1

 Documentation for the Integrated Planning Model version 2.1.9, and "Updating Performance

and Cost of NOx Control Technologies in the Integrated Planning Model, Paper #137," by Sikander Khan

and Ravi Srivastava. 

2

 "Supplemental cost and performance information for NOx combustion controls" and

“Supplemental cost and performance information for NOx controls excel spreadsheet” developed for EPA

by Andover Technology Partners.

TECHNICAL SUPPORT DOCUMENT

METHODOLOGY FOR DEVELOPING BART NOx

PRESUMPTIVE LIMITS

Environmental Protection Agency

Clean Air Markets Division

June 15, 2005

This Technical Support Document describes the methodology adopted by EPA to

calculate the NOx control costs and control rates shown in the "Technical Support

Document for BART NOx Limits for Electric Generating Units Excel Spreadsheet"

("Excel Spreadsheet") prepared by EPA and included in the docket (docket OAR 2002-

0076, June 15, 2005). This analysis used cost and control performance assumptions from

EPA,1as well as supplemental cost and performance information developed for EPA.2

These documents are included in the docket.

The methodology EPA used in applying current combustion control technology to

BART-eligible EGUs is described in the following: If a BART-eligible EGU ("unit")

currently had no NOx controls installed, i.e., an "uncontrolled" unit, we applied a complete

set of combustion controls. A complete set of combustion controls for most units includes

a low NOx burner and over-fire air. If a unit had "partial" combustion controls installed,

i.e., either low NOx burners or over-fire air but not both, we added whichever component

was missing until the unit had a complete set of combustion controls. For example, if a

unit had a low NOx burner but no over-fire air, we added over-fire air. Conversely, if a unit

had over-fire air but no low NOx burner, we added a low NOx burner. If a unit had a

complete or partial set of combustion controls but installed them prior to 1997, our

analysis assumed that such controls were not current combustion control technology and
Technical Support Document

June 13, 2005

Page 2

replaced them with a complete set of combustion controls. We chose 1997 as a cutoff

because EPA estimates the current generation of NOx combustion control technology

became operational at approximately this time. If, after applying current combustion

control technology, a unit's new controlled NOx emission rate was higher than the average

NOx emission rate reported for the unit in the most recent year (2004), we assumed the

unit already had current combustion control technology. EPA assumed units that received

over-fire air in the analysis would have space available to install over-fire air.

The first worksheet in EPA's analysis is a description of the control cases included

in EPA's analysis. The second worksheet, "Unit Fuel Specific Summary," contains cost

and performance of the Nox controls included in EPA's analysis by boiler type and fuel

type for each control case. The third worksheet, "Cyclones," lists all of the Cyclone units. 

The highlighted (yellow) units indicate those that have existing SCR post combustion

controls. The fourth worksheet, "Percentile Analysis," calculates the 75th percentile NOx

rate by unit and fuel type for coal-fired Case 1a (installation of current combustion control

technology) and then determines if installing coal-fired Case 1e (Rotating Opposed Fire

Air- ROFA) controls will result in meeting the 75th percentile NOx rate determined for Case

1a. The fifth worksheet, "Nox control costs and performance," contains the cost and

performance assumptions (algorithms) used in the analysis.

I. Coal-fired Control Cases

The Coal-fired Case 1a, 1d, and 1e worksheets show the detailed calculations and

assumptions used in these three cases. The list of units and unit characteristics (boiler type,

fuel type, controls installed, and nameplate capacity) are consistent among the three cases

and are limited to those coal-fired units that EPA had identified as BART-eligible (or

possibly BART-eligible) and that have a Nameplate Capacity (MW) greater than or equal

to 25 MW.

The list of BART-eligible coal-fired units was developed originally by EPA in 2003

and then was updated in the first half of 2004. The electronic version of the file uses the

file name "BART Eligible Coal-Fired EGU List.xls" and is located in the docket. 

Attachments A and B to this Technical Support Document are memoranda developed by

Perrin Quarles Associates ("PQA") for EPA that explain the development of this list of

potentially BART-eligible coal-fired boilers. This list was used to populate the Excel

Spreadsheet.

To develop some of the unit characteristics, EPA used a variety of sources. NOx

controls and emissions data were queried directly from EPA's Clean Air Markets Division

database "CAMD database" and "Scorecard" data, respectively. The CAMD database is

derived from EPA's Source Management System (SMS), which serves as the primary

inventory database that includes all units covered under existing EPA emissions trading

programs managed by CAMD. States and sources can access SMS to update certain
Technical Support Document

June 13, 2005

Page 3

3

 www.epa.gov/airmarkets/emissions/raw/index.html

4

 "Information Collection Request (ICR) for the Electric Utility Steam Generating Unit Mercury

Emissions Information Collection Effort", OMB Control Number 2060-0396.

information on sources affected by programs, such as the Acid Rain Program (ARP) and

the NOx Budget Program (NBP). The Scorecard emissions data are derived from the

Electronic Data Reports (EDR)3as submitted by power plants and other generation

sources subject to the ARP.

These data are saved in the Excel Spreadsheet. Coal type information came from

EPA's Mercury ICR.4 The pre-control rates (see column J in the Coal-fired control cases)

were obtained from the "Summary of NOx Database" document, dated September 30,

1996. This document, parts 1 through 3, are included in the docket. These pre-control

rates were derived primarily from relative accuracy test audits conducted at the beginning

of the Acid Rain Program and were used to establish pre-control NOx emission rates for

purposes of EPA's Phase II Acid Rain Program NOx Rulemaking. This file includes

summary information on boilers affected by Phase I and II of the ARP and also lists

information specific to each boiler, such as state, ORIS code, unit ID, plant name, capacity,

firing type, control type, and other source-specific information.

For cases where incremental controls were installed, the controlled NOx rate was

calculated using the 2004 NOx Rate.

For nameplate capacity, EPA used the information in the list of BART-eligible

units. This data represents information stored in EPA's Monitoring Data Checking (MDC)

inventory database. This data was collected over time from EIA sources, contacts with

utilities to populate the Data and Maps section of CAMD's website

(www.epa.gov/airmarkets), and from the final NOx SIP Call EGU inventory. 

Each Coal-fired control case is summarized below in Table 1.
Technical Support Document

June 13, 2005

Page 4

Table 1

Coal-fired Control Cases

Control Case Control Action Taken Major Assumptions/Notes

1a Installation of current NOx combustion

controls for units with no prior controls,

or which had controls installed before

1997. For units with controls installed in

or after 1997, install incremental controls

if a complete set of combustion controls

was not installed (LNBO or LNC3). For

Cyclone units, apply Coal Reburn if no

prior controls installed. For Cell Burners,

install Current Combustion Controls if the

unit had no controls or controls were

installed before 1997. For Stokers install

overfire air (OFA). Do not include

existing SCR or SNCR units in the

Control Case NOx Rate.

If the 2004 NOxrate was less than the

floor rate or the new controlled rate, no

controls added.

Used average heat input from 2002 - 2004

to calculate an Average NOx Rate.

Assume 10,000 BTU/ kWh heat rate for

coal-fired boilers. The heat rate is a

measure of how much fuel energy needed

to get electric energy out. Therefore,

1,000,000 Btu/yr divided by 10,000

Btu/kWh = 100 kWh-yr. Multiply Avg

Heat Input (mmBtu) by 100 to get kWhyr. 

1d Install SCR, unless unit already has SCR

installed or the 2004 NOxrate is already

at or below the SCR floor rate. 

1e Install rotating opposed fire air (ROFA),

unless unit already has SCR or the 2004

NOx Rate is already at or below the ROFA

floor rate. Also, for Cyclone units, install

SCR. Do not include units with existing

SCR/SNCR in the Control Case NOx Rate.

The data and calculations performed in the Coal-fired worksheet are summarized in

Table 2 below for each control case. The sources of data referenced under columns Y

(Fraction of Removal) and AB (Floor NOx Emission Rate) were developed by EPA and

include fraction of removal efficiencies for each coal type as well as floor rates by fuel type.
Technical Support Document

June 13, 2005

Page 5

Table 2

Summary of Data and Calculations

Column Column Header Description Source of Data

A State State where unit is located. BART Eligible Coal-fired EGU

List.xls.

B Plant Name Name of the plant. BART Eligible Coal-fired EGU

List.xls.

C ORISPL ORIS code of the facility/plant. BART Eligible Coal-fired EGU

List.xls.

D Unit ID Unit ID assigned. BART Eligible Coal-fired EGU

List.xls.

E Boiler Type Boiler type. CAMD Database.

F 2004 NOx

Controls 

CAMD controls reported by the

unit.

CAMD Database.

G Action Control action taken, if any. See Table 1.

H Hg ICR Primary

Coal

Coal type. Hg ICR.

I Pre Control NOx

Emission Rate

Baseline emission rate. Summary of NOx Database, 

September 30, 1996 

J 2004 NOx Rate

(lbs/mmBtu) Boiler

Level

2004 NOx emission rate from

CAMD.

Scorecard data.

K Nameplate

Capacity (kW)

Nameplate capacity in kW. BART Eligible Coal-Fired

EGU List.xls.

L Effective Control

Case NOx

Emission Rate

New NOx emission rate after the

controls added, if any.

From Column AA.

M Scaling Factor 1 Calculation of scaling factors for

capital and fixed operating and

maintenance (O&M) costs.

See footnotes 1 and 2.

N Scaling Factor 2 Calculation of scaling factors for

variable O&M cost for SCR

installations.

See footnotes 1 and 2.

O Capital Cost- $/kW Capital cost in $/kW. See footnotes 1 and 2.

P Total Capital Cost Total capital costs of the

combustion control types added, if

any, in dollars.

Column K x Column M x

Column O 

(cont.)
Technical Support Document

June 13, 2005

Page 6

Table 2

Summary of Data and Calculations (cont.)

Column Column Header Description Source of Data

Q Annual Capital

Cost

Annualized capital cost. Use

capital recovery factor of 12%.

Column P x 12%

R Fixed O&M -

$/kWyr

Fixed O & M cost per kW-yr. See footnotes 1 and 2.

S Annual Fixed

O&M Cost

Annual fixed operating and

maintenance costs of the

combustion control type.

Column K x Column M x

Column R.

T Variable O&M -

mills/kW-hr

Variable O & M cost in mills/kWhr.See footnotes 1 and 2.

U Avg Heat Input

Used (mmBtu) 

Average HI using 2002, 2003,

2004 data.

Scorecard data.

V kWh-Yr (10,000

Btu/kWh) 

Assume 10,000 Btu/kWhr heat

rate. Heat input (1,000,000

Btu/yr) divided by Heat Rate

(10,000 Btu/kWhr) = 100

kWhr/yr.

Column U x 100 = kWhr/yr.

W Annual Variable

O&M Cost

Calculation for the annual

variable O & M cost of the

combustion control technology.

(Column V x Column T x

Column N)/1000. Divide by

1000 to convert mills to

dollars. Not all control cases

apply scaling factor to variable

O&M cost (Column N).

X Control Case Total

Annual Cost

Sum of Annual Capital Cost,

Annual Fixed O&M Cost and

Annual Variable O&M Cost. 

Column W + Column S +

Column Q.

Y Fraction of

Removal

Calculation based on coal type,

boiler type and control used.

See footnotes 1 and 2.

Z Controlled NOx

Emission Rate

New NOx emission rate after the

controls added, if any.

Pre Control Rate x (1 -

Fraction of Removal). For Pre

Control Rate, use Column J. 

Fraction of Removal is

calculated in Column Y.

AA Effective Control

Case NOx

Emission Rate

Actual control rate used to

calculate Effective Control Case

NOx Tons (column AF).

Column AD x 2000/Column U

AB Floor NOx

Emission Rate

Floor rates established given

boiler type and coal type.

See footnotes 1 and 2.

(cont.)
Technical Support Document

June 13, 2005

Page 7

Table 2

Summary of Data and Calculations (cont.)

Column Column Header Description Source of Data

AC Base Case NOx

Tons

Multiply 2004 NOx Emission Rate

(lbs/mmBtu) by Average HI, then

divide by 2000 to get tons.

(Column J x Column U)/2000.

AD Effective Control

Case NOx Tons

This value is calculated using the

NOx Rate in Column AC, unless

this value is less than the floor

rate, then the floor rate is used.

Multiply Controlled NOx Rate

times Average HI, then divide by

2000 to get tons.

Minimum of 

1: (Maximum of Column AB

or Column Z) x Column

U)/2000, or

2: Column J x Column

U/2000.

AE Effective Tons

Removed

Number of tons removed by using

the new control technology. 

Column AC - Column AD.

AF Effective Cost/Ton

Removed

Cost effectiveness per ton

removed.

Column X/Column AE.

The SCR cost and performance assumptions in Coal-fired Case 1d are summarized

in Table 3. The source of the assumptions used is EPA document entitled "Updating

Performance and Cost of NOx Control Technologies in the Integrated Planning Model,

Paper # 137," and is located in the docket. See footnote 1. 

Table 3

Updated SCR Cost Algorithm For IPM

SCR Cost Category New Cost Factor

Capital Cost 100 ($/kW)

Fixed O&M 0.66 ($/kW-yr)

Variable O&M 0.60 (mills/kWh)

Capital & Fixed O&M Cost Scaling Factor (243/MW)^0.27 (Apply up to maximum of 600

MW. For units larger than 600 MW, use the cost

factor determined for the 600 MW unit).

Variable O&M Cost Scaling Factor (243/MW)^0.11 (Apply up to maximum of 600

MW. For units larger than 600 MW, use the cost

factor determined for the 600 MW unit).

Fraction of Removal 90%

Floor NOx Rate 0.06 lb/mmBtu
Technical Support Document

June 13, 2005

Page 8

5

 Inventory of Electric Utility Power Plants in the United States 1999,

http://www.eia.doe.gov/cneaf/electricity/ipp/ipp99_sum.html; and, Inventory of Non-Utility Electric Power

Plants in the United States, 2000, http://www.eia.doe.gov/cneaf/electricity/ipp/ipp_sum2.html

II. Oil and Gas-fired Control Cases

The last three worksheets (Oil and Gas-fired Cases 2a, 2d, and 2e) show the

detailed calculations and assumptions used in each of these control cases. The list of units

and unit characteristics (boiler type, fuel type, controls installed, nameplate capacity) are

consistent among these three cases and are limited to those Oil and Gas-fired units that

may be BART-eligible (or possibly BART-eligible) and that have a Nameplate Capacity

(MW) greater than or equal to 25 MW. The list of BART-eligible Oil and Gas-fired units

was developed by EPA. See "Oil and Gas BART-eligible units" in the docket. The list

was based on units with a "commence commercial operation date" (as reported in Part 75

EDR) that falls within the BART time frame. In addition, for units that commenced

operation after the BART time frame but may have commenced construction within the

BART time frame, EPA attempted to identify a commenced construction date based on

New Source Review permit information (comparable to the approach used for coal units). 

The EPA evaluated all units with a reported commenced operation date prior to 1987.

This file then indicates that a unit does or may fall within the BART time frame

based on the Part 75 data and this additional research. EPA eliminated any units with a

maximum design heat input capacity less than 250 mmBtu/hr (based on EDR data) and

units with a potential to emit less than 250 tons per year. For the latter cutoff, EPA

identified 40 units that had <250 tons per year of actual emissions (SO2 and NOx) in any

year (from 1995 through 2002). Of these units, four units were identified that had a

potential to emit less than 250 tons per year of either SO2 or NOx. The potential to emit

analysis used the ratio of actual heat input to maximum design heat input capacity to adjust

actual emissions up to a potential to emit basis.

For nameplate capacity, the data represents primarily information in the MDC

inventory database, consistent with the approach taken for coal-fired units. For a few units

with missing capacity data, EPA used EIA (Inventory of U.S. Power Plants) data.5

NOx controls and emissions data for each of these units were queried from CAMD

data. Fuel type information came from the CAMD database. The Pre Control Rate (see

column AV in the Oil and Gas-fired control cases) was calculated with the assumption that

the existing NOx controls achieved the maximum efficiency (see Column AW). Given that

assumption, the Oil and Gas Pre Control Rate was calculated by dividing: (1 - Column

AW) by the Base Case 2002 - 2004 NOx Rate (Column X). The Pre Control Rate was

only calculated for units with existing controls installed before 1997 (adding state of the art

controls requires use of the Pre Control Rate to calculate new controlled rate). For the

remainder of the units, the Base Case Avg 2002 - 2004 NOx Rate was used to calculate the
Technical Support Document

June 13, 2005

Page 9

controlled rate (either because the unit had no controls or was installing incremental

controls -- if incremental controls were installed, the upper boundary fraction of removal

was an incremental percent removed).

Each Oil and Gas-fired control case is described in Table 4. 

Table 4

Oil/Gas-fired Control Cases

Control Case Control Action Taken Major Assumptions/Notes

2a Installation of current combustion control

technology for units with no prior

controls, or which had controls installed

before 1997. For units with controls

installed in or after 1997, install

incremental controls if a complete set of

current combustion controls was not

installed. Do not include existing SCR or

SNCR units in the Control Case NOx

Rate.

If the Base Case NOxrate was less than

the floor rate or the new controlled rate,

no controls added.

Used average heat input and NOx tons

from 2002-2004 to calculate a Base Case

NOx Rate.

2d Install SCR, unless unit already has SCR

installed or the Base Case NOxrate is

already at or below the SCR floor rate. 

2e Install ROFA, unless unit already has

SCR installed or the Base Case NOxrate

is already at or below the ROFA floor

rate. Also, for Cyclone Boilers, install

SCR. Do not include units with existing

SCR or SNCR units in the Control Case

NOx Rate.

The data and calculations performed in the Oil and Gas-fired worksheets are

summarized in Table 5 below (for Control Cases 2a - 2e).
Technical Support Document

June 13, 2005

Page 10

Table 5

Summary of Data and Calculations

Column Column Header Description Source of Data

A State State where unit is located. Oil and Gas BART-eligible

List Nov 12.xls.

B ORISPL ORIS Code of the facility/plant. Oil and Gas BART-eligible

List Nov 12.xls.

C Unit ID Unit ID assigned. Oil and Gas BART-eligible

List Nov 12.xls.

D Plant Name Name of the plant. Oil and Gas BART-eligible

List Nov 12.xls.

E Boiler Type Boiler type. CAMD Database.

F Primary Fuel Primary fuel type. CAMD Database.

G 2004 NOx Control CAMD controls reported by the

unit.

CAMD Database.

H Control

Technology Added

Control action taken, if any. See Table 4.

I Nameplate

Capacity (kW)

Nameplate capacity. MDC inventory data (MW x

1000 = kW).

J Scaling Factor Calculation of scaling factors. See footnote 1 and 2.

K Capital Cost -

$/kW

Capital cost in $/kW. See footnote 1 and 2.

L Total Capital Cost Total capital costs of the

combustion control types.

Column I x Column J x

Column K 

M Annual Capital

Cost

Annualized capital cost. Use

capital recovery factor of 12%.

Column L x 12%

N Fixed O&M $/kWyrFixed O & M cost per kW-yr. See footnote 1 and 2.

O Annual Fixed

O&M Cost

Annual fixed O & M costs of the

combustion control type.

Column I x Column J x

Column N.

P Variable O&M -

mills/kW-hr

Variable O & M cost in mills/kWhr.See footnote 1 and 2.

Q Avg Heat Input

Used (mmBtu) 

Average HI from 2002, 2003,

2004.

Scorecard data.

(cont.)
Technical Support Document

June 13, 2005

Page 11

Table 5

Summary of Data and Calculations (cont.)

Column Column Header Description Source of Data

R kWh-Yr (10,000

Btu/kWh) 

Assume 10,000 Btu/kWhr heat

rate. Heat input (1,000,000

Btu/yr) divided by Heat Rate

(10,000 Btu/kWhr) = 100

kWhr/yr.

Column Q x 100 = kWhr/yr.

S Annual Variable

O&M Cost

Calculation for the annual variable

O & M cost of the combustion

control technology.

(Column R x Column P)/1000. 

Divide by 1000 to convert mills

to dollars. 

T Total Annual Cost Sum of Annual Capital Cost,

Annual Fixed O&M Cost and

Annual Variable O&M Cost. 

Column O + Column M +

Column S.

U Fraction of

Removal

Calculation based on coal type,

boiler type and control used.

See footnote 1 and 2.

V Controlled NOx

Emission Rate

New NOx emission rate after the

controls added, if any.

Pre Control Rate x (1 -

Fraction of Removal). For Pre

Control Rate, use Column Y if

no controls previously installed

or if incremental controls

installed. Otherwise use

Column AX. Fraction of

Removal is calculated in

Column U.

W Floor NOx

Emission Rate

Floor rates established given

boiler type, and fuel type.

See footnote 1 and 2.

X Effective Control

Case NOx

Emission Rate

Actual NOxrate used to determine

the control case NOx tons (in

column AA).

Column AA x 2000/Column Q.

Y Base Case Avg

NOx Rate

Average NOx Rate from 2002 -

2004.

Scorecard data.

Z Base Case NOx

Tons

Multiply Base Case NOx Emission

Rate (lbs/mmBtu) by Average HI,

then divide by 2000 to get tons.

(Column X x Column Q)/2000.

(cont.)
Technical Support Document

June 13, 2005

Page 12

Table 5

Summary of Data and Calculations (cont.)

Column Column Header Description Source of Data

AA Effective Control

Case NOx Tons

This value is calculated using the

NOx Rate in Column X, unless

this value is less than the floor

rate, then the floor rate is used.

Multiply Controlled NOx Rate by

Average HI, then divide by 2000

to get tons.

Minimum of 

1: ((Maximum of Column V or

Column W) x Column

Q)/2000),or

2: Column Z

AB Effective Tons

Removed

Number of tons removed by using

the new control technology. 

Column Z - Column AA.

AC Effective Cost/Ton

Removed

Cost effectiveness per ton

removed.

Column T/Column AB.

The SCR cost and performance assumptions used in Case 2d are summarized in

Table 6. The source of the assumptions EPA used is a memorandum from Andover

Technology Partners dated November 5, 2004 and is located in the docket. See footnote

2.

Table 6

SCR Oil and Gas-fired Cost & Performance Algorithms

SCR Cost Category New Cost Factor

Capital Cost Residual Oil = 50 ($/kW)

Diesel & PNG = 35 ($/kW)

Fixed O&M Residual Oil = 0.66 ($/kW-yr)

Diesel & PNG = 0.33 ($kW-yr)

Variable O&M Residual Oil = 0.45 (mills/kWh)

Diesel & PNG = 0.30 (mill/kWh)

Capital & Fixed O&M Cost Scaling Factor Residual Oil = (550/MW)^0.27 (Apply up to

maximum of 600 MW. For units larger than 600

MW, use the cost factor determined for the 600

MW unit).

Diesel & Pipeline Natural Gas (PNG) =

(320/MW)^0.27 (Apply up to maximum of 600

MW. For units larger than 600 MW, use the cost

factor determined for the 600 MW unit).

(cont.)
Technical Support Document

June 13, 2005

Page 13

Table 6

SCR Oil and Gas-fired Cost & Performance Algorithms (cont.)

SCR Cost Category New Cost Factor

Variable O&M Cost Scaling Factor None

Fraction of Removal 90%

Floor NOx Rate Residual Oil = 0.04 lb/mmBtu

Diesel & PNG = 0.01 lb/mmBtu
June 15, 2005

TECHNICAL SUPPORT DOCUMENT

METHODOLOGY FOR DEVELOPING BART NOx PRESUMPTIVE LIMITS

Attachment A

Memorandum: Summary of BART Source Analyses
PERRIN QUARLES ASSOCIATES , INC.

675 PETER JEFFERSON PARKWAY, SUITE 200

CHARLOTTESVILLE, VIRGINIA 22911

VOICE: (434) 979-3700  FAX: (434) 296-2860

EMAIL: pqa@pqa.com

MEMORANDUM

TO: Chad Whiteman

FROM: Bill Balcke, Doran Stegura

RE: Summary of BART Source Analyses

DATE: March 24, 2003

I. Introduction

Under Work Assignment #3, PQA has conducted a number of analyses to develop

a database and related information on sources that may be subject to controls under EPA's

Proposed Guidelines for Best Available Retrofit Technology (BART) Determinations

Under the Regional Haze Regulations (66 FR 38108, July 20, 2001). The main elements

of this work include identifying BART units, providing summary information on each unit,

and analyzing the cost of retrofitting units with flue gas desulfurization (FGD) controls. 

The following memorandum explains what tasks and analyses were performed, key

assumptions and data sources that were used, and potential further analyses that could be

conducted. These issues are organized into the following eight sections: Identification of

BART Units, Compiling the Data, Plant Summary Sheets, Creating FGD Scorecards,

BART Control Costs, Units Potentially Affected under BART (< 750 MW), Summary of

Key Findings for All Coal Units, and Next Steps.

Enclosed with this memorandum are several materials that document the analyses

conducted under this task. These materials are: 

! An Excel database with BART applicability status and other information for coalfired units (see Section III, below)

! A compilation report of BART plant summary sheets (see Section IV, below)

! FGD "scorecards" (see Section V, below)

! An Excel file with control cost information (see Section VI, below)
Memorandum

March 24, 2003

Page 2

II. Identification of BART Units

Units potentially affected under the proposed BART rule include sources for which

construction was started by August 7, 1977, that were not in operation prior to August 7,

1962, and have the potential to emit more than 250 tons per year of pollutants that

contribute to regional haze. EPA has interpreted the statutory requirement under Section

169A(b) of the CAA to require that States follow the BART guidelines for power plants

built within this timeframe that have a total capacity exceeding 750 MW (see 1980

document entitled "Guidelines for Determining Best Available Retrofit Technology for

Coal-fired Power Plants and Other Existing Stationary Facilities"). 

EPA requested that PQA create a master file to identify the potentially affected

units at plants that could meet these criteria. To identify potentially affected units, PQA

began with a list of coal-fired units that had been developed for a congressional response

on the NSPS status of coal-fired, Acid Rain Program units (the "AR file"). This file

included information on the nameplate capacity and online dates for most coal-fired boilers. 

The data are from Clean Air Markets Division (CAMD) database sources. The nameplate

capacity (in MW), online date, and NSPS status comes primarily from the NOx Boiler

Database compiled as part of the Acid Rain Program Phase II NOx rule. There were a few

units for which the nameplate capacity data were not available in that file, and for those we

used other available sources (EIA Inventory, SIP Call Inventory, and 40 CFR Part 75

monitoring plan data). 

Note that nameplate capacity in the NOx Boiler Database file is the sum of the

generating capacity of each generator serving the applicable unit. Thus, the sum of

generating capacity for units will exceed actual capacity because generators that serve

multiple units will be counted more than once. 

As part of developing the AR file, the online dates were compared to data from the

Emissions & Generation Resource Integrated Database (E-GRID), and in some instances

revised because the E-GRID data appear more accurate for some pre-NSPS units based on

a review of EIA Inventory information. The online date information also reflects

comments from EIA and OAQPS staff. 

As stated above, we identified as BART units those that came online after August

7, 1962, were under construction (i.e. a construction permit was issued) prior to August 7,

1977, and, when summed with other affected units at the same plant, have a nameplate

capacity that exceeds 750 MW. At plants that meet the size criteria but have units with

online dates between 1978 and 1985, the BART rule could apply if construction on these

units commenced prior to August 7, 1977. For these plants, PQA undertook the following

steps to determine the commence construction date of the 1978 - 1985 vintage units:

! Reviewed the RACT/BACT/LAER Clearinghouse, State Part 70 permit, or other

Internet search information to determine the BART applicability status; or 
Memorandum

March 24, 2003

Page 3

! Contacted the appropriate State environmental agencies to verify when the

construction permit was issued. 

In evaluating this information, we made the following assumptions. First, units in

this time period identified as subject to Part 60, Subpart D cannot be excluded because this

NSPS subpart applies to sources that have started construction after August 17, 1971. 

Second, because NSPS Subpart Da requirements only apply to sources that started

construction after September 18, 1978, we assumed that units subject to Subpart Da are

outside the applicable BART time period. Third, if a unit received a PSD permit (with a

BACT requirement), the unit was assumed to be outside the BART time period. In all

cases, we were able to make a BART applicability determination for this subset of units

based on the information gathered or provided by state agency contacts.

III. Compiling the Data

After the BART-applicability status was determined for each unit, we compiled an

Excel file for all Acid Rain Program coal-fired units, both BART and Non-BART. This file

has basic information on BART applicability status, the plant name, plant ID, unit ID,

online dates, NSPS status, nameplate capacity, 2001 NOx and SO2 data, emission controls

currently applied, and projected SO2 controls (the "BART-AR file"). The file has separate

worksheets for: 

! All coal-fired Acid Rain units

! BART units at the > 750 MW plants

! A list of units that are within 30 MW of the 750 MW cutoff

! A list of all data fields and the source of the data (see Table 1 below)

! A sheet that defines the control device abbreviations used in the file

The data fields are derived primarily from the AR file as described above. Some

information, such as 2001 emissions data, and primary and secondary NOx and SO2

controls, were obtained from the most recent 2002 EDR submittals as of early December

2002 (includes second and third quarter submittals). EPA also recently quality checked

this information, and the final version of the BART_AR file reflects this recent quality

assurance activity.

Also, data on projected SO2 controls were obtained from the file

"s100d_2010_Pech_BART.xls" (the "Pechan file") as received by PQA from Chad

Whiteman on November 12, 2002. This file consists of the IPM 2000 base case results for

the model run year 2010 and includes two separate worksheets, one for all units and one

for the coal units. Existing and projected scrubber information are included in the file as

well, which are highlighted in yellow and red, respectively. PQA also identified projected

scrubbers from Internet search information and compliance strategies under North

Carolina's new SO2 regulations. 
Memorandum

March 24, 2003

Page 4

Table 1

Data Fields Included in BART Applicability File 

Acid Rain Program Coal-Fired Units

Data Field Source of Information

State

AR File

Facility Name

ORIS

Unit ID

Online Year

BART Unit Based on Online Year & Nameplate Capacity

Located at Plant with BART Unit Based on Determination of BART Units at Plant

NSPS

AR File Nameplate Capacity

2001 NOx Tons

2001 SO2 Tons

Primary NOx Control

EDR Data (2nd and 3rd quarter 2002)

Secondary NOx Control

Primary SO2 Control

Secondary SO2 Control

Primary Particulate Control

Secondary Particulate Control

Projected Retrofit Scrubbers (IPM) Pechan File

Other Announced Scrubbers Internet search information

Compliance Data on NC Regulations (SB 1078)

Other information as received from EPA

Latitude/Longitude EDR Data (2nd and 3rd quarter 2002)

Nearest Class 1 Area Calculated based on latitude/longitude data and

OAQPS Class 1 centroid data
Memorandum

March 24, 2003

Page 5

PQA used latitude/longitude for each facility to calculate the distance to the nearest

Class I area. These data are listed in both minutes/degrees and decimal format in the

master file described above. PQA used the latitude/longitude data and the Class I area

centroid data (as provided by Tim Smith) to determine the distance of each facility to the

nearest Class I area. ArcView was used to populate this information automatically based

on the underlying datasets. 

IV. Plant Summary Sheets

Based primarily on the BART-AR file, PQA generated and formatted individual

summary sheets for the BART-affected units at each facility. The first draft of these sheets

was delivered to EPA on January 9, 2003. PQA has prepared and submitted a revised

report that contains all of the plant summary sheets in conjunction with this memorandum. 

In addition to the BART-AR file, the summary sheets also rely on projected 2010 SO2 and

NOx emissions from the Pechan file, and on information provided by Chad Whiteman on

planned NOx controls. We also prepared miscellaneous notes to identify any special

considerations about a particular plant. As an example, one of these summary sheets is

presented below.
Memorandum

March 24, 2003

Page 6

Plant: James H Miller, ORIS 6002, Units 1 and 2

Location: Jefferson County, AL

Nearest Class I Area: Sipsey Wilderness, AL (52 miles)

Data Elements Unit 1 Unit 2

Nameplate Capacity (MW) 

[Total: 1,412]

706 706

Online Date 1978 1985

2001 SO2 Tons 9,612 12,242

2010 SO2 Tons 25,898 24,001

FGD No No

FGD: IPM 2010 Base Case

Projected 

No No

2001 NOx Tons 5,694 7,510

2010 NOx Tons 8,910 7,266

NOx Controls Installed None None

NOx Controls Planned No data No data

Miscellaneous Notes The construction of Units 1 and 2 predates the

August 7, 1977 cutoff for BART units. These units

do not have a PSD permit. (Source: AL DEM)

V. Creating FGD Scorecards

After compiling the basic information on each BART-affected source, PQA

compiled the aggregate information for both BART and Non-BART sources in order to

create a series of "FGD Scorecards" which present data on nameplate capacity and

projected 2010 SO2 data for all the coal units in relation to the presence of FGD control

equipment on the units. In addition, these data were used to proceed with the scrubber

cost analysis based on cost algorithms provided by EPA. The compilation of information

for the FGD Scorecard is described below. We also used this information to compile the

cost information discussed in Section VI., below.
Memorandum

March 24, 2003

Page 7

A. Aggregated Nameplate Capacity and 2010 Emissions Data

If available, we used the nameplate capacity data from the AR file. However, for

those coal units that are not currently identified as AR units, we used the nameplate

capacity data in the Pechan file. The nameplate capacity data for all BART affected units

were obtained from the BART-AR file. Note that the total nameplate capacity for the coal

units listed in the AR file was significantly higher than the total for corresponding units in

the Pechan file. As stated above, this could be due to the fact that nameplate capacity in

the BART-AR file is the sum of the generating capacity of each generator serving the

applicable unit. 

It can be difficult to determine which units share a generator, especially if there are

numerous generators and units at the facility. However, we analyzed the BART-affected

units to ensure that no units were included in this category due to inflated nameplate

capacity data. There are two plants with BART-affected units, for which we determined

that the nameplate capacity should be reduced by half since the units share a generator. 

These are Joliet 29 (ORIS 384, Units 71, 72, 81, and 82) and Powerton (ORIS 879, Units

51, 52, 61, and 62), both in Illinois. The nameplate capacity reduction for these units did

not impact the BART applicability determination. Further investigation would be

necessary to determine which non-BART units share a generator. 

We aggregated the projected 2010 SO2 emissions for all the coal units based on the

Pechan file. 

B. Missing Units

There were 29 non-BART units and three BART units in the AR file that we could

not locate in the Pechan file. We assumed that these units are projected to be retired or

will be converted to a unit that relies on fuel other than coal. Thus, we did not include

these units in the calculation of total nameplate capacity or projected 2010 SO2 emissions. 

In addition, for five of the non-BART units, nameplate capacity and projected SO2

emissions data were not listed in the Pechan file and were not included in the overall

calculations. 

C. Results

Based on the nameplate capacity and projected 2010 SO2 emissions data, FGD

"scorecards" (presented as Excel charts) were created to summarize information for BART

and non-BART units in terms of the existence of FGD (i.e. existing, projected or none) in

the BART-AR file. Information on nameplate capacity for all BART and non-BART units

is presented in Table 2 below and is divided into categories based on the existence of FGD. 
Memorandum

March 24, 2003

Page 8

Table 2

Nameplate Capacity of Coal Fired Electric Generating Units

(in terms of BART Status and Existing/Projected SO2 Controls)

Data Element Total

(MW)

BART Affected Not BART Affected

MW Percent

of Total

MW Percent

of Total

FGD Projected 

(IPM 2010 Base Case)*

24,811 18,478 75% 6,333 25%

FGD Existing 94,637 42,658 45% 51,979 55%

Total FGD 

(Existing & Projected)

119,448 61,136 51% 58,312 49%

No FGD 

(Existing or Projected) 

213,814 87,786 41% 126,028 59%

Total Nameplate

Capacity

333,262 148,922 45% 184,340 55%

* FGD Projected includes projected FGD as included in IPM 2010 and other announced or planned scrubbers,

including the NC units expected to install FGD to comply with SB 1078 (12,397 MW Total).

Note: The total nameplate capacity associated with existing and projected FGD at all coal units, BART-affected

coal units, and not BART-affected coal units comprise 36%, 41%, and 32% of the corresponding total

nameplate capacity, respectively.

Similarly, Table 3 below presents information on projected 2010 SO2 emissions for

all BART and non-BART units and, as in Table 2 above, is divided into categories based

on the existence of FGD. 
Memorandum

March 24, 2003

Page 9

Table 3

Projected 2010 SO2 Emissions from Coal Fired Electric Generating Units

(in terms of BART Status and Existing/Projected SO2 Controls)

Data Element Total

Projected

2010 SO2

(tons)

BART Affected Not BART Affected

Projected

2010 SO2

(tons)

Percent

of Total

Projected

2010 SO2

(tons)

Percent

of Total

FGD Projected 

(IPM 2010)*

833,583 607,558 73% 226,025 27%

FGD Existing 1,142,396 445,906 39% 696,490 61%

Total FGD 

(Existing & Projected)

1,975,979 1,053,464 53% 922,515 47%

No FGD 

(Existing or Projected) 

7,718,783 3,407,064 44% 4,311,719 56%

Total Projected 

2010 SO2 (tons)

9,694,762 4,460,528 46% 5,234,234 54%

* FGD Projected includes projected FGD as included in IPM 2010 and other announced or planned scrubbers,

including the NC units expected to install FGD to comply with SB 1078 (323,239 2010 SO2 tons total).

Note: The total 2010 SO2 emissions (tons) associated with existing and projected FGD at all coal units, BARTaffected coal units, and not BART-affected coal units comprise 20%, 24%, and 18% of the corresponding

total 2010 SO2 emissions, respectively.

The FGD scorecards use the information in Tables 2 and 3 to present a pre-BART

control scenario. For a post-BART scenario, the FGD scorecards assume the use of FGD

on all BART-affected units. The scorecards present the information both in terms of

nameplate capacity and projected 2010 SO2 emissions for the universe of coal-fired units. 

For the nameplate capacity scorecards, we removed all MW capacity from the BART, No

FGD category and added this capacity to the BART, FGD Projected category in order to

show the post-BART scenario.

For the scorecards that present SO2 emissions in a pre- and post-BART control

scenario, the emissions from the BART, No FGD category in the pre-BART scenario were

added to the Projected FGD category as controlled emissions. The following section on

evaluating control costs summarizes the method used to apply FGD types to each unit and

then calculate controlled 2010 SO2 emissions. PQA applied two scenarios to evaluate

which FGD type should be applied to each unit. The first scenario was based on IPM

assumptions while the second was based on suggestions from EPA staff. Both scenarios
Memorandum

March 24, 2003

Page 10

are presented in the FGD scorecards for SO2 emissions in separate worksheets. The

approach for these two scenarios is described in greater detail in the following section.

VI. BART Control Costs

A. Overview of Results

We calculated cost effectiveness (dollars per ton of SO2 removed) for the projected

BART FGD installations based on the FGD cost model spreadsheets provided by Chad

Whiteman and Tim Smith. The cost models in the spreadsheets are from Controlling SO2

Emissions: A Review of Technologies, EPA/600/R-00/093, November 2000. 

We performed two sets of cost calculations. Both sets of calculations use 2010

unit information (coal sulfur content and heat input, and coal usage) from the Pechan file

(the IPM 2000 Base Case run for 2010, performed as part of EPA’s Clear Skies analysis). 

For the first set of calculations, we assigned the scrubber type for the unit based on

the coal sulfur content and unit size in the same manner as the IPM model runs

(summarized below in Table 4). Note that if there was more than one affected unit at a

plant, we applied the scrubber type for the largest unit to all of the BART-affected units at

the plant.

Table 4

Determination of FGD Type

Based on Capacity and Sulfur Content

Coal Sulfur

Content (%)

Unit Nameplate Capacity (MW)

< 100 > 100, and

< 550

> 550, and

< 1,000

> 1000

2.0 None MEL LSD LSFO

2.5 None MEL LSFO LSFO

>2.5 None LSD LSFO LSFO

Note: LSD - Lime Spray Drying (90% Control)

LSFO - Limestone Forced Oxidation (95% Control)

MEL - Magnesium Enhanced Lime (95% Control)

For the second set of calculations, we modified the approach by assigning an LSFO

scrubber type to all units greater than 550 MW. This scenario increased the control

efficiency to 95% for units greater than 550 and less than or equal to 1,000 MW with coal

sulfur contents less than or equal to 2.0%. This modification affected all 106 units which

had previously been assigned an LSD scrubber at 90% control. 
Memorandum

March 24, 2003

Page 11

Table 5, below, presents the overall cost, emissions reduction, and cost

effectiveness for both the first and second scenarios. The cost effectiveness for each unit

under the two FGD scenarios are provided in the file BART FGD Cost Calculation

Summary.xls. The second scenario is more cost effective than the first, has lower annual

costs, and reduces emissions overall by 95% compared to 91%. Applying the LSFO FGD

type in the second scenario also is less costly on a unit basis, both in terms of total annual

cost and cost effectiveness, for all of the units which had been assigned an LSD scrubber in

the first scenario.

Table 5

BART Unit FGD Cost Effectiveness

Control Scenario 1 vs. Control Scenario 2 

Control

Scenario

Total Annual

Cost

2010

PreControl

Emissions

2010 Tons

Reduced

Cost

Effectiveness

($/ton)

Overall

Control

1 $3,244,156,622 3,407,064 3,097,896 $1,047 91%

2 $2,640,714,012 3,407,064 3,235,880 $816 95%

B. Cost Spreadsheet Variables

Other variables that we included in the FGD cost calculations for BART units

include:

1. 2010 - Heat Input (trillion Btus), SO2

 Emissions (tons), and Heat Rate

(Btu/kWh)

We obtained the 2010 heat input (trillion btus), sulfur dioxide emissions

(tons), and heat rate (btu/kWh) from the Pechan file. This file contains

the 2000 base case results for the year 2010 IPM model run performed as

part of EPA’s Clear Skies analysis. The file, EPA Base Case 2000 Parsed

for 2010, is available at: 

http://www.epa.gov/airmarkets/epa-ipm/results.html#downloadresults

2. 2010 - Capacity Factor

We calculated the capacity factors used in the cost spreadsheets for each

unit as follows (calculation does not include unit conversion factors): 

[Heat Input (Btu)/Heat Rate (Btu/kWh)]÷[Nameplate Capacity (kW) X

8,760 (hrs/yr)]. As described above, the nameplate capacity was divided

in half for the four pairs of units at the Powerton and Joliet 29 plants in

Illinois with shared generators. 
Memorandum

March 24, 2003

Page 12

3. 2010 - Coal Heat Content

We used three coal heat contents for the cost calculation spreadsheet, and

to back out coal sulfur content as described in item 4. below. We

obtained the heat contents from Section 5 of the IPM Model Run

Documentation Report, which can be found at: 

http://www.epa.gov/airmarkets/epa-ipm/index.html#documentation. The

three heat contents are:

! Bituminous: 23.8 mmBtu/ton (11,900 Btus/lb)

! Sub-bituminous: 17.1 mmBtu/ton (8,550 Btus/lb)

! Lignite: 12.8 mmBtu/ton (6,400 Btus/lb)

4. 2010 Coal Percent Sulfur:

We calculated the projected 2010 sulfur content data for each of the three

types of coal listed above based on the 2010 heat input, SO2 emissions,

and the coal heat content from item c. above: [SO2 (tons)/(2

tonsSO2/tonS)/0.97] ÷ [coal heat input (Btus)/(coal heat content

(Btus/lb)]. This calculation does not include unit conversion factors.

VII. Units Potentially Affected under BART at Plants < 750 MW

A. Overview

In addition to analyzing the BART units at plants that exceed the 750 MW cutoff,

there are a number of other units that, based on the BART time frame alone, could

potentially be subject to the BART requirements. Table 6 summarizes the number of units,

nameplate capacity and SO2 emissions associated with all the coal units previously

identified as non-BART (i.e. for which the sum of the units' nameplate capacity is less than

750 MW) that either:

! Fall within the BART time frame (online 1962-1977), or 

! Potentially fall within the BART time frame (online 1978-1985). 

Note that the data in Tables 6 and 7 only include Acid Rain Program units. While

the Pechan file includes other coal-fired units, that file does not include online dates. 

Therefore, additional, non-Acid Rain Program units are not included in the data

summarized in Tables 6 and 7. The information in Table 6 is divided into AR units that

have existing FGD, projected FGD, or no FGD. 
Memorandum

March 24, 2003

Page 13

Table 6

Potential BART Units (AR file)

Sum of Units < 750 MW and Online 1962 - 1985

Online Data Element Existing

FGD

Projected

FGD

No FGD Total

1962-

1977

Number of Units 35 13 146 194

Nameplate

Capacity (MW)

8,689 3,993 31,642 44,324

2010 SO2(tons) 113,529 150,246 1,193,328 1,457,103

1978-

1985

Number of Units 51 3 44 98

Nameplate

Capacity (MW)

19,119 1,376 19,336 39,831

2010 SO2(tons) 326,739 30,659 568,746 926,144

B. Potential Control Impacts

In order to evaluate the controls that may be applied to the potential BART units

that do not have existing or projected scrubbers, we compiled summary data on the number

of units, nameplate capacity, and 2010 SO2 emissions for both the group of units with

online dates between 1962 and 1977 and the group with online dates between 1978 and

1985. Table 7 summarizes these results. The table presents the data in terms of the size

groupings that correspond with the control assumptions used in the cost spreadsheet as

described above. The table identifies the assumed type of scrubber and control efficiency, 

based on the size of the unit and an assumed sulfur content of the coal.
Memorandum

March 24, 2003

Page 14

Table 7

Potential BART Units at Plants < 750 MW 

with No FGD (AR file) and Online 1962 to 1985 

Online Data

Element

Size of Units (MW)

< 100 > 100 

< 550 

> 550 

< 1,000 

> 1,000 

1962-

1977

Number of

Units

44 90 12 0

Nameplate

Capacity

(MW)

2,923 21,644 7,075 0

2010 SO2

(tons)

85,644 822,195 285,489 0

Type of

FGD

No FGD MEL LSFO* LSFO

Control

Efficiency

0 % 95 % 95 % 95 %

1978-

1985

Number of

Units

6 16 21 1

Nameplate

Capacity

(MW)

928 5,221 11,887 1,300

2010 SO2

(tons)

32,481 156,880 350,499 28,885

Type of

FGD

No FGD MEL LSFO* LSFO

Control

Efficiency

0 % 95 % 95 % 95 %

*Note: LSD or LSFO was originally assumed for units greater than or equal to 550 but less than 1,000 in the cost

spreadsheet depending on the sulfur content. The cost calculations previously assumed that if the sulfur content is less

than or equal to 2%, then LSD would be applied, with LSFO applied for this group of units only if the sulfur content is

greater than 2%. A second cost analysis scenario, as described in the cost section above, assigns LSFO for all units

above 550 MW, and that assumption is used in this table as well. 

As summarized in Table 6, the projected 2010 SO2 emissions for the 1962 to 1977

group and the 1978 to 1985 group, were 1,193,328 tons and 568,745 tons, respectively. If

the assumed FGD types listed in Table 7 are applied, the revised projected 2010 SO2
Memorandum

March 24, 2003

Page 15

emissions would be 141,027 tons and 41,769 tons, respectively. If the original IPM Base

Case control assumptions are applied, it is likely that all the units between 550 and 1,000

MW would have an LSD scrubber applied with a 90 percent control efficiency assumption. 

In this case, the reductions would result in projected 2010 SO2 emissions of 155,302 and

59,294 tons, respectively, for the 1962-1977 and 1978-1985 units. 

C. Non-Acid Rain Units

In addition to the non-BART Acid Rain units, there are also 245 non-Acid Rain

units with a total nameplate capacity of 8,697 MW that are included in the Pechan file but

not in the AR file. Table 8 below summarizes the total nameplate capacity of these units

and the number of units with existing or projected FGD. There are 87 units with a

nameplate capacity greater than 25 MW, and 20 of these have existing or projected FGD.

All 87 units are listed as coal fired units in the Pechan file. However, monitoring plan data

and/or EIA data indicate that for the 67 units greater than 25 MW with no existing or

projected FGD, four are natural gas-fired, one is wood-fired, and one uses petroleum coke

as its primary fuel. 

We were able to obtain online dates from monitoring plan data, EIA data, or the

SIP EGU inventory, for 62 of the 67 units with a nameplate capacity greater than 25 MW. 

Only two of these units were found to have an online date that falls between the 1962 and

1985 time frame. However, one of these units (Orrville, OH, ORIS 2935, Unit 13, online

1971), has projected 2010 SO2 emissions of zero. The other unit (Long Beach Generation

LLC, CA, ORIS 341, unit ST9, online 1977) has a primary fuel of natural gas, according to

EIA data. Therefore, the impact of adding these units into to the analysis of BART

affected sources appears to be relatively small. The remaining five units for which online

dates could not be confirmed, may fall within the time frame but would have a minimal

impact. Based on monitoring plan data, one of these units is deferred. The nameplate

capacity and projected 2010 SO2 emissions for the other four units total only 119 MW and

3,078 tons, respectively. 

Table 8

Potential BART Units in Pechan File

Rated

Nameplate

Capacity

(MW)

Number of

Units

Total

Nameplate

Capacity

(MW)

Number of

Units with

Existing FGD

Number of

Units with

Projected

FGD

> 25 MW 87 6,743 19 1

< 25 MW 158 1,954 1 0

Total 245 8,697 20 1

 
Memorandum

March 24, 2003

Page 16

There are five units that are listed in the Pechan file but do not have any associated

nameplate capacity or 2010 SO2 data, and therefore, were not included in the calculations

for these data or for the overall calculations for the nameplate capacity and 2010 projected

SO2 data in the FGD scorecard charts. These units are Savannah River Mill (GA), ORIS

10361, units GEN3 and GEN4; Silver Bay Power Company (MN), ORIS 10849, units

GEN1 and GEN2; and Piqua (OH), ORIS 2937, unit 10. 

VIII. Summary of Key Findings for All Coal Units

We analyzed a total of 1,298 coal units in terms of BART applicability and the

existence of FGD. Table 9 below lists the number of units in each file in terms of these

criteria. These totals do not include the five units for which no information was listed in

the Pechan file or the 29 units that were included in the AR file but not in the Pechan file as

described in Section V.B. The SO2 control data were obtained from the Pechan file, while

the nameplate capacity data were obtained from this file only for the non-AR units. The

data source for the nameplate capacity is included to show, for each category, the number

of units for which data were obtained from the AR or Pechan files.

Table 9

Summary of BART and FGD Status for Coal Units

Existence

of FGD

BART Units (>750 MW) Non-BART Units

Number

of Units

Data Source for

Nameplate Capacity

Number of

Units

Data Source for

Nameplate Capacity

No FGD 138 AR file 865 AR file (641 units)

Pechan file (224 units)

Existing

FGD

77 AR file 168 AR file (149 units)

Pechan file (19 units)

Projected

FGD

26 AR file 24 AR file (23 units)

Pechan file (1 unit)

All Units 241 AR file 1,057 AR file (812 units)

Pechan file (245 units)

IX. Next Steps

A. Determine Potential BART Applicability of Units at Plants < 750 MW

We could determine the potential applicability under the BART rule for the AR

units that are less than 750 MW, have an online date between 1978 and 1985, do not have

existing or projected scrubbers, and have a rated nameplate capacity greater than 100 MW. 
Memorandum

March 24, 2003

Page 17

This analysis is relevant because these units could be affected under the BART rule and

required to install controls. Table 10 summarizes these 38 units, which could have been

issued a construction permit prior to the August 7, 1977 cutoff. As with the AR units

greater than 750 MW that have an online date between 1978 and 1985, the appropriate

state agency contact could provide this information. 

Table 10

Non-BART Units Potentially Affected by Proposed BART Rule

Online 1978 to 1985 

ST Plant Name

Plant

ID

Unit

ID

Total SO2

Emission

(2010

Tons/yr) 

Nameplate

Capacity

(MW) Online

AR Flint Creek 6138 1 18,109 558 1978

AR Independence 6641 2 24,008 850 1984

CO Pawnee 6248 1 13,097 500 1981

CO Ray D Nixon 8219 1 5,425 207 1980

DE Indian River 594 4 15,761 442 1980

FL Deerhaven 663 B2 8,279 251 1981

GA McIntosh 6124 1 9,444 178 1979

IA Council Bluffs 1082 3 16,884 726 1978

IA George Neal South 7343 4 23,400 640 1979

IA Louisa 6664 101 18,085 738 1983

IA Ottumwa 6254 1 20,240 726 1981

IL Havana 891 9 14,145 488 1978

IN Rockport 6166 MB1 28,885 1,300 1984

KS Nearman Creek 6064 N1 5,789 261 1981

KY Ghent 1356 3 17,889 557 1981

KY Ghent 1356 4 16,593 556 1984

LA Big Cajun 2 6055 2B3 15,387 560 1984

(cont.)
Memorandum

March 24, 2003

Page 18

Table 10

Non-BART Units Potentially Affected by Proposed BART Rule

Online 1978 to 1985 (cont.)

ST Plant Name

Plant

ID

Unit

ID

Total SO2

Emission

(2010

Tons/yr) 

Nameplate

Capacity

(MW) Online

LA Rodemacher 6390 2 19,410 558 1982

MO Iatan 6065 1 15,261 726 1980

NE Platte 59 1 2,846 616 1979

NE Whelan Energy 60 1 2,105 110 1982

NV North Valmy 8224 1 6,534 254 1981

OH Killen Station 6031 2 22,944 666 1982

OK GRDA 165 1 14,247 490 1982

OK Hugo 6772 1 11,425 400 1982

OK Muskogee 2952 6 14,124 572 1984

OR Boardman 6106 1SG 15,187 561 1980

TX Coleto Creek 6178 1 16,489 600 1980

TX Harrington Station 6193 062B 8,352 360 1978

TX Harrington Station 6193 063B 8,328 360 1980

TX Tolk Station 6194 171B 12,330 568 1982

TX Tolk Station 6194 172B 12,214 568 1985

TX W A Parish 3470 WAP7 15,452 615 1980

WI Edgewater 4050 5 11,078 380 1985

WI J P Madgett 4271 B1 10,201 387 1979

WI Pleasant Prairie 6170 1 16,825 617 1980

WI Pleasant Prairie 6170 2 16,825 617 1985

WI Weston 4078 3 12,670 350 1981

B. Additional Analyses for the Units at Plants < 750 MW

For the units identified in Section IX.A. that are within the BART time period, we

could conduct a separate analysis to evaluate the cost of compliance for these units. In

addition, we also could calculate the distance to the nearest Class I area for each of these

units.
Memorandum

March 24, 2003

Page 19

C. Determine which non-BART Units Share a Generator

This determination would not affect the BART-applicability status of these units

but may help present a more accurate picture of the total nameplate capacity represented

by this subset of units. Note that the total nameplate capacity for the BART-affected units

in the AR file were approximately 10 percent higher than the corresponding nameplate

capacity data in the Pechan file.

D. Perform Additional Cost Analyses

Performing additional cost analyses may be helpful and there are several additional

control scenarios we could test in this context. The most basic approach would be to

optimize the scrubber type on a unit basis by modeling each one and assigning the least

expensive type to each unit. However, in some cases, this approach would result in the

application of FGD types that vary between the units located at the plant. Another

approach would be to apply one large scrubber as the control strategy for all of the BART

units at a plant. Of the 135 BART units, 125 are at plants with multiple BART units. 

Modeling this scenario would be more time consuming, and would require additional

calculations to normalize unit capacity factors, heat rate, and fuel sulfur content on a plant

basis before performing the cost calculations. If this approach is used in a cost analysis, the

basis upon which IPM estimates cost (i.e. on a unit or plant basis) should be verified to

ensure consistency with other cost analyses. It may be helpful to test this approach on one

or two plants prior to its application to all BART units.

Enclosures

DLS/eab
June 15, 2005

TECHNICAL SUPPORT DOCUMENT

METHODOLOGY FOR DEVELOPING BART NOx PRESUMPTIVE LIMITS

Attachment B

Memorandum: Follow-Up on Units Potentially Affected by BART
PERRIN QUARLES ASSOCIATES, INC.

675 PETER JEFFERSON PARKWAY, SUITE 200

CHARLOTTESVILLE, VIRGINIA 22911

VOICE: (434) 979-3700  FAX: (434) 296-2860

EMAIL: pqa@pqa.com

MEMORANDUM

TO: Roman Kramarchuk

FROM: Doran Stegura

RE: Follow-Up on Units Potentially Affected by BART

DATE: July 19, 2004

On March 24, 2003, PQA delivered an analysis of sources that may be subject to

controls under EPA’s Proposed Guidelines for Best Available Retrofit Technology

(BART) Determinations. This analysis provided a list of BART units, additional

information on the location and control technologies for each unit, and control cost

information. The March 2003 analysis only focused on the units for which construction

was started by August 7, 1977 and that were not in operation prior to August 7, 1962. 

Based on EPA guidance, the original analysis also assumed that BART-eligible units are

only those that are located at a plant where the total capacity of all units within the BART

timeframe exceeds 750 MW. 

This follow-up analysis provided additional information on units that are below the

750 MW threshold, but that are potentially within the specified BART timeframe. The

approach and assumptions used to identify whether units below the 750 MW threshold

could potentially be BART-eligible are consistent with the March 2003 analysis. The units

that required additional follow-up research in this regard are those with an online date on

or after 1979 since the BART rule could apply if construction on these units commenced

prior to August 7, 1977. It was assumed that units with a 1977 or 1978 online date started

construction prior to the 1977 cutoff and thus, are considered to be within the BART

timeframe. Hunter, unit 1 (UT) is the only exception since it has a PSD permit with an

online date of 1978. For the units in question, PQA reviewed the RACT/BACT/LAER

Clearinghouse and other internet search information and contacted the appropriate State
Memorandum

July 19, 2004

Page 2

environmental agencies to verify when the construction permit was issued. Note that the

date the construction permit was issued is used as an indication of when construction began

for purposes of this analysis. However, actual construction on these units may have started

well after the date the permit was issued. 

In evaluating the list of units below the 750 MW threshold and with an online date

in 1979 or later, PQA assumed that: 1) units subject to Part 60, Subpart D cannot be

excluded because this NSPS subpart applies to sources that have started construction after

August 17, 1971; 2) units subject to NSPS Subpart Da requirements are outside the

applicable BART time period since these requirements apply to sources that started

construction after September 18, 1978; and 3) units that received a PSD permit (with a

BACT requirement) are outside the BART time period. If a PSD permit was issued, PQA

researched the issue date in order to confirm that the unit is outside the BART time period.

Using the above assumptions, a list of 61 units was compiled that required followup with the State environmental agency to confirm whether construction began prior to

August 7, 1977. Of these 61 units, 43 are located in States covered under the Clean Air

Interstate Rule (CAIR) and 18 are located in States not covered under CAIR. Per EPA

guidance, initial priority was given to those units not located in a State affected by CAIR. 

Follow-up with the State environmental agencies revealed that of the 61 units that required

follow-up, 24 units are within the BART time period, 24 units are outside the BART time

period, and 13 units require further follow-up since the State environmental agency was

not able to provide the information needed to determine whether the unit started

construction prior to August 7, 1977. 

Table 1 summarizes the 61 units analyzed by PQA. The table provides an

indication of whether the unit is located in a state affected by CAIR, whether the unit has

been identified as within the BART timeframe, and whether additional follow-up with the

State agency for information on construction permit dates is required to determine BART

eligibility.

Table 1: Potential BART Units Identified for Follow-Up Analysis

State Plant Name ORIS

Code

Unit ID Online NSPS CAIR In BART

timeframe?

Follow-up

Needed

Nameplate

(MW)

AL Charles R Lowman 56 2 1979 D X X 233

AL Charles R Lowman 56 3 1980 D X X 233

AZ Apache Station 160 2 1979 D X 194.7

AZ Apache Station 160 3 1979 D X 194.7

AZ Springerville 8223 1 1985 D 397

AZ Springerville 8223 2 1990 D 397

CO Pawnee 6248 1 1981 D X 500

CO Ray D Nixon 8219 1 1980 D X 207

DE Indian River 594 4 1980 D X X 442.4

FL C D McIntosh 676 3 1982 D X 334

(cont.)
Memorandum

July 19, 2004

Page 3

Table 1: Potential BART Units Identified for Follow-Up Analysis (cont.)

State Plant Name ORIS

Code

Unit ID Online NSPS CAIR In BART

timeframe?

Follow-up

Needed

Nameplate

(MW)

FL Deerhaven 663 B2 1981 D X 250.75

GA McIntosh (6124) 6124 1 1979 PRE X X 177.66

IA Ames 1122 8 1982 D X 65

IA George Neal South 7343 4 1979 D X X 639.9

IA Louisa 6664 101 1983 D X 738.09

IA Ottumwa 6254 1 1981 D X X 726

IN A B Brown Generating Station 6137 1 1979 D X X 265.23

KS Nearman Creek 6064 N1 1981 D X X 261

KY East Bend 6018 2 1981 D X X 669.28

KY R D Green 6639 G1 1979 D X X 263.7

KY R D Green 6639 G2 1981 D X X 263.7

KY Trimble County 6071 1 1990 D X X 566.1

LA Dolet Hills 51 1 1986 D X 720.75

LA R S Nelson 1393 6 1982 D X X 614.6

LA Rodemacher 6190 2 1982 D X X 558

MD Brandon Shores 602 1 1984 D X X 685.08

MD Brandon Shores 602 2 1991 D X X 685.08

MI Presque Isle 1769 9 1979 D X X 90

MI Wyandotte 1866 7 1982 D X 73

MN Clay Boswell 1893 4 1980 D X X 558

MO Iatan 6065 1 1980 D X X 725.85

MO Sikeston 6768 1 1981 D X X 261

NC Elizabethtown Power 10380 UNIT1 1985 D X 35

NC Elizabethtown Power 10380 UNIT2 1985 D X 35

NC Lumberton Power 10382 UNIT1 1985 D X 35

NC Lumberton Power 10382 UNIT2 1985 D X 35

NC Mayo 6250 1A 1983 D X 735.84

NC Mayo 6250 1B 1983 D X 735.84

ND Antelope Valley 6469 B1 1984 D 435

ND Antelope Valley 6469 B2 1986 D 435

ND Coyote 8222 B1 1981 D 450

NE Gerald Whelan Energy Center 60 1 1981 D 76.3

NE Nebraska City 6096 1 1979 D X 615.87

NE Platte 59 1 1982 D 109.8

NV North Valmy 8224 1 1981 D X 254.26

OH Killen Station 6031 2 1982 D X X 666.45

OK Grand River Dam Authority 165 1 1982 D 490

OK Hugo 6772 1 1982 D 400

OR Boardman 6106 1SG 1980 D X 560.5

TX Coleto Creek 6178 1 1980 D X X 600.39

TX Gibbons Creek 6136 1 1983 D X 443.97

TX Pirkey 7902 1 1985 D X 720.75

TX San Miguel 6183 SM-1 1982 D X 410

TX Sandow 6648 4 1981 D X X 590.64

UT Hunter (Emery) 6165 1 1978 D X 446.4

UT Hunter (Emery) 6165 2 1980 D X 446.4

WI Edgewater (4050) 4050 5 1985 D X X 380

WI J P Madgett 4271 B1 1979 D X X 387

WI Pleasant Prairie 6170 1 1980 D X X 616.59

WI Pleasant Prairie 6170 2 1985 D X X 616.59

WI Weston 4078 3 1981 D X X 350.46

DLS/jlj