BART FIVE FACTOR ANALYSIS  HAWAIIAN ELECTRIC COMPANY, INC. 

HAWAII ELECTRIC LIGHT COMPANY, INC. – KANOELEHUA-HILL PLANT

VERSION 0 

Prepared by: 

TRINITY CONSULTANTS

9777 Ridge Drive 

Suite 380 

Lenexa, Kansas 66219 

(913) 894-4500 

Prepared for: 

HAWAII ELECTRIC LIGHT COMPANY, INC.

P.O. Box 1027 

Hilo, Hawaii 96721-1027 

October 2010 

Project 101701.0132 
 

Hawaii Electric Light Company, Inc. i Trinity Consultants 

BART Analysis 

TABLE OF CONTENTS

1. EXECUTIVE SUMMARY ........................................................................................ 1-1

2. INTRODUCTION AND BACKGROUND .................................................................... 2-1

3. EXISTING EMISSIONS AND VISIBILITY IMPAIRMENT ......................................... 3-1

3.1 NOX, SO2, AND PM10 BASELINE EMISSION RATES ................................................ 3-1

3.2 EXISTING NOX, SO2, AND PM10 EMISSIONS AND ASSOCIATED VISIBILITY 

IMPAIRMENT ..................................................................................................................... 3-4

4. SO2 BART EVALUATION .................................................................................... 4-1

4.1 IDENTIFICATION OF AVAILABLE RETROFIT SO2 CONTROL TECHNOLOGIES .......... 4-1

4.2 ELIMINATE TECHNICALLY INFEASIBLE SO2 CONTROL TECHNOLOGIES ................ 4-1

4.2.1 DRY SORBENT INJECTION, SPRAY DRYER ABSORPTION (SDA), WET SCRUBBER,

CIRCULATING DRY SCRUBBER (CDS) ............................................................................. 4-2

4.2.2 FUEL SWITCHING ................................................................................................ 4-2

4.3 RANK OF TECHNICALLY FEASIBLE SO2 CONTROL OPTIONS BY EFFECTIVENESS .. 4-2

4.4 EVALUATION OF IMPACTS FOR FEASIBLE SO2 CONTROLS..................................... 4-3

4.4.1 COST OF COMPLIANCE ........................................................................................ 4-3

4.4.1.1 Energy Impacts and Non-Air Quality Impacts .................................... 4-6

4.4.1.2 Remaining Useful Life ......................................................................... 4-6

4.5 EVALUATION OF VISIBILITY IMPACT OF FEASIBLE SO2 CONTROLS ...................... 4-6

4.6 PROPOSED BART FOR SO2 ..................................................................................... 4-8

5. NOX BART EVALUATION ................................................................................... 5-1

5.1 IDENTIFICATION OF AVAILABLE RETROFIT NOX CONTROL TECHNOLOGIES ......... 5-1

5.2 ELIMINATE TECHNICALLY INFEASIBLE NOX CONTROL TECHNOLOGIES ............... 5-2

5.2.1 COMBUSTION CONTROLS .................................................................................... 5-2

5.2.1.1 Flue Gas Recirculation (FGR) ............................................................. 5-2

5.2.1.2 Overfire Air (OFA) .............................................................................. 5-2

5.2.1.3 Low NOX Burners ................................................................................ 5-2

5.2.2 POST COMBUSTION CONTROLS ........................................................................... 5-3

5.2.2.1 Selective Catalytic Reduction .............................................................. 5-3

5.2.2.2 Selective Non-Catalytic Reduction ...................................................... 5-3

5.3 RANK OF TECHNICALLY FEASIBLE NOX CONTROL OPTIONS BY EFFECTIVENESS .. 5-4

5.4 EVALUATION OF IMPACTS FOR FEASIBLE NOX CONTROLS ................................... 5-5

5.4.1 COST OF COMPLIANCE ........................................................................................ 5-5

5.4.2 ENERGY IMPACTS & NON-AIR IMPACTS ............................................................ 5-8

5.4.3 REMAINING USEFUL LIFE ................................................................................... 5-8

5.5 EVALUATION OF VISIBILITY IMPACT OF FEASIBLE NOX CONTROLS ..................... 5-8

5.6 PROPOSED BART FOR NOX .................................................................................. 5-11
 

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BART Analysis 

6. PM10 BART EVALUATION .................................................................................. 6-1

6.1 IDENTIFICATION OF AVAILABLE RETROFIT PM10 CONTROL TECHNOLOGIES ........ 6-1

6.2 ELIMINATE TECHNICALLY INFEASIBLE PM CONTROL TECHNOLOGIES ................. 6-2

6.2.1 DRY ELECTROSTATIC PRECIPITATORS (ESP) ..................................................... 6-2

6.2.2 MECHANICAL COLLECTORS (CYCLONES) .......................................................... 6-2

6.2.3 WET ELECTROSTATIC PRECIPITATORS (ESP) ..................................................... 6-2

6.2.4 FABRIC FILTER .................................................................................................... 6-2

6.2.5 WET SCRUBBER .................................................................................................. 6-3

6.2.6 FUEL SWITCHING ................................................................................................ 6-3

6.3 RANK OF TECHNICALLY FEASIBLE PM10 CONTROL OPTIONS BY EFFECTIVENESS . 6-4

6.4 EVALUATION OF IMPACTS FOR FEASIBLE PM10 CONTROLS................................... 6-4

6.4.1 COST OF COMPLIANCE ........................................................................................ 6-4

6.4.1.1 Energy Impacts and Non-Air Quality Impacts .................................... 6-5

6.4.1.2 Remaining Useful Life ......................................................................... 6-5

6.5 EVALUATION OF VISIBILITY IMPACT OF FEASIBLE PM10 CONTROLS .................... 6-7

6.6 PROPOSED BART FOR PM10 ................................................................................... 6-9

APPENDIX A - NOX CONTROL COST CALCULATIONS

APPENDIX B - PM10 CONTROL COST CALCULATIONS

Compact Disc - August 2010 Stack Test Report 
 

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BART Analysis 

LIST OF TABLES

TABLE 1-1. EXISTING VISIBILITY IMPAIRMENT ATTRIBUTABLE TO HILL 5 & HILL 6 ........................ 1-1

TABLE 3-1. BASELINE SHORT-TERM NOX AND PM10 EMISSION RATES (LB/HR) BASED ON STACK 

TEST ........................................................................................................................................ 3-2

TABLE 3-2. BASELINE NOX AND PM10 EMISSION RATES (LB/MMBTU) BASED ON STACK TEST ....... 3-2

TABLE 3-3. BASELINE NOX AND PM10 EMISSION RATES (TPY) BASED ON STACK TEST .................... 3-2

TABLE 3-4. SHORT TERM BASELINE SO2 EMISSION RATE (LB/HR) BASED ON MASS BALANCE ....... 3-3

TABLE 3-5. ANNUAL BASELINE SO2 EMISSION RATE (TPY) BASED ON MASS BALANCE .................. 3-4

TABLE 3-6. MODELED BASELINE EMISSION RATES ........................................................................... 3-5

TABLE 3-7. BASELINE VISIBILITY IMPACTS ATTRIBUTABLE TO HILL 5 AND HILL 6 ......................... 3-5

TABLE 4-1. SUMMARY OF BASELINE SO2 EMISSION RATES .............................................................. 4-1

TABLE 4-2. AVAILABLE SO2 CONTROL TECHNOLOGIES FOR HILL 5 & HILL 6 .................................. 4-1

TABLE 4-3. SUMMARY OF FUTURE ANNUAL SO2 EMISSIONS ASSOCIATED WITH DISTILLATE OIL AT 

0.15% SULFUR ........................................................................................................................ 4-4

TABLE 4-4. SUMMARY OF FUTURE ANNUAL SO2 EMISSIONS ASSOCIATED WITH DISTILLATE OIL AT 

0.4% SULFUR .......................................................................................................................... 4-4

TABLE 4-5. SUMMARY OF COST EFFECTIVENESS FOR SWITCHING FROM RESIDUAL FUEL OIL TO 

DISTILLATE FUEL OIL ............................................................................................................. 4-5

TABLE 4-6. SUMMARY OF MAXIMUM SO2 EMISSIONS ASSOCIATED WITH DISTILLATE OIL ............. 4-7

TABLE 4-7. SUMMARY OF EMISSION RATES MODELED TO REFLECT SWITCH TO DISTILLATE OIL FOR 

SO2 CONTROL ......................................................................................................................... 4-7

TABLE 4-8. SUMMARY OF VISIBILITY IMPROVEMENT ASSOCIATED WITH SWITCH TO DISTILLATE OIL4-8

TABLE 5-1. SUMMARY OF BASELINE EMISSION RATES ...................................................................... 5-1

TABLE 5-2. AVAILABLE NOX CONTROL TECHNOLOGIES FOR HILL 5 & HILL 6 ................................. 5-1

TABLE 5-3. CONTROL EFFECTIVENESS OF TECHNICALLY FEASIBLE NOX CONTROL TECHNOLOGIES5-4

TABLE 5-4. SUMMARY OF COST EFFECTIVENESS FOR HILL 5 & HILL 6 NOX CONTROLS ................... 5-7

TABLE 5-5. SUMMARY OF EMISSION RATES MODELED TO REFLECT LNB FOR NOX CONTROL ......... 5-9
 

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BART Analysis 

TABLE 5-6. SUMMARY OF EMISSION RATES MODELED TO REFLECT SCR FOR NOX CONTROL ......... 5-9

TABLE 5-7. SUMMARY OF VISIBILITY IMPROVEMENT ASSOCIATED WITH LNB SYSTEMS ON HILL 5

AND HILL 6 ............................................................................................................................. 5-9

TABLE 5-8. SUMMARY OF VISIBILITY IMPROVEMENT ASSOCIATED WITH SCR SYSTEMS ON HILL 5

AND HILL 6 ........................................................................................................................... 5-10

TABLE 6-1. SUMMARY OF BASELINE PM10 EMISSION RATES............................................................. 6-1

TABLE 6-2. AVAILABLE PM CONTROL TECHNOLOGIES FOR HILL 5 & HILL 6 ................................... 6-1

TABLE 6-3. CONTROL EFFECTIVENESS OF TECHNICALLY FEASIBLE PM CONTROL TECHNOLOGIES 6-4

TABLE 6-4. SUMMARY OF COST EFFECTIVENESS FOR HILL 5 & HILL 6 PM10 CONTROLS .................. 6-6

TABLE 6-5. SUMMARY OF EMISSION RATES MODELED TO REFLECT WET ESP FOR PM10 CONTROL 6-7

TABLE 6-6. SUMMARY OF EMISSION RATES MODELED TO REFLECT WET SCRUBBER FOR PM10

CONTROL ................................................................................................................................ 6-7

TABLE 6-7. SUMMARY OF VISIBILITY IMPROVEMENT ASSOCIATED WITH WET ESPS ON HILL 5 AND 

HILL 6 ..................................................................................................................................... 6-8

TABLE 6-8. SUMMARY OF VISIBILITY IMPROVEMENT ASSOCIATED WITH WET SCRUBBERS ON HILL 5

AND HILL 6 ............................................................................................................................. 6-9
 

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BART Analysis 

1. EXECUTIVE SUMMARY

This report documents the determination of the Best Available Retrofit Technology (BART) as 

proposed by Hawaii Electric Light Company, Inc. (HELCO) for the two boilers at the KanoelehuaHill plant (Hill 5 & Hill 6). Hill 5 is a 14 MW front-fired boiler. Hill 6 is a 21 MW tangentiallyfired boiler. Both boilers currently burn residual (~ No. 6) oil. 

Using the default natural conditions, the Environmental Protection Agency (EPA) Region 9 

determined that cumulative emissions of nitrogen oxides (NOx), sulfur dioxide (SO2), and particulate 

matter (PM) from Hill 5 and Hill 6 cause or contribute greater than 0.5 delta deciviews (∆dv) to 

visibility impairment in Hawaii Volcanoes National Park (VNP) and Haleakala National Park (HNP). 

Since the boilers also meet the three criteria that make a source BART-eligible, the fact that the 

boilers contribute to visibility impairment in a Class I area greater than 0.5 ∆dv means that the boilers 

are subject to BART. 

It is important to note that the default natural visibility conditions used in the EPA Region 9 modeling 

were derived from sites in the western continental United States. Therefore, they do not contain any 

Hawaii-specific conditions, including volcanic emissions. Hawaiian Electric Company, Inc. (HECO) 

provided comments in September 2001 and July 2004 on the “Proposed Guidelines for BART 

Determinations” stating that the Kilauea Volcano emissions were not accounted for in default natural 

visibility at Haleakala and Volcanoes National Parks. EPA responded (docket OAR-2002-0076) 

with: 

“Default [natural] conditions may be used or there are measures to develop refined estimates 

of natural conditions which may account for natural phenomena.” 

A summary of the existing visibility impairment attributable to the Hill 5 and Hill 6 based on the 

default natural conditions is provided in Table 1-1. Note that the visibility impairment summarized in 

Table 1-1 is based on recent modeling conducted by Trinity Consultants (Trinity) using emissions 

data based on a combination of stack testing and mass balance, as further described in Section 3 of 

this report. 

TABLE 1-1. EXISTING VISIBILITY IMPAIRMENT ATTRIBUTABLE TO HILL 5 & HILL 6 

Volcanoes National Park Haleakala National Park 

Max 

∆dv 

98th 

Percentile 

∆dv 

Days 

> 0.5 

∆dv 

Max 

∆dv 

98th 

Percentile 

∆dv 

Days 

> 0.5 

∆dv 

2005 3.08 1.56 123 0.55 0.44 3 

2006 2.56 1.40 115 0.89 0.32 2 

2007 2.21 1.43 103 0.90 0.48 7 
 

Hawaii Electric Light Company, Inc. 1-2 Trinity Consultants 

BART Analysis 

 

Trinity used the EPA’s BART guidelines in 40 CFR Part 511 to determine BART for Hill 5 and Hill 

6. Specifically, Trinity conducted a five-step analysis to determine BART for SO2, NOX, and PM10

that included the following: 

1. Identifying all available retrofit control technologies; 

2. Eliminating technically infeasible control technologies; 

3. Evaluating the control effectiveness of remaining control technologies; 

4. Evaluating impacts and document the results; 

5. Evaluating visibility impacts. 

Based on the five-step analysis, the following were determined to be BART: 

• SO2 – The BART analysis concluded that no controls constitute BART. Add-on controls are 

not technically feasible, and switching fuels is not cost effective. 

• NOX – The BART analysis concluded that the installation of low-NOx burner (LNB) 

systems capable of achieving a NOx level of 0.30 lb/MMBtu for Hill 5 (a wall-fired boiler) 

and a NOx level of 0.18 lb/MMBtu for Hill 6 (a tangentially-fired boiler) constitutes BART 

when using the default natural conditions. 

• PM10 – The BART analysis concluded that no controls constitute BART. Neither a fuel 

change nor add-on controls are cost effective or result in an improvement to the visibility 

impairment attributable to the Hill boilers of over 0.06 Δdv. 

While the BART review concludes that low-NOx burner (LNB) systems are the only controls needed 

to satisfy the requirements of the BART rule, it should noted that the use of more representative 

natural conditions that account for the volcano’s impact would result in reduced visibility 

improvements attributable to Hill 5 and Hill 6. The reduced visibility improvement may show that 

the installation of LNB systems capable of achieving a NOx level of 0.30 lb/MMBtu for Hill 5 (a 

wall-fired boiler) and a NOx level of 0.18 lb/MMBtu for Hill 6 (a tangentially-fired boiler) do not 

constitute BART. 

It also should be mentioned that other long-term emission reduction strategies, such as those included 

as part of the Hawaii Clean Energy Initiative (HCEI) may be viable alternatives to BART. HELCO 

looks forward to working through the BART process with EPA and/or Hawaii DOH in an effort to 

accomplish the Regional Haze Rule objectives. 

1 The BART guidelines were published as amendments to the EPA’s RHR in 40 CFR Part 51, Section 308 on July 

5, 2005. 
 

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2. INTRODUCTION AND BACKGROUND

In the 1977 amendments to the Clean Air Act (CAA), Congress set a national goal to restore 

national parks and wilderness areas to pristine conditions by preventing any future, and 

remedying any existing, man-made visibility impairment. On July 1, 1999, the U.S. EPA published 

the final Regional Haze Rule (RHR). The objective of the RHR is to restore visibility to pristine 

conditions in 156 specific areas across with United States, known as Class I areas. The Clean Air Act 

defines Class I areas as certain national parks (over 6000 acres), wilderness areas (over 5000 acres), 

national memorial parks (over 5000 acres), and international parks that were in existence on August 

7, 1977. 

The RHR requires States to set goals that provide for reasonable progress towards achieving natural 

visibility conditions for each Class I area in their state. On July 6, 2005, the EPA published 

amendments to its 1999 RHR, often called the Best Available Retrofit Technology (BART) rule, 

which included guidance for making source-specific BART determinations. The BART rule defines 

BART-eligible sources as sources that meet the following criteria: 

(1) Have potential emissions of at least 250 tons per year of a visibility-impairing pollutant, 

(2) Began operation between August 7, 1962 and August 7, 1977, and 

(3) Are included as one of the 26 listed source categories in the guidance. 

A BART-eligible source is subject to BART if the source is “reasonably anticipated to cause or 

contribute to visibility impairment in any federal mandatory Class I area.” EPA has determined that a 

source is reasonably anticipated to cause or contribute to visibility impairment if the 98th percentile 

visibility impacts from the source are greater than 0.5 delta deciviews (∆dv) when compared against a 

natural background. Air quality modeling is the tool that is used to determine a source’s visibility 

impacts. 

Once it is determined that a source is subject to BART, a BART determination must address air 

pollution control measures for the source. The visibility regulations define BART as follows: 

“...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...[a BART-eligible source]. The emission limitation must be 

established on a case-by-case basis, taking into consideration the technology available, 

the cost of compliance, the energy and non air quality environmental impacts of 

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

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

may reasonable be anticipated to result from the use of such technology. 

Specifically, the BART rule states that a BART determination should address the following five 

statutory factors: 

1. Existing controls 

2. Cost of controls 

3. Energy and non-air quality environmental impacts 

4. Remaining useful life of the source 

5. Degree of visibility improvement as a result of controls 
 

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BART Analysis 

 

Further, the BART rule indicates that the five basic steps in a BART analysis can be summarized as 

follows: 

1. Identify all available retrofit control technologies; 

2. Eliminate technically infeasible control technologies; 

3. Evaluate the control effectiveness of remaining control technologies; 

4. Evaluate impacts and document the results; 

5. Evaluate visibility impacts 

A BART determination should be made for each visibility affecting pollutant (VAP) by following the 

five steps listed above for each VAP. 

Hill 5 and Hill 6 meet the three BART-eligibility criteria described above. Further, EPA Region 9 

performed an analysis of the existing visibility impairment attributable to the boilers using default 

natural conditions and concluded that the units are subject to BART. The details of the Hill 5 and 

Hill 6 existing/baseline emissions and the contribution of the emissions to visibility can be found in 

Section 3. The VAPs emitted by Hill 5 and Hill 6 include NOx, SO2, and particulate matter with a 

mass mean diameter smaller than ten microns (PM10) of various forms (filterable coarse particulate 

matter [PMc], filterable fine particle matter [PMf], elemental carbon [EC], inorganic condensable 

particulate matter [IOR CPM] as sulfates [SO4], and organic condensable particulate matter [OR 

CPM] also referred to as secondary organic aerosols [SOA]). The BART determinations for SO2, 

NOX, and PM10 can be found in Sections 4, 5, and 6, respectively. 

The BART guidelines2 state the following with regard to presumptive BART controls for oilfired boilers: 

“For oil-fired and gas-fired EGUs larger than 200 MW, we believe that installation of 

current combustion control technology to control NOX is generally highly cost-effective and 

should be considered in your determination of BART for these sources.” 

EPA also established presumptive SO2 controls for oil-fired EGUs in the BART rule. For oil-fired 

units, the guidelines state that sources of all sizes should evaluate limiting the sulfur content of the 

fuel oil to 1 percent or less by weight as BART. 

The BART guidelines do not specify presumptive BART limits for PM10 emissions. Note that the 

BART analysis was conducted for PM10 rather than PM, since PM that is ten microns and smaller is 

the portion of PM that has the potential to impair visibility.

2 Ibid. 
 

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BART Analysis 

3. EXISTING EMISSIONS AND VISIBILITY IMPAIRMENT

As stated in Section 2 of this report, EPA Region 9 determined that emissions of NOx, SO2, and PM10

from Hill 5 and Hill 6 cause or contribute to a level of visibility impairment at Hawaii Volcanoes 

National Park (VNP) and Haleakala National Park (HNP) that is above 0.5 delta deciviews. EPA 

utilized default values for natural conditions as contained in the EPA’s 2003 document “Guidance for 

Estimating Natural Visibility Conditions under the Regional Haze Program”. It should be noted that 

the use of this guidance document to establish natural conditions does not account for the impact of 

the active Kilauea Volcano. The Kilauea Volcano has a significant impact on regional haze in 

Hawaii. The current continuous Kilauea Volcano eruption began 26 years ago in 19833. Over the 

past 200 years, there have been very few periods when Kilauea and Mauna Loa were both inactive4. 

Thus, natural conditions based on the EPA document are grossly under represented. More 

representative natural conditions that take the volcanic activity into account would result in lower 

visibility impacts attributable to Hill 5 and Hill 6.

This section summarizes the existing (i.e. baseline) visibility impairment attributable to the Hill 

boilers based on air quality modeling conducted by Trinity. This section also summarizes emission 

rates that were used as baseline rates in the BART analyses presented in Sections 4, 5, and 6 of this 

report. 

3.1 NOX, SO2, AND PM10 BASELINE EMISSION RATES

Baseline emission rates are needed in several steps of the BART analysis. Baseline emission rates 

representing a worst-case 24-hour period are needed to establish the baseline visibility impairment 

from which the visibility improvement can be evaluated in Step 5 of the BART analysis. Annual 

baseline emission rates are also needed as part of evaluating the annual tons reduced by various 

control options as part of the cost effectiveness analyses conducted in Step 4 of the BART analysis. 

Finally, baseline emission rates in lb/MMBtu can be relevant for comparing existing emission rates to 

controlled emission rates that can be achieved based on the application of certain control devices. 

NOx and PM10

Table 3-1 summarizes the worst-case emission rates used by Trinity in the baseline visibility 

modeling. The emission rates are different than the rates used in any visibility modeling previously 

conducted, as HELCO conducted stack testing for NOx and PM10 in August of 2010, and the data 

from the test provides the basis of the baseline NOx and PM10 rates used in the recent modeling. 

 3 http://hvo.wr.usgs.gov/kilauea/

4 http://pubs.usgs.gov/gip/hawaii/page14.html
 

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BART Analysis 

TABLE 3-1. BASELINE SHORT-TERM NOX AND PM10 EMISSION RATES (LB/HR) BASED ON STACK 

TEST

Pollutant 

Hill 5 

(lb/hr) 

Hill 6 

(lb/hr) 

Total 

(lb/hr) 

NOx 112.6 122.0 234.6 

PM10,total1 11.04 11.17 22.21 1

EPA CTM-27/202 

The NOx and PM10 rates shown in Table 3-1 are based on the lb/MMBtu levels calculated from the 

August 2010 stack test data (shown in Table 3-2) multiplied by the maximum heat inputs to the 

boilers (Hill 5 = 197 MMBtu/hr and Hill 6 = 249 MMBtu/hr). The lb/MMBtu levels in Table 3-2 

were calculated by dividing the average lb/hr rates determined during the test by the average heat 

input to the boilers during the test. Table 3-2 summarizes the NOx and PM10 lb/MMBtu based on the 

test data. A copy of the stack test report is also included on the compact disc submitted with this 

application. Note that a more detailed breakdown of the PM species comprising the PM10 rates 

shown in Tables 3-1 and 3-2 is provided later in the section. 

TABLE 3-2. BASELINE NOX AND PM10 EMISSION RATES (LB/MMBTU) BASED ON STACK TEST

Parameter Hill 5 Hill 6 

Test HI (MMBtu/hr) 166 249 

Test NOx (lb/hr) 94.7 122 

Test PM10 (lb.hr) 9.31 11.17 

NOx (lb/MMBtu) 0.572 0.490 

PM10,total1 (lb/MMBtu) 0.056 0.045 1

EPA CTM-27/202 

Table 3-3 provides a summary of the annual baseline emissions for NOx and PM10. The annual 

baseline emission rates were calculated by multiplying the lb/MMBtu levels shown in Table 3-2 by 

the baseline (2009) heat input (Hill 5 = 1,354,786 MMBtu/yr and Hill 6 = 1,419,920 MMBtu/yr). 

TABLE 3-3. BASELINE NOX AND PM10 EMISSION RATES (TPY) BASED ON STACK TEST

Pollutant 

Hill 5 

(tpy) 

Hill 6 

(tpy) 

Total 

(tpy) 

NOx 387.26 347.85 735.11 

PM10,total1 38.07 31.85 69.92 1

EPA CTM-27/202 
 

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SO2

SO2 emissions are known to be correlated to the sulfur content of the fuel. Therefore, a mass balance 

based on the sulfur content of the fuel that is burned is an appropriate basis for estimating SO2

emissions. Trinity conducted a mass balance to determine both short term and annual baseline 

emissions. As part of the mass balance, Trinity considered the inorganic condensable particulate 

matter emissions that were evaluated as part of the 2010 stack testing. Specifically, Trinity presumed 

the inorganic condensable particulate matter to be in the form of sulfates. Since a portion of the 

sulfur in the No. 6 oil was estimated to have resulted in emissions of sulfate, the amount of sulfur in 

the fuel needed to form the sulfate emissions was determined so that this sulfur would not be 

considered when estimating the amount of sulfur that formed SO2. 

Table 3-4 provides a summary of the mass balance data and calculations for the short term baseline 

SO2 emission rate. In short, the sulfur in the maximum amount of fuel that could be combusted was 

first determined. The maximum amount of fuel was used to represent a worst-case scenario for shortterm emissions. Then, the amount of this sulfur that would be expected to be emitted as sulfate was 

estimated based on the results of the stack test (the stack test rate was scaled up to reflect the 

maximum amount of fuel that could be combusted and then the sulfate rate was reduced to sulfur by 

multiplying the sulfate rate by the ratio of the molecular weight of sulfur to sulfate [32/96]). The 

remaining sulfur was converted to SO2 by multiplying by the molecular weight of SO2 to sulfur 

[64/32]. 

TABLE 3-4. SHORT TERM BASELINE SO2 EMISSION RATE (LB/HR) BASED ON MASS BALANCE

Parameter Hill 5 Hill 6 

Maximum HI per CSP (MMBtu/hr) 197 249 

No. 6 Oil Heat Content (MMBtu/Mgal) 148.77 148.77 

No. 6 Oil Density (lb/gal) 8.04 8.04 

No. 6 Fuel Oil Max Sulfur (%) 2 2 

Maximum Sulfur in No. 6 Oil (lb/hr) 212.93 269.13 

SO4 from 2010 Stack Test [Assume CPM IOR = SO4] (lb/hr) 2.49 5.87 

SO4 from 2010 Stack Test Scaled to Reflect Max HI (lb/hr) 2.96 5.87 

SO4 as Sulfur in Fuel [Assume 1 mol S for each mol SO4] (lb/hr) 0.99 1.96 

% S as SO4 0.46% 0.73% 

Sulfur Available for SO2 Formation [backing out Sulfur for SO4] 211.94 267.17 

% S as SO2 99.54% 99.27% 

Max SO2 (lb/hr) 423.88 534.35 

Table 3-5 provides a summary of the mass balance data and calculations for the annual baseline SO2

emission rate. The calculation approach was the same as that for the short-term SO2, except that the 

2009 fuel usage was used to represent the annual baseline. 
 

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BART Analysis 

TABLE 3-5. ANNUAL BASELINE SO2 EMISSION RATE (TPY) BASED ON MASS BALANCE

Parameter Hill 5 Hill 6 

Baseline [2009] HI (MMBtu/yr) 1,354,786 1,419,920 

No. 6 Oil Heat Content (MMBtu/Mgal) 148.77 148.77 

Fuel Use (gal/yr) 9,106,398 9,544,206 

No. 6 Oil Density (lb/gal) 8.04 8.04 

Average Sulfur in No. 6 Oil (%) 1.86 1.86 

Average Sulfur in No. 6 Oil (tpy) 679.33 711.99 

SO4 from 2010 Stack Test [Assume CPM IOR = SO4] (lb/hr) 2.49 5.87 

SO4 from 2010 Stack Test [Assume CPM IOR = SO4] (tpy) 2.30 5.42 

SO4 as Sulfur in Fuel [Assume 1 mol S for each mol SO4] (tpy) 0.77 1.81 

% S as SO4 0.11% 0.25% 

Sulfur Available for SO2 Formation [backing out Sulfur for SO4] 678.56 710.18 

% S as SO2 99.89% 99.75% 

 SO2 (tpy) 1357.13 1420.37 

3.2 EXISTING NOX, SO2, AND PM10 EMISSIONS AND ASSOCIATED VISIBILITY 

IMPAIRMENT

Trinity conducted modeling to determine the visibility impairment attributable to the Hill 5 and Hill 6 

boilers in both HNP and VNP using the CALPUFF dispersion model. Air quality models, such as 

CALPUFF, are primarily used as a quantitative tool to correlate the emissions and concentration 

levels found in an area. CALPUFF is the EPA preferred model for assessing long-range transport of 

pollutants and their impacts. Table 3-6 summarizes the emission rates used in the baseline modeling. 

The emission rates match the rates shown in Tables 3-1 (NOx and PM10) and 3-4 (SO2), except that 

the PM10 rates in Table 3-6 break down the PM10 species. The emission rates for the PM10 species 

reflect the breakdown of the PM10 determined from the 2010 stack test data. More specifically, the 

stack test showed the following distribution for the PM species: 

• Filterable PM10-2.5 (PMC) = 41.05% 

• Filterable PM2.5 = 31.04% 

• Organic condensable PM (modeled as SOA) = 1.09% 

• Inorganic condensable PM (modeled as SO4) = 26.82% 

The PM2.5 was further speciated into fine PM (PMF) and elemental carbon (EC) using the following 

speciation suggested by the National Park Service in their “speciation spreadsheet” for uncontrolled 

heavy-oil fired utility boilers: 

• PMF = 92.6% Filterable PM2.5

• EC = 7.4% Filterable PM2.
 

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TABLE 3-6. MODELED BASELINE EMISSION RATES

Unit 

SO2

(lb/hr) 

SO4 

(lb/hr) 

NOX 

(lb/hr) 

PMC 

(lb/hr) 

PMF 

(lb/hr) 

SOA 

(lb/hr) 

EC 

(lb/hr) 

PM10, total 

(lb/hr) 

Hill 5 423.9 3.0 112.6 4.5 3.2 0.1 0.3 11.0 

Hill 6 534.3 5.9 122.0 2.0 2.8 0.3 0.2 11.2 

Table 3-7 provides a summary of the modeled visibility impacts attributable to Hill 5 and 

Hills 6 at HNP and VNP based on the emission rates shown in Table 3-6. Note that all of 

the CALMET, CALPUFF, and CALPOST modeling files are included as part of the 

electronic files submitted with this application. 

TABLE 3-7. BASELINE VISIBILITY IMPACTS ATTRIBUTABLE TO HILL 5 AND HILL 6 

Year 

Maximum 

(Δdv) 

98th Percentile 

(Δdv) 

98th Percentile 

% SO4

98th Percentile 

% NO3

98th Percentile 

% PM10 

98th Percentile 

% NO2

Volcanoes National Park

2005 3.08 1.56 73.63 24.32 0.81 1.25 

2006 2.56 1.40 80.88 17.29 0.86 0.98 

2006 2.21 1.43 76.81 20.98 1.04 1.17 

Haleakala National Park 

2005 0.55 0.44 97.87 1.57 0.53 0.03 

2006 0.89 0.32 85.05 8.95 2.09 3.91 

2007 0.90 0.48 93.23 5.66 0.83 0.27 

Table 3-7 shows that for the days representing the 98th percentile of the visibility impacts, the impacts 

are predominantly caused by sulfates. A more detailed review of the CALPOST list files shows that 

most, if not all, days have impacts that are predominantly caused by sulfates. 
 

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4. SO2 BART EVALUATION

The baseline SO2 emission rates that have been used in the BART analysis are summarized in Table 

4-1. The basis of the emission rates is provided in Section 3 of this report. The boilers currently do 

not have SO2 controls. 

TABLE 4-1. SUMMARY OF BASELINE SO2 EMISSION RATES

SO2 Short Term 

Emission Rate 

SO2 Annual 

Emission Rate 

Unit (lb/hr) (tpy) 

Hill 5 423.9 1357.13 

Hill 6 534.3 1420.37 

4.1 IDENTIFICATION OF AVAILABLE RETROFIT SO2 CONTROL 

TECHNOLOGIES

Sulfur oxides, SOx, are generated during fuel oil combustion from the oxidation of sulfur contained in 

the fuel. SOx emissions are almost entirely dependent on the sulfur content of the fuel and are not 

affected by boiler size or burner design. SOx emission from conventional combustion systems are 

predominantly in the form of SO2. Since SO2 is the predominant sulfur compound emitted from the 

Hill boilers, the BART analysis is specific to emissions of SO2. 

Step 1 of the top-down control review is to identify available retrofit control options for SO2. The 

available SO2 retrofit control technologies for the Hill boilers are summarized in Table 4-2. The 

retrofit controls include both add-on controls that eliminate SO2 after it is formed and switching to 

lower sulfur fuels which reduces the formation of SO2. 

TABLE 4-2. AVAILABLE SO2 CONTROL TECHNOLOGIES FOR HILL 5 & HILL 6 

SO2 Control Technologies 

Dry Sorbent Injection 

Spray Dryer Absorber (SDA) i.e., Semi-Dry Scrubber 

Wet Scrubber 

Circulating Dry Scrubber (CDS) 

Fuel Switching 

4.2 ELIMINATE TECHNICALLY INFEASIBLE SO2 CONTROL TECHNOLOGIES

Step 2 of the BART determination is to eliminate technically infeasible SO2 control technologies that 

were identified in Step 1. 
 

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4.2.1 DRY SORBENT INJECTION, SPRAY DRYER ABSORPTION (SDA), WET SCRUBBER,

CIRCULATING DRY SCRUBBER (CDS) 

These technologies are collectively known as flue gas desulfurization (FGD) systems. 

FGD applications have not been used historically for SO2 control on oil-fired units in the 

U.S. electric industry. As there are no known FGD applications for oil-fired units, the 

performance of FGDs on oil-fired units is unknown. EPA took this into account when 

evaluating the presumptive SO2 emission rate for oil-fired units and determined that the 

presumptive emission rate should be based on the sulfur content of the fuel oil, rather than 

on FGD5 rates. Since there are no applications of FGD on oil-fired units in the U.S., FGDs 

are considered technically infeasible for the control of SO2 from Hill 5 and Hill 6 and are 

not considered further for BART. 

4.2.2 FUEL SWITCHING 

The Hill boilers currently burn residual fuel oil with a maximum sulfur content of 2 percent 

by weight. Switching to a fuel with lower sulfur content should reduce SO2 emissions in 

proportion to the reduction in the sulfur content of the fuel. Distillate oil (~No. 2) is 

available and could be burned in the boilers. Although lower sulfur residual oil is 

available, it is not a technically feasible option. This oil has a higher viscosity than the 

existing residual oil and exists as a semi-solid at ambient temperatures. Thus, in order for 

the lower sulfur residual oil to be burned, the barges, piping and tanks that are used to 

transport and store the existing oil would need to be heated. Other grades of fuel oil with 

lower sulfur content are not currently produced by the refineries that supply the Hill plant. 

Natural gas also has less sulfur than the existing residual fuel oil. However, natural gas is 

not a technically feasible option, because there is no natural gas supply in the state of 

Hawaii. Importing liquid natural gas (LNG) would require siting and constructing an LNG 

import facility which, in itself, might be technically or politically, as well as economically, 

infeasible. 

If HELCO were to switch to a lower sulfur fuel, distillate oil is the only feasible option. 

That being said, it has yet to be determined if the refineries that serve the island of Hawaii 

can supply HELCO with enough distillate oil to meet HELCO’s demands. 

4.3 RANK OF TECHNICALLY FEASIBLE SO2 CONTROL OPTIONS BY 

EFFECTIVENESS

The third step in the BART analysis is to rank the technically feasible options according to 

effectiveness. Fuel switching is the only remaining technically feasible control option. Since SO2 

emissions from fuel combustion are generally proportional to the sulfur content of the fuel, 

combusting distillate oil (0. 4 percent sulfur) should result in approximately a 80.0 percent reduction 

in SO2 emissions from the Hill boilers as compared to the combustion of the current residual fuel oil 

(2.0 percent sulfur) 

 5 Summary of Comments and Responses on the 2004 and 2001 Proposed Guidelines for Best Available Retrofit 

Technology (BART) Determinations Under the Regional Haze Regulations EPA Docket Number OAR-2002-0076. 
 

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4.4 EVALUATION OF IMPACTS FOR FEASIBLE SO2 CONTROLS 

Step four of the BART analysis procedure is the impact analysis. The BART determination 

guidelines list the four factors to be considered in the impact analysis: 

▲ Cost of compliance 

▲ Energy impacts 

▲ Non-air quality impacts; and 

▲ The remaining useful life of the source 

4.4.1 COST OF COMPLIANCE

The cost effectiveness of switching to distillate oil has been evaluated. 

Control Cost

The cost of the fuel switching that was used in the cost effectiveness calculations was 

determined by calculating the annual cost of the current residual fuel oil and determining 

the increased cost of switching to distillate oil. Switching fuel will require changes to the 

burners and the fuel system. However, for this analysis capital expenses were not 

included. 

As HELCO currently obtains distillate fuel oil from local suppliers for its other generating 

units including combustion turbines, the estimated per gallon fuel costs were available and 

were used for the costing analysis. Note that the cost estimates prepared for the use of 

distillate oil assume that the existing residual oil would be completely replaced with 

distillate oil. However, this quantity of distillate oil would require new contracts to be 

made between HELCO and the fuel suppliers. This adds a level of uncertainty to the 

pricing and availability scenarios presented. 

Annual Tons Reduced

The annual tons reduced that were used in the cost effectiveness calculations were 

determined by subtracting the estimated controlled annual emission rates from the baseline 

annual emission rates. The baseline annual emission rates are summarized in Table 4-1 

and are further described in Section 3 of this report. 

The controlled annual emission rates were estimated by conducting a mass balance on the 

sulfur in the distillate oil. Since it is unknown what the sulfur level of the distillate oil will 

be in the future, the mass balance considered both the average sulfur level in distillate fuel 

received at the site in 2009 (0.15%) as well as the maximum sulfur level allowed by the 

existing fuel supply contract (0.4%). Tables 4-3 and 4-4 provide a summary of the mass 

balance data and calculations for the future annual SO2 emission rates considering 0.15% 

sulfur distillate oil and 0.4% sulfur distillate oil, respectively. Note that the percentage of 

sulfur that is indicated to be emitted as SO4 in both Tables 4-3 and 4-4 is based on the 

percentage of the baseline annual sulfur that was determined to be SO4, as described in 

Section 3. 
 

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TABLE 4-3. SUMMARY OF FUTURE ANNUAL SO2 EMISSIONS ASSOCIATED WITH DISTILLATE OIL 

AT 0.15% SULFUR

Parameter Hill 5 Hill 6 

Baseline [2009] HI (MMBtu/yr) 1,354,786 1,419,920 

No. 2 Oil Heat Content (MMBtu/Mgal) 139.15 139.15 

Fuel Use (gal/yr) 9,736,296 10,204,388 

No. 2 Oil Density (lb/gal) 7.0 7.0 

Sulfur in No. 2 Oil (%) 0.15 0.15 

Sulfur in No. 2 Oil (tpy) 50.50 52.93 

% S as SO4 0.11% 0.25% 

Sulfur Available for SO2 Formation [backing out Sulfur for SO4] 50.45 52.80 

% S as SO2 99.89% 99.75% 

 SO2 (tpy) 100.89 105.59 

TABLE 4-4. SUMMARY OF FUTURE ANNUAL SO2 EMISSIONS ASSOCIATED WITH DISTILLATE OIL 

AT 0.4% SULFUR

Parameter Hill 5 Hill 6 

Baseline [2009] HI (MMBtu/yr) 1,354,786 1,419,920 

No. 2 Oil Heat Content (MMBtu/Mgal) 139.15 139.15 

Fuel Use (gal/yr) 9,736,296 10,204,388 

No. 2 Oil Density (lb/gal) 7.0 7.0 

 Sulfur in No. 2 Oil (%) 0.40 0.40 

Sulfur in No. 2 Oil (tpy) 136.31 142.86 

% S as SO4 0.11% 0.25% 

Sulfur Available for SO2 Formation [backing out Sulfur for SO4] 136.15 142.50 

% S as SO2 99.89% 99.75% 

 SO2 (tpy) 272.31 285.00 

Cost Effectiveness

Table 4-5 presents a summary of the cost effectiveness of switching from residual fuel to 

distillate oil. The cost effectiveness was determined by dividing the annual cost increase of 

fuel switching by the annual tons of SO2 reduced. In the BART guidelines, EPA calculated 

that the majority of BART-eligible units could meet the presumptive limits at a cost of 

$400 to $2,000 per ton of SO2 removed. Table 4-3 indicates that the cost of switching is to 

distillate oil is over $5,000/ton, which is well above EPA’s calculation. 
TABLE 4-5. SUMMARY OF COST EFFECTIVENESS FOR SWITCHING FROM RESIDUAL FUEL OIL TO DISTILLA

Actual to Actual Approach (2009 Average Sulfur for Baseline, 2009 Average Sulfur for No. 2 Oil)

Hill 5

Sulfur 

ContentA

Baseline 

Emission 

Rate

Controlled 

Emission 

Rate

SO2 

Reduced

Annual Heat 

Input

Fuel Heating 

Value (HHV)B Annual Fuel Usage

Fuel 

CostC Fuel Cost

Cost of Fuel 

Switching

SO2 Cost 

Effectiveness

(%) (tpy) (tpy) (tpy) (MMBtu/yr) (MMBtu/Mgal) (Mgal/yr) ($/gal) $/yr $/yr $/ton

Residual Oil 1.86 1,357.13 - - 1,354,786 148.77 9106.40 1.43 13,022,149 - -

Distillate Oil 0.15 - 100.89 1,256.24 1,354,786 139.15 9736.30 2.00 19,472,592 6,450,443 5,135

Hill 6

Sulfur 

ContentA

Baseline 

Emission 

Rate

Controlled 

Emission 

Rate

SO2 

Reduced

Annual Heat 

Input

Fuel Heating 

Value (HHV)B Annual Fuel Usage

Fuel 

CostC Fuel Cost

Cost of Fuel 

Switching

SO2 Cost 

Effectiveness

(%) (tpy) (tpy) (tpy) (MMBtu/hr) (Mgal/yr) ($/gal) $/hr $/yr $/ton

Residual Oil 1.86 1,420.37 - - 1,419,920 148.77 9544.21 1.43 13,648,215 - -

Distillate Oil 0.15 - 105.59 1,314.78 1,419,920 139.15 10204.39 2.00 20,408,776 6,760,561 5,142

A Sulfur content of residual oil based on average of fuel burned in 2009. Sulfur content of distillate oil based on average sulfur in distillate oil burned in other units at the site.B Higher heating value of residual oil based on average of fuel burned in 2009. Higher heating value of distillate oil from "Combustion - Fossil Fuel Systems, J. G. Singer, Ed: published by Combustion EngC Residual oil cost based on existing purchase price of fuel from Tesoro & Chevron, approximately $60/barrel (~1.43/gal). Diesel oil cost based on existing purchase price from Tesoro & Chevron, approximActual to Contract Approach (2009 Average Sulfur for Baseline, Contract Sulfur for No. 2 Oil)

Hill 5

Sulfur 

ContentA

Baseline 

Emission 

Rate

Controlled 

Emission 

Rate

SO2 

Reduced

Annual Heat 

Input

Fuel Heating 

Value (HHV)B Annual Fuel Usage

Fuel 

CostC Fuel Cost

Cost of Fuel 

Switching

SO2 Cost 

Effectiveness

(%) (tpy) (tpy) (tpy) (MMBtu/yr) (MMBtu/Mgal) (Mgal/yr) ($/gal) $/yr $/yr $/ton

Residual Oil 1.86 1,357.13 - - 38 148.77 9106.40 1.43 13,022,149 - -

Distillate Oil 0.40 - 272.31 1,084.82 38 139.15 9736.30 2.00 19,472,592 6,450,443 5,946

Hill 6

Sulfur 

ContentA

Baseline 

Emission 

Rate

Controlled 

Emission 

Rate

SO2 

Reduced

Annual Heat 

Input

Fuel Heating 

Value (HHV)B Annual Fuel Usage

Fuel 

CostC Fuel Cost

Cost of Fuel 

Switching

SO2 Cost 

Effectiveness

(%) (tpy) (tpy) (tpy) (MMBtu/hr) (Mgal/yr) ($/gal) $/hr $/yr $/ton

Residual Oil 1.86 1,420.37 - - 32 148.77 9544.21 1.43 13,648,215 - -

Distillate Oil 0.40 - 285.00 1,135.37 32 139.15 10204.39 2.00 20,408,776 6,760,561 5,955

AB Higher heating value of residual oil based on average of fuel burned in 2009. Higher heating value of distillate oil from "Combustion - Fossil Fuel Systems, J. G. Singer, Ed: published by Combustion EngC Residual oil cost based on existing purchase price of fuel from Tesoro & Chevron, approximately $60/barrel (~1.43/gal). Diesel oil cost based on existing purchase price from Tesoro & Chevron, approxim

 Sulfur content of residual oil based on average of fuel burned in 2009. Sulfur content of distillate oil based on maximum allowed by contract (0.4%).

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4.4.1.1

4.4.1.2

ENERGY IMPACTS AND NON-AIR QUALITY IMPACTS

The cost increase associated with fuel switching to distillate oil will 

significantly increase energy costs for HELCO customers because it will not 

only increase the cost of electricity produced by Hill 5 and Hill 6, but it will 

also increase the cost of electricity that HELCO purchases from independent 

power producers (“IPPs”). The HELCO system has a high degree of renewable 

energy penetration on its system (approximately 30%). Nearly half of the 

renewable energy is from intermittent sources, primarily wind and hydroelectric 

generation, most of which is provided by IPPs. Given the relatively small size 

of the HELCO system, the intermittent energy tends to destabilize the grid. 

Hill 5 and Hill 6 are "must run" units that, through their frequency regulation, 

voltage regulation and inertia that are not provided by the renewable energy 

resources, provide system stability necessary to offset the impacts of the 

renewable resources. The contracts with the independent power producers 

("IPPs") are tied to HELCO's "avoided cost" of producing electricity. Thus, as 

HELCO's fuel costs increase for Hill 5 and 6, the price that the IPPs receive for 

the roughly 30% of electricity they provide increases. As a result, the costs of 

all electricity sources increase as HELCO's fuel costs increase. 

REMAINING USEFUL LIFE

The remaining useful lives of Hill 5 and Hill 6 do not impact the annualized 

cost for this analysis, since it is assumed that fuel switching will not require any 

significant capital costs, and thus for the purpose of this analysis there is 

nothing to capitalize that would require a review of the life of the equipment. 

4.5 EVALUATION OF VISIBILITY IMPACT OF FEASIBLE SO2 CONTROLS 

An impact analysis was conducted to assess the visibility improvement associated with the 

combustion of distillate oil. Section 3 of this report documented the existing visibility impairment 

attributable to Hill 5 and Hill 6. In order to assess the visibility improvement associated with the 

switch to distillate oil, the maximum short-term SO2 emission rates associated with the combustion of 

distillate oil in Hill 5 and Hill 6 were modeled using CALPUFF. 

The maximum short-term SO2 emission rates associated with the combustion of distillate oil were 

calculated by a mass balance. Table 4-6 provides a summary of maximum short-term SO2 emission 

rate associated with the combustion of distillate oil. Note that the percentage of sulfur that is 

indicated to be emitted as SO4 in Table 4-6 is based on the percentage of the baseline short term 

sulfur that was determined to be SO4, as described in Section 3. 
 

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TABLE 4-6. SUMMARY OF MAXIMUM SO2 EMISSIONS ASSOCIATED WITH DISTILLATE OIL 

Parameter Hill 5 Hill 6 

Maximum HI per CSP (MMBtu/hr) 197 249 

No. 2 Oil Heat Content (MMBtu/Mgal) 139.15 139.15 

Max Fuel Usage (gal/hr) 1415.76 1789.46 

No. 2 Oil Density (lb/gal) 7.0 7.0 

No. 2 Fuel Oil Max Sulfur (%) 0.4 0.4 

Maximum Sulfur in No. 2 Oil (lb/hr) 39.64 50.10 

% S as SO2 99.54% 99.27% 

% S as SO4 0.46% 0.73% 

Max SO2 (lb/hr) 78.92 99.48 

Max SO4 (lb/hr) 0.55 1.09 

Table 4-7 summarizes the emission rates that were modeled to reflect a switch to distillate oil. The 

explanation for the SO2 emission rates associated with the distillate oil is provided above. The 

explanation of the PM10 rates associated with distillate oil is included in Section 6 of this report (the 

BART analysis for PM10). The emission rates for NOx shown in Table 4-7 are the same as in the 

baseline modeling, since, for purposes of the SO2 BART analysis, it is assumed that NOx emissions 

will not be impacted by the switch to distillate oil. In reality, it is likely that NOx emissions will be 

lower on distillate oil than residual oil, but the level of NOx reduction is difficult to project. 

TABLE 4-7. SUMMARY OF EMISSION RATES MODELED TO REFLECT SWITCH TO DISTILLATE OIL 

FOR SO2 CONTROL 

Unit 

SO2

(lb/hr) 

SO4 

(lb/hr) 

NOX 

(lb/hr) 

PMC 

(lb/hr) 

PMF 

(lb/hr) 

SOA 

(lb/hr) 

EC 

(lb/hr) 

PM10, total 

(lb/hr) 

Hill 5 78.9 0.6 112.6 0.0 0.0 0.0 0.0 0.6 

Hill 6 99.5 1.1 122.0 0.0 0.0 0.0 0.0 1.1 

Table 4-8 provides a comparison of the existing visibility impairment and the visibility impairment 

associated with the combustion of distillate oil in VNP and HNP, including the maximum modeled 

visibility impact, 98th percentile modeled visibility impact, and the number of days with a modeled 

visibility impact greater than 0.5 Δdv. The visibility improvement shown in the table was calculated 

as the difference between the existing visibility impairment and the visibility impairment associated 

with the combustion of distillate oil as measured by the 98th percentile. 
 

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TABLE 4-8. SUMMARY OF VISIBILITY IMPROVEMENT ASSOCIATED WITH SWITCH TO 

DISTILLATE OIL

Volcanoes National Park Haleakala National Park 

 

Maximum Impact (

Δdv) 

98% Impact (

Δdv) 

# Days > 0.5 

Δdv 

Visibility Improvement (

Δdv)*,† 

Visibility Improvement*,† Maximum Impact (

Δdv) 

98% Impact (

Δdv) 

# Days > 0.5 

Δdv 

Visibility Improvement (

Δdv)*,† 

Visibility Improvement*,† 

2005 2005 

Baseline 3.08 1.56 123 - - 0.55 0.44 3 - - 

Distillate Oil 1.42 0.60 15 0.96 61.8% 0.12 0.09 0 0.34 78.4%

2006 2006 

Baseline 2.56 1.40 115 - - 0.89 0.32 2 - - 

Distillate Oil 0.76 0.57 11 0.83 59.6% 0.20 0.08 0 0.24 76.3%

2007 2007 

Baseline 2.21 1.43 103 - - 0.90 0.48 7 - - 

Distillate Oil 0.92 0.56 9 0.87 60.9% 0.20 0.11 0 0.37 77.5%

*Improvement is based on the 98th percentile impact (Δdv) compared to the baseline impact (Δdv) 

†The visibility improvement shown in the table has been calculated from 98th percentile baseline and 

controlled impacts that include more decimal places than what is shown in the table. Due to rounding 

of the baseline and controlled 98th percentile impacts shown in the table, the visibility improvement 

calculated from the baseline and controlled 98th percentile impacts shown in the table may be slightly 

different than the visibility improvement reflected in the table. 

As shown in Table 4-8, the combustion of distillate oil results in an estimated 0.83 to 0.96 Δdv 

improvement (60 to 62 percent) of the 98th percentile visibility impairment attributable to Hill 5 and 

Hill 6 in VNP and an estimated 0.24 to 0.37 Δdv improvement (76 to 78 percent) of the 98th

percentile visibility impairment attributable to Hill 5 and Hill 6 in HNP. Note that this improvement 

to the visibility impairment relies on an approach for establishing natural conditions that does not 

consider the local volcanic activity. As the volcanic activity is a primary cause of visibility 

impairment, the improvement in visibility impairment represented by Table 4-8 does not reflect 

reality. More representative natural conditions that take the volcanic activity into account will result 

in reduced visibility improvements. 

4.6 PROPOSED BART FOR SO2

Switching to distillate oil reduces SO2 emissions based on the reduction in the sulfur content of the 

distillate oil compared to the existing residual oil. The estimated cost of completely replacing the 

existing residual oil with distillate oil is between $5,100 and $6,000 per ton of SO2 reduced for each 

of the Hill boilers. While this cost represents the maximum SO2 reductions that are technically 
 

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feasible, it is an extremely costly approach to reducing SO2 emissions. Model predictions based on 

natural conditions that do not account for the local volcanic activity suggest that the combustion of 

distillate oil will reduce the Hill boiler’s contribution to visibility impairment in VNP and HNP by up 

to 0.96 Δdv and 0.37 Δdv, respectively. 

Regardless of whether HELCO were to switch to distillate oil or some other fuel, it may not feasible 

to implement a change in the 5-year time frame required for the implementation of BART controls. 

HELCO needs to explore whether an adequate supply of distillate oil currently exists to meet the full 

needs of the boilers or whether other lower-sulfur fuels can be manufactured and supplied to HELCO. 

That being said, the over $5,100/ton cost of the switch to distillate oil coupled with reduction in 

visibility impairment of up to only 0.96 Δdv do not warrant a determination of this fuel change as 

BART. Thus, there are no fuel changes or add-on controls proposed as BART for SO2 for the Hill 

boilers. 

While there are no fuel changes or add-on controls proposed as BART, it should be mentioned that 

other long-term emission reduction strategies, such as those included as part of the Hawaii Clean 

Energy Initiative (HCEI) may be viable alternatives to BART. HECO looks forward to working 

through the BART process with EPA and/or Hawaii DOH in an effort to accomplish the Regional 

Haze Rule objectives.
 

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5. NOX BART EVALUATION

The baseline NOx emission rates that were used in the BART analysis are summarized in Table 5-1. 

The basis of the emission rates is provided in Section 3 of this report. The boilers currently do not 

have NOx controls. 

TABLE 5-1. SUMMARY OF BASELINE EMISSION RATES 

NOX Emission 

Rate 

NOX Emission 

Rate 

NOX Emission 

Rate 

Unit (lb/hr) (tpy) (lb/MMBtu) 

Hill 5 112.6 387.26 0.57 

Hill 6 122.0 347.85 0.49 

5.1 IDENTIFICATION OF AVAILABLE RETROFIT NOX CONTROL 

TECHNOLOGIES

Nitrogen oxides, NOx, are produced during fuel combustion when nitrogen contained in the fuel and 

combustion air is exposed to high temperatures. The origin of the nitrogen (i.e. fuel vs. combustion 

air) has lead to the use of the terms “thermal” NOx and “fuel” NOx when describing NOx emissions 

from the combustion of fuel. Thermal NOx emissions are produced when elemental nitrogen in the 

combustion air is admitted to a high temperature zone and oxidized. Fuel NOx emissions are created 

during the rapid oxidation of nitrogen compounds contained in the fuel. NOX emissions from residual 

oil can be up to 50% fuel NOx.6

Nitrogen oxide (NO) is typically the predominant form of NOx emissions from fossil fuel combustion, 

along with nitrogen dioxide (NO2). The formation of NOx compounds in utility boilers is sensitive to 

the method of firing and combustion controls utilized. 

Step 1 of the BART determination is the identification of all available retrofit NOx control 

technologies. The available retrofit NOx control technologies are summarized in Table 5-2 for Hill 5 

and Hill 6. 

TABLE 5-2. AVAILABLE NOX CONTROL TECHNOLOGIES FOR HILL 5 & HILL 6 

NOX Control Technologies 

Combustion Controls 

Flue Gas Recirculation (FGR) 

Overfire Air (OFA) 

Low NOX Burners (LNB) 

Post-Combustion Controls Selective Catalytic Reduction (SCR) 

Selective Non-Catalytic Reduction (SNCR) 

NOX emissions controls, as listed in Table 5-2, can be categorized as combustion or post-combustion 

controls. Combustion controls, including flue gas recirculation (FGR), overfire air (OFA), and Low 

 6 AP-42, Fifth Edition, Volume I, Chapter 1, Section 1.3.3 
 

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NOX Burners (LNB), reduce the peak flame temperature and excess air in the furnace which 

minimizes NOX formation. Post-combustion controls, such as selective catalytic reduction (SCR) and 

selective non-catalytic reduction (SNCR) convert NOx in the flue gas to molecular nitrogen and 

water. 

5.2 ELIMINATE TECHNICALLY INFEASIBLE NOX CONTROL TECHNOLOGIES

Step 2 of the BART determination is to eliminate technically infeasible NOX control technologies that 

were identified in Step 1. 

5.2.1 COMBUSTION CONTROLS

5.2.1.1

5.2.1.2

5.2.1.3

 

FLUE GAS RECIRCULATION (FGR) 

FGR uses flue gas as an inert material to reduce flame temperatures. In a 

typical flue gas recirculation system, flue gas is collected from the combustion 

chamber or stack and returned to the burner via a duct and blower. The 

addition of flue gas reduces the oxygen content of the “combustion air” (air + 

flue gas) in the burner. The lower oxygen level in the combustion zone reduces 

flame temperatures; which in turn reduces thermal NOx formation. When 

operated without additional controls, the NOx control range for wall fired 

boilers (Hill 5) with FGR is approximately 0.25-0.30 lb/MMBtu, and for 

tangentially fired boilers (Hill 6) is 0.15-0.20 lb/MMBtu.7 This control is a 

technically feasible option for the control of NOX from Hill 5 and Hill 6. 

OVERFIRE AIR (OFA) 

OFA diverts a portion of the total combustion air from the burners and injects it 

through separate air ports above the top level of burners. Staging of the 

combustion air creates an initial fuel-rich combustion zone with a lower peak 

flame temperature. This reduces the formation of thermal NOx by lowering 

combustion temperature and limiting the availability of oxygen in the 

combustion zone where NOx is most likely to be formed. 

OFA as a single NOx control technique results in estimated NOx emissions for 

wall fired boilers (Hill 5) of 0.2-0.3 lb/MMBtu and for tangentially fired boilers 

(Hill 6) is 0.15-0.20 lb/MMBtu.8 This control is a technically feasible option 

for the control of NOx from Hill 5 and Hill 6. 

LOW NOX BURNERS

LNB technology utilizes advanced burner design to reduce NOx formation 

through the restriction of oxygen, lowering of flame temperature, and/or 

reduced residence time. NOx creation rates typically peak at oxygen levels of 

five to seven percent.9 LNB is a staged combustion process that is designed to 

split fuel combustion into two zones. In the primary zone, NOx formation is 

7 “Alternative Control Techniques (ACT) Document – NOx Emissions from Utility Boiler” EPA, 1994. 

8 Ibid. 

9 http://www.energysolutionscenter.org/boilerburner/Workshop/RCTCombustion.htm.
 

Hawaii Electric Light Company, Inc. 5-3 Trinity Consultants 

BART Analysis 

limited by either one of two methods. Under staged fuel-rich conditions, low 

oxygen levels limit flame temperatures resulting in less NOx formation. The 

primary zone is then followed by a secondary zone in which the incomplete 

combustion products formed in the primary zone act as reducing agents. 

Alternatively, under staged fuel-lean conditions, excess air will reduce flame 

temperature to reduce NOx formation. In the secondary zone, combustion 

products formed in the primary zone act to lower the local oxygen 

concentration, resulting in a decrease in NOx formation. 

The estimated NOX control range for LNBs on wall fired boilers (Hill 5) is 

0.25-0.35 lb/MMBtu and for tangentially fired boilers (Hill 6) is 0.15-0.20 

lb/MMBtu.10 When combined with OFA, the estimated NOX control range on 

wall fired boilers is 0.25-0.30 lb/MMBtu and for tangentially fired boilers (Hill 

6) is 0.15-0.20 lb/MMBtu.11 LNB systems are technically feasible for the 

control of NOx from Hill 5 and Hill 6. 

5.2.2 POST COMBUSTION CONTROLS

5.2.2.1

5.2.2.2

 

SELECTIVE CATALYTIC REDUCTION

SCR refers to the process in which NOx is reduced by ammonia over a 

heterogeneous catalyst in the presence of oxygen. The process is termed 

selective because the ammonia preferentially reacts with NOx rather than 

oxygen, although the oxygen enhances the reaction and is a necessary 

component of the process. The overall reactions are: 

4NO + 4NH3 + O2 Æ 4N2 + 6H2O 

2NO2 + 4NH3 + O2 Æ 3N2 + 6H2O 

The SCR process requires a reactor, a catalyst, and an ammonia storage and 

injection system. The effectiveness of an SCR system is dependent on a variety 

of factors, including the inlet NOx concentration, the exhaust temperature, the 

ammonia injection rate, and the type of catalyst. The estimated NOX control 

range for SCR is 0.05-0.10 for a wall fired boiler (Hill 5) and for tangentially 

fired boilers (Hill 6) is 0.03-0.10 lb/MMBtu.12 When coupled with LNB plus 

OFA, the estimated NOX control range is 0.03 – 0.10 lb/MMBtu and for 

tangentially fired boilers (Hill 6) is 0.03-0.10 lb/MMBtu.13 This control is a 

technically feasible option for the control of NOx from Hill 5 and Hill 6. 

SELECTIVE NON-CATALYTIC REDUCTION

In SNCR systems, a reagent is injected into the flue gas in the furnace within an 

appropriate temperature window. The NOx and reagent (ammonia or urea) 

10 “Alternative Control Techniques (ACT) Document – NOx Emissions from Utility Boiler” EPA, 1994. 

11 Ibid. 

12 “Alternative Control Techniques (ACT) Document – NOx Emissions from Utility Boiler” EPA, 1994. 

13 Ibid. 
 

Hawaii Electric Light Company, Inc. 5-4 Trinity Consultants 

BART Analysis 

react to form nitrogen and water. A typical SNCR system consists of reagent 

storage, multi-level reagent-injection equipment, and associated control 

instrumentation. The SNCR reagent storage and handling systems are similar 

to those for SCR systems. However, both ammonia and urea SNCR processes 

require three or four times as much reagent as SCR systems to achieve similar 

NOx reductions. The estimated NOx control range for SNCR for wall fired 

boilers (Hill 5) is 0.3-0.4 lb/MMBtu and for tangentially fired boilers (Hill 6) is 

0.2-0.25 lb/MMBtu.14 This control is a technically feasible option for the 

control of NOx from Hill 5 and Hill 6. 

5.3 RANK OF TECHNICALLY FEASIBLE NOX CONTROL OPTIONS BY 

EFFECTIVENESS

The third step in the BART analysis is to rank the technically feasible options according to 

effectiveness. Table 5-3 provides a ranking of the control levels for the controls listed in the 

previous section for Hill 5 and Hill 6. 

TABLE 5-3. CONTROL EFFECTIVENESS OF TECHNICALLY FEASIBLE NOX CONTROL 

TECHNOLOGIES

Control Technology 

Estimated Controlled 

Level for 

Wall Fired Boilers 

 (lb/MMBtu)15

Estimated Controlled 

Level for 

Tangentially Fired 

Boilers 

 (lb/MMBtu) 16

SCR ~0.05-0.10 ~0.03-0.10 

LNB & OFA ~0.25-0.30 ~0.15-0.20 

FGR ~0.25-0.30 ~0.15-0.20 

LNB ~0.25-0.35 ~0.15-0.20 

SNCR ~0.30-0.40 ~0.20-0.25 

OFA ~0.30-0.45 ~0.20-0.30 

The control levels in Table 5-3 are presented as a range. This is due to the fact that the specific level 

of control that is achievable for the Hill boilers based on the application of the controls listed in Table 

5-3 is unknown. Based on several discussions between Trinity and a firm that designs LNB 

combustion systems, it is believed that combustion controls such as LNB and possibly LNB in 

combination with OFA or FGR will achieve a NOx level of approximately 0.30 lb/MMBtu and 0.18 

lb/MMBtu for Hill 5 and Hill 6, respectively. As noted in Table 5-1, the Hill boilers are currently 

emitting in the range of 0.49 to 0.57 lb/MMBtu. Further, it is believed that SCR will achieve a NOx

level of approximately 0.10 lb/MMBtu. 

 14 Ibid. 

15 Ibid. 

16 Ibid. 
 

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BART Analysis 

5.4 EVALUATION OF IMPACTS FOR FEASIBLE NOX CONTROLS 

Step four for the BART analysis is the impact analysis. The BART determination guidelines list four 

factors to be considered in the impact analysis: 

▲ Cost of compliance 

▲ Energy impacts 

▲ Non-air quality impacts; and 

▲ The remaining useful life of the source 

5.4.1 COST OF COMPLIANCE

The capital costs, operating costs, and cost effectiveness of LNB systems and SCR were 

estimated for the cost analysis. The use of LNB in the cost analysis is intended to 

represent a level of NOx control of approximately 0.30 lb/MMBtu and 0.18 lb/MMBtu for 

Hill 5 and Hill 6, respectively that is achievable with combustion controls. At this time, it 

is unknown if LNBs alone can achieve emissions in this range or if achieving emissions in 

this range would also require OFA or FGR. In order to take a conservative approach to the 

costing, it is assumed that a NOx level of 0.30 lb/MMBtu and 0.18 lb/MMBtu for Hill 5 

and Hill 6, respectively can be achieved with LNB alone. As the level of NOx emissions 

that can be achieved with SNCR is comparable to combustion controls, the only add-on 

control that would be expected to result in lower achievable NOx rates than combustion 

controls is SCR. 

Control Costs

The capital and operating costs of the controls that were used in the cost effectiveness 

calculations were estimated based on published calculations methods. The capital costs 

were annualized over a 15-year period and then added to the annual operating costs to 

obtain the total annualized costs. The details of the capital and operating cost estimates are 

provided in Appendix A of this report. 

Annual Tons Reduced

The annual tons reduced that were used in the cost effectiveness calculations were 

determined by subtracting the estimated controlled annual emission rates from the baseline 

annual emission rates. The baseline annual emission rates are summarized in Table 5-1 

and are further described in Section 3 of this report. The controlled annual emission rates 

were based on lb/MMBtu levels believed to be achievable multiplied by the baseline heat 

input to each boiler. Assuming HELCO operates the boilers on the same schedule in the 

future as in the past, the future heat input is expected to be approximately the same as the 

past heat input. The baseline [2009] heat inputs are as follows: Hill 5 = 1,354,786 

MMBtu/yr and Hill 6 = 1,419,920 MMBtu/yr. 

 

Cost Effectiveness

The cost effectiveness was determined by dividing the annualized cost by the annual tons 

reduced. The incremental cost effectiveness was also calculated for SCR. In this case, the 

incremental cost analysis was performed to show the incremental increase in costs between 

SCR and an LNB system. The costs effectiveness analysis is summarized in Table 5-4. 
 

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BART Analysis 

In the BART guidelines, EPA calculated that for all types of boilers other than cyclone 

boilers, combustion control technology is generally more cost-effective than postcombustion controls. EPA estimates that approximately 75 percent of the BART units 

(non-cyclone) could meet the presumptive NOx limits at a cost of $100 to $1,000 per ton of 

NOx removed based on the use of combustion control technology. For the units that could 

not meet the presumptive limits using combustion control technology, EPA estimates that 

almost all of these sources could meet the presumptive limits using advanced combustion 

controls. The EPA estimates that the costs of such controls are usually less than $1,500 per 

ton of NOX removed. 

Table 5-4 indicates that the cost effectiveness of LNB at a NOx rate of 0.30 lb/MMBtu and 

0.18 lb/MMBtu for Hill 5 and Hill 6, respectively is between $650-1,100 per ton of NOx 

removed. Table 5-4 also indicates that the costs for SCR for Hill 5 and Hill 6 are greater 

than $2,200 per ton of NOx removed. Additionally, the incremental cost of the SCR over 

the LNB systems is greater than $4,500 and $8,100 per ton of NOx removed for Hill 5 and 

Hill 6, respectively. 
Hawaiian Electric Light Company, Inc. 5-7 

BART Analysis 

TABLE 5-4.

SUMMARY OF 

COST 

EFFECTIVENESS FOR 

HILL 

5

&

HILL 

6 NOX CONTROLS

Hill 5

Baseline Controlled Controlled Annualized Annualized Total 

Emission 

Rate

Emission 

LevelA

Annual Heat 

Input

Emission 

Rate

NOx 

Reduced

Capital 

Cost

Capital 

Cost

Annualized 

Fixed O&M

Variable 

O&M

Annualize

Cost

(tpy) (lb/MMBtu) (MMBtu/yr) (tpy) (ton/yr) ($) ($/yr) ($/yr) ($/yr) ($/yr) 

LNBB 387.26 0.3 1,354,786 203.22 184.04 1,526,715 167,625 22,901 4,931 197,517 

SCRC 387.26 0.10 1354786.15 67.74 319.52 5,351,928 646,374 646,374 153,391 829,305 Hill 6

Baseline 

Emission 

Rate

Controlled 

Emission 

LevelA

Annual Heat 

Input

Controlled 

Emission 

Rate

NOx 

Reduced

Capital 

Cost

Annualized 

Capital 

Cost

Annualized 

Fixed O&M

Annualized 

Variable 

O&M

Total 

Annualize

CostC

(tpy) (lb/MMBtu) (MMBtu/yr) (tpy) (ton/yr) ($) ($/yr) ($/yr) ($/yr) ($/yr) 

LNBB 347.85 0.18 1419920.16 127.79 220.06 1,115,681 122,496 16,735 6,232 146,969 

SCRC 347.85 0.10 1419920.16 71.00 276.86 3,883,355 469,009 469,009 120,231 610,674 

A "Alternative Control Techniques (ACT) Document - NOx Emissions from Utility Boiler." 1994. Tables 2-7 & 2-8.C SCR Cost information: Source: Technical Bulletin: Nitrogen Oxides (NOx), Why and How They Are Controlled, US EPA OAQPS EPA 456/F-99-00B LNB Cost information: Source: ERG, 2005. Analysis of Combustion Controls for Reducing NOx Emissions from Coal-fired EGUs in the WRAP Re

Additional details on the cost calculations are included in Appendix D.
 

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BART Analysis 

5.4.2 ENERGY IMPACTS & NON-AIR IMPACTS

SCR systems require electricity to operate the ancillary equipment. The need for electricity 

to help power some of the ancillary equipment creates a demand for energy that currently 

does not exist. 

SCR can potentially cause significant environmental impacts related to the storage of 

ammonia. That being said, the storage of aqueous ammonia above 10,000 lbs is regulated 

by a risk management program (RMP), since the accidental release of ammonia has the 

potential to cause serious injury and death to persons in the vicinity of the release. SCR 

will likely also cause the release of unreacted ammonia to the atmosphere. This is referred 

to as ammonia slip. Ammonia slip from SCR systems occurs either from ammonia 

injection at temperatures too low for effective reaction with NOx, leading to an excess of 

unreacted ammonia, or from over-injection of reagent leading to uneven distribution; 

which also leads to an excess of unreacted ammonia. Ammonia released from SCR 

systems will react with sulfates and nitrates in the atmosphere to form ammonium sulfate. 

Together, ammonium sulfate and ammonium nitrate are the predominant sources of 

regional haze. 

5.4.3 REMAINING USEFUL LIFE

The remaining useful lives of Hill 5 and Hill 6 do not impact the annualized capital costs of 

potential controls because the useful life of the boilers is anticipated to be at least as long 

as the capital cost recovery period, which is 15 years. 

5.5 EVALUATION OF VISIBILITY IMPACT OF FEASIBLE NOX CONTROLS 

The final impact analysis was conducted to assess the visibility improvement for existing emission 

rates when compared to the emission rates associated with LNB and SCR systems. Section 3 of this 

report documented the existing visibility impairment attributable to Hill 5 and Hill 6. In order to 

assess the visibility improvement associated with LNB and SCR systems, the maximum short-term 

NOx emission rates associated with both LNB and SCR systems were modeled using CALPUFF. 

The maximum short-term NOx emission rates associated with LNB and SCR systems were calculated 

by multiplying the controlled lb/MMBtu level by the maximum heat inputs for the boilers (Hill 5 = 

197 MMBtu/hr and Hill 6 = 249 MMBtu/hr). The controlled emission levels associated with SCR 

systems are 0.1 lb/MMBtu for both Hill 5 and Hill6. The controlled emission levels associated with 

the LNB systems for Hill 5 and Hill 6 are 0.3 lb/MMBtu and 0.18 lb/MMBtu, respectively. 

Tables 5-5 and 5-6 summarize the NOx emission rates that were modeled to reflect the LNB and SCR 

systems, respectively. The emission rates for the other pollutants shown in Table 5-4 are the same as 

in the baseline modeling. 
 

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BART Analysis 

TABLE 5-5. SUMMARY OF EMISSION RATES MODELED TO REFLECT LNB FOR NOX CONTROL

 

SO2

(lb/hr) 

SO4 

(lb/hr) 

NOX 

(lb/hr) 

PMC 

(lb/hr) 

PMF 

(lb/hr) 

SOA 

(lb/hr) 

EC 

(lb/hr) 

PM10, total 

(lb/hr) 

Hill 5 423.9 3.0 59.1 4.5 3.2 0.1 0.3 11.0 

Hill 6 534.3 5.9 44.8 2.0 2.8 0.3 0.2 11.2 

TABLE 5-6. SUMMARY OF EMISSION RATES MODELED TO REFLECT SCR FOR NOX CONTROL

 

SO2

(lb/hr) 

SO4 

(lb/hr) 

NOX 

(lb/hr) 

PMC 

(lb/hr) 

PMF 

(lb/hr) 

SOA 

(lb/hr) 

EC 

(lb/hr) 

PM10, total 

(lb/hr) 

Hill 5 423.9 3.0 19.7 4.5 3.2 0.1 0.3 11.0 

Hill 6 534.3 5.9 24.9 2.0 2.8 0.3 0.2 11.2 

Table 5-7 provides a comparison of the existing visibility impairment and the visibility impairment 

associated with the addition of LNB systems on Hill 5 and Hill 6 in VNP and HNP, including the 

maximum modeled visibility impact, 98th percentile modeled visibility impact, and the number of 

days with a modeled visibility impact greater than 0.5 Δdv. The visibility improvement shown in the 

table was calculated as the difference between the existing visibility impairment and the visibility 

impairment associated with the combustion of distillate oil as measured by the 98th percentile. 

TABLE 5-7. SUMMARY OF VISIBILITY IMPROVEMENT ASSOCIATED WITH LNB SYSTEMS ON HILL 

5 AND HILL 6 

Volcanoes National Park Haleakala National Park 

 

Maximum Impact (

Δdv) 

98% Impact (

Δdv) 

# Days > 0.5 

Δdv 

Visibility Improvement (

Δdv)*,† 

Visibility Improvement* Maximum Impact (

Δdv) 

98% Impact (

Δdv) 

# Days > 0.5 

Δdv 

Visibility Improvement (

Δdv)*,† 

Visibility Improvement* 

2005 2005 

Baseline 3.08 1.56 123 - - 0.55 0.44 3 - - 

LNB Systems 2.65 1.35 108 0.21 13.3% 0.54 0.41 3 0.02 4.6% 

2006 2006 

Baseline 2.56 1.40 115 - - 0.89 0.32 2 - - 

LNB Systems 2.42 1.27 97 0.14 9.6% 0.87 0.31 1 0.01 1.9% 

2007 2007 

Baseline 2.21 1.43 103 - - 0.90 0.48 7 - - 

LNB Systems 1.99 1.27 73 0.16 11.0% 0.89 0.47 6 0.02 3.1% 

*Improvement is based on the 98th percentile impact (Δdv) compared to the baseline impact (Δdv) 
 

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BART Analysis 

†The visibility improvement shown in the table has been calculated from 98th percentile baseline and 

controlled impacts that include more decimal places than what is shown in the table. Due to rounding 

of the baseline and controlled 98th percentile impacts shown in the table, the visibility improvement 

calculated from the baseline and controlled 98th percentile impacts shown in the table may be slightly 

different than the visibility improvement reflected in the table. 

Table 5-8 provides a comparison of the existing visibility impairment and the visibility impairment 

associated with SCR systems on Hill 5 and Hill 6 in Hawaii VNP and HNP, including the maximum 

modeled visibility impact, 98th percentile modeled visibility impact, and the number of days with a 

modeled visibility impact greater than 0.5 Δdv. The visibility improvement shown in the table was 

calculated as the difference between the existing visibility impairment and the visibility impairment 

associated with the combustion of distillate oil as measured by the 98th percentile. More 

representative natural conditions that take the volcanic activity into account would result in reduced 

visibility improvements. 

TABLE 5-8. SUMMARY OF VISIBILITY IMPROVEMENT ASSOCIATED WITH SCR SYSTEMS ON HILL 

5 AND HILL 6 

Volcanoes National Park Haleakala National Park 

 

Maximum Impact (

Δdv) 

98% Impact (

Δdv) 

# Days > 0.5 

Δdv 

Visibility Improvement (

Δdv)*,† 

Visibility Improvement* Maximum Impact (

Δdv) 

98% Impact (

Δdv) 

# Days > 0.5 

Δdv 

Visibility Improvement (

Δdv)*,† 

Visibility Improvement* 

2005 2005 

Baseline 3.08 1.56 123 - - 1.56 123 3 - - 

SCR Systems 2.44 1.29 95 0.27 17.6% 0.54 0.41 3 0.03 5.7% 

2006 2006 

Baseline 2.56 1.40 115 - - 1.40 115 2 - - 

SCR Systems 2.36 1.20 90 0.20 14.1% 0.87 0.31 1 0.01 2.2% 

2007 2007 

Baseline 2.21 1.43 103 - - 1.43 103 7 - - 

SCR Systems 1.88 1.25 58 0.17 12.1% 0.88 0.46 6 0.02 4.6% 

*Improvement is based on the 98th percentile impact (Δdv) compared to the baseline impact (Δdv) 

†The visibility improvement shown in the table has been calculated from 98th percentile baseline and 

controlled impacts that include more decimal places than what is shown in the table. Due to rounding 

of the baseline and controlled 98th percentile impacts shown in the table, the visibility improvement 

calculated from the baseline and controlled 98th percentile impacts shown in the table may be slightly 

different than the visibility improvement reflected in the table. 
 

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BART Analysis 

As shown in Table 5-7, the operation of LNB systems results in an estimated 0.14 to 0.21 Δdv 

improvement (10 to 13 percent) of the 98th percentile visibility impairment attributable to Hill 5 and 

Hill 6 in VNP and an estimated 0.01 to 0.02 Δdv improvement (2 to 5 percent) of the 98th percentile 

visibility impairment attributable to Hill 5 and Hill 6 in HNP. Further, as shown in Table 5-8, the 

operation of SCR systems results in an estimated 0.17 to 0.27 Δdv improvement (12 to 18 percent) of 

the 98th percentile visibility impairment attributable to Hill 5 & Hill 6 in VNP and an estimated 0.01 

to 0.03 Δdv improvement (2 to 6 percent) of the 98th percentile visibility impairment attributable to 

Hill 5 and Hill 6 in HNP. Note that the improvement to the visibility impairment relies on an 

approach for establishing natural conditions that does not consider the local volcanic activity. As the 

volcanic activity is a primary cause of visibility impairment, the improvement in visibility impairment 

represented by Tables 5-7 and 5-8 does not reflect reality. 

5.6 PROPOSED BART FOR NOX 

As mentioned in Section 2 of this report, EPA has concluded that “for oil-fired and gas-fired EGUs 

larger than 200 MW, “we believe that installation of current combustion control technology to control 

NOx is generally highly cost-effective and should be considered in your determination of BART for 

these sources”. While the Hill boilers serve generators that are smaller than 200MW, combustion 

control technology on the smaller Hill boilers is also more cost-effective than post- combustion 

controls. 

Specifically, it would cost an estimated $2,595/ton, and $2,206/ton to install and operate SCR 

systems on Hill 5 and Hill 6, respectively. Model predictions based on natural conditions that do not 

account for the local volcanic activity suggest that the operation of SCR systems will reduce the Hill 

boiler’s contribution to visibility impairment in VNP and HNP by up to 0.27 Δdv and 0.03 Δdv, 

respectively. In addition, it would cost more than $4,600/ton to go from LNB systems that could 

achieve 0.30 lb/MMBtu and 0.18 lb/MMBtu NOx to SCR systems that could achieve 0.10 lb/MMBtu 

NOx. 

LNB systems can be installed for an estimated $650-1,100 per boiler and result in model predicted 

reductions in visibility impairment attributable to the Hill boilers of up to 0.21 Δdv. Thus, BART is 

determined to be the operation of an LNB system capable of achieving a NOx level of 0.30 lb/MMBtu 

for Hill 5 and 0.18 lb/MMBtu for Hill 6. 
 

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BART Analysis 

6. PM10 BART EVALUATION

The baseline PM10 emission rates that were used in the PM10 BART analysis are summarized in Table 

6-1. The basis of the emission rates is provided in Section 3 of this report. The boilers currently do 

not have PM controls. 

TABLE 6-1. SUMMARY OF BASELINE PM10 EMISSION RATES

PM10 Emission 

Rate 

PM10 Emission 

Rate 

PM10 Emission 

Rate 

Unit (lb/hr) (tpy) (lb/MMBtu) 

Hill 5 11.04 38.07 0.056 

Hill 6 11.17 31.85 0.045 

6.1 IDENTIFICATION OF AVAILABLE RETROFIT PM10 CONTROL 

TECHNOLOGIES

PM10 emissions are either “filterable” or “condensable”. Filterable PM10 is generally considered to be 

particles less than or equal to 10 microns in diameter that are trapped by a filter during testing of 

exhaust gas. Condensable PM is material that is emitted in the vapor state which later condenses to 

form aerosol particles. Filterable particulate matter emissions depend predominantly on the grade of 

fuel fired. Combustion of lighter distillate oils results in significantly lower PM formation than does 

combustion of heavier residual oils. Among residual oils, firing of No. 4 or No. 5 oil usually produces 

less PM than does the firing of heavier residual oil. This is due to the higher ash and sulfur contents 

of residual oil compared to lighter oils. As shown in Table 6-1, the PM10 emissions from the Hill 

boilers are fairly low and the majority of the PM10 is filterable PM10. 

 

Step 1 of the BART determination is the identification of all available retrofit PM control 

technologies. The available retrofit PM control technologies are summarized in Table 6-2 for Hill 5 

and Hill 6. 

TABLE 6-2. AVAILABLE PM CONTROL TECHNOLOGIES FOR HILL 5 & HILL 6 

PM10 Control Technologies 

Dry Electrostatic Precipitator (ESP) 

Wet Electrostatic Precipitator (ESP) 

Fabric Filter 

Wet Scrubber 

Cyclone 

Fuel Switching 
 

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BART Analysis 

6.2 ELIMINATE TECHNICALLY INFEASIBLE PM CONTROL TECHNOLOGIES

Step 2 of the BART determination is to eliminate technically infeasible PM control technologies that 

were identified in Step 1. 

6.2.1 DRY ELECTROSTATIC PRECIPITATORS (ESP) 

A dry ESP operates by first placing a charge on the particles through a series of electrodes, 

and then capturing the charged particles on collection plates. Particles from oil-fired 

boilers tend to be sticky and small. Because of these properties and a general lack of 

existence in practice, a dry ESP is not a good technological match for any of the Hill 

boilers. 

6.2.2 MECHANICAL COLLECTORS (CYCLONES) 

Mechanical collectors, or cyclones, control particulates generated during soot blowing, 

during upset conditions, or when a heavy oil is fired. For these situations, high-efficiency 

cyclonic collectors can achieve up to 85% control of particulate17. This control is designed 

for the larger PM size fractions, and thus, when firing residual oil, the control will not be 

effective at controlling the smaller particles that are a source of visibility impairment. 

Further, when a clean oil is combusted, cyclonic collectors are not nearly so effective 

because of the high percentage of small particles (less than 3 micrometers in diameter) 

emitted. Since cyclones are generally not effective at controlling the PM size fractions that 

contribute to visibility impairment, cyclones are considered technically infeasible. 

6.2.3 WET ELECTROSTATIC PRECIPITATORS (ESP) 

A wet ESP operates very similarly to a dry ESP but is a better technological match for oilfired boilers because it is not sensitive to small and sticky particulates. The wet ESP 

utilizes water to collect and remove the particles, and will produce a waste-water product. 

Flue gas leaving wet ESPs will be saturated and may result in a visual steam plume exiting 

the stack. The estimated PM control efficiency is up to 90% for a wet ESP.18 Wet ESP is 

a technically feasible option for control of PM10 for boilers Hill 5 and Hill 6. 

6.2.4 FABRIC FILTER

Fabric filters work by filtering the PM in flue gas through filter bags. The collected 

particles are periodically removed from the bag through a pulse jet or reverse flow 

mechanism. Due to the sticky nature of particles from oil-fired boilers and the associated 

hazard from flammability of their use, fabric filters are not used to control PM from boilers 

firing residual oil. Thus, fabric filters are not technically feasible for Hill 5 and Hill 6. 

 17 AP-42, Fifth Edition, Volume I, Chapter 1, Section 1.3.4.1 

18 Ibid. 
 

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BART Analysis 

6.2.5 WET SCRUBBER

Wet scrubbers remove PM from flue gas. The gas stream is brought into contact with a 

scrubbing liquid using several approaches: spraying the gas stream with the liquid, forcing 

the gas stream through a pool of liquid, or by some other contact method. PM in the gas 

stream is captured in the scrubbing liquid. The PM-laden scrubbing liquid is separated 

from the gas stream, and the resultant scrubbing liquid is treated prior to discharge or reuse 

in the plant. Problems associated with scrubbers include corrosion issues, high power 

requirements, and water-disposal challenges. However, the use of wet scrubbers for the 

Hill boilers is considered a technically feasible option. The estimated PM10 removal 

efficiency for a wet scrubber is 50-60%.19 

While wet scrubbers are considered technically feasible, it is worth noting the wet 

scrubbers are not very efficient at controlling submicron size particles. When drops of 

water are suspended in a stream of air containing particles, such as they are in wet 

scrubbers, the air must go around the drops to pass through the scrubber. This creates 

streamlines of higher velocity air near each drop. For particles to be captured, they must 

push through these streamlines to the surface of the drop. Particles that are under 1 micron 

are hardest to control because they follow the streamlines and avoid contact with the drop. 

As particle size decreases, more energy is needed to force contact with the drops. This 

makes conventional scrubbers ineffective for particles below a few microns.20 While the 

majority of the PM emissions for the Hill boilers are not less than a few microns, particles 

of this size have the highest ability to impair visibility; thus, a wet scrubber may not be 

effective at controlling the particles that have the greatest ability to impair visibility. 

6.2.6 FUEL SWITCHING 

Residual oil has inherent ash that contributes to the emissions of filterable PM. 

Specifically, the residual oil currently burned in the Hill boilers plant has an ash content of 

approximately 0.035 percent by weight. Lower grades of fuel oil have less ash and 

ultimately lower filterable PM emissions. Filterable PM emissions could be reduced by 

switching to a lower grade fuel oil or natural gas. Section 4 discussed the option of fuel 

switching with respect to reducing SO2 emissions. As discussed in Section 4, HELCO is 

limited in fuel choices for the Hill boilers based on its geography. Distillate oil is the only 

technically feasible fuel choice. 

Distillate fuel oil has only trace amounts of ash21. It is estimated that filterable PM10

emissions would be reduced in proportion to the reduction in ash content. Based on the 

reduction in ash content, reductions of filterable PM10 would be expected to be over 99%. 

 19 AP-42, Fifth Edition, Volume I, Chapter 1, Section 1.3.4.1 

20 http://www.tri-mer.com/q&a/comparing-electrostatic-precipitator.htm

21 Combustion-Fossil Power Systems, J.G. Singer published by Combustion Engineer, Inc, 
 

Hawaii Electric Light Company, Inc. 6-4 Trinity Consultants 

BART Analysis 

6.3 RANK OF TECHNICALLY FEASIBLE PM10 CONTROL OPTIONS BY 

EFFECTIVENESS

Step 3 of the top-down control review is to rank the technically feasible options according to 

effectiveness. Table 6-3 provides a ranking of the control levels for the controls listed in the 

previous section. 

TABLE 6-3. CONTROL EFFECTIVENESS OF TECHNICALLY FEASIBLE PM CONTROL 

TECHNOLOGIES

Control Technology 

Estimated Controlled 

Level22 

 (%) 

Distillate oil ~99% 

Wet ESP ≤90 

Wet Scrubber ~50-60 

6.4 EVALUATION OF IMPACTS FOR FEASIBLE PM10 CONTROLS 

Step four for the BART analysis procedure is the impact analysis. The BART determination 

guidelines list the four factors to be considered in the impact analysis: 

▲ Cost of compliance 

▲ Energy impacts 

▲ Non-air quality impacts; and 

▲ The remaining useful life of the source 

6.4.1 COST OF COMPLIANCE

The capital costs, operating costs, and cost effectiveness of wet ESPs and wet scrubbers 

have been estimated for Hill 5 and Hill 6. The cost effectiveness of switching to a distillate 

fuel has also been estimated. 

Control Costs

The capital and operating costs of the ESP and scrubber that were used in the cost 

effectiveness calculations were estimated based on published calculations methods. The 

capital costs were annualized over a 15-year period and then added to the annual operating 

costs to obtain the total annualized costs. The details of the capital and operating cost 

estimates are provided in Appendix B of this report. 

Annual Tons Reduced

The annual tons reduced that were used in the cost effectiveness calculations were 

determined by subtracting the estimated controlled annual emission rates from the baseline 

 22AP-42, Fifth Edition, Volume I, Chapter 1, Section 1.3.4.1 
 

Hawaii Electric Light Company, Inc. 6-5 Trinity Consultants 

BART Analysis 

annual emission rates. The baseline annual emission rates are summarized in Table 6-1 

and are further described in Section 3 of this report. The controlled annual emission rates 

were estimated by reducing the existing annual emission rate by the control percentages 

shown in Table 6-3 (99% for distillate oil, 90% for a wet ESP, and 50% for a wet 

scrubber). 

 

Cost Effectiveness

The cost effectiveness was determined by dividing the annualized cost by the annual tons 

reduced. The costs effectiveness analysis is summarized in Table 6-4. 

Table 6-4 indicates that the cost effectiveness of switching to distillate oil is over 

$170,000/ton for each boiler. Further, Table 6-4 indicates that the cost effectiveness of a 

wet ESP for Hill 5 or Hill 6 is over $13,000/ton per boiler. Finally, Table 6-4 shows that 

the cost effectiveness of a wet scrubber for Hill 5 or Hill 6 is over $4,600/ton per boiler. 

6.4.1.1

6.4.1.2

ENERGY IMPACTS AND NON-AIR QUALITY IMPACTS

There are no energy or non-air quality impacts associated with fuel switching, 

but there are impacts associated with wet ESPs and wet scrubbers. ESPs by 

design apply energy to the particles they are collecting. This energy usage can 

be significant, especially if the wet ESP is designed to control submicron size 

particles where more energy is applied to collect more of the particles. Wet 

scrubbers also require a substantial amount of energy to force exhaust gases 

through the scrubber. 

Both wet ESPs and wet scrubber generate wastewater streams that must either 

be treated on-site or sent to a waste water treatment plant. Further, the 

wastewater treatment process will generate a filter cake that would likely 

require land-filling. 

REMAINING USEFUL LIFE

The remaining useful lives of Hill 5 and Hill 6 do not impact the annualized 

capital costs of the wet ESP or wet scrubber because the useful life of the 

boilers is anticipated to be at least as long as the capital cost recovery period, 

which is 15 years. Further, the remaining useful lives of Hill 5 and Hill 6 do 

not impact the annualized fuel cost, since it is assumed that fuel switching will 

not require any capital costs, and thus there is nothing to capitalize that would 

require a review of the life of the equipment. 
Hawaiian Electric Light Company, Inc. 6-6 

BART Analysis 

TABLE 6-4.

SUMMARY OF 

COST 

EFFECTIVENESS FOR 

HILL 

5

&

HILL 

6 PM10

CONTROLS

Hill 5

Baseline Controlled Annualized Total Total 

Emission 

Rate

Emission 

Control A,B

Emission 

Rate PM Reduced

Capital 

Cost

Capital 

Cost

Total Direct 

Annual Cost

Indirect 

CostE

Annualized 

Cost

Cost 

Effectiven

(tpy) (%) (tpy) (ton/yr) ($) ($/yr) ($/yr) ($/yr) ($/yr) ($/ton

Wet scrubberD 38.07 50 19.04 19.04 170,612 18,732 57,930 30,507 88,437 4,646 

ESPC 38.07 90 3.81 34.26 2,643,532 290,246 31,779 415,054 446,833 13,04

Fuel S

witching to 

Distillate Oil 38.07 99 0.38 37.69 N/A N/A N/A N/A 6,450,443 171,14Hill 6

Baseline 

Annual 

Emission 

Rate

Emission 

Control A,B

Controlled 

Emission 

Rate

Reduced 

Emissions

Capital 

Cost

Annualized 

Capital 

Cost

Total Direct 

Annual Cost

Total 

Indirect 

CostE

Total 

Annualized 

Cost

Cost 

Effectiven

(tpy) (%) (tpy) (ton/yr) ($) ($/yr) ($/yr) ($/yr) ($/yr) ($/ton

Wet scrubberD 31.85 50 15.92 15.92 170,612 18,732 57,930 30,507 88,437 5,554 

ESPC 31.85 90 3.18 28.66 2,643,532 290,246 31,779 415,054 446,833 15,58

Fuel S

witching to 

Distillate Oil 31.85 99 0.32 31.53 N/A N/A N/A N/A 6,760,561 214,41

A Control estimation for ESP and Scrubber from: AP-42, Fifth Edition, Volume I, Chapter 1, Section 1.3.3C ESP Cost information: Source: U.S. Envrionmental Protection Agency, EPA Air Pollution Control Cost Manual, Sixth Edition. Chapter 6. D Wet Scrubber Cost information: Source: U.S. Envrionmental Protection Agency, EPA Air Pollution Control Cost Manual, Sixth Edition. Chapter 6. E Total annual cost for fuel switching is provided in Table 4-3, SO2 fuel analysis.B Percent reduction from fuel switching estimated from reduced ash content in No. 2 fuel compared to May 2010 source tests of current No. 6 fuel, 0.035% a

content in No. 2 fuel is "trace amount". Source: Combustion-Fossil Power Systems, J.G Singer, Ed: published by Combustion Engineer, Inc.
 

Hawaiian Electric Light Company, Inc. 6-7 Trinity Consultants 

BART Analysis 

6.5 EVALUATION OF VISIBILITY IMPACT OF FEASIBLE PM10 CONTROLS 

The final impact analysis was conducted to assess the visibility improvement for existing emission 

rates when compared to the emission rates associated with wet ESPs and wet scrubbers. Note that the 

visibility improvement associated with the switch to distillate oil was evaluated as part of the BART 

review for SO2 in Section 4 of this report. Section 3 of this report documented the existing visibility 

impairment attributable to Hill 5 and Hill 6. In order to assess the visibility improvement associated 

with wet ESPs and scrubbers, the maximum short-term PM10 emission rates associated with these 

controls were modeled using CALPUFF. 

The maximum short-term PM10 emission rates associated with wet ESPs and scrubbers were 

calculated by reducing the uncontrolled short-term PM10 emission rates shown in Tables 6-1 and 3-7 

(where Table 3-7 provides the speciated PM10 emission rates based on the total PM10 shown in Table 

6-1) by the control percentages shown in Table 6-3 (99% for distillate oil, 90% for a wet ESP, and 

50% for a wet scrubber). 

Tables 6-5 and 6-6 summarize the emission rates that were modeled to reflect the wet ESPs and 

scrubber, respectively. The emission rates for the pollutants shown in Table 6-5 and 6-6 that are not 

PM are the same as in the baseline modeling. 

TABLE 6-5. SUMMARY OF EMISSION RATES MODELED TO REFLECT WET ESP FOR PM10

CONTROL

Unit 

SO2

(lb/hr) 

SO4 

(lb/hr) 

NOX 

(lb/hr) 

PMC 

(lb/hr) 

PMF 

(lb/hr) 

SOA 

(lb/hr) 

EC 

(lb/hr) 

PM10, total 

(lb/hr) 

Hill 5 423.9 0.3 112.6 0.5 0.3 0.0 0.0 1.1 

Hill 6 534.3 0.6 122.0 0.2 0.3 0.0 0.0 1.1 

TABLE 6-6. SUMMARY OF EMISSION RATES MODELED TO REFLECT WET SCRUBBER FOR PM10

CONTROL

Unit 

SO2

(lb/hr) 

SO4 

(lb/hr) 

NOX 

(lb/hr) 

PMC 

(lb/hr) 

PMF 

(lb/hr) 

SOA 

(lb/hr) 

EC 

(lb/hr) 

PM10, total 

(lb/hr) 

Hill 5 423.9 1.5 112.6 2.3 1.6 0.1 0.1 5.5 

Hill 6 534.3 2.9 122.0 1.0 1.4 0.2 0.1 5.6 

Table 6-7 provides a comparison of the existing visibility impairment and the visibility impairment 

associated with wet ESPs on Hill 5 and Hill 6 in VNP and HNP, including the maximum modeled 

visibility impact, 98th percentile modeled visibility impact, and the number of days with a modeled 

visibility impact greater than 0.5 Δdv. The visibility improvement shown in the table was calculated 

as the difference between the existing visibility impairment and the visibility impairment associated 

with the addition of wet ESPs as measured by the 98th percentile. More representative natural 

conditions that take the volcanic activity into account will result in reduced visibility improvements. 

 
 

Hawaiian Electric Light Company, Inc. 6-8 Trinity Consultants 

BART Analysis 

TABLE 6-7. SUMMARY OF VISIBILITY IMPROVEMENT ASSOCIATED WITH WET ESPS ON HILL 5

AND HILL 6 

Volcanoes National Park Haleakala National Park 

 

Maximum Impact (

Δdv) 

98% Impact (

Δdv) 

# Days > 0.5 

Δdv 

Visibility Improvement (

Δdv)*,† 

Visibility Improvement*,† Maximum Impact (

Δdv) 

98% Impact (

Δdv) 

# Days > 0.5 

Δdv 

Visibility Improvement (

Δdv)*,† 

Visibility Improvement*,† 

2005 2005 

Baseline 3.08 1.56 123 - - 0.55 0.44 3 - - 

Wet ESPs 2.83 1.48 113 0.08 5.3% 0.53 0.41 1 0.03 7.1% 

2006 2006 

Baseline 2.56 1.40 115 - - 0.89 0.32 2 - - 

Wet ESPs 2.42 1.32 103 0.08 5.5% 0.84 0.31 1 0.01 3.8% 

2007 2007 

Baseline 2.21 1.43 103 - - 0.90 0.48 7 - - 

Wet ESPs 2.13 1.32 76 0.11 7.7% 0.86 0.46 6 0.03 5.2% 

*Improvement is based on the 98th percentile impact (Δdv) compared to the baseline impact (Δdv) 

†The visibility improvement shown in the table has been calculated from 98th percentile baseline and 

controlled impacts that include more decimal places than what is shown in the table. Due to rounding 

of the baseline and controlled 98th percentile impacts shown in the table, the visibility improvement 

calculated from the baseline and controlled 98th percentile impacts shown in the table may be slightly 

different than the visibility improvement reflected in the table. 

Table 6-8 provides a comparison of the existing visibility impairment and the visibility impairment 

associated with wet scrubbers on Hill 5 and Hill 6 in VNP and HNP, including the maximum 

modeled visibility impact, 98th percentile modeled visibility impact, and the number of days with a 

modeled visibility impact greater than 0.5 Δdv. The visibility improvement shown in the table was 

calculated as the difference between the existing visibility impairment and the visibility impairment 

associated with the addition of wet scrubbers as measured by the 98th percentile. 

 
 

Hawaiian Electric Light Company, Inc. 6-9 Trinity Consultants 

BART Analysis 

TABLE 6-8. SUMMARY OF VISIBILITY IMPROVEMENT ASSOCIATED WITH WET SCRUBBERS ON 

HILL 5 AND HILL 6 

Volcanoes National Park Haleakala National Park 

 

Maximum Impact (

Δdv) 

98% Impact (

Δdv) 

# Days > 0.5 

Δdv 

Visibility Improvement (

Δdv)*,† 

Visibility Improvement*,† Maximum Impact (

Δdv) 

98% Impact (

Δdv) 

# Days > 0.5 

Δdv 

Visibility Improvement (

Δdv)*,† 

Visibility Improvement*,† 

2005 2005 

Baseline 3.08 1.56 123 - - 0.55 0.44 3 - - 

Wet Scrubbers 2.94 1.51 117 0.05 3.0% 0.53 0.42 3 0.02 3.7% 

2006 2006 

Baseline 2.56 1.40 115 - - 0.89 0.32 2 - - 

Wet Scrubbers 2.49 1.36 105 0.04 3.1% 0.86 0.31 1 0.01 2.5% 

2007 2007 

Baseline 2.21 1.43 103 - - 0.90 0.48 7 - - 

Wet Scrubbers 2.17 1.36 86 0.06 4.5% 0.88 0.47 6 0.01 2.9% 

*Improvement is based on the 98th percentile impact (Δdv) compared to the baseline impact (Δdv) 

†The visibility improvement shown in the table has been calculated from 98th percentile baseline and 

controlled impacts that include more decimal places than what is shown in the table. Due to rounding 

of the baseline and controlled 98th percentile impacts shown in the table, the visibility improvement 

calculated from the baseline and controlled 98th percentile impacts shown in the table may be slightly 

different than the visibility improvement reflected in the table. 

As shown in Table 6-7, the operation of wet ESPs results in an estimated 0.08 to 0.11 Δdv 

improvement (5 to 8 percent) of the 98th percentile visibility impairment attributable to Hill 5 and Hill 

6 in VNP and an estimated 0.01 to 0.03 Δdv improvement (4 to 7 percent) of the 98th percentile 

visibility impairment attributable to Hill 5 and Hill 6 in HNP. Further, as shown in Table 6-8, the 

operation of wet scrubbers results in an estimated 0.04 to 0.06 Δdv improvement (3 to 5 percent) of 

the 98th percentile visibility impairment attributable to Hill 5 and Hill 6 in VNP and an estimated 0.01 

to 0.02 Δdv improvement (3 to 4 percent) of the 98th percentile visibility impairment attributable to 

Hill 5 and Hill 6 in HNP. Note that the improvement to the visibility impairment relies on an 

approach for establishing natural conditions that does not consider the local volcanic activity. As the 

volcanic activity is a primary cause of visibility impairment, the improvement in visibility impairment 

represented by Tables 6-7 and 6-8 does not reflect reality. 

6.6 PROPOSED BART FOR PM10

The cost effectiveness of all the PM controls evaluated for both the boilers is over $4,600/ton, and for 

most controls is well over $5,000/ton. Based on the low PM10 emission from the boilers (less than 38 
 

Hawaiian Electric Light Company, Inc. 6-10 Trinity Consultants 

BART Analysis 

tpy for either Hill 5 or Hill 6) and the related low improvement to the visibility impairment 

attributable to the Hill boilers based on the application of the controls (only up to 0.06 Δdv), none of 

the controls are determined to satisfy BART. Thus, there are no fuel changes or add-on controls 

proposed as BART for PM10 for the Hill boilers. 
 

Hawaii Electric Light Company, Inc. Trinity Consultants 

BART Analysis 

APPENDIX A 

 NOX CONTROL COST CALCULATIONS
Parameters/Costs Equation Hill 5 Hill 6

Boiler design capacity, mmBtu/hr (C) 197 249

Annual operating hours, hr/yr (H) 8088 8088

Unit Size, kW (kW) 23000 14100

Unit Size, MW (MW) 23 14.1

Capital recovery factor

 = [ I x (1+i)^a]/[(1+i)^a - 1], where I = interest 

rate, a = equipment life 0.11 0.11

a. Equipment CRF, 15-yr life, 7% interest

Cost IndexA

a. May 2009 509.1

b. Dec 2008 575.4

c. 2004 444.2

Total Capital InvestmentB,C,D

TCI ($) =24 x kW x (300/MW)^0.359 $1,526,715 $1,115,681

Direct Annual Operating Costs $/yr

Variable O&M Costs

=(0.027/1000) x (1/10,000) x H x C x (.05/1000) x 

(575.4/444.2) $4,931 $6,232

Indirect Annual Costs, $/yr

1. Fixed O&M Costs (1.5% of capital cost) = 0.015 x TCI $22,901 $16,735

 Fixed O&M Costs with location differentialE,F $24,962 $18,241

2. Capital recovery = Equipment CRF x TCI $167,625 $122,496

1. $/yr =Direct Annual Costs + Indirect Annual Costs $197,517 $146,969

A Cost Index: Chemical Engineering Plant Cost Index (CEPCI). Chemical Engineering Journal. 

B

 Costs range from $6 to $24 per kW capacity of boiler, so the the high end $24/kW was used in this analysis due to the

 increase in demand for steel and the associated increased price.

C Scaling factor = (300/Nameplate capacity)^0.359

D

 Due to high cost of transporting construction materials from the U.S. mainland to the island of Hawaii,

 a 10% factor was applied to capital.

E Fixed Costs include elements such as labor, station power, capital additions/improvements all of which are higher in 

Hawaii as compared to the general US average. 

F Combustion technologies have recurring costs such as a loss in boiler efficiency or increased maintenance labor, associated 

with their use. Hawaii cost of labor differential applied to entire fixed costs to ensure cost accounting for location.

Source: ERG, 2005. Analysis of Combustion Controls for Reducing NOx Emissions from Coal-fired EGUs in the WRAP Region September 6, 2005. Section 4.3.1 

and Appendix D. A cost method developed for coal-fired EGUs was utilized for the residual oil-fired boilers being addressed by this report, since the number 

of EGUs of similar size and fuel type to the boilers being addressed by this report is small and cost estimates are not as established. Further, pluverized coal 

can burn similar to oil, and thus combustion control system options for both fuel types are similar.

LNB Capital and O&M Cost Estimate
Hill 5 Hill 6

23 14.1

0.57 0.49

197 249

0.11 0.11

Cost IndexA

May 2009 509.1

1999 390.6

B = (lb/MMBtu) 0.57 0.49

C = (%) 90 90

A = (kW) 23000 14100

Z = 0.91 0.91

Capital Cost (D) ($) 5,351,928 3,883,355

Capital CostB

location differential ($) 5,887,121 4,271,691

(D)

Annualized Capital Cost ($/yr) 646,374 469,009

G = 0.92 0.92

H = (MMBtu/hr) 197.00 249.00

D = ($/kW) 179 211

E

C,D

location differential = ($/yr) 29,540 21,434

F = ($/yr) 153,391 120,231

Total Cost ($/yr) $829,305 $610,674

Equation 1

Where:

D = Capital cost ($/kW)

B= NOX (lb/10^6 Btu) at the inlet of the SCR reactor; rate of approximate 0.15 - 2.5 lb/10^6 Btu

C = NOx removal efficiency ($%) range of 80-95%

A = Plant capacity (kW)

Equation 2

Capital Recovery Factor (CRF)

SCR Capital and O&M Cost Estimate

MW

Baseline NOx Emission Rate (lb/MMBtu)

Max Heat Input (MMBtu/hr)

35.0

75 300,000 











=

A

Z

D

[( ) ( ) ]

05.0 4.0

Z = B 5.1/ C /100

Equation 3

Where:

E = Fixed O&M cost ($/yr)

D = Capital cost ($/kW) from Equation 1

A = Plant capacity (kw)

C = A constant, 0.0066 yr-1

Equation 4

F = Variable O&M Cost ($/yr)

G = Annual capacity factor (expressed as a fraction)

B = Inlet NOx (lb/MMBtu); range of 0.15 - 2.5 lb/MMBtu

H = Heat input (MMBtu/hr)

C = NOX removal efficiency; range of 80-95%

D = Capital cost ($/kW)

A = Plant capacity (kW)

A Cost Index: Chemical Engineering Plant Cost Index (CEPCI). Chemical Engineering Journal. 

B

 Due to high cost of transporting construction materials from the U.S. mainland to the island of Hawaii, a 10% factor was applied to capital.

C Fixed Costs include elements such as labor, station power, capital additions/improvements all of which are higher in Hawaii as compared 

to the general US average. 

D Combustion technologies have recurring costs such as a loss in boiler efficiency or increased maintenance labor, associated 

with their use. Hawaii cost of labor differential applied to entire fixed costs to ensure cost accounting for location.

Source: Cost of Selective Catalytic Reduction (SCR) Application for NOx Control on Coal-Fired Boilers, EPA/600/R-01/087, October 2001. A cost method 

developed for coal-fired EGUs was utilized for the residual oil-fired boilers being addressed by this report, since the number of EGUs of similar size and fuel 

type to the boilers being addressed by this report is small and cost estimates are not as established. Further, pulverized coal can burn similar to oil, and thus 

combustion control system options for both fuel types are similar.

35.0

75 300,000 











=

A

Z

D

E = D× A×C

F = G{225×[ 37.0 B× H × (C /100)× (8760/ 2000)]× .1 005× 05.1 + .0 025× D × A× Z + 45.1 × A}

[( ) ( ) ]

05.0 4.0

Z = B 5.1/ C /100
 

Hawaii Electric Light Company, Inc. Trinity Consultants 

BART Analysis 

APPENDIX B 

PM10 CONTROL COST CALCULATIONS
Parameters/Costs Equation Hill 5 Hill 6

ParametersTotal Collection Plate area, ft2 (TCP)A 50000 50000

Equipment Cost of ESP, $ (EC)

if TCP </=50,000 =614.55(TCP)^0.6276 $546,551 $546,551

if TCP >50,000 =57.87(TCP)^0.8431

Factor to convert from FRP to other material (m) 1 1

Cost Index

a. May 2009 509.1

b. 1998 389.5

Purchased Equipment Cost (A) $714,375 $714,375

14. Capital recovery factors

= [ I x (1+i)^a]/[(1+i)^a ‐ 1], where I = interest rate, a =

equipment life 0.109794625 0.109794625

Equipment CRF, 15‐yr life, 7$ interest

Direct Costs ‐ Table 3.16

Purchased equipment costs

ESP Capital and O&M Cost Estimate

Page 1 of 2

ESP + auxiliary equipment (A) As estimated, A $714,375 $714,375

Instrumentation 0.10 A $71,438 $71,438

Sales taxes 0.03 A $21,431 $21,431

Freight 0.05 A $35,719 $35,719

Purchased Equipment cost, PEC B = 1.18 A $842,963 $842,963

Direct Installation Costs Table 3.16

Foundation

& supports 0.04 B $33,719 $33,719

Handling

& erection 0.50 B $421,481 $421,481

Electrical 0.08 B $67,437 $67,437

Piping 0.01 B $8,430 $8,430

Insulation for ductwork 0.02B $16,859 $16,859

Painting 0.02B $16,859 $16,859

Direct Installation Costs 0.67 B $564,785 $564,785

Indirect Costs (installation) Table 3.16

Engineering 0.20B $168,593 $168,593Construction

& field expenses 0.20B $168,593 $168,593

Contractor fees 0.10B $84,296 $84,296Start‐up 0.01B $8,430 $8,430Performance test 0.01B $8,430 $8,430Model study 0.02B $16,859 $16,859

Contingencies 0.03B $25,289 $25,289

Total Indirect Costs, IC 0.57B $480,489 $480,489

TOTAL CAPITAL INVESTMENT (2009$)

Table 3.16B

DC + IC = 2.24 * B * (Retrofit factor of 1.4) (Retrofit factor

based on average provided on Page 2‐49) $2,643,532 $2,643,532

Page 1 of 2
Direct Annual Costs

Operating Labor

Operator 3hr/day*360 days/yr * $12/hr $12,960 $12,960

Supervisor 15% of operator $1,944 $1,944

Coordinator 1/3 of operator $4,320 $4,320

Maintenance

Labor

$4,125 for collector area < 50,000 ft^3 (As referenced by

OAQPS for ESP) $4,125 $4,125

Material 1% of purchase equipment costs $8,430 $8,430

Utilities Utilities currently not estimated due to variability

Electricity‐fan

Electricity ‐ operating

Waste disposal

Total Direct Annual Cost $31,779 $31,779

Indirect Costs, IC Table 3.21

Overhead

60% of sum of operating labor, maintenance labor, &

maintenance materials $19,067 $19,067

Administrative charges 2% of Total Capital Investment $52,871 $52,871

Property tax 1% of Total Capital Investment $26,435 $26,435

Insurance 1% of Total Capital Investment $26,435 $26,435

Capital recovery $290,245.55 $290,245.55

Total Indirect Annual Costs $415,054 $415,054

Page 2 of 2

TOTAL ANNUAL COST

$446,833 $446,833

Sources:

A A detailed design of the plate area has not been completed. The exhuast from both boilers had similar flow rates to the example in the manual, thus it was presumed that the

plate area would be of similar size to the example.

B Retrofit factor of 1.4 takes into account the high cost of transporting construction materials from the U. S. mainland to the island of Hawaii, and increased labor cost.

1. U.S. Environmental Protection Agency, EPA Air Pollution Control Cost manual, Sixth Edition. Chapter 6. EPA/452/B‐02‐001, January 2002.

2. Oommen, Roy. Methodology for Estimating Control Costs for the Industrial, Commercial, and Institutional Boilers and Process Heaters National Emission Standards for

Hazardous Air Pollutants, October 2002.

Page 2 of 2
Parameters/Costs Equation Hill 5 Hill 6

 Equipment Cost of Scrubber, $ (EC)

Low engery scrubber w/stainless steel. Stainless steel utilized for corrosion prevention.Scrubber type based on OAQPS example with similar flow rate and temperature. =1.1.*(150*61,000^0.56) $78,935 $78,935

Factor to convert from FRP to other material (m) 1 1Cost Indexa. May 2009 509.1b. 1998 389.5Purchased Equipment Cost (A) $103,173 $103,17314. Capital recovery factors

 = [ I x (1+i)^a]/[(1+i)^a - 1], where I = interest rate, a = equipment life 0.109794625 0.109794625

Equipment CRF, 15-yr life, 7$ interestDirect Costs - Table 2.8 Purchased equipment costs Packaged Unit (A1) As estimated, A1 $103,173 $103,173 Auxiliary Costs (A2) A2 = 0.1A1 $10,317 $10,317 Equipment Costs A = A1 + A2 $113,490 $113,490 Instrumentation 0.10 A $11,349 $11,349 Sales taxes 0.03 A $3,405 $3,405 Freight 0.05 A $5,674 $5,674

Purchased Equipment cost, PEC B = 1.18 A $133,918 $133,918

Direct Installation Costs - Table 2.8 Foundation & supports 0.06 B $8,035 $8,035 Handling & erection 0.40 B $53,567 $53,567 Electrical 0.01 B $1,339 $1,339 Piping 0.05 B $6,696 $6,696 Insulation for ductwork 0.03B $4,018 $4,018 Painting 0.01B $1,339 $1,339

Direct Installation Costs 0.56 B $74,994 $74,994

Indirect Costs (installation) - Table 2.8Engineering 0.10B $13,392 $13,392Construction & field expenses 0.10B $13,392 $2,678Contractor fees 0.10B $13,392 $13,392Start-up 0.01B $1,339 $1,339Performance test 0.01B $1,339 $1,339Model study - Contingencies 0.03B $4,018 $4,018

Total Indirect Costs, IC 0.35B $46,871 $46,871

TOTAL CAPITAL INVESTMENT (2009$)A

(DC + IC ) * (Retrofit factor of 1.4) (Retrofit factor based on average provided for ESP on Page 3-41). No specific factor provided for scrubber, so factor for ESP was relied on. $170,612 $170,612

Scrubber Capital and O&M Cost Estimate

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Direct Annual Costs - Table 2.9

 Operating Labor Operator

3hr/shift*2shifts/day*360 days/yr * $20/hr (Operator hrs/day and $/hr consistent with example on Page 2-57) $43,200 $43,200

 Supervisor 15% of operator $6,480 $6,480 Maintenance Labor

Assumed similar labor requirements as to that required for ESP per Section 6, Page 3-47 of OAQPS Cost manual ($12.50/hr, 7.5 h/wk, 44 wk/yr ) $4,125 $4,125

 Material 100% of maintenance labor $4,125 $4,125 Utilities (consumption rate) * (hrs/yr) * (unit cost) Fan Utilities currently not estimated due to variability Pump Water Operating materials Wastewater disposal

Total Direct Annual Cost $57,930 $57,930

Indirect Costs, IC Administrative charges 2% of Total Capital Investment $3,412 $3,412 Property tax 1% of Total Capital Investment $1,706 $1,706 Insurance 1% of Total Capital Investment $1,706 $1,706 Overhead 60% of total labor and material costs $4,950 $4,950 Capital recovery Capital Recover Factor * Total Capital Investment $18,732.23 $18,732.23

Total Indirect Annual Costs $30,507 $30,507

TOTAL ANNUAL COST

$88,437 $88,437

Sources:A Retrofit factor of 1.4 takes into account the high cost of transporting construction materials from the U. S. mainland to the island of Hawaii, and increased labor cost.

1. U.S. Environmental Protection Agency, EPA Air Pollution Control Cost manual, Sixth Edition. Chapter 6. EPA/452/B-02-001, January 2002.

2. Oommen, Roy. Methodology for Estimating Control Costs for the Industrial, Commercial, and Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants, October 2002.

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