Plain English Guide

to the Part 75 Rule

U.S. Environmental Protection Agency

Clear Air Markets Division

1200 Pennsylvania Avenue, NW

Washington, DC 20460

September, 2005
i

TABLE of CONTENTS

Page

SECTION 1: INTRODUCTION ............................................ 1

1.1 What is the purpose of this guide? .................................. 1

1.2 What is Part 75 and who must comply with it ? ........................ 1

1.3 What is a cap and trade program? .................................. 4

1.4 Why is continuous monitoring necessary? ............................ 5

1.5 How is the Part 75 rule structured? ................................. 5

1.6 What other Federal regulations interface with Part 75 ? .................. 7

SECTION 2: OVERVIEW OF PART 75 MONITORING

REQUIREMENTS ............................................ 8

2.1 Register the Affected Unit(s) with EPA ............................. 9

2.2 Select a Monitoring Methodology .................................. 9

2.3 Install and Certify Monitoring Systems ............................. 12

2.4 Monitor and Record Emissions Data ............................... 12

2.5 Conduct Quality Assurance/Quality Control Procedures ................ 15

2.6 Maintain Records ............................................. 15

2.7 Report Emissions ............................................. 16

SECTION 3: BASIC CONTINUOUS EMISSION MONITORING 

REQUIREMENTS ........................................... 18

3.1 What is a continuous emission monitoring system (CEMS)? ............. 18

3.2 What is a sorbent trap monitoring system? .......................... 21

3.3 Primary and Backup Monitoring Systems ........................... 21

3.4 How must a CEMS be operated? ................................. 22

3.5 How are emissions and heat input rates determined from CEMS data? ..... 23

3.6 When are corrections for stack gas moisture content required? ........... 26

3.7 What if a unit has multiple stacks or shares a stack with other units? ....... 27

3.8 What are the missing data procedures for CEMS ? .................... 27

SECTION 4: APPENDIX D METHODOLOGY FOR 

GAS-FIRED AND OIL-FIRED UNITS .......................... 28

4.1 What is a “gas-fired” or “oil-fired” unit? ............................ 28

4.2 What is the Appendix D alternative monitoring method ? ............... 29
ii

 Page

4.3 How is the fuel flow rate measured? ............................... 29

4.4 What are the fuel sampling requirements of Appendix D ? ............... 30

4.5 How is the SO2 mass emission rate calculated? ....................... 32

4.6 How is the unit heat input rate calculated? .......................... 32

4.7 Which sulfur content, GCV and density values are used in the calculations ? . 33

4.8 What are the on-going quality-assurance requirements of Appendix D ? .... 35

4.9 What are the missing data procedures for an Appendix D unit? ........... 36

SECTION 5: APPENDIX E METHODOLOGY FOR 

GAS-FIRED AND OIL-FIRED PEAKING UNITS ................. 37

5.1 What is a peaking unit? ........................................ 37

5.2 How is an Appendix E correlation curve constructed? .................. 38

5.3 How are hourly NOx emissions determined ? ......................... 39

5.4 What are the fuel sampling requirements of Appendix E ? ............... 40

5.5 What are the on-going quality-assurance requirements of Appendix E ? .... 40

5.6 What are the missing data procedures for an Appendix E unit ? ........... 42

5.7 What happens if an Appendix E unit loses its peaking unit status ? ........ 42

SECTION 6: LOW MASS EMISSIONS METHODOLOGIES ................. 43

6.1 Gas-Fired and Oil-Fired Units .................................... 43

6.1.1 What is a low mass emissions (LME) unit ? ......................... 43

6.1.2 How does a unit qualify for LME status ? ........................... 44

6.1.3 How are emissions and heat input calculated for an LME unit ? .......... 46

6.1.4 How are site-specific default NOx emission rates determined 

for an LME unit ? ............................................. 48

6.1.5 Which site-specific default emission rates are used for reporting ? ......... 50

6.1.6 What are the recordkeeping and reporting requirements for LME units ? ... 51

6.1.7 What are the on-going QA/QC requirements for LME units ? ............ 52

6.1.8 What happens if a low mass emissions unit loses its LME status ? ......... 53

6.2 Coal-Fired Units .............................................. 53

SECTION 7: PART 75 MONITORING SYSTEM

CERTIFICATION PROCEDURES ............................. 57

7.1 How are Part 75 monitoring systems certified ? ....................... 57

7.2 Step 1— Submit an Initial Monitoring Plan .......................... 57

7.3 Step 2— Submit Certification Test Notices .......................... 59

7.4 Step 3— Conduct Certification Testing ............................. 59

7.5 Step 4— Submit Certification Application .......................... 62
iii

 

Page

7.6 Step 5— Receive Agency Approval or Disapproval ................... 63

7.7 What reference test methods and standards are used 

for certification testing ? ........................................ 63

7.8 What performance specifications must be met for certification ? .......... 66

7.9 What is meant by the “span value”, and why is it important ? ............ 69

7.10 Recertification and Diagnostic Testing ............................. 72

SECTION 8: QUALITY ASSURANCE AND QUALITY

CONTROL (QA/QC) PROCEDURES ........................... 73

8.1 Does Part 75 require periodic quality QA/QC testing after a monitoring system is

certified ? If so, where are these test requirements found ? .............. 73

8.2 What are the on-going QA test requirements in Part 75 for units reporting

emissions data year-round ? ..................................... 73

8.3 Are there any exceptions to these basic QA test requirements ? ........... 77

8.4 Are there any special considerations when performing 

these basic QA tests ? .......................................... 78

8.5 What are the on-going QA test requirements for 

ozone season-only reporters ? .................................... 80

8.6 What performance specifications must be met for the routine QA tests 

required by Part 75 ? ........................................... 81

8.7 Are there any notification requirements for the periodic QA tests ? ........ 83

8.8 What are the essential elements of a Part 75 QA/QC program ? .......... 83

SECTION 9: MISSING DATA SUBSTITUTION PROCEDURES ................ 85

9.1 Does Part 75 require emissions to be reported for 

every unit operating hour ? ...................................... 85

9.2 How are emissions data reported when a monitoring system 

is not working ? .............................................. 85

9.3 What are the Part 75 missing data procedures for CEMS ? .............. 87

9.4 What are the missing data procedures for Appendices D, E, and G ? ....... 89

9.5 What is conditional data validation ? ............................... 90

 

SECTION 10: PART 75 REPORTING REQUIREMENTS .................... 92

10.1 What are the basic reporting requirements of Part 75 ? ................. 92

10.2 How does EPA evaluate the electronic quarterly reports ? .............. 93

10.3 Part 75 Audit Program ......................................... 94

10.4 Electronic Reporting—Update ................................... 96
iv

 Page

APPENDIX I: Regulatory Update (CAIR and CAMR Rules) ................ 98 

APPENDIX II: Summary of Part 75 Monitoring Requirements for Common and 

Multiple Stack Configurations ........................... 101

APPENDIX III: On-Going QA Test Requirements for 

Ozone Season-Only Reporters ........................... 115

APPENDIX IV: References .......................................... 121
v

ACRONYMS and UNITS of MEASURE

AAR - Authorized Account Representative

AGA - American Gas Association

API - American Petroleum Institute

ARP - Acid Rain Program

ASME - American Society of Mechanical Engineers

ASTM - American Society of Testing and Materials

BAF - Bias Adjustment Factor

CAIR - Clean Air Interstate Regulation

CAMD - Clean Air Markets Division

CAMR - Clean Air Mercury Regulation

CDV - Conditional Data Validation

CEM - Continuous Emission Monitoring

CEMS - Continuous Emission Monitoring System

CFR - Code of Federal Regulations

CO2 - Carbon Dioxide

DAHS - Data Acquisition and Handling System

DP - Differential Pressure

DR - Designated Representative

EDR - Electronic Data Reporting

EGU - Electric Generating Unit
vi

EPA - Environmental Protection Agency

ETS - Emissions Tracking System

GCV - Gross Calorific Value

GHR - Gross heat Rate

GPA - Gas Processors Association

Hg - Mercury

ISO - International Organization for Standardization

LME - Low Mass Emissions

MDC - Monitoring Data Checking

MER - Maximum Potential Emission Rate (MER)

NBP - NOx Budget Trading Program

NIST - National Institute of Standards and Technology

NSPS - New Source Performance Standards

NOx - Nitrogen Oxides

O2 - Oxygen

OOC - Out-of-Control

PLC - Programmable Logic Controller

PMA - Percent Monitor Data Availability

PNG - Pipeline Natural Gas

QA/QC - Quality Assurance/Quality Control 

RA - Relative Accuracy
vii

RATA - Relative Accuracy Test Audit

RM - Reference method

SIP - State Implementation Plan

SO2 - Sulfur Dioxide

TTFA - Targeting Tool for Field Audits

WAF - Wall Effects Adjustment Factor

Btu - British thermal unit

dscfh - Dry standard cubic feet per hour

dscf/mmBtu - Dry standard cubic feet per million Btu 

lb/hr - Pounds per hour

lb/mmBtu - Pounds per million Btu

lb/scf - Pounds per standard cubic foot

mmBtu/hr - Million Btu per hour

ppmv - Parts per million by volume

scfh - Standard cubic feet per hour

scf CO2/mmBtu - Standard cubic feet of CO2 per million Btu

tons/hr - Tons per hour

tons/scf - Tons per standard cubic foot

:g/scm - Micrograms per standard cubic meter
1

1.0 INTRODUCTION

1.1 What is the purpose of this guide?

EPA has developed this plain-English guide as a “road map” to help interested parties

navigate through the complex Part 75 continuous emission monitoring rule. This guide may be

useful to people responsible for complying with the rule, regulatory agencies assessing compliance

with the rule, and others who want a general understanding of the emissions monitoring approach

used in EPA’s emissions trading programs.

This guide, although quite comprehensive, does not replace the Part 75 rule. Rather, it

provides a general overview of Part 75 and is intended to clarify the regulation. To gain a more

complete understanding of the rule, it is necessary to carefully read and study Part 75, as well as 

the associated guidance documents issued by EPA, such as the “Part 75 Emissions Monitoring

Policy Manual” and the “Electronic Data Reporting Instructions”).

For further information on EPA’s emissions trading programs, continuous emissions

monitoring, Part 75, and related topics, see the EPA Clean Air Markets Division (CAMD)

website at: www.epa.gov/airmarkets

1.2 What is Part 75 and who must comply with it ?

The Part 75 continuous emission monitoring rule, which is found in Volume 40 of the

Code of Federal Regulations (CFR), was originally published in January, 1993. The purpose of

the regulation was to establish continuous emission monitoring (CEM) and reporting

requirements under EPA’s Acid Rain Program (ARP), which was instituted in 1990 under Title

IV of the Clean Air Act. The ARP regulates electric generating units (EGUs) that burn fossil

fuels such as coal, oil and natural gas and that serve a generator > 25 megawatts. For these units,

Part 75 requires continuous monitoring and reporting of sulfur dioxide (SO2) mass emissions,

carbon dioxide (CO2) mass emissions, nitrogen oxides (NOx) emission rate, and heat input. The

SO2 component of the ARP is a “cap and trade” program, designed to reduce acid deposition by

limiting SO2 emission levels in the “lower 48" states of the U.S. 

In October, 1998, EPA added Subpart H to Part 75, which provides a blueprint for the

monitoring and reporting of NOx mass emissions and heat input under a State or Federal NOx

emissions reduction program. The Agency anticipated that such programs were likely to come

into existence, due to growing concern over health hazards associated with NOx emissions from

power plants and large industrial sources. NOx is a precursor to ozone and fine particulate matter

formation. Subpart H has since been adopted as the required monitoring methodology for NOx

mass emissions and heat input under the NOx Budget Trading Program (NBP). 

The NBP is a NOx cap and trade program, designed to limit ground-level ozone formation

during the ozone season (from May 1st through September 30th) in 22 states in the Eastern U.S. 
1

 There is one exception to this. For low mass emissions (LME) units in the Acid Rain Program, NOx

mass emissions are reported in addition to NOx emission rate, to demonstrate that the unit continues to qualify for

LME status from year-to-year. LME units are discussed in detail in Section 6 of this guide.

2

The state regulations for the NBP apply mainly to large EGUs and industrial boilers, although

certain states have included other categories of NOx-emitting sources, such as cement kilns and

refinery process heaters. The state rules are patterned after a model regulation developed by EPA

(40 CFR Part 96), and require NOx mass emissions and heat input to be monitored and reported

according to Subpart H of Part 75. The Program assigns a total NOx emissions budget (tons per

ozone season) to each state, and is administered jointly by the states and EPA’s Clean Air

Markets Division (CAMD). 

On May 12 and May 18, 2005, EPA published two new air regulations, the Clean Air

Interstate Rule (CAIR) and the Clean Air Mercury Rule (CAMR). These regulations provide

model rules for cap and trade programs that can be adopted by the states. The CAIR rule seeks

to reduce fine particulate and ozone emissions by imposing tight emission caps on SO2 and NOx

mass emissions from EGUs in 28 states. CAIR includes annual SO2 and NOx emissions caps for

23 of the 28 affected states and an ozone season cap on NOx emissions in 25 of the states. The

CAMR rule seeks to achieve substantial reductions in mercury (Hg) mass emissions from coalfired EGUs in all 50 states. 

Both CAIR and CAMR require Part 75 monitoring. Under CAIR, monitoring systems for

NOx mass emissions and heat input must be installed and certified by 2008, and monitoring

systems for SO2 mass emissions and heat input must be certified by 2009. Under CAMR, Part

75-compliant monitoring systems for Hg mass emissions and, if required, heat input must be

installed and certified by January 1, 2009. For a further discussion of these new rules, see

Appendix I of this guide. 

Part 75 specifies the types of continuous monitoring systems that may be used for each

parameter (SO2, NOx, Hg, etc.) and sets forth the operation, maintenance and quality

assurance/quality control (QA/QC) requirements for each system. In most cases, continuous

emission monitoring systems (CEMS) are required, although in some instances, other monitoring

methodologies are allowed.

Table 1 summarizes the various programs that require (or will require) Part 75 monitoring.

Each of these programs requires certain parameters to be monitored over specified time periods.

For each affected unit, the specific parameters that must be monitored, the units of measure, and

the averaging (or accounting) periods depend on which program(s) apply. 

Table 1 also shows that when the same pollutant is regulated under two different programs,

the Part 75 monitoring and reporting requirements for the pollutant are not necessarily consistent

between the two programs. For example, the ARP and NBP assess NOx compliance differently. 

The ARP requires the NOx emission rate to be monitored and reported in pounds per million Btu

(lb/mmBtu) and specifies annual NOx emission rate limits for certain coal-fired EGUs, under 40

CFR Part 76. But the ARP does not have an emissions trading component for NOx, and therefore

does not require NOx mass emissions to be reported1. Conversely, the NBP, which is a NOx cap

and trade program, does require NOx mass emissions to be monitored and 
3

Table 1: Programs That Require Part 75 Monitoring

Program Affected

Sources

 Parameter(s) 

 Measured 

 (units)

 Accounting or

Averaging Period

Data Used for

 Program

Compliance ?

Acid Rain

Program

EGUs and other

combustion sources

that opt-in to the SO2

cap and trade

program 

SO2 (tons)

CO2 (tons)

NOx (lbs/mmBtu)

Heat input (mmBtu)

Opacityg (%)

Annual (cumulative)

Annual (cumulative)

Annual (average)

Annual (cumulative)

 Variesh 

Yesa

Nob

Certain units onlyc

In some casesd

 No

NOx Budget

Trading

Program

EGUs , certain large

industrial units, and

units that opt in to the

cap and trade

program 

NOx (tons)

Heat input (mmBtu)

Ozone season5

(cumulative)

Ozone seasone

(cumulative)

Yesa

In some casesf

Trading

Programs

under the

CAIR

Regulation9

EGUs and opt-in units SO2 and NOx (tons)

NOx (tons)

Annual

(cumulative)–23 states

Ozone seasone

(cumulative)—

25 states

Yesa

Trading

Program

under the

CAMR Rulei

Coal-fired EGUs Hg (ounces) Annual (cumulative) Yesa

a

 The cumulative annual tons of SO2, the cumulative annual or ozone season tons of NOx , or the cumulative

annual ounces of Hg emitted must be less than or equal to the number of emission credits (allowances) held

b

 At present, CO2 is not a regulated pollutant. Title IV of the Clean Air Act requires only an estimate of annual

CO2 mass emissions from electrical generating units.

c

 Under 40 CFR Part 76, certain coal-fired units are required to meet an annual NOx emission limit. 

d

 If a unit exceeds its annual NOx emission rate limit under Part 76, the cumulative annual heat input is used to

calculate the excess emission penalty

e

 The ozone season extends from May 1st through September 30th

f

 Heat input monitoring is required for most, but not all NOx Budget Trading Program sources. Heat input data

is used by affected sources to calculate NOx mass emissions and may be used by State agencies to determine

future NOx allowance allocations.

g

 Required only for coal-fired units and certain oil-fired units in the Acid Rain Program.

h

 Varies according to State and/or other Federal requirements
4

reported for allowance accounting purposes, but does not require compliance with NOx emission

limits in lb/mmBtu. For sources subject to both the ARP and the NBP, the requirements of both

programs must be met—therefore, NOx mass emissions and NOx emission rate must both be

monitored and reported. 

1.3 What is a cap and trade program?

A cap and trade program is a market-based approach

to reducing emissions. The concept is simple: EPA caps, or

limits, the total annual or seasonal mass emissions of a

pollutant such as SO2, NOx or Hg. The cap is divided into

emission allowances that are allocated to each affected

source. Each emission allowance represents an authorization

to emit one ton of SO2 or NOx, or one ounce of Hg over a

specified time period (i.e., calendar year or ozone season). 

To demonstrate compliance, a source is required to hold a

number of allowances greater than or equal to its emissions in

the regulated time period. Since the total number of

allowances allocated to the affected sources is less than the

pre-program (“baseline”) mass emissions from those sources,

the program reduces the mass emissions of the regulated

pollutant.. 

At the end of each compliance period, a reconciliation

process takes place to verify that each affected source has enough allowances to cover its

emissions. Automatic penalties for noncompliance are part of the U.S. cap and trade programs.

For example, if an ARP unit does not have enough allowances to cover its annual SO2 emissions,

the owner or operator of the unit must pay an excess emissions penalty and must surrender futureyear allowances to cover the shortfall. For a NBP unit, if its ozone season NOx

 emissions exceed

its allowance holdings, the owner or operator of the unit must surrender at least 3 future-year

allowances and, if required by state rules, pay additional penalties.

This market-based approach allows sources to determine the most cost-effective way to

comply. Sources may reduce emissions by using pollution control technologies, employing energy

conservation measures, reducing utilization, switching fuels, or other strategies. Sources also are

allowed to buy and sell allowances from each other to ensure that each unit has enough allowance

credits in its account to cover its emissions. In this manner, a cap and trade program reduces

emissions at a lower cost than traditional pollution control regulations and policies, by setting a

goal and allowing market forces to determine how the goal is met.

A cap and trade program

does not specify traditional

numerical emission limits

(e.g. ppm, lb/mmBtu, etc.) 

for the regulated pollutant(s)

Instead, compliance is

demonstrated by holding

enough allowances to cover

the total mass emissions

from the affected unit(s)

during a specified time

period. However, numerical

emission limits imposed by

other programs or by the

operating permit still apply.
2

 Or an ounce of emissions, for Hg

3

 Note that three of the Appendices (H, I, and J) are “reserved”. Appendix H was in the original January,

1993 rule, but was removed and reserved in May, 1999. Appendix I was proposed in 1998, but never finalized. 

Appendix J was removed and reserved in May, 1999. 

5

1.4 Why is continuous monitoring necessary?

Emissions monitoring and accounting are the backbone of cap and trade programs.

Because the emission allowances are based on the total mass of a pollutant emitted over a certain

time period, emissions must be monitored continuously during the compliance period. It is

therefore essential to have a reliable measurement method for the commodity being regulated and

traded---in this case, emissions— to ensure that the goal of achieving actual, measurable

emissions reductions in a cost-effective manner is met. Part 75 provides the necessary

measurement method, and gives value to the traded commodity by:

C Ensuring that the emissions from all sources are consistently and accurately

measured and reported. In other words, a ton of emissions2 from one source is

equal to a ton of emissions2 from any other source; 

C Ensuring that a complete record of emission data is produced for each unit in the

program (i.e., data are obtained for every hour of unit operation);

C Verifying that emission caps are not exceeded, thereby ensuring that emissions are

not underestimated and that emission reduction goals are being met.

 

1.5 How is the Part 75 Rule Structured ?

Part 75 consists of nine Subparts, A through I, followed by a series of eleven Appendices,

A through K3. A brief description of each Subpart and Appendix follows. 

Subparts

C Subpart A (§§75.1-75.8) defines the purpose of the regulation and the extent of

its applicability. Subpart A also includes general Acid Rain Program provisions,

compliance dates, prohibitions, and lists various methodologies (e.g., ASTM,

ASME, etc.) that are incorporated into the rule by reference.

C Subpart B (§§75.10–75.19) presents the general emission monitoring

requirements for each pollutant (SO2 , NOx , etc.). Special instructions are given

for monitoring at common stack and multiple stack exhaust configurations.

 
6

C Subpart C (§§75.20-75.24) presents the process for certification and

recertification of the required continuous monitoring systems, provides the quality

assurance and quality control (QA/QC) requirements for the systems, defines “outof-control” periods, and requires bias adjustment of data from SO2

 , NOx , and

flow monitors.

C Subpart D (§§75.30-37) describes the missing data procedures that are used to

determine the appropriate substitute data values, for unit operating hours in which

the monitoring systems fail to provide quality-assured data. 

C Subpart E (§§75.40-75.48) describes the requirements that must be met for

approval of an alternative monitoring system.

C Subpart F (§§75.50-75.59) contains the recordkeeping requirements

 

C Subpart G (§§75.60-75.67) contains the reporting requirements. Instructions are

provided for submitting notifications, monitoring plans, certification applications,

emissions reports, and special petitions to the Administrator.

C Subpart H (§§75.70-75.75) describes the NOx mass emission monitoring

requirements for sources in a NOx mass emissions reduction program that adopts

Part 75, such as the NOx Budget Program or a NOx trading program under the

CAIR rule. Special instructions are provided for sources that report data only

during the ozone season.

C Subpart I (§§75.80-75.84) describes the Hg mass emission monitoring

requirements for sources in a Hg mass emissions reduction program that adopts

Part 75, such as a national Hg trading program under the CAMR rule. 

Appendices

C Appendix A describes CEMS installation and certification test procedures, and

provides performance specifications for the CEMS and explains how to set the

span and range of CEMS ;

C Appendix B describes the required on-going CEMS quality assurance tests and

procedures for CEMS, and includes rules for data validation;

C Appendix C provides guidelines for parametric and load-based missing data

substitution;

C Appendix D provides an optional protocol for estimating SO2 mass emissions and

heat input for gas-fired and oil-fired units;
7

C Appendix E provides an optional protocol for estimating NOx emissions from gasfired and oil-fired peaking units;

C Appendix F provides equations for converting raw monitoring data into the

appropriate units of measure;

C Appendix G gives procedures for monitoring and calculating CO2 mass emissions,

for ARP units;

C Appendices H, I and J are currently reserved; and

C Appendix K provides special operating instructions and quality-assurance

requirements for sorbent trap monitoring systems, which are used to monitor Hg

emissions.

1.6 What other Federal regulations interface with Part 75 ?

Part 75 is one of the Acid Rain Program core rules, which, collectively, are found in

Volume 40 of the CFR, Parts 72 through 78. Part 75 is referenced in several of the other core

rules. First, in §72.2, there are numerous important definitions that apply to Part 75. Second,

Part 76, which specifies annual NOx emission limits for certain coal-fired boilers, requires Part 75

monitoring to be used to demonstrate compliance with these emission limits. Third, Part 74

requires units that opt-in to the Acid Rain Program to monitor and report SO2 emissions

according to Part 75. 

Part 75 also interfaces with some of the New Source Performance Standards (NSPS)

regulations in 40 CFR Part 60. Many units that are currently in the Acid Rain Program or the

NOx Budget Program are also subject to one of the NSPS boiler regulations (Subparts D, Da, Db

and Dc) or to the NSPS rule for combustion turbines (Subpart GG). The Part 60 boiler

regulations require continuous emission monitoring for SO2 and/or NOx , and Subpart GG allows

a NOx CEMS to be used to monitor and report “excess emissions”. Subparts Da and Db allow a

certified Part 75 NOx monitoring system to be used to meet the Part 60 NOx monitoring

requirements. Subpart GG allows a certified Part 75 NOx CEMS to be used for excess emission

monitoring. 
8

Register the affected unit(s)

with the Clean Air Markets

Division of EPA

Select the monitoring

methodology

Install and certify

monitoring systems

Conduct QA/QC

Procedures 

(On-going)

Monitor emissions and use

missing data substitution as

necessary

Maintain Records

Report Emissions

2.0 OVERVIEW OF PART 75 

MONITORING REQUIREMENTS

Part 75 requires an hourly accounting of the emissions from each affected unit. 

Continuous emission monitoring systems (CEMS) are used to provide the emissions data unless

the unit qualifies to use one of the alternative monitoring methodologies specified in the rule. 

With few exceptions, the alternative methodologies apply to oil-fired and gas-fired units. 

The selected monitoring methodology for each unit must be approved by EPA through a

certification process. Once the methodology has been approved and the required monitoring

systems are certified, the recording and reporting of emissions data begins. Part 75 also requires

on-going quality assurance and quality control (QA/QC) procedures, to ensure that the data

collected by the monitoring systems continue to be accurate. 

This section provides an overview and general description of the Part 75 monitoring and

reporting requirements (see Figure 1). More specific information is provided in the subsequent

sections of this guide. 

 

Figure 1. Overview of Part 75 Monitoring Requirements
9

2.1 Register the Affected Unit(s) with EPA. 

Each affected unit must be registered with EPA’s Clean Air Markets Division (CAMD)

before any data is reported for the unit. As part of the registration process, a Designated

Representative, or “DR” (for the Acid Rain and CAIR Programs), a “Hg Designated

Representative” (for the CAMR Program), or an Authorized Account Representative, or “AAR”

(for the NOx Budget Program), must be assigned for each unit. The Designated Representative or

AAR takes the responsibility for ensuring that each affected unit complies with all of the

applicable program requirements, and that the emissions data reported to EPA are true and

accurate. For units subject to both the Acid Rain Program and to one or more of the SO2 and

NOx trading programs under CAIR, the Designated Representative for all of these trading

programs must be the same person. 

2.2 Select a Monitoring Methodology

Monitoring Options

Part 75 provides several monitoring options. The options that are available for a unit

depend on how the unit is classified (see Table 2 in

Section 2.4, below). In general, if a unit is coal-fired

or combusts any type of solid fuel, the basic

continuous monitoring provisions in §§75.10-75.18

require the use of CEMS for all monitored

parameters. However, there are a few exceptions to

this. If a unit is classified as an oil- or gas-fired unit,

it may qualify for an alternative monitoring approach

instead of CEMS for some or all parameters. In

some cases, the unit may even qualify for a

monitoring exemption. 

The monitoring alternatives or exemptions

that apply to a unit depend mainly on how often the unit operates each year, how much it emits,

and the type(s) of fuel(s) it combusts. These alternatives and exemptions are:

C Any oil-fired or gas-fired unit may use the alternative, or “excepted”

methodology in Appendix D of Part 75 to determine SO2 mass emissions and/or

unit heat input. The Appendix D method requires continuous monitoring of the

fuel flow rate with a certified fuel flowmeter and periodic fuel sampling and

analysis to determine one or more of the following quantities: (1) the gross

calorific value (GCV) of the fuel; (2) the fuel sulfur content; and (3) the density of

the fuel. The Appendix D methodology is discussed in greater detail in Section 4

of this guide. 

The Part 75 rule generally requires

the use of CEMS for units that

combust coal or other solid fuel(s). 

Alternative monitoring approaches,

referred to in the rule as “excepted

methods” or “excepted monitoring

systems” , may be used for

qualifying oil-fired and gas-fired

units, and for certain coal-fired

units under the CAMR rule.
10

C Oil-fired and gas-fired peaking units may use the alternative method in Appendix

E of Part 75 to estimate the hourly NOx emission rate in lb/mmBtu. Appendix E

requires hourly determination of the heat input rate to the unit, using the fuel flow

rate measured by a certified Appendix D fuel flowmeter, in conjunction with the

GCV of the fuel. A correlation curve of NOx emission rate versus heat input rate

(derived from emission testing) is then used to estimate the hourly NOx emission

rates. The Appendix E methodology is discussed in greater detail in Section 5 of

this guide. 

C Certain oil-fired and gas-fired units may qualify to use the low mass emissions

(LME) methodology in §75.19 to estimate SO2, CO2, and/or NOx emissions and

heat input. To qualify for LME status, a unit’s annual SO2 and NOx mass

emissions, and in some cases, its ozone season NOx mass emissions, must be

demonstrated to be below certain threshold values. 

The LME methodology requires that records be kept of the hours in which the unit

operates, the type(s) of fuel(s) combusted, the electrical or steam load during each

of those hours, and, in some cases, the operational status of the NOx emission

controls. Default emission rates and estimates of heat input are used to quantify

the unit’s mass emissions. The LME methodology is discussed in greater detail in

Section 6 of this guide. 

C Acid Rain Program units may use the alternative procedures in Appendix G of

Part 75 to estimate CO2 mass emissions, in lieu of installing CEMS. Appendix G

allows CO2 emissions to be estimated, either by using: (1) fuel feed rates and the

results of periodic fuel sampling and analysis (to determine the % carbon in the

fuel); or (2) hourly heat input rate measurements from a certified Appendix D fuel

flowmeter and a fuel-specific, carbon-based “F-factor”. 

Appendix G is the most frequently-used method for estimating CO2 mass emissions

from oil and gas-fired units. Part 75 allows the fuel feed rate methodology (option

(1), above) to be used for coal-fired units also, but it is not currently being used by

any of them.

C Certain Acid Rain Program units are exempted from opacity monitoring

requirements. Coal-fired units with wet scrubbers may be exempted if the presence

of condensed water in the effluent gas stream interferes with the opacity readings. 

Also, any unit that meets the definition of gas-fired or diesel-fired in §72.2, or that

qualifies as a dual-fuel reciprocating engine is exempted from opacity monitoring. 

However, note that these Part 75 exemptions do not supersede the provisions of

any other program, regulation, or permit that may require an opacity monitor to be

installed. 
11

C Affected coal-fired units under the CAMR rule may use an alternative

(“excepted”) type of continuous Hg monitoring system, known as a “sorbent trap

monitoring system”. A sorbent trap system continuously samples the stack gas for

an extended period of time (e.g., up to a week or more) and collects Hg on a

sorbent medium such as activated carbon. The total volume of stack gas sampled

during the collection period is measured, and the Hg concentration is determined

by taking the ratio of the collected Hg mass to the sample volume.

C Certain affected units under CAMR may qualify to use a low mass emissions

methodology to estimate the annual Hg mass emissions, in lieu of continuously

monitoring the Hg concentration. This alternative methodology applies mainly to

small units with very low (< 29 lb/yr) annual Hg mass emissions. It requires

periodic Hg emission testing, and conservatively high default Hg concentrations

must be used for emissions reporting.

Sections 3 through 6 of this guide provide more information on the various Part 75

emission monitoring methodologies. Section 3 describes the basic CEM provisions, and Sections

4, 5, and 6, respectively, discuss the alternative Appendix D, Appendix E, and low mass emission

methodologies.

Special Petitions

Under §75.66, EPA has established a petition process through which affected sources can

request relief or variances from certain provisions of Part 75. Each petition must contain

sufficient information for the Agency to evaluate the request. At a minimum, the petition must:

(1) identify the affected facility and unit(s); (2) explain why the proposed alternative is being

suggested instead of the regulatory requirement; (3) provide a description of any equipment or

procedures used in the proposed alternative; (4) demonstrate that the proposed alternative is

consistent with the purposes of Part 75 and the Clean Air Act; and (5) explain why approving it

will not have any significant adverse effects. 

The regulatory flexibility provided by the petition process reduces the cost of compliance

for many sources and facilitates program implementation. EPA strives for consistency in its

petition responses. When a petition is approved (or denied), petitions of a similar nature will also

be approved (or denied). The Agency also seeks to avoid setting precedents by answering

petitions in a way that will weaken or undermine the Part 75 rule. Finally, when EPA approves a

large number of petitions of the same type, this often indicates the need for a rule change. The

Agency has revised Part 75 a number of times on this basis.

Alternative Monitoring Systems

Subpart E of Part 75 allows sources to petition EPA for approval of an alternative
4

 For LME units, only the first, fourth, and fifth steps of the process apply. The initial monitoring plan

and the certification application are submitted together #45 days before the methodology begins to be used (see

Section 6 of this guide).

5

 For LME units, reporting begins with the first operating hour in the year or ozone season in which the

LME methodology is first used (see Section 6 of this guide for further discussion). This date will always be later

than the date of provisional certification (which in this case, is the date that a complete certification application is

received—see §75.20(h)(3)). 

12

monitoring system. To obtain

approval, the petition must

demonstrate that the alternative system

has the same precision, reliability,

accessibility, and timeliness as a

certified Part 75 CEMS. The

performance of any alternative system

must be demonstrated by simultaneous

testing against a fully certified CEMS

or an EPA reference test method. The

petition must also propose quality

assurance procedures and missing data

substitution procedures for the

alternative monitoring system that are

consistent with the corresponding Part

75 procedures for CEMS. The criteria and procedures for approval of alternative systems are

specified in Subpart E and are not discussed further in this guide.

2.3 Install and Certify Monitoring Systems

Before any monitoring methodology or monitoring system is used, it must be approved

through a certification process. This process is described in detail in Section 7 of this guide. 

Except for LME units4, the general steps for obtaining certification are:

C Step 1---Prepare and submit an initial monitoring plan 

C Step 2---Submit certification test notices 

C Step 3---Conduct certification testing

C Step 4---Submit a certification application

C Step 5---Receive approval or disapproval

2.4 Monitor and Record Emissions Data

With the exception of LME units5, monitoring and reporting of emissions begins as soon as

certification testing is successfully completed, provided that the tests are completed by the

On the one hand, EPA has received

and approved only a few Subpart E

petitions to use alternative monitoring

systems, partly due to the rigorous

requirements of Subpart E and partly

because the Appendix D, Appendix E

and LME “excepted” methods in Part

75 provide substantial flexibility in

choosing a monitoring methodology. On

the other hand, the Agency has

approved many minor variations to the

monitoring provisions of Part 75
6

 When the tests are not completed by the deadline, emissions reporting must begin immediately upon

expiration of the deadline, and conservatively high substitute data values (usually maximum potential values) must

be reported.

13

certification deadline specified in the regulations6. Part 75 monitoring systems are considered to

be “provisionally certified” in the period extending from the date of successful completion of the

Table 2: Part 75 Monitoring Options

 

 If an Affected

Unit Is Classified

as a . . .

 These are the Allowable Monitoring Options ...

Basic CEMS

Provisionsa

(§§75.10-18)

Appendix D 

 Methodb

Appendix E 

 Methodc

 LME

Methodd

(§75.19)

Appendix G 

 Methode

Excepted

 Hg

Methodf

Coal-fired unit

under ARP, NBP,

or CAIR

T T

Coal-fired unit

under CAMR

T T

Non-peaking oilfired or gas-fired

unit under ARP,

NBP, or CAIR

T T T T

Oil-fired or gasfired peaking unit

under ARP, NBP,

or CAIR

T T T T T

a For SO2

, NOX, CO2, flow rate, H g, opacity, and heat inpu t (as applicable). 

b For SO2

 emissions and heat input only.

c

 For NOX emissions only. If Appendix E is used for NOx, Appendix D mu st be used for SO2 and/or hea t input.

d

 If the LME qua lifying thresholds are met and this method is selected, it must be used for all parameters, i.e., for SO2, NOX, CO2, and heat input 

(as applicable)

e For CO2

 emissions only 

f

 Any affected unit under CAM R ma y use an “excepted” sorbent trap monitoring system instead of an Hg CEM S (see § §7 2.2 a nd 7 5.15 ). Lowemitting sources of Hg (< 29 lb/yr) may qualify to use the excepted mer cury low mass emissions methodology described in §75 .81 (b). 
7

 Note that when “conditional data validation” is used, the date of provisional certification may be date

on which certification testing begins (or perhaps even earlier), rather than the date on which the testing is

completed (see Section 9.5 of this guide).

8

 Upon receipt of a complete certification application, the regulatory agencies have 120 days to review the

application. A notice of approval or disapproval may be issued during this time period. Absent such notice, if all

required tests were passed, the monitoring systems are considered to be certified “by default”. 

9

 EPA reference methods are discussed in Section 7.7 of this guide.

10

 The term used in Part 75 to describe this is the “percent monitor data availability”, or PMA. In its

most basic form, the PMA represents the percentage of time that quality-assured data was obtained in a historical

lookback through a certain number of unit operating hours. Note that the PMA tracks the availability of qualityassured data, not the availability of individual monitoring systems. For example, if the primary CEMS is out-ofservice but quality-assured data are recorded by a backup system, the PMA is unaffected.

14

certification tests7 through the end of a 120-day review period8, provided that the systems are 

operated in accordance with all Part 75 requirements and the permitting authority does not

disapprove the systems in the meantime. Emissions data may be reported as quality-assured

during this period of provisional certification. 

Part 75 requires emissions data to be reported for every hour that an affected unit is

operating, including periods of start-up, shutdown, and malfunction. If one of the required

monitoring systems is not working or is out-of-control (e.g., if it fails one of its required quality

assurance tests), data from an approved backup monitor or from an EPA reference method9 may

be reported. If quality-assured data from a back-up monitor or reference method are not

available, the Part 75 missing data substitution procedures must be used to estimate emissions.

The Part 75 missing data routines for CEMS are found in §§75.31 through 75.38 and the

routines for sorbent trap monitoring systems are found in §75.39. These routines consist of

mathematical algorithms that are used to determine an appropriate substitute value for any unit

operating hour in which quality-assured data are not obtained for a monitored parameter (i.e., for

SO2 , NOx, Hg, CO2, O2 , flow rate, or moisture). Generally speaking, historical, quality-assured 

monitoring data are used to determine the substitute data values. The exact substitute data values

that are applied in a given situation depends on:

C The historical availability of quality-assured data from the monitor(s)10;

C The length of the missing data period; and

C For certain parameters (NOx and flow rate), the hourly unit loads during the

missing data period. 

The missing data procedures are designed to be conservative. This provides an incentive to

reduce periods of monitor downtime, by rewarding high percent monitor data availability

(PMA)10. The procedures will produce conservatively high emissions estimates for units with
15

lower PMA values. 

The monitoring methodologies in Appendices D, E, and G of Part 75 also have missing

data procedures. The missing data algorithms under these appendices are considerably less

complex than the CEMS and sorbent trap system algorithms. The Part 75 missing data

substitution procedures are discussed in greater detail in Section 9 of this guide.

2.5 Conduct Quality Assurance/Quality Control Procedures

After certification, the following periodic performance evaluations of all monitoring

systems must be conducted, to ensure the continued accuracy of the emissions data: 

C The quality-assurance tests for CEMS include daily assessments (e.g., calibration

error tests), weekly assessments (system integrity checks of Hg CEMS equipped

with converters), quarterly assessments (e.g., linearity checks), and semi-annual (or

annual in some cases) relative accuracy test audits (RATAs);

C For sorbent trap monitoring systems, annual RATAs and the quality assurance

procedures of Part 75, Appendix K are required;

C For CAMR units that qualify to use the Hg low mass emissions option, either semiannual or annual Hg emission testing is required, depending on the annual mass

emission level;

C For Appendix D fuel flowmeters, annual accuracy tests are required; and

C For Appendix E units and LME units using site-specific emission rates, re-testing is

required once every 5 years. 

Note that for linearity checks, RATAs, and fuel flowmeter accuracy tests, test exemptions

and test deadline extensions are permitted by Part 75 in certain circumstances. The required QA

tests for Part 75 monitoring systems are discussed in greater detail in section 8 of this guide.

For all required continuous monitoring systems, a written quality assurance (QA) plan must

be developed and followed . The quality control plan includes step-by-step procedures for each of

the required QA tests, as well as procedures for calibration adjustments, preventive maintenance,

audits, recordkeeping and reporting.

2.6 Maintain Records

The basic record keeping provisions of Part 75 are found in Subpart F (§75.53 and

§§75.57 through 75.59). Most of the required records are kept electronically, for a minimum of

three years, using a data acquisition and handling system (DAHS), although some monitoring plan
16

information and quality assurance (QA) test support data is kept in hard copy. The DAHS

records all data from the monitoring systems, translates it into the required units of measure, and

stores the data. When emissions data are missing, the DAHS automatically performs missing data

substitution. The DAHS also electronically records and stores operating data for the combustion

unit, emission control device data, monitoring plan data, and the results of QA checks and tests. 

Parallel recordkeeping sections, that frequently cite the basic Subpart F provisions, are 

found in §75.73 of Subpart H (for NOx mass trading programs such as the NBP) and in §75.84 of

Subpart I (for mercury mass trading programs such as the CAMR). The NBP, CAIR and CAMR

rules also include recordkeeping sections, but in general, these sections contain no new or unique

requirements. Rather, they serve as “road signs”, pointing back to the recordkeeping provisions

in Subparts F, H, and I. 

The electronic records that must be maintained are quite detailed and are not discussed

further in this guide. Typically, DAHS vendors can provide software that meets the Part 75

recordkeeping requirements.

2.7 Report Emissions

The basic Part 75 reporting provisions (originally written for the ARP) are found in

Subpart G (§§75.60 through 75.64). Subpart G includes requirements to provide various types of

notifications and to submit monitoring plans, certification applications, and electronic emissions

reports at specified times. Parallel notification and reporting sections, which reference sections of

Subpart G, are found in §§75.73 and 75.74 of Subpart H (for NOx trading programs such as the

NBP), and in §75.84 of Subpart I (for mercury trading programs such as the CAMR). 

The NBP, CAIR and CAMR rules also include notification and reporting sections, but

these sections simply reference the notification and reporting provisions in Subparts G, H, and I of

Part 75. The CAIR SO2 rule refers to Subpart G; the NBP and CAIR NOx rules refer to Subparts

G and H; and the CAMR rule refers to Subpart I.

For units under the Acid Rain Program and/or the CAIR annual SO2 and NOx trading

programs, emissions reports must be submitted four times a year, i.e., one report for each

calendar quarter. Units that are subject to the NOx Budget Program or to the CAIR ozone season

NOx trading program, but are not in either the Acid Rain Program or the CAIR annual SO2 and

NOx programs, have the option of reporting emissions data either year-round or only for the

ozone season (May 1st through September 30th). 

The quarterly reports allow EPA to track the quality of the emissions data throughout the

year (or ozone season) as well as the status of emissions compared to the allowances held. The

data and information to be reported include the following:

C Facility information;
17

C The hourly emissions data, operating data, the results of the required QA tests, and

other information specified in the monitoring plan and recordkeeping sections of

Part 75;

C Unit operating hours for the quarter and cumulative operating hours for the

calendar year and/or ozone season;

C Tons of SO2 emitted during the quarter and cumulative SO2 mass emissions for the

calendar year (ARP units and units in the CAIR SO2 Trading Program, only);

C Average NOx emission rates (lb/mmBtu) for the quarter and for the year-to-date 

(ARP units, and certain units in the NBP and CAIR NOx Trading Programs);

C Tons of CO2 emitted during the quarter and cumulative CO2 mass emissions for the

calendar year (ARP units, only);

C Tons of NOx emitted during the quarter and cumulative NOx mass emissions for

the calendar year and/or ozone season, as applicable (for units in the NBP and

CAIR NOx Trading Programs);

C Ounces of Hg emitted during the quarter and cumulative Hg mass emissions for the

calendar year (CAMR units, only); and 

C Total heat input (mmBtu) for quarter and cumulative heat input for calendar year

(or ozone season)—unless exempted from heat input reporting by regulation.

EPA requires the data be submitted electronically, because of the large volume of

information that must be reported. The Agency provides a standard electronic data reporting

(EDR) format that must be used and provides monitoring data checking (MDC) software that can

be used to perform quality control checks on the data prior to data submittal. While use of the

MDC software is optional, EPA encourages it because using the MDC will cut down on the

number of re-submissions and save time and money. EPA processes each quarterly report through

rigorous quality control checks to verify data accuracy and conformance to the required format.

After the review, the Agency sends notifications to the affected sources, indicating whether the

quarterly data are acceptable or unacceptable. The Part 75 reporting requirements are discussed

in more detail in Section 10 of this guide.
11

 As previously-noted, Part 75 allows the use of Appendix G, a non-CEMS method, to estimate CO2

mass emissions from coal-fired units. However, none of the coal-fired units in the Acid Rain or NOx Budget

Programs are presently using it. Also, for Hg, certain coal-fired may qualify to use the low mass emissions option

in §75.81(b), instead of continuously monitoring the Hg concentration.

18

3.0 BASIC CONTINUOUS EMISSION

 MONITORING REQUIREMENTS

The basic Part 75 continuous monitoring approach is to install CEMS and a DAHS on each

affected unit and record emissions and heat input data. This general approach must be followed

for combustion units that burn coal or any other solid fuel11 (see Table 3). Oil-fired and gas-fired

units may either comply with these basic requirements or may use alternative monitoring methods

for some or all parameters (see Sections 4, 5, and 6 of this guide for further discussion of the

alternative methods).

Table 3: Units that Must Comply with the Basic Part 75

CEMS Requirements

The basic Part 75 CEMS requirements must be met for any unit that . . .

C Is coal-fired, as defined in §72.2; 

or that

C Combusts wood, refuse or other material in addition to gas or fuel oil

3.1 What is a continuous emission monitoring system (CEMS)?

A continuous emission monitoring system, or CEMS, consists of all the equipment needed

to measure and provide a permanent record of the emissions from an affected unit. Examples of

CEMS components include:

C Pollutant concentration monitors (e.g., SO2 , NOx, or Hg monitors).

C Diluent gas monitors, to measure %O2 or %CO2

C Volumetric flow monitors

C Sample probes

C Sample (“umbilical”) lines

C Sample pumps

C Sample conditioning equipment (e.g., heaters, condensers, gas dilution equipment)

C Data loggers or programmable logic controllers (PLCs)
12

 Some in-situ monitoring systems have a probe that measures at a single point or along a short path. 

Other in-situ systems send a beam of light across the stack to a detector.

13

 There are two basic types of wet-basis extractive systems: (1) hot-wet; and (2) dilution extractive. Hotwet systems (which are seldom used) require the sample lines and the analyzer to be heated to prevent moisture

from condensing. Dilution-extractive systems (which are widely-used in Part 75 applications) prevent

condensation by a different principle. The gas sample is diluted with large quantities of purified air to keep it

above its dew point.

19

C DAHS components that electronically record all measurements and automatically

calculate and record emissions and heat input in the units of measure required by

the rule.

The specific components of a CEMS depend upon the parameter being monitored, the

measurement principle of the CEMS, and the required units of measure. Some components are

common to all systems, while others are specific to a particular monitoring technology. To

illustrate:

C The key components of every Part 75 CEMS are the analyzer(s) and the DAHS

(see Table 4). Table 4 shows that all Part 75 CEM systems, except for one, have

only one component monitor. The exception is the NOx emission rate, or “NOx-

diluent” monitoring system, which measures NOx in lb/mmBtu. This system

includes both a NOx monitor and a diluent gas monitor (either CO2 or O2).

C PLCs and data loggers are common to all types of CEMS

C Probes, sample lines, vacuum pumps and sample conditioning equipment are

associated with “extractive” CEMS, which continuously withdraw a sample of the

effluent gas from the stack and send it to an analyzer located in a climatecontrolled environment (i.e., a “CEMS shelter”).

C “In-situ” CEMS, which analyze the effluent gas at stack conditions, sometimes

have probes12, but unlike extractive systems, do not require sample lines, sample

conditioning equipment, etc.

C Extractive CEMS that measure on a dry basis require moisture removal systems,

whereas wet basis extractive systems13 do not.

The number of required monitors can sometimes be minimized by sharing certain

components among two or more monitoring systems. For example, data from a single diluent gas

monitor could be used to calculate NOx emission rate and CO2 mass emissions.
20

Table 4: Part 75 CEM Systems

Type of Monitoring

System

(Units of Measure)

Key Components:

SO2

Monitor

NOx

Monitor

Flow

Monitor

Diluent

Gasa

Monitor

Hg

Monitorg

Moisture

Monitor

Opacity

Monitor

DAHS

SO2 concentration 

 (ppm)

% %

NOx emission rate 

 (lb/mmBtu)

% % %

NOx concentration b 

 (ppm)

% %

Hg concentration

 (:g/scm)

% %

Stack gas flow rate

 (scfh)

% %

CO2 concentration c

 (% CO2)

% %

O2 concentration d

 (% O2)

% %

 Moisture e

 (% H2O)

% %

 Opacity f

 (%)

% %

a Diluent gas is either CO2

 or O2.

b

 This type of system is used only by NOx Budget Program or CAIR NOx Program sources, in conjunction with a stack flow 

 monitor, to quantify NOx mass emissions.

c

 Note that CO2 concentration may be determined indirectly, using an O2 monitor and Equation F-14a or F-14b. In the Acid 

 Rain Program, this type of system is used with a flow monitor to quantify CO2 mass emissions. In the NOx Budget Program 

 or CAIR NOx Program, it is used exclusively for heat input rate determinations. 

d This type of system is used exclusively for heat input rate determinations. An O2

 monitor is required.

e

 This type of system is used whenever the emissions or heat input calculations require a correction for the stack gas moisture 

 content.

f

 This type of system is required only for coal-fired and certain oil-fired units in the Acid Rain Program. It is generally referred 

 to as a “continuous opacity monitoring system”, or “COMS”, rather than a CEMS.

g

 A sorbent trap monitoring system may be used to monitor the Hg concentration, in lieu of a Hg CEMS.
21

3.2 What is a sorbent trap monitoring system ?

As previously noted in Section 2.2, above, a sorbent trap monitoring system is an

alternative type of continuous Hg monitoring system that may be used instead of an Hg CEMS,

for any affected unit under the CAMR rule. A sorbent trap system continuously samples the stack

gas for an extended period of time (anywhere from several hours to several days, depending on

the Hg concentration in the stack). Mercury is collected inside a tube (“trap”) that is filled with a

sorbent medium such as activated carbon, and a dry gas meter is used to measure the total volume

of dry stack gas sampled during the data collection period. 

The sorbent trap system is similar to an extractive-type CEMS, in that it continuously

samples the stack gas and uses a moisture removal system. However, the similarity ends there, as

the sorbent trap system differs from a CEMS in many ways. First, it does not measure the realtime Hg concentration every hour. Rather, it gives only an average Hg concentration over the

data collection period, and this average concentration cannot be known until the sorbent traps

have been analyzed in the lab. Second, unlike a CEMS, which samples at a constant rate, the

sample flow rate through a sorbent trap is varied during the collection period, in proportion to the

stack gas volumetric flow rate. Third, paired sorbent trap systems must be run simultaneously

during each data collection period, and the Hg concentrations obtained from the two systems

must agree to within a specified tolerance to validate the data. Finally, the certification and ongoing quality-assurance test requirements for sorbent trap systems are considerably different from

those for an Hg CEMS. The only QA test common to both types of systems is the RATA. The

certification and QA test requirements for Hg monitoring systems are discussed further in

Sections 7 and 8 of this guide.

3.3 Primary and Backup Monitoring Systems

For each monitored pollutant or parameter, Part 75 requires that a primary monitoring

system be designated. Data from the primary system must be reported if it is in-service. 

However, when the primary system is not able to provide quality-assured data, data from one of

the following types of backup monitors or monitoring systems may be reported:

C Redundant backups. A redundant backup monitoring system is a fully-certified,

stack- or duct-mounted system that continuously records data and is kept on “hot

stand-by” in case of a primary system outage. A redundant backup monitoring

system is operated, maintained and quality-assured in the same manner as the

primary system. 

C Non-redundant backups. A non-redundant backup monitoring system is a

certified system that does not operate continuously. Rather, it is kept on “cold

stand-by”, and must pass a substantive quality-assurance test each time it is

brought into service. For example, before a non-redundant backup gas monitoring

system can be used for Part 75 reporting, it must pass a linearity check. The use of

a non-redundant backup system is restricted to 720 hours per year at a given unit

or stack location. 
14

 Except for opacity data, which generally has a shorter averaging period (e.g., 6 minutes)

15

 However, when required quality-assurance or maintenance activities are performed during a unit

operating hour, only two data points (in two separate quadrants, > 15 minutes apart) are needed to validate the

hourly average. This helps to minimize data loss during mandatory QA activities.

22

C Like-kind replacement analyzers. A like-kind replacement analyzer is a gas 

analyzer of the same type as the primary (i.e., it monitors the same parameter by

the same measurement principle). A like-kind replacement analyzer may be used

for short periods of time when the primary analyzer malfunctions or needs

maintenance. The replacement analyzer does not require certification, provided

that it is connected to the same probe and sample interface as the primary analyzer,

and that it is not used for more than 720 hours per year at a particular unit or stack

location. A linearity check of the analyzer is required each time it is brought into

service.

C Reference method backups. EPA reference test methods (e.g., Method 6C for

SO2 or Method 7E for NOx) may be used to provide quality-assured data during

CEMS outages. 

Although it might save money initially, failure to have backup or redundant monitoring

equipment could result in over-reporting of emissions in the long run. For example, suppose that

the same CO2 monitor is used to determine both CO2 mass emissions and NOx emission rate.

When the CO2 monitor malfunctions, the missing data procedures for both NOx and CO2 must be

applied, since the systems for NOx and CO2 are considered to be out-of-control. As previously

noted, the Part 75 missing data procedures tend to produce increasingly more conservative (i.e.,

conservatively high) emissions estimates as the PMA decreases. Therefore, long missing data

periods may result in significant over-reporting of emissions and loss of allowance credits.

3.4 How must a CEMS be operated?

The minimum operating and data capture requirements for Part 75 CEM systems are

summarized in Table 5. In general, the CEMS must be operated at all times when the unit is

combusting fuel, except when the monitors are being calibrated, maintained, or repaired. As

previously noted, each CEMS must be equipped with an automated DAHS, to record the

emissions data and to reduce it to hourly averages14. To make an hourly average, at least one

valid data point (generally, this means a valid one-minute average) is required in each 15-minute

quadrant of the hour in which the unit operates.15 A single DAHS is usually sufficient to manage

data for all the parameters that must be monitored.
16 Diluent gas monitors give a readout in % CO2

 or %O2 , but this is simply a power of 10 multiple of the

parts per million value, e.g., 10% CO2 corresponds to 100,000 ppmv.

23

Table 5: Minimum Operating and Data Capture Requirements 

for Part 75 CEMS

For this parameter...

The CEMS must

complete one cycle of

sampling and

analyzing at least...

And record valid

data at least... 

And the DAHS must

reduce the recorded

data to...

SO2, CO2, O2, NOx,

Hg, moisture, and flow

rate

Once for each

successive 15-minute

period

Once for each 15-

minute “quadrant” in

each unit operating

hour

Hourly averages

Opacity Once for each

successive 10-second

period

Once for each

successive averaging

period

6-minute averages or

other required

averaging period 

3.5 How are emissions and heat input rates determined from CEMS data?

The methods for determining emissions and heat input rates are shown in Table 6. This

table presents the general equations used to convert monitoring data into the units of measure

required by Part 75. The equations are somewhat different for each parameter monitored, but are

based on the same principles. These principles are explained below.

The gas monitors required by Part 75 (i.e., SO2 , NOx , CO2 and O2) measure concentration

in parts per million by volume (ppmv)16, with one exception—Hg monitors measure concentration

in micrograms per standard cubic meter (:g/scm). However, concentration data alone are not

sufficient to characterize emissions under Part 75---the concentrations must be converted into

emission rates. The rule specifies the appropriate conversion factors to use. 

The units of the emission rates are pounds per standard cubic foot (lb/scf) for SO2 and

NOx, tons per standard cubic foot (tons/scf) for CO2, and ounces per standard cubic foot (oz/scf)

for Hg. These emission rates are then used to determine the emissions in the units of measure

required by Part 75, i.e., either mass per unit of time (lb/hr, tons/hr, or oz/hr), mass per unit of

heat input (e.g., lb/mmBtu), or simply mass (pounds, tons, ounces).
24

Table 6: Calculating Emissions and Heat Input Rate

from Part 75 CEMS Data

To calculate this

quantity. . .

These parameters must be

monitored . . .

And an equation with this general

structure is used . . .

Example 

Equations a

SO2 or NOx mass

emission rate (lb/hr)

 

 or

CO2 mass emission

rate (tons/hr)

 or

Hg mass emission

rate (ounces/hr)

SO2 concentration and

stack gas flow rate 

 or

CO2 concentration and

stack gas flow rate 

or

Hg concentration and

stack gas flow rate 

E = (K) * (C) * (Q) *(H2O)

Where:

E = SO2 , NOx , CO2 or Hg mass

emission rate (lb/hr or tons/hr or

ounces/hr)

K = Species-specific conversion

constant b

C = Hourly average SO2 , NOx , CO2, or

Hg concentration (ppmv or %CO2,

or :g/scm)

Q = Hourly average volumetric flow

rate (scfh)

H2O = Moisture correction term (if SO2 ,

CO2 , or Hg is measured on a dry

basis)

F-1, F-2

SO2 , NOx , CO2 , or

Hg mass emissions 

(lb, tons, or ounces)

SO2 , NOx , CO2 , or Hg

concentration, stack gas

flow rate and operating time

M = (E) * (top)

Where:

E = SO2 , NOx , CO2 , or Hg mass

emission rate, calculated as shown

above (lb/hr, tons/hr, or ounces/hr)

 top = Operating time c (hr)

F-3, F-12,

F-26, F-28,

F-29

NOx emission rate 

 (lb/mmBtu)

NOx concentration 

 and

Diluent gas (CO2 or O2)

concentration

R = (K) * (C) * (F) * (D)* (H2O)

Where:

R = NOx emission rate (lb/mmBtu)

K = Conversion constantb

C = Hourly average NOx concentration

(ppmv)

F = Fuel-specific F-factor (dscf/mmBtu

or scf CO2/mmBtu)

D = Diluent gas correction term

H2O = Moisture correction term (if NOx

and diluent are measured on a

different moisture basis)

F-5, F-6,

19-4, 19-8

NOx mass emissions 

 (lb)

(Alternate method)

Heat input rate, NOx

emission rate, and 

operating time 

M = (R) * (HI) * (top)

Where:

M = NOx mass emissions (lb)

R = NOx emission rate (lb/mmBtu)

HI = Heat input rate (mmBtu/hr)

top = Operating time c (hr)

 F-24
25

Table 6 (cont’d)

To calculate this

quantity. . .

These parameters must be

monitored . . .

And an equation with this general

structure is used . . .

Example 

Equations a

Heat input rate

(mmBtu/hr)

Diluent gas concentration 

 and stack gas flow rate

HI = (Q) * (1/F) * (1/D)*(H2O)

Where:

HI = Heat input rate (mmBtu/hr)

Q = Hourly average volumetric flow

rate (scfh)

F = Fuel-specific F-factor (dscf/mmBtu

or scf CO2/mmBtu)

D = Diluent gas correction term

H2O = Moisture correction term (if

required)

F-15, F-16,

F-17, F-18

Opacity Opacity (%) Follow the site-specific instructions of the

instrument manufacturer

 -------

a Equation codes beginning with “F” are from Appendix F of Part 75. Equations beginning with “19" are from EPA Method 

 19, in Appendix A-7 of 40 CFR Part 60.

b

 The appropriate constants are 1.660 x 10-7 lb/scf-ppm for SO2 , 1.194 x 10-7 lb/scf-ppm for NOx , 5.7 x 10-7 

 tons/scf-%CO2 for CO2, and 9.978 x 10-10 oz-scm/:g-scf for Hg.

c

 Operating time is defined as the fraction of the hour in which the unit operates (or, for a common stack, the 

 fraction of the hour that exhaust gases flow through the stack). For example, top = 1.00 for a full hour of unit 

 operation, 0.50 for a half-hour of unit operation, etc.

Determining lb/mmBtu emission rates

To obtain emission rates in terms of mass per unit of heat input (e.g., NOx emission rate in

lb/mmBtu), the emission rate in lb/scf is multiplied by a fuel-specific “F-factor.” The F-factor

relates the volume of stack gas or CO2 produced by combustion to the caloric heat content of the

fuel combusted. For example, typical units for an F-factor are dry standard cubic feet of stack gas

per million Btu heat input (dscf/mmBtu), or standard cubic feet of CO2 per million Btu (scf CO2

/mmBtu). The F-factors, which are listed in Appendix F of the rule, are derived for each type of

fuel based on the thermodynamic principles of combustion. Since F-factors are derived assuming

that fuel and air are mixed in an exact stoichiometric ratio and that combustion is complete,

corrections for excess air are needed.

Determining mass emission rates

To obtain emission rates in terms of mass per unit time (lb/hr, tons/hr, or oz/hr), the

emission rate (lb/scf, tons/scf, or oz/scf) is multiplied by the stack gas flow rate, in standard cubic

feet per hour (scfh). For NOx, the mass emission rate in lb/hr may also be calculated by

multiplying the NOx emission rate (lb/mmBtu) by the heat input rate (mmBtu/hr).
26

Determining heat input rate, in mmBtu/hr

To determine heat input rate (mmBtu/hr), the monitored stack gas flow rate (scfh) is

divided by the F-factor (scf/mmBtu) and a correction for excess air is applied.

Converting mass emission rates and heat input rates

To convert an hourly pollutant mass emission rate (e.g., lb/hr) to mass (e.g., lb), or to

convert an hourly heat input rate (mmBtu/hr) to heat input (mmBtu), multiply the emission (or

heat input) rate by the operating time. The operating time, top, is defined as the fraction of the

hour in which the unit combusts fuel. For units sharing a common stack, if the CEMS are

installed on the stack, the operating time is the fraction of the hour that exhaust gases flow

through the stack. For example, top = 1.00 for a full hour of unit operation, 0.50 for a half-hour of

unit operation, etc.

3.6 When are corrections for stack gas moisture content required?

Determination of the stack gas moisture content is required only in certain situations where

CEMS are used to satisfy the Part 75 monitoring requirements. Table 7 summarizes when

correction for the stack gas moisture content is required. Generally speaking, the stack gas

moisture content must be monitored when two parameters in the emission or heat input rate

equation (e.g., gas concentration and stack gas flow rate) are not measured on the same moisture

basis (i.e., one is measured on a wet basis and the other on a dry basis). 

For example, flow rate monitors always measure stack gas flow on a wet basis. This means

that the volume of gas measured includes the contribution from the moisture content of the stack

gas. Therefore, when a gaseous pollutant such as SO2 is measured on a dry basis, in order to

obtain the correct mass emission rate in lb/hr, the dry-basis SO2 concentration is multiplied by the

wet-basis stack gas flow rate, and a moisture correction is applied. As a second example, when

NOx emisssion rate in lb/mmBtu is measured, a moisture correction is needed if the NOx

concentration and diluent gas monitors measure on different moisture bases.

If a correction for the stack gas moisture content is required, one of the following moisture

measurement methods must be used:

C An O2 analyzer (or analyzers) capable of measuring on both a wet and dry basis.

C A continuous moisture sensor. 

C A stack temperature sensor and a moisture look-up table (for saturated gas streams

only).

C A fuel-specific default moisture value defined in Part 75 (for coal and wood, only).

C A site-specific default moisture value approved by petition under §75.66.
27

Table 7: Correction for Stack Gas Moisture Content

For this parameter . . . A correction for stack gas moisture is required if . . .

SO2 mass emission rate (lb/hr) SO2 concentrations are measured on a dry basis

NOx emission rate (lb/mmBtu) NOx and diluent gas concentrations are not measured on the same

moisture basis

NOx mass emissions (lb) NOx mass is calculated as the product of NOx concentration, stack gas

flow rate and operating time, and the NOx concentrations are

measured on a dry basis

Hg mass emissions (ounces) Hg concentrations are measured on a dry basis

CO2 mass emission rate

(tons/hr)

CO2 concentrations are measured on a dry basis

Heat input rate (mmBtu/hr) CO2 is the diluent gas and is measured on a dry basis; 

or

O2 is measured as the diluent gas

3.7 What if a unit has multiple stacks or shares a stack with other units?

If a unit shares a common stack with other units or emits through multiple stacks, Part 75

requires procedures to be implemented that ensure complete emissions and heat input accounting.

In some cases, the procedures will require monitoring systems to be installed at more than one

stack or duct location. The configuration of ductwork and stacks, the program(s) that the unit is

subject to, and the regulatory status of the units (i.e., affected or non-affected) determine the

number of monitors needed and the required locations. 

Common and multiple stack configurations for the various trading programs are addressed

in several different places within Part 75. For Acid Rain Program units, the rule provisions

pertaining to common and multiple stacks are found in §§ 75.16 through 75.18. For CAIR SO2

Trading Program units, the provisions are in §75.16. For NOx Budget Trading Program units and

CAIR NOx Trading Program units, the applicable provisions are in §75.72. For Hg Budget units

under CAMR, the common and multiple stack provisions are found in §75.82. 

These rule provisions are summarized in Table II-A of Appendix II of this guide. For

configurations that are not covered in Table II-A, sources should contact EPA for additional

guidance.

3.8 What are the missing data procedures for CEMS ?

For each unit operating hour in which quality-assured CEMS data are not obtained (i.e.,

are missing), Part 75 requires substitute data to be reported. The rather complex CEMS missing

data procedures are discussed in detail in Section 9 of this guide. 
17

 The definitions of gas-fired and oil-fired in §72.2 each consist of two parts. One part of the definition

applies to all purposes under the Acid Rain Program except for Part 75, and the other applies exclusively to Part

75. In Tables 8 and 9, only the Part 75-specific pieces of the definitions are presented.

28

4.0 APPENDIX D METHODOLOGY FOR

 GAS-FIRED AND OIL-FIRED UNITS

If an affected unit meets the definition of gasfired or oil-fired, the alternative methodology in

Appendix D of Part 75 may be used instead of

CEMS, for certain parameters. Appendix D applies

only to the measurement of the SO2 mass emission

rate and the unit heat input rate.

4.1 What is a gas-fired or oil-fired unit ?

Gas-fired and oil-fired units are defined17 in Tables 8 and 9.

Table 8: Gas-Fired Units

According to §72.2, a combustion unit is a gas-fired unit if it . . .

C Combusts natural gas or other gaseous fuel(s) (including coal-derived fuel), such that gaseous

fuel combustion accounts for at least: 

< 90.0 percent of the unit’s average annual heat input during the previous three calendar

years, and 

< 85.0 percent of the annual heat input in each of those calendar years,

and

C Combusts fuel oil for the remaining heat input (if any)

Table 9: Oil-Fired Units

According to §72.2, a combustion unit is an oil-fired unit if it . . .

C Combusts only fuel oil and gaseous fuel(s), 

and

C Does not meet the definition of a gas-fired unit in §72.2

The alternative methodology in

Appendix D of Part 75 for gasfired and oil-fired units pertains

to the monitoring of the SO2

mass emission rate and the unit

heat input rate.
18 These methods represent consensus standards established by various organizations, e.g., ASME,

API, AGA, and ISO. 

29

4.2 What is the Appendix D alternative monitoring method ?

The alternative monitoring methodology in Appendix D requires continuous monitoring of

the fuel flow rate and periodic sampling of the fuel characteristics, such as sulfur content, gross

calorific value (GCV), and density. The measured fuel flow rates are used together with the

results of the fuel sampling and analysis to determine the SO2 mass emission rate and/or the unit

heat input rate, depending on the requirements of the applicable program(s). The Appendix D

methodology is summarized in Table 10. 

Table 10: Appendix D Monitoring Methodology

 for Gas-Fired and Oil-Fired Units 

If an affected unit is . . . Part 75 allows . . . And to obtain the necessary

data . . .

In the Acid Rain Program or

the CAIR SO2 Trading

Program and meets the

definition of oil-fired or gasfired in §72.2

The SO2 mass emission rate

(lb/hr) and the unit heat input

rate (mmBtu/hr) to be calculated

based on measured fuel flow

rates and fuel characteristics

The fuel flow rate is

continuously monitored, 

and

Periodic fuel sampling and

analysis is conducted to

determine some or all of the

following--- fuel sulfur content,

GCV, and density

In the NOx Budget Trading

Program or the CAIR NOx

Trading Program(s), but is not

in the Acid Rain Program or

the CAIR SO2 Trading

Program, and if the unit meets

the definition of oil-fired or

gas-fired in §72.2

The unit heat input rate

(mmBtu/hr) to be calculated

based on measured fuel flow

rates and fuel characteristics

The fuel flow rate is

continuously monitored, 

and

Periodic fuel sampling and

analysis is conducted to

determine the GCV

4.3 How is the fuel flow rate measured ?

Appendix D requires the fuel flow rate to be continuously monitored and the data to be

reduced to hourly averages. To achieve this a certified fuel flowmeter or a commercial billing

meter may be used. To certify a fuel flowmeter, its accuracy must be established using one of the

methods18 specified in section 2.1.5.1 of Appendix D. 
19

 Acid Rain Program and CAIR SO2 Program units, only

30

C In most cases, the certification test procedure consists of calibrating the meter with a

flowing fluid, at three flow rates covering its normal operating range. Generally, this

requirement is met by calibrating the flowmeter in a laboratory, although the

flowmeter may be calibrated at the affected facility, by comparison against an in-line

“master meter” which has been tested for accuracy within the past 365 days using one

of the methods in section 2.1.5.1 of Appendix D.

C Alternatively, an orifice-, nozzle- or venturi-type flowmeter may be certified if its

primary element (for example, the orifice plate) meets the design criteria specified in

American Gas Association Report No. 3, and if its pressure, temperature, and

differential pressure transmitters are calibrated with standards traceable to the

National Institute of Standards and Technology (NIST). 

C A commercial billing meter may be used for Appendix D applications without

certification, if the meter can provide hourly average fuel flow rates, and if the

regulated source is not affiliated with the billing company. 

4.4 What are the fuel sampling requirements of Appendix D ?

For both gaseous fuels and fuel oil, Appendix D requires periodic sampling of fuel

characteristics (sulfur content and/or GCV and/or density). The required samples may be taken

either by the owner/operator, the fuel supplier, or by an independent laboratory.

Sampling of gaseous fuels

Appendix D divides gaseous fuels into three categories: (1) pipeline natural gas (PNG);

(2) natural gas; and (3) other gaseous fuels. The distinction between PNG and natural gas is in

the fuel sulfur content. Natural gas may have as much as 20 grains of total sulfur per 100

standard cubic feet (i.e., 20 gr/100 scf), but to qualify as PNG, the total sulfur content of the gas

must not exceed 0.5 gr/100 scf. The Appendix D fuel sampling and analysis requirements for

gaseous fuels are as follows:

C For PNG and natural gas, annual sampling of the total sulfur content19 is required,

unless a valid fuel contract is in place documenting that the fuel meets the definition of

PNG or natural gas. If such a contract exists, the owner or operator may choose not

to perform the annual sampling—however, the maximum total sulfur content specified

in the contract (often 20 gr/100 scf) must then be used to calculate the SO2 emissions. 
20

 See sections 2.3.5 and 2.3.6 of Appendix D

31

C The GCV of PNG or natural gas must be determined monthly, with certain

exceptions for units that operate infrequently.

C For other gaseous fuels transmitted by pipeline, the required frequency of total sulfur

sampling19 is hourly, unless the results of a 720-hour demonstration20 show that the

fuel qualifies for less frequent (i.e., daily or annual) sampling. 

C The GCV of other gaseous fuels transmitted by pipeline must be determined daily, or

hourly unless the fuel is demonstrated 20 to have a low GCV variability, in which case

monthly sampling is sufficient.

C For other gaseous fuels delivered in shipments or lots, each shipment or lot must be

sampled for sulfur content19 and GCV.

Acceptable ASTM and GPA sampling and analysis methods for gaseous fuels are referenced in

sections 2.3.3.1.2 (for fuel sulfur content) and 2.3.4 (for fuel GCV) of Appendix D.

Fuel oil sampling

For oil, Appendix D provides several fuel sampling and analysis options. The required

sampling of the sulfur content19, GCV and, if applicable, density of the oil may be done using any

of the following methods: 

C Daily sampling; or 

C Composite sampling for up to 168 hours, using hourly flow-proportional sampling or

continuous drip sampling; or 

C Sampling after each addition of oil to the storage tank; or 

C Sampling each delivery or “lot” of fuel (i.e., each ship load, barge load, group of

trucks, etc). The sample may be taken from either the supplier’s storage tank or from

the shipment tank (container) upon receipt.

Acceptable ASTM sampling and analysis methods for fuel oil are given in sections 2.2.5 (for fuel

sulfur content) and 2.2.7 (for fuel GCV) of Appendix D.
32

4.5 How is the SO2 mass emission rate calculated ?

For an Acid Rain Program unit using the Appendix D methodology, the hourly SO2 mass

emission rate is calculated using an equation that has one of the following basic structures: 

SO2 mass emission = Fuel flow rate x Fuel sulfur content x Units conversion factor

 rate (lb/hr)

 or

SO2 mass emission = SO2 emission rate x Heat input rate

 rate (lb/hr) (lb/mmBtu) (mmBtu/hr)

An example of an equation with the first basic structure is Equation D-2 in section 3 of

Appendix D, and an equation with the second basic structure is Equation D-5. In the first general

equation above, the fuel flow rate is the hourly average reading from the fuel flowmeter, and the

fuel sulfur content is based on the results of periodic fuel sampling and analysis (see Section 4.7,

below). In the second general equation, the heat input rate is derived from the hourly average fuel

flowmeter reading and the fuel GCV (see Section 4.6, below), and the SO2 emission rate is either: 

C A generic default value for the type of fuel combusted (e.g., 0.0006 lb/mmBtu for

PNG); or 

C A site-specific default value, determined by substituting the GCV and total sulfur

content of the fuel into Equation D-1h in Appendix D.

Note that for oil, when the fuel flow rate is measured on a volumetric basis (e.g., gal/hr), it

must be converted to a mass basis using the oil density. Therefore, for Acid Rain sources using

volumetric oil flowmeters, periodic sampling of the density of the oil is also required.

4.6 How is the unit heat input rate calculated ?

For an Acid Rain, NOx Budget, or CAIR unit using Appendix D to determine the hourly

unit heat input rate, an equation with the following basic structure is used: 

Heat input rate = Fuel flow rate x Fuel GCV x Units conversion factor

 (mmBtu/hr)
33

Examples of equations having this basic structure are Equations D-6 and D-8 in section 3 of

Appendix D. In the general equation above, the fuel flow rate is the hourly average reading from

the fuel flowmeter, and the GCV is based on the results of periodic fuel sampling and analysis. 

The units of measure for the fuel flow rate and the GCV must be consistent. For example, if the

fuel flowmeter measures in gallons per hour, the GCV is expressed in units of Btu per gallon.

4.7 Which sulfur content, GCV, and density values are used in the calculations ?

Appendix D provides the source owner or operator with considerable flexibility in

selecting the values of fuel sulfur content, GCV and density that are used in the emission and heat

input calculations. Generally speaking, the values used in the calculations are determined in one

of two ways:

(1) The results of the fuel sampling and analysis are used directly in the

calculations. 

Example 1: The GCV from the most recent monthly sample of pipeline natural

gas is used in the heat input rate calculations.

Example 2: For a process gas, hourly samples are taken of the sulfur content

and GCV, and the hourly values are used to calculate the SO2

emissions and unit heat input rate;

or

(2) An “assumed value” is used in the calculations. The assumed value may be:

C A default SO2 emission rate of 0.0006 lb/mmBtu, for a fuel that qualifies as

pipeline natural gas; or

C The highest value from any required sample taken in the previous calendar

year; or

C The highest value from any sample taken in a specified “look-back” period;

or

C The highest value specified in a valid, active fuel contract or tariff sheet; or
21 For gaseous fuels other than natural gas, which are transmitted by pipeline—see sections 2.3.5

and 2.3.6 of Appendix D

34

C The value obtained from a 720-hour characterization of the fuel’s sulfur

content or GCV21

This calculation method is subject to the following conditions:

C If the results of any required fuel sampling and analysis exceed the assumed

value, then that sample result becomes the new assumed value; and

C If the assumed value is from a fuel contract or tariff sheet, and if the

contract or tariff sheet is superseded by a new one, then the assumed value

may have to be adjusted, or, in some instances, the fuel may have to be reclassified. Consider the following examples:

Example 1: A maximum GCV of 105,000 Btu/100 scf is specified in a 

valid, active natural gas contract. This GCV value may

continue to be used in the heat input rate calculations,

provided that it is not exceeded, either by the results of a

required monthly GCV sample, or by the maximum GCV

value in a new contract.

Example 2: In 2004, the highest percent sulfur (%S) value obtained from

the required samples of distillate oil was 0.15 %S, by weight.

This %S value may be used in the SO2 emission calculations

throughout 2005, provided that it is not exceeded by the

results of any required fuel sample.

Example 3: Daily manual sampling of fuel oil is performed, and on each

successive unit operating day, the highest sulfur content,

GCV, and density values from the previous 30 daily samples

are used in the calculations.

Example 4: The results of a 720-hour demonstration under section 2.3.6

of Appendix D show that a process gas has a low sulfur

variability. A default SO2 emission rate of 0.025 lb/mmBtu is

calculated by substituting the 90th percentile value of the fuel’s

sulfur content from the demonstration into Equation D-1h. 

This default emission rate may continue to be used unless it is

exceeded when Equation D-1h is applied to the results of a

required annual sample of the fuel’s sulfur content.
22

 The term “fuel flowmeter QA operating quarter” (see §72.2) is used to describe a quarter in which the

fuel measured by the flowmeter is combusted for 168 hours or more. All such “QA quarters” count toward the

accuracy test deadline. Test deadline extensions may only be claimed for “non-QA” quarters.

35

Example 5: A fuel initially qualifies as pipeline natural gas, based on

historical fuel sampling data. In this year’s required annual

fuel sampling and analysis, 3 samples are taken and the total

sulfur content of all samples is between 1.0 and 1.5 gr/ 100

scf. The fuel is therefore re-classified as “natural gas” and the

average total sulfur value from the 3 samples is used in

Equation D-1h, to calculate a site-specific default SO2

emission rate

For a complete listing of all of the available calculation options for fuel oil and gaseous

fuels, see Tables D-4 and D-5 in Appendix D. Also note that for each of these options,

instructions are given in section 2.3.7 of Appendix D, explaining when and how to apply the fuel

sampling results. This helps to ensure national consistency in the reporting of Appendix D data.

4.8 What are the on-going quality-assurance requirements of Appendix D ?

Following initial certification, each Appendix D fuel flowmeter (except for qualifying fuel

billing meters) must undergo periodic accuracy testing, using the same general approach that was

used for initial certification (see Section 4.3, above). Fuel flowmeter accuracy testing must be

performed once every 4 calendar quarters, unless the flowmeter qualifies for an extension of the

test deadline. A one-quarter extension of the test deadline may be claimed for any calendar

quarter in which:

C The fuel measured by the flowmeter is burned for less than 168 hours22 . This type

of extension is most advantageous for fuels that are seldom combusted and for

units that operate infrequently; or

C The optional fuel flow-to-load ratio test described in section 2.1.7 of Appendix D

is performed and passed. This option is most useful for fuels that are routinely

combusted for more than 168 hours per quarter. 

Note that fuel flowmeter accuracy test deadlines may not be extended indefinitely. The

limits to these extensions are as follows:

C If the deadline extension is based on infrequent combustion of a fuel or infrequent

unit operation, a flowmeter accuracy test must be performed no later than 4 “QA”

quarters

22 or 20 calendar quarters—whichever comes first—after the quarter in

which the previous test was done; or
36

C If the deadline is being extended by performing the fuel flow-to-load ratio test, the

maximum allowable extension is 20 calendar quarters from the quarter of the

previous test.

In addition to performing periodic fuel flowmeter accuracy testing, section 1.3 in

Appendix B of Part 75 requires the owner or operator of an Appendix D unit to develop and

implement a quality-assurance plan. The essential elements of the QA plan include the following:

C A written record of the fuel flowmeter accuracy test procedures;

C Records of maintenance, adjustments, and repairs of the fuel flowmeter(s); and

C A written record of the standard procedures used to perform the required fuel

sampling and analysis.

4.9 What are the missing data procedures for an Appendix D unit ?

Whenever fuel flow rate data or any of the required fuel sampling data is missing,

Appendix D requires substitute data values to be reported. The Appendix D missing data

procedures are discussed in detail in Section 9 of this guide. 
23 According to §72.2, the annual capacity factor is either: (1) the ratio of the unit’s actual annual

electrical output to the nameplate capacity times 8,760; or (2) the ratio of the unit’s actual annual heat input to the

maximum design heat input times 8,760 

24 The ozone season capacity factor is calculated in the same basic way as the annual capacity factor,

except that the ozone season heat input or electrical output is used in the calculation, and “8,760" is replaced with

“3,672", which is the number of hours in the ozone season (see §75.74(c)(11)).

37

5.0 APPENDIX E METHODOLOGY FOR

 GAS-FIRED AND OIL-FIRED PEAKING UNITS

If a unit is in the Acid Rain Program, NOx Budget Program, or CAIR NOx Trading

Program(s), and it meets the definition of a “peaking

unit” in §72.2, and if it also qualifies as oil-fired or

gas-fired (see Section 4.1, above), then the alternative

methodology in Appendix E of Part 75 may be used to

monitor the NOx emission rate, in lieu of installing

CEMS. For a qualifying Appendix E unit:

C The Appendix D methodology must be used to

measure the hourly unit heat input rate (see

Section 4.6, above); and

C Emission testing must be conducted at four

different loads to develop a correlation curve

of NOx emission rate versus heat input rate 

5.1 What is a peaking unit ?

The definition of a peaking unit is presented in Table 11. Table 11 shows that for a unit

that reports emissions data year-round, peaking unit qualification depends on the annual capacity

factor23of the unit. For units in the NOx Budget Program and units in the CAIR Ozone Season

Trading Program that report emissions only for the ozone season months (May through

September), peaking unit qualification depends on the ozone season capacity factor24 of the unit.

Table 11. Peaking Units

According to §72.2, a combustion unit is a peaking unit if it has...

C An average annual capacity factor of 10.0 percent or less over the past three years; 

and

C An annual capacity factor of 20.0 percent or less in each of those three years

The Appendix E methodology for

gas-fired and oil-fired peaking

units pertains only to the

monitoring of NOx emission rate.

To use this methodology, a

correlation curve of NOx emission

rate vs heat input rate is first

derived from emission testing,

Then, the hourly unit heat input

rate is measured using the 

Appendix D methodology, and the

hourly NOx emission rate is

determined from the correlation

curve. 
25

 These test methods are found in Appendices A-2, A-4 and A-7 of 40 CFR Part 60.

38

Figure 2: Typical Appendix E Correlation Curve

5.2 How is an Appendix E correlation curve constructed ?

Appendix E correlation curves are derived from emission test results. Appendix E

requires an initial four-load NOx emission rate test to be performed for each type of fuel

combusted in the unit, except for emergency fuel, for which the testing is optional. For boilers,

the testing is performed using EPA Reference Methods 7E and 3A, and for combustion turbines

and diesel or dual-fuel reciprocating engines, Reference Method 20 is used25. The emission

testing is done at four evenly-spaced load points, ranging from the minimum to the maximum unit

operating load, and three test runs are performed at each load level. For existing units, two years

of historical data are used to establish the minimum and maximum operating loads. For new

units, five-year projections of the minimum and maximum loads are used.

During each Appendix E test run, the unit heat input rate is determined using the fuel

GCV and readings from a fuel flowmeter that meets the requirements of Part 75, Appendix D. 

Also, certain parameters must be monitored during each test run. For boilers, excess oxygen is

monitored, and it must either be set at a normal level or at a conservatively high level. For

turbines and diesel or dual-fuel reciprocating engines, at least four parameters indicative of the

unit’s NOx formation characteristics are monitored and acceptable ranges for each parameter are

established during testing. If a turbine uses water injection to control NOx emissions, the waterto-fuel ratio must be one of the monitored parameters. 

The NOx emission rate and heat input rate data are averaged at each load level. Then, a

correlation curve of NOx emission rate (lb/mmBtu) versus heat input rate (mmBtu/hr) is
39

constructed and the curve segments are programmed into the data acquisition and handling system

(DAHS). A typical Appendix E correlation curve is shown in Figure 2, above.

 

5.3 How are the hourly NOx emissions determined?

The Appendix E methodology is summarized in Table 12. The hourly NOx emission rate

Table 12: Appendix E Methodology for Determining NOx Emissions

from Oil-and Gas-Fired Peaking Units

To use Appendix E to

determine . . .

The following data must be collected . . . And the following calculations

must be performed . . .

NOx emission rate 

 (lb/mmBtu)

The fuel flow rate must be continuously

monitored, using an Appendix D fuel

flowmeter; and

Periodic fuel sampling, according to Appendix

D, is required to determine the GCV.

Use the measured fuel flow rates

and GCV to determine the hourly

unit heat input rate; and

Select from the correlation curve

the NOx emission rate that

corresponds to the measured

hourly heat input rate.

NOx mass emissions 

 (lb) 

The fuel flow rate must be continuously

monitored, using an Appendix D fuel

flowmeter; and

Periodic fuel sampling, according to Appendix

D, is required to determine the GCV; and 

 

The unit operating time must be monitored.

 

Use the measured fuel flow rates

and GCV to determine the hourly

unit heat input rate; and

Select from the correlation curve

the NOx emission rate that

corresponds to the measured

hourly heat input rate; and

Multiply together the measured

hourly heat input rate, the NOx

emission rate from the correlation

curve, and the unit operating time.
26

 See Section 4.6 of this guide.

27

 The NOx emission rate value is, of course, read automatically by the DAHS

28

 The unit operating time is defined as the fraction of the hour in which the unit operates. For example,

unit operating time = 1.00 for a full hour of operation, 0.50 for a half-hour of operation, etc.

29

 The equations needed to determine the heat input rates for each fuel, the total unit heat input, and the

unit level heat input rate are: Equations F-19 and F-20 in Appendix F of Part 75, Equation E-1 in Appendix E, and

Equation F-21c in Appendix F.

30

 Fuel usage time is the fraction of an hour that a fuel is combusted (e.g., fuel usage time = 1.00 if the

fuel is burned for the whole hour, 0.50 if it is burned for 30 minutes, etc.)

40

is determined by measuring the hourly heat input rate26 and reading the corresponding NOx value

from the Appendix E correlation curve27. To calculate the hourly NOx mass emissions, the unit

operating time28 must also be known.

If different fuels are co-fired in an Appendix E unit, there are two possible ways of

determining the hourly NOx emission rate:

C Calculate the heat input rate for each type of fuel combusted during the hour, using

the fuel flow rate and the GCV. Then, determine a NOx emission rate for each fuel

from its correlation curve and use Equation E-2 in Appendix E to calculate a Btuweighted hourly NOx

 emission rate for the unit; or

C If a consistent fuel mixture is always combusted in the unit (i.e., if the composition

of the mixture does not vary by more than ±10%), a single correlation curve for

the mixture may be derived, rather than developing separate curves for the

individual fuels. If a unit qualifies to use this option, the hourly heat input rate will

be a composite value29, derived from the individual fuel flow rates, the GCV

values, the fuel usage times30, and the unit operating time28.

5.4 What are the fuel sampling requirements of Appendix E ?

Appendix E requires the owner or operator of an affected unit to use the fuel sampling and

analysis procedures of Appendix D, to determine the GCV of each type of fuel combusted in the

unit. Therefore, the GCV sampling options and analytical methods described in section 4.4 of this

guide, apply to Appendix E units.

5.5 What are the on-going quality-assurance requirements of Appendix E ?

The on-going quality-assurance requirements for Appendix E units are as follows:
41

C Parameter Monitoring. Once the initial correlation curve has been developed,

Appendix E requires hourly monitoring of the parameters that were monitored

during the baseline emission testing (i.e., excess O2 for boilers and the four

parameters associated with NOx formation for turbines and diesel or dual-fuel

reciprocating engines). 

If, for any boiler operating hour, the excess O2 data is missing or invalid, or if the

excess O2 level is greater than 2% O2 higher than the value observed during the

baseline emission testing at the same heat input rate, then substitute NOx emission

rate data must be reported for that hour. Similarly, for turbines, diesel and dual

fuel reciprocating engines, for any hour in which some or all of the required

parametric data is missing, invalid or outside the acceptable ranges established

during the baseline emission testing, missing data substitution must be used for

NOx emission rate.

C Periodic Re-testing. Appendix E requires periodic re-testing of each affected unit

once every 5 years (20 calendar quarters), to determine new correlation curves. 

Unscheduled re-testing is also required if:

< For boilers, the excess O2 level at a particular heat input rate is more than

2% O2 greater than the value observed during the baseline emission testing,

for more than 16 consecutive unit operating hours; or

< For combustion turbines and for diesel or dual-fuel reciprocating engines,

some or all of the required parametric data is outside the acceptable ranges

established during the baseline emission testing for more than 16

consecutive unit operating hours.

C QA Plan. The owner or operator of an Appendix E unit is required to develop

and implement a quality-assurance (QA) plan for the unit. The contents of the plan

are specified in section 1.3.6 of Part 75, Appendix B and section 4 of Appendix E.

At a minimum, the QA plan must include:

< The data and results from the initial and most recent NOx emission rate

testing, including the parametric data;

< A written record of the procedures used to perform the NOx emission rate

testing;

< The quality-assurance parameters that are monitored and the acceptable

values and ranges of those parameters;
31

 The Appendix E methodology should continue to be used until the CEMS has been certified or until

the December 31st deadline, whichever occurs first. If the certification deadline is not met, the maximum potential

NOx emission rate must be reported for each unit operating hour until the CEMS is certified.

42

< Records of the monitored parametric data for each unit operating hour; and

< Because Appendix E requires an Appendix D fuel flowmeter to be used to

monitor the hourly unit heat input rate, the flowmeter must meet the ongoing QA requirements of Appendix D. Therefore, the the QA plan must

also include the elements described in Section 4.8 of this guide. 

5.6 What are the missing data procedures for an Appendix E unit ?

The owner or operator of an Appendix E unit is required to implement the missing data

procedures of both Appendix D (for fuel flow rate and GCV) and Appendix E (for NOx emission

rate). These procedures are discussed in detail in Section 9 of this guide.

5.7 What happens if an Appendix E unit loses its peaking unit status ?

If, at the end of any calendar year or ozone season, the capacity factor requirements in

Table 11, above, have not been met for an Appendix E unit, its peaking unit status is lost at that

point. When this happens, Part 75 requires a NOx-diluent monitoring system to be installed and

certified by December 31 of the calendar year following the year in which the peaking status is

lost. For example, if, at the end of 2004, the 3-year average annual capacity factor of an

Appendix E unit for 2002, 2003 and 2004 is determined to be 12.5%, then a NOx-diluent CEMS

must be installed and certified by December 31, 2005 31. 

A unit which has previously qualified as a peaking unit but loses that status may qualify

again as a peaking unit in a subsequent year or ozone season, but only if capacity factor data for a

three year period following the loss of peaking status show that the unit once again meets the

criteria in Table 11, above.
43

6.0 LOW MASS EMISSIONS METHODOLOGIES

6.1 Gas-Fired and Oil-Fired Units

Part 75 provides an alternative monitoring

methodology (§75.19) that may be used instead of 

CEMS, for gas- and oil-fired units that have very low

mass emissions. This low mass emissions, or “LME”

methodology does not require actual continuous

monitoring of emissions or unit heat input. Rather,

hourly SO2 , NOx and CO2 emissions are estimated

using fuel-specific default emission rates (“emission

factors”), and hourly heat input is either estimated from

records of fuel usage, or it is reported as the maximum

rated heat input for each unit operating hour. Once the

LME methodology has been selected, it must be used

for all program parameters. “Mixing-and-matching” LME with other Part 75 methodologies is not

allowed. Therefore, the LME methodology must be used for SO2 , NOx , CO2 and heat input if

the unit is in the Acid Rain Program, for SO2 and heat input if the unit is in the CAIR SO2 Trading

Program, and for NOx and heat input if the unit is in the NOx Budget Program or if it is in the

CAIR NOx Trading Program(s).

6.1.1 What is a low mass emissions (LME) unit ?

Low mass emission units are defined in Table 13.

Table 13. Low Mass Emissions Units

A combustion unit may qualify as a low mass emissions, or “LME” unit if it meets the definition of

a gas-fired or oil-fired unit in §72.2, and if its SO2 and/or NOx mass emissions meet the following

limits: . . . .

For Acid Rain and CAIR SO2 Trading

Program units: 

 

C #25 tons of SO2 per year

and

C < 100 tons of NOx per year

For NOx Budget Program and CAIR NOx Trading

Program units:

 

C #50 tons of NOx per ozone season

 and

C < 100 tons of NOx per year

a

 

 

a This limit applies only if the source is required to (or elects to) report NOx

 mass emissions on a year-round basis.

The low mass emissions (LME)

methodology in §75.19 provides an

alternative to CEMS for determining

SO2, NOx, and CO2 emissions and

unit heat input. To qualify to use

the LME methodology, a unit must

be gas-fired or oil-fired, and its SO2

and/or NOx mass emissions must

not exceed certain annual and/or

ozone season limits. 
32 The electronic portion is sent to the EPA Clean Air Markets Division. The hard copy portion goes to

the State and to the EPA Regional Office.

33 For assistance in preparing the electronic portion of the monitoring plan, see Table A-14 in Appendix

A of the EDR Instructions. A tutorial on CD-ROM is also available at the following web address: 

www.epa.gov/airmarkets/monitoring/mdc/index.html

34

 If emission testing will be performed to determine a default NOx emission rate, but at the time of the

application, the testing has not yet been completed, and if the generic default NOx emission rate from Table LM-2

is inappropriately high for the unit, then, for the purposes of initial LME qualification, a more reasonable (but still

conservatively high) default emission rate may be used in the calculations. For example, if the unit is not equipped

with SCR or SNCR, a default NOx emission rate based on the permit limit may be used, or, for units with SCR or

SNCR, a default NOx emission rate of 0.15 lb/mmBtu may be used. However, note that these emission estimates

may not be used for Part 75 reporting purposes. Rather, the generic NOx emission rates from Table LM-2 in

§75.19 or the maximum potential emission rate (MER) must be reported until NOx emission testing has been

completed. 

44

6.1.2 How does a unit qualify for LME status ?

To use the LME methodology for a particular gas-fired or oil-fired unit, a certification

application must be submitted to EPA and to the appropriate State or local agency, at least 45

days prior to the date on which the methodology will first be used. The essential elements of the

certification application, which has both electronic and hard copy portions32, are as follows:

C The application must include a complete monitoring plan for the unit33; and

C For sources that report emissions data on a year-round basis, the application must

demonstrate that in each of the three calendar years immediately preceding the

year of the application, the SO2 and/or NOx mass emissions from the unit did not

exceed the annual threshold limits shown in Table 13 above. And if the unit is in

the NOx Budget Program or in the CAIR Ozone Season Trading Program, it must

be demonstrated that in each of the previous three ozone seasons, the NOx mass

emissions did not exceed 50 tons. 

To make the required demonstration(s):

< Emissions data from historical Part 75 electronic data reports (EDRs) must

be used, where these reports are available, except as noted immediately

below; or

< In the absence of historical EDRs, reliable estimates of the unit’s emissions

for the previous 3 years (or ozone seasons) must be provided. These

estimates may be based on records of unit operation, fuel usage,

representative emission test data, CEM data, fuel sampling data, etc.

Conservative default values may also be used in the calculations (e.g., the

“generic” emission rates from Tables LM-1 through LM-3 in §75.19, the

unit’s maximum rated heat input, etc.)34; or 
45

< For units with less than 3 years (or ozone seasons) of operating history,

projected emissions estimates for one or more years may be used, to make

up the difference. Projections may also be used if emission controls have

been recently installed and the emissions data for one or more of the past 3

years or ozone seasons is not representative of present emission levels. All

projections should be based on the anticipated manner of unit operation,

the type(s) of fuel(s) that will be burned, and the expected emission rates;

or

< If a unit cannot qualify for LME status based on its historical emissions

and is not eligible to use projected emissions estimates, it is still possible to

use the LME methodology if an enforceable permit restriction is accepted,

limiting the number of unit operating hours per year (or ozone season), so

that the LME emission thresholds will not be exceeded; and

C The certification application must also specify the projected date on which the

LME methodology will first be used. Note that this projected date may not be

arbitrarily selected, because §75.19 requires the LME methodology to be used for

all unit operating hours in a calendar year or ozone season. Therefore, the only

acceptable start dates for using the LME methodology are these:

< For an existing unit that reports emissions data on a year-round basis, the

first unit operating hour in a calendar year.

< For an existing unit that reports on an ozone season-only basis, the first

unit operating hour in an ozone season.

< For new Acid Rain Program units, and for new units in the CAIR SO2 and

NOx Trading Programs, at the hour of commencement of commercial

operation (as defined in §72.2).

< For new units in the NOx Budget Program, at the first hour of unit

operation (“first-fire”); and 

C Finally, the certification application must describe the calculation methodology that

will be used to ensure that the unit maintains its LME status. That is:

< For each emissions parameter (i.e., SO2 , CO2 , and/or NOx), the

application must indicate whether the generic default emission rates in

Tables LM-1 through LM-3 will be used in the calculations, or whether

site-specific default values, determined by emission testing or other

acceptable means, will be used; and
35

 The emission rates are in lb/mmBtu for SO2 and NOx , and in ton/mmBtu for CO2.

46

< For heat input, the application must indicate whether the maximum rated

unit heat input will be reported for every operating hour or whether the

long-term fuel flow methodology, based on records of fuel usage, will be

used.

These calculation methods are discussed in greater detail in Section 6.3, below.

Once a complete certification application has been received by EPA and the State, the

LME methodology is assigned a provisionally certified status, pending the results of Agency

review. The regulatory agencies have a period of 120 days from the receipt of a complete

application to review the application and to issue a notice of approval or disapproval to the

source. If no such notice is provided by day 120, then the methodology is considered to be

“certified by default”. However, note that the LME methodology may not be used prior to the

start date indicated in the certification application, even if a notice of approval is issued or if the

methodology is certified by default prior to that date. 

6.1.3 How are emissions and heat input calculated for an LME unit ?

To calculate the hourly SO2 , NOx and CO2 mass emissions in lb (or tons)35, default

emission rates, expressed in units of lb/mmBtu (or ton/mmBtu)35, are used together with an

estimate of the unit heat input (mmBtu). 

Generic vs. Site-Specific Default Emission Rates

For the combustion of fuel oil and natural gas, the generic default emission rates in Tables

LM-1 and LM-3 must be used to estimate SO2 and CO2 emissions, unless a petition to use 

alternative emission rates has been approved under §75.66. However, for NOx, use of the generic

default emission rates in Table LM-2 is optional. In lieu of using these generic values, emission

testing may be performed to determine site-specific NOx emission rates. 

If the unit combusts a gaseous fuel other than natural gas, site-specific default emission

rates must be determined in the following way for all program parameters, since there are no

generic values in §75.19 for such fuels:

C For SO2, the sulfur content of the fuel is quantified by performing the 720-hour

demonstration described in Part 75, Appendix D, section 2.3.6, to determine

whether the unit is eligible to use a default SO2 emission rate for reporting

purposes. If the unit is not eligible, then the LME methodology may not be used.

But if the unit is eligible, the appropriate value of the fuel’s total sulfur content

(from the demonstration) is substituted into Equation D-1h in Appendix D, to

determine the default SO2 emission rate in units of lb/mmBtu.
36

 For ozone season-only reporters, the 2nd quarter includes only the months of May and June.

37

 For oil and natural gas, either use Appendix D fuel sampling procedures to determine the GCV or use

default GCV values from Table LM-5. For other gaseous fuels, the GCV must be measured at the frequency

prescribed by Appendix D.

38

 Unit operating time is the fraction of the hour that the unit combusts fuel, i.e., 1.00 if the unit opeartes

for the whole hour, 0.50 if it operates only for half of the hour, etc. When using the LME methodology, an

operating time of 1.00 may be used for partial unit operating hours.

47

C For NOx, fuel-and unit-specific emission testing is performed to determine the

default emission rate(s), in units of lb/mmBtu.

C For CO2, fuel sampling and analysis is performed to determine a carbon-based Ffactor for the gas. Then, Equation G-4 in Appendix G of Part 75 is solved for the

ratio of (WCO2/H), to obtain the CO2 emission factor in units of tons/mmBtu. 

Heat Input Methodologies

To determine the hourly heat input for an LME unit, there are two options:

C The maximum rated unit heat input may be reported for each unit operating hour;

or

C Long-term fuel flow may be used. The long-term fuel flow methodology requires

a reliable estimate of the amount of each type of fuel combusted in the unit during

each quarter36. Data from certified Appendix D fuel flowmeters or gas billing

records may be used to make these estimates. Alternatively, for fuel oil, one of

several acceptable API “tank drop” measurement methods may be used. The total

unit heat input for the quarter is calculated from the estimated quarterly fuel usage

and the fuel GCV37. The total heat input is then apportioned to the individual unit

operating hours, on the basis of unit load. 

Basic Equations

To determine the hourly SO2 , NOx, and CO2 mass emissions, an equation that has the

following basic structure is used:

Mass emissions = Default emission rate x Hourly heat input

 (lb or tons) (lb or tons/mmBtu) (mmBtu)

In the general equation above, the term “hourly heat input” either represents the product of the

maximum rated hourly unit heat input (mmBtu/hr) and the unit operating time38 (hr), or is an
39

 These reference methods are found in Appendices A-2, A-4 and A-7 of 40 CFR Part 60.

48

apportioned value from the long-term fuel flow methodology. 

The heat input apportionment equations for long-term fuel flow have the general form: 

Hourly heat input = Total quarterly heat input x Hourly unit load 

 (mmBtu) (mmBtu) Sum of all quarterly loads

In this general equation, the unit loads are expressed on a consistent basis, either in megawatts or

thousands of pounds (klb) of steam per hour. 

The quarterly SO2 , NOx, and CO2 mass emissions are calculated by summing the hourly

mass emissions and converting this sum to tons as necessary (i.e., for SO2 and NOx). The

cumulative annual (or ozone season) tons of SO2 , NOx, and CO2 are calculated by summing the

appropriate quarterly values. The cumulative SO2 and/or NOx values are then compared against

the LME emission threshold values in Table 13, above, to determine whether the unit has retained

its LME status.

6.1.4 How are site-specific default NOx emission rates determined for an LME unit ?

There are three basic sources of information that may be used to determine the sitespecific NOx

 emission rate(s) for a LME unit. These are:

C Emission testing;

C Historical CEMS data; and

C Previous Appendix E test results 

Emission Testing

As explained in Section 6.1.3 above, emission testing may (and for gaseous fuels other

than natural gas, must) be performed to establish fuel- and unit-specific default NOx emission rates

for a LME unit. Testing at four load levels is required (with some exceptions---see below), with

three runs at each load. The basic procedures described in Part 75, Appendix E, section 2.1 are

used for the testing, except that unit heat input is not measured during the test runs. Periodic retesting is required, once every five years (20 calendar quarters). 

EPA Reference Methods 7E and 3A are used to test boilers and Method 20 is used for

combustion turbines39, except that the NOx concentrations are not corrected to 15% O2. In

addition, for units equipped with add-on NOx emission controls (e.g., water injection, SCR, etc.)

and for combustion turbines that use lean premix (dry low-NOx ) technology to reduce NOx

emissions, appropriate parameters must be monitored and recorded during the test period, to

document that the emission controls are working properly. From this data, acceptable values
40

 This adjustment is described below, in section 6.1.5.

49

and/or ranges for each parameter are established and kept in a quality-assurance plan for the unit. 

For a group of “identical” LME units, a subset of the units may be tested, rather than

testing each unit individually. To be considered identical, all of the units in the group must:

C Be of the same size (maximum rated hourly heat input); and

C Have the same history of modifications (e.g., control device installations,

frequency of major maintenance outages, etc.); and

C Have stack or turbine outlet temperatures within ±50 B F of the average stack or

turbine outlet temperature for the group.

If the group of LME units qualifies as identical, Table LM-4 in §75.19 is used to determine how

many units need to be tested (e.g., if there are 3 to 6 units in the group, at least 2 units must be

tested).

In the following instances, the initial NOx emission rate testing (or periodic retesting) for

LME units may be done at fewer than four loads

C Testing may be done at a single load if the unit has operated at a single load level

for at least 85% of the operating hours in the past 3 years or ozone seasons; or

C Testing may be conducted at two or three load levels if those load levels

cumulatively represent at least 85% of the operating hours in the past 3 years or

ozone seasons; or

C For combustion turbines that operate principally at base-load (or at a set-point

temperature), but are capable of operating at a higher peak load level (or at a

higher internal operating temperature), testing may be done only at base-load,

provided that a suitable upward adjustment is made to the base-load NOx emission

rate when the unit operates at peak load40; or

C If the initial testing was performed at multiple load levels, the required retests may

be done at single load, i.e., at the load level for which the highest NOx emission

rate was obtained in the initial test.

Historical CEMS Data

If a unit has at least three years (or ozone seasons) of quality-assured historical NOx

emission rate data from a NOx-diluent CEMS, the CEMS data may be used to determine fuel- and

unit-specific default NOx emission rates. In order to do this, at least 168 hours of quality-assured

data are required for each fuel type, representing the full range of normal unit operating
41

 SCR and SNCR stand for selective catalytic reduction and selective non-catalytic reduction,

respectively, which are post-combustion NOx emission control technologies.

50

conditions.

Appendix E Test Results

For a peaking unit switching from the Appendix E methodology (see Section 5 of this

guide) to LME, the results of a previous four-load Appendix E NOx emission test may be used to

determine the site-specific default NOx emission rates, provided that the test results are less than 5

years old.

6.1.5 Which site-specific default NOx emission rates are used for reporting ?

Once the necessary emission test data or CEMS data for each type of fuel combusted in

the unit have been obtained, as described in Section 6.1.4, above, the site-specific default NOx

emission rate(s) that will be used for Part 75 reporting are determined as follows:

C If the NOx emission rate is based on emission test results:

< Report the highest NOx emission rate obtained at any tested load level

(average of three runs), except for units that use SCR or SNCR41, and as

otherwise noted below. 

< If the unit is an uncontrolled diffusion flame turbine, report the highest 3-

run average NOx emission rate obtained at any tested load, corrected to the

average annual ambient conditions of temperature, pressure and relative

humidity at the test site, using Equation LM-1a in §75.19.

< For units equipped with SCR or SNCR:

--- If the testing was done downstream of the SCR or SNCR, while these

emission controls were in operation, report the higher of:

C The highest 3-run average NOx emission rate obtained at

any tested load level; or 

C 0.15 lb/mmBtu

--- If the testing was performed upstream of the SNCR or SNCR (or with the

these controls out-of-service), and if the unit also uses water or steam

injection or dry low-NOx (DLN) technology to reduce NOx emissions, and

if the water injection, steam injection, or DLN technology was in-service

during the testing, report the highest 3-run average emission rate at any
51

tested load level as the default NOx emission rate.

< For a turbine that operates only at base load and peak load (or at two

distinct set-point temperatures), report the 3-run average NOx emission

rate from the base load testing when the unit operates at base load, and

report the 3-run average from the peak load testing when the unit operates

at peak load. If testing was done only at base load, use a NOx emission

rate of 1.15 times the base load emission rate during peak load operation. 

< For units that use add-on (post-combustion) NOx controls of any kind and

for units that use dry low-NOx technology, report the appropriate generic

default NOx emission rate from Table LM-2 (§75.19) instead of the sitespecific NOx

 emission rate, for any unit operating hour in which the

required parametric data (e.g., the water-to-fuel ratio) is unavailable or fails

to document that the emission controls are working properly.

< For a group of identical LME units, follow the same basic rules as for

single units, except that when it is appropriate to use the highest 3-run

average NOx emission rate, apply the highest 3-run average obtained at

any tested load, for any tested unit, to all of the units in the group.

C If the NOx emission rate is based on historical CEMS data:

< Use the 95th percentile value from each fuel-specific data set as the default

NOx emission rate, with one exception—for units equipped with SCR or

SNCR, if the 95th percentile value is less than 0.15 lb/mmBtu, use 0.15

lb/mmBtu as the default NOx emission rate.

6.1.6 What are the recordkeeping and reporting requirements for LME units ?

For a LME unit, the following essential records must be kept for three years, either on-site

or (for unmanned facilities) at a central location:

C Records indicating which hours the unit operated and, for each of these hours, the

unit operating time38;

C The type(s) of fuel(s) combusted during each operating hour;

C The unit load during each operating hour (megawatts or klb/hr of steam), if longterm fuel flow is used to quantify heat input;

C Calculated hourly SO2 , NOx and CO2 mass emissions (as applicable);

C The methods used to determine the hourly heat input values and the hourly NOx

emission rates;

C If the long-term fuel flow method is used , the quantity of each type of fuel

combusted in each quarter, the GCV of each type of fuel, and the total quarterly
42 Additional information on the LME module, in the form of a tutorial on CD-ROM, is available

without cost at the following web address: www.epa.gov/airmarkets/monitoring/mdc/index.html

52

heat input; and

C For units with add-on NOx emission controls or that use dry low-NOx technology,

records of the parametric data to verify proper operation of the emission controls

(i.e., to justify using the site-specific NOx emission rates).

All of the above information, except for the parametric data, must be reported quarterly to

EPA in a standardized electronic data reporting (EDR) format. However, note that a data

acquisition and handling system (DAHS) is not necessarily required to generate the quarterly EDR

reports for an LME unit. EPA’s Clean Air Markets Division has developed a special LME

module within its Monitoring Data Checking (MDC) software, which is capable of generating

quarterly EDRs for LME units42.

6.1.7 What are the on-going QA/QC requirements for LME units ?

On-going quality-assurance is required for LME units only if the long-term fuel flow option

is used for heat input and/or if site-specific emission rates are used to report emissions data. The

quality control and quality-assurance (QA/QC) provisions that must be implemented are as

follows:

C If site-specific NOx emission rates are used for reporting, these emission rates must

be re-determined every five years (20 calendar quarters);

C For gaseous fuels other than natural gas, annual sampling of the fuel’s total sulfur

content is required. The default SO2 emission rate currently in use must be

updated if the results of the annual sulfur sampling give an SO2 emission rate that

exceeds the current value. 

C If site-specific emission rates are used for reporting purposes, records must be kept

of all emission tests and/or data analyses used to determine the emission rates. 

These records are kept until the emission rates are re-determined; 

C If the unit is equipped with add-on NOx emission controls or dry low-NOx

technology, and if site-specific NOx emission rates are used for reporting purposes,

a quality-assurance plan must be developed and kept on-site, which explains the

procedures used to document proper operation of the emission controls. The plan

must clearly define all of the parameters monitored and the acceptable range(s) or

value(s) for each parameter;

C Fuel billing records must be kept for three years, if that option is used for longterm fuel flow;
43

 Therefore, the LME methodology may be used for one more year or ozone season after LME status has

been lost. 

44

 Fuel switching is generally planned well in advance. This provides sufficient time to install and certify

continuous monitoring systems.

53

C If the tank drop method is used to quantify long-term oil flow, records must be

kept for three years of all quarterly measurements, and a copy of the API method

used must be kept on-file; and

C If a certified Appendix D fuel flowmeter is used for long-term fuel flow, the QA

requirements in section 2.1.6 of Appendix D must be met (see Section 4.8 of this

guide).

6.1.8 What happens if a low mass emissions unit loses its LME status ?

If, at the end of a calendar year or ozone season, it is determined that the emissions from

an LME unit have exceeded the applicable threshold value(s) in Table 13, above, the unit’s LME

status is lost at that point. When this occurs, §75.19 requires Part 75-compliant continuous

monitoring systems to be installed and certified for all parameters by December 31 of the calendar

year following the year in which LME status is lost. For example, if an Acid Rain-affected LME

unit emits 125 tons of NOx in 2004, then Part 75 continuous monitoring systems must be installed

and certified by December 31, 2005 43. To meet the Part 75 monitoring requirement, CEMS, fuel

flowmeters, or the Appendix E methodology may be used, as appropriate. If the certification

deadline is not met, maximum potential values and conservative emission factors must be used for

reporting purposes until the certification tests are completed.

LME status can also be lost if a unit switches to a fuel other than oil or gas. In this case,

the unit loses its LME status as of the first hour that the new fuel is combusted, and Part 75-

compliant monitoring systems must be installed and certified prior to the fuel switch44. If the

monitoring requirement is not met on-time, maximum potential values must be reported until the

monitoring systems are certified.

6.2 Coal-Fired Units

The CAMR rule, which was published in the Federal Register on May 18, 2005, provides

the blueprint for a mercury cap and trade program that will affect all 50 states. The program is

scheduled to be implemented in 2009. The regulated units under CAMR are coal-fired EGUs that

serve a generator > 25 megawatts. The rule, which has been codified as Subpart HHHH of 40

CFR Part 60, requires Hg mass emissions to be monitored according to Part 75.

However, prior to 2005, Part 75 did not have any Hg monitoring provisions. Therefore, as
54

part of the May 18, 2005 rulemaking, a new Subpart I was added to Part 75. Subpart I (§§75.80

-84) provides the necessary Hg mass emissions monitoring guidelines for the trading program. 

The available Hg monitoring options are described in §75.81. For any affected unit in the

program, the owner or operator may install and certify an Hg CEMS or a sorbent trap monitoring

system to continuously monitor the Hg concentration. Both of these monitoring options require

the use of a stack flow monitor to convert the measured Hg concentrations to mass emission

rates. For sorbent trap systems and Hg CEMS that measure on a dry basis, a correction for the

stack gas moisture content is also required. 

For units with very low annual Hg mass emissions (#29 lb/yr), continuous monitoring of

the Hg concentration is not required. For these low mass emissions units, Subpart I provides an

alternative Hg monitoring methodology, which allows a conservatively high default Hg

concentration to be reported for each unit operating hour (see §§75.81(b) through (f)). The

default Hg concentration is based on the results of emission testing.

In order for a unit to qualify to use the low mass emissions methodology, the owner or

operator must perform Hg emission testing prior to January 1, 2009, to determine the Hg

concentration in the effluent gas stream. The testing consists of a minimum of three runs at the

normal unit operating load. If the unit is equipped with flue gas desulfurization or add-on Hg

emission controls, the controls must be operating normally during the testing.

Based on the results of the emission testing, the following equation is used to provide an

estimate of the annual Hg mass emissions from the unit:

E = 8760 K CHg Qmax

Where:

E = Estimated annual Hg mass emissions from the affected unit (ounces/year)

K = Units conversion constant, 9.978 x 10-10 oz-scm/:g-scf

8760 = Number of hours in a year

CHg = The highest Hg concentration (:g/scm) from any of the test runs or 0.50

:g/scm, whichever is greater

Qmax = Maximum potential flow rate, determined according to section 2.1.4.1 of

Part 75, Appendix A (scfh)

This equation gives a very conservative estimate of the annual Hg emissions. It assumes that the

unit operates year-round at its maximum potential flow rate. If the highest Hg concentration

measured in any of the test runs is less than 0.50 :g/scm, a default value of 0.50 :g/scm must be

used in the calculations. Note also that this methodology does not require a correction for the

stack gas moisture content.

If the estimate of the annual Hg mass emissions obtained from the equation above is 464
55

ounces per year or less (i.e., # 29 lb/yr), then the unit is eligible to use the low mass emissions

methodology, and continuous monitoring of the Hg concentration is not required. For each

qualifying low mass emissions unit, the owner or operator must submit the results of the Hg

emission testing to the Administrator and to the permitting authority, no later than 45 days after

the testing is completed. The calculations demonstrating that the unit emits 464 ounces (or less)

per year of Hg must also be provided, and the default Hg concentration that will be used for

reporting must be specified. The regulatory agencies will treat the submittal as a certification

application, and the methodology will be considered to be provisionally certified as of the date

and hour of completion of the Hg emission testing.

Following initial certification, the same default Hg concentration value that was used to

estimate the unit’s annual Hg mass emissions is reported for each unit operating hour. The

default Hg concentration value must also be updated periodically, based on the results of

additional required emission testing. Re-testing is required either semiannually or annually,

depending on the results obtained in the previous test. If the estimated annual Hg emissions from

the previous test are #144 ounces/year (9 lb/yr), the retest frequency is annual and the next test is

due in four “QA operating quarters” (see footnote 63, below). If the estimated annual emissions

exceed 9 lb/yr, the retest frequency is semiannual and the next test is due in two QA operating

quarters.

If the low mass emissions unit is equipped with a flue gas desulfurization system or add-on

Hg controls, the owner or operator must record the appropriate parametric data or SO2 emission

data for each unit operating hour, to document proper operation of the emission controls. For

any unit operating hour in which this documentation is unavailable, the maximum potential Hg

concentration must be reported.

The low mass emissions methodology may be used for reporting Hg mass emissions at

common and multiple stack configurations, if the following conditions are met.

C For a common stack, all units using the stack must be CAMR affected units and

each unit must be tested individually to demonstrate that it emits # 464 ounces of

Hg per year. If these conditions are met, the default Hg concentration used for

reporting at the common stack will either be the highest value obtained in any test

run for any of the units serving the common stack or 0.50 :g/scm, whichever is

greater.

C For units with multiple stack or duct configurations, Hg emission testing must be

performed separately on each stack or duct, and the sum of the estimated annual

Hg mass emissions from the stacks or ducts must not exceed 464 ounces of Hg per

year. For reporting purposes, the default Hg concentration used for each stack or

duct will either be the highest value obtained in any test run for that stack or 0.50

:g/scm, whichever is greater.
56

C For units with a main stack and bypass stack configuration, Hg emission testing is

performed only on the main stack. For reporting purposes, the default Hg

concentration used for the main stack will either be the highest value obtained in

any test run or 0.50 :g/scm, whichever is greater. Whenever the main stack is

bypassed, the maximum potential Hg concentration must be reported.

At the end of each calendar year, if the cumulative annual Hg mass emissions from a low

mass emissions unit have exceeded 464 ounces, the owner must install, certify, operate, and

maintain a Hg concentration monitoring system or a sorbent trap monitoring system within 180

days after the end of the calendar year in which the annual Hg mass emissions exceeded 464

ounces. For common stack and multiple stack configurations, installation and certification of a

Hg concentration or sorbent trap monitoring system on each stack (except for bypass stacks) is

likewise required within 180 days after the end of the calendar year, if:

C The annual Hg mass emissions at the common stack have exceeded 464 ounces

times the number of affected units using the common stack; or 

C The sum of the annual Hg mass emissions from all of the multiple stacks or ducts

has exceeded 464 ounces; or

C The sum of the annual Hg mass emissions from the main and bypass stacks has

exceeded 464 ounces.
57

7.0 PART 75 MONITORING SYSTEM 

CERTIFICATION PROCEDURES

7.1 How are Part 75 monitoring systems certified ?

Before any data from Part 75 monitoring systems can be reported as quality-assured, the

systems must pass a series of certification tests, to demonstrate that they are capable of providing

accurate emissions data. The overall monitoring system certification process consists of several

steps, as shown in Figure 3. The requirements of each certification step are discussed in detail,

below. Note that for low mass emissions (LME) units, the certification process is somewhat

different, and therefore is discussed separately in section 6 of this guide. 

7.2 Step 1—Submit an Initial Monitoring Plan

For each affected unit, an initial monitoring plan must be submitted at least 45 days prior to

the start of the certification testing of the monitoring systems. The monitoring plan identifies the

overall monitoring strategy for each unit. The plan must contain sufficient information about the

monitoring systems to demonstrate that all of the regulated emissions from the unit will be

measured and reported. The monitoring plan consists of two parts: 

C Electronic, which includes the following information, arranged in EPA’s standard

electronic data reporting (EDR) format:

< Unit information, such as the unit type, the maximum heat input capacity,

the operating range of the unit (in terms of megawatts or steam load), the

type(s) of fuel combusted, the type(s) of emission controls, etc;

< Unit-stack configuration information, indicating how the effluent gases

from the unit discharge to the atmosphere--- i.e., through a single stack or

multiple stacks, or through a common stack shared with other units;

< A description of the methodology used to monitor each pollutant or

parameter (e.g., CEMS, Appendix D, Appendix E, etc.).

< Monitoring system information, e.g., the pollutant or parameter monitored

by the system, the make, model and serial number of each analyzer, etc; 

< Mathematical formulas used to calculate emissions and heat input; and

< Analyzer span and range information;

C Hard copy, which includes supplemental information that is incompatible with

EDR format, such as:

< Schematic diagrams and blueprints;

< Data flow diagrams;
58

Submit Initial

Monitoring Plan 

The source submits the monitoring

plan to EPA and the State > 45 days

or more before certification testing

Submit Certification 

Test Notices

The source provides notice to EPA and

the State at least 21 days before testing

begins

The required tests are done and a

certification application is prepared for

submission to EPA and the State

Conduct Certification

Testing

The source submits the application within

45 days of completing testing. The

electronic portion goes to CAMD and hard

copy portion goes to the State and EPA

Region.

If the application is incomplete, the source

is notified and given reasonable time to

submit the missing information.

Submit Certification

Application

A notice of approval or disapproval is issued

within 120 days of receipt of the completed

application. In the absence of such notice,

the monitoring systems are considered to be

certified by default.

Receive Agency

Approval or

Disapproval

--------------------------

 

 

 

 

 

-------------------------

 

--------------------------

 . 

 

 

---------------------------

----------------------------

 

Figure 3: Monitoring System Certification Process 
45

 See the following web address— http://www.epa.gov/airmarkets/monitoring/arp/monplanemail.html

59

< Test protocols;

< Technical justifications; and

< Special documentation (e.g., fuel sampling data, vendor guarantees, etc.)

The electronic portion of the monitoring plan must be sent to the EPA Clean Air Markets

Division (CAMD)45, and the hard copy portion goes to the EPA Regional Office and to the State

Agency. CAMD uses its Monitoring Data Checking (MDC) software to evaluate the electronic

portion of the monitoring plan and sends feedback to the source, to the State, and to the EPA

Region. The State and EPA Regional Offices then review the hard copy piece of the monitoring

plan, together with the feedback from CAMD on the electronic portion. The reviewing agencies

communicate their findings to the source and help to resolve any issues or deficiencies identified

during the review process.

The monitoring plan is a “living”document, in that it must be continuously updated to

reflect changes to the monitoring systems over time. As technology advances, the monitors

originally described in the monitoring plan may be replaced, or the monitoring methodology may

be changed. Also, facility operations may change and necessitate the use of additional monitors

or alternative placement of existing monitors. Therefore, for any modification, replacement, or

other change to an approved monitoring system or monitoring methodology, the monitoring plan

must be updated. For example, replacing a gas analyzer requires a monitoring plan update,

because Part 75 requires the make, model and serial number of each analyzer to be reported. 

Note that Part 75 allows all of the monitoring plan information, including the hard copy

portion, to be stored electronically, provided that a paper copy can be furnished to an inspector or

auditor upon request.

7.3 Step 2—Submit Certification Test Notices

Certification test notices must be sent to CAMD, to the EPA Regional Office and to the

appropriate State or local air agency, at least 21 days prior to conducting the required certification

testing. There is one exception to this--- for the certification of Appendix D fuel flowmeters, the

notifications are not required.

7.4 Step 3—Conduct Certification Testing

The types of certification tests required for Part 75 monitoring systems are described

below: 

C 7-day calibration error test--- Evaluates the accuracy and stability of a gas or

flow monitor’s calibration over an extended period of unit operation.
60

C Linearity check—Determines whether the response of a gas monitor is linear

across its range

C System integrity check—For a mercury CEMS equipped with a converter, this

test verifies that the converter is working properly

C RATA--- Compare emissions data recorded by a CEMS to data collected

concurrently with an EPA emission test method.

C Bias test—Determines whether a monitoring system is biased low with respect to

the reference method, based on the RATA results. If a low bias is found, a bias

adjustment factor (BAF) must be calculated and applied to the subsequent hourly

emissions data. This test is required only for SO2, NOx, Hg, and flow monitoring

systems.

C Cycle time test—Determines whether a gas monitoring system is capable of

completing at least one cycle of sampling, analyzing and data recording every 15

minutes.

C Flowmeter Accuracy test—Demonstrates that a fuel flowmeter can accurately

measure the fuel flow rate over the normal operating range of the unit.

C Four-load NOx emission rate testing and heat input measurement–Provides

data for a correlation curve of NOx emission rate vs. heat input rate for an

Appendix E peaking unit.

C NOx emission rate testing at one or more unit loads—Determines fuel-and

unit-specific NOx emission factors for LME units (optional).

C DAHS verification—Ensures that all emissions calculations are being performed

correctly and that the missing data routines are being applied properly.

The specific certification tests required for each Part 75 monitoring system are shown in

Table 14. For the test procedures that must be followed, see the following sections of Part 75:

C For CEMS---Section 6 of Appendix A.

C For fuel flow meters---Section 2.1.5 of Appendix D.

C For Appendix E testing---Section 2.1 of Appendix E.

C For the data acquisition and handling system---§75.20(c)(9)
61

Table 14: Required Certification Tests for 

 Part 75 Monitoring Systems

To certify this type

of monitoring

system. . . . . .

 These tests must be 

 performed. . . . .

 With the following exceptions 

 and qualifications. . . .

SO2 or NOx

concentration

C 7-day calibration error test.

C Linearity check.

C RATA (ppm basis)

C Bias test.

C Cycle time test.

C DAHS verification.

C Peaking units and SO2 and NOx span

values < 50 ppm are exempted from the

7-day calibration error test 

C SO2 and NOx span values < 30 ppm are

exempted from linearity checks

C SO2 monitor is exempt from RATA if the

unit burns only “very low-sulfur fuel” or

combusts higher-sulfur fuel for < 480

hours per year 

NOx- diluent C 7-day calibration error test (each

analyzer).

C Linearity check (each analyzer).

C RATA (lb/mmBtu basis).

C Bias test.

C Cycle time test (each analyzer).

C DAHS verification.

C Peaking units and NOx span values < 50

ppm are exempted from the 7-day

calibration error test

 

C NOx span values < 30 ppm are exempted

from linearity checks

Stack gas flow rate C 7-day calibration error test.

C RATA (3-load)

C Bias test.

C DAHS verification.

C Peaking units are exempted from the 

7-day calibration error test

C Only single-load RATAs are required for

flow monitors on peaking units and

bypass stacks 

CO2 or O2 concentration C 7-day calibration error test.

C Linearity check.

C RATA

C Cycle time test.

C DAHS verification.

C Peaking units are exempted from the 

7-day calibration error test

Hg concentration 

CEMS

C 7-day calibration error test

C Linearity check

C 3-level system integrity check

C Cycle time test

C RATA

C Bias test

C DAHS verification

C The 7-day calibration error test may be

done with elemental Hg or a NISTtraceable source of oxidized Hg

C The linearity check must be done with

elemental Hg standards

C The system integrity check is only

required for CEMS with converters
46

 See the following web address: http://www.epa.gov/airmarkets/monitoring/arp/certemail.html

62

Table 14 (cont’d)

To certify this type

of monitoring

system. . . . . .

 These tests must be 

 performed. . . . .

 With the following exceptions 

 and qualifications. . . .

Sorbent trap monitoring

system

C RATA

C Bias test

C Appendix K quality-assurance

procedures

C DAHS verification

C No exceptions

Moisture system with

wet and dry O2

analyzers(s)

C 7-day calibration error test (each

analyzer).

C Linearity check (each analyzer).

C RATA (% H2O basis).

C Cycle time test (each analyzer).

C DAHS verification.

C Peaking units are exempted from the 

 7-day calibration error test

Continuous moisture

sensor

C RATA (% H2O basis)

C DAHS verification.

C No exceptions

Continuous moisture

system consisting of a

temperature sensor and

a DAHS with a “lookup

table”

C Demonstration that the DAHS

applies the correct moisture value

from the lookup table at 3

representative temperatures.

This option applies to saturated 

gas streams, only.

C No exceptions

Appendix D fuel

flowmeter system

C Flowmeter Accuracy test

C DAHS verification.

C Qualifying billing meters

Appendix E NOx system C NOx emission rate testing and

Appendix D heat input

measurement at 4 unit loads

C DAHS verification

C Emergency fuel (testing optional)

7.5 Step 4—Submit Certification Application

Within 45 days after completing the required certification testing, a certification

application must be submitted. There are two parts to the application---electronic and hard copy. 

C The electronic part of the application consists of a complete, updated monitoring

plan and the results of the certification tests, in EDR format. This part of the

application is sent to CAMD46. 
47

 For the Acid Rain Program, the notice is issued by EPA. For the NOx Budget Program, the notice is

issued by the State or local agency.

48

 Note that if the “conditional data validation” procedures in §75.20(b)(3) are used, the date of

provisional certification will be earlier than the date on which the certification tests are completed (see section 9.5

of this guide).

63

C The hard copy part of the application consists of an application form, the hard

copy certification test report, and any changes made to the hard copy portion of

the monitoring plan as a result of the testing. This part of the application is sent to

the EPA Regional Office and to the appropriate State or local agency.

If the certification application is incomplete or is missing any information, the reviewing agencies

will notify the source, and a reasonable amount of time will be given to submit the required

information. A 120-day review period begins when a complete certification application has been

received.

7.6 Step 5—Receive Agency Approval or Disapproval

The appropriate reviewing agency47 will issue a notice of approval or disapproval of the

certification application within 120 days of receiving the complete application. While the

application is pending, the monitoring systems are considered to be “provisionally certified”. This

means that data from the monitoring systems are considered to be quality-assured, beginning at

the date and hour of completion of the certification tests48, and continuing throughout the 120-day

review period, provided that: 

C The monitoring systems are operated in accordance with all applicable Part 75

requirements; and 

C A notice of disapproval of the application is not issued in the meantime. 

If the reviewing agency fails to provide notice of approval or disapproval of the

application by the end of the 120 day review period, then, provided that all required tests were

successfully completed, the monitoring systems are considered to be certified by default. During

any period that the monitoring systems are not provisionally or officially certified, the Part 75

missing data procedures must be used to estimate emissions (see Section 9 of this guide).

7.7 What reference test methods and standards are used for certification testing?

Various test methods, some of which have been developed by EPA and others by

reputable standards organizations such as ASME, are used to certify Part 75 monitoring systems. 

In addition, high-quality calibration gases are used in many of the certification tests. These test

methods and calibration standards are discussed below.
49

 “EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards” September,

1997, EPA-600/R-97/121.

64

Calibration Gases

The certification tests of Part 75 gas monitoring systems require the use of calibration

gases, either to calibrate the CEMS (e.g., for 7-day calibration error tests and linearity checks) or

to calibrate the reference method analyzers that are used for RATAs. The calibration gas

cylinders used for these tests are special gas mixtures that have been prepared using a standard

EPA protocol49. These protocol gas mixtures consist of known concentrations of the pollutant or

diluent gases of interest (e.g., SO2, NOx, CO2, etc.), in a non-reactive gas such as nitrogen. 

To be acceptable for use in Part 75 applications, a cylinder gas must meet the definition

of “calibration gas” in section 5 of Appendix A, and must be traceable to standard reference

materials prepared by the National Institute of Standards and Technology (NIST). The only

exception to this is purified instrument air, which may be used as a zero gas or as an upscale

calibration material for O2 analyzers.

EPA Reference Methods

Part 75 requires periodic relative accuracy test audits (RATAs) of all CEMS, both gas

and flow monitoring systems. The RATA compares data from the CEMS to measurements made

with an EPA test method (known as a “reference method”). Reference methods are also used for

Appendix E NOx emission testing and to determine fuel- and unit-specific NOx emission rates for

LME units. Except for the Ontario-Hydro method, which is an ASTM method, the EPA

reference test methods are found in Appendices A-1 through A-7 of 40 CFR Part 60. The

specific method(s) used for various Part 75 applications are summarized in Table 15.

Fuel Flowmeter Accuracy Standards

Part 75 sources using Appendix D methodology are required to continuously monitor the

fuel flow rate. With few exceptions, certified fuel flowmeters are used for this purpose. Fuel

flowmeters are certified using test methods or, in some cases, design specifications, that have been

published by consensus standards organizations such as ASME, AGA, and API. See section 4 of

this guide for further discussion. 
65

Table 15 : EPA Reference Test Methods

 Used in Part 75 Applications

This EPA Reference

Methoda.....

Or its Allowable

Alternativesb....

Is Used to ..... In these Part 75

Applications..... 

Method 1 Method 1A Locate traverse

points for flow

rate measurement

Flow monitor RATAs

Method 2 Methods 2F, 2G,

2H and CTM-041c

Measure stack gas

volumetric flow

rate 

Flow monitor RATAs

Method 3A Methods 3, 3B Measure diluent

gas (O2 or CO2) 

concentrations

RATAs of:

C NOx-diluent monitoring

systems 

C CO2 or O2 monitoring systems

C Flow monitors

d

Appendix E tests

LME unit tests

Method 4 Wet bulb-dry bulb

techniqued

Measure the

moisture content

of stack gas

RATAs of:

C Moisture monitoring systems

C Flow monitors

d

C Certain gas monitors

e

Method 6C Methods 6,6A,

6B

Measure SO2

concentration

SO2 monitor RATAs

Method 7E Methods 7, 7A,

7C, and 7D

Measure NOx

concentration

RATAs of NOx monitoring

systems

Appendix E tests

LME unit tests

Method 20

 ---------

Measure NOx and

diluent gas

concentrations 

(gas turbines,

only)

Appendix E tests

LME unit tests
66

Table 15 (cont’d)

This EPA Reference

Methoda.....

Or its Allowable

Alternativesb....

Is Used to ..... In these Part 75

Applications..... 

Ontario Hydro Method Instrumental RM

approved by the

Administratorf

Measure Hg

concentration

RATAs of Hg CEMS

and sorbent trap

monitoring systems

a. These reference methods are found in Appendices A-1 through A-7 in 40 CFR Part 60

b. Methods 3A, 6C and 7E are instrumental methods. Their allowable alternatives are wet-chemistry methods

and are seldom, if ever, used because the results of the RATA (and hence, the quality-assured status of the

CEM data) cannot be known until the laboratory analyses of the samples are completed.

c. Methods 2F and 2G correct the measured flow rates for angular (non-axial) flow. Method 2H (for circular

stacks) and conditional test method CTM-041 (for rectangular stacks and ducts) are used to correct the

measured flow rates for velocity decay near the stack wall, using a “wall effects adjustment factor” (WAF).

d. Molecular weight (MW) determinations are required in all flow RATAs. Measurements of diluent gas

concentration and stack gas moisture content are needed to calculate the MW. Use of the wet bulb-dry bulb

technique is restricted to these molecular weight determinations.

e. When the CEMS and reference method measure on a different moisture basis, moisture corrections are

required.

f. At the present time, EPA is developing an instrumental reference method for Hg

7.8 What performance specifications must be met for certification?

For a Part 75 CEMS, the performance specifications that must be met for initial

certification are found in section 3 of Appendix A. These specifications are summarized in Table

16. Table 16 shows that for certain tests, there is an alternative performance specification in

addition to the principal, or main specification. Generally speaking, the purpose of the alternative

specifications is to provide regulatory relief in cases where the main specification may be too

stringent. For example, for a source with low SO2 emissions, an SO2 monitor may have difficulty

meeting the principal relative accuracy standard of 10.0%, but might be able to meet the

alternative specification, which is a mean difference of 15 ppm or less between the CEMS and

reference method. 

For fuel flowmeters, the basic accuracy specification that must be met is 2.0% of the fullscale, or “upper range value” (URV) of the flowmeter. For flowmeters that are calibrated with a

flowing fluid (e.g., in a laboratory), this accuracy specification must be met at three points across

the normal measurement range of the instrument, i.e., covering the actual range of fuel flow rates

that the meter will be used to measure. For flowmeters that are certified by design (such as orifice

meters), the 2.0% of URV accuracy standard is considered to be met if the primary element

passes a visual inspection, and each of the pressure, temperature and differential pressure

transmitters is calibrated at 3 points or “levels” (low, mid and high) across its normal

measurement range, using NIST-traceable equipment, and if: 
67

C The accuracy of each transmitter is 1.0% of full-scale (or less) at each level; or

C If, at a particular level, the sum of the accuracies of the three transmitters is

4.0% or less. 

Table 16: Performance Specifications for Part 75

 Continuous Monitoring Systems

For this

certification

test.....

On this type of

monitor or

monitoring

system.....

The main performance

specificationa is.....

The alternate performance

specification is.....

And the conditions

of the alternate

specification

are.....

7-day

calibration

error test

SO2 or NOx ± 2.5% of span value, on

each of the 7 days

*R - A*# 5 ppm Span value 

 < 200 ppm

Flow ± 3.0% of span value, on

each of the 7 days

*R - A*# 0.01"H2O Applies only to DPtype flow monitors

CO2 or O2 *R - A* # 0.5% CO2 or O2,

on each of the 7 days

 ---------------- --------------

Hg CEMS ± 5.0% of span value, on

each of the 7 days

*R - A*# 1.0 :g/scm Span value equal to

10 :g/scm

Linearity

check

SO2 or NOx *R - Aavg*# 5.0% of the

reference gas tag value, at

each calibration gas level

*R - Aavg*# 5 ppm The alternate

specification may be

used at any gas level

CO2 or O2 *R - Aavg*# 5.0% of the

reference gas tag value, at

each calibration gas level

*R - Aavg*# 0.5% CO2 or O2 The alternate

specification may be

used at any gas level

Hg CEMS *R - Aavg* # 10.0% of the

reference gas tag value, at

each calibration gas level

*R - Aavg* #1.0 :g/scm The alternate

specification may be

used at any gas level
68

Table 16 (cont’d)

For this

certification

test.....

On this type of

monitor or

monitoring

system.....

The main performance

specificationa is.....

The alternate performance

specificationis.....

And the conditions

of the alternate

specification

are.....

Cycle time test All gas

monitoring

systems

15 minutes 

 ----------------------

 

 ---------------

System

integrity

check

Hg CEMS with

converters

*R - Aavg*# 5.0% of the

span value, at each

calibration gas level

 ----------------------- ----------------

RATA SO2 or NOx

concentration

10.0% RA *RMavg - Cavg *# 15.0 ppmb RMavg # 250 ppm

NOx -diluent 10.0% RA *RMavg - Cavg *# 0.020lb/mmBtu RMavg # 0.200

lb/mmBtu

Flow 10.0% RA *RMavg - Cavg *# 2.0 ft/sec vavg # 10.0 ft/sec

CO2 or O2 10.0% RA *RMavg - Cavg *# 1.0% CO2 or O2 -----------

Moisture 10.0% RA *RMavg - Cavg *# 1.5% H2O --------

Hg CEMS and

sorbent trap

monitoring

systems

20.0% RA *RMavg - Cavg *# 1.0 :g/scm RMavg # 5.0 :g/scm

Flowmeter

accuracy test

Fuel flowmeters 2.0% of full-scale, i.e., the

upper range value (URV)

T, P and )P transmitters are

accurate to 1.0% at each of three

levels, or have a combined

accuracy # 4.0% at any level 

Alternate

specification applies

only to orifice,

nozzle and venturi

meters

a Note that *R - A*is the absolute value of the difference between the reference gas (or signal) value and the

analyzer reading. *R - Aavg* is the absolute value of the difference between the reference gas concentration and

the average of the analyzer responses, at a particular gas level.

b Note that *RMavg - Cavg * is the absolute difference between the mean reference method value and the mean

CEMS value from the RATA. Thus, the arithmetic difference between RMavg and Cavg can be either + or -.
50

 Except for Hg CEMS. For an Hg monitor, the span value is determined by rounding the MPC upward

to the next highest multiple of 10 :g/scm. In other words, the MPC multiplication factor is always 1.00 and the

Hg span value is always a multiple of 10 :g/scm.

69

7.9 What is meant by the “span value”, and why is it important ?

The “span value” is an important concept in Part 75, for several reasons:

C It provides a basis for selecting the full-scale measurement range of a continuous

monitor;

C It is used to define the upscale calibration gases (or calibration signals) that are

used for daily calibrations, linearity checks, and system integrity checks of Hg

monitors;

C The principal performance specifications for daily calibration error checks of SO2,

NOx, Hg, and flow monitors are expressed as a percentage of the span value; and

C The performance specification for system integrity checks of Hg monitors is

expressed as a percentage of the span value. 

The span value is a reasonable estimate, or “educated guess” of how large an analyzer

scale (i.e., range) is needed to accurately record the emissions or flow rate data at a particular

monitored location. For each parameter monitored (e.g., SO2 , NOx, Hg, flow), Part 75 requires a

high span value and a corresponding full-scale measurement range to be defined in the monitoring

plan. For gases, the high span value is based on the maximum potential concentration, or MPC. 

For flow, the span value is based on the maximum potential flow rate, or MPF. 

These maximum potential values can be determined in a number of different ways. For

instance, depending on which gas is being monitored, the MPC may either be a “generic” default

value prescribed in Part 75, or it may be based on historical fuel sampling data, emission test

results, or historical CEM data. The MPF may either be estimated using Equation A-1a or A-1b in

Appendix A of Part 75, or may be derived from measurements of stack gas velocity at maximum

load.

Once the MPC or MPF has been determined, the high span value is set by multiplying the

MPC or MPF by a factor of 1.00 to 1.25, and rounding off the result appropriately50. Thus, the

span value may either be set equal to or slightly higher than the maximum potential value. After

determining the span value, the full-scale range of the monitor must be set. Part 75 requires the

range to be greater than or equal to the span value. However, note that when setting the range,

the guidelines in section 2.1 of Appendix A should be taken into account, to avoid setting it too

high. According to section 2.1, the range should (with certain exceptions, described below) be

selected to ensure that the majority of the data fall between 20% and 80% of full-scale. 

 

For many Part 75 units, the use of high span values and full-scale ranges derived from the
51

 For Hg monitors, a second range is needed only if the high range value is > 20 :g/scm and if the

expected emission levels with the emission controls in proper operation are < 20% of that value. For some units, an

SO2 scrubber produces a co-benefit of significantly reducing Hg emissions.

52

 Except for Hg CEMS. For an Hg monitor, the low span value is always set to 10 :g/scm.

70

maximum potential values is sufficient to ensure that data are accurately recorded. However, for

units with add-on SO2, NOx, or Hg emission controls, or for units that burn multiple fuels with

distinctly different SO2 or NOx emission rates, it may be necessary to define a second, low span

value and a low range. A low span and range will be required if the emission levels are expected

to be consistently below 20% of the high range51 when the add-on emission controls are operating

properly, or when the lowest-emitting fuel is burned.

If a second span and range are required, the low span value is set in a similar manner to

the high span value. The only difference is that the low span is based on the maximum expected

concentration (MEC), rather than the MPC. The MEC is the highest that the concentration of the

pollutant is expected to be when the add-on controls are in normal operation or when the lowestemitting fuel is combusted. There are a number of ways to determine the MEC. For units with

add-on emission controls, it may be based on the expected efficiency of the controls. Emission test

data, historical CEM data, or an emission limit in the operating permit may also be used to

determine the MEC. Once the MEC has been established, the low span value is calculated by

multiplying the MEC by a factor of 1.00 to 1.25 and rounding off the result appropriately52. 

Then, the low range is set greater than or equal to the low span value. 

Note that for units with dual SO2 or NOx spans, Part 75 allows a “default high range

value” to be reported when the emissions go off the low scale, as an alternative to maintaining and

calibrating a high monitor range. But the default high range value is a very high number (200% of

the MPC) and grossly overstates the emissions. Therefore, this option is probably not a good one

except for sources whose emissions rarely, if ever, exceed the full-scale of the low range. Note

also that for dual-span units there are exceptions to the “20-to-80% of range” guideline in section

2.1 of Appendix A. For instance, provided that the low span and range have been set according

to the rule, the low range is exempted from this guideline. And if the add-on emission controls

are operated year-round, the high range is similarly exempted. 

An unusual feature of Part 75 is that for flow monitors, there is only one measurement

range, but there are two span values— the “calibration span value” and the “flow rate span

value”. These two span values are both derived from the MPF and are actually equivalent, but

almost invariably they are expressed in different units of measure. The calibration span value is

the one used for daily calibrations of the flow monitor. Often it is expressed in units such as

inches of water (in. H2O) or thousands of standard cubic feet per minute (kscfm), depending on

the type of flow monitor. The flow rate span value is always in units of standard cubic feet per

hour (scfh), which are the units of measure prescribed by Part 75 for reporting hourly stack gas

flow rates. 
71

Once the span values for all of the required continuous monitors have been established,

these values are used for daily calibration assessments, Hg monitor system integrity checks, and 

linearity checks, as follows: 

C For the daily calibrations of gas monitors, zero and upscale gases are used. The

zero gas must be 0 to 20% of the span value, and the upscale gas may be either a

mid level gas (defined as 50 to 60% of the span value) or a high level gas (80

to100% of the span value).

 

C For the daily calibrations of flow monitors, a zero calibration signal (0 to 20% of

the calibration span value) and an upscale calibration signal (50 to 70% of the

calibration span value) are used. 

C For weekly system integrity checks of Hg CEMS, a mid-level or high-level

calibration standard, with a concentration of 50 to 60% or 80 to 100% of the

span value, is required.

C For linearity checks of gas monitors and 3-level system integrity checks of Hg

CEMS, calibration is required at three different gas levels (low, mid, and high),

using calibration standards with concentrations of 20 to 30%, 50 to 60%, and 80

to 100% of the span value, respectively. 

C The principal performance specification for certain daily calibration error tests

are expressed as a percentage of the span value. For an SO2 , NOx , or Hg

monitor, the performance specification is + 5.0% of the span value, and for a flow

monitor, it is + 6.0% of the calibration span value; and

C The performance specification for single- and 3-level system integrity checks of

Hg monitors is 5.0% of the span value.

Finally, Part 75 requires periodic evaluations (at least once a year) of the MPC, MEC,

span and range values. These evaluations are done by reviewing the emissions and flow rate data

from the previous four quarters. If any of the MPC, MEC, span and/or range values are found to

be improperly set, the necessary adjustments must be made within 45 days (or within 90 days if

new calibration gases must be ordered) after the end of the quarter in which this is discovered.
53

 The Policy Manual is located at: http://www.epa.gov/airmarkets/monitoring/polman/index.html

72

7.10 Recertification and Diagnostic Testing

Whenever a replacement, modification, or other change is made to a monitoring

system that may affect the ability of the system to accurately measure emissions, the system must

be recertified. Also, changes to the flue gas handling system or manner of unit operation that

affect the flow profile or the concentration profile in the stack may trigger recertification. 

Examples of situations that require recertification of Part 75 monitoring systems include:

C Replacement of an analyzer.

C Replacement of an entire CEMS.

C Change in location or orientation of a sampling probe

C Fuel flow meter replacement.

C Exceedance of Part 75 Appendix E operating parameters for more than 16

consecutive operating hours

The requirements for recertification are basically the same as those shown in Figure 3,

above, for initial certification. A recertification application must be submitted within 45 days of

completing the required tests and a 120-day period is allotted for the regulatory agencies to

review the application. However, note that for recertifications, an initial monitoring plan

submittal is not required, and the test notification requirements are slightly different from those

for initial certification. 

 Not all changes made to a certified monitoring system require recertification. In many

cases, only diagnostic testing is required to ensure that the system continues to provide accurate

data. Note also that in some instances EPA requires less than a full battery of tests for

recertification. For a more thorough discussion of recertification and diagnostic testing, see

§75.20(b) and Questions 13.21 and 16.14 through 16.16 in EPA’s “Part 75 Emissions Monitoring

Policy Manual”53.
73

8.0 QUALITY ASSURANCE and QUALITY

CONTROL (QA/QC) PROCEDURES

8.1 Does Part 75 require periodic quality QA/QC testing after a monitoring system is

certified ? If so, where are these test requirements found ? 

 Following initial certification, all Part 75 monitoring systems are required to undergo

periodic quality-assurance testing, to ensure that they continue to provide accurate data. 

C For CEMS, the QA test requirements are found in either:

< Appendix B of Part 75 and §75.21, for sources that report emissions data

year-round; or

< Section 75.74(c), for NOx Budget Program or CAIR Ozone Season

Trading Program sources that report emissions data only during the ozone

season, from May 1st through September 30th;

C For sorbent trap monitoring systems, the QA requirements are found in

Appendices B and K of Part 75; 

C For Appendix D fuel flowmeter systems, the on-going QA test requirements are in

section 2.1.6 of Appendix D; and 

C For Appendix E NOx correlation curve systems, the QA requirements are found in

sections 2.2 and 2.3 of Appendix E.

8.2 What are the on-going QA test requirements in Part 75 for units reporting emissions

data year-round?

 Year-round reporting of emissions data is required for all Acid Rain Program units, all

CAIR SO2 Trading Program units, and for certain NOx Budget Program and CAIR NOx Trading

Program units (see Section 8.5, below). For CEMS, the on-going QA test requirements for yearround reporters are summarized in Table 17. Table 17 shows that routine QA testing of CEMS is

required at four basic frequencies:

C Daily;

C Weekly;

C Quarterly; and

C Semiannual or Annual.

Calibration error checks of all monitors and interference checks of flow monitors are

required daily. For Hg CEMS with converters, system integrity checks are required weekly. Gas

monitor linearity checks, flow-to-load ratio tests, and leak checks (for DP-type flow monitors) are

required quarterly. RATAs are required either semiannually or annually, depending on the type of
74

monitor and/or the results of the tests (see Section 8.6, below). 

For Appendix D fuel flowmeters, the basic frequency for the required accuracy tests is

annual. For Appendix E systems, NOx emission testing is required once every five years, in order

to develop new correlation curves. 

Table 18 summarizes the on-going QA requirements for sorbent trap monitoring systems. 

Table 17: On-Going QA Test Requirements

 for Year-Round Reporters

Perform this type

of QA test....

On these continuous

monitoring systems....

At this

frequency....

With these qualifications and

exceptions....

Calibration error test Gas and flow monitors Daily C Calibrations are not required when the

unit is not in operation. 

Interference check Flow monitors Daily C Check is not required when the unit is

not in operation. 

System integrity check

 (single-level)

Hg CEMS with converters WeeklyaC Not required if daily calibrations are

done with a NIST-traceable source of

oxidized Hg

Linearity check Gas monitors Quarterly C Required only in “QA operating

quarters”b and only on the range(s)

used during the quarter---but no less

than once a year

C 168 operating hour grace period

available

C Not required if SO2 or NOx span is 

< 30 ppm

C For Hg monitors, you may perform a 

3-level system integrity check using

oxidized Hg standards, in lieu of this

test

System integrity check

 (3-level)

Hg CEMS with converters Quarterly C For Hg monitors, you may perform a 

linearity check using elemental Hg

standards, in lieu of this test

Flow-to-load ratio or

gross heat rate test

Flow monitors Quarterly C Required only in “QA operating

quarters”

C Non load-based units are exempted

C Complex configurations may be

exempted by petition under §75.66

Leak check Differential pressure-type

flow monitors

Quarterly C Required only in QA operating

quarters

C 168 operating hour grace period

available
75

Table 17 (cont’d)

Perform this type

of QA test....

On these continuous

monitoring systems....

At this

frequency....

With these qualifications and

exceptions....

RATA 

and 

Bias test

Gas and flow monitors

(Bias test applies to SO2, NOx, 

Hg, and flow monitoring

systems, only)

Semiannual or

Annualc

C Not required for SO2 monitors if the

unit exclusively burns very low sulfur

fuel, or burns higher-sulfur fuel for 

< 480 hours per year

C 720 operating hour grace period

available

C For Hg monitoring systems, the RATA

frequency is always annual

Flowmeter Accuracy test Fuel flowmeter systems

 

Once every four

“fuel flowmeter

QA operating

quarters”d

C The optional “fuel flow-to-load ratio” or

“gross heat rate” test in Appendix D,

section 2.1.7 may be used to extend the

interval between flowmeter accuracy

tests to up to 20 quarters

Primary element visual

inspection

Orifice, nozzle, and venturitype fuel flowmeters that are

certified by design

Once every 3

years 

(12 calendar

quarters)

C The optional fuel flow-to-load ratio or

gross heat rate test may be used to

extend the interval between visual

inspections to up to 20 quarters

NOx emission rate

testing

Appendix E systems Once every 5

years 

(20 calendar

quarters)

 

 -----------

a

“Weekly” means once every 168 unit operating hours 

b That is, a quarter with at least 168 hours of unit operation

c Depending on the % relative accuracy obtained in the previous test, the next RATA is required either

“semiannually” (within 2 QA operating quarters) or “annually” (within 4 QA operating quarters), not to exceed

8 calendar quarters between successive tests.

d 

That is, a quarter in which the fuel measured by the flowmeter is combusted for at least 168 hours.
76

Table 18. Quality Assurance/Quality Control Criteria 

 for Sorbent Trap Monitoring Systems

QA/QC Test or 

Specification Acceptance Criteria Frequency

 Consequences

 if Not Met

Pre-test leak check #4% of target sampling rate Prior to

sampling

Sampling shall not commence

until the leak check is passed

Post-test leak check #4% of average sampling rate After sampling Sample 

invalidateda

Ratio of stack gas flow

rate to sample flow

rate

Maintain within ± 25% of

initial ratio from first hour of

data collection period

Every hour

throughout data

collection period

Case-by-case evaluation

Sorbent trap section 2

breakthrough

#5% of Section 1 Hg mass Every sample Sample

invalidateda

Paired sorbent trap

agreement

#10% Relative Deviation

(RD) 

Every sample Sample

invalidateda

Spike recovery study Average recovery between

85% and 115% for each of the

3 spike concentration levels

Prior to

analyzing field

samples and

prior to use of

new sorbent

media

Field samples shall not be

analyzed until the percent

recovery criteria has been met

Multipoint

analyzer calibration

Each analyzer reading within 

± 10% of true value and

r

2

$0.99

On the day of

analysis, before

analyzing any

samples

Recalibrate until successful

Analysis of

independent

calibration standard

Within ± 10% of true value Following daily

calibration, prior

to analyzing

field samples

Recalibrate and repeat

independent standard analysis

until successful

Spike recovery from 

section 3 of sorbent

trap

75-125% of spike amount Every sample Sample

invalidateda

RATA RA #20.0% 

 or 

Mean difference # 1.0

:g/dscm for low emitters

For initial

certification and

annually

thereafter

Data from the system are

invalidated until a RATA is

passed

Dry gas meter

calibration 

(At 3 orifice settings

initially, and 1 setting

thereafter)

Calibration factor (Y) within 

± 5% of average value from

the initial (3-point)

calibration

Prior to initial

use and at least

quarterly

thereafter

Recalibrate the meter at three

orifice settings to determine a

new value of Y

Temperature sensor

calibration

Absolute temperature

measured by sensor within 

± 1.5% of a reference sensor

Prior to initial

use and at least

quarterly

thereafter

Recalibrate. Sensor may not be

used until specification is met.
77

Table 18 (cont’d)

QA/QC Test or 

Specification Acceptance Criteria Frequency

 Consequences

 if Not Met

Barometer calibration Absolute pressure measured

by instrument within ± 10

mm Hg of reading with a

mercury barometer

Prior to initial

use and at least

quarterly

thereafter

Recalibrate. Instrument may not

be used until specification is met

a

 And data from the pair of sorbent traps are also invalidated

8.3 Are there any exceptions to these basic QA test requirements ?

Yes. Table 17 indicates that there are some exceptions to the basic QA test requirements 

and frequencies for year-round reporters. For instance:

C Linearity checks are not required for SO2 or NOx monitors with span values of 30

ppm or less;

C For calendar quarters in which the unit operates for less than 168 hours, limited

exemptions from linearity checks and limited extensions of RATA deadlines are

available;

C RATAs of SO2 monitors are not required if the unit exclusively combusts “very

low sulfur fuel” (as defined in §72.2) or limits combustion of higher-sulfur fuel to#

480 hours per year;

C For calendar quarters in which a particular fuel is combusted for less than 168

hours, limited extensions of fuel flowmeter accuracy test deadlines are available to

Appendix D units; and

C For calendar quarters in which the optional fuel flow-to-load ratio test is

performed and passed, limited extensions of fuel flowmeter accuracy test deadlines

are available to Appendix D units.

The low-span linearity check exemption described in the first bulleted item above and the

SO2 RATA exemption described in the third bulleted item are permanent exemptions, as long as

the conditions continue to be met. However, the test extensions and exemptions described in the

second, fourth and fifth bulleted items above are conditional and have definite limits, i.e., no more

than 3 consecutive linearity check exemptions may be claimed, a RATA deadline may not be

extended beyond 8 calendar quarters from the quarter of the last test, and the accuracy test

deadline for a fuel flowmeter may not be extended beyond 5 years (20 quarters) from the quarter

of the previous test.

EPA also recognizes that circumstances beyond the control of the source owner or

operator, such as a forced unit outage, may prevent a linearity check or RATA from being done in

the calendar quarter in which it is due. To provide regulatory relief in these instances, Part 75
54

 For new units, projections of the anticipated manner of unit operation may be used to define the

normal load level, and then any necessary adjustments can be made based on the actual unit operation

55

 The advantage of designating two normal loads is that gas monitor RATAs may be done at either load

level. The “down side” is that for flow RATAs, a bias test must be taken at both normal load levels, which

increases the chances that a bias adjustment factor (BAF) will have to be applied to the flow rate data.

78

allows the test to be done in a grace period, immediately following the end of that quarter. For a

linearity check, the grace period is 168 unit operating hours, and for a RATA it is 720 unit

operating hours. Provided that the missed QA test is performed and passed on the first attempt

within the grace period, no loss of emissions data will be incurred by the affected source.

8.4 Are there any special considerations when performing these basic QA tests ?

Yes, there are a number of things must be taken into consideration when performing the

QA tests, to ensure that they are done properly:

C Daily calibration error tests, interference checks, and linearity checks must be done

while the unit is on-line (i.e., combusting fuel). The only exception to this is that

off-line calibration error tests may be used to validate up to 26 consecutive hours

of emissions data, if the off-line calibration error demonstration described in

section 2.1.5 of Appendix B has been performed and passed.

C All RATAs of gas monitors must be done at normal load, while combusting a fuel

that is normal for the unit. For the RATA of an Hg monitoring system, the unit

must be burning coal. Normal load is defined in the monitoring plan as the most

frequently-used load level (low, mid, or high). To determine the normal load:

< First, the unit’s range of operation is defined. It extends from the

“minimum safe, stable load” to the “maximum sustainable load”

. 

< Second, the operating range is divided into three load bands, or levels. The

first 30% of the range is defined as low load, the next 30% is mid load, and

the remainder of the range is high load. 

< Third, at least four quarters of representative historical load data are

analyzed54, to determine which load levels are used the most frequently. 

The load level used most frequently must be designated as the normal load.

The load level that is used second most frequently may be designated as a

second normal load level55. 

C For flow monitors installed on peaking units and bypass stacks, only single-load

RATAs are required.
56

 See section 8.6 of this guide.

57

 If it can be demonstrated to the satisfaction of the permitting authority that the process operates only at

one or two distinct points, the requirement to perform 3-level, or perhaps even 2-level flow RATAs may be waived.

79

C For all other flow monitors:

< The annual RATAs must be done at the 2 most frequently-used load levels

or (at the source’s discretion) at all 3 loads, unless

< The unit has operated at one load level (low, mid or high) for > 85% of the

time since the last annual flow RATA, in which case a single-load test at

normal load may be performed. 

< A 3-load RATA is required at least once every 5 calendar years

C If a semiannual RATA frequency56 is obtained, an additional RATA must be done

in-between the annual RATAs. For a flow monitor, this “extra” RATA may be a

single-load test at normal load.

C For units that do not produce electrical or steam load, such as cement kilns, and

refinery process heaters, the RATA requirements are basically the same as for

load-based units, except that the terms “level” and “operating level” apply instead

of the terms “load” and “load level”. Also, it is possible, with a proper justification

in the monitoring plan

57, for a non load-based unit to be partly or fully exempted

from performing multi-level flow RATAs.

C The quarterly “flow-to-load ratio test” is not actually a test at all. Rather it is a

data analysis, which, in most cases, is performed automatically by the DAHS. The

purpose of the test is to ensure that flow monitors continue to provide accurate

data in-between RATAs. The “test” is performed as follows: 

< The hourly ratio of the stack gas flow rate to unit load is calculated for a

segment of the quarterly flow rate data (i.e., those hours where the load

was within 10% of the average load during the last normal load flow

RATA). 

< These hourly ratios are then compared against a “reference” flow-to-load

ratio, which is the ratio of the average reference method flow rate to the

average unit load from the last normal-load RATA.

< Alternatively, the data analysis may be done on the basis of the “gross heat
58

 The gross heat rate approach includes the diluent gas (CO2 or O2) concentration in the equation. This

alternative is most useful for common stack configurations.

80

rate”58 (GHR), which is the ratio of heat input rate to unit load), rather than

using the flow-to-load ratio.

8.5 What are the on-going QA test requirements for ozone season-only reporters ?

If a unit is in the NOx Budget Trading Program but is not an Acid Rain Program unit,

emissions data may be reported on an ozone season-only basis rather than year-round, if this is

allowed by the State regulation. Ozone season-only reporting is also allowed for units that are in

the CAIR Ozone Season Trading Program and are not otherwise required to report year-round. If

ozone season-only reporting is permitted and this option is selected, the quality assurance

procedures under §75.74 (c) in Subpart H of Part 75 must be met. These procedures require

some pre-ozone season quality assurance testing between October 1 and April 30, and other QA

testing inside the ozone season (May 1st through September 30th). 

The QA test requirements for ozone season-only reporting are considerably different from,

and quite a bit more complex than, the requirements for year-round reporters. For example:

C The required pre-season linearity check of a gas monitor may be done in April (2nd

quarter). However, if the unit operates for > 168 hours in May and June, an

additional 2nd quarter linearity check is required;

C The “window” of data validation for a RATA extends only for 2 calendar quarters

(for semiannual frequency) or 4 calendar quarters (for annual frequency). The

“QA operating quarter” concept (see Table 17) may not be used to extend RATA

deadlines;

C Daily calibrations must be performed from the date and hour of any pre-ozone

season linearity check or RATA , through April 30th;

C If a RATA was performed inside the ozone season, the test may be used to

validate data in the next ozone season, but only if these conditions are met:

< The data validation window from the RATA extends into the next ozone

season; and 

< The monitoring system is maintained and operated, and daily calibrations

are performed, throughout the entire pre-ozone season period from

October 1st of the current year through April 30th of the next year
59

 Except for RATAs of Hg CEMS and sorbent trap monitoring systems, which are only required

annually

81

 These are but a few of the QA provisions in §75.74(c). For a complete listing, see Table

III-A in Appendix III of this guide. In view of this, sources that qualify to use the ozone seasononly reporting option should carefully weigh the perceived benefits of this option, such as reduced

reporting requirements and less required maintenance of CEMS during the off-season, against the

potential invalidation of emissions data (and consequent loss of NOx allowances) that could result

from a misunderstanding or misapplication of the rule requirements. 

8.6 What performance specifications must be met for the routine QA tests required by

Part 75 ?

The performance specifications for the routine Part 75 QA tests are basically the same as

for initial certification (see Table 16 in Section 7 of this guide). There are, however, a few

notable exceptions:

C For daily calibration error tests of SO2, NOx, CO2, O2, and flow monitors, the

calibration error (C.E.) specifications are twice as wide as the C.E.’s allowed in the

7-day calibration error test for initial certification. For example, when an SO2

monitor is certified, the maximum allowable C.E. during the 7-day calibration error

test is ± 2.5% of the span value, but the “control limits” for daily operation of the

monitor are ± 5.0% of span.

C For SO2 and NOx monitors with span values of 50 ppm or less (which are

exempted from the 7-day calibration error test), the control limits for daily

calibration error tests are either ± 5.0% of span or *R - A* #5 ppm.

C For RATAs, there is an incentive system that rewards good monitor performance. 

RATAs may be performed annually rather than semiannually if a certain level of

relative accuracy is achieved59. The relative accuracy test frequency incentive

system is summarized in Table 19. Table 19 shows that when the percent relative

accuracy is 7.5% or less, the test frequency is annual. But even if 7.5% RA is not

achieved, the monitoring system may still be eligible for an annual RATA

frequency, if an alternative relative accuracy specification is met. The alternative

specifications are also shown in Table 19, and they apply to: 

C

< Low emitters of SO2 and NOx ; 

< Sources with very low stack gas velocities; and 

< Moisture, CO2 , and O2 monitoring systems. 

 In each case, the alternative RA specification is the difference between the mean

values of the reference method and CEMS measurements from the RATA.
82

Table 19: Relative Accuracy Test Frequency 

Incentive System

For a RATA of this

type of monitoring

system....

The test frequency is

annual, rather than

semiannual, if the 

% RA is....

However, if the 

following conditions

are met.....

Then annual

frequency may be

attained by meeting

this alternative RA

specificationa..... 

SO2 or NOx concentration # 7.5% (RM)avg # 250 ppmb ± 12.0 ppm

NOx -diluent # 7.5% (RM)avg # 0.200 lb/mmBtu ± 0.015 lb/mmBtu

Flow # 7.5% (RM)avg # 10.0 ft/sec ± 1.5 ft/sec

CO2 or O2 # 7.5% -------------- ± 0.7% CO2 or O2

Moisture # 7.5% --------------- ± 1.0% H2O

a

 The alternative RA specification is the difference between the mean CEMS and reference method values from

the RATA, i.e., [(CEMS)avg - (RM)avg ]

b (RM)avg is the mean value of the reference method measurements from the RATA

C For the flow-to-load ratio (or gross heat rate) test, which is not required for initial

certification, the pass/fail criterion is the absolute average percent deviation of the

hourly flow-to-load ratios (or hourly heat rates) from the reference ratio (or

reference heat rate). Table 20, below, summarizes the acceptance criteria.

Table 20: Flow-to-Load Ratio or Gross Heat Rate

Test Acceptance Criteria

For this QA test.....

If the unit load (or combined

load for a common stack) during

the last normal-load flow RATA

was.....

Then, to pass the test, the absolute

average percent deviation from the

reference ratio or heat rate must be.....

Flow-to-load ratio

 or

Gross heat rate

$60 MW or $500 klb/hr of steam #15.0% if

unadjusted flow rates

are used in the

calculations

#10.0% if biasadjusted flow rates

are used in the

calculations

Flow-to-load ratio

 or

Gross heat rate

< 60 MW or < 500 klb/hr of steam #20.0% if

unadjusted flow rates

are used in the

calculations

#15.0% if biasadjusted flow rates

are used in the

calculations
60

 Electronic storage of the QA plan information is allowed by the rule, provided that the information can

be made available in hard copy upon request during an inspection or audit.

83

8.7 Are there any notification requirements for the periodic QA tests ?

Yes. Part 75 requires sources to provide notice to CAMD, to the EPA Regional Office,

and to the State, at least 21 days in advance of the following QA tests:

C RATAs

C Appendix E retests

C LME unit retests

Part 75 also allows any of the regulatory agencies to issue a waiver from these notification

requirements. CAMD has waived these notification requirements. Therefore, sources are

currently required to notify only the State and EPA Region, unless those agencies issue a similar

waiver.

 

8.8 What are the Essential Elements of a Part 75 QA/QC Program ?

Part 75 requires all owners and operators of affected units to develop and implement a

quality assurance/quality control (QA/QC) program for the continuous monitoring systems. Each

QA/QC program must include a written plan60 that describes in detail the step-by-step procedures

and operations for a number of important activities. This quality assurance plan must be made

available to the regulatory agencies upon request during field audits. The following are the

essential elements that must be included in a QA plan: 

C For all monitoring systems:

< The routine maintenance procedures for the monitoring system, and a

maintenance schedule;

< The procedures used to implement the Part 75 recordkeeping and reporting

requirements; 

< Records of all testing, adjustment, maintenance, repair of the monitoring

system (e.g., maintenance logs); and

< Records of corrective actions taken in response to monitoring system

outages.

C For CEMS:

< A written record of the procedures used for the required QA tests (i.e.,

daily calibration, linearity checks, RATAs, etc.);

< The procedures used to adjust the CEMS to ensure accuracy; and
84

< For units with add-on SO2, NOx, or Hg emission controls, a list of the

parameters that are monitored during monitor outages to verify that the

controls are working properly, and the acceptable values and ranges of the

parameters. 

C For sorbent trap monitoring systems:

< Procedures for permanently marking or inscribing an identification number

on each sorbent trap, for tracking purposes;

< An explanation of the procedures used for leak checks of the traps when

they are placed in or removed from service;

< Other procedures that are used to ensure system integrity and data quality,

including dry gas meter calibrations, verification of moisture removal,

ensuring air-tight pump operation;

< The QA/QC criteria of Part 75, Appendix K;

< The chain of custody procedures used in the packing, transporting and

analysis of the sorbent traps;

< Documentation that the laboratory performing the analyses of the traps

either meets the requirements of ISO 17025, or performs and passes the

spike recovery study described in Appendix K at least once a year;

< The rationale for the minimum acceptable data collection time for the size

of sorbent trap selected; and

< A detailed description of the procedures used for RATAs of the sorbent

traps.

C For units using the Appendix D and E methodologies:

< A written record of the fuel flowmeter accuracy test procedures, including

(if applicable) transmitter calibration and visual inspection procedures;

< A record of all adjustments, maintenance or repairs of the fuel flowmeter

monitoring system;

< A written record of the standard procedures used to perform the periodic

fuel sampling and analysis; 

< For Appendix E units, a list of the operating parameters that are

continuously monitored, and acceptable ranges for the parameters; and

< A record of the procedures used to perform the required Appendix E NOx

emission testing.

C For pertinent information concerning the QA/QC requirements for LME units, see

Section 6.1.7 of this guide.
85

9.0 MISSING DATA SUBSTITUTION

PROCEDURES

9.1 Does Part 75 require emissions to be reported for every unit operating hour ?

Yes. In cap and trade programs, sources are accountable for their emissions during each hour

of unit operation, because compliance is assessed by comparing the total mass emissions for the

compliance period (i.e., year or ozone season) to the total number of allowances held. Therefore,

Part 75 requires a complete data record for each affected unit. Emissions data must be reported for

each unit operating hour, without exception.

9.2 How are emissions data reported when a monitoring system is not working ?

In real-life situations, quality-assured emissions data may not be available for some hours,

because monitoring equipment occasionally malfunctions or needs to undergo routine maintenance.

Also, routine QA tests are sometimes not performed on schedule or are failed. For any unit

operating hour in which a monitoring system is unable to provide quality-assured data, the system is

considered to be “out-of-control” (OOC). Data recorded by an out-of-control monitoring system are

unsuitable for Part 75 reporting and may not be used in the emission calculations. For each hour of

an OOC period, emissions data must be provided in one of the following ways:

C Using an approved Part 75 backup monitoring system that is not out-of-control; or

C Using an EPA reference test method; or

C Using an appropriate substitute data value.

Many facilities do not have backup monitoring systems, and even if they do, there is no

guarantee that the backup monitor will be in-control during an outage of the primary monitor. Using

EPA reference methods to collect data can be expensive and time-consuming. In view of this, there

needs to be a standard methodology for determining appropriate substitute data values during missing

data periods. The necessary missing data procedures are found in the following sections of Part 75:

C §§75.31 through 75.38, for units that use CEMS and report emissions data on a yearround basis;

C §75.39 for sorbent trap monitoring systems

C §75.74 (c)(7), for NOx Budget Program units that use CEMS and report emissions data

on an ozone season-only basis; 

C Section 2.4 of Appendix D;

C Section 2.5 of Appendix E; and

< Section 5 of Appendix G

The Part 75 missing data substitution process is shown in Figure 4.
86

Primary monitoring system is down....

 Are quality-assured data from a 

 backup monitoring system or 

 reference method available ? 

Use the backup

or RM data

Yes

No

Use the appropriate

Appendix D or E

missing data procedures

Are emissions measured

using the Appendix D or E

methodology ?

Yes

No

Use the initial missing data

procedures in §75.31 for

CEMS or §75.39(c) for

sorbent traps

Yes Is the CEMS or sorbent trap

system in the initial missing

data time period ?

No

Determine the PMA and the length

of the missing data period

Apply the standard missing data procedures in

§§75.33-39:

 

C Use Table 1 for SO2, Hg, CO2, O2 and H2O. 

C Follow §75.39(d) for sorbent traps

C Use Table 2 for NOx and flow rate.

C Use Tables 3 and 4 for non load-based units.

C If the unit has add-on SO2 or NOx controls and 

SO2 or NOx data are missing, follow §75.34

 

 

 

 

 

 

 

 

 

 

 

 

 

 Figure 4. Part 75 missing data substitution process
61

 For sorbent trap monitoring systems, the initial and standard missing data procedures are found in

§75.39. The missing data algorithms for sorbent traps are similar, but not identical, to the algorithms used for Hg

CEMS. This is due to the fundamental difference in the way that data is collected and recorded with the two types

of Hg monitoring systems.

62

 If three years have elapsed since the date of provisional certification and the requisite number of hours

of quality-assured data have not yet been obtained, the owner or operator must switch to the standard missing data

routines. All available quality-assured data from the previous three years are used for the “lookbacks”, until 720 (or

2,160, as applicable) hours of quality-assured data have been accumulated.

63

 In its simplest form, the PMA is the ratio of the number of quality-assured hours to the number of unit

operating hours, in a specified lookback period. The PMA is calculated hourly by the DAHS.

87

9.3 What are the Part 75 missing data procedures for CEMS ?

In general, the Part 75 missing data procedures for CEMS are designed to provide

conservatively high substitute data values, to ensure that emissions are not underestimated during

monitor outages. Application of the missing data procedures begins either at the date and hour of

provisional certification, when the CEM systems have passed all required certification tests and begin

generating quality-assured data, or when the certification deadline expires, if the monitoring systems

have not passed all of the required tests.. 

Two distinct sets of CEMS missing data algorithms are described in Part 75---the “initial” and

the “standard” missing data routines. The initial missing data algorithms in §75.31 are temporary

“spin-up” procedures that are used for a specified period of time, after which the standard missing

data algorithms in §§75.33 through 75.38 begin to be applied

61. For both the initial and standard

missing data procedures, all of the appropriate substitute data values are calculated and applied

automatically by the data acquisition and handling system (DAHS). If a missing data period extends

past the end of a quarter, it is treated as two separate missing data periods, one terminating at the end

of the quarter and one starting at the beginning of the next quarter. 

The initial missing data procedures are used until a certain number of hours of quality-assured

CEM data have been obtained. For SO2, Hg, CO2, O2, and moisture, this number is 720 hours, and

for NOx and flow rate, it is 2,160 hours. The initial missing data algorithms are simple and the

substitute data values derived from them are likely to be close to the actual values. For example, the

algorithm for SO2 is the arithmetic average of the SO2 concentrations from the hour before and the

hour after the missing data period. For NOx and flow rate, the substitute data value for each hour is

an arithmetic average of the available historical data at similar load levels.

Once the requisite number of hours of quality-assured data has been obtained (i.e., 720 or

2,160), use of the initial missing data procedures ceases and the standard missing data procedures

begin to be applied.62 The standard missing data routines use a tiered approach, that takes into

account both the percent monitor data availability63 (PMA) and the length of the missing data period.

When the PMA is high ($95%) and the missing data period is relatively short (# 24 hr), the standard

missing data algorithms are nearly identical to the initial missing data routines---consequently, the

substitute data values are generally not punitive. However, as the PMA decreases, the substitute data

values become increasingly conservative, to ensure that emissions are not under-reported. For
64

 For sources that report NOx mass emissions data on an ozone season-only basis, only data from inside

the ozone season are included in the missing data lookbacks.

65

 Alternatively, at a common stack, 20 load bins may be defined for flow rate.

88

example, when the PMA of an SO2 or NOx monitoring system is between 80% and 90%, the

substitute data value will be the maximum value observed by looking back through the last 720 hours

(for SO2) or 2,160 hours (for NOx) of historical, quality-assured emission data64. But if the PMA

drops below 80%, regardless of the length of the missing data period, the maximum potential SO2

concentration or the maximum potential NOx emission rate must be reported. 

For units with add-on SO2, NOx, or Hg emission controls, the use of the initial and standard

missing data routines is conditional. The condition is that parametric data must be available to

document that the add-on controls are working properly during the missing data period. For any

hour in which this parametric evidence is unavailable, the maximum potential concentration or the

maximum potential emission rate must be reported. 

The initial and standard missing data algorithms for NOx and stack gas flow rate are loadbased, in order to provide more representative substitute data values. Appendix C of Part 75 requires

the owner or operator to establish 10 load ranges or “load bins”, by dividing the operating range of

the source (e.g., 0 to 500 megawatts) into 10 equal parts65. Then, during periods of missing NOx or

flow rate data, the substitute data value for each hour is calculated using historical quality-assured

data in the corresponding load bin.

However, certain units in the NOx Budget Program, such as cement kilns and refinery process

heaters, do not produce electrical or steam load. To accommodate these sources, EPA added a series

of special missing data algorithms for NOx and flow rate to Part 75 in 2002. The algorithms are

structurally similar to the standard NOx and flow rate missing data routines, except that they are not

load-based. To alleviate industry concerns that the substitute data values determined in this manner

may not be representative, the rule allows the affected sources to define “operational bins”

corresponding to different process operating conditions, and to populate each bin with CEM data.

The substitute data value for each missing data hour is then drawn from the appropriate operational

bin.

As part of the 2002 revisions to Part 75, EPA also added provisions to §§75.33 and 75.34.

These new provisions allow sources to implement the standard missing data routines in a slightly

different manner, in order to obtain more representative substitute data values. Affected sources that

burn different types of fuel now have the option to separate their historical CEM data according to

fuel type and to apply the standard missing data procedures on a fuel-specific basis. Also, for a unit

that is subject to the NOx Budget Program or to the CAIR Ozone Season Trading Program, and is

equipped with add-on NOx controls, and reports emissions data year-round, the owner or operator

may separate the NOx emission data into ozone season and non-ozone season data “pools”. Then,

depending on the time of the year that the missing data period occurs (i.e., inside or outside the ozone

season), the substitute data values are drawn from the appropriate data pool. This missing data option

is advantageous when the NOx emission controls are operated only (or principally) during the ozone

season.
66

 Note that for peaking units, Appendix D allows a simplified missing data procedure to be used for fuel

flow rate. Iinstead of using the standard lookback procedures, the maximum potential fuel flow rate may be

reported for each hour of the missing data period.

89

9.4 What are the missing data procedures for Appendices D, E and G ?

Appendix D

Appendix D of Part 75 includes missing data procedures for fuel flow rate, fuel sulfur content,

GCV and density. The Appendix D missing data algorithms are considerably less complex than the

CEMS missing data routines. The standard Appendix D missing data algorithms for fuel flow rate are

the most sophisticated, in that they are fuel-specific and load-based. However, the substitute data

value for each hour is simply an arithmetic average of the data in the corresponding load bin, based

on a lookback through 720 hours of quality-assured data66. 

Appendix D requires missing data substitution for fuel sulfur content, GCV and density

whenever a required periodic sample for any of these parameters is not taken, or when the results of

a sample analysis are missing or invalid. The missing data approach is quite simple, in that the

maximum potential value of the parameter is reported for each hour of the missing data period. Fuelspecific maximum potential values for sulfur content, GCV and density are defined in Table D-6 of

Appendix D. In some cases, a conservatively high default value is prescribed (e.g., 1.0% sulfur for

diesel fuel). In other cases, a multiplier is applied to the highest value in a lookback through recent

fuel sampling results (e.g., 1.5 times the highest sulfur content from the previous 30 daily gas

samples).

Appendix E

For Appendix E units, missing data substitution is required for any unit operating hour in

which:

C One or more of the monitored QA/QC parameters is either unavailable or outside the

acceptable range of values; or

C The measured heat input rate is higher than the highest heat input rate from the

baseline correlation tests; or

C For a unit with add-on NOx emission controls, the controls are either shut off or

cannot be documented to be working properly; or

C Emergency fuel is combusted, unless a separate correlation curve has been derived for

the fuel.

Appendix E missing data substitution is fairly straightforward. When the QA/QC parameters

are unavailable or outside the acceptable range of values, the substitute data value is simply the

highest NOx emission rate from the baseline correlation curve. When the measured heat input rate

is above the highest value from the baseline testing, there are two missing data options for NOx

emission rate. Either: 

C Report the higher of the linear extrapolation of the correlation curve or the maximum

potential NOx emission rate (MER); or 
67

 According to §75.20(b)(3)(iv), linearity checks and cycle time tests must be completed within 168 unit

operating hours after the probationary calibration error test. For a RATA, 720 operating hours are allowed, and a 

7-day calibration error test must be completed within 21 unit operating days. 

90

C Report 1.25 times the highest value on the correlation curve, not to exceed the MER.

The fuel-specific MER must be reported for units with add-on NOx emission controls, whenever the

controls are either shut off or cannot be documented to be working properly. The MER must also

be reported when emergency fuel is combusted, if there is no baseline correlation curve for that fuel.

Appendix G

For Acid Rain Program units using Appendix G to determine CO2 mass emissions, missing

data substitution is required whenever the results of the required fuel sampling and analysis for carbon

content or GCV are missing or invalid. For periods of missing carbon content, either the appropriate

default value from Table G-1 in Appendix G or the results of the most recent valid sample may be

reported. When the GCV is missing, Table D-6 in Appendix D is used to determine the substitute

data value. 

9.5 What is conditional data validation?

When a significant change is made to a CEMS (e.g., replacement of an analyzer) and the

system must be recertified, the CEMS must pass a series of recertification tests before it can be used

to report quality-assured data. In most cases, recertification takes at least 7 days (since a 7-day

calibration error test is usually one of the required tests). However, while the recertification tests are

in progress, the requirement to report emissions data for every unit operating hour remains in effect.

Without regulatory relief, this could result in an extended period of missing data substitution, and

possible loss of allowance credits.

To alleviate this situation, §75.20(b)(3) of Part 75 allows conditional data validation (CDV)

to be used for recertification events. Conditional data validation provides a means of minimizing the

use of substitute data while a CEMS is being tested for recertification. To take advantage of this rule

provision, as soon as the monitoring system is ready to be tested, a calibration error test is performed.

This is called a “probationary calibration”. If the probationary calibration is passed, data from the

CEMS are assigned a conditionally valid status from that point on, pending the results of the

recertification tests.

If the required recertification tests are then performed and passed within a certain time

frame67, with no test failures, all of the conditionally valid data recorded by the CEMS from the date

and hour of the probationary calibration to the date and hour of completion of the required tests may

be reported as quality-assured. However, if one of the major recertification tests (such as a linearity

check or RATA) is failed, then all of the conditionally valid data are invalidated and missing data

substitution must be used until all of the required tests have been successfully completed.

Part 75 extends the use of conditional data validation beyond recertification events. The

procedures may also be used for initial certification, diagnostic testing, and for routine QA testing.

The application of conditional data validation to initial CEMS certification is particularly
91

advantageous for new sources in the NOx Budget Program, which are accountable to report NOx

mass emissions from the hour of unit start up (i.e., “first-fire”). The use of CDV for these new

sources allows a significant amount of the data recorded prior to completion of the certification tests

to be reclaimed and reported as quality-assured— data which otherwise would be invalidated and

reported as maximum potential values. Note that if CDV is used for initial certification, it may be

used for the entire window of time allotted for certification (up to 180 days in some cases), and the

shorter time frames described in §75.20(b)(3)(iv) do not apply80. Conditional data validation is also

useful when:

C Monitor repair or maintenance activities are performed that trigger diagnostic test

requirements; or 

C A routine QA test, such as a linearity check or RATA is failed or aborted due to a

problem with the monitoring system and must be repeated. 

In these instances, a probationary calibration may be done following corrective actions, and the CDV

procedures applied until the required diagnostic test or QA test has been performed. 
68

 There is an exception to this, for new units in the NOx Budget Program, which must report emissions

data from first-fire.

69

 The version 2.1 and 2.2 EDR formats and accompanying Instructions are found on the Clean Air

Markets Division website, at: http://www.epa.gov/airmarkets/reporting/edr21/index.html

92

10.0 PART 75 REPORTING REQUIREMENTS 

10.1 What are the basic reporting requirements of Part 75 ?

Under the Acid Rain and NOx Budget Programs, electronic and hard copy data of various

kinds (e.g., emissions data, monitoring plan information, results of certification and QA tests. etc.)

must be reported to EPA and to the State at certain times, as specified in Part 75. 

Initial Reporting

The initial Part 75 reporting requirements include the submittal of a monitoring plan and the

results of the monitoring system certification tests. These requirements have been previously

discussed in Section 7 of this guide.

Quarterly Reporting

In general, emissions data must be reported electronically each quarter, beginning either at

the date and hour of provisional certification when all certification tests have been completed or the

date and hour of the certification deadline specified in the rule, whichever comes first68. EPA uses

the quarterly report data to assess compliance, by comparing each unit’s reported annual SO2 mass

emissions and/or ozone season NOx mass emissions against the number of allowances held. For coalfired units with annual NOx

 emission limits under 40 CFR Part 76, the Agency also assesses

compliance with these limits.

Quarterly reporting of hourly emissions data is vital to the success of a cap and trade program.

Quarterly reporting eases the administrative burden associated with the data reconciliation and

allowance accounting process, because it enables EPA and the affected sources to work together

during the year or ozone season to address any problems with the data, rather than waiting until the

year or ozone season is over.

All quarterly reports must be submitted to EPA by direct computer-to-computer transfer,

either by E-mail or by using an EPA-provided software tool known as the Emissions Tracking System

File Transfer Protocol, or “ETS-FTP”. The reports are due within 30 days after the end of each

calendar quarter. During this 30-day submission period, the reports may be revised and resubmitted

as many times as necessary. 

The data in each quarterly report must be in a standardized electronic data reporting (EDR)

format provided by EPA69. The data acquisition and handling system (DAHS) must be capable of

recording all of the necessary data and putting it into this format. Currently, there are two versions

of the EDR, i.e., versions 2.1 and 2.2. Most affected units use version 2.1 and have the option to

upgrade to version 2.2. However, version 2.2 is required for non load-based units, LME units, and
70

 The MDC software and information on how to use it can be found at the following website address:

http//www.epa.gov/airmarkets/monitoring/mdc/index/html

93

for units using certain Part 75 compliance and missing data options. 

The quarterly EDR files must include the following essential information:

C Facility information;

C Hourly and cumulative emissions data;

C Hourly unit operating information (e.g., load, heat input rate, operating time, etc.);

C Monitoring plan information;

C Results of required quality-assurance tests (e.g., daily calibrations, linearity checks,

RATAs, etc.); and 

C Certification statements from the Designated Representative or Authorized Account

Representative (or the Alternate Representative), attesting to the completeness and

accuracy of the data.

The data from each quarterly report submittal are recorded and stored in EPA’s Emissions

Tracking System (ETS). The tracking system consists of the previously-mentioned ETS-FTP

software and data checking routines, housed in an EPA mainframe computer. All sources must obtain

an account and a password from EPA in order to submit their EDR files. The success of the cap and

trade programs depends vitally on ETS. It instils confidence in allowance transactions by certifying

the existence and quantity of the commodity being traded. 

EPA recommends that sources pre-screen their EDR data before making an official submittal.

ETS has a test region where quarterly reports can be sent to receive a preliminary feedback report.

Also, EPA has developed the Monitoring Data Checking (MDC) software, which is available to all

via the Internet70. EPA uses MDC to perform routine electronic audits of the quarterly reports (see

Sections 10.2 and 10.3, and Figure 5, below). 

10.2 How does EPA evaluate the electronic quarterly reports ?

Each quarter, EPA reviews and evaluates the EDR reports, using the following four-step

review process:

C Data Review - The quarterly reports are analyzed using two software tools: ETS and

MDC. The ETS software recalculates the reported emissions from the raw data. MDC

checks the monitoring plan information, recalculates the reported QA test results, and

determines whether the source is up-to-date on its important QA tests, such as linearity

checks, RATAs, etc. The ETS and MDC evaluations identify sources with reporting

problems and also flag sources that have not submitted their EDRs by the reporting

deadline. 

C Feedback to Sources - EPA provides feedback to the sources, based on the results of the
94

ETS and MDC evaluations. The feedback reports indicate that either:

< The data have been accepted and will be stored in the EPA mainframe for the

purposes of annual reconciliation and dissemination; or

< The EDR is unacceptable, and contains “critical” errors that prevent the data

from being used for allowance accounting and dissemination; or 

< The data have been accepted, but EPA has identified “non-critical”

(informational) errors that must be corrected in subsequent quarterly reports.

C Data Resubmission - EPA requires reports with critical errors to be resubmitted by a

specified deadline (generally within 30 days).

C Data Dissemination - All data are reviewed, and preliminary and final emissions data

reports are prepared for public release and compliance determination.

10.3 Part 75 Audit Program

When emissions data are reported in a standardized electronic format such as the EDR,

regulatory agencies can develop software tools with which to audit the data. The results of these

electronic audits can serve as a basis for targeting problem sources, either for more comprehensive

electronic audits or for field audits. In the Part 75 audit program, both electronic audits and field

audits are routinely performed.

 

Special Electronic Audits

In addition to the routine electronic audits of the Part 75 electronic quarterly reports, using

the ETS and MDC software tools. EPA also occasionally performs special (ad-hoc) electronic audits

to look for other specific data reporting problems (e.g., incorrect application of the missing data

routines). 

Field Audit Targeting Tool

 EPA has recently developed an electronic auditing software tool, known as the Targeting

Tool for Field Audits (TTFA). This tool is intended to be used primarily by State agencies, to assist

them in targeting sources for field audits. The TTFA tool is capable of identifying a variety of CEMS

operation and maintenance problems, such as monitoring systems with an excessive number of failed

calibration error tests or linearity checks, sources with long periods of monitor down time, monitoring

systems with improperly-set span and range values, etc. 

Field Audits and Inspections

 EPA relies primarily on State and local agencies to conduct field audits of Part 75-affected

sources. In many instances, the field audits are integrated with routine source inspections. The audits

encourage good monitoring practices by raising plant awareness of Part 75 requirements. Field audits

generally include the following activities: 
95

 

 

 

 

 

 

 

 

 Figure 5. Part 75 data reporting and review process.
71

 The Field Audit Manual is found at the following Internet address: 

http://www.epa.gov/airmarkets/monitoring/auditmanual/index.html

96

C Pre-audit preparation (e.g., monitoring plan review, examination of historical EDR

data using MDC or the TTFA targeting tool, etc.); 

C On-site inspection of the monitoring equipment and system peripherals; 

C Records review; 

C QA test observations; and 

C Interviews with the appropriate plant personnel.

 EPA has developed a Field Audit Manual, which is available on the Internet71. The Field

Audit Manual details recommended procedures for conducting field audits of Part 75 CEMS. The

Manual includes tools that can be used to prepare for an audit, techniques that can be used to

conduct the on-site inspections and records review, proper methods for observing QA tests, and

guidelines for preparing a final report. Checklists are also provided that can be used to ensure that

all necessary data is obtained during the audit. EPA has designed the audit procedures in the Manual

so that personnel with varying levels of experience can use them. Three levels of audits are described

in the Manual:

C A Level 1 audit, consisting of on-site inspection of the CEM equipment, records

review, and observation of a daily calibration error test;

C A Level 2 audit, including all of the Level 1 activities, plus observation of a linearity

check or RATA; and 

C A Level 3 audit, including the Level 1 activities, plus a performance test (linearity

check or RATA) conducted by agency personnel. 

Any State or local agency can perform a Level 1 or Level 2 audit, but not all agencies have the

necessary equipment or expertise to conduct the performance test required by the Level 3 audit. 

10.4 Electronic Reporting—Update

The Clean Air Markets Division of EPA has recently initiated an effort to re-engineer its data

collection and processing systems. The goal of this project is to modernize the way in which the Part

75 electronic data is reported to the Agency. The current “record type-column” EDR format will be

replaced with an “XML” format that interacts more efficiently with a database structure than does

the current format. Proponents of XML believe that using this format will streamline Part 75

reporting and will make the emissions data more accessible to interested parties because of the

enhanced database management capabilities. 
97

The DAHS vendors will need to develop the necessary software to generate the electronic

reports in XML format. EPA plans to make a gradual transition from the current EDR reporting

format to XML reporting. The Agency plans for a “beta test” version of XML to be available by the

end of 2006. In 2007, beta testers may opt to use the XML version for some or all of their official

quarterly report submittals. In 2008, all sources will, at their discretion, be allowed to report either

in the current EDR format or in XML. In 2009, all sources will be required to report only in the

XML format.

Some changes to Part 75 will be needed to close out the old EDR format and to support the

new XML reporting format. EPA plans to propose these rule changes in November, 2005 and to

finalize them by the end of 2006.
98

APPENDIX I

Regulatory Update

(CAIR and CAMR Rules) 
99

APPENDIX I: Regulatory Update (CAIR and CAMR Rules)

On March 10, 2005 and March 15, 2005, respectively, the EPA Administrator signed two

important air regulations:

< The Clean Air Interstate Rule (CAIR); and

C The Clean Air Mercury Rule (CAMR)

The CAIR rule, which was published on May 12, 2005, applies to units that produce

electricity for sale and serve a generator with a nameplate capacity > 25 megawatts. Some 28 States

are affected by the regulation, mostly in the eastern half of the United States. The CAIR rule, which

has been codified in 40 CFR Part 96, is a model regulation for a cap and trade program for SO2 and

NOx. The goal of this program, which will begin in 2008, is to achieve significant reductions in SO2

and NOx mass emissions, far exceeding the reductions that have thus far been achieved by the Acid

Rain and NOx Budget Programs. 

The CAIR rule actually consists of three separate regulations, i.e., one for annual SO2 mass

emissions, one for annual NOx mass emissions, and one for ozone season NOx mass emissions. Most

of the affected States are subject to all three of these rules, although a few States (MN, GA, TX) are

exempted from the ozone season NOx rule and a handful of other States (AR, DE, NJ, CT, MA) are

subject only to the ozone season NOx rule. Each affected State is required to submit a SIP revision

to EPA for approval within 18 months of the effective date of the rule. If a State adopts the model

rule (or something close to it) and submits it as a SIP revision, Agency approval will be automatic.

 

The CAMR rule, which was published on May 18, 2005, applies to coal-fired units that

produce electricity for sale and serve a generator with a nameplate capacity > 25 megawatts. This

regulation, which is found at Subpart HHHH of 40 CFR Part 60, is also a model rule for a cap and

trade program. The program is designed to achieve substantial reductions in mercury mass emissions,

and is scheduled to begin in 2009. The CAMR rule is similar to CAIR, in that each State must submit

a SIP revision to EPA within 18 months of the effective date of the rule, and any State SIP revision

that adopts the model rule will be automatically approved. However, unlike CAIR, which focuses

mainly on the eastern U.S., the CAMR rule is national in its scope and affects all 50 States. 

The CAMR regulation is rather unique, in that it is based on section 111(d) of the Clean Air

Act. In order to justify a section 111(d) rulemaking for a particular category of existing sources and

for a particular pollutant, there must be a New Source Performance Standards (NSPS) regulation in

place for the same source category and pollutant. However, prior to 2005, there was no NSPS

regulation in existence for mercury emissions from coal-fired power plants. Therefore, on May 18,

2005, a mercury NSPS rule (which had been proposed on January 30, 2004) was published along

with the CAMR regulation. The mercury NSPS rule provisions have been codified as amendments

to Subpart Da of 40 CFR Part 60. The mercury NSPS applies to coal-fired electric generating units

that have a heat input capacity > 250 mmBtu/hr and that commence construction after January 1,
100

2004. The rule requires mercury emissions to be continuously monitored.

Both the CAIR and CAMR rules build upon the existing Part 75 infrastructure and require

the emission monitoring and reporting provisions of Part 75 to be implemented. For SO2 and NOx,

the transition to CAIR should be relatively smooth, because Part 75 monitoring and reporting of SO2

and NOx mass emissions has been successfully implemented under the Acid Rain and NOx Budget

Programs for many years. Most of the units affected by CAIR are currently in one or the other (or

both) of these Programs and already have some or all of the required Part 75 monitoring systems in

place. 

However, implementation of the mercury trading program under the CAMR rule will be more

challenging, because continuous mercury monitoring has not been required by any State or Federal

regulation prior to the CAMR rule. In view of this, as part of the May 18, 2005 final rule package,

EPA has added Subpart I to Part 75. Subpart I serves the same purpose for mercury mass emissions

monitoring as Subpart H of Part 75 does for NOx mass emissions monitoring, in that it provides the

monitoring guidelines for a multi-state trading program. The May 18, 2005 final rule has also added

specific mercury monitoring provisions to Part 75, in support of Subpart I. These new mercury

monitoring provisions apply only to units that are regulated under a State or Federal mercury mass

emissions reduction program that adopts Subpart I.

EPA is aware that mercury monitoring technology is still in its infancy and is not nearly as

well-understood or as well-established as SO2 and NOx monitoring technology. However, the results

of recent field studies of mercury monitors have been encouraging, and at the present rate of

progress, mercury monitoring technology is expected to be sufficiently developed by the time the

CAMR rule is implemented.
101

APPENDIX II

Part 75 Monitoring Requirements for Common

Stack and Multiple Stack Configurations
102

The following Table summarizes the Part 75 monitoring requirements for common stack and

multiple stack configurations, under the Acid Rain, NOx Budget, CAIR and CAMR trading programs.

Table II-A: Part 75 Monitoring Requirements for Common

Stack and Multiple Stack Configurations

Case

 No.

 

 If a unit . . .

Then for this 

parameter . . .

Install the following monitoring equipment** at

these locations . . .

 1 Is in the Acid Rain

Program and shares a

common stack with other

affected units in the

Program, but no nonaffected units

SO2 (or CO2) mass 

 emissions 

[lb/hr (or tons/hr)]

An SO2 (or CO2) monitor and a flow monitor on the

duct leading from each unit to the common stack;

or

An SO2 (or CO2) monitor and a flow monitor on the

common stack and report the combined emissions

NOx emission rate 

 (lb/mmBtu)

A NOx-diluent monitoring system on each duct

leading from each unit to the common stack;

or

A NOx-diluent monitoring system on the common

stack, subject to certain conditions1

Heat input rate

 (mmBtu/hr)

A flow monitor and a diluent gas monitor on the duct

leading from each unit to the common stack;

or

A flow monitor and a diluent gas monitor on the

common stack and apportion the common stack heat

input rate to the individual units on the basis of unit

load (i.e., electrical or steam load)

Opacity (%) An opacity monitor on each unit, if required to do so

by another State or Federal regulation;

otherwise

An an opacity monitor on the common stack.
Case

 No.

 

 If a unit . . .

Then for this 

parameter . . .

Install the following monitoring equipment** at

these locations . . .

103

 2 Is in the Acid Rain

Program and shares a

common stack with at

least one other unit that

is not in the Acid Rain

Program

SO2 (or CO2) mass 

 emissions 

[lb/hr (or tons/hr)]

An SO2 (or CO2) monitor and a flow monitor on the

duct leading from each affected unit to the common

stack;

or

An SO2 (or CO2) monitor and a flow monitor on the

common stack, subject to certain conditions2

NOx emission rate 

 (lb/mmBtu)

A NOx-diluent monitoring system on the duct leading

from each affected unit to the common stack;

or

A NOx-diluent monitoring system on the common

stack and petition the Administrator under §75.66 for

approval of a strategy to apportion the common stack

emission rate to the individual units 

Heat input rate 

 (mmBtu/hr)

A flow monitor and a diluent gas monitor on the duct

leading from each affected unit to the common stack;

or

A flow monitor and a diluent gas monitor on the

common stack, subject to certain conditions3

Opacity (%)

An opacity monitor on each unit, if required to do so

by another State or Federal regulation;

otherwise

An opacity monitor on the common stack.
Case

 No.

 

 If a unit . . .

Then for this 

parameter . . .

Install the following monitoring equipment** at

these locations . . .

104

 3

 

Is in the Acid Rain

Program and either:

(a) Has multiple

exhaust stacks

 or

(b) Has multiple

breechings (i.e.,

ducts) leading to a

single stack, and the

owner or operator

elects to monitor in

the breechings

SO2 (or CO2) mass 

 emissions 

[lb/hr (or tons/hr)]

An SO2 (or CO2) monitor and a flow monitor on

each stack or duct and sum the measured mass

emissions.

NOx emission rate 

 (lb/mmBtu) A NOx

-diluent monitoring system and a flow

monitor on each stack or duct and determine a

Btu-weighted NOx emission rate for the unit;

or

If Appendix D is used to measure the unit heat

input, install a NOx-diluent monitoring system

on each stack or duct and report the highest

hourly NOx emission rate recorded by any of

these systems as the emission rate for the unit;

or

If the combustion products are well-mixed,

install a NOx-diluent monitoring system on one

stack or duct4 

Heat input rate 

 (mmBtu/hr) A flow monitor and a diluent gas monitor on

each stack or duct and sum the measured heat

input rates for the unit; 

or

If the unit uses Appendix D methodology, use

the measured hourly fuel flow rates and the fuel

GCV to quantify the unit heat input rate
Case

 No.

 

 If a unit . . .

Then for this 

parameter . . .

Install the following monitoring equipment** at

these locations . . .

105

 4 Is in the Acid Rain

Program and has a main

stack-bypass stack

exhaust configuration

SO2 (or CO2) mass 

 emissions 

[lb/hr (or tons/hr)]

An SO2 (or CO2) monitor and a flow monitor on both

the main stack and the bypass stack;

or

An SO2 (or CO2) monitor and a flow monitor only on

the main stack and during bypass hours, report the

maximum potential SO2 concentration5 and the

appropriate substitute data values for flow rate and

CO2

NOx emission rate 

 (lb/mmBtu)

A NOx-diluent monitoring system only on the main

stack and report the maximum potential NOx

emission rate (MER) during bypass hours;

or

 Follow the procedures for multiple stacks (Case 3(a),

above) 

Heat input rate

 (mmBtu/hr)

A flow monitor and a diluent gas monitor on both the

main stack and the bypass stack; 

or

A flow monitor and a diluent gas monitor only on the

main stack and report the appropriate substitute data

values for flow rate and diluent gas concentration

during bypass hours

Opacity (%) An opacity monitor on both the main stack and

bypass stack;

or

An opacity monitor only on the main stack, subject to

certain conditions6
Case

 No.

 

 If a unit . . .

Then for this 

parameter . . .

Install the following monitoring equipment** at

these locations . . .

106

 5 Is in the NOx Budget

Trading Program or the

CAIR NOx Trading

Program(s) and shares a

common stack with other

affected units in the

Program(s), but no nonaffected units

NOx mass emissions 

 (lb/hr)

A NOx-diluent monitoring system and a flow monitor

on the duct leading from each unit to the common

stack7;

or

 A NOx concentration monitoring system and a flow

monitor on the duct leading from each unit to the

common stack8;

or

A NOx-diluent monitoring system and a flow monitor

on the common stack7 and report the combined NOx

mass emissions;

or

A NOx concentration monitoring system and a flow

monitor on the common stack8 and report the

combined NOx mass emissions

Heat input rate9

 (mmBtu/hr)

A flow monitor and a diluent gas monitor on the duct

leading from each unit to the common stack;

or

A flow monitor and a diluent gas monitor on the

common stack and apportion the common stack heat

input rate to the individual units by load

10;

or

If any unit is oil-or gas-fired, Appendix D

methodology (i.e., measured fuel flow rates and fuel

GCV) may be used to determine its unit heat input

rate. If this option is selected, a flow monitor and

diluent monitor must be installed in the duct leading

to the common stack for the remaining units. 
Case

 No.

 

 If a unit . . .

Then for this 

parameter . . .

Install the following monitoring equipment** at

these locations . . .

107

 6 Is in the NOx Budget

Trading Program or the

CAIR NOx Trading

Program(s) and shares a

common stack with at

least one non-affected

unit

NOx mass emissions

 (lb/hr)

A NOx-diluent monitoring system and a flow

monitor7 on the duct leading from each affected unit

to the common stack. Alternatively, if any of the

affected units is oil- or gas-fired, for that unit an

Appendix D fuel flowmeter may be installed in lieu

of the stack flow monitor; 

or

A NOx concentration monitoring system and a flow

monitor8 on the duct leading from each affected unit

to the common stack; 

or

A NOx-diluent monitoring system and a flow monitor

on the common stack, subject to certain conditions11.

Heat input rate9

 (mmBtu/hr)

Consistent with the NOx mass emissions monitoring

option used12, install all necessary flow and diluent

gas monitors on the common stack and/or on the

ducts leading from the units to the common stack. 

Alternatively, if any unit is oil-or gas-fired,

Appendix D may be used to determine the heat input

rate for that unit.
Case

 No.

 

 If a unit . . .

Then for this 

parameter . . .

Install the following monitoring equipment** at

these locations . . .

108

 7

 

Is in the NOx Budget

Trading Program or the

CAIR NOx Trading

Program(s) and has a

main stack and bypass

stack exhaust

configuration

NOx mass emissions 

 (lb/hr)

A NOx-diluent monitoring system and a flow monitor

on each stack7. Alternatively, if the unit is oil- or gasfired, Appendix D fuel flowmeters may be used in

lieu of installing a stack flow monitor;

or

A NOx concentration monitoring system and a flow

monitor on each stack8;

or

A NOx-diluent monitoring system and a flow monitor

or a NOx concentration monitoring system and a flow

monitor only on the main stack, and report

maximum potential values for NOx and flow rate

when the bypass stack is used. 

Heat input rate9

 (mmBtu/hr)

If both stacks are monitored, install flow and diluent

gas monitors on each stack;

or

If only the main stack is monitored, install flow and

diluent gas monitors on the main stack and during 

bypass hours, use maximum potential flow rate,

maximum potential CO2 (or minimum potential O2)

concentration values in the heat input rate equation;

or

If the unit is oil or gas-fired, use Appendix D to

determine the unit heat input rate.
Case

 No.

 

 If a unit . . .

Then for this 

parameter . . .

Install the following monitoring equipment** at

these locations . . .

109

 8 Is in the NOx Budget

Program or the CAIR

NOx Trading Program(s)

and either:

(a) Has multiple

exhaust stacks

 or

(b) Has multiple

breechings (i.e.,

ducts) leading to a

single stack, and the

owner or operator

elects to monitor in

the ducts

NOx mass emissions 

 (lb/hr)

A NOx-diluent monitoring system and a flow monitor

on each stack or duct7 and sum the measured NOx

mass emissions;

or

A NOx concentration monitoring system and a flow

monitor on each stack or duct8 and sum the measured

NOx mass emissions; 

or

If the unit is oil- or gas-fired, install a NOx-diluent

system on only one stack or duct, subject to certain

conditions13. 

Heat input rate9

 (mmBtu/hr)

A flow monitor and diluent gas monitor on each

stack or duct and sum the measured heat input rates; 

or

If the unit is oil- or gas-fired and meets certain

criteria13, use Appendix D to determine the unit heat

input rate.

 9 Is in the CAIR SO2

Trading Program and

shares a common stack

with other affected units

in the Program, but no

non-affected units

SO2 mass emissions 

 (lb/hr)

Follow the guidelines for SO2 mass emissions in 

Case 1, above

Heat input rate

 (mmBtu/hr)

Follow the guidelines in Case 1, above

 10 Is in the CAIR SO2

Trading Program and

shares a common stack

with at least one other

unit that is not in the

Program

SO2 mass emissions 

 (lb/hr)

Follow the guidelines for SO2 mass emissions in 

Case 2, above

Heat input rate

 (mmBtu/hr)

Follow the guidelines in Case 2, above
Case

 No.

 

 If a unit . . .

Then for this 

parameter . . .

Install the following monitoring equipment** at

these locations . . .

110

 11 Is in the CAIR SO2

Trading Program and

either:

(a) Has multiple

exhaust stacks

 or

(b) Has multiple

breechings (i.e.,

ducts) leading to a

single stack, and the

owner or operator

elects to monitor in

the ducts

SO2 mass emissions 

 (lb/hr)

Follow the guidelines for SO2 mass emissions in 

Case 3, above

Heat input rate

 (mmBtu/hr)

Follow the guidelines in Case 3, above

 12 Is in the Hg Budget

Trading Program under

CAMR and shares a

common stack with other

affected units in the

Program, but no nonaffected units

Hg mass emissions 

 (oz/hr)

A Hg concentration monitoring system or sorbent

trap system and a flow monitor on the duct leading

from each unit to the common stack .If the units

qualify for the low mass emissions option under

§75.81(b), the Hg monitoring systems are not

required;

or

A Hg concentration monitoring system or a sorbent

trap system and a flow monitor on the common stack

and report the combined Hg mass emissions. If the

units qualify for the low mass emissions option under

§75.81(b), the Hg monitoring system is not required.

Heat input rate9

 (mmBtu/hr)

A flow monitor and a diluent gas monitor on the duct

leading from each unit to the common stack;

or

A flow monitor and a diluent gas monitor on the

common stack and apportion the common stack heat

input rate to the individual units by load, according

to §75.16(e)10.
Case

 No.

 

 If a unit . . .

Then for this 

parameter . . .

Install the following monitoring equipment** at

these locations . . .

111

 13 Is in the Hg Budget

Trading Program under

CAMR and shares a

common stack with at

least one non-affected

unit

Hg mass emissions15

 (oz/hr)

A Hg concentration monitoring system or sorbent

trap system and a flow monitor on the duct leading

from each affected unit to the common stack. If an

affected unit qualifies for the low mass emissions

option under §75.81(b), the Hg monitoring system is

not required;

or

A Hg concentration monitoring system or a sorbent

trap system and a flow monitor on the common stack,

subject to certain conditions14

 14 Is in the Hg Budget

Trading Program under

CAMR and has a main

stack and bypass stack

exhaust configuration

Hg mass emissions15

 (oz/hr)

A Hg concentration monitoring system or sorbent

trap system and a flow monitor on both the main and

bypass stacks and sum the Hg mass emissions

measured at the two stacks; 

or

A Hg concentration monitoring system or sorbent

trap system and a flow monitor on the main stack,

use reference methods at the bypass stack, and sum

the Hg mass emissions measured at the two stacks; 

or

A Hg concentration monitoring system or sorbent

trap system and a flow monitor only on the main 

stack, and report the maximum potential Hg

concentration and substitute data values for flow rate,

diluent gas and moisture during bypass hours. If the

unit qualifies for the low mass emissions option

under §75.81(b), the Hg monitoring system on the

main stack is not required.
Case

 No.

 

 If a unit . . .

Then for this 

parameter . . .

Install the following monitoring equipment** at

these locations . . .

112

 15 Is in the Hg Budget

Trading Program under

CAMR and either:

(a) Has multiple

exhaust stacks

 or

(b) Has multiple

breechings (i.e.,

ducts) leading to a

single stack, and the

owner or operator

elects to monitor in

the ducts

Hg mass emissions15

 (oz/hr)

A Hg concentration monitoring system or sorbent

trap system and a flow monitor on each stack or

duct, and sum the Hg mass emissions measured at

the stacks (or ducts). If the unit qualifies for the low

mass emissions option under §75.81(b), the Hg

monitoring systems are not required
113

Notes----Table II-A

** Although not shown in Cases 1 through 15 in Table II-A, in some instances, installation of a continuous moisture monitoring

system will also be required. As described in Table 7 in Section 3.4 of this guide, a correction for stack gas moisture is

sometimes required to accurately determine the emissions or heat input rate. When a correction for moisture is needed, the

owner or operator must either use an approved default moisture value or install a continuous moisture monitoring system.

1 The compliance options available to the owner or operator depend on: (a) which (if any) of the units has a Part 76 NOx

emission limit; and (b) the magnitude(s) of any such limit(s).

2 Compliance options include: (a) opting the non-affected units into the Program; (b) attributing all measured emissions to the

affected units; (c) monitoring the non-affected units and using a subtractive methodology; and (d) petitioning EPA for approval

of an emission apportionment strategy. The owner or operator must ensure that SO2 or CO2 mass emissions from the affected

unit(s) are not underestimated. 

3

 The owner or operator has the same basic compliance options for heat input rate as for SO2 and CO2 mass emissions

accounting (see preceding footnote). Once the combined heat input rate of the affected units has been quantified, it must be

apportioned to the individual affected units, either on the basis of load or according to a strategy that has been approved by

petition under §75.66.

4 This option may only be used if the monitored stack or duct cannot be bypassed (e.g., with a damper). The option is also

disallowed if the monitored NOx emission rate is not representative of the emissions discharged to the atmosphere (e.g., if

there are additional NOx emission controls downstream of the monitored location).

5

 Coal-fired Acid Rain Program units with this configuration have flue gas desulfurization systems (scrubbers) that reduce SO2

emissions substantially (90% or more, in most cases). Therefore, during scrubber bypass hours, reporting the maximum

potential SO2 concentration (or, if available, data from a certified SO2 monitor at the control device inlet) is appropriate.

6 An opacity monitor is not required on the bypass stack if: (a) a Federal, State, or local regulation exempts the bypass stack

from opacity monitoring; or (b) An opacity monitor is already installed at the inlet of the add-on emission controls; or (3) if

visible emissions observations are made using EPA Method 9 during bypass events.

7

 These monitoring systems are required if NOx mass is calculated by multiplying the NOx emission rate (lb/mmBtu) by the

heat input rate (mmBtu/hr).

8

 These monitoring systems are required of NOx mass is calculated as the product of NOx concentration (ppm), stack gas flow

rate (scfh), and a conversion factor.

9

If heat input reporting is required by the regulation.

10 To use this option, all units using the common stack must have the same F-factor.

11

 Available compliance options include: (a) opting the non-affected units into the Program and reporting the combined NOx

mass emissions; (b) attributing all of the NOx mass emissions measured at the common stack to the affected units; (c)

installing a NOx -diluent monitoring system and a flow monitor on the duct leading from each non-affected unit to the common

stack, and petitioning to use a subtractive methodology; or (d) petitioning for approval of a method of apportioning the NOx

mass emissions measured at the common stack to the individual units.

12

 Depending on the compliance option used, heat input rate determinations may be necessary at the common stack, in the

ductwork to the affected units, in the ductwork of the non-affected units, or some combination of these.
114

13

 The conditions are: (a) Appendix D must be used to determine the heat input rate; (b) the combustion products must be wellmixed; (c) it must be impossible to bypass the monitored stack or duct (e.g., with dampers); and (d) there must be no NOx

emission controls downstream of the monitored location.

14 The available compliance options include: (a) attribute all of the Hg mass emissions measured at the common stack to the

affected unit(s); (b) install a Hg concentration monitoring system or sorbent trap system and a flow monitor on the duct

leading from each non-affected unit to the common stack and petition to use a subtractive methodology for Hg mass (note:

if a non-affected unit qualifies for the low mass emissions option under §75.81(b), the Hg monitoring system is not required);

or (c) petition to use a method of apportioning the Hg mass measured at the common stack to the individual units

15

 Subpart I of Part 75 does not directly address heat input rate monitoring for this case. However, the provisions of §75.16(e),

which are required under Case 12 seem appropriate for this case, also.
115

APPENDIX III

 On-Going QA Test Requirements for 

Ozone Season-Only Reporters
116

The following Table summarizes the on-going QA test requirements for sources that: (1) are in

the NOx Budget Program or in the CAIR Ozone Season Trading Program; and (2) are eligible to

report NOx mass emissions data only during the ozone season, rather than year-round; and (3) elect

to use this option:

Table III-A: On-Going QA Test Requirements 

 for Ozone Season-Only Reporters

Perform these

QA tests...

On these

monitoring

systems...

At these times...

 With these qualifications and 

exceptions...

Daily calibrations 

(outside ozone

season)

Gas and flow

monitors

From the date and hour

of any RATA or linearity

check passed in the "preozone season period"

from 10/1 of previous

year through 4/30 of

current year; or

Throughout the preozone season period, if

an ozone season RATA

from the previous year is

used to validate data in

the current ozone season.

 ---------------------

Daily calibrations 

(inside ozone season)

Gas and flow

monitors

Throughout the ozone

season (5/1 through 9/30)

 ---------------------

Daily interference 

checks 

(outside ozone

season)

Flow monitors From the date and hour

of any flow RATA passed

in the pre-ozone season

period ---------------------

Daily interference

checks 

(inside ozone season)

Flow monitors Throughout the ozone

season --------------------

Flow-to-load ratio or

gross heat rate test

Flow monitor In 2nd and 3rd quarters C Required only in QA operating

quarters

C Non load-based units exempted

C Complex configurations may be

exempted by petition under §75.66
117

Table III-A (cont’d)

Perform these

QA tests...

On these

monitoring

systems...

At these times...

 With these qualifications and 

exceptions...

Linearity checks

(outside ozone

season)

Gas monitors Any time during the preozone season period from

10/1 of previous year

through 4/30 of current

year

If the test is not completed by 4/30,

then either:

C A 168 operating hour grace

period is allowed if a linearity

check was passed in the previous

year and if the unit operated for <

336 hours in the last ozone

season; or

C If the grace period does not apply,

and the test is done in the first

168 operating hours of the ozone

season, it counts as both the preseason linearity check and the 2nd

quarter test. Conditional data

validation may be used.

Linearity checks

(inside ozone season)

Gas monitors In 2nd and 3rd quarters C The linearity check is required

only in QA operating quarters48. 

For 2nd quarter, count only the

operating hours in May and June.

C If the test is done in first 168

hours of ozone season, it counts

as both the pre-season linearity

check and the 2nd quarter check.

C No grace periods allowed for

these checks

C A “make-up” test can be

performed within the first 168

operating hours of next quarter.

Conditional data validation may

be used.
118

Table III-A (cont’d)

Perform these

QA tests...

On these

monitoring

systems...

At these times...

 With these qualifications and 

exceptions...

RATA and Bias test Gas and flow

monitors

(Bias test applies

to NOx and flow

monitors, only)

Pre-ozone season period

from 10/1 of previous

year through 4/30 of

current year

C Not required if RATA from

previous ozone season is able to

validate data for part or all of

current ozone season

C If the results of this RATA

qualify for an annual RATA

frequency, this RATA may be

used to validate data for entire

current ozone season

C If the results of this RATA

require a semiannual frequency,

this RATA may be used to

validate data for entire current

ozone season (if test was

performed in the current year) or

only through 6/30 of current year

(if test was performed in the

previous year)

C If the RATA is required, but is

not completed by 4/30, a 720

operating hour grace period is

allowed if a RATA was passed in

the previous year and if the unit

operated for < 336 hours in the

last ozone season

C If the RATA is required, but is

not completed by 4/30 and the

grace period does not apply, the

test may be performed inside the

current ozone season, using the

conditional data validation

procedures of § 75.20 (b)(3),

subject to certain restrictions.
119

Table III-A (cont’d)

Perform these

QA tests...

On these

monitoring

systems...

At these times...

 With these qualifications and 

exceptions...

RATA and Bias test Gas and flow

monitors

(Bias test applies

to NOx and flow

monitors, only)

Inside the ozone season

i.e., in 2nd or 3rd quarter

C Required only when a pre-ozone

season RATA or a RATA

performed during the last ozone

season is not able to quality

assure data for the entire current

ozone season

C All required RATAs may be done

in the 2nd or 3rd quarter instead of

performing RATAs outside the

ozone season

C An ozone season RATA may be

used to validate data for part or

all of the next ozone season, if

the RATA results qualify for an

annual frequency, and if daily

calibrations (and interference

checks if applicable) are

performed from 10/1 of current

year through 4/30 of the next year

Flow-to-load ratio or

gross heat rate test

Flow monitor In 2nd and 3rd quarters C Required only in QA operating

quarters

C Non load-based units exempted

C Complex configurations may be

exempted by petition under

§75.66

Leak check DP-type flow

monitor

In 2nd and 3rd quarters C Required only in QA operating

quarters
120

Table III-A (cont’d)

Perform these

QA tests...

On these

monitoring

systems...

At these times...

 With these qualifications and 

exceptions...

Flowmeter accuracy

test

Fuel flowmeter Once every four "fuel

flowmeter QA operating

quarters"50

C Include calendar quarters outside

the ozone season when

determining the accuracy test

deadline

C For orifice, nozzle and venturitype flowmeters, visual

inspections are also required

every 3 years

C The optional fuel flow-to-load or

gross heat rate test (see section

2.1.7 of Appendix D) may be

performed in the 2nd and 3rd

quarters to extend the interval

between flowmeter accuracy tests,

to up to 20 quarters

NOx emission rate

testing

Appendix E

systems

Once every 5 years 

(20 calendar quarters) -------
121

APPENDIX IV

References
122

APPENDIX IV: References

The following underlined section numbers in bold print refer to sections of this guide. The

relevant rule citations for each section of the document are listed beneath the section number. All

referenced rule sections are from Volume 40 of the Code of Federal Regulations. 

Section 1

C §§60.4101 through 60.4176 (i.e., the CAMR rule)

C §72.6 

C §§75.1 through 75.84 and Appendices A through K (i.e., the Part 75 rule) 

C §§76.5, 76.6, 76.7, and 76.13

C §§ 96.1 through 96.88, and associated SIP regulations (i.e., the NOx Budget Trading Program) 

C §§96.101 through 96.188 (blueprint for CAIR NOx annual trading program) 

C §§96.201 through 96.288 (blueprint for CAIR SO2 annual trading program) 

C §§96.301 through 96.388 (blueprint for CAIR NOx ozone season trading program) 

Section 2.1

C §§60.4110 through 60.4114

C §72.2

C §§72.20 through 72.25

C §96.2

C §§96.10 through 96.14

C §§96.110 through 96.114

C §§96.210 through 96.214

C §§96.310 through 96.314

Section 2.2

C §72.2

C §§75.10 through 75.18 

C §75.19 

C §§75.40 through 75.48 (Subpart E)

C §75.66

C §§75.81 (a) and (b) 

C Appendices D, E and G to Part 75

Section 2.3

C §§75.20

C §75.61(a)(1)

C §75.62
123

APPENDIX IV: References (cont’d)

Section 2.4

C §72.2

C §§75.10 through 75.19

C §75.20 

C §§75.30 through 75.39

C §§75.81 (a) and (b) 

C Appendices D, E and G to Part 75

Section 2.5

C §75.19(c)(1)(iv)(D)

C §§1, 2.1 through 2.4, and 2.6 of Part 75, Appendix B

C §§ 2.1.6 and 2.1.7 of Part 75, Appendix D

C § 2.2 of Part 75, Appendix E

C Appendix K to Part 75

Section 2.6

C §60.4174

C §75.53

C §§75.57 through 75.59

C §75.73

C §75.84

C §§96.74, 96.174, 96.274, and 96.374

Section 2.7

C §60.4174

C §§75.60 through 75.64 

C §75.73(f)

C §§96.74, 96.174, 96.274, and 96.374

Section 3.1

C §72.2

C §§75.10 through 75.18

C §75.20(d)

Section 3.2

C §72.2

C §75.15

C Appendix K to Part 75
124

APPENDIX IV: References (cont’d)

Section 3.4

C §75.10(d)

Section 3.5

C Part 75, Appendix F—Equations

C Method 19 in Appendix A-7 to Part 60

Section 3.6

C §75.11(b)

C §75.12(b)

C §75.66

C Part 75, Appendix F—Equations

C Method 19 in Appendix A-7 to Part 60

Section 3.7

C §§75.16 through 75.18

C §75.72

C §75.82

Section 3.8

C §§75.30 through 75.39

Section 4.1

C §72.2

Section 4.2

C §§2.1, 2.2 and 2.3 of Part 75, Appendix D

Section 4.3

C §2.1 of Part 75, Appendix D

Section 4.4

C §§2.2 and 2.3 of Part 75, Appendix D

Section 4.5

C §§3.1, 3.2 and 3.3 of Part 75, Appendix D
125

APPENDIX IV: References (cont’d)

Section 4.6

C §3.4 of Part 75, Appendix D

Section 4.7

C Table D-4 in §2.2 of Part 75, Appendix D

C Table D-5 in §2.3 of Part 75, Appendix D

C §§2.3.5, 2.3.6, and 2.3.7 of Part 75, Appendix D 

Section 4.8

C §72.2

C §1.3 of Part 75, Appendix B

C §§2.1.6 and 2.1.7of Part 75, Appendix D

Section 4.9

C §2.4 of Part 75, Appendix D

Sections 5.0 and 5.1

C §72.2

C §75.74(c)(11)

C §§2.1 and 3.4 of Part 75, Appendix D

Section 5.2

C §2.1 of Part 75, Appendix E

Section 5.3

C §2.4 of Part 75, Appendix E

Section 5.4

C Table D-4 in §2.2 of Part 75, Appendix D

C Table D-5 in §2.3 of Part 75, Appendix D

Section 5.5

C §1.3 of Part 75, Appendix B

C §§2.2 and 2.3 of Part 75, Appendix E
126

APPENDIX IV: References (cont’d)

Section 5.6

C §2.5 of Part 75, Appendix E

Section 5.7

C §1.1 of Part 75, Appendix E

Section 6.1

C §72.2

C §75.19

Section 6.1.1

C §72.2

C §75.19(a)(1)

Section 6.1.2

C §§75.19(a)(2) through (a)(4)

C §75.20(h)

Section 6.1.3

C §§75.19(c)(1), (c)(3), and (c)(4)

Section 6.1.4

C §75.19(c)(1)(iv)

Section 6.1.5

C §75.19(c)(1)(iv)(C)

Section 6.1.6

C §§75.19(c)(2), (d) and (e)

Section 6.1.7

C §75.19(e)

Section 6.1.8

C §§75.19(b)(2) and (b)(3)
127

APPENDIX IV: References (cont’d)

Section 6.2

C §§60.4101 through 60.4176

C §§75.80 through 75.84

Section 7.2

C §60.4174(b)

C §75.53

C §75.62

C §§75.73(c) and (e)

C §75.84(e)

Section 7.3

C §60.4173

C §75.61(a)(1)

C §§96.73, 173, 273, and 373

Section 7.4

C §60.4171

C §§75.20(c), (e) and (g)

C §75.70(d)

C §75.80(d)

C §§96.71, 171, 271, and 371

Section 7.5

C §§60.4171(c)(3) and 60.4174(c)

C §75.20(a)(2)

C §75.63

C §75.70(d)

C §75.80(d)

C §§96.71, 171, 271, and 371

Section 7.6

C §60.4171(c)(3)

C §75.20(a)(4)

C §75.70(d)

C §75.80(d)

C §§96.71, 171, 271, and 371
128

APPENDIX IV: References (cont’d)

Section 7.7

C Appendices A-1 through A-7 to Part 60 

C §75.22 

C §§5 and 6.5.10 of Part 75, Appendix A 

Section 7.8

C §3 of Part 75, Appendix A

C §2.1.5 of Part 75, Appendix D

Section 7.9

C §§2.1 through 2.1.7 of Part 75, Appendix A

C §§2.2.2.1, 5.2, 6.2, 6.3.1, and 6.3.2 of Part 75, Appendix A

C §§2.1.1 and 2.1.4 of Part 75, Appendix B

Section 7.10

C §60.4171

C §75.20(b)

C §75.70(d)

C §75.80(d)

C §§96.71, 171, 271, and 371

Sections 8.1 and 8.2

C §75.21 

C §§75.74(c)(2) through (c)(5)

C §§2.1 through 2.4 and 2.6 of Part 75, Appendix B

C §§ 2.1.6 and 2.1.7 of Part 75, Appendix D

C §§2.2 and 2.3 of Part 75, Appendix E

C Appendix K to Part 75

Section 8.3

C §6.2 of Part 75, Appendix A

C §§2.2 and 2.3 of Part 75, Appendix B

C §§2.1.6 and 2.1.7 of Part 75, Appendix D
129

APPENDIX IV: References (cont’d)

Section 8.4

C §§ 6.2, 6.3.1, 6.3.2, 6.5(b), 6.5.1, 6.5.2, 6.5.2.1, and 7.7 of Part 75, Appendix A

C §§2.1.1, 2.1.1.1, 2.1.1.2, 2.1.5, 2.2.5, and 2.3.1.3 of Part 75, Appendix B

Section 8.5

C §§75.74(c)(2) through (c)(5)

Section 8.6

C §§3.2 and 3.3 of Part 75, Appendix A

C §§ 2.1.4 and 2.2.5(b) of Part 75, Appendix B

C Figure 2 in Appendix B to Part 75 

Section 8.7

C §75.61(a)(5)

Section 8.8

C §75.19(e)

C §§1.1 through 1.3 and 1.5 of Part 75, Appendix B

Section 9

C §75.20(b)(3)

C §§75.31 through 75.39

C §75.70(f)

C §75.74(c)(7)

C §75.80(f)

C §2.4 of Part 75, Appendix D

C §2.5 of Part 75, Appendix E

C §5 of Part 75, Appendix G

Section 10

C §60.4174

C §§75.60 through 75.64

C §75.73(f)

C §75.84

C §§96.74, 174, 274, and 374