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 D escription .......................................................................................................... ................................... 4 Permitting Action Scope and Chronology ........................................................................................ ................... 4

TECHNICAL ANALYSES ............................................................................................................ ...................... 6 Overview of Changes ........................................................................................................... ............................... 6

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

BART Alte rnative .............................................................................................................. ............................... 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 ALTERNAT IVE VISIBILITY MODELING

APPENDIX C – INITIAL BART TIER II OPERATING PERMIT

APPENDIX D – BAGHOUSE O&M MANUALT2-2009.0105 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 ad ministrative rules in Idaho promul gated 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 NO x 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 Indust ry Classification System NESHAP National Emission Standards for Hazardous Air Pollutants NO 2 nitrogen dioxide NO x nitrogen oxides NSPS New Source Performance Standards O&M operations and maintenance OFA over-fired air PM particulate matter PM 2.5 particulate matter with an aer odynamic diameter less than or equal to a nominal 2.5 micrometers PM 10 particulate matter with an aer odynamic diameter less than or e qual 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 SO 2 sulfur dioxide SO x 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 NO x burner UTM Universal Transverse Mercator VOC volatile organic compounds Δ dv change in delta deciviewsT2-2009.0105 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 (BAR T) and revises the initial BART determinations, approves a BART Alternative, and revises associated monito ring, 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 inco rporates BART requirements from this permit. Upon the effective date of a revised RH SIP, this permit supe rsedes Tier II Operating Permit No. T2-2009.0105 issued on September 7, 2010. A chronology of events related to the revised and init ial 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 inform ation to refine BART and BART Alternative modeling results. January 11, 2011 EPA proposed approval and pr omulgation of the regional haze SIP. March 17, 2011 DEQ met with TASCO to discuss refined modeling results for re vised BART and BART Alternative.
April 12 – 14, 2011 DEQ and TASCO confirmed items necessary to comp lete an application to revise permit T2-2009.0105 and Idaho’s Regional Ha ze 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, incl uding evaluation of over-fired air feasibility and SCR cost. June 1, 2011 DEQ determined that the applicati on 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 info rmation, including boile r design information. August 22 – August 26, 2011 DEQ made available the draf t 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 draf t permit and statement of basis for facility review. September 7, 2011 DEQ received modeling input information to confirm Riley Boil er natural gas-fired modeling scenario.
September 15 – 20, 2011 DEQ received comments fro m TASCO concerning the draft permit a nd statement of basis, and baseline CO emission rate information on the boi lers in their existing configurations. September 28 – 29, 2011 DEQ provide d an updated draft permit and met wi th TASCO to discuss comments. October 19, 2011 DEQ provided an updated draft pe rmit and supporting documents to FLM and TASCO.
October 21, 2011 DEQ met with FLM to provide modeling results a nd 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 communicati ons from TASCO which provided revi sed emission data and supporting documentation.

August 31, 2006 – July 21, 2009 DEQ received several comm unications from TASCO which included concerns regarding BART technical analyses. DEQ responded to concerns and provided s upporting information, and in formed 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 Boil er 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 exem ption 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 al ternatives for consideration which could achieve greater improvements.
February 9, 2009 DEQ received a revised BART determination anal ysis report from TASCO which included additional feasible control technologies. March 11 – May 13, 2009 DEQ requested and re ceived guidance from EPA concerning evalua tion 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 que stions concerning the subject -to-BART modeling analyses. July 17, 2009 DEQ notified TASCO of the control technology selection and provided the BA RT determination analyses. July 21, 2009 DEQ received financial informati on from TASCO with a claim of confidentiality. August 18, 2009 DEQ made available the draft permit and statem ent 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 re view 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 pe riod 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 BA RT determination info rmation from TASCO.
February 22 – March 14, 2010 DEQ was provided a financial analysis and supporti ng 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 th at BART was affordable and provided the financial analysis and supporting information. March 26, 2010 DEQ made available a revised draft permit and statemen t of basis for facility review.

April 1, 2010 DEQ sent a letter to TASCO responding to concerns id entified in the BART determination letter dated November 18, 2009, and addressi ng financial hardship, modeling, and emissions reduction crediting

concerns. April 6, 2010 DEQ received comments fro m TASCO concerning the draft permit and statement of basis. Specific comments relevant to the selected BA RT control options were addressed. April 19 – May 19, 2010 DEQ provided a public comment period on th e proposed Tier II operating pe rmit and BART determination. May 19, 2010 DEQ received comment s 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 su mmary of the revisions to the initial BART Tier II operating permit and supporting analyses follows, and upda ted documentation of the complete revised BART determinations and of the approved BART Alternative in corporating the revisions di scussed below is provided in Appendix A.



### Table 3 BART AND BART ALTERNA TIVE 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 NO x (BART for NO x )
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 NO x (BART Alternative for SO 2 )

Coal-Firing LNB Control efficiency: ≥ 55% for NO x (BART Alternative for SO 2 )

Pulp Dryers (S-D1, S-D2, and S-D3) Permanent shutdown (BART Alternative for SO 2 )

BART for the control of NO x

• Following the initial BART determination, it was determin ed that SCR is not technically feasible for retrofit on the Riley Boiler. Selective catalytic reduction (S CR) is a post-combustion control device that reduces thermal and fuel NO x emissions with a reagent (generally ammoni a or urea) in the presence of a catalyst to form water and nitrogen.

• Following the initial BART determination, it was determ ined that incorporating over-fired air as part of a coal-fired low NO x burner system (LNB) is not technically feasible for retrofit on the Riley Boiler. Low NO x burners with over-fired air (LNB with OFA) utilize fuel and air mixing optimization and/or staged combustion techniques to reduce thermal NO x formation.

• Following the initial BART determination, a coal-fired low NO x burner system (LNB) has been determined to be BART for the control of NO x emissions from the Riley Boiler. Low NO x burners (without over-fired air) utilize fuel and air mixing optimization and/or st aged combustion techniques to reduce thermal NO x formation.

• Although considered initially as a BART alternative to the control of NO x emissions, the shutdown of three coal-fired pulp dryers has instead been included as pa rt of the BART Alternative to the control of SO 2 emissions.T2-2009.0105 Project 60867 Page 7 BART Alternative to the control of SO 2

• The shutdown of three coal-fired pulp dryers and the retrofit of coal-fired low NO x burner systems (LNB) on two B&W Boilers have been proposed as part of a BART Alternative to the control of SO 2 emissions from the Riley Boiler. The Pulp Dryer shutdowns will eliminate NO x , PM, and SO 2 emissions from the pulp dryers, while LNB will reduce NO x 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 SO 2 (Spray Dry FGD), which remains unchange d 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 SO 2 . (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 F GD was considered feasible. Additional information regarding these concerns is provide d 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 lim its 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, SO 2 , and NO x that were determined under Tier II Operating Perm it No. T2-2009.0105, issued on September 7, 2010.

• In this document the revised BART is defined to mean the BART determination for NO x , which is being revised by this permitting action. (The BART for PM and SO 2 have not been revised and remain the same as what was determined under Tier II Operating Perm it 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 NO x (Riley Boiler with low NO x burners), and the BART Alternative to the control of SO 2 (B&W Boilers #1 and #2 with low NO x burners and the three Pulp Dryers shut down).

• In this document the “BART” scenario is defined to mean the comb ination of BART for PM (Riley Boiler with the existing baghouse), revised BART for NO x (Riley Boiler with low NO x burners), and BART for SO 2 (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 thr ee 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 Dr yers. This scenario allows comparison of both the “BART” and “BART Alternative” scenarios against the sa me 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 pollu tant 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 n on-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 reasona bly be anticipated to result from the use of such technology. (These considerations were include d 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 Ha ze 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 techno logy (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

SO 2 , NO x , and PM emissions were the visibility-impairi ng 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 durin g the winter time. A single emission source which is responsible for a one-half (0.5) deciview change or mo re 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 th e 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 Δ dv) 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

SO 2 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

NO x 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 determ ination. The BART determination for NO x has been revised as described in this section. (b) SO 2 , NO x , and PM emissions were the visibi lity-impairing pollu tants evaluated. (c) Δ dv = delta deciviews; result is based on changes to visibility at the Ea gle 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 ope ration of the Riley Boiler (without controls). (f) Wet FGD was not determined to be effective due to non-ai r 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 adequa te residence time to achieve reliable control. (h) SCR was not considered feasible upstr eam 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 operat ing 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 manageme nt 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 combus tion residence time and to acco mmodate 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 discu ssion 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 engi neering 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 baghou se due to insufficient spa ce 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 c ooling below the effective operating temperature range of the control device.
Infeasibility of OFA As provided in Table 4, based on the results of an engi neering design review of the Riley Boiler, it has been determined that over-fired air (OFA) is not tec hnically feasible for retrofit on the Riley Boiler. 3 It was determined that insufficient vertical distance is available between th e top burner elevation and the furnace nose arch, which is necessary to provide adequate fuel combustion resi dence 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 s howing the greatest impact from the Riley Boiler - over the baseline case of no NO x controls.



### Table 5 NO X 

### 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 Ti er II Operating Permit No. T2-2009.0105, issued on September 7, 2010).



### BART Alternative

Revisions Shutdown of the pulp dryers, in combination with in stallation and operation of LNB on the B&W Boilers, has been proposed as the BART Alternative to the control of SO 2 emissions from the Riley Boiler.
The “BART Alternative” scenario is e xpected to achieve greater reasonabl e progress than the “BART” scenario because this scenario results in great er emissions reductions and in greater visibility improvements, as described below. Although this alternative primarily reduces NO x emissions, with some reduction in PM and SO 2 emissions also resulting from the pulp dryer shutdowns, the “BART Altern ative” scenario is expected to result in greater emission reductions in regi onal haze pollutants (PM, SO2, and NOx) than the “BART” scenario, and the visibility

2 “New Information on Use of Sel ective 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

8 th highest (a) Total days (b) 8 th highest (a) Total days (b) 8 th highest (a) Total days (b) 22 nd 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 8 th highest delta-deciview impact for the calendar year. (b) Total number of days in the 1-year peri od that exceeded 0.5 delta deciviews. (c) The 22 nd highest delta-deciview impact for the 3-year period. (d) Total number of days in the 3-year peri od that exceeded 0.5 delta deciviews.T2-2009.0105 Project 60867 Page 11 improvement at all Class I areas was predicted to be gr eater for the “BART Alternative” scenario – with the reduction or elimination of 41 additiona l 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 installi ng a SCR control technology for the control of NO x 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 SO 2 emissions as described above, in lieu of installing Spray Dry FGD on the Riley Boiler.

Emission Reductions

For evaluation of the “BART Alternative” scenario em ission reductions, the “BART Alternative” scenario was compared to the “BART” scenario. The “Alternative Benc hmark” scenario is included for reference to represent baseline (existing) operating conditions. As provided in the tables below, the “BAR T Alternative” scenario is expected to result in greater emission reductions in regional haze pollutants (PM, SO 2 , and NO x ) than the “BART” scenario. Refer to Appendix A for additional in formation regarding the emission reduction estimates. An increase in carbon monoxide (CO) emissions is expect ed 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 fr om this emissions increase at a later date with a separate submittal and/or permit to construct application (if applicab le). 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

SO 2 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

NO x 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) SO 2 , NO x , and PM emissions were the visibi lity-impairing pollu tants evaluated. (b) “BART” scenario includes the Riley Boiler with BART fo r the control of PM (with the existing baghouse), with BART for the control of NO x (LNB), and with BART for the control of SO 2 (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 re ductions 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

SO 2 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

NO x 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) SO 2 , NO x , and PM emissions were the visibi lity-impairing pollu tants 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 Boile rs with the BART Alternative to the control of SO 2 (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 re ductions 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 Appendi x 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 NO x , and the BART Alternative to SO 2 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 Δ dv 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 22 nd Highest Impact ( Δ dv) Impairment Contribution (Days >0.5 Δ dv) (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. SO 2 , NO x , and PM emissions were the visibilityimpairing pollutants evaluated. (b) Δ dv = delta deciviews; result is based on changes to visibility at the Ea gle 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 re ductions 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, NO x , and SO 2 (with the existing baghouse, LNB, and Spray Dry FGD), full operation of the B&W Bo ilers (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 Boile rs with the BART Alternative to the control of SO 2 (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 A lternative” 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” scenar io – with the reduction or elimination of 41 additional days expected when compared to th e “BART” scenario. The single exception was one additional day of visibility impairment and 22nd highest visibility impact of -0.017 Δ dv 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)

22 nd Highest Days
>0.5 Δ dv 22 nd Highest Days
>0.5 Δ dv 22 nd Highest Days
>0.5 Δ dv
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. SO 2 , NO x , 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. SO 2 , NO x , and PM emissions were the visibil ity-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 Bo ilers (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 Boile rs 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 di fference 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 na tural 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 Appe ndix 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 co mbustion, even when taking into account the emissions reductions resulting from BART control equipment.



### Table 10 VISIBILITY-IMPAIRI NG EMISSIONS BY FUEL

Fuel / Control Scenario PM lb/hr (a) SO 2 lb/hr (a) NO x 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 belo w, coal combustion also resulted in higher predicted visibility impacts than natural gas co mbustion, even when taking into account the emissions reductions resulting from BART control equipment.T2-2009.0105 Project 60867 Page 15 

### Table 11 VISIBILITY IMPACT S BY FUEL – EAGLE CAP (a)

Fuel / Control Scenario 22 nd Highest Impact ( Δ dv) Impairment Contribution (Days >0.5 Δ dv) (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 visibil ity 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-fi red (without controls) operating scenarios; detailed te chnical information can be found in Appendix A and Appendix B. SO 2 , NO x , and PM emissions were the visibility- impairing pollutants evaluated. (b) Δ dv = 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

22 nd Highest Days
>0.5 Δ dv
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 operat ing scenario for the Riley Boiler; detailed technical information can be found in Appendix A and Appendix B. SO 2 , NO x , 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. SO 2 , NO x , and PM emissions were the visibi lity-impairing pollu tants evaluated. As provided, the emissions and modeled visibility impact s when firing 100% natural gas were predicted to be significantly lower than when firing coal in the Riley Boiler, even when acc ounting 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, SO 2 , and NO x emissions when combusting 100% natural gas. As an operational requirement and for compliance monitoring purposes, monitoring of averag e daily feed or firing rate and hours of operation per day for each fuel has been required in lieu of complyi ng 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% na tural gas after the BART compliance date remains a voluntary “compliance option” in lieu of installing BART a nd 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 PM 10 , PM 2.5 , CO, NO 2 , SO x , and Ozone. Reference 40 CFR 81.313. 

### Tier II Operating Pe rmit (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 th e procedures of IDAPA 58.01.01.400-410.



### Title V Classificat ion (IDAPA 58.01.01.300, 40 CFR Part 70)
The operation of BART control equipmen t is not expected to change Title V applicability or classification of the facility. The facility is classified as a major facility as de fined 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 c ontained 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 boile r of more than 250 MMBtu/hr heat input, it has been classified as a designated facility as defined in I DAPA 58.01.01.006.30 and 40 CFR 52.21(b)(1)(i)(a). 

### PTC, PSD, and NSPS Applicability (IDAP A 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 app licable to this permitting action. The facility is classified as an existing major stationa ry source, because the estimated emissions of criteria pollutants and HAP have the potential to exceed major st ationary 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 determin ing 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 opera tion due date of July 22, 2016 and in a separate permit to constr uct permitting action, if applicable. The permittee is encouraged to address any applicable requirements as soon as practicable to a llow 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. Alt hough 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 emi ssion increases from the LNBs. The perm ittee has also indicated that an emission increase of any toxic air pollutant (TAP) is no t 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 equipm ent is not expected to alter the applicability of any affected source regulated by Na tional 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 equipm ent 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 discussi on 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 th is revised Tier II operating permit, EPA approval is required before the revised BART dete rminations 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 w as 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, SO 2 , NO x , 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 Retr ofit Technology (BART) requirements for regional haze visibility impairment. DEQ must submit an implementa tion 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 incl ude 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 ex istence 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 continu ous 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 visi bility which may reasonably be anticipated to result from the use of such technology. These consid erations 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 58.01.01.6 68.05, each source subject to BART is required to maintain the control equipment required and establish pro cedures to ensure such equipment is properly operated and maintained. Permit Condition 3.8 incl udes the requirement of this section. In accordance with §51.308(e)(2) and IDAPA 58.01.01.668.06, DEQ may approv e a BART alternative rather than to require sources subject to BART to install, operate, and maintain BART. The alternative measure must achieveT2-2009.0105 Project 60867 Page 18 greater reasonable progress than would be achieved throug h the installation and operation of BART. For all such alternative measures, DEQ must submit an implementa tion 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 SO 2 emissions. The resultant emissions reduction and visib ility impacts were compared with those that would result from BART for SO 2 . Documentation of BART and BART Alterna tive analyses, including an analysis of BART and the BART Alternative, the associated emissi on reductions, comparison of the BART Alternative to BART, and a determination that the BART Alternativ e achieves greater reasonable progress than would be achieved through the installation and operation of BART w as included in Section 1.3.4 of Appendix A and in Appendix B. Permit Condition 3.5 includes federally enfor ceable emission limitations for the BART Alternative. Permit Conditions 3.7, 3.11, and 4.1 in clude requirements for the installati on, 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 SO 2 emissions). The permittee proposing a BART alternative must demonstr ate that this BART alternative will achieve greater reasonable progress than would be achieved through the in stallation 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 inst allation and operation of BART for SO 2 . Refer to the BART Alternative section for additional information. The permittee proposing a BART alternativ e 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 perform ance testing, which relies upon the u se 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 perm it. With the exception of permit T2-2009.0105, which will be superseded by this permit upon approval of a revi sed RH SIP, the requirements of this Tier II operating permit do not contravene any permit cond itions in any applicable permits to construct and Tier I and Tier II operating permits (T1-050020, T2-050021, P-030062). The pe rmittee must continue to co mply 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 Perm it No. T2-2009.0105 issued September 7, 2010; the permit has been included in Appendix C for refe rence. Each instance of the BART co mpliance 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 SIP 4 as determined in accordance with IDAPA 58. 01.01.668.04 and 40 CF R 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 revi sed BART determinations, the BART Alternative, and the design, equipment, and operational informa tion 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 Altern ative requirements has been approved by EPA. Tier II Operating Permit No. T2-2009.0105 rema ins 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 incl ude 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 descrip tion of each of the boilers involved in BART and the BART Alternative.

4 Approval and Promulgati on of Implementation Plans, State of Idaho, Regional Haze State Implementation Plan and Interstate Trans port Plan, 76 FR Final

36329-36339, Final, June 22, 2011.T2-2009.0105 Project 60867 Page 19 Permit Condition 2.1 (Permit C ondition 2.1 of T2-2009.0105) This permit condition clarifies that compliance with all app licable local, state, and fede ral rules and regulations is required, in accordance with IDAPA 58.01.01.406. Permit Condition 2.2 (Permit C ondition 2.2 of T2-2009.0105) This permit condition incorporates applicable federal requireme nts 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 C ondition 2.3 of T2-2009.0105) This permit condition provides contact information for submittal of required perform ance test reports, reports, applications, submittals, and ot her 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 tes ting general provision (Permit Condition 100). Permit Condition 3.3 (Permit C ondition 3.3 of T2-2009.0105) This permit condition incorporates the BART and BART Alternative compliance d eadlines 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 BA RT Alternative are installed and operating. The permittee has requested the option to use BART Alte rnative control strategies to achieve the BART and BART Alternative emission limits (Per mit 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 langua ge in Permit Condition 3.3 inclusive of either using the approved BART and the BART Alternative, or some other DEQ-a nd-EPA-approved BART alterna tive(s). Additional BART alternative(s) will be considered and re levant 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 equipmen t (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 “complia nce option” in lieu of installing BART and BART Alternative control equipment. Operation of BART and BA RT Alternative control devices is also not required (if installed) when the Riley Boiler is fired exclusively on natural gas. Compliance with the deadline (or altern atively, compliance with firing only natural gas in the Riley Boiler as specified in Permit Condition 3.9) is ensured by comp lying with notification re quirements (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 NO x emission limits were based upon the use of coal-fired low NO x burner systems on the Riley Boiler and B&W Boilers to control NO x 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 monito ring, recordkeeping, and reporting requirements (Permit Conditions 3.14 and 3.15) . Alternatively, compliance with these emissi on limits is ensured by firing the boiler with natural gas. Permit Conditions 3.6 and 3.7 (Permit Conditi ons 3.6, 3.7, and 3.8 of T2-2009.0105) These permit conditions incorporate requirements to opera te 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 equipm ent. 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 F GD is no longer part of the BART Alternative, the requirements to install and operate these c ontrol technologies have been removed. Compliance with these requirements is ensured by comply ing 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 Cond ition 3.3 and 3.9 for a dditional 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 require d and establish procedures to ensure such equipment is properly operated a nd maintained, in accordance with IDAPA 58.01.01.668.05.
For the low NO x burners, compliance with this requirement is ensured by complying with O&M monitoring and recordkeeping requirements (Permit Condition 3.10). Fo r the existing baghouse, the permittee has requested ensuring compliance with this requirement by comply ing 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 c itation for Permit Condition 3.9 of T2-050021 will be updated during permit renewal to include IDAPA 58.01.01.6 68.05 and 40 CFR 51.308(e)(1)(v). It should also be noted that the baghouse pressure drop monitoring frequ ency 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 Ap pendix D. (Although outside th e scope of this permitting action, BART and other monitoring requirements may need to be revisited during rene wal of the Title V permit for the purposes of CAM). Permit Condition 3.9 of T2-050021: The permittee shall install, operate, calibrate, and main tain measuring device(s) to continuously monitor the pressure drop across each of th e baghouses. The pressure drop shall be recorded once per week while the boilers are in operation. In the event the measuring device becomes i noperable, it shall be repaired or replaced as soon as practicable. The records shall be maintained in acco rdance with Facility-wide Condition 2.16.

Permit Condition 3.9 This permit condition limits the Riley Boiler to the combusti on of only natural gas in the event that BART and the BART Alternative control equipment have not b een installed by the BA RT compliance deadline. The permittee has requested ensuring compliance with th is requirement by complying with existing fuel monitoring and recordkeeping requirements in Permit C ondition 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 reco rds 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 con secutive 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 th e 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 c onsecutive 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 change d. 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 a dditional information.) Permit Condition 3.10 (Permit Cond ition 3.13 of T2-2009.0105) This permit condition requires the development and docum entation of operation and maintenance procedures for the operation and maintenance of BART control equipmen t 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 Dr y FGD and over-fired air are no longer part of the BART and the BART Alternative, the requirements to monitor asso ciated indicators (slurry flow rate, adiabatic approach temperature, over-fired airflow) were no long er 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 annua l performance testing to determine PM and NO x emissions from the Riley Boiler, and to determine NO x 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 th e approved changes to the BART and BART Alternative control equipment. Because the SO 2 emissions limit is no longer included as part of the approved BART and BART Alternative emission limits, the requirements to mon itor 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 complyi ng with test monitoring, recordkeeping, and reporting requirements (Permit Conditions 3.14 and 3.15) and General Provision 6. Permit Condition 3.12 (Permit C ondition 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 expect ed 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 fr om this emissions increase at a later date with a separate submittal and/or permit to c onstruct 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 camp aign (generally the period of maximum boiler operating loads). Because CO emissions and regulatory a pplicability will be determined at a la ter 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 a pplicability determination will be availabl e 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 coal 5 which may be used (in absence of more suitable data) to determine regulatory applicability.

Permit Condition 3.14 and Permit C ondition 3.15 (Permit Conditions 3. 16 and 3.17 of T2-2009.0105) These permit conditions specify testing c onditions and require monitoring, reco rdkeeping, and reporting to ensure compliance with initial and periodic pe rformance testing requirements (Perm it 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 Alte rnative control equipment no longer include Spray Dry FGD and over-fired air, the requirements to monitor associat ed indicators (slurry flow rate, adiabatic approach temperature, over-fired airflow) were no long er 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 Cond ition 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 notificati on of the anticipated date of initial startup in accordance with General Provision 5 to ensure compliance with Permit Conditi on 3.7. Contact information was also included. Permit Condition 4.1 (Permit C ondition 4.1 of T2-2009.0105) This permit condition requires permanent shutdown of the th ree pulp dryers to comply with the BART Alternative to the control of SO 2 emissions, in accordance w ith 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 Sp ray Dry FGD adiabatic approach temperature to ensure compliance with the BART SO 2 emission limit, and monitoring of primary and over-fired air flow rates to ensure compliance with the BART NO x emission limit. Because a BART Alternative to the control of SO 2 emissions has been approved in lieu of installati on and operation of Spray Dry FGD, a nd because over-fired air is no longer included as part of the BART determination for the control of NO x emissions, these monitoring indicator requirements were no longer appli cable and have been removed. Permit Condition 3.18 was established to require subm ittal 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 Dr yer when combined with the emission increases from the LNBs. The permittee has also indicated that an emission in crease 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 insta llation and operation of BA RT and BART Alternative control equipment is not expected to alter the app licability of any emissions unit regulated by Compliance Assurance Monitoring (CAM) Part 64. Because CAM requi rements 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 require d elsewhere in the permit in accordance with IDAPA 58.01.01.668.06.c (Permit Conditio ns 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 co mpliance 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 Em issions 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 limit s in the permit (Permit Conditions 3.4 and 3.5). This permit condition was determined to be dupli cative 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. Re fer to the chronology for public comment period dates. A response to public comments document has been craf ted 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 Dr yer Project Completion”, TASCO, January 31, 2007.T2-2009.0105 Project 60867 Page 24 APPENDIX A – BART DETERMINATIONS AND BART ALTERNATIVET2-2009.0105 Project 60867 Page 25 

# Department of Environmental Quality

Amalgamated Sugar Company (TASCO) Best Available Retrofit Technology Determinations

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

## Amalgamated Sugar Company (TASCO) Best Available Retrofit T echnology 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 Se lection ......................................................................... 33 1.5.2 SO 2 BART Control Techno logy Sel ection .................................................................................... 34 1.5.3 NO x BART Control Techno logy Sel ection ................................................................................... 40 1.5.4 SO 2 BART Alte rnative ............................................................................................................. ..... 43 1.6 Natural Gas-Fired Operation ................................................................................................... 47 1.7 Conclusion .................................................................................................................... .......... 49T2-2009.0105 Project 60867 Page 27 

### 1.1 BART Background
The 1977 Clean Air Act (CAA) Amendments created Pa rt 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 th at attain the national air quality standards and provide special protec tions 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 whic h 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 fo cus 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 Na tional Parks and other Class I areas smaller amounts of degradation known as “increment” are allowed. Th e PSD program under Part C, Subpart 1 primarily focuses on emission from 1977 forward and will be fu rther discussed in the chapters on Reasonable Progress and Long Term Strategies. Visibility is called out much stronger in Part C, Subpa rt 2 and set the national goal of “the prevention of any future and the remedying of an y existing, impairment of visibilit y 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 ma intain 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 Colu mbia 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 CF R 51.308(e). As part of the July 6, 2005 rule revisions, EPA published Appendix Y guidance for th e implementation of BART. The guidance can be found beginning at 70 FR 39156 (July 6, 2005). In the spring of 2006, the Department of Envi ronmental 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 foundT2-2009.0105 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 pro cess 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 “c ontributing” 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 specifi c 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 identif ied 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 cau sing or contributing to visibility impairment is done through modeling. An y BART-eligible facility with an impact of one deciview is considered “causing” visibility impairme nt, 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 require d 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 cat egories, was built between 1962 and 1977, and annually emits more than 250 tons of a haze-caus ing 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 (SO 2 , 2,770 T/yr), nitrogen oxide (NO x , 1,708 T/yr), and particulate matter (PM, 55 T/yr), so this emission unit was eligible for incl usion 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 extinc tion, such that uniform changes in haziness correspond to unifor m incremental changes in perception across the entire range of conditions—from pristine to highly-impa ired. A deciview is the minimum percept ible 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 Guide lines for Best Available Retrofit Technology (BART) Determinations contained in 40 CF R Part 51, Appendix Y, a source is considered to contribute to visibility impairment if the modeled 98 th 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 rule making with industry, federal land management agencies, DEQ and the public that the “contribute” threshold for a singl e source would be established at 0.5 deciviews. (See IDAPA 58.01.01.668.02.b.) As suggested in Append ix 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 Stat e Department of Ecolog y and Oregon Department of Environmental Quality contracted with Geomatrix Consultants to develop CALMET datasets to use for the CALPUFF BART modeling. The CALMET datasets we re 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—u sed in the CALPUFF modeling. METSTAT pairs the MM5 forecasted data with meteorological observa tions and then performs various statistical manipulations and aggregates the results for output. 10
Subject-to-BART analysis results for the TASCO Ri ley Boiler, Nampa are shown in Table 1, which highlights the following two threshold values for BART:

• 8th highest value for each of the years modele d (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 th e Application of the CALPUFF M odeling System Pursuant to the Best

Available Retrofit Technology (BART) Regulation.

9 Modeling Protocol for BART CALMET data sets, Idaho Oregon and Washington, Geom atrix Consultants Inc., July 12, 2006.

10 INITIAL METSTAT REPORT CALMET Fields for BART Id aho, Oregon and Washington, Geomatrix Consultants.T2-2009.0105 Project 60867 Page 30 These findings were based on the emission rates and othe r 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 Compa red to 20% Best Days Natural Background Condition

In conclusion, the CALPUFF model predicted that em issions from the Riley Boiler at the TASCO Nampa Factory impacted visibility with the 98 th percentile highest delta-deciview impact of more than 0.5 deciview on the Class I areas of Eagle Cap Wildern ess, 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 da ys 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 fro m the Riley Boiler of the TASCO Nampa Factory are SO 2 and NO 2 , 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 Rile y 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 Cl ass I areas identified in the Subject-to-BART analysis changed slightly in the fina l 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

8 th highest (a) Total days (b) 8 th highest (a) Total days (b) 8 th highest (a) Total days (b) 22 nd 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 8 th highest delta-deciview impact for the calendar year. (b) Total number of days in the 1-year peri od that exceeded 0.5 delta deciviews. (c) The 22 nd highest delta-deciview impact for the 3-year period. (d) Total number of days in the 3-year peri od 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 emissi on 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 c ontrol equipment in use or in existence at the source, the remaining useful life of the source, a nd 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 SO 2 emissions, and a low NO x burner system (LNB) with over-fired air for the control of NO x emissions. BART emission limits, a BART alternative to the control NO x , 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 informati on 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 determina tions and the approved BART Alternative. The specific revisions to BART and to the BART Altern ative, along with the supporting technical analyses, regulatory review, and a discussion of the revised perm it conditions has been provided in the Statement of Basis to Tier II Operating Permit No. T2-2009.0105, Project 60867.

The initial BART determinations ma de under T2-2009.0105 i ssued September 7, 2010 have been revised based on engineering design information specific to the Riley Boiler retrofit project. A summary of the revised BART determinati ons 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 Δ dv) 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. Th e BART determination for NOx has been revised as described in this section. (b) SO 2 , NO x , and PM emissions were the visibi lity-impairing pollu tants evaluated

. (c) Δ dv = delta deciviews; result is based on changes to visibility at the Ea gle 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 base d 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 ope ration 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 ups tream of the baghouse due to insuffici ent space necessary to accommodate the control device, in addition to c oncerns regarding catalyst fouling a nd 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 par ticulate 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 pl ant operations. DEQ reviewed the information as provided below: Existing Baghouse - The existing baghouse efficiently redu ces PM to very low levels. Measured PM emissions are 0.036 lb/MMBTU, well below the previous ly proposed industrial boiler MACT standard of 0.07 lb/MMBTU. Control efficiencies for baghouses are re ported 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 c ould 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 pl ates 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, th e control efficiency was assumed to be 99%. Because of physical space limitations, the installa tion 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 pr otect 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 efficien cy 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 estimat es, 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 remova l 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 b est 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 additi onal 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 re moval efficiency there was no merit in modeling specifically for the particulate control scenarios.

1.5.2 SO 2 BART Control Technology Selection In determining the “best” BART control technology for sulfur dioxide (SO 2 ) 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 pl ant 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 usi ng 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 SO 2 at the liquid/gas surface boundary. The reacti on 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 saturat ed with water vapor and can present a visible steam plume from the stack. Wet FGD systems offer one of the highest SO 2 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 duri ng 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 th e 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 syst em 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 up stream of a particulate removal device (usually an electrostatic precipitator or baghouse). The reactor cons ists of a spray dryer absorber tower and support equipment. Flue gas is introduced into a vessel a nd 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 SO x 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 effici ency of the reactor increases as the exit flue gas temperature approaches the adiabatic saturation temperat ure 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 effici ency 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 r esult of installing a spray dryer. In addition to the ash entering the reactor with flue gas, the spent lim e would contribute to overall particulate loading. Approximately 60% of the formed solids are predicte d to drop out in the reactor while 40% would be carried to the baghouse for removal. The increase in pa rticulate 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 h as 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 re lated to the disposal of byproducts generated in the operation of this technology, an d 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 gr eater 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 reporte d 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 & Ti er II Application”, TASCO, May 4, 2011; and “FW: Attached 2 f iles for DEQ Emailing...”, TASCO, October 27, 2011.T2-2009.0105 Project 60867 Page 37 

### Table 5 Technical Feasibility of SO 2 

### Controls

Pollutant Technology Feasibility Reason Not Feasible

SO 2 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, an ticipated 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 SO 2 

### 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)

SO 2 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 contro l 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 SO 2 

### 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 $6,940T2-2009.0105 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 re garding the wastewater treatment process. It’s not immediately clear that the costs of the wastewat er 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 difficu lt to speculate about the volume of wastewater that might be produced, or any constituent concentrati ons in wastewater from the process. The source and composition of (1) the coal fired in the boiler, a nd (2) the limestone used in the Wet FGD process will largely dictate the constituents and constituent concentra tions 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 cal cium sulfate (i.e., gypsum), scaling is a major issue with operation and maintenance of pr ocess units and piping. The wastewater will also be hot, somewhat acidic, and will have high levels of total dissolved so lids. 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 perm itting 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 produc t 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 a nd more oversight required. The potential volume and quality of the final, treated effluent is very difficu lt to speculate about without knowing more about the wastewater that will be produced by the Wet FGD pro cess 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 improve ments 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 syst em. This could mean that the City would need to expand its treatment system or that TASCO might look to land application to ma nage the new wastewater
stream. TASCO does still have a wastewater land application pe rmit with DEQ, but the facility has only utilized land application for a very small fraction of its tota l 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 to tal WW generated), and no wastewater was land applied in the 2008 season. As a result of this reduc tion in land applied wast ewaters, 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 sta ndards 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 dedi cated staff to operate and maintain. Additionally, the reduction in wastewater land application in recent years has im proved 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 mon itoring/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 SO 2 controls. 

### Table 8 Visibility Improvement of SO 2 

### Controls - Change in Visibility Impacts Comp ared to 20% Best Days Natural Background Condition

Since TASCO believed running the CALPUFF modeli ng for the various control technology scenarios would be costly, DEQ performed the CALPUFF mo deling in-house and invited TASCO to have a contractor review the modeling if deemed necessar y. 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 determ ine 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

8 th highest (a) Total days (b) 8 th highest (a) Total days (b) 8 th highest (a) Total days (b) 22 nd 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

SO 2 Control Scenario 1 Lower Sulfur Coal (wzi10475) 0.682 15 1.016 39 1.028 36 1.014 90

SO 2 Control Scenario 2 Dry Lime Injection (wzi10476) 0.586 9 0.814 28 0.806 29 0.806 66

SO 2 Control Scenario 3 Dry Trona Injection (wzi10477) 0.565 9 0.764 24 0.739 25 0.761 58

SO 2 Control Scenario 4 Spray Dryer FGD (wzi10478) 0.527 9 0.703 22 0.707 20 0.686 51

SO 2 Control Scenario 5 Wet FGD (wzi10479) 0.499 7 0.647 19 0.645 17 0.638 43

a) The 8 th highest delta-deciview imp act for the calendar year. b) Total number of days in the 1-year period that exceeded 0.5 delta deciviews. c) The 22 nd 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 qualit y environmental concerns are to be taken into consideration. Although Wet FGD has a 15% greater rem oval efficiency over the next closest control of Spray Dry FGD, the potential for reversing the curre nt trend of improvements to ground water due to TASCO land applying outweigh the environmental be nefits. 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 hand le. This would more than likely lead to TASCO requesting to increase land application of waste wate r. 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 NO x BART Control Technology Selection In determining the “best” BART control technology for nitrogen oxides (NO x ) 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 fo llowing control technologies appropriate for boilers:

• Low NO x Burners (LNB)

• Low NO x Burners with Over-fired Air (LNB/OFA)

• Ultra Low NO x 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 pl ant operations. DEQ reviewed the information as provided below:

Low NO x Burners - LNBs incorporate staged fuel or stag ed combustion air to control the flame temperature of the boiler. Several low NO x burner systems are available with different levels of cost and performance capabilities. A guaranteed NO x removal efficiency of 60.7% for the Riley Boiler was provided by the vendor.

Low NO x 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 NO x . Over-fired air as a standalone retrofit technology can be difficult to control causing combustion issues with pulverized coal boiler, including water wall corrosi on and reduced boiler efficiencies. When combined with a low NO x burner and reasonable combustion air control, NO x removal efficiencies can approach 65%. In the initial BART determination (as described in th e Statement of Basis to Tier II Operating Permit No. T2-2009.0105, issued September 7, 2010), it was de termined based on technical analyses that low NO x burners with over fired air were technically feasible. However, based on the r esults 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 NO x Burners – These systems are upgraded LNB designs which involve further control and staging of combustion air and fuel. ULNB was determ ined 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 NO x by injecting ammonia and urea into the flue gas before it passes through a catalytic grid to reduce the NO x to N 2 . 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 treat ment, heat is recovered in a heat exchanger to minimize operating costs to reheat the flue g as. This technology is capable of reducing NO x emissions by 70% to 90%. For the purposes of this evaluati on a control efficiency of 90% was assumed. In the initial BART determination (as described in th e 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 insufficien t space necessary to accommoda te the control device, in addition to concerns regarding catalyst foulin g and erosion. SCR was not considered feasible downstream of the baghouse due to exhaust gas coo ling below the effective operating temperature range of the control device. Selective Non-Catalytic Reduction (SNCR) – SNCR consists of inj ecting 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 ec onomizer and the air pre-heater. The process relies on good gas mixing in the narrow high temperature zone to reduce NO x to N 2 as the flue gas moves through the ductwork. Boiler load swings can lead to temper ature changes at the injec tion that can significantly reduce removal efficiencies. In addition, injection points can lead to “ammonia slip” or the condition where unreacted ammonia passes through downstream e quipment, including the baghouse and discharges from the stack. The gas path for the Riley Boiler lack s the necessary residence time to reliably remove the NO x . The results of upsets could lead to “ammonia slip.”
This information is summarized in Table 9, below. 

### Table 9 Technical Feasibility of NO x 

### Controls

Pollutant Technology Feasibility Reason Not Feasible

NO x Low NO x Burners Yes None

Low NO x with Over-Fired Air No Insufficient vertical distance between the top burner elevation

and the furnace nose arch to support OFA system.

Ultra NO x 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 Sel ective 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, an ticipated 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 NO x 

### 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)

NO x Low NO x Burners 374 1,042 60.7% 147 410

Step 4 – Impact Analysis

The use of low NO x burners was the top feasible control technology for minimizing NO x 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 modeli ng for the various control technology scenarios would be costly, DEQ performed the CALPUFF mo deling in-house and invited TASCO to have a contractor review the modeling if deemed necessar y. 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 determ ine the modeling inputs for each of the scenarios. 

### Table 11 Visibility Improvement of NO x 

### 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

8 th highest (a) Total days (b) 8 th highest (a) Total days (b) 8 th highest (a) Total days (b) 22 nd 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 8 th highest delta-deciview impact for the calendar year. (b) Total number of days in the 1-year peri od that exceeded 0.5 delta deciviews. (c) The 22 nd highest delta-deciview impact for the 3-year period. (d) Total number of days in the 3-year peri od that exceeded 0.5 delta deciviews.T2-2009.0105 Project 60867 Page 43 1.5.4 SO 2 BART Alternative In addition to the control technologies reviewed, TA SCO 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, SO 2 , and NO x that were determined under Tier II Oper ating Permit No. T2-2009.0105, issued on September 7, 2010.

• In this document the revised BART is defined to mean the BART determination for NO x , which is being revised by this permitting action. (The BART for PM and SO 2 have not been revised and remain the same as what was determined under Ti er 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 NO x (Riley Boiler with low NO x burners), and the BART Alternative to the control of SO 2 (B&W Boilers #1 and #2 with low NO x 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 NO x (Riley Boiler with low NO x burners), and BART for SO 2 (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 a nd #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 ope rational changes at the facility after the regional haze base years of 2000-2004. In 20 06, TASCO installed a new pulp steam dryer system which better utilized current steam produc tion 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 shutdow n of the pulp dryers is provided in Table 13. As part of the impact and visibility improve ments TASCO requested that DEQ evaluate the visibility improvements resulting from the pul p 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 propo sed 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 (SO 2 ) 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 vi sibility-impairing pollutants evaluated. (b) “BART” scenario includes the Riley Boiler with BART for th e control of PM (with the ex isting 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 th ree pulp dryers. This control scenario re presents BART as de scribed in the BART Determinations section. (c) “Alternative Benchmark” includes the R iley Boiler (with the existing baghouse), fu ll operation of the B&W Boilers (without LNB), and full operation of the three pulp dryers. Estimated em ission 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

SO 2 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

NO x 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 vi sibility-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 (L NB), 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 cont rol 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 th e three pulp dryers. Estimat ed 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” scenar io emission reductions, the “BART Alternative” scenario was compared to the “BART” scenario in Ta ble 13 and Table 12, respectively. As provided in these tables, the “BART Alternative” scenario is exp ected 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 temperatur es, 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” s cenario 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 ( Δ dv) Impairment Contribution (Days >0.5 Δ dv) (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-impairi ng pollutants evaluated. (b) Δ dv = delta deciviews; result is based on changes to visibility at the Ea gle 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 th e three pulp dryers. Estimat ed 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 operati on 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 (L NB), 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 cont rol 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” scenar io. Refer to Appendix B for additional information regarding these modeling scenarios. Based on CALPUFF modeling, the highest modeled visi bility 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 minimu m 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 revi sed BART (as summarized in Table 8).T2-2009.0105 Project 60867 Page 47 

### Table 15 “BART Alternative” S cenario Visibility Improvement

Class I Area (a) “BART”(b) “BART Alternative”(c ) Difference in Improvements (d)

22nd Highest Days
>0.5 Δ dv 22nd Highest Days
>0.5 Δ dv 22nd Highest Days
>0.5 Δ dv
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. SO 2, 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 operati on 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 (L NB), 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 cont rol 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 r esults in greater emissions reductions and in greater visibility improvements. DEQ is therefore approving the co mbination of the pulp dryer shutdowns and the installation and operation of low NO x burners on the B&W Boilers as an alternative to BART for the control of SO 2 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 re quirement to operate Riley Boiler BART control equipment only when firing coal in the Riley Boile r. Modeling of fuel operating scenarios was completed using the same protocol as described in Appendix B (t his 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 be low, 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 combus tion, 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 ( Δ dv) Impairment
Contribution (Days >0.5 Δ dv) (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 visi bility impacts for the Riley Boil er 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 inform ation can be found in Appendix A and Appendix B. SO2, NOx, and PM emi ssions were the visibili ty-impairing pollutants evaluated. (b) Δ dv = 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 Δ dv
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 fo r the natural gas-firing operating scenario for the Riley Boiler; detailed t echnical 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 R iley Boiler. SO2, NOx, and PM emissions were the visibility-impairing po llutants evaluated. As provided, the emissions and modeled visibility im pacts 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 ofT2-2009.0105 Project 60867 Page 49 BART controls. It was therefore considered reas onable 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 t echnologies. 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 a ll 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 be en 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, notif ication, 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 ALTERNAT IVE 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, a nd has proposed a BART Alternative. The revised BART includes Spray Dr y Flue Gas Desulfurizat ion (Spray Dry FGD) for sulfur dioxide (SO 2 

### ) control, Low NO x 

### burners (LNB) for nitrogen oxides (NO x 

### ) 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 SO 2 

### , NO x 

### and PM emission reductions from shutting down 3 pulp dryers. This report describes new modeling to assess the resulti ng 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 Paci fic Northwest. In order to compare the BART Alternative impacts with the sel ected BART control scheme on th e 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 fo r the Riley boiler (LNB) along with emissions from the other emission sources (B&W Boilers a nd 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 22 nd 

### 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 area s combined over the three-year modeling period.

Although the “BART Alternative” scenario reduces the larg est visibility impacts during the winter when both modeled and monitored re gional haze impacts were highest, the shift from SO 2 

### control to additional NO x 

### control will also result in a slightly greater visibility impairment in the best visibility months of March – June when sulfate dominates the re latively clear air at the Starkey IMPROVE site, representing Eagle Cap and Strawberry Mount ain wilderness areas. However, this impairment from the BART Alte rnative in the non-winter months is small in comparison to the visibility benefits projected in the winter months, a nd it is clear that the proposed BART Alternative produces greater re ductions on more high-impact days than the “BART” scenario, and is ther efore a preferred approach for reducing regional haze.

In addition to the greater visibility improve ments, the BART Alternative provides greater ozone mitigation benefits by more than doubling the NO x 

### 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 no n-attainment status may bring and the potential restrictions that the region could incur in the areas of i ndustrial 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 NO x 

### and approval of a BART Alternative to control visibility-impairin g pollutant emissions from the Riley Boiler at their Nampa Factory. The BART determinations (as revised) include Spray Dry Flue Gas Desulfurization (Spray Dry F GD) for sulfur dioxide (SO 2 

### ) control, Low NO x 

### burners (LNB) for nitrogen oxides (NO x 

### ) control, and a baghouse for particulat e matter (PM) control. The proposed BART Alternative replaces th e Spray Dry FGD with a) LN B controls on two (non-BART) Babcock and Wilcox (B&W) boilers, and b) SO 2 

### , NO x 

### and PM emission reduction credits for shutting down 3 pulp dryers. Modeling results docume nting the visibility impacts of the revised BART and the proposed BART Alte rnative along with an Alternative Benchmark scenario are described in this report. The benchmark scen ario provides a common pr e-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 Altern ative 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 degrada tion at the Class I areas where the impacts occur. The modeling summarized in this memo involves the following s cenarios, with computer runs identified by run identification numbers:

“BART” Modeling Scenario This scenario, (Run ID wzI10495) includes Rile y 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 t echnology involving only the Riley Boiler, while “BART” (with quotations) refers to this modeli ng scenario, which includes the other affected emission sources:

• Riley Boiler with existing baghous e, Spray Dry FGD, and LNB

• B&W Boilers #1 and #2 (benchmark emissi ons of sources affected by the BART Alternative)

• Pulp Dryers, full operation (benchmark emi ssions of sources affected by the BART Alternative)

“BART Alternative” Modeling Scenario This scenario (Run ID wzI10493) includes the BART NO x 

### controls on the Riley boiler, along with Low-NO x 

### burners on two other non-BART Babc ock and Wilcox (B&W) boilers. The B&W NO x 

### controls along with credits for shutting down three pulp dryers, is proposed by TASCO as an alternative for SO 2 

### control using Spray-Dry FGD.

• Riley Boiler with ex isting 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 benchm ark or pre-BART emissions from the Riley Boiler and the other sources affected by the BA RT Alternative scenari o. It provides a common benchmark for comparison of the “BART” and “B ART 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 a nd 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 disper sion modeling system to determine the delta-deciview ( Δ dv) visibility impacts, the numbe r of days per year above the 0.5 Δ dv threshold, and the number of days per the three–year pe riod above the 0.5 Δ dv threshold. The modeling was performed in accordance with the BART Modeling Protocol 1 

### , which was jointly developed by the states of Idaho, Washi ngton, and Oregon, and which has undergone public, Federal Land Manager (FLM) and EPA review and a pproval. 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 computat ional domains for the Nampa Factory are shown in Figure 1 along with th e source location (red dot ) and the Class I areas (red with black outlines) within 300 km of the source. Class I ar eas included in this analysis and identifying abbreviations used in Figure 1 are shown in Ta ble 1. The Class I areas ar e primarily wilderness areas managed by the United States Forest Servi ce, with the exception of Craters of the Moon Wilderness Area, managed by the National Park Se rvice. None of the Class I areas within 300 miles of Nampa are managed by the Unite d 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) Se lway-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 anal ysis 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 E nviron International) und er 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 thr ee-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 specia tion was estimated using National Park Service particulate speciation spreadsheets for dry bottom pulverized coal-f ired boilers with and without Spray Dry FGD. 4 

### The resulting speciated emissions of direct particulate matter emi ssions can be seen in Table 3. Note, the sulfate (SO 4 

### ) in Table 3 is shown as (and i nput to CALPUFF) as pounds per hour SO 4


### . However, when totaling the ae rosol species under “Total PM 10 

### ” it is converted to a stoichiometric equivalent mass of ammonium sulfate ((NH 4 

### ) 2 

### SO 4 

### ), since this is the form it assumes in the ambient air, and the ma ss 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 PM 10 , http://www.nature.nps.gov/air/Permits/ect/ectCoalFiredBoiler.cfm7Table 2 Source Locations and Stack ParametersUnit BART Control EquipmentEasting(m)Northing(m)Elevation(m)StackHeight(m)StackDiameter(m)Stack ExitTemperature(K)Stack ExitVelocity(m/s)Stack Parameters for “Alternative Benchmark” Scenario (Run ID wzI10492)Riley BoilerExisting Baghouse534.4064828.03175374.73.35445.912.0B&W 1&2(n/a)534.4064828.03175374.73.35445.912.0South Pulp Dryer(n/a)534.4134828.08775323.53.017348.54.9Center Pulp Dryer(n/a)534.4134828.099753213.017353.47.0North Pulp Dryer(n/a)534.4154828.10675327.72.13346.46.3Stack 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 11.2B&W 1&2 LNB (Each 55% Control) 534.406 4828.031 753 74.7 3.35 445.912.0South Pulp Dryer (n/a) 534.413 4828.087 753 23.5 3.017 348.5 4.9Center Pulp Dryer (n/a) 534.413 4828.099 753 21 3.017 353.4 7.0North Pulp Dryer (n/a) 534.415 4828.106 753 27.7 2.13 346.4 6.3Stack Parameters for “BART Alternative” Scenario (Run ID wzI10493)Riley BoilerLNB (60.7% Control)534.4064828.03175374.73.35440.011.7B&W 1&2LNB (Each 55% Control)534.4064828.03175374.73.35440.011.78Table 3 Emission Rates used in CALPUFF Modeling(a)Unit Control EquipmentSO2lb/hrSO4lb/hrNOXlb/hrHNO3lb/hrNO3lb/hrPMClb/hrPMFlb/hrEClb/hrSOAlb/hrTotalPM10lb/hr(b)Emissions from all Sources in Alternative Benchmark Scenario (Run ID wzI10492)Riley BoilerExisting Baghouse522.36.7373.8000.50.502.312.5B&W 1&2(c)(n/a)435.030.7227002.12.1010.556.9South Pulp Dryer(n/a)7.50.0180.200.01031.305.336.6Center Pulp Dryer(n/a)7.50.0180.200.01031.305.336.6North Pulp Dryer(n/a)2.90.0130.800.01014.205.319.5“Alternative Benchmark” Scenario Totals:975.137.4379200.032.679.4028.7162.2Emissions 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 0 1 5.9B&W 1&2(c)Existing Control, B&W Boilers 1&2 435 30.7 227 0 0 2.1 2.1 0 10.5 56.9South Pulp Dryer (n/a) 7.5 0.01 80.2 0 0.01 0 31.3 0 5.3 36.6Center PulpDryer(n/a) 7.5 0.01 80.2 0 0.01 0 31.3 0 5.3 36.6North Pulp Dryer (n/a) 2.9 0.0130.8 0 0.01 0 14.2 0 5.3 19.5“BART” Scenario Totals:556.8 33.5 565.2 0 0.03 2.6 79.4 0 27.4 155.5“BART Alternative” Emissions after Implementation (Pulp Dryers shut down) (Run ID wzI10493)Riley BoilerLNB (60.7% Control)522.36.7147000.50.502.312.5B&W 1&2(c)LNB (Each 55% Control)43530.7103002.12.1010.556.9“BART Alternative” Scenario Totals:957.337.4250002.62.6012.869.4(a)Pollutant emissions for sulfur dioxide (SO2), Nitrogen oxides (NOx= NO + NO2), nitric acid (HNO3) and speciated particulate matter species (SO4), particulate nitrate(NO3), coarse particulate matter 2.5 – 10μm in aerodynamic diameter (PMC), fine particulate matter < 2.5μm in diameter (PMF), elemental carbon (EC), secondary organicaerosol (SOA), and total particulate matter 10μm and less in aerodynamic diameter (PM10).(b)Total PM10is not used directly in the model but represents total of PM species for information only. SO4is added into total PM10as ammonium sulfate (SO4lb/hr x(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 tothe Riley Boiler

### 9 

### BART Alternative Modeling Results

“BART” and “BART Alternativ e” Model Detailed Results Detailed model results showing re gional haze impacts at all seven Class I areas within 300 km of the source are summarized for the “BART” scenar io in Table 4, and for the “BART Alternative” scenario in Table 5. It is important to em phasize 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 Alterna tive, 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 summar ized in Table 6 to facilitate comparisons. In its 2005 BART guidelines, EPA de termined that a source whose 98 th 

### percentile daily average haze impact (haze index) is grea ter than 0.5 deciview above natu ral background is considered to contribute to regional haze. Impacts above 1.0 deci view are considered to cause regional haze impacts. By selecting the 98 th 

### percentile, the top 7 days in any y ear, or top 21 days in three years, EPA intended to minimize the effects of extr eme meteorology and conservative assumptions. Table 4 and Table 5 highlight the two averaging periods generally used in BART modeling analyses:

• 

### 8 th 

### highest Δ dv value for each of the years modeled (2003-2005), representing the 98th percentile (8/365 = 0.02) cutoff for Δ dv in the each year. In addition the numbers of days in each year above the 0.5 Δ dv threshold are shown.

• 

### 22 nd 

### highest value for the entire period from 2003 through 2005, representing the 98th percentile (22/1095 = 0.02) cutoff for Δ dv over three years. In addition the numbers of days in all three years above the 0.5 Δ dv 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” (>0.5 Δ dv) 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 facil ity, 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 0.5 Δ dv threshold at all sites. Figure 2 clearly shows that the model-predicted visi bility impacts at Eagle Cap (due to the existing Riley boiler) were highest in the wint er 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 ap pear to exceed the 0.5 Δ dv threshold for a 98 th 

### percentile day “contributing” to a haze at a Clas s I area. Since this frequency (3 days in 660) represents only 0.45% of the non-winter days, it suggests that th e Riley boiler does not “c ontribute” to the haze impacts, at the level defined by EPA, outside of the October – February period. However it does “cause” haze impacts (>1 Δ dv) 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 us eful to examine how model results behave in comparison to monitored aerosol ex tinction at IMPROVE monitoring s ites. For this purpose, it is useful to understand how light ex tinction is determined from aeros ol species concentrations and

### 10 how extinction relates to the “h aze index” or changes in visi bility relative to the background visibility in terms of delta deciviews ( Δ dv). Light extinction (b ext) 

### is computed from aerosol species concentrations and reported in units of reciprocal megameters (Mm -1 

### ) according to the equation:

b ext = 3 f(RH) [(NH 4 ) 2 SO 4 ] + 3 f(RH) [NH 4 NO 3 ] + 4[OC] + 1[Soil] + 0.6[Coarse Mass] + 10[EC] + b Ray 

### (Eqn 1)
Equation 1 applies to either measured or modeled aerosol concentrations, where:
f(RH) are monthly averaged relative humidity coefficients, specifica lly tabulated for each Class I area each month, b Ray 

### is Raleigh scattering due to air molecules, Mm -1 [(NH 4 ) 2 SO 4 ] is the ammonium sulfate concentration formed from SO s , μg/m 3 [NH 4 NO 3 ] is the ammonium nitrate concentration formed from NO x , μg/m 3 [OC] is the organic carbon concentration, μg/m 3 (equivalent to “SOA” in 

### Table 3 ) [Soil] is the fine geologic particulate matter, μg/m 3 (equivalent to “PMF” in 

### Table 3 ), [Coarse Mass] is the coarse particulate matter, μg/m 3 (equivalent to “PMC” in 

### Table 3 ), and [EC] is the elemental carbon, μg/m 3



### Light extinction is not measured directly at IMPR OVE sites, but is calculated based on aerosol measurements of the species in Equation 1. In th is 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 IMPROV E monitoring program. When source emissions are modeled to estimate light extinction impact s resulting from those emissions, the resulting b ext (source) 

### is compared to background extinction, b ext (bkg), 

### to predict the haze index in terms of delta-deciviews:

Δ dv = 10 ln [ ( b ext (bkg) 

### + b ext (source) 

### ) / ( b ext (bkg) 

### ) ] (Eqn 2)
A time series view of 2004 light extinction ba sed 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 visibi lity impacts and that the January 2004 stagnation episode produced the greatest monitored and mo deled 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 hi ghest 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) show s a reduction in the three-year 22 nd 

### highest Δ dv of 0.689 Δ dv at Eagle Cap, the most impacted area, and 0.119 Δ dv at Jarbidge Wilderness, the least impacted area. Similarly, the number of days in three year s above the 0.5 Δ dv threshold at Eagle Cap decreases from 195 days to 149 days, a 46 day reduc tion, while Jarbidge is projected to see only a three day reduction. The sum of days in 3 years above 0.5 Δ dv at all seven Class I areas decreases from 455 days for the Alternative Benc hmark 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 A lternative” scenario in comparison to the “Alternative Benchmark” scenario (Table 5) shows a reduction in the three-year 22 nd 

### highest Δ dv at Eagle Cap from 2.201 to 1.411 Δ dv, a visibility improvement of 0.790 Δ dv. The number of days in the three-year period above the 0.5 Δ dv threshold at Eagle Cap decreases from 195 days to 126 days, a 69 day reduction, while Jarbidge is projected to see a thr ee day reduction, identical to the “BART” scenario. The sum of days above 0.5 Δ dv at all the Class I areas combined drops from 455 for the “Alternative Benchmark” scenar io to 275 days for the “BART Alternative” scenario, a reduction of 180 days. A very small visibility degr adation appears at Selway-Bitterroot Wilderness Area.12Table 4 Summary of Visibility Impacts for TASCO-Nampa "BART" ScenarioClass IAreaOperating ScenarioChange in Visibility Compared Against 20% Best Days (Natural Background)Δdv larger than 0.5 from one year periodΔdv > 0.5 over 3 yr2003 2004 2005 2003-20058thhighΔdv(a)Days >0.5Δdv(b)8thhighΔdv(a)Days >0.5Δdv(b)8thhighΔdv(a)Days >0.5Δdv(b)22ndHighest(c)Total Days(d)>0.5Δdv

Eagle Cap Wilderness, OR“Alternative Benchmark” (wzI10492)1.611482.212722.178752.201195“BART”(e)(wzI10495)1.103301.551551.509641.512149Visibility Improvement(f)0.508180.661170.669110.68946

Craters of the Moon NM Wilderness, ID“Alternative Benchmark” (wzI10492) 0.336 1 0.407 6 0.318 3 0.393 10“BART”(e)(wzI10495)0.239 0 0.273 3 0.233 1 0.267 4Visibility Improvement(f)0.097 1 0.134 3 0.085 2 0.126 6

Hells Canyon Wilderness ID/OR“Alternative Benchmark” (wzI10492)1.269271.693511.515511.582129“BART”(e)(wzI10495)0.884201.163321.049351.09287Visibility Improvement(f)0.38570.530190.466160.49042

Jarbidge Wilderness, NV“Alternative Benchmark” (wzI10492) 0.275 1 0.379 3 0.420 4 0.375 8“BART”(e)(wzI10495) 0.192 1 0.256 2 0.278 2 0.256 5Visibility Improvement(f)0.083 0 0.123 1 0.142 2 0.119 3

Sawtooth Wilderness, ID“Alternative Benchmark” (wzI10492)0.47070.51980.43530.47018“BART”(e)(wzI10495)0.34020.34940.29300.3196Visibility Improvement(f)0.13050.17040.14230.15112

SelwayBitterroot Wilderness, ID“Alternative Benchmark” (wzI10492) 0.317 0 0.587 8 0.492 7 0.439 15“BART”(e)(wzI10495) 0.212 0 0.387 1 0.327 2 0.281 3Visibility Improvement(f)0.105 0 0.200 7 0.165 5 0.158 12

Strawberry Mountain Wilderness, OR“Alternative Benchmark” (wzI10492)1.419180.882222.308401.46280“BART”(e)(wzI10495)0.987130.644151.677341.07662Visibility Improvement(f)0.43250.23870.63160.38618All AreasReduction in Total Days > Δdv, all Class I Areas Combined2003: 36 2004: 58 2005: 45 3-Yr: 139(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 controlsplus the pre-BART emissions of the B&Wboilers 1&2 and three pulp dryers so that theresults 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.13Table 5 Summary of Visibility Impacts forTASCO-Nampa “BART Alternative” ScenarioClass I AreaOperating ScenarioChange in Visibility Compared Against 20% Best Days (Natural Background)Δdv larger than 0.5 from one year periodΔdv > 0.5 over 3 yr2003 2004 2005 2003-20058thhighΔdv(a)Days >0.5Δdv(b)8thhighΔdv(a)Days >0.5Δdv(b)8thhighΔdv(a)Days >0.5Δdv(b)22ndHighest(c)Total Days(d)>0.5Δdv

Eagle Cap Wilderness, OR“Alternative Benchmark” (wzI10492)1.611482.212722.178752.201195“BART Alternative” (wzI10493)0.921221.434491.469551.411126Visibility Improvement(e)0.690260.778230.709200.79069

Craters of the Moon NM Wilderness, ID“Alternative Benchmark” (wzI10492) 0.336 1 0.407 6 0.318 3 0.393 10“BART Alternative” (wzI10493) 0.230 0 0.260 2 0.200 1 0.245 3Visibility Improvement(e)0.106 1 0.147 4 0.118 2 0.148 7

Hells Canyon Wilderness ID/OR“Alternative Benchmark” (wzI10492)1.269271.693511.515511.582129“BART Alternative” (wzI10493)0.758171.173311.044321.05980Visibility Improvement(e)0.511100.520200.471190.52349

Jarbidge Wilderness, NV“Alternative Benchmark” (wzI10492) 0.275 1 0.379 3 0.420 4 0.375 8“BART Alternative” (wzI10493) 0.193 1 0.252 2 0.251 2 0.234 5Visibility Improvement(e)0.082 0 0.127 1 0.169 2 0.141 3

Sawtooth Wilderness, ID“Alternative Benchmark” (wzI10492)0.47070.51980.43530.47018“BART Alternative” (wzI10493)0.26810.34040.27810.3076Visibility Improvement(e)0.20260.17940.15720.16312

SelwayBitterroot Wilderness, ID“Alternative Benchmark” (wzI10492) 0.317 0 0.587 8 0.492 7 0.439 15“BART Alternative” (wzI10493) 0.206 0 0.383 2 0.329 2 0.298 4Visibility Improvement(e)0.111 0 0.204 6 0.163 5 0.141 11

Strawberry Mountain Wilderness, OR“Alternative Benchmark” (wzI10492)1.419180.882222.308401.46280“BART Alternative” (wzI10493)0.737100.540111.487300.91751Visibility Improvement(e)0.68280.342110.821100.54529All AreasReduction in Total Days > 0.5 dv, all Class I Areas Combined 2003: 51 2004: 69 2005: 60 3-Yr: 180(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 modeled values.14Table 6 Summary of scenarios and net visibility improvement from “BART Alternative” in comparison to “BART” scenarioClass I Area“AlternativeBenchmark”(a)(wzI10492)“BART”(b)(wzI10495)“BART Alternative”(c)(wzI10493)Net Visibility Improvement(“BART” – “BART Alternative”)22ndHighest(d)Total Days>0.5Δdv(e)22ndHighest(d)Total Days(e)>0.5Δdv22ndHighest(d)Total Days>0.5Δdv(e)Δdv Reduction,22nd HighestDayDecrease inNo. of Days>0.5ΔdvEagle Cap Wilderness, OR 2.201 195 1.512 149 1.411 126 0.101 23Craters of the Moon Wilderness, ID 0.393 10 0.267 4 0.245 3 0.022 1Hells Canyon Wilderness, ID/OR 1.582 129 1.092 87 1.059 80 0.033 7Jarbidge Wilderness, NV 0.375 8 0.256 5 0.234 5 0.022 0Sawtooth Wilderness, ID 0.47 18 0.319 6 0.307 6 0.012 0Selway-Bitterroot Wilderness, ID 0.439 15 0.281 3 0.298 4 -0.017 -1Strawberry Mountain Wilderness, OR 1.462 80 1.076 62 0.917 51 0.159 11Total Number of Days with Improved Visibility:455 316 275 41(a)Includes pre-BART emissions of all sourcesinvolved 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, three pulp dryers operating.(c)Includes all sources involved in BART and the BART Alternative under BART Alternative operations: Riley Boiler (LNB), B&W Boilers 1&2 (LNB), three pulp dryers shutdown.(d)The 22ndhighestΔdv value for the three-year period (2003 – 2005).(e)Total number of days in the three-year period that exceed 0.5Δdv.

### 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 chan ges with FLMs, questions were raised about finding sufficient alternative contro ls at the facility to include in a BART alternative and about the effect on visibility impacts that would result from reducing the level of SO 2 

### control and replacing it with increased NO x 

### control. As a result, DEQ rea ssessed the selection of emission sources included in BART Alternative modeling and evaluated whether i nordinate 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 SO 2 

### emissions by Spray Dry-FGD were proposed by TASCO, in light of both the high cost and the environmenta l impairment due to the waste stream produced by Spray Dry FGD. During the evaluation, the FL Ms 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 inclusi on as part of a BART Alterna tive. DEQ examined the primary regional haze precursors in the facility-wide emission inventor y for the TASCO Nampa Factory in the most recent statewide point source emissi ons inventory (2010). The pulp dryers had been shut down by 2010 and did not appear in this inventory, but were in cluded as reductions in the BART Alternative. The faci lity-wide emissions of NO x 

### , SO 2 

### and PM 10 

### 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 NO x 

### emissions, 99% of the SO 2 

### emissions and 98% of PM 10 

### 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 significan t visibility-impairing pollutant emission sources are available at the fa cility for inclusion in the BART Alternative control plan.

Effects on Visibility from Replacing SO 2 

### Control with Additional NO x 

### Control The proposed BART Alternative replaces th e Spray-Dry Flue Gas Desulfurization SO 2 

### control on the Riley Boiler with additional NO x 

### controls on the two Babcoc k & Wilcox boilers and with additional NO x 

### , SO 2 

### and PM 10 

### reductions achieved by shutting dow n 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 sulf ate was a predominant contributor in any particular se ason during which the facility cont ributes to significant visibility degradation. To assess the importa nce of nitrate, sulfate and primary particulate matter to the regional haze levels, DEQ investigated the monito red impacts at all the Class I areas and seasons most impacted by the TASCO Nampa Factory. IMPROVE aerosol monitoring data 5 

### for the modeling period are presented in this section to provide a multi-year evaluation of pre-BART visibility conditions and th eir 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 Ri ver Valley: Eagle Cap, Strawberry Mountain and Hells Canyon wilderness areas. These areas also experience the highest monitored aerosol impacts, with the exception of isolated wildfi re impacts that affect sites throughout the west. Monitoring data for the years of the mode ling study, 2003, 2004 and 2005 are shown in Figure 7, Figure 8, and Figure 9 (respectively), for the Starke y IMPROVE site. The Starkey site is located between Eagle Cap and Strawbe rry 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 compos ition. A review of Figure 7 thr ough Figure 12 indicates that:

• The greatest non-carbon impacts are in the wint er, 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 summ er, sometimes extending into fall, when carbon predominates ex tinction (~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 visibili ty during these warmer seasons.

• The season with the best vi sibility (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 ex tinction reaches 120 to 300 Mm -1 

### most years.

The Starkey IMPROVE site represents the two Cl ass I areas with greatest modeled impacts from the TASCO Nampa boilers so seasonal regiona l haze impacts measured at Starkey were examined in more detail. Daily extinction values for measured aerosol species were obtained from the WRAP-TSS 5 

### and summarized into monthly averag e 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 high est total extinction and the predominant species is ammoni um nitrate. The season with the best visibility (lowest average extinction) is spring (March through June) when aver age 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 variab ility. 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 th e worst 20% of days, th e greatest contributors to regional haze impacts are carbon in the summ er and fall and nitrate in the winter. Again,

### 18 sulfate predominates in the spring when visibili ty 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 fo r 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 22 nd 

### highest Δ dv days. None of the 22 nd 

### highest days exceed 0.5 Δ dv, 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 ar e shown for Sawtooth Wilderness in Figure 15, Figure 16, and Figure 17 (respect ively); 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 cha nges, 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, s uggesting very little im pact 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 (F igure 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 app ears to be indicative of a very consistent regional background, with very little va riation amongst all 7 Class I area.

Overview of Seasonal Visibility Analysis The above analysis of seasonal visibility impact s suggests that the greatest impacts occur at Starkey and Hells Canyon as a result of wintertime nitrate im pacts 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 (F igure 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, simila r to the levels apparent at the Class I areas east of Nampa (Jarbidge, Sawtooth, Craters of the Moon and Selway-Bi tterroot) where TASCO Nampa emissions were found to not “contribut e” significantly to the modeled extinction.

To confirm the seasonality of the modeled imp acts 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 obs erved 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” s cenario results in greater reductions in haze on the 98 th 

### percentile days, and more days below the 0.5 Δ dv threshold than the “BART” scenario because it more effectively addresses the primar y aerosol contributor (nitrates) during the most impacted season at the most impacted Class I ar eas. This overall improvement comes at the price of slightly less improvement during the best visib ility period in the spri ng, when sulfate is a much smaller, but still predomin ant contributor to visi bility degradation. Thus, the reduction in SO 2 

### control in lieu of more NO x 

### control results in slightly le ss visibility improvement on the clearest days in the spring (< 5Mm -1 

### ). Nevertheless, greater overall improvement in visibility conditions occurs with the “B ART Alternative” in comparison to the “BART” scenario.



### Additional Environmental Benefits in Reducing Ozone The Treasure Valley, including the Boise River a nd Snake River Valleys and stretching from Mountain Home, Idaho to Malheur County, Or egon, has been struggl ing with elevated summertime ozone conditions for a number of year s. As shown in Figure 28, the Treasure Valley area remains perilously close to exceeding th e 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 avoi d a non-attainment designati on in recent years but that as traffic increases and weat her varies, the attainment status of this area is precarious. As a result, Idaho has taken unprecedented steps to lower VOC and NO x 

### ozone precursor emissions, including Stage II vapor control requirements and the nation’s onl y 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 th e 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 NO x 

### . The NO x 

### reductions correspond to a 162 ton per year reduction or an annuali zed reduction of 0.4 tons per day.

In its ongoing effort to be proactive in addr essing the ozone problem, DEQ assessed the ozone mitigation benefits of a numb er 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 NO x 

### reductions are most effective, NO x 

### reductions of around 2 tons per day from the TASCO Factory is expected to result in a reducti on of the peak 8-hour ozone co ncentration 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 Pre ssure in gasolin e, a 54% VOC reduction from a solvent-degreasi ng regulatory program, a 10% re duction in lawn and garden emissions, and a 10% reduction in vehicle refueling emissions.

Ozone mitigation is only beneficial in the summ ertime. 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 NO x 

### emissions from the B&W boilers would not contribute to ozone mitig ation. However, TASCO has confirmed that in addition to the Riley Boiler, the B&W boilers us ually operate about 30 days during the summer ozone season (range is 20 to 60 days). As a re sult, 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 NO x 

### reductions in comparison to the “Alternative Benchmark”, more than double th e 2.7 tons per day reduction from the “BART” scenario. This quantity re presents the greatest NO x 

### reduction of any ozone control measures DEQ has evaluated to date. While NO x 

### -only controls are not as effective as combined NO x 

### plus VOC controls, this large reduction, in conjunction with VOC-only controls should be sufficient to significantly reduce the numbe r of unhealthy days and may help to avoid a non-attainment designation in the next few years.



### Conclusions This air quality modeling analys is addresses the visibility im pacts of the “BART” and “BART Alternative” control scenarios for the BART-s ubject 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% re duction, however total acid gas plus particulate matter emissions for the two scenarios are virt ually identical. TASCO’s alternative proposal involves replacing Spray Dry Fl ue Gas Desulfurization SO 2 

### controls on the Riley Boiler with low-NO x 

### burner controls on two non-BART boilers, along with shutting down three pulp dryers. While the total emissions of all species are si milar, the “BART Altern ative” achieves greater improvements in visibility because the most seve re non-carbon visibility impairment at the Class I areas nearest the Nampa Factory is dominated by ammonium nitrat e in the winter and replacing some of the SO 2 

### control with increased NO x 

### control provides greater reductions on more poor visibility days. An analysis of seasonal aerosol extinction obser vations indicates that while the greatest improvements will occur in the winter wh en impacts are greatest, there will be a small visibility impairment in the spring when the visi bility conditions are best and a low-level sulfate background dominates the extinction.

Nevertheless, overall modeled improvements show that the modeled visibi lity degradation on the 22 nd 

### highest impacted day at Eagle Cap was reduced by an additional 0.101 Δ dv 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 Δ dv threshold. Taking a broader geographic view, the combined number of days at all seven areas above the 0.5 Δ dv threshold were reduced by an additional 41 days for the “BART Alternative” sc enario in comparison to the “BART” scenario.

Finally, the “BART Alternative” scenar io provides signi ficantly greater NO x 

### reductions than the “BART” scenario (2.4 times greater), and ther efore 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 imp roved visibility expected for Class I Areas in the region.

### 21 Figure 4 TASCO Nampa Facility-Wide NO x Emissions

Figure 5 TASCO Nampa Facility-Wide SO2 Emissions

Figure 6 TASCO Nampa Facility-Wide PM 10 Emissions

### 22 Figure 7 Light extinction (Mm-1) based on measured aeroso l 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 aero sol 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 aero sol concentrations at Craters of the Moon Wilderness IMPROVE site, 2003.

Figure 22 Light extinction (Mm-1) based on measured aero sol concentrations at Craters of the Moon Wilderness IMPROVE site, 2004.

Figure 23 Light extinction (Mm-1) based on measured aero sol 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”, select ed “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 CHEM ICAL NOMENCLATURE.......................................................................... 3

1. TIER II OPERATING PERMIT SCOPE................................................................................................. .. 4

2. FACILITY-WIDE CONDITIONS ............................................................................................................ 5

3. RILEY BOIL ER 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 NO X 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
NO 2 nitrogen dioxide
NO X nitrogen oxides
NSPS New Source Performance Standards
O&M operations and maintenance
OFA over-fired air PM particulate matter
PM 10 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
SO 2 sulfur dioxide
SO x 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 Rile y 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 SO 2 BART for SO 2

Low NO X burner system with over-fired air Control efficiency: ≥ 50% for NO X BART for NO X

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 constitu te the full incorporation into this pe rmit 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, Subpa rt P, Section 308 – Best Available Retrofit Technology (BART) requirements

• Compliance Assurance Monitoring (CAM), 40 CFR Part 64 For permit conditions referencing or cited in accordan ce with any document inco rporated by reference (including permit conditions iden tified as BART and CAM), should th ere be any conflict between the requirements of the permit condition and the require ments 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, notif ications of intent to test, testing reports, or compliance certifications, shall contain a certificati on by a responsible official. The certification shall state that, based on information and belief formed af ter 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 natu ral gas, and is used to supply steam and generate electricity for processing of sugar beets into sugar an d 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 h as been required for the control of sulfur dioxide (SO 2 ) emissions from the Riley Boiler. In a spray dry F GD system, the flue gas is introduced into a tower and contacts an atomized spray of lime slurry, which absorbs and neutralizes the SO 2 .

A low NO X burner system (LNB) with over-fired air has b een required for the control of nitrogen oxides (NO X ) emissions from the Riley Boiler. Low NO X combustion with over-fired air utilizes fuel and air mixing optimization and staged combustion techniques to minimize thermal NO X 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 I DAPA 58.01.01.668.04 and 40 CFR 51.308(e)(1)(iv). The permittee may submit a request to obtain a DEQ-a pproved BART alternative a nd to revise this permit in accordance with IDAPA 58.01.01.404.04. DE Q will process the request in accordance with IDAPA 58.01.01.404. The request must be submitted timel y such that any revisions to this permit and the corresponding revision to the Regional Haze SIP ar e approved prior to the BART installation and operation due date (as defined in th is 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 opera tion 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 SO 2 NO X 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 referen ce method, or DEQ approved alternative. (b) BART emission rate lim it 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 63.5 CO Emission Limits On and after the BART installation and opera tion 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 determ ined 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 opera tion due date (as defined in Permit Condition 3.3 ), and at all times the Riley Boiler is fired with coal, the perm ittee shall operate a Baghouse (A-B3) to control PM emissions from the Riley Boiler to ensure comp liance 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 Fl ue Gas Desulfurization Control Equipment On and after the BART installation and opera tion 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 SO 2 emissions from the Riley Boiler and to ensure compliance with the BART SO 2 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 NO X Burner Control Equipment On and after the BART installation and opera tion due date (as defined in Permit Condition 3.3 ), the permittee shall operate at all times th e Riley Boiler is operated, a low NO X burner system (LNB) in the Riley Boiler to reduce NO X emissions and to ensure compliance with the BART NO X 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 pr econstruction complianc e 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 opera tion due date (as defined in Permit Condition 3.3 ), the permittee shall maintain the control equipment re quired 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 inch es 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 main tained 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 f eet 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 main tained in accordance with General Provision 7

.

3.13 Operation and Maintenance Manuals Within 60 days after the BART installation and operation due date (as de fined 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 co ntrol 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 sh all be a permittee developed document based upon, but independent from, the manuf acturer supplied operating manual(s).

• The permittee shall operate the control equipm ent in accordance with the O&M manual. The procedures specified in the O&M manual are incor porated by reference into this permit and are enforceable permit conditions. The O&M manual a nd copies of any manufacturer’s manual(s) and recommendations shall remain on site at all times an d shall be made available to DEQ representatives upon request.

• At a minimum, the manufacturer’s recommended valu es 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 te mperature, 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 parame ters 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 installati on 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 SO 2 emission limit in pounds per hour (Permit Condition 3.4 );

 The BART NO X 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 sp ecified in the performance test monitoring and recordkeeping requirement (Permit Condition 3.16 ).

3.15 Periodic Performance Testing
Performance tests to determine PM, SO 2 , NO X , 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 follo wing 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 alternat e 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, in cluding 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 te mperature, 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 perfo rmance 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 insta llation 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 w ith 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 installati on 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 installa tion 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 SO 2 NO X 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 OPERAT E GENERAL PROVISIONS

General Compliance

1. The permittee has a continuing duty to comply with a ll terms and conditions of th is permit. All emissions authorized herein shall be consistent with the term s 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 li mitation 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 efficien tly as practicable, all treatment or control facilities or systems installed or used to achieve compliance wi th 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 fe deral statutes, rules and regulations. [IDAPA 58.01.01.406, 5/1/94]


### Inspection and Entry

4. Upon presentation of credentials, the permittee shall a llow DEQ or an authorized representative of DEQ to do the following: a. Enter upon the permittee’s premises where an em issions source is located or emissions related activity is conducted, or where records ar e kept under conditions of this permit;

b. Have access to and copy, at reasonable times, any r ecords that are kept under the conditions of this permit;

c. Inspect at reasonable times any facilities, equipmen t (including monitoring and air pollution control equipment), practices, or ope rations regulated or requ ired under this permit; and d. As authorized by the Idaho Environmental Prot ection and Health Act, sample or monitor, at reasonable times, substances or parameters for th e 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 cons truction, 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 thir ty 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 13e. 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 pr ior 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 acco rdance 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 DE Q for any testing deviations, DEQ may determine that the testing does not satisfy the testing requireme nts. 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 pr oposed test, and the proposed test schedule for conducting and reporting the test. Within 30 days following the date in which a performan ce test required by this permit is concluded, the permittee shall submit to DEQ a performance test repo rt. 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 ra w 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 ensu re compliance with all of the terms and conditions of this permit. Records of monitoring information sh all 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 conditi ons 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 14T2-2009.0105 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 ma intenance, 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, testi ng reports, or compliance certification shall contain a certification by a responsible official. The certificati on shall state that, based on information and belief formed after reasonable inquiry, the statements and in formation 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 appli cable rule or order in force pursuant thereto. [IDAPA 58.01.01.125, 3/23/98]


### Tampering

11. No person shall knowingly render inaccurate any monito ring 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 con tinues to meet all terms and conditi ons contained in the permit. The expiration of this permit will not affect the operati on 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 MANUALBoiler 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 9Boiler System Baghouses O&M Manual 

### 3 

## Introduction

In accordance with Permit Condition 2.15 of t he 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 B aghouses 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 t he two B&W Boilers are controll ed 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 duc t and damper is used to bypass the baghouse if necessary in an emergency situation,(i.e . baghouse blinded, boiler t ube leak, etc).

An Operation and Maintenance Manual (attac hed), 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 Temperatur e 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 Revers e Air, with acoustic using 2 horns Rotary airlocksBoiler System Baghouses O&M Manual 

### 4 Riley Boiler Baghouse (A-B3)

Particulate emissions from the Riley Boiler ar e 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 Temperatur e 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 veloci ty particles on filter bags.

Air flows from the bottom insi de 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 particu lates (filter cake), the differ ential pressure increases across the baghouse collector. The filt er bags are periodically cl eaned with reverse air that removes the collected dust allowing it to dr op into a hopper. Dust removal is also enhanced with acoustic horns, which are locat ed 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 hydrau lically conveyed to a settling pond. During beet campaign the water is mixed with flume water in t he settling ponds, but during intercampaign the water is directed to a separate se ttling pond near the piling ground.Boiler System Baghouses O&M Manual 

### 5 

## Upset Conditions and Corrective Procedures
The Company takes its environmental responsibi lities 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 rupt ured. This allows flyash to enter the clean air side of the baghouse and exhaust to the stack.

2) One or more bags have sli pped off the mounting thimble.

3) Boiler tube leak that has the pot ential to blind the bag from excessive moisture.

4) Baghouse cleaning system has faile d 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 em ission 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 differ ential pressure readings.

Corrective Action To assist the operators with detecting l eaking 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 oper ator will shut dow n 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 vi sible emission from the boiler stack must be immediately reported to the Shi ft Supervisor or the Boiler Foreman who will determine if DEQ needs to be notified. The boiler foreman is certified toBoiler System Baghouses O&M Manual 

### 6 perform visual emission determinations using EPA Method 9. If neither is available, the Facility Environmen tal Manager must be notified.


## Boiler Startup and Shutdown Procedures
The following startup procedure is currently on file with DE Q and will be strictly followed for all boiler startups includi ng 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-li ne until the fuel transfer is made from coal back to natural gas to ensure that emission capt ure continues during the entire shutdown procedure. The fuel transfer to natur al 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 emi ssions are not considered an issue during boiler shut down.



## Control Device Monitoring Program
The Tier II air permit requi res 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 se veral different methods. These are listed below along with a de scription 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 per mit. DPD is measured by two independent measuring systems, manually using perm anently mounted manometers (in the boiler control room) and electronically using a DP ce ll. 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 pressu re. Bag leak detectors and VE’s should be used for determining if upset condition s exist that can lead to an excess emission.

The range of differential pressure drop across both baghouses (measured individually) is from 2” H 2 

### O gauge to 14” H 2 

### O water gauge.

Bag Leak Detectors Bag leak detectors have been inst alled 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 additi onal 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 Envi ronmental Manager conducts see, no see VE inspections twice a month at approxim ately 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 immedi ately and take co rrective action to resolve the problem! (see the “Upset Conditions and Corrective Action” section)



## Maintenance Procedures

Maintenance is an important component of proper operat ion of emission control equipment. TASCO has identified the follo wing 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. Che ck that rams activate and operate smoothly and properly. Rotary gates need to cycle pr operly 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 wate r flow is adequate to remove ash from the system.

3. Inspect reverse air fan. Ensure t hat the fan is running smoothly and that the system is cycling and functioning properly.

4. Inspect solenoid valves. Check that that the solenoid va lves 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 emissi ons control equipment in optim al operating condition, the following monthly and annual ma intenance will be performed:

Schedule Annual maintenance on the baghouses can only be performed when the equipment is out of se rvice. The following time periods provide general opportunities to perform annual maintenan ce on equipment. Actual dates of equipment shutdown and avail ability are determined by the operational needs for the equipment:

Oct- February

All equipment is in service duri ng 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 oper ation 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 caus e 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 a ttach 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 st rength 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 t hat they are sealed, sequencing properly and operate smoothly. Repair as necessary.

10) Air Horns Inspect to ensure proper oper ation. Horns must be timed properly and develop the designed energy to remove dus t. 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 servic eable 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 stac k 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 ma intenance is completed as required in the Air Permit. As a minimum t he following information will be collected and retained for up to five years: Operations

1) The baghouse pressure drop will be reco rded at least once per week during baghouse operation and archived in facility files.

Maintenance 1. All Baghouse Maintenance Performed. 2. All calibration information fo r baghouse control instrumentation