MEMORANDUM

TO: Jim Eddinger, U.S. Environmental Protection Agency, OAQPS

FROM: Amanda Singleton and Susan McClutchey , ERG

DATE: 24 March 2010

SUBJECT: DRAFT Methodology for Estimating Control Cost s for the Area Source Industrial, Commercial and Institutional Boilers N ational Emission Standards for Hazardous Air Pollutants

1.0 INTRODUCTION

T his memorandum discusses the algorithms and inputs used to estimate capital and annual control costs for area source industrial, commercial and institution al boilers

. Cost impacts were calculated for add

- on control technologies as well as practices such as tune

- ups, facility

- wide energy audits, testing and monitoring. The add

- on control costs were estimated for a group of model boilers, based on a the distr ibution of boilers in the 13

- state boiler inspector inventory database, which was extrapolated to a national estimate using EIA fuel consumption data for the remaining 13 states. The methodology used to develop model units and establish baseline emission i nputs for each model unit are summarized in other memoranda 1 ,2

.

This memorandum is divided into the following sections: 1.0 Introduction 2.0 Inputs for Cost Algorithms 3.0 Cost Algorithms for Add

- on Control Devices 4.0 Cost Algorithms for Operating Practices , Testing a nd Monitoring 5.0 References Appendices : Detailed Cost Algorithms and Inputs

### 2

**. 0**  **Inputs to Control Cost Algorithms**  The inputs required to estimate the cost impacts include primary fuel type, exhaust gas flow rate (on both an actual and dry standard basis); fl ue gas temperature, oxygen, and moisture; baseline emissions entering the control device; target MACT floor emission rate or concentration; unit design capacity; and hours of operation were estimated using data reported in the 13

- state boiler inspector inv entory. Model boilers were created to represent boilers of various sizes firing biomass, coal, and liquid fuels. These model units included an average boiler design capacity, standardized to million British Thermal Units per hours (mmBtu/hr). Discussions of the how this model units were developed is contained in an other memorand um

. (model unit memo). Annual operating schedule was not reported in the boiler inspector inventories, and since the annual costs increase with additional operating hours, this cos t analysis assumes 8, 400 hours per year of operation to conservatively estimate year

- round operation accounting for a two week downtime period for maintenance. Some control cost algorithms require a pollutant inlet rate to estimate variable operating
cost s , such as dust disposal costs

. The methodology used to assign baseline emission factors and estimate the MACT floor emissions for each subcategory is discussed in separate memoranda (Gibson,Baseline and Singleton MACT Floor memos) . In order to assign the appropriate inlet and emission rates to each model boiler in the cost analysis, a VLOOKUP table was created in Excel to map the appropriate emission value to each model units, based on the boiler fuel type, control devices installed, and combustor design.Information concerning excess air (in percent) and exhaust temperature (in degrees Fahrenheit (F)) was reviewed in an EPA publications on fossil fuel industrial boilers xx and data reported in the ICCR for non

- fossil fuel industrial boilers. (Alvis, ICCR da tabase) Based on review of these documents, distillate oil model units were assigned a typical excess air value of 15% and an exhaust temperature of 350 degrees F. Residual oil model units were assigned a typical excess air value of 15% and an exhaust te mperature of 400 degrees F. Coal model units less than 400 MMBtu/hr were assigned a typical excess air value of 50% and an exhaust temperature of 400 degrees F. Coal model units greater than 400 MMBtu/hr were assigned a typical excess air value of 30% an d an exhaust temperature of 400 degrees F. Model units with non

- fossil material combinations were assigned a typical excess air value of 50% and an exhaust temperature of 400 degrees F.

Information on exhaust gas flowrate, moisture content, and percent oxygen for model boilers was not available in the boiler inspector inventory . Therefore, these parameters were calculated from the combustion kinetics of burning the primary fuels. For this calculation, the hydrogen, carbon, nitrogen, oxygen, and water composition of the primary fuel associated with the model boiler is necessary. Since the moisture content of area source boilers firing biomass fuels is unknown, the biomass m odel boilers were assigned to the fuel composition of wet biomass, since that wou ld conservatively estimate a higher exhaust flowrate for the cost analysis

. Next, the fuel category was assigned to a fuel composition according to Table 2 below:

Table 1 : Boiler Fuel Categories in Database and their Corresponding Fuel Composition Equati ons Fuel Category from

Boiler Inventory Fuel Composition Assumption for Combustion Kinetic s Calculations Coal Subituminous Coal Sub

- Bituminous over 400 MMBtu/hr Light Liquid Distillate Liquids Heavy Liquid Residual Liquids

Biomass Biomass (wet)

An average heating value and material analysis data (in percent by weight) were obtained for hydrogen, carbon, nitrogen, ash, sulfur, and oxygen for each fuel. (STEAM, its generation and uses, 40th Ed)These average percentages and the elements’ molecular wei ghts were used to calculate the theoretical amount of Oxygen (in moles per hundred pounds of fuel (mole/100 lb fuel)) necessary for the combustion of the fuel. The ratio of Nitrogen to Oxygen in the atmosphere, the average heating value for natural gas, a nd the excess air percentage and exhaust temperature (discussed in Section 3.3) for gas model units were used to calculate the exhaust flowrate (actual cubic feet per minute (acfm)), exhaust moisture content (%), and exhaust Oxygen content (%, dry basis) f or gas model u nits. An example calculation is presented in Appendix A

- 1 of the memorandum Methodology for Estimating Control Costs for the Major Source Industrial, Commercial and Institutional Boilers and Process Heaters National Emission Standards for Ha zardous Air Pollutants.” (cite major source control memo)

. 

### 3 **.0 COST ALGORITHMS FOR ADD** 
**- ON TECHNOLOGIES** 

Add

- on control technologies are those that are applied to the vent gas stream of a boiler to reduce emissions before the stream enters the atmosphere. There is limited information available about the control devices currently installed at area source boilers. Permit databases in Wisconsin and Pennsylvania include information on control devices utilized by coal and biomass boilers. Further, a pproximately 664 area source boilers were reported in the 2008 Combustion Survey and the majority (69 percent) of the 104 biomass boilers were reported have a multiclone installed or were uncontrolled

. 98 percent of the liquid boilers were reported to be uncontrolled, and 37 percent of coal

- fired boilers were reported to be uncontrolled. A few larger boilers have more advanced controls installed including a fabric filter, ESP, venturi scrubber or wet scrubbers. However these sources with advanced controls tend to be lo cated at larger area source boilers at industrial facilities and are not representative of the boilers at commercial and institutional sources. When l ooking at the boilers with design capacities less than 10 mmBtu/hr, all liquid and coal boilers are unco ntrolled and the majority of biomass boilers are uncontrolled, while 36 percent of the units are reported to have multiclones installed. No units less than 10 mmBtu/hr have any advanced controls

. The controls analyzed for the impacts anal ysis include the fabric filter , low NOx burner , linkageless boiler management system, and multiclone . In addition, when add

- on technologies are used, consideration must be given to added expenses such as ductwork and associatedequipment. All of these control devices, wi th the exception of a multiclone, were discussed in detail in the memorandum “Methodology for Estimating Control Costs for the Major Source Industrial, Commercial and Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air P ollutants

. ” Additional discussion the algorithms used to calculate capital and annual costs of multiclones an d the inputs used in that algorithm are presented in this section. Similar to the cost estimate analysis prepared for the major source rule, all costs we re

es calated to 2008 dollars. When capital recovery costs were calculated, an interest rate of 7 percent was applied over the life of the equipment.

2.1 Fabric Filter , Low NOx Burner/Replacement burner/Linkageless Boiler Management Systems , and Energy Audit s A description of the assumptions, inputs, and calculations used to estimate the costs for each of these control technologies are described in the “Methodology for Estimating Control Costs for the Major Source Industrial, Commercial and I nstitutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants.” (cite major source control memo) For Energy Audits at area source facilities , each facilit y ’ s NAICS code was unknown. Instead, the cost of the audit was dete rmined according to the distribution of two

- digit SIC codes in the boiler

- inspector inventory. SIC codes 24 and 26, representing the wood products and pulp and paper products industries, respectively, were estimated to require an industrial

- scale Energy Au dit, at a cost of $75,000 per facility. The remaining SIC codes expected to be affected by the proposed rule represent facilities in the commercial and institutional sectors (such as schools, hospitals, and churches) and were estimated to require a smaller

- scale audit, at an average cost of $3,500 per facility. The cost of each audit was annualized over 5 years at 7 percent to obtain an annualized cost estimate for energy audits. Appendix A

- 2 details the energy audit costs assigned to each SIC code anticipa ted to be affected by the area source boiler rule.

2.2 Multiclone A multiclone aids in the reduction of PM emissions

. These controls are most effective atc apturing PM emissions from large particles (>10 μm in aerodynamic diameter), but these controls also achieve modest reductions for PM emissions between 10 and 2.5 μm in aerodynamic diameter. The costs for multiclones were developed using a U.S. EPA Air Po llution Control Technology Fact Sheet (EPA 452/F03

- 005). According to this factsheet, typical exhaust gas flowrate s through a cyclone have a minimum flowrate of 1,060 standard cubic feet per minute. Some of the model boilers created for area source units are very small, and a multiclone control technology may not be feasible. If the calculated exhaust gas flowrate of a boiler was less than 1,060 scfm, no multiclone control costs were estimated for the model boiler. The fact sheet presents a range of costs in 2002$ for both initial capital investment and annual operation and maintenance. G iven the basic cost estimate available for multiclones, and the variation in size among aff ected area source boilers, the upper range of capital cost and operating and main tenance cost ranges was used to estimate a more conservative cost

. The cost estimates do not include dust disposal, which could be added to the current cost estimates by calculating the quantity of dust collected by the multiclone in tons per year and mul tiplying this tonnage by a solid waste disposal fee of $42.14 per ton. The capital recovery estimates were calculated assuming a 20

- year

- life. Appendix A

- 1 details the equations used to estimate the cost to install and operate a multiclone.



### 4 **.0 COST ALGOR**  **ITHMS FOR**  **TESTING AND MONITORING**

Capital and annual costs for testing include stack tests for PM, Hg, and CO . The proposed rule provides a compliance alternative to conduct a fuel analysis in lieu of a stack test for mercury, if the fuel contains less mercury than the MACT floor emission limit for the appropriate subcategory. The proposed rule also provides compliance flexibility to sources that consecutively test at 90 percent or less of the emission limits to test at 3

- year intervals instead of

annua l testing. Since the number of sources expected to qualify for the 3

- year interval is unknown , and all sources must test annually for the first three years of compliance, this cost analysis is based on an annual testing frequency. The cost analysis also as sumes that every solid fuel unit will conduct testing for all pollutants annually, and liquid fuel units wil l conduct stack testing for PM and CO but will conduct fuel analysis for mercury. Testing cost estimates were based on estimates used in the Phase I I test plan and were adjusted down slightly to account forlesser number of pollutants being tested. The testing costs assume that all pollutants will be tested simultaneously, or over the course of a single travel occurrence for a testing contractor. For the simpler methods (e.g., PM), the testing costs range from approximately $5,000 to $7,000. For the pollutants that involve more lab analysis (e.g., mercury ), the testing costs range from approximately $10,000

- $15,000. Although the cost ranges can be applied as is for cases where a single pollutant is being measured, estimating costs for facilities that need test data for more than one pollutant is more difficult and uncertain. For example, if a facility needs PM data and CO data, the test costs woul d not be twice the $5,000

- $7,000 price because some of the cost s are associated with getting the testing contractor to the site and setting up the equipment (these

are one

- time costs and would not be duplicated regardless of the number of pollutants test ed). Therefore, if a facility had more than one of the simpler tests to run (e.g., PM and CO), then the site

- specific cost would start in the $5,000

- $7,000 with a few $1,000 added for the second pollutant. A summary of the testing costs used in this co st analysis are presented in Appendix A

3. Monitoring costs are included for opacity monitoring (for units without bag leak detectors ), bag leak detection (for units with fabric filters), and CO monitors (for units greater than 100 mmBtu/hr). Cost estimat es for CO monitors were developed using the 2007 EPA CEMS cost model. (See 2007 CEMS COST TOOL) Cost estimates for bag leak detection were based on estimates used in the 2009 HMWI rulemaking. (SEE JUlY 2009 HWMI memo) Cost estimates for opacity monitoring we re based on a 1997 memorandum prepared for the HMWI rulemaking, and escalated to 2008. (1997 holloway memo) Monitoring costs include the cost of planning, selecting and installing monitoring equipment and support facilities; conducting an annual relative ac curacy test audit and writing the report; cylinder gas audits; developing a QA/QC plan; monitor O&M; and capital recovery. CO monitors were annualized over a 10

- year lifetime, using guidance from the 2007 EPA CEMS cost model. Bag leak detection and opacity monitoring were all annualized over a 20

- year lifetime. A summary of the monitoring costs are presented in Appendi ces A

- 4 and A

- 5

.



### 5. 0 **REFER ENCES** 

[UNDER DEVELOPMENT]