# 1 MEMORANDUM

DATE: August 2013

TO: Docket EPA-HQ-OAR-2010-0929

FROM: Lisa Grogan-McCulloch, U.S. EPA

SUBJECT: Evaluation of Alternative Calculation Methods

1.0 Introduction and Purpose of Analysis

In the August 25, 2011 final rule deferring re porting to March 31, 2015 of certain inputs

to emission equations under 40 CFR part 98 ( 76 FR 53057), the EPA expressed its intent to

further evaluate the inputs to emission equations. The EPA outlined a four-step process for this

evaluation in the final rule, and in a suppor ting memorandum entitled “Process for Evaluating

and Potentially Amending Part 98 Inputs to Emission Equations” (docket EPA-HQ-OAR-2010-

0929).

The purpose of this memorandum is to describe the review undertaken for the third step

of the evaluation process: the EPA’s evalua tion of alternative cal culation methods. The

evaluation of alternativ e calculation methods is divided in to two reviews: (1) review of

alternative greenhouse gas (GHG) emission equations , and (2) review of a pplication of direct

measurement using continuous emissions m onitoring systems (CEMS). The alternative

calculation evaluation was undertaken for 25 of the 28 subparts of the greenhouse gas reporting

program (GHGRP), for which repor ting of inputs to emission equations has been deferred to

March 31, 2015 (hereafter referred to as “inputs to equations” data elements). The review was

not undertaken for subparts W and II because the EPA’s evaluation of these inputs under Step 2

did not identify the need to proceed to Step 3. a 

# Please see memorandum “Evaluation of

Competitive Harm from Disclosure of “Inputs to Equations” Data Elements Deferred to March

31, 2015” for the results of Step 2 of the evaluation.

Section 2.0 of this memorandum presents the procedures used to collect and review

alternative calculation equations , and the results of the review. Section 3.0 presents the

procedures used to collect information on and ev aluate application of direct measurement of

emissions using CEMS, and summarizes the re sults of the evaluati on. Section 4 provides a

summary of the evaluation. Appendix A presents detailed evaluations of all the alternative

calculation equations reviewed fo r each subpart. Appendix B presen ts a detailed characterization

of facilities and processes using CEMS for each of the subparts. Appendix C provides detailed

cost estimates of requiring CO 2 

# CEMS.

a 

# The review was not conducted for “inputs to equations” in subpart I because reporting of the “inputs to equations”

data elements for that subpart was addressed in a separate proposed action [see 77 FR 63538]. Additionally, the

evaluation of the subpart C “inputs to equations” in this memorandum encompasses the one subpart A “input to

equation” data element. As a result, the one subpart A “inpu t to equation” data element is not listed explicitly in this

memorandum.

# 2 2.0 Alternative Calculation Equations

Section 2.0 of this memorandum evaluate s alternative equations to calculate GHG

emissions. Section 2.1 discusses the procedures used to identify alternative calculation equations,

section 2.2 discusses the data s ources reviewed to obt ain the alternative ca lculation equations,

and section 2.3 summarizes th e results of the review.

2.1 Procedures for Identifying and Review ing Alternative Calculation Equations

Alternative calculation equations were identif ied based on three sources of information:

(1) previous calculation equations that were evaluated during the development of the GHGRP,

(2) calculations used in non-EPA GHG repor ting programs since the GHGRP was developed,

and (3) methods suggested by public commenters in response to the Call for Information notice

[75 FR 81338]. Each alternative ca lculation was evaluated to determ ine if it was the same as the

method chosen in the GHGRP. For calculations di fferent than what is required in the GHGRP,

the alternative calculation equations were evalua ted to determine whether equation inputs are the

same as the “inputs to equations” data elements, and therefore, would not resolve the disclosure

concerns identified in Step 2 of the evaluation. A dditionally, the equations that are different were

also evaluated as to whether they would decr ease accuracy or increase uncertainty in the

calculated emissions based on information pr ovided in the sources reviewed. For those

calculation equations that were id entified as using inputs different than the “inputs to equations”

data elements, and also had similar or lower uncertainty and similar or higher accuracy in

emissions estimation than the current method, costs were estimated if suffi cient cost information

was available. The cost of the alternativ e was then compared to the current method.

2.2 Data Sources Reviewed

As discussed in section 2.1, three sources of information were evaluated. Calculation

equations that the EPA had previously consider ed but not included in the final rule were

identified in the techni cal support documents (TSDs) 1-25 

# for each of the subparts and the

preambles to the proposed and final GHGRP. The original sources of the calculation methods

were then reviewed to dete rmine if the calcula tion methods had been updated since the

development of the GHGRP and to obtain more detailed information. The original sources

consisted of the following: 26-42



#  Annual Inventory of U.S. GHG Emissions and Sinks (U.S. Inv)

 Climate Leaders protocols (CL)

 U.S. Department of Energy ( DOE) 1605(b) reporting program

 The Climate Registry (TCR)

 State programs (California Climate Action Re gistry (CCAR), California Air Resources

Board (CARB) cap and trade program, New Mexico)

 Regional Programs (Regional Greenhouse Gas Initiative [RGGI])

 Western Climate Initiative (WCI)

 2006 Intergovernmental Panel on Climate Change (IPCC) Guidelines

 European Union Emissions Trading System (EU ETS)

# 3  Country-specific GHG reporting programs (Australia National Greenhouse Gas

Reporting Program (ANGGRP), Canada)

 World Resources Institute/World Busine ss Council for Sustainable Development

(WRI/WBCSD) protocols

 American Petroleum Institute (API) protocols

 American Iron and Steel Institute

 European Bank For Reconstruction and Development

Methods used in newer non-EPA GHG progr ams since the GHGRP was developed were

evaluated. These include: 43-44



#  U.N. Framework on Climate Change - Clean Development Mechanism (CDM)

 Australian Emissions Trading Scheme

Lastly, the EPA’s Call for Information no tice solicited input from commenters on

alternative calculation methods. Commenters s uggested alternative cal culation methods for 5

subparts: K, P, Q, R, and X. 45-48



# 2.3 Results of Evaluation

Table 2-1 summarizes the results of evalua ting alternative calculation equations. The

table indicates that for all of the subparts ex cept subparts X and Y, the alternative calculation

equations either used many of the same inputs to the calculation equations as the ”inputs to

equations” data elements, used new inputs that ar e the same type of reporting elements that the

EPA determined have disclosure concerns 49 

# , mandated process configurations (which is not the

intent of the GHGRP), or increased uncertainty or decreased accuracy in emission estimates.

Because of this result, no further evaluation of costs was undertaken for these alternative

calculations. For alternatives that were identified as viable in S ubparts X and Y, further analysis

indicated they resulted in a high cost to implem ent. Appendix A contains detailed evaluations for

each subpart and for each alternat ive calculation method identified.

Table 2-1. Summary of Evaluation of Alternative Calculation Equations

Subpart

of Part

98 Viable

Alternative

Identified

(Y/N) 

# Evaluation of Alternative Calculation Equations a



# Uses Same

“Inputs to

Equations

” Data

Elements b 

# Uses Same

Type of

Inputs

that do not

Alleviate

Disclosure

Concerns c 

# Mandates

Process

Design d 

# Increased

Uncertainty/

Decreased

Accuracy High Cost

to

Implement e



# C N √ NA

E N √ √ NA

F N √ √ NA

G N √ √ √ NA

H N √ √ √ NA

K N √ √ NA

# 4 L N √ √ NA

N N √ √ NA

O N √ √ NA

P N √ √ NA

Q N √ √ NA

R N √ √ NA

S N √ √ √ NA

U N √ √ NA

V N √ √ NA

X N √ √ √ √

Y N √ √ √ √

Z N √ √ NA

AA N √ √ NA

BB N √ √ NA

CC N √ NA

EE N √ √ √ NA

GG N √ √ √ NA

TT N √ √ NA

NA = Not analyzed because other criteria disqualified alternative.

a 

# The table generally summarizes reasons why the alternative calculation methods were considered to not be viable

options. Appendix A contains detailed evaluations for each alternative calculation method reviewed for each

subpart.

b 

# The alternative calculations used many of the same inputs to the calculation equations as the “inputs to equations”

data elements (and therefore, provided no benefit in comparison to the current method).

c 

# The alternative calculations used new data elements that are the same type of reporting elements that the EPA

determined to have disclosure concerns (see the memorandum “Evaluation of Harm from Disclosure of ‘Inputs to

Equations’ Data Elements Deferred to March 31m 2015”).

d 

# The alternative calculations mandated process configur ations (which is not the intent of the GHGRP).

e 

# Costs were only analyzed for equations that did not have data elements for which disclosure concerns were

identified, had low uncertainty, and high accuracy



# .

3.0 Direct Emissions Monitoring Using Cont inuous Emissions Mo nitoring Systems

Section 3.0 of this memorandum evaluates the use of CEMS for each subpart instead of

calculation equations for GHG reporting. For the ev aluation of CEMs, we initially applied the

same criteria that were used for the Alternative Calculati on Equations. Because CEMS are

directly measuring emissions, no equation inputs ar e used. As a result, the use of CEMS would

alleviate the disclosure concerns identified in Step 2 of the ev aluation. In addition, use of the

CEMS does not result in increase d uncertainty or decreased accuracy. However, CEMS are

generally higher cost than the other methodologies in the GHGRP, and the majority of reporters

that reported to the GHGRP in 2011 did not use CEMS. In addition, they cannot be used for

fugitive emission sources that ar e not routed through a stack. Th is review characterizes the

facilities (or process units in a facility) that currently use CO 2 

# CEMS (or N 2 

# O or methane CEMS

if applicable), the facili ties that use another form of CEMS that may be upgraded for use in the

GHGRP, and the cost impacts of applying the u pgrades. Section 3.1 describes the evaluation

performed, and section 3.2 summarizes the results of the review.

# 5 3.1 Description of Evaluation Performed

The GHGRP requires the use of a CO 2 

# CEMS only if a facility already has CEMS for

another regulation and meets cert ain additional criteria [i.e., the six conditions specified in

subpart C 98.33(b)(4)(ii)]. Such facilities would not need to build a structure or install a

sampling system in order to measure CO 2 

# emissions using a CEMS. Most of the subparts with

“inputs to equations” data elements allo w CEMS as an option to determine CO 2 

# emissions (some

also allow N 2 

# O with approval).

Characterization of Facilities and Process Units

The first step in the evaluation of applyi ng GHG CEMS for each subpart was to develop

an up-to-date characterization of the facilities and pro cess units subject to each subpart and the

number that use CEMS. The data reported to the EPA through a nnual report submissions in the

GHGRP 50 

# provides the most up-to-date information on f acility counts, as well as actual usage of

GHG CEMS. Many facilities also use non-GHG CEMS (that can be converted to GHG CEMS),

which are not accounted for in the GHGRP. Theref ore, for this evaluation, we also used

information in the GHGRP regulatory impacts analysis (RIA) 51 

# , the GHGRP background

technical support documents (TSD), and inform ation in other EPA databases (particularly

databases used in the development of air rule s and regulations, such as new source performance

standards (NSPS) or national emission standard s for hazardous air pollu tants (NESHAP)), to

obtain information on facilities a nd process units with non-GHG CEMS.

Estimating Current and Potential CEMS usage

Where information was available in the GHGRP indicating reporters using CEMS for

CO 2 

# , CH 4 

# , and N 2 

# O in facilities, those data were used to identify the actual number of facilities

or process units th at currently use CO 2 

# CEMS (or N 2 

# O or methane, if applicable).

NSPS and NESHAP rule requirements that a pply to GHGRP reporters may also require

CEMS usage not related to GHGs. These regulations do not generally require CO 2 

# CEMS

because they regulate criteria pollutants and air t oxics. However, the CEMS installed to meet the

rules may be modified to be used for GHG re porting, which would lower the overall cost of

installing the CEMS. Table 3-1 summarizes th e NSPS and NESHAP app licable to sources

subject to each subpart with “inputs to equatio ns” data elements, and identifies the NSPS and

NESHAP that have CEMS as an option or re quirement. The CEMS standards in the NESHAPs

and NSPS were used to develop a count of potenti al facilities or proces s units that may have

equipment installed that could be modified for use in the GHGRP. Appendix B contains detailed

summaries of applicability of the air rules for sources or processes in each subpart.

# 6 Table 3-1. NSPS and NESHAP Applicable to GHGRP Reporters with “Inputs to

Equations” Data Elements

Subpart

of Part

98 NESHAP/NSPS Subparts Reviewed a 

# Are CEMS an option or requirement

under the NSPS and/or NESHAP and, if

so, can they be used for GHGRP?

C NSPS: Subpart Db Yes

NESHAP: Subpart DDDDD Yes

NESHAP: Subparts CCC and DDD Yes

E NSPS: Subpart NNN Yes; however CEMS is not required; it is

one of several compliance options NSPS: Subpart RRR

F NSPS: Subpart S No

NESHAP: Subpart LL No

G None Not applicable

H NSPS: Subpart LL Yes

NSPS: Subpart F Yes

NESHAP: Subpart EEE Yes

K NSPS: Subpart Z No

NESHAP: Subpart XXX No

NESHAP: Subpart YYYYYY No

L NESHAP: Subpart FFFF Yes

N NSPS: Subpart CC No

NSPS: Subpart PPP No

NSPS: Subpart NNN No

NESHAP: Subpart HHHH No

NESHAP: Subpart SSSSSS No

NESHAP: Subpart N (Part 61) No

O NESHAP: Subpart FFFF Yes; however CEMS is not required; it is

one of several compliance options

P NESHAP: Subpart CC No

Q NESHAP: Subpart RRRRR No

NESHAP: Subpart FFFFF No

NESHAP: Subpart L No

NESHAP: Subpart CCCCC No

NSPS: Subpart AA and AAa No

NESHAP: Subpart YYYYY No

R NSPS: Subpart L No

NSPS: Subpart R Yes; however CE MS is not required for new

sources only

NESHAP: Subpart X No

S NSPS: Subpart HH No

NESHAP: Subpart AAAAA No

U None Not applicable

V NSPS: Subpart G Yes

# 7 Subpart

of Part

98 NESHAP/NSPS Subparts Reviewed a 

# Are CEMS an option or requirement

under the NSPS and/or NESHAP and, if

so, can they be used for GHGRP?

X NSPS: Subpart III Yes; however CEMS is not required; it is

one of several compliance options NSPS: Subpart NNN

NSPS: Subpart RRR

NESHAP: Subpart F

NESHAP: Subpart G

NESHAP: Subpart YY No

Y NSPS: Subpart J Yes

NESHAP: Subpart CC No

NESHAP: Subpart UUU Yes

Z NSPS: Subpart T No

NESHAP: Subpart AA No

AA NSPS: Subpart BB Yes for Kraf t and Semichemical mills; No

for others.

NESHAP: Subpart S No

NESHAP: Subpart MM No

BB None Not applicable

CC NSPS: Subpart OOO No

NSPS: Subpart UUU No

EE NSPS: Subpart LL No

GG NSPS: Subpart Q No

NSPS: Subpart LL No

NESHAP: Subpart GGGGGG No

NESHAP: Subpart TTTTTT No

TT None Not applicable

a 

# NSPS subparts are in 40 CFR part 60; NESHAP subparts are in 40 CFR part 63.

Estimating Cost Impacts

Depending on the type of monitoring require ments in the NSPS or NESHAP regulations,

the modifications needed to in stall a CO2 CEMS for the purpose of monitoring for the GHGRP

may be minimal, such as adding a CO 2 

# analyzer only, or more co stly, such as adding a CO 2 

# analyzer, flow meter, and infrastructure. In order to accurately assess the cost impacts of

requiring CEMS for the GHGRP, the potential number of facilities that, due to the requirements

in NSPS and NESHAP, would be able to install a CO 2 

# CEMS at a reduced cost was evaluated.

Based on the requirements in the rules, the GHGRP subparts, and the proce ss/facility count and

CEMS information (discussed earlier), the following CEMS usages were identified:

 Source has CO 2 

# CEMS

 Source has non-CO 2 

# GHG CEMS (such as N 2 

# O CEMS) or has non-GHG CEMS (such as

NO X 

# or CO monitors)

 Source has no CEMS

# 8 After the CEMS characteri zation was completed, the co st impacts of requiring CO 2 

# CEMS were estimated for each subpart based on the number of facilities (or sources) or units (or

processes) that would need to upgrade existing monitoring equipment to meet the requirements

of the GHGRP. Cost information in the RIA wa s reviewed and separated into the components

necessary for CO 2 

# CEMS. 51 

# Based on the type of CEMS used, five CEMS usage scenarios were

developed. The costs associated with addi ng equipment to meet the GHGRP monitoring

requirements for sources/units in each of the fi ve CEMS usage scenarios were developed from

the CEMS component costs. Table 3-2 summari zes the costs and equipment necessary for each

scenario. For Scenarios 2 and 3, costs were assign ed considering specific rule requirements that

are presented in Appendix B and information in the RIA.

Table 3-2. Summary of Costs for CO 2 

# CEMS Modifications

Scenario

# Scenario Total annual

cost/application

1 Source has no CEMS -- Add CO 2 

# analyzer, flow meter, and

infrastructure $ 70,265

2 Source has CEMS for other pollutants -- Add CO 2 

# analyzer

and flow meter $ 56,040

3 Source has CEMS for other pollutants -- Add CO 2 

# analyzer

only $ 20,593



# 4 Source has CEMS for other pollutants -- Add flow monitor

only $ 24,511

5 Source has CO 2 

# CEMS No Cost



# 3.2 Results of Evaluation

Table 3-3 summarizes the results of the characterization analysis. The table shows for

each subpart whether information was collected on a facility, unit or process basis. The table

summarizes the actual number of facilities subject to the subpart that use CO 2 

# CEMs, non-CO 2 

# GHG CEMS, or non-GHG CEMS. The ta ble also shows the potential number of sources that

may have the same monitoring equipment base d on a review of requirements in NSPS or

NESHAP, and assumptions regarding which faci lities would use CEMS. The potential number

includes both the actual number and additional units/facilities th at result from reviewing the

NSPS or NESHAP. In some cases, a potential estimate could not be made based on the

evaluation of the air rules, but an actual number was identified based on data sources reviewed.

Appendix B contains detailed summaries of th e CEMS characterization analysis for each

subpart.

Table 3-3. Summary of CEMS Characteriza tion for Each Subpart with “Inputs to

Equations” Data Elements

# 9 Subpart Basis Number

Subject to

Subpart a 

# Reporting CO 2



# CEMS in GHGRP Reporting non

‐

CO 2 

# GHG CEMS in

GHGRP

l Reporting non

‐ GHG CEMS in

NSPS/NESHAP

Actual Potential

C Facilities 1,985 177 0 b 

# NA NA

Units 14,197 311 0 b 

# 1056 1151

E Facilities 3 0 l 

# 0 b 

# NA NA

F Facilities 10 0 l 

# 0 b 

# NA NA

G Facilities 22 0 l 

# 0 b 

# NA NA

H Facilities 96 82 0 b 

# 14 c 

# 14 c



# Units 140 112 0 b 

# 0 d 

# 28 e



# K Facilities 10 0 l 

# 0 b 

# NA NA

L Facilities 16 0 l 

# 1 NA NA

N Facilities 110 3 0 b 

# NA NA

Units NA 3 0 b 

# NA NA

O Facilities 5 0 l 

# 0 b 

# NA NA

P Facilities 103 3 0 b 

# NA NA

Units NA 3 0 b 

# NA NA

Q Facilities 128 11 0 b 

# NA NA

Units 165 14 0 b 

# NA NA

R Facilities 13 0 l 

# 0 b 

# NA NA

S Facilities 73 1 0 b 

# NA NA

U Facilities 18 0 l 

# 0 b 

# NA NA

V Facilities 36 0 l 

# 0 b 

# 20 g 

# NA

Units 65 0 l 

# 0 b 

# 36 g 

# NA

X Facilities 64 2 0 b 

# NA NA

Units NA 2 0 b 

# NA NA

Y

‐

Catalytic

Cracking

and Sulfur

Recovery 

# Facilities 145 21 0 b 

# NA 104 h



# Process

Units 317 26 0 b 

# NA 317 i



# Y

‐ Other

Process

Units j 

# Facilities 145 0 l 

# 0 b 

# 0 0

Process

Units 1,580 0 l 

# 0 b 

# 0 0

Z Facilities 13 0 l 

# 0 b 

# 7 k 

# 7 k



# AA Facilities 110 0 l 

# 0 b 

# 89 m 

# NA

Units 330 m 

# 0 l 

# 0 b 

# 266 m 

# NA

BB Facilities 1 0 l 

# 0 b 

# NA NA

CC Facilities 4 1 0 b 

# NA NA

Units NA 1 0 b 

# NA NA

EE Facilities 7 0 l 

# 0 b 

# NA NA

# 10 GG Facilities 6 0 l 

# 0 b 

# NA NA

TT Facilities 173 0 l 

# 0 b 

# NA NA

NA = No estimate available

a 

# Number of faciliti es that reported to the GHGRP in 2011.

b 

# No units or facilities are known to be using non-CO 2 

# GHG CEMS (e.g., for CH 4 

# or N 2 

# O).

c 

# Used 96 as the actual and high estimate of the number of ope rating plants, minus the 82 that reported to GHGRP in 2011 that

they are using CO 2 

# CEMS.

d 

# The count of units with non-GHG CEMS (102) in Table 4-3 of the RIA for the GHGRP is lower than the number that reported

to GHGRP in 2011 that they are using CO 2 

# CEMS (112). Therefore, we cannot assume that any additional facilities have nonGHG CEMS installed.

e 

# Based on the assumption that all kilns will have a non-GHG CEMS to comply with the NESHAP; used the estimated number of

units (140) in the “Summary of Environm ental and Cost Impacts for Final Portla nd Cement NESHAP and NSPS” (August 6,

2010), minus the 112 that reported to GHGRP in 2011 that they are using CO 2 

# CEMS.

g 

# Based on data reported as a part of the 1990-2006 Inventory of U.S. Greenhouse Gas Emissions and Sinks, which are shown in

the TSD to subpart V. A high estimate was not generated since th e inventory data were reported by the facility and presumed to

be the actual count of units with NO X 

# CEMS.

h 

# Count of facilities which have catalytic cracking and/or sulfur recovery processes. Some facilities have both.

i 

# Unit count assumes all catalytic cracking processes have catalyst regenerators (130 +187), and all will use CEMS to comply with

the NESHAP/NSPS.

j 

# Includes fluid coking, coke calc ining, catalytic reforming, fl ares, loading operations, and ot her process vents. Stationary

combustion units are covered under subpart C.

k 

# Counts are based on data reported in the NESHAP ICR responses.

l 

# No facilities reported to GHGRP in 2011 that th ey were using a CEMS to report GHG emissions.

m 

# The National Council for Air and Stream Improvement (NCASI) survey provided proc ess unit data and the 2009 RIA estimated

that units were subject to Tier 4 require ments. However, these count data and the count for facilities th at reported to GHGRP i n

2011 (110) could not be directly related. Therefore, ba sed on the data, unit and fa cility counts were estimated.



# Table 3-4 summarizes the estimate of capital and annual cost impacts for each subpart if

CO 2 

# CEMS are required for sources or process units subject to the GHGRP. The table does not

show the cost of applying N 2 

# O or CH 4 

# CEMS. The table presents th e cost to upgrade monitoring

equipment (existing equipment for actual sour ces and likely equipmen t for potential sources

based on the air rules) and the cost to add full CO 2 

# CEMS for facilities that are subject to the

GHGRP, but do not have CEMS. Table 3-4 su mmarizes costs based on actual counts of

units/facilities with CEMS, a nd potential counts of units/facilit ies with CEMS based on NSPS

and NESHAP rule requirements. Potential costs in corporate information from actual number of

units/facilities where information is known as well as the additional potential number of

units/facilities that may be using CEMS base d on NESHAP and NSPS rule requirements. See

Appendix B for detailed information for each s ubpart. Appendix C contains detailed cost

estimates for each subpart and each CEMS scenari o. Appendix C also contains cost estimates for

all three types of GHG CEMS (CO 2 

# , N 2 

# O, and CH 4 

# ).

Table 3-4. Summary of Cost Impacts From Requiring CEMS for GHGRP Subparts

Subpart of

Part 98 Capital Cost Estimate For Using

CEMS ($) Total Annual Cost Estimate for

Using CEMS ($/yr)

Actual a 

# Potential b 

# Actual a 

# Potential b



# C $1,680,248,013 $1,689,440,545 $960,678,190 $966,001,990



# E $

‐ $

‐ $

‐ $

‐



# F $1,229,981 $1,229,981 $702,650 $702,650



# G $2,705,958 $2,705,958 $1,545,830 $1,545,830

# 11 H $4,004,048 $560,101 $2,544,024 $576,604



# K $1,229,981 $1,229,981 $702,650 $702,650



# L $

‐ $

‐ $

‐ $

‐



# N $13,160,798 $13,160,798 $7,518,355 $7,518,355



# O $

‐ $

‐ $

‐ $

‐



# P $12,299,811 $12,299,811 $7,026,500 $7,026,500



# Q $18,572,715 $18,572,715 $10,610,015 $10,610,015



# R $1,598,975 $1,598,975 $913,445 $913,445



# S $8,855,864 $

‐ $5,059,080 $

‐



# U $ 2,213,966 $ 2,213,966 $ 1,264,770 $ 1,264,770



# V $

‐ $

‐ $

‐ $

‐



# X $7,625,883 $7,871,879 $4,356,430 $4,496,960



# Y $191,139,063 $175,521,765 $109,191,810 $101,365,847



# Z $878,014 $878,014 $565,741 $565,741



# AA $33,613,009 $33,613,009 $19,404,705 $19,404,705



# BB $122,998 $122,998 $70,265 $70,265



# CC $368,994 $368,994 $210,795 $210,795



# EE $860,987 $860,987 $491,855 $491,855



# GG $737,989 $737,989 $421,590 $421,590



# TT $

‐ $

‐ $

‐ $

‐



# Total $1,981,467,047 $1,962,044,020 $1,133,278,700 $1,123,378,467

a 

# Costs are based on the actual number of units/facilities for which information was available indicating current use

of CEMS under the GHGRP. See Appendix B for detailed information for each subpart.

b 

# Costs are based on potential number of units/facilities that may be using CEMS based on NESHAP and NSPS rule

requirements. Costs include actual number of units/fac ilities based on reporting to the GHGRP as well as the

additional potential number of units/facilities that may be using CEMS based on NESHAP and NSPS rule

requirements. See Appendix B for de tailed information for each subpart.



# 4.0 Summary

Based on the results of this evaluation, the EPA pr oceeded to Step 4 of th e evaluation for all of

the 25 subparts evaluated in this memorandum.

# 12 5.0 References

1. U.S. EPA. "Technical Support Document fo r Stationary Fuel Combustion Emissions:

Proposed Rule for Mandatory Reporting of Greenhouse Gases." Office of Air and

Radiation. January 30, 2009. Available:

http://www.epa.gov/ghgreporting/documents/ pdf/archived/tsd/TS D%20Stationary%20Co

mbustion%202-02-09.pdf.

2. U.S. EPA. "Technical Support Document for the Adipic Acid Production Sector:

Proposed Rule for Mandatory Reporting of Greenhouse Gases." Office of Air and

Radiation. January 22, 2009. Available:

http://www.epa.gov/ghgreporting/documents/ pdf/archived/tsd/TSD%20Adipic_EPA%20

2-12-09.pdf.

3. U.S. EPA. "Technical Support Document for Process Emissions from Primary Production

of Aluminum: Proposed Rule for Mandatory Reporting of Greenhouse Gases." Office of

Air and Radiation. February 4, 2009. Available:

http://www.epa.gov/ghgreporting/document s/pdf/archived/tsd/TSD%20Aluminum_2009

0204.pdf.

4. U.S. EPA. "Technical Support Document for the Ammonia Production Sector: Proposed

Rule for Mandatory Reporting of Greenhous e Gases." Office of Air and Radiation.

January 22, 2009. Available:

http://www.epa.gov/ghgreporting/document s/pdf/archived/tsd/TSD%20Ammonia%20_E

PA%201-22-09.pdf.

5. U.S. EPA. "Technical Support Document fo r Process Emissions from Cement: Proposed

Rule for Mandatory Reporting of Greenhous e Gases." Office of Air and Radiation.

January 28, 2009. Available:

http://www.epa.gov/ghgreporting/document s/pdf/archived/tsd/TSD%20Cement%20_EP

A%201-28-09.pdf.

6. U.S. EPA. "Technical Support Document fo r the Ferroalloy Producti on Sector: Proposed

Rule for Mandatory Reporting of Greenhous e Gases." Office of Air and Radiation.

January 22, 2009. Available:

http://www.epa.gov/ghgreporting/documents/ pdf/archived/tsd/TS D%20Ferroalloys%20_

EPA%201-22-09.pdf.

7. U.S. EPA. "Technical Support Document fo r Emissions from Production of Fluorinated

Gases: Final Rule for Mandatory Reporti ng of Greenhouse Gases." Office of Air and

Radiation. November 5, 2010. Available:

http://www.epa.gov/ghgreporting/docu ments/pdf/2010/Subpart-L_TSD.pdf.

8. U.S. EPA. "Technical Support Document fo r the Glass Manufactur ing Sector: Proposed

Rule for Mandatory Reporting of Greenhous e Gases." Office of Air and Radiation.

January 22, 2009. Available:

# 13 http://www.epa.gov/ghgreporting/documents/ pdf/archived/tsd/TSD%20Glass__EPA%20

1-22-09.pdf.

9. U.S. EPA. "Technical Support Document fo r Emissions of HFC-23 from Production of

HCFC-22: Proposed Rule for Mandatory Repor ting of Greenhouse Gases." Office of Air

and Radiation. February 6, 2009. Available:

http://www.epa.gov/ghgreporting/docume nts/pdf/archived/tsd/TSD%20HFC23_20090206.pdf.

10. U.S. EPA. "Technical Support Document fo r Hydrogen Production: Proposed Rule for

Mandatory Reporting of Greenhouse Gases." Office of Air and Radiation. August 5,

2008. Available:

http://www.epa.gov/ghgreporting/documents/ pdf/archived/tsd/TSD%20HydrogenProduct

ion%20EPA_2-02-09.pdf.

11. U.S. EPA. "Technical Support Document for the Iron and Steel Sector: Proposed Rule for

Mandatory Reporting of Greenhouse Gases." Office of Air and Radiation. August 28,

2009. Available:

http://www.epa.gov/ghgreporting/documents/ pdf/archived/tsd/TSD%20Iron%20and%20

Steel%20_EPA%209-8-08.pdf.

12. U.S. EPA. "Technical Support Document for the Lead Production Sector: Proposed Rule

for Mandatory Reporting of Greenhouse Gases. " Office of Air and Radiation. January 22,

2009. Available:

http://www.epa.gov/ghgreporting/document s/pdf/archived/tsd/TSD%20Lead%20%20_E

PA%201-22-09.pdf.

13. U.S. EPA. "Technical Support Document fo r the Lime Manufacturing Sector: Proposed

Rule for Mandatory Reporting of Greenhous e Gases." Office of Air and Radiation.

January 22, 2009. Available:

http://www.epa.gov/ghgreporting/document s/pdf/archived/tsd/TSD%20Lime%20_EPA%

201-22-09.pdf.

14. U.S. EPA. "Technical Support Document fo r the Miscellaneous Uses of Carbonate

Sector: Proposed Rule for Mandatory Repor ting of Greenhouse Gases." Office of Air and

Radiation. January 22, 2009. Available:

http://www.epa.gov/ghgreporting/documents/ pdf/archived/tsd/TSD%20MiscellaneousCar

bornates_EPA%201-22-09.pdf.

15. U.S. EPA. "Technical Support Document for the Nitric Acid Production Sector: Proposed

Rule for Mandatory Reporting of Greenhous e Gases." Office of Air and Radiation.

January 22, 2009. Available:

http://www.epa.gov/ghgreporting/documents/ pdf/archived/tsd/TSD%20Nitric%20Acid%

20_EPA%201-22-09.pdf.

# 14 16. U.S. EPA. "Technical Support Document for the Petrochemical Production Sector:

Proposed Rule for Mandatory Reporting of Greenhouse Gases." Office of Air and

Radiation. September 9, 2008. Available:

http://www.epa.gov/ghgreporting/documents/ pdf/archived/tsd/TSD%20PetroChem_EPA

_09-09-08.pdf.

17. U.S. EPA. "Technical Support Document fo r the Petroleum Refining Sector: Proposed

Rule for Mandatory Reporting of Greenhous e Gases." Office of Air and Radiation.

September 8, 2008. Available:

http://www.epa.gov/ghgreporting/documents/ pdf/archived/tsd/TSD%20Petroleum%20Re

finery_EPA_01-22-09.pdf.

18. U.S. EPA. "Technical Support Document for the Phosphoric Acid Production Sector:

Proposed Rule for Mandatory Reporting of Greenhouse Gases." Office of Air and

Radiation. February 20, 2009. Available:

http://www.epa.gov/ghgreporting/document s/pdf/archived/tsd/TSD%20Phosphoric%20-

%20_EPA%202-18-09.pdf.

19. U.S. EPA. "Technical Support Document for the Pulp and Paper Sector: Proposed Rule

for Mandatory Reporting of Greenhouse Gases. " Office of Air and Radiation. February

11, 2009. Available:

http://www.epa.gov/ghgreporting/documents/ pdf/archived/tsd/TSD%20Pulp%20and%20

Paper%202_11_09.pdf.

20. U.S. EPA. "Technical Support Document for the Silicon Carbide Production Sector:

Proposed Rule for Mandatory Reporting of Greenhouse Gases." Office of Air and

Radiation. January 22, 2009. Available:

http://www.epa.gov/ghgreporting/documents/ pdf/archived/tsd/TSD%20Silicon%20Carbi

de%20_EPA%201-22-09.pdf.

21. U.S. EPA. "Technical Support Document for the Soda Ash Manufacturing Sector:

Proposed Rule for Mandatory Reporting of Greenhouse Gases." Office of Air and

Radiation. January 22, 2009. Available:

http://www.epa.gov/ghgreporting/document s/pdf/archived/tsd/TSD%20Soda%20Ash%2

0_EPA%201-22-09.pdf.

22. U.S. EPA. "Technical Support Document fo r the Titanium Dioxide Production Sector:

Proposed Rule for Mandatory Reporting of Greenhouse Gases." Office of Air and

Radiation. January 22, 2009. Available:

http://www.epa.gov/ghgreporting/documents/ pdf/archived/tsd/TSD%20Titanium%20Dio

xide_EPA%201-22-09.pdf.

23. U.S. EPA. "Technical Support Document for the Zinc Production Sector: Proposed Rule

for Mandatory Reporting of Greenhouse Gases. " Office of Air and Radiation. January 22,

2009. Available:

# 15 http://www.epa.gov/ghgreporting/documents/ pdf/archived/tsd/TSD%20Zinc%20%20_EP

A%201-22-09.pdf.

24. U.S. EPA. "Technical Support Document fo r Industrial Wastewater Treatment: Final

Rule for Mandatory Reporting of Greenhouse Ga ses." Climate Change Division Office of

Atmospheric Programs. June, 2010. Available:

http://www.epa.gov/ghgreporting/docu ments/pdf/2010/Subpart-II_TSD.pdf.

25. U.S. EPA. "Technical Support Document fo r the Industrial Waste Landfill Sector: Final

Rule for Mandatory Reporting of Greenhouse Ga ses." Climate Change Division Office of

Atmospheric Programs. June 9, 2010. Available:

http://www.epa.gov/ghgreporting/documents/ pdf/archived/tsd/TSD%20Landfills_EPA_0

2%2004%2009_2.pdf.

26. "Inventory of U.S. Greenhouse Gas Emi ssions and Sinks: 1990-2006." April, 2008. EPA

430-R-08-005. Available:

http://www.epa.gov/climatechange/ghgemissi ons/usinventoryreport/archive.html.

27. Climate Leaders Greenhouse Gas Inventory Protocol. Available:

http://www.epa.gov/climateleader ship/guidance/index.html.

28. Voluntary Reporting of Greenhouse Ga ses Program. June 1, 2006. Available:

http://www.eia.gov/oiaf/1605/index.html.

29. The Climate Registry Reporting Protocols. May 2008. Available:

http://www.theclimateregistry.org/resources/p rotocols/general-repo rting-protocol/.

30. California Climate Action Re gistry. August 2008. Available:

http://www.climateregistry.org/tools/prot ocols/general-repor ting-protocol.html.

31. California Air Resources Board Ca p and Trade Program. Available:

http://www.arb.ca.gov/cc/capandtrade/capandtrade.htm.

32. New Mexico Environment Department - Greenhouse Gases Reporting. Available:

http://www.nmenv.state.nm.us/aqb/GHG/ghgrr_index.html.

33. Regional Greenhouse Gas Initiative. Available: http://www.rggi.org/.

34. Western Climate Initiative. Available:

http://www.westernclimatei nitiative.org/index.php.

35. Eggleston H.S., Buendia L., Miwa K., Ng ara T. and Tanabe K. (eds). "2006 IPCC

Guidelines for National Greenhouse Gas I nventories." Prepared by the National

Greenhouse Gas Inventories Programme. The Intergovernmental Panel on Climate

Change (IPCC), 2006. Available: http://www.ipccnggip.iges.or.jp/public/2006gl/index.html.

# 16 36. Official Journal of the European Union, Commission Decision 29 January 2004.

Available:

http://eurlex.europa.eu/LexUriServ/L exUriServ.do?uri=OJ:L:2004:059:0001:0074:EN:P

DF.

37. Australian Government - Clean Energy Regulator - National Greenhouse and Energy

Reporting: Guidelines. Available: http ://www.cleanenergyregul ator.gov.au/NationalGreenhouse-and-Energy-Repor ting/Fact-sheets-FAQs-andguidelines/Guidelines/Pages/default.aspx.

38. Environment Canada - Canada's Greenhous e Gas Emissions Monitoring, Reporting and

Verification of Greenhouse Gas Sources and Si nks. Available: http://www.ec.gc.ca/gesghg/default.asp?lang=En&n=1357a041-1.

39. World Resources Institute and World Bu siness Council for Sustainable Development

Greenhouse Gas Protocol. Availabl e: http://www.ghgprotocol.org/.

40. "Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Natural Gas

Industry." American Petroleum Ins titute (API). August 2009. Available:

http://www.api.org/environment-hea lth-and-safety/climate-change/whatsnew/compendium-ghg-methodologie s-oil-and-gas- industry.aspx.

41. European Bank for Reconstruction and Development. Available:

http://www.ebrd.com/pages/homepage.shtml#&panel1-4.

42. American Iron and Steel Institute. Available: http ://www.steel.org/.

43. United Nations Framework Conventi on on Climate Change. Available:

http://cdm.unfccc.int/methodologies/index.html.

44. "Clean Energy Legislative Package." Aust ralian Government Department of Climate

Change and Energy Efficiency. Available: http://www.cleanenergyfuture.gov.au/cleanenergy-future/our-plan/.

45. Comment on the Mandatory Greenhouse Ga s Reporting Rule from Dow Corning, EPAHQ-OAR-2008-0508-0562.

46. Comment on the Call For Information from the American Chemistry Council, EPA-HQOAR-2010-0964-0015.

47. Comment on the Call For Information from Association of Battery Recyclers, EPA-HQOAR-2010-0964-0019

# 17 48. Comment on the Call For Information from Clean Air Task Force, Environmental

Defense Fund, Natural Resources Defens e Council, and Sierra Club, EPA-HQ-OAR2010-0964-0029.

49. “Evaluation of Competitive Harm from Disclosure of ‘Inputs to Equations’ Data

Elements Deferred to March 31, 2015”. Me morandum from EPA to Docket EPA-HQOAR-2010-0929. August, 2013.

50. U.S. EPA. Greenhouse Gas Reporting Program." RY2011.R.50 UA1-1. Available:

http://www.epa.gov/ghgreporting/re porters/datasystem/index.html.

51. U.S. EPA. "Regulatory Impact Analysis for the Mandatory Reporting of Greenhouse Gas

Emissions Final Rule (GHG Reporting)." Docket ID: EPA-HQ-OAR-2008-0508-2229.

September 2009. Available: http://www.re gulations.gov/#!documentDetail;D=EPA-HQOAR-2008-0508-2229.

# 18 Appendix A1

Summary Evaluation of Altern ative Calculation Equations

# 19 Table A1-1. Summary of the Evaluation of Alt ernative Calculation Equations For Each Subpart

Subpart Description Summary of Evaluation of Alternative Calculations

C Combustion No calculation methodologies were identified that would be an appropriate alternative.

In general, calculation methods reviewed are the same as the current methods required,

which are based on the IPCC methods. The a lternative methods would still require fuel

information (e.g., fuel input, fuel purchases, heat content, etc.) for the calculations;

according to Step 2 of the evaluation, disc losure concerns were identified for this

information. a



# E Adipic Acid No calculation methodologies were identified that would be an appropriate alternative.

Methodologies are similar to 2 IPCC methods. The IPCC Tier 1 methodology

calculates emissions using facility-level data rather than unit-level data and results in

lower accuracy in estimating emissions. IPCC Tier 2 methodology is similar to the Tier

1 methodology, except default factors are us ed instead of facility-specific information

resulting in lower accuracy than Tier 1. Bo th methods still requir e facility production

information as an input; according to Step 2 of the evaluation, disclosure concerns

were identified for this information. a



# F Aluminum No calculation methodologies were identified that would be an appropriate alternative.

3 methods were identified. Two (IPCC Tier 1 for CF 4 

# and C 2 

# F 6 

# and IPCC Tier 1 for

CO 2 

# emitted during electrolysis) use defau lt emission factors which result in greater

uncertainty than the current method. The third for calculating CF 4 

# and C2F 6 

# from

smelter specific anode effects is the IPCC Tier 2 method, which also has high

uncertainty compared to estimating emissions with the current method for CF 4 

# and

C 2 

# F 6 

# , ±50 percent. The alternatives still use pr oduction data; according to Step 2 of the

evaluation, disclosure concerns were identified for this information. a



# G Ammonia No calculation methodologies were identified that would be an appropriate alternative.

Several alternative calculation methods were identified, but all are based on 3 IPCC

methodologies: IPCC Tier 1, 2, and 3. The IPCC Tier 1 and 2 methods are not

considered viable alternative calculation methods because they would result in higher

uncertainty than the current method and would still require reporting of ammonia

production and feedstock information, which, according to Step 2 of the evaluation,

disclosure concerns were identified. a 

# The Tier 3 method is not considered a viable

alternative because it would also require reporting of current “inputs to equations” data

elements which, according to Step 2 of the evaluation, disclosure concerns were

identified. a



# H Cement Kilns No calculation methodologies were identified that would be an appropriate alternative.

Calculation methodologies used in various GHG reporting programs and protocols can

be grouped into 3 categories: (1) calculation of emissions based on clinker production,

(2) calculation of emissions based on cement production, (3) calculation of emissions

based on carbonate input to the kiln.

The clinker calculation methods reviewed are variations on the current method using

more general emission factors (national or default factors) and/or not calculating

emissions from some emission sources (e.g., ra w materials). The alternatives eliminate

the need for some of the current “inputs to equations” data elements. However, they

still require clinker productio n; according to Step 2 of the evaluation, disclosure

concerns were identified for this information. a 

# The alternative methods are all less

accurate, with higher uncertainty levels de pending on how general the emission factors

used are to calculate GHG emissions. Calcul ation method (2) is no longer considered

appropriate because it has a much higher un certainty in emissions. Calculation method

(3) would require more detailed inputs to be reported for raw materials for the kiln

(unless defaults are used); raw material information was identified as having

disclosure concerns in Step 2 of the evaluation. a 

# Use of calculation method (3) would

result in more significant revisions to the reporting rule. The EPA previously

determined this option could potentially be more costly and would not reduce the

uncertainty in emissions calculations.

# 20 Subpart Description Summary of Evaluation of Alternative Calculations

K Ferroalloy No calculation methodologies were identified that would be an appropriate alternative.

For CO 2 

# , other methods reviewed included using production or process input data with

an emission factor; mass balance with less site-specific data; and mass balance with

more generic carbon content data. All alternative methods reviewed still use

production data and/or process input data; according to Step 2 of the evaluation,

disclosure concerns were identified for this information. a 

# No other methods were

identified for CH 4



# . L Fluorinated Gas

Production No calculation methodologies were identified that would be an appropriate alternative.

Two methods from IPCC were reviewed. However, the methods either use default

factors and result in a high uncertainty in emission estimates or still require some of

the same “inputs to equations” data elements which, according to Step 2 of the

evaluation, disclosure concerns were identified. a



# N Glass No calculation methodologies were identified that would be an appropriate alternative.

Alternative calculation methodologies for this subpart are categorized as either inputbased (using raw material information) or output based (using production information).

The output-based methods have a higher uncertainty and use default values. Annual

glass production for each furnace and total for the facility are reported under

98.146(b)(3) but and were determined to be CBI in 76 FR 30782 (May 26, 2011)

. Therefore, the output-based methods would not avoid the disclosure concerns. All

input-based methodologies are based on IPCC Tier 3 calculations. Differences between

different programs are due to different defaults. Estimates using Tier 3 will be higher

than the current method. The input equations still use “inputs to equations” data

elements, which, according to Step 2 of the evaluation, disclosure concerns were

identified. a



# O CFC No calculation methodologies were identified that would be an appropriate alternative.

Alternative methods include calculating emissions using HCFC-22 production data

with a default or site-specific emission factor, and parameter monitoring data (using

process operating rate as a proxy for HF C-23 emissions). The alternative methods

reviewed still use production da ta and/or process input data which, according to Step 2

of the evaluation, disclosure concerns were identified. a 

# The alternative methods result

in increased uncertainty.

P Hydrogen No calculation methodologies were identified that would be an appropriate alternative.

Commenters on the call for information suggested calculating emissions using

aggregated fuel and feedstock consumption data to obscure specific information. This

method would still require monthly analyses of carbon content for each fuel and

feedstock; according to Step 2 of the evaluation, disclosure concerns were identified

for this information. a 

# Commenters also suggested calculating emissions on a carbon

feed basis and not require disaggregation of fuel/feedstock by type. There is

insufficient information or analysis provide d by the commenters to assess the accuracy

of this methodology. The method would not reveal any of the “inputs to equations”

data elements for which disclosure concerns were identified, but would require new

calculation algorithms. One newer method from CDM is limited in use and would not

apply to all reporters in this subpart. Alternative calculation methodologies reviewed

previously for the GHGRP primarily use em ission factors (default or site-specific).

These methodologies are less accurate than the current method. Other methods use

hydrogen production information, which, according to Step 2 of the evaluation,

disclosure concerns were identified. a



# Q Iron and Steel No calculation methodologies were id entified that would be an appropriate alternative.

Alternative calculation methodologies used in various GHG reporting programs and

protocols can be grouped into 5 categories: (1) calculation of emissions using

production based emission factors, (2) calculation of emissions using input based

emission factors, (3) calculation of emissions using default carbon weight fractions, (4)

process unit mass balance calculation that ex cludes small contributors, and (5) plantwide CO 2 

# mass balance for integrated mills only. The alternative methods (1) through

(4) eliminate the need for some of the current data elements. However, they still

require other data elements to be reported, such as production information or

# 21 Subpart Description Summary of Evaluation of Alternative Calculations

ingredient information, whic h, according to Step 2 of the evaluation, disclosure

concerns were identified. a 

# Method (5) was previously determined by the EPA to not be

appropriate because verification is needed on a process basis rather than a facility

basis. Facility-wide estimates also have a higher uncertainty than process based

calculations.

R Lead No calculation methodologies were identified that would be an appropriate alternative.

Other methods reviewed included using production or process input data with an

emission factor or default carbon content da ta. The alternative methods reviewed still

use production data and/or process input data which, according to Step 2 of the

evaluation, disclosure concerns were identified. a 

# The alternative methods result in

increased uncertainty in emission estimates.

S Lime No calculation methodologies were identified that would be an appropriate alternative.

The EPA previously considered allowing a process input based methodology (based on

feedstock) at proposal, but decided not to proceed with that alternative in the final

GHGRP. The process input based methodology requires feedstock based information

(e.g., mass of lime, mass of carbonate consumed); according to Step 2 of the

evaluation, disclosure concerns were identified for this information. a 

# Several of the

alternatives use a process output based methodology using production information;

according to Step 2 of the evaluation, disc losure concerns were identified for this

information. A third methodology reviewed uses the mass balance of carbonates in the

inputs and outputs; according to Step 2 of the evaluation, disclosure concerns were

identified for this information. a



# U Carbonate No calculation methodologies were identif ied that would be an appropriate alternative.

Two alternative calculation methods were id entified: IPCC Tier 1 and Tier 2. The

IPCC Tier 1 method uses emission factors based on the total mass of carbonate

consumed in limestone and dolomite. Default values are used for the fraction of the

carbonate comprised of limestone and dolom ite. The calculation method results in a

high uncertainty in emissions compared to the current method and still requires using

overall carbonate consumed as an input; ac cording to Step 2 of the evaluation,

disclosure concerns were identified for this information. a 

# The IPCC Tier 2

methodology is the same as Tier 1, except the fraction of carbonate in the limestone

versus dolomite consumed is not a default value. This methodology is more accurate

than Tier 1, but still less accura te than current method. It also requires using the mass

of carbonates consumed by carbonate type; according to Step 2 of the evaluation,

disclosure concerns were identified for this information. a



# V Nitric Acid No calculation methodologies were iden tified that would be an appropriate alternative.

Several alternative calculation methods were identified, all of which are similar to

IPCC Tier 1 and Tier 2 methodologies. Both IPCC methodologies calculate emissions

using plant level emission factors. Tier 2 is more refined in that emissions are also

calculated by different control technologies used. Both methodologies still require

using production informati on; according to Step 2 of the evaluation, disclosure

concerns were identified for this information. a 

# Both have a higher level of uncertainty

than the current method.

X Petrochemical No calculation methodologies were identified that would be an appropriate alternative.

Three alternative calculation methodologies were identified. One is the IPCC Tier 1

methodology, which calculates emissions using default emission factors for CO 2 

# and

CH 4 

# (published by IPCC) multiplied by the production of each product. The method

still uses plant specific production rates; according to Step 2 of the evaluation,

disclosure concerns were identified for this information. a 

# . Additionally, the level of

uncertainty is high compared to current method (10-60% higher for CO 2 

# ; 30-80%

higher for CH 4 

# ). The second alternative requires ro uting of process vent emissions to

stacks for direct and continuous measurements of CO 2 

# emissions from each process

stack (except flares) and each combustion source stack. While more accurate and

introducing less uncertainty than the current method, it requires mandating process

configurations that are not the intent of the GHGRP. However, the use of CEMS is

evaluated in section 3.0 as part of the CEMS analysis. A third methodology was

# 22 Subpart Description Summary of Evaluation of Alternative Calculations

suggested by a commenter to the Call for Information notice. The commenter

suggested allowing the use of subpart PP methodologies, which require direct

measurements using gas analyzers on a quarte rly basis. The alternative has a high level

of accuracy because it is based on source sp ecific data. It may likely be more costly

due to quarterly measurements. Additional analyses of the methodology would need to

be undertaken to fully evaluate it, including assessing availability of equipment,

applicability of analyzers for sources in this subpart, and cost.

Y Refineries No calculation methodologies were iden tified that would be an appropriate alternative.

IPCC’s Tier 1 and Tier 2 approaches use default emission factors to calculate GHG

emissions from non-combustion sources at refineries and would provide less reliable

emissions data for the entire refinery and no data on emissions from individual units.

The following is a summary of the alternative calculation methods that were evaluated

for individual emission points covered by subpart Y.

Flares: Two alternative approaches we re identified for calculating CO 2 

# emissions. The

first alternative approach uses default emission factors multiplied by the amount of

flare gas burned. The second method uses te st data (either from facility or vendor

testing). However, both of these methods would be unlikely to yield accurate results

since waste gas composition is highly variable especially during unit startup,

shutdown, and malfunctions.

Catalytic Cracking Units and Fluid Coking Units: part 98 currently includes all three

possible calculation methods.

Asphalt Blowing: One alternative method is based on default emission factors for

calculating the emissions of CO 2 

# and CH 4 

# from asphalt blowing operations. Part 98

calculation methods for both controlled and uncontrolled asphalt blowing operations

rely on site-specific emission factors from facility-specific test data (though default

emission factors are also provided for facilities that do not have the necessary test

data). Allowing all users to use default emission factors instead of site-specific

emission factors result in less accurate GH G emission estimates and would not avoid

the use of “inputs to equations” data el ements data; according to Step 2 of the

evaluation, disclosure concerns were identified for this information. a 

# Equipment Leaks:

Two alternative methods were identified for estimating emissions from equipment

leaks. The first alternative method uses the crude feedstock throughput and a default

emission factor to estimate fugitive emissi ons. This approach will yield less accurate

results than the methods currently included in part 98. Furthermore, according to Step

2 of the evaluation a 

# , disclosure concerns were identified with crude feedstock

throughput data. The second alternative meth od would require refineries to measure

the flow rates of each leaking component (i.e., flanges, connectors, pumps,

compressors, valves, pressure relief valves, etc) using Hi-Flow Samplers TM 

# , calibrated

bag, or other measurement methods. The measured flow rate for each leaking

component is multiplied by the time period during which the component is known to

have been leaking, and the result adjusted for the uncertainty in the measurement of the

flow rate. The total emissions for the refi nery are the sum emissions for all leaking

components. Due to the large number of components that would have to be regularly

monitored and the difficulty of conducting such measurements for some inaccessible

components, this approach is likely to be difficult and costly to implement.

Storage Tanks: For storage tanks used to store unstab ilized fuel oil, 3 alternatives were

identified. The first uses default emission factors multiplied by the quantity of crude oil

to calculate the CH 4 

# emissions from flashing losses and are based on data from

upstream oil and gas production facilities rather than on data from refinery storage

tanks. The second approach uses computer simulation programs to estimate emissions

from flashing losses. The third approach is to use a correlation equation, such as the

Vasquez-Beggs Equation, standing correlation, or EUB rule of thumb. However, all of

these methods would require one or more of the same inputs used in the existing part

98 methods (e.g., tank-specific methane composition data, quantity of unstabilized

crude oil received, etc.); acco rding to Step 2 of the evaluation, disclosure concerns

were identified for this information. a

# 23 Subpart Description Summary of Evaluation of Alternative Calculations

Other Emission Sources : There were no new alternative calculation methods identified

for the flares, catalytic reforming units, sulf ur recovery units, coke calcining, process

vents, blowdowns, working and breathing losses from storage tanks not used to store

unstabilized crude oil, and loading operations. All of the previously identified

calculation methods considered by the EPA were incorporated into part 98.

Z Phosphoric

Acid No calculation methodologies were identified that would be an appropriate alternative.

Only 1 alternative calculation methodology was identified. The methodology requires

using default factors based on regional chemical composition of phosphate rock to

calculate emissions. The methodology was considered and not used in the GHGRP

because it was much less accurate than the method selected . Additionally, the

alternative methodology would still require monthly phosphate rock consumption;

according to Step 2 of the evaluation, disc losure concerns were identified for this

information. a



# AA Pulp and Paper No calculation methodologies were id entified that would be an appropriate alternative.

The major source of GHG emissions from facilities in this subpart are combustion

sources - lime kilns, recovery boilers, and power boilers. Emissions from power boilers

are covered under the subpart C analysis. Two alternative calculation methodologies

for the biogenic component in recovery furn aces were identified. Both are based on

using default factors. One is based on using default values for HHV instead of sitespecific values and the method is only applicab le to kraft or soda mills. The second is

based on multiplying the total energy of spent liquor combusted and emission factors

relating energy to emissions. Neither is very accurate and both have high uncertainty in

emissions. The first method also uses some of the same “inputs to equations” data

elements which, according to Step 2 of the evaluation, disclosure concerns were

identified. a 

# The second method does not allow emissions to be verified on an

equipment basis, and applies only to the facility as a whole.

BB Silicon Carbide No calculation methodologies were identified that would be an appropriate alternative.

Two alternative calculation methods were identified, based on using the IPCC Tier 1

calculation methodology. One option is to use an input-based (using raw material

information) approach using default emission factors from IPCC, and the petroleum

coke input. The option would still use many of the same data elements as inputs that

the current method uses; according to Step 2 of the evaluation, disclosure concerns

were identified for this information. a 

# The second option is to use an output-based

(using production information) approach using default emission factors from IPCC,

and the silicon carbide production. However, silicon carbide production information,

which is reported under 98.286(a)(2) and (b)(2), was determined to be entitled to

confidential treatment in 76 FR 30782 (May 26, 2011)

. CC Soda Ash No calculation methodologies were identified that would be an appropriate alternative.

Two alternative calculation methodologies were identified that were previously

considered but not adopted in the GHGRP. Both are based on the IPCC Tier 2

methodology. One would use default factors applied to the facility. The other would

use site-specific factors. Both have a slig ht decrease in emissions accuracy estimates.

However, both still require quantity of trona used or soda ash produced as inputs;

according to Step 2 of the evaluation, disc losure concerns were identified for this

information. a



# EE Titanium

Dioxide No calculation methodologies were identified that would be an appropriate alternative.

Two alternative calculation methods were identified. One option is to use the IPCC

Tier 1 approach, which calculates emissions using a default emission factor and

production information. However, production information, which is reported under

98.316(a)(3) and (b)(4), was determined to be CBI in 76 FR 30782 (May 26, 2011)

. This option also increases uncertainty. Th e second option is to estimate emissions

based on the carbon reducing agent. Emi ssions would be estimated by multiplying the

tonnage of carbon reducing agent and 2 defau lt factors. The uncertainty of this option

has not been determined, but is likely much higher than the cu rrent method because 2

default factors are used rather th an site-specific information.

GG Zinc No calculation methodologies were identified that would be an appropriate alternative.

# 24 Subpart Description Summary of Evaluation of Alternative Calculations

Five alternative calculation methods were identified. Several of the options (IPCC Tier

1 and Tier 2, U.S. inventory) use default emission factors which would introduce

higher uncertainty in emissions and are more appropriate for aggregated process

information on a sector-wide or nationwide basis. One of the methods would also

require production information which, according to Step 2 of the evaluation, disclosure

concerns were identified. a 

# . One other method is similar in that default emission factors

are used, but the calculation of emissions is ba sed on the quantity of carbon used in the

production of metal. This method has a lo wer uncertainty, but it is still is not as

accurate as the cu rrent method.

TT Industrial

Landfills No calculation methodologies were identified that would be an appropriate alternative.

One alternative calculation method was identified. Reporters would use the existing

part 98 CH 4 

# calculation methodology with default factors. This would result in a higher

uncertainty in emissions than the current method due to the default factor. In addition ,

it requires reporting of some “inputs to equations” data elements which, according to

Step 2 of the evaluation, disclosure concerns were identified. a

a 

# For additional details on the alternative calculation equations evaluated, please see Appendix A2. For the Step 2 evaluation,

please see “Evaluation of Competitive Harm from Disclosure of ‘I nputs to Equations’ Data Elemen ts Deferred to March 31, 2015”

memorandum.

# 25 Appendix A2

Detailed Evaluation of Altern ative Calculation Equations

# 26 Appendix A2. Subpart C – Evaluation of Alternative Calculation Equations

Alternative Analysis

Methods in the Call for

Information None identified.

Methods previously

considered but not adopted in

final GHGRP Source 1 

# ID Description

CARB 1 Same as 40 CFR part 75: CEMS.

2 Calculate emissions sim ilar to IPCC methods usi ng fuel consumption and

carbon or heat content. Sti ll requires fuel input info rmation for calculations,

which was identified as having disclosure concerns in Step 2 of the

evaluation.

CCAR 1 Similar to IPCC met hods. Still requires information on fuel burned in

calculations, which was identified as ha ving disclosure concerns in Step 2

of the evaluation.

2 Same as 40 CFR part 75: CEMS.

TCR 1 Calculate emissions si milar to IPCC methods. Still require fuel input data

in calculations, which was identified as having disclosure concerns in Step

2 of the evaluation.

2 Same as 40 CFR part 75: CEMS.

CCX 1 CEMS

2 Calculate emissions usi ng WRI/WBCSD protocols. St ill requires fuel input

data in calculations, which was identif ied as having disclosure concerns in

Step 2 of the evaluation

RGGI Same as 40 CFR part 75: CEMS, with additional net energy output

monitoring.

DOE 1 Same as 40 CFR part 75: CEMS.

2 Mass balance using fuel burned based on measured purchases or

consumption and default or facility specific factors. Similar to IPCC

methods. Still requires fuel input in formation which was identified as

having disclosure concerns in Step 2 of the evaluation.

40 CFR

part 75 CO 2 

# CEMS combined with stack flow monitor or calculate mass emissions

using fuel sampling for percent carbon content and fuel flow monitoring.

CL 1 Same as 40 CFR part 75: CEMS.

2 Similar to IPCC calculation methods.

EU ETS Emissions calculated using mass bala nce approach similar to Tier 3. Still

requires fuel and heat content informa tion as inputs which were identified

as having disclosure concerns in Step 2 of the evaluation.

ANGERS Tier

1 CEMS.

Tier

2 Similar to IPCC Tier 2, but uses EF based on direct sampling and analysis.

Still requires fuel feed information as inputs and requires fuel specific

inputs to calculate EF which were iden tified as having disclosure concerns

in Step 2 of the evaluation. .

Tier

3 Similar to IPCC Tier 2, but uses EF based on repr esentative sampling. Still

requires fuel feed information which was identified as having disclosure

concerns in Step 2 of the evaluation.

Tier

4 Similar to IPCC Tier 1. Still requires fuel feed information.

CA GHG 1 References IP CC Tier 3 approaches.

2 CEMS when a CO 2 

# diluent monitor is installe d for measurements of other

pollutants.

EU ETS 1 Emissions calculated using mass bala nce approach similar to Tier 3. Still

requires fuel and heat content informa tion as inputs, which were identified

as having disclosure concerns in Step 2 of the evaluation.

2 CO 2 

# CEMS allowed if combined with a stack flow monitor and requires

supplementary calculations.

Protocols and programs

created after GHGRP None identified.

1 

# CARB = California Air Resources Board Mandatory Reporting Rule; CCAR = California Climate Action Registry; TCR = The Climate R egistry; CCX = Chicago

Climate Exchange; RGGI = Regional Greenhouse Gas Initiative; DOE = U.S. DOE 1605 (b) program; CL = U.S EPA Climate Leaders; EU ETS = European Union

Emissions Trading Scheme; ANGERS = Australian National GHG and Energy Reporting System; CA GHG = Canadian GHG National Reportin g Program.

# 27 Appendix A2. Subpart E – Evaluation of Alternative Calculation Equations

Alternative Analysis

Methods in the Call for

Information None identified.

Methods previously

considered but not adopted

in final GHGRP Source 1 

# ID Description

IPCC Tier

1 Multiplies facility-level production times the highest default emissions

factor in IPCC Tier 1, which assumes no abatement of N 2 

# O emissions.

Much lower accuracy than current me thod, still requires production data

which was identified as having disclosure concerns in Step 2 of the

evaluation.

Tier

2 Similar to Tier 1. Uses technology-specific default factors to account for

abatement. Lower accuracy than current method and still requires

production information which was identified as having disclosure

concerns in Step 2 of the evaluation. .

WRI/WBCSD 2 Same as IPCC Tier 2.

3 Same as IPCC Tier 1.

U.S. Inv Same as IPCC Tier 2.

TCR Tier

B Same as IPCC Tier 2.

DOE B Similar to IPCC Tier 2, but uses actual dest ruction factors and not

defaults. More accu rate than IPCC Tier 2 but st ill uses many of current

“inputs to equations” data elements and is not as accurate as current

method which were identified as having disclosure concerns in Step 2 of

the evaluation.

C Similar to IPCC Tier 2.

Protocols and programs

created after GHGRP None identified.

1 

# IPCC = Intergovernmental Panel on Climat e Change, 2006; U.S. Inv = U.S. National I nventory Report, 2008 Method; WRI/WBCSD = Wo rld Resources

Institute/World Business Council for Sustai nable Development; DOE = Department of Energy’s 1605 (b) Voluntary Reporting Program ; TCR = The Climate

Registry.

# 28 Appendix A2. Subpart F – Evaluation of Alternative Calculation Equations

Alternative Analysis

Methods in the Call for

Information None identified.

Methods previously

considered but not adopted

in final GHGRP Source 1 

# ID Description

IPCC Tier 1 -

General Uses default emission factors for CF 4 

# and C 2 

# F 6 

# and production

information. Significant uncertainty and still uses production data which

was identified as having disclosure concerns in Step 2 of the evaluation.

Tier 2 –

Smelter

specific

anode

effects Uses factors for CF 4 

# and C 2 

# F 6 

# . High uncertainty compared to estimating

emissions with the current method for CF 4 

# and C 2 

# F 6 

# , about ±50 percent.

Could develop new emission factors for CF 4 

# and C 2 

# F 6 

# to reduce the

uncertainty of the methodology, but the method still uses quantity of

aluminum produced which was identifie d as having disclosure concerns

in Step 2 of the evaluation.

Tier 1 -

Electrolysis Uses default emission factors for CO 2 

# and production information.

Higher uncertainty compared to current method (5 – 10%) and still uses

production data which was identified as having disclosure concerns in

Step 2 of the evaluation.

Protocols and programs

created after GHGRP None identified.

1 

# IPCC = Intergovernmental Pa nel on Climate Change, 2006.

# 29 Appendix A2. Subpart G – Evaluation of Alternative Calculation Equations

Alternative Analysis

Methods in the Call for

Information None identified.

Methods previously

considered but not adopted

in final GHGRP Source 1 

# ID Description

IPCC Tier

1 Uses default factor per unit of output multiplied by facility-level

ammonia production. Introduces one additional input (ammonia

production) which was identified as ha ving disclosure concerns in Step

2 of the evaluation. Higher uncertainty in emissions than the current

method due to defaults used.

Tier

2 Same as IPCC Tier 1 except that it estimates emissions per fuel type,

using ammonia production disaggregated by fuel input and process type.

Introduces one additional input (ammonia production) which was

identified as having disclosure concerns in Step 2 of the evaluation. Still

requires feedstock information which was identified as having

disclosure concerns in Step 2 of the evaluation. Results in higher

uncertainty in emissions than the current method due to defaults used.

Tier

3 Same as IPCC Tier 2 method, except us es actual total fuel requirement

rather than default. Allows both default and measured carbon content

and carbon oxidation factors. Introduces two additional inputs (total fuel

requirement per plant and carbon oxi dation factor) that are the same

type of information identified as having disclosure concerns in Step 2 of

the evaluation. Still requires feedstock information, which was identified

as having disclosure concerns in Step 2 of the evaluation. Very accurate

method only if actual carbon conten t and carbon oxidation factors are

used.

WRI/WBCSD 2 Same as IPCC Tier 2 if no facility-specific fuel requirement is available

and default factors are used.

3 Same as IPCC Tier 3 if facility-specific fuel requirement is available to

calculate emissions.

U.S. Inv Same as IPCC Tier 2.

DOE B

Rated Similar to IPCC Tier 2. It allows actual or de fault carbon content value

and calculates annual, fa cility-wide emissions. If actual (not default)

factors are used, then the method introduces little uncertainty; however,

calculates only facility-level estimate.

TCR-GRP Tier

A2 Same as IPCC Tier 2.

Protocols and programs

created after GHGRP None identified.

1 

# IPCC = Intergovernmental Panel on Climate Change, 2006; WRI/WB CSD = The World Resource Institute and World Business Council fo r Sustainable

Development’s Greenhouse Gas Protocol; TCR-GRP = The Climate Regi stry General Reporting Protocol For the Voluntary Reporting Pr ogram, May 2008; DOE =

Department of Energy 1605(b) Voluntary Reporting Program – Amm onia; U.S. Inv = U.S. National Inventory Report, 2008 Method.

# 30 Appendix A2. Subpart H – Evaluation of Alternative Calculation Equations

Alternative Analysis

Methods in the

Call for

Information No calculation methods identified.

Methods

previously

considered but

not adopted in

final GHGRP Source 1 

# ID Method

Type 2 

# Description

IPCC Tier

1 Cement Default factor s; Clinker production inferred from cement

production.

Not recommended; high uncertainty.

IPCC Tier

2 Clinker National factor; higher uncertainty than current method.

IPCC Tier

3 Carbonate Default EF for carbonates. Potentially more costly; larger #

of new inputs.

U.S Inv Clinker IPCC Tier 2 w/default factors.

WRI/WBCS

D 1A Clinker Similar to IPCC Tier 2 w/CKD EF.

WRI/WBCS

D 1B Clinker Similar to WRI/WBCS D, 1A but w/default factors.

WRI/WBCS

D 2A Cement Site/corpora te clinker/cement ratio.

Not recommended; high uncertainty.

WRI/WBCS

D 2B Cement Same as WRI/WBCSD, 2A but w/default factors.

CA AB32 Clinker Same as WRI/WBCSD, 1A.

CCAR A Clinker Same as WRI/WBCSD, 1A.

CCAR B Clinker Same as WRI/WBCSD, 1B.

CCAR A Cement Same as WRI/WBCSD, 2A.

CCAR B Cement Same as WRI/WBCSD, 2A, but w/more default factors.

DOE A Clinker Uses clinker production w/site specific ratios of clinker

content.

DOE B Clinker Same as DOE, A but with default factors.

DOE A Cement Same as WRI/WBCSD, 2A.

DOE B Cement Same as WRI/WBCS D, 2A but w/default factors.

DOE C Cement Not recommended; high uncertainty. Default factor x

cement production.

CL 1A Clinker Same as WRI/WBCSD, 1A but doesn’t report raw material

emissions.

CL 1B Clinker Same as WRI/WBCSD, 1B.

CL 2A Cement Same as WRI/WBCSD, 2A.

CL 2B Cement Same as WRI/WBCS D, 2A but w/default factors.

CL 3 Carbonate Same as IPCC Tier 3.

EU ETS A Carbonate Same as IPCC Tier 3, but w/more default factors.

EU ETS B1 Clinker Same as WRI/WBCSD, 1A.

EU ETS B2 Clinker Same as WRI/WBCSD, 1B.

NM Clinker Same as WRI/WBCSD, 1A.

TCR Clinker Same as WRI/WBCSD, 1A but doesn’t report raw material

emissions.

TCR Clinker Same as WRI/WBCSD, 1B.

TCR Carbonate Same as IPCC Tier 3.

Protocols and

programs

created after

GHGRP No new calculation methods identified.

1 

# IPCC = Intergovernmental Panel on Climat e Change, 2006; U.S. Inv = U.S. National I nventory Report, 2008 Method; WRI/WBCSD = Wo rld Resources

Institute/World Business Council for Sustai nable Development; CA AB32 = CA Mandatory Reporting Program; CCA R = California Clima te Action Registry;

DOE = Department of Energy’s 1605 (b) Voluntary Reporting Program; CL = EPA Climate Leaders; EU ETS = European Union Emission T rading System; NM =

New Mexico Mandatory GHG Reporting Program; TCR = The Climate Registry.

2 

# Cement method relies on information about the composition and quantity of raw ma terials consumed, the quantity of clinker incorporated into the cement, and the

quantity of cement produced. It calculates CO 2 

# emissions based on the amount of raw materials and thei r carbonate content. This approach directs companies to

# 31 collect data on cement production, the raw ma terial ratio to produce clinker and the CaCO 3 

# equivalent content of the raw mate rials, thus allowing companies to

monitor changes in emissions due to m odifying the cement manufacturing process.

Clinker Production-Based method is a mass balance approach based on the qua ntity of clinker produced. It calculates CO 2 

# emissions based on the volume and

composition of clinker produced as well as the amount of cement k iln dust (CKD) not recycled to th e kiln. This approach has bec ome an industry standard due to

all companies knowing clinker production and the CaO/MgO content data.

Carbonate Input Approach method is based on the collection of disaggregated data on the ty pes (compositions) and quantities of carbonate(s) consumed to produc e

clinker, as well as the respective emission factor(s) of the carbona te(s) consumed. It includes an adjustment to subtract any u ncalcined carbonate within CKD not

returned to the kiln.

# 32 Appendix A2. Subpart K – Evaluation of Alternative Calculation Equations

Alternative Analysis

Methods in the Call

for Information Source 1 

# ID Description

Dow

Corning 1 Same as current method for CO 2 

# , except excludes from the mass balance

inputs contributing less than 5% of plan t wide emissions. This exclusion is

allowed in Subpart K if <1% of total mass of carbon in or out. Method still

requires using “inputs to e quations” data elements which were identified as

having disclosure concerns in Step 2 of the evaluation. Small reduction in

burden and negligible reduction in accuracy.

Dow

Corning 2 Same as current method for CO 2 

# , except with more flexibility in how carbon

content is reported (e.g., supplier, in dependent laboratory, IPCC). Still uses

mass of each process input and process outputs which were identified as

having disclosure concerns in Step 2 of the evaluation. Unknown reduction

in accuracy.

Methods previously

considered but not

adopted in final

GHGRP IPCC CO 2 

# Tier

1 Uses mass of process outputs (pr oduct and nonproduct) and productionbased emission factors. S till uses production data which was identified as

having disclosure concerns in Step 2 of the evaluation. Method decreases

accuracy of estimates 25-50%.

IPCC CO 2 

# Tier

2 Similar to current method but uses default emission factors instead of

facility specific carbon content. Still us es mass of each process input which

was identified as having disclosure concerns in Step 2 of the evaluation.

Methods use of defaults decreases accuracy of estimates by 15-40%.

ANGGR

P Uses quantity of carbon ma terial, energy content of carbon material, and

emission factor based on energy cont ent. Use of default factors would

decrease accuracy of estimates by 15-40%. Use of facility specific factors

would be similar to current method. St ill requires knowing carbon content of

materials and amount of ma terials which was identified as having disclosure

concerns in Step 2 of the evaluation.

U.S. Inv Same as IPCC CO 2 

# Tier 1.

IPCC CH 4 

# Tier

1 Use mass of product and generic produc tion-based emission factors. Still

uses production data which was identifie d as having disclosure concerns in

Step 2 of the evaluation. Method de creases accuracy of estimates by 40%.

Protocols and

programs created

after GHGRP No programs were identified.

1 

# IPCC = Intergovernmental Panel on Climat e Change, 2006; Dow Corning – Comments subm itted under Call for Information (DCN: EPA- HQ-OAR-2008-0508-

0562); ANGGRP = Australian National Government Greenhouse and Energy Reporting Program; U.S. Inv = U.S. EPA Inventory for Green house Gas Emissions

and Sinks.

# 33 Appendix A2. Subpart L – Evaluation of Alternative Calculation Equations

Alternative Analysis

Methods in the

Call for

Information No calculation methods identified.

Methods

previously

considered but

not adopted in

final GHGRP Sourc

e 1 

# ID Method

Type Description

IPCC Tier 1 Default

emission

factor and

production

data Uses default F-gas generation fa ctor and mass of F-gas produced.

High uncertainty due to emission variability (0.8 to 2% of

production).

IPCC Tier 3A Direct process

measurement Uses frequent or continuous measur ement of the concentration and

flow-rate (i.e., CEMS ) from the vents at an individual plant to

obtain instantaneous F-gas emissi on rate. Total quantity of F-gas

released is the annual sum of measured instan taneous releases

. IPCC Tier 3B Parameter

monitoring Uses process operating rate (e .g., feedstock flow rate, F-gas

production rate) as proxy for F-gas emission rate. Still uses process

data (e.g., feedstock flow ra te, production rate) which were

identified as having disclosure concerns in Step 2 of the evaluation

Protocols and

programs

created after

GHGRP No new calculation methods identified.

1 

# IPCC = Intergovernmental Pa nel on Climate Change, 2006.

# 34 Appendix A2. Subpart N – Evaluation of Alternative Calculation Equations

The current calculation methodology is a modi fied version of IPCC Tier 3. Process CO 2 

# emissions are

calculated using a carbon mass balance for each conti nuous glass melting furnace. The equation is based on:

mass fraction of carbonate mineral in each raw materi al, mass of carbonate raw material charged, default

emission factor for carbonate-based raw material (s hown in Table N-1 of the rule), and fraction of

calcination achieved for each raw material.

Alternative Analysis

Methods in the

Call for

Information No calculation methods identified.

Methods

previously

considered but

not adopted in

final GHGRP Source 1 

# ID Metho

d

Type Description

IPCC Tier

1 Output Uses a default emission factor based on typical raw material mixtures

and total glass production data. Signi ficant decrease in accuracy of

emission estimates (60% from current method).

IPCC Tier

2 Output Uses default emission factor s and cullet ratios, and production

information for specific types of gl ass produced. Accuracy of emission

estimates decreases by 10% from current method.

IPCC Tier

3 Input Similar to current method. Does not limit calculation to mass fraction

of carbonate-based mineral in carbonate-based raw material. Resulting

estimates will be higher than current method. Still uses “inputs to

equations” data elements which were identified as having disclosure

concerns in Step 2 of the evaluation.

U.S Inv Output Similar to IPC C Tier 1 and 2. Uses default carbon weight fractions for

each raw material charged which were identified as having disclosure

concerns in Step 2 of the evaluation. .

DOE Input Same as IPCC Tier 3. Still uses “inputs to equatio ns” data elements

which were identified as having disclosure concerns in Step 2 of the

evaluation.

ANMGGR

P D Input Similar to IPCC Tier 3. Uses di fferent calcination fraction. Still uses

“inputs to equations” data elements which were identified as having

disclosure concerns in Step 2 of the evaluation.

ANMGGR

P H Input Same as IPCC Tier 3. Still us es “inputs to equations” data elements

which were identified as having disclosure concerns in Step 2 of the

evaluation.

EU ETS A Input Same as IPCC Tier 3. Still uses “inputs to equa tions” data elements

which were identified as having disclosure concerns in Step 2 of the

evaluation.

EU ETS B Input Similar to IPCC Tier 3. Uses default fraction of calcination for

carbonate-based raw material. Still uses “inputs to equations” data

elements which were identified as having disclosure concerns in Step 2

of the evaluation.

EB Input Same as IPCC Tier 3. Still uses “inputs to equatio ns” data elements.

Protocols and

programs

created after

GHGRP No new calculation methods identified.

1 

# IPCC = Intergovernmental Panel on Climat e Change, 2006; U.S. Inv = U.S. National I nventory Report, 2008 Method; DOE = Departme nt of Energy’s 1605 (b)

Voluntary Reporting Program; EU ETS = European Union Emission Trading System; ANMGGRP = Aust ralian National Mandatory Greenhous e Gas Reporting

Program; EB = European Bank for Reconstruction and Development.

# 35 Appendix A2. Subpart O – Evaluation of Alternative Calculation Equations

Alternative Analysis

Methods in

the Call for

Information No calculation methods identified.

Methods

previously

considered

but not

adopted in

final

GHGRP Source

1 

# ID Description

IPCC Tier

1 Uses default HFC-23 generation factor and mass of HCFC-22 produced. For control devices,

uses estimated destruct ion efficiency. Still requires produc tion data which was identified as

having disclosure concerns in Step 2 of the ev aluation. Higher uncertain ty in emissions than

the current method due to default factor (using a default emission factor of 4 percent yields

50 percent uncertainty).

IPCC Tier

2 Uses site-specific HFC-23 generation factor (based on records of carbon and fluorine

efficiencies), mass of HCFC-22 produced, and da ta on fraction of year process vent stream

was released untreated which were identified as having disclosure concerns in Step 2 of the

evaluation. Uncertainty varies according to sa mpling frequency (daily sampling yields 1 – 2

percent uncertainty).

IPCC Tier

3A Simplified version of current method (uses conc entration of HFC-23 in the gas vented from

process, mass flow of process stream, ma ss flow of HFC-23/othe r product stream, and

fraction HFC-23 in HCFC-22/other stream.) Methods allow continuous and less frequent

monitoring. Still requires 2015 in put data which were identi fied as having disclosure

concerns in Step 2 of the evaluation. Uncer tainty due to measurement frequency (current

method requires weekly) and exclusion of HFC- 23 destroyed offsite, sold, and stored.

IPCC Tier

3B Uses process operating rate as proxy for HFC- 23 emitted. Still uses two current “inputs to

equations” data elements (i.e., fraction HFC-23 in HCFC-22/other stream and mass flow of

HFC-23/other product stream) which were identified as having disclosure concerns in Step 2

of the evaluation

U.S.

Inv Same as IPCC Tier 3B.

WRI/W

BCSD 2 Similar to IPCC Tier 3A. Accounts for ons ite HFC-23 destruction (fraction abated and

control utilization data)

WRI/W

BCSD 3 Similar to IPCC Tier 3A. WRI method uses default factors for the loss in production

efficiency of HCFC-22, carbon and fluorine c ontent factors, and carbon and fluorine balance

efficiencies.

WRI/W

BCSD 4 Same as IPCC Tier 1.

DOE Similar to IPCC Tier 3A. Accounts for onsite HFC-23 destruction (fraction abated and

control utilization data)

TCR Tier

B Similar to IPCC Tier 2.

TCR Tier

C Similar to IPCC Tier 1. TCR method accounts for HFC-23 dest royed by collecting fraction

abated and control device utilization data.

Protocols

and

programs

created

after

GHGRP No new calculation methods identified.

1 

# IPCC = 2006 Guidelines for National Greenhouse Gas Inventories; U.S. Inv = U.S. National Inventory Report 2008 Method (U.S. In ventory of Greenhouse Gas

Emissions and Sinks 1990-2006); WRI/WBCSD = Wo rld Resources Institute & World Business Council for Sustainable Development. Gre enhouse Gas Protocol:

HCFC-22 Emissions from Production of HCFC-22, Version 2.0. Dece mber 2007; DOE = Department of Energy’s 1605(b) Voluntary Report ing Program; TCR =

The Climate Registry.

# 36 Appendix A2. Subpart P – Evaluation of Alternative Calculation Equations

Alternative Analysis

Methods in the

Call for

Information Commenter

1 

# Description

ACC Calculate emissions using aggregated fuel and feedstock consumption data to obscure specific

information. Method woul d still require monthly analyses of carbon content for each fuel and

feedstock which were identified as having disclosure concerns in Step 2 of the evaluation.

Method is less accurate than current method.

ACC Calculate emissions on a carbon feed basis and not require disaggregation of fuel/feedstock by

type. Insufficient information or analysis provid ed to assess the accuracy of the methodology.

Method would not reveal any of the “inputs to eq uations” data elements that were identified

as having disclosure concerns in Step 2 of the evaluation, but would require new calculation

algorithms.

Methods

previously

considered but

not adopted in

final GHGRP Source 1 

# ID Description

EU ETS Tier

1 Uses default emission factor. Less accurate than current method.

EU ETS Tier

2 Uses a facility specific emission factor calculated from carbon content of feed gas.

Still requires composition information which was identified as having disclosure

concerns in Step 2 of the evaluation. More accurate than Tier 1 but less accurate than

current method.

DOE A Based on fuel burned and the ratio of CO 2 

# to fuel determined from fuel analysis. Still

requires fuel input and composition information which were identified as having

disclosure concerns in Step 2 of the evaluation.

DOE B Uses default emission factors based on fuel. Less accurate than the current method

and still requires fuel consumption inform ation which were identified as having

disclosure concerns in Step 2 of the evaluation.

API 1 Uses production rate and simplified stoich iometric ratios. Met hod requires reporting

of data element determined to be 

# in 76 FR 30782 (May 26, 2011)

. API 2 Uses a default emission factor and feedstock volume. Less accurate than current

method and still requires feedstock information which was identified as having

disclosure concerns in Step 2 of the evaluation.

CARB 1 Similar to current method, but only accounts for carbon in feedstock. Less

comprehensive and accurate than the current method.

IPCC Tier

1 Based on hydrogen production and facility specific proportiona lity factor. Less

accurate than current method and still requires production information which was

identified as having disclosure concerns in Step 2 of the evaluation.

Protocols and

programs

created after

GHGRP CDM provides a different calculation methodology based on using biogas to displace LPG as a feedstock and

fuel in a hydrogen production unit. Method is limited in use. Method has high accuracy and low uncertainty as

the calculated emissions are related to a monetary value under CDM.

1 

# ACC = American Chemistry Council; IPCC = Intergovernmental Panel on Climate Change, 2006; DOE = Department of Energy; EU ETS = European Union

Emission Trading System; API = American Petroleum Institute; CARB = California Air Resources Board; CDM = Clean Development Mec hanism.

# 37 Appendix A2. Subpart Q – Evaluation of Alternative Calculation Equations

Alternative Analysis

Methods in the

Call for

Information Two methods identified by Sierra Club are similar to methods previously consider ed but not adopted in the

final GHGRP: (1) a simple mass ba lance assuming all the carbon input to the process converts to CO 2 

# ; and

(2) exclude small contributors from the mass balance fo r EAFs only. These are addressed in the following

summary.

Methods

previously

considered but

not adopted in

final GHGRP Source 1 

# ID Description

CL Section

2.2 Exclude small contributors from mass bala nce (e.g., CL: slag out of an EAF

furnace, DOE: APCD residue from a decarburization vessel).

 Allowed under GHGRP if <1% of total mass of carbon in or out; concept also

recommended by AISI.

 Small reduction in burden and negligible reduction in accuracy.

 Retains 2015 data elements which were identified as having disclosure

concerns in Step 2 of the evaluation. DOE Section

1.E.4.1.6.

3

IPCC Tier 1 Use production based emission factor s instead of site-specific information and

information on inputs.

 Not comprehensive, i.e., IPCC listed only 5 of the 7 pr ocesses in GHGRP

 Hides recipes/ingredients, but not pr oduction rate which was identified as

having disclosure concerns in Step 2 of the evaluation.

 Decreases accuracy of estimates by 20%.

AISI Fenceline

principle Use input based emission factors instead of site-specific information and

information on production.

 Not comprehensive, e.g., excludes scrap to BOF or EAF and materials

produced on-site like sinter.

 Hides production rates, but not recipes /ingredients, which was identified as

having disclosure concerns in Step 2 of the evaluation.

 Decreases accuracy of estimates by 25%.

IPCC Tier 2 Use default carbon weight fraction instead of carbon content of inputs and

products.

 Hides site specific carbon content, but still requires production rate and

recipes/ingredients which were identified as having disclosure concerns in Step

2 of the evaluation.

 Preamble indicates analysis of ca rbon content is not burdensome.

 IPCC claims accuracy decreases by 5%, but preamble indicates that use of

defaults is more appropriate for a sector wide or national total. WRI/W

BSCD Tier 1

CL All

EU

ETS ANNEX

VI If mill is integrated; conduct a plant-wide CO 2 

# mass balance (ignore movement of

energy sources within plant bounda ries) instead of by process.

 Preamble indicates process level info is needed for verification and to identify

reduction opportunities; so verification issues with option.

 Composite totals are used. AISI Fenceline

principle

CL Section

2.1

DOE Section

1.E.4.1.6.

5

Protocols and

programs

created after

GHGRP 4 programs were identified. However, the methods used to calculate emissions are the same as the methods

previously considered but not ad opted in the final GHGRP or are id entical to methods in the GHGRP.

Therefore, no further analyses of these are presented in this table. The 4 programs are:

 Australian Government – NGER technical guidelines, section 4.67 (similar to CL, section 2.2)

 Australian Government – NGER technical guidelin es, section 4.66 (similar to IPCC Tier 2)

 UN, Framework on Climate Change – Clean De velopment Mechanisms ; AMS-III.V.: Decrease

of coke (similar to IPCC Tier 1)

 CARB (same as GHGRP)

1 

# IPCC = Intergovernmental Panel on Climate Change, 2006; WRI/WBCS D = World Resources Institute/Wor ld Business Council for Susta inable Development;

DOE = Department of Energy; CL = EPA Climate Leaders; EU ETS = European Union Emission Trading System; AISI = American Iron and Steel Institute.

# 38 Appendix A2. Subpart R – Evaluation of Alternative Calculation Equations

Alternative Analysis

Methods in the

Call for

Information The Association of Battery Recyclers suggested using de fault carbon content, rather than measured carbon

content, for secondary lead smelters, as the feed material is predominantly used in lead-acid batteries. Using a

default carbon content value would result in ±10% uncer tainty compared to the current method. However, the

annual mass of each carbon-containing ma terial is the same type of inform ation identified as having disclosure

concerns in Step 2 of the evaluation.

Methods

previously

considered but

not adopted in

final GHGRP Source ID Description

IPCC Tier 1 Uses default emission factor by produc tion type (imperial smel ting furnace, direct

smelting furnace). Uses production data, whic h was identified as having disclosure

concerns in Step 2 of the evaluation, and results in a ±45% increase in uncertainty.

IPCC Tier 2 Similar to IPCC Tier 1 except emi ssion factors are based on country-specific

information on the use of reducing agen ts, furnace types, and other process

materials, and default carbon contents. Met hod is more accurate than IPCC Tier 1,

but is less accurate than current method and also requires production information,

which was identified as having disclosure concerns in Step 2 of the evaluation.

Stack test Uses emissions data from a stack test to develop site-specifi c emission factors that

is applied to the quantity of feed or pr oduct material. Appropria te for facilities

where process inputs and operating paramete rs are consistent. This option was not

adopted because of the potent ial for significant variation at smelters in the feed to

the furnace and process operating parameters.

U.S. Inv Same as IPCC Tier 1.

ANMGGRP Similar to current method, but is based on energy content. Still requires

information on quantity and carbon cont ent of feed to smelter, which was

identified as having disclosure concerns in Step 2 of the evaluation.

Env Canada Use current method for metal ore and reducing agents charged to the furnace only.

For any other non-fuel process input mate rials, use emission factors. This method

would still require reporting of raw material and carbon content data for metal ore

which were identified as having disclosure concerns in Step 2 of the evaluation. It

would underestimate emissions, and has an unknown uncertainty compared to the

current method. Would need to develop emission factors.

Protocols and

programs

created after

GHGRP No new calculation methods identified.

1 

# IPCC = Intergovernmental Panel on Clim ate Change, 2006; ANMGGRP = Australian Nati onal Mandatory Greenhouse Gas Reporting Progr am; Env Canada =

Environment Canada; U.S. Inv = U.S .Inventory of Greenhouse Gases.

# 39 Appendix A2. Subpart S – Evaluation of Alternative Calculation Equations

Alternative Analysis

Methods in the

Call for

Information None identified

Methods

previously

considered but

not adopted in

final GHGRP Source 1 

# ID Method

Type 2 

# Description

IPCC Tier

1 Output Uses default emission factors for each of the 3 types of lime produced.

Still requires production information which was identified as having

disclosure concerns in Step 2 of the evaluation and has a high

uncertainty.

IPCC Tier

2 Output Uses default emission factors based on lime type correcting for the

amount of calcined byproduct/waste produced. Still requires production

information which was identified as having disclosure concerns in Step

2 of the evaluation and has a high uncertainty.

IPCC Tier

3 Input Uses measured quantities of carb onate inputs to the kiln and emission

factors and calcinations fractions to the carbonates consumed. Low

uncertainty in emissions but requir es feedstock information which was

identified as having disclosure concerns in Step 2 of the evaluation.

U.S. Inv Output Sa me as IPCC Tier 2.

WRI/

WBCSD 1 Output Similar to IPCC Tier 2, but encourages more plant-specific data.

WRI/

WBCSD 2 Input Same as IPCC Tier 3.

EU ETS 1A Mass

balance Based on a carbonate mass balance a nd emission factor. Still requires

composition and product information which were identified as having

disclosure concerns in Step 2 of the evaluation.

EU ETS 1B Output Based on identifying MgO and CaO in the lime produced. Still requires

composition and product information which were identified as having

disclosure concerns in Step 2 of the evaluation.

EU ETS 2A Input Based on carbonate input to kilns only. Has a higher uncertainty than

IPCC Tier 3 and requires feedstock information which was identified as

having disclosure concerns in Step 2 of the evaluation.

EU ETS 2B Output Same as EU ETS 1B.

TCR 1, 3 Input Same as IPCC Tier 3, allows plant-specific data.

TCR 2, 4 Output Same as IPCC Tier 3, allows plant-specific data.

Protocols and

programs

created after

GHGRP This alternative is for a new methodology for producing lim e. It is not widely used (or used at all) and not

appropriate for considerat ion. The CDM provides a methodology for hy draulic lime production uses fossil fuel

usage and electricity usage to estima te emissions. This method is for a ne w method of producing hydraulic lime

for construction purposes by blendi ng conventional hydraulic lime with alternative material additives.

1 

# IPCC = Intergovernmental Panel on Climat e Change, 2006; U.S. Inv = U.S. National I nventory Report, 2008 Method; WRI/WBCSD = Wo rld Resources

Institute/World Business Council for Sustaina ble Development; EU ETS = European Union Emission Trading System; TCR = The Climat e Registry; CDM =

Clean Development Mechanism

2 

# Emissions calculated based on inputs to kiln, outputs from kiln, or mass balance of inputs and outputs.

# 40 Appendix A2. Subpart U – Evaluation of Alternative Calculation Equations

Alternative Analysis

Methods in the

Call for

Information None identified.

Methods

previously

considered but

not adopted in

final GHGRP Source 1 

# ID Description

IPCC Tier

1 Uses emission factors based on the mass of carbonate consumed. Considers only

limestone and dolomite are used and assi gns default fraction partitioning the use of

them. High uncertainty in emissions . Still requires know ing overall carbonate

consumed which was identified as having di sclosure concerns in Step 2 of the

evaluation.

IPCC Tier

2 Same as Tier 1, except the fraction of li mestone versus dolomite consumed is not a

default value. More accurate than Tier 1, but still less accurate than current method

and also requires using mass carbonates consumed by carbonate type, which was

identified as having disclosure concerns in Step 2 of the evaluation.

ANMGGRP Same as current method.

Protocols and

programs

created after

GHGRP None identified.

1 

# IPCC = Intergovernmental Panel on Clim ate Change, 2006; ANMGGRP = Australian Nati onal Mandatory Greenhouse Gas Reporting Progr am.

# 41 Appendix A2. Subpart V – Evaluation of Alternative Calculation Equations

Alternative Analysis

Methods in the

Call for

Information None identified.

Methods

previously

considered but

not adopted in

final GHGRP Source 1 

# ID Description

IPCC Tier

1 Uses default emission factors and assumes no abatement. Facility level based

rather than unit based. St ill requires production information which was identified

as having disclosure concerns in Step 2 of the evaluation and has a high

uncertainty in estimates.

IPCC Tier

2 Similar to current method. Uses plant- level production data disaggregated by

technology and default emission factors an d destruction factors on a site-specific

basis. Still requires using production in formation which was identified as having

disclosure concerns in Step 2 of the evaluation.

WRI/WBCS

D 2 Similar to IPCC Tier 2.

WRI/WBCS

D 3 Similar to IPCC Tier 1.

U.S. INV Uses default factor for calculating N 2 

# O emissions. No inputs are used that had

disclosure concerns identified in Step 2of the evaluation, but accuracy is severely

reduced and is more appropriate for nationa l estimates. Facility level data are not

collected.

TCR Tier

B Similar to IPCC Tier 2.

DOE B Similar to IPCC Tier 2.

DOE C Similar to IPCC Tier 2, except uses other published emission factors rather than

IPCC for uncontrolled and non-se lective catalytic reduction control technologies.

Protocols and

programs

created after

GHGRP None identified.

1 

# IPCC = Intergovernmental Panel on Climat e Change, 2006; U.S. Inv = U.S. National I nventory Report, 2008 Method; WRI/WBCSD = Wo rld Resources

Institute/World Business Council for Sustai nable Development; DOE = Department of Energy; TCR = The Climate Registry.

# 42 Appendix A2. Subpart X – Evaluation of Alternative Calculation Equations

Alternative Analysis

Source Method Description

Methods in the

Call for

Information American

Chemistry

Council Gas

composition

meter Commenter suggested allowing the us e of subpart PP methodologies, which

require direct measurements using gas analyzers.

 Quarterly monitoring is required

 High accuracy due to source specific information

Methods

previously

considered but

not adopted in

final GHGRP IPCC Tier 1 Emission

factor Use default emission factors for CO 2 

# and CH 4 

# published by IPCC multiplied

by the production of each product.

 Still uses plant specific production rates, which were identified as having

disclosure concerns in Step 2 of the evaluation.

 Low cost to implement

 Level of uncertainty is high compared to current method (10-60% for

CO 2 

# ; 30-80% for CH 4 

# )

 Default factors cannot reflect site-sp ecific differences in characteristics

such as the type of feedstock, operating conditions, etc.

 More appropriate for s ector wide estimates

IPCC Tier 3,

modified Direct

measurements Requires routing of process vent emissions to stacks for direct and continuous

measurements of CO 2 

# emissions from each process stack (except flares) and

each combustion source stack.

 More costly

 Mandates process configuration changes, which is not the intent of the

GHGRP

 Flare emissions based on emission factor

 CH 4 

# and N 2 

# O emissions from combustion s ources would be calculated

using subpart C procedures.

 More accurate and less uncertainty than current option

 Similar to IPCC Tier 3 approach, exce pt IPCC indicates that process vent

emissions may be either esti mated or measured, and IPCC CH 4 

# estimation

methods for flares is more rigorous

Protocols and

programs

created after

GHGRP No new calculation methods identified.

1 

# IPCC = Intergovernmental Panel on Climate Change, 2006.

# 43 Appendix A2. Subpart Y – Evaluation of Alternative Calculation Equations

Flares

Alternative Analysis

Source Method Description

Methods in the

Call for

Information No new calculation methods identified.

Methods

previously

considered but

not adopted in

final GHGRP API, CARB,

DOE, EU,

and IPCC Default

emission

factors Use quantity of waste gas burned and defa ult emission factors. Still uses plant

specific production rates; according to Step 2 of the evaluation, disclosure

concerns were identified with this information.

 Low cost to implement.

 Level of uncertainty is higher compared to using measured carbon content

or HHV data because the composition of waste gas sent to flares is known

to vary considerably due to process upsets, maintenance activities, etc.

However, the default emi ssion factor approach is thought to be reasonably

accurate during normal operation.

 More appropriate for s ector wide estimates.

API Test data Uses vendor or f acility test data to ca lculate CO 2 

# and CH 4 

# emissions (N 2 

# O are

considered negligible by API).

 More accurate than default emission fa ctors; however, level of uncertainty

is higher compared to using meas ured carbon content or HHV data

because composition of waste gas sent to flares is known to vary

considerably due to process upsets, maintenance activities, etc.

Protocols and

programs

created after

GHGRP No new calculation methods identified.

1 

# IPCC = Intergovernmental Panel on Climat e Change, 2006; U.S. Inv = U.S. National I nventory Report, 2008 Method; WRI/WBCSD = Wo rld Resources

Institute/World Business Council for Sustaina ble Development; EU ETS = European Union Emission Trading System; API = American P etroleum Institute; CARB

= California Air Resources Board.

# 44 Catalytic Cracking Units and Fluid Coking Units

Alternative Analysis

Methods in the Call for

Information No new calculation methods identified.

Methods previously considered

but not adopted in final

GHGRP The previously considered methods are included in part 98. However, larger units are not allowed

to use emission factors to calculate CO 2 

# emissions (allowed only for units with throughputs less

than 10,000 bbls/stream day), th e only input reported for larger units is the molar volume

conversion factor. Small units can use mass balance, CEMS, or emission factors (either sitespecific or default).

Protocols and programs created

after GHGRP No new calculation methods identified.



# Sulfur Recovery

Alternative Analysis

Methods in the Call for

Information No new calculation methods identified.

Methods previously considered

but not adopted in final

GHGRP All of the previously considered methods are included in part 98.

Protocols and programs created

after GHGRP No new calculation methods identified.



# Coke Calcining

Alternative Analysis

Methods in the Call for

Information No new calculation methods identified.

Methods previously considered

but not adopted in final

GHGRP All of the previously considered methods are included in part 98.

Protocols and programs created

after GHGRP No new calculation methods identified.



# Asphalt Blowing

Alternative Analysis

Source Method Description

Methods in the

Call for

Information No new calculation methods identified.

Methods

previously

considered but

not adopted in

final GHGRP API and

CARB Default

emission

factors Use quantity of asphalt blown and defaul t emission factors fo r calculating the

emissions of CO 2 

# and CH 4 

# from asphalt blowing operations. Part 98

calculations methods for both controlled and uncont rolled asphalt blowing

operations relies on site-s pecific emission factors from facility-specific test

data (though default emission factors are also provided for facilities that do

not have the necessary test data).

 Still uses plant specific production rates, which was identified as having

disclosure concerns in Step 2 of the evaluation.

 Low cost to implement

 Level of uncertainty is higher compared to using the site -specific emission

factor approach in the rule

 Default factors cannot reflect site-sp ecific differences in characteristics

such as operatin g conditions, etc.

 More appropriate for s ector wide estimates

Protocols and

programs

created after

GHGRP No new calculation methods identified.

# 45 1 

# API = American Petroleum Institute; CARB = California Air Resources Board.



# Delayed Coking Units

Alternative Analysis

Source Method Description

Methods in the

Call for

Information No new calculation methods identified.

Methods

previously

considered but

not adopted in

final GHGRP EU ETS Mass balance No equation provided

Protocols and

programs

created after

GHGRP No new calculation methods identified.

1 

# EU ETS = European Union Emission Trading System.



# Process Vents

Alternative Analysis

Methods in the Call for

Information No new calculation methods identified.

Methods previously considered

but not adopted in final

GHGRP All of the previously considered methods are included in part 98.

Protocols and programs created

after GHGRP No new calculation methods identified.



# Blowdowns

Alternative Analysis

Methods in the Call for

Information No new calculation methods identified.

Methods previously considered

but not adopted in final

GHGRP All of the previously considered methods are included in part 98.

Protocols and programs created

after GHGRP No new calculation methods identified.



# Equipment Leaks

Alternative Analysis

Source Method Description

Methods in the

Call for

Information No new calculation methods identified.

# 46 Methods

previously

considered but

not adopted in

final GHGRP API Default

emission factor Use default emission factors for amount of crude feedstock and default

emission factors.

 Still uses plant specific production rates, which was identified as having

disclosure concerns in Step 2 of the evaluation.

 Low cost to implement

 Level of uncertainty is high compared to the current methods

 Default factors cannot reflect site-sp ecific differences in characteristics

such as operating conditions, effect iveness of LDAR programs, etc.

 More appropriate for s ector wide estimates

Protocols and

programs

created after

GHGRP UNFCCC Direct

measurements Measure the flow rates of the phys ical leaks using Hi-Flow Samplers TM



# , calibrated bag, or other suitable flow measurements technology and calculate

the emissions using the rate x time period of leaking.

 More accurate and less uncerta inty than current option.

 More costly due to large numbe r of components to monitor.

 May not be practical to monitor so me components due to safety and

accessibility issues.

 Data used to calculate emissi ons does not contain information

determined to have disclosure concer ns in Step 2 of the evaluation.

1 

# API = American Petroleum Institute; UNFCCC = Unit ed Nations Framework Convention on Climate Change



# Storage Tanks – Unstablized Crude Oil

Alternative Analysis

Source Method Description

Methods in the

Call for

Information No new calculation methods identified.

Methods

previously

considered but not

adopted in final

GHGRP API Default

emission factor Use default emission factors for CH 4 

# published by API multiplied by the

quantity of crude oil.

 Still uses the amount of unstabili zed crude delivered, which was

identified as having disclosure concerns in Step 2 of the evaluation.

 Low cost to implement

 Level of uncertainty is unknown but w ould likely be high compared to

current methods

 Default factors cannot reflect site-sp ecific differences in characteristics

such as the type of crude, operating conditions, etc.

 More appropriate for s ector wide estimates

API API E&P

TANKS

program API E&P TANKS program, which uses pr essure differentia l, API gravity,

Reid vapor pressure, composition of the crude oil, and crude oil throughput.

 Less accurate than current options

 Would still require site specific information on methane composition

data and quantity of unsta bilized crude oil received, which was identified

as having disclosure concerns in Step 2 of the evaluation.

API Correlation

equations Similar to one of the current methods . API recommends the Vasquez-Beggs

Equation, standing correlation, or EUB rule of thumb.

 No information regarding accuracy provided.

 Would still require site specific information on methane composition

data and quantity of unsta bilized crude oil received, which was identified

as having disclosure concerns in Step 2 of the evaluation.

API Other process

simulators No specific method provided.

Protocols and

programs created

after GHGRP No new calculation methods identified.

1 

# API = American Petroleum Institute.



# Storage Tanks – Products Othe r than Unstabilized Crude Oil

Analysis

# 47 Alternative

Methods in the Call for

Information No new calculation methods identified.

Methods previously considered

but not adopted in final GHGRP All of the previously considered methods are included in part 98.

Protocols and programs created

after GHGRP No new calculation methods identified.



# Crude Oil, Intermediate, and Product Loading Operations

Alternative Analysis

Methods in the Call for

Information No new calculation methods identified.

Methods previously considered

but not adopted in final GHGRP All of the previously considered methods are included in part 98.

Protocols and programs created

after GHGRP No new calculation methods identified.

# 48 Appendix A2. Subpart Z – Evaluation of Alternative Calculation Equations

Alternative Analysis

Methods in the

Call for

Information None identified.

Methods

previously

considered but

not adopted in

final GHGRP Source 1 

# ID Description

U.S. Inv Option 1 Uses default fa ctors based on regional chemical composition of phosphate rock.

Less accurate than current method, but still requires mont hly phosphate rock

consumption, which was identified as having disclosure concerns in Step 2 of the

evaluation.

Protocols and

programs

created after

GHGRP None identified.

1 

# U.S. Inv = U.S. Greenhouse Gas Emissions and Sinks: 1990-2006. USEPA 430-R-08-005.

# 49 Appendix A2. Subpart AA – Evaluation of Alternative Calculation Equations

Alternative Analysis

Methods in the

Call for

Information No calculation methods identified.

Methods

previously

considered but

not adopted in

final GHGRP Emission

Source Data Source Method

Type 2 

# Description

 No alternative calculation methodologies identified for makeup chemicals.

 All other emissions are from combustion sources.

 Emissions from power boilers are based on fossil fuel information and the calculation methodology in

subpart C is referenced. No altern ative methodologies were reviewed fo r these sources as they will be

covered under the subpart C analysis.

 Subpart AA requires reporting of fossil fuel and biogeni c emissions from recovery furnaces and lime kilns.

The fossil fuel component of the emissions are calcul ated using methods in subpa rt C. Biogenic emissions

are not calculated from lime kilns, as the emissions are accounted for in the recovery furnace calculations.

Alternative calculation methodologies for the biogen ic component in recovery furnaces are presented

below.

Recovery

furnace GHG TSD Emission

factor Method would allow use of default values for HHV for

calculating emissions from kraft or soda recovery furnaces

instead of site-specific data.

 Has high uncertainty and lower accuracy.

 Still requires black liquor solids federates as an input

which was identified as having disclosure concerns in

Step 2 of the evaluation.

 Dismissed at proposal because most facilities already

analyze for HHV.

 Not applicable to sulfite or stand-alone semi-chemical

facilities.

Recovery

furnace

operations WRI/WBCSDI

/ICFPA/NCAS

I spreadsheet Emission

factor Calculates total GHG emissions from a facility based on total

energy of spent liquor combusted on lower heating value

basis.

 High uncertainty in emissions.

 Difficult to verify results because no emissions per

equipment.

Protocols and

programs

created after

GHGRP CARB program refers to S ubpart AA for calculations.

1 

# GHG TSD = GHG technical support documents ; WRI/WBCSD = World Re sources Institute/World Business Council for Sustainable Devel opment;

ICFPA/NCASI = International Council on Forest and Paper Association/National Council for Air and Stream Improvement; CARB = Cal ifornia Air Resources

Board.

# 50 Appendix A2. Subpart BB – Evaluation of Alternative Calculation Equations

Alternative Analysis

Methods in the

Call for

Information None identified.

Methods

previously

considered but

not adopted in

final GHGRP Source 1 

# ID Description

IPCC Tier 1 Output based approach (using production information) and using default CO 2 

# and

CH 4 

# emission factors from the 2006 IPCC guide lines, and silicon carbide output.

Uncertainty estimated to 10%. Requires pr oduction as an input to the emissions

calculation, which was identified as having disclosure concerns in Step 2 of the

evaluation.

IPCC Tier 1 Input based approach (using feedstock informatio n) using default CO 2 

# and CH 4 

# emission factors from the 2006 IPCC guide lines, and petroleum coke input.

Uncertainty estimated to be 10% and still requires same inputs as current method,

which was identified as having disclosure concerns in Step 2 of the evaluation.

Protocols and

programs

created after

GHGRP None identified.

1 

# IPCC = Intergovernmental Pa nel on Climate Change, 2006.

# 51 Appendix A2. Subpart CC – Evaluation of Alternative Calculation Equations

Alternative Analysis

Methods in the

Call for

Information None identified.

Methods

previously

considered but

not adopted in

final GHGRP Source 1 

# ID Description

IPCC Tier 2D Use default factors. Slight decrease in accuracy, but quantity of trona used or soda

ash produced is still an input, which were id entified as having disclosure concerns

in Step 2 of the evaluation.

IPCC Tier 2S Uses an annual s ite-specific emission factor to es timate emissions. A nnual stack test

information may not capture variability in emissions associated with consumption

of various fuels. Still requires quantity of trona used or soda ash produced as an

input, which were identified as having di sclosure concerns in Step 2 of the

evaluation.

Protocols and

programs

created after

GHGRP None identified.

1 

# IPCC = Intergovernmental Pa nel on Climate Change, 2006.

# 52 Appendix A2. Subpart EE – Evaluation of Alternative Calculation Equations

Alternative Analysis

Methods in the

Call for

Information None identified.

Methods

previously

considered but

not adopted in

final GHGRP Source 1 

# ID Description

IPCC Tier 1 Uses default emission factor and production information, which was identified as

having disclosure concerns in Step 2 of the evaluation. Uncertainty is estimated

to be 15%.

ANMGGRP Uses default energy content and 2 default emission factors in combination with

the total tonnage of the carbon reducing agent. Higher emissions uncertainty

because default factors are used.

Protocols and

programs

created after

GHGRP None identified.

1 

# IPCC = Intergovernmental Panel on Clim ate Change, 2006; ANMGGRP = Australian Nati onal Mandatory Greenhouse Gas Reporting Progr am.

# 53 Appendix A2. Subpart GG – Evaluation of Alternative Calculation Equations

Alternative Analysis

Methods in the

Call for

Information None identified.

Methods

previously

considered but

not adopted in

final GHGRP Source 1 

# ID Description

IPCC Tier

1 Uses default emission factor per unit of output and national productivity data. Has a

high uncertainty. More appropriate for aggr egated process information on a sectorwide or nationwide basis. If applied on a facility basis, would require production

data which was identified as having disclosure concerns in Step 2 of the evaluation.

IPCC Tier

1a Same as Tier 1, but uses default emissi on factor specific to production processes.

Better uncertainty, but still more appropriate for sector-wide or nationwide basis. If

applied on a facility basis, would require production data which was identified as

having disclosure concerns in Step 2 of the evaluation.

IPCC Tier

2 Similar to Tier 1, but a ccounts for reducing agents, furnaces, and other process

materials that affect emissions using emission factors based on aggregated plant

statistics. More accurate than Tier 1 but would require production data which was

identified as having disclosure concerns in Step 2 of the evaluation. Uncertainty is

estimated to be 15%.

U.S. Inv Uses default emi ssion factors. High uncertainty in emission estimates. More

appropriate for aggregated process info rmation on a sector-wide or nationwide

basis.

ANGGRP Estimated based on the quantity of each carbon reductant used in production, the

energy content of the reduction and a default fuel emission factor. The basic method

has a high uncertainty in results.

Protocols and

programs

created after

GHGRP None identified.

1 

# IPCC = Intergovernmental Panel on Climat e Change, 2006; U.S. Inv = U.S. National I nventory Report, 2008 Method; ANGGRP = Austr alian National

Government Greenhouse and Energy Reporting Program.

# 54 Appendix A2. Subpart TT – Evaluation of Alternative Calculation Equations

Alternative Analysis

Methods in

the Call for

Information None identified.

Methods

previously

considered

but not

adopted in

final

GHGRP Source 1 

# ID Description

U.S. Inv Reporters use the existing part 98 CH 4 

# calculation methodology. Higher uncertainty in

emissions than the current method due to defau lt factor. Still requires reporting of “inputs to

equations” data elements that were 

# identified as having disclosure concerns in Step 2

of the evaluation.

Protocols

and

programs

created after

GHGRP None identified.

1 

# U.S. Inv = U.S. National Inventory Report 2008 Method (U.S. Inventory of Greenhouse Gas Em issions and Sinks 1990-2006).

# 55 Appendix B

Summary of CEMS Characterization for Each Subpart with “Inputs to Equations” Data

Elements

# 56 Appendix B. General Stationary Fuel Combustion Sources – Subpart C

Industry Background

Stationary fuel combustion comprises many so urces, including boilers , heaters, engines,

furnaces, kilns, ovens, flares, incinerators, dryers, and any other equipment or machinery that

burns fuel. From two regulatory databases, count s for certain sources ar e available: there are

14,142 industrial, commercial, and institutiona l boilers and 55 CISWI units. Based on 2011

annual report submissions, there were 1,985 faciliti es that reported to GHGRP under subpart C.

Under subpart C, sources must provide emission estimates for CO 2 

# , CH 4 

# , and N 2 

# O for each

combustion unit. Emissions must be reported separa tely for each type of fuel combusted. Sources

may use emission factors, annual fuel usage data , and in some subparts use CEMS to calculate

emissions.

Applicable NSPS and NESHAP for Combustion Sources

Table C-1. Applicable NESHAP and NSPS Rules

NESHAP/NSPS Subparts Reviewed Monitoring Required

by the NESHAP or

NSPS Would

Monitoring

Equipment

Relevant to Part

98 be Installed to

Comply With

NESHAP or

NSPS? Were Data on

CEMS Counts

Available in

NESHAP or

NSPS docket?

Subpart DDDDD - Boiler MACT PM CEMS

Yes Yes

Subpart Db - Boiler NSPS PM, NO X 

# , SO 2 

# CEMS

Yes Yes

Subparts CCCC and DDDD - CISWI NSPS

and Emissions Guidelines PM, NO X 

# , SO 2 

# CEMS

Yes Yes



# As shown in Table C-1, multiple CEMS are required for boilers and incinerators. The installation

of this equipment is directly relatable to the inst allation of a GHG CEMS; all major equipment

would already be installed and only the GHG CEMS analyzer would be necessary.

Summary of Available Data on Fac ilities Reporting the Use of CEMS

Non-GHG CEMS data for subpart C facilities were available in two databases compiled for

rulemaking purposes - the Boiler MACT database and CISWI database. These databases showed

what CEMS were installed at the unit le vel. This included CEMS for PM, CO, NO X 

# , and SO 2



# . Table C-2 provides the total number of units wh ich have at least one CEMS installed. In

addition, with new requirements in the Boiler MACT, there are an a dditional 95 units which

would install a CEMS; this value is also show n in Table C-2. There were 177 facilities that

reported under the GHGRP using a total of 311 CO 2 

# CEMS.

# 57 Table C-2. CEMS Data from GHGRP and Regulatory databases

Boiler MACT Boiler MACT CISWI NSPS GHGRP

Total Boiler Count/Count

of Boilers with non-GHG

CEMS Count of Additional

Boilers Installing nonGHG CEMS to

Comply Total Incinerator

Count/Count of

Incinerators with nonGHG CEMS Count of Facilities with

CO 2 

# CEMS/Total

Count of CO 2 

# CEMS

14,142/1025 95 55/31 177/311



# Subpart C CEMS Count

Table C-3 summarizes the actual data collected for facilities using CO 2 

# CEMS, non-CO 2 

# GHG

CEMS, and non-GHG CEMS. The potential count for non-GHG CEMS is based on the 95

facilities which would install CEMS after finalization of the Boiler MACT.

Table C-3. Subpart C CEMS Counts

Basis CO 2 

# CEMS for

GHGRP Reporting non-CO 2



# GHG CEMS for

GHGRP Reporting non-GHG CEMS for

Other EPA Programs

Actual Potential c



# Facilities 177 a 

# 0

- -

Units 311 b 

# 0 1,056 1,151

NA = No information available.

a 

# Number of facilities reporting to GHGRP in 2011 that they are using a CEMS to report CO 2 

# emissions.

b 

# The total number of CO 2 

# CEMS at the facilit ies which reported CO 2 

# CEMS.

c 

# Potential facilities or process units that may have equipment installed that could be modified for use in the GHGRP.

# 58 Appendix B. Adipic Acid Production – Subpart E

Industry Background

Based on 2011 annual report submissions, there were 3 facilities that reported to GHGRP under

subpart E.

Under subpart E, facilities estimate N 2 

# O process emissions from all adipic acid production units

combined. For N 2 

# O emissions, facilities may either use a si te-specific emission factor applied to

the annual adipic acid production, or directly measure the emissions using an EPA-approved

alternative method to the si te-specific emission factor.

Applicable NSPS and NESHAP for Adipic Acid Plants

Table E-1. Applicable NESHAP and NSPS Rules

NESHAP/NSPS Subparts Reviewed Monitoring Required

by the NESHAP or

NSPS Would

Monitoring

Equipment

Relevant to Part

98 be Installed to

Comply With

NESHAP or

NSPS? Were Data on

CEMS Counts

Available in

NESHAP or

NSPS docket?

Subpart NNN—NSPS for VOC Emissions

From Synthetic Organic Chemical

Manufacturing Industry (SOCMI) Distillation

Operations If facility complies with

TRE limit (>1 and not

using VOC control

device) and have an

absorber, condenser, or

carbon adsorber then

organic monitoring is

option Yes No

Subpart RRR—NSPS for VOC Emissions

From Synthetic Organic Chemical

Manufacturing Indust ry (SOCMI) Reactor

Processes If facility complies with

TRE limit (>1 and not

using VOC control

device) and have an

absorber, condenser, or

carbon adsorber then

organic monitoring is

option Yes No



# The relevant monitoring from both the NESHAP and NSPS is organic monitoring. An organic

monitoring device is used to indicate the con centration level of orga nic compounds exiting the

recovery device based on a detection principle such as infra-red, photoi onization, or thermal

conductivity and each is equipped with a contin uous recorder. Although the organic monitoring

would have CEMS related equipment installed, it is only an option and is dependent on the

method of compliance and control device; it is unlikely that faci lities will use this method of

compliance due to cost, and would likely use other options instead (e.g., temperature

monitoring). Due to the amount of unknown variables, for this an alysis it was assumed that no

equipment is installed which would faci litate the installation of GHG CEMS.

# 59 Summary of Available Data on Fac ilities Reporting the Use of CEMS

No facilities reported the use of CEMS to the GHGRP. Subpart E facilities may also use an N 2 

# O

CEMS alternative monitoring optio n provided approval is granted.

Subpart E CEMS Count

Table E-2 summarizes the actual data collected for facilities using N 2 

# O CEMS and non-GHG

CEMS. No facilities were id entified with pre-existing N 2 

# O CEMS and CO 2 

# CEMS are not

required for this subpart. No assumption could be made for a potential count based on lack of

information on control devices.

Table E-2. Subpart E CEMS Counts

Basis CO 2 

# CEMS for the

GHGRP Reporting non-CO 2



# GHG CEMS for the

GHGRP Reporting non-GHG CEMS for

Other EPA Programs

Actual Potential a



# Facilities 0 0 NA NA

Units 0 0 NA NA

NA = No information available.

a 

# Potential facilities or process units that may have equipment installed that could be modified for use in the GHGRP.

# 60 Appendix B. Aluminum Production – Subpart F

Industry Background

Based on 2011 annual report submissions, there we re 10 facilities that reported to GHGRP under

subpart F.

Under subpart F, facilities estimate CF 4 

# and C 2 

# F 6 

# process emissions from anode effects in all

prebake and Søderberg electrolysis cells combined. Facilities also estimate CO 2 

# emissions from

anode consumption and on- site anode baking. For CF 4 

# emissions, facilities must calculate the

emissions using a mass balance approach. Emissions of C 2 

# F 6 

# must be calculated from the CF 4 

# emissions using a tested ratio of C 2 

# F 6 

# to CF 4 

# production. For CO 2 

# emissions, facilities may either

use a mass balance approach for separate proces s and combustion emissions, or use a CEMS to

determine combined process and combustion emissions.

Applicable NSPS and NESHAP for Aluminum Plants

Table F-1. Applicable NESHAP and NSPS Rules

NESHAP/NSPS Subparts

Reviewed Monitoring Required

by the NESHAP or

NSPS Would Monitoring

Equipment Relevant to

Part 98 be Installed to

Comply With NESHAP

or NSPS? Were Data on

CEMS Counts

Available in

NESHAP or

NSPS docket?

Subpart S—NSPS for Primary

Aluminum Reduction Plants (No relevant monitoring

requirements) No No

Subpart LL—NESHAP for Primary

Aluminum Reduction Plants (No relevant monitoring

requirements) No No



# The applicable NESHAP and NSPS for this subpar t do not require monitoring which is related to

CEMS equipment and would thus not f acilitate the instal lation of GHG CEMS.

Summary of Available Data on Fac ilities Reporting the Use of CEMS

No data on CEMS usage in other EPA programs that would be applicable to subpart F facilities

were available. A majority of the control de vices used to comply with the NESHAP are

scrubbers which do not typically require monitori ng relevant to CEMS. No facilities reported the

use of CEMS to the GHGRP

Subpart F CEMS Count

Table F-2 summarizes the actual data collected for facilities using CO 2 

# CEMS, non-CO 2 

# GHG

CEMS, and non-GHG CEMS. No facilities were identified with pre-existing CEMS. No

assumption could be made for a potential count ba sed on lack of informa tion on control devices.

# 61 Table F-2. Subpart F CEMS Counts

Basis CO 2 

# CEMS for

GHGRP Reporting non-CO 2



# GHG CEMS for

GHGRP Reporting non-GHG CEMS for

Other EPA Programs

Actual Potential a



# Facilities 0 0 NA NA

Units 0 0 NA NA

NA = No information available.

a 

# Potential facilities or process units that may have equipment installed that could be modified for use in the GHGRP.

# 62 Appendix B. Ammonia Manufacturing – Subpart G

Industry Background

Based on 2011 annual report submissions, there we re 22 facilities that reported to GHGRP under

subpart G.

Under subpart G, facilities estimate CO 2 

# process emissions from each ammonia manufacturing

unit, and CO 2 

# emissions collected and either used on-si te or transferred off-site following the

requirements of subpart PP (CO 2 

# suppliers). For estimating CO 2 

# process emissions, facilities may

either use a mass balance approach or use a CEMS.

Applicable NSPS and NESHAP for Ammonia Manufacturers

There is no NSPS or NESHAP specifically ap plicable to ammonia manufacturers.

Summary of Available Data on Fac ilities Reporting the Use of CEMS

No facilities reported the use of CEMS to the GHGRP.

Subpart G CEMS Count

Table G-1 summarizes the actual data collected for facilities using CO 2 

# CEMS, non-CO 2 

# GHG

CEMS, and non-GHG CEMS. No facilities we re identified with pre-existing CO 2 

# CEMS. No

assumption could be made for a potential count ba sed on lack of information on control devices

and monitoring requirements.

Table G-1. Subpart G CEMS Counts

Basis CO 2 

# CEMS for

GHGRP Reporting non-CO 2



# GHG CEMS for

GHGRP Reporting non-GHG CEMS for

Other EPA Programs

Actual Potential a



# Facilities 0 0 NA NA

Units 0 0 NA NA

NA = No information available.

a 

# Potential facilities or process units that may have equipment installed that could be modified for use in the GHGRP.

# 63 Appendix B. Cement Production – Subpart H

Industry Background

The Portland Cement Association’s 2004 plant level su mmary included 107 integrated cement plants that

house both kilns for producing clinker and mills for grinding cement from clinker. This latter number

excludes plants that only grind clinker and do not have kilns. The ‘Summary of Environmental and Cost

Impacts for Final Portland Cement NESHAP and NSPS’ (August 6, 2010) estimates there are 100 plants

with 140 kilns. Based on 2011 annual report submissi ons, there were 96 facilities that reported to GHGRP

under subpart H. These counts are used for the total facility and total unit counts (96 plants with 140

kilns).

Under subpart H, facilities estimate CO 2 

# process emissions from calcination in each kiln and CO 2 

# combustion emissions from each kiln. They ar e also required to estimate and report CH 4 

# and N 2 

# O

combustion emissions from each kiln. For CO 2 

# emissions, facilities may either use a mass balance

approach for separate process and combustion emissions , or use a CEMS to determine combined process

and combustion emissions.

Applicable NSPS and NESHAP for Cement Plants

Table H-1. Applicable NESHAP and NSPS Rules

NESHAP/NSPS Subparts

Reviewed Monitoring Required by the

NESHAP or NSPS Would

Monitoring

Equipment

Relevant to Part

98 be Installed to

Comply With

NESHAP or

NSPS? Were Data on

CEMS Counts

Available in

NESHAP or

NSPS docket?

Subpart LLL

— NESHAP for the

Portland Cement Manufacturing

Industry a 

# Hg CEMS, PM CEMS, THC CEMS;

HCl CEMS if not using a scrubber;

Flow rate monitor if using a PM or

Hg CEMS. Yes No

Subpart EEE

— NESHAP for

Hazardous Waste Combustors

(applies to both major and area

sources) CO CEMS or THC CEMS, both

using an O 2 

# CEMS to correct to

constant O 2



# . Yes No

Subpart F

— NSPS for Portland

Cement Plants PM CEMS, NO X 

# CEMS, SO 2



# CEMS, including flow a rate monitor

to determine mass emission rates.

(CEMS requirements apply only to

kilns constructed, reconstructed, or

modified after 2008) Yes No

a 

# Applies to each kiln includ ing alkali bypasses at all major and area so urces, except for kiln s that burn hazardous

waste and are subject to and regulated under 40 CFR 63, subpart EEE.

# 64 Summary of Available GHGRP and Other Da ta on Facilities Reporting the Use of CEMS



# Table H-2. CEMS Data from Databases

GHGRP Cement NSPS Database

Count of Facilities with CO 2



# CEMS/Total Count of CO 2 

# CEMS Total Kiln Count/Count of Kilns with

CEMS; Total Facility Count/Count of

Facilities with non-CO 2 

# CEMS

82/112 121/50; 64/36



#  The cement NSPS database only provides CEMS counts for SO 2 

# , NO X 

# , and THC CEMS, while

data on Hg, PM, and HCl CEMS were not provided. As such, the count fro m the cement database

is a low estimate.

 In comparison to the cement database, the GHGR P database contains an additional 46 facilities

with CEMS data.

 From the ‘Summary of Environmental and Cost Impacts for Final Portland Cement NESHAP and

NSPS’ (August 6, 2010) there ar e 100 plants with 140 kilns.

 The data from GHGRP and the cement database ar e combined for the recommended CEMS count

to provide both a facility and unit level estimate.

 Since Hg, PM, and THC CEMS are applicable according to the NESHAP, although

documentation for this is not available, we also assumed that all kilns have CEMS for a potential

estimate.

Subpart H CEMS Count

Table H-3 summarizes the actual data co llected for facilities and units using CO 2 

# CEMS, non-CO 2 

# GHG

CEMS, and non-GHG CEMS. The table also shows a potential estimate of CEMS usage based on

assumptions regarding the applicability of NSPS and NESHAP requirements.



# Table H-3. Subpart H Facility and Unit CEMS Counts

Basis CO 2 

# CEMS for

GHGRP Reporting non-CO 2



# GHG CEMS for

GHGRP Reporting non-GHG CEMS for

Other EPA Programs

Actual Potential f



# Facilities 82 a 

# 0 c 

# 0 c 

# 14 d



# Units 112 b 

# 0 c 

# 0 c 

# 28 e



# NA = No estimate is available.

a 

# Number of facilities reporting to GHGRP in 2011 that they are using a CEMS to report CO 2 

# emissions.

b 

# The total number of CO 2 

# CEMS at the facilit ies which reported CO 2 

# CEMS.

c 

# No units or facilities are known to be using non-CO 2 

# GHG CEMS (e.g., for CH 4 

# or N 2 

# O).

d 

# Based on assuming that all kilns will have a non-GHG CE MS to comply with the NESHAP, and using 96 as the

number of operating plants, minus the 82 that reported to GHGRP that they are using GHG CEMS.

e 

# Based on assuming that all kilns will have a non-GH G CEMS to comply with the NESHAP, and using the

estimated number of units (140) in the “Summary of Environmental and Cost Impacts for Final Portland 

# Cement

NESHAP and NSPS” (August 6, 2010), minus the 112 that reported to GHGRP that they are using GHG CEMS.

f 

# Potential facilities or process units that may have equipment installed that could be modified for use in the GHGRP.

# 65 Appendix B. Ferroalloy Production – Subpart K

Industry Background

Based on 2011 annual report submissions, there we re 10 facilities that reported to GHGRP under

subpart K.

Under subpart K, facilities estimate CO 2 

# process emissions from each electric arc furnace that is

used for any type of ferroalloy produ ction. Facilities also estimate CH 4 

# emissions from each

electric arc furnace that is used for the producti on of silicon metal or ferrosilicon (65%, 75%, or

90%). For estimating CO 2 

# process emissions, facilities may either use a mass balance approach

or use a CEMS. Emissions of CH 4 

# must be estimated by multiplying the annual production of

silicon metal or ferrosilicon and applying an appl icable emission factor provided in the subpart.

Applicable NSPS and NESHAP for Ferroalloy Plants

Table K-1. Applicable NE SHAP and NSPS Rules

NESHAP/NSPS Subparts Reviewed Monitoring Required

by the NESHAP or

NSPS Would

Monitoring

Equipment

Relevant to Part

98 be Installed to

Comply With

NESHAP or

NSPS? Were Data on

CEMS Counts

Available in

NESHAP or

NSPS docket?

Subpart Z—NSPS for Fe rroalloy Production

Facilities To ensure furnace hood

capture efficiency,

sources must monitor

volumetric flow rate in

ducts from furnace

hoods No No

Subpart XXX—NESHAP for Ferroalloys

Production: Ferromanganese and

Silicomanganese If a source has a venturi

scrubber, the source has

the option of monitoring

the flow rate through

each separately ducted

hood or at the inlet to the

control device No No

Subpart YYYYYY—NESHAP for Area

Sources: Ferroalloys Production Facilities (No relevant monitoring

requirements) No No



# While monitoring of flow rate is required, the location of the flow monitors is not appropriate for

monitoring flow as it relates to CEMS. For this analysis it was assumed that no equipment is

installed which would facilitate the installation of GHG CEMS.

Summary of Available Data on Fac ilities Reporting the Use of CEMS

No facilities reported the use of CEMS to the GHGRP.

Subpart K CEMS Count

# 66 Table K-2 summarizes the actual data collected for facilities using CO 2 

# CEMS, non-CO 2 

# GHG

CEMS, and non-GHG CEMS. No facilities were identified with pre-existing CEMS. No

assumption could be made for a potential count ba sed on lack of informa tion on control devices.

Table K-2. Subpart K CEMS Counts

Basis CO 2 

# CEMS for

GHGRP Reporting non-CO 2



# GHG CEMS for

GHGRP Reporting non-GHG CEMS for

Other EPA Programs

Actual Potential a



# Facilities 0 0 NA NA

Units 0 0 NA NA

NA = No information available.

a 

# Potential facilities or process units that may have equipment installed that could be modified for use in the GHGRP.

# 67 Appendix B. Fluorinated Gas Production – Subpart L

Industry Background

Based on 2011 annual report submissions, there we re 16 facilities that reported to GHGRP under

subpart L.

Under subpart L, facilities estim ate emissions of HFCs, PFCs, SF 6 

# , NF 3 

# , and HFEs from each

fluorinated gas production process and all fluorin ated gas production processes combined, each

fluorinated gas transformation pro cess that is not a part of a fl uorinated gas production process,

each fluorinated GHG destruction process that is not a part of a fl uorinated gas production

process, and venting of residual fluorinated GHGs from contains returned to the field. For

estimating fluorinated GHG emissions, facilities must use either a mass balance approach or an

emission factor or emission calculator factor approach.

Applicable NSPS and NESHAP for Fluorinated Gas Production Plants

Table L-1. Applicable NESHAP and NSPS Rules

NESHAP/NSPS Subparts Reviewed Monitoring Required

by the NESHAP or

NSPS Would

Monitoring

Equipment

Relevant to Part

98 be Installed to

Comply With

NESHAP or

NSPS? Were Data on

CEMS Counts

Available in

NESHAP or

NSPS docket?

Subpart FFFF—NESHAP for Miscellaneous

Organic Chemical Manufacturing CEMS is option; CPMS

required dependent on

control device Yes No



# Subpart L facilities may have CEMS installed to monitor HF emissi ons. However, this is only an

alternative and no data were provided to determ ine how many (if any) would comply using this

method. Since more economical options are availabl e it is not anticipated any facilities would

comply using CEMS. In addition, CPMS requirement s would not be applicab le to installation of

CEMS equipment (e.g., CPMS includes monito ring temperature or liquid flow rate).

Summary of Available Data on Fac ilities Reporting the Use of CEMS

No facilities reported the use of CEMS to the GHGRP. From the response to comments

document for Subpart L proposal, th ere was a specific request for allowance of CEMS to monitor

fluorinated gases. The commenter stated that FTIR CEMS were a mature technology and were

currently used in the fluorinated gas manuf acturing industry. Specifi c discussion on current

installations was provided with discussion on how all equipment was able to withstand the

corrosive environment. The commenter stated th at five FTIR CEMS were installed at this

facility. Note that discussion on CEMS installations was specific to a particular facility; the

commenter did not imply that all facilities used CEMS. In the EPA’s response it was noted that

CEMS would not be required part ly due to the unknown costs.

Subpart L CEMS Count

# 68 Table L-2 summarizes the actual data collected for facilities using CO 2 

# CEMS, non-CO 2 

# GHG

CEMS, and non-GHG CEMS. Based on the public comm ent, one facility was identified as

having a CEMS installed to measure fluorinated gases. No other data on CEMS installations

were available.

Table L-2. Subpart L CEMS Counts

Basis CO 2 

# CEMS for

GHGRP Reporting non-CO 2



# GHG CEMS for

GHGRP Reporting non-GHG CEMS for

Other EPA Programs

Actual Potential a



# Facilities 0 1 b 

# NA NA

Units 0 5 b 

# NA NA

NA = No information available.

a 

# Potential facilities or process units that may have equipment installed that could be modified for use in the GHGRP.

b 

# Counts based on response to subpart L comments, not on data reported to GHGRP. See discussion on previous

page.

# 69 Appendix B. Glass Production – Subpart N

Industry Background

Based on 2011 annual report submissions, there we re 110 facilities that reported to GHGRP

under subpart N.

Under subpart N, facilities estimate CO 2 

# process emissions from each continuous glass melting

furnace and CO 2 

# combustion emissions from each continuous glass melting furnace. They are

also required to estimate and report CH 4 

# and N 2 

# O combustion emissions from each continuous

glass melting furnace. For CO 2 

# emissions, facilities may either use a mass balance approach for

separate process and combustion emissions, or us e a CEMS to determine combined process and

combustion emissions.

Applicable NSPS and NE SHAP for Glass Plants

Table N-1. Applicable NESHAP and NSPS Rules

NESHAP/NSPS Subparts Reviewed Monitoring Required

by the NESHAP or

NSPS Would

Monitoring

Equipment

Relevant to Part

98 be Installed to

Comply With

NESHAP or

NSPS? Were Data on

CEMS Counts

Available in

NESHAP or

NSPS docket?

Subpart CC—NSPS for Glass Manufacturing

Plants (No relevant monitoring

requirements) No No

Subpart PPP—NSPS for Wool Fiberglass

Insulation Manufacturing Plants (No relevant monitoring

requirements) No No

Subpart NNN—NESHAP for Wool Fiberglass

Manufacturing (No relevant monitoring

requirements) No No

Subpart HHHH—NESHAP for Wet-Formed

Fiberglass Mat Production (No relevant monitoring

requirements) No No

Subpart SSSSSS—NESHAP for Glass

Manufacturing Area Sources (No relevant monitoring

requirements) No No

Subpart N—National Emission Standard for

Inorganic Arsenic Emissions From Glass

Manufacturing Plants (No relevant monitoring

requirements)

No No



# The applicable NESHAP and NSPS for this subpar t do not require monitoring which is related to

CEMS equipment and would thus not f acilitate the instal lation of GHG CEMS.

Summary of Available Data on Fac ilities Reporting the Use of CEMS

There were three facilities which reported CO 2 

# CEMS in GHGRP and each only reported one

CEMS.

# 70 Subpart N CEMS Count

Table N-2 summarizes the actual data collected for facilities using CO 2 

# CEMS, non-CO 2 

# GHG

CEMS, and non-GHG CEMS. The only source with da ta regarding CEMS installations was the

CO 2 

# CEMS counts from GHGRP. No assumption could be made for a potential count based on

rule requirements.

Table N-2. Subpart N CEMS Counts

Basis CO 2 

# CEMS for

GHGRP Reporting non-CO 2



# GHG CEMS for

GHGRP Reporting non-GHG CEMS for

Other EPA Programs

Actual Potential c



# Facilities 3 a 

# 0 NA NA

Units 3 b 

# 0 NA NA

NA = No information available.

a 

# Number of facilities reporting to GHGRP in 2011 that they are using a CEMS to report CO 2 

# emissions.

b 

# The total number of CO 2 

# CEMS at the facilit ies which reported CO 2 

# CEMS.

c 

# Potential facilities or process units that may have equipment installed that could be modified for use in the GHGRP.

# 71 Appendix B. HCFC-22 Production and HFC-23 Destruction Plants – Subpart O

Industry Background

Based on 2011 annual report submissions, there were 5 facilities that reported to GHGRP under

subpart O.

Under subpart O, facilities estimate HFC-23 process emissions from all HCFC-22 production

processes and HFC-23 destruction processes at the facility. For estimating HFC-23 process

emissions, facilities must use a mass balance approach for all HCFC-22 production processes

and HFC-23 destruction processes.

Applicable NSPS and NESHAP for HCFC- 22 Production and HFC-23 Destruction Plants

Table O-1. Applicable NE SHAP and NSPS Rules

NESHAP/NSPS Subparts Reviewed Monitoring Required

by the NESHAP or

NSPS Would

Monitoring

Equipment

Relevant to Part

98 be Installed to

Comply With

NESHAP or

NSPS? Were Data on

CEMS Counts

Available in

NESHAP or

NSPS docket?

Subpart FFFF—NESHAP for Miscellaneous

Organic Chemical Manufacturing CEMS is option; CPMS

required dependent on

control device Yes No



# Subpart O facilities may have CEMS installed to monitor HF emissi ons. However, this is only an

alternative and no data were provided to determ ine how many (if any) would comply using this

method. Since more economical options are availabl e it is not anticipated any facilities would

comply using CEMS. In addition, CPMS requirement s would not be applicab le to installation of

CEMS equipment (e.g., CPMS includes monitoring temperature for thermal oxidizers which was

a control device specifically mentio ned in subpart O rule language).

Summary of Available Data on Fac ilities Reporting the Use of CEMS

No facilities reported the use of CEMS to the GHGR P. Of note, subpart L facilities specifically

requested the use of CEMS to measure fluorinat ed gases. However, a similar request was not

made for subpart O. Since FTIR CEMS were show n to measure fluorinated gases in the Subpart

L comments, it may also be feasible for subpart O. The ability of the CEMS to directly measure

HFC-23 was not discussed and as such its applicability to subpart O is unknown.

# 72 Subpart O CEMS Count

Table O-2 summarizes the actual data collected for facilities using CO 2 

# CEMS, non-CO 2 

# GHG

CEMS, and non-GHG CEMS. No facilities were identified with pre-existing CEMS. No

assumption could be made for a potential count based on lack of information.

Table O-2. Subpart O CEMS Counts

Basis CO 2 

# CEMS for

GHGRP Reporting non-CO 2



# GHG CEMS for

GHGRP Reporting non-GHG CEMS for

Other EPA Programs

Actual Potential a



# Facilities 0 0 NA NA

Units 0 0 NA NA

NA = No information available.

a 

# Potential facilities or process units that may have equipment installed that could be modified for use in the GHGRP.

# 73 Appendix B. Hydrogen Production – Subpart P

Industry Background

Based on 2011 annual report submissions, there we re 103 facilities that reported to GHGRP

under subpart P.

Under subpart P, facilities estimate CO 2 

# process and combustion emissions from each hydrogen

production unit. CO 2 

# collected and either used on site or transferred off site must also be

estimated. Facilities also estimate CH 4 

# and N 2 

# O combustion emissions from each hydrogen

production unit. For CO 2 

# emissions, facilities may either use a mass balance approach for

separate process and combustion emissions, or us e a CEMS to determine combined process and

combustion emissions.

Applicable NSPS and NESHAP for Hydrogen Production Plants

Table P-1. Applicable NESHAP and NSPS Rules

NESHAP/NSPS Subparts Reviewed Monitoring Required

by the NESHAP or

NSPS Would

Monitoring

Equipment

Relevant to Part

98 be Installed to

Comply With

NESHAP or

NSPS? Were Data on

CEMS Counts

Available in

NESHAP or

NSPS docket?

Subpart CC—NESHAP for Petroleum

Refineries (No relevant monitoring

requirements) No No



# The applicable NESHAP for this subpart does no t require monitoring which is related to CEMS

equipment and would thus not facili tate the installation of GHG CEMS.

Summary of Available Data on Fac ilities Reporting the Use of CEMS

There were three facilities which reported CO 2 

# CEMS in GHGRP and each reported only one

CEMS.

Subpart P CEMS Count

Table P-2 summarizes the actual data collected for facilities using CO 2 

# CEMS, non-CO 2 

# GHG

CEMS, and non-GHG CEMS. The only source with da ta regarding CEMS installations was the

CO 2 

# CEMS counts from GHGRP. No assumption could be made for a potential count based on

rule requirements.

Table P-2. Subpart P CEMS Counts

Basis CO 2 

# CEMS for

GHGRP Reporting non-CO 2



# GHG CEMS for

GHGRP Reporting non-GHG CEMS for

Other EPA Programs

Actual Potential c



# Facilities 3 a 

# 0 NA NA

Units 3 b 

# 0 NA NA

# 74 NA = No information available.

a 

# Number of facilities reporting to GHGRP in 2011 that they are using a CEMS to report CO 2 

# emissions.

b 

# The total number of CO 2 

# CEMS at the facilit ies which reported CO 2 

# CEMS.

c 

# Potential facilities or process units that may have equipment installed that could be modified for use in the GHGRP.

# 75 Appendix B. Iron and Steel Production – Subpart Q

Industry Background

The iron and steel production source category under s ubpart Q consists of facilities with any of the

following processes:

 Taconite iron ore processing.

 Integrated iron and steel manufacturing (production of steel from iron ore or iron ore pellets).

 Coke making not co-located with an integrated iron and steel manufacturing process.

 Electric arc furnace (EAF) steelmaking not co-lo cated with an integrated iron and steel

manufacturing process.

Under subpart Q, process CO 2 

# emissions are estimated from the following processes at an iron and steel

facility:

 Taconite indurating furnaces

 Basic oxygen process furnaces (BOPF)

 Non-recovery coke oven batteries

 Sintering process

 Electric arc furnaces (EAF)

 Argon-oxygen decarburization (AOD) vessels

 Direct reduction ironmaking (DRI) furnaces

Facilities are required to determine process CO 2 

# emissions using either a carbon mass balance method, a

site-specific emission factor, or by a CO 2 

# CEMS that meets the Tier 4 calculation methodology

requirements of subpart C. Facilities are not required to determine CH 4 

# , N 2 

# O or other process GHG

emissions from the sources subject to subpart Q. For other stationary combustion units located at iron and

steel facilities, the facility must estimate and report GHG emissions under subpart C.

Based on 2011 annual report submis sions, there were 128 facilities that reported to GHGRP under subpart

Q.

Applicable NSPS and NESHAP for Iron and Steel Facilities

The NSPS and NESHAP were reviewed that are a pplicable to the processes for which GHG emissions

must be determined under subpart Q. We evaluated whether complying with the monitoring requirements

in those rules would require the use of a non-GHG or GHG CEMS that could be used to estimate GHG

emissions, or that would require associated equipmen t, such as flow meters, that would facilitate and

reduce the cost of using a GHG CEMS to comply with subpart Q. The results of that analysis are

summarized in Table Q-1.

# 76 Table Q-1. Summary of NSPS and NESHAP Monitori ng Requirements Applicab le to Subpart Q Processes

and Facilities

Iron and Steel

Process Category Applicable

NSPS or

NESHAP Relevant Monitoring Required by

the NSPS or NESHAP Would Monitoring

Equipment Relevant

to Part 98 be

Installed to Comply

With NSPS or

NESHAP? Were Data on

CEMS Counts

Available in

NESHAP or

NSPS docket?

Taconite

indurating

furnaces 40 CFR 63,

subpart RRRRR

(major sources) (No relevant monitoring requirements)

No No

Basic oxygen

process furnaces 40 CFR 63,

subpart FFFFF a



# (major sources) To ensure furnace hood capture

efficiency, sources have the option to

monitor volumetric flow rate in ducts

from furnace hoods or at the inlet to

the control device; or to monitor

system fan amperes and damper

position. Some facilities may

monitor flow rate, but

the flow rate monitors

probably would not

meet the specifications

for a CEMS flow

monitor. No

Non-recovery

coke oven

batteries 40 CFR 63,

subpart L

(area and major

sources) (No relevant monitoring requirements)

No No

40 CFR 63,

subpart CCCCC

(major sources) Pushing operations capture hoods:

monitor volumetric flow rate at inlet

to control, monitor system fan

amperes, or monitor static pressure in

capture device. Some facilities may

monitor flow rate, but

the flow rate monitors

probably would not

meet the specifications

for a CEMS flow

monitor. No

Sintering process 40 CFR 63,

subpart FFFFF a



# (major sources) To ensure furnace hood capture

efficiency, sources have the option to

monitor volumetric flow rate in ducts

from furnace hoods or at the inlet to

the control device; or to monitor

system fan amperes and damper

position. Some facilities may

monitor flow rate, but

the flow rate monitors

probably would not

meet the specifications

for a CEMS flow

monitor. No

Electric arc

furnaces (EAF) 40 CFR 60,

subparts AA

and AAa To ensure EAF fu rnace hood capture

efficiency, sources have the option to

monitor volumetric flow rate in ducts

from furnace hoods or at the inlet to

the control device; or to monitor

system fan amperes and damper

position. Flow rate monitors only need

to have ±10% accuracy and may be

calibrated according to manufacturer’s

specifications. Flow monitors

specified by AA and

AAa probably would

not meet the

specifications for a

CEMS flow monitor. No

40 CFR 63,

subpart

YYYYY

(area sources) (No relevant monitoring requirements)

No No

Argon-oxygen

decarburization

vessels 40 CFR 60,

subpart AAa To ensure hood capture efficiency,

sources have the option to monitor

volumetric flow rate in ducts from

furnace hoods or at the inlet to the

control device; or to monitor system

fan amperes and damper position. Flow monitors

specified by AAa

probably would not

meet the specifications

for a CEMS flow

monitor. No

# 77 Flow rate monitors only need to have

±10% accuracy and may be calibrated

according to manufacturer’s

specifications.

40 CFR 63,

subpart

YYYYY

(area sources) (No relevant monitoring requirements)

No No

Direct reduction

furnaces No applicable NSPS or NESHAP were identified

a 

# 40 CFR 63, subpart FFFFF also regulates emissions from st eel making blast furnaces, but these are not included in

the processes in 40 CFR part 98, subpart Q. Subpart Q includes blast furnaces among th e units that produce GHG

emissions only from fuel combustion and not from raw mate rials. Therefore, GHG emissions would be estimated

under subpart C and not under subpart Q.

None of the applicable NSPS or NESHAP required the use of monitoring equipment that could be used as a GHG

CEMS, or that would facilitate the use of GHG CEMS. As shown in Table Q-2, some of the rules included an

option to monitor volumetric flow rates in ducts to ensure that a sufficient vol ume of air is being drawn into furnace

hoods to maintain good capture efficiency. These same rules also included an option to monitor system fan amperes

and damper position as an alternative to flow rate. It is not known if the flow rate monitors used to comply would

meet the performance specifications needed for a flow ra te monitor used as part of a GHG CEMS, either based on

location or on the accuracy and calibration requirements. Furt hermore, the applicable rules do not specify that the

flow rate monitors meet any applicable EPA performan ce specification, such as EPA Performance Specification 6

for flow rate, or be calibrated against an EPA stack tes ting reference method. Therefore, we could assume that these

rules do not establish monitoring requirements that would f acilitate the use of CEMS to determine GHG emissions.

Summary of Available GHGRP Data on Facilities Reporting the Use of CEMS

A total of 11 subpart Q facilities have reported to GHGRP as using a CO 2 

# CEMS with a total of 14 CEMS. These

11 facilities are owned by two companies; two faciliti es are owned by ArcelorMittal and nine by Nucor.

 One of the ArcellorMittal facilities (Indiana) is an integr ated steel facility, and the other (Pennsylvania) is

an EAF facility, based on online company information.

 The nine facilities owned by Nucor all appear to be EAF facilities, based on online company information.

 The non-CBI information provided by the EPA from GHGRP does not indicate which process units at each

facility are using a CEMS to determine GHG emissions, or the number of units.

 We assume that the majority of process units with CEMS are EAFs or AODs, because these are the only

units present at EAF facilities for which GHG emissi ons must be determined under subpart Q.

 We do not know which units at the ArcellorMittal facility are using a CEMS.

# 78 Subpart Q CEMS Count

Table Q-2 summarizes the actual data co llected for facilities and units using CO 2 

# CEMS, non-CO 2 

# GHG

CEMS, and non-GHG CEMS. The table also shows a potential estimate of CEMS usage based on

assumptions regarding the applicability of NSPS and NESHAP requirements and using the background

information.

Table Q-2. Subpart Q CEMS Counts

Basis CO 2 

# CEMS for

GHGRP Reporting non-CO 2



# GHG CEMS for

GHGRP Reporting non-GHG CEMS for

Other EPA Programs

Actual Potential c



# Facilities 11 a 

# 0 NA NA

Units 14 b 

# 0 NA NA

NA = No information available.

a 

# Number of facilities reporting to GHGRP in 2011 that they are using a CEMS to report CO 2 

# emissions.

b 

# The total number of CO 2 

# CEMS at the facilit ies which reported CO 2 

# CEMS.

c 

# Potential facilities or process units that may have equipment installed that could be modified for use in the GHGRP.

# 79 Appendix B. Lead Production – Subpart R

Industry Background

Based on 2011 annual report submissions, there we re 13 facilities that reported to GHGRP under

subpart R.

Under subpart R, facilities estimate CO 2 

# process emissions from each smelting furnace and CO 2 

# combustion emissions from each smelting furnace. Th ey are also required to estimate and report

CH 4 

# and N 2 

# O combustion emissions from each smelting furnace. For CO 2 

# emissions, facilities

may either use a mass balance approach for separate process and combustion emissions, or use a

CEMS to determine combined process and combustion emissions.

Applicable NSPS and NESHAP for Lead Plants

Table R-1. Applicable NESHAP and NSPS Rules

NESHAP/NSPS Subparts Reviewed Monitoring Required

by the NESHAP or

NSPS Would Monitoring

Equipment Relevant to

Part 98 be Installed to

Comply With

NESHAP or NSPS? Were Data on

CEMS Counts

Available in

NESHAP or

NSPS docket?

Subpart L—NSPS for Secondary Lead

Smelters (No relevant monitoring

requirements) No No

Subpart R—NSPS for Primary Lead

Smelters SO 2 

# CEMS required for

all primary lead

smelters Yes No

Subpart X—NESHAP from Secondary

Lead Smelting (No relevant monitoring

requirements) No No

Subpart TTT—NESHAP for Primary

Lead Smelting Sources must monitor

volumetric flow rate

through each separately

ducted hood or at the

inlet to the control

device Yes No



# The NSPS and NESHAP for secondary lead sme lters do not contain a ny relevant monitoring

requirements. The NSPS for primary lead smelters requires SO 2 

# monitoring, but applies only to

primary lead smelters constructed after Oct ober 16, 1974. There have be en no lead smelters

constructed since 1974. Specifics of the one primary lead smelter in the United States are not

known, and thus we are not certain if the facility operates an SO 2 

# CEMS.

Summary of Available Data on Fac ilities Reporting the Use of CEMS

No facilities reported the use of CEMS to the GHGRP.

Subpart R CEMS Count

Table R-2 summarizes the actual data collected for facilities using CO 2 

# CEMS, non-CO 2 

# GHG

CEMS, and non-GHG CEMS. No facilities we re identified with pre-existing CO 2 

# CEMS. No

# 80 assumption could be made for a potential count ba sed on lack of information on control devices

and monitoring requirements.

Table R-2. Subpart R CEMS Counts

Basis CO 2 

# CEMS for

GHGRP Reporting non-CO 2 

# GHG

CEMS for GHGRP Reporting non-GHG CEMS for

Other EPA Programs

Actual Potential a



# Facilities 0 0 NA NA

Units 0 0 NA NA

NA = No information available.

a 

# Potential facilities or process units that may have equipment installed that could be modified for use in the GHGRP.

# 81 Appendix B. Lime Manufacturing – Subpart S

Industry Background

Based on 2011 annual report submissions, there we re 73 facilities that reported to GHGRP under

subpart S.

Under subpart S, facilities estimate CO 2 

# process emissions from each lime kiln and CO 2 

# combustion emissions from each lime kiln. They ar e also required to estimate and report CH 4



# and N 2 

# O combustion emissions from each lime kiln. For CO 2 

# emissions, facilities may either use

a mass balance approach for separate process and combustion emissions, or use a CEMS to

determine combined process and combustion emissions.

Applicable NSPS and NESHAP for Lime Plants

Table S-1. Applicable NESHAP and NSPS Rules

NESHAP/NSPS Subparts Reviewed Monitoring Required

by the NESHAP or

NSPS Would

Monitoring

Equipment

Relevant to Part

98 be Installed to

Comply With

NESHAP or

NSPS? Were Data on

CEMS Counts

Available in

NESHAP or

NSPS docket?

Subpart HH—NSPS for Lime Manufacturing

Plants (No relevant monitoring

requirements) No No

Subpart AAAAA—NESHAP for Lime

Manufacturing Plants (No relevant monitoring

requirements) No No



# The applicable NESHAP and NSPS for this subpar t do not require monitoring which is related to

CEMS equipment and would thus not f acilitate the instal lation of GHG CEMS.

Summary of Available Data on Fac ilities Reporting the Use of CEMS

One facility was reported to use CO2 CEMS in th e 2011 GHGRP. The RIA for part 98 identified

that all facilities would meet the Tier 4 criter ia to install CEMS. Therefore, the remaining 72

facilities are assumed to meet Tier 4 criteria.

Subpart S CEMS Count

Table S-2 summarizes the actual data collected for facilities using CO 2 

# CEMS, non-CO 2 

# GHG

CEMS, and non-GHG CEMS. The table also shows a potential estimate of CEMS usage based

on assumptions regarding the applicability of NSPS and NESHAP requirements and using the

background information.

Table S-2. Subpart S CEMS Counts

Basis CO 2 

# CEMS for

GHGRP Reporting non-CO 2



# GHG CEMS for Reporting non-GHG CEMS for

Other EPA Programs

# 82 GHGRP Actual Potential b



# Facilities 1 a 

# 0 NA 72

Units 0 0 NA NA

NA = No information available.

a 

# Number of facilities that reported to GHGRP in 2011 that they were using a CEMS to report CO 2 

# emissions.

b 

# Potential facilities or process units that may have equipment installed that could be modified for use in the GHGRP.

# 83 Appendix B. Miscellaneous Uses of Carbonates Facilities – Subpart U

Industry Background

Based on 2011 annual report submissions, there we re 18 facilities that reported to GHGRP under

subpart U.

Under subpart U, facilities estimate CO 2 

# process emissions for all miscellaneous carbonate use at

the facility. For estimating CO 2 

# process emissions, facilities mu st use a mass balance approach.

Applicable NSPS and NESHAP for th e Miscellaneous Use of Carbonates

There is no NSPS or NESHAP specifically appl icable to miscellaneous use of carbonates.

Summary of Available Data on Fac ilities Reporting the Use of CEMS

No facilities reported the use of CEMS to the GHGRP.

Subpart U CEMS Count

Table U-1 summarizes the actual data collected for facilities using CO 2 

# CEMS, non-CO 2 

# GHG

CEMS, and non-GHG CEMS. No facilities we re identified with pre-existing CO 2 

# CEMS. No

assumption could be made for a potential count ba sed on lack of information on control devices

and monitoring requirements.

Table U-1. Subpart UCEMS Counts

Basis CO 2 

# CEMS for

GHGRP Reporting non-CO 2 

# GHG

CEMS for GHGRP Reporting non-GHG

CEMS for Other EPA

Programs

Actual Potential a



# Facilities 0 0 NA NA

Units 0 0 NA NA

NA = No information available.

a 

# Potential facilities or process units that may have equipment installed that could be modified for use in the GHGRP.

# 84 Appendix B. Nitric Acid Production – Subpart V

Industry Background

In the TSD for subpart V, the EPA estimated that 45 nitric acid production plants with a total of

65 production units were operating in the United States, based on the 1990-2006 Inventory of

U.S. Greenhouse Gas Emissions and Sinks . These 45 plants are spread across 25 states, and 18 of

the plants qualify as small businesses. Based on 2011 annual report submissions, there were 36

facilities that reported to GHGRP under subpart V.

Under subpart V, facilities estimate N 2 

# O process emissions from each nitric acid train. For N 2 

# O

emissions, facilities may either use a mass balan ce and emission factor approach, or use a CEMS

to directly measure process emissions.

Applicable NSPS and NESHAP for Nitric Acid Plants

Table V-1. Applicable NESHAP and NSPS Rules

NESHAP/NSPS Subparts

Reviewed Monitoring Required by the

NESHAP or NSPS Would Monitoring

Equipment Relevant to

Part 98 be Installed to

Comply With NESHAP

or NSPS? Were Data on

CEMS Counts

Available in

NESHAP or

NSPS docket?

Subpart G—Standards of

Performance for Nitric Acid

Plants NO X 

# CEMS required for units

constructed or modified after

August 17, 1971 Yes No



# Each emission point for nitric acid production shall install NO X 

# CEMS if constructed or

modified after 1971; no alte rnatives are provided.

Summary of Available Data on Fac ilities Reporting the Use of CEMS

Table V-2. Available CEMS Data

1990-2006 Inventory of U.S. GHG Emissions and Sinks (from TSD)

Total Unit Count/Count of Units with NOx CEMS; Total Facility Count/Count of Facilities with NOx

CEMS

65/36; 45/20



# As shown in the TSD to subpart V, several facilities have NO X 

# CEMS installed. Of the 45 nitric

acid production plants, 20 nitric acid production plants employ CEMS for NO X 

# emissions. At

these 20 nitric acid plants ther e are 36 processes which have NO X 

# CEMS; this is approximately

58 percent of the total processe s. It is presumed that the processes which do not have NO X



# CEMS installed were built prior to 1971. No facilities reported the use of CEMS to the GHGRP.

# 85 Subpart V CEMS Count

Table V-3 summarizes the actual data collected for facilities using CO 2 

# CEMS, non-CO 2 

# GHG

CEMS, and non-GHG CEMS. The table also shows a potential estimate of CEMS usage based

on assumptions regarding the applicability of NSPS and NESHAP requirements and using the

background information.

Table V-3. Subpart V CEMS Counts

Basis CO 2 

# CEMS for

GHGRP Reporting non-CO 2



# GHG CEMS for

GHGRP Reporting non-GHG CEMS

for Other EPA Programs

Actual Potential b



# Facilities 0 0 20 a 

# NA

Units 0 0 36 a 

# NA

NA = No information available.

a 

# Based on data reported as a part of the 1990-2006 Inventory of U.S. Greenhouse Gas Emissions and Sinks, which is

shown in the TSD to subpart V. A potential estimate was no t generated since the inventory data were reported by the

facility and presumed to be the actual count of units with NO X 

# CEMS.

b 

# Potential facilities or process units that may have equipment installed that could be modified for use in the GHGRP.

# 86 Appendix B. Petrochemical Production – Subpart X

Industry Background

The petrochemical production subcategory co nsists of each process that produces:

 Acrylonitrile

 Carbon black

 Ethylene

 Ethylene Dichloride

 Ethylene Oxide

 Methanol

Each petrochemical facility must report CO 2 

# process emissions and CO 2 

# , CH 4 

# , and N 2 

# O emissions

generated by combustion of process off-gas in stationa ry combustion units and flares. GHG estimates are

also necessary for CO 2 

# , CH 4 

# , and N 2 

# O emissions from burning supplemental fuel in stationary

combustion units that also burn process off-gas. If Tier 4 criteria are met then CO 2 

# emissions must be

estimated by CEMS, otherwise the mass balance method is required. For CH 4 

# and N 2 

# O the emission

factor method is used. For ethylene processes only CO 2 

# emissions may be estimated using Tier 3 or Tier 4

for combustion of process off-gas.

Based on 2011 annual report submis sions, there were 64 facilities that reported to GHGRP under subpart

X.

Applicable NSPS and NESHAP for Petr ochemical Plants and Facility Counts

Table X-1 shows the applicable NESHAP and N SPS for each facility type. Table X-2 shows the

monitoring required by each of the NESHAP and N SPS and whether this monitoring is relevant to

installing GHG CEMS.

Table X-1. Applicable NESHAP/NSPS to Petrochemical Facilities for Subpart X

Petrochemical Number of facilities Applicable NESHAP/NSPS

NESHAP NSPS

Acrylonitrile 5 Subparts F, G Subparts III, NNN, RRR

Carbon Black 21 Subpart YY

Ethylene 39 Subpart YY Subparts NNN, RRR

Ethylene Dichloride 16 Subparts F, G Subparts III, NNN, RRR

Ethylene Oxide 12 Subparts F, G Subparts III, NNN, RRR

Methanol 5 Subparts F, G Subparts III, NNN, RRR

# 87 Table X-2. Applicable NESHAP and NSPS Rules

NESHAP/NSPS Subparts Reviewed Monitoring Required

by the NESHAP or

NSPS Would

Monitoring

Equipment

Relevant to Part

98 be Installed to

Comply With

NESHAP or

NSPS? Were Data on

CEMS Counts

Available in

NESHAP or

NSPS docket?

(HON)

Subpart F—NESHAP From the Synthetic

Organic Chemical Manu facturing Industry

Subpart G—NESHAP From the Synthetic

Organic Chemical Manuf acturing Industry for

Process Vents, Storage Vessels, Transfer

Operations, and Wastewater Organic monitoring is an

option if a recovery

device is installed for

process vents with a

TRE index value greater

than 1.0 Yes No

Subpart YY—NESHAP for Source

Categories: Generic Maximum Achievable

Control Technology Standards No relevant monitoring

No No

Subpart III—NSPS for Volatile Organic

Compound (VOC) Emissions From the

Synthetic Organic Chemical Manufacturing

Industry (SOCMI) Air Oxidation Unit

Processes If facility complies with

TRE limit (>1 and not

using VOC control

device) and have an

absorber, condenser, or

carbon adsorber then

organic monitoring is

option Yes No

Subpart NNN—NSPS for Volatile Organic

Compound (VOC) Emissions From Synthetic

Organic Chemical Manu facturing Industry

(SOCMI) Distillation Operations If facility complies with

TRE limit (>1 and not

using VOC control

device) and have an

absorber, condenser, or

carbon adsorber then

organic monitoring is

option Yes No

Subpart RRR—NSPS for Volatile Organic

Compound Emissions From Synthetic Organic

Chemical Manufacturing Industry (SOCMI)

Reactor Processes If facility complies with

TRE limit (>1 and not

using VOC control

device) and have an

absorber, condenser, or

carbon adsorber then

organic monitoring is

option Yes No



# The relevant monitoring from both the NESHAP and N SPS is organic monitoring. An organic monitoring

device is used to indicate the concentration level of organic compounds exiting the recovery device based

on a detection principle such as infra-red, photoioniz ation, or thermal conductivity and each is equipped

with a continuous recorder. Although the organic monitoring would have CEMS related equipment

installed, it is only an option and is dependent on the method of compliance and control device; it is

unlikely that facilities will use this method of complia nce due to cost, and would likely use other options

instead (e.g., temperature monitoring). Due to the am ount of unknown variables, for this analysis it was

assumed that no equipment is installed which w ould facilitate the installation of GHG CEMS.

Summary of Available GHGRP Data on Facilities Reporting the Use of CEMS

# 88 There were two facilities which reported CO 2 

# CEMS in GHGRP and each only reported one CEMS. The

products at these two petrochemical facilities were not identified.

Subpart X CEMS Count

Table X-3 summarizes the actual data co llected for facilities and units using CO 2 

# CEMS, non-CO 2 

# GHG

CEMS, and non-GHG CEMS. The only source with da ta regarding CEMS installations was the CO 2



# CEMS counts from GHGRP. No assumption could be made for a potential count based on rule

requirements.

Table X-3. Subpart X CEMS Counts

Basis CO 2 

# CEMS for

GHGRP Reporting non-CO 2



# GHG CEMS for

GHGRP Reporting non-GHG CEMS

for Other EPA Programs

Actual Potential c



# Facilities 2 a 

# 0 NA NA

Units 2 b 

# 0 NA NA

NA = No information available.

a 

# Number of facilities reporting to GHGRP in 2011 that they are using a CEMS to report CO 2 

# emissions.

b 

# The total number of CO 2 

# CEMS at the facilit ies which reported CO 2 

# CEMS.

c 

# Potential facilities or process units that may have equipment installed that could be modified for use in the GHGRP.



# Also note that in comments to the GHGRP, commenters stated that for ethylene plants specifically there

are no CEMS currently installed.

# 89 Appendix B. Petroleum Refineries – Subpart Y

Industry Background

Under subpart Y, petroleum refineries are classified as those which produce gasoline, gasoline blending

stocks, naphtha, kerosene, distillate fuel oils, residua l fuel oils, lubricants, or asphalt. When reporting

their GHG emissions the following processes at each facility must report data for:

 Flares

 Catalytic cracking

 Fluid coking

 Coke calcining

 Delayed coking

 Catalytic reforming

 Sulfur recovery

 Asphalt blowing

 Equipment leaks

 Storage tanks

 Other process vents

 Uncontrolled blowdown systems

 Loading operations

 Stationary combustion

The database developed for the refinery NESHAP cont ains a total of 148 refineries, excluding the 2

refineries in U.S. territories. Based on 2011 annual report submissions, there were 145 facilities that

reported to GHGRP under subpart Y.

Applicable NSPS and NESHAP for Petroleum Re fineries, Refinery Database Counts, and GHG

Reporting Requirements

Table Y-1 provides a general overview of the N ESHAP and NSPS rules applicable to petroleum

refineries and the applicable CEMS requirements. Table Y-2 shows the specific CEMS requirements for

each applicable refinery process (based on NESHAP /NSPS requirements), and also shows the greenhouse

gases which must be reported under subpart Y for each process. Table Y-2 also shows process unit counts

based on information in the petroleum refinery NES HAP database. The petroleum refinery database was

provided by the EPA/OAQPS. Data detailing how many CEMS are installed were not available in the

database, but process unit information was availabl e that correlated with the NESHAP/NSPS rules.

# 90 Table Y-1. Applicable NESHAP and NSPS Rules

NESHAP/NSPS Subparts Reviewed Monitoring Required by the

NESHAP or NSPS

Subpart CC—NESHAP for Petroleum Refineries No relevant monitoring

Subpart UUU—NESHAP for Petroleum Refineries: Catalytic Cracking Units,

Catalytic Reforming Units, and Sulfur Recovery Units Flow rate, CO CEMS, O 2



# monitor

Subpart J—NSPS for Petroleum Refi neries Flow rate, CO CEMS, O 2 

# monitor, SO 2 

# monitor



# Table Y-2. GHGs Reported for Ea ch Refinery Process, Process Unit Counts, and Monitoring

Information from Applic able NESHAP/NSPS Rules

Refinery Process Greenhouse Gases Which Shall

Be Reported For Subpart Y

Facilities Count of Process

Units from

Refinery

NESHAP

Database Is Process

Required in

NESHAP/NSPS

to Have CEMS

Monitoring? Monitoring

Requirements per

NESHAP/NSPS

CO 2 

# CH 4 

# N 2 

# O

Flares Y Y Y 439 N NA

Catalytic Cracking Y Y Y 130 Y CO monitoring if

catalytic cracking unit

catalyst regenerators

were constructed,

reconstructed, or

modified after 1973.

Otherwise monitor O 2 

# , temperature, or

operation of flare pilot.

Flow monitoring

required if modified

before 1973 and control

device is an ESP.

Fluid Coking Y Y Y

132 a 

# N NA

Coke Calcining Y Y Y N NA

Delayed Coking N Y N N NA

Catalytic Reformi ng Y Y Y 120 N NA

Sulfur Recovery Y N N 187 Y SO 2 

# and O 2 

# monitors

Asphalt Blowing Y Y N N NA

Equipment Leaks N Y N 2593 N NA

Storage Tanks N Y N 8107 N NA

Other Process Vents Y Y Y 588 N NA

Uncontrolled

Blowdown Systems N Y N N NA

Stationary Combustion Y Y Y 3228 N NA

Loading Operations N Y N 301 N NA



# Total Count of Process Units 15825

Count of Process Units With Applicable Monitoring 317

Count of Process Units for CEMS Installation 1,580 Includes fluid coking, coke calcining,

catalytic reforming, flares, loading

operations, and other process vents

a 

# The refinery database only provides a count for ‘coking unit vent s’. This count was applied to all processes which refer to co ke

operations.

# 91 The refinery database provided a total facility count of 148 refineries, and contains 317 catalytic cracking

and sulfur recovery units. For catalytic cracking pr ocesses, CO CEMS are only applicable to catalytic

cracking unit catalyst regenerators. Each catalytic cr acking process has an associated catalyst regenerator;

the value of 130 will be used as a potential estimate. The 130 units are at 88 facilities. 187 sulfur recovery

units are in place at 75 facilities; all 187 units must have an SO 2 

# /O 2 

# monitor associated with it. For CEMS

installation cost estimates, a unit count of 1,580 w as used and only considers those processes which are

relevant to CEMS. For example, a CEMS would not be used to monitor equipment leak emissions.

Summary of Available GHGRP and Boiler Data on Facilities Reporting the Use of CEMS

There were 21 facilities that reported the use of CO 2 

# CEMS within GHGRP, with a total of 24 CO 2



# CEMS. From the boiler MACT database, a total of 2, 096 units were reported with 346 of those currently

operating non-GHG CEMS. For the boiler data, it is not known if subpart Y process emissions are

exhausted through the same stacks as boilers and without this determin ation we will not include the boiler

data in the subpart Y CEMS counts.

Subpart Y CEMS Count

Table Y-3 summarizes the actual data co llected for facilities and units using CO 2 

# CEMS, non-CO 2 

# GHG

CEMS, and non-GHG CEMS. The table also shows a potential estimate of CEMS usage based on

assumptions regarding the applicability of NSPS and NESHAP requirements.

Table Y-3. Subpart Y CEMS Counts

Process Basis CO 2 

# CEMS for

GHGRP Reporting nonCO 2 

# GHG CEMS

for GHGRP Reporting non-GHG CEMS for Other

EPA Programs

Actual Potential f



# Catalytic

Cracking and

Sulfur

Recovery Facilities 21 a 

# 0 NA 104 c



# Units 26 b 

# 0 NA 317 d



# All Other

Process Units

(except

stationary

combustion) e 

# Facilities 0 0 NA NA

Units 0 0 NA NA

NA = No information available.

a 

# Number of facilities reporting to GHGRP in 2011 that they are using a CEMS to report CO 2 

# emissions.

b 

# The total number of CO 2 

# CEMS at the facilit ies which reported CO 2 

# CEMS in GHGRP.

c 

# Count of facilities which have catalytic cracking and/or sulfur recovery processes. Some facilities have both.

d 

# Unit count assumes all catalytic cracking processes have catalyst regenerators (130+187), and all will use CEMS to

comply with the NESHAP/NSPS.

e 

# Includes fluid coking, coke calcining, catalytic reforming, asphalt blowing, other process vents. Stationary

combustion units are covered under subpart C.

f 

# Potential facilities or process units that may have equipment installed that could be modified for use in the GHGRP.

# 92 Appendix B. Phosphoric Acid Production – Subpart Z

Industry Background

Based on 2011 annual report submissions, there we re 13 facilities that reported to GHGRP under

subpart Z.

Under subpart Z, facilities estimate CO 2 

# process emissions from each wet-process phosphoric

acid process line. For CO 2 

# emissions, facilities may either us e a mass balance approach or use a

CEMS to directly measure process emissions.

Applicable NSPS and NESHAP for Phosphoric Acid Plants

Table Z-1. Applicable NESHAP and NSPS Rules

NESHAP/NSPS Subparts Reviewed Monitoring Required

by the NESHAP or

NSPS Would

Monitoring

Equipment

Relevant to Part

98 be Installed to

Comply With

NESHAP or

NSPS? Were Data on

CEMS Counts

Available in

NESHAP or

NSPS docket?

Subpart AA—NESHAP From Phosphoric

Acid Manufacturing Plants (No relevant monitoring

requirements) No No

Subpart T—Standards of Performance for the

Phosphate Fertilizer In dustry: Wet-Process

Phosphoric Acid Plants (No relevant monitoring

requirements) No No



# The applicable NESHAP and NSPS for this subpar t do not require monitoring which is related to

CEMS equipment and would thus not f acilitate the instal lation of GHG CEMS.

Summary of Available Data on Fac ilities Reporting the Use of CEMS

No facilities reported the use of CEMS to the GHGRP. Based on the ICR survey responses

associated with NESHAP development, it is un likely that any of the non-combustion processes

use CO 2 

# CEMS. Phosphoric acid process emissions ar e combined with combustion emissions for

calciners and dryers at 7 facilities. The ICR indicates that the 7 measure O 2 

# instead of CO 2



# .

Subpart Z CEMS Count

Table Z-2 summarizes the actual data collected for facilities using CO 2 

# CEMS, non-CO 2 

# GHG

CEMS, and non-GHG CEMS. The table also shows a potential estimate of CEMS usage based

on assumptions regarding the applicability of NSPS and NESHAP requirements and using the

background information.

# 93 Table Z-2. Subpart Z CEMS Counts

Basis CO 2 

# CEMS for

GHGRP Reporting non-CO 2



# GHG CEMS for

GHGRP Reporting non-GHG CEMS for

Other EPA Programs

Actual Potential b



# Facilities 0 0 7 a 

# 7 a



# Units 0 0 NA NA

NA = No information available.

a 

# Counts are based on data reported in the NESHAP ICR responses.

b 

# Potential facilities or process units that may have equipment installed that could be modified for use in the GHGRP.

# 94 Appendix B. Pulp and Paper Manufacturing – Subpart AA

Industry Background

The pulp and paper manufacturing source category und er subpart AA consists of facilities that do the

following:

 Produce market pulp (i.e., stand-alone pulp facilities),

 Manufacture pulp and paper (i.e., integrated facilities),

 Produce paper products from purchased pulp,

 Produce secondary fiber from recycled paper,

 Convert paper into paperboard pr oducts (e.g., containers), or

 Operate coating and laminating processes.

Under subpart AA, process emissions are estimated from the following emission units:

 Chemical recovery furnaces at kraft and soda mills (including recovery furnaces that burn spent

pulping liquor produced by both the kraft and semichemical process).

 Chemical recovery combustion units at sulfite facilities.

 Chemical recovery combustion units at stand-alone semichemical facilities.

 Pulp mill lime kilns at kraft and soda facilities.

 Systems for adding makeup chemicals (CaCO 3 

# , Na 2 

# CO 3 

# ) in the chemical recovery areas of

chemical pulp mills.

Approximately 425 pulp and paper m ills operated stationary combustion units (e.g., boilers, gas turbines,

lime kilns, recovery furnaces, thermal oxidizers) in 2005, based on an industry survey by the National

Council for Air and Stream Improvement (NCASI) (NCA SI 2006). The results of this survey were cited

in the TSD for subpart AA of part 98. The survey also reported the number of units by the process unit

categories that are included in subpart AA. The survey estimated about 400 units would be subject to

GHG emissions reporting under subpa rt AA. Based on 2011 annual re port submissions, there were 110

facilities that reported to GHGRP under subpart AA.

Applicable GHGRP, NSPS, and NESHAP Monitori ng Requirements for Pulp and Paper Facilities



# Table AA-1 summarizes the number of process units identified by the NCASI survey, and also

summarizes the monitoring requirements for pulp a nd paper facilities under subpart AA of part

98, and under the relevant NSPS and NESHAP.

# 95 Table AA-1. Summary of Emission Units and Relevant GHGRP, NSPS, and NESHAP Monitoring

Requirements Applicable to Subpart AA Facilities

Mill Type

Subject to

Subpart AA Process Units

Subject to

Subpart AA GHG to be

Monitored

Under

Subpart AA Estimated

Number

of Units

(NCASI

Survey) a 

# Monitoring

Required by 40

CFR 60,

subpart BB b 

# Monitoring

Required by

40 CFR 63,

subpart S Monitoring

Required by

40 CFR 63,

subpart MM

Kraft or Soda

Mill Each chemical

recovery

furnace CO 2 

# , biogenic

CO 2 

# , CH 4 

# ,

N 2 

# O 168 Total reduced

sulfur (TRS)

CEMS, O 2



# CEMS, percent

volume dry basis

[60.284(a)(2)] No relevant

monitoring No relevant

monitoring

Kraft or Soda

Mill Lime Kilns,

fossil fuel

combustion CO 2 

# , biogenic

CO 2 

# , CH 4 

# ,

N 2 

# O 164 TRS CEMS, O 2



# CEMS, percent

volume dry basis

[60.284(a)(2)] No relevant

monitoring No relevant

monitoring

Sulfite Pulp

Mills Each chemical

recovery

furnace CO 2 

# , biogenic

CO 2 

# , CH 4 

# ,

N 2 

# O 13 No relevant

monitoring No relevant

monitoring No relevant

monitoring

Stand Alone

Semichemical

Mills Each chemical

recovery

furnace CO 2 

# , biogenic

CO 2 

# , CH 4 

# ,

N 2 

# O 12 No relevant

monitoring No relevant

monitoring No relevant

monitoring

Chemical

pulp mills Makeup

chemical

addition to

chemical

recovery area CO 2



# ≤ 55 No relevant

monitoring No relevant

monitoring No relevant

monitoring

Total estimated number of units ≤ 412

a 

# From TSD for subpart AA, Table 3-1, on page 8; based on an industry survey by the National Council for Air and

Stream Improvement (NCASI) (NCASI 2006. Pulp and Paper Mill Emissions of SO 2 

# , NO X 

# , and Particulate Matter

in 2005. NCASI Special Report No. 06-07. December 2006.)

b 

# Applies to any kraft pulp mill facility that commenced construction or modification after September 24, 1976.



# Although the applicable NSPS and NESHAP for the pulp and paper industry do require monitoring using

non-GHG CEMS, information on the number of units perfo rming that monitoring was not available. The

NSPS (subpart BB) requires oxygen monitoring only fo r chemical recovery furnaces and pulp mill lime

kilns at kraft pulp mills. The two Pulp and Pape r NESHAP (subparts S and MM) do not require any

relevant non-GHG CEMS monitoring, except that subpart S allows for an alternative of using a CEMS to

monitor total HAP or methanol emissions, but we do not have information on the number of facilities that

have taken this alternative.

Under the subpart BB NSPS, all of the chemical reco very furnaces and lime kilns at kraft or soda mills

that have been built or modified since September 24, 1976 should have CEMS for total reduced sulfur

(TRS), O 2 

# , and moisture. This could be a maximum of 332 units (168 + 164), based on the information

from the NCASI survey. The presence of a TRS, O 2 

# , and moisture CEMS would mean that these units

would also have the basic CEMS infrastructure in pl ace, such as platforms, sampling lines, and data

# 96 acquisition systems, and this would lower the cost of adding GHG CEMS equipment, such as a CO 2



# analyzer and flow monitor, at these facilities.

Summary of Data on Facilities Reporting the Use of CEMS

Data on the number of affected process units at pulp and paper facilities using CEMS (either GHG or

non-GHG) are available from the GHGRP database, and from data that were collected to develop the

standards for commercial/industrial solid waste incine rators (CISWI) and the boiler and process heater

NESHAP. Table AA-2 summarizes these data for the to tal number of units and those with a CEMS.

Table AA-2. Summary of CEMS Da ta from Other EPA Databases

GHGRP CISWI Database Boiler and Process Heater

NESHAP Database

Count of Facilities Which Reported

CO 2 

# CEMS as Option Within

GHGRP Total Unit Count/Count of Energy

Recovery Units (ERUs) and Kilns

with CEMS; Total Facility

Count/Count of Facilities with nonGHG CEMS Total Unit Count/Count of

Boilers and Process

Heaters with non-GHG

CEMS

-- 13/9; 9/6

None of the units appear to be in the

source category for subpart AA. 533/160



# No facilities reported the use of CEMS to the GHGRP

.

In the CISWI and the boiler and pro cess heater survey data, we can iden tify units that are located at pulp

and paper facilities using the three-digit NAICS (322, paper manufacturing). From the CISWI data we

identified nine energy recovery units (ERUs) or kiln s at pulp and paper facilities that have some sort of

CEMS; however, none of the units appear to be pr ocess units in the source category for subpart AA.

In the boiler and process heater NESHAP database, we identified a total of 533 units at pulp and paper

facilities, and 160 of these units have some sort of CEMS. However, we cannot determine from the

information in those survey data whether any of th ose units are process units in the source category for

subpart AA.

Subpart AA CEMS Count

Table AA-4 summarizes the actual data collected for facilities and units using CO 2 

# CEMS, non-CO 2 

# GHG

CEMS, and non-GHG CEMS. The table also shows a potential estimate of CEMS usage based on

assumptions regarding the applicability of NSPS and NESHAP requirements and using the background

information.

Table AA-4. Subpart AA CEMS Counts

Basis CO 2 

# CEMS for

GHGRP Reporting non-CO 2



# GHG CEMS for

GHGRP Reporting non-GHG CEMS for

Other EPA Programs

Actual Potential b

# 97 Facilities 0 0 NA NA

Units 0 0 266 a 

# 266 a



# NA = No information available.

a 

# The NCASI survey provided process unit data and the 2009 RIA es timated that units were subject to Ti er 4 requirements.

However, these count data and the count for facilities that reported to GHGRP in 2011 (110) could not be directly related.

Therefore, based on the data, unit and facility counts were estimated.

b 

# Potential facilities or process units that may have equipment installed that could be modified for use in the GHGRP.



# Based on the NSPS requirements, a large percentage of subpart AA units are likely to have TRS and O 2 

# CEMS and, therefore, already have some basic infrast ructure for a CEMS that could be used to estimate

GHG emissions with the addition of a flow meter and CO 2 

# analyzer. Similarly, the RIA estimates that a

large portion of the sources will meet Tier 4 requi rements. However, because the number of facilities

reporting to GHGRP (110) is substantially lower th an the number reported through the NCASI survey

(425), an adjustment to the unit data was necessary. It was estimated that each facility would have at least

three units; this is based on data from the NCASI survey . Therefore, 330 total units were estimated for the

110 facilities. Of these, approximately 80% of the units were assumed to have a CEMS installed. This

was calculated as the number of units at kraft and soda mills (168+164 = 332) which may have CEMS to

comply with subpart BB, divided by the total un it count (412). Performing this calculation yields

approximately 266 units with non-GHG CEMS.

# 98 Appendix B. Silicon Carbide Production – Subpart BB

Industry Background

Based on 2011 annual report submissions, there wa s 1 facility that reported to GHGRP under

subpart BB.

Under subpart BB, facilities estimate CO 2 

# and CH 4 

# process emissions from all silicon carbide

process units or furnaces combined. For estimating CO 2 

# process emissions, facilities may either

use a mass balance approach or us e a CEMS. Process emissions of CH 4 

# are estimated using

emission factors relevant to the monthly amount of petroleum coke cons umed at the facility.

Applicable NSPS and NESHAP fo r Silicon Carbide Manufacturers

There is no NSPS or NESHAP specifically appl icable to silicon carbi de manufacturers.

Summary of Available Data on Fac ilities Reporting the Use of CEMS

No facilities reported the use of CEMS to the GHGRP.

Subpart BB CEMS Count

Table BB-1 summarizes the actual data collected for facilities using CO 2 

# CEMS, non-CO 2 

# GHG

CEMS, and non-GHG CEMS. No facilities we re identified with pre-existing CO 2 

# CEMS. No

assumption could be made for a potential count ba sed on lack of information on control devices

and monitoring requirements.

Table BB-1. Subpart BB CEMS Counts

Basis CO 2 

# CEMS for

GHGRP Reporting non-CO 2



# GHG CEMS for

GHGRP Reporting non-GHG CEMS for

Other EPA Programs

Actual Potential a



# Facilities 0 0 NA NA

Units 0 0 NA NA

NA = No information available.

a 

# Potential facilities or process units that may have equipment installed that could be modified for use in the GHGRP.

# 99 Appendix B. Soda Ash Manufacturing – Subpart CC

Industry Background

Based on 2011 annual report submissions, there were 4 facilities that reported to GHGRP under

subpart CC.

Under subpart CC, facilities estimate CO 2 

# process emissions from each soda ash manufacturing

line and CO 2 

# combustion emissions from each soda ash manufacturing line. They are also

required to estimate and report CH 4 

# and N 2 

# O combustion emissions from each soda ash

manufacturing line. For CO 2 

# emissions, facilities may use a mass balance or emission factor

approach to estimate separate process and comb ustion emissions, or use a CEMS to determine

combined process and combustion emissions.

Applicable NSPS and NESHAP for Soda Ash Plants

Table CC-1. Applicable NESHAP and NSPS Rules

NESHAP/NSPS Subparts Reviewed Monitoring Required

by the NESHAP or

NSPS Would

Monitoring

Equipment

Relevant to Part

98 be Installed to

Comply With

NESHAP or

NSPS? Were Data on

CEMS Counts

Available in

NESHAP or

NSPS docket?

Subpart OOO—Standards of Performance for

Nonmetallic Mineral Processing Plants (No relevant monitoring

requirements) No No

Subpart UUU—Standards of Performance for

Calciners and Dryers in Mineral Industries (No relevant monitoring

requirements) No No



# The applicable NESHAP and NSPS for this subpar t do not require monitoring which is related to

CEMS equipment and would thus not f acilitate the instal lation of GHG CEMS.

Summary of Available Data on Fac ilities Reporting the Use of CEMS

One facility reported the use of one CO 2 

# CEMS to report emissions in the GHGRP.

Subpart CC CEMS Count

Table CC-2 summarizes the actual data collected for facilities using CO 2 

# CEMS, non-CO 2 

# GHG

CEMS, and non-GHG CEMS. One facility wa s identified with pre-existing CO 2 

# CEMS. No

assumption could be made for a potential count ba sed on lack of information on control devices

and monitoring requirements.

# 100 Table CC-2. Subpart CC CEMS Counts

Basis CO 2 

# CEMS for

GHGRP Reporting non-CO 2



# GHG CEMS for

GHGRP Reporting non-GHG CEMS for

Other EPA Programs

Actual Potential c



# Facilities 1 a 

# 0 NA NA

Units 1 b 

# 0 NA NA

NA = No information available.

a 

# Number of facilities reporting to GHGRP in 2011 that they are using a CEMS to report CO 2 

# emissions.

b 

# The total number of CO 2 

# CEMS at the facilit ies which reported CO 2 

# CEMS.

c 

# Potential facilities or process units that may have equipment installed that could be modified for use in the GHGRP.

# 101 Appendix B. Titanium Dioxi de Production – Subpart EE

Industry Background

Based on 2011 annual report submissions, there were 7 facilities that reported to GHGRP under

subpart EE.

Under subpart EE, facilities estimate CO 2 

# process emissions from each chloride process line. For

estimating CO 2 

# process emissions, facilities may either use a mass balance approach or use a

CEMS.

Applicable NSPS and NESHAP for Titanium Dioxide Plants

Table EE-1. Applicable NESHAP and NSPS Rules

NESHAP/NSPS Subparts

Reviewed Monitoring Required

by the NESHAP or

NSPS Would Monitoring

Equipment Relevant to

Part 98 be Installed to

Comply With NESHAP

or NSPS? Were Data on

CEMS Counts

Available in

NESHAP or

NSPS docket?

Subpart LL—Standards of

Performance for Metallic Mineral

Processing Plants (No relevant monitoring

requirements) No No



# The applicable NESHAP and NSPS for this subpar t do not require monitoring which is related to

CEMS equipment and would thus not f acilitate the instal lation of GHG CEMS.

Summary of Available Data on Fac ilities Reporting the Use of CEMS

No facilities reported the use of CEMS to the GHGRP.

Subpart EE CEMS Count

Table EE-2 summarizes the actual data collected for facilities using CO 2 

# CEMS, non-CO 2 

# GHG

CEMS, and non-GHG CEMS. No facilities we re identified with pre-existing CO 2 

# CEMS. No

assumption could be made for a potential count ba sed on lack of information on control devices

and monitoring requirements.

Table EE-2. Subpart EE CEMS Counts

Basis CO 2 

# CEMS for

GHGRP Reporting non-CO 2



# GHG CEMS for

GHGRP Reporting non-GHG CEMS

for Other EPA Programs

Actual Potential a



# Facilities 0 0 NA NA

Units 0 0 NA NA

NA = No information available.

a 

# Potential facilities or process units that may have equipment installed that could be modified for use in the GHGRP.

# 102 Appendix B. Zinc Production – Subpart GG

Industry Background

Based on 2011 annual report submissions, there were 6 facilities that reported to GHGRP under

subpart GG.

Under subpart GG, facilities estimate CO 2 

# process emissions from each Waelz kiln and

electrothermic furnace, and CO 2 

# combustion emissions from each Waelz kiln and electrothermic

furnace. They are also required to estimate and report CH 4 

# and N 2 

# O combustion emissions from

each Waelz kiln and electrothermic furnace. For CO 2 

# emissions, facilities may use a mass

balance or emission factor approa ch to estimate separate proc ess and combustion emissions, or

use a CEMS to determine combined process and combustion emissions.

Applicable NSPS and NE SHAP for Zinc Plants

Table GG-1. Applicable NESHAP and NSPS Rules

NESHAP/NSPS Subparts Reviewed Monitoring Required

by the NESHAP or

NSPS Would

Monitoring

Equipment

Relevant to Part

98 be Installed to

Comply With

NESHAP or

NSPS? Were Data on

CEMS Counts

Available in

NESHAP or

NSPS docket?

Subpart Q—Standards of Performance for

Primary Zinc Smelters SO 2 

# CEMS required for

facilities constructed or

modified after October

16, 1974 No No

Subpart LL—Standards of Performance for

Metallic Mineral Processing Plants (No relevant monitoring

requirements) No No

Subpart GGGGGG—NESHAP for Primary

Nonferrous Metals Area Sources—Zinc,

Cadmium, and Beryllium (No relevant monitoring

requirements)

No No

Subpart TTTTTT—NESHAP for Secondary

Nonferrous Metals Processing Area Sources (No relevant monitoring

requirements) No No



# SO 2 

# CEMS is only applicable for roasters at prim ary zinc smelters which are not applicable to

GHG reporting and are thus not rela ted to GHG CEMS installation.

Summary of Available Data on Fac ilities Reporting the Use of CEMS

No facilities reported the use of CEMS to the GHGRP.

# 103 Subpart GG CEMS Count

Table GG-2 summarizes the actual data collected for facilities using CO 2 

# CEMS, non-CO 2 

# GHG

CEMS, and non-GHG CEMS. No facilities we re identified with pre-existing CO 2 

# CEMS. No

assumption could be made for a potential count ba sed on lack of information on control devices

and monitoring requirements.

Table GG-2. Subpart GG CEMS Counts

Basis CO 2 

# CEMS for

GHGRP Reporting non-CO 2



# GHG CEMS for

GHGRP Reporting non-GHG CEMS for

Other EPA Programs

Actual Potential a



# Facilities 0 0 NA NA

Units 0 0 NA NA

NA = No information available.

a 

# Potential facilities or process units that may have equipment installed that could be modified for use in the GHGRP.

# 104 Appendix B. Industrial Waste Landfills – Subpart TT

Industry Background

Based on 2011 annual report submissions, there we re 173 facilities that reported to GHGRP

under subpart TT.

Under subpart TT, facilities must estimate annual CH 4 

# generation, emission, and destruction

from the landfill. For estimating CH 4 

# generation, facilities may meas ure the generation directly

or estimate a value based on histor ic annual waste disposal quantitie s. Facilities that collect and

control landfill gas must calculate CH 4 

# emissions using two methods: First, a mass balance

method using the equations provided in subpart TT; and second, by applying a gas collection

efficiency to the measured amount of CH 4 

# recovered.

Applicable NSPS and NESHAP for Industrial Waste Landfills

There are no NSPS or NESHAP which are applicab le to industrial waste landfills. The definition

of industrial waste landfills fo r purposes of the GHGRP specifically excludes municipal waste

landfills, so part 60 subpart WWW (NSPS fo r MSW Landfills) is not applicable.

Summary of Available Data on Fac ilities Reporting the Use of CEMS

No facilities reported the use of CEMS to the GHGR P. It is noted in subpart TT that industrial

waste landfills may collect methane with a gas collection system. If they do the rule requires

them to report the annual CH 4 

# recovered. The method of recording the amount of methane

recovered using the gas co llection system is unknown, so the applicability of CH 4 

# CEMS is also

unknown. For these purposes it will be assumed that no facility uses CEMS to monitor CH 4



# recovery. Also, for those industria l waste landfills which have gas co llection systems, the facility

is required to monitor the flow rate and temper ature; the applicability of this equipment to

installing CEMS (e.g., is the flow monitor loca ted at a position which would also meet flow

monitor requirements for CEMS) is also unknown.

Subpart TT CEMS Count

Table TT-1 summarizes the actual data collected for facilities using CO 2 

# CEMS, non-CO 2 

# GHG

CEMS, and non-GHG CEMS. No facilities we re identified with pre-existing CH 4 

# CEMS. No

assumption could be made for a potential count based on lack of information.

Table TT-1. Subpart TT CEMS Counts

Basis CO 2 

# CEMS for

GHGRP Reporting non-CO 2



# GHG CEMS for

GHGRP Reporting non-GHG CEMS for

Other EPA Programs

Actual Potential a



# Facilities 0 0 NA NA

Units 0 0 NA NA

# 105 NA = No information available.

a 

# Potential facilities or process units that may have equipment installed that could be modified for use in the GHGRP.

# 106 Appendix C

Detailed CEMS Costing for Subparts with “Inputs to Equations” Data Elements

# 107 Appendix C

Detailed GHG CEMS Cost Analysis

================== ================== ================== ==============

C.1 GHG CEMS Cost Assumptions

To determine the economic impact of installi ng GHG CEMS for each subpart, a determination of

the applicable population of sources for each subp art was needed. This included the total count

of facilities and process units in each subpart and the count of CEMS which are currently

installed. Data for current CEMS in cluded installations of GHG CEMS (CO 2 

# , CH 4 

# , or N 2 

# O) and

non-GHG CEMS (NO X 

# , PM, CO, etc.). When determining the GHG CEMS cost for each

subpart, data at the process unit level is the most relevant. A facility may have multiple process

units and thus multiple emission sources (e.g., mu ltiple stacks) which would each need their own

CEMS. However, for some subparts this level of detail was not available a nd only facility counts

were known. In those instances, on ly the facility count was used to determine the CEMS cost;

while this may underestimate costs for certain subpart s, due to a lack of data, it was not possible

to provide a reliable count for number of pr ocess units. To determine counts the following

sources were used: GHGRP data, part 98 GHG t echnical support documents for each subpart, a

review of applicable NESHAP and NSPS rule requirements a nd associated databases and

supporting documentation for each subpart, and th e part 98 GHG Regulatory Impact Analysis

(RIA). See Appendix B for a revi ew of the information obtained.

To keep this CEMS cost analysis consis tent with the GHG RIA, the same method of

determining capital and annual costs was used. As shown in section 3.1, the following CEMS

usages were identified:

 Source has CO 2 

# CEMS

 Source has non-CO 2 

# GHG CEMS (such as N 2 

# O CEMS) or has non-GHG CEMS (such as

NO X 

# or CO monitors)

 Source has no CEMS

Five different cost scenarios we re identified from the usage information and are summarized in

Table C-1. Cost scenario 1 is a complete GHG CE MS installation for sour ces which do not have

any CEMS related equipment installed. Cost scen arios 2 through 4 are reduced costs for sources

which have current CEMS installations and w ould need to install minimal equipment (e.g., a

CO 2 

# analyzer and/or flow meter). The decision to apply scenarios 2, 3, or 4 costs to a particular

subpart is based off applicab le NSPS/NESHAP regulation knowl edge and information provided

in the GHG RIA. It was determined that no f acilities/process units me t the requirements for

scenario 4 (see Appendix B for regulatory review results for each subpart). Therefore, no costs

were estimated for scenario 4. Scenario 5 is a facility/process unit that already has CO 2 

# CEMs

and no costs are calculated.

# 108 Table C-1. Summary of Costs for CO 2 

# CEMS Modifications

Scenario

# Scenario Total annual

costs

1 Source has no CEMS -- Add CO 2 

# analyzer, flow meter, and

infrastructure $ 70,265

2 Source has CEMS for other pollutants -- Add CO 2 

# analyzer

and flow meter $ 56,040

3 Source has CEMS for other pollutants -- Add CO 2 

# analyzer

only $ 20,593



# 4 a 

# Source has CEMS for other pollutants -- Add flow monitor

only $ 24,511

5 Source has CO 2 

# CEMS No Cost

a 

# No facilities/process units were determined to meet the scenario.



# Within each scenario, multiple cost scenarios we re calculated because each subpart may require

one analyzer or a combination of analyzers to measure GHGs. The most common GHG to report

is CO 2 

# , however CH 4 

# and N 2 

# O are also applicable depending on the subpart. While the GHG

RIA provided a cost estimate for a CO 2 

# CEMS, CH 4 

# and N 2 

# O CEMS costs were not available.

For this analysis, vendors were contacted and co st estimates were developed for these methods

as well. With these additional data, costs were estimated for installing each CEMS analyzer on a

stand-alone basis and costs were also calculated for installing all three analyzers at one source or

a combination of two analyzers at one source. Subpa rt O requires reporting of fluorinated gases;

the applicability of CEMS for fluorinated gase s was not analyzed, and therefore no costs were

calculated for subpart O. Table C-2 su mmarizes the vendor cost information.

Costs for each subpart were determined based on the count information identified (see Appendix

B for subpart-specific details) a nd the scenario cost options. Cost s were determined based on the

following hierarchy:

 If no current CEMS installations were identified then the total facility/process unit count

was multiplied by the scenario 1 cost fo r installing the appropriate GHG CEMS.

 If current non-CO 2 

# CEMS installations were identified for a subpart then either scenario

2 or 3 costs were applied for these counts de pending on the type of CEMS identified. For

facility/process units without current non-CO2 CEMs, the scenar io 1 costs were applied.

These two costs were added together to get the total cost for the facility.

 For subparts which have a CO 2 

# CEMS installed but would also report CH 4 

# and/or N 2 

# O,

only the cost associated with installing a CH 4 

# and/or N 2 

# O analyzer was incorporated, and

no costs for CO 2 

# analyzers were included.

Costs are shown for each subpart based on two c ount options: actual and potential CEMS counts.

The actual count and associated CEMS costs co rrespond to the actual CEMS installation counts

which were able to be identified from the vari ous sources discussed previously. The potential

# 109 count and associated CEMS costs correspond to the potential CEMS installation counts which

were estimated based on requirements in NSPS a nd NESHAP rules. The potential counts include

the actual counts plus the additional units/facilit ies that may be affected by NSPS or NESHAP

requirements. The costs associated with the act ual count resulted in higher costs than the

potential count scenario, as fewer current CEMS installations were estimated which results in a

higher number of scenario 1 (complete installatio n) costs. For the costs associated with the

potential count, the resulting cost s were lower than the actual count scenario because more

CEMS installations were estimated which resulte d in fewer units in scenario 1 and more in

scenarios 2 or 3. For many subparts, the actu al and potential CEMS counts are identical,

however.

Table C-2. Summary of Vendor Cost Information Collected

Equipment Altech

Environmental CEMS Experts

(GK Associates) EnviroServ Cemtek

Environmental Average Average

(Rounded)

CO 2 

# analyzer $5,000 (a) $15,000

‐ $20,000 $12,000 $7,917 $12,472 $13,000

N 2 

# O analyzer $5,000 (a) $15,000

‐ $20,000 $15,000 $10,096 $14,199 $14,000

CH 4 

# analyzer $5,000 (a) $15,000

‐ $20,000 $12,000 $18,019 $15,840 $16,000

Sampling system

‐‐  ‐‐  ‐‐ $9,766 $9,766 $10,000

DAS, including

software $30,000

‐ $40,000

‐‐  ‐‐ $19,931 $27,466 $28,000

Flow monitors $27,000 $15,000

‐ $20,000

‐‐ $26,250 $23,583 $24,000

Notes:

‐ When cost ranges were provided, the average of the range was used to estimate costs.

(a) Did not include Altech analyzer costs in average per note from Altech that their analyzer costs are typically

lower than normal due to the method by which they price their equipment.



# C.2 GHG CEMS Cost Results

Based on the counts for each subpart and their brea kdown into counts for each scenario, costs for

installing GHG CEMS were estima ted. Section C.2 summarizes the estimated costs for each

subpart and the overall cost to industry.

Tables C-3 through C-11 show the resultant total capital investment and annualized CEMS costs

(actual and potential) for each subpart, the number of sources with existing GHG or non-GHG

CEMS for each subpart, and the division of affected sources into the four cost scenarios for each

subpart. Tables C-3 and C-4 summarize capita l and annual costs for installation of CO 2 

# CEMS

only (similar to the GHG RIA). Tables C-5 th rough C-7 summarize the count information for

actual and potential units/faciliti es with CEMS control, and the assumptions used in the count

determination. Tables C-8 through C-11 provide data on all three t ypes of GHG CEMS (CO 2 

# , N 2 

# O, and CH 4 

# ). Tables C-8 and C-9 show the capital and annual cost estimates based on actual

counts. Tables C-10 and C-11 show the capital and annual cost estimates based on potential

counts.

For subparts which require multiple GHG CEMS, di stributing the total un it installation cost

between two or three CEMS is not appropriate; there are redundant component costs associated

# 110 with CO 2 

# , CH 4 

# , and N 2 

# O CEMS. If a facility were to in stall CEMS for all three GHGs, for

example, the total cost incurred by the f acility would not equal the sum of the CO 2 

# , CH 4 

# , and

N 2 

# O individual monitor costs. Instead, cost estim ates were developed based on vendor quotes for

each possible combination of CO 2 

# , CH 4 

# , and N 2 

# O CEMS for each cost scenario. For this reason,

the CO 2 

# , N 2 

# O, and CH 4 

# costs in Tables C-8 through C-11 do not equal the total cost column; the

CO 2 

# , N 2 

# O, and CH 4 

# costs shown are the cost for instal ling individual GHG CEMS while the total

cost is the more representative co st for installing multiple GHG CEMS.111Table C-3. Capital Cost Breakdown into Each Costing Scenario for Installation of CO2CEMS Only, Based on Actual Counts and Potential CountsSubpartCapitalInvestmentScenario1Scenario2Scenario3TotalActualaPotentialbActualaPotentialbActualaPotentialbActualaPotentialbC$1,578,065,753$1,578,065,753$102,182,259$111,374,792$0$0$1,680,248,013$1,689,440,545E$‐$‐$‐$‐$‐$‐$‐$‐F$1,229,981$1,229,981$‐$‐$‐$‐$1,229,981$1,229,981G$2,705,958$2,705,958$‐$‐$‐$‐$2,705,958$2,705,958H$3,443,947$‐$‐$‐$560,101$560,101$4,004,048$560,101K$1,229,981$1,229,981$‐$‐$‐$‐$1,229,981$1,229,981L$‐$‐$‐$‐$‐$‐$‐$‐N$13,160,798$13,160,798$‐$‐$‐$‐$13,160,798$13,160,798O$‐$‐$‐$‐$‐$‐$‐$‐P$12,299,811$12,299,811$‐$‐$‐$‐$12,299,811$12,299,811Q$18,572,715$18,572,715$‐$‐$‐$‐$18,572,715$18,572,715R$1,598,975$1,598,975$‐$‐$‐$‐$1,598,975$1,598,975S$8,855,864$‐$‐$‐$‐$‐$8,855,864$‐U$2,213,966$2,213,966$0$0$0$0$2,213,966$2,213,966V$‐$‐$‐$‐$‐$‐$‐$‐X$7,625,883$7,871,879$‐$‐$‐$‐$7,625,883$7,871,879Y$191,139,063$155,346,613$‐$18,094,775$‐$2,080,376$191,139,063$175,521,765Z$737,989$737,989$‐$‐$140,025$140,025$878,014$878,014AA$7,881,432$7,881,432$25,731,576$25,731,576$‐$‐$33,613,009$33,613,009BB$122,998$122,998$‐$‐$‐$‐$122,998$122,998CC$368,994$368,994$‐$‐$‐$‐$368,994$368,994EE$860,987$860,987$‐$‐$‐$‐$860,987$860,987GG$737,989$737,989$‐$‐$‐$‐$737,989$737,989TT$‐$‐$‐$‐$‐$‐$‐$‐TOTAL$1,852,853,085$1,800,578,888$127,913,836$158,684,630$700,127$2,780,503$1,981,467,047$1,962,044,020aCosts are based on the actual number of units/facilities for whichinformation was available indicating current use of CEMS. See Appendix B for detailed information for eachsubpart.bCosts are based on potential number of units/facilities that may beusing CEMS based on NESHAP and NSPS rule requirements. Costs include actual number of units/facilitieswhere information is known as well as the additional potential number of units/facilities that may be using CEMS based on NESHAP and NSPS rulerequirements. SeeAppendix B for detailed information for each subpart.112Table C-4. Annual Cost Breakdown into EachCosting Scenario for Installation of CO2CEMS Only, Based on Actual Counts and Potential CountsSubpartAnnualCostScenario1Scenario2Scenario3TotalActualaPotentialbActualaPotentialbActualaPotentialbActualaPotentialbC$901,499,950$901,499,950$59,178,240$64,502,040$‐$‐$960,678,190$966,001,990E$‐$‐$‐$‐$‐$‐$‐$‐F$702,650$702,650$‐$‐$‐$‐$702,650$702,650G$1,545,830$1,545,830$‐$‐$‐$‐$1,545,830$1,545,830H$1,967,420$‐$‐$‐$576,604$576,604$2,544,024$576,604K$702,650$702,650$‐$‐$‐$‐$702,650$702,650L$‐$‐$‐$‐$‐$‐$‐$‐N$7,518,355$7,518,355$‐$‐$‐$‐$7,518,355$7,518,355O$‐$‐$‐$‐$‐$‐$‐$‐P$7,026,500$7,026,500$‐$‐$‐$‐$7,026,500$7,026,500Q$10,610,015$10,610,015$‐$‐$‐$‐$10,610,015$10,610,015R$913,445$913,445$‐$‐$‐$‐$913,445$913,445S$5,059,080$‐$‐$‐$‐$‐$5,059,080$‐U$1,264,770$1,264,770$0$0$0$0$1,264,770$1,264,770V$‐$‐$‐$‐$‐$‐$‐$‐X$4,356,430$4,496,960$‐$‐$‐$‐$4,356,430$4,496,960Y$109,191,810$88,744,695$‐$10,479,480$‐$2,141,672$109,191,810$101,365,847Z$421,590$421,590$‐$‐$144,151$144,151$565,741$565,741AA$4,502,417$4,502,417$14,902,287$14,902,287$‐$‐$19,404,705$19,404,705BB$70,265$70,265$‐$‐$‐$‐$70,265$70,265CC$210,795$210,795$‐$‐$‐$‐$210,795$210,795EE$491,855$491,855$‐$‐$‐$‐$491,855$491,855GG$421,590$421,590$‐$‐$‐$‐$421,590$421,590TT$‐$‐$‐$‐$‐$‐$‐$‐TOTAL$1,058,477,417$1,031,144,332$74,080,527$89,883,807$720,755$2,862,427$1,133,278,700$1,123,378,467aCosts are based on the actual number of units/facilities for whichinformation was available indicating current use of CEMS. See Appendix B for detailed information for eachsubpart.bCosts are based on potential number of units/facilities that may beusing CEMS based on NESHAP and NSPS rule requirements. Costs include actual number of units/facilitieswhere information is known as well as the additional potential number of units/facilities that may be using CEMS based on NESHAP and NSPS rulerequirements. SeeAppendix B for detailed information for each subpart.113Table C-5. Total Facility and Units Counts and Current CEMS Installation CountsaSubpartNumberofAffected...DoesSubpartRequireReportingEmissionsof:NumberwithCO2CEMSNumberwithnon‐CO2GHGCEMSNumberwithnon‐GHGCEMSFacilitiesUnitsCO2?N2O?CH4?FacilitiesUnitsFacilitiesUnitsFacilitiesUnitsC1,98514,197YESYESYES17731100unknown1,056to1,151E33NOYESNO0000unknownunknownF1010YESNONO0000unknownunknownG2222YESNONO0000unknownunknownH96140YESYESYES82112000to140to28K1010YESNOYES0000unknownunknownL1616NONONO0015unknownunknownN110110YESYESYES3300unknownunknownO55NONONO0000unknownunknownP103103YESYESYES3300unknownunknownQ128165YESYESYES111400unknownunknownR1313YESYESYES0000unknownunknownS7373YESYESYES1to731to7300unknownunknownU1818YESNONO0000unknownunknownV3665NOYESNO00002036X6464YESYESYES2200unknownunknownY1451,580YESYESYES212600≤104≤317Z1313YESNONO00007≥7AA110330YESYESYES00to360089266BB11YESNOYES0000unknownunknownCC44YESYESYES1100unknownunknownEE77YESNONO0000unknownunknownGG66YESYESYES0000unknownunknownTT173173NONOYES0000unknownunknownaSee Appendix B for detailed summary for each subpart.114Table C-6. Counts Used to Determine Costs for Each Scenario, Actual CEMS CountsaSubpartNumberinScenario1NumberinScenario2NumberinScenario3FacilitiesUnitsFacilitiesUnitsFacilitiesUnitsCO2N2OCH4TotalCO2N2OCH4TotalCO2N2OCH4TotalCO2N2OCH4TotalCO2N2OCH4TotalCO2N2OCH4Total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aSee Appendix B for detailed summary for each subpart.NA = Data not available on basis.115Table C-6 (cont.) Notes Explaining the Actual CEMS Count Distribution for Each SubpartSubpartNOTES–ActualCEMSCountsCBoilerandCISWIdatabasesreviewedtogetcountofunitswithCEMS(1,056).NoneoftherelevantregulationsrequireCO2orflowmonitors,buttheydorequireCEMSsystemsforotherpollutants.Assumedthatall1,056Tier4unitswouldbeinscenario2andunitswithknownCO2CEMSwouldbeinscenario3.ECurrentCEMSinstallationunknown;assumedallfacilities/unitsinscenario1.FCurrentCEMSinstallationunknown;assumedallfacilities/unitsinscenario1.GCurrentCEMSinstallationunknown;assumedallfacilities/unitsinscenario1.HAssumedunitswithcurrentCEMSinstallationswouldbeinscenario3.KCurrentCEMSinstallationunknown;assumedallfacilities/unitsinscenario1.LCO2,N2O,andCH4notrequiredtobereportedforthissubpart,thusnoassociatedcostsorunitcounts.NScenario3costsappliedtofacilitieswithCO2CEMS,othersassumedtobeinscenario1.AssumptionmadethatthefacilitieswithCO2CEMShaveonlyoneunit.OCO2,N2O,norCH4requiredtobereportedforthissubpart,thusnoassociatedcostsorunitcounts.PScenario3costsappliedtofacilitieswithCO2CEMS,othersassumedtobeinscenario1.AssumptionmadethatthefacilitieswithCO2CEMShaveonlyoneunit.QScenario3costsappliedtofacilitieswithCO2CEMS,othersassumedtobeinscenario1.AssumptionmadethatthefacilitieswithCO2CEMShaveonlyoneunit.RCurrentCEMSinstallationunknown;assumedallfacilities/unitsinscenario1.STheRIAforpart98identifiedallfacilitiesbeingapplicabletoTier4requirementsandwouldthusinstallaCO2CEMS.Note,however,thatthiscountmaynotbeexclusivetosubpartSemissionssourcesand,forexample,someoftheidentifiedunitsmayfallundersubpartC.Fortheactualscount,itwasassumedallunitswouldbeinscenario1(exceptthe1facilitywithaknownCO2CEMS).UCurrentCEMSinstallationunknown;assumedallfacilities/unitsinscenario1.VScenario3costsappliedtofacilitieswithCEMS,othersassumedtobeinscenario1.XScenario3costsappliedtofacilitieswithCO2CEMS,othersassumedtobeinscenario1.AssumptionmadethatthefacilitieswithCO2CEMShaveonlyoneunit.YScenario3costsappliedtofacilitieswithCO2CEMS,othersassumedtobeinscenario1.ForactualCEMScount,assumedzerofacilitieshavenon‐GHGCEMSinstalled.ZScenario3costsappliedtofacilitieswithCEMS,othersassumedtobeinscenario1.AAScenario2costsappliedforfacilitieswithCEMS;basedoffGHGRIAestimatethatmostfacilitieswouldmeetthisforTierIVrequirements.BBCurrentCEMSinstallationunknown;assumedallfacilities/unitsinscenario1.CCScenario3costsappliedtofacilitieswithCO2CEMS,othersassumedtobeinscenario1.AssumptionmadethatthefacilitieswithCO2CEMShaveonlyoneunit.EECurrentCEMSinstallationunknown;assumedallfacilities/unitsinscenario1.GGCurrentCEMSinstallationunknown;assumedallfacilities/unitsinscenario1.TTCurrentCEMSinstallationunknown;assumedallfacilities/unitsinscenario1.116Table C-7. Counts Used to Determine Costs for Each Scenario, Potential CEMS CountsaSubpartNumberinScenario1NumberinScenario2NumberinScenario3FacilitiesUnitsFacilitiesUnitsFacilitiesUnitsCO2N2OCH4TotalCO2N2OCH4TotalCO2N2OCH4TotalCO2N2OCH4TotalCO2N2OCH4TotalCO2N2OCH4TotalCNANANANA12,83012,83012,83012,830NANANANA1,1511,1511,1511,15101771771773110311311E030303030000000000000000F1000101000100000000000000000G2200222200220000000000000000H00000000000000001896969628140140140K100101010010100000000000000000L000000000000000000000000N1071071071071071071071070000000003330333O000000000000000000000000P1001001001001001001001000000000003330333Q1171171171171511511511510000000001111110141414R13131313131313130000000000000000S000000000737373073737300000000U1800181800180000000000000000V01601602902900000000020020036036X64646464646464640000000002220222YNANANANA1,2631,2631,2631,263NANANANA187187187187NANANANA104130130130Z600660060000000070077007AA21212121282828288989898930230230230200000000BB101110110000000000000000CC333333330000000001110111EE700770070000000000000000GG666666660000000000000000TT00173173001731730000000000000000aSee Appendix B for detailed summary for each subpart.NA = Data not available on basis.117Table C-7 (cont.) Notes Explaining the Potential CEMS CountDistribution for Each SubpartSubpartNOTES–PotentialCEMScountsCBoilerandCISWIdatabasesreviewedtogetcountofunitswithCEMS(1,151).NoneoftherelevantregulationsrequireCO2orflowmonitors,buttheydorequireCEMSsystemsforotherpollutants.Assumedthatall1,151Tier4unitswouldbeinscenario2andunitswithknownCO2CEMSwouldbeinscenario3.ECurrentCEMSinstallationunknown;assumedallfacilities/unitsinscenario1.FCurrentCEMSinstallationunknown;assumedallfacilities/unitsinscenario1.GCurrentCEMSinstallationunknown;assumedallfacilities/unitsinscenario1.HAssumedunitswithcurrentCEMSinstallationswouldbeinscenario3.KCurrentCEMSinstallationunknown;assumedallfacilities/unitsinscenario1.LCO2,N2O,andCH4notrequiredtobereportedforthissubpart,thusnoassociatedcostsorunitcounts.NScenario3costsappliedtofacilitieswithCO2CEMS,othersassumedtobeinscenario1.AssumptionmadethatthefacilitieswithCO2CEMShaveonlyoneunit.OCO2,N2O,norCH4requiredtobereportedforthissubpart,thusnoassociatedcostsorunitcounts.PScenario3costsappliedtofacilitieswithCO2CEMS,othersassumedtobeinscenario1.AssumptionmadethatthefacilitieswithCO2CEMShaveonlyoneunit.QScenario3costsappliedtofacilitieswithCO2CEMS,othersassumedtobeinscenario1.AssumptionmadethatthefacilitieswithCO2CEMShaveonlyoneunit.RCurrentCEMSinstallationunknown;assumedallfacilities/unitsinscenario1.STheRIAforpart98identifiedallfacilitiesbeingapplicabletoTier4requirementsandwouldthusinstallaCO2CEMS.Note,however,thatthiscountmaynotbeexclusivetosubpartSemissionssourcesand,forexample,someoftheidentifiedunitsmayfallundersubpartC.Forthepotentialcount,itwasassumedallunitswouldbeinscenario2,pertheRIA.UCurrentCEMSinstallationunknown;assumedallfacilities/unitsinscenario1.VScenario3costsappliedtofacilitieswithCEMS,othersassumedtobeinscenario1.XScenario3costsappliedtofacilitieswithCO2CEMS,othersassumedtobeinscenario1.AssumptionmadethatthefacilitieswithCO2CEMShaveonlyoneunit.YScenario3costsappliedtofacilitieswithCO2CEMS,othersassumedtobeinscenario1.ForpotentialCEMScount,distributednon‐GHGCEMSinscenario2and3basedonengineeringjudgment.ZScenario3costsappliedtofacilitieswithCEMS,othersassumedtobeinscenario1.AAScenario2costsappliedforfacilitieswithCEMS;basedoffGHGRIAestimatethatmostfacilitieswouldmeetthisforTierIVrequirements.BBCurrentCEMSinstallationunknown;assumedallfacilities/unitsinscenario1.CCCurrentCEMSinstallationunknown;assumedallfacilities/unitsinscenario1.EECurrentCEMSinstallationunknown;assumedallfacilities/unitsinscenario1.GGCurrentCEMSinstallationunknown;assumedallfacilities/unitsinscenario1.TTCurrentCEMSinstallationunknown;assumedallfacilities/unitsinscenario1.118Table C-8. Capital Costs (million dollars) forEach Scenario, Based on Actual CEMS CountsaSubpartCapitalCosts(MillionDollars)Scenario1Scenario2Scenario3Total‐AllScenariosCO2N2OCH4TotalCO2N2OCH4TotalCO2N2OCH4TotalC$1,578$1,603$1,640$1,960$102$104$107$134$‐$6.8$7.7$11.9$2,106E$‐$0.37$‐$0.37$‐$‐$‐$‐$‐$‐$‐$‐$0.4F$1.2$‐$‐$1.2$‐$‐$‐$‐$‐$‐$‐$‐$1.2G$2.7$‐$‐$2.7$‐$‐$‐$‐$‐$‐$‐$‐$2.7H$3.4$3.5$3.6$4.3$‐$‐$‐$‐$0.56$2.5$2.8$5.6$9.9K$1.2$‐$1.3$1.4$‐$‐$‐$‐$‐$‐$‐$‐$1.4L$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐N$13.2$13.4$13.7$16.3$‐$‐$‐$‐$‐$0.066$0.074$0.11$16.5O$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐P$12.3$12.5$12.8$15.3$‐$‐$‐$‐$‐$0.066$0.074$0.11$15.4Q$18.6$18.9$19.3$23.1$‐$‐$‐$‐$‐$0.31$0.35$0.54$23.6R$1.6$1.6$1.7$2.0$‐$‐$‐$‐$‐$‐$‐$‐$2.0S$8.9$9.0$9.2$11.0$‐$‐$‐$‐$‐$0.022$0.025$0.038$11.0U$2.2$‐$‐$2.2$‐$‐$‐$‐$‐$‐$‐$‐$2.2V$‐$3.6$‐$3.6$‐$‐$‐$‐$‐$0.79$‐$0.79$4.4X$7.6$7.7$7.9$9.5$‐$‐$‐$‐$‐$0.044$0.050$0.077$9.6Y$191$194$199$237$‐$‐$‐$‐$‐$0.57$0.65$1.00$238.5Z$0.74$‐$‐$0.74$‐$‐$‐$‐$0.14$‐$‐$0.14$0.88AA$7.9$8.0$8.2$9.8$25.7$26.2$27.0$33.7$‐$‐$‐$‐$43.4BB$0.12$‐$0.13$0.14$‐$‐$‐$‐$‐$‐$‐$‐$0.14CC$0.37$0.37$0.38$0.46$‐$‐$‐$‐$‐$0.022$0.025$0.038$0.50EE$0.86$‐$‐$0.86$‐$‐$‐$‐$‐$‐$‐$‐$0.86GG$0.74$0.75$0.77$0.92$‐$‐$‐$‐$‐$‐$‐$‐$0.92TT$‐$‐$22.1$22.1$‐$‐$‐$‐$‐$‐$‐$‐$22.1TOTAL$1,853$1,877$1,940$2,325$127.7$130.2$134$167.7$0.70$11.2$11.7$20.3$2,513aSee Appendix B for detailed summary for each subpart.119Table C-9. Annual Costs (million dollars) forEach Scenario, Based on Actual CEMS CountsaSubpartAnnualCosts(MillionDollars)Scenario1Scenario2Scenario3Total‐AllScenariosCO2N2OCH4TotalCO2N2OCH4TotalCO2N2OCH4TotalC$901$911$915$950$59.2$61.4$61.7$64.6$‐$6.6$6.7$7.1$1,022E$‐$0.21$‐$0.21$‐$‐$‐$‐$‐$‐$‐$‐$0.21F$0.70$‐$‐$0.70$‐$‐$‐$‐$‐$‐$‐$‐$0.70G$1.5$‐$‐$1.5$‐$‐$‐$‐$‐$‐$‐$‐$1.5H$2.0$2.0$2.0$2.1$‐$‐$‐$‐$0.6$2.4$2.4$2.7$4.8K$0.70$‐$0.71$0.73$‐$‐$‐$‐$‐$‐$‐$‐$0.73L$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐N$7.5$7.6$7.6$7.9$‐$‐$‐$‐$‐$0.06$0.06$0.07$8.0O$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐P$7.0$7.1$7.1$7.4$‐$‐$‐$‐$‐$0.06$0.06$0.07$7.5Q$10.6$10.7$10.8$11.2$‐$‐$‐$‐$‐$0.30$0.30$0.32$11.5R$0.91$0.92$0.93$0.96$‐$‐$‐$‐$‐$‐$‐$‐$0.96S$5.1$5.1$5.1$5.3$‐$‐$‐$‐$‐$0.021$0.021$0.023$5.4U$1.3$‐$‐$1.3$‐$‐$‐$‐$‐$‐$‐$‐$1.3V$‐$2.1$‐$2.1$‐$‐$‐$‐$‐$0.76$‐$0.76$2.8X$4.4$4.4$4.4$4.6$‐$‐$‐$‐$‐$0.042$0.043$0.046$4.6Y$109$110$111$115$‐$‐$‐$‐$‐$0.55$0.56$0.60$115.6Z$0.42$‐$‐$0.42$‐$‐$‐$‐$0.14$‐$‐$0.14$0.57AA$4.5$4.5$4.6$4.7$14.9$15.5$15.5$16.3$‐$‐$‐$‐$21.0BB$0.07$‐$0.07$0.07$‐$‐$‐$‐$‐$‐$‐$‐$0.07CC$0.21$0.21$0.21$0.22$‐$‐$‐$‐$‐$0.021$0.021$0.023$0.25EE$0.49$‐$‐$0.49$‐$‐$‐$‐$‐$‐$‐$‐$0.49GG$0.42$0.43$0.43$0.44$‐$‐$‐$‐$‐$‐$‐$‐$0.44TT$‐$‐$12.3$12.3$‐$‐$‐$‐$‐$‐$‐$‐$12.3TOTAL$1,058$1,066$1,082$1,129$74.1$76.8$77.3$80.9$0.74$10.8$10.2$11.9$1,223aSee Appendix B for detailed summary for each subpart.120Table C-10. Capital Costs (million dollars) for Each Scenario, Based on Potential CEMS CountsaSubpartCapitalCosts(MillionDollars)Scenario1Scenario2Scenario3Total‐AllScenariosCO2N2OCH4TotalCO2N2OCH4TotalCO2N2OCH4TotalC$1,578$1,603$1,640$1,960$111$114$117$146$‐$6.8$7.7$11.9$2,118E$‐$0.37$‐$0.37$‐$‐$‐$‐$‐$‐$‐$‐$0.4F$1.2$‐$‐$1.2$‐$‐$‐$‐$‐$‐$‐$‐$1.2G$2.7$‐$‐$2.7$‐$‐$‐$‐$‐$‐$‐$‐$2.7H$‐$‐$‐$‐$‐$‐$‐$‐$0.56$3.1$3.5$7.0$7.0K$1.2$‐$1.3$1.4$‐$‐$‐$‐$‐$‐$‐$‐$1.4L$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐N$13.2$13.4$13.7$16.3$‐$‐$‐$‐$‐$0.066$0.074$0.11$16.5O$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐P$12.3$12.5$12.8$15.3$‐$‐$‐$‐$‐$0.066$0.074$0.11$15.4Q$18.6$18.9$19.3$23.1$‐$‐$‐$‐$‐$0.31$0.35$0.54$23.6R$1.6$1.6$1.7$2.0$‐$‐$‐$‐$‐$‐$‐$‐$2.0S$‐$‐$‐$‐$‐$7.2$7.4$8.4$‐$‐$‐$‐$8.4U$2.2$‐$‐$2.2$‐$‐$‐$‐$‐$‐$‐$‐$2.2V$‐$3.6$‐$3.6$‐$‐$‐$‐$‐$0.79$‐$0.79$4.4X$7.9$8.0$8.2$9.8$‐$‐$‐$‐$‐$0.044$0.050$0.077$9.9Y$155$158$161$193$18.1$18.5$19.0$23.7$2.08$2.85$3.23$6.48$223.1Z$0.74$‐$‐$0.74$‐$‐$‐$‐$0.14$‐$‐$0.14$0.88AA$3.5$3.5$3.6$4.3$29.2$29.8$30.7$38.2$‐$‐$‐$‐$42.5BB$0.12$‐$0.13$0.14$‐$‐$‐$‐$‐$‐$‐$‐$0.14CC$0.37$0.37$0.38$0.46$‐$‐$‐$‐$‐$0.022$0.025$0.038$0.50EE$0.86$‐$‐$0.86$‐$‐$‐$‐$‐$‐$‐$‐$0.86GG$0.74$0.75$0.77$0.92$‐$‐$‐$‐$‐$‐$‐$‐$0.92TT$‐$‐$22.1$22.1$‐$‐$‐$‐$‐$‐$‐$‐$22.1TOTAL$1,801$1,823$1,885$2,260$158.7$169.0$174.4$216.4$2.8$14.0$15.0$27.2$2,504aSee Appendix B for detailed summary for each subpart.121Table C-11. Annual Costs (million dollars) for Each Scenario, Based on Potential CEMS CountsaSubpartAnnualCosts(MillionDollars)Scenario1Scenario2Scenario3Total‐AllScenariosCO2N2OCH4TotalCO2N2OCH4TotalCO2N2OCH4TotalC$901$911$915$950$64.5$66.9$67.3$70.4$‐$6.6$6.7$7.1$1,027E$‐$0.21$‐$0.21$‐$‐$‐$‐$‐$‐$‐$‐$0.21F$0.70$‐$‐$0.70$‐$‐$‐$‐$‐$‐$‐$‐$0.70G$1.5$‐$‐$1.5$‐$‐$‐$‐$‐$‐$‐$‐$1.5H$‐$‐$‐$‐$‐$‐$‐$‐$0.6$3.0$3.0$3.4$3.4K$0.70$‐$0.71$0.73$‐$‐$‐$‐$‐$‐$‐$‐$0.73L$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐N$7.5$7.6$7.6$7.9$‐$‐$‐$‐$‐$0.06$0.06$0.07$8.0O$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐$‐P$7.0$7.1$7.1$7.4$‐$‐$‐$‐$‐$0.06$0.06$0.07$7.5Q$10.6$10.7$10.8$11.2$‐$‐$‐$‐$‐$0.30$0.30$0.32$11.5R$0.91$0.92$0.93$0.96$‐$‐$‐$‐$‐$‐$‐$‐$0.96S$‐$‐$‐$‐$‐$4.2$4.3$4.4$‐$‐$‐$‐$4.4U$1.3$‐$‐$1.3$‐$‐$‐$‐$‐$‐$‐$‐$1.3V$‐$2.1$‐$2.1$‐$‐$‐$‐$‐$0.76$‐$0.76$2.8X$4.5$4.5$4.6$4.7$‐$‐$‐$‐$‐$0.042$0.043$0.046$4.8Y$89$90$90$94$10.5$10.9$10.9$11.4$2.14$2.75$2.79$3.15$108.1Z$0.42$‐$‐$0.42$‐$‐$‐$‐$0.14$‐$‐$0.14$0.57AA$2.0$2.0$2.0$2.1$16.9$17.6$17.6$18.5$‐$‐$‐$‐$20.6BB$0.07$‐$0.07$0.07$‐$‐$‐$‐$‐$‐$‐$‐$0.07CC$0.21$0.21$0.21$0.22$‐$‐$‐$‐$‐$0.021$0.021$0.023$0.25EE$0.49$‐$‐$0.49$‐$‐$‐$‐$‐$‐$‐$‐$0.49GG$0.42$0.43$0.43$0.44$‐$‐$‐$‐$‐$‐$‐$‐$0.44TT$‐$‐$12.3$12.3$‐$‐$‐$‐$‐$‐$‐$‐$12.3TOTAL$1,029$1,036$1,052$1,099$91.9$99.6$100.1$104.7$2.9$13.5$13.0$15.1$1,217aSee Appendix B for detailed summary for each subpart.