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 reporting 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 supporting 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 evaluation of alternative calculation methods. The 

evaluation of alternative calculation methods is divided into two reviews: (1) review of 

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

measurement using continuous emissions monitoring systems (CEMS). The alternative 

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

program (GHGRP), for which reporting 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 evaluate application of direct measurement of 

emissions using CEMS, and summarizes the results of the evaluation. Section 4 provides a 

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

calculation equations reviewed for each subpart. Appendix B presents a detailed characterization 

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

cost estimates of requiring CO2 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 “input to equation” data element is not listed explicitly in this 

memorandum. 
2 

2.0 Alternative Calculation Equations 

 Section 2.0 of this memorandum evaluates alternative equations to calculate GHG 

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

section 2.2 discusses the data sources reviewed to obtain the alternative calculation equations, 

and section 2.3 summarizes the results of the review. 

2.1 Procedures for Identifying and Reviewing Alternative Calculation Equations 

Alternative calculation equations were identified 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 reporting 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 calculation was evaluated to determine if it was the same as the 

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

the alternative calculation equations were evaluated 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. Additionally, the equations that are different were 

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

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

calculation equations that were identified 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 sufficient cost information 

was available. The cost of the alternative 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 considered but not included in the final rule were 

identified in the technical 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 determine if the calculation 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 Registry (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 Business 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 programs 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 notice solicited input from commenters on 

alternative calculation methods. Commenters suggested alternative calculation methods for 5 

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

2.3 Results of Evaluation 

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

table indicates that for all of the subparts except 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 are the same type of reporting elements that the 

EPA determined have disclosure concerns49, 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 Subparts X and Y, further analysis 

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

each subpart and for each alternative 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 Equationsa

Uses Same 

“Inputs to 

Equations

” Data 

Elements b

Uses Same 

Type of 

Inputs 

that do not 

Alleviate 

Disclosure 

Concernsc

Mandates 

Process 

Designd

Increased 

Uncertainty/ 

Decreased 

Accuracy 

High Cost 

to 

Implemente

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 configurations (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 Continuous Emissions Monitoring Systems 

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

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

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

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

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

CEMS does not result in increased 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 are not routed through a stack. This review characterizes the 

facilities (or process units in a facility) that currently use CO2 CEMS (or N2O or methane CEMS 

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

GHGRP, and the cost impacts of applying the upgrades. 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 CO2 CEMS only if a facility already has CEMS for 

another regulation and meets certain 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 CO2 emissions using a CEMS. Most of the subparts with 

“inputs to equations” data elements allow CEMS as an option to determine CO2 emissions (some 

also allow N2O with approval). 

Characterization of Facilities and Process Units

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

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

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

GHGRP50 provides the most up-to-date information on facility 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. Therefore, for this evaluation, we also used 

information in the GHGRP regulatory impacts analysis (RIA)51, the GHGRP background 

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

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

standards (NSPS) or national emission standards for hazardous air pollutants (NESHAP)), to 

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

Estimating Current and Potential CEMS usage 

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

CO2, CH4, and N2O in facilities, those data were used to identify the actual number of facilities 

or process units that currently use CO2 CEMS (or N2O or methane, if applicable). 

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

CEMS usage not related to GHGs. These regulations do not generally require CO2 CEMS 

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

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

installing the CEMS. Table 3-1 summarizes the NSPS and NESHAP applicable to sources 

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

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

and NSPS were used to develop a count of potential facilities or process 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 Revieweda 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 CEMS 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 Revieweda 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 

NSPS: Subpart NNN one of several compliance options 

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 Kraft 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 requirements in the NSPS or NESHAP regulations, 

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

may be minimal, such as adding a CO2 analyzer only, or more costly, such as adding a CO2

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 CO2 CEMS at a reduced cost was evaluated. 

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

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

 Source has CO2 CEMS 

 Source has non-CO2 GHG CEMS (such as N2O CEMS) or has non-GHG CEMS (such as 

NOX or CO monitors) 

 Source has no CEMS 
8 

 After the CEMS characterization was completed, the cost impacts of requiring CO2 

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 was reviewed and separated into the components 

necessary for CO2 CEMS.51 Based on the type of CEMS used, five CEMS usage scenarios were 

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

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

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

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

are presented in Appendix B and information in the RIA. 

Table 3-2. Summary of Costs for CO2 CEMS Modifications 

Scenario 

# Scenario

Total annual 

cost/application

1 Source has no CEMS -- Add CO2 analyzer, flow meter, and 

infrastructure $ 70,265 

2 Source has CEMS for other pollutants -- Add CO2 analyzer 

and flow meter $ 56,040 

3 Source has CEMS for other pollutants -- Add CO2 analyzer 

only $ 20,593 

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

only $ 24,511 

5 Source has CO2 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 CO2 CEMs, non-CO2

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

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

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

includes both the actual number and additional units/facilities that 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 the CEMS characterization analysis for each 

subpart. 

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

Equations” Data Elements 
9 

Subpart Basis Number

Subject to

Subparta

Reporting CO2

CEMS in GHGRP

Reporting non‐

CO2 GHG CEMS in

GHGRP

l

Reporting non‐GHG CEMS in

NSPS/NESHAP

Actual Potential

C Facilities 1,985 177 0b NA NA

Units 14,197 311 0b 1056 1151

E Facilities 3 0l 0b NA NA

F Facilities 10 0l 0b NA NA

G Facilities 22 0l 0b NA NA

H Facilities 96 82 0b 14c 14c

Units 140 112 0b 0d 28e

K Facilities 10 0l 0b NA NA

L Facilities 16 0l 1 NA NA

N Facilities 110 3 0b NA NA

Units NA 3 0b NA NA

O Facilities 5 0l 0b NA NA

P Facilities 103 3 0b NA NA

Units NA 3 0b NA NA

Q Facilities 128 11 0b NA NA

Units 165 14 0b NA NA

R Facilities 13 0l 0b NA NA

S Facilities 73 1 0b NA NA

U Facilities 18 0l 0b NA NA

V Facilities 36 0l 0b 20g NA

Units 65 0l 0b 36g NA

X Facilities 64 2 0b NA NA

Units NA 2 0b NA NA

Y‐ 

Catalytic

Cracking

and Sulfur

Recovery

Facilities

145 21 0b NA 104h

Process

Units

317 26 0b NA 317i

Y ‐ Other

Process

Unitsj Facilities

145 0l 0b 0 0

Process

Units

1,580 0l 0b 0 0

Z Facilities 13 0l 0b 7k 7k

AA Facilities 110 0l 0b 89m NA

Units 330m 0l 0b 266m NA

BB Facilities 1 0l 0b NA NA

CC Facilities 4 1 0b NA NA

Units NA 1 0b NA NA

EE Facilities 7 0l 0b NA NA
10 

GG Facilities 6 0l 0b NA NA

TT Facilities 173 0l 0b NA NA

NA = No estimate available 

a

 Number of facilities that reported to the GHGRP in 2011. b

 No units or facilities are known to be using non-CO2 GHG CEMS (e.g., for CH4 or N2O). c

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

they are using CO2 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 CO2 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 Environmental and Cost Impacts for Final Portland Cement NESHAP and NSPS” (August 6, 

2010), minus the 112 that reported to GHGRP in 2011 that they are using CO2 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 the inventory data were reported by the facility and presumed to 

be the actual count of units with NOX 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 calcining, catalytic reforming, flares, loading operations, and other 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 they were using a CEMS to report GHG emissions. m The National Council for Air and Stream Improvement (NCASI) survey provided process unit data and the 2009 RIA estimated 

that units were subject to Tier 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. 

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

CO2 CEMS are required for sources or process units subject to the GHGRP. The table does not 

show the cost of applying N2O or CH4 CEMS. The table presents the cost to upgrade monitoring 

equipment (existing equipment for actual sources and likely equipment for potential sources 

based on the air rules) and the cost to add full CO2 CEMS for facilities that are subject to the 

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

units/facilities with CEMS, and potential counts of units/facilities with CEMS based on NSPS 

and NESHAP rule requirements. Potential costs incorporate 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 based on NESHAP and NSPS rule requirements. See 

Appendix B for detailed information for each subpart. Appendix C contains detailed cost 

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

all three types of GHG CEMS (CO2, N2O, and CH4).

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) 

Actuala Potentialb Actuala Potentialb

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/facilities 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 detailed information for each subpart. 

4.0 Summary 

Based on the results of this evaluation, the EPA proceeded to Step 4 of the evaluation for all of 

the 25 subparts evaluated in this memorandum. 
12 

5.0 References 

1. U.S. EPA. "Technical Support Document for 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/TSD%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/documents/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 Greenhouse Gases." Office of Air and Radiation. 

January 22, 2009. Available: 

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

PA%201-22-09.pdf. 

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

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

January 28, 2009. Available: 

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

A%201-28-09.pdf. 

6. U.S. EPA. "Technical Support Document for the Ferroalloy 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%20Ferroalloys%20_

EPA%201-22-09.pdf. 

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

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

Radiation. November 5, 2010. Available: 

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

8. U.S. EPA. "Technical Support Document for the Glass Manufacturing Sector: Proposed 

Rule for Mandatory Reporting of Greenhouse 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 for Emissions of HFC-23 from Production of 

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

and Radiation. February 6, 2009. Available: 

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

10. U.S. EPA. "Technical Support Document for 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/documents/pdf/archived/tsd/TSD%20Lead%20%20_E

PA%201-22-09.pdf. 

13. U.S. EPA. "Technical Support Document for the Lime Manufacturing 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%20Lime%20_EPA%

201-22-09.pdf. 

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

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%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 Greenhouse 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 for the Petroleum Refining Sector: Proposed 

Rule for Mandatory Reporting of Greenhouse 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/documents/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/documents/pdf/archived/tsd/TSD%20Soda%20Ash%2

0_EPA%201-22-09.pdf. 

22. U.S. EPA. "Technical Support Document for 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 for Industrial Wastewater Treatment: Final 

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

Atmospheric Programs. June, 2010. Available: 

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

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

Rule for Mandatory Reporting of Greenhouse Gases." 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 Emissions and Sinks: 1990-2006." April, 2008. EPA 

430-R-08-005. Available: 

http://www.epa.gov/climatechange/ghgemissions/usinventoryreport/archive.html. 

27. Climate Leaders Greenhouse Gas Inventory Protocol. Available: 

http://www.epa.gov/climateleadership/guidance/index.html. 

28. Voluntary Reporting of Greenhouse Gases 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/protocols/general-reporting-protocol/. 

30. California Climate Action Registry. August 2008. Available: 

http://www.climateregistry.org/tools/protocols/general-reporting-protocol.html. 

31. California Air Resources Board Cap 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.westernclimateinitiative.org/index.php. 

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

Guidelines for National Greenhouse Gas Inventories." 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/LexUriServ.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.cleanenergyregulator.gov.au/NationalGreenhouse-and-Energy-Reporting/Fact-sheets-FAQs-andguidelines/Guidelines/Pages/default.aspx. 

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

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

39. World Resources Institute and World Business Council for Sustainable Development 

Greenhouse Gas Protocol. Available: http://www.ghgprotocol.org/. 

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

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

http://www.api.org/environment-health-and-safety/climate-change/whatsnew/compendium-ghg-methodologies-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 Convention on Climate Change. Available: 

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

44. "Clean Energy Legislative Package." Australian Government Department of Climate 

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

45. Comment on the Mandatory Greenhouse Gas 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 Defense 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”. Memorandum 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/reporters/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.regulations.gov/#!documentDetail;D=EPA-HQOAR-2008-0508-2229.
18 

Appendix A1 

Summary Evaluation of Alternative Calculation Equations 

 
19 

Table A1-1. Summary of the Evaluation of Alternative 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 alternative 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, disclosure 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 used instead of facility-specific information 

resulting in lower accuracy than Tier 1. Both methods still require 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 CF4 and C2F6 and IPCC Tier 1 for 

CO2 emitted during electrolysis) use default emission factors which result in greater 

uncertainty than the current method. The third for calculating CF4 and C2F6 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 CF4 and 

C2F6, ±50 percent. The alternatives still use production 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., raw materials). The alternatives eliminate 

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

still require clinker production; 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 depending on how general the emission factors 

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

appropriate because it has a much higher uncertainty 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 CO2, 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 CH4. 

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 HFC-23 emissions). 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. 

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 provided 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 emission 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 identified 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 excludes small contributors, and (5) plantwide CO2 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, which, 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 data. 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, disclosure 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 identified that would be an appropriate alternative. 

Two alternative calculation methods were identified: 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 dolomite. 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; according 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 accurate 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 identified 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 information; 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 CO2 and 

CH4 (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 CO2; 30-80% 

higher for CH4). The second alternative requires routing of process vent emissions to 

stacks for direct and continuous measurements of CO2 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 quarterly basis. The alternative has a high level 

of accuracy because it is based on source specific 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 identified 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 were identified for calculating CO2 emissions. The 

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

flare gas burned. The second method uses test 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 CO2 and CH4 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 GHG emission estimates and would not avoid 

the use of “inputs to equations” data elements 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 emissions. This approach will yield less accurate 

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

2 of the evaluationa

, disclosure concerns were identified with crude feedstock 

throughput data. The second alternative method 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 SamplersTM, 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 refinery 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 unstabilized fuel oil, 3 alternatives were 

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

to calculate the CH4 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.); according 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, sulfur 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, disclosure concerns were identified for this 

information.a

 

AA Pulp and Paper No calculation methodologies were identified 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 furnaces 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 applicable 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 slight 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, disclosure 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. The second option is to estimate emissions 

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

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

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

default factors are used rather than 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 based on the quantity of carbon used in the 

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

accurate as the current 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 CH4 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 ‘Inputs to Equations’ Data Elements Deferred to March 31, 2015” 

memorandum. 
25 

Appendix A2 

Detailed Evaluation of Alternative 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 

Source1

 ID Description 

CARB 1 Same as 40 CFR part 75: CEMS. 

2 Calculate emissions similar to IPCC methods using fuel consumption and 

carbon or heat content. Still requires fuel input information for calculations, 

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

evaluation. 

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

calculations, which was identified as having disclosure concerns in Step 2 

of the evaluation. 

2 Same as 40 CFR part 75: CEMS. 

TCR 1 Calculate emissions similar 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 using WRI/WBCSD protocols. Still requires fuel input 

data in calculations, which was identified 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 information which was identified as 

having disclosure concerns in Step 2 of the evaluation. 

40 CFR 

part 75 

 CO2 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 balance approach similar to Tier 3. Still 

requires fuel and heat content information 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 identified as having disclosure concerns 

in Step 2 of the evaluation. . 

Tier 

3 

Similar to IPCC Tier 2, but uses EF based on representative 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 IPCC Tier 3 approaches. 

2 CEMS when a CO2 diluent monitor is installed for measurements of other 

pollutants. 

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

requires fuel and heat content information as inputs, which were identified 

as having disclosure concerns in Step 2 of the evaluation. 

2 CO2 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 Registry; 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 Reporting 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 

Source1

 ID Description 

IPCC Tier 

1 

Multiplies facility-level production times the highest default emissions 

factor in IPCC Tier 1, which assumes no abatement of N2O emissions. 

Much lower accuracy than current method, 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 destruction factors and not 

defaults. More accurate than IPCC Tier 2 but still 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 Climate Change, 2006; U.S. Inv = U.S. National Inventory Report, 2008 Method; WRI/WBCSD = World Resources 

Institute/World Business Council for Sustainable 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 

Source1

 ID Description 

IPCC Tier 1 -

General 

Uses default emission factors for CF4 and C2F6 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 CF4 and C2F6. High uncertainty compared to estimating 

emissions with the current method for CF4 and C2F6, about ±50 percent. 

Could develop new emission factors for CF4 and C2F6 to reduce the 

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

aluminum produced which was identified as having disclosure concerns 

in Step 2 of the evaluation. 

Tier 1 - 

Electrolysis 

Uses default emission factors for CO2 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 Panel 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 

Source1

 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 having 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 uses 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 oxidation 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 content 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 default carbon content value 

and calculates annual, facility-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/WBCSD = The World Resource Institute and World Business Council for Sustainable 

Development’s Greenhouse Gas Protocol; TCR-GRP = The Climate Registry General Reporting Protocol For the Voluntary Reporting Program, May 2008; DOE = 

Department of Energy 1605(b) Voluntary Reporting Program – Ammonia; 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 

Source1

 ID Method 

Type2

Description 

IPCC Tier 

1 

Cement Default factors; 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/WBCSD, 1A but w/default factors. 

WRI/WBCS

D 

2A Cement Site/corporate 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/WBCSD, 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/WBCSD, 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 Climate Change, 2006; U.S. Inv = U.S. National Inventory Report, 2008 Method; WRI/WBCSD = World Resources 

Institute/World Business Council for Sustainable Development; CA AB32 = CA Mandatory Reporting Program; CCAR = California Climate Action Registry; 

DOE = Department of Energy’s 1605 (b) Voluntary Reporting Program; CL = EPA Climate Leaders; EU ETS = European Union Emission Trading 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 materials consumed, the quantity of clinker incorporated into the cement, and the 

quantity of cement produced. It calculates CO2 emissions based on the amount of raw materials and their carbonate content. This approach directs companies to 
31 

collect data on cement production, the raw material ratio to produce clinker and the CaCO3 equivalent content of the raw materials, thus allowing companies to 

monitor changes in emissions due to modifying the cement manufacturing process. 

Clinker Production-Based method is a mass balance approach based on the quantity of clinker produced. It calculates CO2 emissions based on the volume and 

composition of clinker produced as well as the amount of cement kiln dust (CKD) not recycled to the kiln. This approach has become 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 types (compositions) and quantities of carbonate(s) consumed to produce 

clinker, as well as the respective emission factor(s) of the carbonate(s) consumed. It includes an adjustment to subtract any uncalcined 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 

Source1 ID Description 

Dow 

Corning 

1 Same as current method for CO2, except excludes from the mass balance 

inputs contributing less than 5% of plant 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 equations” 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 CO2, except with more flexibility in how carbon 

content is reported (e.g., supplier, independent 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 CO2 Tier 

1 

Uses mass of process outputs (product and nonproduct) and productionbased emission factors. Still uses production data which was identified as 

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

accuracy of estimates 25-50%. 

IPCC CO2 Tier 

2 

Similar to current method but uses default emission factors instead of 

facility specific carbon content. Still uses 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 material, energy content of carbon material, and 

emission factor based on energy content. Use of default factors would 

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

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

materials and amount of materials which was identified as having disclosure 

concerns in Step 2 of the evaluation. 

U.S. Inv Same as IPCC CO2 Tier 1. 

IPCC CH4 Tier 

1 

Use mass of product and generic production-based emission factors. Still 

uses production data which was identified as having disclosure concerns in 

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

Protocols and 

programs created 

after GHGRP 

No programs were identified. 

1

 IPCC = Intergovernmental Panel on Climate Change, 2006; Dow Corning – Comments submitted 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 Greenhouse 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 factor 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 measurement of the concentration and 

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

obtain instantaneous F-gas emission rate. Total quantity of F-gas 

released is the annual sum of measured instantaneous 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 rate, 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 Panel on Climate Change, 2006. 

 
34 

Appendix A2. Subpart N – Evaluation of Alternative Calculation Equations 

The current calculation methodology is a modified version of IPCC Tier 3. Process CO2 emissions are 

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

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

emission factor for carbonate-based raw material (shown 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 

Source1

 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. Significant decrease in accuracy of 

emission estimates (60% from current method). 

IPCC Tier 

2 

Output Uses default emission factors and cullet ratios, and production 

information for specific types of glass 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 equations” 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 different 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 uses “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 equations” 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 equations” data elements. 

Protocols and 

programs 

created after 

GHGRP 

No new calculation methods identified. 

1

 IPCC = Intergovernmental Panel on Climate Change, 2006; U.S. Inv = U.S. National Inventory Report, 2008 Method; DOE = Department of Energy’s 1605 (b) 

Voluntary Reporting Program; EU ETS = European Union Emission Trading System; ANMGGRP = Australian National Mandatory Greenhouse 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 destruction efficiency. Still requires production data which was identified as 

having disclosure concerns in Step 2 of the evaluation. Higher uncertainty 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 data 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 sampling frequency (daily sampling yields 1 – 2 

percent uncertainty). 

IPCC Tier 

3A 

Simplified version of current method (uses concentration of HFC-23 in the gas vented from 

process, mass flow of process stream, mass flow of HFC-23/other product stream, and 

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

monitoring. Still requires 2015 input data which were identified as having disclosure 

concerns in Step 2 of the evaluation. Uncertainty 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 onsite 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 content 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 destroyed 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. Inventory of Greenhouse Gas 

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

HCFC-22 Emissions from Production of HCFC-22, Version 2.0. December 2007; DOE = Department of Energy’s 1605(b) Voluntary Reporting 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 would 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 provided to assess the accuracy of the methodology. 

Method would not reveal any of the “inputs to equations” 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 

Source1

 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 CO2 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 information which were identified as having 

disclosure concerns in Step 2 of the evaluation. 

API 1 Uses production rate and simplified stoichiometric ratios. Method 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 proportionality 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 Mechanism. 

 
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 considered but not adopted in the 

final GHGRP: (1) a simple mass balance assuming all the carbon input to the process converts to CO2; and 

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

summary. 

Methods 

previously 

considered but 

not adopted in 

final GHGRP 

Source1

 ID Description 

CL Section 

2.2 

Exclude small contributors from mass balance (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 factors instead of site-specific information and 

information on inputs. 

 Not comprehensive, i.e., IPCC listed only 5 of the 7 processes in GHGRP 

 Hides recipes/ingredients, but not production 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 carbon 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 CO2 mass balance (ignore movement of 

energy sources within plant boundaries) 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 adopted in the final GHGRP or are identical 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 guidelines, section 4.66 (similar to IPCC Tier 2) 

 UN, Framework on Climate Change – Clean Development 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/WBCSD = World Resources Institute/World Business Council for Sustainable 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 default 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% uncertainty compared to the current method. However, the 

annual mass of each carbon-containing material is the same type of information 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 production type (imperial smelting furnace, direct 

smelting furnace). Uses production data, which 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 emission factors are based on country-specific 

information on the use of reducing agents, furnace types, and other process 

materials, and default carbon contents. Method 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-specific emission factors that 

is applied to the quantity of feed or product material. Appropriate for facilities 

where process inputs and operating parameters are consistent. This option was not 

adopted because of the potential 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 content 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 materials, 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 Climate Change, 2006; ANMGGRP = Australian National Mandatory Greenhouse Gas Reporting Program; 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 

Source1

 ID Method 

Type2

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 carbonate inputs to the kiln and emission 

factors and calcinations fractions to the carbonates consumed. Low 

uncertainty in emissions but requires feedstock information which was 

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

U.S. Inv Output Same 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 and 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 lime. It is not widely used (or used at all) and not 

appropriate for consideration. The CDM provides a methodology for hydraulic lime production uses fossil fuel 

usage and electricity usage to estimate emissions. This method is for a new method of producing hydraulic lime 

for construction purposes by blending conventional hydraulic lime with alternative material additives. 1

 IPCC = Intergovernmental Panel on Climate Change, 2006; U.S. Inv = U.S. National Inventory Report, 2008 Method; WRI/WBCSD = World Resources 

Institute/World Business Council for Sustainable Development; EU ETS = European Union Emission Trading System; TCR = The Climate 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 

Source1

 ID Description 

IPCC Tier 

1 

Uses emission factors based on the mass of carbonate consumed. Considers only 

limestone and dolomite are used and assigns default fraction partitioning the use of 

them. High uncertainty in emissions. Still requires knowing overall carbonate 

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

evaluation. 

IPCC Tier 

2 

Same as Tier 1, except the fraction of limestone 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 Climate Change, 2006; ANMGGRP = Australian National Mandatory Greenhouse Gas Reporting Program. 

 
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 

Source1

 ID Description 

IPCC Tier 

1 

Uses default emission factors and assumes no abatement. Facility level based 

rather than unit based. Still 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 and destruction factors on a site-specific 

basis. Still requires using production information 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 N2O 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 national 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-selective catalytic reduction control technologies. 

Protocols and 

programs 

created after 

GHGRP 

None identified. 

1

 IPCC = Intergovernmental Panel on Climate Change, 2006; U.S. Inv = U.S. National Inventory Report, 2008 Method; WRI/WBCSD = World Resources 

Institute/World Business Council for Sustainable 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 use 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 CO2 and CH4 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 

CO2; 30-80% for CH4) 

 Default factors cannot reflect site-specific differences in characteristics 

such as the type of feedstock, operating conditions, etc. 

 More appropriate for sector wide estimates 

IPCC Tier 3, 

modified 

Direct 

measurements 

Requires routing of process vent emissions to stacks for direct and continuous 

measurements of CO2 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 

 CH4 and N2O emissions from combustion sources would be calculated 

using subpart C procedures. 

 More accurate and less uncertainty than current option 

 Similar to IPCC Tier 3 approach, except IPCC indicates that process vent 

emissions may be either estimated or measured, and IPCC CH4 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 default 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 emission factor approach is thought to be reasonably 

accurate during normal operation. 

 More appropriate for sector wide estimates. 

API Test data Uses vendor or facility test data to calculate CO2 and CH4 emissions (N2O are 

considered negligible by API). 

 More accurate than default emission factors; however, level of uncertainty 

is higher compared to using measured 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 Climate Change, 2006; U.S. Inv = U.S. National Inventory Report, 2008 Method; WRI/WBCSD = World Resources 

Institute/World Business Council for Sustainable Development; EU ETS = European Union Emission Trading System; API = American Petroleum 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 CO2 emissions (allowed only for units with throughputs less 

than 10,000 bbls/stream day), the 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 default emission factors for calculating the 

emissions of CO2 and CH4 from asphalt blowing operations. Part 98 

calculations methods for both controlled and uncontrolled asphalt blowing 

operations relies 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). 

 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-specific differences in characteristics 

such as operating conditions, etc. 

 More appropriate for sector 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-specific differences in characteristics 

such as operating conditions, effectiveness of LDAR programs, etc. 

 More appropriate for sector wide estimates 

Protocols and 

programs 

created after 

GHGRP 

UNFCCC Direct 

measurements 

Measure the flow rates of the physical leaks using Hi-Flow SamplersTM, 

calibrated bag, or other suitable flow measurements technology and calculate 

the emissions using the rate x time period of leaking. 

 More accurate and less uncertainty than current option. 

 More costly due to large number of components to monitor. 

 May not be practical to monitor some components due to safety and 

accessibility issues. 

 Data used to calculate emissions does not contain information 

determined to have disclosure concerns in Step 2 of the evaluation. 1

 API = American Petroleum Institute; UNFCCC = United 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 CH4 published by API multiplied by the 

quantity of crude oil. 

 Still uses the amount of unstabilized 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 would likely be high compared to 

current methods 

 Default factors cannot reflect site-specific differences in characteristics 

such as the type of crude, operating conditions, etc. 

 More appropriate for sector wide estimates 

API API E&P 

TANKS 

program 

API E&P TANKS program, which uses pressure differential, 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 unstabilized 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 unstabilized 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 Other 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 

Source1

 ID Description 

U.S. Inv Option 1 Uses default factors based on regional chemical composition of phosphate rock. 

Less accurate than current method, but still requires monthly 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 

Type2

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 alternative methodologies were reviewed for these sources as they will be 

covered under the subpart C analysis. 

 Subpart AA requires reporting of fossil fuel and biogenic emissions from recovery furnaces and lime kilns. 

The fossil fuel component of the emissions are calculated using methods in subpart 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 biogenic 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 Subpart AA for calculations. 

1

 GHG TSD = GHG technical support documents ; WRI/WBCSD = World Resources Institute/World Business Council for Sustainable Development; 

ICFPA/NCASI = International Council on Forest and Paper Association/National Council for Air and Stream Improvement; CARB = California 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 

Source1

 ID Description 

IPCC Tier 1 Output based approach (using production information) and using default CO2 and 

CH4 emission factors from the 2006 IPCC guidelines, and silicon carbide output. 

Uncertainty estimated to 10%. Requires production 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 information) using default CO2 and CH4

emission factors from the 2006 IPCC guidelines, 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 Panel 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 

Source1

 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 identified as having disclosure concerns 

in Step 2 of the evaluation. 

IPCC Tier 2S Uses an annual site-specific emission factor to estimate emissions. Annual 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 disclosure concerns in Step 2 of the 

evaluation. 

Protocols and 

programs 

created after 

GHGRP 

None identified. 

1

 IPCC = Intergovernmental Panel 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 

Source1

 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 Climate Change, 2006; ANMGGRP = Australian National Mandatory Greenhouse Gas Reporting Program. 

 
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 

Source1

 ID Description 

IPCC Tier 

1 

Uses default emission factor per unit of output and national productivity data. Has a 

high uncertainty. More appropriate for aggregated 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 emission 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 accounts 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 emission factors. High uncertainty in emission estimates. More 

appropriate for aggregated process information 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 Climate Change, 2006; U.S. Inv = U.S. National Inventory Report, 2008 Method; ANGGRP = Australian 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 

Source1

 ID Description 

U.S. Inv Reporters use the existing part 98 CH4 calculation methodology. Higher uncertainty in 

emissions than the current method due to default 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 Emissions 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 sources, including boilers, heaters, engines, 

furnaces, kilns, ovens, flares, incinerators, dryers, and any other equipment or machinery that 

burns fuel. From two regulatory databases, counts for certain sources are available: there are 

14,142 industrial, commercial, and institutional boilers and 55 CISWI units. Based on 2011 

annual report submissions, there were 1,985 facilities that reported to GHGRP under subpart C. 

Under subpart C, sources must provide emission estimates for CO2, CH4, and N2O for each 

combustion unit. Emissions must be reported separately 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, NOX, SO2 CEMS 

Yes Yes 

Subparts CCCC and DDDD - CISWI NSPS 

and Emissions Guidelines 

PM, NOX, SO2 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 installation 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 Facilities 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 level. This included CEMS for PM, CO, NOX, and SO2. 

Table C-2 provides the total number of units which have at least one CEMS installed. In 

addition, with new requirements in the Boiler MACT, there are an additional 95 units which 

would install a CEMS; this value is also shown in Table C-2. There were 177 facilities that 

reported under the GHGRP using a total of 311 CO2 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 

CO2 CEMS/Total 

Count of CO2 CEMS 

14,142/1025 95 55/31 177/311 

 Subpart C CEMS Count

Table C-3 summarizes the actual data collected for facilities using CO2 CEMS, non-CO2 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 CO2 CEMS for 

GHGRP 

Reporting non-CO2

GHG CEMS for 

GHGRP 

Reporting non-GHG CEMS for 

Other EPA Programs 

Actual Potentialc

Facilities 177a

 0 - - 

Units 311b

 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 CO2 emissions. 

b

 The total number of CO2 CEMS at the facilities which reported CO2 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 N2O process emissions from all adipic acid production units 

combined. For N2O emissions, facilities may either use a site-specific emission factor applied to 

the annual adipic acid production, or directly measure the emissions using an EPA-approved 

alternative method to the site-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 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 NSPS 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, photoionization, 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 

compliance due to cost, and would likely use other options instead (e.g., temperature 

monitoring). Due to the amount of unknown variables, for this analysis it was assumed that no 

equipment is installed which would facilitate the installation of GHG CEMS. 

 
59 

Summary of Available Data on Facilities Reporting the Use of CEMS

No facilities reported the use of CEMS to the GHGRP. Subpart E facilities may also use an N2O 

CEMS alternative monitoring option provided approval is granted. 

Subpart E CEMS Count

Table E-2 summarizes the actual data collected for facilities using N2O CEMS and non-GHG 

CEMS. No facilities were identified with pre-existing N2O CEMS and CO2 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 CO2 CEMS for the 

GHGRP 

Reporting non-CO2

GHG CEMS for the 

GHGRP 

Reporting non-GHG CEMS for 

Other EPA Programs 

Actual Potentiala

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 were 10 facilities that reported to GHGRP under 

subpart F. 

Under subpart F, facilities estimate CF4 and C2F6 process emissions from anode effects in all 

prebake and Søderberg electrolysis cells combined. Facilities also estimate CO2 emissions from 

anode consumption and on-site anode baking. For CF4 emissions, facilities must calculate the 

emissions using a mass balance approach. Emissions of C2F6 must be calculated from the CF4

emissions using a tested ratio of C2F6 to CF4 production. For CO2 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 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 subpart do not require monitoring which is related to 

CEMS equipment and would thus not facilitate the installation of GHG CEMS. 

Summary of Available Data on Facilities 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 devices used to comply with the NESHAP are 

scrubbers which do not typically require monitoring 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 CO2 CEMS, non-CO2 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 on control devices. 

 
61 

Table F-2. Subpart F CEMS Counts 

Basis CO2 CEMS for 

GHGRP 

Reporting non-CO2

GHG CEMS for 

GHGRP 

Reporting non-GHG CEMS for 

Other EPA Programs 

Actual Potentiala

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 were 22 facilities that reported to GHGRP under 

subpart G. 

Under subpart G, facilities estimate CO2 process emissions from each ammonia manufacturing 

unit, and CO2 emissions collected and either used on-site or transferred off-site following the 

requirements of subpart PP (CO2 suppliers). For estimating CO2 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 applicable to ammonia manufacturers. 

Summary of Available Data on Facilities 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 CO2 CEMS, non-CO2 GHG 

CEMS, and non-GHG CEMS. No facilities were identified with pre-existing CO2 CEMS. No 

assumption could be made for a potential count based on lack of information on control devices 

and monitoring requirements. 

Table G-1. Subpart G CEMS Counts 

Basis CO2 CEMS for 

GHGRP 

Reporting non-CO2

GHG CEMS for 

GHGRP 

Reporting non-GHG CEMS for 

Other EPA Programs 

Actual Potentiala

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 summary 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 submissions, 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 CO2 process emissions from calcination in each kiln and CO2

combustion emissions from each kiln. They are also required to estimate and report CH4 and N2O 

combustion emissions from each kiln. For CO2 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 

Industrya

 

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 O2 CEMS to correct to 

constant O2. Yes No 

Subpart F—NSPS for Portland 

Cement Plants 

PM CEMS, NOX CEMS, SO2

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 including alkali bypasses at all major and area sources, except for kilns that burn hazardous 

waste and are subject to and regulated under 40 CFR 63, subpart EEE.
64 

Summary of Available GHGRP and Other Data on Facilities Reporting the Use of CEMS

Table H-2. CEMS Data from Databases 

GHGRP Cement NSPS Database 

Count of Facilities with CO2

CEMS/Total Count of CO2 CEMS 

Total Kiln Count/Count of Kilns with 

CEMS; Total Facility Count/Count of 

Facilities with non-CO2 CEMS 

82/112 121/50; 64/36 

 The cement NSPS database only provides CEMS counts for SO2, NOX, and THC CEMS, while 

data on Hg, PM, and HCl CEMS were not provided. As such, the count from the cement database 

is a low estimate. 

 In comparison to the cement database, the GHGRP 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 are 100 plants with 140 kilns. 

 The data from GHGRP and the cement database are 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 collected for facilities and units using CO2 CEMS, non-CO2 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 CO2 CEMS for 

GHGRP 

Reporting non-CO2

GHG CEMS for 

GHGRP 

Reporting non-GHG CEMS for 

Other EPA Programs 

Actual Potentialf

Facilities 82a 0c 0c 14d

Units 112b 0c 0c 28e

NA = No estimate is available. 

a Number of facilities reporting to GHGRP in 2011 that they are using a CEMS to report CO2 emissions. 

b

 The total number of CO2 CEMS at the facilities which reported CO2 CEMS. c

 No units or facilities are known to be using non-CO2 GHG CEMS (e.g., for CH4 or N2O). 

d

 Based on assuming that all kilns will have a non-GHG CEMS 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-GHG 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 were 10 facilities that reported to GHGRP under 

subpart K. 

Under subpart K, facilities estimate CO2 process emissions from each electric arc furnace that is 

used for any type of ferroalloy production. Facilities also estimate CH4 emissions from each 

electric arc furnace that is used for the production of silicon metal or ferrosilicon (65%, 75%, or 

90%). For estimating CO2 process emissions, facilities may either use a mass balance approach 

or use a CEMS. Emissions of CH4 must be estimated by multiplying the annual production of 

silicon metal or ferrosilicon and applying an applicable emission factor provided in the subpart. 

Applicable NSPS and NESHAP for Ferroalloy Plants

Table K-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 Z—NSPS for Ferroalloy 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 Facilities 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 CO2 CEMS, non-CO2 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 on control devices. 

Table K-2. Subpart K CEMS Counts 

Basis CO2 CEMS for 

GHGRP 

Reporting non-CO2

GHG CEMS for 

GHGRP 

Reporting non-GHG CEMS for 

Other EPA Programs 

Actual Potentiala

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 were 16 facilities that reported to GHGRP under 

subpart L. 

Under subpart L, facilities estimate emissions of HFCs, PFCs, SF6, NF3, and HFEs from each 

fluorinated gas production process and all fluorinated gas production processes combined, each 

fluorinated gas transformation process that is not a part of a fluorinated gas production process, 

each fluorinated GHG destruction process that is not a part of a fluorinated 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 emissions. However, this is only an 

alternative and no data were provided to determine how many (if any) would comply using this 

method. Since more economical options are available it is not anticipated any facilities would 

comply using CEMS. In addition, CPMS requirements would not be applicable to installation of 

CEMS equipment (e.g., CPMS includes monitoring temperature or liquid flow rate). 

Summary of Available Data on Facilities 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, there 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 manufacturing industry. Specific discussion on current 

installations was provided with discussion on how all equipment was able to withstand the 

corrosive environment. The commenter stated that 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 partly due to the unknown costs. 

Subpart L CEMS Count
68 

Table L-2 summarizes the actual data collected for facilities using CO2 CEMS, non-CO2 GHG 

CEMS, and non-GHG CEMS. Based on the public comment, 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 CO2 CEMS for 

GHGRP 

Reporting non-CO2

GHG CEMS for 

GHGRP 

Reporting non-GHG CEMS for 

Other EPA Programs 

Actual Potentiala

Facilities 0 1b NA NA 

Units 0 5b 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 were 110 facilities that reported to GHGRP 

under subpart N. 

Under subpart N, facilities estimate CO2 process emissions from each continuous glass melting 

furnace and CO2 combustion emissions from each continuous glass melting furnace. They are 

also required to estimate and report CH4 and N2O combustion emissions from each continuous 

glass melting furnace. For CO2 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 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 subpart do not require monitoring which is related to 

CEMS equipment and would thus not facilitate the installation of GHG CEMS. 

Summary of Available Data on Facilities Reporting the Use of CEMS

There were three facilities which reported CO2 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 CO2 CEMS, non-CO2 GHG 

CEMS, and non-GHG CEMS. The only source with data regarding CEMS installations was the 

CO2 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 CO2 CEMS for 

GHGRP 

Reporting non-CO2

GHG CEMS for 

GHGRP 

Reporting non-GHG CEMS for 

Other EPA Programs 

Actual Potentialc

Facilities 3a

 0 NA NA 

Units 3b

 0 NA NA 

NA = No information available. 

a Number of facilities reporting to GHGRP in 2011 that they are using a CEMS to report CO2 emissions. 

b

 The total number of CO2 CEMS at the facilities which reported CO2 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 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 O facilities may have CEMS installed to monitor HF emissions. However, this is only an 

alternative and no data were provided to determine how many (if any) would comply using this 

method. Since more economical options are available it is not anticipated any facilities would 

comply using CEMS. In addition, CPMS requirements would not be applicable to installation of 

CEMS equipment (e.g., CPMS includes monitoring temperature for thermal oxidizers which was 

a control device specifically mentioned in subpart O rule language). 

Summary of Available Data on Facilities Reporting the Use of CEMS

No facilities reported the use of CEMS to the GHGRP. Of note, subpart L facilities specifically 

requested the use of CEMS to measure fluorinated gases. However, a similar request was not 

made for subpart O. Since FTIR CEMS were shown 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 CO2 CEMS, non-CO2 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 CO2 CEMS for 

GHGRP 

Reporting non-CO2

GHG CEMS for 

GHGRP 

Reporting non-GHG CEMS for 

Other EPA Programs 

Actual Potentiala

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 were 103 facilities that reported to GHGRP 

under subpart P. 

Under subpart P, facilities estimate CO2 process and combustion emissions from each hydrogen 

production unit. CO2 collected and either used on site or transferred off site must also be 

estimated. Facilities also estimate CH4 and N2O combustion emissions from each hydrogen 

production unit. For CO2 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 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 not require monitoring which is related to CEMS 

equipment and would thus not facilitate the installation of GHG CEMS. 

Summary of Available Data on Facilities Reporting the Use of CEMS

There were three facilities which reported CO2 CEMS in GHGRP and each reported only one 

CEMS. 

Subpart P CEMS Count

Table P-2 summarizes the actual data collected for facilities using CO2 CEMS, non-CO2 GHG 

CEMS, and non-GHG CEMS. The only source with data regarding CEMS installations was the 

CO2 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 CO2 CEMS for 

GHGRP 

Reporting non-CO2

GHG CEMS for 

GHGRP 

Reporting non-GHG CEMS for 

Other EPA Programs 

Actual Potentialc

Facilities 3a

 0 NA NA 

Units 3b

 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 CO2 emissions. 

b

 The total number of CO2 CEMS at the facilities which reported CO2 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 subpart 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-located with an integrated iron and steel 

manufacturing process. 

Under subpart Q, process CO2 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 CO2 emissions using either a carbon mass balance method, a 

site-specific emission factor, or by a CO2 CEMS that meets the Tier 4 calculation methodology 

requirements of subpart C. Facilities are not required to determine CH4, N2O 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 submissions, 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 applicable 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 equipment, 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 Monitoring Requirements Applicable 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 FFFFFa 

(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 FFFFFa 

(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 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. 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 steel making blast furnaces, but these are not included in 

the processes in 40 CFR part 98, subpart Q. Subpart Q includes blast furnaces among the units that produce GHG 

emissions only from fuel combustion and not from raw materials. 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 volume 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 rate monitor used as part of a GHG CEMS, either based on 

location or on the accuracy and calibration requirements. Furthermore, the applicable rules do not specify that the 

flow rate monitors meet any applicable EPA performance specification, such as EPA Performance Specification 6 

for flow rate, or be calibrated against an EPA stack testing reference method. Therefore, we could assume that these 

rules do not establish monitoring requirements that would facilitate 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 CO2 CEMS with a total of 14 CEMS. These 

11 facilities are owned by two companies; two facilities are owned by ArcelorMittal and nine by Nucor. 

 One of the ArcellorMittal facilities (Indiana) is an integrated 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 emissions 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 collected for facilities and units using CO2 CEMS, non-CO2 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 CO2 CEMS for 

GHGRP 

Reporting non-CO2

GHG CEMS for 

GHGRP 

Reporting non-GHG CEMS for 

Other EPA Programs 

Actual Potentialc

Facilities 11a

 0 NA NA 

Units 14b

 0 NA NA 

NA = No information available. 

a Number of facilities reporting to GHGRP in 2011 that they are using a CEMS to report CO2 emissions. 

b

 The total number of CO2 CEMS at the facilities which reported CO2 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 were 13 facilities that reported to GHGRP under 

subpart R. 

Under subpart R, facilities estimate CO2 process emissions from each smelting furnace and CO2

combustion emissions from each smelting furnace. They are also required to estimate and report 

CH4 and N2O combustion emissions from each smelting furnace. For CO2 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

SO2 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 smelters do not contain any relevant monitoring 

requirements. The NSPS for primary lead smelters requires SO2 monitoring, but applies only to 

primary lead smelters constructed after October 16, 1974. There have been 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 SO2 CEMS. 

Summary of Available Data on Facilities 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 CO2 CEMS, non-CO2 GHG 

CEMS, and non-GHG CEMS. No facilities were identified with pre-existing CO2 CEMS. No 
80 

assumption could be made for a potential count based on lack of information on control devices 

and monitoring requirements. 

Table R-2. Subpart R CEMS Counts 

Basis CO2 CEMS for 

GHGRP 

Reporting non-CO2 GHG 

CEMS for GHGRP 

Reporting non-GHG CEMS for 

Other EPA Programs 

Actual Potentiala

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 were 73 facilities that reported to GHGRP under 

subpart S. 

Under subpart S, facilities estimate CO2 process emissions from each lime kiln and CO2

combustion emissions from each lime kiln. They are also required to estimate and report CH4

and N2O combustion emissions from each lime kiln. For CO2 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 subpart do not require monitoring which is related to 

CEMS equipment and would thus not facilitate the installation of GHG CEMS. 

Summary of Available Data on Facilities Reporting the Use of CEMS

One facility was reported to use CO2 CEMS in the 2011 GHGRP. The RIA for part 98 identified 

that all facilities would meet the Tier 4 criteria 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 CO2 CEMS, non-CO2 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 CO2 CEMS for 

GHGRP 

Reporting non-CO2

GHG CEMS for 

Reporting non-GHG CEMS for 

Other EPA Programs 
82 

GHGRP Actual Potentialb

Facilities 1a

 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 CO2 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 were 18 facilities that reported to GHGRP under 

subpart U. 

Under subpart U, facilities estimate CO2 process emissions for all miscellaneous carbonate use at 

the facility. For estimating CO2 process emissions, facilities must use a mass balance approach. 

Applicable NSPS and NESHAP for the Miscellaneous Use of Carbonates

There is no NSPS or NESHAP specifically applicable to miscellaneous use of carbonates. 

Summary of Available Data on Facilities 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 CO2 CEMS, non-CO2 GHG 

CEMS, and non-GHG CEMS. No facilities were identified with pre-existing CO2 CEMS. No 

assumption could be made for a potential count based on lack of information on control devices 

and monitoring requirements. 

Table U-1. Subpart UCEMS Counts 

Basis CO2 CEMS for 

GHGRP 

Reporting non-CO2 GHG 

CEMS for GHGRP 

Reporting non-GHG 

CEMS for Other EPA 

Programs 

Actual Potentiala

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 N2O process emissions from each nitric acid train. For N2O 

emissions, facilities may either use a mass balance 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 

NOX CEMS required for units 

constructed or modified after 

August 17, 1971 Yes No 

Each emission point for nitric acid production shall install NOX CEMS if constructed or 

modified after 1971; no alternatives are provided. 

Summary of Available Data on Facilities 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 NOX CEMS installed. Of the 45 nitric 

acid production plants, 20 nitric acid production plants employ CEMS for NOX emissions. At 

these 20 nitric acid plants there are 36 processes which have NOX CEMS; this is approximately 

58 percent of the total processes. It is presumed that the processes which do not have NOX

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 CO2 CEMS, non-CO2 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 CO2 CEMS for 

GHGRP 

Reporting non-CO2

GHG CEMS for 

GHGRP 

Reporting non-GHG CEMS 

for Other EPA Programs 

Actual Potentialb

Facilities 0 0 20 a NA 

Units 0 0 36a 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 not generated since the inventory data were reported by the 

facility and presumed to be the actual count of units with NOX 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 consists of each process that produces: 

 Acrylonitrile 

 Carbon black 

 Ethylene 

 Ethylene Dichloride 

 Ethylene Oxide 

 Methanol 

Each petrochemical facility must report CO2 process emissions and CO2, CH4, and N2O emissions 

generated by combustion of process off-gas in stationary combustion units and flares. GHG estimates are 

also necessary for CO2, CH4, and N2O emissions from burning supplemental fuel in stationary 

combustion units that also burn process off-gas. If Tier 4 criteria are met then CO2 emissions must be 

estimated by CEMS, otherwise the mass balance method is required. For CH4 and N2O the emission 

factor method is used. For ethylene processes only CO2 emissions may be estimated using Tier 3 or Tier 4 

for combustion of process off-gas. 

Based on 2011 annual report submissions, there were 64 facilities that reported to GHGRP under subpart 

X. 

Applicable NSPS and NESHAP for Petrochemical Plants and Facility Counts

Table X-1 shows the applicable NESHAP and NSPS for each facility type. Table X-2 shows the 

monitoring required by each of the NESHAP and NSPS 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 Manufacturing Industry 

 Subpart G—NESHAP From the Synthetic 

Organic Chemical Manufacturing 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 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 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 NSPS 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, photoionization, 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 compliance due to cost, and would likely use other options 

instead (e.g., temperature monitoring). Due to the amount of unknown variables, for this analysis it was 

assumed that no equipment is installed which would 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 CO2 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 collected for facilities and units using CO2 CEMS, non-CO2 GHG 

CEMS, and non-GHG CEMS. The only source with data regarding CEMS installations was the CO2

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 CO2 CEMS for 

GHGRP 

Reporting non-CO2

GHG CEMS for 

GHGRP 

Reporting non-GHG CEMS 

for Other EPA Programs 

Actual Potentialc

Facilities 2a 0 NA NA 

Units 2b 0 NA NA 

NA = No information available. 

a Number of facilities reporting to GHGRP in 2011 that they are using a CEMS to report CO2 emissions. 

b

 The total number of CO2 CEMS at the facilities which reported CO2 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, residual 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 contains 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 Refineries, Refinery Database Counts, and GHG 

Reporting Requirements

Table Y-1 provides a general overview of the NESHAP 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 NESHAP 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 available 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, O2

monitor 

Subpart J—NSPS for Petroleum Refineries Flow rate, CO CEMS, O2

monitor, SO2 monitor 

Table Y-2. GHGs Reported for Each Refinery Process, Process Unit Counts, and Monitoring 

Information from Applicable 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 

CO2 CH4 N2O 

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 O2, 

temperature, or 

operation of flare pilot. 

Flow monitoring 

required if modified 

before 1973 and control 

device is an ESP. 

Fluid Coking Y Y Y 

132a

N NA 

Coke Calcining Y Y Y N NA 

Delayed Coking N Y N N NA 

Catalytic Reforming Y Y Y 120 N NA 

Sulfur Recovery Y N N 187 Y SO2 and O2 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 vents’. This count was applied to all processes which refer to coke 

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 processes, CO CEMS are only applicable to catalytic 

cracking unit catalyst regenerators. Each catalytic cracking 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 SO2/O2 monitor associated with it. For CEMS 

installation cost estimates, a unit count of 1,580 was 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 CO2 CEMS within GHGRP, with a total of 24 CO2

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 determination we will not include the boiler 

data in the subpart Y CEMS counts. 

 

Subpart Y CEMS Count

Table Y-3 summarizes the actual data collected for facilities and units using CO2 CEMS, non-CO2 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 CO2 CEMS for 

GHGRP 

Reporting nonCO2 GHG CEMS 

for GHGRP 

Reporting non-GHG CEMS for Other 

EPA Programs 

Actual Potentialf

Catalytic 

Cracking and 

Sulfur 

Recovery 

Facilities 21a

 0 NA 104c

Units 

26b

 0 NA 317d

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 CO2 emissions. 

b

 The total number of CO2 CEMS at the facilities which reported CO2 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 were 13 facilities that reported to GHGRP under 

subpart Z. 

Under subpart Z, facilities estimate CO2 process emissions from each wet-process phosphoric 

acid process line. For CO2 emissions, facilities may either use 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 Industry: Wet-Process 

Phosphoric Acid Plants 

(No relevant monitoring 

requirements) No No 

The applicable NESHAP and NSPS for this subpart do not require monitoring which is related to 

CEMS equipment and would thus not facilitate the installation of GHG CEMS. 

Summary of Available Data on Facilities 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 unlikely that any of the non-combustion processes 

use CO2 CEMS. Phosphoric acid process emissions are combined with combustion emissions for 

calciners and dryers at 7 facilities. The ICR indicates that the 7 measure O2 instead of CO2. 

Subpart Z CEMS Count

Table Z-2 summarizes the actual data collected for facilities using CO2 CEMS, non-CO2 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 CO2 CEMS for 

GHGRP 

Reporting non-CO2

GHG CEMS for 

GHGRP 

Reporting non-GHG CEMS for 

Other EPA Programs 

Actual Potentialb

Facilities 0 0 7a 7a

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 under 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 products (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 (CaCO3, Na2CO3) in the chemical recovery areas of 

chemical pulp mills. 

Approximately 425 pulp and paper mills 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) (NCASI 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 subpart AA. Based on 2011 annual report submissions, there were 110 

facilities that reported to GHGRP under subpart AA. 

Applicable GHGRP, NSPS, and NESHAP Monitoring 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 and 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 BBb

Monitoring 

Required by 

40 CFR 63, 

subpart S 

Monitoring 

Required by 

40 CFR 63, 

subpart MM 

Kraft or Soda 

Mill 

Each chemical 

recovery 

furnace 

CO2, biogenic 

CO2, CH4, 

N2O 168 

Total reduced 

sulfur (TRS) 

CEMS, O2

CEMS, percent 

volume dry basis 

[60.284(a)(2)] 

No relevant 

monitoring 

No relevant 

monitoring 

Kraft or Soda 

Mill 

Lime Kilns, 

fossil fuel 

combustion 

CO2, biogenic 

CO2, CH4, 

N2O 164 

TRS CEMS, O2

CEMS, percent 

volume dry basis 

[60.284(a)(2)] 

No relevant 

monitoring 

No relevant 

monitoring 

Sulfite Pulp 

Mills 

Each chemical 

recovery 

furnace 

CO2, biogenic 

CO2, CH4, 

N2O 

13 

No relevant 

monitoring 

No relevant 

monitoring 

No relevant 

monitoring 

Stand Alone 

Semichemical 

Mills 

Each chemical 

recovery 

furnace 

CO2, biogenic 

CO2, CH4, 

N2O 

12 

No relevant 

monitoring 

No relevant 

monitoring 

No relevant 

monitoring 

Chemical 

pulp mills 

Makeup 

chemical 

addition to 

chemical 

recovery area 

CO2 

≤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 SO2, NOX, 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 performing that monitoring was not available. The 

NSPS (subpart BB) requires oxygen monitoring only for chemical recovery furnaces and pulp mill lime 

kilns at kraft pulp mills. The two Pulp and Paper 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 recovery 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), O2, 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, O2, and moisture CEMS would mean that these units 

would also have the basic CEMS infrastructure in place, such as platforms, sampling lines, and data 
96 

acquisition systems, and this would lower the cost of adding GHG CEMS equipment, such as a CO2

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 incinerators (CISWI) and the boiler and process heater 

NESHAP. Table AA-2 summarizes these data for the total number of units and those with a CEMS. 

Table AA-2. Summary of CEMS Data from Other EPA Databases 

GHGRP CISWI Database Boiler and Process Heater 

NESHAP Database 

Count of Facilities Which Reported 

CO2 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 process heater survey data, we can identify 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 kilns at pulp and paper facilities that have some sort of 

CEMS; however, none of the units appear to be process 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 those 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 CO2 CEMS, non-CO2 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 CO2 CEMS for 

GHGRP 

Reporting non-CO2

GHG CEMS for 

GHGRP 

Reporting non-GHG CEMS for 

Other EPA Programs 

Actual Potentialb
97 

Facilities 0 0 NA NA 

Units 0 0 266a 266a

NA = No information available. 

a The NCASI survey provided process unit data and the 2009 RIA estimated that units were subject to Tier 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 O2

CEMS and, therefore, already have some basic infrastructure for a CEMS that could be used to estimate 

GHG emissions with the addition of a flow meter and CO2 analyzer. Similarly, the RIA estimates that a 

large portion of the sources will meet Tier 4 requirements. However, because the number of facilities 

reporting to GHGRP (110) is substantially lower than 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 unit 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 was 1 facility that reported to GHGRP under 

subpart BB. 

Under subpart BB, facilities estimate CO2 and CH4 process emissions from all silicon carbide 

process units or furnaces combined. For estimating CO2 process emissions, facilities may either 

use a mass balance approach or use a CEMS. Process emissions of CH4 are estimated using 

emission factors relevant to the monthly amount of petroleum coke consumed at the facility. 

Applicable NSPS and NESHAP for Silicon Carbide Manufacturers

There is no NSPS or NESHAP specifically applicable to silicon carbide manufacturers. 

Summary of Available Data on Facilities 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 CO2 CEMS, non-CO2 GHG 

CEMS, and non-GHG CEMS. No facilities were identified with pre-existing CO2 CEMS. No 

assumption could be made for a potential count based on lack of information on control devices 

and monitoring requirements. 

Table BB-1. Subpart BB CEMS Counts 

Basis CO2 CEMS for 

GHGRP 

Reporting non-CO2

GHG CEMS for 

GHGRP 

Reporting non-GHG CEMS for 

Other EPA Programs 

Actual Potentiala

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 CO2 process emissions from each soda ash manufacturing 

line and CO2 combustion emissions from each soda ash manufacturing line. They are also 

required to estimate and report CH4 and N2O combustion emissions from each soda ash 

manufacturing line. For CO2 emissions, facilities may use a mass balance or emission factor 

approach to estimate separate process and combustion 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 subpart do not require monitoring which is related to 

CEMS equipment and would thus not facilitate the installation of GHG CEMS. 

Summary of Available Data on Facilities Reporting the Use of CEMS

One facility reported the use of one CO2 CEMS to report emissions in the GHGRP. 

Subpart CC CEMS Count

Table CC-2 summarizes the actual data collected for facilities using CO2 CEMS, non-CO2 GHG 

CEMS, and non-GHG CEMS. One facility was identified with pre-existing CO2 CEMS. No 

assumption could be made for a potential count based on lack of information on control devices 

and monitoring requirements. 

 
100 

Table CC-2. Subpart CC CEMS Counts 

Basis CO2 CEMS for 

GHGRP 

Reporting non-CO2

GHG CEMS for 

GHGRP 

Reporting non-GHG CEMS for 

Other EPA Programs 

Actual Potentialc

Facilities 1a

 0 NA NA 

Units 1b

 0 NA NA 

NA = No information available. 

a Number of facilities reporting to GHGRP in 2011 that they are using a CEMS to report CO2 emissions. 

b

 The total number of CO2 CEMS at the facilities which reported CO2 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 Dioxide 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 CO2 process emissions from each chloride process line. For 

estimating CO2 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 subpart do not require monitoring which is related to 

CEMS equipment and would thus not facilitate the installation of GHG CEMS. 

Summary of Available Data on Facilities 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 CO2 CEMS, non-CO2 GHG 

CEMS, and non-GHG CEMS. No facilities were identified with pre-existing CO2 CEMS. No 

assumption could be made for a potential count based on lack of information on control devices 

and monitoring requirements. 

Table EE-2. Subpart EE CEMS Counts 

Basis CO2 CEMS for 

GHGRP 

Reporting non-CO2

GHG CEMS for 

GHGRP 

Reporting non-GHG CEMS 

for Other EPA Programs 

Actual Potentiala

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 CO2 process emissions from each Waelz kiln and 

electrothermic furnace, and CO2 combustion emissions from each Waelz kiln and electrothermic 

furnace. They are also required to estimate and report CH4 and N2O combustion emissions from 

each Waelz kiln and electrothermic furnace. For CO2 emissions, facilities may use a mass 

balance or emission factor approach to estimate separate process and combustion emissions, or 

use a CEMS to determine combined process and combustion emissions. 

Applicable NSPS and NESHAP 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 

SO2 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 

SO2 CEMS is only applicable for roasters at primary zinc smelters which are not applicable to 

GHG reporting and are thus not related to GHG CEMS installation. 

Summary of Available Data on Facilities 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 CO2 CEMS, non-CO2 GHG 

CEMS, and non-GHG CEMS. No facilities were identified with pre-existing CO2 CEMS. No 

assumption could be made for a potential count based on lack of information on control devices 

and monitoring requirements. 

Table GG-2. Subpart GG CEMS Counts 

Basis CO2 CEMS for 

GHGRP 

Reporting non-CO2

GHG CEMS for 

GHGRP 

Reporting non-GHG CEMS for 

Other EPA Programs 

Actual Potentiala

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 were 173 facilities that reported to GHGRP 

under subpart TT. 

Under subpart TT, facilities must estimate annual CH4 generation, emission, and destruction 

from the landfill. For estimating CH4 generation, facilities may measure the generation directly 

or estimate a value based on historic annual waste disposal quantities. Facilities that collect and 

control landfill gas must calculate CH4 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 CH4 recovered. 

Applicable NSPS and NESHAP for Industrial Waste Landfills

There are no NSPS or NESHAP which are applicable to industrial waste landfills. The definition 

of industrial waste landfills for purposes of the GHGRP specifically excludes municipal waste 

landfills, so part 60 subpart WWW (NSPS for MSW Landfills) is not applicable. 

Summary of Available Data on Facilities Reporting the Use of CEMS

No facilities reported the use of CEMS to the GHGRP. 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 CH4 recovered. The method of recording the amount of methane 

recovered using the gas collection system is unknown, so the applicability of CH4 CEMS is also 

unknown. For these purposes it will be assumed that no facility uses CEMS to monitor CH4

recovery. Also, for those industrial waste landfills which have gas collection systems, the facility 

is required to monitor the flow rate and temperature; the applicability of this equipment to 

installing CEMS (e.g., is the flow monitor located 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 CO2 CEMS, non-CO2 GHG 

CEMS, and non-GHG CEMS. No facilities were identified with pre-existing CH4 CEMS. No 

assumption could be made for a potential count based on lack of information. 

Table TT-1. Subpart TT CEMS Counts 

Basis CO2 CEMS for 

GHGRP 

Reporting non-CO2

GHG CEMS for 

GHGRP 

Reporting non-GHG CEMS for 

Other EPA Programs 

Actual Potentiala

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 installing GHG CEMS for each subpart, a determination of 

the applicable population of sources for each subpart 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 included installations of GHG CEMS (CO2, CH4, or N2O) and 

non-GHG CEMS (NOX, 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., multiple stacks) which would each need their own 

CEMS. However, for some subparts this level of detail was not available and only facility counts 

were known. In those instances, only the facility count was used to determine the CEMS cost; 

while this may underestimate costs for certain subparts, due to a lack of data, it was not possible 

to provide a reliable count for number of process units. To determine counts the following 

sources were used: GHGRP data, part 98 GHG technical support documents for each subpart, a 

review of applicable NESHAP and NSPS rule requirements and associated databases and 

supporting documentation for each subpart, and the part 98 GHG Regulatory Impact Analysis 

(RIA). See Appendix B for a review of the information obtained. 

 

To keep this CEMS cost analysis consistent 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 CO2 CEMS 

 Source has non-CO2 GHG CEMS (such as N2O CEMS) or has non-GHG CEMS (such as 

NOX or CO monitors) 

 Source has no CEMS 

Five different cost scenarios were identified from the usage information and are summarized in 

Table C-1. Cost scenario 1 is a complete GHG CEMS installation for sources which do not have 

any CEMS related equipment installed. Cost scenarios 2 through 4 are reduced costs for sources 

which have current CEMS installations and would need to install minimal equipment (e.g., a 

CO2 analyzer and/or flow meter). The decision to apply scenarios 2, 3, or 4 costs to a particular 

subpart is based off applicable NSPS/NESHAP regulation knowledge and information provided 

in the GHG RIA. It was determined that no facilities/process units met 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 CO2 CEMs 

and no costs are calculated. 

 
108 

Table C-1. Summary of Costs for CO2 CEMS Modifications 

Scenario 

# Scenario

Total annual 

costs

1 Source has no CEMS -- Add CO2 analyzer, flow meter, and 

infrastructure $ 70,265 

2 Source has CEMS for other pollutants -- Add CO2 analyzer 

and flow meter $ 56,040 

3 Source has CEMS for other pollutants -- Add CO2 analyzer 

only $ 20,593 

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

only $ 24,511 

5 Source has CO2 CEMS No Cost a

No facilities/process units were determined to meet the scenario. 

 

Within each scenario, multiple cost scenarios were calculated because each subpart may require 

one analyzer or a combination of analyzers to measure GHGs. The most common GHG to report 

is CO2, however CH4 and N2O are also applicable depending on the subpart. While the GHG 

RIA provided a cost estimate for a CO2 CEMS, CH4 and N2O CEMS costs were not available. 

For this analysis, vendors were contacted and cost 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. Subpart O requires reporting of fluorinated gases; 

the applicability of CEMS for fluorinated gases was not analyzed, and therefore no costs were 

calculated for subpart O. Table C-2 summarizes the vendor cost information. 

Costs for each subpart were determined based on the count information identified (see Appendix 

B for subpart-specific details) and the scenario cost options. Costs 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 for installing the appropriate GHG CEMS. 

 If current non-CO2 CEMS installations were identified for a subpart then either scenario 

2 or 3 costs were applied for these counts depending on the type of CEMS identified. For 

facility/process units without current non-CO2 CEMs, the scenario 1 costs were applied. 

These two costs were added together to get the total cost for the facility. 

 For subparts which have a CO2 CEMS installed but would also report CH4 and/or N2O, 

only the cost associated with installing a CH4 and/or N2O analyzer was incorporated, and 

no costs for CO2 analyzers were included. 

Costs are shown for each subpart based on two count options: actual and potential CEMS counts. 

The actual count and associated CEMS costs correspond to the actual CEMS installation counts 

which were able to be identified from the various 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 and NESHAP rules. The potential counts include 

the actual counts plus the additional units/facilities that may be affected by NSPS or NESHAP 

requirements. The costs associated with the actual 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 installation) costs. For the costs associated with the 

potential count, the resulting costs were lower than the actual count scenario because more 

CEMS installations were estimated which resulted in fewer units in scenario 1 and more in 

scenarios 2 or 3. For many subparts, the actual 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)

CO2 analyzer $5,000 (a) $15,000‐$20,000 $12,000   $7,917   $12,472   $13,000  

N2O analyzer $5,000 (a) $15,000‐$20,000 $15,000   $10,096   $14,199   $14,000  

CH4 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 breakdown into counts for each scenario, costs for 

installing GHG CEMS were estimated. 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 capital and annual costs for installation of CO2 CEMS 

only (similar to the GHG RIA). Tables C-5 through C-7 summarize the count information for 

actual and potential units/facilities with CEMS control, and the assumptions used in the count 

determination. Tables C-8 through C-11 provide data on all three types of GHG CEMS (CO2, 

N2O, and CH4). 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, distributing the total unit installation cost 

between two or three CEMS is not appropriate; there are redundant component costs associated 
110 

with CO2, CH4, and N2O CEMS. If a facility were to install CEMS for all three GHGs, for 

example, the total cost incurred by the facility would not equal the sum of the CO2, CH4, and 

N2O individual monitor costs. Instead, cost estimates were developed based on vendor quotes for 

each possible combination of CO2, CH4, and N2O CEMS for each cost scenario. For this reason, 

the CO2, N2O, and CH4 costs in Tables C-8 through C-11 do not equal the total cost column; the 

CO2, N2O, and CH4 costs shown are the cost for installing individual GHG CEMS while the total 

cost is the more representative cost for installing multiple GHG CEMS. 
111 

Table C-3. Capital Cost Breakdown into Each Costing Scenario for Installation of CO2 CEMS Only, Based on Actual Counts and 

Subpart

Capital Investment

Scenario 1 Scenario 2 Scenario 3 Total

Actuala Potentialb Actuala Potentialb Actuala Potentialb Actuala Potentia

C $1,578,065,753 $1,578,065,753 $102,182,259 $111,374,792 $0 $0 $1,680,248,013 $1,689,440

E $ ‐  $ ‐  $ ‐ $ ‐ $ ‐ $ ‐  $ ‐ 

F $1,229,981 $1,229,981 $ ‐ $ ‐ $ ‐ $ ‐  $1,229,981 $1,229

G $2,705,958 $2,705,958 $ ‐ $ ‐ $ ‐ $ ‐  $2,705,958 $2,705H $3,443,947 $ ‐  $ ‐ $ ‐ $560,101 $560,101 $4,004,048 $560

K $1,229,981 $1,229,981 $ ‐ $ ‐ $ ‐ $ ‐  $1,229,981 $1,229

L $ ‐  $ ‐  $ ‐ $ ‐ $ ‐ $ ‐  $ ‐ 

N $13,160,798 $13,160,798 $ ‐ $ ‐ $ ‐ $ ‐  $13,160,798 $13,160

O $ ‐  $ ‐  $ ‐ $ ‐ $ ‐ $ ‐  $ ‐ 

P $12,299,811 $12,299,811 $ ‐ $ ‐ $ ‐ $ ‐  $12,299,811 $12,299

Q $18,572,715 $18,572,715 $ ‐ $ ‐ $ ‐ $ ‐  $18,572,715 $18,572

R $1,598,975 $1,598,975 $ ‐ $ ‐ $ ‐ $ ‐  $1,598,975 $1,598

S $8,855,864 $ ‐  $ ‐ $ ‐ $ ‐ $ ‐  $8,855,864 

U $2,213,966 $2,213,966 $0 $0 $0 $0 $2,213,966 $2,213

V $ ‐  $ ‐  $ ‐ $ ‐ $ ‐ $ ‐  $ ‐ 

X $7,625,883 $7,871,879 $ ‐ $ ‐ $ ‐ $ ‐  $7,625,883 $7,871

Y $191,139,063 $155,346,613 $ ‐ $18,094,775 $ ‐ $2,080,376 $191,139,063 $175,521

Z $737,989 $737,989 $ ‐ $ ‐ $140,025 $140,025 $878,014 $878

AA $7,881,432 $7,881,432 $25,731,576 $25,731,576 $ ‐ $ ‐  $33,613,009 $33,613

BB $122,998 $122,998 $ ‐ $ ‐ $ ‐ $ ‐  $122,998 $122

CC $368,994 $368,994 $ ‐ $ ‐ $ ‐ $ ‐  $368,994 $368

EE $860,987 $860,987 $ ‐ $ ‐ $ ‐ $ ‐  $860,987 $860

GG $737,989 $737,989 $ ‐ $ ‐ $ ‐ $ ‐  $737,989 $737

TT $ ‐  $ ‐  $ ‐ $ ‐ $ ‐ $ ‐  $ ‐ 

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

aCosts are based on the actual number of units/facilities for which information was available indicating current use of CEMS. See Appendix B 

subpart. 

bCosts are based on potential number of units/facilities that may be using CEMS based on NESHAP and NSPS rule requirements. Costs includ

where information is known as well as the additional potential number of units/facilities that may be using CEMS based on NESHAP and NSP

Appendix B for detailed information for each subpart. 
112 

Table C-4. Annual Cost Breakdown into Each Costing Scenario for Installation of CO2 CEMS Only, Based on Actual 

Subpart

Annual Cost

Scenario 1 Scenario 2 Scenario 3 Total

Actuala Potentialb Actuala Potentialb Actuala Potentialb Actuala Potenti

C $901,499,950 $901,499,950 $59,178,240 $64,502,040 $ ‐ $ ‐  $960,678,190 $966,00

E $ ‐  $ ‐  $ ‐ $ ‐ $ ‐ $ ‐  $ ‐ 

F $702,650 $702,650 $ ‐ $ ‐ $ ‐ $ ‐  $702,650 $70

G $1,545,830 $1,545,830 $ ‐ $ ‐ $ ‐ $ ‐  $1,545,830 $1,54H $1,967,420 $ ‐  $ ‐ $ ‐ $576,604 $576,604 $2,544,024 $57

K $702,650 $702,650 $ ‐ $ ‐ $ ‐ $ ‐  $702,650 $70

L $ ‐  $ ‐  $ ‐ $ ‐ $ ‐ $ ‐  $ ‐ 

N $7,518,355 $7,518,355 $ ‐ $ ‐ $ ‐ $ ‐  $7,518,355 $7,51

O $ ‐  $ ‐  $ ‐ $ ‐ $ ‐ $ ‐  $ ‐ 

P $7,026,500 $7,026,500 $ ‐ $ ‐ $ ‐ $ ‐  $7,026,500 $7,02

Q $10,610,015 $10,610,015 $ ‐ $ ‐ $ ‐ $ ‐  $10,610,015 $10,61

R $913,445 $913,445 $ ‐ $ ‐ $ ‐ $ ‐  $913,445 $91

S $5,059,080 $ ‐  $ ‐ $ ‐ $ ‐ $ ‐  $5,059,080 

U $1,264,770 $1,264,770 $0 $0 $0 $0 $1,264,770 $1,26

V $ ‐  $ ‐  $ ‐ $ ‐ $ ‐ $ ‐  $ ‐ 

X $4,356,430 $4,496,960 $ ‐ $ ‐ $ ‐ $ ‐  $4,356,430 $4,49

Y $109,191,810 $88,744,695 $ ‐ $10,479,480 $ ‐ $2,141,672 $109,191,810 $101,36

Z $421,590 $421,590 $ ‐ $ ‐ $144,151 $144,151 $565,741 $56

AA $4,502,417 $4,502,417 $14,902,287 $14,902,287 $ ‐ $ ‐  $19,404,705 $19,40

BB $70,265 $70,265 $ ‐ $ ‐ $ ‐ $ ‐  $70,265 $7

CC $210,795 $210,795 $ ‐ $ ‐ $ ‐ $ ‐  $210,795 $21

EE $491,855 $491,855 $ ‐ $ ‐ $ ‐ $ ‐  $491,855 $49

GG $421,590 $421,590 $ ‐ $ ‐ $ ‐ $ ‐  $421,590 $42

TT $ ‐  $ ‐  $ ‐ $ ‐ $ ‐ $ ‐  $ ‐ 

TOTAL $1,058,477,417 $1,031,144,332 $74,080,527 $89,883,807 $720,755 $2,862,427 $1,133,278,700 $1,123,37

aCosts are based on the actual number of units/facilities for which information was available indicating current use of CEMS. See Appendix B 

subpart. 

bCosts are based on potential number of units/facilities that may be using CEMS based on NESHAP and NSPS rule requirements. Costs includ

where information is known as well as the additional potential number of units/facilities that may be using CEMS based on NESHAP and NSP

Appendix B for detailed information for each subpart.
113 

Table C-5. Total Facility and Units Counts and Current CEMS Installation Countsa

Subpart

Number of Affected... Does Subpart Require Reporting Emissions of: Number with CO2 CEMS Number with non‐CO2 GH

CEMS 

Facilities Units CO2? N2O? CH4? Facilities Units Facilities Units 

C 1,985 14,197 YES YES YES 177 311 0 0 

E 3 3 NO YES NO 0 0 0 0 

F 10 10 YES NO NO 0 0 0 0 

G 22 22 YES NO NO 0 0 0 0 

H 96 140 YES YES YES 82 112 0 0 

K 10 10 YES NO YES 0 0 0 0 

L 16 16 NO NO NO 0 0 1 5 

N 110 110 YES YES YES 3 3 0 0 

O 5 5 NO NO NO 0 0 0 0 

P 103 103 YES YES YES 3 3 0 0 

Q 128 165 YES YES YES 11 14 0 0 

R 13 13 YES YES YES 0 0 0 0 

S 73 73 YES YES YES 1 to 73 1 to 73 0 0 

U 18 18 YES NO NO 0 0 0 0 

V 36 65 NO YES NO 0 0 0 0 

X 64 64 YES YES YES 2 2 0 0 

Y 145 1,580 YES YES YES 21 26 0 0 

Z 13 13 YES NO NO 0 0 0 0 

AA 110 330 YES YES YES 0 0 to 36 0 0 

BB 1 1 YES NO YES 0 0 0 0 

CC 4 4 YES YES YES 1 1 0 0 

EE 7 7 YES NO NO 0 0 0 0 

GG 6 6 YES YES YES 0 0 0 0 

TT 173 173 NO NO YES 0 0 0 0 

a See Appendix B for detailed summary for each subpart. 
114 

Table C-6. Counts Used to Determine Costs for Each Scenario, Actual CEMS Countsa

Subpart

Number in Scenario 1 Number in Scenario 2 Number in 

Facilities Units Facilities Units Facilities 

CO2 N2O CH4 Total CO2 N2O CH4 Total CO2 N2O CH4 Total CO2 N2O CH4 Total CO2 N2O CH4

Tota

l CO

C NA NA NA NA 12,830 12,830 12,830 12,830 NA NA NA NA 1,056 1,056 1,056 1,056 0 177 177 177 0 

E 0 3 0 3 0 3 0 3 0 0 0 0 0 0 0 0 0 0 0 0 0 

F 10 0 0 10 10 0 0 10 0 0 0 0 0 0 0 0 0 0 0 0 0 

G 22 0 0 22 22 0 0 22 0 0 0 0 0 0 0 0 0 0 0 0 0 H 14 14 14 14 28 28 28 28 0 0 0 0 0 0 0 0 14 82 82 82 2

K 10 0 10 10 10 0 10 10 0 0 0 0 0 0 0 0 0 0 0 0 0 

L 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 

N 107 107 107 107 107 107 107 107 0 0 0 0 0 0 0 0 0 3 3 3 0 

O 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 

P 100 100 100 100 100 100 100 100 0 0 0 0 0 0 0 0 0 3 3 3 0 

Q 117 117 117 117 151 151 151 151 0 0 0 0 0 0 0 0 0 11 11 11 0 

R 13 13 13 13 13 13 13 13 0 0 0 0 0 0 0 0 0 0 0 0 0 

S 72 72 72 72 72 72 72 72 0 0 0 0 0 0 0 0 0 1 1 1 0 

U 18 0 0 18 18 0 0 18 0 0 0 0 0 0 0 0 0 0 0 0 0 

V 0 16 0 16 0 29 0 29 0 0 0 0 0 0 0 0 0 20 0 20 0 

X 62 62 62 62 62 62 62 62 0 0 0 0 0 0 0 0 0 2 2 2 0 

Y NA NA NA NA 1,554 1,554 1,554 1,554 0 0 0 0 0 0 0 0 NA NA NA NA 0 

Z 6 0 0 6 6 0 0 6 0 0 0 0 0 0 0 0 7 0 0 7 7 

AA 21 21 21 21 64 64 64 64 89 89 89 89 266 266 266 266 0 0 0 0 0 

BB 1 0 1 1 1 0 1 1 0 0 0 0 0 0 0 0 0 0 0 0 0 

CC 3 3 3 3 3 3 3 3 0 0 0 0 0 0 0 0 0 1 1 1 0 

EE 7 0 0 7 7 0 0 7 0 0 0 0 0 0 0 0 0 0 0 0 0 

GG 6 6 6 6 6 6 6 6 0 0 0 0 0 0 0 0 0 0 0 0 0 

TT 0 0 173 173 0 0 173 173 0 0 0 0 0 0 0 0 0 0 0 0 0 

a See Appendix B for detailed summary for each subpart. 

NA = Data not available on basis. 
115 

Table C-6 (cont.) Notes Explaining the Actual CEMS Count Distribution for Each Subpart 

Subpart NOTES – Actual CEMS Counts

C Boiler and CISWI databases reviewed to get count of units with CEMS (1,056). None of the relevant regulations require CO2 or flow monitors, b

CEMS systems for other pollutants. Assumed that all 1,056 Tier 4 units would be in scenario 2 and units with known CO2 CEMS would be in scen

E Current CEMS installation unknown; assumed all facilities/units in scenario 1.

F Current CEMS installation unknown; assumed all facilities/units in scenario 1.

G Current CEMS installation unknown; assumed all facilities/units in scenario 1.

H Assumed units with current CEMS installations would be in scenario 3.

K Current CEMS installation unknown; assumed all facilities/units in scenario 1.

L CO2, N2O, and CH4 not required to be reported for this subpart, thus no associated costs or unit counts.

N Scenario 3 costs applied to facilities with CO2 CEMS, others assumed to be in scenario 1. Assumption made that the facilities with CO2 CEMS ha

O CO2, N2O, nor CH4 required to be reported for this subpart, thus no associated costs or unit counts.

P Scenario 3 costs applied to facilities with CO2 CEMS, others assumed to be in scenario 1. Assumption made that the facilities with CO2 CEMS ha

Q Scenario 3 costs applied to facilities with CO2 CEMS, others assumed to be in scenario 1. Assumption made that the facilities with CO2 CEMS ha

R Current CEMS installation unknown; assumed all facilities/units in scenario 1.

S

The RIA for part 98 identified all facilities being applicable to Tier 4 requirements and would thus install a CO2 CEMS. Note, however, that this c

exclusive to subpart S emissions sources and, for example, some of the identified units may fall under subpart C. For the actuals count, it was as

would be in scenario 1 (except the 1 facility with a known CO2 CEMS).

U Current CEMS installation unknown; assumed all facilities/units in scenario 1.

V Scenario 3 costs applied to facilities with CEMS, others assumed to be in scenario 1.

X Scenario 3 costs applied to facilities with CO2 CEMS, others assumed to be in scenario 1. Assumption made that the facilities with CO2 CEMS ha

Y Scenario 3 costs applied to facilities with CO2 CEMS, others assumed to be in scenario 1. For actual CEMS count, assumed zero facilities have no

installed.

Z Scenario 3 costs applied to facilities with CEMS, others assumed to be in scenario 1.

AA Scenario 2 costs applied for facilities with CEMS; based off GHG RIA estimate that most facilities would meet this for Tier IV requirements.

BB Current CEMS installation unknown; assumed all facilities/units in scenario 1.

CC Scenario 3 costs applied to facilities with CO2 CEMS, others assumed to be in scenario 1. Assumption made that the facilities with CO2 CEMS ha

EE Current CEMS installation unknown; assumed all facilities/units in scenario 1.

GG Current CEMS installation unknown; assumed all facilities/units in scenario 1.

TT Current CEMS installation unknown; assumed all facilities/units in scenario 1.
116 

Table C-7. Counts Used to Determine Costs for Each Scenario, Potential CEMS Countsa

Subpart

Number in Scenario 1 Number in Scenario 2 Nu

Facilities Units Facilities Units Facilities 

CO2 N2O CH4 Total CO2 N2O CH4 Total CO2 N2O CH4 Total CO2 N2O CH4 Total CO2 N2O CH4 

C NA NA NA NA 12,830 12,830 12,830 12,830 NA NA NA NA 1,151 1,151 1,151 1,151 0 177 177 

E 0 3 0 3 0 3 0 3 0 0 0 0 0 0 0 0 0 0 0 

F 10 0 0 10 10 0 0 10 0 0 0 0 0 0 0 0 0 0 0 

G 22 0 0 22 22 0 0 22 0 0 0 0 0 0 0 0 0 0 0 

H 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 18 96 96 

K 10 0 10 10 10 0 10 10 0 0 0 0 0 0 0 0 0 0 0 

L 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 

N 107 107 107 107 107 107 107 107 0 0 0 0 0 0 0 0 0 3 3 

O 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 

P 100 100 100 100 100 100 100 100 0 0 0 0 0 0 0 0 0 3 3 

Q 117 117 117 117 151 151 151 151 0 0 0 0 0 0 0 0 0 11 11 

R 13 13 13 13 13 13 13 13 0 0 0 0 0 0 0 0 0 0 0 

S 0 0 0 0 0 0 0 0 0 73 73 73 0 73 73 73 0 0 0 

U 18 0 0 18 18 0 0 18 0 0 0 0 0 0 0 0 0 0 0 

V 0 16 0 16 0 29 0 29 0 0 0 0 0 0 0 0 0 20 0 

X 64 64 64 64 64 64 64 64 0 0 0 0 0 0 0 0 0 2 2 

Y NA NA NA NA 1,263 1,263 1,263 1,263 NA NA NA NA 187 187 187 187 NA NA NA 

Z 6 0 0 6 6 0 0 6 0 0 0 0 0 0 0 0 7 0 0 

AA 21 21 21 21 28 28 28 28 89 89 89 89 302 302 302 302 0 0 0 

BB 1 0 1 1 1 0 1 1 0 0 0 0 0 0 0 0 0 0 0 

CC 3 3 3 3 3 3 3 3 0 0 0 0 0 0 0 0 0 1 1 

EE 7 0 0 7 7 0 0 7 0 0 0 0 0 0 0 0 0 0 0 

GG 6 6 6 6 6 6 6 6 0 0 0 0 0 0 0 0 0 0 0 

TT 0 0 173 173 0 0 173 173 0 0 0 0 0 0 0 0 0 0 0 

a See Appendix B for detailed summary for each subpart. 

NA = Data not available on basis. 
117 

Table C-7 (cont.) Notes Explaining the Potential CEMS Count Distribution for Each Subpart 

Subpart NOTES – Potential CEMS counts

C Boiler and CISWI databases reviewed to get count of units with CEMS (1,151). None of the relevant regulations require CO2 or flow monitors, b

CEMS systems for other pollutants. Assumed that all 1,151 Tier 4 units would be in scenario 2 and units with known CO2 CEMS would be in scen

E Current CEMS installation unknown; assumed all facilities/units in scenario 1.

F Current CEMS installation unknown; assumed all facilities/units in scenario 1.

G Current CEMS installation unknown; assumed all facilities/units in scenario 1.

H Assumed units with current CEMS installations would be in scenario 3.

K Current CEMS installation unknown; assumed all facilities/units in scenario 1.

L CO2, N2O, and CH4 not required to be reported for this subpart, thus no associated costs or unit counts.

N Scenario 3 costs applied to facilities with CO2 CEMS, others assumed to be in scenario 1. Assumption made that the facilities with CO2 CEMS ha

O CO2, N2O, nor CH4 required to be reported for this subpart, thus no associated costs or unit counts.

P Scenario 3 costs applied to facilities with CO2 CEMS, others assumed to be in scenario 1. Assumption made that the facilities with CO2 CEMS ha

Q Scenario 3 costs applied to facilities with CO2 CEMS, others assumed to be in scenario 1. Assumption made that the facilities with CO2 CEMS ha

R Current CEMS installation unknown; assumed all facilities/units in scenario 1.

S

The RIA for part 98 identified all facilities being applicable to Tier 4 requirements and would thus install a CO2 CEMS. Note, however, that this c

exclusive to subpart S emissions sources and, for example, some of the identified units may fall under subpart C. For the potential count, it was 

would be in scenario 2, per the RIA.

U Current CEMS installation unknown; assumed all facilities/units in scenario 1.

V Scenario 3 costs applied to facilities with CEMS, others assumed to be in scenario 1.

X Scenario 3 costs applied to facilities with CO2 CEMS, others assumed to be in scenario 1. Assumption made that the facilities with CO2 CEMS ha

Y Scenario 3 costs applied to facilities with CO2 CEMS, others assumed to be in scenario 1. For potential CEMS count, distributed non‐GHG CEMS 

based on engineering judgment.

Z Scenario 3 costs applied to facilities with CEMS, others assumed to be in scenario 1.

AA Scenario 2 costs applied for facilities with CEMS; based off GHG RIA estimate that most facilities would meet this for Tier IV requirements.

BB Current CEMS installation unknown; assumed all facilities/units in scenario 1.

CC Current CEMS installation unknown; assumed all facilities/units in scenario 1.

EE Current CEMS installation unknown; assumed all facilities/units in scenario 1.

GG Current CEMS installation unknown; assumed all facilities/units in scenario 1.

TT Current CEMS installation unknown; assumed all facilities/units in scenario 1.
118 

Table C-8. Capital Costs (million dollars) for Each Scenario, Based on Actual CEMS Countsa

Subpart

Capital Costs (Million Dollars)

Scenario 1 Scenario 2 Scenario 3 Total ‐ All

CO2 N2O CH4 Total CO2 N2O CH4 Total CO2 N2O CH4 Total Scenarios

C $ 1,578 $ 1,603 $ 1,640 $ 1,960 $ 102 $ 104 $ 107 $ 134 $       ‐    $ 6.8 $ 7.7 $ 11.9 $ 2,106

E $          ‐    $ 0.37 $          ‐    $ 0.37 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $          ‐   $          ‐    $          ‐   $ 0.4

F $ 1.2 $          ‐    $          ‐    $ 1.2 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $          ‐   $          ‐    $          ‐   $ 1.2

G $ 2.7 $          ‐    $          ‐    $ 2.7 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $          ‐   $          ‐    $          ‐   $ 2.7H $ 3.4 $ 3.5 $ 3.6 $ 4.3 $          ‐   $          ‐   $          ‐   $          ‐   $ 0.56 $ 2.5 $ 2.8 $ 5.6 $ 9.9

K $ 1.2 $          ‐    $ 1.3 $ 1.4 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $          ‐   $          ‐    $          ‐   $ 1.4

L $          ‐    $          ‐    $          ‐    $          ‐    $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $          ‐   $          ‐    $          ‐   $            ‐  

N $ 13.2 $ 13.4 $ 13.7 $ 16.3 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $ 0.066 $ 0.074 $ 0.11 $ 16.5

O $          ‐    $          ‐    $          ‐    $          ‐    $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $          ‐   $          ‐    $          ‐   $            ‐  

P $ 12.3 $ 12.5 $ 12.8 $ 15.3 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $ 0.066 $ 0.074 $ 0.11 $ 15.4

Q $ 18.6 $ 18.9 $ 19.3 $ 23.1 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $ 0.31 $ 0.35 $ 0.54 $ 23.6

R $ 1.6 $ 1.6 $ 1.7 $ 2.0 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $          ‐   $          ‐    $          ‐   $ 2.0

S $ 8.9 $ 9.0 $ 9.2 $ 11.0 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $ 0.022 $ 0.025 $ 0.038 $ 11.0

U $ 2.2 $          ‐    $          ‐    $ 2.2 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $          ‐   $          ‐    $          ‐   $ 2.2

V $          ‐    $ 3.6 $          ‐    $ 3.6 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $ 0.79 $          ‐    $ 0.79 $ 4.4

X $ 7.6 $ 7.7 $ 7.9 $ 9.5 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $ 0.044 $ 0.050 $ 0.077 $ 9.6

Y $ 191 $ 194 $ 199 $ 237 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $ 0.57 $ 0.65 $ 1.00 $ 238.5

Z $ 0.74 $          ‐    $          ‐    $ 0.74 $          ‐   $          ‐   $          ‐   $          ‐   $ 0.14 $          ‐   $          ‐    $ 0.14 $ 0.88

AA $ 7.9 $ 8.0 $ 8.2 $ 9.8 $ 25.7 $ 26.2 $ 27.0 $ 33.7 $       ‐    $          ‐   $          ‐    $          ‐   $ 43.4

BB $ 0.12 $          ‐    $ 0.13 $ 0.14 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $          ‐   $          ‐    $          ‐   $ 0.14

CC $ 0.37 $ 0.37 $ 0.38 $ 0.46 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $ 0.022 $ 0.025 $ 0.038 $ 0.50

EE $ 0.86 $          ‐    $          ‐    $ 0.86 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $          ‐   $          ‐    $          ‐   $ 0.86

GG $ 0.74 $ 0.75 $ 0.77 $ 0.92 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $          ‐   $          ‐    $          ‐   $ 0.92

TT $          ‐    $          ‐    $ 22.1 $ 22.1 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $          ‐   $          ‐    $          ‐   $ 22.1

TOTAL $ 1,853 $ 1,877 $ 1,940 $ 2,325 $ 127.7 $ 130.2 $ 134 $ 167.7 $ 0.70 $ 11.2 $ 11.7 $ 20.3 $ 2,513

a See Appendix B for detailed summary for each subpart. 
119 

Table C-9. Annual Costs (million dollars) for Each Scenario, Based on Actual CEMS Countsa

Subpart

Annual Costs (Million Dollars)

Scenario 1 Scenario 2 Scenario 3 Total ‐ All

CO2 N2O CH4 Total CO2 N2O CH4 Total CO2 N2O CH4 Total Scenarios

C $ 901 $ 911 $ 915 $ 950 $ 59.2 $ 61.4 $ 61.7 $ 64.6 $       ‐    $ 6.6 $ 6.7 $ 7.1 $ 1,022

E $          ‐    $ 0.21 $          ‐    $ 0.21 $       ‐   $       ‐   $       ‐   $       ‐   $       ‐    $          ‐    $          ‐    $          ‐   $ 0.21

F $ 0.70 $          ‐    $          ‐    $ 0.70 $       ‐   $       ‐   $       ‐   $       ‐   $       ‐    $          ‐    $          ‐    $          ‐   $ 0.70

G $ 1.5 $          ‐    $          ‐    $ 1.5 $       ‐   $       ‐   $       ‐   $       ‐   $       ‐    $          ‐    $          ‐    $          ‐   $ 1.5

H $ 2.0 $ 2.0 $ 2.0 $ 2.1 $       ‐   $       ‐   $       ‐   $       ‐   $ 0.6 $ 2.4 $ 2.4 $ 2.7 $ 4.8

K $ 0.70 $          ‐    $ 0.71 $ 0.73 $       ‐   $       ‐   $       ‐   $       ‐   $       ‐    $          ‐    $          ‐    $          ‐   $ 0.73

L $          ‐    $          ‐    $          ‐    $          ‐    $       ‐   $       ‐   $       ‐   $       ‐   $       ‐    $          ‐    $          ‐    $          ‐   $            ‐  

N $ 7.5 $ 7.6 $ 7.6 $ 7.9 $       ‐   $       ‐   $       ‐   $       ‐   $       ‐    $ 0.06 $ 0.06 $ 0.07 $ 8.0

O $          ‐    $          ‐    $          ‐    $          ‐    $       ‐   $       ‐   $       ‐   $       ‐   $       ‐    $          ‐    $          ‐    $          ‐   $            ‐  

P $ 7.0 $ 7.1 $ 7.1 $ 7.4 $       ‐   $       ‐   $       ‐   $       ‐   $       ‐    $ 0.06 $ 0.06 $ 0.07 $ 7.5

Q $ 10.6 $ 10.7 $ 10.8 $ 11.2 $       ‐   $       ‐   $       ‐   $       ‐   $       ‐    $ 0.30 $ 0.30 $ 0.32 $ 11.5

R $ 0.91 $ 0.92 $ 0.93 $ 0.96 $       ‐   $       ‐   $       ‐   $       ‐   $       ‐    $          ‐    $          ‐    $          ‐   $ 0.96

S $ 5.1 $ 5.1 $ 5.1 $ 5.3 $       ‐   $       ‐   $       ‐   $       ‐   $       ‐    $ 0.021 $ 0.021 $ 0.023 $ 5.4

U $ 1.3 $          ‐    $          ‐    $ 1.3 $       ‐   $       ‐   $       ‐   $       ‐   $       ‐    $          ‐    $          ‐    $          ‐   $ 1.3

V $          ‐    $ 2.1 $          ‐    $ 2.1 $       ‐   $       ‐   $       ‐   $       ‐   $       ‐    $ 0.76 $          ‐    $ 0.76 $ 2.8

X $ 4.4 $ 4.4 $ 4.4 $ 4.6 $       ‐   $       ‐   $       ‐   $       ‐   $       ‐    $ 0.042 $ 0.043 $ 0.046 $ 4.6

Y $ 109 $ 110 $ 111 $ 115 $       ‐   $       ‐   $       ‐   $       ‐   $       ‐    $ 0.55 $ 0.56 $ 0.60 $ 115.6

Z $ 0.42 $          ‐    $          ‐    $ 0.42 $       ‐   $       ‐   $       ‐   $       ‐   $ 0.14 $          ‐    $          ‐    $ 0.14 $ 0.57

AA $ 4.5 $ 4.5 $ 4.6 $ 4.7 $ 14.9 $ 15.5 $ 15.5 $ 16.3 $       ‐    $          ‐    $          ‐    $          ‐   $ 21.0

BB $ 0.07 $          ‐    $ 0.07 $ 0.07 $       ‐   $       ‐   $       ‐   $       ‐   $       ‐    $          ‐    $          ‐    $          ‐   $ 0.07

CC $ 0.21 $ 0.21 $ 0.21 $ 0.22 $       ‐   $       ‐   $       ‐   $       ‐   $       ‐    $ 0.021 $ 0.021 $ 0.023 $ 0.25

EE $ 0.49 $          ‐    $          ‐    $ 0.49 $       ‐   $       ‐   $       ‐   $       ‐   $       ‐    $          ‐    $          ‐    $          ‐   $ 0.49

GG $ 0.42 $ 0.43 $ 0.43 $ 0.44 $       ‐   $       ‐   $       ‐   $       ‐   $       ‐    $          ‐    $          ‐    $          ‐   $ 0.44

TT $          ‐    $          ‐    $ 12.3 $ 12.3 $       ‐   $       ‐   $       ‐   $       ‐   $       ‐    $          ‐    $          ‐    $          ‐   $ 12.3

TOTAL $ 1,058 $ 1,066 $ 1,082 $ 1,129 $ 74.1 $ 76.8 $ 77.3 $ 80.9 $ 0.74 $ 10.8 $ 10.2 $ 11.9 $ 1,223

a See Appendix B for detailed summary for each subpart. 
120 

Table C-10. Capital Costs (million dollars) for Each Scenario, Based on Potential CEMS Countsa

Subpart

Capital Costs (Million Dollars)

Scenario 1 Scenario 2 Scenario 3 Total ‐ All

CO2 N2O CH4 Total CO2 N2O CH4 Total CO2 N2O CH4 Total Scenarios

C $ 1,578 $ 1,603 $ 1,640 $ 1,960 $ 111 $ 114 $ 117 $ 146 $       ‐    $ 6.8 $ 7.7 $ 11.9 $ 2,118

E $          ‐    $ 0.37 $          ‐    $ 0.37 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $          ‐   $          ‐   $          ‐   $ 0.4

F $ 1.2 $          ‐    $          ‐    $ 1.2 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $          ‐   $          ‐   $          ‐   $ 1.2

G $ 2.7 $          ‐    $          ‐    $ 2.7 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $          ‐   $          ‐   $          ‐   $ 2.7

H $          ‐    $          ‐    $          ‐    $          ‐    $          ‐   $          ‐   $          ‐   $          ‐   $ 0.56 $ 3.1 $ 3.5 $ 7.0 $ 7.0

K $ 1.2 $          ‐    $ 1.3 $ 1.4 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $          ‐   $          ‐   $          ‐   $ 1.4

L $          ‐    $          ‐    $          ‐    $          ‐    $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $          ‐   $          ‐   $          ‐   $               ‐  

N $ 13.2 $ 13.4 $ 13.7 $ 16.3 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $ 0.066 $ 0.074 $ 0.11 $ 16.5

O $          ‐    $          ‐    $          ‐    $          ‐    $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $          ‐   $          ‐   $          ‐   $               ‐  

P $ 12.3 $ 12.5 $ 12.8 $ 15.3 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $ 0.066 $ 0.074 $ 0.11 $ 15.4

Q $ 18.6 $ 18.9 $ 19.3 $ 23.1 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $ 0.31 $ 0.35 $ 0.54 $ 23.6

R $ 1.6 $ 1.6 $ 1.7 $ 2.0 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $          ‐   $          ‐   $          ‐   $ 2.0

S $          ‐    $          ‐    $          ‐    $          ‐    $          ‐   $ 7.2 $ 7.4 $ 8.4 $       ‐    $          ‐   $          ‐   $          ‐   $ 8.4

U $ 2.2 $          ‐    $          ‐    $ 2.2 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $          ‐   $          ‐   $          ‐   $ 2.2

V $          ‐    $ 3.6 $          ‐    $ 3.6 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $ 0.79 $          ‐   $ 0.79 $ 4.4

X $ 7.9 $ 8.0 $ 8.2 $ 9.8 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $ 0.044 $ 0.050 $ 0.077 $ 9.9

Y $ 155 $ 158 $ 161 $ 193 $ 18.1 $ 18.5 $ 19.0 $ 23.7 $ 2.08 $ 2.85 $ 3.23 $ 6.48 $ 223.1

Z $ 0.74 $          ‐    $          ‐    $ 0.74 $          ‐   $          ‐   $          ‐   $          ‐   $ 0.14 $          ‐   $          ‐   $ 0.14 $ 0.88

AA $ 3.5 $ 3.5 $ 3.6 $ 4.3 $ 29.2 $ 29.8 $ 30.7 $ 38.2 $       ‐    $          ‐   $          ‐   $          ‐   $ 42.5

BB $ 0.12 $          ‐    $ 0.13 $ 0.14 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $          ‐   $          ‐   $          ‐   $ 0.14

CC $ 0.37 $ 0.37 $ 0.38 $ 0.46 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $ 0.022 $ 0.025 $ 0.038 $ 0.50

EE $ 0.86 $          ‐    $          ‐    $ 0.86 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $          ‐   $          ‐   $          ‐   $ 0.86

GG $ 0.74 $ 0.75 $ 0.77 $ 0.92 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $          ‐   $          ‐   $          ‐   $ 0.92

TT $          ‐    $          ‐    $ 22.1 $ 22.1 $          ‐   $          ‐   $          ‐   $          ‐   $       ‐    $          ‐   $          ‐   $          ‐   $ 22.1

TOTAL $ 1,801 $ 1,823 $ 1,885 $ 2,260 $ 158.7 $ 169.0 $ 174.4 $ 216.4 $ 2.8 $ 14.0 $ 15.0 $ 27.2 $ 2,504

a See Appendix B for detailed summary for each subpart. 
121 

Table C-11. Annual Costs (million dollars) for Each Scenario, Based on Potential CEMS Countsa

Subpart

Annual Costs (Million Dollars)

Scenario 1 Scenario 2 Scenario 3 Total ‐ All

CO2 N2O CH4 Total CO2 N2O CH4 Total CO2 N2O CH4 Total Scenarios

C $ 901 $ 911 $ 915 $ 950 $ 64.5 $ 66.9 $ 67.3 $ 70.4 $       ‐    $ 6.6 $ 6.7 $ 7.1 $ 1,027

E $          ‐    $ 0.21 $          ‐    $ 0.21 $       ‐    $       ‐    $          ‐   $          ‐   $       ‐    $          ‐    $          ‐   $          ‐    $ 0.21

F $ 0.70 $          ‐    $          ‐    $ 0.70 $       ‐    $       ‐    $          ‐   $          ‐   $       ‐    $          ‐    $          ‐   $          ‐    $ 0.70

G $ 1.5 $          ‐    $          ‐    $ 1.5 $       ‐    $       ‐    $          ‐   $          ‐   $       ‐    $          ‐    $          ‐   $          ‐    $ 1.5

H $          ‐    $          ‐    $          ‐    $          ‐    $       ‐    $       ‐    $          ‐   $          ‐   $ 0.6 $ 3.0 $ 3.0 $ 3.4 $ 3.4

K $ 0.70 $          ‐    $ 0.71 $ 0.73 $       ‐    $       ‐    $          ‐   $          ‐   $       ‐    $          ‐    $          ‐   $          ‐    $ 0.73

L $          ‐    $          ‐    $          ‐    $          ‐    $       ‐    $       ‐    $          ‐   $          ‐   $       ‐    $          ‐    $          ‐   $          ‐    $             ‐  

N $ 7.5 $ 7.6 $ 7.6 $ 7.9 $       ‐    $       ‐    $          ‐   $          ‐   $       ‐    $ 0.06 $ 0.06 $ 0.07 $ 8.0

O $          ‐    $          ‐    $          ‐    $          ‐    $       ‐    $       ‐    $          ‐   $          ‐   $       ‐    $          ‐    $          ‐   $          ‐    $             ‐  

P $ 7.0 $ 7.1 $ 7.1 $ 7.4 $       ‐    $       ‐    $          ‐   $          ‐   $       ‐    $ 0.06 $ 0.06 $ 0.07 $ 7.5

Q $ 10.6 $ 10.7 $ 10.8 $ 11.2 $       ‐    $       ‐    $          ‐   $          ‐   $       ‐    $ 0.30 $ 0.30 $ 0.32 $ 11.5

R $ 0.91 $ 0.92 $ 0.93 $ 0.96 $       ‐    $       ‐    $          ‐   $          ‐   $       ‐    $          ‐    $          ‐   $          ‐    $ 0.96

S $          ‐    $          ‐    $          ‐    $          ‐    $       ‐    $ 4.2 $ 4.3 $ 4.4 $       ‐    $          ‐    $          ‐   $          ‐    $ 4.4

U $ 1.3 $          ‐    $          ‐    $ 1.3 $       ‐    $       ‐    $          ‐   $          ‐   $       ‐    $          ‐    $          ‐   $          ‐    $ 1.3

V $          ‐    $ 2.1 $          ‐    $ 2.1 $       ‐    $       ‐    $          ‐   $          ‐   $       ‐    $ 0.76 $          ‐   $ 0.76 $ 2.8

X $ 4.5 $ 4.5 $ 4.6 $ 4.7 $       ‐    $       ‐    $          ‐   $          ‐   $       ‐    $ 0.042 $0.043 $ 0.046 $ 4.8

Y $ 89 $ 90 $ 90 $ 94 $ 10.5 $ 10.9 $ 10.9 $ 11.4 $ 2.14 $ 2.75 $ 2.79 $ 3.15 $ 108.1

Z $ 0.42 $          ‐    $          ‐    $ 0.42 $       ‐    $       ‐    $          ‐   $          ‐   $ 0.14 $          ‐    $          ‐   $ 0.14 $ 0.57

AA $ 2.0 $ 2.0 $ 2.0 $ 2.1 $ 16.9 $ 17.6 $ 17.6 $ 18.5 $       ‐    $          ‐    $          ‐   $          ‐    $ 20.6

BB $ 0.07 $          ‐    $ 0.07 $ 0.07 $       ‐    $       ‐    $          ‐   $          ‐   $       ‐    $          ‐    $          ‐   $          ‐    $ 0.07

CC $ 0.21 $ 0.21 $ 0.21 $ 0.22 $       ‐    $       ‐    $          ‐   $          ‐   $       ‐    $ 0.021 $0.021 $ 0.023 $ 0.25

EE $ 0.49 $          ‐    $          ‐    $ 0.49 $       ‐    $       ‐    $          ‐   $          ‐   $       ‐    $          ‐    $          ‐   $          ‐    $ 0.49

GG $ 0.42 $ 0.43 $ 0.43 $ 0.44 $       ‐    $       ‐    $          ‐   $          ‐   $       ‐    $          ‐    $          ‐   $          ‐    $ 0.44

TT $          ‐    $          ‐    $ 12.3 $ 12.3 $       ‐    $       ‐    $          ‐   $          ‐   $       ‐    $          ‐    $          ‐   $          ‐    $ 12.3

TOTAL $ 1,029 $ 1,036 $ 1,052 $ 1,099 $ 91.9 $ 99.6 $ 100.1 $ 104.7 $ 2.9 $ 13.5 $ 13.0 $ 15.1 $ 1,217

a See Appendix B for detailed summary for each subpart.