State of Idaho 

 Department of Environmental Quality 

 Air Quality Division

AIR QUALITY PERMIT 

STATEMENT OF BASIS

Tier II Operating Permit No. T2-2009.0105 Project 60867 

Proposed for Public Comment 

The Amalgamated Sugar Company LLC (TASCO) 

Nampa Factory 

Nampa, Idaho 

Facility ID No. 027-00010 

October 31, 2011 

Morrie Lewis 

Permit Writer 

The purpose of this Statement of Basis is to satisfy the requirements of 

IDAPA 58.01.01.et seq, Rules for the Control of Air Pollution in Idaho, 

for issuing air permits.
Table of Contents 

ACRONYMS, UNITS, AND CHEMICAL NOMENCLATURE ..................................................................... 3

FACILITY INFORMATION .............................................................................................................................. 4

Facility Description ............................................................................................................................................. 4

Permitting Action Scope and Chronology ........................................................................................................... 4

TECHNICAL ANALYSES .................................................................................................................................. 6

Overview of Changes .......................................................................................................................................... 6

BART Determinations ......................................................................................................................................... 7

BART Alternative ............................................................................................................................................. 10

Natural Gas-Fired Operation ............................................................................................................................. 14

REGULATORY REVIEW ................................................................................................................................ 16

Attainment Designation (40 CFR 81.313) ........................................................................................................ 16

Tier II Operating Permit (IDAPA 58.01.01.401) .............................................................................................. 16

Title V Classification (IDAPA 58.01.01.300, 40 CFR Part 70) ........................................................................ 16

PTC, PSD, and NSPS Applicability (IDAPA 58.01.01.201, 40 CFR 52.21, and 40 CFR 60) ......................... 16

NESHAP and MACT Applicability (40 CFR Parts 61 and 63) ........................................................................ 16

CAM Applicability (40 CFR 64) ...................................................................................................................... 16

BART Applicability (40 CFR 51.308 and IDAPA 58.01.01.668) .................................................................... 17

Permit Conditions Review ................................................................................................................................ 18

PUBLIC COMMENT ......................................................................................................................................... 23

APPENDIX A – BART DETERMINATIONS AND BART ALTERNATIVE 

APPENDIX B – BART ALTERNATIVE VISIBILITY MODELING 

APPENDIX C – INITIAL BART TIER II OPERATING PERMIT 

APPENDIX D – BAGHOUSE O&M MANUAL
T2-2009.0105 Project 60867 Page 3 

ACRONYMS, UNITS, AND CHEMICAL NOMENCLATURE 

AAC acceptable ambient concentrations for non-carcinogens 

AFS AIRS Facility Subsystem 

AIRS Aerometric Information Retrieval System 

AQCR Air Quality Control Region 

BART Best Available Retrofit Technologies 

CAA Clean Air Act 

CAM Compliance Assurance Monitoring 

CFR Code of Federal Regulations 

CO carbon monoxide 

DEQ Department of Environmental Quality 

EPA U.S. Environmental Protection Agency 

ESP electrostatic precipitator 

FGD flue gas desulfurization 

HAP hazardous air pollutants 

IDAPA a numbering designation for all administrative rules in Idaho promulgated in accordance with the Idaho 

Administrative Procedures Act 

km kilometers 

lb/hr pounds per hour 

lb steam/hr pounds of steam output per hour 

LNB coal-firing low NOx burners 

MACT Maximum Achievable Control Technology 

MMBtu/hr million British thermal units per hour 

MMscf/hr million standard cubic feet per hour 

NAAQS National Ambient Air Quality Standards 

NAICS North American Industry Classification System 

NESHAP National Emission Standards for Hazardous Air Pollutants 

NO2 nitrogen dioxide 

NOx nitrogen oxides 

NSPS New Source Performance Standards 

O&M operations and maintenance 

OFA over-fired air 

PM particulate matter 

PM2.5 particulate matter with an aerodynamic diameter less than or equal to a nominal 2.5 micrometers 

PM10 particulate matter with an aerodynamic diameter less than or equal to a nominal 10 micrometers 

PSD prevention of significant deterioration 

RH SIP Regional Haze State Implementation Plan 

Rules Rules for the Control of Air Pollution in Idaho 

SCR selective catalytic reduction 

SIC Standard Industrial Classification 

SIP State Implementation Plan 

SO2 sulfur dioxide 

SOx sulfur oxides 

T/hr tons per hour 

T/yr tons per year 

T2 Tier II operating permit 

TAP toxic air pollutant 

TASCO The Amalgamated Sugar Company LLC 

ULNB ultra-low NOx burner 

UTM Universal Transverse Mercator 

VOC volatile organic compounds 

Δdv change in delta deciviews
T2-2009.0105 Project 60867 Page 4 

FACILITY INFORMATION 

Facility Description 

The Amalgamated Sugar Company LLC (TASCO) – Nampa Factory is a beet sugar manufacturing plant. 

Permitting Action Scope and Chronology 

This permit is a Tier II operating permit (T2) for an existing facility. This T2 revises emission standards 

established for best available retrofit technologies (BART) and revises the initial BART determinations, approves 

a BART Alternative, and revises associated monitoring, recordkeeping, and reporting requirements. 

This permit is not effective until a revised Regional Haze State Implementation Plan (RH SIP) is approved by the 

U.S. Environmental Protection Agency (EPA) which incorporates BART requirements from this permit. Upon the 

effective date of a revised RH SIP, this permit supersedes Tier II Operating Permit No. T2-2009.0105 issued on 

September 7, 2010. 

A chronology of events related to the revised and initial BART permitting actions is provided in Table 1 and 

Table 2, respectively. Refer to the current Tier I permit statement of basis for a history of other permitting actions 

related to this facility. 

Table 1 CHRONOLOGY OF REVISED BART 

Date Description 

T2-2009.0105 Project 60867 

October 12, 2010 TASCO filed a contested case petition seeking review of permit T2-2009.0105. 

November 9, 2010 DEQ met with TASCO to discuss possible revisions to BART and BART Alternative determinations. 

December 13, 2010 DEQ met with TASCO to discuss preliminary modeling results for revised BART and BART Alternative. 

January 2 – February 25, 2011 DEQ received modeling input information to refine BART and BART Alternative modeling results. 

January 11, 2011 EPA proposed approval and promulgation of the regional haze SIP. 

March 17, 2011 DEQ met with TASCO to discuss refined modeling results for revised BART and BART Alternative. 

April 12 – 14, 2011 DEQ and TASCO confirmed items necessary to complete an application to revise permit T2-2009.0105 

and Idaho’s Regional Haze State Implementation Plan (RH SIP). 

May 4, 2011 DEQ received an application to revise permit T2-2009.0105 and the RH SIP. 

May 20, 2011 DEQ received supplemental information, including evaluation of over-fired air feasibility and SCR cost. 

June 1, 2011 DEQ determined that the application was complete. 

June 3 – 6, 2011 DEQ sent copies of the complete application to the EPA, FLM, and affected states for review. 

June 22, 2011 EPA partially approved the RH SIP. 

June 28, 2011 DEQ met with FLM to discuss the application. 

June 29 – July 20, 2011 DEQ performed additional modeling and requested additional information from TASCO to respond to 

FLM comments. 

August 5, 2011 DEQ received supplemental information, including boiler design information. 

August 22 – August 26, 2011 DEQ made available the draft permit and statement of basis for peer review. 

August 22, 2011 TASCO filed a petition for review of the RH SIP BART approval. 

August 26 – September 16, 2011 DEQ made available the draft permit and statement of basis for facility review. 

September 7, 2011 DEQ received modeling input information to confirm Riley Boiler natural gas-fired modeling scenario. 

September 15 – 20, 2011 DEQ received comments from TASCO concerning the draft permit and statement of basis, and baseline 

CO emission rate information on the boilers in their existing configurations. 

September 28 – 29, 2011 DEQ provided an updated draft permit and met with TASCO to discuss comments. 

October 19, 2011 DEQ provided an updated draft permit and supporting documents to FLM and TASCO. 

October 21, 2011 DEQ met with FLM to provide modeling results and respond to questions and comments concerning the 

application. 

October 31, 2011 DEQ notified EPA, FLM, affected states, and interested parties of the public comment period on the 

proposed action. 

October 31 – November 20, 2011 DEQ provided a public comment period on the proposed action. 

DRAFT DEQ issued the final permit and statement of basis. 

(Final approval of BART and BART Alternative pending revision of the regional haze SIP.) 
T2-2009.0105 Project 60867 Page 5 

Table 2 CHRONOLOGY OF INITIAL BART 

Date Description 

T2-2009.0105 

July 31, 2006 DEQ notified TASCO that each of the Nampa, Twin Falls, and Mini-Cassia facilities had a boiler 

considered to be BART-eligible. 

December 14, 2006 DEQ notified TASCO that each facility had a boiler considered to be subject to BART based upon 

preliminary modeling analyses. 

August 31, 2006 – March 2008 DEQ received several communications from TASCO which provided revised emission data and supporting 

documentation. 

August 31, 2006 – July 21, 2009 

DEQ received several communications from TASCO which included concerns regarding BART technical 

analyses. DEQ responded to concerns and provided supporting information, and informed TASCO that the 

option was available to submit alternate analyses. 

February 23, 2007 DEQ provided revised modeling analyses to TASCO, which indicated that the Nampa facility was subject 

to BART and that the Twin Falls and Mini-Cassia facilities were not subject to BART 

June 17, 2007 DEQ notified TASCO that the Riley Boiler was a BART-eligible source and subject to BART. 

July 19, 2007 DEQ notified TASCO that the Riley Boiler was determined to be subject-to-BART and provided the 

subject-to-BART determination. 

July 24, 2007 DEQ sent copies of BART exemption modeling to the EPA and FLM for review. 

November 20, 2007 

DEQ received a BART determination analysis report from TASCO for the Riley Boiler. DEQ sent a letter 

to TASCO requesting review of additional control technologies and requesting information supporting the 

claim of financial hardship and the technically infeasibility of certain control technologies. 

December 24, 2007 DEQ received a letter from TASCO including a claim of financial hardship. 

September 16, 2008 

DEQ provided TASCO the results of modeling analyses for BART alternative control strategies, and 

requested that TASCO provide DEQ with any BART alternatives for consideration which could achieve 

greater improvements. 

February 9, 2009 DEQ received a revised BART determination analysis report from TASCO which included additional 

feasible control technologies. 

March 11 – May 13, 2009 DEQ requested and received guidance from EPA concerning evaluation of the claim of financial hardship. 

June 17, 2009 DEQ sent a letter to TASCO requesting financial information in order to evaluate the claim of financial 

hardship. 

July 1, 2009 DEQ met with TASCO to discuss BART alternatives and extended the deadline for providing supporting 

financial information. 

July 3, 2009 DEQ sent a letter to TASCO addressing questions concerning the subject-to-BART modeling analyses. 

July 17, 2009 DEQ notified TASCO of the control technology selection and provided the BART determination analyses. 

July 21, 2009 DEQ received financial information from TASCO with a claim of confidentiality. 

August 18, 2009 DEQ made available the draft permit and statement of basis for peer and Boise Regional Office review. 

August 21, 2009 DEQ made available the draft permit and statement of basis to TASCO for facility review. 

August 25, 2009 DEQ received a communication from TASCO requesting that facility review of the draft permit and 

statement of basis be postponed until the claim of financial hardship had been evaluated. 

August 28, 2009 DEQ sent an email to TASCO approving the postponement of the facility review period for the draft permit 

and statement of basis. 

September 10, 2009 DEQ was informed by TASCO that financial information could be released to EPA concerning the claim of 

confidentiality. 

October 9, 2009 DEQ met with EPA and TASCO to discuss the claim of financial hardship. 

November 5, 2009 DEQ met with EPA and TASCO to review the financial information submitted and to request additional 

information. 

November 18, 2009 DEQ received supplemental BART determination information from TASCO. 

February 22 – March 14, 2010 DEQ was provided a financial analysis and supporting information from EPA Region X which indicated 

that BART was affordable based upon the financial information provided. 

March 17, 2010 DEQ notified TASCO that it had been determined that BART was affordable and provided the financial 

analysis and supporting information. 

March 26, 2010 DEQ made available a revised draft permit and statement of basis for facility review. 

April 1, 2010 

DEQ sent a letter to TASCO responding to concerns identified in the BART determination letter dated 

November 18, 2009, and addressing financial hardship, modeling, and emissions reduction crediting 

concerns. 

April 6, 2010 DEQ received comments from TASCO concerning the draft permit and statement of basis. Specific 

comments relevant to the selected BART control options were addressed. 

April 19 – May 19, 2010 DEQ provided a public comment period on the proposed Tier II operating permit and BART determination. 

May 19, 2010 DEQ received comments from TASCO concerning the draft permit and statement of basis. 

September 7, 2010 DEQ issued Tier II Operating Permit No. T2-2009.0105. 
T2-2009.0105 Project 60867 Page 6 

TECHNICAL ANALYSES 

Overview of Changes 

Table 3 provides summary descriptions of the emission sources and control equipment relevant to the revised 

BART determinations and the BART Alternative. A summary of the revisions to the initial BART Tier II 

operating permit and supporting analyses follows, and updated documentation of the complete revised BART 

determinations and of the approved BART Alternative incorporating the revisions discussed below is provided in 

Appendix A. 

Table 3 BART AND BART ALTERNATIVE EMISSION POINT SOURCES 

Source Description Control Equipment Descriptions 

Riley Boiler (S-B3) 

Installation Date: 1969 

Rated steam capacity: 250,000 lb steam/hr 

Maximum capacity: 350 MMBTU/hr 

Maximum operation: 8,760 hr/yr 

Fuel types: coal, natural gas 

Baghouse (A-B3) 

Manufacturer: Envirotech Corp. 

Control efficiency: ≥99.0% for PM 

 (BART for PM) 

Coal-Firing LNB 

Control efficiency: ≥60.7% for NOx

 (BART for NOx) 

B&W Boiler #1 (S-B1) 

Installation Date: 1942 

Rated steam capacity: 105,000 lb steam/hr 

Maximum capacity: 126 MMBTU/hr 

Maximum operation: 8,760 hr/yr 

Fuel types: coal, natural gas 

B&W Boiler #2 (S-B2) 

Installation Date: 1942 

Rated steam capacity: 105,000 lb steam/hr 

Maximum capacity: 126 MMBTU/hr 

Maximum operation: 8,760 hr/yr 

Fuel types: coal, natural gas 

Coal-Firing LNB 

Control efficiency: ≥55% for NOx

 (BART Alternative for SO2)

Coal-Firing LNB 

Control efficiency: ≥55% for NOx

 (BART Alternative for SO2)

Pulp Dryers (S-D1, S-D2, and S-D3) Permanent shutdown (BART Alternative for SO2) 

BART for the control of NOx

• Following the initial BART determination, it was determined that SCR is not technically feasible for retrofit 

on the Riley Boiler. Selective catalytic reduction (SCR) is a post-combustion control device that reduces 

thermal and fuel NOx emissions with a reagent (generally ammonia or urea) in the presence of a catalyst to 

form water and nitrogen. 

• Following the initial BART determination, it was determined that incorporating over-fired air as part of a 

coal-fired low NOx burner system (LNB) is not technically feasible for retrofit on the Riley Boiler. Low NOx

burners with over-fired air (LNB with OFA) utilize fuel and air mixing optimization and/or staged 

combustion techniques to reduce thermal NOx formation. 

• Following the initial BART determination, a coal-fired low NOx burner system (LNB) has been determined to 

be BART for the control of NOx emissions from the Riley Boiler. Low NOx burners (without over-fired air) 

utilize fuel and air mixing optimization and/or staged combustion techniques to reduce thermal NOx

formation. 

• Although considered initially as a BART alternative to the control of NOx emissions, the shutdown of three 

coal-fired pulp dryers has instead been included as part of the BART Alternative to the control of SO2

emissions. 
T2-2009.0105 Project 60867 Page 7 

BART Alternative to the control of SO2

• The shutdown of three coal-fired pulp dryers and the retrofit of coal-fired low NOx burner systems (LNB) on 

two B&W Boilers have been proposed as part of a BART Alternative to the control of SO2 emissions from the 

Riley Boiler. The Pulp Dryer shutdowns will eliminate NOx, PM, and SO2 emissions from the pulp dryers, 

while LNB will reduce NOx emissions from the boilers. These controls are predicted to result in greater 

visibility improvement to Class I areas within 300 km of the facility than the BART determination for SO2

(Spray Dry FGD), which remains unchanged from the initial BART determination. 

For spray dry flue gas desulfurization (Spray Dry FGD), the flue gas is introduced into a tower and contacts 

an atomized spray of lime slurry, which absorbs and neutralizes SO2. (The permittee has documented 

concerns regarding the affordability and environmental impacts of Spray Dry FGD;1

 however, for the 

purposes of this BART determination, Spray Dry FGD was considered feasible. Additional information 

regarding these concerns is provided in Section 1.5.2 of Appendix A.) 

Natural Gas-Fired Operation 

• The Riley Boiler was designed to combust coal and/or natural gas fuels. Discussion has been provided 

supporting why BART control equipment and emission limits were applied exclusively to the coal-fired 

operating scenario. 

Terminology 

BART Terminology 

• In this document the initial BART is defined to mean the initial BART determinations for PM, SO2, and NOx

that were determined under Tier II Operating Permit No. T2-2009.0105, issued on September 7, 2010. 

• In this document the revised BART is defined to mean the BART determination for NOx, which is being 

revised by this permitting action. (The BART for PM and SO2 have not been revised and remain the same as 

what was determined under Tier II Operating Permit No. T2-2009.0105, issued on September 7, 2010.) 

BART Alternative Terminology 

• In this document the “BART Alternative” scenario is defined to mean the combination of BART for PM 

(Riley Boiler with the existing baghouse), revised BART for NOx (Riley Boiler with low NOx burners), and 

the BART Alternative to the control of SO2 (B&W Boilers #1 and #2 with low NOx burners and the three 

Pulp Dryers shut down). 

• In this document the “BART” scenario is defined to mean the combination of BART for PM (Riley Boiler 

with the existing baghouse), revised BART for NOx (Riley Boiler with low NOx burners), and BART for SO2

(Riley Boiler with Spray Dry FGD), with the addition of the sources affected by the “BART Alternative” 

scenario: B&W Boilers #1 and #2 and three Pulp Dryers in full operation. 

• In this document the “Alternative Benchmark” scenario is defined to mean the Riley Boiler with the existing 

baghouse, B&W Boilers #1 and #2, and the three Pulp Dryers. This scenario allows comparison of both the 

“BART” and “BART Alternative” scenarios against the same benchmark that includes all of the affected 

sources. 

BART Determinations 

Background 

In accordance with 40 CFR 51.308(e) and IDAPA 58.01.01.668.02.c, Best Available Retrofit Technology 

(BART) means an emission limitation based on the degree of reduction achievable through the application of the 

best system of continuous emission reduction for each pollutant which is emitted by an existing stationary facility. 

The emission limitation must be established, on a case-by-case basis, taking into consideration the technology 

available, the costs of compliance, the energy and non-air quality environmental impacts of compliance, any 

 

1 Section 1.5.2 of Attachment #2 to “BART Alternative Submittal & Tier II Application”, TASCO, May 4, 2011. 
T2-2009.0105 Project 60867 Page 8 

pollution control equipment in use or in existence at the source, the remaining useful life of the source, and the 

degree of improvement in visibility which may reasonably be anticipated to result from the use of such 

technology. (These considerations were included in Step 4 of the BART determinations.) 

The BART analyses and determinations followed the five-step process provided in Guidelines for BART 

Determinations Under the Regional Haze Rule (Appendix Y to Part 51): 

1) Identify all retrofit control technologies 

2) Eliminate technically infeasible options 

3) Evaluate control effectiveness of the remaining control technologies 

4) Evaluate the impacts of each remaining control technology (including energy, non-air quality environmental, 

and cost impacts; and the remaining useful life of the source) 

5) Select BART and determine the degree of visibility improvement 

SO2, NOx, and PM emissions were the visibility-impairing pollutants evaluated in the BART analyses and 

determinations. 

Based on CALPUFF air dispersion modeling results, the Riley Boiler was determined to contribute to visibility 

impairment at three Class I areas, including the Eagle Cap Wilderness, Hells Canyon National Recreation Area, 

and Strawberry Mountain Wilderness, primarily during the winter time. A single emission source which is 

responsible for a one-half (0.5) deciview change or more in any mandatory Class I Federal Area “contributes” to 

visibility impairment as defined in IDAPA 58.01.01.668.02.b. 

As part of the initial and revised BART determinations, modeling analyses were conducted to evaluate visibility 

impacts at seven Class I areas within a 300 km radius around the Riley Boiler. In addition to the three areas listed 

above, the analyses included Craters of the Moon National Monument, Jarbidge Wilderness, Sawtooth 

Wilderness, and Selway-Bitterroot Wilderness. 
T2-2009.0105 Project 60867 Page 9 

Table 4 BART DETERMINATIONS (a)

Pollutant(b)

Step 1 Step 2 Step 3 Step 5 Step 6 

Technologies 

Identified

Technically

Feasible 

(Yes/No) 

Control 

Level 

(lb/hr)

Control 

Ranking

Modeled 

Impairment 

Contribution(c)

(Days>0.5 Δdv) 

Most 

Effective 

(Yes/No) 

PM 

Wet ESP Yes 12.4 1 --(d) No(d)

Dry ESP Yes 12.4 1 --(d) No(d)

Enhanced Baghouse Yes 12.4 1 --(d) No(d)

Existing Baghouse Yes 12.4 1 --(d) Yes 

SO2 

Wet FGD Yes 26 1 43 No(f)

Spray Dry FGD Yes 104 2 51 Yes 

Dry Trona FGD Yes 183 3 58 No 

Dry Lime FGD Yes 235 4 66 No 

Low Sulfur Coal Yes 444 5 90 No 

Base Case(e) Yes 522 6 127 No 

NOx 

SNCR No(g) -- -- -- -- 

SCR No(h) -- -- -- -- 

ULNB No(i) -- -- -- -- 

LNB/OFA No(j) -- -- -- -- 

LNB Yes 147 1 60 Yes 

Base Case(e) Yes 374 2 127 No 

(a) This table summarizes each BART determination. The BART determination for NOx has been revised as described in this 

section. 

(b) SO2, NOx, and PM emissions were the visibility-impairing pollutants evaluated. 

(c) Δdv = delta deciviews; result is based on changes to visibility at the Eagle Cap Wilderness Area. 

(d) Because the cost of the enhanced baghouse, dry ESP, and wet ESP options were determined to outweigh the 

improvement, BART was selected based on costs of compliance and the pollution control equipment in use (existing 

baghouse). Specific modeling of each PM control scenario was not analyzed. 

(e) The “Base Case” represents continuous coal-fired operation of the Riley Boiler (without controls). 

(f) Wet FGD was not determined to be effective due to non-air quality environmental impacts of compliance related to 

wastewater treatment. 

(g) SNCR was not considered feasible due to concerns that the flue gas would not have adequate residence time to achieve 

reliable control. 

(h) SCR was not considered feasible upstream of the baghouse due to insufficient space necessary to accommodate the 

control device, in addition to concerns regarding catalyst fouling and erosion. SCR was not considered feasible 

downstream of the baghouse due to exhaust gas cooling below the effective operating temperature range of the control 

device. 

(i) ULNB was not considered feasible due to concerns that the boiler firebox would not be large enough to accommodate the 

full burner/flame management system required. 

(j) It was determined that insufficient vertical distance is available between the top burner elevation and the furnace nose 

arch, which is necessary to provide adequate fuel combustion residence time and to accommodate the OFA burner/flame 

management system. 

Revisions 

The initial BART determinations made under T2-2009.0105 issued September 7, 2010 have been revised based 

on engineering design information specific to the Riley Boiler retrofit project. A summary of the revised BART 

determinations is provided below, followed by a discussion of the specific changes. Additionally, although not 

considered a change in the initial BART determinations, analyses has been provided for each Riley Boiler fuel 

operating scenario supporting that BART requirements were considered applicable only when firing coal in the 

Riley Boiler. 
T2-2009.0105 Project 60867 Page 10 

Infeasibility of SCR 

As provided in Table 4, based on the results of an engineering design review of the Riley Boiler, it has been 

determined that selective catalytic reduction (SCR) is not technically feasible for retrofit on the Riley Boiler.2

SCR was not considered feasible upstream of the baghouse due to insufficient space necessary to accommodate 

the control device, in addition to concerns regarding catalyst fouling and erosion. SCR was not considered 

feasible downstream of the baghouse due to exhaust gas cooling below the effective operating temperature range 

of the control device. 

Infeasibility of OFA 

As provided in Table 4, based on the results of an engineering design review of the Riley Boiler, it has been 

determined that over-fired air (OFA) is not technically feasible for retrofit on the Riley Boiler.3

 It was determined 

that insufficient vertical distance is available between the top burner elevation and the furnace nose arch, which is 

necessary to provide adequate fuel combustion residence time and to accommodate the OFA burner/flame 

management system. 

As provided in Table 5, LNB is expected to result in the reduction or elimination of 37 days of visibility 

impairment at Eagle Cap Wilderness - the Class I area showing the greatest impact from the Riley Boiler - over 

the baseline case of no NOx controls. 

Table 5 NOX BART VISIBILITY IMPROVEMENT 

Modeling of the revised BART was completed using the same protocol as described in Appendix B (this protocol 

was also used in the BART modeling analyses for Tier II Operating Permit No. T2-2009.0105, issued on 

September 7, 2010). 

BART Alternative 

Revisions 

Shutdown of the pulp dryers, in combination with installation and operation of LNB on the B&W Boilers, has 

been proposed as the BART Alternative to the control of SO2 emissions from the Riley Boiler. 

The “BART Alternative” scenario is expected to achieve greater reasonable progress than the “BART” scenario 

because this scenario results in greater emissions reductions and in greater visibility improvements, as described 

below. 

Although this alternative primarily reduces NOx emissions, with some reduction in PM and SO2 emissions also 

resulting from the pulp dryer shutdowns, the “BART Alternative” scenario is expected to result in greater 

emission reductions in regional haze pollutants (PM, SO2, and NOx) than the “BART” scenario, and the visibility 

 

2 “New Information on Use of Selective Catalytic Reduction as Riley Boiler BART,” TASCO, May 20, 2011; and “Response to July 18, 2011 E-mail 

Questions,” August 5, 2011. 3 “Feasibility Study to Determine Best Suited Combustion Technology to meet BART, TASCO Purchase Order #65276, Nampa Sugar Mill – RPI Contract 

#100477,” Riley Power Inc., May 19, 2011. 

Eagle Cap Wilderness, OR 

Delta-deciview impacts greater than contribution threshold (∆dv>0.5) 

2003 2004 2005 2003-2005 

8th

highest(a) 

Total 

days(b) 

8th

highest(a) 

Total 

days(b) 

8th

highest(a) 

Total 

days(b) 

22nd

highest(c) 

Total 

days(d) 

Base Riley Boiler Scenario 

(wzl10471) 0.721 15 1.086 41 1.109 41 1.086 97 

NOx Control Scenario 1 – LNB 

(wzl10496) 0.467 7 0.766 25 0.823 28 0.760 60 

(a) The 8th highest delta-deciview impact for the calendar year. 

(b) Total number of days in the 1-year period that exceeded 0.5 delta deciviews. 

(c) The 22nd highest delta-deciview impact for the 3-year period. 

(d) Total number of days in the 3-year period that exceeded 0.5 delta deciviews.
T2-2009.0105 Project 60867 Page 11 

improvement at all Class I areas was predicted to be greater for the “BART Alternative” scenario – with the 

reduction or elimination of 41 additional days expected when compared to the “BART” scenario. A description of 

the “BART” and “BART Alternative” scenarios that were evaluated is provided in the Overview of Changes 

section. 

The BART alternative in Tier II Operating Permit No. T2-2009.0105 issued September 7, 2010 (which involved 

shutdown of three pulp dryers in lieu of installing a SCR control technology for the control of NOx emissions), is 

no longer under consideration as initially proposed. Shutdown of this equipment has instead been incorporated as 

part of the new BART Alternative to the control of SO2 emissions as described above, in lieu of installing Spray 

Dry FGD on the Riley Boiler. 

Emission Reductions 

For evaluation of the “BART Alternative” scenario emission reductions, the “BART Alternative” scenario was 

compared to the “BART” scenario. The “Alternative Benchmark” scenario is included for reference to represent 

baseline (existing) operating conditions. As provided in the tables below, the “BART Alternative” scenario is 

expected to result in greater emission reductions in regional haze pollutants (PM, SO2, and NOx) than the 

“BART” scenario. Refer to Appendix A for additional information regarding the emission reduction estimates. 

An increase in carbon monoxide (CO) emissions is expected to result from the operation of LNB on the Riley 

Boiler and the B&W Boilers. The permittee has indicated that the CO emissions increase is not expected to result 

in a major modification as defined in 40 CFR 52.21(b)(2), and has committed to providing further documentation 

to address PSD applicability (or non-applicability) resulting from this emissions increase at a later date with a 

separate submittal and/or permit to construct application (if applicable). CO is not considered a 

visibility-impairing pollutant, and this emissions increase is not expected to affect evaluation of the BART 

determinations and the BART Alternative. 

Table 6 “BART” EMISSION REDUCTIONS 

Pollutant(a) Emission Source 

“BART” 

Emissions 

lb/hr(b)

“Alternative 

Benchmark” 

Emissions 

lb/hr(c)

Net Emission 

Reductions 

lb/hr 

 Riley Boiler 12.4 12.4 0.0 

PM B&W Boilers #1 & #2 56.9 56.9 0.0 

 North, South, & Center Pulp Dryers 92.7 92.7 0.0 

 Riley Boiler 104.0 522.3 418.3 

SO2 B&W Boilers #1 & #2 435.0 435.0 0.0 

 North, South, & Center Pulp Dryers 17.9 17.9 0.0 

 Riley Boiler 147.0 373.8 226.8 

NOx B&W Boilers #1 & #2 227.0 227.0 0.0 

 North, South, & Center Pulp Dryers 191.2 191.2 0.0 

Total 1,284.1 1,929.2 645.1 

(a) SO2, NOx, and PM emissions were the visibility-impairing pollutants evaluated. 

(b) “BART” scenario includes the Riley Boiler with BART for the control of PM (with the existing baghouse), with 

BART for the control of NOx (LNB), and with BART for the control of SO2 (Spray Dry FGD); full operation of 

the B&W Boilers (without LNB), and full operation of the three pulp dryers. This control scenario represents 

BART as described in the BART Determinations section. 

(c) “Alternative Benchmark” includes the Riley Boiler (with the existing baghouse), full operation of the B&W 

Boilers (without LNB), and full operation of the three pulp dryers. Estimated emission reductions attributable to 

shutdown of the pulp dryers were provided in Table 7 of the BART determination submitted February 9, 2009. 
T2-2009.0105 Project 60867 Page 12 

Table 7 “BART ALTERNATIVE” EMISSION REDUCTIONS 

Pollutant(a) Emission Source 

“BART 

Alternative” 

Emissions 

lb/hr(b)

“Alternative 

Benchmark” 

Emissions 

lb/hr(c)

Net Emission 

Reductions 

lb/hr 

PM 

Riley Boiler 12.4 12.4 0.0 

B&W Boilers #1 & #2 56.9 56.9 0.0 

North, South, & Center Pulp Dryers 0.0 92.7 92.7 

SO2

Riley Boiler 522.3 522.3 0.0 

B&W Boilers #1 & #2 435.0 435.0 0.0 

North, South, & Center Pulp Dryers 0.0 17.9 17.9 

NOx

Riley Boiler 147.0 373.8 226.8 

B&W Boilers #1 & #2 103.0 227.0 124.0 

North, South, & Center Pulp Dryers 0.0 191.2 191.2 

Total 1,276.6 1,929.2 652.6 

(a) SO2, NOx, and PM emissions were the visibility-impairing pollutants evaluated. 

(b) “BART Alternative” includes the Riley Boiler with BART for the control of PM (with the existing baghouse) and 

with BART for the control of NOx (LNB), the B&W Boilers with the BART Alternative to the control of SO2

(Coal-Firing LNB for each boiler), and shutdown of the three coal-firing pulp dryers. This control scenario 

represents the control equipment described in Permit Condition 3.2. 

(c) “Alternative Benchmark” includes the Riley Boiler (with the existing baghouse), full operation of the B&W 

Boilers (without LNB), and full operation of the three pulp dryers. Estimated emission reductions attributable to 

shutdown of the pulp dryers were provided in Table 7 of the BART determination submitted February 9, 2009. 

Visibility Improvements 

The “BART Alternative” scenario was determined to achieve greater improvement in visibility impairment in 

Class I areas than the “BART” scenario. Refer to Appendix B for additional information regarding these modeling 

scenarios. 

Based on CALPUFF modeling, the highest modeled visibility impacts were predicted to occur in the Eagle Cap 

Wilderness Area. The combination of BART for PM, BART for NOx, and the BART Alternative to SO2 was 

predicted to result in a minimum reduction or elimination of 23 days of visibility impairment and an improvement 

in the 22nd highest visibility impact of 0.101 Δdv at the Eagle Cap Wilderness, when compared to the revised 

BART (as summarized in Table 8). 
T2-2009.0105 Project 60867 Page 13 

Table 8 “BART ALTERNATIVE” VISIBILITY IMPROVEMENT – 

EAGLE CAP (a)

Control Scenario 

22nd Highest 

Impact 

(Δdv) 

Impairment 

Contribution 

(Days >0.5 Δdv)(b)

“BART”(d)

Riley Boiler w/ Baghouse (“Alternative Benchmark”)(c)

B&W Boilers #1 & #2 – full operation 

North, South, Center Pulp Dryers – full operation 

2.201 195 

Riley Boiler w/ Baghouse, Spray Dry FGD, LNB (f)

B&W Boilers #1 & #2 – full operation 

North, South, Center Pulp Dryers – full operation 

1.512 149 

Net Visibility Improvement 0.689 46 

“BART 

Alternative”(e)

Riley Boiler w/ Baghouse (“Alternative Benchmark”)(c)

B&W Boilers #1 & #2 – full operation 

North, South, Center Pulp Dryers – full operation 

2.201 195 

Riley Boiler w/ Baghouse, LNB (f)

B&W Boilers #1 & #2 w/ LNB (f)

North, South, Center Pulp Dryers – shutdown 

1.411 126 

Net Visibility Improvement 0.790 69 

Difference in Improvement 0.101 23 

(a) This table compares the modeled visibility impacts for the combined BART determinations and the “BART 

Alternative” to the “Alternative Benchmark” operating scenario. SO2, NOx, and PM emissions were the visibilityimpairing pollutants evaluated. 

(b) Δdv = delta deciviews; result is based on changes to visibility at the Eagle Cap Wilderness Area. 

(c) “Alternative Benchmark” includes the Riley Boiler (with the existing baghouse), full operation of the B&W 

Boilers (without LNB), and full operation of the three pulp dryers. Estimated emission reductions attributable to 

shutdown of the pulp dryers were provided in Table 7 of the BART determination submitted February 9, 2009. 

(d) “BART” includes the Riley Boiler with BART for the control of PM, NOx, and SO2 (with the existing baghouse, 

LNB, and Spray Dry FGD), full operation of the B&W Boilers (without LNB), and full operation of the three 

coal-firing pulp dryers. 

(e) “BART Alternative” includes the Riley Boiler with BART for the control of PM (with the existing baghouse) and 

with BART for the control of NOx (LNB), the B&W Boilers with the BART Alternative to the control of SO2

(Coal-Firing LNB for each boiler), and shutdown of the three coal-firing pulp dryers. This control scenario 

represents the control equipment described in Permit Condition 3.2. 

(f) The NOx control efficiency of the Riley Boiler LNBs = 60.7%, and for the B&W Boilers LNBs = 55%. 

Similar modeled visibility improvements for the “BART Alternative” scenario were predicted across all of the 

Class I areas evaluated (as summarized in Table 9). On the balance, visibility improvement at all Class I areas was 

predicted to be greater for the “BART Alternative” scenario – with the reduction or elimination of 41 additional 

days expected when compared to the “BART” scenario. The single exception was one additional day of visibility 

impairment and 22nd highest visibility impact of -0.017 Δdv at the Selway-Bitterroot Wilderness. The modeling 

results also support that the distribution of emissions with respect to the Class I areas evaluated is not 

substantially different than under the “BART” scenario. 
T2-2009.0105 Project 60867 Page 14 

Table 9 “BART ALTERNATIVE” VISIBILITY IMPROVEMENT (a)

Class I Area(a)

“BART”(b) “BART 

Alternative”(c)

Difference in 

Improvements(d)

22nd

Highest

Days 

>0.5 Δdv

22nd

Highest

Days 

>0.5 Δdv 

22nd

Highest 

Days 

>0.5 Δdv

Eagle Cap Wilderness, OR 1.512 149 1.411 126 0.101 23 

Craters of the Moon National Monument, ID 0.267 4 0.245 3 0.022 1 

Hells Canyon National Recreation Area, ID 1.092 87 1.059 80 0.033 7 

Jarbidge Wilderness, NV 0.256 5 0.234 5 0.022 0 

Sawtooth Wilderness, ID 0.319 6 0.307 6 0.012 0 

Selway-Bitterroot Wilderness, ID 0.281 3 0.298 4 -0.017 -1 

Strawberry Mountain Wilderness, OR 1.076 62 0.917 51 0.159 11 

Total Number of Days 316 275 41 

(a) This table compares the modeled visibility impacts for the combined BART determinations and the “BART 

Alternative” to the “Alternative Benchmark” operating scenario. SO2, NOx, and PM emissions were the visibilityimpairing pollutants evaluated. The Class I areas evaluated were the seven areas within a 300 km radius from the 

Riley Boiler. SO2, NOx, and PM emissions were the visibility-impairing pollutants evaluated. 

(b) “BART” includes the Riley Boiler with BART for the control of PM, NOx, and SO2 (with the existing baghouse, 

LNB, and Spray Dry FGD), full operation of the B&W Boilers (without LNB), and full operation of the three 

coal-firing pulp dryers. 

(c) “BART Alternative” includes the Riley Boiler with BART for the control of PM (with the existing baghouse) and 

with BART for the control of NOx (LNB), the B&W Boilers with the BART Alternative to the control of SO2 

(Coal-Firing LNB for each boiler), and shutdown of the three coal-firing pulp dryers. This control scenario 

represents the control equipment described in Permit Condition 3.2. 

(d) Values reported in this column represent the relative difference or improvement of the “BART Alternative” over 

the “BART” control scenario. 

Natural Gas-Fired Operation 

The Riley Boiler was designed to combust coal and/or natural gas fuels. While the initial BART determinations 

were applicable only to coal combustion, supporting discussion was not provided which addressed emissions from 

natural gas combustion in the Statement of Basis for initial Tier II Operating Permit No. T2-2009.0105. 

Discussion and supporting information are provided below which support the requirement to operate Riley Boiler 

BART control equipment only when firing coal in the Riley Boiler. Modeling of fuel operating scenarios was 

completed using the same protocol as described in Appendix B (this protocol was also used in the BART 

modeling analyses for Tier II Operating Permit No. T2-2009.0105, issued on September 7, 2010). 

Comparing the fuel operating scenarios in the table below, coal combustion resulted in higher estimated emissions 

of visibility-impairing pollutants than natural gas combustion, even when taking into account the emissions 

reductions resulting from BART control equipment. 

Table 10 VISIBILITY-IMPAIRING EMISSIONS BY FUEL 

Fuel / Control Scenario PM 

lb/hr(a)

SO2

lb/hr(a)

NOx

lb/hr(a)

Coal-Fired Riley Boiler 12.4 522 374 

Coal-Fired Riley Boiler with BART 12.4 104 147 

Natural Gas-Fired Riley Boiler 7.7 0.2 99 

Comparing the fuel operating scenarios in the tables below, coal combustion also resulted in higher predicted 

visibility impacts than natural gas combustion, even when taking into account the emissions reductions resulting 

from BART control equipment. 
T2-2009.0105 Project 60867 Page 15 

Table 11 VISIBILITY IMPACTS BY FUEL – EAGLE CAP (a)

Fuel / Control Scenario 

22nd Highest 

Impact 

(Δdv) 

Impairment 

Contribution 

(Days >0.5 Δdv)(b)

Coal-Fired Riley Boiler w/ Baghouse 1.086 97 

Coal-Fired Riley Boiler w/ Baghouse, 

Spray Dry FGD, LNB 0.343 5 

Natural Gas-Fired Riley Boiler 0.166 0 

(a) This table summarizes modeled visibility impacts for the Riley Boiler with the existing baghouse and coal-fired, 

the Riley Boiler with BART controls and coal-fired, and for the Riley Boiler natural gas-fired (without controls) 

operating scenarios; detailed technical information can be found in Appendix A and Appendix B. SO2, NOx, and 

PM emissions were the visibility-impairing pollutants evaluated. 

(b) Δdv = delta deciviews; result is based on changes to visibility at the Eagle Cap Wilderness Area. 

Table 12 VISIBILITY IMPACTS FOR NATURAL GAS (a)

Class I Area(a)

Natural Gas 

22nd

Highest

Days 

>0.5 Δdv 

Eagle Cap Wilderness, OR 0.166 0 

Craters of the Moon National Monument, ID 0.028 0 

Hells Canyon National Recreation Area, ID 0.106 0 

Jarbidge Wilderness, NV 0.029 0 

Sawtooth Wilderness, ID 0.034 0 

Selway-Bitterroot Wilderness, ID 0.028 0 

Strawberry Mountain Wilderness, OR 0.099 0 

Total Number of Days 0 

(a) This table summarizes modeled visibility impacts for the natural gas-firing operating scenario for the Riley 

Boiler; detailed technical information can be found in Appendix A and Appendix B. SO2, NOx, and PM emissions 

were the visibility-impairing pollutants evaluated. The Class I areas evaluated were the seven areas within a 300 

km radius from the Riley Boiler. SO2, NOx, and PM emissions were the visibility-impairing pollutants evaluated. 

As provided, the emissions and modeled visibility impacts when firing 100% natural gas were predicted to be 

significantly lower than when firing coal in the Riley Boiler, even when accounting for the use of BART controls. 

It was therefore considered reasonable to determine the “base case” or “no control” options as BART for the 

control of PM, SO2, and NOx emissions when combusting 100% natural gas. As an operational requirement and 

for compliance monitoring purposes, monitoring of average daily feed or firing rate and hours of operation per 

day for each fuel has been required in lieu of complying with explicit BART emission rate limits. (Refer to 

discussion provided for Permit Condition 3.9 in the Permit Conditions Review section for information concerning 

these requirements.) 

As a result, operation of the Riley Boiler on 100% natural gas after the BART compliance date remains a 

voluntary “compliance option” in lieu of installing BART and BART Alternative control equipment. Operation of 

BART and BART Alternative control devices is also not required (if installed) when the Riley Boiler is fired 

exclusively on natural gas, unless required in another permit for other (non-BART) reasons. 
T2-2009.0105 Project 60867 Page 16 

REGULATORY REVIEW 

Attainment Designation (40 CFR 81.313) 

The facility is located in Canyon County, which is designated as attainment or unclassifiable for PM10, PM2.5, CO, 

NO2, SOx, and Ozone. Reference 40 CFR 81.313. 

Tier II Operating Permit (IDAPA 58.01.01.401) 

An application was submitted requesting a BART Tier II operating permit revision. Therefore this permitting 

action was processed in accordance with the procedures of IDAPA 58.01.01.400-410. 

Title V Classification (IDAPA 58.01.01.300, 40 CFR Part 70) 

The operation of BART control equipment is not expected to change Title V applicability or classification of the 

facility. The facility is classified as a major facility as defined in IDAPA 58.01.01.008.10, because it emits or has 

the potential to emit regulated air pollutants in amounts greater than or equal to major facility thresholds listed in 

IDAPA 58.01.01.008.10. The applicable requirements contained in this Tier II operating permit will be 

incorporated into the Tier I operating permit during renewal. 

Because the Nampa Factory contains a fossil-fuel fired boiler of more than 250 MMBtu/hr heat input, it has been 

classified as a designated facility as defined in IDAPA 58.01.01.006.30 and 40 CFR 52.21(b)(1)(i)(a). 

PTC, PSD, and NSPS Applicability (IDAPA 58.01.01.201, 40 CFR 52.21, and 40 CFR 60) 

An application was submitted requesting a BART Tier II operating permit revision. Therefore the procedures of 

IDAPA 58.01.01.200-228 were not applicable to this permitting action. 

The facility is classified as an existing major stationary source, because the estimated emissions of criteria 

pollutants and HAP have the potential to exceed major stationary source thresholds. Because the Nampa Factory 

has a fossil-fuel boiler of more than 250 MMBtu/hr heat input, the boiler house (which includes the Riley Boiler) 

is a designated facility as defined in IDAPA 58.01.01.006.30 and in 40 CFR 52.21(b)(1)(i)(a), and fugitive 

emissions are required to be included when determining the major facility classification in accordance with 

IDAPA 58.01.01.008.10.c.i. 

PSD, NSPS, and PTC regulatory applicability potentially resulting from the installation and operation of BART 

and the BART Alternative have not been evaluated or addressed as part of this permitting action. The permittee 

has requested that regulatory applicability be addressed prior to the installation and operation due date of July 22, 

2016 and in a separate permit to construct permitting action, if applicable. The permittee is encouraged to address 

any applicable requirements as soon as practicable to allow adequate time for DEQ review and permit processing 

(if applicable) before July 22, 2016. 

Ambient air impact analyses of BART and the BART Alternative has not been required or evaluated for 

compliance with ambient air quality standards. Although an increase in carbon monoxide (CO) emissions is 

expected to result from the operation of LNB on the Riley Boiler and the B&W Boilers, the permittee has 

indicated that a net emission decrease in CO is expected to result from the permanent shutdown of the South Pulp 

Dryer when combined with the emission increases from the LNBs. The permittee has also indicated that an 

emission increase of any toxic air pollutant (TAP) is not expected to result from this project. As a result, 

preconstruction compliance with NAAQS or TAP standards is not expected to be applicable to this project. 

NESHAP and MACT Applicability (40 CFR Parts 61 and 63) 

The installation and operation of BART and BART Alternative control equipment is not expected to alter the 

applicability of any affected source regulated by National Emission Standards for Hazardous Air Pollutants 

(NESHAP) Parts 61 or 63. 

CAM Applicability (40 CFR 64) 

The installation and operation of BART and BART Alternative control equipment is not expected to alter the 

applicability of any emissions unit regulated by Compliance Assurance Monitoring (CAM) Part 64. 
T2-2009.0105 Project 60867 Page 17 

BART Applicability (40 CFR 51.308 and IDAPA 58.01.01.668) 

The Riley Boiler was previously determined to be a BART-eligible source and subject-to-BART (refer to the 

Statement of Basis for T2-2009.0105 for a discussion of BART eligibility and the subject-to-BART 

determination). Refer to the BART Determinations section and Appendix A for additional discussion concerning 

BART and the BART Alternative. Following issuance of this revised Tier II operating permit, EPA approval is 

required before the revised BART determinations and the BART Alternative are effective in accordance with the 

requirements of 40 CFR 51, Subpart P. 

• The Riley Boiler is a BART-eligible source because it was an existing stationary facility (fossil-fuel fired 

boiler with heat input of 350 MMBtu/hr, more than 250 MMBtu/hr) that was not in operation prior to 

August 7, 1962 and was in existence on August 7, 1977 (installed in 1969), having the potential to emit 250 

tons per year of air pollutants (PM, SO2, NOx, and CO) as defined in 40 CFR 51.301. 

• The Riley Boiler was determined to be subject-to-BART and to contribute to visibility impairment at the 

Eagle Cap Wilderness, Hells Canyon National Recreation Area, and Strawberry Mountain Wilderness 

mandatory Class I Federal Areas based on CALPUFF modeling, with the 98th percentile highest 

delta-deciview impact greater than 0.5 over the years 2003-2005. 

• DEQ will submit the proposed revisions to BART and the BART Alternative to EPA pursuant to Section 

§51.308(e) for approval as a revision to the RH SIP following issuance of this permit. 

40 CFR 51.308(e) and IDAPA 58.01.01.668 ................................ BART Regional Haze Requirements 

Section §51.308(e) describes the Best Available Retrofit Technology (BART) requirements for regional haze 

visibility impairment. DEQ must submit an implementation plan containing emission limitations representing 

BART and schedules for compliance with BART for each BART-eligible source that may reasonably be 

anticipated to cause or contribute to any impairment of visibility in any mandatory Class I Federal area. The 

purpose of IDAPA 58.01.01.668 is to implement the BART requirements in 40 CFR 51.308(e). 

In accordance with §51.308(e)(1), to address the requirements for BART, DEQ must submit an implementation 

plan containing the plan elements and include documentation for all required analyses. 

Best Available Retrofit Technology (BART) means an emission limitation based on the degree of reduction 

achievable through the application of the best system of continuous emission reduction for each pollutant which is 

emitted by an existing stationary facility. The emission limitation must be established, on a case-by-case basis, 

taking into consideration the technology available, the costs of compliance, the energy and non-air quality 

environmental impacts of compliance, any pollution control equipment in use or in existence at the source, the 

remaining useful life of the source, and the degree of improvement in visibility which may reasonably be 

anticipated to result from the use of such technology. 

In accordance with §51.308(e)(1)(ii)(A) and IDAPA 58.01.01.668.02.c, the determination of BART must be 

based on an analysis of the best system of continuous emission control technology available and associated 

emission reductions achievable for each BART-eligible source that is subject to BART. In this analysis, DEQ 

must take into consideration the technology available, the costs of compliance, the energy and non-air quality 

environmental impacts of compliance, any pollution control equipment in use at the source, the remaining useful 

life of the source, and the degree of improvement in visibility which may reasonably be anticipated to result from 

the use of such technology. These considerations were included in Step 4 of the BART determinations (refer to 

Appendix A for discussion of the BART determinations). 

In accordance with §51.308(e)(1)(iv) and IDAPA 58.01.01.668.04, each source subject to BART is required to 

install and operate BART as expeditiously as practicable, but in no event later than 5 years after approval of the 

revised RH SIP. Permit Condition 3.3 includes this requirement. 

In accordance with §51.308(e)(1)(v) and IDAPA 58.01.01.668.05, each source subject to BART is required to 

maintain the control equipment required and establish procedures to ensure such equipment is properly operated 

and maintained. Permit Condition 3.8 includes the requirement of this section. 

In accordance with §51.308(e)(2) and IDAPA 58.01.01.668.06, DEQ may approve a BART alternative rather than 

to require sources subject to BART to install, operate, and maintain BART. The alternative measure must achieve 
T2-2009.0105 Project 60867 Page 18 

greater reasonable progress than would be achieved through the installation and operation of BART. For all such 

alternative measures, DEQ must submit an implementation plan containing the plan elements and include 

documentation for all required analyses. Installation and operation of Coal-Firing LNB in the B&W Boilers and 

shutdown of three coal-fired pulp dryers was proposed by the permittee as a BART Alternative to the control of 

SO2 emissions. The resultant emissions reduction and visibility impacts were compared with those that would 

result from BART for SO2. Documentation of BART and BART Alternative analyses, including an analysis of 

BART and the BART Alternative, the associated emission reductions, comparison of the BART Alternative to 

BART, and a determination that the BART Alternative achieves greater reasonable progress than would be 

achieved through the installation and operation of BART was included in Section 1.3.4 of Appendix A and in 

Appendix B. Permit Condition 3.5 includes federally enforceable emission limitations for the BART Alternative. 

Permit Conditions 3.7, 3.11, and 4.1 include requirements for the installation, operation, and maintenance of 

Coal-Firing LNB in the B&W Boilers and for shutdown of the coal-fired pulp dryer (BART Alternative to the 

control of SO2 emissions). 

The permittee proposing a BART alternative must demonstrate that this BART alternative will achieve greater 

reasonable progress than would be achieved through the installation and operation of BART. Because both the 

expected visibility improvement and the emissions reductions in visibility-impairing pollutants were greater in the 

case of the BART Alternative, it is expected that the BART Alternative will achieve greater reasonable progress 

than would be achieved through the installation and operation of BART for SO2. Refer to the BART Alternative 

section for additional information. 

The permittee proposing a BART alternative shall include in the BART analysis an analysis and justification of 

the averaging period and method of evaluating compliance with the proposed emission limitation. No revision of 

the requirement for annual performance testing, which relies upon the use of EPA reference methods for 

evaluating compliance with BART and BART Alternative emission limits, has been proposed. 

Permit Conditions Review 

This section describes the permit conditions for this permit. With the exception of permit T2-2009.0105, which 

will be superseded by this permit upon approval of a revised RH SIP, the requirements of this Tier II operating 

permit do not contravene any permit conditions in any applicable permits to construct and Tier I and Tier II 

operating permits (T1-050020, T2-050021, P-030062). The permittee must continue to comply with all applicable 

permits. 

Where substantive changes have been made to permit conditions, the permit conditions that were revised have 

been cited (in parenthesis) from Tier II Operating Permit No. T2-2009.0105 issued September 7, 2010; the permit 

has been included in Appendix C for reference. Each instance of the BART compliance date in the permit has also 

been replaced with July 22, 2016, which is five years from the effective date of the initial approved RH SIP4

 as 

determined in accordance with IDAPA 58.01.01.668.04 and 40 CFR 51.308(e)(1)(iv). 

Permit Conditions 1.1, 1.2, 3.1, and 3.2 (Permit Conditions 1.1, 1.2, 3.1, and 3.2 of T2-2009.0105) 

These permit conditions explain the purpose of this permitting action and describe the emission sources and 

control equipment regulated. Information reflects the revised BART determinations, the BART Alternative, and 

the design, equipment, and operational information presented in the revised BART analyses. 

Permit Condition 1.1 requires that this permit is not effective until a revised Regional Haze State Implementation 

Plan incorporating the revised BART and BART Alternative requirements has been approved by EPA. Tier II 

Operating Permit No. T2-2009.0105 remains effective until approval has been granted by EPA. Upon approval 

this permit supersedes Tier II Operating Permit No. T2-2009.0105. 

Permit Conditions 1.2 and 3.2 have been revised to include revised BART control equipment information for the 

Riley Boiler LNB and the B&W Boilers LNB. 

Permit Condition 3.1 has been revised to include a description of each of the boilers involved in BART and the 

BART Alternative. 

 

4 Approval and Promulgation of Implementation Plans, State of Idaho, Regional Haze State Implementation Plan and Interstate Transport Plan, 76 FR Final 

36329-36339, Final, June 22, 2011. 
T2-2009.0105 Project 60867 Page 19 

Permit Condition 2.1 (Permit Condition 2.1 of T2-2009.0105) 

This permit condition clarifies that compliance with all applicable local, state, and federal rules and regulations is 

required, in accordance with IDAPA 58.01.01.406. 

Permit Condition 2.2 (Permit Condition 2.2 of T2-2009.0105) 

This permit condition incorporates applicable federal requirements into the permit by reference. The intent is that 

the federal requirement shall govern any conflict with a permit condition referencing a federal requirement. 

Permit Condition 2.3 (Permit Condition 2.3 of T2-2009.0105) 

This permit condition provides contact information for submittal of required performance test reports, reports, 

applications, submittals, and other communications to DEQ. 

Permit Condition 2.4 

This permit condition provides approved test methods to be used when performance testing is required, unless 

otherwise approved by DEQ, in accordance with IDAPA 58.01.01.157. 

The permittee is encouraged to submit performance test protocol to DEQ for approval prior to any performance 

testing in accordance with the performance testing general provision (Permit Condition 100). 

Permit Condition 3.3 (Permit Condition 3.3 of T2-2009.0105) 

This permit condition incorporates the BART and BART Alternative compliance deadlines in accordance with 

IDAPA 58.01.01.668.04 and 40 CFR 51.308(e)(1)(iv). Coal may be combusted in the Riley Boiler on and after 

the compliance deadline only if BART and the BART Alternative are installed and operating. 

The permittee has requested the option to use BART Alternative control strategies to achieve the BART and 

BART Alternative emission limits (Permit Conditions 3.4 and 3.5), and has requested the addition of clarifying 

language which documents that the conditions of this permit may be revised in accordance with IDAPA 

58.01.01.404. DEQ has included language in Permit Condition 3.3 inclusive of either using the approved BART 

and the BART Alternative, or some other DEQ-and-EPA-approved BART alternative(s). Additional BART 

alternative(s) will be considered and relevant BART determinations revised if adequate time is allowed to meet 

applicable permitting and SIP deadlines. 

This permit condition has been revised to allow for operation using natural gas-only in lieu of installation and 

operation of BART and BART Alternative control equipment (refer to the Riley Boiler fuel operating scenarios in 

the BART Determinations section for additional discussion). 

As provided in the Natural Gas-Fired Operation section, operation of the Riley Boiler on 100% natural gas after 

the BART compliance date remains a voluntary “compliance option” in lieu of installing BART and BART 

Alternative control equipment. Operation of BART and BART Alternative control devices is also not required (if 

installed) when the Riley Boiler is fired exclusively on natural gas. 

Compliance with the deadline (or alternatively, compliance with firing only natural gas in the Riley Boiler as 

specified in Permit Condition 3.9) is ensured by complying with notification requirements (Permit Condition 

3.16). 

(Refer to discussion provided concerning Riley Boiler fuel operating scenarios in the BART Determinations 

section and discussion provided for Permit Conditions 3.6, 3.7, and 3.9 for additional information.) 

Permit Conditions 3.4 and 3.5 (Permit Condition 3.4 of T2-2009.0105) 

These permit conditions establish revised emission limits for BART and the BART Alternative in accordance 

with IDAPA 58.01.01.668 and 40 CFR 51.308(e). 

The BART PM emission limit was based upon the use of the existing baghouse on Riley Boiler to control PM 

emissions. The BART and the BART Alternative NOx emission limits were based upon the use of coal-fired low 

NOx burner systems on the Riley Boiler and B&W Boilers to control NOx emissions. 

This permit condition has been revised to reflect the approved changes to the BART and BART Alternative 

control equipment, and to separate BART emission limits from the BART Alternative emission limits for 

clarification and for compliance purposes. 
T2-2009.0105 Project 60867 Page 20 

Compliance with these emission limits when firing coal is ensured by complying with performance testing 

(Permit Conditions 3.11 and 3.13) and associated monitoring, recordkeeping, and reporting requirements (Permit 

Conditions 3.14 and 3.15). Alternatively, compliance with these emission limits is ensured by firing the boiler 

with natural gas. 

Permit Conditions 3.6 and 3.7 (Permit Conditions 3.6, 3.7, and 3.8 of T2-2009.0105) 

These permit conditions incorporate requirements to operate the approved BART and BART Alternative control 

equipment (as described in Permit Condition 3.2) in accordance with §51.308(e)(1)(iv) and 

IDAPA 58.01.01.668.04. 

Permit Conditions 3.6 and 3.7 have been revised to allow for operation using natural gas only in lieu of 

installation and operation of BART and BART Alternative control equipment. Permit Condition 3.7 has been 

revised to require the use of LNB on the B&W Boilers, as approved in the BART Alternative. Because over-fired 

air is no longer part of BART, and because Spray Dry FGD is no longer part of the BART Alternative, the 

requirements to install and operate these control technologies have been removed. 

Compliance with these requirements is ensured by complying with operating (Permit Conditions 3.6 through 3.9), 

monitoring and recordkeeping (Permit Condition 3.10), performance testing requirements (Permit Conditions 

3.11, 3.13 through 3.15), and reporting requirements (Permit Condition 3.16). 

(Refer to discussion provided for Permit Condition 3.3 and 3.9 for additional information.) 

Permit Condition 3.8 (Permit Conditions 3.9 and 3.10 of T2-2009.0105) 

Permit Condition 3.8 requires that the permittee maintain the control equipment required and establish procedures 

to ensure such equipment is properly operated and maintained, in accordance with IDAPA 58.01.01.668.05. 

For the low NOx burners, compliance with this requirement is ensured by complying with O&M monitoring and 

recordkeeping requirements (Permit Condition 3.10). For the existing baghouse, the permittee has requested 

ensuring compliance with this requirement by complying with existing baghouse pressure drop monitoring and 

recordkeeping requirements in Permit Condition 3.9 of Tier II Operating Permit No. T2-050021. As a result, this 

condition has been removed from the permit and the citation for Permit Condition 3.9 of T2-050021 will be 

updated during permit renewal to include IDAPA 58.01.01.668.05 and 40 CFR 51.308(e)(1)(v). It should also be 

noted that the baghouse pressure drop monitoring frequency has been reduced from daily to weekly. With 

consideration given to the relevant permitting and compliance histories of the boilers, it was considered 

reasonable to maintain the frequency of monitoring that was previously established. The baghouse O&M manual 

has been included for review and for reference in Appendix D. (Although outside the scope of this permitting 

action, BART and other monitoring requirements may need to be revisited during renewal of the Title V permit 

for the purposes of CAM). 

Permit Condition 3.9 of T2-050021: 

The permittee shall install, operate, calibrate, and maintain measuring device(s) to continuously monitor 

the pressure drop across each of the baghouses. The pressure drop shall be recorded once per week while 

the boilers are in operation. In the event the measuring device becomes inoperable, it shall be repaired or 

replaced as soon as practicable. The records shall be maintained in accordance with Facility-wide 

Condition 2.16. 

Permit Condition 3.9 

This permit condition limits the Riley Boiler to the combustion of only natural gas in the event that BART and the 

BART Alternative control equipment have not been installed by the BART compliance deadline. 

The permittee has requested ensuring compliance with this requirement by complying with existing fuel 

monitoring and recordkeeping requirements in Permit Condition 3.8 of Tier II Operating Permit No. T2-050021. 

Permit Condition 3.8 of T2-050021: 

3.8 The permittee shall monitor and record the following information listed in Permit 

Conditions 3.8.1-3.8.8 for each boiler. The records shall be maintained in accordance with 

Facility-wide Condition 2.16. 

3.8.1 The average daily coal feed rate in tons per hour. 

3.8.2 The coal feed rate for each consecutive 12-month period in tons per year. 
T2-2009.0105 Project 60867 Page 21 

3.8.3 The daily hours of operation with coal. 

3.8.4 The heat input rate expressed in millions of British thermal units per hour by correlating 

the coal feed rate with the coal high-heating value. 

3.8.5 The average daily gas-firing rate in millions of standard cubic feet per hour. 

3.8.6 The natural gas-firing rate for each consecutive 12-month period in millions of standard 

cubic feet per year. 

3.8.7 The daily hours of operation with natural gas. 

3.8.8 The fuel type whenever the fuel type is changed. Fuel type in this section means natural gas 

only, coal only, or the combination of natural gas and coal. 

(Refer to discussion provided for Permit Conditions 3.3, 3.6, and 3.7 for additional information.) 

Permit Condition 3.10 (Permit Condition 3.13 of T2-2009.0105) 

This permit condition requires the development and documentation of operation and maintenance procedures for 

the operation and maintenance of BART control equipment to ensure compliance with the BART emission limits 

(Permit Conditions 3.4 and 3.5), maintenance of BART equipment (Permit Condition 3.9), control equipment 

maintenance and operation (General Provision 2), and manufacturer’s specifications. 

This permit condition has been revised to reflect the approved changes to the BART and BART Alternative 

control equipment. Because the installation of Spray Dry FGD and over-fired air are no longer part of the BART 

and the BART Alternative, the requirements to monitor associated indicators (slurry flow rate, adiabatic approach 

temperature, over-fired airflow) were no longer applicable and have been removed. 

Permit Conditions 3.11 and 3.13 (Permit Conditions 3.14 and 3.15 of T2-2009.0105) 

Permit Conditions 3.11 and 3.13 require annual performance testing to determine PM and NOx emissions from the 

Riley Boiler, and to determine NOx emissions from the B&W Boilers to demonstrate compliance with BART and 

BART Alternative emission limits (Permit Conditions 3.4 and 3.5) in accordance with IDAPA 58.01.01.405. 

These permit conditions have been revised to reflect the approved changes to the BART and BART Alternative 

control equipment. Because the SO2 emissions limit is no longer included as part of the approved BART and 

BART Alternative emission limits, the requirements to monitor associated indicators (slurry flow rate, adiabatic 

approach temperature, over-fired airflow) were no longer applicable and have been removed. Six-month deadlines 

in which to complete required performance testing were requested to accommodate the seasonal operating 

schedule of the facility, and to allow for testing during the beet campaign (generally the period of maximum 

boiler operating loads). 

Compliance with these requirements is ensured by complying with test monitoring, recordkeeping, and reporting 

requirements (Permit Conditions 3.14 and 3.15) and General Provision 6. 

Permit Condition 3.12 (Permit Condition 3.5 of T2-2009.0105) 

Permit Condition 3.12 requires initial performance test(s) to determine CO emissions following installation of 

boiler LNBs, to verify whether the project has resulted in a PSD major modification as defined in 40 CFR 52.21. 

An increase in carbon monoxide (CO) emissions is expected to result from the operation of LNB on the Riley 

Boiler and the B&W Boilers. The permittee has indicated that the CO emissions increase is not expected to result 

in a major modification as defined in 40 CFR 52.21(b)(2), and has committed to providing further documentation 

to address PSD applicability (or non-applicability) resulting from this emissions increase at a later date with a 

separate submittal and/or permit to construct application (if applicable). Six-month deadlines in which to 

complete required performance testing were requested to accommodate the seasonal operating schedule of the 

facility, and to allow for testing during the beet campaign (generally the period of maximum boiler operating 

loads). 

Because CO emissions and regulatory applicability will be determined at a later date, CO emission limits (initially 

included for PSD avoidance purposes) were removed. Permit Condition 3.12 was included to ensure that 

emissions data necessary to make this applicability determination will be available within 90 days of startup of the 

LNBs. The CO emissions from the B&W Boilers and the Riley Boiler remain limited by a combined emissions 

limit of 159.0 T/yr as required by Permit Condition 3.1 of Tier I Operating Permit No. T1-050020. 
T2-2009.0105 Project 60867 Page 22 

For baseline emissions, the permittee has provided performance test data for the Riley Boiler when fired by coal 

and for the B&W Boilers when fired by coal5

 which may be used (in absence of more suitable data) to determine 

regulatory applicability. 

Permit Condition 3.14 and Permit Condition 3.15 (Permit Conditions 3.16 and 3.17 of T2-2009.0105)

These permit conditions specify testing conditions and require monitoring, recordkeeping, and reporting to ensure 

compliance with initial and periodic performance testing requirements (Permit Conditions 3.11 through 3.13) and 

in accordance with IDAPA 58.01.01.157 and General Provision 6. 

This permit condition has been revised to reflect the approved changes to the BART and BART Alternative 

control equipment. Because the BART and BART Alternative control equipment no longer include Spray Dry 

FGD and over-fired air, the requirements to monitor associated indicators (slurry flow rate, adiabatic approach 

temperature, over-fired airflow) were no longer applicable and have been removed. 

The option to request alternate testing frequencies and to utilize a DEQ-approved calculation methods to measure 

coal feed rate was included at the request of the permittee. 

Permit Condition 3.16 (Permit Condition 3.20 of T2-2009.0105) 

This permit condition requires DEQ notification of the method used to disable coal-firing on the Riley Boiler if 

coal-firing LNBs have not been installed by the BART compliance deadline to ensure compliance with Permit 

Condition 3.9, and requires notification of the anticipated date of initial startup in accordance with General 

Provision 5 to ensure compliance with Permit Condition 3.7. Contact information was also included. 

Permit Condition 4.1 (Permit Condition 4.1 of T2-2009.0105) 

This permit condition requires permanent shutdown of the three pulp dryers to comply with the BART Alternative 

to the control of SO2 emissions, in accordance with IDAPA 58.01.01.668.06. 

Removed Permit Conditions (Permit Conditions 3.11, 3.12, 3.18, 3.19, 4.2, and 5 of T2-2009.0105) 

Permit Conditions 3.11 and 3.12 required monitoring of Spray Dry FGD adiabatic approach temperature to ensure 

compliance with the BART SO2 emission limit, and monitoring of primary and over-fired air flow rates to ensure 

compliance with the BART NOx emission limit. Because a BART Alternative to the control of SO2 emissions has 

been approved in lieu of installation and operation of Spray Dry FGD, and because over-fired air is no longer 

included as part of the BART determination for the control of NOx emissions, these monitoring indicator 

requirements were no longer applicable and have been removed. 

Permit Condition 3.18 was established to require submittal of information and preconstruction compliance 

demonstrations necessary to demonstrate compliance with the requirements of IDAPA 58.01.01.200-228. 

Although an increase in carbon monoxide (CO) emissions is expected to result from the operation of LNB on the 

Riley Boiler and the B&W Boilers, the permittee has indicated that a net emission decrease in CO is expected to 

result from the permanent shutdown of the South Pulp Dryer when combined with the emission increases from the 

LNBs. The permittee has also indicated that an emission increase of any toxic air pollutant (TAP) is not expected 

to result from this project. As a result, preconstruction compliance with NAAQS or TAP standards is not expected 

to be applicable to this project. This requirement was no longer considered necessary and was removed. 

Permit Condition 3.19 was established to require submittal of information necessary to address applicable CAM 

requirements in accordance with 40 CFR 64. The installation and operation of BART and BART Alternative 

control equipment is not expected to alter the applicability of any emissions unit regulated by Compliance 

Assurance Monitoring (CAM) Part 64. Because CAM requirements will be determined at the time of Tier I 

operating permit renewal, this requirement has been removed. Because intervals for monitoring, monitor 

calibration, and performance testing have been required elsewhere in the permit in accordance with IDAPA 

58.01.01.668.06.c (Permit Conditions 3.10, 3.11, 3.13, and 3.14), reference to this citation has also been removed. 

Permit Condition 4.2 was established to ensure compliance with Permit Condition 4.1, permanent shutdown of the 

three pulp dryers. The permittee has demonstrated compliance with this requirement, and has provided 

documentation that shutdown of the rotary drum dryer system, including the North, Center, and South Pulp 

 

5 “Attachment A – Net CO Emissions Reductions & Calculations & October 2009 Boiler CO Emissions Test Report,” TASCO, September 15, 2011. 
T2-2009.0105 Project 60867 Page 23 

Dryers, was completed as of December 22, 2006.6 As a result, this requirement was no longer considered 

necessary and was removed. 

Permit Condition 5 was a restatement of the emission limits in the permit (Permit Conditions 3.4 and 3.5). This 

permit condition was determined to be duplicative in nature and has been removed. 

PUBLIC COMMENT 

A public comment period was made available to the public in accordance with IDAPA 58.01.01.404.01.c. During 

this time, comments were submitted in response to DEQ’s proposed action. Refer to the chronology for public 

comment period dates. 

A response to public comments document has been crafted by DEQ based on comments submitted during the 

public comment period. That document is part of the final permit package for this permitting action. 

 

6 “Notification of Steam Dryer Project Completion”, TASCO, January 31, 2007. 
T2-2009.0105 Project 60867 Page 24 

APPENDIX A – BART DETERMINATIONS AND BART ALTERNATIVE
T2-2009.0105 Project 60867 Page 25 

Department of Environmental Quality 

Amalgamated Sugar Company (TASCO) 

Best Available Retrofit Technology Determinations 

Revised October 31, 2011
T2-2009.0105 Project 60867 Page 26 

Amalgamated Sugar Company (TASCO) 

Best Available Retrofit Technology Determinations 

1.1 BART Background ................................................................................................................. 27

1.2 BART Process ......................................................................................................................... 28

1.3 BART Eligibility ..................................................................................................................... 28

1.4 BART Subject ......................................................................................................................... 29

1.5 BART Determinations ............................................................................................................ 31

1.5.1 Particulate BART Control Technology Selection ......................................................................... 33

1.5.2 SO2 BART Control Technology Selection .................................................................................... 34

1.5.3 NOx BART Control Technology Selection ................................................................................... 40

1.5.4 SO2 BART Alternative .................................................................................................................. 43

1.6 Natural Gas-Fired Operation ................................................................................................... 47

1.7 Conclusion .............................................................................................................................. 49
T2-2009.0105 Project 60867 Page 27 

1.1 BART Background 

The 1977 Clean Air Act (CAA) Amendments created Part C of the Act entitled Prevention of Significant 

Deterioration of Air Quality and includes Sections 160-169. The intent of the Prevention of Significant 

Deterioration (PSD) provisions is to maintain good air quality in areas that attain the national air quality 

standards and provide special protections for National Parks Wilderness Areas. Part C is divided into two 

subparts. Subpart 1 established the initial classification of Class I and Class II areas. Class I areas include: 

Section 162(a) 

(1) International Parks, 

(2) National wilderness areas which exceed 5,000 acres in size, 

(3) National memorial parks which exceed 5,000 acres in size, and 

(4) National parks which exceed six thousand acres in size and which are in existence on the date 

of the enactment of the Clean Air Act Amendments of 1977 shall be Class I areas and may not be 

redesignated. . . 

(b) All areas in such State designated . . . as attainment or unclassifiable which are not 

established as class I under subsection (a) shall be class II areas . . . 

The Class I areas that met this criteria and were in existence on or before 1977 became known as 

“mandatory class I federal areas.” Although states could designate other areas as Class I areas after 1977, 

PSD and other portions of the Regional Haze Rule focus on those Class I areas in existence on or before 

1977. 

Based on the classification of an area, the amount of allowable degradation which is from new or 

modified air pollution sources is determined. In National Parks and other Class I areas smaller amounts of 

degradation known as “increment” are allowed. The PSD program under Part C, Subpart 1 primarily 

focuses on emission from 1977 forward and will be further discussed in the chapters on Reasonable 

Progress and Long Term Strategies. 

Visibility is called out much stronger in Part C, Subpart 2 and set the national goal of “the prevention of 

any future and the remedying of any existing, impairment of visibility in mandatory Class I Federal areas 

which impairment results from manmade air pollution” (CAA Section 169(A). In an effort to remediate 

the existing impairments to visibility, the Section 169(A)(2)(A) includes “a requirement that each major 

stationary source which is in existence on the date of enactment of this section, but which has not been in 

operation for more than fifteen years as of such date, . . .emits any air pollutant which may reasonably be 

anticipated to cause or contribute to any impairment of visibility in any such area, shall procure, install 

and operate, as expeditiously as practicable (and maintain thereafter) the best available retrofit 

technology, as determined by the state.” 

To carry out Congress’ intent to install BART on certain emission sources, EPA promulgated the 

“Regional Haze Rule” [64 FR 35714 (July 1, 1999)]. These rules were challenged, and on May 24, 2002, 

the U. S. Court of Appeals for the District of Columbia vacated the Regional Haze Rule and remanded the 

BART provisions in the Rule. Revisions to the rule were published on July 6, 2005 [70 FR 39104 (July 6, 

2005)]. The BART rule can also be found under 40 CFR 51.308(e). As part of the July 6, 2005 rule 

revisions, EPA published Appendix Y guidance for the implementation of BART. The guidance can be 

found beginning at 70 FR 39156 (July 6, 2005). 

In the spring of 2006, the Department of Environmental Quality (DEQ) went through a negotiated 

rulemaking process to develop rules for Regional Haze. During this process rules were negotiated for the 

implementation of BART and Reasonable Progress Goals. These rules pertaining to BART can be found 
T2-2009.0105 Project 60867 Page 28 

at IDAPA 58.01.01.668. During the negotiated rule making process, it was decided to follow EPA 

Appendix Y Guidance on the BART determination process but not incorporate the guidance into rule 

under IDAPA. A threshold of visibility impact of 0.5 deciviews in any Class I Federal Area was 

established through negotiated rulemaking as “contributing” to visibility impairment. 

1.2 BART Process 

The BART provision applies to “major stationary sources” from 26 identified source categories which 

have the potential to emit 250 tons per year or more of any air pollutant. The CAA requires that only 

sources which were built or in operation during a specific 15-year time interval be subject to BART. The 

BART provision applies to sources that existed as of the date of the 1977 CAA amendments (that is, 

August 7, 1977) but which had not been in operation for more than 15 years (that is, not in operation as of 

August 7, 1962). The first phase of the BART process is developing a list of BART “eligible” facilities 

which include those major facilities from the 26 identified source categories that have a potential to emit 

250 tons per year of any light impairing pollutant. 

The CAA requires BART analyses when any source meeting the above description “emits any air 

pollutant which may reasonably be anticipated to cause or contribute to any impairment of visibility” in 

any Class I area. In most cases, the determination of whether a facility is causing or contributing to 

visibility impairment is done through modeling. Any BART-eligible facility with an impact of one 

deciview is considered “causing” visibility impairment, and in Idaho the threshold for “contributing” to 

impairment is 0.5 deciviews.7

 Any BART-eligible facility causing or contributing to visibility impairment 

is BART “subject.” BART subject facilities are required to go through a process to determine what if any 

controls will be required. 

1.3 BART Eligibility 

The source is BART-eligible if it falls into one of 26 sector categories, was built between 1962 and 1977, 

and annually emits more than 250 tons of a haze-causing pollutant. The Riley Boiler of The Amalgamated 

Sugar Company, LLC (TASCO) Sugar Plant in Nampa, Idaho has been determined to be BART-eligible. 

The Boiler is rated at 350 million BTUs per hour which meets the BART criteria as a fossil-fuel boiler of 

more than 250 million BTUs per hour heat input, was installed in 1969, and was put into service between 

August 7, 1962 and August 7, 1977. 

The Riley Boiler’s Potential to Emit (PTE) exceeds 250 tons per year (T/yr) for the haze-causing 

pollutants sulfur dioxide (SO2, 2,770 T/yr), nitrogen oxide (NOx, 1,708 T/yr), and particulate matter (PM, 

55 T/yr), so this emission unit was eligible for inclusion in the subject-to-BART analysis of visibility 

impairment in Class I areas. Following this criteria, the Riley Boiler at the Nampa TASCO plant was 

BART-eligible. 

 

7 A deciview is a haze index derived from calculated light extinction, such that uniform changes in haziness correspond to uniform incremental 

changes in perception across the entire range of conditions—from pristine to highly-impaired. A deciview is the minimum perceptible change 

to the human eye.
T2-2009.0105 Project 60867 Page 29 

1.4 BART Subject 

The source is subject to BART if it is reasonably anticipated to cause or contribute to impairment of 

visibility in a Class I area. According to the Guidelines for Best Available Retrofit Technology (BART) 

Determinations contained in 40 CFR Part 51, Appendix Y, a source is considered to contribute to 

visibility impairment if the modeled 98th percentile change in deciviews (delta deciview)—a measure of 

visibility impairment—is equal to or greater than a contribution threshold of 0.5 deciviews. Although 

Appendix Y does provide for thresholds less than 0.5 deciviews and cumulative impacts, it was 

determined through negotiated rulemaking with industry, federal land management agencies, DEQ and 

the public that the “contribute” threshold for a single source would be established at 0.5 deciviews. (See 

IDAPA 58.01.01.668.02.b.) As suggested in Appendix Y guidance, the determination was made by 

modeling. 

DEQ used the CALPUFF air dispersion modeling system (version 6.112) to determine if the 0.5 deciview 

threshold was exceeded by any of the BART-eligible sources in Idaho. The modeling of BART-eligible 

sources was performed in accordance with the BART Modeling Protocol,

8

 which was jointly developed by 

the states of Idaho, Washington, and Oregon. Refer to the BART Modeling Protocol for details on the 

modeling methodology used in this subject-to-BART analysis. 

The Idaho DEQ, in cooperation with Washington State Department of Ecology and Oregon Department 

of Environmental Quality contracted with Geomatrix Consultants to develop CALMET datasets to use for 

the CALPUFF BART modeling. The CALMET datasets were based on Penn State and National Center of 

Atmospheric Research Mesoscale Model (MM5) runs performed at University of Washington. There 

were two CALMET datasets produced--one using 12km mesh size and another using 4 km mesh size.9

As part of the contract, Geomatrix Consultants ran METSTAT to quantify the quality of the MM5 files 

used as the meteorological dataset in CALMET—used in the CALPUFF modeling. METSTAT pairs the 

MM5 forecasted data with meteorological observations and then performs various statistical 

manipulations and aggregates the results for output.10

Subject-to-BART analysis results for the TASCO Riley Boiler, Nampa are shown in Table 1, which 

highlights the following two threshold values for BART: 

• 8th highest value for each of the years modeled (2003-2005), representing the 98th percentile 

(8/365 = 0.02) cutoff for delta deciviews in each year. 

• 22nd highest value for the entire period from 2003 through 2005, representing the 98th percentile 

(22/1095 = 0.02) cutoff for delta deciviews over three years. 

The determining criterion for both values is a delta deciview of at least 0.5 deciviews. 

 

8 Modeling Protocol for Washington, Oregon and Idaho: Protocol for the Application of the CALPUFF Modeling System Pursuant to the Best 

Available Retrofit Technology (BART) Regulation.

9 Modeling Protocol for BART CALMET datasets, Idaho Oregon and Washington, Geomatrix Consultants Inc., July 12, 2006. 

10 INITIAL METSTAT REPORT CALMET Fields for BART Idaho, Oregon and Washington, Geomatrix Consultants.
T2-2009.0105 Project 60867 Page 30 

These findings were based on the emission rates and other facility parameters provided by TASCO at the 

time of the analysis.11 Based on the CALPUFF modeling analysis, the TASCO Riley Boiler impacted the 

following Class I areas with the 98th percentile highest delta-deciview impact greater than 0.5 over the 

years 2003 to 2005: 

• Eagle Cap Wilderness, Oregon 

• Hells Canyon National Recreation Area, Idaho 

• Strawberry Mountain Wilderness, Oregon 

Table 1 Visibility Impacts Compared to 20% Best Days Natural 

Background Condition 

In conclusion, the CALPUFF model predicted that emissions from the Riley Boiler at the TASCO Nampa 

Factory impacted visibility with the 98th percentile highest delta-deciview impact of more than 0.5 

deciview on the Class I areas of Eagle Cap Wilderness, OR; Strawberry Mountain Wilderness, OR; and 

Hells Canyon Wilderness, ID for the years 2003 to 2005, primarily during the winter time. Eagle Cap 

Wilderness area had the highest number of days (112 days in three years), with a delta-deciview impact 

greater than 0.5. The highest one-year 8th high delta-deciview impact (1.596, year 2005) was found in 

Strawberry Mountain Wilderness. 

The major contributors to visibility deterioration from the Riley Boiler of the TASCO Nampa Factory are 

SO2 and NO2, precursors of sulfate and nitrate aerosols formed in winter under conditions of low 

temperature and high relative humidity. Modeled impacts were greatest when a high-pressure system 

persisted in the area for three to four days or more, the atmosphere was stagnant with poor dispersion, and 

the pollutants transported remained relatively undiluted. 

The subject-to-BART analysis, which followed the BART Modeling Protocol, and additional extensive 

sensitivity analysis have demonstrated that the Riley Boiler of the TASCO Nampa Factory is subject to 

BART. TASCO was notified of the subject-to-BART findings by letter on July 19, 2007. 

 

11 The delta-deciview impact for each of the Class I areas identified in the Subject-to-BART analysis changed slightly in the final determination 

process due to refinements in facility parameters such as stack velocities as provided by TASCO. 

Class I Area 

Delta-deciview impacts greater than contribution threshold (∆dv>0.5) 

2003 2004 2005 2003-2005 

8th

highest(a) 

Total 

days(b) 

8th

highest(a) 

Total 

days(b) 

8th

highest(a) 

Total 

days(b) 

22nd

highest(c) 

Total 

days(d) 

Craters of the Moon 0.161 2 0.224 2 0.153 0 0.196 2 

Eagle Cap Wilderness, OR 0.87 20 1.355 46 1.302 46 1.325 112 

Hells Canyon National 

Recreation Area, ID 0.772 13 1.031 27 0.9 21 0.936 61 

Jarbidge Wilderness, NV 0.151 0 0.198 1 0.201 1 0.179 2 

Sawtooth Wilderness, ID 0.239 2 0.294 4 0.265 0 0.271 6 

Selway-Bitterroot Wilderness, 

ID and MT 0.186 0 0.305 1 0.264 2 0.243 3 

Strawberry Mountain 

Wilderness, OR 0.782 12 0.639 13 1.596 31 0.943 56 

(a) The 8th highest delta-deciview impact for the calendar year. 

(b) Total number of days in the 1-year period that exceeded 0.5 delta deciviews. 

(c) The 22nd highest delta-deciview impact for the 3-year period. 

(d) Total number of days in the 3-year period that exceeded 0.5 delta deciviews.
T2-2009.0105 Project 60867 Page 31 

1.5 BART Determinations 

In accordance with 40 CFR 51.308(e) and IDAPA 58.01.01.668.02.c, Best Available Retrofit Technology 

(BART) means an emission limitation based on the degree of reduction achievable through the 

application of the best system of continuous emission reduction for each pollutant which is emitted by an 

existing stationary facility. The emission limitation must be established, on a case-by-case basis, taking 

into consideration the technology available, the costs of compliance, the energy and non-air quality 

environmental impacts of compliance, any pollution control equipment in use or in existence at the 

source, the remaining useful life of the source, and the degree of improvement in visibility which may 

reasonably be anticipated to result from the use of such technology. (These considerations were included 

in Step 4 of the BART determinations.) 

BART control equipment was initially determined to be the existing baghouse for the control of PM 

emissions, a spray dry flue gas desulfurization (FGD) system for the control of SO2 emissions, and a low 

NOx burner system (LNB) with over-fired air for the control of NOx emissions. BART emission limits, a 

BART alternative to the control NOx, and other BART requirements were incorporated in Tier II 

Operating Permit No. T2-2009.0105, which was issued on September 7, 2010. On October 12, 2010, 

TASCO filed a contested case petition seeking review of the permit. During negotiations to resolve the 

contested case, TASCO provided additional information concerning the feasibility of SCR and over-fired 

air control technologies, requested revision of the initial BART determinations, and proposed a BART 

Alternative to the Spray Dry FGD control technology. The BART determinations in this document have 

been updated based on the revised BART determinations and the approved BART Alternative. The 

specific revisions to BART and to the BART Alternative, along with the supporting technical analyses, 

regulatory review, and a discussion of the revised permit conditions has been provided in the Statement of 

Basis to Tier II Operating Permit No. T2-2009.0105, Project 60867. 

The initial BART determinations made under T2-2009.0105 issued September 7, 2010 have been revised 

based on engineering design information specific to the Riley Boiler retrofit project. A summary of the 

revised BART determinations is provided below. 
T2-2009.0105 Project 60867 Page 32 

Table 2 BART DETERMINATIONS (a)

Pollutant(b)

Step 1 Step 2 Step 3 Step 5 Step 6 

Technologies 

Identified

Technically

Feasible 

(Yes/No) 

Control 

Level 

(lb/hr)

Control 

Ranking

Modeled 

Impairment 

Contribution(c)

(

Days>0.5 Δdv) 

Most 

Effective 

(Yes/No) 

PM 

Wet ESP Yes 12.4 1 --(d) No(d)

Dry ESP Yes 12.4 1 --(d) No(d)

Enhanced Baghouse Yes 12.4 1 --(d) No(d)

Existing Baghouse Yes 12.4 1 --(d) Yes 

SO2

Wet FGD Yes 26 1 43 No(f)

Spray Dry FGD Yes 104 2 51 Yes 

Dry Trona FGD Yes 183 3 58 No 

Dry Lime FGD Yes 235 4 66 No 

Low Sulfur Coal Yes 444 5 90 No 

Base Case(e) Yes 522 6 127 No 

NOx

SNCR No(g) -- -- -- -- 

SCR No(h) -- -- -- -- 

ULNB No(i) -- -- -- -- 

LNB/OFA No(j) -- -- -- -- 

LNB Yes 147 1 60 Yes 

Base Case(e) Yes 374 2 127 No 

(a) This table summarizes each BART determination. The BART determination for NOx has been revised as 

described in this section. 

(b) SO2, NOx, and PM emissions were the visibility-impairing pollutants evaluated.

(c) Δdv = delta deciviews; result is based on changes to visibility at the Eagle Cap Wilderness Area. 

(d) Because the cost of the enhanced baghouse, dry ESP, and wet ESP options were determined to outweigh the 

improvement, BART was selected based on costs of compliance and the pollution control equipment in use 

(existing baghouse). Specific modeling of each PM control scenario was not analyzed. 

(e) The “Base Case” represents continuous coal-fired operation of the Riley Boiler (without controls). 

(f) Wet FGD was not determined to be effective due to non-air quality environmental impacts of compliance 

related to wastewater treatment. 

(g) SNCR was not considered feasible due to concerns that the flue gas would not have adequate residence time to 

achieve reliable control. 

(h) SCR was not considered feasible upstream of the baghouse due to insufficient space necessary to accommodate 

the control device, in addition to concerns regarding catalyst fouling and erosion. SCR was not considered 

feasible downstream of the baghouse due to exhaust gas cooling below the effective operating temperature 

range of the control device. 

(i) ULNB was not considered feasible due to concerns that the boiler firebox would not be large enough to 

accommodate the full burner/flame management system required. 

(j) It was determined that insufficient vertical distance is available between the top burner elevation and the 

furnace nose arch, which is necessary to provide adequate fuel combustion residence time and to accommodate 

the OFA burner/flame management system. 
T2-2009.0105 Project 60867 Page 33 

1.5.1 Particulate BART Control Technology Selection 

In determining the “best” BART control technology for particulate controls on the Riley Boiler, DEQ 

used the five steps as described in EPA Appendix Y. 

Step 1 – Identify all available retrofit emissions control techniques 

In consultation with DEQ, the following particulate control technologies were identified: 

• Existing baghouse 

• Enhanced baghouse 

• Wet Electrostatic Precipitator (Wet ESP) 

• Dry Electrostatic Precipitator (Dry ESP) 

Step 2 – Determine technically feasible options 

In this step, DEQ relied heavily on TASCO engineers to provide the technical feasibility because of plant 

specific requirements and their familiarity with plant operations. DEQ reviewed the information as 

provided below: 

Existing Baghouse - The existing baghouse efficiently reduces PM to very low levels. Measured PM 

emissions are 0.036 lb/MMBTU, well below the previously proposed industrial boiler MACT standard of 

0.07 lb/MMBTU. Control efficiencies for baghouses are reported at 99.0 to 99.9%. For this analysis the 

control efficiency was assumed to be 99% efficient. 

Enhanced Baghouse – The addition of a baghouse module could marginally improve the removal 

efficiency of the existing baghouse. This option would expand the number of modules from four to five 

resulting in reduced baghouse velocities and pressure drop. Adding another baghouse module to the Riley 

Boiler baghouse would be difficult and expensive because of physical space limitations near the existing 

baghouse. PM control efficiency for the additional baghouse was assumed to be 99.0%. 

Wet Electrostatic Precipitator – A Wet ESP consists of a series of collection surfaces in the device that 

removes particulate using an electrical field. The plates are continuously or intermittently cleaned using a 

circulating water system. Control efficiencies for Wet ESP systems have been reported to be 99.0 to 

99.9%. For the purposes of this evaluation, the control efficiency was assumed to be 99%. 

Because of physical space limitations, the installation of the Wet ESP will require demolition and the 

removal of the existing baghouse and installation of the WET ESP in its place. In addition the system will 

produce saturated vapor conditions in the stack during some operation scenarios. A liner will be needed to 

be installed in the existing stack to protect the stack from corrosive conditions. 

Dry Electrostatic Precipitator – A Dry ESP is very similar in operation to the Wet ESP option 

considered above. The particulate to be removed is charged in an electric field and attracted to a 

collection plate. Control efficiencies for Dry ESP system are reported at 99.0 to 99.9% efficient. For this 

evaluation the control efficiency is assumed to be 99.0%. 

This information is summarized in Table 3 below. 
T2-2009.0105 Project 60867 Page 34 

Table 3 Technical Feasibility of PM Controls 

Pollutant Technology Feasibility Reason Not Feasible 

PM 

Existing Baghouse Yes None 

Enhanced Baghouse Yes None 

Wet ESP Yes None 

Dry ESP Yes None 

In conclusion, all particulate technologies identified are technically feasible options for the Riley Boiler. 

Step 3 – Evaluate technically feasible options 

In this step, all of the technically feasible options were ranked in order of effectiveness of each control 

technology identified as technically feasible. Control effectiveness was based on manufacture’s 

performance data, engineering estimates, and demonstrated effectiveness of the technology on the Riley 

Boiler. This data is summarized in Table 4. 

Table 4 Evaluation of PM Controls 

Pollutant Control Option BART 

Baseline 

Maximum 

Emissions

(lb/hr) 

BART 

Baseline 

Annual 

Average 

Emissions 

(T/yr) 

Removal 

Efficiency

(%) 

Expected 

Maximum 

Emissions 

(lb/hr) 

Expected 

Annual 

Emissions

(T/yr) 

PM 

Existing Baghouse 12.4 34.5 99.0% 12.4 34.5 

Enhanced Baghouse 12.4 34.5 99.0% 12.4 34.5 

Dry ESP 12.4 34.5 99.0% 12.4 34.5 

Wet ESP 12.4 34.5 99.0% 12.4 34.5 

Since all control technologies have the same removal efficiency no single control technology is ranked 

higher than the other for emissions removal. 

Step 4 – Impact analysis 

The use of the existing baghouse stands out as the best BART control technology since it will not require 

additional costs. The existing baghouse has the added environmental benefits of not requiring additional 

water or electricity. The benefit of adding an additional bag house is so small the benefits are outweighed 

by the costs. In conclusion, the best BART control technology for particulate is the existing baghouse. 

Step 5 – Determine visibility impacts (improvements) 

Since all control technologies have the same removal efficiency there was no merit in modeling 

specifically for the particulate control scenarios. 

1.5.2 SO2 BART Control Technology Selection 

In determining the “best” BART control technology for sulfur dioxide (SO2) controls on the Riley Boiler, 

DEQ used the five steps as described in EPA Appendix Y. 

Step 1 – Identify all available retrofit emissions control techniques 

• Low sulfur coal (LSC) 

• Wet flue gas desulfurization (FGD) 
T2-2009.0105 Project 60867 Page 35 

• Spray dry FGD 

• Dry lime FGD 

• Dry Trona injection FGD 

Step 2 – Determine technically feasible options 

In this step, DEQ relied heavily on TASCO engineers to provide the technical feasibility because of plant 

specific requirements and their familiarity with plant operations. DEQ reviewed the information as 

provided below: 

Low Sulfur Coal (LSC) – Currently the Nampa plant uses coal that is limited to 1% sulfur by weight to 

comply with the Rules for Control of Air Pollution in Idaho. The average actual percent sulfur for the 

baseline period is approximately 0.75%. This option will look at using 0.6% sulfur with an actual 

reduction of 15%. 

Wet Flue Gas Desulfurization (Wet FGD) – A Wet FGD system typically consists of saturated absorber 

towers located downstream of a particulate control device. The absorbers are usually configured as a 

flooded tray system or spray tower. Flue gas entering the absorber reacts with slurred limestone or slaked 

lime to remove SO2 at the liquid/gas surface boundary. The reaction forms insoluble products or solids 

that can be further treated with forced oxidation to convert to gypsum which is a marketable by product. 

The treated flue gas passes through a mist eliminator system to remove water droplets from the flue gas 

stream. The flue gas leaving the absorber is saturated with water vapor and can present a visible steam 

plume from the stack. 

Wet FGD systems offer one of the highest SO2 removal efficiencies of the available control technologies 

with a removal efficiency of 95% or greater. This is also a technology which EPA is heavily invested and 

supports. The Installation of Wet FGD will require significant modification of the facility. Key sitespecific considerations are as follows: 

Wet FGD results in saturated stack conditions during periods of Riley only operation (Shared stack 

operation during beet campaign with the B&W Boiler is not anticipated to result in saturated stack 

conditions). The resulting condensation formed in the stack is anticipated to have very low pH values that 

will require installation of a stack liner to protect the integrity of the stack. Condensed vapors will need to 

be neutralized. Installation of a stack liner is estimated at $2,000,000. 

Since Wet FGD is a wet process, it will generate a wastewater stream. The actual wet process is 

expected to be contained within the Wet FGD system with a slip stream discharged for wastewater 

treatment. 

Spray Dryer Flue Gas Desulfurization (Spray Dry FGD) – Spray Dry FGD consists of a spray dryer 

reactor to be located between the boiler exhaust and upstream of a particulate removal device (usually an 

electrostatic precipitator or baghouse). The reactor consists of a spray dryer absorber tower and support 

equipment. Flue gas is introduced into a vessel and contacts an atomized spray pattern of lime slurry 

generated by either a set of dual fluid nozzles or a rotary atomizer. The reaction to remove SOx occurs on 

lime slurry droplets as they are evaporated from the heat of the flue gas to form a dry particle. 

Because the exit temperature of the reactor must be maintained at a set temperature above the adiabatic 

saturation temperature of the flue gas (controlled by slurry feed rate), the product removed from the 

system is in dry form. The emission control efficiency of the reactor increases as the exit flue gas 

temperature approaches the adiabatic saturation temperature of the flue gas. The approach temperature is 

typically set at 30-40◦

 F above adiabatic saturation temperature (corresponding to removal efficiencies of 

90-80% respectively). Recycling fly ash into the lime slurry feed mixture may increase emission control 

efficiency depending on the chemical characteristics of the ash. 
T2-2009.0105 Project 60867 Page 36 

For the purposes of this evaluation a control efficiency of 80% will be assumed (a higher temperature 

40◦

F was assumed to protect the baghouse). 

A spray Dry FGD retrofit project would require modifications to the TASCO Nampa facility. The 

particulate loading to the baghouse would increase as a result of installing a spray dryer. In addition to the 

ash entering the reactor with flue gas, the spent lime would contribute to overall particulate loading. 

Approximately 60% of the formed solids are predicted to drop out in the reactor while 40% would be 

carried to the baghouse for removal. The increase in particulate loading would likely require an additional 

baghouse module. 

The permittee has documented concerns regarding the affordability and environmental impacts of Spray 

Dry FGD; however, for the purposes of this BART determination, Spray Dry FGD was considered 

feasible. With regard to affordability, TASCO has provided revised annualized operating cost estimates 

related to the installation, maintenance, and operation of this technology. With regard to non-air quality 

environmental impacts, TASCO has identified concerns related to the disposal of byproducts generated in 

the operation of this technology, and concerns related to the marketability of boiler fly ash for reuse 

activities.12

Dry Lime Injection Flue Gas Desulfurization (Dry Lime FGD) – Dry Lime FGD consists of injecting 

pulverized lime (milled to less than 10 microns) into the flue gas upstream of the baghouse. The emission 

control efficiency of a Dry Lime FGD is critically dependent upon: 

Particle Size – The smaller the particle size, the greater the surface area for reaction. Lime is milled to 

less than 10 microns using a ball mill. The smaller size of the particles is also important to avoid 

downstream depositing of dust in the equipment and ductwork. 

Temperatures – Reaction rates increase with increased temperatures of the flue gas. 

Flue Gas Mixing – Good lime particle mixing with the flue gas is important to provide uniform 

distribution of lime reactant in the baghouse. 

The control efficiency for DLIFGD is reported to vary between 45 to 55%. For the purposes of this 

evaluation, the control efficiency is assumed at 55%. 

Dry Trona Injection Flue Gas Desulfurization (Dry Trona FGD) – Trona is a naturally occurring 

source of sodium carbonate that is available from mines in Wyoming. Similar to Dry Lime FGD, Dry 

Trona FGD consists of injecting pulverized Trona (milled to less than 10 microns) into the flue gas 

downstream of the existing baghouse and upstream of a new baghouse. The injection system requirements 

and technical characteristics are very similar to the Dry Lime FGD system discussed above. 

The control efficiency for Dry Trona FGD is reported to range between 55 to 65%. For the purposes of 

this evaluation, the control efficiency is assumed at 65%. 

This information is summarized in Table 5, below. 

 

12 Section 1.5.2 of Attachment #2 to “BART Alternative Submittal & Tier II Application”, TASCO, May 4, 2011; and “FW: Attached 2 files for 

DEQ Emailing...”, TASCO, October 27, 2011. 
T2-2009.0105 Project 60867 Page 37 

Table 5 Technical Feasibility of SO2 Controls 

Pollutant Technology Feasibility Reason Not Feasible 

SO2

Low Sulfur Coal Yes None 

Wet FGD Yes None 

Spray Dry FGD Yes None 

Dry Lime FGD Yes None 

Dry Trona FGD Yes None 

Step 3 – Evaluate technically feasible options 

Based on the control efficiency rates listed above, TASCO determined the baseline maximum hourly 

emission rates, baseline average annual emission rate, anticipated control efficiency of emission controls, 

expected maximum hourly emission rate and expected annual emission rates. This data is summarized in 

Table 6, below. 

Table 6 Evaluation of SO2 Controls 

Pollutant Control Option BART 

Baseline 

Maximum 

Emissions 

(lb/hr) 

BART 

Baseline 

Annual 

Average 

Emissions 

(T/yr) 

Removal 

Efficiency 

(%) 

Expected 

Maximum 

Emissions 

(lb/hr) 

Expected 

Annual 

Emissions 

(T/yr) 

SO2

Low Sulfur Coal 522 1457 15% 444 1238 

Dry Lime FGD 522 1457 55% 235 655 

Dry Trona FGD 522 1457 65% 183 510 

Spray Dry FGD 522 1457 80% 104 291 

Wet FGD 522 1457 95% 26 73 

Step 4 – Impact analysis 

TASCO did a cost evaluation for each of the control technologies analyzed. A complete cost evaluation 

can be found in Appendix D & E of “Best Available Retrofit Technology (BART) Determination Analysis, 

2009. These findings were based on EPA fact sheets, engineering and performance test data, and 

information and discussions with equipment vendors. Table 7 summarizes those results. 

Table 7 Impacts of SO2 Controls 

Control Scenario Baseline 

Emissions 

(T/yr) 

Removal 

Efficiency 

(%) 

Annual 

Emissions 

Reduction 

(T/yr) 

Total 

Reduction

(T/yr) 

Total 

Capital 

Cost 

($x1,000) 

Total 

Annual 

Cost 

($x1,000) 

Cost 

($/T) 

Incremental

Cost 

($/T) 

Low Sulfur Coal 1,457 15% 219 219 0 $1,024 $4,685 $0 

Dry Lime FGD 1,457 55% 801 801 $11,281 $2,687 $3,353 $2,857 

Dry Trona FGD 1,457 65% 947 947 $11,281 $2,442 $2,557 -$1,678 

Spray Dry FGD 1,457 80% 1,166 1,166 $12,970 $2,521 $2,163 $360 

Wet FGD 1,457 95% 1,384 1,384 $22,006 $4,034 $3,353 $6,940 
T2-2009.0105 Project 60867 Page 38 

After reviewing TASCO’s evaluation, DEQ has concerns with the installation of Wet FGD. In reviewing 

TASCO’s BART Determination Analysis for the Riley Boiler, and specifically looking into wastewater 

treatment processes associated with Wet Flue Gas Desulfurization (Wet FGD), TASCO’s submittal does 

not present technical specifications or much detail regarding the wastewater treatment process. It’s not 

immediately clear that the costs of the wastewater treatment process are included in the estimates 

presented in their submittal; however, there appear to be many vendors who provide wastewater treatment 

processes as part of a Wet FGD project, so it is assumed that the cost of wastewater management is 

contained within the cost estimates provided for the Wet FGD process itself. 

There are several variables that make it very difficult to speculate about the volume of wastewater that 

might be produced, or any constituent concentrations in wastewater from the process. The source and 

composition of (1) the coal fired in the boiler, and (2) the limestone used in the Wet FGD process will 

largely dictate the constituents and constituent concentrations in the wastewater, but there are likely to be 

significant concentrations of chlorides, fluorides, sulfate, arsenic, mercury, selenium, boron, cadmium, 

zinc, iron, aluminum, and inert fines that will require some sort of treatment prior to any discharge. 

Because the wastewater stream is saturated with calcium sulfate (i.e., gypsum), scaling is a major issue 

with operation and maintenance of process units and piping. The wastewater will also be hot, somewhat 

acidic, and will have high levels of total dissolved solids. There’s also information available that indicates 

the presence of nitrates in the wastewater. Many of these constituents have primary or secondary quality 

standards in the Ground Water Quality Rule, and any proposal involving land application would almost 

certainly require impact assessments and/or permitting before DEQ would allow them to go forward. 

It is entirely possible to design treatment units to manage and remove the majority of these constituents 

from the wastewater. The gypsum is a marketable product that would likely be precipitated out of solution 

and recovered as a commodity. The metals can also be precipitated, although many of these are regulated 

as hazardous wastes at relatively low concentrations (i.e., the hazardous waste program would probably 

want to be involved with management of these solids). There are also other processes that can be used to 

reduce residual levels of dissolved solids and nitrates in the final effluent, although it’s important to note 

that more treatment generally means more cost and more oversight required. The potential volume and 

quality of the final, treated effluent is very difficult to speculate about without knowing more about the 

wastewater that will be produced by the Wet FGD process and the treatment processes that will be used to 

manage that wastewater. 

With respect to TASCO’s existing wastewater treatment system, the facility is presently treating most of 

its wastewater on site in an aerated lagoon and sending it to the municipal treatment plant operated by the 

City of Nampa during off-peak hours. To continue with this operation, a very high degree of wastewater 

treatment will be required, and substantial improvements to the existing treatment process will almost 

certainly be required. It would be expected that the city might have concerns about any potential increase 

in the volume of wastewater discharged to its system. This could mean that the City would need to 

expand its treatment system or that TASCO might look to land application to manage the new wastewater 

stream. 

TASCO does still have a wastewater land application permit with DEQ, but the facility has only utilized 

land application for a very small fraction of its total wastewater load in recent years. The company land 

applied ~12MG in the 2005 season (6% of total WW generated), ~5MG in the 2006 season (3% of total 

WW generated), ~1MG in the 2007 season (1% of total WW generated), and no wastewater was land 

applied in the 2008 season. As a result of this reduction in land applied wastewaters, we have seen 

improving trends in its ground water monitoring wells. Historically, there were issues with nitrates, 

chlorides, and total dissolved solids concentrations in ground water around the site. While some 

exceedances of the associated ground water quality standards still exists, most monitoring wells have 

shown improving trends in ground water quality in recent years, and the DEQ Boise Regional Office is 

encouraging TASCO to continue to minimize wastewater land application at this time. 
T2-2009.0105 Project 60867 Page 39 

Although wastewater treatment processes are available to produce a high-quality effluent that could be 

successfully land applied under a permit from DEQ, these processes will be fairly complex and 

expensive, and will likely require dedicated staff to operate and maintain. Additionally, the reduction in 

wastewater land application in recent years has improved historic issues with ground water quality 

that have generally been associated with TASCO’s operation, so any proposal to increase loading 

rates from a new source of wastewater would require a complete permit application that includes a ground 

water impact assessment showing no adverse impacts to existing ground water quality. We would issue a 

permit with enforceable limits and comprehensive monitoring/reporting requirements to ensure protection 

of ground water quality, assuming that the application and impact assessments can be technically verified 

and approved. 

Step 5 – Determine visibility impacts (improvements) 

Table 8 below summarizes the modeling results for SO2 controls. 

Table 8 Visibility Improvement of SO2 Controls - 

Change in Visibility Impacts Compared to 20% Best Days Natural 

Background Condition 

Since TASCO believed running the CALPUFF modeling for the various control technology scenarios 

would be costly, DEQ performed the CALPUFF modeling in-house and invited TASCO to have a 

contractor review the modeling if deemed necessary. Because each scenario can change the stack 

velocities and temperatures, it was important that DEQ work closely with TASCO. DEQ worked very 

closely with TASCO facility engineers to determine the modeling inputs for each of the scenarios. 

Eagle Cap Wilderness, OR 

Delta-deciview impacts greater than contribution threshold (∆dv>0.5) 

2003 2004 2005 2003-2005 

8th

highest(a) 

Total 

days(b) 

8th

highest(a) 

Total 

days(b) 

8th

highest(a) 

Total 

days(b) 

22nd

highest(c) 

Total 

days(d) 

Base Riley Boiler Plus Pulp 

Dryer Full Operation Scenario 

(wzi10469) 

0.956 23 1.454 49 1.388 55 1.399 127 

Base Riley Boiler Scenario 

(wzi10471) 0.721 15 1.086 41 1.109 41 1.086 97 

SO2 Control Scenario 1 

Lower Sulfur Coal (wzi10475) 0.682 15 1.016 39 1.028 36 1.014 90 

SO2 Control Scenario 2 

Dry Lime Injection (wzi10476) 0.586 9 0.814 28 0.806 29 0.806 66 

SO2 Control Scenario 3 

Dry Trona Injection (wzi10477) 0.565 9 0.764 24 0.739 25 0.761 58 

SO2 Control Scenario 4 

Spray Dryer FGD (wzi10478) 0.527 9 0.703 22 0.707 20 0.686 51 

SO2 Control Scenario 5 

Wet FGD (wzi10479) 0.499 7 0.647 19 0.645 17 0.638 43 

a) The 8th highest delta-deciview impact for the calendar year. 

b) Total number of days in the 1-year period that exceeded 0.5 delta deciviews. 

c) The 22nd highest delta-deciview impact for the 3-year period. 

d) Total number of days in the 3-year period that exceeded 0.5 delta deciviews. 
T2-2009.0105 Project 60867 Page 40 

Conclusion - As part of the impact analysis, non-air quality environmental concerns are to be taken into 

consideration. Although Wet FGD has a 15% greater removal efficiency over the next closest control of 

Spray Dry FGD, the potential for reversing the current trend of improvements to ground water due to 

TASCO land applying outweigh the environmental benefits. TASCO is currently sending pretreated 

wastewater to the City of Nampa. There is a high likelihood that an increase in TASCO’s waste stream 

would be greater than the city can currently handle. This would more than likely lead to TASCO 

requesting to increase land application of waste water. For these reasons, DEQ will not be including Wet 

FGD in the control options even though the technology is technically feasible for improvements in air 

quality and visibility. 

1.5.3 NOx BART Control Technology Selection 

In determining the “best” BART control technology for nitrogen oxides (NOx ) controls on the Riley 

Boiler, DEQ used the five steps as described in EPA Appendix Y. 

Step 1 – Identify all available retrofit emissions control techniques 

DEQ in consultation with TASCO identified the following control technologies appropriate for boilers: 

• Low NOx Burners (LNB) 

• Low NOx Burners with Over-fired Air (LNB/OFA) 

• Ultra Low NOx Burners (ULNB) 

• Selective Catalytic Reduction (SCR) 

• Selective Non-Catalytic Reduction (SNCR) 

Step 2 - Determine technically feasible options 

In this step, DEQ relied heavily on TASCO engineers to provide the technical feasibility because of plant 

specific requirements and their familiarity with plant operations. DEQ reviewed the information as 

provided below: 

Low NOx Burners - LNBs incorporate staged fuel or staged combustion air to control the flame 

temperature of the boiler. Several low NOx burner systems are available with different levels of cost and 

performance capabilities. A guaranteed NOx removal efficiency of 60.7% for the Riley Boiler was 

provided by the vendor. 

Low NOx Burners with Over-Fired Air – These systems inject a portion of the combustion air 

downstream of the fuel burner system to lower flame temperatures and the formation of NOx. Over-fired 

air as a standalone retrofit technology can be difficult to control causing combustion issues with 

pulverized coal boiler, including water wall corrosion and reduced boiler efficiencies. When combined 

with a low NOx burner and reasonable combustion air control, NOx removal efficiencies can approach 

65%. 

In the initial BART determination (as described in the Statement of Basis to Tier II Operating Permit No. 

T2-2009.0105, issued September 7, 2010), it was determined based on technical analyses that low NOx

burners with over fired air were technically feasible. However, based on the results of an engineering 

design review of the Riley Boiler, it has subsequently been determined that over fired air (OFA) is not 

technically feasible for retrofit on the Riley Boiler.13 It was determined that insufficient vertical distance 

is available between the top burner elevation and the furnace nose arch, which is necessary to provide 

adequate fuel combustion residence time and to accommodate the OFA burner/flame management 

system. 

 

13 “Feasibility Study to Determine Best Suited Combustion Technology to meet BART, TASCO Purchase Order #65276, Nampa Sugar Mill –

RPI Contract #100477,” Riley Power Inc., May 19, 2011.
T2-2009.0105 Project 60867 Page 41 

Ultra Low NOx Burners – These systems are upgraded LNB designs which involve further control and 

staging of combustion air and fuel. ULNB was determined not technically feasible on the Riley Boiler. 

The boiler’s existing firebox is not large enough to accept the full burner/flame management system 

required by the ULNB. 

Selective Catalytic Reduction – SCR systems reduce NOx by injecting ammonia and urea into the flue 

gas before it passes through a catalytic grid to reduce the NOx to N2. This technology requires the flue gas 

exhaust from the Riley baghouse to be heated to 500◦

 C before injecting ammonia or urea and passing the 

hot gases through the selective catalytic grid. After treatment, heat is recovered in a heat exchanger to 

minimize operating costs to reheat the flue gas. This technology is capable of reducing NOx emissions by 

70% to 90%. For the purposes of this evaluation a control efficiency of 90% was assumed. 

In the initial BART determination (as described in the Statement of Basis to Tier II Operating Permit No. 

T2-2009.0105, issued September 7, 2010), it was determined that SCR was technically feasible. However, 

based on the results of an engineering design review of the Riley Boiler, it has subsequently been 

determined that SCR is not technically feasible for retrofit on the Riley Boiler.14 SCR was not considered 

feasible upstream of the baghouse due to insufficient space necessary to accommodate the control device, 

in addition to concerns regarding catalyst fouling and erosion. SCR was not considered feasible 

downstream of the baghouse due to exhaust gas cooling below the effective operating temperature range 

of the control device. 

Selective Non-Catalytic Reduction (SNCR) – SNCR consists of injecting ammonia or urea into boiler 

flue gases in a narrow temperature zone of 1550 to 1950◦

 F. To achieve these temperatures, the injection 

point must be located between the Riley Boiler economizer and the air pre-heater. The process relies on 

good gas mixing in the narrow high temperature zone to reduce NOx to N2 as the flue gas moves through 

the ductwork. Boiler load swings can lead to temperature changes at the injection that can significantly 

reduce removal efficiencies. In addition, injection points can lead to “ammonia slip” or the condition 

where unreacted ammonia passes through downstream equipment, including the baghouse and discharges 

from the stack. The gas path for the Riley Boiler lacks the necessary residence time to reliably remove the 

NOx. The results of upsets could lead to “ammonia slip.” 

This information is summarized in Table 9, below. 

Table 9 Technical Feasibility of NOx Controls 

Pollutant Technology Feasibility Reason Not Feasible 

NOx

Low NOx Burners Yes None 

Low NOx with 

Over-Fired Air No 

Insufficient vertical distance 

between the top burner elevation 

and the furnace nose arch to 

support OFA system. 

Ultra NOx Low Burners No 

Boiler Firebox is not large enough 

to support the flame management 

system. 

Selective Catalytic 

Reduction No Catalyst fouling and erosion, or exhaust temperature too low 

Selective Non-Catalytic 

Reduction No 

Boiler gas path does not have 

adequate residence time for 

reliable control. 

 

14 “New Information on Use of Selective Catalytic Reduction as Riley Boiler BART,” TASCO, May 20, 2011; and “Response to July 18, 2011 

E-mail Questions,” August 5, 2011. 
T2-2009.0105 Project 60867 Page 42 

Step 3 – Evaluate technically feasible options 

Based on the control efficiency rates listed above, TASCO determined the baseline maximum hourly 

emission rates, baseline average annual emission rate, anticipated control efficiency of emission controls, 

expected maximum hourly emission rate and expected annual emission rates. This data is summarized in 

Table 10, below. 

Table 10 Evaluation of NOx Controls 

Pollutant Control Option 

BART 

Baseline 

Maximum 

Emissions 

(lb/hr) 

BART 

Baseline 

Annual 

Average 

Emissions 

(T/yr) 

Removal 

Efficiency

(%) 

Expected 

Maximum 

Emissions 

(lb/hr) 

Expected 

Annual 

Emissions

(T/yr) 

NOx Low NOx Burners 374 1,042 60.7% 147 410 

Step 4 – Impact Analysis 

The use of low NOx burners was the top feasible control technology for minimizing NOx emissions. 

Control options were not eliminated based on energy, environmental, or economic impacts. 

Step 5 – Determine visibility impacts (improvements) 

Since TASCO believed running the CALPUFF modeling for the various control technology scenarios 

would be costly, DEQ performed the CALPUFF modeling in-house and invited TASCO to have a 

contractor review the modeling if deemed necessary. Because each scenario can change the stack 

velocities and temperatures, it was important that DEQ work closely with TASCO. DEQ worked very 

closely with TASCO facility engineers to determine the modeling inputs for each of the scenarios. 

Table 11 Visibility Improvement of NOx Controls – 

Compared to 20% Best Days Natural Background Condition 

Eagle Cap Wilderness, OR 

Delta-deciview impacts greater than contribution threshold (∆dv>0.5) 

2003 2004 2005 2003-2005 

8th

highest(a) 

Total 

days(b) 

8th

highest(a) 

Total 

days(b) 

8th

highest(a) 

Total 

days(b) 

22nd

highest(c) 

Total 

days(d) 

Base Riley Boiler Scenario 

(wzl10471) 0.721 15 1.086 41 1.109 41 1.086 97 

NOx Control Scenario 1 – LNB 

(wzl10496) 0.467 7 0.766 25 0.823 28 0.760 60 

(a) The 8th highest delta-deciview impact for the calendar year. 

(b) Total number of days in the 1-year period that exceeded 0.5 delta deciviews. 

(c) The 22nd highest delta-deciview impact for the 3-year period. 

(d) Total number of days in the 3-year period that exceeded 0.5 delta deciviews.
T2-2009.0105 Project 60867 Page 43 

1.5.4 SO2 BART Alternative 

In addition to the control technologies reviewed, TASCO has proposed a BART Alternative to provide 

greater reductions in visibility-impairing emissions and associated modeled visibility impacts than what 

would be expected with the use of Spray Dry FGD. 

BART Terminology 

• In this document the initial BART is defined to mean the initial BART determinations for PM, SO2, 

and NOx that were determined under Tier II Operating Permit No. T2-2009.0105, issued on 

September 7, 2010. 

• In this document the revised BART is defined to mean the BART determination for NOx, which is 

being revised by this permitting action. (The BART for PM and SO2 have not been revised and 

remain the same as what was determined under Tier II Operating Permit No. T2-2009.0105, issued on 

September 7, 2010.) 

BART Alternative Terminology 

• In this document the “BART Alternative” scenario is defined to mean the combination of BART for 

PM (Riley Boiler with the existing baghouse), revised BART for NOx (Riley Boiler with low NOx

burners), and the BART Alternative to the control of SO2 (B&W Boilers #1 and #2 with low NOx

burners and the three Pulp Dryers shut down). 

• In this document the “BART” scenario is defined to mean the combination of BART for PM (Riley 

Boiler with the existing baghouse), revised BART for NOx (Riley Boiler with low NOx burners), and 

BART for SO2 (Riley Boiler with Spray Dry FGD), with the addition of the sources affected by the 

“BART Alternative” scenario: B&W Boilers #1 and #2 and three Pulp Dryers in full operation. 

In this document the “Alternative Benchmark” scenario is defined to mean the Riley Boiler with the 

existing baghouse, B&W Boilers #1 and #2, and the three Pulp Dryers. This scenario allows comparison 

of both the “BART” and “BART Alternative” scenarios against the same benchmark that includes all of 

the affected sources. 

Evaluate emission reductions 

TASCO has provided information relating to operational changes at the facility after the 

regional haze base years of 2000-2004. In 2006, TASCO installed a new pulp steam dryer 

system which better utilized current steam production and allowed three coal-fired pulp dryers 

to shut down. The pulp drying typically occurs during the fall and winter months when 

TASCO’s emissions show the highest modeled impact on the 20% worst days. A summary of 

the emission reductions attributed to the shutdown of the pulp dryers is provided in Table 13. 

As part of the impact and visibility improvements TASCO requested that DEQ evaluate the 

visibility improvements resulting from the pulp dryer shutdowns and determine that the 

reductions from the new steam dryers could be used as part of an alternative to BART. Also as 

part of the BART Alternative, TASCO has proposed the installation and operation of low NOx 

burners on both of the B&W Boilers. These steps have been proposed as the BART Alternative 

to the control of sulfur dioxide (SO2) emissions. 
T2-2009.0105 Project 60867 Page 44 

Table 12 “BART” Emission Reductions (a)

Pollutant(a) Emission Source 

“BART” 

Emissions 

lb/hr(b)

“Alternative 

Benchmark” 

Emissions 

lb/hr(c)

Net Emission 

Reductions 

lb/hr 

 Riley Boiler 12.4 12.4 0.0 

PM B&W Boilers #1 & #2 56.9 56.9 0.0 

 North, South, & Center Pulp Dryers 92.7 92.7 0.0 

 Riley Boiler 104.0 522.3 418.3 

SO2 B&W Boilers #1 & #2 435.0 435.0 0.0 

 North, South, & Center Pulp Dryers 17.9 17.9 0.0 

 Riley Boiler 147.0 373.8 226.8 

NOx B&W Boilers #1 & #2 227.0 227.0 0.0 

 North, South, & Center Pulp Dryers 191.2 191.2 0.0 

Total 1,284.1 1,929.2 645.1 

(a) SO2, NOx, and PM emissions were the visibility-impairing pollutants evaluated. 

(b) “BART” scenario includes the Riley Boiler with BART for the control of PM (with the existing baghouse), with BART for 

the control of NOx (LNB), and with BART for the control of SO2 (Spray Dry FGD); full operation of the B&W Boilers 

(without LNB), and full operation of the three pulp dryers. This control scenario represents BART as described in the BART 

Determinations section. 

(c) “Alternative Benchmark” includes the Riley Boiler (with the existing baghouse), full operation of the B&W Boilers (without 

LNB), and full operation of the three pulp dryers. Estimated emission reductions attributable to shutdown of the pulp dryers 

were provided in Table 7 of the BART determination submitted February 9, 2009. 
T2-2009.0105 Project 60867 Page 45 

 Table 13 “BART Alternative” Emission Reductions

Pollutant(a) Emission Source 

“BART 

Alternative” 

Emissions 

lb/hr(b)

“Alternative 

Benchmark” 

Emissions 

lb/hr(c)

Net Emission 

Reductions 

lb/hr 

PM 

Riley Boiler 12.4 12.4 0.0 

B&W Boilers #1 & #2 56.9 56.9 0.0 

North, South, & Center Pulp Dryers 0.0 92.7 92.7 

SO2

Riley Boiler 522.3 522.3 0.0 

B&W Boilers #1 & #2 435.0 435.0 0.0 

North, South, & Center Pulp Dryers 0.0 17.9 17.9 

NOx

Riley Boiler 147.0 373.8 226.8 

B&W Boilers #1 & #2 103.0 227.0 124.0 

North, South, & Center Pulp Dryers 0.0 191.2 191.2 

Total 1,276.6 1,929.2 652.6 

(a) SO2, NOx, and PM emissions were the visibility-impairing pollutants evaluated. 

(b) “BART Alternative” includes the Riley Boiler with BART for the control of PM (with the existing 

baghouse) and with BART for the control of NOx (LNB), the B&W Boilers with the BART Alternative 

to the control of SO2 (Coal-Firing LNB for each boiler), and shutdown of the three coal-firing pulp 

dryers. This control scenario represents the control equipment described in Permit Condition 3.2. 

(c) “Alternative Benchmark” includes the Riley Boiler (with the existing baghouse), full operation of the 

B&W Boilers (without LNB), and full operation of the three pulp dryers. Estimated emission reductions 

attributable to shutdown of the pulp dryers were provided in Table 7 of the BART determination 

submitted February 9, 2009 

For evaluation of the “BART Alternative” scenario emission reductions, the “BART Alternative” 

scenario was compared to the “BART” scenario in Table 13 and Table 12, respectively. As provided in 

these tables, the “BART Alternative” scenario is expected to result in greater emission reductions in 

regional haze pollutants (PM, SO2, and NOx) than the “BART” scenario. 

Determine visibility impacts (improvements) 

Because each scenario can change the stack velocities and temperatures, DEQ utilized stack parameters 

and emission rate estimates provided by TASCO. As described above, for comparison each of the 

emission sources involved in the “BART Alternative” scenario were also included in the other scenarios 

evaluated. 
T2-2009.0105 Project 60867 Page 46 

Table 14 Visibility Improvement of “BART Alternative” Scenario –

Eagle Cap (a)

Control Scenario 

22nd Highest 

Impact 

(Δdv) 

Impairment 

Contribution 

(Days >0.5 Δdv)(b)

“BART”(d)

Riley Boiler w/ Baghouse (“Alternative 

Benchmark”)(c

)

B&W Boilers #1 & #2 – full operation 

North, South, Center Pulp Dryers – full operation 

2.201 195 

Riley Boiler w/ Baghouse, Spray Dry FGD, LNB (f)

B&W Boilers #1 & #2 – full operation 

North, South, Center Pulp Dryers – full operation 

1.512 149 

Net Visibility Improvement 0.689 46 

“BART 

Alternative”(e) 

Riley Boiler w/ Baghouse (“Alternative 

Benchmark”)(c) 

B&W Boilers #1 & #2 – full operation 

North, South, Center Pulp Dryers – full operation 

2.201 195 

Riley Boiler w/ Baghouse, LNB (f)

B&W Boilers #1 & #2 w/ LNB (f)

North, South, Center Pulp Dryers – shutdown 

1.411 126 

Net Visibility Improvement 0.790 69 

Difference in Improvement 0.101 23 

(a) This table compares the modeled visibility impacts for the combined BART determinations and the 

“BART Alternative” to the “Alternative Benchmark” operating scenario. SO2, NOx, and PM emissions 

were the visibility-impairing pollutants evaluated. 

(b) Δdv = delta deciviews; result is based on changes to visibility at the Eagle Cap Wilderness Area. 

(c) “Alternative Benchmark” includes the Riley Boiler (with the existing baghouse), full operation of the 

B&W Boilers (without LNB), and full operation of the three pulp dryers. Estimated emission reductions 

attributable to shutdown of the pulp dryers were provided in Table 7 of the BART determination 

submitted February 9, 2009. 

(d) “BART” includes the Riley Boiler with BART for the control of PM, NOx, and SO2 (with the existing 

baghouse, LNB, and Spray Dry FGD), full operation of the B&W Boilers (without LNB), and full 

operation of the three coal-firing pulp dryers. 

(e) “BART Alternative” includes the Riley Boiler with BART for the control of PM (with the existing 

baghouse) and with BART for the control of NOx (LNB), the B&W Boilers with the BART Alternative 

to the control of SO2 (Coal-Firing LNB for each boiler), and shutdown of the three coal-firing pulp 

dryers. This control scenario represents the control equipment described in Permit Condition 3.2. 

(f)The NOx control efficiency of the Riley Boiler LNBs = 60.7%, and for the B&W Boilers LNBs = 55%. 

The “BART Alternative” scenario was determined to achieve greater improvement in visibility 

impairment in Class I areas than the “BART” scenario. Refer to Appendix B for additional information 

regarding these modeling scenarios. 

Based on CALPUFF modeling, the highest modeled visibility impacts were predicted to occur in the 

Eagle Cap Wilderness Area. The combination of BART for PM, BART for NOx, and the BART 

Alternative to SO2 was predicted to result in a minimum reduction or elimination of 23 days of visibility 

impairment and an improvement in the 22nd highest visibility impact of 0.101 dv at the Eagle Cap 

Wilderness, when compared to the revised BART (as summarized in Table 8). 
T2-2009.0105 Project 60867 Page 47 

Table 15 “BART Alternative” Scenario Visibility Improvement

Class I Area(a)

“BART”(b) “BART 

Alternative”(c) 

Difference in 

Improvements(d)

22nd 

Highest

Days 

>0.5 Δdv

22nd 

Highest

Days 

>0.5 Δdv 

22nd 

Highest 

Days 

>0.5 Δdv

Eagle Cap Wilderness, OR 1.512 149 1.411 126 0.101 23 

Craters of the Moon National Monument, ID 0.267 4 0.245 3 0.022 1 

Hells Canyon National Recreation Area, ID 1.092 87 1.059 80 0.033 7 

Jarbidge Wilderness, NV 0.256 5 0.234 5 0.022 0 

Sawtooth Wilderness, ID 0.319 6 0.307 6 0.012 0 

Selway-Bitterroot Wilderness, ID 0.281 3 0.298 4 -0.017 -1 

Strawberry Mountain Wilderness, OR 1.076 62 0.917 51 0.159 11 

Total Number of Days 316 275 41 

(a) This table compares the modeled visibility impacts for the combined BART determinations and the 

“BART Alternative” to the “Alternative Benchmark” operating scenario. SO2, NOx, and PM emissions 

were the visibility-impairing pollutants evaluated. The Class I areas evaluated were the seven areas 

within a 300 km radius from the Riley Boiler. SO2, NOx, and PM emissions were the visibilityimpairing pollutants evaluated. 

(b) “BART” includes the Riley Boiler with BART for the control of PM, NOx, and SO2 (with the existing 

baghouse, LNB, and Spray Dry FGD), full operation of the B&W Boilers (without LNB), and full 

operation of the three coal-firing pulp dryers. 

(c) “BART Alternative” includes the Riley Boiler with BART for the control of PM (with the existing 

baghouse) and with BART for the control of NOx (LNB), the B&W Boilers with the BART Alternative 

to the control of SO2 (Coal-Firing LNB for each boiler), and shutdown of the three coal-firing pulp 

dryers. This control scenario represents the control equipment described in Permit Condition 3.2. 

(d) Values reported in this column represent the relative difference or improvement of the “BART 

Alternative” over the “BART” control scenario. 

The “BART Alternative” scenario is expected to achieve greater reasonable progress than the “BART” 

scenario because this scenario results in greater emissions reductions and in greater visibility 

improvements. DEQ is therefore approving the combination of the pulp dryer shutdowns and the 

installation and operation of low NOx burners on the B&W Boilers as an alternative to BART for the 

control of SO2 emissions (i.e., as an alternative to the installation and operation of Spray Dry FGD). 

1.6 Natural Gas-Fired Operation 

The Riley Boiler was designed to combust coal and/or natural gas fuels. Discussion and supporting 

information are provided below which support the requirement to operate Riley Boiler BART control 

equipment only when firing coal in the Riley Boiler. Modeling of fuel operating scenarios was completed 

using the same protocol as described in Appendix B (this protocol was also used in the BART modeling 

analyses for Tier II Operating Permit No. T2-2009.0105, issued on September 7, 2010). 

Comparing the fuel operating scenarios in the table below, coal combustion resulted in higher estimated 

emissions of visibility-impairing pollutants than natural gas combustion, even when taking into account 

the emissions reductions resulting from BART control equipment. 

Comparing the fuel operating scenarios in the tables below, coal combustion also resulted in higher 

predicted visibility impacts than natural gas combustion, even when taking into account the emissions 

reductions resulting from BART control equipment. 
T2-2009.0105 Project 60867 Page 48 

Table 16 Visibility-Impairing Emissions by Fuel Type 

Fuel / Control Scenario PM 

lb/hr(a)

SO2 

lb/hr(a)

NOx 

lb/hr(a)

Coal-Fired Riley Boiler 12.4 522 374 

Coal-Fired Riley Boiler with BART 12.4 104 147 

Natural Gas-Fired Riley Boiler 7.7 0.2 99 

Table 17 Visibility Impacts by Fuel Type – Eagle Cap (a) 

Fuel / Control Scenario 

22nd Highest 

Impact 

(Δdv) 

Impairment 

Contribution 

(Days >0.5 Δdv)(b)

Coal-Fired Riley Boiler w/ Baghouse 1.086 97 

Coal-Fired Riley Boiler w/ Baghouse, 

Spray Dry FGD, LNB 0.343 5 

Natural Gas-Fired Riley Boiler 0.166 0 

(a) This table summarizes modeled visibility impacts for the Riley Boiler with the existing baghouse and 

coal-fired, the Riley Boiler with BART controls and coal-fired, and for the Riley Boiler natural 

gas-fired (without controls) operating scenarios; detailed technical information can be found in 

Appendix A and Appendix B. SO2, NOx, and PM emissions were the visibility-impairing pollutants 

evaluated. 

(b) Δdv = delta deciviews; result is based on changes to visibility at the Eagle Cap Wilderness Area. 

Table 18 Visibility Impacts for Natural Gas (a)

Class I Area(a)

Natural Gas 

22nd 

Highest

Days 

>0.5 Δdv 

Eagle Cap Wilderness, OR 0.166 0 

Craters of the Moon National Monument, ID 0.028 0 

Hells Canyon National Recreation Area, ID 0.106 0 

Jarbidge Wilderness, NV 0.029 0 

Sawtooth Wilderness, ID 0.034 0 

Selway-Bitterroot Wilderness, ID 0.028 0 

Strawberry Mountain Wilderness, OR 0.099 0 

Total Number of Days 0 

(a) This table summarizes modeled visibility impacts for the natural gas-firing operating scenario for the 

Riley Boiler; detailed technical information can be found in Appendix A and Appendix B. SO2, NOx, 

and PM emissions were the visibility-impairing pollutants evaluated. The Class I areas evaluated were 

the seven areas within a 300 km radius from the Riley Boiler. SO2, NOx, and PM emissions were the 

visibility-impairing pollutants evaluated. 

As provided, the emissions and modeled visibility impacts when firing 100% natural gas were predicted 

to be significantly lower than when firing coal in the Riley Boiler, even when accounting for the use of 
T2-2009.0105 Project 60867 Page 49 

BART controls. It was therefore considered reasonable to determine the “base case” or “no control” 

options as BART for the control of PM, SO2, and NOx emissions when combusting 100% natural gas. 

1.7 Conclusion 

In conclusion, DEQ approves the “BART Alternative” control scenario – the combination of the existing 

baghouse and LNB on the Riley Boiler, LNB on both of the B&W Boilers, and shutdown of the three 

coal-fired pulp dryers – as the “best” of BART technologies. The “BART Alternative” scenario is 

expected to result in greater emission reductions in regional haze pollutants (PM, SO2, and NOx) than the 

“BART” scenario, and the visibility improvement at all Class I areas was predicted to be greater for the 

“BART Alternative” scenario – with the reduction or elimination of 41 additional days expected when 

compared to the “BART” scenario. 

BART and BART Alternative emission limits have been established in Permit Conditions 3.4 and 3.5 of 

Tier II Operating Permit No. T2-2009.0105 Project 60867. BART and BART Alternative operating, 

monitoring, compliance testing, recordkeeping, notification, and reporting requirements have been 

established in Permit Conditions 3.3, 3.6, 3.7, 3.8, 3.10, 3.11, 3.13, 3.14, 3.15, 3.16, and 4.1. 
T2-2009.0105 Project 60867 Page 50 

APPENDIX B – BART ALTERNATIVE VISIBILITY MODELING 
BART Alternative Visibility Modeling 

for the Riley Boiler at 

TASCO – Nampa Factory 

State of Idaho 

Department of Environmental Quality 

1410 North Hilton 

Boise, ID 83706 

October 19, 2011 
2 

This page intentionally left blank for correct double-sided printing. 
3 

Executive Summary

The Amalgamated Sugar Company LLC (TASCO) has requested a revision to the BART 

determination for the coal-fired Riley Boiler at their Nampa Factory, and has proposed a BART 

Alternative. The revised BART includes Spray Dry Flue Gas Desulfurization (Spray Dry FGD) 

for sulfur dioxide (SO2) control, Low NOx burners (LNB) for nitrogen oxides (NOx) control, and 

a baghouse for particulate matter (PM) control. The proposed BART Alternative replaces the 

Spray Dry FGD with a) LNB controls on two (non-BART) Babcock and Wilcox (B&W) boilers, 

and b) credits SO2, NOx and PM emission reductions from shutting down 3 pulp dryers. This 

report describes new modeling to assess the resulting visibility changes at Class I areas within 

300 km of the facility. 

The modeling was completed in accordance with the three-state BART Modeling 

Protocol which underwent an extensive review and approval process and formed the basis for 

much of the BART modeling conducted in the Pacific Northwest. In order to compare the BART 

Alternative impacts with the selected BART control scheme on the same basis, both scenarios 

were modeled with emissions from all the sources included in the BART Alternative; i.e. the 

pulp dryers and the non-BART B&W Boilers. In this report, the term “BART” (in quotation 

marks) denotes the selected BART technology for the Riley boiler (LNB) along with emissions 

from the other emission sources (B&W Boilers and pulp dryers) affected by the alternative in 

their pre-BART condition. 

Model results for the “BART Alternative” scenario indicate that visibility improves an 

additional 0.159 ∆dv on the 22nd highest day at Strawberry Mountain Wilderness and 0.101∆dv 

at Eagle Cap in comparison to the “BART” scenario. The number of days above 0.5 ∆dv is 

reduced by 11 more days at Strawberry Mountain and 23 more days at Eagle Cap, with a total 

reduction of 41 more days at all the Class I areas combined over the three-year modeling period. 

Although the “BART Alternative” scenario reduces the largest visibility impacts during 

the winter when both modeled and monitored regional haze impacts were highest, the shift from 

SO2 control to additional NOx control will also result in a slightly greater visibility impairment in 

the best visibility months of March – June when sulfate dominates the relatively clear air at the 

Starkey IMPROVE site, representing Eagle Cap and Strawberry Mountain wilderness areas. 

However, this impairment from the BART Alternative in the non-winter months is small in 

comparison to the visibility benefits projected in the winter months, and it is clear that the 

proposed BART Alternative produces greater reductions on more high-impact days than the 

“BART” scenario, and is therefore a preferred approach for reducing regional haze. 

In addition to the greater visibility improvements, the BART Alternative provides greater 

ozone mitigation benefits by more than doubling the NOx reductions over those of the “BART” 

scenario (from 2.7 to 6.5 tons per day). DEQ photochemical modeling indicates that this will 

rank amongst the top ozone mitigation measures being evaluated in our efforts to mitigate ozone 

and avoid an ozone non-attainment designation. This is important to the State of Idaho because 

of the health and economic disadvantages that non-attainment status may bring and the potential 

restrictions that the region could incur in the areas of industrial growth, transportation 

improvements, and agricultural and prescribed burning. 
4 

Introduction

The Amalgamated Sugar Company LLC (TASCO) at Nampa, Idaho has requested revision of 

the initial Best Available Retrofit Technology (BART) determination for NOx and approval of a 

BART Alternative to control visibility-impairing pollutant emissions from the Riley Boiler at 

their Nampa Factory. The BART determinations (as revised) include Spray Dry Flue Gas 

Desulfurization (Spray Dry FGD) for sulfur dioxide (SO2) control, Low NOx burners (LNB) for 

nitrogen oxides (NOx) control, and a baghouse for particulate matter (PM) control. The proposed 

BART Alternative replaces the Spray Dry FGD with a) LNB controls on two (non-BART) 

Babcock and Wilcox (B&W) boilers, and b) SO2, NOx and PM emission reduction credits for 

shutting down 3 pulp dryers. Modeling results documenting the visibility impacts of the revised 

BART and the proposed BART Alternative along with an Alternative Benchmark scenario are 

described in this report. The benchmark scenario provides a common pre-BART basis against 

which the regional haze impacts of both the BART and BART Alternative scenarios can be 

compared. 

Control Scenarios Modeled

The revised BART and BART Alternative determinations are discussed in the Statement of Basis 

prepared in conjunction with this permitting action. This report addresses the relative differences 

in regional haze impacts for the modeled control scenarios and the measured patterns of aerosol 

extinction and visibility degradation at the Class I areas where the impacts occur. The modeling 

summarized in this memo involves the following scenarios, with computer runs identified by run 

identification numbers: 

“BART” Modeling Scenario 

This scenario, (Run ID wzI10495) includes Riley Boiler BART emissions along with benchmark 

emissions of sources affected by the BART Alternative. Note, BART (without quotation marks) 

refers to the BART determination control technology involving only the Riley Boiler, while 

“BART” (with quotations) refers to this modeling scenario, which includes the other affected 

emission sources: 

• Riley Boiler with existing baghouse, Spray Dry FGD, and LNB 

• B&W Boilers #1 and #2 (benchmark emissions of sources affected by the BART 

Alternative) 

• Pulp Dryers, full operation (benchmark emissions of sources affected by the BART 

Alternative) 

“BART Alternative” Modeling Scenario 

This scenario (Run ID wzI10493) includes the BART NOx controls on the Riley boiler, along 

with Low-NOx burners on two other non-BART Babcock and Wilcox (B&W) boilers. The B&W 

NOx controls along with credits for shutting down three pulp dryers, is proposed by TASCO as 

an alternative for SO2 control using Spray-Dry FGD. 

• Riley Boiler with existing baghouse and LNB 

• B&W Boilers #1 and #2 with LNB 

• Pulp Dryers shut down (North, Center, South) 
5 

“Alternative Benchmark” Modeling Scenario 

This scenario (Run ID wzI10492) includes benchmark or pre-BART emissions from the Riley 

Boiler and the other sources affected by the BART Alternative scenario. It provides a common 

benchmark for comparison of the “BART” and “BART Alternative” scenarios on an equivalent 

basis: 

• Riley Boiler with existing baghouse 

• B&W Boilers #1 and #2, full operation 

• Pulp Dryers, full operation 

Methods

The dispersion and visibility modeling described in this report is based on stack parameters and 

emission rates provided by TASCO. The location and stack parameters for all sources involved 

in the modeling of all scenarios are presented in Table 1 and the emission rates for the same 

sources are presented in Table 2. 

DEQ used the CALPUFF (v 6.112) air dispersion modeling system to determine the 

delta-deciview (Δdv) visibility impacts, the number of days per year above the 0.5 Δdv 

threshold, and the number of days per the three–year period above the 0.5 Δdv threshold. The 

modeling was performed in accordance with the BART Modeling Protocol1, which was jointly 

developed by the states of Idaho, Washington, and Oregon, and which has undergone public, 

Federal Land Manager (FLM) and EPA review and approval. This is the identical protocol used 

for DEQ’s Subject-to-BART modeling completed in support of the initial BART Tier II operating 

permit.2 The meteorological and CALPUFF computational domains for the Nampa Factory are 

shown in Figure 1 along with the source location (red dot) and the Class I areas (red with black 

outlines) within 300 km of the source. Class I areas included in this analysis and identifying 

abbreviations used in Figure 1 are shown in Table 1. The Class I areas are primarily wilderness 

areas managed by the United States Forest Service, with the exception of Craters of the Moon 

Wilderness Area, managed by the National Park Service. None of the Class I areas within 300 

miles of Nampa are managed by the United States Fish and Wildlife Service. 

Table 1 Class I Areas Included in Modeling Analysis 

Eagle Cap Wilderness, OR (eaca2) Sawtooth Wilderness Area, ID (sawt2) 

Strawberry Mountain Wilderness, OR (stmo2) Selway-Bitterroot Wilderness Area, ID/MT (selw4) 

Hells Canyon Wilderness Area, ID/OR (heca2) Craters of the Moon Wilderness Area, ID (crmowild) 

Jarbidge Wilderness Area, ID/NV (jarb2) 

The meteorological inputs to CALPUFF for the analysis were the same data set used previously 

for the Subject-to-BART analysis and the BART Determination modeling. The meteorological 

inputs were prepared by Geomatrix, Inc. (now Environ International) under the direction of 

representatives from the states of Washington, Idaho, and Oregon, using Fifth Generation 

 1 Modeling Protocol for Washington, Oregon and Idaho: Protocol for the Application of the CALPUFF 

Modeling System Pursuant to the Best Available Retrofit Technology (BART) Regulation. 

http://www.deq.idaho.gov/air/prog_issues/pollutants/haze_BART_modeling_protocol.pdf 

 

2 Tier II Operating Permit No. T2-2009.0105, issued September 7, 2010. 
6 

Mesoscale Meteorological Model (MM5) data generated by the University of Washington. The 

result was a CALMET output file for the three-year period from 2003 through 2005 that covers 

the entire Pacific Northwest at a 4-km resolution.3

Primary particulate matter from these sources is a relatively small contributor to regional haze. 

Nevertheless, detailed particulate matter speciation was estimated using National Park Service 

particulate speciation spreadsheets for dry bottom pulverized coal-fired boilers with and without 

Spray Dry FGD.4

The resulting speciated emissions of direct particulate matter emissions can be seen in Table 3. 

Note, the sulfate (SO4) in Table 3 is shown as (and input to CALPUFF) as pounds per hour SO4. 

However, when totaling the aerosol species under “Total PM10” it is converted to a 

stoichiometric equivalent mass of ammonium sulfate ((NH4)2SO4), since this is the form it 

assumes in the ambient air, and the mass that is measured in a source test. 

Figure 1 Meteorological (black) CALPUFF (pink) domains with Class I 

areas within 300-km radius (blue) of TASCO Nampa Factory (red dot). 

 3 CALMET Statistical Report, CALMET Fields for BART Modeling, Idaho, Oregon and Washington, 

Geomatrix Consultants, Inc., Lynnwood WA 98036, July 2006. 

 

4 National Park Service, Particulate Matter Speciation, Coal-Fired Boiler PM10, 

http://www.nature.nps.gov/air/Permits/ect/ectCoalFiredBoiler.cfm

 
Table 2 Source Locations and Stack Parameters 

Unit BART Control Equipment Easting (m) Northing (m) Elevation (m) Stack Height (m) Stack Diameter (m) Stack Exit Temperature (K) 

Stack Parameters for “Alternative Benchmark” Scenario (Run ID wzI10492) 

Riley Boiler Existing Baghouse 534.406 4828.031 753 74.7 3.35 445.9 

B&W 1&2 (n/a) 534.406 4828.031 753 74.7 3.35 445.9 

South Pulp Dryer (n/a) 534.413 4828.087 753 23.5 3.017 348.5 

Center Pulp Dryer (n/a) 534.413 4828.099 753 21 3.017 353.4 

North Pulp Dryer (n/a) 534.415 4828.106 753 27.7 2.13 346.4 

Stack Parameters for “BART” Scenario (with affected sources) (Run ID wzI10495) 

Riley Boiler FGD + LNB (60.7% Control) 534.406 4828.031 753 74.7 3.35 403.8 

B&W 1&2 LNB (Each 55% Control) 534.406 4828.031 753 74.7 3.35 445.9 

South Pulp Dryer (n/a) 534.413 4828.087 753 23.5 3.017 348.5 

Center Pulp Dryer (n/a) 534.413 4828.099 753 21 3.017 353.4 

North Pulp Dryer (n/a) 534.415 4828.106 753 27.7 2.13 346.4 

Stack Parameters for “BART Alternative” Scenario (Run ID wzI10493) 

Riley Boiler LNB (60.7% Control) 534.406 4828.031 753 74.7 3.35 440.0 

B&W 1&2 LNB (Each 55% Control) 534.406 4828.031 753 74.7 3.35 440.0 
Table 3 Emission Rates used in CALPUFF Modeling (a)

Unit Control Equipment SO2 lb/hr SO4 lb/hr NOX lb/hr HNO3 lb/hr NO3 lb/hr PMC lb/hr PMF lb/hr 

Emissions from all Sources in Alternative Benchmark Scenario (Run ID wzI10492) 

Riley Boiler Existing Baghouse 522.3 6.7 373.8 0 0 0.5 0.5 

B&W 1&2 (c) (n/a) 435.0 30.7 227 0 0 2.1 2.1 

South Pulp Dryer (n/a) 7.5 0.01 80.2 0 0.01 0 31.3 

Center Pulp Dryer (n/a) 7.5 0.01 80.2 0 0.01 0 31.3 

North Pulp Dryer (n/a) 2.9 0.01 30.8 0 0.01 0 14.2 

“Alternative Benchmark” Scenario Totals: 975.1 37.43 792 0 0.03 2.6 79.4 Emissions from all sources in “BART” Scenario (with affected sources) (Run ID wzI10495) 

Riley Boiler Selected BART (FGD + LNB) 104 2.8 147 0 0 0.5 0.5 

B&W 1&2 (c) Existing Control, B&W Boilers 1&2 435 30.7 227 0 0 2.1 2.1 

South Pulp Dryer (n/a) 7.5 0.01 80.2 0 0.01 0 31.3 

Center Pulp 

Dryer (n/a) 7.5 0.01 80.2 0 0.01 0 31.3 

North Pulp Dryer (n/a) 2.9 0.01 30.8 0 0.01 0 14.2 

“BART” Scenario Totals: 556.8 33.5 565.2 0 0.03 2.6 79.4 “BART Alternative” Emissions after Implementation (Pulp Dryers shut down) (Run ID wzI10493) 

Riley Boiler LNB (60.7% Control) 522.3 6.7 147 0 0 0.5 0.5 

B&W 1&2 (c) LNB (Each 55% Control) 435 30.7 103 0 0 2.1 2.1 

“BART Alternative” Scenario Totals: 957.3 37.4 250 0 0 2.6 2.6 

(a) Pollutant emissions for sulfur dioxide (SO2), Nitrogen oxides (NOx = NO + NO2), nitric acid (HNO3) and speciated particulate matter species (SO4

(NO3), coarse particulate matter 2.5 – 10μm in aerodynamic diameter (PMC), fine particulate matter < 2.5μm in diameter (PMF), elemental carbon 

aerosol (SOA), and total particulate matter 10μm and less in aerodynamic diameter (PM10). 

(b) Total PM10 is not used directly in the model but represents total of PM species for information only. SO4 is added into total PM10 as ammonium su

(132/96)). 

(c) B&W Boilers 1&2 refer to two (non-BART) Babcock &Wilcox Boilers, Units 1 and 2 that operate at the Nampa Factory in addition to the Riley B
9 

BART Alternative Modeling Results

“BART” and “BART Alternative” Model Detailed Results 

Detailed model results showing regional haze impacts at all seven Class I areas within 300 km of 

the source are summarized for the “BART” scenario in Table 4, and for the “BART Alternative” 

scenario in Table 5. It is important to emphasize that both the “BART” and the “BART 

Alternative” results shown in Table 4 and Table 5 include all emission sources involved in the 

BART determinations and in the BART Alternative, so that comparison can be made on an 

equivalent basis, with the full precursor mix accounted for from all affected sources. Overall 

(three-year) results for all scenarios are summarized in Table 6 to facilitate comparisons. 

In its 2005 BART guidelines, EPA determined that a source whose 98th percentile daily average 

haze impact (haze index) is greater than 0.5 deciview above natural background is considered to 

contribute to regional haze. Impacts above 1.0 deciview are considered to cause regional haze 

impacts. By selecting the 98th percentile, the top 7 days in any year, or top 21 days in three years, 

EPA intended to minimize the effects of extreme meteorology and conservative assumptions. 

Table 4 and Table 5 highlight the two averaging periods generally used in BART modeling 

analyses: 

• 8th highest Δdv value for each of the years modeled (2003-2005), representing the 

98th percentile (8/365 = 0.02) cutoff for Δdv in the each year. In addition the 

numbers of days in each year above the 0.5 Δdv threshold are shown. 

• 22nd highest value for the entire period from 2003 through 2005, representing the 98th 

percentile (22/1095 = 0.02) cutoff for Δdv over three years. In addition the numbers 

of days in all three years above the 0.5 Δdv threshold are shown. 

The pre-BART, 3-year modeled impacts shown in Table 4 and Table 5 indicate that the 

“Alternative Benchmark” scenario does not “contribute” (>0.5Δdv) to regional haze at Craters of 

the Moon, Jarbidge, Sawtooth and Selway-Bitterroot wilderness areas, the Class I areas east of 

Nampa. On the other hand, this benchmark scenario does “cause” regional haze impacts 

(>1.0∆dv) at the 3 Class I areas east of the facility, i.e. Eagle Cap, Strawberry Mountain and 

Hells Canyon wilderness areas. In addition, Table 4 and Table 5 show that the meteorology in 

2004 resulted in the highest modeled impacts and most days above the 0.5Δdv threshold at all 

sites. Figure 2 clearly shows that the model-predicted visibility impacts at Eagle Cap (due to the 

existing Riley boiler) were highest in the winter season, and that January 2004 had the highest 

predicted impacts during the three-year model period. In addition, from day 60 through day 280, 

only 3 days in 3 years appear to exceed the 0.5Δdv threshold for a 98th percentile day 

“contributing” to a haze at a Class I area. Since this frequency (3 days in 660) represents only 

0.45% of the non-winter days, it suggests that the Riley boiler does not “contribute” to the haze 

impacts, at the level defined by EPA, outside of the October – February period. However it does 

“cause” haze impacts (>1 Δdv) at the western-most 3 Class I areas during the winter time when 

non-carbon impacts are the greatest. 

Comparison to Measured Extinction at IMPROVE monitoring sites 

To gain confidence in model results, it is useful to examine how model results behave in 

comparison to monitored aerosol extinction at IMPROVE monitoring sites. For this purpose, it is 

useful to understand how light extinction is determined from aerosol species concentrations and 
10 

how extinction relates to the “haze index” or changes in visibility relative to the background 

visibility in terms of delta deciviews (Δdv). Light extinction (bext) is computed from aerosol 

species concentrations and reported in units of reciprocal megameters (Mm-1) according to the 

equation: 

bext = 3 f(RH) [(NH4)2SO4] + 3 f(RH) [NH4NO3] + 4[OC] + 1[Soil] + 0.6[Coarse Mass] + 10[EC] + bRay 

 (Eqn 1) 

Equation 1 applies to either measured or modeled aerosol concentrations, where: 

 f(RH) are monthly averaged relative humidity coefficients, specifically tabulated for each 

Class I area each month, 

bRay is Raleigh scattering due to air molecules, Mm -1

[(NH4)2SO4] is the ammonium sulfate concentration formed from SOs, μg/m3

[NH4NO3] is the ammonium nitrate concentration formed from NOx, μg/m3

[OC] is the organic carbon concentration, μg/m3

 (equivalent to “SOA” in Table 3) 

[Soil] is the fine geologic particulate matter, μg/m3

 (equivalent to “PMF” in Table 3), 

[Coarse Mass] is the coarse particulate matter, μg/m3

 (equivalent to “PMC” in Table 3), and 

[EC] is the elemental carbon, μg/m3

Light extinction is not measured directly at IMPROVE sites, but is calculated based on aerosol 

measurements of the species in Equation 1. In this document, the terms “measured extinction” or 

“monitored extinction” refer to light extinction calculated by Equation 1 based on direct aerosol 

filter measurements and reported by the IMPROVE monitoring program. When source emissions 

are modeled to estimate light extinction impacts resulting from those emissions, the resulting 

bext (source) is compared to background extinction, bext (bkg), to predict the haze index in terms of 

delta-deciviews: 

Δdv = 10 ln [ ( bext (bkg) + bext (source) ) / ( bext (bkg) ) ] (Eqn 2) 

A time series view of 2004 light extinction based on measured aerosol concentrations and 

modeled pre-BART Riley Boiler concentrations at Hells Canyon (Figure 3) again suggests that 

the winter months experience the highest visibility impacts and that the January 2004 stagnation 

episode produced the greatest monitored and modeled aerosol extinction over the 3 year period. 

The similarity in monitor-based and modeled annual patterns shown in Figure 3 suggests that the 

model captures the seasonal variation in haze conditions well and that both the observed and 

modeled visibility impacts are highest in the winter time and much lower from March to midOctober. 

Summary of “BART” results. 

The visibility improvement for the “BART” scenario, in comparison to the Alternative 

Benchmark scenario (Table 4) shows a reduction in the three-year 22nd highest Δdv of 0.689 Δdv 

at Eagle Cap, the most impacted area, and 0.119 Δdv at Jarbidge Wilderness, the least impacted 

area. Similarly, the number of days in three years above the 0.5 Δdv threshold at Eagle Cap 

decreases from 195 days to 149 days, a 46 day reduction, while Jarbidge is projected to see only 

a three day reduction. The sum of days in 3 years above 0.5 Δdv at all seven Class I areas 

decreases from 455 days for the Alternative Benchmark scenario to 316 days for the “BART” 

scenario, a reduction of 139 days overall. 
11 

Summary of “BART Alternative” Results 

The visibility improvement for the “BART Alternative” scenario in comparison to the 

“Alternative Benchmark” scenario (Table 5) shows a reduction in the three-year 22nd highest Δdv 

at Eagle Cap from 2.201 to 1.411Δdv, a visibility improvement of 0.790 Δdv. The number of 

days in the three-year period above the 0.5 Δdv threshold at Eagle Cap decreases from 195 days 

to 126 days, a 69 day reduction, while Jarbidge is projected to see a three day reduction, identical 

to the “BART” scenario. The sum of days above 0.5 Δdv at all the Class I areas combined drops 

from 455 for the “Alternative Benchmark” scenario to 275 days for the “BART Alternative” 

scenario, a reduction of 180 days. A very small visibility degradation appears at 

Selway-Bitterroot Wilderness Area.
 Table 4 Summary of Visibility Impacts for TASCO-Nampa "BART" Scenario 

Class I 

Area Operating Scenario 

Change in Visibility Compared Against 20% Best Day

Δdv larger than 0.5 from one year period 

2003 2004 2005 

8th high 

Δdv(a) Days > 0.5

Δdv(b) 8th high 

Δdv(a) Days > 0.5

Δdv(b) 8th high 

Δdv(a) D

0.5

Eagle Cap 

Wilderness, 

OR 

“Alternative Benchmark” (wzI10492) 1.611 48 2.212 72 2.178 

“BART” (e) (wzI10495) 1.103 30 1.551 55 1.509 

Visibility Improvement (f) 0.508 18 0.661 17 0.669 

Craters of 

the Moon 

NM 

Wilderness, 

ID 

“Alternative Benchmark” (wzI10492) 0.336 1 0.407 6 0.318 

“BART” (e) (wzI10495) 0.239 0 0.273 3 0.233 

Visibility Improvement (f) 0.097 1 0.134 3 0.085 

Hells 

Canyon 

Wilderness 

ID/OR “Alternative Benchmark” (wzI10492) 1.269 27 1.693 51 1.515 

“BART” (e) (wzI10495) 0.884 20 1.163 32 1.049 

Visibility Improvement (f) 0.385 7 0.530 19 0.466 

Jarbidge 

Wilderness, 

NV 

“Alternative Benchmark” (wzI10492) 0.275 1 0.379 3 0.420 

“BART” (e) (wzI10495) 0.192 1 0.256 2 0.278 

Visibility Improvement (f) 0.083 0 0.123 1 0.142 

Sawtooth 

Wilderness, 

ID 

“Alternative Benchmark” (wzI10492) 0.470 7 0.519 8 0.435 

“BART” (e) (wzI10495) 0.340 2 0.349 4 0.293 

Visibility Improvement (f) 0.130 5 0.170 4 0.142 

SelwayBitterroot 

Wilderness, 

ID 

“Alternative Benchmark” (wzI10492) 0.317 0 0.587 8 0.492 

“BART” (e) (wzI10495) 0.212 0 0.387 1 0.327 

Visibility Improvement (f) 0.105 0 0.200 7 0.165 

Strawberry 

Mountain 

Wilderness, 

OR 

“Alternative Benchmark” (wzI10492) 1.419 18 0.882 22 2.308 

“BART” (e) (wzI10495) 0.987 13 0.644 15 1.677 

Visibility Improvement (f) 0.432 5 0.238 7 0.631 

All Areas Reduction in Total Days > 

Δdv, all Class I Areas Combined 2003: 36 2004: 58 2005: 

(a) The 8th highest delta-deciview impact for the calendar year. (b) Total number of days in 1 year that exceeded 0.5 delta deciviews. (c) The 22nd highest delta-deciview impact for the three-year period. 

(d) Total number of days in the three-year period that exceed 0.5 delta deciviews. 

(e) “BART” (with quotations) refers to the Riley Boiler with Spray Dry FGD and LNB controls plus the pre-BART emissions of the B&W boilers 1&2 

results may be compared to the “BART Alternative” and the “Alternative Benchmark” scenarios on an equivalent basis. 

(f) Visibility improvement is calculated as the difference between the “Alternative Benchmark” scenario and the “BART” scenario modeled values. 
Table 5 Summary of Visibility Impacts for TASCO-Nampa “BART Alternative” Scenario 

Class I Area Operating Scenario 

Change in Visibility Compared Against 20% Best Da

Δdv larger than 0.5 from one year period 

2003 2004 2005 

8th high 

Δdv(a) Days > 0.5

Δdv(b) 8th high 

Δdv(a) Days > 0.5

Δdv(b) 8th high 

Δdv(a) Day

0.5

Δ

Eagle Cap 

Wilderness, 

OR 

“Alternative Benchmark” (wzI10492) 1.611 48 2.212 72 2.178 7

“BART Alternative” (wzI10493) 0.921 22 1.434 49 1.469 5

Visibility Improvement (e) 0.690 26 0.778 23 0.709 2

Craters of 

the Moon 

NM 

Wilderness, 

ID 

“Alternative Benchmark” (wzI10492) 0.336 1 0.407 6 0.318 3 

“BART Alternative” (wzI10493) 0.230 0 0.260 2 0.200 1 

Visibility Improvement (e) 0.106 1 0.147 4 0.118 2 

Hells 

Canyon 

Wilderness 

ID/OR “Alternative Benchmark” (wzI10492) 1.269 27 1.693 51 1.515 5

“BART Alternative” (wzI10493) 0.758 17 1.173 31 1.044 3

Visibility Improvement (e) 0.511 10 0.520 20 0.471 1

Jarbidge 

Wilderness, 

NV 

“Alternative Benchmark” (wzI10492) 0.275 1 0.379 3 0.420 4 

“BART Alternative” (wzI10493) 0.193 1 0.252 2 0.251 2 

Visibility Improvement (e) 0.082 0 0.127 1 0.169 2 

Sawtooth 

Wilderness, 

ID 

“Alternative Benchmark” (wzI10492) 0.470 7 0.519 8 0.435 3 

“BART Alternative” (wzI10493) 0.268 1 0.340 4 0.278 1 

Visibility Improvement (e) 0.202 6 0.179 4 0.157 2 

SelwayBitterroot 

Wilderness, 

ID 

“Alternative Benchmark” (wzI10492) 0.317 0 0.587 8 0.492 7 

“BART Alternative” (wzI10493) 0.206 0 0.383 2 0.329 2 

Visibility Improvement (e) 0.111 0 0.204 6 0.163 5 

Strawberry 

Mountain 

Wilderness, 

OR 

“Alternative Benchmark” (wzI10492) 1.419 18 0.882 22 2.308 4

“BART Alternative” (wzI10493) 0.737 10 0.540 11 1.487 3

Visibility Improvement (e) 0.682 8 0.342 11 0.821 1

All Areas Reduction in Total Days > 0.5 dv, all Class I Areas Combined 2003: 51 2004: 69 2005: 6

(a) The 8th highest delta-deciview impact for the calendar year. (b) Total number of days in 1 year that exceeded 0.5 delta deciviews. (c) The 22nd highest delta-deciview impact for the three-year period. 

(d) Total number of days in the three-year period that exceed 0.5 delta deciviews. 

(e) Visibility improvement is calculated as the difference between the “Alternative Benchmark” scenario and the “BART Alternative” scenario modele
Table 6 Summary of scenarios and net visibility improvement from “BART Alternative” in comparison to “BART” scenario 

Class I Area 

“Alternative 

Benchmark”(a)

(wzI10492) 

“BART”(b)

(wzI10495) 

“BART Alternative”(c)

(wzI10493)

Ne

(“BA

22nd 

Highest (d) Total Days >0.5Δdv (e) 22nd Highest (d) Total Days (e) >0.5Δdv 22nd Highest (d) Total Days >0.5Δdv (e) Δdv 

22n

Eagle Cap Wilderness, OR 2.201 195 1.512 149 1.411 126 

Craters of the Moon Wilderness, ID 0.393 10 0.267 4 0.245 3 

Hells Canyon Wilderness, ID/OR 1.582 129 1.092 87 1.059 80 

Jarbidge Wilderness, NV 0.375 8 0.256 5 0.234 5 Sawtooth Wilderness, ID 0.47 18 0.319 6 0.307 6 

Selway-Bitterroot Wilderness, ID 0.439 15 0.281 3 0.298 4 -

Strawberry Mountain Wilderness, OR 1.462 80 1.076 62 0.917 51 

Total Number of Days with Improved Visibility: 455 316 275 

(a) Includes pre-BART emissions of all sources involved in BART and the BART Alternative: Riley Boiler, B&W Boilers 1&2 and pulp dryers. 

(b) Includes all sources involved in BART and the BART Alternative under “BART” operations: Riley Boiler (LNB + SD-FGD), B&W Boilers 1&2, t

(c) Includes all sources involved in BART and the BART Alternative under BART Alternative operations: Riley Boiler (LNB), B&W Boilers 1&2 (LN

down. 

(d) The 22nd highest Δdv value for the three-year period (2003 – 2005). 

(e) Total number of days in the three-year period that exceed 0.5 Δdv. 
15 

Figure 2 Modeled seasonal variation in delta-deciview impacts due to TASCO's Riley Boiler 

(existing control), over the three model years 

Figure 3 Comparison of modeled extinction due to the Riley Boiler (existing control) (left axis) 

and measured total aerosol extinction at the Hells Canyon IMPROVE site (right axis). 
16 

Other Considerations

In preliminary discussion of the proposed changes with FLMs, questions were raised about 

finding sufficient alternative controls at the facility to include in a BART alternative and about 

the effect on visibility impacts that would result from reducing the level of SO2 control and 

replacing it with increased NOx control. As a result, DEQ reassessed the selection of emission 

sources included in BART Alternative modeling and evaluated whether inordinate visibility 

impacts were projected to shift impacts to other Class I areas or to other seasons. This section 

describes those evaluations. 

Availability of other Emission Sources for Inclusion in the BART Alternative 

Alternatives to the control of SO2 emissions by Spray Dry-FGD were proposed by TASCO, in 

light of both the high cost and the environmental impairment due to the waste stream produced 

by Spray Dry FGD. During the evaluation, the FLMs suggested that in seeking alternative 

emission reductions, DEQ should examine the entire facility-wide emission inventory to 

determine if other emission sources, in addition to the two B&W Boilers and the Pulp Dryers 

could be considered for inclusion as part of a BART Alternative. DEQ examined the primary 

regional haze precursors in the facility-wide emission inventory for the TASCO Nampa Factory 

in the most recent statewide point source emissions inventory (2010). The pulp dryers had been 

shut down by 2010 and did not appear in this inventory, but were included as reductions in the 

BART Alternative. The facility-wide emissions of NOx, SO2 and PM10 are shown in Figure 4, 

Figure 5, and Figure 6 (respectively). These charts indicate that the Riley Boiler and the B&W 

boiler Units 1 & 2 together comprise 97% of the total facility-wide NOx emissions, 99% of the 

SO2 emissions and 98% of PM10 emissions. This review confirmed that the emission sources 

contributing the greatest share of visibility-impairing emissions from the Nampa Factory are 

included in the proposed BART Alternative and that no other significant visibility-impairing 

pollutant emission sources are available at the facility for inclusion in the BART Alternative 

control plan. 

Effects on Visibility from Replacing SO2 Control with Additional NOx Control 

The proposed BART Alternative replaces the Spray-Dry Flue Gas Desulfurization SO2 control 

on the Riley Boiler with additional NOx controls on the two Babcock & Wilcox boilers and with 

additional NOx, SO2 and PM10 reductions achieved by shutting down the 3 pulp dryers. Visibility 

reductions resulting from this proposed change would potentially be limited if the highest 

regional haze impacts were primarily caused by sulfate, or if sulfate was a predominant 

contributor in any particular season during which the facility contributes to significant visibility 

degradation. To assess the importance of nitrate, sulfate and primary particulate matter to the 

regional haze levels, DEQ investigated the monitored impacts at all the Class I areas and seasons 

most impacted by the TASCO Nampa Factory. IMPROVE aerosol monitoring data5 for the 

modeling period are presented in this section to provide a multi-year evaluation of pre-BART 

visibility conditions and their seasonal variation. 

 5 Western Regional Air Partnership (WRAP), WRAP-TSS Web site, September 2011. 

http://vista.cira.colostate.edu/TSS/Results/Monitoring.aspx 
17 

Most Impacted Areas 

The modeled visibility impacts from sources at the TASCO Nampa plant were highest at the 

Class I areas at the west end of the Snake River Valley: Eagle Cap, Strawberry Mountain and 

Hells Canyon wilderness areas. These areas also experience the highest monitored aerosol 

impacts, with the exception of isolated wildfire impacts that affect sites throughout the west. 

Monitoring data for the years of the modeling study, 2003, 2004 and 2005 are shown in Figure 7, 

Figure 8, and Figure 9 (respectively), for the Starkey IMPROVE site. The Starkey site is located 

between Eagle Cap and Strawberry Mountain and is intended to represent both of these 

Wilderness areas. Figure 10, Figure 11, and Figure 12 show the measured aerosol extinction for 

the same three years at Hells Canyon IMPROVE site. The three Class I areas represented by 

these two IMPROVE sites reflect very similar patterns of observed seasonal visibility 

degradation and aerosol composition. A review of Figure 7 through Figure 12 indicates that: 

• The greatest non-carbon impacts are in the winter, when nitrate predominates extinction 

(80 to 150 Mm -1) and sulfate is relatively low. This aerosol formation regime generally 

occurs from November through February. 

• The greatest carbon impacts occur in the summer, sometimes extending into fall, when 

carbon predominates extinction (~120 – 280 Mm-1), likely from wildfires in the region, 

nitrate is negligible, and sulfate is relatively low (< 10Mm-1). It is important to note that 

ammonium nitrate is volatile at summertime temperatures and does not exist as an 

aerosol that can impact visibility during these warmer seasons. 

• The season with the best visibility (lowest extinction) is spring, when sulfate 

predominates. During this period, most sulfate impacts appear to be between about 5 and 

10 Mm-1, with the highest sulfate impact in 3 years reaching just over 20 Mm-1. 

Nevertheless, the observed aerosol impacts in the spring are relatively low compared to 

winter and summer when extinction reaches 120 to 300 Mm-1 most years. 

The Starkey IMPROVE site represents the two Class I areas with greatest modeled impacts from 

the TASCO Nampa boilers so seasonal regional haze impacts measured at Starkey were 

examined in more detail. Daily extinction values for measured aerosol species were obtained 

from the WRAP-TSS5

 and summarized into monthly average extinction values. Figure 13 shows 

monthly averaged total extinction at Starkey, and average extinction by species for all days in the 

three-year modeling period, 2003 – 2005. Error bars representing the 95% Confidence Intervals 

(CI) are also shown to indicate variability. The total extinction line demonstrates that average 

extinction is the highest in the summer and fall months, as a result of high organic carbon. The 

colder months of November through February experience the second highest total extinction and 

the predominant species is ammonium nitrate. The season with the best visibility (lowest average 

extinction) is spring (March through June) when average aerosol extinction is half to a third of 

that in the higher seasons. Sulfate predominates for most of the spring months averaging around 

5 – 7 Mm-1 with very little variability. Carbon increases to levels comparable to sulfate in May 

and June. 

Figure 14 shows the monthly average extinction pattern for the 20% of days observed each 

month with the worst visibility conditions. For the worst 20% of days, the greatest contributors 

to regional haze impacts are carbon in the summer and fall and nitrate in the winter. Again, 
18 

sulfate predominates in the spring when visibility conditions are best, yet still contributes only 

about 8 – 12 Mm-1 when averaged over the 20% of days with the highest extinction. 

Less Impacted Areas 

The TASCO Nampa Factory modeled impacts for the “Alternative Benchmark” scenario 

revealed that the other Class I areas further away and to the east of Nampa experienced modeled 

visibility impacts ranging from only 17 to 21% of the impacts at Eagle Cap, for the 22nd highest 

Δdv days. None of the 22nd highest days exceed 0.5Δdv, the EPA suggested threshold for 

“contributing” to a haze problem. The measured haze impacts at Craters, Jarbidge, Sawtooth and 

Selway-Bitterroot were also much lower than those at Starkey and Hells Canyon. The measured 

aerosol extinction charts for 2003, 2004 and 2005 are shown for Sawtooth Wilderness in Figure 

15, Figure 16, and Figure 17 (respectively); for Jarbidge Wilderness in Figure 18, Figure 19, and 

Figure 20; for Craters of the Moon Wilderness in Figure 21, Figure 22, and Figure 23; and for 

the Selway-Bitterroot Wilderness Area in Figure 24, Figure 25, and Figure 26. It should be 

noted, that the scale for each extinction figure changes, and while the highest (nitrate-impacted) 

days at Starkey and Hells Canyon reach 100 to 180 Mm-1, the highest nitrate-impacted days at 

the more distant sites east of Nampa have total extinction levels reaching only 40 to 55 Mm-1. 

The observed aerosol extinction charts for the eastern group of Class I areas indicate that: 

• At Jarbidge, Sawtooth and Selway-Bitterroot wilderness areas, measured nitrate aerosol 

extinction was very low, even in winter, suggesting very little impact from the TASCO 

Nampa Factory. Carbon dominated at these sites during the summer wildfire season, 

peaking around 130 Mm-1 at Sawtooth and over 350 Mm-1 at Selway-Bitterroot. Sulfate 

was more significant in the spring with most days below 5 - 6 Mm-1 and only a few days 

in the range 10 – 20 Mm-1. 

• At Craters of the Moon Wilderness Area (Figure 21 through Figure 23) the highest 

observed aerosol extinction resulted from nitrate in winter, up to 55 Mm-1, and carbon in 

the summer up to 100 Mm-1. Sulfate at Craters of the Moon was similar in magnitude to 

sulfate at all the other sites, typically around 5 - 10 Mm-1 or less, and never exceeds 20 

Mm-1, similar to the other Class I areas. This appears to be indicative of a very consistent 

regional background, with very little variation amongst all 7 Class I area. 

Overview of Seasonal Visibility Analysis 

The above analysis of seasonal visibility impacts suggests that the greatest impacts occur at 

Starkey and Hells Canyon as a result of wintertime nitrate impacts and summer/fall organic 

carbon impacts, probably from wildfires. A review of sulfate impacts at all the Class I areas 

(above) suggests that the level of springtime sulfate impacts (Figure 13 and Figure 14) at the 

Starkey IMPROVE site (~ 6 Mm-1 on the average day and 8 - 12 Mm-1 on the highest 20% of 

days) approximates a regional background level, similar to the levels apparent at the Class I areas 

east of Nampa (Jarbidge, Sawtooth, Craters of the Moon and Selway-Bitterroot) where TASCO 

Nampa emissions were found to not “contribute” significantly to the modeled extinction. 

To confirm the seasonality of the modeled impacts at Eagle Cap, the 22 highest days from the 

“Alternative Benchmark”, “BART” and “BART Alternative” scenarios were plotted in 
19 

Figure 27. All of the highest 22 days were observed in the winter time, and the “BART 

Alternative” results showed a slight improvement over the “BART” results. 

It may be concluded that the “BART Alternative” scenario results in greater reductions in haze 

on the 98th percentile days, and more days below the 0.5Δdv threshold than the “BART” scenario 

because it more effectively addresses the primary aerosol contributor (nitrates) during the most 

impacted season at the most impacted Class I areas. This overall improvement comes at the price 

of slightly less improvement during the best visibility period in the spring, when sulfate is a 

much smaller, but still predominant contributor to visibility degradation. Thus, the reduction in 

SO2 control in lieu of more NOx control results in slightly less visibility improvement on the 

clearest days in the spring (< 5Mm-1). Nevertheless, greater overall improvement in visibility 

conditions occurs with the “BART Alternative” in comparison to the “BART” scenario. 

Additional Environmental Benefits in Reducing Ozone

The Treasure Valley, including the Boise River and Snake River Valleys and stretching from 

Mountain Home, Idaho to Malheur County, Oregon, has been struggling with elevated 

summertime ozone conditions for a number of years. As shown in Figure 28, the Treasure Valley 

area remains perilously close to exceeding the ozone National Ambient Air Quality Standard 

(NAAQS). In 2008, the area escaped non-attainment by less than a part per billion. In 2010 the 

area was again very close to the proposed (but now deferred) range of the revised ozone NAAQS 

(60 – 70 ppb). DEQ believes that a recession-induced reduction in traffic, perhaps along with 

beneficial weather patterns has helped to avoid a non-attainment designation in recent years but 

that as traffic increases and weather varies, the attainment status of this area is precarious. As a 

result, Idaho has taken unprecedented steps to lower VOC and NOx ozone precursor emissions, 

including Stage II vapor control requirements and the nation’s only vehicle testing program (to 

our knowledge) that was not mandated by EPA in an ozone non-attainment plan. This testing 

program, started in June 2010 in Canyon County, where the TASCO Nampa Factory is located 

and was recently evaluated to determine the emission reductions it is providing. Based on 

MOVES modeling results, DEQ determined that the program provides approximately a 6.3% 

reduction in VOCs and a 2.7% reduction in NOx. The NOx reductions correspond to a 162 ton 

per year reduction or an annualized reduction of 0.4 tons per day. 

In its ongoing effort to be proactive in addressing the ozone problem, DEQ assessed the ozone 

mitigation benefits of a number of potential control measures in the CMAQ photochemical 

model, ranging from VMT reductions to reductions in emissions from lawn and garden 

equipment and solvent degreasing controls, etc. DEQ found that while VOC plus NOx reductions 

are most effective, NOx reductions of around 2 tons per day from the TASCO Factory is 

expected to result in a reduction of the peak 8-hour ozone concentration of approximately 0.1 

part per billion (ppb) on high ozone days. This is a better reduction than many of the other 

options, including further seasonal lowering of the Reid Vapor Pressure in gasoline, a 54% VOC 

reduction from a solvent-degreasing regulatory program, a 10% reduction in lawn and garden 

emissions, and a 10% reduction in vehicle refueling emissions. 

Ozone mitigation is only beneficial in the summertime. Thus, when TASCO’s winter processing 

campaign is over in the spring, less boiler capacity is required and at times the B&W Boilers 1& 
20 

2 are not used, in which case summer ozone benefits from lowering the NOx emissions from the 

B&W boilers would not contribute to ozone mitigation. However, TASCO has confirmed that in 

addition to the Riley Boiler, the B&W boilers usually operate about 30 days during the summer 

ozone season (range is 20 to 60 days). As a result, on a significant number of summer days, DEQ 

anticipates that the BART Alternative will provide ozone reduction benefits in the Treasure 

Valley. 

The “BART Alternative” scenario, achieves 6.5 tons per day of NOx reductions in comparison to 

the “Alternative Benchmark”, more than double the 2.7 tons per day reduction from the “BART” 

scenario. This quantity represents the greatest NOx reduction of any ozone control measures 

DEQ has evaluated to date. While NOx-only controls are not as effective as combined NOx plus 

VOC controls, this large reduction, in conjunction with VOC-only controls should be sufficient 

to significantly reduce the number of unhealthy days and may help to avoid a non-attainment 

designation in the next few years. 

Conclusions

This air quality modeling analysis addresses the visibility impacts of the “BART” and “BART 

Alternative” control scenarios for the BART-subject Riley Boiler at TASCO’s Nampa Factory. 

The “BART” scenario results in an overall 36% reduction in acid gas emissions, while the 

“BART Alternative” scenario results in a 31% reduction, however total acid gas plus particulate 

matter emissions for the two scenarios are virtually identical. TASCO’s alternative proposal 

involves replacing Spray Dry Flue Gas Desulfurization SO2 controls on the Riley Boiler with 

low-NOx burner controls on two non-BART boilers, along with shutting down three pulp dryers. 

While the total emissions of all species are similar, the “BART Alternative” achieves greater 

improvements in visibility because the most severe non-carbon visibility impairment at the Class 

I areas nearest the Nampa Factory is dominated by ammonium nitrate in the winter and replacing 

some of the SO2 control with increased NOx control provides greater reductions on more poor 

visibility days. An analysis of seasonal aerosol extinction observations indicates that while the 

greatest improvements will occur in the winter when impacts are greatest, there will be a small 

visibility impairment in the spring when the visibility conditions are best and a low-level sulfate 

background dominates the extinction. 

Nevertheless, overall modeled improvements show that the modeled visibility degradation on the 

22nd highest impacted day at Eagle Cap was reduced by an additional 0.101 Δdv for the “BART 

Alternative” scenario in comparison to the “BART” scenario, and there were projected to be 23 

less days at Eagle Cap over the 0.5 Δdv threshold. Taking a broader geographic view, the 

combined number of days at all seven areas above the 0.5 Δdv threshold were reduced by an 

additional 41 days for the “BART Alternative” scenario in comparison to the “BART” scenario. 

Finally, the “BART Alternative” scenario provides significantly greater NOx reductions than the 

“BART” scenario (2.4 times greater), and therefore is preferred by DEQ over the “BART” 

scenario for additional environmental benefits it is expected to bring to the ozone mitigation 

efforts in the Treasure Valley, in addition to the improved visibility expected for Class I Areas in 

the region. 
21 

Figure 4 TASCO Nampa Facility-Wide NOx Emissions 

Figure 5 TASCO Nampa Facility-Wide SO2 Emissions 

Figure 6 TASCO Nampa Facility-Wide PM10 Emissions 
22 

Figure 7 Light extinction (Mm-1) based on measured aerosol concentrations at Starkey IMPROVE site, representing 

Eagle Cap and Strawberry Mountain, 2003. 

Figure 8 Light extinction (Mm-1) based on measured aerosol concentrations at Starkey IMPROVE site, 2004. 

Figure 9 Light extinction (Mm-1) based on measured aerosol concentrations at Starkey IMPROVE site, 2005. 
23 

Figure 10 Light extinction (Mm-1) based on measured aerosol concentrations at Hells Canyon IMPROVE site, 2003. 

Figure 11 Light extinction (Mm-1) based on measured aerosol concentrations at Hells Canyon IMPROVE site, 2004. 

Figure 12 Light extinction (Mm-1) based on measured aerosol concentrations at Hells Canyon IMPROVE site, 2005. 
24 

Figure 13 Light extinction (Mm-1) based on measured aerosol concentrations at Starkey IMPROVE Site, 

All Days, 2003 - 2005. 

Figure 14 Light extinction (Mm-1) based on measured aerosol concentrations at Starkey IMPROVE Site, 

for 20% Worst Visibility Days, 2003-2005 
25 

Figure 15 Light extinction (Mm-1) based on measured aerosol concentrations at Sawtooth Wilderness IMPROVE site, 

2003.

Figure 16 Light extinction (Mm-1) based on measured aerosol concentrations at Sawtooth Wilderness IMPROVE site, 

2004. 

Figure 17 Light extinction (Mm-1) based on measured aerosol concentrations at Sawtooth Wilderness IMPROVE site, 

2005. 
26 

Figure 18 Light extinction (Mm-1) based on measured aerosol concentrations at Jarbidge Wilderness IMPROVE site, 

2003. 

Figure 19 Light extinction (Mm-1) based on measured aerosol concentrations at Jarbidge Wilderness IMPROVE site, 

2004. 

Figure 20 Light extinction (Mm-1) based on measured aerosol concentrations at Jarbidge Wilderness IMPROVE site, 

2005. 
27 

Figure 21 Light extinction (Mm-1) based on measured aerosol concentrations at Craters of the Moon Wilderness 

IMPROVE site, 2003. 

Figure 22 Light extinction (Mm-1) based on measured aerosol concentrations at Craters of the Moon Wilderness 

IMPROVE site, 2004. 

Figure 23 Light extinction (Mm-1) based on measured aerosol concentrations at Craters of the Moon Wilderness 

IMPROVE site, 2005. 
28 

Figure 24 Light extinction (Mm-1) based on measured aerosol concentrations at Selway-Bitterroot Wilderness 

IMPROVE site, 2003. 

Figure 25 Light extinction (Mm-1) based on measured aerosol concentrations at Selway-Bitterroot Wilderness 

IMPROVE site, 2004. 

Figure 26 Light extinction (Mm-1) based on measured aerosol concentrations at Selway-Bitterroot Wilderness 

IMPROVE site, 2005. 
29 

Figure 27 Seasonal variation in the modeled three-year highest 22 impacted days at Eagle Cap Wilderness 

for the pre-BART “Alternative Benchmark”, selected “BART”, and “BART Alternative” Scenarios. 

Figure 28 History of Treasure Valley Ozone Design Values and NAAQS. 
T2-2009.0105 Project 60867 Page 51 

APPENDIX C – INITIAL BART TIER II OPERATING PERMIT 

Table of Contents 

ACRONYMS, UNITS, AND CHEMICAL NOMENCLATURE.......................................................................... 3

1. TIER II OPERATING PERMIT SCOPE................................................................................................... 4

2. FACILITY-WIDE CONDITIONS ............................................................................................................ 5

3. RILEY BOILER BART............................................................................................................................. 6

4. SOUTH PULP DRYER ........................................................................................................................... 11

5. SUMMARY OF EMISSION RATE LIMITS ......................................................................................... 12

6. TIER II PERMIT TO OPERATE GENERAL PROVISIONS ................................................................ 13
Acronyms, Units, and Chemical Nomenclature 

AQCR Air Quality Control Region 

BART Best Available Retrofit Technologies 

CAA Clean Air Act 

CAM Compliance Assurance Monitoring 

CFR Code of Federal Regulations 

CO carbon monoxide 

DEQ Department of Environmental Quality 

EPA U.S. Environmental Protection Agency 

FGD flue gas desulfurization 

fpm feet per minute 

gpm gallons per minute 

IDAPA a numbering designation for all administrative rules in Idaho promulgated in accordance with 

the Idaho Administrative Procedures Act 

iwg inches of water gauge 

lb/hr pounds per hour 

lb steam/hr pounds of steam output per hour 

LNB low NOX burner system 

MMBtu/hr million British thermal units per hour 

MMscf/hr million standard cubic feet per hour 

NAAQS National Ambient Air Quality Standards 

NAICS North American Industry Classification System 

NO2 nitrogen dioxide 

NOX nitrogen oxides 

NSPS New Source Performance Standards 

O&M operations and maintenance 

OFA over-fired air 

PM particulate matter 

PM10 particulate matter with an aerodynamic diameter less than or equal to a nominal 10 

micrometers 

PSD prevention of significant deterioration of air quality 

SIC Standard Industrial Classification 

SIP State Implementation Plan 

SO2 sulfur dioxide 

SOx sulfur oxides 

TAP toxic air pollutants 

TASCO The Amalgamated Sugar Company, LLC 

T/hr tons per hour 

U.S.C. United States Code 

UTM Universal Transverse Mercator 

VOC volatile organic compounds 

T2-2009.0105 Page 3 
1. TIER II OPERATING PERMIT SCOPE 

Purpose 

1.1 The purpose of this Tier II operating permit is to establish Best Available Retrofit Technology (BART) 

emission standards and requirements for the Riley Boiler in accordance with 40 CFR 51.308(e) 

and IDAPA 58.01.01.401.03.

Regulated Sources 

1.2 The following Regulated Emission Point Sources Table lists all sources of regulated emissions in this 

permit: 

REGULATED EMISSION POINT SOURCES TABLE 

Permit 

Section Source Description Emissions Controls 

2 & 3 

Riley Boiler (S-B3)

Unit number: S-B3 

Installation Date: 1969 

Rated steam capacity: 250,000 lb steam/hr 

Maximum capacity: 350 MMBtu/hr 

Maximum operation: 8,760 hr/yr 

Fuel types: coal, natural gas 

Baghouse (A-B3)

Manufacturer: Envirotech Corp. 

Control efficiency: ≥99.0% for PM 

 BART for PM 

Spray dry flue gas desulfurization system

Reagent: Lime or limestone 

Control efficiency: 80-90% for SO2

 BART for SO2

Low NOX burner system with over-fired air

Control efficiency: ≥50% for NOX

 BART for NOX

2 & 4 Pulp dryers (S-D1, S-D2, and S-D3) Permanent shutdown

T2-2009.0105 Page 4 
2. FACILITY-WIDE CONDITIONS 

Obligation to Comply 

2.1 Receiving a Tier II operating permit shall not relieve any owner or operator of the responsibility to 

comply with all applicable local, state, and federal rules and regulations, in accordance with 

IDAPA 58.01.01.406. 

Incorporation of Federal Requirements by Reference 

2.2 Unless expressly provided otherwise, any reference in this permit to any document identified in IDAPA 

58.01.01.107.03 shall constitute the full incorporation into this permit of that document for the purposes 

of the reference, including any notes and appendices therein, in accordance with IDAPA 58.01.01.107. 

Documents include, but are not limited to: 

• Protection of Visibility, 40 CFR Part 51, Subpart P, Section 308 – Best Available Retrofit 

Technology (BART) requirements 

• Compliance Assurance Monitoring (CAM), 40 CFR Part 64 

For permit conditions referencing or cited in accordance with any document incorporated by reference 

(including permit conditions identified as BART and CAM), should there be any conflict between the 

requirements of the permit condition and the requirements of the document, the requirements of the 

document shall govern, including any amendments. 

DEQ Address 

2.3 Any reporting required by this permit, including, but not limited to, records, monitoring data, supporting 

information, requests for confidential treatment, notifications of intent to test, testing reports, or 

compliance certifications, shall contain a certification by a responsible official. The certification shall 

state that, based on information and belief formed after reasonable inquiry, the statements and information 

in the document(s) are true, accurate, and complete. Any reporting required by this permit shall be 

submitted to the following address: 

Air Quality Permit Compliance 

Department of Environmental Quality 

Boise Regional Office 

1445 N. Orchard 

Boise, ID 83706 

Phone: (208) 373-0550 

Fax: (208) 373-0287

T2-2009.0105 Page 5 
3. RILEY BOILER BART 

3.1 Process Description

The Riley Boiler is fired by pulverized coal and/or natural gas, and is used to supply steam and generate 

electricity for processing of sugar beets into sugar and byproducts, including animal feed at the Nampa 

facility. 

3.2 Emission Control Description

The existing baghouse (Unit No. A-B3) manufactured by Envirotech Corp. is used for the control of 

particulate matter (PM) emissions from the Riley Boiler. 

A spray dry flue gas desulfurization (FGD) system has been required for the control of sulfur dioxide 

(SO2) emissions from the Riley Boiler. In a spray dry FGD system, the flue gas is introduced into a tower 

and contacts an atomized spray of lime slurry, which absorbs and neutralizes the SO2. 

A low NOX burner system (LNB) with over-fired air has been required for the control of nitrogen oxides 

(NOX) emissions from the Riley Boiler. Low NOX combustion with over-fired air utilizes fuel and air 

mixing optimization and staged combustion techniques to minimize thermal NOX formation.

Compliance Dates 

3.3 BART 40 CFR 51.308, Subpart P – BART Installation and Operation Due Date

The permittee shall install and operate BART or a DEQ-approved BART alternative on each source 

subject to BART as expeditiously as practicable, but in no event later than five (5) years after approval of 

the implementation plan, in accordance with IDAPA 58.01.01.668.04 and 40 CFR 51.308(e)(1)(iv). 

The permittee may submit a request to obtain a DEQ-approved BART alternative and to revise this permit 

in accordance with IDAPA 58.01.01.404.04. DEQ will process the request in accordance with 

IDAPA 58.01.01.404. The request must be submitted timely such that any revisions to this permit and the 

corresponding revision to the Regional Haze SIP are approved prior to the BART installation and 

operation due date (as defined in this permit condition). Pursuant to Section 110(k)(2) of the Clean Air 

Act, EPA has 12 months to act on a requested SIP revision. 

Emissions Limits 

3.4 BART 40 CFR 51.308, Subpart P – BART and BART Alternative Emission Limits

On and after the BART installation and operation due date (as defined in Permit Condition 3.3), the 

emissions from the Riley Boiler stack shall not exceed any corresponding emission rate limit listed in the 

following Riley Boiler BART and BART Alternative Emission Limits Table, in accordance with IDAPA 

58.01.01.401.03 and 40 CFR 51.308(e): 

RILEY BOILER BART AND BART ALTERNATIVE EMISSION LIMITS TABLE 

PM SO2 NOX

Source Description lb/hr (a,b) lb/hr (a,b) lb/hr (a,c)

Riley Boiler (S-B3) 14 115 186 

(a) Pounds per hour, as determined by a test method prescribed by 

IDAPA 58.01.01.157, EPA reference method, or DEQ approved 

alternative. 

(b) BART emission rate limit in accordance with 40 CFR 51.308(e). 

(c) BART alternative emission rate limit in accordance with 40 CFR 

51.308(e)(2). 

T2-2009.0105 Page 6 
3.5 CO Emission Limits

On and after the BART installation and operation due date (as defined in Permit Condition 3.3), the 

emissions from the Riley Boiler stack shall not exceed any corresponding emission rate limit listed in the 

following Riley Boiler CO Emission Limits Table, in accordance with IDAPA 58.01.01.401.03 and 

40 CFR 51.308(e): 

RILEY BOILER CO EMISSION LIMITS TABLE 

CO 

Source Description lb/hr (a) T/yr (b)

Riley Boiler (S-B3) 25.8 113 

(a) Pounds per hour, as determined by a test method 

prescribed by IDAPA 58.01.01.157, EPA 

reference method, or DEQ approved alternative. 

(b) Tons per any consecutive 12-calendar month 

period. 

Operating Requirements 

3.6 BART 40 CFR 51.308, Subpart P – Baghouse Control Equipment

On and after the BART installation and operation due date (as defined in Permit Condition 3.3), and at all 

times the Riley Boiler is fired with coal, the permittee shall operate a Baghouse (A-B3) to control PM 

emissions from the Riley Boiler to ensure compliance with the BART PM emission limit (Permit 

Condition 3.4), in accordance with IDAPA 58.01.01.401.03 and 40 CFR 51.308(e). The baghouse need 

not be operated during periods when the Riley Boiler is being fired exclusively with natural gas. 

3.7 BART 40 CFR 51.308, Subpart P – Spray Dry Flue Gas Desulfurization Control Equipment

On and after the BART installation and operation due date (as defined in Permit Condition 3.3), the 

permittee shall operate at all times the Riley Boiler is operated, a spray dry flue gas desulfurization (FGD) 

system to control SO2 emissions from the Riley Boiler and to ensure compliance with the BART SO2

emission limit (Permit Condition 3.4), in accordance with IDAPA 58.01.01.401.03 and 

40 CFR 51.308(e). 

3.8 BART 40 CFR 51.308, Subpart P – Low NOX Burner Control Equipment

On and after the BART installation and operation due date (as defined in Permit Condition 3.3), the 

permittee shall operate at all times the Riley Boiler is operated, a low NOX burner system (LNB) in the 

Riley Boiler to reduce NOX emissions and to ensure compliance with the BART NOX emission limit 

(Permit Condition 3.4), in accordance with IDAPA 58.01.01.401.03 and 40 CFR 51.308(e). 

• The LNB shall have a maximum rated heat input capacity (highest heating value) of less than or equal 

to 350 MMBtu/hr, and shall combust only natural gas and/or coal fuel. 

• If operation of the LNB with OFA in the Riley Boiler is expected to result in an emissions increase, 

the permittee shall submit the required preconstruction compliance demonstrations 

(Permit Condition 3.18). 

3.9 BART 40 CFR 51.308, Subpart P – Maintenance of BART Equipment

On and after the BART installation and operation due date (as defined in Permit Condition 3.3), the 

permittee shall maintain the control equipment required and establish procedures to ensure such 

equipment is properly operated and maintained, in accordance with IDAPA 58.01.01.668.05 and 

40 CFR 51.308(e)(1)(v). 

T2-2009.0105 Page 7 
Monitoring and Recordkeeping Requirements 

3.10 Baghouse Pressure Differential Monitoring

The permittee shall install, calibrate, and maintain measuring device(s) to continuously monitor the 

pressure drop across each of the baghouses, in inches water gauge. The pressure drop shall be recorded 

once per day while the boilers are in operation. In the event a measuring device becomes inoperable, it 

shall be repaired or replaced as soon as practicable. The records shall be maintained in accordance with 

General Provision 7. 

3.11 Spray Dry FGD Adiabatic Approach Temperature Monitoring

The permittee shall install, calibrate, and maintain measuring device(s) to continuously monitor the 

adiabatic approach temperature for the spray dry FGD spray tower in degrees Fahrenheit. The 

temperature differential shall be recorded once per day while the Riley Boiler is in operation. In the event 

a measuring device becomes inoperable, it shall be repaired or replaced as soon as practicable. The 

records shall be maintained in accordance with General Provision 7. 

3.12 Primary and Over-Fired Air Flow Monitoring

The permittee shall install, calibrate, and maintain measuring devices to continuously monitor the primary 

and over-fired air flow rates into the Riley Boiler, in feet per minute. The flow rate shall be recorded once 

per day while the Riley Boiler is in operation. In the event a measuring device becomes inoperable, it 

shall be repaired or replaced as soon as practicable. The records shall be maintained in accordance with 

General Provision 7. 

3.13 Operation and Maintenance Manuals

Within 60 days after the BART installation and operation due date (as defined in Permit Condition 3.3), 

the permittee shall develop and submit to DEQ an Operation and Maintenance (O&M) manual for review 

and comment at the address provided (Permit Condition 2.3). Any changes to the O&M manual shall be 

submitted to DEQ for review and comment within 15 days of the change. 

• The O&M manual shall describe for each of the control equipment described in the Regulated 

Emission Point Sources Table (Permit Condition 1.2) procedures that will be followed to ensure 

compliance with BART emission limits (Permit Condition 3.4), CO emission limits (Permit 

Condition 3.5), the maintenance of BART equipment requirement (Permit Condition 3.9), the control 

equipment maintenance and operation general provision (General Provision 2), and the 

manufacturer’s specifications. The O&M manual shall be a permittee developed document based 

upon, but independent from, the manufacturer supplied operating manual(s). 

• The permittee shall operate the control equipment in accordance with the O&M manual. The 

procedures specified in the O&M manual are incorporated by reference into this permit and are 

enforceable permit conditions. The O&M manual and copies of any manufacturer’s manual(s) and 

recommendations shall remain on site at all times and shall be made available to DEQ representatives 

upon request. 

• At a minimum, the manufacturer’s recommended values that shall be maintained for each of the 

following operating parameters shall be included in the manual: 

 Baghouse minimum and maximum pressure drop, in inches of water (iwg); 

 Spray dry FGD minimum slurry flow rate, in gallons per minute (gpm); 

 Spray dry FGD adiabatic approach temperature, in degrees Fahrenheit (o

F) above the adiabatic 

saturation temperature; 

T2-2009.0105 Page 8 
 LNB minimum and maximum flow rates for both primary and over-fired airflow, in feet per 

minute (fpm); and 

 Requirements to monitor and record the parameters listed above accordance with the frequency 

recommended by the manufacturer, and at a minimum each day that the Riley Boiler is operated. 

Performance Testing Requirements 

3.14 Initial Performance Tests

• No later than 90 days after the BART installation and operation due date (as defined in Permit 

Condition 3.3), performance tests shall be conducted on the Riley Boiler stack to demonstrate 

compliance with the following emission limits, in accordance with IDAPA 58.01.01.405 and IDAPA 

58.01.01.157: 

 The BART PM emission limit in pounds per hour (Permit Condition 3.4); 

 The BART SO2 emission limit in pounds per hour (Permit Condition 3.4); 

 The BART NOX emission limit in pounds per hour (Permit Condition 3.4); and 

 The CO emission limit in pounds per hour (Permit Condition 3.5). 

• Each performance test shall be conducted under the following conditions, unless otherwise approved 

by DEQ, in accordance with IDAPA 58.01.01.405, IDAPA 58.01.01.157, and General Provision 6: 

 Emissions shall be measured while combusting coal fuel in the Riley Boiler. 

 Three separate test runs shall be conducted for each performance test. 

 Parameters shall be monitored and recorded as specified in the performance test monitoring and 

recordkeeping requirement (Permit Condition 3.16). 

3.15 Periodic Performance Testing

Performance tests to determine PM, SO2, NOX, and CO emissions in pounds per hour from the Riley 

Boiler stack shall be conducted no less frequently than annually following the date of each required initial 

performance test, in accordance with IDAPA 58.01.01.405 and under the conditions required for the 

initial performance tests (Permit Condition 3.14), unless another testing frequency has been approved by 

DEQ. 

3.16 Performance Test Monitoring and Recordkeeping

The permittee shall monitor and record the following during each performance test, unless otherwise 

approved by DEQ: 

• Steam production rate of the Riley Boiler, in pounds per hour (lb steam/hr), once every 15 minutes; 

• Coal feed rate to the Riley Boiler, in tons per hour (T/hr), once every 15 minutes (the coal feed rate 

may be determined using alternate relevant operational parameter(s) and a calculation method which 

has been approved by DEQ); 

• Natural gas firing rate, in million standard cubic feet per hour (MMscf/hr), once every 15 minutes; 

• Highest heating value and analysis results, including ash content, of the coal fired; 

• Pressure drop across the baghouse during each test, in inches water gauge (iwg), once every 15 

minutes; 

• Spray dry FGD minimum slurry flow rate, in gallons per minute (gpm); 

• Spray dry FGD adiabatic approach temperature, in degrees Fahrenheit (o

F), once every 15 minutes; 

and 

T2-2009.0105 Page 9 
• LNB primary and over-fired air flow rates, in feet per minute (fpm), once every 15 minutes. 

3.17 Performance Test Reporting

The permittee shall submit performance test reports to DEQ which include records of the monitoring 

required (Permit Condition 3.16) and in accordance with the performance testing general provision 

(General Provision 6). Performance test reports shall be submitted by the permittee to the DEQ address 

provided (Permit Condition 2.3). 

Compliance Submittals and Notifications 

3.18 Preconstruction Compliance Demonstrations

No later than 180 days prior to the BART installation and operation due date (as defined in Permit 

Condition 3.3), the permittee shall submit information and modeling analyses demonstrating that 

installation and operation of BART will not cause or significantly contribute to a violation of any ambient 

air quality standards, in accordance with the procedures provided in IDAPA 58.01.01.200-228. This shall 

include the following, unless otherwise approved by DEQ: 

• Demonstration of Preconstruction Compliance with Toxic Standards 

• Demonstration of Preconstruction Compliance with National Ambient Air Quality Standards 

3.19 CAM 40 CFR 64 and IDAPA 58.01.01.668.06.c – Documentation of Need for Improved Monitoring

No later than 90 days after the BART installation and operation due date (as defined in Permit 

Condition 3.3) and unless otherwise approved by DEQ, the permittee shall submit information to address 

monitoring changes in accordance with IDAPA 58.01.01.668.06.c, and in a Compliance Assurance 

Monitoring (CAM) plan relevant to the installation and operation of BART in accordance with the 

procedures in 40 CFR Part 64. 

3.20 Submittal and Notification Requirements

Required compliance submittals and notifications (Permit Conditions 3.18 and 3.19) shall be submitted to 

the DEQ address provided (Permit Condition 2.3). 

T2-2009.0105 Page 10 
4. SOUTH PULP DRYER 

Operating Requirements 

4.1 BART 40 CFR 51.308, Subpart P – Shutdown of South Pulp Dryer

The permittee shall permanently shut down the South pulp dryer (S-D1). 

Notification and Reporting Requirements 

4.2 Pulp Dryer Shutdown Notification

Within 30 days after completing permanent shut down of the South pulp dryer (as required by Permit 

Condition 4.1), the permittee shall provide written notification to DEQ of the decision to permanently 

shut down the South pulp dryer. The notification shall include a description of the method used to ensure 

permanent shut down of the South pulp dryer. 

T2-2009.0105 Page 11 
5. SUMMARY OF EMISSION RATE LIMITS 

The following table provides a summary of all emission rate limits required by this permit: 

SUMMARY OF EMISSION RATE LIMITS 

PM SO2 NOX CO Source Description lb/hr (a,c) lb/hr (a,c) lb/hr (a,c) lb/hr (a) T/yr (b)

Riley Boiler (S-B3) with 

BART 14 115 186 25.8 113 

(a) Pounds per hour, as determined by a test method prescribed by IDAPA 58.01.01.157, 

EPA reference method, or DEQ approved alternative. 

(b) Tons per any consecutive 12-calendar month period. 

(c) BART emissions rate in accordance with 40 CFR 51.308(e). 

T2-2009.0105 Page 12 
6. TIER II PERMIT TO OPERATE GENERAL PROVISIONS 

General Compliance 

1. The permittee has a continuing duty to comply with all terms and conditions of this permit. All emissions 

authorized herein shall be consistent with the terms and conditions of this permit and the Rules for the 

Control of Air Pollution in Idaho. The emissions of any pollutant in excess of the limitations specified 

herein, or noncompliance with any other condition or limitation contained in this permit, shall constitute a 

violation of this permit and the Rules for the Control of Air Pollution in Idaho, and the Environmental 

Protection and Health Act, Idaho Code §39-101, et seq. 

[Idaho Code §39-101, et seq.] 

2. The permittee shall at all times (except as provided in the Rules for the Control of Air Pollution in Idaho) 

maintain in good working order and operate as efficiently as practicable, all treatment or control facilities 

or systems installed or used to achieve compliance with the terms and conditions of this permit and other 

applicable Idaho laws for the control of air pollution. 

[IDAPA 58.01.01.405, 5/1/94] 

3. Nothing in this permit is intended to relieve or exempt the permittee from the responsibility to comply 

with all applicable local, state, or federal statutes, rules and regulations. 

[IDAPA 58.01.01.406, 5/1/94] 

Inspection and Entry 

4. Upon presentation of credentials, the permittee shall allow DEQ or an authorized representative of DEQ 

to do the following: 

a. Enter upon the permittee’s premises where an emissions source is located or emissions related 

activity is conducted, or where records are kept under conditions of this permit; 

b. Have access to and copy, at reasonable times, any records that are kept under the conditions of this 

permit; 

c. Inspect at reasonable times any facilities, equipment (including monitoring and air pollution control 

equipment), practices, or operations regulated or required under this permit; and 

d. As authorized by the Idaho Environmental Protection and Health Act, sample or monitor, at 

reasonable times, substances or parameters for the purpose of determining or ensuring compliance 

with this permit or applicable requirements. 

[Idaho Code §39-108] 

Construction and Operation Notification 

5. The permittee shall furnish DEQ written notifications as follows: 

a. A notification of the date of initiation of construction, within five working days after occurrence; 

b. A notification of the date of any suspension of construction, if such suspension lasts for one year or 

more; 

c. A notification of the anticipated date of initial start-up of the stationary source or facility not more 

than sixty days or less than thirty days prior to such date; 

d. A notification of the actual date of initial start-up of the stationary source or facility within fifteen 

days after such date; and 

T2-2009.0105 Page 13 
e. A notification of the initial date of achieving the maximum production rate, within five working days 

after occurrence - production rate and date. 

[IDAPA 58.01.01.405, 5/1/94] 

Performance Testing 

6. If performance testing (air emissions source test) is required by this permit, the permittee shall provide 

notice of intent to test to DEQ at least 15 days prior to the scheduled test date or shorter time period as 

approved by DEQ. DEQ may, at its option, have an observer present at any emissions tests conducted on 

a source. DEQ requests that such testing not be performed on weekends or state holidays. 

 All performance testing shall be conducted in accordance with the procedures in IDAPA 58.01.01.157. 

Without prior DEQ approval, any alternative testing is conducted solely at the permittee’s risk. If the 

permittee fails to obtain prior written approval by DEQ for any testing deviations, DEQ may determine 

that the testing does not satisfy the testing requirements. Therefore, at least 30 days prior to conducting 

any performance test, the permittee is encouraged to submit a performance test protocol to DEQ for 

approval. The written protocol shall include a description of the test method(s) to be used, an explanation 

of any or unusual circumstances regarding the proposed test, and the proposed test schedule for 

conducting and reporting the test. 

Within 30 days following the date in which a performance test required by this permit is concluded, the 

permittee shall submit to DEQ a performance test report. The written report shall include a description of 

the process, identification of the test method(s) used, equipment used, all process operating data collected 

during the test period, and test results, as well as raw test data and associated documentation, including 

any approved test protocol. 

[IDAPA 58.01.01.157, 4/5/00] 

Monitoring and Recordkeeping 

7. The permittee shall maintain sufficient records to ensure compliance with all of the terms and conditions 

of this permit. Records of monitoring information shall include, but not be limited to the following: (a) 

the date, place, and times of sampling or measurements; (b) the date analyses were performed; (c) the 

company or entity that performed the analyses; (d) the analytical techniques or methods used; (e) the 

results of such analyses; and (f) the operating conditions existing at the time of sampling or measurement. 

All monitoring records and support information shall be retained for a period of at least five years from 

the date of the monitoring sample, measurement, report, or application. Supporting information includes, 

but is not limited to, all calibration and maintenance records and all original strip-chart recordings for 

continuous monitoring instrumentation and copies of all reports required by this permit. All records 

required to be maintained by this permit shall be made available in either hard copy or electronic format 

to DEQ representatives upon request. 

[IDAPA 58.01.01.405, 5/1/94] 

T2-2009.0105 Page 14 
T2-2009.0105 Page 15 

Excess Emissions 

8. The permittee shall comply with the procedures and requirements of IDAPA 58.01.01.130-136 for excess 

emissions due to startup, shutdown, scheduled maintenance, safety measures, upsets and breakdowns. 

[IDAPA 58.01.01.130-136, 4/5/00] 

Certification 

9. All documents submitted to DEQ, including, but not limited to, records, monitoring data, supporting 

information, requests for confidential treatment, testing reports, or compliance certification shall contain a 

certification by a responsible official. The certification shall state that, based on information and belief 

formed after reasonable inquiry, the statements and information in the document(s) are true, accurate, and 

complete. 

[IDAPA 58.01.01.123, 5/1/94] 

False Statements 

10. No person shall knowingly make any false statement, representation, or certification in any form, notice, 

or report required under this permit, or any applicable rule or order in force pursuant thereto. 

[IDAPA 58.01.01.125, 3/23/98] 

Tampering 

11. No person shall knowingly render inaccurate any monitoring device or method required under this permit 

or any applicable rule or order in force pursuant thereto. 

[IDAPA 58.01.01.126, 3/23/98] 

Expiration and Renewal 

12. This permit shall be renewable on the expiration date, provided the permittee submits an application for 

renewal to the Department and continues to meet all terms and conditions contained in the permit. The 

expiration of this permit will not affect the operation of the stationary source of facility during the 

administrative procedure period associated with the permit renewal process. 

[IDAPA 58.01.01.404.04, 7/1/02] 

Transferability 

13. This permit is transferable in accordance with procedures listed in IDAPA 58.01.01.404.05. 

[IDAPA 58.01.01.404.05, 4/11/06] 
T2-2009.0105 Project 60867 Page 52 

APPENDIX D – BAGHOUSE O&M MANUAL 
Boiler System Baghouses O&M Manual 1

Operations & Maintenance 

Manual for: 

Riley and B&W Boiler Baghouses 

The Amalgamated Sugar Company 

Nampa Facility 

September, 2003 

(revised October 2004) 
Boiler System Baghouses O&M Manual 2

Table of Contents 

I. Introduction Pg 3 

II. General Description of the Control Equipment Pg 3 

III. Normal Operating Conditions Pg 4 

IV. Upset Conditions and Corrective Procedures Pg 5 

V. Boiler Start-up, Shutdown procedures Pg 5 

VI. Control Device Monitoring program Pg 6 

VII. Maintenance Procedures Pg 7 

VIII. Daily Inspections and Maintenance Pg 7 

IX. Annual Maintenance Pg 8 

X. Record keeping Pg 9 
Boiler System Baghouses O&M Manual 3

Introduction 

In accordance with Permit Condition 2.15 of the Tier II Operating Permit (#027-00010), 

this Operations & Maintenance Manual (O&M Manual) outlines procedures that when 

implemented will ensure that the Riley and B&W Boiler Baghouses operate at optimal 

efficiency. The O&M Manual includes the following: 

1) Introduction 

2) General Description of the Control Equipment 

3) Normal Operating Conditions 

4) Upset Conditions and Corrective Procedures 

5) Boiler Start-up, Shutdown procedures 

6) Control Device Monitoring Program 

7) Maintenance Procedures 

a. Daily Inspections and Maintenance 

b. Annual Maintenance 

8) Record keeping 

 

General Description of the Control Equipment 

B&W Boilers Baghouse (Unit Number A-B1/2) 

Particulate emissions from the two B&W Boilers are controlled using a Joy Baghouse. 

The baghouse was installed in 1974 as a retrofit project. It is located just west of the 

boiler house on an elevated platform. Flue gas is ducted from the boiler outlet through 

the baghouse to the stack. A bypass duct and damper is used to bypass the baghouse 

if necessary in an emergency situation,(i.e. baghouse blinded, boiler tube leak, etc). 

An Operation and Maintenance Manual (attached), provided by BHA during a training 

session, was used as a guide for preparing this document. 

Joy Baghouse Specifications: 

Number of Bags 4,224 

Type of Bags BHA brand GL22 fiberglass bags 

Air Permeability 30 to 60 CFM. 

Operating Temperature Range 240 to 360 ° F. . 

Finish 10% Teflon B. 

Dimensions 5.25 “ X 125.5” 

Flow Rate 93,500 to 140,000 ACFM 

Baghouse Differential Pressure 2 to 14 “WG 

Air to Cloth Ratio 1.4 : 1 gross and 1.6 : 1 net. 

Dust Removal Reverse Air, with acoustic using 2 horns 

Rotary airlocks 
Boiler System Baghouses O&M Manual 4

Riley Boiler Baghouse (A-B3) 

Particulate emissions from the Riley Boiler are controlled using a Envirotech Baghouse. 

The baghouse was installed in 1975 as a retrofit project. It is located just north of the 

boiler house on a mezzanine bridging the pulp dryer building and the boiler house. 

Flue gas is ducted from the boiler outlet through the baghouse to the B&W stack. A 

bypass duct and damper is used to bypass the baghouse if necessary in an emergency 

situation, (i.e. baghouse blinded, boiler tube leak, etc). 

Envirotech Baghouse Specifications 

Number of Bags 3920 

Type of Bags BHA brand GL26 fiberglass bags or equivalent 

Air Permeability 30 to 60 CFM. 

Operating Temperature Range 260 to 400 ° F. 

Finish Heat Cleaned with a Chemically Resistant 

Coating. 

Dimensions 5.25” X 166” 

Flow Rate 106,000 to 160,000 ACFM 

Baghouse Differential Pressure 2 to 14 “WG 

Air to Cloth Ratio 1.4 : 1 gross and 1.7: 1 net. 

Dust Removal Reverse Air, with acoustic using 2 horns 

Tensioning Conical Springs 

Rotary Airlocks 

Normal Operating Conditions 

Contaminated air entering the baghouse under negative pressure is distributed using an 

inlet baffle. The inlet baffle decreases inlet gas velocity, which improves distribution and 

reduces the impact of high velocity particles on filter bags. 

Air flows from the bottom inside of the filter bag to the top outside of the filter bag 

effectively filtering particulate matter from the flow. As the bag porosity decreases from 

the build up of filtered particulates (filter cake), the differential pressure increases across 

the baghouse collector. The filter bags are periodically cleaned with reverse air that 

removes the collected dust allowing it to drop into a hopper. Dust removal is also 

enhanced with acoustic horns, which are located in the area between the filter bag 

columns. The dust is removed from the hoppers using air lock rotary gates and mixed 

with water, which is hydraulically conveyed to a settling pond. During beet campaign 

the water is mixed with flume water in the settling ponds, but during intercampaign the 

water is directed to a separate settling pond near the piling ground. 
Boiler System Baghouses O&M Manual 5

Upset Conditions and Corrective Procedures 

The Company takes its environmental responsibilities very seriously. Upsets that can 

lead to excess emissions from the boiler stack are a very serious matter and must be 

managed quickly and efficiently. The following information should be used for properly 

responding to upset conditions that can lead to an excess emission: 

Cause An upset condition has the potential to occur when one or more of the 

following conditions occur: 

1) One of more bags have ruptured. This allows flyash to enter the clean air side 

of the baghouse and exhaust to the stack. 

2) One or more bags have slipped off the mounting thimble. 

3) Boiler tube leak that has the potential to blind the bag from excessive 

moisture. 

4) Baghouse cleaning system has failed and collected dust is not removed 

properly. 

5) Baghouse air lock system has failed. 

6) Baghouse dust conveying system has failed. 

Detection An upset condition that leads to a possible excess emission from the 

stack can be detected by either 1) Boiler House Operators during operation 

checks and shift inspections or by 2) alarmed bag leak detectors. 

Note: A leak large enough to cause a visual emission cannot normally be 

detected by monitoring baghouse differential pressure readings. 

Corrective Action 

To assist the operators with detecting leaking bags, a leak detection system has 

been installed in each baghouse. The leak detection system will alert operators 

of a leak and pinpoint the affected baghouse. To determine which baghouse 

module is has the leaking bags; the operator will shut down each bag house 

module until the leaking stops. The bags are then refitted or replaced and the 

module is placed back into service. 

Reporting Upset conditions that lead to a visible emission from the boiler stack 

must be immediately reported to the Shift Supervisor or the Boiler Foreman who 

will determine if DEQ needs to be notified. The boiler foreman is certified to 
Boiler System Baghouses O&M Manual 6

perform visual emission determinations using EPA Method 9. If neither is 

available, the Facility Environmental Manager must be notified. 

 

Boiler Startup and Shutdown Procedures 

The following startup procedure is currently on file with DEQ and will be strictly followed 

for all boiler startups including scheduled and unscheduled events. 

B&W and Riley Boiler Start-Up Procedure 

The following operating procedure will be followed in the event that a boiler start up is 

required for either scheduled or non-scheduled startups: 

1) The boiler will start up in the normal fashion fueled by natural gas. The 

baghouse system will be bypassed to protect the bags from the high 

moisture conditions that are characteristic of natural gas operation. 

2) After the boiler is brought up to temperature and placed in service 

(nominally up to 24 hours) the baghouse will be pre-coated with an 

appropriate material. After pre-coating, coal will be introduced as the 

primary fuel to establish stable combustion conditions. 

3) Natural gas fueling of the boiler may be discontinued after coal 

combustion is stable. 

4) The baghouse will be placed back in service after stable coal firing 

conditions are established (20 to 60 minutes after coal fuel is introduced 

in to the firebox). 

B&W and Riley Boiler Shut Down Procedures 

During shut down, the baghouses remain on-line until the fuel transfer is made 

from coal back to natural gas to ensure that emission capture continues during 

the entire shutdown procedure. The fuel transfer to natural gas is initiated when 

the steam load is too low to maintain stable combustion conditions with coal 

firing. The baghouse is only by-passed after given sufficient time to clear all the 

flyash from the ducts. Visible emissions are not considered an issue during 

boiler shut down. 

Control Device Monitoring Program 

The Tier II air permit requires that the baghouse systems be monitored to ensure 

optimal operations and to detect any upset conditions that may lead to an excess 

emissions. The monitoring requirements for the baghouses servicing the boiler 

system is outlined below: 

Monitoring Procedures and Equipment 

The baghouse system is monitored using several different methods. These are 

listed below along with a description of the method. 
Boiler System Baghouses O&M Manual 7

Differential Pressure Drop Monitoring Differential pressure drop (DPD) is 

required to be monitored by the Tier II permit. DPD is measured by two independent 

measuring systems, manually using permanently mounted manometers (in the boiler 

control room) and electronically using a DP cell. The DP cells provide data to the 

plants data acquisition system where it is logged and archived for reporting 

requirements. 

Note: A leak large enough to cause a visual emission cannot normally be detected 

by monitoring baghouse differential pressure. Bag leak detectors and VE’s should 

be used for determining if upset conditions exist that can lead to an excess 

emission. 

The range of differential pressure drop across both baghouses (measured 

individually) is from 2” H2O gauge to 14” H2O water gauge. 

Bag Leak Detectors Bag leak detectors have been installed at the outlet of each 

baghouse to alarm when particulate levels indicate that a bag leak is probable (see 

photo below). This is an important tool that can provide additional information about 

the baghouse performance. The BLD should not be used as a replacement for 

visual emissions inspections. 

Visual Emissions Visual emissions of the boiler stack are conducted by two 

independent inspections. The plant Environmental Manager conducts see, no see 

VE inspections twice a month at approximately two weeks apart. VE’s are also 

checked each shift by boiler operators. The findings need to be documented in the 

Boiler Control Room Log. If a visible plume is present notify the shift 

supervisor and boiler foreman immediately and take corrective action to 

resolve the problem! (see the “Upset Conditions and Corrective Action” 

section) 

Maintenance Procedures 

Maintenance is an important component of proper operation of emission control 

equipment. TASCO has identified the following daily monthly and annual tasks to be 

completed to ensure proper operation of the baghouses 

Daily Inspections and Maintenance

To ensure optimal efficiency of emission control equipment, the following inspection 

tasks will be completed each hour with any discrepancies documented in the boiler 

house log: 

 

1. Inspect rotary gates and rams. Check that rams activate and operate smoothly 

and properly. Rotary gates need to cycle properly and remove flyash from the 

hopper. 
Boiler System Baghouses O&M Manual 8

2. Inspect and clean flumes as necessary. Remove any material build up that may 

lead to system plugging. Insure that water flow is adequate to remove ash from 

the system. 

3. Inspect reverse air fan. Ensure that the fan is running smoothly and that the 

system is cycling and functioning properly. 

4. Inspect solenoid valves. Check that that the solenoid valves are timed and 

operating smoothly. 

5. Inspect air horns, and related devices. Check to ensure that the air horns are 

operating during the cleaning cycles. 

Annual Maintenance: 

In order to keep the emissions control equipment in optimal operating condition, the 

following monthly and annual maintenance will be performed: 

Schedule Annual maintenance on the baghouses can only be performed when 

the equipment is out of service. The following time periods provide general 

opportunities to perform annual maintenance on equipment. Actual dates of 

equipment shutdown and availability are determined by the operational needs for 

the equipment: 

Oct- February 

All equipment is in service during the beet campaign period. Annual 

maintenance is not performed during this period of time. 

February – March 

After beet campaign and during Juice Run, the B&W boilers are usually out of 

service for annual maintenance. The Riley boiler supplies steam. 

March – May 

During the separator only operation the Riley is removed from service for annual 

maintenance. Steam is provided using the B&W boilers during this period of 

time. 

A 2-Day plant wide shutdown is usually scheduled during this time period. 

May – Oct. 
Boiler System Baghouses O&M Manual 9

During Juice Run the B&W is usually out of service and maintenance is 

performed. 

Annual Maintenance List 

Annual maintenance presents the opportunity to conduct basic maintenance and 

system changes to resolve root cause issues. The following tasks have been 

identified as important annual inspection/maintenance items: 

1) Baghouse Housing. Check for corrosion, warped panels and other damage 

that may lead to an air leak. Repair as necessary.

2) Tube Sheets Tube sheets need to be properly aligned, with no warp or 

corroded holes. They need to be in good operating condition. Repair as 

necessary if discrepancies are discovered.
Boiler System Baghouses O&M Manual 10

3) Filter Bag Connection Hardware The hardware used to attach the filter bag 

needs to be in good condition and serviceable. Replace as necessary to 

ensure the filter bag will be attached properly. 

4) Filter Bags Inspect filter bags and reject any that appear to have a hole, are 

damaged from abrasion or have lost strength because of heat excursion.
Boiler System Baghouses O&M Manual 11

5) Dampers and Air Rams Ensure that air rams and dampers operate 

smoothly. Also check to ensure that dampers are positioned and seal 

properly. 
Boiler System Baghouses O&M Manual 12

6) Hopper Check for corrosion, warped panels and other damage that may 

lead to an air leakage or retention of dust. Hopper walls need to smoothly 

convey dust to the air lock system. Repair as necessary. 

7) Door Seals Check door seals to ensure that they are in good repair and will 

seal properly. Replace as necessary

8) Inlet Baffle Inspect the baffle to ensure that they are in proper position. 

Also check for damage from abrasion and panel warp. Repair as necessary. 

9) Air Locks Inspect airlocks to ensure that they are sealed, sequencing 

properly and operate smoothly. Repair as necessary.

10) Air Horns Inspect to ensure proper operation. Horns must be timed 

properly and develop the designed energy to remove dust. Check horn 

diaphragms to ensure that wear is within manufactures tolerances.
Boiler System Baghouses O&M Manual 13

11) Reverse Air Fans Inspect reverse air fans to ensure that they provide 

sufficient air flow. Check bearings, and fan blades for wear and repair or 

replace as necessary. 

 

12) Duct work and insulation Check for corrosion, warped panels and other 

damage that may lead to an air leak. Ensure that insulation is replaced after 

maintenance and that it is serviceable condition. Repair as necessary

13) Bypass Louvers Inspect bypass louvers to ensure proper damper seal. 

Check for corrosion, warped panels and other damage that may lead to air 

leakage past the damper. 

14) Stack Insect gas path and breech to stack for corrosion, cracking and other 

damaged. Clean the stack breech and ductwork and repair as necessary. 
Boiler System Baghouses O&M Manual 14

Record Keeping 

Record Keeping is a specific requirement in the Tier II permit. Record keeping is 

important to demonstrate that operational information and maintenance is completed as 

required in the Air Permit. As a minimum the following information will be collected and 

retained for up to five years: 

Operations 

1) The baghouse pressure drop will be recorded at least once per week during 

baghouse operation and archived in facility files. 

Maintenance 

1. All Baghouse Maintenance Performed. 

2. All calibration information for baghouse control instrumentation