## BART F IVE 

## F ACTOR 

## A NALYSIS 

##  H AWAIIAN 

## E LECTRIC 

## C OMPANY 

## , I NC



## . H AWAII 

## E LECTRIC 

## L IGHT 

## C OMPANY


## , I NC



## . – K ANOELEHUA 

## -H ILL 

## P LANT



### V ERSION 

### 0

Prepared by:

T RINITY 

### C ONSULTANTS 

### 9777 Ridge Drive
Suite 380 Lenexa, Kansas 66219 (913) 894-4500

Prepared for:

H AWAII 

### E LECTRIC 

### L IGHT 

### C OMPANY 

### , I NC



### . P.O. Box 1027 Hilo, Hawaii 96721-1027

October 2010

Project 101701.0132

### Hawaii Electric Light Company, Inc. i Trinity Consultants BART Analysis 

## T ABLE OF 

## C ONTENTS



### 1. E XECUTIVE 

### S UMMARY 

### ........................................................................................ 1-1

2. I NTRODUCTION AND 

### B ACKGROUND 

### .................................................................... 2-1

3. E XISTING 

### E MISSIONS AND 

### V ISIBILITY 

### I MPAIRMENT 

### ......................................... 3-1
3.1 NO X 

### , SO 2 

### , AND 

### PM 10 

### B ASELINE 

### E MISSION 

### R ATES 

### ................................................ 3-1
3.2 E XISTING 

### NO X 

### , SO 2 

### , AND 

### PM 10 

### E MISSIONS AND 

### A SSOCIATED 

### V ISIBILITY 

### I MPAIRMENT 

### ..................................................................................................................... 3-4

4. SO 2 

### BART E VALUATION 

### .................................................................................... 4-1
4.1 I DENTIFICATION OF 

### A VAILABLE 

### R ETROFIT 

### SO 2 

### C ONTROL 

### T ECHNOLOGIES 

### .......... 4-1
4.2 E LIMINATE 

### T ECHNICALLY 

### I NFEASIBLE 

### SO 2 

### C ONTROL 

### T ECHNOLOGIES 

### ................ 4-1

4.2.1 D RY 

### S ORBENT 

### I NJECTION


### , S PRAY 

### D RYER 

### A BSORPTION 

### (SDA), W ET 

### S CRUBBER


### , C IRCULATING 

### D RY 

### S CRUBBER 

### (CDS) ............................................................................. 4-2

4.2.2 F UEL 

### S WITCHING 

### ................................................................................................ 4-2 

### 4.3 R ANK OF 

### T ECHNICALLY 

### F EASIBLE 

### SO 2 

### C ONTROL 

### O PTIONS BY 

### E FFECTIVENESS 

### .. 4-2
4.4 E VALUATION OF 

### I MPACTS FOR 

### F EASIBLE 

### SO 2 

### C ONTROLS 

### ..................................... 4-3

4.4.1 C OST OF 

### C OMPLIANCE 

### ........................................................................................ 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 E VALUATION OF 

### V ISIBILITY 

### I MPACT OF 

### F EASIBLE 

### SO 2 

### C ONTROLS 

### ...................... 4-6
4.6 P ROPOSED 

### B ART FOR 

### SO 2 

### ..................................................................................... 4-8

5. NO X 

### BART E VALUATION 

### ................................................................................... 5-1
5.1 I DENTIFICATION OF 

### A VAILABLE 

### R ETROFIT 

### NO X 

### C ONTROL 

### T ECHNOLOGIES 

### ......... 5-1
5.2 E LIMINATE 

### T ECHNICALLY 

### I NFEASIBLE 

### NO X 

### C ONTROL 

### T ECHNOLOGIES 

### ............... 5-2

5.2.1 C OMBUSTION 

### C ONTROLS 

### .................................................................................... 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 NO X 

### Burners ................................................................................ 5-2

5.2.2 P OST 

### C OMBUSTION 

### C ONTROLS 

### ........................................................................... 5-3

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

5.2.2.2 Selective Non-Cataly tic Reduction ...................................................... 5-3


### 5.3 R ANK OF 

### T ECHNICALLY FEASIBLE 

### NO X 

### C ONTROL 

### O PTIONS BY 

### E FFECTIVENESS 

### .. 5-4
5.4 E VALUATION OF 

### I MPACTS FOR 

### F EASIBLE 

### NO X 

### C ONTROLS 

### ................................... 5-5

5.4.1 C OST OF 

### C OMPLIANCE 

### ........................................................................................ 5-5

5.4.2 E NERGY 

### I MPACTS 

### & N ON 

### -A IR 

### I MPACTS 

### ............................................................ 5-8

5.4.3 R EMAINING 

### U SEFUL 

### L IFE 

### ................................................................................... 5-8


### 5.5 E VALUATION OF 

### V ISIBILITY 

### I MPACT OF 

### F EASIBLE 

### NO X 

### C ONTROLS 

### ..................... 5-8
5.6 P ROPOSED 

### B ART FOR 

### NO X 

### .................................................................................. 5-11

### Hawaii Electric Light Company, Inc. ii Trinity Consultants BART Analysis 

### 6. PM 10 

### BART E VALUATION 

### .................................................................................. 6-1
6.1 I DENTIFICATION OF 

### A VAILABLE 

### R ETROFIT 

### PM 10 

### C ONTROL 

### T ECHNOLOGIES 

### ........ 6-1
6.2 E LIMINATE 

### T ECHNICALLY 

### I NFEASIBLE 

### PM C ONTROL 

### T ECHNOLOGIES 

### ................. 6-2

6.2.1 D RY 

### E LECTROSTATIC 

### P RECIPITATORS 

### (ESP) ..................................................... 6-2

6.2.2 M ECHANICAL 

### C OLLECTORS 

### (C YCLONES 

### ) .......................................................... 6-2

6.2.3 W ET 

### E LECTROSTATIC 

### P RECIPITATORS 

### (ESP) ..................................................... 6-2

6.2.4 F ABRIC 

### F ILTER 

### .................................................................................................... 6-2

6.2.5 W ET 

### S CRUBBER 

### .................................................................................................. 6-3

6.2.6 F UEL 

### S WITCHING 

### ................................................................................................ 6-3 

### 6.3 R ANK OF 

### T ECHNICALLY FEASIBLE 

### PM 10 

### C ONTROL 

### O PTIONS BY 

### E FFECTIVENESS 

### . 6-4
6.4 E VALUATION OF 

### I MPACTS FOR 

### F EASIBLE 

### PM 10 

### C ONTROLS 

### ................................... 6-4

6.4.1 C OST OF 

### C OMPLIANCE 

### ........................................................................................ 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 E VALUATION OF 

### V ISIBILITY 

### I MPACT OF 

### F EASIBLE 

### PM 10 

### C ONTROLS 

### .................... 6-7
6.6 P ROPOSED 

### B ART FOR 

### PM 10 

### ................................................................................... 6-9

A PPENDIX 

### A

- NO X 

### C ONTROL 

### C OST 

### C ALCULATIONS



### A PPENDIX 

### B

- PM 10 

### C ONTROL 

### C OST 

### C ALCULATIONS



### Compact Disc - August 2010 Stack Test Report

### Hawaii Electric Light Company, Inc. iii Trinity Consultants BART Analysis 

## L IST OF 

## T ABLES

T ABLE 

### 1-1. E XISTING 

### V ISIBILITY 

### I MPAIRMENT 

### A TTRIBUTABLE TO 

### H ILL 

### 5 & H ILL 

### 6 ........................ 1-1

T ABLE 

### 3-1. B ASELINE 

### S HORT 

### -T ERM 

### NO X AND 

### PM 10 

### E MISSION RATES 

### ( LB 

### / HR 

### ) B ASED ON 

### S TACK


### T EST



### .............................................................................................................................. .......... 3-2

T ABLE 

### 3-2. B ASELINE 

### NO X AND 

### PM 10 

### E MISSION RATES 

### ( LB 

### /MMB TU 

### ) B ASED ON 

### S TACK 

### T EST 

### ....... 3-2

T ABLE 

### 3-3. B ASELINE 

### NO X AND 

### PM 10 

### E MISSION RATES 

### ( TPY 

### ) B ASED ON 

### S TACK 

### T EST 

### .................... 3-2

T ABLE 

### 3-4. S HORT 

### T ERM 

### B ASELINE 

### SO 2 

### E MISSION 

### R ATE 

### ( LB 

### / HR 

### ) B ASED ON 

### M ASS 

### B ALANCE 

### ....... 3-3

T ABLE 

### 3-5. A NNUAL 

### B ASELINE 

### SO 2 

### E MISSION 

### R ATE 

### ( TPY 

### ) B ASED ON 

### M ASS 

### B ALANCE 

### .................. 3-4

T ABLE 

### 3-6. M ODELED 

### B ASELINE 

### E MISSION 

### R ATES 

### ........................................................................... 3-5

T ABLE 

### 3-7. B ASELINE 

### V ISIBILITY 

### I MPACTS 

### A TTRIBUTABLE TO 

### H ILL 

### 5 AND 

### H ILL 

### 6 ......................... 3-5

T ABLE 

### 4-1. S UMMARY OF 

### B ASELINE 

### SO 2 

### E MISSION 

### R ATES 

### .............................................................. 4-1

TABLE 

### 4-2. A VAILABLE 

### SO 2 

### C ONTROL 

### T ECHNOLOGIES FOR 

### H ILL 

### 5 & H ILL 

### 6 .................................. 4-1

T ABLE 

### 4-3. S UMMARY OF 

### F UTURE 

### A NNUAL 

### SO 2 

### E MISSIONS 

### A SSOCIATED WITH 

### D ISTILLATE 

### O IL AT


### 0.15% S ULFUR 

### ........................................................................................................................ 4-4

T ABLE 

### 4-4. S UMMARY OF 

### F UTURE 

### A NNUAL 

### SO 2 

### E MISSIONS 

### A SSOCIATED WITH 

### D ISTILLATE 

### O IL AT


### 0.4% S ULFUR 

### .......................................................................................................................... 4-4

T ABLE 

### 4-5. S UMMARY OF 

### C OST 

### E FFECTIVENESS FOR 

### S WITCHING 

### F ROM 

### R ESIDUAL 

### F UEL 

### O IL TO


### D ISTILLATE 

### F UEL 

### O IL 

### ............................................................................................................. 4-5

T ABLE 

### 4-6. S UMMARY OF 

### M AXIMUM 

### SO 2 

### E MISSIONS 

### A SSOCIATED WITH 

### D ISTILLATE 

### O IL 

### ............. 4-7

T ABLE 

### 4-7. S UMMARY OF 

### E MISSION 

### R ATES 

### M ODELED TO 

### R EFLECT 

### S WITCH TO 

### D ISTILLATE 

### O IL FOR


### SO 2 

### C ONTROL 

### ......................................................................................................................... 4-7

T ABLE 

### 4-8. S UMMARY OF 

### V ISIBILITY 

### I MPROVEMENT 

### A SSOCIATED WITH 

### S WITCH TO 

### D ISTILLATE 

### O IL 

### 4-8

T ABLE 

### 5-1. S UMMARY OF 

### B ASELINE 

### E MISSION 

### R ATES 

### ...................................................................... 5-1

T ABLE 

### 5-2. A VAILABLE 

### NO X 

### C ONTROL 

### T ECHNOLOGIES FOR 

### H ILL 

### 5 & H ILL 

### 6 ................................. 5-1

T ABLE 

### 5-3. C ONTROL 

### E FFECTIVENESS OF 

### T ECHNICALLY 

### F EASIBLE 

### NO X 

### C ONTROL 

### T ECHNOLOGIES 

### 5-4

TABLE 

### 5-4. S UMMARY OF 

### C OST 

### E FFECTIVENESS FOR 

### H ILL 

### 5 & H ILL 

### 6 NO X 

### C ONTROLS 

### ................... 5-7

T ABLE 

### 5-5. S UMMARY OF 

### E MISSION 

### R ATES 

### M ODELED TO 

### R EFLECT 

### LNB FOR 

### NO X 

### C ONTROL 

### ......... 5-9

### Hawaii Electric Light Company, Inc. iv Trinity Consultants BART Analysis T ABLE 

### 5-6. S UMMARY OF 

### E MISSION 

### R ATES 

### M ODELED TO 

### R EFLECT 

### SCR FOR 

### NO X 

### C ONTROL 

### ......... 5-9

T ABLE 

### 5-7. S UMMARY OF 

### V ISIBILITY 

### I MPROVEMENT 

### A SSOCIATED WITH 

### LNB S YSTEMS ON 

### H ILL 

### 5

AND 

### H ILL 

### 6 ............................................................................................................................. 5-9

T ABLE 

### 5-8. S UMMARY OF 

### V ISIBILITY 

### I MPROVEMENT 

### A SSOCIATED WITH 

### SCR S YSTEMS ON 

### H ILL 

### 5

AND 

### H ILL 

### 6 ........................................................................................................................... 5 -10

T ABLE 

### 6-1. S UMMARY OF 

### B ASELINE 

### PM 10 

### E MISSION 

### R ATES 

### ............................................................. 6-1

TABLE 

### 6-2. A VAILABLE 

### PM C ONTROL 

### T ECHNOLOGIES FOR 

### H ILL 

### 5 & H ILL 

### 6 ................................... 6-1

T ABLE 

### 6-3. C ONTROL 

### E FFECTIVENESS OF 

### T ECHNICALLY 

### F EASIBLE 

### PM C ONTROL 

### T ECHNOLOGIES 

### 6-4

T ABLE 

### 6-4. S UMMARY OF 

### C OST 

### E FFECTIVENESS FOR 

### H ILL 

### 5 & H ILL 

### 6 PM 10 

### C ONTROLS 

### .................. 6-6

T ABLE 

### 6-5. S UMMARY OF 

### E MISSION 

### R ATES 

### M ODELED TO 

### R EFLECT 

### W ET 

### ESP FOR 

### PM 10 

### C ONTROL 

### 6-7

T ABLE 

### 6-6. S UMMARY OF 

### E MISSION 

### R ATES 

### M ODELED TO 

### R EFLECT 

### W ET 

### S CRUBBER FOR 

### PM 10 

### C ONTROL



### .............................................................................................................................. .. 6-7

T ABLE 

### 6-7. S UMMARY OF 

### V ISIBILITY 

### I MPROVEMENT 

### A SSOCIATED WITH 

### W ET 

### ESP S ON 

### H ILL 

### 5 AND


### H ILL 

### 6 ............................................................................................................................. ........ 6-8

T ABLE 

### 6-8. S UMMARY OF 

### V ISIBILITY 

### I MPROVEMENT 

### A SSOCIATED WITH 

### W ET 

### S CRUBBERS ON 

### H ILL 

### 5

AND 

### H ILL 

### 6 ............................................................................................................................. 6-9

### Hawaii Electric Light Company, Inc. 1-1 Trinity Consultants BART Analysis 

## 1. E XECUTIVE 

## S UMMARY

This report documents the determination of th e 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 (NO

x 

### ), sulfur dioxide (SO 2 

### ), and particulate matter (PM) from Hill 5 and Hill 6 cause or cont ribute 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 emissi ons. 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 em issions were not accounted for in default natural visibility at Haleakala and Volcanoes Nationa l Parks. EPA responde d (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 a ttributable to the Hill 5 and Hill 6 based on the default natural conditions is provide d 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.

T ABLE 

### 1-1. E XISTING 

### V ISIBILITY 

### I MPAIRMENT 

### A TTRIBUTABLE TO 

### H ILL 

### 5 & H ILL 

### 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 51 1 

### to determine BART for Hill 5 and Hill 6. Specifically, Trinity conducted a five -step analysis to determine BART for SO 2 

### , NO X 

### , and PM 10 

### 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 fo llowing were determined to be BART:

• SO 2 

### – The BART analysis concluded that no c ontrols constitute BART. Add-on controls are not technically feasible, and switching fuels is not cost effective.

• NO X 

### – The BART analysis concluded that the installation of low-NOx burner (LNB) systems capable of achieving a NO

x 

### level of 0.30 lb/MMBtu for Hill 5 (a wall-fired boiler)
and a NO

x 

### level of 0.18 lb/MMBtu for Hill 6 (a tangentially-fired boiler) constitutes BART when using the default natural conditions.

• PM 10 

### – 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 Δ dv.

While the BART review concludes that low-NOx bur ner (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 NO

x 

### level of 0.30 lb/MMBtu for Hill 5 (a wall-fired boiler) and a NO

x 

### 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 pro cess 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.

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

## 2. I NTRODUCTION AND 

## B ACKGROUND

In the 1977 amendments to the Clean Air Act (CAA), Congress set a national goal to restore national parks and wilderness areas to pristin e 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 inte rnational 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 thei r state. On July 6, 2005, the EPA published amendments to its 1999 RHR, often called the B est 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 th e 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 c ontribute to visibility impairment if the 98 th 

### 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 vi sibility regulations define BART as follows:

“...an emission limitation based on the deg ree of reduction achievable through the application of the best system of continu ous emission reduction for each pollutant which is emitted by...[a BART-eligible sou rce]. The emission limitation must be established on a case-by-case basis, taking in to consideration the technology available, the cost of compliance, the energy and n on 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

### Hawaii Electric Light Company, Inc. 2-2 Trinity Consultants BART Analysis Further, the BART rule indicates that the five b asic 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 visi bility 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 impa irment 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 NO

x 

### , SO 2 

### , and particulate matter with a mass mean diameter smaller than ten microns (PM 10 

### ) of various forms (filterable coarse particulate matter [PM
c 

### ], filterable fine particle matter [PM f 

### ], elemental carbon [EC], inorganic condensable particulate matter [IOR CPM] as sulfates [SO 4 

### ], and organic condensable particulate matter [OR CPM] also referred to as secondary organic aeros ols [SOA]). The BART determinations for SO 2 

### , NO X 

### , and PM 10 

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

The BART guidelines 2 

### 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 NO X 

### is generally highly cost-effective and should be considered in your determination of BART for these sources.”

EPA also established presumptive SO 2 

### 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 PM 10 

### emissions. Note that the BART analysis was conducted for PM 10 

### 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.

### Hawaii Electric Light Company, Inc. 3-1 Trinity Consultants BART Analysis 

## 3. E XISTING 

## E MISSIONS AND 

## V ISIBILITY 

## I MPAIRMENT

As stated in Section 2 of this report, EPA Region 9 determined that emissions of NO

x 

### , SO 2 

### , and PM 10 

### 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 natu ral conditions does not account for the impact of
the active Kilauea Volcano. Th e Kilauea Volcano has a significant impact on regional haze in

Hawaii. The current continuous Kilauea Vo lcano eruption began 26 years ago in 1983 3 

### . Over the past 200 years, there have been very few periods when Kilauea and Mauna Loa were both inactive 4



### . Thus, natural conditions based on the EPA document are grossly under represented. More representative natural conditions that take the vol canic 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 Tr inity. 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 NO X 

## , SO 2 

## , AND 

## PM 10 

## B ASELINE 

## E MISSION 

## R ATES

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 evalua ted 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 an alyses 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.

NO

x 

### and PM 10



### Table 3-1 summarizes the worst-case emission rat es 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 NO

x 

### and PM 10 

### in August of 2010, and the data from the test provides the basis of the baseline NO

x 

### and PM 10 

### rates used in the recent modeling.

3 http://hvo.wr.usgs.gov/kilauea/
4 http://pubs.usgs.gov/gip/hawaii/page14.html

### Hawaii Electric Light Company, Inc. 3-2 Trinity Consultants BART Analysis T ABLE 

### 3-1. B ASELINE 

### S HORT 

### -T ERM 

### NO X AND 

### PM 10 

### E MISSION RATES 

### ( LB 

### / HR 

### ) B ASED ON 

### S TACK 

### T EST

Pollutant Hill 5 (lb/hr) Hill 6 (lb/hr) Total (lb/hr)

NO

x 112.6 122.0 234.6

PM 10,total 1 11.04 11.17 22.21

1 EPA CTM-27/202



### The NO

x 

### and PM 10 

### 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 MMBt u/hr). The lb/MMBtu levels in Table 3-2 were calculated by dividing the average lb/hr rat es determined during the test by the average heat input to the boilers during the test. Table 3-2 summarizes the NO

x 

### and PM 10 

### lb/MMBtu based on the test data. A copy of the stack test report is al so included on the compact disc submitted with this application. Note that a more detailed breakdown of the PM species comprising the PM 10 

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

T ABLE 

### 3-2. B ASELINE 

### NO X AND 

### PM 10 

### E MISSION RATES 

### ( LB 

### /MMB TU 

### ) B ASED ON 

### S TACK 

### T EST

Parameter Hill 5 Hill 6 Test HI (MMBtu/hr) 166 249

Test NO

x (lb/hr) 94.7 122

Test PM 10 (lb.hr) 9.31 11.17

NO

x (lb/MMBtu) 0.572 0.490

PM 10

, total 1 (lb/MMBtu) 0.056 0.045

1 EPA CTM-27/202



### Table 3-3 provides a summary of the annual baseline emissions for NO

x 

### and PM 10 

### . The annual baseline emission rates were calculated by multiplyin g the lb/MMBtu levels shown in Table 3-2 by the baseline (2009) heat input (Hill 5 = 1,354,78 6 MMBtu/yr and Hill 6 = 1,419,920 MMBtu/yr).

T ABLE 

### 3-3. B ASELINE 

### NO X AND 

### PM 10 

### E MISSION RATES 

### ( TPY 

### ) B ASED ON 

### S TACK 

### T EST

Pollutant Hill 5 (tpy) Hill 6 (tpy) Total (tpy)

NO

x 387.26 347.85 735.11

PM 10,total 1 38.07 31.85 69.92

1 EPA CTM-27/202

### Hawaii Electric Light Company, Inc. 3-3 Trinity Consultants BART Analysis SO 2



### SO 2 

### 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 SO 2 

### emissions. Trinity conducted a mass balance to determine both short te rm and annual baseline emissions. As part of the mass balance, Trinit y considered the inorganic condensable particulate matter emissions that were evaluated as part of th e 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 resulte d in emissions of sulfate, the amount of sulfur in
the fuel needed to form the sulfate emissions w as determined so that this sulfur would not be considered when estimating the amount of sulfur that formed SO 2



### .

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

SO 2 

### emission rate. In short, the sulfur in the ma ximum amount of fuel that could be combusted was first determined. The maximum amount of fuel was used to represent a wors t-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 (t he 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 molecu lar weight of sulfur to sulfate [32/96]). The remaining sulfur was converted to SO 2 

### by multiplying by the molecular weight of SO 2 

### to sulfur [64/32].

T ABLE 

### 3-4. S HORT 

### T ERM 

### B ASELINE 

### SO 2 

### E MISSION 

### R ATE 

### ( LB 

### / HR 

### ) B ASED ON 

### M ASS 

### B ALANCE

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 SO 2 

### 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.

### Hawaii Electric Light Company, Inc. 3-4 Trinity Consultants BART Analysis T ABLE 

### 3-5. A NNUAL 

### B ASELINE 

### SO 2 

### E MISSION 

### R ATE 

### ( TPY 

### ) B ASED ON 

### M ASS 

### B ALANCE

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 E XISTING 

## NO X 

## , SO 2 

## , AND 

## PM 10 

## E MISSIONS AND 

## A SSOCIATED 

## V ISIBILITY 

## I MPAIRMENT

Trinity conducted modeling to determine the visibilit y 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 pr eferred 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 (NO

x 

### and PM 10 

### ) and 3-4 (SO 2 

### ), except that
the PM 10 

### rates in Table 3-6 break down the PM 10 

### species. The emission rates for the PM 10 

### species

reflect the breakdown of the PM 10 

### determined from the 2010 stack t est data. More specifically, the stack test showed the following distribution for the PM species:

• Filterable PM 10-2.5 

### (PM C 

### ) = 41.05%

• Filterable PM 2.5 

### = 31.04%

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

• Inorganic condensable PM (modeled as SO 4 

### ) = 26.82%

The PM 2.5 

### was further speciated into fine PM (PM F 

### ) and elemental carbon (EC) using the following speciation suggested by the National Park Servi ce in their “speciation spreadsheet” for uncontrolled heavy-oil fired utility boilers:

• PM F 

### = 92.6% Filterable PM 2.5



### • EC = 7.4% Filterable PM 2.

### Hawaii Electric Light Company, Inc. 3-5 Trinity Consultants BART Analysis T ABLE 

### 3-6. M ODELED 

### B ASELINE 

### E MISSION 

### R ATES

Unit SO 2 (lb/hr) SO 4 (lb/hr) NO X (lb/hr) PM C (lb/hr) PM F (lb/hr) SOA (lb/hr) EC (lb/hr) PM 10, 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.

T ABLE 

### 3-7. B ASELINE 

### V ISIBILITY 

### I MPACTS 

### A TTRIBUTABLE TO 

### H ILL 

### 5 AND 

### H ILL 

### 6

Year Maximum ( Δ dv) 98th Percentile ( Δ dv) 98th Percentile
% SO 4 98th Percentile
% NO 3 98th Percentile
% PM 10 98th Percentile
% NO 2 

### 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 98 th 

### 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.

### Hawaii Electric Light Company, Inc. 4-1 Trinity Consultants BART Analysis 

## 4. SO 2 

## BART E VALUATION

The baseline SO 2 

### 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 SO 2 

### controls.

T ABLE 

### 4-1. S UMMARY OF 

### B ASELINE 

### SO 2 

### E MISSION 

### R ATES

SO 2 Short Term
Emission Rate SO 2 Annual
Emission Rate
Unit (lb/hr) (tpy)

Hill 5 423.9 1357.13

Hill 6 534.3 1420.37



## 4.1 I DENTIFICATION OF 

## A VAILABLE 

## R ETROFIT 

## SO 2 

## C ONTROL 

## T ECHNOLOGIES

Sulfur oxides, SO

x 

### , are generated during fuel oil combustion from the oxidation of sulfur contained in
the fuel. SO

x 

### emissions are almost entirely dependent on th e sulfur content of the fuel and are not affected by boiler size or burner design. SO

x 

### emission from conventional combustion systems are predominantly in the form of SO 2 

### . Since SO 2 

### is the predominant sulfur compound emitted from the Hill boilers, the BART analysis is specific to emissions of SO 2



### .

Step 1 of the top-down control review is to identify available retrofit control options for SO 2 

### . The
available SO 2 

### retrofit control technologies for the Hill bo ilers are summarized in Table 4-2. The
retrofit controls include both add- on controls that eliminate SO 2 

### after it is formed and switching to
lower sulfur fuels which reduces the formation of SO 2



### .

TABLE 

### 4-2. A VAILABLE 

### SO 2 

### C ONTROL 

### T ECHNOLOGIES FOR 

### H ILL 

### 5 & H ILL 

### 6

SO 2 Control Technologies

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

Wet Scrubber Circulating Dry Scrubber (CDS) Fuel Switching



## 4.2 E LIMINATE 

## T ECHNICALLY 

## I NFEASIBLE 

## SO 2 

## C ONTROL 

## T ECHNOLOGIES

Step 2 of the BART determination is to eliminate technically infeasible SO 2 

### control technologies that were identified in Step 1.

### Hawaii Electric Light Company, Inc. 4-2 Trinity Consultants BART Analysis 

### 4.2.1 D RY 

### S ORBENT 

### I NJECTION 

### , S PRAY 

### D RYER 

### A BSORPTION 

### (SDA), W ET 

### S CRUBBER 

### , C IRCULATING 

### D RY 

### S CRUBBER 

### (CDS)

These technologies are collectively known as flue gas desulfurization (FGD) systems. FGD applications have not been used historically for SO 2 

### 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 SO 2 

### emission rate for oil-fired units and determined that the presumptive emission rate should be based on the su lfur content of the fuel oil, rather than

on FGD 5 

### 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 SO 2 

### from Hill 5 and Hill 6 and are

not considered further for BART.



### 4.2.2 F UEL 

### S WITCHING



### 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 SO 2 

### 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, th e 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 ther e is no natural gas supply in the state of Hawaii. Importing liquid natural gas (LNG) w ould require siting and constructing an LNG import facility which, in itself, might be t echnically 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 R ANK OF 

## T ECHNICALLY 

## F EASIBLE 

## SO 2 

## C ONTROL 

## O PTIONS BY 

## E FFECTIVENESS

The third step in the BART analysis is to rank the technically feasible options according to effectiveness. Fuel switching is the only remain ing technically feasible control option. Since SO 2 

### emissions from fuel combustion are generally proportional to the sulfur content of the fuel, combusting distillate oil (0. 4 percent sulfur) shoul d result in approximately a 80.0 percent reduction
in SO 2 

### 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 Pr oposed Guidelines for Best Available Retrofit Technology (BART) Determinations Under the Regional Haze Regulations EPA Docket Number OAR-2002-0076.

### Hawaii Electric Light Company, Inc. 4-3 Trinity Consultants BART Analysis 

## 4.4 E VALUATION OF 

## I MPACTS FOR 

## F EASIBLE 

## SO 2 

## C ONTROLS

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 C OST OF 

### C OMPLIANCE



### The cost effectiveness of switching to di stillate 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, fo r this analysis capital expenses were not
included.

As HELCO currently obtains distillate fuel o il from local suppliers for its other generating units including combustion turbines, the estimat ed per gallon fuel costs were available and were used for the costing analysis. Note th at the cost estimates prepared for the use of distillate oil assume that the existing residua l 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 SO 2 

### 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 SO 4 

### in both Tables 4-3 and 4-4 is based on the percentage of the baseline annual sulf ur that was determined to be SO 4 

### , as described in

Section 3.

### Hawaii Electric Light Company, Inc. 4-4 Trinity Consultants BART Analysis T ABLE 

### 4-3. S UMMARY OF 

### F UTURE 

### A NNUAL 

### SO 2 

### E MISSIONS 

### A SSOCIATED WITH 

### D ISTILLATE 

### O IL

AT 

### 0.15% S ULFUR

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



### T ABLE 

### 4-4. S UMMARY OF 

### F UTURE 

### A NNUAL 

### SO 2 

### E MISSIONS 

### A SSOCIATED WITH 

### D ISTILLATE 

### O IL

AT 

### 0.4% S ULFUR

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 eff ectiveness of switching from residual fuel to
distillate oil. The cost effectiveness was dete rmined by dividing the annual cost increase of fuel switching by the annual tons of SO 2 

### reduced. In the BART guidelines, EPA calculated that the majority of BART-eligible units coul d meet the presumptive limits at a cost of $400 to $2,000 per ton of SO 2 

### removed. Table 4-3 indicates that the cost of switching is to distillate oil is over $5,000/ton, which is well above EPA’s calculation.TABLE4-5.SUMMARY OFCOSTEFFECTIVENESS FORSWITCHINGFROMRESIDUALFUELOIL TODISTILLATEFUELOILActualtoActualApproach(2009AverageSulfurforBaseline,2009AverageSulfurforNo.2Oil)Hill5SulfurContentABaselineEmissionRateControlledEmissionRateSO2ReducedAnnual HeatInputFuel HeatingValue (HHV)BAnnual Fuel UsageFuelCostCFuel CostCost of FuelSwitchingSO2 CostEffectiveness(%) (tpy) (tpy) (tpy) (MMBtu/yr) (MMBtu/Mgal) (Mgal/yr) ($/gal) $/yr $/yr $/tonResidual Oil1.86 1,357.13 -- 1,354,786 148.779106.401.43 13,022,149 --Distillate Oil0.15 - 100.89 1,256.24 1,354,786 139.159736.302.00 19,472,592 6,450,443 5,135Hill6SulfurContentABaselineEmissionRateControlledEmissionRateSO2ReducedAnnual HeatInputFuel HeatingValue (HHV)BAnnual Fuel UsageFuelCostCFuel CostCost of FuelSwitchingSO2 CostEffectiveness(%) (tpy) (tpy) (tpy) (MMBtu/hr)(Mgal/yr) ($/gal) $/hr $/yr $/tonResidual Oil1.86 1,420.37 -- 1,419,920 148.779544.211.43 13,648,215 --Distillate Oil0.15 - 105.59 1,314.78 1,419,920 139.1510204.392.00 20,408,776 6,760,561 5,142ASulfur 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.BHigher 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 Engineer Inc.CResidual 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, approximately $2/gal.ActualtoContractApproach(2009AverageSulfurforBaseline,ContractSulfurforNo.2Oil)Hill5SulfurContentABaselineEmissionRateControlledEmissionRateSO2ReducedAnnual HeatInputFuel HeatingValue (HHV)BAnnual Fuel UsageFuelCostCFuel CostCost of FuelSwitchingSO2 CostEffectiveness(%) (tpy) (tpy) (tpy) (MMBtu/yr) (MMBtu/Mgal) (Mgal/yr) ($/gal) $/yr $/yr $/tonResidual Oil1.86 1,357.13 --38 148.779106.401.43 13,022,149 --Distillate Oil0.40 - 272.31 1,084.82 38 139.159736.302.00 19,472,592 6,450,443 5,946Hill6SulfurContentABaselineEmissionRateControlledEmissionRateSO2ReducedAnnual HeatInputFuel HeatingValue (HHV)BAnnual Fuel UsageFuelCostCFuel CostCost of FuelSwitchingSO2 CostEffectiveness(%) (tpy) (tpy) (tpy) (MMBtu/hr)(Mgal/yr) ($/gal) $/hr $/yr $/tonResidual Oil1.86 1,420.37 --32 148.779544.211.43 13,648,215 --Distillate Oil0.40 - 285.00 1,135.37 32 139.1510204.392.00 20,408,776 6,760,561 5,955ABHigher 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 Engineer Inc.CResidual 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, approximately $2/gal.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%).1.Hawaiian Electric Light Company, Inc . 4-5 Trinity ConsultantsBART Analysis

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

### 4.4.1.1

4.4.1.2 E NERGY 

### I MPACTS AND 

### N ON 

### -A IR 

### Q UALITY 

### I MPACTS



### The cost increase associated with fu el switching to distillate oil will significantly increase energy costs fo r 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 (appr oximately 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 ar e not provided by the renewable energy resources, provide system stability nece ssary 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.



### R EMAINI NG 

### U SEFUL 

### L IFE



### The remaining useful lives of Hill 5 and Hill 6 do not impact the annualized cost for this analysis, since it is assume d that fuel switching will not require any significant capital costs, and thus for th e purpose of this analysis there is nothing to capitalize that would require a review of the life of the equipment.



## 4.5 E VALUATION OF 

## V ISIBILITY 

## I MPACT OF 

## F EASIBLE 

## SO 2 

## C ONTROLS

An impact analysis was conducted to assess th e 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 visibilit y improvement associated with the switch to distillate oil, the maximum short-term SO 2 

### emission rates associated with the combustion of
distillate oil in Hill 5 and Hill 6 were modeled using CALPUFF.

The maximum short-term SO 2 

### 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 SO 2 

### emission rate associated with the combustion of distillate oil. Note that the percentage of sulfur that is
indicated to be emitted as SO 4 

### in Table 4-6 is based on the percentage of the baseline short term
sulfur that was determined to be SO 4 

### , as described in Section 3.

### Hawaii Electric Light Company, Inc. 4-7 Trinity Consultants BART Analysis T ABLE 

### 4-6. S UMMARY OF 

### M AXIMUM 

### SO 2 

### E MISSIONS 

### A SSOCIATED WITH 

### D ISTILLATE 

### O IL

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 mode led to reflect a switch to distillate oil. The explanation for the SO 2 

### emission rates associated with the distillate oil is provided above. The explanation of the PM 10 

### rates associated with distillate oil is included in Section 6 of this report (the BART analysis for PM 10 

### ). The emission rates for NO

x 

### shown in Table 4-7 are the same as in the baseline modeling, since, for purposes of the SO 2 

### BART analysis, it is assumed that NO

x 

### emissions will not be impacted by the switch to distillate oil. In reality, it is likely that NO

x 

### emissions will be lower on distillate oil than residual oil, but the level of NO

x 

### reduction is difficult to project.

T ABLE 

### 4-7. S UMMARY OF 

### E MISSION 

### R ATES 

### M ODELED TO 

### R EFLECT 

### S WITCH TO 

### D ISTILLATE 

### O IL

FOR 

### SO 2 

### C ONTROL

Unit SO 2 (lb/hr) SO 4 (lb/hr) NO X (lb/hr) PM C (lb/hr) PM F (lb/hr) SOA (lb/hr) EC (lb/hr) PM 10, 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, 98 th 

### percentile modeled visibility impact, a nd the number of days with a modeled visibility impact greater than 0.5 Δ dv. The visibility improvement shown in the table was calculated as the difference between the existing visibility impa irment and the visibility impairment associated with the combustion of distillate oil as measured by the 98 th 

### percentile.

### Hawaii Electric Light Company, Inc. 4-8 Trinity Consultants BART Analysis T ABLE 

### 4-8. S UMMARY OF 

### V ISIBILITY 

### I MPROVEMENT 

### A SSOCIATED WITH 

### S WITCH TO 

### D ISTILLATE 

### O IL

Volcanoes National Park Haleakala National ParkMaximum Impact(Δdv)98% Impact (Δdv)# Days > 0.5ΔdvVisibility Improvement(Δdv)*,†Visibility Improvement*,†Maximum Impact (Δdv)98% Impact (Δdv)# Days > 0.5ΔdvVisibility 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 98 th percentile impact ( Δ dv) compared to the baseline impact ( Δ dv) †The visibility improvement shown in the table has been calculated from 98 th 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 98 th percentile impacts shown in the table, the visibility improvement

calculated from the baseline and controlled 98 th percentile impacts shown in the table may be slightly different than the visibility impr ovement reflected in the table.



### As shown in Table 4-8, the combustion of distilla te oil results in an estimated 0.83 to 0.96 Δ dv improvement (60 to 62 percent) of the 98 th 

### percentile visibility impairment attributable to Hill 5 and
Hill 6 in VNP and an estimated 0.24 to 0.37 Δ dv improvement (76 to 78 percent) of the 98 th 

### 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 vol canic 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 P ROPOSED 

## B ART FOR 

## SO 2



### Switching to distillate oil reduces SO 2 

### 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 SO 2 

### reduced for each of the Hill boilers. While this cost represents the maximum SO 2 

### reductions that are technically

### Hawaii Electric Light Company, Inc. 4-9 Trinity Consultants BART Analysis feasible, it is an extremely costly approach to reducing SO 2 

### 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 contributi on to visibility impairment in VNP and HNP by up
to 0.96 Δ dv and 0.37 Δ dv, respectively.

Regardless of whether HELCO were to switch to dis tillate oil or some other fuel, it may not feasible to implement a change in the 5-year time frame re quired 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 fu els 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 Δ dv do not warrant a determina tion of this fuel change as BART. Thus, there are no fuel changes or add-on controls proposed as BART for SO 2 

### for the Hill
boilers.

While there are no fuel changes or add-on contro ls 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 alterna tives 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.

### Hawaii Electric Light Company, Inc. 5-1 Trinity Consultants BART Analysis 

## 5. NO X 

## BART E VALUATION

The baseline NO

x 

### emission rates that were used in the BART analysis are summarized in Table 5-1. The basis of the emission rates is provided in Secti on 3 of this report. The boilers currently do not
have NO

x 

### controls.

T ABLE 

### 5-1. S UMMARY OF 

### B ASELINE 

### E MISSION 

### R ATES

NO X Emission
Rate NO X Emission
Rate NO X 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 I DENTIFICATION OF 

## A VAILABLE 

## R ETROFIT 

## NO X 

## C ONTROL 

## T ECHNOLOGIES

Nitrogen oxides, NO

x 

### , are produced during fuel combustion when nitrogen contained in the fuel and combustion air is exposed to high temperatures. Th e origin of the nitrogen (i.e. fuel vs. combustion air) has lead to the use of the terms “thermal” NO

x 

### and “fuel” NO

x 

### when describing NO

x 

### emissions
from the combustion of fuel. Thermal NO

x 

### emissions are produced when elemental nitrogen in the combustion air is admitted to a high temperature zone and oxidized. Fuel NO

x 

### emissions are created during the rapid oxidation of nitrogen compounds contained in the fuel. NO X 

### emissions from residual oil can be up to 50% fuel NO

x 

### . 6



### Nitrogen oxide (NO) is typically the predominant form of NO

x 

### emissions from fossil fuel combustion, along with nitrogen dioxide (NO

2 

### ). The formation of NO

x 

### 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 NO

x 

### control technologies. The available retrofit NO

x 

### control technologies are summarized in Table 5-2 for Hill 5
and Hill 6.

T ABLE 

### 5-2. A VAILABLE 

### NO X 

### C ONTROL 

### T ECHNOLOGIES FOR 

### H ILL 

### 5 & H ILL 

### 6

NO X Control Technologies

Combustion Controls Flue Gas Recirculation (FGR)
Overfire Air (OFA)

Low NO X Burners (LNB)

Post-Combustion Controls Selective Catalytic Reduction (SCR)
Selective Non-Catalytic Reduction (SNCR)



### NO X 

### 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

### Hawaii Electric Light Company, Inc. 5-2 Trinity Consultants BART Analysis NO X 

### Burners (LNB), reduce the peak flame te mperature and excess air in the furnace which
minimizes NO X 

### formation. Post-combustion controls, su ch as selective catalytic reduction (SCR) and selective non-catalytic reduction (SNCR) convert NO

x 

### in the flue gas to molecular nitrogen and

water.



## 5.2 E LIMINATE 

## T ECHNICALLY 

## I NFEASIBLE 

## NO X 

## C ONTROL 

## T ECHNOLOGIES

Step 2 of the BART determination is to eliminate technically infeasible NO X 

### control technologies that were identified in Step 1.



### 5.2.1 C OMBUSTION 

### C ONTROLS



### 5.2.1.1

5.2.1.2

5.2.1.3 F LUE 

### G A S 

### R ECIRCULATION 

### (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 NO

x 

### formation. When operated without additional controls, the NO

x 

### control range for wall fired boilers (Hill 5) with FGR is approximately 0.25-0.30 lb/MMBtu, and for tangentially fired boilers (H ill 6) is 0.15-0.20 lb/MMBtu. 7 

### This control is a technically feasible option for the control of NO X 

### from Hill 5 and Hill 6.



### O VERFIR E 

### A IR 

### (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 NO

x 

### by lowering combustion temperature and limiting the availability of oxygen in the
combustion zone where NO

x 

### is most likely to be formed. OFA as a single NO

x 

### control technique results in estimated NO

x 

### 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 NO

x 

### from Hill 5 and Hill 6.



### L OW 

### NO X 

### B URNERS



### LNB technology utilizes advanced burner design to reduce NO

x 

### formation through the restriction of oxygen, lowering of flame temperature, and/or
reduced residence time. NO

x 

### 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, NO

x 

### 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 NO

x 

### formation. The primary zone is then followed by a sec ondary 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 NO

x 

### formation. In the secondary zone, combustion products formed in the primary zone act to lower the local oxygen concentration, resulting in a decrease in NO

x 

### formation.

The estimated NO X 

### control range for LNBs on wa ll 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 NO X 

### control range on
wall fired boilers is 0.25- 0.30 lb/MMBtu and for tange ntially fired boilers (Hill 6) is 0.15-0.20 lb/MMBtu. 11 

### LNB systems are technically feasible for the
control of NO

x 

### from Hill 5 and Hill 6.



### 5.2.2 P OST 

### C OMBUSTION 

### C ONTROLS



### 5.2.2.1

5.2.2.2 S ELECTI VE 

### C ATALYTIC 

### R EDUCTION



### SCR refers to the process in which NO x 

### is reduced by ammonia over a heterogeneous catalyst in the presence of oxygen. The process is termed selective because the ammonia preferentially reacts with NO x 

### rather than oxygen, although the oxygen enhances the reaction and is a necessary component of the process. The overall reactions are:

4NO + 4NH 3 + O 2 Æ 4N 2 + 6H 2 O

2NO 2 + 4NH 3 + O 2 Æ 3N 2 + 6H 2 O



### 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 NO

x 

### concentration, the exhaust temperature, the ammonia injection rate, and the type of catalyst. The estimated NO X 

### control range for SCR is 0.05-0.10 for a wall fi red 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 NO X 

### control range is 0.03 – 0.10 lb/MMBtu and for tangentially fired boilers (H ill 6) is 0.03-0.10 lb/MMBtu. 13 

### This control is a technically feasible option for the control of NO

x 

### from Hill 5 and Hill 6.



### S ELECTI VE 

### N ON 

### -C ATALYTIC 

### R EDUCTION



### In SNCR systems, a reagent is injected in to the flue gas in the furnace within an appropriate temperature window. The NO x 

### 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 U tility Boiler” EPA, 1994.
13 Ibid.

### Hawaii Electric Light Company, Inc. 5-4 Trinity Consultants BART Analysis react to form nitrogen and water. A ty pical SNCR system consists of reagent storage, multi-level reagent-injecti on 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
NO x 

### reductions. The estimated NO x 

### 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 NO x 

### from Hill 5 and Hill 6.



## 5.3 R ANK OF 

## T ECHNICALLY FEASIBLE 

## NO X 

## C ONTROL 

## O PTIONS BY 

## E FFECTIVENESS

The third step in the BART analysis is to rank the technically feasible options according to effectiveness. Table 5-3 provides a ranking of th e control levels for the controls listed in the previous section for Hill 5 and Hill 6.

T ABLE 

### 5-3. C ONTROL 

### E FFECTIVENESS OF 

### T ECHNICALLY 

### F EASIBLE 

### NO X 

### C ONTROL 

### T ECHNOLOGIES

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 NO

x 

### 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 NO

x 

### level of approximately 0.10 lb/MMBtu.

14 Ibid.
15 Ibid.
16 Ibid.

### Hawaii Electric Light Company, Inc. 5-5 Trinity Consultants BART Analysis 

## 5.4 E VALUATION OF 

## I MPACTS FOR 

## F EASIBLE 

## NO X 

## C ONTROLS

Step four for the BART analysis is the impact an alysis. 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 C OST OF 

### C OMPLIANCE



### 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 NO

x 

### control of approximately 0.30 lb/MMBtu and 0.18 lb/MMBtu for Hill 5 and Hill 6, respectively that is achievabl e 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 NO

x 

### 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 NO

x 

### emissions that can be achieved with SNCR is compar able to combustion controls, the only add-on control that would be expected to result in lower achievable NO

x 

### 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 publishe d calculations methods. The capital costs were annualized over a 15-year period and th en 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 operat es 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 dividi ng 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.

### Hawaii Electric Light Company, Inc. 5-6 Trinity Consultants BART Analysis In the BART guidelines, EPA calculated that fo r all types of boilers other than cyclone boilers, combustion control technology is generally more cost-effective than postcombustion controls. EPA estimates that a pproximately 75 percent of the BART units (non-cyclone) could meet the presumptive NO

x 

### limits at a cost of $100 to $1,000 per ton of

NO

x 

### 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 NO X 

### removed.

Table 5-4 indicates that the cost effectiveness of LNB at a NO

x 

### rate of 0.30 lb/MMBtu and 0.18 lb/MMBtu for Hill 5 and Hill 6, respec tively is between $650-1,100 per ton of NO

x 

### 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 NO

x 

### removed. Additionally, the incremental cost of the SCR over the LNB systems is greater than $4,500 and $8,100 per ton of NO

x 

### removed for Hill 5 and Hill 6, respectively.Hawaiian Electric Light Company, Inc. 5-7 Trinity ConsultantsBART AnalysisTABLE5-4.SUMMARY OFCOSTEFFECTIVENESS FORHILL5&HILL6NOXCONTROLSHill 5BaselineControlledControlledAnnualizedAnnualizedTotalEmissionRateEmissionLevelAAnnual HeatInputEmissionRateNOxReducedCapitalCostCapitalCostAnnualizedFixed O&MVariableO&MAnnualizedCostCostEffectivenessIncrementalCost(tpy) (lb/MMBtu) (MMBtu/yr) (tpy) (ton/yr) ($) ($/yr) ($/yr) ($/yr) ($/yr) ($/ton) ($/ton)LNBB387.26 0.3 1,354,786 203.22 184.04 1,526,715 167,625 22,901 4,931 197,517 1,073 -SCRC387.26 0.10 1354786.15 67.74 319.52 5,351,928 646,374 646,374 153,391 829,305 2,595 4,663Hill 6BaselineEmissionRateControlledEmissionLevelAAnnual HeatInputControlledEmissionRateNOxReducedCapitalCostAnnualizedCapitalCostAnnualizedFixed O&MAnnualizedVariableO&MTotalAnnualizedCostCCostEffectivenessIncrementalCost(tpy) (lb/MMBtu) (MMBtu/yr) (tpy) (ton/yr) ($) ($/yr) ($/yr) ($/yr) ($/yr) ($/ton) ($/ton)LNBB347.85 0.18 1419920.16 127.79 220.06 1,115,681 122,496 16,735 6,232 146,969 668 -SCRC347.85 0.10 1419920.16 71.00 276.86 3,883,355 469,009 469,009 120,231 610,674 2,206 8,164A"Alternative Control Techniques (ACT) Document - NOx Emissions from Utility Boiler." 1994. Tables 2-7 & 2-8.CSCR Cost information: Source: Technical Bulletin: Nitrogen Oxides (NOx), Why and How They Are Controlled, US EPA OAQPS EPA 456/F-99-006R, November 1999BLNB Cost information: Source: ERG, 2005. Analysis of Combustion Controls for Reducing NOx Emissions from Coal-fired EGUs inthe WRAP Region September 6, 2005.Additional details on the cost calculations are included in Appendix D.

### Hawaiian Electric Light Company, Inc. 5-8 Trinity Consultants BART Analysis 

### 5.4.2 E NERGY 

### I MPACTS 

### & N ON 

### -A IR 

### I MPACTS



### SCR systems require electricity to operate the an cillary equipment. The need for electricity to help power some of the ancillary equipm ent 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 amm onia 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 NO x 

### , 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 R EMAINING 

### U SEFUL 

### L IFE



### 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 E VALUATION OF 

## V ISIBILITY 

## I MPACT OF 

## F EASIBLE 

## NO X 

## C ONTROLS

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 visibilit y 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
NO

x 

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

The maximum short-term NO

x 

### 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 cont rolled 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 NO

x 

### 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.

### Hawaiian Electric Light Company, Inc. 5-9 Trinity Consultants BART Analysis T ABLE 

### 5-5. S UMMARY OF 

### E MISSION 

### R ATES 

### M ODELED TO 

### R EFLECT 

### LNB FOR 

### NO X 

### C ONTROL

SO 2 (lb/hr) SO 4 (lb/hr) NO X (lb/hr) PM C (lb/hr) PM F (lb/hr) SOA (lb/hr) EC (lb/hr) PM 10, 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



### T ABLE 

### 5-6. S UMMARY OF 

### E MISSION 

### R ATES 

### M ODELED TO 

### R EFLECT 

### SCR FOR 

### NO X 

### C ONTROL

SO 2 (lb/hr) SO 4 (lb/hr) NO X (lb/hr) PM C (lb/hr) PM F (lb/hr) SOA (lb/hr) EC (lb/hr) PM 10, 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, 98 th 

### percentile modeled visibility impact, and the number of days with a modeled visibility impact greater than 0.5 Δ dv. 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 98 th 

### percentile.

T ABLE 

### 5-7. S UMMARY OF 

### V ISIBILITY 

### I MPROVEMENT 

### A SSOCIATED WITH 

### LNB S YSTEMS ON 

### H ILL 

### 5 AND 

### H ILL 

### 6

Volcanoes National Park Haleakala National ParkMaximum Impact (Δdv)98% Impact (Δdv)# Days > 0.5ΔdvVisibility Improvement(Δdv)*,†Visibility Improvement*Maximum Impact (Δdv)98% Impact (Δdv)# Days > 0.5ΔdvVisibility 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 98 th percentile impact ( Δ dv) compared to the baseline impact ( Δ dv)

### Hawaiian Electric Light Company, Inc. 5-10 Trinity Consultants BART Analysis †The visibility improvement shown in the table has been calculated from 98 th 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 98 th percentile impacts shown in the table, the visibility improvement

calculated from the baseline and controlled 98 th percentile impacts shown in the table may be slightly different than the visibility impr ovement 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, 98 th 

### percentile modeled visibility impact, and the number of days with a modeled visibility impact greater than 0.5 Δ dv. The visibility improvement shown in the table was calculated as the difference between the existing vi sibility impairment and the visibility impairment associated with the combustion of distillate oil as measured by the 98 th 

### percentile. More representative natural conditions that take the volcan ic activity into account would result in reduced visibility improvements.

T ABLE 

### 5-8. S UMMARY OF 

### V ISIBILITY 

### I MPROVEMENT 

### A SSOCIATED WITH 

### SCR S YSTEMS ON 

### H ILL 

### 5 AND 

### H ILL 

### 6

Volcanoes National Park Haleakala National ParkMaximum Impact (Δdv)98% Impact (Δdv)# Days > 0.5ΔdvVisibility Improvement(Δdv)*,†Visibility Improvement*Maximum Impact (Δdv)98% Impact (Δdv)# Days > 0.5ΔdvVisibility 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 98 th percentile impact ( Δ dv) compared to the baseline impact ( Δ dv) †The visibility improvement shown in the table has been calculated from 98 th 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 98 th percentile impacts shown in the table, the visibility improvement

calculated from the baseline and controlled 98 th percentile impacts shown in the table may be slightly different than the visibility impr ovement reflected in the table.

### Hawaiian Electric Light Company, Inc. 5-11 Trinity Consultants BART Analysis As shown in Table 5-7, the operation of LNB systems results in an estimated 0.14 to 0.21 Δ dv improvement (10 to 13 percent) of the 98 th 

### percentile visibility impairment attributable to Hill 5 and
Hill 6 in VNP and an estimated 0.01 to 0.02 Δ dv improvement (2 to 5 percent) of the 98 th 

### percentile visibility impairment attributable to Hill 5 and H ill 6 in HNP. Further, as shown in Table 5-8, the operation of SCR systems results in an estimated 0.17 to 0.27 Δ dv improvement (12 to 18 percent) of
the 98 th 

### percentile visibility impairment attributable to Hill 5 & Hill 6 in VNP and an estimated 0.01
to 0.03 Δ dv improvement (2 to 6 percent) of the 98 th 

### 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 impa irment, the improvement in visibility impairment represented by Tables 5-7 and 5-8 does not reflect reality.



## 5.6 P ROPOSED 

## B ART FOR 

## NO X



### 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

NO

x 

### is generally highly cost-effective and should be considered in your determination of BART for these sources”. While the Hill boilers serve gene rators 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 impair ment in VNP and HNP by up to 0.27 Δ dv and 0.03 Δ dv, 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 NO

x 

### to SCR systems that could achieve 0.10 lb/MMBtu

NO

x 

### .

LNB systems can be installed for an estimated $650-1,100 per boiler and result in model predicted reductions in visibility impairment attribut able to the Hill boilers of up to 0.21 Δ dv. Thus, BART is determined to be the operation of an LNB system capable of achieving a NO

x 

### level of 0.30 lb/MMBtu
for Hill 5 and 0.18 lb/MMBtu for Hill 6.

### Hawaii Electric Light Company, Inc. 6-1 Trinity Consultants BART Analysis 

## 6. PM 10 

## BART E VALUATION

The baseline PM 10 

### emission rates that were used in the PM 10 

### 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.

T ABLE 

### 6-1. S UMMARY OF 

### B ASELINE 

### PM 10 

### E MISSION 

### R ATES

PM 10 Emission
Rate PM 10 Emission
Rate PM 10 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 I DENTIFICATION OF 

## A VAILABLE 

## R ETROFIT 

## PM 10 

## C ONTROL 

## T ECHNOLOGIES

PM 10 

### emissions are either “filterable” or “condensable”. Filterable PM 10 

### is generally considered to be particles less than or equal to 10 microns in diam eter 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 ma tter emissions depend predominantly on the grade of fuel fired. Combustion of lighter distillate oils r esults in significantly lower PM formation than does combustion of heavier residual oils. Among residual o ils, firing of No. 4 or No. 5 oil usually produces less PM than does the firing of heav ier 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 PM 10 

### emissions from the Hill boilers are fairly low and the majority of the PM 10 

### is filterable PM 10



### .

Step 1 of the BART determination is the iden tification of all available retrofit PM control technologies. The available retrofit PM control t echnologies are summarized in Table 6-2 for Hill 5
and Hill 6.

TABLE 

### 6-2. A VAILABLE 

### PM C ONTROL 

### T ECHNOLOGIES FOR 

### H ILL 

### 5 & H ILL 

### 6

PM 10 Control Technologies

Dry Electrostatic Precipitator (ESP) Wet Electrostatic Precipitator (ESP)
Fabric Filter
Wet Scrubber Cyclone Fuel Switching

### Hawaii Electric Light Company, Inc. 6-2 Trinity Consultants BART Analysis 

## 6.2 E LIMINATE 

## T ECHNICALLY 

## I NFEASIBLE 

## PM C ONTROL 

## T ECHNOLOGIES

Step 2 of the BART determination is to eliminate technically infeasible PM control technologies that were identified in Step 1.



### 6.2.1 D RY 

### E LECTROSTATIC 

### P RECIPITATORS 

### (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. Beca use 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 M ECHANICAL 

### C OLLECTORS 

### (C YCLONES 

### )

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 particulate 17 

### . 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, cy clonic collectors are not nearly so effective because of the high percentage of small partic les (less than 3 micrometers in diameter) emitted. Since cyclones are generally not effec tive at controlling the PM size fractions that contribute to visibility impairment, cyclon es are considered technically infeasible.



### 6.2.3 W ET 

### E LECTROSTATIC 

### P RECIPITATORS 

### (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 par ticles, 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 PM 10 

### for boilers Hill 5 and Hill 6.



### 6.2.4 F ABRIC 

### F ILTER



### 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 par ticles from oil-fired boilers and the associated hazard from flammability of their use, fabric filte rs 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.

### Hawaii Electric Light Company, Inc. 6-3 Trinity Consultants BART Analysis 

### 6.2.5 W ET 

### S CRUBBER



### 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 scr ubbers 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 PM 10 

### 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 controlli ng 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 th ey follow the streamlines and avoid contact with the drop. As particle size decreases, more energy is n eeded 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 bo ilers are not less than a few microns, particles of this size have the highest ability to impa ir visibility; thus, a wet scrubber may not be effective at controlling the particles that ha ve the greatest ability to impair visibility.



### 6.2.6 F UEL 

### S WITCHING



### Residual oil has inherent ash that contribu tes 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. Lo wer 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 SO 2 

### 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 ash 21 

### . It is estimated that filterable PM 10 

### emissions would be reduced in proportion to the reduction in ash content. Based on the reduction in ash content, reductions of filterable PM 10 

### 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/compari ng-electrostatic-precipitator.htm
21 Combustion-Fossil Power Systems, J.G. Singer published by Co mbustion Engineer, Inc,

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

## 6.3 R ANK OF 

## T ECHNICALLY FEASIBLE 

## PM 10 

## C ONTROL 

## O PTIONS BY 

## E FFECTIVENESS

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 th e control levels for the controls listed in the previous section.

T ABLE 

### 6-3. C ONTROL 

### E FFECTIVENESS OF 

### T ECHNICALLY 

### F EASIBLE 

### PM C ONTROL 

### T ECHNOLOGIES

Control Technology Estimated Controlled

Level 22

(%)

Distillate oil ~99%

Wet ESP ≤ 90

Wet Scrubber ~50-60



## 6.4 E VALUATION OF 

## I MPACTS FOR 

## F EASIBLE 

## PM 10 

## C ONTROLS

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 C OST OF 

### C OMPLIANCE



### The capital costs, operating costs, and cost effectiveness of wet ESPs and wet scrubbers
have been estimated for Hill 5 and Hill 6. Th e cost effectiveness of switching to a distillate
fuel has also been estimated.

Control Costs The capital and operating costs of the ESP a nd 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 peri od 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

22 AP-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 annua l emission rate by the control percentages shown in Table 6-3 (99% for distillate oi l, 90% for a wet ESP, and 50% for a wet scrubber).

Cost Effectiveness The cost effectiveness was determined by dividi ng the annualized cost by the annual tons reduced. The costs effectiveness analys is is summarized in Table 6-4.

Table 6-4 indicates that the cost effectiven ess 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 pe r boiler. Finally, Table 6-4 shows that

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



### 6.4.1.1

6.4.1.2 E NERGY 

### I MPACTS AND 

### N ON 

### -A IR 

### Q UALITY 

### I MPACTS



### There are no energy or non-air quality im pacts 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 amo unt 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.



### R EMAINI NG 

### U SEFUL 

### L IFE



### 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, si nce 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 Trinity ConsultantsBART AnalysisTABLE6-4.SUMMARY OFCOSTEFFECTIVENESS FORHILL5&HILL6PM10CONTROLSHill 5BaselineControlledAnnualizedTotalTotalEmissionRateEmissionControlA,BEmissionRate PM ReducedCapitalCostCapitalCostTotal DirectAnnual CostIndirectCostEAnnualizedCostCostEffectivenessIncrementalCost(tpy) (%) (tpy) (ton/yr) ($) ($/yr) ($/yr) ($/yr) ($/yr) ($/ton) ($/ton)Wet scrubberD38.07 50 19.04 19.04 170,612 18,732 57,930 30,507 88,437 4,646 -ESPC38.07 90 3.81 34.26 2,643,532 290,246 31,779 415,054 446,833 13,041 23,534FuelSwitchingtoDistillate Oil38.07 99 0.38 37.69 N/A N/A N/A N/A 6,450,443 171,142 341,035Hill 6BaselineAnnualEmissionRateEmissionControlA,BControlledEmissionRateReducedEmissionsCapitalCostAnnualizedCapitalCostTotal DirectAnnual CostTotalIndirectCostETotalAnnualizedCostCostEffectivenessIncrementalCost(tpy) (%) (tpy) (ton/yr) ($) ($/yr) ($/yr) ($/yr) ($/yr) ($/ton) ($/ton)Wet scrubberD31.85 50 15.92 15.92 170,612 18,732 57,930 30,507 88,437 5,554 -ESPC31.85 90 3.18 28.66 2,643,532 290,246 31,779 415,054 446,833 15,589 28,133FuelSwitchingtoDistillate Oil31.85 99 0.32 31.53 N/A N/A N/A N/A 6,760,561 214,417 427,543AControl estimation for ESP and Scrubber from: AP-42, Fifth Edition, Volume I, Chapter 1, Section 1.3.3CESP Cost information: Source: U.S. Envrionmental Protection Agency, EPA Air Pollution Control Cost Manual, Sixth Edition.Chapter 6.DWet Scrubber Cost information: Source: U.S. Envrionmental Protection Agency, EPA Air Pollution Control Cost Manual, Sixth Edition. Chapter 6.ETotal annual cost for fuel switching is provided in Table 4-3, SO2fuel analysis.BPercent 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% ash content. Ashcontent 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 E VALUATION OF 

## V ISIBILITY 

## I MPACT OF 

## F EASIBLE 

## PM 10 

## C ONTROLS

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 SO 2 

### 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 PM 10 

### emission rates associated with these controls were modeled using CALPUFF.

The maximum short-term PM 10 

### emission rates associated with wet ESPs and scrubbers were calculated by reducing the uncontrolled short-term PM 10 

### emission rates shown in Tables 6-1 and 3-7 (where Table 3-7 provides the speciated PM 10 

### emission rates based on the total PM 10 

### 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 th at 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.

T ABLE 

### 6-5. S UMMARY OF 

### E MISSION 

### R ATES 

### M ODELED TO 

### R EFLECT 

### W ET 

### ESP FOR 

### PM 10 

### C ONTROL

Unit SO 2 (lb/hr) SO 4 (lb/hr) NO X (lb/hr) PM C (lb/hr) PM F (lb/hr) SOA (lb/hr) EC (lb/hr) PM 10, 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



### T ABLE 

### 6-6. S UMMARY OF 

### E MISSION 

### R ATES 

### M ODELED TO 

### R EFLECT 

### W ET 

### S CRUBBER FOR 

### PM 10 

### C ONTROL

Unit SO 2 (lb/hr) SO 4 (lb/hr) NO X (lb/hr) PM C (lb/hr) PM F (lb/hr) SOA (lb/hr) EC (lb/hr) PM 10, 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, 98 th 

### percentile modeled visibility impact, a nd the number of days with a modeled visibility impact greater than 0.5 Δ dv. The visibility improvement shown in the table was calculated as the difference between the existing visibility impa irment and the visibility impairment associated with the addition of wet ESPs as measured by the 98 th 

### 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

T ABLE 

### 6-7. S UMMARY OF 

### V ISIBILITY 

### I MPROVEMENT 

### A SSOCIATED WITH 

### W ET 

### ESP S ON 

### H ILL 

### 5

AND 

### H ILL 

### 6

Volcanoes National Park Haleakala National ParkMaximum Impact (Δdv)98% Impact (Δdv)# Days > 0.5ΔdvVisibility Improvement(Δdv)*,†Visibility Improvement*,†Maximum Impact (Δdv)98% Impact (Δdv)# Days > 0.5ΔdvVisibility 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 98 th percentile impact ( Δ dv) compared to the baseline impact ( Δ dv) †The visibility improvement shown in the table has been calculated from 98 th 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 98 th percentile impacts shown in the table, the visibility improvement

calculated from the baseline and controlled 98 th percentile impacts shown in the table may be slightly different than the visibility impr ovement 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, 98 th 

### percentile modeled visibility impact, and the number of days with a modeled visibility impact greater than 0.5 Δ dv. The visibility improvement shown in the table was calculated as the difference between the existing vi sibility impairment and the visibility impairment
associated with the addition of wet scrubbers as measured by the 98 th 

### percentile.

### Hawaiian Electric Light Company, Inc. 6-9 Trinity Consultants BART Analysis

T ABLE 

### 6-8. S UMMARY OF 

### V ISIBILITY 

### I MPROVEMENT 

### A SSOCIATED WITH 

### W ET 

### S CRUBBERS ON 

### H ILL 

### 5 AND 

### H ILL 

### 6

Volcanoes National Park Haleakala National ParkMaximum Impact (Δdv)98% Impact (Δdv)# Days > 0.5ΔdvVisibility Improvement(Δdv)*,†Visibility Improvement*,†Maximum Impact (Δdv)98% Impact (Δdv)# Days > 0.5ΔdvVisibility 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 98 th percentile impact ( Δ dv) compared to the baseline impact ( Δ dv) †The visibility improvement shown in the table has been calculated from 98 th 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 98 th percentile impacts shown in the table, the visibility improvement

calculated from the baseline and controlled 98 th percentile impacts shown in the table may be slightly different than the visibility impr ovement reflected in the table.



### As shown in Table 6-7, the operation of wet ESPs results in an estimated 0.08 to 0.11 Δ dv improvement (5 to 8 percent) of the 98 th 

### percentile visibility impairment attributable to Hill 5 and Hill
6 in VNP and an estimated 0.01 to 0.03 Δ dv improvement (4 to 7 percent) of the 98 th 

### percentile visibility impairment attributable to Hill 5 and H ill 6 in HNP. Further, as shown in Table 6-8, the operation of wet scrubbers results in an estimated 0.04 to 0.06 Δ dv improvement (3 to 5 percent) of
the 98 th 

### percentile visibility impairment attributable to Hill 5 and Hill 6 in VNP and an estimated 0.01
to 0.02 Δ dv improvement (3 to 4 percent) of the 98 th 

### 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 impa irment, the improvement in visibility impairment represented by Tables 6-7 and 6-8 does not reflect reality.



## 6.6 P ROPOSED 

## B ART FOR 

## PM 10



### The cost effectiveness of all the PM controls evalua ted for both the boilers is over $4,600/ton, and for
most controls is well over $5,000/ton. Based on the low PM 10 

### 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 relate d low improvement to the visibility impairment
attributable to the Hill boilers based on the a pplication of the controls (only up to 0.06 Δ dv), none of the controls are determined to satisfy BART. T hus, there are no fuel changes or add-on controls proposed as BART for PM 10 

### for the Hill boilers.

### Hawaii Electric Light Company, Inc. Trinity Consultants BART Analysis 

## A PPENDIX 

## A

NO X 

### C ONTROL 

### C OST 

### C ALCULATIONSParameters/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 Index A

a. May 2009 509.1

b. Dec 2008 575.4

c. 2004 444.2

Total Capital Investment B,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 differential E,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 EstimateHill 5 Hill 6
23 14.1
0.57 0.49

197 249

0.11 0.11
Cost Index A

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) ($) 5,351,928 3,883,355 Capital Cost B location differential ($) 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

000

, 300 75 

    

= A

Z D



### ( ) ( ) 

# [ ] 4.0 05.0 100 / 5.1/ C B Z =

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 ($/yr)
G = Annual capacity factor (expressed as a fraction) B = Inlet NOx (lb/MMBtu); range of 0.15 - 2.5 lb/MMB tu H = Heat input (MMBtu/hr) C = NOX removal efficiency; range of 80-95% D = Capital cost ($/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 mate rials from the U.S. mainland to the island of Hawai i, 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 mainten ance labor, associated

with their use. Hawaii cost of labor differential applied to entire fixed costs to ensure cost accoun ting 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 an d 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 typ es are similar. 35.0 000

, 300 75 

    

= A

Z D

C A D E × × =

( ) ( ) 

### [ ] { } A Z A D C H B G F × + × × × + × × × × × × = 45.1 025 .0 05.1 005 .1 2000 / 8760 100 / 37.0 225 

### ( ) ( ) 

# [ ] 4.0 05.0 100 / 5.1/ C B Z =

### Hawaii Electric Light Company, Inc. Trinity Consultants BART Analysis 

## A PPENDIX 

## B

PM 10 

### C ONTROL 

### C OST 

### C ALCULATIONSParameters/Costs Equation Hill5 Hill6ParametersTotalCollectionPlatearea,ft2(TCP)A50000 50000EquipmentCostofESP,$(EC)ifTCP</=50,000=614.55(TCP)^0.6276$546,551 $546,551ifTCP>50,000=57.87(TCP)^0.8431FactortoconvertfromFRPtoothermaterial(m)1 1CostIndexa.May2009 509.1b.1998 389.5PurchasedEquipmentCost(A)$714,375 $714,37514.Capitalrecoveryfactors=[Ix(1+i)^a]/[(1+i)^a‐1],whereI=interestrate,a=equipmentlife0.109794625 0.109794625EquipmentCRF,15‐yrlife,7$interestDirectCosts‐Table3.16PurchasedequipmentcostsESP Capital and O&M Cost EstimatePage1of2ESP+auxiliaryequipment(A)Asestimated,A$714,375 $714,375Instrumentation0.10A $71,438 $71,438Salestaxes0.03A $21,431 $21,431Freight0.05A $35,719 $35,719PurchasedEquipmentcost,PECB=1.18A $842,963 $842,963DirectInstallationCostsTable3.16Foundation&supports0.04B $33,719 $33,719Handling&erection0.50B $421,481 $421,481Electrical0.08B $67,437 $67,437Piping0.01B $8,430 $8,430Insulationforductwork0.02B $16,859 $16,859Painting0.02B $16,859 $16,859DirectInstallationCosts0.67B $564,785 $564,785IndirectCosts(installation)Table3.16Engineering0.20B $168,593 $168,593Construction&fieldexpenses0.20B $168,593 $168,593Contractorfees0.10B $84,296 $84,296Start‐up0.01B $8,430 $8,430Performancetest0.01B $8,430 $8,430Modelstudy0.02B $16,859 $16,859Contingencies0.03B $25,289 $25,289TotalIndirectCosts,IC0.57B $480,489 $480,489TOTALCAPITALINVESTMENT(2009$)Table3.16BDC+IC=2.24*B*(Retrofitfactorof1.4)(RetrofitfactorbasedonaverageprovidedonPage2‐49)$2,643,532 $2,643,532Page1of2DirectAnnualCostsOperatingLaborOperator3hr/day*360days/yr*$12/hr $12,960 $12,960Supervisor15%ofoperator $1,944 $1,944Coordinator1/3ofoperator $4,320 $4,320MaintenanceLabor$4,125forcollectorarea<50,000ft^3(AsreferencedbyOAQPSforESP)$4,125 $4,125Material1%ofpurchaseequipmentcosts $8,430 $8,430UtilitiesUtilitiescurrentlynotestimatedduetovariabilityElectricity‐fanElectricity‐operatingWastedisposalTotalDirectAnnualCost$31,779 $31,779IndirectCosts,ICTable3.21Overhead60%ofsumofoperatinglabor,maintenancelabor,&maintenancematerials$19,067 $19,067Administrativecharges2%ofTotalCapitalInvestment $52,871 $52,871Propertytax1%ofTotalCapitalInvestment $26,435 $26,435Insurance1%ofTotalCapitalInvestment $26,435 $26,435Capitalrecovery$290,245.55 $290,245.55TotalIndirectAnnualCosts$415,054 $415,054Page2of2TOTALANNUALCOST$446,833 $446,833Sources:AAdetaileddesignoftheplateareahasnotbeencompleted.Theexhuastfrombothboilershadsimilarflowratestotheexampleinthemanual,thusitwaspresumedthattheplateareawouldbeofsimilarsizetotheexample.BRetrofitfactorof1.4takesintoaccountthehighcostoftransportingconstructionmaterialsfromtheU.S.mainlandtotheislandofHawaii,andincreasedlaborcost.1.U.S.EnvironmentalProtectionAgency,EPAAirPollutionControlCostmanual,SixthEdition.Chapter6.EPA/452/B‐02‐001,January2002.2.Oommen,Roy.MethodologyforEstimatingControlCostsfortheIndustrial,Commercial,andInstitutionalBoilersandProcessHeatersNationalEmissionStandardsforHazardousAirPollutants,October2002.Page2of2Parameters/CostsEquationHill 5Hill 6Equipment Cost of Scrubber, $ (EC)Low engery scrubber w/stainless steel. Stainless steel utilizedfor corrosion prevention.Scrubber type based on OAQPS example with similar flow rateand temperature.=1.1.*(150*61,000^0.56)$78,935 $78,935Factor to convert from FRP to other material (m)11Cost Indexa. May 2009509.1b. 1998389.5Purchased Equipment Cost (A)$103,173$103,17314. Capital recovery factors= [ I x (1+i)^a]/[(1+i)^a - 1], where I = interest rate, a =equipment life0.109794625 0.109794625Equipment CRF, 15-yr life, 7$ interestDirect Costs - Table 2.8Purchased equipment costsPackaged Unit (A1)As estimated, A1$103,173$103,173Auxiliary Costs (A2)A2 = 0.1A1$10,317$10,317Equipment CostsA = A1 + A2$113,490$113,490Instrumentation0.10 A$11,349$11,349Sales taxes0.03 A$3,405$3,405Freight0.05 A$5,674$5,674Purchased Equipment cost, PECB = 1.18 A$133,918$133,918Direct Installation Costs - Table 2.8Foundation & supports0.06 B$8,035$8,035Handling & erection0.40 B$53,567$53,567Electrical0.01 B$1,339$1,339Piping0.05 B$6,696$6,696Insulation for ductwork0.03B$4,018$4,018Painting0.01B$1,339$1,339Direct Installation Costs0.56 B$74,994$74,994Indirect Costs (installation) - Table 2.8Engineering0.10B$13,392$13,392Construction & field expenses0.10B$13,392$2,678Contractor fees0.10B$13,392$13,392Start-up0.01B$1,339$1,339Performance test0.01B$1,339$1,339Model study-Contingencies0.03B$4,018$4,018Total Indirect Costs, IC0.35B$46,871$46,871TOTAL CAPITAL INVESTMENT (2009$)A(DC + IC ) * (Retrofit factor of 1.4) (Retrofit factor based onaverage provided for ESP on Page 3-41). No specific factorprovided for scrubber, so factor for ESP was relied on.$170,612 $170,612Scrubber Capital and O&M Cost EstimatePage 1 of 2Direct Annual Costs - Table 2.9Operating LaborOperator3hr/shift*2shifts/day*360 days/yr * $20/hr (Operator hrs/dayand $/hr consistent with example on Page 2-57)$43,200 $43,200Supervisor15% of operator$6,480$6,480MaintenanceLaborAssumed similar labor requirements as to that required forESP per Section 6, Page 3-47 of OAQPS Cost manual($12.50/hr, 7.5 h/wk, 44 wk/yr )$4,125 $4,125Material100% of maintenance labor$4,125$4,125Utilities(consumption rate) * (hrs/yr) * (unit cost)FanUtilities currently not estimated due to variabilityPumpWaterOperating materialsWastewater disposalTotal Direct Annual Cost$57,930$57,930Indirect Costs, ICAdministrative charges2% of Total Capital Investment$3,412$3,412Property tax1% of Total Capital Investment$1,706$1,706Insurance1% of Total Capital Investment$1,706$1,706Overhead60% of total labor and material costs$4,950$4,950Capital recoveryCapital Recover Factor * Total Capital Investment$18,732.23$18,732.23Total Indirect Annual Costs$30,507$30,507TOTAL ANNUAL COST$88,437$88,437Sources:ARetrofit 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 EmissionStandards for Hazardous Air Pollutants, October 2002.Page 2 of 2