. Continuous emission monitoring......................................... 145

4. NOx emission limits........................................................ 146

C. Operating Permits Program......................................................... 146

D. Case-Specific MACT Determination.............................................. 146

VIII. Air Quality Impact Analysis.................................................................. 148

A. Required analyses..................................................................... 148

B. Modeling methodology............................................................... 150

1. General........................................................................ 150

2. Near field modeling......................................................... 150

3. Full-impact modeling ....................................................... 150

4. Far-field analysis............................................................. 151

5. Visibility modeling.......................................................... 152

6. Deposition analysis.......................................................... 152

C. Modeling inputs and assumptions.................................................. 153

1. Description of models selected............................................ 153

a. Near field analysis.................................................. 153

b. Far field analysis.................................................... 153

c. Visibility analysis................................................... 154

2. Modeling domain and receptor locations ................................. 154

a. Near field analysis .................................................. 154

b. Far field analysis.................................................... 154
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3. Topography/terrain.......................................................... 155

4. Source inventory ............................................................ 155

5. Ambient background concentration....................................... 155

6. Meteorology.................................................................. 156

7. Emission rates................................................................ 156

8. Additional data inputs for far-field analysis ............................. 158

a. Precipitation data ................................................... 158

b. Land use data........................................................ 158

c. Ozone data........................................................... 159

D. Exemption from pre-construction ambient monitoring ......................... 160

E. Results and conclusions............................................................. 160

1. National Ambient Air Quality Standards analysis results............. 161

a. Near field analysis results ........................................ 161

b. Full impact analysis results ....................................... 162

2. PSD Class II increment consumption analysis results.................. 163

a. Near field analysis results ......................................... 163

b. Full impact analysis results ....................................... 163

3. PSD Class I increment consumption analysis results ................... 164

4. Visibility impact analysis results .......................................... 167

5. Deposition analysis results ................................................ 167

6. Lake chemistry analysis results............................................ 168

7. EPA adjustments to permit applicant’s analysis........................ 169

8. Post-construction ambient monitoring .................................. 170

9. Emission limits for modeling purposes ................................. 170

IX. Environmental Justice Assessment......................................................... 172
I. Introduction

Deseret Power Electric Cooperative (“Deseret Power”) has applied to the Region 8 office

of the U.S. Environmental Protection Agency (EPA) for a Federal Clean Air Act permit to

construct a waste-coal-fired electric utility generating unit at its existing Bonanza power plant,

near Bonanza, Utah. The request for a permit was made under regulations promulgated pursuant

to the Clean Air Act, titled “Prevention of Significant Deterioration” of air quality (PSD), in Title

40, section 52.21, of the Code of Federal Regulations (CFR).

The Bonanza plant is within the exterior boundaries of the Uintah and Ouray Indian

Reservation. Since there is no EPA-approved tribal permitting program on the Reservation under

the Clean Air Act, the Bonanza plant is under Federal permitting jurisdiction. The existing plant

is a major stationary source as defined in Federal PSD rules at 40 CFR 52.21. The new unit will

constitute a “major modification” to the existing plant, as defined in PSD rules. The specific

pollutants for which the modification will be major are listed in section V.B and again in section

VI.C of this Statement of Basis.

The proposed new Waste Coal Fired Unit (WCFU) will have a rated heat input capacity

not to exceed 1,445 million British thermal units per hour (MMBtu/hr) and a rated electrical

output capacity not to exceed 110 megawatts. The WCFU will consist of a single Circulating

Fluidized Bed (CFB) boiler and associated equipment. Proposed emission controls for the CFB

boiler, for satisfying PSD requirements for Best Available Control Technology (BACT), will

consist of:

 a fabric filter baghouse for control of filterable particulate matter (PM), including

particulate matter with an aerodynamic diameter smaller than 10 microns (PM10),

 limestone injection and a dry scrubber (spray dry absorber) for sulfur dioxide (SO2)

control and sulfuric acid (H2SO4) control,

 Selective Non-Catalyic Reduction (SNCR) for nitrogen oxides (NOx) control,

 a combustion control system for carbon monoxide (CO) control, and

 a combination of limestone injection, dry scrubber and fabric filter baghouse for control

of condensible PM.

The CFB boiler will be designed to be fired on waste coal obtained from Deseret’s

existing Deserado mine about 35 miles away. The waste coal is an unavoidable byproduct of the

coal washing process used to supply washed coal to the existing 500-megawatt Unit 1 at Bonanza

plant. If waste coal is not available due to emergencies, run-of-mine (ROM) coal or washed coal

from the mine will be utilized in the WCFU. Deseret Power has also requested operating

flexibility, in the EPA permit, to blend ROM coal with the waste coal, at up to a 50/50 ratio by
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weight, as needed at any time, such as in the event of operational difficulties arising from use of

waste coal as sole fuel, or in the event of unexpected difficulties in meeting BACT emission

limits.

The existing Bonanza Unit 1 was constructed under a Federal PSD permit issued in

February of 1981. The permit was updated and re-issued in February of 2001. The permit for

the new WCFU will be issued as a separate PSD permit.

A more detailed description of the waste coal fired project may be found in section IV

below. A description of emission control options considered and determination of emission

limits may be found in section VI. A description of the air quality impact analysis may be found

in section VIII.
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II. Authority

40 CFR 52.21, Prevention of Significant Deterioration (PSD): Requirements under

§52.21 to obtain a Federal PSD preconstruction permit apply to construction of new major

stationary sources (“major” as defined in §52.21), as well as to major modifications of existing

major stationary sources (Amajor modification@ as defined in §52.21). EPA is charged with

direct implementation of these provisions where there is no approved State or Tribal

implementation plan for implementation of the PSD regulations. Pursuant to section 301(d)(4)

of the Clean Air Act (42 U.S.C. § 7601(d)), EPA is authorized to implement the PSD regulations

at §52.21 in Indian country. The Bonanza power plant, where this proposed project will be

located, is 35 miles southeast of Vernal, Utah, near Bonanza, Utah in Uintah County, and within

the exterior boundaries of the Uintah and Ouray Indian Reservation. As stated in section I above,

the existing plant is a major stationary source and the proposed project will be a major

modification.

40 CFR 124, Procedures for Decision Making: Federal administrative permitting

standards at 40 CFR part 124, Procedures for Decision Making, provide requirements for several

environmental permit programs, including the PSD program. General administrative procedures

are codified in Part 124, including those that relate to the PSD program. Federal PSD permit

actions, such as issuing, modifying, reissuing, or terminating permits, are addressed in 40 CFR

124, Subpart A, General Program Requirements. Part 124 also includes requirements that

pertain to draft permits, Statement of Basis, Fact Sheets, public notices of permit actions, public

comment periods, handling of public comments and requests for public hearings, handling of

public hearings, and appeals of PSD permit decisions. Requirements in Part 124 that provide for

public review and involvement in this proposed action will be used by EPA in its decision

making.

In particular, the administrative requirements of 40 CFR § 124, Subpart C, Specific

Procedures Applicable to PSD Permits, will be followed. Specifically, whenever a major

source=s air emissions might affect a Class I area, 40 CFR § 124.42, Additional Procedures for

PSD Permits Affecting Class I Areas, states that the Regional Administrator must provide notice

of receipt of a permit application to the Federal Land Manager and the Federal official charged

with direct responsibility for management of lands within such area. A copy of the permit

application for this project was provided by the permit applicant directly to the National Park

Service and the U.S. Forest Service, at the same time the application was submitted to the EPA.

A copy of the permit application was also provided by the permit applicant to the Ute Indian

Tribe.
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III. Public Notice, Comment, Hearings and Appeals

Public notice for the draft PSD permit was published in late June, 2006, in the Salt Lake

Tribune (Salt Lake City, UT), the Vernal Express (Vernal, UT), the Uintah Basin Standard

(Roosevelt, UT), the Grand Junction Sentinel (Grand Junction, CO) and the Rio Blanco Herald

Times (Meeker/ Rangely, CO). The public comment period extended until July 29, 2006.

During the public comment period, States, Tribes, local governmental agencies, and the

public were given the opportunity to review a copy of the permit application, analysis, draft

permit prepared by EPA, draft Statement of Basis for the permit, and permit-related

correspondence. Copies of these documents were available for review at the US EPA Region 8,

Air and Radiation Program Office, in Denver, Colorado, as well as at Uintah County Clerk’s

Office in Vernal, Utah, as well as at the Ute Indian Tribe, Environmental Programs Office, in

Fort Duchesne, Utah. A copy of the draft permit and draft Statement of Basis was also available

during public comment period on EPA website at: http://www.epa.gov/region8/air, under the

heading “Topics of Interest.“

In accordance with 40 CFR 52.21(q), Public participation, any interested person was

afforded the opportunity to submit written comments on the draft permit during the public

comment period and to request a public hearing.

In accordance with 40 CFR 124.13, Obligation to raise issues and provide information

during the public comment period, anyone, including the permit applicant, who believes any

condition of the draft permit is inappropriate, or that EPA’s tentative decision to prepare a draft

permit for the WCFU is inappropriate, must raise all reasonable ascertainable issues and submit

all arguments supporting the commenter’s position, by the close of the public comment period.

Any supporting materials submitted must be included in full and may not be incorporated by

reference, unless the material has been already submitted as part of the administrative record in

the same proceeding or consists of state or federal statutes and regulations, EPA documents of

general applicability, or other generally available reference material. An extension of the 30-day

public comment period may be granted if the request for an extension adequately explains why

more time is needed to prepare comments.

During the public comment period, one comment letter and one comment e-mail were

received by EPA that expressed concerns with the draft permit and/or Statement of Basis. The

comment letter, received on July 28, 2006, was from a group of seven environmental

organizations: Western Resource Advocates, Environmental Defense, Utah Chapter of the Sierra

Club, Southern Utah Wilderness Alliance, Western Colorado Congress, Wasatch Clean Air

Coalition, and HEAL Utah. The comment e-mail, received on July 26, 2006, was from Kathy

Van Dame, representing the Wasatch Clean Air Coalition.

Comment letters supporting the proposed WCFU project were received from the mayors

of seven Utah municipalities: Salem City, Spanish Fork, Provo, Manti City, St. George, Nephi
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and Levan. Since these letters did not express any concerns with the draft PSD permit, EPA does

not consider a response necessary.

A copy of the final permit and final Statement of Basis are available on the abovementioned EPA website, as well as public comments received on the draft permit package,

EPA’s responses to public comments, and permit-related correspondence extending from the date

that the draft permit was issued until the date that the final permit was issued.

In accordance with 40 CFR 124.15, Issuance and Effective Date of Permit, the

permit shall become effective immediately upon issuance as a final permit, if no comments

request a change in the draft permit. If changes are requested, the permit shall become effective

thirty days after issuance of a final permit decision, unless review is requested on the permit

under §124.19 (permit appeals). Notice of the final permit decision shall be provided to the

permit applicant and to each person who submitted written comments or requested notice of the

final permit decision. Since commenters requested changes in the draft permit, the effective date

listed in the final permit is thirty days after permit issuance.

In accordance with 40 CFR 124.19, Appeal of RCRA, UIC, and PSD Permits, any person

who filed comments on the draft permit or participated in the public hearing may petition the

Environmental Appeals Board, within 30 days after the final permit decision, to review any

condition of the permit decision. Any person who failed to file comments or failed to participate

in the public hearing on the draft permit may petition for administrative review only to the extent

of changes from the draft to the final permit decision.

The permit and Statement of Basis represent an Agency action to issue a Federal PSD

permit to Deseret Power Electric Cooperative for the addition of the Waste Coal Fired Unit at

Bonanza Power Plant, under Title I, Part A, Air Quality Emission Limitations, and Part C,

Prevention of Significant Deterioration of Air Quality, of the Clean Air Act, as amended. For

completeness, this Statement of Basis should be read in conjunction with the PSD permit.

Any requirements established by this permit for the gathering and reporting of

information are not subject to review by the Office of Management and Budget (OMB) under the

Paperwork Reduction Act, because this permit is not an “information collection request” within

the meaning of 44 U.S.C. § 3502(4), 3502(11), 3507, 3512 and 3518. Furthermore, this permit

and any information-gathering and reporting requirements established by this permit are exempt

from OMB review under the Paperwork Reduction Act because it is directed to fewer than ten

persons, 44 U.S.C. § 3502(4) and 3502(11); 5 CFR § 1320.5(a).
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IV. Project Description

A. Location

The proposed WCFU will be located at the existing Bonanza Power Plant, approximately

35 miles southeast of Vernal, Utah, near Bonanza, Utah in Uintah County. This location is

within the exterior boundaries of the Uintah and Ouray Indian Reservation. The UTM

coordinates for the proposed CFB boiler stack are 646192 meters East and 4438740 meters

North. The latitude and longitude coordinates for the stack are 40

o

05’ 11” North and 109

o

16’

48” West. The proposed project will be located in an attainment area for all pollutants. The

closest non-attainment area, Utah County, which is located approximately 125 miles west of the

proposed facility, is in non-attainment for PM10.

The proposed WCFU will be located at an elevation of 5,030 feet above Mean Sea Level

(MSL). Elevated terrain surrounds the Bonanza plant. The closest elevated terrain, the East

Tavaputs Plateau, is located approximately 6 miles south of the plant. The East Tavaputs Plateau

is oriented in a southwest-northeast direction with elevations ranging from approximately 6,000

to 8,000 feet MSL. Another area of elevated terrain, located northeast of the plant, is Raven

Ridge. Raven Ridge, oriented southeast to northwest, has elevations ranging from 6,000 to 6,350

feet MSL. The Blue Mountain Plateau, located approximately 17 miles northeast of the plant,

has elevations ranging from 6,000 to 8,500 feet.

B. Existing Facility and PSD Permitting History

As stated earlier in this Statement of Basis, the existing Bonanza power plant is a major

stationary source, as defined in Federal PSD rules at 40 CFR 52.21. The existing plant consists

of a single electric utility generating unit currently rated at approximately 500 megawatts, known

as Unit 1. The existing Unit 1 is a pulverized coal-fired boiler fueled by washed bituminous coal

from the company’s Deserado mine, approximately 35 miles east of the plant. The plant is the

sole user of coal from the mine. Emission controls for existing Unit 1 consist of a baghouse for

PM/PM10 control, a wet scrubber for SO2 control, and low-NOx burners for NOx control.

On February 4, 1981, EPA Region 8 issued a Federal PSD permit for initial construction

of Bonanza Power Plant, which at the time was planned to consist of two 400-megawatt units,

and was permitted as such. Only one unit was built. After EPA approved Utah’s PSD permitting

program in the early 1980’s, the State of Utah issued its own PSD permit for Unit 1, later revised

to account for modifications that upgraded Unit 1 to approximately 500 megawatts. In late 1997,

as a result of a Federal court decision, EPA Region 8 asserted Federal jurisdiction over Bonanza

Power Plant and issued an updated Federal PSD permit for Unit 1 on February 4, 2001, replacing

the 1981 Federal permit. There is currently no Federal PSD permit in effect for construction of

Bonanza Unit 2.
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C. Company Contacts

Ed Thatcher, Vice President and Chief Engineer

David Crabtree, Vice President and General Counsel

Deseret Power Electric Cooperative

10714 South Jordan Gateway

South Jordan, Utah 84095

Phone: (801) 619-6500

D. Process Description

The proposed WCFU will utilize circulating fluidized bed (CFB) combustion technology.

Control of SO2, NOx and acid gases (including H2SO4) in the combustion chamber is one of the

major advantages of this technology over conventional pulverized coal fired boilers. Additional

emission controls are described later in this Statement of Basis. The electricity generated by the

WCFU will be supplied to the Bonanza substation.

The major components of the proposed WCFU include:

• Combustion and generating systems,

• Exhaust systems and pollution control equipment,

• Emergency power,

• Coal and limestone material handling and storage systems,

• Cooling water systems, and

• Ash disposal systems.

Principal components of a CFB boiler include primary and secondary air fans, combustor,

cyclone/solids separator, superheater, economizer, air heater and induced draft fan. The CFB

boiler will supply superheated steam to the extraction/condensing turbine to drive an electrical

generator and supply cycle and plant auxiliary steam through uncontrolled extraction from the

turbine. The boiler heat input design capacity at maximum load will be no more than 1,445

million British Thermal Units per hour (MMBtu/hr). The boiler will be fueled by western

bituminous waste coal obtained from the company’s nearby Deserado mine. If waste coal is not

available in emergencies, ROM coal or washed coal from the Deserado Mine will be utilized

(explained further below).

Combustion in the CFB boiler takes place in a vertical chamber called the combustor.

The crushed coal and limestone are introduced into the combustor, fluidized and burned at

temperatures of approximately 1550 F (1500 – 1650 F). The pulverized limestone reacts with the

sulfur dioxide released from the burning fuel to form calcium sulfate (gypsum). This is the initial

stage of SO2 emission control. The bed material in the combustor consists primarily of mineral

matter from the fuel, gypsum and excess calcined lime.
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Combustion air is fed to the combustor at two levels. The bed material is fluidized with

primary air introduced through an air distribution system at the bottom of the combustor and also

by the combustion gases generated. Secondary air is added to the lower section of the

combustor, above the dense phase fluidized bed, to achieve complete and staged combustion.

Bed material that is fluidized does not become molten, but rather the action of the air/flue

gas bubbling through the bed allows the bed material to behave and move as though it were a

fluid and allow thorough mixing of the bed material. Roughly fifty percent of the combustion air

is introduced as primary or fluidizing air through the bottom air distribution system, and the

balance is admitted as secondary air through multiple ports in the side walls. This staged

combustion, at controlled relatively low temperatures, along with the injection of ammonia at the

furnace outlets, effectively controls NOx formation through selective non-catalytic reduction and

provides conditions to most effectively capture SO2 at low calcium to sulfur molar ratios.

The recycle cyclones/solids separator removes a major portion of the hot ash particles

from the flue gas stream and re-circulates them back into the combustor, to enhance heat transfer

to the combustor walls and to provide more time for complete combustion of the coal particles

and calcination of the limestone particles. Ash is continuously withdrawn from the combustion

chamber, cooled, and is then transferred for disposal.

Heat for steam generation is removed from the system in two ways: In the primary loop,

heat is removed from the solids circulating in the CFB system by the heat absorbing surface in

the water walls of the combustor and heat absorbing surface in the fluid bed heat exchangers. In

the convection pass, heat is removed from the flue gas exiting the recycle cyclones/solids

separator by superheater and economizer surfaces.

Relatively clean flue gases from the recycle cyclones/solids separator enter the convective

pass of the steam generator where they pass over the superheater and economizer elements.

After the convection pass, the flue gases are further cooled in an air heater, which utilizes the low

grade heat of the flue gas to pre-heat combustion air. From the air heater, the flue gas continues

to the dry scrubber for additional SO2 removal, then to the baghouse filter for removal of residual

particulate, then to the induced draft (ID) fan at the stack.

Flue gas will be exhausted from the boiler/baghouse train by an induced draft fan to a 275

foot high, 14 foot diameter steel stack. Ports will be provided to accommodate flue gas sampling

equipment and the continuous emission monitoring system. Startup burners are used for

preheating the CFB boiler bed up to coal ignition temperature and to provide heat input support

at low loads. In-duct or above bed burners, firing #2 fuel oil, will be provided for startup and

low load operating conditions.

The proposed WCFU will utilize portions of the existing Bonanza power plant facilities,

including: the control room, administration building, raw water supply system, fuel oil system,

plant drains, storm drains, sanitary and corrosive drain systems, ash conveyors, coal rail car
9

receiving hopper and transfer building, demineralized water system, fire protection/service water,

potable water, auxiliary steam, and the grounding and cathodic protection system.

An emergency generator will supply power to the WCFU systems in the event that

normal electrical power is interrupted. The emergency generator will be a diesel-fired

compression-ignition internal combustion engine, rated at 750 kilowatts and 1,005 horsepower.

Deseret Power estimates that use of this generator will be less than 100 hours per year.

E. Waste Coal Characteristics

The waste coal is presently landfilled in refuse pits at the Deserado mine and will be

reclaimed and/or diverted from the landfill for use in the CFB boiler. Based on core samples

from the existing waste coal stockpile, the permit applicant (Deseret Power) estimates the

following:

Characteristics of Waste Coal Currently Stockpiled

At Deserado Mine

Based on samples taken from conveyors currently transporting waste coal from the wash

circuit at Deserado mine to the waste coal stockpile, Deseret Power estimates that sulfur content

in new waste coal going to the stockpile ranges from 0.35% to 1.33%, somewhat higher than the

range of sulfur content in the current stockpile. Based on core samples from the coal seam

reserve at the Deserado mine, Deseret Power estimates that future waste coal material will reach

0.71% sulfur content on a 30-day average, approximately double the average sulfur content in the

current waste coal stockpile.

F. Waste Coal Versus Run-of-Mine or Washed Coal as Potential Fuel.

Deseret Power has stated that it plans to use waste coal as sole fuel for the WCFU, except

for emergencies that would prevent waste coal from being delivered from the Deserado mine and

placed into the WCFU, as long as a supply of waste coal, as supplemented by waste coal

generated from ongoing operations, remains available from the mine. For the aforementioned

emergencies where waste coal is not available, Deseret Power wants the option of using run-ofmine (ROM) coal or washed coal from the Deserado mine in the WCFU. ROM coal is raw

Characteristic Average Range

Nominal heating

value

4,000 Btu/lb 3,000 Btu/lb - 5,400 Btu/lb

Sulfur content

(30-day average)

0.34% 0.24% - 0.71%

Ash content 50.5% 40% - 56%

Nitrogen content 0.51% 0.37% - 0.66%
10

mined coal that has not been washed in the coal washing facility at the mine. Washed coal is

mined coal that has been washed in the coal washing facility and is normally intended for use

exclusively at the existing Bonanza Unit 1.

Deseret Power has also requested operational flexibility, in the EPA permit, to blend

ROM coal in with the waste coal, at up to a 50/50 ratio by weight, as needed at any time, such as

in the event of operational difficulties arising from use of waste coal as sole fuel, or in the event

of unexpected difficulties in meeting BACT emission limits. The ROM coal has a heating value

range of approximately 8,500 Btu/lb to 10,000 Btu/lb. A 50/50 blend would yield coal with

average heating value of approximately 6500 Btu/lb.

Sulfur content of washed coal delivered to existing Bonanza Unit 1 has historically

ranged from 0.30% to 0.86% on a daily basis, and up to 0.66% on a 30-day average. For 2005,

the maximum 30-day average sulfur content increased to 0.74%. Sulfur content of ROM coal is

believed by Deseret Power to be similar.

Although ROM or washed coal would be higher quality fuel than waste coal in terms of

heat content (Btu’s) per pound of coal burned, the cost of waste coal is much lower at current

prices, by about $30 to $35 per ton of coal, versus ROM coal. This price differential does not

include the additional cost of ROM or washed coal that accrues from the fact that use of ROM

coal or washed coal at the WCFU would reduce the lifespan of the fuel supply for Unit 1, and

therefore the useful lifespan of Unit 1 itself, which relies solely on the Deserado mine for fuel.

Deseret Power estimates that the WCFU can be fueled solely on waste coal from the

Deserado mine for about 12 to 15 years at current mine operation levels, before other coal might

have to be used to supplement the ongoing waste coal generated at the mine. This estimate is

based on the following figures:

 The current waste coal stockpile is estimated at 7.9 million tons.

 New waste coal is being produced at the mine at a rate of about 0.4 to 0.6 million

tons per year.

 The WCFU will use about 1.2 to 1.3 million tons per year of waste coal. This

estimate is based on projected WCFU heat input rate of 1,445 MMBtu/hr, average

waste coal heat content of 4,000 Btu/lb, and projected WCFU capacity factor of

80% to 85%.

Although there is a limited stockpile of waste coal as described above, the WCFU is

being designed specifically to burn the waste coal. This means that equipment such as the coal

handling, ash handling, limestone handling, lime supply, ammonia injection and control systems

are all being designed to burn solely waste coal. If ROM coal or washed coal was to be

combusted instead as primary fuel, these support systems, as well as the furnace, would be
11

oversized, since run-of-mine coal and washed coal have two to three times as many Btu’s per

pound versus waste coal.

Generally, fuel quality shifts can be accommodated in the CFB combustion process, but

some operating upsets would likely occur and might increase the emissions over the short term.

For example, if the primary fuel shifted from the waste fuel to ROM coal or washed coal, a spike

in emissions due to the change in sulfur content would most likely occur. The spike in sulfur

emissions would automatically cause a spike in limestone and lime quantity flows as controls

reacted to the changed condition. The spike in limestone flow would then cause an increase in

NOx emissions, which would then cause an increase in ammonia emissions. These changes in

emissions would eventually settle out once the controls were adjusted to the higher quality fuel;

however, a potential additional complication is that the material handling systems might be

oversized to handle the run-of-mine or washed coal and would have to be modified.

Other impacts from a potential switch to ROM coal or washed coal, as fuel for the

proposed WCFU, would be associated with the increased material handling requirements to

inject sand into the furnace. As the heating value of the coal increases, the tonnage of coal

required to maintain the same furnace temperature is reduced. If the percentage of sulfur in the

coal remains relatively constant when switching to ROM or washed coal, then the uncontrolled

SO2 per ton of coal burned will be reduced, such that the boiler will require less limestone in

order to control the SO2 at the same required levels. Also, the ash content will be lower in ROM

or washed coal. Proper operation of a CFB boiler requires that the inventory of solids in the

furnace be maintained at a specified level. Based upon burning ROM or washed coal, having

approximately the same sulfur content as the waste coal, and lower ash content, the volume of

coal, ash and limestone (bed materials) will be reduced in the furnace. When this operating

condition is encountered, it is necessary to inject sand into the furnace in order to maintain the

proper solids volume or inventory in the furnace. This would affect the performance of the

boiler.

G. Coal, Limestone and Ash Handling

1. Coal. Approximately 20 electric powered trains per month will deliver the

needed waste coal to the WCFU. The railcars will discharge the coal into a track hopper and the

waste coal will then be transported by conveyor to a storage pile containing 30 to 60 days of coal

storage. The coal will be reclaimed from the storage pile by a dozer pushing the coal into a

reclaim hopper, which feeds the coal onto a conveyor, which transports the coal to a crusher to

size the coal and then to coal storage silos. The silos will be sized to store approximately 10.5

hours of fuel supply based on the maximum boiler load. The silos will discharge the coal onto

gravimetric feeders controlling fuel flow rate to the boiler furnace.

2. Limestone. Limestone will be delivered by truck to the existing limestone

pile at Bonanza plant. The limestone will be reclaimed with a dozer pushing the limestone into a

reclaim hopper. The limestone will be transported by conveyor to a silo. The silo will be sized
12

to accommodate approximately 30 hours of storage (200 tons) based on full load operation. The

limestone will be discharged from the silo into crusher/dryer mills where the limestone will be

crushed and dried. A pneumatic system will transport the dry, sized limestone from the

crusher/dryer mills to the boiler furnace to control SO2.

3. Ash. Fly ash and bottom ash generated by the CFB combustor will be

hydrated prior to transfer for disposal.

H. Proposed Emission Control Techniques

1. CFB boiler. Control of filterable PM/PM10 emissions will consist of a

fabric filter baghouse. Control of SO2 and H2SO4 emissions will consist of limestone injection

into the CFB combustor unit and a dry ‘polishing’ scrubber (spray dry absorber) downstream.

Control of NOx emissions will consist of Selective Non-Catalytic Reduction (SNCR), via

ammonia injection directly into the CFB combustor unit. Control of CO emissions will consist

of a combustion control system designed and operated to ensure complete combustion. Control

of condensible PM emissions will consist of a combination of limestone injection, dry scrubber

and fabric filter baghouse.

2. Emergency generator. PM/PM10 emission control will consist of positive

crankcase ventilation, good combustion practices, and use of low-sulfur diesel fuel. SO2 and

H2SO4 emission control will consist of use of low-sulfur diesel fuel (500 parts per million sulfur

content or less). NOx emission control will consist of combustion controls (ignition retarding

and/or lean burn, to the maximum extent that the engine specifications will allow). CO emission

control will consist of good combustion practices as specified in the operation and maintenance

manual from the engine manufacturer. The engine to be purchased will be “Tier 2 certified,”

meaning that it will be designed by the manufacturer to comply with the “Tier 2” emission limits

in 40 CFR 89.112, Table 1, that apply to non-road compression-ignition engines with electrical

generating capacity greater than 560 kilowatts.

3. Coal, limestone and ash handling. PM/PM10 point source emissions from

conveying systems will be controlled by use of enclosed conveyors, and by installing dust control

and collection systems at all material transfer points. The dust collection systems will utilize

either induced draft filter bag units (baghouses) or cartridge type (vent) filters, as follows:

Estimated

Emissions Emission Point ID Air flow Location

Coal dust Baghouse OCH/DC-1 15,000 dscfm Existing terminal building

Coal dust Baghouse EP-W-MH-01 8,500 dscfm Crusher building

Coal dust Baghouse EP-W-MH-02 8,500 dscfm Coal day silo headhouse

Limestone dust Baghouse EP-W-MH-03 1,000 dscfm Limestone crushers

Limestone dust Vent filter EP-W-MH-04 1,000 dscfm Surge bin
13

Limestone dust Baghouse EP-W-MH-05 4,000 dscfm Limestone storage silo

Ash dust Vent filter EP-W-MH-06 1,000 dscfm Bed ash recirculation bin

Ash dust Vent filter EP-W-MH-07 1,000 dscfm Bed ash disposal surge bin

Ash dust Baghouse EP-W-MH-08 3,600 dscfm Fly ash silo

Ash dust Baghouse EP-W-MH-09 3,600 dscfm Bed ash silo

Lime dust Vent filter EP-W-MH-10 2.000 dscfm Lime storage silo

Inert material Vent filter EP-W-MH-11 2.000 dscfm Inert bed day bin

Control of PM/PM10 non-point source (i.e., fugitive) emissions will consist of the

following: Control for the coal stockpile will include compaction, water sprays and surfactant as

needed. Also, the working area of the coal stockpile will be minimized. Control for the

limestone stockpile will include water sprays and surfactant as needed. (“As needed” is defined

in the proposed permit as any time a ten percent opacity level is exceeded.) Control for the

ash/sludge pile will include compaction, water sprays, minimizing the exposed area and revegetation.

4. Cooling tower. For control of PM/PM10 emissions generated from

evaporation of particulate-laden water, the cooling tower will be equipped with cellular-type mist

eliminators designed to limit circulating water drift loss to 0.001 percent or less.
14

I. Potential to Emit

1. Controlled (with BACT applied)

Pollutant

Estimated

emissions Basis of estimate

Particulate matter

(filterable) from

CFB boiler

76 tons/yr [0.012 lb/MMBtu allowed in permit] x

[1445 MMBtu/hr boiler heat input capacity] x

[8760 hrs/yr operation] x [1 ton per 2000 lbs]

Particulate matter

(condensible) from

CFB boiler

120 tons/yr [0.019 lb/MMBtu EPA engineering estimate] x

[1445 MMBtu/hr boiler heat input capacity] x

[8760 hrs/yr operation] x [1 ton per 2000 lbs]

Sulfur dioxide 348 tons/yr [0.055 lb/MMBtu allowed in permit] x

[1445 MMBtu/hr boiler heat input capacity] x

[8760 hrs/yr operation] x [1 ton per 2000 lbs]

Nitrogen oxide 557 tons/yr [0.088 lb/MMBtu allowed in permit] x

[1445 MMBtu/hr boiler heat input capacity] x

[8760 hrs/yr operation] x [1 ton per 2000 lbs]

Carbon monoxide 949 tons/yr [0.15 lb/MMBtu allowed in permit] x

[1445 MMBtu/hr boiler heat input capacity] x

[8760 hrs/yr operation] x [1 ton per 2000 lbs]

Sulfuric acid 22 tons/yr [0.0035 lb/MMBtu allowed in permit] x

[1445 MMBtu/hr boiler heat input capacity] x

[8760 hrs/yr operation] x [1 ton per 2000 lbs]

Volatile organic

compounds

32 tons/yr [0.005 lb/MMBtu by boiler design] x

[1445 MMBtu/hr boiler heat input capacity] x

[8760 hrs/yr operation] x [1 ton per 2000 lbs]

Particulate matter

from coal, ash and

limestone handling

18 tons/yr AP-42 emission factors for coal, ash and

limestone handling, and taking into account

compaction of stockpiles, watering, enclosed

conveyors, baghouses, vent filters, and other

emission controls proposed by Deseret Power.
15

2. Uncontrolled

Pollutant

Estimated

emissions Basis of estimate

Particulate matter

(filterable) from

CFB boiler

632,900

tons/yr

[0.66 lb total ash per lb of waste coal burned] x

[0.8 lb fly ash per lb of total ash] x

[projected coal consumption of 1.2 million

tons/year for “average” waste coal]

Particulate matter

(condensible) from

CFB boiler

317 tons/yr [0.0501 lb/MMBtu estimated by boiler supplier,

based on boiler design and combustion of

“average” waste coal] x

[1445 MMBtu/hr boiler heat input capacity] x

[8760 hrs/yr operation] x [1 ton per 2000 lbs]

Sulfur dioxide 10,823

tons/yr

[1.71 lb/MMBtu uncontrolled SO2 emission

potential for “average” waste coal] x

[1445 MMBtu/hr boiler heat input capacity] x

[8760 hrs/year operation] x [1 ton per 2000 lbs]

Nitrogen oxide 949 tons/yr [0.15 lb/MMBtu estimated by boiler supplier,

based on boiler design and combustion of

“average” waste coal] x

[1445 MMBtu/hr boiler heat input capacity] x

[8760 hrs/year operation] x [1 ton per 2000 lbs]

Carbon monoxide 949 tons/yr [0.15 lb/MMBtu estimated by boiler supplier,

based on boiler design and combustion of

“average” waste coal] x

[1445 MMBtu/hr boiler heat input capacity] x

[8760 hrs/year operation] x [1 ton per 2000 lbs]

Sulfuric acid 165 tons/yr [1.71 lb/MMBtu uncontrolled SO2 emission

potential for “average” coal] x

[1% of sulfur content emitted as H2SO4] x

[98 lb H2SO4 per 64 lb SO2] x

[1445 MMBtu/hr boiler heat input capacity] x

[8760 hrs/year operation] x [1 ton per 2000 lbs]
16

Volatile organic

compounds

32 tons/yr [0.005 lb/MMBtu estimated by boiler supplier,

based on boiler design and combustion of

“average” waste coal] x

[1445 MMBtu/hr boiler heat input capacity] x

[8760 hrs/year operation] x [1 ton per 2000 lbs]

Particulate matter

from coal, ash and

limestone handling

83 tons/yr AP-42 emission factors

J. Proposed Emission Monitoring Techniques

1. CFB boiler: Filterable PM emissions will be monitored continuously by a

particulate matter continuous emission monitoring system (PM CEMS). Condensible PM

emissions will be monitored by annual EPA Method 202 or EPA Conditional Test Method 39

stack tests. H2SO4 emissions will be monitored by annual EPA Method 8 or NCASI Method 8A

stack tests. (Note: NCASI Method 8A is not an EPA Method, but is published by the National

Council on Air and Stream Improvement, Inc., December 1996 It is available on NCASI

website at http://www.ncasi.org. An explanation of why EPA is allowing it as an alternative to

EPA Method 8 may be found in section VI.L.7 of this Statement of Basis.)

SO2, NOx and CO emissions will be monitored continuously by SO2, NOx and CO

continuous emission monitoring systems (CEMS). A diluent continuous monitoring system will

be required for converting CEMS data into units of lb/MMBtu. All CEMS will be required to

pass the applicable Performance Specification Tests in 40 CFR part 60, Appendix B, and comply

with ongoing quality assurance requirements in 40 CFR part 60, Appendix F.

2. Emergency generator: Monitoring for nitrogen oxide, carbon monoxide

and particulate emissions will consist of: (1) records demonstrating that the emergency generator

engine is purchased from a manufacturer who has obtained a “certificate of conformity” from

EPA, certifying that the engine is compliant with the “Tier 2” emission standards for PM10, NOx

and CO in 40 CFR 89.112, Table 1, for engines with electrical generating capacity greater than

560 kilowatts, and (2) records demonstrating that the engine manufacturer’s recommendations

are being followed for compliance with the “Tier 2” standards. Monitoring for SO2 emissions

will consist of records verifying that only diesel fuel with sulfur content of less than 0.05 percent

by weight is used.

3. Materials handling system baghouses: PM/PM10 emissions will be

monitored by initial stack testing at the largest (15,000 dry standard cubic feet per minute,

“dscfm”) baghouse, one of the two 8,500 dscfm baghouses, and one of the smaller baghouses

(the 4,000 dscfm baghouse). If stack test results at the first 8,500 dscfm baghouse are in excess

of the allowable emission limit, then the second 8,500 dscfm baghouse will be required to be
17

tested. If stack test results at the 4,000 dscfm baghouse are in excess of the allowable emission

limit, then the remaining 3 baghouses will be required to be tested.

After initial testing, in lieu of subsequent annual tests (if test results are in compliance),

EPA proposes to require monthly opacity monitoring at each baghouse exhaust stack via EPA

Method 22. If a Method 22 opacity observation detects any visible emissions, then: (1) a EPA

Method 9 opacity observation will be required, to establish whether the emissions are in excess

of the 10% opacity limit, and (2) the cause of the visible emissions will be required to be

investigated and, if caused by a baghouse malfunction, will be required to be corrected within

three working days, if the cause of the malfunction is broken bags, or within seven working days

for any other cause.

4. Non-point source (i.e., fugitive) PM/PM10 emissions: Monitoring will

consist of records demonstrating that water sprays and/or surfactant are applied “as warranted”

for adequate dust control at the coal and limestone stockpiles. “As warranted” is defined in the

permit as dust control sufficient to keep visible emissions at the stockpiles below ten percent

opacity. Weekly observations for any visible emissions will be required.
18

V. Description of this Permitting Action

A. Purpose.

The purpose of this permit action is to approve construction of a new 110 megawatt

electric utility unit at Deseret Power’s existing Bonanza power plant, known as the Waste Coal

Fired Unit (WCFU). Steam for generating electricity will be provided by a Circulating Fluidized

Bed (CFB) boiler, rated at no more than 1,445 MMBtu/hr heat input capacity, fueled by waste

coal from the nearby Deserado Mine. As explained earlier, emission controls for the CFB boiler

will include a fabric filter baghouse for filterable PM/PM10 control, limestone injection and dry

scrubber (spray dry absorber) for SO2 and H2SO4 control, Selective Non-Catalytic Reduction

(SNCR) for NOx control, a combustion control system for CO control, and a combination of

limestone injection, dry scrubber and fabric filter baghouse for condensible PM control.

Also permitted for construction will be coal, limestone and ash handling systems for the

WCFU. Emission controls for point source PM/PM10 emissions from the materials handling

systems will include enclosed conveyers, along with fabric filter baghouses and vent filters at

material transfer points. Emission controls for non-point source (i.e., fugitive) emissions will

consist of compaction of material stockpiles, minimizing the working area of the stockpile, and

application of surfactant and water sprays as warranted.

B. PSD Applicability.

40 CFR 52.21(a)(2)(iii) provides: “No new major stationary source or major modification

to which the requirements of paragraphs (j) through (r)(5) of this section apply shall begin actual

construction without a permit that states that the major stationary source or major modification

will meet those requirements. The Administrator has authority to issue any such permit.” As

explained in sections I and II of this Statement of Basis, EPA has determined that the WCFU

project will constitute a major modification to an existing PSD major stationary source (Bonanza

power plant), and therefore is subject to PSD permitting. The WCFU project will result in

significant emission increases at Bonanza plant for the following PSD-listed pollutants: total

PM, PM10, SO2, NOx, H2SO4 and CO.

C. Application Submittals and Addendums.

The initial PSD permit application was submitted by Deseret Power via cover letter dated

April 13, 2004. The application was revised and resubmitted on November 1, 2004. Further

revisions were submitted via letters and e-mails on the following dates:

 March 23, 2005: Letter and attachments from Deseret Power to EPA modified the

permit modeling, in response to EPA’s November 22 and December 29, 2004

letters. Deseret also corrected the coordinates of the stack.
19

 March 23, 2005: Letter from Deseret Power to U.S. Forest Service modified the

permit modeling.

 May 4, 2005: E-mail from Deseret Power to EPA agreed to installation of a dry

scrubber for additional sulfur dioxide control and reduced the proposed SO2

BACT emission limit from 0.10 lb/MMBtu to 0.055 lb/MMBtu.

 May 10, 2005: Letter from Deseret Power to EPA reduced the proposed NOx

BACT emission limit to 0.088 lb/MMBtu.

 May 10, 2005: Letter from Deseret Power to EPA proposed alternative BACT

emission limits in pounds per hour for startup/shutdown periods.

 May 10, 2005: Letter from Deseret Power to EPA agreed to install a particulate

matter continuous emission monitoring system (PM CEMS).

 May 10, 2005: Letter from Deseret Power to EPA committed to comply with the

recently released mercury emission limits and install a mercury CEMS. (EPA

later replied to Deseret on June 13, 2005 that electric utilities have been delisted

from MACT rulemaking and therefore a case-specific MACT determination for

mercury will not be required. Deseret Power will, however, be required to comply

with mercury emission limits recently established in 40 CFR 60, subpart Da.)

 May 10, 2005: Letter from Deseret Power to EPA clarified (at EPA’s request) the

reference in Deseret’s permit application to the NSPS emission standard for total

filterable particulate matter, with regard to averaging time of the standard.

 May 10, 2005: Letter from Deseret Power to EPA provided a revised Section 7,

Miscellaneous Permit Information, for the permit application. Specifically, the

information pertained to potential impact of the WCFU project on endangered

species.

 June 16, 2005: E-mail from Deseret Power to EPA increased the amount of

anticipated ammonia slip, due to the lower NOx and SO2 emission limits now

being proposed by Deseret Power (0.088 lb/MMBtu for NOx and 0.055 lb/MMBtu

for SO2).

 October 17, 2005: E-mail from Deseret Power to EPA amended the BACT

analysis for the Emergency Diesel Generator, contained in Sections 5.9 through

5.13 of the permit application, and provided revised predicted emissions for the

Emergency Diesel Generator.
20

 November 11, 2005: E-mail from Deseret Power to EPA proposed BACT for

PM/PM10 emissions at the cooling tower. Cost calculations were provided via

followup e-mail to EPA on December 13, 2005.

 January 9, 2006: E-mail from Deseret Power to EPA proposed a calculated

emission limit as BACT for SO2 instead of the 0.040 lb/MMBtu limit that EPA

proposed to Deseret on December 1, 2005, as the ‘lower tier’ limit (i.e., when

uncontrolled SO2 emission potential of the coal drops below 1.9 lb/MMBtu on a

30-day average). The calculated limit would be a weighted average between the

upper and lower tiers proposed earlier by EPA (0.055 and 0.040).

 January 13, 2006: E-mail from Deseret Power to EPA, in response to verbal

request from EPA, provided an expanded description of waste coal characteristics.

 January 13, 2006: E-mail from Deseret Power to EPA, in response to verbal

request from EPA, suggested permit language corresponding to Deseret’s

weighted average SO2 BACT proposal of January 9, 2006.

 January 30, 2006: E-mail from Deseret Power to EPA provided a revised estimate

of condensible particulate matter emissions (0.033 lb/MMBtu) and proposed a

revised BACT emission limit for total PM10 of 0.045 lb/MMBtu, rather than the

0.052 lb/MMBtu originally proposed by Deseret.

 February 2, 2006: E-mail from Deseret Power to EPA, in response to verbal

request from EPA, provided a description of boiler operational changes and

materials handling changes that would likely be necessary, if run-of-mine coal

was to be burned as primary fuel instead of waste coal.

 February 7 and 8, 2006: E-mails from Deseret Power to EPA, in response to

verbal request from EPA, provided additional information in support of Deseret’s

proposed BACT emission limit of 0.15 lb/MMBtu (30-day rolling average) for

CO.

 February 21, 2006: E-mail from Deseret Power to EPA proposes PSD BACT

emission limit of 0.0038 lb/MMBtu on a 30-day rolling average for sulfuric acid

(H2SO4), on the basis that 0.0038 is the lowest detectable limit when using

NCASI Method 8A.

 February 22, 2006: E-mail from Deseret Power to EPA provides supporting

information requested by EPA for Deseret’s estimate of 0.033 lb/MMBtu for

condensible particulate matter emissions.
21

 February 23, 2006: E-mail from Deseret Power to EPA provides top-down BACT

analysis requested by EPA for control options for condensible particulate matter

emissions.

 April 10, 2006: E-mail from Deseret Power to EPA confirms that Deseret Power

wants operational flexibility to blend run-of-mine coal with the waste coal at any

time, if needed, at up to a 50/50 ratio by weight, equivalent to about 6500 Btu/lb

heat content coal.

 April 25, 2006: E-mail from Deseret Power to EPA provides an estimate of

potential uncontrolled fugitive particulate emissions from coal, ash and limestone

handling, based on AP-42 emission factors.

 April 5, 2007: E-mail from Deseret Power to EPA, regarding Endangered Species

Act section 7 consultation, requests that a prior e-mail from Deseret Power to

EPA, dated December 8, 2006, be incorporated as part of the PSD permit

application for the 110-MW WCFU project. The prior e-mail said:

1. Deseret agrees that it will provide to the USFWS, on an annual basis, the

amount of water withdrawn from the Green River for Deseret’s 110-MW

WCFU project, once the project is built and operating.

2. Deseret agrees to notify EPA and USFWS the date when construction of the

110-MW WCFU project commences.

 April 5, 2007: E-mail from Deseret Power to EPA, regarding Endangered Species

Act section 7 consultation, requests that a prior e-mail from Deseret Power to

EPA, dated December 4, 2006, be incorporated as part of the PSD permit

application for the 110-MW WCFU project. The Dec. 4, 2006 e-mail said Deseret

will commit to paying the final 90% of the water depletion fee, for withdrawing

water from the Green River for the 110-MW WCFU, when construction

commences on the WCFU, rather than just prior to any water being withdrawn

from the Green River. (The first 10% of the fee is due when the EPA PSD permit

is issued.)
22

VI. Best Available Control Technology Analysis

A. Approach Used in BACT Analysis

Pursuant to 40 CFR 52.21(j), a new major stationary source shall apply BACT for each

pollutant subject to regulation under the Clean Air Act (CAA) that it would have the potential to

emit in significant amounts. A major modification shall apply BACT for each pollutant subject

to regulation under the CAA for which it would result in a significant net emissions increase at

the source. The requirement applies to each proposed emissions unit at which a net emissions

increase in the pollutant would occur as a result of a physical change or change in the method of

operation in the unit. The definition of BACT at §52.21(b)(12) states, in part, that BACT means:

... an emissions limitation (including a visible emission standard) based on the maximum

degree of reduction for each pollutant subject to regulation under [the Clean Air] Act which

would be emitted from any proposed major stationary source or major modification which the

Administrator, on a case-by-case basis, taking into account energy, environmental, and

economic impacts and other costs, determines is achievable for such source or modification

through application of production processes or available methods, systems, and techniques,

including fuel cleaning or treatment or innovative fuel combustion techniques for control of such

pollutant. In no event shall application of best available control technology result in emissions

of any pollutant which would exceed the emissions allowed by any applicable standard under 40

CFR parts 60 and 61. If the Administrator determines that technological or economic

limitations on the application of measurement technology to a particular emissions unit would

make the imposition of an emissions standard infeasible, a design, equipment, work practice,

operational standard, or combination thereof, may be prescribed instead to satisfy the

requirement for the application of best available control technology.

The 1990 Clean Air Act amendments added “clean fuels” after “fuel cleaning or

treatment” in the above definition.

On December 1, 1987, EPA issued a memorandum defining the top-down approach for

determining BACT. In brief, the top-down approach provides that all available control

technologies be ranked in descending order of control effectiveness. Each alternative is then

evaluated, starting with the most stringent, until BACT is determined. The top-down approach

consists of the following steps, for each pollutant to which BACT applies:

Step 1: Identify all control technologies.

Step 2: Evaluate technical feasibility of options from Step 1 and eliminate

technically infeasible options, based on physical, chemical and engineering

principles.
23

Step 3: Rank remaining control technologies from Step 2 by control effectiveness,

in terms of emission reduction potential.

Step 4: Evaluate most effective controls from Step 3, considering economic,

environmental and energy impacts of each control option. If top option is

not selected, evaluate the next most effective control option.

Step 5: Select BACT (most effective option from Step 4 not rejected)

B. PSD BACT Emission Limits Apply at All Times.

EPA’s interpretation of the CAA, and of the PSD rules in 40 CFR parts 51 and 52, is that

PSD BACT emission limits must apply at all times. Automatic exemptions from PSD BACT

emission limits cannot be allowed for periods of startup, shutdown, malfunctions, or for any

other reason. The following EPA memoranda have consistently made this clear:

September 28, 1982 memorandum from Kathleen Bennett, EPA Assistant Administrator

for Air, Noise and Radiation, to EPA Regional Offices, titled “Policy on Excess

Emissions During Startup, Shutdown, Maintenance and Malfunctions.”

February 15, 1983 memorandum from Kathleen Bennett to EPA Regional Offices, same

title as above.

January 28, 1993 memorandum from John Rasnic of EPA’s Office of Air Quality

Planning and Standards (OAQPS) to Linda Murphy of EPA Region I.

September 20, 1999 memorandum from Steve Herman and Robert Perciasepe, EPA

Assistant Administrators, to EPA Regional Offices, titled “State Implementation Plans:

Policy Regarding Excess Emissions During Malfunctions, Startup, and Shutdown.”

In particular, the 1993 memorandum states that PSD permits cannot contain automatic

exemptions which allow excess emissions during startup and shutdown. The 1982 memorandum

states the same for malfunctions. These memoranda are available on EPA’s NSR Policy and

Guidance database, at the following website:

http://www.epa.gov/region07/programs/artd/air/nsr/nsrpg.htm
24

C. Pollutants Subject to BACT for this Project

For major modifications to existing major stationary sources, 40 CFR 52.21(j)(3) requires

that BACT be applied for each regulated NSR pollutant for which there will be a significant net

emission increase at the source. The requirement applies to each proposed emitting unit at which

a net emissions increase in the pollutant would occur as a result of the physical change or change

in the method of operation of the unit. As detailed in Deseret Power’s PSD permit application

dated November 1, 2004, the WCFU project will result in significant net emission increases from

the Bonanza power plant for the following regulated NSR pollutants:

 particulate matter (PM),

 particulate matter smaller than 10 microns (PM10),

 sulfur dioxide (SO2),

 nitrogen oxide (NOx),

 sulfuric acid (H2SO4), and

 carbon monoxide (CO).

A BACT analysis for each of these pollutants is presented later in this Statement of Basis.

Since potential uncontrolled emissions of volatile organic compounds (VOC) from the WCFU

project are estimated at 32 tons per year, less than the PSD significance threshold, no BACT

analysis for VOC is required.

The definition of “regulated NSR pollutant” in 40 CFR 52.21(b)(5) includes “any

pollutant for which a national ambient air quality standard [NAAQS] has been promulgated.” On

July 18, 1997, EPA promulgated the NAAQS for particulate matter with aerodynamic diameter

smaller than 2.5 microns (PM2.5).

Consistent with the October 23, 1997 memorandum titled, ”Interim Implementation of

New Source Review Requirements for PM2.5,” issued by John Seitz, Director of EPA’s Office

of Air Quality Planning & Standards (OAQPS), and consistent with the April 5, 2005

memorandum titled, “Implementation of New Source Review Requirements in PM2.5

Nonattainment Areas,” issued by Stephen D. Page, Director of OAQPS, and consistent with the

November 1, 2005, Federal Register notice on the proposed implementation rule for the PM2.5

NAAQS (70 FR 66044.), in which EPA recommends that PM10 be used as a surrogate for PM2.5,

EPA considers all permit limits and analyses in this Statement of Basis that pertain to PM10 to

also satisfy the requirements for PM2.5 at Deseret Power’s proposed WCFU project.

The aforementioned memoranda are available on EPA website:

Oct. 1997 memo: http://www.epa.gov/region07/programs/artd/air/nsr/nsrmemos/pm25.pdf

Apr. 2005 memo: http://www.epa.gov/region07/programs/artd/air/nsr/nsrmemos/pmguid25.pdf
25

D. Alternative Coal (Clean Fuels) for BACT

Under the Clean Air Act definition of BACT, the permitting authority must consider

“clean fuels” when making a BACT determination. From the discussion in section IV.F of this

Statement of Basis, on operational changes that would be necessary at the WCFU to accommodate coal other than waste coal as primary fuel, EPA believes the WCFU could accommodate

alternative coal as primary fuel without a basic redesign of the WCFU project. EPA therefore

believes that consideration of alternative coal as “clean fuel” is within the scope of a BACT

analysis for this project. The following analysis leads EPA to conclude that use of alternative

coal (i.e., coal other than waste coal) from the Deserado mine would be economically costprohibitive as a BACT option, and that use of alternative coal from other mines would also be

cost-prohibitive as a BACT option, in terms of economic, energy and environmental costs.

1. Alternative coal from Deserado mine. The following is an incremental

cost analysis to determine if use of alternative coal from the Deserado mine, rather than waste

coal, would be cost-prohibitive for BACT. All figures used below are considered conservative

by EPA, yielding the lowest dollar-per-ton cost to switch to alternative coal. The alternative coal

would be either ROM coal or washed coal. Since the washed coal is generated specifically for

use at existing Bonanza Unit 1, and is more expensive than ROM coal because it must be

processed through a wash plant, this analysis will focus on the lower-cost ROM coal as the

alternative coal.

As explained earlier in this Statement of Basis, ROM coal is raw mined coal that has not

been processed through the wash plant. The ROM coal characteristics discussed in this analysis

are those of the coal currently being mined, not the ROM coal that might be used 12 to 16 years

from now, after the waste coal stockpile is depleted. As discussed in section IV.E of this

Statement of Basis, based on core samples from the coal seam reserve at the Deserado mine,

future mined coal is expected by Deseret Power to have as much as double the sulfur content of

currently mined coal.

The only significant physical difference between the waste coal and the currently mined

ROM coal that EPA or Deseret Power is aware of, as far as the effect on emission rate in

lb/MMBtu, is the difference in heating value. Deseret Power states that heating value of the

current ROM coal ranges from 8,500 to 10,000 Btu/lb. For the sake of this analysis, EPA will

use 9,250 Btu/lb. Deseret states that “average” waste coal stockpiled at the Deserado mine has

heating value of about 4,000 Btu/lb.

Regarding cost of the coal, Deseret Power states that the waste coal is approximately $5

per ton delivered, which includes cost to reclaim the coal at the mine, transport it to the power

plant, and any associated taxes. ROM coal would have to be purchased from the mine operator

at $35 to $40 per ton. For the sake of this analysis, EPA will use a conservative (i.e., lower end)

estimate of $35 per ton to purchase and deliver ROM coal.
26

Deseret Power has stated that the WCFU would use about 1.2 million tons of waste coal

per year. Based on the relative heating values of ROM coal versus waste coal mentioned above,

EPA calculates that about 519,000 tons of ROM coal would be need to be combusted per year, to

achieve equivalent annual boiler heat output as combustion of 1.2 million tons of waste coal per

year. Therefore, for sake of this analysis, EPA estimates that a switch entirely to ROM coal for

the WCFU would involve the following coal purchase cost for the ROM coal:

$35/ton x 519,000 tons/year = $18,165,000/year.

The annual cost of using the waste coal would be:

$5/ton x 1,200,000 tons/year = $6,000,000/year

(Note: The draft Statement of Basis indicated $5/ton x 1,200,000 tons/year = $3,405,000. This

was an inadvertent mathematical error.) The incremental cost to use entirely ROM coal rather

than waste coal would therefore be the difference in cost of the two coals, which is

$12,165,000/year.

Regarding potential emission reductions in lb/MMBtu that might result from a switch

entirely from waste coal to ROM coal, EPA estimates the following:

NOx: EPA is proposing 0.080 lb/MMBtu on a 30-day average as BACT for the WCFU

(after a 15-month “break-in” period), based on combustion of waste coal. EPA believes the

emissions might be reduced down to 0.07 lb/MMBtu on currently mined ROM coal. This

estimated reduction is based on the higher heat content of ROM coal versus waste coal, and on

0.07 lb/MMBtu being the lowest BACT determination in the RACT/BACT/LAER Clearinghouse database, and the lowest BACT determination EPA is aware of anywhere, for a CFB boiler

project. (See NOx BACT discussion later in this Statement of Basis.) A reduction down to 0.07

lb/MMBtu would be equivalent to a NOx reduction of about 63 tons/yr, assuming the WCFU

runs at design heat input capacity all year.

SO2: EPA is proposing a “lower tier” emission limit of 0.040 lb/MMBtu on a 30-day

average as BACT for the WCFU, based on combustion of “average” waste coal. EPA believes

the emissions might be reduced down to about 0.022 lb/MMBtu on currently mined ROM coal.

This estimated SO2 reduction is based on an uncontrolled SO2 emission potential of 0.734

lb/MMBtu for currently mined ROM coal (which takes into account the higher heat content of

ROM coal versus waste coal), and on an estimated SO2 control efficiency of 97%. (The figure of

0.022 lb/MMBtu is also the lowest BACT determination in the RACT/BACT/LAER Clearinghouse database, and the lowest BACT determination EPA is aware of anywhere, for a CFB boiler

project. See SO2 BACT discussion later in this Statement of Basis.) A reduction down to 0.022

lb/MMBtu would be equivalent to a SO2 reduction of about 114 tons/yr, assuming the WCFU

runs at design heat input capacity all year.
27

CO: EPA is proposing 0.15 lb/MMBtu on a 30-day average as BACT for the WCFU,

based on combustion of waste coal. EPA believes the emissions might be reduced down to about

0.10 lb/MMBtu on currently mined ROM coal. This estimated reduction is based on the higher

heat content of ROM coal versus waste coal, and on 0.10 lb/MMBtu being the lowest BACT

determination in the RACT/BACT/LAER Clearinghouse database, and the lowest BACT

determination EPA is aware of anywhere, for a CFB boiler project, excluding projects that will

not be constructed. (See CO BACT discussion later in this Statement of Basis.) A reduction

down to 0.10 lb/MMBtu would be equivalent to a CO reduction of about 316 tons/yr, assuming

the WCFU runs at design heat input capacity all year.

Sulfuric acid (H2SO4): EPA is proposing 0.0035 lb/MMBtu on a 3-run stack test average

(equivalent to roughly a 3-hour average) as BACT for the WCFU, based on combustion of waste

coal. EPA believes the emissions might be reduced down to about 0.0024 lb/MMBtu on

currently mined ROM coal. This estimated reduction is based on the higher heat content of

ROM coal versus waste coal, and on 0.0024 lb/MMBtu being the lowest BACT determination in

the RACT/BACT/LAER Clearing-house database, and the lowest BACT determination EPA is

aware of anywhere, for a CFB boiler project. (See H2SO4 BACT discussion later in this

Statement of Basis.) A reduction down to 0.0024 lb/MMBtu would be equivalent to a reduction

of about 7 tons/yr, assuming the WCFU runs at design heat input capacity all year.

Filterable particulate matter: For the filterable portion of total PM, EPA is proposing

0.012 lb/MMBtu on a 30-day average as BACT for the WCFU, based on combustion of waste

coal. EPA believes the emissions might be reduced down to about 0.010 lb/MMBtu on currently

mined ROM coal. This estimated reduction is based on the higher heat content of ROM coal

versus waste coal, and on 0.010 lb/MMBtu being the lowest BACT determination in the

RACT/BACT/LAER Clearinghouse database, and the lowest BACT determination EPA is aware

of anywhere, for a CFB boiler project. (See BACT discussion for filterable PM later in this

Statement of Basis.) A reduction down to 0.010 lb/MMBtu would be equivalent to a reduction

of about 13 tons/yr, assuming the WCFU runs at design heat input capacity all year.

Condensible particulate matter: For the condensible portion of PM, EPA has estimated

emissions of 0.019 lb/MMBtu for the WCFU, based on combustion of waste coal. (See BACT

discussion for condensible PM later in this Statement of Basis.) The limits of control for

condensible PM are not very well known. (See BACT discussion for condensible PM later in

this Statement of Basis.) For the sake of this alternative coal analysis, EPA will assume this

estimate might be reduced down to 0.005 lb/MMBtu on currently mined ROM coal., which is the

condensible portion of the total PM/PM10 emission limit in the recent Utah permit for the Sevier

Power Company CFB boiler project. A reduction down to 0.005 lb/MMBtu would be equivalent

to a reduction of about 88 tons/yr, assuming the WCFU runs at design heat input capacity all

year.
28

The estimates above lead to the following cost estimates, in dollars per ton of additional

pollutant removed annually, to use ROM coal rather than waste coal as primary fuel for the

WCFU.

Annualized Cost of Potential Emission Reductions

If Run-Of-Mine Coal is Used Rather Than Waste Coal

for Deseret Power’s Proposed WCFU

Potential Emission Reduction

(Currently Mined “Run of Mine” Annualized

Pollutant Coal versus Waste Coal) Cost ($/ton)

NOx 63 tons/yr $ 193,095/ton

SO2 114 tons/yr $ 106,710/ton

CO 316 tons/yr $ 38,496/ton

H2SO4 7 tons/yr $1,737,857/ton

Filterable PM 13 tons/yr $ 935,769/ton

Condensible PM 88 tons/yr $ 138,238/ton

All (sum) 601 tons/yr $ 20,241/ton

From the cost estimates above, EPA concludes that use of currently mined “run-of-mine”

(ROM) coal at the Deserado mine, i.e., raw coal that has not been washed, rather than waste coal

from the Deserado mine, would be cost-prohibitive as a BACT option for the proposed WCFU,

even if reductions of all pollutants are summed together and then the annualized cost in dollarsper-ton for emission reduction is calculated on that basis. (As shown above, summing the

pollutants yields $20,241/ton, which is a lower dollar-per-ton cost than looking at any one

pollutant individually.) The same annualized dollar-per-ton costs would be incurred if there was

only a partial switch to ROM coal (i.e., coal blending). This is because a partial switch yields

only partial emission reductions. This option (i.e., use of alternative coal from the Deserado

mine, either partially or entirely in place of waste coal) is therefore eliminated as a BACT option.

As stated earlier in this Statement of Basis, Deseret Power has requested operational

flexibility, in the EPA permit, to blend ROM coal in with the waste coal, at up to a 50/50 ratio by

weight, as needed at any time, such as in the event of operational difficulties arising from use of

waste coal as sole fuel, or in the event of unexpected difficulties in meeting BACT emission

limits. Although EPA finds that use of ROM coal in place of waste coal would be costprohibitive for BACT, and Deseret Power is not proposing to blend ROM coal with waste coal

except for the contingency situations described immediately above, EPA believes that the BACT

emission limits in the permit are sufficiently stringent to represent BACT at up to a 50/50 blend

ratio.
29

2. Alternative coal from other mines. The following analysis supplements

the analysis of alternative coals in the draft Statement of Basis, to explain more fully, in terms of

cost per ton of additional pollutant removed from the atmosphere, why use of coal from any mine

in the region other than the Deserado mine, rather than use of waste coal from the Deserado

mine, would be cost-prohibitive as a BACT option. In presenting this analysis, EPA is not taking

a position on whether the use of a coal supply other than the one proposed by the applicant must

be evaluated in the BACT analysis for the WCFU or similarly situated facilities.

After EPA issued the draft permit for the WCFU, the EPA Environmental Appeals

Board issued its opinion in In re: Prairie State Generating Company, PSD Appeal No. 05-05

(Aug. 24, 2006). This opinion established that there may be circumstances under which the

permitting authority has the discretion not to list alternative coal supplies as an option at Step 1

of the BACT analysis, because such an option could fundamentally redefine the source.

However, we need not address whether this permit presents a similar circumstance, since

the draft Statement of Basis included the use of a cleaner coal as an option and evaluated the

economic impact of requiring the applicant to use exclusively mined coal from the Deserado

mine rather than waste coal, or alternatively, exclusively mined coal from other mines rather than

waste coal. (Draft Statement of Basis at pages 25-29.) Since EPA already started down this path

of looking at other coal supplies for this permitted project, EPA has supplemented its analysis, in

response to public comments on the draft Statement of Basis, to further illustrate why it is

appropriate to eliminate this option for this permit.

Similar to the approach used above for evaluating use of alternative coal at the Deserado

mine as a BACT option, the first step in evaluating use of coal from an alternative mine as a

BACT option is to determine what a coal switch would cost, per ton of coal delivered. EPA

asked Deseret Power to provide an estimate of what the total cost would be, per ton of coal

delivered, to have coal supplied to the WCFU from mines in the region other than the Deserado

mine. EPA asked that the estimate be for the least total cost scenario of the various other mines

that could potentially supply coal. EPA further asked for a breakdown of mine-mouth (“FreeOn-Board”) cost plus transportation cost. (Ref: November 14, 2006 e-mail from Mike Owens,

EPA Region 8, to Ed Thatcher, Deseret Power, included in the Administrative Record for

issuance of the final Deseret WCFU permit.)

Deseret Power responded that its letter to EPA dated May 10, 2005, at page 5, provided a

cost estimate for coal purchased on the open market and delivered to the WCFU unit. The

estimated cost for the coal at that time was $40 to $45 per ton delivered, which included the

estimated delivery charge of $15 per ton. The FOB mine cost for the coal was estimated to be

$25 to $30 per ton at that time. According to the November 13, 2006 issue of Coal Outlook

(copy attached to Deseret Power’s November 15, 2006 e-mail cited below), the FOB mine cost

for coal in Utah has increased to $37.75 per ton for current purchases of coal.

As mentioned in the draft Statement of Basis, the Bonanza plant is approximately 75

miles from the nearest rail transportation and approximately 100 miles by truck from the nearest
30

alternative source of coal. The cost to construct a rail line to connect to the interstate rail system

has been estimated by Deseret Power to exceed $300 million. (EPA has eliminated this option as

too expensive.) The cost to truck the coal from the nearest alternative coal source (i.e., other than

the Deserado mine) was estimated by Deseret Power to be at least $15/ton. (Ref: Sept. 13, 2005

letter from Deseret Power to EPA, page 3, footnote 1, included in the Administrative Record for

issuance of the draft Deseret WCFU permit.)

In more recent correspondence to EPA, Deseret Power stated that it believes the delivery

cost to haul the coal from the nearest alternative mines to the Bonanza plant site would still be

about $15 per ton. Therefore, the current delivered cost would be $37.75 plus $15.00, or about

$52.75 per ton delivered. (Ref: November 15, 2006 e-mail from Ed Thatcher, Deseret Power, to

Mike Owens, EPA Region 8, included in the Administrative Record for issuance of the final

Deseret WCFU permit.) Being the cost from the nearest alternative mines, this ‘cheapest

delivered’ cost is a conservative estimate, i.e., yielding the lowest calculated BACT cost to

switch to coal from a mine other than the Deserado mine.

The next step in the analysis is to determine the annual cost of switching from Deserado

waste coal to alternative coal from another mine. This requires a determination of how much

alternative coal is necessary to achieve the equivalent annual boiler heat output as combustion of

1.2 million tons of waste coal per year, which is Deseret Power’s projected waste coal usage rate.

To make this determination, it is necessary to know the estimated heat content of the alternative

coal. The CFB boiler project cited by commenters, Sevier Power Company, would use coal with

an estimated heat content range of 10,200 to 12,000 Btu/lb, with average heat content of 11,390

Btu/lb. (Ref: “New Source Plan Review” by Utah Division of Air Quality, dated December 23,

2003, for the Sevier Power Company project, page 13, Table I-2, available online at

http://www.airquality.utah.gov/Permits/PmtPowerPlants.htm.)

Rather than rely just on the Sevier project cited by commenters for an estimate of the

heat content of available coals in the region, EPA also examined a recent Utah Geological

Survey (UGS) report, which lists heat content of coal at Utah mines ranging from 11,243 Btu/lb

to 13,052 Btu/lb. (Ref: “Annual Review and Forecast of Utah Coal, Production and Distribution

- 2005,” published August 2006 by Utah Geological Survey, Open-File Report 481, Table A8:

“Average Coal Quality at Utah Mines, 2005.” Report available online at

http://ugs.utah.gov/online/ofr.ofr-481.pdf.) For the sake of this analysis, EPA will use the upper

end of this range (13,052 Btu/lb) as a conservative assumption, i.e., yielding the lowest

calculated BACT cost to switch to alternative coal.

Since Deseret Power’s waste coal has an average heat content of about 4,000 Btu/lb, EPA

calculates that it would require about 367,760 tons per year of alternative coal rated at 13,052

Btu/lb heat content, to achieve the equivalent annual WCFU boiler heat output as combustion of

1.2 million tons per year of waste coal. The coal purchase cost of the alternative coal would

therefore be:

$52.75/ton x 367,760 tons/year = $19,400,000/year.
31

EPA stated in the draft Statement of Basis that the cost of waste coal would be about $5 per ton

delivered. The annual cost of using the waste coal would be:

$5/ton x 1,200,000 tons/year = $6,000,000/year.

The incremental cost to use entirely alternative coal from another mine in the region, rather than

waste coal from the Deserado mine, would therefore be the difference in cost of the two coals,

which is $13,400,000/year.

The next step in the analysis is to determine the potential annual emission reductions that

could be achieved by switching from waste coal to alternative coal from another mine. In the

draft Statement of Basis, EPA presented its calculation of the reductions that could be achieved

for each PSD pollutant, if emissions are reduced from the proposed WCFU permit allowables

down to the lowest BACT determination EPA is aware of anywhere for a CFB boiler project

(including the Sevier Power Company project cited by commenters). For condensible PM, EPA

has since revised its estimate of lowest achievable emission rate down to 0.005 lb/MMBtu, to

correspond to the condensible portion of the BACT emission limit for total PM/PM10 in the Utah

permit for the Sevier Power Company project.

Potential Emission Reductions Due to a Switch

From Waste Coal to Alternative Coal from Another Mine

For Deseret Power’s Proposed WCFU

Lowest BACT

Proposed Emission Determination Anywhere Equivalent

Limit for WCFU for a CFB Boiler Project Annual Reduction

Pollutant (lb/MMBtu) (lb/MMBtu) (tons/year)

NOx 0.080 0.07 63

SO2 0.040 0.022 114

CO 0.15 0.10 316

H2SO4 0.0035 0.0024 7

Filterable PM 0.012 0.010 13

Condensible PM 0.019 0.005 88

FOOTNOTE #1: The Sevier Power Company project cited by commenters is permitted at 0.1 lb/MMBtu for NOx,

0.022 lb/MMBtu for SO2, 0.115 lb/MMBtu for CO, 0.0024 lb/MMBtu for H2SO4, and 0.015 lb/MMBtu. “Lowest

BACT Determination” values listed above are at least as low.

FOOTNOTE #2: The proposed WCFU permit has no separate BACT emission limit for condensibles. The figure of

0.019 lb/MMBtu above is an estimate based on best information available to EPA and the proposed emission

controls for the WCFU, as described in the draft Statement of Basis.
32

EPA believes it is unlikely that lower emissions than listed above could be achieved on

any coal in the Region. As explained in Footnote #1 above, the figures listed as “Lowest BACT

Determination Anywhere for a CFB Boiler Project” are at least as low as the BACT

determination for each pollutant at the Sevier project cited by commenters. Further, based on

“Average Coal Quality at Utah Mines, 2005,” listed in the afore-mentioned UGS report, it

appears to EPA that the proposed coal for the Sevier project is at least as clean, in terms of ash

content and sulfur content, as any other coals in the region. The lowest ash content of the coals

listed in Table A8 of the UGS report is 8.5%. The ash content of the proposed coal for the Sevier

project is lower, at 8.3%. The lowest sulfur content of the coals listed in Table A8 of the UGS

report is 0.4%. The sulfur content of the proposed coal for the Sevier project is at least as low, at

0.40%. (Ref: Table A8 of the aforementioned UGS report; Table I-2 of the aforementioned

“New Source Plan Review” for the Sevier project.)

The calculated cost and corresponding emission reductions described above lead to the

following cost estimates, in dollars per ton of additional pollutant removed annually, to use

alternative coal from another mine in the region, rather than waste coal from the Deserado mine:

Annualized Cost of Potential Emission Reductions

Due to a Switch from Waste Coal at the Deserado Mine

to Alternative Coal from Another Mine

for Deseret Power’s Proposed WCFU

Potential Emission Reduction

Pollutant (Alternative Coal versus Waste Coal) Cost ($/ton)

NOx 63 tons/yr $ 212,698/ton

SO2 114 tons/yr $ 117,543/ton

CO 316 tons/yr $ 42,405/ton

H2SO4 7 tons/yr $1,914,285/ton

Filterable PM 13 tons/yr $1,030,769/ton

Condensible PM 88 tons/yr $ 152,272/ton

All (sum) 651 tons/yr $ 20,583/ton

As mentioned in the draft Statement of Basis’s discussion of alternative coal from other

mines, there would also be substantial energy and environmental costs associated with obtaining

coal from a mine other than the Deserado mine, due to the large number of truck trips to deliver

the coal (more than 20 per day, assuming 50 tons payload per truck), at 200 miles round trip per

load. The substantial energy expenditure in terms of diesel fuel, the amount of pollution from

truck exhaust, and the increased traffic hazard on public highways, all make this option even

more cost-prohibitive.

Based on the analysis above, EPA concludes that use of alternative coal from any other

mine in the region, rather than waste coal from the Deserado mine, would be cost-prohibitive as a
33

BACT option for the proposed WCFU, even if reductions of all pollutants are summed together

and then the annualized cost in dollars-per-ton for emission reduction is calculated on that basis.

(As shown above, summing the pollutants yields $20,583/ton, which is a lower dollar-per-ton

BACT cost than looking at any one pollutant individually.)

The same annualized dollar-per-ton costs would be incurred if there was only a partial

switch to alternative coal from another mine (i.e., coal blending). This is because a partial switch

yields only partial emission reductions.

Regarding comparison to the cost of BACT that other similar sources have to bear (which

EPA believes is best evaluated in terms of dollars per ton of additional pollutant removed, not

simply in terms of what other sources pay for their coal as commenters on the draft WCFU

permit have suggested), EPA is not aware of any BACT determination for a CFB boiler project

anywhere in the U.S. where incremental cost effectiveness as high as $20,583/ton (the EPAcalculated economic cost for using coal from an alternative mine rather than waste coal from the

Deserado mine), or as high as $20,241/ton (the EPA-calculated economic cost for using ROM

coal from the Deserado mine rather than waste coal from the Deserado mine) has been

considered reasonable for BACT for any pollutants, regardless of the type of BACT option being

considered.

Although EPA considers the economic, energy and environmental costs associated with

use of alternative coal for Deseret Power’s project to be clearly excessive for BACT, EPA has

nevertheless looked at some recent BACT determinations by other permitting authorities for

similar projects, for purposes of comparison. EPA found the following:

1) In a PSD permit action in mid 2006 for Longleaf Energy Associates LLC, Longleaf

Energy Station project, Georgia indicated that incremental cost effectiveness of

$8,964/ton, comparing dry scrubbing to wet scrubbing for SO2 control at a pulverized

coal fired electric utility boiler, was excessive for BACT. Incremental and average cost

effectiveness of the selected BACT option (dry scrubbing) was listed as $724/ton.

(Ref: Georgia’s Preliminary Determination for SIP Permit Application #15846, page 62,

dated July 2006, available online at:

http://www.air.dnr.state.ga.us/airpermit/psd/dockets/longleaf/permitdocs/0990030pd.pdf.

2) In a PSD permit action in early 2007 for Southern Montana Electric Generation and

Transmission Cooperative’s CFB boiler project (Highwood Generating Station), Montana

indicated that a “cost effective value” of $27,365/ton for SO2 control, for a control option

employing a combination of limestone injection, low-sulfur coal and wet flue gas

desulfurization (FGD), was excessive for BACT. Montana also indicated that a “cost

effective value” of $7,939/ton for SO2 control, for a control option employing a

combination of limestone injection, low-sulfur coal and dry FGD, was excessive for

BACT.
34

The selected BACT option for SO2 control, with a “cost effective value” of $4,054/ton,

employed a combination of limestone injection, low-sulfur coal, and hydrated ash

reinjection. Montana did not indicate whether “cost effective value” means incremental

cost effectiveness or total cost effectiveness.

(Ref: Montana’s “Permit Analysis” for Air Quality Permit #3423-00, page 23, dated May

30, 2007, obtained from the Montana Department of Environmental Quality Air

Resources Management Bureau, Helena, Montana.)

3) In a PSD permit action in early 2005 for Rocky Mountain Power Inc.’s Hardin project,

Montana indicated that incremental cost effectiveness of $23,855/ton, comparing dry

FGD/spray dry absorber to wet FGD for SO2 control, at a pulverized coal fired electric

utility boiler, was excessive for BACT. Average cost effectiveness of wet FGD was

listed as $1,395/ton. Average cost effectiveness of the selected BACT option (dry

FGD/spray dry absorber) was listed as $918/ton.

(Ref: Montana’s Permit Analysis for Hardin project, Permit #3185-02, pages 15 and 17,

dated May 16, 2005, obtained from Montana Air Resources Management Bureau, in the

Montana Department of Environmental Quality.)

4) In a PSD permit action in late 2006 for Cargill’s Blair corn milling and ethanol

production plant, Nebraska indicated that incremental cost effectiveness of $5,900/ton,

comparing limestone injection alone to limestone injection plus dry FGD, for SO2 control

at a CFB boiler, was excessive for BACT.

(Ref: Nebraska permit action CP06-0008, page 12 of Fact Sheet, dated September 8,

2006, available online at

http://www.epa.gov/region07/programs/artd/air/nsr/archives/2006/finalpermits/

cargill_blair_final_psd_permit.pdf.)

5) In a PSD permit action in late 2006 for ADM’s Columbus corn milling and ethanol

production plant, Nebraska indicated that incremental cost effectiveness of $5,600/ton for

NOx control (comparing Selective Non-Catalytic Reduction (SNCR) at 0.07 lb/MMBtu to

SNCR at below 0.07), and incremental cost effectiveness of $6,700/ton for

SO2/H2SO4/HF control (comparing limestone injection to “additional” limestone

injection) at a CFB boiler, were excessive for BACT. Nebraska listed incremental costeffectiveness of $2,174 for the selected BACT option for NOx control (SNCR at 0.07

lb/MMBtu). Nebraska also listed average cost-effectiveness of $5,200/ton for the

selected BACT option for VOC control at the CFB boiler (wet scrubbing/packed tower),

(Ref: Nebraska permit action CPM02-0006, page 14 of Appendix B of Fact Sheet; pages

8, 9, 19 and 20 of Appendix D of Fact Sheet, dated August 4.2006, available online at:

http://www.epa.gov/region07/programs/artd/air/nsr/archives/2006/finalpermits/

adm_columbus_final_psd_permit.pdf.)
35

6) In a PSD permit in early 2005 for Montana-Dakota Utilities/Westmoreland Power,

Gascoyne Generating Station project, North Dakota indicated that incremental cost

effectiveness of $14,339/ton, comparing Selective Catalytic Reduction (SCR) at 0.04

lb/MMBtu to SNCR at 0.09 lb/MMBtu, for NOx control at a CFB boiler, was excessive

for BACT. Average cost effectiveness of SCR was listed as $7,545/ton. Average and

incremental cost effectiveness of the selected BACT option (SNCR) was listed as

$2,926/ton.

(Ref: North Dakota’s Permit Application Analysis for Gascoyne Project, pages 65 and

68, dated March 2005, obtained from the North Dakota Department of Health,

Environmental Health Section, Air Quality Division, Bismarck, ND.)

7) In a PSD permit action in early 2004 for Red Trail Energy’s Richardton, ND, ethanol

production plant, North Dakota listed incremental cost effectiveness of $10,252/ton,

comparing wet FGD plus limestone injection to dry FGD (spray dryer absorber) plus

limestone injection, for SO2 control at a CFB boiler. Average cost effectiveness of wet

FGD plus limestone injection was listed as $1,041/ton. Average cost effectiveness of dry

FGD plus limestone injection was listed as $527/ton. North Dakota rejected wet FGD

and determined that BACT is represented by dry FGD plus limestone injection.

(Ref: North Dakota’s Permit Application Analysis for Red Trail Energy project, pages 38

and 40, dated May 2004, obtained from the North Dakota Department of Health,

Environmental Health Section, Air Quality Division, Bismarck, ND.)

8) In a PSD permit action in early 2005 for River Hill Power Company’s CFB boiler

project, Pennsylvania indicated that incremental cost effectiveness of $15,975/ton,

comparing use of the waste coal proposed by the permit applicant to use of the nearest

alternative source of coal with lower sulfur content, for SO2 control at the CFB boiler,

was excessive for BACT.

Pennsylvania also indicated that all SO2 BACT options involving wet FGD systems

“were economically infeasible at an incremental dollar per ton value greater than $5,000

per ton of SO2 removed.”

Pennsylvania concluded that use of a spray dryer absorber or flash dryer absorber (i.e., dry

FGD) was “economically feasible for the control of SO2 at an incremental cost of

$1,511.01 per ton of SO2 removed.”

(Ref: Pennsylvania’s “Plan Approval Application Review Memo, Plan Approval

Application #17-00055A,” pages 10-11, dated May 2, 2005, obtained from the

Commonwealth of Pennsylvania, Department of Environmental Protection, Northcentral

Region, Air Quality Program.)
36

9) In a PSD permit action in early 2005 for Wellington Development’s Greene Energy

Resource Recovery Project, Pennsylvania indicated that incremental cost effectiveness of

at least $20,000/ton, comparing use of the waste coal proposed by the applicant to precombustion cleaning of the waste coal (excluding additional coal disposal costs after

cleaning of the waste coal), for SO2 control at the CFB boiler, was excessive for BACT.

Pennsylvania also indicated that overall cost effectiveness of $5,764/ton, for limestone

injection plus wet FGD for SO2 control at the CFB boiler, was excessive for BACT.

(Ref: Pennsylvania’s “Comment and Response Document,” Air Quality File PA-30-

00150A, page 6, dated June 21, 2005; Table 5-4 of PSD Permit Application, prepared by

ENSR International, August 2004, page 5-29. Both documents were obtained from the

Commonwealth of Pennsylvania, Department of Environmental Protection, Southwest

Regional Office, Air Quality Program.)

10) In a PSD permit action in early 2004 for Intermountain Power’s Unit 3 project, Utah

indicated that incremental cost effectiveness of about $14,000/ton to $16,350/ton,

comparing different types of baghouse fabric filter bags (Ryton-type bags versus specialty

coated bags) for PM/PM10 control at a pulverized coal fired electric utility boiler, was

excessive for BACT. Average cost effectiveness of the selected BACT option for PM10

control (a baghouse with Ryton-type bags) was $31/ton.

(Ref: Utah’s Modified Source Plan Review for IPP3 project, pages 132-133, dated March

22, 2004, available online at:

http://www.airquality.utah.gov/Permits/PmtPowerPlants.htm.)

11) In a PSD permit action in early 2007 for Basin Electric’s Dry Fork Station project (a

pulverized coal-fired electric utility boiler),Wyoming indicated that incremental cost

effectiveness of $23,755/ton for NOx control (comparing Selective Catalytic Reduction

(SCR) at 0.043 lb/MMBtu to SCR at 0.040 lb/MMBtu) was excessive for BACT.

Average cost effectiveness for SCR at 0.040 lb/MMBtu was listed as $2,004/ton.

Average cost effectiveness for SCR at 0.043 lb/MMBtu was listed at $1,751/ton.

Although Wyoming determined that incremental cost effectiveness of $10,303/ton was

reasonable for SCR at 0.043 lb/MMBtu, for other reasons described by Wyoming the

selected BACT option for NOx control was SCR at 0.05 lb/MMBtu, with incremental cost

effectiveness of $3,512/ton and average cost effectiveness of $1,511/ton.

Wyoming also indicated that incremental cost effectiveness of $15,299/ton for SO2

control (comparing dry FGD/spray dry absorber at 0.073 lb/MMBtu to wet FGD at 0.054

lb/MMBtu), was excessive for BACT. Average cost effectiveness of wet FGD at 0.054

lb/MMBtu was listed as $1,595/ton.
37

Although Wyoming determined that incremental cost effectiveness of $9,296/ton was

reasonable for a spray dry absorber at 0.043 lb/MMBtu, for other reasons described by

Wyoming the selected BACT option for SO2 control was a spray dry absorber at 0.08

lb/MMBtu, with average cost effectiveness of $1,159/ton; no incremental cost

effectiveness listed by Wyoming for this BACT option..

(Ref: Wyoming’s Permit Application Analysis for the Dry Fork project, NSR-AP-3546,

pages 6, 7, 8, 10 and 11, dated February 5, 2007, obtained from Wyoming Air Quality

Division, Cheyenne, WY.)

12) In a PSD permit action in early 2002 for Black Hills Power & Light’s WYGEN2

project, Wyoming indicated that incremental cost effectiveness of $7,742/ton, comparing

low-NOx burners plus SCR at 0.06 lb/MMBtu to low-NOx burners plus SCR at 0.08

lb/MMBtu, for NOx control at a pulverized coal fired electric utility boiler, was

reasonable for BACT. However, for other reasons described by Wyoming, the selected

BACT option was low-NOx burners plus SCR at 0.07 lb/MMBtu, with “total” (i.e.,

average) cost effectiveness somewhere between $4,067/ton (the average cost

effectiveness to achieve 0.08 lb/MMBtu) and $4,156/ton (the average cost effectiveness

to achieve 0.06 lb/MMBtu).

(Ref: Wyoming’s Permit Application Analysis for the WYGEN2 project, NSR-AP-92,

page 7, dated April 24, 2002, obtained from Wyoming Air Quality Division, Cheyenne,

WY.)

13) In a PSD permit action in late 2006 for Black Hills Power & Light’s WYGEN3

project, Wyoming indicated that incremental cost effectiveness of $14,609/ton,

comparing a baghouse with fiberglass or polyphenylene sulfide filter bags (listed as

capable of achieving 0.012 lb/MMBtu) to a baghouse with specialty filter bags such as

Teflon (listed as capable of achieving 0.011 to 0.010 lb/MMBtu), for PM/PM10 control at

a pulverized coal fired electric utility boiler, was excessive for BACT.

Average cost effectiveness of the selected BACT option (a baghouse with fiberglass or

polyphenylene sulfide filter bags) was listed as $130/ton. Average cost effectiveness of a

baghouse with specialty filter bags was listed as $134/ton.

(Ref: Wyoming’s Permit Application Analysis for the WYGEN3 project, NSR-AP-3934,

pages 10 and 11, dated October 9, 2006, obtained from Wyoming Air Quality Division,

Cheyenne, WY.)

The pages cited above, for each of the 13 examples, are included in the Administrative

Record for issuance of the final Deseret WCFU permit.
38

Although this information is only on comparative economic costs of BACT options, not

on comparative energy and environmental costs (which were generally not quantified by the

permitting authorities), the information does seem to indicate that similar sources have typically

not been expected to bear BACT costs, on an incremental cost effectiveness basis, as high as the

incremental cost effectiveness for using alternative sources of coal for Deseret Power’s s project,

in lieu of waste coal ($20,583/ton for alternative coal from another mine and $20,241/ton for

alternative coal from the Deserado mine).

Regarding the Sevier Power project cited by commenters on the draft WCFU permit

package, the State of Utah presented no data in its “New Source Plan Review” on cost of BACT

for any PSD pollutant, and none of the BACT options considered by Utah for that project

involved alternative sources of coal. Further, no information was provided on cost of coal for the

Sevier project.

Alternative coal for the WCFU project is therefore eliminated as a BACT option, in terms

of environmental, economic and energy costs, at Step 4 of the BACT analysis.

3. Proposed fuel restrictions at CFB boiler to reflect basis for BACT analysis.

EPA proposes to include the following CFB boiler fuel restrictions in the permit, to reflect the

basis for the BACT analysis:

a. Fuel during startup: The Permittee shall not combust, in the

CFB boiler, any startup fuel other than diesel fuel (#2 grade fuel oil or better) or natural

gas. The diesel fuel shall have a sulfur content of no more than 0.05 percent (500 parts per

million) by weight.

b. Fuel during emergencies when waste coal is not available:

During any emergency that prevents waste coal from being delivered from the Deserado

mine and placed into the WCFU, the Permittee is permitted to combust, in the CFB boiler,

any other coal originating from the Deserado mine, including run-of-mine coal or washed

coal. For purposes of this permit condition, an emergency is defined as any situation

arising from sudden and reasonably unforeseeable events beyond the control of the

Permittee. Depletion of the waste coal stockpile at the Deserado mine is not an emergency.

c. Fuel other than during startup and emergencies: Other than

during startup or emergencies as specified in this permit, the Permittee is permitted to

combust, in the CFB boiler, coal from the Deserado mine consisting of either waste coal

alone, or else a blend of waste coal and run-of-mine coal in any ratio yielding up to 6,500

Btu/lb heat content on a 30-day rolling average.
39

E. Supercritical Boiler Technology for BACT.

EPA has evaluated a supercritical CFB boiler as a BACT option and has determined that

since there are no known supercritical pressure turbines available in the size needed for the

WCFU project, this option should be eliminated at step two of the top-down BACT analysis as

technically infeasible, because it is not available and applicable for the WCFU project.

At the first step of the top-down BACT analysis, all demonstrated and potentially

applicable control technology alternatives must be identified. This must include a survey of

production processes or innovative technologies that have a practical potential for application to

reduce relevant emissions at the source type being evaluated. At the second step, technically

infeasible options are eliminated. A technology is feasible if either it is demonstrated, i.e.

installed and operated successfully at a similar facility, or it is both “available” and “applicable.”

A technology is considered “available” if it can be obtained by the applicant through commercial

channels. An available technology is “applicable” if it can reasonably be installed and operated

on the source type under consideration. If a technology is not demonstrated, or is found to be

unavailable or not applicable, that technology will be eliminated from BACT consideration as

technically infeasible.

As described by Babcock & Wilcox, a major boiler supplier, a supercritical boiler

(regardless of combustion process, i.e. PC-fired, CFB, gas-fired, etc.) is designed to operate with

the working medium, i.e. water, at a pressure above the critical point (3200 psia). At this

pressure the medium cannot be separated to liquid and steam thus natural circulation is

impossible, and the fluid is pumped through all heat absorbing tubes (called “Once-Through” in

the boiler industry, versus natural circulation that the sub-critical pressure WCFU boiler is based

on). (Ref: e-mails and attachments from Ed Thatcher, Deseret Power, to Mike Owens, EPA

Region 8, November 6, 2006.)

The use of supercritical pressure in a power plant affects the design of all components

within the plant cycle, boiler, turbine, pumps, etc. The steam cycle is based on available turbine

designs. The boiler and other equipment are designed to meet the steam cycle defined by the

turbine. This technology is being deployed currently at pulverized coal utility boilers. EPA

therefore concludes that it is appropriate to consider supercritical technology, as a technology

transfer control option under step one of the top-down BACT analysis.

However, according to Babcock & Wilcox and Foster-Wheeler, two major boiler

suppliers, supercritical pressure steam turbines are not available in the size needed for the WCFU

project. The smallest supercritical pressure turbine currently known to be available is three to

four times larger than is needed for the WCFU project, which will operate at approximately 1500

psia and is thus based on a sub-critical steam cycle. (Ref: e-mails and attachments from Ed

Thatcher, Deseret Power, to Mike Owens, EPA Region 8, November 6, 2006 and November 13,

2006.)
40

In addition, the following information was provided by Siemens Power Systems to

Deseret Power (forwarded to EPA Region 8 via e-mail from Deseret Power on November 13,

2006):

"To our knowledge, no manufacturer offers supercritical steam turbines in 110-120 MW

range. The reason is that you would be unlikely to see any significant performance

improvements for units that small. Key reasons are as follows:

1. When you go to supercritical steam conditions the specific volume of the steam is

reduced because of the higher pressure. That means the blades in the HP section have to

be shorter. A major source of inefficiency in steam turbines is due to "flow disruptions"

at the top and bottom of the blade where the moving flow meets the stationary rotor or

casing. As the blades get shorter the impact of this "end wall" condition increases which

in turn increases the flow losses.

2. The supercritical conditions require a once-through boiler which requires a more

powerful feed pump drive (higher pressures). That decreases plant efficiency and if you

can't make that difference up with improved cycle performance, supercritical makes no

sense.

We generally don't see units less than about 500 MW being built as supercritical because

the performance improvement isn't significant and the unit is more expensive than

subcritical.”

A Western Governors Association report, cited in public comments on the draft WCFU

permit, states that “no supercritical CFB combustion units have been demonstrated on a

commercial scale.” EPA is aware of only one supercritical CFB boiler that has been proposed,

designed and/or constructed anywhere in the world. As of January 11, 2006, design of that unit

had not yet been completed. The unit is being designed for Poland's Poludniowy Koncern

Energetyczny (PKE) for installation at its power plant at Lagisza in southern Poland. The

proposed unit will have an output of 460 MW (four times larger than Deseret Power’s proposed

WCFU) and is being designed to fire bituminous coal. It is currently scheduled to begin

operation in 2009. The unit is being designed to fire bituminous coal. (Ref: Foster-Wheeler

press release, January 11, 2006.)

Supercritical CFB boilers, while potentially applicable as a BACT option, are not a

“demonstrated” technology under the BACT analysis, as the only such boiler EPA is aware of

(the PKE boiler planned in Poland) has not been installed and operated successfully. Further, the

technology is not “available” under the BACT analysis since, as explained above, it is not

commercially available for CFB boilers, and supercritical pressure steam turbines are not

available in the size needed for the WCFU project. Therefore, this technology is eliminated at

step two of the top-down BACT analysis because it is undemonstrated and is not available.
41

F. IGCC not Within Scope of BACT Analysis for this Project.

Consideration of Integrated Gasification Combined Cycle (IGCC) technology, as an

alternative to a waste-coal-fired CFB boiler, has not been included in Step 1 of the BACT

analyses below, since IGCC would be redefining the source. In preparing the draft permit, EPA

did consider whether IGCC is a BACT option, but concluded it is not because it would

fundamentally change the basic design of the proposed source. Prior to reaching this conclusion,

EPA did, however, request detailed information from Deseret Power regarding whether or not

IGCC would be technically feasible using waste coal from the Deserado mine. Correspondence

between EPA and Deseret Power on this topic has been included in the Administrative Record

for this permit action.
42

G. BACT for NOx Emissions from CFB Boiler.

Emissions of NOx from coal combustion are formed from three chemical mechanisms:

(1) fuel NOx (resulting from oxidation of chemically bound nitrogen in the fuel),

(2) thermal NOx (resulting from oxidation of molecular nitrogen in the combustion

air), and

(3) prompt NOx (resulting from reaction between molecular nitrogen and hydrocarbon

radicals).

Most of the emissions from coal combustion are from fuel NOx, with lesser amounts from

thermal NOx and relatively negligible amounts from prompt NOx.

Fuel NOx formation depends on many complex chemical characteristics in the coal and

boiler. Due to the chemical complexities and large number of factors affecting fuel NOx

formation, it is difficult to accurately quantify the amount of expected fuel NOx formation for a

particular facility. The chemical reactions that take place depend on numerous factors, including

fuel-bound nitrogen content, carbon to volatile matter ratio, oxygen content, calcium content,

sulfur, and moisture content. While a survey of the literature does suggest that the percentage of

fuel-bound nitrogen converted to NOx decreases as the total nitrogen in the fuel increases

(probably due to the percentage of volatile fuel-bound nitrogen in the total amount of fuel-bound

nitrogen), the literature also suggests that, in general, there will be an increase in NOx emissions

with increases in fuel-bound nitrogen.

Thermal NOx formation for coal-fired utilities is often controlled through combustion

techniques. Deseret Power has proposed CFB boiler technology, which inherently reduces the

amount of thermal NOx formation through low combustion temperatures and staged combustion

capabilities. Deseret Power has also proposed Selective Non-Catalytic Reduction (ammonia

injection) as an add-on control.

Clean fuels (i.e., alternative coal, either from the Deserado mine or another mine) is also a

possible option for BACT, but has already been eliminated as cost-prohibitive for BACT, for all

pollutants at this project. This was explained earlier in this Statement of Basis.

1. Step 1: Identify Potential Control Technologies.

Control technologies with practical potential for application to coal-fired CFB boilers for

NOx emission control are listed below. This list is based on literature survey (including AP-42

and a November 1999 EPA Technical Bulletin on NOx Control, discussed further below), as well

as review of recent BACT determinations for CFB utility boilers. As a result of this review, EPA

considers the following technologies to be potential control options:
43

a. Selective Catalytic Reduction (SCR)

b. Selective Non-Catalytic Reduction (SNCR)

c. Non-thermal Plasma Reactor

d. Carbon Injection in Combustion Chamber

Recent permit applications for other CFB boiler projects (e.g., permit application by

Great Northern Power Development for the South Heart Power Project in North Dakota) identify

additional NOx control technologies as possible options. These are: staged combustion, lowNOx burners, overfire air, and flue gas recirculation. However, EPA does not consider these to

be potential control options for a CFB boiler, for the following reasons:

 Staged combustion – In staging, a portion of the total air required to complete

combustion is withheld from the initial combustion stage. The balance of air

required for complete combustion is mixed with the incomplete products of

combustion only after the oxygen content of the first-stage air is consumed.

Staged combustion design of the boiler reduces air-rich combustion and NOx

formation. This is an inherent part of CFB process design, rather than a “control

option.”

 Low-NOx burners (LNBs) and overfire air (OFA) – LNBs restrict NOx formation

by controlling the stoichiometric and temperature profiles of the combustion

flame in each burner flame envelope. OFA involves the staged injection of air

into the firing chamber. LNB and OFA are widely used in PC-fired boilers.

However, CFB boilers do not use burners during normal operation, as combustion

takes place within the fluidized bed. Therefore, these technologies are not

applicable to a CFB boiler.

 Flue gas recirculation (FGR) – FGR is a flame-quenching technique that involves

recirculating a portion of the flue gas from the economizer or air heater outlet and

returning it to the furnace through the burner or windbox. The primary effect of

FGR is to reduce the peak flame temperature through adsorption of the

combustion heat by the relatively inert flue gas and to reduce the O2 concentration

in the combustion zone. Because FGR reduces NOx formation by reducing peak

flame temperature, it is ineffective on combustion sources such as CFBs that

operate at low combustion temperatures.

Table 1.1-2 of AP-42 (Sept. 1998 edition) lists several types of combustion modifications

as potential additional NOx control options for coal-fired boilers; however, Table 1.1-2 does not

indicate that any of these options have practical potential for application to CFB boilers, nor is

EPA aware of any reason why any of these options would have practical potential for application

to CFB boilers. Generally, combustion design of a CFB boiler controls thermal NOx formation

to the same degree, if not to a greater degree, than combustion controls for the other types of
44

boilers listed in Table 1.1-2 of AP-42.

Options for NOx control at coal-fired CFB boilers are also listed in an EPA publication

titled, “Technical Bulletin: Nitrogen Oxides (NOx), Why and How They are Controlled,” EPA456/F-99-006R, November 1999. The Technical Bulletin mentions the following control

techniques:

 Natural Gas Reburn

 Low Excess Air

 Reduced Air Preheat

 Reducing Residence Time

 Fuel Reburning

 Non-Thermal Plasma Reactor

 Sorbent Injection

Natural gas reburn, low excess air, reduced air preheat, reducing residence time, and fuel

reburning all act on thermal NOx. The combustion temperature of a CFB boiler, by nature of its

design, is much lower than that of a pulverized coal (PC) boiler (1,500

o

F versus 3,000

o

F). (Ref:

Western Governors Association Technology Working Group Report, undated, page 10.) This

lower combustion temperature results in virtually no thermally-generated NOx. Because of this,

control techniques designed to reduce NOx emissions by reducing the combustion temperature,

and thus reducing thermal NOx, were not considered to have practical potential for application to

coal-fired CFB boilers and thus were eliminated as control options at Step 1 of the BACT

analysis. This is explained in more detail below.

Two of the control techniques listed in the Technical Bulletin are already proposed to be

included for the WCFU: Low Excess Air is an inherent part of the CFB boiler design, and

Sorbent Injection (a.k.a. Selective Non-Catalytic Reduction, discussed further below) is the

chosen BACT control option. Non-Thermal Plasma Reactor is not known to be commercially

available for CFB units and is therefore not considered to be a technically feasible control option.

Below are descriptions from the Technical Bulletin of the individual control techniques,

along with a more detailed discussion of each technique’s potential (or lack thereof) for control

of NOx emissions at the proposed WCFU.

Natural Gas Reburn – This is considered by EPA to be the same method as generic “Fuel

Reburning.” The principles are the same whether the additional fuel reburned is natural gas, fuel

oil, or coal. See “Fuel Reburning” below.

Low Excess Air – Excess air flow for combustion has been correlated to the amount of

thermal NOx generated. Limiting the net excess air flow to less than 2% can strongly limit NOx

content of flue gas at pulverized coal fired boilers. Although there are fuel-rich and fuel-lean

zones in the combustion region, the overall net excess air is limited when using this approach.
45

A certain amount of excess air is required to maintain flame stability and provide

satisfactory combustion. Limiting excess air to such a low level would also increase emissions

of carbon monoxide (CO).

Reducing the amount of excess air may be a valid way to reduce NOx emissions from an

older CFB unit with poor combustion controls. However, the unit proposed by Deseret is a new

unit with state-of-the-art combustion controls. One of the goals of those controls is to minimize

excess air to maximize boiler efficiency. If one were to consider reducing excess air further than

the design rate, it would result in increased CO emissions and disrupt the stable operation of the

unit. Further, this control technique acts primarily on thermal NOx and therefore, while it may

have substantial effect on NOx emissions at pulverized coal fired boilers, it has much less effect

on NOx emissions at combustion sources such as CFBs that operate at low combustion

temperatures.

This control technique was addressed earlier in this discussion, through reference to Table

1.1-2 of AP-42, which indicates it is does not have practical potential for application to coal-fired

CFB boilers for NOx control. It has therefore been eliminated at Step 1 of the BACT analysis.

Reduced Air Preheat – Preheating the combustion air cools the flue gases, reduces the

heat losses, and gains efficiency. However, this can raise the temperature of combustion air to a

level where NOx forms more readily. Reducing the amount of air preheat reduces the

combustion temperature and NOx formation is suppressed. However, reducing the amount by

which the incoming combustion air is preheated carries a significant efficiency penalty of up to

1% per 40

o

F. (Ref: Technical Bulletin, page 12.) This reduction in efficiency would increase

emissions of all criteria pollutants. As mentioned in the introductory discussion of thermal NOx

above, the combustion temperature of a CFB boiler, by nature of its design, is much lower than

that of a pulverized coal (PC) boiler and results in virtually no thermally-generated NOx.

Therefore, reduced air preheat is not considered to be an effective NOx control option for coalfired CFB boilers, i.e., it does not have practical potential for application to CFB boilers for NOx

control. It has therefore been eliminated as a control option at Step 1 of the BACT analysis.

Reducing Residence Time (at peak temperature through injection of steam) – This control

technique involves injection of water or steam, which causes the stoichiometry of the mixture to

be changed and adds steam to dilute calories generated by combustion. Both of these actions

cause combustion temperature to be lower. If temperature is sufficiently reduced, thermal NOx

will not be formed in as great a concentration.

In order to control NOx, steam is typically injected directly into the flame to reduce the

adiabatic flame temperature. In a CFB boiler, this is not physically possible, as combustion

occurs throughout the fluidized bed. As with reduced air preheat, injecting steam would reduce

boiler efficiency and result in increased emissions of all pollutants.
46

This control technique is addressed in the introductory discussion of thermal NOx above

and is not considered to be an effective control option for coal-fired CFB boilers, i.e., it does not

have practical potential for application to CFB boilers. It has therefore been eliminated as a

control option at Step 1 of the BACT analysis.

Fuel Reburning – This control technique consists of recirculation of cooled flue gas with

added fuel, similar to Flue Gas Recirculation (FGR) discussed on page 31 of the Statement of

Basis. With fuel reburn, calories are diluted and the primary combustion temperature can be

lowered. In other words, the peak flame temperature can be lowered through adsorption of the

combustion heat by the relatively inert flue gas. As explained in the introductory discussion of

thermal NOx above, this control technique acts on thermal NOx and is not considered to be

effective on combustion sources such as CFBs that operate at low combustion temperatures. As

such, it does not have practical potential for application to coal-fired CFB boilers for NOx

control. It has therefore been eliminated as a control option at Step 1 of the BACT analysis.

Non-Thermal Plasma Reactor – This control technique involves using methane and

hexane as reducing agents. Non-thermal plasma has been shown to remove NOx in a laboratory

setting with a reactor duct only two feet long. The reducing agents were ionized by a transient

high voltage that created a non-thermal plasma. The ionized reducing agents reacted with NOx

and achieved a 94% destruction efficiency. There are indications that even higher destruction

efficiency can be achieved. A successful commercial vendor uses ammonia as a reducing agent

to react with NOx in an electron beam generated plasma. Such a short reactor can meet available

space requirements for virtually any plant. The non-thermal plasma reactor could also be used

without reducing agent to generate ozone and use that ozone to raise the valence of nitrogen for

subsequent absorption as nitric acid.

Trinity Consultants investigated the non-thermal plasma reactor as a NOx control option

and advised Deseret Power that it is not known to be commercially available. (Ref: E-mail from

Ed Thatcher, Deseret Power, to Mike Owens, EPA Region 8, November 13, 2006.) Therefore,

while this control technique might be considered a technology transfer control option at Step 1 of

the BACT analysis, it is eliminated at Step 2 as technically infeasible (see below) because it is

not known to be commercially available for NOx control at CFB boilers.

Sorbent Injection (in combustion chamber/duct) -- This control technique involves

injection of limestone into the combustion zone. As explained further in Steps 2 through 5 of

this NOx BACT analysis, injection of ammonia (Selective Non-Catalytic Reduction) is the

chosen NOx control option for the proposed WCFU.

According to the Technical Bulletin, another version of sorbent injection “uses carbon

injected into the air flow to finish the capture of NOx. The carbon is captured in either the

baghouse or the ESP just like other sorbents.” (Ref: Technical Bulletin at page 19.) Although

carbon injection is an emerging technology used to reduce mercury emissions, Deseret Power is

not aware of it having been used anywhere to control NOx. (Ref: E-mail dated November 13,
47

2006, from Ed Thatcher of Deseret Power to Mike Owens of EPA Region 8.) EPA is similarly

not aware of carbon injection having been used anywhere to control NOx. Carbon injection for

NOx control is therefore eliminated at Step 2 of the BACT analysis as technically infeasible (see

below) because it is not known to be commercially available for that purpose.

2. Step 2: Eliminate Technically Infeasible Options

a. Selective Catalytic Reduction (SCR). SCR is a post-combustion

technology that reduces NOx by the injection of ammonia into the flue gas in the presence of a

catalyst to reduce NOx to nitrogen and water. SCR systems have been widely employed on

pulverized coal (PC)-fired boilers in the United States and have achieved emission rates below

0.05 lb/MMBtu. To date, there are no known SCR systems operating on a CFB unit.

SCR systems operate effectively in a temperature range of 650-750 degrees F. For a CFB

boiler, this temperature would exist in an area upstream of the particulate control device.

Considering the high particulate loading rate and calcium oxide (CaO) concentration of the flue

gas due to limestone injection in this section of a CFB boiler, and due to use of waste coal fuel in

the boiler with ash content as high as 60%, an SCR system installed upstream of particulate

controls would experience rapid catalyst de-activation and fouling. These technical problems

would make high-dust SCR upstream of the particulate controls technically infeasible for a CFB

boiler design.

Another possible approach is to install the SCR system downstream of the particulate

control equipment. For Deseret’s CFB boiler, the temperature downstream of the particulate

control equipment (baghouse) would be in the range of 150 degrees F, which is lower than the

temperature range for operating SCRs on coal-fired utilities.

Although EPA is not aware of any CFB boilers operating with SCR for NOx control,

either upstream or downstream of particulate controls, EPA asked Deseret Power to evaluate

whether low-temperature SCR downstream of the particulate controls could be a feasible NOx

control option. Based on information from the National Park Service on this topic, EPA listed

SCR vendors that Deseret Power could contact. Deseret Power contacted those vendors and

found that the vendors only provide SCR technology for natural gas applications, not for coalfired boilers. Based on this information, EPA does not consider low-temperature SCR a

technically feasible NOx control option for this project.

Since low-temperature SCR is not technically feasible, EPA asked Deseret Power to

evaluate the possibility of reheating the flue gas downstream of the baghouse to the temperature

range known to be effective for SCR use (650-750 F). Applicants and permitting authorities for

other CFB projects (Gascoyne and South Heart projects in North Dakota and River Hill project in

Pennsylvania) have considered flue gas reheat for SCR.
48

While Deseret Power informed EPA that they do not believe technology is available for

flue gas reheat that warrants its consideration in the BACT analysis, Deseret Power did provide

an estimate of fuel cost for raising flue gas stack temperature to the extent that SCR might be

utilized. (These costs are presented in Step 4 below.) Based on review of other determinations

on the technical feasibility of flue gas reheat and the potential use of SCR on a CFB unit, EPA

believes SCR is a technically feasible NOx control option for this project.

b. Selective Non-Catalytic Reduction. SNCR is another postcombustion control option where ammonia or urea is injected into the flue gas in the reaction

zone to reduce NOx to nitrogen and water. The SNCR reaction occurs at temperatures higher

than with an SCR system, without the use of a catalyst. The optimum temperature range for

SNCR is about 1600-1900 F. SNCR has been employed at CFB units in the United States and is

considered a technically feasible NOx control option for this project.

c. Non-thermal plasma reactor. As explained in Step 1 above, a nonthermal plasma reactor may have practical potential for application to coal-fired CFB boilers, as

a technology transfer control option at Step 1 of the BACT analysis, but is not known to be

commercially available for CFB boilers. Therefore, it is not considered to be technically feasible

and is eliminated at this Step 2.

d. Carbon injection into the combustion chamber. As explained in

Step 1 above, carbon injection into the combustion chamber may have practical potential for

application to coal-fired CFB boilers, as a technology transfer control option at Step 1 of the

BACT analysis, but is not known to be commercially available for CFB boilers. Therefore, it is

not considered to be technically feasible and is eliminated at this Step 2.

3. Step 3 - Rank Remaining Control Technologies by Control Effectiveness.

The two NOx control options that are considered technically feasible for this project are

SCR and SNCR. EPA believes application of SCR to a CFB boiler could achieve emission

levels comparable to application of SCR at a PC-fired boiler. PC-fired boilers with SCR have

been able to achieve NOx emission rates below 0.05 lb/MMBtu on a 30-day average. For

example, the BACT analysis by North Dakota for the Gascoyne CFB boiler project estimates a

controlled NOx emission rate with SCR of 0.04 lb/MMBtu on a 30-day average.

Public comments received by EPA on the draft WCFU permit cited statements from

Babcock & Wilcox (a boiler manufacturer) that commercial SCR installations have shown that

90% NOx reductions can be achieved with low ammonia slip, and that Babcock & Wilcox states

that up to 95% NOx control can be achieved with SCR. While EPA’s analysis in the draft

Statement of Basis was based on 0.04 lb/MMBtu potentially achievable with SCR, as a result of

new information provided in public comments EPA has re-analyzed on the basis of 90%

emission reduction from an uncontrolled emission rate of 0.15 lb/MMBtu, which is equivalent to

a final emission rate of 0.015 lb/MMBtu potentially achievable with SCR. Therefore, for the
49

sake of ranking in Step 3 of this BACT analysis, and for the sake of cost analysis in Step 4, EPA

estimates that an emission rate of 0.015 lb/MMBtu could potentially be achieved with flue gas

reheat and SCR.

EPA’s review of recently issued permits, permit applications, and operating data for CFB

projects utilizing SNCR (discussed further in Step 5 below) indicates that an emission rate of

0.07 lb/MMBtu could be achieved with SNCR under certain conditions, which are not present

with Deseret’s project. However, as explained below, EPA believes Deseret Power’s WCFU

project will be able to consistently achieve an emission rate of 0.080 lb/MMBtu. The two control

options (SCR and SNCR) are therefore ranked by EPA as follows:

 SCR – 0.015 lb/MMBtu (30-day rolling average)

 SNCR – 0.08 lb/MMBtu (30-day rolling average)

4. Step 4: Evaluate Economic, Environmental and Energy Impacts.

a. Selective Catalytic Reduction. As noted above, for SCR to be a

technically feasible NOx control option for this project, flue gas reheating would be required

downstream of the particulate controls. This would involve significant additional fuel cost. The

cost and environmental impacts are discussed below. Even without flue gas reheating, an SCR

system does require some additional energy in order to overcome the pressure drop over the SCR

catalyst beds; however, this has not proven to be a significant energy or economic impact for

employing SCR technology on coal-fired power plants.

With any SCR installation, there are some commonly noted adverse environmental

impacts. These would include ammonia slip emissions, catalyst disposal, and potential ammonia

handling hazards. These impacts are usually deemed to be offset by the environmental benefits

of significant NOx reduction from the SCR system. With the SCR system located downstream of

the particulate and SO2 control devices in order to deal with technical problems associated with a

CFB application, there may be additional condensible particulate emissions resulting from the

conversion of SO2 to SO3 and eventually to H2SO4 over the catalyst bed.

Another adverse environmental impact is the additional emissions from combustion of

distillate fuel oil or propane for flue gas reheating. Deseret Power has calculated a required heat

input of 99.2 MMBtu/hr to raise the temperature of the flue gas from 275 F to 480 F. The 480 F

used by Deseret Power is on the low end of, or even below, where an SCR can most effectively

operate. Thus, the fuel consumption values may actually be higher than calculated by Deseret.

Since there are no natural gas lines into Deseret Power’s Bonanza plant, the only reheat

options are distillate fuel oil or propane. EPA has calculated the emissions based on AP-42

emission factors. These emissions are presented in the table below. The calculations assume

heat rating of the distillate fuel oil to be 0.14 MMBtu/gal, which equals 710 gallons per hour.

For propane, the calculations assume 0.0905 MMBtu/gal, which equals 1,100 gallons per hour.
50

The difference in emission rates between SNCR and SCR would be 0.065 lb/MMBtu

(i.e., 0.08 minus 0.015). Assuming CFB operation at 90% of capacity on an annual average, this

difference would be equivalent to a NOx reduction of 370 tons per year:

(0.08 lb/MMBtu – 0.015 lb/MMBtu) x (1,445 MMBtu/hr) x

(8,760 hr/yr) x (0.9) x (1 ton/2,000 lb) = 370 tons/year

With distillate reheat, the net NOx reduction would be 308 tons per year (i.e., 370 minus

62). With propane reheat, the net NOx reduction would be 278 tons per year (i.e., 370 minus 92).

These figures are shown in the table below.

Estimated Emissions From Reheating of CFB Flue Gas

To Accommodate Use of Conventional SCR

At Deseret Power’s Proposed WCFU

Pollutant Distillate Oil

Emissions

(tons/year)

Propane

Emissions

(tons/year)

PM (total) 10 3

SO2 3 Negligible

NOx 62 92

VOC 1 2

CO 16 15

Even without considering reheat cost, the annualized cost of SCR is several times greater

than SNCR, due to higher capital and operating costs. (Example: PSD permit application dated

August 2005, for South Heart CFB boiler project in North Dakota, calculates the annualized

capital recovery cost for SCR to be about six times as much as for SNCR.) As explained above,

SCR installed downstream of particulate controls would also involve reheat cost. Deseret Power

provided cost figures for only the supplemental fuel that would be required to reheat the flue gas

so that SCR could be used. No additional costs were calculated for capital, installation, or

operation of the SCR system or capital, installation, and other non-fuel operational costs for the

reheat system. Hence, this is a very conservative cost analysis, since as mentioned above, these

additional capital, installation and operational costs for the SCR and reheat system would likely

be substantial. The lowest-cost option for reheat fuel was calculated to be distillate oil at

$12,411,476 per year, based on 6,205,738 gallons per year at $2.00 per gallon.

Without any add-on controls, EPA estimates that the CFB boiler should be able to

achieve a NOx emission rate of about 0.15 lb/MMBtu or lower. (Actual operational data on

existing CFB boilers suggests to EPA that this value could be much lower. The 0.15 value was

chosen by EPA only as a conservative estimate in doing this cost analysis.) Using this

uncontrolled emission rate as a baseline, the total cost effectiveness for the SCR/reheat system

only, considering the cost of reheat fuel, is calculated as follows:
51

Emission reduction going from baseline to SCR controlled emissions:

(0.15 lb/MMBtu – 0.015 lb/MMBtu) x (1,445 MMBtu/hr) x

(8,760 hr/yr)(0.9) (1 ton/2,000 lb) = 769 tons/year

The average cost per ton for NOx reductions, considering only distillate fuel costs when

considering the additional NOx that would be generated by burning distillate fuel:

($12,411,476 / yr) / (769 - 62 ton/yr) = $17,555/ton

The incremental cost of going from SNCR to SCR, considering only the distillate fuel costs is

calculated as follows:

($12,411,476 / yr) / (370 ton/yr) = $33,545 /ton

The incremental cost going from SNCR to SCR, considering only the distillate fuel costs, and

considering the additional emissions caused by reheat for SCR, is calculated as follows:

($12,411,476 / yr) / (370 - 62 ton/yr) = $40,297 /ton

EPA concludes that the economic impacts associated with a cost of more than $40,000

per ton of pollutant removed justify elimination of SCR as the top control option. Both the total

cost effectiveness and incremental cost effectiveness are considered by EPA as cost-prohibitive

for BACT. In addition, if capital, installation, and other operational costs for both the SCR and

reheat system were considered, the above cost values would increase significantly.

b. Selective Non-Catalytic Reduction. Deseret has proposed SNCR

as BACT for NOx, which is the next highest ranked control option. Since SCR has been rejected

above, and since there are no significant collateral impacts for SNCR, this control option is

selected as BACT.

5. Step 5: Proposed NOx BACT for CFB Boiler.

As stated above, SNCR has been selected as NOx BACT. An emission limit must now be

established that represents the maximum degree of reduction achievable for SNCR for this

project. The above discussion and analysis indicates that SNCR for the WCFU project can

achieve 0.080 lb/MMBtu on a rolling 30-day average. Deseret Power has proposed an emission

limit of 0.088 lb/MMBtu on a 30-day rolling average. Deseret Power searched the

RACT/BACT/LAER Clearinghouse (RBLC) database and found the following determinations:
52

Comparison of CFB Boiler NOX Emission Rates using SNCR:

RACT/BACT/LAER Clearinghouse Data

Facility RBLC ID Heat Input

mmBtu/hr

NOX Emissions

Lb/mmBtu

Fuel

AES-PRCP PR-0007 4922.7 0.1 Columbian Coal

Reliant Energy MidAtlantic PowerPA-0182 2532.0 0.15 Coal

Archer Daniels

Midland (9&10)

IL-0060 1500.0 0.12 Coal

Choctaw Generation MS-0036 2475.6 0.2 Lignite

Archer Daniels

Midland (5&6)

IA-0046 1500.0 0.07 Coal

Archer Daniels

Midland

IA-0051 1500 0.07 Bituminous Coal

Kimberly Clark PA-0204 799 0.2 Coal

Toledo Edison OH-0231 1764 0.2 Pet Coke

York County Energy

Partners

PA-0132 2500.0 0.125 Bituminous Coal

Northampton

Generating Co.

PA-0134 1146.0 0.1 Anthracite Culm

Westwood Energy PA-0124 423 0.3 Anthracite Culm

Gilberton Power PA-0110 520 0.3 Anthracite Culm

Archer Daniels

Midland (7&8)

IL-0058 1500 0.12 Coal

Energy New Bedford

Cogeneration

MA-0028 1671.0 0.15 Eastern US Coal

AES Warrior Run MD-0022 2070.0 0.1 Eastern US Coal

Archer Daniels

Midland

IA-0025 551.5 0.07 Coal

Energy New Bedford

Cogeneration

MA-0009 3342.0 0.15 Eastern US Coal

Tauton Energy

Center

MA-0011 1604.4 0.15 Eastern US Coal

North Branch Energy

Partners

PA-0058 563.5 0.15 Waste Bit. Coal

Deseret Power proposed 0.088 lb/MMBtu on a 30-day rolling average as NOx BACT.

The following section describes EPA’s basis for proposing a second limit of 0.080 lb/MMBtu on

a 30-day rolling average, applicable beginning 15 months after the date of initial startup of the

CFB boiler. During the first 15 months, the limit will be Deseret’s requested limit of 0.088

lb/MMBtu on a 30-day rolling average, the basis for which is described later in this discussion.
53

EPA reviewed several recently issued permits and permit applications for CFB boiler

projects fired on lower quality coal, to compare limits using SNCR. These projects are not listed

in the RBLC database. Some projects are, or will be, subject to BACT limits as low as 0.07

lb/MMBtu. This information is presented in the table below.

Summary of Recent CFB Projects Permitted or Proposed:

NOx Emission Rates using SNCR

Project / Company

Name

State

Primary Coal

Type

Permit Status

NOx Emission Rate

(lb/MMBtu)

Karthaus Township CFB

Project / River Hill

Power Company

PA Eastern Waste Issued 07/21/05 0.07 (30 DRA)

Highwood Generating

Station / Southern

Montana Electric

MT

Western

Subbituminous

Application

11/30/05

0.07 (annual avg)

0.09 (24-hr avg)

Kentucky Mountain

Power Project

KY

Unknown; not

specified in

permit

Issued 05/04/01 0.07 (30 DRA)

Beech Hollow Energy

Project / Robinson

Power Co. LLC

PA Eastern Waste Issued 04/01/05 0.08 (30 DRA)

Greene Energy Resource

Recovery Project /

Wellington Dvpt, LLC

PA Eastern Waste Issued 06/21/05

0.08 (30 DRA)

0.1 (24-hr avg)

Gascoyne Generating

Station / MontanaDakota Utilities Co.ND Lignite Issued 06/02/05 0.09 (30 DRA)

South Heart Power

Project / Great Northern

Power Dvpt, L.P.

ND Lignite

Application

08/18/05

0.09 (30 DRA)

30 DRA = 30-day rolling average

Deseret Power maintains that comparing its plant to eastern plants is unfair because of the

higher Btu content of the eastern waste coal and the ability of some of these projects to blend

higher grade bituminous coal with its waste coal to boost the heat content even higher. For the

sake of comparison, EPA will compare the Deseret waste coal profile to two permitted or

proposed projects with NOx limits of 0.07 lb/MMBtu, listed in the table above. These projects

are the River Hill Power Project in Pennsylvania and the Highwood Generating Station in

Montana.
54

(Note 1: A similar proposed CFB boiler project listed in the table above, Kentucky

Mountain Power Project (KMPP), also with an emission limit of 0.07 lb/MMBtu, has not been

included by EPA in this analysis, because, unlike the Deseret WCFU permit, the KMPP permit

says the NOx emission limit is “waived for the specific SNCR optimization study activity as

detailed in Condition 2 above not to extend more than 365 days after the initial compliance

demonstration. However, the nitrogen oxide emissions rate shall never exceed 0.10 lb/MMBtu,

during or after the SNCR optimization study.” By contrast, the Deseret WCFU permit says the

initial NOx emission limit is 0.088 lb/MMBtu and the final NOx emission limit (applicable

starting 12 months after completion of initial performance testing) is 0.080 lb/MMBtu, with no

waiver or provision for raising the limit later. Since Kentucky is willing to waive the initial NOx

emission limit for up to a year while a study is conducted, and adjust it up to as high as 0.10

lb/MMBtu after the study is conducted, EPA discounts to some degree the significance of

KMPP’s initial emission limit of 0.07 lb/MMBtu.)

(Note 2: Another similar proposed CFB boiler project, Estill County Energy Partners in

Kentucky, has not been included by EPA in this analysis, and is furthermore not listed in the

table above, because the permit application – which proposed a NOx emission limit of 0.07

lb/MMBtu -- is no longer actively being processed. It was determined to be incomplete by

Kentucky in late 2004.)

Deseret Power’s “average” waste coal will have a High Heating Value (HHV) of 4,000

Btu/lb (with a range of 3,000-5,400 Btu/lb). The River Hill Project is proposing to burn eastern

waste coal blended with bituminous coal, which could boost the Btu content substantially higher

than Deseret’s proposed waste coal. The Highwood Generating Station is proposing to burn

subbituminous coal with a heating value of 8,752 Btu/lb. This is over twice the heat content of

Deseret’s average waste coal.

With respect to the heating value of the coal, EPA believes the River Hill and Highwood

Generating Station projects mentioned above will have an inherent advantage over Deseret to

meet a lower NOx limit. Therefore, EPA is not convinced that a direct comparison can be made

between the NOx limits for these projects and Deseret’s WCFU project, even if Deseret were to

blend up to a 50/50 ratio of waste coal with ROM coal from the Deserado mine, when needed. A

50/50 blend would yield an average Btu content of about 6500 Btu/lb. While EPA considered

these projects in establishing a NOx limit for Deseret, EPA believes the difference in the heating

value of Deseret’s fuel versus the fuel for River Hill and Highwood warrants some consideration.

In addition to looking at some of the recent permitting activity, EPA attempted to review

actual emissions data for CFB boilers combusting waste coal. Unfortunately, there are not any

examples of waste coal CFB plants operating in the Western United States. However EPA found

emissions data from several waste coal CFB units operating in Pennsylvania. These units are

primarily fueled by either eastern bituminous waste coal (gob) or waste anthracite (culm).
55

It appears that the plants burning waste anthracite emit very low levels of NOx emissions,

even without the use of SNCR (Gilberton and Northeastern Power). However, among other

differences, anthracite is known to have a lower percent volatile matter compared to bituminous

coal. A lower percent volatile matter will result in less fuel-nitrogen being released as NOx.

Therefore, while these data indicate that extremely low emissions are sometimes achievable for

waste coal CFBs, they are probably not the best comparison of what can be achieved for

Deseret’s WCFU project. Deseret will be burning waste bituminous coal, so the best comparison

for currently operating plants would be to look at CFB units in Pennsylvania that are burning

waste eastern bituminous coal. Below is a table summarizing monthly 2005 NOx emissions for

these plants.

As can be seen from the table below, several plants are achieving below 0.08 lb/MMBtu

during the ozone season months of May through September (in bold). While these plants are all

equipped with SNCR, it appears that the controls are generally only operated during the ozone

season. Conversely, if the controls are being operated during the non-ozone season, they are not

being utilized to the same extent, as emissions are higher during those months.

While these data do suggest that NOx emission rates of 0.08 lb/MMBtu are being

achieved in practice, they should not necessarily be interpreted as representing what Deseret’s

WCFU is capable of sustaining over the long term. EPA has not investigated what NOx limits

these plants are required to meet, nor has EPA investigated other specific coal characteristics that

might affect NOx (other than that these plants burn some level of bituminous waste coal), so EPA

cannot say these emissions represent the best achievable NOx emissions for these facilities. EPA

can say that these data show that an emission rate 0.08 lb/MMBtu has been achieved for CFB

units fired on eastern bituminous waste coal.

Actual NOx Emissions During 2005 From

Eastern Bituminous Waste Coal Fired CFB Units

Scrubgrass

Generating

Station

Unit 1

Scrubgrass

Generating

Station

Unit 2

Seward Unit

1

Seward Unit

2

Piney Creek

Power

Cambria Cogen

Unit 1

Cambria Cogen

Unit 2 Month

NOx

(lb/MMBtu)

NOx

(lb/MMBtu)

NOx

(lb/MMBtu)

NOx

(lb/MMBtu)

NOx

(lb/MMBtu)

NOx

(lb/MMBtu)

NOx

(lb/MMBtu)

Jan 0.154 0.145 0.230 0.230 0.205 0.295 0.301

Feb 0.174 0.169 0.230 0.230 0.199 0.294 0.298

Mar 0.154 0.133 0.390 0.230 0.175 0.287 0.297

Apr 0.157 0.134 0.230 0.230 0.179 0.291 0.300

May 0.066 0.061 0.067 0.095 0.138 0.143 0.143

Jun 0.066 0.058 0.065 0.067 0.078 0.117 0.117

Jul 0.063 0.064 0.085 0.089 0.074 0.098 0.098

Aug 0.066 0.068 0.074 0.074 0.062 0.088 0.088

Sep 0.060 0.085 0.060 0.080 0.064 0.088 0.088
56

Oct 0.116 0.135 0.094 0.093 0.170 0.292 0.290

Nov 0.115 0.136 0.085 0.108 0.163 0.288 0.287

Dec 0.121 0.145 0.087 0.083 0.191 0.284 0.292

Furthermore, these data show that of the CFB plants currently in operation, none are

consistently demonstrating emission rates much lower than 0.08 lb/MMBtu, as to warrant EPA

setting a lower NOx BACT limit for Deseret’s WCFU. Additionally, in presenting its position

for a NOx limit of 0.088 lb/MMBtu, Deseret Power has stated that the limestone injection rate

into the boiler that will be required to meet the low SO2 BACT emission limits proposed by

EPA, will prevent the proposed WCFU from meeting a NOx limit any lower than 0.088

lb/MMBtu. EPA agrees that increasing the limestone injection rate into the boiler may increase

NOx formation (due to the presence of excess unreacted CaO in the boiler), but finds this effect

difficult to quantify, especially considering the effect the SNCR will have on actual NOx

emissions. That said, EPA is unaware of any other waste coal CFB projects currently being

permitted with NOx limits below 0.08 lb/MMBtu that also have SO2 limits of 0.04 lb/MMBtu or

below.

Considering the comparisons of recently permitted low quality coal CFB projects and the

above actual emissions data for operating CFB plants burning eastern waste bituminous coal and

utilizing SNCR, EPA believes a NOx emission rate of 0.080 lb/MMBtu on a rolling 30-day

average represents BACT for Deseret’s WCFU project, after an initial break-in period (see

further discussion below), and taking into account the operational flexibility requested by Deseret

Power to blend, when needed, up to 50/50 ratio of run-of-mine coal with the waste coal.

Deseret Power maintains that in order to optimize NOx control, a “break-in” period will

be needed after initial startup of the CFB unit, to fine-tune and chemically balance the SNCR.

EPA asked for further explanation. Below is Deseret’s response:

The “Break-in Period” for a CFB unit and optimization of the unit to achieve the

permitted NOx emission limit, with the most efficient plant operation, would occur after

the completion of plant commissioning and performance testing at full load operation

which is expected to take 3 to 4 months after initial startup. During this initial operating

period, the operation and maintenance personnel will be trained for this specific unit,

plant controls would be checked out and tuned and equipment problems would be debugged.

The NOx optimization process involves making many adjustments to the unit such as

combustion controls, adjustments to the SNCR ammonia system, and since the limestone

injection rate affects NOx production, adjustments will have to be made to the limestone

feed system in conjunction with adjustments to the dry scrubber so the SO2 emission limit

is also met. The NOx optimization process is expected to consist of up to 3 periods each

consisting of the following steps:
57

a) Testing – Initial NOx and boiler performance evaluations would be made with installed

instrumentation and control room indications. Following these initial evaluations,

formal tests are required to confirm the indications from the installed instruments. Data

will also be collected from test connections that do not have permanent instrumentation

installed. This requires testing contractors with specialized testing equipment to measure

emissions at the stack, in addition to other test grids at the boiler outlet and possibly

other locations in the system. The scheduling of personnel and contractors to perform

testing can often require 4 – 8 weeks of pre-planning. In addition to emissions many

other measurements and fuel / sorbent / ash samples will be taken simultaneously with

the emissions measurements.

b) Evaluation – Follow-up fuel / sorbent / ash laboratory analyses will be conducted and

a test report prepared. The lab analysis and report preparation usually requires 4 to 6

weeks. The report will then be reviewed by a team of engineers to determine whether

further actions are necessary, this study will require up to 4 weeks of engineering time.

c) Adjustments – If the evaluation determines that further action is needed, the actions

would be implemented. These actions may consist of making operating adjustments or

installing additional test connections or making modifications to components inside the

plant systems. Implementation of these actions may require anywhere from a few weeks

to several months, depending on the type / scope of the action required.

d) Re-retest – Once the adjustments are implemented, formal re-testing would be

conducted as explained in ‘a)’ above.

e) Evaluation – The re-test report would be prepared, then analyzed to determine if

further action is needed. If action is needed, this process would then be repeated.

One period of the above steps would require 3 to 4 months to complete, thus 9 to 12

months of testing / evaluation would be required to go through this process 3 times plus

the initial startup and commissioning period of 3 to 4 months. In addition, time needs to

be allowed to schedule and conduct at least one modification outage to make

modifications to systems internal to the boiler. Thus a “Break-in Period” of at least 12

to 15 months is recommended. It is possible that it may take more time to complete the

optimization process depending on the problems that are encountered and the permitted

NOx emission rate. Progress reports could be submitted to EPA to keep EPA advised on

the status of the work during the “Break-in Period”.

Based on the above explanation from Deseret, and on the NOx BACT analysis above,

EPA proposes the following emission limits as NOx BACT:

 Prior to the date which is 12 months after completion of initial performance

testing: 0.088 lb/MMBtu on a rolling 30-day average.
58

 Beginning on the date which is 12 months after completion of initial

performance testing, and thereafter: 0.080 lb/MMBtu on a rolling 30-day

average.

As explained earlier in this Statement of Basis, Deseret Power will be permitted to use

coal from the Deserado mine, consisting of either waste coal alone, or else a blend of waste coal

and run-of-mine coal yielding heat content of up to 6,500 Btu/lb. For reasons explained above,

EPA believes the proposed NOx BACT emission limit of 0.080 lb/MMBtu, on a rolling 30-day

average, will represent BACT up to at least a 50/50 blend.

6. Comparison to applicable NSPS emission standard.

The definition of BACT in 40 CFR 52.21(b)(12) contains the statement that, “In no event

shall application of best available control technology result in emissions of any pollutant which

would exceed the emissions allowed by any applicable standard under 40 CFR parts 60 and 61.”

The applicable NOx emission standard, in Subpart Da of 40 CFR part 60 (New Source

Performance Standards), is 1.0 pound per megawatt-hour (lb/MWh) on a rolling 30-day average.

The following equation is used by EPA to convert from lb/MWh to lb/MMBtu:

X lb/MMBtu * 3.412 MMBtu/MWh * 1/Efficiency = Y lb/MWh

In developing Subpart Da standards in lb/MWh, EPA assumed a 36% gross efficiency for

coal-fired electric utility boilers. Approximately a quarter of existing boilers presently have

average efficiencies greater than 36%; however, CFB boilers tend to have lower gross efficiency

values, ranging from 30% to 38%. With the relative low-quality waste coal that will be used at

Deseret’s proposed WCFU, EPA expects that the WCFU efficiency would be at the lower end of

this efficiency range.

If 36% gross efficiency is assumed, then by the equation above, the WCFU would have to

maintain NOx emissions at 0.11 lb/MMBtu or lower, to meet the 1.0 lb/MWh standard. If the

WCFU operates at a low efficiency of 30%, then it must maintain an emissions rate of 0.09

lb/MMBtu or less, to meet the 1.0 lb/MWh standard. Considering rounding (1.049 lb/MWh), a

unit with a NOx emission limit of 0.090 lb/MMBtu would only have to maintain an efficiency of

29.2% to comply with the NSPS. Approximately 90% of existing units have average efficiency

values greater than this. The proposed NOx BACT emission limits for the WCFU (0.088

lb/MMBtu initially; 0.080 lb/MMBtu after a 15-month break-in period) are lower than 0.09

lb/MMBtu and therefore are at least as stringent as the applicable NSPS emission standard of 1.0

lb/MWh.
59

7. Proposed compliance monitoring approach.

For compliance demonstrations, EPA proposes to require use of NOx CEMS. EPA also

proposes to allow the diluent cap approach from 40 CFR part 75 for calculating emissions in

lb/MMBtu, in the event of very low boiler load, such as during startup or shutdown. This

approach was developed by EPA in Part 75 to address low-load situations at electric utility

boilers. Further explanation of the diluent cap approach may be found at the end of section

VI.K.5 of this Statement of Basis (Step 5 of SO2 BACT discussion).
60

H. BACT for PM/PM10 Filterable Emissions from CFB Boiler.

The composition and amount of filterable particulate matter emitted from coal fired

boilers are a function of firing configuration, boiler operation, coal properties, and emission

controls. Particulate matter (as total suspended particulate) will be emitted from the CFB boiler

as a result of entrainment of incombustible inert matter (ash) and condensable substances. Since

CFB boilers attain nearly complete combustion, very little carbon will be present.

In addition to the potential control technologies listed in Step 1 below, clean fuels (i.e.,

alternative coal, either from the Deserado mine or another mine) is also a possible option for

BACT, but has already been eliminated as cost-prohibitive for BACT, for all pollutants at this

project. This was explained earlier in this Statement of Basis.

1. Step 1: Identify Potential Control Technologies.

EPA knows of two potential technologies for the control of filterable particulate from

coal fired boilers:

a. Fabric filtration

b. Electrostatic Precipitation

2. Step 2: Eliminate Technically Infeasible Options.

Both fabric filtration (FF) and electrostatic precipitation (ESP) are technically feasible.

Control of PM/PM10 using either FF or ESP is clearly demonstrated, available, and applicable to

CFB boilers. This finding is consistent with general scientific thought that FFs and ESPs

represent technically feasible control options for the control of particulate and trace metals from

CFB boilers. Wet control techniques do not represent a demonstrated control technique for CFB

boilers and do not offer more stringent levels of control of particulate matter than fabric filters.

a. Fabric Filtration. Fabric filtration is a constant emission device.

Pressure drop across the filters, inlet particulate loading, or changes in gas volumes may change

the rate of filter cake buildup but will not change the final emission rate. The major particle

collection mechanisms of fabric filters are inertial impaction, diffusion from Brownian motion

and interception. During fabric filtration, dusty gas is drawn through the fabric by induced draft

fans. The fabric is responsible for some filtration, but more significantly it acts as support for the

dust layer that accumulates. The layer of dust, also known as filter cake, is a highly efficient

filter, even for sub-micrometer particles.

Fabric filters possess some key advantages over other types of particle collection devices.

Along with the very high collection efficiencies, for filterable particulate matter, they also have

the flexibility to treat many types of dusts and a wide range of volumetric gas flows. Fabric

filters can be operated with relatively low pressure drops of 4 to 8 inches water gauge, depending
61

upon dust loading and other factors. Fabric filters also have some potential disadvantages. In

general, they are limited to filtering dry streams.

b. Electrostatic Precipitation. Collection of particles by electrostatic

precipitation involves the ionization of the stream passing through the ESP, the charging,

migration, and collection of particles on oppositely charged surfaces, and the removal of particles

from the collection surface. In dry ESPs, the particulate is removed by rappers, which vibrate the

collection surface. Wet ESPs use water to rinse the particles off.

Fabric filters and ESPs are both capable of particulate matter and trace metal control

levels in excess of 99%. Some literature reports that fabric filters are more effective in collecting

fine particulates than ESPs. ESP vendors, however, counter that this is a misconception since it

is based on general comparisons of performance of new fabric filter installations with old,

undersized, ESP installations (Masteropietro, 1994). Particulate collection industry experts

currently consider new ESP designs capable of levels of particulate matter control equivalent to

fabric filters. Pressure drop through an ESP is generally 1-2 inches water gauge.

Effectiveness of an ESP is impacted by the resistivity of the fly ash. Presence of SO3

improves the ash resistivity, enabling the ash to be ionized and collected in the ESP. Inherently

less SO3 is generated in the CFB combustion process, even with a medium to high sulfur coal,

due to in situ sulfur capture with limestone injection. Even less SO3 is generated in a CFB with a

low sulfur coal such as with this project fuel. In order to enhance the collection efficiency of an

ESP with low SO3 levels in the flue gas, elemental sulfur would need to be converted to SO3 and

injected into the flue gas upstream of the ESP with sufficient residence time for complete mixing.

Recent studies, conducted by Sjostrom, Bustard, et al, for the EPA and Department of

Energy, suggest that fabric filters achieve a much higher mercury removal when compared to

ESPs. For subbituminous coal, the percentage of mercury removed was 70% by fabric filtration

versus 9% by electrostatic precipitation.

3. Step 3: Rank Remaining Control Technologies by Control Effectiveness.

The control technologies not eliminated in Step 2 are ranked in order of most effective

(lowest emission rate) as follows:

a. Fabric filtration

b. Electrostatic precipitation

While both technologies offer similar removal properties for particulate matter, the project is

proposing fabric filters due to the higher mercury removal as evidenced by the studies conducted

for EPA.
62

4. Step 4: Evaluate Economic, Environmental and Energy Impacts.

The proposed project will employ fabric filters (the highest ranked option) as the control

device to reduce particulate matter and trace metal emissions; thus, further review of economic,

environmental and energy impacts is not necessary.

5. Step 5: Proposed PM/PM10 Filterable BACT for CFB Boiler.

Deseret Power searched the RACT/BACT/ LAER Clearinghouse (RBLC) and the

California Air Resources Board (CARB) listings for coal fired fluidized bed boilers with limits

on particulate matter emissions. Below is a summary of facilities utilizing CFB boiler

technology and fabric filters for PM/PM10 reduction.

Comparison of CFB Boiler Filterable PM/PM10

Emission Rates using Fabric Filtration:

RACT/BACT/LAER Clearinghouse Data

Filterable particulate

emissions (lb/MMBtu)

Facility RBLC ID Heat Input

MMBtu/hr

PM PM10

Fuel

AES-PRCP PR-0007 4922.7 - 0.015 Columbian Coal

Reliant Energy MidAtlantic PowerPA-0182 2532.0 - 0.01 Coal

Archer Daniels

Midland (9&10)

IL-0060 1500.0 0.025 - Coal

Choctaw Generation MS-0036 2475.6 - 0.015 Lignite

Archer Daniels

Midland (5&6)

IA-0046 1500.0 0.015 0.03 Coal

Archer Daniels

Midland

IA-0051 1500 0.015 0.03 Bituminous Coal

Kimberly Clark PA-0204 799 - - Coal

Toledo Edison OH-0231 1764 0.03 - Pet Coke

York County Energy

Partners

PA-0132 2500.0 - 0.011 Bituminous Coal

Northampton

Generating Co.

PA-0134 1146.0 - 0.01 Anthracite Culm

Westwood Energy PA-0124 423 - - Anthracite Culm

Gilberton Power PA-0110 520 - - Anthracite Culm

Archer Daniels

Midland (7&8)

IL-0058 1500 0.025 - Coal

Energy New Bedford

Cogeneration

MA-0028 1671.0 - 0.018 Eastern US Coal
63

AES Warrior Run MD-0022 2070.0 0.015 - Eastern US Coal

Archer Daniels

Midland

IA-0025 551.5 - 0.03 Coal

Energy New Bedford

Cogeneration

MA-0009 3342.0 0.018 - Eastern US Coal

Tauton Energy

Center

MA-0011 1604.4 0.018 - Eastern US Coal

North Branch Energy

Partners

PA-0058 563.5 - 0.02 Waste Bit. Coal

In consideration of emission limits for similar facilities, EPA has concluded that an

appropriate BACT emission limit for filterable particulate matter at Deseret’s WCFU would be

0.012 lb/MMBtu on a 24-hour block average (midnight to midnight). EPA’s reasoning for this

conclusion is presented below.

With the exception of the AES-PRCP plant, all other plants operating CFB boilers with

PM/PM10 emission limits utilized fabric filters for control of filterable PM/PM10 emissions. The

facilities reporting the lowest filterable PM10 emission limits were the Reliant Energy MidAtlantic Power and Northampton Generating Company with an emission limit of 0.01

lb/MMBtu. York County Energy Partners reported a PM10 emission limit of 0.011 lb/MMBtu.

Although EPA does not have data on the heat content of the coal for these three facilities, EPA

expects that the heat content of these eastern coals would be substantially higher than the heat

content of the waste coal for Deseret’s WCFU (which is derived from western bituminous coal),

and would also likely be higher than the heat content of a 50/50 blend of Deseret’s waste coal

and run-of-mine coal. Therefore, these facilities can reasonably be expected to achieve a lower

PM/PM10 emission rate in lb/MMBtu than Deseret’s WCFU.

Not yet listed in the Clearinghouse database (but available to the public) is a permit

issued by Pennsylvania on July 21, 2005, for a CFB boiler project by River Hill Power Company

LLC. The permit was revised on March 7, 2006. The revised permit (also available to the

public) sets an emission limit for filterable PM10 of 0.010 lb/MMBtu, with compliance to be

demonstrated by EPA Method 5, 201, or 201A. The choice of required test method implies an

averaging time of approximately 3 hours. EPA Region 8 has been informed by EPA Region 3

that the heat content of River Hill’s waste coal is expected to be in the vicinity of 6,000 Btu/lb.

While the numerical value and averaging time of the River Hill emission limit are more

stringent than what EPA has selected for Deseret Power, the considerations below lead EPA to

conclude that the emission limit proposed for Deseret Power constitutes BACT:

(1) Pennsylvania’s “Plan Approval Application Review Memo” dated January 23, 2006,

indicates the emission limit of 0.010 lb/MMBtu was calculated on the basis of fabric filter

collection efficiency of 99.98%, fabric filter inlet loading of 170,996 lbs/hr, and CFB boiler heat

input capacity of 2,871 MMBtu/hr. Using these figures, EPA Region 8 calculates 0.012
64

lb/MMBtu rather than 0.010 lb/MMBtu as the BACT determination for River Hill.

(2) Deseret Power’s waste coal is lower quality than River Hill’s, particularly in terms of ash

content. For the proposed WCFU, the average fabric filter inlet loading has been calculated by

Deseret Power as follows: At maximum boiler heat input of 1,445 MMBtu/hr, average waste

coal heating value of 4,000 Btu/lb, 40% ash content, and 0.4% sulfur, the amount of fuel required

would be 180 tons/hr and the amount of ash generated in the boiler furnace would be 72 tons/hr.

Assuming approximately 30% of the ash leaves the furnace as bottom ash along with some of the

calcium sulfate formed in the furnace, the amount of particulates entering the baghouse would be

approximately 50 tons/hr, or 100,000 lbs/hr. This would require a removal efficiency of

approximately 99.98% (same as River Hill), to not exceed the WCFU emission limit of 0.012

lb/MMBtu for filterable PM.

When burning 3,000 Btu/lb coal with 50% ash (the low end of Deseret Power’s estimated

waste coal quality range), the baghouse inlet loading would be approximately 85 tons/hr, or

170,000 lbs/hr. This would be the same inlet loading as River Hill’s project (which is three times

as large as Deseret’s proposed WCFU, in terms of heat input capacity). This amount of inlet

loading would require a removal efficiency of 99.99% at the WCFU baghouse, to comply with

the WCFU emission limit of 0.012 lb/MMBtu. EPA cannot expect Deseret Power to comply

with an even lower limit of 0.010 lb/MMBtu, over the entire range of expected coal quality.

EPA calculates that to do so would require baghouse control efficiency of 99.992%. EPA is not

aware of any BACT determinations anywhere for filterable PM from coal-fired projects that

require as high as 99.992% control efficiency under any operating scenario.

(3) River Hill is only required to conduct annual stack tests to demonstrate compliance with

its filterable PM10 limit, whereas Deseret Power will be required to continuously demonstrate

compliance via PM CEMS. The River Hill permit does require a “PM-10 CEMS” to be installed,

but says the CEMS shall not be used to demonstrate compliance with any emission limitations

for up to 24 months from initial startup of River Hill’s CFB boiler. PM10 CEMS are not yet

commercially available and EPA has not yet developed a Performance Specification Test for

PM10 CEMS. Performance Specification 11 (PS11), in Appendix B of 40 CFR part 60, is

applicable to PM CEMS but not to PM10 CEMS. Paragraph 3.20 of PS11 requires that PM

CEMS accuracy be challenged via EPA Method 5, 5I, or 17. None of these test methods involve

size fractionation to determine the PM10 emissions.

(4) Pennsylvania’s PSD permit for the River Hill project, dated March 7, 2006, says in

section C-VII, condition #012, that the Pennsylvania Department of Environmental Protection

may revise the allowable BACT emission rates in the permit, based upon demonstrated performance (CEM data, stack test results) during the first five years of operation, provided that the

revised allowable BACT emission rates do not exceed “levels at which BACT was evaluated.”

This provision is applicable to any BACT emission limit in the permit. EPA Region 8 interprets

this provision to allow for the possibility that the BACT emission limit for filterable PM10 of

0.010 lb/MMBtu could be revised upward later, to any value deemed appropriate by the
65

Pennsylvania DEP, based on the aforementioned CEM data and stack test results. For Deseret

Power, however, EPA is not proposing any permit language saying the filterable PM emission

limit may be revised upward later.

In the draft permit for Deseret’s WCFU, EPA proposed an emission limit for filterable

PM of 0.012 lb/MMBtu on a rolling 30-day average. However, EPA re-considered and

determined that a 24-hour block average should be specified instead, on the basis of comparison

with the applicable PM emission limit in Subpart Da of 40 CFR part 60, New Source

Performance Standards. A 1986 guidance memorandum by EPA’s Office of Air Quality

Planning and Standards states that, “The PSD regulations clearly require that the application of

BACT conform with any applicable standard of performance under 40 CFR Part 60 at a

minimum.”

Ref: Memorandum from Gerald A. Emison, Director, Office of Air Quality Planning and

Standards, US EPA, to David Kee, Director, Air Management Division, EPA Region 5,

November 24, 1986, page 1, available online at:

http://www.epa.gov/region7/programs/artd/air/nsr/nsrmemos/shrtterm.pdf

The applicable PM emission limit in Subpart Da is expressed on a daily average (equivalent to a

24-hour block average). To conform with Subpart Da of 40 CFR part 60, EPA considers it

necessary to specify the averaging time of the BACT limit as a 24-hour block average. On the

basis of comparison with other similar permitted facilities, EPA considers 0.012 lb/MMBtu on a

24-hour block average to be achievable at Deseret’s WCFU.

As explained earlier in this Statement of Basis, for the proposed WCFU, Deseret Power

will be permitted to use coal from the Deserado mine consisting of either waste coal alone, or

else a blend of waste coal and run-of-mine coal yielding heat content of up to 6,500 Btu/lb.

While this heat content is similar to River Hill’s, the ash content of the blended coal would still

be higher than River Hill’s, and Deseret Power would still need to operate at a baghouse

collection efficiency of nearly 99.98% for even this “best case” coal. As explained earlier,

Deseret Power only plans to blend to the extent necessary to deal with any unexpected

operational difficulties when firing waste coal alone, or to deal with any unexpected difficulties

in meeting BACT emission limits.

In summary, EPA believes an emission limit for filterable PM of 0.012 lb/MMBtu on a

24-hour block average will represent BACT for coal from the Deserado mine with heat content

up to at least 6,500 Btu/lb, and will ensure a continued high degree of PM emission control

efficiency. EPA therefore proposes the following as a BACT emission limit for total filterable

particulate matter:

0.012 lb/MMBtu on a 24-hour block average (midnight to midnight)
66

Since EPA expects that virtually all filterable particulate emissions will be PM10 size or

smaller, EPA is proposing the same limit of 0.012 lb/MMBtu as BACT for filterable PM10.

Also, since EPA is proposing to require use of a particulate matter continuous emission

monitoring system (PM CEMS) for demonstrating compliance, EPA does not consider it

necessary to also propose an opacity limit as part of BACT for total filterable particulate. See

further discussion below.

6. Comparison to applicable NSPS emission standard.

The definition of BACT in 40 CFR 52.21(b)(12) contains the statement that, “In no event

shall application of best available control technology result in emissions of any pollutant which

would exceed the emissions allowed by any applicable standard under 40 CFR parts 60 and 61.”

The applicable particulate matter emission standard in Subpart Da of 40 CFR part 60 (New

Source Performance Standards) is 0.015 lb/MMBtu on a daily average. Allowed alternatives in

Subpart Da are: 0.14 lb/MWh on a daily average, or 0.03 lb/MMBtu and 99.9% emission

reduction on a daily average. The BACT emission limit of 0.012 lb/MMBtu on a 24-hour block

average for the WCFU is at least as stringent as the NSPS limit. EPA also notes that the NSPS

exemptions for startup, shutdown and malfunction will not apply to the BACT limit.

7. Proposed compliance monitoring approach.

For compliance demonstrations, EPA proposes to require use of a particulate matter

continuous emission monitoring system (PM CEMS). EPA considers this particulate monitoring

approach superior to establishment of an opacity limit and monitoring of opacity via a Continuous Opacity Monitoring System (COMS). This PM CEMS approach is consistent with 40 CFR

60, Subpart Da, under which PM CEMS is an allowed alternative to an opacity limit and COMS.

EPA further proposes to allow the diluent cap approach from 40 CFR part 75, for

calculating emissions in lb/MMBtu, in the event of very low boiler load, such as during startup or

shutdown. This approach was developed by EPA in Part 75 to address low-load situations at

electric utility boilers. Further explanation of the diluent cap approach may be found in section

VI.J.5 of this Statement of Basis, at the end of Step 5 of SO2 BACT discussion.

EPA considered opacity monitoring and imposition of an opacity limit as a means of

helping assure compliance with particulate emission limits. However, EPA believes that opacity

monitoring at Deseret Power’s WCFU, as an addition to requiring a PM CEMS calibrated

according to 40 CFR 60, Appendix B, Performance Specification 11, would be ineffective for

assuring compliance with emission limits for either filterable PM or total PM.

Opacity monitoring can be useful as a surrogate for direct measurement of particulate

emissions. However, EPA does not consider it useful for assuring compliance with PM emission

limits where those limits are extremely low. The emission limit for Deseret Power’s WCFU for

total PM/PM10 is 0.03 lb/MMBtu. This limit is based on a filterable PM/PM10 emission limit of
67

0.012 lb/MMBtu, added to projected emissions of no more than 0.018 lb/MMBtu for

condensable PM. These emission limits are so low that EPA believes it highly improbable, if not

impossible, that any form of existing opacity monitor could reliably detect opacity at levels that

would correspond to these limits. Moreover, given the sensitivity of the PM CEMS, elevated

emissions would be detected by PM CEMS well in advance of detection via a Continuous

Opacity Monitoring System (COMS), or via a Method 9 or Method 22 visible emissions

observation. Further, opacity only provides data from a subset of all particles, namely those

particles whose size is roughly the same wavelength as visible light.

A status report prepared for EPA on PM CEMS, dated February 12, 1997 (available at

http://www.epa.gov/ttn/emc/cem.html) in support of proposed revised regulations for hazardous

waste combustors (HWC), states that opacity monitors are not effective below filterable PM

concentrations of 45 mg/dscm. For coal combustion, this is equivalent to about 0.04 lb/MMBtu.

(The total PM/PM10 emission limit for Deseret Power’s WCFU, cited above, is lower than this.)

The Introduction to the status report states:

EPA in the past has relied on opacity monitors as a form of surrogate-PM monitoring to

indicate compliance with a PM standard. This approach involved a continuous opacity

monitor to demonstrate compliance with a separately-enforceable opacity limit

approximately aligned with, or near, the PM emission limit. However, this approach has

a serious limitation relative to the proposed HWC rule, because of poor correlation

between opacity and PM at low PM concentrations near the proposed PM emission limit

of 69 mg/dscm (at 7 % O2).

EPA recognizes that there are two inherent problems with the opacity/PM approach: 1)

the general concern about the stability of any opacity/PM correlation, which is strongly

dependent on particle size distribution and composition, and 2) the specific concern

about the insensitivity of opacity monitors typically below PM levels of about 45 mg/dscm

(at 7 % O2).

Consequently, opacity monitors would not be sufficient because to maintain compliance

with 69 mg/dscm, facilities would generally need to operate near 35 mg/dscm. Thus,

emissions would typically be below the detection limits of opacity monitors most of the

time. While normal emission levels below the detection limits of CEMS are acceptable,

facilities often desire the detection limit to be one-tenth of the emission limit. This gives

sufficient warning of how emissions are changing before the emission limit is

approached, and allows the facility, based on CEMS readings, to change operations as

necessary to be in compliance.

If possible, EPA desires a quantitative, continuous measure of PM mass concentrations

rather than opacity. Based on surveys and preliminary testing, EPA has recently

determined that CEMS do exist that do this: beta gauges and light scattering based

CEMS. These CEMS rely on calibration/certification of the device by manual gravmetric
68

measurements. Therefore, EPA is proposing use of CEMS based on the availability of

these newer technologies and a related Draft CEMS Performance Specification for

monitoring PM mass concentration. EPA believes that such monitoring is feasible and

that opacity monitoring has borderline sensitivity relative to the proposed PM emission

limit. The newer technology PM CEMS can give a real-time quantitative measure of low

PM concentrations while opacity monitors cannot.

(Ref: Status Report No. IV, Particulate Matter CEMS Demonstration, prepared by

Energy and Environmental Research Corporation, EPA Contract 68-D2-0164, Work Assignment

4-02, February 12, 1997.)

This same reasoning is reflected in the recent revisions to Subpart Da of New Source

Performance standards (40 CFR 60). The revised Subpart Da exempts facilities from ongoing

opacity monitoring after initial performance testing, where PM CEMS is installed and used. The

same reasoning is also reflected in EPA’s Technical Guidance Document for Compliance

Assurance Monitoring (available on EPA website at http://www.epa.gov/ttn/emc/cam.html), at

Appendix A, Facility V (pages A.19b-1 through A.19b-4), in which no opacity monitoring is

suggested where PM CEMS are used.

Further, the emission control technique for condensible PM at the proposed WCFU is a

combination of alkali injection, dry SO2 scrubbing and a fabric filter baghouse. Each of these

control techniques will be installed and used to comply with other emission limits in the permit

(alkali injection for NOx control, dry SO2 scrubbing for SO2 control, and a fabric filter baghouse

for filterable PM control). The permit requires compliance with these three other emission limits

to be tracked continuously via CEMS. (Ref: Conditions III.I.4.a and III.I.4.c of the WCFU

permit.) This continuous monitoring, in addition to annual stack tests required in the permit for

condensable PM, is considered by EPA to be sufficient for ensuring good control of the both the

condensable PM portion and the filterable PM portion of total PM.
69

I. BACT for PM/PM10 Condensible Emissions from CFB Boiler.

Portions of the discussion of condensible particulate matter (CPM) in Steps 1 through 4

below, including the discussion of why a wet ESP has been eliminated as a control option, come

from an e-mail and attachments provided by Deseret Power to EPA on February 23, 2006. EPA

has made a number of changes, including the addition of a discussion of wet SO2 scrubbers as a

potential control technology.

In addition to the potential control technologies listed in Step 1 below, clean fuels (i.e.,

alternative coal, either from the Deserado mine or another mine) is also a possible option for

BACT, but has already been eliminated as cost-prohibitive for BACT, for all pollutants at this

project. This was explained earlier in this Statement of Basis.

1. Step 1: Identify Potential Control Technologies.

The following control technologies with the potential to reduce condensable particulate

matter (CPM) are known to EPA and Deseret Power.

a. Alkali (limestone) injection + fabric filter baghouse

b. Dry SO2 scrubbing + fabric filter baghouse

c. Alkali injection + dry SO2 scrubbing + fabric filter baghouse

d. Alkali injection + wet SO2 scrubbing + fabric filter baghouse

e. Alkali injection + dry SO2 scrubbing + fabric filter baghouse +

wet electrostatic precipitation (ESP)

2. Step 2: Eliminate Technically Infeasible Options.

All potential control technologies (or technology combinations) listed in Step 1 above are

technically feasible; however, it must be noted that each of these technologies is only effective in

reducing some of the constituents that make up condensible particulate matter (CPM). The

primary CPM constituents identified by Deseret Power for the WCFU include hydrogen chloride

(HCl), hydrogen fluoride (HF), sulfuric acid (H2SO4), ammonium sulfate ((NH4)2SO4),

ammonium bisulfate (NH4HSO4), dinitrogen pentoxide (N2O5), and volatile organic compounds

(VOC). (Reference: e-mails from Deseret Power to EPA dated February 23, 2006 and March

27, 2006.) Based on EPA Region 8’s research of publicly available literature, these technologies

would be expected to provide significant emission control for all these CPM constituents except

N2O5 and VOC.
70

a. Alkali (limestone) injection + fabric filter baghouse. Alkali

injection reduces CPM emissions by removing SO3 from the exhaust, thus preventing formation

of H2SO4. The alkali material may be injected at various points within the process and may

consist of materials such as magnesium hydroxide, sodium bisulfite, sodium bicarbonate,

calcium hydroxide or calcium carbonate. Crushed limestone (CaCO3) is part of the solid

medium that makes up the combustion bed. Within the combustion zone, CaO is formed by

calcining the limestone. SO2 formed during the combustion process combines with the calcined

lime to form solid CaSO3, which is then collected downstream in the fabric filter baghouse.

As explained in more detail in the SO2 BACT analysis in this Statement of Basis, alkali

injection not only removes SO3, but also removes SO2 in the combustion bed. This reduces the

quantity of SO2 available for oxidation into SO3. Excess lime in the combustion bed will also

react with SO3 to form solid CaSO4, which is collected downstream in the fabric filter baghouse.

Furthermore, excess CaO in the combustion bed and fabric filter cake will be available to react

with SO3 generated in the combustion bed.

Deseret Power is already planning to inject calcium carbonate into the CFB boiler and

lime in the dry SO2 scrubber, to reduce SO2 emissions, and install a fabric filter baghouse. As a

result, SO3 formed during the combustion process will be controlled to the extent possible.

In processes that incorporate selective catalytic reduction (SCR), additional SO2 may be

oxidized to SO3 as the exhaust passes through the catalyst bed. Those processes may benefit

from alkali injection in the SCR or air heater outlet ducts; however, Deseret’s proposed WCFU

will not be using SCR. Because additional generation of SO3 downstream of the boiler is not

anticipated, there would be no benefit associated with injecting additional alkali elsewhere in the

process. While duct injection would serve no purpose, alkali injection in the boiler is considered

to be technically feasible and is proposed for the WCFU.

b. Dry SO2 scrubbing + fabric filter baghouse. Dry SO2 scrubbing

has the potential to control CPM by the same mechanism as alkali injection. The alkali (in this

case lime) is injected in slurry form, dried by the exhaust gas, combines with SO2 and forms a

solid that is collected downstream in the fabric filter baghouse. This control technology is

considered technically feasible and is proposed by Deseret Power for installation at the WCFU.

c. Alkali injection + dry SO2 scrubbing + fabric filter baghouse. The

combination of these controls is proposed by Deseret Power for the WCFU and is expected to

achieve better control of CPM than the previous two control technology combinations (options a

and b) discussed above.

d. Alkali injection + wet SO2 scrubbing + fabric filter baghouse.

Although a control option that includes wet scrubbing is technically feasible, it is not considered

as effective as option c above. This is explained below.
71

The wet scrubbing process uses an alkaline slurry made by adding lime or limestone to

water. The alkaline slurry is sprayed into the absorber tower and reacts with SO2 in the flue gas

to form insoluble CaSO3 and CaSO4 solids. A wet FGD process must be located downstream of

the fabric filter baghouse. SO2 entering the wet scrubber will react with water and create micron

sized H2SO4 droplets. Micron sized droplets can pass through the spray levels in the absorber

tower and the most eliminator and be emitted as H2SO4. Although some of the H2SO4 droplets

will react with the alkaline reactant in the wet scrubber, industry experience suggests that many

of the micron-sized droplets will not come into contact with limestone. (Reference: Gooch, J.P.,

Dismukes, E.B., Formation of Sulfate Aerosol in an SO2 Scrubbing System, Southern Research

Institute, Birmingham, AL.) Furthermore, because of the inherently low SO3 concentration in

CFB flue gas, it is not anticipated that a wet FGD system will provide any significant reduction

in overall SO3 or H2SO4 emissions.

Acid gases and ammonium sulfate are water soluble and will be removed in the wet FGD

control system. These compounds will also be removed in the unit’s fabric filter baghouse;

however, because the wet FGD would have to be located downstream of the fabric filter, it is

expected that acid gas removal in the fabric filter will be less effective with the wet FGD

combination. In conclusion, while it is technically feasible, a H2SO4 control system involving a

wet FGD is expected to have lower control efficiency than option c above.

e. Addition of wet electrostatic precipitation to option c above. This

discussion pertains to the technical feasibility of adding a wet electrostatic precipitator (ESP)

downstream of the combination of controls listed as option c above. Wet ESPs are capable of

controlling particulate matter as well as acid mists. ESPs collect particulate matter by applying a

negative electrical charge to the particles as they pass through the charging zone of wires or

electrodes. The negatively charged particles are then attracted to and captured by positively

charged collector plates. In a dry ESP, the captured particles are periodically removed from the

collector plates by rapping. In a wet ESP, the particles are either continuously or intermittently

removed from the plates by wash water. It is the presence of wash water and the resulting high

humidity inside a wet ESP that allows it to control mists or aerosols as well as particulate matter.

A wet ESP’s ability to control the CPM is somewhat dependent on the temperature of the exhaust

stream as it passes through the wet ESP.

The exit temperature of the dry SO2 scrubber, which Deseret Power plans to install at the

WCFU, is expected to be about 275 degrees Fahrenheit. To avoid reaching saturation and the

resulting wet plume and associated corrosion, the WCFU exhaust stack exit temperature must be

maintained at or near this temperature. If a wet ESP is installed as well at the WCFU,

adjustments to the exhaust system (including the scrubber) would have to be made to maintain

the desired temperature profile. Although this makes feasibility of a wet ESP somewhat

questionable at the WCFU, a wet ESP shall be considered technically feasible for the purposes of

this analysis, and will be evaluated further in Steps 3 and 4 below.
72

3. Step 3: Rank Remaining Control Technologies by Control Effectiveness.

As mentioned in Step 2 above, Deseret Power proposes to install alkali injection, dry SO2

scrubbing and a fabric filter baghouse (option c in Step 1 above). For reasons explained in Step 2

above, this proposed combination of controls is expected to be more effective than a combination

involving wet scrubbing (option d in Step 1 above). The only option that might achieve greater

control effectiveness than option c would be to add a wet ESP downstream. Below is a

discussion of the possible additional CPM control that might be achieved by a wet ESP.

There are little data available on the H2SO4 reduction achievable with a wet ESP on a

coal-fired boiler. In its BACT analysis for H2SO4 at the proposed Intermountain Power Unit 3,

the Utah Division of Air Quality (UDAQ) stated that no more than 80 percent removal efficiency

for H2SO4 might be expected, for a wet ESP at a pulverized coal-fired boiler, under optimum

conditions. (Reference: “Modified Source Plan Review” by UDAQ for IPP3 project, March 22,

2004, page 109.) However, others have cited a removal efficiency equivalent to about 86 percent

(SO3 reduction from 21 to 3 ppm) in conducting economic analyses of wet ESP control for CPM.

(Reference: Dombroski, K, et al, “SO3 Mitigation Guide and Cost-Estimating Workbook,”

Proceedings of the 2004 Mega-Symposium, August 30 – September 2, Washington, D.C.) Due

to the lack of additional data, and the desire to present a conservative analysis of the control

technology, a value of 86 percent will be used in the Step 4 analysis below, for removal of

H2SO4. It is also conservatively assumed that a wet ESP would remove equivalent amounts of

other acid gases, such as HCl and HF, as well as filterable PM10 not captured by the proposed

fabric filter.

No information regarding the potential of a wet ESP to control the other principal

condensible PM10 constituents identified by Deseret’s boiler supplier was found, and thus the

removal efficiency for VOC, N2O5, and (NH4)2SO4 is assumed to be zero.

4. Step 4: Evaluate Economic, Environmental and Energy Impacts.

The following analysis explains why addition of a wet ESP would be economically costprohibitive, for achieving additional CPM control for the WCFU project. The estimated capital

cost of a wet ESP ranges from $20 to $40 per SCFM (standard cubic foot per minute) of gas flow

handled. Reference: EPA-452/F-03-030, July 15, 2003, available at:

http://www.epa.gov/ttn/catc/dir1/fwespwpl.pdf.

Operation and maintenance (O&M) costs range from $5 to $40 per SCFM. The exhaust

flow rate for the proposed unit is about 399,971 SCFM (based on a modeled flow rate of 565,440

actual cubic feet per minute at 275 degrees F, corrected to standard conditions). The table below

presents the capital and O&M costs of a wet ESP for the proposed WCFU, based on the low,

midpoint, and high end of the ranges provided in the EPA document cited above. Total annualized costs are based on a capital recovery factor of 0.10296 (15 years and 6% discount rate).
73

Capital and O&M Costs

For Addition of a Wet ESP

at Deseret Power’s Proposed WCFU

The next table below shows the amount of CPM removed by a wet ESP, assuming 86

percent removal efficiency. The pre-wet ESP control emission rate for filterable PM is based on

the proposed BACT emission limit for the WCFU of 0.012 lb/MMBtu. The pre-wet ESP

control emission rate for H2SO4 is based on the proposed BACT emission limit for the WCFU of

0.0035 lb/MMBtu. The pre-wet ESP control emission rates for HCl and HF (0.0022 and 0.0008

lb/MMBtu, respectively) are based on emission estimates from Deseret’s boiler supplier,

provided to EPA by Deseret Power via e-mail of February 23, 2006. Potential emissions in tons

per year are based on the maximum heat input rate of 1,445 MMBtu/hr and 8,760 hours per year

of operation.

Estimated Emissions Reduction

for Addition of a Wet ESP

at Deseret Power’s Proposed WCFU

Constituent Pre-wet ESP Control Emissions

Lb/MMBtu tons/year

Emissions Removed

(tons/year)

HCl 0.0022 14.1 12.1

HF 0.0008 4.9 4.2

H2SO4 0.0035 22.2 19.1

PM10 (filterable) 0.012 75.9 65.3

Total - - 100.7

The next table below shows the cost of control for both filterable and condensable

particulate matter based on the annualized costs and the emission removals shown in the two

tables above.

Estimated PM10 Control Cost

for Addition of a Wet ESP

at Deseret Power’s WCFU

EPA Cost Range Control Cost

($/ton)

Low 26,039

Mid-Point 101,636

High 175,234

EPA Cost

Range

Capital Cost

($)

O&M Cost

($)

Total Annualized Cost

($)

Low 7,999,427 1,999.857 2,823,478

Mid-Point 11,999,140 8,999,355 10,234,786

High 15,998,853 15,998,853 17,646,095
74

As shown in the table above, even the most conservative analysis demonstrates that

addition of a wet ESP to the proposed WCFU would be economically prohibitive for BACT.

Some of the potential negative environmental impacts associated with a wet ESP include

increased water usage, disposal of a wet waste stream, and the generation of ozone. In addition,

due to the temperature drop across a wet ESP and the need to maintain the necessary exhaust

temperature exiting the stack, the temperature of the exhaust entering the wet ESP would need to

be higher. This would result in less heat being available for steam generation and have the result

of reducing the overall efficiency of the proposed WCFU. For these reasons and the economic

reasons discussed earlier, EPA believes a wet ESP should be eliminated as a BACT option for

condensible particulate matter.

5. Step 5: Proposed PM/PM10 Condensible BACT for CFB Boiler.

The following analysis, for determination of a BACT emission limit, is based on the

selected CPM control combination of alkali injection, dry SO2 scrubbing and fabric filter

baghouse. Consistent with the approach taken by permitting authorities for other CFB boiler

projects, and consistent with dispersion modeling for the WCFU project, which used one

emission rate for the total of filterable PM plus condensible PM, EPA does not propose a

separate BACT emission limit specifically for condensible PM. Instead, EPA proposes an

emission limit of 0.03 lb/MMBtu for total PM, which includes both condensible PM and

filterable PM. EPA proposes the same emission limit of 0.03 lb/MMBtu for total PM10, on the

basis that EPA expects virtually all PM emitted from the WCFU, downstream of all emission

controls, will be of PM10 size or smaller. This proposed emission limit is based on what EPA

believes to be achievable control, in practice, of total PM, and is consistent with other issued

permits for similar projects.

For demonstrating compliance with the total PM limit, EPA proposes to require the

condensible PM portion to be measured by EPA Method 202 (or EPA Conditional Test Method

39 as an allowed alternative). As also explained below, EPA proposes to allow the emission

limit for total PM to be adjusted to as high as 0.045 lb/MMBtu, pending EPA’s review of actual

stack testing data from the WCFU, after the WCFU begins operation.

In its permit application dated November 1, 2004, Deseret Power proposed a BACT

emission limit for total PM10 of 0.052 lb/MMBtu. Dispersion modeling was based on this

emission rate. Deseret Power stated in its application that this proposed limit is based on 0.012

lb/MMBtu for filterable PM10 and 0.040 lb/MMBtu for condensible PM. Deseret Power also

stated that the condensibles emission factor is based on AP-42 since no vendor data are available.

EPA found that the AP-42 emission factor cited by Deseret Power is actually for spreader

stoker, traveling grate overfeed stoker, and underfeed stoker boilers. There is no specific

emission factor in AP-42 for condensible PM from CFB units. However, a footnote to Table 1.1-

5 in AP-42 says that for CFB units, the emission factor for pulverized coal fired boilers with PM
75

and FGD controls should be used. This value is 0.02 lb/MMBtu. Regardless of interpretation of

AP-42, EPA advised Deseret Power that AP-42 is not intended by EPA to represent BACT.

To determine an appropriate estimate for condensible PM, EPA looked at other sources of

information on condensible PM from CFB boilers, primarily the permit applications for three

other projects, where the permit application was actively being processed or the permit had been

issued: Gascoyne in North Dakota, Estill County Energy Partners in Kentucky, and River Hill

Power in Pennsylvania. These applications all contained estimates of the various components of

condensible PM that can be summed to give a value for total condensible PM. The components

were: hydrogen chloride [HCl], hydrogen fluoride [HF], ammonium sulfate [(NH4)2SO4],

sulfuric acid [H2SO4], and volatile organic compounds [VOC].

EPA also looked at the estimates for some of these components of condensible PM that

appeared in an appendix to Deseret Power’s PSD permit application. Summing the components,

EPA came up with a rough estimate of 0.011 lb/MMBtu for condensible PM and 0.023

lb/MMBtu for total PM/PM10. This EPA analysis was explained in detail in a pre-draft

Statement of Basis that was e-mailed to Deseret Power on December 1, 2005.

In a January 30, 2006 email, Deseret Power responded by submitting its own estimation

ranges for components of condensible PM. Deseret Power proposed a total PM/PM10 limit of

0.045 lb/MMBtu, of which 0.033 lb/MMBtu was estimated for condensible PM. This estimate

was three times as high as EPA’s estimate of 0.011 lb/MMBtu, primarily due to differences in

the estimates for the sulfuric acid and ammonium sulfate components, and also due to Deseret

Power’s inclusion of a small amount of dinitrogen pentoxide [N2O5]. Deseret Power stated that

its condensible PM estimate assumes EPA Method 202 condenses SO2 and SO3 to H2SO4 and

that all ammonia slip emitted at the boiler exhaust stack will condense as ammonium sulfate in

the Method 202 impingers.

There was no discussion in Deseret Power’s January 30, 2006 e-mail, nor in a subsequent

e-mail from Deseret Power dated February 23, 2006, on top-down BACT analysis for

condensible PM, on how Deseret Power’s estimate for condensible PM compares to estimates for

other proposed CFB boiler projects. There was also no discussion of why 0.033 lb/MMBtu

should represent BACT based on the selected emission controls (alkali injection and dry SO2

scrubbing). Below is EPA’s own discussion and analysis.

The largest component by far in Deseret Power’s condensible PM emission estimate was

ammonium sulfate. Deseret’s estimate for this component was about three times as much as

Deseret’s estimate for the next largest component (sulfuric acid), and was about half of Deseret’s

estimate for total condensible PM. This seemed incorrect to EPA. In other permit applications

and analyses reviewed by EPA, the largest component of condensible PM was consistently

sulfuric acid, not ammonium sulfate.
76

In light of this disparity between Deseret Power’s information and the information in

permit applications for other CFB boiler projects, EPA closely examined Deseret Power’s

emission estimate for ammonium sulfate. In a February 3, 2006 e-mail, EPA asked Deseret

Power what level of ammonia slip was estimated and how that was used to calculate ammonium

sulfate emissions. Deseret Power replied on February 22, 2006 that the “estimated contribution

of (NH4)2SO4 is based on an ammonia slip level of 4 ppm at the stack” and “all of the ammonia

was assumed to be picked up as NH4HSO4 in the M202 impingers.” While this provided some

description of the estimation method, it did not entirely clear up why the estimate was so much

higher than other permit applicants. It was also unclear to EPA whether Deseret Power was

calculating ammonium sulfate or ammonium bisulfate emissions.

Consequently, EPA did a mass balance calculation that assumed all of the ammonia slip

coming out of the CFB combustor unit (i.e., immediately downstream of SNCR controls) would

react with sulfuric acid to form ammonium sulfate. This would occur upstream of the dry

scrubber and baghouse. EPA also assumed 85% control of ammonium sulfate by the dry

scrubber and baghouse. These assumptions were consistent with analyses in permit applications

reviewed by EPA for other CFB boiler projects. EPA’s calculation yielded an emission estimate

of 0.0036 lb/MMBtu for ammonium sulfate. This was about one-fifth of Deseret Power’s

estimated emission range of 0.014 to 0.0209 lb/MMBtu.

EPA also did a separate mass balance calculation for sulfuric acid, since Deseret Power

did not provide a calculation or other basis for its own estimated emission range. These

calculations were also e-mailed to Deseret Power on March 9, 2006. In that e-mail, EPA

concluded that the estimate for total condensible PM should be about 0.019 lb/MMBtu. When

added to 0.012 lb/MMBtu for filterable PM, this would yield about 0.03 lb/MMBtu for total

PM/PM10, which EPA believes is an appropriate BACT emission limit for total PM/PM10.

In a March 27, 2006 e-mail, Deseret Power responded to EPA’s calculations by

explaining Deseret’s underlying estimates and assumptions for calculating a range of 0.014 to

0.0209 lb/MMBtu for ammonium sulfate. Some of these underlying estimates and assumptions

are different than what EPA has seen in permit applications for other CFB boiler projects with

similar controls. The key differences are the concentration of unreacted free ammonia slip at the

final exhaust stack, and whether that free ammonia would form ammonium sulfate or ammonium

bisulfate in the Method 202 impingers.

Deseret Power estimated that 10 ppm ammonia slip would exit the CFB combustor unit.

Deseret Power also estimated that approximately 40-60% of that ammonia slip would be

removed by the dry scrubber and baghouse downstream (presumably once the ammonia has

reacted to form an ammonium salt). Permit applicants for other CFB boiler projects typically

predicted 85% or greater removal of ammonia slip prior to the final exhaust stack. Also, Deseret

Power assumed that 100% of the ammonia at the final exhaust stack would be measured as

ammonium bisulfate in the Method 202 impingers. The dominant ammonia salt predicted by

other permit applicants was ammonium sulfate.
77

These underlying estimates and assumptions are inherently difficult to evaluate for

validity, yet greatly affect the predicted level of ammonium salt formation measured by Method

202. The estimate of how much ammonia slip would be removed by a dry scrubber and

baghouse would primarily depend on whether the ammonia reacts to form an ammonium salt,

prior to reaching the dry scrubber and baghouse. Predicting exactly which reactions occur, to

what extent they occur, and whether they occur upstream or downstream of the control

equipment, is difficult. The eventual fate of any free ammonia in the Method 202 impingers is

also difficult to predict. Deseret Power’s assumption that all of the free ammonia would form

ammonium bisulfate would yield a higher mass emission rate than the assumption by other

permit applicants that the free ammonia would form ammonium sulfate. This is due to the

different molar ratio in each reaction equation.

The chemical reactions involving ammonia in the CFB boiler, upstream of the dry

scrubber and baghouse, and in the Method 202 impingers, is very likely more complicated than

either Deseret Power’s or EPA’s calculations suggest. While the calculations referenced above

may provide a rough estimate of this component of condensible PM, EPA is not confident that all

of the chemical reactions that would take place have been accurately accounted for and

quantified. Therefore, EPA examined other CFB permit limits and stack testing data, to compare

to both Deseret Power’s and EPA’s emission estimates for condensible PM at the WCFU, and to

help determine an appropriate BACT emission limit for total PM. Information on other CFB

permit limits and proposed permit limits is summarized in the table below.

Summary of Recent CFB Projects:

Permitted or Proposed Condensible PM Emission Rates

with SNCR / Dry Scrubber / Baghouse Controls

Project / Company

Name

Permit

Authority

Primary Coal

Type

Permit Status

PM10 Emission Rate

(lb/MMBtu)

AES Puerto Rico

Cogeneration Plant

EPA

Region 2

Columbian Coal

Issued 10/29/01

Revised 8/10/04

to raise the total

PM10 limit from

0.015 to 0.03

lb/MMBtu based

on stack testing

0.03 (total PM10)

This limit was originally

0.015 but was adjusted

upward to 0.03 based on

stack testing.

Karthaus Township

CFB Project / River

Hill Power

Company

PA Eastern Waste

Issued 7/21/05

Revised 3/7/06 to

raise total PM10

limit from 0.012 to

0.05

0.05 (total PM10)

Limit may be revised

upon review of CEM

data and stack test

results

Highwood

Generating Station /

Southern Montana

Electric

MT

Western

Subbitmumous

Draft Permit

3/30/06

0.026 (total PM10)
78

Beech Hollow

Energy Project /

Robinson Power

Co. LLC

PA Eastern Waste Issued 4/1/05

0.012 (total PM10)

Limit may be revised

upon review of stack test

results

Greene Energy

Resource Recovery

Project / Wellington

Dvpt, LLC

PA Eastern Waste

Issued 6/21/05

Revised 9/1/05

Revision did not

affect PM10 limit.

0.012 (total PM10)

Limit may be revised up

to a maximum of 0.05

lb/MMBtu if operator

can demonstrate

condensible portion of

PM10 is causing

noncompliance.

Gascoyne

Generating Station /

Montana-Dakota

Utilities Co.

ND Lignite Issued 6/2/05 0.0275 (total PM10)

South Heart Power

Project / Great

Northern Power

Dvpt, L.P.

ND Lignite

Application

8/18/05

0.0132 (condensable

PM10 only)

0.0232 (total PM10

proposed)

East Kentucky

Power Cooperative

/ Spurlock #4

KY

Eastern

Bituminous

Supplemental

Application

1/13/06

Draft Permit

2/14/06

0.012 (total

particulates)

Applicant counterproposes optimization

study with provision to

raise limit no higher

than 0.03 total PM10

As can be seen from the table above, a fairly wide range of emission limits for total PM10

have been either proposed or permitted, from 0.012 lb/MMBtu up to 0.05 lb/MMBtu. Most of

those emission limits have either been adjusted, or, according to language in the permits, have

the ability to be adjusted later by the permitting agency based on stack test results.

EPA’s estimate mentioned above for total PM/PM10 of 0.03 lb/MMBtu, which

incorporates an estimate of 0.019 lb/MMBtu for condensible PM, is about in the middle of the

range of permit limits listed above. It is about the same as the emission limit for the AES Puerto

Rico Cogeneration Plant, after EPA Region 2 adjusted the original limit of 0.015 lb/MMBtu up

to 0.03 lb/MMBtu based on stack testing results. It is also slightly higher than proposed or final

emission limits for other similar CFB boiler projects in Region 8 states (Highwood, Gascoyne,

and South Heart projects). The permit applications for these three projects all contain detailed

engineering calculations to estimate the condensible PM emissions. All three estimates are in

relatively close agreement, leading to very similar proposed or final emission limits for total

PM10 (0.0232 to 0.0275 lb/MMBtu).
79

As explained above, the permit applications for these projects had drastically lower

estimates for the ammonium sulfate component than Deseret Power’s own estimate. EPA

believes the adjusted emission limit in the AES permit of 0.03 lb/MMBtu for total PM10, which

is based on actual operating data, and the proposed or final emission limits for the other three

CFB boiler projects in EPA Region 8 (which are based on consistent engineering calculations),

are the most credible limits of those listed in the table above. Below is an explanation of why

EPA Region 8 has reason to believe the emission limits on the low and high end of the spectrum

of limits in the table above (0.012 lb/MMBtu and 0.05 lb/MMBtu) may not be as credible.

With regard to the Spurlock #4 project in Kentucky, as noted in the table above, the

permit applicant has requested that the draft permit be revised to allow the emission limit of

0.012 lb/MMBtu for total PM10 to be raised to as high as 0.03 lb/MMBtu, based on results of an

optimization study. The requested upper limit is the same as the final adjusted limit for the AES

Puerto Rico project and is the same as EPA’s estimate mentioned above for Deseret Power.

Since Kentucky has not yet issued a final permit for the Spurlock #4 project, it remains to be seen

whether this limit (0.012 lb/MMBtu) will stand, or if the permit will allow for upward

adjustment based on stack testing.

With regard to the projects in Pennsylvania, the proposed or final permit limits for Beech

Hollow and Greene Energy are 0.012 lb/MMBtu for total PM10; however, as noted in the table

above, Pennsylvania recently revised the emission limit for River Hill from 0.012 lb/MMBtu up

to 0.05 lb/MMBtu, with a provision for revising the limit downward again, based on operating

data. Overall, it appears to EPA that Pennsylvania is willing to set total PM10 emission limits

anywhere between 0.012 and 0.05 lb/MMBtu and adjust those limits once operating emission

data are obtained. Because of this wide range of limits, EPA discounts to some degree the

significance of the initial emission limits in these permits.

EPA Region 3 submitted adverse comments to Pennsylvania on the State’s permit action

to raise the total PM10 limit for River Hill from 0.012 lb/MMBtu to 0.05 lb/MMBtu. EPA

Region 3 discounted the purported degree of Method 202 artifact formation cited by River Hill

and Pennsylvania. EPA Region 3 recommended an initial permit limit identical to the adjusted

limit in the AES Puerto Rico permit (0.03 lb/MMBtu) with the ability to revise that limit upward,

if stack testing shows it is not achievable.

Consistent with EPA Region 3’s recommendation, EPA Region 8 does not favor selecting

an upper bound initially in the permit (e.g., Deseret Power’s proposal of 0.045 lb/MMBtu) and

then providing for the limit to be adjusted downward based on operating emissions data. EPA

believes this approach is a disincentive for the source to operate controls optimally during

compliance testing, or to take steps to run the test method as accurately as possible. EPA instead

favors setting an initial emission limit that EPA believes can reasonably be achieved (with

appropriate margin of compliance) and provide for adjusting the limit upward in the event that

stack testing demonstrates it is not achievable.
80

EPA Region 8 believes that allowing for adjustment based on stack testing is an

appropriate approach for total PM/PM10 at Deseret Power because the emission limit

incorporates condensible PM, for which there are limited test data for similar operating plants

and significant uncertainty, explained above, as to the amount of expected emissions.

Deseret Power contends that a total PM/PM10 emission limit lower than 0.045 lb/MMBtu

cannot be guaranteed, presumably because of vendor doubts on whether the limit is achievable.

However, stack testing results at some other CFB facilities indicate that 0.03 lb/MMBtu can be

achieved with a substantial margin of compliance. As mentioned before, the permit limit for

AES Puerto Rico was adjusted from 0.015 lb/MMBtu up to 0.03 lb/MMBtu after stack testing

revealed that 0.015 could not be achieved, but that a limit of 0.03 lb/MMBtu could be achieved.

In its April 2004 Proposed Administrative Changes to the PSD permit application, AES Puerto

Rico submitted stack testing results for AES’s two recently-constructed CFB units. The total

PM10 emissions from Unit 1 and Unit 2 were 0.023 lb/MMBtu and 0.019 lb/MMBtu respectively,

including condensible PM measured by Method 202. (A copy of this information may be found

in the Administrative Record for issuance of Deseret Power’s permit.)

In addition, a December 5, 2004 emissions compliance test report for the Reliant Energy

Seward facility shows emissions of 0.004 lb/MMBtu total PM from Seward’s two CFB units

(equipped with SNCR, baghouse and “fly dryer absorber”), including condensible PM measured

by Method 202. (A copy of that report may be found in the Administrative Record for issuance

of Deseret Power’s permit.)

Furthermore, in a March 31, 2006 comment letter on the draft PSD permit for its

Spurlock #4 unit, East Kentucky Power Cooperative cites a July 8, 2005 stack test, with

emissions of 0.0136 and 0.0113 lb/MMBtu total PM10 from the Gilberton Unit 3 CFB unit

(equipped with SNCR, baghouse, and dry scrubber) including condensible PM measured by

Method 202. (A copy of the comment may be found in the Administrative Record for issuance

of Deseret Power’s permit.)

While we recognize this is a somewhat small set of data and these facilities burn different

coal from that proposed by Deseret Power, these data do demonstrate that a limit of 0.03

lb/MMBtu can be achieved at some CFB units with a large margin of compliance (30% to

750%). Overall, EPA believes there is ample support for proposing an initial total PM/PM10

emission limit for Deseret Power at 0.03 lb/MMBtu on a 30-day rolling average. EPA further

believes this proposal compares much more reasonably to other permit limits and stack test data

than does Deseret Power’s proposal of 0.045 lb/MMBtu.

In several e-mails to EPA, Deseret Power has cited numerous technical papers questioning the reliability of Method 202 and highlighting the effects of artifact formation in the

impingers in skewing test results upward. In a November 23, 2005 e-mail, Deseret Power

proposed to use the following test methodology for condensible PM: “EPA Method 5B (with

filter at 340 ±5 °F): Filterable particulate and USEPA Method 202 (downstream of the Method
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5B train) modified to exclude all inorganic compounds: Organic fraction CH2Cl2 extract and

Parallel Controlled Condensation Method (CCM) with second Method 5B filter (with filter at

340 ±5 °F) upstream of the CCM train: H2SO4 (molecular weight of 98.08) average of three- 4

hour tests.”

EPA Region 8 consulted with EPA’s Office of Air Quality Planning and Standards

(OAQPS) to evaluate this proposed test methodology. OAPQS rejected the proposal, instead

maintaining that the artifact formation from Method 202 can be minimized by properly purging

dissolved SO2 from the sampling solution. In a November 30, 2006 email, Region 8 forwarded

OAQPS’s statement to Deseret Power. Below is the full text of that e-mail, as modified slightly

by OAQPS on April 25, 2006.

We do not think that using Method 5B combined with Method 202 excluding all of the

inorganic compounds and adding the sulfuric acid quantified by a controlled condensation train

provides a reasonable measurement of the total particulate matter emissions to the atmosphere.

We have posted our recommendations on the specific procedures and options available within

Method 202 on our FAQ's page for this method. While the use of the elevated temperature of

Method 5B would only serve to transfer particulate matter from the filter fraction to the impinger

fraction, the additional post test heating of the filter would tend to vaporize any material that

should be considered as particulate matter emissions.

It is recognized that Method 202 has a small positive bias due to the slow conversion of

SO2 to SO3 and then H2SO4. Although the one hour nitrogen purge prevents much of this

conversion, some small bias remains. For many sources which can collect quantifiable

quantities (> 3 mg) of particulate matter in a one hour sample, we think this bias is insignificant

when compared to the overall variability associated with stack sampling. However, for sources

with very low concentrations of particulate matter, even this small bias may still be small

compared to the variability associated with the remainder of the sampling. Ignoring the

variabilities of the particulate filter matter mass, one could portray the bias as a significant

percentage difference in the result.

In order to overcome the difficulties associated with the collection of sample in water,

EPA developed a dilution based sampling system that replicated the particulate formation

mechanisms that occur at operating emissions sources. The development of a dilution sampling

method was recommended by the National Academy of Sciences in their 2000 report "Research

Priorities for Airborne Particulate Matter" (see page 56 of the attached excerpt from this

report). We have posted the dilution based sampling method on the Emissions Measurement

Center web site as Conditional Test Method 39 ( see the methods near the bottom of

http://www.epa.gov/ttn/emc/ctm.html ). We have performed limited comparisons of CTM39 and

Method 202 and found that these methods provide comparable results.
82

Deseret Power responded to EPA in a December 21, 2005 email as follows.

The equipment supplier needs to know the test methodology before a total PM10 limit can

be established. This is due to the substantial positive bias in using Reference Method 202 to

determine condensable particulate matter. Deseret’s November 23, 2005 email provided EPA

with the supplier’s proposed test method to compensate for the substantial positive bias

associated with Reference Method 202. As recommended by EPA, Deseret has reviewed the

questions and answers on EPA’s website associated with Method 202. We did not find any

answers on EPA’s website that would change our concerns about Method 202.

EPA also recommended using CTM-039 in lieu of Method 202. However, neither

Deseret nor its supplier has any experience with conditional test method 39. Therefore, we

cannot base compliance with an emission limit on a test method that we do not have any

experience with. We again request EPA to review the supplier’s proposed test method sent to

you with the November 23

rd

email and advise if it is acceptable. If EPA insists on using Method

202 without any modifications, then we need to discuss how to adjust the total emission limit to

allow for the significant positive bias associated with using Method 202.

The EPA position presented to Deseret Power was similarly articulated in EPA Region

3’s February 6, 2006 comment letter to Pennsylvania on the River Hill permit revision.

We respond to these assertions by discussing some results from EPA’s research into the

efficacy of EPA’s Method 202. According to EPA’s research, varying the concentration of sulfur

dioxide in the flue gas has a limited effect on the amount of condensable particulate matter

measured by Method 202. In short, we found that SO2 from flue gas dissolved in sampling water

reaches a saturation point allowing no more SO2 in solution. Thus in order for the applicant’s

SO2 argument to hold true, additional sample water must be introduced to absorb more SO2

from the higher SO2 concentration of River Hill Power Plant’s flue gas (compared to that of the

Puerto Rican Power Plant).

A recent report from EPA has shown that there is a constant 20 ppm condensable

particulate creation (known as artifact) in the water used in the sample train for Method 202.

EPRI has also alleged a flaw with Method 202 is that dissolved SO2 cannot be sufficiently

purged from the sample water to give meaningful condensable PM-10 results. EPA, however,

has data from a recently conducted laboratory study showing the purge method used in Method

202 rids the system of 90 to 95 % of the dissolved SO2. EPA has also recommended an

alternative sampling method using air dilution [CTM-039], which eliminates the issue of SO2

causing potentially high artificial results.

In conclusion, we feel that the applicant is correct in its statement that there is limited

data available regarding condensable PM-10 from coal-fired power plants and in particular,

waste coal-fired plants. We recognize that the applicant has spent a lot of time researching this

issue and has committed to installing the appropriate and most up-to date control equipment for
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PM-10 emissions. Based on discussions with engineers and scientists at EPA, we are convinced

that Method 202 can be a valid method to use if the purging procedure is correctly performed.

However, we feel that alternative testing methods should be made available if they are

appropriate.

EPA recommends an alternative sampling method (known as conditional test method 39

or CTM 039) using air dilution which is suitable for determining both filterable and condensable

components of PM-10, and it eliminates the issue of SO2 in flue gas causing potentially high

artificial results. We have determined that SO2 from flue gas has limited effect on the

measurement of condensable PM-10. In addition, actual stack testing on the AES plant in Puerto

Rico shows that condensable PM-10 is emitted from the power plant in lower amounts than

originally theorized. In light of these conclusions, EPA feels that a limit of 0.030 lb, PM-10

should be initially established, until data is obtained from stack testing determines the actual

emission factor. The stack test data obtained should be used to establish the permanent total

PM-10 limit. If the stack testing shows a higher limit than the permit contains, the PADEP will

be able to revise that limit in consultation with EPA.

Clearly, EPA and Deseret Power do not agree on the effect of potential artifact formation

associated with Method 202. While EPA does acknowledge a small degree of bias, EPA has

found it to be insignificant. EPA Region 8 agrees with the position taken by EPA Region 3, that

initially establishing a total PM10 limit of 0.03 lb/MMBtu represents BACT for total PM/PM10.

EPA Region 8 also agrees with Region 3’s position that it is appropriate to allow for an upward

adjustment of that limit, if stack testing shows that the initial limit is not achievable, based on

contributions from the condensible PM portion.

In summary, EPA proposes the following permit language:

The Permittee shall not discharge or cause the discharge of total particulate matter

(including condensible particulate matter) from the CFB boiler to the atmosphere in

excess of 0.03 lb/MMBtu heat input, on a 24-hour block average (midnight to

midnight), of which the filterable (non-condensible) portion shall not exceed 0.012

lb/MMBtu heat input on 24-hour block average. The same emission limits shall

apply for PM10.

Because condensible particulate matter emissions from fluidized bed boilers have

not been widely quantified, there is a possibility that the actual condensible portion

of particulate matter would cause the PSD BACT emission limit in this permit of

0.03 lb/MMBtu for total PM/PM10 to be exceeded. In such event, EPA may adjust

the emission limit to a level not to exceed 0.045 lb/MMBtu, pending EPA's review of

stack test results.

As explained above, EPA believes this adjustable limit approach is an acceptable

approach, which has been supported in the past by the Environmental Appeals Board.
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(Reference: In re AES Puerto Rico L.P. (May 27, 1999).) EPA further believes this approach

should address Deseret Power’s concern about meeting a guaranteed limit, since the final limit

will essentially be dependent on actual stack testing data. EPA notes that 0.045 lb/MMBtu is less

than the emission rate used in the air quality modeling analysis for the WCFU project.

As explained earlier in this Statement of Basis, for the proposed WCFU, Deseret Power

will be permitted to use coal from the Deserado mine consisting of either waste coal alone, or

else a blend of waste coal and ROM coal yielding heat content of up to 6,500 Btu/lb. For reasons

explained above, EPA believes the proposed BACT emission limit of 0.03 lb/MMBtu on a

rolling 30-day average, for total PM/PM10, will represent BACT for coal from the Deserado mine

with heat content of up to at least 6,500 Btu/lb, and will ensure a continued high degree of PM

emission control efficiency.

6. Comparison to applicable NSPS emission standard.

Since 40 CFR 60, Subpart Da contains no emission standard that incorporates

condensible PM, there is no comparison to make.

7. Proposed compliance monitoring.

For measuring the condensible portion of PM, EPA proposes to require annual stack tests

using Method 202. In lieu of Method 202, the Permittee shall be allowed to use Conditional Test

Method 39 (CTM-039). For demonstrating compliance with the BACT limit for total PM/PM10

(filterable plus condensible), EPA proposes to require that the emissions data from the PM

CEMS, in lb/MMBtu on a 24-hour block average, be added to the results of the latest stack test

for condensible emissions, also expressed in lb/MMBtu.
85

J. BACT for CO Emissions from CFB Boiler.

Emissions of CO result from the incomplete combustion of carbon and organic

compounds. CO emissions are a function of oxygen availability (excess air), flame temperature,

residence time at furnace temperature, combustor design, and turbulence.

In addition to the potential control technologies listed in Step 1 below, clean fuels (i.e.,

alternative coal, either from the Deserado mine or another mine) is also a possible option for

BACT, but has already been eliminated as cost-prohibitive for BACT, for all pollutants at this

project. This was explained earlier in this Statement of Basis.

1. Step 1: Identify Potential Control Technologies.

The only potential CO control technologies known to EPA for CFB boilers are the

following:

a. Catalytic oxidation

b. Combustion controls

Catalytic oxidation consists of oxidation, in the flue gas, of any CO formed in the combustion

process. Combustion controls consist of combustion modifications to minimize the formation of

the pollutant.

2. Step 2: Eliminate Technically Infeasible Options.

Combustion controls are technically feasible but catalytic oxidation is not, for reasons

described below.

a. Catalytic Oxidation. Catalytic oxidation is the control technology

used to obtain the most stringent control level for CO from gas turbine combustion units. This

technology has never been applied to a coal fired unit, however. For catalytic oxidation, a

catalyst is situated in the flue gas stream, which would lower the activation energy of a series of

reactions where reactant species, such as CO, are converted to carbon dioxide and water. The

catalyst permits the combination of the reactant species at lower gas temperatures than would be

required for uncatalyzed oxidation.

The catalyst would be located at a point where the gas temperature is within an acceptable

range. The effective temperature range for CO oxidation is between 600 and 1150 F. In a CFB,

this means that the catalyst grid would need to be installed at a point upstream of the particulate

matter control device.
86

Catalyst non-selectivity is a problem for sulfur containing fuels such as coal. Catalysts

promote oxidation of SO2 to SO3 as well as CO to CO2. The amount of SO2 conversion is a

function of temperature and catalyst design. Under optimum conditions, formation of SO3 can be

minimized to 2% of inlet SO2. Compared to the proposed emissions level, this level of

conversion would increase H2SO4 emissions and would result in corrosion to the air preheater

and ductwork.

Catalysts require intimate contact with the flue gas and some residence time to be

effective. For best utilization, catalyst plates are closely spaced. Flue gas from a CFB firing high

ash, low-grade waste coal will contain a very large amount of fly ash, which could cause high

erosion of the catalyst and potential pluggage. Specially designed catalyst with wider spacing

would need to be provided to accommodate the very high ash loading which would decrease its

effectiveness, requiring more layers of catalyst to compensate. In the available open literature, it

does not appear that this has been done on a CFB, and it is not considered technically feasible

b. Combustion Controls. The other means of controlling CO

emissions is through the design and operation of the boiler in a manner so as to limit CO

formation. Such controls are commonly referred to as combustion controls. In general, a

combustion control system seeks to maintain the proper conditions to ensure complete

combustion through one or more of the following operation design features: high excess air,

staged combustion, overfire air, sufficient residence time, and good mixing. In the case of the

proposed project, the boiler itself will incorporate design features, which enhance uniform

fuel/air distribution and mixing, along with oxygen monitoring and adjustment of the staged air

combustion to suppress CO formation.

3. Step 3: Rank Remaining Control Technologies by Control Effectiveness.

Since the only technically feasible control technology is combustion controls, no ranking

is necessary.

4. Step 4: Evaluate Economic, Environmental and Energy Impacts.

Since the proposed project will implement combustion controls as the only technically

feasible option to reduce CO emissions, review of economic, environmental, and energy impacts

is not necessary.

5. Step 5: Proposed CO BACT for CFB Boiler.

Deseret Power searched EPA’s RACT/BACT/LAER Clearinghouse database and

California Air Resources Board (CARB) listings for coal fired CFB boilers, which report limits

on CO emissions. The table below presents a summary of facilities utilizing CFB boiler

technology and employ combustion controls for CO reduction.
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Comparison of CFB Boiler CO Emission Rates

using Combustion Controls:

RACT/BACT/LAER Clearinghouse and CARB Data

Facility RBLC ID Heat Input

mmBtu/hr

CO Emissions

lb/mmBtu

Fuel

AES-PRCP PR-0007 4922.7 0.10 Columbian Coal

Reliant Energy MidAtlantic PowerPA-0182 2532.0 0.15 Coal

Archer Daniels

Midland (9&10)

IL-0060 1500.0 0.1 Coal

Choctaw Generation MS-0036 2475.6 0.2 Lignite

Archer Daniels

Midland (5&6)

IA-0046 1500.0 0.15 Coal

Archer Daniels

Midland

IA-0051 1500 0.15 Bituminous Coal

Kimberly Clark PA-0204 799 No limit Coal

Toledo Edison OH-0231 1764 0.13 Pet Coke

York County Energy

Partners

PA-0132 2500.0 No limit Bituminous Coal

Northampton

Generating Co.

PA-0134 1146.0 0.15 Anthracite Culm

Westwood Energy PA-0124 423 No limit Anthracite Culm

Gilberton Power PA-0110 520 No limit Anthracite Culm

Archer Daniels

Midland (7&8)

IL-0058 1500 0.1 Coal

Energy New Bedford

Cogeneration

MA-0028 1671.0 0.14 Eastern US Coal

AES Warrior Run MD-0022 2070.0 0.15 Eastern US Coal

Archer Daniels

Midland

IA-0025 551.5 0.2 Coal

Energy New Bedford

Cogeneration

MA-0009 3342.0 0.018 Eastern US Coal

Tauton Energy

Center

MA-0011 1604.4 0.13 Eastern US Coal

North Branch Energy

Partners

PA-0058 563.5 0.15 Waste Bit. Coal

The facility with the lowest listed CO emission limit is Energy New Bedford

Cogeneration (MA-0009), at 0.018 lb/MMBtu. Another Energy New Bedford facility (MA0028) is listed at 0.14 lb/MMBtu. Deseret Power informed EPA (via February 7, 2006 e-mail)

that they asked the Massachusetts Division of Air Quality about the status of these two facilities
88

and was told that the permits were issued in April 1993 for MA-0009 and in July 1994 for MA0028, but neither facility was built.

Two Archer Daniels Midland facilities and the AES-PRCP facility are listed with CO

emission limits of 0.10 lb/MMBtu; however, these facilities all use coal with much higher heat

content than Deseret Power’s coal, which means these facilities should be able to achieve a lower

CO emission rate in lb/MMBtu than Deseret Power’s proposed WCFU. Deseret Power has

stated (via April 14, 2006 e-mail to EPA) that the ADM facilities both use a blend of Illinois coal

with a heat content of 12,000 to 13,000 Btu/lb and Powder River Basin (Wyoming) coal with a

heat content of approximately 8,500 Btu/lb. The ADM facilities are also permitted to utilize

wood and shredded tires for up to 10% of the fuel, such that the heat content of the overall fuel

averages 10,000 to 11,000 Btu/lb.

Deseret Power has also stated (via April 14 and 16, 2006 e-mails to EPA) that the AESPRCP facility burns Columbian coal with a heat content range of 10,500 Btu/lb to 12,000 Btu/lb.

Average heat content is 11,300 Btu/lb. By contrast, Deseret Power’s “average” waste coal has

heat content of about 4,000 Btu/lb. Blending the waste coal with run-of-mine coal from the

Deserado mine at up to a 50/50 ratio (which Deseret Power has requested for operational

flexibility) would yield heat content of about 6,500 Btu/lb.

Three other facilities are listed above with CO emission limits below 0.15 lb/MMBtu:

Toledo Edison (OH-0231), Energy New Bedford Cogeneration (MA-0028) and Tauton Energy

Center (MA-0011). Deseret Power has stated (via February 8, 2006 e-mail to EPA) that the heat

content of the coal for all facilities listed above, except for Northampton, Westwood, Gilberton

and North Branch (which are listed with waste coal or anthracite culm), is higher than the heat

content of the waste coal for Deseret’s WCFU. Again, the higher heat content means these

facilities should be able to achieve a lower CO emission rate in lb/MMBtu than Deseret Power’s

proposed WCFU. The Northampton and North Branch facilities are listed with CO emission

limits of 0.15 lb/MMBtu. No CO emission limits are listed for the Westwood and Gilberton

facilities.

Besides having lower heat content than the coal for other CFB boiler projects, Deseret

Power’s waste coal will have higher ash content as well. Deseret Power has stated (via February

8, 2006 e-mail to EPA) that this results in higher CO emissions, due to some ash having carbon

entrapped within the ash particle that is not released until the particle is above the combustion

zone in the CFB boiler. Some of this carbon will form CO rather than being combusted.

Another consideration in determining the achievable CO emission rate for Deseret

Power’s proposed WCFU is the NOx emission rate that must also be achieved. EPA is proposing

a relatively stringent NOx BACT emission limit of 0.080 lb/MMBtu. Since generation of NOx

and CO are inversely related to each other, achieving such a low NOx limit makes it difficult to

also achieve a low CO limit. Lower temperature and lower excess oxygen will lead to lower

NOx, but will also result in higher CO due to incomplete combustion. Facilities with higher NOx
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limits can achieve lower CO limits. The following facilities from the table above have NOx

limits that are same as proposed for Deseret Power’s WCFU, or higher, and with CO emission

limits of 0.15 lb/MMBtu or higher:

Reliant Energy Mid-Atlantic Power

Choctaw Generation

Northampton Generating Co.

AES Warrior Run

North Branch Energy Partners

In assessing the CO emission rates that the proposed WCFU can achieve, Deseret Power

has stated (in its November 1, 2004 PSD permit application) that they have tried to optimize all

relevant factors in the context of efforts to reduce NOX emissions; however, those efforts tend to

increase CO emissions. In light of the NOX reductions discussed above, Deseret Power has

stated that the lowest emission level that can be consistently achieved and guaranteed by its

vendor is 0.15 lb/mmBtu, from 70 to 100% of design load. As explained above, this emission

rate is at least as stringent as CO emission limits for other CFB boilers listed in the RBLC that

combust either waste coal or blended coal with heat content as low as Deseret’s waste coal or

blended coal.

For operation at below 70% of design load, Deseret Power proposed an alternate CO

BACT emission limit of 155 lb/hr. EPA cannot consider this proposal justifiable as BACT for

operation below 70% of design load, because it is equivalent to 0.15 lb/MMBtu times 70% of the

full load heat input capacity of the boiler (1,445 MMBtu/hr). EPA proposes the following CO

emission limit, applicable at all times:

0.15 lb/MMBtu on a 30-day rolling average

As explained earlier in this Statement of Basis, Deseret Power will be permitted to use

coal from the Deserado mine, consisting of either waste coal alone, or else a blend of waste coal

and run-of-mine coal yielding heat content of up to 6,500 Btu/lb. For reasons explained above,

EPA believes the proposed CO BACT emission limit of 0.15 lb/MMBtu on a rolling 30-day

average, will represent BACT up to at least a 50/50 blend ratio.

6. Comparison to applicable NSPS emission standard.

Since 40 CFR 60, Subpart Da contains no emission standard for CO, there is no

comparison to make.

7. Proposed compliance monitoring approach.

For compliance demonstrations, EPA proposes to require CO CEMS. EPA proposes to

allow the diluent cap approach from 40 CFR part 75 for calculating emissions in lb/MMBtu, in
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the event of very low boiler load, such as during startup or shutdown. This approach was

developed by EPA in Part 75 to address low-load situations at electric utility boilers. Further

explanation of the diluent cap approach may be found in section VI.J.5 of this Statement of

Basis, at the end of Step 5 of the SO2 BACT discussion.
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K. BACT for SO2 Emissions from CFB Boiler

In addition to the potential control technologies listed in Step 1 below, clean fuels (i.e.,

alternative coal, either from the Deserado mine or another mine) is also a possible option for

BACT, but has already been eliminated as cost-prohibitive for BACT, for all pollutants at this

project. This was explained earlier in this Statement of Basis.

1. Step 1: Identify Potential Control Technologies.

From fossil fuel fired sources, emissions of SO2 and other related compounds, such as

total reduced sulfur and reduced sulfur compounds, are generated from the release of sulfur in the

fuel. Upon combustion, approximately 98% of sulfur in solid fuels is emitted as gaseous sulfur

oxides. Sulfur dioxide, related sulfur compounds, sulfuric acid mist, and hydrogen fluoride,

commonly referred to as acid gases, are all controlled by the technologies listed below. All these

technologies are considered by EPA to be potential control technologies for SO2 at CFB boilers.

a. Limestone injection

b. Dry scrubbing

(i) Spray dry absorber

(ii) Circulating dry scrubber

(iii) Hydrated ash reinjection

(iv) Dry sorbent injection

c. Wet scrubbing

2. Step 2: Eliminate Technically Infeasible Options.

With the exception of dry sorbent injection and alternative coal from other mines, all

technologies listed above are considered technically feasible for SO2 control at CFB boilers.

Below is a discussion of each technology.

a. Limestone injection. Limestone injection is technically feasible

and is typically an inherent part of the combustor design for “second generation” CFB

combustors. Crushed limestone is fed to the CFB combustor, becoming the solid medium in

which coal combustion takes place. When limestone is heated to 1550 F, it releases CO2 and

forms lime (CaO), which subsequently reacts with acid gases released from the burning coal, to

form calcium sulfate (CaSO4). The CaSO4 product is removed from the flue gas in the

particulate collector or directly from the furnace.

In theory, 100% SO2 removal could be achieved with a Ca/S ratio of 1.0. In practice,

however, the desulfurization process results in less than complete utilization of the injected

limestone. It has been found that only about 50% of the SO2 is removed at a Ca/S ratio of 1. As

Ca/S ratio is increased above 1, greater desulfurization can be achieved, but with diminishing

return. Typically, CFB boilers are designed with a Ca/S stoichiometric ratio of 1.5, although
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ratios of up to 2.0 to 2.3 have been proposed by recent CFB permit applicants. In emission

calculations submitted to EPA, Deseret Power has indicated that it expects limestone injection at

the new WCFU to achieve SO2 control efficiency of about 85%, for both “design” coal and

“average” coal.

b. Dry scrubbing.

(i) Spray dry absorber. SDA systems are used in large utility

boilers and have demonstrated 90-94% SO2 removal efficiency in pulverized coal fired boilers.

An SDA system is also used at a CFB boiler in Jacksonville, Florida. Deseret Power has stated

that an SDA system could be installed at the WCFU, and has proposed to do so. Deseret Power

estimates that about 98.8% control efficiency is achievable with SDA plus limestone injection at

the WCFU, when firing “design” coal (3,000 Btu/lb and 0.71% sulfur content). Deseret

estimates that the SDA could provide about 92.3% control efficiency for the SO2 that remains

after limestone injection controls, for the “design” coal.

The typical SDA system uses a lime and water slurry injected into the absorber tower to

remove SO2 from the combustion gases. The towers must be designed to provide adequate

contact and residence time between the exhaust gas and the slurry to produce a relatively dry byproduct.

Designing an SDA for use with a CFB boiler presents significant challenges. First, the

SDA must be located upstream of particulate controls, at a point where the CFB boiler flue gas is

already laden with combustion ash, calcium sulfite solids, and unreacted lime from the

combustion bed. An SDA will add unreacted hydrated lime to the flue gas, and increase

particulate loading to the particulate control device.

(ii) Circulating dry scrubber. A Circulating Dry Scrubber

(CDS) uses a circulating fluidized bed of dry hydrated lime reactant to remove SO2. Flue gas

passes through a venturi at the base of a vertical reactor tower and is humidified by a water mist.

The humidified flue gas then enters a fluidized bed of powdered hydrated lime where SO2 is

removed. The dry by-product produced by this system is similar to the SDA by-product, and is

routed with the flue gas to the particulate control system.

CDS equipment vendors claim that CDS systems can achieve SO2 removal efficiencies

similar to those achieved by SDA systems. However, thus far, CDS systems have had limited

application, and have not been used on large pulverized coal fired boilers or CFB boilers. The

largest CDS unit, in Austria, is on a 275-megawatt oil-fired boiler burning 1.0% to 2.0% sulfur

oil. Operating experience on smaller PC-fired boilers in the U.S. has shown high lime

consumption rates, and significant fluctuations in lime utilization, based on inlet SO2 loading.

Furthermore, CDS systems result in high particulate loading to the unit’s particulate control

device. Because of the high particulate loading, the pressure drop across a fabric filter may

become unacceptable, and electrostatic precipitators are generally used for particulate control.
93

(iii) Hydrated ash reinjection. Hydrated ash reinjection is a

modified dry FGD process developed to increase utilization of unreacted CaO in the CFB ash

and further reduce the SO2 concentration in the flue gas. In a hydrated ash reinjection system, a

portion of the unit’s ash is collected, hydrated and re-introduced into a reaction vessel located

ahead of the fabric filter inlet duct. In conventional boiler applications, additional lime may be

added to the ash to increase the mixture alkalinity; however, for CFB applications sufficient

residual CaO is available in the ash and additional lime is not required.

Two CFB units have recently been permitted with hydrated ash reinjection systems.

Based on review of the technical literature, and on information provided by system vendors, it is

anticipated that use of a hydrated ash reinjection system would result in a slight reduction in the

CaS ratio in CFB boilers. Based on vendor information, it is estimated that the hydrated ash

reinjection, downstream of a CFB boiler that utilizes limestone injection, could reduce the

remaining SO2 by about 80%.

(iv) Dry sorbent injection. Dry sorbent injection involves the

injection of powdered absorbent directly into the flue gas exhaust stream. Dry sorbent injection

systems are simple systems, and generally require a sorbent storage tank, feeding mechanism,

transfer line and blower, and an injection device. The dry sorbent is typically injected countercurrent to the gas flow. An expansion chamber is often located downstream of the injection

point, to increase residence time and efficiency.

A dry sorbent injection system is not practical for use in a CFB boiler. The CFB boiler

flue gas already contains excess unreacted lime and fly ash will be reinjected back into the CFB

boiler combustion bed. A dry sorbent injection system would simply add additional unreacted

lime to the flue gas. Furthermore, SO2 control efficiencies for dry sorbent injection systems are

typically only about 50% on units with a much higher uncontrolled SO2 concentration in the flue

gas. If used in conjunction with a CFB unit (with a relatively low SO2 concentration in the flue

gas), and especially if used at Deseret’s proposed WCFU where the coal itself has relatively low

sulfur content, the control efficiency would probably be substantially below 50%. While it could

be argued that dry sorbent injection is technically feasible at CFB boilers, EPA believes, for the

reasons just described, that dry sorbent injection should be eliminated from further consideration

in this BACT analysis.

c. Wet scrubbing. Wet flue gas desulfurization (FGD) scrubbers are

typically used to control SO2 emissions from pulverized coal fired boilers. Although EPA is not

aware of any CFB boilers equipped with a wet scrubbing system, EPA is also not aware of any

reason why wet FGD would be technically infeasible at a CFB boiler.

Wet FGD systems use either lime or limestone slurry as the scrubbing liquid. The wet

lime scrubbing process uses an alkaline slurry made by adding CaO to water. The alkaline slurry

is sprayed in the absorber and reacts with SO2 in the flue gas. Insoluble calcium sulfite and
94

calcium sulfate solids are formed in the scrubber and are removed as a wet byproduct, which

must be dewatered prior to disposal. Limestone scrubbers are very similar to lime scrubbers,

except that limestone slurry is used as the scrubbing liquid rather than lime. This requires a

higher liquid-to-gas ratio than lime scrubbing and therefore a larger absorbing unit.

Wet FGD systems have achieved control efficiencies of approximately 96% on large PC

boilers firing high-sulfur bituminous coals. Deseret Power has estimated that a wet FGD

installed downstream of the CFB combustor for the WCFU, after 85% removal by limestone

injection, could remove about 94% of the remaining SO2, for an overall SO2 removal efficiency

of about 99.1% (limestone injection + wet FGD).

3. Step 3: Rank Remaining Control Technologies by Control Effectiveness.

Since limestone injection will be an inherent part of the CFB boiler design, it is included

as part of all options listed below, with assumed control efficiency of 85%. The options are

ranked as follows, in terms of potential SO2 control efficiency, from most to least efficient:

a. Wet FGD scrubber + limestone injection 99.1%

b. Spray dry absorber + limestone injection 98.8%

c. Circulating dry scrubber + limestone injection 98.8%

d. Hydrated ash reinjection + limestone injection 97.0%

4. Step 4: Evaluate Economic, Environmental and Energy Impacts.

Since wet FGD scrubber + limestone injection has been ranked higher than spray dry

absorber + limestone injection, this Step 4 will compare the impacts of both, to determine if wet

FGD scrubber should be eliminated and the next most effective option chosen (SDA + limestone

injection).

Both wet and dry FGD control system designs are technically feasible and capable of

achieving very stringent SO2 emission rates. Deseret Power estimates that for its “design” coal

scenario, an FGD system designed as a wet FGD appears capable of achieving a controlled SO2

emission rate of 0.045 lb/MMBtu and a dry FGD control system is capable of achieving a

controlled SO2 emission rate of 0.055 lb/MMBtu (30-day rolling average). To achieve these

emission rates, these control systems, coupled with the CFB boiler with limestone injection, will

have to achieve an average overall control efficiency of approximately 99%. An evaluation of

the economic, energy and environmental impacts of each control system is provided below.

Wet FGD systems are considered technically feasible control systems based on an

engineering review of the technology, however, there are no wet FGD systems in operation with

a CFB unit and there is no commercial operating history upon which to base expected SO2

emission rates. The SO2 emission rates used in this BACT analysis for a wet scrubber were based

on the assumption that a wet FGD system could lower the controlled emission rate from 0.055
95

lb/MMBtu which can be achieved with a dry scrubber to 0.045 lb/MMBtu.

Economic Evaluation

Summarized in the table below are the expected controlled SO2 emission rates, and maximum

annual SO2 emissions, associated with wet and dry FGD systems based on the design sulfur coal.

Also shown are the capital costs and annual costs associated with building and operating each

control system. The table also presents the average annual control efficiency for each SO2 control

system. A detailed summary of the cost estimates used in this BACT determination is attached.

A CFB boiler with limestone injection is an inherently low SO2 emitting technology, and

can be designed to remove approximately 85% of the potential SO2 with limestone injection.

The incremental cost of $10,540 per ton of removed SO2 to install a wet scrubber rather than a

dry scrubber is too high to justify the expenditure. Based on “average” coal for the proposed

WCFU, the incremental cost is $28,054 per ton of additional removed SO2 to go from dry

scrubber to wet scrubber, also too expensive to justify.

Comparison of Wet FGD to Dry FGD for WCFU,

Downstream of Limestone Injection Controls:

Costs and Emission Rates

Parameter Wet FGD with Limestone

Injection, for “design” coal

Dry FGD with Limestone

Injection, for “design” coal

Controlled SO2 Emission

Rate (lb/MMBtu)

0.045 0.055

Overall Control Efficiency 99.1% 98.8%

Maximum SO2 Emissions

(tpy)

285 350

Total Capital Cost ($) 20,211,840 13,379,115

Total Capital Cost ($/kw) 202 134

Total Annual Costs ($/yr) 12,410,610 11,747,546

Annual SO2 Removed (tpy) 26,675 26,612

Average Annual Cost per

Ton ($/ton)

418 397

Incremental SO2 Removed

(tpy)

63 ---

Incremental Cost per Ton

($/ton)

10,540 ---

Environmental Impacts of Wet FGD

In addition to the adverse economic impacts of a wet FGD system versus a dry FGD

system, there are several collateral adverse environmental impacts associated with a wet FGD
96

system. Wet FGD systems generate a CaSO4 waste by-product that must be properly managed.

Solid wastes generated from wet FGD systems at the Bonanza site will have to be dewatered and

disposed of in the landfill. A wet FGD system will also result in greater particulate matter

emissions. Wet FGD systems must be located downstream of the unit’s particulate control

device, therefore, dissolved solids from the wet FGD system will be emitted with the wet FGD

moisture plume. In addition, any SO3 remaining in the flue gas could react with moisture in the

wet FGD to generate H2SO4. H2SO4 is classified as a condensible particulate. Wet FGD systems

also require significantly more water than the dry FGD system. This is an especially important

consideration for Deseret’s project, which will be located in an arid region of Utah. Also, wet

FGD systems generate a wastewater stream that must be treated and discharged to evaporation

ponds.

Environmental Impacts of Dry Scrubbing

Collateral environmental impacts are less significant with dry FGD than wet FGD. Using

a dry FGD system in conjunction with a CFB boiler will require the facility to handle two

reactants: limestone for injection in the CFB boiler and pebble lime for use in the dry scrubber.

The receipt, storage, management and use of two reactants could result in a slight increase in

material handling particulate matter emissions. Lime in a dry FGD is hydrated prior to use,

therefore using a dry FGD system will increase the facility’s overall consumption of water but

much less than a wet FGD system would. Water used to hydrate the lime will be evaporated in

the absorber vessel, and using a dry FGD should not result in the generation of a wastewater

stream.

Summary – Elimination of Wet FGD as BACT Control Option

Limestone injection + wet FGD is eliminated as a BACT control option, based on

economic impacts of wet FGD (unacceptably high incremental SO2 removal costs) and

environmental impacts of wet FGD (increased particulate matter and condensible particulate

matter emissions; increased waste that is generated and has to be disposed of). Since the next

most effective option is limestone injection + dry FGD, this option is selected as BACT.

5. Step 5: Proposed SO2 BACT for CFB Boiler.

Deseret Power searched the RACT/BACT/LAER Clearinghouse and located the

following SO2 BACT determinations for CFB boilers:
97

Comparison of CFB Boiler SO2 Emission Rates:

RACT/BACT/LAER Clearingthouse Data

Facility RBLC

ID

Heat Input

mmBtu/hr

SO2

Emissions

lb/mmBtu

Control Fuel

AES-PRCP PR-0007 4922.7 0.022 Limestone

and Dry

Scrubber

Columbian

Coal

Reliant Energy

Mid-Atlantic

Power

PA-0182 2532.0 0.6 Fly ash

Reinjection

Coal

Archer Daniels

Midland (9&10)

IL-0060 1500.0 0.7 Limestone Coal

Choctaw

Generation

MS00362475.6 0.25 Lime Lignite

Archer Daniels

Midland (5&6)

IA-0046 1500.0 0.36 Limestone Coal

Archer Daniels

Midland

IA-0051 1500 0.36 Limestone Bituminous

Coal

Kimberly Clark PA-0204 799 No limit Not stated Coal

Toledo Edison OH02311764 0.6 Limestone Pet Coke

York County

Energy Partners

PA-0132 2500.0 0.25 Lime Bituminous

Coal

Northampton

Generating Co.

PA-0134 1146.0 0.129 Lime Anthracite

Culm

Westwood

Energy

PA-0124 423 No limit Not stated Anthracite

Culm

Gilberton Power PA-0110 520 No limit Not stated Anthracite

Culm

Archer Daniels

Midland (7&8)

IL-0058 1500 0.7 Limestone Coal

Energy New

Bedford

Cogeneration

MA00281671.0 0.23 Limestone Eastern US

Coal

AES Warrior

Run

MD00222070.0 0.21 Limestone Eastern US

Coal

Archer Daniels

Midland

IA-0025 551.5 No limit Not stated Coal

Energy New

Bedford

Cogeneration

MA00093342.0 0.23 Limestone Eastern US

Coal
98

Tauton Energy

Center

MA00111604.4 0.23 Limestone Eastern US

Coal

North Branch

Energy Partners

PA-0058 563.5 0.49 Limestone Waste Bit.

Coal

One CFB facility, AES-Puerto Rico, was permitted with limestone injection plus a dry

scrubber and a controlled SO2 emission rate of 0.022 lb/MMBtu. However, the AES-Puerto Rico

permit also requires the facility to fire a high-heating value low-sulfur coal. Based on

information in the permit application, maximum uncontrolled SO2 emissions from the AES fuel

will be approximately 1.3 lb/MMBtu, for ‘worst-case’ coal. Therefore, the facility will have to

achieve an overall SO2 control efficiency of approximately 98.3% to meet its permit limit when

firing ‘worst-case’coal.

The “design” fuel for Deseret’s project has an uncontrolled SO2 emission rate of 4.73

lb/MMBtu, more than twice the worst case SO2 emission rate calculated for the AES-Puerto Rico

facility. Therefore, in order to achieve a controlled emission rate of 0.055 lb/MMBtu on

“design” coal for its proposed WCFU, Deseret will have to achieve a control efficiency of 98.8%,

higher than the control efficiency proposed at AES-Puerto Rico. However, there are additional

considerations when comparing Deseret’s proposed WCFU to the AES-Puerto Rico project.

This is discussed later in this analysis.

Utah recently permitted a new 275-megawatt CFB unit, known as Nevco Energy (a.k.a.

Sevier Power Plant), for which limestone injection + dry FGD has been determined as BACT for

SO2 control. The SO2 BACT emission limits are 0.05 lb/MMBtu (24-hour rolling average) and

0.022 lb/MMBtu (30-day rolling average). The CFB unit will be fired on western bituminous

coal with an average sulfur content of 0.25% and a worst-case sulfur content of 0.9%. Based on

a worst-case (i.e., lower) heating value of 10,200 Btu/lb, the uncontrolled SO2 emission potential

for Nevco will range from 0.49 lb/MMBtu (average) to 1.76 lb/MMBtu (worst-case), less than

one-half the uncontrolled SO2 emission potential of “design” coal for Deseret’s WCFU project.

The Nevco plant will have to achieve a control efficiency of 95.5% to reduce the average

emissions from 0.49 lb/MMBtu to 0.022 lb/MMBtu, and a control efficiency of 97.16% to reduce

the worst-case emissions from 1.76 lb/MMBtu to 0.05 lb/MMBtu. As mentioned above, for its

“design” coal scenario, Deseret Power calculates that the emission limit of 0.055 lb/MMBtu they

have proposed as BACT would equate to 98.8% SO2 control.

To summarize Deseret Power’s BACT proposal: Deseret Power proposed 0.055

lb/MMBtu on a 30-day rolling average as SO2 BACT, using limestone injection plus dry scrubber

(spray dry absorber). This proposed emission limit is based on the “design” waste coal (3,000

Btu/lb heat content and 0.71% sulfur content). As stated above, the “design” waste coal has

uncontrolled SO2 emission potential of about 4.73 lb/MMBtu, such that to achieve an emission

rate of 0.055 lb/MMBtu, SO2 control efficiency would need to be about 98.8%. For this “design”

coal scenario, Deseret Power has projected a control breakdown of about 85% control from
99

limestone injection and about 92.3% control of the remaining SO2 by a dry scrubber.

While EPA can agree that 0.055 lb/MMBtu is BACT for the “design” coal scenario, EPA

does not consider it to be BACT when “average” or better waste coal is used, or when a blend of

waste coal and ROM coal is used. Based on coal sampling data from the waste coal stockpile,

and from the coal washing plant at the Deserado Mine, Deseret Power has stated that “average”

waste coal for the WCFU would have about 4,000 Btu/lb heat content and about 0.34% sulfur

content. The “average” coal would therefore have uncontrolled SO2 emission potential of about

1.71 lb/MMBtu. This is only about one-third of the emission potential of the “design” coal.

Various coal scenarios for Deseret’s WCFU, as well as for other CFB projects using

waste coal or other similar quality coal, are presented in the table below. Expected control

efficiencies at other CFB projects listed are all higher than Deseret has projected for the WCFU

for “average” coal and emissions of 0.055 lb/MMBtu. As shown in the table, to achieve an

emission rate of 0.055 lb/MMBtu, SO2 control efficiency for “average” coal at the WCFU (not

“design” coal) would need to be only about 96.6%. For this “average” coal scenario, Deseret

Power has projected a control breakdown of about 85% SO2 control from limestone injection and

78.5% control of the remaining SO2 by a dry scrubber.

EPA believes a dry scrubber should be able to achieve much better control than 78.5% for

this scenario. EPA believes that limestone injection plus dry scrubbing should instead be able to

achieve about 98% overall control for “average” coal at the WCFU, consisting of 80-85% control

by limestone injection and roughly 90% control of the remaining SO2 by a dry scrubber. This

level of control would be equivalent to an emission rate of about 0.040 lb/MMBtu.

Coal Scenarios and Sulfur Dioxide Control Efficiency

Comparisons for CFB Projects: EPA Compilation

CFB Plant /

Company

Source of

Information

Coal

Scenario

Btu/lb Sulfur

Wt %

Uncontrolled

SO2

(lb/MMBtu)

Controlled

SO2

(lb/MMBtu)

Control

Efficiency

Richardton

Ethanol Plant

/ Red Trail

Energy LLC

Permit

application

--- 6900 1.2 3.3 0.09 97.3%

Gascoyne

Gen. Stn /

MDU Co.

Permit

application

--- 5974 0.93 2.95 0.038 98.7%

Annual

average

South Heart / 5965 1.17 3.72 0.039 98.9%

Great North.

Power

Development

Permit

application

24-hr

average

5782 1.7 5.58 0.039 99.3%
100

Highwood

Gen. Stn. /

Southern MT

Electric Co.

Permit

application

Annual

average

8752 0.62 1.42 0.038 97.3%

“worst

case” coal

12,000 0.8 1.3 0.022

(3-hr avg)

AES Puerto 98.3%

Rico

Permit

08/10/04;

actual

operating

data

“average”

coal

Unk. Unk. 0.88 0.022

(3-hr avg)

97.5%

“worst

case” coal

10,200 0.9 1.76 0.05

(24-hr avg)

Nevco 97.2%

Energy

Permit

10/12/04

“average”

coal

10,200 0.25 0.49 0.022

(30-day avg)

95.5%

Letter

09/13/05,

E-mail

11/09/05

“design”

coal

3000 0.71 4.73 0.055

(Deseret

proposal for

BACT)

98.8%

4000 0.34 1.71 0.055

(Deseret

proposal for

BACT)

Permit 96.6%

application,

E-mail

11/09/05

“average”

coal

4000 0.34 1.71 Variable

limit

between

0.055 and

0.040

(final EPA

BACT)

97.7%

4000 0.40 1.9

(EPA draft

selection for

cutpoint)

97.1%

Bonanza

WCFU /

Deseret

Power

Coal

sampling

data from

Deseret

Permit

cut-point

coal

(slightly

worse

than

“average”

coal)

4000 0.43 2.2

(EPA final

selection for

cutpoint)

Variable

limit

between

0.055 and

0.040

(final EPA

BACT)

97.5%

To address the large difference in uncontrolled SO2 emission potential between “design”

coal and “average” coal at the WCFU (a factor of almost three), and to resolve the issue about

which scenario is more appropriate as a basis for BACT, EPA proposed in the draft WCFU

permit a ‘second tier’ SO2 BACT limit, applicable when coal is being fired with uncontrolled

SO2 emission potential of 1.9 lb/MMBtu or less.

A two-tier emission limit approach for SO2 BACT has already been applied in state and

Federal PSD permits for coal-fired boilers. EPA Region 7 has issued two such PSD permits.

(Reference: Permits issued by Region 7 on March 1, 1990, to Archer-Daniels-Midland, for coal-
101

fired CFB boilers at ADM plants in Des Moines and Cedar Rapids, Iowa.) More recently, a PSD

permit was issued on May 5, 2005 by the State of Nevada, to Newmont-Nevada Energy

Investment, specifying a two-tier limit as SO2 BACT for a proposed 200-megawatt pulverized

coal fired boiler. In the Newmont-Nevada permit, the higher tier SO2 limit (in lb/MMBtu on a

24-hour average) applies when coal with sulfur content equal to or greater than 0.45% is being

used. The lower tier SO2 limit (also in lb/MMBtu on a 24-hour average) applies when coal with

sulfur content less than 0.45% is being used. In addition to the lb/MMBtu limits, the NewmontNevada permit imposes two tiers of SO2 removal efficiency, again based on sulfur content of

coal.

An alternative approach for addressing a wide variety of coal quality scenarios at

Deseret’s WCFU would be to establish a control efficiency requirement as BACT, either in lieu

of, or in addition to, a lb/MMBtu emission limit. (As explained above, the latter was done in the

Newmont Nevada permit.) However, Deseret Power objected to this approach, and EPA does

not consider it necessary for Deseret’s project, as long as a ‘second tier’ emission limit in

lb/MMBtu is established, to address situations where coal with substantially lower uncontrolled

SO2 emission potential than Deseret’s “design” coal scenario is being used.

Deseret Power maintained that having to achieve an SO2 emission rate lower than 0.055

lb/MMBtu could prevent them from achieving a NOx emission rate below 0.088 lb/MMBtu.

(EPA has proposed 0.080 lb/MMBtu as NOx BACT, after an initial 15-month ‘break-in’ period

to fine-tune the SNCR controls.) As explained in the NOx BACT analysis portion of this

Statement of Basis, EPA agrees that increasing the limestone injection rate into the boiler may

increase NOx formation (due to the presence of excess unreacted CaO in the boiler), but finds this

effect difficult to quantify.

EPA at first considered setting the ‘second tier’ limit for the WCFU at 0.040 lb/MMBtu,

on a 30-day rolling average. When the uncontrolled SO2 emission potential of the coal, also on a

30-day rolling average, drops below 1.9 lb/MMBtu, the applicable 30-day average emission limit

would change on the next boiler operating day from 0.055 to 0.040. A coal ‘cutpoint’ of 1.9

lb/MMBtu was originally chosen by EPA, to approximate Deseret’s “average” coal, but with a

slight margin (0.4% sulfur content, rather than 0.34%.) (By ‘cutpoint,’ EPA means the threshold,

in terms of uncontrolled SO2 emission potential of the coal, at which the applicable SO2 emission

limit changes from a higher limit to a lower limit, in this case changing from 0.055 to 0.040

lb/MMBtu.)

Deseret Power raised issues with this proposal. Deseret Power explained that if the

emission limit changes overnight from 0.055 to 0.040, a slight shift of fuel sulfur content could

result in the WCFU running out of compliance for many days, despite best operating practices.

Deseret Power presented an example to EPA (via Excel spreadsheets submitted on January 6,

2006) where 4000 Btu/lb coal changing from 0.37% sulfur content to 0.31% sulfur content, on

one day out of 60 days, could result in a shift from 0.055 to 0.040 as the applicable emission

limit, and the WCFU would be running out of compliance for 16 days of the 60 day period, while
102

WCFU operator tries to ‘catch up’ with a 30-day limit which has dropped overnight from 0.055

to 0.040.

The underlying problem, according to Deseret Power, is the non-homogeneous, inherently

unpredictable quality of the waste coal, which could not be easily controlled by the WCFU

operator. Core samples from the waste coal stockpile have indicated sulfur content ranging from

0.34% to 0.71% and heating value ranging from 3000 Btu/lb to 5400 Btu/lb. The sulfur and

heating value variations are not uniform through the waste pile. Thus at any given time, a high

sulfur, low heating value fuel could be fed to the furnace, or a low sulfur, high heating value fuel,

or any combination of sulfur and heating value. Deseret Power pointed out that this situation is

fundamentally different than other scenarios where two-tier SO2 BACT limits have been written

into PSD permits (e.g., the Region 7 and State of Nevada permits cited above). In the other

scenarios, “run-of-mine” coals would be used rather than waste coal, each with a narrow range of

composition variation. In such scenarios, separate emissions limits for the different fuel types

could be established and met with real time controls.

Another issue raised by Deseret Power is the delay in obtaining the coal analysis results.

Deseret Power states that it will not be possible for them to determine the analysis of the fuel

being fired, as it is being fired. Average samples of fuel being loaded into the silo will be taken

to Deseret’s laboratory for analysis. Deseret states that results will take a minimum of one day

and may take up to three days.

If there will be a substantial delay in getting the results of the in-house analysis, Deseret

stated that the coal may have to be sent to an outside laboratory for analysis, which may take up

to five days. Results therefore might not be available until three days or more after fuel is loaded

to the fuel input silo. The applicable SO2 tier limit would not be known to the WCFU operator

until the coal analysis is received. Thus the plant could be running out of compliance during the

period when the samples were taken, but the WCFU operator would have no way of knowing as

the fuel is being fired. Further, due to the non-uniform nature of fuel flow in silos, combined

with the wide variation of fuel sulfur and heating value of the non-homogeneous Deseret waste

fuel, Deseret Power expects that the sample analysis would very likely not be a precise indication

of the fuel being fed to the furnace.

When the coal analysis is received, if it is determined by the WCFU operator that the

WCFU is now subject to the lower tier SO2 limit of 0.040, rather than 0.055, and is out of

compliance, excess limestone might be fed to the WCFU. Feeding excess limestone might help

the WCFU ‘catch up’ with an SO2 limit that has dropped from 0.055 to 0.040 overnight, by

quickly reducing SO2 and achieving immediate reductions in 30-day average emissions.

However, since the waste coal has high volatile matter content, Deseret Power expects that

feeding excess limestone will result in higher NOx emissions. Since EPA is proposing a very low

NOx limit as BACT (0.080 lb/MMBtu on a 30-day average), Deseret Power expressed concern

that the WCFU could go out of compliance for NOx while trying to quickly come down to the

lower tier SO2 30-day average. Deseret Power therefore does not view excess limestone feed as a
103

viable approach for dealing with an overnight shift from 0.055 to 0.040 as the applicable SO2

emission limit.

To address the issue of lag time in obtaining coal analysis results, EPA discussed with

Deseret Power the possibility of using ‘real-time’ coal sampling equipment. Deseret Power

acknowledged that such equipment is available for purchase, but said its personal experience

with the equipment is that it is difficult to calibrate and results are unreliable. They stated that

other coal-fired facilities they spoke to have had similar problems.

In summary, EPA views the concerns expressed by Deseret Power about the “two-tier”

approach originally proposed by EPA as legitimate concerns, but still considers 0.040 lb/MMBtu

to be achievable when “average” coal is being combusted. Therefore, EPA decided to express

the ‘second tier’ SO2 BACT emission limit as a calculated limit, prorated between 0.055

lb/MMBtu and 0.040 lb/MMBtu, on a 30-day rolling average, based on the uncontrolled SO2

emission potential of the as-fired coal, also to be determined on a 30-day rolling average.

EPA does not view this prorating approach as a relaxation of the BACT determination. If

the uncontrolled SO2 emission potential of the coal remains below the ‘cutpoint’ for every day

over a very long period of time, then the calculated emission limit will end up at 0.040

lb/MMBtu. The overall SO2 control efficiency needed to achieve 0.040 lb/MMBtu, when

uncontrolled SO2 emission potential of the coal is below the ‘cutpoint,’ would be well above

97%. EPA considers this level of control efficiency to be BACT for combustion of Deseret’s

“average” waste coal.

Revision of proposed cutpoint: As stated above, in the draft WCFU permit, EPA

proposed a cutpoint of 1.9 lb/MMBtu, below which the applicable SO2 emission limit would

change from a fixed limit of 0.055 lb/MMBtu to a variable limit prorated between 0.055 and

0.040 lb/MMBtu, based on the uncontrolled SO2 emission potential of the as-fired coal. As a

result of public comments on the draft WCFU permit, EPA re-evaluated the selection of the

cutpoint, as compared to SO2 emission limits and theoretical control efficiencies required for the

AES-Puerto Rico project, discussed below.

The AES Puerto Rico project includes two CFB boilers burning Columbian coal that

utilize limestone injection and dry scrubbers for SO2 control, same as Deseret Power’s proposed

WCFU project. The SO2 emission limit for the AES Puerto Rico project is 0.022 lb/MMBtu on a

3-hour average. (Ref: PSD permit issued by EPA Region 2 on October 29, 2001 and revised on

August 10, 2004, page 4, condition VIII.4-CFB.a.). However, the AES Puerto Rico permit also

says “Emissions in excess of the applicable emission limit listed under Condition VIII of this

permit, during periods of startup and shutdown, shall not be considered a violation of the

applicable emission limit.” (Ref: permit at page 15, condition XIV.7.)

This startup/shutdown exemption language does not appear in the WCFU permit.

Instead, the WCFU permit says “The PSD BACT emission limits in this permit, as well as the
104

modeling limits, apply at all times, including periods of startup, shutdown and malfunction.”

(Ref: WCFU permit at condition III.I.1.) Therefore, EPA believes that making a direct

comparison of the stringency of the SO2 emission limit in the AES-Puerto Rico permit with the

SO2 emission limit in the WCFU permit is not entirely meaningful. Nevertheless, in

consideration of public comments received, EPA compared the theoretical control efficiency

requirements of the two permits over the respective range of coal qualities from worst-case coal

to average coal, assuming steady-state operations apply and averaging times do not significantly

affect those control requirements. This is explained in the step-by-step process below.

First, using mass balance, EPA calculated an uncontrolled SO2 emission potential of the

coal for the AES-Puerto Rico plant, in lb/MMBtu, based on coal quality parameters of 0.8%

sulfur content and 12,000 Btu/lb heat content cited by commenters for the “worst case” coal. The

result of EPA’s calculation was 1.3 lb/MMBtu:

0.008 lb sulfur x 2 lb SO2 x lb coal x 1,000,000 Btu = 1.3 lb SO2/MMBtu

lb coal lb sulfur 12,000 Btu MMBtu

To meet an emission limit of 0.022 lb/MMBtu, the AES-Puerto Rico plant would need to

achieve about 98.3% SO2 control efficiency.

Second, EPA obtained information on the sulfur content and heat content of coal that has

been used historically at the AES Puerto Rico plant. EPA learned that the sulfur content varied

from 0.49% to 0.75% during the fourth quarter of 2004 and the heat content was about 11,350

Btu/lb. From February of 2002 through June of 2003, the sulfur content varied from 0.53% to

0.85% and the heat content varied from 11,317 Btu/lb to 11,495 Btu/lb. From this information,

EPA found that the uncontrolled SO2 emission potential of the actual coal ranges from about 1.3

lb/MMBtu down to about 0.88 lb/MMBtu. At the low end of this range (which EPA will refer to

in this analysis as “average” coal), the AES Puerto Rico plant would be need to achieve about

97.5% SO2 control efficiency, to meet an emission limit of 0.022 lb/MMBtu. (Ref:

Memorandum and attachments to the file by Mike Owens of EPA Region 8, dated August 8,

2007, included in the Administrative Record for the final WCFU permit action.)

Third, EPA compared the above-mentioned control efficiencies for AES-Puerto Rico to

those that the WCFU would need to achieve to comply with the SO2 emission limit in the draft

WCFU permit. As noted in the table above, the WCFU would need to achieve about 98.8%

control efficiency to comply with the upper emission limit of 0.055 lb/MMBtu, when burning

worst-case coal, and a control efficiency of about 97.7% to comply with an emission limit of

0.040 lb/MMBtu, when burning average coal. Both of these control efficiencies are higher than

the control efficiencies cited above for the range of coal at the AES-Puerto Rico plant (98.3% for

worst-case coal and 97.5% for average coal).

The above-mentioned comparison is somewhat misleading, however, for average coal at

the WCFU, because at the cutpoint originally proposed by EPA in the draft WCFU permit (i.e.,
105

uncontrolled SO2 emission potential of coal of 1.9 lb/MMBtu, only slightly higher than 1.71

lb/MMBtu for average coal), the applicable emission limit would be the upper limit of 0.055

lb/MMBtu. Condition III.D.1.b.(ii)(b) of the draft WCFU permit states that the calculated

emission limit of between 0.055 and 0.040 lb/MMBtu only applies below the “cutpoint.”

Therefore, the statement in the draft Statement of Basis that a control efficiency of 97.9% would

need to be achieved to comply with the applicable emission limit at the “cutpoint,” is incorrect,

because the statement was erroneously based on complying with an emission limit of 0.040

lb/MMBtu. The correct control efficiency that would need to be achieved at the 1.9 lb/MMBtu

“cutpoint” is 97.1%, based on an applicable emission limit of 0.055 lb/MMBtu. This corrected

control efficiency, shown in the table above, is lower than the 97.5% control efficiency that the

AES-Puerto Rico plant must achieve to meet its SO2 emission limit of 0.022 lb/MMBtu when

burning average coal.

Based on this correction, EPA re-evaluated the appropriate level to set for the “cutpoint”

and determined that, to require a minimum control efficiency of 97.5% across the range of coal

qualities described in the permit application for the WCFU, the “cutpoint” would need to be 2.2

lb/MMBtu, rather than 1.9 lb/MMBtu. This would correspond to a control efficiency of 97.5%,

to comply with an applicable emission limit of 0.055 lb/MMBtu when burning coal with

uncontrolled SO2 emission potential of 2.2 lb/MMBtu. This is also shown in the table above.

When burning coal above the revised “cutpoint,” i.e., coal with uncontrolled SO2

emission potential greater than 2.2 lb/MMBtu, to comply with the applicable emission limit of

0.055 lb/MMBtu the WCFU would need to achieve higher SO2 control efficiencies than 97.5%,

reaching 98.8% when burning worst-case coal. Below the revised “cutpoint,” a calculated SO2

emission limit of between 0.055 and 0.040 lb/MMBtu is applicable and needed control

efficiencies range from 98.1% just below the cut-point (2.14 lb/MMBtu) to 97.7% for the

average coal.

EPA believes this revised “cutpoint” is an appropriate approach for ensuring that the

WCFU maintains a high level of SO2 control over the wide range of coal quality, and reflects the

maximum degree of SO2 reduction that can be achieved, commensurate with SO2 BACT

determinations for other similar facilities (listed in the two tables in Step 5 of this SO2 BACT

analysis), including Nevco and AES-Puerto Rico. Specifically, this revised “cutpoint” ensures a

minimum control efficiency of at least 97.5%, over the range of worst-case coal to average coal.

EPA also reviewed 30-day average SO2 CEMS data for the AES Puerto Rico plant, in

quarterly CEMS reports from the years 2003 through 2005, and found a very low amount of

excess emissions with regard to the emission limit of 0.022 lb/MMBtu on a 3-hour average. The

reports seem to EPA to indicate that an emission limit of 0.022 lb/MMBtu on a 30-day rolling

average (and the corresponding control efficiencies) could consistently be met by the AES Puerto

Rico facility, over the range of coal quality cited above. (The CEMS reports are included in the

Administrative Record for the final WCFU permit action.) Therefore, EPA concludes that the

revised “cutpoint” of 2.2 lb/MMBtu for the WCFU represents an overall SO2 BACT determina-
106

tion that is achievable for a CFB unit with limestone injection and a dry scrubber for SO2

controls. The final WCFU permit specifies a “cutpoint” of 2.2 lb/MMBtu, rather than 1.9

lb/MMBtu in the draft permit, for triggering applicability of the lower-tier SO2 BACT emission

limit in the permit.

To address Deseret Power’s concern about the lag time in obtaining coal analysis results,

EPA proposes that the calculation of the applicable SO2 emission limit be based on coal samples

obtained during a period which ends five boiler operating days prior to the day on which the

emission limit will apply.

EPA proposes that the two-tier SO2 emission limit approach go into effect 12 months

after completion of initial performance testing, to provide a sufficient ‘break-in’ period to finetune and balance the emission control equipment for optimum efficiency. Prior to that point in

time, Deseret’s requested BACT emission limit of 0.055 lb/MMBtu would be in effect for any

coal burned. The explanation of need for a break-in period may be found in the NOx BACT

discussion of this Statement of Basis. EPA considers the inter-relationship between NOx control

and SO2 (explained in the NOx BACT discussion) to call for a break-in period applicable to both

pollutants.

In conclusion, EPA proposes the following emission limits as SO2 BACT:

Prior to the date which is 12 months after completion of initial performance testing:

0.055 lb/MMBtu heat input, on a 30-day rolling average.

Beginning on the date which is 12 months after completion of initial performance

testing, and thereafter:

(a) 0.055 lb/MMBtu heat input, on a 30-day rolling average, for any boiler

operating day when the uncontrolled SO2 emission potential of the

combusted coal is 2.2 lb/MMBtu or greater, on a 30-day rolling average.

(b) a calculated emission limit, on a 30-day rolling average, as set forth below,

for any boiler operating day when the uncontrolled SO2 emission potential of

the combusted coal is less than 2.2 lb/MMBtu, on a 30-day rolling average:

0.055A + 0.040B lb/MMBtu heat input

30

Where:

A = Number of BOD, during 30 successive BODs prior to the

calculation, when the uncontrolled SO2 emission potential

of the combusted coal was 2.2 lb/MMBtu or greater, on a

30-day rolling average.
107

B = Number of BOD, during 30 successive BODs prior to the

calculation, when the uncontrolled SO2 emission potential

of the combusted coal was less than 2.2 lb/MMBtu, on a

30-day rolling average.

BOD = Boiler Operating Day

For purposes of determining the applicable SO2 emission limit in either (a) or (b)

above, the uncontrolled SO2 emission potential of the coal, on a 30-day rolling

average, shall be based on coal samples obtained during a period of 30 successive

BODs which ends five BODs prior to the day on which the emission limit applies

The term “30-day rolling average,” as used in this permit, shall mean the average of

30 successive boiler operating days. The term “boiler operating day,” as used in this

permit, shall have the meaning given in the revised NSPS Subpart Da, published in

the Federal Register on February 27, 2006 (71 FR 9866), as it applies to new units:

“Boiler operating day” ... means a 24-hour period between 12 midnight and the

following midnight during which any fuel is combusted at any time in the steam

generating unit. It is not necessary for fuel to be combusted for the entire 24-hour

period.

As explained earlier in this Statement of Basis, Deseret Power will be permitted to use

coal from the Deserado mine, consisting of either waste coal alone, or else a blend of waste coal

and run-of-mine coal, yielding heat content of up to 6,500 Btu/lb. Based on the SO2 BACT

analysis above, EPA believes that the proposed ‘second tier’ SO2 emission limit described above

will represent BACT for coal from the Deserado mine with heat content up to at least 6,500

Btu/lb, and will ensure a continued high degree of SO2 emission control efficiency.

6. Comparison to applicable NSPS emission standard.

The definition of BACT in 40 CFR 52.21(b)(12) contains the statement that, “In no event

shall application of best available control technology result in emissions of any pollutant which

would exceed the emissions allowed by any applicable standard under 40 CFR parts 60 and 61.”

The applicable SO2 emission standard in Subpart Da of 40 CFR part 60 is 1.4 pounds per

megawatt-hour (lb/MWh) on a rolling 30-day average. An allowed alternative in Subpart Da is

94% reduction on a 30-day rolling average.

The following equation is used by EPA to convert from lb/MWh to lb/MMBtu:

X lb/MMBtu * 3.412 MMBtu/MWh * 1/Efficiency = Y lb/MWh

In developing Subpart Da standards in lb/MWh, EPA assumed a 36% gross efficiency for
108

coal-fired electric utility boilers. Approximately a quarter of existing boilers presently have

average efficiencies greater than 36%; however, CFB boilers tend to have lower gross efficiency

values, ranging from 30% to 38%. With the relative low-quality waste coal that will be used at

Deseret’s proposed WCFU, EPA expects that the WCFU efficiency would be at the lower end of

this efficiency range.

If 36% gross efficiency is assumed, then by the equation above, the WCFU would have to

maintain SO2 emissions at 0.147 lb/MMBtu or lower, to meet the 1.4 lb/MWh standard. If the

WCFU operates at a low efficiency of 30%, then it must maintain an emissions rate of 0.123

lb/MMBtu or less, to meet the 1.4 lb/MWh standard. The proposed SO2 BACT emission limits

for the WCFU (0.055 lb/MMBtu on a rolling 30-day average, or else a prorated limit between

0.055 and 0.040 on a rolling 30-day average, depending on the uncontrolled SO2 emission

potential of the coal) are substantially lower than 0.123 lb/MMBtu and therefore are at least as

stringent as the applicable NSPS emission standard of 1.4 lb/MWh.

7. Proposed compliance monitoring approach.

For compliance demonstrations, EPA proposes to require use of SO2 CEMS. EPA also

proposes to allow the diluent cap approach from 40 CFR part 75 for calculating emissions in

lb/MMBtu, in the event of very low boiler load, such as during startup or shutdown. This

approach was developed by EPA in Part 75 to address low-load situations at electric utility

boilers, when Btu’s coming from the boiler drop to zero (i.e., when the denominator in the

lb/MMBtu calculation drops to zero). The diluent cap approach allows for the substitution of a

constant carbon dioxide (CO2) or oxygen (O2) diluent value for a measured value from a CO2 or

O2 diluent monitor. This is explained further below.

In the F factor equation of Method 19, the denominator is allowed to be expressed as

either percent CO2 or [20.9 minus the percent O2]. If combustion ceases, the percent CO2 would

drop to zero and the percent O2 would rise to ambient value of 20.9%. In either case, the

denominator of the F factor equation would drop to zero, which means the calculated emissions

in lb/MMBtu could rise to infinity, despite very little actual emissions coming from the boiler.

With the diluent cap approach, if the measured CO2 concentration in the boiler exhaust stack

drops below 5%, it is allowed to be capped at a lower-end value of 5%. Similarly, if the

measured O2 concentration in the boiler exhaust stack rises above 14%, it is allowed to be capped

at a higher-end value of 14%. EPA does not view the diluent cap approach as a relaxation of

BACT.

Further description of the diluent cap approach may be found in the preamble to a direct

final Part 75 rule, published in the Federal Register on May 17, 1995. The rule allows the

approach to be used for boiler startup. In a subsequent Part 75 rulemaking, published in the

Federal Register on May 21, 1998, EPA determined that it is appropriate to allow the diluent cap

approach to be used anytime where there is very low boiler load, such as when the boiler is idling

on standby status, not just during startup.
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L. BACT for Sulfuric Acid (H2SO4) Emissions from CFB Boiler.

Combustion of fuel containing sulfur results in the reaction of sulfur trioxide (SO3) with

water vapor outside of the combustion section, resulting in formation of sulfuric acid mist

(H2SO4). Since the formation of SO3 is a function of the generation of SO2, uncontrolled

emissions of sulfuric acid mist are a function of the sulfur content of the coal. Sulfuric acid mist

is controlled by the same technologies as for the H2SO4 component of PM/PM10 condensibles,

described earlier in this Statement of Basis.

In addition to the potential control technologies listed in Step 1 below, clean fuels (i.e.,

alternative coal, either from the Deserado mine or another mine) is also a possible option for

BACT, but has already been eliminated as cost-prohibitive for BACT, for all pollutants at this

project. This was explained earlier in this Statement of Basis.

1. Step 1: Identify Potential Control Technologies.

The potential control technologies for H2SO4 control are the same as the technologies

listed in Step 1 of the BACT discussion for PM/PM10 condensibles:

a. Alkali (limestone) injection + fabric filter baghouse

b. Dry SO2 scrubbing + fabric filter baghouse

c. Alkali injection + dry SO2 scrubbing + fabric filter baghouse

d. Alkali injection + wet SO2 scrubbing + fabric filter baghouse

e. Alkali injection + dry SO2 scrubbing + fabric filter baghouse +

wet electrostatic precipitation (ESP)

2. Step 2: Eliminate Technically Infeasible Options.

As explained in Step 2 of the BACT discussion for PM/PM10 condensibles, all potential

control technologies (or technology combinations) listed above are technically feasible for

control of H2SO4.

3. Step 3: Rank Remaining Control Technologies by Control Effectiveness.

As explained in Step 3 of the BACT discussion for PM/PM10 condensibles, Deseret

Power proposes to install alkali injection, dry SO2 scrubbing and a fabric filter baghouse (option

c above). The only option that might achieve greater control effectiveness for H2SO4 would be to

add a wet ESP downstream of that combination of controls. The amount of additional control

that might be possible is discussed in Step 3 of the PM/PM10 condensibles BACT analysis.
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4. Step 4: Evaluate Economic, Environmental and Energy Impacts.

Same as discussion in Step 4 of the BACT discussion for PM/PM10 condensibles. For

control of H2SO4, Deseret Power proposes to install alkali injection, dry SO2 scrubbing and a

fabric filter baghouse. As explained in the BACT discussion for PM/PM10 condensibles, adding

a wet ESP downstream of those controls has been determined to be economically cost-prohibitive

for BACT for H2SO4.

5. Step 5: Proposed H2SO4 BACT for CFB Boiler.

The following discussion, for determination of a BACT emission limit, is based on the

selected combination of H2SO4 controls, consisting of alkali injection, dry SO2 scrubbing and a

fabric filter baghouse. Deseret Power searched the RACT/BACT/LAER Clearinghouse listings

for coal fired fluidized bed boilers with limits on H2SO4 emissions where available. The table

below presents a summary of facilities utilizing CFB boiler technology with limits on H2SO4.

Comparison of CFB Boiler H2SO4 Emission Rates:

RACT/BACT/LAER Clearinghouse Data

Facility RBLC

ID

Heat Input

MMBtu/hr

H2SO4

Emissions

Lb/MMBtu

Control Fuel

AES-PRCP PR-0007 4922.7 0.0024 Limestone

and Dry

Scrubber

Columbian

Coal

AES Warrior

Run

MD00222070.0 0.015 Limestone Eastern US

Coal

Prior to agreeing to install a dry scrubber for SO2 and H2SO4 control, Deseret Power

proposed an emission limit of 0.005 lb/MMBtu as BACT for H2SO4. However, with the dry

scrubber now proposed by Deseret Power, EPA believes it should be possible to do better. For

calculating a BACT emission limit, EPA has used the following basis and calculation

methodology:

Calculation of potential uncontrolled H2SO4:

(a) Basis of calculation:

 For purposes of this analysis, use "average" coal, as specified in proposed permit

condition III.H.5 for compliance testing for H2SO4. This coal has uncontrolled

SO2 emission potential of 1.71 lb/MMBtu.
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 1% of uncontrolled SO2 is converted to SO3, as used in H2SO4 BACT analyses in

PSD permit applications for the proposed Gascoyne and South Heart CFB boiler

projects in North Dakota.

 Assume all of the SO3 formed in the combustion process combines with water to

form H2SO4 in a one-to-one molar ratio: SO3 + H2O => H2SO4

(b) Resulting calculation:

(1.71 lb SO2/MMBtu) x (1 lb-mole SO2/64 lb SO2) x

(0.01 lb-mole SO3/1 lb-mole SO2) x (1 lb-mole H2SO4/1 lb-mole SO3) x

(98 lb H2SO4/lb-mole H2SO4) =

0.026 lb/MMBtu H2SO4 (uncontrolled)

Calculation of potential controlled H2SO4:

(a) Basis of calculation:

 Gascoyne proposes about 90% overall control for H2SO4, based on 50% control in

the boiler using limestone injection, followed by 80% control of the remainder

with a dry SO2 scrubber.

 South Heart proposes about 93% overall control for H2SO4, based on 60% control

in the boiler using limestone injection, followed by 82% control of the remainder

with a dry SO2 scrubber.

 Deseret’s “average” waste coal will have lower uncontrolled H2SO4 emission

potential than the coal for the proposed Gascoyne and South Heart CFB boiler

projects. (This can be seen from the table of coal comparisons in Step 5 of the

SO2 BACT analysis in this Statement of Basis. Coal that has much lower

uncontrolled SO2 emission potential than other coals can also be expected to have

lower uncontrolled H2SO4 emission potential.) Therefore, a somewhat lower

emission control efficiency than Gascoyne’s 90% and South Heart’s 93% would

seem reasonable for Deseret. EPA estimates that about 87% control of H2SO4 is

reasonable to expect at Deseret, considering Deseret expects 80% control of the

H2SO4 by the SO2 scrubber alone.

(b) Resulting calculation:

Reduce 0.026 lb/MMBtu by 87% in boiler and scrubber

= > 0.0034 lb/MMBtu H2SO4 at SO2 scrubber outlet
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This calculation does not necessarily represent EPA’s final determination on setting a BACT

limit for H2SO4. See further discussion below.

EPA is aware that there are some higher proposed or permitted BACT limits for other

CFB boiler projects. The Gascoyne project has a permitted H2SO4 BACT limit of 0.0061

lb/MMBtu. The PSD permit application for the South Heart project has proposed a H2SO4

BACT limit of 0.0042 lb/MMBtu. However, as mentioned above, Deseret Power’s waste coal

has lower uncontrolled H2SO4 emission potential than the coal for these two projects. Therefore,

EPA expects that Deseret Power should be able to do better for controlled H2SO4 than these two

lignite projects.

Additionally, in a February 21, 2006 e-mail, Deseret Power has pointed to the higher

limits in the River Hill permit of 0.006 lb/MMBtu and the East Kentucky Power Cooperative

Spurlock #4 proposed limit of 0.005 lb/MMBtu. Again, these projects will be burning eastern

waste and bituminous coals, which are higher in sulfur content than the waste coal proposed for

Deseret Power’s WCFU and would therefore have higher uncontrolled H2SO4 potential.

EPA is also aware there are some lower proposed or permitted BACT limits for other

CFB boiler projects. The AES project in Puerto Rico has a permitted H2SO4 BACT limit of

0.0024 lb/MMBtu. However, as mentioned in Step 5 of the SO2 BACT discussion in this

Statement of Basis, the AES-Puerto Rico permit requires the facility to fire a high-heating value

low-sulfur coal, which means lower uncontrolled H2SO4 emission potential than Deseret Power’s

waste coal. The Nevco project in Utah also has a permitted H2SO4 BACT limit of 0.0024

lb/MMBtu, but will also be firing low-sulfur coal with a much higher heating value than Deseret

Power’s waste coal. (The average heating value of both the Nevco and AES-Puerto Rico coals

will be in excess of 11,000 Btu/lb, versus 4,000 Btu/lb for Deseret Power’s “average” waste coal,

or 6,500 Btu/lb for a 50/50 blend of Deseret Power’s waste coal with run-of-mine coal.)

The PSD permit for the Robinson Power’s Beech Hollow waste-coal-fired CFB boiler

project in Pennsylvania has a final H2SO4 BACT limit of 0.003 lb/MMBtu, burning waste coal

with 1.8% sulfur content and a dry scrubber for control. By comparison, Deseret Power’s

“design” waste coal has sulfur content of 0.71% and Deseret Power’s “average” waste coal has

sulfur content of 0.34%. Therefore, we would normally expect that Deseret Power could achieve

a lower H2SO4 limit than the Robinson Power project; however, there are other factors which

override this expectation. This is explained below.

According to the April 4, 2005 technical support document by Pennsylvania for the

Robinson Power permit, Pennsylvania assumed only 0.7% of the SO2 converts to SO3 and

subsequently to H2SO4, as opposed to 1% in EPA’s calculation above for Deseret Power. In

addition, Pennsylvania assumed the same level of H2SO4 control as they did for SO2 control,

which was 97%. Both of these assumptions would explain why the Robinson Power limit is

lower than Deseret Power, even though Robinson Power will be burning much higher sulfur

content coal.
113

Despite the aforementioned assumptions by Pennsylvania for the Robinson Power permit,

EPA Region 8 does not believe the control efficiency for H2SO4 will be equal to that for SO2,

considering that for both Robinson Power and Deseret Power, the concentrations of H2SO4 will

be roughly an order of magnitude lower than SO2. As noted above, EPA has assumed the overall

H2SO4 control for Deseret Power’s project to be 87%. EPA believes this is a reasonable

assumption compared to the other permit analyses EPA has reviewed, and considering the lower

sulfur content of Deseret Power’s coal.

EPA also notes that the Robinson Power permit allows for an adjustment to the BACT

limit (upward or downward) based on stack testing for H2SO4. This permit language implies that

Pennsylvania would be willing to raise the H2SO4 BACT limit later, if Robinson Power cannot

control its H2SO4 emissions by 97% to meet 0.003 lb/MMBtu. In summary, for the reasons

outlined above, we do not believe the H2SO4 limit in the Robinson Power permit, for a project

that will have higher sulfur coal than Deseret Power, precludes EPA from setting a BACT limit

for H2SO4 at Deseret Power that is higher than 0.003 lb/MMBtu.

In a February 21, 2006 e-mail to EPA, Deseret Power proposed a BACT limit of 0.0038

lb/MMBtu for H2SO4. This proposal was based primarily on Deseret Power’s assertion that

0.0038 is the “minimum detectable limit,” if NCASI Method 8A is used.

Deseret Power stated that since EPA has agreed to allow use of NCASI Method 8A for

measurement of H2SO4 at the proposed WCFU, in lieu of EPA Method 8, and since NCASI

Method 8A cites a “minimum detectable limit” for SO3 which is equivalent to about 0.0038

lb/MMBtu for H2SO4, Deseret Power believes that BACT for H2SO4 cannot be lower than

0.0038. For reasons explained below, EPA does not consider Deseret Power’s assertion to be

valid:

(1) The regulatory definition of BACT in 40 CFR 52.21(b)(12) does not say or imply that

issues about the accuracy or detection limits of a particular test method should be determinant of

BACT. The definition states that the BACT determination is to be based on the degree of

emission control that is achievable by available processes, methods, systems or techniques. The

only mention of measurement methodology in the definition is in regard to whether technological

or economic limitations on the application of that measurement methodology to a particular

emissions unit would make the imposition of an emissions standard infeasible.

(2) The “minimum detectable limit” cited by Deseret Power is not an absolute, but depends

on how a particular test is conducted. The main factor affecting detection limit is the amount of

sample collected, which is a direct function of the sampling rate and sampling time. Method 8A

specifies a minimum sampling time of 30 minutes, which EPA believes was used by the authors

of Method 8A to calculate the minimum detectable limit. However, EPA considers a sampling

time of at least two hours to be possible under Method 8A. This would make the minimum

detectable limit four times as low as what Deseret has cited. EPA also believes a somewhat
114

higher sampling rate is possible than what is assumed under Method 8A. This would also lower

the minimum detectable limit. Overall, EPA believes the minimum detectable limit under

Method 8A could be as much as six times lower than what Deseret Power has cited.

EPA also notes that the minimum detectable emissions cited under Method 8 are an order

of magnitude lower than the minimum cited under Method 8A. The sampling rate for Method

8A is about one-third the maximum rate for Method 8.

In a later e-mail dated March 27, 2006, Deseret Power calculated 0.0021 lb/MMBtu of

actual H2SO4 emissions, based on a scrubber inlet concentration of 0.0127 lb/MMBtu and 80%

removal by the scrubber. (These figures would actually yield calculated emissions of 0.0025

lb/MMBtu.) In the same e-mail, Deseret Power stated that its vendor will guarantee 0.0035

lb/MMBtu.

As explained above, EPA has calculated an H2SO4 emission rate of 0.0034 lb/MMBtu,

based on scrubber inlet concentration of 0.026 lb/MMBtu and 87% removal by the scrubber.

This calculation is very close to Deseret Power’s vendor guarantee of 0.0035 and, as also

explained above, compares reasonably with issued permits for other similar CFB boiler projects,

both with higher sulfur coal and with lower sulfur coal. Considering the uncertainties involved

with the assumptions underlying EPA’s H2SO4 calculation, EPA believes a slight adjustment

from 0.0034 can be justified, to propose a BACT limit equivalent to the vendor’s guarantee.

EPA therefore proposes the following as BACT for H2SO4:

0.0035 lb/MMBtu, based on annual EPA Method 8 or

NCASI Method 8A stack testing

As explained earlier in this Statement of Basis, for the proposed WCFU, Deseret Power

will be permitted to use coal from the Deserado mine, consisting of either waste coal alone, or

else a blend of waste coal and run-of-mine coal yielding heat content of up to 6,500 Btu/lb.

Based on the H2SO4 BACT analysis above, EPA believes that the proposed H2SO4 emission limit

will represent BACT for coal from the Deserado mine with heat content up to at least 6,500

Btu/lb, and will ensure a continued high degree of H2SO4 emission control efficiency.

6. Comparison to applicable NSPS emission standard.

Since 40 CFR 60, Subpart Da contains no emission standard for sulfuric acid, there is no

comparison to make.

7. Proposed compliance monitoring approach.

For compliance demonstrations, EPA proposes to require annual EPA Method 8 stack

tests. In lieu of Method 8, EPA proposes to allow use of NCASI Method 8A. Deseret Power has

requested use of NCASI Method 8A due to concern about possible upward bias in Method 8 test
115

results. The potential for bias arises if there is interference from sulfates, which are present in the

particulate matter emissions, and from sulfur dioxide. NCASI Method 8A is a type of controlled

condensation test method designed to eliminate this interference problem. EPA specialists in

stack test methods, at EPA’s Office of Air Quality Planning and Standards, have confirmed that

use of NCASI Method 8A, as an alternative to EPA Method 8, would be acceptable.
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M. BACT for NOx Emissions from Emergency Generator.

In an internal combustion (IC) engine, NOx can be formed two ways: thermal NOx

(oxidation of atmospheric nitrogen found in the combustion air), and fuel NOx (conversion of

nitrogen chemically bound in the fuel). Factors that influence NOx emissions include engine

design and operating parameters, type of fuel and ambient conditions.

Thermal NOx forms in the combustion chamber when N2 and O2 molecules dissociate

into free atoms at elevated temperatures and pressures encountered during combustion and then

recombine to form NO. Thermal NOx increases exponentially with increases in flame

temperature and linearly with increases in resistance time. The NO further oxidizes to NOx and

other NOx compounds downstream of the combustion chamber.

Fuel NOx is formed when fuels containing bound nitrogen are burned. The emergency

generator for the WCFU project will burn diesel fuel, which typically contains little or no fuel

bound NOx. As a result, when compared to thermal NOx, fuel bound NOx is not a major

contributor to overall NOx emissions from most IC engines.

1. Step 1: Identify Potential Control Technologies.

Based on review of the EPA document, Alternative Control Techniques for NOx

Emissions from Internal Combustion Engines (EPA-453/R-94-032), the following potential

control technologies for controlling NOx emissions from compression ignition, diesel fired

internal combustion engines were identified:

a. Injection timing retardation

b. Lean burn combustion

c. Selective catalytic reduction (SCR)

Non-selective catalytic reduction (NSCR) is not a potential control technology for dieselfired engines. A review of available literature from NSCR suppliers (e.g., DCL International

Inc.) reveals that NSCR is effective and applied only to engines fired on natural gas, propane or

gasoline.

2. Step 2: Eliminate Technically Infeasible Options.

All potential control technologies listed above are technically feasible and are described

further below.

a. Injection timing retardation. The operating pressures and

temperatures in the combustion chamber are affected by adjusting the ignition timing in the

power cycle. Advancing the timing so that ignition occurs earlier in the power cycle results in

peak combustion when the piston is near the top of the chamber (when volume of the combustion
117

chamber is at a minimum). This timing adjustment results in maximum pressures and temperatures and has the potential to increase NOx emissions. Conversely, retarding the ignition timing

causes the combustion process to occur later in the power stroke when the piston is in the

downward motion and combustion volume is increasing.

Ignition timing retardation has the potential to reduce NOx formation 20% to 30% on

average, by reducing operating pressures, temperatures, and residence time. However, the exact

magnitude of reduction is engine specific. Some of the limitations associated with retarded

injection timing are related to the degree of retardation specific to the engines so that the greatest

NOx reduction can be achieved without causing performance impacts such as increased exhaust

temperatures, decreased power output, misfiring, and elevated opacity at startup. Hence, the

degree of timing retardation should be recommended by the manufacturer based on testing of

similar size and type engines.

b. Lean burn combustion. A lean burn engine has an air to fuel ratio

that is fuel lean and operates with high excess air which reduces the peak temperature achieved

and exhaust gas which is rich in oxygen. This inhibits the reaction responsible for thermal NOx.

Lean burn combustion engines may emit as much as 8% lower NOX than rich burn or uncontrolled engines. Lean burn combustion is usually accomplished through special combustion

features such as pr-combustion chamber and pre-stratifying the intake charge. Air/fuel ratio

controllers are often used to maximize the reduction in emissions, increase engine efficiency, and

maximize the power output. The only technical limitations associated with lean burn combustion

are related to the optimal degree of lean combustion specific to the engines in order to achieve

the greatest NOx reduction. This should be recommended by the engine manufacturer based on

testing of similar size and type of engines.

c. Selective catalytic reduction. Selective catalytic reduction (SCR)

is an add-on NOx control technology that is placed in the exhaust stream following the engine.

The SCR process reduces NOx emissions by injecting ammonia into the exhaust upstream of a

catalyst bed. The ammonia reacts with NOx in the presence of a catalyst to form water and

nitrogen. The operating range for SCR catalysts is typically 550 to 750 F. Variations in exhaust

gas tempera-ture of 50 F can have an impact on NOx reduction efficiency. Also, the molar ratio

of ammonia to NOx is critical to NOx reduction. Injection of ammonia at higher than the

stoichiometric amount enhances NOx reduction but results in higher ammonia emissions. The

ammonia must be injected such that uniform distribution occurs across the catalyst bed.

It has been reported that NOx reductions from 80-95% may be obtained through the

implementation of SCR. SCR has only been installed on a very limited number of IC engines,

based on data in the EPA RBLC database. None of these engines are limited duty emergency use

applications such as proposed for the WCFU project.
118

3. Step 3: Rank Remaining Control Technologies by Control Effectiveness.

All potential control options discussed above are technically feasible and are ranked as

follows:

a. SCR

b. Combustion controls

(lean burn combustion and ignition timing retardation)

4. Step 4: Evaluate Economic, Environmental and Energy Impacts.

The annualized cost to install an SCR system was evaluated. EPA’s document (EPA453/R-94-032) entitled, Alternative Control Techniques (ACT) for NOX Emissions from Internal

Combustion Engines, was utilized to determine SCR capital installation costs. The costs were

developed for a generator with the following operating specifications:

 Rated capacity – 750 KW/1005 HP

 Exhaust Flow Rate – 7 ft

3

/sec

 Exhaust Temperature – 515 C

 Uncontrolled NOX emission rate – 3.2 lb/mmBtu

 NOX reduction – minimum 80%

 Ammonia slip - <10 ppm

The data were obtained from AP-42 Section 3.4 and estimates from similar generators.

An economic analysis was conducted based on the following capital and annualized cost

algorithms from the previously referenced document:

Capital cost = $22,800 + (56.4 x HP) per unit

Annual operating cost = $37,300 + (16.7 x HP) (for engines operating 500 hours or less).

For the proposed 1,005 HP engine the capital and annualized costs are $79,482 and

$54,083 respectively. Typically, control costs are evaluated based on cost effectiveness

calculated as annual cost per ton of pollutant removed. Based on 80% removal efficiency for the

oxidation catalyst per the above reference document, and an uncontrolled emission rate of

approximately 1 TPY, the cost effectiveness of installing an SCR system on the emergency

generator is over $9 million per ton of NOx removed. Based on this cost estimate, the use of

SCR would be cost prohibitive for the emergency generator. Combustion controls (lean burn

combustion and ignition timing retardation) are the proposed BACT control option for NOx for

the emergency generator.
119

5. Step 5: Proposed NOx BACT for Emergency Generator.

Below is a comparison of NOx BACT determinations for the most recent nine emergency

generators listed in the RACT/BACT/LAER Clearinghouse database:

Comparison of Emergency Generator Nitrogen Oxide Emission Rates:

RACT/BACT/LAER Clearinghouse Data

Facility RBLC ID Permit

Date

Rating

in kW

NOx emissions NOx emissions

(gm/kW-hr)

Arizona Clean Fuels

Yuma

AZ-0046 04/14/05 1050 6.40

gm/kW-hr

6.40

PSI Energy Madison

Station

OH-0275 08/24/04 1680 55.07 lb/hr 14.87

Duke Energy

Washington County

OH-0254 08/14/03 600 12.4 lb/hr 9.37

Mid-American Energy

Company

IA-0067 06/17/03 1340 1.71

lb/MMBtu

7.92

Duke Energy Stephens OK-0090 03/21/03 560 2.16

lb/MMBtu

10.01

Cardinal FG

CO/Cardinal Glass Plant

OK-0091 03/18/03 2000 2.035

lb/MMBtu

9.43

Sterne Electric

Generating Facility

TX-0407 12/06/02 1005 41.9 lb/hr 18.91

Redbud Power Plant OK-0072 05/06/02 1355 0.024 lb/bhp-hr 8.11

Greater Des Moines

Energy Center

IA-0058 04/10/02 700 22.69 lb/hr 14.70

The most stringent BACT determination listed above is 6.40 gm/kW-hr. This is the same

as the “Tier 2” emission limit listed in 40 CFR 89.112, Table 1, for nonroad compression ignition

engine generators larger than 560 kW. (Note: The “Tier 2” limit is actually for NOx plus

nonmethane hydrocarbons, but the NMHC portion is considered by EPA to be extremely small

compared to the NOx.) The requirement for manufacturers to supply “Tier 2” certified engines

does not go into effect until January 1, 2007. EPA proposes the “Tier 2” limit as the NOx BACT

limit for the emergency generator at Deseret Power’s WCFU project, based on use of combustion

controls (ignition retardation and/or lean burn), to the maximum extent that engine specification

will allow, at a “Tier 2” certified engine:

6.40 gm/kW-hr

6. Proposed compliance monitoring approach.

For compliance demonstration, EPA proposes to require the following, in lieu of NOx

emission measurement:
120

(a) Maintain, for the life of the engine, a record of the engine manufacturer’s “certification of

conformity” from EPA that the engine complies with “Tier 2” emission limits. (40 CFR

89.105 requires the manufacturer to obtain such certification from EPA.)

(b) Install, maintain and operate the engine in accordance with the engine manufacturer’s

instructions and recommendations, for ensuring ongoing compliance with the “Tier 2”

emission standards.

(c) Maintain, for the life of the engine, the engine manufacturer’s instructions and

recommendations referenced above.

(d) Maintain records of any engine maintenance.

(e) Restrict engine usage to 100 hours per rolling 12-month period (except for maintenance

firings and test firings, provided that the tests are recommended by the manufacturer, the

vendor, or the insurance company associated with the engine).

EPA considers these requirements to be sufficient for demonstrating emission compliance, in lieu

of NOx emission measurement, for the following reasons:

(a) The engine manufacturer is required under 40 CFR 89.120 to test engines within each

engine family for compliance with “Tier 2” emission limits.

(b) The engine manufacturer is required by 40 CFR 89 to apply deterioration factors when

seeking certification of conformity, to account for accumulated engine usage.

(c) Deterioration of the emergency generator engine at Deseret Power is expected to be

minimal, because: (i) Engine usage will be restricted to 100 hours per rolling 12-month

period, and (ii) there are no add-on emission controls for NOx.
121

N. BACT for PM/PM10 Emissions from Emergency Generator

1. Step 1: Identify Potential Control Technologies.

Potential control technologies of PM emissions from diesel fired internal combustion

engines include the following, ranked in order of potential effectiveness:

a. Positive crankcase ventilation

b. Add on control (i.e. electrostatic precipitator, baghouse, scrubber)

c. Combustion of clean (low-sulfur) fuels

d. Implementation of good combustion practices

2. Step 2 - Eliminate Technically Infeasible Options.

All potential control technologies except add-on controls are considered technically

feasible. Below is a detailed description of each technology.

a. Positive crankcase ventilation. The positive crankcase ventilation

(PCV) system uses a hose connected between the engine and the intake manifold to draw these

gases out of the engine’s crankcase and back into the cylinders to burn with the regular fuel. The

only problem to solve is how to keep these gases from going into the manifold and upsetting the

required air fuel ratio. The solution to this problem is the PCV valve.

The PCV valve controls the release of crankcase gases and vapors to the intake manifold.

The valve is kept closed by spring action when the engine is at rest. When the engine is running

normally, the low vacuum it creates allows the valve to open and release crankcase vapors and

gases into the intake manifold for burning. If the engine is idling or slowing down, the vacuum

level rises and pulls the valve plunger into the valve opening. This partially blocks off the

opening so that only a small amount of vapors and gases can be drawn into the intake manifold.

The literature suggests that a PCV system can reduce crankcase PM10 emissions by at least 90%

over an uncontrolled crankcase vent. The use of a PCV system may be technically feasible for

the proposed engine.

b. Add-on controls. EPA is not aware of any available or technically

feasible add-on controls. No diesel fired IC engines were identified in the permit review which

utilized add-on control technology for PM/PM10 control.

c. Combustion of clean (low-sulfur) fuel. Fuel combustion is

responsible for significant emissions of PM/PM10. The type of fuel and process have a great

impact on the PM emissions from combustion. The combustion of clean fuels to minimize

PM/PM10 emissions is accomplished by burning fuels with minimal amounts of impurities in

conjunction with good combustion practices. Low sulfur diesel fuel (less than 0.05% sulfur

content) is available and will be used.
122

d. Good combustion practices. Good combustion practices refer to

the operation of the engines at high combustion efficiency, which reduce the product of

incomplete combustion such as PM/PM10. The engines will be designed to maximize

combustion efficiency. The engine manufacturer will provide operation and maintenance

manuals to the Permittee, which will detail the methods to maintain a high level of combustion

efficiency.

3. Step 3: Rank Remaining Control Technologies by Control Effectiveness.

Add-on controls have been eliminated in Step 2 above. The remaining control options

are ranked as follows:

a. Positive crankcase ventilation

b. Good combustion practices

c. Combustion of clean (low-sulfur) fuel

4. Step 4: Evaluate Economic, Environmental and Energy Impacts.

The emergency generator will implement all of the above listed technically feasible

control technologies; thus, further review of economic, environmental and energy impacts is not

necessary.

5. Step 5: Proposed PM/PM10 BACT for Emergency Generator.

Deseret Power searched the RACT/BACT/LAER Clearinghouse for PM/PM10 BACT

determinations for emergency generators. Below is a comparison of the most recent nine

permitted emergency generators:

Comparison of Emergency Generator PM/PM10 Emission Rates:

RACT/BACT/LAER Clearinghouse Data

Facility RBLC ID Permit

Date

Rating

in kW

PM emissions PM emissions

(gm/kW-hr)

Arizona Clean Fuels

Yuma

AZ-0046 04/14/05 1050 0.020

gm/kW-hr

0.02

PSI Energy Madison Stn OH-0275 08/24/04 1680 0.27 tons/yr 0.02

Duke Energy

Washington County

OH-0254 08/14/03 600 0.72 lb/hr 0.54

Mid-American Energy

Company

IA-0067 06/17/03 1340 0.14

lb/MMBtu

0.65

Duke Energy Stephens OK-0090 03/21/03 560 0.124

lb/MMBtu

0.57
123

Cardinal FG

CO/Cardinal Glass Plant

OK-0091 03/18/03 2000 0.0444

lb/MMBtu

0.21

Sterne Electric Gen. Fac. TX-0407 12/06/02 1005 2.97 lb/hr 1.34

Redbud Power Plant OK-0072 05/06/02 1355 None stated None stated

Greater Des Moines

Energy Center

IA-0058 04/10/02 700 0.95 lb/hr 0.62

The most stringent BACT determination listed above is 0.2 gm/kW-hr. This is the same

as the “Tier 2” emission limit listed in 40 CFR 89.112, Table 1, for nonroad compression ignition

engine generators larger than 560 kW. The requirement for manufacturers to supply “Tier 2”

certified engines does not go into effect until January 1, 2007. EPA proposes the “Tier 2” limit

as BACT for the emergency generator at Deseret Power’s WCFU project, based on use of

positive crankcase ventilation, good combustion practices, and diesel fuel with sulfur content of

no more than 0.05% sulfur content, at a “Tier 2” certified engine:

0.20 gm/kW-hr

6. Proposed compliance monitoring approach.

For compliance demonstration, EPA proposes to require the following, in lieu of PM10

emission measurement:

(a) Restrict diesel fuel sulfur content to 0.05% or less. Records for each fuel delivery will be

required to demonstrate compliance with the fuel restriction.

(b) Maintain, for the life of the engine, a record of the engine manufacturer’s “certification of

conformity” from EPA that the engine complies with “Tier 2” emission limits. (40 CFR

89.105 requires the manufacturer to obtain such certification from EPA.)

(c) Install, maintain and operate the engine in accordance with the engine manufacturer’s

instructions and recommendations, for ensuring ongoing compliance with the “Tier 2”

emission standards.

(d) Maintain, for the life of the engine, the engine manufacturer’s instructions and

recommendations referenced above.

(e) Maintain records of any engine maintenance.

(f) Restrict engine usage to 100 hours per rolling 12-month period (except for maintenance

firings and test firings, provided that the tests are recommended by the manufacturer, the

vendor, or the insurance company associated with the engine).
124

EPA considers these requirements to be sufficient for demonstrating emission

compliance, in lieu of PM10 emission measurement, for the following reasons:

(a) The engine manufacturer is required under 40 CFR 89.120 to test engines within each

engine family for compliance with “Tier 2” emission limits.

(b) The engine manufacturer is required by 40 CFR 89 to apply deterioration factors when

seeking certification of conformity, to account for accumulated engine usage.

(c) Deterioration of the emergency generator engine at Deseret Power is expected to be

minimal, because: (a) Engine usage will be restricted to 100 hours per rolling 12-month

period, and (b) there are no add-on emission controls for PM10.
125

O. BACT for CO Emissions from Emergency Generator.

Carbon monoxide emissions are generated from incomplete combustion of the diesel fuel.

These emissions occur when there is a lack of oxygen available, if the combustion temperature is

too low, or if the residence time in the cylinder is too short.

1. Step 1: Identify Potential Control Technologies

a. Oxidation Catalyst

b. Good combustion practices

2. Step 2: Eliminate Technically Infeasible Options.

Good combustion practices are considered technically feasible but oxidation catalyst is

not, for reasons described below.

a. Oxidation catalyst. Oxidation catalysts, which are typically a

precious metal deposited onto a solid honeycomb substrate, convert carbon monoxide to carbon

dioxide in the presence of oxygen. A search of various regulatory databases did not show where

this control method has been applied on similar emergency generator engines. Therefore, this

technology is not considered a feasible option for CO emissions control.

b. Good combustion practices. Good combustion practices refer to

the operation of engines at high combustion efficiency, thus reducing products of incomplete

combustion such as CO. The engines will be designed to maximize combustion efficiency. The

engine manufacturers will provide operation and maintenance manuals, which will detail the

methods to maintain a high level of combustion efficiency. Good combustion practices are

technically feasible to control CO emissions from the proposed emergency generator engine.

3. Step 3: Rank Remaining Control Technologies by Control Effectiveness.

Since the only technically feasible control technology is good combustion practices,

ranking is not necessary.

4. Step 4: Evaluate Economic, Environmental and Energy Impacts.

Since the only technically feasible control technology is good combustion practices, and

is proposed below as BACT, no review of economic, environmental and energy impacts is

necessary.

5. Step 5: Proposed CO BACT for Emergency Generator.

Deseret Power searched the RACT/BACT/LAER Clearinghouse for CO BACT
126

determinations for emergency generators. Below is a comparison of the most recent nine

permitted emergency generators:

Comparison of Emergency Generator Carbon Monoxide Emission Rates:

RACT/BACT/LAER Clearinghouse Data

Facility RBLC ID Permit

Date

Rating

in kW

CO emissions CO emissions

(gm/kW-hr)

Arizona Clean Fuels

Yuma

AZ-0046 04/14/05 1050 3.50

gm/kW-hr

3.50

PSI Energy Madison

Station

OH-0275 08/24/04 1680 14.63 lb/hr 3.95

Duke Energy

Washington County

OH-0254 08/14/03 600 15.2 lb/hr 11.49

Mid-American Energy

Company

IA-0067 06/17/03 1340 0.85

lb/MMBtu

3.94

Duke Energy Stephens OK-0090 03/21/03 560 2.66 lb/hr 2.15

Cardinal FG

CO/Cardinal Glass Plant

OK-0091 03/18/03 2000 0.202

lb/MMBtu

0.94

Sterne Electric

Generating Facility

TX-0407 12/06/02 1005 9.02 lb/hr 4.07

Redbud Power Plant OK-0072 05/06/02 1355 0.055

lb/bhp-hr

18.59

Greater Des Moines

Energy Center

IA-0058 04/10/02 700 2.86 lb/hr 1.85

The “Tier 2” emission limit listed in 40 CFR 89.112, Table 1, for nonroad compression

ignition engine generators larger than 560 kW, is 3.50 gm/kW-hr for CO. Three of the CO

determinations listed above are more stringent than the “Tier 2” limit; however, the BACT

determinations for NOx for those three installations are much higher than the “Tier 2” limit for

NOx. NOx and CO are inversely related to each other, in terms of emission rate. It is not known

if there was a desire at those installations to minimize CO at the expense of NOx. Nevertheless,

it is believed that the “Tier 2” limits for NOx and CO appropriate balance emissions of those

pollutants. EPA proposes the “Tier 2” limit as BACT limit for the emergency generator at

Deseret’s WCFU, based on good combustion practices, and using a “Tier 2” certified engine:

3.50 gm/kW-hr

6. Proposed compliance monitoring approach.

For compliance demonstration, EPA proposes to require the following:

(a) Maintain, for the life of the engine, a record of the engine manufacturer’s “certification of
127

conformity” from EPA that the engine complies with “Tier 2” emission limits. (40 CFR

89.105 requires the manufacturer to obtain such certification from EPA.)

(b) Install, maintain and operate the engine in accordance with the engine manufacturer’s

instructions and recommendations, for ensuring ongoing compliance with the “Tier 2”

emission standards.

(c) Maintain, for the life of the engine, the engine manufacturer’s instructions and

recommendations referenced above.

(d) Maintain records of any engine maintenance.

(e) Restrict engine usage to 100 hours per rolling 12-month period (except for maintenance

firings and test firings, provided that the tests are recommended by the manufacturer, the

vendor, or the insurance company associated with the engine).

EPA considers these requirements to be sufficient for demonstrating emission compliance, in lieu

of CO emission measurement, for the following reasons:

(a) The engine manufacturer is required under 40 CFR 89.120 to test engines within each

engine family for compliance with “Tier 2” emission limits.

(b) The engine manufacturer is required by 40 CFR 89 to apply deterioration factors when

seeking certification of conformity, to account for accumulated engine usage.

(c) Deterioration of the emergency generator engine at Deseret Power is expected to be

minimal, because: (i) Engine usage will be restricted to 100 hours per rolling 12-month

period, and (ii) there are no add-on emission controls for CO.
128

P. BACT for SO2 Emissions from Emergency Generator.

1. Step 1: Identify Potential Control Technologies.

Sulfur dioxide emissions occur from the reaction of various elements in the diesel fuel. A

search of regulatory databases revealed no evidence that add-on controls have been installed for

SO2 control from diesel internal combustion engines. Only one control option was found, which

is use of low sulfur fuel. Low-sulfur diesel fuel (less than 0.05% sulfur content) is available and

will be used.

2. Step 2: Eliminate Technically Infeasible Options.

Not necessary. Only one control option was found and is technically feasible.

3. Step 3: Rank Remaining Control Technologies by Control Effectiveness.

Not necessary. Only one control option was found.

4. Step 4: Evaluate Economic, Environmental and Energy Impacts.

Not necessary. Only one control option was found.

5. Step 5: Proposed SO2 BACT for Emergency Generator.

Deseret Power searched the RACT/BACT/LAER Clearinghouse for SO2 BACT

determinations for emergency generators. Below is a comparison of the most recent nine

permitted emergency generators:

Comparison of Emergency Generator Sulfur Dioxide Emission Rates:

RACT/BACT/LAER Clearinghouse Data

Facility RBLC ID Permit

Date

Rating

in kW

SO2 emissions SO2 emissions

(gm/kW-hr)

Arizona Clean Fuels

Yuma

AZ-0046 04/14/05 1050 None stated None stated

PSI Energy Madison Stn OH-0275 08/24/04 1680 8.61 lb/hr 2.32

Duke Energy

Washington County

OH-0254 08/14/03 600 0.40 lb/hr 0.30

Mid-American Energy

Company

IA-0067 06/17/03 1340 0.052

lb/MMBtu

0.24

Duke Energy Stephens OK-0090 03/21/03 560 0.30 lb/hr 0.24

Cardinal FG

CO/Cardinal Glass Plant

OK-0091 03/18/03 2000 0.05

lb/MMBtu

0.23
129

Sterne Electric Gen. Fac. TX-0407 12/06/02 1005 2.77 lb/hr 1.25

Redbud Power Plant OK-0072 05/06/02 1355 0.40 lb/bhp-hr 1.85

Greater Des Moines

Energy Center

IA-0058 04/10/02 700 None stated None stated

The most stringent BACT determination listed above is 0.23 gm/kW-hr. There is no

“Tier 2” emission limit listed in 40 CFR 89.112, Table 1, for SO2 emissions from nonroad

compression ignition engine generators. However, the “Tier 2” standards in general are based on

availability of diesel fuel with sulfur content of 0.05% or less. As mentioned above, there are no

known add-on controls for SO2 emissions from diesel engines. EPA therefore proposes the

following BACT emission limit for the emergency generator at Deseret Power’s WCFU, based

on applicable AP-42 emission factor and use of diesel fuel with no more than 0.05% sulfur

content, at a “Tier 2” certified engine:

0.25 gm/kW-hr.

6. Proposed compliance monitoring approach.

For compliance demonstration, in lieu of emission measurement, EPA proposes to restrict

diesel fuel sulfur content to 0.05% or less by weight. Records for each fuel delivery will be

required to demonstrate compliance with the fuel restriction. EPA also proposes to restrict

engine usage to 100 hours per rolling 12-month period.
130

Q. BACT for PM/PM10 Point Source Emissions from Materials Handling

1. Step 1: Identify Potential Control Technologies.

This section addresses BACT for point sources of PM/PM10 emissions associated with

materials handling for the WCFU (coal, limestone and ash). These point sources of emissions

are the material transfer points (conveyor to storage, reclaim from storage to conveyor, and

conveyor-to-conveyor). The available technology for dust collectors that could be used consists

of enclosing the transfer points and routing fugitive emissions to fabric filters (baghouses or vent

filters), or to mechanical collectors (cyclones). Alternatively, water sprays could be used for dust

suppression. Below is a description of each potential option.

a. Fabric filters

(i) Baghouses. A baghouse separates dry particles from an

exhaust stream by filtering the stream through a fabric filter and collecting the filtered material

on the fabric. Following collection, baghouses can be cleaned using several methods, including

reverse air, pulse-jet, and mechanical shakers. The particles removed from the bags are then

collected in hoppers below the filter bags. Baghouse removal efficiencies are at least 99%. AP42 Table B.2-3 lists the collection efficiency of fabric filters as 99% or 99.5%, depending on

particle size.

(ii) Vent filters. Vent filters collect the particulate matter in the

same manner as baghouses, except that when the vent filters become caked with particulate

matter, the filters are replaced. Vent filter control efficiencies are also at least 99%.

b. Cyclones. Cyclones use funnel shape devices that remove particles

by the shape of the flow stream, causing heavier particles to fall out of the air flow. The removal

efficiency can range from 75% to 99%.

c. Water sprays. Water sprays wet the material and thereby suppress

fugitive emissions. Emission control efficiency of water sprays at unenclosed material transfer

points is estimated at 50-75%. Emission control efficiency of water sprays at enclosed material

transfer points is estimated at 95%.

2. Step 2: Eliminate Technically Infeasible Options.

All technologies listed above are technically feasible.

3. Step 3: Rank Remaining Control Technologies by Control Effectiveness:

 Fabric filters – 99% to 99.5%

 Cyclones – 75% to 99%
131

 Water sprays at enclosed transfer points – 95%

 Water sprays at unenclosed transfer points – 50% to 75%

4. Step 4: Evaluate Economic, Environmental and Energy Impacts.

Deseret Power proposes to install baghouses or vent filters with control efficiencies of at

least 99%. Since this is the highest ranked option in terms of control effectiveness, evaluation of

impacts in comparison to other options is not necessary.

5. Step 5: Proposed BACT for PM/PM10 Point Source Emissions from

Materials Handling.

As stated above, Deseret Power proposes to install baghouses or vent filters to control

point source emissions from materials handling for the WCFU. Below is a list of the proposed

baghouses and vent filters.

Emission Point ID Air flow Location

Baghouse OCH/DC-1 15,000 dscfm existing terminal building

Baghouse EP-W-MH-01 8,500 dscfm crusher building

Baghouse EP-W-MH-02 8,500 dscfm coal day silo headhouse

Baghouse EP-W-MH-03 1,000 dscfm Limestone crushers

Vent filter EP-W-MH-04 1,000 dscfm Surge bin

Baghouse EP-W-MH-05 4,000 dscfm Limestone storage

Vent filter EP-W-MH-06 1,000 dscfm Bed ash recirculation bin

Vent filter EP-W-MH-07 1,000 dscfm Bed ash disposal surge bin

Baghouse EP-W-MH-08 3,600 dscfm Fly ash silo

Baghouse EP-W-MH-08 3,600 dscfm Bed ash

Vent filter EP-W-MH-10 2.000 dscfm Lime storage silo

Based on a search of the RACT/BACT/LAER Clearinghouse, Deseret Power originally

proposed 0.01 grains per dry standard cubic foot (0.01 gr/dscf) as BACT for the baghouses.

However, EPA found more stringent BACT determinations in issued PSD permits for coal-fired

energy projects:

North Dakota – Gascoyne CFB boiler project: 0.005 gr/dscf

North Dakota – Coal Creek Coal Drying Demonstration Project: 0.004 gr/dscf

Iowa – Mid-American Energy Company: 0.005 gr/dscf

Wisconsin – Energy Services of Manitowoc: 0.004 gr/dscf

Colorado -- Lamar Light & Power:

0.005 gr/dscf for baghouses larger than 5,000 dscfm;

0.01 gr/dscf for baghouses smaller than 5,000 dscfm.
132

Based on the above information, Deseret Power has proposed to meet the same baghouse

emission limits as in the Colorado permit for Lamar Light & Power. EPA considers that permit

to be an appropriate representation of achievable baghouse performance for relatively small

baghouses, as it accounts for baghouse size in assessing performance. EPA proposes these same

limits as BACT for Deseret Power.

EPA has also found that a 10 percent opacity limit is typically imposed for material

handling baghouses used in many industries. For example, the EPA-approved Utah PM10 State

Implementation Plan for Salt Lake and Utah Counties imposes a countywide 10 percent opacity

limit for baghouses as Reasonably Available Control Technology. A 10 percent opacity limit is

also typically imposed for small baghouses in PSD permits for new coal-fired energy projects.

EPA considers the opacity limit necessary and appropriate for demonstrating continued proper

operation and maintenance of the baghouses.

Based on the above information, EPA proposes the following as BACT for PM/PM10

point source emissions from materials handling:

All fugitive PM/PM10 emissions generated at coal, limestone and ash conveyor

transfer points, as well as at coal, limestone, ash, lime and inert material storage

silos and storage bins serving the WCFU, shall be routed to fabric filter dust

collectors (baghouses or vent filters).

Emissions of filterable PM/PM10 from the materials handling baghouses shall not

exceed the following:

 0.005 gr/dscf, expressed as the average of 3 Method 5 or 5D test runs, for

baghouses OCH-DC-1, EP-W-MH-01 and EP-W-MH-02

 0.01 gr/dscf, expressed as the average of 3 Method 5 or 5D test runs, for

baghouses EP-W-MH-03, EP-W-MH-05, EP-W-MH-08 and EP-W-MH-09.

Visible emissions shall not exceed 10 percent opacity at any materials handling

baghouse or vent filter.

Deseret Power has noted that AP-42, Table 1.1-6, states that the PM10 emissions from a

baghouse are 92% of the total particulate matter emissions from a baghouse. Based on this

information, EPA proposes that the BACT limit for total filterable particulate also serve as the

BACT limit for filterable PM10, and that Method 5 or 5D test results be considered sufficient for

both purposes.
133

EPA is not proposing any BACT emission limits for the vent filters because EPA is not

aware of any feasible way to measure the emissions. Instead, EPA proposes that the opacity limit

serve to monitor overall performance of the PM/PM10 controls for materials handling.

6. Proposed compliance monitoring approach: For compliance demonstrations at the baghouses, EPA proposes to require Method 5 or 5D stack tests. Since Method 5 or

5D measures total filterable particulate, which includes filterable PM10, EPA is not proposing to

require separate Method 201 or 201A testing for filterable PM10.

EPA considered requiring at least an initial stack test at each of the baghouses, but

Deseret Power asked EPA to reconsider, on the basis that the information gained from testing

would not justify the cost. Deseret Power pointed out that the baghouses will not come equipped

with sampling access. Construction of sampling ports and sampling platforms would add to the

cost of testing. EPA Region 8 consulted on this with specialists at the Emission Measurement

Center (EMC) in EPA’s Office of Air Quality Planning and Standards (OAQPS). EMC provided

the following cost estimate, which should be regarded as only a very rough estimate:

Construct sampling port $ 700

Construct sampling platform 4,000

Utilities 1,200

Total to create sampling access $5,900

The cost of a Method 5 or 5D test is estimated by EMC at $3,000 to $5,000 (assuming

less than 500 miles of travel for the stack testing firm), bringing the total to about $9,000 to

$11,000 per baghouse, to create sampling access and conduct a test.

In evaluating whether or not the permit should require testing at all baghouses, EPA

considered the following factors besides cost:

 the need to ensure in PSD permits that emission limits are enforceable as a

practical matter,

 the likelihood of emission noncompliance, due to baghouse malfunction,

baghouse bypassing, baghouse deterioriation over time, or any other reason,

 the amount of potential emissions from each baghouse,

 the feasibility of conducting three consecutive Method 5 or 5D test runs, given the

expected intermittent use of some of the baghouses (e.g., silo loading or

unloading) and the amount of time needed to collect a measurable sample, and

 the possibility that test results at one baghouse could be representative of other

baghouses.
134

Key considerations were that the smaller baghouses at the proposed WCFU have very low

emission potential and will only be used intermittently (because operations such as silo loading/

unloading only occur intermittently). After weighing all the considerations, EPA determined that

the appropriate testing regime for the WCFU project would be to require at least an initial stack

test at the three materials handling baghouses which are believed to have the largest emission

potential. These are baghouses OCH-DC-1, EP-W-MH-01, and EP-W-MH-05. If tests at these

baghouses are in excess of emission allowables, then tests will be required at the remaining

baghouses. EPA proposes the following permit provisions:

Initial performance stack tests shall be completed within 60 calendar days

after initial startup of baghouses OCH/DC-1, EP-W-MH-01 and EP-W-MH05.

If results of initial performance stack testing at EP-W-MH-01 are in excess of

the applicable emission limit in this permit, then baghouse EP-W-MH-02

shall also be initially stack tested, within 90 calendar days after initial

performance stack test results at EP-W-MH-01 are required to be submitted

to EPA.

If results of initial performance stack testing at EP-W-MH-05 are in excess of

the applicable emission limit in this permit, then baghouses EP-W-MH-03,

EP-W-MH-08 and EP-W-MH-09 shall also be initially stack tested, within 90

calendar days after initial performance stack test results at EP-W-MH-05 are

required to be submitted to EPA.

If results of any initial performance stack test are in excess of the applicable

emission limit for that baghouse, the baghouse shall be retested annually. If

results of a retest are not in excess of the applicable emission limit, further

retests shall not be required.

For monitoring performance of the materials handling baghouses, and to track ongoing

compliance with particulate emission limits, EPA also proposes, as mentioned above, a 10

percent opacity limit and monthly opacity observations. EPA proposes the following permit

provisions:

For demonstrating compliance with the opacity limit of ten percent at the

materials handling vent filters and baghouses in this permit, the Permittee

shall conduct Method 22 visible emission observations at least once per

month, at each vent filter and baghouse. If any visible emissions are

observed, both of the following actions shall be taken:

a. The cause of the visible emissions shall be investigated and any

baghouse or vent filter malfunction shall be corrected within three
135

working days in the case of broken or damaged bags, or within seven

working days for any other type of baghouse malfunction.

b. A Method 9 visible emission observation shall be conducted and

recorded for that baghouse or vent filter, by an observer who is

certified in the use of Method 9, within 24 hours after visible

emissions are observed by Method 22.

If no visible emissions are observed in three consecutive monthly

observations, frequency of observation at that baghouse or vent filter may be

reduced to quarterly. If visible emissions are observed in any quarterly

observation, frequency of observation shall return to monthly.

EPA proposes to allow seven working days to correct baghouse malfunctions, other than

broken or damaged bags, because Deseret Power has stated that parts needed to make baghouse

repairs are not always readily available and have to be special-ordered and delivered by air

freight to Salt Lake City and then transported by motor carrier to the plant site, which is located

in remote eastern Utah. EPA proposes three working days in the case of broken or damaged bags

because EPA considers it reasonable to expect Deseret Power to keep extra bags on hand at the

plant site.

EPA considered also requiring installation and use of bag leak detectors at the materials

handling baghouses. These detectors are considered by EPA to be very useful and effective for

early detection of bag leaks; however, cost should also be considered where small baghouses are

involved. EPA Region 8 was informed by the Emission Monitoring Center at EPA-OAQPS that

the capital cost of a bag leak detector might be as much as $24,000, and the annualized cost

might be as much as $7,000 (including capital cost recovery). Although these estimates are

considered very preliminary by the EMC, they appear to EPA Region 8 to be too high to be

justified for the materials handling baghouses at this project, considering that baghouse operation

is expected to be intermittent, potential emissions are expected to be low, baghouse bypassing,

according to Deseret Power, by design is expected to be physically impossible, and the baghouses

will be monitored for opacity compliance on an ongoing basis.

This cost analysis for bag leak detectors is only pertinent to the materials handling

baghouses and should not be construed as a statement that bag leak detectors are too expensive to

be justified at larger baghouses, such as at the main boiler baghouse for the WCFU. EPA is not

requiring bag leak detectors at the main boiler baghouse because EPA is requiring use of PM

CEMS instead. EPA considers PM CEMS a superior technique for monitoring main boiler

baghouse performance and tracking compliance with the PSD BACT emission limit in this

permit for filterable particulate matter emissions from the CFB boiler.
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7. Comparison to applicable NSPS emission standard.

The definition of BACT in 40 CFR 52.21(b)(12) contains the statement that, “In no event

shall application of best available control technology result in emissions of any pollutant which

would exceed the emissions allowed by any applicable standard under 40 CFR parts 60 and 61.”

The applicable emission standard, in Subpart Y of 40 CFR part 60 (New Source Performance

Standards), is a 20 percent opacity limit, which will be applicable to coal processing baghouses

OCH/DC-1, EP-W-MH-01 and EP-W-MH-02. The proposed PSD BACT emission limit of 10

percent is more stringent.
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R. BACT for PM/PM10 Non-Point Source Emissions from Materials Handling.

This section addresses BACT for non-point sources of PM/PM10 emissions associated

with materials handling for the WCFU (coal, limestone and ash). Non-point emission sources

include: conveyors for coal, limestone and ash, unenclosed coal and limestone stockpiles, coal

stockpile loadout, and ash handling. Fugitive emissions generated at conveyor transfer points are

considered by EPA to be point source emissions and are addressed in section L above.

1. Step 1: Identify Potential Control Technologies.

 Coal, ash and limestone conveyors – Eliminate exposure of

material to the wind by enclosing the conveyors.

 Unenclosed coal and limestone stockpiles -- Compact the surface,

seal the stockpiles with a surfactant initially, and with subsequent

application of surfactant sealant and water sprays as warranted to

minimize fugitive emissions. Alternatively, enclose the stockpiles.

 Coal stockpile loadout – Use a telescoping chute to enclose the free

fall of material during loadout operation and limit the exposure of

the material flow stream to the wind.

 Ash handling for disposal -- Hydrate the ash prior to transfer for

disposal.

2. Step 2: Eliminate Technically Infeasible Options.

All potential control technologies listed above are technically feasible, with the exception

of enclosing the stockpiles. Due to handling problems that would be caused when trying to

reclaim coal from an enclosed stockpile, this option is not considered technically feasible.

3. Step 3: Rank Remaining Control Technologies by Control Effectiveness.

Since Deseret Power proposes to utilize all technically feasible control technologies listed

above, ranking is not necessary.

4. Step 4: Evaluate Economic, Environmental and Energy Impacts.

Since Deseret Power proposes to utilize all technically feasible control technologies listed

above, a comparison of the technologies in terms of impacts is not necessary.
138

5. Step 5: Proposed BACT for PM/PM10 Non-Point Source Emissions from

Materials Handling.

EPA proposes the following permit conditions as BACT:

 All coal, limestone and ash conveyors serving the WCFU shall be fully

enclosed.

 All fugitive emissions generated at coal, limestone and ash conveyor

transfer points serving the WCFU, as well as at coal, limestone, ash,

lime and inert material storage silos and storage bins serving the

WCFU, shall be routed to fabric filter dust collectors (baghouses or

vent filters).

 All fugitive emissions from unenclosed coal and limestone stockpiles

serving the WCFU shall be controlled by compaction of the surface

and by application of water sprays and surfactant when warranted.

Conditions which warrant application of surfactant or water sprays

are defined in this permit as any time a ten percent opacity level is

exceeded.

 The Permittee shall conduct weekly Method 22 observations of the

coal and limestone stockpiles for visible emissions. If any visible

emissions are observed, the Permittee shall conduct a Method 9 visible

emission observation within 24 hours, by an observer who is certified

in the use of Method 9. If opacity in excess of ten percent is observed

by Method 9, the Permittee shall immediately apply dust suppression

(water spray and/or surfactant).

 The coal stockpile loadout shall be equipped with a telescoping chute

to enclose the free fall of material during loadout operation and limit

the exposure of the material flow stream to the wind.

 All ash generated by the CFB boiler shall be hydrated, via a pugmill

mixer, prior to transfer for disposal.

6. Proposed compliance monitoring approach.

EPA proposes that compliance with the above requirements be demonstrated by keeping

the necessary records.
139

S. BACT for PM/PM10 Emissions from Cooling Tower.

There will be one mechanical draft cooling tower installed as part of the project to cool

the circulating water. The cooling tower will have 3 or 4 cells to provide the needed cooling.

Each cell will have a large fan to move the air through the tower. Because wet cooling towers

provide direct contact between the cooling water and the air passing through the tower, some of

the liquid water is entrained in the air stream and can be carried out of the tower as drift droplets.

As the water evaporates in the drifting cooling tower plume, the dissolved solids in the water

forms particulates or PM10. The magnitude of the uncontrolled drift loss is influenced by the

design of the cooling tower, the fill design, the air and water flow pattern and other factors.

1. Step 1: Identify Potential Control Technologies.

The only known method of control for particulate matter from cooling towers is effective

drift eliminators. Drift eliminators are incorporated into cooling tower design to remove as many

water droplets as practical from the air stream before exiting the tower. The drift eliminators rely

on separation caused by direction changes as the air passes through the drift eliminators.

2. Step 2: Eliminate Technically Infeasible Options.

Drift eliminators are the only technically feasible control option. Drift eliminator

configurations include blades, herringbone, wave form and cellular or honeycomb designs. The

cellular design is the most efficient.

3. Step 3: Rank Remaining Control Technologies by Control Effectiveness.

Deseret Power proposes to use drift eliminators with the most efficient configuration

available (cellular), therefore ranking is not necessary.

4. Step 4: Evaluate Economic, Environmental and Energy Impacts.

Deseret Power proposes to use drift eliminators with the most efficient configuration

available (cellular), therefore evaluation of impacts is not necessary.

5. Step 5: Proposed PM/PM10 BACT for Cooling Tower.

Deseret Power has stated that the proposed cooling tower will be equipped with high

efficiency drift eliminators capable of removing 99.999% of the potential drift loss. This will

result in a drift loss rate of 0.001% of the cooling tower circulating water flow. In an e-mail to

EPA on November 11, 2005, Deseret Power proposed 0.001% drift loss as BACT. PM10

emission calculations of 3.0 lb/hr and 11.81 tons/year, on page A-3 of Deseret's PSD Permit

Application dated November 1, 2004, are based on this rate of drift loss.
140

EPA found two recently issued PSD permits for coal-fired energy projects with BACT

determinations of 0.0005% maximum drift loss at cooling towers:

 Intermountain Power Unit 3 project in Utah

 Excel Energy Comanche Unit 3 project in Colorado

Reducing drift loss from 0.001% to 0.0005% would reduce PM/PM10 emissions at

Deseret Power’s proposed WCFU from 11.8 tons/year to 5.9 tons/year. Deseret Power has stated

that to reduce drift loss to 0.0005%, it would be necessary for the manufacturer to install

additional layers of the cellular material in the cooling tower. This would make the cooling

tower taller and increase the fan horsepower to force the air through the enlarged drift

eliminators.

Deseret Power has provided a cost analysis indicating that reducing drift loss from

0.001% to 0.0005% would cost approximately $10,195 per ton of additional PM/PM10 removed.

Below is a summary of that cost analysis. Calculation methods from EPA’s Office of Air Quality

Planning and Standards (OAQPS) Control Cost Manual were used.

PM/PM10 BACT Cost Analysis for Cooling Tower:

Reducing Drift Loss from 0.001 Percent to 0.0005 Percent

Capital Costs:

 Total Direct Cost (TDC) $140,000

 Total Indirect Cost (TIC) 41,700

 Total Direct and Indirect Costs (TDIC) $181,700

 Contingency (0.1 x TDIC) 18,170

 Total Installed Capital Cost (TICC) $199,870

Annualized Costs:

 Direct Annualized Costs:

-- Total Fixed O&M Costs (TFOM) $10,292

-- Total Variable O&M Costs (TVOM) 13,705

-- Total Direct Annualized Costs (TDAC) $23,997

 Indirect Annualized Costs:

-- Overhead, property tax, insurance, G&A charges $14,170

-- Capital cost recovery 21,986

-- Total Indirect Annualized Costs (TIAC) $36,156

 Total Annualized Costs (TAC = TDAC + TIAC) $60,153
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Total additional tons of pollutant removed per year 5.9

Cost Effectiveness ($ per ton of pollutant removed) $10,195

EPA agrees with Deseret Power’s conclusion that the cost per ton of achieving lower than

0.001 percent drift loss is not justified. EPA therefore proposes the following as BACT for

PM/PM10 at the cooling tower:

0.001 percent maximum drift loss

Considering the high cost of stack testing ($20,000 estimated by the vendor), and the

technical difficulties of such testing, and the fact that a drift eliminator is a passive control device

(i.e., its effectiveness is based largely on its design, rather than on operation and maintenance

practices), EPA proposes to express the BACT limit for drift loss as a design requirement, as

follows:

The cooling tower shall be equipped with cellular-type mist eliminators

designed to limit circulating water drift loss to 0.001 percent or less.

6. Proposed compliance monitoring approach: EPA proposes for compliance

to be demonstrated by records documenting that the drift eliminator has been designed to limit

drift loss to 0.001 percent or less.
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VII. Applicability/Non-applicability of Other Federal Requirements

A. New Source Performance Standards.

The WCFU will be subject to the following subparts of 40 CFR part 60:

Subpart A – General Provisions

Subpart Da – Standards of Performance for Electric Utility Steam Generating

Units for Which Construction is Commenced After September 18, 1978

Subpart Y – Standards of Performance for Coal Preparation Plants

Appendix B – Performance Specifications

Appendix F – Quality Assurance Procedures

Subpart A: Any emissions unit subject to an NSPS subpart is also subject to the general

provisions in Subpart A (40 CFR 60.1 through 60.15). Key provisions of Subpart A include:

§60.7 – Notification and recordkeeping (including excess emission reporting and

continuous emission monitoring system performance reporting)

§60.8 – Performance testing

§60.11 – Compliance with standards and maintenance requirements

§60.13 – Monitoring requirements

Subpart Da: NSPS Subpart Da applies to electric utility steam generating units for which

construction or modification is commenced after September 18, 1978, and which are capable of

combusting more than 250 MMBtu/hr heat input of fossil fuel. The following provisions will

apply:

§60.40Da – Applicability and designation of affected facility

§60.41Da – Definitions

§60.42Da – Standard for particulate matter

§60.43Da – Standard for sulfur dioxide

§60.44Da – Standard for nitrogen oxides

§60.45Da – Standard for mercury

§60.48Da – Compliance provisions

§60.49Da – Emission monitoring

§60.50Da – Compliance determination procedures and methods

§60.51Da – Reporting requirements

§60.52Da – Recordkeeping requirements
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Emission Limits in Amended NSPS Subpart Da, as of July 1, 2007

Applicable to Units Commencing Construction after February 28, 2005

Pollutant

NSPS

Emission Limit

NSPS

Citation

NSPS Required

Performance Test

Particulate

matter

(filterable)

[0.015 lb/MMBtu heat input or

0.14 lb/MWh gross energy output]

(daily average)

**OR**

[0.03 lb/MMBtu heat input and

99.9% reduction]

(daily average)

§60.42Da(c)

and (d)

Method 5 stack test

SO2 1.4 lb/MWh or 94% reduction

(30-day rolling average)

applicable to units burning 75% or

more (by heat input) coal refuse on a

12-month rolling average basis,

otherwise 95% reduction applies.

§60.43Da(i)(1)

and (j)(1)

CEMS

NOx 1.0 lb/MWh

(30-day rolling average)

§60.44Da(e)(1) CEMS

Opacity 20% on a 6-minute average

(except for one 6-minute period

per hour not to exceed 27%)

§60.42Da(b) Method 9

(3 hours for initial

performance test);

COMS thereafter

unless PM CEMS is

installed and used

Mercury 0.016 lb/GWh

(12-month rolling average)

applicable to units burning only coal

refuse; otherwise for coal blends a

weighted average applies

§60.45Da(a)(4)

and (5)

CEMS

Footnote: MWh = megawatt-hour, GWh = gigawatt-hour.
144

§60.48Da(c) states that the PM, NOx and mercury emission standards apply at all times

except during periods of startup, shutdown or malfunction. §60.48Da(d) contains provisions that

allow an affected facility with a malfunctioning flue gas desulfurization system to operate during

“emergency conditions.”

In addition to amended emission limits, the following key amendments were made in

2005, applicable to units commencing construction after February 28, 2005:

 §60.41Da has been amended, to change the definition of boiler operating day to mean any

24-hour midnight-to-midnight period during which fuel is combusted in the unit. The

existing definition in Subpart Da was any 24-hour period during which fuel is combusted

the entire 24 hours. The existing definition will continue to apply to existing units.

 §60.48Da(i) has been added, to specify the calculation methodology for demonstrating

compliance with NOx emission limits in lb/MWh.

 §60.48Da(l) has been added, to specify the calculation methodology for demonstrating

compliance with mercury emission limits in lb/MWh.

 §60.48Da(m) has been added, to specify the calculation methodology for demonstrating

compliance with SO2 emission limits in lb/MWh.

 §60.48Da(n) has been added, to specify the calculation methodology for demonstrating

compliance with particulate matter emission limits in lb/MWh.

 §60.48Da(o)(1) has been added, to require the initial performance test for particulate

matter to be repeated annually.

 §60.48Da(o)(2) has been added, to require that opacity monitoring be used not only to

demonstrate compliance with the opacity limit in §60.42a(b), but also be used as an

indicator of continuous particulate matter control device performance. For the latter

purpose, a baseline opacity level must be established during the initial performance test.

If subsequent measurement of hourly average opacity is more than 110% of the baseline

level, a new performance test will be required within 60 days, to demonstrate emission

compliance. A new baseline is established with each performance test. In no event may

the baseline exceed the opacity limit in §60.42a(b). A Continuous Opacity Monitoring

System (COMS) is required for tracking opacity compliance.

 §60.48Da(o)(4) has been added, to require a bag leak detection system at fabric filters

(baghouses) used to comply with the particulate matter standard in Subpart Da. Specific

performance requirements for the bag leak detection system are laid out in §60.48a(o)(4).
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 §60.48Da(p) has been added, to allow for PM CEMS to be used as an alternative to the

monitoring requirements of §60.48a(o). The PM CEMS must be certified by Performance Specification 11, as required by new section §60.49a(v). Valid hourly average

emission measurements are required for 90% of all operating hours, on a 30-day rolling

average.

 §60.49Da(f)(2) has been added, to require that emission data from SO2 CEMS, NOx

CEMS, and COMS (where required) be obtained for at least 90% of all operating hours

for each 30 successive boiler operating days. Existing units will remain subject to the

existing CEMS availability requirement in Subpart Da (at least 18 hours in at least 22 out

of 30 successive boiler operating days), specified in §60.49a(f)(1).

 §60.49Da(p) has been added, to require a mercury CEMS.

 §60.50Da(h) has been added, to specify performance test requirements for demonstrating

mercury emission compliance.

Subpart Y: Since waste coal for the WCFU will be crushed at the Bonanza Power Plant

at a rate exceeding 200 tons per day, the coal processing, conveying and storage system will be

subject to a 20% opacity limit in 40 CFR 60.252(c). Baghouses OCH/DC-1, EP-W-MH-01 and

EP-W-MH-02 will be subject to this opacity limit.

In the proposed PSD permit for construction of the WCFU, EPA does not specify the

detailed requirements of NSPS, but just states that NSPS subparts A, Da and Y will apply. PSD

BACT must be at least as stringent as NSPS, but PSD rules do not require that NSPS provisions

be included in PSD permits. The detailed NSPS provisions will be included in the 40 CFR part

71 operating permit, to be issued after the WCFU is constructed and operating. The requirement

for Deseret Power to apply for an operating permit for the WCFU is cited in section VII.C below.

Appendices B and F: Pursuant to §60.13, the WCFU will also be subject to the provisions of Appendices B and F of 40 CFR 60. Appendix B contains Performance Specifications

(PS’s) for continuous monitoring systems for opacity (PS1), SO2 and NOx (PS2), diluent (PS3),

CO (PS4), and total filterable particulate matter (PS11). Appendix F contains quality assurance

procedures for gaseous CEMS used for NSPS compliance determination. The gaseous CEMS

for SO2 and NOx at the WCFU will be compliance-determining under NSPS Subpart Da.

B. Acid Rain Program.

The WCFU will be an “affected unit” as defined in 40 CFR 72.2 and will therefore be

subject to applicable acid rain rules at 40 CFR parts 72 through 78. Key requirements are:

1. Permitting. At least twenty four (24) months before commencing

operation of the WCFU, the Permittee must submit an application for an Acid Rain Program
146

permit in accordance with 40 CFR 72.

2. SO2 allowances. The WCFU will be subject to requirements under 40

CFR 72.9(c)(1) and 40 CFR 73 for affected Acid Rain units to obtain and hold acid rain SO2

allowances in the unit’s compliance subaccount (after any applicable deductions), as of the

allowance transfer deadline (defined in 40 CFR 72), not less than the total annual emissions of

SO2 for the previous calendar year from the unit, and to comply with the applicable Acid Rain

emission limitation for SO2.

3. Continuous emission monitoring. The WCFU will also be subject to the

continuous emission monitoring requirements in 40 CFR part 75. These include requirements

for monitoring of SO2, NOx, CO2 (not CO) and volumetric flow rate, and quality assurance

requirements for continuous monitors.

4. NOx emission limits. The WCFU will not be subject to any acid rain NOx

emission limits in 40 CFR part 76. This is because the unit did not combust any coal during

1990-1995, therefore is not a “coal-fired utility unit” as defined in §76.2. However, continuous

monitoring of NOx emissions will still be required under 40 CFR part 75.

C. Operating Permits Program.

Under 40 CFR part 71, the Permittee is required to submit an application for a Part 71

(Clean Air Act title V) Permit to Operate, within twelve months after commencing operation of

the WCFU.

D. Case-Specific MACT Determination.

The November 1, 2004 permit application for the WCFU included a proposal for casespecific determination of Maximum Available Control Technology (MACT) under section

112(g) of the Clean Air Act. However, such determination will not be required. On March 29,

2005, EPA published a final rule, entitled:

Revision of December 2000 Regulatory Finding on the Emissions of

Hazardous Air Pollutants from Electric Utility Steam Generating

Units and the Removal of Coal- and Oil-Fired Electric Utility Steam

Generating Units from the Section 112(c) List.

In that final rule, EPA removed coal-fired and oil-fired electric utility steam generating

units from the Clean Air Act section 112(c) source category list. As a result of that action, the

requirements of section 112(g) no longer apply to such units and therefore section 112(g) is no

longer an applicable requirement for such units, within the meaning of 40 CFR 71.2. Accordingly, the discussion of case-specific MACT in Deseret Power’s PSD permit application of

November 1, 2004, is no longer applicable.
147

In a related final rulemaking published in the Federal Register on May 18, 2005, 70 FR

28606, the EPA Administrator issued standards of performance under section 111 of the Clean

Air Act (“New Source Performance Standards”), rather than section 112 MACT standards, to

regulate mercury emissions from coal-fired and oil-fired electric utility steam generating units.

The WCFU will be subject to those NSPS standards, found at 40 CFR 60.45Da, titled “Standards

for mercury.” The reference in the proposed PSD permit to NSPS subpart Da encompasses those

new standards. The applicable mercury emission limit for the WCFU is listed in section VII.A

above.
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VIII. Air Quality Impact Analysis

A. Required analyses. The Federal PSD rules, at 40 CFR 52.21(k), require the permit

applicant to demonstrate that the allowable emission increases (including secondary emissions)

from the proposed source modification (in this case, addition of a coal-fired unit at Deseret’s

Bonanza power plant), in conjunction with all other applicable emission increases or reductions

at the source, for all pollutants that would be emitted in excess of the significance thresholds at

§52.21(b)(23)(i), would not cause or contribute to a violation of any National Ambient Air

Quality Standard (NAAQS), nor cause or contribute to a violation of any applicable “maximum

allowable increase” over the baseline concentration in any area. The PSD significance thresholds

are listed in the table below.

Significant Emission Rates in Tons Per Year

Pollutant Emission Rate

Carbon Monoxide 100

Nitrogen Oxides 40

Sulfur Dioxide 40

Particulate Matter (PM/PM10) 25/15

Sulfuric Acid Mist 7

Fluorides 3

Under the proposed PSD permit for the WCFU, emission increases at Bonanza plant

would be allowed in excess of PSD significance thresholds for PM/PM10, SO2, NOx, CO and

H2SO4. Therefore, a demonstration of NAAQS and increment protection under §52.21(k) is

required for these pollutants.

(Note: Fluorides will be allowed to be emitted in excess of the significance threshold of 3

tons per year, but all of these emissions will be in the form of hydrogen fluoride (HF), a

hazardous air pollutant not regulated under PSD. EPA’s Office of Air Quality Planning and

Standards has advised that PSD requirements for ambient impact analysis and BACT are not

applicable where all fluoride emissions from the proposed project are in the form of HF.)

The “maximum allowable increases,” also known as PSD increments, are listed in

§52.21(c). There are PSD Class I, II and III increments, applicable to areas designated Class I, II

and III. Class I areas are defined in §52.21(e). Mandatory Class I areas (which may not be

redesignated to Class II or III) are international parks, national wilderness areas larger than 5,000

acres, memorial parks larger than 5,000 acres, and national parks larger than 6,000 acres.

Mandatory Class I areas in Utah are listed in 40 CFR 81.430. Class II areas are defined in

§52.21(g). These are defined as all areas not designated Class I, except for any areas

redesignated from Class II to Class III. No areas have been redesignated to Class III that might

be impacted by this project. The PSD Class I and II increments and the NAAQS are listed in the

table below.
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NAAQS and PSD Class I/II Increments

Pollutant Averaging

Period

NAAQS

(ug/m

3

)

PSD Class I

Increment

(ug/m

3

)

PSD Class II

Increment

(ug/m

3

)

NO2 Annual 100 2.5 25

CO 8-hour 10,000 NA NA

1-hour 40,000 NA NA

3-Hour 1,300 25 512

24-Hour 365 5 91

SO2

Annual 80 2 20

PM10 24-Hour 150 8 30

Annual 50 4 17

§52.21(m) requires the PSD permit application to include an air quality impact analysis

for making the demonstration required by §52.21(k). For each pollutant for which a NAAQS or

PSD increment exists, §52.21(m)(1)(iv) requires the analysis to include at least one year of preconstruction ambient air quality monitoring data, unless EPA approves a shorter monitoring

period (not less than four months). The analysis must be based on air quality models, data bases,

and other requirements specified in 40 CFR 51, Appendix W, Guideline on Air Quality Models.

§52.21(m)(2) requires post-construction ambient air quality monitoring, if EPA determines it is

necessary to determine the effect that emissions from the source modification may have on air

quality.

§52.21(i)(5)(i) allows exemption from the requirement for pre-construction ambient

monitoring, where the net emissions increase of a pollutant from the proposed source

modification would cause air quality impact less than the amount listed for that pollutant in

§52.21(i)(5)(i).

§52.21(o) requires additional impact analyses, which must include an analysis of the

impairment to visibility, soils and vegetation that would occur as a result of the proposed source

modification, or that would occur as a result of any commercial, residential, industrial and other

growth associated with the source modification. Analysis for vegetation having no significant

commercial or recreational value is not required.

For sources impacting Federal Class I areas, §52.21(p) requires EPA to consider any

demonstration by the Federal Land Manager that emissions from the proposed source

modification would have an adverse impact on air quality related values (AQRVs), including

visibility impairment. If EPA concurs with the demonstration, the rules require that EPA shall

not issue the PSD permit.
150

B. Modeling methodology.

1. General. Prior to conduct of modeling, a modeling protocol was submitted

and methodologies were approved by the EPA and federal land managers (National Park

Service). The dispersion modeling analysis for NAAQS compliance and PSD Class II increment

compliance consisted of two phases: (1) a near field analysis and (2) a full impact analysis. For

each pollutant, results of the near field analysis determine whether a full-impact analysis is

needed for that pollutant. Near field analysis was performed to determine pollutant concentrations at the fence line and beyond for the proposed WCFU alone. Full-impact analysis was

performed to determine pollutant concentrations from all sources (including Bonanza Unit 1)

within and around the area of impact, and at Class I areas (far-field), for compliance with

NAAQS and PSD Class I and II increments.

Additional modeling analyses were also performed as part of the far-field analysis, to

ascertain the impact on regional haze, plume blight, and deposition at the Class I areas in Utah,

Colorado, and Wyoming from the proposed WCFU

2. Near field modeling. Near field dispersion modeling was performed to

determine the impact from proposed WCFU emissions only. This modeling addressed only the

regulated NSR pollutants for which the WCFU would cause a significant net emissions increase

at Bonanza plant. The pollutants with emission rates above PSD significance levels include

carbon monoxide (CO), nitrogen oxides (as NO2), sulfur dioxide (SO2), particulate 10 microns or

less (PM10), sulfuric acid mist (H2SO4), fluorides (Fl), and beryllium (Be). The Building Profile

Input Program (BPIP) was utilized to address downwash and determine Good Engineering

Practice (GEP) stack height.

(Note: After the modeling protocol for the WCFU was first submitted to EPA in August

of 2001, EPA removed beryllium from the list of pollutants with PSD significance thresholds in

§52.21(b)(23)(i).)

3. Full-impact modeling (evaluate cumulative analysis area). The WCFU

project full-impact (i.e., cumulative analysis) area was determined based on the modeled

maximum pollutant concentrations from the WCFU, obtained from the near field analysis

described above. The impact area is the geographical area for which the required air quality

impact analyses for the NAAQS and PSD increments are carried out. Existing emissions sources

within the full-impact area are included in WCFU PSD increment and NAAQS modeling to

determine cumulative impacts. This area includes all locations where the significant increase in

the potential emissions of a pollutant from WCFU sources only will cause a significant ambient

impact (i.e., equals or exceeds the applicable significant impact level, or SIL, listed in 40 CFR

51.165). The SILs are a screening tool to determine the extent of the air quality analysis required

to demonstrate compliance with the NAAQS and PSD increments. The table below presents the

SILs for air quality impacts in PSD Class II areas.
151

Significance Levels for Air Quality Impacts

in PSD Class II Areas

Pollutant Annual 24-hour 8-hour 3-hour 1-hour

SO2 1 5 - 25 -

PM10 1 5 - - -

NO2 1 - - - -

CO - - 500 - 2,000

Modeled maximum concentration results from near field modeling were above the

significance levels listed above for SO2 and PM10. Based on these pollutant concentrations, the

full-impact area was determined.

The full-impact area is a circular area with a radius extending from the source to the most

distant point where the model (ISC3 in this case – Industrial Source Complex, version 3) predicts

a significant impact will occur. The impact area used for the full impact analysis was the largest

of the areas determined for each pollutant reviewed. The maximum distances determined for

each pollutant above the significance levels were 16.0 kilometers for SO2 and 3.9 kilometers for

PM10. A distance of 50 kilometers was added to each distance to define the scope of the full

impact analysis.

A nearby source inventory was conducted for sources that fell within the impact area.

Sources with SO2 and PM10 emissions of 25 tons or greater were identified from emissions

information obtained from the Colorado Department of Health for Rio Blancho, Moffat, and

Garfield Counties in western Colorado, EPA AIRS database, and from the Utah Division of Air

Quality for Uintah County. Based on this source inventory information, no sources in Colorado

or Utah met the 25 ton criteria and fell within the impact area with the exception of Bonanza Unit

1.Source (stack and fugitive) emission information for Bonanza Unit 1 was obtained and added

to the ISC3 model for the full impact analysis.

4. Far-field modeling. Far-field modeling was performed as part of the fullimpact analysis, to determine the maximum ground-level pollutant concentrations at the PSD

Class I and II areas from the proposed WCFU, for impact on air quality, visibility, and

deposition. After consultation with the National Park Service, Bureau of Land Management

(BLM), and the Forest Service Managers, Deseret Power was requested to evaluate the impacts

from the proposed project at Canyonlands, Capitol Reef, and Arches National Parks in

southeastern Utah, High Uintah Wilderness Area in Utah, Flat Tops and Mt. Zirkel Wilderness

areas and Colorado National Monument in western Colorado, and Fitzpatrick and Bridger

Wilderness areas in eastern Wyoming. For Dinosaur and Colorado National Monuments in

Colorado, SO2 concentrations were reviewed against the PSD Class I increments only. At the

High Uintah Wilderness area and receptors within the Ute Tribe reservation, pollutant

concentrations were compared against the PSD Class II increments.
152

5. Visibility modeling. Visibility impairment is defined as “...any humanly

perceptible change in visibility (visual range, contrast, coloration) from that which would have

existed under natural conditions.” First, the pollutant loading of a section of the atmosphere can

become visible, by the contrast or color difference between a layer or plume and a viewed

background, such as a landscape feature or the sky. The second way that visibility can be

impaired is a general alteration in the appearance of landscape features or the sky, changing the

color or the contrast between landscape features or causing features of a view to disappear. The

first phenomenon is referred to as plume impairment or plume blight; the second is referred to as

uniform haze impairment. As plumes are transported within a stable atmospheric layer, they may

become a layered haze

Visibility modeling was performed to determine the impact from the proposed WCFU

plume against a background (plume impairment) and uniform haze impairment. For the uniform

haze impairment, the concentrations derived from the CALPUFF model were used to calculate

the extinction coefficients due to these pollutants. These values were then compared against the

light extinction coefficient of the background air. CALPOST was set up to directly calculate the

combined visibility effects from different visibility impairing pollutants.

Although all the Class I areas in this analysis were greater than 50 kilometers from the

proposed WCFU, VISCREEN was applied to assess the visual effects at Arches, Canyonlands

and Capitol Reef National Parks, and Mt. Zirkel, Fitzpatrick, Bridger, and Flat Tops Wilderness

Areas. The extinction coefficients for hygroscopic species (modeled and background) were

computed using the seasonal relative humidity (RH) adjustment factors for each national park

and wilderness area found in the FLAG Phase I report, Table 2.B-1. Per recommendation by the

National Park Service, the maximum relative humidity was set to 98% and 95% to cap the

maximum f(RH) used in the averages. The 95% relative humidity cap was described by the NPS

as the future procedure for calculating light extinction that will be incorporated in the next FLAG

report release.

6. Deposition analysis. At the request of the BLM, a deposition analysis was

performed to determine the proposed WCFU’s contribution to the total sulfur and nitrogen

deposition at the PSD Class I areas. The total sulfur and total nitrogen deposition was calculated

for two lakes in the Flat Tops Wilderness Area, Ned Wilson Lake and Upper Ned Wilson Lake,

and for three lakes in the Mt. Zirkel Wilderness Area, Lake Elbert, Seven Lakes, and Summit

Lakes.

For sulfur (S) deposition, the wet and dry fluxes of SO2 and sulfate (SO4) were calculated

and normalized by the molecular weight of sulfur (32), and expressed as total S. For nitrogen

(N) deposition, IWAQM recommended that the wet and dry fluxes of nitric acid (HNO3) and

nitrate (NO3) and the dry flux of nitrogen oxides (NOX) be calculated, normalized by the

molecular weight of N (14), and express as total N.
153

CALPUFF was used to output the wet and dry fluxes of SO2, SO4, HNO3, and NO3. The

modeled deposition flux of each of the oxides of sulfur and nitrogen from CALPUFF was

adjusted for the difference of the molecular weight of their oxides and the element, and the

various forms were summed to yield a total deposition of sulfur. This was accomplished by

using a multiplier in CALPOST to do the conversions. The CALPOST program calculated an

average flux.

C. Modeling inputs and assumptions

1. Description of models selected.

a. Near field analysis. ISCST3 (Industrial Source Complex, ShortTerm, version 3) was used for near field analysis. The ISC3 model is a steady-state Gaussian

plume model that can be used to assess pollutant concentrations from a wide variety of sources

associated with an industrial source complex. This model can account for the following: settling

and dry deposition of particles; building downwash; area, line, and volume sources; plume rise as

a function of downwind distance, building dimensions and stack placement with respect to a

building; separation of point sources; and limited terrain adjustment. The ISC3 model assumes

that:

 Pollutant concentrations from a continuously emitted plume are

proportional to the emission rate,

 Ground-level concentrations are inversely proportional to the wind speed,

 The plume doesn’t undergo any chemical reaction, and

 Dispersion produces a normal (Gaussian) distribution of pollutants along

any cross-sectional transect.

b. Far-field analysis. The CALMET/CALPUFF/ CALPOST

modeling system was used for far-field analysis. CALPUFF is a non-steady-state transport and

dispersion model that advects “puffs” of material emitted from modeled sources, simulating

dispersion and transformation processes along the way. The CALPUFF modeling system has

three main components which were utilized for the far-field analyses: CALMET (a diagnostic 3-

D meteoro-logical model), CALPUFF (the transport and dispersion model), and CALPOST (a

post-processing package).

CALMET was utilized to develop hourly wind, temperature, and other geophysical

parameter fields on a three-dimensional meteorological grid. Associated two-dimensional fields

such as mixing height, surface characteristics and dispersion properties were also included in the

file produced by CALMET. The CALMET output was used by CALPUFF for dispersion

calculations. In addition, several other processors were used to prepare geophysical (land use
154

and terrain) data, meteorological data (surface, upper air, precipitation, and buoy data) and utilize

output from other prognostic models such as the Penn State/NCAR Mesoscale Model (MM5).

c. Visibility analysis. For visibility modeling, the VISCREEN and

CALPUFF models were used to determine the impact from the proposed WCFU plume against a

background (plume impairment) and uniform haze impairment, respectively.

VISCREEN is designed to determine whether a plume from a facility has the potential to

be perceptible by untrained observers under worst-case conditions. Generally, VISCREEN is

usually applied for sources locating less than 50 km from a Class I area. Point source emissions

of NOx, PM10, and H2SO4 were modeled using worst-case meteorological conditions. In

addition, for screening-level analyses, the Federal Land Managers Air Quality Related Values

Workgroup (FLAG) recommends the use of the annual average reconstructed natural conditions,

which were used in the analysis.

The FLAG report identified screening criteria for determining whether a pollutant plume

can be perceived compared against natural conditions. These screening criteria are a plume

contrast greater than 0.05 (absolute value) and a change in the color difference index (delta-E)

greater than 2.0.

VISCREEN can be applied in two successive levels of screening (Levels 1 and 2). Level

1 screening is designed to provide a conservative estimate of plume visual impacts using worstcase meteorological conditions. Level 2 screening is identical to that of Level 1 (estimation of

worst-day plume visual impacts) with the exception that more realistic data may be input to the

model. The joint frequency distribution based on wind speed and stability for given wind

direction was calculated for six-hour periods utilizing the on-site meteorological data.

2. Modeling domain and receptor locations. The WCFU project impact area

was determined based on the modeled maximum pollutant concentrations. SO2 and PM10 were

the only pollutants with modeled maximum concentrations above EPA significant impact levels

(SILs). The modeling domain must be large enough to encompass the cumulative analysis area

discussed in B.3 above.

a. Near field analysis. An approximate 50 kilometer (km) by 50 km

modeling domain was used. A discrete receptor grid, consisting of over 18,000 receptors, was

utilized to insure that maximum pollutant concentrations were determined by the model.

Receptors with 50 meter spacing were placed around the fence line and extended out to

approximately 200 meters. From 200 meters to 1 km, receptors were placed every 100 meters.

From 1 km to 5 km, receptors were placed every 200 meters. From 5 km to 25 km, 500 meter

receptor spacing was used.

b. Far field analysis. The study area for the PSD Class I analyses

(CALPUFF modeling domain) was rectangular shaped, approximately 512 km by 776 km region,
155

roughly centered on the proposed WCFU stack. This domain includes a 50 km buffer zone

around the Class I areas to capture recirculation effects. Puffs are tracked within this grid until

they cross outside the boundary. At this point, they are dropped from the simulation.

3. Topography/terrain. The terrain elevation data used for this study were

obtained from the United States Geological Survey’s (USGS) Digital Elevation Model (DEM) in

NAD 27 format. Terrain surrounding the proposed stack and in the modeling domain is

complex. The terrain data consisted of 1 degree quadrangles with a scale of 1:250,000 and a

horizontal resolution of 90-meters. The land use data used in this modeling analysis were also

obtained from the USGS. These land use land cover (LULC) data consisted of 1:250,000 scale

or 1:100,000 scale quadrangles with a horizontal resolution of 200 meters. The grid spacing was

4 kilometers.

4. Source inventory. For full-impact modeling, a nearby source inventory

was conducted for sources that fell within the impact area. Bonanza Unit 1 was the only source,

with pollutant emissions (SO2 or PM10) of 25 tons or greater, identified within the impact area.

The emissions from Bonanza Unit 1, based on 2002 actual emissions, as well as the emissions

from the proposed WCFU, were modeled for full-impact.

5. Ambient background concentration. Determination of ambient background concentration is necessary for the NAAQS compliance analysis. Ambient air quality data

(NO2, SO2, and CO) from the Bonanza plant site were available for the period 1991 through

1993. Particulate data (PM10) were also collected from the first quarter, 1991 through the second

quarter, 1993 and were used to determine a PM10 background value. Based on these monitoring

data and considering potential growth in the area that has occurred since 1993 (including an

estimated 29% increase in SO2 emission rate at the existing Bonanza Unit 1, as reported by

Deseret Power to EPA via March 23, 2005 letter), estimates of background concentrations were

determined as indicated in the table below.

Background Pollutant Concentration Values

(As Corrected by EPA for SO2)

Pollutant Averaging

Period

Concentration

(ug/m3)

24-Hour 12.9

3-Hour 25.8

SO2

Annual 6.5

NO2 Annual 5

PM10 24-Hour 28

Annual 10

CO 1-Hour 1150 (1 ppm)

8-Hour 1150 (1 ppm)
156

6. Meteorology. ISCST3 requires hourly surface wind speed, wind direction,

temperature, stability class and mixing height data. Four years (July 1986-June 1987, 1991-

1993) of on-site surface meteorological data, merged with concurrent mixing height information

for Grand Junction, Colorado, were utilized for input into ISCST3. Three-dimensional timevarying fields of meteorological conditions were developed using hourly surface observations

obtained from the National Weather Service (NWS) Salt Lake City, Utah, Lander/Riverton,

Wyoming, and Grand Junction, Colorado offices for 1992, 1996, and 1999 as well as additional

surface stations that were identified within the modeling domain. For 1992, 1996, and 1999, 18,

17, and 38 additional surface stations, respectively, were utilized. These data were obtained from

National Climatic Data Center (NCDC), Mesowest, and the NPS.

CALMET requires that at least one upper air station also be included in the analysis.

Routinely available NWS twice-daily upper air sounding data obtained from the NCDC for Salt

Lake City, Utah, Lander/Riverton, Wyoming, and Grand Junction, Colorado from 1992, 1996,

and 1999 were used in this analysis. Precipitation data for stations within the modeling domain

for the 1992, 1996, and 1999 were obtained from Earth Info, Inc. Ozone data, obtained from the

EPA’s CASTNET website, were utilized for 1992, 1996, and 1999.

The 1992 and 1996 data, supplied by the NPS and utilized by CALMET/CALPUFF,

consisted of MM4 and MM5 data, respectively. The MM4 and MM5 meteorological data sets

were produced using the Penn State University/NCAR Mesoscale Model (MM) Versions 4 and

5. One year of Rapid Update Cycle (RUC2) analysis converted onto a 30 km Lambert

Conformal grid and written into the MM5.dat format for the period January 26, 1999 through

January 26, 2000 was also input to the CALMET model. These data included 17 vertical levels

of data extending to 450 millibars. Use of these data was concurred on by the NPS on November

16, 2001.

7. Emission rates. The point source emission rates used for modeling the

WCFU and Bonanza Unit 1 are listed in the tables below. Fugitive emissions from coal,

limestone and ash handling were also included in the modeling.

The proposed WCFU source parameters, including UTM coordinates and stack base

elevations for each emissions point, emission rates, and source release parameters that were used

in the modeling are presented in the next table below. The emission rates were based on “worstcase” (i.e., lowest) expected coal heating value of 3031 Btu/lb and the permit emission

allowables requested by Deseret Power in the November 1, 2004 permit application, with the

exception that for short-term (3-hour and 24-hour) SO2 emission rates, EPA adjusted the

emission rates upward by a factor of 5.93 for the 3-hour rate, and by 1.37 for the 24-hour rate, to

account for periods of uncontrolled startup emissions, as reported by Deseret Power in a letter to

EPA on March 23, 2005.

For SO2 and NOx, the emission allowables proposed by EPA for the PSD permit are

substantially lower than the emission rates used for modeling. The November 1, 2004 permit
157

application proposed emission allowables of 0.10 lb/MMBtu for SO2 and 0.10 lb/MMBtu for

NOx, which are roughly equivalent to the emission rates in grams per second (g/sec) used by

Deseret Power in modeling for 3-hour and 24-hour SO2 impacts (18.52 g/sec) and for annual SO2

and NOx impacts (18.21 g/sec). As explained above, EPA later scaled up the short-term SO2

emission rate used for modeling (18.52 g/sec) by factors of 5.93 for 3-hour SO2 and by 1.37 for

24-hour SO2, to account for higher startup emissions. EPA also scaled up the modeling results

accordingly. The emission allowables proposed by EPA as BACT for the PSD permit, however,

are 0.055 lb/MMBtu for SO2 and 0.088 lb/MMBtu for NOx, applicable prior to the date which is

12 months after completion of initial performance testing. Beginning on that date, and thereafter,

the applicable emission allowables will be the following: 0.080 lb/MMBtu for NOx and a

‘sliding scale’ value for SO2 between 0.055 and 0.040 lb/MMBtu, when waste coal with

uncontrolled SO2 emission potential of less than 1.90 2.2 lb/MMBtu is being burned; otherwise,

0.055 lb/MMBtu will continue to apply for SO2. These emission allowables are substantially

lower than the emission rate of 0.10 lb/MMBtu originally assumed by Deseret Power for

modeling for SO2 and NOx.

ISC3 WCFU Stack Input Parameters Used for Modeling

As Corrected by EPA for 3-Hour and 24-Hour SO2

ISC3 Input Parameters Parameter Values

SO2 Emission Rate 110.0

1)

g/sec (872 lb/hr);

25.46

2)

g/sec (201.9 lb/hr);

18.21

3)

g/sec (144.4 lb/hr)

PM10 Emission Rate 9.47 g/sec (75.4 lb/hr)

NO2 Emission Rate 18.21 g/sec

CO Emission Rate 27.32

4)

g/sec

Beryllium Emission Rate 8.82 E-5 g/sec

H2SO4 Emission Rate 0.91 g/sec

HCl Emission Rate 2.31 g/sec

HF Emission Rate 0.61 g/sec

UTM Coordinate East 646635 m

UTM Coordinate North 4438574 m

Stack Base Elevation 5030 ft (1533.1 m)

Stack Height 275 feet (83.82 m)

Stack Gas Temperature 275 ΕF (135 ΕC)

Stack Gas Exit Velocity 71 fps (21.64 m/s)

Stack Diameter 13 feet (3.96 m)

FOOTNOTES: 1) Worst-case 3-hour emission rate

2) Worst-case 24-hour emission rate.

3) Annual emission rate.

4) Worst-case 1 and 8-hour emission rate.
158

The next table below presents the Bonanza Unit 1 emission rates used for full-impact modeling.

These emission estimates are based on 2002 actual emissions. The 3-hour and 24-hour SO2

emission rates in the table (140 g/sec and 106 g/sec, respectively) are corrections to the

November 1, 2004 permit application, which had listed an SO2 emission rate of 56.3 g/sec for all

averaging periods. The correction was reported to EPA by Deseret Power via letter of March 23,

2005.

Bonanza Unit I Stack Parameters Used for Modeling

As Corrected by EPA for 3-Hour and 24-Hour SO2

Model Input Parameters Parameter Values

SO2 Emission Rate 140 g/sec (3-hr)

106 g/sec (24-hr)

56.30 g/sec (annual)

PM10 Emission Rate 16.50 g/sec

UTM Coordinate East 646441 m

UTM Coordinate North 4438414 m

Stack Base Elevation 5020 feet (1530.3 m)

Stack Height 600 feet (182.88 m)

Stack Gas Temperature 118 ΕF (47.78 ΕC)

Stack Gas Exit Velocity 3201 fpm (16.26 m/s)

Stack Diameter 26 feet (7.93 m)

FOOTNOTE: The higher short-term (3-hr and 24-hr) emission rates for SO2 listed above (140

g/sec and 106 g/sec, respectively) were provided by Deseret in a March 23, 2005 letter to

EPA. These higher rates have been factored into the modeling results tables below, for

cumulative NAAQS and Class II increment analysis.

8. Additional data inputs for far-field analysis.

a. Precipitation data. Precipitation data for stations within the

modeling domain for the 1992, 1996, and January, 1999 through January, 2000 period were

obtained from Earth Info, Inc. These data consist of hourly observations and were thoroughly

QA’d prior to use by CALMET.

b. Land use data. The land use data used in the far-field analysis were

obtained from the USGS. These land use land cover (LULC) data consisted of 1:250,000 scale

or 1:100,000 scale quadrangles with a horizontal resolution of 200 meters. The grid spacing was

4 kilometers. The CALMET preprocessor, Makegeo.exe, was used to combine the terrain and

the LULC data to generate the geophysical file needed by CALPUFF. Makegeo.exe maps the

original 37 USGS land uses to the 14 CALMET-default land uses, which are presented in the

next table below. The default values presented in this table were used by CALPUFF.
159

Default CALMET Land Use Categories

And Associated Geophysical Parameters

Based on USGS Classification System

Land

Use

Type

Description Surface

Roughness (m)

Albedo Bowen

Ratio

Soil Heat

Flux

Parameter

Anthropogenic

Heat Flux

(W/m

2

)

Leaf

Area

Index

10 Urban 1.0 0.18 1.5 0.25 0.0 0.2

20 Agricultural Land –

Unirrigated

0.25 0.15 1.0 0.15 0.0 3.0

-20 Agricultural Land –

Irrigated

0.25 0.15 0.5 0.15 0.0 3.0

30 Rangeland 0.05 0.25 1.0 0.15 0.0 0.5

40 Forest Land 1.0 0.10 1.0 0.15 0.0 7.0

51 Small Water Body 0.001 0.10 0.0 1.0 0.0 0.0

54 Bays and Estuaries 0.001 0.10 0.0 1.0 0.0 0.0

55 Large Water Body 0.001 0.10 0.0 1.0 0.0 0.0

60 Wetland 1.0 0.10 0.5 0.25 0.0 2.0

61 Forested Wetland 1.0 0.1 0.5 0.25 0.0 2.0

62 Non-forested Wetland 0.2 0.1 0.1 0.25 0.0 1.0

70 Barren Land 0.05 0.30 1.0 0.15 0.0 0.05

80 Tundra 0.20 0.30 0.5 0.15 0.0 0.0

90 Per. Snow or Ice 0.20 0.70 0.5 0.15 0.0 0.0

c. Ozone data. Ozone data, obtained from the EPA’s CASTNET

website, were utilized for 1992, 1996, and January 1999 through January 2000. The stations and

data periods used are presented in the table below.

Ozone Station Data

Station Name Latitude Longitude Data Period

Gothic, WY 38.9564 -106.9858 1992, 1996, Jan. 1999 – Jan. 2000

Mesa Verde, CO 37.1983 -108.4903 1996, Jan. 1999 – Jan. 2000

Canyonlands, UT 38.4583 -109.8211 1996, Jan. 1999 – Jan. 2000

Pinedale, WY 42.9288 -109.7880 1992, 1996, Jan. 1999 – Jan. 2000
160

D. Exemption from pre-construction ambient monitoring. Near field dispersion

modeling for the WCFU was conducted, using four years (1986/1987, 1991, 1992, and 1993) of

on-site meteorological data collected by Deseret Power. These near field modeled maximum

concentration results are presented in the table below.

While the results of this modeling indicated that the ambient impacts from the proposed

WCFU are slightly above the concentration threshold in 40 CFR 52.21(i)(5)(i) that would require

pre-construction ambient monitoring for SO2, EPA determined that pre-construction ambient

monitoring need not be required, since ambient SO2 air quality monitoring data are already

available from the plant site for the period 1991-93. These data are considered representative

since: (1) the data were collected on-site, (2) there were no other major sources of SO2 in the

area then, (3) no major sources have been added since that time, and (4) the data were collected

in accordance with EPA’s PSD monitoring guidelines. The data therefore satisfy the criteria in

EPA’s “Ambient Monitoring Guidelines for Prevention of Significant Deterioration (PSD),”

EPA-450/4-87-007 (May 1987), for pre-construction monitoring data to be considered

representative of pre-construction ambient air quality for PSD purposes.

The 3-hour and 24-hour SO2 “Modeled Maximum” values in the table below reflect a

29% scaling up by EPA, as compared to the values presented by Deseret Power in the PSD

permit application of November 1, 2004, to reflect a 29% increase in existing Bonanza Unit 1

SO2 emissions since 1991-93, as reported by Deseret Power to EPA via e-mail on November 13,

2006.

Near field WCFU Modeling Results

and Comparison to Monitoring Exemption Levels

(Modeled Maximums As Corrected by EPA for 3-Hour and 24-Hour SO2)

Pollutant Averaging

Period

Modeled

Maximum

(ug/m

3

)

Year

Maximum

Occurred

Threshold Level

in 40 CFR

52.21(i)(5)(i) for

Exemption

Percent of

Threshold

Level

24-hour 13.3 1993 13 >100

3-hour 60.5 1992 NA NA

SO2

Annual 0.66 1991 NA NA

NO2 Annual 0.65 1991 14 4.6

PM10 24-hour 7.6 1993 10 76.0

Annual 1.5 1992 NA NA

CO 1-hour 185.3 1993 NA NA

8-hour 38.5 1991 575 6.7

E. Results and conclusions. The modeling analyses predicted no exceedances of the

Class I or II increments, NAAQS, deposition action thresholds, plume blight thresholds, and light

extinction thresholds. Results are described in more detail below.
161

1. National Ambient Air Quality Standards analysis results

a. Near field analysis results. Results of near field analysis for

NAAQS compliance are presented in the next table below. The modeled highest and secondhighest pollutant concentrations, the background concentrations, the NAAQS, and the percent of

NAAQS for WCFU project sources are presented. The “Model-Predicted Concentration”

reflects scale-up factors of 5.93 for 3-hour SO2 and 1.37 for 24-hour SO2 for the WCFU, as

compared to the results presented in the PSD permit application of November 1, 2004, to reflect

higher emission rates at the WCFU during a cold startup, as reported by Deseret Power to EPA

via a March 23, 2005 letter. See section VIII.E.7 below for details. Also, the “Background

Concentration” for SO2, for all averaging periods, reflects a 29% scale-up, as compared to the

“Background Concentration” presented by Deseret Power in the PSD permit application of

November 1, 2004, to account for a 29% increase in existing Bonanza Unit 1 SO2 emissions

since 1991-93, as reported in an e-mail from Deseret Power to EPA on November 13, 2006.

NAAQS Compliance Demonstration for WCFU Project Sources

(Results as Corrected by EPA for SO2)

Pollutant Averaging

Period

ModelPredicted

Concentration

(g/m

3

)

Background

Concentration

(g/m

3

)

Total

Concentration

(g/m

3

)

NAAQS

(g/m

3

)

Percent

of

NAAQS

3-hour (H) 324.4 25.8 350.2 1300 26.9

3-hour (SH) 244.9 25.8 270.7 1300 20.8

24-hour (H) 14.8 12.9 27.7 365 7.6

24-hr (SH) 10.4 12.9 23.3 365 6.4

SO2

Annual 0.66 6.5 7.2 80 9.0

24-hour (H) 7.6 28.0 35.6 150 23.7

24-hr (SH) 5.5 28.0 33.5 150 22.3

PM10

Annual 1.5 10.0 11.5 50 23.0

NO2 Annual 0.65 5.0 5.7 100 5.7

1-hour (H) 185.3 1150 1335.3 40,000 3.3

1-hour (SH) 178.9 1150 1328.9 40,000 3.3

8-hour (H) 38.5 1150 1188.5 10,000 11.9

CO

8-hour (SH) 28.0 1150 1178.0 10,000 11.8
162

FOOTNOTES: H - Modeled maximum concentration

SH - Second highest modeled concentration

b. Full-impact analysis results. Results of full-impact analysis for

NAAQS compliance are presented in the next table below. The WCFU’s contribution to the

“Model-Predicted Concentration” reflects scale-up factors of 5.93 for 3-hour SO2 and 1.37 for

24-hour SO2, as compared to modeling results presented in the PSD permit application of

November 1, 2004, to reflect higher emission rates during a cold startup, reported by Deseret

Power to EPA via a March 23, 2005 letter. See section VIII.E.7 below for details.

Also, Bonanza Unit 1’s contribution to the “model-predicted concentration” reflects a

scale-up factor of [140/56.3 = 2.5 ] for 3-hour SO2, and a scale-up factor of [106/56.3 = 1.9 ] for

24-hour SO2, as compared to modeling results presented in the PSD permit application of

November 1, 2004, to reflect higher short-term SO2 emission rates at Unit 1, as reported by

Deseret Power to EPA via a March 23, 2005 letter. The letter indicated that Unit 1 peak SO2

emissions are 140 g/sec on a 3-hour average and 106 g/sec on a 24-hour average. Unit 1’s annual

average SO2 emission rate remains at 56.3 g/sec.

Also, the “Background Concentration” for SO2, for all averaging periods, reflects a 29%

scale-up, as compared to the “Background Concentration” presented by Deseret Power in the

PSD permit application of November 1, 2004, to account for a 29% increase in existing Bonanza

Unit 1 SO2 emissions since 1991-93, as reported in an e-mail from Deseret Power to EPA on

November 13, 2006.

NAAQS Compliance Demonstration for Full Impact Area Sources

(Results as Corrected by EPA for SO2)

Pollutant Averaging

Period

ModelPredicted

Concentration

(ug/m

3

)

Background

Concentration

(ug/m

3

)

Total

Concentration

(ung/m

3

)

NAAQS

(ug/m

3

)

Percent

of

NAAQS

3-hr (H) 329.2 25.8 355.0 1300 27.3

3-hr (SH) 245.4 25.8 271.2 1300 20.9

24-hr (H) 14.8 12.9 27.7 365 7.6

24-hr (SH) 12.9 12.9 25.8 365 7.1

SO2

Annual 1.2 6.5 7.7 80 9.6

24-hr (H) 16.3 28.0 44.3 150 29.5

24-hr (SH) 9.6 28.0 37.6 150 25.1

PM10

Annual 2.5 10.0 12.5 50 25.0

FOOTNOTES: H - Modeled maximum concentration

SH - Second highest modeled concentration
163

2. PSD Class II increment consumption analysis results

a. Near field analysis results. Results of near field analysis for PSD

Class II increment compliance are presented in the next table below. The “Model-Predicted

Concentration” reflects scale-up factors of 5.93 for 3-hour SO2 and 1.37 for 24-hour SO2, as

compared to the results presented in the PSD permit application of November 1, 2004, to reflect

higher emission rates during startup, as reported by Deseret Power to EPA via a March 23, 2005

letter. See section VIII.E.7 below for details.

PSD Class II Increment Compliance for WCFU Sources

(Near field Analysis)

(Results as Corrected by EPA for SO2)

Pollutant Averaging

Period

Model-Predicted

Concentration

(ug/m

3

)

PSD Class II

Increment

(ug/m

3

)

Percent of

Class II

Increment

3-hour (H) 324.4 512 63.3

3-hour (SH) 244.9 512 47.8

24-hour (H) 14.8 91 16.3

24-hour (SH) 10.4 91 11.4

SO2

Annual 0.66 20 3.3

24-hour (H) 7.6 30 25.3

24-hour (SH) 5.5 30 18.3

PM10

Annual 1.5 17 8.8

NO2 Annual 0.65 25 2.6

FOOTNOTES: H - Modeled maximum concentration

SH - Second highest modeled concentration

b. Full-impact analysis results. Results of full-impact analysis

for PSD Class II increment compliance are presented in the next table below. The WCFU’s

contribution to the “model-predicted concentration” reflects scale-up factors of 5.93 for 3-hour

SO2 and 1.37 for 24-hour SO2, as compared to modeling results presented in the PSD permit

application of November 1, 2004, to reflect higher emission rates during startup, reported by

Deseret Power to EPA via a March 23, 2005 letter. See section VIII.E.7 below for details.

Also, Bonanza Unit 1’s contribution to the “model-predicted concentration” reflects a

scale-up factor of [140/56.3 = 2.5 ] for 3-hour SO2, and a scale-up factor of [106/56.3 = 1.9 ] for

24-hour SO2, as compared to modeling results presented in the PSD permit application of

November 1, 2004, to reflect higher short-term SO2 emission rates at Unit 1, as reported by

Deseret Power to EPA via a March 23, 2005 letter. The letter indicated that Unit 1 peak SO2

emissions are 140 g/sec on a 3-hour average and 106 g/sec on a 24-hour average. Unit 1’s annual

average SO2 emission rate remains at 56.3 g/sec.
164

PSD Class II Increment Compliance

for Full Impact Area Sources

(Results as Corrected by EPA for SO2)

Pollutant Averaging

Period

Model-Predicted

Concentration

(ug/m

3

)

PSD Class II

Increment

(ug/m

3

)

Percent of

Class II

Increment

3-hour (H) 329.2 512 64.3

3-hour (SH) 245.4 512 47.9

24-hour (H) 14.8 91 16.3

24-hour (SH) 12.9 91 14.2

SO2

Annual 1.2 20 6.0

24-hour (H) 16.3 30 54.3

24-hour (SH) 9.6 30 32.0

PM10

Annual 2.5 17 14.7

FOOTNOTES: H - Modeled maximum concentration

SH - Second highest modeled concentration

3. PSD Class I increment consumption analysis results. Far-field analysis was

conducted by Deseret Power for SO2, PM10 and NOx impacts on PSD Class I areas. Results for

Class I increment compliance are presented in the next table below. The table is a summary of

results based on various meteorological data sets (1992 MM4 data, 1996 MM5 data, and 1999

RUC2 data). Only the highest percent increment consumption of any of the data sets and for any

averaging period is presented in this table. The applicable increment averaging periods are 3-

hour, 24-hour and annual for SO2, 24-hour and annual for PM10, and annual for NOx. The

highest modeled percent increment consumption was 12.5% for 24-hour SO2 at Dinosaur

National Monument in Colorado. The second highest was 4.4% for 24-hour SO2 at Colorado

National Monument. Complete results may be found in the PSD permit application.

Modeled Maximum CALPUFF PSD Class I Increment

Consumption Results for WCFU Project

Class I Area Pollutant Averaging Period of

Highest Percent

Increment Consumption

Percent of

Class I Increment

Consumed

SO2 24-hr 2.1

PM10 24-hr <1

Arches National Park

NO2 Annual <1

SO2 3-hr <1

PM10 24-hr <1

Bridger Wilderness

NOx Annual <1
165

SO2 3-hr <1

PM10 24-hr <1

Fitzpatrick Wilderness

NO2 Annual <1

SO2 24-hr 1.6

PM10 24-hr <1

Canyonlands National

Park

NO2 Annual <1

SO2 24-hr 1.4

PM10 24-hr <1

Capitol Reef National

Park

NO2 Annual <1

SO2 24-hr 4.4

PM10 24-hr <1

Colorado National

Monument

(1)

NO2 Annual <1

SO2 24-hr 1.5

PM10 24-hr 2.3

Dinosaur National

Monument (Utah)

(2)

NO2 Annual <1

SO2 24-hr 12.5

PM10 24-hr 1.2

Dinosaur National

Monument (Colorado)

(3) NO2 Annual <1

SO2 24-hr 2.5

PM10 24-hr <1

Flat Tops Wilderness

NO2 Annual <1

SO2 24-hr 1.5

PM10 24-hr <1

Mt. Zirkel Widerness

NO2 Annual <1

SO2 3-hr <1

PM10 24-hr <1

High Uintah

Wilderness

NO2 Annual <1

SO2 3-hr <1

PM10 24-hr <1

Ute Tribe Areas of

Concern

NO2 Annual <1

FOOTNOTES:

(1) Colorado National Monument is PSD Class I for SO2 only.

(2) Portion of Dinosaur National Monument in Utah is classified as

PSD Class II for all pollutants.

(3) Portion of Dinosaur National Monument in Colorado is classified as

PSD Class I for SO2 only.

An e-mail from the National Park Service to EPA on June 16, 2005, stated that “...the

modeling analyses for Class I and Class II PSD increments and impacts to Air Quality Related

Values has been performed correctly and all issues regarding impacts to the NPS Class I and
166

Class II units have been addressed.” This statement was noted in the draft Statement of Basis.

Nevertheless, public comments received by EPA on the draft WCFU permit action raised issues

with the Class I increment analysis.

The public commenters’ suggested use of worst case short term emission rates

(“modeling limits” in the permit), in determining impacts to Air Quality Related Values

(AQRVs) or PSD Class I increments, greater than 50 kilometers from the source, is not an

approach EPA would require, since the worst case emission rate is not intended to represent a

routine or frequent operating condition. The low frequency of occurrence of the WCFU facility

operating at the worst case emission rate (reflecting a cold startup), combining with simultaneous

meteorology to transport emissions a considerable distance to the nearest Class I area, makes the

likelihood of impacts on the nearest Class I areas extremely unlikely.

However, to be responsive to public commenters, EPA has supplemented the analysis

results presented in the table above with a screening analysis for nearby Class I areas, using

worst-case emission rates cited by public commenters. This was done by scaling Deseret

Power’s PSD Class I modeling analysis to the level of the worst case short term emission rates

applied above to NAAQS and Class II increment modeling (872 lb/hr for 3-hour SO2 and 202

lb/hr for 24-hour SO2), even though this is not an approach EPA would require (as explained

above).

Specifically, the 3-hour PSD increment concentrations were multiplied by 5.93 and the

24-hour PSD increment concentrations by 1.37. The adjusted modeled concentrations from the

WCFU were then added to the cumulative PSD increment concentrations calculated by

Intermountain Power Agency (IPA) for their Unit 3 PSD permit application to the State of Utah

in May of 2003. The modeling analysis in the IPA Unit 3 application has been reviewed and

approved by the Utah Division of Air Quality. The State of Utah has a SIP-approved PSD

permitting program and implements the PSD program in Utah. That analysis showed that the

PSD Class1 increment is not threatened in these areas. (See table below.)
167

Cumulative PSD Increment Consumption for Selected Utah Class 1 Areas

Based on Combined Modeled Impacts from Deseret WCFU

and Reported PSD Increment Modeling Results

from Intermountain Power Project, Unit 3

Ref: Addendum to Final Permit Application (“Notice-Of-Intent”), Intermountain Power

Project, Proposed Unit 3, June 16, 2003.

In addition, in a letter to EPA dated March 23, 2005, Deseret Power presented revised

modeling results for impact on Class I SO2 increment at Dinosaur National Monument in

Colorado, based on worst-case startup emission rates for 3-hour and 24-hour SO2 at the WCFU

(872 lb/hr and 202 lb/hr, respectively, rather than 147 lb/hr used in the PSD permit application of

November 1, 2004), and higher 3-hour and 24-hour SO2 emission rates at Bonanza Unit 1 than

used in the PSD permit application of November 1, 2004 (140 g/sec for 3-hour SO2 and 106

g/sec for 24-hour SO2, rather than 56.3 g/sec originally used in the November 1, 2004 PSD

permit application). Results indicated increment will not be exceeded.

4. Visibility impact analysis results. The results of the Level 1 screening

analysis, using VISCREEN, indicated that all Class 1 areas were below the Level 1 screening

criteria. After CALPOST was run and Bext (visibility extinction) was calculated at each receptor,

the maximum Bext values were reviewed and tabulated based on the maximum relative humidity

cap, for 1992, 1996 and 1999 meteorological data sets. The results of the visibility modeling

indicated that, at a relative humidity cap of 98%, and using 1992 meteorological data, there were

2 days at Arches and Capitol Reef National Parks which were slightly above the 5 percent

maximum percentage change. However, using a relative humidity cap of 95%, no days exceeded

the suggested 5 percent maximum percentage change, for any meteorological data. Complete

results may be found in the PSD permit application.

5. Deposition analysis results. The highest total sulfur and nitrogen

deposition results, in kilograms per hectare per year (kg/ha/yr), for each Class I area, for 1992,

1996, and 1999 datasets, were calculated. Total deposition is the sum of the wet and dry

deposition components. The results were compared to the Deposition Analysis Thresholds

(DAT). A DAT is the additional amount of nitrogen or sulfur within a Class I area, below which

estimated impacted from a proposed new or modified source are considered insignificant. The

Location 3-hour

SO2

24-Hour

SO2

Annual

SO2

24-Hour

PM10

Annual

PM10

Arches NP 3.8 0.8 0.1 0.2 .02

Canyonlands NP 9.6 2.2 0.1 0.2 .02

Capitol Reef NP 4.0 0.9 0.1 0.2 0.2

PSD Class 1

Increment

25 5 2 8 4
168

DATs for nitrogen (N) and sulfur (S) in western Class I parks is 0.005 kg/ha/yr. Results are

shown in the next table below, in terms of percent of the DAT.

PSD Class I Total Deposition Results

For WCFU Project

6. Lake chemistry analysis results. At the request of the Bureau of Land Management,

Deseret Power calculated the total sulfur and total nitrogen deposition for two lakes in the Flat

Tops Wilderness Area (Ned Wilson Lake and Upper Ned Wilson Lake), and for three lakes in the

Mt. Zirkel Wilderness Area (Lake Elbert, Seven Lakes, and Summit Lakes). These deposition

values were used to predict the changes to the chemistry of these sensitive lakes. The total sulfur

and nitrogen deposition values for these lakes are shown in the table below. All values are below

the DAT of 0.005 kilograms per hectare per year (kg/ha/yr).

Total Deposition at Sensitive Lakes of Concern

Sensitive Lake Receptor No. Total Sulfur

(Kg/Ha/Yr)

Total Nitrogen

(Kg/Ha/Yr)

1992

Ned Wilson Lake 2429 3.29 E-03 9.61 E-04

Upper Ned Wilson Lake 2429 3.29 E-03 9.61 E-04

Lake Elbert 2619 3.67 E-03 9.92 E-04

Seven Lakes 2771 3.47 E-03 8.84 E-04

Summit Lake 2574 3.43 E-03 9.28 E-04

1996

Ned Wilson Lake 2429 2.82 E-03 8.75 E-04

Upper Ned Wilson Lake 2429 2.82 E-03 8.75 E-04

Location Year of

Dataset

w/Highest

Result

Total Sulfur

Deposition

As Percent

Of DAT

Total Nitrogen

Deposition

As Percent

of DAT

Arches NP 1996 26 9

Bridger WA 1992 7 1

Fitzpatrick WA 1992 5 1

Canyonlands NP 1996 19 6

Capitol Reef NP 1992 6 1

Flat Tops NP 1992 77 24

Mt. Zirkel WA 1992 82 23
169

Lake Elbert 2619 2.16 E-03 6.39 E-04

Seven Lakes 2771 1.63 E-03 4.31 E-04

Summit Lake 2574 2.19 E-03 6.61 E-04

1999

Ned Wilson Lake 2429 1.59 E-03 4.69 E-04

Upper Ned Wilson Lake 2429 1.59 E-03 4.69 E-04

Lake Elbert 2619 1.68 E-03 4.42 E-04

Seven Lakes 2771 1.46 E-03 3.79 E-04

Summit Lake 2574 1.73 E-03 4.54 E-04

7. EPA adjustments to permit applicant’s modeling analysis. In a letter to

Deseret Power on December 29, 2004, EPA asked Deseret Power to provide the methodology

used to estimate the "worst case" emission rates used in modeling compliance with the NAAQS

and/or PSD increments for SO2 and CO. Upon reviewing the spreadsheet in Deseret’s response

of March 23, 2005, which documented the calculations, EPA found that Deseret Power

considered short term emission peaks of 10 start-up emission scenarios in the analysis. While

Deseret Power considered that these startup emissions would occur for 120 hours per year,

Deseret Power averaged these peak startup emissions over the remaining 8640 hours in the year.

What Deseret Power provided, therefore, was an estimate of annual average emissions

that reflects 10 start-up cycles that may occur during the year. EPA determined that this was not

responsive to EPA’s December 29, 2004 request. The short-term NAAQS and PSD increments

are based on the second highest short term average concentration that occurs during the year.

Thus the start up peak emission scenarios must consider peak emissions rates that would occur

on the worst day (or 3 or 8 hour period) during the year.

Deseret Power provided enough information in the March 23, 2005 submittal, however,

that the short term emission rates during startup scenarios could be re-calculated by EPA. For

SO2, the worst case 3-hour average emission rate would increase from Deseret’s estimate of

146.99 lb/hr to 872 lb/hr (5.93 times as high as Deseret’s estimate), while 24-hour average

emissions would increase from 146.99 lb/hr to 201.9 lb/hr (1.37 times as high as Deseret’s

estimate). When the higher emissions values are used as input for dispersion models (as shown

in the tables of modeling results above), it still appears to EPA that the NAAQS and PSD Class I

and II increments would not be exceeded.

EPA also determined that its revision to Deseret Power's SO2 emissions estimate for the

WCFU should be taken into account in estimating the significant impact area of the WCFU. In

Deseret Power's original analysis, the Class II significant impact area for SO2 was a 16-kilometer

radius from the proposed WCFU. Deseret Power added 50 kilometers to the impact area radius

and looked for other increment affecting sources within 66 kilometers of the proposed WCFU.
170

Other than Bonanza Unit 1, there were no other sources in the 66-kilometer radius impact area.

The revised emission estimate for the WCFU would expand the impact area somewhat, but there

are no additional large SO2 sources near the edge of the 66-kilometer impact area. (This area is

very remote.) At distances exceeding 66 kilometers, it would take a huge source to materially

affect increment concentrations and there are none that large within at least 100 kilometers of the

proposed WCFU.

On November 3, 2005, Deseret Power notified EPA via e-mail that Deseret Power

accepts EPA’s re-calculation of modeling for startup scenarios and asked that EPA consider the

re-calculation to be an amendment to the PSD permit application.

8. Post-construction ambient monitoring. As mentioned earlier in this

Statement of Basis, 40 CFR 52.21(m)(2) requires post-construction ambient air quality

monitoring, if EPA determines it is necessary to determine the effect that emissions from the

source modification may have on air quality. Since the modeled ambient air quality impacts of

the WCFU project are far below the NAAQS and PSD Class I and II increments, EPA has

determined that it will not be necessary to require post-construction ambient monitoring for the

WCFU project.

9. Emission limits for modeling purposes. As explained in section VIII.A of

this Statement of Basis, 40 CFR 52.21(k) requires the permit applicant to demonstrate that the

allowable emission increases (including secondary emissions) from the proposed source

modification (in this case, addition of a coal-fired unit at Deseret’s Bonanza power plant), in

conjunction with all other applicable emission increases or reductions at the source, for all

pollutants that would be emitted in excess of the significance thresholds at §52.21(b)(23)(i),

would not cause or contribute to a violation of any National Ambient Air Quality Standard

(NAAQS), nor cause or contribute to a violation of any applicable “maximum allowable

increase” over the baseline concentration in any area.

EPA interprets §52.21(k) to require that emission limits be included in PSD permits

(‘modeling limits’) consistent with emission rates used in dispersion modeling for ambient

impacts, unless it would be physically impossible for the proposed source modification to emit at

a greater rate (i.e., maximum potential uncontrolled emissions). This requirement is in addition

to the requirement under §52.21(j)(3) to establish BACT emission limits.

For the WCFU project, the WCFU exhaust stack emission rates that were used in

dispersion modeling for PSD Class II increment compliance (with adjustments by EPA as

described in section VIII.E.7 of this Statement of Basis) are the following:

PM10 24-hr increment 75.4 lb/hr

SO2 3-hr increment 872 lb/hr

SO2 24-hr increment 201.9 lb/hr

NOx annual increment 144.4 lb/hr
171

These emission rates used for modeling are well below the maximum potential

uncontrolled emission rates of the WCFU, listed in section IV.I.2 of this Statement of Basis.

Therefore, modeling limits are needed in the permit.

EPA believes the proposed BACT limit for NOx in the permit (0.080 lb/hr on a 30-day

rolling average, equivalent to 115.6 lb/hr on a 30-day average at boiler heat input capacity) can

also serve as a modeling limit for NOx, since the BACT limit is lower than the NOx emission rate

used for modeling and is on a shorter-term average (30-day versus annual). However, the

proposed BACT limits for PM10 and SO2 in the permit, being on 30-day averages also, cannot

serve as modeling limits because they are not consistent with the short-term averaging times used

for dispersion modeling for those pollutants, i.e., the BACT limits are not on 3-hour or 24-hour

averages. EPA therefore proposes the following emission limits as modeling limits in the permit:

The Permittee shall not discharge or cause the discharge of emissions from the CFB

boiler to the atmosphere in excess of the following rates used in modeling ambient impacts

of the WCFU:

1. 872 pounds per hour of sulfur dioxide, averaged over a 3-hour block period.

2. 202 pounds per hour of sulfur dioxide, averaged over a 24-hour block period.

3. 75.4 pounds per hour of total PM10 (filterable plus condensible), averaged

over a 24-hour block period.

For compliance demonstrations, EPA proposes to require use of PM CEMS and SO2

CEMS in the CFB boiler exhaust stack. For SO2, as well as for the filterable portion of PM10, the

CEMS output will be multiplied by the output from the in-stack continuous volumetric flow rate

monitor, and appropriate conversion factors applied, to yield an output in pounds per hour.

Results will then be averaged over 3-hour and 24-hour block periods for SO2, and over 24-hour

block periods for PM10. For the condensible portion of PM10, results of the latest required annual

stack test for condensibles will be used, expressed in pounds per hour. Those results will then be

added to the filterable portion, to yield total PM10.
172

IX. Environmental Justice Assessment

This environmental justice assessment was offered by EPA as a draft for public comment

in June of 2006, as part of the draft PSD permit package for the proposed WCFU project. No

public comments were received on this assessment. This assessment is not in response to any

allegations of environmental injustice about the proposed project. No such allegations have been

made to EPA. Nothing in this assessment is meant to imply that environmental justice assessments must be done for all EPA permit actions in the absence of allegations of environmental

injustice.

On February 11, 1994, President Clinton issued Executive Order 12898, entitled “Federal

Actions To Address Environmental Justice in Minority Populations and Low-income Populations.” The Executive Order calls on each federal agency to make environmental justice a part of

its mission by “identifying and addressing, as appropriate, disproportionately high and adverse

human health or environmental effects of its programs, policies and activities on minority

populations and low-income populations.” The broad goal of EO12898 is then tempered in

subsection 6-609 of the Executive Order by the caution that “this order is intended only to

improve the internal management of the executive branch and is not intended to...create any

right...enforceable...against the United States.”

EPA used the following step-by-step approach for determining whether or not the

proposed WCFU project might result in disproportionately high and adverse human health or

environmental effects on minority populations or low-income populations.

1. Determine the affected geographical area for the proposed WCFU project.

EPA has no standardized procedure for determining the “affected area” of a PSDpermitted project for environmental justice purposes. The determination is case-by-case. For the

WCFU project, EPA determined the “affected area” for this environmental justice assessment by

examining the dispersion modeling results and comparing them to the National Ambient Air

Quality Standards (NAAQS). These are health-based standards, set at a level presumptively

sufficient to protect public health with an adequate margin of safety. Based on this approach,

EPA determined that the “affected area” is an area extending no more than a few miles out from

the Bonanza power plant, with the portion of that area most likely to be affected being to the east

of the Bonanza power plant (downwind). Below is an explanation of how EPA arrived at this

determination.

As shown in the Statement of Basis, the air pollutants that are anticipated to be emitted in

largest amounts from the proposed WCFU project are particulate matter, sulfur dioxide (SO2),

nitrogen dioxide (NO2) and carbon monoxide (CO). The predicted ambient air quality impacts of

the project, based on dispersion modeling, are shown in two tables in the Statement of Basis,

entitled “NAAQS Compliance Demonstration for WCFU Project Sources (Results as Corrected

by EPA for SO2}” and “NAAQS Compliance Demonstration for Full Impact Sources (Results as
173

Corrected by EPA for SO2}.” By “ambient air quality impact,” EPA means the model-predicted

increase in concentration of a pollutant outside the fenceline of the Bonanza power plant.

The “WCFU Project Sources” table shows the predicted ambient air quality impact of the

WCFU project alone. The “Full Impact Sources” table uses the same modeling approach as the

“WCFU Project Sources” table, but shows the predicted ambient air quality impact of the WCFU

project cumulative with the impact of the existing Bonanza Unit 1. (No other stationary sources

of air pollution were included in the cumulative analysis because EPA is not aware of any other

large stationary sources in the area whose emissions would be cumulative with the ambient

impact from the proposed WCFU project. This is explained further in Step 2 below. By “large,”

EPA means sources with potential to emit more than 100 tons per year or more of any one

pollutant.)

The “Full Impact Sources” table does not include NO2 and CO from the “WCFU Project

Sources” table because the results for those pollutants in the “WCFU Project Sources” table did

not exceed EPA “significance levels” for proceeding to a cumulative analysis. Since the

“significance levels” are so far below the NAAQS, EPA does not believe the screening out of

NO2 and CO from full impact analysis will have any effect on this environmental justice

assessment. The “significance levels” may be found in a table in the Statement of Basis, entitled

“Significance Levels for Air Quality Impacts in PSD Class II Areas.”

The “WCFU Project Sources” table shows that the model-predicted ambient concentrations resulting from the WCFU project alone (including “background concentration”) are

below about 27% of the 3-hour NAAQS for SO2, 24% of the 24-hour NAAQS for particulate

matter, 12% of the 8-hour NAAQS for CO, and 7% of the annual NAAQS for NOx. The “Full

Impact Sources” table shows that the model-predicted ambient concentrations for cumulative

impact are below 28% of the 3-hour NAAQS for SO2 and 30% of the 24-hour NAAQS for

particulate matter.

For particulate matter, NOx and CO, both tables reveal that the “background concentration” is a substantial portion of the total ambient concentration. The “background concentration” is the concentration of an air pollutant that does not come from the Bonanza power plant

itself, but is present everywhere. The “background concentration” is not an impact that is

specific to the “affected area.”

For 3-hour SO2 ambient impacts, the “model-predicted concentration” is very high in

terms of micrograms per cubic meter, reflecting about 25% of the 3-hour NAAQS for SO2,

because EPA corrected the modeling results to reflect a worst-case cold startup scenario for the

WCFU. This is a very infrequent scenario. Outside of cold startups, the ambient impact for SO2

would be 9% or less of the NAAQS for SO2, for all averaging periods.

Based on the above information, EPA proposes to conclude that the “affected area”

cannot be meaningfully defined for the WCFU project with respect to the gaseous pollutants
174

(SO2, NO2 and CO), because the dispersion modeling results (other than the very infrequent

worst-case cold startup scenario for SO2) are such a small percentage of the NAAQS. Further,

the results represent the ambient air quality impact at the worst-case location (i.e., the location of

maximum predicted concentration of each pollutant), and for the worst-case meteorological

conditions. The ambient concentrations at all other locations, and for all other meteorological

conditions, would be lower. EPA is not aware of any reason why adverse health effects should

be suspected when results are such a low percentage of the NAAQS. Instead, EPA concluded

that the “affected area” should be defined in terms of particulate matter, for which the dispersion

modeling results are a higher percentage of the NAAQS (nearly 30% for cumulative impact).

Particulate matter is heavier than air and can be expected to drop out of the atmosphere

within a few miles from the Bonanza power plant. Meteorological data in the PSD permit

application from Deseret Power (“wind rose”) suggest that the greatest ambient air quality impact

would be along the prevailing wind direction, which is generally eastward from the Bonanza

power plant. (The “wind rose” is data on how frequently the wind comes from each particular

direction.) Therefore, EPA concluded that the “affected area” for this assessment should be

considered an area extending no more than a few miles out from the Bonanza power plant, with

the majority of the ambient air quality impact being in an eastward direction.

2. Determine the locations and air pollutant emissions from any existing sources that may impact

the affected area, cumulative with impacts from the proposed WCFU.

As mentioned above, EPA is not aware of any large stationary sources other than

Bonanza Unit 1 whose emissions would be cumulative with the ambient impact from the

proposed WCFU project. There are several large oil and gas processing facilities in Uintah

County, which emit primarily NO2 and CO; however, none of these facilities are close to the

Bonanza power plant. These facilities are listed below. EPA concluded that the emissions from

these facilities would not add more than a negligible amount, if at all, to the dispersion modeling

results described above for the WCFU project.

Company Facility

Canyon Gas Resources Mesa Tap Compressor Station

Colorado Interstate Gas Natural Buttes Compressor Station

Kerr-McGee Cottonwood Wash Compressor Station

Kerr-McGee Ouray Compressor Station

Questar Fidlar Compressor Station

Questar Red Wash 24B Natural Gas Processing Plant

Questar Wonsits Compressor Station

Wind River Resources North Hill Creek Compressor Station
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3. Examine demographic data to determine if there is a minority or low-income population

residing within the affected area.

All census information described below is from http://factfinder.census.gov. The data are

based on the 2000 census.

EPA has no census data or other information indicating that there are any full-time

residents within the proposed “affected area.” The closest town is Bonanza, Utah, which is

approximately 5 miles from the Bonanza power plant. The only residents EPA is aware of in

Bonanza, based on information obtained from Deseret Power, are a small number of employees

of American Gilsonite, who are part-time residents. EPA has no information on whether any of

these part-time residents would be classified as minority or low-income.

Census data indicate an average population density in Uintah County, where the Bonanza

power plant is located, of about seven residents per square mile. Excluding the main population

center in the county (Vernal/Naples), which is about 32 to 35 miles from the power plant and is

not in the proposed “affected area,” the average population density in the remainder (non-urban

portion) of the county would be somewhat less. As mentioned above, EPA has no census data or

other information to indicating that there are any full-time residents of Uintah County within the

“affected area” for this assessment.

Based on the above information, EPA is unable to conclude that there is any population in

the “affected area” for the WCFU project, whether minority, low-income, or otherwise. In

offering this environmental justice assessment in draft form for public comment, EPA solicited

comment relative to this matter. No such comments were received. For the sake of determining

whether or not any nearby population may be minority or low-income even though outside the

”affected area,” EPA presents the following demographic data.

Uintah County’s population is 87.7% Caucasian, 9.4% American Indian and Alaska

Native, 3.5% Hispanic, and the remainder being other minorities. Utah’s population is 89%

Caucasian, 11% Hispanic, and the remainder being other minorities. In comparison to the

reference population (i.e., the statewide average), it appears to EPA that Uintah County could be

classified as a minority community.

In Utah, the median family income in 1999 dollars is $51,022. In Uintah County, the

median family income is $38,877. In Utah, the percentage of individuals below the poverty level

is 9.4%. In Uintah County, the percentage of individuals below the poverty level is 14.5%. In

comparison to the reference population (i.e., the statewide average), it appears to EPA that

Uintah County could be classified as a low-income community.

The nearest communities to the Bonanza power plant that have measurable population are

the towns of Dinosaur and Rangely, Colorado. Dinosaur is about 18 to 20 miles north-northeast
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of the plant. Rangely is about 19 to 20 miles east-northeast of the plant. Dinosaur has a total

population of 319 people, of whom 98.7% were classified by the 2000 U.S. Census as White.

Minorities constitute 5.4% of the population of Dinosaur, which is under the Colorado state

average of 25.5%. Rangely has a total population of 2,098 people, of whom 94.4% were

classified by the 2000 U.S. Census as White. Minorities constitute 10.7% of the population of

Rangely, which is under the Colorado state average of 25.5. Based on this information it appears

to EPA that neither of these communities could be classified as a minority community.

In summary, EPA has no information indicating that any minority or low-income

population resides within the “affected area.” As mentioned above, in offering this environmental justice assessment in draft form for public comment, EPA solicited comment to aid in

determining whether or not there is any population within the “affected area,” as well as whether

such population may be minority or low-income. No such comments were received.

4. Determine the extent and nature of adverse impact from cumulative air pollutant emissions

within the affected area.

Based on the dispersion modeling results described above, in comparison to the NAAQS,

EPA concluded that there will not be any adverse impact from cumulative SO2, NO2 or CO

emissions within the “affected area” for this assessment. For particulate matter, EPA concluded

that adverse impact may be somewhat more likely, since predicted ambient concentrations are a

higher percentage of the NAAQS than for the gaseous pollutants (again, excluding the worst-case

cold startup scenario for SO2), and that the extent of the potential adverse impact would be

within a few miles of the Bonanza power plant, generally eastward. EPA refers to this as

“potential” adverse impact because EPA considers it unlikely there would be any adverse health

or environmental impacts at 30% or less of the NAAQS for particulate matter.

5. Determine whether the proposed WCFU project, when added to existing sources, will have a

disproportionately high and adverse impact on air quality affecting the minority or low-income

population.

Based on the dispersion modeling results for the proposed WCFU project relative to the

NAAQS, and based on information on locations of other large pollutant-emitting facilities, and

based on available demographic information about the nearest population, EPA concluded that

the proposed project, when added to existing sources, will not have a disproportionately high and

adverse impact on air quality affecting any minority or low-income population. Again, in

offering this environmental justice assessment in draft form for public comment, EPA solicited

comment on any information relevant to this assessment. No such comments were received.